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)
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
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See Notes to Condensed Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(in thousands, except per share amounts)
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
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See Notes to Condensed Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
ASSETS
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
========== ==========
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See Notes to Condensed Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
(dollars in thousands)
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
=========== ===========
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See Notes to Condensed Consolidated Financial Statements.
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
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See Notes to Condensed Consolidated Financial Statements.
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
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
(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.
* 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
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
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.
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):
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
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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.
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.
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.
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):
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
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
====== ====== ====== ======
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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;
* 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.
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):
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)
==========
|
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).
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):
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
==========
|
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
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
====== ====== ====== ======
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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.
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
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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.
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.
* 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.
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.
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.
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
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
========
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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
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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)
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(a) Essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is hedged
with a portfolio of forward purchases that protects the economic value of
the sales transactions.
(b) These contracts are hedges of our forecasted purchases of natural gas. The
impact of these hypothetical price movements would substantially offset the
impact that these same price movements would have on the physical exposures
being hedged.
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including one counterparty for which a worst case exposure
represents approximately 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.
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.
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
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In addition, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation ss.229.10(d) by reference to the filings set forth below:
Originally Filed Date
Exhibit No. Description as Exhibit: File No.(a) Effective
----------- ----------- -------------------- ----------- ---------
3.1 Articles of Incorporation 19.1 to the Company's 1-8962 11-14-88
restated as of July 29, September 30, 1988
1988 Form 10-Q Report
3.2 Bylaws, amended as of 4.1 to the Company's 1-8962 1-20-00
December 15, 1999 Registration Statement
on Form S-8 No. 333-95035
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(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.
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)
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Exhibit 4.1
AMENDMENT TO RIGHTS AGREEMENT
This Amendment to Rights Agreement (this "Amendment") is made effective as of January 1, 2002, by and among Pinnacle West Capital Corporation, an Arizona corporation ("Pinnacle West"), Fleet National Bank, formerly known as BankBoston, N.A. ("Fleet"), and EquiServe Trust Company, N.A. ("EquiServe"), as the new Rights Agent. All capitalized terms used herein and not defined shall have their meanings set forth in the Agreement (as defined below).
1. GENERAL BACKGROUND. In accordance with Section 27 of the Amended and Restated Rights Agreement between Pinnacle West and BankBoston, N.A., dated as of March 26, 1999 (the "Agreement"), the parties hereto desire to amend the Agreement as set forth below.
2. APPOINTMENT OF SUCCESSOR RIGHTS AGENT. Pinnacle West hereby appoints EquiServe as the successor Rights Agent under the Agreement and EquiServe hereby accepts such appointment and assumes and agrees to perform each and all of the obligations, covenants and agreements of the Rights Agent under the Agreement, as such Agreement may be modified herein.
3. REVISION. Section 21 of the Agreement entitled "Change of Rights Agent" is hereby deleted in its entirety and replaced with the following:
CHANGE OF RIGHTS AGENT. The Rights Agent or any successor Rights Agent may resign and be discharged from its duties under this Agreement upon 30 days' notice in writing mailed to the Company and to each transfer agent of the Common Stock or Preferred Stock by registered or certified mail, and, following the Distribution Date, to the holders of the Right Certificates by first-class mail. The Company may remove the Rights Agent or any successor Rights Agent upon 30 days' notice in writing, mailed to the Rights Agent or successor Rights Agent, as the case may be, and to each transfer agent of the Common Stock or Preferred Stock by registered or certified mail, and, following the Distribution Date, to the holders of the Right Certificates by first-class mail. If the Rights Agent shall resign or be removed or shall otherwise become incapable of acting, the Company shall appoint a successor to the Rights Agent. If the Company shall fail to make such appointment within a period of 30 days after giving notice of such removal or after it has been notified in writing of such resignation or incapacity by the resigning or incapacitated Rights Agent or by the holder of a Right Certificate (who shall, with such notice, submit such holder's Right Certificate for inspection by the Company), then the registered holder of any Right Certificate may apply to any court of competent jurisdiction for the appointment of a new Rights Agent. Any successor Rights Agent or its agent, whether appointed by the Company or by such a court, shall be a corporation, bank or trust company organized and doing
business under the laws of the United States, in good standing, which is authorized under such laws to exercise corporate trust or stock transfer powers and is subject to supervision or examination by federal or state authority and which has individually or combined with an affiliate at the time of its appointment as Rights Agent a combined capital and surplus of at least $100 million dollars. After appointment, the successor Rights Agent shall be vested with the same powers, rights, duties and responsibilities as if it had been originally named as Rights Agent without further act or deed; but the predecessor Rights Agent shall deliver and transfer to the successor Rights Agent any property at the time held by it hereunder, and execute and deliver any further assurance, conveyance, act or deed necessary for the purpose. Not later than the effective date of any such appointment the Company shall file notice thereof in writing with the predecessor Rights Agent and each transfer agent of the Common Stock or Preferred Stock, and, following the Distribution Date, mail a notice thereof in writing to the registered holders of the Right Certificates. Failure to give any notice provided for in this Section 21, however, or any defect therein, shall not affect the legality or validity of the resignation or removal of the Rights Agent or the appointment of the successor Rights Agent, as the case may be.
4. Except as explicitly amended hereby, the Agreement and all schedules or exhibits thereto shall remain in full force and effect.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed in their names and on their behalf by and through their duly authorized officers, as of the date first set forth above.
PINNACLE WEST CAPITAL CORPORATION FLEET NATIONAL BANK (FORMERLY KNOWN AS
BANKBOSTON, N.A.)
Faye Widenmann Dennis V. Moccia
--------------------------------- ----------------------------------------
By: Faye Widenmann By: Dennis V. Moccia
Title: Vice President & Secretary Title: Managing Director
EQUISERVE TRUST COMPANY, N.A.
