FORM 10-Q
Securities and Exchange Commission
Washington, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended September 30, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission file number 1-8962
PINNACLE WEST CAPITAL CORPORATION
(Exact name of registrant as specified in its charter)
Arizona 86-0512431
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
400 North Fifth Street, P.O. Box 53999, Phoenix, Arizona 85072-3999
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (602) 250-1000
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Number of shares of common stock, no par value,
outstanding as of November 2, 2001: 84,642,939
Glossary
ACC - Arizona Corporation Commission
ACC Staff - Staff of the Arizona Corporation Commission
ADEQ - Arizona Department of Environmental Quality
APS - Arizona Public Service Company, a subsidiary of the Company
APS Energy Services - APS Energy Services Company, Inc., a subsidiary of the
Company
Bookout - one party appears more than once in a contract path for the purchase
and sale of a commodity, resulting in an unplanned net settlement
CC&N - Certificate of Convenience and Necessity
Citizens - Citizens Communications Company
Company - Pinnacle West Capital Corporation
EITF - Emerging Issues Task Force
El Dorado - El Dorado Investment Company, a subsidiary of the Company
El Paso - El Paso Natural Gas Company
ERMC - Energy Risk Management Committee
FASB - Financial Accounting Standards Board
FERC - United States Federal Energy Regulatory Commission
Four Corners - Four Corners Power Plant
GWh - gigawatt-hour, one billion watts per hour
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-hour, one million watts per hour
1999 Settlement Agreement - comprehensive settlement agreement related to the
implementation of retail electric competition
Native Load - retail and wholesale sales supplied under traditional cost-based
rate regulation
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 between APS and the Company
PX - California Power Exchange
RTO - regional transmission organization
Rules - ACC retail electric competition rules
Salt River Project - Salt River Project Agricultural Improvement and Power
District
SCE - Southern California Edison Company
SFAS - Statement of Financial Accounting Standards
SunCor - SunCor Development Company, a subsidiary of the Company
2000 10-K - Pinnacle West Capital Corporation Annual Report on Form 10-K for the
fiscal year ended December 31, 2000
WestConnect - WestConnect RTO, LLC
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(dollars in thousands, except per share amounts)
Three Months Ended
September 30,
2001 2000
----------- -----------
Operating Revenues
Electric $ 1,531,005 $ 1,567,960
Real estate 43,024 39,396
----------- -----------
Total 1,574,029 1,607,356
----------- -----------
Operating Expenses
Purchased power and fuel 949,436 1,078,860
Operations and maintenance 150,916 113,519
Real estate operations 37,803 33,980
Depreciation and amortization 107,932 114,092
Taxes other than income taxes 29,336 25,641
----------- -----------
Total 1,275,423 1,366,092
----------- -----------
Operating Income 298,606 241,264
Other Income (Expense) (1,930) (14,833)
----------- -----------
Income Before Interest and Income Taxes 296,676 226,431
Interest Expense
Interest charges 42,531 41,684
Capitalized interest (12,450) (5,240)
----------- -----------
Total 30,081 36,444
----------- -----------
Income Before Income Taxes 266,595 189,987
Income Taxes 104,096 73,938
----------- -----------
Income Before Accounting Change 162,499 116,049
Cumulative Effect of a Change in Accounting for Derivatives
- Net of Income Tax Benefit of $8,099 (12,446) --
----------- -----------
Net Income $ 150,053 $ 116,049
=========== ===========
Average Common Shares Outstanding - Basic 84,721 84,745
Average Common Shares Outstanding - Diluted 84,909 85,012
Earnings Per Average Common Share Outstanding
Income Before Accounting Change - Basic $ 1.92 $ 1.37
Net Income - Basic 1.77 1.37
Income Before Accounting Change - Diluted 1.91 1.37
Net Income - Diluted 1.77 1.37
Dividends Declared Per Share $ 0.375 $ 0.35
See Notes to Condensed Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(dollars in thousands, except per share amounts)
Nine Months Ended
September 30,
2001 2000
----------- -----------
Operating Revenues
Electric $ 3,698,857 $ 2,734,362
Real estate 107,813 117,659
----------- -----------
Total 3,806,670 2,852,021
----------- -----------
Operating Expenses
Purchased power and fuel 2,324,617 1,493,535
Operations and maintenance 408,305 331,301
Real estate operations 101,248 101,374
Depreciation and amortization 318,842 325,393
Taxes other than income taxes 80,101 76,643
----------- -----------
Total 3,233,113 2,328,246
----------- -----------
Operating Income 573,557 523,775
Other Income (Expense) 569 13,620
----------- -----------
Income Before Interest and Income Taxes 574,126 537,395
----------- -----------
Interest Expense
Interest charges 129,103 123,283
Capitalized interest (35,404) (13,875)
----------- -----------
Total 93,699 109,408
----------- -----------
Income Before Income Taxes 480,427 427,987
Income Taxes 188,866 167,967
----------- -----------
Income Before Accounting Change 291,561 260,020
Cumulative Effect of a Change in Accounting for Derivatives
- Net of Income Tax Benefit of $9,892 (15,201) --
----------- -----------
Net Income $ 276,360 $ 260,020
=========== ===========
Average Common Shares Outstanding - Basic 84,731 84,735
Average Common Shares Outstanding - Diluted 84,972 84,901
Earnings Per Average Common Share Outstanding
Income Before Accounting Change - Basic $ 3.44 $ 3.07
Net Income - Basic 3.26 3.07
Income Before Accounting Change - Diluted 3.43 3.06
Net Income - Diluted 3.25 3.06
Dividends Declared Per Share $ 1.125 $ 1.05
See Notes to Condensed Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(dollars in thousands, except per share amounts)
Twelve Months Ended
September 30,
2001 2000
----------- -----------
Operating Revenues
Electric $ 4,496,305 $ 3,234,499
Real estate 148,519 163,958
----------- -----------
Total 4,644,824 3,398,457
----------- -----------
Operating Expenses
Purchased power and fuel 2,763,873 1,653,139
Operations and maintenance 527,206 458,715
Real estate operations 134,296 142,497
Depreciation and amortization 424,678 427,496
Taxes other than income taxes 103,238 100,221
----------- -----------
Total 3,953,291 2,782,068
----------- -----------
Operating Income 691,533 616,389
Other Income (Expense) (13,463) 25,256
----------- -----------
Income Before Interest and Income Taxes 678,070 641,645
----------- -----------
Interest Expense
Interest charges 172,265 162,913
Capitalized interest (43,167) (15,286)
----------- -----------
Total 129,098 147,627
----------- -----------
Income Before Income Taxes 548,972 494,018
Income Taxes 215,099 189,197
----------- -----------
Income Before Accounting Change 333,873 304,821
Cumulative Effect of a Change in Accounting for Derivatives
- Net of Income Tax Benefit of $9,892 (15,201) --
----------- -----------
Net Income $ 318,672 $ 304,821
=========== ===========
Average Common Shares Outstanding - Basic 84,730 84,732
Average Common Shares Outstanding - Diluted 84,984 84,898
Earnings Per Average Common Share Outstanding
Income Before Accounting Change - Basic $ 3.94 $ 3.60
Net Income - Basic 3.76 3.60
