ITEM 1. BUSINESS
THE COMPANY
We were incorporated in 1920 under the laws of Arizona and are engaged principally in serving electricity in the State of Arizona. Our principal executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000). Pinnacle West owns all of the outstanding shares of our common stock.
We are Arizona's largest electric utility, with 799,000 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. During 1998, no single purchaser or user of energy accounted for more than 2% of total electric revenues. At December 31, 1998, we employed 6,075 people, which includes employees assigned to joint projects where we are project manager.
This document contains forward-looking statements that involve risks and uncertainties. Words such as "estimates," "expects," "anticipates," "plans," "believes," "projects," and similar expressions identify forward-looking statements. These risks and uncertainties include, but are not limited to, the ongoing restructuring of the electric industry; the outcome of the regulatory proceedings relating to the restructuring; regulatory, tax, and environmental legislation; our ability to successfully compete outside our traditional regulated markets; regional economic conditions, which could affect customer growth; the cost of debt and equity capital; weather variations affecting customer usage; technological developments in the electric industry; and Year 2000 issues. See "Competition" in this Item for a discussion of some of these factors.
COMPETITION
RETAIL
GENERAL. Under current law, we are not in direct competition with any other regulated electric utility for electric service in our retail service territory. Nevertheless, we are subject to varying degrees of competition in certain territories adjacent to or within areas that we serve that are also currently served by other utilities in our region (such as Tucson Electric Power Company, Southwest Gas Corporation, and Citizens Utility Company) as well as cooperatives, municipalities, electrical districts, and similar types of governmental organizations (principally Salt River Project).
We face competitive challenges from low-cost hydroelectric power and natural gas fuel, as well as the access of some utilities to preferential low-priced federal power and other subsidies. In addition, some customers, particularly industrial and large commercial, may own and operate facilities to generate their own electric energy requirements. Such facilities may be operated by the customers themselves or by other entities engaged for such purpose.
ARIZONA ELECTRIC INDUSTRY RESTRUCTURING. See Note 3 of Notes to Financial Statements in Item 8 for a discussion of the electric industry restructuring in Arizona, including ACC rules for the introduction of retail electric competition; stranded cost recovery; and Arizona legislative initiatives. See also "Financial Review - Competition and Industry Restructuring" in Item 7.
WHOLESALE
GENERAL. 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 that competition to sell capacity will remain
vigorous. Our rates for wholesale power sales and transmission services are subject to regulation by the FERC. During 1998, approximately 16% of our electric operating revenues resulted from such sales and charges.
The National Energy Policy Act of 1992 (the "Energy Act") has promoted increased competition in the wholesale electric power markets. The Energy Act reformed provisions of the Public Utility Holding Company Act of 1935 (the "1935 Act") and the Federal Power Act to remove certain barriers to competition for the supply of electricity. For example, the Energy Act permits the FERC to order transmission access for third parties to transmission facilities owned by another entity so that independent suppliers and other third parties can sell at wholesale to customers wherever located. The Energy Act does not, however, permit the FERC to issue an order requiring transmission access to retail customers.
Effective July 9, 1996, a FERC decision requires all electric utilities subject to the FERC's jurisdiction to file transmission tariffs which provide competitors with access to transmission facilities comparable to the transmission owners' access for wholesale transactions, establishes information requirements, and provides for recovery of certain wholesale stranded costs. Retail stranded costs resulting from a state-authorized retail direct-access program are the responsibility of the states, unless a state lacks authority to impose rates to recover such costs, in which case FERC will consider doing so. We have filed a revised open access tariff in accordance with this decision. We do not believe that this decision will have a material adverse impact on our results of operations or financial position.
REGULATORY ASSETS
Our major regulatory assets are deferred income taxes and rate synchronization cost deferrals. These items, combined with miscellaneous regulatory assets and liabilities, amounted to approximately $900 million at December 31, 1998. Under a 1996 regulatory agreement, the ACC accelerated the amortization of substantially all of our regulatory assets to an eight-year period that will end June 30, 2004. Our existing regulatory orders and the current regulatory environment support our accounting practices related to regulatory assets. If rate recovery of these assets is no longer probable, whether due to competition or regulatory action, we would be required to write off the remaining balance as an extraordinary charge to expense. This could have a material impact on our financial statements. See Notes 1, 3, and 10 of Notes to Financial Statements in Item 8 for additional information.
COMPETITIVE STRATEGIES
We are pursuing strategies to maintain and enhance our competitive position. These strategies include (i) cost management, with an emphasis on the reduction of variable costs (fuel, operations, and maintenance expenses) and on increased productivity through technological efficiencies; (ii) a focus on our core business through customer service, distribution system reliability, business segmentation, and the anticipation of market opportunities; (iii) an emphasis on good regulatory relationships; (iv) asset maximization (e.g., higher capacity factors and lower forced outage rates); (v) expanding our generation asset base to support growth in the competitive power marketing arena; (vi) strengthening our capital structure and financial condition; (vii) leveraging core competencies into related areas, such as energy management products and services; and (viii) establishing a trading floor and implementing a risk management program to provide for more stability of prices and the ability to retain or grow incremental margin through more competitive pricing and risk management. Underpinning our competitive strategies are the strong growth characteristics of our service territory. As competition in the electric utility industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete effectively in a more competitive, restructured industry.
GENERATING FUEL AND PURCHASED POWER
1998 ENERGY MIX
Our sources of energy during 1998 were: coal - 36.2%; nuclear - 27.5%; purchased power - 32.3%; and other - 4.0%.
COAL SUPPLY
We believe that Cholla has sufficient reserves of low sulfur coal committed to the plant through 2005. In 1998, the current supplier agreed to allow Cholla to test burn coal from other sources, which led to coal purchases on the spot market. The current supplier is expected to continue to provide substantially all of Cholla's low sulfur coal requirements. We believe there are sufficient reserves of low sulfur coal available to allow the continued operation of Cholla for its useful life. We also believe that Four Corners and NGS have sufficient reserves of low sulfur coal available for use by those plants to continue operating them for their useful lives.
The current sulfur content of coal being used at Four Corners, NGS, and Cholla is approximately 0.77%, 0.54%, and 0.44%, respectively. In 1998, average prices paid for coal supplied from the reserves dedicated under existing contracts were slightly lower, but still comparable to 1997. Escalation components of existing long-term coal contracts impact future coal prices. In addition, major price adjustments can occur from time to time as a result of contract renegotiation.
NGS and Four Corners are located on the Navajo Reservation and held under easements granted by the federal government as well as leases from the Navajo Nation. See "Properties- Plant Sites Leased from the Navajo Nation" 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 ---------
Other............................................................. 5,600 ---------
Total........................................................ 3,986,900 ========= - ---------- (1) West Phoenix steam units (108,300 kW) are currently mothballed.
-----------------------------------------------------
RESERVE MARGIN
Our peak one-hour demand on our electric system was recorded on July 16, 1998 at 5,072,000 kW, compared to the 1997 peak of 4,608,600 kW recorded on August 22. Taking into account additional capacity then available to us under purchase power contracts as well as our own generating capacity, our capability of meeting system demand on July 16, 1998, computed in accordance with accepted industry practices, amounted to 5,139,600 kW, for an installed reserve margin of 3.1%. 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 1998 peak amounted to 4,862,600 kW, for a margin of (3.9%). Firm purchases from neighboring utilities totaling 1,467,000 kW were in place at the time of the peak ensuring the ability to meet the load requirement, with an actual reserve margin of 7.4%.
PLANT SITES LEASED FROM NAVAJO NATION
NGS and Four Corners are located on land held under easements from the federal government and also under leases from the Navajo Nation. We do not believe that the risk with respect to enforcement of these easements and leases is material. The lease for Four Corners waives until 2001 the requirement that we, as well as our fuel supplier, pay certain taxes to the Navajo Nation. In September 1997, a settlement agreement was finalized between the coal supplier to Four Corners, the Navajo Nation, and us which settled certain issues in the Four Corners lease regarding the obligation of the fuel supplier to pay taxes prior to the expiration of tax waivers in 2001. Pursuant to the agreement, in 1997 we recognized approximately $14 million of pretax earnings related to a partial refund of
possessory interest taxes paid by the fuel supplier. The parties also agreed to renegotiate their business relationship before 2001 in an effort to permit the electricity generated at Four Corners to be priced competitively. We cannot currently predict the outcome of this matter. Certain of our transmission lines and almost all of its contracted coal sources are also located on Indian reservations. See "Generating Fuel and Purchased Power--Coal Supply" in Item 1.
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
The NRC recently amended its rules on financial assurance requirements for the decommissioning of nuclear power plants. The amended rules became effective on November 23, 1998. The amended rules 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. Proposed ACC rules regarding the introduction of retail electric competition in Arizona (see Note 3) currently 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.
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
See "Environmental Matters" and "Water Supply" in Item 1 in regard to pending or threatened litigation and other disputes. See "Regulatory Matters" in Note 3 of Notes to Financial Statements in Item 8 for a discussion of competition and the rules regarding the introduction of retail electric competition in Arizona. On February 28, 1997 and October 16, 1998, we filed lawsuits to protect our legal rights regarding the rules and the amended rules, respectively, and in each 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 97-03753 (consolidated under CV 97-03748.) ARIZONA PUBLIC SERVICE COMPANY v. ARIZONA CORPORATION COMMISSION, CV 98-18896. On August 28, 1998, we filed two lawsuits to protect our legal rights under the stranded cost order and in its complaints the Company 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.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS OF THE REGISTRANT
The Company's executive officers are as follows:
AGE AT NAME MARCH 1, 1999 POSITION(S) AT MARCH 1, 1999 - ---- ------------- ---------------------------- Richard Snell 68 Chairman of the Board of Directors(1) William J. Post 48 Chief Executive Officer(1) Jack E. Davis 52 President, Energy Delivery and Sales(1) William L. Stewart 55 President, Generation(1) George A. Schreiber, Jr. 50 Executive Vice President and Chief Financial Officer(1) Armando B. Flores 55 Executive Vice President, Corporate Business Services James M. Levine 49 Senior Vice President, Nuclear Generation Jan H. Bennett 51 Vice President, Distribution John G. Bohon 53 Vice President, Corporate Services and Human Resources John R. Denman 56 Vice President, Fossil Generation Edward Z. Fox 45 Vice President, Environmental/Health/Safety and New Technology Ventures William E. Ide 52 Vice President, Nuclear Engineering Nancy C. Loftin 45 Vice President, Chief Legal Counsel and Secretary Gregg R. Overbeck 52 Vice President, Nuclear Production Chris N. Froggatt 41 Controller Michael V. Palmeri 40 Treasurer
- ---------- (1) Member of the Board of Directors.
