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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
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 No o
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 o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
PINNACLE WEST CAPITAL CORPORATION Yes þ No o
ARIZONA PUBLIC SERVICE COMPANY Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation
S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or in any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer,
or a smaller reporting company. See the definitions of “large accelerated filer,”“accelerated filer” and “smaller reporting
company” in Rule 12b-2 of the Exchange Act. (Check one):
PINNACLE WEST CAPITAL CORPORATION
Large accelerated filer þ
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
(Do not check if a smaller reporting company)
ARIZONA PUBLIC SERVICE COMPANY
Large accelerated filer o
Accelerated filer o
Non-accelerated filer þ
Smaller reporting company o
(Do not check if a smaller reporting company)
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:
The number of shares outstanding of each registrant’s common stock as of February 21, 2008
PINNACLE WEST CAPITAL CORPORATION
100,499,104 shares
ARIZONA PUBLIC SERVICE COMPANY
Common Stock, $2.50 par value,
71,264,947 shares. Pinnacle West
Capital Corporation is the sole holder
of Arizona Public Service Company’s
Common Stock.
Portions of Pinnacle West Capital Corporation’s definitive Proxy Statement relating to its Annual
Meeting of Shareholders to be held on May 21, 2008 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.
Off-System Sales – sales of electricity from generation owned or contracted by the Company that is
over and above the amount required to serve APS’ retail customers and traditional wholesale
contracts
Palo Verde – Palo Verde Nuclear Generating Station
Pinnacle West – Pinnacle West Capital Corporation, the Company
Pinnacle West Energy (PWEC) – Pinnacle West Energy Corporation, a subsidiary of the Company,
dissolved as of August 31, 2006
Pinnacle West Marketing & Trading – Pinnacle West Marketing & Trading Co., LLC, a subsidiary of the
Company
PRP – potentially responsible parties under Superfund
PSA – power supply adjustor approved by the ACC to provide for recovery or refund of variations in
actual fuel and purchased power costs compared with the Base Fuel Rate
PWEC Dedicated Assets – the following power plants, each of which was transferred by Pinnacle West
Energy to APS on July 29, 2005: Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3
Salt River Project – Salt River Project Agricultural Improvement and Power District
SEC – United States Securities and Exchange Commission
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
2005 Deferrals – PSA deferrals related to 2005 replacement power costs associated with Palo Verde
outages
2006 Deferrals – PSA deferrals related to 2006 replacement power costs associated with outages or
reduced power operations at Palo Verde
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 is 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 relates to APS, and Supplemental Notes to APS’ Financial
Statements.
PART I
ITEM 1. BUSINESS
OVERVIEW
General
Pinnacle West was incorporated in 1985 under the laws of the State of Arizona and owns all of
the outstanding equity securities of APS, its major subsidiary. APS is a vertically-integrated
electric utility that provides either retail or wholesale electric service to most of the state of
Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson
metropolitan area and Mohave County in northwestern Arizona.
Pinnacle West’s other principal subsidiary is SunCor, which is engaged in real estate
development activities in the western United States. See “Business of SunCor Development Company”
in this Item 1. Pinnacle West’s other first-tier subsidiaries, APSES, El Dorado and Pinnacle West
Marketing & Trading are discussed in “Business of Other Subsidiaries” in this Item 1.
Pinnacle West Energy, which owned and operated unregulated generating plants, transferred the
PWEC Dedicated Assets to APS on July 29, 2005 and sold its 75% ownership interest in Silverhawk to
NPC on January 10, 2006. As a result, Pinnacle West Energy no longer owned any generating plants
and was dissolved as of August 31, 2006.
Pinnacle West has two principal business segments (determined by products, services and the
regulatory environment):
•
the regulated electricity segment (accounting for 83% of operating revenues in
2007), which consists of traditional regulated retail and wholesale electricity
businesses (primarily electric service to Native Load customers) and related
activities, and includes electricity generation, transmission and distribution; and
•
the real estate segment (accounting for 6% of operating revenues in 2007), which
consists of SunCor’s real estate development and investment activities.
See Note 17 for financial information about the business segments.
APS ACC Proceedings
The key issue affecting Pinnacle West’s and APS’ financial outlook is adequate and timely
retail rate treatment by the ACC. Note 3 discusses the results of APS’ most recent retail rate
case as well as other rate matters.
Employees
At December 31, 2007, Pinnacle West employed approximately 7,600 people, including the
employees of its subsidiaries. Of these employees, approximately 6,800 were employees of APS,
including employees at jointly-owned generating facilities (approximately 3,000 employees) for
which APS serves as the generating facility manager. Approximately 800 people were employed by
Pinnacle West and its other subsidiaries. Pinnacle West’s principal executive offices are located
at 400 North Fifth Street, Phoenix, 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, Nuclear and Operating Committee and Human Resources Committee;
Ethics Policy and Standards of Business Practices;
•
Director Independence Standards;
•
Executive Officer Stock Ownership Guidelines; and
•
Restricted Stock Retention Policy.
Pinnacle West will post any amendments to the Code of Ethics and Ethics Policy and Standards
of Business Practices, and any waivers that are required to be disclosed by the rules of either the
SEC or the New York Stock Exchange, on its internet site. The information on Pinnacle West’s
internet site is not incorporated by reference into this report.
You can request a copy of these documents, excluding exhibits, by contacting Pinnacle West at
the following address: Pinnacle West Capital Corporation, Office of the Secretary, Station 9068,
P.O. Box 53999, Phoenix, 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, particularly
those affecting our rates and our recovery of fuel and purchased power costs;
•
the outcome of regulatory, legislative and judicial proceedings, both current and
future, relating to the restructuring of the electric industry and environmental matters (including those
related to climate change);
•
the ongoing restructuring of the electric industry, including decisions impacting
wholesale competition and the introduction of retail electric competition in Arizona;
•
market prices for electricity and natural gas;
•
volatile market liquidity, 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);
•
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 and Pacific Northwest energy
situations, 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);
•
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 value of our nuclear decommissioning trust, pension, and other
postretirement benefit plan assets, the amount of required contributions to Pinnacle
West’s pension plan and contributions to 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 or encumbrance of APS’ property used to provide retail electric service
and approve or receive prior notification of certain transactions between Pinnacle West, APS and
their respective affiliates.
APS is subject to varying degrees of competition from other investor-owned utilities in
Arizona (such as Southwest Gas Corporation), as well as cooperatives, municipalities, electrical
districts and similar types of governmental or non-profit organizations. In addition, some
customers, particularly industrial and large commercial customers, may own and operate generation
facilities to meet their own energy requirements.
In 1999, the ACC approved rules for the introduction of retail electric competition in
Arizona. As a result, as of January 1, 2001, all of APS’ retail customers were eligible to choose
alternate energy suppliers. However, there are currently no active retail competitors offering
unbundled energy or other utility services to APS’ customers. In 2000, an Arizona Superior Court
found that the rules were in part unconstitutional and in other respects unlawful, the latter
finding being primarily on procedural grounds, and invalidated all ACC orders authorizing
competitive electric services providers to operate in Arizona. In 2004, the Arizona Court of
Appeals invalidated some, but not all of the rules and upheld the invalidation of the orders
authorizing competitive electric service providers. In 2005, the Arizona Supreme Court declined to
review the Court of Appeals decision. To date, the ACC has taken no action on either the rules or
the prior 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. However, the ACC has scheduled a
hearing during the first quarter of 2008 to consider the new application of a competitive electric
service provider for authority to provide competitive electric services. Certain intervenors in
that proceeding have requested the ACC to dismiss the application because of, among other reasons,
the legal uncertainties
associated with the rules, as described above. The ACC has taken this motion to dismiss under
advisement. APS cannot predict when, and the extent to which, additional competitors will re-enter
APS’ service territory.
Wholesale
General
The FERC regulates rates for wholesale power sales and transmission services. See “Rate
Requests for Transmission and Ancillary Services” in Note 3 for information regarding APS’ pending
rate case at the FERC. During 2007, approximately 4.4% of APS’ electric operating revenues
resulted from such sales and services. APS’ wholesale activity primarily consists of managing fuel
and purchased power risks in connection with the costs of serving retail customer energy
requirements. APS also sells, in the wholesale market, its generation output that is not needed
for APS’ Native Load and, in doing so, competes with other utilities, power marketers and
independent power producers. Additionally, subject to specified parameters, APS markets, hedges
and trades principally in electricity and fuels.
BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY
General
APS was incorporated in 1920 under the laws of the state of Arizona and currently has
approximately 1.1 million customers. APS does not distribute any products. During 2007, no single
purchaser or user of energy accounted for more than 5.8% of electric revenues. See “Overview” and
“Regulation and Competition” above for additional background information about APS.
At December 31, 2007, APS employed approximately 6,800 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).
Portfolio Resources
APS’ sources of energy during 2007 were: coal – 36.8%; purchased power – 23.3%; nuclear –
21.5%; and gas – 18.4%. In accordance with GAAP, a substantial portion of APS’ purchased power
expense is netted against wholesale sales on the Consolidated Statements of Income. See Note 18.
The disclosure below provides a more detailed description of each of APS’ current sources of
energy.
Generation Facilities
APS’ portfolio of owned or leased generating capacity is provided in the table below:
14% owned Units 1, 2 and 3 at the Navajo Generating Station
315,000
Subtotal
1,741,000
Gas or Oil:
Two steam units at Ocotillo and two steam units at Saguaro
430,000
Twenty-two combustion turbine units
992,000
Seven combined cycle units
1,862,000
Subtotal
3,284,000
Nuclear:
29.1% owned or leased Units 1, 2 and 3 at Palo Verde
1,126,752
1
Solar
5,817
Total
6,157,569
1
As of January 26, 2008, nuclear capacity increased to 1,147,122 kW, reflecting
completion of the steam generator replacement program.
Coal Fueled Generating Facilities
Four Corners – Four Corners is a coal-fired power plant located in the northwestern corner of
New Mexico. APS operates the plant and owns 100% of Four Corners Units 1, 2 and 3 and 15% of Units
4 and 5. APS purchases all of Four Corners’ coal requirements from a supplier with a long-term
lease of coal reserves with the Navajo Nation. The Four Corners coal contract runs through 2016,
with options on APS’ part to extend the contract for five to fifteen additional years. The Four
Corners plant site is leased from the Navajo Nation and is also subject to an easement from the
federal government. See “Plant and Transmission Line Leases and Easements on Indian Lands” below
for additional information.
Cholla – Cholla is a coal-fired power plant located in northeastern Arizona. APS operates the
plant and owns 100% of Cholla Units 1, 2 and 3. PacifiCorp owns Cholla Unit 4 and APS operates
that unit for PacifiCorp. Cholla’s common facilities are jointly owned by APS and PacifiCorp. APS
purchases most of Cholla’s coal requirements from coal suppliers that mine all of the coal under
long-term leases of coal reserves with the Navajo Nation, the federal government and private
landholders. There are currently two coal contracts in place with two separate suppliers for
Cholla. One supplier is ramping down its supply to the plant, which will be complete in 2009, and
the other is ramping up its supply to the plant to provide Cholla’s full coal requirement by 2010.
This agreement runs through 2024. Additionally, APS may purchase a portion of Cholla’s coal
requirements on the spot market to take advantage of competitive pricing options and to supplement
coal required for increased operating capacity. APS believes that the current fuel contracts and
competitive fuel supply options ensure the continued operation of Cholla for its useful life.
In addition, APS has a long-term coal transportation contract.
Navajo Generating Station – The Navajo Generating Station is a coal-fired power plant located
in northern Arizona. Salt River Project operates the plant and APS owns a 14% interest in Navajo
Units 1, 2 and 3. The Navajo Generating Station’s coal requirements are purchased from a supplier
with long-term leases from the Navajo Nation and the Hopi Tribe. The Navajo Generating Station is
under contract with its coal supplier through 2011, with options to extend through 2019. The
Navajo Generating Station plant site is leased from the Navajo Nation and is also subject to an
easement from the federal government. See “Plant and Transmission Line Leases and Easements on
Indian Lands” below for additional information.
See “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 Note 11 for information regarding APS’ coal mine reclamation obligations.
Natural Gas Fueled Generating Facilities
APS has seven natural gas power plants located throughout Arizona, consisting of Redhawk,
located near the Palo Verde Nuclear Generating Station; Ocotillo, located in Tempe; Sundance,
located in Coolidge; West Phoenix, located in southwest Phoenix; Saguaro, located north of Tucson;
Douglas, located in the town of Douglas; and Yucca, located near Yuma. APS owns and operates each
plant with the exception of one combustion turbine unit and one steam unit at Yucca that are
operated by APS and owned by the Imperial Irrigation District.
Nuclear Generating Facility
Palo Verde Nuclear Generating Station – Palo Verde is a nuclear power plant located about 50
miles west of Phoenix, Arizona. APS operates the plant and owns 29.1% of Palo Verde Units 1 and 3
and about 17% of Unit 2. In addition, APS leases about 12.1% of Unit 2, resulting in a 29.1%
combined interest in that Unit. See “Palo Verde Leases” below for additional information regarding
the Palo Verde Unit 2 sale leaseback transactions.
Palo Verde Fuel Cycle – The fuel cycle for Palo Verde is comprised of the following stages:
•
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 are continually identifying their future resource needs and
negotiating arrangements to fill those needs. The Palo Verde participants have contracted for all
of Palo Verde’s requirements for uranium concentrates and conversion services through 2008 and for
approximately 50% of uranium concentrates and conversion services in 2009. The participants have
also contracted for all of Palo Verde’s enrichment services through 2013 and all of Palo
Verde’s fuel assembly fabrication services until at least 2015.
Spent Nuclear Fuel and Waste Disposal – See “Palo Verde Nuclear Generating Station” in Note 11
for a discussion of spent nuclear fuel and waste disposal.
Palo Verde Leases – In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain
common facilities in three separate sale leaseback transactions. APS accounts for these leases as
operating leases. The leases, which have terms of 29.5 years, contain options to renew the leases
and to purchase the property for fair market value at the end of the lease terms. See Notes 9 and
20 for additional information regarding the Palo Verde Unit 2 sale leaseback transactions.
Regulatory – Operation of each of the three Palo Verde units requires an operating license
from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in
April 1986 and Unit 3 in November 1987. The full power operating licenses, each valid for a period
of approximately 40 years, authorize APS, as operating agent for Palo Verde, to operate the three
Palo Verde units at full power.
NRC Inspection – In October 2006, the NRC conducted an inspection of the Palo Verde emergency
diesel generators after a Palo Verde Unit 3 generator started, but did not provide electrical output
during routine inspections on July 25 and September 22, 2006. On February 22, 2007, the NRC issued
a “white” finding (low to moderate safety significance) for this matter. Under the NRC’s Action
Matrix, this finding, coupled with a previous NRC “yellow” finding relating to a 2004 matter
involving Palo Verde’s safety injection systems, resulted in Palo Verde Unit 3 being placed in the
“multiple/repetitive degraded cornerstone” column of the NRC’s Action Matrix (“Column 4”), which
has resulted in an enhanced NRC inspection regime. Although only Palo Verde Unit 3 is in NRC’s
Column 4, in order to adequately assess the need for improvements, APS’ management has been
conducting site-wide assessments of equipment and operations.
Preliminary
work in support of the NRC’s enhanced inspection regime took
place throughout the
summer of 2007. On June 21, 2007, the NRC issued an initial confirmatory action letter confirming
APS’ commitments regarding specific actions APS will take to improve Palo Verde’s performance.
From October 1, 2007 through November 2, 2007, a team of NRC inspectors performed on-site in-depth
inspections of Palo Verde’s equipment and operations. The NRC’s inspection results were presented at
a public meeting on December 19, 2007, and documented in an NRC letter to APS dated February 1,2008 (the “Inspection Report”). The Inspection Report indicated that the facility is being
operated safely, but also identified certain performance deficiencies. On December 31, 2007, APS
submitted its improvement plan to the NRC, which addresses issues
identified by APS’ management
during its site-wide assessments of equipment and operations that occurred during 2007. The NRC
reviewed the adequacy of this improvement plan and issued a revised confirmatory action letter on
February 15, 2008 that outlines the actions APS must take in order for the NRC to return the Palo
Verde site to the NRC’s routine inspection and assessment process. This revised confirmatory
action letter was anticipated as part of the NRC’s inspection
procedure and a substantial majority of the actions required therein
were contained in APS’ improvement plan. In March 2008, APS
intends to submit to the NRC a revision to its improvement plan to address issues raised by the NRC
in its Inspection Report. The NRC will continue to provide increased oversight at Palo Verde until
the facility demonstrates sustained performance improvement. APS will
continue cooperating fully with
the NRC throughout this process.
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 for additional information about APS’ nuclear decommissioning costs.
Palo Verde Liability and Insurance Matters – See “Palo Verde Nuclear Generating Station” in
Note 11 for a discussion of the insurance maintained by the Palo Verde participants, including APS,
for Palo Verde.
Alternative Generation Sources
In connection with its ongoing resource planning efforts, APS continues to focus on increasing
the percentage of its energy that is produced by renewable resources. On November 1, 2006, the ACC
approved the Arizona Renewable Energy Standard and Tariff (the “Renewable Energy Standard”). Under
the Renewable Energy Standard, covered utilities like APS must supply an increasing percentage of
their retail electric energy sales from renewable resources, including solar, wind, biomass, biogas
and geothermal technologies. The renewable energy requirement increases from 1.5% in 2007 to 15%
in 2025. In addition, an increasing percentage of that requirement must be supplied from
distributed resources (generally speaking, small-scale renewable technologies that are located on
customers’ properties) to increase system reliability. The distributed resource requirement
increases from 5% of the overall renewable energy requirement in 2007 to 30% in 2012 and subsequent
years. APS currently has a diverse portfolio of renewable resources including wind from New Mexico,
geothermal from California and Utah, and solar and biomass in Arizona, which collectively will
generate over 120 MW of renewable energy for our customers.
On
February 8, 2008, APS entered into a Renewable Energy Purchase and
Sale Agreement under which APS agreed to purchase the energy and
related renewable energy credits from a solar power plant for a
period of thirty years after the plant begins commercial operation.
The plant, which will have a nameplate rating of 280 MW and a
projected
annual output of 900,000 MWh, will be located near Gila Bend,
Arizona, about 70 miles southwest of Phoenix, Arizona. The agreement
is subject to various conditions, including ACC approval. If these
conditions are met, commercial operation is expected during 2011.
APS
continues to actively consider
opportunities to enhance its renewable energy portfolio, both to ensure its compliance with the
Renewable Energy Standard and to meet the needs of its customer base.
In addition to its own available generating capacity, APS purchases electricity under various
arrangements. APS’ purchased power capacity under long-term contracts, as of December 31, 2007, is
summarized in the table below, and does not include the recently-executed solar agreement described under “Alternative Generation
Sources.” APS also purchases power through short-term markets to supplement
its long-term resources and hedge its energy requirements.
Deliveries expected to commence in 2008; expires 2028
3
Biomass Agreement
Deliveries expected to commence in 2008; expires 2022
14
(a)
The amount of electricity available to APS under this agreement is based in large part on
customer demand and is adjusted annually. Effective June 16, 2007, the seller, Salt River
Project, reduced the capacity available to APS by 150 MW. Additionally, Salt River Project
has elected to cancel this contract effective June 15, 2010.
(b)
This is a 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 2007, APS
received 571,342 MWh of energy under the capacity exchange. Additionally, under a
supplemental energy sales agreement, APS must also make additional offers of energy to
PacifiCorp each year through October 31, 2020. Pursuant to this requirement, during 2007,
PacifiCorp received offers of 1,093,175 MWh and purchased 174,340 MWh.
APS continually assesses its need for additional capacity resources to assure system
reliability. APS remains committed to seeking proposals from the competitive wholesale market for
filling its future resource needs, including renewable resource capacity.
Reserve Margin
APS’ 2007 peak one-hour demand on its electric system was recorded on August 13, 2007 at
7,545,100 kW, compared with the 2006 peak of 7,652,000 kW recorded on July 21, 2006. Taking into
account additional capacity then available to APS under long-term purchased power contracts as well
as APS generating capacity, APS had capacity of 6,783,000 kW to meet system demand on August 13,2007, for an installed reserve margin of negative 11.3%. 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 2007 peak amounted to 5,839,000 kW, for a margin of a negative 33.5%.
Firm purchases totaling 3,484,000 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 10.1%.
Transmission and Distribution Facilities
APS’ transmission facilities consist of approximately 5,759 pole miles of overhead lines and
approximately 45 miles of underground lines, 5,535 miles of which are located in Arizona. APS’
distribution facilities consist of approximately 12,471 miles of overhead lines and
approximately 16,210 miles of underground primary cable, all of which are located in Arizona. APS shares
ownership of some of its transmission facilities with other companies. The following table shows
APS’ jointly-owned interests in those transmission facilities recorded on the Consolidated Balance
Sheets at December 31, 2007:
Percent Owned
(Weighted Average)
Harquahala
80.0
%
Palo Verde – Estrella 500KV System
55.5
%
ANPP500KV System
35.8
%
Navajo Southern System
31.4
%
Four Corners Switchyards
27.5
%
Palo Verde – Yuma 500KV System
23.9
%
Phoenix – Mead System
17.1
%
Plant and Transmission Line Leases and Easements on Indian Lands
The Navajo Generating Station and Four Corners are located on land held under leases from the
Navajo Nation and also under easements from the federal government. The easement and lease for the
Navajo Generating Station expire in 2019 and the easement and lease for Four Corners expire in
2016. Each of the leases contains an option to extend for an additional 25-year period from the
end of the existing lease term, for a rental amount tied to the original rent payment adjusted
based on an index. The easements do not contain an express renewal option and it is unclear what
conditions to renewal or extension of the easements may be imposed. The ultimate cost of renewal
of the Navajo Generating Station and Four Corners leases and easements is uncertain. As noted
above under “Portfolio Resources — Coal Fueled Generating Facilities,” the coal contracted for use
in these plants is also located on Indian reservations.
Certain portions of the transmission lines that carry power from several of our power plants
are located on Indian lands pursuant to easements or other rights-of-way that are effective for
specified periods. Some of these rights-of-way have expired and our renewal applications have not
yet been acted upon by the appropriate Indian tribes. Other rights expire at various times in the
future and will have to be acted on for renewal by the applicable tribe at that time. The majority
of our transmission lines residing on Indian lands are on the Navajo Nation. The Four Corners and
Navajo Generating Station plant leases provide Navajo Nation consent to certain of the
rights-of-way for transmission lines related to those plants at a specified rental rate for the
original term of the
rights-of-way and for a like payment in any renewal period. In addition, a 1985 amendment to
the leases provides a formula for calculating payments for certain new and renewal rights-of-way.
However, some of our rights-of-way are not covered by the leases, or are granted by other Indian
tribes. In recent negotiations with other utilities or companies for renewal of similar
rights-of-way, certain of the affected Indian tribes have required payments substantially in excess
of amounts that we have paid in the past for such rights-of-way or that are typical for similar
permits across non-Indian lands; however, we are unaware of the underlying agreements and/or
specific circumstances surrounding these renewals. The ultimate cost of renewal of the
rights-of-way for our transmission lines is uncertain. We are monitoring these rights-of-way and
easement issues and are currently unable to predict the outcome of this matter.
Construction Program
During the years 2005 through 2007, APS incurred approximately $2.4 billion in capital
expenditures. APS’ capital expenditures for the years 2008 through 2010 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 $900 million in 2007. APS’ capital expenditures, including expenditures for
environmental control facilities, for the years 2008 through 2010, have been estimated as follows
(dollars in millions):
Estimate
2008
2009
2010
Major facilities:
Distribution
$
410
$
440
$
430
Generation
380
390
380
Transmission
220
320
290
Other
50
40
50
Total
$
1,060
$
1,190
$
1,150
The
above amounts do not include any impacts from the recent changes in the line extension policy (see Note 3). In
addition, the amounts exclude capitalized interest costs and include capitalized property taxes.
Nuclear fuel expenditures of approximately $90 million to $120 million per year are also included.
As part of our planning and cost control process, APS conducts a continuing review of its
construction program.
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations –
Liquidity and Capital Resources” in Item 7 for additional information about APS’ construction
program.
Environmental Matters
EPA Environmental Regulation
Regional Haze Rules On April 22, 1999, the EPA announced final regional haze rules. These
regulations required states to submit state implementation plans (SIPs) by December 2007 to
demonstrate “reasonable progress” towards achieving natural visibility conditions in certain “Class
I Areas,” including several on the Colorado Plateau. SIPs are required to consider and potentially
apply “best available retrofit technology” (BART) for certain older major stationary sources. The
rules allow nine western states and Indian tribes to follow an alternate implementation plan
and schedule for the Class I Areas. This alternate implementation plan is known as the Annex Rule.
On June 15, 2005, the EPA issued the Clean Air Visibility Rule, which amends the 1999 regional
haze rules by providing guidelines, known as the BART guidelines, for states to use in determining
which facilities must install controls and the type of controls the facilities must use. The EPA
also issued a Revised Annex Rule on October 13, 2006 to address a previous challenge and court
remand of that rule.
ADEQ is currently undertaking a rulemaking process to amend its SIP to reconcile it with the
Revised Annex Rule and to implement the Clean Air Visibility Rule requirements. ADEQ’s Regional
Haze SIPs were due to EPA Region 9 in December 2007, but are actually expected to be submitted
during 2008. As part of the rulemaking process, ADEQ is requiring certain sources in the state to
conduct BART analyses. Cholla and West Phoenix received letters from ADEQ asserting that the
plants are potentially subject to BART and requesting that we either perform a BART analysis on
each plant or provide information demonstrating that we are not subject to BART. We recently
completed a BART analysis for Cholla and submitted our BART recommendations to ADEQ on February 4,2008. ADEQ will now review our submission and determine what constitutes BART for Cholla. Our
recommendations include the installation of certain pollution control equipment that we believe
constitutes BART. Once we receive ADEQ’s final determination, we will have five years to complete
the installation of the equipment and to achieve the emission limits established by ADEQ. However,
in order to coordinate with the plant’s other scheduled activities, we are currently implementing
our recommended plan for Cholla on a voluntary basis. Costs related to the implementation of our
recommended plan are included in our environmental expenditure estimates (see “Management’s
Discussion and Analysis of Financial Condition and Results of Operation – Capital Expenditures” in
Item 7).
Because we believed that ADEQ’s baseline modeling for West Phoenix may have contained some
errors, we re-performed the baseline modeling using correct input and have determined that West
Phoenix is not subject to BART. We submitted these findings for West Phoenix to ADEQ, and ADEQ has
verbally informed us that West Phoenix is not subject to BART.
In addition, EPA Region 9 requested us to perform a BART analysis for Four Corners. We
recently completed the analysis and submitted it to the EPA on January 30, 2008. The EPA will now
review our submission and determine what constitutes BART for Four Corners. Our recommendations
include the installation of certain pollution control equipment that we believe constitutes BART.
Once we receive the EPA’s final determination, we will have five years to complete the installation
of the equipment and to achieve the emission limits established by EPA Region 9. Until the EPA
makes a final determination on this matter, we cannot accurately estimate the expenditures that may
be required. As a result, our current environmental expenditure estimates (see “Management’s
Discussion and Analysis of Financial Condition and Results of Operation – Capital Expenditures” in
Item 7) do not include amounts for Four Corners BART expenditures.
While we continue to monitor this matter, at the present time we cannot predict whether the
agencies will agree with our BART recommendations or, if the agencies disagree with our
recommendations, the nature of the BART controls the agencies may ultimately mandate and the
resulting financial or operational impact.
Mercury On March 15, 2005, the EPA issued the Clean Air Mercury Rule (CAMR) to control
mercury emissions from coal-fired power plants. This rule establishes performance standards
limiting mercury emissions from coal-fired power plants and establishes a two phased
market-based emissions trading program. Under the trading program, the EPA has assigned each state
a mercury emissions “budget” and each state must submit to the EPA a plan detailing how it will
meet its “budget.” In the first phase of the program, beginning in 2010, mercury emissions from
all coal-fired power plants in the country will be reduced from a total of 48 tons per year to 38
tons. In 2018, those emissions will be further reduced to 15 tons.
In November 2006, ADEQ submitted a SIP to the EPA to implement the CAMR. ADEQ’s SIP generally
incorporates the EPA’s model cap-and-trade program, but it includes additional requirements,
including the requirement to meet a 90% mercury removal control level or 0.0087 lbs/GWh, whichever
is greater, the requirement to obtain mercury allowances at a 2:1 ratio for any emissions that fall
below the specified control level, and the requirement, beginning in 2013, to consider clean coal
technologies as part of permitting any new generation.
On February 8, 2008, the U.S. Court of Appeals for the D.C. Circuit vacated the CAMR and the
EPA rule that allowed for the creation of the CAMR. While we continue to monitor this matter, we
cannot predict the timing of the court’s issuance of a mandate to vacate the rules, the response of
ADEQ or the scope, timing or impact of any alternate rules that may be proposed to address mercury
emissions.
We have installed, and may continue to install, certain of the equipment necessary to meet
these mercury standards. However, due to the recent U.S. Court of Appeals decision, we will
monitor the type and timing of any necessary equipment installation. The estimated costs expected
to be incurred over the next three years for such equipment are included in our environmental
expenditure estimates (see “Management’s Discussion and Analysis of Financial Condition and Results
of Operation – Capital Expenditures” in Item 7).
Federal Implementation Plan In September 1999, the EPA proposed FIPs to set air quality
standards at certain power plants, including Four Corners and the Navajo Generating Station. On
September 12, 2006, the EPA proposed revised FIPs to establish air quality standards at both of
these plants.
Four Corners FIP
On April 30, 2007, the EPA adopted a source specific FIP to set air quality standards at Four
Corners. The FIP essentially federalizes the requirements contained in the New Mexico State
Implementation Plan, which Four Corners has historically followed. The FIP also includes a
requirement to maintain and enhance dust suppression methods. On July 2, 2007, APS filed a
petition for review in the United States District Court of Appeals for the Tenth Circuit seeking
revisions to the FIP to clarify certain requirements and allow operational flexibility. The Sierra
Club has intervened in this action. On July 6, 2007, the Sierra Club and other parties filed a
petition for review with the same court challenging the FIP’s compliance with the Clean Air Act and
we have intervened in their action. In our lawsuit, we challenge two key provisions of the FIP: a
20% opacity limit on certain fugitive dust emissions, which the EPA filed a motion to remand and
vacate in early December 2007, and a 20% stack opacity limit on Units 4 and 5. Briefing in this
case is now complete, and the court is next expected to determine whether to hold oral arguments on
the matter, as requested by the EPA. Although we cannot predict the outcome or the timing of these
matters, we do not believe that they will have a material adverse impact on our financial position,
results of operations or cash flows.
