FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)
For the fiscal year ended December 31, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the transition period from __________ to __________.
Commission File Number 1-5924
TUCSON ELECTRIC POWER COMPANY
(Exact name of registrant as specified in its charter)
ARIZONA 86-0062700
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
220 WEST SIXTH STREET, TUCSON, ARIZONA P.O. BOX 711
85701 85702
(Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (602) 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 $542,442,494.25 based on the
last reported sale price thereof on the consolidated tape on March 6, 1995.
At March 6, 1995, 160,723,702 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 1995 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
The Financial Restructuring 1
Utility Operations
Peak Demand and Customers 2
Peak Demand 2
Sales for Resale 3
Competition 3
Nations Energy Corporation 4
Generating and Other Resources
Company Resources 5
Springerville Station 5
Irvington Station 6
SCE/TEP Power Exchange Agreement 6
Future Generating Resources 6
Other Purchases 6
Rates and Regulation
General 7
1994 Rate Order 7
Other Rate Matters 8
Fuel Supply
General 8
Coal 8
Valencia 9
Gas 10
Water Supply 10
Environmental Matters
General 10
Four Corners Generating Station 11
Irvington Generating Station 11
Navajo Generating Station 11
San Juan Generating Station 11
Springerville Generating Station 11
Employees 12
Discontinued Investment Subsidiary Operations 12
Utility Operating Statistics 13
Item 2. ---- Properties 14
Item 3. ---- Legal Proceedings
SDGE/FERC Proceedings 15
Water Rights Adjudication 15
Tax Assessments 15
Item 4. - Submission of Matters to a Vote of Security Holders 15
- PART II -
Item 5. ---- Market for Registrant's Common Equity and Related Stockholder
Matters 16
Item 6. ---- Selected Consolidated Financial Data 17
TABLE OF CONTENTS
(CONTINUED)
Page
Item 7. ---- Management's Discussion and Analysis of Financial Condition and
Results of Operations
Overview 18
Proposed Holding Company 19
Results of Operations
Results of Utility Operations
Sales and Revenues 20
Operating Expenses 20
Other Income (Deductions) 21
Interest Expense 22
Results of Discontinued Operations 22
Accounting for the Effects of Regulation 22
Dividends 23
Liquidity and Capital Resources
Cash Flows 23
Financing Developments 24
Short-Term Credit Facilities
Revolving Credit 24
Other 24
Restrictive Covenants
General First Mortgage Covenants 25
General Second Mortgage Covenants 25
Prepayments 25
Additional Restrictive Covenants 26
Construction Expenditures 26
Item 8. ---- Consolidated Financial Statements and Supplementary Data 26
Independent Auditors' Report 27
Consolidated Statements of Income (Loss) 28
Consolidated Balance Sheets 29
Consolidated Statements of Capitalization 30
Consolidated Statements of Cash Flows 31
Consolidated Statements of Changes in Stockholders' Equity (Deficit) 32
Notes to Consolidated Financial Statements
Note 1. Nature of Operations and Summary of Significant Accounting Policies
Nature of Operations 33
Basis of Presentation 33
Use of Estimates 33
Regulation 33
Accounting for the Effects of Regulation 33
Utility Plant 34
Utility Plant Under Capital Leases 35
Allowance for Springerville Unit 1 35
Deferred Common Facility Costs 36
Utility Operating Revenues 36
Amortization of MSR Option Gain Regulatory Liability 36
Fuel and Purchased Power Costs 36
Financial Restructuring Costs 36
Income Taxes 37
Debt Expense 37
Fair Value of Financial Instruments 37
Reclassification 37
Note 2. 1994 Rate Order 38
Note 3. 1992 Consummation of the Financial Restructuring 38
Banks 39
TABLE OF CONTENTS
(CONTINUED)
Page
Springerville Unit 1 39
Capital Leases 39
Preferred Stock 39
Other 40
Note 4. Income Taxes 40
Note 5. Discontinued Operations 42
Note 6. Long and Short-Term Debt and Capital Lease Obligations
Long-Term Debt
First Mortgage Bonds and Installment Sale Agreement 43
Restructured Arrangements 43
Letters of Credit 43
Term Loan 44
Additional Restrictive Covenants 44
Fair Value of Long-Term Debt 44
Short-Term Debt
Revolving Credit 45
Discontinued Operations 45
Capital Lease Obligations 45
Note 7. Commitments and Contingencies
Utility Contractual Matters
Coal and Transportation Contracts 45
Fuel Purchase Commitments 46
Commitments-Environmental Regulation 46
Contingencies
SDGE/FERC Proceedings 47
San Diego Gas & Electric v. Tucson Electric Power Company 47
Alamito Company, Docket No ER79-97-009 47
Tax Assessments 48
Note 8. SCECorp/SCE Litigation Settlement 48
Note 9. Jointly Owned Facilities 49
Note 10. Employee Benefits Plans 49
Pension Plans 49
Postretirement Benefits Other Than Pensions 50
Adoption of FAS 112 50
Stock Option Plans 50
Note 11. Quarterly Financial Data (unaudited) 52
Note 12. Supplemental Cash Flow Information 53
Item 9. ---- Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure 54
- PART III -
Item 10. ---- Directors and Executive Officers of the Registrant
Directors 54
Executive Officers 54
Item 11. ---- Executive Compensation 56
Item 12. ---- Security Ownership of Certain Beneficial Owners and Management
General 56
Security Ownership of Certain Beneficial Owners 56
Security Ownership of Management 56
Item 13. ---- Certain Relationships and Related Transactions 56
TABLE OF CONTENTS
(CONCLUDED)
Page
- PART IV -
Item 14. ---- Exhibits, Financial Statement Schedules, and Reports on Form 8-K
57
Signatures 58
Exhibit Index 60
DEFINITIONS
The abbreviations and acronyms used in the 1994 Form 10-K are defined below:
ACC Arizona Corporation Commission.
ACC Staff Staff of the Arizona Corporation Commission.
ADEQ Arizona Department of Environmental Quality.
AFDC Allowance for Funds Used During Construction.
APB11 Accounting Principles Board Opinion #11: Accounting for
Income Taxes.
APS Arizona Public Service Company.
Articles Company's Restated Articles of Incorporation, as amended.
Banks Various banks with which the Company has credit
relationships.
Brookland Brookland Financial Corporation, a wholly-owned, indirect
subsidiary of SRI.
BTU British Thermal Unit(s).
CAAA Federal Clean Air Act Amendments.
Catalyst Catalyst Energy Corporation, the parent company of Century.
Century Century Power Corporation, an indirect subsidiary of
Catalyst and formerly known as Alamito Company.
Citadel Citadel Holding Corporation, a California-based holding
company.
Closing The closing of the transactions contemplated by the
Financial Restructuring, which occurred on December
15, 1992.
Commission or SEC Securities and Exchange Commission.
Common Stock The Company's common stock, without par value.
Company or TEP Tucson Electric Power Company.
Creditors Certain of the Company's creditors and lease participants
and Century and the Springerville Unit 1 Leases'
participants.
CWIP Construction Work In Progress.
Energy Act The Energy Policy Act of 1992.
EPA The Environmental Protection Agency.
FAS 13 Statement of Financial Accounting Standards #13:
Accounting for Leases.
FAS 15 Statement of Financial Accounting Standards #15:
Accounting by Debtors and Creditors for Troubled Debt
Financial Restructurings.
FAS 71 Statement of Financial Accounting Standards #71:
Accounting for the Effects of Certain Types of
Regulation.
FAS 92 Statement of Financial Accounting Standards #92:
Regulated Enterprises - Accounting for Phase-In
Plans.
FAS 98 Statement of Financial Accounting Standards #98:
Accounting for Leases: Sale Leaseback Transactions
Involving Real Estate, Sales-Type Leases of Real Estate,
Definition of the Lease Term, Initial Direct Costs of
Direct Financing Leases.
FAS 101 Statement of Financial Accounting Standards #101:
Regulated Enterprises- Accounting for the
Discontinuation of Application of FAS 71.
FERC The Federal Energy Regulatory Commission.
Financial Restructuring The comprehensive financial restructuring of the
Company's obligations to Creditors and the
reclassification of all shares of the Preferred Stock into
Common Stock which occurred on December 15, 1992.
First Mortgage Bonds The Company's first mortgage bonds issued under the
General First Mortgage.
Four Corners Four Corners Generating Station.
GAAP Generally Accepted Accounting Principles.
Gallo Wash Gallo Wash Development Company, a wholly-owned subsidiary
of Valencia.
General First Mortgage The Indenture, dated as of April 1, 1941, of Tucson
Gas, Electric Light and Power Company to The Chase
National Bank of the City of New York, as trustee, as
supplemented and amended.
General Second Mortgage The Indenture, dated as of December 1, 1992, of
Tucson Electric Power Company to Bank of Montreal Trust
Company of the City of New York, as trustee, as
supplemented.
Holding Company Act The Public Utility Holding Company Act of 1935, as
amended.
IBEW 1116 International Brotherhood of Electrical Workers labor
union, Local Chapter 1116.
IDBs Industrial development revenue or pollution control
revenue bonds.
DEFINITIONS
(continued)
Installment Sale Agreement $52 million principal amount of City of
Farmington, New Mexico, 6.25% Pollution Control Revenue
Bonds Series 1973.
Interconnection Agreement The Company's agreement with Century for
receiving, delivering and transmitting power.
IRS Internal Revenue Service.
Irvington Irvington Generating Station.
Irvington Lease The leveraged lease arrangement relating to Irvington Unit
4.
Irvington Unit 4 Unit 4 of the Irvington Generating Station.
ITC Investment Tax Credit.
kW Kilowatt(s).
kWh Kilowatt-hour(s).
kV Kilovolt(s).
kVA Kilovoltampere(s).
LOC Letter of Credit.
MRA The master Financial Restructuring agreement between
the Company and the Banks (other than the Bank providing
the LOC relating to the 1981 Apache B Bonds) which
includes the Term Loan, Revolving Credit, Additional
Reimbursement Agreement and Replacement Reimbursement
Agreement.
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.
1989 Rate Order The ACC's October 24, 1989, Rate Order concerning
the Company's 1988 application for a rate increase.
1981 Apache A Bonds $100 million principal amount of variable rate IDBs
assumed by Century in 1984 from which the Company
released Century as part of the Financial Restructuring.
1981 Apache B Bonds $100 million principal amount of variable rate IDBs
which are secured by First Mortgage Bonds.
1990 Pima A Bonds $20 million principal amount of variable rate IDBs
which are secured by First Mortgage Bonds.
1994 Rate Order The ACC's January 11, 1994, Rate Order concerning an
increase in the Company's retail base rates and
regulatory write-offs.
1991 Rate Order The ACC's October 11, 1991, Rate Order concerning an
increase in the Company's retail base rates, regulatory
write-offs and rate and accounting synchronization.
NPC Nevada Power Company.
NTUA Navajo Tribal Utility Authority.
Palo Verde The Palo Verde Nuclear Generating Station.
Payment Moratorium Payment moratoria implemented by the Company with
respect to certain obligations of the Company commencing
January 31, 1991.
PDEQ Pima County Department of Environmental Quality.
P&M Pittsburg & Midway Coal Mining Co.
PNM Public Service Company of New Mexico.
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.
PURPA The Public Utility Regulatory Policies Act of 1978, as
amended.
Reimbursement Agreements Eleven separate reimbursement agreements
between the Company and individual Banks pursuant to
which LOCs were issued by such Banks to trustees for
issues of tax-exempt IDBs issued by several government
entities to finance certain facilities of the Company.
Renewable Term Loan The credit facility that replaces the Term Loan
pursuant to the MRA Sixth Amendment, dated as of
November 1, 1994, completed March 7, 1995.
Replacement LOCs The extensions to at least 1997 of the LOCs as part of the
Financial Restructuring.
Replacement Reimbursement
Agreement A new master reimbursement agreement entered into
among the Company and all Banks that are parties to the
Reimbursement Agreements with the exception of the Bank
which issued the LOC supporting the 1981 Apache B Bonds.
DEFINITIONS
(concluded)
Restated Century Purchase
Contract Contract pursuant to which the Company was obligated
to purchase the entire capacity of Springerville Unit 1
from Century through December 31, 2014.
Revolving Credit The $50 million revolving credit facility entered
into between a syndicate of certain of the Banks and the
Company as part of the Financial Restructuring.
RTGs Regional Transmission Groups.
San Carlos San Carlos Resources Inc., a wholly-owned subsidiary of
the Company.
San Juan San Juan Generating Station.
San Juan Unit 3 Unit 3 of San Juan.
SCE Southern California Edison Company, a subsidiary of
SCECorp.
SDGE San Diego Gas & Electric Company.
Second Mortgage BondsThe Company's second mortgage bonds issued under the
General Second Mortgage.
Securities Exchange Act The Securities Exchange Act of 1934, as amended.
Southwest Gas Southwest Gas Corporation.
SWRTA Southwest Regional Transmission Association.
Springerville Springerville Generating Station.
Springerville Common
Facilities Leases The leveraged lease arrangement relating to the
Company's undivided one-half interest in certain
facilities at Springerville used in common with
Springerville Unit 1 and Springerville Unit 2.
Springerville Unit 1 Unit 1 of the Springerville Generating Station.
Springerville Unit 1 Leases The leveraged lease arrangement pursuant to
which Century leased Springerville Unit 1 and which has
been assumed by the Company.
Springerville Unit 2 Unit 2 of the Springerville Generating Station.
SRI Sierrita Resources Inc., a wholly-owned investment
subsidiary of the Company.
SRP Salt River Project Agricultural Improvement and Power
District.
Term Loan The $243.4 million original principal amount term
loan provided by a syndicate of certain Banks as part of
the Financial Restructuring.
TRI Tucson Resources Inc., a wholly-owned investment
subsidiary of the Company.
Unit 2 First Mortgage First mortgage lien on and security interest in
Springerville Unit 2 which secures, in part, the Term
Loan, the Revolving Credit and the Replacement
Reimbursement Agreement.
Valencia Valencia Energy Company, a wholly-owned subsidiary of the
Company.
Valencia Leases Valencia's leveraged lease arrangement relating to
the coal handling facilities serving Springerville.
Warrants Warrants for purchase of the Common Stock which were
issued under the Financial Restructuring to the owner
participants in the Springerville Unit 1 Leases.
WRTA Western Regional Transmission Association.
WSCC Western Systems Coordinating Council.
PART I
ITEM 1. - BUSINESS
THE COMPANY
Tucson Electric Power Company was incorporated under the laws of the State
of Arizona on December 16, 1963. The Company is the successor by merger as of
February 20, 1964, to a Colorado corporation which was incorporated on January
25, 1902. The Company is an operating public utility engaged in the generation,
purchase, transmission, distribution and sale of electricity for customers in
the City of Tucson and the surrounding area and to wholesale customers. The
Company holds a franchise which expires in 2001 to provide electric service to
customers in the City of Tucson.
The Company owns all of the outstanding stock of Valencia Energy Company
(Valencia), which supplies coal to the Springerville Generating Station (see
Fuel Supply, Valencia), all of the outstanding stock of San Carlos Resources
Inc. (San Carlos), which holds title to Springerville Unit 2, and all of the
outstanding stock of Nations Energy Corporation. See Competition below for a
description of Nations Energy. The Company owns all of the outstanding stock of
two investment subsidiaries, Tucson Resources Inc. (TRI) and Sierrita Resources
Inc. (SRI). See Consolidated Statements of Income (Loss) and Note 5 of Notes to
Consolidated Financial Statements, Discontinued Operations for comparative
financial information relating to the Company's investment business segments.
TRI and SRI have 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) 1994 Rate Order; (ii) Discontinued Investment Subsidiary Operations;
(iii) Item 3., Legal Proceedings; (iv) Item 7., Management's Discussion and
Analysis of Financial Condition and Results of Operations, Overview; and (v)
Notes 2 and 7 of Notes to Consolidated Financial Statements, 1994 Rate Order,
and Commitments and Contingencies, respectively.
THE FINANCIAL RESTRUCTURING
In December 1992, the Company consummated a comprehensive restructuring of
obligations to certain creditors and reclassified its preferred stock into
common stock. The Financial Restructuring was concluded following negotiations
with various creditors including, but not limited to, bank lenders and lease
participants. See Note 3 of Notes to Consolidated Financial Statements, 1992
Consummation of the Financial Restructuring. The Company initiated the
Financial Restructuring because it projected that it might have insufficient
liquidity to meet its cash obligations by the end of the first quarter of 1991.
A payment moratorium on certain of the Company's debt, lease, coal and rail
obligations during part of the period of negotiations provided cash flow
sufficient to meet the Company's other obligations.
The Company believes that the Financial Restructuring provides the Company
the opportunity to return gradually to long-term financial viability. However,
the Financial Restructuring itself will not be sufficient to assure the
Company's long-term financial viability. Also, the Company's capital structure
remains highly leveraged and the Company's financial prospects and cash flows
remain subject to significant economic, regulatory and other uncertainties, many
of which are beyond the Company's control.
UTILITY OPERATIONS
PEAK DEMAND AND CUSTOMERS
Certain operating and system data related to the Company's utility
operations for each of the last five years were as follows:
PEAK DEMAND 1994 1993 1992 1991 1990
- MW -
Retail Customers-Net One Hour 1,585 1,449 1,399 1,319 1,356
Other Utilities-Firm 226 225 150 150 100
Non-Coincident Peak Demand 1,811 1,674 1,549 1,469 1,456
Total Generating Resources 1,975 1,975 1,983 2,048 2,048
Total Reserves 164 301 434 579 592
Reserve Margin (% of Non-Coincident
Peak Demand) 9% 18% 28% 39% 41%
The peak demand for the Company's retail service area occurs during the
summer months due to the space cooling requirements of its retail customers.
The Company has experienced growth in peak demand (excluding the demand of its
copper mining customers which fluctuates widely) at an average annual rate of
approximately 4.9% for the past five years. Including the load of its mining
customers, which comprised approximately 8.0% of the retail peak demand for the
past five years, the Company experienced growth in peak demand of retail
customers at an average annual rate of approximately 4.0% during the same
period.
In 1994, based on non-coincident peak demand, the Company's reserve margin
was only 9% compared with 18% in the prior year. The Company seeks to maintain
a reserve margin equal to its largest single hazard plus 5% of its non-
coincident peak demand in accordance with guidelines established by the WSCC.
The targeted reserve requirement was 295 MW in 1994 or 16% of non-coincident
peak demand. The Company's operations were not adversely affected by the
Company's failure to maintain its targeted reserve requirement in 1994. It is
expected that near-term growth in demand will be met with existing resources and
the additional capacity provided under a power exchange agreement between the
Company and SCE. See SCE/TEP Power Exchange Agreement below. Also, see
Generating Resources below for a discussion of the Company's electric generating
resources.
The average number of retail customers served by the Company increased 2.9%
in 1994 compared with 1993 and 2.1% on average annually over the past five
years. The Company is currently projecting an average annual customer growth
rate of approximately 2.5% and an average annual growth rate in the peak demand
of retail customers of approximately 1.4% for the period 1995 through 1999.
Realized growth in customers and retail demand may be affected by factors
discussed under Competition below. Customer growth rates are projected to
exceed historical growth rates because the Company anticipates greater
population and economic growth than occurred in the past five years.
Also, the Company is projecting a 2.3% average annual growth rate in sales
to retail customers over the next five years. Sales to residential, non-mining
industrial and mining customers account for approximately 41%, 26% and 10%,
respectively, of the projected sales.
The Company has two principal copper mining customers. In 1994, sales to
such customers represented 11% and 6% of the Company's retail sales and their
contract demands were 6% and 5%, respectively, of the Company's 1994 retail non-
coincident peak demand. The total coincident peak load for the Company's two
mining customers was 8.6% of the Company's 1994 retail peak demand. Revenues
from sales to mining customers have comprised between 10% and 11% of the
Company's revenues from retail customers in each of the three years in the
period ended December 31, 1994.
In March 1994, the Company and the large mining customer to which the
Company supplied approximately 50 MW, executed a new contract that included a
reduced rate designed to induce such customer to remain on the Company's system
rather than self-generate. In April 1994, the ACC approved such contract.
Revenues from this customer were $23.6 million and $22.3 million in 1993 and
1994, respectively. In 1993, the Company entered into a similar contract with
its largest mining customer although at a different rate level. 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 has been notified at least one and up
to two years prior to such termination. The ability to extend contracts, and to
avoid early termination, will be dependent on market conditions at the time and
alternatives available to customers at that time.
Future markets and prices for fuel, access to capital, as well as ACC
decisions regarding rate design and the timing of rate decisions will affect the
economics of self-generation projects (including cogeneration) and may
ultimately affect whether customers, such as the mining customers described
above, if any, might reduce or terminate their contract demand 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 (or Maximum)
Contract
Company Demand MW Contract Term
SRP 100 June 1, 1991 - May 31, 2011
NPC 50 May 16, 1990 - December 31, 1995
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's peak demand is expected to be about 70 MW.
COMPETITION
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. Regardless of such regulation, the Company competes for retail
markets against gas service suppliers and others who may provide energy services
which would be substitutes for, or bypass of, the Company's services.
The Company does compete with other utilities, marketers and independent
power producers in the sale of electric capacity and energy in the wholesale
market. It is expected that competition to sell capacity will remain vigorous
and that prices will remain depressed for 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 of the 3,810 MW Palo Verde nuclear generating station
and other generating stations in the southwestern United States, the
availability and prices of natural gas and oil, spot energy prices and
transmission access. In addition, the Energy Act has increased competition in
the wholesale electric power markets.
The Energy Act addresses a wide range of energy issues, including several
matters affecting bulk power competition in the electric utility industry. It
creates exemptions from regulation under the Holding Company Act for persons or
corporations that own and/or operate in the United States certain generating and
interconnecting transmission facilities dedicated exclusively to wholesale
sales, thereby encouraging the participation of utility affiliates, independent
power producers and other non-utility participants in the development of power
generation. In order to facilitate competition in power generation, the Energy
Act also confers expanded authority upon FERC to issue orders requiring electric
utilities to transmit power and energy to or for wholesale purchasers and
sellers, and to require electric utilities to enlarge or construct additional
transmission capacity to provide these services. While the Energy Act prohibits
FERC from issuing any such order that would unreasonably impair the continuing
reliability of affected electric systems or that would be conditioned upon or
require transmission services directly to an ultimate consumer, the Energy Act
creates the potential for utilities and other power producers to gain increased
access to the transmission systems of other entities to facilitate wholesale
sales. FERC is encouraging all parties interested in transmission access to
form RTGs to facilitate access to and development of transmission service and to
assist in settling disputes regarding such matters. RTGs will not relieve FERC
of its responsibilities related to transmission access; however, such
organizations could provide for more efficient handling of transmission service
requests and planning for regional transmission needs. The Company is currently
involved in the development of two RTGs in the West, SWRTA and WRTA. WRTA and
SWRTA both filed applications for approval with the FERC during 1994 which have
yet to be accepted. The Company currently intends to become a member of SWRTA
and is also considering membership in WRTA.
On the retail level, industrial and large commercial customers may have the
ability to own and operate facilities to generate their own electric energy
requirements and, if such facilities are qualifying facilities, to require the
displaced electric utility to purchase the output of such facilities at "avoided
costs" pursuant to PURPA. Such facilities may be operated by the customers
themselves or by other entities engaged for such purpose.
