SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): February 24, 2003
ARIZONA PUBLIC SERVICE COMPANY
(Exact name of registrant as specified in its charter)
Arizona 1-4473 86-0011170
(State or other jurisdiction (Commission (IRS Employer
of incorporation) File Number) Identification Number)
400 NORTH FIFTH STREET, P.O. BOX 53999, PHOENIX, ARIZONA 85004
(Address of principal executive offices) (Zip Code)
(602) 250-1000
(Registrant's telephone number, including area code)
NONE
(Former name or former address, if changed since last report)
ITEM 5. OTHER EVENTS
This Current Report on Form 8-K is limited to the reclassification of
financial statements of Arizona Public Service Company (the "Company" or "APS")
to reflect certain reclassifications of revenue and costs and other income and
expenses and the impacts of those reclassifications on Management's Discussion
and Analysis of Financial Condition and Results of Operations, Financial
Statements and Notes to Financial Statements, and the Selected Financial Data as
originally reported in our Annual Report on Form 10-K for the fiscal year ended
December 31, 2001. NO ATTEMPT HAS BEEN MADE IN THIS REPORT TO MODIFY OR UPDATE
OTHER DISCLOSURES EXCEPT AS REQUIRED TO REFLECT THE EFFECTS OF THE
RECLASSIFICATIONS DESCRIBED BELOW. THESE OTHER DISCLOSURES ARE INCLUDED IN OUR
ANNUAL, QUARTERLY AND CURRENT REPORTS AND OTHER INFORMATION FILED WITH THE SEC.
As previously disclosed in our Quarterly Report on Form 10-Q for the fiscal
quarter ended September 30, 2002, prior to the third quarter of 2002, we
recorded and reported upon settlement, sales under electricity trading contracts
as revenues and purchased power costs. Effective July 1, 2002, we reclassified
revenues from such electricity trading activity to a net basis of reporting
which resulted in a substantial reduction in both revenues and purchased power
and fuel expense but did not have any impact on our financial condition, results
of operations or cash flows. In addition, we have presented in our income
statements our operating revenues and purchased power and fuel separately for
our electric retail, and marketing and trading segments. We also have presented
our other income and expense items on a gross basis in our income statements.
Our third quarter Form 10-Q, previously filed with the Securities and Exchange
Commission, reflects such reclassifications. This Form 8-K Report provides
updated information to substantially conform such filing to the presentation
reported in our third quarter Form 10-Q. Accordingly, this report provides
additional information previously reported in our Form 10-K in Item 6. Selected
Financial Data, Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations, Item 8. Financial Statements and
Supplementary Data, and Item 14. Exhibits, Financial Statements, Financial
Statement Schedules and Reports on Form 8-K to reflect the aforementioned
reclassifications.
TABLE OF CONTENTS
PAGE
----
GLOSSARY.................................................................... 3
Selected Financial Data................................................ 5
Management's Discussion and Analysis of Financial Condition
and Results of Operations............................................ 6
Quantitative and Qualitative Disclosures about Market Risk............. 27
Financial Statements and Supplementary Data............................ 28
2
GLOSSARY
ACC - Arizona Corporation Commission
ACC Staff - Staff of the Arizona Corporation Commission
ADEQ - Arizona Department of Environmental Quality
AISA - Arizona Independent Scheduling Administrator
ALJ - Administrative Law Judge
ANPP - Arizona Nuclear Power Project, also known as Palo Verde
APSES - APS Energy Services Company, Inc., a subsidiary of Pinnacle West
CC&N - Certificate of Convenience and Necessity
Cholla - Cholla Power Plant
Citizens - Citizens Communications Company
Clean Air Act - Clean Air Act, as amended
Company - Arizona Public Service Company
DOE - United States Department of Energy
EITF - Emerging Issues Task Force
EPA - United States Environmental Protection Agency
ERMC - Energy Risk Management Committee
FASB - Financial Accounting Standards Board
FERC - United States Federal Energy Regulatory Commission
FIP - Federal Implementation Plan
Four Corners - Four Corners Power Plant
GAAP - generally accepted accounting principles in the United States of America
ISO - California Independent System Operator
ITC - investment tax credit
KW - kilowatt, one thousand watts
KWh - kilowatt-hour, one thousand watts per hour
MW - megawatt, one million watts
MWh - megawatt-hours, one million watts per hour
1999 Settlement Agreement - Settlement Agreement among the Company and other
parties related to the implementation of retail electric competition in Arizona
NOV - Notice of Violation
NRC - United States Nuclear Regulatory Commission
Nuclear Waste Act - Nuclear Waste Policy Act of 1982, as amended
Palo Verde - Palo Verde Nuclear Generating Station
3
PG&E - PG&E Corp.
Pinnacle West - Pinnacle West Capital Corporation, parent company of the Company
Pinnacle West Energy - Pinnacle West Energy Corporation, a subsidiary of
Pinnacle West
PPA - Purchase power agreement
PRP - Potentially responsible parties under Superfund
PX - California Power Exchange
RTO - regional transmission organization
Rules - ACC retail electric competition rules
Salt River Project - Salt River Project Agricultural Improvement and Power
District
SCE - Southern California Edison Company
SEC - United States Securities and Exchange Commission
SFAS - Statement of Financial Accounting Standards
Superfund - Comprehensive Environmental Response, Compensation, and Liability
Act
T&D - transmission and distribution
WestConnect - WestConnect RTO, LLC, a proposed RTO to be formed by owners of
electric transmission lines in the southwestern United States
4
SELECTED FINANCIAL DATA
2001 2000 1999 1998 1997
----------- ----------- ----------- ----------- -----------
(DOLLARS IN THOUSANDS)
Electric operating revenues
Electric retail segment (a) ............... $ 2,562,088 $ 2,538,750 $ 1,914,722 $ 1,741,148 $ 1,711,134
Marketing and trading segment (a) ......... 549,240 395,392 154,126 180,145 167,419
Purchased power and fuel costs
Electric retail segment ................... 1,227,188 1,065,596 432,844 306,884 284,153
Marketing and trading segment ............. 313,991 267,032 136,522 151,164 157,380
Operating expenses ........................... 1,171,171 1,155,278 1,115,664 1,097,471 1,070,517
----------- ----------- ----------- ----------- -----------
Operating income .......................... 398,978 446,236 383,818 365,774 366,503
Other income/(deductions) .................... (79) (6,545) 20,857 20,315 21,453
Interest deductions ___ net .................. 118,211 133,097 136,353 130,842 136,463
----------- ----------- ----------- ----------- -----------
Income before extraordinary charge
and cumulative effect adjustment ........ 280,688 306,594 268,322 255,247 251,493
Extraordinary charge - net of tax (b) ..... -- -- (139,885) -- --
Cumulative effect of change in
accounting - net of tax (c) ............. (15,201) -- -- -- --
----------- ----------- ----------- ----------- -----------
Net income ................................ 265,487 306,594 128,437 255,247 251,493
Preferred dividends ....................... -- -- 1,016 9,703 12,803
----------- ----------- ----------- ----------- -----------
Earnings for common stock ................. $ 265,487 $ 306,594 $ 127,421 $ 245,544 $ 238,690
=========== =========== =========== =========== ===========
Total Assets ................................. $ 6,367,054 $ 6,413,549 $ 6,117,624 $ 6,393,299 $ 6,331,142
=========== =========== =========== =========== ===========
Capital Structure:
Common stock equity ....................... $ 2,150,690 $ 2,119,768 $ 1,983,174 $ 1,975,755 $ 1,849,324
Non-redeemable preferred stock ............ -- -- -- 85,840 142,051
Redeemable preferred stock ................ -- -- -- 9,401 29,110
Long-term debt less current maturities .... 1,949,074 1,806,908 1,997,400 1,876,540 1,953,162
----------- ----------- ----------- ----------- -----------
Total capitalization .................... 4,099,764 3,926,676 3,980,574 3,947,536 3,973,647
Commercial paper .......................... 171,162 82,100 38,300 178,830 130,750
Current maturities of long-term debt ...... 125,451 250,266 114,711 164,378 104,068
----------- ----------- ----------- ----------- -----------
Total ................................... $ 4,396,377 $ 4,259,042 $ 4,133,585 $ 4,290,744 $ 4,208,465
=========== =========== =========== =========== ===========
- ----------
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations" for a discussion of certain information in the table above.
(a) Amounts related to energy trading activities have been reclassified to a
net basis (see Note 18).
(b) Charges associated with a regulatory disallowance. See Note 1.
(c) Change in accounting standards related to derivatives. See Note 16.
5
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
In this section, we explain the results of operations, general financial
condition, and outlook including:
* the changes in our earnings from 2000 to 2001 and from 1999 to 2000;
* our capital needs, liquidity and capital resources;
* our marketing and trading activities;
* our financial outlook;
* our critical accounting policies;
* major factors that affect our financial outlook; and
* our management of market risks.
OVERVIEW OF OUR BUSINESS
We are an Arizona electric utility and provide either retail or wholesale
electric service to substantially all of the state, with the major exceptions of
the Tucson metropolitan area and about one-half of the Phoenix metropolitan
area. We also generate and, through Pinnacle West's marketing and trading
division, sell and deliver electricity to wholesale customers in the western
United States. Pinnacle West owns all of our outstanding common stock.
We are required to transfer our competitive electric assets and services to
one or more corporate affiliates no later than December 31, 2002. Consistent
with that requirement, we have been addressing the legal and regulatory
requirements necessary to complete the transfer of our generation assets to
Pinnacle West Energy before that date. As we discuss in greater detail below
under "Business Outlook - Other Factors Affecting Our Financial Outlook," recent
Arizona regulatory developments have raised uncertainty about the status and
pace of retail electric competition in Arizona, including our transfer of
generation assets to Pinnacle West Energy.
BUSINESS SEGMENTS
We have two principal business segments (determined by products, services
and regulatory environment), which consist of regulated retail electricity
business and related activities (electric retail business segment) and
competitive business activities (marketing and trading segment). Our electric
retail business segment currently includes activities related to electricity
transmission and distribution, as well as electricity generation. Our marketing
and trading segment currently includes activities related to wholesale marketing
and trading.
6
These reportable segments reflect a change in the reporting of our segment
information. Before the fourth quarter of 2001, we had two segments (generation
and delivery). The "generation segment" information combined our marketing and
trading activities with our generation of electricity activities. The "delivery
segment" included transmission and distribution activities.
In the fourth quarter, we filed with the ACC a request for a proposed rule
variance and approval of a purchase power agreement (see Note 3) that inherently
views our business in the new reportable segments described herein. Internal
management reporting has been changed to reflect this alignment. See "Business
Segments" in Note 15 for more information about our business segments.
The following is a summary of earnings by business segment for 2001, 2000,
and 1999 (dollars in millions):
2001 2000 1999
----- ----- -----
Electric Retail $ 140 $ 230 $ 257
Marketing and trading 140 77 10
----- ----- -----
Income from continuing operations 280 307 267
Extraordinary charge - net of
income taxes -- -- (140)
Cumulative effect of change in
accounting - net of income taxes (15) -- --
----- ----- -----
Earnings for common stock $ 265 $ 307 $ 127
===== ===== =====
Throughout this section, we refer to specific "Notes" in the Notes to Financial
Statements. These Notes add further details to the discussion.
7
RESULTS OF OPERATIONS
2001 COMPARED WITH 2000
Our net income for the year ended December 31, 2001 was $265 million
compared with $307 million for the year ended December 31, 2000. In 2001, we
recognized a $15 million after-tax loss in net income as a cumulative effect of
a change in accounting for derivatives. See Note 16 for further discussion on
accounting for derivatives.
Income before accounting change for the year ended December 31, 2001 was
$281 million compared with $307 million for the year ended December 31, 2000.
The year-to-year comparison benefited from strong marketing and trading results
and retail customer growth. These factors were partially offset by higher
purchased power and fuel costs, due in part to increased power plant
maintenance; generation reliability measures; continuing retail electricity
price decreases; and a charge related to Enron and its affiliates. The major
factors that increased (decreased) income before accounting change were as
follows (dollars in millions):
Increase
(Decrease)
----------
Increases (decreases) in marketing and trading and electric retail segments'
revenues, net of purchased power and fuel expense due to:
Marketing and trading activities:
Increase from generation sales other than native load due to
higher market prices $ 25
Decrease in other realized marketing and trading in current
period primarily due to less transactions (7)
Change in prior period mark-to-market value for commodity
contracts delivered in current period 18(a)
Increase in mark-to-market value related to future periods 71(a)
----
Net increase in marketing and trading 107
Higher replacement power costs for plant outages related to higher market
prices (70)
Higher purchased power costs related to 2001 generation reliability program (30)
Retail price reductions (see Note 3) (27)
Charges related to purchased power contracts with Enron and its affiliates (13)(b)
Miscellaneous revenues 1
----
Total decrease in marketing and trading and electric retail segments' revenues,
net of purchased power and fuel expense (32)
Higher operations and maintenance expense related to 2001 generation
reliability program (12)
Higher operations and maintenance expense related primarily to employee
benefits, plant outage and maintenance, and other costs (23)
Lower net interest expense primarily due to lower interest rates 15
Higher other net income 10
Miscellaneous items, net 3
----
Net decrease in income before income taxes (39)
Lower income taxes primarily due to lower income 13
----
Net decrease in income before accounting change $(26)
====
8
(a) Essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is
hedged with a portfolio of forward purchases that protects the
economic value of the sales transactions.
(b) We recorded charges totaling $13 million before income taxes for
exposure to Enron and its affiliates in the fourth quarter of 2001.
Marketing and trading and electric retail segments' revenues increased
approximately $177 million because of:
* changes in marketing and trading revenues ($154 million, net increase) due
to:
- increased revenues related to generation sales other than native load
as a result of higher average market prices ($32 million);
- increased realized revenues related to other marketing and trading in
current period primarily due to more transactions and higher market
prices ($40 million);
- increased prior period mark-to-market value for losses transferred to
realized margin in current period ($11 million);
- increased mark-to-market value for future periods primarily as a
result of more forward sales volumes ($71 million);
* decreased revenues related to other wholesale sales and miscellaneous
revenues as a result of sales volumes ($28 million);
* increased retail revenues primarily related to higher sales volumes
primarily due to customer growth ($78 million); and
* decreased retail revenues related to reductions in retail electricity
prices ($27 million).
Purchased power and fuel expenses increased approximately $209 million
primarily because of:
* changes in marketing and trading purchased power and fuel costs ($47
million, net increase) due to:
- increased fuel costs related to generation sales other than native
load as a result of higher fuel prices ($7 million);
- increased fuel and purchased power costs related to other realized
marketing and trading in current period primarily due to more
transactions ($47 million);
- decreased mark-to-market fuel costs related to accounting for
derivatives ($7 million) (see Note 16);
* decreased costs related to other wholesale sales as a result of lower
volumes ($29 million);
* higher replacement power costs primarily due to higher market prices and
increased plant outages ($70 million), including costs of $12 million
related to a Palo Verde outage extension to replace fuel control element
assemblies;
* higher purchase power costs related to 2001 generation reliability program
($30 million);
* higher costs related to retail sales volumes due to customer growth ($78
million); and
* charges related to purchased power contracts with Enron and its affiliates
($13 million).
The increase in operations and maintenance expenses of $35 million
primarily related to the 2001 generation summer reliability program (the
9
addition of generating capability to enhance reliability for the summer of 2001
($12 million)) and increased employee benefit costs, plant outage and
maintenance, and other costs ($23 million).
Other net income increased $10 million primarily because of insurance
recovery of environmental remediation costs.
Interest expense decreased by $15 million primarily because of lower
interest rates and increased capitalized interest resulting from higher
construction project balances.
2000 COMPARED WITH 1999
Our earnings for the year ended December 31, 2000 were $307 million
compared with $127 million for the year ended December 31, 1999. Our 2000
earnings increased $180 million over 1999 primarily because of a $140 million
after-tax extraordinary charge that we recorded in 1999. This charge reflected a
regulatory disallowance resulting from an ACC-approved Settlement Agreement
related to the implementation of retail electric competition. See "Regulatory
Agreements" below and Notes 1 and 3 for additional information about the 1999
Settlement Agreement and the resulting regulatory disallowance.
Earnings excluding the extraordinary charge increased $39 million, or 15%,
over 1999 primarily because of increases in wholesale and retail electric sales.
These positive factors more than offset decreases resulting from the completion
of ITC amortization in 1999, reductions in retail electricity prices, and
miscellaneous factors. See "Regulatory Agreements" below and Note 3 for
information on the price reductions. See "Regulatory Agreements" below and Note
4 for additional information about ITC amortization. The major factors that
increased (decreased) earnings were as follows (dollars in millions):
Increase
(Decrease)
----------
Increases (decreases) in marketing and trading and electric retail segments'
revenues, net of purchased power and fuel expense due to:
Marketing and trading activities:
Increase from generation sales other than native load due to
higher market prices $ 47
Increase in other realized marketing and trading in current
period primarily due to more transactions 53
Change in prior period mark-to-market value for commodity
contracts delivered in current period (2)(a)
Increase in mark-to-market value related to future periods 13 (a)
----
Net increase in marketing and trading 111
Retail price reductions (see Note 3) (28)
Higher retail sales primarily related to customer growth 10
Miscellaneous revenues 9
----
Total increase in marketing and trading and electric retail segments'
revenues, net of purchased power and fuel expense 102
10
Lower operations and maintenance expense related primarily to $19 million
of non-recurring items recorded in 1999 partially offset by increased
costs related to customer growth 7
Higher depreciation and amortization expense (9)
Miscellaneous items, net 2
----
Net increase in income before income taxes 102
Higher income taxes due to higher income in 2000 and higher ITC
amortization in 1999 (63)
----
Net increase in income before extraordinary charge and accounting
change $ 39
====
(a) Essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is
hedged with a portfolio of forward purchases that protects the
economic value of the sales transactions.
Marketing and trading and electric retail segments' revenues increased
approximately $865 million because of:
* changes in marketing and trading revenues ($241 million, net increase) due
to:
- increased revenues related to generation sales other than native load
as a result of higher market prices ($86 million);
- increased realized revenues related to other marketing and trading in
current period primarily due to more transactions and higher market
prices ($144 million);
- decreased prior period mark-to-market value for gains transferred to
realized margin in current period ($2 million);
- increased mark-to-market value for future periods primarily as a
result of more forward sales volumes ($13 million);
* increased revenues related to increased volumes and higher market prices
for other wholesale sales resulting from retail load hedging activities and
miscellaneous revenues ($523 million);
* increased retail revenues primarily related to higher sales volumes due to
customer growth ($129 million); and
* decreased retail revenues related to reductions in retail electricity
prices ($28 million).