The proposed FIP for the Navajo Generating Station is still pending. APS cannot currently
predict the effect of this proposed FIP on its financial position, results of operations or cash
flows, or whether the proposed FIP will be adopted in its current form.
Superfund Superfund establishes liability for the cleanup of hazardous substances found
contaminating the soil, water or air. Those who generated, transported or disposed of hazardous
substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often
jointly and severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA
considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3
(OU3) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and
Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS
facilities within OU3. Because the investigation has not yet been completed and ultimate
remediation requirements are not yet finalized, at the present time neither APS nor Pinnacle West
can accurately estimate the expenditures that may be required.
Manufactured Gas Plant Sites APS is currently investigating properties, which it now owns or
which were previously owned by it or its corporate predecessors, that were at one time sites of, or
sites associated with, manufactured gas plants. APS is taking action to voluntarily remediate
these sites. APS does not expect these matters to have a material adverse effect on its financial
position, results of operations, cash flows or liquidity.
Navajo Nation Environmental Issues
Four Corners and the Navajo Generating Station are located on the Navajo Reservation and are
held under easements granted by the federal government as well as leases from the Navajo Nation.
See “Portfolio Resources – Coal Fueled Generating Facilities” above for additional information
regarding these plants.
In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control
Act, the Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively,
the Navajo Acts). The Navajo Acts purport to give the Navajo Nation Environmental Protection
Agency authority to promulgate regulations covering air quality, drinking water and pesticide
activities, including those activities that occur at Four Corners and the Navajo Generating
Station. On October 17, 1995, the Four Corners participants and the Navajo Generating Station
participants each filed a lawsuit in the District Court of the Navajo Nation, Window Rock District,
challenging the applicability of the Navajo Acts as to Four Corners and the Navajo Generating
Station. The Court has stayed these proceedings pursuant to a request by the parties, and the
parties are seeking to negotiate a settlement.
In April 2000, the Navajo Tribal Council approved operating permit regulations under the
Navajo Nation Air Pollution Prevention and Control Act. APS believes the regulations fail to
recognize that the Navajo Nation did not intend to assert jurisdiction over Four Corners and the
Navajo Generating Station. On July 12, 2000, the Four Corners participants and the Navajo
Generating Station participants each filed a petition with the Navajo Supreme Court for review of
the operating permit regulations. Those proceedings have been stayed, pending the settlement
negotiations mentioned above. APS cannot currently predict the outcome of this matter.
On May 18, 2005, APS, Salt River Project, as the operating agent for the Navajo Generating
Station, and the Navajo Nation executed a Voluntary Compliance Agreement (“VCA”) to resolve their
disputes regarding the Navajo Nation Air Pollution Prevention and Control Act. On March 21, 2006,
the EPA determined that the Navajo Nation was eligible for “treatment as a state” for the purpose
of entering into a supplemental delegation agreement with the EPA to administer the Clean Air Act
Title V, Part 71 federal permit program over Four Corners and the Navajo Generating Station. The
EPA entered into the supplemental delegation agreement with the Navajo Nation on the same day.
Because the EPA’s approval was consistent with the requirements of the VCA, APS sought dismissal of
the pending litigation in the Navajo Nation Supreme Court, as well as the pending litigation in the
Navajo Nation District Court to the extent the claims relate to the Clean Air Act, and the Courts
have dismissed the claims accordingly. The agreement does not address or resolve any dispute
relating to other Navajo Acts. APS cannot currently predict the outcome of this matter.
Climate Change
In 2007, six western states (Arizona, California, New Mexico, Oregon, Utah and Washington) and
two Canadian provinces (British Columbia and Manitoba) entered into an accord, the Western Climate
Initiative (the “Initiative”), to reduce greenhouse gas emissions from automobiles and certain
industries, including utilities. In August 2007, the Initiative participants set a goal of
reducing greenhouse gas emissions 15% below 2005 levels by 2020. By August 2008, the Initiative
participants intend to develop a plan for implementation of this goal. Any such implementation
would require independent action by each individual state’s or province’s legislature or Governor
to adopt a version of the plan. While we continue to monitor the impact of the Initiative, at the
present time we cannot predict what form it will ultimately take, whether it will be implemented
or, if it is implemented, what impact it will have on our operations.
We are currently developing a Climate Management Report to comply with an ACC order in which
the ACC directed APS to undertake a climate management plan, carbon emission reduction study and
commitment and action plan with public input and ACC review. We expect to complete the report in
2008.
In January 2008, APS joined the Climate Registry as a Founding Reporter. Founding Reporters
are companies that voluntarily join the non-profit organization before May 2008 to measure and
report greenhouse gas emissions in a common, accurate and transparent manner consistent across
industry sectors and borders. Pinnacle West also makes available on its website
(www.pinnaclewest.com) its annual Corporate Responsibility Report, which provides information
related to the Company, its approach to sustainability and its workplace and environmental
performance. The information on Pinnacle West’s website, including the Corporate Responsibility
Report, is not incorporated by reference into this report.
Water Supply
Assured supplies of water are important for APS’ generating plants. At the present time, APS
has adequate water to meet its needs. However, conflicting claims to limited amounts of water in
the southwestern United States have resulted in numerous court actions.
Both groundwater and surface water in areas important to APS’ operations have been the subject
of inquiries, claims and legal proceedings, which will require a number of years to resolve.
APS is one of a number of parties in a proceeding, filed March 13, 1975, before the Eleventh
Judicial District Court in New Mexico to adjudicate rights to a stream system from which water for
Four Corners is derived. An agreement reached with the Navajo Nation in 1985, however, provides
that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will
provide, for an agreed upon cost, sufficient water from its allocation to offset the loss.
A summons served on APS in early 1986 required all water claimants in the Lower Gila River
Watershed in Arizona to assert any claims to water on or before January 20, 1987, in an action
pending in Maricopa County, Arizona, Superior Court. Palo Verde is located within the geographic
area subject to the summons. APS’ rights and the rights of the other Palo Verde participants to
the use of groundwater and effluent at Palo Verde are potentially at issue in this action. As
operating agent of Palo Verde, APS filed claims that dispute the court’s jurisdiction over the Palo
Verde participants’ groundwater rights and their contractual rights to effluent relating to Palo
Verde. Alternatively, APS seeks confirmation of such rights. Five of APS’ other power plants are
also located within the geographic area subject to the summons. APS’ claims dispute the court’s
jurisdiction over its groundwater rights with respect to these plants. Alternatively, APS seeks
confirmation of such rights. In November 1999, the Arizona Supreme Court issued a decision
confirming that certain groundwater rights may be available to the federal government and Indian
tribes. In addition, in September 2000, the Arizona Supreme Court issued a decision affirming the
lower court’s criteria for resolving groundwater claims. Litigation on both of these issues has
continued in the trial court. In December 2005, APS and other parties filed a petition with the
Arizona Supreme Court requesting interlocutory review of a September 2005 trial court order
regarding procedures for determining whether groundwater pumping is affecting surface water rights.
The Court denied the petition in May 2007, and the trial court is now proceeding with
implementation of its 2005 order. No trial date concerning APS’ water rights claims has been set
in this matter.
APS has also filed claims to water in the Little Colorado River Watershed in Arizona in an
action pending in the Apache County, Arizona, Superior Court, which was originally filed on
September 5, 1985. APS’ groundwater resource utilized at Cholla is within the geographic area
subject to the adjudication and, therefore, is potentially at issue in the case. APS’ claims
dispute the court’s jurisdiction over its groundwater rights. Alternatively, APS seeks
confirmation of such rights. A number of parties are in the process of settlement negotiations
with respect to certain claims in this matter. Other claims have been identified as ready for
litigation in motions filed with the court. No trial date concerning APS’ water rights claims has
been set in this matter.
Although the above matters remain subject to further evaluation, 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 future operations of the plant. The effect
of the drought cannot be fully assessed at this time, and APS cannot predict the ultimate outcome,
if any, of the drought or whether the drought will adversely affect the amount of power available,
or the price thereof, from Four Corners.
On August 8, 2005, the President signed the Energy Policy Act of 2005 into law. The Act
includes a wide range of provisions addressing many aspects of the energy industry. Specifically,
with respect to the electric utility industry, the Act includes provisions that, among other
things, repeals the Public Utility Holding Company Act of 1935 through enactment of the Public
Utility Holding Company Act of 2005, effective as of February 8, 2006, creates incentives for the
construction of transmission infrastructure, eliminates the statutory restrictions on ownership of
qualifying facilities by electric utilities, establishes civil penalty authority over electric
utilities and expands the authority of the FERC to include overseeing the reliability of the bulk
power system. While we continue to monitor the impact of this new federal legislation, we cannot
predict the impact of this Act on our operations at this time.
BUSINESS OF SUNCOR DEVELOPMENT COMPANY
SunCor was incorporated in 1965 under the laws of Arizona and is a developer of residential,
commercial and industrial real estate projects in Arizona, Idaho, New Mexico and Utah. The
principal executive offices of SunCor are located at 80 East Rio Salado Parkway, Suite 410, Tempe,
Arizona85281 (telephone 480-317-6800). SunCor and its subsidiaries had approximately 650
employees at December 31, 2007.
At December 31, 2007, SunCor had total assets of about $670 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, and mixed-use residential, commercial, office and industrial projects.
SunCor
projects include six master-planned communities and several commercial and
residential projects. Four of the master-planned communities and the commercial and residential
projects are in Arizona. Other master-planned communities are located
in Idaho, New Mexico and Utah.
SunCor’s operating revenues were approximately $215 million in 2007, $400 million in 2006 and
$338 million in 2005. SunCor’s net income was approximately $24 million in 2007, $61 million in
2006 and $56 million in 2005. 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.
See Note 6 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 OTHER SUBSIDIARIES
APSES was incorporated in 1998 under the laws of Arizona and provides energy-related products
and services (such as energy master planning, energy use consultation and facility audits,
cogeneration analysis and installation, and project management) and competitive commodity-related
energy services (such as direct access commodity contracts, energy procurement and energy supply
consultation) to commercial and industrial retail customers in the western United States.
Recently, APSES has de-emphasized its commodity-related energy services. APSES had approximately
60
APSES had a net loss of $4 million in 2007, a net loss of $3 million in 2006 and a net loss of
$6 million in 2005. At December 31, 2007, APSES had total assets of $95 million.
El Dorado was incorporated in 1983 under the laws of Arizona. El Dorado owns minority
interests in several energy-related investments and Arizona community-based ventures. El Dorado’s
short-term goal is to prudently realize the value of its existing investments. On a long-term
basis, Pinnacle West may use El Dorado, when appropriate, for investments that are strategic to the
business of generating, distributing and marketing electricity. El Dorado’s offices are located at
400 North Fifth Street, Phoenix, Arizona85004 (telephone 602-250-3517).
El Dorado had a net loss of $6 million in 2007, a net loss of $4 million in 2006 and net
income of $4 million in 2005. Income taxes related to El Dorado are recorded by Pinnacle West. At
December 31, 2007, El Dorado had total assets of $30 million.
Pinnacle West Marketing & Trading began operations in early 2007. These operations were
conducted by a division of Pinnacle West through the end of 2006. Pinnacle West
Marketing & Trading had a net loss of $11 million in 2007. At December 31, 2007, Pinnacle West
Marketing & Trading had total assets of $73 million.
ITEM 1A. RISK FACTORS
In addition to the factors affecting specific business operations identified in connection
with the description of these operations contained elsewhere in this report, set forth below are
risks and uncertainties that could affect our financial results. Unless otherwise indicated or the
context otherwise requires, the following risks and uncertainties apply to Pinnacle West and its
subsidiaries, including APS.
APS is subject to comprehensive government regulation by several federal, state and local
regulatory agencies that could have a material adverse impact on its business and results of
operations.
APS is subject to comprehensive regulation by several federal, state and local regulatory
agencies that significantly influence its business and results of operations. The ACC regulates
APS’ retail electric rates and APS’ issuance of securities. The ACC must also approve any transfer
of APS’ property used to provide retail electric service and approve or receive prior notification
of certain transactions between us, APS and our respective affiliates. While approved electric
rates are intended to permit APS to recover its costs of service and earn a reasonable rate of
return, the profitability of APS is affected by the rates it may charge. Consequently, our
financial condition and results of operations are dependent upon the satisfactory resolution of
APS’ retail rate proceedings and ancillary matters which are before or which may come before the
ACC.
APS is required to have numerous permits, approvals and certificates from the agencies that
regulate APS’ business. The FERC, the NRC, the EPA, and the ACC regulate many aspects of our
utility operations, including siting and construction of facilities, customer service and, as noted
in the preceding paragraph, the rates that APS can charge customers. We believe the necessary
permits, approvals and certificates have been obtained for APS’ existing operations and that APS’
business is
conducted in accordance with applicable laws in all material respects. However, changes in
regulations or the imposition of additional regulations could have an adverse impact on our results
of operations. We are also unable to predict the impact on our business and operating results from
pending or future regulatory activities of any of these agencies.
The NRC has broad authority under federal law to impose licensing and safety-related
requirements for the operation of nuclear generation facilities. In the event of noncompliance,
the NRC has the authority to impose monetary civil penalties or a progressively increased
inspection regime that could ultimately result in the shut down of a unit, or both, depending upon
the NRC’s assessment of the severity of the situation, until compliance is achieved. In early
2007, the NRC placed Palo Verde Unit 3 in the “multiple/repetitive degraded cornerstone” column of
the NRC’s Action Matrix (“Column 4”), which has resulted in an enhanced NRC inspection regime,
including on-site in-depth inspections of Palo Verde equipment and operations. Although only Palo
Verde Unit 3 is in NRC’s Column 4, in order to adequately assess the need for improvements, APS
management has been conducting site-wide assessments of equipment and operations. APS continues to
cooperate fully with the NRC throughout this process. The enhanced NRC inspection regime and APS’
ongoing commitment to the conservatively safe operation of Palo Verde could result in NRC action or
an APS decision to shut down one or more units in the event of noncompliance with operating
requirements or in light of other operational considerations.
APS is subject to numerous environmental laws and regulations that may increase its cost of
operations, impact its business plans, or expose it to environmental liabilities.
APS is subject to numerous environmental laws and regulations affecting many aspects of its
present and future operations, including air emissions, water quality, wastewater discharges, solid
waste, and hazardous waste. These laws and regulations can result in increased capital, operating,
and other costs, particularly with regard to enforcement efforts focused on power plant emissions
obligations. These laws and regulations generally require APS to obtain and comply with a wide
variety of environmental licenses, permits, inspections and other approvals. If there is a delay
in obtaining any required environmental regulatory approval, or if APS fails to obtain, maintain or
comply with any such approval, operations at affected facilities could be suspended or subject to
additional expenses. In addition, failure to comply with applicable environmental laws and
regulations could result in civil liability or criminal penalties. Both public officials and
private individuals may seek to enforce applicable environmental laws and regulations. We cannot
predict the outcome (financial or operational) of any related litigation that may arise.
In addition, we may be a responsible party for environmental clean up at sites identified by a
regulatory body. We cannot predict with certainty the amount and timing of all future expenditures
related to environmental matters because of the difficulty of estimating clean-up costs. There is
also uncertainty in quantifying liabilities under environmental laws that impose joint and several
liability on all potentially responsible parties.
We cannot be sure that existing environmental regulations will not be revised or that new
regulations seeking to protect the environment will not be adopted or become applicable to us.
Revised or additional regulations that result in increased compliance costs or additional operating
restrictions, particularly if those costs incurred by APS are not fully recoverable from APS’
customers, could have a material adverse effect on our financial position, results of operations or
cash flows.
Concern over climate change could result in significant legislative and regulatory efforts to
limit greenhouse gas emissions or related litigation, which may increase APS’ cost of operations.
Concern over climate change, deemed by many to be induced by rising levels of greenhouse gases
in the atmosphere, has led to significant legislative and regulatory efforts to limit
CO2, which is a major byproduct of the combustion of fossil fuel, and other greenhouse
gas emissions. In addition, lawsuits have been filed against companies that emit greenhouse gasses, including a recent lawsuit filed against us and several other
utilities, seeking damages related to climate change. In the past several years, the United States Congress has considered bills that
would regulate domestic greenhouse gas emissions, but such bills have not received sufficient
Congressional approval to date to become law; however, there is growing consensus that some form of
regulation or legislation is likely to occur in the near future at the federal level with respect
to greenhouse gas emissions. If the United States Congress, or individual states or groups of
states in which we operate, ultimately pass legislation regulating the emissions of greenhouse
gases, any resulting limitations on generation facility CO2 and other greenhouse gas
emissions could result in the creation of substantial additional costs in the form of taxes,
emissions allowances or required equipment upgrades and could have a material adverse impact on all
fossil fuel fired generation facilities (particularly coal fired facilities), including ours.
There are inherent risks in the operation of nuclear facilities, such as environmental, health
and financial risks and the risk of terrorist attack.
Through APS, we have an ownership interest in and operate, on behalf of a group of owners,
Palo Verde, which is the largest nuclear electric generating facility in the United States. Palo
Verde is subject to environmental, health and financial risks such as the ability to dispose of
spent nuclear fuel; the ability to maintain adequate reserves for decommissioning; potential
liabilities arising out of the operation of these facilities; the costs of securing the facilities
against possible terrorist attacks; and unscheduled outages due to equipment and other problems.
APS maintains nuclear decommissioning trust funds and external insurance coverage to minimize its
financial exposure to some of these risks; however, it is possible that damages could exceed the
amount of insurance coverage.
The NRC has broad authority under federal law to impose licensing and safety-related
requirements for the operation of nuclear generation facilities. In the event of noncompliance,
the NRC has the authority to impose monetary civil penalties or a progressively increased
inspection regime, which could ultimately result in the shut down of a unit, or both, depending
upon its assessment of the severity of the situation, until compliance is achieved. See the first
risk factor above for a discussion of the enhanced NRC inspection regime currently in effect at
Palo Verde and the related operational and regulatory implications. In addition, although we have
no reason to anticipate a serious nuclear incident at Palo Verde, if an incident did occur, it
could materially and adversely affect our results of operations or financial condition. A major
incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the
operation or licensing of any domestic nuclear unit.
The operation of Palo Verde requires licenses that need to be periodically renewed and/or
extended. We do not anticipate any problems renewing these licenses. However, as a result of
potential terrorist threats and increased public scrutiny of utilities, the licensing process could
result in increased licensing or compliance costs that are difficult or impossible to predict.
The operation of power generation facilities involves risks that could result in unscheduled
power outages or reduced output, which could materially affect our results of operations.
The operation of power generation facilities involves certain risks, including the risk of
breakdown or failure of equipment, fuel interruption, and performance below expected levels of
output or efficiency. Unscheduled outages, including extensions of scheduled outages due to
mechanical failures or other complications occur from time to time and are an inherent risk of our
business. If APS’ facilities operate below expectations, we may lose revenue or incur additional
expenses.
Deregulation or restructuring of the electric industry may result in increased competition,
which could have a significant adverse impact on our business and our financial results.
In 1999, the ACC approved rules for the introduction of retail electric competition in
Arizona. Retail competition could have a significant adverse financial impact on APS due to an
impairment of assets, a loss of retail customers, lower profit margins or increased costs of
capital. Although some very limited retail competition existed in APS’ service area in 1999 and
2000, there are currently no active retail competitors offering unbundled energy or other utility
services to APS’ customers. As a result, we cannot predict when, and the extent to which,
additional competitors will re-enter APS’ service territory.
As a result of changes in federal law and regulatory policy, competition in the wholesale
electricity market has greatly increased due to a greater participation by traditional electricity
suppliers, non-utility generators, independent power producers, and wholesale power marketers and
brokers. This increased competition could affect APS’ load forecasts, plans for power supply and
wholesale energy sales and related revenues. As a result of the changing regulatory environment
and the relatively low barriers to entry, we expect wholesale competition to increase.
Changes in technology may adversely affect our business.
Research and development activities are ongoing to improve alternative technologies to produce
power, including fuel cells, micro turbines, clean coal and coal gasification, photovoltaic (solar)
cells and improvements in traditional technologies and equipment, such as more efficient gas
turbines. Advances in these, or other technologies could reduce the cost of power production,
making APS’ generating facilities less competitive. In addition, advances in technology could
reduce the demand for power supply, which could adversely affect APS’ business.
Our results of operations can be adversely affected by weather conditions.
Weather conditions directly influence the demand for electricity and affect the price of
energy commodities. Electric power demand is generally a seasonal business. In Arizona, demand
for power peaks during the hot summer months, with market prices also peaking at that time. As a
result, our overall operating results fluctuate substantially on a seasonal basis. In addition,
APS has historically sold less power, and consequently earned less income, when weather conditions
are milder. As a result, unusually mild weather could diminish our results of operations and harm
our financial condition.
Our cash flow largely depends on the performance of our subsidiaries.
We conduct our operations primarily through subsidiaries. Substantially all of our
consolidated assets are held by such subsidiaries. Accordingly, our cash flow is dependent upon
the earnings and cash flows of these subsidiaries and their distributions to us. The subsidiaries
are separate and distinct legal entities and have no obligation to make distributions to us.
The debt agreements of some of our subsidiaries may restrict their ability to pay dividends,
make distributions or otherwise transfer funds to us. An ACC financing order requires APS to
maintain a common equity ratio of at least 40% and does not allow APS to pay common dividends if
the payment would reduce its common equity below that threshold. The common equity ratio, as
defined in the ACC order, is common equity divided by the sum of common equity and long-term debt,
including current maturities of long-term debt.
Our ability to meet our debt service obligations could be adversely affected because our debt
securities are structurally subordinated to the debt securities and other obligations of our
subsidiaries.
Because we are structured as a holding company, all existing and future debt and other
liabilities of our subsidiaries will be effectively senior in right of payment to our debt
securities. None of the indentures under which we or our subsidiaries may issue debt securities
limits our ability or the ability of our subsidiaries to incur additional debt in the future. The
assets and cash flows of our subsidiaries will be available, in the first instance, to service
their own debt and other obligations. Our ability to have the benefit of their assets and cash
flows, particularly in the case of any insolvency or financial distress affecting our subsidiaries,
would arise only through our equity ownership interests in our subsidiaries and only after their
creditors have been satisfied.
Financial market disruptions may increase our financing costs or limit our access to the
credit markets, which may adversely affect our liquidity and our ability to implement our financial
strategy.
We rely on access to short-term money markets, longer-term capital markets and the bank
markets as a significant source of liquidity and for capital requirements not satisfied by the cash
flow from our operations. We believe that we will maintain sufficient access to these financial
markets based upon current credit ratings. However, certain market disruptions may increase our
cost of borrowing or adversely affect our ability to access one or more financial markets. Such
disruptions could include:
•
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;
the overall health of the utility or real estate industry.
Changes in economic conditions could result in higher interest rates, which would increase our
interest expense on our debt and reduce funds available to us for our current plans. Additionally,
an increase in our leverage could adversely affect us by:
•
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 with our competitors that have
less debt.
Recent sub-prime mortgage issues have adversely affected the overall financial markets,
generally resulting in increased interest rates, reduced access to the capital markets, and actual
or potential downgrades of bond insurers, among other negative matters. The interest rates on
certain issues of APS’ pollution control bonds are periodically reset through auction processes.
These bonds are supported by bond insurance policies provided by Ambac, and the interest rates on
those bonds are directly affected by the rating of the bond insurer. Accordingly, interest rates
on these bonds have recently increased. We do not expect, however,
that any such increase will have a material adverse impact on our
financial position, results of operations, cash flows or liquidity.
A reduction in our credit ratings could materially and adversely affect our business,
financial condition and results of operations.
We cannot be sure that any of our current ratings will remain in effect for any given period
of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its
judgment, circumstances in the future so warrant. Any downgrade could limit our access to capital
and increase our borrowing costs, which would diminish our financial results. We would likely be
required to pay a higher interest rate in future financings, and our potential pool of investors
and funding sources could decrease. In addition, borrowing costs under certain of our existing
credit facilities depend on our credit ratings. A downgrade could also require us to provide
additional support in the form of letters of credit or cash or other collateral to various
counterparties. If our short-term ratings were to be lowered, it could limit our access to the
commercial paper market. We note that the ratings from rating agencies are not recommendations to
buy, sell or hold our securities and that each rating should be evaluated independently of any
other rating.
The use of derivative contracts in the normal course of our business and changing interest
rates and market conditions could result in financial losses that negatively impact our results of
operations.
Our operations include managing market risks related to commodity prices and, subject to
specified risk parameters, engaging in marketing and trading activities intended to profit from
market price movements. We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal, and emissions allowances. We have
established procedures to manage risks associated with these market fluctuations by utilizing
various commodity
derivatives, including exchange-traded futures and options and over-the-counter forwards,
options, and swaps. As part of our overall risk management program, we enter into derivative
transactions to hedge purchases and sales of electricity, fuels, and emissions allowances and
credits. The changes in market value of such contracts have a high correlation to price changes in
the hedged commodity.
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We
use a risk management process to assess and monitor the financial exposure of all counterparties.
Despite the fact that the majority of trading counterparties are rated as investment grade by the
rating agencies, there is still a possibility that one or more of these companies could default,
resulting in a material adverse impact on our earnings for a given period.
Changing interest rates affect interest paid on variable-rate debt and interest earned on
variable-rate securities in our pension plan, other postretirement benefit plan and nuclear
decommissioning trust funds. Our policy is to manage interest rates through the use of a
combination of fixed-rate and floating-rate debt. The pension plan and other postretirement
benefit liabilities are also impacted by the discount rate, which is the interest rate used to
discount future pension and other postretirement benefit obligations. Declining interest rates
impact the discount rate, and may result in increases in pension and other postretirement benefit
costs, cash contributions, regulatory assets, and charges to other comprehensive income. The
pension plan, other postretirement benefit and nuclear decommissioning trust funds also have risks
associated with changing market values of fixed income and equity investments. A significant
portion of the pension costs and other postretirement benefit costs and all of the nuclear
decommissioning costs are recovered in regulated electricity prices.
The market price of our common stock may be volatile.
The market price of our common stock could be subject to significant fluctuations in response
to factors such as the following, some of which are beyond our control:
•
variations in our quarterly operating results;
•
operating results that vary from the expectations of management, securities analysts
and investors;
•
changes in expectations as to our future financial performance, including financial
estimates by securities analysts and investors;
•
developments generally affecting industries in which we operate, particularly the
energy distribution and energy generation industries;
•
announcements by us or our competitors of significant contracts, acquisitions, joint
marketing relationships, joint ventures or capital commitments;
•
announcements by third parties of significant claims or proceedings against us;
•
favorable or adverse regulatory or legislative developments;
future sale of equity or equity-linked securities; and
•
general domestic and international economic conditions.
In addition, the stock market in general has experienced volatility that has often been
unrelated to the operating performance of a particular company. These broad market fluctuations
may adversely affect the market price of our common stock.
We may enter into credit and other agreements from time to time that restrict our ability to
pay dividends.
Payment of dividends on our common stock may be restricted by credit and other agreements
entered into by us from time to time. There are currently no material restrictions on our ability
to pay dividends under any such agreement.
SunCor’s business and financial performance could be adversely affected by a variety of
factors affecting the real estate market.
SunCor’s business and financial performance could continue to be adversely affected by a
variety of factors affecting the real estate market, including downward changes in general
economic, real estate construction or other business conditions; the potential overvaluation of
land and new homes, which could result in an economic down cycle for the homebuilding industry;
future increases in interest rates, reductions in mortgage availability or increases in the
effective costs of owning a home, which could prevent potential customers from buying homes in
SunCor’s developments; competition for homebuyers or commercial customers or partners, which could
reduce SunCor’s profitability; supply shortages and other risks related to the demand for skilled
labor and building materials, which could increase costs and delay deliveries; government
regulations, which could increase the cost and limit the availability of SunCor’s development,
homebuilding and commercial projects; and inflation, which could result in increased costs that
SunCor may not be able to recoup if demand declines.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Neither Pinnacle West nor APS has received written comments regarding its periodic or current
reports from the SEC staff that were issued 180 days or more preceding the end of its 2007 fiscal
year and that remain unresolved.
See “Business of Arizona Public Service Company – Portfolio Resources” in Item 1 for the
location and a description of our principal properties.
See “Business of Arizona Public Service Company – Environmental Matters” and “Water Supply” in
Item 1 with respect to matters having a possible impact on the operation of certain of APS’ power
plants.
See “Business of Arizona Public Service Company – Construction Program” in Item 1 and
“Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity
and Capital Resources” in Item 7 for a discussion of APS’ construction program.
Real Estate Segment Properties
See “Business of SunCor Development Company” in Item 1 for information regarding SunCor’s
properties. Substantially all of SunCor’s debt is collateralized by interests in certain real
property.
See “Business of Arizona Public Service Company – Environmental Matters” and “Water Supply” in
Item 1 with regard to pending or threatened litigation and other disputes.
See Note 3 with respect to retail rate proceedings before the ACC.
See Note 11 with regard to a lawsuit against APS and the other Navajo Generating Station
participants and for information relating to the FERC proceedings on California energy market
issues.
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
The executive officers of Pinnacle West are elected no less often than annually and may be
removed by the Board of Directors at any time. The terms served by the named officers in their
current positions and their principal occupations (in addition to those stated in the table) of
such officers for the past five years have been as follows:
Mr. Post was elected Chairman of the Board effective February 2001, and Chief Executive
Officer effective February 1999. He has served as an officer of Pinnacle West since 1995 in the
following capacities: from August 1999 to February 2001 as President; from February 1997 to
February 1999 as President; and from June 1995 to February 1997 as Executive Vice President. Mr.
Post is also Chairman of the Board (since February 2001) of APS. He was President of APS from
February 1997 until October 1998 and he was Chief Executive Officer from February 1997 until
October 2002. Mr. Post is also a director of Phelps Dodge Corporation.
Mr. Davis was elected President effective February 2001 and Chief Operating Officer effective
September 2003. Prior to that time, he was Chief Operating Officer and Executive Vice President of
Pinnacle West (April 2000 – February 2001) and Executive Vice President, Commercial Operations of
APS (September 1996 – October 1998). Mr. Davis was also President of APS (October 1998 – December
2006) and is Chief Executive Officer of APS (since October 2002). Mr. Davis has announced that he
will retire effective March 1, 2008. He is also a director of APS.
Mr. Brandt was elected Executive Vice President of Pinnacle West in September 2003. Prior to
that time, he was Senior Vice President of Pinnacle West (December 2002 – September 2003). He was
also elected Chief Financial Officer of Pinnacle West in December 2002. Mr. Brandt was also
elected President of APS in December 2006. Prior to that time, he was Executive Vice President of
APS (September 2003 – December 2006) and Senior Vice President of APS (January 2003 – September
2003). He was also elected Chief Financial Officer of APS in January
of 2003. Effective March 1, 2008, Mr. Brandt will serve as President
and Chief Operating Officer of Pinnacle West, and President and Chief
Executive Officer of APS.