Our executive officers are elected no less often than annually and may be removed by the Board of Directors at any time. The terms served by the named officers in their current positions and the principal occupations (in addition to those stated in the table) of such officers for the past five years have been as follows:
Mr. Snell was elected to his present position as of February 1990. He was also elected Chairman of the Board, President and Chief Executive Officer of Pinnacle West at that time. He retired as President in February 1997 and as Chief Executive Officer in February 1999. Mr. Snell is also a director of Pinnacle West, Aztar Corporation, and Central Newspapers, Inc.
Mr. Post was elected President and Chief Executive Officer in February 1997. In October 1998, he resigned as President and maintained the position of Chief Executive Officer. Prior to that time he was Senior Vice President and Chief Operating Officer (September 1994 - February 1997) and Senior Vice President, Planning, Information and Financial Services (June 1993 - September 1994). Mr. Post was President of Pinnacle West (February 1997 - February 1999) and in February 1999, he became Chief Executive Officer of Pinnacle West. Mr. Post is also a director of Pinnacle West.
Mr. Davis was elected to his present position in October 1998. Prior to that time he was Executive Vice President, Commercial Operations (September 1996 - - October 1998) and Vice President, Generation and Transmission (June 1993-September 1996).
Mr. Stewart was elected to his present position in October 1998. Prior to that time he was Executive Vice President, Generation (September 1996 - October 1998), Executive Vice President, Nuclear (May 1994 - September 1996) and Senior Vice President--Nuclear for Virginia Power (since 1989).
Mr. Schreiber was elected to his present position in February 1997. Prior to that time he was Managing Director at PaineWebber, Inc. (since February 1990). Mr. Schreiber was Executive Vice President of Pinnacle West (February 1997 - February 1999), and he is currently President (since February 1999) and Chief Financial Officer (since February 1997) of Pinnacle West. Mr. Schreiber is also a director of Pinnacle West.
Mr. Flores was elected to his present position in October 1998. Prior to that time, he was Senior Vice President, Corporate Business Services (September 1996 - October 1998) and Vice President, Human Resources (1991-1996). Mr. Flores is a director of Harris Trust Bank.
Mr. Levine was elected to his present position in September 1996. Prior to that time he was Vice President, Nuclear Production (since September 1989).
Mr. Bennett was elected to his present position in May 1991.
Mr. Bohon was elected to his present position in October 1998. Prior to that time he was Vice President, Procurement (April 1997 - October 1998) and Director, Corporate Services (December 1989-April 1997).
Mr. Denman was elected to his present position in April 1997. Prior to that time he was Director of Fossil Generation (since 1990).
Mr. Fox was elected to his present position in October 1995. Prior to that time he was Director, Arizona Department of Environmental Quality and Chairman, Wastewater Management Authority of Arizona (July 1991-September 1995).
Mr. Ide was elected to his present position in September 1996. Prior to that time he was Director, Palo Verde Operations (1994-1996) and Palo Verde Unit 1 Plant Manager (1988-1994).
Ms. Loftin was elected to the positions of Vice President and Chief Legal Counsel in September 1996 and has been Secretary since April 1987. Prior to that time, in addition to Secretary, she was Corporate Counsel (since February 1989).
Mr. Overbeck was elected to his current position in July 1995. Prior to that time he was Assistant to Vice President of the Company (January 1994-July 1995).
Mr. Froggatt was elected to his present position in July 1997. Prior to that time he was Director, Accounting Services (since December 1992) of the Company.
Mr. Palmeri was elected to his present position in July 1997. Prior to that time he was Assistant Treasurer (February 1994-July 1997) and Manager of Finance (June 1990-February 1994) of Pinnacle West. He also became Treasurer of Pinnacle West in July 1997.
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 1998 and 1997.
COMMON STOCK DIVIDENDS (THOUSANDS OF DOLLARS) - -------------------------------------------------------------------------------- QUARTER 1998 1997 - -------------------------------------------------------------------------------- 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 Notes 4 and 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
In this section, we explain our results of operations, general financial condition, and outlook, including:
+ the changes in our earnings from 1997 to 1998 and from 1996 to + the factors impacting our business, including competition and electric industry restructuring + the effects of regulatory agreements on our results + our capital needs and resources and + Year 2000 technology issues.
Throughout this Financial Review, we refer to specific "Notes" in the Notes to Financial Statements that begin on page 35. These Notes add further details to the discussion.
RESULTS OF OPERATIONS
1998 COMPARED WITH 1997 Our 1998 earnings increased $6.9 million - a 2.9% increase - over 1997 earnings primarily because of an increase in customers, expanded power marketing and trading activities, and lower financing costs. In the comparison, these positive factors more than offset the effects of milder weather, two fuel-related settlements recorded in 1997, and two retail price reductions. See Note 3 for additional information about the price reductions.
In 1998, electric operating revenues increased $128 million primarily because of:
+ increased power marketing and trading revenues ($94 million) + increases in the number of customers and the amount of electricity used by customers ($77 million) and + miscellaneous factors ($8 million).
As mentioned above, these positive factors were partially offset by the effects of milder weather ($33 million) and reductions in retail prices ($18 million).
Power marketing and trading activities are predominantly short-term opportunity wholesale sales. The increase in power marketing revenues resulted from higher prices, increased activity in Western bulk power markets, and increased sales to large customers in California. The increase in power marketing and trading revenues was accompanied by related increases in purchased power expenses.
The two fuel-related settlements increased 1997 pretax earnings by about $21 million. The income statement reflects these settlements as reductions in fuel expense and as other income.
Operations and maintenance expense increased $15 million because of customer growth, initiatives related to competition, and expansion of our power marketing and trading function.
Depreciation and amortization expense increased $11 million because we had more plant in service.
Financing costs decreased by $9 million primarily because of lower amounts of outstanding debt and preferred stock.
1997 COMPARED WITH 1996 Our 1997 earnings increased $12.3 million - a 5.4% increase - over 1996 earnings primarily because of:
+ an increase in customers + a $32 million pretax charge in 1996 for a voluntary severance program + two fuel-related settlements in 1997 and + lower financing costs.
These positive factors more than offset the effects of our 1996 regulatory agreement with the Arizona Corporation Commission (ACC), which during 1997 resulted in about $60 million of additional regulatory asset amortization and a $35 million revenue decrease caused by two retail price reductions. See Note 3 and "Results of Operations ___ Regulatory Agreements" below for additional information. In addition, we recognized $12 million of income tax benefits in 1996 that were not repeated in 1997.
In 1997, electric operating revenues increased $160 million primarily because of:
+ increased power marketing revenues ($128 million) + an increase in the number of customers ($58 million) and + weather effects ($7 million).
As mentioned above, these positive factors were partially offset by a $35 million revenue decrease caused by retail price reductions. The increase in power marketing revenues resulted from increased activity in Western bulk power markets. This did not significantly affect our earnings because the increase was substantially offset by higher purchased power expenses.
Two fuel-related settlements in 1997 increased pretax earnings by about $21 million. The income statement shows these settlements as reductions in fuel expense and as other income. About $16 million of the settlements related to years prior to 1997 and $5 million related to 1997. We expect the total annual savings from the settlements for at least the next several years to be about $10 million before income taxes. We do not have a fuel adjustment clause as part of our retail rate structure. As a result, we show changes in fuel and purchased power expenses in current earnings.
We lowered our operations and maintenance expenses in 1997 by putting in place a voluntary severance program in late 1996, with related savings reflected in 1997. These savings were partially offset by increased expenses for marketing, information technology, and power plant maintenance.
We decreased our financing costs by $12 million during 1997 by lowering the amounts of outstanding debt and preferred stock.
REGULATORY AGREEMENTS Regulatory agreements with the ACC affect the results of our operations. The following discussion focuses on two agreements: a 1996 agreement to accelerate the amortization of our regulatory assets and a 1994 settlement to accelerate amortization of our deferred investment tax credits (ITCs).
Under the 1996 agreement with the ACC, we are recovering substantially all of our present regulatory assets through accelerated amortization. The recovery of these assets is taking place over an eight-year period that will end June 30, 2004. For more details, see Note 3. This accelerated amortization increased annual amortization expense by about $120 million ($72 million after taxes).
Also, as part of the 1996 regulatory agreement, we reduced our retail prices by 3.4% effective July 1, 1996. This reduces revenue by about $48.5 million annually ($29 million after taxes). We also agreed to share future cost savings with our customers, which resulted in the following additional retail price reductions:
+ $17.6 million annually ($10.5 million after income taxes), or 1.2%, effective July 1, 1997, and
+ $17 million annually ($10 million after income taxes), or 1.1%, effective July 1, 1998.
We expect to file with the ACC for another retail price decrease of approximately $10.8 million annually ($6.5 million after income taxes) to become effective July 1, 1999. The amount and timing of the price decrease are subject to ACC approval. This will be the last price decrease under the 1996 regulatory agreement.
We discuss above, in "Results of Operations," the factors that offset the earnings impact of the accelerated regulatory asset amortization and the price decreases.
