Document/Exhibit Description Pages Size
1: 10-Q Quarterly Report for the Qtr Ended 03/31/2002 43 179K
2: EX-4.1 Amendment to Rights Agreement 2 13K
3: EX-10.1 Amendment No 5 - Decommissioning Trust Agr Unit 2 5 18K
4: EX-10.2 Amendment No 3 Decommissioning Trust Agr Unit 1 8 25K
5: EX-10.3 Amendment No 6 Decommissioning Trust Agr Unit 2 9 31K
6: EX-10.4 Amendment No 3 Decommissioning Trust Agr Unit 3 7 25K
7: EX-12.1 Ratio of Earnings to Fixed Charges 1 6K
Securities and Exchange Commission
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended March 31, 2002
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 May 10, 2002: 84,806,733
GLOSSARY
ACC - Arizona Corporation Commission
ACC Staff - Staff of the Arizona Corporation Commission
APS - Arizona Public Service Company, a subsidiary of the Company
APSES - APS Energy Services Company, Inc., a subsidiary of the Company
CC&N - Certificate of Convenience and Necessity
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
ERMC - Energy Risk Management Committee
FASB - Financial Accounting Standards Board
FERC - United States Federal Energy Regulatory Commission
Four Corners - Four Corners Power Plant
GAAP - Generally accepted accounting principles in the United States
GCVTC - Grand Canyon Visibility Transport Commission
ISO - California Independent System Operator
MW - megawatt, one million watts
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
Pinnacle West Energy - Pinnacle West Energy Corporation, a subsidiary of the
Company
PX - California Power Exchange
Rules - ACC retail electric competition rules
SFAS - Statement of Financial Accounting Standards
SNWA - Southern Nevada Water Authority
SPE - special purpose entity
SunCor - SunCor Development Company, a subsidiary of the Company
T&D - transmission and distribution
2001 10-K - Pinnacle West Capital Corporation Annual Report on Form 10-K for the
fiscal year ended December 31, 2001
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(in thousands, except per share amounts)
[Enlarge/Download Table]
Three Months Ended March 31,
----------------------------
2002 2001
--------- ---------
Operating Revenues
Electric $ 579,772 $ 906,494
Real estate 41,185 32,335
--------- ---------
Total 620,957 938,829
--------- ---------
Operating Expenses
Purchased power and fuel 221,036 516,424
Operations and maintenance 117,430 125,250
Real estate operations 37,358 31,008
Depreciation and amortization 99,913 104,781
Taxes other than income taxes 26,758 25,303
--------- ---------
Total 502,495 802,766
--------- ---------
Operating Income 118,462 136,063
--------- ---------
Other Income (Expense) 1,088 (738)
--------- ---------
Interest Expense
Interest charges 44,688 42,749
Capitalized interest (14,123) (10,427)
--------- ---------
Total 30,565 32,322
--------- ---------
Income Before Income Taxes 88,985 103,003
Income Taxes 35,228 40,798
--------- ---------
Income Before Accounting Change 53,757 62,205
Cumulative Effect of a Change in Accounting for Derivatives
- Net of Income Tax Benefit of $1,793 -- (2,755)
--------- ---------
Net Income $ 53,757 $ 59,450
========= =========
Weighted-Average Common Shares Outstanding - Basic 84,735 84,727
Weighted-Average Common Shares Outstanding - Diluted 84,884 84,966
Earnings Per Weighted-Average Common Share Outstanding
Income Before Accounting Change - Basic $ 0.63 $ 0.73
Net Income - Basic 0.63 0.70
Income Before Accounting Change - Diluted 0.63 0.73
Net Income - Diluted 0.63 0.70
Dividends Declared Per Share $ 0.40 $ 0.375
See Notes to Condensed Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(in thousands, except per share amounts)
[Enlarge/Download Table]
Twelve Months Ended March 31,
-----------------------------
2002 2001
----------- -----------
Operating Revenues
Electric $ 4,055,743 $ 3,992,076
Real estate 177,758 148,811
----------- -----------
Total 4,233,501 4,140,887
----------- -----------
Operating Expenses
Purchased power and fuel 2,368,830 2,323,784
Operations and maintenance 522,275 465,006
Real estate operations 159,812 132,610
Depreciation and amortization 423,035 433,553
Taxes other than income taxes 102,523 99,691
----------- -----------
Total 3,576,475 3,454,644
----------- -----------
Operating Income 657,026 686,243
----------- -----------
Other Income (Expense) (3,939) (36,635)
----------- -----------
Interest Expense
Interest charges 177,761 169,697
Capitalized interest (51,558) (28,216)
----------- -----------
Total 126,203 141,481
----------- -----------
Income Before Income Taxes 526,884 508,127
Income Taxes 207,965 197,660
----------- -----------
Income Before Accounting Change 318,919 310,467
Cumulative Effect of Change in Accounting for Derivatives
- Net of Income Tax Benefits of $8,099 and $1,793 (12,446) (2,755)
----------- -----------
Net Income $ 306,473 $ 307,712
=========== ===========
Weighted-Average Common Shares Outstanding - Basic 84,719 84,732
Weighted-Average Common Shares Outstanding - Diluted 84,910 84,974
Earnings Per Weighted-Average Common Share Outstanding
Income Before Accounting Change - Basic $ 3.76 $ 3.66
Net Income - Basic 3.62 3.63
Income Before Accounting Change - Diluted 3.76 3.65
Net Income - Diluted 3.61 3.62
Dividends Declared Per Share $ 1.55 $ 1.45
See Notes to Condensed Consolidated Financial Statements.
-3-
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
ASSETS
[Download Table]
March 31, December 31,
2002 2001
---------- ----------
(unaudited)
Current Assets
Cash and cash equivalents $ 20,443 $ 28,619
Trust fund for bond redemption 121,668 --
Customer and other receivables--net 313,426 367,241
Accrued utility revenues 63,708 76,131
Materials and supplies (at average cost) 79,428 81,215
Fossil fuel (at average cost) 28,334 27,023
Assets from risk management and trading activities 58,520 66,973
Other current assets 83,140 80,203
---------- ----------
Total current assets 768,667 727,405
---------- ----------
Investments and Other Assets
Real estate investments--net 427,465 418,673
Assets from risk management and trading activities -
long-term 226,482 200,351
Other assets 302,946 320,004
---------- ----------
Total investments and other assets 956,893 939,028
---------- ----------
Property, Plant and Equipment
Plant in service and held for future use 8,101,610 8,030,134
Less accumulated depreciation and amortization 3,340,326 3,290,097
---------- ----------
Total 4,761,284 4,740,037
Construction work in progress 1,147,903 1,032,234
Intangible assets, net of accumulated amortization 87,201 86,782
Nuclear fuel, net of accumulated amortization 58,689 49,282
---------- ----------
Net property, plant and equipment 6,055,077 5,908,335
---------- ----------
Deferred Debits
Regulatory assets 316,800 342,383
Other deferred debits 71,007 64,597
---------- ----------
Total deferred debits 387,807 406,980
---------- ----------
Total Assets $8,168,444 $7,981,748
========== ==========
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)
[Enlarge/Download Table]
March 31, December 31,
2002 2001
----------- -----------
(unaudited)
Current Liabilities
Accounts payable $ 151,583 $ 269,124
Accrued taxes 138,464 96,729
Accrued interest 42,358 48,806
Short-term borrowings 152,300 405,762
Current maturities of long-term debt 6,885 126,140
Customer deposits 32,014 30,232
Deferred income taxes 3,244 3,244
Liabilities from risk management and trading activities 25,556 35,994
Other current liabilities 97,988 74,898
----------- -----------
Total current liabilities 650,392 1,090,929
----------- -----------
Long-Term Debt Less Current Maturities 3,264,626 2,673,078
----------- -----------
Deferred Credits and Other
Liabilities from risk management and trading activities -
long-term 184,055 207,576
Deferred income taxes 1,072,670 1,064,993
Unamortized gain - sale of utility plant 62,916 64,060
Other 384,361 381,789
----------- -----------
Total deferred credits and other 1,704,002 1,718,418
----------- -----------
Commitments and contingencies (Note 12)
Common Stock Equity
Common stock, no par value 1,533,454 1,531,038
Retained earnings 1,052,719 1,032,850
Accumulated other comprehensive loss (36,749) (64,565)
----------- -----------
Total common stock equity 2,549,424 2,499,323
----------- -----------
Total Liabilities and Equity $ 8,168,444 $ 7,981,748
=========== ===========
See Notes to Condensed Consolidated Financial Statements.
-5-
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)
Three Months Ended March 31,
----------------------------
2002 2001
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Income before accounting change $ 53,757 $ 62,205
Items not requiring cash
Depreciation and amortization 99,913 104,781
Nuclear fuel amortization 7,484 7,581
Deferred income taxes--net (10,434) (6,250)
Mark-to-market gains--trading (2,724) (52,425)
Mark-to-market gains--system (366) (1,629)
Changes in current assets and liabilities
Customer and other receivables--net 53,815 69,118
Accrued utility revenues 12,423 12,966
Materials, supplies and fossil fuel 476 (4,128)
Other current assets (2,937) 20,790
Accounts payable (117,731) (50,899)
Accrued taxes 41,735 56,567
Accrued interest (6,448) (28,933)
Other current liabilities 24,872 37,795
Increase in real estate investments (8,340) (19,789)
Increase in regulatory assets (2,096) (2,856)
Other--net (7,314) (15,685)
--------- ---------
Net Cash Flow Provided By Operating Activities 136,085 189,209
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Trust fund for bond redemption (121,668) (117,510)
Capital expenditures (219,923) (189,924)
Capitalized interest (14,123) (10,427)
Other--net 26,706 (14,747)
--------- ---------
Net Cash Flow Used For Investing Activities (329,008) (332,608)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 603,430 387,000
Short-term borrowings--net (253,462) 95,850
Dividends paid on common stock (33,888) (31,785)
Repayment of long-term debt (133,749) (184,206)
Other--net 2,416 (1,940)
--------- ---------
Net Cash Flow Provided By Financing Activities 184,747 264,919
--------- ---------
Net Cash Flow (8,176) 121,520
Cash and Cash Equivalents at Beginning of Period 28,619 10,363
--------- ---------
Cash and Cash Equivalents at End of Period $ 20,443 $ 131,883
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest, net of amounts capitalized $ 35,212 $ 57,839
Income taxes $ 30,557 $ 16,077
See Notes to Condensed Consolidated Financial Statements.