Mr. Bennett was elected to his present position effective November 2007. Prior to that time,
he was Vice President, Customer Service of APS (May 1991 – November 2007).
Mr. Denman was elected to his present position effective November 2007. Prior to that time,
he was Vice President, Fossil Generation of APS (April 1997 – November 2007).
Mr. Edington was elected to his present position effective November 2007. Prior to that time,
he was Senior Vice President and Chief Nuclear Officer of APS (January 2007 – November 2007). He
was previously with Entergy Corporation, serving as Site Vice President and Chief Nuclear Officer
of Cooper Generating Station (2003 – January 2007) and Vice President of Operator Training, Indian
Point Energy Center (2001 – 2003).
Mr. Flores was elected to his present position in September 2003. Prior to that time, he was
Executive Vice President, Corporate Business Services of Pinnacle West (July 1999 – September
2003). He was also Executive Vice President, Corporate Business Services of APS (October 1998 –
July 1999). Mr. Flores has announced that he will retire effective March 31, 2008.
Mr. Froggatt was elected to his present position in October 2002. Prior to that time, he was
Vice President and Controller of Pinnacle West (August 1999 – October 2002), Controller of Pinnacle
West (July 1999 – August 1999) and Controller of APS (July 1997 – July 1999).
Ms. Gomez was elected to her present position in February 2004. Prior to that time, she was
Treasurer of Pinnacle West (August 1999 – February 2004) and Manager, Treasury Operations of APS
(1997 – 1999). She was also elected Treasurer of APS in October 1999 and Vice President of APS in
February 2004.
Ms. Loftin was elected to her present position effective November 2007. Prior to that time,
she was Vice President, General Counsel and Secretary of Pinnacle West (October 2002 – November
2007) and Vice President and General Counsel (July 1999 – October 2002). She was also elected Vice
President and General Counsel of APS in July 1999 and Secretary of APS in October 2002.
Mr. Robinson was elected to his present position effective November 2007. Prior to that time,
he was Vice President, Planning of APS (September 2003 – November 2007), Vice President, Finance
and Planning of APS (October 2002 – September 2003), Vice President, Regulation and Planning of
Pinnacle West (June 2001 – October 2002) and Director, Accounting, Regulation and Planning of
Pinnacle West (prior to June 2001).
Ms. Sundberg was elected Vice President, Human Resources of APS effective November 2007.
Prior to that time, she was with American Express Company, serving as Vice President, Employee
Relations, Safety, Compliance & Embrace (January 2007 – November 2007), Vice President, HR
Relationship Leader, Global Corporate Travel Division (August 2003 – January 2007) and Vice
President, Global Culture Initiative (January 2003 – August 2003).
Mr. Wheeler was elected to his present position in September 2003. Prior to that time, he was
Senior Vice President, Regulation, System Planning and Operations of APS (October 2002 – September
2003) and Senior Vice President, Transmission, Regulation and Planning of Pinnacle West and APS
(June 2001 – October 2002).
ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Pinnacle West’s common stock is publicly held and is traded on the New York Stock Exchange.
At the close of business on February 21, 2008, Pinnacle West’s common stock was held of record by
approximately 30,177 shareholders.
QUARTERLY STOCK PRICES AND DIVIDENDS PAID PER SHARE
STOCK SYMBOL: PNW
Dividends
2007
High
Low
Close
Per Share
1st Quarter
$
51.67
$
46.43
$
48.25
$
0.525
2nd Quarter
50.68
39.38
39.85
0.525
3rd Quarter
41.76
36.79
39.51
0.525
4th Quarter
44.50
39.04
42.41
0.525
Dividends
2006
High
Low
Close
Per Share
1st Quarter
$
44.14
$
38.76
$
39.10
$
0.500
2nd Quarter
41.06
38.31
39.91
0.500
3rd Quarter
45.99
39.90
45.05
0.500
4th Quarter
51.00
45.12
50.69
0.525
APS’ common stock is wholly-owned by Pinnacle West and is not listed for trading on any stock
exchange. As a result, there is no established public trading market for APS’ common stock.
The chart below sets forth the dividends paid on APS’ common stock for each of the four
quarters for 2007 and 2006.
Common Stock Dividends
(Dollars in Thousands)
Quarter
2007
2006
1st Quarter
$42,500
$42,500
2nd Quarter
42,500
42,500
3rd Quarter
42,500
42,500
4th Quarter
42,500
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, 2007, APS did not have any
outstanding preferred stock.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion should be read in conjunction with Pinnacle West’s Consolidated
Financial Statements and APS’ Financial Statements and the related Notes that appear in Item 8 of
this report.
OVERVIEW
Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated
electric utility that provides retail and wholesale electric service to most of the state of
Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson
metropolitan area and Mohave County in northwestern Arizona. APS has historically accounted for a
substantial part of our revenues and earnings, and is expected to continue to do so. Customer
growth in APS’ service territory is above the national average and remains an important driver of
our revenues and earnings.
Our cash flows and profitability are affected by the rates APS may charge and the timely
recovery of costs through those rates. APS’ retail rates are regulated by the ACC and its
wholesale electric rates (primarily for transmission) are regulated by the FERC. APS’ capital
expenditure requirements, which are discussed below under “Liquidity and Capital Resources,” are
substantial because of customer growth in APS’ service territory and inflationary impacts on the
capital budget, highlighting APS’ need for the timely recovery through rates of these and
other expenditures. On June 28, 2007, the ACC issued an order in a general rate case granting APS
retail base rate increases. The ACC rate case decision and other retail and wholesale rate matters
are discussed in Note 3.
SunCor, our real estate development subsidiary, has been an important source of earnings in
recent years, although SunCor’s earnings in 2007 and expected
earnings in 2008 reflect a slowdown in the western United
States real estate markets. See discussion below in “Pinnacle West Consolidated – Factors
Affecting our Financial Outlook – Subsidiaries.” Our subsidiary, APSES, provides energy-related
products and services and competitive commodity-related energy services to commercial and
industrial retail customers in the western United States. Recently, APSES has de-emphasized its
commodity-related energy services. El Dorado, our investment subsidiary, owns minority interests
in several energy-related investments and Arizona community-based ventures.
We continue to focus on solid operational performance in our electricity generation and
delivery activities. In the delivery area, we focus on superior reliability and customer
satisfaction. We plan to expand long-term energy resources and our transmission and distribution
systems to meet the electricity needs of our growing retail customers and sustain reliability.
See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” below for a
discussion of several factors that could affect our future financial results.
PINNACLE WEST CONSOLIDATED –
EARNINGS CONTRIBUTION BY BUSINESS SEGMENT
Pinnacle West’s two reportable business segments are:
•
our regulated electricity segment, which consists of traditional regulated retail
and wholesale electricity businesses (primarily electric service to Native Load
customers) and related activities and includes electricity generation, transmission
and distribution; and
•
our real estate segment, which consists of SunCor’s real estate development and
investment activities.
The following table summarizes income from continuing operations for the years ended December31, 2007, 2006 and 2005 and reconciles net income in total (dollars in millions):
2007
2006
2005
Regulated electricity segment (a)
$
274
$
259
$
167
Real estate segment
12
50
35
All other (b)
13
8
21
Income from continuing operations
299
317
223
Discontinued operations – net of tax:
Real estate (c)
11
10
17
Sale of Silverhawk (d)
—
1
(67
)
All other (b)
(3
)
(1
)
3
Net income
$
307
$
327
$
176
(a)
Includes an $84 million after-tax regulatory disallowance of plant costs in
2005 in accordance with APS’ 2003 general retail rate case settlement.
(b)
Includes activities related to marketing and trading, APSES and El Dorado.
None of these segments is a reportable segment.
(c)
Primarily relates to sales of commercial properties.
(d)
See Note 22.
PINNACLE WEST CONSOLIDATED – RESULTS OF OPERATIONS
2007 Compared with 2006
Our consolidated net income for 2007 was $307 million compared with $327 million for 2006.
The current period includes income from discontinued operations of $11 million related to sales of
commercial properties by SunCor and a loss from discontinued operations of $3 million related to an
APSES project. The prior year includes income from discontinued operations of $10 million related
to sales of commercial properties by SunCor. Income from continuing operations decreased $18
million in the year-to-year comparison and is reflected in the segments as follows:
Regulated Electricity Segment – Income from continuing operations increased
approximately $15 million primarily due to higher retail sales related to customer
growth; the effects of weather on retail sales; and impacts of the retail rate
increase. These positive factors were partially offset by higher operations and
maintenance expense primarily due to increased generation costs (including increased
maintenance and overhauls and the Palo Verde performance improvement plan), customer
service and other costs; higher depreciation and amortization primarily due to
increased plant balances; lower other income, net of expense, primarily due to
miscellaneous asset sales in the prior year and lower interest income as a result of
lower investment balances; and a regulatory disallowance. In addition, higher fuel
and purchased power costs related to commodity price increases were substantially
offset by deferral of such costs in accordance with the PSA. See Note 3 for further
discussion of the regulatory disallowance and the PSA.
•
Real Estate Segment – Income from continuing operations decreased approximately $38
million primarily due to lower sales of residential property and land parcels
resulting from the continued slowdown in the western United States real estate
markets.
·
Additional details on the major factors that increased (decreased) net income for the year
ended December 31, 2007 compared with the prior year are contained in the following table (dollars
in millions):
Increase (Decrease)
Pretax
After Tax
Regulated electricity segment:
Higher retail sales primarily due to customer growth, excluding
weather effects
$
46
$
28
Effects of weather on retail sales
37
23
Impacts of retail rate increase effective July 1, 2007:
Revenue increase related to higher Base Fuel Rate
185
113
Decreased deferred fuel and purchased power costs related to
higher Base Fuel Rate
(171
)
(104
)
Non-fuel rate increase
6
4
Net changes in fuel and purchased power costs related to price:
Higher fuel and purchased power costs related to increased
commodity prices
(121
)
(74
)
Increased deferred fuel and purchased power costs related
to increased prices
115
70
Mark-to-market fuel and purchased power costs,
net of related deferred fuel and purchased power costs
18
11
Regulatory disallowance (see Note 3)
(14
)
(8
)
Operations and maintenance increases primarily due to:
Increased generation costs, including increased maintenance
and overhauls and Palo Verde performance
improvement plan
(25
)
(15
)
Customer service and other costs
(21
)
(13
)
Higher depreciation and amortization primarily due to increased
plant balances
(12
)
(7
)
Lower other income, net of expense, primarily due to
lower interest income as a result of lower investment
balances and miscellaneous asset sales in prior year
(15
)
(9
)
Income tax benefits resolved in 2007 related to prior years
—
13
Income tax credits resolved in 2006 related to prior years
—
(14
)
Miscellaneous items, net
6
(3
)
Increase in regulated electricity segment net income
34
15
Lower real estate segment income from continuing operations
primarily due to:
Lower sales of residential property resulting from the continued
slowdown in the western United States real estate markets
(47
)
(29
)
Lower sales of land parcels
(12
)
(7
)
Higher other costs
(5
)
(2
)
Higher marketing and trading contribution primarily due to higher
mark-to-market gains resulting from changes in forward prices
and higher unit margins
Regulated electricity segment revenues were $283 million higher for the year ended December31, 2007 compared with the prior year primarily because of:
•
a $191 million increase in retail revenues due to a rate increase effective July 1,2007;
•
a $60 million increase in retail revenues primarily related to customer growth,
excluding weather effects;
•
a $50 million increase in retail revenues due to the effects of weather;
•
a $3 million increase in revenues from Off-System Sales due to higher prices and
volumes;
•
a $35 million decrease in retail revenues related to recovery of PSA deferrals,
which had no earnings effect because of amortization of the same amount recorded as
fuel and purchased power expense (see Note 3); and
•
a $14 million net increase due to miscellaneous factors.
Real Estate Segment Revenues
Real estate segment revenues were $185 million lower for the year ended December 31, 2007
compared with the prior year primarily because of:
•
a $167 million decrease in residential property sales due to the continued slowdown
in western United States real estate markets; and
•
an $18 million decrease primarily due to lower sales of land parcels.
All Other Revenues
Marketing and trading revenues were $12 million higher for the year ended December 31, 2007
compared with the prior year primarily because of higher mark-to-market gains resulting from
changes in forward prices and higher competitive retail sales volumes in California.
Other revenues were $12 million higher for the year ended December 31, 2007 compared with the
prior year primarily as a result of increased sales by APSES of energy-related products and
services.
2006 Compared with 2005
Our consolidated net income for 2006 was $327 million compared with $176 million for the
comparable prior-year period. The prior year included a net loss from discontinued operations of
$47 million, which was related to the sale and operations of Silverhawk, partially offset by income
from sales of real estate commercial properties at SunCor. Income from continuing operations
increased $94 million in the period-to-period comparison, reflecting the following changes in
earnings by segment:
Regulated Electricity Segment – Income from continuing operations increased
approximately $92 million primarily due to an $84 million after-tax regulatory
disallowance of plant costs recorded in 2005. Income also increased due to higher
retail sales volumes due to customer growth; income tax credits related to prior years
resolved in 2006; and increased other income due to higher interest income on higher
investment balances. These positive factors were partially offset by higher operations
and maintenance expense related to generation and customer service; and higher
depreciation and amortization primarily due to increased plant asset balances,
partially offset by lower depreciation rates. In addition, higher fuel and purchased
power costs of $74 million after-tax were partially offset by the deferral of $45
million after-tax of costs in accordance with the PSA.
•
Real Estate Segment – Income from continuing operations increased approximately $15
million primarily due to increased margins on residential sales and the sale of certain
joint venture assets, partially offset by higher general and administrative expenses.
Income from discontinued operations decreased $7 million due to lower commercial
property sales.
•
Other – Income from continuing operations decreased approximately $13 million
primarily due to lower mark-to-market gains, partially offset by higher unit margins on
wholesale sales and competitive retail sales in California.
Additional details on the major factors that increased (decreased) net income for the year ended
December 31, 2006 compared with the prior year are contained in the following table (dollars in
millions):
Increase (Decrease)
Pretax
After Tax
Regulated electricity segment:
Higher fuel and purchased power costs
$
(121
)
$
(74
)
Increased deferred fuel and purchased power costs
(deferrals began April 1, 2005)
73
45
Higher retail sales volumes due to customer growth,
excluding weather effects
87
53
Regulatory disallowance of plant costs in 2005, in
accordance with APS’ 2003 general retail rate case
settlement
139
84
Operations and maintenance increases primarily due to:
Generation costs, including increased maintenance and
overhauls
(41
)
(25
)
Customer service costs, including regulatory demand-side
management programs and planned maintenance
(16
)
(10
)
Miscellaneous items, net
3
2
Higher depreciation and amortization primarily due to
increased plant asset balances partially offset by lower
depreciation rates
(11
)
(7
)
Higher other income, net of expense, primarily due to
miscellaneous asset sales and increased interest income on
higher investment balances
13
8
Income tax credits related to prior years resolved in 2006
—
14
Miscellaneous items, net
(4
)
2
Increase in regulated electricity segment net income
122
92
Lower marketing and trading contribution primarily related to
lower mark-to-market gains, partially offset by higher unit
margins on wholesale sales and competitive retail sales in
California
(18
)
(11
)
Higher real estate segment contribution primarily related to
increased margins on residential sales and the sale of
certain joint venture assets
25
15
Miscellaneous items, net
(5
)
(2
)
Increase in income from continuing operations
$
124
94
Discontinued operations:
Silverhawk loss in 2005
68
Lower commercial property real estate sales
(7
)
Income in 2005 related to sale of NAC
(4
)
Increase in net income
$
151
Regulated Electricity Segment Revenues
Regulated electricity segment revenues were $398 million higher for 2006 compared with the
prior-year period primarily as a result of:
•
a $265 million increase in revenues related to recovery of PSA deferrals, which had
no earnings effect because of amortization of the same amount recorded as fuel and
purchased power expense;
a $124 million increase in retail revenues related to customer growth, excluding
weather effects;
•
a $6 million increase in Off-System Sales primarily resulting from $12 million of
sales previously reported in marketing and trading that were classified beginning in
April 2005 as sales in the regulated electricity segment in accordance with APS’ 2003
general retail rate case settlement, partially offset by $6 million of lower Off-System
Sales in 2006; and
•
a $3 million increase due to miscellaneous factors.
Real Estate Segment Revenues
Real estate segment revenues were $62 million higher for 2006 compared with the prior-year
period primarily as a result of:
•
a $55 million increase in residential sales due to higher prices and volumes; and
•
a $7 million increase in commercial real estate sales.
Other Revenues
Other revenues were $25 million lower for 2006 compared with the prior-year period primarily
as a result of decreased sales-related products and services by APSES.
Marketing and trading revenues were $21 million lower for 2006 compared with the prior-year
period primarily as a result of:
•
a $20 million decrease in mark-to-market gains on contracts for future delivery due
to changes in forward prices;
•
a $12 million decrease in Off-System Sales due to the absence of sales previously
reported in marketing and trading that were classified beginning in April 2005 as sales
in the regulated electricity segment in accordance with APS’ 2003 general retail rate
case settlement;
•
a $23 million increase from higher prices on competitive retail sales in California;
and
•
a $12 million decrease due to miscellaneous factors.
LIQUIDITY AND CAPITAL RESOURCES – Pinnacle West Consolidated
Operating Cash Flows
Net
cash provided by operating activities was $658 million for 2007, compared with $394
million for 2006, an increase in net cash flow of $264 million. This change was primarily due to a
decrease in 2007 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.
Net cash provided by operating activities was $394 million for 2006, compared with $730
million for 2005, a decrease in net cash flow of $336 million. This change was primarily due to an
increase in 2006 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.
Investing Cash Flows
Net cash used for investing activities was $873 million for 2007, compared with $569 million
for 2006, a decrease in net cash flow of $304 million.
This cash flow decrease was primarily due to:
•
A decrease in cash provided by investing activities related to proceeds of
$208 million received in 2006 from the sale of Silverhawk; and
•
An increase in cash used for capital expenditures and capitalized interest
of $183 million (see table and discussion below).
The
cash flow decreases were partially offset by:
•
A decrease of $65 million in cash invested in securities at APS;
•
An increase of $19 million cash provided by sale of real estate
investments; and
•
A net increase of $3 million due to miscellaneous factors.
Net cash used for investing activities was $569 million for 2006, compared with $585 million
for 2005, an increase in net cash flow of $16 million.
This cash flow increase was primarily due to:
•
Proceeds of $208 million received in 2006 from the sale of Silverhawk; and
•
Less cash used for capital expenditures (including the 2005 acquisition of
the Sundance Plant) and capitalized interest of approximately $72 million (see
table and discussion below).
The
cash flow increases were partially offset by:
•
An increase of $214 million in cash invested in securities at APS;
•
A decrease of $43 million in cash provided by sale of real estate
investments; and
A net decrease of $7 million due to miscellaneous factors.
Financing Cash Flows
Net cash provided by
financing activities was $185 million for 2007, compared with $108
million for 2006, an increase in net cash flow of $77 million.
This
cash flow increase was primarily due to a net increase of $295 million in short-term
borrowings to fund day-to-day operations and liquidity needs.
The
cash flow increases were partially offset by:
•
A decrease of $161 million in net new long-term debt (issuances net of redemptions and
refinancing) to fund our construction program and for other general corporate
purposes; and
•
A net decrease of $57 million due to miscellaneous factors.
Net cash provided by financing activities was $108 million for 2006, compared with net cash
used for financing activities in 2005 of $155 million, an increase in net cash flow of $263
million.
This cash flow increase was primarily due to:
•
An increase of $429 million in net new long-term debt (issuances net of redemptions and
refinancing) to fund our construction program and for other general corporate
purposes;
•
A net increase of $56 million in short-term borrowings to fund day-to-day
operations and liquidity needs; and
•
A net increase of $37 million due to miscellaneous factors.
The
cash flow increases were partially offset by:
•
A decrease of $259 million related to common stock issuance, primarily due
to a 2005 public offering.
Liquidity
Capital Expenditure Requirements
The following table summarizes the actual capital expenditures for 2005, 2006 and 2007 and
estimated capital expenditures for the next three years:
Includes $185 million in 2005 for the acquisition of the Sundance Plant.
(b)
Primarily information systems and facilities projects.
(c)
Consists primarily of capital expenditures for residential, land development
and retail and office building construction reflected in “Real estate investments” and
“Capital expenditures” on the Consolidated Statements of Cash Flows.
Distribution and transmission capital expenditures are comprised of infrastructure additions
and upgrades, capital replacements, new customer construction and related information systems and
facility costs. Examples of the types of projects included in the forecast include power lines,
substations, line extensions to new residential and commercial developments and upgrades to
customer information systems. In addition, these amounts do not
include any
impacts from the recent changes in the line extension
policy (see Note 3). Major transmission projects are driven by regional customer growth.
Generation capital expenditures are comprised of various improvements to APS’ existing fossil
and nuclear plants. Examples of the types of projects included in this category are additions,
upgrades and capital replacements of various power plant equipment such as turbines, boilers and
environmental equipment. Installation of new steam generators in Palo Verde Unit 3 was completed
in the fourth quarter of 2007 at an approximate cost of $70 million (APS’ share), which completed
the steam generator replacement program for all three units. Environmental expenditures are
estimated at approximately $70 million to $120 million per year for 2008, 2009 and 2010. We are
also monitoring the status of certain environmental matters, which, depending on their final
outcome, could require additional environmental expenditures. (See “Business of Arizona Public
Service Company – Environmental Matters – Regional Haze Rules” in Item 1.) Generation also
includes nuclear fuel expenditures of approximately $90 million to $120 million per year for 2008,
2009 and 2010.
Capital expenditures will be funded with internally generated cash and/or external financings,
which may include issuances of long-term debt and Pinnacle West common stock.
Our primary cash needs are for dividends to our shareholders and principal and interest
payments on our long-term debt. The level of our common stock dividends and future dividend growth
will be dependent on a number of factors including, but not limited to, payout ratio trends, free
cash flow and financial market conditions.
On January 23, 2008, the Pinnacle West Board of Directors declared a quarterly dividend of
$0.525 per share of common stock, payable on March 3, 2008, to shareholders of record on
February 1, 2008.
Our primary sources of cash are dividends from APS, external debt and equity financings and
cash distributions from our other subsidiaries, primarily SunCor. For the years 2005 through 2007,
total dividends from APS were $510 million and total distributions from SunCor were $70 million.
For 2007, cash contributions from APS were $170 million and distributions from SunCor were $10
million. An existing ACC order requires APS to maintain a common equity ratio of at least 40% and
prohibits APS from paying common stock dividends if the payment would reduce its common equity
below that threshold. As defined in the ACC order, the common equity ratio is common equity
divided by the sum of common equity and long-term debt, including current maturities of long-term
debt. At December 31, 2007, APS’ common equity ratio, as defined, was approximately 54%.
At December 31, 2007, Pinnacle West’s outstanding long-term debt, including current
maturities, was $175 million. Pinnacle West has a $300 million revolving credit facility that
terminates in December 2010. This line of credit is available to support the issuance of up to
$250 million in commercial paper or to be used as bank borrowings, including issuances of letters
of credit. At December 31, 2007, Pinnacle West had no borrowings outstanding under its revolving
line of credit. At December 31, 2007, we had $115 million of commercial paper outstanding.
Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a
non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and
our subsidiaries. IRS regulations require us to contribute a minimum amount to the qualified plan.
We contribute at least the minimum amount required under IRS regulations, but no more than the
maximum tax-deductible amount. The minimum required funding takes into consideration the value of
plan assets and our pension obligation. The assets in the plan are comprised of fixed-income,
equity and short-term investments. Future year contribution amounts are dependent on plan asset
performance and plan actuarial assumptions. We contributed approximately $52 million in 2007. The
contribution to our pension plan in 2008 is estimated to be approximately $50 million. The
expected contribution to our other postretirement benefit plans in 2008 is estimated to be
approximately $20 million. APS and other subsidiaries fund their share of the contributions. APS’
share is approximately 96% of both plans.
Significant Financing Activities – 2007. On January 4, 2007, the FERC issued an order
permitting Pinnacle West to transfer its market-based rate tariff and wholesale power sales
agreements to a newly-created Pinnacle West subsidiary, Pinnacle West Marketing & Trading.
Pinnacle West completed the transfer on February 1, 2007, which resulted in Pinnacle West no longer
being a public utility under the Federal Power Act. As a result, Pinnacle West is no longer
subject to FERC jurisdiction in connection with its issuance of securities or its incurrence of
long-term debt.
In May 2007, Pinnacle West infused approximately $40 million of equity into APS, consisting of
proceeds of stock issuances in 2006 under Pinnacle West’s Investors Advantage Plan (direct stock
purchase and dividend reinvestment plan) and employee stock plans.
Significant Financing Activities –2006. In January 2006, Pinnacle West infused into APS $210
million of the proceeds from the sale of Silverhawk.
On February 28, 2006, Pinnacle West entered into an Uncommitted Master Shelf Agreement with
Prudential Investment Management, Inc. (“Prudential”) and certain of its affiliates. The agreement
provides the terms under which Pinnacle West may offer up to $200 million of its senior notes for
purchase by Prudential affiliates at any time prior to December 31, 2007. The maturity of notes
issued under the agreement cannot exceed five years. Pursuant to the agreement, on February 28,2006, Pinnacle West issued and sold to Prudential affiliates $175 million of its 5.91% Senior
Notes, Series A, due February 28, 2011 (the “Series A Notes”).
On April 3, 2006, Pinnacle West repaid $300 million of its 6.40% Senior Notes due April 2006.
Pinnacle West used the proceeds of the Series A Notes, cash on hand and commercial paper proceeds
to repay these notes.
APS
APS’ capital requirements consist primarily of capital expenditures and optional and mandatory
redemptions of long-term debt. APS pays for its capital requirements with cash from operations,
equity infusions from Pinnacle West and, to the extent necessary, external financings. APS has
historically paid its dividends to Pinnacle West with cash from operations. See “Pinnacle West
(Parent Company)” above for a discussion of the common equity ratio that APS must maintain in order
to pay dividends to Pinnacle West. As noted above, in May 2007, Pinnacle West infused
approximately $40 million of equity into APS.
APS’ outstanding long-term debt, including current maturities, was approximately $2.9 billion
at December 31, 2007. APS has two committed lines of credit totaling $900 million that are
available either to support the issuance of up to $250 million in commercial paper or to be used
for bank borrowings, including issuances of letters of credit. The $400 million line terminates in
December 2010 and the $500 million line terminates in September 2011. At December 31, 2007, APS
had borrowings of $218 million under its revolving line of credit. The amount drawn was used for
general corporate purposes.
Significant Financing Activities –2007. Although provisions in APS’ articles of incorporation
and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue,
APS does not expect any of these provisions to limit its ability to meet its capital requirements.
On October 30, 2007, the ACC issued a financing order in which it approved APS’ request, subject to
specified parameters and procedures, to increase (a) APS’ short-term debt authorization from 7% of
APS’ capitalization to (i) 7% of APS’ capitalization plus (ii) $500 million and (b) APS’ long-term
debt authorization from approximately $3.2 billion to $4.2 billion in light of the projected growth
of APS and its customer base and the resulting projected financing needs.
Significant Financing Activities –2006. On August 3, 2006, APS issued $400 million of debt as
follows: $250 million of its 6.25% Notes due 2016 and $150 million of its 6.875% Notes due 2036.
A portion of the proceeds was used to pay at maturity approximately $84 million of APS’
6.75% Senior Notes due November 15, 2006. The remainder was used to fund its construction program
and other general corporate purposes.
On September 28, 2006, APS put in place the $500 million revolving credit facility that
terminates in September 2011. APS may increase the amount of the facility up to a maximum facility
of $600 million upon the satisfaction of certain conditions. APS will use the facility for general
corporate purposes. The facility can also be used for the issuance of letters of credit. Interest
rates are based on APS’ senior unsecured debt credit ratings.
Other Financing Matters — See Note 3 for information regarding the PSA approved by the ACC.
Although APS defers actual retail fuel and purchased power costs on a current basis, APS’ recovery
of the deferrals from its ratepayers is subject to annual and, if necessary, periodic PSA
adjustments.
See “Cash Flow Hedges” in Note 18 for information related to decreased collateral provided to
us by counterparties and the change in our margin account.
Other Subsidiaries
During the past three years, SunCor funded its cash requirements with cash from operations and
its own external financings. SunCor’s capital needs consist primarily of capital expenditures for
land development and retail and office building construction. See the capital expenditures table
above for actual capital expenditures during 2007 and projected capital expenditures for the next
three years. SunCor expects to fund its future capital requirements with cash from operations and
external financings.
SunCor entered into a secured construction loan on April 13, 2007, in the amount of $60
million, of which $48 million was outstanding at December 31, 2007. The loan matures on April 19,2009, and may be extended one year if certain conditions are met.
On July 31, 2007, SunCor borrowed $12 million under a new secured construction loan. The loan
matures on July 31, 2009, and may be extended annually up to two years.
SunCor’s total outstanding debt was approximately $246 million as of December 31, 2007,
including $94 million of debt classified as current maturities of long-term debt under revolving
lines of credit totaling $170 million. SunCor’s long-term debt, including current maturities, was
$238 million and total short-term debt was $8 million at December 31, 2007. See Note 6.
El Dorado expects minimal capital requirements over the next three years and intends to focus
on prudently realizing the value of its existing investments.
APSES expects minimal capital expenditures over the next three years.
Pinnacle West’s and APS’ debt covenants related to their respective bank financing
arrangements include debt to capitalization ratios. Certain of APS’ bank financing arrangements
also include an interest coverage test. Pinnacle West and APS comply with these covenants and each
anticipates it will continue to meet these and other significant covenant requirements. For both
Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total
consolidated capitalization not exceed 65%. At December 31, 2007, the ratio was approximately 50%
for Pinnacle West and 47% for APS. The provisions regarding interest coverage require minimum cash
coverage of two times the interest requirements for APS. The interest coverage was approximately
4.7 times under APS’ bank financing agreements as of December 31, 2007. Failure to comply with
such covenant levels would result in an event of default which, generally speaking, would require
the immediate repayment of the debt subject to the covenants and could cross-default other debt.
See further discussion of “cross-default” provisions below.
Neither Pinnacle West’s nor APS’ financing agreements contain “rating triggers” that would
result in an acceleration of the required interest and principal payments in the event of a rating
downgrade. However, our bank financial agreements contain a pricing grid in which the interest
costs we pay are determined by our current credit ratings.
All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in
defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or
APS were to default under certain other material agreements. All of APS’ bank agreements contain
cross-default provisions that would result in defaults and the potential acceleration of payment
under these bank agreements if APS were to default under certain other material agreements.
Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings.
See Note 6 for further discussions.
Credit Ratings
The ratings of
securities of Pinnacle West and APS as of February 25, 2008 are shown below.
