Indicate by check mark whether each 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. Yes þ No o
Indicate by check mark whether each registrant is an accelerated filer (as defined in Exchange
Act Rule 12b-2).
PINNACLE WEST CAPITAL CORPORATION
ARIZONA PUBLIC SERVICE COMPANY
Yesþ
Yeso
Noo
Noþ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock as
of the latest practicable date.
PINNACLE WEST CAPITAL CORPORATION
Number of shares of common stock, no
par value, outstanding as of August 8,2005: 98,760,860
ARIZONA PUBLIC SERVICE COMPANY
Number of shares of common stock, $2.50
par value, outstanding as of August 8,2005: 71,264,947
Arizona Public Service Company meets the conditions set forth in General Instruction H(1)(a)
and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format allowed
under that General Instruction.
This combined Form 10-Q 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-Q that relates to such registrant. Neither registrant is filing any
information that does not relate to such registrant, and therefore makes no representation as to
any such information.
ADEQ — Arizona Department of Environmental Quality
ALJ — Administrative Law Judge
APS — Arizona Public Service Company, a subsidiary of the Company
APS Energy Services — APS Energy Services Company, Inc., a subsidiary of the Company
CC&N — Certificate of Convenience and Necessity
Clean Air Act — Clean Air Act, as amended
Company — Pinnacle West Capital Corporation
DOE — United States Department of Energy
EITF — FASB’s Emerging Issues Task Force
El Dorado — El Dorado Investment Company, a subsidiary of the Company
EPA — United States Environmental Protection Agency
ERMC — Energy Risk Management Committee
FASB — Financial Accounting Standards Board
FERC — United States Federal Energy Regulatory Commission
FIN — FASB Interpretation
Financing Order — ACC Order that authorized APS’ $500 million loan to Pinnacle West Energy in May
2003
GAAP — accounting principles generally accepted in the United States of America
IRS — United States Internal Revenue Service
March 2005 Form 10-Q — Pinnacle West/APS Quarterly Report on Form 10-Q for the fiscal quarter ended
March 31, 2005
Moody’s — Moody’s Investors Service
MW — megawatt, one million watts
MWh — megawatt-hours, one million watts per hour
NAC — collectively, NAC Holding Inc. and NAC International Inc., subsidiaries of El Dorado that
were sold in November 2004
Native Load — retail and wholesale sales supplied under traditional cost-based rate regulation
NPC — Nevada Power Company
NRC — United States Nuclear Regulatory Commission
Nuclear Waste Act — Nuclear Waste Policy Act of 1982, as amended
OCI — other comprehensive income
Off-System Sales — sales of electricity from generation owned by the Company that is over and above
the amount required to serve the Company’s retail customers and traditional wholesale contracts
Palo Verde — Palo Verde Nuclear Generating Station, also known as ANPP
Pinnacle West — Pinnacle West Capital Corporation, the Company
Pinnacle West Energy — Pinnacle West Energy Corporation, a subsidiary of the Company
PPL Sundance — PPL Sundance Energy, LLC
PRP — potentially responsible party
PSA — power supply adjuster
PWEC Dedicated Assets — the following Pinnacle West Energy power plants, each of which is dedicated
to serving APS’ customers: Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3
PX — California Power Exchange
RFP — request for proposals
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, a 570-megawatt, natural gas-fueled, combined-cycle electric
generating facility located 20 miles north of Las Vegas, Nevada
Standard & Poor’s — Standard & Poor’s Corporation
SunCor — SunCor Development Company, a subsidiary of the Company
Sundance Plant -450-megawatt generating facility located approximately 55 miles southeast of
Phoenix, Arizona
Superfund — Comprehensive Environmental Response, Compensation and Liability Act
T&D — transmission and distribution
Track B Order — ACC order dated March 14, 2003 regarding competitive solicitation requirements for
power purchases by Arizona’s investor-owned electric utilities
Trading — energy-related activities entered into with the objective of generating profits on
changes in market prices
2004 Settlement Agreement — an agreement settling APS’ general rate case
2004 Form 10-K — Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December31, 2004
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1.
Consolidation and Nature of Operations
The condensed consolidated financial statements include the accounts of Pinnacle West and our
wholly-owned subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and El Dorado.
All significant intercompany accounts and transactions between the consolidated companies have been
eliminated. Our accounting records are maintained in accordance with GAAP. The preparation of
financial statements in accordance with GAAP requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities, disclosure of contingent assets and
liabilities at the date of the financial statements and reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates. We have
reclassified certain prior year amounts to conform to the current year presentation.
2.
Condensed Consolidated Financial Statements
Our unaudited condensed consolidated financial statements reflect all adjustments which we
believe are necessary for the fair presentation of our financial position, results of operations
and cash flows for the periods presented. We suggest that these condensed consolidated financial
statements and notes to condensed consolidated financial statements be read along with the
consolidated financial statements and notes to consolidated financial statements included in our
2004 Form 10-K.
3.
Quarterly Fluctuations
Weather conditions cause significant seasonal fluctuations in our revenues. In addition, real
estate, trading and wholesale marketing activities can have significant impacts on our results for
interim periods. For these reasons, results for interim periods do not necessarily represent
results to be expected for the year.
4.
Changes in Liquidity
On January 15, 2005, APS repaid its $100 million 6.25% Notes due 2005. APS used cash on hand
to repay these notes.
On March 1, 2005, Maricopa County, Arizona Pollution Control Corporation issued $164 million
of variable interest rate pollution control bonds, 2005 Series A-E, due 2029. The bonds were
issued to refinance $164 million of outstanding pollution control bonds. The Series A-E bonds are
payable solely from revenues obtained from APS pursuant to a loan agreement between APS and
Maricopa County, Arizona Pollution Control Corporation. These bonds are classified as long-term
debt on our Condensed Consolidated Balance Sheets.
On April 11, 2005, Pinnacle West Energy issued $500 million of Floating Rate Senior Notes due
April 1, 2007. Pinnacle West has unconditionally guaranteed these notes. Pinnacle West Energy
used the proceeds of this issuance to repay a $500 million loan from APS. See “ACC Financing
Order” in Note 5. APS intends to transfer $500 million in connection with Pinnacle West Energy’s
transfer of the PWEC Dedicated Assets to APS. In the interim, APS intends to invest the proceeds
or use them for general corporate purposes. See “APS General Rate Case” in Note 5 for information
regarding APS’ acquisition of the PWEC Dedicated Assets.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
On May 2, 2005, Pinnacle West redeemed at par all of its $165 million Floating Rate Senior
Notes due November 1, 2005. Pinnacle West used cash on hand to redeem the notes.
On May 2, 2005, Pinnacle West issued 6,095,000 shares of its common stock at an offering price
of $42 per share, resulting in net proceeds of approximately $248 million. Pinnacle West used the
net proceeds for general corporate purposes, including making capital contributions to APS, which,
in turn, used 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.
On August 1, 2005, APS repaid $300 million of its 7.625% Notes due 2005. APS used cash on
hand to repay these notes.
APS had $566 million of pollution control bonds outstanding under which interest rates are
reset on a daily, weekly or annual basis as of June 30, 2005. The holders of $223 million of these
bonds have the right to cause APS to purchase their bonds on the applicable reset date if the bonds
are not remarketed. Of these bonds, $50 million is classified as current maturities of long-term
debt. The remaining $173 million of bonds are classified as long-term debt because APS has the
intent and ability, as demonstrated by credit agreements in place that extend for more than one
year, to refinance any bonds that APS is required to purchase.
The following is a list of principal payments due on Pinnacle West’s consolidated long-term
debt and capitalized lease requirements as of June 30, 2005:
•
$352 million in 2005;
•
$389 million in 2006;
•
$674 million in 2007;
•
$6 million in 2008;
•
$1 million in 2009; and
•
$2.012 billion thereafter.
We have investments in auction rate securities in which interest rates are reset on a
short-term basis; however, the underlying contract maturity dates extend beyond three months. We
classify the investments in auction rate securities as investments in debt securities on our
Condensed Consolidated Balance Sheets. The purchase and sale activities related to these
investments have been reclassified on the Condensed Consolidated Statements of Cash Flows for the
prior-year period to show purchases and sales on a gross basis.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
5.
Regulatory Matters
Electric Industry Restructuring
State
APS General Rate Case
On April 7, 2005, the ACC issued an order in the general rate case that APS filed on June 27,2003. The order became final and non-appealable on April 28, 2005. In its order, the ACC approved
the 2004 Settlement Agreement, with certain revisions. Certain key financial components of the
order include:
•
APS received an annual retail rate increase of approximately $75.5 million, or
4.21%, which was effective as of April 1, 2005. This increase does not include the
impact of the PSA (discussed below).
•
The PSA provides for the annual adjustment of rates to reflect variations in fuel
and purchased power costs, subject to specified parameters and procedures, including
the following:
•
APS will record deferrals for recovery or refund to the extent actual fuel
and purchased power costs vary from $0.020743 per kWh (basic fuel amount);
•
The above deferrals are subject to a 90/10 sharing arrangement in which APS
must absorb 10% of the costs above the base fuel amount and may retain 10% of
the benefit from the costs that are below the base fuel amount;
•
amounts to be recovered or refunded through the annual PSA adjustment are
limited to a cumulative plus or minus $0.004 per kWh over the life of the PSA;
•
in addition, the ACC order provides for a PSA surcharge mechanism as
follows:
•
each time the accumulated pretax net deferrals reach $50 million,
APS must notify the ACC, but prior to the deferral balance exceeding
$100 million, APS must file with the ACC to recover or refund such
deferral balance through a surcharge;
•
amounts recovered or refunded through any surcharge are not included
in the $0.004 per kWh PSA annual adjustment limit;
•
the recoverable amount of net fuel and purchased power costs through base
rates and the $0.004 per kWh adjustment is capped at $776.2 million per year -
PSA surcharge amounts are not included in the $776.2 million annual limits on
fuel and purchased power recovery (APS does not expect such costs to exceed
$776.2 million in 2005);
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
•
the PSA will remain in effect for a minimum five-year period, but the ACC
may eliminate the PSA at any time, if appropriate, in the event APS files a
rate case before the expiration of the five-year period or if APS does not
comply with the terms of the PSA;
•
APS filed a request for a PSA surcharge on July 22, 2005 (see discussion
below); and
•
the first regular annual adjustment to the PSA would be on April 1, 2006,
and is expected to be for the full $0.004 per kWh permitted by the ACC’s order,
which is in addition to the PSA surcharge requested on July 22, 2005.
•
The 2004 Settlement Agreement included a self-build moratorium for generating plants
to be in service prior to January 1, 2015. The ACC order modified that moratorium to
include the acquisition of a generating unit, or an interest in a generating unit, from
any utility or merchant generator without prior ACC approval.
•
APS was authorized to acquire Redhawk Units 1 and 2, West Phoenix Units 4 and 5, and
Saguaro Unit 3, which are dedicated to serving APS’ customers (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 will result in a mandatory rate base disallowance of approximately $150
million. This transfer was approved by the FERC on June 15, 2005 and completed on July29, 2005. As a result, for financial reporting purposes, APS will recognize a
one-time, after-tax net plant write-off of approximately $90 million during the third
quarter of 2005.
•
To bridge the time between the effective date of the rate increase and the actual
date the PWEC Dedicated Assets transfer, effective April 1, 2005, APS and PWEC entered
into a cost-based purchase power agreement (the “Bridge PPA”), which was based on the
value of the PWEC Dedicated Assets. When the Bridge PPA became effective, prior power
purchase agreements entered into between APS and PWEC were terminated. The Bridge PPA
was terminated on July 29, 2005, upon Pinnacle West Energy’s transfer of the PWEC
Dedicated Assets to APS.
•
Effective April 1, 2005, APS adopted longer service lives in accordance with
the 2004 Settlement Agreement for certain depreciable assets. This
change is expected to have the effect of
reducing annual depreciation expense for financial reporting purposes by approximately
$30 million. Also in accordance with the 2004 Settlement Agreement, we adopted longer
service lives for the PWEC Dedicated Assets, which is expected to have the effect of reducing annual
depreciation expense for financial reporting purposes by approximately $10 million.
Power Supply Adjuster
On July 22, 2005, APS filed an Application for Surcharge with the ACC requesting recovery of
$100 million in deferred purchased power and fuel costs under the PSA approved by the ACC in APS’
recent general rate case. As required by the ACC order approving the PSA, APS filed the
Application for Surcharge after the PSA “bank balance” reached $50 million and before it reached
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
$100 million, which APS expects to occur by mid-August of this year. APS proposes to recover the
$100 million PSA bank balance over a 24-month period beginning with the billing cycle one of
November 2005. The requested PSA surcharge represents an approximate 2.2% temporary increase in
overall APS retail revenues.
