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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
For the fiscal year ended December 31, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
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 of (IRS Employer
Incorporation or Organization) Identification No.)
220 WEST SIXTH STREET, P.O. BOX 711
TUCSON, ARIZONA 85702
85701 (Zip Code)
(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 $478,020,278.00 based on the
last reported sale price thereof on the consolidated tape on March 4, 1997.
At March 4, 1997, 32,135,817 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 1997 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 .................................................1
Utility Operations
Peak Demand and Customers ....................................2
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
1996 Rate Order ..............................................7
ACC Rules on Retail Competition ..............................7
FERC Orders on Wholesale Transmission Access .................9
Other Rate Matters ...........................................9
Fuel Supply
General ......................................................9
Coal ........................................................10
Springerville Coal Handling Facilities ......................11
Gas .........................................................11
Water Supply .................................................11
Environmental Matters
General .....................................................11
Four Corners Generating Station .............................13
Irvington Generating Station ................................13
Navajo Generating Station ...................................13
San Juan Generating Station .................................13
Springerville Generating Station ............................13
Employees ....................................................13
Energy-Related Ventures ......................................14
Utility Operating Statistics .................................15
Item 2. -- Properties..........................................16
Item 3. -- Legal Proceedings
Tax Assessments ..............................................17
Item 4. -- Submission of Matters to a Vote of Security Holders...17
- PART II -
Item 5. -- Market for Registrant's Common Equity and Related Stockholder Matters
18
Item 6. -- Selected Consolidated Financial Data................19
Item 7. -- Management's Discussion and Analysis of Financial Condition and
Results of Operations
Overview....................................................20
Competition
Wholesale ..................................................21
Retail .....................................................22
Holding Company Proposal .....................................24
Investments in Energy-Related Ventures .......................25
Results of Operations ........................................26
Results of Utility Operations
Sales and Revenues........................................26
Operating Expenses........................................27
Other Income (Deductions).................................27
Interest Expense..........................................28
Accounting for the Effects of Regulation .....................28
Dividends on Common Stock ....................................28
Liquidity and Capital Resources
Cash Flows .................................................29
Financing Developments .....................................30
Short-Term Credit Facilities
Revolving Credit..........................................31
Other.....................................................31
Income Tax Position ..........................................31
Restrictive Covenants
General First Mortgage Covenants ...........................32
General Second Mortgage Covenants ..........................32
Additional Restrictive Covenants ...........................33
Construction Expenditures ....................................33
Safe Harbor for Forward-Looking Statements ...................33
Item 8. -- Consolidated Financial Statements and Supplementary Data...34
Independent Auditors' Report .................................35
Consolidated Statements of Income ............................36
Consolidated Statements of Cash Flows ........................37
Consolidated Balance Sheets ..................................38
Consolidated Statements of Capitalization ....................39
Consolidated Statements of Changes in Stockholders' Equity (Deficit)...40
Notes to Consolidated Financial Statements
Note 1. Nature of Operations and Summary of Significant Accounting Policies
Nature of Operations .......................................41
Basis of Presentation ......................................41
Use of Estimates ...........................................41
Regulation .................................................41
Accounting for the Effects of Regulation ...................41
Utility Plant ..............................................43
Utility Plant Under Capital Leases .........................43
Springerville Unit 1 Allowance .............................44
Deferred Common Facility Costs .............................44
Utility Operating Revenues .................................44
MSR Option Gain Regulatory Liability .......................45
Fuel and Purchased Power Costs .............................45
Income Taxes ...............................................45
EPA Allowances .............................................45
Fair Value of Financial Instruments ........................46
Reclassification ...........................................46
Common Stock Reverse Split .................................46
Impact of FAS 121 ..........................................46
Note 2. 1996 Rate Order ......................................46
Note 3. Income Taxes ........................................48
Note 4. Consolidated Subsidiaries
Nations Energy Corporation .................................50
Advanced Energy Technologies, Inc. .........................50
Valencia Energy Company ....................................50
Investment Subsidiaries ....................................51
Note 5. Long and Short-Term Debt and Capital Lease Obligations
Long-Term Debt .............................................51
First Mortgage Bonds......................................51
MRA.......................................................51
Dividends - Restrictive Covenants.........................52
Letters of Credit.........................................52
Renewable Term Loan.......................................52
Fair Value of Long-Term Debt..............................52
Authorization To Issue Tax-Exempt Bonds...................53
Capital Lease Obligations ..................................53
Maturities and Sinking Fund Requirements ...................53
Short-Term Debt
Revolving Credit..........................................54
Investment Subsidiaries...................................54
Note 6. Commitments and Contingencies
Utility Contractual Matters
Coal and Transportation Contracts - Reversal of Accrued Liabilities ...54
Fuel Purchase Commitments.................................54
Commitments-Environmental Regulation .......................55
Contingencies
Ruling on Arizona Sales Tax Assessments - Coal Sales......56
Arizona Sales Tax Assessments - Leases....................56
Note 7. Jointly Owned Facilities .............................57
Note 8. Employee Benefits Plans
Voluntary Severance Plan (VSP) .............................57
Pension Plans ..............................................57
Postretirement Benefits Other Than Pensions ................58
Stock Option Plans .........................................59
Note 9. Quarterly Financial Data (unaudited) .................61
Note 10. Supplemental Cash Flow Information ..................62
Item 9. -- Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure...........................................63
- PART III -
Item 10. -- Directors and Executive Officers of the Registrant
Directors ....................................................63
Executive Officers ...........................................63
Item 11. -- Executive Compensation.............................65
Item 12. -- Security Ownership of Certain Beneficial Owners and Management
General ......................................................65
Security Ownership of Certain Beneficial Owners ..............65
Security Ownership of Management .............................65
Item 13. -- Certain Relationships and Related Transactions ....65
- PART IV -
Item 14. -- Exhibits, Financial Statement Schedules, and Reports on Form 8-K 66
Signatures ...................................................67
Exhibit Index ................................................69
DEFINITIONS
The abbreviations and acronyms used in the 1996 Form 10-K are defined below:
ACC............ Arizona Corporation Commission.
ACC Staff...... Staff of the Arizona Corporation Commission.
ADEQ........... Arizona Department of Environmental Quality.
Advanced Energy Advanced Energy Technologies, Inc., a wholly-owned
subsidiary of the Company.
AFDC........... Allowance for Funds Used During Construction.
APS............ Arizona Public Service Company.
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.
Century........ Century Power Corporation, an indirect subsidiary of the
Catalyst Corporation and formerly known as Alamito
Company.
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.
EPA............ The Environmental Protection Agency.
FAS 71......... Statement of Financial Accounting Standards No. 71:
Accounting for the Effects of Certain Types of
Regulation.
FAS 92......... Statement of Financial Accounting Standards No. 92: Regulated
Enterprises - Accounting for Phase-In Plans.
FAS 101........ Statement of Financial Accounting Standards No. 101: Regulated
Enterprises - Accounting for the Discontinuation of
Application of FAS 71.
FAS 121........ Statement of Financial Accounting Standards No. 121:
Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of.
FAS 123........ Statement of Financial Accounting Standards No. 123:
Accounting for Stock-Based Compensation.
FERC.............. Federal Energy Regulatory Commission.
FERC Order No. 888 An Order of the FERC issued in April 1996 pertaining to
open access transmission service.
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 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.
Global Solar...... Global Solar Energy, LLC, a corporation in which a 50%
interest is owned by Advanced Energy.
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 $48 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.
ITC............... Investment tax credit.
kW................ Kilowatt(s).
kWh............... Kilowatt-hour(s).
kV................ Kilovolt(s).
kVA............... Kilovoltampere(s).
LOC............... Letter of Credit.
MRA............... Master restructuring agreement between the Company and the
Banks which includes the Renewable Term Loan, Revolving
Credit, and certain replacement reimbursement agreements.
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.
NEV............... New Energy Ventures, Inc.
NOL............... Net Operating Losses.
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.
1996 Rate Order... ACC Rate Order concerning an increase in the Company's
retail base rates and the recovery of Springerville Unit
2 costs, issued March 29, 1996.
1994 Rate Order... ACC Rate Order concerning an increase in the Company's
retail base rates and regulatory write-offs, issued
January 11, 1994.
1991 Rate Order... ACC Rate Order concerning an increase in the Company's
retail base rates, regulatory write-offs and rate and
accounting synchronization, issued October 11, 1991.
1989 Rate Order... The ACC's October 24, 1989, Rate Order concerning the
Company's 1988 application for a rate increase.
NTUA.............. Navajo Tribal Utility Authority.
PDEQ.............. Pima County Department of Environmental Quality.
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.
PNM............... Public Service Company of New Mexico.
Renewable Term Loan Credit facility that replaces the Term Loan pursuant to
the MRA Sixth Amendment, dated as of November 1, 1994,
and effective March 7, 1995.
Revolving Credit.. $50 million revolving credit facility entered into between
a syndicate of certain of the Banks and the Company.
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.
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.
Shareholders...... Holders of Common Stock.
Southwest Energy.. Southwest Energy Solutions, Inc., a wholly-owned
subsidiary of the Company.
Springerville.. Springerville Generating Station.
Springerville Coal Handling
Facilities Leases Leveraged lease arrangements relating to the coal
handling facilities serving Springerville.
Springerville Common
Facilities Leases Leveraged lease arrangements 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 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.
SWPP........... SWPP Investment Company, a wholly-owned subsidiary of the
Company.
Term Loan...... $243.4 million original principal amount term loan entered
into by a syndicate of certain Banks and the Company.
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
Renewable Term Loan, the Revolving Credit and the
Replacement Reimbursement Agreement.
Valencia....... Valencia Energy Company, previously a wholly-owned subsidiary
of the Company, merged into the Company on May 31, 1996.
VSP............ Voluntary Severance Plan offered to Company employees and
implemented in May 1996.
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.
WSCC........... Western Systems Coordinating Council.
PART I
This Annual Report on Form 10-K contains forward-looking statements as
defined by the Private Securities Litigation Reform Act of 1995. Forward-
looking statements should be read with the cautionary statements and important
factors included in this Form 10-K. (See Item 7. - Management's Discussion and
Analysis of Financial Condition and Results of Operations, Safe Harbor for
Forward-Looking Statements.) Forward-looking statements include statements
concerning plans, objectives, goals, strategies, future events or performance
and underlying assumptions and other statements which are other than statements
of historical facts. Such forward-looking statements may be identified, without
limitation, by the use of the words "anticipates," "estimates," "expects,"
"intends," "plans," "predicts," "projects," and similar expressions. The
Company's expectations, beliefs and projections are expressed in good faith and
are believed by the Company to have a reasonable basis, including without
limitation, management's examination of historical operating trends, data
contained in the Company's records and other data available from third parties,
but there can be no assurance that management's expectations, beliefs or
projections will result or be achieved or accomplished.
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) San Carlos Resources
Inc. (San Carlos), which holds title to Springerville Unit 2, (ii) Nations
Energy Corporation (Nations Energy), which is active in the development of
independent power projects worldwide, (iii) Advanced Energy Technologies, Inc.
(Advanced Energy), formerly known as TEP Solar Energy Corporation, which holds a
50% interest in a manufacturer of thin-film photovoltaic cells, (iv) SWPP
Investment Company (SWPP), which was formed to hold an ownership interest in a
business engaged in the manufacture and sale of concrete power poles, and (v)
Southwest Energy Solutions Inc. (Southwest Energy), which was formed to provide
ancillary energy services to electric consumers. See Energy-Related Ventures
below for a description of these subsidiaries. The Company also owns all of the
outstanding stock of two non-energy related 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
For descriptions of certain factors affecting the Company, including
commitments and contingencies, which subject the Company to continuing risks,
see (i) Item 3., Legal Proceedings; (ii) Item 7., Management's Discussion and
Analysis of Financial Condition and Results of Operations, Overview and Safe
Harbor for Forward-Looking Statements; and (iii) Notes 1 and 6 of Notes to
Consolidated Financial Statements, Nature of Operations and Summary of
Significant Accounting Policies and Commitments and Contingencies, respectively.
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 are summarized in the following
table:
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
PEAK DEMAND - MW -
Retail Customers-Net One Hour 1,619 1,617 1,585 1,449 1,399
Other Utilities-Firm 177 223 226 225 150
----- ----- ----- ----- -----
Non-Coincident Peak Demand (A) 1,796 1,840 1,811 1,674 1,549
----- ----- ----- ----- -----
Total Generating Resources (B) 2,085 2,085 1,975 1,975 1,983
Total Reserves ((B) - (A)) 289 245 164 301 434
===== ===== ===== ===== =====
Reserve Margin (% of Non-Coincident
Peak Demand) 16% 13% 9% 18% 28%
===== ===== ===== ===== =====
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 of retail customers at an
average annual rate of approximately 4.2% for the past five years. The load of
its mining customers comprised on average approximately 8.5% of the retail peak
demand for the past five years.
In 1996, based on non-coincident peak demand, the Company's reserve margin
increased to 16% compared with 13% in the prior year. This increase was due to
lower demand from firm wholesale customers. 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 in 1996 was 302 MW, or 17% of non-coincident peak demand.
The Company's operations have not been adversely affected by having an actual
reserve margin lower than the targeted reserve requirement. 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 Company
Resources below for a discussion of the Company's electric generating resources.
The growth in the number of retail customers remained strong in 1996, with
year-end customers increasing by 2.8% compared to the five-year annual average
of 2.6%. The growth rate in the number of customers is expected to be
approximately 2.4% annually through the year 2001. Retail peak demand is
expected to grow at an average annual rate of 2.5% 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 expected growth in the number of customers, retail
peak demand and retail sales is 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, including the assumption that the Company will incur no
significant loss of retail customers due to self-generation or retail wheeling.
The Company has two principal mining customers. In 1996, the sales to
these customers totaled approximately 16% of the Company's total retail energy
sales, and their contract demands totaled approximately 11% of the 1996 retail
peak demand. The total coincident peak load for the Company's two mining
customers was only 7.2% of the coincident peak demand due to temporary non-
mandated demand reductions at certain mining facilities. Based on normal
electrical loads for these customers, the Company's coincident peak demand would
have increased by 34 MW to 1,651 MW, or 2.1%, over the 1995 retail peak demand.
Revenues from sales to mining customers accounted for approximately 9% of the
Company's retail revenues in 1996 and approximately 10% in 1995 and 1994. Sales
to mining customers are expected to grow as approximately 20 MW of additional
mining load is scheduled for 1997. However, sales to mining customers are
dependent on a variety of factors including, but not limited to, changes in the
international copper market and the economics of self-generation.
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.
No termination notices have been received by the Company. 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 retail wheeling, will affect the economics
of self-generation projects (including cogeneration) and potential purchases
from competing energy suppliers. Such factors may ultimately affect whether
customers, such as the mining customers described above, might reduce or
terminate their 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
- -------------
(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 available excess energy in the
short-term markets (hourly up to one year) and, to the extent that it is
economic, commitments for available generating capacity and energy in the longer
term markets (one year and longer). 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, the restructuring of the electric utility industry
in California and other western states, and the presence of a highly competitive
spot market 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.
COMPETITION
See Rates and Regulation, ACC Rules on Retail Competition and FERC Orders
on Wholesale Transmission Access below, and 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 owned or leased by the Company at
December 31, 1996, was 1,952 MW as set forth in the following table:
Net Capa- Company Share
Unit Fuel bility Operating -------------
Generating Source No. Location Type MW Agent % MW
----------------- ---- -------- ---- ------- --------- ---- ----
Springerville Station (1) 1 Springerville, AZ Coal 360 TEP 100.0 360
Springerville Station (1) 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 (2) 1,952
=====
- ---------------------------------------------
(1) As of January 1, 1997, the net generating capability at Springerville was
increased to 380 MW for each unit. See Springerville Station below.
(2) Excludes 215 MW of additional resources, which consists of certain other
capacity purchases and interruptible retail load. At December 31, 1996,
total Company-owned capacity was 1,339 MW and Company-leased capacity was
613 MW. Internal combustion turbines with 96 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
The Springerville Station consists of two 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. Based on a review
of generating unit capabilities and changes in certain operating procedures, the
net capacity rating for each unit was increased from 360 MW to 380 MW as of
January 1, 1997. Under emergency conditions, such units may be operated for up
to eight hours at a net capacity of 400 MW each.
The primary terms of the Springerville Unit 1 Leases expire on January 1,
2015. At December 31, 1996, the capitalized lease asset related to Springerville
Unit 1, net of allowance and accumulated amortization, was $252 million, or $663
per kW based on a 380 MW capacity rating. 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 $77 million. In 1996, the cash cost to
the Company of Springerville Unit 1 capacity attributable to rent obligations
and other operation and maintenance expenses was $76 million, or an average of
approximately $17 per kW per month based on a 380 MW capacity rating. Such
average cash cost is estimated to be approximately $19 per kW per month
(approximately $87 million per year) for the period from January 1997 through
December 2001 and will increase thereafter. However, due to timing differences
between cash and accrued expenses, capacity costs attributable to rent
obligations and other operation and maintenance expenses were accrued in the
Company's financial statements during 1996 at an average of approximately $20
per kW per month, or $92 million for the year, before amortization of the
regulatory disallowance and related interest expense. The estimated cost is
expected to average approximately $21 per kW per month (approximately $96
million per year) for the period from January 1997 through December 2001 and is
expected to increase slightly thereafter. The 1991 Rate Order allowed the
Company to recover the cost of 360 MW of capacity for Springerville Unit 1, but
limited 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, 1996, the capitalized lease asset related to Springerville common
facilities, net of accumulated amortization, was $122 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 approximately $12 million per year in 1994, 1995 and 1996.
Based on current interest rates, average annual lease payments would total
approximately $11 million.
Including the cost of leased common facilities (but excluding the cost of
coal-handling facilities at Springerville which were included in recoverable
fuel costs), the total initial cost of Springerville Unit 2 was $838 million, or
$2,328 per kW based on the previous 360 MW capacity rating. 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 $663 million.
