ITEM 1. BUSINESS
GENERAL
We were incorporated in 1920 under the laws of Arizona and are Arizona's largest electric utility, with more than 850,000 customers. We provide wholesale or retail electric service to the entire state of Arizona, with the exception of Tucson and about one-half of the Phoenix area. We also generate and, directly or through Pinnacle West's power marketing division, sell and deliver electricity to wholesale customers in the western United States. During 2000, no single purchaser or user of energy accounted for more than 3.5% of total electric revenues.
At December 31, 2000, we employed about 5,300 people, which includes employees assigned to joint projects where we are project manager. Our principal executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000).
See Note 16 of Notes to Financial Statements in Item 8 for a discussion of our business segments.
FORWARD-LOOKING STATEMENTS
This document contains forward-looking statements based on current expectations and we assume no obligation to update these statements. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by us. These factors include the ongoing restructuring of the electric industry; the outcome of regulatory and legislative proceedings relating to the restructuring; regional economic and market conditions, including the California energy situation, which could affect customer growth and the cost of power supplies; the cost of debt and equity capital; weather variations affecting local and regional customer energy usage; conservation programs; our ability to compete successfully outside traditional regulated markets (including the wholesale market); and technological developments in the electric industry.
REGULATION AND COMPETITION
RETAIL
The ACC regulates our retail electric rates and our issuance of securities. The ACC must also approve any transfer of our utility property and transactions between us and affiliated parties. See "Financial Review - Business Outlook - Competition and Industry Restructuring" in Item 7 and Note 3 of Notes to Financial Statements in Item 8 for a discussion of electric industry restructuring in Arizona, including our 1999 Settlement Agreement, the ACC retail electric competition rules, and the legal challenges to both the 1999 Settlement Agreement and the Rules.
Although the Rules allow retail customers to have access to competitive providers of energy and energy services, we are the " provider of last resort" for standard offer customers under rates that have been approved by the ACC. These rates are fixed until July 1, 2004. The 1999 Settlement
Agreement allows us to seek adjustment of these rates in the event of emergency conditions or circumstances, such as the inability to secure financing on reasonable terms, or material changes in our cost of service for ACC-regulated services resulting from federal, tribal, state or local laws, regulatory requirements, judicial decisions, actions or orders. Energy prices in the western wholesale market vary and, during the course of the last year, have been volatile. At various times, prices in the spot wholesale market have significantly exceeded the amount included in our current retail rates. We expect these market conditions to continue in 2001. We believe that our current generation portfolio has been adequately supplemented with power purchased through contracts and hedging techniques that limit exposure to the volatile spot wholesale power market. However, in the event of shortfalls due to unforeseen increases in load demand or generation outages, we may need to purchase additional supplemental power in the wholesale spot market. Unless we are able to obtain an adjustment of our rates under the 1999 Settlement Agreement, there can be no assurance that we would be able to fully recover the costs of this power.
As discussed in "Financial Review - Electric Competition (Retail)" in Item 7 and in Note 3 of Notes to Financial Statements in Item 8, the 1999 Settlement Agreement authorizes us to transfer our competitive generation assets and services to one or more corporate affiliates no later than December 31, 2002. We intend to move our generation assets to Pinnacle West Energy within that timeframe. Following its receipt of these generation assets, Pinnacle West Energy expects to sell its power at wholesale to Pinnacle West's power marketing division (Power Marketing). Power Marketing, in turn, is expected to sell power to us and to non-affiliated power purchasers. We expect to meet fifty percent of our energy needs under a power purchase agreement with Power Marketing. As required by the Rules, we will acquire the remaining fifty percent of our energy needs through a competitive bid process in which Power Marketing may participate. We believe that these arrangements will allow us to manage our exposure to the wholesale power market during the period within which our rates are fixed, as discussed in the preceding paragraph.
In addition to the introduction of competition pursuant to the 1999 Settlement Agreement and the Rules, we are subject to varying degrees of competition from other utilities in our region (such as Tucson Electric Power Company, Southwest Gas Corporation, and Citizens Communications Company) as well as cooperatives, municipalities, electrical districts, and similar types of governmental organizations (principally Salt River Project). We also face competition from low-cost hydroelectric power and parties that have access to preferential low-priced federal power and other subsidies. In addition, some customers, particularly industrial and large commercial customers, may own and operate facilities to generate their own electric energy requirements.
WHOLESALE
We compete with other utilities, power marketers, and independent power producers in the sale of electric capacity and energy in the wholesale market. We expect competition in the wholesale market will remain vigorous. The FERC regulates rates for wholesale power sales and transmission services. During 2000, approximately 46% of our electric operating revenues resulted from such sales and services. We transferred the wholesale power marketing function to Pinnacle West during 2000.
The 1992 Energy Act and the FERC's rulemaking activities have established the regulatory framework to open the wholesale energy market to competition. The 1992 Energy Act permits utilities to develop independent electric generating plants for sales to wholesale customers, and authorizes the FERC to order transmission access for third parties to transmission facilities owned by another entity. The 1992 Energy Act does not, however, permit the FERC to require transmission access to retail customers. Open-access transmission for wholesale customers provides energy suppliers, including us, with opportunities to sell and deliver electricity at market-based prices.
On December 20, 1999, the FERC issued its Order No. 2000 regarding Regional Transmission Organizations (RTO). In its order, the FERC stressed the voluntary nature of RTO participation by utilities and set minimum characteristics and functions that must be met by utilities that participate in RTOs. The order provides for an open, flexible structure for RTOs to meet the needs of the market, and provides for the possibility of incentive ratemaking and other benefits for utilities that participate in an RTO.
The characteristics for an acceptable RTO include independence from market participants, operational control over a region large enough to support efficient and nondiscriminatory markets, and exclusive authority to maintain short-term reliability. As required by the FERC order, we, along with several neighboring transmission owners located in the southwestern United States, filed a report with the FERC on October 16, 2000 that detailed the progress in establishing an RTO that would be responsible for ensuring transmission reliability and nondiscriminatory access to the regional transmission grid. We expect that Desert STAR, the non-profit corporation named in the filing, will make additional filings with the FERC in the near future to establish itself as an RTO for the region.
See "Financial Review - Business Outlook - California Energy Market Issues" in Item 7 for a discussion of the energy situation in California.
The ACC retail electric competition rules require the formation and implementation of an Arizona Independent Scheduling Administrator Association. The AISA is anticipated to be a temporary organization until the formation and implementation of an independent system operator or RTO. We, as an "Affected Utility" under the Rules, participated in the creation of the AISA. Recently, the board of AISA approved a set of operating protocols that have been filed with the FERC. The operating protocols were partially rejected and the remainder are currently under review.
See "Financial Review - Business Outlook - Competition and Industry Restructuring" in Item 7 and Note 3 of Notes to Financial Statements in Item 8 for additional information about the ACC Rules and the legal challenges to the Rules.
REGULATORY ASSETS
Our major regulatory assets are deferred income taxes and rate synchronization cost deferrals. As a result of our 1999 Settlement Agreement, we discontinued the application of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," for our generation operations. As a result, we tested the generation assets for impairment and determined that the generation assets were not impaired. Pursuant to the 1999 Settlement Agreement, we reported a regulatory disallowance ($140 million after income taxes) as an extraordinary charge on the 1999 income statement. Prior to the 1999 Settlement Agreement, under a 1996 regulatory agreement, the ACC accelerated the amortization of substantially all of our regulatory assets to an eight-year period that would have ended June 30, 2004. The regulatory assets to be recovered under the 1999 Settlement Agreement are being amortized pursuant to a revised amortization schedule. See Notes 1, 3, and 9 of Notes to Financial Statements in Item 8 for additional information.
GENERATING FUEL AND PURCHASED POWER
2000 ENERGY MIX
Our sources of energy during 2000 were: purchased power - 46.0% (approximately 88% of which was for wholesale power operations); coal - 27.9%; nuclear - 19.8%; gas - 6.0%; and other (including oil, hydro and solar) - 0.3%.
COAL SUPPLY
CHOLLA We purchase most of Cholla's coal requirements from a coal supplier who mines all of the coal under a long-term lease of coal reserves owned by the Navajo Nation, the federal government, and private landholders. Cholla has sufficient coal under current contracts to ensure a reliable fuel supply through 2005. We purchase a portion of Cholla's coal requirements on the spot market to take advantage of competitive pricing options. Following expiration of current contracts, we believe that numerous competitive fuel supply options will exist to ensure continuous plant operation. We expect the current supplier to continue to provide most of Cholla's low sulfur coal requirements through the current contract. We believe that there are sufficient reserves of low sulfur coal available from other suppliers to ensure the continued operation of Cholla for its useful life.
FOUR CORNERS We purchase all of Four Corners' coal requirements from a coal supplier with a long-term lease of coal reserves owned by the Navajo Nation. Four Corners is under contract for coal through 2004, with options to extend the contract through the plant site lease expiration in 2017. The Four Corners lease waives, until July 2001, the requirement that we and our fuel supplier pay certain taxes to the Navajo Nation. The coal supplier currently pays a possessory interest tax to the Navajo Nation, which is reimbursed by the Four Corners participants. The coal supplier, the Navajo Nation, and the Four Corners participants agreed to investigate alternative contractual arrangements and business relationships before the expiration of tax waivers in an effort to permit the electricity generated at Four Corners to be priced competitively. We anticipate that the Navajo Nation will levy additional taxes upon the expiration of the tax waivers; however, we cannot currently predict the outcome of this matter or the amount of any additional taxes.
NAVAJO GENERATING STATION The Navajo Generating Station's coal requirements are purchased from a supplier with long-term leases from the Navajo Nation and the Hopi Tribe. The Navajo Generating Station is under contract with its coal supplier through 2011, with options to extend through the plant site lease expiration in 2019. The Navajo Generating Station lease waives certain taxes through the lease expiration in 2019. The lease provides for the potential to renegotiate the coal royalty in 2007 and 2017, which may impact the fuel price.
See "Properties - Accredited Capacity" in Item 2
ITEM 2. PROPERTIES
ACCREDITED CAPACITY
Our present generating facilities have an accredited capacity as follows:
Capacity(kW) ---------- Coal: Units 1, 2, and 3 at Four Corners............................. 560,000 15% owned Units 4 and 5 at Four Corners....................... 222,000 Units 1, 2, and 3 at Cholla Plant............................. 615,000 14% owned Units 1, 2, and 3 at the Navajo Plant............... 315,000 ----------
1,712,000 Gas or Oil: Two steam units at Ocotillo and two steam units at Saguaro.... 435,000(1) Eleven combustion turbine units............................... 493,000 Three combined cycle units.................................... 255,000 ----------
1,183,000 Nuclear: 29.1% owned or leased Units 1, 2, and 3 at Palo Verde......... 1,086,300 ----------
Hydro and Solar................................................. 6,000 ----------
Total 3,987,300 ==========
- ---------- (1) West Phoenix steam units (108,300 kW) are currently mothballed, but are expected to be back in service by summer 2001.