As part of the 1994 rate settlement, we accelerated amortization of substantially all deferred ITCs over a five-year period that ends on December 31, 1999. The amortization of ITCs is shown on our income statement as Other Income ___ Income Taxes. It decreases annual income tax expense by about $28 million. Beginning in 2000, no further benefits will be reflected in income tax expense. See Note 10.
CAPITAL NEEDS AND RESOURCES
Our capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt and preferred stock. We pay for our capital requirements with:
+ cash from our operations + annual cash payments from Pinnacle West of $50 million from 1996 through 1999 (see Note 3) and + to the extent necessary, external financing.
During the period from 1996 through 1998, we paid for all of our capital expenditures with cash from our operations. We expect to do so in 1999 through 2001 as well.
Our capital expenditures in 1998 were $327 million. Our projected capital expenditures for the next three years are: 1999, $328 million; 2000, $317 million; and 2001, $300 million. These amounts include about $30-$35 million each year for nuclear fuel. In general, most of the projected capital expenditures are for:
+ expanding transmission and distribution capabilities to meet customer growth + upgrading existing utility property and + environmental purposes.
In addition, we are considering expanding certain of our operations over the next several years, which may result in additional expenditures. We currently believe that there will be opportunities to expand our investment in generating assets in the next five years. It is expected that these generating assets would be organized in a newly created non-regulated affiliate under Pinnacle West.
During 1998, we redeemed about $145 million of long-term debt and $76 million of preferred stock, including premiums, with cash from operations and long- and short-term debt. Our long-term debt and preferred stock redemption requirements and payment obligations on a capitalized lease for the next three years are: 1999, $260 million; 2000, $115 million; and 2001, $2 million. On March 1, 1999, we redeemed all $95 million of our outstanding preferred stock. 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, 1998, we had credit commitments from various banks totaling about $400 million, which were available either to support the issuance of commercial paper or to be used as bank borrowings. At the end of 1998, we had about $179 million of commercial paper and $125 million of long-term bank borrowings outstanding.
In 1998, we issued $100 million of unsecured long-term debt and in February 1999, we issued $125 million of unsecured long-term debt.
Although provisions in our first mortgage bond indenture, articles of incorporation, 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.
COMPETITION AND INDUSTRY RESTRUCTURING
The electric industry is undergoing significant change. It is moving to a competitive, market-based structure from a highly-regulated, cost-based environment in which companies have been entitled to recover their costs and to earn fair returns on their invested capital in exchange for commitments to serve all customers within designated service territories. In December 1996, the ACC adopted rules that provide a framework for the introduction of retail electric competition in Arizona and adopted amendments to the rules in August 1998. On January 11, 1999, the ACC issued an order which stayed the amended rules and granted waivers from compliance with the rules to all affected utilities (including us) pending further ACC decisions. On February 5, 1999, ACC hearing officers issued recommendations for changes to the amended rules. These recommended changes were further amended by an ACC Procedural Order dated March 12, 1999. See Note 3 for additional information about these rules and other competitive developments, including an agreement with Salt River Project Agricultural Improvement and Power District (Salt River Project). We cannot currently predict when or if the amended rules will be further modified, when the stay of the amended rules will be lifted, or when retail electric competition will be introduced in Arizona with respect to affected utilities.
The rules as recommended indicate that the ACC will allow affected utilities the opportunity to fully recover unmitigated stranded costs, but do not set forth the mechanisms for determining and recovering such costs. On June 22, 1998, the ACC issued an order on stranded cost determination and recovery and on February 5, 1999, an ACC hearing officer issued recommended changes to that order. These recommended changes were further amended by an ACC Procedural Order dated March 12, 1999. See Note 3 for additional information on proposed modifications to the stranded cost order.
An Arizona joint legislative committee studied electric utility restructuring issues in 1996 and 1997. In May 1998, a law was enacted 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 a discussion of legislative developments.
We believe that further ACC decisions, legislation at the Arizona and federal levels, and perhaps amendments to the Arizona Constitution will ultimately be required before significant implementation of retail electric competition can lawfully occur in Arizona. Until it has been determined how competition will be implemented in Arizona, including the manner in which stranded costs will be addressed, we cannot accurately predict the impact of full retail competition on our financial position, cash flows, or results of operations. 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.
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. Our existing regulatory orders and the current regulatory environment support our accounting practices related to regulatory assets, which amounted to about $900 million at December 31, 1998. Under the 1996 regulatory agreement, the ACC
accelerated the amortization of substantially all of our regulatory assets to an eight-year period that will end June 30, 2004. If we cease to be cost-based regulated, we would no longer be able to apply the provisions of SFAS No. 71 to part or all of our operations, which could have a material impact on our financial statements. See Note 1 for additional information on regulatory accounting.
YEAR 2000 READINESS DISCLOSURE
OVERVIEW As the year 2000 approaches, many companies face problems because many computer systems and equipment will not properly recognize calendar dates beginning with the year 2000. We are addressing the Year 2000 issue as described below. We initiated a comprehensive company-wide Year 2000 program during 1997 to review and resolve all Year 2000 issues in mission critical systems (systems and equipment that are key to business function, health, and safety) in a timely manner to ensure the reliability of electric service to our customers. This included a company-wide awareness program of the Year 2000 issue.
The following chart shows Year 2000 readiness of our mission critical systems as of January 31, 1999:
INVENTORY ASSESSMENT REMEDIATION & TESTING
100% 100% 70%*
* Estimated to be at 100% by June 30, 1999, except one Palo Verde unit as discussed below.
DISCUSSION We have been actively implementing and replacing systems and technology since 1995 for general business reasons unrelated to the Year 2000, and these actions have resulted in substantially all of our major information technology (IT) systems becoming Year 2000 ready. The major IT systems that were, and are being, implemented and replaced include the following:
+ Work Management + Materials Management + Energy Management + Payroll + Financial + Human Resources + Trouble Call Management + Computer and Communications Network Upgrades + Geographic Information Management + Customer Information System and + Palo Verde Site Work Management.
We have made, and will continue to make, certain modifications to computer hardware and software systems and applications, including IT and non-IT systems, in an effort to ensure they are capable of handling changing business needs, including dates in the year 2000 and thereafter. In addition, we are analyzing other IT systems and non-IT systems, including embedded technology and real-time process control systems, for potential modifications.
We have inventoried and assessed essentially all mission critical IT and non-IT systems and equipment. We are 70% complete with the remediation and testing of these systems. Remediation and testing is expected to be completed by June 30, 1999, for all mission critical systems, except for those items that can only be completed during maintenance outages at Palo Verde, which will be completed for the last unit, which is substantially identical to the other two units, during the last half of 1999. We have an internal audit/quality review team that is periodically reviewing the individual Year 2000 projects and their Year 2000 readiness.
We currently estimate that we will spend about $5 million relating to Year 2000 issues, about $3 million of which has been spent to date. This includes an estimated allocation of payroll costs for our employees working on Year 2000 issues, and costs for consultants, hardware, and software. We do not separately track other internal costs. This does not include costs incurred since 1995 to implement and replace systems for reasons unrelated to the Year 2000, as discussed above. Our cost to address the Year 2000 issue is charged to operating expenses as incurred and has not had, and is not expected to have, a material adverse effect on our financial position, cash flows, or results of operations. We expect to fund this cost with available cash balances and cash provided by operations.
We are communicating with our significant suppliers, business partners, other utilities, and large customers to determine the extent to which we may be affected by these third parties' plans to remediate their own Year 2000 issues in a timely manner. We have been interfacing with suppliers of systems, services, and materials in order to assess whether their schedules for analysis and remediation of Year 2000 issues are timely and to assess their ability to continue to supply required services and materials.
We are also working with the North American Electric Reliability Council (NERC) through the Western Systems Coordinating Council (WSCC) to develop operational plans for stable grid operation that will be used by other utilities and us in the western United States. These plans are expected to be completed by June 30, 1999. However, we cannot currently predict the effect on us if the systems of these other companies are not Year 2000 ready.
We currently expect that our most reasonably likely worst case Year 2000 scenario would be intermittent loss of power to customers, similar to an outage during a severe weather disturbance. In this situation, we would restore power as soon as possible by, among other things, re-routing power flows. We do not currently expect that this scenario would have a material adverse effect on our financial position, cash flows, or results of operations.
We are working to develop our own contingency plans to handle Year 2000 issues, including the most reasonably likely worst case scenario, discussed above, and we expect these plans to be completed by June 30, 1999. As discussed above, we have also been working with NERC and WSCC to develop contingency plans related to grid operation.
ACCOUNTING MATTERS
We describe two new accounting rules in Note 2. First, the new rule on energy trading and risk management is effective in 1999. We do not expect it to have a material impact on our financial results. Secondly, the new standard on derivatives is effective for us in 2000. We are currently evaluating what impact it will have on our financial statements. Also, see Note 13 for a description of a proposed standard on accounting for certain liabilities related to closure or removal of long-lived assets.
RISK MANAGEMENT
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 the nuclear decommissioning trust fund. Our policy is to manage interest rates through the use of a combination of fixed 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 rates.
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, 1998 and December 31, 1997. The weighted average interest rates for the various debt presented are actual as of December 31, 1998 and December 31, 1997.
EXPECTED MATURITY/PRINCIPAL REPAYMENT DECEMBER 31, 1998 (THOUSANDS OF DOLLARS)
EXPECTED MATURITY/PRINCIPAL REPAYMENT DECEMBER 31, 1997 (THOUSANDS OF DOLLARS)
COMMODITY PRICE RISK We utilize a variety of derivative instruments including exchange-traded futures, options, and swaps as part of our overall risk management strategies and for trading purposes. In order to reduce the risk of adverse price fluctuations in the electricity and natural gas markets, we enter into futures and/or option transactions to hedge certain natural gas held in storage as well as certain expected purchases and sales of natural gas and electricity. The changes in market value of such contracts have a high correlation to the price changes in the hedged commodity. Gains and losses related to derivatives that qualify as hedges of expected transactions are recognized in income when the underlying hedged physical transaction closes (deferral method). Gains and losses on derivatives utilized for trading are recognized in income on a current basis (the mark to market method).