-6-
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, APSES, 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 2001 10-K.
3. Weather conditions and trading and wholesale 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. On February 8, 2002, Pinnacle West issued $215 million of 4.5% Notes due
2004. On March 1, 2002, APS issued $375 million of 6.5% Notes due 2012. As of
March 31, 2002, APS deposited $122 million, plus interest, with the trustee
under its Mortgage for the redemption in April 2002 of its First Mortgage Bonds,
8.75% Series due 2024. The above items represent the primary changes in
capitalization for the three months ended March 31, 2002.
5. Regulatory Matters
ELECTRIC INDUSTRY RESTRUCTURING
STATE
OVERVIEW. On September 21, 1999, the ACC approved Rules that provide a
framework for the introduction of retail electric competition in Arizona. On
September 23, 1999, the ACC approved a comprehensive settlement agreement among
APS and various parties related to the implementation of retail electric
competition in Arizona. Under the Rules, as modified by the 1999 Settlement
Agreement, APS is required to transfer all of its competitive electric assets
and services either to an unaffiliated party or to a separate corporate
affiliate no later than December 31, 2002. Consistent with that requirement, APS
has been addressing the legal and regulatory requirements necessary to complete
the transfer of its generation assets to Pinnacle West Energy on or before that
date.
In February 2002, the ACC opened a "generic" docket to "determine if
changed circumstances require the [ACC] to take another look at electric
restructuring in Arizona." The ACC Staff filed a report with the ACC in this
docket stating, among other things, that transfers of generation assets required
by the Rules would be "unwise" at the present time and that such transfers
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should be stayed pending the completion of the generic docket. On June 17, 2002,
ACC hearings are scheduled to begin on various issues, including APS' planned
divestiture of generation assets to Pinnacle West Energy. These regulatory
developments have raised uncertainty about the status and pace of retail
electric competition in Arizona, including APS' transfer of generation assets to
Pinnacle West Energy.
These matters are discussed in more detail below.
1999 SETTLEMENT AGREEMENT. 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 a
July 1, 1999 retail price decrease of approximately $11 million ($7
million after income taxes) related to the 1996 regulatory agreement.
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 of 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; material changes in APS'
cost of service for ACC-regulated services resulting from federal,
tribal, state or local laws; regulatory requirements; or 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
-8-
(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.
* Prior to the 1999 Settlement Agreement, APS was recovering
substantially all of its regulatory assets through July 1, 2004,
pursuant to a 1996 regulatory agreement. In addition, the 1999
Settlement Agreement states that APS has demonstrated that its
allowable stranded costs, after mitigation and exclusive of regulatory
assets, are at least $533 million net present value. APS will not be
allowed to recover $183 million net present value of the above
amounts. The 1999 Settlement Agreement provides that APS will have the
opportunity to recover $350 million net present value through a
competitive transition charge that will remain in effect through
December 31, 2004, at which time it will terminate. The costs subject
to recovery under the adjustment clause described above will be
decreased or increased by any over/under-recovery due to sales volume
variances.
* APS will form, or cause to be formed, a separate corporate affiliate
or affiliates and transfer to such affiliate(s) its competitive
electric assets and services at book value as of the date of transfer,
and will complete the transfer no later than December 31, 2002.
Consistent with that requirement, APS has been addressing the legal
and regulatory requirements necessary to complete the transfer of its
generation assets to Pinnacle West Energy on or before that date.
However, as noted above and discussed in greater detail below, the
ACC's recent establishment of a "generic" docket to consider electric
industry restructuring in Arizona could affect APS' ability to
transfer assets to Pinnacle West Energy. APS will be allowed to defer
and later collect, beginning July 1, 2004, sixty-seven percent of its
costs to accomplish the required transfer of generation assets to an
affiliate.
RETAIL ELECTRIC COMPETITION RULES. 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.
* Affected utilities must file ACC tariffs that unbundle rates for
noncompetitive services.
* The ACC shall allow a reasonable opportunity for recovery of
unmitigated stranded costs.
-9-
* Absent an ACC waiver, prior to January 1, 2001, each affected utility
(except certain electric cooperatives) must transfer all competitive
electric assets and services either to an unaffiliated party or to a
separate corporate affiliate. Under the 1999 Settlement Agreement, APS
received a waiver to allow transfer of its competitive electric assets
and services to affiliates no later than December 31, 2002.
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 November 27, 2000, a Maricopa County, Arizona, Superior Court judge
issued a final judgment holding that the Rules are unconstitutional and unlawful
in their entirety due to failure to establish a fair value rate base for
competitive electric service providers and because certain of the Rules were not
submitted to the Arizona Attorney General for certification. The judgment also
invalidates all ACC orders authorizing competitive electric service providers,
including APSES, to operate in Arizona. We do not believe the ruling affects the
1999 Settlement Agreement. The 1999 Settlement Agreement was not at issue in the
consolidated cases before the judge. Further, the ACC made findings related to
the fair value of APS' property in the order approving the 1999 Settlement
Agreement. The ACC and other parties aligned with the ACC have appealed the
ruling to the Arizona Court of Appeals, as a result of which the Superior
Court's ruling is automatically stayed pending further judicial review. In a
similar appeal concerning the issuance of competitive telecommunications CC&N's,
the Arizona Court of Appeals invalidated rates for competitive carriers due to
the ACC's failure to establish a fair value rate base for such carriers. That
telecommunications case has been appealed to the Arizona Supreme Court, where a
decision is pending.
PROVIDER OF LAST RESORT OBLIGATION. Although the Rules allow retail
customers to have access to competitive providers of energy and energy services,
APS is the "provider of last resort" for standard-offer, full-service customers
under rates that have been approved by the ACC. These rates are established
until July 1, 2004. The 1999 Settlement Agreement allows APS to seek adjustment
of these rates in the event of emergency conditions or circumstances, such as
the inability to secure financing on reasonable terms, or material changes in
APS' cost of service for ACC-regulated services resulting from federal, tribal,
state or local laws; regulatory requirements; judicial decisions, actions or
orders. Energy prices in the western wholesale market vary and, during the
course of the last two years, have been volatile. At various times, prices in
the spot wholesale market have significantly exceeded the amount included in
APS' current retail rates. In the event of shortfalls due to unforeseen
increases in load demand or generation outages, APS may need to purchase
additional supplemental power in the wholesale spot market. Unless APS is able
to obtain an adjustment of its rates under the emergency provisions of the 1999
Settlement Agreement, there can be no assurance that APS would be able to fully
recover the costs of this power.
PROPOSED RULE VARIANCE AND PURCHASE POWER AGREEMENT. Commencing on the
transfer of the fossil-fueled generating assets and the receipt of certain
regulatory approvals, Pinnacle West Energy expects to sell its power at
-10-
wholesale to Pinnacle West's marketing and trading division, which, in turn, is
expected to sell power to APS and to non-affiliated power purchasers. In a
filing with the ACC on October 18, 2001, APS requested the ACC to:
* grant APS a partial variance from an ACC Rule that would obligate APS
to acquire all of its customers' standard-offer, full-service
generation requirements from the competitive market (with at least 50%
of those requirements coming from a "competitive bidding" process)
starting in 2003; and
* approve as just and reasonable a long-term purchase power agreement
between APS and Pinnacle West.
APS requested these ACC actions to ensure ongoing reliable service to APS
standard-offer, full-service customers in a volatile generation market and to
recognize Pinnacle West Energy's significant investment to serve APS load.
GENERIC DOCKET. In February 2002, the ACC opened a "generic" docket to
"determine if changed circumstances require the [ACC] to take another look at
electric restructuring in Arizona." Also, in February 2002, the ACC docket
relating to APS' October 2001 filing was consolidated with several other pending
ACC dockets, including the generic docket. On April 19, 2002, APS filed a motion
in the consolidated docket addressing the following issues, among others:
* APS confirmed its position that whether or not the ACC approved the
matters requested in its October 2001 filing, APS would proceed with
the divestiture of its generation assets by the end of 2002.
* APS also advised the ACC that whether or not the ACC approved the
matters requested in its October 2001 filing, APS would implement a
competitive bidding process later in 2002 to the extent legally
required.
* APS noted that Pinnacle West Energy, the affiliate to which APS
intends to transfer the generation assets, had committed to a $1
billion investment in generating capacity to meet APS customer needs
in reliance on the 1999 Settlement Agreement and in accordance with an
ACC Rule that prohibited APS' ownership of new generation assets. APS
further noted that it had taken numerous actions in reliance on the
1999 Settlement Agreement and the ACC retail electric competition
rules, including writing off $234 million of prudently incurred costs,
reducing retail rates by approximately $120 million in a still-ongoing
series of rate reductions, and incurring tens of millions of dollars
in expenses related to the expected generation asset transfer. APS
stated that if the ACC elects to reverse course on retail electric
competition or attempts to stay the transfer of APS' generation
assets, the ACC would be legally required to address just compensation
to APS and Pinnacle West Energy, which would include, at a minimum:
* recognizing the transfer to APS of all assets that Pinnacle West
Energy constructed to meet APS' load-serving requirements, and
-11-
subsequently including such units in APS' rate base in accordance
with traditional rate-of-return regulation;
* reversing APS' $234 million write-off and providing for the
recovery of such amounts in future rates; and
* providing for the recovery of all costs incurred as a result of
the transition to competition, including 100 percent of the costs
incurred in preparation for divestiture (and not just the
two-thirds of costs permitted under the 1999 Settlement
Agreement).
