ITEM 1. BUSINESS
The Company
The Company was incorporated in 1920 under the laws of Arizona and is engaged principally in serving electricity in the State of Arizona. The principal executive offices of the Company are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000). The Company currently employs approximately 6,535 people, which includes employees assigned to joint projects where the Company is project manager.
The Company serves approximately 681,000 customers in an area that includes all or part of 11 of Arizona's 15 counties. During 1994, no single purchaser or user of energy accounted for more than 3% of total electric revenues.
Pinnacle West owns all of the outstanding shares of the Company's common stock. Pursuant to a Pledge Agreement, dated as of January 31, 1990, between Pinnacle West and Citibank, N.A., as Collateral Agent (the "Pledge Agreement"), and as part of a restructuring of substantially all of its outstanding indebtedness, Pinnacle West granted certain of its lenders a security interest in all of the Company's outstanding common stock. Until the Collateral Agent and Pinnacle West receive notice of the occurrence and continuation of an Event of Default (as defined in the Pledge Agreement), Pinnacle West is entitled to exercise or refrain from exercising any and all voting and other consensual rights pertaining to the common stock. As to matters other than the election of directors, Pinnacle West agreed not to exercise or refrain from exercising any such rights if, in the Collateral Agent's judgment, such action would have a material adverse effect on the value of the common stock. After notice of an Event of Default, the Collateral Agent would have the right to vote the common stock.
Industry and Company Issues
The utility industry continues to experience a number of challenges. Depending on the circumstances of a particular utility, these may include (i) competition in general from numerous sources (see "Competition" below); (ii) difficulties in meeting government imposed environmental requirements; (iii) the necessity to make substantial capital outlays for transmission and distribution facilities; (iv) uncertainty regarding projected electrical demand growth; (v) controversies over electromagnetic fields; (vi) controversies over the safety and use of nuclear power; (vii) issues related to spent fuel and low-level waste (see "Generating Fuel" below); and (viii) increasing costs of wages and materials.
Competition
Certain territory adjacent to or within areas served by the Company is served by other investor-owned utilities (notably Tucson Electric Power Company serving electricity in the Tucson area, Southwest Gas Corporation serving gas throughout the state, and Citizens Utilities Company serving electricity and gas in various locations throughout the state) and a number of cooperatives, municipalities, electrical districts, and similar types of governmental organizations (principally SRP serving electricity in various areas in and around Phoenix).
Electric utilities have historically operated in a highly-regulated environment that provides limited opportunities for direct competition in providing electric service to their customers. The National Energy Policy Act of 1992 (the "Energy Act") has far-reaching implications for the Company by moving utilities toward a more competitive environment. The Energy Act is designed, among other things, to promote competition among utility and non- utility generators by amending the Public Utility Holding Company Act of 1935 (the "1935 Act") to exempt a new class of independent power producers that are not subject to regulation under the 1935 Act. The Energy Act also amends the Federal Power Act to allow the FERC to order electric utilities to transmit, or "wheel," wholesale power for others. The FERC is prohibited under the Energy Act from requiring utilities to provide transmission access to retail customers, and there remains uncertainty about a state's ability to authorize such transmission access to and for retail electric customers.
One of the issues that must be addressed responsibly is the recovery in a more competitive environment of the carrying value of assets (including those referred to in Note 1a of Notes to Financial Statements) acquired or recorded under the existing regulatory environment. Pursuant to a 1994 rate settlement (see Note 2 of Notes to Financial Statements), the Company and the ACC staff will develop certain procedures that are responsive to the competitive forces in larger customer segments, with the objective of making joint recommendations to the ACC in 1995. A separate ACC proceeding on competition was opened in mid-1994 and is expected to continue for some months.
As the forces of competition continue to impact the industry, it will become clearer as to what customer sectors and what regions will be most affected and what strategies are best to deal with those forces. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Competition" in Item 7 for a discussion of some of the Company's strategies.
Capital Structure
The capital structure of the Company (which, for this purpose, includes short-term borrowings and current maturities of long-term debt) as of December 31, 1994 is tabulated below.
Amount Percentage ---------- ---------- (Thousands of Dollars) Long-Term Debt Less Current Maturities: First mortgage bonds................................ $1,740,071 Other............................................... 441,761 ---------- Total long-term debt less current maturities...... 2,181,832 52.5% ---------- Non-Redeemable Preferred Stock........................ 193,561 4.7 ---------- Redeemable Preferred Stock............................ 75,000 1.8 ---------- Common Stock Equity: Common stock, $2.50 par value, 100,000,000 shares authorized; 71,264,947 shares outstanding......... 178,162 Premiums and expenses............................... 1,039,303 Retained earnings................................... 353,655 ---------- Total common stock equity......................... 1,571,120 37.8 ---------- Total capitalization............................ 4,021,513 Current Maturities of Long-Term Debt.................. 3,428 .1 Short-Term Borrowings................................. 131,500 3.1 ---------- --------
Total........................................... $4,156,441 100.0% ---------- -------- ---------- -------- See Notes 3, 4, and 5 of Notes to Financial Statements in Item 8.
On January 12, 1995, the Company issued $75 million of its 10% junior subordinated deferrable interest debentures, Series A (MIDS), due 2025, and applied the net proceeds to the repayment of short-term borrowings incurred for the redemption of preferred stock in 1994. On March 2, 1995, the Company redeemed $49.15 million in aggregate principal amount of the Company's First Mortgage Bonds, 10.25% Series due 2000 (the "10.25% Bonds").
So long as any of the Company's first mortgage bonds are outstanding, the Company is required for each calendar year to deposit with the trustee under its Mortgage cash in a formularized amount related to net additions to the Company's mortgaged utility plant; however, the Company may satisfy all or any part of this "replacement fund" requirement by utilizing redeemed or retired bonds, net property additions, or property retirements. For 1994, the replacement fund requirement amounted to approximately $125 million. Many, though not all, of the bonds issued by the Company under the Mortgage are redeemable at their par value plus accrued interest with cash deposited by the Company in the replacement fund, subject in many cases to a period of time after the original issuance of the bonds during which they may not be so redeemed and/or to other restrictions on any such redemption. The cash deposited with the trustee by the Company in partial satisfaction of its 1994 replacement fund requirements was used to redeem the 10.25% Bonds at their principal amount plus accrued interest.
Rates
State. The ACC has regulatory authority over the Company in matters relating to retail electric rates and the issuance of securities. See Note 2 of Notes to Financial Statements in Item 8 for a discussion of the 1994 retail rate settlement agreement between the Company and the ACC.
Federal. The Company's rates for wholesale power sales and transmission services are subject to regulation by the FERC. During 1994, approximately 6% of the Company's electric operating revenues resulted from such sales and charges. For most wholesale transactions regulated by the FERC, a fuel adjustment clause results in monthly adjustments for changes in the actual cost of fuel for generation and in the fuel component of purchased power expense.
