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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 has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files).
PINNACLE WEST CAPITAL CORPORATION
Yes þ
No o
ARIZONA PUBLIC SERVICE COMPANY
Yes o
No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large
accelerated filer,”“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act.
PINNACLE WEST CAPITAL CORPORATION
Large accelerated filer þ
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
ARIZONA PUBLIC SERVICE COMPANY
Large accelerated filer o
Accelerated filer o
Non-accelerated filer þ
Smaller reporting company o
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 April 25, 2011: 109,016,655
ARIZONA PUBLIC SERVICE COMPANY
Number of shares of common stock, $2.50
par value, outstanding as of April 25,2011: 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 provided by Pinnacle West Capital Corporation
(“Pinnacle West”) and Arizona Public Service Company (“APS”). Any use of the words “Company,”“we,” and “our” refer to Pinnacle West. Each registrant is providing 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 providing any
information that does not relate to such registrant, and therefore makes no representation as to
any such information. The information required with respect to each company is set forth within
the applicable items. Item 1 of this report includes Condensed Consolidated Financial Statements
of Pinnacle West and Condensed Consolidated Financial Statements of APS. Item 1 also includes
Notes to Pinnacle West’s Condensed Consolidated Financial Statements, the majority of which also
relate to APS, and Supplemental Notes, which only relate to APS’s Condensed Consolidated Financial
Statements.
This document contains forward-looking statements based on current expectations. These
forward-looking statements are often identified by words such as “estimate,”“predict,”“may,”“believe,”“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 outcomes currently expected or sought by Pinnacle West or APS. In
addition to the Risk Factors described in Item 1A of the Pinnacle West/APS Annual Report on Form
10-K for the fiscal year ended December 31, 2010 (“2010 Form 10-K”) and in Item 2 — “Management’s
Discussion and Analysis of Financial Condition and Results of Operations,” these factors include,
but are not limited to:
•
our ability to achieve timely and adequate rate recovery of our costs, including returns on
debt and equity capital;
•
our ability to manage capital expenditures and other costs while maintaining reliability
and customer service levels;
•
variations in demand for electricity, including those due to weather, the general economy,
customer and sales growth (or decline), and the effects of energy conservation measures and
distributed generation;
•
power plant performance and outages;
•
volatile fuel and purchased power costs;
•
fuel and water supply availability;
•
regulatory and judicial decisions, developments and proceedings;
•
new legislation or regulation, including those relating to greenhouse gas emissions,
renewable energy mandates, nuclear plant operation and energy efficiency standards;
•
our ability to meet renewable energy requirements and recover related costs;
•
risks inherent in the operation of nuclear facilities, including spent fuel disposal
uncertainty;
•
competition in retail and wholesale power markets;
•
the duration and severity of the economic decline in Arizona and current real estate market
conditions;
•
the cost of debt and equity capital and the ability to access capital markets when
required;
•
changes to our credit ratings;
•
the investment performance of the assets of our nuclear decommissioning trust, pension, and
other postretirement benefit plans and the resulting impact on future funding requirements;
•
the liquidity of wholesale power markets and the use of derivative contracts in our
business;
•
potential shortfalls in insurance coverage;
•
new accounting requirements or new interpretations of existing requirements;
•
generation, transmission and distribution facility and system conditions and operating
costs;
•
the ability to meet the anticipated future need for additional baseload generation and
associated transmission facilities in our region;
•
the willingness or ability of our counterparties, power plant participants and power plant
land owners to meet contractual or other obligations or extend the rights for continued power
plant operations;
•
technological developments affecting the electric industry; and
•
restrictions on dividends or other burdensome provisions in our credit agreements and
Arizona Corporation Commission (“ACC”) orders.
These and other factors are discussed in Risk Factors described in Item 1A of our 2010 Form
10-K, which readers should review carefully before placing any reliance on our financial statements
or disclosures. Neither Pinnacle West nor APS assumes any obligation to update these statements,
even if our internal estimates change, except as required by law.
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, SunCor Development Company (“SunCor”), APS Energy Services Company,
Inc. (“APSES”), and El Dorado Investment Company (“El Dorado”). Intercompany accounts and
transactions between the consolidated companies have been eliminated. The unaudited condensed
consolidated financial statements for APS include the accounts of APS and the Palo Verde sale
leaseback variable interest entities (“VIEs”) (see Note 7 for further discussion). Our accounting
records are maintained in accordance with accounting principles generally accepted in the United
States of America (“GAAP”). The preparation of financial statements in accordance with GAAP
requires management to make estimates and assumptions that affect the reported amounts of assets
and liabilities, disclosure of contingent assets and liabilities at the date of the financial
statements and reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results
for interim periods do not necessarily represent results expected for the year.
In preparing the condensed consolidated financial statements, we have evaluated the events
that have occurred after March 31, 2011 through the date the financial statements were issued.
Our condensed consolidated financial statements reflect all adjustments (consisting only of
normal recurring adjustments except as otherwise disclosed in the notes) that we believe are
necessary for the fair presentation of our financial position, results of operations and cash flows
for the periods presented. These condensed consolidated financial statements and notes have been
prepared consistently with the 2010 Form 10-K with the exception of the reclassification of certain
prior year amounts on our Condensed Consolidated Statements of Income, Condensed Consolidated
Balance Sheets and Condensed Consolidated Statements of Cash Flows in accordance with accounting
requirements for reporting discontinued operations (see Note 14), and the impacts related to the
reclassification of regulatory assets and liabilities for the current portion (see Note 3).
The following table shows principal payments due on Pinnacle West’s and APS’s total long-term
debt and capitalized lease requirements as of March 31, 2011 (dollars in millions):
Consolidated
Consolidated
Year
Pinnacle West
APS
2011
$
457
$
457
2012
477
477
2013
140
140
2014
502
502
2015
488
313
Thereafter
1,620
1,620
Total
$
3,684
$
3,509
Credit Facilities and Debt Issuances
Pinnacle West and APS maintain committed revolving credit facilities in order to enhance
liquidity and provide credit support for their commercial paper programs. During the first quarter
of 2011, APS refinanced an existing revolving credit facility (as discussed below) that would have
otherwise matured in September 2011.
Pinnacle West
On February 23, 2011, Pinnacle West entered into a $175 million term loan facility that
matures February 20, 2015. Pinnacle West used the proceeds of the loan to repay its 5.91%
$175 million Senior Notes. Interest rates are based on Pinnacle West’s senior unsecured
debt credit ratings, or if unavailable, its long-term issuer ratings.
At March 31, 2011, Pinnacle West’s $200 million credit facility, which matures in 2013, was
available for general corporate purposes, support of its $200 million commercial paper program, or
for issuances of letters of credit. Pinnacle West has the option to increase the amount of the
facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the
consent of the lenders. At March 31, 2011, Pinnacle West had no outstanding borrowings under this
credit facility, no outstanding letters of credit and commercial paper borrowings of $17 million.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
APS
On February 14, 2011, APS refinanced its $489 million revolving credit facility that would
have matured in September 2011, with a new $500 million facility. The new revolving credit
facility terminates in February 2015. APS may increase the amount of the facility up to a maximum
of $700 million upon the satisfaction of certain conditions and with the consent of the lenders.
APS will use the facility for general corporate purposes, commercial paper program support and for
the issuance of letters of credit. Interest rates are based on APS’s senior unsecured debt credit
ratings.
At March 31, 2011, APS had two credit facilities totaling $1 billion, including the $500
million credit facility described above and a $500 million facility that matures in February 2013.
These facilities are available to support its $250 million commercial paper program, for bank
borrowings or for issuances of letters of credit. See Note 12 for discussion of APS’s letters of
credit. At March 31, 2011, APS had no borrowings outstanding under any of its credit facilities
and no outstanding commercial paper. A $20 million letter of credit was outstanding under APS’s
2011 $500 million credit facility described above.
Debt Provisions
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 total shareholder equity divided by the sum of
total shareholder equity and long-term debt, including current maturities of long-term debt. At
March 31, 2011, APS was in compliance with the common equity ratio requirements established by the
ACC. Its total shareholder equity was approximately $3.8 billion, and total capitalization was
approximately $7.1 billion. APS would be prohibited from paying dividends if the payment would
reduce its total shareholder equity below approximately $2.9 billion, assuming APS’s total
capitalization remains the same. This restriction does not materially affect Pinnacle West’s
ability to meet its ongoing capital requirements.
3. Regulatory Matters
2008 General Retail Rate Case Impacts
On December 30, 2009, the ACC issued an order approving a settlement agreement entered into by
APS and twenty-one other parties to its general retail rate case, which was originally filed in
March 2008. The settlement agreement included a net retail rate increase of $207.5 million, which
represented a base rate increase of $344.7 million less a reclassification of $137.2 million of
fuel and purchased power revenues from the then-existing PSA to base rates. The new rates were
effective January 1, 2010. The settlement agreement also contained on-going requirements,
commitments and authorizations, including the following:
•
Revenue accounting treatment for line extension payments received for new or
upgraded service from January 1, 2010 through year end 2012 (or until new rates are
established in APS’s next general rate case, if that is before the end of 2012);
•
An authorized return on common equity of 11%;
•
A capital structure comprised of 46.2% debt and 53.8% common equity;
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
•
A commitment from APS to reduce average annual operational expenses by at least $30
million from 2010 through 2014;
•
Authorization and requirements of equity infusions into APS of at least $700 million
during the period beginning June 1, 2009 through December 31, 2014 ($253 million of
which was infused into APS from proceeds of a Pinnacle West equity issuance in the
second quarter of 2010); and
•
Various modifications to the existing energy efficiency, demand-side management and
renewable energy programs that require APS to, among other things, expand its
conservation and demand-side management programs and its use of renewable energy, as
well as allow for concurrent recovery of renewable energy expenses and provide for more
concurrent recovery of demand-side management costs and incentives.
The parties also agreed to a rate case filing plan in which APS is prohibited from filing its
next two general rate cases until on or after June 1, 2011 and June 1, 2013, respectively, unless
certain extraordinary events occur. Subject to the foregoing, APS may not request its next general
retail rate increase to be effective prior to July 1, 2012. On February 1, 2011, APS filed a
120-day advanced notice of its intent to file its next rate case on June 1, 2011. The parties
agreed to use good faith efforts to process these subsequent rate cases within twelve months of
sufficiency findings from the ACC staff, which generally occur within 30 days after the filing of a
rate case.
Cost Recovery Mechanisms
APS has received regulatory decisions that allow for more timely recovery of certain costs
through the following recovery mechanisms.
Renewable Energy Standard. In 2006, the ACC approved the Arizona Renewable Energy Standard
and Tariff (“RES”). Under the RES, electric utilities that are regulated by the ACC must supply an
increasing percentage of their retail electric energy sales from eligible renewable resources,
including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these
requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover
the approved amounts for use on renewable energy projects. Each year APS is required to file a
five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES
budget.
During 2009, APS filed its annual RES implementation plan, covering the 2010-2014 timeframe
and requesting 2010 RES funding approval. The plan provided for the acquisition of renewable
generation in compliance with requirements through 2014, and requested RES funding of $87 million
for 2010, which was later approved by the ACC. APS also sought various other determinations in its
plan, including approval of the AZ Sun Program and the Community Power Project in Flagstaff,
Arizona described below.
On March 3, 2010, the ACC approved the AZ Sun Program, which contemplates the addition of 100
megawatts (“MW”) of APS-owned solar resources through 2014. Through this program, APS plans to
invest up to $500 million in solar photovoltaic projects across Arizona, which APS will acquire
through competitive procurement processes. The costs associated with the first 50 MW under this
program will be recovered initially through the RES until such time as the costs are recovered in
base rates or other mechanisms. The costs of the second 50 MW will be recovered through a
mechanism to be determined in APS’s next retail rate case.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
On April 1, 2010, the ACC approved the Community Power Project, a pilot program in which APS
will own, operate and receive energy from approximately 1.5 MW of solar panels on the rooftops of
up to 200 residential and business customers located within a certain test area in Flagstaff,
Arizona. The capital carrying costs of the program will be recovered through the RES until such
time as these costs are recovered in base rates.