* APS recommended that the ACC confirm whether or not Arizona would
proceed with the transition to a competitive electric market, and
proposed a procedural plan in response to issues identified by the ACC
Staff in a previous report.
On April 26, 2002, the ACC issued a procedural order in which the ACC
stayed the previously-scheduled April 29, 2002 hearing on the matters raised in
APS' October 2001 ACC filing (see "Proposed Rule Variance and Purchase Power
Agreement" above). On May 2, 2002, the ACC issued a procedural order stating
that hearings will begin on June 17, 2002 on various issues ("Track A Issues"),
including APS' planned divestiture of generation assets to Pinnacle West Energy
and associated market and affiliate issues. The procedural order stated that the
schedule is designed to have a recommended order issued by the administrative
law judge by approximately July 22, 2002, with comments on the recommended order
due from affected parties on July 31, 2002. Under this schedule, August 1, 2002
is the earliest date the ACC could consider a decision on the Track A Issues.
The procedural order also stated that consideration of the competitive
bidding process (the "Track B Issues") required by the Rules would proceed
concurrently with the Track A Issues. The objectives and process of the Track B
Issues will be determined in one or more meetings of affected parties beginning
the week of May 20, 2002, with a "target completion date" of October 21, 2002.
A modification to the Rules or the 1999 Settlement Agreement could, among
other things, adversely affect APS' ability to transfer its generation assets to
Pinnacle West Energy by December 31, 2002. Pinnacle West cannot predict the
outcome of the consolidated docket or its effect on the specific requests in
APS' October 2001 filing, the existing Arizona electric competition rules, or
the 1999 Settlement Agreement.
FEDERAL
In June 2001, the FERC adopted a price mitigation plan that constrains the
price of electricity in the wholesale spot electricity market in the western
United States. The plan remains in effect until September 30, 2002. We cannot
accurately predict the overall financial impact of the plan on the various
aspects of our business, including our wholesale and purchased power activities.
-12-
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.
6. Nuclear Insurance
The Palo Verde participants have insurance for public liability resulting
from nuclear energy hazards to the full limit of liability under federal law.
This potential liability is covered by primary liability insurance provided by
commercial insurance carriers in the amount of $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' interest
in the three Palo Verde units, APS' maximum potential assessment per incident
for all three units is approximately $77 million, with an annual payment
limitation of approximately $9 million.
The Palo Verde participants maintain "all risk" (including nuclear hazards)
insurance for property damage to, and decontamination of, property at Palo Verde
in the aggregate amount of $2.75 billion, a substantial portion of which must
first be applied to stabilization and decontamination. APS has also secured
insurance against portions of any increased cost of generation or purchased
power and business interruption resulting from a sudden and unforeseen outage of
any of the three units. The insurance coverage discussed in this and the
previous paragraph is subject to certain policy conditions and exclusions.
7. Business Segments
We have two principal business segments (determined by products, services
and regulatory environment) which consist of regulated retail electricity
business and related activities (retail business segment) and competitive
business activities (marketing and trading segment). Our retail business segment
includes activities related to electricity transmission and distribution, as
well as electricity generation. Our marketing and trading business segment
includes activities related to wholesale marketing and trading and APSES'
competitive energy services. The other amounts include activities relating to
SunCor and El Dorado. Financial data for the business segments is provided as
follows (dollars in millions):
-13-
Three Months Ended Twelve Months Ended
------------------ -------------------
March 31, March 31,
2002 2001 2002 2001
------- ------- ------- -------
Operating Revenues:
Retail $ 380 $ 413 $ 2,531 $ 2,572
Marketing and trading 200 494 1,525 1,420
Other 41 32 178 149
------- ------- ------- -------
Total $ 621 $ 939 $ 4,234 $ 4,141
======= ======= ======= =======
Income Before
Accounting Change:
Retail $ 31 $ 3 $ 179 $ 199
Marketing and trading 21 58 134 122
Other 2 1 5 (10)
------- ------- ------- -------
Total $ 54 $ 62 $ 318 $ 311
======= ======= ======= =======
As of March 31, As of December 31,
2002 2001
------ ------
Assets:
Retail $7,261 $7,077
Marketing and trading 411 417
Other 496 488
------ ------
Total $8,168 $7,982
====== ======
8. Accounting Matters
On January 1, 2002, we adopted 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 have no goodwill recorded and have separately disclosed
other intangible assets in our consolidated balance sheets. This new standard
has no material impact on our financial statements, and the required disclosures
are provided in Note 13.
On January 1, 2002, we adopted 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. This standard did not impact our financial statements
at adoption.
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.
-14-
In 2001, the American Institute of Certified Public Accountants issued an
exposure draft of a proposed Statement of Position, "Accounting for Certain
Costs Related to Property, Plant, and Equipment." This proposed Statement of
Position would create a project timeline framework for capitalizing costs
related to property, plant and equipment construction, which require that
property, plant and equipment assets be accounted for at the component level,
and require administrative and general costs incurred in support of capital
projects to be expensed in the current period. The American Institute of
Certified Public Accountants plans to issue the final Statement of Position in
the fourth quarter of 2002.
9. Off-Balance Sheet Financing
In 1986, APS entered into agreements with three separate SPE lessors in
order to sell and lease back interests in Palo Verde Unit 2. The leases are
accounted for as operating leases in accordance with GAAP. In February 2002, the
FASB discussed issues related to SPEs. It is expected that the FASB will issue
additional guidance on accounting for SPEs later this year. As a result of
future FASB actions, we may be required to consolidate the Palo Verde SPEs in
our financial statements. If consolidation is required, the assets and
liabilities of the SPEs that relate to the sale-leaseback transactions would be
reflected on our consolidated balance sheets. The SPE debt that is not reflected
on our consolidated balance sheets is approximately $300 million at March 31,
2002. Rating agencies have already considered this debt when evaluating our
credit ratings. This is the Company's only significant off-balance sheet
financing activity.
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 and credits. The changes in market value of such contracts have a
high correlation to price changes in the hedged commodity. In addition, subject
to specified risk parameters established by our Board of Directors and monitored
by our 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 sheets and measure those instruments at fair value. Changes in the fair
value of derivative financial instruments are either recognized periodically in
income or shareholders' equity (as a component of other comprehensive income),
depending on whether or not the derivative meets specific hedge accounting
criteria. We use cash flow hedges to limit our exposure to cash flow variability
on forecasted transactions. Hedge effectiveness is related to the degree to
which the derivative contract and the hedged item are correlated. It is measured
based on the relative changes in fair value between the derivative contract and
the hedged item over time. We exclude the time value of certain options from our
assessment of hedge effectiveness. Any change in the fair value resulting from
ineffectiveness is recognized immediately in net income.
-15-
On January 1, 2001, we recorded a $3 million after-tax loss in net income
and a $64 million after-tax gain in equity (as a component of other
comprehensive income), both as a cumulative effect of a change in accounting
principle. The gain resulted from unrealized gains on cash flow hedges.
In June 2001, the FASB issued new guidance related to electricity
contracts. The effective date of this new guidance was July 1, 2001. As of July
1, 2001, we recorded an additional $12 million after-tax loss in net income and
an additional $8 million after-tax gain in equity (as a component of other
comprehensive income), as a result of adopting the new guidance related to
electricity contracts. The loss resulted primarily from electricity options
contracts. The gain resulted from unrealized gains on cash flow hedges. The
impact of the new guidance is reflected in net income and other comprehensive
income as a cumulative effect of a change in accounting principle.
In December 2001, the FASB issued revised guidance on the accounting for
electricity contracts with option characteristics and the accounting for
contracts that combine a forward contract and a purchased option contract. The
effective date for the revised guidance is April 1, 2002. We are currently
evaluating the new guidance to determine what impact, if any, it will have on
our financial statements.
The change in derivative fair value included in the consolidated statements
of income for the three and twelve months ended March 31, 2002 and 2001 are
comprised of the following (dollars in thousands):
Three Months Ended Twelve Months Ended
March 31, March 31,
-------------------- --------------------
2002 2001 2002 2001
-------- -------- -------- --------
Losses on the ineffective
portion of derivatives
qualifying for hedge
accounting $ (2,548) $ (4,764) $ (6,155) $ (4,764)
Losses from the
discontinuance of cash
flow hedges for
forecasted transactions
that will not occur (899) -- (10,425) --
Prior period mark-to-
market losses realized
upon delivery of
commodities 3,813 6,393 23,368 6,393
-------- -------- -------- --------
Total pretax gain $ 366 $ 1,629 $ 6,788 $ 1,629
======== ======== ======== ========
As of March 31, 2002, the maximum length of time over which we are hedging
our exposure to the variability in future cash flows for forecasted transactions
is thirty-three months. During the twelve months ending March 31, 2003, we
estimate that a net loss of $3 million before income taxes will be reclassified
from accumulated other comprehensive loss as an offset to the effect on earnings
of market price changes for the related hedged transactions.
