-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, V4ifgjur03k0Qap4h80MZB1BJTf+a8qKpyFIBsyAtlBI3QjqHJS+VYa5f9f9Jn5H JbboomAEELRVrZmX2yVyhQ== 0000100122-96-000006.txt : 19960306 0000100122-96-000006.hdr.sgml : 19960306 ACCESSION NUMBER: 0000100122-96-000006 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 19951231 FILED AS OF DATE: 19960305 SROS: NYSE SROS: PSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: TUCSON ELECTRIC POWER CO CENTRAL INDEX KEY: 0000100122 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 860062700 STATE OF INCORPORATION: AZ FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-05924 FILM NUMBER: 96531370 BUSINESS ADDRESS: STREET 1: 220 W 6TH ST STREET 2: P O BOX 711 CITY: TUCSON STATE: AZ ZIP: 85702 BUSINESS PHONE: 5205714000 FORMER COMPANY: FORMER CONFORMED NAME: TUCSON GAS & ELECTRIC CO /AZ/ DATE OF NAME CHANGE: 19790528 10-K 1 FORM 10-K SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED) For the fiscal year ended December 31, 1995 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED) For the transition period from to . Commission File Number 1-5924 TUCSON ELECTRIC POWER COMPANY (Exact name of registrant as specified in its charter) ARIZONA 86-0062700 (State or Other Jurisdiction (IRS Employer of Identification No.) Incorporation or Organization) P.O. BOX 711 85702 220 WEST SIXTH STREET, (Zip Code) TUCSON, ARIZONA 85701 (Address of Principal Executive Offices) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (520) 571-4000 SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT: NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED COMMON STOCK, NO PAR VALUE New York Stock Exchange Pacific Stock Exchange FIRST MORTGAGE BONDS 8-1/8% Series due 2001 New York Stock Exchange 7.55% Series due 2002 New York Stock Exchange 7.65% Series due 2003 New York Stock Exchange SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ X ] The aggregate market value of the registrant's outstanding voting Common Stock held by non-affiliates of the registrant is $502,084,300.00 based on the last reported sale price thereof on the consolidated tape on March 1, 1996. At March 1, 1996, 160,666,976 shares of the registrant's Common Stock, no par value (the only class of Common Stock), were outstanding. Documents incorporated by reference: Specified portions of Tucson Electric Power Company's Proxy Statement relating to the 1996 Annual Meeting of Shareholders are incorporated by reference into PART III. TABLE OF CONTENTS Page Definitions....................................................vi - PART I - Item 1. -- Business The Company ...................................................1 Certain Risks; Forward-Looking Information ....................1 Utility Operations Peak Demand and Customers ...................................1 Peak Demand................................................1 Sales for Resale ............................................3 Competition .................................................3 Generating and Other Resources Company Resources ...........................................4 Springerville Station......................................4 Irvington Station..........................................5 SCE/TEP Power Exchange Agreement ............................5 Future Generating Resources .................................5 Other Purchases .............................................6 Rates and Regulation General .....................................................6 1995 Rate Application .......................................7 Notice of Intent to Form a Holding Company ..................8 1994 Rate Order .............................................8 Other Rate Matters ..........................................8 Fuel Supply General .....................................................9 Coal ........................................................9 Valencia ...................................................10 Gas ........................................................11 Water Supply .................................................11 Environmental Matters General ....................................................11 Four Corners Generating Station ............................12 Irvington Generating Station ...............................12 Navajo Generating Station ..................................13 San Juan Generating Station ................................13 Springerville Generating Station ...........................13 Employees ....................................................13 Discontinued Investment Subsidiary Operations ................13 Utility Operating Statistics .................................14 Item 2. -- Properties..........................................15 Item 3. -- Legal Proceedings SDGE/FERC Proceedings ........................................16 Tax Assessments ..............................................16 Water Rights Adjudication ....................................16 Item 4. -- Submission of Matters to a Vote of Security Holders.16 - PART II - Item 5. -- Market for Registrant's Common Equity and Related Stockholder Matters...........................................17 Item 6. -- Selected Consolidated Financial Data................18 Item 7. -- Management's Discussion and Analysis of Financial Condition and Results of Operations Overview General ....................................................19 Competition Wholesale ..................................................20 Retail .....................................................21 Holding Company Proposal .....................................22 Nations Energy Corporation .................................23 Results of Operations ........................................23 Results of Utility Operations Sales and Revenues........................................23 Operating Expenses........................................24 Other Income (Deductions).................................25 Interest Expense..........................................25 Accounting for the Effects of Regulation .....................26 Dividends ....................................................26 Liquidity and Capital Resources Cash Flows .................................................27 Financing Developments .....................................28 Short-Term Credit Facilities Revolving Credit..........................................28 Other.....................................................28 Income Tax Position ..........................................29 Restrictive Covenants General First Mortgage Covenants ...........................29 General Second Mortgage Covenants ..........................30 Additional Restrictive Covenants ...........................30 Construction Expenditures ....................................30 Item 8. -- Consolidated Financial Statements and Supplementary Data............................................31 Independent Auditors' Report .................................32 Consolidated Statements of Income (Loss) .....................33 Consolidated Statements of Cash Flows ........................34 Consolidated Balance Sheets ..................................35 Consolidated Statements of Capitalization ....................36 Consolidated Statements of Changes in Stockholders' Equity (Deficit).............................................37 Notes to Consolidated Financial Statements Note 1. Nature of Operations and Summary of Significant Accounting Policies Nature of Operations .......................................38 Basis of Presentation ......................................38 Use of Estimates ...........................................38 Regulation .................................................38 Accounting for the Effects of Regulation ...................38 Utility Plant ..............................................40 Utility Plant Under Capital Leases .........................40 Springerville Unit 1 Allowance .............................41 Deferred Common Facility Costs .............................41 Utility Operating Revenues .................................41 MSR Option Gain Regulatory Liability .......................41 Fuel and Purchased Power Costs .............................42 Income Taxes ...............................................42 EPA Allowances .............................................42 Fair Value of Financial Instruments ........................43 Reclassification ...........................................43 New Accounting Standards ...................................43 Note 2. Rate Matters 1995 Rate Increase Application .............................44 1994 Rate Order ............................................44 Note 3. Income Taxes ........................................45 Note 4. Consolidated Subsidiaries Nations Energy Corporation..................................47 Discontinued Operations ....................................48 Note 5. Long and Short-Term Debt and Capital Lease Obligations Long-Term Debt .............................................48 First Mortgage Bonds......................................48 MRA.......................................................48 Dividends - Restrictive Covenants.........................49 Letters of Credit.........................................49 Renewable Term Loan.......................................49 Fair Value of Long-Term Debt..............................50 Authorization To Issue Tax-Exempt Bonds...................50 Capital Lease Obligations ..................................50 Maturities and Sinking Fund Requirements ...................51 Short-Term Debt Revolving Credit..........................................51 Investment Subsidiaries...................................51 Note 6. Commitments and Contingencies Utility Contractual Matters Coal and Transportation Contracts - Reversal of Accrued Liabilities......................................52 Fuel Purchase Commitments.................................52 Commitments-Environmental Regulation .......................52 Contingencies SDGE/FERC Proceedings San Diego Gas & Electric v. Tucson Electric Power Company................................................53 Alamito Company, Docket No ER79-97-009 ..................53 Tax Assessments...........................................53 Note 7. Jointly Owned Facilities .............................54 Note 8. Employee Benefits Plans Pension Plans ..............................................54 Postretirement Benefits Other Than Pensions ................55 Stock Option Plans .........................................56 Note 9. Quarterly Financial Data (unaudited) .................58 Note 10. Supplemental Cash Flow Information ..................59 Item 9. -- Changes in and Disagreements with Accountants on Accounting and Financial Disclosure...........................................60 - PART III - Item 10. -- Directors and Executive Officers of the Registrant Directors ....................................................60 Executive Officers ...........................................60 Item 11. -- Executive Compensation.............................62 Item 12. -- Security Ownership of Certain Beneficial Owners and Management General ......................................................62 Security Ownership of Certain Beneficial Owners ..............62 Security Ownership of Management .............................62 Item 13. -- Certain Relationships and Related Transactions.....62 - PART IV - Item 14. -- Exhibits, Financial Statement Schedules, and Reports on Form 8-K...........................................63 Signatures ...................................................64 Exhibit Index ................................................66 DEFINITIONS The abbreviations and acronyms used in the 1995 Form 10-K are defined below: ACC............... Arizona Corporation Commission. ACC Staff......... Staff of the Arizona Corporation Commission. ADEQ.............. Arizona Department of Environmental Quality. AFDC.............. Allowance for Funds Used During Construction. APS............... Arizona Public Service Company. Articles.......... Company's Restated Articles of Incorporation, as amended. Banks............. Various banks with which the Company has credit relationships. Brookland......... Brookland Financial Corporation, a wholly-owned, indirect subsidiary of SRI, which formerly initiated and sold vehicle contract receivable portfolios. BTU............... British Thermal Unit(s). CAAA.............. Federal Clean Air Act Amendments. Catalyst.......... Catalyst Energy Corporation, the parent company of Century. Century........... Century Power Corporation, an indirect subsidiary of Catalyst and formerly known as Alamito Company. Closing........... The closing of the transactions contemplated by the Financial Restructuring, which occurred on December 15, 1992. Commission or SEC. Securities and Exchange Commission. Common Stock...... The Company's common stock, without par value. Company or TEP.... Tucson Electric Power Company. CWIP.............. Construction Work In Progress. Emission Allowance(s)..... An EPA issued allowance which permits emission of one ton of sulfur dioxide. Such allowances can be sold. Energy Act........ The Energy Policy Act of 1992. EPA............... The Environmental Protection Agency. FAS 71............ Statement of Financial Accounting Standards #71: Accounting for the Effects of Certain Types of Regulation. FAS 92............ Statement of Financial Accounting Standards #92: Regulated Enterprises - Accounting for Phase-In Plans. FAS 101........... Statement of Financial Accounting Standards #101: Regulated Enterprises - Accounting for the Discontinuation of Application of FAS 71. FERC.............. The Federal Energy Regulatory Commission. Financial Restructuring.... The comprehensive financial restructuring of the Company's obligations to certain of the Company's creditors and lease participants and Century and the Springerville Unit 1 Leases' participants and the reclassification of all shares of the Preferred Stock into Common Stock which occurred on December 15, 1992. First Mortgage Bonds............ The Company's first mortgage bonds issued under the General First Mortgage. Four Corners...... Four Corners Generating Station. GAAP.............. Generally Accepted Accounting Principles. General First Mortgage......... The Indenture, dated as of April 1, 1941, of Tucson Gas, Electric Light and Power Company to The Chase National Bank of the City of New York, as trustee, as supplemented and amended. General Second Mortgage......... The Indenture, dated as of December 1, 1992, of Tucson Electric Power Company to Bank of Montreal Trust Company of the City of New York, as trustee, as supplemented. Holding Company Act............... The Public Utility Holding Company Act of 1935, as amended. IBEW 1116......... International Brotherhood of Electrical Workers labor union, Local Chapter 1116. IDBs.............. Industrial development revenue or pollution control revenue bonds. Installment Sale Agreement........ $49 million principal amount of City of Farmington, New Mexico, 6.25% Pollution Control Revenue Bonds Series 1973. IRS............... Internal Revenue Service. Irvington......... Irvington Generating Station. Irvington Lease... The leveraged lease arrangement relating to Irvington Unit 4. Irvington Unit 4.. Unit 4 of the Irvington Generating Station. ITC............... Investment tax credit. kW................ Kilowatt(s). kWh............... Kilowatt-hour(s). kV................ Kilovolt(s). kVA............... Kilovoltampere(s). LOC............... Letter of Credit. MRA............... The master financial restructuring agreement completed during the Financial Restructuring between the Company and certain banks excluding the LOC relating to the 1981 Apache B Bonds) which includes the Renewable Term Loan, Revolving Credit, and LOCs. MSR............... Modesto, Santa Clara and Redding Public Power Agency. MW................ Megawatt(s). MWh............... Megawatt-hour(s). Nations Energy.... Nations Energy Corporation, a wholly-owned subsidiary of the Company. Navajo............ Navajo Generating Station. NOL............... Net Operating Losses. 1989 Rate Order... The ACC's October 24, 1989, Rate Order concerning the Company's 1988 application for a rate increase. 1981 Apache B Bonds............ $100 million principal amount of variable rate IDBs which are secured by First Mortgage Bonds. 1990 Pima A Bonds. $20 million principal amount of variable rate IDBs which are secured by First Mortgage Bonds. 1994 Rate Order... The ACC's January 11, 1994, Rate Order concerning an increase in the Company's retail base rates and regulatory write-offs. 1991 Rate Order... The ACC's October 11, 1991, Rate Order concerning an increase in the Company's retail base rates, regulatory write-offs and rate and accounting synchronization. NTUA.............. Navajo Tribal Utility Authority. PDEQ.............. Pima County Department of Environmental Quality. P&M............... Pittsburg & Midway Coal Mining Co. Preferred Stock... The Company's previously outstanding Cumulative Preferred Stock, $100 Par Value, and Cumulative Preferred Stock (No Par) which were reclassified into Common Stock pursuant to the Financial Restructuring. Proposed Settlement Agreement....... The Agreement between the Company and the ACC Staff that proposed to settle both the 1995 rate application and the notice of intent to form a holding company. PNM............... Public Service Company of New Mexico. PURPA ............ The Public Utility Regulatory Policies Act of 1978, as amended. Reimbursement Agreements....... Eleven separate reimbursement agreements between the Company and individual Banks pursuant to which LOCs were issued by such Banks to trustees for issues of tax-exempt IDBs issued by several government entities to finance certain facilities of the Company. Renewable Term Loan............. The credit facility that replaces the Term Loan pursuant to the MRA Sixth Amendment, dated as of November 1, 1994, completed March 7, 1995. Replacment Reimbursement Agreement....... A new master reimbursement agreement entered into among the Company and all Banks that are parties to the Reimbursement Agreements with the exception of the Bank which issued the LOC supporting the 1981 Apache B Bonds. RUCO.............. Residential Utility Consumer Office. Revolving Credit.. The $50 million revolving credit facility entered into between a syndicate of certain of the Banks and the Company as part of the Financial Restructuring. RTGs.............. Regional Transmission Groups. San Carlos........ San Carlos Resources Inc., a wholly-owned subsidiary of the Company. San Juan.......... San Juan Generating Station. San Juan Unit 3... Unit 3 of San Juan. SCE............... Southern California Edison Company, a subsidiary of Edison International. SDGE.............. San Diego Gas & Electric Company, a subsidiary of Enova Corporation. Second Mortgage Bonds............ The Company's second mortgage bonds issued under the General Second Mortgage. Securities Exchange Act.............. The Securities Exchange Act of 1934, as amended. Southwest Gas..... Southwest Gas Corporation. SWRTA ............ Southwest Regional Transmission Association. Springerville..... Springerville Generating Station. Springerville Common Facilities Leases The leveraged lease arrangement relating to the Company's undivided one-half interest in certain facilities at Springerville used in common with Springerville Unit 1 and Springerville Unit 2. Springerville Unit 1............ Unit 1 of the Springerville Generating Station. Springerville Unit 1 Leases.... The leveraged lease arrangement pursuant to which Century leased Springerville Unit 1 and which has been assumed by the Company. Springerville Unit 2........... Unit 2 of the Springerville Generating Station. SRI............... Sierrita Resources Inc., a wholly-owned investment subsidiary of the Company. SRP............... Salt River Project Agricultural Improvement and Power District. Term Loan......... The $243.4 million original principal amount term loan provided by a syndicate of certain Banks as part of the Financial Restructuring. TNP............... Texas New Mexico Power Company. TRI............... Tucson Resources Inc., a wholly-owned investment subsidiary of the Company. Unit 2 First Mortgage......... First mortgage lien on and security interest in Springerville Unit 2 which secures, in part, the Term Loan, the Revolving Credit and the Replacement Reimbursement Agreement. Valencia.......... Valencia Energy Company, a wholly-owned subsidiary of the Company. Valencia Leases... Valencia's leveraged lease arrangement relating to the coal handling facilities serving Springerville. Warrants.......... Warrants for purchase of the Common Stock which were issued under the Financial Restructuring to the owner participants in the Springerville Unit 1 Leases. WRTA ............. Western Regional Transmission Association. WSCC.............. Western Systems Coordinating Council. PART I ITEM 1. -- BUSINESS THE COMPANY Tucson Electric Power Company was incorporated under the laws of the State of Arizona on December 16, 1963. The Company is the successor by merger as of February 20, 1964, to a Colorado corporation which was incorporated on January 25, 1902. The Company is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity for customers in the City of Tucson and the surrounding area and to wholesale customers. The Company holds a franchise which expires in 2001 to provide electric service to customers in the City of Tucson. The Company owns all of the outstanding stock of (i) Valencia Energy Company (Valencia), which supplies coal to the Springerville Generating Station (see Fuel Supply , Valencia ), (ii) San Carlos Resources Inc. (San Carlos), which holds title to Springerville Unit 2, and (iii) Nations Energy Corporation which is active in the development of independent power projects worldwide. See Competition below for a description of Nations Energy. The Company also owns all of the outstanding stock of two non-energy related investment subsidiaries, Tucson Resources Inc. (TRI) and Sierrita Resources Inc. (SRI). In 1994, TRI and SRI substantially completed the process of liquidating their respective investments. CERTAIN RISKS; FORWARD-LOOKING INFORMATION For descriptions of certain factors affecting the Company, including commitments and contingencies, which subject the Company to continuing risks, see (i) 1995 Rate Application and 1994 Rate Order; (ii) Item 3., Legal Proceedings; (iii) Item 7., Management's Discussion and Analysis of Financial Condition and Results of Operations, Overview; and (iv) Notes 1, 2 and 6 of Notes to Consolidated Financial Statements, Nature of Operations and Summary of Significant Accounting Policies, Rate Matters, and Commitments and Contingencies, respectively. The forward-looking statements contained herein regarding growth in the number of customers, growth in retail peak demand and retail sales growth are based, in part, upon publicly available population and demographic studies conducted by persons or entities unaffiliated with the Company. Such statements are also based upon various assumptions including, without limitation, assumptions relating to weather, economic and competitive conditions and the assumption that the Company will incur no significant loss of retail customers due to self-generation or retail wheeling. Actual experience may vary significantly from forward-looking information. UTILITY OPERATIONS PEAK DEMAND AND CUSTOMERS Certain operating and system data related to the Company's utility operations for each of the last five years were as follows: PEAK DEMAND
PEAK DEMAND 1995 1994 1993 1992 1991 ---- ---- ---- ---- ---- -MW- Retail Customers-Net One Hour 1,617 1,585 1,449 1,399 1,319 Other Utilities-Firm 223 226 225 150 150 ----- ----- ----- ----- ----- Non-Coincident Peak Demand (A) 1,840 1,811 1,674 1,549 1,469 ----- ----- ----- ----- ----- Total Generating Resources (B) 2,085 1,975 1,975 1,983 2,048 ----- ----- ----- ----- ----- Total Reserves ((B) - (A)) 245 164 301 434 579 ===== ===== ===== ===== ===== Reserve Margin (% of Non-Coincident Peak Demand) 13% 9% 18% 28% 39% ===== ===== ===== ===== =====
The peak demand for the Company's retail service area occurs during the summer months due to the space cooling requirements of its retail customers. The Company has experienced growth in peak demand (excluding the demand of its copper mining customers) at an average annual rate of approximately 3.9% for the past five years. Including the load of its mining customers, which comprised on average approximately 8.5% of the retail peak demand for the past five years, the Company experienced growth in peak demand of retail customers at an average annual rate of approximately 3.6% during the same period. In 1995, based on non-coincident peak demand, the Company's reserve margin was 13% compared with 9% in the prior year due to the addition of the SCE/TEP power exchange to the Company's available resources. (See SCE/TEP Power Exchange Agreement below.) The Company seeks to maintain a reserve margin equal to its largest single hazard plus 5% of its non-coincident peak demand in accordance with guidelines established by the WSCC. The targeted reserve requirement was 296 MW in 1995 or 16% of non-coincident peak demand. The Company's operations were not adversely affected by the Company's failure to maintain its targeted reserve requirement in 1995. It is expected that near- term growth in demand will be met with existing resources and additional resources as discussed in Future Generating Resources below. Also, see Generating Resources below for a discussion of the Company's electric generating resources. The growth in the number of retail customers remained strong in 1995, increasing by 2.9% compared to the five-year annual average of 2.4%. The annual growth rate in the number of customers is expected to be approximately 2.2% through the year 2000. Retail peak demand is expected to grow at an average annual rate of 2.1% during the same period. The average annual rate of growth of energy sales to retail customers is anticipated to be in the 2.3% range for the remainder of the decade. On average, residential, non-mining industrial, and mining energy sales are expected to account for 34%, 28%, and 17%, respectively, of the projected sales for the remainder of the decade. The Company has two principal mining customers. In 1995, the sales to these customers totaled approximately 16.6% of the Company's total retail energy sales, and their contract demands totaled approximately 11% of the 1995 retail peak demand. The total coincident peak load for the Company's two mining customers was 6.9% of the coincident peak demand. Revenues from sales to mining customers have accounted for an average of approximately 10% of the Company's retail revenues in each of the three years from 1993 to 1995. The Company serves its two principal mining customers under reduced rate contracts designed to induce them to continue to purchase electricity from the Company rather than self-generate. These contracts expire after the year 2000. However, such contracts contain various provisions allowing the customers to terminate partially or entirely, under certain circumstances, provided that the Company is notified at least one and up to two years prior to such termination. The ability to extend contracts and to avoid early termination will depend on market conditions and available alternatives. Future markets and prices for fuel, access to capital, as well as ACC decisions regarding rate design, and the timing of rate decisions will affect the economics of self-generation projects (including cogeneration) and may ultimately affect whether customers, such as the mining customers described above, might reduce or terminate their contract demands on the Company's system (see Competition below). SALES FOR RESALE The Company makes sales for resale to others on both a firm and an interruptible basis. To the extent capacity is not providing energy to the Company's retail customers, such as during off-peak periods, the Company markets this capacity and energy at wholesale. Surplus energy is sold from time to time under various power pooling arrangements. The Company currently has contracts to sell firm capacity as follows: Minimum Contract Company Demand MW Contract Term ------- --------- ------------- SRP 100 June 1, 1991 - May 31, 2011 NTUA (1) 45 June 1, 1993 - May 31, 1999 TNP 30 January 1, 1996 - December 31, 1996 (1) The agreement with NTUA provides for a minimum contract demand of 45 MW and requires NTUA to obtain all of its electric power requirements from the Company. NTUA is a winter peaking utility and their coincident peak demand is expected to reach approximately 70 MW during the term of this contract. The Company continues to actively market long-term and short-term sales of excess capacity and energy. Competition to sell capacity is expected to remain vigorous in the next few years as a result of surplus capacity in the Southwestern United States and depressed prices in the spot market due to the abundance of low-cost hydroelectric power in the Western United States. Regarding the contracts described above, the Company cannot currently make any predictions about the replacement or extension of such contracts in the future. However, the Company has been notified that TNP will not renew its current contract with the Company in 1997. COMPETITION See Item 7. -- Management's Discussion and Analysis of Financial Condition and Results of Operations, Competition, for a discussion of developments regarding competition in the industry at the wholesale as well as at the retail level. GENERATING AND OTHER RESOURCES COMPANY RESOURCES The total net generating capability currently owned or leased by the Company at December 31, 1995 was 1,952 MW as set forth in the table below:
Net Capa- Unit Fuel bility Operating Company Share Generating Source No. Location Type MW Agent % MW - ----------------- ---- -------- ---- ------ --------- -------------- Springerville Station 1 Springerville, AZ Coal 360 TEP 100.0 360 Springerville Station 2 Springerville, AZ Coal 360 TEP 100.0 360 San Juan Station 1 Farmington, NM Coal 316 PNM 50.0 158 San Juan Station 2 Farmington, NM Coal 312 PNM 50.0 156 Navajo Station 1 Page, AZ Coal 750 SRP 7.5 56 Navajo Station 2 Page, AZ Coal 750 SRP 7.5 56 Navajo Station 3 Page, AZ Coal 750 SRP 7.5 56 Four Corners Station 4 Farmington, NM Coal 784 APS 7.0 55 Four Corners Station 5 Farmington, NM Coal 784 APS 7.0 55 Irvington Station 1 Tucson, AZ Gas/Oil 81 TEP 100.0 81 Irvington Station 2 Tucson, AZ Gas/Oil 81 TEP 100.0 81 Irvington Station 3 Tucson, AZ Gas/Oil 104 TEP 100.0 104 Irvington Station 4 Tucson, AZ Coal/Gas/Oil 156 TEP 100.0 156 Internal Combustion Turbines Tucson, AZ Gas/Oil 218 TEP 100.0 218 Total Company Capacity(1) 1,952
(1) Excludes 133 MW of additional resources, which consists of certain other capacity purchases and interruptible retail load. Total Company-owned capacity is 1,339 MW and Company-leased capacity is 613 MW. Internal combustion turbines with 100 MW of capacity are leased by the Company. At the end of such lease in 1998, the Company may exercise fair market value purchase and renewal options. SPRINGERVILLE STATION Springerville Station consists of two 360 MW coal fired units. Springerville Unit 1 began commercial operation in 1985 and is currently leased and operated by the Company. Springerville Unit 2 commenced commercial operation in June 1990 and is owned by San Carlos and operated by the Company. The primary terms of the Springerville Unit 1 Leases expire on January 1, 2015. At December 31, 1995, the capitalized lease asset related to Springerville Unit 1, net of allowance and accumulated amortization, was $257 million. At the end of the primary term, the Company may exercise fair market value purchase and renewal options. Annual lease payments for the Springerville Unit 1 Leases will range from $33 million to $176 million, averaging approximately $76 million. The average cash cost to the Company of Springerville Unit 1 capacity attributable to rent obligations and other operation and maintenance expenses after December 15, 1992, is estimated to be approximately $18 per kW per month (approximately $78 million per year), for the period from January 1993 through December 1997 and is expected to increase thereafter. However, due to timing differences between cash and accrued expenses, capacity costs attributable to rent obligations and other operation and maintenance expenses will be accrued in the Company's financial statements over the 1993 - 1997 period at an average of approximately $22 per kW per month (approximately $95 million per year) before amortization of the regulatory disallowance and interest expense thereon. The 1991 Rate Order allows the Company to recover the cost of the entire 360 MW capacity of Springerville Unit 1, but limits such recovery to a rate of $15 per kW per month (approximately $65 million per year). Substantially all of the present value of disallowed Springerville Unit 1 costs was recorded as a loss in 1990, and as a result of the Financial Restructuring, an additional loss was recorded in 1992. The losses together reflect the present value of the difference between projected costs and the amount the Company is allowed to recover through the lease term ending January 1, 2015. See Note 1 of Notes to Consolidated Financial Statements, Nature of Operations and Summary of Significant Accounting Policies, Springerville Unit 1 Allowance. In December 1985, pursuant to the Springerville Common Facilities Leases, the Company sold and leased back its 50% interest in the common facilities at Springerville. The sales price of such facilities was $132 million. At December 31, 1995, the capitalized lease asset related to Springerville common facilities, net of accumulated amortization, was $124 million. The initial lease term for the common facilities expires in 2017 for one owner participant and 2021 for the other two owner participants, subject to optional renewal periods and purchase options. Annual lease payments for the common facilities vary with changes in the interest rate on the underlying debt. Such lease payments totaled $12 million in both 1994 and 1995, and totaled $7 million in 1993. Based on current interest rates, annual lease payments would average approximately $13 million. Including the cost of leased common facilities (but excluding the cost of coal-handling facilities at Springerville which are included in recoverable fuel costs), the total initial cost of Springerville Unit 2 was $838 million, or $2,328 per kW. Approximately 26% of such cost is attributable to AFDC accrued prior to July 1, 1989. In the 1991 Rate Order, the ACC disallowed recovery from retail customers of $175 million of the book value of Springerville Unit 2. The Company recorded a loss for such disallowance in 1991. The net recoverable cost, including the leased common facilities, is $1,842 per kW. See Rates and Regulation, 1994 Rate Order and Note 2 of Notes to Consolidated Financial Statements, 1994 Rate Order. IRVINGTON STATION In January 1988, the Company began coal-fired commercial operation and entered into a sale and leaseback arrangement for Irvington Unit 4 pursuant to the Irvington Lease. The unit was sold at its cost of $152 million. At December 31, 1995, the capitalized lease asset related to Irvington Unit 4, net of accumulated amortization, was $123 million. This lease calls for annual payments which will range from approximately $9 million to $28 million and which average approximately $13 million. The lease term expires in 2011, but the lease provisions have optional renewal periods and purchase options. With the addition of coal firing capability, Irvington Unit 4 (156 MW capability) has the flexibility to operate on coal, gas or fuel oil. Coal has been the primary fuel and natural gas the secondary fuel. SCE/TEP POWER EXCHANGE AGREEMENT As part of a 1992 litigation settlement, the Company and SCE agreed to a ten-year power exchange agreement. Under the agreement, which began in May 1995, SCE provides firm system capacity of 110 MW to the Company during summer months, for which the Company pays an annual capacity charge of approximately $1 million increasing annually after the first five years to a maximum of approximately $2 million annually. The Company is entitled to schedule firm energy deliveries from SCE during the summer (May 15 through September 15) of up to 36,300 MWh per month, and is obligated to return to SCE on an interruptible basis the same amount of energy the following winter season (November 1 through February 28). The energy provided pursuant to the exchange is expensed based upon the cost of interruptible energy provided to SCE. The Company believes the agreement may reduce the Company's overall system fuel costs, allow it to sell additional capacity on the wholesale market, and/or permit it to defer the construction of future generating resources. The 1994 Rate Order directed the Company to propose an allocation of the benefits of this agreement with its retail customers. The Company included such an allocation proposal in its 1995 rate application and in the Proposed Settlement Agreement. See Rates and Regulation, 1995 Rate Application. In 1995, pursuant to the exchange agreement, the Company received 91,000 MWh, and as of the end of January 1996, the Company had provided 72,255 MWh SCE. FUTURE GENERATING RESOURCES In December 1995, the Company filed an integrated resource plan pursuant to the ACC's regulations governing resource planning. In its filing the Company projected the need for an additional 128 MW of peaking resources in 1998 and additional peaking resources in the year 2002 and beyond. No need for additional base load generation facilities was forecast through the year 2010. The Company has begun a program to determine whether the 1998 peaking resource should be constructed by the Company or purchased. In addition, the Company projected that demand-side management programs should reduce peak demand and, therefore, capacity requirements, from what they would be without such programs by 60 MW by the year 2000. As part of the integrated resource plan, the Company has committed to adding 5 MW of renewable generation resources by the year 2000. OTHER PURCHASES In addition to generating electricity at generating stations owned or leased by the Company and the SCE/TEP Power Exchange , the Company participates in a number of interchange agreements through which it can purchase additional electric energy from other utilities. The amount of energy purchased from other utilities varies substantially from time to time depending on both the cost of purchased energy as compared to the Company's cost of generating energy and the availability of such energy. Through these same agreements, the Company may also sell its surplus electric energy from time to time. The Company has transmission access to and/or power transaction arrangements with over 130 electric systems or suppliers, including those in the southern California markets. The Company is a member of the Inland Power Pool, which is comprised of a group of utilities serving customers in portions of the western United States. The Inland Power Pool membership facilitates interchange with companies having system peak periods different from those of the Company. The Company is also a member of the WSCC, a group of western electric systems and suppliers that works cooperatively to assure the reliability of the region's interconnected generation and transmission systems. In 1990, the Company joined the Western Systems Power Pool which is a voluntary power pooling experiment to achieve more efficient use of electric generation and transmission facilities among its members. See Competition for a discussion of possible changes in transmission issues. RATES AND REGULATION GENERAL The Company is subject to the jurisdiction of the ACC, which has authority, among other things, to prescribe the classifications of accounts to be used and the rates and charges to be made and collected from retail customers, and to regulate the issuance of securities. The ACC also has authority to approve affiliate transactions and the establishment of holding companies and subsidiaries under ACC promulgated Affiliated Interest Rules. The Company is also subject to regulation by FERC in certain respects, including the terms and prices of sales to other utilities. Arizona law requires that the Company's rates for retail sales of electric energy be determined by the ACC on a "cost of service" basis and be designed to provide, after recovery of allowable operating expenses, an opportunity to earn a reasonable rate of return on "fair value rate base". Fair value rate base is, generally, determined by the ACC by reference to the original cost and the reproduction cost (in each case, net of depreciation) of utility plant in service to the extent deemed used and useful, and to various adjustments for deferred taxes and other items, plus a working capital component. Thus, over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirements of utility plant from service. Both operating expenses and fair value rate base determination are subject to judgment by the ACC regarding prudency and recoverability. The Company's rates for wholesale sales of capacity and energy, generally, are not permitted by FERC to exceed rates determined on a cost of service basis. With respect to long-term firm sales, the Company's wholesale rates are substantially below rates determined on a fully allocated cost of service basis, but, in all instances, rates exceed the level necessary to recover fuel and other variable costs. The ACC consists of three commissioners, each serving a six-year term. One of the three is elected at each general election except when a vacancy occurs prior to the expiration of a commissioner's term. The present commissioners are: - - Renz D. Jennings (Democrat), Chairman, was elected to a third term in 1992. His term expires in 1999. - - Marcia Weeks (Democrat) was elected to a second term in 1990. Her term expires in 1997. - - Carl Kunasek (Republican) was elected to a first term in 1994. His term expires in 2001. Under a 1992 Arizona law, commissioners cannot serve consecutive terms and can be elected to another term only after the passing of six years after the end of their previous term as commissioners. 