Income Before Accounting Change - Diluted 3.93 3.59
Net Income - Diluted 3.75 3.59
Dividends Declared Per Share $ 1.50 $ 1.40
See Notes to Condensed Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
(dollars in thousands)
September 30, December 31,
2001 2000
---------- ----------
(unaudited)
Current Assets
Cash and cash equivalents $ 25,337 $ 10,363
Trust fund for bond redemption 72,370 --
Customer and other receivables--net 625,794 513,822
Accrued utility revenues 102,951 74,566
Materials and supplies 81,304 71,966
Fossil fuel 24,833 19,405
Deferred income taxes 5,793 5,793
Assets from risk management and trading activities 152,939 17,506
Other current assets 86,948 80,492
---------- ----------
Total current assets 1,178,269 793,913
---------- ----------
Investments and Other Assets
Real estate investments--net 405,497 371,323
Other assets 712,481 318,249
---------- ----------
Total investments and other assets 1,117,978 689,572
---------- ----------
Property, Plant and Equipment
Plant in service and held for future use 8,128,669 7,809,566
Less accumulated depreciation and amortization 3,339,977 3,188,302
---------- ----------
Total 4,788,692 4,621,264
Construction work in progress 777,039 464,540
Nuclear fuel, net of amortization 54,853 47,389
---------- ----------
Net property, plant and equipment 5,620,584 5,133,193
---------- ----------
Deferred Debits
Regulatory assets 370,943 469,867
Other deferred debits 75,088 62,606
---------- ----------
Total deferred debits 446,031 532,473
---------- ----------
Total Assets $8,362,862 $7,149,151
========== ==========
See Notes to Condensed Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
(dollars in thousands)
September 30, December 31,
2001 2000
----------- -----------
(unaudited)
Current Liabilities
Accounts payable $ 412,226 $ 375,805
Accrued taxes 343,982 89,246
Accrued interest 28,039 42,954
Short-term borrowings 199,400 82,775
Current maturities of long-term debt 400,266 463,469
Customer deposits 29,468 26,189
Liabilities from risk management and trading activities 197,495 37,179
Other current liabilities 46,530 73,681
----------- -----------
Total current liabilities 1,657,406 1,191,298
----------- -----------
Long-Term Debt Less Current Maturities 2,349,677 1,955,083
----------- -----------
Deferred Credits and Other
Deferred income taxes 1,030,870 1,143,040
Unamortized gain - sale of utility plant 65,204 68,636
Other 768,384 408,380
----------- -----------
Total deferred credits and other 1,864,458 1,620,056
----------- -----------
Commitments and contingencies (Notes 6, 7, 9 and 12)
Common Stock Equity
Common stock, no par value 1,527,026 1,532,831
Accumulated other comprehensive loss (66,609) --
Retained earnings 1,030,904 849,883
----------- -----------
Total common stock equity 2,491,321 2,382,714
----------- -----------
Total Liabilities and Equity $ 8,362,862 $ 7,149,151
=========== ===========
See Notes to Condensed Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)
Nine Months Ended
September 30,
2001 2000
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Income before accounting change $ 291,561 $ 260,020
Items not requiring cash
Depreciation and amortization 318,842 325,393
Nuclear fuel amortization 22,221 23,139
Deferred income taxes--net (58,936) (69,086)
Other--net -- (3,350)
Changes in current assets and liabilities
Customer and other receivables--net (111,972) (425,259)
Accrued utility revenues (28,385) (38,396)
Materials, supplies and fossil fuel (14,766) 3,787
Other current assets (6,456) (10,969)
Accounts payable 30,729 308,407
Accrued taxes 254,736 161,228
Accrued interest (14,915) (6,843)
Risk management and trading activities - net (196,032) 17,934
Other current liabilities (23,872) 6,911
Change in El Dorado partnership investment 966 (11,897)
Increase in land held for sale (31,481) (21,073)
Other--net 6,486 33,033
--------- ---------
Net Cash Flow Provided By Operating Activities 438,726 552,979
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Trust fund for bond redemption (72,370) --
Capital expenditures (685,307) (398,994)
Capitalized interest (35,404) (13,875)
Other--net 22,939 20,259
--------- ---------
Net Cash Flow Used For Investing Activities (770,142) (392,610)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 744,500 494,000
Short-term borrowings--net 116,625 (36,316)
Dividends paid on common stock (95,341) (88,963)
Repayment of long-term debt (413,589) (461,157)
Other--net (5,805) (956)
--------- ---------
Net Cash Flow Provided by /(Used for) Financing Activities 346,390 (93,392)
--------- ---------
Net Cash Flow 14,974 66,977
Cash and Cash Equivalents at Beginning of Period 10,363 20,705
--------- ---------
Cash and Cash Equivalents at End of Period $ 25,337 $ 87,682
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest, net of amounts capitalized $ 101,072 $ 109,778
Income taxes $ 32,349 $ 127,013
See Notes to Condensed Consolidated Financial Statements.
-8-
PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. The Condensed Consolidated Financial Statements include the accounts of the
Company and its subsidiaries: APS, Pinnacle West Energy, APS Energy Services,
SunCor, and El Dorado. All significant intercompany accounts and transactions
have been eliminated. We have reclassified certain prior year amounts to conform
to the current year presentation.
2. Our unaudited Condensed Consolidated Financial Statements reflect all
adjustments which we believe are necessary for the fair presentation of our
financial position and results of operations for the periods presented. These
adjustments are of a normal recurring nature with the exception of the
cumulative effect of a change in accounting for derivatives (see Note 10). We
suggest that these Condensed Consolidated Financial Statements and Notes to
Condensed Consolidated Financial Statements be read along with the Consolidated
Financial Statements and Notes to Consolidated Financial Statements included in
our 2000 10-K.
3. Weather conditions and trading and wholesale power marketing activities can
have significant impacts on our results for interim periods. Results for interim
periods do not necessarily represent results to be expected for the year.
4. See "Liquidity and Capital Resources" in Part I, Item 2 of this report for
changes in capitalization for the nine months ended September 30, 2001.
5. Regulatory Accounting
APS is regulated by the ACC and FERC. The accompanying financial statements
reflect the ratemaking 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 6 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, or $1.65 per
basic or diluted share) was reported as an extraordinary charge on the income
statement during the third quarter of 1999. Prior to the 1999 Settlement
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Agreement, under the 1996 regulatory agreement (see Note 6), the ACC accelerated
the amortization of substantially all of our regulatory assets to an eight-year
period that would have ended June 30, 2004.
The regulatory assets to be recovered under the 1999 Settlement Agreement
are now being amortized through June 30, 2004 as follows (dollars in millions):
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $86 $18 $686
The majority of our remaining regulatory assets relate to deferred income
taxes and rate synchronization cost deferrals.
