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): November 21, 2002
PINNACLE WEST CAPITAL CORPORATION
(Exact name of registrant as specified in its charter)
Arizona 1-8962 86-0512431
(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 Pinnacle West Capital Corporation (the "Company" or
"Pinnacle West") to reflect certain reclassifications of revenue from
electricity trading activities to a net basis of reporting and the impacts of
the reclassifications on Management's Discussion and Analysis of Financial
Condition and Results of Operations, Consolidated Financial Statements and Notes
to Consolidated Financial Statements, and the Selected Consolidated 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.
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 consolidated
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
consolidated 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 Consolidated 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.
1
TABLE OF CONTENTS
PAGE
----
GLOSSARY ................................................................... 3
Selected Consolidated Data............................................. 5
Management's Discussion and Analysis of Financial Condition
and Results of Operations............................................ 10
Quantitative and Qualitative Disclosures about Market Risk............. 36
Financial Statements and Supplementary Data............................ 37
2
GLOSSARY
ACC - Arizona Corporation Commission
ACC Staff - Staff of the Arizona Corporation Commission
ALJ - Administrative Law Judge
ANPP - Arizona Nuclear Power Project, also known as Palo Verde
APS - Arizona Public Service Company, a subsidiary of the Company
APSES - APS Energy Services Company, Inc., a subsidiary of the Company
CC&N - Certificate of Convenience and Necessity
Cholla - Cholla Power Plant
Citizens - Citizens Communications Company
Company - Pinnacle West Capital Corporation
DOE - United States Department of Energy
EITF - Emerging Issues Task Force
El Dorado - El Dorado Investment Company, a subsidiary of the Company
ERMC - Energy Risk Management Committee
FASB - Financial Accounting Standards Board
FERC - United States Federal Energy Regulatory Commission
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 APS and other parties
related to the implementation of retail electric competition in Arizona
NRC - United States Nuclear Regulatory Commission
3
Nuclear Waste Act - Nuclear Waste Policy Act of 1982, as amended
Palo Verde - Palo Verde Nuclear Generating Station
PG&E - PG&E Corp.
Pinnacle West Energy - Pinnacle West Energy Corporation, a subsidiary of the
Company
PPA - purchase power agreement
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
SFAS - Statement of Financial Accounting Standards
SNWA - Southern Nevada Water Authority
SunCor - SunCor Development Company, a subsidiary of the Company
T&D - transmission and distribution
4
SELECTED CONSOLIDATED DATA
2001 2000 1999 1998 1997
------------ ------------ ------------ ------------ ------------
(dollars in thousands, except per share amounts)
OPERATING RESULTS
Operating revenues
Electric retail segment $ 2,562,089 $ 2,538,752 $ 1,915,108 $ 1,741,148 $ 1,711,134
Marketing and trading segment (a) 651,230 418,532 154,125 180,145 167,419
Real estate 168,908 158,365 130,169 124,188 116,473
Other revenues 11,771 3,873 439 -- --
Income from continuing operations $ 327,367 $ 302,332 $ 269,772 $ 242,892 $ 235,856
Discontinued operations (b) -- -- 38,000 -- --
Extraordinary charge - net of
income taxes (c) -- -- (139,885) -- --
Cumulative effect of change in -- -- -- -- --
accounting-net of income taxes (d) (15,201) -- -- -- --
------------ ------------ ------------ ------------ ------------
Net income $ 312,166 $ 302,332 $ 167,887 $ 242,892 $ 235,856
============ ============ ============ ============ ============
COMMON STOCK DATA
Book value per share - year-end $ 29.46 $ 28.09 $ 26.00 $ 25.50 $ 23.90
Earnings (loss) per weighted average
common share outstanding
Continuing operations - basic $ 3.86 $ 3.57 $ 3.18 $ 2.87 $ 2.76
Discontinued operations -- -- 0.45 -- --
Extraordinary charge -- -- (1.65) -- --
Cumulative effect of change
in accounting (0.18) -- -- -- --
------------ ------------ ------------ ------------ ------------
Net income - basic $ 3.68 $ 3.57 $ 1.98 $ 2.87 $ 2.76
============ ============ ============ ============ ============
Continuing operations - diluted $ 3.85 $ 3.56 $ 3.17 $ 2.85 $ 2.74
Net income - diluted $ 3.68 $ 3.56 $ 1.97 $ 2.85 $ 2.74
Dividends declared per share $ 1.525 $ 1.425 $ 1.325 $ 1.225 $ 1.125
Indicated annual dividend rate
per share - year-end $ 1.60 $ 1.50 $ 1.40 $ 1.30 $ 1.20
Weighted-average common shares
outstanding - basic 84,717,649 84,732,544 84,717,135 84,774,218 85,502,909
Weighted-average common shares
outstanding - diluted 84,930,140 84,935,282 85,008,527 85,345,946 86,022,709
BALANCE SHEET DATA
Total assets $ 7,981,748 $ 7,162,985 $ 6,608,506 $ 6,824,546 $ 6,850,417
============ ============ ============ ============ ============
Liabilities and equity:
Long-term debt less current
maturities $ 2,673,078 $ 1,955,083 $ 2,206,052 $ 2,048,961 $ 2,244,248
Other liabilities 2,809,347 2,825,188 2,196,721 2,516,993 2,407,572
------------ ------------ ------------ ------------ ------------
Total liabilities 5,482,425 4,780,271 4,402,773 4,565,954 4,651,820
Minority interests
Non-redeemable preferred
stock of APS -- -- -- 85,840 142,051
Redeemable preferred stock of APS -- -- -- 9,401 29,110
Common stock equity 2,499,323 2,382,714 2,205,733 2,163,351 2,027,436
------------ ------------ ------------ ------------ ------------
Total liabilities and equity $ 7,981,748 $ 7,162,985 $ 6,608,506 $ 6,824,546 $ 6,850,417
============ ============ ============ ============ ============
5
(a) Amounts related to energy trading activities have been reclassified to a
net basis. See Note 19.
(b) Tax benefit stemming from the resolution of income tax matters related to a
former subsidiary MeraBank, A Federal Savings Bank. See Note 4.
(c) Charges associated with a regulatory disallowance. See Note 3.
(d) Change in accounting standards related to derivatives. See Note 17.
6
2001 2000 1999 1998 1997
------------ ------------ ------------ ------------ ------------
(dollars in thousands)
ELECTRIC RETAIL AND
MARKETING AND TRADING
SEGMENTS' REVENUES
Retail
Residential $ 914,711 $ 880,468 $ 805,173 $ 766,378 $ 746,937
Business 952,627 935,214 911,449 889,244 873,232
------------ ------------ ------------ ------------ ------------
Total retail 1,867,338 1,815,682 1,716,622 1,655,622 1,620,169
------------ ------------ ------------ ------------ ------------
Wholesale revenue on
delivered electricity:
Traditional contracts 73,305 120,618 60,486 58,184 63,027
Retail load hedge management (a) 577,784 560,493 108,153 -- --
Marketing and trading -
delivered:
Generation other than
native load (a) 148,316 115,476 29,551 -- --
Realized margin on electricity
trading (b) 62,067 55,910 8,565 2,157 --
Other delivered electricity
(a) 328,972 244,183 112,551 170,796 163,801
------------ ------------ ------------ ------------ ------------
Total delivered marketing
and trading 539,355 415,569 150,667 172,953 163,801
------------ ------------ ------------ ------------ ------------
Total delivered wholesale
electricity 1,190,444 1,096,680 319,306 231,137 226,828
------------ ------------ ------------ ------------ ------------
Other marketing and trading:
Realized margins on delivered
commodities other than
electricity (13,646) (8,789) 2,483 7,192 3,618
Prior period mark-to-market
(gains) losses on
contracts delivered
during current period (1,059) (2,079) -- -- --
Change in mark-to-market for
future period deliveries 126,580 13,831 975 -- --
------------ ------------ ------------ ------------ ------------
Total other marketing and
trading 111,875 2,963 3,458 7,192 3,618
------------ ------------ ------------ ------------ ------------
Transmission for others 25,971 14,765 11,348 11,058 10,295
Other miscellaneous services 17,691 27,194 18,499 16,284 17,643
------------ ------------ ------------ ------------ ------------
Total electric retail and
marketing and trading
segments' revenues $ 3,213,319 $ 2,957,284 $ 2,069,233 $ 1,921,293 $ 1,878,553
============ ============ ============ ============ ============
(a) The break-out of retail load hedge management and generation other than
native load is not available for 1997 through 1998.
(b) Amounts related to trading related activities have been reclassified to a
net basis. See Note 19.
7
2001 2000 1999 1998 1997
------------ ------------ ------------ ------------ ------------
ELECTRIC SALES (MWH)
Retail:
Residential 10,334,860 9,780,680 8,774,822 8,310,689 7,970,309
Business 13,064,152 12,753,844 12,299,748 12,152,394 11,846,618
------------ ------------ ------------ ------------ ------------
Total retail 23,399,012 22,534,524 21,074,570 20,463,083 19,816,927
------------ ------------ ------------ ------------ ------------
Wholesale electricity delivered:
Traditional contracts 1,213,704 1,610,032 1,421,522 1,410,392 1,486,439
Retail load hedge management (a) 3,039,905 6,673,658 630,945 -- --
Marketing and trading -
delivered:
Generation other than
native load (a) 1,387,860 1,494,299 1,267,349 -- --
Electricity trading 12,031,055 9,259,054 5,679,023 846,864 --
Other delivered electricity (a) 2,581,942 2,960,314 6,694,995 8,060,135 7,747,134
------------ ------------ ------------ ------------ ------------
Total delivered marketing
and trading 16,000,857 13,713,667 13,641,367 8,906,999 7,747,134
------------ ------------ ------------ ------------ ------------
Total delivered wholesale
electricity 20,254,466 21,997,357 15,693,834 10,317,391 9,233,573
------------ ------------ ------------ ------------ ------------
Total electric sales 43,653,478 44,531,881 36,768,404 30,780,474 29,050,500
============ ============ ============ ============ ============
ELECTRIC CUSTOMERS -
AVERAGE
Retail:
Residential 776,339 749,285 719,774 689,871 663,493
Business 98,198 94,128 90,496 87,831 84,576
------------ ------------ ------------ ------------ ------------
Total retail 874,537 843,413 810,270 777,702 748,069
Wholesale 66 67 69 60 59
------------ ------------ ------------ ------------ ------------
Total customers 874,603 843,480 810,339 777,762 748,128
============ ============ ============ ============ ============
(a) The break-out of retail load hedge management and generation other than
native load is not available for 1997 through 1998.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations" for a discussion of certain information in the tables above.
8
QUARTERLY STOCK PRICES AND DIVIDENDS PER SHARE
STOCK SYMBOL: PNW
Dividends
Per
2001 High Low Close Share
---- ------- ------- ------- -------
1st Quarter $ 47.96 $ 39.06 $ 45.87 $ 0.375
2nd Quarter 50.70 45.20 47.40 0.375
3rd Quarter 49.93 37.65 39.70 0.375
4th Quarter 43.50 38.00 41.85 0.400
Dividends
Per
2000 High Low Close Share
---- ------- ------- ------- -------
1st Quarter $ 32.31 $ 26.25 $ 28.19 $ 0.350
2nd Quarter 35.88 27.88 33.88 0.350
3rd Quarter 51.31 33.81 50.89 0.350
4th Quarter 52.22 40.89 47.63 0.375
9
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 for Pinnacle West Capital Corporation and our
subsidiaries: Arizona Public Service Company (APS), Pinnacle West Energy
Corporation (Pinnacle West Energy), APS Energy Services Company, Inc. (APSES),
SunCor Development Company (SunCor), and El Dorado Investment Company (El
Dorado), 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
Pinnacle West owns all of the outstanding common stock of APS. APS is
Arizona's largest electric utility and provides 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. APS also generates and, through our marketing and trading division, sells
and delivers electricity to wholesale customers in the western United States.
