Document/ExhibitDescriptionPagesSize 1: 10-Q Quarterly Report HTML 544K
2: EX-10.1 Material Contract HTML 10K
3: EX-10.2 Material Contract HTML 9K
4: EX-10.3 Material Contract HTML 70K
5: EX-10.4 Material Contract HTML 68K
6: EX-12.1 Statement re: Computation of Ratios HTML 18K
7: EX-12.2 Statement re: Computation of Ratios HTML 19K
8: EX-12.3 Statement re: Computation of Ratios HTML 29K
9: EX-31.1 Certification per Sarbanes-Oxley Act (Section 302) HTML 14K
10: EX-31.2 Certification per Sarbanes-Oxley Act (Section 302) HTML 14K
11: EX-31.3 Certification per Sarbanes-Oxley Act (Section 302) HTML 14K
12: EX-31.4 Certification per Sarbanes-Oxley Act (Section 302) HTML 14K
13: EX-32.1 Certification per Sarbanes-Oxley Act (Section 906) HTML 11K
14: EX-32.2 Certification per Sarbanes-Oxley Act (Section 906) HTML 11K
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.
PINNACLE WEST CAPITAL CORPORATION
Yes þ
No o
ARIZONA PUBLIC SERVICE COMPANY
Yes þ
No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated
filer” in Rule 12b-2 of the Exchange Act.
PINNACLE WEST CAPITAL CORPORATION
Large accelerated filer þ Accelerated filer o Non-accelerated filer o
ARIZONA PUBLIC SERVICE COMPANY
Large accelerated filer o Accelerated filer o Non-accelerated filer þ
Indicate by check mark whether each registrant is a shell company (as defined in Exchange Act
Rule 12b-2).
PINNACLE WEST CAPITAL CORPORATION
Yes o
No þ
ARIZONA PUBLIC SERVICE COMPANY
Yes o
No þ
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 November 2,2007: 100,385,036
ARIZONA PUBLIC SERVICE COMPANY
Number of shares of common stock, $2.50
par value, outstanding as of November 2,2007: 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 and, where required, its subsidiaries.
Except as stated in the preceding sentence, neither registrant is filing any information that does
not relate to such registrant, and therefore makes no representation as to any such information.
ADEQ – Arizona Department of Environmental Quality
ALJ – Administrative Law Judge
APS – Arizona Public Service Company, a subsidiary of the Company
APSES – APS Energy Services Company, Inc., a subsidiary of the Company
Base Fuel Rate – the portion of APS’ retail base rates attributable to fuel and purchased power
costs
Cholla – Cholla Power Plant
Clean Air Act – Clean Air Act, as amended
Company – Pinnacle West Capital Corporation
DOE – United States Department of Energy
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
FIP – Federal Implementation Plan
FIN – FASB Interpretation Number
Fitch – Fitch, Inc.
Four Corners – Four Corners Power Plant
GAAP – accounting principles generally accepted in the United States of America
IRS – United States Internal Revenue Service
kWh – kilowatt-hour, one thousand watts per hour
Moody’s – Moody’s Investors Service
MWh – megawatt-hour, one million watts per hour
Native Load – retail and wholesale sales supplied under traditional cost-based rate regulation
Note – a Note to Pinnacle West’s Condensed Consolidated Financial Statements in Item 1 of this
report
NRC – United States Nuclear Regulatory Commission
OCI – other comprehensive income
Off-System Sales – sales of electricity from generation owned or contracted by the Company that is
over and above the amount required to serve APS’ retail customers and traditional wholesale
contracts
Palo Verde – Palo Verde Nuclear Generating Station
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. Consolidation and Nature of Operations
The unaudited condensed consolidated financial statements include the accounts of Pinnacle
West and our subsidiaries: APS, APSES, SunCor, El Dorado, Pinnacle West Marketing & Trading and
Pinnacle West Energy (dissolved as of August 31, 2006). 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.
2. Condensed Consolidated Financial Statements
Our unaudited condensed consolidated financial statements reflect all adjustments that 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 be read along with the consolidated financial statements and notes to
consolidated financial statements included in our 2006 Form 10-K. We have condensed certain prior
year amounts on our condensed consolidated statements of cash flows to conform to current year
presentations.
3. Quarterly Fluctuations
Weather conditions cause significant seasonal fluctuations in our revenues. In addition, real
estate and 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 4, 2007, the FERC issued an order permitting Pinnacle West to transfer its
market-based rate tariff and wholesale power sales agreements to a newly-created Pinnacle West
subsidiary, Pinnacle West Marketing & Trading. Pinnacle West completed the transfer on February 1,2007, which resulted in Pinnacle West no longer being a public utility under the Federal Power Act.
As a result, Pinnacle West is no longer subject to FERC jurisdiction in connection with its
issuance of securities or its incurrence of long-term debt.
SunCor entered into a secured construction loan on April 13, 2007, in the amount of $60
million, of which $35 million was outstanding at September 30, 2007. The loan matures on April 19,2009, and may be extended one year if certain conditions are met.
In May 2007, Pinnacle West infused approximately $40 million of equity into APS, consisting of
the proceeds of stock issuances in 2006 under Pinnacle West’s Investors Advantage Plan (direct
stock purchase and dividend reinvestment plan) and employee stock plans.
On July 31, 2007, SunCor borrowed $12 million under a new secured construction loan. The loan
matures on July 31, 2009, and may be extended annually up to two years.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
At September 30, 2007, APS had borrowings of $150 million under its revolving line of credit.
Pinnacle West had borrowings of $105 million under its revolving line of credit. The amounts drawn
under the Pinnacle West and APS lines of credit were used for general corporate purposes.
An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As
defined in the ACC order, the common equity ratio is common equity divided by the sum of common
equity and long-term debt, including current maturities of long-term debt. At September 30, 2007,
APS’ common equity ratio, as defined, was 54%, its total common equity was approximately $3.4
billion, and total capitalization was approximately $6.3 billion. APS would be prohibited from
paying dividends if the payment would reduce its common equity below approximately $2.5 billion,
assuming APS’ total capitalization remains the same.
SunCor has a $150 million loan facility secured primarily by an interest in land, commercial
properties, land contracts and homes under construction. The loan facility requires compliance
with certain loan covenants pertaining to debt to net worth, debt service, liquidity, cash flow
coverage and restrictions on debt. As of September 30, 2007, the amount of SunCor’s net assets
that could not be transferred to Pinnacle West in the form of cash dividends as a result of these
covenants was approximately $213 million.
As a result of the restrictions in the preceding two paragraphs, as of September 30, 2007, the
restricted net assets of our subsidiaries exceeded 25% of our consolidated net assets (at September30, 2007, our consolidated net assets were approximately $3.6 billion). These restrictions do not
materially affect Pinnacle West’s ability to meet its ongoing capital requirements.
The following table shows principal payments due on Pinnacle West’s and APS’ total long-term
debt and capitalized lease requirements as of September 30, 2007 (dollars in millions):
PINNACLE
WEST CAPITAL CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
5. Regulatory Matters
APS General Rate Case and Power Supply Adjustor
Retail Rate Increase
On June 19, 2007, the ACC rendered its decision in APS’ general retail rate case pursuant to
which APS had requested a 20.4%, or $435 million, increase in its annual retail electricity
revenues. APS’ request was designed to recover approximately $315 million in fuel-related expenses
and approximately $120 million in non-fuel related expenses. The ACC order, which was formally
issued on June 28, 2007, increased APS’ annual retail base revenues by approximately $322 million,
effective July 1, 2007, which includes a fuel-related increase of approximately $315 million
(excluding the PSA surcharge for 2005 Deferrals discussed below), or 15.1%, and non-fuel related
increases of approximately $7 million. The interim PSA adjustor approved by the ACC on May 1,2006, which was designed to recover a portion of APS’ fuel and purchased power costs deferred under
the PSA, terminated effective with the rate increase, resulting in a net retail rate increase of
approximately 6.8%. The base rate increase is premised on a return on equity of 10.75%; a 45%/55%
long-term debt/common equity capital structure; a weighted-average cost of capital of 8.32%; an
original cost rate base of $4.4 billion as of September 30, 2005; and a Base Fuel Rate of $0.0325
per kWh.
PSA Modifications
The ACC order modified the PSA in various respects, effective July 1, 2007. The PSA, which
the ACC initially approved in 2005 as a part of APS’ 2003 rate case, provides for the adjustment of
retail rates to reflect variations in retail fuel and purchased power costs. As modified by the
ACC’s recent order, the PSA is subject to specified parameters and procedures, including the
following:
•
APS records deferrals for recovery or refund to the extent actual retail fuel and
purchased power costs vary from the Base Fuel Rate;
•
the deferrals continue to be subject to a 90/10 sharing arrangement in which APS
must absorb 10% of the retail fuel and purchased power costs above the Base Fuel Rate
and may retain 10% of the benefit from the retail fuel and purchased power costs that
are below the Base Fuel Rate, excluding certain costs, such as renewable energy
resources and the capacity components of long-term purchase power agreements acquired
through competitive procurement;
•
the adjustment is made annually each February 1st and goes into effect
automatically unless suspended by the ACC;
•
the PSA now uses a forward-looking estimate of fuel and purchased power costs
(instead of historical deferred costs, as under the prior PSA) to set the annual PSA
rate, which will be reconciled to actual costs experienced for each PSA Year (February
1 through January 31) (see the following bullet point);
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
•
the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds
differences between expected fuel and purchased power costs for the
upcoming calendar year and those embedded in the Base Fuel Rate; (b) an “Historical
Component,” under which the differences between actual fuel and purchased power
costs and those recovered through the combination of the Base Fuel Rate and the
Forward Component are recovered during the next PSA Year; and (c) a “Transition
Component” under which APS may seek mid-year PSA changes due to large variances
between actual fuel and purchased power costs and the combination of the Base Fuel
Rate and the Forward Component;
•
amounts to be recovered or refunded through the sum of the PSA components discussed
in the preceding bullet point are limited to a maximum plus or minus $0.004 per kWh
change in the PSA rate in any PSA Year;
•
the Base Fuel Rate established in the ACC order reflects projected 2007 fuel and
purchased power costs; as a result, the “Forward Component” for the PSA Year ending
January 31, 2008 will be zero; and
•
the PSA adjustor that took effect on February 1, 2007 ($0.004 per kWh), and that was
scheduled to expire on January 31, 2008, will remain in effect as long as necessary
after January 31, 2008 to collect $46 million of 2007 fuel and purchased power costs
deferred as a result of the mid-year implementation of the new Base Fuel Rate.
2008 PSA Year
On September 28, 2007, APS submitted preliminary forecast calculations to the ACC for the
Forward Component, Historical Component and Transition Component for the PSA Year beginning
February 1, 2008. APS will update the calculations in a filing to the ACC prior to December 31,2007. Based upon the preliminary calculations, the PSA rates would be limited to $0.004 per kWh
for the 2008 PSA Year. Any uncollected deferrals during the 2008 PSA Year resulting from this
limit will flow into the 2009 Historical Component at the end of 2008.
PSA Deferrals Related to Palo Verde Outages
APS recorded $45 million of 2005 Deferrals and $79 million of 2006 Deferrals. The ACC order
(a) disallowed approximately $14 million, including accrued interest ($8 million after income
taxes), of the 2005 Deferrals because the ACC found that the outage costs giving rise to those
amounts resulted from APS’ imprudence and (b) approved APS’ recovery of the balance of the 2005
Deferrals (approximately $34 million, including accrued interest) through a temporary PSA surcharge
over a twelve-month period effective July 1, 2007. In connection with the interim PSA adjustor
approved on May 1, 2006, the ACC directed the ACC staff to conduct a “prudence audit” of 2006 Palo
Verde outage costs. Virtually all of the 2006 Deferrals were associated with a Unit 1 vibration
issue. On October 4, 2007 the ACC staff filed a report with the ACC that concludes that APS’
response to the Unit 1 vibration issue was “reasonable and prudent.” APS continues to believe that
these costs were prudently incurred and that the 2006 Deferrals are, therefore, recoverable.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
PSA Balance
The following table shows the changes in the deferred fuel and purchase power regulatory asset
for the nine months ended September 30, 2007 and 2006 (dollars in millions):
Deferred fuel and purchased power costs-current period
198
225
Regulatory disallowance
(14
)
—
Interest on deferred fuel and purchased power
5
6
Amounts recovered through revenues
(199
)
(195
)
Ending balance
$
150
$
209
Other Matters
The ACC order approved an environmental improvement surcharge (“EIS”) to recover capital costs
incurred for environmental improvements made by APS in compliance with federal and state laws or
regulatory requirements. The EIS will be set initially at $0.00016 per kWh, designed to produce
approximately $4.5 million of cash per year until further order of the ACC.
The ACC order requires APS and the ACC staff to work to prepare a “nuclear performance
standard” that the ACC can consider in a separate proceeding. The parties are currently working
together to develop the standard.
The ACC Order also required APS to file a revised line extension schedule for ACC
approval that would eliminate certain footage and equipment allowances for new or expanded electric
service and remove any requirement for economic feasibility analyses used to determine whether or
how much of an allowance should be granted. This would permit APS to collect, on a current basis,
costs related to line extensions. Such pretax costs are currently estimated to be approximately
$3,500-$5,000 per new meter set. These are average figures and the actual costs of a service
extension will vary by customer class and the particulars of the extension.
On October 24, 2007, APS filed a proposed amendment to its line extension schedule. On
November 2, 2007, the ACC staff issued its recommended order, which accepts APS’ proposed amendment
in all respects except for the accounting treatment for payments received for new or upgraded
service. APS’ proposal would treat such payments as non-refundable other electric revenues, while
the ACC Staff proposes these payments should be treated as contributions in aid of construction
(“CIAC”). CIAC treatment would result in a positive cash flow that would offset capital
expenditures, but without any revenue impact.