Purchased power and fuel expenses increased approximately $763 million
primarily due to:
* changes in marketing and trading purchased power and fuel costs ($130
million, net increase) due to:
- increased fuel costs related to generation sales other than native
load as a result of higher fuel prices ($39 million);
- increased fuel and purchased power costs related to other realized
marketing and trading in current period primarily due to more
transactions ($91 million);
* increased costs related to increased volumes and higher market prices for
wholesale sales resulting from retail hedging activities ($513 million);
and
* higher costs related to retail sales volumes due to customer growth and
increased fuel and purchased power prices ($120 million).
11
The decrease in operations and maintenance expenses of $7 million primarily
related to $19 million of non-recurring items recorded in 1999 partially offset
by increased costs related to customer growth.
The increase in depreciation and amortization of $9 million primarily
related to higher plant in service balances offset by lower regulatory asset
amortization.
REGULATORY AGREEMENTS
Regulatory agreements approved by the ACC affect the results of our
operations. The following discussion focuses on three agreements approved by the
ACC, each of which included retail electricity price reductions:
* The 1999 Settlement Agreement to implement retail electric
competition;
* A 1996 agreement that accelerated the amortization of our regulatory
assets; and
* A 1994 settlement that accelerated the amortization of our deferred
ITCs.
1999 SETTLEMENT AGREEMENT
As part of the 1999 Settlement Agreement, we agreed to reduce retail
electricity prices for standard-offer, full-service customers with loads less
than three megawatts in a series of annual decreases of 1.5% on July 1, 1999
through July 1, 2003, for a total of 7.5%. The first reduction of approximately
$24 million ($14 million after income taxes) included the July 1, 1999 retail
price decrease required by the 1996 regulatory agreement (see below). For
customers having loads three megawatts or greater, standard-offer rates will be
reduced in annual increments that total 5% in the years 1999 through 2002.
The 1999 Settlement Agreement also removed, as a regulatory disallowance,
$234 million before income taxes ($183 million net present value) from ongoing
regulatory cash flows. We recorded this regulatory disallowance as a net
reduction of regulatory assets and reported it as a $140 million after-tax
extraordinary charge on the 1999 income statement.
Under the 1996 regulatory agreement, we were recovering substantially all
of our regulatory assets through accelerated amortization over an eight-year
period that would have ended June 30, 2004. For more details, see Note 1. The
regulatory assets to be recovered under the 1999 Settlement Agreement are
currently being amortized as follows (dollars in millions):
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $ 86 $ 18 $686
12
See Note 3 and "Business Outlook - Electric Competition (Retail)" below for
additional information regarding the 1999 Settlement Agreement.
1996 REGULATORY AGREEMENT
As part of the 1996 regulatory agreement, we reduced our retail electricity
prices by 3.4% effective July 1, 1996. This reduction decreased electric revenue
by about $49 million annually ($29 million after income taxes). We also agreed
to share future cost savings with our customers during the term of this
agreement, which resulted in the following additional retail price reductions:
* $18 million annually ($11 million after income taxes), or 1.2%,
effective July 1, 1997;
* $17 million annually ($10 million after income taxes), or 1.1%,
effective July 1, 1998; and
* $11 million annually ($7 million after income taxes), or 0.7%,
effective July 1, 1999 (as noted above, this reduction was included in
the July 1, 1999 price reduction under the 1999 Settlement Agreement).
1994 RATE SETTLEMENT
As part of a 1994 rate settlement, we accelerated amortization of
substantially all of our ITCs over a five-year period that ended on December 31,
1999. The amortization of ITCs decreased annual income tax expense by about $28
million. Beginning in 2000, no further benefits were reflected in income tax
expense related to the acceleration of the ITCs (see Note 4).
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL NEEDS AND RESOURCES
CAPITAL EXPENDITURE REQUIREMENTS
The following table summarizes the actual capital expenditures for the year
ended December 31, 2001 and estimated capital expenditures for the next three
years.
13
CAPITAL EXPENDITURES
(dollars in millions)
(actual) (estimated)
-------- --------------------------
2001 2002 2003 2004
---- ---- ---- ----
Delivery $354 $349 $271 $280
Generation (a) 117 149 -- --
---- ---- ---- ----
Total $471 $498 $271 $280
==== ==== ==== ====
(a) Pursuant to the 1999 Settlement Agreement, we are required to transfer our
competitive electric assets and services no later than December 31, 2002.
We and the other Palo Verde participants are currently considering issues
related to replacement of the steam generators in Units 1 and 3. Although a
final determination of whether Units 1 and 3 will require steam generator
replacement to operate over their current full licensed lives has not yet been
made, the other participants and us have approved an expenditure in 2002 to
procure long lead-time materials for fabrication of a spare set of steam
generators for either Unit 1 or 3. Our portion of this expenditure is
approximately $7 million and is included in the estimated expenditures above.
This action will provide the other Palo Verde participants and us an option to
replace the steam generators at either Unit 1 or 3 as early as fall 2005 should
we ultimately choose to do so. If the participants decide to proceed with steam
generator replacement at both Units 1 and 3, we have estimated that our portion
of the fabrication and installation costs and associated power uprate
modifications would be approximately $130 million over the next seven years,
which would be funded with internally-generated cash or external financings.
Generation capital expenditures are comprised of multiple improvements for
our 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. The increase in this category in 2002 is due primarily to Four
Corners and various gas-fired units. The increased work on equipment is due to
higher use of the units and also a stack replacement project for Four Corners
Units 1 and 2. The 2002 generation category also contains approximately $30
million of nuclear fuel expenditures.
Delivery capital expenditures are comprised of transmission and
distribution (T&D) infrastructure additions and upgrades, capital replacements,
new customer construction, and related information systems and facility costs.
Examples of the types of projects included in the forecast include T&D lines and
substations, line extensions to new residential and commercial developments, and
upgrades to customer information systems. In addition, we began several major
transmission projects in 2001. These projects are periodic in nature and are
driven by strong regional customer growth. We expect to spend about $150 million
on major transmission projects during the 2002-2004 time frame.
14
CAPITAL RESOURCES AND CASH REQUIREMENTS
We had lines of credit available in the amount of $250 million at December
31, 2001. There was no outstanding balance on our lines of credit at December
31, 2001. We project that these lines of credit will be available over the next
three years. The lines of credit are anticipated to be renewed at their
expiration dates. See Note 5 for further information on our lines of credit.
We have obtained approximately $500 million in letters of credit primarily
to provide credit support for our variable rate tax-exempt bonds and our Palo
Verde sale-leaseback transactions.
We do not have ratings triggers in any of our debt agreements. Ratings
triggers are provisions that would result in the acceleration of repayment
obligations based upon a credit rating agency downgrade. Although those rating
triggers appear in certain power marketing and trading agreements, their
financial impacts are not expected to be significant.
Our first mortgage bondholders share a lien on substantially all utility
plant assets (other than nuclear fuel, transportation equipment and other
excluded assets). The mortgage bond indenture restricts the payment of common
stock dividends under certain conditions. These conditions did not exist at
December 31, 2001.
Our capital requirements consist primarily of capital expenditures and
optional and mandatory redemptions of long-term debt. We pay for our capital
requirements with cash from operations and, to the extent necessary, external
financing. We pay for our dividends to Pinnacle West with cash from operations.
During the period from 1999 through 2001, we paid for substantially all of
our capital expenditures with cash from operations. We expect to do so in 2002
through 2004 with cash from operations and our debt issuances.
See the capital expenditure table above for additional information
regarding actual capital expenditures in 2001 and projected capital expenditures
for the next three years.
15
The following table summarizes cash commitments for the year ended December
31, 2001 and estimated commitments for the next three years (dollars in
millions):
(actual) (estimated)
-------- --------------------
2001 2002 2003 2004
---- ---- ---- ----
Long-term debt repayments (see Note 6) $384 $247 $ -- $205
Operating leases payments (see Note 8) 62 63 61 61
Fuel and purchase power commitments
(see Note 10) 374 252 124 80
---- ---- ---- ----
Total cash commitments $820 $562 $185 $346
==== ==== ==== ====
Based on market conditions and call provisions, we may make optional
redemptions of long-term debt from time to time.
As of December 31, 2001, we had credit commitments from various banks
totaling about $250 million, which were available either to support the issuance
of commercial paper or to be used as bank borrowings. At the end of 2001, we had
about $171 million of commercial paper outstanding and no long-term bank
borrowings.
Our long-term debt was approximately $2.1 billion at December 31, 2001 and
2000 (see Note 6).
Although ACC financing orders establish maximum amounts of additional debt
that we may issue, we do not expect these orders to limit our ability to meet
our capital requirements.
On March 1, 2002, we issued $375 million of 6.50% Notes due 2012. On March
15, 2002, we announced the redemption on April 15, 2002 of approximately $125
million of our First Mortgage Bonds, 8.75% Series due 2024.
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with generally accepted
accounting principles (GAAP), management must often make estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues,
expenses, and related disclosures at the date of the financial statements and
during the reporting period. Some of those judgments can be subjective and
complex, and actual results could differ from those estimates. Our most critical
accounting policies include the determination of the appropriate accounting for
our derivative instruments, mark-to-market accounting and the impacts of
regulatory accounting on our financial statements. See Note 1 for a discussion
of these critical accounting policies.
16
OTHER ACCOUNTING MATTERS
In June 2002, the FASB's EITF issued certain guidance related to energy
trading activities in EITF 02-3, "Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and
Risk Management Activities." The new guidance, which was effective July 1, 2002,
required that all energy trading activities within the scope of EITF 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities," be presented on a net basis in revenues and that prior period
amounts be restated.
In October 2002, the EITF reached a consensus that gains and losses on
derivative instruments within the scope of SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" should be shown net in the income
statement if the derivative is held for trading purposes. This decision
effectively supersedes the guidance provided at the June meeting. Historically,
we have reported our electric revenues and purchased power and fuel costs on a
gross basis in our statements of income, with the exception of unrealized gains
and losses recorded under the mark-to-market method. When the gain or loss was
realized, the gross amount was recorded as revenue and purchased power and fuel
costs in the statements of income. Throughout this document, we have made the
reclassification change to net revenues and purchased power and fuel costs
related to our energy trading activities. This change has no impact on our gross
margin, net income or cash provided by operating activities. The following table
shows the impact of the change on our Marketing and Trading segment revenues and
purchased power and fuel costs:
Year ended December 31,
(dollars in thousands)
------------------------------
2001 2000 1999
-------- -------- --------
Marketing and trading segment revenues before
reclassification $748,704 $941,502 $378,076
Less: Purchased power and fuel costs netted
with revenues 199,464 546,110 223,950
-------- -------- --------
Marketing and trading segment revenues after
reclassification $549,240 $395,392 $154,126
======== ======== ========
Marketing and trading segment purchased power
and fuel before reclassification $513,455 $813,142 $360,472
Less: Purchased power and fuel costs netted
with revenues 199,464 546,110 223,950
-------- -------- --------
Marketing and trading segment purchased power
and fuel after reclassification $313,991 $267,032 $136,522
======== ======== ========
17
In the October 2002 meeting, the EITF also rescinded EITF 98-10. This
guidance is effective immediately for all new contracts and on January 1, 2003
for existing contracts. As such, energy trading contracts will be accounted for
on an accrual basis with the associated revenues and costs recorded at the time
the contracted commodities are delivered or received, unless the contracts are
required to be marked to market as derivatives under SFAS No. 133 or if allowed
by other guidance. For existing contracts, we will record a cumulative effect
adjustment in net income for the previously recorded accumulated unrealized
mark-to-market on energy trading contracts that do not meet the definition of a
derivative under SFAS No. 133. We are currently evaluating the impact of this
guidance on our financial statements.
We prepare our financial statements in accordance with SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." SFAS No. 71
requires a cost-based, rate-regulated enterprise to reflect the impact of
regulatory decisions in its financial statements. As a result of the 1999
Settlement Agreement (see "Regulatory Agreements" above and Note 3), we
discontinued the application of SFAS No. 71 for our generation operations. As a
result, we tested the generation assets for impairment and determined that the
generation assets were not impaired. Pursuant to the 1999 Settlement Agreement,
we reported a regulatory disallowance ($140 million after income taxes) as an
extraordinary charge on the 1999 income statement. See Note 1 for additional
information on regulatory accounting and Note 3 for additional information on
the 1999 Settlement Agreement.
Effective January 1, 2001, we adopted SFAS No. 133. SFAS No. 133 requires
that entities recognize all derivatives as either assets or liabilities on the
balance sheets and measure those instruments at fair value. Changes in the fair
value of derivative financial instruments are either recognized periodically in
income or stockholders' equity (as a component of other comprehensive income),
depending on whether or not the derivative meets specific hedge accounting
criteria. Hedge effectiveness is measured based on the relative changes in fair
value between the derivative contract and the hedged commodity over time. Any
change in the fair value resulting from ineffectiveness is recognized
immediately in net income. This new standard may result in additional volatility
in our net income and other comprehensive income.
As a result of adopting SFAS No. 133 in 2001, we recorded a $15 million
after-tax loss in net income and a $72 million after-tax gain in equity (as a
component of other comprehensive income), both as a cumulative effect of a
change in accounting principle. The loss primarily resulted from electricity
options contracts. The gain resulted from unrealized gains on cash flow hedges.
See Note 16 for further information on accounting for derivatives under SFAS No.
133, including discussions on new guidance effective on April 1, 2002.
In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets." This Statement addresses financial accounting and reporting for
acquired goodwill and other intangible assets and supersedes Accounting
Principles Board Opinion No. 17, "Intangible Assets." This standard is effective
for the year beginning January 1, 2002. We have no goodwill recorded in the
balance sheets. The impacts of this new standard are not material to our
financial statements.
18
The FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations," in August 2001. The standard requires the estimated present value
of the cost of decommissioning and certain other removal costs to be recorded as
a liability, along with an offsetting plant asset, when a decommissioning or
other removal obligation is incurred. We are currently evaluating the impacts of
the new standard, which is effective for the year beginning January 1, 2003.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." This statement supersedes SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of," and the accounting and reporting provisions for the
disposal of a segment of a business. SFAS No. 144 is effective for the year
beginning January 1, 2002. This standard does not impact our financial
statements at adoption.
In 2001, the American Institute of Certified Public Accountants (AICPA)
issued an exposure draft of a proposed Statement of Position (SOP), "Accounting
for Certain Costs Related to Property, Plant and Equipment (PP&E)." This
proposed SOP would create a project timeline framework for capitalizing costs
related to PP&E construction, require that PP&E assets be accounted for at the
component level and require administrative and general cost incurred in support
of capital projects to be expensed in the current period. The AICPA plans to
issue the final SOP in the fourth quarter of 2002. We are currently evaluating
the impacts of the proposed SOP.
In 1986, we entered into agreements with three separate special purpose
entity (SPE) lessors in order to sell and lease back interests in Palo Verde
Unit 2 (see Note 8). The leases are accounted for as operating leases in
accordance with GAAP. In February 2002, the FASB discussed issues related to
special purpose entities. It is expected that FASB will issue additional
guidance on accounting for SPEs later this year. As a result of future FASB
actions, we may be required to consolidate the SPEs in our financial statements.
If consolidation is required, the assets and liabilities of the SPEs that relate
to the sale-leaseback transactions would be reflected on our balance sheets. The
SPE debt that is not reflected on our balance sheets is approximately $300
million at December 31, 2001. Rating agencies have already considered this debt
when evaluating our credit ratings.
BUSINESS OUTLOOK
FINANCIAL OUTLOOK
For 2001, our reported income before accounting change was $281 million and
included charges totaling $13 million before income taxes that we do not expect
to recur related to our exposure to Enron and its affiliates. Our earnings in
2002 are expected to be negatively affected by the completed transition to
Pinnacle West in 2001 of marketing and trading activities, as well as retail
electricity price decreases. These negative factors are expected to be partially
offset in 2002 by the absence of significant expenses for reliability and power
plant outages that we incurred in 2001 that we do not expect to recur in 2002
and by retail customer growth, although the pace of growth is expected to be
slower than in the past. These factors are described in more detail below.
19
As of December 31, 2001, we completed the transition of marketing and
trading activities to Pinnacle West's marketing and trading division. In 2001,
we recorded the following pretax amounts related to marketing and trading
activities: $549 million of electric operating revenues and $314 million of
purchased power and fuel costs.
During 2001, in order to meet the highest customer demand in our history,
we incurred significant expenses for our summer reliability program and for
higher replacement power costs related to power plant outages. These efforts
cost approximately $140 million before income taxes, which is not expected to be
repeated in 2002. See "Results of Operations - 2001 Compared with 2000" above.
We estimate our retail customer growth in 2002 to be 3.2%, which is slower
than the pace of growth in recent years, although still about three times the
national average. Our customer growth in 2001 was 3.7%. We expect the customer
growth rate to be weak in the first two quarters of 2002, then begin a rebound.
Our current estimate for customer growth in 2003 and 2004 is between 3.5% and
4.0% annually.
The retail price decreases are described above in "Results of Operations -
Regulatory Agreements."
The foregoing discussion of future expectations is forward-looking
information. Actual results may differ materially from expectations. See
"Forward-Looking Statements" below.
OTHER FACTORS AFFECTING OUR FINANCIAL OUTLOOK
COMPETITION AND INDUSTRY RESTRUCTURING
ELECTRIC COMPETITION (WHOLESALE)
The FERC regulates rates for wholesale power sales and transmission
services. Pinnacle West's marketing and trading division sells in the wholesale
market our generation production output that is not needed for our native load
and, in doing so, competes with other utilities, power marketers, and
independent power producers. Wholesale market prices significantly fell during
2001 and remain low for the reasons discussed under "Financial Outlook" above.
We cannot predict whether these lower prices will continue, or whether changes
in various factors that affect demand and capacity, including regulatory
actions, will cause the market prices to rise during 2002 or thereafter.