1995 RATE APPLICATION On June 13, 1995, the Company filed an application with the ACC requesting an overall 4.9% increase in retail rates (approximately $28.4 million in annual revenues). The Company's request was based on original cost rate base of approximately $1.17 billion, a rate of return on original cost rate base of 8.2%, a rate of return on common equity of 11.5%, and a 1994 test period. The proposed rate structure was a continuation of the Company's effort to insure that retail customer classes pay their appropriate allocated share of the cost of providing service. The Company proposed increases of 7.5% for residential customers, 3.6% for commercial customers, and 5.0% for industrial customers. The proposed increase would result in an increase of $5.37 in the average monthly residential bill, from $70.92 (9.46 cents per kWh) to $76.29 (10.17 cents per kWh) for residential customers using an average 750 kilowatt- hours per month. The application requested recovery of the costs associated with the remaining 37.5% (135 MW) of Springerville Unit 2 that is "used and useful" in accordance with ACC methodologies. Currently, the Company is only allowed to recover 62.5% of the costs related to Springerville Unit 2. In 1994, the Company's system peak demand was 139 MW over the demand upon which current rates are based. Total proposed additions to rate base due to the inclusion of the remaining 37.5% of Springerville Unit 2, including related deferrals of previously incurred costs, amounted to approximately $191 million. The Company's request contained elements of traditional cost of service/rate of return ratemaking as well as several proposals designed to increase the Company's competitiveness. Such proposals included, among others, the flexibility to enter into special contracts with customers without specific ACC approval at prices below previously approved tariff levels; allocation of the savings resulting from improved operating efficiencies between the Company and its customers; allocation of the benefits of the 110 MW added generating capacity related to the SCE/TEP Power Exchange solely to the retail customers; and allocation of new long-term wholesale sales based on marginal costs of a wholesale transaction rather than the Company's average costs. The Company further proposed that, if the ACC approved the Company's request and proposals as filed, the Company would not file another rate case until the year 2000, absent any emergencies. On November 30, 1995, the Company reached an agreement with the ACC Staff proposing to resolve the Company's application for a rate increase, and the Company's notice of intent to form a holding company. The Proposed Settlement Agreement was subject to final approval by the full ACC following a hearing which started on January 17, 1996. At the conclusion of such hearings, on January 19, 1996, the ACC denied the Proposed Settlement Agreement by a 2 to 1 vote. On January 24, 1996, the Company filed a motion for reconsideration with the ACC. On February 13, 1996, the motion for reconsideration was deemed denied by operation of law. Although the Company's application for a rate increase remains pending, the Company intends to propose and seek approval of a revised settlement agreement in March 1996. The Proposed Settlement Agreement called for a one-time base rate increase of 1.8%, or $8.4 million annually. Also, the Company agreed not to seek another increase in base rates before January 1, 2000. The agreement also would have permitted the Company to invest up to $50 million annually in energy-related businesses. Although the agreement would not have approved the holding company structure, it did provide that the Company could re-file for authority to establish a holding company in 18 months from the approval of the Proposed Settlement Agreement. See Notice of Intent to Form a Holding Company below for a description of further action taken by the ACC with respect to the formation of a holding company. NOTICE OF INTENT TO FORM A HOLDING COMPANY In February 1995, the Company filed a Notice of Intent to Form a Holding Company with the ACC. In June 1995, the ACC Staff filed testimony recommending that the ACC deny the Company's request on the basis that retail customers would be exposed to certain risks resulting from diversification. However, ACC Staff recommended that, in the event that the ACC approves formation of the holding company, the ACC impose various operating and financial conditions on the Company and the holding company. In concurrently filed testimony, RUCO, an intervenor in the matter, did not oppose the formation of the holding company. The Company filed rebuttal testimony on July 27, 1995, and a public hearing was held on August 22, 1995. In November 1995, the Company and the ACC Staff entered into the Proposed Settlement Agreement which included a proposal to resolve the Company's holding company application. On January 19, 1996, the Proposed Settlement Agreement was denied (see 1995 Rate Application above). Following the denial of the Proposed Settlement Agreement, the ACC Hearing Officer submitted a recommended order on the holding company proposal. On February 22, 1996, the ACC denied the formation of a holding company. However, the ACC granted the Company a waiver for the authority to invest in subsidiaries that will engage in energy related projects in an amount equal to the lesser of $25 million or the maximum amount allowed by the MRA. To the extent that the Company obtains retroactive approval or waiver of projects from the ACC, the energy related diversification amount will be reinstated up to the $25 million limit. This investment authority is subject to the conditions that (i) the total waiver amount shall not exceed $50 million annually, (ii) 60% of net profits from diversified activities be applied to repay the Company's debt and (iii) total investment in such diversified activities does not exceed 15% of the Company's capitalization. 1994 RATE ORDER On January 11, 1994, the ACC issued a decision approving a 4.2% retail rate increase for the Company. The new rates were effective as of January 11, 1994. According to the 1994 Rate Order, the new rates were intended to produce an annual increase in gross revenues of approximately $21.6 million based upon a test year ended June 30, 1992. This reflects an allowed original cost rate base of approximately $1.0 billion and a return on original cost rate base (after write-offs) of 8.51% based upon a rate of return on common equity of 11%. The Company requested in its January 1993 filing a $49 million increase in gross revenues based on an original cost rate base of approximately $1.1 billion and a rate of return base of 9.17% based upon 12.5% return on equity. In determining the required return on rate base, the 1994 Rate Order utilized a hypothetical capital structure of 49.8% long-term debt, 44.1% common equity, 4.7% preferred equity and 1.4% short-term debt as contemplated under a 1991 rate settlement agreement. The decision authorized the inclusion of an additional 17.5% of Springerville Unit 2 in rate base, for a total of 62.5%. The 1994 Rate Order also allowed inclusion of 62.5% of the Springerville Unit 2 rate synchronization and excess capacity deferred expenses in rate base. Amortization of those rate synchronization deferred expenses allowed in rate base was authorized to be recovered from retail customers over a three-year period. However, amortization of the excess capacity deferred expenses allowed in rate base was authorized to be recovered from retail customers over 37.4 years. The 37.5% of the rate synchronization and excess capacity expenses not currently being recovered continue to accrue at a 7.19% interest carrying charge. See Note 2 of Notes to Consolidated Financial Statements, Rate Matters, 1994 Rate Order. OTHER RATE MATTERS See Utility Operations, Peak Demand and Customers for a discussion of the Company's contracts and negotiations with certain of its mining customers. FUEL SUPPLY GENERAL The Company's principal fuel for electric generation is low-sulfur coal. The following table provides fuel cost information for the years 1995 through 1991: Cost Per Million BTU Consumed Percentage of Total BTU Consumed ----------------------------- -------------------------------- 1995 1994 1993 1992 1991 1995 1994 1993 1992 1991 ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- Coal (A) $1.89 $2.06 $2.01 $1.89 $2.04 99% 98% 99% 99% 99% Gas 1.69 1.86 2.76 2.39 2.14 1 2 1 1 1 --- --- --- --- --- All Fuels 1.89 2.05 2.02 1.90 2.05 100% 100% 100% 100% 100% ==== ==== ==== ==== ====
(A)The average cost per ton of coal for each of the last five years (1995 - 1991) was $35.53, $38.93, $37.60, $36.46 and $39.55, respectively. COAL The Company is the operator for the Springerville and Irvington generating stations. Their coal supplies are transported from northwestern New Mexico by railroad. The coal contract for Springerville is for the remaining lives of Units 1 and 2 with a bilateral option to renegotiate the contract price and escalation procedures in 2009 and every five years thereafter. At Irvington, the contract termination date is the earlier of 2015 or the remaining life of Unit 4. The Springerville and Irvington contracts have various adjustment clauses which will affect the future cost of coal delivered. Coal reserves are expected to be sufficient to supply the estimated requirements of Springerville and Irvington for their presently estimated remaining lives. TEP is a participant in the San Juan Generation Station and shares a 50/50 responsibility split of the coal agreement. The coal quantities for the San Juan Station, a mine mouth operation, are partially contracted through the year 2017. The Company also participates in jointly owned generating facilities under long-term contracts entered into by the operating agents. Coal supplies are surface-mined in northern Arizona and northwestern New Mexico. The coal quantities under contract for Four Corners terminate in 2005. The coal quantities under contract for the Navajo mine-mouth coal fired generating station are expected to be sufficient to supply the estimated requirements for its presently estimated remaining life. Additional information concerning the coal contracts is set forth on the following page:
Year Average Cost Per Contract Sulfur Million BTU(A) Station Coal Supplier Terminates Content 1995 1994 1993 Coal Obtained From(B) - ------- ------------- ----------- ------- ---- ---- ---- --------------------- Four Corners BHP Utah International, Inc. 2005 0.8% $1.15 $1.28 $1.15 Navajo Indian Tribe San Juan San Juan Coal Company 2017 0.8% $1.76 $1.81 $1.89 Federal and State Agencies Navajo Peabody Coal Company 2011 0.6% $1.12 $1.09 $1.11 Navajo and Hopi Indian Tribes Springerville Hanson Natural Resources Company (C) 0.7% $2.20(D) $2.47(D) $2.33(D) Lee Ranch Coal Company Irvington The Pittsburg & Midway Coal Mining Company 2015 0.4% $2.20 $2.21 $2.50 Navajo Indian Tribe and Federal and State Agencies
(A) Includes costs of transportation and handling in addition to the purchase price under the basic contract. (B) Substantially all of the suppliers' leases extend at least as long as coal is being mined in economic quantities. (C) The coal contract for Springerville is for the remaining lives of Units 1 and 2 with a bilateral option to renegotiate the contract price and escalation procedures in 2009. (D) The Springerville costs include costs associated with Valencia operations, including the costs of the Valencia Leases. Such costs were 65 cents, 60 cents, and 56 cents for 1995, 1994 and 1993, respectively. Valencia is responsible for the handling of fuel for the Springerville Station. Also, in July 1992 the San Juan coal supply agreement was amended to, among other things, reduce operations and maintenance pass-through costs by 10%, reduce ash handling costs and also to provide price reduction incentives for coal purchased above certain minimum quantities. Such amendment provides yearly savings to the Company of approximately 6%, or $1.4 million. On September 1, 1995, the San Juan agreement was amended to allow the mines the flexibility of mining more economical leases. The reductions will be passed on to TEP in the form of lower unit costs. The Company intends to continue to actively negotiate its fuel and transportation contracts in 1996 and in the future. VALENCIA Valencia is responsible for the acquisition, transportation and handling of fuel for Springerville. Pursuant to a fuel burn agreement with the Company, Valencia has the exclusive right and obligation to provide all of the fuel requirements for Springerville. Pursuant to the Valencia Leases, Valencia is the lessee of the coal- handling facilities at Springerville under a capital lease with a remaining initial lease term of approximately 20 years with incremental extensions of five to six years depending on certain criteria at the date of each extension. At December 31, 1995, the capitalized lease asset related to Valencia coal-handling facilities, net of accumulated amortization, was $181 million. Annual rental payments range from approximately $10 million to $28 million but average $21 million. Rental payments and other obligations of Valencia under the leases are guaranteed by the Company. Valencia allocates portions of its costs to deferred expense for future recovery through sales of fuel. See Note 1 of Notes to Consolidated Financial Statements, Nature of Operations and Summary of Significant Accounting Policies, for a description of the accounting for Valencia lease costs. GAS In 1995, the Company purchased a small amount of natural gas for power generation (less than 2% of total Company generation) from Southwest Gas, Chevron, Natural Gas Clearinghouse, Mobil and USGT. During 1995, the Company received natural gas sufficient to meet all of its gas fuel requirements. WATER SUPPLY Arrangements have been made for water sufficient to supply the requirements of existing and planned units of all electric generating stations in which the Company has an interest for their estimated lives. ENVIRONMENTAL MATTERS GENERAL The Company must operate its generating stations in accordance with numerous local, state and federal guidelines, laws, regulations and ordinances designed to preserve and enhance environmental integrity. Resource extraction and waste disposal operations are also regulated for environmental compatibility. Generally, air quality and water quality are under the most stringent regulations. Land use is also regulated. Various federal, state and local laws, regulations and requirements for air quality control continue to have a significant impact on the Company. Due to the proximity of national parks, monuments, wilderness areas and Indian reservations and relatively high air quality at such locations, the principal generating units of the Company are subject to control standards of best available control technology (BACT) and best available retrofit technology (BART). Such standards relate to the "prevention of significant deterioration" of visibility and tall stack limitation rules. Certain other generating units of the Company are located in areas which have been designated by federal and state agencies as "non-attainment" areas (where federal ambient air quality standards are not achieved). This designation requires such generating units to comply with "lowest achievable emission rate" or "reasonably available control technology" standards or "offset" requirements. New Mexico has adopted emission regulations restricting the emissions from both existing and future coal, oil and gas-fired plants located in New Mexico. Regulations adopted by the New Mexico Environmental Improvement Board (NMEIB) are in some instances more stringent than those adopted by the EPA. The NMEIB has adopted regulations, which apply to all units at the San Juan and Four Corners generating stations, that prohibit emissions of sulfur dioxide, particulates, and nitrogen oxide above certain levels. The Company expended $11 million during 1995 for environmental construction costs in maintaining compliance with environmental requirements. The Company estimates that it will make expenditures for environmental facilities of approximately $12 million in 1996 and $9 million in 1997. These amounts include the Company's estimated share of initial expenditures for improvements to the pollution control facilities at the Navajo station which are associated with the final rule issued by EPA on October 3, 1991, regarding visibility impairment in Grand Canyon National Park (see Navajo Generating Station below for information regarding the projected total cost of such facilities). The Company believes that all existing generating facilities are or will be in compliance with all existing or expected environmental regulations except as described below. In the fall of 1990, Congress adopted certain Federal Clean Air Act Amendments (CAAA) with respect to reductions in sulfur dioxide and nitrogen oxide emissions which will affect the Company's operation. The nitrogen oxide reductions will be based upon EPA regulations finalized in 1995 for certain boilers and expected to be finalized by 1997 for all remaining boilers. In addition, the rules promulgated in 1995 may be revised in 1997. The required reductions of sulfur dioxide emissions will be implemented in two phases which are effective in 1995 and 2000, respectively. The Company is not affected by the requirements for sulfur dioxide emissions and nitrogen oxide reductions which went into effect in 1995 (Phase I), but is subject to the requirements that go into effect January 1, 2000 (Phase II). In Phase II, the maximum sulfur dioxide emission rates are set at 1.2 pounds per million BTU. Because of the Company's general use of low-sulfur coal and installed scrubbers at certain units, the Company's coal-fired generating stations already meet the sulfur dioxide emission rate requirements for Phase II. Additionally, further reductions are to be met through a market- based system. Affected Company generating units will be allocated Emission Allowances based on required emission reductions and past use. Generating station units must hold Emission Allowances equal to their level of emissions or face penalties and a requirement to offset excess tons in future years. In 1993, the EPA allocated Emission Allowances for all Phase I and Phase II affected utility units. An analysis of the Emission Allowances that were allocated to the Company shows that the Company would have sufficient allowances to permit normal plant operation and be in compliance with the sulfur dioxide regulations once the Phase II requirements become effective. However, until all the rulemaking regulation processes for implementing the CAAA are completed, the Company is unable to predict the specific impacts of all such amendments. The CAAA also introduced the concept of an organized market for the trading of Emission Allowances. This market would have allowed utilities to buy and sell the right to emit sulfur dioxide and served as the mechanism to enforce compliance with the new standards promulgated under the CAAA. The CAAA also required the EPA to hold or sponsor an auction for Emission Allowances within the first three months of each year. The first of such auction was held in March 1993, following the allocation of Emission Allowances to Utilities in January 1993. Title V of the CAAA established a new air quality permitting system that will be administered in Arizona by the ADEQ. Electric utilities in the state were required to submit applications for Title V permits by February 1, 1995. Processing and issuance of such permits is expected to take at least 18 months. Until a Title V permit is issued, permits that expire during that period will either be honored or will be reissued by ADEQ with additional requirements reflecting Title V regulations. The CAAA also require multi-year studies of visibility impairment in specified areas and studies of hazardous air pollutants which relate to the necessity of future regulations of electric utility generating units. Since these activities involve the gathering of information not currently available, the Company cannot predict the outcome of these studies. As a result of recent and possible future changes in federal and state environmental laws, regulations and permit requirements, the Company may incur additional costs for the purchase or upgrading of pollution control emission monitoring equipment on existing electric generating facilities and may experience a reduction in operating efficiency. There may be a need for variances from certain environmental standards and operating permit conditions until required equipment and processes for control, handling and disposal of emissions are operational and reliable. Failure to comply with any EPA or state compliance requirements may result in substantial penalties or fines which are provided for by law and which in some cases are mandatory. FOUR CORNERS GENERATING STATION The Company believes that all units at Four Corners are presently operating in compliance with federal and state regulations. IRVINGTON GENERATING STATION The Company's ADEQ operating permit for Irvington Unit 4 expired on February 8, 1996. By law, the permit remains in effect until ADEQ issues a new facility-wide Title V permit in 1996. The other facilities at the Irvington station were under the jurisdiction of the PDEQ until 1993. However, because of 1990 CAAA requirements which require the facility to obtain a Title V permit, the entire facility was placed under the jurisdiction of ADEQ in April 1994. The Company timely filed a Title V permit application for the Irvington facility on February 1, 1995, thus providing the facility with a permit application shield. Each major source requiring a Title V permit must pay an annual emission-based fee. The fee in 1996 for emissions at the Irvington facility was assessed at $191,000 and is expected to range between $150,000 to $250,000 for 1997. NAVAJO GENERATING STATION In 1991, the EPA adopted a rule for the reduction of Navajo's sulfur dioxide emissions on an annual averaging basis by 90% to address visibility impairment at Grand Canyon National Park. The Company estimates that its share of the required capital expenditures remaining as of December 31, 1995 relating to the rule's implementation will be approximately $31 million, including AFDC, through 1999. SAN JUAN GENERATING STATION The Company believes that all units at San Juan are presently operating in compliance with federal and state regulations. SPRINGERVILLE GENERATING STATION Springerville Units 1 and 2 meet all existing federal and state regulations pertaining to environmental quality. Springerville Units 1 and 2 are operating under an operating permit issued by ADEQ on December 19, 1994, which expires on December 19, 1999. Springerville Generating Station is a major source requiring a Title V permit, and the Company filed a Title V permit application for the Springerville facility on February 1, 1995. As a result of requirements imposed by the CAAA of 1990, each major source requiring a Title V permit must pay an annual emission-based fee. The fee in 1996 for emissions at the Springerville Generating Station Units 1 and 2 was assessed at $328,000 and is expected to be approximately the same for 1997. EMPLOYEES The Company and the IBEW 1116, which represents about 63% of the 1,366 employees of the Company and its subsidiaries at December 31, 1995, are parties to a two-year collective bargaining agreement for the period from December 1, 1994 through November 30, 1996. The collective bargaining agreement, which was negotiated with and approved by the IBEW 1116 in November 1994, includes annual wage increases of 3.6% and 4.0% in 1995 and 1996, respectively, and modifications to the pension, health and supplemental retirement plans. The Company expects to begin negotiations to extend and modify the collective bargaining agreement after June 1996. DISCONTINUED INVESTMENT SUBSIDIARY OPERATIONS The Company directly owns two non-energy related investment subsidiaries, TRI and SRI. TRI and SRI each wholly own several subsidiaries both directly and indirectly. In July 1990, each of the Board of Directors of TRI and SRI adopted resolutions for the liquidation of substantially all of the assets of these subsidiaries. As a consequence, the investment subsidiaries were reclassified as discontinued operations for financial statement purposes through 1994. During 1994, the investment subsidiaries sold all of their remaining interests in cogeneration and independent power projects, as well as the hotels located in Louisville, Kentucky and Woodland Hills, California, substantially completing the liquidation of the investment subsidiary assets. In January and February 1995, the remaining equity securities were sold. The Company intends to continue to liquidate the remaining assets. The Company received cash dividends from TRI of $50 million in 1994 and $13 million in March 1995. Since July 1990, a total of $110 million of cash dividends has been received by the Company from the investment subsidiaries. UTILITY OPERATING STATISTICS
For Years Ended December 31, 1995 1994 1993 1992 1991 - -------------------------------------------------------------------------------------------------------- Generation and Purchased Power-kWh (000) Remote Generation (Coal) 8,716,513 9,341,342 8,986,350 6,148,825 5,518,543 Local Generation (Oil, Gas & Coal) 500,958 825,385 615,100 527,405 314,441 Purchased Power 692,769 501,269 335,897 2,436,152 2,736,620 --------- ---------- --------- --------- --------- Total Generation and Purchased Power 9,910,240 10,667,996 9,937,347 9,112,382 8,569,604 Less Losses and Company Use 661,901 639,278 591,412 610,040 585,964 --------- ---------- --------- --------- --------- Total Energy Sold 9,248,339 10,028,718 9,345,935 8,502,342 7,983,640 ========= ========== ========= ========= ========= Sales-kWh (000) Residential 2,330,191 2,374,868 2,223,479 2,146,268 2,081,476 Commercial 1,280,752 1,281,050 1,242,367 1,215,179 1,182,599 Large Users 1,979,317 1,948,331 1,832,278 1,771,937 1,756,887 Mining 1,147,281 1,135,424 1,090,061 1,081,791 951,646 Public Authorities 204,746 183,525 159,310 165,922 164,380 --------- ---------- --------- --------- --------- Total-Retail Customers 6,942,287 6,923,198 6,547,495 6,381,097 6,136,988 Sales to Other Utilities 2,306,052 3,105,520 2,798,440 2,121,245 1,846,652 --------- ---------- --------- --------- --------- Total 9,248,339 10,028,718 9,345,935 8,502,342 7,983,640 ========= ========== ========= ========= ========= Operating Revenues (000) Residential $218,208 $220,341 $197,368 $190,089 $174,054 Commercial 138,294 137,508 128,688 125,655 114,826 Large Users 146,409 144,677 131,858 127,456 121,269 Mining 54,948 53,821 53,510 57,266 49,996 Public Authorities 14,952 13,435 11,464 11,757 11,273 Other 2,114 1,651 1,925 1,791 1,583 -------- -------- -------- -------- -------- Total-Retail Customers 574,925 571,433 524,813 514,014 473,001 Amortization of MSR Option Gain Regulatory Liability 20,053 20,053 6,053 6,053 16,553 Sales to Other Utilities 75,591 99,987 93,273 70,026 65,441 -------- -------- -------- -------- -------- Total $670,569 $691,473 $624,139 $590,093 $554,995 ======== ======== ======== ======== ======== Customers (End of Period) Residential 273,976 266,060 258,168 251,656 246,538 Commercial 27,858 27,360 26,838 26,441 26,144 Large Users 620 588 551 527 531 Mining 4 4 4 4 4 Public Authorities 59 59 59 59 59 ------- ------- ------- ------- ------- Total Retail Customers 302,517 294,071 285,620 278,687 273,276 ======= ======= ======= ======= ======= Average Revenue per kWh Sold (cents) Residential 9.4 9.3 8.9 8.9 8.4 Commercial 10.8 10.7 10.4 10.3 9.7 Large Users and Mining 6.4 6.4 6.3 6.5 6.3 Total - Retail Customers 8.3 8.3 8.0 8.1 7.7 Average Revenue per Residential Customer $809 $841 $776 $765 $714 Average kWh Sales per Residential Customer 8,641 9,066 8,739 8,632 8,534
ITEM 2. -- PROPERTIES The Company's transmission facilities are located within the states of Arizona and New Mexico. The primary purpose of the Company's transmission facilities is to transmit electricity from the Company's remote electric generating stations at Four Corners, Navajo, San Juan and Springerville to the Tucson area for use by the Company's retail customers (see Item 1, Business, Generating and Other Resources for the location of the Company's plants). The transmission system is directly interconnected with systems operated by the following utilities: Utility Location ------- -------- Arizona Public Service Co. Arizona Arizona Electric Power Cooperative Arizona El Paso Electric Co. New Mexico, Texas Public Service Co. of New Mexico New Mexico Salt River Project Arizona The Company has arrangements with approximately 130 companies, including the five listed above, which are utilized to interchange capacity and energy. As of December 31, 1995, the Company owned or participated in an overhead electric transmission and distribution system consisting of 511 circuit-miles of 500 kV lines, 1,122 circuit-miles of 345 kV lines, 335 circuit-miles of 138 kV lines, 454 circuit-miles of 46 kV lines and 9,233 circuit-miles of lower voltage primary lines. The underground electric distribution system was comprised of 4,514 cable-miles. Approximately 24% of the poles upon which the lower voltage lines are located are not owned by the Company. Electric substation capacity associated with the above-described electric system consisted of 166 substations with a total installed transformer capacity of 5,258,355 kVA. The electric generating stations (except as noted below), the Company's general office building, operating headquarters and the warehouse and service center are located on land owned by the Company in fee. The electric distribution and transmission facilities owned by the Company are located (1) on property owned in fee by the Company, (2) under or over streets, alleys, highways and other public places, the public domain and national forests and state lands under franchises, easements or other rights which, with some exceptions, are subject to termination, (3) under or over private property by virtue of easements obtained for the most part from the record holder of title, and (4) under Indian reservations under grant of easement by the Secretary of Interior or lease by Indian tribes. In most instances, no examination has been made by counsel for the Company as to the title to easements of the Company from the record holder or to the property over which the easement has been granted, or as to possible liens, encumbrances, reservations or restrictions thereon. Therefore, some of the easements and the property over which the easements have been secured may be subject to title defects and encumbered by, or subject to, mortgages and liens existing at the time the easements were acquired. Most of the land parcels comprising Springerville are held by the Company under a long-term surface ownership agreement with the State of Arizona. The Company's 50% interest in the common facilities of Springerville and its 100% interest in Irvington Unit 4 and related common facilities were sold and are leased back by the Company. The coal-handling facilities at Springerville were sold and leased back by Valencia. The Company leases Springerville Unit 1 and the remaining 50% interest in the common facilities at Springerville. Four Corners and Navajo are located on properties held under easements from the United States and under leases from the Navajo Indian Tribe. The Company, individually and in conjunction with PNM in connection with San Juan, has acquired easements and leases for transmission lines and a water diversion facility located on the Navajo Indian Reservation. The Company has also acquired easements for transmission facilities, related to San Juan and Navajo, across the Zuni, Navajo and Tohono O'odham Indian Reservations. The Company's rights under the various easements and leases described under this heading may be subject to possible defects (including conflicting grants or encumbrances not ascertainable because of absence of or inadequacies in the recording laws or the record systems of the Bureau of Indian Affairs and the Indian tribes, the possible inability of the Company to resort to legal process to enforce its rights against certain possible adverse claimants and the Indian tribes without Congressional consent, the possible failure or inability of the Indian tribes to protect the Company's interests in, and use and occupancy of, these facilities from interference or interruption, and, in the case of the leases, possible impairment or termination under certain circumstances by Congress, the Secretary of the Interior or certain possible adverse claimants). However, these possible defects have not and are not expected to materially interfere with the Company's interest in and operation of its facilities. With the exception of Springerville Unit 2, substantially all of the utility assets of the Company are subject to the lien of the General First Mortgage and the General Second Mortgage. Legal title to Springerville Unit 2, which is not subject to such liens, is held by San Carlos. Springerville Unit 2 is subject to the Unit 2 First Mortgage. ITEM 3. -- LEGAL PROCEEDINGS SDGE/FERC PROCEEDINGS See SDGE/FERC Proceedings in Note 6 of Notes to Consolidated Financial Statements. TAX ASSESSMENTS See Tax Assessments in Note 6 of Notes to Consolidated Financial Statements. WATER RIGHTS ADJUDICATION On March 13, 1975, the State of New Mexico filed an action entitled State of New Mexico v. United States, et al., in the District Court of San Juan County, New Mexico, to adjudicate all water rights in the San Juan River Stream System. The action is expected to adjudicate certain water rights applicable to the water supply for San Juan and Four Corners. The Company was made a party to this action in June 1976 and an answer was filed on behalf of the Company and others in May 1978. For the past several years, the State of New Mexico Engineer's Office has reportedly been completing reports on hydrographic surveys performed in conjunction with the litigation. It is anticipated that once those reports are completed, offers of judgment will be issued to the Company and other parties. The Company is unable to predict the effect, if any, of any adjudication on its present arrangements for a water supply to these stations. However, pursuant to an agreement reached in 1985, the Navajo Tribe will provide sufficient water to Four Corners from its own allocation to offset any portion of the water rights affected by this proceeding. ITEM 4. -- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not Applicable. PART II ITEM 5. -- MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The following table sets forth, for the periods indicated, the high and low sale prices of the Company's Common Stock on the consolidated tape as reported by Dow Jones. No dividends were paid on Common Stock during such periods. Market Price per Quarter Share of Common Stock High Low 1995 First...... $3.75 $3.00 Second..... 3.50 3.00 Third...... 3.25 2.63 Fourth..... 3.25 2.88 1994 First..... $4.13 $3.38 Second..... 3.88 2.88 Third...... 3.75 2.88 Fourth..... 3.88 3.00 The closing price of the Common Stock on March 1, 1996 was $3.125. The Common Stock is traded on the New York Stock Exchange and the Pacific Stock Exchange. At March 1, 1996, there were 35,870 shareholders of record of the Common Stock. See Item 7., Management's Discussion and Analysis of Financial Condition and Results of Operations, Dividends on Common Stock. ITEM 6. - SELECTED CONSOLIDATED FINANCIAL DATA
1995 1994 1993 1992 1991 (In thousands - except per share data and ratios) Summary of Operations - ---------------------------------------------------------------------------------------------------------------- Operating Revenues $670,569 $691,473 $624,139 $590,093 $554,995 Regulatory Disallowances and Adjustments - - (13,777) - (239,232) Income Taxes-Net 20,436 4,911 5,277 5,745 6,638 Loss on Restructuring - - - (26,669) - Income (Loss) from: Continuing Operations 54,905 20,740 (21,816) (79,022) (421,493) Provision for Loss on Disposal of Discontinued Operations - - (4,000) (44,047) (36,000) Net Income (Loss) 54,905 20,740 (25,816) (123,069) (457,493) Net Income (Loss) for Common Stock 54,905 20,740 (25,816) (123,069) (465,339) Income (Loss) per Average Share of Common Stock from: Continuing Operations $0.34 $0.13 $(0.14) $(2.48) $(16.70) Provision for Loss on Disposal of Discontinued Operations - - (0.02) (1.38) (1.40) Total Net Income (Loss) per Average Share of Common Stock $0.34 $0.13 $(0.16) $(3.86) $(18.10) Shares of Common Stock Outstanding Average 160,691 160,724 160,544 31,872 25,716 End of Year 160,671 160,724 160,724 160,430 25,716 - ---------------------------------------------------------------------------------------------------------------- Financial Position - ---------------------------------------------------------------------------------------------------------------- Total Utility Plant - Net $1,978,126 $2,007,422 $2,029,764 $2,052,695 $1,351,729 Total Investments 52,116 12,992 62,850 98,126 203,712 Total Assets 2,530,930 2,699,593 2,711,753 2,656,089 2,004,336 Long-Term Debt - Net 1,207,460 1,381,935 1,416,352 1,466,555 500,060 Capital Lease Obligations 897,958 922,735 927,201 931,163 5,836 Preferred Stock - - - - 82,793 Common Stock Equity (Deficit) 12,488 (42,233) (62,973) (38,209) (191,903) Total Capitalization 2,117,906 2,262,437 2,280,580 2,359,509 396,786 Defaulted Long-Term Debt - Due on Demand - - - - 760,966 Defaulted Short-Term Debt - Due on Demand - - - - 219,800 Reserve for Litigation and Contract Disputes - - - 27,500 27,219 Total Capitalization and Other Liabilities 2,530,930 2,699,593 $2,711,753 $2,656,089 $2,004,336 - ---------------------------------------------------------------------------------------------------------------- Selected Cash Flow Data - ---------------------------------------------------------------------------------------------------------------- Cash Flow Interest Coverage (A) 2.5x 3.0x 2.3x 2.0x 3.2x Cash & Cash Equivalents/Current Liabilities (B) 0.48 1.29 0.91 1.06 N/M Construction Expenditures (including AFDC) $62,317 $64,479 $48,375 $30,207 $48,728 Cash Generated as a Percent of Construction Expenditures: Internally Generated (C) 191.6% 222.7% 184.7% 293.4% 232.6% Internally Generated (C), Including Drawdowns of Funds Held in Trust 191.6% 222.7% 226.0% 348.8% 232.6% - ---------------------------------------------------------------------------------------------------------------- Note: See Item 7., Management's Discussion and Analysis of Financial Condition and Results of Operations. (A) Cash from Continuing Operations plus Interest Paid divided by Interest Paid. (B) Excludes Cash from Discontinued Operations. (C) Cash generated is cash provided from continuing operations less cash dividends. Ratios for 1992 and 1991 include cash conserved under the payment moratoria implemented by the Company on certain obligations during 1992 and 1991. N/M - Not meaningful.