APS proposed to “grandfather” applicants that have executed line extension agreements prior to
the effective date of its amended line extension schedule. The impact of the amended line
extension schedule on APS’ financial condition cannot be accurately predicted at this time and
depends on the accounting treatment authorized for the proceeds, the extent of any “grandfathering”
required by the ACC, and the level and mix of new APS customers. APS intends to file exceptions to
the ACC staff’s recommended order by mid-November, and the final outcome of this matter is pending
until further ACC action, which is expected to occur in late November.
APS Financing Authorization
On December 15, 2006, APS filed a financing application with the ACC requesting an increase in
APS’ (a) current short-term debt authorization (7% of APS’ capitalization) to (i) 7% of APS’
capitalization plus (ii) $500 million in order to meet its growing cash requirements, including
cash requirements for natural gas and power purchases and (b) current long-term debt authorization
(approximately $3.2 billion) to $4.2 billion in light of the projected growth of APS and its
customer base and the resulting projected financing needs. On October 30, 2007, the ACC issued a
financing order in which it approved APS’ requests, subject to specified parameters and procedures.
Federal
Price Mitigation Plan
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. On February 13,2006, the FERC increased this price cap to $400 per MWh for prospective sales. Sales at prices
above the cap must be justified and are subject to potential refund. We do not expect this price
cap to have a material impact on our financial statements.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
FERC Order
On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy, and APSES (collectively, the
“Pinnacle West Companies”) submitted to the FERC an update to their three-year market-based rate
review pursuant to the FERC’s order implementing a new generation market power analysis. On
December 20, 2004, the FERC issued an order approving the Pinnacle West Companies’ market-based
rates for control areas other than those of APS, Public Service Company of New Mexico (“PNM”) and
Tucson Electric Power Company (“TEP”). The FERC staff required the Pinnacle West Companies to
submit additional data with respect to these control areas, and the Pinnacle West Companies did so.
On April 17, 2006, the FERC issued an order revoking the Pinnacle West Companies’ authority to
make sales at market-based rates in the APS control area (the “April 17 Order”). The FERC found
that the Pinnacle West Companies failed to provide the necessary information about the calculation
of transmission imports into the APS control area to allow the FERC to make a determination
regarding FERC’s generation market power “screens” in the APS control area. The FERC found that
the Pinnacle West Companies may charge market-based rates in the PNM and TEP control areas.
On August 13, 2007, the FERC issued an order on rehearing, reinstating the authority of the
Pinnacle West Companies to make sales at market-based rates in all seasons for sales outside of the
Phoenix Valley, and in all seasons except the summer for sales within the Phoenix Valley. The
Pinnacle West Companies submitted a compliance filing implementing this order to the FERC on
October 12, 2007.
Based upon an analysis of this matter and preliminary calculations of the refund obligations,
at this time neither Pinnacle West nor APS believes that this proceeding will have a material
adverse effect on its financial position, results of operations or cash flows.
FERC Rate Case
On July 10, 2007, APS submitted a revised Open Access Transmission Tariff (OATT) filing with
the FERC to move from a fixed rate to a formula rate in order to more accurately reflect the costs
that APS incurs in providing transmission and ancillary services. The requested formula rate would
result in an estimated $37 million increase in annual transmission revenues, effective October 1,2007. The proposed formula rate would be updated each year on June 1 on the basis of APS’ actual
cost of service, as disclosed in APS’ FERC Form 1 reports, and projected capital expenditures.
Approximately $30 million of the requested increase represents charges for transmission services to
serve APS’ retail customers (“Retail Transmission Charges”) and, as a result, would not affect APS’
earnings until such time as APS retail rates are adjusted to include these charges. As part of a
retail rate case settlement order in 2005, the ACC approved the use of a mechanism by which changes
in Retail Transmission Charges can be reflected in APS’ retail rates. APS is currently addressing
the appropriate procedure to implement the retail transmission rate change.
On September 21, 2007, the FERC issued an order on these proposed revisions to APS’
transmission rates in which it accepted APS’ proposed formula rates and ordered settlement judge
procedures, with an initial settlement conference held on October 11, 2007. The proposed rates
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
become effective March 1, 2008, subject to refund based upon the outcome of the settlement
procedures and a hearing, if necessary, that has been scheduled in abeyance to allow time for such
settlement procedures.
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 (“SEBRP”), and other postretirement
benefit plans for the employees of Pinnacle West and our subsidiaries. Pinnacle West uses a
December 31 measurement date for its pension and other postretirement benefit plans. The
market-related value of our plan assets is their fair value at the measurement date.
Pursuant to the ACC’s June 28, 2007 order in APS’ general rate case, APS was not allowed to
recover the pension costs associated with the SEBRP through the ratemaking process. Therefore,
amounts that were previously recorded as a regulatory asset, approximately $45 million ($27
million, net of income taxes), were charged to OCI at June 30, 2007 (see Notes 11 and S-2). This
treatment is consistent with the accounting for this type of plan by our unregulated entities.
The following table provides details of the plans’ benefit costs for the three and nine months
ended September 30, 2007 and 2006. Also included is the portion of these costs charged to expense,
including administrative costs and excluding amounts billed to electric plant participants or
capitalized as overhead construction (dollars in millions):
Our pension contribution of $52 million has been made for the year. The contribution to our
other postretirement benefit plans in 2007 is estimated to be approximately $18 million, of which
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
approximately $15 million was contributed through September 30, 2007. APS and other subsidiaries
fund their share of the contributions. APS’ share is approximately 96% of both plans.
7. Business Segments
Pinnacle West’s two reportable business segments are:
•
our regulated electricity segment, which consists of traditional regulated retail
and wholesale electricity businesses (primarily electricity service to Native Load
customers) and related activities and includes electricity generation, transmission and
distribution; and
•
our real estate segment, which consists of SunCor’s real estate development and
investment activities.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
8. Income Taxes
As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax
accounting method change on our 2001 federal consolidated income tax return. The accelerated
deduction resulted in a $200 million reduction in the current income tax liability and a
corresponding increase in the plant-related deferred tax liability. Our 2001 federal consolidated
income tax return is currently under examination by the IRS. As part of its ongoing examination,
the IRS is reviewing this accounting method change and the resultant deduction. Within the next 12
months, we expect that the IRS will finalize its examination and will issue a settlement on the tax
accounting method change. At this time, an estimate of the range of reasonably possible change in
the uncertain tax position cannot be made. However, we do not expect the ultimate outcome of this
examination to have a material adverse impact on our financial position or results of operations.
We expect that it will have a negative impact on cash flows.
We adopted FIN 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB
Statement No. 109” on January 1, 2007. The effect of applying the new guidance was not
significantly different in terms of tax impacts from the application of our previous policy.
Accordingly, the impact to retained earnings upon adoption was immaterial. In addition, the
guidance required us to reclassify certain tax benefits, which had the effect of increasing accrued
taxes and deferred debits by approximately $50 million to better reflect the expected timing of the
payment of taxes and interest.
The total amount of unrecognized tax benefits recorded in accrued taxes as of January 1, 2007
was $186 million, of which $179 million related to APS. The majority of the unrecognized tax
benefits relate to the 2001 tax return position described above. Included in the balance of
unrecognized tax benefits at January 1, 2007 are approximately $5 million of tax positions for
consolidated Pinnacle West that, if recognized, would decrease our effective tax rate. For APS,
approximately $3 million would have the same effect.
We continue to recognize potential accrued interest related to unrecognized tax benefits in
the financial statements as income tax expense. As of January 1, 2007, the total amount of accrued
interest expense related to unrecognized tax benefits was $54 million for consolidated Pinnacle
West, which is included as a component of the $186 million unrecognized tax benefit noted above.
APS’ share included in the total was approximately $53 million. Additionally, Pinnacle West has
accrued $9 million of interest income to be received on the overpayment of income taxes for certain
adjustments that we have filed, or will file, with the IRS. APS’ share included in the total was
approximately $7 million. Partial resolution of previously unrecognized tax benefits during the
quarter ended September 30, 2007 resulted in a $10 million benefit.
As of January 1, 2007, the tax year ended December 31, 1999 and all subsequent tax years
remain subject to examination by federal and state taxing authorities. In addition, tax years
ended prior to December 31, 1999 may remain subject to examination by state taxing authorities.
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
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 September 30, 2007, APS would have been required to assume
approximately $208 million of debt and pay the equity participants approximately $174 million.
10. Derivative and Energy Trading Accounting
We use derivative instruments (primarily forward purchases and sales, swaps, options and
futures) to manage our exposure to the commodity price risk inherent in the purchase and sale of
fuel, electricity and emission allowances and credits. As of September 30, 2007, we hedged
exposures to the price variability of the power and gas commodities for a maximum of 40 months.
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, after consideration of amounts deferred under the PSA, for the three and nine
months ended September 30, 2007 and 2006 are comprised of the following (dollars in thousands):
Gains (losses) on
the ineffective
portion of
derivatives
qualifying for
hedge accounting
$
(239
)
$
(2,830
)
$
1,094
$
(5,984
)
Gains (losses) from
the change in
options’ time value
excluded from
measurement of
effectiveness
—
4
—
(10
)
Gains from the
discontinuance of
cash flow hedges
6
—
320
434
During the next twelve months ending September 30, 2008, we estimate that a net gain of $34
million before income taxes will be reclassified from accumulated other comprehensive income as an
offset to the effect of market price changes for the related hedged transactions. To the extent
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a
regulatory asset or liability and have no effect on earnings (see Note 5).
Our assets and liabilities from risk management and trading activities are presented in two
categories, regulated electricity and marketing and trading.
The following tables summarize our assets and liabilities from risk management and trading
activities at September 30, 2007 and December 31, 2006 (dollars in thousands):
During the first quarter of 2007, we changed the presentation of mark-to-market positions
related to natural gas basis swaps in the regulated electricity segment. We historically presented
the buy side and the sell side of such swaps at fair value gross on our consolidated balance
sheets, which resulted in mark-to-market assets and separate mark-to-market liabilities. We now
offset these matching assets and liabilities, thus presenting the net mark-to-market position by
contract, which correctly reflects the true nature of these contracts. The net asset/liability
position as historically
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
disclosed in the table above is unchanged. Further, this change has no
impact on results of operations, common stock equity or cash flows. Had we previously presented
such amounts net, the effect on the December 31, 2006 balance sheet would have been to decrease
Current Assets and Current Liabilities by $376 million and decrease Investments and Other Assets
and Deferred Credits and Other by $59 million. We believe that the effect of presenting these
contracts gross in prior periods is immaterial to previously issued financial statements.
We maintain a margin account with a broker to support our risk management and trading
activities. The margin account was an asset of $58 million at September 30, 2007 and $73 million
at December 31, 2006 and is included in the margin account in the table above. Cash is deposited
with the broker in this account at the time futures or options contracts are initiated. The change
in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin
account balance.
Cash or other assets may be required to serve as collateral against our open positions on
certain energy-related contracts. Collateral provided to counterparties was $4 million at
September 30, 2007 and $10 million at December 31, 2006, and is included in other current assets on
the Condensed Consolidated Balance Sheets. No collateral was provided to us by counterparties at
September 30, 2007 and $54 million was provided to us at December 31, 2006, and is included in
other current liabilities 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. Our risk management process
assesses and monitors the financial exposure of all counterparties. Despite the fact that the
great majority of trading counterparties’ securities are rated as investment grade by the credit
rating agencies, there is still a possibility that one or more of these companies could default,
resulting in a material impact on consolidated earnings for a given period. Counterparties in the
portfolio consist principally of financial institutions, major energy companies, municipalities and
local distribution companies. We maintain credit policies that we believe minimize overall credit
risk to within acceptable limits. Determination of the credit quality of our counterparties is
based upon a number of factors, including credit ratings and our evaluation of their financial
condition. To manage credit risk, we employ collateral requirements, standardized agreements that
allow for the netting of positive and negative exposures associated with a single counterparty and
credit default swaps. Valuation adjustments are established representing our estimated credit
losses on our overall exposure to counterparties.
11. Comprehensive Income
Components of comprehensive income for the three and nine months ended September 30, 2007 and
2006 are as follows (dollars in thousands):
Net unrealized losses on
derivative instruments (a)
(44,715
)
(68,201
)
(15,035
)
(342,307
)
Net reclassification of
realized (gains) losses on
derivative instruments to
income (b)
17,989
2,519
(1,072
)
(15,688
)
Net unrealized gains (losses)
related to pension and other
postretirement benefits (c)
605
—
(43,968
)
—
Reclassification of pension and
other postretirement benefits
to income
1,223
—
1,702
—
Net income tax benefit related
to items of other comprehensive
income
9,764
25,649
22,917
139,798
Total other comprehensive loss
(15,134
)
(40,033
)
(35,456
)
(218,197
)
Comprehensive income
$
193,574
$
144,134
$
268,776
$
90,579
(a)
These amounts primarily include unrealized gains and losses on contracts used to
hedge our forecasted electricity and natural gas requirements to serve Native Load.
These changes are primarily due to changes in forward natural gas prices and wholesale
electricity prices.
(b)
These amounts primarily include the reclassification of unrealized gains and
losses to realized for contracted commodities delivered during the period.
(c)
In accordance with the ACC’s June 28, 2007 order in APS’ general rate case, these
amounts primarily include costs that were previously recorded as a regulatory asset and
have now been charged to OCI.
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
Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent
nuclear fuel by 1998, the DOE announced that the repository cannot be completed before at least
2017. In November 1997, the United States Court of Appeals for the District of Columbia Circuit
(D.C.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the
DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of
utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages
actions against the DOE in the Court of Federal Claims. APS is currently pursuing that damages
claim.
APS currently estimates it will incur $147 million (in 2006 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
September 30, 2007, APS had a regulatory liability of approximately $8 million that represents
amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel
storage.