20
ELECTRIC COMPETITION (RETAIL)
On September 21, 1999, the ACC approved Rules that provide a framework for
the introduction of retail electric competition in Arizona. A Maricopa County,
Arizona, Superior Court later found the Rules unlawful and unconstitutional;
however, the Rules remain in effect pending the outcome of appeals. See "Retail
Electric Competition Rules" in Note 3 for additional information about the Rules
and the outstanding legal challenges to the Rules.
Although the Rules allow retail customers to have access to competitive
providers of energy and energy services, we are the "provider of last resort"
for standard-offer, full service customers under rates that have been approved
by the ACC. These rates are established until July 1, 2004. The 1999 Settlement
Agreement allows us to seek adjustment of these rates in the event of emergency
conditions or circumstances, such as the inability to secure financing on
reasonable terms, or material changes in our cost of service for ACC-regulated
services resulting from federal, tribal, state or local laws, regulatory
requirements, judicial decisions, actions or orders. Energy prices in the
western U.S. wholesale market vary and, during the course of the last two years,
have been volatile. At various times, prices in the spot wholesale market have
significantly exceeded the amount included in our current retail rates. In the
event of shortfalls due to unforeseen increases in load demand or generation
outages, we may need to purchase additional supplemental power in the wholesale
spot market. Unless we are able to obtain an adjustment of our rates under the
1999 Settlement Agreement, there can be no assurance that we would be able to
fully recover the costs of this power.
On September 23, 1999, the ACC approved a comprehensive 1999 Settlement
Agreement among us and various parties related to the implementation of retail
electric competition in Arizona. See "1999 Settlement Agreement" in Note 3 for
additional information about the 1999 Settlement Agreement, including the recent
resolution of legal challenges to the 1999 Settlement Agreement.
Under the Rules, as modified by the 1999 Settlement Agreement, we are
required to transfer our competitive electric assets and services either to an
unaffiliated party or to a separate corporate affiliate no later than December
31, 2002. Consistent with that requirement, we have been addressing the legal
and regulatory requirements necessary to complete the transfer of our generation
assets to Pinnacle West Energy on or before that date. In anticipation of our
transfer of generation assets, Pinnacle West Energy has completed, and is in the
process of developing and planning, various generation expansion projects so
that we can reliably meet the energy requirements of our Arizona customers.
Following the transfer of our fossil-fueled generation assets and the
receipt of certain regulatory approvals, Pinnacle West Energy expects to sell
its power at wholesale to Pinnacle West's marketing and trading division, which,
in turn, is expected to sell power to us and to non-affiliated power purchasers.
In a filing with the ACC on October 18, 2001, we requested the ACC to:
* grant us a partial variance from an ACC Rule that would obligate us to
acquire all of our customers' standard-offer generation requirements
21
from the competitive market (with at least 50% of those requirements
coming from a "competitive bidding" process) starting in 2003; and
* approve as just and reasonable a long-term purchase power agreement
between us and Pinnacle West.
We requested these ACC actions to ensure ongoing reliable service to our
standard-offer, full-service customers in a volatile generation market and to
recognize Pinnacle West Energy's significant investment to serve our load. See
"Proposed Rule Variance and Purchase Power Agreement" in Note 3 for additional
information about our October 2001 ACC filing.
On February 8, 2002, the ACC's Chief ALJ issued a procedural order which
consolidated the ACC docket relating to our October 2001 filing with several
other pending ACC dockets, including a "generic" docket request by the ACC
Chairman to "determine if changed circumstances require the [ACC] to take
another look at restructuring in Arizona." Although the order consolidates
several dockets, it states that a hearing on the matter will commence on April
29, 2002. The order went on to state that, contrary to our position, the ALJ was
construing the October 2001 filing as a request by us to amend the 1999 ACC
order that approved the 1999 Settlement Agreement.
On March 22, 2002, the ACC Staff issued a report to the ACC recommending
that the ACC address the following issues in the generic docket:
* The extent and manner of the ACC's involvement in monitoring market
conditions and/or mitigating the development of market power for
generation and transmission;
* The lack of guidance in the Rules regarding the mechanics of the
"competitive bidding process" referenced above;
* The consideration of alternatives to the transfer of generation assets
required by the Rules (the ACC Staff stated that such transfers would
be "unwise" at the present time and recommended that "all transfer and
separation of utilities' assets be stayed pending the completion of
the generic docket");
* The consideration of transmission constraints that could impact the
development of the wholesale power market;
* The reassessment of adjustor mechanisms for standard-offer rates in
light of problems with the development of a wholesale power market;
and
* The adequacy of customer "shopping credits" in the context of the
development of a competitive retail market (a shopping credit is the
cost a customer does not pay to a utility distribution company if the
customer obtains generation from another party).
Although not a specific ACC Staff recommendation, the report was also critical
of certain aspects of the proposed purchase power agreement between the Company
and Pinnacle West.
22
A modification to the Rules or the 1999 Settlement Agreement as a result of
the consolidated docket could, among other things, adversely affect our ability
to transfer our generation assets to Pinnacle West Energy by December 31, 2002.
We cannot predict the outcome of the consolidated docket or its effect on the
specific requests in our October 2001 filing, the existing Arizona electric
competition rules, or the 1999 Settlement Agreement.
As a result of the foregoing matters, as well as energy market
developments, including those relating to California's failed deregulation
efforts and to Enron's recent bankruptcy filing, electric utility restructuring
is in a state of flux in the western United States, including Arizona, and
around the country.
CALIFORNIA ENERGY MARKET ISSUES
See Note 10 for information regarding California energy market issues.
FACTORS AFFECTING OPERATING REVENUES
Electric operating revenues are derived from sales of electricity in
regulated retail markets in Arizona, and from competitive retail and wholesale
bulk power markets in the western United States. These revenues are expected to
be affected by electricity sales volumes related to customer mix, customer
growth and average usage per customer, as well as electricity prices and
variations in weather from period to period.
In our regulated retail market area, we will provide electricity services
to standard-offer, full-service customers and to energy delivery customers who
have chosen another provider for their electricity commodity needs (unbundled
customers). Customer growth in our service territory averaged about 4% a year
for the three years 1999 through 2001; we currently expect customer growth to be
about 3.2% in 2002 and between 3.5% and 4.0% a year in 2003 and 2004. We
currently estimate that retail electricity sales in kilowatt-hours will grow
3.5% to 5.5% a year in 2002 through 2004, before the retail effects of weather
variations. The customer growth and sales growth referred to in this paragraph
apply to energy delivery customers. As industry restructuring evolves in the
regulated market area, we cannot predict the number of our standard-offer
customers that will switch to unbundled service. As previously noted, under the
1999 Settlement Agreement, we have annual retail electricity price reductions of
1.5% through July 1, 2003 (see Note 3).
OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS
Purchased power and fuel costs are impacted by our electricity sales
volumes, existing contracts for generation fuel and purchased power, our power
plant performance, prevailing market prices, new generating plants being placed
in service, and our hedging program for managing such costs. See "Generating
Fuel and Purchased Power-Natural Gas Supply" in Part I for additional
information on a pending dispute related to a natural gas-fired transportation
contract with El Paso Natural Gas Company.
23
Operations and maintenance expenses are expected to be affected by sales
mix and volumes, power plant operations, inflation, outages and other factors.
Depreciation and amortization expenses are expected to be affected by net
additions to existing utility plant and other property and changes in regulatory
asset amortization. See Note 1 for the regulatory asset amortization that is
being recorded in 1999 through 2004 pursuant to the 1999 Settlement Agreement.
Also, see Note 1 regarding current depreciation rates.
Taxes other than income taxes consist primarily of property taxes, which
are affected by tax rates and the value of property in service and under
construction. The average property tax rate for us was 9.32% for 2001 and 9.16%
for 2000. We expect property taxes to increase primarily due to our additions to
existing facilities.
Interest expense is affected by the amount of debt outstanding and the
interest rates on that debt. The primary factors affecting borrowing levels in
the next several years are expected to be our internally-generated cash flow.
We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, results of operations, or liquidity. As
competition in the electric industry continues to evolve, we will continue to
evaluate strategies and alternatives that will position us to compete
effectively in a restructured industry.
Our financial results may be affected by the application of SFAS No. 133.
See "Critical Accounting Policies" above and Note 16 for further information.
Our financial results may be affected by a number of broad factors. See
"Forward-Looking Statements" below for further information on such factors,
which may cause our actual future results to differ from those we currently seek
or anticipate.
MARKET RISKS
Our operations include managing market risks related to changes in interest
rates, commodity prices, and investments held by the nuclear decommissioning
trust fund.
INTEREST RATE AND EQUITY RISK
Our major financial market risk exposure is changing interest rates.
Changing interest rates will affect interest paid on variable-rate debt and
interest earned by our nuclear decommissioning trust fund (see Note 11). Our
policy is to manage interest rates through the use of a combination of
fixed-rate and floating-rate debt. The nuclear decommissioning fund also has
risks associated with changing market values of equity investments. Nuclear
decommissioning costs are recovered in regulated electricity prices.
The tables below present contractual balances of our long-term debt and
commercial paper at the expected maturity dates as well as the fair value of
24
those instruments on December 31, 2001 and 2000. The interest rates presented in
the tables below represent the weighted average interest rates for the years
ended December 31, 2001 and 2000.
Expected Maturity/Principal Repayment
December 31, 2001
(dollars in thousands)
Variable-Rate Fixed-Rate
Short-Term Debt Long-Term Debt Long-Term Debt
--------------------- --------------------- --------------------
Interest Interest Interest
Rates Amount Rates Amount Rates Amount
----- ----------- ----- ----------- ----- -----------
2002 4.72% $ 171,162 $ -- 8.10% $ 125,451
2003 -- -- 6.18% 337
2004 -- -- 6.08% 205,185
2005 -- -- 7.59% 400,185
2006 -- -- 6.77% 83,880
Years thereafter -- 2.60% 476,860 6.73% 787,894
----------- ----------- -----------
Total $ 171,162 $ 476,860 $ 1,602,932
=========== =========== ===========
Fair Value $ 171,162 $ 476,860 $ 1,621,937
=========== =========== ===========
Expected Maturity/Principal Repayment
December 31, 2000
(dollars in thousands)
Variable-Rate Fixed-Rate
Short-Term Debt Long-Term Debt Long-Term Debt
--------------------- --------------------- --------------------
Interest Interest Interest
Rates Amount Rates Amount Rates Amount
----- ----------- ----- ----------- ----- -----------
2001 6.64% $ 82,100 7.33% $ 250,000 7.75% $ 266
2002 -- -- 8.13% 125,000
2003 -- -- 7.75% 443
2004 -- -- 6.17% 205,000
2005 -- -- 7.28% 400,000
Years thereafter -- 4.06% 476,860 7.48% 605,598
----------- ----------- -----------
Total $ 82,100 $ 726,860 $ 1,336,307
=========== =========== ===========
Fair Value $ 82,100 $ 726,860 $ 1,393,251
=========== =========== ===========
COMMODITY PRICE RISK
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal, and emissions
allowances. We employ established procedures to manage risks associated with
these market fluctuations by utilizing various commodity derivatives, including
25
exchange-traded futures and options and over-the-counter forwards, options, and
swaps. As part of our overall risk management program, we enter into derivative
transactions to hedge purchases and sales of electricity, fuels, and emissions
allowances and credits. The changes in market value of such contracts have a
high correlation to price changes in the hedged commodity.
In addition, subject to specified risk parameters established by the
Pinnacle West Board of Directors and monitored by Pinnacle West's ERMC, we
engage in trading activities intended to profit from market price movements. In
accordance with Emerging Issues Task Force (EITF) 98-10 "Accounting For
Contracts Involved in Energy Trading and Risk Management Activities", such
trading positions are marked-to-market (see Note 18). These trading activities
are part of our marketing and trading activities and are reflected in the
marketing and trading revenues and expenses.
The following schedule shows the changes in mark-to-market of our trading
positions during the years ended December 31, 2001 and 2000 (dollars in
millions):
2001 2000
----- -----
Mark-to-market of net trading positions
at beginning of year $ 12 $ --
Prior period mark-to-market (gains)
losses realized during the year 7 (2)
Change in mark-to-market gains for
future period activities 85 14
Transfer of mark-to-market balance
to Pinnacle West marketing and
trading (104) --
----- -----
Mark-to-market of net trading positions
at end of year $ -- $ 12
===== =====
As of December 31, 2001, a hypothetical adverse price movement of 10% in
the market price of our risk management and trading assets and liabilities that
would have decreased the fair market value of these contracts by approximately
$23 million, compared to a $28 million decrease that would have been realized as
of December 31, 2000. A hypothetical favorable price movement of 10% would have
increased the fair market value of these contracts by approximately $23 million,
compared to a $28 million increase that would have been realized as of December
31, 2000. These contracts are hedges of our forecasted purchases of natural gas.
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.
We are exposed to losses in the event of nonperformance or nonpayment by
counterparties. We use a risk management process to assess and monitor the
financial exposure of this and all other counterparties. Despite the fact that
the great majority of our counterparties are rated as investment grade by the
credit rating agencies there is still a possibility that one or more of these
companies could default, resulting in a material impact on earnings for a given
period. Counterparties in the portfolio consist principally of major energy
companies, municipalities, and local distribution companies. We maintain credit
26
policies that we believe minimize overall credit risk to within acceptable
limits. Determination of the credit quality of our counterparties is based upon
a number of factors, including credit ratings and our evaluation of their
financial condition. In many contracts, we employ collateral requirements and
standardized agreements that allow for the netting of positive and negative
exposures associated with a single counterparty. Credit reserves are established
representing our estimated credit losses on our overall exposure to
counterparties. See Note 1 for a discussion of our credit reserve policy.
FORWARD-LOOKING STATEMENTS
The above discussion contains forward-looking statements based on current
expectations and we assume no obligation to update these statements. Because
actual results may differ materially from expectations, we caution readers not
to place undue reliance on these statements. A number of factors could cause
future results to differ materially from historical results, or from results or
outcomes currently expected or sought by us. These factors include the ongoing
restructuring of the electric industry, including the introduction of retail
electric competition in Arizona and our October 2001 ACC filing; the outcome of
regulatory and legislative proceedings relating to the restructuring; state and
federal regulatory and legislative decisions and actions, including the price
mitigation plan adopted by the FERC in June 2001; regional economic and market
conditions, including the California energy situation and completion of
generation construction in the region, which could affect customer growth and
the cost of power supplies; the cost of debt and equity capital; weather
variations affecting local and regional customer energy usage; conservation
programs; power plant performance; our ability to compete successfully outside
traditional regulated markets (including the wholesale market); and
technological developments in the electric industry.
These factors and the other matters discussed above may cause future
results to differ materially from historical results, or from results or
outcomes we currently expect or seek.
QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
See "Market Risks" for a discussion of quantitative and qualitative
disclosures about market risk.
27
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
Report of Management..........................................................29
Independent Auditors' Report..................................................30
Statements of Income for 2001, 2000 and 1999..................................31
Balance Sheets as of December 31, 2001 and 2000...............................32
Statements of Cash Flows for 2001, 2000 and 1999..............................34
Statements of Changes in Common Stock Equity for 2001, 2000 and 1999..........35
Notes to Financial Statements.................................................36
Financial Statement Schedule for 2001, 2000 and 1999 Schedule II - Reserve
for 2001, 2000 and 1999.....................................................77
See Note 12 of Notes to Financial Statements for the selected quarterly
financial data required to be presented in this Item.
28
REPORT OF MANAGEMENT
The responsibility for the integrity of our financial information rests
with management, which has prepared the accompanying financial statements and
related information. This information was prepared in accordance with generally
accepted accounting principles as appropriate in the circumstances, and based on
management's best estimates and judgments. These financial statements have been
audited by independent auditors and their report is included on the following
page.
Management maintains and relies upon systems of internal control. A
limiting factor in all systems of internal control is that the cost of the
system should not exceed the benefits to be derived. Management believes that
our system provides the appropriate balance between such costs and benefits.
Periodically the internal control system is reviewed by both our internal
auditors to test for compliance and our independent auditors in conjunction with
their audit of our financial statements. Reports issued by the internal auditors
are released to management, and such reports or summaries thereof are
transmitted to the Audit Committee of the Board of Directors and the independent
auditors on a timely basis. By letter dated February 8, 2002, to the Audit
Committee, our independent auditors confirmed that they are independent
accountants with respect to us within the meaning of the Securities Act and the
requirements of the Independence Standards Board.
The Audit Committee, composed solely of outside directors, meets
periodically with the internal auditors and independent auditors (as well as
management) to review the work of each. The internal auditors and independent
auditors have free access to the Audit Committee, without management present, to
discuss the results of their audit work.
Management believes that our systems, policies and procedures provide
reasonable assurance that operations are conducted in conformity with the law
and with management's commitment to a high standard of business conduct.
William J. Post Chris N. Froggatt
Chairman and Vice President and Controller
Chief Executive Officer
29
INDEPENDENT AUDITORS' REPORT
To the Stockholder of
Arizona Public Service Company
Phoenix, Arizona
We have audited the accompanying balance sheets of Arizona Public Service
Company as of December 31, 2001 and 2000, and the related statements of income,
changes in common stock equity and cash flows for each of the three years in the
period ended December 31, 2001. Our audits also included the financial statement
schedule listed in the accompanying Index. These financial statements and the
financial statement schedule are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements and
the financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of Arizona Public Service Company at December
31, 2001 and 2000, and the results of its operations and its cash flows for each
of the three years in the period ended December 31, 2001, in conformity with
accounting principles generally accepted in the United States of America. Also,
in our opinion, such financial statement schedule, when considered in relation
to the basic financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.
As discussed in Note 16 of the financial statements, in 2001 Arizona Public
Service Company changed its method of accounting for derivatives and hedging
activities in order to comply with the provisions of Statement of Financial
Accounting Standards No. 133.
DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Phoenix, Arizona
February 8, 2002 (March 22, 2002, as to Note 17 and February 24, 2003, as to
Note 18)
30
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31,
-----------------------------------------
2001 2000 1999
----------- ----------- -----------
(DOLLARS IN THOUSANDS)
Electric Operating Revenues
Electric retail segment ........................... $ 2,562,088 $ 2,538,750 $ 1,914,722
Marketing and trading segment ..................... 549,240 395,392 154,126
----------- ----------- -----------
Total ........................................... 3,111,328 2,934,142 2,068,848
----------- ----------- -----------
Purchased Power and Fuel Costs:
Electric retail segment ........................... 1,227,188 1,065,596 432,844
Marketing and trading segment ..................... 313,991 267,032 136,522
----------- ----------- -----------
Total ........................................... 1,541,179 1,332,628 569,366
----------- ----------- -----------
Operating Revenues less Purchased Power
and Fuel Costs ..................................... 1,570,149 1,601,514 1,499,482
----------- ----------- -----------
Other Operating Expenses:
Operations and maintenance ........................ 465,561 430,092 437,125
Depreciation and amortization ..................... 420,893 425,479 416,331
Income taxes (Note 4) ............................. 183,640 199,977 165,629
Other taxes ....................................... 101,077 99,730 96,579
----------- ----------- -----------
Total ........................................... 1,171,171 1,155,278 1,115,664
----------- ----------- -----------
Operating Income ..................................... 398,978 446,236 383,818
Other Income (Deductions):
Income taxes ...................................... 504 4,312 32,614
Other income ...................................... 20,207 9,690 13,861
Other expense ..................................... (20,790) (20,547) (25,618)
----------- ----------- -----------
Total ........................................... (79) (6,545) 20,857
----------- ----------- -----------
Income Before Interest Deductions .................... 398,899 439,691 404,675
----------- ----------- -----------
Interest Deductions:
Interest on long-term debt ........................ 126,118 134,431 132,676
Interest on short-term borrowings ................. 4,407 7,455 8,272
Debt discount, premium and expense ................ 2,650 2,105 2,084
Capitalized interest .............................. (14,964) (10,894) (6,679)
----------- ----------- -----------
Total ........................................... 118,211 133,097 136,353
----------- ----------- -----------
Income Before Extraordinary Charge and Cumulative
Effect Adjustment ................................. 280,688 306,594 268,322
Extraordinary Charge - net of income taxes
of $94,115 (Note 1) ............................... -- -- (139,885)
Cumulative Effect of Change in Accounting
for Derivatives - net of income taxes of
$9,892 ............................................ (15,201) -- --
----------- ----------- -----------
Net Income ........................................... 265,487 306,594 128,437
Preferred Stock Dividend Requirements ................ -- -- 1,016
----------- ----------- -----------
Earnings for Common Stock ............................ $ 265,487 $ 306,594 $ 127,421
=========== =========== ===========
See Notes to Financial Statements.
31
ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
ASSETS
DECEMBER 31,
--------------------------
2001 2000
----------- -----------
(DOLLARS IN THOUSANDS)
Utility Plant (Notes 1, 8 and 9):
Electric plant in service and held for future use ........... $ 8,105,106 $ 7,805,025
Less accumulated depreciation and amortization .............. 3,374,098 3,187,328
----------- -----------
Total ................................................ 4,731,008 4,617,697
Construction work in progress ............................... 321,305 245,749
Nuclear fuel, net of accumulated amortization of $56,836
and $61,836 ............................................... 49,282 47,389
----------- -----------
Utility Plant -- net ...................................... 5,101,595 4,910,835
----------- -----------
Investments and Other Assets
Decommissioning trust accounts (Note 11) .................... 202,036 204,716
Assets from risk management and trading activities -
long-term (Note 16) ....................................... 2,082 32,955
Other assets ................................................ 76,322 45,841
----------- -----------
Total Investments and Other Assets ................... 280,440 283,512
----------- -----------
Current Assets:
Cash and cash equivalents ................................... 16,821 2,609
Accounts receivable:
Service customers ......................................... 182,749 422,012
Other ..................................................... 153,988 48,711
Allowance for doubtful accounts ........................... (3,349) (2,380)
Accrued utility revenues .................................... 76,131 74,566
Materials and supplies (at average cost) .................... 81,215 71,966
Fossil fuel (at average cost) ............................... 27,023 19,405
Deferred income taxes (Note 4) .............................. -- 5,793
Assets from risk management and trading activities
(Note 16) ................................................. 10,097 17,506
Other ....................................................... 42,009 38,414
----------- -----------
Total Current Assets ................................. 586,684 698,602
----------- -----------
Deferred Debits:
Regulatory assets (Notes 1 and 3) ........................... 342,383 469,867
Unamortized debt issue costs ................................ 13,163 12,805
Other ....................................................... 42,789 37,928
----------- -----------
Total Deferred Debits ................................ 398,335 520,600
----------- -----------
Total Assets ................................................... $ 6,367,054 $ 6,413,549
=========== ===========
See Notes to Financial Statements.
32
ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
LIABILITIES AND EQUITY
DECEMBER 31,
--------------------------
2001 2000
----------- -----------
(DOLLARS IN THOUSANDS)
Capitalization:
Common stock ................................................ $ 178,162 $ 178,162
Additional paid - in capital ................................ 1,246,804 1,246,804
Retained earnings ........................................... 790,289 694,802
Accumulated other comprehensive loss ........................ (64,565) --
----------- -----------
Common stock equity ....................................... 2,150,690 2,119,768
Long-term debt less current maturities (Note 6) ............. 1,949,074 1,806,908
----------- -----------
Total Capitalization ................................. 4,099,764 3,926,676
----------- -----------
Current Liabilities:
Commercial paper (Note 5) ................................... 171,162 82,100
Current maturities of long-term debt (Note 6) ............... 125,451 250,266
Accounts payable ............................................ 98,959 267,999
Accrued taxes ............................................... 107,595 106,515
Accrued interest ............................................ 41,043 39,488
Customer deposits ........................................... 28,664 24,498
Deferred income taxes (Note 4) .............................. 3,244 --
Liabilities from risk management and trading activities
(Note 16) ................................................. 21,840 37,179
Other ....................................................... 117,770 104,947
----------- -----------
Total Current Liabilities ............................ 715,728 912,992
----------- -----------
Deferred Credits and Other:
Deferred income taxes (Note 4) .............................. 1,023,079 1,110,437
Deferred investment tax credit (Note 4) ..................... 4,306 4,570
Liabilities from risk management and trading activities -
long term (Note 16) ....................................... 95,159 14,711
Unamortized gain -- sale of utility plant (Note 8) .......... 64,060 68,636
Customer advances for construction .......................... 69,293 40,694
Other ....................................................... 295,665 334,833
----------- -----------
Total Deferred Credits and Other ..................... 1,551,562 1,573,881
----------- -----------
Commitments and Contingencies (Notes 3, 10, and 11)
Total Liabilities and Equity ................................... $ 6,367,054 $ 6,413,549
=========== ===========
See Notes to Financial Statements.
33
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
-----------------------------------
2001 2000 1999
--------- --------- ---------
(DOLLARS IN THOUSANDS)
Cash Flows from Operations:
Net income ............................................ $ 265,487 $ 306,594 $ 128,437
Items not requiring cash:
Depreciation and amortization ....................... 420,893 425,479 416,331
Nuclear fuel amortization ........................... 28,362 30,083 31,371
Deferred income taxes - net ......................... (26,252) (65,457) (56,127)
Deferred investment tax credit - net ................ (264) (269) (27,626)
Mark-to-market gains - trading ...................... (91,978) (11,752) (975)
Mark-to-market gains - system ....................... (8,052) -- --
Extraordinary Charge - net of income taxes .......... -- -- 139,885
Cumulative effect of change in
accounting - net of income taxes .................. 15,201 -- --
Changes in certain current assets and liabilities:
Accounts receivable - net ........................... 226,933 (232,493) (8,363)
Accrued utility revenues ............................ (1,565) (1,647) (5,179)
Materials, supplies and fossil fuel ................. (16,867) 475 (8,794)
Other current assets ................................ (3,595) (25,035) (4,190)
Accounts payable .................................... (190,141) 101,558 22,992
Accrued taxes ....................................... 1,080 43,657 3,031
Accrued interest .................................... 1,555 7,189 1,081
Other current liabilities ........................... 16,989 124,473 6,833
Increase in regulatory assets ......................... (17,516) (14,138) (12,262)
Other - net ........................................... (13,164) 34,954 1,514
--------- --------- ---------
Net cash provided ................................... 607,106 723,671 627,959
--------- --------- ---------
Cash Flows from Investing:
Capital expenditures .................................. (467,391) (464,368) (322,547)
Capitalized interest .................................. (14,964) (10,894) (6,679)
Other ................................................. (41,926) (72,189) (8,173)
--------- --------- ---------
Net cash used ....................................... (524,281) (547,451) (337,399)
--------- --------- ---------
Cash Flows from Financing:
Issuance of long-term debt ............................ 396,072 300,000 392,952
Short-term borrowings - net ........................... 89,062 43,800 (140,530)
Common equity infusion from parent .................... -- -- 50,000
Dividends paid on common stock ........................ (170,000) (170,000) (170,000)
Dividends paid on preferred stock ..................... -- -- (1,393)
Repayment of preferred stock .......................... -- -- (96,499)
Repayment and reacquisition of long-term debt ......... (383,747) (354,888) (323,171)
--------- --------- ---------
Net cash used ....................................... (68,613) (181,088) (288,641)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents ..... 14,212 (4,868) 1,919
Cash and cash equivalents at beginning of year ........... 2,609 7,477 5,558
--------- --------- ---------
Cash and cash equivalents at end of year ................. $ 16,821 $ 2,609 $ 7,477
========= ========= =========
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest (excluding capitalized interest) ........... $ 114,094 $ 123,895 $ 132,995
Income taxes ........................................ $ 212,989 $ 222,866 $ 189,002
See Notes to Financial Statements.
34
ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
For the Years Ended December 31, 1999, 2000 and 2001
(dollars in thousands)
Additional Accumulated Other
Common Preferred Paid-in Retained Comprehensive
Stock Stock Capital Earnings Income (Loss) Total
----------- ----------- ----------- ----------- ------------- -----------
Balance at December 31, 1998 $ 178,162 $ 95,241 $ 1,195,625 $ 601,968 $ -- $ 2,070,996
Net income 128,437 128,437
Redemption of preferred
stock (95,241) (95,241)
Preferred stock dividend
requirements (1,016) (1,016)
Dividends on common stock (170,000) (170,000)
Common equity infusion
from parent 50,000 50,000
Other 1,179 (1,181) (2)
----------- ----------- ----------- ----------- ----------- -----------
Balance at December 31, 1999 178,162 -- 1,246,804 558,208 -- 1,983,174
Net income 306,594 306,594
Dividends on common
stock (170,000) (170,000)
----------- ----------- ----------- ----------- ----------- -----------
Balance at December 31, 2000 178,162 -- 1,246,804 694,802 -- 2,119,768
----------- ----------- ----------- ----------- ----------- -----------
Net income 265,487 265,487
Minimum pension liability,
net of $634 tax effect (966) (966)
Cumulative effect of
change in accounting for
derivatives, net of
$47,404 tax effect 72,274 72,274
Unrealized loss on
derivative instruments,
net of $54,028 tax effect (82,373) (82,373)
Reclassification of net
realized gain to income,
net of $35,091 tax effect (53,500) (53,500)
----------- ----------- ----------- ----------- ----------- -----------
Comprehensive income
(loss) 265,487 (64,565) 200,922
----------- ----------- ----------- ----------- ----------- -----------
Dividends on common
stock (170,000) (170,000)
----------- ----------- ----------- ----------- ----------- -----------
Balance at December 31, 2001 $ 178,162 $ -- $ 1,246,804 $ 790,289 $ (64,565) $ 2,150,690
=========== =========== =========== =========== =========== ===========
See Notes to Financial Statements.
35
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS
We are an Arizona electric utility. We are a wholly-owned subsidiary of
Pinnacle West Capital Corporation. We provide either retail or wholesale
electric service to substantially all of the state of Arizona, with the major
exceptions of the Tucson metropolitan area and about one-half of the
metropolitan Phoenix area. We also generate and, through Pinnacle West's
marketing and trading division, sell and deliver electricity to wholesale
customers in the western United States.
During 2001, we transferred most of our marketing and trading activities to
Pinnacle West, which approximated $219 million in assets and $149 million in
liabilities. From time to time, we enter into transactions with Pinnacle West or
Pinnacle West's subsidiaries. The following table summarizes the amounts
included in the income statements and balance sheets related to transactions
with affiliated companies (dollars in millions):
For the year ended
December 31,
------------------
2001 2000 1999
---- ---- ----
Electric operating revenues:
Pinnacle West - marketing and trading $ 50 $ -- $ --
APSES 15 26 --
---- ---- ----
Total $ 65 $ 26 $ --
==== ==== ====
Purchased power and fuel costs:
Pinnacle West - marketing and trading $ 50 $ -- $ --
Pinnacle West Energy 14 -- --
---- ---- ----
Total $ 64 $ -- $ --
==== ==== ====
As of
December 31,
-----------
2001 2000
---- ----
Accounts receivable - other:
Pinnacle West - marketing and trading $ 76 $ 10
Pinnacle West 24 14
APSES 13 1
Pinnacle West Energy 2 --
---- ----
Total $115 $ 25
==== ====
Accounts payable:
Pinnacle West - marketing and trading $ 21 $ 1
Pinnacle West Energy 2 1
---- ----
Total $ 23 $ 2
==== ====
36
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
Electric revenues include sales of electricity to affiliated companies at
contract prices. Purchased power includes purchases of electricity from
affiliated companies at contract prices. Intercompany receivables primarily
include the amounts related to the transfer of marketing and trading activities
discussed above and intercompany sales of electricity. Intercompany payables
primarily include amounts related to the purchase of electricity.
ACCOUNTING RECORDS AND USE OF ESTIMATES
Our accounting records are maintained in accordance with accounting
principles generally accepted in the United States of America (GAAP). The
preparation of financial statements in accordance with GAAP requires management
to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates. We have
reclassified certain prior year amounts to conform to current year presentation.
DERIVATIVE INSTRUMENTS
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal, and emissions
allowances. We employ established procedures to manage risks associated with
these market fluctuations by utilizing various commodity derivatives, including
exchange-traded futures and options and over-the-counter forwards, options, and
swaps. As part of our overall risk management program, we enter into derivative
transactions to hedge purchases and sales of electricity, fuels, and emissions
allowances and credits. The changes in market value of such contracts have a
high correlation to price changes in the hedged commodity.
In addition, subject to specified risk parameters established by the
Pinnacle West Board of Directors and monitored by Pinnacle West's ERMC, we
engage in trading activities intended to profit from market price movements. If
a contract was entered into for trading purposes, we account for it in
accordance with EITF 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities." EITF 98-10 requires energy trading contracts to
be measured at fair value as of the balance sheet date with unrealized gains and
losses included in earnings on a current basis (the mark-to-market method). See
"Mark-to-Market Method" below and Note 16 and Note 18 for further information
about our trading contracts.
We examine contracts at inception to determine the appropriate accounting
treatment. If a contract is not considered energy trading we must determine if
it is a derivative as defined in SFAS No. 133 (see Note 16 for further
information on SFAS No. 133). If a contract does not meet the derivative
criteria or if it qualifies for a SFAS No. 133 scope exception, we account for
the contract using accrual accounting (this means that costs and revenues are
recorded when physical delivery occurs). For contracts that qualify as a
derivative and do not meet a SFAS No. 133 scope exception, we further examine
the contract to determine if it will qualify for hedge accounting. If a contract
37
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
does not meet the hedging criteria in SFAS No. 133, we recognize the changes in
the fair value of the derivative instrument in income each period
(mark-to-market). If it does qualify for hedge accounting, changes in the fair
value are recognized as either an asset, as a liability or in stockholder's
equity (as a component of accumulated other comprehensive income) depending on
the nature of the hedge.
Gains and losses related to derivatives that qualify as cash flow hedges of
expected transactions are recognized in revenue or fuel and purchased power
expense as an offset to the related item being hedged when the underlying hedged
physical transaction impacts earnings (deferral method). See Note 16 for further
discussion on derivative accounting.
MARK-TO-MARKET METHOD
Under mark-to-market accounting the purchase or sale of energy commodities
are reflected at fair market value, net of reserves, with resulting unrealized
gains and losses recorded as assets and liabilities from risk management and
trading activities in the balance sheets.
We determine fair market value using actively-quoted prices when available.
We consider quotes for exchange-traded contracts and over-the-counter quotes
obtained from independent brokers to be actively-quoted.
When actively-quoted prices are not available, we use prices provided by
other external sources. This includes quarterly and calendar year quotes from
independent brokers. We shape quarterly and calendar year quotes into monthly
prices based on historical relationships.
For options, long-term contracts and other contracts where price quotes are
not available, we use models and other valuation methods. For illiquid or
unquoted market locations, we consider the historical relationship to
readily-available market quotations. The valuation models we employ utilize spot
prices, forward prices, historical market data and other factors to forecast
future prices.
For non-exchange traded contracts, we calculate fair market value based on
the average of the bid and offer price, and we discount to reflect net present
value. We maintain certain reserves for a number of risks associated with the
valuation of future commitments. These include reserves for liquidity and credit
risks based on the financial condition of counterparties. The liquidity reserve
represents the cost that would be incurred if all unmatched positions were
closed-out or hedged. As we mark positions to a mid-market value this reserve
adjusts the mid-market valuation to the bid or offer, after taking into
consideration offsetting positions, to reflect the true cash flow that would be
realized upon exiting the net position.
A credit reserve is also recorded to represent 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,
38
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
and local distribution companies. We maintain credit policies that management
believes minimize overall credit risk. Determination of the credit quality of
counterparties is based upon a number of factors, including credit ratings,
financial condition, project economics and collateral requirements. When
applicable, we employ standardized agreements that allow for the netting of
positive and negative exposures associated with a single counterparty.
The use of models and other valuation methods to determine fair market
value often requires subjective and complex judgment. Actual results could
differ from the results estimated through application of these methods. However,
essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is substantially
hedged with a portfolio of forward purchases that protects the economic value of
the sales transactions. Our practice is to hedge within timeframes established
by the Pinnacle West ERMC.
REGULATORY ACCOUNTING
We are regulated by the ACC and the FERC. The accompanying financial
statements reflect the rate-making policies of these commissions. For regulated
operations, we prepare our financial statements in accordance with SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." SFAS No. 71
requires a cost-based, rate-regulated enterprise to reflect the impact of
regulatory decisions in its financial statements.