On July 1, 2010, APS filed its annual RES implementation plan, covering the 2011-2015
timeframe and requesting 2011 RES funding of $96 million. The 2011 Plan addressed
enhancements to the residential distributed energy incentive program based on high customer
participation, among other things. On October 13, 2010, APS filed an adjusted RES implementation
plan to reflect the following items, among others: 1) increased clarity relating to customer
project in-service dates and related budget revisions; 2) AZ Sun Program updates; and 3) the
addition of 10 MW of biomass capacity. On December 10, 2010, the ACC approved the 2011 Plan
and associated funding request. In January 2011, the ACC voted to reconsider four aspects of the
approved 2011 Plan, including: (a) approval to proceed with a feed-in tariff filing; (b) approval
for APS to participate in the ownership of distributed energy facilities in the Schools and
Government program; (c) denial of a Rapid Reservation program that allows customers to receive
priority in the incentive reservation process in exchange for receipt of a reduced incentive
amount; and (d) allocation of the budget among various programs and studies. Hearings were held on
January 24, 2011 and January 28, 2011. The ACC amended its original decision that approved the
2011 Plan as follows: the ACC (a) reversed its approval of a feed-in tariff program; (b)
restricted APS’s ownership of facilities to only economically challenged, rural schools and only
after a school has received a bid from a third-party solar installer; (c) approved the Rapid
Reservation program; and (d) maintained the original approved budget with some timing
modifications.
Demand-Side Management Adjustor Charge (“DSMAC”). The settlement agreement related to the
2008 retail rate case requires APS to submit an annual Energy Efficiency Implementation Plan for
review by and approval of the ACC. On July 15, 2009, APS filed its initial Energy Efficiency
Implementation Plan, requesting approval by the ACC of programs and program elements for which APS
had estimated a budget in the amount of $50 million for 2010. APS received ACC approval of all of
its proposed programs and implemented the new DSMAC on March 1, 2010. A surcharge was added to
customer bills in order to recover these estimated amounts for use on certain demand-side
management programs. The surcharge allows for the recovery of energy efficiency expenses and any
earned incentives.
The ACC approved recovery of all 2009 program costs plus incentives. The change from program
cost recovery on a historical basis to recovery on a concurrent basis, as authorized in the
settlement agreement, resulted in this one-time need to address two years (2009 and 2010) of cost
recovery. As requested by APS, 2009 program cost recovery is to be spread over a three-year
period.
On June 1, 2010, APS filed its 2011 Energy Efficiency Implementation Plan. In order to meet
the energy efficiency goal for 2011 established by the settlement agreement of annual energy
savings of 1.25%, expressed as a percent of total energy resources to meet retail load, APS
proposed a total budget for 2011 of $79 million. On February 17, 2011, a total budget for 2011 of
$80 million was approved and when added to the amortization of 2009 costs discussed above less the
$10 million
already being recovered in general rates, the DSMAC would recover approximately $75 million
over a twelve month period beginning March 1, 2011. These amounts do not include
approximately $1 million for an electric vehicle charging station program submitted to the ACC for
approval on September 30, 2010.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
PSA
Mechanism and Balance. The power supply adjustor (“PSA”)
provides for the adjustment of retail rates to reflect variations in retail fuel and purchased
power costs.
The following table shows the changes in the deferred fuel and purchased power regulatory
liability for 2011 and 2010 (dollars in millions):
Deferred fuel and purchased power costs-current period
(50
)
(44
)
Amounts refunded through revenues
31
26
Ending balance
$
(77
)
$
(105
)
The PSA rate for the PSA year beginning February 1, 2011 is ($0.0057) per kWh as compared to
($0.0045) per kWh for the prior year. The regulatory liability at March 31, 2011 reflects lower
average prices, primarily for natural gas and gas-based generation. Any uncollected
(overcollected) deferrals during the 2011 PSA year will be included in the calculation of the PSA
rate for the PSA year beginning February 1, 2012.
Transmission Rates and Transmission Cost Adjustor. In July 2008, the United States Federal
Energy Regulatory Commission (“FERC”) approved an Open Access Transmission Tariff for APS to move
from fixed rates to a formula rate-setting methodology in order to more accurately reflect and
recover the costs that APS incurs in providing transmission services. A large portion of the rate
represents charges for transmission services to serve APS’s retail customers (“Retail Transmission
Charges”). In order to recover the Retail Transmission Charges, APS must file an application with,
and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the
transmission cost adjustor (“TCA”).
The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of
service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be
updated include actual capital expenditures made as compared with previous projections,
transmission revenue credits and other items. The resolution of proposed adjustments can result in
significant volatility in the revenues to be collected. APS reviews the proposed formula rate
filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the
ACC staff can remain in dispute until settled or litigated at FERC. Settlement or litigated
resolution of disputed issues could require an extended period of time and could have a significant
effect on the Retail Transmission Charge because any adjustment, though applied prospectively, may
be calculated to account for previously over-collected amounts.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Effective June 1, 2011, APS’s annual wholesale transmission rates for all users of its
transmission system will increase by approximately $44.3 million for the twelve-month period beginning June 1, 2011 in accordance with the FERC-approved formula as a result of higher costs and lower revenues reflected in the formula.
Approximately $38.2 million of this revenue increase relates to transmission services used for
APS’s retail customers. On April 22, 2011, APS filed with the ACC an application for the related
increase of its TCA rate.
Regulatory Assets and Liabilities
As discussed in Note 1, as of March 31, 2011, the Company revised its presentation of
regulatory assets and liabilities to separately reflect current and non-current amounts on the
Condensed Consolidated Balance Sheets. This presentation is reflected in the tables below.
The detail of regulatory assets is as follows (dollars in millions):
Deferred fuel and purchased
power —
mark-to-market (Note 8)
38
38
42
35
Deferred income taxes
3
68
3
69
Transmission vegetation
management
—
45
—
46
Coal reclamation
2
36
2
36
Palo Verde VIE (Note 7)
—
33
—
33
Deferred compensation
—
33
—
32
Tax expense of Medicare subsidy
2
22
2
21
Loss on reacquired debt
1
20
1
21
Demand side management (a)
9
5
12
6
Other
1
17
—
18
Total regulatory assets (b)
$
56
$
980
$
62
$
986
(a)
See Cost Recovery Mechanisms discussion above.
(b)
There are no regulatory assets for which the ACC has allowed recovery of
costs but not allowed a return by exclusion from rate base. FERC
rates are set using a formula rate as described in “Transmission Rates and Transmission Cost Adjustor.”
Included in the balance of regulatory assets at March 31, 2011 and December 31, 2010 is a
regulatory asset for pension and other postretirement benefits. This regulatory asset represents
the future recovery of these costs through retail rates as these amounts are charged to earnings.
If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result
in lower future earnings.
In accordance with regulatory accounting guidance, APS accrues for removal costs for
its regulated assets, even if there is no legal obligation for removal.
(b)
See Cost Recovery Mechanisms discussion above.
(c)
Subject to a carrying charge.
4. Retirement Plans and Other Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a
non-qualified supplemental excess benefit retirement plan, 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.
The following table provides details of the plans’ net periodic benefit costs and the portion
of these costs charged to expense (including administrative costs and excluding amounts capitalized
as overhead construction, billed to electric plant participants or
charged to a regulatory asset) (dollars in millions):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Contributions
The required minimum contribution to our pension plan is zero in 2011 and approximately $85
million in 2012. The contributions to our other postretirement benefit plans for 2011 and 2012 are
expected to be approximately $20 million each year. APS and other subsidiaries fund their share of
the contributions. APS’s share is approximately 99% of both plans.
5. Business Segments
Pinnacle West’s reportable business segment is our regulated electricity segment, which
consists of traditional regulated retail and wholesale electricity businesses (primarily retail and
wholesale sales supplied to traditional cost-based rate regulation (“Native Load”) customers) and
related activities and includes electricity generation, transmission and distribution.
All other activities relate to APSES and El Dorado.
(b)
All other activities relate to SunCor, APSES and El Dorado.
6. Income Taxes
The $68 million income tax receivable on the Condensed Consolidated Balance Sheets represents
the anticipated refunds related to an APS tax accounting method change approved by the IRS in the
third quarter of 2009. This amount is classified as long-term, as cash refunds are not expected to
be received in the next twelve months.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
On February 17, 2011, Arizona enacted legislation (H.B. 2001) that included a four year
phase-in of corporate income tax rate reductions beginning in 2014. As a result of these tax rate
reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in
Arizona. In accordance with accounting for regulated companies, the benefit of this rate reduction
is substantially offset by a regulatory liability. In the first quarter of 2011, Pinnacle West
increased regulatory liabilities by a total of $53 million, with a corresponding decrease in
accumulated deferred income tax liabilities to reflect the impact of this change in tax law.
As of the balance sheet date, the tax year ended December 31, 2008 and all subsequent tax
years remain subject to examination by the IRS. With few exceptions, we are no longer subject to
state income tax examinations by tax authorities for years before 2006. We do not anticipate that
there will be any significant increases or decreases in our unrecognized tax benefits within the
next twelve months.
7. Variable-Interest Entities
Palo Verde Sale Leaseback Trusts
In 1986, APS entered into agreements with three separate variable-interest entity (“VIE”)
lessor trusts in order to sell and lease back interests in Palo Verde Nuclear Generating Station
(“Palo Verde”) Unit 2 and related common facilities. The VIE lessor trusts are single-asset
leasing entities. APS will pay approximately $49 million per year for the years 2011 to 2015
related to these leases. The leases do not contain fixed price purchase options or residual value
guarantees. However, the lease agreements include fixed rate renewal periods which may have a
significant impact on the VIEs’ economic performance. We have concluded that these fixed rate
renewal periods may give APS the ability to utilize the asset for a significant portion of the
asset’s economic life, and therefore provide APS with the power to direct activities of the VIEs
that most significantly impact the VIEs’ economic performance. In addition to the fixed rate
renewal periods, our primary beneficiary analysis also considered that APS is the operating agent
for Palo Verde, is obligated to decommission the leased assets and has fair value purchase options.
For the reasons discussed above, APS consolidates these VIEs. Consolidation of these VIEs
eliminates the lease accounting and results in changes in our consolidated assets, debt, equity,
and net income. Assets of the VIEs are restricted and may only be used to settle the VIEs’ debt
obligations and for payment to the noncontrolling interest holders. Other than the VIEs’ assets
reported on our consolidated financial statements, the creditors of the VIEs have no other recourse
to the assets of APS or Pinnacle West, except in certain circumstances such as a default by APS
under the lease. As a result of consolidation we eliminate rent expense and recognize depreciation
and interest expense, resulting in an increase in net income for the three months ended March 31,2011 of $5 million entirely attributable to the noncontrolling interests. Income attributable to
Pinnacle West shareholders remains the same. Consolidation of these VIEs also results in changes
to our Condensed Consolidated Statements of Cash Flows, but does not impact net cash flows.
Property plant and equipment, net of
accumulated depreciation
$
136
$
138
Long-term debt including current maturities
126
126
Equity- Noncontrolling interests
97
91
For regulatory ratemaking purposes the agreements continue to be treated as operating leases
and, as a result, we have recorded a regulatory asset of $33 million as of March 31, 2011 and
December 31, 2010.
APS is exposed to losses relating to these lessor trust VIEs upon the occurrence of certain
events that APS does not consider to be reasonably likely to occur. Under certain circumstances
(for example, the United States Nuclear Regulatory Commission (“NRC”) issuing specified violation
orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be
required to make specified payments to the VIEs’ noncontrolling equity participants, assume the
VIEs’ debt, 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 March 31, 2011, APS would have
been required to pay the noncontrolling equity participants approximately $146 million and assume
$126 million of debt. Since APS consolidates the VIEs, the debt APS would be required to assume is
already reflected in our Condensed Consolidated Balance Sheets.
8. Derivative Accounting
We are exposed to the impact of market fluctuations in the commodity price and transportation
costs of electricity, natural gas, coal, emissions allowances, and in interest rates. We manage
risks associated with these market fluctuations by utilizing various derivative instruments,
including futures, forwards, options and swaps. As part of our overall risk management program, we
may use such instruments to hedge purchases and sales of electricity, fuels, and emissions
allowances and credits. Derivative instruments that are designated as cash flow hedges are used to
limit our exposure to cash flow variability on forecasted transactions. The changes in market
value of such contracts have a high correlation to price changes in the hedged transactions. We may
also invest in derivative instruments for trading purposes; however, for the period ended March 31,2011, there was no material trading activity.
Our derivative instruments are accounted for at fair value; see Note 15 for a discussion of
fair value measurements. Derivative instruments for the physical delivery of purchase and sale
quantities transacted in the normal course of business qualify for the normal purchase and sales
scope exception and are accounted for under the accrual method of accounting. Due to the scope
exception, these derivative instruments are excluded from our derivative instrument discussion and
disclosures below.
We also enter into derivative instruments for economic hedging purposes. While we believe the
economic hedges mitigate exposure to fluctuations in commodity prices, some of these instruments
may not meet the specific hedge accounting requirements and are not designated as accounting
hedges. Economic hedges not designated as accounting hedges are recorded at fair value on our
balance sheet with changes in fair value recognized in the statement of income as incurred. These
instruments are included in the “non-designated hedges” discussion and disclosure below.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Hedge effectiveness is the degree to which the derivative instrument contract and the hedged
item are correlated and is measured based on the relative changes in fair value of the derivative
instrument contract and the hedged item over time. We assess hedge effectiveness both at
inception and on a continuing basis. These assessments exclude the time value of certain options.