Dennis V. Moccia
----------------------------------------
By: Dennis V. Moccia
Title: Managing Director
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Exhibit 10.1
This Amendment No. 5, dated as of June 30, 2000, to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of January 31, 1992, as amended by Amendment No. 1 thereto dated as of November 1, 1992, Amendment No. 2 thereto dated as of November 1, 1994, Amendment No. 3 thereto dated as of June 20, 1996, and Amendment No. 4 thereto dated as of December 16, 1996 (the "Decommissioning Trust Agreement"; terms used herein as therein defined), is entered into between Arizona Public Service Company ("APS"), State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee and as Lessor, and Mellon Bank, N.A., as Decommissioning Trustee ("Decommissioning Trustee").
R E C I T A L S:
WHEREAS, the parties hereto wish to amend the investment parameters for the Decommissioning Trust Fund and the Second Fund contained in Exhibit B to the Decommissioning Trust Agreement;
NOW, THEREFORE, in consideration of the premises and of other good and valuable consideration, receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:
A G R E E M E N T S:
SECTION 1. Amendment.
Paragraph (l) of Exhibit B to the Decommissioning Trust Agreement is hereby deleted and is replaced in its entirety by the following:
(l) (x) corporate equity securities, including, but not limited to, investment in units of common or collective trust funds investing in corporate equity securities; including, but not limited to, the Decommissioning Trustee's Nuclear Decommissioning Trust Equity Index Fund (the "NDT Equity Index Fund") and (y) obligations not included in clauses (a) through (k) issued or guaranteed by a person controlled or supervised by and acting as an instrumentality of the United States of America pursuant to authority granted by the Congress of the United States of America, including Federal Intermediate Credit Bank, Banks for Cooperatives, Federal Land Banks, Federal Home Loan Banks, Federal Home Loan Mortgage Corporation; provided, that no more than fifty percent (50%) of the aggregate assets of the Funds may be invested in securities described in (x) and (y) of this subparagraph (l) during the period from June 27, 1996 through December 31, 2003, no more than thirty percent (30%) during the period from January 1, 2004 through December 31, 2006, and no more than fifteen percent (15%) during the period from January 1, 2007 through January 31, 2010; and provided further that after January 31, 2010, no investments shall be made in such securities.
SECTION 2. Effectiveness.
This Amendment No. 5 shall become effective as of the date hereof upon the execution and delivery of a counterpart of this Amendment No. 5 by each of the parties hereto.
SECTION 3. Miscellaneous
(a) Full Force and Effect.
Except as expressly provided herein, the Decommissioning Trust Agreement shall remain unchanged and in full force and effect. Each reference in the Decommissioning Trust Agreement and in any exhibit or schedule thereto to "this Agreement," "hereto," "hereof" and terms of similar import shall be deemed to refer to the Decommissioning Trust Agreement as amended hereby.
(b) Counterparts.
This Amendment No. 5 may be executed in any number of counterparts, all of which taken together shall constitute one and the same instrument, and any of the parties hereto may execute this Amendment No. 5 by signing any such counterpart.
(c) Arizona Law.
This Amendment No. 5 shall be construed in accordance with and governed by the law of the State of Arizona.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 5 to the Decommissioning Trust Agreement to be duly executed as of the day and year first above written.
ARIZONA PUBLIC SERVICE COMPANY
MELLON BANK N.A., as
Decommissioning Trustee
STATE STREET BANK AND TRUST COMPANY, as
Owner Trustee under a Trust Agreement
with Security Pacific Capital Leasing
Corporation and as Lessor under a
Facility Lease with Arizona Public
Service Company
STATE STREET BANK AND TRUST COMPANY, as
Owner Trustee under a Trust Agreement
with Emerson Finance Co. and as Lessor
under a Facility Lease with Arizona
Public Service Company
STATE OF ARIZONA )
) ss.
County of Maricopa )
|
The foregoing instrument was acknowledged before me this 8th day of December, 2000, by Barbara M. Gomez, the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, on behalf of said corporation.
My commission expires:
STATE OF PENNSYLVANIA )
) ss.
County of Allegheny )
|
The foregoing instrument was acknowledged before me this 14th day of December, 2000, by Gerald T. McDermott, a Trust Officer of MELLON BANK, N.A., a corporation having trust powers, as Decommissioning Trustee, on behalf of said corporation.
My commission expires:
STATE OF MASSACHUSETTS )
) ss.
County of Suffolk )
|
The foregoing instrument was acknowledged before me this 7th day of December, 2000, by John Correia, the Assistant Vice President of STATE STREET BANK AND TRUST COMPANY, a Massachusetts trust company, in its capacity as Owner Trustee under a Trust Agreement with Security Pacific Capital Leasing Corporation, and as Lessor under a Facility Lease with Arizona Public Service Company, on behalf of said association in such capacities.
My commission expires:
STATE OF MASSACHUSETTS )
) ss.
County of Suffolk )
|
The foregoing instrument was acknowledged before me this 7th day of December, 2000, by John Correia, the Assistant Vice President of STATE STREET BANK AND TRUST COMPANY, a Massachusetts trust company, in its capacity as Owner Trustee under a Trust Agreement with Emerson Finance Co., and as Lessor under a Facility Lease with Arizona Public Service Company, on behalf of said association in such capacities.
My commission expires:
Exhibit 10.2
AMENDMENT NO. 3
Decommissioning Trust Agreement
(PVNGS Unit 1)
This Amendment No. 3 dated as of March 18, 2002, to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of July 1, 1991, as amended by Amendment No. 1 thereto dated as of December 1, 1994 and Amendment No. 2 thereto dated as of December 16, 1996 (the "Decommissioning Trust Agreement", terms used herein as therein defined), is entered into between Arizona Public Service Company ("APS") and Mellon Bank, N.A., as Decommissioning Trustee ("Decommissioning Trustee").
R E C I T A L S:
WHEREAS, the parties hereto wish to amend the Agreement.
NOW, THEREFORE, in consideration of the premises and of other good and valuable consideration, receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:
SECTION 1. Amendment.