The consolidated balance sheets include the amounts listed below for
generation assets not subject to SFAS No. 71 (for additional generation
information see Note 8):
(dollars in thousands)
September 30, December 31,
2001 2000
----------- -----------
Electric plant in service and held for future use $ 3,967,771 $ 3,856,600
Accumulated depreciation and amortization ....... (1,771,158) (1,693,079)
Construction work in progress ................... 595,383 304,992
Nuclear fuel, net of amortization ............... 54,853 47,389
6. Regulatory Matters
ELECTRIC INDUSTRY RESTRUCTURING
STATE
1999 SETTLEMENT AGREEMENT. On May 14, 1999, APS entered into a
comprehensive 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 singular issue of whether the ACC could itself become a
party to the Settlement Agreement by virtue of its
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approval of the Settlement Agreement. The Supreme Court has not yet set a date
for oral argument on this matter.
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.
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* 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 generating assets and
competitive 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.
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.
* When the 1999 Settlement Agreement approved by the ACC is no longer subject
to judicial review, APS will move to dismiss all of its litigation pending
against the ACC as of the date APS entered into the 1999 Settlement
Agreement. To protect its rights, APS has several lawsuits pending on ACC
orders relating to stranded cost recovery and the adoption and amendment of
the ACC's electric competition rules, which would be voluntarily dismissed
at the appropriate time under this provision.
As discussed in Note 5 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 the Company's power marketing 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 (a) 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 that coming from a "competitive bidding" process)
starting in 2003 and (b) approve as just and reasonable a long-term purchase
power agreement (PPA) between APS and the Company. APS has requested these ACC
actions to ensure continued reliable service to APS standard offer 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:
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* 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 the Company.
* 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.
* The Company would assume contractual responsibility for reliability and
would supplement any potential shortfall even after full utilization of
Pinnacle West Energy's dedicated generating resources.
* The Company 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 the Company under certain
"dedicated contracts"; and (d) power procured on the open market, including
a competitively-bid component described below.
* Beginning in 2003, the Company 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).
* The Company 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 the Company'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) FERC acceptance
of the PPA and the companion agreement between the Company and Pinnacle
West Energy.
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 customers under rates that have been approved by the
ACC. Energy prices in the western wholesale market vary and, during the course
of the last year, have been volatile. At various times, prices in the spot
wholesale market have significantly exceeded the amount included in APS' current
retail rates. APS expects that the market may continue to be volatile. We
believe that through a combination of hedging and our current generation
portfolio, we will be able to adequately manage our exposure to the volatility
of the power market. However, 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
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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.
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 is pending, along with several other lawsuits on ACC orders relating to
stranded cost recovery (including those described above involving APS), the
adoption or amendment of the Rules, and the certification of competitive
electric service providers.
On November 27, 2000, a Maricopa County, Arizona, Superior Court judge
issued a final judgment holding that the Rules are unconstitutional and unlawful
in their entirety due to failure to establish a fair value rate base for
competitive electric service providers and because certain of the Rules were not
submitted to the Arizona Attorney General for certification. The judgment also
invalidates all ACC orders authorizing competitive electric service providers,
including APS Energy Services, to operate in Arizona. 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.
-14-
* Affected utilities must file ACC tariffs that unbundle rates for
non-competitive 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
generation 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 generation and other competitive
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.
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):
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
-15-
* 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
The 1992 Energy Act and recent rulemakings by FERC have promoted increased
competition in the wholesale energy markets. We do not expect these rules to
have a material impact on our financial statements.
In June 2001, 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. The Company
cannot accurately predict the overall financial impact of the plan on the
various aspects of its business, including its wholesale and purchased power
activities.
7. Nuclear Insurance
The Palo Verde participants have insurance for public liability payments
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 APS'
29.1% interest in the three Palo Verde units, APS' maximum potential assessment
per incident 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 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.
-16-
8. Business Segments
We have two principal business segments (determined by products, services
and regulatory environment),which consist of activities related to the
transmission and distribution of electricity (delivery business segment) and the
generation of electricity and wholesale and power trading (generation business
segment).
These reportable segments reflect a change in the reporting of our
functional activities. Before January 1, 2001, our reported segment information
combined transmission and distribution activities with wholesale and power
trading activities. Our current operational activities are more closely based on
the strong integration of our wholesale and power trading activities with our
generation of electricity, and have been combined for segment reporting
purposes. The corresponding information for earlier periods has been restated.
Beginning in 2001, we changed our method of allocating revenues between the
delivery business segment and the generation business segment to reflect the
seasonal impact of market prices. This change had the impact of decreasing
delivery segment income and increasing generation segment income in all the
periods presented when compared to the prior comparable periods. The after-tax
change is $45 million in the three-month period and $2 million in the nine- and
twelve-month periods.
The other amounts include activity relating to the parent company and other
subsidiaries, including APS Energy Services, SunCor and El Dorado. Eliminations
primarily relate to intersegment sales of electricity. Segment information for
the three, nine and twelve months ended September 30, 2001 and 2000 is as
follows (dollars in millions):
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
-------------------- -------------------- --------------------
2001 2000 2001 2000 2001 2000
------- ------- ------- ------- ------- -------
Operating Revenues:
Delivery $ 612 $ 683 $ 1,577 $ 1,563 $ 1,984 $ 1,963
Generation 1,355 1,194 3,001 1,886 3,601 2,169
Other 46 41 116 120 154 166
Eliminations (439) (311) (887) (717) (1,094) (900)
------- ------- ------- ------- ------- -------
Total $ 1,574 $ 1,607 $ 3,807 $ 2,852 $ 4,645 $ 3,398
======= ======= ======= ======= ======= =======
Income Before
Accounting Change:
Delivery $ 6 $ 28 $ 95 $ 84 $ 116 $ 115
Generation 156 95 204 168 234 172
Other -- (7) (8) 8 (16) 18
------- ------- ------- ------- ------- -------
Total $ 162 $ 116 $ 291 $ 260 $ 334 $ 305
======= ======= ======= ======= ======= =======
-17-
As of September 30, As of December 31,
2001 2000
------- -------
Assets:
Delivery $ 3,950 $ 3,987
Generation 4,029 2,687
Other 384 475
------- -------
Total $ 8,363 $ 7,149
======= =======
9. 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." We are currently evaluating the impacts of the new standard
and do not expect it to have a material impact on our financial statements. We
have no goodwill. This standard is effective for the year beginning January 1,
2002.
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. We are currently evaluating the impacts of the new
standard and do not expect it to have a material impact on our financial
statements.
10. 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/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.
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 sheet and measure those instruments at fair value. Changes in the fair
value of derivative financial instruments are
-18-
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.
In June 2001, the FASB determined that certain electricity contracts,
including those with option characteristics and those subject to "bookout,"
would qualify for the normal purchases and sales exception if certain criteria
were met. Prior to the issuance of the guidance, we accounted for electricity
contracts with characteristics of options and those subject to "bookout" as
normal purchases and sales. As a result, we did not previously mark these
contracts to their fair market values each reporting period. The effective date
of this new guidance was July 1, 2001.
As a result of adopting SFAS No. 133, we recognized $118 million of
derivative assets and $16 million of derivative liabilities in our balance sheet
as of January 1, 2001. Also as of January 1, 2001, we recorded a $3 million
after-tax loss, or $0.03 per basic or diluted share, in net income as a
cumulative effect of a change in accounting principle and a $65 million
after-tax gain in equity (as a component of other comprehensive income). The
gain resulted from unrealized gains on cash flow hedges.