We have prepared a sensitivity analysis to estimate our exposure to the market risk of our derivative position for natural gas and electricity. With respect to these derivatives, a potential adverse price movement of 10% in the market price of natural gas and electricity from the December 31, 1998 levels would decrease the fair value of these instruments by approximately $1 million. This analysis does not include the favorable impact that the same hypothetical price movement would have on expected physical purchases and sales of natural gas and electricity.
We are exposed to credit losses in the event of non-performance or non-payment by counterparties. We use a credit management process to assess and monitor the financial viability of counterparties. We do not expect counterparty defaults to materially impact our financial condition, results of operations, or net cash flows.
FORWARD-LOOKING STATEMENTS
The above discussion contains forward-looking statements that involve risks and uncertainties. Words such as "estimates," "expects," "anticipates," "plans," "believes," "projects," and similar expressions identify forward-looking statements. These risks and uncertainties include, but are not limited to, the ongoing restructuring of the electric industry; the outcome of the regulatory proceedings relating to the restructuring; regulatory, tax, and environmental legislation; our ability to successfully compete outside our traditional regulated markets; regional economic conditions, which could affect customer growth; the cost of debt and equity capital; weather variations affecting customer usage; technological developments in the electric industry; and Year 2000 issues.
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 "Financial Review" in Item 7 for a discussion of quantitative and qualitative disclosures about market risk.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page ---- Report of Management...................................................... 29
Independent Auditors' Report.............................................. 30
Statements of Income for 1998, 1997, and 1996............................. 31
Balance Sheets as of December 31, 1998 and 1997........................... 32
Statements of Cash Flows for 1998, 1997, and 1996......................... 34
Statements of Retained Earnings for 1998, 1997, and 1996.................. 35
Notes to Financial Statements............................................. 35
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 the Company's financial information rests with management, which has prepared the accompanying financial statements and related information. Such information was prepared in accordance with generally accepted accounting principles appropriate in the circumstances and based on management's best estimates and judgments. Materiality was given due consideration. These financial statements have been audited by independent auditors and their report is included.
Management maintains and relies upon systems of internal accounting controls. A limiting factor in all systems of internal accounting control is that the cost of the system should not exceed the benefits to be derived. Management believes that the Company's system provides the appropriate balance between such costs and benefits.
Periodically the internal accounting control system is reviewed by both the Company's internal auditors and its 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 Review Committee of the Board of Directors and the independent auditors on a timely basis.
The Audit Review 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 Review Committee, without management present, to discuss the results of their audit work.
Management believes that the Company's 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 George A. Schreiber, Jr.
William J. Post George A. Schreiber, Jr. Chief Executive Officer Executive Vice President and Chief Financial Officer
INDEPENDENT AUDITORS' REPORT
We have audited the accompanying balance sheets of Arizona Public Service Company as of December 31, 1998 and 1997 and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1998. 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 generally accepted auditing standards. 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 the Company at December 31, 1998 and 1997 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles.
Deloitte & Touche LLP
Deloitte & Touche LLP Phoenix, Arizona March 4, 1999
ARIZONA PUBLIC SERVICE COMPANY STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31, ------------------------------------- 1998 1997 1996 ---------- ---------- ---------- (THOUSANDS OF DOLLARS)
Electric Operating Revenues ............. $2,006,398 $1,878,553 $1,718,272 ---------- ---------- ---------- Fuel Expenses: Fuel for electric generation ......... 231,967 201,341 230,393 Purchased power ...................... 305,534 235,286 95,130 ---------- ---------- ---------- Total .............................. 537,501 436,627 325,523 ---------- ---------- ----------
Operating Revenues Less Fuel Expenses ... 1,468,897 1,441,926 1,392,749 ---------- ---------- ---------- Other Operating Expenses: Operations and maintenance excluding fuel expenses ...................... 414,041 399,434 430,714 Depreciation and amortization (Note 1) 376,574 365,671 297,210 Income taxes (Note 10) ............... 192,207 184,737 178,513 Other taxes .......................... 115,264 120,259 121,104 ---------- ---------- ---------- Total .............................. 1,098,086 1,070,101 1,027,541 ---------- ---------- ----------
Operating Income ........................ 370,811 371,825 365,208 ---------- ---------- ---------- Other Income (Deductions): Allowance for equity funds used during construction ....................... -- -- 5,209 Income taxes (Note 10) ............... 32,751 31,413 45,552 Other -- net ......................... (12,303) (9,827) (15,544) ---------- ---------- ---------- Total .............................. 20,448 21,586 35,217 ---------- ---------- ----------
Income Before Interest Deductions ....... 391,259 393,411 400,425 ---------- ---------- ---------- Interest Deductions: Interest on long-term debt ........... 137,214 140,931 147,666 Interest on short-term borrowings .... 7,481 9,404 10,621 Debt discount, premium and expense ... 7,580 7,791 8,176 Capitalized interest ................. (16,263) (16,208) (9,509) ---------- ---------- ---------- Total .............................. 136,012 141,918 156,954 ---------- ---------- ----------
Net Income .............................. 255,247 251,493 243,471 Preferred Stock Dividend Requirements ... 9,703 12,803 17,092 ---------- ---------- ----------
Earnings for Common Stock ............... $ 245,544 $ 238,690 $ 226,379 ========== ========== ==========
See Notes to Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY BALANCE SHEETS ASSETS
DECEMBER 31, ------------------------- 1998 1997 ----------- ----------- (THOUSANDS OF DOLLARS) Utility Plant (Notes 5, 8 and 9): Electric plant in service and held for future use...................................... $ 7,265,604 $ 7,009,059 Less accumulated depreciation and amortization .. 2,814,762 2,620,607 ----------- ----------- Total ......................................... 4,450,842 4,388,452 Construction work in progress ................... 228,643 237,492 Nuclear fuel, net of amortization of $68,569 and $66,081 ................................... 51,078 51,624 ----------- ----------- Utility Plant -- net .......................... 4,730,563 4,677,568 ----------- -----------
Investments and Other Assets (Note 13) ............. 183,549 164,906 ----------- -----------
Current Assets: Cash and cash equivalents ....................... 5,558 12,552 Accounts receivable: Service customers ............................. 205,999 141,022 Other ......................................... 23,213 31,313 Allowance for doubtful accounts ............... (1,725) (1,338) Accrued utility revenues ........................ 67,740 58,559 Materials and supplies (at average cost) ........ 69,074 70,634 Fossil fuel (at average cost) ................... 13,978 9,621 Deferred income taxes (Note 10) ................. 3,999 3,496 Other ........................................... 26,695 24,529 ----------- ----------- Total Current Assets .......................... 414,531 350,388 ----------- ----------- Deferred Debits: Regulatory asset for income taxes (Note 10) ..... 400,795 458,369 Rate synchronization cost deferral .............. 303,660 358,871 Unamortized costs of reacquired debt ............ 53,744 63,501 Unamortized debt issue costs .................... 14,916 15,303 Other ........................................... 291,541 242,236 ----------- ----------- Total Deferred Debits ......................... 1,064,656 1,138,280 ----------- ----------- Total ......................................... $ 6,393,299 $ 6,331,142 =========== ===========
See Notes to Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY BALANCE SHEETS LIABILITIES
DECEMBER 31, ----------------------- 1998 1997 ---------- ---------- (THOUSANDS OF DOLLARS) Capitalization (Notes 4 and 5): Common stock ...................................... $ 178,162 $ 178,162 Additional paid--in capital ....................... 1,195,625 1,142,364 Retained earnings ................................. 601,968 528,798 ---------- ---------- Common stock equity ............................. 1,975,755 1,849,324 Non-redeemable preferred stock .................... 85,840 142,051 Redeemable preferred stock ........................ 9,401 29,110 Long-term debt less current maturities ............ 1,876,540 1,953,162 ---------- ---------- Total Capitalization ............................ 3,947,536 3,973,647 ---------- ---------- Current Liabilities: Commercial paper (Note 6) ......................... 178,830 130,750 Current maturities of long-term debt (Note 5) ..... 164,378 104,068 Accounts payable .................................. 145,139 107,423 Accrued taxes ..................................... 59,827 85,886 Accrued interest .................................. 31,218 31,660 Customer deposits ................................. 26,815 29,116 Other ............................................. 16,755 19,588 ---------- ---------- Total Current Liabilities ....................... 622,962 508,491 ---------- ---------- Deferred Credits and Other: Deferred income taxes (Note 10) ................... 1,312,007 1,345,177 Deferred investment tax credit (Note 10) .......... 32,465 60,093 Unamortized gain--sale of utility plant (Note 9)... 77,787 82,363 Customer advances for construction ................ 31,451 29,294 Other ............................................. 369,091 332,077 ---------- ---------- Total Deferred Credits and Other ................ 1,822,801 1,849,004 ---------- ---------- Commitments and Contingencies (Note 12)
Total ............................................. $6,393,299 $6,331,142 ========== ==========
ARIZONA PUBLIC SERVICE COMPANY STATEMENTS OF CASH FLOWS
See Notes to Financial Statements.