Equity Infusion Notice
On July 20, 2005, Pinnacle West filed a Notice with the ACC indicating its intent to infuse
more than $100 million of equity into APS during each of 2005, 2006 and subsequent years.
Under Arizona law and decisions, Pinnacle West is required to give such notice at least 120 days
prior to such an equity infusion into APS. The ACC may, but need not, take action on this Notice.
If the ACC takes no action within the 120 day notice period, Pinnacle West may thereafter make the
proposed equity infusions, at management’s discretion.
ACC Financing Order
On May 12, 2003, APS issued $500 million of debt pursuant to the Financing Order and made a
$500 million loan to Pinnacle West Energy. Pinnacle West Energy distributed the net proceeds of
that loan to the Company to fund the repayment of a portion of the debt incurred to finance the
construction of the PWEC Dedicated Assets. On April 11, 2005, this loan was repaid with the
proceeds of a new debt issuance by Pinnacle West Energy. See “Capital Needs and Resources — By
Company — Pinnacle West Energy” in Part I, Item 2 below.
The ACC granted the Financing Order subject to various conditions. One of these conditions is
that APS must maintain a common equity ratio of at least 40% and may not pay common dividends if
such payment would reduce its common equity ratio below that threshold, unless otherwise waived by
the ACC. This condition is an ongoing requirement and was not affected by Pinnacle West Energy’s
repayment of APS’ $500 million loan.
Retail Electric Competition Rules
In 1999, the ACC approved rules for the introduction of retail electric competition in
Arizona. The rules include the following major provisions:
•
They apply to virtually all Arizona electric utilities regulated by the ACC,
including APS.
•
Effective January 1, 2001, retail access became available to all APS retail
electricity customers.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
•
Electric service providers that get CC&N’s from the ACC can supply only competitive
services, including electric generation, but not electric transmission and
distribution.
•
Affected utilities must file ACC tariffs that unbundle rates for noncompetitive
services.
•
The ACC shall allow a reasonable opportunity for recovery of unmitigated stranded
costs.
On November 27, 2000, a Maricopa County, Arizona, Superior Court judge issued a final judgment
holding that the rules are unconstitutional and unlawful in their entirety due to failure to
establish a fair value rate base for competitive electric service providers and because certain of
the rules were not submitted to the Arizona Attorney General for certification. The judgment also
invalidates all ACC orders authorizing competitive electric service providers, including APS Energy
Services, to operate in Arizona. The ACC and other parties aligned with the ACC appealed the
ruling to the Arizona Court of Appeals, and in January 2004, the Court invalidated some, but not
all, of the rules as either violative of Arizona’s constitutional requirement that the ACC consider
the “fair value” of a utility’s property in setting rates or as being beyond the ACC’s
constitutional and statutory powers. Other rules were set aside for failure to submit such
regulations to the Arizona Attorney General for certification as required by statute. A request
for the Arizona Supreme Court to review the Court of Appeals decision was denied on January 4,2005. To date, the ACC has taken no action on either the rules or the orders authorizing
competitive electric service providers in response to the now 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.
Track B Order
On March 14, 2003, the ACC issued the Track B Order, which required APS to solicit bids for
certain estimated amounts of capacity and energy for periods
beginning July 1, 2003. By May 6, 2003, APS entered into
contracts to meet all or a portion of its requirements for the years 2003 through 2006 as follows:
(1)
Pinnacle West Energy agreed to provide 1,700 MW in July through September of
2003 and in June through September of 2004, 2005 and 2006, by means of a unit
contingent contract.
(2)
PPL EnergyPlus, LLC agreed to provide 112 MW in July through September of 2003
and 150 MW in June through September of 2004 and 2005, by means of a unit contingent
contract.
(3)
Panda Gila River LP agreed to provide 450 MW in October of 2003 and 2004 and
May of 2004 and 2005, and 225 MW from November 2003 through April 2004 and from
November 2004 through April 2005, by means of firm call options.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
With final ACC approval of the 2004 Settlement Agreement, the Track B contract with Pinnacle
West Energy was cancelled, effective April 1, 2005 and replaced by the Bridge PPA. Also, the Track
B contract with PPL was cancelled upon closing of the purchase of the
Sundance Plant. On May 13, 2005, APS acquired the Sundance Plant
from PPL Sundance for a purchase price of approximately
$190 million.
General
Although some very limited
retail competition existed in APS’ service area in 1999 and 2000, there are currently no active
retail competitors providing unbundled energy or other utility services to APS’ customers. As a
result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’
service territory.
Federal
In July 2002, the FERC adopted a price mitigation plan that constrains the price of
electricity in the wholesale spot electricity market in the western United States. The FERC
adopted a price cap of $250 per MWh for the period subsequent to October 31, 2002. Sales at prices
above the cap must be justified and are subject to potential refund.
On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking for Standard Market Design
for wholesale electric markets and, on April 28, 2003, the FERC Staff issued an additional white
paper on the proposed Standard Market Design. On July 19, 2005, the FERC terminated the rulemaking
proceeding.
On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy, and APS Energy Services
(collectively, the “Pinnacle West Companies”) submitted to the FERC an update to its 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 market-based rates for control
areas other than those of APS, Public Service Company of New Mexico and Tucson Electric Company.
The order required the Pinnacle West Companies to submit additional data with respect to these
control areas, and on February 18, 2005, the Pinnacle West Companies submitted such data. On April11, 2005, APS and a group of APS wholesale electric customers, the Arizona Districts, submitted a
settlement that resolved concerns raised by the Arizona Districts in the proceeding. On May 2,2005, a protest and a motion to intervene were filed by the Yavapai-Apache Energy Office with
respect to the settlement between APS and the Arizona Districts. On April 5, 2005, the FERC issued
a deficiency letter seeking further information from the Pinnacle West Companies relating to the
APS control area and the Pinnacle West Companies filed a response on April 22, 2005. The notice
period for filing comments on that response expired on May 5, 2005, and no additional comments were
filed. We cannot currently predict the outcome of this proceeding, but we do not believe that the
outcome will have a material adverse effect on our financial position, results of operations or
cash flows.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
6.
Retirement Plans and Other Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a
nonqualified supplemental excess benefit retirement plan, and other postretirement benefit plans
for the employees of Pinnacle West and our subsidiaries.
The following table provides details of the plans’ benefit costs for the three and six months
ended June 30, 2005 and 2004. Also included is the portion of these costs charged to expense,
including administrative costs and excluding amounts billed to electric plant participants or
amounts capitalized as overhead construction (dollars in millions):
Our minimum required pension contribution in 2005 is approximately $53 million. Of this
amount, we have contributed approximately $27 million through July 2005. The contribution to be
made to other postretirement benefit plans in 2005 is estimated to be approximately $37 million.
Of this amount, we contributed approximately $18 million through July 2005. APS’ share is
approximately 92% of both plans.
7.
Business Segments
We have three principal business segments (determined by products, services and the regulatory
environment):
•
our regulated electricity segment, which consists of traditional regulated retail
and wholesale electricity businesses (primarily electricity service to Native Load
customers) and related activities and includes electricity generation, transmission and
distribution;
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
•
our marketing and trading segment, which consists of our competitive energy business
activities, including wholesale marketing and trading and APS Energy Services’
commodity-related energy services; and
•
our real estate segment, which consists of SunCor’s real estate development and
investment activities.
Effective April 1, 2005, Off-System Sales of approximately $12 million that
would have previously been reported in the marketing and trading segment are now included in
the regulated electricity segment in accordance with the retail rate settlement.
(b)
The 2005 periods include a $59 million (after-tax) loss in discontinued
operations related to the pending sale of Silverhawk.
(c)
The 2004 periods include $21 million (after-tax) gain
related to the sale of a limited partnership interest in the Phoenix Suns.
In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment.” The standard
establishes accounting for transactions in which an entity exchanges its equity instruments for
goods or services. It also addresses transactions in which an entity incurs liabilities in
exchange for goods or services that are based on the fair value of the entity’s equity instruments
or that may be settled by the issuance of those equity instruments. SFAS No. 123(R) is effective
for us as of January 1, 2006. We have evaluated the impacts of this new guidance and do not
believe it will have a material impact on our financial statements.
In March 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement
Obligations.” FIN No. 47 clarifies that an entity must record a liability for the fair value of an
asset retirement obligation for which the timing and (or) method of settlement are conditional on a
future event if the liability’s fair value can be reasonably estimated. FIN No. 47 is effective no
later than the end of fiscal years ending after December 15, 2005. We are currently evaluating the
new guidance, but do not expect the adoption of this interpretation to have a material impact on
our financial statements.
9. 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.
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 June 30, 2005, APS would have been required to assume
approximately $245 million of debt and pay the equity participants approximately $191 million.
10. Derivative and Energy Trading Accounting
We are exposed to the impact of market fluctuations in the commodity price of electricity,
natural gas, coal and emissions allowances and in interest rates. We manage risks associated with
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
these market fluctuations by utilizing various instruments that qualify as derivatives,
including exchange-traded futures and options and over-the-counter forwards, options and swaps. As
part of our overall risk management program, we use such instruments to hedge our exposure to
changes in interest rates and to hedge purchases and sales of electricity, fuels, and emissions
allowances and credits. As of June 30, 2005, we hedged exposures to the price variability of the
commodities for a maximum of four years. The changes in market value of such contracts have a high
correlation to price changes in the hedged transactions. In addition, subject to specified risk
parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit
from market price movements.
Cash Flow Hedges
The changes in the fair value of our hedged positions included in the Condensed Consolidated
Statements of Income for the three and six months ended June 30, 2005 and 2004 were comprised of
the following (dollars in thousands):
Gains on the ineffective portion
of derivatives qualifying for
hedge accounting
$
4,514
$
88
$
11,837
$
1,472
Gains (losses) from the change
in options’ time value
excluded from measurement
of effectiveness
(1,189
)
(17
)
(331
)
63
Gains from the discontinuance
of cash flow hedges
—
—
385
1,137
During the twelve months ending June 30, 2006, we estimate that a net gain of $87 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.
Our assets and liabilities from risk management and trading activities are presented in two
categories, consistent with our business segments:
•
Regulated Electricity — non-trading derivative instruments that hedge our purchases
and sales of electricity and fuel for APS’ Native Load requirements of our regulated
electricity business segment; and
•
Marketing and Trading — both non-trading and trading derivative instruments of our
competitive business segment.
The following table summarizes our assets and liabilities from risk management and trading
activities at June 30, 2005 and December 31, 2004 (dollars in thousands):
Cash or other assets may be required to serve as collateral against our open positions on
certain energy-related contracts. Collateral provided to counterparties was $6 million at June 30,2005 and $1 million at December 31, 2004, and is included in other current assets on the Condensed
Consolidated Balance Sheets. Collateral provided to us by counterparties was $122 million at June30, 2005 and $24 million at December 31, 2004, and is included in other current liabilities on the
Condensed Consolidated Balance Sheets.
Fair Value Hedges
On January 29, 2004, we entered into two fixed-for-floating interest rate swap transactions on
our $300 million 6.4% Senior Notes. The purpose of these hedges is to protect against significant
fluctuations in the fair value of our debt. Our interest rate swaps are considered to be fully
effective with any resulting gains or losses on the derivative offset by a similar loss or gain
amount on the underlying fair value of our debt. The fair value of the interest rate swaps was a
loss of approximately $2.7 million at June 30, 2005 and is included in other current liabilities
with the corresponding offset in current maturities of long-term debt on the Condensed 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, including one counterparty for
which a worst case exposure represents approximately 16% of Pinnacle West’s $620 million of risk
management and trading assets as of June 30, 2005. Our risk management process assesses and
monitors the financial exposure of these and all other counterparties. Despite the fact that the
great majority of trading counterparties are rated as investment grade by the credit rating
agencies, including the counterparty discussed above, there is still a possibility that one or more
of these companies could default, resulting in a material impact on consolidated earnings for a
given period. Counterparties in the portfolio consist principally of major energy companies,
municipalities, local distribution companies and financial institutions. We maintain credit
policies that we believe minimize overall credit risk to within acceptable limits. Determination
of the credit quality of our counterparties is based upon a number of factors, including credit
ratings and our evaluation of their financial condition. In many contracts, we employ collateral
requirements and standardized agreements that allow for the netting of positive and negative
exposures associated with a single counterparty. Valuation adjustments are established
representing our estimated credit losses on our overall exposure to counterparties.