NRC Matters
In October 2006, the NRC conducted an inspection of the Palo Verde emergency diesel generators
after a Palo Verde Unit 3 generator started but did not provide electrical output during routine
inspections on July 25 and September 22, 2006. On February 22, 2007, the NRC issued a “white”
finding (low to moderate safety significance) for this matter. Under the NRC’s Action Matrix, this
finding, coupled with a previous NRC “yellow” finding relating to a 2004 matter involving Palo
Verde’s safety injection systems, resulted in Palo Verde Unit 3 being placed in the
“multiple/repetitive degraded cornerstone” column of the NRC’s Action Matrix (“Column 4”), which
has resulted in an enhanced NRC inspection regimen. Although only Palo Verde Unit 3 is in NRC’s
Column 4, in order to adequately assess the need for improvements, APS management has been
conducting site-wide assessments of equipment and operations. Preliminary work in support of the
NRC’s enhanced inspection regimen took place throughout summer 2007. On June 21, 2007, the NRC
issued an initial confirmatory action letter confirming APS’ commitments regarding specific actions
APS will take to improve Palo Verde’s performance. From October 1, 2007, through November 2, 2007,
a team of NRC inspectors performed on-site in-depth inspections of Palo Verde equipment and
operations. APS expects to be informed of the NRC’s inspection findings in late December 2007 or
January 2008. APS continues to cooperate fully with the NRC throughout this process. Following
receipt of the inspection findings and APS’ revisions to improvement plans to address the
inspection findings, the NRC will issue a revised confirmatory action letter in the first quarter
of 2008.
On November 9, 2006, APS notified the NRC that a senior reactor operator at Palo Verde had
attempted to conceal a mistaken entry the operator had made in a Palo Verde operations verification
log. The senior reactor operator resigned shortly thereafter. By letter dated July 12, 2007, the
NRC notified APS that, based upon the results of its investigation of the matter, the NRC was
considering an escalated enforcement action against Palo Verde due to the willfulness of the senior
reactor operator’s actions. The NRC noted in its letter that the safety significance of the matter
was very low. The NRC also offered to resolve the potential escalated enforcement action through
the agency’s alternative dispute resolution program, which APS elected to do. As a result of the
alternative dispute resolution proceeding between the NRC and APS, a settlement was reached under
which APS agreed to take a number of corrective actions, including specified training for certain
Palo Verde personnel and follow up reporting to the NRC. As a result of APS’ commitments, the NRC
agreed not to pursue any further enforcement action in connection with this matter. The agreement
between APS and the NRC became effective upon the NRC’s issuance of a confirmatory order, dated
October 19, 2007, memorializing the agreement.
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
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
a recipient as well as a payor of such amounts. The FERC is still considering the evidence
and refund amounts have not yet been finalized. However, on September 6, 2005, the Ninth Circuit
issued a decision, concluding that the FERC may not order refunds from entities that are not within
the FERC’s jurisdiction. Because a number of the entities owing refunds under the FERC’s
calculations are not within the FERC’s jurisdiction, this order may affect the level of recovery of
refunds due in this proceeding. In addition, on August 8, 2005, the FERC issued an order allowing
sellers in the California markets to demonstrate that its refund methodology results in an overall
revenue shortfall for their transactions in the relevant markets over a specified time frame. More
than twenty sellers made such cost recovery filings on September 14, 2005. On January 26, 2006,
the FERC conditionally accepted thirteen of these filings, reducing the refund liability for these
sellers. Correspondingly, this will reduce the recovery of total refunds in the California
markets. On August 2, 2006, the Ninth Circuit issued a decision on the appropriate temporal scope
and the type of transactions that are properly subject to the refund orders. In the decision, the
Court preserved the scope of the FERC’s existing refund proceedings, but also expanded it
potentially to include additional transactions, remanding the orders to the FERC for further
proceedings. Various parties filed petitions for rehearing on this order. In addition, on
December 19, 2006, the Ninth Circuit issued a decision on the appropriate standard of review at the
FERC on wholesale power contracts in the refund proceedings, specifically addressing the
application of the so-called “just and reasonable” standard as opposed to the “public interest”
standard. In so doing, the Ninth Circuit remanded the matter back to the FERC with the requirement
that the FERC review the refund matter using the appropriate standard of review. Like the August 2,2006 Ninth Circuit decision, the December 19, 2006 decision has the potential to expand the
existing FERC refund proceedings. We currently believe the refund claims at FERC will have no
material adverse impact on our financial position, results of operations, or cash flows.
On March 19, 2002, the State of California filed a complaint with the FERC alleging that
wholesale sellers of power and energy, including the Company, failed to properly file rate
information at the FERC in connection with sales to California from 2000 to the present under
market-based rates. The complaint requests the FERC to require the wholesale sellers to refund any
rates that are “found to exceed just and reasonable levels.” This complaint was dismissed by the
FERC and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an
order issued September 9, 2004, the Ninth Circuit upheld the FERC’s authority to permit
market-based rates, but rejected the FERC’s claim that it was without authority to consider
retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements
of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the
FERC for further proceedings. Several of the intervenors in this appeal filed a petition for
rehearing of this decision on October 25, 2004. The petition for rehearing was denied on July 31,2006. On December 28, 2006, certain parties petitioned the Supreme Court for a writ of certiorari.
This petition was denied on June 18, 2007. On October 10, 2006, the State of California filed a
motion to stay the issuance of the mandate (scheduled to be issued on November 2, 2006) until June13, 2007. The Ninth Circuit has extended the stay until November 16, 2007. The outcome of the
further proceedings cannot be predicted at this time.
On July 25, 2001, the FERC also ordered an evidentiary proceeding to discuss and evaluate
possible refunds for wholesale sales in the Pacific Northwest. The FERC affirmed the ALJ’s
conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds
should not be ordered in this proceeding. This decision was appealed to the U.S. Court of Appeals
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
for the Ninth Circuit. On August 24, 2007, the Ninth Circuit issued an opinion that remanded
the proceeding to the FERC for further consideration. The Court stayed the date for petitions for
rehearing of this opinion until November 16, 2007 to allow for any possible settlement
negotiations. Although the FERC ruling in this 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, the FERC made public a Final Report on Price Manipulation in Western
Markets, prepared by its staff and covering spot markets in the West in 2000 and 2001. The report
stated that a significant number of entities who participated in the California markets during the
2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions
that allegedly violated certain provisions of the Independent System Operator tariff. After
reviewing 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.
FERC Order
See “FERC Order” in Note 5 for a discussion of an order issued by the FERC on April 17, 2006.
Natural Gas Supply
Pursuant to the terms of a comprehensive settlement entered into in 1996 with El Paso Natural
Gas Company, the rates charged for natural gas transportation were subject to a rate moratorium
through December 31, 2005.
On July 9, 2003, the FERC issued an order that altered the capacity rights of parties to the
1996 settlement but maintained the cost responsibility provisions agreed to by parties to that
settlement. On December 28, 2004, the D.C. Court of Appeals upheld the FERC’s authority to alter
the capacity rights of parties to the settlement. With respect to the FERC’s authority to maintain
the cost responsibility provisions of the settlement, a party sought appellate review to reallocate
the cost responsibility associated with the changed contractual obligations in a way that would
have increased APS’ annual capacity cost by approximately $3 million per year after income taxes
for the period September 2003 through December 2005. This appeal had been stayed pending further
consideration by the FERC. On May 26, 2006, the FERC issued an Order on Remand affirming its
earlier decision that there was no basis for modifying the settlement rates during the remaining
term of the settlement. By order of the D.C. Court of Appeals issued on October 10, 2007, this
case was dismissed as a result of a motion for voluntary dismissal filed by the party that
originally sought review in this case.
Navajo Nation Litigation
In June 1999, the Navajo Nation served Salt River Project with a lawsuit filed in the United
States District Court for the District of Columbia (the “D.C. Lawsuit”) naming Salt River Project,
several Peabody Coal Company entities (collectively, “Peabody”), Southern California Edison
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Company and other defendants, and citing various claims in connection with the renegotiations of
the coal royalty and lease agreements under which Peabody mines coal for the Navajo Generating
Station and the Mohave Generating Station. APS is a 14% owner of the Navajo Generating Station,
which Salt River Project operates. The D.C. Lawsuit alleges, among other things, that the
defendants obtained a favorable coal royalty rate by improperly influencing the outcome of a
federal administrative process under which the royalty rate was to be adjusted. The suit seeks
$600 million in damages, treble damages, punitive damages of not less than $1 billion, and the
ejection of defendants “from all possessory interests and Navajo Tribal lands arising out of the
[primary coal lease].” In July 2001, the court dismissed all claims against Salt River Project.
In January 2005, Peabody served APS with a lawsuit filed in the Circuit Court for the City of
St. Louis naming APS and the other Navajo Generating Station participants and seeking, among other
things, a declaration that the participants “are obligated to reimburse Peabody for any royalty,
tax, or other obligation arising out of the D.C. Lawsuit.” Based on APS’ ownership interest in the
Navajo Generating Station, APS could be liable for up to 14% of any such obligation. APS cannot
currently predict the outcome of this matter.
Superfund
Superfund establishes liability for the cleanup of hazardous substances found contaminating
the soil, water or air. Those who generated, transported or disposed of hazardous substances at a
contaminated site are among those who are PRPs. PRPs may be strictly, and often jointly and
severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers
APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (OU3) in
Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West
have agreed with the EPA to perform certain investigative activities of the APS facilities within
OU3. Because the investigation has not yet been completed and ultimate remediation requirements
are not yet finalized, neither APS nor Pinnacle West can currently estimate the expenditures that
may be required.
Salt River Project
Salt River Project has notified APS that Salt River Project allegedly failed to bill APS for
(a) energy losses under certain service schedules of a power contract between the parties and (b)
certain other charges under the contract. Salt River Project asserts that certain of these
failures to bill APS for such losses and charges may extend back to 1996 and, as a result, claims
that APS owes it approximately $29 million. APS disputes that it is required to pay these
amounts. No lawsuit or litigation has been initiated in the matter at this time. We do not expect
that resolution of this matter will have a material adverse impact on our financial position,
results of operations, or cash flows.
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.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 program exceed the accumulated funds, APS could be assessed
retrospective premium adjustments. The maximum assessment per reactor under the program for each
nuclear incident is approximately $101 million, subject to an annual limit of $15 million per
incident, to be periodically adjusted for inflation. Based on APS’ interest in the three Palo
Verde units, APS’ maximum potential assessment per incident for all three units is approximately
$88 million, with an annual payment limitation of approximately $13 million.
The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for
property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75
billion, a substantial portion of which must first be applied to stabilization and decontamination.
APS has also secured insurance against portions of any increased cost of generation or purchased
power and business interruption resulting from a sudden and unforeseen accidental outage of any of
the three units. The property damage, decontamination, and replacement power coverages are
provided by Nuclear Electric Insurance Limited (NEIL). APS is subject to retrospective assessments
under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum
amount of retrospective assessments APS could incur under the current NEIL policies totals
$21.1 million. The insurance coverage discussed in this and the previous paragraph is subject to
certain policy conditions and exclusions.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
14. Other Income and Other Expense
The following table provides detail of other income and other expense for the three and nine
months ended September 30, 2007 and 2006 (dollars in thousands):
As defined by the FERC, includes below-the-line non-operating utility income
and expense (items excluded from utility rate recovery).
(b)
Includes equity earnings from a real estate joint venture that is a
pass-through entity for tax purposes.
15. Guarantees
We have issued parental guarantees and letters of credit and obtained surety bonds on behalf
of our subsidiaries. Our parental guarantees for Pinnacle West Marketing & Trading relate to
commodity energy products. Our credit support instruments enable APSES to offer commodity energy
and energy-related products. Non-performance or non-payment under the original contract by our
subsidiaries would require us to perform under the guarantee or surety bond. No liability is
currently recorded on the Condensed Consolidated Balance Sheets related to Pinnacle West’s current
outstanding guarantees on behalf of our subsidiaries. Our guarantees have no recourse or
collateral provisions to allow us to recover amounts paid under the guarantees. The amounts and
approximate terms of our guarantees and surety bonds for each subsidiary at September 30, 2007 are
as follows (dollars in millions):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Guarantees
Surety Bonds
Term
Term
Amount
(in years)
Amount
(in years)
Parental:
Pinnacle West Marketing & Trading
$
45
1
$
—
—
APSES
18
1
22
1
Total
$
63
$
22
At September 30, 2007, Pinnacle West had approximately $5 million of letters of credit related
to workers’ compensation expiring in 2009. We intend to provide from either existing or new
facilities for the extension, renewal or substitution of the letters of credit to the extent
required.
APS has entered into various agreements that require letters of credit for financial assurance
purposes. At September 30, 2007, approximately $200 million of letters of credit were outstanding
to support existing pollution control bonds of approximately $200 million. The letters of credit
are available to fund the payment of principal and interest of such debt obligations and expire in
2010. APS has also entered into approximately $83 million of letters of credit to support certain
equity lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the
Palo Verde sale leaseback transactions). These letters of credit expire in 2010. Additionally, at
September 30, 2007, APS had approximately $4 million of letters of credit related to counterparty
collateral requirements expiring in 2007. APS intends to provide from either existing or new
facilities for the extension, renewal or substitution of the letters of credit to the extent
required.
We enter into agreements that include indemnification provisions relating to liabilities
arising from or related to certain of our agreements; most significantly, APS has agreed to
indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions
with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in
the indemnification provisions and, therefore, the overall maximum amount of the obligation under
such indemnification provisions cannot be reasonably estimated. Based on historical experience and
evaluation of the specific indemnities, we do not believe that any material loss related to such
indemnification provisions is likely.