ARIZONA PUBLIC SERVICE COMPANY STATEMENTS OF RETAINED EARNINGS
YEAR ENDED DECEMBER 31, ------------------------------ 1998 1997 1996 -------- -------- -------- (THOUSANDS OF DOLLARS)
Retained earnings at beginning of year .......... $528,798 $460,106 $403,843 Add: Net income ................................ 255,247 251,493 243,471 -------- -------- -------- Total ........................................ 784,045 711,599 647,314 -------- -------- -------- Deduct: Dividends: Common stock (Notes 4 and 5) ................. 170,000 170,000 170,000 Preferred stock (at required rates) (Note 4).. 9,703 12,801 17,092 Other .......................................... 2,374 -- 116 -------- -------- -------- Total deductions ............................. 182,077 182,801 187,208 -------- -------- --------
Retained earnings at end of year ................ $601,968 $528,798 $460,106 ======== ======== ========
See Notes to Financial Statements.
APS NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS We are Arizona's largest electric utility, with 799,000 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.
ACCOUNTING RECORDS Our accounting records are maintained in accordance with generally accepted accounting principles (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 Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (FERC). The accompanying financial statements reflect the rate-making policies of these commissions. 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.
Our major regulatory assets are deferred income taxes (see Note 10) and rate synchronization cost deferrals (see "Rate Synchronization Cost Deferrals" in this Note). These items, combined with miscellaneous regulatory assets and liabilities, amounted to approximately $900 million at December 31, 1998 and $1.0 billion at December 31, 1997. Most of these items are included in "Deferred Debits" on the Balance Sheets. 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 will end June 30, 2004. We record the accelerated portion of the regulatory asset amortization, approximately $120 million pretax in 1998 and 1997 and $60 million pretax in 1996, in depreciation and amortization expense on the Statements of Income.
APS NOTES TO FINANCIAL STATEMENTS
During 1997, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (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.
Although rules have been proposed for transitioning generation services to competition, there are many unresolved issues. We continue to apply SFAS No. 71 to our generation operations. If rate recovery of regulatory assets is no longer probable, whether due to competition or regulatory action, we would be required to write off the remaining balance as an extraordinary charge to expense.
COMMON STOCK All of the outstanding shares of our common stock are owned by Pinnacle West. See Note 4.
UTILITY PLANT AND DEPRECIATION Utility plant is the term we use to describe the business property and equipment that supports electric service. We report utility plant at its original cost, which includes:
+ material and labor + contractor costs + construction overhead costs (where applicable) and + capitalized interest or an allowance for funds used during construction.
We charge retired utility plant, plus removal costs less salvage realized, to accumulated depreciation. See Note 13 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 1996 through 1998 the rates, as prescribed by our regulators, ranged from a low of 1.51% to a high of 20%. The weighted-average rate for 1998 was 3.32%. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 50 years.
CAPITALIZED INTEREST In 1997 we began capitalizing interest in accordance with SFAS No. 34, "Capitalization of Interest Cost." Capitalized interest represents the cost of debt funds used to finance construction of utility plant. Plant construction costs, including capitalized interest, are recovered in authorized rates 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 for 1998 was 6.88% and for 1997 was 7.25%.
Prior to 1997 we accrued an allowance for funds used during construction (AFUDC). AFUDC represented the cost of debt and equity funds used to finance construction of utility plant. AFUDC did not represent current cash earnings. AFUDC has been calculated using a composite rate of 7.75% for 1996.
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). Beginning July 1, 1996, the deferrals are being amortized over an eight-year period in
APS NOTES TO FINANCIAL STATEMENTS
accordance with the 1996 regulatory agreement (see Note 3). Prior to July 1, 1996, the deferrals were amortized over thirty-five year periods. 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 expect to produce with that fuel. We then multiply that rate by the number of thermal units that we produce within the current period. This provides us with 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. In addition, Note 13 has information on nuclear decommissioning costs.
REACQUIRED DEBT COSTS When we incur gains or losses on debt that we retire prior to maturity, we amortize those gains and losses over the remaining original life of the debt. In accordance with the 1996 regulatory agreement (see Note 3), the ACC accelerated our amortization of the regulatory asset for reacquired debt costs to 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.
CASH AND CASH EQUIVALENTS For purposes of reporting cash flows, we define cash equivalents as highly liquid debt instruments that will mature in three months or less.
RECLASSIFICATIONS We have reclassified certain prior year amounts for comparison purposes with 1998.
2. ACCOUNTING MATTERS
In 1998 we adopted SFAS No. 130, "Reporting Comprehensive Income." This standard changes the reporting of certain items previously reported in the common stock equity section of the balance sheet. The effects of adopting SFAS No. 130 were not material to our financial statements.
In November 1998, the Financial Accounting Standards Board's Emerging Issues Task Force issued EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," which is effective for us in 1999. 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. We have evaluated the impact of this rule and believe the effects are not material to our financial statements.
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," which is effective for us in 2000. 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. The standard also provides specific guidance for accounting for derivatives designated as hedging instruments. We are currently evaluating what impact this standard will have on our financial statements.
APS NOTES TO FINANCIAL STATEMENTS
3. REGULATORY MATTERS
ELECTRIC INDUSTRY RESTRUCTURING
STATE In December 1996, the ACC adopted rules that provide a framework for the introduction of retail electric competition in Arizona. The rules, as amended, became effective on August 10, 1998, and on December 10, 1998, the ACC adopted the amended rules without any modifications that would have a significant impact on us. We believe that certain provisions of the 1996 ACC rules and the amended rules are deficient and we have filed lawsuits to protect our legal rights regarding the 1996 rules and the amended rules. These lawsuits are pending but two related cases filed by other utilities have been partially decided in a manner adverse to those utilities' positions.
On January 11, 1999, the ACC issued an order which stayed the amended rules, granted reconsideration of the decision to make the rules permanent, and directed the hearing division of the ACC to establish a procedural order for further action on these rules. The order also granted waivers from compliance with the rules for us, and all affected utilities.
On February 5, 1999, the ACC Hearing Division issued recommendations for changes to the amended rules. The recommended changes to the amended rules were further modified by a Procedural Order of the ACC Hearing Division dated March 12, 1999. The recommended rules include the following major provisions:
+ They would apply to virtually all Arizona electric utilities regulated by the ACC, including APS.
+ Each utility must make at least 20% of its 1995 retail peak demand available for competitive generation supply.
+ The rules become effective when the ACC makes a final decision on each utility's stranded costs and unbundled rates (Final Decision Date) or January 1, 2001, whichever comes first.
+ Subject to the 20% requirement, all utility customers with single premise loads of one megawatt or greater will be eligible for competitive electric services on the Final Decision Date. Customers with single premise loads of 40 kilowatts or greater may aggregate loads to meet this one megawatt requirement.
+ When effective, residential customers will be phased in at 1 1/4% per quarter calculated beginning on January 1, 1999, subject to the 20% requirement above.
+ Electric service providers that get Certificates of Convenience and Necessity (CC&Ns) from the ACC can supply only competitive services, including electric generation, but not electric transmission and distribution.
+ Affected utilities must file ACC tariffs with separate pricing for electric services provided for noncompetitive services.
+ ACC shall allow a reasonable opportunity for recovery of unmitigated stranded costs (see "Stranded Costs" below).
APS NOTES TO FINANCIAL STATEMENTS
+ Absent an ACC waiver, prior to January 1, 2001, each affected utility must transfer all competitive generation assets and services either to an unaffiliated party or to a separate corporate affiliate.
+ Affiliate transaction rules prohibit a utility and its competitive electric affiliates from sharing certain assets, employees, and information.
If approved by the ACC, the rules would be subject to the formal rulemaking process under Arizona statute. In compliance with statutory procedural requirements, ACC oral proceedings on the matter would be scheduled no sooner than 30 days after the proposed rules are published by the Secretary of State.
We cannot currently predict when or if the amended rules will be further modified, when the stay of the amended rules will be lifted, or when retail electric competition will be introduced in Arizona.
STRANDED COSTS On June 22, 1998, the ACC issued an Order on stranded cost determination and recovery. We believe that certain provisions of the stranded cost order are deficient and in August 1998, we filed two lawsuits to protect our legal rights relating to the order.
On February 5, 1999, the ACC Hearing Division issued recommended changes to the June 1998 stranded cost order. These recommended changes were further amended by an ACC Procedural Order dated March 12, 1999. The recommended changes to the stranded cost order would be effective upon approval of the ACC. The recommended order, as amended on March 12, 1999, allows each affected utility to choose from five options for the recovery of stranded costs:
+ Net Revenues Lost Methodology is the difference between generation revenues under traditional regulation and generation revenues under competition. This option provides for declining recovery percentages for stranded costs over a five-year recovery period. Regulatory assets are to be fully recovered under their presently authorized amortization schedule. In accordance with a 1996 regulatory agreement, the ACC accelerated the amortization of substantially all of our regulatory assets to an eight-year period that ends June 30, 2004.
+ Divestiture/Auction Methodology allows a utility to divest all or substantially all of its generating assets, including regulatory assets associated with generation, in order to collect 100 percent of the difference between net sales price and book value of generating assets divested over a ten-year period, with no return on the unamortized balance.
+ Financial Integrity Methodology allows a utility "sufficient revenues to meet minimum financial ratios" for a period of ten years.
+ Settlement Methodology allows a settlement to be agreed upon by the ACC and a utility.
+ Any combination of the above if shown to be in the best interests of all affected parties.
LEGISLATIVE INITIATIVES An Arizona joint legislative committee studied electric utility industry restructuring issues in 1996 and 1997. In conjunction with that study, the Arizona legislative counsel prepared memoranda in late 1997 related to the legal authority of the ACC to deregulate the Arizona electric utility industry. The memoranda raise a question as to the degree to which the ACC may, under the Arizona Constitution, deregulate any portion of the electric utility industry and allow rates to be determined by market forces. This latter
APS NOTES TO FINANCIAL STATEMENTS
issue has been subsequently decided by lower courts in favor of the ACC in four separate lawsuits, two of which are unrelated.