(a) The period at the end of clause (iii) in Section 8, paragraph (a) is
deleted and ";or" is added in its place and the following subparagraph
(iv) shall be added to Section 8, paragraph (a):
"(iv) in any property safekept or settled outside of the United States".
(b) The third and fifth sentences of clause (ii) of Paragraph (c) of
Section 8 shall be restated as follows;
Upon proper notification from the Investment Manager(s), Decommissioning Trustee shall execute and deliver instruments in accordance with the appropriate trading authorizations; provided that the Trustee shall not follow any direction that would result in assets of the Second Fund being invested in assets other than those investments permitted for a qualified nuclear decommissioning reserve fund under Section 468A of the Code and the regulations thereunder.
Such notification shall be proper authority for Decommissioning Trustee to pay for portfolio securities purchased against receipt thereof, and to deliver portfolio securities sold against payment therefor, as the case may be.
(c) Clause (ii) of Paragraph (d) of Section 8 shall be restated as follows:
(ii) Decommissioning Trustee is required to supervise and review the securities and other assets and investments authorized for purchase by the Investment Managers(s) within two weeks of the end of the calendar month during which such purchase was made to
determine that such securities, assets and/or investments are Permitted Investments and satisfy the further conditions of this Agreement as set out in Exhibit B. Upon the completion of such review, the Decommissioning Trustee shall promptly notify APS in writing if any securities, assets or investments are not Permitted Investments or fail to satisfy such further conditions.
(d) The following shall be added to Section 11:
Notwithstanding the foregoing, if the Decommissioning Trustee advances cash or securities for any purpose or in the event that the Decommissioning Trustee shall incur or be assessed taxes, interest, charges, expenses, assessments, or other liabilities in connection with the performance of this Agreement, except such as may arise from its own negligent action, negligent failure to act or willful misconduct, any property at any time held for the Funds or under this Agreement shall be security therefor and the Decommissioning Trustee shall be entitled to collect from the Funds sufficient cash for reimbursement, and if such cash is insufficient, dispose of the assets held under this Agreement to the extent necessary to obtain reimbursement. To the extent the Decommissioning Trustee advances funds to the Funds for disbursements or to effect the settlement of purchase transactions, the Decommissioning Trustee shall be entitled to collect from the Funds an amount equal to what would have been earned on the sums advanced (an amount approximating the "federal funds" interest rate).
(e) The second sentence of the fourth paragraph of Section 21 shall be restated as follows:
Decommissioning Trustee shall promptly advise APS if it has actual knowledge that any of the investments do not constitute Permitted Investments or otherwise satisfy the further conditions of this Agreement.
(f) The first sentence of Section 23 shall be restated as follows:
Decommissioning Trustee shall not be liable for any acts, omissions, or defaults of any agent (other than its officers and employees), provided such agent was selected with reasonable care and the performance and status of such agent is monitored with reasonable care.
(g) Clause (b) of the second paragraph of Section 23 shall be restated as follows:
(b) any direct damages and any consequential damages permitted under Section 28 arising from the violation of the restrictions on the investment of Fund assets under this Agreement 1) where the decision to invest Fund assets in such investments was made by the Decommissioning Trustee, or 2) if not made by the Decommissioning Trustee, such damages could have been prevented by the Decommissioning Trustee through the exercise of reasonable care in the exercise of its duties hereunder, including but not limited to its duties of supervision and review under Section 8 hereof, and/or
(h) The following Section 28 shall be added:
Section 28: Notwithstanding anything in this Agreement to the contrary, the Decommissioning Trustee shall not be responsible or liable for its failure to perform under this Agreement or for any losses to the Funds resulting from any event beyond the reasonable control of the Decommissioning Trustee, its agents or subcustodians, including but not limited to nationalization, strikes, expropriation, devaluation, seizure, or similar action by any governmental authority, de facto or de jure; or enactment, promulgation, imposition or enforcement by any such governmental authority of currency restrictions, exchange controls, levies or other charges affecting the Funds' property; or the breakdown, failure or malfunction of any utilities or telecommunications systems; or any order or regulation of any banking or securities industry including changes in market rules and market conditions affecting the execution or settlement of transactions; or acts of war, terrorism, insurrection or revolution; or acts of God; or any other similar event. The Decommissioning Trustee shall not be liable for any indirect, consequential, or special damages with respect to its role as Decommissioning Trustee to the extent such damages exceed the Trustee's annual compensation under this Agreement for the previous calendar year. This Section shall survive the termination of this Agreement.
(i) EXHIBIT B to the Decommissioning Trust Agreement is hereby deleted and replaced in its entirety by EXHIBIT B hereto.
SECTION 2. Miscellaneous
(a) Full Force and Effect.
Except as expressly provided herein, the Decommissioning Trust Agreement shall remain unchanged and in full force and effect. Each reference in the Decommissioning Trust Agreement and in any exhibit or schedule thereto to `this Agreement," "hereto," "hereof" and terms of similar import shall be deemed to refer to the Decommissioning Trust Agreement as amended hereby.
(b) Counterparts/Representations.
The Amendment No. 3 may be executed in any number of counterparts, all of which taken together shall constitute one and the same instrument, and any of the parties hereto may execute this Amendment No. 3 by signing any such counterpart. Each party represents and warrants to the other that it has full authority to enter into this Amendment upon the terms and conditions hereof and that the individual executing this Amendment on its behalf has the requisite authority to bind that Party.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 3 to the Decommissioning Trust Agreement to be duly executed as of the day and year first above written.
ARIZONA PUBLIC SERVICE COMPANY
MELLON BANK, N.A. as
Decommissioning Trustee
STATE OF ARIZONA )
) ss:
County of Maricopa )
|
The foregoing instrument was acknowledged before me this 20th day of March, 2002, by Barbara M. Gomez, the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, on behalf of said corporation.
My commission expires:
COMMONWEALTH OF PENNSYLVANIA )
) ss:
County of Allegheny )
|
The foregoing instrument was acknowledged before me this 28th day of March, 2002, by Robert F. Sass, a Vice President of Mellon Bank, N.A. a national banking association having trust powers, as Decommissioning Trustee, on behalf of said national banking association.