During 1997, the EITF of the FASB issued EITF 97-4. EITF 97-4 requires that
SFAS No. 71 be discontinued no later than when legislation is passed or a rate
order is issued that contains sufficient detail to determine its effect on the
portion of the business being deregulated, which could result in write-downs or
write-offs of physical and/or regulatory assets. Additionally, the EITF
determined that regulatory assets should not be written off if they are to be
recovered from a portion of the entity which continues to apply SFAS No. 71.
The 1999 Settlement Agreement was approved by the ACC in September 1999
(see Note 3 for a discussion of the agreement). Consequently, we have
discontinued the application of SFAS No. 71 for our generation operations. As a
result, we tested the generation assets for impairment and determined that the
generation assets were not impaired. Pursuant to the 1999 Settlement Agreement,
a regulatory disallowance removed $234 million pretax ($183 million net present
value) from ongoing regulatory cash flows and was recorded as a net reduction of
regulatory assets. This reduction ($140 million after income taxes) was reported
as an extraordinary charge on the income statement during the third quarter of
1999. Prior to the 1999 Settlement Agreement, under the 1996 regulatory
agreement (see Note 3), the ACC accelerated the amortization of substantially
all of our regulatory assets to an eight-year period that would have ended June
30, 2004.
The regulatory assets to be recovered under the 1999 Settlement Agreement
are currently being amortized as follows (dollars in millions):
39
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
------ ------ ------ ------ ------ ------ ------
$ 164 $ 158 $ 145 $ 115 $ 86 $ 18 $ 686
Regulatory assets are reported as deferred debits on the balance sheets. As of
December 31, 2001 and 2000, they are comprised of the following (dollars in
millions):
December 31,
--------------------
2001 2000
-------- --------
Remaining balance recoverable under the 1999
Settlement Agreement (a) $ 219 $ 364
Spent fuel storage (Note 10) 43 40
Electric industry restructuring transition costs (Note 3) 34 24
Other 46 42
-------- --------
Total regulatory assets $ 342 $ 470
======== ========
(a) The majority of our unamortized regulatory assets above relates to deferred
income taxes (see Note 4) and rate synchronization cost deferrals (see
"Rate Synchronization Cost Deferrals" below).
Regulatory liabilities are included in deferred credits on the balance sheets
and as of December 31, 2001 and 2000 are comprised of the following (dollars in
millions):
December 31,
--------------------
2001 2000
-------- --------
Deferred gains on utility property $ 20 $ 20
Other 7 8
-------- --------
Total regulatory liabilities $ 27 $ 28
======== ========
The balance sheets include the amounts listed below for generation assets
not subject to SFAS No. 71 as of December 31, 2001 and 2000 (dollars in
millions):
December 31,
--------------------
2001 2000
-------- --------
Electric plant in service and held for future use ...... $ 3,878 $ 3,854
Accumulated depreciation and amortization .............. (1,990) (1,902)
Construction work in progress .......................... 119 86
Nuclear fuel, net of amortization ...................... 49 47
40
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
As a result of our 1999 Settlement Agreement, we plan to move our
generation assets and activities to Pinnacle West Energy no later than December
31, 2002. Following the transfer, our financial statements would no longer
include generation assets and activities. Our preliminary estimate of the net
assets (the generation assets described above and the related liabilities) that
would be transferred is approximately $850 million based on book values at
December 31, 2001. We have requested that the ACC approve a purchase power
agreement and a proposed rule variance related to our power procurement after
the transfer. This request is currently pending ACC consideration (see Note 3).
The specific impacts of the generation transfer on our revenues and expenses are
not yet determinable pending the outcome of the ACC proceedings. In addition, as
of December 31, 2001, we completed the transition of our marketing and trading
activities to the parent. In 2001, we recorded the following pretax amounts
related to marketing and trading activities: $549 million of electric revenues
and $314 million of purchased power and fuel costs.
UTILITY PLANT AND DEPRECIATION
Utility plant is the term we use to describe the business property and
equipment that supports electric service, consisting primarily of generation,
transmission, and distribution facilities. We report utility plant at our
original cost, which includes:
* material and labor;
* contractor costs;
* construction overhead costs (where applicable); and
* capitalized interest or an allowance for funds used during
construction.
We charge retired utility plant, plus removal costs less salvage realized,
to accumulated depreciation. See Note 2 for information on a new accounting
standard that impacts accounting for removal costs.
We record depreciation on utility property on a straight-line basis. For
the years 1999 through 2001 the rates, as prescribed by our regulators, ranged
from a low of 1.49% to a high of 20%. The weighted-average rate was 3.40% for
2001, 3.40% for 2000, and 3.34% for 1999. We depreciate non-utility property and
equipment over the estimated useful lives of the related assets, ranging from 3
to 30 years. We expense the costs of plant outages, major maintenance and
routine maintenance as incurred.
CAPITALIZED INTEREST
Capitalized interest represents the cost of debt funds used to finance
construction of utility plants. Plant construction costs, including capitalized
interest, are expensed through depreciation when completed projects are placed
into commercial operation. Capitalized interest does not represent current cash
earnings. The rate used to calculate capitalized interest was a composite rate
of 6.26% for 2001, 6.62% for 2000, and 6.65% for 1999.
41
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
REVENUES
We record electric operating revenues on the accrual basis, which includes
estimated amounts for service rendered but unbilled at the end of each
accounting period. We exclude sales taxes on electric revenues from both revenue
and taxes other than income taxes. Other than revenues and purchased power costs
related to energy trading activities, revenues are recorded on a gross basis in
our income statements. See Note 18 for information related to a change in
presentation of certain marketing and trading revenues to a net basis.
CASH AND CASH EQUIVALENTS
For purposes of the statement of cash flows, we consider all highly liquid
debt instruments purchased with an initial maturity of three months or less to
be cash equivalents.
RATE SYNCHRONIZATION COST DEFERRALS
As authorized by the ACC, operating costs (excluding fuel) and financing
costs of Palo Verde Units 2 and 3 were deferred from the commercial operation
dates (September 1986 for Unit 2 and January 1988 for Unit 3) until the date the
units were included in a rate order (April 1988 for Unit 2 and December 1991 for
Unit 3). In accordance with the 1999 Settlement Agreement, we are continuing to
accelerate the amortization of the deferrals over an eight-year period that will
end June 30, 2004. Amortization of the deferrals is included in depreciation and
amortization expense in the statements of income.
NUCLEAR FUEL
We charge nuclear fuel to fuel expense by using the unit-of-production
method. The unit-of-production method is an amortization method that is based on
actual physical usage. We divide the cost of the fuel by the estimated number of
thermal units that we expect to produce with that fuel. We then multiply that
rate by the number of thermal units that we produce within the current period.
This calculation determines the current period nuclear fuel expense.
We also charge nuclear fuel expense for the permanent disposal of spent
nuclear fuel. The United States Department of Energy (DOE) is responsible for
the permanent disposal of spent nuclear fuel, and it charges us $0.001 per kWh
of nuclear generation. See Note 10 for information about spent nuclear fuel
disposal and Note 11 for information on nuclear decommissioning costs.
42
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
REACQUIRED DEBT COSTS
For debt related to the regulated portion of our business, we amortize
those gains and losses incurred upon early retirement over the remaining life of
the debt. In accordance with the 1999 Settlement Agreement, we are continuing to
accelerate reacquired debt costs over an eight-year period that will end June
30, 2004. The accelerated portion of the regulatory asset amortization is
included in depreciation and amortization expense in the statements of income.
2. ACCOUNTING MATTERS
In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets." This statement addresses financial accounting and reporting for
acquired goodwill and other intangible assets and supersedes APB Opinion No. 17,
"Intangible Assets." This standard is effective for the year beginning January
1, 2002. We have no goodwill recorded in our balance sheets. The impacts of this
new standard are not material to our financial statements.
In August 2001, the FASB issued SFAS No. 143 "Accounting for Asset
Retirement Obligations." The standard requires the estimated present value of
the cost of decommissioning and certain other removal costs to be recorded as a
liability, along with an offsetting plant asset, when a decommissioning or other
removal obligation is incurred. We are currently evaluating the impacts of the
new standard, which is effective for the year beginning January 1, 2003.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." This statement supersedes SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of," and the accounting and reporting provisions for the
disposal of a segment of a business. SFAS No. 144 is effective for the year
beginning January 1, 2002. This standard does not impact our financial
statements at adoption.
In 2001, the American Institute of Certified Public Accountants (AICPA)
issued an exposure draft of a proposed Statement of Position (SOP), "Accounting
for Certain Costs Related to Property, Plant, and Equipment." This proposed SOP
would create a project timeline framework for capitalizing costs related to
property, plant and equipment (PP&E) construction, require that PP&E assets be
accounted for at the component level, and require administrative and general
costs incurred in support of capital projects to be expensed in the current
period. The AICPA plans to issue the final SOP in the fourth quarter of 2002.
In 1986, we entered into agreements with three separate special purpose
entity (SPE) lessors in order to sell and lease back interests in Palo Verde
Unit 2 (see Note 8). The leases are accounted for as operating leases in
accordance with GAAP. In February 2002, the FASB discussed issues related to
special purpose entities. It is expected that FASB will issue additional
guidance on accounting for SPEs later this year. As a result of future FASB
actions, we may be required to consolidate the SPEs in our financial statements.
If consolidation is required, the assets and liabilities of the SPEs that relate
to the sale-leaseback transactions would be reflected on our balance sheets. The
43
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
SPE debt that is not reflected on our balance sheets is approximately $300
million at December 31, 2001. Rating agencies have already considered this debt
when evaluating our credit ratings.
3. REGULATORY MATTERS
ELECTRIC INDUSTRY RESTRUCTURING
STATE
1999 SETTLEMENT AGREEMENT. On May 14, 1999, we entered into a comprehensive
1999 Settlement Agreement with various parties, including representatives of
major consumer groups, related to the implementation of retail electric
competition. On September 23, 1999, the ACC voted to approve the 1999 Settlement
Agreement, with some modifications.
On December 13, 1999, two parties filed lawsuits challenging the ACC's
approval of the 1999 Settlement Agreement. Each party bringing the lawsuits
appealed the ACC's order approving the 1999 Settlement Agreement directly to the
Arizona Court of Appeals, as provided by Arizona law. In one of the appeals, on
December 26, 2000, the Arizona Court of Appeals affirmed the ACC's approval of
the 1999 Settlement Agreement. This decision was not appealed and has become
final. In the other appeal, on April 5, 2001, the Arizona Court of Appeals again
affirmed the ACC's approval of the 1999 Settlement Agreement. The Arizona
Consumers Council, which filed that appeal, petitioned the Arizona Supreme Court
for review of the Court of Appeals' decision. On October 5, 2001, the Arizona
Supreme Court agreed to hear the appeal on the single issue of whether the ACC
could itself become a party to the 1999 Settlement Agreement by virtue of its
approval of the 1999 Settlement Agreement. On December 14, 2001, the Arizona
Supreme Court vacated its own October 5, 2001 order accepting jurisdiction and
decided to dismiss the appeal. As a result, the judicial challenges to the 1999
Settlement Agreement have terminated. Consistent with our obligations under the
1999 Settlement Agreement, on January 7, 2002, we and the ACC filed in Maricopa
County, Arizona Superior Court a stipulation to dismiss all of our litigation
pending against the ACC. On January 15, 2002, a Maricopa County Superior Court
judge issued an order dismissing such litigation.
The following are the major provisions of the 1999 Settlement Agreement, as
approved:
* We have reduced, and will reduce, rates for standard-offer service for
customers with loads less than three MW in a series of annual retail
electricity price reductions of 1.5% beginning July 1, 1999 through
July 1, 2003, for a total of 7.5%. The first reduction of
approximately $24 million ($14 million after income taxes) included
the July 1, 1999 retail price decrease of approximately $11 million
($7 million after income taxes) related to the 1996 regulatory
agreement. See "1996 Regulatory Agreement" below. Based on the price
reductions authorized in the 1999 Settlement Agreement, there were
also retail price decreases of approximately $28 million ($17 million
after taxes), or 1.5%, effective July 1, 2000, and approximately $27
44
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
million ($16 million after taxes), or 1.5%, effective July 1, 2001.
For customers having loads three MW or greater, standard-offer rates
will be reduced in varying annual increments that total 5% in the
years 1999 through 2002.
* Unbundled rates being charged by us for competitive direct access
service (for example, distribution services) became effective upon
approval of the 1999 Settlement Agreement, retroactive to July 1,
1999, and also became subject to annual reductions beginning January
1, 2000, that vary by rate class, through January 1, 2004.
* There will be a moratorium on retail price changes for standard-offer
and unbundled competitive direct access services until July 1, 2004,
except for the price reductions described above and certain other
limited circumstances. Neither the ACC nor we will be prevented from
seeking or authorizing rate changes prior to July 1, 2004 in the event
of conditions or circumstances that constitute an emergency, such as
an inability to finance on reasonable terms, or material changes in
our cost of service for ACC-regulated services resulting from federal,
tribal, state or local laws, regulatory requirements, judicial
decisions, actions or orders.
* We will be permitted to defer for later recovery prudent and
reasonable costs of complying with the ACC electric competition rules,
system benefits costs in excess of the levels included in then-current
(1999) rates, and costs associated with the "provider of last resort"
and standard-offer obligations for service after July 1, 2004. These
costs are to be recovered through an adjustment clause or clauses
commencing on July 1, 2004.
* Our distribution system opened for retail access effective September
24, 1999. Customers were eligible for retail access in accordance with
the phase-in adopted by the ACC under the electric competition rules
(see "Retail Electric Competition Rules" below), including an
additional 140 MW being made available to eligible non-residential
customers. We opened our distribution system to retail access for all
customers on January 1, 2001.
* Prior to the 1999 Settlement Agreement, we were recovering
substantially all of our regulatory assets through July 1, 2004,
pursuant to the 1996 regulatory agreement. In addition, the 1999
Settlement Agreement states that we have demonstrated that our
allowable stranded costs, after mitigation and exclusive of regulatory
assets, are at least $533 million net present value. We will not be
allowed to recover $183 million net present value of the above
amounts. The 1999 Settlement Agreement provides that we will have the
opportunity to recover $350 million net present value through a
competitive transition charge that will remain in effect through
45
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
December 31, 2004, at which time it will terminate. The costs subject
to recovery under the adjustment clause described above will be
decreased or increased by any over/under-recovery due to sales volume
variances.
* We will form, or cause to be formed, a separate corporate affiliate or
affiliates and transfer to such affiliate(s) our competitive electric
assets and services at book value as of the date of transfer, and will
complete the transfer no later than December 31, 2002. Accordingly, we
plan to complete the move of such assets and services to the parent
company or to Pinnacle West Energy by the end of 2002, as required,
although the ACC's recent establishment of a "generic" docket to
consider electric industry restructuring in Arizona and the
consolidation of that docket with our request for approval of a PPA
between Pinnacle West and us could affect our ability to transfer
assets to Pinnacle West Energy. We will be allowed to defer and later
collect, beginning July 1, 2004, sixty-seven percent of our costs to
accomplish the required transfer of generation assets to an affiliate.
As discussed in Note 1 above, we have discontinued the application of SFAS
No. 71 for our generation operations.
PROPOSED RULE VARIANCE AND PURCHASE POWER AGREEMENT. As authorized by the
1999 Settlement Agreement, we intend to move substantially all of our generation
assets to Pinnacle West Energy no later than December 31, 2002. Commencing upon
the transfer of the fossil-fueled generating assets and the receipt of certain
regulatory approvals, Pinnacle West Energy expects to sell its power at
wholesale to Pinnacle West's marketing and trading division, which, in turn, is
expected to sell power to us and to non-affiliated power purchasers. In a filing
with the ACC on October 18, 2001, we requested the ACC to:
* grant us a partial variance from an ACC rule that would obligate us to
acquire all of our customers' standard-offer, full-service generation
requirements from the competitive market (with at least 50% of those
requirements coming from a "competitive bidding" process) starting in
2003; and
* approve as just and reasonable a long-term purchase power agreement
(PPA) between us and Pinnacle West.
We have requested these ACC actions to ensure ongoing reliable service to our
standard-offer, full-service customers in a volatile generation market and to
recognize Pinnacle West Energy's significant investment to serve our load. The
following are the major provisions of the PPA:
* The PPA would run through 2015, with three optional five-year renewal
terms, which renewals would occur automatically unless notice is given
by either us or Pinnacle West.
46
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
* The PPA would provide for all of our anticipated standard-offer
generation needs, including any necessary reserves, except for (a)
those provided by us through renewable resources or other generation
assets retained by us; (b) amounts that we are obligated by law to
purchase from "qualified facilities" and other forms of distributed
generation; and (c) any purchased power agreements that we cannot
transfer to Pinnacle West Energy.
* Pinnacle West would assume contractual responsibility for reliability
and would supplement any potential shortfall even after full
utilization of Pinnacle West Energy's dedicated generating resources.
* Pinnacle West would supply us standard-offer requirements through a
combination of (a) our generation assets transferred to Pinnacle West
Energy; (b) certain of Pinnacle West Energy's new Arizona generation
projects to be constructed during the 2001-2004 period to reliably
serve our load requirements; (c) power procured by Pinnacle West under
certain "dedicated contracts"; and (d) power procured on the open
market, including a competitively-bid component described below.
* Beginning in 2003, Pinnacle West would acquire 270 MW of our
standard-offer requirements on the open market through a competitive
bidding process. This competitive bid obligation would be increased by
an additional 270 MW each year through 2008 (representing
approximately 23% of estimated 2008 peak load).
* Pinnacle West would charge us based on (a) a combination of fixed and
variable price components for the Pinnacle West Energy assets, subject
to periodic adjustment, and (b) a pass-through of Pinnacle West's
costs to procure power from the remaining sources.
* The PPA would take effect on the latest of the following events: (a)
transfer of non-nuclear generating assets from us to Pinnacle West
Energy; (b) ACC approval of the rule variance and the PPA; and (c) the
FERC's acceptance of the PPA and the companion agreement between
Pinnacle West and Pinnacle West Energy.