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, 1996, the capitalized lease asset related to Irvington Unit 4, net
of accumulated amortization, was $118 million. This lease calls for annual
payments which will range from approximately $9 million to $14 million and which
average approximately $13 million. The lease term expires in 2011, but the
lease has optional renewal and purchase option provisions.
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 estimated cost of interruptible energy to be provided
to SCE. Pursuant to the exchange agreement the Company received 104,028 MWh
from SCE in 1996 and had returned 51,855 MWh to SCE as of December 31, 1996.
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.
Subsequently, the Company has delayed the need for peaking resources to 2001
through a review of net generating capabilities at Springerville and an increase
in the percentage of retail load served now on an interruptible basis.
In the 1995 integrated resource plan 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.
The need for all of these future resources may be affected by the ACC's
rules on retail competition and the Company's ability to retain and attract
customers. See Rates and Regulation, ACC Rules on Retail Competition below and
Item 7. - Management's Discussion and Analysis of Financial Condition and
Results of Operations, Competition.
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 160 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 provides emergency assistance and
reserve sharing among its members in order to enhance system reliability in the
Rocky Mountain region. 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 addition, the Company is a member of the Western Systems Power Pool, a
voluntary power pooling arrangement designed 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 prudence and recoverability. To the extent that
customer choice and retail wheeling are introduced into the Company's retail
service area in the future, retail rates may be changed to reflect market levels
which are different from traditional "cost of service" rate levels.
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. Rates have historically been set by the FERC in formal
rate application proceedings.
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:
- - Carl Kunasek (Republican), Chairman, began his first term in 1995. His term
expires in 2001.
- - Renz D. Jennings (Democrat), began a third term in 1993. His term expires in
1999.
- - Jim Irvin (Republican) started his first term in 1997. His term expires in
2003.
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.
1996 RATE ORDER
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). On March 27, 1996, the ACC took formal action to resolve the
Company's rate application. In its order dated March 29, 1996, the ACC approved
with certain modifications a rate settlement agreement which was filed with the
ACC on March 8, 1996, and approved a one-time rate increase for the Company of
1.1% (approximately $6.4 million annually). The rate increase was implemented
by the Company on March 31, 1996 for electrical usage on or after such date.
Since the rate increase was not implemented for special contract customers, the
effective rate increase was slightly less than 1.1%.
The 1996 Rate Order recognizes all of Springerville Unit 2 as used
and useful for ratemaking purposes so that the Company is presently recovering
the operating and capital costs associated with that portion of the generating
unit not previously included in rates. See Note 2 of the Notes to Consolidated
Financial Statements, 1996 Rate Order. The 1996 Rate Order and approved
settlement agreement also establish a rate moratorium period for the Company.
The Company has committed not to file for a change in base rates prior to
January 1, 2000, except for conditions or circumstances which constitute an
emergency, for the sharing of benefits with customers of cost containment
efforts where appropriate, or in the event the Company is acquired or merged
with another company. By April 15 of each year the Company is required to
provide the ACC Staff with a report quantifying the Company's cost containment
efforts. Beginning July 1, 1997, the ACC Staff may propose to terminate or
modify the rate moratorium for the purpose of reducing the Company's rates or
shortening capital recovery periods to reflect the Company's cost containment
efforts. In addition to the rate moratorium provisions, the 1996 Rate Order and
approved settlement agreement also contain provisions relating to the
implementation of time-of-use rates for residential customers, increased pricing
flexibility for commercial and industrial customers, the consideration of
incentive regulation and a review of jurisdictional cost allocation procedures
for wholesale sales.
The rates approved in the 1996 Rate Order are based on a rate of return of
6.59% on a fair value rate base of approximately $1.36 billion, or 7.72% on an
original cost rate base of approximately $1.16 billion. The capital structure
adopted by the ACC for rate making purposes assumes 62.5% debt and 37.5% equity.
Consistent with previous ACC rate orders, the Company's leasehold interest in
utility plant was reflected in rates through an allowance for rental expense,
and was therefore not included in rate base.
ACC RULES ON RETAIL COMPETITION
On December 23, 1996, the ACC voted to adopt rules on retail
electric competition. The rules require each "Affected Utility" to open its
retail service area to competing electric service providers on a phased-in basis
over the period 1999 to 2003. Beginning no later than January 1, 1999, retail
customers representing at least 20% of each Affected Utility's 1995 peak demand
will be eligible to choose their electric service provider from companies
certificated by the ACC. Such service providers would include Affected
Utilities as well as other entities that apply for and receive a certificate of
convenience and necessity from the ACC. Beginning no later than January 1,
2001, retail customers representing at least 50% of each Affected Utility's 1995
peak demand will be eligible to choose their service provider. All remaining
retail customers would then be eligible to choose from certificated service
providers by January 1, 2003. Under the rules, Affected Utilities will be
required to provide distribution wheeling services (i.e., retail wheeling) at
rates approved by the ACC in order to facilitate sales by competing energy
providers. Such wheeling services would involve the transmission of energy
produced by other entities over the Company's transmission and distribution
system to consumers located in the Company's present retail service area.
While retail wheeling will expose the Company's service area to increased
competition, it will also open additional markets into which the Company may
sell its electric power.
The Affected Utilities whose service territories will be open to competing
service providers under the rules include Tucson Electric Power Company, Arizona
Public Service Company, Citizens Utilities Company, and several electric
cooperatives. However, electric cooperatives will be permitted to request a
modification to the proposed phase-in schedule in order to preserve their tax
exempt status or to modify power supply arrangements and related loan
agreements. Each of the Affected Utilities will be eligible to offer electric
service to customers of other certificated entities within Arizona.
Participation in competitive retail markets by other electric utilities which
are not regulated by the ACC, such as the Salt River Project and certain
municipal utilities, will be permitted under the rules on a similar
reciprocal basis (i.e., their service territories would be similarly open to
competing service providers).
The rules specify that the ACC shall allow the recovery of unmitigated
stranded costs by Affected Utilities. Stranded cost is defined in the rules
as the net difference between the value of prudent jurisdictional assets
and obligations under traditional regulation and the market value of those
assets and obligations in a competitive retail market. In order to recover
stranded costs, utilities would have to demonstrate to the ACC that they have
taken every feasible, cost effective measure to mitigate or offset stranded
costs, and utilities would have to file estimates of unmitigated stranded
costs with the ACC which are fully supported by analyses and records of
market transactions undertaken by willing buyers and sellers. Furthermore,
Affected Utilities would have to seek ACC approval of distribution charges or
other means of recovering unmitigated stranded costs from customers who reduce
or terminate service as a direct result of retail competition. The rules
specify that other issues related to the analysis and recovery of stranded
costs would be examined by a working group following adoption of the rules.
Until such time as the ACC adopts specific guidelines for quantifying
unmitigated stranded costs, including the methods used to identify and value
jurisdictional assets and obligations, the Company believes that any estimate of
unmitigated stranded costs would be highly speculative.
Each Affected Utility will be required to file unbundled service tariffs
with the ACC by December 31, 1997, for the following services: distribution
wheeling service, metering and meter reading services, billing and collection
services, open access transmission service (as approved by the FERC, if
applicable), ancillary services (as defined by FERC Order No. 888), information
services such as the provision of customer information to other service
providers, and other ancillary services necessary for safe and reliable system
operation. Until such time as the ACC determines that retail competition has
been substantially implemented, each Affected Utility will also have to
regulated rates to all consumers located in their current
retail service areas.
The rules require new market entrants to obtain a certificate of
convenience and necessity from the ACC prior to offering retail electric
service. New market entrants will be required to demonstrate adequate technical
and financial capabilities to the ACC prior to certification. In addition, all
competitive market participants, including Affected Utilities, will be required
to obtain at least one-half of one percent of the energy sold competitively in
the Arizona retail market from new solar generating resources by January 1,
1999. This required percentage will increase to one percent on January 1, 2002.
New solar resources are defined under the proposed rule as photovoltaic or solar
thermal resources that are installed on or after January 1, 1997. Electric
service providers not in compliance with these solar resource standards will be
subject to a penalty of up to 30 cents per kWh to be applied to the kWh
deficiency in solar energy provided.
Under the rules, certain issues pertaining to retail electric competition
will be addressed by the ACC in workshops or proceedings to be held after
adoption of the rule. Such issues include the guidelines to be used for
stranded cost quantification and recovery, the possible formation of an
independent system operator for electrical transmission facilities, issues
related to system reliability and safety, legal issues and the methods to be
used in determining consumer participation during the early phase-in periods.
On January 10, 1997, the Company filed with the ACC a motion for
reconsideration and request for stay of the rules. The motion was filed in
order to provide the ACC with an opportunity to remedy certain procedural and
substantive deficiencies in the rules identified by the Company. Concerns
expressed by the Company in its motion included the potential impact on system
reliability, mechanisms for stranded cost quantification and recovery, the
ability to compete fairly with public power entities and recipients of federal
preference power, and certain legal deficiencies which would likely result in
legal appeals and litigation. On January 30, 1997, the Company's motion for
reconsideration was deemed denied by the ACC by operation of law. On February
28, 1997, the Company filed an appeal of the ACC order in both the Arizona
Superior Court and the Arizona Court of Appeals. At the present time, the
Company is unable to predict the outcome of the appeals or the effects such
rules, in their present form, would have on the Company's future results of
operations. For a discussion of the potential impact of increased competition
on the Company's accounting policies, see Item 7. - Management's Discussion and
Analysis of Financial Condition and Results of Operations, Accounting for the
Effects of Regulation, and Note 1 of Notes to Consolidated Financial Statements,
Nature of Operations and Summary of Significant Accounting Policies, Accounting
for the Effects of Regulation.
FERC ORDERS ON WHOLESALE TRANSMISSION ACCESS
In April 1996, the FERC issued two orders pertaining to wholesale
transmission access. FERC Order No. 888, among other things, requires all
public utilities that own, control, or operate interstate transmission
facilities to offer transmission service to others under a single tariff that
incorporates certain minimum terms and conditions of transmission service
established by the FERC. This tariff must also be used by public utilities for
their own wholesale market transactions. Transmission and generation services
for new wholesale service are to be unbundled and priced separately. A Phase I
open access tariff containing the terms and conditions outlined in the Order was
filed by the Company on July 9, 1996. The FERC has scheduled a hearing on the
rates contained in the Company's Phase I open access tariff for May 1997. The
Company is working with the FERC Staff and intervenors in an attempt to resolve
this matter.
FERC Order No. 889 requires transmission service providers to establish or
participate in an open access same-time information system (OASIS) that provides
information on the availability of transmission capacity to wholesale market
participants. The order also establishes standards of conduct that are designed
to prevent employees of a public utility engaged in marketing functions from
obtaining preferential access to OASIS-related information or from engaging in
unduly discriminatory business practices. As such, public utilities are
required to completely separate their wholesale power marketing and transmission
operation functions. The Company is currently in compliance with these
requirements.
OTHER RATE MATTERS
See Utility Operations, Peak Demand and Customers and Item 7. -
Management's Discussion of Financial Condition and Results of Operations,
Competition, Retail 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 1996 through
1992:
Cost Per Million BTU Consumed Percentage of Total BTU Consumed
-------------------------------- --------------------------------
1996 1995 1994 1993 1992 1996 1995 1994 1993 1992
---- ---- ---- ---- ---- ---- ---- ---- ---- ----
Coal (A) $1.76 $1.71 $1.75 $1.77 $1.51 98% 99% 98% 99% 99%
Gas 2.24 1.69 1.86 2.76 2.39 2 1 2 1 1
---- ---- ---- ---- ----
All Fuels 1.77 1.71 1.75 1.79 1.53 100% 100% 100% 100% 100%
==== ==== ==== ==== ====
- -----------------------------------------------
(A) The average cost per ton of coal for each of the last five years (1996 -
1992) was $32.95, $32.11, $33.12, $33.11, and $29.01, respectively. Coal
costs have been restated to reflect the May 1996 merger of Valencia into the
Company.
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 at intervals of 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 contract for
coal for Four Corners terminates 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 below:
Year Average Cost Per Coal
Contract Sulfur Million BTU (A) Obtained
Station Coal Supplier Terminates Content 1996 1995 1994 From (B)
- ------- ------------- ---------- ------- ---- ---- ---- -------
Four Corners BHP Minerals International, Inc. 2005 0.8% $1.34 $1.15 $1.28 Navajo Indian Tribe
San Juan San Juan Coal Company 2017 0.8% $1.77 $1.76 $1.81 Federal and State Agencies
Navajo Peabody Western Coal Company 2011 0.6% $1.18 $1.12 $1.09 Navajo and Hopi Indian Tribes
Springerville(C) Lee Ranch Coal Company (D) 0.7% $1.84 $1.73 $1.89 Lee Ranch Coal Company
Irvington The Pittsburg & Midway Coal Mining Company 2015 0.4% $2.21 $2.20 $2.21 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) Fuel handling costs at Springerville have been restated to reflect the May
1996 merger of Valencia into the Company. Coal handling facilities costs
included in Springerville fuel costs above were $0.25 per million BTU in
1996, $0.34 per million BTU in 1995, and $0.33 per million BTU in 1994.
(D) 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.
The Irvington coal supply contract contains take-or-pay provisions, whereby
the Company is required to make certain minimum payments for a base amount of
tonnage not taken at a rate of 50% of the contract price. Although the
Company's present fuel requirements are generally in excess of the stated take-
or-pay minimum amounts, from time to time the Company has purchased coal and
natural gas in the spot market 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. During 1996 the Company purchased coal for the
Irvington Station from an alternative supplier. As a result, the Company
incurred take-or-pay minimum charges of approximately $4 million during 1996.
The Company incurred no take-or-pay charges in 1995.
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 1997 and in the
future.
SPRINGERVILLE COAL HANDLING FACILITIES
Prior to May 31, 1996, a former subsidiary of the Company, Valencia Energy
Company, was responsible for the acquisition, transportation and handling of
fuel for Springerville. Pursuant to a fuel burn agreement with the Company,
Valencia had the exclusive right and obligation to provide all of the fuel
requirements for Springerville. Upon the merger of Valencia into the Company on
May 31, 1996, the Company became directly responsible for the acquisition,
transportation and handling of fuel for Springerville.
Pursuant to the Springerville Coal Handling Facilities Leases, the Company
is the lessee of the coal-handling facilities at Springerville under a capital
lease with a remaining initial lease term of approximately 19 years with
incremental extensions of five to six years depending on certain criteria at the
date of each extension. At December 31, 1996, the capitalized lease asset
related to the Springerville coal-handling facilities, net of accumulated
amortization, was $178 million. Annual rental payments range from approximately
$10 million to $28 million but average $21 million.
The Company allocates portions of its Springerville Coal Handling Facility
Lease costs to deferred expense for future recovery through rates. 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
Springerville coal handling facility lease costs. Approximately half of the
expenses of the coal handling facilities, including lease costs and other
operating and maintenance expenses, are charged to fuel expense and amounted to
$15 million, $17 million, and $18 million in 1996, 1995 and 1994, respectively.
Prior to the merger of Valencia into the Company in May 1996, nearly all of the
costs associated with Springerville coal handling facilities were charged to
fuel expense. As discussed in Note 4 of Notes to Consolidated Financial
Statements, Consolidated Subsidiaries, Valencia Energy Company, such costs have
been reclassified on the Company's Consolidated Statements of Income.
GAS
In 1996, the Company purchased a small amount of natural gas for power
generation (approximately 2% of total Company generation) from El Paso Gas
Marketing, Equitable Resources Marketing, Natural Gas Clearinghouse, and Mobil.
During 1996, the Company received natural gas sufficient to meet all of its gas
fuel requirements.
WATER SUPPLY
The Company believes there will be sufficient water 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. A federal
contract for water at San Juan expires in 2005, and negotiations for extension
are being overseen by PNM.
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 1996 for environmental construction
costs in maintaining compliance with environmental requirements. The Company
estimates that it will make expenditures for environmental facilities of
approximately $22 million in 1997 and $15 million in 1998. These amounts
include the Company's estimated share of expenditures for improvements to the
pollution control facilities at the Navajo and San Juan stations, as discussed
below. 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 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 1993 affected Company generating units were allocated Emission
Allowances based on past use. Beginning with the year 2000, Phase II generating
station units must hold Emission Allowances (by January 30 of the year following
the compliance year) equal to the level of emissions in the compliance year, or
face penalties and a requirement to offset excess tons in future years. An
analysis of the Emission Allowances that were allocated to the Company shows
that the Company may not have sufficient allowances to permit normal plant
operation and be in compliance with the sulfur dioxide regulations once the
Phase II requirements become effective due to the increase in the rated capacity
at Springerville. See Generating and Other Resources, Company Resources,
Springerville Station. To the extent that the Company does not have sufficient
allowances, due to increased energy output at Springerville or due to other
factors, the Company would have to purchase additional Emission Allowances.
Based upon current estimates of additional required Emission Allowances and the
current market price of such allowances, the Company believes that it will be
able to acquire additional required allowances and that such purchases will not
have a material effect on the Company.
The nitrogen oxide emission rule finalized in 1995 allows certain Phase II
affected coal-fired boilers to elect by January 1, 1997, and thus be subject to
compliance beginning January 1, 1997, instead of January 1, 2000. Utility
boilers that so elect are exempt until January 1, 2008, from compliance with any
stricter emission regulations that went into effect January 1, 1997, in the
revised nitrogen oxide rule. The Company has placed Springerville Units 1 and 2
into the early election program to take advantage of the exemption, but may
choose to withdraw in future years after the effects of the revised rules are
determined. In order to comply with the nitrogen oxide emission limits,
Irvington Unit 4 may require installation of low nitrogen oxide
burners by January 1, 2000, at a cost of approximately $1 million.
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, because of and in
addition to the CAAA, 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. 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 1997 for emissions at the Irvington facility was
assessed at $144,000 and is expected to range between $180,000 to $200,000 for
1998. As discussed above, the Company may need to install low nitrogen oxide
burners at Irvington Unit 4 by January 1, 2000, in order to comply with nitrogen
oxide emission limits.