For accounting hedges that are deemed an effective hedge, the effective portion of the gain or loss
on the derivative instrument is reported as a component of accumulated other comprehensive income
(“AOCI”) and reclassified into earnings in the same period during which the hedged transaction
affects earnings. We recognize in current earnings, subject to the PSA, the gains and losses
representing hedge ineffectiveness, and the gains and losses on any hedge components which are
excluded from our effectiveness assessment. As of March 31, 2011, we hedged the majority of certain
exposures to the price variability of commodities for a maximum of 39 months.
In the electricity business, some contracts to purchase energy are netted against other
contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the
same terms (quantities and delivery points) and for which power does not flow. We net these
book-outs, which reduces both revenues and fuel and purchased power costs in our Condensed
Consolidated Statements of Income, but this does not impact our financial condition, net income or
cash flows.
For its regulated operations, APS defers for future rate treatment approximately 90% of
unrealized gains and losses on certain derivatives pursuant to the PSA mechanism that would
otherwise be recognized in income. Realized gains and losses on derivatives are deferred in
accordance with the PSA to the extent the amounts are above or below the portion of APS’s base
rates attributable to fuel and purchased power costs (see Note 3). Gains and losses from
derivatives in the following tables represent the amounts reflected in income before the effect of
PSA deferrals.
As of March 31, 2011, we had the following outstanding gross notional amount of derivatives,
which represent both purchases and sales (does not reflect net position):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Derivative Instruments in Designated Accounting Hedging Relationships
The following table provides information about gains and losses from derivative instruments in
designated accounting hedging relationships and their impact on our Condensed Consolidated
Statements of Income during the three months ended March 31, 2011 and 2010 (dollars in thousands):
Three Months Ended
Financial Statement
March 31,
Commodity Contracts
Location
2011
2010
Amount of
Gain (Loss) Recognized in AOCI on Derivative Instruments (Effective Portion)
Accumulated other comprehensive
loss-derivative instruments
$
988
$
(91,667
)
Amount of Loss Reclassified from AOCI into Income (Effective Portion Realized)
Regulated electricity segment fuel
and purchased power
(14,846
)
(13,185
)
Amount of
Gain (Loss) Recognized in Income from Derivative Instruments (Ineffective Portion and Amount Excluded from Effectiveness Testing) (a)
Regulated electricity segment fuel
and purchased power
12
(10,467
)
(a)
During the three months ended March 31, 2011 and 2010, we had no amounts
reclassified from AOCI to earnings related to discontinued cash flow hedges.
During the next twelve months, we estimate that a net loss of $102 million before income taxes
will be reclassified from AOCI as an offset to the effect of market price changes for the related
hedged transactions. Approximately 90% of the amounts related to derivatives subject to the PSA
will be recorded as either a regulatory asset or liability and have no effect on earnings.
Derivative Instruments Not Designated as Accounting Hedges
The following table provides information about gains and losses from derivative instruments
not designated as accounting hedging instruments and their impact on our Condensed Consolidated
Statements of Income during the three months ended March 31, 2011 and 2010 (dollars in thousands):
Three Months Ended
Financial Statement
March 31,
Commodity Contracts
Location
2011
2010
Amount of Net Gain Recognized in Income from Derivative Instruments
Regulated electricity segment revenue
$
1,507
$
170
Amount of Net Loss Recognized in Income from Derivative Instruments
Regulated electricity segment fuel
and purchased power expense
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Fair Values of Derivative Instruments in the Condensed Consolidated Balance Sheets
The following table provides information about the fair value of our derivative instruments,
margin account and cash collateral reported on a gross basis. Transactions with counterparties
that have master netting arrangements are reported net on the Condensed Consolidated Balance
Sheets. These amounts are located in the assets and liabilities from risk management activities
lines of our Condensed Consolidated Balance Sheets. Amounts are as of March 31, 2011 (dollars in
thousands):
Investments
Current
Deferred Credits
Total Assets
Commodity Contracts
Current Assets
and Other Assets
Liabilities
and Other
(Liabilities)
Derivatives designated
as accounting hedging
instruments:
Assets
$
—
$
663
$
9,583
$
4,234
$
14,480
Liabilities
—
(245
)
(98,821
)
(54,802
)
(153,868
)
Total hedging
instruments
—
418
(89,238
)
(50,568
)
(139,388
)
Derivatives not
designated as accounting
hedging instruments:
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table provides information about the fair value of our derivative
instruments, margin account and cash collateral reported on a gross basis at December 31, 2010
(dollars in thousands):
Investments
Current
Deferred Credits
Total Assets
Commodity Contracts
Current Assets
and Other Assets
Liabilities
and Other
(Liabilities)
Derivatives designated
as accounting hedging
instruments:
Assets
$
1,234
$
142
$
9,062
$
4,913
$
15,351
Liabilities
(602
)
(1,933
)
(107,784
)
(71,109
)
(181,428
)
Total hedging
instruments
632
(1,791
)
(98,722
)
(66,196
)
(166,077
)
Derivatives not
designated as accounting
hedging instruments:
Assets
36,831
40,927
27,322
19,886
124,966
Liabilities
(312
)
(33
)
(112,535
)
(85,473
)
(198,353
)
Total non-hedging
instruments
36,519
40,894
(85,213
)
(65,587
)
(73,387
)
Total derivatives
37,151
39,103
(183,935
)
(131,783
)
(239,464
)
Margin account
24,579
—
997
—
25,576
Collateral provided to
counterparties
11,556
—
125,367
66,393
203,316
Collateral provided
from counterparties
(1,750
)
—
(1,250
)
—
(3,000
)
Prepaid option
premiums and other
2,252
(71
)
(155
)
—
2,026
Balance Sheet Total
$
73,788
$
39,032
$
(58,976
)
$
(65,390
)
$
(11,546
)
Credit Risk and Credit-Related Contingent Features
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We
have risk management contracts with many counterparties, including two counterparties for which our
exposure represents approximately 53% of Pinnacle West’s $93 million of risk management assets as
of March 31, 2011. This exposure relates to long-term traditional wholesale contracts with
counterparties that have very high credit quality. Our risk management process assesses and
monitors the financial exposure of all counterparties. Despite the fact that the great majority of
trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is
still a possibility that one or more of these companies could default, resulting in a material
impact on consolidated 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 and standardized agreements that allow
for the netting of positive and negative exposures associated with a single counterparty.
Valuation adjustments are established representing our estimated credit losses on our overall
exposure to counterparties.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Certain of our derivative instrument contracts contain credit-risk-related contingent features
including, among other things, investment grade credit rating provisions, credit-related cross
default provisions, and adequate assurance provisions. Adequate assurance provisions allow a
counterparty with reasonable grounds for uncertainty to demand additional collateral based on
subjective events and/or conditions. The aggregate fair value of all derivative instruments with
credit-risk-related contingent features that were in a liability position on March 31, 2011 was
$328 million, for which we had posted collateral of $167 million in the normal course of business.
For those derivative instruments in a net liability position, with investment grade credit
contingencies, the counterparties could demand additional collateral if our debt credit ratings
were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for
Moody’s), which would be a violation of the credit rating provisions. If the investment grade
contingent features underlying these agreements had been fully triggered on March 31, 2011, after
off-setting asset positions under master netting arrangements we would have been required to post
approximately an additional $122 million of collateral to our counterparties; this amount includes
those contracts which qualify for scope exceptions, which are excluded from the derivative details
in the above footnote. We also have energy related non-derivative instrument contracts with
investment grade credit-related contingent features which could also require us to post additional
collateral of approximately $196 million if our debt credit ratings were to fall below investment
grade.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
9. Changes in Equity
The following tables show Pinnacle West’s changes in shareholders’ equity and changes in
equity of noncontrolling interests for the three months ended March 31, 2011 and 2010 (dollars in
thousands):
Net unrealized gains
(losses) on derivative
instruments (a)
988
—
988
(91,667
)
—
(91,667
)
Net reclassification of
realized losses to
income (b)
14,846
—
14,846
13,185
—
13,185
Reclassification of
pension and other
postretirement benefits
to income
1,433
—
1,433
1,393
—
1,393
Net income tax benefit
(expense) related to
items of other
comprehensive income
(loss)
(6,821
)
—
(6,821
)
30,426
—
30,426
Total other comprehensive
income (loss)
10,446
—
10,446
(46,663
)
—
(46,663
)
Total comprehensive
income (loss)
(4,689
)
5,461
772
(52,677
)
5,117
(47,560
)
Issuance of capital stock
13,560
—
13,560
2,680
—
2,680
Purchase of treasury
stock,
net of reissuances
(3,530
)
—
(3,530
)
1,078
—
1,078
Other (primarily stock
compensation)
(148
)
—
(148
)
2
(22
)
(20
)
Dividends on common
stock
(57,109
)
—
(57,109
)
(53,259
)
—
(53,259
)
Net capital activities by
noncontrolling interests
—
—
—
—
(923
)
(923
)
Ending balance,
March 31
$
3,631,411
$
97,360
$
3,728,771
$
3,213,933
$
116,067
$
3,330,000
(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.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
10. Commitments and Contingencies
Palo Verde Nuclear Generating Station
Spent Nuclear Fuel and Waste Disposal
APS currently estimates it will incur $122 million (in 2011 dollars) over the
current life of Palo Verde for its share of the costs related to the on-site interim storage of
spent nuclear fuel. At March 31, 2011, APS had a regulatory liability of $46 million that
represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent
fuel storage.
Nuclear Insurance
The Palo Verde participants are insured against public liability for a nuclear incident up to
$12.6 billion per occurrence. As required by the Price Anderson Nuclear Industries Indemnity Act,
Palo Verde maintains the maximum available nuclear liability insurance in the amount of $375
million, which is provided by commercial insurance carriers. The remaining balance of $12.2
billion is provided through a mandatory 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 $118 million, subject to an annual limit of $18 million
per incident, to be periodically adjusted for inflation. Based on APS’s interest in the three Palo
Verde units, APS’s maximum potential assessment per incident for all three units is approximately
$103 million, with an annual payment limitation of approximately $15 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 APS could incur under the current NEIL policies totals approximately $18 million
for each retrospective assessment declared by NEIL’s Board of Directors due to losses. In
addition, NEIL policies contain rating triggers that would result in APS providing approximately
$46 million of collateral assurance within 20 business days of a rating downgrade to non-investment
grade. 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
Contractual Obligations
Our future contractual purchase obligations have increased from approximately $456 million at December 31, 2010 as disclosed in the
2010 Form 10-K to $699 million at March 31, 2011. This increase is primarily related to an amended
agreement for certain transmission rights-of-way and a new contract for the construction of a solar
facility. Total contractual purchase obligations are as follows (dollars in millions):
2011
2012
2013
2014
2015
Thereafter
Total
$
232
$
116
$
69
$
6
$
6
$
270
$
699
Payments for the transmission rights-of-way are subject to change based on changes in
the Consumer Price Index.
FERC Market Issues
On July 25, 2001, the FERC ordered an evidentiary proceeding to discuss and evaluate possible
refunds for wholesale sales in the Pacific Northwest. The FERC affirmed the administrative law
judge’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and
refunds should not be ordered in this proceeding. This decision was appealed to the U.S. Court of
Appeals for the Ninth Circuit. On August 24, 2007, the Ninth Circuit issued an opinion that
remanded the proceeding to the FERC for further consideration. Although the FERC has not yet
determined whether any refunds will ultimately be required, we do not expect that the resolution of
these issues will have a material adverse impact on our financial position, results of operations
or cash flows.
Superfund
The Comprehensive Environmental Response, Compensation and Liability Act (“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 potentially responsible parties (“PRPs”). PRPs may be strictly, and
often are jointly and severally, liable for clean-up. On September 3, 2003, the United States
Environmental Protection Agency (“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. In addition, on
September 23, 2009, APS agreed with the EPA and one other PRP to voluntarily assist with the
funding and management of the site-wide groundwater remedial investigation and feasibility study
work plan. We estimate that our costs related to this investigation and study will be
approximately $1 million, which is reserved as a liability on our financial statements. We
anticipate incurring additional expenditures in the future, but because the overall investigation
is not complete and ultimate remediation requirements are not yet finalized, at the present time we
cannot accurately estimate our total expenditures.