Finally, the legislatures and/or the regulatory commissions in several
states have considered or are considering "retail wheeling" which, in general
terms, means the transmission by an electric utility of energy produced by
another entity over its transmission and distribution system to a retail
customer in such utility's service territory. A requirement to transmit
directly to retail customers could have the result of permitting retail
customers to purchase electric capacity and energy from, at the election of such
customers, the electric utility in whose service area they are located or from
other electric utilities or independent power producers.
In Arizona, the ACC Staff issued its first report on a retail electric
competition workshop held in October of 1994. This report is the first in a
series of reports that will be issued on various workshops that will be held
from time to time to identify and address policy issues related to competition.
While other states are considering competition proposals, the ACC effort is
designed to obtain information about competition. No specific proposals are
currently being considered. The report proposes that Staff develop a
comprehensive set of options to better inform the ACC about its choices. Staff
recommended that three options be considered: 1) encouraging retail
competition, 2) tolerating limited retail competition, and 3) discouraging
retail competition by prohibiting retail wheeling and tolerating distributed
energy services. The ACC has also established a working group on retail
electric competition. Membership in the working group includes ACC Staff,
Arizona utilities, and other interested parties, and the first meeting of the
group took place in January 1995. A report from the group is expected by August
1995. The Company cannot predict what the working group will recommend and
what, if any, changes in electric regulation and competition will be implemented
by the ACC.
See Peak Demand and Customers above for information concerning mining
customers which have considered self-generation and Generating and Other
Resources and Other Purchases and Item 2., Properties below for information
concerning the Company's transmission access to and interchange relationships
with other utilities in the southwestern United States.
The Company continues to assess the impact of the Energy Act and other
possible legislation on the Company's ability to remain competitive in the
electric utility industry. The Company is unable to predict the ultimate impact
the Energy Act or any other possible legislation will have on its operations.
NATIONS ENERGY CORPORATION
The Company's wholly-owned subsidiary Nations Energy Corporation
(previously known as Escalante Resources, Inc.) is pursuing opportunities in the
independent power business. Nations Energy is exploring independent power
prospects in the domestic and foreign energy markets. Such prospects may
include, for instance, the development of cogeneration facilities, the
acquisition of interests in existing power production facilities that sell to
utilities or utility authorities, or the construction of independent power
projects in countries that are privatizing their electric utility industry.
Initially, an emphasis will be placed on exploring opportunities in the Western
hemisphere. To date, no project has been approved for development or
acquisition. Nations Energy's activities may be limited due to various
restrictions including certain restrictions imposed by the MRA. See Item 7.,
Management's Discussion and Analysis of Financial Condition and Results of
Operations, Restrictive Covenants, Additional Restrictive Covenants.
In an effort to adapt its structure to the new competitive environment, the
Company is currently planning to create a holding company. See Item 7.,
Management's Discussion and Analysis of Financial Condition and Results of
Operations, Proposed Holding Company.
GENERATING AND OTHER RESOURCES
COMPANY RESOURCES
The total net generating capability currently owned or leased by the
Company at December 31, 1994 was 1,952 MW as set forth in the table below:
Net
Capa-
Unit Fuel bility Operating Company Share
No. Location Type MW Agent % MW
Springerville Station 1 Springerville, AZ Coal 360 TEP 100.0 360
Springerville Station 2 Springerville, AZ Coal 360 TEP 100.0 360
San Juan Station 1 Farmington, NM Coal 316 PNM 50.0 158
San Juan Station 2 Farmington, NM Coal 312 PNM 50.0 156
Navajo Station 1 Page, AZ Coal 750 SRP 7.5 56
Navajo Station 2 Page, AZ Coal 750 SRP 7.5 56
Navajo Station 3 Page, AZ Coal 750 SRP 7.5 56
Four Corners Station 4 Farmington, NM Coal 784 APS 7.0 55
Four Corners Station 5 Farmington, NM Coal 784 APS 7.0 55
Irvington Station 1 Tucson, AZ Gas/Oil 81 TEP 100.0 81
Irvington Station 2 Tucson, AZ Gas/Oil 81 TEP 100.0 81
Irvington Station 3 Tucson, AZ Gas/Oil 104 TEP 100.0 104
Irvington Station 4 Tucson, AZ Coal/Gas/Oil 156 TEP 100.0 156
Internal Combustion Turbines Tucson, AZ Gas/Oil 218 TEP 100.0 218
-----
Total Company Capacity(1) 1,952
=====
(1)Excludes 23 MW of additional resources, which consists of certain other
capacity purchases and interruptible retail load. Total Company capacity
owned is 1,339 MW and leased is 613 MW.
SPRINGERVILLE STATION
Springerville Station consists of two 360 MW coal fired units.
Springerville Unit 1 began commercial operation in 1985 and is currently leased
and operated by the Company. Springerville Unit 2 commenced commercial
operation in June 1990 and is owned by San Carlos and operated by the Company.
Prior to the Closing, the Springerville Station was operated by Century, Century
leased Springerville Unit 1 and the Company purchased capacity and energy from
Springerville Unit 1 under the Restated Century Purchase Contract.
The primary terms of the Springerville Unit 1 Leases expire on January 1,
2015. At December 31, 1994, the capitalized lease asset related to Springerville
Unit 1, net of allowance and accumulated amortization, was $260 million for
financial statement purposes. 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
but average approximately $73 million. The average cash cost to the Company of
Springerville Unit 1 capacity attributable to rent obligations and other
operation and maintenance expenses after December 15, 1992, is estimated to be
approximately $18 per kW per month (approximately $78 million per year), from
January 1993 through December 1997, 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
will be accrued in the Company's financial statements over the 1993 - 1997
period at an average of approximately $22 per kW per month (approximately $95
million per year) before amortization of the regulatory disallowance and
interest expense thereon. The 1991 Rate Order allows the Company to recover the
cost of the entire 360 MW capacity of Springerville Unit 1, but limits such
recovery to a rate of $15 per kW per month (approximately $65 million per year).
Substantially all of the present value of disallowed Springerville Unit 1 costs
was recorded as a loss in 1990, and as a result of the Financial Restructuring,
an additional loss was recorded in 1992. The losses together reflect the
present value of the difference between projected costs and the amount the
Company is allowed to recover through the lease term ending January 1, 2015.
See Notes 1 and 3 of Notes to Consolidated Financial Statements, Nature of
Operations and Summary of Significant Accounting Policies, Allowance for
Springerville Unit 1 and 1992 Consummation of the Financial Restructuring,
Capital Leases, respectively.
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, 1994, the capitalized lease asset related to Springerville common
facilities, net of accumulated amortization, was $126 million for financial
statement purposes. 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. In 1993 and 1994, such lease payments totalled $7 million and
$12 million, respectively. Based on current interest rates, annual lease
payments would average approximately $13 million.
Including the cost of leased common facilities (but excluding the cost of
coal-handling facilities at Springerville which are included in recoverable fuel
costs), the total initial cost of Springerville Unit 2 was $838 million, or
$2,328 per kW. Approximately 26% of such cost is attributable to AFDC accrued
prior to July 1, 1989. In the 1991 Rate Order, the ACC disallowed recovery from
retail customers of $175 million of the book value of Springerville Unit 2. The
Company recorded a loss for such disallowance in 1991. The net recoverable
cost, including the leased common facilities, is $1,842 per kW. See Rates and
Regulation, 1994 Rate Order and Note 2 of Notes to Consolidated Financial
Statements, 1994 Rate Order.
IRVINGTON STATION
In January 1988, the Company began coal-fired commercial operation and
entered into a sale and leaseback arrangement for Irvington Unit 4 pursuant to
the Irvington Lease. The unit was sold at its cost of $152 million. At
December 31, 1994, the capitalized lease asset related to Irvington Unit 4, net
of accumulated amortization, was $128 million for financial statement purposes.
This lease calls for annual payments which will range from approximately $9
million to $28 million and which average approximately $13 million. The lease
term expires in 2011 but the lease provisions have optional renewal periods and
purchase options.
With the addition of coal firing capability, Irvington Unit 4 (156 MW
capability) has the flexibility to operate on coal, gas or fuel oil. Coal has
been the primary fuel and natural gas the secondary fuel.
SCE/TEP POWER EXCHANGE AGREEMENT
As part of a 1992 litigation settlement, the Company and SCE have agreed to
a ten-year power exchange agreement. Under the agreement, beginning in May
1995, SCE will provide firm system capacity of 110 MW to the Company during
summer months, for which the Company will pay 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 will be 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 will be obligated to return to
SCE on an interruptible basis the same amount of energy the following winter
season (November 1 through February 28). The Company will incur fuel expense
related to the exchange in an amount equal to the cost of interruptible energy
provided to SCE. The Company believes the agreement may reduce the Company's
overall system fuel costs, allow it to sell additional capacity on the wholesale
market, and/or permit it to defer the construction of future generating
resources. The agreement has been accepted for filing by the FERC. The 1994
Rate Order directed the Company to propose an allocation of the benefits of this
agreement with its retail customers. The Company expects to include such an
allocation proposal in its next rate filing. See Rates and Regulation, 1994
Rate Order.
FUTURE GENERATING RESOURCES
In December 1992, the Company filed an integrated resource plan pursuant to
the ACC's regulations governing resource planning. In its filing the Company
projected no need for any new peaking or intermediate generation facilities
until after the year 2000 or base load generation facilities until after the
year 2007. In addition, the Company projected that demand-side management
programs should reduce peak demand and, therefore, capacity requirements, from
what they would be without such programs by 76 MW by the year 2000. As part of
the integrated resource plan, the Company has committed to adding 5 MW of
renewable resources generation by the year 2000. Also as mentioned above, the
Company has a power exchange agreement with SCE; such exchange will provide
additional generating resources to the Company.
OTHER PURCHASES
In addition to generating electricity at generating stations owned or
leased by the Company, 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 74 electric systems or suppliers, including those in the
southern California markets. The Company is a member of the Inland Power Pool,
which is comprised of a group of utilities serving customers in portions of the
western United States. The Inland Power Pool membership facilitates interchange
with companies having system peak periods different from those of the Company.
The Company is also a member of the WSCC, a group of western electric systems
and suppliers that works cooperatively to assure the reliability of the region's
interconnected generation and transmission systems. In 1990, the Company joined
the Western Systems Power Pool which is a voluntary power pooling experiment to
achieve more efficient use of electric generation and transmission facilities
among its members. See Competition for a discussion of possible changes in
transmission issues.
RATES AND REGULATION
GENERAL
The Company is subject to the jurisdiction of the ACC, which has authority,
among other things, to prescribe the classifications of accounts to be used and
the rates and charges to be made and collected from retail customers, and to
regulate the issuance of securities. The Company is also subject to regulation
by FERC in certain respects, including sales to other utilities.
Arizona statute 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 judgement by the ACC regarding prudency and recoverability.
The Company's rates for wholesale sales of capacity and energy, generally,
are not permitted to exceed rates determined on a cost of service basis. In all
instances, the Company's wholesale rates are substantially below rates
determined on a fully allocated cost of service basis, but in any event exceed
the level necessary to recover fuel and other variable costs.
The ACC consists of three commissioners, each serving a six-year term. One
of the three is elected at each general election except when a vacancy occurs
prior to the expiration of a commissioner's term. The present commissioners
are:
- - Renz D. Jennings (Democrat), Chairman, was elected to a third term in 1992.
His term expires in 1999.
- - Marcia Weeks (Democrat) was elected to a second term in 1990. Her term
expires in 1997.
- - Carl Kunasek (Republican) was elected to a first term in 1994. His term
expires in 2001.
1994 RATE ORDER
On January 11, 1994, the ACC issued a decision approving a 4.2% retail rate
increase for the Company. The new rates were effective as of January 11, 1994.
According to the 1994 Rate Order, the new rates were intended to produce an
annual increase in gross revenues of approximately $21.6 million based upon a
test year ended June 30, 1992. This reflects an allowed original cost rate base
of approximately $1.0 billion and a return on original cost rate base (after
write-offs) of 8.51% based upon a rate of return on common equity of 11%. The
Company requested in its January 1993 filing a $49 million increase in gross
revenues, based on an original cost rate base of approximately $1.1 billion and
a rate of return base of 9.17% based upon 12.5% return on equity. In
determining the required return on rate base, the 1994 Rate Order utilized a
hypothetical capital structure of 49.8% long-term debt, 44.1% common equity,
4.7% preferred equity and 1.4% short-term debt as contemplated under a 1991 rate
settlement agreement.
The decision authorized the inclusion of an additional 17.5% of
Springerville Unit 2 in rate base, for a total of 62.5%. The 1994 Rate Order
also allowed inclusion of 62.5% of the Springerville Unit 2 rate synchronization
and excess capacity deferred expenses in rate base. Amortization of those rate
synchronization deferred expenses allowed in rate base was authorized to be
recovered from retail customers over a three-year period. However, amortization
of the excess capacity deferred expenses allowed in rate base was authorized to
be recovered from retail customers over 37.4 years. The 37.5% of the rate
synchronization and excess capacity expenses not currently being recovered
continue to accrue a 7.19% interest carrying charge. See Note 2 of Notes to
Consolidated Financial Statements, 1994 Rate Order.
Based on the 1994 Rate Order, the Company recorded an additional $13.6
million in write-offs related to previously capitalized Springerville Unit 2
costs and certain other minor costs for which recovery was permanently
disallowed. See Note 2 of Notes to Consolidated Financial Statements, 1994 Rate
Order.
The Company's filing also discussed a proposal for the allocation of the
future benefits of the 1992 settlement of a lawsuit brought against SCECorp. and
SCE for interference with the Company's 1988 attempted merger with SDGE. SCE
paid the Company a $40 million cash settlement and entered into a ten-year, 110-
megawatt power exchange agreement to begin in 1995 which FERC has accepted for
filing. The ACC stipulated in the 1994 Rate Order that the Company use $27
million of the litigation settlement, which is equal to the $40 million less
costs of litigation, to prepay debt. Also, the ACC ordered the Company to
submit a proposal for the sharing of the benefits of the SCE power exchange
agreement. The Company expects to include such benefit sharing proposal in its
next rate filing.
The Company intends to seek rate recovery of the costs associated with the
remaining 37.5% of Springerville Unit 2 that is not in base rates. This rate
request is expected to be filed in 1995.
See Note 2 of Notes to Consolidated Financial Statements, 1994 Rate Order,
for additional discussion concerning the 1994 Rate Order.
OTHER RATE MATTERS
See Utility Operations, Peak Demand and Customers for a discussion of the
Company's contracts and negotiations with certain of its mining customers.
FUEL SUPPLY
GENERAL
The Company's principal fuel for electric generation is low-sulfur coal.
The following table provides fuel cost information for the years 1994 through
1990:
Cost Per Million BTU Consumed Percentage of Total BTU Consumed
1994 1993 1992 1991 1990 1994 1993 1992 1991 1990
Coal(A)(B) $2.06 $2.01 $1.89 $2.04 $1.94 98% 99% 99% 99% 99%
Gas 1.86 2.76 2.39 2.14 2.67 2 1 1 1 1
--- --- --- --- ---
All Fuels 2.05 2.02 1.90 2.05 1.95 100% 100% 100% 100% 100%
=== === === === ===
(A) The average cost per ton of coal for each of the last five years (1994 -
1990) was $38.93, $37.60, $36.46, $39.55 and $37.90, respectively.
(B) Includes the cost of fuel handling facilities at Springerville. Such costs
per million BTU consumed were: $0.36, $0.37, $0.26, $0.35 and $0.25 for 1994
to 1990, respectively.
COAL
The Company is the operator for the Springerville and Irvington generating
stations. Their coal supplies are transported from northwestern New Mexico by
railroad. The coal contract for Springerville is for the remaining lives of
Units 1 and 2 with a bilateral option to renegotiate the contract price and
escalation procedures in 2009 and every five years thereafter. At Irvington,
the contract termination date is the earlier of 2015 or the remaining life of
Unit 4. The Springerville and Irvington contracts have various adjustment
clauses which will affect the future cost of coal delivered. Coal reserves are
expected to be sufficient to supply the estimated requirements of Springerville
and Irvington for their presently estimated remaining lives. The Company also
participates in jointly owned generating facilities under long-term contracts
entered into by the operating agents. Coal supplies are surface-mined in
northern Arizona and northwestern New Mexico. The coal quantities under
contract for the Navajo and Four Corners mine-mouth, coal fired generating
stations are expected to be sufficient to supply the estimated requirements for
their presently estimated remaining lives. The coal quantities for San
uan, also a mine-mouth generating station, are partially contracted through the
year 2017. Additional information concerning the coal contracts is set forth
below:
Cost Per
Year Average Million
Contract Sulfur BTU in
Station Coal Supplier Terminates Content 1994(A) Coal Obtained From(B)
Four Corners BHP Utah International, Inc. 2005 0.8% $1.15 Navajo Indian Tribe
San Juan San Juan Coal Company 2017 0.8% $1.89 Federal and State Agencies
Navajo Peabody Coal Company 2011 0.6% $1.11 Navajo and Hopi Indian Tribes
Springerville Hanson Natural Resources
Company 0.7% $2.33(C) Lee Ranch Coal Company
Irvington The Pittsburg & Midway Coal
Mining Company 2015 0.4% $2.50 Navajo Indian Tribe and
Federal and State Agencies
(A)Includes costs of transportation and handling in addition to the purchase price under the basic contract.
(B) Substantially all of the suppliers' leases extend at least as long as coal is being mined in economic quantities.
(C) The Springerville costs include approximately $0.93 per million BTU for costs associated with Valencia operations,
including the costs of the Valencia Leases. Valencia is responsible for the handling of fuel for the Springerville Station.
In 1991, 1992, 1993 and 1994, the Company obtained various amendments to
its contracts with the Springerville and Irvington coal and rail transportation
suppliers. The Company estimates that such amendments produced aggregate
savings of $59.6 million, $42.7 million, and $27.8 million in 1994, 1993 and
1992, respectively, compared with the costs which would have been incurred had
such amendments not been obtained.
Some of the 1991 amendments provided for the repayment of certain amounts
withheld during the Payment Moratorium and the forgiveness of other amounts in
exchange for certain land. All of the 1991 amendments provide for the
preservation of the suppliers' claims under the original contracts, as though
such contracts had not been amended, for a period of four years from the
amendments if the Company does not perform under the terms of the amended
contracts. See Note 7 of Notes to Consolidated Financial Statements,
Commitments and Contingencies.
Also, in July 1992 the contract with the San Juan coal supplier was amended
to, among other things, reduce operations and maintenance pass-through costs by
10%, reduce ash handling costs and also to provide price reduction incentives
for coal purchased above certain minimum quantities. Such amendment provides
yearly savings to the Company of approximately 6%, or $1.4 million.
The Company intends to continue to actively negotiate its fuel and
transportation contracts in 1995 and in the future.
VALENCIA
Valencia is responsible for the acquisition, transportation and handling of
fuel for Springerville. Pursuant to a fuel burn agreement with the Company,
Valencia has the exclusive right and obligation to provide all of the fuel
requirements for Springerville.
Pursuant to the Valencia Leases, Valencia is the lessee of the coal-
handling facilities at Springerville under a capital lease with a remaining
initial lease term of approximately 21 years with incremental extensions of five
to six years depending on certain criteria at the date of each extension. At
December 31, 1994, the capitalized lease asset related to Springerville coal-
handling facilities, net of accumulated amortization, was $184 million for
financial statement purposes. Annual rental payments range from approximately
$15 million to $25 million but average $21 million. Rental payments and other
obligations of Valencia under the leases are guaranteed by the Company.
Valencia allocates portions of its costs to deferred expense for future
recovery through sales of fuel. See Note 1 of Notes to Consolidated Financial
Statements, Nature of Operations and Summary of Significant Accounting Policies,
for a description of the accounting for Valencia lease costs.
GAS
In 1994, the Company purchased a small amount of natural gas for power
generation (less than 2% of total Company generation) from Southwest Gas, Anthem
Energy, BridgeGas, Chevron, Natural Gas Clearinghouse, Mobil and USGT. During
1994, the Company received natural gas sufficient to meet all of its gas fuel
requirements; however, as in the past, the Company's supply of natural gas for
boiler fuel may be limited occasionally in the future.
WATER SUPPLY
Arrangements have been made for water sufficient to supply the requirements
of existing and planned units of all electric generating stations in which the
Company has an interest for their estimated lives.
ENVIRONMENTAL MATTERS
GENERAL
The Company must operate its generating stations in accordance with
numerous local, state and federal guidelines, laws, regulations and ordinances
designed to preserve and enhance environmental integrity. Resource extraction
and waste disposal operations are also regulated for environmental
compatibility. Generally, air quality and water quality are under the most
stringent regulations. Land use is also carefully 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
their proximity to national parks, monuments, wilderness areas and Indian
reservations and due to the 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 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 $6.2 million during 1994 for environmental
construction costs in maintaining compliance with environmental requirements.
The Company estimates that it will make expenditures for environmental
facilities of approximately $9.8 million in 1995 and $8.8 million in 1996.
These amounts include the Company's estimated share of initial expenditures for
improvements to the pollution control facilities at Navajo which are associated
with the final rule issued by EPA on October 3, 1991, regarding visibility
impairment in Grand Canyon National Park (see Navajo Generating Station below
for information regarding the projected total cost of such facilities), and
procurement of continuous emission monitors for Irvington Units 1, 2, 3, and 4
and Springerville Units 1 and 2. With the construction expenditures described
above, the Company believes that all existing generating facilities are or will
be in compliance with all existing or expected environmental regulations except
as described below.
In the fall of 1990, Congress adopted certain Federal Clean Air Act
Amendments (CAAA) with respect to reductions in sulfur dioxide and nitrogen
oxide emissions which will affect the Company's operation. The nitrogen oxide
reductions will be based upon EPA regulations expected to be finalized in 1995
for certain boilers and by 1997 for all remaining boilers. In addition, the
rules expected to be promulgated in 1995 may be revised in 1997. The required
reductions of sulfur dioxide emissions will be implemented in two phases which
will be effective in 1995 and 2000, respectively.
The Company is not affected by the requirements for sulfur dioxide
emissions and nitrogen oxide reductions which go into effect in 1995 (Phase I),
but is subject to the requirements that go into effect January 1, 2000 (Phase
II). In Phase II, the maximum sulfur dioxide emission rates are set at 1.2
pounds per million BTU. Because of the Company's general use of low-sulfur coal
and installed scrubbers at certain units, the Company's coal-fired generating
stations already meet the sulfur dioxide emission rate requirements for Phase
II. Additionally, further reductions are to be met through a proposed market-
based system. Affected Company generating units will be allocated allowances
based on required emission reductions and past use. An allowance permits
emission of one ton of sulfur dioxide and may be sold. Generating station units
must hold allowances equal to their level of emissions or face penalties and a
requirement to offset excess tons in future years. On March 23, 1993, the EPA
published the final sulfur dioxide allowance allocations for all Phase I and
Phase II affected utility units, including the allowances that will be allocated
to all Company units. An analysis of the sulfur dioxide allowances that were
allocated to the Company shows that the Company would have sufficient allowances
to permit normal plant operation and be in compliance with the sulfur dioxide
regulations once the Phase II requirements become effective. However, until all
the rulemaking regulation processes for implementing the CAAA are completed, the
Company is unable to predict the specific impacts of all such amendments.