Arizona Corporation Commission Petition
Pinnacle West and its subsidiaries, including the Company, are currently exempt from registration under the 1935 Act; however, the SEC has the authority to revoke or condition an exemption if it appears that any question exists as to whether the exemption may be detrimental to the public interest or the interest of investors or consumers. In May 1990, the ACC filed a petition with the SEC requesting the SEC to revoke or modify the Pinnacle West's exemption under the 1935 Act. To date, the SEC has not taken any action with respect to the ACC petition. The Company cannot predict what action, if any, the SEC may take with respect to such petition. The Company does not believe that the revocation or modification of the Pinnacle West exemption under the 1935 Act, if acted on by the SEC, would have a material adverse effect on the operations or financial position of the Company.
Construction Program
Present construction plans exclude any major baseload generating plants. Utility construction expenditures for the years 1995 through 1997 are therefore expected to be primarily for expanding transmission and distribution capabilities to meet customer growth, upgrading existing facilities and for environmental purposes. Construction expenditures, including expenditures for environmental control facilities, for the years 1995 through 1997 have been estimated as follows:
(Millions of Dollars) By Year By Major Facilities ----------------- ---------------------------------------------------- 1995 $300 Electric generation $278 1996 257 Electric transmission 59 1997 236 Electric distribution 367 ---- General facilities 89 $793 ---- ==== $793 ====
The amounts for 1995 through 1997 exclude capitalized interest costs and capitalized property taxes. These amounts include about $27 million each year for nuclear fuel expenditures. The Company conducts a continuing review of its construction program. This program and the above estimates are subject to periodic revisions based upon changes in projections as to system reliability, system load growth, rates of inflation, the availability and timing of environmental and other regulatory approvals, the availability and costs of outside sources of capital, and changes in project construction schedules. During the years 1992 through 1994, the Company incurred approximately $728 million in construction expenditures and approximately $31 million in additional capitalized items.
Environmental Matters
Pursuant to the Clean Air Act, the EPA has adopted regulations, applicable to certain federally-protected areas, that address visibility impairment that can be reasonably attributed to specific sources. In September 1991, the EPA issued a final rule that would limit sulfur dioxide emissions at NGS. Compliance with the emission limitation becomes applicable to NGS Units 1, 2, and 3 in 1997, 1998, and 1999, respectively. SRP, the NGS operating agent, has estimated a capital cost of $500 million, most of which will be incurred from 1995 through 1998, and annual operations and maintenance costs of approximately $14 million for all three units, for NGS to meet these requirements. The Company will be required to fund 14% of these expenditures.
The Clean Air Act Amendments of 1990 (the "Amendments") became effective on November 15, 1990. The Amendments address, among other things, "acid rain," visibility in certain specified areas, toxic air pollutants, and the nonattainment of national ambient air quality standards. With respect to "acid rain," the Amendments establish a system of sulfur dioxide emissions "allowances." Each existing utility unit is granted a certain number of "allowances." On March 5, 1993, the EPA promulgated rules listing allowance allocations applicable to Company-owned plants, which allocations will begin in the year 2000. Based on those allocations, the Company will have sufficient allowances to permit continued operation of its plants at current levels without installing additional equipment. In addition, the Amendments require the EPA to set nitrogen oxides emissions limitations which would require certain plants to install additional pollution control equipment. On March 22, 1994, the EPA issued rules for nitrogen oxides emissions limitations; however, on November 29, 1994, the United States Court of Appeals for the District of Columbia Circuit vacated the rules and remanded them to the EPA for further consideration. The EPA has not yet proposed revised rules.
With respect to protection of visibility in certain specified areas, the Amendments require the EPA to complete a study by November 1995 concerning visibility impairment in those areas and identification of sources contributing to such impairment. Interim findings of this study have indicated that any beneficial effect on visibility as a result of the Amendments would be offset by expected population and industry growth. The EPA has established a "Grand Canyon Visibility Transport Commission" to complete a study by November 1995 on visibility impairment in the "Golden Circle of National Parks" in the Colorado Plateau. NGS, Cholla, and Four Corners are located near the "Golden Circle of National Parks." Based on the recommendations of the Commission, the EPA may require additional emissions controls at various sources causing visibility impairment in the "Golden Circle of National Parks" and may limit economic development in several western states. The Company cannot currently estimate the capital expenditures, if any, which may be required as a result of the EPA studies and the Commission's recommendations.
With respect to hazardous air pollutants emitted by electric utility steam generating units, the Amendments require two studies. The results of the first study indicated an impact from mercury emissions from such units in certain unspecified areas; however, the EPA has not yet stated whether or not emissions limitations will be imposed. Next, the EPA will complete a general study by November 1995 concerning the necessity of regulating such units under the Amendments. Due to the lack of historical data, and because the Company cannot speculate as to the ultimate requirements by the EPA, the Company cannot currently estimate the capital expenditures, if any, which may be required as a result of these studies.
Certain aspects of the Amendments may require related expenditures by the Company, such as permit fees, none of which the Company expects to have a material impact on its financial position.
Generating Fuel
Coal, nuclear, gas, and other contributions to total net generation of electricity by the Company in 1994, 1993, and 1992, and the average cost to the Company of those fuels (in dollars per MWh), were as follows:
Other includes oil and hydro generation.
The Company believes that Cholla has sufficient reserves of low sulfur coal committed to that plant for the next five years, the term of the existing coal contract. Sufficient reserves of low sulfur coal are available to continue operating Cholla for its useful life. The Company also believes 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 0.8%, 0.6%, and 0.4%, respectively. In 1994, average prices paid for coal supplied from reserves dedicated under the existing contracts were relatively stable, although applicable contract clauses permit escalations under certain conditions. 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 Tribe. See "Properties" in Item 2.

ITEM 2. PROPERTIES
The Company's present generating facilities have an accredited capacity aggregating 4,022,410 kW, comprised as follows:
Capacity(kW) ------------ Coal: Units 1, 2, and 3 at Four Corners, aggregating........... 560,000 15% owned Units 4 and 5 at Four Corners, representing.... 222,000 Units 1, 2, and 3 at Cholla Plant, aggregating........... 590,000 14% owned Units 1, 2, and 3 at the Navajo Plant, representing........................................... 315,000 ----------- 1,687,000 ===========
Gas or Oil: Two steam units at Ocotillo, two steam units at Saguaro, and one steam unit at Yucca, aggregating............... 468,400(1) Eleven combustion turbine units, aggregating............. 500,600 Three combined cycle units, aggregating.................. 253,500 ----------- 1,222,500 ===========
Nuclear: 29.1% owned or leased Units 1, 2, and 3 at Palo Verde, representing........................................... 1,108,710 =========== Other........................................................ 4,200 =========== ---------- (1) West Phoenix steam units (96,300 kW) are currently mothballed.
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The Company's peak one-hour demand on its electric system was recorded on June 29, 1994 at 4,214,000 kW, compared to the 1993 peak of 3,802,300 kW recorded on August 2. Taking into account additional capacity then available to it under purchase power contracts as well as its own generating capacity, the Company's capability of meeting system demand on June 29, 1994, computed in accordance with accepted industry practices, amounted to 4,514,300 kW, for an installed reserve margin of 8.1%. The power actually available to the Company from its 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 1994 peak amounted to 4,193,500 kW, for a margin of -0.5%. Firm purchases from neighboring utilities totaling 550 MW were in place at the time of the 1994 peak, ensuring the Company's ability to meet the load requirement.