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, 1996 relating
to the rule's implementation will be approximately $17 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. In order to improve the
efficiency of sulfur dioxide removal at the station, the existing removal
process will be replaced with a new process at an estimated cost to the Company
of $20 million, including AFDC, during the period 1997 through 1999.
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 1997 for emissions at
the Springerville Generating Station Units 1 and 2 was assessed at $310,000 and
is expected to be approximately the same for 1998.
EMPLOYEES
The Company and its subsidiaries had a combined total of 1,175 employees as
of December 31, 1996. The IBEW 1116, which represents about 62% of the total
employees, and the Company are parties to a two-year collective bargaining
agreement for the period from December 1, 1996 through November 30, 1998. The
collective bargaining agreement, which was negotiated with and approved by the
IBEW 1116 in December 1996 for classified employees in Tucson, includes annual
wage increases of 3.2% in December 1996 and 3.0% in December 1997, as well as
modifications to the pension plan. This same agreement was also approved by the
IBEW 1116 in January 1997 for classified employees at the Springerville
location.
ENERGY-RELATED VENTURES
The Company has established four wholly-owned subsidiaries for the purpose
of pursuing various energy-related investment opportunities. In 1995, the
Company established Nations Energy Corporation for the purpose of investing in
independent power projects in the domestic and foreign energy markets. In
September 1995, Nations Energy and Trigen Energy Corporation formed a limited
partnership which purchased Coors Brewing Company's energy production assets.
Nations Energy has a 49% interest in such partnership. In 1996, a wholly-owned
subsidiary of Nations Energy acquired an ownership interest in two companies
located in the Czech Republic for the purpose of participating in a power
project to be developed near the City of Kladno, Czech Republic. This project
involves the upgrading and expansion of an existing coal-fired thermal and
electric generating plant. Participation in this project will require
additional capital investment by Nations and related investment authority from
the ACC. In addition to these projects, Nations Energy is presently evaluating
several other investment opportunities in the domestic and foreign energy
markets.
In May 1996 the Company established Advanced Energy Technologies, Inc.
(formerly known as TEP Solar Energy Corporation). This wholly-owned subsidiary
is responsible for developing renewable energy and distributed generation
technologies, and in 1996 it acquired a 50% ownership interest in Global Solar
Energy, LLC, an Arizona corporation recently formed for the purpose of
developing and manufacturing flexible thin-film photovoltaic cells. Commercial
production of photovoltaic cells is presently scheduled to commence in mid-1997.
Global Solar's manufacturing facility is initially expected to produce up to
1,500 kW of product, or approximately 255,000 square-feet of photovoltaic
material, per year.
SWPP Investment Company was formed in 1996 for the purpose of holding an
ownership interest in a business engaged in the manufacture and sale of concrete
power poles. Although SWPP has yet to acquire such ownership interest, the
Company currently has a contract with a Mexican corporation for the distribution
and sale of concrete power poles in the United States.
In January 1997, the Company established another wholly-owned subsidiary
known as Southwest Energy Solutions, Inc. It is anticipated that Southwest
Energy will provide a variety of ancillary energy services to retail electric
consumers. Southwest Energy will likely focus its initial marketing efforts on
electric energy consumers in southern Arizona.
In addition to the activities currently underway or planned for each
of these subsidiaries, the Company continues to evaluate potential investment
opportunities in other energy-related markets. For example, the Company
currently has a consulting services contract with New Energy Ventures Inc.
(NEV), a California corporation. NEV, which recently obtained a Federal Power
Marketer's license from the FERC, is a buyer's agent providing load aggregation
and advisory services to energy consumers located primarily in California. The
Company has a currently exercisable option (through February 1998) to purchase
for a nominal amount a 50% interest in NEV.
In comparison to the Company's large investment in regulated utility
assets, the Company's current investments in Nations Energy, Advanced Energy,
SWPP and Southwest Energy are not material in terms of recorded assets or net
income. As of December 31, 1996, the Company's Consolidated Balance Sheet
reflected an investment in energy-related ventures of approximately $22 million
(included in Investments and Other Property). However, depending on the nature
of future investment opportunities, and the ability of the Company to make
additional investments as determined by the ACC and in certain credit
agreements, the Company expects to make additional investments in these
subsidiaries and in other energy-related ventures. Over time, such additional
investments may have a material impact on the Company's future cash flow and
profitability. Pursuant to an ACC order issued in February 1996, the Company is
permitted to invest in subsidiaries that 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 further authority from the ACC, the
Company would be authorized to expend additional funds. This investment
authority is subject to the conditions that (i) the total amount permitted to be
invested in such projects shall not exceed $50 million annually, (ii) 60% of net
profits from such projects be applied to repay the Company's debt, and (iii)
total investment in such projects does not exceed 15% of the Company's
capitalization. Under the MRA, the Company's capital investments are restricted
to assets which are related to the utility business, and are limited in size by
a ceiling on total capital expenditures and investments. The
Company is currently reviewing different alternatives for funding investments in
energy-related ventures.
UTILITY OPERATING STATISTICS
For Years Ended December 31,
1996 1995 1994 1993 1992
- --------------------------------------------------------------------------------------------------------
Generation and Purchased
Power-kWh (000)
Remote Generation (Coal) 9,784,918 8,716,513 9,341,342 8,986,350 6,148,825
Local Generation (Oil, Gas
& Coal) 723,232 500,958 825,385 615,100 527,405
Purchased Power 925,394 692,769 501,269 335,897 2,436,152
--------- ---------- --------- --------- ---------
Total Generation and
Purchased Power 11,433,544 9,910,240 10,667,996 9,937,347 9,112,382
Less Losses and Company Use 776,436 661,901 639,278 591,412 610,040
--------- ---------- --------- --------- ---------
Total Energy Sold 10,657,108 9,248,339 10,028,718 9,345,935 8,502,342
========= ========== ========= ========= =========
Sales-kWh (000)
Residential 2,516,282 2,330,191 2,374,868 2,223,479 2,146,268
Commercial 1,306,826 1,280,752 1,281,050 1,242,367 1,215,179
Large Users 2,080,763 1,979,317 1,948,331 1,832,278 1,771,937
Mining 1,164,140 1,147,281 1,135,424 1,090,061 1,081,791
Public Authorities 228,800 204,746 183,525 159,310 165,922
--------- ---------- --------- --------- ---------
Total-Retail Customers 7,296,811 6,942,287 6,923,198 6,547,495 6,381,097
Sales for Resale 3,360,297 2,306,052 3,105,520 2,798,440 2,121,245
--------- ---------- --------- --------- ---------
Total 10,657,108 9,248,339 10,028,718 9,345,935 8,502,342
========= ========== ========= ========= =========
Operating Revenues (000)
Residential $237,569 $218,208 $220,341 $197,368 $190,089
Commercial 143,623 138,294 137,508 128,688 125,655
Large Users 154,547 146,409 144,677 131,858 127,456
Mining 56,240 54,948 53,821 53,510 57,266
Public Authorities 16,949 14,952 13,435 11,464 11,757
Other 2,636 2,114 1,651 1,925 1,791
-------- -------- -------- -------- --------
Total-Retail Customers 611,564 574,925 571,433 524,813 514,014
Amortization of MSR Option Gain
Regulatory Liability 20,053 20,053 20,053 6,053 6,053
Sales for Resale 84,256 75,591 99,987 93,273 70,026
-------- -------- -------- -------- --------
Total $715,873 $670,569 $691,473 $624,139 $590,093
======== ======== ======== ======== ========
Customers (End of Period)
Residential 282,060 273,976 266,060 258,168 251,656
Commercial 28,199 27,858 27,360 26,838 26,441
Large Users 626 620 588 551 527
Mining 4 4 4 4 4
Public Authorities 61 59 59 59 59
------- ------- ------- ------- -------
Total Retail Customers 310,950 302,517 294,071 285,620 278,687
======= ======= ======= ======= =======
Average Revenue per kWh Sold (cents)
Residential 9.4 9.4 9.3 8.9 8.9
Commercial 11.0 10.8 10.7 10.4 10.3
Large Users and Mining 6.5 6.4 6.4 6.3 6.5
Total - Retail Customers 8.4 8.3 8.3 8.0 8.1
Average Revenue per
Residential Customer $854 $809 $841 $776 $765
Average kWh Sales per
Residential Customer 9,050 8,641 9,066 8,739 8,632
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 160 companies, including the
five listed above, which are utilized to interchange capacity and energy.
As of December 31, 1996, 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 9,408 circuit-miles of lower voltage
primary lines. The underground electric distribution system was comprised of
4,771 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 169 substations
with a total installed transformer capacity of 5,258,605 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.
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.
The Company leases under separate sale and leaseback arrangements the
following facilities (which do not include land): (i) the coal handling
facilities at Springerville; (ii) a 50% undivided interest in the other common
facilities at Springerville; (iii) Springerville Unit 1 and the remaining 50%
undivided interest in common facilities at Springerville; (iv) Irvington Unit 4
and related common facilities; and (v) three internal combustion turbines having
a combined net generating capability of 96 MW. See Note 5 of Notes to
Consolidated Financial Statements, Long and Short-Term Debt and Capital Lease
Obligations for additional information on the Company's capital lease
obligations.
Substantially all of the utility assets owned by the Company are subject to
the lien of the General First Mortgage and the General Second Mortgage.
Springerville Unit 2, legal title to which is held by San Carlos, is not subject
to such liens. Springerville Unit 2 is subject to the Unit 2 First Mortgage.
ITEM 3. -- LEGAL PROCEEDINGS
TAX ASSESSMENTS
See Contingencies in Note 6 of Notes to Consolidated Financial Statements.
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. Sale prices prior to May 20, 1996, have been adjusted to reflect
the one-for-five reverse split of the Company's Common Stock in May 1996. No
dividends were paid on Common Stock during such periods.
Market Price per
Quarter Share of Common Stock
------- ---------------------
High Low
1996 ---- ---
----
First $16.88 $14.38
Second 15.00 13.13
Third 17.81 12.25
Fourth 20.75 16.25
1995
----
First $18.75 $15.00
Second 17.50 15.00
Third 16.25 13.13
Fourth 16.25 14.38
The closing price of the Common Stock on the consolidated tape on March 4,
1997 was $14.875.
The Common Stock is traded on the New York Stock Exchange and the Pacific
Stock Exchange. At March 4, 1997, there were 30,821 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
1996 1995 1994 1993 1992
(In thousands - except per share data and ratios)
Summary of Operations
- ----------------------------------------------------------------------------------------------------------------
Operating Revenues $715,873 $670,569 $691,473 $624,139 $590,093
Regulatory Disallowances and Adjustments - - - (13,777) -
Income Tax Benefit 82,155 20,436 4,911 5,277 5,745
Loss on Restructuring - - - - (26,669)
Income (Loss) from:
Continuing Operations 120,852 54,905 20,740 (21,816) (79,022)
Provision for Loss on Disposal of
Discontinued Operations - - - (4,000) (44,047)
Net Income (Loss) 120,852 54,905 20,740 (25,816) (123,069)
Income (Loss) per Average Share of
Common Stock from:
Continuing Operations (A) $3.76 $1.71 $0.65 $(0.68) $(12.40)
Provision for Loss on Disposal of
Discontinued Operations (A) - - - (0.12) (6.91)
Total Net Income (Loss) per Average
Share of Common Stock (A) $3.76 $1.71 $0.65 $(0.80) $(19.31)
Shares of Common Stock Outstanding
Average (A) 32,134 32,138 32,145 32,109 6,374
End of Year (A) 32,135 32,138 32,145 32,145 32,086
- --------------------------------------------------------------------------------------------------------------
Financial Position
- --------------------------------------------------------------------------------------------------------------
Total Utility Plant - Net $1,953,904 $1,978,126 $2,007,422 $2,029,764 $2,052,695
Investments and Other Property 69,289 52,116 12,992 62,850 98,126
Total Assets 2,568,541 2,563,461 2,730,229 2,742,932 2,656,089
Long-Term Debt 1,223,025 1,207,460 1,381,935 1,416,352 1,466,555
Capital Lease Obligations 895,867 897,958 922,735 927,201 931,163
Common Stock Equity (Deficit) 133,288 12,488 (42,233) (62,973) (38,209)
Total Capitalization 2,252,180 2,117,906 2,262,437 2,280,580 2,359,509
Reserve for Litigation and Contract Disputes - - - - 27,500
Total Capitalization and Other Liabilities 2,568,541 2,563,461 2,730,229 $2,742,932 $2,656,089
- ----------------------------------------------------------------------------------------------------------------
Selected Cash Flow Data
- ----------------------------------------------------------------------------------------------------------------
Cash Flow Interest Coverage (B) 3.2x 2.5x 3.0x 2.3x 2.0x
Cash & Cash Equivalents/Current Liabilities (C) 0.92 0.48 1.29 0.91 1.06
Construction Expenditures
(including AFDC) $66,519 $59,097 $62,599 $48,162 $34,512
Cash Generated as a Percent of
Construction Expenditures:
Internally Generated (D) 227% 202% 229% 186% 257%
Internally Generated (D), Including
Drawdowns of Funds Held in Trust 227% 202% 229% 227% 305%
- ----------------------------------------------------------------------------------------------------------------
Note: See Item 7., Management's Discussion and Analysis of Financial Condition and Results of Operations.
(A) Per share data restated to reflect the one-for-five reverse stock split in May 1996.
(B) Cash from Continuing Operations plus Interest Paid divided by Interest Paid.
(C) Excludes Cash from Discontinued Operations.
(D) Cash generated is cash provided from continuing operations. The ratio for 1992 includes cash
conserved under the payment moratoria implemented by the Company on certain obligations during 1992.
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 1996 compared with 1995 and 1995 compared with
1994 and changes in liquidity and capital resources of the Company during 1996.
Also, management's expectations of identifiable material trends are discussed
herein.
OVERVIEW
Earnings for the Company improved in 1996 as net income increased to $120.9
million from $54.9 million recorded in 1995 and $20.7 million recorded in 1994.
The improvement over 1995 earnings is due primarily to the recognition of
K-21
substantial non-cash income tax benefits as well as to increased sales and
revenues, reduced operating and capital costs, and a reversal of loss provision
involving the Company's non-energy related subsidiaries. Due to continuing
improvement in the Company's profitability, the Company recognized non-cash
income tax benefits associated with the current and expected future utilization
of federal and state net operating loss carryforwards generated in prior
periods. Such recognized benefits totaled $88.6 million in 1996 and $23.3
million in 1995. See Income Tax Position below. The Company had common stock
equity of $133.3 million at year-end, compared to $12.5 million as of December
31, 1995.
In addition to the income tax benefits described above, items having a one-
time effect on earnings during 1996 include net pre-tax charges of $10.6 million
related to implementation of the Company's Voluntary Severance Plan (VSP),
charges of $9.2 million related to a court ruling on contested sales tax
assessments, and income of $9.5 million attributable primarily to a reversal of
loss provision involving the Company's non-energy related subsidiaries. See
Notes 5, 6, and 8 of Notes to Consolidated Financial Statements for information
pertaining to these items. During 1995 the Company recorded a one-time $12.2
million reduction to fuel and purchased power expense due to the satisfaction of
certain fuel contract provisions. Net income for 1995 was also affected by a
one-time gain of $3.6 million related to sales of securities and a reduction in
loss reserves for the non-energy related subsidiaries. Excluding each of these
one-time items from the periods in which they were recorded, the Company's
income before income taxes increased to $48.9 million in 1996 from $18.6 million
in 1995. The following table compares the Company's operating results in 1996
and 1995 exclusive of these one-time items and the recognition of NOL
carryforward benefits:
1996 1995
- Thousands of Dollars -
Net Income $120,852 $54,905
One-Time Items:
Fuel and Purchased Power 0 (12,245)
Taxes Other Than Income Taxes(1) 7,331 0
Employee Severance Plan Expense - Net 10,555 0
Other Income - Reversal of Loss Provision(2) (8,472) 0
Other Income - Other(2) (1,064) (3,623)
Interest Expense - Other(1) 1,880 0
Estimated Income Taxes Associated
with One-Time Items(3) (4,130) 6,408
------ ------
Net Adjustment for One-Time Items 6,100 (9,460)
NOL Carryforward Benefits (88,638) (23,282)
------ ------
Total Adjustments to Net Income (82,538) (32,742)
Net Income, as Adjusted for One-Time Items
and NOL Carryforward Benefits $38,314 $22,163
======= =======
- --------------------------------------------
(1) Adjustments related to contested sales tax assessments.
(2) Adjustments related to the Company's non-energy related subsidiaries.
(3) Calculated based on composite income tax rate of 40.4%.
Due primarily to increased cash receipts from retail customers, net cash
flows from continuing operating activities also improved in 1996, increasing to
$151.3 million in 1996 from $119.4 million in 1995 and $143.6 million in 1994.
After capital expenditures, scheduled debt maturities and payments to retire
capital lease obligations, net cash flows available for other investing and
financing activities were $36.9 million in 1996, $25.9 million in 1995, and
$61.1 million in 1994.
Despite improvements in the Company's financial performance, 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 industry changes or unanticipated
economic downturns. The Company's success will depend, in part, on the
Company's ability to contain the costs of serving retail customers and the level
of sales to such customers. Although 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, a number of factors such as
changes in the economic and regulatory environment and the increasingly
competitive electric markets could affect the Company's levels of sales.
The Company is developing strategies to address the uncertainties discussed
above as well as to position itself to benefit from the changing regulatory
environment. Such strategies include the implementation of enhanced cost
measurement and management techniques, organizational realignment and staffing
reductions, and the development of new entities to provide energy services to
markets beyond the Company's retail service territory. See Note 8 of Notes to
Consolidated Financial Statements, Employee Benefit Plans, Voluntary Severance
Plan (VSP), and Investments in Energy-Related Ventures below.