My commission expires:
EXHIBIT B
UNIT 1
PERMITTED INVESTMENTS FOR THE
DECOMMISSIONING TRUST FUND AND THE SECOND FUND
The Second Fund must meet all applicable requirements of the Code, and applicable rules and regulations promulgated by the Internal Revenue Service with respect to a Nuclear Decommissioning Reserve Fund.
Subject to the foregoing, the Decommissioning Trust Fund and the Second Fund may invest in any of the following:
SECURITIES
Except as may be constrained elsewhere in these guidelines, the following types of taxable or tax-exempt securities are eligible for investment, including any investment in a common or collective trust fund (including but not limited to, any such fund maintained by the Decommissioning Trustee or any of its affiliates, including but not limited to, the Decommissioning Trustee's Nuclear Decommissioning Trust Equity Index Fund) holding any securities listed in items 1 through 3 below:
1. Debt Obligations of
- The U.S. Government and its agencies or instrumentalities
- States, U.S. possessions, District of Columbia, and any agency or political subdivision thereof
- Domestic corporations
- Municipalities and municipal agencies
2. Asset-backed and mortgage-backed securities
3. Equities
4. FDIC Certificates of Deposit, including but not limited to, those of the Decommissioning Trustee or any of its affiliates
5. Shares of regulated investment companies, including but not limited to, mutual funds, including but not limited to, those for which the Decommissioning Trustee performs advisory management or other services for a fee
6. Cash equivalent securities, including but not limited to, the Decommissioning Trustee's STIF accounts or those of any of its affiliates
QUALITY
1. Debt obligations other than U.S. Government and agency securities must have a rating of at least A by both Moody's Investors Services, Inc. ("Moody's") and Standard & Poor's Ratings Group ("S & P") at time of purchase. This limitation shall not apply to securities that have been pre-refunded where a third party trustee holds direct U.S. Government or agency obligations sufficient to pay debt service and the specified call price to a specific call or maturity date.
2. Commercial paper must be rated at least A-1 by S&P and P-1 by Moody's.
3. Certificates of Deposit must be at a bank with a minimum of one billion dollars in assets as of such bank's most recent report of condition.
DIVERSIFICATION
No investment shall represent more than 10% of the aggregate assets held under this Decommissioning Trust Agreement, the Unit 2 Trust Agreement, and the Unit 3 Trust Agreement combined, except for:
1. Positions in securities issued by the U.S. Government or fully government backed securities or instruments fully pre-refunded where a third party trustee holds direct U.S. Government or agency obligations sufficient to pay debt service and the specified call price to a specific call or maturity date.
2. Units of a common or collective trust fund.
Equity securities are limited to 60% of the aggregate assets held under this Decommissioning Trust Agreement, the Unit 2 Trust Agreement, and the Unit 3 Trust Agreement combined.
Notwithstanding the foregoing, the following restrictions are placed on the investment of the assets of the Funds:
1. Securities of APS, APS' parent corporation, Pinnacle West Capital Corporation, or its affiliates, are not permitted.
2. Securities issued by Maricopa County, Arizona Pollution Control Corporation in connection with the financing of certain facilities at the Palo Verde Nuclear Generation Station are not permitted.
3. Securities issued by or on behalf of any participant in the Palo Verde Nuclear Generating Station are not permitted.
4. Investments in any bank, savings and loan association, or other financial institution whose deposits are not insured by the Federal Deposit Insurance Corporation or other comparable federal agency are not permitted, except that this restriction does not apply to investments in the Decommissioning Trustee's STIF.
5. Property that is settled or safekept outside of the United States is not permitted.
6. The following securities and transactions are explicitly prohibited unless engaged in in the ordinary course by a common or collective trust fund described under the heading "Securities" above:
(a) put and call options on securities, securities indices and foreign currencies;
(b) financial futures contracts including bond, bond index, foreign currency futures contracts and options thereon;
(c) spot and forward currency transactions both to effect securities transactions and to manage currency;
(d) private placements;
(e) preferred stock;
(f) warrants;
(g) margin purchases or borrowing money; and
(h) short selling or securities lending.
Exhibit 10.3
AMENDMENT NO. 6
Decommissioning Trust Agreement
(PVNGS Unit 2)
This Amendment No. 6 dated as of March 18, 2002, to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of January 31, 1992, as amended by Amendment No. 1 thereto dated as of November 1, 1992, Amendment No. 2 thereto dated as of November 1, 1994, Amendment No. 3 thereto dated as of June 20, 1996, Amendment No. 4 thereto dated as of December 16, 1996, and Amendment No. 5 thereto dated as of June 30, 2000 (the "Decommissioning Trust Agreement", terms used herein as therein defined), is entered into between Arizona Public Service Company ("APS"), State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee and as Lessor, and Mellon Bank, N.A., as Decommissioning Trustee ("Decommissioning Trustee").
RECITALS:
WHEREAS, the parties hereto wish to amend the Agreement.
NOW, THEREFORE, in consideration of the premises and of other good and valuable consideration, receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:
SECTION 1. Amendment.
(a) The third and fifth sentences of clause (ii) of Paragraph (c) of
Section 9 shall be restated as follows;
Upon proper notification from the Investment Manager(s), Decommissioning Trustee shall execute and deliver instruments in accordance with the appropriate trading authorizations; provided that the Trustee shall not follow any direction that would result in assets of the Second Fund being invested in assets other than those investments permitted for a qualified nuclear decommissioning reserve fund under Section 468A of the Code and the regulations thereunder.
Such notification shall be proper authority for Decommissioning Trustee to pay for portfolio securities purchased against receipt thereof, and to deliver portfolio securities sold against payment therefor, as the case may be.