Title V of the CAAA established a new air quality permitting system that
will be administered in Arizona by the ADEQ. Electric utilities in the state
were required to submit applications for Title V permits by February 1, 1995;
processing and issuance of these permits is expected to take at least 18 months.
Until a Title V permit is issued, permits that expire during that period will
either be honored or will be reissued by ADEQ with additional requirements
reflecting Title V regulations.
The CAAA also require multi-year studies of visibility impairment in
specified areas and studies of hazardous air pollutants which relate to the
necessity of future regulations of electric utility generating units. Since
these activities involve the gathering of information not currently available,
the Company cannot predict the outcome of these studies.
As a result of recent and possible future changes in federal and state
environmental laws, regulations and permit requirements, the Company may incur
additional costs for the purchase or upgrading of pollution control emission
monitoring equipment on existing electric generating facilities and may
experience a reduction in operating efficiency. There may be a need for
variances from certain environmental standards and operating permit conditions
until required equipment and processes for control, handling and disposal of
emissions are operational and reliable. Failure to comply with any EPA or state
compliance requirements may result in substantial penalties or fines which are
provided for by law and which in some cases are mandatory.
FOUR CORNERS GENERATING STATION
The Company believes that all units at Four Corners are presently operating
in compliance with federal and state regulations.
IRVINGTON GENERATING STATION
The Company has an ADEQ operating permit for Irvington Unit 4, which
expires on February 8, 1996. The other facilities at the Irvington station were
under the jurisdiction of the PDEQ until 1993. However, because of 1990 CAAA
requirements which require the facility to obtain a Title V permit, the entire
facility was placed under the jurisdiction of ADEQ in April 1994. The Company
has filed a Title V permit application for the Irvington facility on February 1,
1995. Each major source requiring a Title V permit must pay an annual emission-
based fee. The 1995 emission fee for the Irvington facility was assessed at
$179,000 and is expected to range between $150,000 to $250,000 for 1996.
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, 1994 relating
to the rule's implementation will be approximately $44 million, including AFDC,
through 1999.
SAN JUAN GENERATING STATION
The Company believes that all units at San Juan are presently operating in
compliance with federal and state regulations.
SPRINGERVILLE GENERATING STATION
Springerville Units 1 and 2 meet all existing federal and state regulations
pertaining to environmental quality. Springerville Units 1 and 2 are operating
under an operating permit issued by ADEQ on December 19, 1994, which expires on
December 19, 1999. Springerville Generating Station is a major source requiring
a Title V permit, and the Company filed a Title V permit application for the
Springerville facility on February 1, 1995. As a result of requirements imposed
by the CAAA of 1990, each major source requiring a Title V permit must pay an
annual emission-based fee. The 1995 emission fee for the Springerville
Generating Station Units 1 and 2 was assessed at $316,000 and is expected to be
approximately the same for 1996.
EMPLOYEES
The Company and the IBEW 1116, which represents about 63% of the 1,396
employees of the Company and its subsidiaries at December 31, 1994, are parties
to a two-year collective bargaining agreement for the period from December 1,
1994 through November 30, 1996. The collective bargaining agreement, which was
negotiated with and approved by the IBEW 1116 in November 1994, includes annual
wage increases of 3.6% and 4.0% in 1995 and 1996, respectively, and
modifications to the pension, health and supplemental retirement plans.
DISCONTINUED INVESTMENT SUBSIDIARY OPERATIONS
The Company directly owns two investment subsidiaries, TRI and SRI. TRI
and SRI each wholly own several subsidiaries both directly and indirectly.
In July 1990, each of the Board of Directors of TRI and SRI adopted
resolutions for the liquidation of substantially all of the assets of these
subsidiaries. As a consequence, the investment subsidiaries were reclassified
as discontinued operations for financial statement purposes. This
reclassification required the Company to estimate the net realizable value of
the investment subsidiary assets in light of the projected time frame of the
liquidation and in accordance therewith, the Company established appropriate
reserves for losses. The estimated net realizable value of the investment
subsidiaries' net assets as of December 31, 1994 was approximately $8.5 million.
The Company intends to continue to liquidate the remaining assets.
The investment subsidiaries have been in the process of liquidating their
assets and have dividended available asset-sale proceeds to the Company. During
1994, the investment subsidiaries sold all of their remaining interests in
cogeneration and independent power projects, as well as the hotels located in
Louisville, Kentucky and Woodland Hills, California. In January and February
1995, the remaining equity securities were sold. The Company received cash
dividends from TRI of $10 million in April 1994, $15 million in June 1994 and
$25 million in December 1994. Since July 1990, a total of $97 million of cash
dividends has been received by the Company from the investment subsidiaries.
See Item 7. - Management's Discussion and Analysis of Financial Condition and
Results of Operations, Restrictive Covenants, Prepayments.
See Note 5 of Notes to Consolidated Financial Statements, Discontinued
Operations.
UTILITY OPERATING STATISTICS
1994 1993 1992 1991 1990
Generation and Purchased
Power-kWh (000)
Remote Generation (Coal) 9,341,342 8,986,350 6,148,825 5,518,543 5,191,186
Local Generation (Oil, Gas
& Coal) 825,385 615,100 527,405 314,441 692,651
Purchased Power 501,269 335,897 2,436,152 2,736,620 2,685,647
---------- --------- --------- --------- ---------
Total Generation and
Purchased Power 10,667,996 9,937,347 9,112,382 8,569,604 8,569,484
Less Losses and Company Use 639,278 591,412 610,040 585,964 584,101
---------- --------- --------- --------- ---------
Total Energy Sold 10,028,718 9,345,935 8,502,342 7,983,640 7,985,383
========== ========= ========= ========= =========
Sales-kWh (000)
Residential 2,374,868 2,223,479 2,146,268 2,081,476 2,069,718
Commercial 1,281,050 1,242,367 1,215,179 1,182,599 1,193,964
Large Users 1,948,331 1,832,278 1,771,937 1,756,887 1,751,263
Mining 1,135,424 1,090,061 1,081,791 951,646 898,584
Public Authorities 183,525 159,310 165,922 164,380 162,575
---------- --------- --------- --------- ---------
Total-Retail Customers 6,923,198 6,547,495 6,381,097 6,136,988 6,076,104
Sales to Other Utilities 3,105,520 2,798,440 2,121,245 1,846,652 1,909,279
---------- --------- --------- --------- ---------
Total 10,028,718 9,345,935 8,502,342 7,983,640 7,985,383
========== ========= ========= ========= =========
Operating Revenues (000) (A)
Residential $220,341 $197,368 $190,089 $174,054 $159,813
Commercial 137,508 128,688 125,655 114,826 107,373
Large Users 144,677 131,858 127,456 121,269 109,236
Mining 53,821 53,510 57,266 49,996 46,365
Public Authorities 13,435 11,464 11,757 11,273 10,079
Other 1,651 1,925 1,791 1,583 1,475
-------- -------- -------- -------- --------
Total-Retail Customers 571,433 524,813 514,014 473,001 434,341
Amortization of MSR Option Gain
Regulatory Liability 20,053 6,053 6,053 16,553 -
Sales to Other Utilities 99,987 93,273 70,026 65,441 60,199
-------- -------- -------- -------- --------
Total $691,473 $624,139 $590,093 $554,995 $494,540
======== ======== ======== ======== ========
Customers (End of Period)
Residential 266,060 258,168 251,656 246,538 242,539
Commercial 27,360 26,838 26,441 26,144 25,938
Large Users 588 551 527 531 516
Mining 4 4 4 4 3
Public Authorities 59 59 59 59 59
------- ------- ------- ------- -------
Total Retail Customers 294,071 285,620 278,687 273,276 269,055
======= ======= ======= ======= =======
Average Revenue per kWh Sold (cents) (A)
Residential 9.3 8.9 8.9 8.4 7.7
Commercial 10.7 10.4 10.3 9.7 9.0
Large Users 6.4 6.3 6.5 6.3 5.9
Total - Retail Customers 8.3 8.0 8.1 7.7 7.1
Average Revenue per
Residential Customer $841 $776 $765 $714 $666
Average kWh Sales per
Residential Customer 9,066 8,739 8,632 8,534 8,621
(A) Amounts for 1993-1990 have been restated to eliminate revenue related taxes. See
Note 1 of Notes to Consolidated Financial Statements, Nature of Operations and
Summary of Significant Accounting Policies, Reclassification.
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. 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 74 companies, including the
five listed above, which are utilized to interchange capacity and energy.
As of December 31, 1994, 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 8,947 circuit-miles of lower voltage
primary lines. The underground electric distribution system was comprised of
4,223 cable-miles. Approximately 25% 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 165 substations
with a total installed transformer capacity of 5,209,355 kVA.
The electric generating stations (except as noted below), the Company's
general office building, operating headquarters and the warehouse and service
center are located on land owned by the Company in fee. The electric
distribution and transmission facilities owned by the Company are located (1) on
property owned in fee by the Company, (2) under or over streets, alleys,
highways and other public places, the public domain and national forests and
state lands under franchises, easements or other rights which, with some
exceptions, are subject to termination, (3) under or over private property by
virtue of easements obtained for the most part from the record holder of title,
and (4) under Indian reservations under grant of easement by the Secretary of
Interior or lease by Indian tribes. In most instances, no examination has been
made by counsel for the Company as to the title to easements of the Company from
the record holder or to the property over which the easement has been granted,
or as to possible liens, encumbrances, reservations or restrictions thereon.
Therefore, some of the easements and the property over which the easements have
been secured may be subject to title defects and encumbered by, or subject to,
mortgages and liens existing at the time the easements were acquired.
Most of the land parcels comprising Springerville are held by the Company
under a long-term surface ownership agreement with the State of Arizona. The
Company's 50% interest in the common facilities of Springerville and its 100%
interest in Irvington Unit 4 and related common facilities were sold and are
leased back by the Company. The coal-handling facilities at Springerville were
sold and leased back by Valencia. The Company leases Springerville Unit 1 and
the remaining 50% interest in the common facilities at Springerville.
Four Corners and Navajo are located on properties held under easements from
the United States and under leases from the Navajo Indian Tribe. The Company,
individually and in conjunction with PNM in connection with San Juan, has
acquired easements and leases for transmission lines and a water diversion
facility located on the Navajo Indian Reservation. The Company has also
acquired easements for transmission facilities, related to San Juan and Navajo,
across the Zuni, Navajo and Tohono O'odham Indian Reservations.
The Company's rights under the various easements and leases described under
this heading may be subject to possible defects (including conflicting grants or
encumbrances not ascertainable because of absence of or inadequacies in the
recording laws or the record systems of the Bureau of Indian Affairs and the
Indian tribes, the possible inability of the Company to resort to legal process
to enforce its rights against certain possible adverse claimants and the Indian
tribes without Congressional consent, the possible failure or inability of the
Indian tribes to protect the Company's interests in, and use and occupancy of,
these facilities from interference or interruption, and, in the case of the
leases, possible impairment or termination under certain circumstances by
Congress, the Secretary of the Interior or certain possible adverse claimants).
However, these possible defects have not and are not expected to materially
interfere with the Company's interest in and operation of its facilities.
With the exception of Springerville Unit 2, substantially all of the
utility assets of the Company are subject to the lien of the General First
Mortgage and the General Second Mortgage. Legal title to Springerville Unit 2,
which is not subject to such lien, is held by San Carlos. Springerville Unit 2
is subject to the Unit 2 First Mortgage.
The Company provided to certain banks, at the time of the Closing, the Unit
2 First Mortgage, a first mortgage lien on and security interest in
Springerville Unit 2, and $50 million in principal amount of collateral bonds
issued under the General Second Mortgage, a second mortgage, junior to the lien
of the General First Mortgage, on all the utility assets (other than excepted
property).
ITEM 3. - LEGAL PROCEEDINGS
SDGE/FERC PROCEEDINGS
See SDGE/FERC Proceedings in Note 7 of Notes to Consolidated Financial
Statements.
WATER RIGHTS ADJUDICATION
On March 13, 1975, the State of New Mexico filed an action entitled State
of New Mexico v. United States, et al., in the District Court of San Juan
County, New Mexico, to adjudicate all water rights in the San Juan River Stream
System. The action is expected to adjudicate certain water rights applicable to
the water supply for San Juan and Four Corners. The Company was made a party to
this action in June 1976 and an answer was filed on behalf of the Company and
others in May 1978. For the past several years, the State of New Mexico
Engineer's Office has reportedly been completing reports on hydrographic surveys
performed in conjunction with the litigation. It is anticipated that once those
reports are completed, offers of judgment will be issued to the Company and
other parties. The Company is unable to predict the effect, if any, of any
adjudication on its present arrangements for a water supply to these stations.
However, pursuant to an agreement reached in 1985, the Navajo Tribe will provide
sufficient water to Four Corners from its own allocation to offset any portion
of the water rights affected by this proceeding.
TAX ASSESSMENTS
See Tax Assessments in Note 7 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 The Wall Street Journal. No dividends were paid on Common Stock during such
periods.
Market Price per
Quarter Share of Common Stock
High Low
1994
First $4.13 $3.38
Second 3.88 2.88
Third 3.75 2.88
Fourth 3.88 3.00
1993
First $3.75 $1.88
Second 4.50 2.75
Third 4.63 3.63
Fourth 4.38 3.25
The closing price of the Common Stock on March 6, 1995 was $3.375.
The Common Stock is traded on the New York Stock Exchange and the Pacific
Stock Exchange. At March 6, 1995, there were 39,199 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
1994 1993 1992 1991 1990
(In thousands - except per share data and ratios)
Operating Revenues (A) $691,473 $624,139 $590,093 $554,995 $494,540
Income (Loss) from:
Continuing Operations 20,740 (21,816) (79,022) (421,493) (269,643)
Discontinued Operations - - - - (12,659)
Provision for Loss on Disposal of
Discontinued Operations - (4,000) (44,047) (36,000) (104,727)
Net Income (Loss) 20,740 (25,816) (123,069) (457,493) (387,029)
Net Income (Loss) for Common Stock $20,740 $(25,816) $(123,069) $(465,339) $(397,226)
Income (Loss) per Average Share of
Common Stock from:
Continuing Operations $0.13 $(0.14) $(2.48) $(16.70) $(10.92)
Discontinued Operations - - - - (0.49)
Provision for Loss on Disposal of
Discontinued Operations - (0.02) (1.38) (1.40) (4.09)
Total Net Income (Loss) per Average
Share of Common Stock $0.13 $(0.16) $(3.86) $(18.10) $(15.50)
Shares of Common Stock Outstanding
Average 160,724 160,544 31,872 25,716 25,633
End of Year 160,724 160,724 160,430 25,716 25,716
Rate of Return on Average Common Equity N/M N/M N/M N/M (79.26)%
Total Utility Plant-Net $2,007,422 $2,029,764 $2,052,695 $1,351,729 $1,599,707
Total Investments 12,992 62,850 98,126 203,712 229,328
Total Assets 2,701,936 2,714,096 2,656,089 2,004,336 2,214,497
Long-Term Debt 1,381,935 1,416,352 1,466,555 500,060 500,915
Capital Lease Obligations 922,735 927,201 931,163 5,836 6,646
Total Preferred Stock - - - 82,793 82,793
Total Common Equity (42,233) (62,973) (38,209) (191,903) 265,590
Total Capitalization 2,262,437 2,280,580 2,359,509 396,786 855,944
Defaulted Long-Term Debt - Due on Demand - - - 760,966 661,909
Defaulted Short-Term Debt - Due on Demand - - - 219,800 219,800
Regulatory Liabilities 41,214 54,924 53,910 226,645 249,610
Reserve for Litigation and Contract Disputes - - 27,500 27,219 17,219
Total Liabilities and Stockholders' Equity $2,701,936 $2,714,096 $2,656,089 $2,004,336 $2,214,497
Construction Expenditures
(including AFDC) $64,479 $48,375 $30,207 $48,728 $66,147
Cash Generated as a Percent of
Construction Expenditures
Internally Generated (B) 222.7% 184.7% 293.4%(C) 232.6%(C) (110.8)%
Internally Generated (B), Including
Drawdowns of Funds Held in Trust 222.7% 226.0% 348.8%(C) 232.6%(C) (59.0)%
Note: Total investments, assets and liabilities and stockholders' equity have
been restated to reflect the adoption of discontinued operations. Also, see Item 7.,
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
(A) Due to the adoption of FERC Order No. 529 interchange sales of electricity have
been reclassified to Sales to Other Utilities for all periods. Revenue related
taxes were removed from Operating Revenues for all periods.
(B) Cash generated is cash provided from operations less cash dividends.
(C) 1992 and 1991 ratios include cash conserved under the Payment Moratorium.
N/M - Not meaningful.
ITEM 7. - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following contains information regarding the Company's continuing and
discontinued operations during 1994 compared with 1993 and 1993 compared with
1992 and changes in liquidity and capital resources of the Company during 1994.
Also, management's expectations of identifiable material trends are discussed
herein.
OVERVIEW
In December 1992, the Company consummated a comprehensive Financial
Restructuring of obligations to certain creditors and reclassified its preferred
stock into common stock. The Financial Restructuring was concluded following
nearly two years of negotiations with various creditors including, but not
limited to, bank lenders and lease participants. The Company initiated the
Financial Restructuring because it projected that it might have insufficient
liquidity to meet its cash obligations by the end of the first quarter of 1991.
A payment moratorium on certain of the Company's debt, lease, coal and rail
obligations during part of the period of negotiations provided cash flow
sufficient to meet the Company's other obligations.
The Company believes that the Financial Restructuring provides the Company
the opportunity to return gradually to long-term financial viability. However,
the Financial Restructuring itself is not sufficient to assure the Company's
long-term financial viability.
The Company's capital structure remains highly leveraged and the Company's
financial prospects and cash flows remain subject to significant economic,
regulatory and other uncertainties, some which are beyond the Company's control.
These uncertainties include the degree of utilization of capacity through either
retail electric service or wholesale sales and the extent to which the Company
can alter operations and reduce costs in response to unanticipated economic
downturns or industry changes due to continued high financial and operating
leverage. The Company's ability to recover the costs of serving retail
customers is dependent upon pricing of the Company's services, which requires
ACC approval, and the level of sales to such customers. The Company anticipates
continued growth in sales over the next five years primarily as a result of
anticipated population and economic growth in the Tucson area. However, a
number of factors such as changes in economic conditions and the increasingly
competitive electric markets, could affect the Company's levels of sales.
Increased revenues, including increases for the recovery of plant and
operating costs associated with the remaining 37.5% of Springerville Unit 2,
which is not currently included in rate base, may be required in order for the
Company to maintain its existing level of liquidity over the longer term as
obligations become due. See Item 1., Business, Rates and Regulation, 1994 Rate
Order. Also, see Notes 2 and 7 of Notes to Consolidated Financial Statements,
1994 Rate Order and Commitments and Contingencies, respectively. The level of
cash flow from wholesale sales is affected generally by factors affecting the
market for such sales, including the availability of capacity and energy in the
western United States with pricing and procurement processes influenced by the
ongoing review of bulk power markets by FERC and the various state public
utility commissions. In addition, because the Company has a significant amount
of variable rate debt, the Company's future cash flows are also affected by the
level of interest rates. See Liquidity and Capital Resources, Cash Flows
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. The
Company has approximately $1.1 billion of long-term debt maturing, including
approximately $774 million in reimbursement agreements relating to letters of
credit which expire, during the 1997-2001 period. See Consolidated Statements
of Capitalization and Note 6 of Notes to Consolidated Financial Statements. The
Company intends to pay or refinance maturing bonds and bank loans and to replace
or extend such reimbursement agreements. There can be no assurance, however,
that the Company will be able to pay such debt or replace or extend such
reimbursement agreements.
In addition, the Company's ability to raise capital (through either public
or private financings) is limited. The Company's ability to obtain debt
financing will be limited by reason of limited free cash flow available to meet
additional interest expense and due to the restrictive covenants contained in
its obligations to creditors. Further, if the Company is required to refinance
its debt obligations in order to repay them when due, such refinancing may be
made on terms which are adverse to the Company. Access to equity capital may be
limited because of the Company's likely limited future profitability and its
inability to pay dividends for the foreseeable future. See Dividends below.
During the next twelve months, the Company does not expect any need to
obtain new debt financing to fund continuing operating activities and
construction expenditures. The Company instead will rely on internal cash
flows, existing cash balances and, if necessary, borrowings under the Renewable
Term Loan and/or a revolving credit line provided under the MRA. The Company's
cash balance, excluding the cash of the investment subsidiaries, but including
cash equivalents, at December 31, 1994, was approximately $233 million. Cash
balances are invested in investment grade, money-market securities with an
emphasis on preserving the principal amount invested.
In 1993 and 1992, the Company's results from continuing operations were
affected by certain unusual and infrequent adjustments and accruals. The table
below shows the Company's income or losses from continuing operations and
income/loss from continuing operations per average share of Common Stock had
such unusual and infrequent adjustments and accruals not been recorded.
December 31,
1994 1993 1992
- Thousands of Dollars -
Income (Loss) From Continuing Operations $20,740 $(21,816) $(79,022)
------- -------- --------
Regulatory Disallowances and Adjustments-Net - 13,177 -
Financial Restructuring Costs - 1,498 29,511
Loss on Financial Restructuring - - 26,669
SCECorp/SCE Litigation Settlement - - (40,000)
------- -------- --------
Total Adjustments to Income (Loss)
From Continuing Operations - 14,675 16,180
------- -------- --------
Adjusted Income (Loss) From Continuing
Operations $20,740 $ (7,141) $(62,842)
======= ======== ========
Adjusted Income (Loss) From Continuing
Operations Per Average Share
of Common Stock $0.13 $(0.04) $(1.97)
===== ====== ======
PROPOSED HOLDING COMPANY
The Company intends to establish in early 1996 a new corporate structure in
which the Company will be a subsidiary of a new holding company, UniSource
Energy Corporation (UniSource). The Company proposes to establish a holding
company structure because the Company believes that it is in the best interests
of its shareholders for the Company to participate in various segments of the
evolving and expanding electric energy business. The Company believes that such
participation would be enhanced by the holding company structure, a commonly
used structure in the electric and other industries, to conduct different lines
of business.
Approval of a holding company structure will require the affirmative vote
of holders of shares of common stock representing not less than a majority of
all votes entitled to be cast by all holders of shares of common stock. In
addition to shareholder approval, consummation of the holding company plan is
predicated upon receiving approval from the ACC and FERC. The Company will also
seek a "no action" position from the Staff of the SEC under the Public Utility
Holding Company Act of 1935, as amended, or, in the alternative, will seek
approval of the SEC under such Act. The Company is in the process of obtaining
such approvals.
If approved by the requisite vote of the Company shareholders and if
required regulatory approvals are satisfactorily obtained, the outstanding
shares of the Company common stock would be exchanged, on a share-for-share
basis, for shares of UniSource. As a result, the holders of the Company common
stock will become the owners of UniSource common stock, and UniSource will
become the owner of the Company common stock.