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. These adjustments resulted primarily from contracts
with characteristics of options that did not meet the new criteria for the
normal purchases and sales exception. The impact of the new guidance is
reflected as a cumulative effect of a change in accounting principle. In October
2001, FASB again revised its guidance for option-like contracts. We are
currently in the process of evaluating the effect, if any, of this revised
guidance.
The change in derivative fair value in the consolidated statements of
income for the three, nine and twelve months ending September 30, 2001 and 2000
is comprised of the following (dollars in thousands):
-19-
Three Months Ended Nine Months Ended Twelve Months Ended
September 30, September 30, September 30,
-------------------- -------------------- --------------------
2001 2000 2001 2000 2001 2000
-------- -------- -------- -------- -------- --------
Ineffective portion of
derivatives qualifying for
hedge accounting (a) $ (1,879) $ -- $ (8,063) $ -- $ (8,063) $ --
Discontinuance of cash
flow hedges for
forecasted transactions
that will not occur (1,367) -- (9,692) -- (9,692) --
Reclassification of mark-
to-market to realized 19,880 -- 26,359 -- 26,359 --
-------- -------- -------- -------- -------- --------
Total $ 16,634 $ -- $ 8,604 $ -- $ 8,604 $ --
======== ======== ======== ======== ======== ========
----------
(a) Time value component of options excluded from assessment of hedge
effectiveness.
As of September 30, 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-nine months. During the twelve months ending September
30, 2002, we estimate that a net loss of $23 million before income taxes will be
reclassified from accumulated other comprehensive income as an offset to the
effect on earnings of market price changes for the related hedged transaction.
Net gains and losses on derivatives utilized for trading activities are
recognized in power marketing revenues on a current basis (the mark-to-market
method). Trading positions are measured at fair value as of the balance sheet
date. The mark-to-market gains recognized in power marketing revenues were the
following for the three, nine and twelve months ended September 30, 2001 and
2000 (dollars in millions):
-20-
Three Months Ended Nine Months Ended Twelve Months Ended
September 30, September 30, September 30,
-------------------- -------------------- --------------------
2001 2000 2001 2000 2001 2000
-------- -------- -------- -------- -------- --------
Mark-to-market gains (losses) $ 92 $ (45) $ 187 $ (18) $ 214 $ (17)
Realized gains (losses) (4) 66 6 80 (27) 83
-------- -------- -------- -------- -------- --------
Total trading gains $ 88 $ 21 $ 193 $ 62 $ 187 $ 66
======== ======== ======== ======== ======== ========
11. Comprehensive Income
Components of comprehensive income for the three, nine and twelve months
ended September 30, 2001 and 2000, are as follows (dollars in thousands):
Three Months Ended Nine Months Ended Twelve Months Ended
September 30, September 30, September 30,
---------------------- ---------------------- ----------------------
2001 2000 2001 2000 2001 2000
--------- --------- --------- --------- --------- ---------
Net income $ 150,053 $ 116,049 $ 276,360 $ 260,020 $ 318,672 $ 304,821
--------- --------- --------- --------- --------- ---------
Other comprehensive income(loss), net of tax:
Cumulative effect of change in
accounting for derivatives 7,801 -- 72,501 -- 72,501 --
Unrealized holding losses arising
during period (11,353) -- (109,281) -- (109,281) --
Reclassification adjustment for
derivatives (11,145) -- (29,829) -- (29,829) --
--------- --------- --------- --------- --------- ---------
Total other comprehensive loss (14,697) -- (66,609) -- (66,609) --
--------- --------- --------- --------- --------- ---------
Comprehensive income $ 135,356 $ 116,049 $ 209,751 $ 260,020 $ 252,063 $ 304,821
========= ========= ========= ========= ========= =========
12. Generation Expansion
PINNACLE WEST ENERGY
Pinnacle West Energy has announced plans to build about 3,277 MW of natural
gas-fired generating capacity from 2001-2006 at an estimated cost of about $1.7
billion.
-21-
Site MW
---- ------
West Phoenix 4 - In Service 120
West Phoenix 5 530
Redhawk 1 530
Redhawk 2 530
Redhawk 3 530
Redhawk 4 530
Saguaro 3 80
Silverhawk* 427
------
TOTAL 3,277
======
----------
* 75% Pinnacle West Energy Share of 570 MW Unit
Pinnacle West Energy is currently funding its capital requirements through
capital infusions from the parent company, which finances those infusions
through debt financings and internally generated cash. As Pinnacle West Energy
develops and obtains additional 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 generating station near Palo Verde,
called Redhawk. Redhawk Units 1 and 2 will be combined-cycle units.
Construction began in December 2000, and commercial operation is
currently scheduled for the Summer of 2002. Pinnacle West Energy is
evaluating initially constructing Redhawk Units 3 and 4 as
simple-cycle units, to be converted to combined-cycle units at a later
date.
* Pinnacle West Energy is also constructing an 80 MW simple-cycle power
plant at Saguaro in Southern Arizona. Commercial operation is
currently scheduled for the Summer of 2002.
* Pinnacle West Energy plans to develop 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. The
Company has signed a memorandum of understanding with Las Vegas-based
Southern Nevada Water Authority for them to be a 25-percent owner of
the plant.
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
-22-
feasibility study is in progress to determine if the proposed acreage can
support a natural gas storage cavern. Results are expected by the end of 2001.
13. El Dorado Partnership Investment Income
Net other income has consisted primarily of El Dorado's share in 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 investment. 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.
14. California Energy Market Issues and Refunds in the Pacific Northwest
We are closely monitoring developments in the California energy market and
the potential impact of those 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; APS Energy Services' retail transactions
involving SCE and PG&E; and power marketing exposures. Based on our current
evaluations, we have reserved $10 million before income taxes for our credit
exposure related to the California energy situation. 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, 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 FERC after
the California ISO provides necessary historical data. FERC also ordered an
evidentiary proceeding to discuss and evaluate possible refunds for the Pacific
Northwest. The Administrative Law Judge at 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 FERC Commissioners. Although 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 will have a material adverse impact on our financial position,
results of operations or liquidity.
15. Legal Proceedings
SunCor is a party to a lawsuit pending in Maricopa County, Arizona,
Superior Court entitled SUNCOR DEVELOPMENT COMPANY V. BERGSTROM CORPORATION, CV
98-11472. On March 15, 2001, a jury returned a verdict against SunCor in the
amount of $28.6 million, $25.7 million of which represents a punitive damage
award. 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. SunCor believes that the verdict is neither supported
by the evidence or the law and has filed post-trial motions to that effect and,
if necessary, will appeal. On September 27, 2001, the Court denied SunCor's
motions for a new trial and for a reduction of the compensatory damage award,
but ruled that it was not
-23-
yet in a position to rule on the amount of the punitive damages award and
requested additional information from the parties on this issue. We do not
expect this litigation to have a material adverse impact on our financial
position, results of operations or liquidity.
16. Power Service Agreement
By letter dated March 7, 2001, Citizens 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. 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.