We are required to transfer our competitive electric assets and services to
one or more corporate affiliates on or before December 31, 2002. Consistent with
that requirement, we have been addressing the legal and regulatory requirements
necessary to complete the transfer of our generation assets to Pinnacle West
Energy on or before that date. In anticipation of our transfer of generation
assets, Pinnacle West Energy has completed, and is in the process of developing
and planning, various generation expansion projects so that we can reliably meet
47
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
the energy requirements of our Arizona customers. See Note 1 for information
relating to our pending transfer of generation assets and associated liabilities
to Pinnacle West Energy.
By letter dated January 14, 2002, the Chairman of the ACC stated that "the
[ACC's] Electric Competition Rules, along with the Settlement Agreements
approved for us and [Tucson Electric Company], establish the framework for the
transition to a retail generation competitive market." The ACC Chairman then
recommended that the ACC establish a new "generic" docket to "determine if
changed circumstances require the [ACC] to take another look at electric
restructuring in Arizona." Matters that would be addressed by the ACC in the new
docket would include:
* whether the ACC should continue implementation of the retail electric
competition Rules adopted by the ACC in 1999 in their current form or
with modifications;
* whether the ACC should "slow the pace of the implementation of the
[Rules] to provide an opportunity to consider the extent to which
[Rule] modification and variance is in the public interest, including
changing the direction to retail electric competition"; and
* whether the ACC should "step back from electric industry restructuring
until the [ACC] is convinced that there exists a viable competitive
wholesale electric market to support retail electric competition in
Arizona."
On January 22, 2002 the ACC's Chief ALJ issued a procedural order by which
a generic docket was opened. On February 8, 2002, the ACC's ALJ issued a
procedural order which consolidated the ACC docket relating to our October 2001
filing with several other pending ACC dockets, including the generic docket.
Although the order consolidates several dockets, it states that a hearing on our
matter will commence on April 29, 2002. The order went on to state that,
contrary to our position, the ALJ was construing the October 2001 filing as a
request by us to amend the ACC order that approved the 1999 Settlement
Agreement.
On March 22, 2002, the ACC Staff issued a report to the ACC recommending
that the ACC address the following issues in the generic docket:
* The extent and manner of the ACC's involvement in monitoring market
conditions and/or mitigating the development of market power for
generation and transmission;
* The lack of guidance in the Rules regarding the mechanics of the
"competitive bidding process" referenced above;
* The consideration of alternatives to the transfer of generation assets
required by the Rules (the ACC Staff stated that such transfers would
be "unwise" at the present time and recommended that "all transfer and
48
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
separation of utilities' assets be stayed pending the completion of
the generic docket");
* The consideration of transmission constraints that could impact the
development of the wholesale power market;
* The reassessment of adjustor mechanisms for standard-offer rates in
light of problems with the development of a wholesale power market;
and
* The adequacy of customer "shopping credits" in the context of the
development of a competitive retail market (a shopping credit is the
cost a customer does not pay to a utility distribution company if the
customer obtains generation from another party).
Although not a specific ACC Staff recommendation, the report was also critical
of certain aspects of the proposed purchase power agreement between the Company
and Pinnacle West.
A modification to the competition Rules or the 1999 Settlement Agreement
could, among other things, adversely affect our ability to transfer our
generation assets to Pinnacle West Energy by December 31, 2002. We cannot
predict the outcome of the consolidated docket or its effect on the specific
requests in our October 2001 filing, the existing Arizona electric competition
rules, or the 1999 Settlement Agreement.
RETAIL ELECTRIC COMPETITION RULES. On September 21, 1999, the ACC voted to
approve Rules that provide a framework for the introduction of retail electric
competition in Arizona. Under the 1999 Settlement Agreement, the Rules are to be
interpreted and applied, to the greatest extent possible, in a manner consistent
with the 1999 Settlement Agreement. If the two cannot be reconciled, we must
seek, and the other parties to the 1999 Settlement Agreement must support, a
waiver of the Rules in favor of the 1999 Settlement Agreement. On December 8,
1999, we filed a lawsuit to protect our legal rights regarding the Rules. This
lawsuit has been dismissed.
On November 27, 2000, a Maricopa County, Arizona, Superior Court judge
issued a final judgment holding that the Rules are unconstitutional and unlawful
in their entirety due to failure to establish a fair value rate base for
competitive electric service providers and because certain of the Rules were not
submitted to the Arizona Attorney General for certification. The judgment also
invalidates all ACC orders authorizing competitive electric service providers to
operate in Arizona. We do not believe the ruling affects the 1999 Settlement
Agreement. The 1999 Settlement Agreement was not at issue in the consolidated
cases before the judge. Further, the ACC made findings related to the fair value
of our property in the order approving the 1999 Settlement Agreement. The ACC
and other parties aligned with the ACC have appealed the ruling to the Arizona
Court of Appeals, as a result of which the Superior Court's ruling is
automatically stayed pending further judicial review. In a similar appeal
concerning the issuance of competitive telecommunications CC&N's, the Arizona
Court of Appeals invalidated rates for competitive carriers due to the ACC's
49
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
failure to establish a fair value rate base for such carriers. That case has
been appealed to the Arizona Supreme Court, where a decision is pending.
The Rules approved by the ACC include the following major provisions:
* They apply to virtually all Arizona electric utilities regulated by
the ACC, including us.
* Effective January 1, 2001, retail access became available to all our
retail electricity customers.
* Electric service providers that get CC&N's from the ACC can supply
only competitive services, including electric generation, but not
electric transmission and distribution.
* Affected utilities must file ACC tariffs that unbundle rates for
noncompetitive services.
* The ACC shall allow a reasonable opportunity for recovery of
unmitigated stranded costs.
* Absent an ACC waiver, prior to January 1, 2001, each affected utility
(except certain electric cooperatives) must transfer all competitive
electric assets and services either to an unaffiliated party or to a
separate corporate affiliate. Under the 1999 Settlement Agreement, we
received a waiver to allow transfer of our competitive electric assets
and services to affiliates no later than December 31, 2002. We plan to
complete the move of such assets by the end of 2002, as required,
although the ACC's recent establishment of a "generic" docket to
consider electric industry restructuring in Arizona and the
consolidation of that docket with our request for approval of a PPA
between Pinnacle West and us could affect our ability to transfer
assets to Pinnacle West Energy (see "Proposed Rule Variance and
Purchase Power Agreement" above).
PROVIDER OF LAST RESORT OBLIGATION. Although the Rules allow retail
customers to have access to competitive providers of energy and energy services
(see "Retail Electric Competition Rules" below), we are the "provider of last
resort" for standard-offer, full-service customers under rates that have been
approved by the ACC. These rates are established until July 1, 2004. The 1999
Settlement Agreement allows us to seek adjustment of these rates in the event of
emergency conditions or circumstances, such as the inability to secure financing
on reasonable terms, or material changes in our cost of service for
ACC-regulated services resulting from federal, tribal, state or local laws,
regulatory requirements, judicial decisions, actions or orders. Energy prices in
the western wholesale market vary and, during the course of the last two years,
have been volatile. At various times, prices in the spot wholesale market have
significantly exceeded the amount included in our current retail rates. In the
50
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
event of shortfalls due to unforeseen increases in load demand or generation
outages, we may need to purchase additional supplemental power in the wholesale
spot market. Unless we are able to obtain an adjustment of our rates under the
emergency provisions of the 1999 Settlement Agreement, there can be no assurance
that we would be able to fully recover the costs of this power.
1996 REGULATORY AGREEMENT. In April 1996, the ACC approved a regulatory
agreement between the ACC Staff and us. Based on the price reduction formula
authorized in the agreement, the ACC approved retail price decreases
(approximate) as follows (dollars in millions):
Annual Electric Percentage
Revenue Decrease Decrease Effective Date
---------------- -------- --------------
$49 3.4% July 1, 1996
$18 1.2% July 1, 1997
$17 1.1% July 1, 1998
$11 0.7% July 1, 1999(a)
(a) Included in the first rate reduction under the 1999 Settlement
Agreement (see above).
The regulatory agreement also required that Pinnacle West infuse $200
million of common equity into us in annual payments of $50 million from 1996
through 1999. All of these equity infusions were made by December 31, 1999.
LEGISLATION. In May 1998, a law was enacted to facilitate implementation of
retail electric competition in Arizona. The law includes the following major
provisions:
* Arizona's largest government-operated electric utility (Salt River
Project) and, at their option, smaller municipal electric systems must
(i) make at least 20% of their 1995 retail peak demand available to
electric service providers by December 31, 1998 and for all retail
customers by December 31, 2000; (ii) decrease rates by at least 10%
over a ten-year period beginning as early as January 1, 1991; (iii)
implement procedures and public processes comparable to those already
applicable to public service corporations for establishing the terms,
conditions, and pricing of electric services as well as certain other
decisions affecting retail electric competition;
* describes the factors which form the basis of consideration by Salt
River Project in determining stranded costs; and
* metering and meter reading services must be provided on a competitive
basis during the first two years of competition only for customers
having demands in excess of one MW (and that are eligible for
51
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
competitive generation services), and thereafter for all customers
receiving competitive electric generation.
GENERAL
We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, results of operations, or liquidity. As
competition in the electric industry continues to evolve, we will continue to
evaluate strategies and alternatives that will position us to compete in the new
regulatory environment.
FEDERAL
In June 2001, the FERC adopted a price mitigation plan that constrains the
price of electricity in the wholesale spot electricity market in the western
United States. The plan remains in effect until September 30, 2002. We cannot
accurately predict the overall financial impact of the plan on the various
aspects of our business, including our wholesale and purchased power activities.
4. INCOME TAXES
INCOME TAXES
We are included in Pinnacle West's consolidated tax return. However, when
Pinnacle West allocates income taxes to us, it does so based on our taxable
income or loss alone. Because of a 1994 rate settlement agreement, we
accelerated amortization of substantially all of our ITCs over a five-year
period (1995-1999).
Certain assets and liabilities are reported differently for income tax
purposes than they are for financial statements. The tax effect of these
differences is recorded as deferred taxes. We calculate deferred taxes using the
current income tax rates.
We have recorded a regulatory asset related to income taxes on our balance
sheets in accordance with SFAS No. 71. This regulatory asset is for certain
temporary differences, primarily the allowance for equity funds used during
construction. We amortize this amount as the differences reverse. In accordance
with the 1999 Settlement Agreement, we are continuing to accelerate our
amortization of the regulatory asset for income taxes over an eight-year period
that will end June 30, 2004 (see Note 1). We are including this accelerated
amortization in depreciation and amortization expense on the Statements of
Income. The components of income tax expense for income before extraordinary
charge and cumulative effect adjustment are (dollars in thousands):
52
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
Year Ended December 31,
--------------------------------------
2001 2000 1999
---------- ---------- ----------
Current
Federal $ 174,251 $ 211,139 $ 175,227
State 35,401 50,252 41,541
---------- ---------- ----------
Total current 209,652 261,391 216,768
Deferred (26,252) (65,457) (56,127)
ITC amortization (264) (269) (27,626)
---------- ---------- ----------
Total expense $ 183,136 $ 195,665 $ 133,015
========== ========== ==========
The following chart compares pretax income at the 35% federal income tax rate to
income tax expense (dollars in thousands):
Year Ended December 31,
--------------------------------------
2001 2000 1999
---------- ---------- ----------
Federal income tax expense at 35%
statutory rate $ 162,338 $ 175,791 $ 140,444
Increases (reductions) in tax expense
resulting from:
ITC amortization (264) (269) (27,626)
State income tax net of federal
income tax benefit 20,563 20,007 20,699
Other 499 136 (502)
---------- ---------- ----------
Income tax expense $ 183,136 $ 195,665 $ 133,015
========== ========== ==========
53
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
The components of the net deferred income tax liability were as follows (dollars
in thousands):
December 31,
-------------------------
2001 2000
---------- ----------
DEFERRED TAX ASSETS
Deferred gain on Palo Verde Unit 2 sale/leaseback $ 25,374 $ 27,056
Risk management and trading activities 46,343 15,002
Other 111,318 126,909
---------- ----------
Total deferred tax assets 183,035 168,967
---------- ----------
DEFERRED TAX LIABILITIES
Plant-related 1,069,207 1,081,637
Regulatory asset for income taxes 121,757 172,082
Risk management and trading activities 18,394 19,892
---------- ----------
Total deferred tax liabilities 1,209,358 1,273,611
---------- ----------
Accumulated deferred income taxes - net $1,026,323 $1,104,644
========== ==========
5. LINES OF CREDIT
We had committed lines of credit with various banks of $250 million at
December 31, 2001 and 2000, which were available either to support the issuance
of commercial paper or to be used for bank borrowings. The commitment fees at
December 31, 2001 and 2000 for these lines of credit were 0.09% per annum. We
had no bank borrowings outstanding under these lines of credit at December 31,
2001 and 2000.
Our commercial paper borrowings outstanding were $171 million at December
31, 2001 and $82 million at December 31, 2000. The weighted average interest
rate on commercial paper borrowings was 4.72% for the year ended December 31,
2001 and 6.64% for the year ended December 31, 2000. By Arizona statute, our
short-term borrowings cannot exceed 7% of our total capitalization unless
approved by the ACC.
6. LONG-TERM DEBT
Borrowings under our mortgage bond indenture are secured by substantially
all utility plant. We also have unsecured debt. The following table presents the
components of long-term debt outstanding at December 31, 2001 and 2000 (dollars
in thousands):
54
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
December 31,
-----------------------
Maturity Interest
Dates (a) Rates 2001 2000
--------- ---------- ---------- ----------
First mortgage bonds 2002 8.125% $ 125,000 $ 125,000
2004 6.625% 80,000 80,000
2021 9.5% -- 45,140
2021 9.0% -- 72,370
2023 7.25% 54,150 70,650
2024 8.75% 121,668 121,668
2025 8.0% 33,075 33,075
2028 5.5% 25,000 25,000
2028 5.875% 154,000 154,000
Unamortized discount and
premium (5,266) (5,993)
Pollution control bonds 2024-2034 Adjustable
rate(b) 386,860 476,860
Pollution control bonds 2029 3.30%(c) 90,000 --
Unsecured notes 2004 5.875% 125,000 125,000
Unsecured notes 2005 6.25% 100,000 100,000
Unsecured notes 2005 7.625% 300,000 300,000
Unsecured notes 2011 6.375% 400,000 --
Floating rate notes 2001 Adjustable
rate(d) -- 250,000
Senior notes (e) 2006 6.75% 83,695 83,695
Capitalized lease obligation 2001-2003 7.75% 417 709
Capitalized lease obligation 2006 5.89% 926 --
---------- ----------
Total long-term debt 2,074,525 2,057,174
Less current maturities 125,451 250,266
---------- ----------
Total long-term debt less
current maturities $1,949,074 $1,806,908
========== ==========
(a) This schedule does not reflect the timing of redemptions that may occur
prior to maturity.
(b) The weighted-average rate for the year ended December 31, 2001 was 2.55%
and for December 31, 2000 was 4.06%. Changes in short-term interest rates
would affect the costs associated with this debt.
(c) In November 2001 these bonds were converted to a one year fixed rate of
3.30%. These bonds were previously adjustable rate and from January 1, 2001
until October 31, 2001 the weighted average rate was 2.72%.
(d) The weighted-average rate for the year ended December 31, 2000 was 7.33%.
Interest for 2000 was based on LIBOR + 0.72%.
(e) We currently have outstanding $84 million of first mortgage bonds (senior
note mortgage bonds) issued to the senior note trustee as collateral for
the senior notes. The senior note mortgage bonds have the same interest
55
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
rate, interest payment dates, maturity, and redemption provisions as the
senior notes. Our payments of principal, premium, and/or interest on the
senior notes satisfy our corresponding payment obligations on the senior
note mortgage bonds. As long as the senior note mortgage bonds secure the
senior notes, the senior notes will effectively rank equally with the first
mortgage bonds. When we repay all of our first mortgage bonds, other than
those that secure senior notes, the senior note mortgage bonds will no
longer secure the senior notes and will cease to be outstanding.
Our bank agreements have financial covenants, including an interest
coverage test and a debt ratio. We anticipate that we will be able to meet the
covenant requirement levels.
The following is a list of principal payments due on total long-term debt
and sinking fund requirements through 2006:
* $125 million in 2002;
* $ 0 million in 2003;
* $205 million in 2004;
* $400 million in 2005; and
* $ 84 million in 2006.
Our first mortgage bondholders share a lien on substantially all utility
plant assets (other than nuclear fuel and transportation equipment and other
excluded assets). The mortgage bond indenture restricts the payment of common
stock dividends under certain conditions. These conditions did not exist at
December 31, 2001.
7. RETIREMENT PLANS AND OTHER BENEFITS
PENSION PLAN
Through 1999, we sponsored defined benefit pension plans for our employees.
As of January 1, 2000, we are part of a multi-employer plan sponsored by
Pinnacle West. In 2001, we represent 89% of the total cost of this plan. A
defined benefit plan specifies the amount of benefits a plan participant is to
receive using information about the participant. The plan covers nearly all of
our employees. Our employees do not contribute to this plan. Generally, the
benefits under this plan are calculated based on age, years of service, and pay.
Pinnacle West funds the plan by contributing at least the minimum amount
required under Internal Revenue Service regulations but no more than the maximum
tax-deductible amount. The assets in the plan at December 31, 2001 were mostly
domestic and international common stocks and bonds and real estate.