During the second quarter of 1995, the Company intends to provide a proxy
statement-prospectus to all shareholders which will set forth in detail the
holding company structure, the plan of the share exchange and a shareholder
meeting date. Accompanying the proxy statement-prospectus will be a form of
proxy solicited on behalf of the Board of Directors of the Company.
RESULTS OF OPERATIONS
RESULTS OF UTILITY OPERATIONS
SALES AND REVENUES
Revenues from sales to retail customers increased 9.0% in 1994 compared
with 1993 and 2.1% in 1993 compared with 1992. The table below identifies the
components of the increases in 1994 and 1993.
1994 1993
- Millions of Dollars -
Price Change $17 $(3)
Consumption Change 15 3
Customer Growth 15 12
--- ---
Increase in Retail Revenues $47 $12
=== ===
The revenue increase in 1994 resulted from greater kWh sales due to
continued growth in the average number of retail customers, increase in usage
due to warmer than normal temperatures, and increased prices as a result of the
1994 Rate Order. There were 289,697 electric customers on average during 1994,
an increase of 2.9% over 1993. Based on billed cooling degree days, a commonly
used measure in the electric industry, that are calculated by subtracting 75
degrees from the daily average of the high and low temperatures, the Tucson area
registered a 26% increase in such cooling degree days in 1994 over 1993, and a
33% increase in such cooling degree days in 1994 over the 10 year average from
1984 to 1993. The 1993 revenue decrease due to change in price, shown in the
table above, resulted from lower rates charged under a renegotiated contract
with one of the Company's mining customers.
Amortization of the MSR Option Gain Regulatory Liability increased in 1994
compared with 1993 as a result of the 1991 Rate Order which set the non-cash
operating revenue for the amortization of the regulatory liability for the MSR
option gain at $6 million for 1992 and 1993, $20 million in 1994, 1995 and 1996,
and $8 million in 1997 at which point the MSR Option Gain will be fully
amortized. See Note 1 of Notes to Consolidated Financial Statements, Nature of
Operations and Summary of Significant Accounting Policies.
In 1994, revenues from Other Utilities increased 7.2% over 1993 as a result
of a 13% increase in revenues from firm sales of energy, offset by a 4% decrease
in revenues from economy sales. Revenues from Other Utilities increased 33% in
1993 compared with 1992 primarily due to a 56% increase in revenues from firm
sales of energy and a 12% increase in the average revenue per kWh sold on a non-
firm basis. In 1994, firm sales accounted for 37% of sales to Other Utilities
and 58% of revenues from Other Utilities. In 1993, firm sales accounted for 33%
of sales to Other Utilities and 56% of revenues from Other Utilities. The
Company's ability to market available capacity and energy in the future, at
levels comparable with 1994, may be limited due to lower prevailing prices and
other market conditions.
OPERATING EXPENSES
As a result of the Financial Restructuring, the Company's Irvington Lease,
Valencia Leases and the Springerville Common Facilities Leases were reclassified
from operating leases to capital lease obligations. The effect of this
reclassification significantly increased recorded assets and liabilities
relating to these leases and resulted in the reallocations of the lease expenses
relating to the Irvington and Springerville Common Facilities Leases from Other
Operations expense to Capital Lease Expense. The Valencia Leases expense
continues to be expensed as a component of Fuel expense. In addition, as part
of the Financial Restructuring, the Company became the direct lessee under the
Springerville Unit 1 Leases which is also stated as a capital lease obligation.
The assumption of the Springerville Unit 1 Leases and the termination of the
Restated Century Purchase Contract increased assets and liabilities relating to
capital leases and, for periods subsequent to the Financial Restructuring,
result in the recognition of certain expenses, which were previously included in
Purchased Power-Demand expense, as Capital Lease Expense and various other
operating expenses.
Fuel expenses increased 6.4% in 1994 over 1993 as a result of the fourth
quarter 1994 reallocation of a reserve for sales tax disputes from Taxes Other
than Income Taxes. See Note 7 of Notes to Consolidated Financial Statements,
Commitments and Contingencies, Tax Assessments. Aggregate fuel expense
increased 48.6% in 1993 compared with 1992 due to greater generation to
accommodate increased sales to Other Utilities and Retail Customers and fuel
expenses from Springerville Unit 1, which were previously accounted for as
Purchased Power-Energy. Average cost per kWh of fuel and its transportation
only were 1.79 cents in 1994 and 1.76 cents in 1993. Following the Financial
Restructuring, the Company no longer makes purchases under the Restated Century
Purchase Contract, which was terminated, but purchases fuel directly from
Valencia. Increased generation requirements were met primarily through
increased generation at Springerville Unit 1.
Purchased Power-Energy increased in 1994 over 1993 as a result of greater
kWh requirements to provide for increased sales. Purchased Power-Energy expense
decreased in 1993 compared with 1992 as a result of the termination of the
Restated Century Purchase Contract and the change in the status of Springerville
Unit 1 described above.
Purchased Power-Demand expense decreased in 1993 compared with 1992 due to
the termination of the Restated Century Purchase Contract.
The increase in Capital Lease Expense in 1993 compared with 1992 reflects
the reclassification of the Irvington Lease and Springerville Common Facilities
Leases to capital lease obligations and the assumption of the Springerville Unit
1 Leases.
Amortization of Springerville Unit 1 Allowance, a non-cash item, decreased
in 1994 compared with 1993 due to lower projected operation and maintenance
expenses included in the calculation of the Springerville Unit 1 Allowance. The
Springerville Unit 1 Allowance was originally calculated by projecting the
yearly costs associated with Springerville Unit 1 over the remaining life of the
Springerville Unit 1 Leases and taking the present value of the difference
between such costs and the ACC allowed level of recovery. Such costs are then
recognized in each period along with a corresponding interest accrual and
amortization of the allowance as a credit to operating expenses. The interest
accrual is included in the Consolidated Statements of Income (Loss) as
Regulatory Interest. Amortization of Springerville Unit 1 Allowance, a non-
cash credit originally resulting from the write-off of the portion of
Springerville Unit 1 demand charges under the Restated Century Purchase Contract
in excess of the $15 per kW per month allowed by the ACC, increased in 1993
compared with 1992 due to increased Springerville Unit 1 Leases expense. As a
result of the assumption of the Springerville Unit 1 Leases, the Company's
levelized amortization of lease expenses is based on rents over the full primary
term of the leases rather than through 2001, the date utilized when the rents
were paid by Century and passed through under the Restated Century Purchase
Contract. See Note 1 of Notes to Consolidated Financial Statements, Nature of
Operations and Summary of Significant Accounting Policies.
Other Operations expense increased in 1994 compared with 1993 as a result
of the accrual of increased employee expenses related to compensation and
pension benefits. Other Operations expense decreased in 1993 compared with 1992
primarily due to the reclassification of the Irvington Lease and the
Springerville Common Facilities Leases expenses to Capital Lease Expense.
Maintenance and Repairs expense was higher in 1993 compared with 1992
because of the change in the status of Springerville Unit 1 described above.
Depreciation and Amortization increased in 1994 over 1993 as a result of
the amortization of 62.5% of the Springerville Unit 2 rate synchronization
deferral costs over 3 years (beginning in January 1994) pursuant to the 1994
Rate Order. Depreciation expense increased in 1993 compared with 1992 primarily
reflecting various additions to plant and equipment and a one-time adjustment
decreasing depreciation expense mandated by FERC which was recorded in the
second quarter of 1992.
Taxes Other than Income Taxes decreased in 1994 compared with 1993 as a
result of the fourth quarter 1994 reallocation of a reserve for sales tax
disputes to Fuel. See Note 7 of Notes to Consolidated Financial Statements,
Commitments and Contingencies, Tax Assessments. The increase in Taxes Other
than Income Taxes in 1993 compared with 1992 reflects that property tax expense
related to the Company's assumption of the Springerville Unit 1 Leases, which
expense previously had been part of demand charges paid under the Restated
Century Purchase Contract and included in Purchased Power-Demand is currently
recorded as Taxes Other than Income Taxes.
Financial Restructuring costs decreased in 1993 compared with 1992 as a
result of the completion of the Financial Restructuring in December 1992.
OTHER INCOME (DEDUCTIONS)
Regulatory Disallowances and Adjustments in 1993 reflect primarily the
write-off of Springerville Unit 2 deferred expenses mandated by the 1994 Rate
Order.
Deferred Springerville Unit 2 Carrying Costs decreased in 1994 compared
with 1993 as a result of the incorporation into rate base of 62.5% of
Springerville Unit 2.
The Loss on Financial Restructuring in 1992 was based on, among other
things, the excess of the fair value of the Common Stock and Warrants issued, at
values of $2.33 per share and $0.82 per warrant, respectively, compared to the
amount of plant, materials and supplies inventories received by the Company from
Century and accrued rent under the Springerville Unit 1 Leases, reflected on the
Company's financial statements as of December 15, 1992 as demand charges payable
to Century. In addition, the Company reversed a reserve of approximately $9
million due to the dismissal of related regulatory matters as a part of the
Financial Restructuring. The restructuring of Bank obligations gave rise to a
deferred gain of $21 million, which is being amortized as a reduction of
interest expense over an eight-year period. See Note 3 of Notes to Consolidated
Financial Statements, 1992 Consummation of the Financial Restructuring.
Litigation Settlement income in 1993 decreased compared with 1992 due to
the settlement of litigation against SCE in the third quarter of 1992. See Item
1., Business, SCE/TEP Power Exchange Agreement.
Other Income increased in 1994 compared with 1993 due to greater interest
earned on cash and cash equivalents. Other Income decreased in 1993 compared
with 1992 due to the collection in 1992 of approximately $8 million in interest
income on a Federal income tax refund.
INTEREST EXPENSE
Interest expense on Long-Term Debt-Net increased in 1994 compared with 1993
as a result of slightly higher interest rates. Interest expense on Long-Term
Debt-Net decreased in 1993 compared with 1992 due to the prepayment of $68
million of long-term debt combined with significantly lower interest rates on
the Company's obligations in the first quarter of 1993 compared with interest
rates during the same period of 1992. The lower rates reflect primarily the
elimination of default rates on such obligations in 1993 as a result of the
Financial Restructuring (discussed below), and in part, lower market rates. The
effect of lower rates was partly offset by the reclassification of previously
outstanding short-term debt into the Term Loan which is classified as Long-Term
Debt.
In the first quarter of 1992, the Payment Moratorium was in effect on most
obligations of the Company. Therefore, the Company accrued interest on such
obligations at default rates, which were substantially higher than market rates.
Interest at default rates was accrued on approximately $900 million of bank
credit obligations including approximately $650 million of reimbursement
obligations related to LOCs that provide credit support for variable-rate tax-
exempt bond issues. The irrevocable LOCs were fully drawn through the first
quarter of 1992. In March 1992, such issues were remarketed and the proceeds
were used to pay reimbursement obligations for the drawn LOCs and interest was
no longer accrued at default rates.
There was no interest expense on Short-Term Debt in 1994 and 1993 as a
result of the reclassification of previously outstanding short-term debt into
the Term Loan which is classified as Long-Term Debt.
Interest Expense - Other decreased in 1994 compared with 1993 due to an
accrual in 1993 for interest on contested tax payments and litigation
settlement. Interest Expense - Other increased in 1993 compared with 1992
primarily due to the reinstatement of LOC fees and remarketing fees related to
the remarketing of the tax exempt bonds supported by the LOCs. LOC fees and
remarketing fees were not paid for part of 1992 because the LOCs were drawn and
the IDBs were held by the banks.
RESULTS OF DISCONTINUED OPERATIONS
See Note 5 of Notes to Consolidated Financial Statements.
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, 1994 and 1993 contain certain line items solely as a result of the
application of FAS 71. In addition, a number of line items in the Company's
Consolidated Statements of Income (Loss) for the years ended December 31, 1994,
1993 and 1992 also reflect the application of FAS 71. See Note 1 of Notes to
Consolidated Financial Statements, Nature of Operations and Summary of
Significant Accounting Policies, Accounting for the Effects of Regulation.
If, at some point in the future, the Company determines that all or a
portion of the Company's regulated operations no longer meet the criteria for
continued application of FAS 71, the Company would be required to adopt the
provisions of FAS 101 for that portion of the operations for which FAS 71 no
longer applied. Adoption of FAS 101 would require the Company to write off its
regulatory assets and liabilities as of the date of adoption of FAS 101 and
would preclude the future deferral in the balance sheet of costs not recovered
through rates at the time such costs were incurred, even if such costs were
expected to be recovered in the future. Based on the balances of the Company's
regulatory assets and liabilities as of December 31, 1994, the Company estimates
that future adoption of FAS 101 for all of the Company's regulated operations
would result in an extraordinary loss of $142 million, which includes a
reduction for the related deferred income taxes. The Company's cash flows would
not be affected by the adoption of FAS 101.
DIVIDENDS
The Company does not expect to be able to pay cash dividends on its Common
Stock for the foreseeable future. The Company is currently precluded by State
statute and restrictive covenants in certain debt agreements from declaring or
paying dividends. No dividends on Common Stock have been declared or paid since
1989.
Under current applicable provisions of the Arizona General Corporation Law,
the Company is permitted to declare and pay dividends on its shares in cash,
property, or its own shares, only out of unreserved and unrestricted earned
surplus or out of the unreserved and unrestricted net earnings of the current
fiscal year and the immediately preceding fiscal year taken as a single period,
except that the Company may not declare or pay dividends when the Company is
insolvent (unable to pay its debts as they become due in the ordinary course of
business) or when the payment of the dividend would render the Company
insolvent, or when the declaration or payment of the dividend would be contrary
to any restriction contained in the Articles.
At December 31, 1994, the Company had no earned surplus (its accumulated
deficit on that date was $681 million), and the Company had no net earnings for
the two fiscal years then ended taken together. Also, the Company expects to
have no earned surplus and limited net earnings and cash flow for several years.
Under applicable provisions of amendments to the Arizona General
Corporation Law, which will be effective in 1996, a company will be 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.
As of December 31, 1994, the Company's common stock deficit was $42 million.
Although the Company expects to meet the requirements under the amended
corporation law for making distributions to shareholders within several years,
restrictive covenants in certain existing debt agreements may continue to
preclude the Company from declaring or paying dividends.
The General First Mortgage contains covenants, applicable so long as
certain series of First Mortgage Bonds (aggregating $194 million in principal
amount) are outstanding, which restrict the payment of dividends on Common Stock
if certain cash flow coverage and retained earnings tests are not met. The
retained earnings test will prevent the Company from paying dividends on its
Common Stock until such time as the Company has positive retained earnings
rather than an accumulated deficit. 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 includes a similar
dividend restriction based on retained earnings.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS
The Company's cash and cash equivalents, including such amounts held by the
Company's investment subsidiaries, increased $86 million or 53%, over the 1993
year end balance of $162 million, to the 1994 year end balance of $248 million.
Receipts from retail customers increased $55 million over 1993 reflecting
the sales and customers growth discussed above. Cash expenditures for
continuing operating activities increased, in aggregate, $10 million, due
primarily to increased sales levels. As a result, Net Cash Flow - Continuing
Operating Activities increased 61% to $144 million for 1994.
Construction expenditures, primarily for expansion and reinforcement of the
Company's transmission and distribution systems, increased $14 million over 1993
levels. In addition, the Company continued reducing its debt and lease
obligations by retiring $37 million of such obligations in 1994.
During 1995, the Company expects to generate sufficient internal cash flows
to fund its continuing operating activities and construction expenditures
provided short-term interest rates remain near current levels and revenues from
wholesale sales are similar to last year. An increase in short-term interest
rates of 100 basis points (1%) would result in an approximate $10 million
increase in interest expense. If 1994 cash flows fall short of expectations,
the Company would expect to use its cash balances or its Renewable Term Loan
and/or a revolving credit line provided under the MRA to meet operating and
capital requirements.
The Company's cash balance including cash equivalents at March 7, 1995 was
approximately $185 million (including the cash and cash equivalents of the
investment subsidiaries). Cash balances are invested in investment grade,
money-market securities with an emphasis on preserving the principal amounts
invested.
FINANCING DEVELOPMENTS
On December 30, 1994, the Company purchased and cancelled $17.25 million
principal amount of its First Mortgage Bonds 12.22% Series due June 1, 2000.
The payment was made to fulfill the Company's requirement under the MRA to
utilize Extraordinary Cash to reduce outstanding indebtedness. The
Extraordinary Cash was generated from cash dividends paid to the Company by the
investment subsidiaries. See Restrictive Covenants, Prepayments.
On March 7, 1995, the Company and its banks completed the Sixth Amendment
to the MRA which eased certain debt prepayment restrictions and modified the
Term Loan to allow reborrowing of amounts which will have been previously
prepaid (Renewable Term Loan). The amendment will allow the Company to better
manage its cash position and reduce capital costs while maintaining liquidity.
Prior to the amendment the Company was not permitted to prepay non-MRA debt
except to the extent that Excess Cash and Extraordinary Cash were generated, see
Restrictive Covenants, Prepayments below for the description of such terms. The
amendment, now in effect, renders the Excess Cash and Extraordinary Cash
provisions inapplicable and allows the Company to optionally prepay outstanding
debt of the Company provided certain conditions are met. Such conditions
include that $1 of principal outstanding under the Renewable Term Loan is
permanently prepaid, and the commitment therefore terminated, for every $2 used
to permanently prepay other debt such as First Mortgage Bonds. The Renewable
Term Loan allows the Company to reborrow amounts paid down to the extent of the
remaining outstanding loan commitment. The commitment fee on the Renewable Term
Loan will be 0.5% of the unused portion of such commitment.
As a condition to the amendment becoming effective, the Company permanently
prepaid $19.3 million of the Term Loan reducing the outstanding balance from
$193.4 million to approximately $174 million. Thus, the initial commitment and
outstanding balance of the Renewable Term Loan was approximately $174 million.
SHORT-TERM CREDIT FACILITIES
REVOLVING CREDIT
The Banks provided as part of the MRA a $50 million Revolving Credit for
working capital purposes. The Revolving Credit has a termination and maturity
date of December 31, 1999, and bears interest at a variable rate based upon, at
the option of the Company, either (i) prime rate or (ii) an adjusted eurodollar
rate plus a percentage ranging from 0.75% during 1994, gradually increasing to
2% by 1998 and thereafter. The Company is required to repay loans under the
Revolving Credit in full for at least 30 consecutive days in each twelve-month
period prior to November 30 of each year. The annual commitment fee for the
Revolving Credit equals 0.5% of the unused portion. The Revolving Credit is
secured and contains restrictive covenants. See Restrictive Covenants below.
As of December 31, 1994 the Company had not borrowed any funds under the
$50 million Revolving Credit.
OTHER
The balances of $12 million, $12 million and $18 million of short-term debt
of the investment subsidiaries as of December 31, 1994, 1993 and 1992,
respectively, were associated with wholly-owned subsidiaries indirectly owned by
SRI and, therefore, such debt is reflected in net assets of discontinued
operations. Such debt is without recourse to SRI or the Company. Approximately
$220 million of utility and utility-related short-term debt was restructured
upon the Closing and reclassified as long-term debt.
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, 1994, the Company had the ability to
issue approximately $152 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 $74 million of new First Mortgage Bonds on the
basis of retired bonds. However, issuance of such amounts may be limited by MRA
covenants. See Additional Restrictive Covenants below.
See Dividends above for 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, 1994, $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, 1994, the amount of net additions and retired bonds
would permit (and the net earnings test would not prohibit) the issuance of $455
million aggregate principal amount of new Second Mortgage Bonds (at an assumed
interest rate of 12% per annum). The issuance of such amount of Second Mortgage
Bonds assumes that the $226 million of First Mortgage Bonds available to be
issued at December 31, 1994 would be issued first at a rate of 11%. However,
issuance of such amounts may be limited by MRA covenants. See Additional
Restrictive Covenants below.
PREPAYMENTS
Prior to the Sixth Amendment to the MRA becoming effective on March 7,
1995, see Financing Developments above, certain prepayments of indebtedness were
required. The required prepayment equaled the Company's adjusted operating
income, as defined in the MRA, less certain capital expenditures and charges,
for the preceding twelve-month period as of June 30 of each year; provided,
however, that the prepayment amount (Excess Cash) was limited to the excess (if
any) over $25 million of (i) the Company's cash balance, including cash
equivalents, as of each June 30 plus (ii) the cumulative amount of all
dividends, if any, paid on Common Stock from December 15, 1992 to such June 30.
The Company was required to apply the Excess Cash to the prepayment of
indebtedness. For the period ended June 30, 1994, the Company had $31 million
which constituted Excess Cash. The Company had no such Excess Cash for the
period ended June 30, 1993.
The Company was also required to apply other funds as defined in the MRA
(Extraordinary Cash) to the prepayment of its indebtedness. Extraordinary Cash
included the net proceeds from the issuance of equity and certain debt
securities of the Company or any subsidiary; provided, however, that upon
prepayment of the Term Loan in a principal amount of $50 million, Extraordinary
Cash did not include proceeds from the issuance of equity securities, and
included only 50% of the proceeds from the issuance of debt securities.
Extraordinary Cash also included all cash dividends received by the Company from
its investment subsidiaries, TRI and SRI, or any subsidiary thereof. In 1993
and 1994, the Company received cash dividends of $6 million and $50 million,
respectively, from TRI which constituted Extraordinary Cash.
In April 1993, the MRA lenders waived, to the extent of $68 million, as
consideration for certain prepayments, the requirement that the Company use
Excess Cash and Extraordinary Cash to prepay debt as described above.
Therefore, no mandatory prepayments were made during 1993 as a result of such
prepayment provisions and although $81 million of excess cash and extraordinary
cash was generated in 1994 ($87 million for 1993 and 1994 combined), the Company
was required to prepay only $19 million of indebtedness in 1994. See Financing
Developments above.
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 at least 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 1.2 to 1 in 1994 and gradually
increasing to 2 to 1 in 2000 continuing through the year 2003. For the year
ended December 31, 1994, the Company's MRA interest coverage ratio was 2.98 to
1. With respect to dividends, the MRA incorporates, until the Renewable Term
Loan and the Revolving Credit are paid in full and commitments thereunder
terminate, a restrictive covenant similar to that currently in the General First
Mortgage which limits the Company's ability to pay dividends on Common Stock
until it has positive retained earnings (through future earnings or otherwise)
rather than an accumulated deficit (such accumulated deficit was $681 million at
December 31, 1994). The Company does not anticipate being able to satisfy the
test of this and other dividend restrictions (see Dividends above) and
therefore, does not anticipate being permitted to pay cash dividends on its
Common Stock for the foreseeable future.
CONSTRUCTION EXPENDITURES
Estimated construction expenditures of the Company, including AFDC, for the
five years 1995 through 1999, respectively, are $74 million, $67 million, $81
million, $85 million and $62 million. These amounts include the following: $190
million for transmission and distribution facilities in the Tucson area; $44
million for expenditures which are necessary to upgrade pollution control
facilities at Navajo (see Item 1., Business, Environmental Matters, Navajo
Generating Station); and $135 million for modifications to existing production
facilities. These estimated construction expenditures include costs to comply
with current federal and state environmental regulations. All of these
estimates are subject to continuing review and adjustment. Actual construction
expenditures may vary from these estimates due to factors such as changes in
business conditions, construction schedules and environmental requirements. Due
to the limitation on the Company's ability to issue debt or equity capital and
to apply such proceeds, if any, to capital requirements, the Company must
finance these construction expenditures with internally generated funds and/or
reductions of its cash and short-term investments. In the event that funds from
such sources are unavailable, the Company would be unable to expend the amounts
shown above.