NGS and Four Corners are located on land held under easements from the federal government and also under leases from the Navajo Tribe. The risk with respect to enforcement of these easements and leases is not deemed by the Company to be material. The Company is dependent, however, in some measure upon the willingness and ability of the Navajo Tribe to honor its commitments. Certain of the Company's transmission lines and almost all of its contracted coal sources are also located on Indian reservations. See "Generating Fuel" in Item 1.
On August 18, 1986 and December 19, 1986, the Company entered into a total of three sale and leaseback transactions under which it sold and leased back approximately 42% of its 29.1% ownership interest in Palo Verde Unit 2. The leases under each of the sale and leaseback transactions have initial lease terms expiring on December 31, 2015. Each of the leases also allows the Company to extend the term of the lease and/or to repurchase the leased Unit 2 interest under certain circumstances at fair market value. The leases in the aggregate require annual payments of approximately $40 million through 1999, approximately $46 million in 2000, and approximately $49 million through 2015 (see Note 7 of Notes to Financial Statements in Item 8).
See "Water Supply" in Item 1 with respect to matters having possible impact on the operation of certain of the Company's power plants, including Palo Verde.
The Company's construction plans are susceptible to changes in forecasts of future demand on its electric system and in its ability to finance its construction program. Although its plans are subject to change, present construction plans exclude any major baseload generating plants. Important factors affecting the Company's ability to delay the construction of new major generating units are continuing efforts to upgrade and improve the reliability of existing generating stations, system load diversity with other utilities, and continuing efforts in customer demand-side conservation and load management programs.
In addition to that available from its own generating capacity, the Company purchases electricity from other utilities under various arrangements. One of the most important of these is a long-term contract with SRP which may be canceled by SRP on three years' notice and which requires SRP to make available, and the Company to pay for, certain amounts of electricity that are based in large part on customer demand within certain areas now served by the Company pursuant to a related territorial agreement. The Company believes that the prices payable by it under the contract are fair to both parties. The generating capacity available to the Company pursuant to the contract was 304,000 kW until May, 1994, at which time the capacity increased to 313,000 kW. In 1994, the Company received approximately 887,650 MWh of energy under the contract and paid approximately $40 million for capacity availability and energy received.
In September 1990, the Company and PacifiCorp entered into certain agreements relating principally to sales and purchases of electric power and electric utility assets, and in July 1991, after regulatory approvals, the Company sold Cholla 4 to PacifiCorp for approximately $230 million. As part of the transaction, PacifiCorp agreed to make a firm system sale to the Company for thirty years during the Company's summer peak season in the amount of 175 megawatts for the first five years, increasing thereafter, at the Company's option, up to a maximum amount equal to the rated capacity of Cholla 4. After the first five years, all or part of the sale may be converted to a one-for-one seasonal capacity exchange. PacifiCorp has the right to purchase from the Company up to 125 average megawatts of energy per year for thirty years. PacifiCorp and the Company also entered into a 100 megawatt one-for-one seasonal capacity exchange to be effective upon the latter of January 1, 1996 or the completion of certain new transmission projects. In addition, PacifiCorp agreed to pay the Company (i) $20 million upon commercial operation of 150 megawatts of peaking capacity constructed by the Company and (ii) $19 million ($9.5 million of which has been paid) in connection with the construction of transmission lines and upgrades that will afford PacifiCorp 150 megawatts of northbound transmission rights. In addition, PacifiCorp secured additional firm transmission capacity of 30 megawatts, for which approximately $0.5 million was paid during 1994. In 1994, the Company received 389,110 MWh of energy from PacifiCorp under these transactions and paid approximately $18 million for capacity availability and the energy received, and PacifiCorp paid approximately $0.5 million for approximately 32,000 MWh.
See "El Paso Electric Company Bankruptcy" in Note 10 of Notes to Financial Statements in Item 8 for a discussion of the filing by EPEC of a voluntary petition to reorganize under Chapter 11 of the Bankruptcy Code. EPEC has a joint ownership interest with the Company and others in Palo Verde and Four Corners Units 4 and 5.
See Notes 4 and 7 of Notes to Financial Statements in Item 8 with respect to property of the Company not held in fee or held subject to any major encumbrance.
GRAPHIC -------
In accordance with Item 304 of Regulation S-T of the Securities Exchange Act of 1934, the Company's 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
Property Taxes
On June 29, 1990, a new Arizona state tax law was enacted, effective as of December 31, 1989, which adversely impacted the Company's earnings in tax years 1990 through 1994 by an aggregate amount of approximately $21 million per year, before income taxes. On December 20, 1990, the Palo Verde participants, including the Company, filed a lawsuit in the Arizona Tax Court, a division of the Maricopa County Superior Court, against the Arizona Department of Revenue, the Treasurer of the State of Arizona, and various Arizona counties, claiming, among other things, that portions of the new tax law are unconstitutional. (Arizona Public Service Company, et al. v. Apache County, et al., No. TX 90-01686 (Consol.), Maricopa County Superior Court). In December 1992, the court granted summary judgment to the taxing authorities, holding that the law is constitutional. The Company has appealed this decision to the Arizona Court of Appeals. The Company cannot currently predict the ultimate outcome of this matter.
See "Water Supply" and "Palo Verde Nuclear Generating Station" in Item 1 and "El Paso Electric Company Bankruptcy" in Note 10 of Notes to Financial Statements in Item 8 in regard to pending or threatened litigation and other disputes.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the fourth quarter of the fiscal year covered by this report, through the solicitation of proxies or otherwise.
SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS OF THE REGISTRANT
The Company's executive officers are as follows:
Age at Name March 1, 1995 Position(s) at March 1, 1995 ---- ------------- ---------------------------- Richard Snell 64 Chairman of the Board of Directors (1) O. Mark DeMichele 60 President and Chief Executive Officer(1) William J. Post 44 Senior Vice President and Chief Operating Officer(1) Jaron B. Norberg 57 Executive Vice President and Chief Financial Officer(1) Shirley A. Richard 47 Executive Vice President, Customer Service, Marketing and Corporate Relations William L. Stewart 51 Executive Vice President, Nuclear Jan H. Bennett 47 Vice President, Customer Service Jack E. Davis 48 Vice President, Generation and Transmission Armando B. Flores 51 Vice President, Human Resources James M. Levine 45 Vice President, Nuclear Production Richard W. MacLean 48 Vice President, Environmental, Health and Safety E. C. Simpson 46 Vice President, Nuclear Support Jack A. Bailey 41 Vice President, Nuclear Engineering and Projects William J. Hemelt 41 Controller Nancy C. Loftin 41 Secretary and Corporate Counsel Nancy E. Newquist 43 Treasurer ---------- (1) Member of the Board of Directors.
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The executive officers of the Company 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 and exclusive of directorships) 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. Previously, he was Chairman of the Board (1989- 1992) and Chief Executive Officer (1989-1990) of Aztar Corporation and Chairman of the Board, President, and Chief Executive Officer of Ramada Inc. (1981-1989).