56
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
The following table shows our contributions and pension expense, including
administrative costs, and after consideration of amounts capitalized or billed
to electric plant participants for 2001, 2000, and 1999 (dollars in millions):
2001 2000 1999
-------- -------- --------
Contributions $ 44 $ 23 $ 25
Pension Expense $ 6 $ 2 $ 4
The following table shows the components of Pinnacle West's consolidated
net periodic pension cost before consideration of amounts capitalized or billed
to electric plant participants (dollars in thousands):
2001 2000 1999
---------- ---------- ----------
Service cost - benefits earned during the period $ 26,640 $ 24,955 $ 24,982
Interest cost on projected benefit obligation 62,920 58,361 52,905
Expected return on plan assets (77,340) (77,231) (68,335)
Amortization of:
Transition asset (3,227) (3,227) (3,226)
Prior service cost 2,716 2,078 2,078
Net actuarial gain -- (1,633) --
---------- ---------- ----------
Net periodic pension cost $ 11,709 $ 3,303 $ 8,404
========== ========== ==========
The following table shows a reconciliation of the funded status of the plan
to the amounts recognized in Pinnacle West's consolidated balance sheets
(dollars in thousands):
2001 2000
--------- ---------
Funded status - pension plan assets less than
projected benefit obligation $(116,213) $ (20,730)
Unrecognized net transition asset (13,554) (16,781)
Unrecognized prior service cost 24,465 18,558
Unrecognized net actuarial (gains)/losses 94,952 (23,816)
--------- ---------
Net pension liability recognized in the balance sheets $ (10,350) $ (42,769)
========= =========
57
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
The following table sets forth the change in projected benefit obligation
for Pinnacle West's consolidated defined benefit pension plan for the plan years
2001 and 2000 (dollars in thousands):
2001 2000
---------- ----------
Projected pension benefit obligation at
beginning of year $ 795,926 $ 742,638
Service cost 26,640 24,955
Interest cost 62,920 58,361
Benefit payments (31,647) (30,568)
Actuarial losses 18,625 540
Plan amendments 8,622 --
---------- ----------
Projected pension benefit obligation at end of year $ 881,086 $ 795,926
========== ==========
The following table sets forth Pinnacle West's consolidated defined benefit
pension plan's change in the fair value of plan assets for the plan years 2001
and 2000 (dollars in thousands):
2001 2000
---------- ----------
Fair value of pension plan assets at
beginning of year $ 775,196 $ 779,913
Actual gain/(loss) on plan assets (22,876) 1,851
Employer contributions 44,200 24,000
Benefit payments (31,647) (30,568)
---------- ----------
Fair value of pension plan assets at end of year $ 764,873 $ 775,196
========== ==========
Pinnacle West made the assumptions below to calculate the pension liability:
2001 2000
---------- ----------
Discount rate 7.50% 7.75%
Rate of increase in compensation levels 4.00% 4.25%
Expected long-term rate of return on assets 10.00% 10.00%
58
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
EMPLOYEE SAVINGS PLAN BENEFITS
Through 1999, we sponsored defined contribution savings plans for our
employees. As of January 1, 2000, we are part of a multi-employer plan sponsored
by Pinnacle West. In 2001, we represent 83% of the total cost of this plan. In a
defined contribution plan, the benefits a participant will receive result from
regular contributions they make to a participant account. Under this plan,
Pinnacle West makes matching contributions in Pinnacle West stock to participant
accounts. At December 31, 2001 approximately 30% of total plan assets were in
Pinnacle West stock. We recorded expenses for this plan of approximately $4
million for 2001, $3 million for 2000, and $4 million for 1999.
POSTRETIREMENT PLAN
Through 1999, we sponsored postretirement medical and life insurance plans
for our employees. As of January 1, 2000, we are part of a multi-employer plan
sponsored by Pinnacle West. In 2001, we represent 93% of the total cost of this
plan. We provide medical and life insurance benefits to retired employees.
Employees must retire to become eligible for these retirement benefits, which
are based on years of service and age. For the medical insurance plans, retirees
make contributions to cover a portion of the plan costs. For the life insurance
plan, retirees do not make contributions to cover a portion of the plan costs.
We retain the right to change or eliminate these benefits.
Funding is based upon actuarially determined contributions that take tax
consequences into account. Plan assets consist primarily of domestic stocks and
bonds.
The following table shows our contributions and postretirement benefit
expense after consideration of amounts capitalized or billed to electric plant
participants for 2001, 2000, and 1999 (dollars in millions):
2001 2000 1999
-------- -------- --------
Contributions $ 11 $ 5 $ 10
Postretirement benefit expense $ 6 $ 2 $ 6
The following table shows the components of Pinnacle West's consolidated
net periodic postretirement benefit costs before consideration of amounts
capitalized or billed to electric plant participants (dollars in thousands):
59
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
2001 2000 1999
---------- ---------- ----------
Service cost - benefits earned during the period $ 9,438 $ 8,613 $ 8,939
Interest cost on accumulated benefit obligation 21,585 19,315 17,366
Expected return on plan assets (21,985) (22,381) (18,454)
Amortization of:
Transition obligation 7,698 7,698 7,698
Net actuarial gains (4,066) (7,983) (5,117)
---------- ---------- ----------
Net periodic postretirement benefit cost $ 12,670 $ 5,262 $ 10,432
========== ========== ==========
The following table shows a reconciliation of the funded status of the plan
to the amounts recognized in Pinnacle West's consolidated balance sheets
(dollars in thousands):
2001 2000
---------- ----------
Funded status - postretirement plan assets less
than projected benefit obligation $ (80,544) $ (14,851)
Unrecognized net obligation at transition 84,748 92,446
Unrecognized net actuarial gains (8,606) (81,280)
---------- ----------
Net postretirement amount recognized in the
balance sheets $ (4,402) $ (3,685)
========== ==========
The following table sets forth Pinnacle West's consolidated postretirement
benefit plan's change in accumulated benefit obligation for the plan years 2001
and 2000 (dollars in thousands):
2001 2000
---------- ----------
Accumulated postretirement benefit obligation
at beginning of year $ 264,006 $ 231,989
Service cost 9,438 8,613
Interest cost 21,585 19,315
Benefit payments (10,194) (8,905)
Actuarial losses 33,520 12,994
---------- ----------
Accumulated postretirement benefit obligation
at end of year $ 318,355 $ 264,006
========== ==========
60
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
The following table sets forth Pinnacle West's consolidated postretirement
benefit plan's change in the fair value of plan assets for the plan years 2001
and 2000 (dollars in thousands):
2001 2000
---------- ----------
Fair value of postretirement plan assets at
beginning of year $ 249,154 $ 257,538
Actual loss on plan assets (12,550) (4,436)
Employer contributions 11,400 4,958
Benefit payments (10,194) (8,906)
---------- ----------
Fair value of postretirement plan assets at
the end of year $ 237,810 $ 249,154
========== ==========
Pinnacle West made the assumptions below to calculate the postretirement
liability:
2001 2000
-------- --------
Discount rate 7.50% 7.75%
Expected long-term rate of return on assets - after tax 8.86% 8.77%
Initial health care cost trend rate - under age 65 7.00% 7.00%
Initial health care cost trend rate - age 65 and over 7.00% 6.00%
Ultimate health care cost trend rate 5.00% 5.00%
Year ultimate health care trend rate is reached 2006 2002
The following table shows the effect of a 1% increase or decrease in the
health care cost trend rate (dollars in millions):
1% increase 1% decrease
----------- -----------
Effect on 2001 cost of postretirement benefits
other than pensions $ 6 $ (5)
Effect on the accumulated postretirement benefit
obligation at December 31, 2001 $ 54 $ (43)
8. LEASES
In 1986, we sold about 42% of our share of Palo Verde Unit 2 and certain
common facilities in three separate sale leaseback transactions. We account for
these leases as operating leases. The gain of approximately $140 million was
deferred and is being amortized to operations expense over 29.5 years, the
original term of the leases. There are options to renew the leases for two
additional years and to purchase the property for fair market value at the end
of the lease terms. Consistent with the ratemaking treatment, an amount equal to
the annual lease payments is included in rent expense. A regulatory asset is
recognized for the difference between lease payments and rent expense calculated
on a straight-line basis. See Note 2 for a discussion of special purpose
61
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
entities, including the special purpose entities involved in the Palo Verde
sale-leaseback transactions.
The average amounts to be paid for the Palo Verde Unit 2 leases are
approximately $49 million per year for the years 2002-2015.
In accordance with the 1999 Settlement Agreement, we are continuing to
accelerate amortization of the regulatory asset for leases over an eight-year
period that will end June 30, 2004 (see Note 1). All regulatory asset
amortization is included in depreciation and amortization expense in the
statements of income. The balance of this regulatory asset at December 31, 2001
was $24 million.
In December 2000, we purchased Units 1, 2, and 3 of West Phoenix Power
Plant, which was previously leased under a capitalized lease obligation.
In addition, we lease certain land, buildings, equipment, and miscellaneous
other items through operating rental agreements with varying terms, provisions,
and expiration dates.
Total lease expense was $52 million in 2001, $53 million in 2000, and $49
million in 1999.
Estimated future minimum lease commitments, are approximately $61 million
for each of the years 2002 to 2006 and $507 million thereafter.
62
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
9. JOINTLY-OWNED FACILITIES
We share ownership of some of our generating and transmission facilities
with other companies. The following table shows our interest in those
jointly-owned facilities recorded on the balance sheets at December 31, 2001.
Our share of operating and maintaining these facilities is included in the
income statement in operations and maintenance expense. Each participant is
entitled to its share of power generated.
PERCENT CONSTRUCTION
OWNED BY PLANT IN ACCUMULATED WORK IN
COMPANY SERVICE DEPRECIATION PROGRESS
------- ---------- ------------ ---------
(dollars in thousands)
Generating Facilities:
Palo Verde Nuclear Generating Station
Units 1 and 3 29.1% $1,822,369 $(862,880) $ 10,984
Palo Verde Nuclear Generating Station
Unit 2 (see Note 8) 17.0% 571,217 (278,234) 46,284
Four Corners Steam Generating Station
Units 4 and 5 15.0% 150,298 (78,983) 503
Navajo Steam Generating Station
Units 1, 2, and 3 14.0% 235,409 (104,189) 1,044
Cholla Steam Generating Station
Common Facilities (a) 62.8%(b) 74,356 (41,555) 1,093
Transmission Facilities:
ANPP 500KV System 35.8%(b) 67,911 (24,293) 405
Navajo Southern System 31.4%(b) 27,053 (16,833) 202
Palo Verde-Yuma 500KV System 23.9%(b) 9,685 (4,029) 8
Four Corners Switchyards 27.5%(b) 3,071 (1,945) --
Phoenix-Mead System 17.1%(b) 36,418 (2,766) --
Palo Verde - Estrella 500KV System 50.0%(b) -- -- 2,215
(a) PacifiCorp owns Cholla Unit 4 and we operate the unit for PacifiCorp. The
common facilities at the Cholla Plant are jointly-owned.
(b) Weighted average of interests.
63
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
10. COMMITMENTS AND CONTINGENCIES
ENRON
We recorded charges totaling $13 million before income taxes for exposure
to Enron and its affiliates in the fourth quarter of 2001. This amount is
comprised of a $7 million reserve for the Company's net exposure to Enron and
its affiliates, and additional expenses of $6 million primarily related to 2002
power contracts with Enron that were canceled.
POWER SERVICE AGREEMENT
By letter dated March 7, 2001, Citizens, which owns a utility in Arizona,
advised us that it believes we have overcharged Citizens by over $50 million
under a power service agreement. We believe that our charges under the agreement
were fully in accordance with the terms of the agreement. In addition, in
testimony filed with the ACC on March 13, 2002, Citizens acknowledged that,
based on its review, "if Citizens filed a complaint with FERC, it probably would
lose the central issue in the contract interpretation dispute." We terminated
the power service agreement with Citizens effective July 15, 2001. In
replacement of the power service agreement, Pinnacle West and Citizens entered
into a power sale agreement under which Pinnacle West will supply Citizens with
specified amounts of electricity and ancillary services through May 31, 2008.
This new agreement does not address issues previously raised by Citizens with
respect to charges under the original power service agreement through June 1,
2001.
PALO VERDE NUCLEAR GENERATING STATION
Nuclear power plant operators are required to enter into spent fuel
disposal contracts with DOE, and DOE is required to accept and dispose of all
spent nuclear fuel and other high-level radioactive wastes generated by domestic
power reactors. Although the Nuclear Waste Act required the DOE to develop a
permanent repository for the storage and disposal of spent nuclear fuel by 1998,
the DOE has announced that the repository cannot be completed before 2010 and
that it does not intend to begin accepting spent fuel prior to that date. In
November 1997, the United States Court of Appeals for the District of Columbia
Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its
own delay, but refused to order the DOE to begin accepting spent nuclear fuel.
Based on this decision and DOE's delay, a number of utilities filed damages
actions against DOE in the Court of Federal Claims.
In February 2002 the Secretary of Energy recommended to President Bush that
the Yucca Mountain, Nevada site be developed as a permanent repository for spent
nuclear fuel. The President transmitted this recommendation to Congress. A
congressional decision on this issue is expected sometime during mid-summer
2002. We cannot currently predict what further steps will be taken in this area.
We have existing fuel storage pools at Palo Verde and are in the process of
completing construction of a new facility for on-site dry storage of spent fuel.
With the existing storage pools and the addition of the new facility, we believe
64
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
that spent fuel storage or disposal methods will be available for use by Palo
Verde to allow our continued operation through the term of the operating license
for each Palo Verde unit.
Although some low-level waste has been stored on-site in a low-level waste
facility, we are currently shipping low-level waste to off-site facilities. We
currently believe that interim low-level waste storage methods are or will be
available for use by Palo Verde to allow our continued operation and to safely
store low-level waste until a permanent disposal facility is available.
We currently estimate that we will incur $407 million (in 2001 dollars)
over the life of Palo Verde for our share of the costs related to the on-site
interim storage of spent nuclear fuel. As of December 31, 2001, we had recorded
a liability and regulatory asset of $43 million for on-site interim nuclear fuel
storage costs related to nuclear fuel burned to date.
The Palo Verde participants have insurance for public liability resulting
from nuclear energy hazards to the full limit of liability under federal law.
This potential liability is covered by primary liability insurance provided by
commercial insurance carriers in the amount of $200 million and the balance by
an industry-wide retrospective assessment program. If losses at any nuclear
power plant covered by the programs exceed the accumulated funds, we could be
assessed retrospective premium adjustments. The maximum assessment per reactor
under the program for each nuclear incident is approximately $88 million,
subject to an annual limit of $10 million per incident. Based upon our interest
in the three Palo Verde units, our maximum potential assessment per incident for
all three units is approximately $77 million, with an annual payment limitation
of approximately $9 million.
The Palo Verde participants maintain "all risk" (including nuclear hazards)
insurance for property damage to, and decontamination of, property at Palo Verde
in the aggregate amount of $2.75 billion, a substantial portion of which must
first be applied to stabilization and decontamination. We have also secured
insurance against portions of any increased cost of generation or purchased
power and business interruption resulting from a sudden and unforeseen outage of
any of the three units. The insurance coverage discussed in this and the
previous paragraph is subject to certain policy conditions and exclusions.
FUEL AND PURCHASED POWER COMMITMENTS
We are a party to various fuel and purchased power contracts with terms
expiring from 2002 through 2021 that include required purchase provisions. We
estimate our contract requirements to be approximately $252 million in 2002,
$124 million in 2003, $80 million in 2004, $65 million in 2005 and $68 million
in 2006. However, this amount may vary significantly pursuant to certain
provisions in such contracts that permit us to decrease our required purchases
under certain circumstances. Any purchased power contracts after 2003 will all
be recorded on Pinnacle West through their marketing and trading division.
65
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
COAL MINE RECLAMATION OBLIGATIONS
We must reimburse certain coal providers for amounts incurred for coal mine
reclamation. We estimate our share of the total obligation to be about $103
million. The portion of the coal mine reclamation obligation related to coal
already burned is about $59 million at December 31, 2001 and is included in
deferred credits-other in the balance sheets.
A regulatory asset has been established for amounts not yet recovered from
ratepayers related to the coal obligations. In accordance with the 1999
Settlement Agreement with the ACC, we are continuing to accelerate the
amortization of the regulatory asset for coal mine reclamation over an
eight-year period that will end June 30, 2004. Amortization is included in
depreciation and amortization expense on the statements of income.
CALIFORNIA ENERGY MARKET ISSUES AND REFUNDS IN THE PACIFIC NORTHWEST
SCE and PG&E have publicly disclosed that their liquidity has been
materially and adversely affected because of, among other things, their
inability to pass on to ratepayers the prices each has paid for energy and
ancillary services procured through the PX and the ISO.
We are closely monitoring developments in the California energy market and
the potential impact of these developments on us. We have evaluated, among other
things, SCE's role as a Palo Verde and Four Corners participant; our
transactions with the PX and the ISO; contractual relationships with SCE and
PG&E; and marketing and trading exposures. Based on our evaluations, we do not
believe the foregoing matters will have a material adverse effect on our
financial position and liquidity. We cannot predict with certainty, however, the
impact that any future resolution or attempted resolution, of the California
energy market situation may have on us or the regional energy market in general.
In July 2001, the FERC ordered an expedited fact-finding hearing to
calculate refunds for spot market transactions in California during a specified
time frame. This order calls for a hearing, with findings of fact due to the
FERC after the California ISO and PX provide necessary historical data. The FERC
also ordered an evidentiary proceeding to discuss and evaluate possible refunds
for the Pacific Northwest. The ALJ at the FERC in charge of that evidentiary
proceeding made an initial finding that no refunds were appropriate. The Pacific
Northwest issues will now be addressed by the FERC Commissioners. Although the
FERC has not yet made a final ruling in the Pacific Northwest matter or
calculated the specific refund amounts due in California, we do not expect that
the resolution of these issues, as to amounts alleged in the proceedings, will
have a material adverse impact on our financial position, results of operations
or liquidity.
On March 19, 2002, the State of California filed a complaint with the FERC
alleging that wholesale sellers of power and energy, including Pinnacle West,
failed to properly file rate information at the FERC in connection with sales to
California from 2000 to present. STATE OF CALIFORNIA V. BRITISH COLUMBIA POWER
EXCHANGE ET AL., Docket No. EL02-71-000. The complaint requests the FERC to
require the wholesale sellers to refund any rates that are "found to exceed just
and reasonable levels." The complaint indicates that Pinnacle West sold
approximately $106 million of power to the California Department of Water
Resources from January 17, 2001 to October 31, 2001 and does not allege any
66
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
amount above "just and reasonable levels." Pinnacle West believes that the
claims as they relate to Pinnacle West are without merit.
CONSTRUCTION PROGRAM
Total capital expenditures in 2002 are estimated at $498 million.
LITIGATION
We are party to various claims, legal actions, and complaints arising in
the ordinary course of business. In our opinion, the ultimate resolution of
these matters will not have a material adverse effect on our financial
statements or liquidity.
11. NUCLEAR DECOMMISSIONING COSTS
We recorded $11 million for nuclear decommissioning expense in each of the
years 2001, 2000, and 1999. We estimate it will cost about $1.8 billion ($506
million in 2001 dollars) to decommission our share of the three Palo Verde
units. The majority of decommissioning costs are expected to be incurred over a
14-year period beginning in 2024. We charge decommissioning costs to expense
over each unit's operating license term and include them in the accumulated
depreciation balance until each unit is retired. Nuclear decommissioning costs
are recovered in rates.