Our other major subsidiaries are:
* Pinnacle West Energy, through which we conduct our unregulated
electricity generation operations;
* APSES, which provides commodity energy and energy-related products to
key customers in competitive markets in the western United States;
* SunCor, a developer of residential, commercial, and industrial real
estate projects in Arizona, New Mexico, and Utah; and
* El Dorado, an investment firm.
10
Pinnacle West's marketing and trading division sells in the wholesale
market APS and Pinnacle West Energy generation production output that is not
needed for APS' native load, which includes loads for retail customers and
traditional cost-of-service wholesale customers. Subject to specified risk
parameters established by our Board of Directors, the marketing and trading
division also engages in activities to hedge purchases and sales of electricity,
fuels, and emissions allowance and credits and to profit from market price
movements. We explain in detail below the historical and prospective
contribution of marketing and trading activities to our financial results.
APS is required to transfer its competitive electric assets and services to
one or more corporate affiliates no later than December 31, 2002. Consistent
with that requirement, APS has been addressing the legal and regulatory
requirements necessary to complete the transfer of its 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 APS' 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 and APSES' competitive energy services.
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, APS 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 as presented herein.
Internal management reporting has been changed to reflect this alignment. See
"Business Segments" in Note 16 for more information about our business segments.
The following is a summary of net income by business segment for 2001,
2000, and 1999 (dollars in millions):
11
2001 2000 1999
------ ------ ------
Electric retail $ 152 $ 225 $ 246
Marketing and trading 172 63 5
Other 3 14 19
------ ------ ------
Income from continuing operations 327 302 270
Income tax benefit from discontinued operations -- -- 38
Extraordinary charge - net of income taxes -- -- (140)
Cumulative effect of change in accounting -
net of income taxes (15) -- --
------ ------ ------
Net income $ 312 $ 302 $ 168
====== ====== ======
Throughout this section, we refer to specific "Notes" in the Notes to
Consolidated Financial Statements. These Notes add further details to the
discussion.
RESULTS OF OPERATIONS
The following is a summary of our net income by legal entity for 2001, 2000
and 1999 (dollars in millions):
2001 2000 1999
------ ------ ------
APS $ 281 $ 307 $ 267
Pinnacle West Energy 18 (2) --
APSES (10) (13) (9)
SunCor 3 11 6
El Dorado -- 2 11
Parent company (a) 35 (3) (5)
------ ------ ------
Income from continuing operations 327 302 270
Income tax benefit from discontinued operations -- -- 38
Extraordinary charge - net of income taxes -- -- (140)
Cumulative effect of change in accounting - net of
income taxes (15) -- --
------ ------ ------
Net income $ 312 $ 302 $ 168
====== ====== ======
(a) The 2001 amount primarily includes marketing and trading activities. APS
also includes some marketing and trading activities. (See Note 16 for
further discussion of our business segments.)
2001 COMPARED WITH 2000
Our consolidated net income for the year ended December 31, 2001 was $312
million compared with $302 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 17 for further
discussion on accounting for derivatives.
12
Income from continuing operations for the year ended December 31, 2001 was
$327 million compared with $302 million for the year ended December 31, 2000.
The year-to-year comparison benefited from strong marketing and trading results,
including significant benefits in the 2001 third quarter from structured trading
activities, 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 from continuing operations 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
Increase in other realized marketing and trading in current period
primarily due to more transactions 45
Change in prior period mark-to-market value for losses transferred to
realized margin in current period 16 (a)
Change in prior period mark-to-market value related to
trading with Enron and its affiliates (8)(b)
Increase in mark-to-market value related to future periods 113 (a)
----------
Net increase in marketing and trading 191
Higher replacement power costs for plant outages related to higher market
prices (70)
Retail price reductions (see Note 3) (27)
Charges related to purchased power contracts with Enron and its affiliates (13)(b)
Higher retail sales primarily related to customer growth 35
Miscellaneous revenues 3
----------
Total increase in marketing and trading and electric retail segments'
revenues, net of purchased power and fuel expense 119
Decrease in real estate contributions (8)
Higher operations and maintenance expense related to 2001 generation
reliability program (42)
Higher operations and maintenance expense related primarily to employee
benefits, plant outage and maintenance; and other costs (38)
Lower net interest expense primarily due to higher capitalized interest 17
Higher other net expense (4)
----------
Net increase in income from continuing operations before income taxes 44
Higher income taxes primarily due to higher income (19)
----------
Net increase in income from continuing operations $ 25
==========
13
(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 $21 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 $256 million because of:
* changes in marketing and trading revenues ($233 million, net increase):
- 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 ($87 million);
- decreased prior period mark-to-market value related to trading with
Enron and its affiliates ($8 million);
- increased prior period mark-to-market value for losses transferred to
realized margin in current period ($9 million);
- increased mark-to-market value for future periods primarily as a
result of more forward sales volumes ($113 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 $137 million
primarily because of:
* changes in marketing and trading purchased power and fuel costs ($42
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 activities in the current period primarily due to more
transactions ($42 million);
- decreased mark-to-market fuel costs related to accounting for
derivatives ($7 million) (see Note 17);
* decreased costs related to other wholesale sales as a result of lower
volumes ($31 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 costs related to retail sales volumes due to customer growth ($43
million); and
* charges related to purchased power contracts with Enron and its affiliates
($13 million).
14
The decrease in real estate profits of $8 million resulted primarily from
decreases in sales of land and homes by SunCor.
The increase in operations and maintenance expenses of $80 million
primarily related to the 2001 generation summer reliability program (the
addition of generating capability to enhance reliability for the summer of 2001
($42 million)) and increased employee benefit costs, plant outage and
maintenance, and other costs ($38 million). The comparison reflects Pinnacle
West's $10 million provision for our credit exposure related to the California
energy situation, $5 million of which was recorded in the fourth quarter of 2000
and $5 million of which was recorded in the first quarter of 2001.
Net other expense increased $4 million primarily because of a change in the
market value of El Dorado's investment in a technology-related venture capital
partnership in 2000 (see Note 1) and other nonoperating costs partially offset
by an insurance recovery of environmental remediation costs.
Interest expense decreased by $17 million primarily because of increased
capitalized interest resulting from our generation expansion plan partially
offset with higher interest expense due to higher debt balances.
2000 COMPARED WITH 1999
Our consolidated net income for the year ended December 31, 2000 was $302
million compared with $168 million for the year ended December 31, 1999. Our
2000 net income increased $134 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. The
resulting increase in our 2000 net income was partially offset by the absence of
a $38 million income tax benefit from discontinued operations that we also
recorded in 1999. See "Regulatory Agreements" below and Notes 1 and 3 for
additional information about the 1999 Settlement Agreement and the resulting
regulatory disallowance. See Note 4 for additional information about the income
tax benefit from discontinued operations.
Income from continuing operations for the year ended December 31, 2000 was
$302 million compared with $270 million for the year ended December 31, 1999.
The year-to-year comparison benefited from strong wholesale and retail electric
sales and real estate profits. These positive factors more than offset decreases
resulting from the completion of ITC amortization in 1999, reductions in retail
electricity prices, lower earnings from El Dorado, 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)
income from continuing operations were as follows (dollars in millions):
15
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 51
Change in prior period mark-to-market value for gains transferred to
realized margin in current period (2)(a)
Increase in mark-to-market value related to future periods 13 (a)
----------
Net increase in marketing and trading 109
Retail price reductions (see Note 3) (28)
Higher retail sales primarily related to customer growth 9
Miscellaneous revenues 10
----------
Total increase in marketing and trading and electric retail segments'
revenues, net of purchased power and fuel expense 100
Increase in real estate contributions 13
Higher operations and maintenance expense related primarily to customer
growth substantially offset by $20 million of other items recorded in 1999 (4)
Higher other net expense primarily related to El Dorado (14)
Higher depreciation and amortization expense (11)
Miscellaneous items, net 1
----------
Net increase in income from continuing operations before income taxes 85
Higher income taxes due to higher income in 2000 and higher ITC amortization
in 1999 (53)
----------
Net increase in income from continuing operations $ 32
==========
(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 $888 million because of:
* changes in marketing and trading revenues ($264 million, net increase):
- 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 ($167 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);
16
* 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 $788 million
primarily due to:
* changes in marketing and trading purchased power and fuel costs ($155
million, 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 activities in the current period primarily due to more
transactions ($116 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).
The increase in real estate profits of $13 million resulted primarily from
increases in sales of land and homes by SunCor.
The increase in operations and maintenance expenses of $4 million primarily
related to customer growth was substantially offset by $20 million of other
items recorded in 1999.
The increase in depreciation and amortization of $11 million primarily
related to higher plant in service balances offset by lower regulatory asset
amortization.
Net other expense decreased $14 million primarily because of changes in
2000 in the market value of El Dorado's investment in a technology-related
venture capital partnership. See Note 1 for additional information about the
valuation of El Dorado's investments.
REGULATORY AGREEMENTS
Regulatory agreements approved by the ACC affect the results of APS'
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 APS' regulatory
assets; and
* A 1994 settlement that accelerated the amortization of APS' deferred
ITCs.
17
1999 SETTLEMENT AGREEMENT
As part of the 1999 Settlement Agreement, APS 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. APS 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, APS was recovering substantially all
of its 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
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, APS reduced its 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).
APS also agreed to share future cost savings with its 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).
18
1994 RATE SETTLEMENT
As part of a 1994 rate settlement, APS accelerated amortization of
substantially all of its ITCs over a five-year period that ended on December 31,
1999. The amortization of ITCs decreased annual consolidated income tax expense
by about $24 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.
CAPITAL EXPENDITURES
(dollars in millions)
(actual) (estimated)
-------- ----------------------------
2001 2002 2003 2004
------ ------ ------ ------
APS
Delivery $ 354 $ 349 $ 271 $ 280
Existing generation (a) 117 149 -- --
------ ------ ------ ------
Subtotal 471 498 271 280
------ ------ ------ ------
Pinnacle West Energy (b)
Generation expansion 533 411 255 113(e)
Existing generation (a) -- -- 107 99
------ ------ ------ ------
Subtotal 533 411 362 212
------ ------ ------ ------
SunCor (c) 80 79 48 52
Other (d) 45 35 15 16
------ ------ ------ ------
Total $1,129 $1,023 $ 696 $ 560
====== ====== ====== ======
(a) Pursuant to the 1999 Settlement Agreement, APS is required to transfer its
competitive electric assets and services no later than December 31, 2002.
(b) See Note 10 for further discussion of Pinnacle West Energy's generation
expansion program and "Capital Resources and Cash Requirements - Pinnacle
West Energy" below.
(c) Consists primarily of capital expenditures for land development and retail
and office building construction reflected in the "Increase in real estate
investments" in the consolidated statements of cash flows.
(d) Primarily Pinnacle West and APSES.
(e) This amount does not include an expected reimbursement by Southern Nevada
Water Authority (SNWA) of $100 million of these costs in 2004 in exchange
for SNWA's purchase of a 25% interest in the Silverhawk project at that
time.
19
APS 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, APS and the other participants 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. APS' portion of this expenditure is
approximately $7 million and is included in the estimated expenditures above.
This action will provide the Palo Verde participants an option to replace the
steam generators at either Unit 1 or 3 as early as fall 2005 should they
ultimately choose to do so. If the participants decide to proceed with steam
generator replacement at both Units 1 and 3, APS has estimated that its 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.