RESERVE MARGIN
Our 2000 peak one-hour demand on its electric system was recorded on July 25, 2000 at 5,478,500 kW, compared to the 1999 peak of 4,934,700 kW recorded on August 24. Taking into account additional capacity then available to us under long-term purchase power contracts as well as our own generating capacity, our capability of meeting system demand on July 25, 2000, amounted to 4,774,600 kW, for an installed reserve margin of (15.3%). The power actually available to us from our resources fluctuates from time to time due in part to planned outages and technical problems. The available capacity from sources actually operable at the time of the 2000 peak amounted to 3,501,600 kW, for a margin of (27.5%). Firm purchases, including short-term seasonal purchases, totaling 2,238,000 kW were in place at the time of the peak ensuring the ability to meet the load requirement, with an actual reserve margin of 6.4%.
See "Business - Purchased Power Agreements" in Item 1 for information about certain of our long-term power agreements.
PLANT SITES LEASED FROM NAVAJO NATION
The Navajo Generating Station and Four Corners are located on land held under easements from the federal government and also under leases from the Navajo Nation. These are long term agreements with options to extend, and we do not believe that the risk with respect to enforcement of these easements and leases is material. The majority of coal contracted for use in these plants and certain associated transmission lines are also located on Indian reservations. See "Generating Fuel and Purchased Power ___ Coal Supply" in Item 1.
See "Generating Fuel and Purchased Power - Coal Supply" in Item 1 for a discussion of changes in the amount of royalty payments and expiration of tax waivers under the Navajo Generating Station and Four Corners leases.
PALO VERDE NUCLEAR GENERATING STATION
PALO VERDE LEASES
See Note 9 of Notes to Financial Statements in Item 8 for a discussion of three sale and leaseback transactions related to Palo Verde Unit 2.
REGULATORY
Operation of each of the three Palo Verde units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986, and Unit 3 in November 1987. The full power operating licenses, each valid for a period of approximately 40 years, authorize us, as operating agent for Palo Verde, to operate the three Palo Verde units at full power.
NUCLEAR DECOMMISSIONING COSTS
NRC rules on financial assurance requirements for the decommissioning of nuclear power plants provide that a licensee may use an external sinking fund as the exclusive financial assurance mechanism if the licensee recovers estimated total decommissioning costs through cost of service rates or through a "non-bypassable charge." Other mechanisms are prescribed, including prepayment, if the requirements for exclusive reliance on the external sinking fund mechanism are not met. We currently rely on the external sinking fund mechanism to meet the NRC financial assurance requirements for our interests in Palo Verde Units 1, 2, and 3. The decommissioning costs of Palo Verde Units 1, 2, and 3 are currently included in ACC jurisdictional rates. ACC retail electric competition rules provide that decommissioning costs would be recovered through a non-bypassable "system benefits" charge, which would allow us to maintain our external sinking fund mechanism. See Note 13 of Notes to Financial Statements in Item 8 for additional information about our nuclear decommissioning costs. See "Financial Review - Business Outlook - Competition and Industry Restructuring" in Item 7 and Note 3 of Notes to Financial Statements in Item 8 for additional information about the ACC retail electric competition rules and the legal challenges to these rules.
PALO VERDE LIABILITY AND INSURANCE MATTERS
See "Palo Verde Nuclear Generating Station" in Note 12 of Notes to Financial Statements in Item 8 for a discussion of the insurance maintained by the Palo Verde participants, including us, for Palo Verde.
OTHER INFORMATION REGARDING OUR PROPERTIES
See "Environmental Matters" and "Water Supply" in Item 1 with respect to matters having possible impact on the operation of certain of our power plants.
See "Construction Program" in Item 1 and "Financial Review ___ Capital Needs and Resources" in Item 7 for a discussion of our construction plans.
See Notes 5, 8, and 9 of Notes to Financial Statements in Item 8 with respect to our property not held in fee or held subject to any major encumbrance.
[MAP PAGE]
In accordance with Item 304 of Regulation S-T of the Securities Exchange Act of 1934, our Service Territory map contained in this Form 10-K is a map of the State of Arizona showing the Company's service area, the location of its major power plants and principal transmission lines, and the location of transmission lines operated by the Company for others. The major power plants shown on such map are the Navajo Generating Station located in Coconino County, Arizona; the Four Corners Power Plant located near Farmington, New Mexico; the Cholla Power Plant, located in Navajo County, Arizona; the Yucca Power Plant, located near Yuma, Arizona; and the Palo Verde Nuclear Generating Station, located about 55 miles west of Phoenix, Arizona (each of which plants is reflected on such map as being jointly owned with other utilities), as well as the Ocotillo Power Plant and West Phoenix Power Plant, each located near Phoenix, Arizona, and the Saguaro Power Plant, located near Tucson, Arizona. The Company's major transmission lines shown on such map are reflected as running between the power plants named above and certain major cities in the State of Arizona. The transmission lines operated for others shown on such map are reflected as running from the Four Corners Plant through a portion of northern Arizona to the California border.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
In June 1999, the Navajo Nation served Salt River Project with a lawsuit naming Salt River Project, several Peabody Coal Company entities, Southern California Edison Company and other defendants, and citing various claims in connection with the renegotiations of the coal royalty and lease agreements under which Peabody mines coal for Navajo Generating Station and the Mohave Generating Station. THE NAVAJO NATION V. PEABODY HOLDING COMPANY, INC., ET AL., UNITED STATES DISTRICT COURT FOR THE DISTRICT OF COLUMBIA, CA-99-0469-EGS. We are a 14% owner of the Navajo Generating Station, which Salt River Project operates. The suit alleges, among other things, that the defendants obtained a favorable coal royalty rate by improperly influencing the outcome of a federal administrative process under which the royalty rate was to be adjusted. The suit seeks $600 million in damages, treble damages, punitive damages of not less than $1 billion, and the ejection of defendants "from all possessory interests and Navajo Tribal lands" arising out of the [primary coal lease]. Salt River Project has advised us that it denies all charges and will vigorously defend itself. Because the litigation is in preliminary stages, we cannot currently predict the outcome of this matter.
See "Environmental Matters" and "Water Supply" in Item 1 in regard to pending or threatened litigation and other disputes. See Note 3 of Notes to Financial Statements in Item 8 for a discussion of competition and the ACC retail electric competition rules and related litigation. In December 1999, we filed a lawsuit to protect our legal rights regarding the rules, and in the complaint we asked the Court for (i) a judgment vacating the retail electric competition rules, (ii) a declaratory judgment that the rules are unlawful because, among other things, they were entered into without proper legal authorization, and (iii) a permanent injunction barring the ACC from enforcing or implementing the rules and from promulgating any other regulations without lawful authority. ARIZONA PUBLIC SERVICE COMPANY V. ARIZONA CORPORATION COMMISSION, CV 99-21907. On August 28, 1998, we filed two lawsuits to protect our legal rights under the stranded cost order and in our complaints we asked the Court to vacate and set aside the order. ARIZONA PUBLIC SERVICE COMPANY V. ARIZONA CORPORATION COMMISSION, CV 98-15728. ARIZONA PUBLIC SERVICE COMPANY V. ARIZONA CORPORATION COMMISSION, 1-CA-CC-98-0008.
We are a party to a power service agreement with Citizens Communications Company under which we supply Citizens with power. By letter dated March 7, 2001, Citizens advised us that it believes we have overcharged Citizens by over $50 million under the agreement since the summer of 2000. We believe that our charges to Citizens under the agreement are fully in accordance with the terms of the agreement and we will vigorously defend any contrary claims raised by Citizens.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER MATTERS
The Company's common stock is wholly-owned by Pinnacle West and is not listed for trading on any stock exchange. As a result, there is no established public trading market for the Company's common stock.
The chart below sets forth the dividends declared on the Company's common stock for each of the four quarters for 2000 and 1999.
COMMON STOCK DIVIDENDS (DOLLARS IN THOUSANDS)
QUARTER 2000 1999 ------- ------- ------- 1st Quarter $42,500 $42,500 2nd Quarter 42,500 42,500 3rd Quarter 42,500 42,500 4th Quarter 42,500 42,500
After payment or setting aside for payment of cumulative dividends and mandatory sinking fund requirements, where applicable, on all outstanding issues of preferred stock, the holders of common stock are entitled to dividends when and as declared out of funds legally available therefor. See Note 5 of Notes to Financial Statements in Item 8 for restrictions on retained earnings available for the payment of common stock dividends.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
See "Financial Review" in Item 7
ITEM 7. FINANCIAL REVIEW
INTRODUCTION
In this section, we explain the results of operations, general financial condition, and outlook including:
* the changes in our earnings from 1999 to 2000 and from 1998 to 1999;
* the effects of regulatory agreements on our results and outlook;
* our capital needs and resources;
* major factors that affect our financial outlook; and
* our management of market risks.
OVERVIEW OF OUR BUSINESS
We are Arizona's largest electric utility and provide retail and wholesale electric service to the entire state with the exception of Tucson and about one-half of the Phoenix area. We also generate and, directly or through Pinnacle West's power marketing division, sell and deliver electricity to wholesale customers in the western United States. Pinnacle West owns all of our outstanding common stock.
Throughout this Financial Review, we refer to specific "Notes" in the Notes to Financial Statements that begin on page 42. These Notes add further details to the discussion.
RESULTS OF OPERATIONS
2000 COMPARED WITH 1999
Our 2000 earnings were $307 million compared with $127 million in 1999. Our 2000 earnings increased $180 million over 1999 primarily because of a $140 million after-tax extraordinary charge that we recorded in 1999. This charge reflected a regulatory disallowance resulting from an ACC-approved Settlement Agreement related to the implementation of retail electric competition. See "Regulatory Agreements" below and Notes 1 and 3 for additional information about the 1999 Settlement Agreement and the resulting regulatory disallowance.
Earnings excluding the extraordinary charge increased $39 million, or 15%, over 1999 primarily because of increases in wholesale and retail electric sales. These positive factors more than offset decreases resulting from the completion of investment tax credit (ITC) amortization in 1999, reductions in retail electricity prices and miscellaneous factors. See "Regulatory Agreements" below and Note 3 for information on the price reductions. See "Regulatory Agreements" below and Note 10 for additional information about ITC amortization.
In 2000, electric operating revenues increased $1.2 billion primarily because of:
* increased wholesale revenues ($1.1 billion);
* increases in the number of retail electricity customers and the average amount of electricity used by customers ($98 million); and
* weather impacts ($33 million).
As mentioned above, these positive factors were partially offset by the effects of reductions in retail electricity prices ($28 million).
The increase in wholesale revenues resulted primarily from higher prices and increased activity in western United States wholesale power markets. These revenues were accompanied by increases in purchased power and fuel expense of $1.0 billion.
Fuel and purchased power expenses were also higher because of higher retail sales volumes and increased prices.
The increase in operations and maintenance expenses, which primarily related to customer growth, was substantially offset by $19 million of non-recurring items recorded in 1999.
1999 COMPARED WITH 1998
Our 1999 earnings were $127 million compared with $246 million in 1998. Our 1999 earnings decreased $119 million from 1998 primarily because of a $140 million after-tax extraordinary charge that we recorded in 1999. This charge reflected a regulatory disallowance resulting from an ACC-approved Settlement Agreement related to the implementation of retail electric competition. See "Regulatory Agreements" below and Notes 1 and 3 for additional information about the 1999 Settlement Agreement and the resulting regulatory disallowance.