16. Earnings Per Share
The following table presents earnings per weighted average common share outstanding for the
three and nine months ended September 30, 2007 and 2006:
Dilutive stock options and performance shares increased average common shares outstanding by
approximately 505,000 shares and 482,000 shares for the three months ended September 30, 2007 and
September 30, 2006, respectively, and by approximately 567,000 shares and 446,000 shares for the
nine months ended September 30, 2007 and 2006, respectively.
Options to purchase 610,250 shares of common stock for the three-month period and 115,200
shares for the nine-month period ended September 30, 2007 were outstanding but were excluded from
the computation of diluted earnings per share because the options’ exercise prices were greater
than the average market price of the common shares. Options to purchase shares of common stock
that were excluded from the computation of diluted earnings per share for that same reason were
447,650 shares for the three-month period ended September 30, 2006 and 732,534 shares for the
nine-month period ended September 30, 2006.
17. Discontinued Operations
SunCor (real estate segment) – In 2006 and 2007, SunCor sold commercial properties that were
required to be reported as discontinued operations on Pinnacle West’s Condensed Consolidated
Statements of Income in accordance with SFAS No. 144. As a result of those sales, we recorded in
2007 a gain from discontinued operations of approximately $8 million ($13 million pretax). Assets
held for sale at September 30, 2007 relate to commercial properties in the amount of $6 million.
The following table contains SunCor’s revenue, income before income taxes and income after income
taxes classified as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of
Income for the three and nine months ended September 30, 2007 and 2006 (dollars in millions):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
18. Nuclear Decommissioning Trust
To fund the costs APS expects to incur to decommission Palo Verde, APS established external
decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in fixed
income and equity securities. APS applies the provisions of SFAS No. 115, “Accounting for Certain
Investments in Debt and Equity Securities,” in accounting for investments in decommissioning trust
funds, and classifies these investments as available for sale. As a result, we record the
decommissioning trust funds at their fair value on our Condensed Consolidated Balance Sheets.
Because of the ability of APS to recover decommissioning costs in rates and in accordance with the
regulatory treatment for decommissioning trust funds, APS has recorded the offsetting amount of
unrealized gains (losses) on investment securities in other regulatory liabilities/assets. The
following table summarizes the fair value of APS’ nuclear decommissioning trust fund assets at
September 30, 2007 and December 31, 2006 (dollars in millions):
The costs of securities sold are determined on the basis of specific identification. The
following table sets forth approximate gains and losses and proceeds from the sale of securities by
the nuclear decommissioning trust funds (dollars in millions):
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This guidance
establishes a framework for measuring fair value and expands disclosures about fair value
measurements. The Statement is effective for us on January 1, 2008. We are currently evaluating
this new guidance and preparing for the new disclosure requirements.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets
and Financial Liabilities.” SFAS No. 159 provides companies with an option to report selected
financial assets and liabilities at fair value. SFAS No. 159 is effective for us on January 1,2008. We are currently evaluating this new guidance.
See Note 8 for a discussion of FIN 48 on accounting for uncertainty in income taxes, which we
adopted January 1, 2007. The effect of applying the new guidance was not significantly different
in terms of tax impacts from the application of our previous policy. Accordingly, the impact to
retained earnings upon adoption was immaterial.
In
April 2007, the FASB issued FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation
No. 39, Offsetting of Amounts Related to Certain Contracts” (FSP FIN 39-1). Under FSP FIN 39-1, a
reporting entity is permitted to offset the fair value amounts recognized for cash collateral paid
or cash collateral received against the fair value amounts recognized for derivative instruments
executed with the same counterparty under a master netting arrangement. This new guidance is
effective for us on January 1, 2008, with early application permitted. We are currently evaluating
the impacts of FSP FIN 39-1 on our balance sheet. We do not expect the guidance to have an impact
on our results of operations or cash flows.
Allowance for equity funds used during construction
5,235
3,178
Other income (Note S-3)
4,083
7,713
Other expense (Note S-3)
(3,303
)
(2,770
)
Total
7,277
8,805
INTEREST DEDUCTIONS
Interest on long-term debt
40,232
39,175
Interest on short-term borrowings
2,715
2,438
Debt discount, premium and expense
1,162
1,066
Allowance for borrowed funds used during construction
(2,945
)
(1,928
)
Total
41,164
40,751
NET INCOME
$
204,257
$
168,634
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
14,874
10,612
Other income (Note S-3)
12,872
22,798
Other expense (Note S-3)
(10,976
)
(10,298
)
Total
18,387
24,985
INTEREST DEDUCTIONS
Interest on long-term debt
120,707
108,315
Interest on short-term borrowings
6,748
7,449
Debt discount, premium and expense
3,477
3,264
Allowance for borrowed funds used during construction
(7,833
)
(5,322
)
Total
123,099
113,706
NET INCOME
$
283,664
$
256,870
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
100,479
95,601
Nuclear fuel, net of accumulated amortization
74,500
60,100
Total utility plant
8,240,053
7,826,739
INVESTMENTS AND OTHER ASSETS
Assets from long-term risk management and trading
activities (Note S-1)
50,147
96,892
Decommissioning trust accounts (Note 18)
375,898
343,771
Other assets
70,773
67,763
Total investments and other assets
496,818
508,426
CURRENT ASSETS
Cash and cash equivalents
37,410
81,870
Investment in debt securities
—
32,700
Customer and other receivables
578,328
410,436
Allowance for doubtful accounts
(4,754
)
(4,223
)
Materials and supplies (at average cost)
146,755
125,802
Fossil fuel (at average cost)
30,806
21,973
Assets from risk management and trading activities (Note
S-1)
94,242
539,308
Deferred income taxes
33,713
19,220
Other current assets
12,298
13,367
Total current assets
928,798
1,240,453
DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Note 5)
150,286
160,268
Other regulatory assets
583,331
686,016
Unamortized debt issue costs
24,882
26,393
Other (Note 8)
80,470
65,397
Total deferred debits
838,969
938,074
TOTAL ASSETS
$
10,504,638
$
10,513,692
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to
Arizona Public Service Company’s Condensed Financial Statements.
Accumulated other comprehensive income (loss) (Note S-2):
Pension benefits
(26,496
)
—
Derivative instruments
7,385
2,988
Common stock equity
3,383,299
3,207,473
Long-term debt less current maturities (Note 4)
2,876,970
2,877,502
Total capitalization
6,260,269
6,084,975
CURRENT LIABILITIES
Short-term debt
150,000
—
Current maturities of long-term debt (Note 4)
987
968
Accounts payable
205,560
223,417
Accrued taxes (Note 8)
448,514
381,444
Accrued interest
40,689
45,254
Customer deposits
68,987
61,900
Liabilities from risk management and trading activities (Note S-1)
65,352
490,855
Other current liabilities
114,533
74,728
Total current liabilities
1,094,622
1,278,566
DEFERRED CREDITS AND OTHER
Deferred income taxes
1,262,589
1,215,862
Regulatory liabilities
672,679
635,431
Liability for asset retirements
277,378
268,389
Pension and other postretirement liabilities (Note 6)
516,579
551,531
Customer advances for construction
85,672
71,211
Unamortized gain – sale of utility plant
37,750
41,182
Liabilities from long-term risk management and trading
activities (Note S-1)
48,563
135,056
Other
248,537
231,489
Total deferred credits and other
3,149,747
3,150,151
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY
$
10,504,638
$
10,513,692
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to
Arizona Public Service Company’s Condensed Financial Statements.
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization including nuclear fuel
296,318
284,036
Deferred fuel and purchased power
(203,065
)
(231,388
)
Deferred fuel and purchased power amortization
198,677
195,127
Deferred fuel and purchased power regulatory disallowance
14,370
—
Allowance for equity funds used during construction
(14,874
)
(10,612
)
Deferred income taxes
36,646
29,566
Changes in mark-to-market valuations
(3,785
)
6,060
Changes in current assets and liabilities:
Customer and other receivables
(152,467
)
(85,190
)
Materials, supplies and fossil fuel
(29,786
)
(5,152
)
Other current assets
12
4,311
Accounts payable
(26,687
)
(13,468
)
Accrued taxes
31,504
133,359
Collateral
(2,491
)
(185,091
)
Other current liabilities
42,923
41,306
Change in risk management and trading – liabilities
(1,952
)
(120,769
)
Change in other long-term assets
31,960
(70,411
)
Change in other long-term liabilities
60,390
57,278
Net cash flow provided by operating activities
561,357
285,832
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures
(675,870
)
(466,095
)
Capitalized interest
(7,833
)
(5,322
)
Proceeds from sale of investment securities
69,225
389,178
Purchases of investment securities
(36,525
)
(592,495
)
Proceeds from nuclear decommissioning trust sales
203,014
170,827
Investment in nuclear decommissioning trust
(218,570
)
(186,383
)
Other
(62
)
(3,453
)
Net cash flow used for investing activities
(666,621
)
(693,743
)
CASH FLOWS FROM FINANCING ACTIVITIES
Equity infusion
39,548
210,000
Short-term borrowings, net
150,000
—
Issuance of long-term debt
—
395,481
Dividends paid on common stock
(127,500
)
(127,500
)
Repayment and reacquisition of long-term debt
(1,244
)
(2,310
)
Net cash flow provided by financing activities
60,804
475,671
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(44,460
)
67,760
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
81,870
49,933
CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
37,410
$
117,693
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Income taxes, net of refunds
$
70,083
$
24,414
Interest, net of amounts capitalized
$
124,186
$
95,149
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 that are required disclosures for APS and should be read in conjunction with Pinnacle West’s
Condensed Consolidated Notes.
APS is exposed to the impact of market fluctuations in the commodity price of electricity,
natural gas and emissions allowances. As part of its overall risk management program, APS uses
various commodity instruments that qualify as derivatives to hedge purchases and sales of
electricity, fuels, and emission allowances and credits. As of September 30, 2007, APS hedged
exposures to these risks for a maximum of 40 months.
Cash Flow Hedges
The changes in the fair value of APS’ hedged positions included in the APS Condensed
Statements of Income, after consideration of amounts deferred under the PSA, for the three and nine
months ended September 30, 2007 and 2006 were comprised of the following (dollars in thousands):
Gains (losses) on the ineffective
portion of derivatives qualifying
for hedge accounting
$
(239
)
$
(2,505
)
$
1,094
$
(5,765
)
Gains (losses) from the change in
options’ time value excluded from
measurement of effectiveness
—
4
—
(10
)
Gains from the discontinuance of
cash flow hedges
—
—
150
159
During the next twelve months ending September 30, 2008, APS estimates that a net gain of $16
million before income taxes will be reclassified from accumulated other comprehensive income as an
offset to the effect of market price changes for the related hedged transactions. To the extent
the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a
regulatory asset or liability and have no effect on earnings (see Note 5).
APS’ assets and liabilities from risk management and trading activities are presented in two
categories.
The following tables summarize APS’ assets and liabilities from risk management and trading
activities at September 30, 2007 and December 31, 2006 (dollars in thousands):
During the first quarter of 2007, we changed the presentation of mark-to-market positions
related to natural gas basis swaps in the regulated electricity segment. We historically presented
the buy side and the sell side of such swaps at fair value gross on our consolidated balance
sheets, which resulted in mark-to-market assets and separate mark-to-market liabilities. We now
offset these matching assets and liabilities, thus presenting the net mark-to-market position by
contract, which correctly reflects the true nature of these contracts. The net asset/liability
position as historically disclosed in the table above is unchanged. Further, this change has no
impact on income, common stock equity or cash flows. Had we previously presented such amounts net,
the effect on the December 31, 2006 balance sheet would have been to decrease Current Assets and
Current Liabilities by $376 million and decrease Investments and Other Assets and Deferred Credits
and Other by $59 million. We believe that the effect of presenting these contracts gross in prior
periods is immaterial to previously issued financial statements.
We maintain a margin account with a broker to support our risk management and trading
activities. The margin account was an asset of $58 million at September 30, 2007 and $73 million
at December 31, 2006 and is included in the margin account in the table above. Cash is deposited
with the broker in this account at the time futures or options contracts are initiated. The change
in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin
account balance.
Cash or other assets may be required to serve as collateral against APS’ open positions on
certain energy-related contracts. Collateral provided to counterparties was $4 million at
September 30, 2007 and $2 million at December 31, 2006 and is included in other current assets on
the
Condensed Balance Sheets. No collateral was provided to us by counterparties at September 30, 2007
and $1 million was provided to us at December 31, 2006, and is included in other current
liabilities on the Condensed Balance Sheets.
S-2. Comprehensive Income
Components of APS’ comprehensive income (loss) for the three and nine months ended
September 30, 2007 and 2006 are as follows (dollars in thousands):
Net unrealized losses on derivative
instruments (a)
(35,322
)
(51,359
)
(10,558
)
(276,555
)
Net reclassification of realized
losses on derivative instruments to
income (b)
23,324
8,068
17,795
910
Net unrealized losses related to
pension benefits (c)
—
—
(44,613
)
—
Reclassification of pension and
other
postretirement benefits to income
1,005
—
1,005
—
Net income tax benefit related to
items of other comprehensive income
4,314
16,906
14,272
107,640
Total other comprehensive loss
(6,679
)
(26,385
)
(22,099
)
(168,005
)
Comprehensive income
$
197,578
$
142,249
$
261,565
$
88,865
(a)
These amounts primarily include unrealized gains and losses on contracts used to
hedge our forecasted electricity and natural gas requirements to serve Native Load.
These changes are primarily due to changes in forward natural gas prices and wholesale
electricity prices.
(b)
These amounts primarily include the reclassification of unrealized gains and
losses to realized gains and losses for contracted commodities delivered during the
period.
(c)
In accordance with the ACC’s June 28, 2007 order in APS’ general rate case, these
amounts include costs that were previously recorded as a regulatory asset and have now
been charged to OCI.