The ratings reflect the respective views of the rating agencies, from which an explanation of the
significance of their ratings may be obtained. There is no assurance that these ratings will
continue for any given period of time. The ratings may be revised or withdrawn entirely by the
rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision
or withdrawal may adversely affect the market price of Pinnacle West’s or APS’ securities and serve
to increase the cost of and access to capital. It may also require additional collateral related
to certain derivative instruments, natural gas transportation, fuel supply, and other
energy-related contracts.
Pinnacle West has a shelf registration under SEC Rule 415. Pinnacle West
currently has no outstanding, rated senior unsecured securities. However, Moody’s
assigned a provisional (P) rating and Standard & Poor’s assigned a preliminary (prelim)
rating to the senior unsecured securities that can be issued under such shelf
registration.
Off-Balance Sheet Arrangements
In 1986, APS entered into agreements with three separate VIE lessors in order to sell and
lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in
accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly,
do not consolidate them (see Note 9).
APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of
certain events that APS does not consider to be reasonably likely to occur. Under certain
circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde
or the occurrence of specified nuclear events), APS would be required to assume the debt associated
with the transactions, make specified payments to the equity participants, and take title to the
leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If
such an event had occurred as of December 31, 2007, APS would have been required to assume
approximately $194 million of debt and pay the equity participants approximately $170 million.
Guarantees and Letters of Credit
We have issued parental guarantees and letters of credit and obtained surety bonds on behalf
of our subsidiaries. Our parental guarantees for Pinnacle West Marketing & Trading and APS relate
to commodity energy products. Our credit support instruments enable APSES to offer energy-related
products and commodity energy. Non-performance or non-payment under the original contract by our
subsidiaries would require us to perform under the guarantee or surety bond. No liability is
currently recorded on the Consolidated Balance Sheets related to Pinnacle West’s current
outstanding guarantees on behalf of our subsidiaries. Our guarantees have no recourse or
collateral provisions to allow us to recover amounts paid under the guarantees. We generally agree
to indemnification provisions related to liabilities arising from or related to certain of our
agreements, with limited exceptions depending on the particular agreement. See Note 21 for
additional information regarding guarantees and letters of credit.
The following table summarizes Pinnacle West’s consolidated contractual requirements as of
December 31, 2007 (dollars in millions):
2009-
2011-
2008
2010
2012
Thereafter
Total
Long-term debt payments,
including interest: (a)
APS
$
158
$
537
$
1,038
$
3,135
$
4,868
SunCor
173
78
2
2
255
Pinnacle West
10
21
177
—
208
Total long-term debt payments,
including interest
341
636
1,217
3,137
5,331
Short-term debt payments,
including interest (b)
342
—
—
—
342
Purchased power and fuel
commitments (c)
418
651
434
1,584
3,087
Operating lease payments
79
148
133
195
555
Nuclear decommissioning
funding requirements
21
46
49
210
326
Purchase obligations (d)
99
29
2
91
221
Uncertain tax positions
203
12
—
—
215
Total contractual commitments
$
1,503
$
1,522
$
1,835
$
5,217
$
10,077
(a)
The long-term debt matures at various dates through 2036 and bears interest principally at
fixed rates. Interest on variable-rate long-term debt is determined by using the rates at
December 31, 2007 (see Note 6).
(b)
The short-term debt is primarily related to APS bank borrowings under its revolving line of
credit and commercial paper at Pinnacle West (see Note 5).
(c)
Our purchased power and fuel commitments include purchases of coal, electricity, natural gas
and nuclear fuel (see Note 11).
(d)
These contractual obligations include commitments for capital expenditures and other
obligations.
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with GAAP, management must often make
estimates and assumptions that affect the reported amounts of assets, liabilities, revenues,
expenses and related disclosures at the date of the financial statements and during the reporting
period. Some of those judgments can be subjective and complex, and actual results could differ
from those estimates. We consider the following accounting policies to be our most critical
because of the uncertainties, judgments and complexities of the underlying accounting standards and
operations involved.
Regulatory accounting allows for the actions of regulators, such as the ACC and the FERC, to
be reflected in our financial statements. Their actions may cause us to capitalize costs that
would otherwise be included as an expense in the current period by unregulated companies. If
future recovery of costs ceases to be probable, the assets would be written off as a charge in
current period earnings. A major component of our regulatory assets is the retail fuel and power
costs deferred under the PSA. APS defers for future rate recovery 90% of the difference between
actual retail fuel and power costs and the amount of such costs currently included in base rates.
We had $625 million, including $111 million related to the PSA, of regulatory assets on the
Consolidated Balance Sheets at December 31, 2007.
Also included in the balance of regulatory assets at December 31, 2007 is a regulatory asset
of $338 million in accordance with SFAS No. 158 for pension and other postretirement benefits.
This regulatory asset represents the future recovery of these costs through retail rates as these
amounts are charged to earnings. If these costs are disallowed by the ACC, this regulatory asset
would be charged to OCI and result in lower future earnings.
In addition, we had $643 million of regulatory liabilities on the Consolidated Balance Sheets
at December 31, 2007, which primarily are related to removal costs. See Notes 1 and 3 for more
information.
Pensions and Other Postretirement Benefit Accounting
Changes in our actuarial assumptions used in calculating our pension and other postretirement
benefit liability and expense can have a significant impact on our earnings and financial position.
The most relevant actuarial assumptions are the discount rate used to measure our liability and
net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings
on invested funds over the long-term, and the assumed healthcare cost trend rates. We review these
assumptions on an annual basis and adjust them as necessary.
The following chart reflects the sensitivities that a change in certain actuarial assumptions
would have had on the December 31, 2007 reported pension liability on the Consolidated Balance
Sheets and our 2007 reported pension expense, after consideration of amounts capitalized or billed
to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in
millions):
Each fluctuation assumes that the other assumptions of the calculation are held constant while
the rates are changed by one percentage point.
The following chart reflects the sensitivities that a change in certain actuarial assumptions
would have had on the December 31, 2007 reported other postretirement benefit obligation on the
Consolidated Balance Sheets and our 2007 reported other postretirement benefit expense, after
consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s
Consolidated Statements of Income (dollars in millions):
Increase (Decrease)
Impact on Other
Impact on Other
Postretirement Benefit
Postretirement
Actuarial Assumption (a)
Obligation
Benefit Expense
Discount rate:
Increase 1%
$
(90
)
$
(4
)
Decrease 1%
105
5
Health care cost trend
rate (b):
Increase 1%
94
7
Decrease 1%
(76
)
(5
)
Expected long-term rate
of return on plan
assets – pretax:
Increase 1%
—
(2
)
Decrease 1%
—
2
(a)
Each fluctuation assumes that the other assumptions of the calculation are held constant
while the rates are changed by one percentage point.
(b)
This assumes a 1% change in the initial and ultimate health care cost trend rate.
See Note 8 for further details about our pension and other postretirement benefit plans.
Derivative Accounting
Derivative accounting requires evaluation of rules that are complex and subject to varying
interpretations. Our evaluation of these rules, as they apply to our contracts, determines whether
we
use accrual accounting (for contracts designated as normal) or fair value (mark-to-market)
accounting. Mark-to-market accounting requires that changes in the fair value are recognized
periodically in income unless certain hedge criteria are met. For cash flow hedges, the effective
portion of changes in the fair value of the derivative is recognized in common stock equity (as a
component of other comprehensive income (loss)).
The fair value of our derivative contracts is not always readily determinable. In some cases,
we use models and other valuation techniques to determine fair value. The use of these models and
valuation techniques sometimes requires subjective and complex judgment. Actual results could
differ from the results estimated through application of these methods. Our marketing and trading
portfolio consists of structured activities hedged with a portfolio of forward purchases that
protects the economic value of the sales transactions. See “Market Risks – Commodity Price Risk”
below for quantitative analysis. See Note 1 for discussion on accounting policies and Note 18 for
a further discussion on derivative and energy trading accounting.
OTHER ACCOUNTING MATTERS
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This guidance
establishes a framework for measuring fair value and expands disclosures about fair value
measurements. The Statement is effective for us on January 1, 2008. We are currently evaluating
this new guidance but do not expect it to have a material impact on our financial statements.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets
and Financial Liabilities.” SFAS No. 159 provides companies with an option to report selected
financial assets and liabilities at fair value. SFAS No. 159 is effective for us on January 1,2008. We are currently evaluating this new guidance but do not expect it to have a material impact
on our financial statements.
In April 2007, the FASB issued FASB Staff Position No. FIN 39-1, “Amendment of FASB
Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FSP FIN 39-1). Under
FSP FIN 39-1, a reporting entity is permitted to offset the fair value amounts recognized for cash
collateral paid or cash collateral received against the fair value amounts recognized for
derivative instruments executed with the same counterparty under a master netting
arrangement. This new guidance is effective for us on January 1, 2008, with early application
permitted. We are currently evaluating the impacts of FSP FIN 39-1 on our balance sheet. We do
not expect the guidance to have an impact on our results of operations or cash flows.
See Note 4 for a discussion of FIN 48 on accounting for uncertainty in income taxes, which we
adopted January 1, 2007.
PINNACLE WEST CONSOLIDATED – FACTORS AFFECTING
OUR FINANCIAL OUTLOOK
Factors Affecting Operating Revenues, Fuel and Purchased Power Costs
General Electric operating revenues are derived from sales of electricity in regulated retail
markets in Arizona and from competitive retail and wholesale power markets in the western United
States. For the years 2005 through 2007, retail electric revenues comprised approximately 84% of
our total electric operating revenues. Our electric operating revenues are affected by electricity
sales volumes related to customer growth, variations in weather from period to period, customer
mix, average usage per customer, electricity rates and tariffs and the recovery of PSA deferrals.
Off-System Sales of excess generation output, purchased power and natural gas are included in
regulated electricity segment revenues and related fuel and purchased power because they are
credited to APS’ retail customers through the PSA. These revenue transactions are affected by the
availability of excess economic generation or other energy resources and wholesale market
conditions, including demand and prices. Competitive retail sales of energy and energy-related
products and services are made by APSES in certain western states that have opened to competition.
Rate Proceedings Our cash flows and profitability are affected by the rates APS may charge
and the timely recovery of costs through those rates. APS’ retail rates are regulated by the ACC
and its wholesale electric rates (primarily for transmission) are regulated by the FERC. APS’
capital expenditure requirements, which are discussed above under “Liquidity and Capital
Resources,” are substantial because of customer growth in APS’ service territory and inflationary
impacts on the capital budget, highlighting APS’ need for the timely recovery through rates of
these and other expenditures. On June 28, 2007, the ACC issued an order in a general rate case
granting APS retail base rate increases. The ACC rate case decision and other retail and wholesale
rate matters are discussed in Note 3.
Fuel and Purchased Power Costs Fuel and purchased power costs included on our Consolidated
Statements of Income are impacted by our electricity sales volumes, existing contracts for
purchased power and generation fuel, our power plant performance, transmission availability or
constraints, prevailing market prices, new generating plants being placed in service in our market
areas, our hedging program for managing such costs and, since April 1, 2005, PSA deferrals and the
amortization thereof. See “PSA Modifications” and “2006 Deferrals” in Note 3 for information
regarding the PSA, including the 2006 Deferrals. APS’ recovery of PSA deferrals from its
ratepayers is subject to annual and, if necessary, periodic PSA adjustments.
Customer and Sales Growth The customer and sales growth referred to in this paragraph apply
to Native Load customers and sales to them. Customer growth in APS’ service territory was 3.3%
during 2007. Customer growth averaged 4.0% a year for the three years 2005 through 2007; and we
currently expect customer growth to decline, averaging about 1% to 2% per year for 2008
through 2010 due to factors reflecting the economic conditions both nationally and in Arizona. For
the three years 2005 through 2007, APS’ actual retail electricity sales in kilowatt-hours grew at
an average annual rate of 4.8%; adjusted to exclude the effects of weather variations, such retail sales
growth averaged 3.8% a year. We currently estimate that total retail electricity sales in
kilowatt-hours will grow 1% to 2% on average per year, during 2008 through 2010, excluding the effects
of weather variations. We currently expect our retail sales growth in 2008 to be below average
because of potential effects on customer usage from the economic conditions mentioned above and
retail rate increases (see Note 3).
Actual sales growth, excluding weather-related variations, may differ from our projections as
a result of numerous factors, such as economic conditions, customer growth, usage patterns and
responses to retail price changes. Our experience indicates that a reasonable range of variation
in our kilowatt-hour sales projection attributable to such economic factors can result in increases
or decreases in annual net income of up to $10 million.
Weather In forecasting retail sales growth, we assume normal weather patterns based on
historical data. Historical extreme weather variations have resulted in annual variations in net
income in excess of $20 million. However, our experience indicates that the more typical
variations from normal weather can result in increases or decreases in annual net income of up to
$10 million.
Wholesale Market Our marketing and trading activities focus primarily on managing APS’ risks
relating to fuel and purchased power costs in connection with its costs of serving Native Load
customer demand. Our marketing and trading activities include, subject to specified parameters,
marketing, hedging and trading in electricity, fuels and emission allowances and credits. See
“Rate Requests for Transmission and Ancillary Services” in Note 3 for information regarding APS’
recent filing with the FERC requesting an increase in transmission rates.
Other Factors Affecting Financial Results
Operations and Maintenance Expenses Operations and maintenance expenses are impacted by
growth, power plant operations, maintenance of utility plant (including generation, transmission,
and distribution facilities), inflation, outages, higher-trending pension and other postretirement
benefit costs and other factors.
Depreciation and Amortization Expenses Depreciation and amortization expenses are impacted by
net additions to utility plant and other property (such as new generation, transmission, and
distribution facilities), and changes in depreciation and amortization rates. See “Capital
Expenditures” above for information regarding planned additions to our facilities.
Property Taxes Taxes other than income taxes consist primarily of property taxes, which are
affected by the value of property in-service and under construction, assessment ratios, and tax
rates. The average property tax rate for APS, which currently owns the majority of our property,
was 8.3% of the assessed value for 2007, 8.9% of assessed value for 2006 and 9.2% for 2005. We
expect property taxes to increase as we add new utility plant (including new generation,
transmission and distribution facilities) and as we improve our existing facilities. See “Capital
Expenditures” above for information regarding planned additions to our facilities.
Interest Expense Interest expense is affected by the amount of debt outstanding and the
interest rates on that debt. The primary factors affecting borrowing levels are expected to be our
capital expenditures, long-term debt maturities, and internally generated cash flow. Capitalized
interest offsets a portion of interest expense while capital projects are under construction. We
stop accruing capitalized interest on a project when it is placed in commercial operation.
Retail Competition Although some very limited retail competition existed in Arizona in 1999
and 2000, there are currently no active retail electric service providers providing unbundled
energy or other utility services to APS’ customers. We cannot predict when, and the extent to
which, additional electric service providers will re-enter APS’ service territory.
Subsidiaries SunCor’s net income was $24 million in 2007, $61 million in 2006 and $56 million
in 2005. See Note 17 for further discussion. We currently expect SunCor’s net income in 2008 to
be approximately $20 million. This estimate reflects continuation of the slowdown in the western
United States real estate markets.
The historical results of APSES, Pinnacle West Marketing & Trading and El Dorado are not
indicative of future performance.
General Our financial results may be affected by a number of broad factors. See
“Forward-Looking Statements” below for further information on such factors, which may cause our
actual future results to differ from those we currently seek or anticipate.
Market Risks
Our operations include managing market risks related to changes in interest rates, commodity
prices and investments held by our nuclear decommissioning trust fund.
Interest Rate and Equity Risk
We have exposure to changing interest rates. Changing interest rates will affect interest
paid on variable-rate debt and the market value of fixed income securities held by our nuclear
decommissioning trust fund (see Note 12). The nuclear decommissioning trust fund also has risks
associated with the changing market value of its investments. Nuclear decommissioning costs are
recovered in regulated electricity prices.
The tables below present contractual balances of our consolidated long-term and short-term
debt at the expected maturity dates as well as the fair value of those instruments on December 31,2007 and 2006. The interest rates presented in the tables below represent the weighted-average
interest rates as of December 31, 2007 and 2006 (dollars in thousands):
The tables below present contractual balances of APS’ long-term debt at the expected maturity
dates as well as the fair value of those instruments on December 31, 2007 and 2006. The interest
rates presented in the tables below represent the weighted-average interest rates as of December31, 2007 and 2006 (dollars in thousands):
We are exposed to the impact of market fluctuations in the commodity price and transportation
costs of electricity, natural gas and emissions allowances. Our ERMC, consisting of officers and
key management personnel, oversees company-wide energy risk management activities and monitors the
results of marketing and trading activities to ensure compliance with our stated energy risk
management and trading policies. We manage risks associated with these market fluctuations by
utilizing various commodity instruments that qualify as derivatives, including exchange-traded
futures and options and over-the-counter forwards, options and swaps. As part of our risk
management program, we use such instruments to hedge purchases and sales of electricity, fuels and
emissions allowances and credits. The changes in market value of such contracts have a high
correlation to price changes in the hedged commodities.
The following tables show the net pretax changes in mark-to-market of our derivative positions
in 2007 and 2006 (dollars in millions):
2007
2006
Mark-to-market of net positions at beginning of year
$
15
$
516
Recognized in earnings:
Change in mark-to-market losses for future
period deliveries
(2
)
(27
)
Mark-to-market gains realized including
ineffectiveness during the period
(15
)
(3
)
Decrease (increase) in regulatory asset
55
(93
)
Recognized in OCI:
Change in mark-to-market losses for future
period deliveries (a)
(1
)
(352
)
Mark-to-market gains realized during the period
(12
)
(26
)
Change in valuation techniques
—
—
Mark-to-market of net positions at end of year
$
40
$
15
(a)
The decreases in mark-to-market recorded in OCI are due
primarily to
decreases in forward natural gas prices.
The tables below show the fair value of maturities of our non-trading and trading derivative
contracts (dollars in millions) at December 31, 2007 by maturities and by the type of valuation
that is performed to calculate the fair values. See Note 1, “Derivative Accounting,” for more
discussion of our valuation methods.
Total
fair
Source of Fair Value
2008
2009
2010
2011
2012
Years thereafter
value
Prices actively quoted
$
(12
)
$
10
$
14
$
2
$
—
$
—
$
14
Prices provided by
other external sources
(4
)
(16
)
1
4
3
—
(12
)
Prices based on models
and other valuation
methods
12
15
(1
)
—
2
10
38
Total by maturity
$
(4
)
$
9
$
14
$
6
$
5
$
10
$
40
The table below shows the impact that hypothetical price movements of 10% would have on the
market value of our risk management and trading assets and liabilities included on Pinnacle West’s
Consolidated Balance Sheets at December 31, 2007 and 2006 (dollars in millions).
These contracts are hedges of our forecasted purchases of natural gas and
electricity. The impact of these hypothetical price movements would substantially
offset the impact that these same price movements would have on the physical exposures
being hedged. To the extent the amounts are eligible for inclusion in the PSA, the
amounts are recorded as either a regulatory asset or liability.
Credit Risk
We are exposed to losses in the event of non-performance or non-payment by counterparties.
See Note 1, “Derivative Accounting” for a discussion of our credit valuation adjustment policy.
See Note 18 for further discussion of credit risk.
ARIZONA PUBLIC SERVICE COMPANY – RESULTS OF OPERATIONS
Regulatory Matters
See “Pinnacle West Consolidated – Results of Operations — Regulatory Matters” above for
information about the ACC’s order in APS’ general retail rate case and the PSA.
2007 Compared with 2006
Our net income for 2007 was $284 million compared with $270 million for 2006. APS’ net income
increased approximately $14 million primarily due to higher retail sales related to customer
growth; the effects of weather on retail sales; and impacts of the retail rate increase. These
positive factors were partially offset by higher operations and maintenance expense primarily due
to increased generation costs (including increased maintenance and overhauls and the Palo Verde
performance improvement plan), customer service and other costs; higher depreciation and
amortization primarily due to increased plant balances; higher interest expense due to higher debt
balances and higher rates; lower other income, net of expense, primarily due to miscellaneous asset
sales in the prior year and lower interest income as a result of lower investment balances; and a
regulatory disallowance (see Note 3). In addition, higher fuel and purchased power costs related
to commodity price increases were partially offset by the deferral of such costs in accordance with
the PSA. See Note 3 for further discussion.
Additional details on the major factors that increased (decreased) net income for the year
ended December 31, 2007 compared with the prior year are contained in the following table (dollars
in millions):
Higher retail sales primarily due to customer growth, excluding
weather effects
$
46
$
28
Effects of weather on retail sales
37
23
Impacts of
retail rate increase effective July 1, 2007:
Revenue increase related to higher Base Fuel Rate
185
113
Decreased deferred fuel and purchased power costs related
to
higher Base Fuel Rate
(171
)
(104
)
Non-fuel rate increase
6
4
Net changes in fuel and purchased power costs related to price:
Higher fuel and purchased power costs related to increased
commodity prices
(121
)
(74
)
Increased deferred fuel and purchased power costs related
to increased prices
115
70
Mark-to-market fuel and purchased power costs,
net of related deferred fuel and purchased power costs
18
11
Regulatory disallowance (see Note 3)
(14
)
(8
)
Operations and maintenance increases primarily due to:
Increased generation costs, including increased maintenance
and overhauls and Palo Verde performance
improvement plan
(25
)
(15
)
Customer service and other costs
(19
)
(11
)
Higher depreciation and amortization primarily due to increased
plant balances
(12
)
(7
)
Lower other income, net of expense, primarily due to
lower interest income as a result of lower investment
balances and miscellaneous asset sales in prior year
(7
)
(4
)
Income tax benefits resolved in 2007 related to prior years
—
11
Income tax credits resolved in 2006 related to prior years
—
(11
)
Higher interest expense, net of capitalized financing costs,
primarily
due to higher debt balances and higher rates
(7
)
(4
)
Lower marketing and trading contribution primarily due to lower
mark-to-market gains because of changes in forward prices
(7
)
(4
)
Other miscellaneous items, net
2
(4
)
Increase in net income
$
26
$
14
Electric operating revenues were $278 million higher for the year ended December 31, 2007
compared with the prior year primarily because of:
•
a $191 million increase in retail revenues due to a rate increase effective
July 1, 2007;
•
a $60 million increase in retail revenues primarily related to customer growth,
excluding weather effects;
•
a $50 million increase in retail revenues due to the effects of weather;
a $3 million increase in revenues from Off-System Sales due to higher prices and
volumes;
•
a $35 million decrease in retail revenues related to recovery of PSA deferrals,
which had no earnings effect because of amortization of the same amount recorded as
fuel and purchased power expense (see Note 3); and
•
a $9 million net increase due to miscellaneous factors.
2006 Compared with 2005
APS’ net income for 2006 was $270 million compared with $170 million for the comparable
prior year. The $100 million increase was primarily due to an $84 million after-tax
regulatory disallowance of plant costs recorded in 2005. Income also increased due to higher
retail sales volumes due to customer growth; higher marketing and trading gross margin primarily
due to higher mark-to-market gains; income tax credits related to prior years resolved in 2006; and
increased other income due to higher interest income on higher investment balances. These positive
factors were partially offset by higher operations and maintenance expense related to generation
and customer service; higher depreciation and amortization primarily due to increased plant asset
balances, partially offset by lower depreciation rates; and higher interest expense. In addition,
higher fuel and purchased power costs of $74 million after-tax were partially offset by the
deferral of $45 million after-tax costs in accordance with the PSA.
Additional details on the major factors that increased (decreased) net income for the year
ended December 31, 2006 compared with the year ended December 31, 2005 are contained in the
following table (dollars in millions):
Increase (Decrease)
Pretax
After Tax
Higher fuel and purchased power costs (see Note 3)
$
(121
)
$
(74
)
Higher retail sales volumes due to customer growth,
excluding weather effects
87
53
Increased deferred fuel and purchased power costs (deferrals
began April 1, 2005)
73
45
Absence of prior-year cost-based contract for PWEC Dedicated
Assets (see Note 3)
56
34
Higher marketing and trading gross margin primarily related to
higher mark-to-market gains
20
12
Regulatory disallowance of plant costs in 2005, in accordance with
APS’ 2003 general retail rate case settlement
139
84
Operations and maintenance increases primarily due to:
Generation costs, including increased maintenance and overhauls
(41
)
(25
)
Costs of PWEC Dedicated Assets not included in prior year
(18
)
(11
)
Customer service costs, including regulatory demand-side
management programs and planned maintenance
(16
)
(10
)
Miscellaneous items, net
1
1
Depreciation and amortization increases primarily due to:
Higher depreciable assets due to transfer of PWEC Dedicated
Assets (see Note 3)
(14
)
(8
)
Higher other depreciable assets partially offset by lower
depreciation rates
(14
)
(8
)
Higher interest expense, net of capitalized financing costs, primarily
due to higher debt balances and higher rates
(14
)
(8
)
Higher other income, net of expense, primarily due to miscellaneous
asset sales and increased interest income on higher investment
balances
9
5
Income tax credits related to prior years resolved in 2006
—
11
Miscellaneous items, net
(7
)
(1
)
Increase in net income
$
140
$
100
Electric
operating revenues were $388 million higher for 2006 compared
with the prior year primarily as a result of:
•
a $265 million increase in revenues related to recovery of PSA deferrals, which had
no earnings effect because of amortization of the same amount recorded as fuel and
purchased power expense;
•
a $124 million increase in retail revenues related to customer growth, excluding
weather effects; and
•
a $1 million decrease due to miscellaneous factors.
LIQUIDITY AND CAPITAL RESOURCES – ARIZONA PUBLIC SERVICE COMPANY
Operating Cash Flows
Net cash provided by operating activities was $766 million for 2007, compared with $394
million for 2006, an increase in net cash flow of $372 million. This change was primarily due to a
decrease in 2007 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.
Net cash provided by operating activities was $394 million for 2006, compared with $722
million for 2005, a decrease in net cash flow of $328 million. This change was primarily due to an
increase in 2006 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.
Investing Cash Flows
Net cash used for investing
activities was $881 million for 2007, compared with $714 million
for 2006, a decrease in net cash flow of $167 million.
This cash flow decrease was primarily due to:
•
An increase of $239 million in cash used for capital expenditures and
allowance for borrowed funds used during construction (see table and
discussion above).
The cash flow decrease was partially offset by:
•
A decrease of $65 million in cash invested in securities; and
•
A net increase of $7 million due to miscellaneous factors.
Net cash used for
investing activities was $714 million for 2006, compared with $645 million
for 2005, a decrease in net cash flow of $69 million.
This cash flow decrease was primarily due to:
•
A decrease of $500 million related to repayment in 2005 by PWEC of a loan;
•
An increase of $214 million in cash invested in
securities; and
•
A net decrease of $1 million due to miscellaneous factors.
The cash flow decreases were partially offset by:
•
Less cash used for capital expenditures (including, in 2005, the acquisition
of the PWEC Dedicated Assets and the Sundance Plant) and allowance for
borrowed funds used during construction of $646 million (see table and
discussion above).
Financing Cash Flows
Net cash provided by financing activities was $86 million for 2007, compared with $352 million
for 2006, a decrease in net cash flow of $266 million.
The cash flow decrease was primarily due to:
•
A decrease of $311 million in net new long-term
debt (issuances net of redemptions and
refinancing) to fund APS’ construction program and for general corporate
purposes; and
A decrease of $173 million due to decreased equity infusions from Pinnacle
West.
The cash flow decreases were partially offset by:
•
A net increase of $218 million in short-term borrowings to fund day-to-day
operations and liquidity needs.
Net cash provided by financing activities was $352 million for 2006, compared with net cash
used for financing activities in 2005 of $76 million, an increase in net cash flow of $428 million.
This cash flow increase was primarily due to:
•
An increase of $466 million in net new long-term debt
issuances net of redemptions and
refinancings in order to fund our construction program and for other general
corporate purposes.
This cash flow increase was partially offset by:
•
A decrease of $37 million due to decreased equity infusions from Pinnacle
West; and
•
A net decrease of $1 million due to miscellaneous factors.
Liquidity
For additional discussion see “Liquidity and Capital Resources – Pinnacle West Consolidated.”
The following table summarizes contractual requirements for APS as of December 31, 2007
(dollars in millions):
2009-
2011-
There-
2008
2010
2012
after
Total
Long-term debt payments,
including interest (a)
$
158
$
537
$
1,038
$
3,135
$
4,868
Short-term debt payments,
including interest
219
—
—
—
219
Purchased power and fuel
commitments (b)
375
651
422
1,584
3,032
Operating lease payments
72
136
124
177
509
Nuclear decommissioning
funding requirements
21
46
49
210
326
Purchase obligations (c)
99
29
2
91
221
Uncertain tax positions
198
12
—
—
210
Total contractual
commitments
$
1,142
$
1,411
$
1,635
$
5,197
$
9,385
(a)
The long-term debt matures at various dates through 2036 and bears interest principally at
fixed rates. Interest on variable-rate long-term debt is determined by the rates at
December 31, 2007 (see Note 6).
(b)
APS’ purchased power and fuel commitments include purchases of coal, electricity, natural
gas, and nuclear fuel (see Note 11).
(c)
These contractual obligations include commitments for capital expenditures and other
obligations.
See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” in Item 7 above for
a discussion of quantitative and qualitative disclosures about market risk.
Our management is responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Pinnacle West
Capital Corporation. Management conducted an evaluation of the effectiveness of our internal
control over financial reporting based on the framework in Internal Control – Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our
evaluation under the framework in Internal Control – Integrated Framework, our management concluded
that our internal control over financial reporting was effective as of December 31, 2007. The
effectiveness of our internal control over financial reporting as of December 31, 2007 has been
audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in
their report which is included herein and relates also to the Company’s consolidated financial
statements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Pinnacle West Capital Corporation
Phoenix, Arizona
We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation
and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated
statements of income, changes in common stock equity, and cash flows for each of the three years in
the period ended December 31, 2007. Our audits also included the financial statement schedules
listed in the Index at Item 15. We also have audited the Company’s internal control over financial
reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The
Company’s management is responsible for these financial statements and financial statement
schedules, for maintaining effective internal control over financial reporting, and for its
assessment of the effectiveness of internal control over financial reporting, included in the
accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility
is to express an opinion on these financial statements and financial statement schedules and an
opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement and
whether effective internal control over financial reporting was maintained in all material
respects. Our audits of the financial statements included examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and evaluating the overall financial
statement presentation. Our audit of internal control over financial reporting included obtaining
an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness of internal control
based on the assessed risk. Our audits also included performing such other procedures as we
considered necessary in the circumstances. We believe that our audits provide a reasonable basis
for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the
supervision of, the company’s principal executive and principal financial officers, or persons
performing similar functions, and effected by the company’s board of directors, management, and
other personnel to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes
those policies and procedures that (1) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions are recorded
as necessary to permit preparation of financial statements in accordance with generally accepted
accounting principles and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the
possibility of collusion or improper management override of controls, material misstatements due to
error or fraud may not be prevented or detected on a timely basis. Also, projections of any
evaluation of the effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all
material respects, the financial position of the Company as of December 31, 2007 and 2006, and the
results of their operations and their cash flows for each of the three years in the period ended
December 31, 2007, in conformity with accounting principles generally accepted in the United States
of America. Also, in our opinion, such financial statement schedules, when considered in relation
to the basic consolidated financial statements taken as a whole, present fairly, in all material
respects, the information set forth therein. Also, in our opinion, the Company maintained, in all
material respects, effective internal control over financial reporting as of December 31, 2007,
based on the criteria established in Internal Control—Integrated Framework issued by the Committee
of Sponsoring Organizations of the Treadway Commission.