(b) Clause (ii) of Paragraph (d) of Section 9 shall be restated as follows:
(ii) Decommissioning Trustee is required to supervise and review the securities and other assets and investments authorized for purchase by the Investment Managers(s) within two weeks of the end of the calendar month during which such purchase was made to determine that such securities, assets and/or investments are Permitted Investments and satisfy the further conditions of this Agreement as set out in Exhibit B. Upon the completion of such review, the Decommissioning Trustee shall promptly notify APS and the Secured Parties and Equity Participants in writing if any
securities, assets or investments are not Permitted Investments or fail to satisfy such further conditions.
(c) The second sentence of the fourth paragraph of Section 24 shall be restated as follows:
Within two weeks of the end of each calendar quarter, the Decommissioning Trustee shall send a written statement to APS and the Secured Parties and Equity Participants indicating whether during that previous quarter such securities, assets and/or investments held in the Funds during that quarter were Permitted Investments and satisfied the further conditions of this Agreement; provided however, the Decommissioning Trustee shall promptly advise APS and the Secured Parties and Equity Participants if it has actual knowledge that any of the investments do not constitute Permitted Investments or otherwise satisfy the further conditions of this Agreement.
(d) The words "any such consequences" shall be added after the words "as provided in this Agreement or" and before the words "could have been prevented" in clause (b) of the first sentence of the second paragraph of Section 26.
(e) The following Section 33 shall be added:
Section 33: Notwithstanding anything in this Agreement to the contrary, the Decommissioning Trustee shall not be responsible or liable for its failure to perform under this Agreement or for any losses to the Funds resulting from any event beyond the reasonable control of the Decommissioning Trustee, its agents or subcustodians, including but not limited to nationalization, strikes, expropriation, devaluation, seizure, or similar action by any governmental authority, de facto or de jure; or enactment, promulgation, imposition or enforcement by any such governmental authority of currency restrictions, exchange controls, levies or other charges affecting the Funds' property; or the breakdown, failure or malfunction of any utilities or telecommunications systems; or any order or regulation of any banking or securities industry including changes in market rules and market conditions affecting the execution or settlement of transactions; or acts of war, terrorism, insurrection or revolution; or acts of God; or any other similar event. The Decommissioning Trustee shall not be liable for any indirect, consequential, or special damages with respect to its role as Decommissioning Trustee to the extent such damages exceed the Trustee's annual compensation under this Agreement for the previous calendar year. This Section shall survive the termination of this Agreement.
(f) EXHIBIT B to the Decommissioning Trust Agreement is hereby deleted and replaced in its entirety by EXHIBIT B hereto.
SECTION 2. Miscellaneous
(a) Full Force and Effect.
Except as expressly provided herein, the Decommissioning Trust Agreement shall remain unchanged and in full force and effect. Each reference in the Decommissioning Trust Agreement and in any exhibit or schedule thereto to "this Agreement," "hereto," "hereof" and terms of similar import shall be deemed to refer to the Decommissioning Trust Agreement as amended hereby.
(b) Counterparts/Representations.
The Amendment No. 6 may be executed in any number of counterparts, all of which taken together shall constitute one and the same instrument, and any of the parties hereto may execute this Amendment No. 6 by signing any such counterpart. Each party represents and warrants to the other that it has full authority to enter into this Amendment upon the terms and conditions hereof and that the individual executing this Amendment on its behalf has the requisite authority to bind that Party.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 6 to the Decommissioning Trust Agreement to be duly executed as of the day and year first above written.
ARIZONA PUBLIC SERVICE COMPANY
MELLON BANK, N.A. as
Decommissioning Trustee
STATE STREET BANK AND TRUST COMPANY, as
Owner Trustee under a Trust Agreement
with Security Pacific Capital Leasing
Corporation and as Lessor under a
Facility Lease with Arizona Public
Service Company
STATE STREET BANK AND TRUST COMPANY, as
Owner Trustee under a Trust Agreement
with Emerson Finance Co. and as Lessor
under a Facility Lease with Arizona
Public Service Company
STATE OF ARIZONA )
) ss:
County of Maricopa )
|
The foregoing instrument was acknowledged before me this 20th day of March, 2002, by Barbara M. Gomez, the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, on behalf of said corporation.
My commission expires:
COMMONWEALTH OF PENNSYLVANIA )
) ss:
County of Allegheny )
|
The foregoing instrument was acknowledged before me this 28th day of March, 2002, by Robert F. Sass, a Vice President of Mellon Bank, N.A. a national banking association having trust powers, as Decommissioning Trustee, on behalf of said national banking association.
My commission expires:
COMMONWEALTH OF MASSACHUSETTS )
) ss:
County of Suffolk )
|
The foregoing instrument was acknowledged before me this 18th day of March, 2002, by Kenneth R. Ring, an Assistant Vice President of State Street Bank and Trust Company, a Massachusetts trust company, in its capacity as Owner Trustee under a Trust Agreement with Security Pacific Capital Leasing Corporation and as Lessor under a Facility Lease with Arizona Public Service Company, on behalf of said association in such capacities.
My commission expires:
COMMONWEALTH OF MASSACHUSETTS )
) ss:
County of Suffolk )
|
The foregoing instrument was acknowledged before me this 18th day of March, 2002, by Kenneth R. Ring, an Assistant Vice President of State Street Bank and Trust Company, a Massachusetts trust company, in its capacity as Owner Trustee under a Trust Agreement with Emerson Finance Company and as Lessor under a Facility Lease with Arizona Public Service Company, on behalf of said association in such capacities.
My commission expires:
EXHIBIT B
UNIT 2
PERMITTED INVESTMENTS FOR THE
DECOMMISSIONING TRUST FUND AND THE SECOND FUND
The Second Fund must meet all applicable requirements of the Code, and applicable rules and regulations promulgated by the Internal Revenue Service with respect to a Nuclear Decommissioning Reserve Fund.