S-3. Other Income and Other Expense
The following table provides detail of APS’ other income and other expense for the three and
nine months ended September 30, 2007 and 2006 (dollars in thousands):
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. APS has historically accounted for a
substantial part of our revenues and earnings, and is expected to continue to do so. Customer
growth in APS’ service territory is about three times the national average and remains a
fundamental driver of our revenues and earnings.
The ACC regulates APS’ retail electric rates. Our profitability is affected by the rates APS
may charge and the timely recovery of costs through those rates. APS’ capital expenditure
requirements, which are discussed below under “Liquidity and Capital Resources,” are substantial
because of the significant customer growth in APS’ service territory, highlighting APS’ need for
the timely recovery of these and other expenditures through rates. As discussed in greater detail
in Note 5, on June 28, 2007, the ACC issued an order in a general rate case that APS filed in late
2005. Additionally, the ACC directed the ACC staff to conduct a “prudence audit” of 2006 Palo
Verde outage costs. Virtually all of the 2006 Deferrals were
associated with a Unit 1 vibration
issue. On October 4, 2007 the ACC staff filed a report with the ACC that concludes that APS’
response to the Unit 1 vibration issue was “reasonable and prudent.” APS continues to believe that
these costs were prudently incurred and that the 2006 Deferrals, totaling approximately $79
million, are, therefore, recoverable.
SunCor, our real estate development subsidiary, has been and is expected to continue to be an
important source of earnings. See discussion below in “Pinnacle West Consolidated – Factors
Affecting our Financial Outlook – Subsidiaries.” Our subsidiary, APSES, provides competitive
commodity-related energy services and energy-related products and services to commercial and
industrial retail customers in the western United States. El Dorado, our investment subsidiary,
owns minority interests in several energy-related investments and Arizona community-based ventures.
Pinnacle West Marketing & Trading is the Company’s marketing and trading subsidiary, which began
activity in February 2007. See Note 4.
We continue to focus on solid operational performance in our electricity generation and
delivery activities. In the delivery area, we focus on superior reliability and customer
satisfaction. We plan to expand long-term resources and our transmission and distribution systems
to meet the electricity needs of our growing retail customers and sustain reliability.
See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” below for a
discussion of several factors that could affect our future financial results.
Pinnacle West’s two reportable business segments are:
•
our regulated electricity segment, which consists of traditional regulated retail
and wholesale electricity businesses (primarily electric service to Native Load
customers) and related activities and includes electricity generation, transmission
and distribution; and
•
our real estate segment, which consists of SunCor’s real estate development and
investment activities.
The following table summarizes income (loss) from continuing operations for the three months
and nine months ended September 30, 2007 and 2006 and reconciles net income in total (dollars in
millions):
All other includes activities related to marketing and trading, APSES
products and services and El Dorado. None of these segments is a reportable segment.
(b)
Primarily relates to sales of commercial properties.
PINNACLE WEST CONSOLIDATED – RESULTS OF OPERATIONS
Regulatory Matters
On June 28, 2007, the ACC issued an order in the general rate case of APS. In its order,
effective July 1, 2007, among other things, the ACC (a) approved an increase in APS’ retail base
rates, the components of which included an increase in APS’ Base Fuel Rate and a non-fuel rate
increase; (b) modified the PSA; and (c) disallowed certain PSA deferrals as described below.
Under the PSA, APS defers for future rate recovery or refund 90% of the difference between
actual retail fuel and purchased power costs and the Base Fuel Rate included in APS’ retail rates,
subject to specified parameters. APS absorbs the other 10% of variances between actual retail fuel
and purchased power costs and the Base Fuel Rate. The increase in APS’ Base Fuel Rate approved by
the ACC reduced the amount of fuel and purchased power costs subject to the 90/10 PSA sharing
arrangement. APS recovers PSA deferrals from its customers through PSA annual adjustors and
surcharges. The recovery of PSA deferrals recorded as revenue is offset dollar-for-dollar by the
amortization of those deferred expenses recorded as fuel and purchased power. The balance of APS’
PSA accumulated unrecovered
deferrals at September 30, 2007 was approximately $150 million. See Note 5 for additional
information about the ACC order and the PSA.
APS recorded PSA deferrals of (a) $45 million related to the 2005 Deferrals and (b) $79
million related to the 2006 Deferrals. In its order, the ACC (a) disallowed approximately
$14 million, including accrued interest ($8 million after income taxes), of the 2005 Deferrals and
(b) approved APS’ recovery of the balance of the 2005 Deferrals (approximately $34 million,
including accrued interest) through a temporary PSA surcharge over a twelve-month period beginning
July 1, 2007. The ACC directed the ACC staff to conduct a “prudence audit” of the 2006 Palo Verde
outage costs. Virtually all of the 2006 Deferrals were associated with a Unit 1 vibration issue.
On October 4, 2007, the ACC staff filed a report with the ACC that concludes that APS’ response to
the Unit 1 vibration issue was “reasonable and prudent.” APS continues to believe that the 2006
Deferrals were prudently incurred and, therefore, are recoverable.
Our consolidated net income for the three months ended September 30, 2007 was $209 million
compared with $184 million for the comparable prior-year period. The current period includes
income from discontinued operations of $8 million, which was related to income from the sale of
commercial properties at SunCor. Income from continuing operations increased $17 million in the
period-to-period comparison, reflecting the following changes in earnings:
•
Regulated Electricity Segment – Income from continuing operations increased
approximately $35 million primarily due to the effects of hotter weather on retail
sales; higher retail sales primarily due to customer growth and usage patterns;
impacts of the retail rate increase (see “Regulatory Matters” above); and income tax
benefits related to prior years resolved in 2007. These positive factors were
partially offset by higher operations and maintenance expense primarily for customer
service and regulatory programs and increased costs for generation, including the Palo
Verde performance improvement plan. In addition, higher fuel and purchased power
costs related to commodity price increases were offset by the deferral of such costs
in accordance with the PSA. See “Regulatory Matters” above.
•
Real Estate Segment – Income from continuing operations decreased approximately $19
million primarily due to lower sales of residential property and land parcels
resulting from the continued slowdown in the western United States real estate markets
and prior-year sales of certain joint venture assets. Income from discontinued
operations increased $8 million due to increased commercial property sales.
Additional details on the major factors that increased (decreased) net income for the three-month
period ended September 30, 2007 compared with the same period in 2006 are contained in the
following table (dollars in millions):
Higher retail sales primarily due to customer growth and
usage patterns, excluding weather effects
17
10
Impacts of retail rate increase (see discussion above):
Revenue increase related to higher Base Fuel Rate
114
70
Decreased deferred fuel and purchased power costs related to
higher Base Fuel Rate
(103
)
(63
)
Non-fuel rate increase
5
3
Net changes in fuel and purchased power costs related to prices:
Higher fuel and purchased power costs due to increased
prices
(39
)
(24
)
Increased deferred fuel and purchased power costs related to
increased prices
37
23
Operations and maintenance increases primarily due to:
Customer service costs and regulatory programs
(8
)
(5
)
Increased generation costs, including Palo Verde
performance improvement plan
(6
)
(4
)
Income tax benefits related to prior years resolved in 2007
—
10
Miscellaneous items, net
(4
)
(1
)
Increase in regulated electricity segment net income
40
35
Lower real estate segment contribution primarily due to decreased
sales of residential property and land parcels and prior-year sales
of certain joint venture assets
(31
)
(19
)
Other miscellaneous items, net
1
1
Increase in income from continuing operations
$
10
17
Discontinued operations primarily related to sales of
commercial real estate assets
8
Increase in net income
$
25
Regulated Electricity Segment Revenues
Regulated electricity segment revenues were $157 million higher for the three months ended
September 30, 2007 compared with the prior-year period primarily because of:
•
a $119 million increase in retail revenues due to retail rate increase effective
July 1, 2007;
•
a $36 million increase in retail revenues due to the effects of hotter weather;
•
a $22 million increase in retail revenues primarily related to customer growth and
usage patterns, excluding weather effects;
•
a $16 million increase in Off-System Sales due to higher prices and volumes;
•
a $44 million decrease in retail revenues related to recovery of PSA deferrals,
which had no earnings effect because of amortization of the same amount
recorded as fuel and purchased power expense (see “Regulatory Matters” above); and
•
an $8 million net increase due to miscellaneous factors.
Real Estate Segment Revenues
Real estate segment revenues were $50 million lower for the three months ended September 30,2007 compared with the prior-year period primarily because of:
•
a $48 million decrease in residential property sales due to the continued slowdown
in the western United States real estate markets;
•
a $4 million decrease in revenue primarily due to lower sales of land parcels; and
•
a $2 million net increase due to miscellaneous factors.
All Other Revenues
Marketing and trading revenues were $15 million higher for the three months ended September30, 2007 compared with the prior-year period primarily due to an increase in competitive retail
sales volumes in California.
Other revenues were $8 million higher for the three months ended September 30, 2007 compared
to the prior-year period primarily as a result of increased sales by APSES of energy related
products and services.
Our consolidated net income for the nine months ended September 30, 2007 was $304 million
compared with $309 million for the comparable prior-year period. Our net income includes income
from discontinued operations related primarily to sales of commercial properties by SunCor of $9
million in the current period and $2 million in the prior-year period. Income from continuing
operations decreased $12 million in the period-to-period comparison, reflecting the following
changes in earnings:
•
Regulated Electricity Segment — Income from continuing operations increased
approximately $26 million primarily due to higher retail sales primarily due to
customer growth and usage patterns; the effects of weather on retail sales; impacts of
the retail rate increase; and income tax benefits related to prior years resolved in
2007. These positive factors were partially offset by higher operations and
maintenance expense primarily due to increased generation costs, including the Palo
Verde performance improvement plan, customer service and regulatory programs; income
tax credits related to prior years resolved in 2006; lower other income, net of
expense, primarily due to miscellaneous asset sales in the prior-year period and
lower interest income as a result of lower investment balances; and a
regulatory disallowance. In addition, higher fuel and purchased power costs
related to commodity price increases were partially offset by the deferral of such
costs in accordance with the PSA. See “Regulatory Matters” above for further
discussion.
•
Real Estate Segment — Income from continuing operations decreased approximately
$40 million primarily due to lower sales of residential property and land parcels
resulting from the continued slowdown in the western United States real estate markets
and prior-year sales of certain joint venture assets. Income from discontinued
operations increased $7 million due to increased commercial property sales.
Additional details on the major factors that increased (decreased) net income for the nine-month
period ended September 30, 2007 compared with the same period in 2006 are contained in the
following table (dollars in millions):
Increase (Decrease)
Pretax
After Tax
Regulated electricity segment:
Higher retail sales primarily due to customer growth and usage
patterns, excluding weather effects
$
37
$
23
Effects of weather on retail sales
33
20
Impacts of retail rate increase (see discussion above):
Revenue increase related to higher Base Fuel Rate
114
70
Decreased deferred fuel and purchased power costs related
to
higher Base Fuel Rate
(103
)
(63
)
Non-fuel rate increase
5
3
Net changes in fuel and purchased power costs related to price:
Higher fuel and purchased power costs due to increased
prices
(80
)
(49
)
Increased deferred fuel and purchased power costs related
to increased prices
75
46
Regulatory disallowance (see “Regulatory Matters” above)
(14
)
(8
)
Operations and maintenance increases primarily due to:
Increased generation costs, including Palo Verde
performance improvement plan
(8
)
(5
)
Customer service costs and regulatory programs
(8
)
(5
)
Higher depreciation and amortization primarily due to
increased
plant balances
(8
)
(5
)
Lower other income, net of expense, primarily due to
lower interest income as a result of lower investment
balances and miscellaneous asset sales in the prior-year
period
(13
)
(8
)
Income tax benefits related to prior years resolved in 2007
—
13
Income tax credits related to prior years resolved in 2006
—
(10
)
Miscellaneous items, net
7
4
Increase in regulated electricity segment net income
37
26
Lower real estate segment contribution primarily due to decreased
sales of residential property and land parcels and prior year sales
of certain joint venture assets
(66
)
(40
)
Higher marketing and trading contribution primarily due to higher
competitive retail sales volumes in California and higher
mark-to-market gains because of changes in forward prices
6
4
Other miscellaneous items, net
(3
)
(2
)
Decrease in income from continuing operations
$
(26
)
(12
)
Discontinued operations primarily related to increased
sales of commercial real estate assets
7
Decrease in net income
$
(5
)
Regulated Electricity Segment Revenues
Regulated electricity segment revenues were $225 million higher for the nine months ended
September 30, 2007 compared with the prior-year period primarily because of:
a $119 million increase in retail revenues due to retail rate increase effective
July 1, 2007;
•
a $49 million increase in retail revenues primarily related to customer growth and
usage patterns, excluding weather effects;
•
a $45 million increase in retail revenues due to the effects of weather; and
•
a $12 million net increase due to miscellaneous factors.
Real Estate Segment Revenues
Real estate segment revenues were $145 million lower for the nine months ended September 30,2007 compared with the prior-year period primarily because of:
•
a $124 million decrease in residential property sales due to the continued slowdown
in western United States real estate markets;
•
a $23 million decrease in revenue primarily due to lower sales of land parcels; and
•
a $2 million net increase due to miscellaneous factors.
All Other Revenues
Marketing and trading revenues were $5 million higher for the nine months ended September 30,2007 compared with the prior-year period primarily because of higher competitive retail sales
volumes in California and higher mark-to-market gains because of changes in forward prices.
Other revenues were $8 million higher for the nine months ended September 30, 2007 compared to
the prior-year period primarily as a result of increased sales by APSES of energy-related products
and services.
LIQUIDITY AND CAPITAL RESOURCES — Pinnacle West Consolidated
Operating Cash Flows
Net cash provided by operating activities was $477 million for the nine months ended September30, 2007, compared to $283 million for the same period in 2006, an increase in cash provided of
$194 million. This change was primarily due to the 2006 return of cash collateral and margin cash
held as a result of changes in commodity prices, partially offset by lower cash contributions from
decreased sales of residential properties and land parcels due to the continued slowdown in western
United States real estate markets.