As
reflected in the consolidated statements of changes in common stock
equity, the Company adopted Statement of Financial Accounting
Standards No. 158, “Employers’s Accounting for Defined
Benefit Pension and Other Postretirement Plans” effective
December 31, 2006.
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and
our subsidiaries: APS, SunCor, APSES, El Dorado, Pinnacle West Marketing & Trading, and Pinnacle
West Energy (dissolved as of August 31, 2006). Significant intercompany accounts and transactions
between the consolidated companies have been eliminated.
APS is a vertically-integrated electric utility that provides either retail or wholesale
electric service to substantially all of the state of Arizona, with the major exceptions of about
one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in
northwestern Arizona. SunCor is a developer of residential, commercial and industrial real estate
projects in Arizona, New Mexico, Idaho and Utah. APSES provides energy-related projects and
competitive commodity energy to commercial and industrial retail customers in competitive markets
in the western United States. Recently, APSES has de-emphasized its commodity-related energy
services. El Dorado is an investment firm. Pinnacle West Marketing & Trading began operations in
early 2007. These operations were previously conducted by a division of Pinnacle West through the
end of 2006.
Accounting Records and Use of Estimates
Our accounting records are maintained in accordance with accounting principles generally
accepted in the United States of America (GAAP). The preparation of financial statements in
accordance with GAAP requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of
the financial statements and reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
Derivative Accounting
We are exposed to the impact of market fluctuations in the commodity price and transportation
costs of electricity, natural gas and emissions allowances. We manage risks associated with these
market fluctuations by utilizing various instruments that qualify as derivatives, including
exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of
our overall risk management program, we use such instruments to hedge purchases and sales of
electricity, fuels, and emissions allowances and credits. The changes in market value of such
contracts have a high correlation to price changes in the hedged transactions.
We account for our derivative contracts in accordance with SFAS No. 133, “Accounting for
Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 requires that entities
recognize all derivatives as either assets or liabilities on the balance sheet and measure those
instruments at fair value. Changes in the fair value of derivative instruments are either
recognized periodically in income or, if certain hedge criteria are met, in common stock equity (as
a component of other comprehensive income (loss)). To the extent the amounts that would otherwise
be recognized in income are eligible to be recovered through the PSA, the amounts will be recorded
as either a regulatory asset or liability and have no effect on earnings. SFAS No. 133 provides a
scope
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
exception for contracts that meet the normal purchases and sales criteria specified in the
standard. Contracts that do not meet the definition of a derivative are accounted for on an
accrual basis with the associated revenues and costs recorded at the time the contracted
commodities are delivered or received.
Under fair value (mark-to-market) accounting, derivative contracts for the purchase or sale of
energy commodities are reflected at fair market value, net of valuation adjustments, as current or
long-term assets and liabilities from risk management and trading activities on the Consolidated
Balance Sheets.
We determine fair market value using actively-quoted prices when available. We consider
quotes for exchange-traded contracts and over-the-counter quotes obtained from independent brokers
to be actively-quoted.
When actively-quoted prices are not available, we use prices provided by other external
sources. This includes quarterly and calendar year quotes from independent brokers, which we
convert into monthly prices using historical relationships.
For options, long-term contracts and other contracts for which price quotes are not available,
we use models and other valuation methods. The valuation models we employ utilize spot prices,
forward prices, historical market data and other factors to forecast future prices. The primary
valuation technique we use to calculate the fair value of contracts where price quotes are not
available is based on the extrapolation of forward pricing curves using observable market data for
more liquid delivery points in the same region and actual transactions at the more illiquid
delivery points. We also value option contracts using a variation of the Black-Scholes
option-pricing model.
For non-exchange traded contracts, we calculate fair market value based on the average of the
bid and offer price, discounted to reflect net present value. We maintain certain valuation
adjustments for a number of risks associated with the valuation of future commitments. These
include valuation adjustments for liquidity and credit risks based on the financial condition of
counterparties. The liquidity valuation adjustment represents the cost that would be incurred if
all unmatched positions were closed-out or hedged.
The credit valuation adjustment represents estimated credit losses on our overall exposure to
counterparties, taking into account netting arrangements, expected default experience for the
credit rating of the counterparties and the overall diversification of the portfolio.
Counterparties in the portfolio consist principally of major energy companies, municipalities,
local distribution companies and financial institutions. We maintain credit policies that
management believes minimize overall credit risk. Determination of the credit quality of
counterparties is based upon a number of factors, including credit ratings, financial condition,
project economics and collateral requirements. When applicable, we employ standardized agreements
that allow for the netting of positive and negative exposures associated with a single
counterparty.
The use of models and other valuation methods to determine fair market value often requires
subjective and complex judgment. Actual results could differ from the results estimated through
application of these methods. Our marketing and trading portfolio includes structured activities
hedged with a portfolio of forward purchases that protects the economic value of the sales
transactions. Our practice is to hedge within timeframes established by the ERMC.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
See Note 2 for information about a new accounting standard on fair value measurements.
See Note 18 for additional information about our derivative and energy trading accounting
policies.
Regulatory Accounting
APS is regulated by the ACC and the FERC. The accompanying financial statements reflect the
rate-making policies of these commissions. For regulated operations, we prepare our financial
statements in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of
Regulation.” SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of
regulatory decisions in its financial statements. As a result, we capitalize certain costs that
would be included as expense in the current period by unregulated companies. Regulatory assets
represent incurred costs that have been deferred because they are probable of future recovery in
customer rates. Regulatory liabilities generally represent expected future costs that have already
been collected from customers.
Management continually assesses whether our regulatory assets are probable of future recovery
by considering factors such as applicable regulatory environment changes and recent rate orders to
other regulated entities in the same jurisdiction. This determination reflects the current
political and regulatory climate in the state and is subject to change in the future. If future
recovery of costs ceases to be probable, the assets would be written off as a charge in current
period earnings.
A major component of our regulatory assets is the retail fuel and power costs deferred under
the PSA. APS defers for future rate recovery or refund 90% of the difference between actual retail
fuel and purchased power costs and the amount of such costs currently included in base rates,
subject to specified parameters.
The detail of regulatory assets is as follows (dollars in millions):
Regulatory liability related to asset retirement
obligations
153
133
Tax benefit of Medicare subsidy
35
50
Deferred gains on utility property
20
20
Deferred interest income (b)
13
18
Regulatory liability for deferred income taxes
6
11
Other
24
16
Total regulatory liabilities
$
643
$
635
(a)
In accordance with SFAS No. 71, APS accrues for removal costs for its regulated assets,
even if there is no legal obligation for removal.
(b)
Subject to a carrying charge.
Utility Plant and Depreciation
Utility plant is the term we use to describe the business property and equipment that supports
electric service, consisting primarily of generation, transmission and distribution facilities. We
report utility plant at its original cost, which includes:
•
material and labor;
•
contractor costs;
•
capitalized leases;
•
construction overhead costs (where applicable); and
•
capitalized interest or an allowance for funds used during construction.
We expense the costs of plant outages, major maintenance and routine maintenance as incurred.
We charge retired utility plant to accumulated depreciation. Liabilities associated with the
retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized
as part of the related tangible long-lived assets. Accretion of the liability due to the passage
of time is an operating expense and the capitalized cost is depreciated over the useful life of the
long-lived asset. See Note 12.
APS records a regulatory liability for the asset retirement obligations related to its
regulated assets. This regulatory liability represents the difference between the amount that has
been recovered in regulated rates and the amount calculated under SFAS No. 143 “Accounting for
Asset Obligations,” as interpreted by FIN 47. APS believes it can recover in regulated rates the
costs calculated in accordance with SFAS No. 143.
We record depreciation on utility plant on a straight-line basis over the remaining useful
life of the related assets. The approximate remaining average useful lives of our utility property
at December 31, 2007 were as follows:
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
•
Fossil plant – 17 years;
•
Nuclear plant – 17 years;
•
Other generation – 29 years;
•
Transmission – 43 years;
•
Distribution – 33 years; and
•
Other – 6 years.
For the years 2005 through 2007, the depreciation rates ranged from a low of 1.11% to a high
of 12.46%. The weighted-average rate was 3.11% for 2007, 3.14 % for 2006 and 3.0% for 2005. We
depreciate non-utility property and equipment over the estimated useful lives of the related
assets, ranging from 3 to 34 years.
Investments
El Dorado accounts for its investments using either the equity method (if significant
influence) or the cost method (if less than 20% ownership).
Our investments in the nuclear decommissioning trust fund are accounted for in accordance with
EITF 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain
Investments.” See Note 12 for more information on these investments.
Capitalized Interest
Capitalized interest represents the cost of debt funds used to finance non-regulated
construction projects. The rate used to calculate capitalized interest was a composite rate of
5.8% for 2007, 6.8% for 2006 and 5.7% for 2005. Capitalized interest ceases when construction is
complete.
Allowance for Funds Used During Construction
AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed
return on the equity funds used for construction of regulated utility plant. APS’ allowance for
borrowed funds is included in capitalized interest on the Consolidated Financial Statements. Plant
construction costs, including AFUDC, are recovered in authorized rates through depreciation when
completed projects are placed into commercial operation.
AFUDC was calculated by using a composite rate of 8.2% for 2007, 8.0% for 2006 and 7.7% for
2005. APS compounds AFUDC monthly and ceases to accrue AFUDC when construction work is completed
and the property is placed in service.
Electric Revenues
We derive electric revenues from sales of electricity to our regulated Native Load customers
and sales to other parties from our marketing and trading activities. Revenues related to the sale
of electricity are generally recorded when service is rendered or electricity is delivered to
customers. The billing of electricity sales to individual Native Load customers is based on the
reading of their meters, which occurs on a systematic basis throughout the month. Unbilled
revenues are estimated by applying an average revenue/kWh to the number of estimated kWhs delivered
but not billed. Differences historically between the actual and estimated unbilled revenues are
immaterial. We
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
exclude sales taxes on electric revenues from both revenue and taxes other than income taxes.
Beginning April 2005, in accordance with a 2005 ACC order, we also
exclude city franchise fees from both electric revenues and operating expenses.
Revenues from our Native Load customers and non-derivative instruments are reported on a gross
basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some
contracts to purchase energy are netted against other contracts to sell energy. This is called a
“book-out” and usually occurs for contracts that have the same terms (quantities and delivery
points) and for which power does not flow. We net these book-outs, which reduces both revenues and
purchased power and fuel costs.
All gains and losses (realized and unrealized) on energy trading contracts that qualify as
derivatives are included in marketing and trading revenues on the Consolidated Statements of Income
on a net basis.
Real Estate Revenues
SunCor recognizes revenue from land, home and qualifying commercial operating assets sales in
full, provided (a) the income is determinable, that is, the collectibility of the sales price is
reasonably assured or the amount that will not be collectible can be estimated, and (b) the
earnings process is virtually complete, that is, SunCor is not obligated to perform significant
activities after the sale to earn the income. Unless both conditions exist, recognition of all or
part of the income is postponed under the percentage of completion method per SFAS No. 66,
“Accounting for Sales of Real Estate.” SunCor recognizes income only after the asset title has
passed. Commercial property and management revenues are recorded over the term of the lease or
period in which services are provided. In addition, see Note 22 – Discontinued Operations.
Real Estate Investments
Real estate investments primarily include SunCor’s land, home inventory, commercial property
and investments in joint ventures. Land includes acquisition costs, infrastructure costs, property
taxes and capitalized interest directly associated with the acquisition and development of each
project. Land under development and land held for future development are stated at accumulated
cost, except that, to the extent that such land is believed to be impaired, it is written down to
fair value. Land held for sale is stated at the lower of accumulated cost or estimated fair value
less costs to sell. Home inventory consists of construction costs, improved lot costs, capitalized
interest and property taxes on homes and condos under construction. Home inventory is stated at
the lower of accumulated cost or estimated fair value less costs to sell. Homes under construction
classified as “real estate investments” on the Consolidated Balance Sheets are transferred to “home
inventory” upon completion of construction with the expectation that they will be sold in a timely
manner. In previous years, “home inventory” was classified as “other current assets” on the
Consolidated Balance Sheets. Investments in joint ventures for which SunCor does not have a
controlling financial interest are not consolidated but are accounted for using the equity method
of accounting. In addition, see Note 22 – Discontinued Operations.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cash and Cash Equivalents
We consider all highly liquid investments with a maturity of three months or less at
acquisition to be cash equivalents.
Investments in auction rate securities have interest rates that are reset on a short-term
basis; however, the underlying contract maturity dates extend beyond three months. We classify the
investments in auction rate securities as investment in debt securities on our Consolidated Balance
Sheets.
Nuclear Fuel
APS amortizes nuclear fuel by using the unit-of-production method. The unit-of-production
method is based on actual physical usage. APS divides the cost of the fuel by the estimated number
of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number
of thermal units produced within the current period. This calculation determines the current
period nuclear fuel expense.
APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent
nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charges
APS $0.001 per kWh of nuclear generation. See Note 11 for information on spent nuclear fuel
disposal and Note 12 for information on nuclear decommissioning costs.
Income Taxes
Income taxes are provided using the asset and liability approach prescribed by SFAS No. 109,
“Accounting for Income Taxes” and FIN 48, “Accounting for Uncertainty in Income Taxes — An
Interpretation of FASB Statement No. 109.” We file our federal income tax return on a consolidated
basis and we file our state income tax returns on a consolidated or unitary basis. In accordance
with our intercompany tax sharing agreement, federal and state income taxes are allocated to each
first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return. Any
difference between that method and the consolidated (and unitary) income tax liability is
attributed to the parent company. The income tax liability accounts reflect the tax and interest
associated with management’s estimate of the most probable resolution of all known and measurable
tax exposures. See Note 4.
Reacquired Debt Costs
APS defers gains and losses incurred upon early retirement of debt. These costs are amortized
equally on a monthly basis over the remaining life of the original debt consistent with its
ratemaking treatment.
Stock-based Compensation
Pinnacle West offers stock-based compensation plans for officers and key employees of Pinnacle
West and some of our subsidiaries.
Effective January 1, 2006, we adopted SFAS No. 123(R), “Share-Based Payment,” using the
modified prospective application method. Because the fair value recognition provisions of both
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SFAS No. 123 and SFAS No. 123(R) are materially consistent with respect to our stock-based
compensation plans, the adoption of SFAS No. 123(R) did not have a material impact on our financial
statements. See Note 16.
Intangible Assets
We have no goodwill recorded and have separately disclosed other intangible assets, primarily
software, on Pinnacle West’s Consolidated Balance Sheets in accordance with SFAS No. 142, “Goodwill
and Other Intangible Assets.” The intangible assets are amortized over their finite useful lives.
Amortization expense was $37 million in 2007, $39 million in 2006 and $33 million in 2005.
Estimated amortization expense on existing intangible assets over the next five years is $29
million in 2008, $20 million in 2009, $19 million in 2010, $12 million in 2011 and $10 million in
2012. At December 31, 2007, the weighted average remaining amortization period for intangible
assets was 5 years.
2. New Accounting Standards
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This guidance
establishes a framework for measuring fair value and expands disclosures about fair value
measurements. The Statement is effective for us on January 1, 2008. We are currently evaluating
this new guidance but do not expect it to have a material impact on our financial statements.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets
and Financial Liabilities.” SFAS No. 159 provides companies with an option to report selected
financial assets and liabilities at fair value. SFAS No. 159 is effective for us on January 1,2008. We are currently evaluating this new guidance but do not expect it to have a material impact
on our financial statements.
In April 2007, the FASB issued FASB Staff Position No. FIN 39-1, “Amendment of FASB
Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FSP FIN 39-1). Under
FSP FIN 39-1, a reporting entity is permitted to offset the fair value amounts recognized for cash
collateral paid or cash collateral received against the fair value amounts recognized for
derivative instruments executed with the same counterparty under a master netting
arrangement. This new guidance is effective for us on January 1, 2008, with early application
permitted. We are currently evaluating the impacts of FSP FIN 39-1 on our balance sheet. We do
not expect the guidance to have an impact on our results of operations or cash flows.
See Note 4 for a discussion of FIN 48 on accounting for uncertainty in income taxes, which we
adopted January 1, 2007.
3. Regulatory Matters
Retail Rate Order
Retail Rate Increase On June 28, 2007, the ACC issued an order (the “Retail Rate Order”) in a
general retail rate case that APS filed in late 2005. The Retail Rate Order approved a $322
million increase in APS’ annual retail base revenues, effective July 1, 2007, which included a $315
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
million fuel-related increase and a $7 million non-fuel related increase. The Retail Rate
Order also authorized APS’ recovery of approximately $34 million of 2005 Deferrals through a
temporary PSA surcharge over a twelve-month period beginning July 1, 2007. The ACC disallowed
approximately $14 million of 2005 Deferrals because it found the Palo Verde outage costs giving
rise to those amounts resulted from APS’ imprudence.
PSA Modifications The Retail Rate Order modified the PSA in various respects, effective
July 1, 2007. The PSA, which the ACC initially approved in 2005 as a part of APS’ 2003 rate case,
provides for the adjustment of retail rates to reflect variations in retail fuel and purchased
power costs. As modified by the Retail Rate Order, the PSA is subject to specified parameters and
procedures, including the following:
•
APS records deferrals for recovery or refund to the extent actual retail fuel and
purchased power costs vary from the Base Fuel Rate (currently $0.0325 per kWh);
•
under a 90/10 sharing arrangement, APS defers 90% of the difference between retail
fuel and purchased power costs (excluding certain costs, such as renewable energy
resources and the capacity components of long-term purchase power agreements acquired
through competitive procurement) and the Base Fuel Rate; APS absorbs 10% of the
retail fuel and purchased power costs above the Base Fuel Rate and
retains 10% of
the benefit from the retail fuel and purchased power costs that are below the Base Fuel
Rate;
•
an adjustment is made annually each February 1st and goes into effect
automatically unless suspended by the ACC;
•
the PSA uses a forward-looking estimate of fuel and purchased power costs to set the
annual PSA rate, which will be reconciled to actual costs experienced for each PSA Year
(February 1 through January 31) (see the following bullet point);
•
the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds
differences between expected fuel and purchased power costs for the upcoming calendar
year and those embedded in the Base Fuel Rate; (b) an “Historical Component,” under
which differences between actual fuel and purchased power costs and those recovered
through the combination of the Base Fuel Rate and the Forward Component are recovered
during the next PSA Year; and (c) a “Transition Component,” under which APS may seek
mid-year PSA changes due to large variances between actual fuel and purchased power
costs and the combination of the Base Fuel Rate and the Forward Component;
•
amounts to be recovered or refunded through the sum of the PSA components discussed
in the preceding bullet point are limited to a maximum plus or minus $0.004 per kWh
change in the PSA rate in any PSA Year; and
•
the PSA adjustor that took effect on February 1, 2007 ($0.004 per kWh), and that was
scheduled to expire on January 31, 2008, will remain in effect as long as necessary
after January 31, 2008 to collect $46 million of 2007 fuel and purchased power costs
deferred as a result of the mid-2007 implementation of the new Base Fuel Rate.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSA Balance
The following table shows the changes in the deferred fuel and purchased power regulatory
asset for the years ended December 31, 2007 and 2006 (dollars in millions):
2007
2006
Beginning balance
$
160
$
173
Deferred fuel and purchased power costs-current period
189
244
Regulatory disallowance
(14
)
—
Interest on deferred fuel and purchased power
7
8
Amounts recovered through revenues
(231
)
(265
)
Ending balance
$
111
$
160
The PSA rate for the PSA Year beginning February 1, 2008 was set at the maximum $0.004 per
kWh. Any uncollected deferrals during the 2008 PSA Year resulting from this limit will be included
in the Historical Component of the PSA rate for the PSA Year beginning February 1, 2009.
2006 Deferrals
In May 2006, the ACC directed the ACC staff to conduct a “prudence audit” of 2006 Palo Verde
outage costs. APS recorded approximately $79 million of 2006 Deferrals, virtually all of which
were associated with a Unit 1 vibration issue. On October 4, 2007, the ACC staff filed a report
with the ACC that concluded that APS’ response to the Unit 1 vibration issue was “reasonable and
prudent.” APS continues to believe that these costs, which have been fully recovered, were
prudently incurred.
Line Extension Schedule
The Retail Rate Order required APS to file a revised line extension schedule for ACC approval
that would eliminate certain footage and equipment allowances for new or expanded electric service
and remove any requirement for economic feasibility analyses used to determine whether or how much
of an allowance should be granted. These changes would permit APS to collect, on a current basis,
costs related to line extensions.
On October 24, 2007, APS filed a proposed amendment to its line extension schedule, including
a proposal to treat line extension payments received as non-refundable other electric revenues.
APS proposed to “grandfather” applicants that have executed line extension agreements prior to the
effective date of its amended line extension schedule. The ACC Staff issued a recommended order
that was consistent with APS’ proposed line extension amendments in all significant respects except
for the authorized accounting treatment. The ACC staff proposed that payments received for new or
upgraded service be treated as contributions in aid of construction (“CIAC”), rather than as
non-refundable other electric revenues as APS requested. CIAC treatment would result in a positive
cash flow that will partially offset capital expenditures, but without any revenue impact. On
February 13, 2008, the ACC voted to approve the ACC staff recommended order, with minor
modifications.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Rate Requests for Transmission and Ancillary Services
On July 10, 2007, APS submitted a revised Open Access Transmission Tariff filing with the FERC
to move from a fixed rate to a formula rate in order to more accurately reflect the costs that APS
incurs in providing transmission and ancillary services. The requested formula rate would have
resulted in an estimated $37 million increase in annual transmission revenues, effective October 1,2007. The proposed formula rate would be updated each year effective June 1 on the basis of APS’
actual cost of service, as disclosed in APS’ FERC Form 1 report for the previous fiscal year, and
projected capital expenditures. Approximately $30 million of the requested increase represents
charges for transmission services to serve APS’ retail customers (“Retail Transmission Charges”).
On September 21, 2007, the FERC issued an order on these proposed revisions to APS’
transmission rates in which it accepted APS’ proposed formula rates and ordered settlement judge
procedures, which are underway. The proposed rates become effective March 1, 2008, subject to
refund based upon the ultimate outcome of proceedings at the FERC on this matter.
On December 31, 2007, APS filed with the ACC an application to increase annual pretax retail
revenues by approximately $30 million, effective March 1, 2008, to cover the Retail Transmission
Charges authorized by the FERC. This retail rate increase implements an ACC-approved mechanism by
which changes in Retail Transmission Charges can be reflected in APS’ retail rates. On February13, 2008, the ACC voted to approve APS’ request, subject to refund pending final outcome of FERC
proceedings on this matter.
Other
On April 7, 2005, the ACC issued an order in the rate case that APS filed on June 27, 2003. As
part of this order, APS was authorized to acquire the PWEC Dedicated Assets from Pinnacle West
Energy, with a net carrying value of approximately $850 million, and to rate base the PWEC
Dedicated Assets at a rate base value of $700 million, which resulted in a mandatory rate base
disallowance of approximately $150 million. Due to depreciation and other miscellaneous factors,
the actual disallowance was $139 million at December 31, 2005. This transfer was completed on
July 29, 2005. As a result, for financial reporting purposes, APS recognized a one-time, after-tax
net plant regulatory disallowance of approximately $84 million in 2005.
Federal
FERC Order
On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy, and APSES (collectively, the
“Pinnacle West Companies”) submitted to the FERC an update to their three-year market-based rate
review pursuant to the FERC’s order implementing a new generation market power analysis. On
December 20, 2004, the FERC issued an order approving the Pinnacle West Companies’ market-based
rates for control areas other than those of APS, Public Service Company of New Mexico (“PNM”) and
Tucson Electric Power Company (“TEP”). The FERC staff required the Pinnacle West Companies to
submit additional data with respect to these control areas, and the Pinnacle West Companies did so.
On April 17, 2006, the FERC issued an order revoking the Pinnacle West Companies’ authority to
make sales at market-based rates in the APS control area (the “April 17 Order”). The
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FERC found that the Pinnacle West Companies failed to provide the necessary information about the
calculation of transmission imports into the APS control area to allow the FERC to make a
determination regarding FERC’s generation market power “screens” in the APS control area. The FERC
found that the Pinnacle West Companies may charge market-based rates in the PNM and TEP control
areas.
On August 13, 2007, the FERC issued an order on rehearing, reinstating the authority of the
Pinnacle West Companies to make sales at market-based rates in all seasons for sales outside of the
Phoenix Valley, and in all seasons except the summer for sales within the Phoenix Valley. The
Pinnacle West Companies submitted a compliance filing implementing this order to the FERC on
October 12, 2007. This compliance filing was conditionally accepted by FERC in an order issued
January 17, 2008, requiring an additional compliance filing by the Pinnacle West Companies by
February 19, 2008.
Based upon an analysis of this matter and preliminary calculations of the refund obligations,
at this time neither Pinnacle West nor APS believes that this proceeding will have a material
adverse effect on its financial position, results of operations or cash flows.
4. Income Taxes
Certain assets and liabilities are reported differently for income tax purposes than they are
for financial statements purposes. The tax effect of these differences is recorded as deferred
taxes. We calculate deferred taxes using the current income tax rates.
APS has recorded a regulatory asset and a regulatory liability related to income taxes on its
Balance Sheets in accordance with SFAS No. 71. The regulatory asset is for certain temporary
differences, primarily the allowance for equity funds used during construction. The regulatory
liability relates to excess deferred taxes resulting primarily from pension and other
postretirement benefits. APS amortizes these amounts as the differences reverse.
As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax
accounting method change on our 2001 federal consolidated income tax return. The accelerated
deduction resulted in a $200 million reduction in the current income tax liability and a
corresponding increase in the plant-related deferred tax liability. Our 2001 federal consolidated
income tax return is currently under examination by the IRS. As part of its ongoing examination,
the IRS is reviewing this accounting method change and the resultant
deduction. Within the next six
months, we expect that the IRS will finalize its examination of the 2001 return, which will include
a settlement on the tax accounting method change. Although the ultimate outcome of this matter
cannot currently be predicted, the current status of the examination has resulted in changes in our
judgment, which are reflected in the reconciliation of the total amounts of unrecognized tax
benefits presented below. We do not expect the ultimate outcome of this examination to have a
material adverse impact on our financial position or results of operations. We expect that it will
have a negative impact on cash flows. We do not expect that there will be any other significant
increases or decreases in our unrecognized tax benefits within the next 12 months.
We adopted FIN 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB
Statement No. 109,” on January 1, 2007. The effect of applying the new guidance was not
significantly different in terms of tax impacts from the application of our previous policy.
Accordingly, the impact to retained earnings upon adoption was immaterial. In addition, the
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
guidance required us to reclassify certain tax benefits, which had the effect of increasing
accrued taxes and deferred debits by approximately $50 million to better reflect the expected
timing of the payment of taxes and interest.
Following
is a tabular reconciliation of the total amounts of unrecognized tax
benefits, excluding interest and penalties, at the
beginning and end of the period that are included in accrued taxes and other deferred credits on
the Consolidated Balance Sheets (dollars in thousands):
Included in the balance of unrecognized tax benefits at December 31, 2007 are approximately
$5 million of tax positions that, if recognized, would decrease our effective tax rate.
We reflect interest and penalties, if any, on unrecognized tax benefits in the statement of
operations as income tax expense. For 2007, the amount of interest recognized in the statement of
operations related to unrecognized tax benefits was $3 million.
As of December 31, 2007, the total amount of interest expense recognized in the statement of
financial position related to unrecognized tax benefits was $57 million. To the extent that matters are
settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, we
have recognized $5 million of interest income to be received on the overpayment of income taxes for
certain adjustments that we have filed, or will file, with the IRS.
As of December 31, 2007, the tax year ended December 31, 1999 and all subsequent tax years
remain subject to examination by federal and state taxing authorities. In addition, tax years
ended prior to December 31, 1999 may remain subject to examination by state taxing authorities.
The components of income tax expense are as follows (dollars in thousands):
Less: income tax expense (benefit) on
discontinued operations
5,572
6,570
(29,797
)
Income tax expense — continuing operations
$
150,920
$
156,418
$
126,892
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):
Pinnacle West had a committed line of credit with various banks totaling $300 million at
December 31, 2007 and December 31, 2006, which was available either to support the issuance of up
to $250 million in commercial paper or to be used for bank borrowings, including issuance of
letters of credit. The current line terminates in December 2010. Pinnacle West had no outstanding
borrowings under the lines of credit at December 31, 2007 and December 31, 2006. Pinnacle West had
approximately $5 million of letters of credit issued under the line at December 31, 2007 and
approximately $4 million of letters of credit issued under the line at December 31, 2006. The
commitment fees were 0.15% in 2007 and 2006. Pinnacle West had commercial paper borrowings of $115
million outstanding at December 31, 2007 and $28 million outstanding at December 31, 2006. The
weighted average interest rates were 5.73% at December 31, 2007 and 5.625% at December 31, 2006.
All Pinnacle West and APS bank lines of credit and commercial paper agreements are unsecured.
APS had two committed lines of credit with various banks totaling $900 million at December
2007 and 2006, all of which were available either to support the issuance of up to $250 million in
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
commercial paper or to be used for bank borrowings, including the issuance of letters of
credit. The $400 million line terminates in December 2010 and the $500 million line terminates in
September 2011. APS may increase the $500 million line to $600 million if certain conditions are
met. The commitment fees for these lines of credit were 0.10% and 0.11% at December 31, 2007 and
December 31, 2006. APS had bank borrowings outstanding of $218 million under the $500 million line
of credit at December 31, 2007 and no borrowings outstanding at December 31, 2006. The weighted
average interest rate was 5.361% at December 31, 2007. APS had approximately $4 million of letters
of credit issued under the $400 million line at December 31, 2007 and 2006.
Although provisions in APS’ articles of incorporation and ACC financing orders establish
maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these
provisions to limit its ability to meet its capital requirements. On October 30, 2007, the ACC
issued a financing order in which it approved APS’ request, subject to specified parameters and
procedures, to increase (a) APS’ short-term debt authorization from 7% of APS’ capitalization to
(i) 7% of APS’ capitalization plus (ii) $500 million and (b) APS’ long-term debt authorization from
approximately $3.2 billion to $4.2 billion in light of the projected growth of APS and its customer
base and the resulting projected financing needs.