In May 1998, a law was enacted to facilitate implementation of retail electric competition in Arizona. The law includes the following major provisions:
+ Arizona's largest government-operated electric utility (Salt River Project) and, at their option, smaller municipal electric systems must (i) make at least 20% of their 1995 retail peak demand available to electric service providers by December 31, 1998 and for all retail customers by December 31, 2000; (ii) decrease rates by at least 10% over a ten-year period beginning as early as January 1, 1991; (iii) implement procedures and public processes comparable to those already applicable to public service corporations for establishing the terms, conditions, and pricing of electric services as well as certain other decisions affecting retail electric competition;
+ describes the factors which form the basis of consideration by Salt River Project in determining stranded costs; and
+ metering and meter reading services must be provided on a competitive basis during the first two years of competition only for customers having demands in excess of one megawatt (and that are eligible for competitive generation services), and thereafter for all customers receiving competitive electric generation.
In addition, the Arizona legislature will review and make recommendations for the 1999 legislature on certain competitive issues.
AGREEMENT WITH SALT RIVER PROJECT On April 25, 1998, we entered into a Memorandum of Agreement with Salt River Project in anticipation of, and to facilitate, the opening of the Arizona electric industry. The Agreement contains the following major components:
+ Both parties would amend the Territorial Agreement to remove any barriers to the provision of competitive electricity supply and non-distribution services.
+ Both parties would amend the Power Coordination Agreement to lower the price that we will pay Salt River Project for purchased power by approximately $17 million (pretax) during the first full year that the Agreement is effective and by lesser annual amounts during the next seven years.
+ Both parties agreed on certain legislative positions regarding electric utility restructuring at the state and federal level.
Certain provisions of the Agreement (including those relating to the amendments of the Territorial Agreement and the Power Coordination Agreement) are affected by the timing of the introduction of competition. See "ACC Rules" above. On February 18, 1999, the ACC approved the Agreement.
GENERAL We believe that further ACC decisions, legislation at the Arizona and federal levels, and perhaps amendments to the Arizona Constitution (which would require a vote of the people) will ultimately be required before significant implementation of retail electric competition can lawfully occur in Arizona. Until the manner of implementation of competition, including addressing stranded costs, is determined, we cannot accurately predict the impact of full retail competition on our financial position, cash flows, or results of operation.
APS NOTES TO FINANCIAL STATEMENTS
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 Energy Policy Act of 1992 and recent rulemakings by FERC have promoted increased competition in the wholesale electric power markets. We do not expect these rules to have a material impact on our financial statements.
Several electric utility reform bills have been introduced during recent congressional sessions, which as currently written would allow consumers to choose their electricity suppliers by 2000 or 2003. These bills, other bills that 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 substantial restructuring of the electric utility industry can occur.
1996 REGULATORY AGREEMENT
In April 1996, the ACC approved a regulatory agreement between the ACC Staff and us. The major provisions of this agreement are:
+ An annual rate reduction of approximately $48.5 million ($29 million after income taxes), or 3.4% on average for all customers except certain contract customers, effective July 1, 1996.
+ Recovery of substantially all of our present regulatory assets through accelerated amortization over an eight-year period that will end June 30, 2004, increasing annual amortization by approximately $120 million ($72 million after income taxes). See Note 1.
+ A formula for sharing future cost savings between customers and shareholders (price reduction formula), referencing a return on equity (as defined) of 11.25%.
+ A moratorium on filing for permanent rate changes prior to July 2, 1999, except under the price reduction formula and under certain other limited circumstances.
+ Infusion of $200 million of common equity into us by Pinnacle West, in annual payments of $50 million starting in 1996.
Based on the price reduction formula, the ACC approved retail price decreases of approximately $17.6 million ($10.5 million after income taxes), or 1.2%, effective July 1, 1997, and approximately $17 million ($10 million after income taxes), or 1.1%, effective July 1, 1998. We expect to file with the ACC for another retail price decrease of approximately $10.8 million annually ($6.5 million after income taxes) to become effective July 1, 1999. The amount and timing of the price decrease are subject to ACC approval. This will be the last price decrease under the 1996 regulatory agreement.
APS NOTES TO FINANCIAL STATEMENTS
4. COMMON AND PREFERRED STOCKS
On March 1, 1999, we redeemed all of our preferred stock. Common and preferred stock balances at December 31, 1998 and 1997 are shown below:
- ---------- (a) The actual call price per share is the indicated amount plus any accrued dividends.
(b) This authorization also covers all outstanding redeemable preferred stock.
(c) Dividend rate adjusted quarterly to 2% below that of certain United States Treasury securities, but in no event less than 6% or greater than 12% per annum. Redeemable at par.
APS NOTES TO FINANCIAL STATEMENTS
We cannot pay common stock dividends or acquire shares of common stock if preferred stock dividends or sinking fund requirements are in arrears.
Redeemable preferred stock transactions during each of the three years in the period ended December 31, 1998 are as follows:
APS NOTES TO FINANCIAL STATEMENTS
5. LONG-TERM DEBT
The following table presents long-term debt outstanding:
DECEMBER 31 MATURITY INTEREST ----------------------- DATES (a) RATES 1998 1997 --------- ----- ---- ---- (THOUSANDS OF DOLLARS)
First mortgage bonds 1998 7.625% $ -- $100,000 1999 7.625% 100,000 100,000 2000 5.75% 100,000 100,000 2002 8.125% 125,000 125,000 2004 6.625% 85,000 85,000 2020 10.25% 100,550 109,550 2021 9.5% 45,140 45,140 2021 9% 72,370 72,370 2023 7.25% 91,900 97,150 2024 8.75% 121,668 121,918 2025 8% 88,300 88,500 2028 5.5% 25,000 25,000 2028 5.875% 154,000 154,000 Unamortized discount and premium (6,482) (7,033) Pollution control bonds 2024-2033 Adjustable 456,860 439,990 rate (b) Collateralized loan 1999-2000 5.375% - 20,000 10,000 6.125% Unsecured note 2005 6.25% 100,000 -- Senior notes(c) 1999 6.72% 50,000 50,000 Senior notes(c) 2006 6.75% 100,000 100,000 Debentures 2025 10% 75,000 75,000 Bank loans 2003 Adjustable 125,000 150,000 rate (d) Capitalized lease obligation 1998-2001 7.48% (e) 11,612 15,645 ---------- ---------- Total long-term debt 2,040,918 2,057,230 Less current maturities 164,378 104,068 ---------- ---------- Total long-term debt less current maturities $1,876,540 $1,953,162 ========== ========== - ----------
(a) This schedule does not reflect the timing of redemptions that may occur prior to maturity.
(b) The weighted-average rate for the years ended December 31, 1998 was 3.39% and for December 31, 1997 was 3.62%. Changes in short-term interest rates would affect the costs associated with this debt.
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(c) We issued $150 million of first mortgage bonds ("senior note mortgage bonds") 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.
(d) The weighted-average rate at December 31, 1998 was 5.69% and at December 31, 1997 was 6.25%. Changes in short-term interest rates would affect the costs associated with this debt.
(e) 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 (see Note 9).
Principal payments due on total long-term debt and sinking fund requirements over the next five years are:
+ $164.4 million in 1999 + $114.7 million in 2000 + $2.5 million in 2001 + $125 million in 2002 and + $125 million in 2003.
First mortgage bondholders have a lien on substantially all utility plant assets (other than nuclear fuel, transportation equipment, and the combined cycle plant). The mortgage bond indenture restricts the payment of common stock dividends under certain conditions. These conditions did not exist at December 31, 1998.
6. LINES OF CREDIT
We had committed lines of credit with various banks of $400 million at December 31, 1998 and 1997, which were available either to support the issuance of commercial paper or to be used for bank borrowings. The commitment fees at December 31, 1998 and 1997 for these lines of credit ranged from .07% to .15% per annum. We had long-term bank borrowings of $125 million outstanding at December 31, 1998, and $150 million outstanding at December 31, 1997.
Our commercial paper borrowings outstanding were $178.8 million at December 31, 1998, and $130.8 million at December 31, 1997. The weighted average interest rate on commercial paper borrowings was 6.21% on December 31, 1998 and 6.27% on December 31, 1997. 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, 1998 and 1997 due to their short maturities. We hold investments in debt and equity securities for purposes other than trading. The December 31, 1998 and 1997 fair values of these investments, which we determine by using quoted market values or by discounting cash flows at rates equal to our cost of capital, approximate their carrying amounts.
APS NOTES TO FINANCIAL STATEMENTS
The carrying value of our long-term debt (excluding a capitalized lease obligation) was $2.03 billion on December 31, 1998, with an estimated fair value of $2.11 billion. On December 31, 1997, the carrying value of our long-term debt (excluding a capitalized lease obligation) was $2.04 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, 1998. Our share of operating and maintaining these facilities is included in the income statement in operations and maintenance expense.
PERCENT CONSTRUCTION OWNED BY PLANT IN ACCUMULATED WORK IN COMPANY SERVICE DEPRECIATION PROGRESS -------- -------- ------------ ------------ (THOUSANDS OF DOLLARS) Generating Facilities: Palo Verde Nuclear Generating Station Units 1 and 3 29.1% $1,821,620 $670,403 $20,152 Palo Verde Nuclear Generating Station Unit 2 (see Note 9) 17.0% 568,184 224,502 9,839 Four Corners Steam Generating Station Units 4 and 5 15.0% 150,165 69,764 312 Navajo Steam Generating Station Units 1, 2, and 3 14.0% 203,356 90,237 25,560(a) Cholla Steam Generating Station Common Facilities (b) 62.8%(c) 67,513 37,096 267 Transmission Facilities: ANPP 500KV System 35.8%(c) 66,547 20,282 1,384 Navajo Southern System 31.4%(c) 26,918 17,285 21 Palo Verde-Yuma 500KV System 23.9%(c) 11,376 4,215 - Four Corners Switchyards 27.5%(c) 3,071 1,780 143 Phoenix-Mead System 17.1%(c) 36,324 536 -
- ---------- (a) The construction costs at Navajo are primarily related to the installation of scrubbers required by environmental legislation.