Earnings excluding the extraordinary charge increased $21 million, or 9%, over 1998 primarily because of increases in retail electricity revenues and lower financing costs. These positive factors more than offset the effects of retail electricity price reductions and higher utility operations and maintenance expense. See "Regulatory Agreements" below and Note 3 for additional information about the price reductions.
In 1999, electric operating revenues increased $286 million primarily because of:
* increased wholesale revenues ($219 million);
* increases in retail electricity customers and the average amount of electricity used by customers ($81 million); and
* miscellaneous factors ($8 million).
As mentioned above, these positive factors were partially offset by the effects of reductions in retail prices ($22 million).
The increase in wholesale revenues resulted from higher prices and increased activity in western United States wholesale markets. The revenues were accompanied by an increase in purchased power expenses. Although these activities contributed positively to earnings in both periods, the contribution in 1999 was lower than in 1998.
Operations and maintenance expenses increased $18 million primarily because of $19 million of non-recurring items recorded in 1999, including a provision for certain environmental costs. Other increases primarily related to customer growth were partially offset by lower employee benefit costs.
REGULATORY AGREEMENTS
Regulatory agreements approved by the ACC affect the results of our operations. The following discussion focuses on three agreements approved by the ACC, each of which included retail electricity price reductions:
* The 1999 Settlement Agreement to implement retail electric competition;
* A 1996 agreement that accelerated the amortization of our regulatory assets; and
* A 1994 settlement that accelerated the amortization of our deferred ITCs.
1999 SETTLEMENT AGREEMENT
As part of the 1999 Settlement Agreement, we agreed to reduce retail electricity prices for standard, full offer service customers with loads less than three megawatts in a series of annual decreases of 1.5% on July 1, 1999 through July 1, 2003, for a total of 7.5%. The first reduction of approximately $24 million ($14 million after income taxes) included the July 1, 1999 retail price decrease required by the 1996 regulatory agreement (see below). For customers having loads three megawatts or greater, standard offer rates will be reduced in annual increments that total 5% in the years 1999 through 2002.
The 1999 Settlement Agreement also removed, as a regulatory disallowance, $234 million before income taxes ($183 million net present value) from ongoing regulatory cash flows. We recorded this regulatory disallowance as a net reduction of regulatory assets and reported it as a $140 million after-tax extraordinary charge on the 1999 income statement.
Under the 1996 Regulatory Agreement, we were recovering substantially all of our regulatory assets through accelerated amortization over an eight-year period that would have ended June 30, 2004. For more details, see Note 1. The regulatory assets to be recovered under the 1999 Settlement Agreement are now being amortized as follows:
(dollars in millions)
1/1 - 6/30 1999 2000 2001 2002 2003 2004 Total ---- ---- ---- ---- ---- ---- ----- $164 $158 $145 $115 $86 $18 $686
See Note 3 and "Business Outlook - Electric Competition (Retail)" below for additional information regarding the 1999 Settlement Agreement.
1996 REGULATORY AGREEMENT
As part of the 1996 regulatory agreement, we reduced our retail electricity prices by 3.4% effective July 1, 1996. This reduction decreased annual revenue by about $49 million annually ($29 million after income taxes). We also agreed to share future cost savings with our customers during the term of this agreement, which resulted in the following additional retail price reductions:
* $18 million annually ($11 million after income taxes), or 1.2%, effective July 1, 1997;
* $17 million annually ($10 million after income taxes), or 1.1%, effective July 1, 1998; and
* $11 million annually ($7 million after income taxes), or 0.7%, effective July 1, 1999 (as noted above, this reduction was included in the July 1, 1999 price reduction under the 1999 Settlement Agreement).
1994 RATE SETTLEMENT
As part of a 1994 rate settlement, we accelerated amortization of substantially all of our ITCs over a five-year period that ended on December 31, 1999. The amortization of ITCs decreased annual income tax expense by about $28 million. Beginning in 2000, no further benefits were reflected in income tax expense related to the acceleration of the ITCs (see Note 10).
CAPITAL NEEDS AND RESOURCES
CAPITAL RESOURCES AND CASH REQUIREMENTS
Our capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. We pay for our capital requirements with cash from operations and, to the extent necessary, external financing.
During the period from 1998 through 2000, we paid for substantially all of our capital expenditures with cash from operations. We expect to do so in 2001 through 2003, as well.
Our capital expenditures in 2000 were $472 million. Our projected capital expenditures for the next three years are: $455 million in 2001; $401 million in 2002; and $294 million in 2003. These amounts include about $30 - $35 million each year for nuclear fuel. In general, most of our projected capital expenditures are for:
* expanding transmission and distribution capabilities to serve growing customer needs;
* upgrading existing utility property; and
* environmental purposes.
During 2000, we redeemed approximately $357 million of long-term debt, including premiums, with cash from operations and from the issuance of long- and short-term debt. Our long-term debt redemption requirements for the next three years are approximately: $380 million in 2001; $125 million in 2002; and zero in 2003. We made optional redemptions of about $13 million of long-term debt in February 2001. Based on market conditions and optional call provisions, we may make optional redemptions of long-term debt from time to time.
As of December 31, 2000, we had credit commitments from various banks totaling about $250 million, which were available either to support the issuance of commercial paper or to be used as bank borrowings. At the end of 2000, we had about $82 million of commercial paper and no long-term bank borrowings outstanding.
Our long-term debt was $2.1 billion at December 31, 2000 and 1999.
Although provisions in our first mortgage bond indenture and ACC financing orders establish maximum amounts of additional first mortgage bonds that we may issue, we do not expect any of these provisions to limit our ability to meet our capital requirements.
ACCOUNTING MATTERS
We adopted a new standard on accounting for derivatives in 2001. As a result, in January 2001 we recognized a $3 million after-tax loss in net income as a cumulative effect of a change in accounting principles and a $64 million after-tax gain in equity (as a component of other comprehensive income). The gain resulted from unrealized gains on cash flow hedges. There are still several unresolved issues related to the application of certain provisions of this new standard as it relates to the electric utility industry. The ultimate resolution of these issues by the Financial Accounting Standards Board (FASB) could result in a material impact to our financial statements and increased volatility in future net income and comprehensive income. See Note 2 for further information. Also, see Note 2 for a description of a proposed standard on accounting for certain liabilities related to closure or removal of long-lived assets.
We prepare our financial statements in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements. As a result of the 1999 Settlement Agreement (see "Regulatory Agreements" above and Note 3), we discontinued the application of SFAS No. 71 for our generation operations. As a result, we tested the generation assets for impairment and determined that the generation assets were not impaired. Pursuant to the 1999 Settlement Agreement, we reported a regulatory disallowance ($140 million after income taxes) as an extraordinary charge on the 1999 income statement. See Note 1 for additional information on regulatory accounting and Note 3 for additional information on the 1999 Settlement Agreement.
BUSINESS OUTLOOK
This section describes several major factors affecting our financial outlook.
COMPETITION AND INDUSTRY RESTRUCTURING
ELECTRIC COMPETITION (WHOLESALE)
The National Energy Policy Act of 1992 (1992 Energy Act) and the FERC's subsequent rulemaking activities have established the regulatory framework to open the wholesale electricity market to competition. The 1992 Energy Act amended provisions of the Public Utility Holding Company Act of 1935 and the Federal Power Act to remove certain barriers to a competitive wholesale market. The 1992 Energy Act permits utilities to participate in the development of independent electric generating plants for electricity sales to wholesale customers, and also permits the FERC to order transmission access for third parties to transmission facilities owned by another entity. The 1992 Energy Act does not, however, permit the FERC to issue an order requiring transmission access to retail customers. Open-access transmission for wholesale customers as defined by the FERC's final rules provides energy suppliers, including us, with opportunities to sell and deliver electricity at market-based prices.
ELECTRIC COMPETITION (RETAIL)
On September 21, 1999, the Arizona Corporation Commission (ACC) voted to approve the rules that provide a framework for the introduction of retail electric competition in Arizona (the Rules). Among other things, the Rules require most utilities, including us, to transfer all competitive generation assets and services either to an unaffiliated party or to a separate corporate affiliate. The Rules require the transfer to take place by January 1, 2001, absent a waiver. We received a waiver in the 1999 Settlement Agreement to allow the transfer of our competitive generation assets and services to affiliates no later than December 31, 2002. Accordingly, we plan to complete the move of such assets and services to the parent company or to Pinnacle West Energy by the end of 2002, as required.
Although the Rules allow retail customers to have access to competitive providers of energy and energy services, we are the "provider of last resort" for standard offer customers under rates that have been approved by the ACC. These rates are fixed until July 1, 2004. The 1999 Settlement Agreement allows us to seek adjustment of these rates in the event of emergency conditions or circumstances, such as the inability to secure financing on reasonable terms, or material changes in our cost of service for ACC-regulated services resulting from federal, tribal, state, or local laws, regulatory requirements, judicial decisions, actions or orders. Energy prices in the western wholesale market vary and, during the course of the last year, have been volatile. At various times prices in the spot wholesale market have significantly exceeded the amount included in our current retail rates. We expect these market conditions to continue in 2001. We believe we have adequately supplemented our current generation portfolio with power purchased through contracts and hedging techniques that limit exposure to the volatile spot wholesale power market. However, in the event of shortfalls due to unforeseen increases in load demand or generation outages, we may need to purchase additional supplemental power in the wholesale spot market. Unless we are able to obtain an adjustment of our rates under the 1999 Settlement Agreement, there can be no assurance that we would be able to fully recover the costs of this power.
As discussed in Note 3 of Notes to Financial Statements in Item 8, the 1999 Settlement authorizes us to transfer our competitive generation assets and services to one or more corporate affiliates no later than December 31, 2002. We intend to move our generation assets to Pinnacle West Energy within that timeframe. Following its receipt of these generation assets,
Pinnacle West Energy expects to sell its power at wholesale to Pinnacle West's power marketing division (Power Marketing). Power Marketing, in turn, is expected to sell power to us and to non-affiliated power purchasers. We expect to meet fifty percent of our energy needs under a power purchase agreement with Power Marketing. As required by the Rules, we will acquire the remaining fifty percent of our energy needs through a competitive bid process in which Power Marketing may participate. We believe that these arrangements will allow us to manage our exposure to the wholesale power market during the period within which our rates are fixed, as discussed in the preceding paragraph.
Under the 1999 Settlement Agreement, the Rules are to be interpreted and applied, to the greatest extent possible, in a manner consistent with the 1999 Settlement Agreement. If the two cannot be reconciled, we must seek, and the other parties to the 1999 Settlement Agreement must support, a waiver of the Rules in favor of the 1999 Settlement Agreement. Several rural electric cooperatives and the Arizona Consumers Council, a private non-profit public interest group (represented by the Arizona Center for Law in the Public Interest, also a private non-profit public interest organization) have filed court challenges to the Rules. Although these actions do not directly challenge the divestiture provisions of the Rules, they do raise fundamental constitutional issues concerning the ability of the ACC to permit the forces of competition to determine retail electric prices.