Investing Cash Flows
Net cash used for investing activities was $678 million for the nine months ended September30, 2007, compared to $560 million for the same period in 2006, an increase in cash used of $118
million. This change was primarily due to:
Approximately $208 million in proceeds received from the sale of Silverhawk in
2006;
•
An approximate $178 million increase in capital expenditures (see table and
discussion below);
•
An approximate $236 million decrease in the invested position, primarily at APS.
In 2006 we issued long-term debt and invested some of the proceeds in short-term
investment securities until they were later redeemed and the cash used for general
corporate purposes.
Capital Expenditure Requirements
The following table summarizes the actual capital expenditures for the nine months ended
September 30, 2006 and 2007 and estimated capital expenditures for the next three years (dollars in
millions):
Primarily information systems and facilities projects.
(b)
Consists primarily of capital expenditures for residential land development and
retail and office building construction reflected in “Real estate investments” on the
Condensed Consolidated Statements of Cash Flows.
Distribution and transmission capital expenditures are comprised of infrastructure additions
and upgrades, capital replacements, new customer construction and related information systems and
facility costs. Examples of the types of projects included in the forecast include lines,
substations, line extensions to new residential and commercial developments and upgrades to customer
information systems. Major transmission projects are driven by strong regional customer growth.
Generation capital expenditures are comprised of various improvements to APS’ existing fossil
and nuclear plants 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.
Environmental expenditures are estimated at approximately $80 million to $100 million per year for
2007, 2008 and
2009. Generation also includes nuclear fuel expenditures of approximately
$110 million for 2007, $40 million for 2008, and $100 million for 2009.
Installation of new steam generators in Palo Verde Unit 3 is in progress and is scheduled for completion
in the fourth quarter of 2007 at an approximate cost of $70 million (APS’ share). Approximately
$52 million of the Unit 3 steam generator costs have been incurred through September 30, 2007, with
the remaining $18 million included in the capital expenditures table above. Capital expenditures
will be funded with internally generated cash and/or external financings.
Financing Cash Flows and Liquidity
Net cash provided by financing activities was $157 million for the nine months ended September30, 2007, compared to $251 million for the same period in 2006, a decrease in cash provided of $94
million. This change was primarily due to:
•
An approximate $256 million decrease due to the 2006 issuance of approximately
$318 million of new long-term debt, net of redemptions, in order to fund our
construction program and for other general corporate purposes. During the first
nine months for 2007, we issued approximately $62 million of new long-term debt, net of refinancing.
•
An approximate $196 million increase in short-term borrowings to fund day-to-day
operations and liquidity needs.
Pinnacle West (Parent Company)
Our primary cash needs are for dividends to our shareholders and principal and interest
payments on our long-term debt. The level of our common stock dividends and future dividend growth
will be dependent on a number of factors including, but not limited to, payout ratio trends, free
cash flow and financial market conditions.
Our primary sources of cash are dividends from APS, external financings and cash distributions
from our other subsidiaries, primarily SunCor. An existing ACC order requires APS to maintain a
common equity ratio of at least 40% and prohibits APS from paying common stock dividends if the
payment would reduce its common equity below that threshold. As defined in the ACC order, the
common equity ratio is common equity divided by the sum of common equity and long-term debt,
including current maturities of long-term debt. At September 30, 2007, APS’ common equity ratio,
as defined, was approximately 54% (see Note 4).
In May 2007, Pinnacle West infused approximately $40 million of equity into APS, consisting of
the proceeds of stock issuances in 2006 under Pinnacle West’s Investors Advantage Plan (direct
stock purchase and dividend reinvestment plan) and employee stock plans.
On October 17, 2007, the Pinnacle West Board of Directors declared a quarterly dividend of
$0.525 per share of common stock, payable on December 3, 2007, to shareholders of record on
November 1, 2007.
At September 30, 2007, Pinnacle West had borrowings of $105 million under its revolving line
of credit. The amount drawn was used for general corporate purposes.
Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a
non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and
our subsidiaries. IRS regulations require us to contribute a minimum amount to the qualified plan.
We contribute at least the minimum amount required under IRS regulations, but no more than the
maximum tax-deductible amount. The minimum required funding takes into consideration the value of
plan assets and our pension obligation. The assets in the plan are comprised of fixed-income,
equity and short-term investments. Future year contribution amounts are dependent on fund
performance and fund valuation assumptions. We contributed $47 million in 2006. Our 2007 pension
contribution of $52 million has been made for the year. The contribution to our other
postretirement benefit plans in 2007 is estimated to be approximately $18 million, of which
approximately $15 million has been contributed through September 30, 2007. APS and other
subsidiaries fund their share of the contributions. APS’ share is approximately 96% of both plans.
APS
APS’ capital requirements consist primarily of capital expenditures and optional and mandatory
redemptions of long-term debt. APS pays for its capital requirements with cash from operations
and, to the extent necessary, external financings. APS has historically paid its dividends to
Pinnacle West with cash from operations. See “Pinnacle West (Parent Company)” above for a
discussion of the common equity ratio that APS must maintain in order to pay dividends to Pinnacle
West. As noted above, in May 2007, Pinnacle West infused approximately $40 million of equity into
APS.
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. APS requested the ACC to
increase (a) APS’ current short-term debt authorization (7% of APS’ capitalization) to (i) 7% of
APS’ capitalization plus (ii) $500 million and (b) APS’ current long-term debt authorization
(approximately $3.2 billion) to $4.2 billion in light of the projected growth of APS and its
customer base and the resulting projected financing needs. On October 30, 2007, the ACC issued a
financing order in which it approved APS’ requests, subject to specified parameters and procedures.
See “APS Financing Authorization” in Note 5.
See “Regulatory Matters” above and “PSA Modifications” in Note 5 for information regarding the
PSA approved by the ACC. Although APS defers actual retail fuel and purchased power costs on a
current basis, APS’ recovery of the deferrals from its ratepayers is subject to annual PSA
adjustments and, if necessary, periodic surcharge applications.
See “Cash Flow Hedges” in Note 10 for information related to collateral provided to us by
counterparties.
At September 30, 2007, APS had borrowings of $150 million under its revolving line of credit.
The amount drawn was used for general corporate purposes.
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 nine months ended September 30, 2007 and projected
capital
expenditures for the next three years. SunCor expects to fund its future capital
requirements with cash from operations and external financings.
SunCor entered into a secured construction loan on April 13, 2007, in the amount of $60
million, of which $35 million was outstanding at September 30, 2007. The loan matures on April 19,2009, and may be extended one year if certain conditions are met.
On July 31, 2007, SunCor borrowed $12 million under a new secured construction loan. The loan
matures on July 31, 2009, and may be extended annually up to two years.
El Dorado expects minimal capital requirements over the next three years and intends to focus
on prudently realizing the value of its existing investments.
APSES expects minimal capital expenditures over the next three years.
See “Overview” above and Note 4 for discussion of Pinnacle West Marketing & Trading, the
Company’s marketing and trading subsidiary, which began activity in February 2007.
Debt Provisions
Pinnacle West’s and APS’ debt covenants related to their respective bank financing
arrangements include debt to capitalization ratios. Certain of APS’ bank financing arrangements
also include an interest coverage test. Pinnacle West and APS comply with these covenants and each
anticipates it will continue to meet these and other significant covenant requirements. For both
Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total
consolidated capitalization not exceed 65%. At September 30, 2007, the ratio was approximately 49%
for Pinnacle West and 46% for APS. The provisions regarding interest coverage require a minimum
cash coverage of two times the interest requirements for APS. The interest coverage was
approximately 4.8 times under APS’ bank financing agreements as of September 30, 2007. Failure to
comply with such covenant levels would result in an event of default which, generally speaking,
would require the immediate repayment of the debt subject to the covenants and could cross-default
other debt. See further discussion of “cross-default” provisions below.
Neither Pinnacle West’s nor APS’ financing agreements contain “rating triggers” that would
result in an acceleration of the required interest and principal payments in the event of a rating
downgrade. However, in the event of a rating downgrade, Pinnacle West and/or APS may be subject to
increased interest costs under certain financing agreements.
All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in
defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or
APS were to default under certain other material agreements. All of APS’ bank agreements contain
cross-default provisions that would result in defaults and the potential acceleration of payment
under these bank agreements if APS were to default under certain other material agreements.
Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings.
The ratings of securities of Pinnacle West and APS as of November 2, 2007 are shown below.
The ratings reflect the respective views of the rating agencies, from which an explanation of the
significance of their ratings may be obtained. There is no assurance that these ratings will
continue for any given period of time. The ratings may be revised or withdrawn entirely by the
rating agencies, if, in their respective judgments, circumstances so warrant. Any downward
revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’ securities
and serve to increase the cost of and access to capital. It may also require additional collateral
related to certain derivative instruments (see Note 10).
Moody’s
Standard & Poor’s
Fitch
Pinnacle West
Senior unsecured (a)
Baa3 (P)
BB+ (prelim)
N/A
Commercial paper
P-3
A-3
F-3
Outlook
Negative
Stable
Stable
APS
Senior unsecured
Baa2
BBB-
BBB
Secured lease obligation bonds
Baa2
BBB-
BBB
Commercial paper
P-2
A-3
F-2
Outlook
Negative
Stable
Stable
(a)
Pinnacle West has a shelf registration under SEC Rule 415. Pinnacle West
currently has no outstanding, rated senior unsecured securities. However, Moody’s
assigns a provisional (P) rating and Standard & Poor’s assigns a preliminary (prelim)
rating to the senior unsecured securities that can be issued under such shelf
registration.
Off-Balance Sheet Arrangements
In 1986, APS entered into agreements with three separate VIE lessors in order to sell and
lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in
accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly,
do not consolidate them.
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 September 30, 2007, APS would have been required to
assume approximately $208 million of debt and pay the equity participants approximately $174
million.
We have issued parental guarantees and letters of credit and obtained surety bonds on behalf
of our subsidiaries. Our parental guarantees for Pinnacle West Marketing & Trading relate to
commodity energy products. Our credit support instruments enable APSES to offer commodity energy
and energy-related products. Non-performance or non-payment under the original contract by our
subsidiaries would require us to perform under the guarantee or surety bond. No liability is
currently recorded on the Condensed Consolidated Balance Sheets related to Pinnacle West’s current
outstanding guarantees on behalf of our subsidiaries. Our guarantees have no recourse or
collateral provisions to allow us to recover amounts paid under the guarantees. We generally agree
to indemnification provisions related to liabilities arising from or related to certain of our
agreements, with limited exceptions depending on the particular agreement. See Note 15 for
additional information regarding guarantees and letters of credit.
Contractual Obligations
Our future contractual obligations have not changed materially from the amounts disclosed in
Part II, Item 7 of the 2006 Form 10-K, with the exception of our aggregate fuel and purchased power
commitments, which increased from approximately $2.6 billion at December 31, 2006 to $3.5 billion
at September 30, 2007 as follows (dollars in billions):
2007
2008-2009
2010-2011
Thereafter
Total
$0.5
$
0.7
$
0.5
$
1.8
$
3.5
See Note 4 for a list of payments due on total long-term debt and capitalized lease
requirements.
Given our adoption of FIN 48, we are now required to include uncertain tax positions in our
contractual obligations disclosure. As of September 30, 2007, we have uncertain tax positions of
approximately $210 million and we expect a majority of these positions to be settled within the
next twelve months. See Note 8 for additional information.
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, 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 2006 Form 10-K. See “Critical Accounting Policies” in Item 7 of the
2006 Form 10-K for further details about our critical accounting policies.
OTHER ACCOUNTING MATTERS
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This guidance
establishes a framework for measuring fair value and expands disclosures about fair value
measurements. The Statement is effective for us on January 1, 2008. We are currently evaluating
this new guidance and preparing for the new disclosure requirements.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets
and Financial Liabilities.” SFAS No. 159 provides companies with an option to report selected
financial assets and liabilities at fair value. SFAS No. 159 is effective for us on January 1,2008. We are currently evaluating this new guidance.
See Note 8 for a discussion of FIN 48 on accounting for uncertainty in income taxes, which we
adopted January 1, 2007. The effect of applying the new guidance was not significantly different
in terms of tax impacts from the application of our previous policy. Accordingly, the impact to
retained earnings upon adoption was immaterial.
In
April 2007, the FASB issued FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation
No. 39, Offsetting of Amounts Related to Certain Contracts” (FSP FIN 39-1). Under FSP FIN 39-1, a
reporting entity is permitted to offset the fair value amounts recognized for cash collateral paid
or cash collateral received against the fair value amounts recognized for derivative instruments
executed with the same counterparty under a master netting arrangement. This new guidance is
effective for us on January 1, 2008, with early application permitted. We are currently evaluating
the impacts of FSP FIN 39-1 on our balance sheet. We do not expect the guidance to have an impact
on our results of operations or cash flows.
PINNACLE WEST CONSOLIDATED — FACTORS AFFECTING
OUR FINANCIAL OUTLOOK
Factors Affecting Operating Revenues, Fuel and Purchased Power Costs
General Electric operating revenues are derived from sales of electricity in regulated retail
markets in Arizona and from competitive retail and wholesale power markets in the western United
States. For the years 2004 through 2006, retail electric revenues comprised approximately 82% of
our total electric operating revenues. Our electric operating revenues are affected by electricity
sales volumes related to customer mix, customer growth, average usage per customer, electricity
rates and tariffs, variations in weather from period to period, and amortization of PSA deferrals.
Competitive retail sales of energy and energy-related products and services are made by APSES in
certain western states that have opened to competition. Off-System Sales of excess generation
output, purchased power and natural gas are included in regulated electricity segment revenues and
related fuel and purchased power because they are credited to APS’ retail customers through the
PSA. These revenue transactions are affected by the availability of excess generation or other
energy resources and wholesale market conditions, including demand and prices. Competitive
wholesale transactions are made by the marketing and trading group through structured trading
opportunities involving matched sales and purchases of commodities.