Also, see Note 6 of Notes to Consolidated Financial Statements, Long and
Short-Term Debt and Capital Lease Obligations.
ITEM 8. - CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See Item 14, page 57, for a list of the Consolidated Financial Statements
which are included in the following pages. See Note 11 of Notes to Consolidated
Financial Statements.
INDEPENDENT AUDITORS' REPORT
TUCSON ELECTRIC POWER COMPANY
We have audited the accompanying consolidated balance sheets and statements of
capitalization of Tucson Electric Power Company and subsidiaries (the Company)
as of December 31, 1994 and 1993, and the related consolidated statements of
income (loss), cash flows, and changes in stockholders' equity (deficit) for
each of the three years in the period ended December 31, 1994. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Company at December 31, 1994
and 1993, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 1994 in conformity with
generally accepted accounting principles.
As discussed in Note 2 to the financial statements, the timing of the recovery
of the costs associated with 37.5% of Springerville Unit 2 cannot presently be
determined because the Company has not yet received rate relief for such costs.
DELOITTE & TOUCHE LLP
Tucson, Arizona
January 31, 1995
(March 7, 1995 as to Note 6)
CONSOLIDATED STATEMENTS OF INCOME (LOSS) For the Years Ended December 31,
1994 1993 1992
- Thousands of Dollars -
Operating Revenues
Retail Customers $ 571,433 $ 524,813 $ 514,014
Amortization of MSR Option Gain
Regulatory Liability 20,053 6,053 6,053
Other Utilities 99,987 93,273 70,026
---------- ---------- ----------
Total Operating Revenues 691,473 624,139 590,093
---------- ---------- ----------
Operating Expenses
Fuel 209,889 197,323 132,775
Purchased Power - Energy 13,878 9,032 62,726
Purchased Power - Demand - - 88,288
Deferred Fuel and Purchased Power 7,359 10,716 7,030
Capital Lease Expense 93,056 92,844 19,854
Amortization of Springerville
Unit 1 Allowance (26,204) (33,398) (31,228)
Other Operations 100,948 90,880 95,218
Maintenance and Repairs 42,122 42,300 34,386
Depreciation and Amortization 89,905 74,184 69,445
Taxes Other than Income Taxes 46,118 54,814 48,632
Financial Restructuring Costs - 1,498 29,511
---------- ---------- ----------
Total Operating Expenses 577,071 540,193 556,637
---------- ---------- ----------
Operating Income 114,402 83,946 33,456
---------- ---------- ----------
Other Income (Deductions)
Regulatory Disallowances and Adjustments - (13,777) -
Deferred Springerville Unit 2 Carrying
Costs 1,133 5,359 4,143
Loss on Financial Restructuring - - (26,669)
Litigation Settlement - - 27,576
Interest Income 7,556 3,909 4,568
Income Taxes 4,820 5,186 5,654
Other Income 489 805 7,744
---------- ---------- ----------
Total Other Income (Deductions) 13,998 1,482 23,016
---------- ---------- ----------
Interest Expense
Long-Term Debt - Net 69,353 68,053 72,687
Regulatory Interest 32,280 31,303 29,781
Short-Term Debt - - 26,311
Other 7,118 8,604 7,770
Allowance for Borrowed Funds Used
During Construction (1,091) (716) (1,055)
---------- ---------- ----------
Total Interest Expense 107,660 107,244 135,494
---------- ---------- ----------
(continued on next page)
CONSOLIDATED STATEMENTS OF INCOME (LOSS) (Continued)
For the Years Ended December 31,
1994 1993 1992
- Thousands of Dollars -
Income (Loss) from Continuing Operations 20,740 (21,816) (79,022)
Provision for Loss on Disposal of
Discontinued Operations - (4,000) (44,047)
---------- ---------- ----------
Net Income (Loss) $ 20,740 $ (25,816) $(123,069)
========== ========== ==========
Average Shares of
Common Stock Outstanding (000) 160,724 160,544 31,872
========== ========== ==========
Net Income (Loss) per Average Share
Continuing Operations $ 0.13 $ (0.14) $ (2.48)
Discontinued Operations - (0.02) (1.38)
---------- ---------- ----------
Total Net Income (Loss) per
Average Share $ 0.13 $ (0.16) $ (3.86)
========== ========== ==========
See Notes to Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
1994 1993
- Thousands of Dollars -
Utility Plant
Plant in Service $2,053,123 $2,004,112
Utility Plant Under Capital Leases 893,064 894,508
Construction Work in Progress 40,870 33,568
----------- -----------
Total Utility Plant 2,987,057 2,932,188
Less Accumulated Depreciation and Amortization (791,617) (727,101)
Less Accumulated Amortization of Capital Leases (25,595) (12,634)
Less Allowance for Springerville Unit 1 (162,423) (162,689)
----------- -----------
Total Utility Plant - Net 2,007,422 2,029,764
----------- -----------
Investments
Net Assets of Discontinued Operations 8,685 58,480
Other Investments 4,307 4,370
----------- -----------
Total Investments 12,992 62,850
----------- -----------
Current Assets
Cash and Cash Equivalents 233,300 139,817
Accounts Receivable 66,332 65,212
Materials and Fuel 36,109 36,312
Deferred Income Tax - Current 12,870 8,927
Other 10,719 10,538
----------- -----------
Total Current Assets 359,330 260,806
----------- -----------
Deferred Debits - Regulatory Assets
Income Taxes Recoverable Through Future Rates 143,372 149,508
Deferred Common Facility Costs 65,843 68,383
Deferred Springerville Unit 2 Costs 54,983 67,543
Deferred Lease Expense 25,228 32,602
Deferred Fuel and Purchased Power Expense 5,872 13,231
Other Deferred Regulatory Assets 9,362 8,165
Deferred Debits - Other 17,532 21,244
----------- -----------
Total Deferred Debits 322,192 360,676
----------- -----------
Total Assets $2,701,936 $2,714,096
=========== ===========
See Notes to Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND OTHER LIABILITIES
December 31,
1994 1993
- Thousands of Dollars -
Capitalization
Common Stock Equity (Deficit) $ (42,233) $ (62,973)
Capital Lease Obligations 922,735 927,201
Long-Term Debt 1,381,935 1,416,352
----------- -----------
Total Capitalization 2,262,437 2,280,580
----------- -----------
Current Liabilities
Current Maturities of Long-Term Debt 17,167 2,203
Accounts Payable 39,777 40,190
Interest Accrued 59,480 65,738
Taxes Accrued 29,215 20,269
Accrued Employee Expenses 15,247 4,222
Current Obligations Under Capital Leases 12,803 14,825
Other 6,624 6,389
----------- -----------
Total Current Liabilities 180,313 153,836
----------- -----------
Deferred Credits and Other Liabilities
MSR Option Gain Regulatory Liability 41,214 54,924
Accumulated Deferred Investment Tax Credits
Regulatory Liability 24,368 29,279
Accumulated Deferred Income Taxes 166,684 168,833
Other 26,920 26,644
----------- -----------
Total Deferred Credits and Other Liabilities 259,186 279,680
----------- -----------
Total Capitalization and Other Liabilities $2,701,936 $2,714,096
=========== ===========
See Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
1994 1993
COMMON STOCK EQUITY (DEFICIT) - Thousands of Dollars -
Common Stock--No Par Value 1994 1993
----------- -----------
Shares Authorized 200,000,000 200,000,000
Shares Outstanding 160,723,702 160,723,702 $ 645,479 $ 645,479
Capital Stock Expense (6,357) (6,357)
Accumulated Deficit (681,355) (702,095)
----------- -----------
Total Common Stock Equity (Deficit) (42,233) (62,973)
----------- -----------
PREFERRED STOCK, No Par Value,
1,000,000 Shares Authorized, None Outstanding - -
CAPITAL LEASE OBLIGATIONS
Springerville Unit 1 458,092 449,984
Springerville Common Facilities 139,076 144,114
Irvington Unit 4 143,407 143,909
Valencia Coal Handling Facilities 187,523 195,309
Other Leases 7,440 8,710
----------- -----------
Total Capital Lease Obligations 935,538 942,026
Less Current Maturities (12,803) (14,825)
----------- -----------
Total Long-Term Capital Lease Obligations 922,735 927,201
----------- -----------
LONG-TERM DEBT Interest
Issue Maturity Rate
- -----------------------------------------------------
First Mortgage Bonds
Corporate 1995 - 2009 4.55% to 12.22% 269,750 287,000
Industrial Development 2005 - 2025 6.10% to 8.25%
Revenue Bonds (IDBs) and variable* 232,200 232,200
Loan Agreements (IDBs) 2003 - 2022 6.25% and
variable* 703,600 704,555
Term Loan 1997 - 1999 variable* 193,400 193,400
Promissory Note 1992 - 1995 8.00% 152 1,400
----------- -----------
Total Stated Principal Amount 1,399,102 1,418,555
Less Current Maturities (17,167) (2,203)
----------- -----------
Total Long-Term Debt 1,381,935 1,416,352
----------- -----------
Total Capitalization $2,262,437 $2,280,580
=========== ===========
* Interest rates on variable rate tax-exempt (IDB) debt ranged from 1.50%
to 5.75% during 1994 and 1993, and the average interest rate on such debt
was 2.96% in 1994 and 2.65% in 1993. Interest rates on the Term Loan
ranged from 3.63% to 6.69% in 1994 and 1993, and the average interest
rate on such debt was 4.92% in 1994 and 4.03% in 1993.
See Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
1994 1993 1992
- Thousands of Dollars -
Cash Flows from Continuing Operating Activities
Cash Receipts from Retail Customers $611,917 $557,222 $546,801
Cash Receipts from Other Utilities 99,198 91,799 68,775
Purchased Power - Energy (15,829) (9,610) (7,896)
Purchased Power - Demand - (1,006) (34,114)
Fuel Costs Paid (171,301) (157,075) (139,146)
Wages Paid, Net of Amounts Capitalized (49,284) (44,394) (37,275)
Payment of Other Operations and
Maintenance Costs (78,808) (91,924) (110,993)
Capital Lease Interest Paid (82,511) (81,932) -
Interest Paid, Net of
Amounts Capitalized (72,556) (70,316) (91,531)
Taxes Paid, Net of Amounts Capitalized (104,498) (103,005) (92,673)
Litigation Settlements - Net - (5,000) 35,000
Lease Payments, Net of
Amounts Capitalized - - (61,328)
Interest Received 7,288 4,652 11,588
Federal Income Tax Refund Received - - 1,440
Other - (80) (18)
--------- --------- ---------
Net Cash Flows -
Continuing Operating Activities 143,616 89,331 88,630
--------- --------- ---------
Net Cash Flows - Discontinued Operations 42,685 5,677 41,878
--------- --------- ---------
Cash Flows from Capital Transactions
Construction Expenditures (62,599) (48,162) (34,512)
Other Investments 103 (286) 58
--------- --------- ---------
Net Cash Flows - Capital Transactions (62,496) (48,448) (34,454)
--------- --------- ---------
Cash Flows from Financing Activities
Proceeds from Long-Term Debt - 20,000 16,732
Payments to Retire Long-Term Debt (19,424) (72,187) (32,908)
Payments to Retire Capital Lease Obligations (17,747) (10,690) (320)
Other (478) 862 (306)
--------- --------- ---------
Net Cash Flows - Financing Activities (37,649) (62,015) (16,802)
--------- --------- ---------
Net Increase (Decrease) in
Cash and Cash Equivalents 86,156 (15,455) 79,252
Cash and Cash Equivalents, Beginning of Year * 161,996 177,451 98,199
--------- --------- ---------
Cash and Cash Equivalents, End of Year ** $248,152 $161,996 $177,451
========= ========= =========
* Beginning of year balance includes cash and cash equivalents from
discontinued operations of $22,179,000 for 1994, $22,502,000 for 1993 and
$11,856,000 for 1992.
** End of year balance includes cash and cash equivalents from discontinued
operations of $14,852,000 for 1994, $22,179,000 for 1993 and $22,502,000
for 1992.
See Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT)
Premium
on Capital Accumulated
Preferred Common Capital Stock Earnings
Stock Stock Stock Expense (Deficit)
----------------------------------------------
- Thousands of Dollars -
Balances at December 31, 1991 $82,793 $357,782 $7,007 $(3,482) $(553,210)
1992 Net Loss - - - - (123,069)
1992 Issuances: 134,713,860
Shares of Common Stock,
including the reclassification
of all Preferred Stock to
Common Stock. See Note 3. (82,793) 286,645 (7,007) (2,875) -
-------- -------- ------- -------- ----------
Balances at December 31, 1992 - 644,427 - (6,357) (676,279)
1993 Net Loss - - - - (25,816)
1993 Sale of Treasury Stock:
294,050 Shares of Common Stock - 1,052 - - -
-------- -------- ------- -------- ----------
Balances at December 31, 1993 - 645,479 - (6,357) (702,095)
1994 Net Income - - - - 20,740
-------- -------- ------- -------- ----------
Balances at December 31, 1994 $ - $645,479 $ - $(6,357) $(681,355)
======== ======== ======= ======== ==========
See Note 6. Long-Term Debt - Additional Restrictive Covenants for discussion
of restrictions on the Company's ability to pay dividends.
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ----------------------------------------------------------------------------
NATURE OF OPERATIONS
The Company is a public utility engaged in the business of generation,
transmission, distribution and sale of electricity. The Company's retail
service area encompasses 1,155 square miles in Pima and Cochise counties in
Southern Arizona. The Company also engages in wholesale sales to other
utilities in Arizona, California, Colorado, New Mexico, Oregon, Texas and
Utah. Approximately 63% of the Company's work force is subject to a
collective bargaining unit. The collective bargaining agreement in place at
December 31, 1994 terminates on December 1, 1996.
BASIS OF PRESENTATION
The consolidated financial statements include the accounts of the
Company and three wholly-owned, utility-related 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 have been classified as discontinued operations
since June 30, 1990.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
REGULATION
The Company's utility accounting practices and electricity rates are
subject to regulation by the ACC and, in certain areas, by the FERC.
ACCOUNTING FOR THE EFFECTS OF REGULATION
The Company prepares its financial statements in accordance with the
provisions of FAS 71. A regulated enterprise can prepare its financial
statements in accordance with FAS 71 only if (i) the enterprise's rates for
regulated services are established by or subject to approval by an
independent third-party regulator, (ii) the regulated rates are designed to
recover the enterprise's costs of providing the regulated services and (iii)
in view of demand for the regulated services and the level of competition, it
is reasonable to assume that rates set at levels that will recover the
enterprise's costs can be charged to and collected from customers. FAS 71
requires a cost-based, rate-regulated enterprise to reflect the impact of
regulatory decisions in its financial statements. In certain circumstances,
FAS 71 requires that certain costs and/or obligations (such as incurred costs
not currently recovered through rates, but expected to be so recovered in the
future) be reflected in a deferral account in the balance sheet and not be
reflected in the statement of income or loss until matching revenues are
recognized. It is the Company's policy to assess the recoverability of costs
recognized as regulatory assets and the Company's ability to continue to
account for its activities in accordance with FAS 71, based on each rate
action and the criteria set forth in FAS 71.
The Company's Consolidated Balance Sheets at December 31, 1994 and 1993
contain certain amounts solely as a result of the application of FAS 71:
Assets (Liabilities) 1994 1993
-------------------- ----- -----
- Millions of Dollars -
Income Taxes Recoverable Through Future Rates $143 $150
Deferred Common Facility Costs 66 68
Deferred Springerville Unit 2 Costs 55 68
Deferred Lease Expense 25 33
Deferred Fuel and Purchased Power Expense 6 13
Other Deferred Charges 9 8
MSR Option Gain Regulatory Liability (41) (55)
Deferred Investment Tax Credits (24) (29)
Other Deferred Credits (1) (1)
Regulatory assets are recorded based on prior rate orders issued by the
ACC which provide a mechanism for recovery in regulated rates or historical
rate treatment which provides evidence as to the probability of future rate
recovery. The material regulatory assets listed above earn either a return
on investment through inclusion in rate base or earn a set rate of interest
stipulated by the ACC.
A number of accounts in the Company's Consolidated Statements of Income
(Loss) for the three years in the period ended December 31, 1994 also reflect
the application of FAS 71:
Income (Expense) 1994 1993 1992
---------------- ----- ----- -----
- Millions of Dollars -
Amortization of MSR Option Gain
Regulatory Liability $ 20 $ 6 $ 6
Amortization of Springerville Unit 2
Rate Synchronization (14) - -
Deferred Fuel and Purchased Power (7) (11) (7)
Amortization of Deferred Common Facility Costs (3) (3) (4)
Deferred Springerville Unit 2 Carrying Costs 1 5 4
Regulatory Disallowances and Adjustments - (14) -
Amortization of Investment Tax Credit 5 5 6
Regulatory Interest Relating to MSR Option Gain
Regulatory Liability (6) (7) (7)
If the Company had not applied the provisions of FAS 71 in these years,
each of these amounts appearing in the Consolidated Statements of Income
(Loss) would have been reflected in the Consolidated Statements of Income or
Loss in prior periods, except for two items which would not have been
recorded: 1) the amortization of the MSR Option Gain Regulatory Liability,
including regulatory interest; 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, 1994, 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 $142 million, which includes a reduction for the
related deferred income taxes. The Company's cash flows would not be
affected by the adoption of FAS 101.
UTILITY PLANT
Utility Plant by major classes at December 31, 1994 and 1993 is as
follows:
1994 1993
---------- ----------
- Thousands of Dollars -
Utility Plant:
Production Plant $1,002,409 $ 988,241
Transmission Plant 460,055 454,105
Distribution Plant 495,336 473,830
General Plant 84,441 77,874
Intangible Plant 10,238 8,685
Electric Plant Held for Future Use 644 1,377
---------- ----------
Total Utility Plant $2,053,123 $2,004,112
========== ==========
Utility plant is stated at original cost. In accordance with the
Uniform System of Accounts prescribed by the FERC and accepted by the ACC,
the Company capitalizes AFDC based on the cost of borrowed funds and a
reasonable rate upon equity funds used to finance CWIP, when recovery of such
costs from ratepayers is probable. The component of AFDC attributable to
borrowed funds is presented as a reduction of Interest Expense. The
Consolidated Statements of Income (Loss) reflect no AFDC - Equity as all
construction expenditures were deemed under FERC prescribed rules to be
financed with debt. In accordance with FERC Accounting Release No. 13, AFDC
is recorded on construction expenditures and on the balances of construction
funds held in trust, if any are held. Interest income from construction
funds held in trust, if any, net of income taxes, is credited to CWIP.
Interest Expense on Long-Term Debt - Net reflects interest expense on the
stated principal amount of bonds in excess of the average month-end balance
of construction funds held in trust during the period. Interest expense on
stated bond principal equal to the average month-end balance of construction
funds held in trust is charged against AFDC. In 1994, 1993 and 1992, gross
AFDC rates of 4.94%, 4.85% and 8.01%, respectively, were used for all CWIP.
Depreciation is computed on a straight-line basis at component rates
which are based on the economic lives of the assets. These component rates,
which are authorized by the ACC, averaged 3.73%, 3.68% and 3.71% in 1994,
1993 and 1992, 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
As described in Note 3, since December 15, 1992, the date of closing of
the Company's Financial Restructuring, the Company's leases of the
Springerville Common Facilities, Springerville Unit 1, Valencia coal handling
facilities and Irvington Unit 4 have been classified as capital leases in the
Consolidated Balance Sheets. For rate making purposes, the ACC treats these
leases as operating leases and has allowed for recovery of the lease costs by
straight-line amortization of the total amount of lease rent payments over
the primary term of the leases, except for the Valencia coal handling
facilities lease. The Valencia coal handling facilities lease is being
amortized on a straight-line basis over the primary term of the lease plus
the first optional renewal period of six years to reflect the recovery period
mandated by the ACC. Under GAAP, the lease term would have been only the
primary term of the lease. Interest and depreciation relating to the leases
are recorded as expense on a basis which reflects the regulatory straight-
line treatment. The amount of lease amortization incurred for the four above-
described leases, as well as the Company's remaining leases, for the years
1994, 1993 and 1992 amounted to:
Years Ended December 31,
1994 1993 1992
----- ----- -----
- Millions of Dollars -
Lease Amortization:
Interest $ 94 $ 93 $ 22
Depreciation 13 12 2
---- ---- ----
Total Lease Amortization $107 $105 $ 24
==== ==== ====
Lease Amortization Included In:
Operating Expenses - Fuel $ 20 $ 17 $ 1
Operating Expenses - Capital Lease Expense 93 93 20
Balance Sheet - Deferred Lease Expense (6) (5) 3
----- ----- ----
Total Lease Amortization $107 $105 $ 24
===== ===== ====
The Deferred Lease Expense of $25 million and $33 million at December
31, 1994 and 1993, 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 Allowance for Springerville Unit 1 below.
ALLOWANCE FOR SPRINGERVILLE UNIT 1
The 1989 Rate Order limited recovery through retail rates of Century
demand charges for Springerville Unit 1 under the Restated Century Purchase
Contract to a rate of only $15 per kW per month. From inception through
termination of such contract on December 15, 1992, capacity costs for
Springerville Unit 1 averaged approximately $20 per kW per month.
Prior to its termination as a part of the Financial Restructuring
described in Note 3, the Restated Century Purchase Contract required the
Company to purchase all of Springerville Unit 1 capacity through 2014, but
was subject to cancellation by Century after 2001 on five years' advance
notice. In addition, in 1990, industry and Company projections for the
demand for power in the western United States indicated that excess capacity
conditions would be likely to continue for a few years, but should not exist
by the year 2000. Due to the significant uncertainties regarding the power
markets beyond 2001 and the existence of Century's cancellation option, the
amount of loss, if any, which may have been incurred as a result of the $15
per kW per month limitation beyond such date appeared significantly
uncertain. In December 1990, the Company, therefore, recognized a loss of
approximately $178 million and established a deferred liability for this
estimated loss, the Allowance for Springerville Unit 1, equal to the present
value of the excess of the Company's costs estimated to be incurred during
the period through 2001 over $15 per kW per month using a discount rate of
13%.
In connection with the Financial Restructuring, the Company assumed
Century's lease of Springerville Unit 1 under a capital lease agreement
extending to January 1, 2015. Accordingly, in December 1992, the remaining
unamortized balance of the Allowance for Springerville Unit 1 was
recalculated based on the $15 per kW rate currently permitted pursuant to the
1991 Rate Order and current cost estimates through the year 2014. This
resulted in an additional loss of approximately $7 million, which was
recorded as a component of the Loss on Financial Restructuring in the
Consolidated Statement of Income (Loss) for the year ended December 31, 1992.