We have issued parental guarantees and obtained surety bonds on behalf of our subsidiaries,
including credit support instruments enabling APSES to offer energy-related products and surety
bonds at APS, principally related to self-insured workers’ compensation. Non-performance or
non-payment under the underlying contract by our subsidiaries would result in a payment liability
on our part under the guarantee or surety bond. No liability is currently recorded on the
Condensed Consolidated Balance Sheets related to such instruments. At March 31, 2011, we had no
outstanding claims for payment under any of these instruments. Our guarantees and surety bonds
have no recourse or collateral provisions to allow us to recover amounts paid under these
instruments. The amounts and approximate terms of our guarantees and surety bonds for each
subsidiary at March 31, 2011 are as follows (dollars in millions):
Guarantees
Surety Bonds
Term
Term
Amount
(in years)
Amount
(in years)
APSES
$
5
1
$
60
1
APS
4
1
9
1
Total
$
9
$
69
APS has entered into various agreements that require letters of credit for financial assurance
purposes. At March 31, 2011, approximately $44 million of letters of credit were outstanding to
support existing pollution control bonds of similar amount. The letters of credit are available to
fund the payment of principal and interest of such debt obligations. These letters of credit
expire in 2011 and 2013. APS has also entered into approximately $54 million of letters of credit
to support certain equity participants in the Palo Verde sale leaseback transactions (see Note 7
for further details on the Palo Verde sale leaseback transactions). These letters of credit were
amended and extended in April 2010, and will expire in 2013.
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.
Income (loss) from continuing
operations attributable to common
shareholders
$
(0.14
)
$
0.07
Loss from discontinued operations
—
(0.13
)
Earnings per share — basic
$
(0.14
)
$
(0.06
)
Diluted earnings per share:
Income (loss) from continuing
operations attributable to common
shareholders
$
(0.14
)
$
0.07
Loss from discontinued operations
—
(0.13
)
Earnings per share — diluted
$
(0.14
)
$
(0.06
)
For the three months ended March 31, 2011 and 2010, the weighted average common shares
outstanding were the same for both basic and diluted shares. Options to purchase 45,500 shares of
common stock for the three-month period ended March 31, 2011, and 387,800 shares for the
three-month period ended March 31, 2010 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.
14. Discontinued Operations
SunCor (real estate segment) — In 2009, our real estate subsidiary, SunCor, began disposing
of its homebuilding operations, master-planned communities, land parcels, commercial assets and
golf courses in order to reduce its outstanding debt. All activity for the income statement and
prior comparative period income statement amounts are included in discontinued operations. In
2010, SunCor recorded real estate impairment charges of $15 million in the first quarter. SunCor’s
asset sales resulted in no gain for 2010. SunCor has approximately $3 million of assets on its
balance sheet classified as assets held for sale which are included in other current assets at
March 31, 2011.
APSES (other) — In 2010, our subsidiary, APSES, sold its district cooling business consisting
of operations in downtown Phoenix, Tucson, and on certain Arizona State University campuses. As a
result of the sale, we recorded an after-tax gain from discontinued operations of approximately $25
million in June 2010. Prior period income statement amounts related to this sale and the associated
revenues and costs are reflected in discontinued operations in 2010.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table provides revenue, income (loss) before income taxes and income (loss)
after taxes classified as discontinued operations in Pinnacle West’s Condensed Consolidated
Statements of Income for the three months ended March 31, 2011 and 2010 (dollars in millions):
Includes a tax benefit recognized by the parent company in accordance with an
intercompany tax sharing agreement of $8 million for the three months ended March 31,2010.
15. Fair Value Measurements
We disclose the fair value of certain assets and liabilities according to a fair value
hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair
values, which are then classified and disclosed in one of three categories. The three levels of
the fair value hierarchy are:
Level 1 — Quoted prices in active markets for identical assets or liabilities. Active
markets are those in which transactions for the asset or liability occur in sufficient
frequency and volume to provide information on an ongoing basis. This category includes
derivative instruments that are exchange-traded such as futures, cash equivalents invested
in exchange-traded money market funds, exchange-traded equities, and nuclear decommissioning
trust investments in Treasury securities.
Level 2 — Quoted prices in active markets for similar assets or liabilities; quoted prices
in markets that are not active; and model-derived valuations whose inputs are observable.
This category includes nonexchange-traded contracts such as forwards, options, and swaps.
This category also includes investments in common and commingled funds that are redeemable
and valued based on the funds’ net asset values.
Level 3 — Model-derived valuations with significant unobservable inputs that are supported
by little or no market activity. Instruments in this category include long-dated derivative
transactions where models are required due to the length of the transaction, options,
transactions in locations where observable market data does not exist, and common and
collective trusts with significant restrictions on our ability to transact in the fund. The
valuation models we employ utilize spot prices, forward prices, historical market data and
other factors to forecast future prices. The primary valuation technique we use to
calculate the fair value of contracts where price quotes are not available is based on the
extrapolation of forward
pricing curves using observable market data for more liquid delivery points in the same
region and actual transactions at the more illiquid delivery points.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Assets and liabilities are classified in their entirety based on the lowest level of input
that is significant to the fair value measurement. We maximize the use of observable inputs and
minimize the use of unobservable inputs. If market data is not readily available, inputs may
reflect our own assumptions about the inputs market participants would use. Our assessment of the
significance of a particular input to the fair value measurement requires judgment and may affect
the valuation of fair value assets and liabilities as well as their placement within the fair value
hierarchy levels. Thus, a valuation may be classified in Level 3 even though the valuation may
include significant inputs that are readily observable. We assess whether a market is active by
obtaining observable broker quotes, reviewing actual market transactions, and assessing the volume
of transactions. We consider broker quotes observable inputs when the quote is binding on the
broker, we can validate the quote with market transactions, or we can determine that the inputs the
broker used to arrive at the quoted price are observable.
Recurring Fair Value Measurements
We apply recurring fair value measurements to derivative instruments, nuclear decommissioning
trusts, certain cash equivalents and plan assets held in our retirement and other benefit plans
(see Note 8).
Cash Equivalents
Cash equivalents represent short-term investments in exchange-traded money market funds that
are valued using quoted prices in active markets.
Risk Management Activities
Exchange-traded contracts are valued using quoted prices in active markets. For non-exchange
traded contracts, we calculate fair market value based on the average of the bid and offer price,
discounted to reflect net present value. We maintain certain valuation adjustments for a number of
risks associated with the valuation of future commitments. These include valuation adjustments for
liquidity and credit risks based on the financial condition of counterparties. The liquidity
valuation adjustment represents the cost that would be incurred if all unmatched positions were
closed-out or hedged.
The credit valuation adjustment represents estimated credit losses on our overall exposure to
counterparties, taking into account netting arrangements, expected default experience for the
credit rating of the counterparties and the overall diversification of the portfolio.
Counterparties in the portfolio consist principally of major energy companies, municipalities,
local distribution companies and financial institutions. We maintain credit policies that
management believes minimize overall credit risk. Determination of the credit quality of
counterparties is based upon a number of factors, including credit ratings, financial condition,
project economics and collateral requirements. When applicable, we employ standardized agreements
that allow for the netting of positive and negative exposures associated with a single
counterparty.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Some of our derivative instrument transactions are valued based on unobservable inputs due to
the long-term nature of contracts or the unique location of the transactions. Our long-dated
energy transactions consist of observable valuations for the near term portion and unobservable
valuations for the long-term portions of the transaction. When the unobservable portion is
significant to the overall valuation of the transaction, the entire transaction is classified as
Level 3. Our classification of instruments as Level 3 is primarily reflective of the long-term
nature of our energy transactions, and is not reflective of material inactive markets.
Nuclear Decommissioning Trust
The nuclear decommissioning trust invests in fixed income securities directly and equity
securities indirectly through commingled funds. The commingled funds are valued based on the
fund’s net asset value and are classified within Level 2. We may transact in the equity commingled
fund on a semi-monthly basis and the cash-equivalent commingled fund on a daily basis. Our trustee
provides valuation of our nuclear decommissioning trust assets by using pricing services to
determine fair market value. We assess these valuations and verify that pricing can be supported
by actual recent market transactions. The trust fund investments have been established to satisfy
APS’s nuclear decommissioning obligations.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Fair Value Tables
The following table presents the fair value at March 31, 2011 of our assets and liabilities
that are measured at fair value on a recurring basis (dollars in millions):
Quoted Prices
Significant
in Active
Other
Significant
Markets for
Observable
Unobservable
Counterparty
Balance at
Identical Assets
Inputs
Inputs (a)
Netting &
March 31,
(Level 1)
(Level 2)
(Level 3)
Other (b)
2011
Assets
Risk management activities:
Commodity contracts
$
—
$
65
$
64
$
(36
)
$
93
Nuclear decommissioning
trust:
Equity securities:
U.S. commingled funds
—
178
—
—
178
Fixed income securities:
U.S. Treasury
69
—
—
—
69
Cash and cash
equivalent funds (c)
—
21
—
—
21
Corporate
—
59
—
—
59
Mortgage-backed
—
81
—
—
81
Municipality
—
70
—
—
70
Other
—
20
—
(11
)
9
Total
$
69
$
494
$
64
$
(47
)
$
580
Liabilities
Risk management activities:
Commodity contracts
$
—
$
(240
)
$
(112
)
$
224
$
(128
)
(a)
Primarily consists of long-dated electricity contracts.
(b)
Risk management activities represent netting under master netting agreements,
including margin and collateral (see Note 8). Nuclear decommissioning trust represents
net pending securities sales and purchases.
(c)
These cash equivalents are held in a commingled short-term investment fund that
invests in short-term, highly liquid, fixed income instruments.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table presents the fair value at December 31, 2010 of our assets and liabilities
that are measured at fair value on a recurring basis (dollars in millions):
Quoted Prices
Significant
in Active
Other
Significant
Markets for
Observable
Unobservable
Counterparty
Balance at
Identical Assets
Inputs
Inputs (a)
Netting &
December 31,
(Level 1)
(Level 2)
(Level 3)
Other (b)
2010
Assets
Cash equivalents
$
35
$
—
$
—
$
—
$
35
Risk management activities:
Commodity contracts
—
80
61
(28
)
113
Nuclear decommissioning
trust:
Equity securities:
U.S. commingled funds
—
168
—
—
168
Fixed income securities:
U.S. Treasury
50
—
—
—
50
Cash and cash
equivalent funds (c)
—
22
—
—
22
Corporate
—
60
—
—
60
Mortgage-backed
—
81
—
—
81
Municipality
—
79
—
—
79
Other
—
20
—
(10
)
10
Total
$
85
$
510
$
61
$
(38
)
$
618
Liabilities
Risk management activities:
Commodity contracts
$
(1
)
$
(280
)
$
(99
)
$
256
$
(124
)
(a)
Primarily consists of long-dated electricity contracts.
(b)
Risk management activities represent netting under master netting arrangements,
including margin and collateral. See Note 8. Nuclear decommissioning trust represents
net pending securities sales and purchases.
(c)
These cash equivalents are held in a commingled short-term investment fund that
invests in short-term, highly liquid, fixed income instruments.
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table shows the changes in fair value for assets and liabilities that are
measured at fair value on a recurring basis using Level 3 inputs for the three months ended March31, 2011 and 2010 (dollars in millions):
Three Months Ended
March 31,
Commodity Contracts
2011
2010
Net derivative balance at beginning of period
$
(38
)
$
(10
)
Total net gains (losses) realized/unrealized:
Included in earnings
1
(1
)
Included in OCI
2
(6
)
Deferred as a regulatory asset or liability
(7
)
(12
)
Transfers into Level 3 from Level 2
(5
)
—
Transfers from Level 3 into Level 2
(1
)
(2
)
Net derivative balance at end of period
$
(48
)
$
(31
)
Net unrealized gains (losses) included in
earnings related to instruments still held at
end of period
$
1
$
(1
)
Amounts included in earnings are recorded in either regulated electricity segment revenue or
regulated electricity segment fuel and purchased power depending on the nature of the underlying
contract.
Transfers reflect the fair market value at the beginning of the period and are triggered by a
change in the lowest significant input as of the end of the period. We had no significant Level 1
transfers to or from any other hierarchy level. Transfers in or out of Level 3 are typically
related to our long-dated energy transactions that extend beyond available quoted periods.
Nonrecurring Fair Value Measurements
We may be required to record other assets at fair value on a nonrecurring basis.
These nonrecurring fair value measurements typically involve write-downs of individual assets due
to impairment.
Financial Instruments Not Carried at Fair Value
The carrying value of our net accounts receivable, accounts payable and short-term borrowings
approximate fair value. Our long-term debt fair value estimates are based on quoted market prices
of the same or similar issues. Certain of our debt instruments contain third-party credit
enhancements and, in accordance with GAAP, we do not consider the effect of these credit
enhancements when determining fair value.