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 period 1999-2003, approximately $250 million of the Company's long-term debt
obligations will mature. Letters of credit supporting $805 million of the
Company's long-term variable rate debt obligations are also scheduled to expire
during the period 1999-2002. Should the credit ratings on the Company's senior
debt securities reach investment grade levels on certain dates or during certain
periods subsequent to January 1, 1998, the expiration dates for such letters of
credit would move forward to the period 1998-2000. In the event that expiring
letters of credit are not replaced or extended, the corresponding variable rate
debt obligations would be subject to mandatory redemption. While the Company
intends to pay or refinance maturing bonds, and to replace or extend expiring
letters of credit, there can be no assurance that the Company will be able to
pay such debt or replace or extend such letters of credit. The Company's future
cash flows will also be affected by the level of interest rates due to the
significant amount of variable rate debt outstanding. See Liquidity and Capital
Resources below.
The Company's capital structure is highly leveraged and the Company's
ability to raise capital (through either public or private financings) is
limited. The Company's ability to obtain debt financing is limited 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 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. As discussed in
Liquidity and Capital Resources below, there are a variety of factors that could
cause actual cash flows to differ materially from projected cash flows. As of
March 4, 1997, the Company's cash balance including cash equivalents was
approximately $82 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 prices 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, wholesale sales
have been made at prices which 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 may 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 Policy Act
of 1992 has promoted increased competition in the wholesale electric power
markets by encouraging the participation of utility affiliates, independent
power producers and other non-utility participants in the development of power
generation.
The FERC issued two orders pertaining to transmission access in April 1996.
FERC Order No. 888, among other things, requires all public utilities that own,
control, or operate interstate transmission facilities to offer transmission
service to others under a single tariff that incorporates certain minimum terms
and conditions of transmission service established by the FERC. This tariff
must also be used by public utilities for their own wholesale market
transactions. Transmission and generation services for new wholesale service
are to be unbundled and priced separately. FERC Order No. 889 requires
transmission service providers to establish or participate in an open access
same-time information system (OASIS) that provides information on the
availability of transmission capacity to wholesale market participants. The
order also establishes standards of conduct that are designed to prevent
employees of a public utility engaged in marketing functions from obtaining
preferential access to OASIS-related information or from engaging in unduly
discriminatory business practices.
Given the level of competition already present in the wholesale market for
electricity, the Company does not believe that FERC Order No. 888 or Order No.
889 will have a material effect on the Company's future results of operations.
However, these orders could assume greater significance if the Company's retail
service territory were to be opened to competing suppliers of electricity.
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. However, the Company does compete against gas service suppliers and
others who may provide energy services which would be substitutes for, or bypass
of, the Company's services. In addition, the ACC recently adopted rules that
require a phase-in of retail electric competition in Arizona over a four year
period beginning January 1, 1999.
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 the Public Utilities Regulatory
Act of 1978, as amended. 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. For example, the Company's two
principal 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. In 1996, the Company negotiated contract amendments with
its largest mining customer. In return for further rate reductions and a market
pricing mechanism covering a portion of the customer's electrical load, service
to this customer was changed from a firm basis to an interruptible basis,
thereby delaying the Company's need for additional peaking capacity. In
addition, the provisions allowing for an early termination of the contract were
substantially narrowed. Such contract is scheduled to expire in January 2003,
while the contract with the Company's other principal mining customer is
scheduled to expire in March 2001. Early terminations of the contracts by
mining customers require 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.
On December 23, 1996, the ACC voted to adopt rules on retail electric
competition. The rules require each "Affected Utility" to open its retail
service area to competing electric service providers on a phased-in basis over
the period 1999 to 2003. Beginning no later than January 1, 1999, retail
customers representing at least 20% of each Affected Utility's 1995 peak demand
will be eligible to choose their electric service provider from companies
certificated by the ACC. Such service providers would include Affected
Utilities as well as other entities that apply for and receive a certificate of
convenience and necessity from the ACC. Beginning no later than January
1, 2001, retail customers representing at least 50% of each Affected Utility's
1995 peak demand will be eligible to choose their service provider. All
remaining retail customers would then be eligible to choose from certificated
service providers by January 1, 2003. Under the rules, Affected Utilities will
be required to provide distribution wheeling services (i.e., retail wheeling) at
rates approved by the ACC in order to facilitate sales by competing energy
providers. Such wheeling services would involve the transmission of energy
produced by other entities over the Company's transmission and distribution
system to consumers located in the Company's present retail service area.
While retail wheeling will expose the Company's service area to increased
competition, it will also open additional markets into which the Company may
sell its electric power.
The Affected Utilities whose service territories will be open to competing
service providers under the rules include Tucson Electric Power Company, Arizona
Public Service Company, Citizens Utilities Company, and several electric
cooperatives. However, electric cooperatives will be permitted to request a
modification to the proposed phase-in schedule in order to preserve their tax
exempt status or to modify power supply arrangements and related loan
agreements. Each of the Affected Utilities will be eligible to offer electric
service to customers of other certificated entities within Arizona.
Participation in competitive retail markets by other electric utilities which
are not regulated by the ACC, such as the Salt River Project and certain
municipal utilities, will be permitted under the rules on a similar reciprocal
basis (i.e., their service territories would be similarly open to competing
service providers).
The rules require new market entrants to obtain a certificate of
convenience and necessity from the ACC prior to offering retail electric
service. New market entrants will be required to demonstrate adequate technical
and financial capabilities to the ACC prior to certification. In addition, all
competitive market participants, including Affected Utilities, will be
required to obtain at least one-half of one percent of the energy sold
competitively in the Arizona retail market from new solar generating resources
by January 1, 1999. This required percentage will increase to one percent on
January 1, 2002. New solar resources are defined under the proposed rule as
photovoltaic or solar thermal resources that are installed on or after January
1, 1997. Electric service providers not in compliance with these solar
resource standards will be subject to a penalty of up to 30 cents per kWh to be
applied to the kWh deficiency in solar energy provided.
On January 10, 1997, the Company filed with the ACC a motion for
reconsideration and request for stay of the rules. The motion was filed in
order to provide the ACC with an opportunity to remedy certain procedural and
substantive deficiencies in the rules identified by the Company. Concerns
expressed by the Company in its motion included the potential impact on system
reliability, mechanisms for stranded cost quantification and recovery, the
ability to compete fairly with public power entities and recipients of federal
preference power, and certain legal deficiencies which would likely result in
legal appeals and litigation. On January 30, 1997, the Company's motion for
reconsideration was deemed denied by the ACC by operation of law. On February
28, 1997, the Company filed an appeal of the ACC order in both the Arizona
Superior Court and the Arizona Court of Appeals. At the present time, the
Company is unable to predict the outcome of the appeals or the effects such
rules, in their present form, would have on the Company's future results of
operations.
The Arizona Legislature is also investigating the potential merits of
retail electric competition. Legislation was passed in 1996 requiring the
establishment of a joint legislative study committee on electric industry
competition. This committee is charged with studying and making recommendations
on a wide variety of issues related to electric industry competition. The
committee is to complete a report to the legislature no later than December 31,
1997. Such report is to contain a proposal for electric utility
competition for implementation by December 31, 1999. An advisory committee on
electric industry competition was also created, consisting of members
representing electric consumers, electric utilities, various State offices and
agencies, and other interested parties. The Company has a representative on
such advisory committee who is actively participating as a committee member.
Bills pertaining to electric utility competition have recently been filed
in the Arizona Legislature. One of these bills, House Bill 2202, contains
various provisions relating to electric industry restructuring including, among
other things, standards for retail electric competition, electric utility
restructuring plans, retail customer choice and supplier registration. Another
bill, House Bill 2213, would require the ACC to establish a pilot program for
the purpose of determining the implications of retail competition in the
electric industry. The Company is closely monitoring legislative activity
related to these bills and other proposed legislation that could affect the
Company.
The Company cannot predict whether or not there will be competing
initiatives on industry restructuring from both the ACC and the Arizona
Legislature. However, the Company believes that certain matters contained in
the ACC's rules on retail competition may require legislative changes, while
other matters may require constitutional amendments. The Company will continue
to assess the likely impact of the ACC's rules on retail competition, proposed
legislation on retail competition, and other potential market reforms on the
Company. At the present time the Company is unable to predict the ultimate
impact of increased wholesale and retail competition on the Company's future
results of operations. See Accounting for the Effects of Regulation below, and
Note 1 of Notes to Consolidated Financial Statements, Nature of Operations and
Summary of Significant Accounting Policies, Accounting for the Effects of
Regulation for a discussion of the potential impact of increased competition on
the Company's accounting policies.
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. 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 structure
commonly used in the electric industry 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 conditioned upon receiving approval from the ACC and the FERC.
In February 1995, the Company filed a Notice of Intent to Form a Holding Company
with the ACC. In February 1996, the ACC denied the formation of a holding
company, and instead granted the Company a waiver giving the Company the
authority to invest in subsidiaries that will engage in energy-related projects.
See Investments in Energy-Related Ventures below. As a result of the ACC order,
the Company did not establish the holding company structure and withdrew its
holding company application with the FERC.
Since the Company believes that a holding company structure would be
beneficial, the Company may file another application with the ACC in 1997 for
approval of a holding company structure. If the requisite regulatory approvals
are received, then the Company would likely effect the one-for-one share
exchange described above. It is likely that no further Shareholder approval
would be required to effect such share exchange.
If the holding company structure were to be established, substantially
all of its assets initially following the share exchange would consist of the
Company's Common Stock. The holding company would rely primarily on funding
sources other than TEP to fund its operations and to capitalize affiliate
companies because the Company is currently prohibited from paying dividends (see
Dividends on Common Stock below) and because the Company may be prohibited from
making investments in the holding company or affiliated companies. Also, the
ACC's affiliated interest rules would limit certain transactions between the
holding company and the Company unless approved by the ACC. Accordingly, funds
for the holding company would be limited until the holding company obtains
outside financing or until the affiliate companies are able to pay cash
dividends to the holding company. The Company is reviewing various methods for
the holding company to obtain outside financing, including the issuance of new
equity by the holding company.
In the unlikely event the holding company incurs liabilities in excess of
cash flow available from the Company, the affiliate companies or outside
financings, the holding company might not have sufficient cash available to meet
such liabilities. Under such circumstances the Company may be required to seek
waivers of the provisions of certain of its credit agreements and leases and the
affiliated interest rules in order to permit the Company to provide interim
financing to the holding company. There can be no assurance that a holding
company structure will be effected in the future, that the holding company will
be able to obtain outside financing, or that the Company would be able to obtain
necessary waivers if so required.
INVESTMENTS IN ENERGY-RELATED VENTURES
The Company has established four wholly-owned subsidiaries for the purpose
of pursuing various energy-related investment opportunities. In 1995,the Company
established Nations Energy Corporation for the purpose of investing
in independent power projects in the domestic and foreign energy markets. In
September 1995, Nations Energy and Trigen Energy Corporation formed a limited
partnership which purchased Coors Brewing Company's energy production assets.
Nations Energy has a 49% interest in such partnership. In 1996, a wholly-owned
subsidiary of Nations Energy acquired an ownership interest in two companies
located in the Czech Republic for the purpose of participating in a power
project to be developed near the City of Kladno, Czech Republic. This project
involves the upgrading and expansion of an existing coal-fired thermal and
electric generating plant. Participation in this project will require
additional capital investment by Nations and related investment authority from
the ACC. In addition to these projects, Nations Energy is presently evaluating
several other investment opportunities in the domestic and foreign energy
markets.
In May 1996 the Company established Advanced Energy Technologies, Inc.
(formerly known as TEP Solar Energy Corporation). This wholly-owned subsidiary
is responsible for developing renewable energy and distributed generation
technologies, and in 1996 it acquired a 50% ownership interest in Global Solar
Energy, LLC, an Arizona corporation recently formed for the purpose of
developing and manufacturing flexible thin-film photovoltaic cells. Commercial
production of photovoltaic cells is presently scheduled to commence in mid-1997.
Global Solar's manufacturing facility is initially expected to produce up to
1,500 kW of product, or approximately 255,000 square-feet of photovoltaic
material, per year.
SWPP Investment Company was formed in 1996 for the purpose of holding an
ownership interest in a business engaged in the manufacture and sale of concrete
power poles. Although SWPP has yet to acquire such ownership interest, the
Company currently has a contract with a Mexican corporation for the distribution
and sale of concrete power poles in the United States.
In January 1997, the Company established another wholly-owned subsidiary
known as Southwest Energy Solutions, Inc. It is anticipated that Southwest
Energy will provide a variety of ancillary energy services to retail electric
consumers. Southwest Energy will likely focus its initial marketing efforts on
electric energy consumers in southern Arizona.
In addition to the activities currently underway or planned for each of
these subsidiaries, the Company continues to evaluate potential investment
opportunities in other energy-related markets. For example, the Company
currently has a consulting services contract with New Energy Ventures Inc.
(NEV), a California corporation. NEV, which recently obtained a Federal Power
Marketer's license from the FERC, is a buyer's agent providing load aggregation
and advisory services to energy consumers located primarily in California. The
Company has a currently exercisable option (through February 1998) to purchase
for a nominal amount a 50% interest in NEV.
In comparison to the Company's large investment in regulated utility
assets, the Company's current investments in Nations Energy, Advanced Energy,
SWPP and Southwest Energy are not material in terms of recorded assets or net
income. As of December 31, 1996, the Company's Consolidated Balance Sheet
reflected an investment in energy-related ventures of approximately $22 million
(included in Investments and Other Property). However, depending on the nature
of future investment opportunities, and the ability of the Company to make
additional investments as determined by the ACC and in certain credit
agreements, the Company expects to make additional investments in these
subsidiaries and in other energy-related ventures. Over time, such additional
investments may have a material impact on the Company's future cash flow and
profitability. Pursuant to an ACC order issued in February 1996, the Company is
permitted to invest in subsidiaries that 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 further authority from the ACC, the
Company would be authorized to expend additional funds. This investment
authority is subject to the conditions that (i) the total amount permitted to be
invested in such projects shall not exceed $50 million annually, (ii) 60% of net
profits from such projects be applied to repay the Company's debt, and (iii)
total investment in such projects does not exceed 15% of the Company's
capitalization. Under the MRA, the Company's capital investments are restricted
to assets which are related to the utility business, and are limited in size by
a ceiling on total capital expenditures and investments. The Company is
currently reviewing different alternatives for funding investments in energy-
related ventures.
RESULTS OF OPERATIONS
In 1996, the Company had net income of $120.9 million or $3.76 per average
share of common stock compared with $54.9 million or $1.71 per average share of
common stock in 1995 and $20.7 million or $0.65 per average share of common
stock in 1994.
The improvement in earnings in 1996 was due primarily to the recognition of
substantial non-cash income tax benefits as well as from increased sales and
revenues, reduced operating and capital costs, and a reversal of loss provision
involving the Company's non-energy related subsidiaries.
RESULTS OF UTILITY OPERATIONS
SALES AND REVENUES
Retail sales and revenues are affected principally by price changes,
consumption and growth factors. In 1996, the increase in retail revenues was
mostly due to customer growth and increased customer consumption. The average
number of retail customers grew by 3.0% in 1996. Warmer temperatures and
an increase in industrial energy consumption also contributed to higher energy
sales on a per customer basis in 1996 relative to 1995. Although prices
increased due to the implementation of a 1.1% retail rate increase on March 31,
1996, the impact on revenues was small compared to the impact of customer growth
and the increase in customer consumption.
Revenues from sales to retail customers increased 6.4% in 1996 compared
with 1995 and 0.6% in 1995 compared with 1994. The following table identifies
the components of the increases in 1996 and 1995:
1996 1995
==== ====
- Millions of Dollars -
1994 Price Change $ 0 $ 3
1996 Price Change 6 0
Consumption Change 14 (13)
Customer Growth 16 13
--- ---
Increase in Retail Revenues $ 36 $ 3
KWh sales to retail customers increased by 5.1% in 1996 compared with 1995.
The kWh sales increase resulted from an increase in the average number of retail
customers and increased usage due to higher industrial energy consumption and
warmer temperatures in 1996 compared with 1995. Based on 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 10% increase in such cooling degree days for 1996
compared with 1995, and a 5% increase in such cooling degree days for 1996
compared with the 10 year average for the same period from 1986 to 1995.
Specifically, cooling degree days were 1,488, 1,354, and 1,415 for 1996, 1995,
and the 10 year average, respectively. The Company had 306,773 retail customers
on average in 1996. KWh sales in 1995 compared with 1994 increased as a result
of a 2.9% increase in the average number of customers, partially offset by
reduced consumption due to cooler temperatures.
Revenues from sales to retail customers increased in 1996 compared with
1995 due to higher kWh sales discussed above and the rate increase allowed under
the 1996 Rate Order. In 1995, revenues increased 0.6% over 1994 due to
slightly higher kWh sales and a full year of increased prices resulting from the
1994 Rate Order.
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. KWh sales for resale increased by 46% in 1996 compared to
1995. This increase was attributable to several factors: the availability of
generating capacity which was out of service for planned maintenance during
1995; higher regional loads due to warmer weather conditions in the second
quarter of 1996; higher demands for power generated in the southwestern United
States due to a reduction in power transfer capability between the Pacific
Northwest and California during the third quarter of 1996; and higher natural
gas prices which contributed to increased sales of surplus coal-fired energy.
Revenues from sales for resale increased by 11% in 1996 compared to 1995. Such
revenues did not increase proportionately with the increase in kWh sales due to
the loss of demand revenues attributable to the expiration of a firm power sale
agreement with Nevada Power Company in December 1995.
In 1995, revenues from sales for resale decreased by 24% compared with 1994
as a result of lower sales and lower spot market prices. Energy sales in
1995 were affected by lower regional loads attributable to mild weather
conditions and increased availability of lower cost hydroelectric power in the
western United States.