Existing 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 existing generation also contains nuclear fuel
expenditures of approximately $30 million annually in 2002, 2003, and 2004.
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.
20
CAPITAL RESOURCES AND CASH REQUIREMENTS
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 payments (see Note 6)
APS $ 384 $ 247 $ -- $ 205
Pinnacle West 213 -- 276 216
SunCor 24 -- 42 86
------ ------ ------ ------
Total long-term debt payments 621 247 318 507
Operating leases payments (see Note 8) 67 68 66 65
Fuel and purchase power commitments
(see Note 10) 374 270 124 80
------ ------ ------ ------
Total cash commitments $1,062 $ 585 $ 508 $ 652
====== ====== ====== ======
Pinnacle West had available lines of credit in the amount of $250 million
at December 31, 2001. APS had lines of credit available in the amount of $250
million at December 31, 2001. There was no outstanding balance on either the
Pinnacle West or APS lines of credit at December 31, 2001. Pinnacle West and APS
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 Pinnacle West's and APS' lines of credit.
SunCor had an available line of credit at December 31, 2001 in the amount
of $140 million. This line of credit had an outstanding balance at December 31,
2001 of $128 million. SunCor projects that this line of credit will be available
over the next three years. SunCor also anticipates renewing the line of credit
at its expiration date. See Note 5 for further details on SunCor's line of
credit.
The parent company has issued parental guarantees and obtained surety bonds
on behalf of its unregulated subsidiaries, primarily for Pinnacle West Energy's
expansion plans, which are reflected in the capital expenditure table above, and
APSES' retail and energy business.
APS has obtained approximately $500 million in letters of credit primarily
to provide credit support for its variable rate tax-exempt bonds and its Palo
Verde sale-leaseback transactions. Pinnacle West has obtained approximately $40
million in letters of credit to provide credit support for Pinnacle West
Energy's generation expansion plans.
Pinnacle West and APS do not have ratings triggers in any of their debt
agreements. Rating triggers are provisions that would result in the acceleration
of repayment obligations based upon a credit rating agency downgrade. Although
those ratings triggers appear in certain power marketing and trading agreements,
their financial impacts are not expected to be significant.
21
APS' 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.
See the Company's consolidated debt structure in Note 6. The parent company
and our subsidiaries' capital needs and resources are described as follows.
PINNACLE WEST (PARENT COMPANY)
During the past three years, our primary cash needs were for:
* dividends to our shareholders;
* equity infusions into our subsidiaries;
* interest payments; and
* optional and mandatory repayment of principal on our long-term debt.
The equity infusions into our subsidiaries during the past three years
included $50 million invested in APS in 1999. This investment completed the
funding of Pinnacle West's commitment under the 1996 regulatory agreement (see
Note 3) to infuse $50 million a year into APS ($200 million total) from 1996
through 1999. The investments into Pinnacle West Energy were $484 million in
2001 and $193 million in 2000 to fund portions of its capital expenditures for
its generation expansion program.
Over the next three years, we anticipate that our cash needs will fall into
these same categories. We expect our equity infusions into Pinnacle West Energy
to continue as it invests in additional generating facilities (see Note 10)
until it begins to finance its own construction needs.
Our primary sources of cash are dividends from APS, our marketing and
trading operations, and external financing. For the years 1999 through 2001,
total dividends from APS were $510 million.
Our long-term debt at December 31, 2001 was $576 million compared with $238
million at December 31, 2000. We had $235 million of borrowings outstanding on
our commercial paper at December 31, 2001. Our debt repayment requirements for
the parent company for the next three years are approximately: zero in 2002,
$276 million in 2003, and $216 million in 2004.
On February 8, 2002, we issued $215 million of our 4.5% Notes due 2004.
APS
APS' capital requirements consist primarily of capital expenditures and
optional and mandatory redemptions of long-term debt. APS pays for its capital
requirements with cash from operations and, to the extent necessary, external
financing. APS pays for its dividends to Pinnacle West with cash from
operations.
22
During the period from 1999 through 2001, APS paid for substantially all of
its capital expenditures with cash from operations. APS expects to do so in 2002
through 2004 with cash from operations and its own 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.
During 2001, APS redeemed approximately $384 million of long-term debt,
including premiums, with cash from operations and from the issuance of long- and
short-term debt. APS' long-term debt redemption requirements for the next three
years are approximately: $247 million in 2002; zero in 2003; and $205 million in
2004. Based on market conditions and call provisions, APS may make optional
redemptions of long-term debt from time to time.
As of December 31, 2001, APS 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, APS
had about $171 million of commercial paper outstanding and no bank borrowings.
APS' 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 APS may issue, APS does not expect these orders to limit its ability to
meet its capital requirements.
On March 1, 2002, APS issued $375 million of 6.50% Notes due 2012. On March
15, 2002, APS announced the redemption on April 15, 2002 of approximately $125
million of its First Mortgage Bonds, 8.75% Series due 2024.
PINNACLE WEST ENERGY
See Note 10 for a discussion of Pinnacle West Energy's generation expansion
plans. Pinnacle West Energy is currently funding its capital requirements
through capital infusions from the parent. We finance those infusions through
debt financing and internally generated cash, as Pinnacle West Energy develops
and obtains additional generation assets. Pinnacle West Energy also expects to
fund its capital requirements through internally generated cash and its own debt
issuances. See the Capital Expenditures Table above for actual capital
expenditures in 2001 and projected capital expenditures for the next three
years.
OTHER SUBSIDIARIES
During the past three years, both SunCor and El Dorado funded all of their
cash requirements with cash from operations and, in the case of SunCor, its own
external financings. APSES funded its cash requirements with cash infusions from
Pinnacle West.
23
SunCor's capital needs consist primarily of capital expenditures for land
development and retail and office building construction. See the Capital
Expenditures Table above for actual capital expenditures in 2001 and projected
capital expenditures for the next three years. SunCor expects to fund its
capital requirements with cash from operations and external financings.
As of December 31, 2001, SunCor had a $140 million line of credit, under
which $128 million of borrowings were outstanding. SunCor's debt repayment
obligations for the next three years are approximately: zero in 2002; $42
million in 2003; and $86 million in 2004.
El Dorado does not have any capital requirements over the next three years.
El Dorado intends to focus on prudently realizing the value of its existing
investments. El Dorado's future investments are expected to be related to the
energy sector.
APSES capital expenditures and other cash requirements are increasingly
funded by operations, with some funding from cash infused by Pinnacle West. See
the Capital Expenditures Table above regarding APSES' capital expenditures.
See Notes 5 and 6 for additional information about outstanding lines of
credit and long-term debt obligations.
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.
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
24
realized, the gross amount was recorded as revenue and purchased power and fuel
costs in the consolidated 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
---------- ---------- ----------
Revenues before reclassification $1,820,376 $ 993,058 $ 378,076
Less: Purchased power and fuel costs netted with
revenues 1,169,146 574,526 223,951
---------- ---------- ----------
Revenues after reclassification $ 651,230 $ 418,532 $ 154,125
========== ========== ==========
Purchased power and fuel before reclassification $1,503,355 $ 867,195 $ 360,472
Less: Purchased power and fuel costs netted with
revenues 1,169,146 574,526 223,951
---------- ---------- ----------
Purchased power and fuel after reclassification $ 334,209 $ 292,669 $ 136,521
========== ========== ==========
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 consolidated financial statements.
We prepare our financial statements in accordance with Statement of
Financial Accounting Standards (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 consolidated
income statement. See Note 1 for additional information on regulatory accounting
and Note 3 for additional information on the 1999 Settlement Agreement.
25
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 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 consolidated 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 17 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 our
consolidated balance sheets. The impacts of this new standard are not material
to our consolidated financial statements.
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.
26
In 1986, APS 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 Palo Verde 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
consolidated balance sheets. The SPE debt that is not reflected on our
consolidated 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
We currently believe that it will be a challenge for us in 2002 to repeat
our 2001 earnings. For 2001, our reported income from continuing operations was
$327 million, or $3.85 per diluted share of common stock, and included charges
totaling $21 million before income taxes, or $0.15 per diluted share, 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 a significant
decrease in the earnings contribution from our marketing and trading activities
and retail electricity price decreases. These negative factors are expected to
be substantially 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.
In 2001, our marketing and trading activities contributed about one-half of
our income from continuing operations before the Enron-related charges. These
activities are currently expected to provide about one-fourth of our earnings in
2002. The drivers of such reduced earnings contributions from our marketing and
trading activities in 2002 are significant reductions in wholesale market prices
for electricity that occurred during 2001; wholesale market liquidity, which
affects our ability to buy and resell electricity; and market volatility, which
affects our ability to capture profitable structured trading activities. These
reductions in regional market factors were due, in large part, to conservation
measures in California and throughout the West; more generating plants in
service in the West; lower natural gas prices; and the price mitigation plan
that took effect in June 2001 as mandated by the FERC.
During 2001, in order to meet the highest customer demand in APS' 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.
27
The retail price decreases are described above in "Results of Operations -
Regulatory Agreements."
As of December 31, 2001, the indicated annual dividend rate on our common
stock was $1.60 per share. Since 1994, we have increased the dividend on our
common stock ten cents per share per year. We currently plan to continue annual
dividend increases of relatively consistent amounts, which would continue
dividend growth at a pace above the industry average.
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. Our marketing and trading division sells in the wholesale market APS
and Pinnacle West Energy generation production output that is not needed for
APS' 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.
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, APS is 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 APS 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 APS' 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 APS' current retail rates. In the
event of shortfalls due to unforeseen increases in load demand or generation
28
outages, APS may need to purchase additional supplemental power in the wholesale
spot market. Unless APS is able to obtain an adjustment of its rates under the
1999 Settlement Agreement, there can be no assurance that APS would be able to
fully recover the costs of this power.
On September 23, 1999, the ACC approved a comprehensive 1999 Settlement
Agreement among APS 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, APS is
required to transfer all of its 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, APS has been addressing the
legal and regulatory requirements necessary to complete the transfer of its
generation assets to Pinnacle West Energy on or before that date. In
anticipation of APS' transfer of generation assets, Pinnacle West Energy has
completed, and is in the process of developing and planning, various generation
expansion projects so that APS can reliably meet the energy requirements of its
Arizona customers.
Following APS' transfer of its fossil-fueled generation assets and the
receipt of certain regulatory approvals, Pinnacle West Energy expects to sell
its power at wholesale to our marketing and trading division, which, in turn, is
expected to sell power to APS and to non-affiliated power purchasers. In a
filing with the ACC on October 18, 2001, APS requested the ACC to:
* grant APS a partial variance from an ACC Rule that would obligate APS
to acquire all of its customers' standard-offer 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
between APS and Pinnacle West.
APS requested these ACC actions to ensure ongoing reliable service to APS
standard-offer, full-service customers in a volatile generation market and to
recognize Pinnacle West Energy's significant investment to serve APS load. See
"Proposed Rule Variance and Purchase Power Agreement" in Note 3 for additional
information about APS' October 2001 ACC filing.
On February 8, 2002, the ACC's Chief ALJ issued a procedural order which
consolidated the ACC docket relating to APS' 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 APS matter will commence on
April 29, 2002. The order went on to state that, contrary to APS' position, the
ALJ was construing the October 2001 filing as a request by APS to amend the 1999
ACC order that approved the 1999 Settlement Agreement.
29
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 APS and
Pinnacle West.
A modification to the Rules or the 1999 Settlement Agreement as a result of
the consolidated docket could, among other things, adversely affect APS' ability
to transfer its 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 APS' 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.