Mr. DeMichele was elected President in September 1982 and became Chief Executive Officer as of January 1988.
Mr. Post was elected to his present position in September 1994. Prior to that time he was Senior Vice President, Planning, Information and Financial Services (since June 1993), and Vice President, Finance & Rates (since April 1987).
Mr. Norberg was elected to his present position in July 1986.
Ms. Richard was elected to her present position in January 1989.
Mr. Stewart was elected to his present position in May 1994. Prior to that time he was Senior Vice President -- Nuclear for Virginia Power (since 1989).
Mr. Bennett was elected to his present position in May 1991. Prior to that time he was Director, Customer Service (September 1990 to May 1991), and Manager, State Region -- Customer Service (January 1988 to September 1990).
Mr. Davis was elected to his present position in June 1993. Prior to that time he was Director, Transmission Systems (January 1993-June 1993); Director, Fossil Generation (June 1992-December 1992); Director, System Development and Power Operations (May 1990-May 1992); and Manager, Power Contracts (March 1979-May 1990).
Mr. Flores was elected to his present position in December 1991. Prior to that time, he was Director -- Human Resources (1990 to 1991) and Manager -- Employment (1989 to 1990) of GENCORP, Propulsion Division, Aerojet Group.
Mr. Levine was elected to his present position in September 1989.
Mr. MacLean was elected to his present position in December 1991. Prior to that time he held the following positions at General Electric (Corporate Environmental Programs): Manager, EHS Resource Development (January to December 1991); and Manager, Environmental Protection (February 1986 to January 1991).
Mr. Simpson was elected to his present position in February 1990.
Mr. Bailey was elected to his present position in April 1994. Prior to that time he was Assistant Vice President, Nuclear Engineering and Projects (July 1993-April 1994); Director, Nuclear Engineering (1991-1993); and, Assistant Plant Manager (1989 to 1991) at Palo Verde.
Mr. Hemelt was elected to his present position in June 1993. Prior to that time he was Treasurer and Assistant Secretary (since April 1987).
Ms. Loftin was elected Secretary in April 1987 and became Corporate Counsel in February 1989.
Ms. Newquist was elected to her present position in June 1993. Prior to that time she was Assistant Treasurer (since October 1992). She is also Treasurer (since June 1990) and Vice President (since February 1994) of Pinnacle West. From May 1987 to June 1990, Ms. Newquist served as Pinnacle West's Director of Finance.
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. See "The Company" in Part I, Item 1 for information regarding the Pledge Agreement to which the common stock is subject.
The chart below sets forth the dividends declared on the Company's common stock for each of the four quarters for 1994 and 1993.
Common Stock Dividends (Thousands of Dollars)
------------------------------------------------- Quarter 1994 1993 ------------------------------------------------- 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 3 and 4 of Notes to Financial Statements in Item 8 for restrictions on retained earnings available for the payment of dividends.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
1994 Compared with 1993
Earnings in 1994 were $218.2 million compared with $219.5 million in 1993. Electric operating revenues increased primarily due to strong customer growth and significantly warmer weather in 1994, partially offset by lower interchange sales and the 1994 rate reduction. Substantially offsetting the earnings effect of the 1994 rate reduction was a one-time depreciation reversal, also occasioned by the 1994 rate settlement. (See Note 2 of Notes to Financial Statements for information regarding the 1994 rate settlement.) Interest expense declined due to the Company's refinancing efforts in 1994 and 1993. The Company's effort to refinance high-cost debt, started in 1992, was substantially completed at the end of 1994.
Substantially offsetting these positive factors were the completion in May 1994 of the recording of non-cash income related to a 1991 rate settlement (see Note 1 of Notes to Financial Statements); increased operations and maintenance expense due primarily to employee severance costs related to various cost-reduction efforts; and increased nuclear decommissioning costs reflecting the most recent site-specific study (see Note 1 of Notes to Financial Statements).
Fuel and purchased power expenses remained relatively unchanged in 1994 compared with 1993. Higher costs to meet increased retail sales were about offset by lower fuel costs for reduced interchange sales. The Company does not have a fuel adjustment clause as part of its retail rate structure; therefore, changes in fuel and purchased power expenses are reflected currently in earnings.
1993 Compared with 1992
Earnings in 1993 were $219.5 million compared with $214.3 million in 1992. The primary factor that contributed to this increase was lower interest expense due to refinancing debt at lower rates, lower average debt balances and lower interest rates on the Company's variable-rate debt. Partially offsetting the lower interest expense were increased taxes and higher operating expenses.
Operating revenue increased significantly due to customer growth. Offsetting customer growth were the effects of milder weather and increased fuel and purchased power costs due to Palo Verde outages and reduced power levels related to steam generator tube problems (see Note 10 of Notes to Financial Statements).
Operations and maintenance expense for 1993 increased over 1992 levels primarily due to the implementation of new accounting standards for postemployment benefits and postretirement benefits other than pensions, which added $17.0 million to expense in 1993 (see Note 9 of Notes to Financial Statements). Partially offsetting these factors were lower power plant operating costs, lower rent expense and lower costs for an employee cost-saving incentive plan.
Operating Revenues
Operating revenues reflect changes in both the volume of units sold and price per kilowatt-hour of electric sales. An analysis of the changes in 1994 and 1993 electric operating revenues compared with the prior year follows (in millions of dollars):
1994 1993 ------ ------ Volume variance ................................. $ 86.7 $22.3 1994 rate reduction ............................. (27.4) -- Interchange sales ............................... (19.5) (7.2) Reversal of refund obligation ................... (12.1) -- Other operating revenues ........................ (3.9) (.3) ------ ------ Total change ................................... $ 23.8 $14.8 ====== ======
The volume increase in 1994 primarily reflects the effects on retail sales of customer growth ($56 million) and warmer weather ($42 million). The volume increase in 1993 was primarily due to customer growth ($41 million), partially offset by milder weather ($20 million reduction). Other factors affecting volumes include changes in usage, unbilled revenue and firm sales for resale for a net total of $11 million reduction in 1994 and $1 million increase in 1993.
Other Income/Rate Settlement Impacts
Net income reflects accounting practices required for regulated public utilities and represents a composite of cash and non-cash items, including AFUDC, accretion income on Palo Verde Unit 3 and the reversal of a refund obligation arising out of the 1991 rate settlement (see Statements of Cash Flows and Note 1 of Notes to Financial Statements). The accretion and refund reversals, net of income taxes, totaled $25.9 million, $58.2 million and $53.6 million in 1994, 1993 and 1992, respectively. The Company has now recorded all of the Palo Verde Unit 3 accretion income and refund obligation reversals related to the 1991 settlement. Also in 1994 was a one-time Palo Verde depreciation reversal of $15 million, net of income tax, which is included in "Other -- net" in the Statements of Income (see Note 2 of Notes to Financial Statements).
The retail rate settlement which was approved by the ACC in May 1994 did not significantly affect 1994 earnings as previously discussed, and is not expected to significantly affect earnings for the years 1995 through 1999 because the rate reduction will be substantially offset by accelerated amortization of deferred investment tax credits (see Note 2 of Notes to Financial Statements).