17. 2001 Generation Summer Reliability Program
We recently added over 500 MW of generating capability to enhance
reliability for the summer of 2001 in light of market conditions in the western
United States. The additional capacity included the 120 MW West Phoenix Unit 4
(see Note 12) and approximately 200 MW of gas-fired portable generators leased
for the summer of 2001 by Pinnacle West Energy. Additionally, APS restored
approximately 100 MW of previously mothballed gas-fired steam units at the West
Phoenix Power Plant and refurbished the entire fossil plant fleet during the
spring of 2001 (which resulted in additional capability of approximately 110
MW).
-24-
SUPPLEMENTAL ITEM. SELECTED CONSOLIDATED DATA
Three Months Ended Nine Months Ended Twelve Months Ended
September 30, September 30, September 30,
---------------------- ---------------------- ----------------------
2001 2000 2001 2000 2001 2000
--------- --------- --------- --------- --------- ---------
ELECTRIC OPERATING REVENUES
(dollars in millions)
Retail
Residential $ 328 $ 324 $ 735 $ 708 $ 907 $ 872
Business 276 275 733 724 945 940
--------- --------- --------- --------- --------- ---------
Total retail 604 599 1,468 1,432 1,852 1,812
Sales for resale 816 934 2,025 1,188 2,432 1,292
Transmission for others 9 4 19 11 22 13
Miscellaneous services 102 31 187 103 190 117
--------- --------- --------- --------- --------- ---------
Net electric operating
revenues $ 1,531 $ 1,568 $ 3,699 $ 2,734 $ 4,496 $ 3,234
========= ========= ========= ========= ========= =========
ELECTRIC SALES (GWh)
Retail
Residential 3,597 3,506 8,187 7,753 10,215 9,633
Business 3,724 3,674 9,993 9,790 12,957 12,722
--------- --------- --------- --------- --------- ---------
Total retail 7,321 7,180 18,180 17,543 23,172 22,355
Sales for resale 5,692 10,144 14,654 17,004 19,162 20,513
--------- --------- --------- --------- --------- ---------
Total sales 13,013 17,324 32,834 34,547 42,334 42,868
========= ========= ========= ========= ========= =========
POWER PLANT PERFORMANCE
(capacity factors)
Nuclear 97% 98% 92% 94% 91% 93%
Coal 85% 88% 84% 83% 84% 83%
Gas and Oil 38% 40% 46% 24% 39% 23%
ELECTRIC CUSTOMERS
(end of period)
Retail
Residential 776,000 750,918
Business 99,339 95,165
--------- ---------
Total retail 875,339 846,083
Sales for resale 66 67
--------- ---------
Total electric
customers 875,405 846,150
========= =========
BOOK VALUE PER SHARE
(end of period) $ 29.37 $ 28.01
Additional operating statistics for the periods ended September 30, 2001 and
September 30, 2000 are available on the Company's website and in a Form 8-K
Report dated October 18, 2001.
-25-
PINNACLE WEST CAPITAL CORPORATION
ITEM 2. 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 and our subsidiaries: APS, Pinnacle
West Energy, APS Energy Services, SunCor, and El Dorado, including:
* the changes in our earnings for the three, nine and twelve months
ended September 30, 2001 and 2000;
* the effects of regulatory agreements on our results and outlook;
* our capital needs and resources;
* major factors that affect our financial outlook; and
* our management of market risks.
We suggest this section be read along with the 2000 10-K. Throughout this
Management's Discussion and Analysis of Financial Condition and Results of
Operations, we refer to specific "Notes" in the Notes to Condensed Consolidated
Financial Statements in this report. These Notes add further details to the
discussion.
OVERVIEW OF OUR BUSINESS
Pinnacle West owns all of the outstanding common stock of APS. APS is
Arizona's largest electric utility and provides retail and wholesale electric
service to the entire state with the exception of Tucson and about one-half of
the Phoenix area. APS also generates and, directly or through our power
marketing division, sells and delivers electricity to wholesale customers in the
western United States.
Our other major subsidiaries are wholly-owned and are:
* Pinnacle West Energy, through which we intend to conduct our
unregulated generation operations;
* APS Energy Services, which sells energy and energy-related products
and services in competitive retail markets in the western United
States;
* SunCor, which is a developer of residential, commercial, and
industrial real estate projects in Arizona, New Mexico, and Utah; and
* El Dorado, which is an investment firm.
-26-
We have two principal business segments, determined by products, services,
and regulatory environment:
* The electricity delivery business segment, which consists of the
transmission and distribution of electricity activities; and
* The generation business segment, which consists of our generation,
wholesale and power trading activities.
See "Business Segments" in Note 8 for more information about our business
segments.
OPERATING RESULTS
The following table summarizes net income for the three, nine and twelve
months ended September 30, 2001 and the comparable prior year periods for
Pinnacle West and each of its subsidiaries (dollars in millions):
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
--------------- --------------- ---------------
2001 2000 2001 2000 2001 2000
----- ----- ----- ----- ----- -----
APS $ 108 $ 124 $ 242 $ 253 $ 296 $ 288
Pinnacle West Energy 13 (1) 14 (2) 14 (1)
APS Energy Services (3) -- (10) (4) (19) (8)
SunCor 2 2 3 8 6 11
El Dorado -- (9) -- 7 (5) 18
Parent Company(a) 42 -- 42 (2) 42 (3)
----- ----- ----- ----- ----- -----
Income before accounting change 162 116 291 260 334 305
Cumulative effect of a change
in accounting - net of income
taxes (12) -- (15) -- (15) --
----- ----- ----- ----- ----- -----
Net income $ 150 $ 116 $ 276 $ 260 $ 319 $ 305
===== ===== ===== ===== ===== =====
----------
(a) The 2001 amount primarily includes power trading activities.
OPERATING RESULTS - THREE-MONTH PERIOD ENDED SEPTEMBER 30, 2001 COMPARED
WITH THREE-MONTH PERIOD ENDED SEPTEMBER 30, 2000
Our consolidated net income for the three months ended September 30, 2001
was $150 million compared with $116 million for the same period in the prior
year. In July 2001, we recognized a $12 million after-tax loss in net income as
a cumulative effect of a change in accounting for derivatives as required by
SFAS No. 133. See Note 10 for further discussion.
Income before accounting change for the three months ended September 30,
2001 was $162 million compared with $116 million for the same period in the
prior year. The major factors that increased (decreased) income before
accounting change were as follows (dollars in millions):
-27-
Increase/
(Decrease)
----------
Increased margin on structured power trading activities $ 52
Increased margin on power marketing, other trading and
wholesale activities 33
Higher margin from retail sales 5
Retail price reductions (9)
Higher replacement power costs on plant outages (6)
SFAS No. 133 accounting adjustment 17
--------
Increase in revenues, net of purchased power and fuel expense 92
Higher operations and maintenance expense primarily related to
generation summer reliability program (37)
Higher other income primarily related to El Dorado 13
Miscellaneous items, net 8
--------
Net increase in income before income taxes 76
Higher income taxes primarily due to higher income (30)
--------
Net increase in income before accounting change $ 46
========
Electric operating revenues decreased approximately $37 million primarily
because of:
* change in power marketing, trading and wholesale revenues ($42 million, net
decrease):
* increased trading revenues related to structured power trading
activities ($128 million);
* decreased wholesale revenues primarily related to generation sales
other than for Native Load ($2 million);
* decreased power marketing revenues related to other trading and other
wholesale activities ($168 million);
* increased retail revenues primarily related to higher sales volumes due to
weather impacts and customer growth, partially offset by lower average
usage per customer ($14 million); and
* decreased retail revenues related to the reduction in retail electricity
prices ($9 million). See Note 6 for information on the price reductions.