ITEM 7. -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following contains information regarding the Company's continuing and discontinued operations during 1995 compared with 1994 and 1994 compared with 1993 and changes in liquidity and capital resources of the Company during 1995. Also, management's expectations of identifiable material trends are discussed herein. OVERVIEW GENERAL The Company closed 1995 with positive earnings for the second consecutive year and with positive common stock equity (instead of a deficit) for the first time since 1990. In addition to underlying growth, results reflect the Company's efforts to lower operating costs as well as reduce capital costs and strengthen the balance sheet. The results also reflect a one-time $12.2 million non-cash accounting reversal of fuel expenses and the non-cash recognition of $23 million of defined tax benefits based on the expectation of the realization of such benefits in the future from net operating loss carryforwards. Despite such improvements, the Company's financial prospects continue to be subject to significant economic, regulatory and other uncertainties, some of which are beyond the Company's control. These uncertainties include the degree of utilization of generation capacity through either retail electric service or wholesale sales and the extent to which the Company, due to continued high financial and operating leverage, can alter operations and reduce costs in response to unanticipated economic downturns or industry changes. The Company's ability to recover the costs of serving retail customers is dependent upon pricing of the Company's services, which requires ACC approval, and the level of sales to such customers. The Company anticipates continued growth in sales over the next five years primarily as a result of anticipated population and economic growth in the Tucson area. However, a number of factors such as changes in economic conditions and the increasingly competitive electric markets could affect the Company's levels of sales. If the Company is unable to make sales at prices adequate to recover its costs or if for other reasons the Company fails to maintain or improve its cash flows, the Company's ability to meet its obligations may be jeopardized. During the 1997-2001 period, approximately $1.1 billion of the Company's long-term debt will be maturing, including approximately $774 million in reimbursement agreements relating to letters of credit which will expire. The Company intends to pay or refinance maturing bonds and bank loans and to replace or extend such reimbursement agreements. There can be no assurance, however, that the Company will be able to pay such debt or replace or extend such reimbursement agreements. In addition, the Company has a significant amount of variable rate debt and, as a result, the Company's future cash flows are also affected by the level of interest rates. See Liquidity and Capital Resources below. The Company's capital structure is highly leveraged and its ability to raise capital (through either public or private financings) is limited. The Company's ability to obtain debt financing is limited by reason of limited free cash flow available to meet additional interest expense and due to the restrictive covenants contained in existing obligations to creditors. To the extent the Company refinances its debt obligations in order to repay them when due, such refinancing may be made on terms which may be adverse to the Company. Such terms could include, among other things, higher interest rates and various restrictive covenants, such as dividend payment restrictions. Access to equity capital may be limited because of the Company's likely limited future profitability and its present inability to pay dividends. See Dividends on Common Stock below. During the next twelve months, the Company expects to be able to fund continuing operating activities and construction expenditures with internal cash flows, existing cash balances, and, if necessary, drawdowns under the Renewable Term Loan and/or borrowings under the Revolving Credit. However, the Company may issue debt to take advantage of lower interest rates resulting from tax-exempt financings. At December 31, 1995, the Company's cash balance including cash equivalents was approximately $85 million. Cash balances are invested in investment grade, money-market securities with an emphasis on preserving the principal amount invested. COMPETITION WHOLESALE The Company competes with other utilities, marketers and independent power producers in the sale of electric capacity and energy in the wholesale market. The Company's rates for wholesale sales of capacity and energy, generally, are not permitted to exceed rates determined on a cost of service basis. In the current market, wholesale prices are substantially below costs determined on a fully allocated cost of service basis, but, in all instances, prices exceed the level necessary to recover fuel and other variable costs. It is expected that competition to sell capacity will remain vigorous, and that prices will remain depressed for at least the next several years, due to increased competition and surplus capacity in the southwestern United States. Competition for the sale of capacity and energy is influenced by many factors, including the availability of capacity in the southwestern United States, the availability and prices of natural gas and oil, spot energy prices and transmission access. In addition, the Energy Act has promoted increased competition in the wholesale electric power markets. The Energy Policy Act of 1992 addresses a wide range of energy issues, including several matters affecting bulk power competition in the electric utility industry. It creates exemptions from regulation under the Holding Company Act for persons or corporations that own and/or operate in the United States certain generating and interconnecting transmission facilities dedicated exclusively to wholesale sales, thereby encouraging the participation of utility affiliates, independent power producers and other non-utility participants in the development of power generation. In order to facilitate competition in power generation, the Energy Act also confers expanded authority upon FERC to issue orders requiring electric utilities to transmit power and energy to or for wholesale purchasers and sellers, and to require electric utilities to enlarge or construct additional transmission capacity to provide these services. While the Energy Act prohibits FERC from issuing any such order that would unreasonably impair the continuing reliability of affected electric systems or that would be conditioned upon or require transmission services directly to an ultimate consumer, the Energy Act creates the potential for utilities and other power producers to gain increased access to the transmission systems of other entities to facilitate wholesale sales. FERC is encouraging all parties interested in transmission access to form RTGs to facilitate access to and development of transmission service and to assist in settling disputes regarding such matters. RTGs will not relieve FERC of its responsibilities related to transmission access; however, such organizations could provide for more efficient handling of transmission service requests and planning for regional transmission needs. The Company is currently involved in the development of two RTGs in the West, SWRTA and WRTA. WRTA was approved by FERC on May 16, 1995 and SWRTA was approved on October 31, 1995. The Company is a member of SWRTA and is also considering membership in WRTA. As a condition of its approval of WRTA and SWRTA as RTGs the FERC has required all transmitting utility members of each RTG to offer comparable transmission services at least to other members of such RTG through tariffs that set forth the rates, terms and conditions of service. On March 29, 1995, the FERC issued a Notice of Proposed Rulemaking (NOPR) on Open Access Non-Discriminatory Transmission Services by Public Utilities and Transmitting Utilities (the Open Access NOPR) and a supplemental NOPR on Recovery of Stranded Costs (the Stranded Costs NOPR). The rules proposed in the Open Access NOPR are intended to facilitate competition among electric generators for sales in the bulk power market. If adopted, the NOPR on open access transmission would require public utilities under the Federal Power Act to provide third party access to their transmission systems and would establish guidelines for their doing so. Under the Open Access NOPR, each public utility would also be required to establish separate rates for its transmission and generation services for new wholesale service, and to take transmission services, including ancillary services, under the same tariffs that would be applicable to third-party users for all of its new wholesale sales and purchases of energy. In addition, the FERC requested comment on the desirability of unified standards for both wholesale and retail transmission services, suggesting, as a possible approach, the establishment by each vertically integrated electric utility of a distribution function which would, for ratemaking purposes, be treated as a wholesale customer taking transmission services under the utility's filed wholesale transmission tariff. The FERC recognized, and numerous comments received by the FERC confirm, that such an approach would change the traditional approach of state-federal allocation of transmission costs. The Stranded Costs NOPR would provide a basis for recovery by regulated public utilities of legitimate and verifiable stranded costs associated with existing wholesale requirements customers and retail customers who become unbundled wholesale transmission customers of the utility. The FERC would provide public utilities a mechanism for recovery of stranded costs that result from municipalization, former retail customers becoming wholesale customers, or the loss of a wholesale customer. The FERC would consider allowing recovery of stranded investment costs associated with retail wheeling only if a state regulatory commission lacks the authority to consider that issue. The Company does not believe that the Open Access NOPR or the Stranded Costs NOPR will have a material effect on the Company's results of operations, assuming that the final rule is adopted substantially as proposed. On December 13, 1995, FERC issued a third and supplemental NOPR on Real- Time Information Networks and Standards of Conduct. This NOPR proposes that each public utility that owns and/or controls transmission facilities would be required to create or participate in an electronic information network which would provide customers with information regarding, among other things, the availability and pricing of transmission capacity. Additionally, FERC is proposing that a code of conduct be established which would govern the relationships between the transmission and generation marketing functions of all regulated public utilities. FERC is proposing that these functions should be separated and that the generation marketing function be required to follow the same procedures to acquire transmission access that third party competitors are required to utilize. The FERC is currently expected to issue final rules on these NOPRs in the second or third quarter of 1996. RETAIL Under current law, the Company is not in direct competition with any other regulated electric utility for electric service in the Company's retail service territory. Nevertheless, the Company competes for retail markets against gas service suppliers and others who may provide energy services which would be substitutes for, or bypass of, the Company's services. Electric energy for meeting retail customers' needs primarily competes with natural gas, an alternative fuel source for certain retail energy uses. Such uses may include heating, cooling and a limited number of other energy applications. In most applications, electric energy is a cost effective source of energy compared with natural gas. Also, customers, particularly industrial and large commercial customers, may own and operate facilities to generate their own electric energy requirements and, if such facilities are qualifying facilities, to require the displaced electric utility to purchase the output of such facilities at "avoided costs" pursuant to PURPA. Such facilities may be operated by the customers themselves or by other entities engaged for such purpose. The Company actively markets energy and customized energy-related services to meet customer needs. The Company has to date lost no customers to self- generation in part because of such efforts and in part because such self- generation alternatives have proven to be uneconomic in comparison with Company- provided electric service. For example, the Company's two mining customers, which provide approximately 10% of the Company's total annual revenues from retail customers, each have considered self-generation. However, following negotiations with the Company in 1993 and 1994, new contracts were executed that included, among other things, rate reductions and term extensions. These contracts expire after the year 2000, subject to various provisions allowing the customers to terminate partially or entirely, under certain circumstances upon at least one and up to two years prior notice. To date, no such notice has been received. The ability to enter into or extend contracts, to avoid early termination, and to retain customers will be dependent on, among other things, the Company's ability to contain its costs, market conditions and alternatives available to customers from time to time. The legislatures and/or the regulatory commissions in several states have considered or are considering "retail wheeling" which, in general terms, means the transmission by an electric utility of energy produced by another entity over its transmission and distribution system to a retail customer in such utility's service territory. A requirement to transmit directly to retail customers could have the result of permitting retail customers to purchase electric capacity and energy from, at the election of such customers, the electric utility in whose service area they are located or from other electric utilities or independent power producers. While retail wheeling would expose the Company's service territory to increased competition, it would also open additional markets into which the Company may sell its electric power. In Arizona, the ACC Staff issued its first report on a retail electric competition workshop held in October of 1994. This report is the first in a series of reports that will be issued on various workshops that will be held from time to time to identify and address policy issues related to competition. While other states are considering competition proposals, the ACC effort is designed to obtain information about competition. No specific proposals are currently being considered. The report proposes that Staff develop a comprehensive set of options to better inform the ACC about its choices. Staff recommended that three options be considered: 1) encouraging retail competition, 2) permitting limited retail competition, and 3) discouraging retail competition by prohibiting retail wheeling and allowing distributed energy services. The ACC has also established a working group on retail electric competition. Membership in the working group includes ACC Staff, Arizona utilities, and other interested parties, and the first meeting of the group took place in January 1995. A report from the group was issued in October 1995. This report concludes Phase I of the Commission's investigation into retail electric competition. In February 1996, Phase II started and is focusing on obtaining more information from interested parties and recommendations on policy. The Company cannot predict what the working group will recommend and what, if any, changes in electric regulation and competition will be implemented by the ACC. The Company continues to assess the impact of the Energy Act and other possible legislation on the Company's ability to remain competitive in the electric utility industry. The Company is unable to predict the ultimate impact the Energy Act or any other possible legislation will have on its operations. HOLDING COMPANY PROPOSAL In 1995, the Company sought approvals to establish through a one-for-one share exchange a new corporate structure in which the Company would have been a subsidiary of a new holding company, UniSource Energy Corporation (UniSource). The Company sought to establish a holding company structure because the Company believes that it is in the best interests of its shareholders for the Company to participate in various segments of the evolving and expanding electric energy business. The Company believes that such participation would be enhanced by the holding company structure, a commonly used structure in the electric and other industries, to conduct different lines of business. In May 1995, shareholders of the Company approved the proposed holding company. However, in addition to shareholder approval, implementation of the holding company plan was predicated upon receiving approval from the ACC and FERC. Also, on September 27, 1995, the Company received a "no action" position from the staff of the SEC under the Public Utility Holding Company Act of 1935, as amended. Also, on April 26, 1995, the Company filed an application with FERC requesting approval to form a holding company. In February 1995, the Company filed a Notice of Intent to Form a Holding Company with the ACC. In June 1995, the ACC Staff filed testimony recommending that the ACC deny the Company's request on the basis that retail customers would be exposed to certain risks resulting from diversification. However, ACC Staff recommended that, in the event that the ACC approves formation of the holding company, the ACC impose various operating and financial conditions on the Company and the holding company. In concurrently filed testimony, RUCO, an intervenor in the matter, did not oppose the formation of the holding company. The Company filed rebuttal testimony on July 27, 1995, and a public hearing was held on August 22, 1995. In November 1995, the Company and the ACC Staff entered into the Proposed Settlement Agreement which included a proposal to resolve the holding company application. On January 19, 1996, the ACC denied the Proposed Settlement Agreement. Following the denial of the Proposed Settlement Agreement, the ACC Hearing Officer submitted a recommended order on the holding company proposal. On February 22, 1996, the ACC denied the formation of a holding company. However, the ACC granted the Company a waiver authorizing it to invest in subsidiaries that will engage in energy related projects in an amount equal to the lesser of $25 million or the maximum amount allowed by the MRA. To the extent that the Company obtains retroactive approval or waiver of projects from the ACC, the energy related diversification amount will be reinstated up to the $25 million limit. This investment authority is subject to the conditions that (i) the total waiver amount shall not exceed $50 million annually, (ii) 60% of net profits from diversified activities be applied to repay the Company's debt and (iii) total investment in such diversified activities does not exceed 15% of the Company's capitalization. As a result of the ACC order, the Company will not establish the holding company proposal structure at this time and will withdraw its holding company application with FERC. The Company may, in the future, seek the approval of the ACC for the establishment of the holding company structure and could, upon the receipt of the requisite regulatory approvals, effect the plan of exchange. NATIONS ENERGY CORPORATION In 1995, the Company established Nations Energy (formerly known as Escalante Resources Inc.) for the purpose of investing in independent power projects in the domestic and foreign energy markets. The 1995 consolidated financial statements reflect the accounts of Nations Energy, a wholly-owned subsidiary of the Company. In September 1995, Nations Energy and Trigen Energy Corporation formed a limited partnership which purchased Coors Brewing Company's energy production (utility) assets. Nations Energy has a 49% interest in such partnership. The partnership will provide electricity and steam for the brewery operation in Golden, Colorado. In addition, the partnership expects to upgrade Coors' power plant to improve fuel efficiency and increase capacity. The investment of aproximately $12 million by Nations Energy is included in the Company's Consolidated Balance Sheet at December 31, 1995 under Investments and Other Property and in the Company's Consolidated Statement of Cash Flows for the year ended December 31, 1995 as Investment in Partnership. RESULTS OF OPERATIONS In 1995, the Company had net income of $54.9 million or $0.34 per average share of common stock compared with $20.7 million or $0.13 per average share of common stock in 1994 and a net loss of $25.8 million or $0.16 per average share of common stock in 1993. The improved positive earnings for the second consecutive year resulted from strong growth in the Company's service territory, an increase in income tax benefits due to the recognition of net operating loss carryforwards which will likely be realized in the future, a one time $12.2 million reduction in fuel expenses due to the satisfaction of certain requirements under fuel and transportation agreements restructured in 1991, and the Company's efforts to contain costs. RESULTS OF UTILITY OPERATIONS SALES AND REVENUES Sales and revenues are affected principally by price changes, consumption and growth factors. In 1995, much of the changes were attributable to growth, as the average number of retail customers grew 2.9% which led to a slight increase in consumption. Consumption was affected by milder temperatures in 1995 than the ten-year average. Prices did not change in 1995, and the change in revenues is also attributable to strong growth in the Company's retail customer base. Revenues from sales to retail customers increased 0.6% in 1995 compared with 1994 and 8.9% in 1994 compared with 1993. The table below identifies the components of the increases in 1995 and 1994. 1995 1994 - Millions of Dollars - 1994 Price Change $ 3 $17 Consumption Change (13) 15 Customer Growth 13 15 Increase in Retail Revenues $ 3 $47 KWh sales to retail customers increased less than 1% in 1995 compared with 1994. The kWh sales increase resulted from a 2.9% increase in the average number of retail customers, partially offset by decreased usage due to cooler temperatures in 1995 than in 1994. Based on billed cooling degree days, a commonly used measure in the electric industry that is calculated by subtracting 75 from the average of the high and low daily temperatures, the Tucson area registered an approximate 24% decrease in such billed cooling degree days for 1995 compared with 1994, and a 4% decrease in such billed cooling degree days for 1995 compared with the 10 year average for the same period from 1985 to 1994. Specifically, billed cooling degree days were 1,399, 1,844, and 1,454 for 1995, 1994, and the 10 year average, respectively. The Company had 297,939 retail customers on average in 1995. KWh sales in 1994 compared with 1993 increased as a result of a 2.9% increase in the average number of customers and increased usage as a result of warmer than normal temperatures. Revenues from sales to retail customers increased in 1995 compared with 1994 due to slightly higher kWh sales discussed above and the rate increase allowed under the 1994 Rate Order being in effect throughout 1995. In 1994, revenues increased 9% over 1993 due to greater kWh sales and increased prices as a result of the 1994 Rate Order. Amortization of the MSR Option Gain Regulatory Liability increased in 1994 compared with 1993 as a result of the 1991 Rate Order which set the non-cash operating revenue for the amortization of the regulatory liability for the MSR option gain at $6 million for 1993, $20 million in 1994, 1995 and 1996, and $8 million in 1997 at which point the MSR Option Gain will be fully amortized. See Note 1 of Notes to Consolidated Financial Statements, Nature of Operations and Summary of Significant Accounting Policies. The Company makes sales for resale to the extent capacity is not needed for providing energy to the Company's retail customers. Rates for such sales are substantially below rates determined on a fully allocated cost of service basis, but, in all instances, rates exceed the level necessary to recover fuel and other variable costs. Lower kWh sales to other utilities in 1995 compared with 1994 resulted from lower regional loads due to mild weather conditions and the increased availability of lower cost hydroelectric power in the western United States. Lower revenues from sales to other utilities resulted from lower sales and lower spot market prices in 1995 than in 1994. Revenues from other utilities decreased by 24% compared with 1994. In 1994, revenues from sales to other utilities increased 7% over 1993 as a result of a 13% increase in revenues from firm sales of energy, offset by a 4% decrease in revenues from economy sales. OPERATING EXPENSES Fuel and purchased power expense decreased in 1995 compared with 1994 as a result of lower generation requirements in 1995 than in 1994, a one time $12.2 million reduction in fuel expenses due to the satisfaction of certain requirements under fuel and transportation agreements restructured in 1991 and lower incremental fuel costs resulting from fuel contracts negotiations. Fuel expenses increased 6.4% in 1994 over 1993 as a result of the 1994 reallocation of a reserve for sales tax disputes from Taxes Other than Income Taxes. See Note 6 of Notes to Consolidated Financial Statements, Commitments and Contingencies, Tax Assessments. Average cost per kWh of fuel and transportation only, excluding accounting adjustments, were 1.55 cents, 1.71 cents and 1.79 cents for 1995, 1994 and 1993, respectively. Amortization of Springerville Unit 1 Allowance, a non-cash item, decreased in 1994 compared with 1993 due to lower projected operation and maintenance expenses included in the calculation of the Springerville Unit 1 Allowance. The Springerville Unit 1 Allowance was originally calculated by projecting the yearly costs associated with Springerville Unit 1 over the remaining life of the Springerville Unit 1 Leases and recording the present value of the difference between such costs and the ACC allowed level of recovery. Such costs are then recognized in each period along with a corresponding interest accrual and amortization of the allowance as a credit to operating expenses. The interest accrual is included in the Consolidated Statements of Income (Loss) as Interest Imputed on Losses Recorded at Present Value. See Note 1 of Notes to Consolidated Financial Statements, Nature of Operations and Summary of Significant Accounting Policies. Other Operations expense decreased in 1995 due to cost containment measures implemented by the Company and increased in 1994 compared with 1993 as a result of the accrual of increased employee expenses related to compensation and pension benefits expenses. Depreciation and Amortization increased in 1994 over 1993 as a result of the amortization of 62.5% of the Springerville Unit 2 rate synchronization deferral costs over 3 years (beginning in January 1994) pursuant to the 1994 Rate Order. Taxes Other than Income Taxes increased in 1995 compared with 1994 as a result of the 1994 reallocation of an $8 million reserve for sales tax disputes to Fuel in 1994. See Note 6 of Notes to Consolidated Financial Statements, Commitments and Contingencies, Tax Assessments. Such reallocation caused taxes other than income taxes expense to decrease in 1994 compared with 1993. Income tax expense increased in 1995 compared with 1994 because the Company's operations produced taxable operating income for the first time since 1988. OTHER INCOME (DEDUCTIONS) Regulatory Disallowances and Adjustments in 1993 reflect primarily the write-off of Springerville Unit 2 deferred expenses mandated by the 1994 Rate Order. Deferred Springerville Unit 2 Carrying Costs decreased in 1994 compared with 1993 as a result of the incorporation into rate base of 62.5% of Springerville Unit 2. Interest Income increased in 1994 compared with 1993 due to greater interest earned on cash and cash equivalents. Income Tax benefits included in Other Income (Deductions) increased in 1995 compared with 1994 and 1993. In 1994 and 1993, the Company was in a net operating loss carryforward position and generating tax losses; therefore, the income tax benefits included in the Consolidated Statements of Income (Loss) for the years 1994 and 1993 reflected only ITC amortization. In 1995, income tax benefits include the recognition of a portion of the Company's deferred tax benefits based on the expectation of realization of such benefits in the future from net operating loss carryforwards, as well as ITC amortization. Other income increased in 1995 compared with 1994 as a result of gains realized on the sales of equity securities held by the investment subsidiaries. As of January 1, 1995, the Company ceased to account for the investment subsidiaries as discontinued operations. Previously, when the investment subsidiaries were classified as discontinued operations for financial statement purposes, no income or loss related to discontinued operations was recorded unless the estimates of proceeds from disposition of investment subsidiary assets changed materially. INTEREST EXPENSE Interest expense on Long-Term Debt increased in 1994 compared with 1993 as a result of slightly higher interest rates. Although interest rates increased in 1995, interest expense did not increase due to lower amounts of debt outstanding. Interest Expense - Other decreased in 1994 compared with 1993 due to an accrual in 1993 for interest on contested tax payments and litigation settlement. ACCOUNTING FOR THE EFFECTS OF REGULATION The Company prepares its financial statements in accordance with the provisions of FAS 71. This statement requires a cost-based rate-regulated utility to reflect the effect of regulatory decisions in its financial statements. In certain circumstances, FAS 71 requires that certain costs and/or obligations be reflected in a deferral account in the balance sheet and not be reflected in the statement of income or loss until matching revenues are recognized. Therefore, the Company's Consolidated Balance Sheets at December 31, 1995, 1994 and 1993 contain certain line items (showing on the balance sheet under Deferred Debits - Regulatory Assets and MSR Option Gain Regulatory Liability, Accumulated Deferred Investment Tax Credits Regulatory Liability, and Other Regulatory Liabilities) solely as a result of the application of FAS 71. In addition, a number of line items in the Company's Consolidated Statements of Income (Loss) for the years ended December 31, 1995, 1994 and 1993 also reflect the application of FAS 71. See Note 1 of Notes to Consolidated Financial Statements, Nature of Operations and Summary of Significant Accounting Policies, Accounting for the Effects of Regulation. If, at some point in the future, the Company determines that all or a portion of the Company's regulated operations no longer meet the criteria for continued application of FAS 71, the Company would be required to adopt the provisions of FAS 101 for that portion of the operations for which FAS 71 no longer applied. Adoption of FAS 101 would require the Company to write off its regulatory assets and liabilities as of the date of adoption of FAS 101 and would preclude the future deferral in the balance sheet of costs not recovered through rates at the time such costs were incurred, even if such costs were expected to be recovered in the future. Based on the balances of the Company's