CAPITAL NEEDS AND RESOURCES
The Company's capital needs consist primarily of construction expenditures and optional and mandatory repayments or redemptions of long-term debt and preferred stock. The capital resources available to meet these requirements include funds provided by operations and external financings.
Present construction plans do not include any major baseload generating plants. In general, most of the construction expenditures are for expanding transmission and distribution capabilities to meet customer growth, upgrading existing facilities and for environmental purposes. Construction expenditures are anticipated to be approximately $300 million, $257 million and $236 million for 1995, 1996 and 1997, respectively. These amounts include about $27 million each year for nuclear fuel expenditures.
In the period 1992 through 1994, the Company funded all of its construction expenditures and capitalized property taxes with funds provided by operations, after the payment of dividends. For the period 1995 through 1997, the Company estimates that it will fund substantially all such expenditures in the same manner.
During 1994, the Company repurchased or redeemed approximately $587 million of long-term debt and preferred stock, of which approximately $518 million was optional. Refunding obligations for preferred stock, long-term debt, a capitalized lease obligation and certain anticipated early redemptions are expected to total approximately $106 million, $4 million and $164 million for the years 1995, 1996 and 1997, respectively. On March 2, 1995, the Company redeemed all of its outstanding first mortgage bonds, 10.25% Series due 2000 (the 10.25% Bonds) for approximately $50 million.
The Company currently expects to issue up to $175 million of debt in 1995. Of this amount, on January 12, 1995, the Company issued $75 million of 10% junior subordinated deferrable interest debentures (MIDS) due 2025, and applied the net proceeds to the repayment of short-term debt that had been incurred for the redemption of preferred stock in 1994. The Company expects that substantially all of the net proceeds of the remaining financing activity in 1995 will be used for the retirement of outstanding debt.
Provisions in the Company's mortgage bond indenture and articles of incorporation require certain coverage ratios to be met before the Company can issue additional first mortgage bonds or preferred stock. In addition, the bond indenture limits the amount of additional first mortgage bonds which may be issued to a percentage of net property additions, to the amount of certain first mortgage bonds that have been redeemed or retired, and/or to cash deposited with the mortgage bond trustee. After giving proforma effect to the redemption of the 10.25% Bonds as of December 31, 1994, the Company estimates that the bond indenture and the articles of incorporation would then have allowed it to issue up to approximately $1.33 billion and $768 million of additional first mortgage bonds and preferred stock, respectively.
The ACC has authority over the Company with respect to the issuance of long-term debt and equity securities. Existing ACC orders allow the Company to have up to approximately $2.6 billion in long-term debt and approximately $501 million of preferred stock outstanding at any one time.
Management does not expect any of the foregoing restrictions to limit the Company's ability to meet its capital requirements.
As of December 31, 1994, the Company had credit commitments from various banks totaling approximately $300 million, which were available either to support the issuance of commercial paper or to be used as bank borrowings. There were no bank borrowings outstanding at the end of 1994. Commercial paper borrowings totaling $131.5 million were then outstanding.
COMPETITION
A significant challenge for the Company will be how well it is able to respond to increasingly competitive conditions in the electric utility industry, while continuing to earn an acceptable return for its shareholders. Strategies emphasize managing costs, stabilizing electric rates, negotiating long-term contracts with large customers and capitalizing on the growth characteristics of the Company's service territory.
One of the issues that must be addressed responsibly is the recovery in a more competitive environment of the carrying value of assets (including those referred to in Note 1a of Notes to Financial Statements) acquired or recorded under the existing regulatory environment.
Pursuant to the 1994 rate settlement, APS and the ACC staff will develop certain procedures that are responsive to the competitive forces in larger customer segments, with the objective of making joint recommendations to the ACC in 1995. A separate ACC proceeding on competition was opened in mid-1994 and is expected to continue for some months.
As the forces of competition continue to impact the industry, it will become clearer as to what customer sectors and what regions will be most affected and what strategies are best to deal with those forces.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page ----
Report of Management ...................................................... 20
Independent Auditors' Report .............................................. 21
Statements of Income for each of the three years in the period ended December 31, 1994 .................................... 23
Balance Sheets -- December 31, 1994 and 1993 .............................. 24
Statements of Retained Earnings for each of the three years in the period ended December 31, 1994 ........................ 26
Statements of Cash Flows for each of the three years in the period ended December 31, 1994 .............................. 27
Notes to Financial Statements ............................................. 28
See Note 11 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, based on management's best estimates and judgments and giving due consideration to materiality. 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 Committee of the Board of Directors and the independent auditors on a timely basis.
The Audit Committee, composed solely of outside directors, meets periodically with the internal auditors and independent auditors (as well as management) to review the work of each. The internal auditors and independent auditors have free access to the Audit Committee, without management present, to discuss the results of their audit work.
Management believes that 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.
O. MARK DEMICHELE JARON B. NORBERG
O. Mark DeMichele Jaron B. Norberg President and Executive Vice President and Chief Executive Officer Chief Financial Officer
WILLIAM J. POST
William J. Post Senior Vice President and Chief Operating Officer
INDEPENDENT AUDITORS' REPORT
Arizona Public Service Company:
We have audited the accompanying balance sheets of Arizona Public Service Company as of December 31, 1994 and 1993 and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1994. 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, 1994 and 1993 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP Phoenix, Arizona March 3, 1995
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ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
a. Accounting Records -- The accounting records are maintained in accordance with generally accepted accounting principles applicable to rate-regulated enterprises. The Company is regulated by the ACC and the FERC and the accompanying financial statements reflect the rate-making policies of these commissions.
The Company prepares its financial statements in accordance with the provisions of 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.
The Company's major regulatory assets are Palo Verde cost deferrals (see Note 1j) and deferred taxes (see Note 8). These items, combined with miscellaneous other items and regulatory liabilities, amounted to approximately $1.1 billion at December 31, 1994 and 1993, most of which are included in "Deferred Debits" on the Balance Sheets.
b. Common Stock -- All of the outstanding shares of common stock of the Company are owned by Pinnacle West.
c. Cash and Cash Equivalents -- For purposes of the statements of cash flows, the Company considers all highly liquid debt instruments purchased with an initial maturity of three months or less to be cash equivalents.
d. Utility Plant and Depreciation -- Utility plant represents the buildings, equipment and other facilities used to provide electric service. The cost of utility plant includes labor, materials, contract services, other related items and an allowance for funds used during construction. The cost of retired depreciable utility plant, plus removal costs less salvage realized, is charged to accumulated depreciation.
Depreciation on utility property is recorded on a straight-line basis. The applicable rates for 1992 through 1994 ranged from 0.84% to 15.00%, which resulted in an annual composite rate of 3.43% for 1994.
e. Nuclear Decommissioning Costs -- In 1994, the Company recorded $11.9 million for decommissioning expense. The Company estimates it will cost approximately $2.1 billion ($425 million in 1994 dollars), over a thirteen-year period beginning in 2023, to decommission its 29.1% interest in Palo Verde. Decommissioning costs are charged to expense over the respective unit's operating license term and are included in the accumulated depreciation balance until each Palo Verde unit is fully decommissioned. Nuclear decommissioning costs are currently recovered in rates.