In addition, the liability was reclassified to a contra-asset, Allowance for
Springerville Unit 1. The Allowance for Springerville Unit 1 increases each
year by the accrual of interest and decreases by the amount which is being
amortized to income, as a contra-expense, through 2014. The imputed interest
expense, calculated using a 13% discount rate, associated with this liability
is included as part of Regulatory Interest in the Interest Expense section in
the Consolidated Statements of Income (Loss).
DEFERRED COMMON FACILITY COSTS
Springerville Common Facility Costs are lease costs and operating costs
incurred for the Springerville Common Facilities during the period after
Springerville Unit 1 was placed in service and before Springerville Unit 2
was placed in service. Pursuant to an accounting order from the ACC, these
costs were deferred and are being amortized over the primary term of the
Springerville Common Facilities Leases. The ACC has allowed for the recovery
of the amortization costs plus a return on investment.
UTILITY OPERATING REVENUES
Operating Revenues include accruals for unbilled revenues, thereby
recognizing revenue that is earned, but not billed, at the end of an
accounting period.
AMORTIZATION OF MSR OPTION GAIN REGULATORY LIABILITY
The 1989 Rate Order 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. In the 1989 Rate Order, the ACC ordered the MSR Option Gain be
amortized over a six-year period through 1995 as a $20 million per year
revenue credit, and in 1990 the Company established a deferred liability for
the present value of the amount to be amortized, calculated using a 13%
discount rate. Such deferred liability increases each year by the accrual of
interest at 13% and decreases by the amount of revenue credit prescribed by
the ACC. Such revenue credit is included in Operating Revenues. The
interest accrual is included as part of Regulatory Interest in the Interest
Expense section of the Consolidated Statements of Income (Loss). The 1991
Rate Order deferred amortization of a portion of the regulatory liability to
1996 and 1997.
FUEL AND PURCHASED POWER COSTS
Fuel inventory, primarily coal, is stated on a basis which approximates
weighted average cost. The Company utilizes full absorption costing.
Certain lease and interest costs incurred by Valencia, the Company's
fuel-handling and procurement subsidiary for Springerville, are accounted for
as deferred costs, which were allocated to fuel inventory based on fuel
quantities purchased and then amortized to Fuel expense and, prior to the
closing of the Financial Restructuring on December 15, 1992, to Purchased
Power - Energy, based on the rate of fuel burn at Springerville through
December 31, 1992. Effective January 1, 1993, these costs are amortized to
Fuel expense on a straight-line basis over 37.4 years pursuant to the 1994
Rate Order.
FINANCIAL RESTRUCTURING COSTS
Financial Restructuring costs include costs incurred for legal,
accounting and other consulting services in connection with the restructuring
of the Company's obligations, as described in Note 3.
INCOME TAXES
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 has been in a net operating loss carryforward position, the income
tax benefits reflected in the Consolidated Statements of Income (Loss) result
only from such ITC amortization.
Income taxes are allocated to the subsidiaries based on contributions to
the consolidated tax return liability. The investment subsidiaries' losses
in 1994, 1993 and 1992 provided no tax benefits to the consolidated group
and, therefore, no tax benefits are recorded as a reduction of the 1993 and
1992 Provisions for Loss on Disposal of Discontinued Operations in the
Consolidated Statements of Income (Loss).
DEBT EXPENSE
Debt discount and issuance costs are amortized over the lives of the
related issues or the related refunding issues.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying value and fair value at December 31, 1994 and 1993 of the
Company's financial instruments are as follows:
1994 1993
------ ------
Carrying Fair Carrying Fair
Value Value Value Value
-------- ----- -------- -----
- Thousands of Dollars -
Assets:
Cash and Cash Equivalents $ 233,300 $ 233,300 $ 139,817 $ 139,817
Accounts Receivable 66,332 66,332 65,212 65,212
Other Investments 4,307 4,307 4,370 4,370
Liabilities:
Accounts Payable (39,777) (39,777) (40,190) (40,190)
Long-Term Debt, Including
Current Portion
(See Note 6) (1,399,102) (1,372,236) (1,418,555) (1,397,838)
The carrying amounts of all financial instruments, except Long-Term
Debt, are considered to be reasonable estimates of the fair value of each
because of the short maturity of those instruments.
RECLASSIFICATION
Minor reclassifications have been made to the prior year financial
statements presented to conform to the current year's presentation.
Beginning in the fourth quarter of 1994, state and city sales taxes
and similar taxes collected on revenues were removed from Operating
Revenues and Taxes Other Than Income Taxes on the Consolidated Statements
of Income (Loss). These taxes are included as part of Accounts Receivable
and Taxes Accrued on the Consolidated Balance Sheets. Such
reclassification was made to enhance the comparability of the Company's
income statements with those of other companies. All financial
information presented has been restated to conform to this presentation.
The tax amounts reclassified were as follows:
Years Ended December 31,
1994 1993 1992
------- ------- -------
- Thousands of Dollars -
State Sales Taxes $28,392 $26,027 $25,379
City Sales and Franchise Taxes 12,585 11,351 11,052
ACC Assessment Fee 934 920 952
------- ------- -------
Total Taxes Reclassified $41,911 $38,298 $37,383
======= ======= =======
NOTE 2. 1994 RATE ORDER
- ------------------------
Effective January 11, 1994, the ACC authorized a 4.2% increase in base
rates. The 1994 Rate Order recognized that an additional 17.5% of the
Springerville Unit 2 capacity was used and useful for the retail
jurisdiction, which lowered the percentage of that unit's capacity that is
not in rate base to 37.5%. Therefore, the Company is not presently
recovering through retail rates the depreciation, property taxes, operating
and maintenance expenses other than fuel, or interest costs associated with
the 37.5% of Springerville Unit 2 capacity which was not then considered to
be used and useful for the retail jurisdiction and therefore was not included
in rate base (hereinafter referred to as "retail excess capacity deferrals").
These expenses are being expensed as incurred. However, the 1994 Rate Order
permits such costs to be deferred for future recovery over the remaining
useful life of Springerville Unit 2. This phase-in plan does not qualify
under FAS 92 and, therefore, such retail excess capacity deferrals, while
deferred for regulatory purposes, cannot be deferred for financial reporting
purposes. Such regulatory deferrals associated with the excluded
Springerville Unit 2 capacity, not included in the financial statements,
totaled $63 million at December 31, 1994. Either inclusion in costs
recoverable through retail rates or additional wholesale sales at sufficient
prices of an equivalent amount of capacity (or a combination thereof) will be
required to recover these retail excess capacity deferrals.
As a result of the 1994 Rate Order, the retail excess capacity deferrals
allocable to the 62.5% of Springerville Unit 2 capacity allowed in rate base
was also included in rate base. At December 31, 1993, the retail excess
capacity deferrals allocable to the 17.5% of the Springerville Unit 2
capacity amounted to $17 million. As specified in the 1994 Rate Order, for
rate purposes, these costs are being recovered over a 37.4 year period.
The 1994 Rate Order allowed in rate base 62.5% of deferred Springerville
Unit 2 rate synchronization costs, $42 million at December 31, 1993, which
were non-fuel costs of Springerville Unit 2 incurred from January 1, 1991
through October 14, 1991, including an interest carrying charge, deferred
pursuant to the 1991 Rate Order. For rate making purposes, such costs are
being recovered over a three-year period and are included in Depreciation and
Amortization on the Consolidated Statements of Income (Loss), in accordance
with the 1994 Rate Order. The Company is not presently recovering through
retail rates 37.5% of the deferred Springerville Unit 2 rate synchronization
costs ($26 million at December 31, 1994). This amount, together with the
balance of such costs ($29 million at December 31, 1994) that the Company is
presently recovering through rates, are reported in the Company's
consolidated financial statements as Deferred Springerville Unit 2 Costs.
The 1994 Rate Order provided that the rate synchronization and retail
excess capacity deferrals associated with the 37.5% of Springerville Unit 2
capacity not found to be used and useful for the retail jurisdiction will
continue to incur an interest charge of 7.19% until authorized to be included
in rate base or for a period of three years ending in 1997, whichever occurs
first.
The 1994 Rate Order disallowed recovery of $13.6 million of previously
capitalized Springerville Unit 2 rate synchronization costs and certain other
minor costs. The $13.6 million is comprised of $5.2 million for wholesale
power sale revenue credits which the Company had offset against the off-
balance sheet retail excess capacity deferrals which the ACC stated should
have been offset against the rate synchronization deferrals. The remaining
$8.4 million of disallowance results from the ACC's finding that the Company
should have calculated the 7.19% carrying charge on a net-of-tax basis rather
than pre-tax, as calculated by the Company. Such disallowances were recorded
in December 1993 and are reflected in Regulatory Disallowances and
Adjustments in the Consolidated Statement of Income (Loss) for the year ended
December 31, 1993.
In connection with the 1994 Rate Order, on August 26, 1993, the ACC
authorized the Company to collect the sum of $2.1 million through a temporary
fuel surcharge of .96 mills per kWh beginning September 1, 1993 until further
order of the ACC. The Company had requested a temporary rate surcharge to
recover $4 million of previously authorized but uncollected deferred fuel
expenses. The Company wrote-off $1.9 million of unrecovered deferred fuel
costs in 1993.
NOTE 3. 1992 CONSUMMATION OF THE FINANCIAL RESTRUCTURING
- ---------------------------------------------------------
On December 15, 1992, the Company consummated the transactions required
to finalize its financial restructuring plan, including the comprehensive
restructuring of obligations to certain of its creditors, lease participants,
Century and the Springerville Unit 1 lease participants and the
reclassification of all outstanding Preferred Stock into Common Stock.
Approximately 135 million shares of Common Stock were issued in the Financial
Restructuring, increasing the number of common shares outstanding to
approximately 160 million. In addition, warrants to purchase an additional
12 million shares of Common Stock at an exercise price of $3.20 per share
were issued in the Financial Restructuring. The issuance of Common Stock and
Warrants is further discussed below. In accordance with FAS 15 such stock
(other than the 55 million shares of Common Stock into which the Preferred
Stock was reclassified) was recorded at fair value as determined by the
Company on or about the date of issuance. In the accompanying financial
statements, the Common Stock issued pursuant to the Financial Restructuring
was recorded based on a fair value of $2.33 per share, which was the average
of the high and low trading price reported by the Dow Jones Stock Quote
Reporter Service during the period December 16, 1992 through December 31,
1992, the period immediately following the Closing. The Warrants were valued
for purposes of these financial statements at an estimated value of $0.82 per
share, calculated using an option pricing model and the $2.33 estimated fair
value per share of Common Stock. Losses and deferred gains related to the
issuance of the Common Stock and Warrants in the Financial Restructuring
described in the succeeding paragraphs were determined using these values for
such Common Stock and Warrants. Such values are not intended to be
indicative of current or future trading values for either the Common Stock or
the Warrants.
BANKS
The Company provided the banks approximately 32 million shares of Common
Stock, a first mortgage lien on Springerville Unit 2, $50 million of bonds
issued under a second mortgage as collateral, and $20.8 million in first
mortgage bonds as collateral and became subject to certain restrictive
financial and operating covenants. In exchange, the Company received the
waiver of $96 million in accrued interest payments, more favorable credit
terms, extensions of LOCs and related agreements, the restructuring of
several prior debt agreements into the Term Loan, a new $20 million LOC and a
new $50 million working capital revolving credit facility. The restructuring
of these Bank obligations gave rise to a deferred gain of $21 million, which
is being amortized as a reduction of interest expense over an eight-year
period, the weighted average life of the restructured credit arrangements.
These restructured bank credit arrangements also increased Common Stock
Equity $75 million. See the Consolidated Statements of Changes in
Stockholders' Equity (Deficit).
SPRINGERVILLE UNIT 1
The Company provided the participants in the Springerville Unit 1 Leases
approximately 48 million shares of Common Stock and Warrants to purchase
12,054,278 shares of Common Stock at an exercise price of $3.20 per share.
The Warrants were exercisable at the Closing of the Financial Restructuring
and expire in 2002. In addition, the Company assumed Century's former
obligations under the Springerville Unit 1 Leases and released Century from
its obligations relating to the 1981 Apache A Bonds. Amendments were also
made to the Interconnection Agreement which the Company has with Century. In
exchange, the Company received Century's leasehold interests in Springerville
Unit 1, Century's investment in plant and inventories at Springerville Unit 1
and the Restated Century Purchase Contract was terminated. The Company also
received the waiver of demand charge payments due under the Restated Century
Purchase Contract equivalent to $57 million, the release from certain tax
indemnification liabilities related to Springerville Unit 1, and the
dismissal with prejudice of certain actions which had been filed against the
Company by some of the Springerville Unit 1 owner participants.
The restructuring of these obligations gave rise to approximately $31
million of the Loss on Financial Restructuring appearing in the Consolidated
Statement of Income (Loss) for the year ended December 31, 1992. These
transactions also increased Common Stock Equity by $122 million. See the
Consolidated Statements of Changes in Stockholders' Equity (Deficit). Also,
see Note 1 regarding the loss of approximately $7 million, which was recorded
as a component of the Loss on Financial Restructuring in the Consolidated
Statement of Income (Loss) for the year ended December 31, 1992, as a result of
the assumption of the Springerville Unit 1 Leases.
CAPITAL LEASES
The terms of the Irvington Lease, the Valencia Leases, the Springerville
Common Facilities Leases and the assumed Springerville Unit 1 Leases (see
Note 1) were amended to waive certain accrued payment obligations, defer
certain lease payments due in the next several years to later years, and
extend the terms of certain leases. As a result of the lease amendments, in
accordance with FAS 13, as amended by FAS 98, these leases are accounted for
as capital leases subsequent to December 15, 1992. Amendment of these leases
increased rent expense by $18 million in the Consolidated Statement of Income
(Loss) for the year ended December 31, 1992.
PREFERRED STOCK
All of the Company's outstanding Preferred Stock was reclassified into
approximately 55 million shares of newly issued Common Stock. The
reclassification was recorded at the book value of the Preferred Stock. This
increased Common Stock Equity by $90 million, decreased the Premium on
Capital Stock by $7 million and decreased Preferred Stock by $83 million.
See the Consolidated Statements of Changes in Stockholders' Equity (Deficit).
OTHER
The reversal of other reserves and accruals that were resolved by the
Closing, primarily through the dismissal of certain regulatory proceedings,
reduced the Loss on Financial Restructuring included in the Consolidated
Statement of Income (Loss) for the year ended December 31, 1992 by $11
million.
NOTE 4. INCOME TAXES
- ---------------------
In January 1993, the Company adopted Statement of Financial Accounting
Standards No. 109 (FAS 109), Accounting for Income Taxes, on a prospective
basis. The adoption of FAS 109 changed the Company's method of accounting
for income taxes from the deferred method (APB 11) to an asset and liability
approach. Previously, the Company deferred the past income tax effects of
timing differences between financial reporting and taxable income. The asset
and liability approach requires the recognition of deferred income tax
liabilities and assets for the expected future income tax consequences of
temporary differences between the carrying amounts and the tax bases of other
assets and liabilities.
The adoption of FAS 109 increased both total assets and total
liabilities of the Company by $149 million in 1993. The increase in assets
results primarily from the recording of a regulatory asset for the recovery
of income taxes from future ratepayers. See Note 1. Such regulatory asset
consists primarily of the right to recover income taxes relating to
previously flowed-through differences, both timing and permanent, which
provided rate benefits to past ratepayers. The increase in liabilities is
primarily the net increase in deferred income tax assets and deferred income
tax liabilities resulting from the adoption of FAS 109.
Deferred tax assets (liabilities) are comprised of the following:
December 31,
1994 1993
----------- ----------
- Thousands of Dollars -
Gross Deferred Income Tax Liabilities:
Electric Plant - Net $(558,509) $(554,441)
Regulatory Asset (Income Taxes
Recoverable Through Future Rates) (57,902) (60,615)
Deferred Springerville Unit 2 Costs (22,206) (27,384)
Deferred Valencia Inventory Costs (21,780) (21,628)
Deferred Lease Payments (15,510) (16,329)
Property Taxes (10,465) (10,340)
Deferred Fuel (2,372) (5,364)
Other (6,016) (7,371)
---------- ----------
Gross Deferred Income Tax Liability (694,760) (703,472)
---------- ----------
Gross Deferred Income Tax Assets:
Capital Lease Obligations 377,825 384,506
Tax Operating Loss Carryforwards 199,564 181,200
Springerville Unit 1 Disallowed Costs 65,597 65,959
Investment in Loans and Partnerships 7,757 34,205
Investment Tax Credit Carryforwards 28,088 28,100
MSR Option Gain Regulatory Liability 16,645 22,268
Capital Loss Carryforwards 19,078 20,700
Lease Interest Payable 17,429 17,570
Deferred Regulatory Capital Lease Expense 11,397 8,213
Financial Restructuring Costs Not Yet
Deductible for Tax Purposes 8,034 7,773
Gain on Financial Restructuring of
Long-Term Debt 6,458 7,571
Other 27,166 29,492
---------- ----------
Gross Deferred Income Tax Asset 785,038 807,557
Deferred Tax Assets Valuation Allowance (244,092) (263,991)
---------- ----------
Net Deferred Income Tax Liability $(153,814) $(159,906)
========== ==========
The decrease in the gross deferred tax assets valuation allowance of
approximately $20 million primarily resulted from the sale of the
discontinued operation's assets (see Note 5) which had corresponding deferred
tax assets, which were fully reserved by the valuation allowance.
The net deferred income tax liability is included in the Consolidated
Balance Sheets in the following accounts:
December 31,
1994 1993
---------- ----------
- Thousands of Dollars -
Deferred Income Tax - Current $ 12,870 $ 8,927
Accumulated Deferred Income Taxes (166,684) (168,833)
---------- ----------
Net Deferred Income Tax Liability $(153,814) $(159,906)
========== ==========
Income Tax Benefit is included in the Consolidated Statements
of Income (Loss) in the following accounts:
Years Ended December 31,
1994 1993 1992
---------- ---------- ----------
- Thousands of Dollars -
Operating Expenses - Other Operations $ 91 $ 91 $ 91
Other Income (Deductions) - Income Taxes 4,820 5,186 5,654
---------- ---------- ----------
Total Income Tax Benefit $ 4,911 $ 5,277 $ 5,745
========== ========== ==========
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 for each of the three years in the period ended December 31,
1994, are as follows:
Years Ended December 31,
1994 1993 1992
---------- ---------- ----------
- Thousands of Dollars -
Federal Income Tax (Expense) Benefit
at Statutory Rate $ (5,540) $ 10,883 $ 43,797
Investment Tax Credit amortization 4,911 5,277 5,745
Loss for Which No Tax Benefit
is Available - (10,883) (43,797)
Net Operating Loss Carryforwards 5,540 - -
---------- ---------- ----------
Total Benefit for Federal and
State Income Taxes $ 4,911 $ 5,277 $ 5,745
========== ========== ==========
On August 10, 1993, the Revenue Reconciliation Act of 1993 was signed
into law which, among other things, raised the maximum corporate U.S.
statutory federal income tax rate from 34% to 35%, retroactively effective to
January 1, 1993. The Company increased its deferred tax balances and the
corresponding deferred tax asset valuation allowance at December 31, 1993 as
a result of this rate change.
At December 31, 1994, the Company had, for federal income tax purposes,
$28 million of unused ITC, the use of which will expire during 2001 through
2005, $2 million of alternative minimum tax credit which will carry forward
to future years, and $47 million of capital loss carryforwards which expire
during 1995 through 1999. In addition, for federal income tax purposes the
Company has approximately $494 million of net operating loss carryforwards
expiring in 2004 through 2009 and $169 million of alternative minimum tax
loss carryforwards expiring in 2005 through 2007. For state income tax
purposes, the Company has approximately $352 million of net operating loss
carryforwards expiring in 1995 through 1999.
Due to the Company's Financial Restructuring, as described in Note 3,
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 loss 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. This limit 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. The 1992 section 382 limitation increased by
approximately $84 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, 1994, the Company had pre-change net
operating loss, ITC, capital loss and alternative minimum tax carryforwards
of approximately $365 million, $28 million, $31 million and $136 million,
respectively.
The 1980 through 1985 Federal Income Tax Audit resulted in a 1992
federal tax refund of approximately $1 million and approximately $8 million
in interest. The interest income had not been previously accrued and is
included as Other Income in the Consolidated Statement of Income (Loss) for
the year ended December 31, 1992.
NOTE 5. DISCONTINUED OPERATIONS
- --------------------------------
In July 1990, the Boards of Directors of the Company's investment
subsidiaries adopted formal plans of liquidation of the investment
operations. Pursuant to such actions, investment subsidiaries' results of
operations, estimated net realizable value of net assets and cash flows have
been classified as discontinued operations in the Company's consolidated
financial statements since June 30, 1990. The Company recorded a provision
for losses on disposal of discontinued operations of $105 million in 1990 to
reduce the carrying values of the assets to their then-estimated net
realizable values. The financial results of activities from discontinued
operations subsequent to June 30, 1990 have been recorded as an adjustment to
the reserve for losses. Additional provisions for losses on disposal of
discontinued operations of $36 million in 1991, $44 million in 1992, and $4
million in 1993 were made to reflect further weakening of markets for certain
subsidiary investments, increased estimates of holding-period costs for those
assets and a $10 million addition to the reserve for litigation in 1992.
The components of net assets of discontinued operations are summarized
as follows:
December 31,
1994 1993
--------- ---------
- Thousands of Dollars -
Cash and Cash Equivalents $ 14,852 $ 22,179
Investment in Citadel - 23,374
Real Estate Investments 17,127 65,119
Vehicle Contracts Receivable 17,509 17,509
Other Assets and Investments 6,859 19,403
Reserve for Loss on Disposal of
Discontinued Operations (34,494) (74,109)
--------- ---------
Total Assets 21,853 73,475
Current Liabilities (13,168) (14,995)
--------- ---------
Net Assets of Discontinued Operations $ 8,685 $ 58,480
========= =========
Loss from discontinued operations is as follows:
Years Ended December 31
1994 1993 1992
--------- --------- ---------
- Thousands of Dollars -
Investment Losses $(35,447) $(20,403) $(27,473)
Hotel Revenues 13,171 13,930 13,669
Hotel Depreciation and Other Expense (16,242) (17,129) (16,914)
Other Investment Expense (1,097) (2,289) (1,927)
--------- --------- ---------
Operating Loss (39,615) (25,891) (32,645)
Reduction in Reserve for Losses 39,615 25,891 32,645
--------- --------- ---------
Loss from Discontinued Operations $ - - $ -
========= ========= =========
Net assets of discontinued operations declined by approximately $50
million between December 31, 1993 and December 31, 1994 as a result of
dividends paid by TRI to the Company.
Gross investment losses during 1994 included losses of: $21 million on
sales of real estate; $21 million on the sale of the remaining Citadel common
stock; and $5 million on the sale of two small power projects. Offsetting
these losses were gains of: $9 million on the sale of various marketable
securities and $1 million on the sale of a vehicle contracts receivable
portfolio. The resulting net losses reduced the Reserve for Losses by an
equal amount. Also included in Investment Losses is $2 million of other
investment income.
As of December 31, 1994, Real Estate Investments consist of 1) loans
collateralized by real property and 2) land held for sale in Arizona.