Retail Rate Proceedings The ACC regulates APS’ retail electric rates. Our profitability is
affected by the rates APS may charge and the timely recovery of costs through those rates. APS’
capital expenditure requirements, which are discussed above under “Liquidity and Capital
Resources,” are substantial because of the significant customer growth in APS’ service territory,
highlighting APS’ need for the timely recovery of these and other expenditures through rates. As
discussed in greater detail in Note 5, on June 28, 2007, the ACC issued an order in a general rate
case that APS filed in late 2005. Additionally, the ACC directed the ACC staff to conduct a
“prudence audit” of 2006 Palo Verde outage costs. Virtually all of the deferrals related to these
2006 outage costs were associated with a Unit 1 vibration issue. On October 4, 2007, the ACC staff
filed a report with the ACC that concludes that APS’ response to the Unit 1 vibration issue was
“reasonable and prudent.” APS continues to believe that these
costs were prudently incurred and that the 2006 Deferrals, totaling approximately $79 million, are, therefore, recoverable.
Fuel and Purchased Power Costs Fuel and purchased power costs included on our income
statements are impacted by our electricity sales volumes, existing contracts for purchased power
and generation fuel, our power plant performance, transmission availability or constraints,
prevailing market prices, new generating plants being placed in service in our market areas, our
hedging program for managing such costs and, since April 1, 2005, PSA deferrals and the
amortization thereof. See “PSA Modifications” and “PSA Deferrals Related to Palo Verde Outages” in
Note 5 for information regarding the PSA, including the 2006 Deferrals. APS’ recovery of PSA
deferrals from its ratepayers is subject to annual PSA adjustments and, if necessary, periodic
surcharge applications.
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 for the
nine-month period ended September 30, 2007 was 3.5% compared with the prior-year period. Customer
growth averaged 4.1% a year for the three years 2004 through 2006, and we currently expect customer
growth to average about 3.0% per year from 2007 to 2009. For the three years 2004 through 2006,
APS’ actual retail electricity sales in kilowatt-hours grew at an average rate of 4.2%; adjusted to
exclude effects of weather variations, such retail sales growth averaged 4.6% a year. We currently
estimate that total retail electricity sales in kilowatt-hours will grow 2.8% on average, during
2007 through 2009, before excluding the effects of weather variations. We currently expect our
retail sales growth in 2007 to be below average because of potential effects on customer growth and
usage from the slowdown in the residential housing market and retail rate increases (see Note 5).
Actual sales growth, excluding weather-related variations, may differ from our projections as
a result of numerous factors, such as economic conditions, customer growth, usage patterns and
responses to retail price changes. Our experience indicates that a reasonable range of variation
in our kilowatt-hour sales projection attributable to such economic factors can result in increases
or decreases in annual net income of up to $10 million.
Weather In forecasting retail sales growth, we assume normal weather patterns based on
historical data. Historical extreme weather variations have resulted in annual variations in net
income in excess of $20 million. However, our experience indicates that the more typical
variations from normal weather can result in increases or decreases in annual net income of up to
$10 million.
Wholesale Market Our marketing and trading activities focus primarily on managing APS’ risks
relating to fuel and purchased power costs in connection with its costs of serving Native Load
customer demand. Our marketing and trading activities include, subject to specified parameters,
marketing, hedging and trading in electricity, fuels and emission allowances and credits. See
“FERC Rate Case” in Note 5 for information regarding APS’ recent filing with the FERC requesting an
increase in transmission rates.
Other Factors Affecting Financial Results
Operations and Maintenance Expenses Operations and maintenance expenses are impacted by
growth, power plant additions and operations, inflation, outages, higher-trending pension and other
postretirement benefit costs and other factors.
Depreciation and Amortization Expenses Depreciation and amortization expenses are impacted by
net additions to utility plant and other property, which include generation construction, changes
in depreciation and amortization rates, and changes in regulatory asset amortization.
Property Taxes Taxes other than income taxes consist primarily of property taxes, which are
affected by the value of property in-service and under construction, assessed valuation ratios, and
tax rates. The average property tax rate for APS, which currently owns the majority of our
property, was 8.9% of assessed value for 2006 and 9.2% for 2005. We expect property taxes to
increase as new power plants and additions to our transmission and distribution facilities are
included in the property tax base.
Interest Expense Interest expense is affected by the amount of debt outstanding and the
interest rates on that debt. The primary factors affecting borrowing levels are expected to be our
capital expenditures, long-term debt maturities, and internally generated cash flow. Capitalized
interest offsets a portion of interest expense while capital projects are under construction. We
stop accruing capitalized interest on a project when it is placed in commercial operation.
Retail Competition Although some very limited retail competition existed in Arizona in 1999
and 2000, there are currently no active retail electric service providers providing unbundled
energy or other utility services to APS’ customers. We cannot predict when, and the extent to
which, additional electric service providers will re-enter APS’ service territory.
Subsidiaries SunCor’s net income was $61 million in 2006, $56 million in 2005, and $45
million in 2004. See Note 17 for further discussion. We currently expect SunCor’s net income in
2007 to be approximately $20 million. This estimate reflects the continued slowdown in the western
United States real estate markets, as well as deteriorating credit markets in the second half of
2007.
APSES’ and El Dorado’s historical results are not indicative of future performance.
General Our financial results may be affected by a number of broad factors. See
“Forward-Looking Statements” below for further information on such factors, which may cause our
actual future results to differ from those we currently seek or anticipate.
Market Risks
Our operations include managing market risks related to changes in interest rates, commodity
prices and investments held by our nuclear decommissioning trust fund.
Interest Rate and Equity Risk
We have exposure to changing interest rates. Changing interest rates will affect interest
paid on variable-rate debt and the market value of fixed income securities held by our nuclear
decommissioning trust fund. The nuclear decommissioning trust fund also has risks associated with
the changing market value of its investments. Nuclear decommissioning costs are recovered in
regulated electricity prices.
Commodity Price Risk
We are exposed to the impact of market fluctuations in the commodity price and transportation
costs of electricity, natural gas and emissions allowances. Our ERMC, consisting of officers and
key management personnel, oversees company-wide energy risk management activities and monitors the
results of marketing and trading activities to ensure compliance with our stated energy risk
management and trading policies. We manage risks associated with these market fluctuations by
utilizing various commodity instruments that qualify as derivatives, including exchange-traded
futures and options and over-the-counter forwards, options and swaps. As part of our risk
management program, we use such instruments to hedge purchases and sales of electricity, fuels and
emissions allowances and credits. The changes in market value of such contracts have a high
correlation to price changes in the hedged commodities. 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:
•
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 activities.
The following tables show the pretax changes in mark-to-market value of our non-trading and
trading derivative positions for the nine months ended September 30, 2007 and 2006 (dollars in
millions):
Mark-to-market of net positions
at beginning of period
$
(62
)
$
77
$
335
$
181
Recognized in earnings:
Change in mark-to-market
gains (losses) for future
period
deliveries
1
(8
)
(9
)
(3
)
Mark-to-market
gains realized including
ineffectiveness during the
period
(1
)
(12
)
(3
)
(2
)
Decrease (increase) in
regulatory asset
28
—
(76
)
—
Recognized in OCI:
Change in mark-to-market
for future period deliveries —
losses (a)
(11
)
(4
)
(277
)
(66
)
Mark-to-market
(gains) losses realized during
the period
18
(19
)
1
(17
)
Change in valuation techniques
—
—
—
—
Mark-to-market of net positions
at end of period
$
(27
)
$
34
$
(29
)
$
93
(a)
The increases (decreases) in regulated mark-to-market recorded in OCI are due
primarily to increases (decreases) in forward natural gas prices.
The tables below show the fair value of maturities of our non-trading and trading derivative
contracts (dollars in millions) at September 30, 2007 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 2006 Form 10-K for more discussion of our valuation methods.
Regulated Electricity
Years
Total fair
Source of Fair Value
2007
2008
2009
2010
thereafter
value
Prices actively quoted
$
(13
)
$
(12
)
$
2
$
3
$
—
$
(20
)
Prices provided by
other external sources
—
(8
)
(4
)
(3
)
—
(15
)
Prices based on models
and other valuation
methods
Prices based on models
and other valuation
methods
—
—
—
—
—
—
—
Total by maturity
$
9
$
20
$
—
$
—
$
3
$
2
$
34
The table below shows the impact that hypothetical price movements of 10% would have on the
market value of our risk management and trading assets and liabilities included on Pinnacle West’s
Condensed Consolidated Balance Sheets at September 30, 2007 and December 31, 2006 (dollars in
millions):
To the extent the amounts are eligible for inclusion in the PSA, the amounts
are recorded as either a regulatory asset or liability.
(b)
These contracts are hedges of our forecasted purchases of natural gas and
electricity. The impact of these hypothetical price movements would substantially
offset the impact that these same price movements would have on the physical exposures
being hedged.
Credit Risk
We are exposed to losses in the event of non-performance or non-payment by counterparties.
See Note 1, “Derivative Accounting” in Item 8 of our 2006 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
Regulatory Matters
See “Pinnacle West Consolidated – Results of Operations — Regulatory Matters” above for
information about the ACC’s order in APS’ general retail rate case and the PSA.
APS’ net income for the three months ended September 30, 2007 was $204 million compared with
$168 million for the comparable prior-year period. The $36 million increase was primarily due to
the effects of hotter weather on retail sales; higher retail sales primarily due to customer growth
and usage patterns; impacts of the retail rate increase (see Note 5); and income tax benefits
related to prior years resolved in 2007. These positive factors were partially offset by higher
operations and maintenance expense primarily for customer service and regulatory programs and
increased costs for generation, including the Palo Verde performance improvement plan. In
addition, higher fuel and purchased power costs related to commodity price increases were offset by
the deferral of such costs in accordance with the PSA. See Note 5 for further discussion.
Additional details on the major factors that increased (decreased) net income for the three-month
period ended September 30, 2007 compared with the same period in 2006 are contained in the
following table (dollars in millions):
Increase (Decrease)
Pretax
After Tax
Effects of hotter weather on retail sales
$
27
$
16
Higher retail sales primarily due to customer growth and usage
patterns, excluding weather effects
17
10
Impacts of
retail rate increase (see Note 5):
Revenue increase related to higher Base Fuel Rate
114
70
Decreased deferred fuel and purchased power costs related to
higher Base Fuel Rate
(103
)
(63
)
Non-fuel rate increase
5
3
Net changes in fuel and purchased power costs related to prices:
Higher fuel and purchased power costs due to increased prices
(39
)
(24
)
Increased deferred fuel and purchased power costs related to
increased prices
37
23
Operations and maintenance increases primarily due to:
Customer service costs and regulatory programs
(10
)
(6
)
Increased generation costs, including Palo Verde
performance improvement plan
(6
)
(4
)
Income tax benefits related to prior years resolved in 2007
Regulated electricity revenues were $157 million higher for the three months ended September30, 2007 compared with the prior-year period primarily because of:
•
a $119 million increase in retail revenues due to retail rate increase effective
July 1, 2007;
•
a $36 million increase in retail revenues due to the effects of hotter weather;
•
a $22 million increase in retail revenues primarily related to customer growth and
usage patterns, excluding weather effects;
•
a $16 million increase in Off-System Sales due to higher prices and volumes;
•
a $44 million decrease in retail revenues related to recovery of PSA deferrals,
which had no earnings effect because of amortization of the same amount recorded as
fuel and purchased power expense (see Note 5); and
•
an $8 million net increase due to miscellaneous factors.
APS’
net income for the nine months ended September 30, 2007 was $284 million compared with
$257 million for the comparable prior-year period. The $27 million increase was primarily due to
higher retail sales primarily due to customer growth and usage patterns; the effects of weather on
retail sales; impacts of the retail rate increase; and income tax benefits related to prior years
resolved in 2007. These positive factors were partially offset by higher operations and
maintenance expense primarily due to increased generation costs, including the Palo Verde
performance improvement plan and customer service and regulatory programs; income tax credits
related to prior years resolved in 2006; lower other income, net of expense, primarily due to
miscellaneous asset sales in the prior-year period and lower interest income as a result of lower
investment balances; and a regulatory disallowance. In addition, higher fuel and purchased power
costs related to commodity price increases were partially offset by the deferral of such costs in
accordance with the PSA. See Note 5 for further discussion.
Additional details on the major factors that increased (decreased) net income for the
nine-month period ended September 30, 2007 compared with the same period in 2006 are contained in
the following table (dollars in millions):
Increase (Decrease)
Pretax
After Tax
Higher retail sales primarily due to customer growth and usage
patterns, excluding weather effects
$
37
$
23
Effects of weather on retail sales
33
20
Impacts of
retail rate increase (see Note 5):
Revenue increase related to higher Base Fuel Rate
114
70
Decreased deferred fuel and purchased power costs related to
higher Base Fuel Rate
(103
)
(63
)
Non-fuel rate increase
5
3
Net changes in fuel and purchased power costs related to price:
Higher fuel and purchased power costs due to increased prices
(80
)
(49
)
Increased deferred fuel and purchased power costs related
to increased prices
75
46
Regulatory disallowance (see “Regulatory Matters” above)
(14
)
(8
)
Operations and maintenance increases primarily due to:
Increased generation costs, including the Palo Verde
performance improvement plan
(8
)
(5
)
Customer service costs and regulatory programs
(7
)
(4
)
Higher depreciation and amortization primarily due to increased
plant balances
(8
)
(5
)
Lower other income, net of expense, primarily due to
lower interest income as a result of lower investment
balances and miscellaneous asset sales in the prior-year period
(10
)
(6
)
Income tax benefits related to prior years resolved in 2007
—
11
Income tax credits related to prior years resolved in 2006
—
(7
)
Other miscellaneous items, net
2
1
Increase in net income
$
36
$
27
Regulated Electricity Revenues
Regulated electricity revenues were $225 million higher for the nine months ended September30, 2007 compared with the prior-year period primarily because of:
•
a $119 million increase in retail revenues due to retail rate increase effective
July 1, 2007;
•
a $49 million increase in retail revenues primarily related to customer growth and
usage patterns, excluding weather effects;
•
a $45 million increase in retail revenues due to the effects of weather; and
•
a $12 million net increase due to miscellaneous factors.