The Company is utilizing a 1992 site-specific study for Palo Verde, prepared for the Company by an independent consultant, that assumes the prompt removal/dismantlement method of decommissioning. The study is updated every three years.
As required by the ACC, the Company has established external trust accounts into which quarterly deposits are made for decommissioning. As of December 31, 1994, the Company had deposited a total of $45.0 million. The trust accounts are included in "Investments and Other Assets" on the Balance Sheets at a market value of $55.2 million on December 31, 1994. The trust funds are invested primarily in fixed-income securities and domestic stock and are classified as available for sale. Gains and losses are reflected in accumulated depreciation.
In 1994, FASB added a project to its agenda on accounting for nuclear decommissioning obligations. Only preliminary views have been discussed at this time; however, there is some indication the FASB may require the estimated present value of the cost of decommissioning to be recorded as a liability along with an offsetting plant asset. The Company is unable to determine what, if any, impact these deliberations may have on its financial position or results of operations.
f. Revenues -- Operating revenues are recognized on the accrual basis and include estimated amounts for service rendered but unbilled at the end of each accounting period.
In 1991 the Company recorded a refund obligation of $53.4 million ($32.3 million after tax) as a result of a 1991 rate settlement. The refund obligation was used to reduce the amount of a 1991 rate increase granted rather than require specific customer refunds and was reversed over the thirty months ended May 1994. The after-tax refund
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (continued)
obligation reversals that were recorded as electric operating revenues by the Company amounted to $5.6 million in 1994 and $12.9 million in each of the years 1993 and 1992.
Consistent with the 1994 presentation, prior years' electric operating revenues and other taxes have been restated to exclude sales tax on electric revenue.
g. Allowance for Funds Used During Construction -- AFUDC represents the cost of debt and equity funds used to finance construction of utility plant. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation. AFUDC does not represent current cash earnings.
AFUDC has been calculated using composite rates of 7.70% for 1994; 7.20% for 1993; and 10.00% for 1992. The Company compounds AFUDC semiannually and ceases to accrue AFUDC when construction is completed and the property is placed in service.
h. Reacquired Debt Costs -- The Company amortizes gains and losses on reacquired debt over the remaining life of the original debt, consistent with ratemaking.
i. Nuclear Fuel -- Nuclear fuel is charged to fuel expense using the unit-of-production method under which the number of units of thermal energy produced in the current period is related to the total thermal units expected to be produced over the remaining life of the fuel.
Under federal law, the DOE is responsible for the permanent disposal of spent nuclear fuel. The DOE assesses $.001 per kWh of nuclear generation. This amount is charged to nuclear fuel expense and recovered through rates.
j. Palo Verde Cost Deferrals -- As authorized by the ACC, the Company deferred operating costs (excluding fuel) and financing costs for Palo Verde Units 2 and 3 from the commercial operation date (September 1986 and January 1988, respectively) until the date the units were included in a rate order (April 1988 and December 1991, respectively). The deferrals are being amortized and recovered in rates over thirty-five year periods.
k. Palo Verde Accretion Income -- In 1991, the Company discounted the carrying value of Palo Verde Unit 3 to reflect the present value of lost cash flows resulting from a 1991 rate settlement agreement deeming a portion of the unit to temporarily be excess capacity. In accordance with generally accepted accounting principles, the Company recorded accretion income over a thirty-month period ended May 1994 in the aggregate amount of the original discount. The after-tax accretion income recorded in 1994, 1993 and 1992 was $20.3 million, $45.3 million and $40.7 million, respectively.
2. Regulatory Matters
In May 1994, the ACC approved a retail rate settlement agreement which was jointly proposed by the Company and the ACC staff. The major provisions of the settlement include:
* A net annual rate reduction of approximately $32.3 million ($19 million after tax), or 2.2% on average, effective June 1, 1994.
* A moratorium on filing for permanent rate changes, except under certain circumstances, prior to the end of 1996 for both the Company and the ACC staff.
* A joint APS-ACC study to develop rate principles allowing the Company greater flexibility to deal with market conditions and increasing competition in the electric industry.
* All of Palo Verde Unit 3 included in rate base.
* An incentive rewarding reduction in fuel and operating and maintenance cost per kWh below established targets.
As part of the settlement, the Company reversed approximately $20 million of depreciation ($15 million after tax) which related to the portion of Palo Verde which was written off as a result of a 1991 rate settlement. The settlement also provided for the accelerated amortization of substantially all deferred ITCs over a five-year period beginning in 1995. Overall, the settlement is not expected to materially affect the Company's financial position or results of operations for the years 1995-1999.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (continued)
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (continued)
If there were to be any arrearage in dividends on any of the Company's preferred stock or in the sinking fund requirements applicable to any of its redeemable preferred stock, the Company could not pay dividends on its common stock or acquire any shares thereof for consideration.
The redemption requirements for the above issues for the next five years are: $0 in 1995 and 1996, and $10.0 million in each of the years 1997 through 1999.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (continued)
Aggregate annual principal payments due on long-term debt and for sinking fund requirements through 1999 are as follows: 1995, $3.4 million; 1996, $3.5 million; 1997, $153.8 million; 1998, $109.1 million; and 1999, $109.4 million. See Note 3 for redemption and sinking fund requirements of redeemable preferred stock of the Company.
On January 12, 1995, the Company issued $75 million of 10% junior subordinated deferrable interest debentures (MIDS) due 2025.
Substantially all utility plant (other than nuclear fuel, transportation equipment, and the combined cycle plant) is subject to the lien of the mortgage bond indenture. The mortgage bond indenture includes provisions which would restrict the payment of common stock dividends under certain conditions which did not exist at December 31, 1994.
5. Lines of Credit
The Company had committed lines of credit with various banks of $300 million at December 31, 1994, and $302 million at December 31, 1993, which were available either to support the issuance of commercial paper or to be used for bank borrowings. The commitment fees on these lines were 0.25% per annum through June 30, 1994, 0.20% per annum on $200 million and 0.15% per annum on $100 million thereafter, through December 31, 1994. The Company had commercial paper borrowings outstanding of $131.5 million at December 31, 1994, and $148.0 million at December 31, 1993. The weighted average interest rate on commercial paper borrowings was 6.25% on December 31, 1994, and 3.48% on December 31, 1993. By Arizona statute, the Company's short-term borrowings cannot exceed 7% of its total capitalization without the consent of the ACC.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (continued)
7. Leases
In 1986, the Company entered into sale and leaseback transactions under which it sold approximately 42% of its share of Palo Verde Unit 2 and certain common facilities. The gain of approximately $140.2 million has been deferred and is being amortized to operations expense over the original lease term. The leases are being accounted for as operating leases. The amounts paid each year approximate $40.1 million through December 1999, $46.3 million through December 2000, and $49.0 million through December 2015. Options to renew for two additional years and to purchase the property at fair market value at the end of the lease terms are also included. Consistent with the ratemaking treatment, an amount equal to the annual lease payments is included in rent expense. A regulatory asset (totaling approximately $52.8 million at December 31, 1994) has been established for the difference between lease payments and rent expense calculated on a straight-line basis. Lease expense for 1994, 1993 and 1992 was $42.2 million, $41.8 million and $45.8 million, respectively.