GENERATION EXPANSION
See Note 10 for information regarding our generation expansion plans. The
planned additional generation is expected to increase revenues, fuel expenses,
operating expenses, and financing costs.
CALIFORNIA ENERGY MARKET ISSUES
See Note 10 for information regarding California energy market issues.
30
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 APS' regulated retail market area, APS 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 APS' 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 APS' 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).
Competitive sales of energy and energy-related products and services are
made by APSES in western states that have opened to competitive supply. Such
activities currently are not material to our consolidated financial results.
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.
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, changes in regulatory
asset amortization, and our generation expansion program. 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 APS, which currently owns the
majority of our property, was 9.32% for 2001 and 9.16% for 2000. We expect
property taxes to increase primarily due to our generation expansion program and
our additions to existing facilities.
31
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 generation expansion program and
our internally-generated cash flow.
The annual earnings contribution from APSES is expected to be modest, yet
positive, over the next several years due primarily to a number of retail
electricity contracts in California. APSES' pretax losses were $10 million in
2001 and $13 million in 2000.
The annual earnings contribution from SunCor is expected to remain modest
over the next several years. SunCor's earnings were $3 million in 2001, $11
million in 2000 and $6 million in 1999.
El Dorado's historical results are not necessarily indicative of future
performance for El Dorado. El Dorado's strategies focus on prudently realizing
the value of its existing investments. Any future investments are expected to be
related to the energy sector. See Note 1 for additional information regarding El
Dorado.
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 17 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.
32
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
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 4.01% $ 405,762 7.76% $ 207 8.10% $ 125,933
2003 -- 4.75% 292,912 6.87% 25,829
2004 -- 5.32% 85,601 6.08% 205,677
2005 -- 7.70% 294 7.59% 400,380
2006 -- 7.30% 3,018 6.48% 384,085
Years thereafter -- 2.63% 480,740 6.73% 799,808
----------- ----------- -----------
Total $ 405,762 $ 862,772 $ 1,941,712
=========== =========== ===========
Fair value $ 405,762 $ 862,772 $ 1,963,389
=========== =========== ===========
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% $ 82,775 7.23% $ 438,203 6.63% $ 25,266
2002 -- 8.62% 36,890 8.13% 125,000
2003 -- 8.61% 73,578 6.89% 25,443
2004 -- 8.87% 268 6.17% 205,000
2005 -- 8.89% 294 7.28% 400,000
Years thereafter -- 4.13% 483,790 7.47% 610,813
----------- ----------- -----------
Total $ 82,775 $ 1,033,023 $ 1,391,522
=========== =========== ===========
Fair value $ 82,775 $ 1,033,023 $ 1,422,014
=========== =========== ===========
33
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
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 Board
of Directors and monitored by the Energy Risk Management Committee, 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 19). 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
realized during the year (1) (2)
Change in mark-to-market gains for
future period deliveries 127 14
------ ------
Mark-to-market of net trading positions
at end of year $ 138 $ 12
====== ======
Net gains at inception include a reasonable marketing margin and were
approximately $3 million in 2001 and $2 million in 2000. See Note 17 for
disclosure of risk management activities recorded on the consolidated balance
sheets.
The table below shows the maturities of our trading positions as of
December 31, 2001 in millions of dollars by the type of valuation that is
performed to calculate the fair value of the contract. In addition, see Note 1
for more discussion on our valuation methods.
34
Years Total fair
Source of Fair Value 2002 2003-2004 2005-2006 thereafter value
-------------------- ------ --------- --------- ---------- ------
Prices actively quoted $ (13) $ 4 $ 2 $ -- $ (7)
Prices provided by other external
sources (12) (8) (4) -- (24)
Prices based on models and other
valuation methods 68 50 39 12 169
------ ------ ------ ------ ------
Total by maturity $ 43 $ 46 $ 37 $ 12 $ 138
====== ====== ====== ====== ======
The table below shows the impact that hypothetical price movements of 10%
would have on the market value of our risk management and trading assets and
liabilities included on the consolidated balance sheets at December 31, 2001 and
2000 (dollars in millions):
December 31, 2001 December 31, 2000
Gain (Loss) Gain (Loss)
----------------------------- -----------------------------
Commodity Price Up 10% Price Down 10% Price Up 10% Price Down 10%
--------- ------------ -------------- ------------ --------------
Trading (a):
Electric $ (3) $ 3 $ 2 $ (2)
Natural gas (1) 1 (1) 1
Other -- 2 -- --
System (b):
Natural gas
hedges 23 (23) 28 (28)
------ ------ ------ ------
Total $ 19 $ (17) $ 29 $ (29)
====== ====== ====== ======
(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) 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 have risk management and trading contracts with many
counterparties, including one counterparty for which a worst case exposure
represents approximately 50% of our $267 million of risk management and trading
assets as of December 31, 2001. 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 trading counterparties are rated as investment
grade by the credit rating agencies, including the counterparty noted above,
there is still a possibility that one or more of these companies could default,
resulting in a material impact on consolidated earnings for a given period.
Counterparties in the portfolio consist principally of major energy companies,
municipalities, 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
35
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 APS' 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; the successful completion of our generation
expansion program; regulatory issues associated with generation expansion, such
as permitting and licensing; our ability to compete successfully outside
traditional regulated markets (including the wholesale market); technological
developments in the electric industry; and the strength of the real estate
market in SunCor's market areas, which include Arizona, New Mexico and Utah.
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.
36
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULE
Report of Management....................................................... 38
Independent Auditors' Report............................................... 39
Consolidated Statements of Income for 2001, 2000 and 1999.................. 40
Consolidated Balance Sheets as of December 31, 2001 and 2000............... 41
Consolidated Statements of Cash Flows for 2001, 2000 and 1999.............. 43
Consolidated Statements of Changes in Common Stock Equity
for 2001, 2000 and 1999.................................................. 44
Notes to Consolidated Financial Statements................................. 45
Financial Statement Schedule for 2001, 2000 and 1999
Schedule II - Valuation and Qualifying Accounts for 2001, 2000
and 1999................................................................. 89
See Note 12 of Notes to Consolidated Financial Statements for the selected
quarterly financial data required to be presented in this Item.
37
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
38
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Pinnacle West Capital Corporation
Phoenix, Arizona
We have audited the accompanying consolidated balance sheets of Pinnacle
West Capital Corporation and subsidiaries as of December 31, 2001 and 2000 and
the related consolidated statements of income, changes in common stock equity,
and cash flows for each of the three years in the period ended December 31,
2001. Our audits also included the financial statement schedule listed in the
accompanying Index. These financial statements and financial statement schedule
are the responsibility of the Corporation'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 consolidated financial statements present fairly, in
all material respects, the financial position of Pinnacle West Capital
Corporation and subsidiaries at December 31, 2001 and 2000 and the results of
their operations and their 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 consolidated
financial statements taken as a whole, presents fairly in all material respects
the information set forth therein.
As discussed in Note 17 to the financial statements, in 2001 Pinnacle West
Capital Corporation 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 18 and November 21, 2002 as to
Note 19)
39
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(dollars in thousands, except per share amounts)
Year Ended December 31,
--------------------------------------------
2001 2000 1999
------------ ------------ ------------
OPERATING REVENUES
Electric retail segment $ 2,562,089 $ 2,538,752 $ 1,915,108
Marketing and trading segment 651,230 418,532 154,125
Real estate 168,908 158,365 130,169
Other revenues 11,771 3,873 439
------------ ------------ ------------
Total 3,393,998 3,119,522 2,199,841
------------ ------------ ------------
OPERATING EXPENSES
Electric retail segment purchased
power and fuel 1,160,863 1,065,597 433,459
Marketing and trading segment
purchased power and fuel 334,209 292,669 136,521
Operations and maintenance 530,095 450,205 446,173
Real estate operations 153,462 134,422 119,516
Depreciation and amortization 427,903 431,229 419,842
Taxes other than income taxes 101,068 99,780 96,606
Other expenses 10,375 782 200
------------ ------------ ------------
Total 2,717,975 2,474,684 1,652,317
------------ ------------ ------------
OPERATING INCOME 676,023 644,838 547,524
------------ ------------ ------------
OTHER
Preferred stock dividends of APS -- -- (1,016)
Other income 26,416 21,832 38,303
Other expense (33,577) (25,329) (27,969)
------------ ------------ ------------
Total (7,161) (3,497) 9,318
------------ ------------ ------------
INTEREST EXPENSE
Interest charges 175,822 166,447 157,142
Capitalized interest (47,862) (21,638) (11,664)
------------ ------------ ------------
Total 127,960 144,809 145,478
------------ ------------ ------------
INCOME FROM CONTINUING
OPERATIONS BEFORE INCOME
TAXES 540,902 496,532 411,364
INCOME TAXES 213,535 194,200 141,592
------------ ------------ ------------
INCOME FROM CONTINUING
OPERATIONS 327,367 302,332 269,772
Income tax benefit from
discontinued operations -- -- 38,000
Extraordinary charge - net of income
taxes of $94,115
-- -- (139,885)
Cumulative effect of a change in
accounting for derivatives -
net of income taxes of $9,892 (15,201) -- --
------------ ------------ ------------
NET INCOME $ 312,166 $ 302,332 $ 167,887
============ ============ ============
WEIGHTED-AVERAGE COMMON
SHARES OUTSTANDING - BASIC 84,718 84,733 84,717
WEIGHTED-AVERAGE COMMON
SHARES OUTSTANDING - DILUTED 84,930 84,935 85,009
EARNINGS PER WEIGHTED -
AVERAGE COMMON SHARE
OUTSTANDING
Income from continuing operations -
basic $ 3.86 $ 3.57 $ 3.18
Net income - basic 3.68 3.57 1.98
Income from continuing operations -
diluted 3.85 3.56 3.17
Net income - diluted 3.68 3.56 1.97
DIVIDENDS DECLARED PER SHARE $ 1.525 $ 1.425 $ 1.325
============ ============ ============
See Notes to Consolidated Financial Statements.
40
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
December 31,
---------------------------
2001 2000
------------ ------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 28,619 $ 10,363
Customer and other receivables - net 367,241 513,822
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 17) 66,973 17,506
Other current assets 80,203 80,492
------------ ------------
Total current assets 727,405 793,913
------------ ------------
INVESTMENTS AND OTHER ASSETS
Real estate investments - net (Note 1 and 6) 418,673 371,323
Assets from risk management and trading
activities-long term (Note 17) 200,351 32,955
Other assets 321,024 299,128
------------ ------------
Total investments and other assets 940,048 703,406
------------ ------------
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6, 8
and 9)
Plant in service and held for future use 8,203,888 7,809,566
Less accumulated depreciation and amortization 3,378,089 3,188,302
------------ ------------
Total 4,825,799 4,621,264
Construction work in progress 1,032,234 464,540
Nuclear fuel, net of accumulated amortization
of $56,836 and $61,256 49,282 47,389
------------ ------------
Net property, plant and equipment 5,907,315 5,133,193
------------ ------------
DEFERRED DEBITS
Regulatory assets (Notes 1, 3 and 4) 342,383 469,867
Other deferred debits 64,597 62,606
------------ ------------
Total deferred debits 406,980 532,473
------------ ------------
TOTAL ASSETS $ 7,981,748 $ 7,162,985
============ ============
See Notes to Consolidated Financial Statements.