Unrealized gain (loss) on
derivative instruments (a)
(24,220
)
25,721
135,424
73,287
Reclassification of realized
gain to income (b)
(9,769
)
(6,318
)
(15,688
)
(6,480
)
Income tax (expense) benefit
related to items of other
comprehensive income
13,334
(7,620
)
(46,972
)
(26,235
)
Total other comprehensive income
(loss)
(20,655
)
11,783
72,764
40,572
Comprehensive income
$
6,080
$
84,423
$
123,947
$
144,638
(a)
These amounts primarily include unrealized gains and losses on contracts used to
hedge our forecasted electricity and gas requirements to serve Native Load.
(b)
These amounts primarily include the reclassification of unrealized gains and
losses to realized for contracted commodities delivered during the period.
12.
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 Act required the DOE to develop a permanent repository for the storage
and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed
before 2010 and it does not intend to begin accepting spent nuclear fuel prior to that date.
In
November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit)
issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin
accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including
APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court
of Federal Claims. Arizona Public Service Company v. United States
of America, United States Court of Federal
Claims, 03-2832C.
APS currently estimates it will incur $147 million (in 2004 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 June 30, 2005, APS had a regulatory asset of $10 million which represents amounts spent for
on-site interim spent fuel storage net of amounts recovered in rates per the ACC rate order that
was effective April 1, 2005.
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.
APS does not anticipate material changes in its exposure and still believes, subject to
the finalization of the revised proxy prices, that it will be entitled to a net refund.
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. State of California v. British
Columbia Power Exchange et al.,
Docket No. EL02-71-000. 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. State of California ex rel. Bill Lockyer, Attorney General v. FERC, No.
02-73093. Several of the intervenors in this appeal filed a petition for rehearing of this
decision on October 25, 2004. The petition for rehearing has not been acted upon, and the outcome
of the further proceedings cannot be predicted at this time.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for
the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific
Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding.
This decision has now been appealed to the Ninth Circuit Court of Appeals. Although the FERC
ruling in the Pacific Northwest matter is being appealed and the FERC has not yet calculated the
specific refund amounts due in California, we do not expect that the resolution of these issues, as
to the amounts alleged in the proceedings, will have a material adverse impact on our financial
position, results of operations or cash flows.
On March 26, 2003, FERC made public a Final Report on Price Manipulation in Western Markets,
prepared by its staff and covering spot markets in the West in 2000 and 2001. The report stated
that a significant number of entities who participated in the California markets during the
2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions
that allegedly violated certain provisions of the Independent System Operator tariff. After
reviewing the matter, along with the data supplied by APS, the FERC staff moved to dismiss the
claims against APS and to dismiss the proceeding. The motion to dismiss was granted by the FERC on
January 22, 2004. Certain parties have sought rehearing of this order, and that request is
pending.
California Civil Energy Market Litigation
The State of California and others have filed various claims, which have now been
consolidated, against several power suppliers to California alleging antitrust violations.
Wholesale Electricity Antitrust Cases I and II, Superior Court in and for the County of San
Diego, Proceedings Nos. 4204-00005 and 4204-00006. Two of the suppliers who were named as
defendants in those matters, Reliant Energy Services, Inc. (and other Reliant entities) and Duke
Energy and Trading, LLP (and other Duke entities), filed cross-claims against various other
participants in the PX and California independent system operator markets, including APS,
attempting to expand those matters to such other participants. On December 13, 2002, the judge
remanded the case to state court for the second time and the matter was appealed. On December 8,2004, the Ninth Circuit issued its opinion on immunity on certain unrelated defendants. The
cross-defendants will not be required to respond until the Court rules on pending motions. APS
believes the claims by Reliant and Duke as they relate to APS are without merit.
APS was also named in a lawsuit regarding wholesale contracts in California, which, after
being moved to state court, has been removed to the federal court for a second time. James
Millar, et al. v. Allegheny Energy Supply, et al., San Francisco Superior Court, Case No.
407867, U.S. District Court (Northern District) C-04-0519 SBA. The First Amended Complaint alleges basically that
the contracts entered into were the result of an unfair and unreasonable market, in violation of
California unfair competition laws. The defendants have filed a motion in the state court
requesting that the case be dismissed and expect a ruling prior to trial within the next several
months. The PX has filed a lawsuit against the State of California regarding the seizure of forward contracts and the
State has filed a cross complaint against APS and numerous other PX participants. Cal PX v.
The State of California, Superior Court in and for the County of Sacramento, JCCP No. 4203.
Various motions continue to be filed, and we currently believe these claims will have no material
adverse impact on our financial position, results of operations or cash flows.
Natural Gas Supply
Pursuant to the terms of a comprehensive settlement entered into in 1996 with El Paso Natural
Gas Company, the rates charged for natural gas transportation are subject to a rate moratorium
through December 31, 2005.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
On July 9, 2003 the FERC issued an order that altered the capacity rights of parties to the
1996 settlement but maintained the cost responsibility provisions agreed to by parties to that
settlement. On December 28, 2004, the D.C. Court of Appeals upheld the FERC’s authority to alter
the capacity rights of parties to the settlement. With respect to the FERC’s authority to maintain
the cost responsibility provisions of the settlement, a party has sought appellate review and is
seeking to reallocate the costs responsibility associated with the changed contractual obligations
in a way that would be less favorable to APS and Pinnacle West Energy than under the FERC’s July 9,2003 order. Should this party prevail on this point, APS and Pinnacle West Energy’s annual
capacity cost could be increased by approximately $3 million per year, from September 2003 through
December 2005.
Consistent with its obligations under the 1996 settlement, El Paso filed a new rate case on
June 30, 2005, which proposes new rates and new services to become effective on January 1, 2006.
Protests were filed on July 12, 2005.
Navajo Nation Litigation
In June 1999, the Navajo Nation served Salt River Project with a 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. The Navajo Nation v. Peabody
Holding Company, Inc., et al., United States District Court for the District of Columbia,
CA-99-0469-EGS (the “D.C. Lawsuit”). 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 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”. Peabody Western Coal Company v. Salt River Project Agricultural Improvement and
Power District, et al., Circuit Court for the City of St. Louis, Division No. 1, Cause No.
042-08561. Based on APS’ ownership interest in the Navajo Generating Station, APS could be liable
for up to 14% of any such obligation. Because the litigation is in preliminary stages, APS cannot
currently predict the outcome of this matter.
Environmental Matters
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
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
and
Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS
facilities within OU3. Because the investigation has not yet been completed and ultimate
remediation requirements are not yet finalized, neither APS nor Pinnacle West can currently
estimate the expenditures which may be required.
Litigation
We are party to various other claims, legal actions and complaints arising in the ordinary
course of business, including but not limited to environmental matters related to the Clean Air
Act, Navajo Nation issues and EPA and ADEQ issues. In our opinion, the ultimate resolution of
these matters will not have a material adverse effect on our financial position, results of
operations or cash flows.
13. Nuclear Insurance
The Palo Verde participants have insurance for public liability resulting from nuclear energy
hazards to the full limit of liability under federal law. This potential liability is covered by
primary liability insurance provided by commercial insurance carriers in the amount of $300 million
and the balance by an industry-wide retrospective assessment program. If losses at any nuclear
power plant covered by the programs exceed the accumulated funds, APS could be assessed
retrospective premium adjustments. The maximum assessment per reactor under the program for each
nuclear incident is approximately $101 million, subject to an annual limit of $10 million per
incident. 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 $9 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 outage of any of the three
units. The insurance coverage discussed in this and the previous paragraph is subject to certain
policy conditions and exclusions.
Possible Price-Anderson Act Changes
Versions of comprehensive energy bills signed by the President on
August 8, 2005 contain provisions that would amend the Price-Anderson Act, addressing public
liability from nuclear energy hazards in ways that would increase the annual limit on retrospective
assessments from $10.0 million to $15.0 million per reactor
per incident with APS’ annual
exposure per incident increasing from $9.0 million to $13 million.
14.
Other Income and Other Expense
The following table provides detail of other income and other expense for the three and six
months ended June 30, 2005 and 2004 (dollars in thousands):
The three and six months ended June 30, 2004 include a $35 million gain ($21
million after tax) related to the sale of a limited partnership interest in
the Phoenix Suns.
(b)
As defined by the FERC, includes below-the-line non-operating utility costs
(primarily community relations and other costs excluded from utility rate recovery).
15.
Guarantees
We have issued parental guarantees and letters of credit and obtained surety bonds on behalf
of our unregulated subsidiaries. Our parental guarantees related to Pinnacle West Energy consist
of equipment and performance guarantees related to our generation construction program, and
long-term service agreement guarantees for new power plants. Our credit support instruments enable
APS Energy Services to offer commodity energy and energy-related products. Non-performance or
non-payment under the original contract by our unregulated
subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Condensed
Consolidated Balance Sheets related to Pinnacle West’s guarantees on behalf of its subsidiaries.
Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under
the guarantee. The amounts and approximate terms of our guarantees and surety bonds for each
subsidiary at June 30, 2005 are as follows (dollars in millions):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Guarantees
Surety Bonds
Amount
Term
Amount
Term
(in years)
(in years)
Parental:
Pinnacle West Energy
$
17
1
$
—
—
APS Energy Services
26
1
83
1
Total
$
43
$
83
At June 30, 2005, we had entered into approximately $37 million of letters of credit which
support various transmission and construction agreements. These letters of credit expire in 2005
and 2006. We intend to provide from either existing or new facilities for the extension, renewal
or substitution of the letters of credit to the extent required. At June 30, 2005, Pinnacle West
had approximately $4 million of letters of credit related to workers’ compensation expiring in
2006.
APS has entered into various agreements that require letters of credit for financial assurance
purposes. At June 30, 2005, approximately $200 million of letters of credit were outstanding to
support existing pollution control bonds of approximately $200 million. The letters of credit are
available to fund the payment of principal and interest of such debt obligations. In July 2004,
$150 million of these letters of credit were renewed for a three-year term and expire in 2007. The
remainder expire in 2005. APS has also entered into approximately $100 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, APS has approximately $5 million of letters of credit related to
counterparty collateral requirements expiring in 2006. APS intends to provide from either existing
or new facilities for the extension, renewal or substitution of the letters of credit to the extent
required.
We enter into agreements that include indemnification provisions relating to liabilities
arising from or related to certain of our agreements. APS has agreed to indemnify the equity
participants and other parties in the Palo Verde sale leaseback transactions with respect to
certain tax matters. Generally, a maximum obligation is not explicitly stated in the
indemnification provisions and therefore, the overall maximum amount of the obligation under such
indemnification provisions cannot be reasonably estimated. Based on historical experience and
evaluation of the specific indemnities, we do not believe that any material loss related to such
indemnification provisions is likely.
See Note 4 for information regarding Pinnacle West’s guarantee of $500 million of Pinnacle
West Energy’s debt obligations.
16.
Earnings Per Share
The following table presents earnings per weighted average common share outstanding for the
three and six months ended June 30, 2005 and 2004:
Dilutive stock options increased average common shares outstanding by approximately 107,000
shares and 85,000 shares for the three months ended June 30, 2005 and June 30, 2004, respectively,
and by approximately 100,000 shares and 87,000 shares for the six months ended June 30, 2005 and
June 30, 2004, respectively.
Options to purchase 491,984 shares for the three-month period ended June 30, 2005 and 503,859
shares of common stock for the six month period ended June 30, 2005 were outstanding but were not
included in the computation of 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 for that same reason were
2,325,165 shares for the three-month period ended June 30, 2004 and 2,355,287 shares for the
six-month period ended June 30, 2004.
17.
Discontinued Operations
Silverhawk (marketing and trading segment) – In June 2005, we entered into an agreement to
sell our 75% interest in Silverhawk to NPC. Closing of the sale is subject to regulatory
approvals, including approval by the Nevada Public Utilities Commission and the FERC, which are
expected to occur by this fall. As a result of this pending sale, we recorded an after-tax loss
from discontinued operations of approximately $55 million. The assets held for sale at June 30,2005 are $207 million, of which property, plant and equipment accounted for approximately $200
million. Liabilities held for sale relate to accounts payable in the amount of $2 million.
SunCor (real estate segment) – In 2005, SunCor sold commercial properties, which are required
to be reported as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of
Income in accordance with SFAS No. 144. The assets held for sale at June 30, 2005 relate to
property in the amount of $35 million. Liabilities held for sale relate to current maturities of
long-term debt in the amount of $29 million.
NAC (other segment) – In 2004, we sold our investment in NAC.