Purchased power and fuel expenses decreased approximately $129 million
primarily because of:
* changes related to power marketing, trading and wholesale sales ($127
million, net decrease):
* increased trading costs related to structured power trading activities
($76 million);
* decreased costs related to generation other than Native Load ($5
million);
* decreased power marketing costs related to other trading and other
wholesale activities ($198 million);
* decreased costs for a SFAS No. 133 adjustment related to changes in
electricity and gas market prices ($17 million). See Note 10 for additional
information on SFAS No. 133;
* increased costs related to higher retail sales volumes and associated
higher purchased power and fuel prices ($9 million); and
* higher replacement power costs primarily for increased plant outages ($6
million).
-28-
The increase in operations and maintenance expenses of $37 million
primarily related to the generation summer reliability program (the addition of
approximately 500 MW of generating capability to enhance reliability for the
summer of 2001, particularly the leasing of gas-fired portable generators) ($29
million) and other costs ($8 million). See Note 17 for additional information on
the generation summer reliability program.
Depreciation and amortization decreased $6 million primarily because of
lower regulatory asset amortization.
Net other income increased $13 million primarily because of a change in the
market value of El Dorado's investment in a technology-related venture capital
partnership in the prior-year period (see Note 13).
Interest expense decreased by $6 million primarily because of increased
capitalized interest resulting from our generation expansion plan. See Note 12
for additional information on the generation expansion plan.
OPERATING RESULTS - NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2001 COMPARED
WITH NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2000
Our consolidated net income for the nine months ended September 30, 2001
was $276 million compared with $260 million for the same period in the prior
year. In 2001, we recognized a $15 million after-tax loss in net income as a
cumulative effect of a change in accounting for derivatives, as required by SFAS
No. 133. See Note 10 for further discussion.
Income before accounting change for the nine months ended September 30,
2001 was $291 million compared with $260 million for the same period in the
prior year. The major factors that increased (decreased) income before
accounting change were as follows (dollars in millions):
Increase/
(Decrease)
----------
Increased margin on generation sales other than Native Load $ 118
Increased margin on power marketing, other trading and
wholesale activities 80
Increased margin on structured power trading activities 52
Lower margin from retail sales (10)
Retail price reductions (22)
SFAS No. 133 accounting adjustments 9
Higher replacement power costs for plant outages (94)
--------
Increase in revenues, net of purchased power and fuel expense 133
Higher operations and maintenance expenses primarily related to
generation and other costs (77)
Lower other income primarily related to El Dorado (13)
Miscellaneous items, net 9
--------
Net increase in income before income taxes 52
Higher income taxes primarily due to higher income (21)
--------
Net increase in income before accounting change $ 31
========
-29-
Electric operating revenues increased approximately $964 million primarily
because of:
* change in power marketing, trading and wholesale revenues ($928 million,
net increase):
* increased trading revenues related to structured power trading
activities ($128 million);
* increased wholesale revenues primarily related to generation sales
other than for Native Load ($182 million);
* increased power marketing revenues related to other trading and other
wholesale activities ($618 million);
* increased retail revenues primarily related to higher sales volumes due to
weather impacts and customer growth, partially offset by lower average
usage per customer ($58 million); and
* decreased retail revenues related to reductions in retail electricity
prices ($22 million). See Note 6 for information on the price reductions.
Purchased power and fuel expenses increased approximately $831 million
primarily because of:
* changes related to power marketing, trading and wholesale sales ($678
million, net increase):
* increased trading costs related to structured power trading activities
($76 million);
* increased costs related to generation other than Native Load ($64
million);
* increased power marketing costs related to other trading and other
wholesale activities ($538 million);
* higher replacement power costs primarily for increased plant outages ($94
million), including costs of $12 million related to the Palo Verde outage
extension to replace fuel control element assemblies;
* increased costs related to higher retail sales volumes and associated
higher purchased power and fuel prices ($68 million); and
* decreased costs related to SFAS No. 133 adjustments related to changes in
electricity and gas market prices ($9 million). See Note 10 for additional
information on SFAS No. 133.
The increase in operations and maintenance expenses of $77 million
primarily related to the generation summer reliability program (the addition of
approximately 500 MW of generating capability to enhance reliability for the
summer of 2001) and increased power plant maintenance ($56 million), increased
pension and other costs ($16 million) and a provision for credit exposure
related to the California energy situation ($5 million). See Note 17 for
additional information on the generation summer reliability program. See Note 14
for additional information related to the California energy situation.
Depreciation and amortization decreased $7 million primarily because of
lower regulatory asset amortization.
Net other income decreased by $13 million primarily because of a change in
the market value of El Dorado's investment in a technology-related venture
capital partnership
-30-
in the prior year period (see Note 13) and other non-operating costs, partially
offset by an insurance recovery of environmental remediation costs.
Interest expense decreased by $16 million primarily because of increased
capitalized interest resulting from our generation expansion plan. See Note 12
for additional information on the generation expansion plan.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 2001 COMPARED
WITH TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 2000
Our consolidated net income for the twelve months ended September 30, 2001
was $319 million compared with $305 million for the same period in the prior
year. In 2001, we recognized a $15 million after-tax loss in net income as a
cumulative effect of a change in accounting for derivatives, as required by SFAS
No.133. See Note 10 for further discussion.
Income before accounting change for the twelve months ended September 30,
2001 was $334 million compared with $305 million for the same period in the
prior year. The major factors that increased (decreased) income before
accounting change were as follows (dollars in millions):
Increase/
(Decrease)
----------
Increased margin on generation sales other than Native Load $ 163
Increased margin on power marketing, other trading and
wholesale activities 83
Increased margin on structured power trading activities 52
Retail price reductions (27)
Lower margin from retail sales (13)
SFAS 133 accounting adjustments 9
Higher replacement power costs for plant outages (116)
--------
Increase in revenues, net of purchased power and fuel expense 151
Higher operations and maintenance expense primarily related to
generation and other costs (68)
Lower other income primarily related to El Dorado (39)
Miscellaneous items, net 11
--------
Net increase in income before income taxes 55
Higher income taxes primarily due to higher income (26)
--------
Net increase in income before accounting change $ 29
========
Electric operating revenues increased approximately $1.26 billion because
of:
* change in power marketing, trading and wholesale revenues ($1.22 billion,
net increase):
* increased trading revenues related to structured power trading
activities ($128 million);
* increased wholesale revenues primarily related to generation sales
other than for Native Load ($269 million);
* increased power marketing revenues related to other trading and other
wholesale activities ($825 million);
-31-
* increased retail revenues primarily related to higher sales volumes due to
weather impacts and customer growth, partially offset by lower average
usage per customer ($67 million); and
* decreased retail revenues related to the reduction in retail electricity
prices ($27 million). See Note 6 for information on the price reductions.