To fund the costs APS expects to incur to decommission Palo Verde, APS established external
decommissioning trusts in accordance with NRC regulations. Third-party investment managers are
authorized to buy and sell securities per their stated investment guidelines. The trust funds are
invested in fixed income securities and domestic equity securities. APS classifies investments in
decommissioning trust funds 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, we have recorded the offsetting amount of gains or
losses on investment securities in other regulatory liabilities or assets. The
following table summarizes the fair value of APS’s nuclear decommissioning trust fund assets at
March 31, 2011 and December 31, 2010 (dollars in millions):
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The costs of securities sold are determined on the basis of specific identification. The
following table sets forth approximate realized gains and losses and proceeds from the sale of
securities by the nuclear decommissioning trust funds (dollars in millions):
The fair value of fixed income securities, summarized by contractual maturities, at March 31,2011 is as follows (dollars in millions):
Fair Value
Less than one year
$
24
1 year - 5 years
68
5 years - 10 years
98
Greater than 10 years
130
Total
$
320
16. Asset Retirement Obligations
APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other
generation, transmission and distribution assets. During the period ending March 31, 2011, a new
decommissioning study with updated cash flow estimates was completed for Palo Verde. This study reflects the
twenty-year license extension approved by the NRC on April 21, 2011, which extends the commencement of
decommissioning to 2045. The new study resulted in a $90 million decrease to the liability for
asset retirements, a $78 million decrease to electric plant in service, and a $12 million increase
to regulatory liabilities.
Allowance for equity funds used during construction
5,395
5,389
Other income (Note S-2)
1,978
1,783
Other expense (Note S-2)
(3,592
)
(3,626
)
Total
2,441
4,389
INTEREST EXPENSE
Interest on long-term debt
54,737
54,752
Interest on short-term borrowings
2,308
842
Debt discount, premium and expense
1,157
1,137
Allowance for borrowed funds used during construction
(3,576
)
(3,019
)
Total
54,626
53,712
NET INCOME (LOSS)
(6,611
)
16,112
Less: Net income attributable to noncontrolling
interests (Note 7)
5,470
5,128
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDER
$
(12,081
)
$
10,984
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to
Arizona Public Service Company’s Condensed Consolidated Financial Statements.
Palo Verde sale leaseback, net of accumulated
depreciation (Note 7)
135,766
137,956
Intangible assets, net of accumulated amortization
182,673
184,768
Nuclear fuel, net of accumulated amortization
129,554
108,794
Total property, plant and equipment
9,579,053
9,577,497
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 15)
486,737
469,886
Assets from risk management activities (Note 8)
38,520
39,032
Other assets
29,124
71,428
Total investments and other assets
554,381
580,346
CURRENT ASSETS
Cash and cash equivalents
104,386
99,937
Customer and other receivables
276,698
288,323
Accrued unbilled revenues
93,659
103,292
Allowance for doubtful accounts
(7,489
)
(7,646
)
Materials and supplies (at average cost)
161,063
181,414
Fossil fuel (at average cost)
20,505
21,575
Assets from risk management activities (Note 8)
54,579
73,788
Regulatory assets (Note 3)
55,743
62,286
Deferred income taxes
104,389
105,042
Other current assets
27,756
25,135
Total current assets
891,289
953,146
DEFERRED DEBITS
Regulatory assets (Note 3)
979,854
986,370
Income tax receivable (Note 6)
68,133
65,498
Unamortized debt issue costs
19,938
20,530
Other
103,759
88,490
Total deferred debits
1,171,684
1,160,888
TOTAL ASSETS
$
12,196,407
$
12,271,877
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental
Notes to Arizona Public Service Company’s Condensed Consolidated Financial Statements.
Palo Verde sale leaseback lessor notes less current maturities
(Notes 2 and 7)
96,803
96,803
Total capitalization
6,533,164
6,961,831
CURRENT LIABILITIES
Current maturities of long-term debt (Note 2)
832,275
456,879
Accounts payable
204,480
218,491
Accrued taxes
170,904
106,431
Accrued interest
54,471
54,638
Customer deposits
68,809
68,312
Liabilities from risk management activities (Note 8)
71,047
58,976
Deferred fuel and purchased power regulatory liability (Note 3)
77,151
58,442
Other regulatory liabilities (Note 3)
78,167
80,526
Other current liabilities
96,561
132,170
Total current liabilities
1,653,865
1,234,865
DEFERRED CREDITS AND OTHER
Deferred income taxes
1,800,146
1,895,654
Regulatory liabilities (Note 3)
689,942
614,063
Liability for asset retirements (Note 16)
244,483
328,571
Liabilities for pension and other postretirement
benefits (Note 4)
782,556
770,611
Liabilities from risk management activities (Note 8)
56,517
65,390
Customer advances
118,778
121,645
Coal mine reclamation
117,455
117,243
Unrecognized tax benefits (Note 6)
81,640
65,363
Other
117,861
96,641
Total deferred credits and other
4,009,378
4,075,181
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY
$
12,196,407
$
12,271,877
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to
Arizona Public Service Company’s Condensed Consolidated Financial Statements.
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Depreciation and amortization including nuclear fuel
123,256
113,195
Deferred fuel and purchased power
49,947
44,040
Deferred fuel and purchased power amortization
(31,238
)
(25,953
)
Allowance for equity funds used during construction
(5,395
)
(5,389
)
Deferred income taxes
(47,962
)
47,754
Change in mark-to-market valuations
(284
)
1,842
Changes in current assets and liabilities:
Customer and other receivables
61,973
61,239
Accrued unbilled revenues
9,633
24,505
Materials, supplies and fossil fuel
21,421
6,240
Other current assets
248
(7,811
)
Accounts payable
(18,168
)
(22,275
)
Other current liabilities
26,872
(64,600
)
Change in margin and collateral accounts — assets
4,220
(11,280
)
Change in margin and collateral accounts — liabilities
35,478
(124,495
)
Change in long-term income tax receivable
(2,635
)
—
Change in unrecognized tax benefits
18,972
(61,683
)
Change in other long-term assets
(29,494
)
(23,723
)
Change in other long-term liabilities
44,324
(31,926
)
Net cash flow provided by (used for) operating activities
254,557
(64,208
)
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures
(191,596
)
(199,276
)
Contributions in aid of construction
9,136
2,949
Allowance for borrowed funds used during construction
(3,576
)
(3,019
)
Proceeds from nuclear decommissioning trust sales
189,318
158,448
Investment in nuclear decommissioning trust
(194,241
)
(164,552
)
Other
(1,879
)
(1,639
)
Net cash flow used for investing activities
(192,838
)
(207,089
)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayment of long-term debt
(170
)
(357
)
Short-term borrowings and payments-net
—
195,000
Dividends paid on common stock
(57,100
)
(42,500
)
Net cash flow provided by (used for) financing activities
(57,270
)
152,143
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
4,449
(119,154
)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
99,937
120,798
CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
104,386
$
1,644
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of (refunds)
$
—
$
65,498
Interest, net of amounts capitalized
$
53,636
$
54,174
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental
Notes to Arizona Public Service Company’s Condensed Consolidated Financial Statements.
Certain notes to APS’s Condensed Consolidated 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’s Condensed Consolidated 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.
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
S-1. Changes in Equity
The following tables show APS’s changes in shareholder equity and changes in equity of
noncontrolling interests for the three and nine months ended March 31, 2011 and 2010 (dollars in
thousands):
Net unrealized
gains (losses) on
derivative
instruments (a)
988
—
988
(91,667
)
—
(91,667
)
Net
reclassification of
realized losses to
income (b)
14,846
—
14,846
13,185
—
13,185
Reclassification of
pension and other
postretirement
benefits to income
1,288
—
1,288
1,064
—
1,064
Net income tax
benefit (expense)
related to items of
other comprehensive
income (loss)
(6,764
)
—
(6,764
)
30,565
—
30,565
Total other
comprehensive income
(loss)
10,358
—
10,358
(46,853
)
—
(46,853
)
Total comprehensive
income (loss)
(1,723
)
5,470
3,747
(35,869
)
5,128
(30,741
)
Dividends on common
stock
(57,100
)
—
(57,100
)
(42,500
)
—
(42,500
)
Other
1
—
1
—
—
—
Ending balance,
March 31
$
3,766,131
$
96,554
$
3,862,685
$
3,366,986
$
87,452
$
3,454,438
(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.
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 APS’s Condensed Consolidated Financial Statements and the
related Notes that appear in Item 1 of this report. For information on the broad factors that may
cause our actual future results to differ from those we currently seek or anticipate, see
“Forward-Looking Statements” at the front of this report and “Risk Factors” in Item 1A of the 2010
Form 10-K.
OVERVIEW
Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated
electric utility that provides either retail or wholesale electric service to most of the state of
Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson
metropolitan area and Mohave County in northwestern Arizona. APS accounts for substantially all of
our revenues and earnings, and is expected to continue to do so.
Areas of Business Focus
Operational Performance, Reliability and Recent Developments.
Nuclear. APS operates and is a joint-owner of the Palo Verde Nuclear Generating Station.
With a focus on safely and efficiently generating electricity for the long-term, APS applied for
twenty-year extensions of its operating licenses for each of the three Palo Verde units in December
2008. On April 21, 2011, the NRC approved the twenty-year extensions of the Palo Verde licenses.
Coal and Related Environmental Matters. APS is a joint-owner of three coal-fired power plants
and acts as operating agent for two of the plants. APS is focused on the impacts on its coal fleet
that may result from potential legislation and increased regulation concerning greenhouse gas
emissions. Recent concern over climate change and other emission-related issues could have a
significant impact on our capital expenditures and operating costs in the form of taxes, emissions
allowances or required equipment upgrades for these plants. APS is closely monitoring its
long-range capital management plans, understanding that any resulting legislation and regulation
could impact the economic viability of certain plants, as well as the willingness or ability of
power plant participants to fund any such equipment upgrades.
Southern California Edison (“SCE”), a participant in the Four Corners Power Plant (“Four
Corners”), has indicated that certain California legislation may prohibit it from making emission
control expenditures at the coal-fired plant. On November 8, 2010, APS and SCE entered into an
asset purchase agreement, providing for the purchase by APS of SCE’s 48% interest in each of Units
4 and 5 of Four Corners. The purchase price is $294 million, subject to certain adjustments.
Completion of the purchase by APS, which is expected to occur in the second half of 2012, is
subject to the receipt of approvals by the ACC, the California Public Utilities Commission and the
FERC. APS and SCE filed applications with their respective commissions seeking requisite authority
or approvals to complete the transaction. Hearings with the ACC are scheduled to commence on July14, 2011. Closing is also conditioned on the execution of a new coal supply contract for the lease
renewal period described below, expiration of the
waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and other typical
closing conditions.
APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility
lease with the Navajo Nation which would extend the Four Corners leasehold interest to 2041.
Execution by the Navajo Nation of the lease amendments is a condition to closing of the purchase by
APS of SCE’s interests in Four Corners. The amendments were approved by the Navajo Nation Council
on February 15, 2011 and signed by the Nation’s President on March 7, 2011. The effectiveness of
the amendments also requires the approval of the U.S. Department of the Interior (“DOI”), as does a
related Federal rights-of-way grant which the Four Corners participants will pursue. A Federal
environmental review will be conducted as part of the DOI review process.
Pursuant to a Co-Tenancy Agreement among the Four Corners participants, the other participants
have a right of first refusal to purchase shares of SCE’s interests proportional to their current
ownership percentages. The exercise of this purchase right by any of the other participants expired
on March 8, 2011 and none of the other participants exercised this right.
APS has announced that, if APS’s purchase of SCE’s interests in Units 4 and 5 at Four Corners
is consummated, it will close Units 1, 2 and 3 at the plant. These events will change the plant’s
overall generating capacity from 2,100 MW to 1,540 MW and APS’s entitlement from the plant from 791
MW to 970 MW. When applying for approval to purchase Units 4 and 5, APS also requested from the ACC
recovery of any unrecovered costs associated with the closure of Units 1, 2 and 3.
APS cannot predict whether all of the conditions necessary to consummate the purchase of SCE’s
interest will be met such that closing can occur, including whether the parties will receive
satisfactory regulatory approvals.
Transmission and Delivery. APS’s 2011 transmission plan projects that it will invest
approximately $450 million in new transmission over the next ten years, which includes 258 miles of
new lines. The first three years of these additional line miles are included in the capital
expenditures table presented in the “Liquidity” section below along with other transmission costs
for upgrades and replacements. APS is working closely with regulators to identify and plan for
transmission needs resulting from the current focus on renewable energy. APS is also working to
establish and expand smart grid technology throughout its service territory designed to provide
long-term benefits both to APS and its customers. APS is piloting and deploying a variety of
technologies that are intended to allow customers to better monitor their energy use and needs,
minimize system outage durations and the number of customers that experience outages, and
facilitate cost savings to APS through improved reliability and the automation of certain
distribution functions, including remote meter reading and remote connects and disconnects.