Subject to the foregoing, the Decommissioning Trust Fund and the Second Fund may invest in any of the following obligations or securities maturing at such time or times as to enable payments or transfers to be made from the Funds or which shall be readily marketable prior to the final maturity thereof:
(a) bills, notes, bonds and savings bonds of the Treasury of the United States of America;
(b) obligations of the United States of America not included in clause (a) taken into consideration for purposes of determining the public debt limit of the United States of America;
(c) time or demand deposits in a bank (as defined in Section 581 of the Code) or an insured credit union (within the meaning of Section 101(6) of the Federal Credit Union Act, 12 U.S.C. 1752(7) (1982)) (for the purposes of this paragraph, "time or demand deposits" shall include checking accounts, savings accounts, certificates of deposit, and other time or demand deposits but shall not include common or collective trust funds);
(d) obligations of the Federal National Mortgage Association and Government National Mortgage Association;
(e) AAA rated collateralized mortgage obligations; interest only, principal only, and inverse floaters are specifically prohibited;
(f) commercial paper maturing within 60 days and rated the highest grade by Moody's Investor's Services, Inc. ("Moody's") or Standard & Poor's Corporation ("S & P") or if one of such agencies does not rate such paper, rated the highest grade by the other;
(g) deposit accounts (which may be represented by certificates of deposit) payable on demand or maturing within 180 days, in Federally insured national or state banks; provided, however, if the aggregate amount of such deposit accounts in a bank is $100,000 or more, such bank shall have combined capital and surplus as of its last report of condition exceeding $250,000,000 and a senior unsecured debt rating of Investment Grade;
(h) The Decommissioning Trustee's Short Term Investment Fund ("STIF") account; provided, however, that no more than fifteen percent (15%) of the aggregate assets of the Funds may be invested in the Decommissioning Trustee's STIF account at any one time, except that the full amount of APS' quarterly contribution to the Funds or any portion thereof may be invested in the Decommissioning Trustee's STIF account for a period of up to seven (7) business days after such contribution is made and, during such period, the amount of such contribution or portion thereof that shall have been so invested shall not count against the fifteen percent (15%) limitation in this paragraph (h):
(i) repurchase agreements fully secured (and perfected) by any of the foregoing obligations or securities maturing within 30 days with any Federally insured national or state bank (including Decommissioning Trustee) or any other financial institution that is a nationally recognized dealer that reports to the Market Reports Division of the Federal Reserve Bank of New York; provided, however, if the aggregate face amount of such repurchase agreements with an issuer is $1,000,000 or more, the issuer shall have combined capital and surplus as of its last report of condition exceeding $250,000,000 and a senior unsecured debt rating of Investment Grade;
(j) obligations rated Investment Grade of a State, a possession of the United States of America, the District of Columbia or any political subdivision of the foregoing, the interest on which is exempt from tax under Section 103(a) of the Code;
(k) corporate debt obligations rated Investment Grade; and
(l) (x) corporate equity securities, including, but not limited to,
investment in units of common or collective trust funds investing in corporate
equity securities; including, but not limited to, the Decommissioning Trustee's
Nuclear Decommissioning Trust Equity Index Fund (the "NDT Equity Index Fund")
and (y) obligations not included in clauses (a) through (k) issued or guaranteed
by a person controlled or supervised by and acting as an instrumentality of the
United States of America pursuant to authority granted by the Congress of the
United States of America, including Federal Intermediate Credit Bank, Banks for
Cooperatives, Federal Land Banks, Federal Home Loan Banks, Federal Home Loan
Mortgage Corporation; provided, that no more than fifty percent (50%) of the
aggregate assets of the Funds may be invested in securities described in (x) and
(y) of this subparagraph (1) during the period from June 27, 1996 through
December 31, 2003, no more than thirty percent (30%) during the period from
January 1, 2004 through December 31, 2006, and no more than fifteen percent
(15%) during the period from January 1, 2007 through January 31, 2010; and
provided further that after January 31, 2010, no investments shall be made in
such securities.
Notwithstanding the foregoing, the following restrictions are placed on the investment of the assets of the Funds:
1. Securities of APS, APS' parent corporation, Pinnacle West Capital Corporation, or its affiliates, are not permitted.
2. Securities issued by Maricopa County, Arizona Pollution Control Corporation in connection with the financing of certain facilities at the Palo Verde Nuclear Generation Station are not permitted.
3. Securities issued by or on behalf of any participant in the Palo Verde Nuclear Generating Station are not permitted.
4. Investments in any bank or other financial institution whose deposits are not insured by the Federal Deposit Insurance Corporation or other comparable federal agency are not permitted, except that this restriction does not apply to investments in the Decommissioning Trustee's STIF.
5. There shall be no short-selling, securities lending, options trading,
financial futures, over-the-counter derivative transactions, or other
specialized investment activity, except as specifically allowed in paragraphs
(a) through (1) hereof, or except as may be effected in the ordinary course of
operation of the Decommissioning Trustee's STIF account or its NDT Equity Index
Fund.
6. No investment shall be made which would cause the holding of any one issue (excluding obligations of the United States Government and agencies of or guaranteed by the United States Government and excluding units of a common or collective trust fund), to exceed ten percent (10%) of the aggregate assets held under this Decommissioning Trust Agreement, the Unit 1 Trust Agreement, and the Unit 3 Trust Agreement, valued at cost.
7. Bank certificates of deposit must be at banks with a minimum of one billion ($1,000,000,000) in assets as of such banks' most recent report of condition.
8. Short-term taxable and non-taxable debt securities are not permitted unless such securities have a rating of at least P-1 by Moody's or at least A-1 by S&P.
9. Long-term taxable and non-taxable debt securities are not permitted unless such securities have a rating of at least "A" by Moody's or S&P.
10. No investment shall be made which would cause sixty percent (60%) or more of the aggregate assets held under this Decommissioning Trust Agreement and the Unit 1 Trust Agreement and the Unit 3 Trust Agreement to be invested in equity securities.