regulatory assets and liabilities as of December 31, 1995, the Company estimates that future adoption of FAS 101 for all of the Company's regulated operations would result in an extraordinary loss of $145 million, which includes a reduction for the related deferred income taxes. The Company's cash flows would not be affected by the adoption of FAS 101. DIVIDENDS The Company is precluded by restrictive covenants in certain debt agreements from declaring or paying dividends. No dividend on common stock has been declared or paid since 1989. Under the applicable provisions of amendments to the Arizona General Corporation Law, in effect starting in 1996, a company is permitted to make distributions to shareholders unless, after giving effect to such distribution, either (i) the company would not be able to pay its debt as they come due in the usual course of business, or (ii) the company's total assets would be less than the sum of its total liabilities plus the amount necessary to satisfy any liquidation preferences of shareholders with preferential rights. Under such provisions, the Company is currently able to declare and pay a dividend. However, the Company may not declare or pay dividends pursuant to covenants under both the MRA and the General First Mortgage. The Company's ability to pay a dividend is restricted by certain covenants of the General First Mortgage applicable so long as certain series of First Mortgage Bonds (aggregating $184 million in principal amount) are outstanding. These covenants restrict the payment of dividends on Common Stock if certain cash flow coverage and retained earnings tests are not met. The cash flow coverage and retained earnings test will prevent the Company from paying dividends on its Common Stock until such time as the Company's cash flow coverage ratio, as defined therein, is greater or equal to a ratio of 2 to 1, and the Company has positive retained earnings rather than an accumulated deficit. As of December 31, 1995, the Company had a cash flow coverage ratio slightly above 2 to 1 and the Company's accumulated deficit was $626 million. Such covenants will remain in effect until the First Mortgage Bonds of such series have been paid or redeemed. The latest maturity of such First Mortgage Bonds is in 2003. The MRA contains a similar dividend restriction based on retained earnings. Such restriction will no longer apply if (i) the Renewable Term Loan and the Revolving Credit have been paid in full and the commitments relating thereto have been terminated and (ii) the Company's senior long-term debt is rated investment grade. Currently, the Company's total outstanding amounts under the Renewable Term Loan are $31 million and to date no amounts have been borrowed under the Revolving Credit. Commitments relating to such facilities permit the Company to borrow $133 million under the Renewable Term Loan and $50 million under the Revolving Credit. Also, the Company's senior debt is currently rated below investment grade. In order for the Company to pay a dividend when such covenants would otherwise restrict such payment, the Company would have to (i) obtain a waiver or an amendment to the MRA's retained earnings covenant and (ii) redeem all outstanding First Mortgage Bonds of the series that contain dividend restrictions or amend the General First Mortgage. Such amendment would require approval by holders of 75% of all First Mortgage Bonds. In addition to such restrictive covenants, the Company may also be restricted under the Federal Power Act from paying dividends from funds properly included in the capital account. The provisions of the Federal Power Act leaves the scope of any such restriction and its potential applicability to the Company unclear. LIQUIDITY AND CAPITAL RESOURCES CASH FLOWS Due to growth in retail sales and cost containment efforts, the Company's net cash flows from continuing operations were more than sufficient, in all three years from 1993 to 1995, to cover all construction expenditures and debt maturities. Net cash flows from continuing operating activities decreased in aggregate $24 million in 1995 compared with 1994 due primarily to a $14.6 million tax payment in 1995 made by the Company relating to an appeal of a transaction privilege tax assessment (see Note 6 of Notes to Consolidated Financial Statements, Commitments and Contingencies, Tax Assessments); increased compensation paid relating to the 1994 incentive plan and increased employee compensation and pension benefits expenses; and lower cash receipts from sales to other utilities. Cash receipts from sales to other utilities decreased due to lower kWh sales and lower energy prices as a result of lower regional loads and an abundance of hydroelectric power in the western United States. Increased cash expenditures were partially offset in 1995 by lower fuel and purchased power expenses and by revenues from the sales of Emission Allowances. Net cash flows from investing activities decreased in 1995 compared with 1994 as a result of the purchase of lease debt securities described below under Financing Developments , and the investment in the Coors Energy project by Nations Energy through a partnership interest. Net cash flows from financing activities decreased $159 million in 1995 compared with 1994 as a result of the Company reducing its outstanding debt obligations by 13% or $180 million in 1995. Such reduction was comprised of $17 million of first mortgage bond and Installment Sale Agreement maturities, a $19 million permanent prepayment of the Term Loan and $143 million payment of the Renewable Term Loan of which $133 million can be reborrowed. During 1996, the Company expects to generate sufficient internal cash flows to fund its continuing operating activities and construction expenditures. Cash flow levels are subject to short-term interest rates and revenues from wholesale sales remaining near current levels. An increase in short-term interest rates of 100 basis points (1%) would result in an approximate $10 million increase in interest expense. If 1996 cash flows fall short of expectations, the Company would fund its cash requirements by reducing cash balances and/or borrowing under its Renewable Term Loan and/or the Revolving Credit. As a result of activities described above, the Company's cash and cash equivalents, including such amounts held by the Company's investment subsidiaries, decreased $163 million or 66%, from the 1994 year-end balance of $248 million, to the 1995 year-end balance of $85 million. The Company's cash balance including cash equivalents at March 1, 1996 was approximately $52 million. Cash balances are invested in investment grade, money-market securities with an emphasis on preserving the principal amounts invested. FINANCING DEVELOPMENTS In March 1995, the Company and its banks completed an amendment to the MRA which eased certain debt prepayment restrictions and allowed reborrowing of certain Renewal Term Loan prepayments. The amendment allows the Company to optionally prepay non-MRA debt provided certain conditions are met. Such conditions include that $1 of principal outstanding under the Renewable Term Loan is permanently prepaid and the commitment therefore terminated for every $2 used to permanently prepay other debt such as First Mortgage Bonds. The Renewable Term Loan allows the Company to reborrow amounts paid down to the extent of the remaining outstanding loan commitment. The commitment fee on the Renewable Term Loan is 0.5% of the unused portion of such commitment. As a condition to the amendment becoming effective, the Company permanently prepaid $19 million of the Term Loan reducing the outstanding balance from $193 million to approximately $174 million. Thus, the initial commitment and outstanding balance of the Renewable Term Loan was approximately $174 million. In May 1995, the Company purchased approximately $18 million of Springerville Unit 1 lease debt securities. The Company expects yearly cash earnings of approximately $2 million as a result of the above-mentioned purchase. This purchase is shown on the balance sheet under Investments and Other Property and the interest earned is included in Interest Income on the income statement. Also, as a result of the debt securities purchase, the Renewable Term Loan commitment was decreased by $10 million, to $164 million, to meet the prepayment provisions of the MRA. In aggregate, in 1995, the Company made payments on the Renewable Term Loan totaling $162 million. The Company can currently reborrow $133 million under the Renewable Term Loan. Also, in 1995, the Company reduced its long-term debt by $17 million, as a result of scheduled maturities. In January 1996, the Company obtained a tax-exempt volume cap allocation from the state of Arizona. The Company's allocation is for approximately $16.7 million to be issued by the Pollution Control Corporation of the county of Coconino in Arizona, for the benefit of the Company. The Company expects to issue such bonds in early April 1996. If the Company were to fail to issue the bonds by such time, the Company would lose its volume cap allocation. The proceeds will be used to reimburse the Company for expenditures relating to the Company's interest in pollution control facilities at the Navajo Generating Station. Also, in order for the Company to issue such bonds, the Company will need approval from the ACC. The Company filed a financing application with the ACC on February 14, 1996. See C onstruction Expenditures below. SHORT-TERM CREDIT FACILITIES REVOLVING CREDIT Under the MRA, the Banks provided a $50 million Revolving Credit for working capital purposes. To date, the Company had not borrowed any funds under the $50 million Revolving Credit. The Revolving Credit has a termination and maturity date of December 31, 1999, and borrowings, if any, thereunder bear interest at a variable rate based upon, at the option of the Company, either (i) prime rate or (ii) an adjusted eurodollar rate plus a percentage ranging from 1% during 1996, gradually increasing to 2% by 1998 and thereafter. The Company is required to repay loans under the Revolving Credit in full for at least 30 consecutive days in each twelve-month period prior to November 30 of each year. The annual commitment fee for the Revolving Credit equals 0.5% of the unused portion. The Revolving Credit is secured and contains restrictive covenants. See Restrictive Covenants below. OTHER The balance of $12 million of short-term debt of the investment subsidiaries as of December 31, 1995, and 1994, respectively, was associated with wholly-owned subsidiaries indirectly owned by SRI. Such debt is reflected in Short-Term Debt and is without recourse to SRI or the Company. INCOME TAX POSITION At December 31, 1995, the Company had, for federal income tax purposes, approximately $508 million of net operating loss carryforwards expiring in 2004 through 2009 and $148 million of alternative minimum tax loss carryforwards expiring in 2006 through 2008. For state income tax purposes, the Company has approximately $215 million of net operating loss carryforwards expiring in 1996 through 1999. In addition, for federal income tax purposes the Company has $26 million of unused ITC, the use of which will expire during 2002 through 2005, $3 million of alternative minimum tax credit which will carry forward to future years, and $21 million of capital loss carryforwards which expire during 1996 through 1999. Due to the Company's Financial Restructuring, the Company experienced a change in ownership under section 382 of the Internal Revenue Code in December 1991. As a result of that change, the amount of the taxable income for any post-change year which may be offset by pre-change net operating losses will be limited based on the value of the Company on the ownership change date. The Company estimates an annual limit of such offset by prechange losses of approximately $23 million. The total limitation may be increased to the extent of gain recognized on sales of assets whose fair market value was greater than tax basis at the ownership change date, thereby representing a built-in-gain as of that date. The limitation may increase by built-in-gain recognized within a period of five years after the change in ownership. During 1992 through 1995, the limitation increased by approximately $102 million of built-in-gain recognized due to asset sales. Unused limitation may be carried forward until the pre-change tax attributes expire. At December 31, 1995, the Company had pre-change federal net operating loss, ITC, capital loss and alternative minimum tax loss carryforwards of approximately $351 million, $26 million, $7 million and $115 million, respectively. Because the Company's results from operations have been steadily improving and have been positive for the last two years, the Company now believes it is more likely than not that it will realize at least $66.5 million of the total federal NOL carryforwards of $508 million. Accordingly, the Company recognized a $23 million income tax benefit related to the expected utilization of $66.5 million of tax operating loss carryforwards which is included in Income Taxes in Other Income (Deductions) in the Consolidated Statement of Income (Loss). Furthermore, the Company expects to record similar or greater amounts in 1996 provided the Company's results of operations continue to improve. RESTRICTIVE COVENANTS GENERAL FIRST MORTGAGE COVENANTS The Company's General First Mortgage places limits on the amount of additional First Mortgage Bonds which can be issued. Under the General First Mortgage, the Company may issue additional First Mortgage Bonds (a) to the extent of 60% of net additions to utility property if net earnings, as defined therein, for a specified period of 12 consecutive calendar months out of the 15 calendar months preceding the date of issuance are at least two (2.0) times the annual interest requirements on all First Mortgage Bonds to be outstanding and (b) to the extent of the principal amount of retired bonds. The net earnings test specified in clause (a) above generally need not be satisfied prior to the issuance of bonds in accordance with clause (b) above unless (x) (i) the new bonds are issued within one year after the issuance of, or more than two years prior to the stated maturity of, the retired bonds and (ii) the new bonds bear a greater rate of interest than the retired bonds or (y) the new bonds are issued in respect of retired bonds the interest charges on which have been excluded from any net earnings certificate filed with the indenture trustee since the retirement of such bonds. At December 31, 1995, the Company had the ability to issue approximately $107 million of new First Mortgage Bonds on the basis of property additions, as described above, and, in addition, the Company had the ability to issue approximately $90 million of new First Mortgage Bonds on the basis of retired bonds. However, issuance of such amounts may be limited by MRA covenants. See Additional Restrictive Covenants below. See Dividends above for a discussion of restrictions on the payment of Common Stock dividends under the General First Mortgage. GENERAL SECOND MORTGAGE COVENANTS The General Second Mortgage establishes a second mortgage lien on and security interest in substantially all of the utility assets of the Company, subordinate only to the first mortgage lien and security interest. At December 31, 1995, $50 million of such General Second Mortgage bonds had been issued and provided to the Banks as collateral for the Revolving Credit and, subsequent to January 2, 1997, subject to certain conditions, the Renewable Term Loan and the Replacement Reimbursement Agreement. The Company's General Second Mortgage allows the issuance of additional Second Mortgage Bonds under certain circumstances. The Company may issue additional Second Mortgage Bonds (a) to the extent of 70% of net additions to utility property if net earnings as defined therein, for a specified period of 12 consecutive calendar months within the 16 calendar months preceding the date of issuance are at least one and three-quarter (1-3/4) times the annual interest requirements on all First Mortgage Bonds and Second Mortgage Bonds to be outstanding and (b) to the extent of the principal amount of retired Second Mortgage Bonds and First Mortgage Bonds. Issuance of Second Mortgage Bonds on the basis of an amount of retired First Mortgage Bonds reduces by the same amount of First Mortgage Bonds which could be issued under the General First Mortgage on the basis of retired bonds. The net earnings test specified in clause (a) above generally need not be satisfied prior to the issuance of bonds in accordance with clause (b) above unless (x) (i) the new bonds are issued within one year after the issuance of, or more than two years prior to the stated maturity of, the retired bonds and (ii) the new bonds bear a greater rate of interest than the retired bonds or (y) the new bonds are issued in respect of retired bonds the interest charges on which have been excluded from any net earnings certificate filed with the indenture trustee since the retirement of such bonds. At December 31, 1995, the amount of net additions and retired bonds would permit (and the net earnings test would not prohibit) the issuance of $596 million aggregate principal amount of new Second Mortgage Bonds (at an assumed interest rate of 12% per annum). The issuance of such amount of Second Mortgage Bonds assumes that the $197 million of First Mortgage Bonds available to be issued at December 31, 1995 would be issued first at a rate of 11%. However, issuance of such amounts may be limited by MRA covenants. See Additional Restrictive Covenants below. ADDITIONAL RESTRICTIVE COVENANTS In addition to the prepayment provisions described above, the MRA contains a number of restrictive covenants including, but not limited to, covenants limiting, with certain exceptions, (i) the incurrence of additional indebtedness, including lease obligations, or the prepayment of existing indebtedness, or the guarantee of any such indebtedness, (ii) the incurrence of liens, (iii) the sale of assets or the merger with or into any other entity, (iv) the declaration or payment of dividends on Common Stock or any other class of capital stock, (v) the making of capital expenditures beyond those contemplated in the Company's 1992 ten-year capital budget, and (vi) the Company's ability to enter into sale-leaseback arrangements, operating lease arrangements and coal and railroad arrangements. All of these restrictive covenants described above, other than (i), (iv) and (vi), will be in effect until at least December 1997. The covenants described in (i), (iv) and (vi) will cease to be binding on the Company when both the Renewable Term Loan and the Revolving Credit are paid in full and commitments thereunder terminate and the Company's senior long-term debt is rated investment grade. In addition, the Company is required pursuant to the MRA to maintain an interest coverage ratio of (a) operating cash flows plus interest paid to (b) interest paid, through the year 2003, ranging from 1.40 to 1 in 1995 and gradually increasing to 2 to 1 in 2000 continuing through the year 2003. For the year ended December 31, 1995, the Company's MRA interest coverage ratio was 2.52 to 1. With respect to dividends, the MRA incorporates, until the Renewable Term Loan and the Revolving Credit are paid in full and commitments thereunder terminate and the Company's senior debt is rated investment grade, a restrictive covenant similar to that currently in the General First Mortgage which limits the Company's ability to pay dividends on Common Stock until it has positive retained earnings (through future earnings or otherwise) rather than an accumulated deficit (such accumulated deficit was $626 million at December 31, 1995. (See Dividends for a discussion of the effects of such covenants on the Company's ability to declare or pay dividends.) CONSTRUCTION EXPENDITURES Estimated construction expenditures of the Company, including AFDC, for the five years 1996 through 2000, respectively, are $80 million, $97 million, $91 million, $52 million and $84 million. These amounts include the following: $180 million for transmission and distribution facilities in the Tucson area; $31 million for expenditures which are necessary to upgrade pollution control facilities at Navajo (see Item 1., Business, Environmental Matters, Navajo Generating Station); $85 million for new generation equipment; and $108 million for modifications to existing production facilities. These estimated construction expenditures include costs to comply with current federal and state environmental regulations. All of these estimates are subject to continuing review and adjustment. Actual construction expenditures may vary from these estimates due to factors such as changes in business conditions, construction schedules and environmental requirements. Due to the limitation on the Company's ability to issue debt or equity capital at economically feasible rates, and to apply such proceeds, if any, to capital requirements, the Company must fund these construction expenditures and any Nations Energy equity investment funding with internally generated funds, tax-exempt debt when available, and/or reductions of its cash and cash equivalents. Also, see Notes 5 and 6 of Notes to Consolidated Financial Statements, Long and Short-Term Debt and Capital Lease Obligations, and Commitments and Contigencies, respectively. ITEM 8. -- CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA See Item 14, page 63, for a list of the Consolidated Financial Statements which are included in the following pages. See Note 9 of Notes to Consolidated Financial Statements. INDEPENDENT AUDITORS' REPORT TUCSON ELECTRIC POWER COMPANY We have audited the accompanying consolidated balance sheets and statements of capitalization of Tucson Electric Power Company and its subsidiaries (the Company) as of December 31, 1995 and 1994, and the related consolidated statements of income (loss), changes in stockholders equity (deficit), and cash flows for each of the three years in the period ended December 31, 1995. 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 consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles. As discussed in Note 2 to the financial statements, the timing of the recovery of the costs associated with 37.5% of Springerville Unit 2 cannot presently be determined because the Company has not yet received rate relief for such costs. DELOITTE & TOUCHE LLP Tucson, Arizona January 29, 1996 CONSOLIDATED STATEMENTS OF INCOME (LOSS) For the Years Ended December 31, 1995 1994 1993 - Thousands of Dollars - Operating Revenues Retail Customers $ 574,925 $ 571,433 $ 524,813 Amortization of MSR Option Gain Regulatory Liability 20,053 20,053 6,053 Other Utilities 75,591 99,987 93,273 ---------- ---------- ---------- Total Operating Revenues 670,569 691,473 624,139 ---------- ---------- ---------- Operating Expenses Fuel and Purchased Power 186,330 231,126 217,071 Capital Lease Expense 95,441 93,056 92,844 Amortization of Springerville Unit 1 Allowance (28,432) (26,204) (33,398) Other Operations 99,493 101,039 92,469 Maintenance and Repairs 38,943 42,122 42,300 Depreciation and Amortization 92,179 89,905 74,184 Taxes Other than Income Taxes 55,640 46,118 54,814 Income Taxes 8,920 (91) (91) ---------- ---------- ---------- Total Operating Expenses 548,514 577,071 540,193 ---------- ---------- ---------- Operating Income 122,055 114,402 83,946 ---------- ---------- ---------- Other Income (Deductions) Regulatory Disallowances and Adjustments - - (13,777) Deferred Springerville Unit 2 Carrying Costs 1,127 1,133 5,359 Interest Income 8,222 7,556 3,909 Income Taxes 29,356 4,820 5,186 Other Income 2,826 489 805 ---------- ---------- ---------- Total Other Income (Deductions) 41,531 13,998 1,482 ---------- ---------- ---------- Interest Expense Long-Term Debt 69,174 69,353 68,053 Interest Imputed on Losses Recorded at Present Value 32,633 32,280 31,303 Other 7,997 7,118 8,604 Allowance for Borrowed Funds Used During Construction (1,123) (1,091) (716) ---------- ---------- ---------- Total Interest Expense 108,681 107,660 107,244 ---------- ---------- ---------- (continued on next page) CONSOLIDATED STATEMENTS OF INCOME (LOSS) (Continued) For the Years Ended December 31, 1995 1994 1993 - Thousands of Dollars - Income (Loss) from Continuing Operations 54,905 20,740 (21,816) Provision for Loss on Disposal of Discontinued Operations - - (4,000) ---------- ---------- ---------- Net Income (Loss) $ 54,905 $ 20,740 $ (25,816) ========== ========== ========== Average Shares of Common Stock Outstanding (000) 160,691 160,724 160,544 ========== ========== ========== Net Income (Loss) per Average Share Continuing Operations $ 0.34 $ 0.13 $ (0.14) Discontinued Operations - - (0.02) ---------- ---------- ---------- Total Net Income (Loss) per Average Share $ 0.34 $ 0.13 $ (0.16) ========== ========== ========== See Notes to Consolidated Financial Statements. CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1995 1994 1993 - Thousands of Dollars - Cash Flows from Continuing Operating Activities Cash Receipts from Retail Customers $616,064 $611,917 $557,222 Cash Receipts from Other Utilities 80,415 99,198 91,799 Fuel and Purchased Power Costs Paid (167,672) (187,130) (167,691) Wages Paid, Net of Amounts Capitalized (63,412) (51,960) (47,073) Payment of Other Operations and Maintenance Costs (75,504) (73,036) (86,582) Capital Lease Interest Paid (83,986) (82,511) (81,932) Interest Paid, Net of Amounts Capitalized (78,743) (72,556) (70,316) Taxes Paid, Net of Amounts Capitalized (120,759) (107,594) (105,748) Income Taxes Paid (1,960) - - Litigation Settlement - - (5,000) Emission Allowance Inventory Purchases (4,190) - - Emission Allowance Inventory Sales 11,255 - - Interest Received 7,882 7,288 4,652 --------- --------- --------- Net Cash Flows - Continuing Operating Activities 119,390 143,616 89,331 --------- --------- --------- Net Cash Flows - Discontinued Operations - 42,685 5,677 --------- --------- --------- Cash Flows from Investing Activities Construction Expenditures (59,097) (62,599) (48,162) Purchase of Debt Securities (17,697) - - Investment in Partnership (12,429) - - Other Investments - Net 3,321 103 (286) --------- --------- --------- Net Cash Flows - Investing Activities (85,902) (62,496) (48,448) --------- --------- --------- Cash Flows from Financing Activities Proceeds from Long-Term Debt - - 20,000 Payments to Retire Long-Term Debt (36,507) (19,424) (72,187) Payments on Renewable Term Loan (143,060) - - Payments to Retire Capital Lease Obligations (17,231) (17,747) (10,690) Other - Net 252 (478) 862 --------- --------- --------- Net Cash Flows - Financing Activities (196,546) (37,649) (62,015) --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents (163,058) 86,156 (15,455) Cash and Cash Equivalents, Beginning of Year * 248,152 161,996 177,451 --------- --------- --------- Cash and Cash Equivalents, End of Year ** $ 85,094 $248,152 $161,996 ========= ========= ========= (continued on next page) CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued) * Beginning of year balance includes cash and cash equivalents from discontinued operations of $14,852,000 for 1995, $22,179,000 for 1994 and $22,502,000 for 1993 ** End of year balance includes cash and cash equivalents from discontinued operations of $14,852,000 for 1994 and $22,179,000 for 1993. See Notes to Consolidated Financial Statements. CONSOLIDATED BALANCE SHEETS ASSETS December 31, 1995 1994 - Thousands of Dollars - Utility Plant Plant in Service $2,095,679 $2,053,123 Utility Plant Under Capital Leases 893,064 893,064 Construction Work in Progress 50,898 40,870 ----------- ----------- Total Utility Plant 3,039,641 2,987,057 Less Accumulated Depreciation and Amortization (859,227) (791,617) Less Accumulated Amortization of Capital Leases (40,113) (25,595) Less Springerville Unit 1 Allowance (162,175) (162,423) ----------- ----------- Total Utility Plant - Net 1,978,126 2,007,422 ----------- ----------- Investments Investments and Other Property 52,116 4,307 Net Assets of Discontinued Operations - 8,685 ----------- ----------- Total Investments 52,116 12,992 ----------- ----------- Current Assets Cash and Cash Equivalents 85,094 233,300 Accounts Receivable 61,717 66,332 Materials and Fuel 42,168 36,109 Deferred Income Taxes - Current 18,250 12,870 Other 7,565 8,376 ----------- ----------- Total Current Assets 214,794 356,987 ----------- ----------- Deferred Debits - Regulatory Assets Income Taxes Recoverable Through Future Rates 135,957 143,372 Deferred Common Facility Costs 63,303 65,843 Deferred Springerville Unit 2 Costs 42,039 54,983 Deferred Lease Expense 19,808 25,228 Other Deferred Regulatory Assets 8,576 15,234 Deferred Debits - Other 16,211 17,532 ----------- ----------- Total Deferred Debits 285,894 322,192 ----------- ----------- Total Assets $2,530,930 $2,699,593 =========== =========== See Notes to Consolidated Financial Statements. CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND OTHER LIABILITIES December 31, 1995 1994 - Thousands of Dollars - Capitalization Common Stock Equity (Deficit) $ 12,488 $ (42,233) Capital Lease Obligations 897,958 922,735 Long-Term Debt 1,207,460 1,381,935 ----------- ----------- Total Capitalization 2,117,906 2,262,437 ----------- ----------- Current Liabilities Short-Term Debt 12,039 - Current Obligations Under Capital Leases 33,389 12,803 Current Maturities of Long-Term Debt 12,075 17,167 Accounts Payable 25,178 39,777 Interest Accrued 57,389 59,480 Taxes Accrued 15,696 29,215 Accrued Employee Expenses 13,680 15,247 Other 7,989 6,624 ----------- ----------- Total Current Liabilities 177,435 180,313 ----------- ----------- Deferred Credits and Other Liabilities MSR Option Gain Regulatory Liability 25,610 41,214 Accumulated Deferred Investment Tax Credits Regulatory Liability 19,603 24,368 Other Regulatory Liabilities 10,343 469 Deferred Income Taxes - Noncurrent 145,982 164,341 Other 34,051 26,451 ----------- ----------- Total Deferred Credits and Other Liabilities 235,589 256,843 ----------- ----------- Total Capitalization and Other Liabilities $2,530,930 $2,699,593 =========== =========== See Notes to Consolidated Financial Statements. CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31, 1995 1994 COMMON STOCK EQUITY (DEFICIT) - Thousands of Dollars - Common Stock--No Par Value 1995 1994 ----------- ----------- Shares Authorized 200,000,000 200,000,000 Shares Outstanding 160,671,157 160,723,702 Warrants Outstanding * 12,054,278 12,054,278 $ 645,295 $ 645,479 Capital Stock Expense (6,357) (6,357) Accumulated Deficit (626,450) (681,355) ----------- ----------- Total Common Stock Equity (Deficit) 12,488 (42,233) ----------- ----------- PREFERRED STOCK, No Par Value, 1,000,000 Shares Authorized, None Outstanding - - CAPITAL LEASE OBLIGATIONS Springerville Unit 1 466,187 458,092 Springerville Common Facilities 136,128 139,076 Irvington Unit 4 142,878 143,407 Valencia Coal Handling Facilities 179,990 187,523 Other Leases 6,164 7,440 ----------- ----------- Total Capital Lease Obligations 931,347 935,538 Less Current Maturities (33,389) (12,803) ----------- ----------- Total Long-Term Capital Lease Obligations 897,958 922,735 ----------- ----------- LONG-TERM DEBT Interest Issue Maturity Rate - ----------------------------------------------------- First Mortgage Bonds Corporate 1995 - 2009 4.55% to 12.22% 253,750 269,750 Industrial Development 2005 - 2025 6.10% to 8.25% Revenue Bonds (IDBs) and variable** 232,200 232,200 Loan Agreements (IDBs) 2003 - 2022 6.25% and variable** 702,585 703,600 Renewable Term Loan 1997 - 1999 variable** 31,000 - Term Loan (See Note 5) variable** - 193,400 Promissory Note 1995 8.00% - 152 ----------- ----------- Total Stated Principal Amount 1,219,535 1,399,102 (continued on next page) CONSOLIDATED STATEMENTS OF CAPITALIZATION (Continued) Less Current Maturities (12,075) (17,167) ----------- ----------- Total Long-Term Debt 1,207,460 1,381,935 ----------- ----------- Total Capitalization $2,117,906 $2,262,437 =========== =========== * The Warrants to purchase Common Stock at an exercise price of $3.20 per share, are exercisable and expire in 2002. ** Interest rates on variable rate tax-exempt debt (IDBs) ranged from 1.65% to 5.75% during 1995 and 1994, and the average interest rate on such debt was 3.91% in 1995 and 2.96% in 1994. Interest rates on the Term Loan ranged from 3.63% to 6.75% in 1995 and 1994, and the average interest rate on such debt was 6.50% in 1995 and 4.92% in 1994. See Notes to Consolidated Financial Statements. CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT) Capital Accumulated Common Stock Earnings Stock Expense (Deficit) ---------------------------------- - Thousands of Dollars - Balances at December 31, 1992 $644,427 $(6,357) $(676,279) 1993 Net Loss - - (25,816) Sale of 294,050 Shares of Treasury Stock 1,052 - - --------- -------- ---------- Balances at December 31, 1993 645,479 (6,357) (702,095) 1994 Net Income - - 20,740 --------- -------- ---------- Balances at December 31, 1994 645,479 (6,357) (681,355) 1995 Net Income - - 54,905 52,545 Shares Purchased by Deferred Compensation Trust (184) - - --------- -------- ---------- Balances at December 31, 1995 $645,295 $(6,357) $(626,450) ========= ======== ========== See Note 5. Long-Term Debt - Dividends - Restrictive Covenants for discussion of restrictions on the Company's ability to pay dividends. See Notes to Consolidated Financial Statements. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - ---------------------------------------------------------------------------- NATURE OF OPERATIONS The Company is a public utility engaged in the business of generation, transmission, distribution and sale of electricity. The Company's retail service area encompasses 1,155 square miles in Pima and Cochise counties in Southern Arizona. The Company also engages in wholesale sales to other utilities in Arizona, California, Colorado, New Mexico, Oregon, Texas and Utah. Approximately 63% of the Company's work force is subject to a collective bargaining unit. The collective bargaining agreement in place at December 31, 1995 terminates on December 1, 1996. BASIS OF PRESENTATION The consolidated financial statements include the accounts of the Company, four wholly-owned, utility-related subsidiaries and two investment subsidiaries on a consolidated basis. All significant intercompany balances and transactions have been eliminated in the consolidation. The results of operations, estimated net realizable value of net assets and cash flows of the Company's two investment subsidiaries were classified as discontinued operations from June 30, 1990 until December 31, 1994. See Note 4. USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. REGULATION The Company's utility accounting practices and electricity rates are subject to regulation by the ACC and, in certain areas, by the FERC. ACCOUNTING FOR THE EFFECTS OF REGULATION The Company prepares its financial statements in accordance with the provisions of FAS 71. A regulated enterprise can prepare its financial statements in accordance with FAS 71 only if (i) the enterprise's rates for regulated services are established by or subject to approval by an independent third-party regulator, (ii) the regulated rates are designed to recover the enterprise's costs of providing the regulated services and (iii) in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates set at levels that will recover the enterprise's costs can be charged to and collected from customers. FAS 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements. In certain circumstances, FAS 71 requires that certain costs and/or obligations (such as incurred costs not currently recovered through rates, but expected to be so recovered in the future) be reflected in a deferral account in the balance sheet and not be reflected in the statement of income or loss until matching revenues are recognized. It is the Company's policy to assess the recoverability of costs recognized as regulatory assets and the Company's ability to continue to account for its activities in accordance with FAS 71, based on each rate action and the criteria set forth in FAS 71. The Company's Consolidated Balance Sheets at December 31, 1995 and 1994 contain certain amounts solely as a result of the application of FAS 71: Assets (Liabilities) 1995 1994 -------------------- ----- ----- - Millions of Dollars - Income Taxes Recoverable Through Future Rates $136 $143 Deferred Common Facility Costs 63 66 Deferred Springerville Unit 2 Costs 42 55 Deferred Lease Expense 20 25 Other Deferred Charges 9 15 MSR Option Gain Regulatory Liability (26) (41) Deferred Investment Tax Credits (20) (24) Other Deferred Credits (10) (1) Regulatory assets are recorded based on prior rate orders issued by the ACC which provide a mechanism for recovery in regulated rates or historical rate treatment which provides evidence as to the probability of future rate recovery. The material regulatory assets listed above earn either a return on investment through inclusion in rate base or earn a set rate of interest stipulated by the ACC. A number of accounts in the Company's Consolidated Statements of Income (Loss) for the three years in the period ended December 31, 1995 also reflect the application of FAS 71: Income (Expense) 1995 1994 1993 ---------------- ----- ----- ----- - Millions of Dollars - Amortization of MSR Option Gain Regulatory Liability $ 20 $ 20 $ 6 Amortization of Springerville Unit 2 Rate Synchronization (14) (14) - Deferred Fuel and Purchased Power (6) (7) (11) Amortization of Deferred Common Facility Costs (3) (3) (3) Deferred Springerville Unit 2 Carrying Costs 1 1 5 Regulatory Disallowances and Adjustments - - (14) Investment Tax Credit Amortization 5 5 5 Interest Imputed on Loss (MSR Option Gain Regulatory Liability) Recorded at Present Value (4) (6) (7) If the Company had not applied the provisions of FAS 71 in these years, each of these amounts appearing in the Consolidated Statements of Income (Loss) would have been reflected in the Consolidated Statements of Income or Loss in prior periods, except for two items which would not have been recorded: 1) the amortization of the MSR Option Gain Regulatory Liability, including interest imputed on the loss recorded at present value; and 2) the Springerville Unit 2 carrying cost deferrals. Lease expense relating to the capital leases, while the same over the life of the leases, would be recognized at different annual amounts if the Company were to discontinue the application of FAS 71. See Utility Plant Under Capital Leases below. If at some point in the future the Company determines that it no longer meets the criteria for continued application of FAS 71 to all or a portion of the Company's regulated operations, the Company would be required to adopt the provisions of FAS 101 for that portion of the operations for which FAS 71 no longer applied. Adoption of FAS 101 would require the Company to write off its regulatory assets and liabilities as of the date of adoption of FAS 101 and would preclude the future deferral in the Consolidated Balance Sheet of costs not recovered through rates at the time such costs were incurred, even if such costs were expected to be recovered in the future. Based on the balances of the Company's regulatory assets and liabilities as of December 31, 1995, the Company estimates that future adoption of FAS 101, if applied to all of the Company's regulated operations, would result in an extraordinary loss of $145 million, which includes a reduction for the related deferred income taxes of $69 million. The Company's cash flows would not be affected by the adoption of FAS 101. UTILITY PLANT Utility Plant by major classes at December 31, 1995 and 1994 is as follows: 1995 1994 ---------- ---------- - Thousands of Dollars - Utility Plant: Production Plant $1,013,171 $1,002,409 Transmission Plant 460,986 460,055 Distribution Plant 517,999 495,336 General Plant 92,069 84,441 Intangible Plant 10,441 10,238 Electric Plant Held for Future Use 1,013 644 ---------- ---------- Total Utility Plant $2,095,679 $2,053,123 ========== ========== Utility plant is stated at original cost. In accordance with the Uniform System of Accounts prescribed by the FERC and accepted by the ACC, the Company capitalizes AFDC based on the cost of borrowed funds and a reasonable rate upon equity funds used to finance CWIP, when recovery of such costs from ratepayers is probable. The component of AFDC attributable to borrowed funds is presented as a reduction of Interest Expense. The Consolidated Statements of Income (Loss) reflect no AFDC - Equity as all construction expenditures were deemed under FERC prescribed rules to be financed with debt. In 1995, 1994 and 1993, gross AFDC rates of 5.59%, 4.94% and 4.85%, respectively, were used for all CWIP. Depreciation is computed on a straight-line basis at component rates which are based on the economic lives of the assets. These component rates, which are authorized by the ACC, averaged 3.79%, 3.73% and 3.68% in 1995, 1994 and 1993, respectively. The economic lives for production plant are based on remaining lives. The economic lives for transmission plant, distribution plant, general plant and intangible plant are based on average lives. The component rates also reflect estimated removal costs, net of estimated salvage value. Minor replacements and repairs are expensed as incurred. Retirements of utility plant, together with removal costs less salvage, are charged to accumulated depreciation. UTILITY PLANT UNDER CAPITAL LEASES The Company's leases of the Springerville Common Facilities, Springerville Unit 1, Valencia coal handling facilities and Irvington Unit 4 are classified as capital leases in the Consolidated Balance Sheets. For rate making purposes, the ACC treats these leases as operating leases and has allowed for recovery of the lease costs by straight-line amortization of the total amount of lease rent payments over the primary term of the leases, except for the Valencia coal handling facilities lease. The Valencia coal handling facilities lease is being amortized on a straight-line basis over the primary term of the lease plus the first optional renewal period of six years to reflect the recovery period mandated by the ACC. Under GAAP, the lease term would have been only the primary term of the lease. Interest and depreciation relating to the leases are recorded as expense on a basis which reflects the regulatory straight-line treatment. The amount of lease amortization incurred for the four above-described leases, as well as the Company's remaining leases, for the years 1995, 1994 and 1993 amounted to: Years Ended December 31, 1995 1994 1993 ----- ----- ----- - Millions of Dollars - Lease Amortization: Interest $ 97 $ 94 $ 93 Depreciation 14 13 12 ---- ---- ---- Total Lease Amortization $111 $107 $105 ==== ==== ==== Lease Amortization Included In: Operating Expenses - Fuel and Purchased Power $ 20 $ 20 $ 17 Operating Expenses - Capital Lease Expense 95 93 93 Balance Sheet - Deferred Lease Expense (4) (6) (5) ----- ----- ---- Total Lease Amortization $111 $107 $105 ===== ===== ==== The Deferred Lease Expense of $20 million and $25 million at December 31, 1995 and 1994, respectively, reflects: 1) the cumulative difference between the straight-line method of amortizing the leases for regulatory purposes and capital lease amortization as promulgated by GAAP; and 2) the balance of the deferred costs described under Fuel and Purchased Power Costs below. Also, see Springerville Unit 1 Allowance below. SPRINGERVILLE UNIT 1 ALLOWANCE In the 1989 Rate Order the ACC limited recovery through retail rates of non-fuel expenses of Springerville Unit 1 to a rate of only $15 per kW per month. Such costs averaged approximately $22 per kW per month during 1995, 1994 and 1993. Consequently, in 1990 and 1992, the Company recorded losses, Springerville Unit 1 Allowance, equal to the present value of the excess of the Company's costs estimated to be incurred during the period through 2014, the term of the lease, over $15 per kW per month using a discount rate of 13%. The balance sheet contra asset Springerville Unit 1 Allowance increases each year by the accrual of interest and decreases by the amount which is amortized to income as a contra-expense, Amortization of Springerville Unit 1 Allowance. In 1995, 1994 and 1993, the accrual of such interest was $28.2 million, $25.9 million and $24.2 million, respectively, and the amount amortized was $28.4 million, $26.2 million and $33.4 million, respectively. The imputed interest expense associated with this liability, calculated using a 13% discount rate, is included as part of Interest Imputed on Losses Recorded at Present Value in the Interest Expense section in the Consolidated Statements of Income (Loss). DEFERRED COMMON FACILITY COSTS Springerville Common Facility Costs are lease costs and operating costs incurred for the Springerville Common Facilities during the period after Springerville Unit 1 was placed in service and before Springerville Unit 2 was placed in service. Pursuant to an accounting order from the ACC, these costs were deferred and are being amortized, as depreciation, over the primary term of the Springerville Common Facilities Leases. The ACC has allowed for the recovery of the amortization costs plus a return on investment. UTILITY OPERATING REVENUES Operating Revenues include accruals for unbilled revenues, thereby recognizing revenue that is earned, but not billed, at the end of an accounting period. MSR OPTION GAIN REGULATORY LIABILITY In the 1989 Rate Order the ACC allocated to retail customers a portion of the price paid to the Company upon the 1982 sale of an option to purchase a 28.8% interest in San Juan Unit 4, asserting that such option was related to an interconnection agreement which the Company also entered into with MSR at that time. The ACC ordered the Company to recognize the MSR Option Gain by amortizing amounts to operating revenue through 1997. Therefore, in 1990, the Company recorded a loss, MSR Option Gain Regulatory Liability, equal to the present value of the amount to be amortized to operating revenues through 1997, calculated using a 13% discount rate. The MSR Option Gain Regulatory Liability increases each year by the accrual of interest and decreases by the amount which is amortized to operating revenues. In 1995, 1994 and 1993, the accrual of such interest was $4.4 million, $6.4 million and $7.1 million, respectively, and the amount amortized was $20.1 million, $20.1 million and $6.1 million, respectively. The imputed interest expense associated with this liability, calculated using a 13% discount rate, is included as part of Interest Imputed on Losses Recorded at Present Value in the Interest Expense section in the Consolidated Statements of Income (Loss). FUEL AND PURCHASED POWER COSTS Fuel inventory, primarily coal, is stated on a basis which approximates weighted average cost. The Company utilizes full absorption costing. Certain lease and interest costs incurred by Valencia, the Company's fuel-handling and procurement subsidiary for Springerville, are accounted for as deferred costs. These costs are being amortized to fuel expense on a straight-line basis through the year 2030 pursuant to the 1994 Rate Order. INCOME TAXES In January 1993, the Company adopted Statement of Financial Accounting Standards No. 109 (FAS 109), Accounting for Income Taxes, on a prospective basis. FAS 109 requires the recognition of deferred income tax liabilities and assets for the expected future income tax consequences of temporary differences between the carrying amounts and the tax bases of other assets and liabilities. The adoption of FAS 109 increased both total assets and total liabilities of the Company by $149 million in 1993. The increase in assets results primarily from the recording of a regulatory asset, Income Taxes Recoverable Through Future Rates. Such regulatory asset consists primarily of the right to recover income taxes relating to previously flowed- through differences, both timing and permanent, which provided rate benefits to past ratepayers. The increase in liabilities is primarily the net increase in deferred income tax assets and deferred income tax liabilities resulting from the adoption of FAS 109. Reductions in federal income taxes resulting from ITC relating to utility operations have been deferred. As authorized by the ACC, these amounts are amortized over the tax lives of the related property. As the Company was in a net operating loss carryforward position and generating tax losses, the income tax benefits reflected in the Consolidated Statements of Income (Loss) for the years 1994 and 1993 resulted only from such ITC amortization. In 1995, income tax benefits include the recognition of a portion of the Company's net operating loss carryforwards, as well as ITC amortization. See Note 3. Income taxes are allocated to the subsidiaries based on contributions to the consolidated tax return liability. The investment subsidiaries' losses in 1994 and 1993 provided no tax benefits to the consolidated group and, therefore, no tax benefits are recorded as a reduction of the 1993 Provision for Loss on Disposal of Discontinued Operations in the Consolidated Statements of Income (Loss). EPA ALLOWANCES Purchased Emission Allowances are recorded in a noncurrent inventory account included in Investments and Other Property on the Consolidated Balance Sheet at December 31, 1995. Emission Allowance inventory is recorded using the weighted average cost method. Gains on sales of Emission Allowances are deferred (included as part of Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheet at December 31, 1995) and will be amortized as income in 2000 - 2024, the period the Company expects to use the Emission Allowance inventory to meet EPA regulations. The amortization reflects the expected regulatory treatment for the gains. FAIR VALUE OF FINANCIAL INSTRUMENTS The carrying value and fair value at December 31, 1995 and 1994 of the Company's financial instruments are as follows: 1995 1994 ------ ------ Carrying Fair Carrying Fair Value Value Value Value -------- ----- -------- ----- - Thousands of Dollars - Assets: Cash and Cash Equivalents $ 85,094 $ 85,094 $ 233,300 $ 233,300 Debt Securities (Included in Investments and Other Property) 17,713 18,267 - - Liabilities: Short-Term Debt (12,039) (12,039) - - Long-Term Debt, Including Current Portion (See Note 5) (1,219,535) (1,233,457) (1,399,102) (1,372,236) The carrying amounts of Cash and Cash Equivalents and Short-Term Debt are considered to be reasonable estimates of the fair value of each because of the short maturity of those instruments. The Company intends to hold the investment in Debt Securities to maturity (January 1, 2013.) Such Debt Securities are stated at amortized cost, adjusted for the amortization of the discount to maturity, and the fair value is based on current transactions for the same or similar debt. RECLASSIFICATION Minor reclassifications have been made to the prior year financial statements presented to conform to the current year's presentation. NEW ACCOUNTING STANDARDS In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 121 (FAS 121), Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. This statement requires that an asset be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Company adopted FAS 121 on January 1, 1996, and does not expect the application of FAS 121 to have a material impact on the Company's financial statements. This conclusion may change in the future depending on the extent that the Company's regulated and non- regulated operations are influenced by an increasingly competitive environment. In October 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 123 (FAS 123), Accounting for Stock-Based Compensation. This statement encourages, but does not require, companies to adopt a new accounting method for stock-based compensation awards. Under the new method, an expense is recorded for stock compensation awards based on the estimated fair value of the award at the grant date. The cost of the award is reflected as an expense over the period that the stock option vests. Companies that continue to follow existing standards and do not adopt the valuation method prescribed by FAS 123 are required to disclose pro forma net income and earnings per share as if the company had recognized expense based on FAS 123. Beginning with the 1996 financial statements, companies will be required to meet these disclosure requirements for any awards made in 1995 and after. The Company plans to continue to follow existing standards (APB Opinion 25), rather than adopt FAS 123, for measurement and recognition of stock-based compensation. The Company will adopt the disclosure requirements of FAS 123 in 1996. NOTE 2. RATE MATTERS - --------------------- 1995 RATE INCREASE APPLICATION On June 13, 1995, the Company filed an application with the ACC for an overall 4.9% or approximately $28.4 million rate increase. The Company's rate request sought recovery of the operating and capital costs of the remaining 37.5% of Springerville Unit 2 which is not currently being recovered. On November 30, 1995, the Company entered into the Proposed Settlement Agreement with the ACC Staff, subject to final approval by the ACC, that would have provided an overall 2% or approximately $10.4 million rate increase including recovery of the remaining 37.5% of Springerville Unit 2. The Company is not presently recovering through retail rates the depreciation, property taxes, operating and maintenance expenses other than fuel, or interest costs associated with the 37.5% of Springerville Unit 2 capacity which was not considered to be used and useful for the retail jurisdiction at the time of the 1994 Rate Order and therefore was not included in rate base (hereinafter referred to as "retail excess capacity deferrals"). These expenses are being expensed as incurred. However, the 1994 Rate Order permits such costs to be deferred for future recovery over the remaining useful life of Springerville Unit 2. This phase-in plan does not qualify under FAS 92 and, therefore, such retail excess capacity deferrals, while deferred for regulatory purposes, cannot be deferred for financial reporting purposes. Such regulatory deferrals associated with the excluded Springerville Unit 2 capacity, not included in the financial statements, totaled $78 million at December 31, 1995. Either inclusion in costs recoverable through retail rates or additional wholesale sales at sufficient prices of an equivalent amount of capacity (or a combination thereof) will be required to recover these retail excess capacity deferrals. The ACC denied the Proposed Settlement Agreement on January 19, 1996. The Company's application for a rate increase remains pending. The Company intends to propose and seek ACC approval of a revised settlement agreement in March 1996. 1994 RATE ORDER Effective January 11, 1994, the ACC authorized a 4.2% increase in base rates. The 1994 Rate Order recognized that an additional 17.5% of the Springerville Unit 2 capacity was used and useful for the retail jurisdiction, which lowered the percentage of that unit's capacity that is not in rate base to 37.5%. As a result of the 1994 Rate Order, the retail excess capacity deferrals allocable to the 62.5% of Springerville Unit 2 capacity allowed in rate base was also included in rate base. At December 31, 1993, the retail excess capacity deferrals allocable to the 17.5% of the Springerville Unit 2 capacity amounted to $17 million. As specified in the 1994 Rate Order, for rate purposes, these costs are being recovered over a 37.4 year period. The 1994 Rate Order allowed in rate base 62.5% of deferred Springerville Unit 2 rate synchronization costs, $42 million at December 31, 1993, which were non-fuel costs of Springerville Unit 2 incurred from January 1, 1991 through October 14, 1991, including an interest carrying charge, deferred pursuant to the 1991 Rate Order. For rate making purposes, such costs are being recovered over a three-year period and are included in Depreciation and Amortization on the Consolidated Statements of Income (Loss), in accordance with the 1994 Rate Order. The Company is not presently recovering through retail rates 37.5% of the deferred Springerville Unit 2 rate synchronization costs ($28 million at December 31, 1995). This amount, together with the balance of such costs ($14 million at December 31, 1995) that the Company is presently recovering through rates, are reported in the Company's Consolidated Balance Sheets as Deferred Springerville Unit 2 Costs. The 1994 Rate Order provided that the rate synchronization and retail excess capacity deferrals associated with the 37.5% of Springerville Unit 2 capacity not found to be used and useful for the retail jurisdiction will continue to incur an interest charge of 7.19% until authorized to be included in rate base or for a period of three years ending in 1997, whichever occurs first. The 1994 Rate Order disallowed recovery of $13.6 million of previously capitalized Springerville Unit 2 rate synchronization costs and certain other costs. The $13.6 million is comprised of $5.2 million for wholesale power sale revenue credits which the Company had offset against the off-balance sheet retail excess capacity deferrals which the ACC stated should have been offset against the rate synchronization deferrals. The remaining $8.4 million of disallowance results from the ACC's finding that the Company should have calculated the 7.19% carrying charge on a net-of-tax basis rather than pre-tax, as calculated by the Company. Such disallowances are reflected in Regulatory Disallowances and Adjustments in the Consolidated Statement of Income (Loss) for the year ended December 31, 1993. NOTE 3. INCOME TAXES - --------------------- Deferred tax assets (liabilities) are comprised of the following: December 31, 1995 1994 ----------- ---------- - Thousands of Dollars - Gross Deferred Income Tax Liabilities: Electric Plant - Net $(563,884) $(558,509) Regulatory Asset (Income Taxes Recoverable Through Future Rates) (54,904) (57,902) Deferred Springerville Unit 2 Costs (16,974) (22,206) Deferred Valencia Inventory Costs (21,654) (21,780) Deferred Lease Payments (14,791) (15,510) Property Taxes (10,476) (10,465) Deferred Fuel - (2,372) Other (7,357) (6,016) ---------- ---------- Gross Deferred Income Tax Liability (690,040) (694,760) ---------- ---------- Gross Deferred Income Tax Assets: Capital Lease Obligations 375,897 377,825 Tax Operating Loss Carryforwards 197,100 199,564 Springerville Unit 1 Disallowed Costs 65,491 65,597 Investment in Loans and Partnerships 12,576 7,757 Investment Tax Credit Carryforwards 26,396 28,088 MSR Option Gain Regulatory Liability 10,342 16,645 Capital Loss Carryforwards 8,572 19,078 Lease Interest Payable 17,626 17,429 Deferred Regulatory Capital Lease Expense 13,980 11,397 Financial Restructuring Costs Not Yet Deductible for Tax Purposes 7,907 8,034 Gain on Financial Restructuring of Long-Term Debt 5,374 6,458 Alternative Minimum Tax 3,044 2,343 Other 26,789 27,166 ---------- ---------- Gross Deferred Income Tax Asset 771,094 787,381 Deferred Tax Assets Valuation Allowance (208,786) (244,092) ---------- ---------- Net Deferred Income Tax Liability $(127,732) $(151,471) ========== ========== The decrease of approximately $35 million in the gross deferred tax assets valuation allowance in 1995 is primarily due to an increase in the estimate of future income to be earned and the utilization of tax operating loss carryforwards and capital loss carryforwards. This adjustment reduced income tax expense for the current year. Previously the Company had provided a full deferred tax assets valuation allowance against the tax operating loss carryforwards, investment tax credit carryforwards and capital loss carryforwards due to the uncertainty of their future use. Because the Company's results from operations have been steadily improving and have been positive for the last two years, the Company believes it is more likely than not that the Company will realize at least $66.5 million of the total federal NOL carryforwards of $508 million. Accordingly, the Company recognized a $23 million income tax benefit related to the expected utilization of $66.5 million of tax operating loss carryforwards which is included in Income Taxes in Other Income (Deductions) in the Consolidated Statement of Income (Loss). The decrease of approximately $20 million in the gross deferred tax assets valuation allowance in 1994 primarily resulted from the sale of the discontinued operation's assets (see Note 4) which had corresponding deferred tax assets, which were fully reserved by the valuation allowance. The net deferred income tax liability is included in the Consolidated Balance Sheets in the following accounts: December 31, 1995 1994 ---------- ---------- - Thousands of Dollars - Deferred Income Taxes - Current $ 18,250 $ 12,870 Deferred Income Taxes - Noncurrent (145,982) (164,341) ---------- ---------- Net Deferred Income Tax Liability $(127,732) $(151,471) ========== ========== The benefit for income taxes included in the Consolidated Statements of Income (Loss) consists of the following: Years Ended December 31, 1995 1994 1993 ---------- ---------- ---------- - Thousands of Dollars - Current Tax Expense Federal $ (4,439) State (683) ---------- ---------- ---------- Total Current Tax Expense (5,122) ---------- ---------- ---------- Deferred Tax Expense Federal (4,429) State (681) ---------- ---------- ---------- Total Deferred Tax Expense (5,110) ---------- ---------- ---------- Reduction in Valuation Allowance - Benefit 23,282 Investment Tax Credit Amortization 4,766 $ 4,911 $ 5,277 Other 2,620 - - ---------- ---------- ---------- Total Benefit for Federal and State Income Taxes $ 20,436 $ 4,911 $ 5,277 ========== ========== ========== The differences between income tax benefit and the amount obtained by multiplying income (loss) before income taxes by the U.S. statutory federal income tax rate are as follows: Years Ended December 31, 1995 1994 1993 ---------- ---------- ---------- - Thousands of Dollars - Federal Income Tax (Expense) Benefit at Statutory Rate $ (12,064) $ (5,540) $ 10,883 State Income Tax Expense, Net of Federal Deduction (1,364) - - Investment Tax Credit Amortization 4,766 4,911 5,277 Reduction in Valuation Allowance - Benefit 23,282 - - Loss for Which No Tax Benefit is Available - - (10,883) Net Operating Loss Carryforwards 5,122 5,540 - Capital Loss Carryforwards 1,045 - - Other (351) - - ---------- ---------- ---------- Total Benefit for Federal and State Income Taxes $ 20,436 $ 4,911 $ 5,277 ========== ========== ========== At December 31, 1995, the Company had, for federal income tax purposes, approximately $508 million of net operating loss carryforwards expiring in 2004 through 2009 and $148 million of alternative minimum tax loss carryforwards expiring in 2006 through 2008. For state income tax purposes, the Company has approximately $215 million of net operating loss carryforwards expiring in 1996 through 1999. In addition, for federal income tax purposes the Company has $26 million of unused ITC, the use of which will expire during 2002 through 2005, $3 million of alternative minimum tax credit which will carry forward to future years, and $21 million of capital loss carryforwards which expire during 1996 through 1999. Due to the Financial Restructuring, the Company experienced a change in ownership under section 382 of the Internal Revenue Code in December 1991. As a result of that change, the amount of the taxable income for any post- change year which may be offset by pre-change net operating losses will be limited to the section 382 limitation. The section 382 limitation is based on the value of the Company on the ownership