The
following table provides revenue and income (loss) before income
taxes and after income taxes
classified as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of
Income for the three and six months ended June 30, 2005 and 2004 (dollars in millions):
Allowance for equity funds used during construction
2,952
2,184
Other income (Note S-4)
7,005
4,668
Other expense (Note S-4)
(2,876
)
(1,220
)
Total
5,532
4,331
INTEREST DEDUCTIONS
Interest on long-term debt
35,612
31,997
Interest on short-term borrowings
2,055
1,215
Debt discount, premium and expense
1,188
1,188
Capitalized interest
(2,000
)
(1,399
)
Total
36,855
33,001
NET INCOME
$
63,998
$
54,934
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to
Arizona Public Service Company’s Condensed Financial Statements.
Allowance for equity funds used during construction
5,555
4,186
Other income (Note S-4)
12,664
15,903
Other expense (Note S-4)
(6,234
)
(6,124
)
Total
9,599
10,195
INTEREST DEDUCTIONS
Interest on long-term debt
71,129
67,643
Interest on short-term borrowings
3,246
3,716
Debt discount, premium and expense
2,192
2,383
Capitalized interest
(3,947
)
(2,256
)
Total
72,620
71,486
NET INCOME
$
91,043
$
89,363
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to
Arizona Public Service Company’s Condensed Financial Statements.
Intangible assets, net of accumulated amortization
96,800
103,701
Nuclear fuel, net of accumulated amortization
53,459
51,188
Utility plant – net
6,585,272
6,258,358
INVESTMENTS AND OTHER ASSETS
Note receivable from Pinnacle West Energy
(Notes 5 and S-5)
—
498,489
Decommissioning trust accounts
276,746
267,700
Assets from long-term risk management and trading
activities (Note S-2)
75,236
20,123
Other assets
61,086
61,364
Total investments and other assets
413,068
847,676
CURRENT ASSETS
Cash and cash equivalents
204,597
49,575
Investment in debt securities
272,783
181,175
Accounts receivable:
Service customers
178,304
214,487
Other
73,093
63,131
Allowance for doubtful accounts
(3,228
)
(3,444
)
Accrued utility revenues
120,678
76,154
Materials and supplies (at average cost)
88,663
83,893
Fossil fuel (at average cost)
26,590
20,506
Assets from risk management and trading
activities (Note S-2)
133,685
70,430
Other current assets
9,634
10,187
Total current assets
1,104,799
766,094
DEFERRED DEBITS
Deferred purchased power and fuel regulatory asset
33,785
—
Other regulatory assets
139,690
135,051
Unamortized debt issue costs
22,951
21,832
Other deferred debits
72,566
69,541
Total deferred debits
268,992
226,424
TOTAL ASSETS
$
8,372,131
$
8,098,552
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to
Arizona Public Service Company’s Condensed Financial Statements.
Liabilities from risk management and trading activities (Note S-2)
74,250
34,292
Other current liabilities
156,451
91,441
Total current liabilities
1,201,435
1,178,770
DEFERRED CREDITS AND OTHER
Deferred income taxes
1,137,253
1,108,571
Regulatory liabilities
524,107
506,646
Liability for asset retirements
259,524
251,612
Pension liability
219,812
203,668
Customer advances for construction
60,851
59,185
Unamortized gain — sale of utility plant
48,045
50,333
Liabilities from long term risk management and trading
activities (Note S-2)
19,722
13,124
Other
206,528
227,147
Total deferred credits and other
2,475,842
2,420,286
COMMITMENTS AND CONTINGENCIES (Notes 5, 12, 13 and S-5)
TOTAL LIABILITIES AND EQUITY
$
8,372,131
$
8,098,552
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental
Notes to Arizona Public Service Company’s Condensed Financial Statements.
Allowance for equity funds used during construction
(5,555
)
(4,186
)
Deferred income taxes
(1,926
)
8,770
Change in mark-to-market valuations
(12,191
)
4,423
Changes in current assets and liabilities:
Accounts receivable
32,301
(4,630
)
Accrued utility revenues
(44,524
)
(38,126
)
Materials, supplies and fossil fuel
(10,854
)
3,416
Other current assets
2,566
(2,836
)
Accounts payable
(61,798
)
28,686
Accrued taxes
80,816
54,242
Accrued interest
(3,227
)
(9,500
)
Other current liabilities
68,372
5,519
Increase in regulatory assets
(4,699
)
(5,205
)
Change in risk management and trading activities – assets
16,387
7,203
Change in risk management and trading activities – liabilities
2,244
—
Change in pension liability
6,458
26,141
Change in other long-term assets
12,038
7,007
Change in other long-term liabilities
(4,923
)
3,934
Net cash flow provided by operating activities
291,384
365,955
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures
(301,098
)
(224,259
)
Purchase of Sundance Plant
(185,046
)
—
Capitalized interest
(3,947
)
(2,256
)
Repayment of loan by Pinnacle West Energy
500,000
—
Purchases of investment securities
(769,166
)
(124,000
)
Proceeds from sale of investment securities
677,558
94,050
Other
(11,163
)
(13,657
)
Net cash flow used for investing activities
(92,862
)
(270,122
)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt
163,975
476,240
Equity infusion
100,000
—
Dividends paid on common stock
(42,500
)
(85,000
)
Repayment and reacquisition of long-term debt
(264,975
)
(385,133
)
Net cash flow provided by (used for) financing activities
(43,500
)
6,107
NET INCREASE IN CASH AND CASH EQUIVALENTS
155,022
101,940
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
49,575
141,952
CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
204,597
$
243,892
Supplemental disclosure of cash flow information:
Cash paid (received) during the year for:
Income taxes refunded
$
(8,829
)
$
(1,726
)
Interest, net of amounts capitalized
$
73,656
$
78,604
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes
to Arizona Public Service Company’s Condensed Financial Statements.
Certain notes to APS’ Condensed Financial Statements are combined with the Notes to
Pinnacle West’s Condensed Consolidated Financial Statements. Listed below are the Condensed
Consolidated Notes to Pinnacle West’s Condensed Consolidated Financial Statements, the majority of
which also relate to APS’ Condensed Financial Statements. In addition, listed below are the
Supplemental Notes which are required disclosures for APS and should be read in conjunction with
Pinnacle West‘s Condensed Consolidated Notes.
Condensed
APS'
Consolidated
Supplemental
Footnote
Footnote
Reference
Reference
Consolidation and Nature of Operations
Note 1
—
Condensed Consolidated Financial Statements
Note 2
—
Quarterly Fluctuations
Note 3
—
Changes in Liquidity
Note 4
Note S-1
Regulatory Matters
Note 5
—
Retirement Plans and Other Benefits
Note 6
—
Business Segments
Note 7
—
New Accounting Standards
Note 8
—
Variable Interest Entities
Note 9
—
Derivative and Energy Trading Accounting
Note 10
Note S-2
Comprehensive Income
Note 11
Note S-3
Commitments and Contingencies
Note 12
—
Nuclear Insurance
Note 13
—
Other Income and Other Expense
Note 14
Note S-4
Guarantees
Note 15
—
Earnings Per Share
Note 16
—
Discontinued Operations
Note 17
—
Related Party Transactions
—
Note S-5
S-1. Changes in Liquidity
The following is a list of principal payments due on APS’ total long-term debt and capitalized
lease requirements:
•
$351 million in 2005;
•
$86 million in 2006;
•
$174 million in 2007;
•
$1 million in 2008;
•
$1 million in 2009; and
•
$2.012 billion, thereafter.
S-2. Derivative and Energy Trading Accounting
APS is exposed to the impact of market fluctuations in the commodity price of electricity,
natural gas and coal. As part of its overall risk management program, APS uses various commodity
ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS
instruments that qualify as derivatives to hedge purchases and sales of electricity and fuels. As
of June 30, 2005, APS hedged exposures to these risks for a maximum of three years.
Cash Flow Hedges
The changes in the fair value of APS’ hedged positions included in the APS Condensed
Statements of Income for the three and six months ended June 30, 2005 and 2004 were comprised of
the following (dollars in thousands):
Gains on the ineffective portion of
derivatives qualifying for hedge
accounting
$
4,512
$
124
$
11,930
$
1,535
Gains (losses) from the change in
options’ time value excluded from
measurement of effectiveness
(1,189
)
(17
)
(331
)
63
Gains from the discontinuance of
cash flow hedges
—
—
302
575
During the twelve months ending June 30, 2006, we estimate that a net gain of $54 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.
APS’ assets and liabilities from risk management and trading activities are presented in two
categories, consistent with Pinnacle West’s business segments:
•
Regulated Electricity – non-trading derivative instruments that hedge APS’ purchases
and sales of electricity and fuel for its Native Load requirements; and
•
Marketing and Trading – both non-trading and trading derivative instruments.
The following table summarizes APS’ assets and liabilities from risk management and trading
activities at June 30, 2005 and December 31, 2004 (dollars in thousands):
Cash or other assets may be required to serve as collateral against APS’ open positions on
certain energy-related contracts. No collateral was provided to counterparties at June 30, 2005 or
December 31, 2004. Collateral provided to us by counterparties was $90 million at June 30, 2005
and $6 million at December 31, 2004, and is included in other current liabilities on the Condensed
Balance Sheets.
S-3. Comprehensive Income
Components of APS’ comprehensive income for the three and six months ended June 30, 2005 and
2004, are as follows (dollars in thousands):
Unrealized gains (losses) on
derivative instruments (a)
(24,147
)
17,836
84,070
48,078
Reclassification of realized
gain to income (b)
(4,437
)
(4,963
)
(5,819
)
(6,829
)
Income tax (expense) benefit
related to items of other
comprehensive income
11,253
(5,076
)
(30,807
)
(16,267
)
Total other comprehensive income
(loss)
(17,331
)
7,797
47,444
24,982
Comprehensive income
$
46,667
$
62,731
$
138,487
$
114,345
(a)
These amounts primarily include unrealized gains and losses on contracts used to
hedge our forecasted electricity and gas requirements to serve Native Load.
(b)
These amounts primarily include the reclassification of unrealized gains and
losses to realized for contracted commodities delivered during the period.
ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS
S-4. Other Income and Other Expense
The following table provides detail of APS’ other income and other expense for the three and
six months ended June 30, 2005 and 2004 (dollars in thousands):
As defined by the FERC, includes below-the-line non-operating utility costs
(primarily community relations and other costs excluded from utility rate recovery).
S-5. Related Party Transactions
From time to time, APS enters into transactions with Pinnacle West or Pinnacle West’s
subsidiaries. The following table summarizes the amounts included in the APS Condensed Statements
of Income and Condensed Balance Sheets related to transactions with affiliated companies (dollars
in millions):
Electric revenues include sales of electricity to affiliated companies at contract prices.
Purchased power includes purchases of electricity from affiliated companies at contract prices.
The Company purchases electricity from and sells electricity to APS Energy Services; however, these
transactions are settled net and reported net in accordance with EITF 03-11, “Reporting Realized
Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held
for Trading Purposes’ As Defined in EITF Issue No. 2-3.”
Intercompany receivables primarily include amounts related to the $500 million loan APS made
to Pinnacle West Energy and intercompany sales of electricity. This loan was settled in May 2005.
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.
ITEM 2. 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 Condensed
Consolidated Financial Statements and Arizona Public Service Company’s Condensed Financial
Statements and the related Notes that appear in Item 1 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. Through its marketing and trading
division, APS also generates, sells and delivers electricity to wholesale customers in the western
United States. APS has historically accounted for a substantial part of our revenues and earnings.
Customer growth in APS’ service territory is about three times the national average and remains a
fundamental driver of our revenues and earnings.
Pinnacle West Energy is our unregulated generation subsidiary. Pursuant to the ACC’s April 7,2005 order in APS’ general rate case, on July 29, 2005, Pinnacle West Energy transferred the PWEC
Dedicated Assets to APS. See “APS General Rate Case” in Note 5. As a result, Pinnacle West
Energy’s remaining generating plant is Silverhawk, a 570 MW combined cycle plant located north of
Las Vegas, Nevada. See Note 17 of Notes to Condensed Consolidated Financial Statements for a
discussion of the pending sale of our 75% ownership interest in this plant.
As part of the ACC order in APS’ general rate case, the ACC approved the PSA, which permits
APS to defer for recovery or refund fuel and purchased power costs, subject to specified parameters
and procedures. On July 22, 2005, APS filed an Application for Surcharge with the ACC requesting
the recovery of $100 million in deferred fuel and purchased power costs over a 24-month period
beginning with billing cycle one of November, 2005. See “APS General Rate Case” in Note 5. APS
expects to file another general rate case in late 2005.
SunCor, our real estate development subsidiary, has been and is expected to be an important
source of earnings and cash flow, particularly during the years 2003 through 2005 due to
accelerated asset sales activity.