Renewable Energy. The ACC approved the RES in 2006, recognizing the importance of renewable
energy to our state. The renewable energy requirement is 3% of retail electric sales in 2011 and
increases annually until it reaches 15% in 2025. In the settlement agreement related to the 2008
retail rate case, APS agreed to exceed the RES standards, committing to 1,700 GWh of new renewable
resources to be in service by year-end 2015 in addition to its 2008 renewable resource commitments.
Taken together, APS’s commitment is estimated to be 3,400 GWh or approximately 10% of APS’s retail
energy sales by year-end 2015, which is double the existing RES target of 5% for that year. See
Note 3. A component of the RES is focused on stimulating development of distributed energy systems
(generally speaking, small-scale renewable technologies that are located on customers’ properties).
During the first quarter 2011, APS’s third-party owned distributed energy resources in
operation and planned or under development grew by 16 MW and 10 MW, respectively. At March 31,2011, APS’s renewable resources totaled 901 MW, including solar, wind, geothermal, biomass and
biogas. Of this portfolio, 304 MW are currently in operation and 597 MW are under contract for
development or are under construction. Renewable resources in operation include 5 MW of
utility-scale facilities owned by APS, 223 MW of long-term purchased power agreements, and an
estimated 76 MW of distributed energy resources. Resources under contract or under development
include 83 MW of utility-scale facilities to be owned by APS, 382 MW of long-term purchased power
agreements and an estimated 132 MW of distributed energy resources.
On April 5, 2011, APS issued its 2011 Small Generation request for proposal to solicit for a
broad base of renewable technology projects between 2 MW and 15 MW. APS continues to actively
consider opportunities to enhance its renewable energy portfolio, both to ensure its compliance
with the Renewable Energy Standard and to meet the needs of its customer base.
Demand Side Management. Arizona regulators are placing an increased focus on energy
efficiency and other demand side management programs to encourage customers to conserve energy,
while incentivizing utilities to aid in these efforts that ultimately reduce the demand for energy.
In December 2009, the ACC initiated Energy Efficiency rulemaking, with a proposed Energy
Efficiency Standard of 22% cumulative annual energy savings by 2020. The 22% figure represents the
cumulative reduction in future energy usage through 2020 attributable to energy efficiency
initiatives. On July 27, 2010, the proposed Energy Efficiency Standard was adopted by the ACC,
approved by the Arizona Attorney General and became effective on January 1, 2011. This ambitious
standard will likely impact Arizona’s future energy resource needs.
Rate Matters. APS needs timely recovery through rates of its capital and operating
expenditures to maintain adequate financial health. APS’s retail rates are regulated by the ACC
and its wholesale electric rates (primarily for transmission) are regulated by the FERC. At the
end of 2009, the ACC approved a settlement agreement entered into by APS and twenty-one of the
twenty-three other parties to APS’s general retail rate case, with modifications that did not
materially affect the overall economic terms of the agreement. The rate case settlement authorizes
and requires equity infusions into APS of at least $700 million prior to the end of 2014. The
settlement demonstrated cooperation among APS, the ACC staff, the Residential Utility Consumer
Office and other intervenors to the rate case, and establishes a future rate case filing
plan that allows APS the opportunity to help shape Arizona’s energy future outside of continual
rate cases. See Note 3 for a detailed discussion of the settlement agreement terms and information
on APS’s FERC rates.
APS has several recovery mechanisms in place that provide more timely recovery to APS of its
fuel and transmission costs, and costs associated with the promotion and implementation of its
demand-side management and renewable energy efforts and customer programs. These mechanisms are
described more fully in Note 3.
On October 18, 2010, the Chairman of the ACC issued a draft decoupling policy statement for
consideration by the commission. On December 15, 2010, the ACC unanimously approved a slightly
modified decoupling policy statement supportive of using a revenue-per-customer methodology, which
is the mechanism APS and a number of other parties support. Decoupling refers to a ratemaking
design which reduces or removes the linkage between sales and utility revenues and/or profits,
reducing utility disincentives to the adoption of programs that benefit customers by saving energy.
Mechanically, decoupling compares actual versus authorized revenues or revenue per customer over a
period and either
credits or collects any differences from customers in a subsequent period. The policy permits
regulated utilities to file a decoupling proposal in their next general rate case. In its 120-day
notice of intent to file a rate case, APS indicated it would be filing a decoupling model
consistent with the policy statement and other mechanisms to more timely recover capital and
operating costs for consideration in its upcoming general rate case, currently expected to be filed
in June 2011.
Financial Strength and Flexibility. Pinnacle West and APS currently have ample borrowing
capacity under their respective credit facilities and have been able to access these facilities and
the commercial paper markets, ensuring adequate liquidity for each company. In early February
2011, APS entered into a $500 million revolving credit facility, replacing its $489 million
revolving credit facility that would have otherwise terminated in September 2011.
Subsidiaries. The operations of APSES and El Dorado are not expected to have any material
impact on our financial results, or to require any material amounts of capital, over the next three
years. In addition, as a result of the continuing distressed conditions in the real estate
markets, during 2009 our other first-tier subsidiary, SunCor, undertook a program to dispose of its
homebuilding operations, master-planned communities, land parcels, commercial assets and golf
courses in order to reduce its outstanding debt. At March 31, 2011, SunCor had total remaining
assets of about $16 million, which includes approximately $3 million of assets held for sale.
Key Financial Drivers
In addition to the continuing impact of the matters described above, many factors influence
our financial results and our future financial outlook, including those listed below. We closely
monitor these factors to plan for the Company’s current needs, and to adjust our expectations,
financial budgets and forecasts appropriately.
Electric Operating Revenues. For the years 2008 through 2010, retail electric revenues
comprised approximately 93% of our total electric operating revenues. Our electric operating
revenues are affected by customer growth or decline, variations in weather from period to period,
customer mix, average usage per customer and the impacts of energy efficiency programs, electricity
rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms.
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’s 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 competition, demand and prices.
Customer and Sales Growth. Customer growth in APS’s service territory for the three-month
period ended March 31, 2011 was 0.4% compared with the prior year period. For the three years 2008
through 2010, APS’s customer growth averaged 0.9% per year. We currently expect customer growth to
average about 1.7% per year for 2011 through 2013 due to anticipated improving economic conditions,
both nationally and in Arizona. Retail sales in kilowatt-hours, adjusted to exclude the effects of
weather variations, for the three-month period ended March 31, 2011 increased 1.2% compared to the
same period in the prior year, reflecting the improving economic conditions, partially offset by
the effects of our energy efficiency programs. For the three years 2008 through 2010, APS’s actual
retail electricity sales in kilowatt-hours, adjusted to exclude the effects of weather variations,
declined at an average annual rate of 0.9%. We currently estimate that total retail electricity
sales in kilowatt-hours will remain flat on average per year during 2011 through 2013, including
the effects of APS’s energy efficiency programs, but excluding the effects of weather variations.
A continuation of the economic downturn, or the failure of the
Arizona economy to rebound in the near future, could further impact these estimates. The
customer and sales growth referred to in this paragraph apply to Native Load customers.
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, impacts
of energy efficiency programs and responses to retail price changes. Our experience indicates that
a reasonable range of variation in our kilowatt-hour sales projection attributable to such economic
factors under normal business conditions can result in increases or decreases in annual net income
of up to $10 million.
Weather. In forecasting the retail sales growth numbers provided above, 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.
Fuel and Purchased Power Costs. Fuel and purchased power costs included on our Condensed
Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts
for purchased power and generation fuel, our power plant performance, transmission availability or
constraints, prevailing market prices, new generating plants being placed in service in our market
areas, our hedging program for managing such costs and PSA deferrals and the related amortization.
Operations and Maintenance Expenses. Operations and maintenance expenses are impacted by
growth, power plant operations, maintenance of utility plant (including generation, transmission,
and distribution facilities), inflation, outages, higher-trending pension and other postretirement
benefit costs, renewable energy and demand side management related expenses (which are offset by
the same amount of regulated electricity segment operating revenues) and other factors. In the
settlement agreement related to the 2008 retail rate case, APS committed to operational expense
reductions from 2010 through 2014 and received approval to defer certain pension and other
postretirement benefit cost increases to be incurred in 2011 and 2012.
Depreciation and Amortization Expenses. Depreciation and amortization expenses are impacted
by net additions to utility plant and other property (such as new generation, transmission, and
distribution facilities), and changes in depreciation and amortization rates. See “Capital
Expenditures” below for information regarding the planned additions to our facilities. With the
twenty-year extensions of the operating licenses for each of the Palo Verde units recently granted
by the NRC, we estimate that our annual pretax depreciation expense will decrease by approximately
$34 million at January 1, 2012.
Property Taxes. Taxes other than income taxes consist primarily of property taxes, which are
affected by the value of property in-service and under construction, assessment ratios, and tax
rates. The average property tax rate for APS, which currently owns substantially all of our
property, was 8.0% of the assessed value in 2010 and 7.5% of the assessed value in 2009. We expect
property taxes to increase as we add new utility plants (including new generation, transmission and
distribution facilities) and as we improve our existing facilities.
Income Taxes. Income taxes are affected by the amount of pre-tax book income, income tax
rates, and certain non-taxable items, such as the allowance for equity funds used during
construction. In addition, income taxes may also be affected by the settlement of issues with
taxing authorities.
Interest Expense. Interest expense is affected by the amount of debt outstanding and the
interest rates on that debt (see Note 2.) The primary factors affecting borrowing levels are
expected to be our capital expenditures, long-term debt maturities, equity issuances and internally
generated cash flow. An allowance for borrowed funds offsets a portion of interest expense while
capital projects are under construction. We stop accruing allowance for borrowed funds on a
project when it is placed in commercial operation.
RESULTS OF OPERATIONS
Pinnacle West’s reportable business segment is 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.
Operating Results — Three-month period ended March 31, 2011 compared with three-month period ended
March 31, 2010
Our consolidated net loss attributable to common shareholders for the three months ended March31, 2011 was $15 million, compared with a net loss of $6 million for the comparable prior-year
period. The $9 million variance consists of a $22 million decrease in income (loss) from
continuing operations, partially offset by a $13 million improvement in our loss from discontinued
operations (primarily due to real estate impairment charges in the prior-year period). The
reduction in results from continuing operations reflects a decrease of approximately $22 million in
regulated electricity segment net income primarily due to increased operations and maintenance
expenses related to planned timing and level of maintenance at two of our gas-fired,
combined-cycle generation plants.
Income (Loss) from Continuing
Operations Attributable to Common
Shareholders:
Regulated Electricity Segment:
Operating revenues less fuel and
purchased power expenses (a)
$
436
$
396
$
40
Operations and maintenance (a)
(255
)
(207
)
(48
)
Depreciation and amortization
(107
)
(101
)
(6
)
Taxes other than income taxes
(38
)
(32
)
(6
)
Interest charges, net of allowance for
funds used during construction
(52
)
(52
)
—
Income taxes
6
8
(2
)
Less income related to noncontrolling
interests (Note 7)
(5
)
(5
)
—
Regulated electricity segment
net income (loss)
(15
)
7
(22
)
Loss from Discontinued Operations
Attributable to Common Shareholders
(primarily real estate impairment
charges)
—
(13
)
13
Net Loss Attributable to Common
Shareholders
$
(15
)
$
(6
)
$
(9
)
(a)
Includes effects of settlement of certain prior-period transmission rights-of-way related
to Four Corners, which did not affect net income, but increased both electric operating
revenues and operations and maintenance expenses by $28 million. Costs related to the
settlement were offset by related revenues to be received from SCE, which leases the
related transmission line from APS.
Regulated electricity segment
This section includes a discussion of major variances in income and expense amounts for the
regulated electricity segment.
Operating revenues less fuel and purchased power expenses Regulated electricity segment
operating revenues less fuel and purchased power expenses were $40 million higher for the three
months ended March 31, 2011 compared with the prior-year period. The following table describes the
major components of this change:
Increase (Decrease)
Fuel and
purchased
Operating
power
revenues
expenses
Net change
(dollars in millions)
Settlement of certain prior-period transmission
rights-of-way (offset in operations and
maintenance expense)
$
28
$
—
$
28
Effects of weather on retail sales
10
4
6
Higher retail sales primarily due to higher
usage per customer, excluding the effects of
weather, but including the effects of APS’s
energy efficiency programs
7
2
5
Higher demand-side management, renewable
energy and similar regulatory surcharges
(substantially offset in operations and
maintenance expense)
4
4
Lower retail revenues related to refund of PSA
deferrals, substantially offset by lower
amortization of fuel and purchased power
expense
(5
)
(6
)
1
Miscellaneous items, net
(7
)
(3
)
(4
)
Total
$
37
$
(3
)
$
40
Operations and maintenance Operations and maintenance expenses increased $48 million for the
three months ended March 31, 2011 compared with the prior-year period primarily because of:
•
An increase of $28 million for settlement of certain transmission rights-of-way,
which is offset in operating revenues;
•
An increase of $19 million in generation costs, primarily due to planned timing and level of
maintenance at two of our gas-fired combined-cycle generation plants;
•
An increase of $4 million related to costs for demand-side management, renewable
energy, and similar regulatory programs, which are offset in operating revenues; and
•
A decrease of $3 million due to other miscellaneous factors.