Our current estimates are based on a 2001 site-specific study for Palo
Verde that assumes the prompt removal/dismantlement method of decommissioning.
An independent consultant prepared this study. We are required to update the
study every three years.
To fund the costs we expect to incur to decommission the plant, we
established external decommissioning trusts in accordance with NRC regulations.
We invest the trust funds primarily in fixed income securities and domestic
stock and classify them as available for sale. Realized and unrealized gains and
losses are reflected in accumulated depreciation in accordance with industry
practice. The following table shows the cost and fair value of our nuclear
decommissioning trust fund assets which are reported in investments and other
assets on the balance sheets at December 31, 2001 and 2000 (dollars in
millions):
67
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
2001 2000
-------- --------
Trust fund assets - at cost
Fixed income securities $ 103 $ 94
Domestic stock 61 52
-------- --------
Total $ 164 $ 146
======== ========
Trust fund assets - fair value
Fixed income securities $ 106 $ 97
Domestic stock 96 100
-------- --------
Total $ 202 $ 197
======== ========
See Note 2 for information on a new accounting standard on accounting for
certain liabilities related to closure or removal of long-lived assets.
12. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly financial information for 2001 and 2000 is as follows:
(dollars in thousands)
2001
--------------------------------------------------------
QUARTER ENDED March 31 June 30 September 30 December 31
---------- ---------- ------------ -----------
Electric operating revenues (a)
Electric retail segment $ 412,807 $ 739,317 $ 973,398 $ 436,566
Marketing and trading
segment (b) 247,022 230,894 65,129 6,195
Operating income (a) $ 97,034 $ 95,238 $ 135,139 $ 71,567
Income before accounting
change $ 64,606 $ 69,639 $ 107,556 $ 38,887
Cumulative effect of change in
accounting - net of income tax (2,755) -- (12,446) --
---------- ---------- ---------- ----------
Net income $ 61,851 $ 69,639 $ 95,110 $ 38,887
========== ========== ========== ==========
68
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
(dollars in thousands)
2000
--------------------------------------------------------
QUARTER ENDED March 31 June 30 September 30 December 31
---------- ---------- ------------ -----------
Electric operating revenues (a)
Electric retail segment $ 379,428 $ 547,091 $1,156,659 $ 455,572
Marketing and trading
segment (b) 35,040 104,386 93,141 162,825
Operating income (a) $ 64,849 $ 131,034 $ 159,589 $ 90,764
---------- ---------- ---------- ----------
Net income $ 32,775 $ 95,851 $ 124,231 $ 53,737
========== ========== ========== ==========
(a) Electric revenues are seasonal in nature, with the peak sales periods
generally occurring during the summer months. Comparisons among quarters of
a year may not represent overall trends and changes in operations.
(b) See Note 18 for information related to a change in presentation of certain
marketing and trading revenues to a net basis.
13. FAIR VALUE OF FINANCIAL INSTRUMENTS
We believe that the carrying amounts of our cash equivalents and commercial
paper are reasonable estimates of their fair values at December 31, 2001 and
2000 due to their short maturities.
We hold investments in debt and equity securities for purposes other than
trading. The December 31, 2001 and 2000 fair values of such investments, which
we determine by using quoted market values, approximate their carrying amount.
On December 31, 2001, the carrying value of our long-term debt (excluding a
capitalized lease obligation) was $2.08 billion, with an estimated fair value of
$2.10 billion. The carrying value of our long-term debt (excluding a capitalized
lease obligation) was $2.06 billion on December 31, 2000, with an estimated fair
value of $2.11 billion. The fair value estimates are based on quoted market
prices of the same or similar issues.
14. STOCK-BASED COMPENSATION
Pinnacle West offers two stock incentive plans for officers and key
employees of our company.
One of the plans (1994 plan) provides for the granting of new options
(which may be non-qualified stock options or incentive stock options) of up to
3.5 million shares at a price per option not less than the fair market value on
the date the option is granted. The other plan (1985 plan) includes outstanding
options but no new options will be granted from the plan. Options vest one-third
69
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
of the grant per year beginning one year after the date the option is granted
and expire ten years from the date of the grant. The plan also provides for the
granting of any combination of shares of restricted stock, stock appreciation
rights or dividend equivalents.
The awards outstanding under the incentive plans at December 31, 2001 are
1,832,725 non-qualified stock options, 237,833 shares of restricted stock, and
no incentive stock options, stock appreciation rights or dividend equivalents.
SFAS No. 123, "Accounting for Stock-Based Compensation" encourages, but
does not require, that a company record compensation expense based on the fair
value of options granted (the fair value method). We continue to recognize
expense based on Accounting Principles Board Opinion No. 25, "Accounting for
Stock Issued to Employees."
If we had recorded compensation expense based on the fair value method, our
net income would have been reduced to the following pro forma amounts (dollars
in thousands):
2001 2000 1999
---------- ---------- ----------
Net income
As reported $ 265,487 $ 306,594 $ 128,437
Pro forma (fair value method) $ 263,594 $ 305,610 $ 127,658
In order to present the pro forma information above, we calculated the fair
value of each fixed stock option in the incentive plans using the Black-Scholes
option-pricing model. The fair value was calculated based on the date the option
was granted. The following weighted-average assumptions were also used in order
to calculate the fair value of the stock options:
2001 2000 1999
---------- ---------- ----------
Risk-free interest rate 4.08% 5.81% 5.68%
Dividend yield 3.70% 3.48% 3.33%
Volatility 27.66% 32.00% 20.50%
Expected life (months) 60 60 60
70
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
15. BUSINESS SEGMENTS
We have two principal business segments (determined by products, services
and regulatory environment) which consist of regulated retail electricity
business and related activities (electric retail business segment) and
competitive business activities (marketing and trading segment). Our electric
retail business segment currently includes activities related to electricity
transmission and distribution, as well as electricity generation. Our marketing
and trading business segment currently includes activities related to wholesale
marketing and trading.
These reportable segments reflect a change in the reporting of our segment
information. Before the fourth quarter of 2001, we had two segments (generation
and delivery). The "generation segment" information combined our marketing and
trading activities with our generation of electricity activities. The "delivery
segment" included transmission and distribution activities.
In the fourth quarter of 2001, we filed with the ACC a proposed rule
variance and purchase power agreement with the ACC (see Note 3) that inherently
views our business in the new reportable segments described herein. Internal
management reporting has been changed to reflect this alignment. The
corresponding information for earlier periods has been restated. Financial data
for the business segments is provided as follows (dollars in millions):
Business Segments for Year Ended December 31, 2001
Electric Marketing and
Retail Trading (a) Total
-------- ----------- --------
Operating revenues $ 2,562 $ 549 $ 3,111
Purchased power and fuel costs 1,227 314 1,541
Other operating expenses 568 -- 568
-------- -------- --------
Operating margin 767 235 1,002
Depreciation and amortization 421 -- 421
Interest and other expenses 118 -- 118
-------- -------- --------
Pretax margin 228 235 463
Income taxes 90 93 183
-------- -------- --------
Income before accounting change 138 142 280
Cumulative effect of change in
accounting for derivatives - net of
income taxes of $10 (15) -- (15)
-------- -------- --------
Net income $ 123 $ 142 $ 265
======== ======== ========
Total assets $ 6,228 $ 139 $ 6,367
======== ======== ========
Capital expenditures $ 471 $ -- $ 471
======== ======== ========
71
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
Business Segments for Year Ended December 31, 2000
Electric Marketing and
Retail Trading (a) Total
-------- ----------- --------
Operating revenues $ 2,539 $ 395 $ 2,934
Purchased power and fuel costs 1,065 267 1,332
Other operating expenses 541 -- 541
-------- -------- --------
Operating margin 933 128 1,061
Depreciation and amortization 425 -- 425
Interest and other expenses 133 -- 133
-------- -------- --------
Pretax margin 375 128 503
Income taxes 145 51 196
-------- -------- --------
Net income $ 230 $ 77 $ 307
======== ======== ========
Total assets $ 6,096 $ 318 $ 6,414
======== ======== ========
Capital expenditures $ 472 $ -- $ 472
======== ======== ========
Business Segments for Year Ended December 31, 1999
Electric Marketing and
Retail Trading (a) Total
-------- ----------- --------
Operating revenues $ 1,915 $ 154 $ 2,069
Purchased power and fuel costs 432 137 569
Operating expenses 547 -- 547
-------- -------- --------
Operating margin 936 17 953
Depreciation and amortization 416 -- 416
Interest and preferred stock
dividend requirements 137 -- 137
-------- -------- --------
Pretax margin 383 17 400
Income taxes 126 7 133
Extraordinary charge - net of
income taxes of $94 (140) -- (140)
-------- -------- --------
Earnings for common stock $ 117 $ 10 $ 127
======== ======== ========
Total assets $ 6,056 $ 62 $ 6,118
======== ======== ========
Capital expenditures $ 332 $ -- $ 332
======== ======== ========
(a) See Note 18 for information related to a change in presentation of certain
marketing and trading revenues and purchased power and fuel costs to a net
basis.
72
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
16. DERIVATIVE INSTRUMENTS
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal and emissions allowances.
We employ established procedures to manage risks associated with these market
fluctuations by utilizing various commodity derivatives, including
exchange-traded futures and options and over-the-counter forwards, options, and
swaps. As part of our overall risk management program, we enter into derivative
transactions to hedge purchases and sales of electricity, fuels, and emissions
allowance and credits. The changes in market value of such contracts have a high
correlation to price changes in the hedged commodity. In addition, subject to
specified risk parameters established by the Pinnacle West Board of Directors
and monitored by Pinnacle West's ERMC, we engage in trading activities intended
to profit from market price movements.
We are exposed to losses in the event of nonperformance or nonpayment by
counterparties. We use a risk management process to assess and monitor the
financial exposure of this and all other counterparties. Despite the fact that
the great majority of our counterparties are rated as investment grade by the
credit rating agencies there is still a possibility that one or more of these
companies could default, resulting in a material impact on earnings for a given
period. Counterparties in the portfolio consist principally of major energy
companies, municipalities, and local distribution companies. We maintain credit
policies that we believe minimize overall credit risk to within acceptable
limits. Determination of the credit quality of our counterparties is based upon
a number of factors, including credit ratings and our evaluation of their
financial condition. In many contracts, we employ collateral requirements and
standardized agreements that allow for the netting of positive and negative
exposures associated with a single counterparty. Credit reserves are established
representing our estimated credit losses on our overall exposure to
counterparties. See Note 1 for a discussion of our credit reserve policy.
Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133 requires that
entities recognize all derivatives as either assets or liabilities on the
balance sheets and measure those instruments at fair value. Changes in the fair
value of derivative financial instruments are either recognized periodically in
income or shareholders' equity (as a component of other comprehensive income),
depending on whether or not the derivative meets specific hedge accounting
criteria. Hedge effectiveness is measured based on the relative changes in fair
value between the derivative contract and the hedged item over time. Any change
in the fair value resulting from ineffectiveness is recognized immediately in
net income. This new standard may result in additional volatility in our net
income and comprehensive income.
As a result of adopting SFAS No. 133, we recognized $118 million of
derivative assets and $16 million of derivative liabilities in our balance
sheets as of January 1, 2001. Also as of January 1, 2001, we recorded a $3
million after-tax loss in net income and a $64 million after-tax gain in equity
(as a component of other comprehensive income) both as a cumulative effect of a
change in accounting principle. The gain resulted from unrealized gains on cash
flow hedges.
73
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
In June 2001, the FASB issued new guidance related to electricity
contracts. The effective date of this new guidance was July 1, 2001. As of July
1, 2001, we recorded an additional $12 million after-tax loss in net income and
an additional $8 million after-tax gain in equity (as a component of other
comprehensive income), as a result of adopting the new guidance related to
electricity contracts. The loss resulted primarily from electricity options
contracts. The gain resulted from unrealized gains on cash flow hedges. The
impact of the new guidance is reflected in net income and other comprehensive
income as a cumulative effect of change in accounting principle.
In December 2001, the FASB issued revised guidance on the accounting for
electricity contracts with option characteristics and the accounting for
contracts that combine a forward contract and a purchased option contract. The
effective date for the revised guidance is April 1, 2002. We are currently
evaluating the new guidance to determine what impact, if any, it will have on
our financial statements.
The change in derivative fair value included in the statements of income
for the year ending December 31, 2001 is comprised of the following (dollars in
thousands):
December 31,
2001
----------
Ineffective portion of derivatives
qualifying for hedge accounting (a) $ (8,371)
Discontinuance of cash flow hedges for
forecasted transactions that will not occur (9,525)
Reclassification of mark-to-market losses to realized 25,948
----------
Total $ 8,052
==========
(a) Time value component of options excluded from assessment of hedge
effectiveness.
As of December 31, 2001, the maximum length of time over which we are
hedging our exposure to the variability in future cash flows for forecasted
transactions is thirty-six months. During the twelve months ended December 31,
2002, we estimate that a net loss of $23 million before income taxes will be
reclassified from accumulated other comprehensive loss as an offset to the
effect on earnings of market price changes for the related hedged transaction.
Net gains and losses on instruments utilized for trading activities are
recognized in marketing and trading revenues on a current basis (the
mark-to-market method). Trading positions are measured at fair value as of the
balance sheet date. The unrealized trading gains recognized in marketing and
trading revenues were $85 million for the year ended December 31, 2001 and $14
million for the year ended December 31, 2000.
74
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
17. SUBSEQUENT EVENTS
On March 1, 2002, we issued $375 million of 6.50% Notes due 2012. On March
15, 2002, we announced the redemption on April 15, 2002 of approximately $125
million of our First Mortgage Bonds, 8.75% Series due 2024.
On March 19, 2002, the State of California filed a complaint with the FERC
alleging that wholesale sellers of power and energy, including Pinnacle West,
failed to properly file rate information at the FERC in connection with sales to
California from 2000 to the present. STATE OF CALIFORNIA V. BRITISH COLUMBIA
POWER EXCHANGE ET. AL., Docket No. EL02-71-000. The complaint requests the FERC
to require the wholesale sellers to refund any rates that are "found to exceed
just and reasonable levels." The complaint indicates that Pinnacle West sold
approximately $106 million of power to California Department of Water Resources
from January 17, 2001 to October 31, 2001 and does not allege any amount above
"just and reasonable levels." Pinnacle West believes that the claims as they
relate to Pinnacle West are without merit.
See Note 3 for information relating to the March 22, 2002 ACC Staff report
addressing issues in the generic docket.
18. SUBSEQUENT EVENT - NET REVENUE PRESENTATION CHANGE
In June 2002, the FASB's EITF issued certain guidance related to energy
trading activities in EITF 02-3, "Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and
Risk Management Activities." The new guidance, which was effective July 1, 2002,
required that all energy trading activities within the scope of EITF 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities," be presented on a net basis in revenues and that prior period
amounts be restated.
In October 2002, the EITF reached a consensus that gains and losses on
derivative instruments within the scope of SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" should be shown net in the income
statement if the derivative is held for trading purposes. This decision
effectively supersedes the guidance provided at the June meeting. Historically,
we have reported our electric revenues and purchased power and fuel costs on a
gross basis in our statements of income, with the exception of unrealized gains
and losses recorded under the mark-to-market method. When the gain or loss was
realized, the gross amount was recorded as revenue and purchased power and fuel
costs in the statements of income. Throughout this document, we have made the
reclassification change to net revenues and purchased power and fuel costs
related to our energy trading activities. This change has no impact on our gross
margin, net income or cash provided by operating activities. The following table
shows the impact of the change on our Marketing and Trading segment revenues and
purchased power and fuel costs:
75
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
Year ended December 31,
(dollars in thousands)
----------------------------------
2001 2000 1999
-------- -------- --------
Marketing and trading revenues before reclassification $748,704 $941,502 $378,076
Less: Purchased power and fuel costs netted with revenues 199,464 546,110 223,950
-------- -------- --------
Marketing and trading revenues after reclassification $549,240 $395,392 $154,126
======== ======== ========
Marketing and trading purchased power and fuel before reclassification $513,455 $813,142 $360,472
Less: Purchased power and fuel costs netted with revenues 199,464 546,110 223,950
-------- -------- --------
Marketing and trading purchased power and fuel after reclassification $313,991 $267,032 $136,522
======== ======== ========
In the October 2002 meeting, the EITF also rescinded EITF 98-10. This
guidance is effective immediately for all new contracts and on January 1, 2003
for existing contracts. As such, energy trading contracts will be accounted for
on an accrual basis with the associated revenues and costs recorded at the time
the contracted commodities are delivered or received, unless the contracts are
required to be marked to market as derivatives under SFAS No. 133 or if allowed
by other guidance. We adopted the guidance for all contracts in the fourth
quarter of 2002. The impact of this guidance was immaterial to our financial
statements.
In addition, we have presented in our income statements our operating
revenues and purchased power and fuel separately for our electric retail and
marketing and trading segments. We also have presented our other income and
expense items on a gross basis in our income statements.
76
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
ARIZONA PUBLIC SERVICE COMPANY
SCHEDULE II - RESERVE FOR UNCOLLECTIBLES
(DOLLARS IN THOUSANDS)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
ADDITIONS
---------------------
CHARGED
BALANCE AT TO COST CHARGED TO BALANCE AT
BEGINNING AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
----------- --------- -------- -------- ---------- -------
RESERVE FOR UNCOLLECTIBLES
Year ended December 31, 2001 $ 2,380 $ 7,609 $ -- $ 6,640 $ 3,349
Year ended December 31, 2000 $ 1,538 $ 5,438 $ -- $ 4,596 $ 2,380
Year ended December 31, 1999 $ 1,725 $ 4,778 $ -- $ 4,965 $ 1,538
77
ITEM 7. FINANCIAL STATEMENTS, PRO FORMA FINANCIAL INFORMATION AND EXHIBITS.
(c) Exhibits.
Exhibit No. Description
----------- -----------
23.1 Consent of Deloitte & Touche LLP
78
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Company has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
ARIZONA PUBLIC SERVICE COMPANY
(Registrant)
Dated: February 26, 2003 By: Barbara M. Gomez
------------------------------------
Barbara M. Gomez
Treasurer
79