41
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
December 31,
----------------------------
2001 2000
------------ ------------
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable $ 269,124 $ 375,805
Accrued taxes 96,729 89,246
Accrued interest 48,806 42,954
Short-term borrowings (Note 5) 405,762 82,775
Current maturities of long-term debt (Note 6) 126,140 463,469
Customer deposits 30,232 26,189
Deferred income taxes (Note 4) 3,244 --
Liabilities from risk management and trading
activities (Note 17) 35,994 37,179
Other current liabilities 74,898 73,681
------------ ------------
Total current liabilities 1,090,929 1,191,298
------------ ------------
LONG-TERM DEBT LESS CURRENT
MATURITIES (Note 6) 2,673,078 1,955,083
------------ ------------
DEFERRED CREDITS AND OTHER
Liabilities from risk management and trading
activities-long term (Note 17) 207,576 14,711
Deferred income taxes (Note 4) 1,064,993 1,143,040
Unamortized gain - sale of utility plant (Note 8) 64,060 68,636
Other 381,789 407,503
------------ ------------
Total deferred credits and other 1,718,418 1,633,890
------------ ------------
COMMITMENTS AND CONTINGENCIES (NOTES
3, 10 AND 11)
COMMON STOCK EQUITY
Common stock, no par value; authorized
150,000,000 shares; issued and outstanding
84,824,947 at end of 2001 and 2000 1,531,038 1,532,831
Retained earnings 1,032,850 849,883
Accumulated other comprehensive loss (64,565) --
------------ ------------
Total common stock equity 2,499,323 2,382,714
------------ ------------
TOTAL LIABILITIES AND EQUITY $ 7,981,748 $ 7,162,985
============ ============
See Notes to Consolidated Financial Statements.
42
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
Year Ended December 31,
--------------------------------------------
2001 2000 1999
------------ ------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES
Income from continuing operations $ 327,367 $ 302,332 $ 269,772
Items not requiring cash
Depreciation and amortization 427,903 431,229 419,842
Nuclear fuel amortization 28,362 30,083 31,371
Deferred income taxes - net (16,939) (38,625) (43,886)
Deferred investment tax credit (264) 740 (23,514)
Mark-to-market gains - trading (125,521) (11,752) (975)
Mark-to-market gains - system (8,052) -- --
Changes in current assets and liabilities
Customer and other receivables - net 146,581 (269,223) (10,723)
Accrued utility revenues (1,565) (1,647) (5,179)
Materials, supplies and fossil fuel (16,867) 475 (8,794)
Other current assets 289 (37,436) (12,968)
Accounts payable (127,782) 193,502 28,193
Accrued taxes 7,483 18,736 12,591
Accrued interest 5,852 9,701 1,387
Other current liabilities 5,260 98,493 14,047
Change in El Dorado partnership investment 1,671 (3,773) (25,786)
Increase in real estate investments (44,173) (25,937) (12,542)
Increase in regulatory assets (17,516) (14,138) (12,262)
Other - net (21,159) 30,634 15,026
------------ ------------ ------------
Net cash flow provided by operating
activities 570,930 713,394 635,600
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (1,040,585) (658,608) (343,448)
Capitalized interest (47,862) (21,638) (11,664)
Other - net (31,357) (55,595) (16,143)
------------ ------------ ------------
Net cash flow used for investing activities (1,119,804) (735,841) (371,255)
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 995,447 651,000 607,791
Short-term borrowings - net 322,987 44,475 (140,530)
Dividends paid on common stock (129,199) (120,733) (112,311)
Repayment of long-term debt (621,057) (558,019) (510,693)
Redemption of preferred stock -- -- (96,499)
Other - net (1,048) (4,618) (11,936)
------------ ------------ ------------
Net cash flow provided by (used for) financing
activities 567,130 12,105 (264,178)
------------ ------------ ------------
NET CASH FLOW 18,256 (10,342) 167
CASH AND CASH EQUIVALENTS AT
BEGINNING OF YEAR 10,363 20,705 20,538
------------ ------------ ------------
CASH AND CASH EQUIVALENTS AT
END OF YEAR $ 28,619 $ 10,363 $ 20,705
============ ============ ============
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes $ 223,037 $ 219,411 $ 199,799
Interest paid, net of amounts capitalized $ 115,276 $ 132,434 $ 141,138
See Notes to Consolidated Financial Statements.
43
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
For the Years Ended December 31, 2001, 2000 and 1999
(dollars in thousands)
ACCUMULATED
OTHER
RETAINED COMPREHENSIVE
COMMON STOCK EARNINGS INCOME (LOSS) TOTAL
------------ ------------ ------------ ------------
Balance at December 31, 1998 $ 1,550,643 $ 612,708 $ -- $ 2,163,351
Net income 167,887 167,887
Dividends on common stock (112,311) (112,311)
Common stock expense (13,194) (13,194)
------------ ------------ ------------ ------------
Balance at December 31, 1999 1,537,449 668,284 -- 2,205,733
Net income 302,332 302,332
Dividends on common stock (120,733) (120,733)
Common stock expense (4,618) (4,618)
------------ ------------ ------------ ------------
Balance at December 31, 2000 1,532,831 849,883 -- 2,382,714
------------ ------------ ------------ ------------
Net income 312,166 312,166
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) 312,166 (64,565) 247,601
------------ ------------ ------------
Dividends on common stock (129,199) (129,199)
Common stock expense (1,793) (1,793)
------------ ------------ ------------ ------------
Balance at December 31, 2001 $ 1,531,038 $ 1,032,850 $ (64,565) $ 2,499,323
============ ============ ============ ============
See Notes to Consolidated Financial Statements.
44
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION AND NATURE OF OPERATIONS
The consolidated financial statements include the accounts of Pinnacle West
and our subsidiaries: APS, Pinnacle West Energy, APSES, SunCor, and El Dorado.
Significant intercompany accounts and transactions between the consolidated
companies have been eliminated.
APS, our major subsidiary and Arizona's largest electric utility, provides
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. APS also generates and, directly or through our
marketing and trading division, sells and delivers electricity to wholesale
customers in the western United States. During 2001, APS transferred most of its
marketing and trading activities to the parent company. Pinnacle West Energy,
which was formed in 1999, is the subsidiary through which we conduct our
unregulated generation operations. APSES was formed in 1998 and provides
commodity energy and energy-related products to key customers in competitive
markets in the western United States. SunCor is a developer of residential,
commercial, and industrial real estate projects in Arizona, New Mexico, and
Utah. El Dorado is an investment firm.
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 Board
of Directors and monitored by the 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
Notes 17 and 19 for further information about our trading contracts.
45
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 17 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
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 or liability or in stockholders' 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 17 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 consolidated balance sheets.
We determine fair market value using actively-quoted prices when available.
We consider quotes for exchange-traded contracts and over-the-counter quotes
obtained from independent brokers to be actively-quoted.
When actively-quoted prices are not available, we use prices provided by
other external sources. This includes quarterly and calendar year quotes from
independent brokers. 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.
46
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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,
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 ERMC.
REGULATORY ACCOUNTING
APS is regulated by the ACC and the FERC. The accompanying financial
statements reflect the rate-making policies of these commissions. For regulated
operations, we prepare our financial statements in accordance with SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." SFAS No. 71
requires a cost-based, rate-regulated enterprise to reflect the impact of
regulatory decisions in its financial statements.
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.
47
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
Regulatory assets are reported as deferred debits on the consolidated 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 and other on the
consolidated balance sheets. As of December 31, 2001 and 2000, they 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
====== ======
48
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The consolidated balance sheets include the amounts listed below for
generation assets not subject to SFAS No. 71 (dollars in millions):
December 31,
--------------------
2001 2000
------- -------
Electric plant in service and held for future use ...... $ 3,954 $ 3,854
Accumulated depreciation and amortization .............. (1,990) (1,902)
Construction work in progress .......................... 824 304
Nuclear fuel, net of amortization ...................... 49 47
UTILITY PLANT AND DEPRECIATION
Utility plant is the term we use to describe the business property and
equipment that supports electric service, consisting primarily of generation,
transmission, and distribution facilities. We report utility plant at its
original cost, which includes:
* material and labor;
* contractor costs;
* 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.
EL DORADO INVESTMENTS
El Dorado accounts for its investments using the equity method. Net other
income has consisted primarily of El Dorado's share of the earnings of a venture
capital partnership. We record our share of the earnings from the partnership as
the partnership adjusts the value of its investments. In 2001, El Dorado
received a distribution of securities representing substantially all of El
Dorado's investment in the partnership. The securities were sold in the first
quarter of 2001 and a gain was recognized in other income. The book value of El
Dorado's investment in the partnership was approximately $1 million at December
31, 2001, and $7 million at December 31, 2000. El Dorado's net investment book
value was approximately $10 million at December 31, 2001 and $21 million at
December 31, 2000.
49
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 6.13% for 2001, 6.62% for 2000, and 6.65% for 1999.
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 reported on a gross basis in
our income statements. See Note 19 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 consolidated statements of income.
NUCLEAR FUEL
APS charges 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. APS divides the cost of the fuel by the estimated number
of thermal units that it expects to produce with that fuel. APS then multiplies
that rate by the number of thermal units that it produces within the current
period. This calculation determines the current period nuclear fuel expense.
APS also charges 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 APS $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.
50
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
INCOME TAXES
Income taxes are provided using the asset and liability approach prescribed
by SFAS No. 109. We file our federal income tax return on a consolidated basis
and we file our state income tax returns on a consolidated or unitary basis. In
accordance with our intercompany tax sharing agreement, federal and state income
taxes are allocated to each subsidiary as though each subsidiary filed a
separate income tax return. Any difference between the aforementioned
allocations and the consolidated (and unitary) income tax liability is
attributed to the parent company.
REACQUIRED DEBT COSTS
For debt related to the regulated portion of APS' business, APS amortizes
those gains and losses incurred upon early retirement over the remaining life of
the debt. In accordance with the 1999 Settlement Agreement, APS is continuing to
accelerate reacquired debt costs over an eight-year period that will end June
30, 2004. All regulatory asset amortization is included in depreciation and
amortization expense in the consolidated statements of income.
REAL ESTATE INVESTMENTS
Real estate investments primarily include SunCor's land, home inventory and
investments in joint ventures. Land includes acquisition costs, infrastructure
costs, property taxes and capitalized interest directly associated with the
acquisition and development of each project. Land under development and land
held for future development are stated at accumulated cost, except to the extent
that such land is believed to be impaired, it is written down to fair value.
Land held for sale is stated at the lower of accumulated cost or estimated fair
value less costs to sell. Home inventory consists of construction costs,
improved lot costs, capitalized interest and property taxes on homes under
construction. Home inventory is stated at the lower of accumulated cost or
estimated fair value less costs to sell. Investments in joint ventures for which
SunCor does not have a controlling financial interest are not consolidated but
are accounted for using the equity method of accounting.
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 consolidated 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.
51
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, which 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, APS 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 Palo Verde 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
consolidated balance sheets. The SPE debt that is not reflected on our
consolidated 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, APS 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 its obligations under the
1999 Settlement Agreement, on January 7, 2002, APS and the ACC filed in Maricopa
County, Arizona Superior Court a stipulation to dismiss all of APS' litigation
52
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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:
* APS has 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
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 APS 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 APS 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
APS' cost of service for ACC-regulated services resulting from
federal, tribal, state or local laws, regulatory requirements,
judicial decisions, actions or orders.
* APS 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.
* APS' 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. APS opened its distribution system to retail access for all
customers on January 1, 2001.
53
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
* Prior to the 1999 Settlement Agreement, APS was recovering
substantially all of its regulatory assets through July 1, 2004,
pursuant to the 1996 regulatory agreement. In addition, the 1999
Settlement Agreement states that APS has demonstrated that its
allowable stranded costs, after mitigation and exclusive of regulatory
assets, are at least $533 million net present value. APS will not be
allowed to recover $183 million net present value of the above
amounts. The 1999 Settlement Agreement provides that APS will have the
opportunity to recover $350 million net present value through a
competitive transition charge that will remain in effect through
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.