(b) Pacificorp owns Cholla Unit 4 and we operate the unit for them. The common facilities at the Cholla Plant are jointly-owned.
(c) Weighted average of interests.
APS NOTES TO FINANCIAL STATEMENTS
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 $140.2 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 as follows:
YEAR (IN MILLIONS) - ---- 1999 $40.1 2000 46.3 2001-2015 49.0
In accordance with the 1996 regulatory agreement (see Note 3), the ACC accelerated our amortization of the regulatory asset for leases to an eight-year period that will end June 30, 2004. The accelerated amortization is included in depreciation and amortization expense on the Statements of Income. The balance of this regulatory asset at December 31, 1998 was $48.5 million. Lease expense was approximately $42 million in each of the years 1996 through 1998.
We have a capital lease on a combined cycle plant, which we sold and leased back. The lease requires semiannual payments of $2.6 million through June 2001, and includes renewal and purchase options based on fair market value. The plant is included in plant in service at its original cost of $54.4 million; accumulated amortization at December 31, 1998 was $48.6 million.
In addition, we lease certain land, buildings, equipment, and miscellaneous other items through operating rental agreements with varying terms, provisions, and expiration dates.
Approximate miscellaneous lease expense was:
+ $9.6 million in 1998 + $7.8 million in 1997 and + $9.7 million in 1996.
APS NOTES TO FINANCIAL STATEMENTS
Estimated future minimum lease commitments, excluding the Palo Verde and combined cycle leases, are as follows:
YEAR (IN MILLIONS) - ---- 1999 $ 13 2000 13 2001 14 2002 14 2003 13 Thereafter 91 ------- Total future commitments $ 158 =======
10. 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 are amortizing almost all of our investment tax credits (ITCs) over 5 years (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 on our Balance Sheet in accordance with SFAS No. 71. This regulatory asset is for certain temporary differences, primarily AFUDC equity. We amortize this amount as the differences reverse. We have been able to accelerate the amortization of the regulatory asset for income taxes to an eight-year period that will end June 30, 2004. This is a result of a 1996 regulatory agreement with the ACC. We are including this accelerated amortization in depreciation and amortization expense on the Statements of Income.
The components of income tax expense are as follows:
YEAR ENDED DECEMBER 31, ----------------------------------- 1998 1997 1996 --------- --------- --------- (THOUSANDS OF DOLLARS) Current: Federal .............................. $ 170,806 $ 187,701 $ 137,531 State ................................ 42,652 48,531 35,777 --------- --------- --------- Total current ...................... 213,458 236,232 173,308 Deferred ................................ (26,374) (55,278) (869) Change in valuation allowance ........... -- -- (11,848) Investment tax credit amortization ...... (27,628) (27,630) (27,630) --------- --------- --------- Total expense ...................... $ 159,456 $ 153,324 $ 132,961 ========= ========= =========
APS NOTES TO FINANCIAL STATEMENTS
Multiplying income before income taxes by the statutory federal income tax rate does not equal the amount recorded as income tax expense because of the following:
The components of the net deferred income tax liability were as follows:
DECEMBER 31, ----------------------- 1998 1997 ---------- ---------- (THOUSANDS OF DOLLARS) Deferred tax assets: Deferred gain on Palo Verde Unit 2 sale/leaseback $ 31,285 $ 33,257 Other ........................................... 74,292 77,412 ---------- ---------- Total deferred tax assets ..................... 105,577 110,669 ---------- ----------
Deferred tax liabilities: Plant related ................................... 1,112,897 1,096,222 Regulatory asset for income taxes ............... 161,836 185,084 Rate synchronization deferrals .................. 122,130 144,908 Other ........................................... 16,722 26,136 ---------- ---------- Total deferred tax liabilities ................ 1,413,585 1,452,350 ---------- ----------
Deferred income taxes -- net ....................... $1,308,008 $1,341,681 ========== ==========
11. RETIREMENT PLANS AND OTHER BENEFITS
VOLUNTARY SEVERANCE PLAN We sponsored a voluntary severance plan in 1996. There was a pretax charge of $31.7 million in 1996 recorded mostly as operations and maintenance expense. This pretax charge included additional pension and postretirement benefit expense. Employees who participated in the plan were credited with an additional year of age and service when their pension and postretirement benefits were calculated. The additional expenses recorded in 1996 for this plan were $2.3 million for pension and $5.4 million for postretirement benefits.
PENSION PLAN We sponsor a defined benefit pension plan for our employees. 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 APS employees. Our employees do not contribute to this plan. Generally, we calculate the benefits under this
APS NOTES TO FINANCIAL STATEMENTS
plan based on age, years of service, and pay. We fund the plan by contributing at least the minimum amount required under Internal Revenue Service regulations but no more than the maximum tax-deductible amount. The assets in the plan at December 31, 1998 were mostly domestic and international common stocks and bonds and real estate. Pension expense, including administrative and severance costs, was:
+ $9.8 million in 1998 + $8.7 million in 1997 and + $14.9 million in 1996.
The following table shows the components of net pension cost before consideration of amounts capitalized or billed to others and excluding severance costs of $2.9 million in 1996:
1998 1997 1996 -------- -------- -------- (THOUSANDS OF DOLLARS) Service cost -- benefits earned during the period................................ $ 24,126 $ 19,881 $ 22,861 Interest cost on projected benefit obligation ............................... 50,863 47,824 44,602 Expected return on plan assets ............. (53,883) (47,422) (41,958) Amortization of: Transition asset ...................... (3,216) (3,216) (3,216) Prior service cost .................... 2,063 2,063 1,727 Net actuarial losses .................. -- -- 721 -------- -------- -------- Net periodic pension cost .................. $ 19,953 $ 19,130 $ 24,737 ======== ======== ========
The following table shows a reconciliation of the funded status of the plan to the amounts recognized in the balance sheets:
1998 1997 -------- -------- (THOUSANDS OF DOLLARS) Funded status -- Pension plan assets less than projected benefit obligation .................... $(38,957) $(87,208) Unrecognized net transition asset ................. (23,159) (26,376) Unrecognized prior service cost ................... 22,562 24,625 Unrecognized net actuarial losses/(gains) ......... (38,916) 16,989 -------- -------- Net pension amount recognized in the balance sheets........................................... $(78,470) $(71,970) ======== ========
APS NOTES TO FINANCIAL STATEMENTS
The following table sets forth the defined benefit pension plan's change in projected benefit obligation for the plan years 1998 and 1997:
1998 1997 --------- --------- (THOUSANDS OF DOLLARS) Projected pension benefit obligation at beginning of year ............................ $ 699,600 $ 601,094 Service cost ...................................... 24,126 19,881 Interest cost ..................................... 50,863 47,824 Benefit payments .................................. (29,384) (29,741) Plan amendments ................................... -- 5,537 Actuarial losses/(gains) .......................... (23,976) 55,005 --------- --------- Projected pension benefit obligation at end of year................................... $ 721,229 $ 699,600 ========= =========
The following table sets forth the defined benefit pension plan's change in the fair value of plan assets for the plan years 1998 and 1997:
1998 1997 --------- --------- (THOUSANDS OF DOLLARS) Fair value of pension plan assets at beginning of year ............................ $ 612,392 $ 533,444 Actual return on plan assets ...................... 85,764 87,583 Employer contributions ............................ 13,500 21,106 Benefit payments .................................. (29,384) (29,741) --------- --------- Fair value of pension plan assets at end of year .................................. $ 682,272 $ 612,392 ========= =========
We made the assumptions below to calculate the pension liability:
Discount rate .................................. 7.00% 7.25% Rate of increase in compensation levels ........ 3.50% 4.50% Expected long-term rate of return on assets..... 10.00% 9.00%
EMPLOYEE SAVINGS PLAN BENEFITS We also sponsor a defined contribution savings plan that is offered to nearly all APS employees. In a defined contribution plan, the benefits a participant is to receive result from regular contributions to a participant account. Under this plan, we make matching contributions to participant accounts. We recorded expenses for this plan of:
+ $3.9 million in 1998 + $3.7 million in 1997 and + $3.4 million in 1996.
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,
APS NOTES TO FINANCIAL STATEMENTS
retirees do not make contributions to cover a portion of the plan costs. We retain the right to change or eliminate these benefits.
Funding is based upon actuarially determined contributions that take tax consequences into account. Plan assets consist primarily of domestic stocks and bonds. The postretirement benefit expense was:
+ $8.7 million for 1998 + $9.4 million for 1997 and + $15.8 million for 1996.