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 in Arizona. We do not believe the ruling affects the 1999 Settlement Agreement. The 1999 Settlement Agreement was not at issue in the consolidated cases before the judge. Further, the ACC made findings related to the fair value of our property in the order approving the 1999 Settlement Agreement. The ACC and other parties aligned with the ACC have appealed the ruling to the Court of Appeals, as a result of which the ruling is automatically stayed pending further judicial review.
On December 13, 1999, two parties filed lawsuits challenging the ACC's approval of the 1999 Settlement Agreement. Each party bringing the lawsuits appealed the ACC's order approving our 1999 Settlement Agreement directly to the Arizona Court of Appeals, as provided by Arizona law. In one of the appeals, on December 26, 2000, the Arizona Court of Appeals affirmed the ACC's approval of the 1999 Settlement Agreement. A decision is still pending on the other appeal, which raises a number of different issues.
Neither party challenging the 1999 Settlement Agreement has raised issues regarding the 1999 Settlement Agreement that could not be remedied by the ACC if the Arizona Court of Appeals remands the 1999 Settlement Agreement to the ACC. However, it is impossible to predict with certainty exactly what the ACC would do in the event the order approving the 1999 Settlement Agreement were invalidated, either in whole or in part. Even aside from the pending litigation, the ACC retains continuing jurisdiction over all orders issued by it and can attempt to "rescind, alter or amend" such order under appropriate circumstances and upon notice and hearing.
In May 1998, a law was enacted by the Arizona legislature to facilitate implementation of retail electric competition in the state. Additionally, legislation related to electric competition has been proposed in the United States Congress. See Note 3 for additional information about the Rules, the 1999 Settlement Agreement, the ongoing litigation related to each, and for legislative developments.
As a result of the foregoing matters, as well as energy market developments, particularly in California (see "California Energy Market Issues" below), electric utility restructuring is in a state of flux in the western United States and around the country.
CALIFORNIA ENERGY MARKET ISSUES
Southern California Edison (SCE) and PG&E Corp. (PG&E) have publicly disclosed that their liquidity has been materially and adversely affected because of, among other things, their inability to pass on to ratepayers the prices each has paid for energy and ancillary services procured through the California Power Exchange (PX) and California Independent System Operator (ISO).
We are closely monitoring developments in the California energy market and the potential impact of these developments on us. We have evaluated, among other things, SCE's role as a Palo Verde and Four Corners participant; our transactions with the PX and the ISO; contractual relationships with SCE and PG&E; and power marketing exposures. Based upon the financial transactions to date, we do not believe the foregoing matters will have a material adverse effect on our financial position or liquidity. We cannot predict with certainty, however, the impact that any future resolution, or attempted resolution, of the California energy market situation may have on us or the regional energy market in general.
FACTORS AFFECTING OPERATING REVENUES
Electric operating revenues are derived from sales of electricity in regulated retail markets in Arizona, and from competitive retail and wholesale bulk power markets in the western United States. These revenues are expected to be affected by electricity sales volumes related to customer mix, customer growth and average usage per customer, as well as electricity prices and variations in weather from period to period.
In our regulated retail market area, we will provide electricity services to standard-offer, full-service customers and to energy delivery customers who have chosen another provider for their electricity commodity needs (unbundled customers). Customer growth in our service territory averaged 3.8% a year for the three years 1998 through 2000; we currently expect customer growth to average 3.5% to 4% a year for 2001 through 2003. We currently estimate that retail electricity sales in kilowatt-hours will grow 3.5% to 4.5% a year in 2001 through 2003, before the retail effects of weather variations. The customer growth and sales growth referred to in this paragraph apply to energy delivery customers. As industry restructuring evolves in the regulated market area, we cannot predict the number of our standard offer customers that will switch to unbundled service.
Wholesale activities will be affected by electricity prices and costs of available fuel and purchased power in the western United States, as well as competitive market conditions and regulatory and legislative changes in various state and federal jurisdictions. These factors have significantly affected our wholesale power activities and their resultant earnings contributions over the last several years. We cannot predict future contributions from wholesale activities.
OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS
Fuel and purchased power costs are impacted by our electricity sales volumes, existing contracts for generation fuel and purchased power, our power plant performance, prevailing market prices, and our hedging program for managing such costs.
Operations and maintenance expenses are expected to be affected by sales mix and volumes, inflation, and other factors.
Depreciation and amortization expenses are expected to be affected by net additions to existing utility plant and other property, and changes in regulatory asset amortization. See Note 1 for the regulatory asset amortization that is being recorded in 1999 through 2004 pursuant to the 1999 Settlement Agreement. Also, see Note 1 regarding current depreciation rates.
Taxes other than income taxes consist primarily of property taxes, which are affected by tax rates and the value of property in service and under construction. We expect property taxes to increase primarily due to our additions to existing facilities.
Interest expense is affected by the amount of debt outstanding and the interest rates on that debt.
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.
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.
MARKET RISKS
Our operations include managing market risks related to changes in interest rates, commodity prices, and investments held by the nuclear decommissioning trust fund.
INTEREST RATE AND EQUITY RISK
Our major financial market risk exposure is changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and interest earned by our nuclear decommissioning trust fund (see Note 13). Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. The nuclear decommissioning fund also has risks associated with changing market values of equity investments. Nuclear decommissioning costs are recovered in regulated electricity prices.
The tables below present contractual balances of our long-term debt and commercial paper at the expected maturity dates as well as the fair value of those instruments on December 31, 2000 and December 31, 1999. The interest rates presented in the tables below represent the weighted average interest rates for the years ended December 31, 2000 and December 31, 1999.
Expected Maturity/Principal Repayment December 31, 2000 (dollars in thousands)
Short-Term Variable Long-Term Fixed Long-Term ------------------ ------------------ ------------------ Interest Interest Interest Rates Amount Rates Amount Rates Amount ----- ---------- ----- ---------- ----- ---------- 2001 6.64% $ 82,100 7.33% $ 250,000 7.75% $ 266 2002 -- 8.13% 125,000 2003 -- 7.75% 443 2004 -- 6.17% 205,000 2005 -- 7.28% 400,000 Years thereafter -- 4.06% 476,860 7.48% 605,598 ---------- ---------- ---------- Total $ 82,100 $ 726,860 $1,336,307 ========== ========== ========== Fair value $ 82,100 $ 726,860 $1,393,251 ========== ========== ==========
Expected Maturity/Principal Repayment December 31, 1999 (dollars in thousands)
Short-Term Variable Long-Term Fixed Long-Term ------------------ ------------------ ------------------ Interest Interest Interest Rates Amount Rates Amount Rates Amount ----- ---------- ----- ---------- ----- ---------- 2000 5.33% $ 38,300 $ 5.79% $ 114,711 2001 -- -- 6.85% 250,000 7.48% 2,488 2002 -- -- 8.13% 125,000
2003 -- -- 5.50% 50,000 2004 -- -- 6.17% 205,000 Years thereafter -- -- 3.15% 476,860 7.87% 895,148 ---------- ---------- ---------- Total $ 38,300 $ 776,860 $1,342,347 ========== ========== ========== Fair value $ 38,300 $ 776,860 $1,312,423 ========== ========== ==========
COMMODITY PRICE RISK
We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal, and emissions allowances. We employ established procedures to manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options, and swaps. As part of our overall risk management program, we enter into derivative transactions to hedge purchases and sales of electricity, fuels, and emissions allowances/credits. In addition, subject to specified risk parameters, 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 wholesale activities and are reflected in the wholesale revenues and expenses.
As of December 31, 2000, a hypothetical adverse price movement of 10% in the market price of our commodity derivative portfolio would have decreased the fair market value of these contracts by approximately $29 million, compared to a $6 million decrease that would have been realized as of December 31, 1999. The increase in this exposure over 1999 is a result of the increased volume of hedged positions and increased prices in this portfolio. This analysis does not include the favorable impact this same hypothetical price move would have had on certain underlying physical exposures being hedged with the commodity derivative portfolio.
We are exposed to losses in the event of non-performance or non-payment by counterparties. We use a risk management process to assess and monitor the financial exposure of counterparties. Despite the fact that the great majority of trading counterparties are rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on earnings for a given period.
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; the outcome of the regulatory proceedings relating to the restructuring; regional economic and market conditions, including the California energy situation, which could affect customer growth and the cost of power supplies; the cost of debt and equity capital; weather variations affecting local and regional customer energy usage; conservation programs; our ability to compete successfully outside traditional regulated markets (including the wholesale market); and technological developments in the electric industry.
These factors and the other matters discussed above may cause future results to differ materially from historical results, or from results or outcomes we currently expect or seek.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See "Market Risks" in Item 7 for a discussion of quantitative and qualitative disclosures about market risk.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
Report of Management........................................................ 34 Independent Auditors' Report................................................ 35 Statements of Income for 2000, 1999 and 1998................................ 37 Balance Sheets as of December 31, 2000 and 1999............................. 38 Statements of Cash Flows for 2000, 1999 and 1998............................ 40 Statements of Retained Earnings for 2000, 1999 and 1998..................... 41 Notes to Financial Statements............................................... 42
See Note 14 of Notes to Financial Statements for the selected quarterly financial data required to be presented in this Item.
REPORT OF MANAGEMENT
The primary responsibility for the integrity of our financial information rests with management, which has prepared the accompanying financial statements and related information. This information was prepared in accordance with generally accepted accounting principles as appropriate in the circumstances, and based on management's best estimates and judgments. These financial statements have been audited by independent auditors and their report is included on the following page.
Management maintains and relies upon systems of internal control. A limiting factor in all systems of internal control is that the cost of the system should not exceed the benefits to be derived. Management believes that our system provides the appropriate balance between such costs and benefits.
Periodically the internal control system is reviewed by both our internal auditors and our independent auditors to test for compliance. Reports issued by the internal auditors are released to management, and such reports or summaries thereof, are transmitted to the Audit Committee of the Board of Directors and the independent auditors on a timely basis.
The Audit Committee, composed solely of outside directors, meets periodically with the internal auditors and independent auditors (as well as management) to review the work of each. The internal auditors and independent auditors have free access to the Audit Committee, without management present, to discuss the results of their audit work.
Management believes that our systems, policies and procedures provide reasonable assurance that operations are conducted in conformity with the law and with management's commitment to a high standard of business conduct.
William J. Post Chris N. Froggatt
William J. Post Chris N. Froggatt Chairman and Vice President and Controller Chief Executive Officer Pinnacle West Capital Corporation
INDEPENDENT AUDITORS' REPORT
To the Board of Directors of Arizona Public Service Company Phoenix, Arizona
We have audited the accompanying balance sheets of Arizona Public Service Company as of December 31, 2000 and 1999 and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Arizona Public Service Company at December 31, 2000 and 1999 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America.
Deloitte & Touche LLP
Deloitte & Touche LLP Phoenix, Arizona February 9, 2001
[THIS PAGE INTENTIONALLY LEFT BLANK.]
ARIZONA PUBLIC SERVICE COMPANY STATEMENTS OF INCOME
See Notes to Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY BALANCE SHEETS ASSETS
See Notes to Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY BALANCE SHEETS LIABILITIES
See Notes to Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY STATEMENTS OF CASH FLOWS
See Notes to Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY STATEMENTS OF RETAINED EARNINGS
See Notes to Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS
We are Arizona's largest electric utility. We provide retail and wholesale electric service to the entire state with the exception of Tucson and about one-half of the Phoenix area. We also generate and, directly or through Pinnacle West's power marketing division, sell and deliver electricity to wholesale customers in the western United States.