Vehicle Contracts Receivable consists principally of automobile installment
sales contracts of Brookland, a financial services company. In January 1991,
the Board of Directors of Brookland elected to discontinue its business
operations. Brookland remains liable for credit obligations to outside
lenders of $12 million. These credit obligations are collateralized by
Brookland's vehicle contracts portfolio and other interests in Vehicle
Contracts Receivable.
As of December 31, 1994, the Company has substantially completed its
disposal of discontinued operations. The losses from discontinued operations
for the period June 30, 1990 through December 31, 1994 of $139 million have
been recorded as reductions in the Reserve for Losses. The gross proceeds
from the sale of assets, excluding scheduled collections on loans and notes
receivable, for the period June 30, 1990 through December 31, 1994 amounted
to $498 million. The remaining assets and liabilities will be accounted for
as a part of continuing operations beginning January 1, 1995.
NOTE 6. LONG AND SHORT-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
- ---------------------------------------------------------------
LONG-TERM-DEBT
First Mortgage Bonds and Installment Sale Agreement
First Mortgage Bond and Installment Sale Agreement maturities and cash
sinking fund requirements for the next five years include $17 million in 1995,
$12 million in 1996, $2 million in 1997, $3 million in 1998, and $19 million in
1999. In addition, certain First Mortgage Bonds have additional annual sinking
fund requirements which total approximately $3 million for each of the next
five years. These sinking fund requirements can be and have been satisfied to
date primarily by pledges of additional property. 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.
Restructured Arrangements
Approximately $900 million of the Company's previous bank obligations
including bank lines, LOCs and related reimbursement agreements (excluding
the reimbursement agreement relating to the 1981 Apache B Bonds) were
combined and restructured into a master restructuring agreement between the
Company and the Banks (the MRA) on December 15, 1992. The MRA provided for a
$243.3 million Term Loan, Replacement LOCs supporting $674 million of IDBs,
and a $50 million Revolving Credit. 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.
Additionally, the MRA provided for an additional $20 million LOC which
was issued in March 1993 to the indenture trustee for industrial development
revenue bonds originally issued in 1990. The reimbursement agreement related
to that LOC, which is secured by first mortgage bonds, allowed the debt
proceeds to be released to the Company which reimbursed the Company for costs
of qualifying facilities. See Letters of Credit below.
In March 1995, the Company and its banks completed an amendment to the
MRA which eased certain debt prepayment restrictions and modified the Term
Loan to allow reborrowing of amounts which will have been previously prepaid
(Renewable Term Loan) (see Term Loan below). The amendment will allow the
Company to better manage its cash position and reduce capital costs while
maintaining liquidity. Prior to the amendment the Company was not permitted
to prepay non-MRA debt except to the extent that certain cash amounts, as
defined in the MRA, were generated. The amendment, now in effect, 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.
To comply with provisions of the MRA prior to the March 7, 1995
amendment, the Company prepaid $17.25 million of First Mortgage Bonds during
1994. During 1993 the Company, under a bank waiver to certain restrictions
of the MRA, voluntarily prepaid $49 million of First Mortgage Bonds and $19
million of the Term Loan.
Additional details regarding the components and covenants of the MRA are
described below.
Letters of Credit
At December 31, 1994 there were $774 million principal amount of
variable rate tax-exempt IDBs outstanding. Payment of principal and interest
on these bonds is secured by LOCs. The LOCs expire at various dates during
the period December 31, 1999 through December 31, 2002. However, all the
LOCs could expire by December 31, 2000, including an expiration as early as
August 1997, if the Company's senior long-term debt is rated investment grade
on certain dates or during certain periods subsequent to December 31, 1996.
The reimbursement agreement related to the 1981 Apache B Bonds is secured by
First Mortgage Bonds. The weighted average commitment fee on the Replacement
LOCs is approximately 0.53% through 1997 and increases to 0.82% in 1998,
1.07% in 1999 and thereafter.
Term Loan
The Term Loan, on March 7, 1995, was amended and renamed the Renewable
Term Loan. As a condition to the amendment becoming effective the Company
permanently prepaid $19.34 million of the Term Loan reducing the outstanding
balance from $193.4 million to approximately $174 million at March 7, 1995.
Thus, the initial commitment and outstanding balance of the Renewable Term
Loan was approximately $174 million.
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. The adjusted eurodollar rate was approximately
4.92% per annum and 4.03% per annum for the years ended December 31, 1994 and
1993, respectively, and was approximately 3.66% for the one month period
ended December 31, 1992. During 1993 and 1992 the Company prepaid $19
million and $31 million, respectively, of the outstanding balance.
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 at least
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 1.2
to 1 in 1994 and gradually increasing to 2 to 1 in 2000 continuing through
the year 2003. For the year ended December 31, 1994, the Company's MRA
interest coverage ratio was 2.98 to 1. With respect to dividends, the MRA
incorporates, until the Renewable Term Loan and the Revolving Credit are paid
in full and commitments thereunder terminate, a restrictive covenant similar
to that currently in the General First Mortgage which limits the Company's
ability to pay dividends on Common Stock until it has positive retained
earnings (through future earnings or otherwise) rather than an accumulated
deficit (such accumulated deficit was $681 million at December 31, 1994).
For the foreseeable future, the Company does not anticipate being able to
satisfy the tests of this restrictive covenant, and therefore, does not
anticipate being permitted to pay cash dividends on its Common Stock.
Fair Value of Long-Term Debt
1994 1993
Carrying Fair Carrying Fair
Value Value Value Value
-------- ----- -------- -----
- Thousands of Dollars -
First Mortgage Bonds:
Corporate $ 269,750 $ 256,009 $ 287,000 $ 275,687
IDBs
1981 Apache B Bonds 100,000 100,000 100,000 100,000
Pollution Control Financing
Bonds 112,200 102,944 112,200 106,030
1990 Pima A Bonds 20,000 20,000 20,000 20,000
Loan Agreements:
Installment Sale Agreement 50,000 46,131 50,955 47,646
IDBs 653,600 653,600 653,600 653,600
Term Loan 193,400 193,400 193,400 193,400
Promissory Note 152 152 1,400 1,475
---------- ---------- ---------- ----------
$1,399,102 $1,372,236 $1,418,555 $1,397,838
========== ========== ========== ==========
The principal amount of variable rate debt outstanding at December 31,
1994 and 1993 of the 1981 Apache B Bonds, the 1990 Pima A Bonds, the Loan
Agreements-IDBs, and the 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 Pollution Control Financing Bonds, the Installment Sale
Agreement and Promissory Note was determined by calculating the present value of
the cash flows of each fixed rate obligation. The discount rate used for each
calculation was a rate consistent with market yields generally available as
of December 1994 for 1994 amounts and December 1993 for 1993 amounts,
obtained from the Moody's Bond Survey report, 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.
SHORT-TERM DEBT
Revolving Credit
The $50 million Revolving Credit, provided as 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 0.75% in 1994 and 1995 which gradually increases to 2% by 1998 and
thereafter. The Company is required to repay the Revolving Credit in full
for at least 30 consecutive days in each twelve-month period prior to
November 30 of each year. The annual commitment fee for the Revolving Credit
equals 0.5% of the unused portion.
Discontinued Operations
Vehicle contracts receivable and other interests in vehicle contracts
receivable held by Brookland are financed through a warehouse line of credit
and a loan which totaled approximately $12 million at December 31, 1994 and
1993. The weighted average interest rate applicable to the warehouse line of
credit at December 31, 1994 and 1993 was 17%.
CAPITAL LEASE OBLIGATIONS
A schedule by years of future minimum lease payments under capital
leases together with the present value of the net minimum lease payments
(Capital Lease Obligations) as of December 31, 1994 follows:
Years ending December 31, - Thousands of Dollars -
1995.......................... $ 99,262
1996.......................... 119,155
1997.......................... 95,019
1998.......................... 97,200
1999.......................... 103,277
Thereafter.................... 1,913,905
------------
2,427,818
Imputed Interest.............. (1,492,280)
------------
Capital Lease Obligations..... $ 935,538
============
The Irvington Lease has an initial term to January 2011 and provides for
renewal periods of two or more years through 2020. The Springerville Common
Facilities Leases have an initial term of 2017 for one owner participant and
2021 for the other two owner participants, subject to optional renewal
periods of two or more years through 2025. The Springerville Unit 1 Leases
have an initial term to January 2015 and provide for renewal periods of three
or more years through 2030. The Valencia Leases have an initial term to
April 2015 and provide for an initial renewal period of six years, then
additional renewal periods of five or more years through 2035.
NOTE 7. COMMITMENTS AND CONTINGENCIES
- -------------------------------------
UTILITY CONTRACTUAL MATTERS
Coal and Transportation Contracts
On October 14, 1991, amendments to the contract with the Springerville
coal supplier were entered into, and became effective, which, among other
things, reduced the price of coal shipments at Springerville. The amended
contract contains provisions which protect the claims of the Springerville
coal supplier under the original agreement in the event that the Company does
not perform its obligations under the terms of the amended agreement at any
time prior to August 23, 1995. If such a failure to perform occurs, the
Company would be responsible for approximately $7 million per year in
additional payments to the Springerville coal supplier. Also, at December
31, 1994, a $3 million accrued liability remained on the Company's
Consolidated Balance Sheet which will be forgiven if all conditions are met
during the four years subsequent to the amendment of the Springerville coal
agreement.
The Company has contracted with P&M to supply coal to Irvington.
Originally, all units at Irvington were scheduled to be converted and coal
supplies were contracted for those units. The original contract required
annual minimum quantities of 650,000 tons. However, the conversion of Units
1, 2 and 3 at Irvington was canceled. The then-existing P&M contract
contained minimum take-or-pay provisions which required the Company to pay
one-half of the base price of coal for any contract quantities not scheduled
and delivered. On November 5, 1991, amendments to the contract with P&M were
entered into and became effective, which, among other things, substantially
reduced the minimum annual coal quantities to levels which the Company
estimates can be utilized by Irvington Unit 4 alone (Irvington Unit 4 is
expected to burn approximately 225,000 tons of coal per year), amended
contract price adjustment procedures, extended the expiration date of the
agreement from 2002 to 2015 and provided for an exchange of the proceeds of
the sale of undeveloped land for the $8 million 1990 penalty payment which
was withheld during the period of the Payment Moratorium (the $8 million 1990
penalty payment remains an accrued liability on the Company's Consolidated
Balance Sheet at December 31, 1994). Additionally, the penalty provisions of
the contract were amended. P&M maintains their claim under the prior contract
if the Company does not perform its obligations under the terms of the amended
agreement at any time prior to November 4, 1995. If the Company fails to
perform, the Company would be required, pursuant to the prior contract, to
pay for approximately 5.1 million tons, that would not be delivered to the
Company, at one-half the base price of coal through 2002, at an estimated
aggregate cost of $98 million.
Amendments to transportation agreements have also been executed,
effective October 18, 1991, with the Springerville and Irvington rail
transportation suppliers which, among other things, reduced the price for
coal shipments and limited annual changes in the contract price. As
discussed above with respect to the coal contracts, the Springerville amended
rail transportation agreement includes provisions which protect the
supplier's claims under the original contract in the event the Company does
not perform its obligations under the terms of the amended agreement at any
time during the four years subsequent to the amendment. If such a failure to
perform occurs, the Company would be responsible for approximately $3 million
per year to the Springerville transportation supplier at current contract
prices. At December 31, 1994, a $3 million accrued liability remained on the
Company's Consolidated Balance Sheet which will be forgiven, if all conditions
are met during the four years subsequent to amendment of the Springerville
agreement.
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 $16 million.
Fuel Purchase Commitments
The Company's contracts to purchase coal for use at Springerville,
Irvington and each of the joint projects in which the Company participates
contain various provisions calling for the payment of a take-or-pay amount,
if certain minimum quantities of coal are not scheduled and delivered. The
Company's present fuel requirements are generally in excess of the stated
take-or-pay minimum amounts; however, from time to time, the Company has
purchased spot market alternative fuels or switched fuel burn from one
generating station to another in order to achieve lower overall fuel costs,
while incurring take-or-pay minimum charges. As a result, the Company
incurred take-or-pay minimum charges of approximately $1 million during 1993
and 1992. The Company incurred no take-or-pay charges in 1994.
COMMITMENTS - ENVIRONMENTAL REGULATION
In the fall of 1990, Congress adopted certain Federal Clean Air Act
Amendments (CAAA) with respect to reductions in sulfur dioxide and nitrogen
oxide emissions which will affect the Company's operation. The nitrogen
oxide reductions will be based upon EPA regulations expected to be finalized
in 1995 for certain boilers and by 1997 for all remaining boilers. In
addition, the rules expected to be promulgated in 1995 may be revised in
1997. The required reductions of sulfur dioxide emissions will be
implemented in two phases which will be effective in 1995 and 2000,
respectively.
The Company is not affected by the requirements for sulfur dioxide
emissions and nitrogen oxide reductions which go into effect in 1995 (Phase
I), but is subject to the requirements that go into effect January 1, 2000
(Phase II). In Phase II, the maximum sulfur dioxide emission rates are set
at 1.2 pounds per million BTU. Because of the Company's general use of low-
sulfur coal and installed scrubbers at certain units, the Company's coal-
fired generating stations already meet the sulfur dioxide emission rate
requirements for Phase II. Additionally, further reductions are to be met
through a proposed market-based system. Affected Company generating units
will be allocated allowances based on required emission reductions and past
use. An allowance permits emission of one ton of sulfur dioxide and may be
sold. Generating station units must hold allowances equal to their level of
emissions or face penalties and a requirement to offset excess tons in future
years. On March 23, 1993, the EPA published the final sulfur dioxide
allowance allocations for all Phase I and Phase II affected utility units,
including the allowances that will be allocated to all Company units. An
analysis of the sulfur dioxide allowances that were allocated to the Company
shows that the Company would have sufficient allowances to permit normal
plant operation and be in compliance with the sulfur dioxide regulations once
the Phase II requirements become effective. However, until all the
rulemaking regulation processes for implementing the CAAA are completed, the
Company is unable to predict the specific impacts of all such amendments.
The CAAA also require multi-year studies of visibility impairment in
specified areas and studies of hazardous air pollutants which relate to the
necessity of future regulations of electric utility generating units. Since
these activities involve the gathering of information not currently
available, the Company cannot predict the outcome of these studies.
As a result of recent and possible future changes in federal and state
environmental laws, regulations and permit requirements, the Company may
incur additional costs for the purchase or upgrading of pollution control
emission monitoring equipment on existing electric generating facilities and
may experience a reduction in operating efficiency. There may be a need for
variances from certain environmental standards and operating permit
conditions until required equipment and processes for control, handling and
disposal of emissions are operational and reliable. Failure to comply with
any EPA or state compliance requirements may result in substantial penalties
or fines which are provided for by law and which in some cases are mandatory.
In 1991, the EPA adopted a rule for the reduction of Navajo's sulfur
dioxide emissions on an annual averaging basis by 90% to address visibility
impairment at Grand Canyon National Park. The Company estimates that its
share of the required capital expenditures remaining as of December 31, 1994
relating to the rule's implementation will be approximately $44 million,
including AFDC, through 1999.
CONTINGENCIES
SDGE/FERC Proceedings
San Diego Gas & Electric v. Tucson Electric Power Company
On February 11, 1993, SDGE filed a complaint and motion for summary
disposition against the Company and Century before the FERC (San Diego Gas
& Electric Company v. Tucson Electric Power Company and Century Power
Corporation, Docket No. EL93-13-000). The complaint alleges that the Company
and Century overbilled SDGE during Phases 3 through 5 of the Ten Year Power
Sale Agreement (Ten Year Agreement) and requests that the FERC order refunds
by the Company of an aggregate amount of approximately $14.5 million, plus
interest. On April 23, 1993, the Company filed an answer denying the
allegations of the complaint. The matter is pending.
Alamito Company, Docket No. ER79-97-009
On September 27, 1993, SDGE filed a motion for decision by the FERC in
Alamito Company, Docket No. ER79-97-009. This proceeding involved the proper
capital structure and rate of return for rates under which Century Power
Corporation (formerly Alamito Company) sold Company system power to SDGE
during Phase 5 of the Ten Year Agreement, from June 1, 1987 through May 31,
1989. An initial decision of an administrative law judge in January 1986,
found the Company's capital structure was inflated and its return on equity
excessive. SDGE claimed that the Company would owe Century on SDGE's behalf
up to approximately $12 million plus interest. On October 8, 1993, the
Company filed an answer opposing SDGE's motion. It was the Company's
position that the FERC's order of July 19, 1991 approving a settlement
between SDGE and Century in Docket No. ER79-97-009, as well as the Company's
and Century's mutual release of all claims against each other as part of
their Financial Restructuring, bars SDGE's claim. On December 23, 1993, the
FERC issued an order confirming that the July 19, 1991 order disposed of this
case, and denied SDGE's September 27, 1993 motion. On January 21, 1994, SDGE
requested rehearing of the FERC's order. That request is pending.
Based on consultations with counsel, the Company believes that the
resolution of the SDGE/FERC Proceedings described herein should not have a
material adverse effect, if any, on the Company's Consolidated Financial
Statements.
Tax Assessments
During the first quarter of 1993, the IRS completed an examination of
the Company's consolidated federal income tax returns for tax years 1986
through 1990. The Company has reached a tentative settlement with the IRS,
pending final approval, which would result in the Company paying additional
taxes and interest, of approximately $5.4 million, as of December 31, 1994.
The Arizona Department of Revenue has issued transaction privilege tax
assessments to the Company for the period November 1985 through May 1993
alleging that Valencia is liable for sales tax on gross income received from
coal sales, transportation, and coal-handling services during such period.
The Company protested the assessments. On March 11, 1994, the Arizona Tax
Court issued a Minute Entry granting Summary Judgment to the Arizona
Department of Revenue and upholding the validity of the assessment issued for
the period November 1985 through March 1990. The Company appealed this
decision to the Court of Appeals.
Also, the Arizona Department of Revenue has issued transaction privilege
tax assessments to the lessors from whom the Company leases certain property
alleging sales tax liability on a component of rents paid by the Company on
the Springerville Unit 1 Leases, Springerville Common Facilities Leases,
Irvington Lease and Valencia Leases. Assessments cover the period August 1,
1988 to September 30, 1993. Under the terms of the lease agreements, if the
Arizona Department of Revenue prevails the Company must indemnify the lessors
for taxes paid.
In the opinion of management, the Company has recorded, through the
Consolidated Statement of Income (Loss) in current and prior years, a
liability for the amount of federal and state taxes and interest thereon
which the Company feels is probable of incurrence as of December 31, 1994.
In the event that all or most of the Arizona Department of Revenue's proposed
assessments are sustained, additional liabilities would result. Based on the
current status of the legal proceedings, the Company believes that the
ultimate resolution of such disputes will occur over a period of one and a
half to four years. Although it is reasonably possible that the ultimate
resolution of such matters could result in a loss of up to approximately $25
million in excess of amounts accrued, management and outside tax counsel
believe that the Company has meritorious defenses to mitigate or eliminate
the assessed amounts. Based on consultations with counsel, the Company
believes that the resolution of the tax matters described herein should not
have a material adverse effect on the Company's Consolidated Financial
Statements.
NOTE 8. SCECorp/SCE LITIGATION SETTLEMENT
- ------------------------------------------
On September 5, 1990, the Company commenced an action against SCECorp
and SCE in the Superior Court of California for the County of San Diego. On
September 15, 1992, the action was settled. Under the terms of the
settlement agreement, SCECorp paid the Company $25 million in settlement of
claims of interference with the proposed merger between the Company and SDGE,
plus $15 million to cover the Company's litigation and related expenses.
Pursuant to the terms of the settlement agreement, the lawsuit was dismissed
with prejudice on September 28, 1992. In the Consolidated Statement of
Income (Loss) for the year ended December 31, 1992, the proceeds from the
settlement agreement are included as a reduction of Other Operations to the
extent of litigation expenses incurred by the Company in pursuit of its claim
(approximately $12 million as of December 31, 1992) and the remainder of the
proceeds are included as Litigation Settlement.
The Company and SCE also agreed to a ten-year power exchange agreement
beginning in 1995. Under the agreement, beginning in 1995 SCE will provide
firm system capacity of 110 MW to the Company during summer months, for which
the Company will pay an annual capacity charge of approximately $1 million
annually increasing to a maximum of approximately $2 million annually. The
Company will be entitled to schedule firm energy deliveries from SCE during
the summer of up to 36,300 MWh per month, and will be obligated to return to
SCE on an interruptible basis the same amount of energy the following winter
season.
NOTE 9. JOINTLY OWNED FACILITIES
- ---------------------------------
At December 31, 1994, the Company's interests in jointly owned
generating and transmission facilities were as follows:
Percent Plant Construction
Owned By in Work in Accumulated
Company Service Progress Depreciation
----------- -------- ------------ ------------
- Thousands of Dollars -
San Juan Units 1 and 2 50.0 $294,156 $ 1,712 $190,721
Navajo Station 7.5 77,963 6,524 36,819
Four Corners Units 4 and 5 7.0 75,725 1,520 47,565
Transmission Facilities 7.5 to 95.0 204,930 1,166 90,159
-------- ------- --------
Total $652,774 $10,922 $365,264
======== ======= ========
The Company has financed or provided funds for the above facilities and
its share of operating expenses is included in the Consolidated Statements of
Income (Loss).
NOTE 10. EMPLOYEE BENEFITS PLANS
- ---------------------------------
PENSION PLANS
The Company has noncontributory pension plans for all regular employees.
Benefits are based on years of service and the employee's average
compensation. The Company makes annual contributions to the plans that are
not greater than the maximum tax deductible contribution and not less than
the minimum funding requirement by the Employee Retirement Income Security
Act of 1974. Contributions are intended to provide for both current and
future accrued benefits.
The following table sets forth the plans' funded status and amount
recognized in the Company's Consolidated Financial Statements at December 31,
1994 and 1993. The actuarial present value of benefit obligations and
reconciliation of funding status at October 1, were as follows:
1994 1993
-------- --------
- Thousands of Dollars -
Accumulated Benefit Obligations
Vested $46,679 $51,955
Non-Vested 6,318 6,497
-------- --------
Total $52,997 $58,452
======== ========
Plan Assets at Fair Value, Principally Equity and
Fixed Income Securities $77,021 $78,478
Projected Benefit Obligations (67,393) (78,997)
-------- --------
Plan Assets in Excess of (Less Than) Projected
Benefit Obligations 9,628 (519)
Unrecognized Net (Gain) Loss from Past Experience (10,549) 568
Prior Service Cost Not Yet Recognized in Net Periodic
Pension Cost 5,198 5,404
Unrecognized Net Assets at Transition Being Amortized
Over 15 Years (2,017) (2,305)
-------- --------
Prepaid Pension Cost Included in the Balance Sheet $ 2,260 $ 3,148
======== ========
Years Ended December 31,
1994 1993 1992
-------- -------- --------
- Thousands of Dollars -
Components of Net Pension Cost
Service Cost of Benefits Earned During Period $ 2,680 $ 1,558 $ 1,390
Interest Cost of Projected Benefit Obligation 5,615 4,689 4,283
Actual (Gain) Loss on Plan Assets 492 (14,508) (4,075)
Net Amortization and Deferral (6,214) 10,187 54
-------- -------- --------
Net Periodic Pension Cost $ 2,573 $ 1,926 $ 1,652
======== ======== ========
Assumed Rates Used to Determine Pension Cost 1994 1993 1992
---- ---- ----
Discount Rate - Funding Status 8.5% 7.0% 8.0%
Average Compensation Increase 5.0 5.5 5.5
Expected Long-Term Rate of Return on Plan Assets 9.0 7.5 7.5
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Health care and life insurance benefits are provided for retired
employees. All regular employees may become eligible for those benefits if
they reach retirement age while working for the Company. Those and similar
benefits are provided through an independent administrator handling health
claims and a life insurance company that has premiums based on group rates.