Exhibit 10.4
AMENDMENT NO. 3
Decommissioning Trust Agreement
(PVNGS Unit 3)
This Amendment No. 3 dated as of March 18, 2002, to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of July 1, 1991, as amended by Amendment No. 1 thereto dated as of December 1, 1994 and Amendment No. 2 thereto dated as of December 16, 1996 (the "Decommissioning Trust Agreement", terms used herein as therein defined), is entered into between Arizona Public Service Company ("APS") and Mellon Bank, N.A., as Decommissioning Trustee ("Decommissioning Trustee").
RECITALS:
WHEREAS, the parties hereto wish to amend the Agreement.
NOW, THEREFORE, in consideration of the premises and of other good and valuable consideration, receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:
SECTION 1. Amendment.
(a) The period at the end of clause (iii) in Section 8, paragraph (a) is
deleted and ";or" is added in its place and the following subparagraph
(iv) shall be added to Section 8, paragraph (a):
"(iv) in any property safekept or settled outside of the United States".
(b) The third and fifth sentences of clause (ii) of Paragraph (c) of
Section 8 shall be restated as follows;
Upon proper notification from the Investment Manager(s), Decommissioning Trustee shall execute and deliver instruments in accordance with the appropriate trading authorizations; provided that the Trustee shall not follow any direction that would result in assets of the Second Fund being invested in assets other than those investments permitted for a qualified nuclear decommissioning reserve fund under Section 468A of the Code and the regulations thereunder.
Such notification shall be proper authority for Decommissioning Trustee to pay for portfolio securities purchased against receipt thereof, and to deliver portfolio securities sold against payment therefor, as the case may be.
(c) Clause (ii) of Paragraph (d) of Section 8 shall be restated as follows:
(ii) Decommissioning Trustee is required to supervise and review the securities and other assets and investments authorized for purchase by the Investment Managers(s) within two weeks of the end of the calendar month during which such purchase was made to determine that such securities, assets and/or investments are
Permitted Investments and satisfy the further conditions of this Agreement as set out in Exhibit B. Upon the completion of such review, the Decommissioning Trustee shall promptly notify APS in writing if any securities, assets or investments are not Permitted Investments or fail to satisfy such further conditions.
(d) The following shall be added to Section 11:
Notwithstanding the foregoing, if the Decommissioning Trustee advances cash or securities for any purpose or in the event that the Decommissioning Trustee shall incur or be assessed taxes, interest, charges, expenses, assessments, or other liabilities in connection with the performance of this Agreement, except such as may arise from its own negligent action, negligent failure to act or willful misconduct, any property at any time held for the Funds or under this Agreement shall be security therefor and the Decommissioning Trustee shall be entitled to collect from the Funds sufficient cash for reimbursement, and if such cash is insufficient, dispose of the assets held under this Agreement to the extent necessary to obtain reimbursement. To the extent the Decommissioning Trustee advances funds to the Funds for disbursements or to effect the settlement of purchase transactions, the Decommissioning Trustee shall be entitled to collect from the Funds an amount equal to what would have been earned on the sums advanced (an amount approximating the "federal funds" interest rate).
(e) The second sentence of the fourth paragraph of Section 21 shall be restated as follows:
Decommissioning Trustee shall promptly advise APS if it has actual knowledge that any of the investments do not constitute Permitted Investments or otherwise satisfy the further conditions of this Agreement.
(f) The first sentence of Section 23 shall be restated as follows:
Decommissioning Trustee shall not be liable for any acts, omissions, or defaults of any agent (other than its officers and employees), provided such agent was selected with reasonable care and the performance and status of such agent is monitored with reasonable care.
(g) Clause (b) of the second paragraph of Section 23 shall be restated as follows:
(b) any direct damages and any consequential damages permitted under Section 28 arising from the violation of the restrictions on the investment of Fund assets under this Agreement 1) where the decision to invest Fund assets in such investments was made by the Decommissioning Trustee, or 2) if not made by the Decommissioning Trustee, such damages could have been prevented by the Decommissioning Trust through the exercise of reasonable care in the exercise of its duties hereunder, including but not limited to its duties of supervision and review under Section 8 hereof, and/or
(h) The following Section 28 shall be added:
Section 28: Notwithstanding anything in this Agreement to the contrary, the Decommissioning Trustee shall not be responsible or
liable for its failure to perform under this Agreement or for any losses to the Funds resulting from any event beyond the reasonable control of the Decommissioning Trustee, its agents or subcustodians, including but not limited to nationalization, strikes, expropriation, devaluation, seizure, or similar action by any governmental authority, de facto or de jure; or enactment, promulgation, imposition or enforcement by any such governmental authority of currency restrictions, exchange controls, levies or other charges affecting the Funds' property; or the breakdown, failure or malfunction of any utilities or telecommunications systems; or any order or regulation of any banking or securities industry including changes in market rules and market conditions affecting the execution or settlement of transactions; or acts of war, terrorism, insurrection or revolution; or acts of God; or any other similar event. The Decommissioning Trustee shall not be liable for any indirect, consequential, or special damages with respect to its role as Decommissioning Trustee to the extent such damages exceed the Trustee's annual compensation under this Agreement for the previous calendar year. This Section shall survive the termination of this Agreement.
(i) EXHIBIT B to the Decommissioning Trust Agreement is hereby deleted and replaced in its entirety by EXHIBIT B hereto.
SECTION 2. Miscellaneous
(a) Full Force and Effect.
Except as expressly provided herein, the Decommissioning Trust Agreement shall remain unchanged and in full force and effect. Each reference in the Decommissioning Trust Agreement and in any exhibit or schedule thereto to "this Agreement," "hereto," "hereof" and terms of similar import shall be deemed to refer to the Decommissioning Trust Agreement as amended hereby.
(b) Counterparts/Representations.
The Amendment No. 3 may be executed in any number of counterparts, all of which taken together shall constitute one and the same instrument, and any of the parties hereto may execute this Amendment No. 3 by signing any such counterpart. Each party represents and warrants to the other that it has full authority to enter into this Amendment upon the terms and conditions hereof and that the individual executing this Amendment on its behalf has the requisite authority to bind that Party.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 3 to the Decommissioning Trust Agreement to be duly executed as of the day and year first above written.