ACCOUNTING RECORDS
Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of financial statements in accordance with GAAP requires the use of estimates by management. Actual results could differ from those estimates.
REGULATORY ACCOUNTING
We are regulated by the ACC and the FERC. The accompanying financial statements reflect the rate-making policies of these commissions. For regulated operations, we prepare our financial statements in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements.
During 1997, the EITF of the FASB issued EITF 97-4. EITF 97-4 requires that SFAS No. 71 be discontinued no later than when legislation is passed or a rate order is issued that contains sufficient detail to determine its effect on the portion of the business being deregulated, which could result in write-downs or write-offs of physical and/or regulatory assets. Additionally, the EITF determined that regulatory assets should not be written off if they are to be recovered from a portion of the entity which continues to apply SFAS No. 71.
The 1999 Settlement Agreement was approved by the ACC in September 1999 (see Note 3 for a discussion of the agreement). Consequently, we have discontinued the application of SFAS No. 71 for our generation operations. Accordingly, we tested the generation assets for impairment and determined that the generation assets were not impaired. Pursuant to the 1999 Settlement Agreement, a regulatory disallowance removed $234 million pre-tax ($183 million net present value) from ongoing regulatory cash flows and was recorded as a net reduction of regulatory assets. This reduction ($140 million after income taxes) was reported as an extraordinary charge on the income statement during the third quarter of 1999. Prior to the 1999 Settlement Agreement, under the 1996 regulatory agreement (see Note 3), the ACC accelerated the amortization of substantially all of our regulatory assets to an eight-year period that would have ended June 30, 2004.
The regulatory assets to be recovered under the 1999 Settlement Agreement are now being amortized as follows:
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
(dollars in millions)
1/1 - 6/30 1999 2000 2001 2002 2003 2004 Total ---- ---- ---- ---- ---- ---- ----- $164 $158 $145 $115 $86 $18 $686
The majority of our remaining regulatory assets relate to deferred income taxes (see Note 10) and rate synchronization cost deferrals (see "Rate Synchronization Cost Deferrals" in this Note).
The balance sheets include the amounts listed below for generation assets not subject to SFAS No. 71 (for additional generation information see Note16):
(dollars in thousands)
December 31, December 31, 2000 1999 ----------- ----------- Electric plant in service and held for future use $ 3,856,600 $ 3,817,919 Accumulated depreciation and amortization ........ (1,693,079) (1,664,782) Construction work in progress .................... 86,329 67,306 Nuclear fuel, net of amortization ................ 47,389 49,114
UTILITY PLANT AND DEPRECIATION
Utility plant is the term we use to describe the business property and equipment that supports electric service consisting primarily of generation, transmission and distribution facilities. We report utility plant at our original cost, which includes:
* material and labor; * contractor costs; * construction overhead costs (where applicable); and * capitalized interest or an allowance for funds used during construction.
We charge retired utility plant, plus removal costs less salvage realized, to accumulated depreciation. See Note 2 for information on a proposed accounting standard that impacts accounting for removal costs.
We record depreciation on utility property on a straight-line basis. For the years 1998 through 2000 the rates, as prescribed by our regulators, ranged from a low of 3.33% to a high of 20%. The weighted-average rate was 3.40% for 2000, 3.34% for 1999, and 3.32% for 1998. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 30 years.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
CAPITALIZED INTEREST
Capitalized interest represents the cost of debt funds used to finance construction of utility plants. Plant construction costs, including capitalized interest, are expensed through depreciation when completed projects are placed into commercial operation. Capitalized interest does not represent current cash earnings. The rate used to calculate capitalized interest was a composite rate of 6.62% for 2000, 6.65% for 1999, and 6.88% for 1998.
REVENUES
We record electric operating revenues on the accrual basis, which includes estimated amounts for service rendered but unbilled at the end of each accounting period.
RATE SYNCHRONIZATION COST DEFERRALS
As authorized by the ACC, operating costs (excluding fuel) and financing costs of Palo Verde Units 2 and 3 were deferred from the commercial operation dates (September 1986 for Unit 2 and January 1988 for Unit 3) until the date the units were included in a rate order (April 1988 for Unit 2 and December 1991 for Unit 3). In accordance with the 1999 Settlement Agreement, we are continuing to accelerate the amortization of the deferrals over an eight-year period that will end June 30, 2004. Amortization of the deferrals is included in depreciation and amortization expense on the Statements of Income.
NUCLEAR FUEL
We charge nuclear fuel to fuel expense by using the unit-of-production method. The unit-of-production method is an amortization method that is based on actual physical usage. We divide the cost of the fuel by the estimated number of thermal units that we expects to produce with that fuel. We then multiply that rate by the number of thermal units that we produce within the current period. This calculation determines the current period nuclear fuel expense.
We also charge nuclear fuel expense for the permanent disposal of spent nuclear fuel. The United States Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel, and it charges us $0.001 per kWh of nuclear generation. See Note 12 for information about spent nuclear fuel disposal and Note 13 for information on nuclear decommissioning costs.
REACQUIRED DEBT COSTS
For debt related to the regulated portion of our business, we amortize those gains and losses incurred upon early retirement over the remaining life of the debt. In accordance with the 1999 Settlement Agreement, we are continuing to accelerate reacquired debt costs over an eight-year period that will end June 30, 2004. The accelerated portion of the regulatory asset amortization is included in depreciation and amortization expense in the Statements of Income.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
DERIVATIVE INSTRUMENTS
We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal, and emissions allowances. We employ established procedures to manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options, and swaps. As part of our overall risk management program, we enter into derivative transactions to hedge purchases and sales of electricity, fuels, and emissions allowances/credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodity. In addition, subject to specified risk parameters, we engage in trading activities intended to profit from market price movements.
Gains and losses related to derivatives that qualify as hedges of expected transactions are recognized in revenue or fuel and purchased power expense as an offset to the related item being hedged when the underlying hedged physical transaction closes (deferral method).
Net gains and losses on derivatives utilized for trading are recognized in wholesale revenues on a current basis (the mark to market method). Trading positions are measured at fair value as of the balance sheet date. The net gain was $9 million for 2000 and $1 million for 1999.
CASH AND CASH EQUIVALENTS
We consider temporary cash investments and marketable securities, with original maturities of less than 90 days, to be cash equivalents for purposes of reporting cash flows.
2. ACCOUNTING MATTERS
Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the fair value of derivative financial instruments are either recognized periodically in income or shareholder's equity (as a component of other comprehensive income), depending on whether or not the derivative meets specific hedge accounting criteria. Hedge effectiveness is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in the fair value resulting from ineffectiveness, as defined by SFAS No. 133, is recognized immediately in net income. This new standard may result in additional volatility in our net income and comprehensive income.
As a result of adopting SFAS No. 133, we recognized $118 million of derivative assets and $16 million of derivative liabilities in our balance sheet as of January 1, 2001. We recorded a $3 million after-tax loss in net income as a cumulative effect of change in accounting principles and a $64 million after-tax gain in equity (as a component of other comprehensive income). The gain resulted from unrealized gains on cash flow hedges.
In December 2000, the FASB's Derivatives Implementation Group (DIG) discussed whether contracts in the electric industry that have some of the characteristics of purchased and written options
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
should qualify for the "normal purchases and sales" scope exception. The DIG did not reach a conclusion on this issue. We account for electricity contracts with characteristics of options as normal purchases and sales if it is probable that the contract will not be settled in cash and will result in the physical delivery of electricity. The DIG also discussed but did not conclude on whether electricity contracts subject to "bookout" should qualify for the normal exception. A bookout occurs when one party appears more than once in a contract path for the sale and purchase of energy. In that instance, the counterparties may agree that they will not schedule or deliver physical energy that originates and ends with the same counterparty, but rather will settle in cash the amounts due to or from each counterparty. We account for transactions that bookout as gross settlement with physical delivery (and eligible for the normal scope exception) if title transfers, gross cash payment is made, and the transaction retains both performance and credit risk. The contracts we are referring to here are not trading contracts, which we already measure at fair value (mark to market) as discussed in Note 1.
Our accounting is reflective of the non-storability of our product and the lack of predictability of the demand for electricity at any point in time. If the FASB or DIG ultimately provide contrary guidance, we may be required to mark certain contracts to their fair market values each reporting period, which could have a material impact on our financial statements and add significant net income and comprehensive income volatility that would not be reflective of the nature of our business. If these agreements are required to be treated as derivative instruments, a cumulative effect of a change in accounting principles would be applied in the quarter following final resolution of the issues.
In 1999 we adopted EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." EITF 98-10 requires energy trading contracts to be measured at fair value as of the balance sheet date with the gains and losses included in earnings and separately disclosed in the financial statements or footnotes. The effects of adopting EITF 98-10 were not material to our 1999 financial statements.
In February 1996, the FASB issued an exposure draft, "Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets." This proposed standard would require 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. The FASB issued a revised exposure draft in February 2000 and we are evaluating the impacts.
3. REGULATORY MATTERS
ELECTRIC INDUSTRY RESTRUCTURING
STATE
1999 SETTLEMENT AGREEMENT. On May 14, 1999, we entered into a comprehensive Settlement Agreement with various parties, including representatives of major consumer groups, related to the implementation of retail electric competition. On September 23, 1999, the ACC voted to approve the 1999 Settlement Agreement, with some modifications. On December 13, 1999, two parties filed lawsuits challenging the ACC's approval of the 1999 Settlement Agreement. Each party
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
bringing the lawsuits appealed the ACC's order approving our 1999 Settlement Agreement directly to the Arizona Court of Appeals, as provided by Arizona law. In one of the appeals, on December 26, 2000, the Arizona Court of Appeals affirmed the ACC's approval of the 1999 Settlement Agreement. A decision is still pending on the other appeal, which raises a number of different issues.
The following are the major provisions of the 1999 Settlement Agreement, as approved:
* We have reduced, and will reduce, rates for standard offer service for customers with loads less than three megawatts (MW) in a series of annual retail electric price reductions of 1.5% beginning July 1, 1999 through July 1, 2003, for a total of 7.5%. The first reduction of approximately $24 million ($14 million after income taxes) included the July 1, 1999 retail price decrease of approximately $11 million ($7 million after income taxes) related to the 1996 regulatory agreement. See "1996 Regulatory Agreement" below. Based on the price reduction authorized in the 1999 Settlement Agreement, there was a retail price decrease of approximately $28 million ($17 million after taxes), or 1.5%, effective July 1, 2000. For customers having loads three MW or greater, standard offer rates will be reduced in varying annual increments that total 5% in the years 1999 through 2002.
* Unbundled rates being charged by us for competitive direct access service (for example, distribution services) became effective upon approval of the 1999 Settlement Agreement, retroactive to July 1, 1999, and also became subject to annual reductions beginning January 1, 2000, that vary by rate class, through January 1, 2004.