SunCor had two revolving lines of credit totaling $170 million at December 31, 2007, and
December 31, 2006 maturing in October 2008 and December 2008. The commitment fees were 0.125% in
2007 and 2006 for the $150 million line of credit. The commitment fees for the $20 million line of
credit were 0.50% in 2007 and 2006. SunCor had $94 million outstanding at December 31, 2007 and
$118 million outstanding at December 31, 2006. The weighted-average interest rate was 7.27% at
December 31, 2007 and 7.09% at December 31, 2006. Interest was based on LIBOR plus 2.0% for 2007
and 2006. The balance is included in current maturities of long-term debt on the Consolidated
Balance Sheets at December 31, 2007 and 2006. SunCor had other short-term loans in the amount of
$8 million at December 31, 2007 and $8 million at December 31, 2006. These loans are made up of
multiple notes primarily with variable interest rates based on LIBOR plus 2.5% at December 31, 2007
and 2006.
6. Long-Term Debt
Substantially all of APS’ debt is unsecured. SunCor’s short and long-term debt is
collateralized by interests in certain real property and Pinnacle West’s debt is unsecured. The
following table presents the components of long-term debt on the Consolidated Balance Sheets
outstanding at December 31, 2007 and 2006 (dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31,
Maturity
Interest
Dates (a)
Rates
2007
2006
APS
Pollution control bonds
2024-2034
(b
)
$
565,855
$
565,855
Pollution control bonds with senior
notes
2029
5.05
%
90,000
90,000
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
2014
5.80
%
300,000
300,000
Secured note
2014
6.00
%
1,430
1,592
Senior notes
2035
5.50
%
250,000
250,000
Senior notes (c)
2016
6.25
%
250,000
250,000
Senior notes (c)
2036
6.875
%
150,000
150,000
Unamortized discount and premium
(8,883
)
(9,857
)
Capitalized lease obligations
2007-2012
(d
)
4,457
5,880
Subtotal (e)
2,877,859
2,878,470
SUNCOR
Notes payable
2008-2013
(f
)
237,671
180,316
Capitalized lease obligations
2007-2010
(g
)
368
328
Subtotal
238,039
180,644
PINNACLE WEST
Senior notes (h)
2011
5.91
%
175,000
175,000
Capitalized lease obligations
2007
5.45
%
—
115
Subtotal
175,000
175,115
Total long-term debt
3,290,898
3,234,229
Less current maturities
163,773
1,596
TOTAL LONG-TERM DEBT LESS CURRENT
MATURITIES
$
3,127,125
$
3,232,633
(a)
This schedule does not reflect the timing of redemptions that may occur prior to maturity.
(b)
The weighted-average rate was 3.76% at December 31, 2007 and 3.77% at December 31, 2006.
Changes in short-term interest rates would affect the costs associated with this debt. In
addition, these amounts include $343 million of auction rate debt securities backed by
insurance at December 31, 2007 and 2006.
(c)
On August 3, 2006, APS issued $250 million 6.25% notes due 2016 and $150 million 6.875% notes
due 2036. A portion of the proceeds was used to repay outstanding commercial paper balances
and $84 million of its 6.75% senior note that matured November 15, 2006. The remainder has
been used to fund its construction program and other general corporate purposes.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(f)
SunCor had $94 million outstanding at December 31, 2007 under its revolving lines of credit.
The weighted-average interest rate was 7.27% at December 31, 2007. The remaining amount of
approximately $143 million at December 31, 2007 was made up of multiple notes with variable
interest rates based on the lenders’ prime rates plus 1.75% and 2.0% or LIBOR plus 1.7%, 2.0%
and 2.25%. SunCor had $118 million outstanding at December 31, 2006 under its revolving line
of credit. The weighted-average interest rate was 7.08% at December 31, 2006. The remaining
amount of approximately $62 million at December 31, 2006 was made up of multiple notes with
variable interest rates based on the lenders’ prime rates plus 1.75% and 2.0% or LIBOR plus
2.25%. There is also a note at a fixed rate of 4.25% at December 31, 2007 and 2006
On February 28, 2006, Pinnacle West entered into a $200 million Senior Notes Uncommitted
Master Shelf Agreement with Prudential Investment Management Inc. (“Prudential”). Under the
terms of the agreement, Pinnacle West may offer up to $200 million of its senior notes for
purchase by Prudential at any time prior to December 31, 2007. The maturity of the notes
cannot exceed five years. On February 28, 2006, Pinnacle West issued $175 million of its
5.91% senior notes, series A, to Prudential.
Pinnacle West’s and APS’ debt covenants related to their respective bank financing
arrangements include debt to capitalization ratios. Certain of APS’ bank financing arrangements
also include an interest coverage test. Pinnacle West and APS comply with these covenants and each
anticipates it will continue to meet these and other significant covenant requirements. For both
Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total
consolidated capitalization cannot exceed 65%. At December 31, 2007, the ratio was approximately
50% for Pinnacle West and 47% for APS. The provisions regarding interest coverage require a
minimum cash coverage of two times the interest requirements for APS. The interest coverage was
approximately 4.7 times under APS’ bank financing agreements as of December 31, 2007. Failure to
comply with such covenant levels would result in an event of default which, generally speaking,
would require the immediate repayment of the debt subject to the covenants and could cross-default
other debt. See further discussion of “cross-default” provisions below.
Neither Pinnacle West’s nor APS’ financing agreements contain “rating triggers” that would
result in an acceleration of the required interest and principal payments in the event of a rating
downgrade. However, our bank financing agreements contain a pricing grid in which interest costs
we pay are determined by our current credit ratings.
All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in
defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or
APS were to default under certain other material agreements. All of APS’ bank agreements contain
cross-default provisions that would result in defaults and the potential acceleration of payment
under these bank agreements if APS were to default under certain other material agreements.
Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings.
An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As
defined in the ACC order, the common equity ratio is common equity divided by the sum of common
equity and long-term debt, including current maturities of long-term debt. At December 31, 2007,
APS’ common equity ratio, as defined, was 54%, its total common equity was approximately $3.4
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
billion, and total capitalization was approximately $6.2 billion. APS would be prohibited
from paying dividends if the payment would reduce its common equity below approximately $2.5
billion, assuming APS’ total capitalization remains the same.
SunCor has a $150 million loan facility secured primarily by an interest in land, commercial
properties, land contracts and homes under construction. The loan facility requires compliance
with certain loan covenants pertaining to debt to net worth, debt service, liquidity, cash flow
coverage and restrictions on debt. As of December 31, 2007, the amount of SunCor’s net assets that
could not be transferred to Pinnacle West in the form of cash dividends as a result of these
covenants was approximately $217 million.
As a result of the restrictions in the preceding two paragraphs, as of December 31, 2007, the
restricted net assets of our subsidiaries exceeded 25% of our consolidated net assets (at December31, 2007, our consolidated net assets were approximately $3.5 billion). These restrictions do not
materially affect Pinnacle West’s ability to meet its ongoing capital requirements.
The following table shows principal payments due on Pinnacle West’s and APS’ total long-term
debt and capitalized lease requirements (dollars in millions):
Year
Pinnacle West
APS
2008
$
164
$
1
2009
72
1
2010
224
224
2011
578
401
2012
376
376
Thereafter
1,886
1,884
Total
$
3,300
$
2,887
7. Common Stock and Treasury Stock
Our common stock and treasury stock activity during each of the three years 2007, 2006 and
2005 is as follows (dollars in thousands):
On May 2, 2005, Pinnacle West issued 6,095,000 shares of its common stock at an
offering price of $42 per share, resulting in net proceeds of approximately $248
million. Pinnacle West used the net proceeds for general corporate purposes, including
making capital contributions to APS, which, in turn, used such funds to pay a portion
of the approximately $190 million purchase price to acquire the Sundance Plant and for
other capital expenditures incurred to meet the growing needs of APS’ service
territory.
(b)
Represents shares of common stock withheld from certain stock awards for tax
purposes.
8. Retirement Plans and Other Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a
non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and
its subsidiaries. All new employees participate in the account balance plan. A defined benefit
plan specifies the amount of benefits a plan participant is to receive using information about the
participant. The pension plan covers nearly all employees. The supplemental excess benefit
retirement plan covers officers of the Company and highly compensated employees designated for
participation by the Board of Directors. Our employees do not contribute to the plans. Generally,
we calculate the benefits based on age, years of service and pay.
We also sponsor other postretirement benefits for the employees of Pinnacle West and our
subsidiaries. We provide medical and life insurance benefits to retired employees. Employees must
retire to become eligible for these retirement benefits, which are based on years of service and
age.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the medical insurance plans, retirees make contributions to cover a portion of the plan
costs. For the life insurance plan, retirees do not make contributions. We retain the right to
change or eliminate these benefits.
Pinnacle West uses a December 31 measurement date for its pension and other postretirement
benefit plans. The market-related value of our plan assets is their fair value at the measurement
date. The fair market value of investments in our retirement and
postretirement plans is determined using actively-quoted prices when
available. When actively-quoted prices are not available, we use
prices provided by external sources, models or other valuation
methods. The use of models and other valuation methods to determine
fair market value often requires subjective and complex judgment.
Actual results could differ from the results estimated through the
application of these methods.
A
significant portion of the changes in the actuarial gains and losses
of our pension and postretirement plans are attributable to APS and
therefore are recoverable in rates. Accordingly these changes are
recorded as a regulatory asset.
The following table provides details of the plans’ benefit costs. Also included is the
portion of these costs charged to expense, including administrative costs and excluding amounts
capitalized as overhead construction or billed to electric plant participants (dollars in
thousands):
Pension
Other Benefits
2007
2006
2005
2007
2006
2005
Service cost-benefits
earned during the
period
$
51,803
$
47,287
$
45,027
$
18,491
$
19,968
$
20,913
Interest cost on benefit
obligation
100,736
92,196
87,189
35,284
34,653
34,223
Expected return on plan
assets
(107,165
)
(95,912
)
(88,403
)
(42,177
)
(36,930
)
(30,471
)
Amortization of:
Transition
(asset) obligation
—
(645
)
(3,227
)
3,005
3,005
3,005
Prior service
cost (credit)
2,957
2,401
2,401
(125
)
(125
)
(125
)
Net actuarial
loss
16,331
23,366
19,810
3,929
8,662
9,243
Net periodic benefit
cost
$
64,662
$
68,693
$
62,797
$
18,407
$
29,233
$
36,788
Portion of cost charged
to expense
$
28,063
$
30,912
$
26,375
$
7,989
$
13,155
$
15,451
APS share of costs charged
to expense
$
26,548
$
29,203
$
24,169
$
7,557
$
12,428
$
14,159
The following table shows the plans’ changes in the benefit obligations and funded status for
the years 2007 and 2006 (dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Change in Plan Assets
Fair value of plan assets at
January 1
$
1,214,229
$
1,064,848
$
480,638
$
416,174
Actual return on plan assets
101,138
148,895
26,952
47,988
Employer contributions
52,000
46,500
18,407
29,233
Benefit payments
(48,428
)
(46,014
)
(26,233
)
(12,757
)
Fair value of plan assets at
December 31
1,318,939
1,214,229
499,764
480,638
Funded Status at December 31
$
(401,905
)
$
(456,045
)
$
(105,361
)
$
(136,347
)
The following table shows the projected benefit obligation and the accumulated benefit
obligation for the pension plan in excess of plan assets as of December 31, 2007 and 2006 (dollars
in thousands):
2007
2006
Projected benefit obligation
$
1,720,844
$
1,670,274
Accumulated benefit obligation
1,484,444
1,426,492
Fair value of plan assets
1,318,939
1,214,229
The following table shows the amounts recognized on the Consolidated Balance Sheets as of
December 31, 2007 and 2006 (dollars in thousands):
Pension
Other Benefits
2007
2006
2007
2006
Current asset
$
—
$
—
$
1,321
$
—
Current liability
(3,984
)
(3,540
)
—
—
Noncurrent liability
(397,921
)
(452,505
)
(106,682
)
(136,347
)
Net amount recognized
$
(401,905
)
$
(456,045
)
$
(105,361
)
$
(136,347
)
The following table shows the details related to accumulated other comprehensive loss before
income taxes as of December 31, 2007 and 2006 (dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table shows the estimated amounts that will be amortized from accumulated other
comprehensive loss and regulatory assets into net periodic benefit cost in 2008 (dollars in
thousands):
Other
Pension
Benefits
Net actuarial loss
$
9,048
$
4,042
Prior service cost (credit)
2,455
(125
)
Transition obligation
—
3,005
Total amounts estimated to be
amortized from accumulated
other comprehensive income and
regulatory assets in 2008
$
11,503
$
6,922
The following table shows the weighted-average assumptions used for both the pension and other
benefits to determine benefit obligations and net periodic benefit costs:
In selecting the pretax expected long-term rate of return on plan assets we consider past
performance and economic forecasts for the types of investments held by the plan. For the year
2008, we are assuming a 9% long-term rate of return on plan assets, which we believe is reasonable
given our asset allocation in relation to historical and expected performance.
Assumed health care cost trend rates have a significant effect on the amounts reported for the
health care plans. A one percentage point change in the assumed initial and ultimate health care
cost trend rates would have the following effects (dollars in millions):
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
$
(5
)
Effect on service and interest
cost components of net periodic
other postretirement benefit
costs
10
(8
)
Effect on the accumulated other
postretirement benefit
obligation
94
(76
)
Plan Assets
Pinnacle West’s qualified pension plan and other postretirement benefit plans’ asset
allocation at December 31, 2007 and 2006 is as follows:
Pension
Other Benefits
Asset Category:
2007
2006
Target
2007
2006
Target
Equity securities
68
%
69
%
68
%
70
%
74
%
70
%
Fixed income
25
25
25
28
25
27
Other
7
6
7
2
1
3
Total
100
%
100
%
100
%
100
%
100
%
100
%
The Board of Directors has delegated oversight of the plan assets to an Investment Management
Committee. The investment policy sets forth the objective of providing for future pension benefits
by maximizing return consistent with acceptable levels of risk. The primary investment strategies
are diversification of assets, stated asset allocation targets and ranges, prohibition of
investments in Pinnacle West securities, and external management of plan assets.
The Investment Management Committee, described above, has also been delegated oversight of the
plan assets for the other postretirement benefit plans. The investment policy for other
postretirement benefit plans’ assets is similar to that of the pension plan assets described above.
Contributions
The contribution to our pension plan in 2008 is estimated to be approximately $50 million.
The contribution to our other postretirement benefit plans in 2008 is estimated to be approximately
$20 million. APS and other subsidiaries fund their share of the contributions. APS’ share is
approximately 96% of both plans.
Estimated Future Benefit Payments
Benefit payments, which reflect estimated future employee service, for the next five years and
the succeeding five years thereafter are estimated to be as follows (dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Year
Pension
Other Benefits (a)
2008
$
60,536
$
19,315
2009
66,799
21,246
2010
73,624
23,846
2011
82,764
26,579
2012
93,371
29,293
Years 2013-2017
639,326
194,680
(a)
The expected future other benefit payments take into account the Medicare Part
D subsidy.
Employee Savings Plan Benefits
Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle
West and its subsidiaries. In 2007, costs related to APS’ employees represented 97% of the total
cost of this plan. In a defined contribution savings plan, the benefits a participant receives
result from regular contributions participants make to their own individual account, the Company’s
matching contributions and earnings or losses on their investments.
Under this plan, the Company matches a percentage of the
participants’ contributions in cash which is then invested in
the same investment mix as participants elect to invest their own
future contributions. At December 31, 2007,
approximately 15% of total plan assets were in Pinnacle West stock. Pinnacle West recorded
expenses for this plan of approximately $7 million for 2007, $6 million for 2006 and $6 million for
2005. APS recorded expenses for this plan of approximately $6 million in 2007, $6 million in 2006
and $6 million in 2005.
9. Leases
In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in
three separate sale leaseback transactions. APS accounts for these leases as operating leases.
The gain resulting from the transaction of approximately $140 million was deferred and is being
amortized to operations and maintenance expense over 29.5 years, the original term of the leases.
There are options to renew the leases and to purchase the property for fair market value at the end
of the lease terms. Rent expense is calculated on a straight-line basis. See Note 20 for a
discussion of VIEs, including the VIE’s involved in the Palo Verde sale leaseback transactions.
In addition, we lease certain land, buildings, equipment, vehicles and miscellaneous other
items through operating rental agreements with varying terms, provisions and expiration dates.
Total lease expense recognized in the Consolidated Statements of Income was $73 million in
2007, $72 million in 2006 and $71 million in 2005. APS’ lease expense was $66 million in 2007, $64
million in 2006 and $58 million in 2005.
The amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year
for the years 2008 to 2015.
Estimated future minimum lease payments for Pinnacle West’s and APS’ operating leases,
excluding purchase power agreements, are approximately as follows (dollars in millions):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pinnacle West
Year
Consolidated
APS
2008
$
79
$
72
2009
75
69
2010
73
67
2011
68
63
2012
65
61
Thereafter
195
177
Total future lease commitments
$
555
$
509
10. Jointly-Owned Facilities
APS shares ownership of some of its generating and transmission facilities with other
companies. Our share of operations and maintenance expense and utility plant costs related to
these facilities is accounted for using proportional consolidation. The following table shows APS’
interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at
December 31, 2007 (dollars in thousands):
Construction
Percent
Plant in
Accumulated
Work in
Owned
Service
Depreciation
Progress
Generating facilities:
Palo Verde Units 1 and 3
29.1
%
$
1,939,389
$
1,038,432
$
132,618
Palo Verde Unit 2 (see Note 9)
17.0
%
672,564
303,638
16,630
Four Corners Units 4 and 5
15.0
%
182,052
99,127
12,345
Navajo Generating Station
Units 1, 2 and 3
14.0
%
255,592
142,144
1,855
Cholla common facilities (a)
63.9
%(b)
91,636
49,741
31,692
Transmission facilities:
ANPP500KV System
35.8
%(b)
79,515
24,001
4,399
Navajo Southern System
31.4
%(b)
38,935
12,665
5,575
Palo Verde — Yuma 500KV
System
23.9
%(b)
9,230
3,857
3,427
Four Corners Switchyards
27.5
%(b)
3,198
1,304
—
Phoenix — Mead System
17.1
%(b)
36,032
4,823
—
Palo Verde — Estrella 500KV
System
55.5
%(b)
74,318
3,990
—
Harquahala
80.0
%(b)
—
—
6,418
(a)
PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common
facilities at Cholla are jointly-owned.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. Commitments and Contingencies
Palo Verde Nuclear Generating Station
Spent Nuclear Fuel and Waste Disposal
Nuclear power plant operators are required to enter into spent fuel disposal contracts with
the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other
high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste
Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent
nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before at least
2017. In November 1997, the United States Court of Appeals for the District of Columbia Circuit
(D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to
order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a
number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed
damages actions against the DOE in the Court of Federal Claims. APS is currently pursuing that
damages claim.
APS currently estimates it will incur $147 million (in 2007 dollars) over the life of Palo
Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At
December 31, 2007, APS had a regulatory liability of $11 million that represents amounts recovered
in retail rates in excess of amounts spent for on-site interim spent fuel storage.
Nuclear Insurance
The Palo Verde participants have insurance for public liability resulting from nuclear energy
hazards to the full limit of liability under federal law. This potential liability is covered by
primary liability insurance provided by commercial insurance carriers in the amount of $300 million
and the balance by an industry-wide retrospective assessment program. If losses at any nuclear
power plant covered by the program exceed the accumulated funds, APS could be assessed
retrospective premium adjustments. The maximum assessment per reactor under the program for each
nuclear incident is approximately $101 million, subject to an annual limit of $15 million per
incident, to be periodically adjusted for inflation. Based on APS’ interest in the three Palo
Verde units, APS’ maximum potential assessment per incident for all three units is approximately
$88 million, with an annual payment limitation of approximately $13 million.
The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for
property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75
billion, a substantial portion of which must first be applied to stabilization and decontamination.
APS has also secured insurance against portions of any increased cost of generation or purchased
power and business interruption resulting from a sudden and unforeseen accidental outage of any of
the three units. The property damage, decontamination, and replacement power coverages are
provided by Nuclear Electric Insurance Limited (NEIL). APS is subject to retrospective assessments
under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum
amount of retrospective assessments APS could incur under the current NEIL policies totals
$21.1 million. The insurance coverage discussed in this and the previous paragraph is subject to
certain policy conditions and exclusions.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fuel and Purchased Power Commitments
Pinnacle West and APS are parties to various fuel and purchased power contracts with terms
expiring between 2008 and 2025 that include required purchase provisions. Pinnacle West estimates
the contract requirements to be approximately $418 million in 2008; $358 million in 2009; $293
million in 2010; $218 million in 2011; $216 million in 2012; and $1.6 billion thereafter. APS
estimates the contract requirements to be approximately $375 million in 2008; $358 million in 2009;
$293 million in 2010; $212 million in 2011; $210 million in 2012; and $1.6 billion thereafter.
However, these amounts may vary significantly pursuant to certain provisions in such contracts that
permit us to decrease required purchases under certain circumstances.
Of the various fuel and purchased power contracts mentioned above some of those contracts have
take-or-pay provisions. The contracts APS has for its coal supply include take-or-pay provisions.
The current take-or-pay coal contracts have terms that expire in 2024.
The following table summarizes our actual and estimated take-or-pay commitments (dollars in
millions):
Actual
Estimated (a)
2005
2006
2007
2008
2009
2010
2011
2012
Thereafter
Coal take-or-pay
commitments
$
48
$
67
$
70
$
81
$
97
$
75
$
77
$
78
$
476
(a)
Total take-or-pay commitments are approximately $884 million. The total net
present value of these commitments is approximately $588 million.
Coal Mine Reclamation Obligations
APS must reimburse certain coal providers for amounts incurred for coal mine reclamation.
APS’ coal mine reclamation obligation was approximately $91 million at December 31, 2007 and $75
million at December 31, 2006 and is included in Deferred Credits and Other on the Consolidated
Balance Sheets.
California Energy Market Issues and Refunds in the Pacific Northwest
FERC
In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot
market transactions in California during a specified time frame. APS was a seller and a purchaser
in the California markets at issue and, to the extent that refunds are ordered, APS should be a
recipient as well as a payor of such amounts. The FERC is still considering the evidence and
refund amounts have not yet been finalized. However, on September 6, 2005, the Ninth Circuit
issued a decision, concluding that the FERC may not order refunds from entities that are not within
the FERC’s jurisdiction. Because a number of the entities owing refunds under the FERC’s
calculations are not within the FERC’s jurisdiction, this order may affect the level of recovery of
refunds due in this proceeding. In addition, on August 8, 2005, the FERC issued an order allowing
sellers in the California markets to demonstrate that its refund methodology results in an overall
revenue shortfall for their transactions in the relevant markets over a specified time frame. More
than twenty sellers made such cost recovery filings on September 14, 2005. On January 26, 2006,
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the FERC conditionally accepted thirteen of these filings, reducing the refund liability for
these sellers. Correspondingly, this will reduce the recovery of total refunds in the California
markets. On August 2, 2006, the Ninth Circuit issued a decision on the appropriate temporal scope
and the type of transactions that are properly subject to the refund orders. In the decision, the
Court preserved the scope of the FERC’s existing refund proceedings, but also expanded it
potentially to include additional transactions, remanding the orders to the FERC for further
proceedings. Various parties filed petitions for rehearing on this order. In addition, on
December 19, 2006, the Ninth Circuit issued a decision on the appropriate standard of review at the
FERC on wholesale power contracts in the refund proceedings, specifically addressing the
application of the so-called “just and reasonable” standard as opposed to the “public interest”
standard. In so doing, the Ninth Circuit remanded the matter back to the FERC with the requirement
that the FERC review the refund matter using the appropriate standard of review. Several parties
sought rehearing of this decision at the Ninth Circuit. Like the August 2, 2006 Ninth Circuit
decision, the December 19, 2006 decision has the potential to expand the existing FERC refund
proceedings. We currently believe the refund claims at the FERC will have no material adverse
impact on our financial position, results of operations or cash flows.
On March 19, 2002, the State of California filed a complaint with the FERC alleging that
wholesale sellers of power and energy, including the Company, failed to properly file rate
information at the FERC in connection with sales to California from 2000 to the present under
market-based rates. The complaint requests the FERC to require the wholesale sellers to refund any
rates that are “found to exceed just and reasonable levels.” This complaint was dismissed by the
FERC, and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an
order issued September 9, 2004, the Ninth Circuit upheld the FERC’s authority to permit
market-based rates, but rejected the FERC’s claim that it was without authority to consider
retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements
of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the
FERC for further proceedings. Several of the intervenors in this appeal filed a petition for
rehearing of this decision on October 25, 2004. The petition for rehearing was denied on July 31,2006. On December 28, 2006, certain parties petitioned the Supreme Court for a writ of certiorari.
This petition was denied on June 18, 2007. The Ninth Circuit issued the mandate for this
proceeding on December 4, 2007. The outcome of the further proceedings cannot be predicted at this
time.
On July 25, 2001, the FERC also ordered an evidentiary proceeding to discuss and evaluate
possible refunds for wholesale sales in the Pacific Northwest. The FERC affirmed the ALJ’s
conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds
should not be ordered in this proceeding. This decision was appealed to the U.S. Court of Appeals
for the Ninth Circuit. On August 24, 2007, the Ninth Circuit issued an opinion that remanded the
proceeding to the FERC for further consideration. Petitions for rehearing of this opinion were
filed on December 17, 2007. Although the FERC ruling in this matter is being appealed and the FERC
has not yet calculated the specific refund amounts at issue, we do not expect that the resolution
of these issues will have a material adverse impact on our financial position, results of
operations or cash flows.
On March 26, 2003, the FERC made public a Final Report on Price Manipulation in Western
Markets, prepared by its staff and covering spot markets in the West in 2000 and 2001. The report
stated that a significant number of entities who participated in the California markets during the
2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions
that allegedly violated certain provisions of the Independent System Operator tariff. After
reviewing
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the matter, along with the data supplied by APS, the FERC staff moved to dismiss the claims
against APS and to dismiss the proceeding. The motion to dismiss was granted by the FERC on
January 22, 2004. Certain parties have sought rehearing of this order, and that request is
pending.
Navajo Nation Litigation
In June 1999, the Navajo Nation served Salt River Project with a lawsuit filed in the United
States District Court for the District of Columbia (the “D.C. Lawsuit”) naming Salt River Project,
several Peabody Coal Company entities (collectively, “Peabody”), Southern California Edison Company
and other defendants, and citing various claims in connection with the renegotiations of the coal
royalty and lease agreements under which Peabody mines coal for the Navajo Generating Station and
the Mohave Generating Station. APS is a 14% owner of the Navajo Generating Station, which Salt
River Project operates. The D.C. Lawsuit alleges, among other things, that the defendants obtained
a favorable coal royalty rate by improperly influencing the outcome of a federal administrative
process under which the royalty rate was to be adjusted. The suit seeks $600 million in damages,
treble damages, punitive damages of not less than $1 billion, and the ejection of defendants “from
all possessory interests and Navajo Tribal lands arising out of the [primary coal lease].” In July
2001, the court dismissed all claims against Salt River Project.
In January 2005, Peabody served APS with a lawsuit filed in the Circuit Court for the City of
St. Louis naming APS and the other Navajo Generating Station participants and seeking, among other
things, a declaration that the participants “are obligated to reimburse Peabody for any royalty,
tax, or other obligation arising out of the D.C. Lawsuit.” Based on APS’ ownership interest in the
Navajo Generating Station, APS could be liable for up to 14% of any such obligation. APS cannot
currently predict the outcome of this matter.
Superfund
Superfund establishes liability for the cleanup of hazardous substances found contaminating
the soil, water or air. Those who generated, transported or disposed of hazardous substances at a
contaminated site are among those who are PRPs. PRPs may be strictly, and often jointly and
severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers
APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (OU3) in
Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West
have agreed with the EPA to perform certain investigative activities of the APS facilities within
OU3. Because the investigation has not yet been completed and ultimate remediation requirements
are not yet finalized, at the present time neither APS nor Pinnacle West can accurately estimate
the expenditures that may be required.
Salt River Project
Salt River Project has notified APS that Salt River Project allegedly failed to bill APS for
(a) energy losses under certain service schedules of a power contract between the parties and (b)
certain other charges under the contract. Salt River Project asserts that certain of these
failures to bill APS for such losses and charges may extend back to 1996 and, as a result, claims
that APS owes it approximately $29 million. APS disputes that it is required to pay these
amounts. No lawsuit or litigation has been initiated in the matter at this time. We do not expect
that resolution of this matter will have a material adverse impact on our financial position,
results of operations, or cash flows.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Litigation
We are party to various other claims, legal actions and complaints arising in the ordinary
course of business, including but not limited to environmental matters related to the Clean Air
Act, Navajo Nation issues and EPA and ADEQ issues. In our opinion, the ultimate resolution of
these matters will not have a material adverse effect on our financial position, results of
operations or cash flows.
12. Asset Retirement Obligations
APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other
generation, transmission and distribution assets. The Palo Verde asset retirement obligation
primarily relates to final plant decommissioning. This obligation is based on the NRC’s
requirements for disposal of radiated property or plant and agreements APS reached with the ACC for
final decommissioning of the plant. The non-nuclear generation asset retirement obligations
primarily relate to requirements for removing portions of those plants at the end of the plant life
or lease term.
Some of APS’ transmission and distribution assets have asset retirement obligations because
they are subject to right of way and easement agreements that require final removal. These
agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS
cannot reasonably estimate the fair value of the asset retirement obligation related to such
distribution and transmission assets.
Additionally, APS has aquifer protection permits for some of its generation sites that require
the closure of certain facilities at those sites. The generation sites are strategically located
to serve APS Native Load customers. Management expects to continuously use the sites and, thus,
cannot estimate a potential closure date. The asset retirement obligations associated with our
non-regulated assets are immaterial.
The following schedule shows the change in our asset retirement obligations for 2007 and 2006
(dollars in millions):
2007
2006
Asset retirement obligations at the
beginning of year
$
268
$
269
Changes attributable to:
Liabilities settled
(2
)
(2
)
Accretion expense
20
19
Estimated cash flow revisions
(4
)
(18
)
Asset retirement obligations at the
end of year
$
282
$
268
In accordance with SFAS No. 71, APS accrues removal costs for its regulated utility assets,
even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 1.
To fund the costs APS expects to incur to decommission Palo Verde, APS established external
decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
fixed income securities and domestic equity securities. APS applies the provisions of SFAS No.
115, “Accounting for Certain Investments in Debt and Equity Securities,” in accounting for
investments in decommissioning trust funds, and classifies these investments as available for sale.