The Company has a capital lease on a combined cycle plant which it 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. This plant is included in plant in service at its original cost of $54.4 million; accumulated amortization at December 31, 1994, was $40.3 million.
In addition, the Company also leases certain land, buildings, equipment and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates. Rent expense for 1994, 1993 and 1992 was approximately $10.1 million, $11.1 million and $14.7 million, respectively. Annual future minimum rental commitments, excluding the Palo Verde and combined cycle leases, for the period 1995 through 1999 range between $11 million and $12 million. Total rental commitments after 1999 are estimated at $122 million.
8. Income Taxes
The Company is included in the consolidated income tax returns of Pinnacle West. Income taxes are allocated to the Company based on its separate company taxable income or loss. Approximately $1.8 million of income tax overpayments were due from Pinnacle West at December 31, 1994. Investment tax credits were deferred and are being amortized to other income over the estimated lives of the related assets as directed by the ACC. Beginning in 1995, the ACC portion of the unamortized investment tax credits will be amortized over a five-year period in accordance with the 1994 rate settlement agreement (see Note 2).
Effective January 1, 1993, the Company adopted the provisions of SFAS No. 109, which requires the use of the liability method of accounting for income taxes. Upon adoption the Company recorded deferred income taxes related to the equity component of AFUDC; the debt component of AFUDC recorded net-of-tax; and other temporary differences for which deferred income taxes had not been provided. Deferred tax balances were also adjusted for changes in tax rates. The adoption of SFAS No. 109 had no material effect on net income but increased net deferred income tax liabilities by $585.3 million at December 31, 1993. Historically the FERC and the ACC have allowed revenues sufficient to pay for these deferred tax liabilities and, in accordance with SFAS No. 109, a regulatory asset was established in a corresponding amount.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (continued)
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (continued)
9. Pension Plan and Other Benefits
Pension Plan
The Company sponsors a defined benefit pension plan covering substantially all employees. Benefits are based on years of service and compensation utilizing a final average pay benefit formula. The plan is funded on a current basis to the extent deductible under existing tax regulations. Plan assets consist primarily of domestic and international common stocks and bonds and real estate. Pension cost, including administrative cost, for 1994, 1993 and 1992 was approximately $25.4 million, $14.0 million and $14.0 million, respectively, of which approximately $11.9 million, $6.5 million and $3.9 million, respectively, was charged to expense. The remainder was either capitalized or billed to others.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (continued)
In addition to the defined benefit pension plan described above, the Company also sponsors qualified defined contribution plans. Collectively, these plans cover substantially all employees. The plans provide for employee contributions and partial employer matching contributions after certain eligibility requirements are met. The cost of these plans for 1994, 1993 and 1992 was $6.8 million, $6.3 million and $5.3 million, respectively, of which $3.2 million, $3.0 million and $2.5 million, respectively, was charged to expense.
Postretirement Plans
The Company provides medical and life insurance benefits to its retired employees. Employees may become eligible for these retirement benefits based on years of service and age. The retiree medical insurance plans are contributory; the retiree life insurance plan is noncontributory. In accordance with the governing plan documents, the Company retains the right to change or eliminate these benefits.
During 1993, the Company adopted SFAS No. 106, which requires the cost of postretirement benefits be accrued during the years employees render service. Prior to 1993, the costs of retiree benefits were recognized as expense when claims were paid. This change had the effect of increasing 1994 and 1993 retiree benefit costs from approximately $6 million in each year to $28 million and $34 million, respectively. The amount charged to expense for 1994 increased from about $3 million to $13 million, and for 1993 increased from about $2 million to $17 million. The balance was either capitalized or billed to others. The above amounts include the amortization (over 20 years) of the initial postretirement benefit obligation estimated at January 1, 1993, to be $183 million. Funding is based upon actuarially determined contributions that take tax consequences into account. Plan assets consist primarily of domestic stocks and bonds.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (continued)
The components of the net periodic postretirement benefit costs are as follows:
1994 1993 -------- -------- (Thousands of Dollars)
Service cost -- benefits earned during the period ..... $ 8,785 $ 9,510 Interest cost on accumulated benefit obligation ....... 14,026 15,630 Return on plan assets ................................. (6,459) -- Net amortization and deferral ......................... 11,619 9,146 -------- -------- Net periodic postretirement benefit cost .............. $ 27,971 $ 34,286 ======== ========
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (continued)
Assuming a one percent increase in the health care cost trend rate, the 1994 cost of postretirement benefits other than pensions would increase by approximately $5 million and the accumulated benefit obligation as of December 31, 1994, would increase by approximately $31 million.
In 1993, the Company adopted SFAS No. 112. This standard required a change from a cash method to an accrual method in accounting for benefits (such as long-term disability) provided to former or inactive employees after employment but before retirement. The adoption of this standard resulted in an increase in 1993 postemployment benefit expense of approximately $2 million.
10. Commitments and Contingencies
Litigation
The Company is a party to various claims, legal actions and complaints arising in the ordinary course of business. In the opinion of management, the ultimate resolution of these matters will not have a material adverse effect on the operations or financial position of the Company.
Palo Verde Nuclear Generating Station
The Company has encountered tube cracking in steam generators and has taken, and will continue to take, remedial actions that it believes have slowed further tube problems to manageable levels. The Company believes that the Palo Verde steam generators are capable of operating for their designed life of 40 years, although at some point, long-term economic considerations may make steam generator replacement desirable. All of the Palo Verde units were operating at full power at December 31, 1994.
The Palo Verde participants have insurance for public liability payments resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $200 million and the balance by an industry-wide retrospective assessment program. The maximum assessment per reactor under the retrospective rating program for each nuclear incident is approximately $79 million, subject to an annual limit of $10 million per incident. Based upon the Company's 29.1% interest in the three Palo Verde units, the Company's maximum potential assessment per incident for all three units is approximately $69 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 $2.78 billion, a substantial portion of which must first be applied to stabilization and decontamination. The Company has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.
El Paso Electric Company Bankruptcy
El Paso Electric Company (EPEC), one of the joint owners of Palo Verde and Four Corners, has been operating under Chapter 11 of the Bankruptcy Code since 1992. A plan whereby EPEC would become a wholly-owned subsidiary of Central and South West Corporation (CSW) has been confirmed by the bankruptcy court, but cannot become fully effective until several other approvals are obtained. Under the plan, certain issues, including EPEC allegations regarding the 1989-90 Palo Verde outages, would be resolved, and EPEC would assume the joint facilities operating agreements. CSW has stated that several matters have arisen which may impede completion of the merger. If the plan is not approved, the Company does not expect that there would be a material adverse effect on its operations or financial position.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (continued)
Construction Program
Total construction expenditures in 1995 are estimated at $300 million, excluding capitalized property taxes and capitalized interest.