LIQUIDITY AND CAPITAL RESOURCES – Arizona Public Service Company
Operating Cash Flows
Net cash provided by operating activities was $561 million for the nine months ended
September 30, 2007, compared to $286 million for the same period in 2006, an increase in cash
provided of $276 million. This change was primarily due to the 2006 return of cash collateral and
margin cash held as a result of changes in commodity prices.
Investing Cash Flows
Net cash used for investing activities was $667 million for the nine months ended September30, 2007, compared to $694 million for the same period in 2006, a decrease in cash used of $27
million. This change was primarily due to:
•
An approximate $236 million decrease in APS’ invested position. In 2006, we
issued long-term debt and invested some of the proceeds in short-term investment
securities until they were later redeemed and the cash used for general corporate
purposes; partially offset by
•
An approximate $201 million increase in capital expenditures. See “capital
expenditures” chart, Liquidity and Capital Resources — Pinnacle West Consolidated.
Financing Cash Flows and Liquidity
Net cash provided by financing activities was $61 million for the nine months ended September30, 2007, compared to $476 million for the same period in 2006, a decrease in cash provided of $415
million. This change was primarily due to:
•
An approximate $394 million decrease due to the issuance
of approximately $393
million of new long-term debt, net of redemptions, in order to fund our
construction program and for other general corporate purposes. During the first
nine months of 2007, APS has not issued any new long-term debt.
•
An approximate $170 million decrease due to decreased equity infusions from
Pinnacle West; and
•
An approximate $150 million increase in short-term borrowings to fund day-to-day
operations and liquidity needs.
For additional discussion see “LIQUIDITY AND CAPITAL RESOURCES – Pinnacle West Consolidated.”
APS’ future contractual obligations have not changed materially from the amounts disclosed in
Part II, Item 7 of the 2006 Form 10-K, with the exception of our aggregate fuel and purchased power
commitments, which increased from approximately $2.5 billion at December 31, 2006 to $3.4 billion
at September 30, 2007 as follows (dollars in billions):
2007
2008-2009
2010-2011
Thereafter
Total
$0.4
$
0.7
$
0.5
$
1.8
$
3.4
See Note 4 for a list of APS’ payments due on total long-term debt and capitalized lease
requirements.
Given our adoption of FIN 48, APS is now required to include uncertain tax positions in the
contractual obligations disclosure. As of September 30, 2007, APS has uncertain tax positions of
approximately $204 million and expects a majority of these positions will be settled within the
next twelve months. See Note 8 for additional information.
FORWARD-LOOKING STATEMENTS
This document contains forward-looking statements based on current expectations, and neither
Pinnacle West nor APS assumes any obligation to update these statements or make any further
statements on any of these issues, except as required by applicable law. These forward-looking
statements are often identified by words such as “estimate,”“predict,”“hope,”“may,”“believe,”“anticipate,”“plan,”“expect,”“require,”“intend,”“assume” and similar words. Because actual
results may differ materially from expectations, we caution readers not to place undue reliance on
these statements. A number of factors could cause future results to differ materially from
historical results, or from results or outcomes currently expected or sought by Pinnacle West or
APS. In addition to the Risk Factors described in Item 1A of the 2006 Form 10-K, these factors
include, but are not limited to:
•
state and federal regulatory and legislative decisions and actions, particularly
those affecting our rates and our recovery of fuel and purchased power costs;
•
the ongoing restructuring of the electric industry, including the introduction of
retail electric competition in Arizona and decisions impacting wholesale competition;
•
the outcome of regulatory, legislative and judicial proceedings, both current and
future, relating to the restructuring and environmental matters (including those
relating to climate change);
•
market prices for electricity and natural gas;
•
power plant performance and outages;
•
transmission outages and constraints;
•
weather variations affecting local and regional customer energy usage;
•
customer growth and energy usage;
•
regional economic and market conditions, including the results of litigation and
other proceedings resulting from the California energy situation, volatile fuel and
purchased power costs and the completion of generation and transmission construction in
the region, which could affect customer growth and the cost of power supplies;
•
the cost of debt and equity capital and access to capital markets;
•
current credit ratings remaining in effect for any given period of time;
our ability to compete successfully outside traditional regulated markets (including
the wholesale market);
•
the performance of our marketing and trading activities due to volatile market
liquidity and any deteriorating counterparty credit and the use of derivative contracts
in our business (including the interpretation of the subjective and complex accounting
rules related to these contracts);
•
changes in accounting principles generally accepted in the United States of America
and the interpretation of those principles;
•
the performance of the stock market and the changing interest rate environment,
which affect the value of our nuclear decommissioning trust, pension, and other
postretirement benefit plan assets, the amount of required contributions to Pinnacle
West’s pension plan and contributions to APS’ nuclear decommissioning trust funds, as
well as the reported costs of providing pension and other postretirement benefits;
•
technological developments in the electric industry;
•
the strength of the real estate market in SunCor’s market areas, which include
Arizona, Idaho, New Mexico and Utah; and
•
other uncertainties, all of which are difficult to predict and many of which are
beyond the control of Pinnacle West and APS.
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.
Item 4. CONTROLS AND PROCEDURES
(a) Disclosure Controls and Procedures
The term “disclosure controls and procedures” means controls and other procedures of a company
that are designed to ensure that information required to be disclosed by a company in the reports
that it files or submits under the Securities Exchange Act of 1934, as amended (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 September 30, 2007. Based on that evaluation, Pinnacle West’s Chief
Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s
disclosure controls and procedures were effective.
APS’ management, with the participation of APS’ Chief Executive Officer and Chief Financial
Officer, have evaluated the effectiveness of APS’ disclosure controls and procedures as of
September 30, 2007. Based on that evaluation, APS’ Chief Executive Officer and Chief Financial
Officer have concluded that, as of that date, APS’ disclosure controls and procedures were
effective.
(b) 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 September 30, 2007 that materially affected, or is reasonably likely to
materially affect, Pinnacle West’s or APS’ internal control over financial reporting.
See Note 12 in regard to pending or threatened litigation or other disputes. See also
“Federal Implementation Plan – Four Corners FIP” under Item 5 below.
Item 1A. RISK FACTORS
In addition to the other information set forth in this report, you should carefully consider
the factors discussed in Part I, “Item 1A. Risk Factors” in the 2006 Form 10-K, which could
materially affect the business, financial condition, cash flows or future results of APS and
Pinnacle West. The risks described in the 2006 Form 10-K are not the only risks facing APS and
Pinnacle West. Additional risks and uncertainties not currently known to us or that we currently
deem to be immaterial also may materially adversely affect the business, financial condition, cash
flows and/or operating results of APS and Pinnacle West.
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.
Regulatory Matters
See Note 5 for a discussion of regulatory developments.
Environmental Matters
See “Environmental Matters – Superfund” in Note 12 for a discussion of a Superfund site.
Regional Haze Rules
On April 22, 1999, the EPA announced final regional haze rules. These regulations require
states to submit state implementation plans (SIPs) by December 2007 to demonstrate “reasonable
progress” towards achieving natural visibility conditions in certain “Class I Areas,” including
several on the Colorado Plateau. The SIP is required to consider and potentially apply “best
available retrofit technology” (BART) for certain older major stationary sources. The rules allow
nine western states and Indian tribes to follow an alternate implementation plan and schedule for
the Class I Areas. This alternate implementation plan is known as the Annex Rule.
On June 15, 2005, the EPA issued the Clean Air Visibility Rule, which amends the 1999 regional
haze rules by providing guidelines, known as the BART guidelines, for states to use in determining
which facilities must install controls and the type of controls the facilities must use. The EPA
also issued a Revised Annex Rule on October 13, 2006 to address a previous challenge and court
remand of that rule.
ADEQ is currently undertaking a rulemaking process to amend its SIP to reconcile it with the
Revised Annex Rule and to implement the Clean Air Visibility Rule requirements. ADEQ’s Regional
Haze SIPs are due to EPA Region 9 in December 2007. As part of the rulemaking process, ADEQ will
require certain sources in the state to conduct BART analyses. Cholla and West Phoenix received
letters from ADEQ asserting that the plants are potentially subject to BART and requesting that we
either perform a BART analysis on each plant or provide information demonstrating that we are not
subject to BART. We are currently performing a BART analysis for Cholla and expect to complete and
submit it to ADEQ by the end of December 2007. Because we believe that ADEQ made several errors in
its baseline modeling for West Phoenix, we re-performed the baseline modeling using correct input
and have determined that West Phoenix is not subject to BART. We submitted these findings for West
Phoenix to ADEQ and are awaiting its response. In addition, EPA Region 9 has requested us to
perform a BART analysis for Four Corners. We are performing that analysis and expect to submit it
to the EPA by the end of November 2007.
Once the analyses and BART recommendations for Cholla and Four Corners are submitted to ADEQ
and the EPA respectively, the agencies will review the submissions and determine what, if anything,
constitutes BART for the plants and will incorporate those determinations into implementation plans
for the plants. We expect to receive the agencies’ final determinations in 2008. Implementation of
any such recommendations would likely occur over a five-year period. While we continue to monitor
this matter, at the present time we cannot predict the outcome of our BART analyses, the nature of
the BART controls, if any, the agencies may mandate, or the resulting financial or operational
impact.
Federal Implementation Plan (“FIP”)
In September 1999, the EPA proposed FIPs to set air quality standards at certain power plants,
including Four Corners and the Navajo Generating Station. On September 12, 2006, the EPA proposed
revised FIPs to establish air quality standards at both of these plants.
Four Corners FIP
On April 30, 2007, the EPA adopted a source specific FIP to set air quality standards at Four
Corners. See “Environmental Regulation – Federal Implementation Plan” in Part 1, Item 1 of the
2006 Form 10-K for additional information regarding the procedural and litigation issues leading to
the EPA’s adoption of the FIP. The FIP essentially federalizes the requirements contained in the
New Mexico State Implementation Plan, which Four Corners has historically followed. The FIP also
includes a requirement to maintain and enhance dust suppression methods. On July 2, 2007, APS
filed a petition for review in the United States District Court of Appeals for the Tenth Circuit
seeking revisions to the FIP to clarify certain requirements and allow operational flexibility.
The Sierra Club has intervened in this action. On July 6, 2007, the Sierra Club and other parties
filed a petition for review with the same court challenging the FIP’s compliance with the Clean Air
Act and we have intervened in their action. Although we cannot predict the outcome of these
matters, we do not believe that they will have a material adverse impact on our financial position,
results of operations or cash flows.
Navajo Generating Station FIP
The proposed FIP for the Navajo Generating Station is still pending. APS cannot currently
predict the effect of this proposed FIP on the Company’s financial position, results of operations
or cash flows, or whether the proposed FIP will be adopted in its current form.
Climate Change Initiative
On February 26, 2007, five western states (Arizona, California, New Mexico, Oregon and
Washington) entered into an accord, called the Western Regional Climate Action Initiative, later
renamed the Western Climate Initiative (the “Initiative”), to reduce greenhouse gas emissions
from automobiles and certain industries, including utilities. Since then, Utah, British Columbia
and Manitoba have joined the Initiative. In August 2007, the Initiative participants set a goal of
reducing greenhouse gas emissions 15% below 2005 levels by 2020. By August 2008, the Initiative
participants intend to develop a plan for implementation of this goal. Any such implementation
would require independent action by each individual state’s (or province’s) legislature or Governor
to adopt a version of the plan. The Company is currently developing a climate change management
plan to address these and related issues. While we continue to monitor the impact of the
Initiative, at the present time we cannot predict what form it will ultimately take, whether it
will be implemented or, if it is implemented, what impact it will have on our operations.
Description of Annual Stock Grants to
Non-Employee Directors
10.2a
Pinnacle West
Description of Stock Grant to W. Douglas Parker
10.3a
Pinnacle West
APS
Form of Key Executive Employment and Severance
Agreement between Pinnacle West and certain officers of Pinnacle West and its
subsidiaries
10.4ab
Pinnacle West
APS
Form of Amended and Restated Key Executive
Employment and Severance Agreement between
Pinnacle West and certain officers
of Pinnacle West and its subsidiaries
12.1
Pinnacle West
Ratio of Earnings to Fixed Charges
12.2
APS
Ratio of Earnings to Fixed Charges
12.3
Pinnacle West
Ratio of Earnings to Combined Fixed Charges
and Preferred Stock Dividend Requirements
31.1
Pinnacle West
Certificate of William J. Post, Chief
Executive Officer, pursuant to Rule 13a-14(a)
and Rule 15d-14(a) of the Securities Exchange
Act, as amended
31.2
Pinnacle West
Certificate of Donald E. Brandt, Chief
Financial Officer, pursuant to Rule 13a-14(a)
and Rule 15d-14(a) of the Securities Exchange
Act, as amended
a
Management contract or compensatory plan or arrangement
to be filed as an exhibit pursuant to Item 6 of Form 10-Q.
b
The Company has entered into identical Amended and
Restated Key Executive Employment and Severance Agreements (“KEESAs”) with each
of its executive officers.
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
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:
Exhibit
Date
No.
Registrant(s)
Description
Previously
Filed as
Exhibit1
Filed
3.1
Pinnacle West
Articles of
Incorporation,
restated as of May23, 2007
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.