Our subsidiary, APS Energy Services, provides competitive commodity-related energy services
and energy-related products and services to commercial and industrial retail customers in the
western United States.
El Dorado, our investment subsidiary, owns minority interests in several energy-related
investments and Arizona community-based ventures.
We continue to focus on solid operational performance in our electricity generation and
delivery activities. In the generation area, 2004 represented the thirteenth consecutive year Palo
Verde was the largest power producer in the United States. In the delivery area, we focus on
superior reliability and customer satisfaction while expanding our transmission and distribution
system to
meet growth and sustain reliability. We plan to expand long-term resources to meet our retail
customers’ growing electricity needs.
See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” below for a
discussion of several factors that could affect our future financial results.
EARNINGS CONTRIBUTION BY BUSINESS SEGMENT
We have three principal business segments (determined by products, services and the regulatory
environment):
•
our regulated electricity segment, which consists of traditional regulated retail
and wholesale electricity businesses (primarily electric service to Native Load
customers) and related activities and includes electricity generation, transmission and
distribution.
•
our marketing and trading segment, which consists of our competitive energy business
activities, including wholesale marketing and trading and APS Energy Services’
commodity-related energy services; and
•
our real estate segment, which consists of SunCor’s real estate development and
investment activities.
The following table summarizes net income for the three months and six months ended June 30, 2005
and 2004 (dollars in millions):
Throughout the following explanations of our results of operations, we refer to “gross
margin.” With respect to our regulated electricity segment and our marketing and trading segment,
gross margin refers to electric operating revenues less purchased power and fuel costs. “Gross
margin” is a “non-GAAP financial measure,” as defined in accordance with SEC rules. Exhibit 99.3
reconciles this non-GAAP financial measure to operating income, which is the most directly
comparable financial measure calculated and presented in accordance with GAAP. We view gross
margin as an important performance measure of the core profitability of our operations. This
measure is a key component of our internal financial reporting and is used by our management in
analyzing our business segments. We believe that investors benefit from having access to the same
financial measures that our management uses. In addition, we have reclassified certain
prior-period amounts to conform to our current-period presentation.
Pending Sale of Silverhawk
In June 2005, we entered into an agreement to sell our 75% interest in Silverhawk to NPC.
Closing of the sale is subject to regulatory approvals, including approval by the Nevada Public
Utilities Commission and the FERC, which are expected to occur by this fall. As a result of this
pending sale, we recorded an after-tax loss from discontinued operations of approximately $55
million. We have also reclassified Silverhawk operations in the current and prior periods to
discontinued operations.
Deferred Purchased Power and Fuel Costs
APS’ retail rate case settlement became effective April 1, 2005. As part of the settlement,
the ACC approved a 4.2% annual retail rate increase and a PSA that provides mechanisms for
adjusting rates to reflect variations in fuel and purchased power costs. In accordance with the
PSA, APS defers for future rate recovery 90% of the difference between actual purchased power and
fuel costs and the amount for such costs currently included in base rates. As of June 30, 2005,
APS had deferred $34 million of pretax purchased power and fuel costs.
Operating Results – Three-month period ended June 30, 2005 compared with three-month period ended
June 30, 2004
Our consolidated net income for the three months ended June 30, 2005 was $27 million compared
with $73 million for the prior-year period. The current-quarter net income included a loss from
discontinued operations of $58 million which is primarily related to the pending sale and
operations of Silverhawk (see discussion above). Income from continuing operations increased $11
million in the period-to-period comparison reflecting the following changes in earnings by segment:
•
Regulated Electricity Segment – Income from continuing operations increased
approximately $29 million primarily due to a retail price increase effective April 1,2005, higher retail sales volumes due to customer growth, the absence of regulatory
asset amortization, deferred purchased power and fuel costs, net of higher costs, in
accordance with the retail rate settlement, and lower depreciation due to lower
depreciation rates. These positive factors were partially offset by higher operations
and maintenance costs primarily related to generation, customer service, and benefit
costs.
Marketing and Trading Segment – Income from continuing operations decreased
approximately $4 million primarily due to lower realized margins on wholesale sales.
•
Real Estate Segment – Income from continuing operations increased approximately $7
million primarily due to increased parcel sales.
•
Other Segment – Income from continuing operations decreased approximately $21
million primarily due to an after-tax gain related to the sale of El Dorado’s limited
partnership interest in the Phoenix Suns recorded in the prior-year period.
Higher retail sales volumes due to customer growth,
excluding weather effects
13
8
Deferred purchased power and fuel costs, net of higher
costs, in accordance with the retail rate settlement
8
5
Miscellaneous items, net
2
1
Net increase in regulated electricity segment gross
margin
51
31
Marketing and trading segment gross margin:
Lower realized margins on wholesale sales primarily
due to lower unit margins and lower sales volumes
(6
)
(4
)
Miscellaneous items, net
(3
)
(1
)
Net decrease in marketing and trading segment
gross margin
(9
)
(5
)
Net increase in gross margin for regulated electricity
and marketing and trading segments
42
26
Higher real estate segment contribution primarily related to
increased parcel sales
12
7
Lower other income due to sale of limited partnership interest
in Phoenix Suns recorded in prior-year period
(35
)
(21
)
Higher operation and maintenance expense due to
generation, customer service and benefit costs
(15
)
(9
)
Depreciation and amortization decreases primarily due to:
Absence of regulatory asset amortization
10
6
Lower
depreciation rates (see Note 5) partially offset by higher
depreciable assets
7
4
Higher interest expense, net of capitalized financing
costs, primarily due to higher debt balances
and interest rates
(6
)
(4
)
Miscellaneous items, net
6
2
Net increase in income from continuing operations
$
21
11
Discontinued operations primarily related to the pending
sale of Silverhawk (see discussion above)
(57
)
Net decrease in net income
$
(46
)
Regulated Electricity Segment Revenues
Regulated electricity segment revenues were $60 million higher for the three months ended June30, 2005 compared with the prior-year period primarily as a result of:
a $28 million increase in retail revenues due to a price increase
effective April 1, 2005;
•
an $18 million increase in retail revenues related to customer growth,
excluding weather effects;
•
a $12 million increase in Off-System Sales primarily due to sales
previously reported in the marketing and trading segment now classified as sales in the
regulated electricity segment in accordance with the retail rate settlement; and
•
a $2 million increase due to miscellaneous factors.
Marketing and Trading Segment Revenues
Marketing and trading segment revenues were $39 million lower for the three months ended June30, 2005 compared with the prior-year period primarily as a result of:
•
a $25 million decrease in revenues from Off-System Sales primarily due
to lower sales volumes and sales previously reported in the marketing and trading
segment now classified as sales in the regulated electricity segment in accordance with
the retail rate settlement;
•
a $7 million decrease in energy trading revenues on realized sales of
electricity primarily due to lower delivered electricity prices and lower sales
volumes;
•
a $5 million decrease from lower volumes and prices for competitive
retail sales in California; and
•
a $2 million decrease on future mark-to-market gains due to higher price volatility.
Real Estate Revenues
Real estate revenues were $19 million higher for the three months ended June 30, 2005 compared
with the prior-year period primarily due to increased parcel sales.
Operating Results – Six-month period ended June 30, 2005 compared with six-month period ended June30, 2004
Our consolidated net income for the six months ended June 30, 2005 was $51 million compared
with $104 million for the prior-year period. The current year period net income included a loss
from discontinued operations of $64 million which is primarily related to the pending sale and
operations of Silverhawk (see discussion above). Income from continuing operations increased $10
million in the period-to-period comparison reflecting the following changes in earnings by segment:
•
Regulated Electricity Segment – Income from continuing operations increased
approximately $28 million primarily due to a retail price increase effective April 1,2005, higher retail sales volumes due to customer growth, the absence of regulatory
asset amortization, deferred purchased power and fuel costs, net of higher costs, in
accordance with the retail rate settlement, and lower depreciation due to lower
depreciation rates. These positive factors were partially offset by higher
operations and maintenance costs primarily related to generation, customer service,
and benefit costs, and higher property taxes due to increased plant in service.
•
Marketing and Trading Segment – Income from continuing operations decreased
approximately $11 million primarily due to lower realized margins on wholesale sales
and competitive retail sales in California.
•
Real Estate Segment – Income from continuing operations increased approximately $14
million primarily due to increased parcel sales.
•
Other Segment – Income from continuing operations decreased approximately $21
million primarily due to an after-tax gain related to the sale of El Dorado’s limited
partnership interest in the Phoenix Suns recorded in the prior-year period.
Higher retail sales volumes due to customer growth,
excluding weather effects
20
12
Deferred purchased power and fuel costs, net of higher
costs, in accordance with the retail rate settlement
15
9
Miscellaneous items, net
(1
)
(1
)
Net increase in regulated electricity segment gross margin
62
37
Marketing and trading segment gross margin:
Lower unit margins on competitive retail sales in California
(7
)
(4
)
Lower realized margins on wholesale sales primarily
due to lower unit margins and lower sales volumes
(5
)
(3
)
Miscellaneous items, net
1
—
Net decrease in marketing and trading segment
gross margin
(11
)
(7
)
Net increase in gross margin for regulated electricity
and marketing and trading segments
51
30
Higher real estate segment contribution primarily related to
increased parcel sales
24
14
Lower other income due to sale of limited partnership interest in
Phoenix Suns recorded in the prior-year period
(35
)
(21
)
Operations and maintenance increases primarily due to:
Generation costs, including planned maintenance
(11
)
(7
)
Customer service costs, including planned maintenance
(10
)
(6
)
Benefit costs
(8
)
(5
)
Miscellaneous items, net
(3
)
(2
)
Depreciation and amortization decreases primarily due to:
Absence of regulatory asset amortization
19
11
Lower
depreciation rates (see Note 5) partially offset by higher
depreciable assets
8
5
Higher property taxes due to increased plant in service
(7
)
(4
)
Miscellaneous items, net
(5
)
(5
)
Net increase in income from continuing operations
$
23
10
Discontinued operations primarily related to the pending
sale of Silverhawk (see discussion above)
(63
)
Net decrease in net income
$
(53
)
Regulated Electricity Segment Revenues
Regulated electricity segment revenues were $60 million higher for the six months ended June 30,2005 compared with the prior-year period primarily as a result of:
a $28 million increase in retail revenues related to customer growth,
excluding weather effects;
•
a $28 million increase in retail revenues due to a price increase
effective April 1, 2005;
•
a $12 million increase in Off-System Sales primarily due to sales
previously reported in the marketing and trading segment now classified as sales in the
regulated electricity segment in accordance with the retail rate settlement;
•
a $9 million decrease in retail revenues related to milder weather; and
•
a $1 million increase due to miscellaneous factors.
Marketing and Trading Segment Revenues
Marketing and trading segment revenues were $38 million lower for the six months ended June30, 2005 compared with the prior-year period primarily as a result of:
•
a $19 million decrease in revenues from Off-System Sales primarily due
to lower sales volumes, prices and sales previously reported in the marketing and
trading segment now classified as sales in the regulated electricity segment in
accordance with the retail rate settlement;
•
a $14 million decrease from lower volumes and prices on competitive
retail sales in California; and
•
a $5 million decrease in energy trading revenues on realized sales of
electricity primarily due to lower delivered electricity prices and lower volumes.
Real Estate Revenues
Real estate revenues were $40 million higher for the six months ended June 30, 2005 compared
with the prior-year period primarily due to increased parcel sales.
LIQUIDITY AND CAPITAL RESOURCES
Capital Needs and Resources – Pinnacle West Consolidated
Capital Expenditure Requirements
The following table summarizes the actual capital expenditures for the six months ended June30, 2005 and estimated capital expenditures for the next three years.
As discussed in Note 5 under “APS General Rate Case,” as part of the ACC’s
order in APS’ general rate case, APS received rate base treatment of the PWEC Dedicated
Assets. The estimated capital expenditures related to the PWEC Dedicated Assets are
reflected in APS generation for the years 2005, 2006 and 2007.
(b)
The six months ended June 30, 2005 includes $190 million for the acquisition of
the Sundance Plant. See Note 4 for a discussion of APS’ acquisition of the Sundance
Plant.
(c)
Primarily information systems and facilities projects.
(d)
Consists primarily of capital expenditures for land development and retail and
office building construction reflected in “Real estate investments” on the Condensed
Consolidated Statements of Cash Flows.
Delivery capital expenditures are comprised of T&D 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 T&D lines and substations, line
extensions to new residential and commercial developments and upgrades to customer information
systems. Major transmission projects are driven by strong regional customer growth. APS will
begin major projects each year for the next several years, and expects to spend about $200 million
on major transmission projects during the 2005 to 2007 time frame. These amounts are included in
“APS-Delivery” in the table above. Completion of these projects is expected by at least 2008.