As a result, we record the decommissioning trust funds at their fair value on our Consolidated
Balance Sheets. Because of the ability of APS to recover decommissioning costs in rates and in
accordance with the regulatory treatment for decommissioning trust funds, we have recorded the
offsetting amount of gains on investment securities in other regulatory liabilities or assets. The
following table summarizes the fair value of APS’ nuclear decommissioning trust fund assets at
December 31, 2007 and December 31, 2006 (dollars in millions):
Total
Unrealized
Fair Value
Gains
2007
Equity securities
$
175
$
68
Fixed income securities
204
5
Total
$
379
$
73
2006
Equity securities
$
164
$
63
Fixed income securities
180
3
Total
$
344
$
66
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
14. Fair Value of Financial Instruments
We believe that the carrying amounts of our cash equivalents are reasonable estimates of their
fair values at December 31, 2007 and 2006 due to their short maturities.
We hold short-term investments in fixed income securities for purposes other than trading. We
believe that the carrying amounts of these investments represent reasonable estimates of their fair
values at December 31, 2007 and 2006 due to the short-term reset of interest rates.
APS also holds investments in fixed income and domestic equity securities for purposes other
than trading in its nuclear decommissioning trust. The December 31, 2007 and 2006 fair values of
such investments, which we determine by using quoted market prices, approximate their carrying
amount. For further information, see disclosure of cost and fair value of APS’ nuclear
decommissioning trust fund assets in Note 12.
On December 31, 2007, the carrying value of our long-term debt for Pinnacle West, excluding
capitalized lease obligations was $3.29 billion, with an estimated fair value of $3.20 billion.
The carrying value of our long-term debt for Pinnacle West excluding capitalized lease obligations
was $3.23 billion on December 31, 2006, with an estimated fair value of $3.19 billion. On December31, 2007, the carrying value of APS’ long-term debt, excluding capitalized lease obligations, was
$2.87 billion, with an estimated fair value of $2.79 billion. The carrying value of APS’ long-term
debt excluding capital lease obligations was $2.87 billion on December 31, 2006, with an estimated
fair value of $2.84 billion. The fair value estimates are based on quoted market prices of the
same or similar issues.
15. Earnings Per Share
The following table presents earnings per weighted-average common share outstanding for the
years ended December 31, 2007, 2006 and 2005:
2007
2006
2005
Basic earnings per share:
Income from continuing operations
$
2.98
$
3.19
$
2.31
Income (loss) from discontinued
operations
0.08
0.10
(0.48
)
Earnings per share — basic
$
3.06
$
3.29
$
1.83
Diluted earnings per share:
Income from continuing operations
$
2.96
$
3.17
$
2.31
Income (loss) from discontinued
operations
0.09
0.10
(0.49
)
Earnings per share — diluted
$
3.05
$
3.27
$
1.82
Dilutive stock options and performance shares (which are contingently issuable) increased
average common shares outstanding by approximately 579,000 shares in 2007, 593,000 shares in 2006
and 106,000 shares in 2005. Total average common shares outstanding for the purposes of
calculating diluted earnings per share were 100,834,871 shares in 2007, 100,010,108 shares in 2006
and 96,589,949 shares in 2005.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Options to purchase 114,213 shares of common stock were outstanding at December 31, 2007 but
were not included in the computation of diluted earnings per share because the options’ exercise
prices were greater than the average market price of the common shares. Options to purchase shares
of common stock that were not included in the computation of diluted earnings per share were
437,401 at December 31, 2006 and 495,367 at December 31, 2005.
16. Stock-Based Compensation
Pinnacle West offers stock-based compensation plans for officers and key employees of Pinnacle
West and some of our subsidiaries.
The 2007 Long-Term Incentive Plan (“2007 Plan”) allows Pinnacle West to grant incentive and
nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units,
performance shares, performance share units, performance cash awards, dividend equivalents and
stock to eligible individuals. We have reserved 8 million shares of common stock for issuance
under the 2007 plan plus additional shares that become available for issuance under prior stock
plans (“Prior Plans”). Under the 2007 Plan, any shares of stock that are potentially deliverable
under any award granted under a Prior Plan will be added to the number of shares of stock available
for grant under the 2007 Plan if the award expires or is cancelled or terminated without a delivery
of such shares to the participant. In addition, any shares of stock that have been issued in
connection with any award granted under a Prior Plan will be added to the number of shares
available for grant under the 2007 Plan if the award is cancelled, forfeited, or terminated such
that those shares are returned to the Company. No more than 500,000 shares of stock may be granted
to any one participant during a calendar year. The maximum performance-based award (other than a
performance cash award) payable to any one participant during a performance period is 500,000
shares of stock or the cash equivalent. The plan also provides for the granting of new incentive
and non-qualified stock options at a price per share equal to at least 100% of the fair market
value of the common stock at the time of grant. The terms of the options cannot be longer than 10
years and the options cannot be repriced during their terms.
The 2002 Long-Term Incentive Plan (“2002 Plan”) relates to outstanding performance shares but
no new awards may be granted under the plan. Performance share awards under the 2002 Plan contain
performance criteria that affect the number of shares that ultimately vest. Generally, each
recipient of performance shares is entitled to receive shares of common stock at the end of a
three-year performance period. The number of shares each recipient ultimately receives, if any, is
based upon the percentile ranking of Pinnacle West’s earnings per share growth rate at the end of
the three-year period as compared with the earnings per share growth rate of all relevant companies
in a specified utilities index. The fair value of the grant is estimated on the date of the grant
using the Company’s closing stock price on the date of grant. Management evaluates the probability
of meeting the performance criteria at each balance sheet date and related compensation cost is
amortized over the performance period on a straight-line basis. If the goals are not achieved, no
compensation cost is recognized and any previously recognized compensation cost is reversed.
The 1994 Long-Term Incentive Plan (“1994 Plan”) relates to outstanding options but no new
awards may be granted under the plan. Options vest by thirds over a three-year period beginning
one year after the date the option is granted and expire ten years from the date of the grant. The
1994 Plan also includes outstanding shares of restricted stock.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In 2006, Retention Unit Awards (“Retention Units”) were granted to key employees. Each
Retention Unit represents the right to receive a cash payment equal to the fair market value of one
share of Pinnacle West’s common stock, determined on pre-established valuation dates. One-fourth
of the Retention Units will be redeemed the first business day of calendar years 2007, 2008, 2009
and 2010. In addition, the employee will receive the amount of dividends that the employee would
have received if the employee had owned the stock from the date of grant to the date of payment
plus interest. The Retention Units vest over a four-year period from 2006 through 2009, unless the
employee is eligible to retire, in which case the employee’s Retention Units are immediately vested
and the compensation expense is immediately recognized. As this award is accounted for as a
liability award, compensation costs, initially measured based on the Company’s stock price on the
grant date, are remeasured at each balance sheet date, using Pinnacle West’s closing stock price.
The amount of cash to settle the payment on the first business day of 2007 was $1.6 million.
In 2007 under the 2007 Plan, Restricted Stock Unit Awards (“Restricted Stock Units”) were
granted to officers and key employees. Each officer and key employee had to elect to receive
payment for the vested Restricted Stock Units in cash or in fully transferable shares of stock.
The fair value of the stock election is estimated on the date of the grant using the Company’s
closing stock price on the date of grant. Each Restricted Stock Unit cash election represents the
right to receive a cash payment equal to the fair market value of one share of Pinnacle West’s
common stock, determined on pre-established valuation dates. One-fourth of the Restricted Stock
Units will be redeemed February 20th of calendar years 2008, 2009, 2010 and 2011. In addition, the
employee will receive the amount of dividends that the employee would have received if the employee
had owned the Restricted Stock Unit from the date of grant to the date of payment plus interest.
Restricted Stock Units vest over a four-year period from 2007 through 2010, unless the employee is
eligible to retire, in which case the employee’s Restricted Stock Units are immediately vested
(with the same redemption dates) and the compensation expense is immediately recognized; however,
the Restricted Stock Units will be redeemed on the pre-established valuation dates. As the
Restricted Stock Unit cash election award is accounted for as a liability award, the fair market
value of the outstanding Restricted Stock Unit cash election is measured at each balance sheet
date, using Pinnacle West’s closing stock price.
The compensation cost that has been charged against Pinnacle West’s income for share-based
compensation plans was $6 million in 2007, $13 million in 2006 and $6 million in 2005. The
compensation cost that Pinnacle West has capitalized was immaterial in 2007, 2006 and 2005.
Pinnacle West’s total income tax benefit recognized in the Consolidated Statements of Income for
share-based compensation arrangements was $2 million in 2007, $5 million in 2006 and $2 million in
2005. APS’ share of compensation cost that has been charged against income was $6 million in 2007,
$12 million in 2006 and $5 million in 2005.
The following table is a summary of option activity under our equity incentive plans as of
December 31, 2007 and changes during the year:
There were no options granted during the years 2005 through 2007. The intrinsic value of
options exercised was $2 million for 2007, $5 million for 2006 and $4 million for 2005.
The following table is a summary of the status of stock compensation awards, other than
options, as of December 31, 2007 and changes during the year:
As of December 31, 2007, there was $7 million of total unrecognized compensation cost related
to nonvested share-based compensation arrangements granted under the plans. That cost is expected
to be recognized over a weighted-average period of 1.3 years. The total fair value of shares
vested during 2007 was $6 million, $10 million for 2006 and $3 million for 2005.
The following table is a summary of the amount and weighted-average grant date fair value of
stock compensation awards granted, other than options, during the years ended December 31, 2007,
2006 and 2005:
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2007
2007 Grant
2006
2006 Grant
2005 Grant
Shares/
Date Fair
Shares/
Date Fair
2005
Date Fair
Units
Value (a)
Units
Value (a)
Shares
Value (a)
Restricted stock
award units
27,026
$
46.58
—
$
—
—
$
—
Restricted cash
award units
107,891
46.58
—
—
—
—
Performance share
awards
134,917
48.42
274,070
41.50
215,300
41.36
Stock ownership
incentive awards
—
—
12,526
41.50
13,114
44.13
Retention unit
awards
—
—
123,197
49.92
—
—
Special grant
2,000
41.88
—
—
—
—
(a)
Restricted stock units, performance shares, special grant and stock ownership
incentive awards priced at the closing market price on the grant date.
Cash
received from options exercised under our share-based payment
arrangements was $8 million for
2007, $22 million for 2006 and $17 million for 2005. The tax benefit realized for the tax
deductions from option exercises of the share-based payment arrangements was $1 million for 2007,
$2 million for 2006 and $1 million for 2005.
Pinnacle West’s current policy is to issue new shares to satisfy share requirements for stock
compensation plans and it does not expect to repurchase any shares during 2008.
17. Business Segments
Pinnacle West’s two reportable business segments are:
•
our regulated electricity segment, which consists of traditional regulated retail
and wholesale electricity businesses (primarily electricity service to Native Load
customers) and related activities and includes electricity generation, transmission and
distribution; and
•
our real estate segment, which consists of SunCor’s real estate development and
investment activities.
Financial data for 2007, 2006 and 2005 is provided as follows (dollars in millions):
Income from continuing
operations before income taxes
257
58
35
350
Income taxes
90
23
14
127
Income from continuing operations
167
35
21
223
Income (loss) from discontinued
operations — net of income
tax benefit of $(30) (see Note
22) (c)
—
17
(64
)
(47
)
Net income (loss)
$
167
$
52
$
(43
)
$
176
Capital expenditures
$
811
$
106
$
11
$
928
(a)
All other activities relate to marketing and trading, APSES and El Dorado.
None of these segments is a reportable segment.
(b)
Effective April 1, 2005, revenues of approximately $40 million from Off-System
Sales, which were previously reported in the other segment, began being reported in the
regulated electricity segment in accordance with the retail rate case settlement.
(c)
The other segment primarily relates to the sale and operations of Silverhawk.
See Note 22.
18. Derivative and Energy Trading Accounting
We are exposed to the impact of market fluctuations in the commodity price and transportation
costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage
risks associated with these market fluctuations by utilizing various instruments that qualify as
derivatives, including exchange-traded futures and options and over-the-counter forwards, options
and swaps. As part of our overall risk management program, we use such instruments to hedge
purchases and sales of electricity, fuels, and emissions allowances and credits. As of December31, 2007, we hedged certain exposures to the price variability of commodities for a maximum of 39
months. The changes in market value of such contracts have a high correlation to price changes in
the hedged transactions.
We recognize all derivatives, except those which qualify for a scope exception, as either
assets or liabilities on the balance sheet and measure those instruments at fair value in
accordance
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
with SFAS No. 133, as amended by SFAS No. 149. Derivative commodity contracts for the
physical delivery of purchase and sale quantities transacted in the normal course of business
qualify for the normal purchase and sales exception and are accounted for under the accrual method
of accounting. Changes in the fair value of derivative instruments are recognized periodically in
income unless certain hedge criteria are met. For cash flow hedges, the effective portion of
changes in the fair value of the derivative is recognized in common stock equity (as a component of
other comprehensive income (loss)). For fair value hedges, the gain or loss on the derivative as
well as the offsetting loss or gain on the hedged item associated with the hedged risk are
recognized in earnings. We use cash flow hedges to limit our exposure to cash flow variability on
forecasted transactions. We use fair value hedges to limit our exposure to changes in fair value
of an asset or liability.
For its regulated operations, APS defers for future rate recovery 90% of gains and losses on
derivatives that would otherwise be recognized in income. In the following discussion, amounts
that would otherwise be recognized in income will be recorded as either a regulatory asset or
liability and have no effect on earnings to the extent these amounts are eligible to be recovered
through the PSA.
We assess hedge effectiveness both at inception and on a continuing basis. Hedge
effectiveness is related to the degree to which the derivative contract and the hedged item are
correlated and is measured based on the relative changes in fair value between the derivative
contract and the hedged item over time. We exclude the time value of certain options from our
assessment of hedge effectiveness. Any change in the fair value resulting from ineffectiveness, or
the amount by which the derivative contract and the hedged commodity are not directly correlated,
is recognized immediately in net income.
Both non-trading and trading derivatives that do not qualify for a scope exception are
classified as assets and liabilities from risk management and trading activities on the
Consolidated Balance Sheets. Certain of our non-trading derivatives qualify for cash flow hedge
accounting treatment. Non-trading derivatives, or any portion thereof that are not effective
hedges, are adjusted to fair value through income. Realized gains and losses related to
non-trading derivatives that qualify as cash flow hedges of expected transactions are recognized in
revenue or purchased power and fuel expense as an offset to the related item being hedged when the
underlying hedged physical transaction impacts earnings. If it becomes probable that a forecasted
transaction will not occur, we discontinue the use of hedge accounting and recognize in income the
unrealized gains and losses that were previously recorded in other comprehensive income (loss). In
the event a non-trading derivative is terminated or settled, the unrealized gains and losses remain
in other comprehensive income (loss), and are recognized in income when the underlying transaction
impacts earnings.
All gains and losses (realized and unrealized) on trading contracts that qualify as
derivatives are included in marketing and trading revenues on the Consolidated Statements of Income
on a net basis. Trading contracts that do not meet the definition of a derivative are accounted
for on an accrual basis with the associated revenues and costs recorded at the time the contracted
commodities are delivered or received.
In the electricity business, some contracts to purchase energy are netted against other
contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the
same terms (quantities and delivery points) and for which power does not flow. We net these
book-outs, which reduces both revenues and fuel and purchased power costs in our Consolidated
Statement of Income, but this does not impact our financial condition, net income or cash flows.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cash Flow Hedges
The changes in the fair value of our hedged positions included in the Consolidated Statements
of Income, after consideration of amounts deferred under the PSA, for the years ended December 31,2007, 2006 and 2005 are comprised of the following (dollars in thousands):
2007
2006
2005
Gains (losses) on the ineffective portion
of derivatives qualifying for hedge
accounting
$
1,430
$
(5,666
)
$
14,289
Gains (losses) from the change in options’
time value excluded from measurement
of effectiveness
—
(10
)
620
Gains from the discontinuance of
cash flow hedges
320
453
556
During 2008, we estimate that a net gain of $18 million before income taxes will be
reclassified from accumulated other comprehensive income as an offset to the effect of market price
changes for the related hedged transactions. To the extent the amounts are eligible for inclusion
in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no
effect on earnings (see Note 3).
The following table summarizes our assets and liabilities from risk management and trading
activities at December 31, 2007 and 2006 (dollars in thousands):
Margin account,
options and
emission
allowances -
at
cost
77,705
839
(14,981
)
—
63,563
Total
$
641,040
$
167,211
$
(558,195
)
$
(171,170
)
$
78,886
During the first quarter of 2007, we changed the presentation of mark-to-market positions
related to natural gas basis swaps. We historically presented the buy side and the sell side of
such swaps at fair value gross on our Consolidated Balance Sheets, which resulted in mark-to-market
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
assets and separate mark-to-market liabilities. We now offset these matching assets and
liabilities, thus presenting the net mark-to-market position by contract, which correctly reflects
the true nature of these contracts. The net asset or liability position as historically disclosed
in the table above is unchanged. Further, this change has no impact on results of operations,
common stock equity or cash flows. Had we previously presented such amounts net, the effect on the
December 31, 2006 balance sheet would have been to decrease Current Assets and Current Liabilities
by $376 million and decrease Investments and Other Assets and Deferred Credits and Other by $59
million. We believe that the effect of presenting these contracts gross in prior periods is
immaterial to previously issued financial statements.
We maintain a margin account with a broker to support our risk management and trading
activities. The margin account was an asset of $31 million at December 31, 2007 and an asset of
$73 million at December 31, 2006 and is included in the margin account in the table above. Cash is
deposited with the broker in this account at the time futures or options contracts are initiated.
The change in market value of these contracts (reflected in mark-to-market) requires adjustment of
the margin account balance.
Cash or other assets may be required to serve as collateral against our open positions on
certain energy-related contracts. Collateral provided to counterparties was $1 million at December31, 2007 and $10 million at December 31, 2006, and is included in other current assets on the
Consolidated Balance Sheets. There was no collateral provided to us by counterparties at December31, 2007 and $54 million was provided at December 31, 2006, and is included in other current
liabilities on the Consolidated Balance Sheets.
Credit Risk
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We
have risk management and trading contracts with many counterparties. Our risk management process
assesses and monitors the financial exposure of all counterparties. Despite the fact that the
great majority of trading counterparties’ securities is rated as investment grade by the credit
rating agencies, there is still a possibility that one or more of these companies could default,
resulting in a material impact on consolidated net income for a given period. Counterparties in
the portfolio consist principally of financial institutions, major energy companies, municipalities
and local distribution companies. We maintain credit policies that we believe minimize overall
credit risk to within acceptable limits. Determination of the credit quality of our counterparties
is based upon a number of factors, including credit ratings and our evaluation of their financial
condition. To manage credit risk, we employ collateral requirements, standardized agreements that
allow for the netting of positive and negative exposures associated with a single counterparty and
credit default swaps. Valuation adjustments are established representing our estimated credit
losses on our overall exposure to counterparties. See Note 1 “Derivative Accounting” for a
discussion of our credit valuation adjustment policy.
19. Other Income and Other Expense
The following table provides detail of other income and other expense for 2007, 2006 and 2005
(dollars in thousands):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2007
2006
2005
Other income:
Interest income
$
11,656
$
18,867
$
14,793
SunCor other income (a)
10,702
10,881
2,623
SO2 emission allowance sales and
other (b)
—
10,782
3,187
Investment gains — net
—
2,537
752
Miscellaneous
2,336
949
2,005
Total other income
$
24,694
$
44,016
$
23,360
Other expense:
Non-operating costs (b)
$
(14,021
)
$
(16,223
)
$
(13,589
)
Asset dispositions
—
(2,056
)
(9,759
)
Investment losses — net
(2,339
)
—
—
Miscellaneous
(9,523
)
(9,521
)
(3,368
)
Total other expense
$
(25,883
)
$
(27,800
)
$
(26,716
)
(a)
Includes equity earnings from a real estate joint venture that is a pass-through entity for
tax purposes.
(b)
As defined by the FERC, includes below-the-line non-operating utility income and expense
(items excluded from utility rate recovery).
20. Variable-Interest Entities
In 1986, APS entered into agreements with three separate VIE lessors in order to sell and
lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in
accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly,
do not consolidate them (see Note 9).
APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of
certain events that APS does not consider to be reasonably likely to occur. Under certain
circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde
or the occurrence of specified nuclear events), APS would be required to assume the debt associated
with the transactions, make specified payments to the equity participants, and take title to the
leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If
such an event had occurred as of December 31, 2007, APS would have been required to assume
approximately $194 million of debt and pay the equity participants approximately $170 million.
SunCor has certain land development arrangements that are required to be consolidated under
FIN 46R, “Consolidation of Variable Interest Entities.” The assets and non-controlling interests
reflected in our Consolidated Balance Sheets related to these arrangements were approximately $38
million at December 31, 2007 and $39 million at December 31, 2006.
21. Guarantees
We have issued parental guarantees and letters of credit and obtained surety bonds on behalf
of our subsidiaries. Our parental guarantees for Pinnacle West Marketing & Trading and APS relate
to commodity energy products. Our credit support instruments enable APSES to offer energy-related
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
products and commodity energy. Non-performance or non-payment under the original contract by our
subsidiaries would require us to perform under the guarantee or surety bond. No liability is
currently recorded on the Consolidated Balance Sheets related to Pinnacle West’s current
outstanding guarantees on behalf of our subsidiaries. Our guarantees have no recourse or
collateral provisions to allow us to recover amounts paid under the guarantees. The amounts and
approximate terms of our guarantees and surety bonds for each subsidiary at December 31, 2007 are
as follows (dollars in millions):
Guarantees
Surety Bonds
Term
Term
Amount
(in years)
Amount
(in years)
Parental:
Pinnacle West Marketing & Trading
$
25
1
$
—
—
APSES
18
1
20
1
APS
4
1
—
—
Total
$
47
$
20
At December 31, 2007, Pinnacle West had approximately $5 million of letters of credit related
to workers’ compensation expiring in 2009. We intend to provide from either existing or new
facilities for the extension, renewal or substitution of the letters of credit to the extent
required.
APS has entered into various agreements that require letters of credit for financial assurance
purposes. At December 31, 2007, approximately $200 million of letters of credit were outstanding
to support existing pollution control bonds of approximately $200 million. The letters of credit
are available to fund the payment of principal and interest of such debt obligations and expire in
2010. APS has also entered into approximately $83 million of letters of credit to support certain
equity lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the
Palo Verde sale leaseback transactions). These letters of credit expire in 2010. Additionally, at
December 31, 2007, APS had approximately $4 million of letters of credit related to counterparty
collateral requirements expiring in 2008. APS intends to provide from either existing or new
facilities for the extension, renewal or substitution of the letters of credit to the extent
required.
We enter into agreements that include indemnification provisions relating to liabilities
arising from or related to certain of our agreements; most significantly, APS has agreed to
indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions
with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in
the indemnification provisions and, therefore, the overall maximum amount of the obligation under
such indemnification provisions cannot be reasonably estimated. Based on historical experience and
evaluation of the specific indemnities, we do not believe that any material loss related to such
indemnification provisions is likely.
22. Discontinued Operations
SunCor (real estate segment) - In 2007, 2006 and 2005, SunCor sold commercial properties,
which are required to be reported as discontinued operations on Pinnacle West’s Consolidated
Statements of Income in accordance with SFAS No. 144. As a result of the sales, we recorded a gain
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
from discontinued operations of approximately $10 million ($17 million pretax) in 2007; $9
million ($15 million pretax) in 2006; and $15 million ($25 million pretax) in 2005.
Silverhawk (other) - In June 2005, we entered into an agreement to sell our 75% interest in
the Silverhawk Power Station to NPC. The sale was completed on January 10, 2006. As a result of
this sale, we recorded a loss from discontinued operations of approximately $56 million ($91
million pretax) in the second quarter of 2005. The chart below includes the revenues and expenses
related to the operations of Silverhawk.
Other — Includes activities related to APSES in 2007 and to El Dorado in 2006 and 2005.
The following table provides revenue, income (loss) before income taxes and income (loss)
after taxes classified as discontinued operations in Pinnacle West’s Consolidated Statements of
Income for the years ended December 31, 2007, 2006 and 2005 (dollars in millions):
2007
2006
2005
Revenue:
SunCor — commercial operations
$
4
$
3
$
9
Silverhawk
—
1
95
Total revenue
$
4
$
4
$
104
Income (loss) before taxes:
SunCor — commercial operations
$
19
$
17
$
28
Silverhawk (a)
—
1
(111
)
Other
(5
)
(1
)
6
Total income (loss) before taxes
$
14
$
17
$
(77
)
Income (loss) after taxes:
SunCor — commercial operations
$
11
$
10
$
17
Silverhawk
—
1
(67
)
Other
(3
)
(1
)
3
Total income (loss) after taxes
$
8
$
10
$
(47
)
(a)
Income before income taxes includes an interest expense allocation, net of
capitalized amounts, of $13 million in 2005. The allocation was based on Pinnacle
West’s weighted-average interest rate applied to the net property, plant and equipment.
MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
(ARIZONA PUBLIC SERVICE COMPANY)
Our management is responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Arizona Public
Service Company. Management conducted an evaluation of the effectiveness of our internal control
over financial reporting based on the framework in Internal Control — Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation
under the framework in Internal Control — Integrated Framework, our management concluded that our
internal control over financial reporting was effective as of December 31, 2007. The effectiveness
of our internal control over financial reporting as of December 31, 2007 has been audited by
Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report
which is included herein and relates also to the Company’s financial statements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
Arizona Public Service Company
Phoenix, Arizona
We have audited the accompanying balance sheets of Arizona Public Service Company (the “Company”)
as of December 31, 2007 and 2006, and the related statements of income, changes in common stock
equity, and cash flows for each of the three years in the period ended December 31, 2007. Our
audits also included the financial statement schedule listed in the Index at Item 15. We also have
audited the Company’s internal control over financial reporting as of December 31, 2007, based on
criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. The Company’s management is responsible for these
financial statements and financial statement schedule, for maintaining effective internal control
over financial reporting, and for its assessment of the effectiveness of internal control over
financial reporting, included in the accompanying Management’s Report on Internal Control Over
Financial Reporting. Our responsibility is to express an opinion on these financial statements and
financial statement schedule and an opinion on the Company’s internal control over financial
reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement and
whether effective internal control over financial reporting was maintained in all material
respects. Our audits of the financial statements included examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and evaluating the overall financial
statement presentation. Our audit of internal control over financial reporting included obtaining
an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness of internal control
based on the assessed risk. Our audits also included performing such other procedures as we
considered necessary in the circumstances. We believe that our audits provide a reasonable basis
for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the
supervision of, the company’s principal executive and principal financial officers, or persons
performing similar functions, and effected by the company’s board of directors, management, and
other personnel to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes
those policies and procedures that (1) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles and
that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the
possibility of collusion or improper management override of controls, material misstatements due to
error or fraud may not be prevented or detected on a timely basis. Also, projections of any
evaluation of the effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the financial statements referred to above present fairly, in all material
respects, the financial position of the Company as of December 31, 2007 and 2006, and the results
of its operations and its cash flows for each of the three years in the period ended December 31,2007, in conformity with accounting principles generally accepted in the United States of America.
Also, in our opinion, such financial statement schedule, when considered in relation to the basic
financial statements taken as a whole, present fairly, in all material respects, the information
set forth therein. Also, in our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2007, based on the criteria
established in Internal Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
As
reflected in the statements of changes in common stock equity, the
Company adopted Statement of Financial Accounting Standards No. 158,
“Employers’ Accounting for Defined Benefit Pension and
Other Postretirement Plans” effective December 31, 2006.
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.
APS is included in Pinnacle West’s consolidated tax return. However, when Pinnacle West
allocates income taxes to APS, it is done based upon APS’ taxable income computed on a stand-alone
basis, in accordance with the tax sharing agreement.
Certain assets and liabilities are reported differently for income tax purposes than they are
for financial statements purposes. The tax effect of these differences is recorded as deferred
taxes. We calculate deferred taxes using the current income tax rates.
APS has recorded a regulatory asset and a regulatory liability related to income taxes on its
Balance Sheets in accordance with SFAS No. 71. The regulatory asset is for certain temporary
differences, primarily the allowance for equity funds used during construction. The regulatory
liability relates to excess deferred taxes resulting primarily from pension and other
postretirement benefits. APS amortizes these amounts as the differences reverse.
As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax
accounting method change on our 2001 federal consolidated income tax return. The accelerated
deduction resulted in a $200 million reduction in the current income tax liability and a
corresponding increase in the plant-related deferred tax liability. Our 2001 federal consolidated
income tax return is currently under examination by the IRS. As part of its ongoing examination,
the IRS is reviewing this accounting method change and the resultant
deduction. Within the next six
months, we expect that the IRS will finalize its examination of the 2001 return, which will include
a settlement on the tax accounting method change. Although the
ultimate outcome of this matter cannot currently be predicted, the
current status of the examination has resulted in changes in our
judgement which are reflected in the reconciliation of the total
amounts of unrecognized tax benefits presented below. We do not expect
the ultimate outcome of this examination to have a material adverse impact on our financial
position or results of operations. We expect that it will have a negative impact on cash flows. We
do not expect that there will be any other significant increases or decreases in our unrecognized
tax benefits within the next 12 months.
We adopted FIN 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB
Statement No. 109” on January 1, 2007. The effect of applying the new guidance was not
significantly different in terms of tax impacts from the application of our previous policy.
Accordingly, the impact to retained earnings upon adoption was immaterial. In addition, the
guidance required us to reclassify certain tax benefits, which had the effect of increasing accrued
taxes and deferred debits by approximately $50 million to better reflect the expected timing of the
payment of taxes and interest.
Following
is a tabular reconciliation of the total amounts of unrecognized tax
benefits, excluding interest and penalties, at the
beginning and end of the period that are included in accrued taxes and other deferred credits on
the Balance Sheets (dollars in thousands):
Included in the balance of unrecognized tax benefits at December 31, 2007 are approximately
$4 million of tax positions that, if recognized, would decrease our effective tax rate.
We
reflect interest and penalties, if any, on unrecognized tax benefits in the statement of operations
as income tax expense. For 2007, the amount of interest recognized in the statement of operations
related to unrecognized tax benefits was $3 million.
As of December 31, 2007, the total amount of interest expense recognized in the statement of
financial position related to unrecognized tax benefits was
$56 million. To the extent that matters are settled favorably, this amount
could reverse and decrease our effective tax rate. Additionally, we have
recognized $5 million of interest income to be received on the overpayment of income taxes for
certain adjustments that we have filed, or will file, with the IRS.