Purchased power and fuel expenses increased approximately $1.11 billion
primarily because of:
* changes related to power marketing, trading and wholesale sales ($924
million, net increase):
* increased trading costs related to structured power trading activities
($76 million);
* increased costs related to generation other than Native Load ($106
million);
* increased power marketing costs related to other trading and other
wholesale activities ($742 million);
* higher replacement power costs primarily for increased plant outages ($116
million), including costs of $12 million related to the Palo Verde outage
extension to replace fuel control element assemblies;
* higher costs related to retail sales volumes and associated purchased power
and fuel prices ($80 million); and
* decreased costs for SFAS No. 133 adjustments related to changes in
electricity and gas market prices ($9 million). See Note 10 for additional
information on SFAS No. 133.
The increase in operations and maintenance expenses of $68 million
primarily related to generation summer reliability programs (the addition of
approximately 500 MW of generating capability to enhance reliability for the
summer of 2001) and increased power plant maintenance ($61 million), increased
pension and other costs ($10 million), and provisions for credit exposure
related to the California energy situation ($10 million), partially offset by
approximately $13 million of non-recurring items recorded in the fourth quarter
of 1999. See Note 17 for information on the generation summer reliability
program. See Note 14 for additional information related to the California energy
situation.
Net other income decreased $39 million primarily because of a change in the
market value of El Dorado's investment in a technology-related venture capital
partnership in the prior year period (see Note 13) and other non-operating costs
offset by an insurance recovery of environmental remediation costs.
Interest expense decreased by $19 million primarily because of increased
capitalized interest resulting from our generation expansion plan. See Note 12
for additional information on the generation expansion plan.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL EXPENDITURE REQUIREMENTS
The following table summarizes the actual capital expenditures for the nine
months ended September 30, 2001 and estimated capital expenditures for the next
three years:
-32-
CAPITAL EXPENDITURES
(dollars in millions)
(actual) (estimated)
----------------- --------------------------------
Nine-months ended Years ending
September 30, December 31,
2001 2001 2002 2003
-------- -------- -------- --------
APS
Delivery $ 256 $ 340 $ 333 $ 305
Existing generation (a) 84 121 154 --
-------- -------- -------- --------
Subtotal 340 461 487 305
-------- -------- -------- --------
Pinnacle West Energy
Generation expansion (b) 333 527 368 336
Existing generation (a) -- -- -- 119
-------- -------- -------- --------
Subtotal 333 527 368 455
-------- -------- -------- --------
SunCor (c) 45 84 66 27
-------- -------- -------- --------
Other (d) 18 24 15 8
-------- -------- -------- --------
Total $ 736 $ 1,096 $ 936 $ 795
======== ======== ======== ========
----------
(a) Pursuant to the 1999 Settlement Agreement, APS is required to move its
generating assets and competitive services no later than December 31, 2002.
(b) See Note 12 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.
(d) Primarily APS Energy Services.
CAPITAL RESOURCES AND DEBT FINANCING
PINNACLE WEST
The parent company's cash requirements and its ability to fund those
requirements are discussed under "Capital Needs and Resources" in Management's
Discussion and Analysis of Financial Condition and Results of Operation in Part
II, Item 7 of the 2000 10-K.
During the nine-months ended September 30, 2001, the parent company
increased its outstanding indebtedness by about $400 million. During the
nine-month period ended September 30, 2001, the parent company issued $550
million in long-term debt and $122 million in short-term borrowings and repaid
$275 million of long- and short-term debt. The majority of these borrowings were
used to fund Pinnacle West Energy capital expenditures.
APS
APS' long-term debt redemption requirements, including optional repayments
on long-term debt are: $384 million in 2001; $125 million in 2002; and zero in
2003. During 2001, APS expects to satisfy its long-term debt redemption
requirements with cash from operations and long and short-term borrowings.
Through September 2001, APS redeemed
-33-
$62 million of its long-term debt. APS has also deposited $72 million, plus
interest, with the trustee for redemption in December 2001 of its First Mortgage
Bonds, 9% Series due 2021. On October 5, 2001, APS issued $400 million of 6.375%
Notes due 2011. Based on market conditions and optional call provisions, APS may
make optional redemptions of long-term debt from time to time.
Although provisions in APS' first mortgage bond indenture, articles of
incorporation, and ACC financing orders establish maximum amounts of additional
first mortgage bonds and preferred stock that APS may issue, APS does not expect
any of these provisions to limit its ability to meet its capital requirements.
PINNACLE WEST ENERGY
See Note 12 of Notes to Condensed Consolidated Financial Statements for a
discussion of construction and financing programs relating to Pinnacle West
Energy.
OTHER SUBSIDIARIES
SunCor and El Dorado each fund all of their cash requirements with cash
from operations and, in the case of SunCor, its own external financings. APS
Energy Services funds its cash requirements with cash infusions from the parent
company.
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 for the nine months
ended September 30, 2001 and projected capital expenditures through 2003. SunCor
expects to fund its capital requirements from internally generated cash and its
own external financings.
El Dorado intends to focus on the realization of the value of its existing
investments and does not have any capital requirements over the next three
years. El Dorado's future investments are expected to be limited to
opportunities related to the energy sector.
BUSINESS OUTLOOK
This section describes several major factors affecting our financial
outlook.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See "Business Outlook - Competition and Industry Restructuring" in Item 7
of the 2000 10-K and Note 6 above for a discussion of developments affecting
retail and wholesale electric competition. See Note 5 for a discussion of
regulatory accounting.
GENERATION EXPANSION
See Note 12 for information regarding our generation expansion plans. The
planned additional generation is expected to increase revenues, fuel expenses,
operating expenses, and financing costs.
-34-
CALIFORNIA ENERGY MARKET ISSUES AND REFUNDS IN THE PACIFIC NORTHWEST
See Note 14 for information regarding California energy market issues and
possible Pacific Northwest refunds.
FACTORS AFFECTING OPERATING REVENUES
Electric operating revenues are derived from sales of electricity in
regulated retail markets in Arizona and in 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 4.1% a year for
the three years 1998 through 2000; we currently expect customer growth to
average 3% to 4% a year for 2001 through 2003. We currently estimate that retail
electricity sales in kilowatt-hours will grow 3% to 4.5% a year in 2001 through
2003, 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.
Wholesale activities will be affected by electricity prices and costs of
available fuel and purchased power in the western United States, as well as
competitive market conditions and regulatory and legislative changes in various
state and federal jurisdictions, including the price mitigation plan adopted by
FERC in June 2001 (see Note 6). These factors have significantly affected our
trading and wholesale power activities and their resultant earnings
contributions over the last several years. We cannot predict future
contributions from trading and wholesale activities. See Note 10 and Item 3
below for additional information.
Competitive sales of energy and energy-related products and services are
made by APS Energy Services in western states that have opened to competitive
supply. Such activities are currently 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, and our hedging program for
managing such costs. See "Natural Gas Supply" in Part II for additional
information on gas transportation costs.
Operations and maintenance expenses are expected to be affected by sales
mix and volumes, power plant operations, inflation, and other factors.
-35-
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 5 for the
regulatory asset amortization that is being recorded in 1999 through 2004
pursuant to the 1999 Settlement Agreement.