change date. The Company estimates an annual section 382 limit of approximately $23 million. The total section 382 limitation may be increased to the extent of gain recognized on sales of assets whose fair market value was greater than tax basis at the ownership change date, the built-in-gain. The section 382 limitation may increase by built-in-gain recognized within a period of five years after the change in ownership. During 1992 through 1995, the section 382 limitation increased by approximately $102 million of built-in-gain recognized due to asset sales. Unused section 382 limitation may be carried forward until the pre-change tax attributes expire. At December 31, 1995, the Company had pre-change federal net operating loss, ITC, capital loss and alternative minimum tax loss carryforwards of approximately $351 million, $26 million, $7 million and $115 million, respectively. NOTE 4. CONSOLIDATED SUBSIDIARIES - ---------------------------------- NATIONS ENERGY CORPORATION In 1995 the Company established Nations Energy (formerly known as Escalante Resources Inc.) for the purpose of investing in independent power projects in the domestic and foreign energy markets. The 1995 consolidated financial statements reflect the accounts of Nations Energy, a wholly-owned subsidiary of the Company. In September 1995, Nations Energy and Trigen Energy Corporation formed a limited partnership and purchased Coors Brewing Company's energy production (utility) assets. Nations Energy has a 49% interest in such partnership. The partnership will provide electricity and steam for the brewery operation in Golden, Colorado. In addition, the partnership expects to upgrade Coors' power plant to improve fuel efficiency and increase capacity. The investment of approximately $12 million by Nations Energy is included in the Company's Consolidated Balance Sheet at December 31, 1995 under Investments and Other Property and in the Company's Consolidated Statement of Cash Flows for the year ended December 31, 1995 as Investment in Partnership. DISCONTINUED OPERATIONS In July 1990, the Boards of Directors of the Company's investment subsidiaries adopted formal plans of liquidation of the investment operations. Pursuant to such actions, investment subsidiaries' results of operations, estimated net realizable value of net assets and cash flows were classified as discontinued operations in the Company's consolidated financial statements from June 30, 1990 through December 31, 1994, the date that the liquidation was substantially complete. The Company's Consolidated Statement of Income (Loss) for 1993 includes a $4 million Provision for Loss on Disposal of Discontinued Operations made to reflect further weakening of markets for certain subsidiary investments and increased estimates of holding- period costs for those assets. At December 31, 1994, the Company's Consolidated Balance Sheet reflected $9 million of net assets of discontinued operations comprised mainly of real estate investments. Beginning January 1, 1995, the remaining assets and liabilities are accounted for as a part of continuing operations and are included in the Company's consolidated financial statements. As a result, Short-Term Debt of $12 million on the Consolidated Balance Sheet at December 31, 1995 was previously classified as Net Assets of Discontinued Operations. NOTE 5. LONG AND SHORT-TERM DEBT AND CAPITAL LEASE OBLIGATIONS - --------------------------------------------------------------- LONG-TERM DEBT During 1995 the Company reduced its long-term debt as a result of $17 million of bond and Installment Sale Agreement maturities, a $19 million permanent repayment of the Term Loan and payments totaling $143 million on the Renewable Term Loan. Pursuant to the terms of the Renewable Term Loan, $133 million of the payments on the Renewable Term Loan may be reborrowed, as needed by the Company. First Mortgage Bonds The Company's utility plant, with the exception of Springerville Unit 2, is subject to the lien of the General First Mortgage and the General Second Mortgage. MRA At December 31, 1995, the obligations covered by the provisions of the MRA were the $164 million Renewable Term Loan commitment (of which $31 million was borrowed), LOCs supporting $674 million of IDBs, and the $50 million Revolving Credit commitment (of which no amounts are borrowed). Obligations under the MRA are secured by a first mortgage lien on and security interest in Springerville Unit 2, and, under certain conditions, are secured by $50 million in principal amount of collateral bonds issued under the General Second Mortgage, junior to the General First Mortgage securing the Company's First Mortgage Bonds. In March 1995, the Company and its banks completed an amendment to the MRA which eased certain debt prepayment restrictions and allowed reborrowing of certain Renewable Term Loan prepayments (see Renewable Term Loan below). The amendment allows the Company to optionally prepay non-MRA debt provided certain conditions are met. Such conditions include that $1 of principal outstanding under the Renewable Term Loan is permanently prepaid and the commitment therefore terminated for every $2 used to permanently prepay other debt such as First Mortgage Bonds. In addition to the prepayment provisions, the MRA contains a number of restrictive covenants including, but not limited to, covenants limiting, with certain exceptions, (i) the incurrence of additional indebtedness, including lease obligations, or the prepayment of existing indebtedness, or the guarantee of any such indebtedness, (ii) the incurrence of liens, (iii) the sale of assets or the merger with or into any other entity, (iv) the declaration or payment of dividends on Common Stock or any other class of capital stock, (v) the making of capital expenditures beyond those contemplated in the Company's 1992 ten-year capital budget, and (vi) the Company's ability to enter into sale-leaseback arrangements, operating lease arrangements and coal and railroad arrangements. All of these restrictive covenants described above, other than (i), (iv) and (vi), will be in effect until at least December 1997. The covenants described in (i), (iv) and (vi) will cease to be binding on the Company when both the Renewable Term Loan and the Revolving Credit are paid in full and commitments thereunder terminate, and the Company's senior long-term debt is rated investment grade. In addition, the Company is required pursuant to the MRA to maintain an interest coverage ratio of (a) operating cash flows plus interest paid to (b) interest paid, through the year 2003, ranging from 1.40 to 1 in 1995 and gradually increasing to 2 to 1 in 2000 continuing through the year 2003. For the year ended December 31, 1995, the Company's MRA interest coverage ratio was 2.52 to 1. Dividends - Restrictive Covenants The Company's ability to pay a dividend is restricted by certain covenants in the agreements of certain General First Mortgage Bonds ($184 million at December 31, 1995). These covenants limit the Company's ability to pay dividends on Common Stock until it has positive retained earnings (through future earnings or otherwise) rather than an accumulated deficit (such accumulated deficit was $626 million at December 31, 1995) and the Company's cash flow coverage ratio is greater or equal to a ratio of 2 to 1. As of December 31, 1995, the Company's cash flow coverage ratio was slightly above 2 to 1. The MRA contains, until the Renewable Term Loan and the Revolving Credit are paid in full and commitments thereunder terminate and the Company's senior long-term debt is rated investment grade, a similar dividend restriction based on retained earnings. The Company's senior long-term debt is currently rated below investment grade. Letters of Credit At December 31, 1995 there were $774 million principal amount of variable rate tax-exempt IDBs outstanding. Payment of principal and interest on these bonds is secured by LOCs. The LOCs expire at various dates during the period December 31, 1999 through December 31, 2002. However, all the LOCs could expire by December 31, 2000, including an expiration as early as August 1997, if the Company's senior long-term debt is rated investment grade on certain dates or during certain periods subsequent to December 31, 1996. The reimbursement agreement related to the 1981 Apache B Bonds is secured by First Mortgage Bonds. The weighted average commitment fee on the LOCs is approximately 0.53% through 1997 and increases to 0.82% in 1998, 1.07% in 1999 and thereafter. Renewable Term Loan The Term Loan, on March 7, 1995, was amended and renamed the Renewable Term Loan. As a condition to the amendment becoming effective the Company permanently prepaid $19 million of the Term Loan reducing the outstanding balance from $193 million to approximately $174 million at March 7, 1995. Thus, the initial commitment and outstanding balance of the Renewable Term Loan was approximately $174 million. In May 1995, following the Company's purchase of approximately $18 million of debt securities, the Renewable Term Loan commitment was decreased by $10 million to approximately $164 million to meet the prepayment provisions of the MRA. The Renewable Term Loan commitment amount at March 31, 1997 will be reduced as follows: 20% in 1997, 40% in 1998 and 40% in 1999. Any outstanding Renewable Term Loan balance in excess of the commitment will be payable immediately. The Renewable Term Loan bears interest at a variable rate based on an adjusted eurodollar rate plus 0.5% and the commitment fee is 0.5% of the unused portion. Such rates averaged approximately 6.50%, 4.92% and 4.03% for the years ended December 31, 1995, 1994 and 1993, respectively. Fair Value of Long-Term Debt 1995 1994 Carrying Fair Carrying Fair Value Value Value Value -------- ----- -------- ----- - Thousands of Dollars - First Mortgage Bonds: Corporate $ 253,750 $ 267,902 $ 269,750 $ 256,009 IDBs 1981 Apache B Bonds 100,000 100,000 100,000 100,000 Pollution Control Financing Bonds 112,200 112,276 112,200 102,944 1990 Pima A Bonds 20,000 20,000 20,000 20,000 Loan Agreements: Installment Sale Agreement 48,985 48,679 50,000 46,131 IDBs 653,600 653,600 653,600 653,600 Renewable Term Loan 31,000 31,000 - - Term Loan - - 193,400 193,400 Promissory Note - - 152 152 ---------- ---------- ---------- ---------- $1,219,535 $1,233,457 $1,399,102 $1,372,236 ========== ========== ========== ========== The principal amount of variable rate debt outstanding at December 31, 1995 and 1994 of the 1981 Apache B Bonds, the 1990 Pima A Bonds, the Loan Agreements-IDBs, and the Renewable Term Loan (Term Loan at December 31, 1994) are considered reasonable estimates of their fair value as these are variable interest rate liabilities. The fair value of the Company's fixed rate obligations including the Corporate First Mortgage Bonds, the Pollution Control Financing Bonds, the Installment Sale Agreement and Promissory Note was determined by calculating the present value of the cash flows of each fixed rate obligation. The discount rate used for each calculation was a rate consistent with market yields generally available as of December 1995 for 1995 amounts and December 1994 for 1994 amounts for bonds with similar characteristics with respect to: credit rating, time-to-maturity, and the tax status of the bond coupon for Federal income tax purposes. The use of different market assumptions and/or estimation methodologies may yield different estimated fair value amounts. Authorization To Issue Tax-Exempt Bonds In January 1996, the Company obtained a tax-exempt volume cap allocation from the state of Arizona. The Company's allocation is for approximately $16.7 million to be issued by the Pollution Control Corporation of the county of Coconino in Arizona, for the benefit of the Company. The Company expects to issue such bonds in early April 1996. If the Company were to fail to issue the bonds by such time, the Company would lose its volume cap allocation. The proceeds will be used to reimburse the Company for expenses relating to pollution control facilities at the Company's Navajo generating station. Also, in order for the Company to issue such bonds, the Company will need approval from the ACC. The Company filed a financing application with the ACC on February 14, 1996. CAPITAL LEASE OBLIGATIONS The Irvington Lease has an initial term to January 2011 and provides for renewal periods of two or more years through 2020. The Springerville Common Facilities Leases have an initial term of 2017 for one owner participant and 2021 for the other two owner participants, subject to optional renewal periods of two or more years through 2025. The Springerville Unit 1 Leases have an initial term to January 2015 and provide for renewal periods of three or more years through 2030. The Valencia Leases have an initial term to April 2015 and provide for an initial renewal period of six years, then additional renewal periods of five or more years through 2035. MATURITIES AND SINKING FUND REQUIREMENTS A schedule by years of the aggregate amount of maturities and sinking fund requirements for all long-term borrowings as of December 31, 1995 follows: Expiring Scheduled LOCs Long-Term Supporting Debt Capital Lease IDBs Retirements Obligations Total -------- -------- ------------ ---------- Years ending December 31, - Thousands of Dollars - 1996 $ 12,075 $ 119,155 $ 131,230 1997 8,335 95,019 103,354 1998 15,605 97,200 112,805 1999 $100,000 31,900 120,815 252,715 2000 364,900 83,325 164,121 612,346 -------- -------- ----------- ----------- Total 1996 - 2000 464,900 151,240 596,310 1,212,450 Thereafter 308,700 294,695 1,732,246 2,335,641 Imputed Interest - - (1,397,209) (1,397,209) -------- -------- ----------- ----------- Total $773,600 $445,935 $ 931,347 $2,150,882 ======== ======== =========== =========== The Company expects to refinance the LOCs supporting IDBs at expiration. The above schedule does not include sinking fund requirements for certain First Mortgage Bonds of approximately $1.6 million for each of the next five years. The Company expects to satisfy these sinking fund requirements with pledges of additional property of approximately $3 million each year. Maturities under capital lease obligations for 1999 and 2000 include $25 million and $45 million, respectively, of maturing lease debt that the Company expects to refinance so that the debt payments are extended over the remaining lease term. The capital lease obligations were recorded assuming completion of such refinancing. SHORT-TERM DEBT Revolving Credit The $50 million Revolving Credit, which is part of the MRA, has a termination and maturity date of December 31, 1999. No amounts have been borrowed by the Company under this facility. Revolving Credit borrowings would bear interest at variable rates based upon, at the option of the Company, either (i) prime rate or (ii) an adjusted eurodollar rate plus a margin of 1% in 1996 which gradually increases to 2% by 1998 and thereafter. The Company is required to repay the Revolving Credit in full for at least 30 consecutive days in each twelve-month period prior to November 30 of each year. The annual commitment fee for the Revolving Credit equals 0.5% of the unused portion. Investment Subsidiaries Vehicle contracts receivable and other interests in vehicle contracts receivable held by Brookland are financed through a warehouse line of credit and a loan which totaled approximately $12 million at December 31, 1995 and 1994. The weighted average interest rate applicable to the warehouse line of credit at December 31, 1995 and 1994 was 17%. NOTE 6. COMMITMENTS AND CONTINGENCIES - ------------------------------------- UTILITY CONTRACTUAL MATTERS Coal and Transportation Contracts - Reversal of Accrued Liabilities In 1991 amendments to the contracts with the Springerville coal supplier, the Irvington coal supplier and the Springerville rail transportation suppliers were entered into which, among other things, contained provisions which protected the claims of the suppliers under the original agreements in the event the Company did not perform its obligations under the terms of the amended agreements during the subsequent four year period. In 1995, the Company satisfied all of the conditions of the amended contracts and, consequently, reversed $12 million of accrued liabilities. The reversal of the accrued liabilities reduced Fuel and Purchased Power expense by $12 million in the third quarter of 1995. Fuel Purchase Commitments The Company has contracts to purchase coal for use at Springerville and Irvington. The Springerville coal contract is for the remaining lives of the units with a bilateral option to renegotiate the contract price and escalation procedures in 2009 and every five years thereafter. The Irvington contract termination date is the earlier of 2015 or the remaining life of the coal-fired unit. Both contracts have various adjustment clauses that will affect the future cost of coal delivered. The contracts, in the aggregate, require the Company to take 2.1 million tons of coal per year at an estimated annual cost of $70 million from 1996 to 2009. The Company's contracts to purchase coal for use at the joint projects in which the Company participates expire at various dates from 2005 to 2017 and, in the aggregate, require the Company to take 1.5 million tons of coal per year at an estimated annual cost of $45 million from 1996 to 2005. The Company's contracts to purchase coal for use at Springerville, Irvington and each of the joint projects in which the Company participates contain various provisions calling for the payment of a take-or-pay amount, if certain minimum quantities of coal are not scheduled and delivered. The Company's present fuel requirements are generally in excess of the stated take-or-pay minimum amounts; however, from time to time, the Company has purchased spot market alternative fuels or switched fuel burn from one generating station to another in order to achieve lower overall fuel costs, while incurring take-or-pay minimum charges. As a result, the Company incurred take-or-pay minimum charges of approximately $1 million during 1993. The Company incurred no take-or-pay charges in 1995 or 1994. COMMITMENTS - ENVIRONMENTAL REGULATION In the fall of 1990, Congress adopted certain Federal Clean Air Act Amendments (CAAA) with respect to reductions in sulfur dioxide and nitrogen oxide emissions which will affect the Company's operation. The nitrogen oxide reductions will be based upon EPA regulations finalized in 1995 for certain boilers and expected to be finalized by 1997 for all remaining boilers. In addition, the rules promulgated in 1995 may be revised in 1997. The required reductions of sulfur dioxide emissions will be implemented in two phases which are effective in 1995 and 2000, respectively. The Company is not affected by the requirements for sulfur dioxide emissions and nitrogen oxide reductions which went into effect in 1995 (Phase I), but is subject to the requirements that go into effect January 1, 2000 (Phase II). In Phase II, the maximum sulfur dioxide emission rates are set at 1.2 pounds per million BTU. Because of the Company's general use of low- sulfur coal and installed scrubbers at certain units, the Company's coal- fired generating stations already meet the sulfur dioxide emission rate requirements for Phase II. Additionally, further reductions are to be met through a proposed market-based system. Affected Company generating units will be allocated Emission Allowances based on required emission reductions and past use. Generating station units must hold Emission Allowances equal to their level of emissions or face penalties and a requirement to offset excess tons in future years. In 1993, the EPA allocated Emission Allowances for all Phase I and Phase II affected utility units. An analysis of the Emission Allowances that were allocated to the Company shows that the Company would have sufficient allowances to permit normal plant operation and be in compliance with the sulfur dioxide regulations once the Phase II requirements become effective. However, until all the rulemaking regulation processes for implementing the CAAA are completed, the Company is unable to predict the specific impacts of all such amendments. The CAAA also require multi-year studies of visibility impairment in specified areas and studies of hazardous air pollutants which relate to the necessity of future regulations of electric utility generating units. Since these activities involve the gathering of information not currently available, the Company cannot predict the outcome of these studies. As a result of recent and possible future changes in federal and state environmental laws, regulations and permit requirements, the Company may incur additional costs for the purchase or upgrading of pollution control emission monitoring equipment on existing electric generating facilities and may experience a reduction in operating efficiency. There may be a need for variances from certain environmental standards and operating permit conditions until required equipment and processes for control, handling and disposal of emissions are operational and reliable. Failure to comply with any EPA or state compliance requirements may result in substantial penalties or fines which are provided for by law and which in some cases are mandatory. In 1991, the EPA adopted a rule for the reduction of Navajo's sulfur dioxide emissions on an annual averaging basis by 90% to address visibility impairment at Grand Canyon National Park. The Company estimates that its share of the required capital expenditures remaining as of December 31, 1995 relating to the rule's implementation will be approximately $34 million, including AFDC, through 1999. CONTINGENCIES SDGE/FERC Proceedings San Diego Gas & Electric v. Tucson Electric Power Company On February 11, 1993, SDGE filed a complaint and motion for summary disposition against the Company and Century before the FERC (San Diego Gas & Electric Company v. Tucson Electric Power Company and Century Power Corporation, Docket No. EL93-19-001). The complaint alleged that the Company and Century overbilled SDGE during Phases 3 through 5 of the Ten Year Power Sale Agreement (Ten Year Agreement) and requested that the FERC order refunds by the Company of an aggregate amount of approximately $14.5 million, plus interest. The Company and SDGE have agreed to resolve this dispute by waiving all claims under the Ten Year Agreement and dismissing all proceedings relating thereto. An Offer of Settlement was approved by FERC on January 18, 1996. Alamito Company, Docket No. ER79-97-009 On September 27, 1993, SDGE filed a motion for decision by the FERC in Alamito Company, Docket No. ER79-97-009. This proceeding involved the proper capital structure and rate of return for rates under which Century Power Corporation (formerly Alamito Company) sold Company system power to SDGE during Phase 5 of the Ten Year Agreement, from June 1, 1987 through May 31, 1989. SDGE claimed that the Company would owe Century on SDGE's behalf up to approximately $12 million, plus interest. SDGE moved to dismiss all appeals relating to the SDGE/FERC Proceedings described herein on February 23, 1996. Tax Assessments The Arizona Department of Revenue has issued transaction privilege tax assessments to the Company for the period November 1985 through May 1993 alleging that Valencia is liable for sales tax on gross income received from coal sales, transportation, and coal-handling services to the Company during such period. The Company protested the assessments. On March 11, 1994, the Arizona Tax Court issued a Minute Entry granting Summary Judgment to the Arizona Department of Revenue and upholding the validity of the assessment issued for the period November 1985 through March 1990. The Company appealed this decision to the Court of Appeals. Generally, Arizona law requires payment of the assessment due prior to the appellate process. To date the Company has paid, under protest, a total of $23 million ($14.6 million in 1995, $2.8 million in 1994 and $5.6 million in 1993) of the disputed sales tax assessments, subject to refund in the event the Company prevails. Also, the Arizona Department of Revenue has issued transaction privilege tax assessments to the lessors from whom the Company leases certain property. The assessments allege sales tax liability on a component of rents paid by the Company on the Springerville Unit 1 Leases, Springerville Common Facilities Leases, Irvington Lease and Valencia Leases. Assessments cover the period August 1, 1988 to September 30, 1993. Under the terms of the lease agreements, if the Arizona Department of Revenue prevails the Company must reimburse the lessors for taxes paid by them pursuant to indemnification provisions. In the opinion of management, the Company has recorded, through the Consolidated Statements of Income (Loss) in current and prior years, a liability for the amount of federal and state taxes and interest thereon for which the Company feels incurrence is probable as of December 31, 1995. In the event that all or most of the Arizona Department of Revenue's proposed assessments are sustained, additional liabilities would result. Based on the current status of the legal proceedings, the Company believes that the ultimate resolution of such disputes will occur over a period of one to four years. Although it is reasonably possible that the ultimate resolution of such matters could result in a loss of up to approximately $27 million in excess of amounts accrued, management and outside tax counsel believe that the Company has meritorious defenses to mitigate or eliminate the assessed amounts. Based on consultations with counsel, the Company believes that the resolution of the tax matters described herein should not have a material adverse effect on the Company's Consolidated Financial Statements. NOTE 7. JOINTLY OWNED FACILITIES - --------------------------------- At December 31, 1995, the Company's interests in jointly owned generating and transmission facilities were as follows: Percent Plant Construction Owned By in Work in Accumulated Company Service Progress Depreciation ----------- -------- ------------ ------------ - Thousands of Dollars - San Juan Units 1 and 2 50.0 $294,456 $ 4,492 $204,250 Navajo Station 7.5 78,016 16,082 39,165 Four Corners Units 4 and 5 7.0 77,078 264 51,535 Transmission Facilities 7.5 to 95.0 204,213 1,853 95,182 -------- ------- -------- Total $653,763 $22,691 $390,132 ======== ======= ======== The Company has financed or provided funds for the above facilities and its share of operating expenses is included in the Consolidated Statements of Income (Loss). NOTE 8. EMPLOYEE BENEFITS PLANS - -------------------------------- PENSION PLANS The Company has noncontributory pension plans for all regular employees. Benefits are based on years of service and the employee's average compensation. The Company makes annual contributions to the plans that are not greater than the maximum tax deductible contribution and not less than the minimum funding requirement by the Employee Retirement Income Security Act of 1974. Contributions are intended to provide for both current and future accrued benefits. The following table sets forth the plans' funded status and amount recognized in the Company's Consolidated Financial Statements at December 31, 1995 and 1994. The actuarial present value of the benefit obligation and reconciliation of funding status at October 1, were as follows: 1995 1994 -------- -------- - Thousands of Dollars - Accumulated Benefit Obligation Vested $75,014 $46,679 Non-Vested 5,447 6,318 -------- -------- Total $80,461 $52,997 ======== ======== Plan Assets at Fair Value, Principally Equity and Fixed Income Securities $93,317 $77,021 Projected Benefit Obligation (91,414) (67,393) -------- -------- Plan Assets in Excess of Projected Benefit Obligation 1,903 9,628 Unrecognized Net Gain from Past Experience (8,136) (10,549) Prior Service Cost Not Yet Recognized in Net Periodic Pension Cost 9,410 5,198 Unrecognized Net Assets at Transition Being Amortized Over 15 Years (1,729) (2,017) -------- -------- Prepaid Pension Cost Included in the Balance Sheet $ 1,448 $ 2,260 ======== ======== The increases in the Accumulated Benefit Obligation and Projected Benefit Obligation from 1994 to 1995 reflect the decrease in the discount rate used from 8.5% in 1994 to 7.5% in 1995 and amendments to the plans which now generally allow an employee to receive a normal retirement benefit if his age and credited years of service equal at least 85. Years Ended December 31, 1995 1994 1993 -------- -------- -------- - Thousands of Dollars - Components of Net Pension Cost Service Cost of Benefits Earned During Period $ 3,236 $ 2,680 $ 1,558 Interest Cost on Projected Benefit Obligation 6,752 5,615 4,689 Actual (Gain) Loss on Plan Assets (8,417) 492 (14,508) Net Amortization and Deferral 532 (6,214) 10,187 -------- -------- -------- Net Periodic Pension Cost $ 2,103 $ 2,573 $ 1,926 ======== ======== ======== Actuarial Assumptions: 1995 1994 1993 ---- ---- ---- Discount Rate - Funding Status 7.5% 8.5% 7.0% Average Compensation Increase 5.0 5.0 5.5 Expected Long-Term Rate of Return on Plan Assets 9.0 9.0 7.5 POSTRETIREMENT BENEFITS OTHER THAN PENSIONS Health care and life insurance benefits are provided for retired employees. All regular employees may become eligible for those benefits if they reach retirement age while working for the Company. Those and similar benefits are provided through an independent administrator handling health claims and insurance companies that offer premiums based on group rates. The Company adopted FAS 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, in 1993. Adoption of FAS 106 resulted in an increase in the Company's annual expense for postretirement benefits of approximately $3 million in 1993. The accumulated postretirement benefit obligation as of January 1, 1993 of $19 million is being amortized to expense over a twenty-year period, in accordance with the provisions of FAS 106. The Company recognizes the FAS 106 periodic benefit cost as expense. In January 1994, the Company was authorized by the ACC to recover through rates the costs of benefits only as payments are made to retired employees; the postretirement benefits are currently funded entirely on a pay-as-you-go basis. Therefore, the Company has not recorded a regulatory asset for the excess of FAS 106 expense over actual benefit payments. 