ARIZONA PUBLIC SERVICE COMPANY
MELLON BANK, N.A. as
Decommissioning Trustee
STATE OF ARIZONA )
) ss:
County of Maricopa )
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The foregoing instrument was acknowledged before me this 20th day of March, 2002, by Barbara M. Gomez, the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, on behalf of said corporation.
My commission expires:
COMMONWEALTH OF PENNSYLVANIA )
) ss:
County of Allegheny )
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The foregoing instrument was acknowledged before me this 28th day of March, 2002, by Robert F. Sass, a Vice President of Mellon Bank, N.A. a national banking association having trust powers, as Decommissioning Trustee, on behalf of said national banking association.
My commission expires:
EXHIBIT B
UNIT 3
PERMITTED INVESTMENTS FOR THE
DECOMMISSIONING TRUST FUND AND THE SECOND FUND
The Second Fund must meet all applicable requirements of the Code, and applicable rules and regulations promulgated by the Internal Revenue Service with respect to a Nuclear Decommissioning Reserve Fund.
Subject to the foregoing, the Decommissioning Trust Fund and the Second Fund may invest in any of the following:
SECURITIES
Except as may be constrained elsewhere in these guidelines, the following types of taxable or tax-exempt securities are eligible for investment, including any investment in a common or collective trust fund (including but not limited to, any such fund maintained by the Decommissioning Trustee or any of its affiliates, including but not limited to, the Decommissioning Trustee's Nuclear Decommissioning Trust Equity Index Fund) holding any securities listed in items 1 through 3 below:
1. Debt Obligations of
- The U.S. Government and its agencies or instrumentalities
- States, U.S. possessions, District of Columbia, and any agency or political subdivision thereof
- Domestic corporations
- Municipalities and municipal agencies
2. Asset-backed and mortgage-backed securities
3. Equities
4. FDIC Certificates of Deposit, including but not limited to, those of the Decommissioning Trustee or any of its affiliates
5. Shares of regulated investment companies, including but not limited to, mutual funds, including but not limited to, those for which the Decommissioning Trustee performs advisory management or other services for a fee
6. Cash equivalent securities, including but not limited to, the Decommissioning Trustee's STIF accounts or those of any of its affiliates
QUALITY
1. Debt obligations other than U.S. Government and agency securities must have a rating of at least A by both Moody's Investors Services, Inc. ("Moody's") and Standard & Poor's Ratings Group ("S & P") at time of purchase. This limitation shall not apply to securities that have been pre-refunded where a third party trustee holds direct U.S. Government or agency obligations sufficient to pay debt service and the specified call price to a specific call or maturity date.
2. Commercial paper must be rated at least A-1 by S&P and P-1 by Moody's.
3. Certificates of Deposit must be at a bank with a minimum of one billion dollars in assets as of such bank's most recent report of condition.
DIVERSIFICATION
No investment shall represent more than 10% of the aggregate assets held under this Decommissioning Trust Agreement, the Unit 2 Trust Agreement, and the Unit 1 Trust Agreement combined, except for:
1. Positions in securities issued by the U.S. Government or fully government backed securities or instruments fully pre-refunded where a third party trustee holds direct U.S. Government or agency obligations sufficient to pay debt service and the specified call price to a specific call or maturity date.
2. Units of a common or collective trust fund.
Equity securities are limited to 60% of the aggregate assets held under this Decommissioning Trust Agreement, the Unit 2 Trust Agreement, and the Unit 1 Trust Agreement combined.
Notwithstanding the foregoing, the following restrictions are placed on the investment of the assets of the Funds:
1. Securities of APS, APS' parent corporation, Pinnacle West Capital Corporation, or its affiliates, are not permitted.
2. Securities issued by Maricopa County, Arizona Pollution Control Corporation in connection with the financing of certain facilities at the Palo Verde Nuclear Generation Station are not permitted.
3. Securities issued by or on behalf of any participant in the Palo Verde Nuclear Generating Station are not permitted.
4. Investments in any bank, savings and loan association, or other financial institution whose deposits are not insured by the Federal Deposit Insurance Corporation or other comparable federal agency are not permitted, except that this restriction does not apply to investments in the Decommissioning Trustee's STIF.
5. Property that is settled or safekept outside of the United States is not permitted.
6. The following securities and transactions are explicitly prohibited unless engaged in in the ordinary course by a common or collective trust fund described under the heading "Securities" above:
(a) put and call options on securities, securities indices and foreign currencies;
(b) financial futures contracts including bond, bond index, foreign currency futures contracts and options thereon;
(c) spot and forward currency transactions both to effect securities transactions and to manage currency;
(d) private placements;
(e) preferred stock;
(f) warrants;
(g) margin purchases or borrowing money; and
(h) short selling or securities lending.
Exhibit 12.1
PINNACLE WEST CAPITAL CORPORATION
Computation of Earnings to Fixed Charges
($000's)
THREE
MONTHS
ENDED
3/31/02 2001 2000 1999 1998 1997
-------- -------- -------- -------- -------- --------
Income From Continuing Operations $ 53,757 $327,367 $302,332 $269,772 $242,892 $235,856
Income Taxes 35,228 213,535 194,200 141,592 138,589 126,943
Fixed Charges 52,802 211,958 202,804 194,070 201,184 215,201
-------- -------- -------- -------- -------- --------
Total $141,787 $752,860 $699,336 $605,434 $582,665 $578,000
Fixed Charges:
Interest Expense $ 44,688 $175,822 $166,447 $157,142 $163,975 $177,383
Estimated Interest Portion of Annual Rents 8,114 36,136 36,357 36,928 37,209 37,818
-------- -------- -------- -------- -------- --------
Total Fixed Charges $ 52,802 $211,958 $202,804 $194,070 $201,184 $215,201
Ratio of Earnings to Fixed Charges (rounded down) 2.68 3.55 3.44 3.11 2.89 2.68
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