-16-
The following table summarizes our assets and liabilities from risk
management and trading activities related to trading and system (retail and
traditional wholesale activities) as of March 31, 2002 (dollars in thousands):
Current Current Other Net Asset/
Assets Investments Liabilities Liabilities (Liability)
--------- ----------- ----------- ----------- -----------
Mark-to-
market:
Trading $ 44,858 $ 165,479 $ (11,610) $ (57,968) $ 140,759
System 13,662 247 (13,946) (60,694) (60,731)
Cost-emission
allowances
and other -- 60,756 -- (65,393) (4,637)
--------- --------- --------- --------- ---------
Total $ 58,520 $ 226,482 $ (25,556) $(184,055) $ 75,391
========= ========= ========= ========= =========
11. Comprehensive Income
Components of comprehensive income for the three and twelve months ended
March 31, 2002 and 2001, are as follows (dollars in thousands):
[Enlarge/Download Table]
Three Months Ended Twelve Months Ended
March 31, March 31,
--------------------- ----------------------
2002 2001 2002 2001
--------- --------- --------- ---------
Net income $ 53,757 $ 59,450 $ 306,473 $ 307,712
--------- --------- --------- ---------
Other comprehensive income (losses):
Minimum pension liability, net of tax -- -- (966) --
Cumulative effect of change in
accounting for derivatives, net
of tax -- 64,700 7,777 64,700
Unrealized gains (losses) on
derivative instruments, net of
tax 26,826 (10,453) (47,161) (10,453)
Reclassification of net realized
(gains) losses to income, net of
tax 990 (16,822) (33,824) (16,822)
--------- --------- --------- ---------
Total other comprehensive income (losses) 27,816 37,425 (74,174) 37,425
--------- --------- --------- ---------
Comprehensive income $ 81,573 $ 96,875 $ 232,299 $ 345,137
========= ========= ========= =========
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12. Commitments and Contingencies
In July 2001, the FERC ordered an expedited fact-finding hearing to
calculate refunds for spot market transactions in California during a specified
time frame. This order calls for a hearing, with findings of fact due to the
FERC after the ISO and PX provide necessary historical data. The FERC also
ordered an evidentiary proceeding to discuss and evaluate possible refunds for
the Pacific Northwest. The administrative law judge at the FERC in charge of
that evidentiary proceeding made an initial finding that no refunds were
appropriate. The Pacific Northwest issues will now be addressed by the FERC
Commissioners. Although the FERC has not yet made a final ruling in the Pacific
Northwest matter or calculated the specific refund amounts due in California, we
do not expect that the resolution of these issues, as to the amounts alleged in
the proceedings, will have a material adverse impact on our financial position,
results of operations or liquidity.
On March 19, 2002, the State of California filed a complaint with the FERC
alleging that wholesale sellers of power and energy, including Pinnacle West,
failed to properly file rate information at the FERC in connection with sales to
California from 2000 to the present. STATE OF CALIFORNIA V. BRITISH COLUMBIA
POWER EXCHANGE ET. AL., Docket No. EL02-71-000. The complaint requests the FERC
to require the wholesale sellers to refund any rates that are "found to exceed
just and reasonable levels." The complaint indicates that Pinnacle West sold
approximately $106 million of power to the California Department of Water
Resources from January 17, 2001 to October 31, 2001 and does not allege any
amount above "just and reasonable levels." We believe that the claims as they
relate to Pinnacle West are without merit. In addition, the State of California
and others have filed various claims, which have now been consolidated, against
several power suppliers to California alleging antitrust violations. WHOLESALE
ELECTRICITY ANTITRUST CASES I AND II, Superior Court in and for the County of
San Diego, Proceedings Nos. 4204-00005 and 4204-00006. Two of the suppliers who
were named as defendants in those matters, Reliant Energy Services, Inc. (and
other Reliant entities) and Duke Energy Trading and Marketing, LLP (and other
Duke entities), filed cross-claims against various other participants in the
California PX and ISO markets, including APS, attempting to expand those matters
to such other participants. APS has not yet filed a responsive pleading in the
matter, but APS believes the claims by Reliant and Duke as they relate to APS
are without merit.
By letter dated March 7, 2001, Citizens, which owns a utility in Arizona,
advised APS that it believes APS has overcharged Citizens by over $50 million
under a power service agreement. APS believes that its charges under the
agreement were fully in accordance with the terms of the agreement. In addition,
in testimony filed with the ACC on March 13, 2002, Citizens acknowledged that,
based on its review, "if Citizens filed a complaint with FERC, it probably would
lose the central issue in the contract interpretation dispute." APS and Citizens
terminated the power service agreement effective July 15, 2001. In replacement
of the power service agreement, the Company and Citizens entered into a power
sale agreement under which the Company will supply Citizens with specified
amounts of electricity and ancillary services through May 31, 2008. This new
agreement does not address issues previously raised by Citizens with respect to
charges under the original power service agreement through June 1, 2001.
13. Intangible Assets
On January 1, 2002, we adopted 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." The Company's gross intangible assets (which are primarily
software) were $179 million at March 31, 2002 and $175 million at December 31,
2001. The related accumulated amortization was $92 million at March 31, 2002 and
$88 million at December 31, 2001. Amortization expense for the three-month
period ended March 31 was $4 million in 2002 compared with $5 million in 2001.
Amortization expense for the twelve-month period ended March 31 was $21 million
in 2002 and $20 million in 2001. Estimated amortization expense on existing
-18-
intangible assets over the next five years is $17 million in 2002, $16 million
in 2003, $15 million in 2004, $13 million in 2005 and $11 million in 2006.
14. Earnings Per Share
The following table presents earnings per weighted average common share
outstanding (EPS):
Three Months Ended Twelve Months Ended
March 31, March 31,
------------------ -------------------
2002 2001 2002 2001
------ ------ ------ ------
Basic EPS:
Income before accounting change $ 0.63 $ 0.73 $ 3.76 $ 3.66
Cumulative effect of change in
accounting -- (0.03) (0.14) (0.03)
------ ------ ------ ------
Earnings per share - basic $ 0.63 $ 0.70 $ 3.62 $ 3.63
====== ====== ====== ======
Diluted EPS:
Income before accounting change $ 0.63 $ 0.73 $ 3.76 $ 3.65
Cumulative effect of change in
accounting -- (0.03) (0.15) (0.03)
------ ------ ------ ------
Earnings per share - diluted $ 0.63 $ 0.70 $ 3.61 $ 3.62
====== ====== ====== ======
The following table reconciles average common shares outstanding - basic to
average common shares outstanding - diluted that are used in the EPS calculation
to the consolidated income statement (in thousands):
Three Months Ended Twelve Months Ended
March 31, March 31,
------------------ -------------------
2002 2001 2002 2001
------ ------ ------ ------
Average common shares outstanding -
basic 84,735 84,727 84,719 84,732
Diluted stock options 149 239 191 242
------ ------ ------ ------
Average common shares outstanding -
diluted 84,884 84,966 84,910 84,974
====== ====== ====== ======
-19-
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 and twelve months ended
March 31, 2002 and 2001;
* the effects of regulatory agreements on our results and outlook;
* our capital needs, liquidity and capital resources;
* our business outlook; and
* our management of market risks.
We suggest this section be read along with the 2001 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. Operating statistics for the periods ended March 31, 2002 and March
31, 2001 are available on the Company's website (www.pinnaclewest.com) and in
the Company's Current Report on Form 8-K dated March 31, 2002.
OVERVIEW OF OUR BUSINESS
Pinnacle West owns all of the outstanding common stock of APS. APS is
Arizona's largest electric utility and provides either retail or wholesale
electric service to substantially all of the state, with the major exceptions of
the Tucson metropolitan area and about one-half of the Phoenix metropolitan
area. APS also generates and, through our marketing and trading division, sells
and delivers electricity to wholesale customers in the western United States.
Our other major subsidiaries are:
* Pinnacle West Energy, through which we conduct our unregulated
electricity generation operations;
* APSES, which provides commodity energy and energy-related products to
key customers in competitive markets in the western United States;
-20-
* SunCor, a developer of residential, commercial, and industrial real
estate projects in Arizona, New Mexico, and Utah; and
* El Dorado, an investment firm.
Pinnacle West's marketing and trading division sells in the wholesale
market APS and Pinnacle West Energy generation production output that is not
needed for APS' native load, which includes loads for retail customers and
traditional cost-of-service wholesale customers. Subject to specified risk
parameters established by our Board of Directors, the marketing and trading
division also engages in activities to hedge purchases and sales of electricity,
fuels, and emissions allowances and credits and to profit from market price
movements. We explain in detail below the historical and prospective
contribution of marketing and trading activities to our financial results.
APS is required to transfer its competitive electric assets and services to
one or more corporate affiliates no later than December 31, 2002. Consistent
with that requirement, APS has been addressing the legal and regulatory
requirements necessary to complete the transfer of its generation assets to
Pinnacle West Energy before that date. As we discuss in greater detail in Note
5, recent Arizona regulatory developments have raised uncertainty about the
status and pace of retail electric competition in Arizona, including APS'
transfer of generation assets to Pinnacle West Energy.
EARNINGS CONTRIBUTIONS BY SUBSIDIARY
The following table summarizes net income for the three and twelve months
ended March 31, 2002 and the comparable prior-year periods for Pinnacle West and
each of its subsidiaries (dollars in millions):
Three Months Twelve Months
Ended Ended
March 31, March 31,
------------------- --------------------
2002 2001 2002 2001
------- ------- ------- -------
Arizona Public Service (APS) $ 32 $ 65 $ 248 $ 338
Pinnacle West Energy 1 -- 19 (2)
APS Energy Services (APSES) 2 (8) -- (20)
SunCor 2 -- 5 7
El Dorado -- 1 -- (17)
Parent Company (a) 17 4 46 5
------- ------- ------- -------
Income before accounting
change 54 62 318 311
Cumulative effect of change
in accounting - net of
income taxes -- (3) (12) (3)
------- ------- ------- -------
Net income $ 54 $ 59 $ 306 $ 308
======= ======= ======= =======
----------
(a) These amounts primarily include marketing and trading activities. APS also
includes some marketing and trading activities in 2001.
-21-
BUSINESS SEGMENTS
We have two principal business segments determined by products, services
and regulatory environment, which consist of our regulated retail electricity
business and related activities (retail business segment) and competitive
business activities (marketing and trading segment). Our retail business segment
includes activities related to electricity transmission and distribution, as
well as electricity generation. Our marketing and trading segment includes
activities related to wholesale marketing and trading and APSES' competitive
energy services. The other amounts include activity relating to Suncor and El
Dorado.