1995 1994 --------- --------- - Thousands of Dollars - Accumulated Postretirement Benefit Obligation Retirees $ (6,993) $ (5,270) Fully Eligible Active Plan Participants (4,273) (3,286) Other Active Participants (13,885) (9,849) --------- --------- Total Accumulated Postretirement Benefit Obligation (25,151) (18,405) Unrecognized Net Loss (Gain) from Past Experience 732 (4,429) Unrecognized Portion of the Transition Obligation Being Amortized Over 20 Years 16,289 17,247 --------- --------- Accrued Postretirement Benefit Cost Included in the Balance Sheet $ (8,130) $ (5,587) ========= ========= Years Ended December 31, 1995 1994 1993 ------- ------- ------- - Thousands of Dollars - Components of Net Postretirement Benefit Cost Service Cost of Benefits Earned During Period $ 838 $ 931 $ 950 Interest Cost on Postretirement Benefit Obligation 1,541 1,395 1,491 Amortization of the Unrecognized Transition Obligation 958 958 958 Amortization of the Unrecognized Gain (152) - - ------- ------- ------- Net Periodic Postretirement Benefit Cost $3,185 $3,284 $3,399 ======= ======= ======= The accumulated postretirement benefit obligation was determined using a 7.0% and 8.5% discount rate for 1995 and 1994, respectively. The health care cost trend rates were assumed to be 9.21% and 10.33% for 1995 and 1994, respectively, gradually declining to 3.88% and 5%, respectively, in 2003 and thereafter. The effect of a one percentage point increase in the assumed health care cost trend rate would increase the accumulated postretirement benefit obligation as of December 31, 1995 by approximately $4 million and the net periodic cost by $0.4 million for 1995. STOCK OPTION PLANS On May 20, 1994, the Shareholders of the Company approved two stock option plans, the 1994 Outside Director Stock Option Plan (Directors' Plan) and the 1994 Omnibus Stock and Incentive Plan (Omnibus Plan). The Directors' Plan provides for the annual grant of 6,000 non- qualified stock options to each eligible director, at an exercise price equal to the market price of the Company's Common Stock at the grant date, beginning January 3, 1995. These options vest ratably and become exercisable in one-third increments on each anniversary date of the grant and expire on the tenth anniversary. The Omnibus Plan allows the Compensation Committee, a committee comprised solely of non-employee directors, to grant any or all of the following types of awards to each eligible employee of the Company: stock options, including incentive stock options, non-qualified stock options and discounted stock options; stock appreciation rights; restricted stock; performance units; performance shares; and dividend equivalents. The total number of shares of the Company's stock which may be awarded under the Omnibus Plan cannot exceed eight million. During 1995 and 1994, the Compensation Committee granted stock options intended to qualify as incentive stock options under the Internal Revenue Code to key employees and to all employees, respectively, at exercise prices greater than or equal to the market price of the Company's Common Stock at the grant date. These options vest ratably and become exercisable in one- third increments on each anniversary date of the grant and expire on the tenth anniversary. Options outstanding under the 1985 Stock Option Plan have exercise prices equal to the market price of the Company's Common Stock at the grant date, are fully exercisable and expire in 1997. No options were exercised and the Company recorded no compensation expense for the plans during 1993 through 1995. The following summarizes the stock option transactions during 1993, 1994 and 1995: 1994 1994 1985 Stock Omnibus Directors' Option Plan Plan Plan ----------- ---------- ---------- Options Outstanding, December 31, 1992 and 1993 37,803 - - Granted - 2,212,364 - Canceled (2,706) - - ----------- ---------- ---------- Options Outstanding, December 31, 1994 35,097 2,212,364 - Granted - 414,579 54,000 Canceled or Expired (26,980) (50,466) (6,000) ----------- ---------- ---------- Options Outstanding, December 31, 1995 8,117 2,576,477 48,000 =========== ========== ========== Option Price Per Share $58.625 $3.25 to $3.125 to $3.563 $3.313 Options Exercisable At December 31, 1993 37,803 - - At December 31, 1994 35,097 - - At December 31, 1995 8,117 720,207 - NOTE 9. QUARTERLY FINANCIAL DATA (unaudited) - ---------------------------------------------- First Second Third Fourth --------- --------- --------- --------- - Thousands of Dollars - (except per share data) 1995 Operating Revenue $142,745 $162,305 $217,787 $147,732 Operating Income 6,748 26,970 84,357 3,980 Net Income (Loss) (14,960) 3,014 60,729 6,122 Net Income (Loss) per Average Share (0.09) 0.02 0.37 0.04 1994 Operating Revenue $146,579 $171,097 $220,486 $153,311 Operating Income 8,259 27,951 64,310 13,882 Net Income (Loss) (14,580) 4,432 40,688 (9,800) Net Income (Loss) per Average Share (0.09) 0.03 0.25 (0.06) Due to seasonal fluctuations in sales, a $16 million net increase in income tax benefits and a one-time $12 million reduction in fuel expenses, the quarterly results are not indicative of annual operating results. See Note 3 regarding the income tax adjustments recorded during the fourth quarter of 1995 and Note 6 regarding the one-time reduction in fuel expenses recorded during the third quarter of 1995. NOTE 10. SUPPLEMENTAL CASH FLOW INFORMATION - -------------------------------------------- For purposes of this statement, the Company defines Cash and Cash Equivalents as cash (unrestricted demand deposits) and all highly liquid investments purchased with a maturity of three months or less related to all of the Company's operations, including discontinued operations. A reconciliation of net income (loss) to net cash flows from continuing operating activities for the three years ended December 31, 1995 follows: 1995 1994 1993 ---------- ---------- ---------- - Thousands of Dollars - Income (Loss) from Continuing Operations $ 54,905 $ 20,740 $ (21,816) Adjustments to Reconcile Income (Loss) from Continuing Operations to Net Cash Flows Depreciation Expense 92,179 89,905 74,184 Taxes Accrued (13,519) 8,946 (2,303) Deferred Income Taxes and Investment Tax Credits - Net (21,136) (4,911) (5,277) Deferred Fuel and Purchased Power 5,872 7,359 10,716 Litigation Settlement - - (5,000) Lease Payments Deferred 32,977 32,024 29,870 Deferred Springerville Unit 2 Costs (1,127) (1,133) (5,359) Regulatory Amortizations, Net of Interest Imputed on Losses Recorded at Present Value (15,852) (13,977) (8,148) Regulatory Disallowances - - 13,777 Other (4,457) (506) 314 Changes in Assets and Liabilities which Provided (Used) Cash Exclusive of Changes Shown Separately Accounts Receivable 4,615 (1,120) (6,014) Accounts Payable (14,599) (413) 1,634 Materials and Fuel (5,973) 343 6,484 Other Current Assets and Liabilities (6,751) 2,384 2,032 Other Deferred Assets and Liabilities 12,256 3,975 4,237 ---------- ---------- ---------- Net Cash Flows - Continuing Operating Activities $ 119,390 $ 143,616 $ 89,331 ========== ========== ========== Non-cash investing and financing activities of the Company that affected recognized assets and liabilities but did not result in cash receipts or payments during the three years ended December 31, 1995 were: 1995 1994 1993 ---------- ---------- ---------- - Thousands of Dollars - Capital Lease Obligations $ 8,095 $ 8,107 $ 10,523 Acquisition of Leased Assets - - 3,385 ITEM 9. -- CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable. PART III ITEM 10. -- DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT DIRECTORS Information concerning Directors is contained under Election of Directors in the Company's Proxy Statement relating to the 1996 Annual Meeting of Shareholders, which information is incorporated herein by reference. EXECUTIVE OFFICERS Executive Officers of the Company who are elected annually by the Company's Board of Directors, are as follows: Executive Officer Name Age Title Since - ------------------ --- ------------------------------- --------- Charles E. Bayless 53 Chairman of the Board, President and Chief Executive Officer (a) 1989 Ira R. Adler 45 Senior Vice President and Chief Financial Officer (b) 1988 James S. Pignatelli 52 Senior Vice President - Business Development (c) 1994 Thomas A. Delawder 49 Vice President - Energy Resources (d) 1985 Gary L. Ellerd 45 Vice President - Operations (e) 1985 Steven J. Glaser 38 Vice President - Wholesale/Retail Pricing and System Planning (f) 1994 Thomas N. Hansen 45 Vice President - Technical Advisor (g) 1992 Karen G. Kissinger 41 Vice President and Controller (h) 1991 George W. Miraben 54 Vice President - Human Resources and Public Affairs (i) 1990 Dennis R. Nelson 45 Vice President, General Counsel and Corporate Secretary (j) 1991 Gerald A. O'Brien 54 Vice President - Customer Services & Marketing (k) 1990 Romano Salvatori 58 Vice President - Independent Power (l) 1994 Susan R. Wallach 48 Vice President - Planning and Development (m) 1990 Kevin P. Larson 39 Treasurer (n) 1994 (a) Charles E. Bayless: Mr. Bayless joined the Company as Senior Vice President and Chief Financial Officer in December 1989. He was elected President and Chief Executive Officer in July 1990 and was elected to the Board of Directors in June 1990. On January 28, 1992, Mr. Bayless was named Chairman of the Board of Directors. Prior to joining the Company, he was Senior Vice President and Chief Financial Officer of Public Service Company of New Hampshire from 1981 through 1989. (b) Ira R. Adler: Mr. Adler joined the Company in 1986 as Manager of Financial Planning. In 1987 he was elected as Vice President and Treasurer of TRI, one of the Company's investment subsidiaries, from which position he resigned in October 1988, when he was elected Treasurer of the Company. He was elected Vice President - Finance and Treasurer in July 1989 and was elected Senior Vice President and Chief Financial Officer in July 1990 and President of TRI and SRI in April 1992. Prior to joining the Company, he was Vice President - Finance of US WEST Financial Services, Inc. (c) James S. Pignatelli: Mr. Pignatelli joined the Company as Senior Vice President in August 1994. Prior to joining the Company, he was President and Chief Executive Officer from 1988 to 1993 of Mission Energy Company, a subsidiary of SCE Corp. (d) Thomas A. Delawder: Mr. Delawder joined the Company in 1974 and thereafter served in various engineering and operations positions. In April 1985 he was named Manager, Systems Operations and was elected Vice President - Power Supply and System Control in November 1985. In February 1991, he became Vice President - - Engineering and Power Supply and in January 1992 he became Vice President - System Operations. In 1994, he became Vice President - Energy Resources. (e) Gary L. Ellerd: Mr. Ellerd joined the Company as Vice President and Controller in January 1985. He was elected Vice President - Services and Chief Information Officer in January 1991 and in January 1992 he became Vice President - - Corporate Information Services and Chief Information Officer. In 1994, he was named Vice President - Retail Customers. In 1995, he was named Vice President - Operations. (f) Steven J. Glaser: Mr. Glaser joined the Company in 1990 as a Senior Attorney in charge of Regulatory Affairs. He was Manager of the Company's Legal department from 1992 to 1994, and Manager of Contracts and Wholesale Marketing from 1994 until elected Vice President - Business Development. In 1995, he was named Vice President - Wholesale/Retail Pricing and System Planning. (g) Thomas N. Hansen: Mr. Hansen joined the Company in December 1992 as Vice President - Power Production. Prior to joining the Company, Mr. Hansen was Century's Vice President - Operations from 1989 and Plant Manager at Springerville from 1987 through 1988. In 1994, he was named Vice President - Technical Advisor. (h) Karen G. Kissinger: Ms. Kissinger joined the Company as Vice President and Controller in January 1991. Prior to joining the Company, she was a Manager with Deloitte & Touche from 1986 through 1989 and a Senior Manager through 1990. (i) George W. Miraben: Mr. Miraben was elected Vice President, Public Affairs, effective March 1990, and named Vice President - Human Resources and Public Affairs in 1994. Prior to joining the Company, he was Director of External Affairs for US WEST Communications' Arizona operation from 1981 through March 1990. j) Dennis R. Nelson: Mr. Nelson joined the Company in 1976. He was manager of the Legal Department from 1985 to 1990. He was elected Vice President, General Counsel and Corporate Secretary in January 1991. (k) Gerald A. O'Brien: Mr. O'Brien joined the Company in 1961. Formerly Manager, Customer and Corporate Services, he was elected Vice President - Customer Services and Human Resources in May 1990 and in January 1992 he became Vice President - Customer Operations. In 1994, he was named Vice President - Operations Support. In 1995, he was named Vice President - Customer Services & Marketing. (l)Romano Salvatori: Mr. Salvatori joined the Company as Vice President - Independent Power in December 1994. Prior to joining the Company, he was Deputy General Manager, Power Generation Business Unit and General Manager, Power Generation Strategic Affairs Division of Westinghouse Electric Corporation from 1990 to 1994, and General Manager, Power Generation Commercial Operations Division from 1990 to 1993. In 1995, he was named President of Nations Energy Corporation, in addition to his responsibilities as Vice President - Independent Power. (m) Susan R. Wallach: Ms. Wallach joined the Company in 1974. Formerly Manager of Accounting Services and Assistant Controller, she was elected Vice President and Treasurer in July 1990. She was named Vice President - Future Marketing/Sales/Planning in 1994. In 1995, she was named Vice President - Planning and Development. (n) Kevin P. Larson: Mr. Larson joined the Company in 1985 and thereafter held various positions in its finance department and at the Company's investment subsidiaries. In January 1991, he was elected Assistant Treasurer of the Company and named Manager of Financial Programs. He was elected Treasurer in August 1994. ITEM 11. -- EXECUTIVE COMPENSATION Information concerning Executive Compensation is contained under Executive Compensation and Other Information in the Company's Proxy Statement relating to the 1996 Annual Meeting of Shareholders, which information is incorporated herein by reference. ITEM 12. -- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT GENERAL At March 1, 1996, the Company had outstanding 160,666,976 shares of Common Stock. As of March 1, 1996, the number of shares of Common Stock beneficially owned by all directors and officers of the Company as a group amounted to less than 1% of the outstanding Common Stock. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS Information concerning the security ownership of certain beneficial owners of the Company is contained under Security Ownership of Certain Beneficial Owners in the Company's Proxy Statement relating to the 1996 Annual Meeting of Shareholders, which information is incorporated herein by reference. SECURITY OWNERSHIP OF MANAGEMENT Information concerning the security ownership of the Directors and Executive Officers of the Company is contained under Security Ownership of Certain Beneficial Owners in the Company's Proxy Statement relating to the 1996 Annual Meeting of Shareholders, which information is incorporated herein by reference. ITEM 13. -- CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None. PART IV ITEM 14. -- EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K Page (a) 1. Consolidated Financial Statements as of December 31, 1995 and 1994 and for Each of the Three Years in the Period Ended December 31, 1995. Independent Auditors' Report 32 Consolidated Statements of Income (Loss) 33 Consolidated Statements of Cash Flows 34 Consolidated Balance Sheets 35 Consolidated Statements of Capitalization 36 Consolidated Statements of Changes in Stockholders' Equity (Deficit) 37 Notes to Consolidated Financial Statements 38 2. Supplemental Consolidated Schedules for the Years Ended December 31, 1993 to 1995. Schedules I to V, inclusive, are omitted because they are not applicable or not required. 3. Exhibits. Reference is made to the Exhibit Index commencing on page 66 (b) Reports on Form 8-K. The Company filed Current Reports on Form 8-K as follows: - Dated December 8, 1995 reporting on a settlement agreement between the Company and the ACC proposing to resolve the Company's application for rate increase and the Company's notice of intent to form a holding company. - Dated January 26, 1996 reporting on the ACC's denial of the Proposed Settlement Agreement. - Dated February 9, 1996 disclosing the ACC's Chief Hearing Officer recommendation regarding the Company's notice of intent to form a holding company. 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. TUCSON ELECTRIC POWER COMPANY Date: March 5, 1996 By Ira R. Adler ------------ IRA R. ADLER Senior Vice President and Principal Financial 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. Date: March 5, 1996 Charles E. Bayless* ------------------------------------ Charles E. Bayless Chairman of the Board, President and Principal Executive Officer Date: March 5, 1996 Ira R. Adler --------------------------- Ira R. Adler Principal Financial Officer Date: March 5, 1996 Karen G. Kissinger* ---------------------------- Karen G. Kissinger Principal Accounting Officer Date: March 5, 1996 Elizabeth Alexander* ------------------------- Elizabeth Alexander Director Date: March 5, 1996 Jose Canchola* ------------------- Jose Canchola Director Date: March 5, 1996 John A. Jeter* ------------------- John A. Jeter Director Date: March 5, 1996 R. B. O'Rielly* -------------------- R. B. O'Rielly Director Date: March 5, 1996 Martha R. Seger* --------------------- Martha R. Seger Director Date: March 5, 1996 Donald G. Shropshire* -------------------------- Donald G. Shropshire Director Date: March 5, 1996 H. Wilson Sundt* --------------------- H. Wilson Sundt Director Date: March 5, 1996 J. Burgess Winter* ----------------------- J. Burgess Winter Director Date: March 5, 1996 By Ira R. Adler -------------- Ira R. Adler as attorney-in-fact for each of the persons indicated EXHIBIT INDEX *3(a) -- Restated Articles of Incorporation, filed with the ACC on August 11, 1994. (Form 10-Q for the quarter ended September 30, 1994, File No. 1-5924--Exhibit 3).) *3(b) -- Bylaws of the Registrant, as amended May 20, 1994. (Form 10-Q for the quarter ended June 30, 1994, File No. 1-5924--Exhibit 3).) *4(a)(1)-- Indenture dated as of April 1, 1941, to The Chase National Bank of the City of New York, as Trustee. (Form S-7, File No. 2-59906--Exhibit 2(b)(1).) *4(a)(2)-- First Supplemental Indenture, dated as of October 1, 1946. (Form S- 7, File No. 2-59906--Exhibit 2(b)(2).) *4(a)(3)-- Second Supplemental Indenture dated as of October 1, 1947. (Form S- 7, File No. 2-59906--Exhibit 2(b)(3).) *4(a)(4)-- Third Supplemental Indenture, dated as of April 1, 1949. (Form S-7, File No. 2-59906--Exhibit 2(b)(4).) *4(a)(5)-- Fourth Supplemental Indenture, dated as of December 1, 1952. (Form S-7, File No. 2-59906--Exhibit 2(b)(5).) *4(a)(6)-- Fifth Supplemental Indenture, dated as of January 1, 1955. (Form S- 7, File No. 2-59906--Exhibit 2(b)(6).) *4(a)(7)-- Sixth Supplemental Indenture, dated as of January 1, 1958. (Form S- 7, File No. 2-59906--Exhibit 2(b)(7).) *4(a)(8)-- Seventh Supplemental Indenture, dated as of November 1, 1959. (Form S-7, File No. 2-59906--Exhibit 2(b)(8).) *4(a)(9)-- Eighth Supplemental Indenture, dated as of November 1, 1961. (Form S-7, File No. 2-59906--Exhibit 2(b)(9).) *4(a)(10)-- Ninth Supplemental Indenture, dated as of February 20, 1964. (Form S-7, File No. 2-59906--Exhibit 2(b)(10).) *4(a)(11)-- Tenth Supplemental Indenture, dated as of February 1, 1965. (Form S-7, File No. 2-59906--Exhibit 2(b)(11).) *4(a)(12)-- Eleventh Supplemental Indenture, dated as of February 1, 1966. (Form S-7, File No. 2-59906--Exhibit 2(b)(12).) *4(a)(13)-- Twelfth Supplemental Indenture, dated as of November 1, 1969. (Form S-7, File No. 2-59906--Exhibit 2(b)(13).) *4(a)(14)-- Thirteenth Supplemental Indenture, dated as of January 20, 1970. (Form S-7, File No. 2-59906--Exhibit 2(b)(14).) *4(a)(15)-- Fourteenth Supplemental Indenture, dated as of September 1, 1971. (Form S-7, File No. 2-59906--Exhibit 2(b)(15).) *4(a)(16)-- Fifteenth Supplemental Indenture, dated as of March 1, 1972. (Form S-7, File No. 2-59906--Exhibit 2(b)(16).) *4(a)(17)-- Sixteenth Supplemental Indenture, dated as of May 1, 1973. (Form S-7, File No. 2-59906--Exhibit 2(b)(17).) *4(a)(18)-- Seventeenth Supplemental Indenture, dated as of November 1, 1975. (Form S-7, File No. 2-59906--Exhibit 2(b)(18).) *4(a)(19)-- Eighteenth Supplemental Indenture, dated as of November 1, 1975. (Form S-7, File No. 2-59906--Exhibit 2(b)(19).) *4(a)(20)-- Nineteenth Supplemental Indenture, dated as of July 1, 1976. (Form S-7, File No. 2-59906--Exhibit 2(b)(20).) *4(a)(21)-- Twentieth Supplemental Indenture, dated as of October 1, 1977. (Form S-7, File No. 2-59906--Exhibit 2(b)(21).) *4(a)(22)-- Twenty-first Supplemental Indenture, dated as of November 1, 1977. (Form 10-K for year ended December 31, 1980, File No. 1-5924-- Exhibit 4(v).) *4(a)(23)-- Twenty-second Supplemental Indenture, dated as of January 1, 1978. (Form 10-K for year ended December 31, 1980, File No. 1-5924-- Exhibit 4(w).) *4(a)(24)-- Twenty-third Supplemental Indenture, dated as of July 1, 1980. (Form 10-K for year ended December 31, 1980, File No. 1-5924--Exhibit 4(x).) *4(a)(25)-- Twenty-fourth Supplemental Indenture, dated as of October 1, 1980. (Form 10-K for year ended December 31, 1980, File No. 1-5924-- Exhibit 4(y).) *4(a)(26)-- Twenty-fifth Supplemental Indenture, dated as of April 1, 1981. (Form 10-Q for quarter ended March 31, 1981, File No. 1-5924--Exhibit 4(a).) *4(a)(27)-- Twenty-sixth Supplemental Indenture, dated as of April 1, 1981. (Form 10-Q for quarter ended March 31, 1981, File No. 1-5924--Exhibit 4(b).) *4(a)(28)-- Twenty-seventh Supplemental Indenture, dated as of October 1, 1981. (Form 10-Q for quarter ended September 30, 1982, File No. 1- 5924--Exhibit 4(c).) *4(a)(29)-- Twenty-eighth Supplemental Indenture, dated as of June 1, 1990. (Form 10-Q for quarter ended June 30, 1990, File No. 1-5924--Exhibit 4(a)(1).) *4(a)(30)-- Twenty-ninth Supplemental Indenture, dated as of December 1, 1992. (Form S-1, Registration No. 33-55732--Exhibit 4(a)(30).) *4(a)(31)-- Thirtieth Supplemental Indenture, dated as of December 1, 1992. (Form S-1, Registration No. 33-55732--Exhibit 4(a)(31).) *4(b)(1)-- Installment Sale Agreement, dated as of December 1, 1973, among the City of Farmington, New Mexico, Public Service Company of New Mexico and the Registrant. (Form 8-K for the month of January 1974, File No. 0-269--Exhibit 3.) *4(b)(2)-- Ordinance No. 486, adopted December 17, 1973, of the City of Farmington, New Mexico. (Form 8-K for the month of January 1974, File No. 0-269--Exhibit 4.) *4(c)(1)-- Loan Agreement, dated as of September 15, 1981, between the Industrial Development Authority of the County of Apache, Arizona and the Registrant, relating to Floating Rate Monthly Demand Pollution Control Revenue Bonds, 1981 Series B (Tucson Electric Power Company Project). (Form 10-K for year ended December 31, 1981, File No. 1- 5924--Exhibit 4(d)(1).) *4(c)(2)-- Indenture of Trust, dated as of September 15, 1981, between the Apache County Authority and Morgan Guaranty Trust Company of New York, authorizing Floating Rate Monthly Demand Pollution Control Revenue Bonds, 1981 Series B (Tucson Electric Power Company Project). (Form 10-K for year ended December 31, 1981, File No. 1-5924--Exhibit 4(d)(2).) *4(d)(1)-- Second Supplemental Loan Agreement, dated as of October 1, 1981, between the Apache County Authority and the Registrant, relating to Floating Rate Monthly Demand Pollution Control Revenue Bonds, 1981 Series B (Tucson Electric Power Company Project). (Form 10-K for year ended December 31, 1982, File No. 1-5924--Exhibit 4(f)(1).) *4(d)(2)-- Second Supplemental Indenture, dated as of October 1, 1981, between the Apache County Authority and Morgan Guaranty, relating to Floating Rate Monthly Demand Pollution Control Revenue Bonds, 1981 Series B (Tucson Electric Power Company Project). (Form 10-K for year ended December 31, 1982, File No. 1-5924--Exhibit 4(f)(2).) *4(d)(3)-- Third Supplemental Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and the Registrant, relating to Floating Rate Monthly Demand Pollution Control Revenue Bonds, 1981 Series B (Tucson Electric Power Company Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924--Exhibit 4(d)(3).) *4(d)(4)-- Third Supplemental Indenture, dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty, relating to Floating Rate Monthly Demand Pollution Control Revenue Bonds, 1981 Series B (Tucson Electric Power Company Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924--Exhibit 4(d)(4).) *4(d)(5)-- Fourth Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty, relating to Pollution Control Revenue Bonds, 1981 Series B (Tucson Electric Power Company Project). (Form S-4, Registration No. 33-52860--Exhibit 4(d)(5).) *4(d)(6)-- Fourth Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and the Registrant, relating to Pollution Control Revenue Bonds, 1981 Series B (Tucson Electric Power Company Project). (Form S-4, Registration No. 33-52860--Exhibit 4(d)(6).) *4(e)(1)-- Loan Agreement, dated as of October 1, 1981, between The Industrial Development Authority of the County of Pima, Arizona (the Pima County Authority) and the Registrant, relating to Floating Rate Monthly Demand Pollution Control Revenue Bonds, 1981 Series A (Tucson Electric Power Company Project). (Form 10-K for year ended December 31, 1981, File No. 1-5924--Exhibit 4(f)(1).) *4(e)(2)-- Indenture of Trust, dated as of October 1, 1981, between the Pima County Authority and Morgan Guaranty, authorizing Floating Rate Monthly Demand Pollution Control Revenue Bonds, 1981 Series A (Tucson Electric Power Company Project). (Form 10-K for year ended December 31, 1981, File No. 1-5924--Exhibit 4(f)(2).) *4(f)(1)-- Loan Agreement, dated as of July 1, 1982, between the Pima County Authority and the Registrant, relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company General Project). (Form 10-Q for quarter ended June 30, 1982, File No. 1-5924--Exhibit 4(a).) *4(f)(2)-- Indenture of Trust, dated as of July 1, 1982, between the Pima County Authority and Morgan Guaranty, authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company General Project). (Form 10-Q for quarter ended June 30, 1982, File No. 1-5924--Exhibit 4(b).) *4(f)(3)-- First Supplemental Loan Agreement, dated as of March 31, 1992, between the Pima County Authority and the Registrant relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company General Project). (Form S-4, Registration No. 33-52860- -Exhibit 4(f)(3).) *4(f)(4)-- First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Pima County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company General Project). (Form S-4, Registration No. 33-52860-- Exhibit 4(f)(4).) *4(g)(1)-- Loan Agreement, dated as of July 1, 1982, between the Pima County Authority and the Registrant, relating to Quarterly Tender Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power General Project). (Form 10-Q for quarter ended June 30, 1982, File No. 1-5924--Exhibit 4(c).) *4(g)(2)-- Indenture of Trust, dated as of July 1, 1982, between the Pima County Authority and Morgan Guaranty, authorizing Quarterly Tender Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company General Project). (Form 10-Q for quarter ended June 30, 1982, File No. 1-5924--Exhibit 4(d).) *4(g)(3)-- First Supplemental Loan Agreement, dated as of March 31, 1992, between the Pima County Authority and the Registrant relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company General Project). (Form S-4, Registration No. 33-52860- -Exhibit 4(g)(3).) *4(g)(4)-- First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Pima County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company General Project). (Form S-4, Registration No. 33-52860-- Exhibit 4(g)(4).) *4(h)(1)-- Loan Agreement, dated as of October 1, 1982, between the Pima County Authority and the Registrant relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Irvington Project). (Form 10-Q for quarter ended September 30, 1982, File No. 1-5924--Exhibit 4(a).) *4(h)(2)-- Indenture of Trust, dated as of October 1, 1982, between the Pima County Authority and Morgan Guaranty authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Irvington Project). (Form 10-Q for quarter ended September 30, 1982, File No. 1-5924--Exhibit 4(b).) *4(h)(3)-- First Supplemental Loan Agreement, dated as of March 31, 1992, between the Pima County Authority and the Registrant relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Irvington Project). (Form S-4, Registration No. 33- 52860--Exhibit 4(h)(3).) *4(h)(4)-- First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Pima County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Irvington Project). (Form S-4, Registration No. 33- 52860--Exhibit 4(h)(4).) *4(i)(1)-- Loan Agreement, dated as of December 1, 1982, between the Pima County Authority and the Registrant relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form 10-K for year ended December 31, 1982, File No. 1-5924--Exhibit 4(k)(1).) *4(i)(2)-- Indenture of Trust, dated as of December 1, 1982, between the Pima County Authority and Morgan Guaranty authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form 10-K for year ended December 31, 1982, File No. 1-5924--Exhibit 4(k)(2).) *4(i)(3)-- First Supplemental Loan Agreement, dated as of March 31, 1992, between the Pima County Authority and the Registrant relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form S-4, Registration No. 33-52860--Exhibit 4(i)(3).) *4(i)(4)-- First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Pima County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company Projects). (Form S-4, Registration No. 33-52860--Exhibit 4(i)(4).) *4(j)(1)-- Loan Agreement, dated as of March 1, 1983, between the Pima County Authority and the Registrant relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company General Project). (Form 10-Q for the quarter ended March 31, 1983, File No. 1-5924--Exhibit 4(a).) *4(j)(2)-- Indenture of Trust, dated as of March 1, 1983, between the Pima County Authority and Morgan Guaranty authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric Power Company General Project). (Form 10-Q for the quarter ended March 31, 1983, File No. 1-5924--Exhibit 4(b).) *4(j)(3)-- First Supplemental Loan Agreement, dated as of March 31, 1992, between the Pima County Authority and the Registrant relating to Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company General Project) (Form S-4 dated October 2, 1992, Registration No. 33-52860--Exhibit 4(j)(3).) *4(j)(4)-- First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Pima County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company General Project) (Form S-4 dated October 2, 1992, Registration No. 33-52860--Exhibit 4(j)(4).) *4(k)(1)-- Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and the Registrant relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for year ended December 31, 1983, File No. 1-5924--Exhibit 4(l)(1).) *4(k)(2)-- Indenture of Trust, dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty authorizing Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for year ended December 31, 1983, File No. 1-5924--Exhibit 4(l)(2).) *4(k)(3)-- First Supplemental Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and the Registrant relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924-- Exhibit 4(k)(3).) *4(k)(4)-- First Supplemental Indenture, dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924--Exhibit 4(k)(4).) *4(k)(5)-- Second Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and the Registrant relating to Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33- 52860--Exhibit 4(k)(5).) *4(k)(6)-- Second Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33- 52860--Exhibit 4(k)(6).) *4(l)(1)-- Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and the Registrant relating to Variable Rate Demand Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form 10-K for year ended December 31, 1983, File No. 1-5924--Exhibit 4(m)(1).) *4(l)(2)-- Indenture of Trust, dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty authorizing Variable Rate Demand Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form 10-K for year ended December 31, 1983, File No. 1-5924--Exhibit 4(m)(2).) *4(l)(3)-- First Supplemental Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and the Registrant relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924-- Exhibit 4(l)(3).) *4(l)(4)-- First Supplemental Indenture, dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924--Exhibit 4(l)(4).) *4(l)(5)-- Second Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and the Registrant relating to Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33- 52860--Exhibit 4(l)(5).) *4(l)(6)-- Second Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33- 52860--Exhibit 4(l)(6).) *4(m)(1)-- Loan Agreement, dated as of December 1, 1983, between the Apache County Authority and the Registrant relating to Variable Rate Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form 10-K for year ended December 31, 1983, File No. 1-5924--Exhibit 4(n)(1).) *4(m)(2)-- Indenture of Trust, dated as of December 1, 1983, between the Apache County Authority and Morgan Guaranty authorizing Variable Rate Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form 10-K for year ended December 31, 1983, File No. 1-5924--Exhibit 4(n)(2).) *4(m)(3)-- First Supplemental Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and the Registrant relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924-- Exhibit 4(m)(3).) *4(m)(4)-- First Supplemental Indenture, dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty relating to Floating Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924--Exhibit 4(m)(4).) *4(m)(5)-- Second Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and the Registrant relating to Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33- 52860--Exhibit 4(m)(5).) *4(m)(6)-- Second Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33- 52860--Exhibit 4(m)(6).) *4(n) -- Reimbursement Agreement, dated as of September 15, 1981, as amended, between the Registrant and Manufacturers Hanover Trust Company. (Form 10-K for the year ended December 31, 1984, File No. 1-5924--Exhibit 4(o)(4).) *4(o)(1)-- Loan Agreement, dated as of December 1, 1985, between the Apache County Authority and the Registrant relating to Variable Rate Demand Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1985, File No. 1-5924---Exhibit 4(r)(1).) *4(o)(2)-- Indenture of Trust, dated as of December 1, 1985, between the Apache County Authority and Morgan Guaranty authorizing Variable Rate Demand Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power Company Springerville Project). (Form 10-K for the year ended December 31, 1985, File No. 1-5924--Exhibit 4(r)(2).) *4(o)(3)-- First Supplemental Loan Agreement, dated as of March 31, 1992, between the Apache County Authority and the Registrant relating to Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33- 52860--Exhibit 4(o)(3).) *4(o)(4)-- First Supplemental Indenture of Trust, dated as of March 31, 1992, between the Apache County Authority and Morgan Guaranty relating to Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric Power Company Springerville Project). (Form S-4, Registration No. 33- 52860--Exhibit 4(o)(4).) *4(p)(1)-- Loan Agreement, dated as of February 22, 1991, between the Industrial Development Authority of the County of Pima and the Registrant, amending and restating the Loan Agreement, dated as of May 1, 1990, relating to Industrial Development Revenue Bonds, 1990 Series A (Tucson Electric Power Company Project). (Form 10-K for the year ended December 31, 1990, File No. 1-5924--Exhibit 4(p)(1).) *4(p)(2)-- Indenture of Trust, dated as of February 22, 1991, between the Industrial Development Authority of the County of Pima and Texas Commerce Bank National Association, amending and restating the Indenture of Trust, dated as of May 1, 1990, authorizing Industrial Development Revenue Bonds, 1990 Series A (Tucson Electric Power Company Project). (Form 10-K for the year ended December 31, 1990, File No. 1-5924--Exhibit 4(p)(2).) *4(q) -- Warrant Agreement and Form of Warrant, dated as of December 15, 1992. (Form S-1, Registration No. 33-55732--Exhibit 4(q).) *4(r)(1)-- Indenture of Mortgage and Deed of Trust dated as of December 1, 1992, to Bank of Montreal Trust Company, Trustee. (Form S-1, Registration No. 33-55732--Exhibit 4(r)(1).) *4(r)(2)-- Supplemental Indenture No. 1 creating a series of bonds designated Second Mortgage Bonds, Collateral Series A, dated as of December 1, 1992. (Form S-1, Registration No. 33-55732-Exhibit 4(r)(2).) *+10(a)--1985 Stock Option Plan of the Registrant. (Form 10-K for the year ended December 31, 1985, File No. 1-5924--Exhibit 10(b).) *+10(b)--1987 Phantom Stock Plan of the Registrant. (Form 10-K for the year ended December 31, 1987, File No. 1-5924--Exhibit 10(c).) *10(c)(1)-- Lease Agreements, dated as of December 1, 1984, between Valencia and United States Trust Company of New York, as Trustee, and Thomas B. Zakrzewski, as Co-Trustee, as amended and supplemented. (Form 10-K for the year ended December 31, 1984, File No. 1-5924--Exhibit 10(d)(1).) *10(c)(2)-- Guaranty and Agreements, dated as of December 1, 1984, between the Registrant and United States Trust Company of New York, as Trustee, and Thomas B. Zakrzewski, as Co-Trustee. (Form 10-K for the year ended December 31, 1984, File No. 1-5924--Exhibit 10(d)(2).) *10(c)(3)-- General Indemnity Agreements, dated as of December 1, 1984, between Valencia and the Registrant, as Indemnitors; General Foods Credit Corporation, Harvey Hubbell Financial, Inc. and J. C. Penney Company, Inc. as Owner Participants; United States Trust Company of New York, as Owner Trustee; Teachers Insurance and Annuity Association of America as Loan Participant; and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1984, File No. 1-5924--Exhibit 10(d)(3).) *10(c)(4)-- Tax Indemnity Agreements, dated as of December 1, 1984, between General Foods Credit Corporation, Harvey Hubbell Financial, Inc. and J. C. Penney Company, Inc., each as Beneficiary under a separate Trust Agreement dated December 1, 1984, with United States Trust of New York as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee, Lessor, and Valencia, Lessee, and the Registrant, Indemnitors. (Form 10-K for the year ended December 31, 1984, File No. 1-5924--Exhibit 10(d)(4).) *10(c)(5)-- Amendment No. 1, dated December 31, 1984, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924--Exhibit 10(e)(5).) *10(c)(6)-- Amendment No. 2, dated April 1, 1985, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski as Co- Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1- 5924--Exhibit 10(e)(6).) *10(c)(7)-- Amendment No. 3, dated August 1, 1985, to the Lease Agreements, dated December 1, 1984, between Valencia and United States Trust Company of New York, as Owner Trustee, and Thomas Zakrzewski as Co- Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1- 5924--Exhibit 10(e)(7).) *10(c)(8)-- Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co- Trustee, under a Trust Agreement dated as of December 1, 1984, with General Foods Credit Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924--Exhibit 10(e)(8).) *10(c)(9)-- Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co- Trustee, under a Trust Agreement dated as of December 1, 1984, with J. C. Penney Company, Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924--Exhibit 10(e)(9).) *10(c)(10) -- Amendment No. 4, dated June 1, 1986, to the Lease Agreement, dated December 1, 1984, between Valencia and United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co- Trustee, under a Trust Agreement dated as of December 1, 1984, with Harvey Hubbell Financial Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924--Exhibit 10(e)(10).) *10(c)(11) -- Lease Amendment No. 5 and Supplement No. 2, to the Lease Agreement, dated July 1, 1986, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co- Trustee and J. C. Penney as Owner Participant. (Form 10-K for the year ended December 31, 1986, File No. 1-5924--Exhibit 10(e)(11).) *10(c)(12) -- Lease Amendment No. 5, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and General Foods Credit Corporation as Owner Participant. (Form 10-K for the year ended December 31, 1988, File No. 1-5924--Exhibit 10(f)(12).) *10(c)(13) -- Lease Amendment No. 5, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and Harvey Hubbell Financial Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1988, File No. 1-5924--Exhibit 10(f)(13).) *10(c)(14) -- Lease Amendment No. 6, to the Lease Agreement, dated June 1, 1987, between Valencia, United States Trust Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-Trustee and J. C. Penney Company, Inc. as Owner Participant. (Form 10-K for the year ended December 31, 1988, File No. 1-5924--Exhibit 10(f)(14).) *10(c)(15) -- Lease Supplement No. 1, dated December 31, 1984, to Lease Agreements, dated December 1, 1984, between Valencia, as Lessee and United States Trust Company of New York and Thomas B. Zakrzewski, as Owner Trustee and Co-Trustee, respectively (document filed relates to General Foods Credit Corporation; documents relating to Harvey Hubbel Financial, Inc. and JC Penney Company, Inc. are not filed but are substantially similar). (Form S-4, Registration No. 33-52860--Exhibit 10(f)(15).) *10(c)(16) -- Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and the Registrant, as Indemnitors, General Foods Credit Corporation, as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924-- Exhibit 10(e)(12).) *10(c)(17) -- Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and the Registrant, as Indemnitors, J. C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924-- Exhibit 10(e)(13).) *10(c)(18) -- Amendment No. 1, dated June 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and the Registrant, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1- 5924--Exhibit 10(e)(14).) *10(c)(19) -- Amendment No. 2, dated as of July 1, 1986, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and the Registrant, as Indemnitors, J. C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860--Exhibit 10(f)(19).) *10(c)(20) -- Amendment No. 2, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and the Registrant, as Indemnitors, General Foods Credit Corporation, as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860--Exhibit 10(f)(20).) *10(c)(21) -- Amendment No. 2, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and the Registrant, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860--Exhibit 10(f)(21).) *10(c)(22) -- Amendment No. 3, dated as of June 1, 1987, to the General Indemnity Agreement, dated as of December 1, 1984, between Valencia and the Registrant, as Indemnitors, J. C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860--Exhibit 10(f)(22).) *10(c)(23) -- Supplemental Tax Indemnity Agreement, dated July 1, 1986, between J. C. Penney Company, Inc., as Owner Participant, and Valencia and the Registrant, as Indemnitors. (Form 10-K for the year ended December 31, 1986, File No. 1-5924--Exhibit 10(e)(15).) *10(c)(24) -- Supplemental General Indemnity Agreement, dated as of July 1, 1986, among Valencia and the Registrant, as Indemnitors, J. C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-5924--Exhibit 10(e)(16).) *10(c)(25) -- Amendment No. 1, dated as of June 1, 1987, to the Supplemental General Indemnity Agreement, dated as of July 1, 1986, among Valencia and the Registrant, as Indemnitors, J. C. Penney Company, Inc., as Owner Participant, United States Trust Company of New York, as Owner Trustee, Teachers Insurance and Annuity Association of America, as Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee. (Form S-4, Registration No. 33-52860--Exhibit 10(f)(25).) *10(c)(26) -- Valencia Agreement, dated as of June 30, 1992, among the Registrant, as Guarantor, Valencia, as Lessee, Teachers Insurance and Annuity Association of America, as Loan Participant, Marine Midland Bank, N.A., as Indenture Trustee, United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski, as Co-Trustee, and the Owner Participants named therein relating to the Restructuring of Valencia's lease of the coal-handling facilities at the Springerville Generating Station. (Form S-4, Registration No. 33-52860--Exhibit 10(f)(26).) *10(c)(27) -- Amendment, dated as of December 15, 1992, to the Lease Agreements, dated December 1, 1984, between Valencia, as Lessee, and United States Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski, as Co-Trustee. (Form S-1, Registration No. 33-55732-- Exhibit 10(f)(27).) *10(d)(1)-- Lease Agreements, dated as of December 1, 1985, between the Registrant and San Carlos Resources Inc. (San Carlos) (a wholly-owned subsidiary of the Registrant) jointly and severally, as Lessee, and Wilmington Trust Company, as Trustee, as amended and supplemented. (Form 10-K for the year ended December 31, 1985, File No. 1-5924-- Exhibit 10(f)(1).) *10(d)(2)-- Tax Indemnity Agreements, dated as of December 1, 1985, between Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Finance Co., each as beneficiary under a separate trust agreement, dated as of December 1, 1985, with Wilmington Trust Company, as Owner Trustee, and William J. Wade, as Co-Trustee, and the Registrant and San Carlos, as Lessee. (Form 10-K for the year ended December 31, 1985, File No. 1-5924--Exhibit 10(f)(2).) *10(d)(3)-- Participation Agreement, dated as of December 1, 1985, among the Registrant and San Carlos as Lessee, Philip Morris Credit Corporation, IBM Credit Financing Corporation, and Emerson Finance Co. as Owner Participants, Wilmington Trust Company as Owner Trustee, The Sumitomo Bank, Limited, New York Branch, as Loan Participant, and Bankers Trust Company, as Indenture Trustee. (Form 10-K for the year ended December 31, 1985, File No. 1-5924--Exhibit 10(f)(3).) *10(d)(4)-- Restructuring Commitment Agreement, dated as of June 30, 1992, among the Registrant and San Carlos, jointly and severally, as Lessee, Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Capital Funding William J. Wade, as Owner Trustee and Cotrustee, respectively, The Sumitomo Bank, Limited, New York Branch, as Loan Participant and United States Trust Company of New York, as Indenture Trustee. (Form S-4, Registration No. 33-52860--Exhibit 10(g)(4).) *10(d)(5)-- Lease Supplement No. 1, dated December 31, 1985, to Lease Agreements, dated as of December 1, 1985, between the Registrant and San Carlos, jointly and severally, as Lessee Trustee and Co-Trustee, respectively (document filed relates to Philip Morris Credit Corporation; documents relating to IBM Credit Financing Corporation and Emerson Financing Co. are not filed but are substantially similar). (Form S-4, Registration No. 33-52860--Exhibit 10(g)(5).) *10(d)(6)-- Amendment No. 1, dated as of December 15, 1992, to Lease Agreements, dated as of December 1, 1985, between the Registrant and San Carlos, jointly and severally, as Lessee, and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor. (Form S-1, Registration No. 33-55732-- Exhibit 10(g)(6).) *10(d)(7)-- Amendment No. 1, dated as of December 15, 1992, to Tax Indemnity Agreements, dated as of December 1, 1985, between Philip Morris Credit Corporation, IBM Credit Financing Corporation and Emerson Capital Funding Corp., as Owner Participants and the Registrant and San Carlos, jointly and severally, as Lessee. (Form S-1, Registration No. 33-55732--Exhibit 10(g)(7).) *10(e)(1)-- Amended and Restated Participation Agreement, dated as of November 15, 1987, among the Registrant, as Lessee, Ford Motor Credit Company, as Owner Participant, Financial Security Assurance Inc., as Surety, Wilmington Trust Company and William J. Wade in their respective individual capacities as provided therein, but otherwise solely as Owner Trustee and Co-Trustee under the Trust Agreement, and Morgan Guaranty, in its individual capacity as provided therein, but Secured Party. (Form 10-K for the year ended December 31, 1987, File No. 1-5924--Exhibit 10(j)(1).) *10(e)(2)-- Lease Agreement, dated as of January 14, 1988, between Wilmington Trust Company and William J. Wade, as Owner Trust Agreement described therein, dated as of November 15, 1987, between such parties and Ford Motor Credit Company, as Lessor, and the Registrant, as Lessee. (Form 10-K for the year ended December 31, 1987, File No. 1- 5924--Exhibit 10(j)(2).) *10(e)(3)-- Tax Indemnity Agreement, dated as of January 14, 1988, between the Registrant, as Lessee, and Ford Motor Credit Company, as Owner Participant, beneficiary under a Trust Agreement, dated as of November 15, 1987, with Wilmington Trust Company and William J. Wade, Owner Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K for the year ended December 31, 1987, File No. 1-5924--Exhibit 10(j)(3).) *10(e)(4)-- Loan Agreement, dated as of January 14, 1988, between the Pima County Authority and Wilmington Trust Company and William J. Wade in their respective individual capacities as expressly stated, but otherwise solely as Owner Trustee and Co-Trustee, respectively, under and pursuant to a Trust Agreement, dated as of November 15, 1987, with Ford Motor Credit Company as Trustor and Debtor relating to Industrial Development Lease Obligation Refunding Revenue Bonds, 1988 Series A (the Registrant's Irvington Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924--Exhibit 10(j)(4).) *10(e)(5)-- Indenture of Trust, dated as of January 14, 1988, between the Pima County Authority and Morgan Guaranty authorizing Industrial Development Lease Obligation Refunding Revenue Bonds, 1988 Series A (Tucson Electric Power Company Irvington Project). (Form 10-K for the year ended December 31, 1987, File No. 1-5924--Exhibit 10(j)(5).) *10(e)(6)-- Lease Amendment No. 1, dated as of May 1, 1989, between the Registrant, Wilmington Trust Company and William J. Wade as Owner Trustee and Co-trustee, respectively under a Trust Agreement dated as of November 15, 1987 with Ford Motor Credit Company. (Form 10-K for the year ended December 31, 1990, File No. 1-5924--Exhibit 10(i)(6).) *10(e)(7)-- Lease Supplement, dated as of January 1, 1991, between the Registrant, Wilmington Trust Company and William J. Wade as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement dated as of November 15, 1987, with Ford. (Form 10K for the year ended December 31, 1991, File No. 1-5924--Exhibit 10(i)(8).) *10(e)(8)-- Lease Supplement, dated as of March 1, 1991, between the Registrant, Wilmington Trust Company and William J. Wade as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement dated as of November 15, 1987, with Ford. (Form 10-K for the year ended December 31, 1991, File No. 1-5924--Exhibit 10(i)(9).) *10(e)(9)-- Lease Supplement No. 4, dated as of December 1, 1991, between the Registrant, Wilmington Trust Company and William J. Wade as Owner Trustee and Co-Trustee, respectively, under a Trust Agreement dated as of November 15, 1987, with Ford. (Form 10-K for the year ended December 31, 1991, File No. 1-5924--Exhibit 10(i)(10).) *10(e)(10) -- Supplemental Indenture No. 1, dated as of December 1, 1991, between the Pima County Authority and Morgan Guaranty relating to Industrial Lease Development Obligation Revenue Project). (Form 10-K for the year ended December 31, 1991, File No. 1-5924--Exhibit 10(I)(11).) *10(e)(11) -- Restructuring Commitment Agreement, dated as of June 30, 1992, among the Registrant, as Lessee, Ford Motor Credit Company, as Owner Participant, Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, and Morgan Guaranty, as Indenture Trustee and Refunding Trustee, relating to the restructuring of the Registrant's lease of Unit 4 at the Irvington Generating Station. (Form S-4, Registration No. 33-52860--Exhibit 10(i)(12).) *10(e)(12) -- Amendment No. 1, dated as of December 15, 1992, to Amended and Restated Participation Agreement, dated as of November 15, 1987, among the Registrant, as Lessee, Ford Motor Credit Company, as Owner Participant, Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, Financial Security Assurance Inc., as Surety, and Morgan Guaranty, as Indenture Trustee. (Form S- 1, Registration No. 33-55732--Exhibit 10(h)(12).) *10(e)(13) -- Amended and Restated Lease, dated as of December 15, 1992, between the Registrant, as Lessee and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor. (Form S-1, Registration No. 33-55732--Exhibit 10(h)(13).) *10(e)(14) -- Amended and Restated Tax Indemnity Agreement, dated as of December 15, 1992, between the Registrant, as Lessee, and Ford Motor Credit Company, as Owner Participant. (Form S-1, Registration No. 33- 55732--Exhibit 10(h)(14).) *10(f)-- Power Sale Agreement for the years 1990 to 2011, dated as of March 10, 1988, between the Registrant and Salt River Project Agricultural Improvement and Power District. (Form 10-K for the year ended December 31, 1987, File No. 1-5924--Exhibit 10(k).) *+10(g)(1) -- Employment Agreements between the Registrant and Thomas A. Delawder and Gary L. Ellerd. (Form 10-K for the year ended December 31, 1987, File No. 1-5924--Exhibit 10(l).) *+10(g)(2) -- Employment Agreements between the Registrant and currently in effect with Ira R. Adler, Charles E. Bayless, Karen G. Kissinger, George W. Miraben, Dennis R. Nelson, Gerald A. O'Brien, Susan R. Wallach, James S. Pignatelli and Steven J. Glaser. (Form 10-K for the year ended December 31, 1989, File No. 1-5924--Exhibit 10(n)(2).) *+10(g)(3) -- Release and Proposed Settlement Agreement between the Registrant and Frederic N. Finney. (Form 10-K for the year ended December 31, 1994, File No. 1-5924--Exhibit 10(g)(3).) *+10(g)(4) -- Release and Proposed Settlement Agreement between the Registrant and Norman B. Johnsen. (Form 10-K for the year ended December 31, 1994, File No. 1-5924--Exhibit 10(g)(4).) *10(g)(5)-- Letter, dated February 25, 1992, from Dr. Martha R. Seger to the Registrant and Capital Holding Corporation. (Form S-4, Registration No. 33-52860--Exhibit 10(k)(4).) *+10(g)(6) -- Employment Agreement between the Registrant and Thomas N. Hansen. (Form 10-K for the year ended December 31, 1993, File No. 1- 5924--Exhibit 10(i)(5).) *10(h)-- Power Sale Agreement, dated April 29, 1988, for the dates of May 16, 1990 to December 31, 1995, between the Registrant and Nevada Power Company. (Form 10-K for the year ended December 31, 1988, File No 1- 5924--Exhibit 10(m)(2).) *10(i)-- Master Restructuring Agreement, dated as of June 30, 1992, among the Registrant, Escavada Company, Gallo Wash Development Company, Valencia, Barclays Bank PLC, New York Branch, as administrative agent and collateral agent and the several banks parties thereto. (Form S-4, Registration No. 33-52860--Exhibit 10(bb).) *10(j)-- Amendment No. 1, dated as of December 15 , 1992, to Master Restructuring Agreement, dated as of June 30, 1992, among the Registrant, Escavada Company, Gallo Wash Development Company, Valencia, Barclays Bank PLC, New York Branch, as administrative agent and collateral agent and the several banks parties thereto. (Form S- 1, Registration No. 33-55732--Exhibit 10(s)(2).) *10(k)-- Amendment No. 2, dated as of October 12, 1993, to Master Restructuring Agreement, dated as of June 30, 1992, among the Registrant, Escavada Company, Gallo Wash Development Company, Valencia, Barclays Bank PLC, New York Branch, as administrative agent and collateral agent and the several banks parties thereto. (Form 10-K for the year ended December 31, 1993, File No. 1-5924--Exhibit 10(n).) *10(l)-- Amendment No. 3, dated as of December 20, 1993, to Master Restructuring Agreement, dated as of June 30, 1992, among the Registrant, Escavada Company, Gallo Wash Development Company, Valencia, Barclays Bank PLC, New York Branch, as administrative agent and collateral agent and the several banks parties thereto. (Form 10- K for the year ended December 31, 1993, File No. 1-5924--Exhibit 10(o).) *10(m)-- Amendment No. 4, dated as of April 13, 1994, to Master Restructuring Agreement, dated as of June 30, 1992, among the Registrant, Escavada Company, Gallo Wash Development Company, Valencia, Barclays Bank PLC, New York Branch, as administrative agent and collateral agent and the several banks parties thereto. (Form 10-Q for the quarter ended June 30, 1994, File No. 1-5924--Exhibit 10(a).) *10(n)-- Amendment No. 5, dated as of June 30, 1994, to Master Restructuring Agreement, dated as of June 30, 1992, among the Registrant, Escavada Company, Gallo Wash Development Company, Valencia, Barclays Bank PLC, New York Branch, as administrative agent and collateral agent and the several banks parties thereto. (Form 10-Q for the quarter ended June 30, 1994, File No. 1-5924--Exhibit 10(b).) *10(o)-- Amendment No. 6, dated as of November 1, 1994, to Master Restructuring Agreement, dated as of June 30, 1992, among the Registrant, Escavada Company, Gallo Wash Development Company, Valencia, Barclays Bank PLC, New York Branch, as administrative agent and collateral agent and the several banks parties thereto. (Form 10-K for the year ended December 31, 1994, File No. 1-5924--Exhibit 10(o).) *10(p)-- Deed of Trust, Assignment of Rents and Leases and Security Agreement, dated as of June 30, 1992, from San Carlos to Transamerica Title Insurance Company, as trustee for the use and benefit of Barclays Bank PLC, New York Branch, as collateral agent. (Form S-1, Registration No. 33-55732--Exhibit 10(t).) *10(q)-- Participation Agreement, dated as of June 30, 1992, among the Registrant, as Lessee, various parties thereto, as Owner Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, and LaSalle National Bank, as Indenture Trustee relating to the Registrant's lease of Springerville Unit 1. (Form S-1, Registration No. 33-55732--Exhibit 10(u).) *10(r)-- Lease Agreement, dated as of December 15, 1992, between the Registrant, as Lessee and Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor. (Form S-1, Registration No. 33-55732--Exhibit 10(v).) *10(s)-- Tax Indemnity Agreements, dated as of December 15, 1992, between the various Owner Participants parties thereto and the Registrant, as Lessee. (Form S-1, Registration No. 33-55732, Exhibit 10(w).) *10(t)-- Restructuring Agreement, dated as of December 1, 1992, between the Registrant and Century Power Corporation. (Form S-1, Registration No. 33-55732--Exhibit 10(x).) *10(u)-- Voting Agreement, dated as of December 15, 1992, between the Registrant and Chrysler Capital Corporation (documents relating to CILCORP Lease Management, Inc., MWR Capital Inc., US West Financial Services, Inc. and Philip Morris Capital Corporation are not filed but are substantially similar). (Form S-1, Registration No. 33-55732-- Exhibit 10(y).) *10(v)-- Wholesale Power Supply Agreement between the Registrant and Navajo Tribal Utility Authority dated January 5, 1993. (Form 10-K for the year ended December 31, 1992, File No. 1-5924--Exhibit 10(t).) 11 -- Statement re computation of per share earnings. 21 -- Subsidiaries of the Registrant. 23 -- Consents of experts and counsel. 24 -- Power of Attorney. 27a -- Financial Data Schedule. 27b -- Financial Data Schedule. (*)Previously filed as indicated and incorporated herein by reference. (+)Management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by item 601(10)(iii) of Regulation S-K. EX-11 2 EXHIBIT 11 EXHIBIT 11 - COMPUTATION OF FULLY DILUTED EARNINGS PER SHARE For the Years Ended December 31, 1995 1994 1993 ------ ------ ------ -In Millions- (except per share data) Earnings Income (Loss) from Continuing Operations $ 55 $ 21 $ (22) Provision for Loss on Disposal of Discontinued Operations - - (4) ------ ------- ------- Net Income (Loss) $ 55 $ 21 $ (26) ====== ======= ======= Shares Weighted Average Number of Common Shares Outstanding 161 161 161 Additional Shares Assuming Conversion of: Warrants - 1 1 Stock Options - - - ------ ------- ------- Average Shares of Common Stock Outstanding and Equivalents 161 162 162 ====== ======= ======= Fully Diluted Earnings (Loss) per Average Share Income (Loss) from Continuing Operations $0.34 $ 0.13 $(0.14) Provision for Loss on Disposal of Discontinued Operations - - (0.02) ------ ------- ------- Net Income (Loss) $0.34 $ 0.13 $(0.16) ====== ======= ======= EX-21 3 EXHIBIT 21 Exhibit 21 Tucson Electric Power Company Subsidiaries Subsidiary State of Incorporation Brookland Financial Corporation California BFC Receivables Financing Corporation I Delaware BFC Receivables Financing Corporation II Delaware BFC Receivables Financing Corporation III Delaware Catalina Securities Inc. New York Escavada Company Arizona Gallo Wash Development Company Arizona Irvine Portfolio Services Corporation California Nations Energy Corporation, Escalante Resources Inc. (prior to 1/5/95) Arizona Nations-Colorado Energy Corporation Delaware Palomas Securities Inc. New York Pantano Securities Inc. New York Picacho-Warner Center Inc. Arizona Rincon Investing Company Arizona Sabino Investing Inc. Delaware San Carlos Resources Inc. Arizona Santa Cruz Resources Inc. Delaware Santa Rosa Resources Inc. Arizona Sierrita Resources Inc. Delaware Sofar 1 Inc. Arizona Sofar 2 Inc. Arizona Sofar 3 Inc. Arizona Sofar 4 Inc. Arizona Tucson Resources Inc. Delaware Tucsonel Inc. Arizona Valencia Energy Company Arizona EX-23 4 EXHIBIT 23 Exhibit 23 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Post-Effective Amendment No. 1 to Registration Statement No. 33-55732 of Tucson Electric Power Company and Subsidiaries (the Company) on Form S-3 and in Registration Statements No. 33-56523, No. 33-57233, and No. 33-57231 of the Company on Form S-8 of our report dated January 29, 1996, which included an explanatory paragraph relating to the timing of the recovery of the costs associated with 37.5% of Springerville Unit 2 which cannot presently be determined, appearing in this Annual Report on Form 10-K of the Company for the year ended December 31, 1995. DELOITTE & TOUCHE LLP Tucson, Arizona March 5, 1996 EX-24 5 EXHIBIT 24 EXHIBIT 24 Power of Attorney KNOW ALL MEN BY THESE PRESENTS, that the undersigned Principal Executive Officer, Principal Financial Officer, Principal Accounting Officer, officers and/or directors of Tucson Electric Power Company, an Arizona corporation, which corporation proposes to file with the Securities and Exchange Commission an Annual Report on Form 10-K for the year ended December 31, 1995, under the Securities Exchange Act of 1934, as amended, does each for himself and not for one another, hereby constitute and appoint Ira R. Adler, Dennis R. Nelson and Karen G. Kissinger and each of them, his true and lawful attorneys, in his name, place and stead, to sign his name to said proposed Annual Report on Form 10-K and any and all amendments thereto, and to cause the same to be filed with the Securities and Exchange Commission, it being intended to grant and hereby granting to said attorneys, and each of them, full power and authority to do and perform any act and thing necessary and proper to be done in the premises as fully and to all intents and purposes as the undersigned could do if personally present; and each of the undersigned for himself hereby ratifies and confirms all that said attorneys, or any one of them, shall lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, each of the undersigned has hereunto set their hand as of the 5th day of March, 1996. Charles E. Bayless Elizabeth T. Alexander ____________________________ ________________________________ Charles E. Bayless Elizabeth T. Alexander, Director Principal Executive Officer and Chairman of the Board of Directors Jose L. Canchola ________________________________ Jose L. Canchola, Director Ira R. Adler _____________________________ Ira R. Adler John A. Jeter Principal Financial Officer ________________________________ John A. Jeter, Director Karen G. Kissinger _____________________________ R. B. O'Rielly Karen G. Kissinger ________________________________ Principal Accounting Officer R. B. O'Rielly, Director Martha R. Seger ________________________________ Martha R. Seger, Director Donald G. Shropshire ________________________________ Donald G. Shropshire, Director H. Wilson Sundt ________________________________ H. Wilson Sundt, Director J. Burgess Winter ________________________________ J. Burgess Winter, Director EX-27 6 EXHIBIT 27A
UT 1,000 YEAR DEC-31-1995 DEC-31-1995 PER-BOOK 1,978,126 52,116 214,794 285,894 0 2,530,930 638,938 0 (626,450) 12,488 0 0 1,207,460 12,039 0 0 12,075 0 897,958 33,389 355,521 2,530,930 670,569 8,920 539,594 548,514 122,055 41,531 163,586 108,681 54,905 0 54,905 0 64,198 119,390 0.34 0.34
EX-27 7 EXHIBIT 27B
UT 1,000 YEAR DEC-31-1994 DEC-31-1994 PER-BOOK 2,007,422 12,992 356,987 322,192 0 2,699,593 639,122 0 (681,355) (42,233) 0 0 1,381,935 0 0 0 17,167 0 922,735 12,803 407,186 2,699,593 691,473 (91) 577,162 577,071 114,402 13,998 128,400 107,660 20,740 0 20,740 0 59,661 143,616 0.13 0.13
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