* APS will form, or cause to be formed, a separate corporate affiliate
or affiliates and transfer to such affiliate(s) its 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, APS plans to complete the move of such assets and
services from APS 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 APS' request for
approval of a PPA between Pinnacle West and APS could affect APS'
ability to transfer assets to Pinnacle West Energy. APS will be
allowed to defer and later collect, beginning July 1, 2004,
sixty-seven percent of its 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, APS intends to move substantially all of its
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 APS and to non-affiliated power
purchasers. In a filing with the ACC on October 18, 2001, APS requested the ACC
to:
* grant APS a partial variance from an ACC rule that would obligate APS
to acquire all of its 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 APS and Pinnacle West.
APS has requested these ACC actions to ensure ongoing reliable service to APS
standard-offer, full-service customers in a volatile generation market and to
recognize Pinnacle West Energy's significant investment to serve APS load. The
following are the major provisions of the PPA:
54
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
* The PPA would run through 2015, with three optional five-year renewal
terms, which renewals would occur automatically unless notice is given
by either APS or Pinnacle West.
* The PPA would provide for all of APS' anticipated standard-offer
generation needs, including any necessary reserves, except for (a)
those provided by APS itself through renewable resources or other
generation assets retained by APS; (b) amounts that APS is obligated
by law to purchase from "qualified facilities" and other forms of
distributed generation; and (c) any purchased power agreements that
APS 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 APS standard-offer requirements through a
combination of (a) APS 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 APS 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 APS
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 APS 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 APS 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.
APS is required to transfer its competitive electric assets and services to
one or more corporate affiliates on or before December 31, 2002. Consistent with
that requirement, APS has been addressing the legal and regulatory requirements
necessary to complete the transfer of its generation assets to Pinnacle West
Energy, on or before that date. In anticipation of APS' transfer of generation
assets, Pinnacle West Energy has completed, and is the process of developing and
planning, various generation expansion projects so that APS can reliably meet
the energy requirements of its Arizona customers.
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 APS and [Tucson Electric Company], establish the framework for the
55
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 APS' 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 the
APS matter will commence on April 29, 2002. The order went on to state that,
contrary to APS' position, the ALJ was construing the October 2001 filing as a
request by APS 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
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
56
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
* 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 APS and
Pinnacle West.
A modification to the competition Rules or the 1999 Settlement Agreement
could, among other things, adversely affect APS' ability to transfer its
generation assets to Pinnacle West Energy by December 31, 2002. Pinnacle West
cannot predict the outcome of the consolidated docket or its effect on the
specific requests in APS' 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, APS 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, APS filed a lawsuit to protect its 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,
including APSES, 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 APS' 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 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 APS.
* Effective January 1, 2001, retail access became available to all APS
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.
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
* 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, APS
received a waiver to allow transfer of its competitive electric assets
and services to affiliates no later than December 31, 2002. APS plans
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 APS' request for approval of a PPA
between Pinnacle West and APS could affect APS' 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), APS is 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 APS 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 APS' 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 APS' current retail rates. In the
event of shortfalls due to unforeseen increases in load demand or generation
outages, APS may need to purchase additional supplemental power in the wholesale
spot market. Unless APS is able to obtain an adjustment of its rates under the
emergency provisions of the 1999 Settlement Agreement, there can be no assurance
that APS 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 APS. Based on the price reduction formula
authorized in the agreement, the ACC approved retail price decreases
(approximate) as follows (dollars in millions):
58
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 we infuse $200 million of
common equity into APS 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
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.
59
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. INCOME TAXES
INCOME TAXES
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.
APS has recorded a regulatory asset related to income taxes on its 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. APS amortizes this amount as the differences reverse. In
accordance with the 1999 Settlement Agreement, APS is continuing to accelerate
its 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 all regulatory
asset amortization in depreciation and amortization expense on our consolidated
statements of income. The components of income tax expense for continuing
operations are (dollars in thousands):
Year Ended December 31,
-------------------------------------------
2001 2000 1999
--------- --------- ---------
Current
Federal $ 184,893 $ 189,779 $ 171,491
State 45,845 42,306 37,501
--------- --------- ---------
Total current 230,738 232,085 208,992
Deferred (16,939) (38,625) (43,886)
ITC amortization (264) 740 (23,514)
--------- --------- ---------
Total expense $ 213,535 $ 194,200 $ 141,592
========= ========= =========
The following chart compares pretax income at the 35% federal income tax rate to
income tax expense (dollars in thousands):
60
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Year Ended December 31,
-----------------------------------
2001 2000 1999
--------- --------- ---------
Federal income tax expense at 35%
statutory rate $ 189,316 $ 173,786 $ 143,977
Increases (reductions) in tax expense
resulting from:
Preferred stock dividends of APS -- -- 356
ITC amortization (264) 740 (23,514)
State income tax net of federal income
tax benefit 23,353 19,848 19,595
Other 1,130 (174) 1,178
--------- --------- ---------
Income tax expense $ 213,535 $ 194,200 $ 141,592
========= ========= =========
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 73,043 15,002
Other 110,002 94,306
---------- ----------
Total deferred tax assets 208,419 136,364
---------- ----------
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 85,692 19,892
---------- ----------
Total deferred tax liabilities 1,276,656 1,273,611
---------- ----------
Accumulated deferred income taxes - net $1,068,237 $1,137,247
========== ==========
INVESTMENT TAX CREDIT
Because of a 1994 rate settlement agreement, we accelerated amortization of
substantially all of our ITCs over a five-year period that ended December 31,
1999.
INCOME TAX BENEFIT FROM DISCONTINUED OPERATIONS
In 1999, the income tax benefit from discontinued operations for $38
million resulted from resolution of tax issues related to a former subsidiary,
MeraBank, A Federal Savings Bank.
61
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. LINES OF CREDIT
APS 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. APS
had no bank borrowings outstanding under these lines of credit at December 31,
2001 and 2000.
APS' 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, APS'
short-term borrowings cannot exceed 7% of its total capitalization unless
approved by the ACC.
Pinnacle West 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
commercial paper program was launched in May 2001. The commitment fees ranged
from 0.10% to 0.15% in 2001 and 2000. There were no short-term bank borrowings
outstanding at December 31, 2001 and $188 million outstanding at December 31,
2000. Pinnacle West commercial paper borrowings were $235 million at December
31, 2001. The weighted average interest rate on commercial paper borrowings was
3.50% for the year ended December 31, 2001.
SunCor had revolving lines of credit totaling $140 million at December 31,
2001 and $120 million at December 31, 2000. The commitment fees were 0.125% in
2001 and 2000. SunCor had $128 million outstanding at December 31, 2001 and $110
million outstanding at December 31, 2000. The balance is included in long-term
debt on the consolidated balance sheets (see Note 6).
6. LONG-TERM DEBT
Borrowings under the APS mortgage bond indenture are secured by
substantially all utility plant. APS also has unsecured debt. SunCor's debt is
collateralized by interests in certain real property and Pinnacle West's debt is
unsecured. The following table presents the components of consolidated long-term
debt outstanding at December 31, 2001 and 2000:
62
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands)
December 31,
Maturity Interest -----------------------
Dates (a) Rates 2001 2000
--------- ----- ---------- ----------
APS
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 --
---------- ----------
Subtotal 2,074,525 2,057,174
---------- ----------
SUNCOR
Revolving credit 2003-2004 (f) 128,000 110,000
Notes payable 2001-2008 (g) 7,912 8,163
Bonds payable 2024 5.95% 5,215 5,215
Bonds payable 2026 6.75% 7,500 --
---------- ----------
Subtotal 148,627 123,378
---------- ----------
PINNACLE WEST
Revolving credit 2001 (h) -- 188,000
Senior notes 2003-2006 (i) 325,000 50,000
Floating rate notes 2003 Adjustable
rate (j) 250,000 --
Capitalized lease obligation 2004 7.75% 1,066 --
---------- ----------
Subtotal 576,066 238,000
---------- ----------
Total long-term debt 2,799,218 2,418,552
Less current maturities 126,140 463,469
---------- ----------
TOTAL LONG-TERM DEBT
LESS CURRENT
MATURITIES $2,673,078 $1,955,083
========== ==========
63
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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 plus 0.72%. (e) APS currently has
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 rate, interest
payment dates, maturity, and redemption provisions as the senior notes.
APS' payments of principal, premium, and/or interest on the senior notes
satisfy its 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 APS repays all of its 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.
(f) The weighted-average rate at December 31, 2001 was 5.31% and at December
31, 2000 was 8.61%. Interest for 2001 and 2000 was based on LIBOR plus 2%
or prime plus 0.5%.
(g) Multiple notes primarily with variable interest rates based mostly on the
lenders' prime plus 1.75% and lenders' prime plus .25%.
(h) The weighted-average rate at December 31, 2000 was 7.51%. Interest for 2000
was based on LIBOR plus 0.75%.
(i) Includes two series of notes: $25 million at 6.87% due in 2003 and $300
million at 6.4% due in 2006.
(j) The weighted average rate for the year ended December 31, 2001 was 4.65%.
Interest for 2001 was based on LIBOR plus 0.98%.
The Pinnacle West and APS 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;
* $318 million in 2003;
* $507 million in 2004;
* $401 million in 2005; and
* $387 million in 2006.
APS' 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.
64
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The parent company has issued parental guarantees and obtained surety bonds
on behalf of its unregulated subsidiaries, primarily for Pinnacle West Energy's
expansion plans and APSES' retail and energy business.
7. RETIREMENT PLANS AND OTHER BENEFITS
PENSION PLAN
Through 1999, Pinnacle West and its subsidiaries each sponsored defined
benefit pension plans for their own employees. As of January 1, 2000, these
plans were consolidated and now a single pension plan is sponsored by Pinnacle
West for the employees of Pinnacle West and its subsidiaries. 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, we calculate the
benefits under this plan based on age, years of service, and pay. We fund 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.
Pension expense, including administrative costs and after consideration of
amounts capitalized or billed to electric plant participants, was:
* $7 million in 2001;
* $2 million in 2000; and
* $4 million in 1999.
The following table shows the components of 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 the consolidated balance sheets (dollars in
thousands):
65
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 consolidated
balance sheets $ (10,350) $ (42,769)
========= =========
The following table sets forth the defined benefit pension plan's change in
projected benefit obligation 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 the 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
========= =========
We 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%
66
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
EMPLOYEE SAVINGS PLAN BENEFITS
Through 1999, Pinnacle West and its subsidiaries each sponsored defined
contribution savings plans for their own employees. As of January 1, 2000, these
plans were consolidated and now a single defined contribution savings plan is
sponsored by Pinnacle West for the employees of Pinnacle West and its
subsidiaries. In a defined contribution plan, the benefits a participant will
receive result from regular contributions they make to a participant account.
Under this plan, we make 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 $5 million for 2001 and $4 million for 2000 and 1999.
POSTRETIREMENT PLAN
Through 1999, Pinnacle West and its subsidiaries each sponsored
postretirement plans for their own employees. As of January 1, 2000, these plans
were consolidated and now a single postretirement plan is sponsored by Pinnacle
West for the employees of Pinnacle West and its subsidiaries. We provide medical
and life insurance benefits to retired employees. Employees must retire to
become eligible for these retirement benefits, which are based on years of
service and age. 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 postretirement benefit expense after consideration of amounts
capitalized or billed to electric plant participants, was:
* $6 million for 2001;
* $3 million for 2000; and
* $7 million for 1999.