Generation capital expenditures are comprised of various improvements to APS’ existing fossil
and nuclear plants, the acquisition of the Sundance Plant and the replacement of Palo Verde steam
generators (see below). Examples of the types of projects included in this category are additions,
upgrades and capital replacements of various power plant equipment such as turbines, boilers and
environmental equipment. Generation also includes nuclear fuel expenditures of approximately $30
million annually for 2005 through 2007.
Replacement of the steam generators in Palo Verde Unit 2 was completed during the fall outage
of 2003 at a cost to APS of approximately $70 million. The Palo Verde owners have approved the
manufacture of two additional sets of steam generators. These generators will be installed in Unit
1 (scheduled completion in the fall of 2005) and Unit 3 (scheduled completion in the fall of 2007).
Our portion of steam generator expenditures for Units 1 and 3 is approximately $140 million, which
will be spent through 2008. In 2005 through 2007, approximately $95 million of the costs for steam
generator replacements at Units 1 and 3 are included in the generation capital expenditures table
above and will be funded with internally-generated cash or external financings.
Contractual Obligations
Our future contractual obligations have not changed materially from the amounts disclosed in
Part II, Item 7 of the 2004 Form 10-K with the exception
of our aggregate:
•
purchased power and fuel commitments, which increased from approximately $855
million at December 31, 2004 to $1.0 billion at June 30,2005 primarily due to increased commitment for the years
2005 through 2007; and
•
nuclear decommissioning funding requirements, which increased
from approximately $201 million at December 31, 2004 to
$386 million at June 30, 2005 for the years 2005 and thereafter.
See Note 4 for a list of payments due on total long-term debt and capitalized lease
requirements.
Off-Balance Sheet Arrangements
In 1986, APS entered into agreements with three separate VIE lessors in order to sell and
lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in
accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly,
do not consolidate them.
APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of
certain events that APS does not consider to be reasonably likely to occur. Under certain
circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde
or the occurrence of specified nuclear events), APS would be required to assume the debt associated
with the transactions, make specified payments to the equity participants, and take title to the
leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If
such an event had occurred as of June 30, 2005, APS would have been required to assume
approximately $245 million of debt and pay the equity participants approximately $191 million.
Guarantees and Letters of Credit
We and certain of our subsidiaries have issued guarantees and letters of credit in support of
our unregulated businesses. We have also obtained surety bonds on behalf of APS Energy Services.
We have not recorded any liability on our Condensed Consolidated Balance Sheets with respect to
these obligations. We generally agree to indemnification provisions related to liabilities arising
from or related to certain of our agreements, with limited exceptions depending on the particular
agreement. See Note 15 for additional information regarding guarantees and letters of credit.
See “Pinnacle West Energy” below for information regarding Pinnacle West’s guarantee of $500
million of Pinnacle West Energy’s debt obligations.
The
ratings of securities of Pinnacle West and APS as of August 8, 2005 are shown below and
are considered to be “investment-grade” ratings. The ratings reflect the respective views of the
rating agencies, from which an explanation of the significance of their ratings may be obtained.
There is no assurance that these ratings will continue for any given period of time. The ratings
may be revised or withdrawn entirely by the rating agencies, if, in their respective judgments,
circumstances so warrant. Any downward revision or withdrawal may adversely affect the market
price of Pinnacle West’s or APS’ securities and serve to increase those companies’ cost of and
access to capital. It may also require additional collateral related to certain derivative
instruments (see Note 10).
Moody’s
Standard & Poor’s
Pinnacle West
Senior unsecured
Baa2
BBB-
Commercial paper
P-2
A-2
Outlook
Stable
Stable
APS
Senior unsecured
Baa1
BBB
Secured lease
obligation bonds
Baa1
BBB
Commercial paper
P-2
A-2
Outlook
Stable
Stable
Debt Provisions
Pinnacle West’s and APS’ debt covenants related to their respective bank financing
arrangements include a debt-to-total-capitalization ratio and 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. These covenants require that the ratio of debt to total
capitalization cannot exceed 65% for the Company and for APS. At June 30, 2005, the ratio was
approximately 53% for Pinnacle West and 51% for APS. The provisions regarding interest coverage
require a minimum cash coverage of two times the interest requirements for each of the Company and
APS. The interest coverage is approximately 4 times under the Company’s and APS’ bank financing
agreements. 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.
Neither Pinnacle West’s nor APS’ financing agreements contain “ratings triggers” that would
result in an acceleration of the required interest and principal payments in the event of a ratings
downgrade. However, in the event of a ratings downgrade, Pinnacle West and/or APS may be subject
to increased interest costs under certain financing agreements.
All of Pinnacle West’s bank agreements contain “cross-default” provisions that would result in
defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or
APS were to default under other 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 other agreements. Pinnacle West’s and APS’ credit
agreements generally contain provisions under which the lenders could refuse to advance loans in
the event of a material adverse change in financial condition or financial prospects, except that
Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings
equal to outstanding commercial paper amounts.
See Note 4 for further discussions.
Capital Needs and Resources — By Company
Pinnacle West (Parent Company)
Our primary cash needs are for dividends to our shareholders; interest payments and optional
and mandatory repayments of principal on our long-term debt. The level of our common dividends and
future dividend growth will be dependent on a number of factors including, but not limited to,
payout ratio trends, free cash flow and financial market conditions.
Our primary sources of cash are dividends from APS, external financings and cash distributions
from our other subsidiaries, primarily SunCor. We expect SunCor to make cash distributions to the
parent company of approximately $80 to $100 million in 2005 based on anticipated asset sales
activities. As discussed in Note 5 under “ACC Financing Order,” APS must maintain a common equity
ratio of at least 40% and may not pay common dividends if the payment would reduce its common
equity below that threshold. As defined in the Financing Order, common equity ratio is common
equity divided by common equity plus long-term debt, including current maturities of long-term
debt. At June 30, 2005, APS’ common equity ratio as defined was approximately 48%.
Pinnacle West sponsors a qualified pension plan for the employees of Pinnacle West and our
subsidiaries. We contribute at least the minimum amount required under IRS regulations, but no
more than the maximum tax-deductible amount. The minimum required funding takes into consideration
the value of the fund assets and our pension obligation. We contributed $35 million in 2004. APS
and other subsidiaries fund their share of the pension contribution, of which APS represents
approximately 92% of the total funding amounts described above. The assets in the plan are
comprised of common stocks, bonds and real estate. Future year contribution amounts are dependent
on fund performance and fund valuation assumptions. Our minimum required pension contribution in
2005 is approximately $53 million. Of this amount, we have contributed approximately $27 million
through July 2005. The contribution to be made to other post retirement benefit plans in 2005 is
estimated to be approximately $37 million. Of this amount, we contributed approximately $18
million through July 2005. APS’ share is approximately 92% of both plans.
On May 2, 2005, Pinnacle West redeemed at par all of its $165 million Floating Rate Senior
Notes due November 1, 2005. The Company used cash on hand to redeem the notes.
On May 2, 2005, Pinnacle West issued 6,095,000 shares of its common stock at an offering price
of $42 per share, resulting in net proceeds of approximately $248 million. Pinnacle West used the
net proceeds for general corporate purposes, including making capital contributions to APS, which,
in turn, used 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
On July 13, 2005, the Pinnacle West Board of Directors declared a quarterly dividend of $0.475
per share of common stock, payable on September 1, 2005, to shareholders of record on August 1,2005.
APS
APS’ capital requirements consist primarily of capital expenditures and optional and mandatory
redemptions of long-term debt. See “ACC Financing Order” in Note 5 for a discussion of the $500
million loan from APS to Pinnacle West Energy authorized by the ACC pursuant to the Financing
Order. This loan was repaid on April 11, 2005.
APS pays for its capital requirements with cash from operations and, to the extent necessary,
external financings. APS has historically paid for its dividends to Pinnacle West with cash from
operations. See “Pinnacle West (Parent Company)” above for a discussion of the common equity ratio
that APS must maintain in order to pay dividends to Pinnacle West.
On January 15, 2005, APS repaid its $100 million 6.25% Notes due 2005. APS used cash on hand
to redeem these notes.
On March 1, 2005, Maricopa County, Arizona Pollution Control Corporation issued $164 million
of variable interest rate pollution control bonds, 2005 Series A-E, due 2029. The bonds were
issued to refinance $164 million of outstanding pollution control bonds. The Series A-E bonds are
payable solely from revenues obtained from APS pursuant to a loan agreement between APS and
Maricopa County, Arizona Pollution Control Corporation. These bonds are classified as long-term
debt on our Condensed Consolidated Balance Sheets.
On August 1, 2005, APS repaid $300 million of its 7.625% Notes due 2005. APS used cash on
hand to repay these notes.
Although provisions in APS’ articles of incorporation and ACC financing orders establish
maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these
provisions to limit its ability to meet its capital requirements.
See
“Deferred Purchased Power and Fuel Costs” above and
“APS General Rate Case” in Note 5 for information regarding the PSA approved
by the ACC.
Pinnacle West Energy
Pinnacle West Energy expects minimal capital expenditures over the next three years. See the
capital expenditures table above for actual capital expenditures during the six months ended June30, 2005 and projected capital expenditures for the next three years (the estimated capital
expenditures related to the PWEC Dedicated Assets are reflected in APS).
See “ACC Financing Order” in Note 5 for a discussion of the $500 million loan from APS to
Pinnacle West Energy authorized by the ACC pursuant to the Financing Order. On April 11, 2005
Pinnacle West Energy issued $500 million Floating Rate Senior Notes due April 1, 2007. Pinnacle
West has unconditionally guaranteed these notes. Pinnacle West Energy used the proceeds of this
issuance to repay the APS loan. Pinnacle West Energy intends to repay the Floating Rate Senior
Note with $500 million expected to be received from APS in connection with Pinnacle West Energy’s
transfer of the PWEC Dedicated Assets to APS.
See Note 17 of Notes to Condensed Consolidated Financial Statements above for a discussion of
the pending sale of our 75% ownership interest in Silverhawk.
Other Subsidiaries
During the past three years, SunCor funded its cash requirements with cash from operations and
its own external financings. SunCor’s capital needs consist primarily of capital expenditures for
land development and retail and office building construction. See the capital expenditures table
above for actual capital expenditures during the six months ended June 30, 2005 and projected
capital expenditures for the next three years. SunCor expects to fund its capital requirements
with cash from operations and external financings.
We expect SunCor to make cash distributions to the parent company of approximately $80 to $100
million in 2005 based on anticipated asset sales activities.
El Dorado expects minimal capital requirements over the next three years and intends to focus
on prudently realizing the value of its existing investments.
APS Energy Services expects minimal capital expenditures over the next three years.
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with GAAP, management must often make
estimates and assumptions that affect the reported amounts of assets, liabilities, revenues,
expenses and related disclosures at the date of the financial statements and during the reporting
period. Some of those judgments can be subjective and complex, and actual results could differ
from those estimates. Our most critical accounting policies include the impacts of regulatory
accounting and the determination of the appropriate accounting for our pension and other
postretirement benefits and derivatives accounting. There have been no changes to our critical
accounting policies since our 2004 Form 10-K. See “Critical Accounting Policies” in Item 7 of the
2004 Form 10-K for further details about our critical accounting policies.
PINNACLE WEST CONSOLIDATED – FACTORS AFFECTING
OUR FINANCIAL OUTLOOK
Factors Affecting Operating Revenues, Purchased Power and Fuel Costs
General Electric operating revenues are derived from sales of electricity in regulated retail
markets in Arizona and from competitive retail and wholesale power markets in the western United
States. These revenues are affected by electricity sales volumes related to customer mix, customer
growth and average usage per customer as well as electricity prices and variations in weather from
period to period. Competitive sales of energy and energy-related products and services are made by
APS Energy Services in western states that have opened to competition.
Customer and Sales Growth The customer and sales growth referred to in this paragraph applies
to Native Load customers and sales to them. Customer growth in APS’ service territory averaged
about 3.4% a year for the three years 2002 through 2004; we currently expect customer growth to
average about 3.8% per year from 2005 to 2007. We currently estimate that total retail electricity
sales in kilowatt-hours will grow 5.0% on average, from 2005 through 2007, before the effects of
weather variations. Customer growth for the six-month period ended June 30, 2005 compared with the
prior year period was 4.1%.
Actual sales growth, excluding weather-related variations, may differ from our projections as
a result of numerous factors, such as economic conditions, customer growth and usage patterns. 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.