The following table shows the components of net periodic postretirement benefit costs before consideration of amounts capitalized or billed to others and excluding severance costs of $9.6 million in 1996:
1998 1997 1996 -------- -------- -------- (THOUSANDS OF DOLLARS) Service cost -- benefits earned during the period.................................. $ 7,676 $ 6,865 $ 7,974 Interest cost on accumulated benefit obligation ................................. 15,610 14,315 13,395 Expected return on plan assets ............... (12,001) (8,706) (6,696) Amortization of: Transition obligation .................... 7,652 7,652 8,223 Net actuarial gains ...................... (2,927) (2,647) (1,344) -------- -------- -------- Net periodic postretirement benefit cost ..... $ 16,010 $ 17,479 $ 21,552 ======== ======== ========
The following table shows a reconciliation of the funded status of the plan to the amounts recognized in the balance sheets:
1998 1997 --------- --------- (THOUSANDS OF DOLLARS) Funded status -- postretirement plan assets less than accumulated benefit obligation ................ $ (21,912) $ (46,435) Unrecognized net obligation at transition ............ 107,134 114,787 Unrecognized net actuarial gains ..................... (86,131) (78,209) --------- --------- Net postretirement amount recognized in the balance sheets .............................. $ (909) $ (9,857) ========= =========
APS NOTES TO FINANCIAL STATEMENTS
The following table sets forth the postretirement benefit plan's change in accumulated benefit obligation for the plan years 1998 and 1997:
1998 1997 --------- --------- (THOUSANDS OF DOLLARS)
Accumulated postretirement benefit obligation at beginning of year ............................... $ 197,581 $ 179,550 Service cost ......................................... 7,676 6,865 Interest cost ........................................ 15,610 14,315 Benefit payments ..................................... (10,347) (6,732) Actuarial losses ..................................... 24,802 3,583 --------- --------- Accumulated postretirement benefit obligation at end of year ..................................... $ 235,322 $ 197,581 ========= =========
The following table sets forth the postretirement benefit plan's change in the fair value of plan assets for the plan years 1998 and 1997:
1998 1997 --------- --------- (THOUSANDS OF DOLLARS) Fair value of postretirement plan assets at beginning of year ............................... $ 151,146 $ 109,763 Actual return on plan assets ......................... 47,284 30,846 Employer contributions ............................... 25,327 17,269 Benefit payments ..................................... (10,347) (6,732) --------- --------- Fair value of postretirement plan assets at end of year ..................................... $ 213,410 $ 151,146 ========= =========
We made the assumptions below to calculate the postretirement liability:
Discount rate ............................................ 7.00% 7.25% Expected long-term rate of return on assets - after tax .. 8.73% 7.75% Initial health care cost trend rate - under age 65........ 7.50% 8.00% Initial health care cost trend rate - age 65 and over..... 6.50% 7.00% Ultimate health care cost trend rate (reached in the year 2002) ............................. 5.00% 5.00%
Assuming a 1% increase in the health care cost trend rate, the 1998 cost of postretirement benefits other than pensions would increase by approximately $5 million and the accumulated benefit obligation as of December 31, 1998 would increase by approximately $37 million.
Assuming a 1% decrease in the health care cost trend rate, the 1998 cost of postretirement benefits other than pensions would decrease by approximately $4 million and the accumulated benefit obligations as of December 31, 1998 would decrease by approximately $32 million.
APS NOTES TO FINANCIAL STATEMENTS
12. COMMITMENTS AND CONTINGENCIES
LITIGATION We are a 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.
PALO VERDE NUCLEAR GENERATING STATION Under the Nuclear Waste Policy Act, DOE was to develop the facilities necessary for the storage and disposal of spent fuel and to have the first such facility in operation by 1998. That facility was to be a permanent repository, but DOE has announced that such a repository now cannot be completed before 2010. In response to lawsuits filed over DOE's obligation to accept used nuclear fuel, the United States Court of Appeals for the D.C. Circuit has ruled that DOE had an obligation to begin accepting used nuclear fuel in 1998. However, the Court refused to issue an order compelling DOE to begin moving used fuel. Instead, the Court ruled that any damages to utilities should be sought under the standard contract signed between DOE and utilities, including APS. The United States Supreme Court has refused to grant review of the D.C. Circuit's decision. In July 1998, we filed a Petition for Review regarding DOE's obligation to begin accepting spent nuclear fuel.
We have capacity in existing fuel storage pools at Palo Verde which, with certain modifications, could accommodate all fuel expected to be discharged from normal operation of Palo Verde through about 2002, and believe we could augment that wet storage with new facilities for on-site dry storage of spent fuel for an indeterminate period of operation beyond 2002, subject to obtaining any required governmental approvals. We currently estimate that we will incur $113 million (in 1998 dollars) over the life of Palo Verde for our share of the costs related to the on-site interim storage of spent nuclear fuel. Beginning in 1999, we will accrue these costs as a component of fuel expense, meaning the charges will be accrued as the fuel is burned. During 1998, we recorded a liability and a regulatory asset of $35 million for on-site interim nuclear fuel storage costs related to nuclear fuel burned prior to 1999. We currently believe that spent fuel storage or disposal methods will be available for use by Palo Verde to allow its continued operation beyond 2002.
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 29.1% interest in the three Palo Verde units, our maximum potential assessment per incident for all three units is approximately $77 million, with an annual payment limitation of approximately $9 million.
The Palo Verde participants maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. 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 1999 through 2020 that include required purchase provisions. We estimate our 1999 contract requirements to be about $132 million. However, this amount may vary significantly pursuant to certain provisions in such contracts that permit us to decrease our required purchases under certain circumstances.
APS NOTES TO FINANCIAL STATEMENTS
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 $62 million at December 31, 1998 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 1996 regulatory agreement (see Note 3), the ACC began accelerated amortization of our regulatory asset for coal mine reclamation costs 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, 1998 was about $51 million.
CONSTRUCTION PROGRAM Total capital expenditures in 1999 are estimated at $328 million.
13. NUCLEAR DECOMMISSIONING COSTS
We recorded $11.4 million for decommissioning expense in each of the years 1998, 1997, and 1996. We estimate it will cost about $1.8 billion ($452 million in 1998 dollars) to decommission our 29.1% 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 include 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 for us. 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 trusts in accordance with Nuclear Regulatory Commission (NRC) regulations. The trust accounts are reported in "Investments and Other Assets" in our Balance Sheets at their market value of $145.6 million at December 31, 1998 and $124.6 million at December 31, 1997. 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.
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 has indicated that a revised exposure draft will be issued in 1999.
APS NOTES TO FINANCIAL STATEMENTS
14. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly financial information for 1998 and 1997 is as follows:
ELECTRIC EARNINGS OPERATING OPERATING NET FOR QUARTER ENDED REVENUES INCOME(a) INCOME COMMON STOCK - ------------- --------- --------- ------ ------------ (THOUSANDS OF DOLLARS) March 31 $380,423 $ 63,541 $ 31,935 $ 29,057 June 30 441,715 81,299 52,184 49,749 September 30 740,734 155,079 133,193 130,846 December 31 443,526 70,892 37,935 35,892 March 31 $379,021 $61,439 $28,645 $25,019 June 30 458,751 99,706 69,493 66,298 September 30 632,821 150,892 129,699 126,715 December 31 407,960 59,788 23,656 20,658
- ----------
(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.
APS NOTES TO FINANCIAL STATEMENTS
15. STOCK OPTIONS
Our parent company, Pinnacle West Capital Corporation, offers several stock incentive plans for our officers, our parent company's officers, and key employees.
The plans provide for the granting of new options or awards of up to 3.5 million shares at a price per option not less than fair market value on the date the option is granted. The plans also provide for the granting of any combination of stock appreciation rights or dividend equivalents. The awards outstanding under the various incentive plans at December 31, 1998 approximate 1,497,012 non-qualified stock options, 158,121 restricted shares, and no dividend equivalent shares, incentive stock options, or stock appreciation rights.
The FASB issued SFAS No. 123, "Accounting for Stock-Based Compensation," which was effective beginning in 1996. This statement encourages, but does not require, that a company record compensation expense based on the fair value method. We continue to recognize expense based on Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." If we had recorded compensation expense based on the fair value method, our net income would have been reduced to the following pro forma amounts:
1998 1997 1996 -------- -------- -------- (THOUSANDS OF DOLLARS) Net income As reported....................... $255,247 $251,493 $243,471 Pro forma (fair value method)..... $254,640 $251,142 $243,291
We did not consider compensation costs for stock options granted before January 1, 1995. Therefore, future reported net income may not be representative of this compensation cost calculation.
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:
1998 1997 1996 ------ ------ ------- Risk-free interest rate............. 4.54% 5.66% 5.77% Dividend growth..................... 3.03% 4.50% 4.50% Volatility.......................... 18.80% 15.63% 17.10% Expected life (months).............. 60 60 58
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 on page 28.
EXHIBITS FILED
EXHIBIT NO. DESCRIPTION - ----------- -----------
10.1(a) -- 1999 Management Variable Incentive Plan
10.2(a) -- 1999 Senior Management Variable Incentive Plan
10.3(a) -- 1999 Officers Variable Incentive Plan
23.1 -- Consent of Deloitte & Touche LLP
27.1 -- Financial Data Schedule
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:
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(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, 1998 and the period ended March 30, 1999, the Company filed the following Report on Form 8-K:
Report dated December 1, 1998 relating to an order by the Arizona Supreme Court staying ACC hearings regarding our settlement agreement with the ACC Staff.
Report dated December 9, 1998 relating to (1) a Notice of Withdrawal of Settlement filed by the ACC Staff, (2) terms of expiration of a memorandum of understanding, (3) ACC adoption of the amended rules, and (4) issues affecting the agreement with Salt River Project.
Report dated January 11, 1999 relating to (i) the ACC hearing officers' recommended changes to the amended rules regarding the introduction of retail electric competition in Arizona and to the June 1998 stranded cost order and (ii) action by the Arizona Supreme Court vacating its order staying ACC hearings on the proposed settlement agreement and dismissing the Attorney General's action.
Report dated February 18, 1999 comprised of Exhibits to the Company's Registration Statements (Registration Nos. 333-27551 and 333-58445) relating to the Company's offering of $125 million of Notes.
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 30, 1999 WILLIAM J. POST ------------------------------------------ (William J. Post, 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.
Commission File Number 1-4473 - -------------------------------------------------------------------------------- - --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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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, 1998
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Arizona Public Service Company (Exact name of registrant as specified in charter)
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INDEX TO EXHIBITS
Exhibit No. Description - ----------- -----------
10.1a ___ 1999 Management Variable Incentive Plan
10.2a ___ 1999 Senior Management Variable Incentive Plan
10.3a ___ 1999 Officers Variable Incentive Plan
23.1 ___ Consent of Deloitte & Touche LLP
27.1 ___ Financial Data Schedule
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(a) Management contract or compensatory plan or arrangement required to be filed as an exhibit pursuant to Item 14(c) of Form 10-K.
For a description of the Exhibits incorporated in this filing by reference, see Part IV, Item 14.