OPERATING EXPENSES
Fuel and Purchased Power expense increased in 1996 compared with 1995 due
to increased kWh sales and a one-time $12.2 million reduction to fuel expense
recorded in 1995. This one-time non-cash reduction to fuel expense was related
to the satisfaction of certain fuel contract provisions. Fuel and purchased
power expense decreased in 1995 compared with 1994 as a result of lower
generation requirements in 1995 than in 1994, the one-time $12.2 million
reduction to fuel expenses in 1995, and lower incremental fuel costs resulting
from fuel contracts negotiations. Excluding deferred fuel expenses and the one-
time $12.2 million reduction to fuel expenses in 1995, the average cost of fuel
per kWh generated was 1.83 cents, 1.77 cents and 1.80 cents for 1996, 1995 and
1994, respectively. Such fuel costs include costs associated with the
Springerville coal handling facilities and have been restated to reflect the
merger of Valencia into the Company in May 1996.
Maintenance and Repairs expense was lower in 1996 than in 1995 due
primarily to overhaul work performed at the San Juan and Springerville stations
in 1995.
Depreciation and Amortization expense increased in 1996 relative to 1995
due to the amortization of additional Springerville Unit 2 rate synchronization
costs which are being recovered over a three year period pursuant to the 1996
Rate Order. See Note 2 of Notes to Consolidated Financial Statements, 1996 Rate
Order.
Employee Severance Plan Expense - Net of $10.6 million in 1996 reflects
implementation of the Company's Voluntary Severance Plan in the second
quarter of 1996 and related pension settlements. The VSP, which was offered to
nearly all of the Company's employees in May 1996, was accepted by approximately
200 employees, or 15% of the total workforce.
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)
Income Tax benefits included in Other Income (Deductions) increased in 1996
compared with 1995 due primarily to the recognition of non-cash income tax
benefits associated with the current and expected future utilization of federal
and state net operating loss carryforwards generated in prior periods. Such
recognized benefits totaled $88.6 million in 1996 and $23.3 million in 1995.
The recognition of such benefits in 1995 also caused total income tax benefits
to be higher in 1995 compared with 1994. In 1994 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 for 1994
reflected only ITC amortization. See Income Tax Position below.
A Reversal of Loss Provision in the amount of $8.5 million was recorded in
the third quarter of 1996. The reversal of loss provision relates to the
satisfaction by the Company's non-energy related subsidiaries of approximately
$8.5 million of short-term debt obligations through the assignment of certain
finance receivables held by such subsidiaries. See Note 5 of Notes to
Consolidated Financial Statements, Long and Short-Term Debt and Capital Lease
Obligations, Short-Term Debt, Investment Subsidiaries.
INTEREST EXPENSE
Interest Expense on Long-Term Debt decreased in 1996 compared with
1995 due to a reduction in the average amount of debt outstanding and due to
lower interest rates on the Company's variable rate debt obligations. The
weighted average interest rate on the Company's tax exempt variable rate debt
obligations was 3.5% in 1996 and 3.9% in 1995.
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, 1996 and 1995 contain certain line items (for example, 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 for the years ended
December 31, 1996, 1995 and 1994 also reflect the application of FAS 71. See
Note 1 of Notes to Consolidated Financial Statements, Nature of Operations and
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, 1996, the Company estimates that
future adoption of FAS 101 for all of the Company's regulated operations would
result in an extraordinary loss of $157 million, which includes a reduction for
the related deferred income taxes of $81 million. The Company's cash flows
would not be affected by the adoption of FAS 101.
At the present time, the Company recovers the costs of its plant assets
through its regulated revenues. If in the future the Company discontinues
accounting according to the provisions of FAS 71, the Company would also need to
consider whether the markets in which the Company is then selling power will
allow the Company to recover the costs of its plant assets. If at that time
market prices are not expected to allow the Company to recover the costs of its
plant assets, additional write-downs may be required in accordance with the
provisions of FAS 121.
DIVIDENDS ON COMMON STOCK
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 debts 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. The Company
is not currently prevented from declaring and paying a dividend under such
provisions.
The Company's ability to pay a dividend is restricted by certain covenants
of the General First Mortgage. 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 test
would 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 retained earnings test would permit
dividend payments if the Company has positive retained earnings rather than an
accumulated deficit. As of December 31, 1996, the Company had a cash flow
coverage ratio in excess of 2 to 1 and the Company's accumulated deficit was
$506 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 dividend restriction based on the amount of 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. At February 28, 1997, there was no outstanding balance
due under the Renewable Term Loan, and to date no amounts have been borrowed
under the Revolving Credit. Commitments relating to such facilities permit the
Company to borrow $164 million under the Renewable Term Loan and $50 million
under the Revolving Credit. The Company's senior long-term 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 General First
Mortgage amendment would require approval by holders of 75% of all First
Mortgage Bonds.
In addition to such restrictive covenants, the Federal Power Act states
that dividends shall not be paid out of funds properly included in the capital
account. It is unclear whether such provisions of the Federal Power Act
restrict the Company from paying dividends.
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 1994 to 1996, to cover all construction expenditures and debt
maturities.
Net cash flows from continuing operating activities increased in aggregate
by $32 million in 1996 compared with 1995 due primarily to a $38 million
increase in cash receipts from retail customers, an $8 million decrease in
interest paid (net of amounts capitalized), and a reduction of $18 million in
taxes paid (net of amounts capitalized). The reduction in taxes paid was mainly
attributable to a $14.6 million tax payment in 1995 made by the Company in
connection with an appeal of a transaction privilege tax assessment (see Note 6
of Notes to Consolidated Financial Statements, Commitments and Contingencies ).
These increases to net cash flows were partially offset by a $13 million
increase in fuel and purchased power payments, a $10 million increase in wages
paid (net of amounts capitalized), a $5 million reduction in net cash flows
derived from sales and purchases of emission allowances, and the establishment
of a $4.5 million low income customer assistance fund required by the 1996 Rate
Order. The increase in fuel and purchased power payments was mainly
attributable to increased energy sales, while the increase in wages paid was due
primarily to implementation of the Company's Voluntary Severance Plan in the
second quarter of 1996.
Net cash outflows from investing activities decreased in aggregate by $10
million in 1996 compared with 1995 due primarily to the May 1995 purchase of
approximately $18 million of Springerville Unit 1 lease debt securities. This
decrease in net cash outflows was partially offset by a $7 million increase in
construction expenditures in 1996 compared with 1995.
Net cash outflows from financing activities decreased in aggregate by $166
million in 1996 compared with 1995 due to lower debt principal repayments and
the receipt of loan proceeds related to the May 1996 issuance of pollution
control bonds by the Pollution Control Corporation of Coconino County, Arizona.
See Financing Developments below. Payments toward the retirement of capital
lease obligations increased by $19 million due primarily to a scheduled $23.8
million lease payment on Irvington Unit 4 made in July 1996. Lease payments on
Irvington Unit 4 totaled $28.0 million during 1996, compared with $8.5 million
in 1995. Future scheduled lease payments on Irvington Unit 4 average
approximately $13 million per year through the end of the lease term in 2011.
During 1997, the Company expects to generate sufficient internal cash flows
to fund its continuing operating activities and construction expenditures.
However, the Company's cash flows are subject to variation due to changes in
wholesale revenues, changes in short-term interest rates, and other factors.
For example, an increase in short-term interest rates of 100 basis points (1%)
would result in an approximate $10 million increase in annual interest payments.
If cash flows were to fall short of expectations, the Company would rely on
existing cash balances, borrowings under the Renewable Term Loan and, if
necessary, borrowings under the Revolving Credit.
As a result of activities described above, the Company's cash
and cash equivalents increased by $45 million or 53% from the 1995 year-end
balance of $85 million to the 1996 year-end balance of $130 million. The
Company's cash balance including cash equivalents at March 4, 1997, was
approximately $82 million. Cash balances are invested in investment grade,
money-market securities with an emphasis on preserving the principal amounts
invested.
FINANCING DEVELOPMENTS
In May 1996, the Pollution Control Corporation of Coconino County, Arizona
issued $16.7 million aggregate principal amount of its Series A pollution
control revenue bonds for the benefit of the Company. The proceeds from this
issuance have been loaned to the Company to reimburse the Company for
expenditures related to the Company's interest in pollution abatement facilities
at the Navajo Generating Station.
In May 1996, the Pollution Control Corporation of Coconino County, Arizona
also issued $14.7 million aggregate principal of its Series B pollution control
refunding revenue bonds for the benefit of the Company. The proceeds from this
issuance have been loaned to the Company and were used on June 14, 1996, to
redeem all of the Company's 1975 Series A pollution control revenue bonds (8.25%
due in 2005) then outstanding.
In February 1996, the Company retired upon maturity the $10 million balance
of 4.875% first mortgage bonds then outstanding. The Company retired an
additional $1.6 million of long-term debt during 1996 due to scheduled sinking
fund payments.
In January 1997, the Company obtained a tax-exempt volume cap allocation
from the state of Arizona. The Company's allocation is for $20 million to be
issued by the Pollution Control Corporation of the county of Coconino
in Arizona, for the benefit of the Company. The Company intends to issue such
bonds by May 1997. 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. See
Construction Expenditures below. In conjunction with the planned issuance of
pollution control bonds, the Company may also decide to refund certain existing
tax-exempt bonds and/or convert certain variable rate bonds to a fixed rate of
interest. The Company filed a financing application with the ACC on February
28, 1997, to request approval for the issuance of new tax-exempt bonds and for
the refunding of certain existing tax-exempt bonds.
Subsequent to December 31, 1996, the Company repaid the outstanding
Renewable Term Loan balance of $31 million.
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 has 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 of 1.5% during
1997 and 2% in 1998 and 1999. 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 $3.6 million of short-term debt of the non-energy related
subsidiaries as of December 31, 1996, 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, 1996, the Company had, for federal income tax purposes,
approximately $489 million of net operating loss carryforwards expiring in 2004
through 2009 and $96 million of alternative minimum tax loss carryforwards
expiring in 2006 through 2008. For state income tax purposes, the Company has
approximately $79 million of net operating loss carryforwards expiring in 1997
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,
$11 million of capital loss carryforwards which expire during 1997 through 1999,
and $4 million of alternative minimum tax credit which will carry forward to
future years.
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, for federal income tax purposes 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 limitation 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 1996, 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, 1996, the Company had pre-change federal net operating
loss, ITC, and alternative minimum tax loss carryforwards of approximately $333
million, $26 million and $63 million, respectively. Such amounts are included
in the amounts disclosed in the preceding paragraph.
For financial statement purposes, the Company recognized in 1996 and 1995
income tax benefits of $89 million and $23 million, respectively, related to the
current and expected future utilization of the federal and state carryforwards
which are included in Income Taxes in Other Income (Deductions) in the
Consolidated Statements of Income. The recognition of these benefits results
from a revision in the estimated amount of NOLs that the Company believes are
likely to reduce future taxable income. The Company recognizes benefits related
to prior period NOLs based on changes in the estimated amount of NOLs that, in
the Company's judgment, are more likely than not to be realized in the future.
A significant factor, among others, considered in estimating such amount is the
three year historical average book income before taxes.
If the Company's operating results continue to improve, the three year
historical average net book income would continue to increase. Correspondingly,
for financial statement purposes the Company would likely recognize NOL benefits
totaling up to approximately $45 million over the next two years relating to
prior period NOLs unrecognized at December 31, 1996. The amount of NOL benefits
recognized in periods subsequent to 1996, if any, and the timeframe in which
such benefits are recognized, may vary significantly from the estimates
described in this paragraph. In addition, in future periods when such
NOLs are utilized for federal income tax purposes to offset taxable income,
income tax expense shown on the Company's Consolidated Statements of
Income will not be reduced to reflect such utilization.
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, 1996, the Company had the ability to
issue approximately $105 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 $101 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 on Common Stock 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, 1996, $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, 1996, the amount of net additions and retired bonds
would permit (and the net earnings test would not prohibit) the issuance
of $300 million aggregate principal amount of new Second Mortgage Bonds (at an
assumed interest rate of 11% per annum). The issuance of such amount of Second
Mortgage Bonds assumes that the $206 million of First Mortgage Bonds available
to be issued at December 31, 1996 would be issued first at a rate of 10%.
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 1.50 to 1 in 1996 and gradually increasing to 2 to 1 in
2000 continuing through the year 2003. For the year ended December 31, 1996,
the Company's MRA interest coverage ratio was 3.15 to 1. With respect to
dividends, 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, the MRA incorporates a restrictive covenant similar to
that currently in the General First Mortgage. Such restrictive covenant 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 $506 million at December 31,
1996. (See Dividends on Common Stock 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 1997 through 2001, respectively, are $91 million, $80 million, $53
million, $52 million and $48 million. These amounts include the following: $195
million for transmission and distribution facilities in the Tucson area; $17
million for expenditures which are necessary to upgrade pollution control
facilities at Navajo (see Item 1., Business, Environmental Matters, Navajo
Generating Station); $20 million for expenditures associated with the pollution
control facilities at San Juan (see Item 1., Business, Environmental Matters,
San Juan Generating Station); $8 million for purchasing generation equipment
currently being leased by the Company; and $84 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 restrictive covenants contained in the MRA
regarding the incurrence of additional indebtedness, the Company will likely
fund these construction expenditures and any additional investments in energy-
related subsidiaries through internally generated funds, the issuance of tax-
exempt debt (when available), the issuance of Common Stock (as appropriate),
and/or reductions in 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
Contingencies, respectively.
SAFE HARBOR FOR FORWARD LOOKING STATEMENTS
The Company is including the following cautionary statements to make
applicable and take advantage of the safe harbor provisions of the Private
Securities Litigation Reform Act of 1995 for any forward-looking statements made
by, or on behalf, of the Company in this Annual Report on Form 10-K. Forward-
looking statements include statements concerning plans, objectives, goals,
strategies, future events or performance and underlying assumptions and other
statements which are other than statements of historical facts. Such forward-
looking statements may be identified, without limitation, by the use of the
words "anticipates," "estimates," "expects," "intends," "plans," "predicts,"
"projects," and similar expressions. From time to time, the Company may publish
or otherwise make available forward-looking statements of this nature. All such
forward-looking statements, whether written or oral, and whether made by or on
behalf of the Company, are expressly qualified by these cautionary statements
and any other cautionary statements which may accompany the forward-looking
statements. In addition, the Company disclaims any obligation to update any
forward-looking statements to reflect events or circumstances after the date
hereof.
Forward-looking statements involve risks and uncertainties which could
cause actual results or outcomes to differ materially from those expressed in
the forward-looking statements. The Company's expectations, beliefs and
projections are expressed in good faith and are believed by the Company
to have a reasonable basis, including without limitation, management's
examination of historical operating trends, data contained in the Company's
records and other data available from third parties, but there can be no
assurance that management's expectations, beliefs or projections will result or
be achieved or accomplished. In addition to other factors and matters discussed
elsewhere herein, some of the important factors that, in the view of the
Company, could cause actual results to differ materially from those discussed in
the forward-looking statements include the following:
1. Effects of restructuring initiatives in the electric industry and other
energy-related industries.
2. Changes in economic conditions, demographic patterns and weather conditions
in the Company's retail service area.
3. Changes affecting the Company's cost of providing electrical service
including, but not limited to, changes in fuel costs, generating unit
operating performance, interest rates, tax laws, environmental laws, and the
general rate of inflation.
4. Changes in governmental policies and regulatory actions with respect to
allowed rates of return, financings, and rate structures.
5. Changes affecting the cost of competing energy alternatives, including
changes in available generating technologies and changes in the cost of
natural gas.
6. Changes in accounting principles or the application of such principles to
the Company.