The following table shows the components of net periodic postretirement
benefit costs before consideration of amounts capitalized or billed to electric
plant participants (dollars in thousands):
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 the consolidated balance sheets (dollars in
thousands):
67
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 the 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
========= =========
The following table sets forth the 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
========= =========
68
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We 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, APS sold about 42% of its share of Palo Verde Unit 2 and certain
common facilities in three separate sale-leaseback transactions. APS accounts
for these leases as operating leases. The gain 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
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, APS is 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
consolidated statements of income. The balance of this regulatory asset at
December 31, 2001 was $24 million.
In December 2000, APS 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.
69
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Total lease expense was $56 million in 2001, $58 million in 2000, and $52
million in 1999.
Estimated future minimum lease commitments, are approximately as follows
(dollars in millions):
Year
2002 $ 68
2003 66
2004 65
2005 64
2006 63
Thereafter 543
-----
Total future commitments $ 869
=====
9. JOINTLY-OWNED FACILITIES
APS shares ownership of some of its generating and transmission facilities
with other companies. The following table shows APS' interest in those
jointly-owned facilities recorded on the consolidated balance sheets at December
31, 2001. APS' 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
APS 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 APS operates the unit for PacifiCorp. The
common facilities at the Cholla Plant are jointly-owned.
(b) Weighted average of interests.
70
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. COMMITMENTS AND CONTINGENCIES
ENRON
We recorded charges totaling $21 million before income taxes for exposure
to Enron and its affiliates in the fourth quarter of 2001. This amount is
comprised of a $15 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 APS that it believes APS has overcharged Citizens by over $50 million
under a power service agreement. APS believes that its 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." APS and Citizens
terminated the power service agreement effective July 15, 2001. In replacement
of the power service agreement, the Company and Citizens entered into a power
sale agreement under which the Company 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.
SUNCOR
On March 15, 2001, a jury returned a verdict against SunCor in the amount
of $28.6 million, $25.7 million of which represented a punitive damage award, in
a lawsuit in Maricopa County, Arizona, Superior Court entitled SunCor
Development Company v. Bergstrom Corporation, CV 98-11472. The verdict was based
on the Bergstrom Corporation's claims that it was defrauded in connection with
the acquisition of approximately ten acres of land in a SunCor commercial
development and a subsequent settlement agreement relating to those claims. On
December 14, 2001, the Court ruled that the jury award was constitutionally
excessive and reduced the punitive damage award to $5 million. Following this
ruling, SunCor settled the matter for an amount that did not have a material
impact on our 2001 results of operations.
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 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.
71
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
APS has existing fuel storage pools at Palo Verde and is 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, APS
believes that spent fuel storage or disposal methods will be available for use
by Palo Verde to allow its 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, APS is currently shipping low-level waste to off-site facilities. APS
currently believes that interim low-level waste storage methods are or will be
available for use by Palo Verde to allow its continued operation and to safely
store low-level waste until a permanent disposal facility is available.
APS currently estimates that it will incur $407 million (in 2001 dollars)
over the life of Palo Verde for its share of the costs related to the on-site
interim storage of spent nuclear fuel. As of December 31, 2001, APS 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, APS 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. APS has also secured
insurance against portions of any increased cost of generation or purchased
power and business interruption resulting from a sudden and unforeseen outage of
any of the three units. The insurance coverage discussed in this and the
previous paragraph is subject to certain policy conditions and exclusions.
72
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FUEL AND PURCHASED POWER COMMITMENTS
APS and Pinnacle West are parties to various fuel and purchased power
contracts with terms expiring from 2002 through 2021 that include required
purchase provisions. We estimate the contract requirements to be approximately
$270 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
required purchases under certain circumstances.
COAL MINE RECLAMATION OBLIGATIONS
APS must reimburse certain coal providers for amounts incurred for coal
mine reclamation. APS estimates its 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 consolidated 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, APS is 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 and our subsidiaries. We have
evaluated, among other things, SCE's role as a Palo Verde and Four Corners
participant; APS' transactions with the PX and the ISO; contractual
relationships with SCE and PG&E; APSES' retail transactions involving SCE and
PG&E; and marketing and trading exposures. Based on our evaluations, we have
reserved $10 million before income taxes for our credit exposure related to the
California energy situation, $5 million of which was recorded in the fourth
quarter of 2000 and $5 million of which was recorded in first quarter of 2001.
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 our subsidiaries 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 the amounts alleged in the proceedings,
will have a material adverse impact on our financial position, results of
operations or liquidity.
73
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 the California Department of Water
Resources from January 17, 2001 to October 31, 2001 and does not allege any
amount above "just and reasonable levels." We believe that the claims as they
relate to Pinnacle West are without merit.
CONSTRUCTION PROGRAM
Consolidated capital expenditures in 2002 are estimated to be (dollars in
millions):
APS $ 498
Pinnacle West Energy 411
SunCor 79
Other (primarily APSES and
Pinnacle West) 35
-------
Total $ 1,023
=======
GENERATION EXPANSION
Pinnacle West Energy has completed or announced plans to build about 3,420
MW of natural gas-fired generating capacity from 2000 through 2007 at an
estimated cost of about $1.9 billion. This does not reflect an expected
reimbursement in 2004 by SNWA of $100 million of Pinnacle West Energy's
cumulative capital expenditures in the Silverhawk project in exchange for SNWA's
purchase of a 25% interest in the project. Our expansion plan will be sized to
meet native load growth, cash flow and market conditions. Pinnacle West Energy
is currently funding its capital requirements through capital infusions from
Pinnacle West, which finances those infusions through debt financings and
internally-generated cash. As Pinnacle West Energy develops and obtains
additional generation assets, including APS' existing generation assets,
Pinnacle West Energy expects to fund its capital requirements through
internally-generated cash and its own debt issuances.
Pinnacle West Energy has completed or is currently planning the following
projects:
* A 650 MW expansion of the West Phoenix Power Plant in Phoenix. The 120
MW West Phoenix Unit 4 began commercial operation on June 1, 2001.
Construction has begun on the 530 MW West Phoenix Unit 5, with
commercial operation expected to begin in mid-2003.
* The construction of a four-unit combined cycle 2,120 MW generating
station near Palo Verde, called Redhawk. Construction of Units 1 and 2
began in December 2000, and commercial operation is currently
scheduled for the summer of 2002. Although Pinnacle West Energy
currently plans to bring Units 3 and 4 on line in or before the first
quarter of 2007, equipment procurement, engineering and construction
plans will allow for these units to come on line as early as 2005 if
warranted by market conditions.
74
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
* The construction of an 80 MW simple-cycle power plant at Saguaro in
Southern Arizona. Commercial operation is currently scheduled for the
summer of 2002.
* Development of an electric generating station 20 miles north of Las
Vegas, Nevada. Construction of the 570 MW Silverhawk combined-cycle
plant is expected to begin in the spring of 2002, with an expected
commercial operation date of mid-2004. Pinnacle West Energy has signed
a 25% participation agreement with Las Vegas-based SNWA.
* A Pinnacle West Energy affiliate is exploring the possibility of
creating an underground natural gas storage facility on Company-owned
land west of Phoenix. A feasibility study is in progress to determine
if the proposed acreage can support a natural gas storage cavern.
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
APS recorded $11 million for nuclear decommissioning expense in each of the
years 2001, 2000, and 1999. APS estimates it will cost about $1.8 billion ($506
million in 2001 dollars) to decommission its 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. APS charges decommissioning costs to expense
over each unit's operating license term and includes them in the accumulated
depreciation balance until each unit is retired. Nuclear decommissioning costs
are recovered in rates.
APS' 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. APS is required to update the
study every three years.
To fund the costs APS expects to incur to decommission the plant, APS
established external decommissioning trusts in accordance with NRC regulations.
APS invests the trust funds primarily in fixed income securities and domestic
stock and classifies 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 consolidated balance sheets at December 31, 2001 and 2000 (dollars
in millions):
75
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED 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.
76
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Consolidated quarterly financial information for 2001 and 2000 is as
follows:
(dollars in thousands, except per share amounts)
2001
-----------------------------------------------------
QUARTER ENDED March 31 June 30 September 30 December 31
---------- ---------- ------------ -----------
Operating revenues (a)
Electric retail segment $ 412,807 $ 739,317 $ 973,398 $ 436,567
Marketing and trading
segment (b) 258,296 233,841 141,674 17,419
Real estate 32,335 32,454 43,024 61,095
Other revenues 1,543 1,653 2,682 5,893
Operating income $ 136,646 $ 140,010 $ 298,752 $ 100,615
Income from continuing
operations $ 62,205 $ 66,857 $ 162,499 $ 35,806
Cumulative effect of change in
accounting - net of income tax (2,755) -- (12,446) --
---------- ---------- ---------- ----------
Net income $ 59,450 $ 66,857 $ 150,053 $ 35,806
========== ========== ========== ==========
Earnings (loss) per weighted
average common share
outstanding - basic
Continuing operations - basic $ 0.73 $ 0.79 $ 1.92 $ 0.42
Cumulative effect of change
in accounting - basic (0.03) -- (0.15) --
---------- ---------- ---------- ----------
Earnings per weighted average
common share outstanding-
basic $ 0.70 $ 0.79 $ 1.77 $ 0.42
========== ========== ========== ==========
Continuing operations - diluted $ 0.73 $ 0.79 $ 1.91 $ 0.42
Cumulative effect of change
in accounting - diluted (0.03) -- (0.14) --
---------- ---------- ---------- ----------
Earnings per weighted average
common share outstanding -
diluted $ 0.70 $ 0.79 $ 1.77 $ 0.42
========== ========== ========== ==========
Dividends declared per share $ 0.375 $ 0.375 $ 0.375 $ 0.40
77
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per share amounts)
2000
-----------------------------------------------------
QUARTER ENDED March 31 June 30 September 30 December 31
---------- ---------- ------------ -----------
Operating revenues (a)
Electric retail segment $ 379,428 $ 547,091 $1,156,659 $ 455,574
Marketing and trading
segment (b) 35,287 105,166 95,479 182,600
Real estate 41,889 36,374 39,396 40,706
Other revenues 27 525 2,559 762
Operating income $ 91,540 $ 191,407 $ 243,523 $ 118,368
Net income $ 54,070 $ 89,901 $ 116,049 $ 42,312
Earnings per weighted average
common share outstanding
Net income - basic $ 0.64 $ 1.06 $ 1.37 $ 0.50
Net income - diluted $ 0.64 $ 1.06 $ 1.37 $ 0.50
Dividends declared per share $ 0.35 $ 0.35 $ 0.35 $ 0.375
(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 19 for information related to a change in presentation of certain
marketing and trading revenues to a net basis.
78
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 $2.80 billion, with an estimated fair value of
$2.82 billion. The carrying value of our long-term debt (excluding a capitalized
lease obligation) was $2.42 billion on December 31, 2000, with an estimated fair
value of $2.48 billion. The fair value estimates are based on quoted market
prices of the same or similar issues.
14. EARNINGS PER SHARE
The following table presents earnings per weighted average common share
outstanding (EPS):
2001 2000 1999
---------- ---------- ----------
Basic EPS:
Continuing operations $ 3.86 $ 3.57 $ 3.18
Discontinued operations -- -- 0.45
Extraordinary charge -- -- (1.65)
Cumulative effect of change in
accounting (0.18) -- --
---------- ---------- ----------
Earnings per share-basic $ 3.68 $ 3.57 $ 1.98
========== ========== ==========
Diluted EPS:
Continuing operations $ 3.85 $ 3.56 $ 3.17
Discontinued operations -- -- 0.45
Extraordinary charge -- -- (1.65)
Cumulative effect of change in
accounting (0.17) -- --
---------- ---------- ----------
Earnings per share-diluted $ 3.68 $ 3.56 $ 1.97
========== ========== ==========
Dilutive stock options increased average common shares outstanding by
212,491 shares in 2001, 202,738 shares in 2000, and 291,392 shares in 1999.