The following table summarizes net income by business segment for the three
and twelve months ended March 31, 2002 and the comparable prior-year periods
(dollars in millions):
Three Months Twelve Months
Ended Ended
March 31, March 31,
------------------- --------------------
2002 2001 2002 2001
------- ------- ------- -------
Retail $ 31 $ 3 $ 179 $ 199
Marketing and trading 21 58 134 122
Other 2 1 5 (10)
------- ------- ------- -------
Income before accounting
change 54 62 318 311
Cumulative effect of a change
in accounting - net of
income taxes -- (3) (12) (3)
------- ------- ------- -------
Net income $ 54 $ 59 $ 306 $ 308
======= ======= ======= =======
OPERATING RESULTS
OPERATING RESULTS - THREE-MONTH PERIOD ENDED MARCH 31, 2002 COMPARED WITH
THREE-MONTH PERIOD ENDED MARCH 31, 2001
Our consolidated net income for the three months ended March 31, 2002 was
$54 million compared with $59 million for the same period in the prior year. In
2001, we recognized a $3 million after-tax loss in net income as the cumulative
effect of a change in accounting for derivatives, as required by SFAS No.133.
Income before accounting change for the three months ended March 31, 2002
was $54 million compared with $62 million for the same period in the prior year.
The period-to-period decrease is the result of lower marketing and trading
earnings contributions and a retail electricity price decrease. These negative
factors were partially offset by lower costs for replacement power due to lower
market prices and less outages, power plant maintenance, and generation
reliability. The major factors that increased (decreased) income before
accounting change were as follows (dollars in millions):
-22-
[Enlarge/Download Table]
Increase
(Decrease)
----------
Increases (decreases) in electric revenues, net of purchased power and fuel
expense due to:
Marketing and trading activities:
Decrease from generation sales other than native load due to lower
market prices and resulting lower sales volumes $ (46)
Increase in other realized marketing and trading in the current period
primarily due to higher unit margins on increased volumes 38(a)
Change in prior-period mark-to-market gains for contracts delivered
during the current period (b) (35)(a)
Lower mark-to-market gains for future-period deliveries (b) (24)
----------
Net decrease in marketing and trading (67)
Lower replacement power costs for plant outages due to lower
market prices and fewer unplanned outages 50
Increased fuel costs related to higher hedged natural gas and
purchased power prices (11)
Change in mark-to-market for hedged natural gas and purchased power
costs for future-period deliveries related to accounting for
derivatives 3
Effects of milder weather on retail sales (6)
Higher retail sales volumes due to customer growth and higher
average usage excluding weather effects 4
Retail price reductions effective July 1, 2001 (5)
Miscellaneous factors - net 1
----------
Total decrease in electric revenues, net of purchased power and fuel expense (31)
Lower operations and maintenance expenses primarily related to reliability,
outage and maintenance costs, and the absence of a provision for credit
expense, partially offset by higher employee benefit costs 8
Lower depreciation and amortization primarily due to lower regulatory asset
amortization 5
Miscellaneous items, net 4
----------
Decrease in income before income taxes (14)
Lower income taxes primarily due to lower income 6
----------
Decrease in income before accounting change $ (8)
==========
----------
(a) Net marketing and trading gains (excluding the effects of generation sales
other than native load) realized during the current period increased $3
million.
(b) Essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is hedged
with a portfolio of forward purchases that protects the economic value of
the sales transactions.
-23-
Electric operating revenues decreased approximately $327 million primarily
because of:
* changes in marketing and trading revenues ($294 million, net decrease) due
to:
- decreased revenues related to generation sales other than native load
due to lower market prices and resulting lower sales volumes ($79
million);
- decreased realized revenues related to other realized marketing and
trading in the current period primarily due to lower prices ($165
million);
- change in prior-period mark-to-market gains on contracts delivered
during the current period ($28 million decrease);
- lower mark-to-market gains for future-period deliveries primarily as a
result of lower market price volatility ($22 million);
* decreased revenues related to other wholesale sales as a result of lower
sales volumes and lower prices ($27 million);
* decreased retail revenues related to milder weather ($9 million);
* increased retail revenues related to customer growth and higher usage
excluding weather effects ($7 million);
* decreased retail revenues related to a reduction in retail electricity
prices ($5 million); and
* other miscellaneous factors ($1 million increase).
Purchased power and fuel expenses decreased approximately $296 million
primarily because of:
* changes in purchased power and fuel costs related to marketing and trading
activities ($227 million, net decrease) due to:
- decreased fuel costs related to generation sales other than native
load primarily because of lower sales volumes and lower natural gas
prices ($33 million);
- decreased purchased power costs related to other realized marketing
and trading in the current period primarily due to lower prices ($203
million);
- change in prior-period mark-to-market fuel costs for current-period
deliveries related to accounting for derivatives ($7 million
increase);
- change in mark-to-market fuel costs for future-period deliveries
related to accounting for derivatives ($2 million increase);
* decreased costs related to other wholesale sales as a result of lower sales
volumes and lower prices ($27 million);
* increased fuel costs related to higher hedged natural gas and purchased
power prices ($11 million);
* change in mark-to-market for hedged natural gas and purchased power costs
for future-period deliveries related to accounting for derivatives ($3
million decrease);
* decreased costs related to the effects of milder weather on retail sales
($3 million);
* increased costs related to retail sales growth excluding weather effects
($3 million); and
* decreased replacement power costs for power plant outages due to lower
market prices and fewer unplanned outages ($50 million).
-24-
The decrease in operations and maintenance expenses of $8 million primarily
related to costs incurred in 2001 for the generation reliability program (the
addition of generation capacity to enhance reliability for the summer of 2001)
and plant outages and maintenance ($7 million); and the absence of a provision
for credit exposure related to the California energy situation recorded in 2001
($5 million). These factors were partially offset by increased employee benefit
and other costs in the current period ($4 million).
The decrease in depreciation and amortization expenses of $5 million
primarily related to lower regulatory asset amortization, in accordance with
APS' 1999 Settlement Agreement.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED MARCH 31, 2002 COMPARED WITH
TWELVE-MONTH PERIOD ENDED MARCH 31, 2001
Our consolidated net income for the twelve months ended March 31, 2002 was
$306 million compared with $308 million for the same period in the prior year.
We recognized $12 million after-tax loss in the twelve months ended March 31,
2002 and a $3 million after-tax loss in the twelve months ended March 31, 2001
as cumulative effects of change in accounting for derivatives, as required by
SFAS No.133.
Income before accounting change for the twelve months ended March 31, 2002
was $318 million compared with $311 million for the same period a year earlier.
The period-to-period comparison benefited from favorable marketing and trading
results, including significant benefits in the third quarter of 2001 from
structured trading activities; lower replacement power costs; and retail
customer growth. These factors were partially offset by continuing retail
electricity price decreases; higher hedged purchased power and fuel costs, costs
of generation reliability measures; and charges related to Enron and its
affiliates. The major factors that increased (decreased) income before
accounting change were as follows (dollars in millions):
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[Enlarge/Download Table]
Increase
(Decrease)
----------
Increases (decreases) in electric revenues, net of purchased power and fuel
expense due to:
Marketing and trading activities:
Decrease from generation sales other than native load due to
lower market prices and resulting lower sales volumes $ (66)
Increase in other realized marketing and trading in the current
period primarily due to higher unit margins on increased sales
volumes 80(a)
Change in prior-period mark-to-market gains for contracts
delivered in the current period (b) (24)(a)
Change in prior-period mark-to-market value related to trading with
Enron and its affiliates (c) (8)
Increase in mark-to-market gains for future-period deliveries (b) 42
----------
Net increase in marketing and trading 24
Lower replacement power costs for plant outages related to lower
market prices and fewer unplanned outages 24
Retail price reductions effective July 1, 2001 and 2000 (27)
Charges related to purchased power contracts with Enron and its
affiliates(c) (13)
Change in mark-to-market for hedged natural gas and purchased
power costs for future-period deliveries related to accounting for
derivatives (9)
Higher retail sales primarily related to customer growth and
weather impacts, partially offset by lower usage and higher
hedged cost of purchased power and fuel 20
----------
Total increase in electric revenues, net of purchased power and fuel 19
expense
Higher operations and maintenance expense primarily related to 2001
generation reliability program (57)
Lower depreciation and amortization primarily due to lower regulatory
asset amortization 11
Lower net interest expense primarily due to higher capitalized interest 15
Lower other net expense primarily related to El Dorado 33
Miscellaneous items, net (4)
----------
Net increase in income before income taxes 17
Higher income taxes primarily due to higher income (10)
----------
Net increase in income before accounting change $ 7
==========
----------
(a) Net marketing and trading gains (excluding the effects of generation sales
other than native load) realized during the current period increased $56
million.
(b) Essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is hedged
with a portfolio of forward purchases that protects the economic value of
the sales transactions.
(c) We recorded charges totaling $21 million for exposure to Enron and its
affiliates in the fourth quarter of 2001.
-26-
Electric operating revenues increased approximately $64 million primarily
because of:
* changes in marketing and trading revenues ($105 million, net increase) due
to:
- decreased revenues related to generation sales other than native load
as a result of lower market prices and resulting lower sales volumes
($125 million);
- increased realized revenues related to other marketing and trading in
the current period primarily due to higher sales volumes ($212
million);
- decrease in prior-period mark-to-market value related to trading with
Enron and its affiliates ($8 million);
- change in prior-period mark-to-market gains for contracts delivered
during the current period ($14 million decrease);
- increased mark-to-market gains for future-period deliveries primarily
because of higher sales volumes ($40 million);
* decreased wholesale and other revenues as a result of lower sales volumes
($69 million);
* higher retail sales related to customer growth and weather impacts,
partially offset by lower average residential usage ($55 million); and
* decreased retail revenues related to reductions in retail electricity
prices effective July 1, 2001 and 2000 ($27 million).