ITEM 8. -- CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See Item 14, page 66, 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 AND ITS STOCKHOLDERS
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, 1996 and 1995, and the related consolidated
statements of income, changes in stockholders' equity (deficit), and cash flows
for each of the three years in the period ended December 31, 1996. 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, 1996
and 1995, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 1996 in conformity with
generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Tucson, Arizona
January 27, 1997
CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31,
1996 1995 1994
- Thousands of Dollars -
Operating Revenues
Retail Customers $ 611,564 $ 574,925 $ 571,433
Amortization of MSR Option Gain
Regulatory Liability 20,053 20,053 20,053
Sales for Resale 84,256 75,591 99,987
---------- ---------- ----------
Total Operating Revenues 715,873 670,569 691,473
---------- ---------- ----------
Operating Expenses
Fuel and Purchased Power 208,808 167,989 204,668
Capital Lease Expense 104,087 105,368 102,994
Amortization of Springerville
Unit 1 Allowance (29,090) (28,432) (26,204)
Other Operations 97,555 99,883 101,823
Maintenance and Repairs 36,449 41,801 44,781
Depreciation and Amortization 98,246 93,136 90,909
Taxes Other Than Income Taxes 61,902 58,733 57,718
Employee Severance Expense - Net 10,555 - -
Income Taxes 9,795 8,920 (91)
---------- ---------- ----------
Total Operating Expenses 598,307 547,398 576,598
---------- ---------- ----------
Operating Income 117,566 123,171 114,875
---------- ---------- ----------
Other Income (Deductions)
Income Taxes 91,950 29,356 4,820
Reversal of Loss Provision 8,472 - -
Interest Income 6,271 8,222 7,556
Deferred Springerville Unit 2 Carrying
Costs 286 1,127 1,133
Other Income (Deductions) (1,020) 2,826 489
---------- ---------- ----------
Total Other Income (Deductions) 105,959 41,531 13,998
---------- ---------- ----------
Interest Expense
Long-Term Debt 59,647 69,174 69,353
Interest Imputed on Losses Recorded at
Present Value 32,599 32,633 32,280
Other Interest Expense 11,721 9,113 7,591
Allowance for Borrowed Funds Used
During Construction (1,294) (1,123) (1,091)
---------- ---------- ----------
Total Interest Expense 102,673 109,797 108,133
---------- ---------- ----------
(continued on next page)
CONSOLIDATED STATEMENTS OF INCOME (Continued)
For the Years Ended December 31,
1996 1995 1994
- Thousands of Dollars -
Net Income $ 120,852 $ 54,905 $ 20,740
========== ========== ==========
Average Shares of
Common Stock Outstanding (000) 32,134 32,138 32,145
========== ========== ==========
Net Income per Average Share $ 3.76 $ 1.71 $ 0.65
========== ========== ==========
See Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31,
1996 1995 1994
- Thousands of Dollars -
Cash Flows from Continuing Operating Activities
Cash Receipts from Retail Customers $653,933 $616,064 $611,917
Cash Receipts from Sales for Resale 80,123 80,415 99,198
Fuel and Purchased Power Costs Paid (180,134) (167,672) (187,130)
Wages Paid, Net of Amounts Capitalized (73,184) (63,412) (51,960)
Payment of Other Operations and
Maintenance Costs (76,529) (75,504) (73,036)
Capital Lease Interest Paid (84,383) (83,986) (82,511)
Interest Paid, Net of Amounts Capitalized (70,275) (78,743) (72,556)
Taxes Paid, Net of Amounts Capitalized (103,079) (120,759) (107,594)
Income Taxes Paid (1,566) (1,960) -
Emission Allowance Inventory Purchases (12,340) (4,190) -
Emission Allowance Inventory Sales 14,710 11,255 -
Interest Received 6,342 7,882 7,288
Other (2,351) - -
--------- --------- ---------
Net Cash Flows -
Continuing Operating Activities 151,267 119,390 143,616
--------- --------- ---------
Net Cash Flows - Discontinued Operations - - 42,685
--------- --------- ---------
Cash Flows from Investing Activities
Construction Expenditures (66,519) (59,097) (62,599)
Purchase of Debt Securities - (17,697) -
Investments in Joint Ventures (9,173) (12,429) -
Other Investments - Net 240 3,321 103
--------- --------- ---------
Net Cash Flows - Investing Activities (75,452) (85,902) (62,496)
--------- --------- ---------
Cash Flows from Financing Activities
Proceeds from Issuance of Long-Term Debt 31,400 - -
Proceeds from Borrowings Under the
Renewable Term Loan 14,000 - -
Payments on Renewable Term Loan (14,000) (143,060) -
Payments to Retire Long-Term Debt (26,275) (36,507) (19,424)
Payments to Retire Capital Lease Obligations (36,292) (17,231) (17,747)
Other 549 252 (478)
--------- --------- ---------
Net Cash Flows - Financing Activities (30,618) (196,546) (37,649)
--------- --------- ---------
Net Increase (Decrease) in
Cash and Cash Equivalents 45,197 (163,058) 86,156
Cash and Cash Equivalents, Beginning of Year 85,094 248,152 161,996
--------- --------- ---------
Cash and Cash Equivalents, End of Year $130,291 $ 85,094 $248,152
========= ========= =========
(continued on next page)
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
See Notes to Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
1996 1995
- Thousands of Dollars -
Utility Plant
Plant in Service $2,129,205 $2,095,679
Utility Plant Under Capital Leases 893,064 893,064
Construction Work in Progress 74,210 50,898
----------- -----------
Total Utility Plant 3,096,479 3,039,641
Less Accumulated Depreciation and Amortization (922,947) (859,227)
Less Accumulated Amortization of Capital Leases (56,240) (40,113)
Less Springerville Unit 1 Allowance (163,388) (162,175)
----------- -----------
Total Utility Plant - Net 1,953,904 1,978,126
----------- -----------
Investments and Other Property 69,289 52,116
----------- -----------
Current Assets
Cash and Cash Equivalents 130,291 85,094
Accounts Receivable 65,905 61,717
Materials and Fuel 30,356 42,168
Deferred Income Taxes - Current 10,223 18,250
Other 14,026 7,565
----------- -----------
Total Current Assets 250,801 214,794
----------- -----------
Deferred Debits - Regulatory Assets
Income Taxes Recoverable Through Future Rates 173,731 168,488
Deferred Common Facility Costs 60,762 63,303
Deferred Springerville Unit 2 Costs 21,260 42,039
Deferred Lease Expense 15,067 19,808
Other Deferred Regulatory Assets 8,004 8,576
Deferred Debits - Other 15,723 16,211
----------- -----------
Total Deferred Debits 294,547 318,425
----------- -----------
Total Assets $2,568,541 $2,563,461
=========== ===========
See Notes to Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND OTHER LIABILITIES
December 31,
1996 1995
- Thousands of Dollars -
Capitalization
Common Stock Equity $ 133,288 $ 12,488
Capital Lease Obligations 895,867 897,958
Long-Term Debt 1,223,025 1,207,460
----------- -----------
Total Capitalization 2,252,180 2,117,906
----------- -----------
Current Liabilities
Short-Term Debt 3,567 12,039
Current Obligations Under Capital Leases 10,383 33,389
Current Maturities of Long-Term Debt 1,635 12,075
Accounts Payable 28,806 27,162
Interest Accrued 57,404 57,389
Taxes Accrued 24,007 15,696
Other 15,614 19,685
----------- -----------
Total Current Liabilities 141,416 177,435
----------- -----------
Deferred Credits and Other Liabilities
Deferred Income Taxes - Noncurrent 96,422 178,513
Accumulated Deferred Investment Tax Credits
Regulatory Liability 15,188 19,603
MSR Option Gain Regulatory Liability 7,853 25,610
Other Regulatory Liabilities 17,596 10,343
Other 37,886 34,051
----------- -----------
Total Deferred Credits and Other Liabilities 174,945 268,120
----------- -----------
Total Capitalization and Other Liabilities $2,568,541 $2,563,461
=========== ===========
See Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
1996 1995
COMMON STOCK EQUITY - Thousands of Dollars -
Common Stock--No Par Value 1996 1995
----------- -----------
Shares Authorized 75,000,000 75,000,000
Shares Outstanding 32,134,610 32,138,261
Warrants Outstanding * 2,410,856 2,410,856 $ 645,243 $ 645,295
Capital Stock Expense (6,357) (6,357)
Accumulated Deficit (505,598) (626,450)
----------- -----------
Total Common Stock Equity 133,288 12,488
----------- -----------
PREFERRED STOCK, No Par Value,
1,000,000 Shares Authorized, None Outstanding - -
CAPITAL LEASE OBLIGATIONS
Springerville Unit 1 474,523 466,187
Springerville Coal Handling Facilities 172,424 179,990
Springerville Common Facilities 131,743 136,128
Irvington Unit 4 122,818 142,878
Other Leases 4,742 6,164
----------- -----------
Total Capital Lease Obligations 906,250 931,347
Less Current Maturities (10,383) (33,389)
----------- -----------
Total Long-Term Capital Lease Obligations 895,867 897,958
----------- -----------
LONG-TERM DEBT Interest
Issue Maturity Rate
- -----------------------------------------------------
First Mortgage Bonds
Corporate 1996 - 2009 4.88% to 12.22% 243,750 253,750
Industrial Development 2005 - 2025 6.10% to 8.25%
Revenue Bonds (IDBs) and variable** 248,400 232,200
Loan Agreements (IDBs) 2003 - 2022 6.25% and
variable** 701,510 702,585
Renewable Term Loan 1997 - 1999 variable** 31,000 31,000
----------- -----------
Total Stated Principal Amount 1,224,660 1,219,535
(continued on next page)
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Continued)
Less Current Maturities (1,635) (12,075)
----------- -----------
Total Long-Term Debt 1,223,025 1,207,460
----------- -----------
Total Capitalization $2,252,180 $2,117,906
=========== ===========
* The Warrants to purchase Common Stock at an exercise price of $16.00 per
share, are exercisable and expire in 2002.
** Interest rates on variable rate tax-exempt debt (IDBs) ranged from 2.35%
to 5.75% during 1996 and 1995, and the average interest rate on such debt
was 3.50% in 1996 and 3.91% in 1995. Interest rates on the Renewable Term
Loan ranged from 5.81% to 6.75% in 1996 and 1995, and the average interest
rate on such debt was 6.02% in 1996 and 6.50% in 1995.
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, 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
10,509 Shares Purchased by Deferred
Compensation Trust (184) - -
--------- -------- ----------
Balances at December 31, 1995 645,295 (6,357) (626,450)
1996 Net Income - - 120,852
2,886 Shares Issued Under Stock
Option Plans 47 - -
2,265 Shares Issued by Deferred
Compensation Trust 33 - -
8,802 Shares Purchased by Deferred
Compensation Trust (132) - -
--------- -------- ----------
Balances at December 31, 1996 $645,243 $(6,357) $(505,598)
========= ======== ==========
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 sales for resale to other
utilities and other power marketing entities in Arizona, California,
Colorado, New Mexico, Oregon, Texas and Utah. Approximately 62% of the
Company's work force is subject to a collective bargaining unit. The
collective bargaining agreement in place at December 31, 1996 terminates on
November 30, 1998.
BASIS OF PRESENTATION
The consolidated financial statements include the accounts of the
Company, five wholly-owned, utility-related subsidiaries and two other
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. On May 31, 1996,
Valencia Energy Company, a utility-related subsidiary, was merged into the
Company resulting in the reclassification of Fuel and Purchased Power expense
in the Consolidated Statements of Income. 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 contain certain amounts solely
as a result of the application of FAS 71:
December 31,
Assets (Liabilities) 1996 1995
-------------------- ----- -----
- Millions of Dollars -
Income Taxes Recoverable Through Future Rates $174 $168
Deferred Common Facility Costs 61 63
Deferred Springerville Unit 2 Costs 21 42
Deferred Lease Expense 15 20
Other Deferred Regulatory Assets 8 9
MSR Option Gain Regulatory Liability (8) (26)
Accumulated Deferred Investment Tax Credits
Regulatory Liability (15) (20)
Other Regulatory Liabilities (18) (10)
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 a return on
investment through inclusion in rate base and resultant recovery through
sales to retail customers.
A number of accounts in the Company's Consolidated Statements of Income
also reflect the application of FAS 71:
Years Ended December 31,
Income (Expense) 1996 1995 1994
---------------- ----- ----- -----
- Millions of Dollars -
Amortization of MSR Option Gain
Regulatory Liability $ 20 $ 20 $ 20
Amortization of Springerville Unit 2
Rate Synchronization (21) (14) (14)
Deferred Fuel and Purchased Power - (6) (7)
Amortization of Deferred Common Facility Costs (3) (3) (3)
Deferred Springerville Unit 2 Carrying Costs - 1 1
Investment Tax Credit Amortization 4 5 5
Interest Imputed on Loss (MSR Option Gain
Regulatory Liability) Recorded at Present Value (2) (4) (6)
If the Company had not applied the provisions of FAS 71 in these years,
each of these amounts included in the Consolidated Statements of Income 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, 1996, 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 $157 million, which includes a reduction for the
related deferred income taxes of $81 million. The Company's cash flows would
not be affected by the adoption of FAS 101.
At the present time, the Company recovers the costs of its plant assets
through its regulated revenues. If in the future the Company discontinues
accounting according to the provisions of FAS 71, the Company would also need
to consider whether the markets in which the Company is then selling power
will allow the Company to recover the costs of its plant assets. If at that
time market prices are not expected to allow the Company to recover the costs
of its plant assets, additional write-downs may be required in accordance
with the provisions of FAS 121. The Company is presently unable to predict
the amounts, if any, of any potential future write-downs attributable to the
provisions of FAS 121 under such circumstances.
UTILITY PLANT
Utility Plant by major classes is as follows:
December 31,
1996 1995
---------- ----------
- Thousands of Dollars -
Utility Plant:
Production Plant $1,019,528 $1,013,171
Transmission Plant 464,115 460,986
Distribution Plant 538,162 517,999
General Plant 95,779 92,069
Intangible Plant 10,608 10,441
Electric Plant Held for Future Use 1,013 1,013
---------- ----------
Total Utility Plant $2,129,205 $2,095,679
========== ==========
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. For 1995 and
1994 the Consolidated Statements of Income reflect no AFDC - Equity as all
construction expenditures were deemed under FERC prescribed rules to be
financed with debt. In 1995 and 1994, gross AFDC rates of 5.59% and 4.94%,
respectively, were used for all CWIP. In 1996 the gross AFDC rates for
equity and debt were 0.33% and 3.91%, respectively.
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 3.56%, 3.79% and 3.73% in 1996,
1995 and 1994, 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, Springerville 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 Springerville Coal Handling Facilities Leases. The
Springerville Coal Handling Facilities Leases are 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. But for the application of FAS 71 due to the ACC requirement the
amortization period for such costs would have been only the primary term of
the lease under GAAP. 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 are set forth in
the following table:
Years Ended December 31,
1996 1995 1994
----- ----- -----
- Millions of Dollars -
Lease Amortization:
Interest $ 95 $ 97 $ 94
Depreciation 15 14 13
---- ---- ----
Total Lease Amortization $110 $111 $107
==== ==== ====
Lease Amortization Included In:
Operating Expenses - Fuel and
Purchased Power $ 9 $ 10 $ 10
Operating Expenses - Capital Lease Expense 104 105 103
Balance Sheet - Deferred Lease Expense (3) (4) (6)
----- ----- ----
Total Lease Amortization $110 $111 $107
===== ===== ====
The Deferred Lease Expense of $15 million and $20 million at December
31, 1996 and 1995, 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 based on a 360 MW capacity rating. Such costs averaged approximately
$22 per kW per month during the period 1994 through 1996. 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 through 2014, the end of the primary 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 1996, 1995 and 1994, the accrual of such interest was $30.3
million, $28.2 million and $25.9 million, respectively, and the amount
amortized was $29.1 million, $28.4 million and $26.2 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.
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 deferred costs plus a return on investment in
such deferred costs.
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 1996, 1995 and 1994, the
accrual of such interest was $2.3 million, $4.4 million and $6.4 million,
respectively, and the amount amortized was $20.1 million each year. 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.
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 related to the Springerville Coal
Handling Facilities 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
The Income Taxes Recoverable Through Future Rates 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.
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 for the year 1994 resulted only from such ITC amortization. In the
years 1996 and 1995, income tax benefits included 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.
EPA ALLOWANCES
Purchased Emission Allowances are recorded in a noncurrent inventory
account included in Investments and Other Property on the Consolidated
Balance Sheet. 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) 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 of the Company's financial instruments
are as follows:
December 31,
1996 1995
------ ------
Carrying Fair Carrying Fair
Value Value Value Value
-------- ----- -------- -----
- Thousands of Dollars -
Assets:
Cash and Cash Equivalents $ 130,291 $ 130,291 $ 85,094 $ 85,094
Debt Securities (Included
in Investments and Other
Property) 17,748 18,267 17,713 18,267
Liabilities:
Short-Term Debt (3,567) (3,567) (12,039) (12,039)
Long-Term Debt, Including
Current Portion
(See Note 5) (1,224,660) (1,231,686) (1,219,535) (1,233,457)
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, other than those described below and in Note 4,
have been made to the prior year financial statements presented to conform to
the current year's presentation.
COMMON STOCK REVERSE SPLIT
In May 1996, Shareholders approved a one-for-five reverse split of the
Company's common stock. All references in the financial statements to
average number of shares and per share amounts of the Common Stock have been
retroactively restated to reflect the reverse split. In addition,
Shareholders also approved the reduction in the number of authorized shares
of Common Stock from 200 million to 75 million.
IMPACT OF FAS 121
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. The adoption of FAS 121 did not impact the Company's financial
statements in 1996 and the Company does not expect the application of FAS 121
to have a material impact on the Company's financial statements in the near
term. This conclusion may change in the future depending on the extent that
the Company's operations are influenced by an increasingly competitive
environment.
NOTE 2. 1996 RATE ORDER
- ------------------------
On March 29, 1996, the ACC authorized a 1.1%, or $6.4 million, increase
in base rates effective March 31, 1996. Pursuant to the 1996 Rate Order, the
Company agreed to not seek an increase in base rates before January 1, 2000,
subject to conditions specified in such order.
The 1996 Rate Order recognizes all of Springerville Unit 2 as used and
useful for regulatory purposes, so the Company is presently recovering
operating and capital costs associated with the portion of such generating
unit not previously included in rate base. Prior to the 1996 Rate Order, the
Company was not 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 not deemed by the
ACC to be used and useful for the retail jurisdiction and therefore not
included in rate base (hereinafter referred to as "retail excess capacity
deferrals"). A 1994 rate order permitted such costs to be deferred for
future recovery over the remaining useful life of Springerville Unit 2.
However, this phase-in plan did not qualify under FAS 92 and, therefore, such
retail excess capacity deferrals, while deferred for regulatory purposes,
were not deferred for financial reporting purposes and were expensed as
incurred. Such retail excess capacity deferrals totaled $81 million at March
30, 1996. Beginning March 31, 1996, the retail excess capacity deferrals are
recovered through retail rates at a rate reflecting amortization for
regulatory purposes over 20 years.
In addition, prior to the 1996 Rate Order, the Company was not
recovering through retail rates 37.5% of the deferred Springerville Unit 2
rate synchronization costs ($28 million at March 30, 1996), which were non-
fuel costs of Springerville Unit 2 incurred from January 1, 1991 through
October 14, 1991. Beginning March 31, 1996, these costs are being amortized
over a three-year period on the Consolidated Statements of Income, in
accordance with the 1996 Rate Order. These costs are reported in the
Company's Consolidated Balance Sheet as Deferred Springerville Unit 2 Costs.
The 62.5% of the deferred Springerville Unit 2 rate synchronization costs
that the Company has been recovering through rates, pursuant to a 1994 rate
order, have been fully amortized as of December 31, 1996. The total
amortization of the above costs is included in Depreciation and Amortization
on the Company's Consolidated Statements of Income and amounted to $21
million for 1996 and $14 million for 1995 and 1994.