Fuel and Purchased Power Commitments
The Company is a party to various fuel and purchased power contracts with terms expiring from 1995 through 2020 that include required purchase provisions. The Company estimates its 1995 contract requirements to be approximately $127 million. However, this amount may vary significantly pursuant to certain provisions in such contracts which permit the Company to decrease its required purchases under certain circumstances.
11. Selected Quarterly Financial Data (Unaudited)
Quarterly financial information for 1994 and 1993 is as follows:
Electric Operating Operating Net Earnings for Quarter Revenues(a) Income(b) Income Common Stock ------- ----------- --------- -------- ------------- (Thousands of Dollars)
First ........... $346,049 $ 67,147 $ 38,468 $ 30,958 Second .......... 397,156 83,607 65,851 58,879 Third ........... 540,883 155,115 116,267 110,359 Fourth .......... 342,080 62,564 22,900 18,016
First ........... $353,891 $ 79,441 $ 47,166 $ 39,277 Second .......... 387,871 92,264 61,364 53,716 Third ........... 497,282 132,639 102,911 95,617 Fourth .......... 363,369 68,144 38,945 30,936
(a) Consistent with the presentation for the quarter ended December 31, 1994, prior quarters' electric operating revenues and other taxes have been restated to exclude sales tax on electric revenues.
(b) The Company's operations are subject to seasonal fluctuations primarily as a result of weather conditions. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year.
12. Fair Value of Financial Instruments
The Company estimates that the carrying amounts of its cash equivalents and commercial paper are reasonable estimates of their fair values at December 31, 1994 and 1993 due to their short maturities. The December 31, 1994 and 1993 fair values of debt and equity investments, determined by using quoted market values or by discounting cash flows at rates equal to its cost of capital, approximate their carrying amounts. Investments in debt and equity securities are held for purposes other than trading.
On December 31, 1994, the carrying amount of long-term debt (excluding $26 million of capital lease obligations) was $2.16 billion and its estimated fair value was approximately $1.99 billion. On December 31, 1993, the carrying amount of long-term debt (excluding $30 million of capital lease obligations) was $2.10 billion and its estimated fair value was approximately $2.26 billion. The fair value estimates were determined by independent sources using quoted market rates where available. Where market prices were not available, the fair values were based on market values of comparable instruments.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Reference is hereby made to "Election of Directors" in the Company's Proxy Statement relating to the annual meeting of shareholders to be held on May 16, 1995 (the "1995 Proxy Statement") and to the Supplemental Item -- "Executive Officers of the Registrant" in Part I of this report.
ITEM 11. EXECUTIVE COMPENSATION
Reference is hereby made to the fourth paragraph under the heading "The Board and its Committees," and to "Executive Compensation" in the 1995 Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Reference is hereby made to "Principal Holders of Voting Securities" and "Ownership of Pinnacle West Securities by Management" in the 1995 Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Reference is hereby made to the last paragraph under the heading "The Board and its Committees" in the 1995 Proxy Statement.
PART IV
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 19.
In addition to those Exhibits shown above, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation ss201.24 by reference to the filings set forth below:
Reports on Form 8-K
During the quarter ended December 31, 1994, and the period ended March 29, 1995, the Company filed the following Reports on Form 8-K:
Report filed January 11, 1995 comprised of exhibits to the Company's Registration Statements (Registration Nos. 33-61228 and 33-55473) relating to the Company's offering of $75 million of its Junior Subordinated Deferrable Interest Debentures.
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 29, 1995 O. MARK DEMICHELE -------------------------------- (O. Mark DeMichele, President and Chief Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature Title Date --------- ----- ----
O. MARK DEMICHELE Principal Executive Officer March 29, 1995 ------------------------------- and Director (O. Mark DeMichele, President and Chief Executive Officer)
WILLIAM J. POST Principal Accounting Officer March 29, 1995 ------------------------------- and Director (William J. Post, Senior Vice President and Chief Operating Officer)
JARON B. NORBERG Principal Financial Officer March 29, 1995 ------------------------------- and Director (Jaron B. Norberg, Executive Vice President and Chief Financial Officer)
KENNETH M. CARR Director March 29, 1995 ------------------------------- (Kenneth M. Carr)
MARTHA O. HESSE Director March 29, 1995 ------------------------------- (Martha O. Hesse)
MARIANNE MOODY JENNINGS Director March 29, 1995 ------------------------------- (Marianne Moody Jennings)
ROBERT G. MATLOCK Director March 29, 1995 ------------------------------- (Robert G. Matlock)
JOHN R. NORTON III Director March 29, 1995 ------------------------------- (John R. Norton III)
DONALD M. RILEY Director March 29, 1995 ------------------------------- (Donald M. Riley)
HENRY B. SARGENT Director March 29, 1995 ------------------------------- (Henry B. Sargent)
WILMA W. SCHWADA Director March 29, 1995 ------------------------------- (Wilma W. Schwada)
VERNE D. SEIDEL Director March 29, 1995 ------------------------------- (Verne D. Seidel)
RICHARD SNELL Director March 29, 1995 ------------------------------- (Richard Snell)
DIANNE C. WALKER Director March 29, 1995 ------------------------------- (Dianne C. Walker)
BEN F. WILLIAMS, JR. Director March 29, 1995 ------------------------------- (Ben F. Williams, Jr.)
THOMAS G. WOODS, JR. Director March 29, 1995 ------------------------------- (Thomas G. Woods, Jr.)
Commission File Number 1-4473 ------------------------------------------------------------------------------ ------------------------------------------------------------------------------ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 -------------- EXHIBITS TO FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1994 -------------- Arizona Public Service Company (Exact name of registrant as specified in charter) ------------------------------------------------------------------------------ ------------------------------------------------------------------------------
INDEX TO EXHIBITS
Exhibit No. Description ----------- ----------- 3.1 -- Bylaws, amended as of November 19, 1991
3.2 -- Resolution of Board of Directors temporarily suspending Bylaws in part
10.1 -- Amendment No. 1 to Decommissioning Trust Agreement (PVNGS Unit 1) dated as of December 1, 1994
10.2 -- Amendment No. 1 to Decommissioning Trust Agreement (PVNGS Unit 3) dated as of December 1, 1994
10.3 -- Amendment No. 2 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of November 1, 1994
10.4a -- 1995 Key Employee Variable Pay Plan
10.5a -- 1995 Officers Variable Pay Plan
10.6a -- Letter Agreement dated December 21, 1993, between the Company and William L. Stewart
10.7a -- Pinnacle West Capital Corporation and Arizona Public Service Company Directors' Retirement Plan
10.8ac -- Second revised form of Key Executive Employment and Severance Agreement between the Company and certain key employees of the Company
10.9ac -- Second revised form of Key Executive Employment and Severance Agreement between the Company and certain executive officers of the Company
23.1 -- Consent of Deloitte & Touche LLP
27.1 -- Financial Data Schedule ----------
a Management contract or compensatory plan or arrangement required to be filed as an exhibit pursuant to Item 14(c) of Form 10-K.
b 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.
c 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.
For a description of the Exhibits incorporated in this filing by reference, see Part IV, Item 14.