* There will be a moratorium on retail price changes for standard offer and unbundled competitive direct access services until July 1, 2004, except for the price reductions described above and certain other limited circumstances. Neither the ACC nor we will be prevented from seeking or authorizing rate changes prior to July 1, 2004 in the event of conditions or circumstances that constitute an emergency, such as an inability to finance on reasonable terms, or material changes in our cost of service for ACC-regulated services resulting from federal, tribal, state or local laws, regulatory requirements, judicial decisions, actions or orders.
* We will be permitted to defer for later recovery prudent and reasonable costs of complying with the ACC electric competition rules, system benefits costs in excess of the levels included in current rates, and costs associated with the "provider of last resort" and standard offer obligations for service after July 1, 2004. These costs are to be recovered through an adjustment clause or clauses commencing on July 1, 2004.
* Our distribution system opened for retail access effective September 24, 1999. Customers were eligible for retail access in accordance with the phase-in adopted by the ACC under the electric competition rules (see "Retail Electric Competition Rules" below), including an additional 140 MW being made available to eligible non-residential customers. We opened our distribution system to retail access for all customers on January 1, 2001.
* Prior to the 1999 Settlement Agreement, we were recovering substantially all of our regulatory assets through July 1, 2004, pursuant to the 1996 regulatory agreement. In
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
addition, the 1999 Settlement Agreement states that we have demonstrated that our allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least $533 million net present value. We will not be allowed to recover $183 million net present value of the above amounts. The 1999 Settlement Agreement provides that we will have the opportunity to recover $350 million net present value through a competitive transition charge (CTC) that will remain in effect through December 31, 2004, at which time it will terminate. Any over/under-recovery due to sales volume variances will be credited/debited against the costs subject to recovery under the adjustment clause described above.
* We will form a separate corporate affiliate or affiliates and transfer to such affiliate(s) our generating assets and competitive services at book value as of the date of transfer, which transfer shall take place no later than December 31, 2002. Accordingly, we plan to complete the move of such assets and services to the parent company or to Pinnacle West Energy by the end of 2002, as required. We will be allowed to defer and later collect, beginning July 1, 2004, sixty-seven percent of our costs to accomplish the required transfer of generation assets to an affiliate.
* When the 1999 Settlement Agreement approved by the ACC is no longer subject to judicial review, we will move to dismiss all of our litigation pending against the ACC as of the date we entered into the 1999 Settlement Agreement. To protect our rights, we have several lawsuits pending on ACC orders relating to stranded cost recovery and the adoption and amendment of the ACC's electric competition rules, which would be voluntarily dismissed at the appropriate time under this provision.
As discussed in Note 1 above, we have discontinued the application of SFAS No. 71 for our generation operations.
RETAIL ELECTRIC COMPETITION RULES. On September 21, 1999, the ACC voted to approve the rules that provide a framework for the introduction of retail electric competition in Arizona. Under the 1999 Settlement Agreement, the Rules are to be interpreted and applied, to the greatest extent possible, in a manner consistent with the 1999 Settlement Agreement. If the two cannot be reconciled, we must seek, and the other parties to the 1999 Settlement Agreement must support, a waiver of the Rules in favor of the 1999 Settlement Agreement. On December 8, 1999, we filed a lawsuit to protect our legal rights regarding the Rules. This lawsuit is pending, along with several other lawsuits on ACC orders relating to stranded cost recovery, the adoption or amendment of the Rules, and the certification of competitive electric service providers.
On November 27, 2000, a Maricopa County, Arizona, Superior Court judge issued a final judgment holding that the Rules are unconstitutional and unlawful in their entirety due to failure to establish a fair value rate base for competitive electric service providers and because certain of the Rules were not submitted to the Arizona Attorney General for certification. The judgment also invalidates all ACC orders authorizing competitive electric service providers 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
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
value of our property in the order approving the 1999 Settlement Agreement. The ACC and other parties aligned with the ACC have appealed the ruling to the Court of Appeals, as a result of which the ruling is automatically stayed pending further judicial review.
The Rules approved by the ACC include the following major provisions:
* They apply to virtually all Arizona electric utilities regulated by the ACC, including us.
* Effective January 1, 2001 retail access was available to all of our retail customers.
* Electric service providers that get Certificates of Convenience and Necessity 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 non-competitive services.
* The ACC shall allow a reasonable opportunity for recovery of unmitigated stranded costs.
* Absent an ACC waiver, prior to January 1, 2001, each affected utility (except certain electric cooperatives) must transfer all competitive generation assets and services either to an unaffiliated party or to a separate corporate affiliate. Under the 1999 Settlement Agreement, we received a waiver to allow transfer of our generation and other competitive assets and services to affiliates no later than December 31, 2002. See "1999 Settlement Agreement" above for a discussion of the planned timing of the transfer.
1996 REGULATORY AGREEMENT. In April 1996, the ACC approved a regulatory agreement between the ACC Staff and us. Based on the price reduction formula authorized in the agreement, the ACC approved retail price decreases (approximate) as follows (dollars in millions):
Annual Electric Percentage Revenue Decrease Decrease Effective Date ---------------- -------- -------------- $49 3.4% July 1, 1996 $18 1.2% July 1, 1997 $17 1.1% July 1, 1998 $11 0.7% July 1, 1999 (a)
(a) Included in the first rate reduction under the 1999 Settlement Agreement (see above).
The regulatory agreement also required that the parent company infuse $200 million of common equity into us in annual payments of $50 million from 1996 through 1999. All of these equity infusions were made by December 31, 1999.
LEGISLATION. In May 1998, a law was enacted to facilitate implementation of retail electric competition in Arizona. The law includes the following major provisions:
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
* Arizona's largest government-operated electric utility (Salt River Project) and, at their option, smaller municipal electric systems must (i) make at least 20% of their 1995 retail peak demand available to electric service providers by December 31, 1998 and for all retail customers by December 31, 2000; (ii) decrease rates by at least 10% over a ten-year period beginning as early as January 1, 1991; (iii) implement procedures and public processes comparable to those already applicable to public service corporations for establishing the terms, conditions, and pricing of electric services as well as certain other decisions affecting retail electric competition;
* describes the factors which form the basis of consideration by Salt River Project in determining stranded costs; and
* metering and meter reading services must be provided on a competitive basis during the first two years of competition only for customers having demands in excess of one MW (and that are eligible for competitive generation services), and thereafter for all customers receiving competitive electric generation.
GENERAL
We cannot accurately predict the impact of full retail competition on our financial position, cash flows, results of operations, or liquidity. As competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete in the new regulatory environment.
FEDERAL
The 1992 Energy Act and recent rulemakings by FERC have promoted increased competition in the wholesale energy markets. We do not expect these rules to have a material impact on our financial statements.
Several electric utility industry restructuring bills will undoubtedly be introduced during the current congressional session. Several of these bills are written to allow consumers to choose their electricity suppliers beginning in 2001 and beyond. These bills and other bills are expected to be introduced, and ongoing discussions at the federal level suggest a wide range of opinion that will need to be narrowed before any comprehensive restructuring of the electric utility industry can occur.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
4. COMMON AND PREFERRED STOCKS
On March 1, 1999, we redeemed all of our preferred stock. Common stock balances at December 31, 2000 and 1999 are shown below:
Preferred Stock:
Redeemable preferred stock transactions during each of the three years in the period ended December 31, 2000 are as follows:
5. LONG-TERM DEBT
Borrowings under our mortgage bond indenture are secured by substantially all utility plant; we also have unsecured debt. The following table presents the components of long-term debt outstanding at December 31, 2000 and December 31, 1999:
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
(dollars in thousands)
- ---------- (a) This schedule does not reflect the timing of redemptions that may occur prior to maturity. (b) The weighted-average rate for the year ended December 31, 2000 was 4.06% and for December 31, 1999 was 3.15%. Changes in short-term interest rates would affect the costs associated with this debt.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
(c) The weighted-average rate for the year ended December 31, 2000 was 7.33% and for December 31, 1999 was 6.8525%. (d) We currently have outstanding $84 million of first mortgage bonds (senior note mortgage bonds) issued to the senior note trustee as collateral for the senior notes. The senior note mortgage bonds have the same interest rate, interest payment dates, maturity, and redemption provisions as the senior notes. Our payments of principal, premium, and/or interest on the senior notes satisfy our corresponding payment obligations on the senior note mortgage bonds. As long as the senior note mortgage bonds secure the senior notes, the senior notes will effectively rank equally with the first mortgage bonds. When we repay all of our first mortgage bonds, other than those that secure senior notes, the senior note mortgage bonds will no longer secure the senior notes and will cease to be outstanding. (e) The weighted-average rate for the year ended December 31, 2000 was 6.53% and for December 31, 1999 was 5.5%. Changes in short-term interest rates would affect the costs associated with this debt. At December 31, 2000, we had no long-term bank borrowings outstanding. (f) Represents the present value of future lease payments (discounted at an interest rate of 7.48%) on a combined cycle plant that was sold and leased back. The capital lease was paid off early and the related asset was purchased in December 2000 (See Note 9).
The following is a list of principal payments due on total long-term debt and sinking fund requirements through 2005:
(dollars in millions)
Year Amount ------ ------ 2001 $ 250 2002 125 2003 -- 2004 205 2005 400
First mortgage bondholders share a lien on substantially all utility plant assets (other than nuclear fuel and transportation equipment). The mortgage bond indenture restricts the payment of common stock dividends under certain conditions. These conditions did not exist at December 31, 2000.
6. LINES OF CREDIT
We had committed lines of credit with various banks of $250 million at December 31, 2000 and $350 million at December 31, 1999, which were available either to support the issuance of commercial paper or to be used for bank borrowings. The commitment fees at December 31, 2000 and 1999 for these lines of credit ranged from 0.09% to 0.125% per annum. We have no long-term bank borrowings at December 31, 2000 and $50 million outstanding at December 31, 1999.
Our commercial paper borrowings outstanding were $82 million at December 31, 2000 and $38 million at December 31, 1999. The weighted average interest rate on commercial paper borrowings was 6.64% for the year ended December 31, 2000 and 5.33% for the year ended
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
December 31, 1999. By Arizona statute, our short-term borrowings cannot exceed 7% of our total capitalization unless approved by the ACC.
7. FAIR VALUE OF FINANCIAL INSTRUMENTS
We believe that the carrying amounts of our cash equivalents and commercial paper are reasonable estimates of their fair values at December 31, 2000 and 1999 due to their short maturities.
We hold investments in debt and equity securities for purposes other than trading. The December 31, 2000 and 1999 fair values of such investments, which we determine by using quoted market values, approximate their carrying amount.
The carrying value of our long-term debt (excluding a capitalized lease obligation) was $2.06 billion on December 31, 2000, with an estimated fair value of $2.11 billion. On December 31, 1999, the carrying value of our long-term debt (excluding a capitalized lease obligation) was $2.10 billion, with an estimated fair value of $2.08 billion. The fair value estimates are based on quoted market prices of the same or similar issues.
8. JOINTLY-OWNED FACILITIES
We share ownership of some of our generating and transmission facilities with other companies. The following table shows our interest in those jointly-owned facilities at December 31, 2000. Our share of operating and maintaining these facilities is included in the income statement in operations and maintenance expense.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
- ---------- (a) PacifiCorp owns Cholla Unit 4 and we operate the unit for them. The common facilities at the Cholla Plant are jointly-owned. (b) Weighted average of interests.