NOTE 3. INCOME TAXES
- ---------------------
Deferred tax assets (liabilities) are comprised of the following:
December 31,
1996 1995
----------- ----------
- Thousands of Dollars -
Gross Deferred Income Tax Liabilities:
Electric Plant - Net $(465,223) $(460,448)
Income Taxes Recoverable Through
Future Rates - Regulatory Asset (173,731) (168,488)
Deferred Inventory Costs (21,371) (21,654)
Deferred Lease Payments (13,916) (14,791)
Property Taxes (9,970) (10,476)
Deferred Springerville Unit 2 Costs (8,584) (16,974)
Other (9,829) (7,357)
---------- ----------
Gross Deferred Income Tax Liability (702,624) (700,188)
---------- ----------
Gross Deferred Income Tax Assets:
Capital Lease Obligations 365,935 375,897
Tax Operating Loss Carryforwards 163,046 197,100
Springerville Unit 1 Disallowed Costs 65,974 65,491
Investment Tax Credit Carryforwards 26,396 26,396
Lease Interest Payable 17,328 17,626
Deferred Regulatory Capital Lease Expense 16,018 13,980
Sales Tax Assessments Not Yet
Deductible for Tax Purposes 13,974 9,549
Investment in Loans and Partnerships 10,276 12,576
Financial Restructuring Costs Not Yet
Deductible for Tax Purposes 7,782 7,907
Deferred Gain on Emission Allowances 6,923 3,970
Capital Loss Carryforwards 4,634 8,572
Alternative Minimum Tax 4,544 3,044
Gain on Financial Restructuring of
Long-Term Debt 4,289 5,374
MSR Option Gain Regulatory Liability 3,171 10,342
Other 17,204 13,270
---------- ----------
Gross Deferred Income Tax Asset 727,494 771,094
Deferred Tax Assets Valuation Allowance (111,069) (231,169)
---------- ----------
Net Deferred Income Tax Liability $ (86,199) $(160,263)
========== ==========
The decreases of approximately $120 million and $35 million in the gross
deferred tax assets valuation allowance in 1996 and 1995, respectively, are
primarily due to revisions in the estimated amount of NOLs that the Company
believes are likely to reduce future taxable income. The utilization of NOL
carryforwards and capital loss carryforwards also contributed to the 1996 and
1995 decreases. Additionally, expiring state NOL carryforwards and a change
in the effective tax rate used to record tax operating loss carryforwards
also contributed to the 1996 decrease.
The Company recognizes benefits related to prior period NOLs based on
changes in the estimated amount of NOLs that, in the Company's judgment, are
more likely than not to be realized in the future. A significant factor,
among others, considered in estimating such amount is the three year
historical average book income before income taxes. 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 three years, the amount the Company believes is more
likely than not to be realized in the future has increased. Accordingly, the
Company recognized in 1996 and 1995 income tax benefits of $89 million and
$23 million, respectively, related to the current and expected future
utilization of federal and state NOL carryforwards. These benefits are
included in Income Taxes in Other Income (Deductions) in the Consolidated
Statements of Income.
The net deferred income tax liability is included in the Consolidated
Balance Sheets in the following accounts:
December 31,
1996 1995
---------- ----------
- Thousands of Dollars -
Deferred Income Taxes - Current $ 10,223 $ 18,250
Deferred Income Taxes - Noncurrent (96,422) (178,513)
---------- ----------
Net Deferred Income Tax Liability $ (86,199) $(160,263)
========== ==========
The benefit for income taxes included in the Consolidated Statements of
Income consists of the following:
Years Ended December 31,
1996 1995 1994
---------- ---------- ----------
- Thousands of Dollars -
Operating Expenses:
Deferred Tax Expense
Federal $ (7,836) $ (7,803)
State (2,019) (1,200)
---------- ---------- ----------
Total (9,855) (9,003)
Investment Tax Credit Amortization 60 83 $ 91
---------- ---------- ----------
Total Benefit (Expense) Included in
Operating Expenses (9,795) (8,920) 91
---------- ---------- ----------
Other Income (Deductions):
Deferred Tax Expense
Federal (777) (1,065) -
State (266) (164) -
---------- ---------- ----------
Total (1,043) (1,229) -
Reduction in Valuation
Allowance - Benefit 88,638 23,282 -
Investment Tax Credit Amortization 4,355 4,683 4,820
Other - 2,620 -
---------- ---------- ----------
Total Benefit Included in Other
Income (Deductions) 91,950 29,356 4,820
---------- ---------- ----------
Total Benefit for Federal and State
Income Taxes $ 82,155 $ 20,436 $ 4,911
========== ========== ==========
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,
1996 1995 1994
---------- ---------- ----------
- Thousands of Dollars -
Federal Income Tax Expense
at Statutory Rate $ (13,544) $ (12,064) $ (5,540)
State Income Tax Expense, Net of
Federal Deduction (2,081) (1,364) -
Investment Tax Credit Amortization 4,415 4,766 4,911
Reduction in Valuation Allowance - Benefit 88,638 23,282 -
Net Operating Loss Carryforwards - 5,122 5,540
Capital Loss Carryforwards 5,616 1,045 -
Other (889) (351) -
---------- ---------- ----------
Total Benefit for Federal and
State Income Taxes $ 82,155 $ 20,436 $ 4,911
========== ========== ==========
At December 31, 1996, the Company had, for federal income tax purposes,
approximately $489 million of net operating loss carryforwards expiring in
2004 through 2009 and $96 million of alternative minimum tax loss
carryforwards expiring in 2006 through 2008. For state income tax purposes,
the Company has approximately $79 million of net operating loss carryforwards
expiring in 1997 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, $11 million of capital loss carryforwards which
expire during 1997 through 1999 and $4 million of alternative minimum tax
credit which will carry forward to future years.
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 1996, 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, 1996,
the Company had pre-change federal net operating loss, ITC and alternative
minimum tax loss carryforwards of approximately $333 million, $26 million and
$63 million, respectively.
NOTE 4. CONSOLIDATED SUBSIDIARIES
- ----------------------------------
NATIONS ENERGY CORPORATION
In 1995 the Company established Nations Energy, a wholly-owned
subsidiary, for the purpose of investing in independent power projects in the
domestic and foreign energy markets. 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 provides electricity and
steam for the brewery operation in Golden, Colorado. The investment of
approximately $12 million by Nations Energy is included in the Company's
Consolidated Balance Sheet under Investments and Other Property at December
31, 1996 and 1995 and in the Company's Consolidated Statement of Cash Flows
for the year ended December 31, 1995 as Investments in Joint Ventures.
ADVANCED ENERGY TECHNOLOGIES, INC.
In May 1996, Advanced Energy Technologies, Inc. (formerly known as TEP
Solar Energy Corporation), a wholly-owned subsidiary of the Company, and ITN
Energy Systems formed Global Solar Energy, LLC for the purpose of development
and manufacturing of photovoltaic materials. Advanced Energy has a 50%
interest in Global Solar. The investment in Global Solar is included in the
Company's Consolidated Balance Sheet at December 31, 1996 under Investments
and Other Property and in the Company's Consolidated Statement of Cash Flows
for the year ended December 31, 1996 as Investments in Joint Ventures.
VALENCIA ENERGY COMPANY
On May 31, 1996, Valencia Energy Company, a wholly-owned subsidiary of
the Company, was merged into the Company using historical book values. As a
result of the merger, the Company succeeded to all of the assets and
liabilities of Valencia; the responsibilities for the coal procurement, coal
transportation and coal handling services at Springerville Generating
Station; and the responsibilities as the lessee of the Springerville Coal
Handling Facilities Leases. Certain amounts previously included in Fuel and
Purchased Power have been reclassified to Capital Lease Expense, Other
Operations, Maintenance and Repairs, Depreciation and Amortization, Taxes
Other Than Income Taxes and Other Interest Expense on the Company's
Consolidated Statements of Income to conform to the current year's
presentation.
INVESTMENT SUBSIDIARIES
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. 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. Activity in the investment subsidiaries since January 1, 1995,
is not material to the consolidated financial statements.
NOTE 5. LONG AND SHORT-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
- ---------------------------------------------------------------
LONG-TERM DEBT
On May 1, 1996, the Coconino County, Arizona Pollution Control
Corporation, on behalf of the Company, issued $16.7 million of variable rate
Pollution Control Revenue Bonds. The Pollution Control Corporation also
issued $14.7 million of variable rate Pollution Control Refunding Revenue
Bonds on behalf of the Company to provide funds to refund previously issued
8.25% Pollution Control Revenue Bonds. Both issues have a scheduled maturity
in 2031 and are secured by separate LOCs that expire in 1999.
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, 1996, the credit commitments and obligations covered by
the provisions of the MRA included $164 million of 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. 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 1.50 to 1 in 1996 and gradually
increasing to 2 to 1 in 2000 continuing through the year 2003. For the year
ended December 31, 1996, the Company's MRA interest coverage ratio was 3.15
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, 1996). 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 $506 million at December 31, 1996) and the
Company's cash flow coverage ratio is greater or equal to a ratio of 2 to 1.
As of December 31, 1996, the Company's cash flow coverage ratio was in excess
of 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, 1996 there were $805 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 April 30, 1999 through December 31, 2002. However, all the LOCs
could expire by December 31, 2000, including an expiration as early as
December 31, 1998, if the Company's senior long-term debt is rated investment
grade on certain dates or during certain periods subsequent to December 31,
1997. The weighted average commitment fee on the LOCs is approximately 0.57%
through 1997, increasing to 0.85% in 1998 and 1.09% in 1999.
Renewable Term Loan
At December 31, 1996 the outstanding balance of the Renewable Term Loan
was $31 million with a commitment of approximately $164 million. 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 6.02%, 6.50%, and 4.92%
for the years ended December 31, 1996, 1995 and 1994, respectively.
Subsequent to December 31, 1996, the Company repaid the outstanding
Renewable Term Loan balance of $31 million.
Fair Value of Long-Term Debt
December 31,
1996 1995
---- ----
Carrying Fair Carrying Fair
Value Value Value Value
-------- ----- -------- -----
- Thousands of Dollars -
First Mortgage Bonds:
Corporate $ 243,750 $ 252,443 $ 253,750 $ 267,902
IDBs
Variable Rate 151,400 151,400 120,000 120,000
Fixed Rate 97,000 95,573 112,200 112,276
Loan Agreements:
Installment Sale Agreement 47,910 47,670 48,985 48,679
IDBs 653,600 653,600 653,600 653,600
Renewable Term Loan 31,000 31,000 31,000 31,000
---------- ---------- ---------- ----------
$1,224,660 $1,231,686 $1,219,535 $1,233,457
========== ========== ========== ==========
The principal amount of variable rate debt outstanding at December 31,
1996 and 1995 of the First Mortgage Bonds-IDBs (variable rate), the Loan
Agreements-IDBs and the Renewable Term Loan 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 First Mortgage Bonds-IDBs
(fixed rate) and the Installment Sale Agreement 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 1996 for 1996 amounts and December
1995 for 1995 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 1997, the Company obtained a tax-exempt volume cap allocation
from the state of Arizona. The Company's allocation is for $20 million to be
issued by the Pollution Control Corporation Coconino County, Arizona, for the
benefit of the Company. The Company expects to issue such bonds by May 1997.
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 28, 1997, to request approval
for the issuance of new tax-exempt bonds and for the refunding of certain
existing tax-exempt bonds.
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 Springerville Coal Handling Facilities
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, 1996
follows:
Expiring Scheduled
LOCs Long-Term
Supporting Debt Capital Lease
IDBs Retirements Obligations Total
-------- -------- ------------ ----------
Years Ending
December 31, - Thousands of Dollars -
1997 $ 1,635 $ 94,975 $ 96,610
1998 2,705 97,200 99,905
1999 $131,400 50,000 120,815 302,215
2000 364,900 82,825 164,121 611,846
2001 100,000 29,155 101,781 230,936
-------- -------- ------------ -----------
Total 1997 - 2001 596,300 166,320 578,892 1,341,512
Thereafter 208,700 253,340 1,630,465 2,092,505
Imputed Interest - - (1,303,107) (1,303,107)
-------- -------- ----------- -----------
Total $805,000 $419,660 $ 906,250 $2,130,910
======== ======== =========== ===========
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 $1.5 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.
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 1.5% in 1997 which increases to 2% in 1998 and 1999. 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 $4 million and $12 million at December
31, 1996 and 1995, respectively. The weighted average interest rate
applicable to the warehouse line of credit at December 31, 1996 and 1995 was
17%. In July 1996, Brookland satisfied approximately $8.5 million of these
short-term debt obligations with the assignment of certain finance
receivables. Upon settlement, a provision for loss recorded against such
receivables in prior years was reversed, resulting in income of approximately
$8.5 million.
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 supplier 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 $12.2 million of accrued liabilities.
The reversal of the accrued liabilities reduced Fuel and Purchased Power
expense by $12.2 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 useful 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 1997 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 1997 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. The Company incurred no take-or-
pay charges in 1995 or 1994. In 1996, the Company incurred a take-or-pay
charge of approximately $4.4 million related to the Irvington contract. The
Company entered into an agreement with an alternate coal supplier for 1996
resulting in the incurrence of the take-or-pay charge but reducing coal costs
overall at Irvington.
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 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 1993 affected Company generating units were allocated Emission
Allowances based on past use. Beginning with the year 2000, Phase II
generating station units must hold Emission Allowances by January 30 of the
year following the compliance year equal to the level of emissions in the
compliance year, or face penalties and a requirement to offset excess tons in
future years. An analysis of the Emission Allowances that were allocated to
the Company shows that the Company may not have sufficient allowances to
permit normal plant operation and be in compliance with the sulfur dioxide
regulations once the Phase II requirements become effective due to an
increase in the rated capacity of both units at Springerville from 360 MW to
380 MW. To the extent that the Company does not have sufficient allowances,
due to increased energy output at Springerville or due to other factors, the
Company would have to purchase additional allowances. Based upon current
estimates of additional required Emission Allowances and the current market
price of such allowances, the Company believes that it will be able to
acquire additional required allowances and that such purchases will not have
a material effect on the Company.
The nitrogen oxide (NOx) emission rule finalized in 1995 allows certain
Phase II affected coal-fired boilers to early elect by January 1, 1997, and
thus be subject to compliance beginning January 1, 1997, instead of January
1, 2000. Utility boilers that early elect are exempt until January 1, 2008
from compliance with any stricter emission regulations that went into effect
January 1, 1997 in the revised NOx rule. The Company has placed the
Springerville Generating Units 1 and 2 into the early election program to
take advantage of the exemption, but may choose to withdraw in future years
after the effects of the revised rules are determined. In order to comply
with the NOx emission limits Irvington Generating Unit 4 may require
installation of low NOx burners by January 1, 2000, at a cost of
approximately $1 million.
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, because of and in
addition to the CAAA, 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, 1996
relating to the rule's implementation will be approximately $17 million,
including AFDC, through 1999.
CONTINGENCIES
Ruling on Arizona Sales Tax Assessments - Coal Sales
The Arizona Department of Revenue (ADOR) issued transaction privilege
(sales) tax assessments to the Company alleging that Valencia was liable for
sales tax on gross income received from coal sales, transportation and coal-
handling services to the Company for the period November 1985 through May
1993. The Company protested these assessments. On March 11, 1994, the
Arizona Tax Court issued a Minute Entry granting Summary Judgment to the ADOR
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. On September 12, 1996, the Arizona Court of Appeals upheld the
validity of the assessment issued for the period November 1985 through March
1990. The Company filed with the Court of Appeals a motion for
reconsideration of their September 12, 1996 decision which was denied. On
December 10, 1996, the Company filed with the Court of Appeals a Petition for
Review by the Arizona Supreme Court of the September 12, 1996 decision.
Additionally, the Company is protesting the assessments for the period April
1990 through May 1993.
Previously, the Company had recorded an expense through the Consolidated
Statements of Income (Loss) in current and prior years and related liability
for the amount of sales taxes and interest thereon which the Company then
believed was probable of incurrence. As a result of the Court of Appeals
decision, the Company recorded an additional expense of approximately $9.2
million in September 1996. Such expense is included in Taxes Other Than
Income Taxes ($7.3 million) and Other Interest Expense ($1.9 million) in the
Consolidated Statement of Income. The amounts recorded by the Company
included estimates for the period June 1993 through May 1996, the period for
which the Company has not yet been assessed.
On May 31, 1996, Valencia was merged into the Company (see Note 4).
Effective with the merger, Valencia no longer supplies coal to the Company.
Instead the Company acquires coal directly from the supplier. As a result,
the Company believes it is not liable for transaction privilege tax computed
on a basis similar to the assessments described above subsequent to May 31,
1996. For periods subsequent to May 31, 1996 the Company continues to record
an estimated interest expense on the above assessments.
Generally, Arizona law requires payment of an assessment due prior to
pursuing the appellate process. The Company has previously paid, under
protest, a total of $23 million of the disputed sales tax assessments,
subject to refund in the event the Company would prevail. The Court's
decision does not require additional cash payments by the Company at this
time.
Arizona Sales Tax Assessments - Leases
The ADOR has issued transaction privilege (sales) 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 Springerville Coal Handling Facilities Leases.
Assessments cover the period August 1, 1988 to September 30, 1993. Under the
terms of the lease agreements, if the ADOR 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 state taxes and interest thereon for which the
Company feels incurrence is probable as of December 31, 1996. In the event
that the assessments by the ADOR are sustained, an additional liability would
result. Although it is reasonably possible that the ultimate resolution of
such matter could result in an additional sales tax expense of up to
approximately $20 million in excess of amounts recorded, management and
outside tax counsel believe that the Company has meritorious defenses to
mitigate or eliminate the assessed amounts.
Based on the current status of the legal proceedings, the Company
believes that the ultimate resolution of such dispute will occur over a
period of two to four years. Based on consultations with counsel and
considering the amounts already accrued, the Company believes that the
resolution of this tax matter should not have a material adverse effect on
the Company's Consolidated Financial Statements
NOTE 7. JOINTLY OWNED FACILITIES
- ---------------------------------
At December 31, 1996, 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 $295,631 $ 2,163 $216,749
Navajo Station 7.5 80,006 25,874 42,215
Four Corners Units 4 and 5 7.0 77,396 944 55,208
Transmission Facilities 7.5 to 95.0 205,313 944 102,580
-------- ------- --------
Total $658,346 $29,925 $416,752
======== ======= ========
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.