Purchased power and fuel expenses increased approximately $45 million
primarily because of:
* changes in purchased power and fuel costs related to marketing and trading
activities ($81 million, net increase) due to:
- decreased fuel costs related to generation sales other than native
load as a result of lower sales volumes ($59 million);
- increased fuel and purchased power costs related to other realized
marketing and trading in the current period primarily due to higher
sales volumes ($132 million);
- change in prior-period mark-to-market fuel costs for current-period
deliveries related to accounting for derivatives ($10 million
increase);
- change in mark-to-market fuel costs for future-period deliveries
related to accounting for derivatives ($2 million decrease);
* decreased costs related to other wholesale sales as a result of lower sales
volumes ($69 million);
* lower replacement power costs primarily due to lower market prices and
fewer unplanned outages ($24 million);
* higher costs related to retail sales as a result of the higher hedged cost
of purchased power and fuel and higher retail sales volumes related to
customer growth and weather impacts ($35 million);
* change in mark-to-market for hedged natural gas and purchased power costs
for future-period deliveries related to accounting for derivatives ($9
million increase) and;
* charges related to purchased power contracts with Enron and its affiliates
($13 million).
The increase in operations and maintenance expenses of $57 million
primarily related to the 2001 generation reliability program (the addition of
generating capability to enhance reliability for the summer of 2001) and
-27-
scheduled plant outages and maintenance ($39 million); and increased employee
benefit and other costs ($28 million). These factors were partially offset by a
provision for our credit exposure related to the California energy situation
recorded in the prior period ($10 million).
The decrease in depreciation and amortization expenses of $11 million
primarily related to lower regulatory asset amortization, in accordance with
APS' 1999 regulatory settlement agreement.
Net other expense decreased $33 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 period and an insurance recovery of
environmental remediation costs, partially offset by other non-operating costs.
The major investment in the venture capital partnership was sold in the first
quarter of 2001.
Net interest expense decreased by $15 million primarily because of the
increase in capitalized interest ($23 million) related to our generation
expansion program and the effects of lower interest rates. The reductions in net
interest expense more than offset the increases in interest expense for higher
debt balances that were related primarily to our generation expansion program.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL EXPENDITURE REQUIREMENTS
The following table summarizes the actual capital expenditures for the
three months ended March 31, 2002 and estimated capital expenditures for the
next three years (dollars in millions):
Three- Estimated
Months ----------------------------
Ended Years Ended December 31,
March 31, ----------------------------
2002 2002 2003 2004
------ ------ ------ ------
APS
Delivery $ 92 $ 349 $ 271 $ 280
Existing generation (a) 27 149 -- --
------ ------ ------ ------
Subtotal 119 498 271 280
------ ------ ------ ------
Pinnacle West Energy (b)
Generation expansion 98 411 255 113(e)
Existing generation (a) -- -- 107 99
------ ------ ------ ------
Subtotal 98 411 362 212
------ ------ ------ ------
SunCor (c) 17 79 48 52
Other (d) 4 35 15 16
------ ------ ------ ------
Total $ 238 $1,023 $ 696 $ 560
====== ====== ====== ======
-28-
----------
(a) Pursuant to the 1999 Settlement Agreement, APS is required to transfer its
competitive electric assets and services no later than December 31, 2002.
See Note 5.
(b) See further discussion below of Pinnacle West Energy's generation expansion
program and "Capital Resources and Cash Requirements - Pinnacle West
Energy" below.
(c) Consists primarily of capital expenditures for land development and retail
and office building construction reflected in the "Increase in real estate
investments" in the condensed consolidated statements of cash flows.
(d) Primarily Pinnacle West and APSES.
(e) This amount does not include an expected reimbursement by SNWA of $100
million of these costs in 2004 in exchange for SNWA's purchase of a 25%
interest in the Silverhawk project at that time.
APS and the other Palo Verde participants are currently considering issues
related to replacement of the steam generators in Units 1 and 3. Although a
final determination of whether Units 1 and 3 will require steam generator
replacement to operate over their current full licensed lives has not yet been
made, APS and the other participants have approved an expenditure in 2002 to
procure long lead-time materials for fabrication of a spare set of steam
generators for either Unit 1 or 3. APS' portion of this expenditure is
approximately $7 million and is included in the estimated expenditures above.
This action will provide the Palo Verde participants an option to replace the
steam generators at either Unit 1 or 3 as early as fall 2005 should they
ultimately choose to do so. If the participants decide to proceed with steam
generator replacement at both Units 1 and 3, we have estimated that our portion
of the fabrication and installation costs and associated power uprate
modifications would be approximately $130 million over the next seven years,
which would be funded with internally-generated cash or external financings. See
Note 5.
Existing generation capital expenditures are comprised of multiple
improvements for our existing fossil and nuclear plants. Examples of the types
of projects included in this category are additions, upgrades and capital
replacements of various power plant equipment such as turbines, boilers, and
environmental equipment. The existing generation also contains nuclear fuel
expenditures of approximately $30 million annually in 2002, 2003, and 2004.
Delivery capital expenditures are comprised of T&D infrastructure additions
and upgrades, capital replacements, new customer construction, and related
information systems and facility costs. Examples of the types of projects
included in the forecast include T&D lines and substations, line extensions to
new residential and commercial developments, and upgrades to customer
information systems. In addition, we began several major transmission projects
in 2001. These projects are periodic in nature and are driven by strong regional
customer growth. We expect to spend about $150 million on major transmission
projects during the 2002-2004 time frame.
-29-
CAPITAL RESOURCES AND CASH REQUIREMENTS
The following table summarizes actual cash commitments for the three months
ended March 31, 2002 and estimated commitments for the next three years (dollars
in millions):
Three Estimated
Months ----------------------------
Ended Years Ended December 31,
March 31, ----------------------------
2002 2002 2003 2004
------ ------ ------ ------
Long-term debt payments
APS $ 125 $ 247 $ -- $ 205
Pinnacle West -- -- 276 216
SunCor -- -- 42 86
------ ------ ------ ------
Total long-term debt payments 125 247 318 507
Operating leases payments 5 68 66 65
Fuel and purchase power commitments 55 270 124 80
------ ------ ------ ------
Total cash commitments $ 185 $ 585 $ 508 $ 652
====== ====== ====== ======
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 2001 10-K.
During the three months ended March 31, 2002, the parent company increased
its outstanding indebtedness by about $215 million. On February 8, 2002, we
issued $215 million of 4.5% Notes due 2004. See the cash commitments table above
for the parent company's debt repayment requirements. The majority of these
borrowings were used to fund Pinnacle West Energy capital expenditures.
APS
APS' 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 2001 10-K.
During the three months ended March 31, 2002, APS increased its outstanding
indebtedness by about $375 million. On March 1, 2002, APS issued $375 million of
6.50% Notes due 2012. See the cash commitments table above for APS' debt
repayments. Based on market conditions and optional call provisions, APS may
make optional redemptions of long-term debt from time to time.
-30-
As of March 31, 2002, APS deposited $122 million, plus interest, with the
trustee under its Mortgage for the redemption in April 2002 of its First
Mortgage Bonds, 8.75% Series due 2024.
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
Pinnacle West Energy has completed or announced plans to build about 3,420
MW of natural gas-fired generating capacity from 2001 through 2007 at an
estimated cost of about $1.9 billion. This does not reflect an expected
reimbursement in 2004 by SNWA of $100 million of Pinnacle West Energy's
cumulative capital expenditures in the Silverhawk project in exchange for SNWA's
purchase of a 25% interest in the project. Our expansion plan will be sized to
meet native load growth, cash flow and market conditions. Pinnacle West Energy
is currently funding its capital requirements through capital infusions from
Pinnacle West, which finances those infusions through debt financings and
internally-generated cash. As Pinnacle West Energy develops and obtains
additional generation assets, including APS' existing generation assets,
Pinnacle West Energy expects to fund its capital requirements through
internally-generated cash and its own debt issuances. See the Capital
Expenditures Table above for actual capital expenditures through March 31, 2002
and projected capital expenditures for the next three years.
Pinnacle West Energy has completed or is currently planning the following
projects:
* A 650 MW expansion of the West Phoenix Power Plant in Phoenix. The 120
MW West Phoenix Unit 4 began commercial operation on June 1, 2001.
Construction has begun on the 530 MW West Phoenix Unit 5, with
commercial operation expected to begin in mid-2003.
* The construction of a four-unit combined cycle 2,120 MW generating
station near Palo Verde, called Redhawk. Construction of Units 1 and 2
began in December 2000, and commercial operation is currently
scheduled for the summer of 2002. Although Pinnacle West Energy
currently plans to bring Units 3 and 4 on line in or before the first
quarter of 2007, equipment procurement, engineering and construction
plans will allow for these units to come on line as early as 2005 if
warranted by market conditions.
* The construction of an 80 MW simple-cycle power plant at Saguaro in
Southern Arizona. Commercial operation is currently scheduled for the
summer of 2002.
* Development of an electric generating station 20 miles north of Las
Vegas, Nevada. Construction of the 570 MW Silverhawk combined-cycle
plant is expected to begin in the spring of 2002, with an expected
commercial operation date of mid-2004. Pinnacle West Energy has signed
a 25% participation agreement with Las Vegas-based SNWA.
-31-
* A Pinnacle West Energy affiliate is exploring the possibility of
creating an underground natural gas storage facility on Company-owned
land west of Phoenix. A feasibility study is in progress to determine
if the proposed acreage can support a natural gas storage cavern.
OTHER SUBSIDIARIES
During the past three years, both SunCor and El Dorado funded all of their
cash requirements with cash from operations and, in the case of SunCor, its own
external financings. APSES funded its cash requirements with cash infusions from
Pinnacle West.