Total average common shares outstanding for the purposes of calculating diluted
earnings per share were 84,930,140 shares in 2001, 84,935,282 shares in 2000,
and 85,008,527 shares in 1999.
Options to purchase 212,562 shares of common stock were outstanding at
December 31, 2001 but were not included in the computation of diluted EPS
because the options' exercise price was greater than the average market price of
the common shares. Options to purchase shares of common stock that were not
included in the computation of diluted EPS were 517,614 at December 31, 2000 and
506,734 at December 31, 1999.
79
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
15. STOCK-BASED COMPENSATION
Pinnacle West offers two stock incentive plans for officers and key
employees of our company and our subsidiaries.
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
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 and earnings per share would have been reduced to the following pro
forma amounts (dollars in thousands):
2001 2000 1999
--------- --------- ---------
Net income
As reported $ 312,166 $ 302,332 $ 167,887
Pro forma (fair value method) $ 309,800 $ 301,102 $ 166,913
Earnings per share - basic
As reported $ 3.68 $ 3.57 $ 1.98
Pro forma (fair value method) $ 3.66 $ 3.55 $ 1.97
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:
80
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
The following table is a summary of the status of our stock option plans as
of December 31, 2001, 2000, and 1999 and changes during the years ending on
those dates:
2001 2000 1999
Weighted Weighted Weighted
Average Average Average
2001 Exercise 2000 Exercise 1999 Exercise
Shares Price Shares Price Shares Price
--------- ---------- --------- ---------- --------- ----------
Outstanding at
beginning of year 1,569,171 $37.55 1,441,124 $33.45 1,563,512 $27.95
Granted 444,200 42.55 451,450 43.28 458,450 35.95
Exercised (162,229) 28.53 (283,819) 20.90 (516,838) 18.19
Forfeited (18,417) 41.67 (39,584) 39.86 (64,000) 40.36
--------- --------- ---------
Outstanding at end
of year 1,832,725 39.52 1,569,171 37.55 1,441,124 33.45
--------- --------- ---------
Options exercisable
at year-end 926,315 37.41 831,537 34.37 835,381 29.69
--------- --------- ---------
Weighted average
fair value of
options granted
during the year 8.84 11.81 7.05
The following table summarizes information about our stock option plans at
December 31, 2001:
Weighted
Weighted Average Weighted
Average Remaining Average
Exercise Options Exercise Contract Options Exercise
Prices Per Share Outstanding Price Life (Years) Exercisable Price
---------------- ----------- ----- ------------ ----------- -----
$14.03-18.71 15,150 $18.09 0.5 15,150 $18.09
18.71-23.39 88,284 20.53 2.3 88,284 20.53
23.39-28.07 78,167 27.39 4.6 64,834 27.44
28.07-32.75 72,250 31.44 4.8 72,250 31.44
32.75-37.42 285,024 34.69 7.7 165,245 34.69
37.42-42.10 217,500 40.15 6.1 175,500 39.95
42.10-46.78 1,076,350 43.96 8.8 345,052 45.70
--------- ---------
1,832,725 926,315
========= =========
81
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
16. 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 and APSES' competitive energy services.
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, APS 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 above. Internal
management reporting has been changed to reflect this alignment. The
corresponding information for earlier periods has been restated. The other
amounts include activity relating to the parent company and other subsidiaries
including SunCor and El Dorado. Financial data for the business segments is
provided as follows (dollars in millions):
Business Segments for the Year Ended
December 31, 2001
-------------------------------------------
Marketing
Electric and
Retail Trading(a) Other Total
-------- ---------- -------- --------
Operating revenues $ 2,562 $ 651 $ 181 $ 3,394
Purchased power and fuel costs 1,161 334 -- 1,495
Other operating expenses 602 32 168 802
-------- -------- -------- --------
Operating margin 799 285 13 1,097
Depreciation and amortization 423 1 4 428
Interest expense 124 -- 4 128
-------- -------- -------- --------
Pretax margin 252 284 5 541
Income taxes 100 112 2 214
-------- -------- -------- --------
Income from continuing operations 152 172 3 327
Cumulative effect of change in
accounting for derivatives -
net of income taxes of $10 (15) -- -- (15)
-------- -------- -------- --------
Net income $ 137 $ 172 $ 3 $ 312
======== ======== ======== ========
Total assets $ 6,938 $ 556 $ 488 $ 7,982
======== ======== ======== ========
Capital expenditures $ 1,004 $ 23 $ 102 $ 1,129
======== ======== ======== ========
82
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Business Segments for the Year Ended
December 31, 2000
-------------------------------------------
Marketing
Electric and
Retail Trading(a) Other Total
-------- ---------- -------- --------
Operating revenues $ 2,539 $ 419 $ 162 $ 3,120
Purchased power and fuel costs 1,066 293 -- 1,359
Other operating expenses 538 21 130 689
-------- -------- -------- --------
Operating margin 935 105 32 1,072
Depreciation and amortization 425 1 5 431
Interest expense 141 -- 4 145
-------- -------- -------- --------
Pretax margin 369 104 23 496
Income taxes 144 41 9 194
-------- -------- -------- --------
Net income $ 225 $ 63 $ 14 $ 302
======== ======== ======== ========
Total assets $ 6,326 $ 386 $ 451 $ 7,163
======== ======== ======== ========
Capital expenditures $ 665 $ -- $ 50 $ 715
======== ======== ======== ========
Business Segments for the Year Ended
December 31, 1999
-------------------------------------------
Marketing
Electric and
Retail Trading(a) Other Total
-------- ---------- -------- --------
Operating revenues $ 1,916 $ 154 $ 130 $ 2,200
Purchased power and fuel costs 433 137 -- 570
Other operating expenses 549 9 95 653
-------- -------- -------- --------
Operating margin 934 8 35 977
Depreciation and amortization 417 -- 3 420
Interest expense 142 -- 3 145
-------- -------- -------- --------
Pretax margin 375 8 29 412
Income taxes 129 3 10 142
-------- -------- -------- --------
Income from continuing operations 246 5 19 270
Income tax benefit from
discontinued operations 38 -- -- 38
Extraordinary charge - net of
income taxes of $94 (140) -- -- (140)
-------- -------- -------- --------
Net income $ 144 $ 5 $ 19 $ 168
======== ======== ======== ========
Capital expenditures $ 353 $ -- $ 126 $ 479
======== ======== ======== ========
(a) See Note 19 for information related to a change in presentation of certain
marketing and trading revenues and purchased power and fuel costs to a net
basis.
83
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
17. 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 Board of Directors and monitored
by the Energy Risk Management Committee, 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 have risk management and trading contracts with many
counterparties, including one counterparty for which a worst case exposure
represents approximately 50% of our $267 million of risk management and trading
assets as of December 31, 2001. 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 trading counterparties are rated as investment
grade by the credit rating agencies, including the counterparty noted above,
there is still a possibility that one or more of these companies could default,
resulting in a material impact on consolidated earnings for a given period.
Counterparties in the portfolio consist principally of major energy companies,
municipalities, 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 consolidated
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.
84
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED 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 consolidated 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.
The following table summarizes our assets and liabilities from risk
management and trading activities related to trading and system (retail and
traditional wholesale activities) as of December 31, 2001 and 2000 (dollars in
thousands):
85
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001
Current Current Other Net Asset/
Assets Investments Liabilities Liabilities (Liability)
--------- ----------- ----------- ----------- -----------
Mark-to-market:
Trading $ 56,876 $ 148,457 $ (14,154) $ (53,253) $ 137,926
System 10,097 -- (21,840) (95,159) (106,902)
Trading - at cost -- 51,894 -- (59,164) (7,270)
--------- --------- --------- --------- ---------
Total $ 66,973 $ 200,351 $ (35,994) $(207,576) $ 23,754
========= ========= ========= ========= =========
December 31, 2000
Current Current Other Net Asset/
Assets Investments Liabilities Liabilities (Liability)
--------- ----------- ----------- ----------- -----------
Trading - mark-
to-market $ 17,506 $ 32,955 $ (37,179) $ (877) $ 12,405
Trading - at cost -- -- -- (13,834) (13,834)
--------- --------- --------- --------- ---------
Total $ 17,506 $ 32,955 $ (37,179) $ (14,711) $ (1,429)
========= ========= ========= ========= =========
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 $127 million for the year ended December 31, 2001 and $14
million for the year ended December 31, 2000.
18. SUBSEQUENT EVENTS
On February 8, 2002, Pinnacle West issued $215 million of 4.5% Notes due
2004. On March 1, 2002, APS issued $375 million of 6.50% Notes due 2012. On
March 15, 2002, APS announced the redemption on April 15, 2002 of approximately
$125 million of its 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." We believe 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.
86
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
19. 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 consolidated 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
---------- ---------- ----------
Revenues before reclassification $1,820,376 $ 993,058 $ 378,076
Less: Purchased power and fuel costs netted with
revenues 1,169,146 574,526 223,951
---------- ---------- ----------
Revenues after reclassification $ 651,230 $ 418,532 $ 154,125
========== ========== ==========
Purchased power and fuel before reclassification $1,503,355 $ 867,195 $ 360,472
Less: Purchased power and fuel costs netted with
revenues 1,169,146 574,526 223,951
---------- ---------- ----------
Purchased power and fuel after reclassification $ 334,209 $ 292,669 $ 136,521
========== ========== ==========
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
87
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 consolidated financial statements.
In addition, we have presented in our consolidated 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 consolidated income statements.
88
PINNACLE WEST CAPITAL CORPORATION
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Column A Column B Column C Column D Column E
Additions
----------------------
Balance at Charged to Charged Balance
beginning cost and to other at end of
Description of period expenses accounts Deductions Period
----------- --------- --------- -------- ---------- --------
(dollars in thousands)
YEAR ENDED DECEMBER 31, 2001
Real Estate Valuation Reserves $ 2,000 $ -- $ -- $ --(a) $ 2,000
YEAR ENDED DECEMBER 31, 2000
Real Estate Valuation Reserves $ 8,000 $ -- $ -- $ 6,000(a) $ 2,000
YEAR ENDED DECEMBER 31, 1999
Real Estate Valuation Reserves $ 15,000 $ -- $ -- $ 7,000(a) $ 8,000
YEAR ENDED DECEMBER 31, 2001
Reserve for uncollectibles $ 2,580 $ 7,609 $ -- $ 6,640 $ 3,549
YEAR ENDED DECEMBER 31, 2000
Reserve for uncollectibles $ 1,538 $ 5,638 $ -- $ 4,596 $ 2,580
YEAR ENDED DECEMBER 31, 1999
Reserve for uncollectibles $ 1,725 $ 4,778 $ -- $ 4,965 $ 1,538
(a) Represents pro-rata allocations for sale of land.
89
ITEM 7. FINANCIAL STATEMENTS, PRO FORMA FINANCIAL INFORMATION AND EXHIBITS.
(c) Exhibits.
Exhibit No. Description
----------- -----------
23.1 Consent of Deloitte & Touche LLP
90
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.
PINNACLE WEST CAPITAL CORPORATION
(Registrant)
Dated: November 25, 2002 By: Barbara M. Gomez
------------------------------------
Barbara M. Gomez
Treasurer
91