NOTE 8. EMPLOYEE BENEFITS PLANS
- --------------------------------
VOLUNTARY SEVERANCE PLAN (VSP)
In May 1996, the Company implemented a VSP. The VSP resulted in an
expense in the second quarter of 1996 for termination benefits of
approximately $14 million included in Voluntary Severance Plan Expense on the
Company's Consolidated Statement of Income. Approximately $10 million of the
termination benefits were paid in 1996 with the remaining benefits to be paid
over the next three years. See Pension Plans (below) for a discussion of the
impact of the VSP on the Company's pension obligation.
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,
1996 and 1995. The actuarial present value of the benefit obligation and
reconciliation of funding status at October 1, were as follows:
October 1,
1996 1995
-------- --------
- Thousands of Dollars -
Accumulated Benefit Obligation
Vested $60,711 $75,014
Non-Vested 7,341 5,447
-------- --------
Total $68,052 $80,461
======== ========
Plan Assets at Fair Value, Principally Equity and
Fixed Income Securities $86,387 $93,317
Projected Benefit Obligation (76,563) (91,414)
-------- --------
Plan Assets in Excess of Projected Benefit Obligation 9,824 1,903
Unrecognized Net Gain from Past Experience (8,088) (8,136)
Prior Service Cost Not Yet Recognized in Net Periodic
Pension Cost 7,705 9,410
Unrecognized Net Assets at Transition Being Amortized
Over 15 Years (1,405) (1,729)
-------- --------
Prepaid Pension Cost Included in the Balance Sheet $ 8,036 $ 1,448
======== ========
The decreases in the Accumulated Benefit Obligation and Projected
Benefit Obligation from 1995 to 1996 reflect the partial settlements and
curtailments of the Company's two pension plans as a result of the reduction
in the workforce due to the VSP. As a result of such settlements and
curtailments, in the third quarter of 1996 the Company recognized a gain of
approximately $3.7 million primarily due to the reduction of the projected
benefit obligation associated with severed employees' pension benefits. This
gain is included as a reduction of Voluntary Severance Plan Expense on the
Company's Consolidated Statement of Income.
Years Ended December 31,
1996 1995 1994
-------- -------- --------
- Thousands of Dollars -
Components of Net Pension Cost
Service Cost of Benefits Earned During Period $ 2,746 $ 3,236 $ 2,680
Interest Cost on Projected Benefit Obligation 6,022 6,752 5,615
Actual (Gain) Loss on Plan Assets (7,757) (8,417) 492
Net Amortization and Deferral 404 532 (6,214)
-------- -------- --------
Net Periodic Pension Cost $ 1,415 $ 2,103 $ 2,573
======== ======== ========
Actuarial Assumptions: 1996 1995 1994
---- ---- ----
Discount Rate - Funding Status 8.0% 7.5% 8.5%
Average Compensation Increase 5.0 5.0 5.0
Expected Long-Term Rate of Return on Plan Assets 9.0 9.0 9.0
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 is 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.
December 31,
1996 1995
--------- ---------
- Thousands of Dollars -
Accumulated Postretirement Benefit Obligation
Retirees $(15,471) $ (6,993)
Fully Eligible Active Plan Participants (1,817) (4,273)
Other Active Participants (14,100) (13,885)
--------- ---------
Total Accumulated Postretirement Benefit Obligation (31,388) (25,151)
Unrecognized Net Loss from Past Experience 3,172 732
Unrecognized Portion of the Transition Obligation
Being Amortized Over 20 Years 13,893 16,289
--------- ---------
Accrued Postretirement Benefit Cost Included in the
Balance Sheet $(14,323) $ (8,130)
========= =========
Years Ended December 31,
1996 1995 1994
------- ------- -------
- Thousands of Dollars -
Components of Net Postretirement Benefit Cost
Service Cost of Benefits Earned During Period $1,025 $ 838 $ 931
Interest Cost on Postretirement Benefit
Obligation 2,071 1,541 1,395
Amortization of the Unrecognized Transition
Obligation 913 958 958
Amortization of the Unrecognized Loss (Gain) 42 (152) -
------- ------- -------
Net Periodic Postretirement Benefit Cost $4,051 $3,185 $3,284
======= ======= =======
The accumulated postretirement benefit obligation was determined using
a 7.25% and 7.0% discount rate for 1996 and 1995, respectively. The health
care cost trend rates were assumed to be 8.5.% and 9.21% for 1996 and 1995,
respectively, gradually declining to 3.88% 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, 1996 by approximately $4.4 million and the net periodic
cost by $0.8 million for 1996.
STOCK OPTION PLANS
On May 20, 1994, the Shareholders of the Company approved two stock
option plans, the 1994 Outside Director Stock Option Plan (1994 Directors'
Plan) and the 1994 Omnibus Stock and Incentive Plan (1994 Omnibus Plan).
The 1994 Directors' Plan provides for the annual grant of 1,200 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 1994 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 1.6 million.
The Compensation Committee granted stock options intended to qualify as
incentive stock options under the Internal Revenue Code to key employees
during 1996 and 1995 and to all employees during 1994 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 additional options are
to be granted under this plan and the Company does not expect any of the
outstanding options to be exercised as the exercise price of such options is
$293.13.
A summary of the activity of the Company's 1994 Directors' Plan and
1994 Omnibus Plan for the years 1996, 1995 and 1994 is as follows:
1996 1995 1994
---------------- ---------------- ----------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
------- -------- ------- -------- ------- --------
Options Outstanding,
Beginning of Year 525,522 $16.26 442,952 $16.28 - -
Granted 212,684 $13.16 93,718 $16.19 442,952 $16.28
Exercised (2,886) $16.25 - - - -
Forfeited (47,197) $16.25 (11,148) $16.18 - -
------- ------- -------
Options Outstanding,
End of Year 688,123 $15.30 525,522 $16.26 442,952 $16.28
======= ======= =======
Option Price Range,
End of Year $13.00
to
$17.81
Options Exercisable,
End of Year 286,944 $16.27
Weighted Average Remaining Contractual Life at December 31, 1996: 8.2 Years
The Company applies Accounting Principles Board Opinion No. 25,
Accounting for Stock Issued to Employees, and related interpretations in
accounting for its stock option plans. No compensation cost has been
recognized for the plans during 1994 though 1996. The Company has adopted
the disclosure-only provisions of Statement of Financial Accounting Standards
No. 123: Accounting for Stock-Based Compensation (FAS 123). Had
compensation costs for the Company's stock option plans been determined based
on the fair value at the grant date for awards in 1996 and 1995 consistent
with the provisions of FAS 123, the Company's net income and net income per
average share would have been reduced to the proforma amounts indicated
below:
Years Ended
December 31,
1996 1995
-------- -------
- Thousands of Dollars -
Net Income
As reported $120,852 $54,905
Pro forma $120,612 $54,844
Net Income per Average Share
As reported $3.76 $1.71
Pro forma $3.75 $1.71
The fair value of each stock option grant is estimated on the date of
grant using the Black-Scholes option pricing model with the following
weighted average assumptions:
1996 1995
-------- --------
Expected life (years) 4 4)
Interest rate 6.51% 6.30%
Volatility 23.51% 23.51%
Dividend yield None None
NOTE 9. QUARTERLY FINANCIAL DATA (unaudited)
- ----------------------------------------------
First Second Third Fourth
--------- --------- --------- ---------
- Thousands of Dollars -
(except per share data)
1996
Operating Revenue $148,028 $184,533 $223,078 $160,234
Operating Income 17,118 27,110 52,616 20,722
Net Income 419 10,289 102,498 7,646
Net Income per Average Share 0.01 0.32 3.19 0.24
1995
Operating Revenue $142,745 $162,305 $217,787 $147,732
Operating Income 6,964 27,078 84,472 4,657
Net Income (Loss) (14,960) 3,014 60,729 6,122
Net Income (Loss) per Average Share (0.46) 0.09 1.89 0.19
Due to seasonal fluctuations in sales, the recognition of NOL
carryforward benefits and one-time adjustments, the quarterly results are not
indicative of annual operating results. See Note 3 regarding the income tax
adjustments recorded in 1996 and the fourth quarter of 1995, Note 5 regarding
the reversal of a $8.5 million provision for loss in the third quarter of
1996, Note 6 regarding the recognition of $9.2 million in sales tax expense
in the third quarter of 1996 and the $12.2 million reduction in fuel expense
during the third quarter of 1995 and Note 8 regarding the $10.6 million of
net VSP expense recorded in the second and third quarters of 1996.
Beginning in the second quarter of 1996, certain amounts previously
included in Fuel and Purchased Power have been reclassified in the
Consolidated Statements of Income. See Note 4. Also in the second quarter
of 1996, income tax benefits related to Emission Allowances have been
reclassified and are now included in the Other Income (Deductions) section of
the Consolidated Statements of Income.
First Second Third Fourth
--------- --------- --------- ---------
- Thousands of Dollars -
1996
Operating Income - Historical $18,572 $26,997 N/A N/A
Reclassification (1,454) 113 N/A N/A
--------- --------- --------- ---------
Operating Income - Restated $17,118 $27,110 N/A N/A
========= ========= ========= =========
1995
Operating Income - Historical $6,748 $26,970 $84,357 $3,980
Reclassification 216 108 115 677
--------- --------- --------- ---------
$6,964 $27,078 $84,472 $4,657
Operating Income - Restated ========= ========= ========= =========
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 to net cash flows from continuing operating
activities follows:
Years Ended December 31,
1996 1995 1994
---------- ---------- ----------
- Thousands of Dollars -
Net Income $120,852 $ 54,905 $ 20,740
Adjustments to Reconcile Net Income
to Net Cash Flows
Depreciation Expense 98,246 93,136 90,909
Deferred Income Taxes and Investment
Tax Credits - Net (83,722) (21,136) (4,911)
Deferred Fuel and Purchased Power - 5,872 7,359
Lease Payments Deferred 30,756 32,299 31,346
Deferred Springerville Unit 2 Costs (286) (1,127) (1,133)
Regulatory Amortizations, Net of Interest
Imputed on Losses Recorded at
Present Value (16,544) (15,852) (13,977)
Reversal of Loss Provision (8,472) - -
Other (8,980) (4,457) (506)
Changes in Assets and Liabilities which
Provided (Used) Cash Exclusive of
Changes Shown Separately
Accounts Receivable (4,188) 4,615 (1,120)
Materials and Fuel 11,812 (6,059) 203
Accounts Payable 1,644 (16,022) 788
Taxes Accrued 8,311 (13,519) 8,946
Other Current Assets and Liabilities (9,926) (5,328) 1,183
Other Deferred Assets and Liabilities 11,764 12,063 3,789
---------- ---------- ----------
Net Cash Flows - Continuing Operating
Activities $151,267 $119,390 $143,616
========== ========== ==========
Non-cash investing and financing activities of the Company that affected
recognized assets and liabilities but did not result in cash receipts or
payments were:
Years Ended December 31,
1996 1995 1994
---------- ---------- ----------
- Thousands of Dollars -
Capital Lease Obligations $ 8,336 $ 8,095 $ 8,107
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 1997 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 54 Chairman of the Board, President and
Chief Executive Officer (a) 1989
Ira R. Adler 46 Senior Vice President and Chief
Financial Officer (b) 1988
George W. Miraben 55 Senior Vice President - Policy
and Human Resources (c) 1990
James S. Pignatelli 53 Senior Vice President and Chief
Operating Officer (d) 1994
Thomas A. Delawder 50 Vice President - Energy Resources (e) 1985
Gary L. Ellerd 46 Vice President - Operations (f) 1985
Steven J. Glaser 39 Vice President - Energy Services (g) 1994
Thomas N. Hansen 46 Vice President - Technical Services
Advisor (h) 1992
Karen G. Kissinger 42 Vice President and Controller (i) 1991
Dennis R. Nelson 46 Vice President, General Counsel and
Corporate Secretary (j) 1991
Romano Salvatori 59 Vice President - Independent Power (k) 1994
Kevin P. Larson 40 Treasurer (l) 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) George W. Miraben: Mr. Miraben was elected Vice President, Public Affairs,
effective March 1990, was named Vice President - Human Resources and Public
Affairs in 1994, and became Senior Vice President - Policy and Human Resources
in 1996. Prior to joining the Company, he was Director of External Affairs for
US WEST Communications' Arizona operation from 1981 through March 1990.
(d) James S. Pignatelli: Mr. Pignatelli joined the Company as Senior Vice
President in August 1994 and was elected Senior Vice President and Chief
Operating Officer in 1996. 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.
(e) 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.
(f) 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.
(g) 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. He was
named Vice President - Energy Services in 1996.
(h) 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.
(i) 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.
(j) Dennis R. Nelson: Mr. Nelson joined the Company as a staff attorney 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) 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.
(l) 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 1997 Annual Meeting of Shareholders, which information is incorporated
herein by reference.
ITEM 12. -- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
GENERAL
At March 4, 1997, the Company had outstanding 32,135,817 shares of Common
Stock. As of March 4, 1997, 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 1997 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
Management in the Company's Proxy Statement relating to the 1997 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, 1996 and 1995 and for Each
of the Three Years in the Period Ended
December 31, 1996.
Independent Auditors' Report 35
Consolidated Statements of Income 36
Consolidated Statements of Cash Flows 37
Consolidated Balance Sheets 38
Consolidated Statements of Capitalization 39
Consolidated Statements of Changes in Stockholders'
Equity (Deficit) 40
Notes to Consolidated Financial Statements 41
2. Supplemental Consolidated Schedules for the Years
Ended December 31, 1994 to 1996.
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 69
(b) Reports on Form 8-K.
The Company has not filed any Current Reports on Form 8-K since filing
the Form 10-Q for the third quarter of 1996.
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 7, 1997 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 7, 1997 Charles E. Bayless*
----------------------------
Charles E. Bayless
Chairman of the Board, President
and Principal Executive Officer
Date: March 7, 1997 Ira R. Adler
-----------------------------
Ira R. Adler
Principal Financial Officer
Date: March 7, 1997 Karen G. Kissinger*
-----------------------------
Karen G. Kissinger
Principal Accounting Officer
Date: March 7, 1997 Elizabeth Alexander*
-----------------------------
Elizabeth Alexander
Director
Date: March 7, 1997 Jose Canchola*
-----------------------------
Jose Canchola
Director
Date: March 7, 1997 John. L. Carter*
-----------------------------
John L. Carter
Director
Date: March 7, 1997 John A. Jeter*
-----------------------------
John A. Jeter
Director
Date: March 7, 1997 R. B. O'Rielly*
-----------------------------
R. B. O'Rielly
Director
Date: March 7, 1997 Martha R. Seger*
-----------------------------
Martha R. Seger
Director
Date: March 7, 1997 Donald G. Shropshire*
-----------------------------
Donald G. Shropshire
Director
Date: March 7, 1997 H. Wilson Sundt*
-----------------------------
H. Wilson Sundt
Director
Date: March 7, 1997 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, as amended by Amendment to Article Fourth of the Company's
Restated Articles of Incorporation, filed with the ACC on May 17,
1996.
*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(a)(32)-- Thirty-first Supplemental Indenture, dated as of May 1, 1996.
4(a)(33)-- Thirty-second Supplemental Indenture, dated as of May 1, 1996.
*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).)
*4(s)(1)-- Loan Agreement, dated as of May 1, 1996, between Coconino County,
Arizona Pollution Control Corporation and the Registrant relating to
Pollution Control Revenue Bonds, 1996 Series A (Tucson Electric Power
Company Project). (Form 10-Q for the quarter ended March 31, 1996,
File No. 1-5924--Exhibit 4a.)
*4(s)(2)-- Indenture of Trust, dated as of May 1, 1996, between Coconino County,
Arizona Pollution Control Corporation and First Trust of New York,
National Association authorizing Pollution Control Revenue Bonds,
1996 Series A Tucson Electric Power Company Project). (Form 10-Q for
the quarter ended March 31, 1996, File No. 1-5924--Exhibit 4b.)
*4(s)(3)-- Letter of Credit and Reimbursement Agreement, dated as of May 1,
1996, between the Registrant, Various Banks, and Canadian Imperial
Bank of Commerce, New York Agency. (Form 10-Q for the quarter ended
March 31, 1996, File No. 1-5924--Exhibit 4c.)
*4(s)(4)-- Loan Agreement, dated as of May 1, 1996, between Coconino County,
Arizona Pollution Control Corporation and the Registrant relating to
Pollution Control Refunding Revenue Bonds, 1996 Series B (Tucson
Electric Power Company Project). (Form 10-Q for the quarter ended
March 31, 1996, File No. 1-5924--Exhibit 4d.)
*4(s)(5)-- Indenture of Trust, dated as of May 1, 1996, between Coconino County,
Arizona Pollution Control Corporation and First Trust of New York,
National Association authorizing Pollution Control Refunding Revenue
Bonds, 1996 Series B (Tucson Electric Power Company Project). (Form
10-Q for the quarter ended March 31, 1996, File No. 1-5924--Exhibit
4e.)
*4(s)(6)-- Letter of Credit and Reimbursement Agreement, dated as of May 1,
1996, between the Registrant and Societe Generale, Los Angeles
Branch. (Form 10-Q for the quarter ended March 31, 1996, File No. 1-
5924--Exhibit 4f.)
*+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 currently in
effect with Ira R. Adler, Charles E. Bayless, Thomas A. Delawder, Gary
L. Ellerd, Steven J. Glaser, Thomas N. Hansen, Karen G. Kissinger,
George W. Miraben, Dennis R. Nelson, James S. Pignatelli and Romano
Salvatori.
+10(g)(2)-- Employment Agreement between the Registrant and Romano Salvatori.
*10(g)(3)-- 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(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.