Retail Rate Matters See “APS General Rate Case” in Note 5 for a discussion of the ACC’s order
in APS’ general rate case and “Power Supply Adjuster” for information regarding APS’ application to
the ACC requesting recovery of $100 million in deferred fuel and purchased power costs under the
PSA. APS expects to file another general rate case in late 2005.
Purchased Power and Fuel Costs See “APS General Rate Case” in Note 5 for information
regarding the PSA approved by the ACC. Purchased power and fuel costs
are impacted by our electricity sales volumes, existing contracts for purchased power and
generation fuel, our power plant performance, transmission availability or constraints, prevailing
market prices, new generating plants being placed in service and our hedging program for managing
such costs. See “Natural Gas Supply” in Note 12 for more information on fuel costs.
Wholesale Power Market Conditions The marketing and trading division focuses primarily on
managing APS’ purchased power and fuel risks in connection with its costs of serving retail
customer demand. The marketing and trading division, subject to specified parameters, markets,
hedges and trades in electricity, fuels and emission allowances and credits. Our future earnings
will be affected by the strength or weakness of the wholesale power market.
Other Factors Affecting Financial Results
Operations and Maintenance Expenses Operations and maintenance expenses are impacted by
growth, power plant additions and operations, inflation, outages, higher trending pension and other
postretirement benefit costs and other factors.
Depreciation and Amortization Expenses Depreciation and amortization expenses are impacted by
net additions to utility plant and other property, which includes generation construction
or
acquisition, changes in depreciation and amortization rates (see
Note 5), and changes in regulatory asset amortization. See Note 17 for information on the
pending sale of Silverhawk. See Note 4 for information on APS’ acquisition of the Sundance Plant
in 2005 and “Requests for Proposals” in Part II,
Item 5 of this report for more information on requests for proposals to acquire additional long-term resources in 2006 and 2007.
Property Taxes Taxes other than income taxes consist primarily of property taxes, which are
affected by tax rates and the value of property in-service and under construction. The average
property tax rate for APS, which currently owns the majority of our property, was 9.2% of assessed
value for 2004 and 9.3% for 2003. We expect property taxes to increase as new power plants, the
acquisition of the Sundance Plant and our additions to transmission and distribution facilities
phase-in to the property tax base.
Interest Expense Interest expense is affected by the amount of debt outstanding and the
interest rates on that debt. The primary factors affecting borrowing levels in the next several
years are expected to be our capital requirements and our internally generated cash flow.
Capitalized interest offsets a portion of interest expense while capital projects are under
construction. We stop accruing capitalized interest on a project when it is placed in commercial
operation. We placed new power plants in commercial operation in 2001, 2002, 2003 and 2004.
Interest expense is also affected by interest rates on variable-rate debt and interest rates on the
refinancing of the Company’s future liquidity needs.
Retail Competition Although
some very limited retail competition existed in APS’ service area in 1999 and 2000, there are
currently no active retail competitors providing unbundled energy or other utility services to APS’
customers. As a result, we cannot predict when, and the extent to which, additional competitors
will re-enter APS’ service territory.
Subsidiaries In the case of SunCor, efforts to accelerate asset sales activities in 2004 were
successful. A portion of these sales have been, and additional amounts may be required to be,
reported as discontinued operations on our Condensed Consolidated Statements of Income. SunCor’s
net income was $45 million in 2004. See Note 17 for further discussion. We anticipate SunCor’s
earnings contributions in 2005 to be approximately $50 million after income taxes.
El Dorado’s historical results are not indicative of future performance.
General Our financial results may be affected by a number of broad factors. See
“Forward-Looking Statements” for further information on such factors, which may cause our actual
future results to differ from those we currently seek or anticipate.
Market Risks
Our operations include managing market risks related to changes in interest rates, commodity
prices and investments held by our nuclear decommissioning trust fund.
Our major financial market risk exposure is to changing interest rates. Changing interest
rates will affect interest paid on variable-rate debt and interest earned by our nuclear
decommissioning trust fund. Our policy is to manage interest rates through the use of a
combination of fixed-rate and floating-rate debt.
Commodity Price Risk
We are exposed to the impact of market fluctuations in the commodity price and transportation
costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with
these market fluctuations by utilizing various commodity instruments that qualify as derivatives,
including exchange-traded futures and options and over-the-counter forwards, options and swaps.
Our ERMC, consisting of officers and key management personnel, oversees company-wide energy risk
management activities and monitors the results of marketing and trading activities to ensure
compliance with our stated energy risk management and trading policies. As part of our risk
management program, we use such instruments to hedge purchases and sales of electricity, fuels and
emissions allowances and credits. The changes in market value of such contracts have a high
correlation to price changes in the hedged commodities. In addition, subject to specified risk
parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit
from market price movements.
The mark-to-market value of derivative instruments related to our risk management and trading
activities are presented in two categories consistent with our business segments:
•
Regulated Electricity – non-trading derivative instruments that hedge our purchases
and sales of electricity and fuel for APS’ Native Load requirements of our regulated
electricity business segment; and
•
Marketing and Trading – non-trading and trading derivative instruments of our
competitive business segment.
The following tables show the pretax changes in mark-to-market of our non-trading and trading
derivative positions for the six months ended June 30, 2005 and 2004 (dollars in millions):
Mark-to-market of net positions
at beginning of period
$
33
$
107
$
—
$
69
Change in mark-to-market gains
for future period deliveries
4
12
11
13
Changes in cash flow hedges
recorded in OCI
84
(9
)
48
25
Ineffective portion of changes
in fair value
12
—
1
1
Mark-to-market (gains) losses
realized during the period
(7
)
41
3
(10
)
Mark-to-market of net positions
at end of period
$
126
$
151
$
63
$
98
The tables below show the fair value of maturities of our non-trading and trading derivative
contracts (dollars in millions) at June 30, 2005 by maturities and by the type of valuation that is
performed to calculate the fair values. See Note 1, “Derivative Accounting,” in Item 8 of our 2004
Form 10-K for more discussion of our valuation methods.
Regulated Electricity
Total
fair
Source of Fair Value
2005
2006
2007
value
Prices actively quoted
$
39
$
54
$
28
$
121
Prices provided by other external
sources
—
4
3
7
Prices based on models and other
valuation methods
(1
)
(1
)
—
(2
)
Total by maturity
$
38
$
57
$
31
$
126
Marketing and
Trading
Total
fair
Source of Fair Value
2005
2006
2007
2008
2009
value
Prices actively quoted
$
28
$
—
$
—
$
—
$
—
$
28
Prices provided by
other external sources
—
66
83
41
(1
)
189
Prices based on models
and other valuation
methods
(5
)
(21
)
(30
)
(10
)
—
(66
)
Total by maturity
$
23
$
45
$
53
$
31
$
(1
)
$
151
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
These contracts are primarily structured sales activities hedged with a
portfolio of forward purchases that protects the economic value of the sales
transactions.
(b)
These contracts are hedges of our forecasted purchases of natural gas and
electricity. The impact of these hypothetical price movements would substantially
offset the impact that these same price movements would have on the physical exposures
being hedged.
Credit Risk
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We
have risk management and trading contracts with many counterparties, including one counterparty for
which a worst case exposure represents approximately 16% of Pinnacle West’s $620 million of risk
management and trading assets as of June 30, 2005. See Note 1, “Derivative Accounting” in Item 8
of our 2004 Form 10-K for a discussion of our credit valuation adjustment policy. See Note 10 for
further discussion of credit risk.
ARIZONA PUBLIC SERVICE COMPANY – RESULTS OF OPERATIONS
General
Throughout the following explanations of our results of operations, we refer to “gross
margin.” Gross margin refers to electric operating revenues less purchased power and fuel costs.
Gross margin is a “non-GAAP financial measure,” as defined in accordance with SEC rules. Exhibit
99.4 reconciles this non-GAAP financial measure to operating income, which is the most directly
comparable financial measure calculated and presented in accordance with GAAP. We view gross
margin as an important performance measure of the core profitability of our operations. This
measure is a key component of our internal financial reporting and is used by our management in
analyzing our business. We believe that investors benefit from having access to the same financial
measures that our management uses. In addition, we have reclassified certain prior-period amounts
to conform to our current-period presentation.
Deferred Purchased Power and Fuel Costs
APS’ retail rate case settlement became effective April 1, 2005. As part of the settlement,
the ACC approved a 4.2% annual retail rate increase and a PSA that provides mechanisms for
adjusting rates to reflect variations in fuel and purchased power costs. In accordance with the
PSA, APS defers for future rate recovery 90% of the difference between actual purchased power and
fuel costs and the amount for such costs currently included in base rates. As of June 30, 2005,
APS had deferred $34 million of pretax purchased power and fuel costs.
Operating Results – Three-month period ended June 30, 2005 compared with three-month period ended
June 30, 2004
APS’ net income for the three months ended June 30, 2005 was $64 million compared with $55
million for the prior-year period. The $9 million increase in the period-to-period comparison is
due to a retail price increase effective April 1, 2005, higher retail sales volumes due to customer
growth, the absence of regulatory asset amortization, and lower depreciation due to lower
depreciation rates. These positive factors were partially offset by higher purchased power and
fuel costs, net of deferred costs, in accordance with the retail rate settlement, higher operations
and maintenance costs primarily related to generation, customer service, and benefit costs and
lower realized margins on wholesale sales.
Higher retail sales volumes due to customer growth,
excluding weather effects
13
8
Higher purchased power and fuel costs, net of deferred
costs, in accordance with the retail rate settlement
(23
)
(14
)
Higher margins on energy trading primarily due to higher
wholesale electricity prices
3
2
Miscellaneous items, net
1
—
Net increase in gross margin
22
13
Higher operation and maintenance expense due to
generation, customer service and benefit costs
(11
)
(7
)
Depreciation and amortization decreases primarily due to:
Absence of regulatory asset amortization
10
6
Lower
depreciation rates (see note 5) partially offset by higher
depreciable assets
2
1
Higher interest expense, net of capitalized financing
costs, primarily due to higher debt balances
and interest rates
(3
)
(2
)
Miscellaneous items, net
(1
)
(2
)
Net increase in net income
$
19
$
9
Regulated Electricity Revenues
Regulated electricity revenues were $58 million higher for the three months ended June 30,2005 compared with the prior-year period primarily as a result of:
•
a $28 million increase in retail revenues due to a price increase
effective April 1, 2005;
•
an $18 million increase in retail revenues related to customer growth,
excluding weather effects; and
•
a $12 million increase in Off-System Sales primarily due to sales
previously reported in marketing and trading now classified as sales in regulated
electricity in accordance with the retail rate settlement.
Marketing and Trading Revenues
Marketing and trading revenues were $39 million lower for the three months ended June 30, 2005
compared with the prior-year period primarily as a result of:
a $25 million decrease in revenues from Off-System Sales primarily due
to lower sales volumes and sales previously reported in marketing and trading now
classified as sales in the regulated electricity in accordance with the retail rate
settlement;
•
a $15 million decrease in energy trading revenues on realized sales of
electricity primarily due to lower delivered electricity prices and lower sales
volumes; and
•
a $1 million increase on future mark-to-market gains due to higher price
volatility.
Operating Results – Six-month period ended June 30, 2005 compared with six-month period ended June30, 2004
APS’ net income for the six months ended June 30, 2005 was $91 million compared with $89
million for the prior-year period. The $2 million increase in the period-to-period comparison is
due to a retail price increase effective April 1, 2005, higher retail sales volumes due to customer
growth, the absence of regulatory asset amortization, and lower depreciation due to lower
depreciation rates. These positive factors were partially offset by higher purchased power and
fuel costs, net of deferred costs, in accordance with the retail rate settlement, higher operations
and maintenance costs primarily related to generation, customer service, and benefit costs, lower
realized margins on wholesale sales, and higher property taxes due to increased plant in service.
Additional details on the major factors that increased (decreased) net income are contained in the
following table (dollars in millions):
Regulated electricity revenues were $56 million higher for the six months ended June 30, 2005
compared with the prior-year period primarily as a result of:
•
a $28 million increase in retail revenues related to customer growth,
excluding weather effects;
•
a $28 million increase in retail revenues due to a price increase
effective April 1, 2005;
•
a $12 million increase in Off-System Sales due to increased volumes for
plants dedicated to APS customers and sales previously reported in marketing and
trading now classified as sales in regulated electricity in accordance with the retail
rate settlement;
•
a $9 million decrease in retail revenues related to milder weather; and
•
a $3 million decrease due to miscellaneous factors.