9. LEASES
In 1986, we sold about 42% of our share of Palo Verde Unit 2 and certain common facilities in three separate sale leaseback transactions. We account for these leases as operating leases. The gain of approximately $140 million was deferred and is being amortized to operations expense over 29.5 years, the original term of the leases. There are options to renew the leases for two additional years and to purchase the property for fair market value at the end of the lease terms. Consistent with the ratemaking treatment, an amount equal to the annual lease payments is included in rent expense. A regulatory asset is recognized for the difference between lease payments and rent expense calculated on a straight-line basis.
The average amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year for the years 2001-2015.
In accordance with the 1999 Settlement Agreement, we are continuing to accelerate amortization of the regulatory asset for leases over an eight-year period that will end June 30, 2004 (see Note 1). The accelerated amortization is included in depreciation and amortization expense on
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
the Statements of Income. The balance of this regulatory asset at December 31, 2000 was $33 million.
In December 2000, we purchased Units 1, 2, and 3 of West Phoenix Power Plant. These units were previously reflected as a capital lease.
In addition, we lease certain land, buildings, equipment, and miscellaneous other items through operating rental agreements with varying terms, provisions, and expiration dates.
Total lease expense was $53 million in 2000, $49 million in 1999, and $52 million in 1998.
Estimated future minimum lease commitments, are approximately $64 million for each of the years 2001 to 2005 and $613 million thereafter.
10. INCOME TAXES
INCOME TAXES
We are included in Pinnacle West's consolidated tax return. However, when Pinnacle West allocates income taxes to us, it does so based on our taxable income or loss alone. Because of a 1994 rate settlement agreement, we accelerated amortization of substantially all of our ITCs over a five-year period (1995-1999).
Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the current income tax rates.
We have recorded a regulatory asset related to income taxes on our Balance Sheet in accordance with SFAS No. 71. This regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. We amortize this amount as the differences reverse. In accordance with the 1999 Settlement Agreement, we are continuing to accelerate our amortization of the regulatory asset for income taxes over an eight-year period that will end June 30, 2004 (see Note 1). We are including this accelerated amortization in depreciation and amortization expense on the Statements of Income. The components of income tax expense for continuing operations are:
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
(dollars in thousands)
Year Ended December 31, ----------------------------------- 2000 1999 1998 --------- --------- --------- Current Federal $ 211,139 $ 175,227 $ 170,806 State 50,252 41,541 42,652 --------- --------- --------- Total current 261,391 216,768 213,458
Deferred (35,805) (29,654) (26,374) ITC amortization (269) (27,626) (27,628) --------- --------- --------- Total expense $ 225,317 $ 159,488 $ 159,456 ========= ========= =========
The following chart compares pretax income at the 35% federal income tax rate to income tax expense:
(dollars in thousands)
Year Ended December 31, ----------------------------------- 2000 1999 1998 --------- --------- --------- Federal income tax expense at 35% statutory rate $ 186,169 $ 149,710 $ 145,146 Increases (reductions) in tax expense resulting from: Tax under book depreciation 12,328 14,575 17,848 ITC amortization (269) (27,626) (27,628) State income tax net of federal income tax benefit 23,714 24,135 23,024 Other 3,375 (1,306) 1,066 --------- --------- --------- Income tax expense $ 225,317 $ 159,488 $ 159,456 ========= ========= =========
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
The components of the net deferred income tax liability were as follows:
(dollars in thousands)
Year Ended December 31, ------------------------ 2000 1999 ---------- ---------- DEFERRED TAX ASSETS Deferred gain on Palo Verde Unit 2 sale/leaseback $ 27,056 $ 29,446 Other 122,019 139,518 ---------- ---------- Total deferred tax assets 149,075 168,964 ---------- ---------- DEFERRED TAX LIABILITIES Plant-related 1,081,637 1,104,769 Regulatory asset for income taxes 172,082 234,117 ---------- ---------- Total deferred tax liabilities 1,253,719 1,338,886 ---------- ---------- Accumulated deferred income taxes - net $1,104,644 $1,169,922 ========== ==========
11. RETIREMENT PLANS AND OTHER BENEFITS
PENSION PLANS
Through 1999, we sponsored defined benefit pension plans for our employees. As of January 1, 2000, this plan is sponsored by Pinnacle West. In 2000, we represent 71% of the total cost of this plan. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. The plan covers nearly all of our employees. Our employees do not contribute to this plan. Generally, we calculate the benefits under these plans based on age, years of service, and pay. We fund the plan by contributing at least the minimum amount required under Internal Revenue Service regulations but no more than the maximum tax-deductible amount. The assets in the plan at December 31, 2000 were mostly domestic and international common stocks and bonds and real estate.
Pension expense, including administrative costs, was:
* $2 million in 2000; * $4 million in 1999; and * $10 million in 1998.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
The following table shows the components of net pension cost before consideration of amounts capitalized or billed to others:
(dollars in thousands)
The following table shows a reconciliation of the funded status of the plans to the amounts recognized in the balance sheets:
(dollars in thousands)
2000 1999 -------- -------- Fund status - pension plan assets more than (less than) projected benefit obligation $(22,438) $ 37,784 Unrecognized net transition asset (16,745) (19,943) Unrecognized prior service cost 18,440 20,499 Unrecognized net actuarial gains (20,075) (99,602) -------- -------- Net pension liability recognized in the balance sheets $(40,818) $(61,262) ======== ========
The following table sets forth the defined benefit pension plans' change in projected benefit obligation for the plan years 2000 and 1999:
(dollars in thousands)
2000 1999 -------- --------
Projected pension benefit obligation at beginning of year $732,911 $721,229 Service cost 24,197 24,266 Interest cost 57,785 52,208 Benefit payments (30,498) (29,444) Actuarial (gains)/losses 3,461 (35,348) -------- -------- Projected pension benefit obligation at end of year $787,856 $732,911 ======== ========
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
The following table sets forth the defined benefit pension plans' change in the fair value of plan assets for the plan years 2000 and 1999:
(dollars in thousands)
2000 1999 --------- ---------
Fair value of pension plan assets at beginning of year $ 770,695 $ 682,272 Actual return on plan assets 1,830 92,867 Employer contributions 23,391 25,000 Benefit payments (30,498) (29,444) --------- --------- Fair value of pension plan assets at end of year $ 765,418 $ 770,695 ========= =========
We made the assumptions below to calculate the pension liability:
2000 1999 ----- -----
Discount rate 7.75% 7.75% Rate of increase in compensation levels 4.25% 4.25% Expected long-term rate of return on assets 10.00% 10.00%
EMPLOYEE SAVINGS PLAN BENEFITS
Through 1999, we sponsored defined contribution savings plans for our employees. As of January 1, 2000, this plan is sponsored by Pinnacle West. In 2000, we represent 92% of the total cost of this plan. In a defined contribution plan, the benefits a participant will receive result from regular contributions they make to a participant account. Under this plan, we make matching contributions to participant accounts. We recorded expenses for this plan of approximately $3 million for 2000 and $4 million for each of the years 1999 and 1998.
POSTRETIREMENT PLANS
We provide medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plans, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions to cover a portion of the plan costs. We retain the right to change or eliminate these benefits. In 2000, we represent 84% of the total cost of this plan.
Funding is based upon actuarially determined contributions that take tax consequences into account. Plan assets consist primarily of domestic stocks and bonds. The postretirement benefit expense was:
* $ 2 million for 2000; * $ 6 million for 1999; and * $ 9 million for 1998.
The following table shows the components of net periodic postretirement benefit costs before consideration of amounts capitalized or billed to others:
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
(dollars in thousands)
The following table shows a reconciliation of the funded status of the plan to the amounts recognized in the balance sheets:
(dollars in thousands)
2000 1999 --------- --------- Funded status - postretirement plan assets more than (less than) projected benefit obligation $ (12,786) $ 27,930 Unrecognized net obligation at transition 91,844 99,482 Unrecognized net actuarial gains (79,596) (127,338) --------- --------- Net postretirement amount recognized in the balance sheets $ (538) $ 74 ========= =========
The following table sets forth the postretirement benefit plans' change in accumulated benefit obligation for the plan years 2000 and 1999:
(dollars in thousands)
2000 1999 --------- --------- Accumulated postretirement benefit obligation at beginning of year $ 229,608 $ 235,322 Service cost 8,312 8,675 Interest cost 19,169 17,188 Benefit payments (8,905) (8,761) Actuarial (gains) losses 13,756 (22,816) --------- --------- Accumulated postretirement benefit obligation at end of year $ 261,940 $ 229,608 ========= =========
The following table sets forth the postretirement benefit plans' change in the fair value of plan assets for the plan years 2000 and 1999:
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
(dollars in thousands)
2000 1999 --------- --------- Fair value of postretirement plan assets at beginning of year $ 257,538 $ 213,410 Actual return on plan assets (4,436) 42,975 Employer contributions 4,957 9,914 Benefit payments (8,905) (8,761) --------- --------- Fair value of postretirement plan assets at the end of year $ 249,154 $ 257,538 ========= =========
We made the assumptions below to calculate the postretirement liability:
2000 1999 ----- -----
Discount rate 7.75% 7.75% Expected long-term rate of return on assets - after tax 8.77% 8.77% Initial health care cost trend rate - under age 65 7.00% 7.00% Initial health care cost trend rate - age 65 and over 6.00% 6.00% Ultimate health care cost trend rate (reached in the year 2002) 5.00% 5.00%
The following table shows the effect of a 1% increase or decrease in the health care cost trend rate:
(dollars in millions)
1% increase 1% decrease ----------- ----------- Effect on 2000 cost of postretirement benefits other than pensions $ 5 $ (4) Effect on the accumulated postretirement benefit obligation at December 31, 2000 42 (34)
12. COMMITMENTS AND CONTINGENCIES
LITIGATION
We are party to various claims, legal actions, and complaints arising in the ordinary course of business. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our financial statements.
POWER SERVICE AGREEMENT
We are a party to a power service agreement with Citizens Communications Company (Citizens) under which we supply Citizens with power. By letter dated March 7, 2001, Citizens advised us that it believes we have overcharged Citizens by over $50 million under the agreement since the summer of 2000. We believe that our charges to Citizens under the agreement are fully in accordance with the terms of the agreement and will vigorously defend any contrary claims raised by Citizens.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
PALO VERDE NUCLEAR GENERATING STATION
Pursuant to the Nuclear Waste Policy Act of 1982, the DOE must accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. The United States Nuclear Regulatory Commission (NRC) requires operators of nuclear power reactors to enter into spent fuel disposal contracts with the DOE. Under the Nuclear Waste Policy Act of 1982, the DOE was to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998. The DOE has announced that such a permanent repository cannot be completed before 2010, and that it does not intend to begin accepting spent fuel prior to that date.
In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision precluding the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision, a number of utilities filed damages actions against DOE in the Court of Federal Claims. In decisions that became final in December 2000, the United States Court of Appeals for the Federal Circuit held that utilities do not have to exhaust the DOE administrative claims before filing lawsuits for damages against the DOE in the Court of Federal Claims.