The components of APS’ income tax expense are as follows (dollars in thousands):
S-2. Selected Quarterly Financial Data (Unaudited)
Quarterly financial information for 2007 and 2006 is as follows (dollars in thousands):
2007 Quarter Ended,
2007
March 31,
June 30,
September 30,
December 31,
Total
Operating revenues
$
538,260
$
721,759
$
1,047,062
$
629,196
$
2,936,277
Operations and maintenance
165,934
170,631
171,963
201,549
710,077
Operating income
40,589
109,643
238,144
37,619
425,995
Net income
4,317
75,090
204,257
276
283,940
2006 Quarter Ended,
2006
March 31,
June 30,
September 30,
December 31,
Total
Operating revenues
$
476,869
$
718,850
$
886,686
$
576,108
$
2,658,513
Operations and maintenance
173,353
164,373
156,170
171,735
665,631
Operating income
25,044
119,967
200,580
52,351
397,942
Net income (loss)
(5,521
)
93,757
168,634
12,860
269,730
S-3. Derivative and Energy Trading Accounting
APS is exposed to the impact of market fluctuations in the commodity price and transportation
costs of electricity, natural gas, coal and emissions allowances. As part of its overall risk
management program, APS uses various commodity instruments that qualify as derivatives to hedge
purchases and sales of electricity, fuels and emissions allowances and credits. As of December 31,2007, APS hedged certain exposures to these risks for a maximum of 39 months.
Cash Flow Hedges
The changes in the fair value of APS’ hedged positions included in the APS Statements of
Income, after consideration of amounts deferred under the PSA, for the years ended December 31,2007, 2006 and 2005 are comprised of the following (dollars in thousands):
2007
2006
2005
Gains (losses) on the ineffective portion
of
derivatives qualifying for hedge
accounting
$
1,430
$
(5,666
)
$
14,452
Gains (losses) from the change in options’
time value excluded from measurement
of effectiveness
—
(10
)
620
Gains from the discontinuance of
cash flow hedges
150
178
473
During 2008, APS estimates that a net gain of $1 million before income taxes will be
reclassified from accumulated other comprehensive income as an offset to the effect of market price
changes for the related hedged transactions. To the extent the amounts are eligible for inclusion
in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no
effect on earnings (see Note 3).
The following table summarizes APS’ assets and liabilities from risk management and trading
activities at December 31, 2007 and 2006 (dollars in thousands):
During the first quarter of 2007, we changed the presentation of mark-to-market positions
related to natural gas basis swaps. We historically presented the buy side and the sell side of
such swaps at fair value gross on our Balance Sheets, which resulted in mark-to-market assets and
separate mark-to-market liabilities. We now offset these matching assets and liabilities, thus
presenting the net mark-to-market position by contract, which correctly reflects the true nature of
these contracts. The net asset or liability position as historically disclosed in the table above
is unchanged. Further, this change has no impact on income, common stock equity or cash flows.
Had we previously presented such amounts net, the effect on the December 31, 2006 balance sheet
would have been to decrease Current Assets and Current Liabilities by $376 million and decrease
Investments and Other Assets and Deferred Credits and Other by $59 million. We believe that the
effect of presenting these contracts gross in prior periods is immaterial to previously issued
financial statements.
We maintain a margin account with a broker to support our risk management and trading
activities. The margin account was an asset of $31 million at December 31, 2007 and an asset of
$73 million at December 31, 2006 and is included in the margin account in the table above. Cash is
deposited with the broker in this account at the time futures or options contracts are initiated.
The change in market value of these contracts (reflected in mark-to-market) requires adjustment of
the margin account balance.
Cash or other assets may be required to serve as collateral against APS’ open positions on
certain energy-related contracts. Collateral provided to counterparties was $1 million at
December 31, 2007 and was $2 million at December 31, 2006 and is included in other current assets
on the balance sheet. There was no cash collateral provided to us by counterparties at December31, 2007 and $1 million was provided at December 31, 2006, and is included in other current
liabilities on the Balance Sheets.
The following table provides detail of APS’ other income and other expense for 2007, 2006 and
2005 (dollars in thousands):
2007
2006
2005
Other income:
Interest income
$
10,961
$
16,526
$
14,513
SO2 emission allowance sales
and other (a)
1,001
10,782
3,187
Investment gains — net
2,429
3,645
1,705
Miscellaneous
2,336
949
2,736
Total other income
$
16,727
$
31,902
$
22,141
Other expense:
Non-operating costs (a)
$
(12,712
)
$
(15,415
)
$
(11,706
)
Asset dispositions
(1,981
)
(1,851
)
(9,759
)
Miscellaneous
(6,937
)
(6,564
)
(1,739
)
Total other expense
$
(21,630
)
$
(23,830
)
$
(23,204
)
(a)
As defined by the FERC, includes below-the-line non-operating utility income
and expense (items excluded from utility rate recovery).
S-5. Related Party Transactions
From time to time, APS enters into transactions with Pinnacle West or Pinnacle West’s other
subsidiaries. The following table summarizes the amounts included in the APS Statements of Income
and Balance Sheets related to transactions with affiliated companies (dollars in millions):
Pinnacle West Marketing & Trading began operations in
early 2007. These operations were conducted by a division of Pinnacle
West through the end of 2006.
Pinnacle West Marketing & Trading began operations in
early 2007. These operations were conducted by a division of Pinnacle
West through the end of 2006.
Electric revenues include sales of electricity to affiliated companies at contract prices.
Purchased power includes purchases of electricity from affiliated companies at contract prices.
However, these transactions are
settled net and reported net in accordance with EITF 03-11, “Reporting Realized Gains and Losses on
Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading
Purposes’ As Defined in EITF Issue No. 02-3.”
On November 8, 2005, the ACC approved Pinnacle West’s request to infuse more than $450 million
of equity into APS during 2005 or 2006. These infusions consisted of about $250 million of the
proceeds of Pinnacle West’s common equity issuance on May 2, 2005 and about $210 million of the
proceeds from the sale of Silverhawk in January 2006. In May 2007, Pinnacle West infused
approximately $40 million of equity into APS, consisting of proceeds of stock issuances in 2006
under Pinnacle West’s Investors Advantage Plan (direct stock purchase and dividend reinvestment
plan) and employee stock plans.
Intercompany receivables primarily include amounts related to the intercompany sales of
electricity. Intercompany payables primarily include amounts related to the intercompany purchases
of electricity. Intercompany receivables and payables are generally settled on a current basis in
cash.
Income from continuing operations — net of
income taxes
307,143
327,345
165,947
Income (loss) from discontinued operations
—
(90
)
10,320
Net income
$
307,143
$
327,255
$
176,267
(a)
Pinnacle West Marketing & Trading began operations in early 2007. These operations were
conducted by a division of Pinnacle West through the end of 2006.
Assets from risk management and trading activities
—
101,604
Other current assets
1,262
10,810
Total current assets
83,402
285,808
Investments and other assets
Assets from long-term risk management
and trading activities
—
70,319
Investments in subsidiaries
3,711,737
3,545,329
Deferred income taxes
11,806
—
Other assets
23,591
73,300
Total investments and other assets
3,747,134
3,688,948
Total Assets
$
3,830,536
$
3,974,756
Liabilities and Common Stock Equity
Current liabilities
Accounts payable
$
22,177
$
80,903
Accrued taxes
(86,081
)
(118,073
)
Short-term borrowings
115,000
27,900
Current maturities of long-term debt
—
115
Deferred income taxes
7,682
18,238
Liabilities from risk management and
trading activities
2
67,340
Other current liabilities
18,019
130,985
Total current liabilities
76,799
207,408
Long-term debt less current maturities
175,000
175,000
Deferred credits and other
Deferred income taxes
—
19,582
Pension and other postretirement liabilities
22,248
13,437
Liabilities from risk management and
trading activities
—
36,114
Other
24,878
23,218
Total deferred credits and other
47,126
92,351
Common stock equity
Common stock
2,133,733
2,587,201
Accumulated
other comprehensive income (loss)
(15,863
)
17,512
Retained earnings
1,413,741
895,284
Total common stock equity
3,531,611
3,499,997
Total Liabilities and Common Stock Equity
$
3,830,536
$
3,974,756
(a)
Pinnacle West Marketing & Trading began operations in early 2007. These operations were
conducted by a division of Pinnacle West through the end of 2006.
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended December 31
2007 (a)
2006
2005
Cash flows from operating activities
Net Income
$
307,143
$
327,255
$
176,267
Less: equity in earnings of subsidiaries — net
(287,078
)
(324,504
)
(58,759
)
Net income attributable to Pinnacle West
20,065
2,751
117,508
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization
320
470
551
Deferred income taxes
(24,192
)
30,384
(19,929
)
Change in mark-to-market valuations
53,228
21,698
(15,162
)
Customer and other receivables
112,543
2,816
1,730
Accounts payable
(57,978
)
(55,675
)
43,969
Accrued taxes
25,127
(49,529
)
(84,758
)
Change in risk management and trading — net
(11,602
)
65,633
(82,650
)
Other net
(104,968
)
(20,746
)
102,432
Net cash flow (used for) provided by
operating activities
12,543
(2,198
)
63,691
Cash flows from investing activities
Investments in and advances to subsidiaries — net
(83,993
)
(4,677
)
(230,229
)
Repayments and advances of loans from
subsidiaries
(4,800
)
2,686
2,402
Dividends received from subsidiaries
180,000
180,000
220,000
Purchases of investment securities
—
(147,501
)
(1,485,655
)
Proceeds from sale of investment securities
—
147,501
1,485,683
Net cash flow (used for) provided by
investing activities
91,207
178,009
(7,799
)
Cash flows from financing activities
Issuance of long-term debt
—
175,000
—
Short-term borrowings and payments — net
87,371
27,900
—
Dividends paid on common stock
(210,473
)
(201,221
)
(186,677
)
Repayment of long-term debt
(115
)
(298,687
)
(165,104
)
Common stock equity issuance
19,593
35,834
290,542
Net cash flow used for financing activities
(103,624
)
(261,174
)
(61,239
)
Net increase (decrease) in cash and cash
equivalents
126
(85,363
)
(5,347
)
Cash and cash equivalents at beginning of year
11
85,374
90,721
Cash and cash equivalents at end of year
$
137
$
11
$
85,374
(a)
Pinnacle West Marketing & Trading began operations in early 2007. These operations were
conducted by a division of Pinnacle West through the end of 2006.
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, 2007. Based on that evaluation, Pinnacle West’s Chief
Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s
disclosure controls and procedures were effective.
APS’ management, with the participation of APS’ Chief Executive Officer and Chief Financial
Officer, have evaluated the effectiveness of APS’ disclosure controls and procedures as of December31, 2007. Based on that evaluation, APS’ Chief Executive Officer and Chief Financial Officer have
concluded that, as of that date, APS’ disclosure controls and procedures were effective.
(b) Management’s Annual Reports on Internal Control Over Financial Reporting
Reference is made to “Management’s Report on Internal Control Over Financial Reporting
(Pinnacle West Capital Corporation)” on page 74 of this report and “Management’s Report on Internal
Control Over Financial Reporting (Arizona Public Service
Company)” on page 129 of this report.
(c) Attestation Reports of the Registered Public Accounting Firm
Reference
is made to “Report of Independent Registered Public Accounting
Firm” on page 75 of
this report and “Report of Independent Registered Public
Accounting Firm” on page 130 of this report
on the internal control over financial reporting of Pinnacle West and APS, respectively.
(d) Changes In Internal Control Over Financial Reporting
The term “internal control over financial reporting” (defined in SEC Rule 13a-15(f)) refers to
the process of a company that is designed to provide reasonable assurance regarding the reliability
of
financial reporting and the preparation of financial statements for external purposes in
accordance with GAAP.
No change in Pinnacle West’s or APS’ internal control over financial reporting occurred during
the fiscal quarter ended December 31, 2007 that materially affected, or is reasonably likely to
materially affect, Pinnacle West’s or APS’ internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS
AND CORPORATE GOVERNANCE OF PINNACLE WEST
Reference is hereby made to “Information About Our Board, Its Committees and Our Corporate
Governance,”“Election of Directors” and to “Section 16(a) Beneficial Ownership Reporting
Compliance” in the Pinnacle West Proxy Statement relating to the Annual Meeting of Shareholders to
be held on May 21, 2008 (the “2008 Proxy Statement”) and to the Supplemental Item — “Executive
Officers of Pinnacle West” in Part I of this report.
Pinnacle West has adopted a Code of Ethics for Financial Professionals that applies to
professional employees in the areas of finance, accounting, internal audit, energy risk management,
marketing and trading financial control, tax, investor relations, and treasury and also includes
Pinnacle West’s Chief Executive Officer, Chief Financial Officer, Controller, Treasurer, and
officers holding substantially equivalent positions at Pinnacle West’s subsidiaries. The Code of
Ethics for Financial Professionals is posted on Pinnacle West’s website at www.pinnaclewest.com.
Pinnacle West intends to satisfy the requirements under Item 5.05 of Form 8-K regarding disclosure
of amendments to, or waivers from, provisions of the Code of Ethics for Financial Professionals by
posting such information on Pinnacle West’s website.
ITEM 11. EXECUTIVE COMPENSATION
Reference is hereby made to “Information About Our Board, Its Committees and Our Corporate
Governance — How are directors compensated?” and “Executive Compensation” in the 2008 Proxy
Statement.
ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
Reference is hereby made to “Shares of Pinnacle West Stock Owned by Management and Large
Shareholders” in the 2008 Proxy Statement.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets forth information as of December 31, 2007 with respect to our
compensation plans and individual compensation arrangements under which our equity securities are
authorized for issuance.
EQUITY COMPENSATION PLAN INFORMATION
Number of securities
remaining available
for future issuance
under equity
Number of securities
Weighted-average
compensation plans
to be issued upon
exercise price of
(excluding
exercise of
outstanding
securities
outstanding options,
options, warrants
reflected in column
warrants and rights
and rights
(a))
Plan Category
(a)1
(b)2
(c)3
Equity compensation
plans approved by
security holders
2,008,887
$
40.84
7,950,520
Equity compensation
plans not approved
by security holders
—
—
—
Total
2,008,887
$
40.84
7,950,520
1
This amount includes shares subject to outstanding options as well as shares subject
to outstanding performance share awards and restricted stock unit awards at the maximum amount of
shares issuable under such awards. However, payout of the performance share awards is contingent
on the Company reaching certain levels of performance during a three-year performance period. If
the performance criteria for these awards are not fully satisfied, the award recipient will receive
less than the maximum number of shares available under these grants and may receive nothing from
these grants.
2
The weighted average exercise price in this column does not take performance share
awards or restricted stock unit awards into account, as those awards have no exercise price.
3
Awards can take the form of options, stock appreciation rights, restricted stock,
performance shares, performance share units, performance cash, stock grants, dividend equivalents,
and restricted stock units..
Equity Compensation Plans Approved By Security Holders
Amounts in column (a) in the table above include shares subject to awards outstanding under
three equity compensation plans that were approved by our shareholders: (a) the Pinnacle West
Capital Corporation 1994 Long-Term Incentive Plan, under which no new stock awards may be granted;
(b) the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan (the “2002 Plan”), under
which no new stock awards may be granted; and (c) the Pinnacle West Capital
Corporation 2007 Long-Term Incentive Plan (the “2007 Plan”), which was approved by our shareholders
at our 2007 annual meeting of shareholders. Although we cannot issue additional awards under the
2002 Plan, shares subject to outstanding awards under the 2002 Plan that expire or are cancelled or
terminated will be available for issuance under the 2007 Plan. See Note 16 of the Notes to
Consolidated Financial Statements for additional information regarding these plans.
Equity Compensation Plans Not Approved By Security Holders
The Company does not have any equity compensation plans under which shares can still be issued
that have not been approved by shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Reference is hereby made to “Information About Our Board, Its Committees and Our Corporate
Governance” and to “Related Party Transactions” in the 2008 Proxy Statement.
ITEM 14. PRINCIPAL ACCOUNTANT
FEES AND SERVICES
Pinnacle West
Reference is hereby made to “Audit Matters — What fees were paid to our independent registered
public accountants in 2006 and 2007?” and “What are the Audit Committee’s pre-approval policies?”
in the 2008 Proxy Statement.
APS
The following fees were paid to APS’ independent registered public accountants, Deloitte &
Touche LLP, for the last two fiscal years:
Type of Service
2006
2007
Audit Fees (1)
$
1,925,550
$
1,921,601
Audit-Related Fees (2)
167,912
178,840
Tax Fees (3)
17,096
7,751
(1)
The aggregate fees billed for services rendered for the audit of annual financial statements
and for review of financial statements included in Reports on Form 10-Q.
(2)
The aggregate fees billed for assurance services that are reasonably related to the
performance of the audit or review of the financial statements that are not included in Audit
Fees reported above, which primarily consist of fees for employee benefit plan audits.
(3)
The aggregate fees billed primarily for tax compliance and tax planning.
Pinnacle West’s Audit Committee pre-approves each audit service and non-audit service to be
provided by APS’ independent public accountants. The Audit Committee has delegated to the Chairman
of the Audit Committee the authority to pre-approve audit and non-audit services to be
performed by the independent public accountants if the services are not expected to cost more than
$50,000. The Chairman must report any pre-approval decisions to the Audit Committee at its next
scheduled meeting. All of the services performed by Deloitte & Touche LLP for APS were
pre-approved by the Audit Committee.
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.
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
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
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
3-30-94
10.1.1
Pinnacle West
APS
Two separate
Decommissioning
Trust Agreements
(relating to PVNGS
Units 1 and 3,
respectively), each
dated July 1, 1991,
between APS and
Mellon Bank, N.A.,
as Decommissioning
Trustee
10.2 to APS’ September 30, 1991 Form
10-Q Report, File No. 1-4473
11-14-91
10.1.1a
Pinnacle West
APS
Amendment No. 1 to
Decommissioning
Trust Agreement
(PVNGS Unit 1),
dated as of
December 1, 1994
10.1 to APS’ 1994 Form
10- K Report, File No. 1-4473
3-30-95
10.1.1b
Pinnacle West
APS
Amendment No. 1 to
Decommissioning
Trust Agreement
(PVNGS Unit 3),
dated as of
December 1, 1994
10.2 to APS’ 1994 Form
10-K Report, File No. 1-4473
3-30-95
10.1.1c
Pinnacle West
APS
Amendment No. 2 to
APS Decommissioning
Trust Agreement
(PVNGS Unit 1)
dated as of July 1,
1991
10.4 to APS’ 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
10.1.2a
Pinnacle West
APS
First Amendment to
Amended and
Restated
Decommissioning
Trust Agreement
(PVNGS Unit 2),
dated as of
November 1, 1992
10.2 to APS’ 1992 Form
10-K Report, File No. 1-4473
3-30-93
10.1.2b
Pinnacle West
APS
Amendment No. 2 to
Amended and
Restated
Decommissioning
Trust Agreement
(PVNGS Unit 2),
dated as of
November 1, 1994
10.3 to APS’ 1994 Form
10-K Report, File No. 1-4473
3-30-95
10.1.2c
Pinnacle West
APS
Amendment No. 3 to
Amended and
Restated
Decommissioning
Trust Agreement
(PVNGS Unit 2),
dated as of January31, 1992
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
10.2.1ab
Pinnacle West
APS
Third Amendment to
the Arizona Public
Service Company
Deferred
Compensation Plan,
effective as of
January 1, 1993
10.3A to APS’ 1993 Form
10-K Report, File No. 1-4473
3-30-94
10.2.1bb
Pinnacle West
APS
Fourth Amendment to
the Arizona Public
Service Company
Deferred
Compensation Plan
effective as of May1, 1993
Fourth Amendment to
the Arizona Public
Service Company
Directors Deferred
Compensation Plan,
effective as of
January 1, 1999
10.8A to Pinnacle West’s 1999 Form 10-K
Report, File No. 1-8962
3-30-00
10.2.3b
Pinnacle West
APS
Trust for the
Pinnacle West
Capital
Corporation,
Arizona Public
Service Company and
SunCor Development
Company Deferred
Compensation Plans
dated August 1,1996
10.14A to Pinnacle West’s 1999 Form 10-K
Report, File No. 1-8962
3-30-00
10.2.3ab
Pinnacle West
APS
First Amendment
dated December 7,1999 to the Trust
for the Pinnacle
West Capital
Corporation,
Arizona Public
Service Company and
SunCor Development
Company Deferred
Compensation Plans
10.15A to Pinnacle West’s 1999 Form 10-K
Report, File No. 1-8962
Pinnacle West
Capital
Corporation,
Arizona Public
Service Company,
SunCor Development
Company and El
Dorado Investment
Company Deferred
Compensation Plan
as amended and
restated effective
January 1, 1996
10.10A to APS’ 1995 Form 10-K Report,
File No. 1-4473
3-29-96
10.2.4ab
Pinnacle West
APS
First Amendment
effective as of
January 1, 1999, to
the Pinnacle West
Capital
Corporation,
Arizona Public
Service Company,
SunCor Development
Company and El
Dorado Investment
Company Deferred
Compensation Plan
10.7A to Pinnacle West’s 1999 Form 10-K
Report, File No. 1-8962
3-30-00
10.2.4bb
Pinnacle West
APS
Second Amendment
effective January1, 2000 to the
Pinnacle West
Capital
Corporation,
Arizona Public
Service Company,
SunCor Development
Company and El
Dorado Investment
Company Deferred
Compensation Plan
10.10A to Pinnacle West’s 1999 Form 10-K
Report, File No. 1-8962
Third Amendment to
the Pinnacle West
Capital
Corporation,
Arizona Public
Service Company,
SunCor Development
Company and El
Dorado Investment
Company Deferred
Compensation Plan,
effective as of
January 1, 2002
Fourth Amendment to
the Pinnacle West
Capital
Corporation,
Arizona Public
Service Company,
SunCor Development
Company and El
Dorado Investment
Company Deferred
Compensation Plan,
effective
January 1, 2003
10.64 to Pinnacle West/APS 2005 Form
10-K Report, File Nos. 1-8962 and 1-4473
3-13-06
10.2.5b
Pinnacle West
APS
Schedules of
William J. Post and
Jack E. Davis to
Arizona Public
Service Company
Deferred
Compensation Plan,
as amended
10.3A to Pinnacle West 2002 Form 10-K
Report, File No. 1-8962
3-31-03
10.3.1b
Pinnacle West
APS
Pinnacle West
Capital Corporation
Supplement Excess
Benefit Retirement
Plan, amended and
restated as of
January 1, 2003
10.7A to Pinnacle West’s 2003 Form 10-K
Report, File No. 1-8962
3-15-04
10.3.1ab
Pinnacle West
APS
Pinnacle West
Capital Corporation
Supplemental Excess
Benefit Retirement
Plan, as amended
and restated, dated
December 18, 2003
10.48b to Pinnacle West/APS 2005 Form
10-K Report, File Nos. 1-8962 and 1-4473
Form of Amended and
Restated Key
Executive
Employment and
Severance Agreement
between Pinnacle
West and certain
officers of
Pinnacle West and
its subsidiaries
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
10.7.1b
Pinnacle West
APS
Amendment and
Supplement No. 1 to
Supplemental and
Additional
Indenture of Lease
Four Corners, dated
April 25, 1985
10.36 to Pinnacle West’s Registration
Statement on Form 8-B Report, File No.
1-8962
7-25-85
10.7.2
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
10.7.2a
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
7-25-85
10.7.3
Pinnacle West
APS
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
10.7.3a
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
Four Corners
Project Co-Tenancy
Agreement Amendment
No. 6
10.7 to Pinnacle West’s 2000 Form 10-K
Report, File No. 1-8962
3-14-01
10.8.1
Pinnacle West
APS
Indenture of Lease,
Navajo Units 1, 2,
and 3
5(g) to APS’ Form S-7 Registration
Statement, File No. 2-36505
3-23-70
10.8.2
Pinnacle West
APS
Application of
Grant of
rights-of-way and
easements, Navajo
Plant
5(h) to APS Form S-7 Registration
Statement, File No. 2-36505
3-23-70
10.8.3
Pinnacle West
APS
Water Service
Contract Assignment
with the United
States Department
of Interior, Bureau
of Reclamation,
Navajo Plant
5(l) to APS’ Form S-7 Registration
Statement, File No. 2-394442
3-16-71
10.8.4
Pinnacle West
APS
Navajo Project
Co-Tenancy
Agreement dated as
of March 23, 1976,
and Supplement No.
1 thereto dated as
of October 18,
1976, Amendment No.
1 dated as of July
5, 1988, and
Amendment No. 2
dated as of June14, 1996; Amendment
No. 3 dated as of
February 11, 1997;
Amendment No. 4
dated as of January21, 1997; Amendment
No. 5 dated as of
January 23, 1998;
Amendment No. 6
dated as of July31, 1998
10.107 to Pinnacle West/APS 2005 Form
10-K Report, File Nos. 1-8962 and 1-4473
Navajo Project
Participation
Agreement dated as
of September 30,
1969, and Amendment
and Supplement No.
1 dated as of
January 16, 1970,
and Coordinating
Committee Agreement
No. 1 dated as of
September 30, 1971
10.108 to Pinnacle West/APS 2005 Form
10-K Report, File Nos. 1-8962 and 1-4473
3-13-06
10.9.1
Pinnacle West
APS
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
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 31, 1991 Form 10-Q
Report, File No. 1-4473
5-15-91
10.9.1b
Pinnacle West
APS
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
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 30, 1991 Form 10-Q
Report, File No. 1-4473
8-8-91
10.10.2
Pinnacle West
APS
Long-Term Power
Transaction
Agreement dated
September 21, 1990
between APS and
PacifiCorp, as
amended as of
October 11, 1990,
and as of July 8,
1991
10.2 to APS’ June 30, 1991 Form 10-Q
Report, File No. 1-4473
8-8-91
10.10.2a
Pinnacle West
APS
Amendment No. 1
dated April 5, 1995
to the Long-Term
Power Transaction
Agreement and Asset
Purchase and Power
Exchange Agreement
between PacifiCorp
and APS
10.3 to APS’ 1995 Form 10-K Report, File
No. 1-4473
3-29-96
10.10.3
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
10.10.4
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
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
3-29-96
10.11.1
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
10.11.2
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
10.11.3
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
10.95 to Pinnacle West/APS 2005 Form
10-K Report, File Nos. 1-8962 and 1-4473
3-13-06
10.11.4
Pinnacle West
$200,000,000 Senior
Notes Uncommitted
Master Shelf
Agreement dated as
of February 28,2006
10.96 to Pinnacle West 2005 Form 10-K
Report, File No. 1-8962
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
10.97 to Pinnacle West 2005 Form 10-K
Report, File No. 1-8962
3-13-06
10.11.5a
Pinnacle West
First Amendment to
Amended and
Restated Credit
Agreement, dated as
of May 15, 2006,
supplementing and
amending the
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
parties thereto
$500,000,000
Five-Year Credit
Agreement dated as
of September 29,2006 among Arizona
Public Service
Company as
Borrower, Bank of
America, N.A. as
Administrative
Agent and Issuing
Bank, The Bank of
New York as
Syndication Agent
and Issuing Bank
and the other
parties thereto
10.1 to APS’ September 2006 Form 10-Q
Report, File No. 1-4473
11-8-06
10.11.8
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
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
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 30, 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
10.12.1cc
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
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
1-20-87
10.12.2a
Pinnacle West
APS
Amendment No. 1,
dated as of August
1, 1987, to
Facility Lease,
dated as of
December 15, 1986,
between 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
10.12.2b
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
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
10.13.2
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
10.13.3
Pinnacle West
APS
Agreement for the
Transfer and Use of
Wastewater and
Effluent by and
between APS, SRP
and PWE dated
June 1, 2001
10.103 to Pinnacle West/APS 2004 Form
10-K Report, File Nos. 1-8962 and 1-4473
3-16-05
10.13.4
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
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
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
99.1
Pinnacle West
APS
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
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
99.2c
Pinnacle West
APS
Participation
Agreement, dated as
of August 1, 1986,
among PVNGS Funding
Corp., Inc., Bank
of America National
Trust and Savings
Association, State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, in its
individual capacity
and as Owner
Trustee, Chemical
Bank, in its
individual capacity
and as Indenture
Trustee, APS, and
the Equity
Participant named
therein
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 30, 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
99.3ac
Pinnacle West
APS
Supplemental
Indenture No. 1,
dated as of
November 1, 1986 to
Trust Indenture,
Mortgage, Security
Agreement and
Assignment of
Facility Lease,
dated as of August
1, 1986, between
State Street Bank
and Trust Company,
as successor to The
First National Bank
of Boston, as
Owner Trustee, and
Chemical Bank, as
Indenture Trustee
10.6 to APS’ September 30, 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
99.4c
Pinnacle West
APS
Assignment,
Assumption and
Further Agreement,
dated as of August
1, 1986, between
APS and State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, as Owner
Trustee
28.3 to APS’ Form S-3 Registration
Statement, File No. 33-9480
10-24-86
99.4ac
Pinnacle West
APS
Amendment No. 1,
dated as of
November 1, 1986,
to Assignment,
Assumption and
Further Agreement,
dated as of August
1, 1986, between
APS and State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, as
Owner Trustee
10.10 to APS’ September 30, 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
99.5
Pinnacle West
APS
Participation
Agreement, dated as
of December 15,
1986, among PVNGS
Funding Report
Corp., Inc., State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, in its
individual capacity
and as Owner
Trustee, Chemical
Bank, in its
individual capacity
and as Indenture
Trustee under a
Trust Indenture,
APS, and the Owner
Participant named
therein
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
99.5b
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
99.6a
Pinnacle West
APS
Supplemental
Indenture No. 1,
dated as of
August 1, 1987, to
Trust Indenture,
Mortgage, Security
Agreement and
Assignment of
Facility Lease,
dated as of
December 15, 1986,
between State
Street Bank and
Trust Company, as
successor to The
First National Bank
of Boston, as Owner
Trustee, and
Chemical Bank, as
Indenture Trustee
4.13 to APS’ 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
99.7
Pinnacle West
APS
Assignment,
Assumption and
Further Agreement,
dated as of
December 15, 1986,
between APS and
State Street Bank
and Trust Company,
as successor to The
First National Bank
of Boston, as Owner
Trustee
10.5 to APS’ November 18, 1986 Form 8-K
Report, File No. 1-4473
1-20-87
99.7a
Pinnacle West
APS
Amendment No. 1,
dated as of 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
99.8c
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
Reports filed under File No. 1-4473 and 1-8962 were filed in the office of the
Securities and Exchange Commission located in Washington, D.C.
b
Management contract or compensatory plan or arrangement to be filed as an exhibit
pursuant to Item 15(b) of Form 10-K.
c
An additional document, substantially identical in all material respects to this
Exhibit, has been entered into, relating to an additional Equity Participant. Although such
additional document
may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates
of execution), there are no material details in which such document differs from this Exhibit.
d
Additional agreements, substantially identical in all material respects to this
Exhibit have been entered into with additional persons. Although such additional documents may
differ in other respects (such as dollar amounts and dates of execution), there are no material
details in which such agreements differ from this Exhibit.
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.
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.
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.