SunCor's capital needs consist primarily of capital expenditures for land
development and retail and office building construction. See the capital
expenditures table above for actual capital expenditures in the three months
ended March 31, 2002 and projected capital expenditures for the next three
years. SunCor expects to fund its capital requirements with cash from operations
and external financings.
El Dorado does not have any capital requirements over the next three years.
El Dorado intends to focus on prudently realizing the value of its existing
investments. El Dorado's future investments are expected to be related to the
energy sector.
APSES' capital expenditures and other cash requirements are increasingly
funded by operations, with some funding from cash infused by Pinnacle West. See
the capital expenditures table above regarding APSES' capital expenditures.
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with GAAP, management
must often make estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues, expenses, and related disclosures at the date of
the financial statements and during the reporting period. Some of those
judgments can be subjective and complex, and actual results could differ from
those estimates. Our most critical accounting policies include the determination
of the appropriate accounting for our derivative instruments, mark-to-market
accounting and the impacts of regulatory accounting on our consolidated
financial statements. See Note 1 in the 2001 10-K.
BUSINESS OUTLOOK
We currently believe that it will be a challenge for us in 2002 to repeat
our 2001 earnings. For 2001, our reported income before accounting change was
$327 million, or $3.85 per diluted share of common stock, and included charges
totaling $21 million before income taxes, or $0.15 per diluted share, that we do
not expect to recur related to our exposure to Enron and its affiliates. Our
earnings in 2002 are expected to be negatively affected by a significant
decrease in the earnings contribution from our marketing and trading activities
and retail electricity price decreases. These negative factors are expected to
be substantially offset in 2002 by the absence of significant expenses for
reliability and power plant outages that we incurred in 2001 that we do not
expect to recur in 2002 and by retail customer growth, although the pace of
growth is expected to be slower than in the past. These factors are described in
more detail below.
-32-
In 2001, our marketing and trading activities contributed about one-half of
our income before accounting change before the Enron-related charges. These
activities are currently expected to provide about one-fourth of our earnings in
2002. The drivers of such reduced earnings contributions from our marketing and
trading activities in 2002 are significant reductions in wholesale market prices
for electricity that occurred during 2001; wholesale market liquidity, which
affects our ability to buy and resell electricity; and market volatility, which
affects our ability to capture profitable structured trading activities. These
reductions in regional market factors were due, in large part, to conservation
measures in California and throughout the West; more generating plants in
service in the West; lower natural gas prices; and the price mitigation plan
that took effect in June 2001 as mandated by the FERC.
During 2001, in order to meet the highest customer demand in APS' history,
we incurred significant expenses for our summer reliability program and for
higher replacement power costs related to power plant outages. These efforts
cost approximately $140 million before income taxes, which is not expected to be
repeated in 2002.
We estimate our retail customer growth in 2002 to be 3.2%, which is slower
than the pace of growth in recent years, although still about three times the
national average. Our customer growth in 2001 was 3.7%. We expect the customer
growth rate to be weak in the first two quarters of 2002, then begin a rebound.
Our current estimate for customer growth in 2003 and 2004 is between 3.5% and
4.0% annually.
As of December 31, 2001, the indicated annual dividend rate on our common
stock was $1.60 per share. Since 1994, we have increased the dividend on our
common stock ten cents per share per year. We currently plan to continue annual
dividend increases of relatively consistent amounts, which would continue
dividend growth at a pace above the industry average.
The foregoing discussion of future expectations is forward-looking
information. Actual results may differ materially from expectations. See
"Forward-Looking Statements" below.
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See "Business Outlook - Competition and Industry Restructuring" in Item 7
of the 2001 10-K and Note 5 above for a discussion of developments affecting
retail and wholesale electric competition.
GENERATION EXPANSION
See "Capital Resources and Cash Requirements - Pinnacle West Energy" above
for information regarding our generation expansion plans. The planned additional
generation is expected to increase revenues, fuel expenses, operating expenses,
and financing costs.
-33-
FACTORS AFFECTING OPERATING REVENUES
Electric operating revenues are derived from sales of electricity in
regulated retail markets in Arizona, and from competitive retail and wholesale
bulk power markets in the western United States. These revenues are expected to
be affected by electricity sales volumes related to customer mix, customer
growth and average usage per customer, as well as electricity prices and
variations in weather from period to period.
In APS' regulated retail market area, APS will provide electricity services
to standard-offer, full-service customers and to energy delivery customers who
have chosen another provider for their electricity commodity needs (unbundled
customers). Customer growth in APS' service territory averaged about 4% a year
for the three years 1999 through 2001; we currently expect customer growth to be
about 3.2% in 2002 and between 3.5% and 4.0% a year in 2003 and 2004. We
currently estimate that retail electricity sales in kilowatt-hours will grow
3.5% to 5.5% a year in 2002 through 2004, before the retail effects of weather
variations. The customer growth and sales growth referred to in this paragraph
apply to energy delivery customers. As industry restructuring evolves in the
regulated market area, we cannot predict the number of APS' standard-offer
customers that will switch to unbundled service. As previously noted, under the
1999 Settlement Agreement, we have retail electricity price reductions of 1.5%
annually through July 1, 2003 (see Note 5).
Competitive sales of energy and energy-related products and services are
made by APSES in western states that have opened to competitive supply. Such
activities currently are not material to our consolidated financial results.
OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS
Purchased power and fuel costs are impacted by our electricity sales
volumes, existing contracts for generation fuel and purchased power, our power
plant performance, prevailing market prices, new generating plants being placed
in service and our hedging program for managing such costs.
Operations and maintenance expenses are expected to be affected by sales
mix and volumes, power plant operations, inflation, outages and other factors.
Depreciation and amortization expenses are expected to be affected by net
additions to existing utility plant and other property, changes in regulatory
asset amortization, and our generation expansion program.
Taxes other than income taxes consist primarily of property taxes, which
are affected by tax rates and the value of property in service and under
construction. The average property tax rate for APS, which currently owns the
majority of our property, was 9.32% for 2001 and 9.16% for 2000. We expect
property taxes to increase primarily due to our generation expansion program and
our additions to existing facilities.
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. Capitalized interest offsets a portion of
interest expense while capital projects are under construction. We stop
recording capitalized interest on a project when it is placed in commercial
operation.
-34-
The annual earnings contribution from APSES is expected to be modest, yet
positive, over the next several years due primarily to a number of retail
electricity contracts in California. APSES' pretax losses were $10 million in
2001 and $13 million in 2000.
The annual earnings contribution from SunCor is expected to remain modest
over the next several years. SunCor's earnings were $3 million in 2001, $11
million in 2000 and $6 million in 1999.
El Dorado's historical results are not necessarily indicative of future
performance for El Dorado. El Dorado's strategies focus on prudently realizing
the value of its existing investments. Any future investments are expected to be
related to the energy sector.
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 5 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
The above discussion contains forward-looking statements based on current
expectations and we assume no obligation to update these statements. Because
actual results may differ materially from expectations, we caution readers not
to place undue reliance on these statements. A number of factors could cause
future results to differ materially from historical results, or from results or
outcomes currently expected or sought by us. These factors include the ongoing
restructuring of the electric industry, including the introduction of retail
electric competition in Arizona; the outcome of regulatory and legislative
proceedings relating to the restructuring; state and federal regulatory and
legislative decisions and actions, including the price mitigation plan adopted
by the FERC in June 2001; regional economic and market conditions, including the
California energy situation and completion of generation construction in the
region, which could affect customer growth and the cost of power supplies; the
cost of debt and equity capital; weather variations affecting local and regional
customer energy usage; conservation programs; power plant performance; the
successful completion of our generation expansion program; regulatory issues
-35-
associated with generation expansion, such as permitting and licensing; our
ability to compete successfully outside traditional regulated markets (including
the wholesale market); technological developments in the electric industry; and
the strength of the real estate market in SunCor's market areas, which include
Arizona, New Mexico and Utah.
These factors and the other matters discussed above may cause future
results to differ materially from historical results, or from results or
outcomes we currently expect or seek.
ITEM 3. MARKET RISKS
Our operations include managing market risks related to changes in interest
rates, commodity prices, and investments held by our nuclear decommissioning
trust fund.
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal, and emissions
allowances. We employ established procedures to manage risks associated with
these market fluctuations by utilizing various commodity derivatives, including
exchange-traded futures and options and over-the-counter forwards, options, and
swaps. As part of our overall risk management program, we enter into derivative
transactions to hedge purchases and sales of electricity, fuels, and emissions
allowances and credits. The changes in market value of such contracts have a
high correlation to price changes in the hedged commodity.
In addition, subject to specified risk parameters established by the Board
of Directors and monitored by the Energy Risk Management Committee, we engage in
trading activities intended to profit from market price movements. In accordance
with Emerging Issues Task Force (EITF) 98-10, "Accounting For Contracts Involved
in Energy Trading and Risk Management Activities," such trading positions are
marked-to-market. These trading activities are part of our marketing and trading
activities and are reflected in the marketing and trading segment revenues and
expenses.
The following schedule shows the changes in mark-to-market of our trading
positions during the three months ended March 31, 2002 (dollars in millions):
For Three
Months Ended
March 31,
2002
------------
Mark-to-market of net trading
positions at beginning of period $ 138
Prior period mark-to-market gains
realized during the period (22)
Change in mark-to-market gains for
future period deliveries 25
--------
Mark-to-market of net trading
positions at end of period $ 141
========
-36-
Net gains at inception include a reasonable marketing margin and were
approximately $8 million for the three months ended March 31, 2002. See Note 10
for mark-to-market on system hedges and for disclosure of risk management
activities recorded on the consolidated balance sheets.