We have existing fuel storage pools at Palo Verde and are in the process of completing construction of a new facility for on-site dry storage of spent fuel. With the existing storage pools and the addition of the new facility, we believe that spent fuel storage or disposal methods will be available for use by Palo Verde to allow its continued operation through the term of the operating license for each Palo Verde unit.
Although some low-level waste has been stored on-site in a low-level waste facility, we are currently shipping low-level waste to off-site facilities. We currently believe that interim low-level waste storage methods are or will be available for use by Palo Verde to allow its continued operation and to safely store low-level waste until a permanent disposal facility is available.
We currently estimate that we will incur $113 million (in 2000 dollars) over the life of Palo Verde for our share of the costs related to the on-site interim storage of spent nuclear fuel. As of December 31, 2000, we have recorded a liability and regulatory asset of $40 million for on-site interim nuclear fuel storage costs related to nuclear fuel burned to date.
The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $200 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, we could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $88 million, subject to an annual limit of $10 million per incident. Based upon our interest in the three Palo Verde units, our maximum potential assessment per incident for all three units is approximately $77 million, with an annual payment limitation of approximately $9 million.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
The Palo Verde participants maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. We have also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.
FUEL AND PURCHASED POWER COMMITMENTS
We are a party to various fuel and purchased power contracts with terms expiring from 2001 through 2021 that include required purchase provisions. We estimate our 2001 contract requirements to be approximately $277 million in 2001; $145 million in 2002; $90 million in 2003; $83 million in 2004; and $55 million in 2005. However, this amount may vary significantly pursuant to certain provisions in such contracts that permit us to decrease our required purchases under certain circumstances.
We must reimburse certain coal providers for amounts incurred for coal mine reclamation. We estimate our share of the total obligation to be about $103 million. The portion of the coal mine reclamation obligation related to coal already burned is about $58 million at December 31, 2000 and is included in "Deferred Credits-Other" in the Balance Sheet.
A regulatory asset has been established for amounts not yet recovered from ratepayers. In accordance with the 1999 Settlement Agreement with the ACC, we are continuing to accelerate the amortization of the regulatory asset for coal mine reclamation over an eight-year period that will end June 30, 2004. Amortization is included in depreciation and amortization expense on the Statements of Income. The balance of the regulatory asset at December 31, 2000 was about $32 million.
CALIFORNIA ENERGY MARKET ISSUES
SCE and PG&E have publicly disclosed that their liquidity has been materially and adversely affected because of, among other things, their inability to pass on to ratepayers the prices each has paid for energy and ancillary services procured through the PX and the ISO.
We are closely monitoring developments in the California energy market and the potential impact of these developments on us. We have evaluated, among other things, SCE's role as a Palo Verde and Four Corners participant; our transactions with the PX and the ISO; contractual relationships with SCE and PG&E; and power marketing exposures. Based upon the financial transactions to date, we do not believe the foregoing matters will have a material adverse effect on our financial position or liquidity. We cannot predict with certainty, however, the impact that any future resolution or attempted resolution, of the California energy market situation may have on us or the regional market in general.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
CONSTRUCTION PROGRAM
Total capital expenditures in 2001 are estimated at $455 million.
13. NUCLEAR DECOMMISSIONING COSTS
We recorded $11 million for nuclear decommissioning expense in each of the years 2000, 1999, and 1998. We estimate it will cost about $1.8 billion ($493 million in 2000) to decommission our share of the three Palo Verde units. The decommissioning costs are expected to be incurred over a 14-year period beginning in 2024. We charge decommissioning costs to expense over each unit's operating license term and includes them in the accumulated depreciation balance until each unit is retired. Nuclear decommissioning costs are recovered in rates.
Our current estimates are based on a 1998 site-specific study for Palo Verde that assumes the prompt removal/dismantlement method of decommissioning. An independent consultant prepared this study. We are required to update the study every three years.
To fund the costs we expect to incur to decommission the plant, we established external decommissioning trusts in accordance with NRC regulations. The trust accounts are reported in investments and other assets on the Balance Sheets at their market value of $205 million at December 31, 2000 and $176 million at December 31, 1999. We invest the trust funds primarily in fixed income securities and domestic stock and classify them as available for sale. Realized and unrealized gains and losses are reflected in accumulated depreciation.
See Note 2 for a proposed accounting standard on accounting for certain liabilities related to closure or removal of long-lived assets.
14. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly financial information for 2000 and 1999 is as follows:
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
(dollars in thousands)
------------------------------------------------- QUARTER ENDED March 31 June 30 September 30 December 31 -------- ------- ------------ -----------
Electric operating revenues $445,981 $719,394 $1,565,622 $749,255 Operating income (a) $ 66,094 $132,345 $ 160,646 $ 91,810 Net income and Earnings for Common Stock $ 32,775 $ 95,851 $ 124,231 $ 53,737
(dollars in thousands)
------------------------------------------------- QUARTER ENDED March 31 June 30 September 30 December 31 -------- ------- ------------ -----------
Electric operating revenues $413,983 $511,434 $867,504 $499,877 Operating income (a) $ 66,956 $ 98,503 $150,914 $ 72,551 Net Income/(Loss) (b) $ 33,795 $ 69,542 $(10,377) $ 35,477 Earnings/(Loss) for Common Stock $ 32,779 $ 69,542 $(10,377) $ 35,477
- ---------- (a) Our utility business is seasonal in nature, with the peak sales periods generally occurring during the summer months. Comparisons among quarters of a year may not represent overall trends and changes in operations.
(b) The quarter ending September 30, 1999 includes and extraordinary charge of $139,885, net of income taxes of $94,115.
15. STOCK-BASED COMPENSATION
Pinnacle West offers two stock incentive plans for our officers and key employees.
The plan provides for the granting of new options (which may be non-qualified stock options or incentive stock options) of up to 3.5 million shares at a price per option not less than the fair market value on the date the option is granted. Options vest one-third of the grant per year beginning one year after the date the option is granted and expire ten years from the date of the grant. The plan also provides for the granting of any combination of shares of restricted stock, stock appreciation rights or dividend equivalents.
The awards outstanding under the incentive plans at December 31, 2000 approximate 1,569,171 non-qualified stock options, 193,992 shares of restricted stock, and no incentive stock options, stock appreciation rights or dividend equivalents.
The FASB issued SFAS No. 123, "Accounting for Stock-Based Compensation" which was effective beginning in 1996. The statement encourages, but does not require, that a company record compensation expense based on the fair value of options granted (the fair value method). We continue to recognize expense based on Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees."
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
If we had recorded compensation expense based on the fair value method, our net income would have been reduced to the following pro forma amounts:
(dollars in thousands)
2000 1999 1998 -------- -------- -------- Net income As reported $306,594 $128,437 $255,247 Pro forma (fair value method) $305,610 $127,658 $254,640
In order to present the pro forma information above, we calculated the fair value of each fixed stock option in the incentive plans using the Black-Scholes option-pricing model. The fair value was calculated based on the date the option was granted. The following weighted-average assumptions were also used in order to calculate the fair value of the stock options:
2000 1999 1998 ----- ----- -----
Risk-free interest rate 5.81% 5.68% 4.54% Dividend yield 3.48% 3.33% 3.03% Volatility 32.00% 20.50% 18.80% Expected life (months) 60 60 60
16. BUSINESS SEGMENTS
We have two principal business segments (determined by products, services and regulatory environment) which consist of the transmission and distribution of electricity and wholesale activities (delivery business segment) and the generation of electricity (generation business segment). Eliminations primarily relate to intersegment sales of electricity. Financial data for the business segments is provided as follows:
Business Segments For Year Ended December 31, 2000 (dollars in thousands)
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
Business Segments For Year Ended December 31, 1999 (dollars in thousands)
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Not applicable.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Not applicable.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Not applicable.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Not applicable.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
FINANCIAL STATEMENTS
See the Index to Financial Statements in Part II, Item 8.
EXHIBITS FILED
EXHIBIT NO. DESCRIPTION - ----------- -----------
12.1 -- Computation of Ratio of Earnings to Fixed Charges
23.1 -- Consent of Deloitte & Touche LLP
In addition to those Exhibits shown above, 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:
- ---------- (a) Management contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 14(c) of Form 10-K. (b) Reports filed under File No. 1-4473 were filed in the office of the Securities and Exchange Commission located in Washington, D.C. (c) An additional document, substantially identical in all material respects to this Exhibit, has been entered into, relating to an additional Equity Participant. Although such additional document may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates of execution), there are no material details in which such document differs from this Exhibit. (d) Additional agreements, substantially identical in all material respects to this Exhibit have been entered into with additional officers and key employees of the Company. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit.
REPORTS ON FORM 8-K
During the quarter ended December 31, 2000 and the period ended March 13, 2001, the Company filed the following Reports on Form 8-K:
Report dated November 27, 2000, regarding (i) the Court of Appeals affirming the ACC's approval of the 1999 Settlement Agreement; (ii) a Maricopa County Superior Court judge's final judgment related to the Rules; (iii) the proposed timing of the transfer of generation assets; and (iv) the issues related to generation expansion.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ARIZONA PUBLIC SERVICE COMPANY (Registrant)
Date: March 13, 2001 William J. Post ----------------------------------------- (William J. Post, Chairman of the Board of Directors and Chief Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature Title Date --------- ----- ----
William J. Post Principal Executive Officer March 13, 2001 - ----------------------------- and Director (William J. Post, Chairman of the Board of Directors and Chief Executive Officer)
Jack E. Davis Principal Accounting Officer, March 13, 2001 - ----------------------------- President and Director (Jack E. Davis, President)
Michael V. Palmeri Principal Financial Officer March 13, 2001 - ----------------------------- (Michael V. Palmeri, Vice President, Finance)
Edward N. Basha, Jr. Director March 13, 2001 - ----------------------------- (Edward N. Basha, Jr.)
Michael L. Gallagher Director March 13, 2001 - ----------------------------- (Michael L. Gallagher)
Pamela Grant Director March 13, 2001 - ----------------------------- (Pamela Grant)
Roy A. Herberger, Jr. Director March 13, 2001 - ----------------------------- (Roy A. Herberger, Jr.)
Martha O. Hesse Director March 13, 2001 - ----------------------------- (Martha O. Hesse)
William S. Jamieson, Jr. Director March 13, 2001 - ----------------------------- (William S. Jamieson, Jr.)
Humberto S. Lopez Director March 13, 2001 - ----------------------------- (Humberto S. Lopez)
Robert G. Matlock Director March 13, 2001 - ----------------------------- (Robert G. Matlock)
Kathryn L. Munro Director March 13, 2001 - ----------------------------- (Kathryn L. Munro)
Bruce J. Nordstrom Director March 13, 2001 - ----------------------------- (Bruce J. Nordstrom)
Commission File Number 1-4473 ================================================================================
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------
EXHIBITS TO
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2000
----------
Arizona Public Service Company (Exact name of registrant as specified in charter)
================================================================================
INDEX TO EXHIBITS
Exhibit No. Description - ----------- -----------
12.1 -- Computation of Ratio of Earnings to Fixed Charges
23.1 -- Consent of Deloitte & Touche LLP
For a description of the Exhibits incorporated in this filing by reference, see Part IV, Item 14.