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. We expect property taxes to increase primarily due to our
generation expansion program and our additions to existing facilities.
Interest expense is affected by the amount of debt outstanding and the
interest rates on that debt. The primary factors affecting borrowing levels in
the next several years are expected to be our generation expansion program and
our internally generated cash flow.
The annual earnings contribution from our real estate subsidiary, SunCor,
is expected to remain modest over the next several years.
El Dorado's historical results are not necessarily indicative of future
performance for El Dorado. See Note 13 for additional information regarding El
Dorado. El Dorado's strategies focus on realization of the value of its existing
investments. Any future investments are expected to be related to the energy
business.
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 Note 10 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.
RATE MATTERS
See Note 6 for a discussion of a price reduction effective as of July 1,
2001, and for a discussion of the 1999 Settlement Agreement that will, among
other things, result in five annual price reductions over a four-year period
ending July 1, 2003.
FORWARD-LOOKING STATEMENTS
This document 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; the outcome of regulatory and
legislative proceedings relating to the restructuring; state and federal
regulatory and
-36-
legislative decisions and actions, including the price mitigation plan adopted
by FERC in June 2001; regional economic and market conditions, including the
California energy situation, 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 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.
ITEM 3. MARKET RISKS
Our operations include managing market risks related to changes in
commodity prices, interest rates, and investments held by our nuclear
decommissioning trust fund.
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 our 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 these
derivative transactions to ensure that we have enough energy for our customers
and limit our exposure to volatile wholesale prices for power and fuel. In
addition, we engage in trading activities intended to profit from favorable
movements of market prices.
As of September 30, 2001, a hypothetical adverse price movement of 10% in
the market price of our commodity derivative portfolio would decrease the fair
market value of these contracts by approximately $20 million. This analysis does
not include the favorable impact this same hypothetical price move would have on
the underlying physical exposures being hedged with the commodity derivative
portfolio. We plan to complete the move of our wholesale power marketing and
trading activities from APS to the parent company by the end of 2002.
We are exposed to credit losses in the event of non-performance or
non-payment by counterparties. We use a credit management process to assess and
monitor the financial exposure of counterparties. Despite the fact that the
great majority of our trading counterparties are rated as investment grade by
the credit rating agencies, there is still a possibility that one or more of
these companies could default, resulting in a material impact on consolidated
earnings for a given period.
Changing interest rates will affect interest paid on variable-rate debt and
interest earned by our nuclear decommissioning trust fund. Our policy is to
manage interest rates through the use of a combination of fixed-rate and
floating-rate debt. The nuclear decommissioning fund also has risks associated
with changing market values of equity investments. Nuclear decommissioning costs
are recovered in regulated electricity prices.
-37-
PART II - OTHER INFORMATION
ITEM 5. OTHER INFORMATION
CONSTRUCTION AND FINANCING PROGRAMS
See "Liquidity and Capital Resources" in Part I, Item 2 of this report for
a discussion of construction and financing programs of the Company and its
subsidiaries.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
RETAIL. See Note 6 of Notes to Condensed Consolidated Financial Statements
in Part I, Item 1 of this report for a discussion of competition and the rules
regarding the introduction of retail electric competition in Arizona and a
settlement agreement with the ACC.
WHOLESALE. On October 16, 2001, APS and other owners of electric
transmission lines in the Southwest filed with FERC a request for a declaratory
order confirming that their proposal to form WestConnect would satisfy FERC's
requirements for the formation of a regional transmission organization. APS and
the other filing parties have agreed to fund the start-up of WestConnect's
operations, which are projected to begin in 2004, subject to FERC approval.
WestConnect has been structured as a for-profit RTO and evolved from DesertSTAR,
a non-profit corporation in which APS participated, which was originally
designed to serve as an RTO for the southwestern United States.
ENVIRONMENTAL MATTERS
The Arizona Department of Environmental Quality issued to APS Notices of
Violation, dated September 25, 2001 and October 15, 2001 alleging, among other
things, burning of unauthorized materials and storage of hazardous waste without
a permit. Each Notice of Violation requires APS to achieve and document
compliance with specific environmental requirements. Although ADEQ may still
seek civil penalties or take other enforcement action against APS, APS does not
expect these matters to have a material adverse effect on its financial
position, results of operations, or liquidity.
NATURAL GAS SUPPLY
The gas supply for APS and Pinnacle West Energy gas-fired facilities
located, and to be located (see Note 12), in Pinal, Maricopa and Yuma Counties
in Arizona, is transported pursuant to a firm, Full Requirements Transportation
Service Agreement with El Paso Natural Gas Company. The transportation agreement
features a 10 year rate moratorium established in a comprehensive rate case
settlement entered into in 1996.
In a pending FERC proceeding, El Paso has proposed allocating its gas
pipeline capacity in such a way that APS' (and other companies' with the same
contract type) gas transportation rights could be significantly impacted.
Various parties, including APS and Pinnacle West Energy, have challenged this
allocation as being inconsistent with El Paso's existing contractual obligations
and the 1996 settlement. At this time, there are ongoing discussions among FERC,
El Paso and other affected parties to resolve these issues. We cannot currently
predict the outcome of this matter.
-38-
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit No. Description
----------- -----------
12.1 Ratio of Earnings to Fixed Charges
In addition, the Company hereby incorporates the following Exhibits
pursuant to Exchange Act Rule 12b-32 and Regulation ss.229.10(d) by reference to
the filings set forth below:
ORIGINALLY FILED DATE
EXHIBIT NO. DESCRIPTION AS EXHIBIT: FILE NO.(a) EFFECTIVE
----------- ----------- ----------- ----------- ---------
3.1 Articles of Incorporation 19.1 to the Company's 1-8962 11-14-88
restated as of July 29, September 30, 1988
1988 Form 10-Q Report
3.2 Bylaws, amended as of 4.1 to the Company's 1-8962 1-20-00
December 15, 1999 Registration Statement
on Form S-8 No. 333-95035
(b) Reports on Form 8-K
During the quarter ended September 30, 2001, and the period from October 1
through November 5, 2001, we filed the following reports on Form 8-K:
Report dated September 26, 2001 containing Regulation FD disclosure
regarding operating statistics and market, weather, and economic indicators.
Report dated October 22, 2001 containing Regulation FD disclosure relating
to written materials to be presented at an analyst conference on October 23,
2001.
Report dated October 18, 2001 regarding (i) financial information for the
periods ended September 30, 2001 and 2000; (ii) the Arizona Supreme Court's
decision to review a lower court decision affirming the 1999 Settlement
Agreement; (iii) APS' October 18, 2001 filing with the ACC requesting ACC
approval of a rule variance and a purchase power agreement with the Company; and
(iv) Regulation FD disclosure relating to operating statistics and market,
weather, and economic indicators.
----------
(a) Reports filed under File No. 1-8962 were filed in the office of the
Securities and Exchange Commission located in Washington, D.C.
-39-
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 thereunto duly authorized.
PINNACLE WEST CAPITAL CORPORATION
(Registrant)
Dated: November 5, 2001 By: Chris N. Froggatt
------------------------------------
Chris N. Froggatt
Vice President and Controller
(Principal Accounting Officer
and Officer Duly Authorized
to sign this Report)