Depreciation and Amortization Depreciation and amortization expenses were $6 million higher
for the three months ended March 31, 2011 compared with the prior-year period primarily because of
increased plant in service.
Taxes other than income taxes Taxes other than income taxes increased $6 million for the
three months ended March 31, 2011 compared with the prior-year period primarily because of higher
property tax rates in the current period.
Income taxes Income tax benefits were $2 million lower for the three months ended March 31,2011 compared to 2010. The prior-year period includes $8 million of income tax benefits related to
a reduction in the Company’s 2010 effective income tax rate.
Discontinued Operations
Real estate activities SunCor’s operations have been reclassified to discontinued operations.
The loss from discontinued operations related to real estate activities improved by $13 million
for the three months ended March 31, 2011 compared with the prior-year period primarily because of
real estate impairment charges recorded in the prior-year period.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows — Pinnacle West Consolidated
The following table presents net cash provided by (used for) operating, investing and
financing activities for the three months ended March 31, 2011 and 2010 (dollars in millions):
Net cash flow provided by (used for)
operating activities
$
243
$
(14
)
Net cash flow used for investing activities
(193
)
(210
)
Net cash flow provided by (used for)
financing activities
(47
)
82
The increase of approximately $257 million in net cash provided by operating activities is
primarily due to return of collateral and margin cash as a result of changes in commodity prices
and expiration of prior hedge contracts; a voluntary pension contribution in 2010 of approximately
$100 million; and other changes in working capital.
The decrease of approximately $17 million in net cash used for investing activities is
primarily due to lower capital expenditures.
The decrease of approximately $129 million in net cash provided by financing activities is
primarily due to lower levels of short-term borrowings.
Cash Flows — Arizona Public Service Company Consolidated
The following table presents net cash provided by (used for) operating, investing and
financing activities for the three months ended March 31, 2011 and 2010 (dollars in millions):
Net cash flow provided by (used for)
operating activities
$
255
$
(64
)
Net cash flow used for investing activities
(193
)
(207
)
Net cash flow provided by (used for)
financing activities
(57
)
152
The increase of approximately $319 million in net cash provided by operating activities is
primarily due to return of collateral and margin cash as a result of changes in commodity prices
and expiration of prior hedge contracts; a voluntary pension contribution in 2010 of approximately
$100 million; income tax payments in 2010; and other changes in working capital.
The decrease of approximately $14 million in net cash used for investing activities is
primarily due to lower capital expenditures.
The decrease of approximately $209 million in net cash provided by financing activities is
primarily due to lower levels of short-term borrowings.
Liquidity
Capital Expenditure Requirements
The following table summarizes the actual capital expenditures on an accrual basis for the
three months ended March 31, 2011 and 2010 and the estimated capital expenditures for the next
three years:
Generation capital expenditures are comprised of various improvements to APS’s existing fossil
and nuclear plants. Examples of the types of projects included in this category are additions,
upgrades and capital replacements of various power plant equipment, such as turbines, boilers and
environmental equipment. Included under Renewables is the AZ Sun Program, which is a significant
component of the increase in capital expenditures from 2010 to 2011. For purposes of this table,
we have assumed the consummation of APS’s purchase of SCE’s interest in Four Corners Units 4 and 5
and the subsequent shut down of Units 1-3, as discussed in the “Overview” section above. As a
result, we included the $294 million purchase price under Generation and have not included
environmental expenditures for Units 1-3. We are also monitoring the status of certain
environmental matters, which, depending on their final outcome, could require modification to our
environmental expenditures. (See “Business of Arizona Public Service Company — Environmental
Matters — EPA Environmental Regulation — Regional Haze Rules and Coal Combustion Waste” in Item 1
of the 2010 Form 10-K and “Mercury and other Hazardous Air Pollutants” in Part II, Item 5 below.)
Distribution and transmission capital expenditures are comprised of infrastructure additions
and upgrades, capital replacements, new customer construction, related information systems and
facility costs. Examples of the types of projects included in the forecast include power lines,
substations, line extensions to new residential and commercial developments and upgrades to
customer information systems.
Capital expenditures will be funded with internally generated cash and external financings,
which may include issuances of long-term debt and Pinnacle West common stock.
Pinnacle West (Parent Company)
Our primary cash needs are for dividends to our shareholders and principal and interest
payments on our short-term and long-term debt. The level of our common stock dividends and future
dividend growth will be dependent on a number of factors including, but not limited to, payout
ratio trends, free cash flow and financial market conditions.
On April 20, 2011, the Pinnacle West Board of Directors declared a quarterly dividend of
$0.525 per share of common stock, payable on June 1, 2011, to shareholders of record on May 2,2011.
Our primary sources of cash are dividends from APS, external debt and equity financings. 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 total shareholder equity divided by the sum of total
shareholder equity and long-term debt, including current maturities of long-term debt. At March31, 2011, APS’s common equity ratio, as defined, was 53%. Its total shareholder equity was
approximately $3.8 billion, and total capitalization was approximately $7.1 billion. APS would be
prohibited from paying dividends if the payment would reduce its total shareholder equity below
approximately $2.9 billion, assuming APS’s total capitalization remains the same. This restriction
does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.
Pinnacle West maintains committed revolving credit facilities in order to enhance
liquidity and provide credit support for its commercial paper program.
On February 23, 2011, Pinnacle West entered into a $175 million term loan facility that
matures February 20, 2015. Pinnacle West used the proceeds of the loan to repay its 5.91%
$175 million Senior
Notes. Interest rates are based on Pinnacle West’s senior unsecured debt credit
ratings, or, if unavailable, its long-term issuer ratings.
At March 31, 2011, Pinnacle West’s $200 million credit facility, which matures in 2013, was
available for general corporate purposes, support of its $200 million commercial paper program, or
for issuances of letters of credit. Pinnacle West has the option to increase the amount of the
facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the
consent of the lenders. At March 31, 2011, Pinnacle West had no outstanding borrowings under this
credit facility, no outstanding letters of credit and commercial paper borrowings of $17 million.
The $68 million income tax receivable on the Condensed Consolidated Balance Sheets represents
the anticipated refunds related to an APS tax accounting method change approved by the IRS in the
third quarter of 2009. This amount is classified as long-term, as cash refunds are not expected to
be received in the next twelve months.
The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 includes
provisions making qualified property placed into service after September 8, 2010 and before January1, 2012 eligible for 100% bonus depreciation for federal income tax purposes. In addition,
qualified property placed into service in 2012 is eligible for 50% bonus depreciation for federal
income tax purposes. These provisions of the recent tax legislation are expected to generate
approximately $425-475 million of cash tax benefits for APS through accelerated depreciation. It
is anticipated that these cash benefits will be fully realized by APS by the end of 2013, with a
majority of the benefit realized in 2012 and 2013. The cash generated is an acceleration of tax
benefits that APS would have otherwise received over 20 years.
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, real estate, and short-term investments. Future year contribution amounts are dependent on
plan asset performance and plan actuarial assumptions. The required minimum contribution to our
pension plan is zero in 2011 and approximately $85 million in 2012. The contributions to our other
postretirement benefit plans for 2011 and 2012 are expected to be approximately $20 million each
year. APS and other subsidiaries fund their share of the contributions. APS’s share is
approximately 99% of both plans.
APS
APS’s capital requirements consist primarily of capital expenditures and maturities of
long-term debt. APS funds its capital requirements with cash from operations and, to the extent
necessary, external debt financing and equity infusions from Pinnacle West. See “Pinnacle West
(Parent Company)” above for a discussion of the common equity ratio that APS must maintain in order
to pay dividends to Pinnacle West.
On February 14, 2011, APS refinanced its $489 million credit facility that would have matured
in September 2011 with a new $500 million facility. The new credit facility terminates in February
2015. APS may increase the amount of the facility up to a maximum of $700 million upon the
satisfaction of certain conditions and with the consent of the lenders. APS will use the facility
for general corporate
purposes, commercial paper program support and for the issuance of letters of credit.
Interest rates are based on APS’s senior unsecured debt credit ratings.
At March 31, 2011, APS had two credit facilities totaling $1 billion, including the $500
million credit facility described above and a $500 million facility that matures in February 2013.
These facilities are available to support its $250 million commercial paper program, for bank
borrowings, or for issuances of letters of credit. See Note 12 for a discussion of APS’s letters
of credit. At March 31, 2011, APS had no borrowings outstanding under any of its credit facilities
and no outstanding commercial paper. A $20 million letter of credit was outstanding under APS’s
2011 $500 million credit facility described above.
Other Financing Matters — See Note 3 for information regarding the PSA approved by the ACC.
Although APS defers actual retail fuel and purchased power costs to the extent those costs vary from the base fuel rate on a current basis, APS’s recovery
or refund of the deferrals from or to its ratepayers, as appropriate, is subject to annual and, if
necessary, periodic PSA adjustments.
See Note 3 for information regarding the retail rate case settlement, which includes ACC
authorization and requirements of equity infusions into APS of at least $700 million by December31, 2014.
See Note 8 for information related to the change in our margin accounts.
Other Subsidiaries
SunCor — At March 31, 2011, SunCor had total remaining assets of approximately $16 million,
which includes approximately $3 million of assets held for sale. At March 31, 2011, SunCor had no
debt outstanding.
As of March 31, 2011, SunCor could not transfer any cash dividends to Pinnacle West. This
restriction does not affect Pinnacle West’s ability to meet its ongoing capital requirements.
El Dorado — El Dorado expects minimal capital requirements over the next three years and
intends to focus on prudently realizing the value of its existing investments.
APSES —APSES expects minimal capital expenditures over the next three years.
Debt Provisions
Pinnacle West’s and APS’s debt covenants related to their respective bank financing
arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this
covenant and each anticipates it will continue to meet this and other significant covenant
requirements. For both Pinnacle West and APS, this covenant requires that the ratio of
consolidated debt to total consolidated capitalization not exceed 65%. At March 31, 2011, the
ratio was approximately 50% for Pinnacle West and 47% for APS. 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’s financing agreements contain “rating triggers” that would
result in an acceleration of the required interest and principal payments in the event of a rating
downgrade.
However, our bank credit agreements contain a pricing grid in which the interest rates we pay for
borrowings and letters of credit issued thereunder are determined by our current credit ratings.
All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in
defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or
APS were to default under certain other material agreements. All of APS’s 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 credit facilities
borrowings.
See Note 2 for further discussions of liquidity matters.
Credit Ratings
The ratings of securities of Pinnacle West and APS as of April 27, 2011 are shown below. We are
disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt. 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’s securities and/or result in an increase in the cost of, or limit
access to, capital. Such revisions may also result in substantial additional cash or other
collateral requirements related to certain derivative instruments, insurance policies, natural gas
transportation, fuel supply, and other energy-related contracts. At this time, we believe we have
sufficient liquidity to cover a downward revision to our credit ratings.
Moody’s
Standard & Poor’s
Fitch
Pinnacle West
Senior unsecured (a)
Baa3 (P)
BB+ (prelim)
N/A
Commercial paper
P-3
A-3
F3
Outlook
Stable
Positive
Stable
APS
Senior unsecured
Baa2
BBB-
BBB
Secured lease
obligation bonds
Baa2
BBB-
BBB
Commercial paper
P-2
A-3
F3
Outlook
Stable
Positive
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
assigned a provisional (P) rating and Standard & Poor’s assigned a preliminary (prelim)
rating to the senior unsecured securities that can be issued under such shelf
registration.
Off-Balance Sheet Arrangements
See Note 7 for a discussion of VIEs and the impacts on our financial statements of
consolidating certain VIEs.
We have issued parental guarantees and obtained surety bonds on behalf of our subsidiaries,
including credit support instruments enabling APSES to offer energy-related products and surety
bonds at APS, principally related to self-insured workers’ compensation. Non-performance or
non-payment under the underlying contract by our subsidiaries would result in a payment liability
on our part under the guarantee or surety bond. No liability is currently recorded on the
Condensed Consolidated Balance Sheets related to such instruments. At March 31, 2011, we had no
outstanding claims for payment under any of these instruments. Our guarantees and surety bonds
have no recourse or collateral provisions to allow us to recover amounts paid under these
instruments or surety bonds from our subsidiaries. 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 12 for additional information
regarding guarantees and letters of credit.