Marketing and Trading Revenues
Marketing and trading revenues were $37 million lower for the six months ended June 30, 2005
compared with the prior-year period primarily as a result of:
•
an $18 million decrease in revenues from Off-System Sales primarily due
to lower sales volumes, prices, and sales previously reported in marketing and trading
now classified as sales in regulated electricity in accordance with the retail rate
settlement;
•
a $17 million decrease in energy trading revenues on realized sales of
electricity primarily due to lower delivered electricity prices and lower volumes; and
•
a $2 million decrease due to miscellaneous factors.
ARIZONA PUBLIC SERVICE COMPANY – LIQUIDITY AND CAPITAL RESOURCES
Contractual Obligations
APS’ future contractual obligations have not changed materially from the amounts disclosed in
Part II, Item 7 of the 2004 Form 10-K with the exception of our aggregate:
•
purchased power and fuel commitments, which increased from
approximately $948 million at December 31, 2004 to
$1.1 billion at June 30, 2005 primarily due to increased
commitments for the years 2005 through 2007; and
•
nuclear decommissioning funding requirements which increased
from approximately $201 million at December 31, 2004 to
$386 million at June 30, 2005 for the years 2005 and thereafter.
See Note S-1 for a list of APS’ payments due on total
long-term debt and capitalized lease requirements.
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 Exhibits 99.1 and 99.2 to this report, these
factors include, but are not limited to:
•
state and federal regulatory and legislative decisions and actions, including by the
ACC and the FERC;
•
the ongoing restructuring of the electric industry, including the introduction of
retail electric competition in Arizona and decisions impacting wholesale competition;
•
the outcome of regulatory, legislative and judicial proceedings relating to the
restructuring;
•
market prices for electricity and natural gas;
•
power plant performance and outages;
•
transmission outages and constraints;
•
weather variations affecting local and regional customer energy usage;
•
customer growth and energy usage;
•
regional economic and market conditions, including the results of litigation and
other proceedings resulting from the California energy situation, volatile purchased
power and fuel 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;
•
the uncertainty that current credit ratings will remain in effect for any given
period of time;
•
our ability to compete successfully outside traditional regulated markets (including
the wholesale market);
•
the performance of our marketing and trading activities due to volatile market
liquidity and any deteriorating counterparty credit and the use of derivative contracts
in our business (including the interpretation of the subjective and complex accounting
rules related to these contracts);
•
changes in accounting principles generally accepted in the United States of America
and the interpretation of those principles;
•
the performance of the stock market and the changing interest rate environment,
which affect the amount of required contributions to Pinnacle West’s pension plan and
APS’ nuclear decommissioning trust funds, as well as the reported costs of providing
pension and other postretirement benefits;
•
technological developments in the electric industry;
•
the strength of the real estate market in SunCor’s market areas, which include
Arizona, Idaho, New Mexico and Utah; and
•
other uncertainties, all of which are difficult to predict and many of which are
beyond the control of Pinnacle West and APS.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK
See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” in Item 2 above for
a discussion of quantitative and qualitative disclosures about market risks.
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 June 30, 2005. Based on that evaluation, Pinnacle West’s Chief
Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s
disclosure controls and procedures were effective.
APS’ management, with the participation of APS’ Chief Executive Officer and Chief Financial
Officer, have evaluated the effectiveness of APS’ disclosure controls and procedures as of June 30,2005. Based on that evaluation, APS’ Chief Executive Officer and Chief Financial Officer have
concluded that, as of that date, APS’ disclosure controls and procedures were effective.
(b) 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 June 30, 2005 that materially affected, or is reasonably likely to
materially affect, Pinnacle West’s or APS’ internal control over financial reporting.
See Note 12 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this
report in regard to pending or threatened litigation or other disputes.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Directors
At our Annual Meeting of Shareholders held on May 18, 2005, the following persons were elected
as directors:
Class II (Term to expire at
Abstentions and
2008 Annual Meeting)
Votes For
Votes Against
Broker Non-Votes
Edward N. Basha, Jr.
77,333,734
1,359,058
N/A
Michael L. Gallagher
70,656,769
8,036,023
N/A
Bruce J. Nordstrom
77,456,120
1,236,672
N/A
William J. Post
76,929,393
1,763,399
N/A
Continuing Directors
The terms of Jack E. Davis, Pamela Grant, Martha O. Hesse, and William S. Jamieson, Jr. will
expire in 2006. The terms of Roy A. Herberger, Jr., Humberto S. Lopez, Kathryn L. Munro, and
William L. Stewart will expire in 2007.
Independent Auditors
At the same meeting, a proposal for the ratification of the selection of Deloitte & Touche LLP
as independent Auditors of the Company was submitted to the shareholders, and the voting was as
follows:
Proposal for the ratification
Abstentions and
of Deloitte & Touche LLP
Votes For
Votes Against
Broker Non-Votes
75,880,147
2,031,585
781,060
Item 5. OTHER INFORMATION
Construction and Financing Programs
See “Liquidity and Capital Resources” in Part I, Item 2 of this report for a discussion of
construction and financing programs of the Company and its subsidiaries.
See Note 5 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this
report for a discussion of regulatory developments.
In connection with the FERC proceeding under which APS received
approval to acquire the Sundance Plant, APS committed to an independent market monitoring plan that
provides for an independent expert to monitor APS’ generation dispatch and operation of its
transmission system and report to the FERC any potentially anti-competitive conduct. The plan took
effect upon closing of the transaction and will continue in effect until the FERC approves a
regional market monitoring plan or five years, whichever is earlier.
Environmental Matters
See “Environmental Matters — Superfund” in Note 12 of Notes to Condensed Consolidated
Financial Statements in Part I, Item 1 of this report for a discussion of a Superfund site.
Regional Haze Rules
On June 15, 2005, EPA issued the Clean Air Visibility Rule, which amends the 1999 regional
haze rules by providing guidelines, known as the BART guidelines, for states to use in determining
which facilities must install controls and the type of controls the facilities must use. See
“Environmental Matters — Regional Haze Rules” in
Part I, Item 1 of the 2004 Form 10-K. The Company is
currently evaluating the potential impact of this rule.
On
August 1, 2005, the EPA proposed a rule to, among other things, revise a previously-adopted
rule that would have allowed nine western states and tribes to follow a regional haze
implementation plan for “Class I Areas” different from that provided for in the Clean
Air Visibility Rule. See “EPA Environmental Regulation -
Regional Haze Rules” in Part I, Item 1 of the 2004 Form 10-K for additional information
about the previously-adopted rule. The Company is currently evaluating the impact of the proposed
rule.
Navajo Nation Environmental Issues
On October 16, 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 Nation Air Pollution Prevention and Control Act, the
Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively, the Navajo
Acts). See “Environmental Matters — Navajo Nation
Environmental Issues”, in Part I, Item 1 of the
2004 Form 10-K. On May 18, 2005, APS, Salt River Project and the Navajo Nation executed a Voluntary
Compliance Agreement (“VCA”) to resolve their disputes regarding the Navajo Nation Air Pollution
Prevention and Control Act for the Four Corners Power Plant and the Navajo Generating Station. The
fundamental premise of the VCA is that the Navajo Nation EPA may regulate air issues for the Four
Corners Power Plant only because the participants have agreed to submit to such regulation for the
term of the agreement and under certain circumstances. If EPA approves the Navajo Nation’s air
programs consistent with the VCA, APS would dismiss the pending litigation in the Navajo Nation
Supreme Court and would dismiss the pending litigation in the Navajo Nation District Court to the
extent the claims relate to the Clean Air Act. The Agreement does not address or resolve any
dispute relating to the other Navajo Acts.
The Four Corners region, in which the Four Corners Plant is located, has been experiencing
drought conditions. See “Water Supply” in Part I,
Item 1 of the 2004 Form 10-K. APS has signed an
agreement with area stakeholders to minimize the effect of the drought on the operations of the
plant in 2005. 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.
Maricopa County Environmental Issues
During the period from November 2004 through March 2005, the Maricopa County Air Quality
Department (“MCAQD”) issued a series of Notices of
Violation (“NOVs”) to APS’ West Phoenix Power
Plant that generally allege that the plant failed to comply with applicable permit requirements.
APS is currently engaged in discussions with MCAQD concerning the NOVs. We do not expect the
resolution of these matters to have a material adverse effect on our financial position, results of
operations, or cash flows.
On October 16, 2001, APS and other owners of electric transmission lines in the southwestern
U.S. filed with the FERC a request for a declaratory order confirming that their proposal to form
WestConnect RTO, LLC would satisfy the FERC’s requirements for the formation of an RTO. See
“Regulation and Competition — Wholesale — Regional Transmission Organizations” in Part I, Item 1 of
the 2004 Form 10-K. On July 1, 2005, FERC issued an order in response to a request from Bonneville
Power Administration and utilities in the Northwest, regarding Grid West, a proposed regional
organization for the Northwest region. In that order, FERC agreed that a regional organization for
the Northwest region would not need to satisfy all of the RTO requirements established in the
December 1999 order. APS is currently evaluating the impact of this order on its RTO initiative.
Federal Energy Legislation
On
August 8, 2005, the President signed the Energy Policy Act of
2005 into law. Due to its recent enactment and because many
provisions require implementing regulations, the Company is unable to
predict the impact of the Act on its operations.
Requests for Proposals
APS continually assesses its need for additional capacity resources to assure system
reliability. Under the terms of the 2004 Settlement Agreement, APS committed to seek proposals
from the competitive wholesale market for filling its future resource needs. The current
reliability RFP identifies the amount of capacity and energy needed to reliably meet expected
customer demands and sought proposals for at least 1,000 MW of new generating capacity for 2007 and beyond. Bid responses were submitted by July 18, 2005. Short-listed bidders will be notified
by August 30, 2005, and winning bidders will be notified in mid-October.
APS also has in process a renewable RFP seeking at least 100 MW of renewable capacity with a
capability of producing at least 250,000 MWH annually. In accordance with the terms of the 2004
Settlement Agreement, power must be deliverable to the APS transmission system and its pricing must
not exceed 125% of conventional resource alternatives. A final decision, which is expected in
mid-September 2005, is subject to ACC approval if an out-of-state provider is selected.
Certificate of William J. Post, Chief
Executive Officer, pursuant to Rule
13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended
31.2
Pinnacle West
Certificate of Donald E. Brandt, Chief
Financial Officer, pursuant to Rule
13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended
31.3
APS
Certificate of Jack E. Davis, Chief
Executive Officer, pursuant to Rule
13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended
31.4
APS
Certificate of Donald E. Brandt, Chief
Financial Officer, pursuant to Rule
13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended
32.1
Pinnacle West
Certification of Chief Executive Officer
and Chief Financial Officer, pursuant to 18
U.S.C. Section 1850, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of
2002
32.2
APS
Certification of Chief Executive Officer
and Chief Financial Officer, pursuant to 18
U.S.C. Section 1850, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of
2002
99.1
Pinnacle West
Pinnacle West Risk Factors
99.2
APS
APS Risk Factors
99.3
Pinnacle West
Reconciliation of Operating Income to Gross
Margin
Reconciliation of Operating Income to Gross
Margin
99.5
Pinnacle West
Purchase Agreement by and among Pinnacle
West Energy Corporation and GenWest, L.L.C.
and Nevada Power Company, dated June 21,2005
99.6
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.
In addition, the Company hereby incorporates the following Exhibits pursuant to Exchange Act
Rule 12b-32 and Regulation §229.10(d) by reference to the filings set forth below:
Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Certificate of William J. Post, Chief
Executive Officer, pursuant to Rule
13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended
31.2
Pinnacle West
Certificate of Donald E. Brandt, Chief
Financial Officer, pursuant to Rule
13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended
31.3
APS
Certificate of Jack E. Davis, Chief
Executive Officer, pursuant to Rule
13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended
31.4
APS
Certificate of Donald E. Brandt, Chief
Financial Officer, pursuant to Rule
13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended
32.1
Pinnacle West
Certification of Chief Executive Officer
and Chief Financial Officer, pursuant to 18
U.S.C. Section 1850, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of
2002
32.2
APS
Certification of Chief Executive Officer
and Chief Financial Officer, pursuant to 18
U.S.C. Section 1850, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of
2002
99.1
Pinnacle West
Pinnacle West Risk Factors
99.2
APS
APS Risk Factors
99.3
Pinnacle West
Reconciliation of Operating Income to Gross
Margin
Reconciliation of Operating Income to Gross
Margin
99.5
Pinnacle West
Purchase Agreement by and among Pinnacle
West Energy Corporation and GenWest, L.L.C.
and Nevada Power Company, dated June 21,2005
99.6
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.
In addition, the Company hereby incorporates the following Exhibits pursuant to Exchange Act
Rule 12b-32 and Regulation §229.10(d) by reference to the filings set forth below: