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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.