Contractual Obligations
Our future contractual purchase obligations have increased from approximately $0.5 billion at December 31, 2010 as discussed in the
2010 Form 10-K to $0.7 billion at March 31, 2011. This increase is primarily related to an amended
agreement for certain transmission rights-of-way and a new contract for the construction of a solar
facility. Total contractual purchase obligations are as follows (dollars in billions):
2011
2012-2013
2014-2015
Thereafter
Total
$
0.2
$
0.2
$
0.0
$
0.3
$
0.7
Payments for the transmission rights-of-way are subject to change based on changes in
the Consumer Price Index.
See Note 2 for a list of payments due on total long-term debt and capitalized lease
requirements.
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. There have been no changes to our critical accounting policies since our
2010 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2010 Form 10-K for further
details about our critical accounting policies.
MARKET AND CREDIT RISKS
Market Risks
Our operations include managing market risks related to changes in interest rates, commodity
prices and investments held by our nuclear decommissioning trust fund.
Interest Rate and Equity Risk
We have exposure to changing interest rates. Changing interest rates will affect interest
paid on variable-rate debt and the market value of fixed income securities held by our nuclear
decommissioning
trust fund (see Note 15). 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.
We are exposed to the impact of market fluctuations in the commodity price and transportation
costs of electricity and natural gas. Our risk management committee, consisting of officers and
key management personnel, oversees company-wide energy risk management activities to ensure
compliance with our stated energy risk management policies. We manage risks associated with these
market fluctuations by utilizing various commodity instruments that qualify as derivatives,
including exchange-traded futures and options and over-the-counter forwards, options and swaps. As
part of our risk management program, we use such instruments to hedge purchases and sales of
electricity and fuels. The changes in market value of such contracts have a high correlation to
price changes in the hedged commodities.
The following table shows the net pretax changes in mark-to-market of our derivative positions
for the three months ended March 31, 2011 and 2010 (dollars in millions):
The table below shows the fair value of maturities of our derivative contracts (dollars in
millions and excluding margin and collateral) at March 31, 2011 by maturities and by the type of
valuation that is performed to calculate the fair values. See Note 1, “Derivative Accounting” and
“Fair Value Measurements,” in Item 8 of our 2010 Form 10-K and Note 15 for more discussion of our
valuation methods.
Total
Years
fair
Source of Fair Value
2011
2012
2013
2014
2015
thereafter
value
Prices actively quoted
$
—
$
—
$
—
$
—
$
—
$
—
$
—
Prices provided by
other external sources
(118
)
(45
)
(13
)
1
—
—
(175
)
Prices based on models
and other valuation
methods
(10
)
(8
)
(10
)
(7
)
(7
)
(6
)
(48
)
Total by maturity
$
(128
)
$
(53
)
$
(23
)
$
(6
)
$
(7
)
$
(6
)
$
(223
)
The table below shows the impact that hypothetical price movements of 10% would have on the
market value of our risk management assets and liabilities included on Pinnacle West’s Condensed
Consolidated Balance Sheets at March 31, 2011 and December 31, 2010 (dollars in millions):
These contracts are hedges of our forecasted purchases of natural gas and
electricity. The impact of these hypothetical price movements would substantially
offset the impact that these same price movements would have on the physical exposures
being hedged. To the extent the amounts are eligible for inclusion in the PSA, the
amounts are recorded as either a regulatory asset or liability.
Credit Risk
We are exposed to losses in the event of non-performance or non-payment by counterparties.
See Note 15 — “Fair Value Measurements” for a discussion of our credit valuation adjustment
policy. See Note 8 for a further discussion of credit risk.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See “Key Financial Drivers” and “Market and Credit Risks” 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 March 31, 2011. 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’s management, with the participation of APS’s Chief Executive Officer and Chief Financial
Officer, have evaluated the effectiveness of APS’s disclosure controls and procedures as of March31, 2011. Based on that evaluation, APS’s Chief Executive Officer and Chief Financial Officer have
concluded that, as of that date, APS’s 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’s internal control over financial reporting occurred
during the fiscal quarter ended March 31, 2011 that materially affected, or is reasonably likely to
materially affect, Pinnacle West’s or APS’s internal control over financial reporting.
See “Environmental Matters” in Item 5 below and “Business of Arizona Public Service Company —
Environmental Matters” in Item 1 of the 2010 Form 10-K in regard to pending or threatened
litigation or other disputes.
See Note 10 for information relating to FERC proceedings on Pacific Northwest energy market
issues.
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 2010 Form 10-K, which could
materially affect the business, financial condition, cash flows or future results of Pinnacle West
and APS. The risks described in the 2010 Form 10-K are not the only risks facing Pinnacle West and
APS. 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 Pinnacle West and APS.
Item 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Issuer Purchases of Equity Securities
The following table contains information about our purchases of our common stock during the
first quarter of 2011.
Represents shares of common stock withheld by Pinnacle West to satisfy tax withholding
obligations upon the vesting of restricted stock units and performance shares.
Item 5.
OTHER INFORMATION
Environmental Matters
Superfund
See “Superfund” in Note 10 for a discussion of the OU3 Superfund site.
By letter dated April 25, 2008, the EPA informed APS that it may be a PRP in the Gila River
Indian Reservation Superfund Site in Maricopa County, Arizona. APS, along with three other electric
utility companies, owns a parcel of property on which a transmission pole and a portion of a
transmission line are located. The property abuts the Gila River Indian Community boundary and, at
one time, may have been part of an airfield where crop dusting took place. The EPA has settled the
matter with APS and four other PRPs for past cleanup-related costs involving contamination from the
crop dusting. APS’s share of the settlement had no material adverse impact on APS’s financial
position, results of operations, or cash flows.
Climate Change
Climate Change Lawsuits. In February 2008, the Native Village of Kivalina and the City of
Kivalina, Alaska filed a lawsuit in federal court in the Northern District of California against
nine oil companies, fourteen power companies (including Pinnacle West), and a coal company,
alleging that the defendants’ emissions of carbon dioxide contribute to global warming and
constitute a public and private nuisance. The plaintiffs also allege that the effects of global
warming will require the relocation of the village, and they are seeking an unspecified amount of
monetary damages. In June 2008, the defendants filed motions to dismiss the action, which were
granted. The plaintiffs filed an appeal with the Ninth Circuit Court of Appeals in November 2009,
and Pinnacle West filed its reply on June 30, 2010. The court has not yet scheduled oral
arguments on the plaintiffs’ appeal. On January 24, 2011, the defendants filed a motion to defer
calendaring of oral argument until after the United States Supreme Court rules in a similar
nuisance lawsuit, American Electric Power Co., Inc. v. Connecticut. The Kivalina court granted
that motion on February 23, 2011. We believe the action in Kivalina is without merit and intend to
continue to defend against the claims.
EPA Environmental Regulation
Mercury and other Hazardous Air Pollutants. In early 2008, the U.S. Court of Appeals for the
D.C. Circuit vacated the Clean Air Mercury Rule (“CAMR”), which was adopted by the EPA to regulate
mercury emissions from coal-fired power plants. As a result, the law in effect prior to the
adoption of the CAMR became the applicable law, and the EPA is now required to adopt final maximum
achievable control technology emissions (“MACT”) standards. Under a consent decree that was
finalized on April 15, 2010, the EPA has agreed to issue final MACT standards for mercury and other
hazardous air pollutants by November 2011. APS will have three years after the EPA’s final rule
becomes effective to achieve compliance. EPA released its proposed MACT standards on March 16,2011. The proposed rule would require APS to install additional pollution control equipment, which
is consistent with APS’s expectations. The proposed rule is subject to a sixty-day public comment
period from the date published in the federal register.
APS has installed, and continues to install, certain of the equipment necessary to meet the
anticipated standards. APS estimates that the cost for equipment necessary to meet these
anticipated standards is approximately $220 million for Four Corners Units 1-3 and $89 million for
Cholla Units 1-3. The estimated costs for Four Corners Units 1-3 are not included in our current
environmental expenditure estimates since our estimates assume the consummation of APS’s purchase
of SCE’s interest in Four Corners Units 4 and 5 and the subsequent shut down of Units 1-3.
Cholla’s estimated costs for the next three years are included in our environmental expenditure
estimates. (See “Management’s Discussion and Analysis of Financial Condition and Results of
Operations — Capital Expenditures” in Item 2 for details of our capital expenditure estimates).
Cooling Water Intake Structures. The EPA issued its proposed cooling water intake structures
rule on April 20, 2011, which provides national standards applicable to certain cooling water
intake
structures at existing power plants and other facilities pursuant to Section 316(b) of the
Clean Water Act. The proposed standards are intended to protect fish and other aquatic organisms
by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or
against screens) and entrainment mortality (the capture of fish or shellfish in water flow entering
and passing through intake structures). To minimize impingement mortality, the proposed rule would
require facilities such as Four Corners and the Navajo Generating Station to either demonstrate
that impingement mortality at its cooling water intakes does not exceed a specified rate or reduce
the flow at those structures to less than a specified velocity, and to take certain protective
measures with respect to impinged fish. To minimize entrainment mortality, the proposed rule would
also require these facilities to conduct a “structured site-specific analysis” to determine what
site-specific controls, if any, should be required. Additional studies and a peer review process
will also be required at these facilities.
The proposed rule is subject to a ninety-day public comment period, which ends on July 19,2011, and the EPA is expected to issue a final rule by July 2012. As proposed, existing facilities
subject to the rule would have to comply with the impingement mortality requirements as soon as
possible, but in no event later than eight years after the effective date of the rule, and would
have to comply with the entrainment requirements as soon as possible under a schedule of compliance
established by the permitting authority. APS is performing analyses to determine the costs of
compliance with the proposed rule.
Impact of Earthquake and Tsunami in Japan on Nuclear Energy Industry
On March 11, 2011, a 9.0 magnitude earthquake occurred off the north-eastern coast of Japan.
The earthquake produced a tsunami that caused significant damage to the Fukushima Daiichi Nuclear
Power Station in Japan. Preliminary data available from the Fukushima Daiichi plant operator and
Japanese government have each indicated that the earthquake and tsunami were beyond the plant’s
required licensing and design parameters. Validation of that data will continue as more
information becomes available.
The Nuclear Energy Institute (“NEI”) and the Institute of Nuclear Power Operations (“INPO”)
are working closely to analyze the situation in Japan and develop action plans for U.S. nuclear
power plants. APS is actively engaged with NEI and INPO in these efforts. Additionally, the NRC
is performing its own independent review of the events at Fukushima Daiichi. On March 23, 2011, the
NRC Commissioners voted to launch a two-pronged review of U.S. nuclear power plant safety. The NRC
announced that it supports the establishment of an agency task force that will conduct both a
short- and long-term analysis of the lessons that can be learned from the situation in Japan. The
NRC expects the task force to begin its long-term evaluations within 90 days and anticipates that a
report with any recommended actions will be available within six months after the evaluations
begin. Until formal action, if any, is taken by the NRC as a result of its review, we cannot predict whether there will be any financial or operational impacts on Palo Verde or APS.
Amendment and Supplement No. 2 to
Supplemental and Additional Indenture of
Lease with the Navajo Nation dated March 7,2011
10.2
APS
Amendment and Supplement No. 3 to
Supplemental and Additional Indenture of
Lease with the Navajo Nation dated March 7,2011
10.3
Pinnacle West
Credit Agreement dated as of February 23,2011 among Pinnacle West Capital
Corporation, as Borrower, Union Bank, N.A.,
as Agent, and the lenders and other parties
thereto
10.4
Pinnacle West
Form of Performance Share Agreement under
the Pinnacle West Capital Corporation 2007
Long-Term Incentive Plan
10.5
Pinnacle West
Form of Restricted Stock Unit Agreement
under the Pinnacle West Capital Corporation
2007 Long-Term Incentive Plan
10.6
Pinnacle West
Form of Restricted Stock Unit Agreement
under the Pinnacle West Capital Corporation
2007 Long-Term Incentive Plan (Supplemental
2010 Award)
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 Donald E. Brandt, 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 James R. Hatfield, Senior
Vice President and Chief Financial Officer,
pursuant to Rule 13a-14(a) and Rule
15d-14(a) of the Securities Exchange Act,
as amended
Certificate of Donald E. Brandt, Chief
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 James R. Hatfield, Senior
Vice President and 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 1350, 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 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of
2002
In addition, Pinnacle West hereby incorporates the following Exhibits pursuant to Exchange Act
Rule 12b-32 and Regulation §229.10(d) by reference to the filings set forth below:
Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