The table below shows the maturities of our trading positions as of March
31, 2002, by the type of valuation that is performed to calculate the fair value
of the contract (millions of dollars):
2005 and Total
years fair
Source of Fair Value 2002 2003 2004 thereafter value
-------------------- ------ ------ ------ ---------- ------
Prices actively quoted $ (34) $ -- $ -- $ -- $ (34)
Prices provided by other
external sources 1 (1) 7 12 19
Prices based on models and
other valuation methods 58 28 21 49 156
------ ------ ------ ------ ------
Total by maturity $ 25 $ 27 $ 28 $ 61 $ 141
====== ====== ====== ====== ======
The table below shows the impact that hypothetical price movements of 10%
would have on the market value of our risk management and trading assets and
liabilities included on the consolidated balance sheets at March 31, 2002
(dollars in millions):
March 31, 2002
--------------------------------
Gain (Loss)
--------------------------------
Commodity Price Up 10% Price Down 10%
--------- ------------ --------------
Trading (a):
Electric $ (2) $ 2
Natural gas (1) 1
Other 1 (1)
System (b):
Natural gas
hedges 26 (24)
------- -------
Total $ 24 $ (22)
======= =======
----------
(a) Essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is hedged
with a portfolio of forward purchases that protects the economic value of
the sales transactions.
(b) These contracts are hedges of our forecasted purchases of natural gas. The
impact of these hypothetical price movements would substantially offset the
impact that these same price movements would have on the physical exposures
being hedged.
We are exposed to losses in the event of nonperformance or nonpayment by
counterparties. We have risk management and trading contracts with many
counterparties, including one counterparty for which a worst case exposure
-37-
represents approximately 44% of our $285 million of risk management and trading
assets as of March 31, 2002. We use a risk management process to assess and
monitor the financial exposure of this and all other counterparties. Despite the
fact that the great majority of trading counterparties are rated as investment
grade by the credit rating agencies, including the counterparty noted above,
there is still a possibility that one or more of these companies could default,
resulting in a material impact on consolidated earnings for a given period.
Counterparties in the portfolio consist principally of major energy companies,
municipalities, and local distribution companies. We maintain credit policies
that we believe minimize overall credit risk to within acceptable limits.
Determination of the credit quality of our counterparties is based upon a number
of factors, including credit ratings and our evaluation of their financial
condition. In many contracts, we employ collateral requirements and standardized
agreements that allow for the netting of positive and negative exposures
associated with a single counterparty. Credit reserves are established
representing our estimated credit losses on our overall exposure to
counterparties.
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.
-38-
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
See Note 5 of Notes to Condensed Consolidated Financial Statements in Part
I, Item 1 of this report for a discussion of regulatory developments regarding
the introduction of retail electric competition in Arizona and related matters.
PALO VERDE NUCLEAR GENERATING STATION
In February 2002, the U. S. Secretary of Energy recommended to President
Bush that the Yucca Mountain, Nevada site be developed as a permanent repository
for spent nuclear fuel. See Note 10 of Notes to Consolidated Financial
Statements of the 2001 10-K. The President transmitted this recommendation to
Congress and the State of Nevada has vetoed the President's recommendation. A
congressional decision on whether to override the Nevada veto is expected
sometime during the summer of 2002. We cannot currently predict what further
steps will be taken in this area.
ENVIRONMENTAL MATTERS
The EPA reviewed an "Annex" to the GCVTC recommendations and, on April 26,
2002, the EPA proposed to accept the GCVTC's Annex, submitted by the Western
Regional Air Partnership (successor to GCVTC) in September 2000. See
"Environmental Matters - EPA Environmental Regulations - Clean Air Act" in Part
I, Item 1 of the 2001 10-K. The Annex specifies regional sulfur dioxide emission
reduction milestones. The EPA's final approval of the Annex would allow the
GCVTC states and tribes to pursue the alternate implementation of the regional
haze rules through 2018. Any states and tribes that implement this option would
have to submit state implementation plans by 2003 to address visibility in areas
identified in the GCVTC process, and revised implementation plans in 2008 to
address Class I Areas which were not included in the GCVTC process. The State of
Arizona is in the process of developing a State Implementation Plan to implement
the provisions of the Annex. Because Four Corners is located on the Navajo
Reservation and is currently regulated by EPA Region IX, the provisions of the
Annex currently could become applicable to Four Corners only through a Federal
Implementation Plan promulgated by EPA Region IX. At this time, it is uncertain
how the State of Arizona and/or EPA Region IX will proceed to implement the
Annex, so the actual impact on APS cannot yet be determined.
In February 2001, the U.S. Supreme Court found, among other things, that
the EPA implementation policy for revised ozone standards was unlawful, and
remanded this issue for consideration along with other preserved challenges to
the National Ambient Air Quality Standards. See "Environmental Matters - EPA
Environmental Regulation - Clean Air Act" in the 2001 10-K. On remand, on March
26, 2002, the U.S. Court of Appeals for the District of Columbia upheld the more
stringent eight-hour ozone standard and the particulate matter standard.
-39-
Because the actual level of emissions controls, if any, for any unit cannot be
determined at this time, APS currently cannot estimate the capital expenditures,
if any, which would result from the final rules. However, APS does not currently
expect these rules to have a material adverse effect on its financial position,
results of operations, or liquidity.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit No. Description
----------- -----------
4.1 Amendment to Rights Agreement, effective as of
January 1, 2002
10.1 Amendment No. 5 to the Amended and Restated
Decommissioning Trust Agreement (PVNGS Unit 2),
dated as of June 30, 2000
10.2 Amendment No. 3 to the Decommissioning Trust
Agreement (PVNGS Unit 1), dated as of March 18, 2002
10.3 Amendment No. 6 to the Amended and Restated
Decommissioning Trust Agreement (PVNGS Unit 2),
dated as of March 18, 2002
10.4 Amendment No. 3 to the Decommissioning Trust
Agreement (PVNGS Unit 3), dated as of March 18, 2002
12.1 Ratio of Earnings to Fixed Charges
-40-
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:
[Enlarge/Download Table]
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 March 31, 2002, and the period from April 1
through May 15, 2002, we filed the following reports on Form 8-K:
Report dated December 14, 2001 regarding the (i) Arizona Supreme Court
dismissal of an appeal related to the 1999 Settlement Agreement and (ii) new ACC
generic docket relating to electric restructuring in Arizona.
Report dated February 8, 2002 regarding the consolidation of pending ACC
dockets.
Report dated March 31, 2002 regarding (i) exhibits comprised of financial
information and earnings variance explanations, (ii) an exhibit of a slide
presentation for use at an analyst conference, and (iii) a motion filed by APS
in a consolidated ACC docket.
Report dated April 26, 2002 regarding ACC procedural orders.
----------
(a) Reports filed under File No. 1-8962 were filed in the office of the
Securities and Exchange Commission located in Washington, D.C.
-41-
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: May 15, 2002 By: Chris N. Froggatt
------------------------------------
Chris N. Froggatt
Vice President and Controller
(Principal Accounting Officer
and Officer Duly Authorized
to sign this Report)
-42-
Dates Referenced Herein and Documents Incorporated by Reference
| Referenced-On Page |
|---|
| This ‘10-Q’ Filing | | Date | | First | | Last | | | Other Filings |
|---|
| |  |
| | 5/31/08 | | 19 |
| | 12/31/04 | | 10 | | | | | 10-K, 11-K, 8-K, U-3A-2 |
| | 7/1/04 | | 9 | | 11 | | | 4 |
| | 1/1/04 | | 9 |
| | 7/1/03 | | 9 | | 36 | | | 4, 4/A |
| | 3/31/03 | | 17 | | | | | 10-K, 10-Q, 8-K |
| | 1/1/03 | | 15 |
| | 12/31/02 | | 8 | | 30 | | | 10-K, 11-K, 5, 8-K, U-3A-2 |
| | 10/21/02 | | 13 |
| | 9/30/02 | | 13 | | | | | 10-Q, 8-K |
| | 8/1/02 | | 13 |
| | 7/31/02 | | 13 |
| | 7/22/02 | | 13 | | | | | 4 |
| | 6/17/02 | | 9 | | 13 |
| | 5/20/02 | | 13 |
| Filed on: | | 5/15/02 | | 42 | | 43 |
| | 5/10/02 | | 1 | | | | | 4 |
| | 5/2/02 | | 13 |
| | 4/29/02 | | 13 |
| | 4/26/02 | | 13 | | 42 | | | 4, 8-K |
| | 4/19/02 | | 12 |
| | 4/1/02 | | 17 | | | | | 4 |
| For Period End: | | 3/31/02 | | 1 | | 42 | | | 8-K |
| | 3/26/02 | | 40 | | | | | 144 |
| | 3/19/02 | | 19 |
| | 3/18/02 | | 41 |
| | 3/13/02 | | 19 |
| | 3/1/02 | | 8 | | 31 |
| | 2/8/02 | | 8 | | 42 | | | 8-K |
| | 1/1/02 | | 15 | | 41 |
| | 12/31/01 | | 2 | | 34 | | | 10-K405, 11-K, 4, U-3A-2 |
| | 12/14/01 | | 42 | | | | | 8-K |
| | 10/31/01 | | 19 |
| | 10/18/01 | | 12 | | | | | 8-K |
| | 7/15/01 | | 19 |
| | 7/1/01 | | 9 | | 36 |
| | 6/1/01 | | 19 | | 32 |
| | 3/31/01 | | 17 | | 26 | | | 10-Q |
| | 3/7/01 | | 19 |
| | 1/17/01 | | 19 | | | | | U-1/A |
| | 1/1/01 | | 10 | | 17 |
| | 11/27/00 | | 11 | | | | | 8-K |
| | 7/1/00 | | 9 | | 28 |
| | 6/30/00 | | 41 | | | | | 10-Q, S-8 POS |
| | 1/1/00 | | 9 |
| | 12/15/99 | | 42 |
| | 9/24/99 | | 9 |
| | 9/23/99 | | 8 |
| | 9/21/99 | | 8 | | | | | 8-K |
| | 7/1/99 | | 9 |
| List all Filings |
4 Subsequent Filings that Reference this Filing
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