The Company adopted FAS 106, Employers' Accounting for Postretirement
Benefits Other Than Pensions, in 1993. The accumulated postretirement
benefit obligation as of January 1, 1993 of $19 million is being amortized to
expense over a twenty-year period, in accordance with the provisions of FAS
106. The Company recognizes the FAS 106 periodic benefit cost as expense.
In January 1994, the Company was authorized by the ACC to recover through
rates the costs of benefits only as payments are made to retired employees;
the postretirement benefits are currently funded entirely on a pay-as-you-go
basis. Therefore, the Company has not recorded a regulatory asset for the
excess of FAS 106 expense over actual benefit payments.
1994 1993
--------- ---------
- Thousands of Dollars -
Accumulated Postretirement Benefits Obligation
Retirees $ (5,270) $ (5,832)
Fully Eligible Active Plan Participants (3,286) (3,130)
Other Active Participants (9,849) (11,295)
--------- ---------
Total Accumulated Postretirement Benefits Obligation (18,405) (20,257)
Unrecognized Net Gain from Past Experience (4,429) (786)
Unrecognized Portion of the Transition Obligation
Being Amortized Over 20 Years 17,247 18,205
--------- ---------
Accrued Postretirement Benefit Cost Included in the
Balance Sheet $ (5,587) $(2,838)
========= =========
1994 1993
--------- ---------
- Thousands of Dollars -
Components of Net Postretirement Benefit Cost
Service Cost of Benefits Earned During Period $ 931 $ 950
Interest Cost of Projected Benefit Obligation 1,395 1,491
Amortization of the Unrecognized Transition
Obligation 958 958
--------- ---------
Net Periodic Postretirement Benefit Cost $ 3,284 $ 3,399
========= =========
The accumulated postretirement benefit obligation was determined using
an 8.5% and 7% discount rate for 1994 and 1993, respectively. The health care
cost trend rates were assumed to be 10% and 11% for 1994 and 1993,
respectively, gradually declining to 5% 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, 1994 by approximately $2.8 million and the net periodic cost by
$0.4 million for the year.
ADOPTION OF FAS 112
In January 1994 the Company adopted FAS 112, Employers' Accounting for
Postemployment Benefits. Prior to 1994, postemployment benefits other than
those related to retirement benefits were recognized on a pay-as-you-go
basis. The effect of this change was an increase in postemployment benefits
expense of $0.6 million for the year ended December 31, 1994.
STOCK OPTION PLANS
On May 20, 1994, the Shareholders of the Company approved two stock
option plans, the 1994 Outside Director Stock Option Plan (Directors'
Plan) and the 1994 Omnibus Stock and Incentive Plan (Omnibus Plan).
The Directors' Plan provides for the annual grant of 6,000 non-
qualified stock options to each eligible director. Under the Directors'
Plan, the first grant on January 3, 1995 consisted of 48,000 options at an
exercise price of $3.125; these options vest ratably and become
exercisable in one-third increments on each anniversary date of the grant
and expire in 2005.
The Omnibus Plan allows the Compensation Committee, a committee
comprised solely of non-employee directors, to grant any or all of the
following types of awards to each eligible employee of the Company: stock
options, including incentive stock options, non-qualified stock options
and discounted stock options; stock appreciation rights; restricted stock;
performance units; performance shares; and dividend equivalents. The
total number of shares of the Company's stock which may be awarded under
the Omnibus Plan cannot exceed eight million.
During 1994, the Compensation Committee granted stock options
intended to qualify as incentive stock options under the Internal Revenue
Code to all employees, with exercise prices of $3.25 - $3.50. The options
vest ratably over a three year period, with the first third becoming
exercisable in 1995, and expire in 2004. The aggregate number of
shares attributable to the 1994 grants is 2,214,205.
The Company's 1985 Stock Option Plan remains in effect and the
options outstanding thereunder, which are fully exercisable, expire in
1995 to 1997. No options were exercised and the Company incurred no
expense for the 1985 Plan during 1992 through 1994. The following
summarizes the stock option transactions during the period December 31,
1992 through December 31, 1994:
Number of Exercise
Options Price
------- -----------
Options Outstanding, December 31, 1992 and 1993:
1985 Plan - Primary 23,750 $40.375 to $58.625
Dividend Equivalents 14,053 ---
Granted During 1994:
1994 Omnibus Plan 2,214,205 $3.25 to $3.50
---------
Options Outstanding, December 31, 1994 2,252,008
=========
NOTE 11. QUARTERLY FINANCIAL DATA (unaudited)
- ----------------------------------------------
First Second Third Fourth
--------- --------- --------- ---------
- Thousands of Dollars -
(except per share data)
1994
Operating Revenue $146,579 $171,097 $220,486 $153,311
Operating Income 8,259 27,951 64,310 13,882
Net Income (Loss) (14,580) 4,432 40,688 (9,800)
Net Income (Loss) per Average Share (0.09) 0.03 0.25 (0.06)
1993
Operating Revenue $136,149 $148,349 $189,432 $150,209
Operating Income 4,511 14,179 44,902 20,354
Income (Loss) from
Continuing Operations (18,522) (7,978) 22,386 (17,702)
Provision for Loss on Disposal of
Discontinued Operations - - - (4,000)
Net Income (Loss) (18,522) (7,978) 22,386 (21,702)
Net Income (Loss) per Average Share
Continuing Operations (0.12) (0.05) 0.14 (0.11)
Provision for Loss on Disposal of
Discontinued Operations - - - (0.02)
Total Net Income (Loss) per
Average Share (0.12) (0.05) 0.14 (0.13)
Due to seasonal fluctuations in sales, recognition of regulatory
disallowances and adjustments, and provisions for loss on discontinued
operations, the quarterly results are not indicative of annual operating
results. See Notes 2 and 5 regarding significant adjustments which were
recorded during the fourth quarter of 1993.
Beginning in the fourth quarter of 1994, state and city sales taxes and
similar taxes collected on revenues were removed from Operating Revenues and
Taxes Other Than Income Taxes on the Consolidated Statement of Income (Loss).
See Note 1. The tax amounts reclassified were as follows:
First Second Third Fourth
--------- --------- --------- ---------
- Thousands of Dollars -
1994
Operating Revenue - Historical $155,475 $180,671 $234,083 N/A
Total Taxes Reclassified (8,896) (9,574) (13,597) N/A
--------- --------- --------- ---------
Operating Revenue - Restated $146,579 $171,097 $220,486 N/A
========= ========= ========= =========
1993
Operating Revenue - Historical $144,424 $157,434 $201,204 $159,375
Total Taxes Reclassified (8,275) (9,085) (11,772) (9,166)
--------- --------- --------- ---------
Operating Revenue - Restated $136,149 $148,349 $189,432 $150,209
========= ========= ========= =========
NOTE 12. 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 (see below).
A reconciliation of net income (loss) to net cash flows from operating
activities for the three years ended December 31, 1994 follows:
1994 1993 1992
---------- ---------- ----------
- Thousands of Dollars -
Income (Loss) from Continuing Operations $ 20,740 $ (21,816) $ (79,022)
Adjustments to Reconcile Income (Loss) from
Continuing Operations to Net Cash Flow
Depreciation Expense 89,905 74,184 69,445
Capital Lease Rent Expense - - 13,161
Taxes Accrued 8,946 (2,303) 6,578
Deferred Income Taxes and Investment
Tax Credits - Net (4,911) (5,277) (11,194)
Deferred Fuel and Purchased Power 7,359 10,716 7,030
Litigation Settlements - Net - (5,000) (5,000)
Lease Payments Deferred 32,024 29,870 10,830
Deferred Springerville Unit 2 Costs (1,133) (5,359) (4,143)
Regulatory Disallowances and
Adjustments, Net of Amortization (13,977) 5,629 (4,501)
Loss on Financial Restructuring - - 26,669
Payments Withheld due to Payment
Moratorium - - 46,665
Other (506) 314 13,188
Changes in Assets and Liabilities which
Provided (Used) Cash Exclusive of
Changes Shown Separately
Accounts Receivable - Other (375) 1,119 4,526
Materials and Fuel 343 6,484 (629)
Unbilled Revenues 625 (1,438) (631)
Other Current Assets and Liabilities 601 (2,029) 3,034
Other Deferred Assets and Liabilities 3,975 4,237 (7,376)
---------- ---------- ----------
Net Cash Flows - Continuing Operating
Activities $ 143,616 $ 89,331 $ 88,630
========== ========== ==========
Non-cash capital transactions and financing activities of the Company
that affected recognized assets and liabilities but did not result in cash
receipts or payments during the three years ended December 31, 1994 were:
1994 1993 1992
---------- ---------- ----------
- Thousands of Dollars -
Capital Lease Obligations $ 8,107 $ 10,523 $ 926,169
Acquisition of Leased Assets - 3,385 883,607
Issuance of Common Stock and Warrants - - 197,128
Acquisition of Springerville Assets - - 30,645
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 1995 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 52 Chairman of the
Board, President and
Chief Executive Officer (a) 1989
Ira R. Adler 44 Senior Vice President and
Chief Financial Officer (b) 1988
James S. Pignatelli 51 Senior Vice President
- Business Development (c) 1994
Thomas A. Delawder 48 Vice President
- Energy Resources (d) 1985
Gary L. Ellerd 44 Vice President
- Operations (e) 1985
Steven J. Glaser 37 Vice President - Wholesale
/Retail Pricing and
System Planning (f) 1994
Thomas N. Hansen 44 Vice President
- Technical Advisor (g) 1992
Karen G. Kissinger 40 Vice President
and Controller (h) 1991
George W. Miraben 53 Vice President
- Human Resources and
Public Affairs (i) 1990
Dennis R. Nelson 44 Vice President,
General Counsel and
Corporate Secretary (j) 1991
Gerald A. O'Brien 53 Vice President
- Customer Services & Marketing (k) 1990
Romano Salvatori 57 Vice President
- Independent Power (l) 1994
Susan R. Wallach 47 Vice President
- Business Development (m) 1990
Kevin P. Larson 38 Treasurer (n) 1994
(a) Charles E. Bayless: Mr. Bayless joined the Company as Senior Vice
President and Chief Financial Officer in December 1989. He was elected
President and Chief Executive Officer in July 1990 and was elected to the Board
of Directors in June 1990. On January 28, 1992, Mr. Bayless was named Chairman
of the Board of Directors. Prior to joining the Company, he was Senior Vice
President and Chief Financial Officer of Public Service Company of New Hampshire
from 1981 through 1989.
(b) Ira R. Adler: Mr. Adler joined the Company in 1986 as Manager of Financial
Planning. In 1987 he was elected as Vice President and Treasurer of TRI, one of
the Company's investment subsidiaries, from which position he resigned in
October 1988, when he was elected Treasurer of the Company. He was elected Vice
President - Finance and Treasurer in July 1989 and was elected Senior Vice
President and Chief Financial Officer in July 1990 and President of TRI and SRI
in April 1992. Prior to joining the Company, he was Vice President - Finance of
US WEST Financial Services, Inc.
(c) James S. Pignatelli: Mr. Pignatelli joined the Company as Senior Vice
President in August 1994. Prior to joining the Company, he was President and
Chief Executive Officer from 1988 to 1993 of Mission Energy Company, a
subsidiary of SCE Corp.
(d) Thomas A. Delawder: Mr. Delawder joined the Company in 1974 and thereafter
served in various engineering and operations positions. In April 1985 he was
named Manager, Systems Operations and was elected Vice President - Power Supply
and System Control in November 1985. In February 1991, he became Vice President
- - Engineering and Power Supply and in January 1992 he became Vice President -
System Operations. In 1994, he became Vice President - Energy Resources.
(e) Gary L. Ellerd: Mr. Ellerd joined the Company as Vice President and
Controller in January 1985. He was elected Vice President - Services and Chief
Information Officer in January 1991 and in January 1992 he became Vice President
- - Corporate Information Services and Chief Information Officer. In 1994, he was
named Vice President - Retail Customers. In 1995, he was named Vice President
- - Operations.
(f) Steven J. Glaser: Mr. Glaser joined the Company in 1990 as a Senior
Attorney in charge of Regulatory Affairs. He was Manager of the Company's Legal
department from 1992 to 1994, and Manager of Contracts and Wholesale Marketing
from 1994 until elected Vice President - Business Development. In 1995, he was
named Vice President - Wholesale/Retail Pricing and System Planning.
(g) Thomas N. Hansen: Mr. Hansen joined the Company in December 1992 as Vice
President - Power Production. Prior to joining the Company, Mr. Hansen was
Century's Vice President - Operations from 1989 and Plant Manager at
Springerville from 1987 through 1988. In 1994, he was named Vice President -
Technical Advisor.
(h) Karen G. Kissinger: Ms. Kissinger joined the Company as Vice President
and Controller in January 1991. Prior to joining the Company, she was a Manager
with Deloitte & Touche from 1986 through 1989 and a Senior Manager through 1990.
(i) George W. Miraben: Mr. Miraben was elected Vice President, Public Affairs,
effective March 1990, and named Vice President - Human Resources and Public
Affairs in 1994. Prior to joining the Company, he was Director of External
Affairs for US WEST Communications' Arizona operation from 1981 through March
1990.
(j) Dennis R. Nelson: Mr. Nelson joined the Company in 1976. He was manager
of the Legal Department from 1985 to 1990. He was elected Vice President,
General Counsel and Corporate Secretary in January 1991.
(k) Gerald A. O'Brien: Mr. O'Brien joined the Company in 1961. Formerly
Manager, Customer and Corporate Services, he was elected Vice President
- - Customer Services and Human Resources in May 1990 and in January 1992 he
became Vice President - Customer Operations. In 1994, he was named Vice
President - Operations Support. In 1995, he was named Vice President
- - Customer Services & Marketing.
(l) Romano Salvatori: Mr. Salvatori joined the Company as Vice President -
Independent Power in December 1994. Prior to joining the Company, he was Deputy
General Manager, Power Generation Business Unit and General Manager, Power
Generation Strategic Affairs Division of Westinghouse Electric Corporation from
1990 to 1994, and General Manager, Power Generation Commercial Operations
Division from 1990 to 1993. In 1995, he was named President of Nations Energy
Corporation, in addition to his responsibilities as Vice President - Independent
Power.
(m) Susan R. Wallach: Ms. Wallach joined the Company in 1974. Formerly
Manager of Accounting Services and Assistant Controller, she was elected Vice
President and Treasurer in July 1990. She was named Vice President - Future
Marketing/Sales/Planning in 1994. In 1995, she was named Vice President -
Business Development.
(n) Kevin P. Larson: Mr. Larson joined the Company in 1985 and thereafter held
various positions in its finance department and at the Company's investment
subsidiaries. In January 1991, he was elected Assistant Treasurer of the
Company and named Manager of Financial Programs. He was elected Treasurer in
August 1994.
ITEM 11. - EXECUTIVE COMPENSATION
Information concerning Executive Compensation is contained under Executive
Compensation and Other Information in the Company's Proxy Statement relating to
the 1995 Annual Meeting of Shareholders, which information is incorporated
herein by reference.
ITEM 12. - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
GENERAL
At March 6, 1995, the Company had outstanding 160,723,702 shares of Common
Stock. As of March 6, 1995, 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 1995 Annual Meeting of
Shareholders, which information is incorporated herein by reference.
SECURITY OWNERSHIP OF MANAGEMENT
Information concerning the security ownership of the Directors and
Executive Officers of the Company is contained under Security Ownership of
Certain Beneficial Owners in the Company's Proxy Statement relating to the 1995
Annual Meeting of Shareholders, which information is incorporated herein by
references.
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, 1994 and 1993 and for Each
of the Three Years in the Period Ended
December 31, 1994.
Independent Auditors' Report 27
Consolidated Statements of Income (Loss) 28
Consolidated Balance Sheets 29
Consolidated Statements of Capitalization 30
Consolidated Statements of Cash Flows 31
Consolidated Statements of Changes in Stockholders'
Equity (Deficit) 32
Notes to Consolidated Financial Statements 33
2. Supplemental Consolidated Schedules for the Years
Ended December 31, 1992 to 1994.
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 60
(b) Reports on Form 8-K.
The Company has not filed any Current Reports on Form 8-K during the last
quarter of the period covered in this report.
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 8, 1995 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 8, 1995 Charles E. Bayless*
-------------------------------------
Charles E. Bayless
Chairman of the Board, President and
Principal Executive Officer
Date: March 8, 1995 Ira R. Adler
------------------------------------
Ira R. Adler
Principal Financial Officer
Date: March 8, 1995 Karen G. Kissinger*
------------------------------------
Karen G. Kissinger
Principal Accounting Officer
Date: March 8, 1995 Jose Canchola*
------------------------------------
Jose Canchola
Director
Date: March 8, 1995 Kathryn N. Dusenberry*
------------------------------------
Kathryn N. Dusenberry
Director
Date: March 8, 1995 John Jeter*
------------------------------------
John Jeter
Director
Date: March 8, 1995 R. B. O'Rielly*
------------------------------------
R. B. O'Rielly
Director
Date: March 8, 1995 Martha R. Seger*
------------------------------------
Martha R. Seger
Director
Date: March 8, 1995 Donald G. Shropshire*
------------------------------------
Donald G. Shropshire
Director
Date: March 8, 1995 H. Wilson Sundt*
------------------------------------
H. Wilson Sundt
Director
Date: March 8, 1995 By Ira R. Adler
---------------------------------
Ira R. Adler
as attorney-in-fact for each
of the persons indicated
EXHIBIT INDEX
*3(a) -- Restated Articles of Incorporation, filed with the ACC on August
11, 1994. (Form 10-Q for the quarter ended September 30, 1994, File
No. 1-5924--Exhibit 3).)
*3(b) -- Bylaws of the Registrant, as amended May 20, 1994. (Form 10-Q
for the quarter ended June 30, 1994, File No. 1-5924--Exhibit 3).)
*4(a)(1) -- Indenture dated as of April 1, 1941, to The Chase National Bank
of the City of New York, as Trustee. (Form S-7, File No. 2-59906--
Exhibit 2(b)(1).)
*4(a)(2) -- First Supplemental Indenture, dated as of October 1, 1946. (Form
S-7, File No. 2-59906--Exhibit 2(b)(2).)
*4(a)(3) -- Second Supplemental Indenture dated as of October 1, 1947.
(Form S-7, File No. 2-59906--Exhibit 2(b)(3).)
*4(a)(4) -- Third Supplemental Indenture, dated as of April 1, 1949. (Form
S-7, File No. 2-59906--Exhibit 2(b)(4).)
*4(a)(5) -- Fourth Supplemental Indenture, dated as of December 1, 1952.
(Form S-7, File No. 2-59906--Exhibit 2(b)(5).)
*4(a)(6) -- Fifth Supplemental Indenture, dated as of January 1, 1955.
(Form S-7, File No. 2-59906--Exhibit 2(b)(6).)
*4(a)(7) -- Sixth Supplemental Indenture, dated as of January 1, 1958.
(Form S-7, File No. 2-59906--Exhibit 2(b)(7).)
*4(a)(8) -- Seventh Supplemental Indenture, dated as of November 1, 1959.
(Form S-7, File No. 2-59906--Exhibit 2(b)(8).)
*4(a)(9) -- Eighth Supplemental Indenture, dated as of November 1, 1961.
(Form S-7, File No. 2-59906--Exhibit 2(b)(9).)
*4(a)(10)-- Ninth Supplemental Indenture, dated as of February 20, 1964.
(Form S-7, File No. 2-59906--Exhibit 2(b)(10).)
*4(a)(11)-- Tenth Supplemental Indenture, dated as of February 1, 1965.
(Form S-7, File No. 2-59906--Exhibit 2(b)(11).)
*4(a)(12)-- Eleventh Supplemental Indenture, dated as of February 1, 1966.
(Form S-7, File No. 2-59906--Exhibit 2(b)(12).)
*4(a)(13)-- Twelfth Supplemental Indenture, dated as of November 1, 1969.
(Form S-7, File No. 2-59906--Exhibit 2(b)(13).)
*4(a)(14)-- Thirteenth Supplemental Indenture, dated as of January 20, 1970.
(Form S-7, File No. 2-59906--Exhibit 2(b)(14).)
*4(a)(15)-- Fourteenth Supplemental Indenture, dated as of September 1,
1971. (Form S-7, File No. 2-59906--Exhibit 2(b)(15).)
*4(a)(16)-- Fifteenth Supplemental Indenture, dated as of March 1, 1972.
(Form S-7, File No. 2-59906--Exhibit 2(b)(16).)
*4(a)(17)-- Sixteenth Supplemental Indenture, dated as of May 1, 1973. (Form
S-7, File No. 2-59906--Exhibit 2(b)(17).)
*4(a)(18)-- Seventeenth Supplemental Indenture, dated as of November 1,
1975. (Form S-7, File No. 2-59906--Exhibit 2(b)(18).)
*4(a)(19)-- Eighteenth Supplemental Indenture, dated as of November 1, 1975.
(Form S-7, File No. 2-59906--Exhibit 2(b)(19).)
*4(a)(20)-- Nineteenth Supplemental Indenture, dated as of July 1, 1976.
(Form S-7, File No. 2-59906--Exhibit 2(b)(20).)
*4(a)(21)-- Twentieth Supplemental Indenture, dated as of October 1, 1977.
(Form S-7, File No. 2-59906--Exhibit 2(b)(21).)
*4(a)(22)-- Twenty-first Supplemental Indenture, dated as of November 1,
1977. (Form 10-K for year ended December 31, 1980, File No. 1-5924--
Exhibit 4(v).)
*4(a)(23)-- Twenty-second Supplemental Indenture, dated as of January 1,
1978. (Form 10-K for year ended December 31, 1980, File No. 1-5924--
Exhibit 4(w).)
*4(a)(24)-- Twenty-third Supplemental Indenture, dated as of July 1, 1980.
(Form 10-K for year ended December 31, 1980, File No. 1-5924--Exhibit
4(x).)
*4(a)(25)-- Twenty-fourth Supplemental Indenture, dated as of October 1,
1980. (Form 10-K for year ended December 31, 1980, File No. 1-5924--
Exhibit 4(y).)
*4(a)(26)-- Twenty-fifth Supplemental Indenture, dated as of April 1, 1981.
(Form 10-Q for quarter ended March 31, 1981, File No. 1-5924--Exhibit
4(a).)
*4(a)(27)-- Twenty-sixth Supplemental Indenture, dated as of April 1, 1981.
(Form 10-Q for quarter ended March 31, 1981, File No. 1-5924--Exhibit
4(b).)
*4(a)(28)-- Twenty-seventh Supplemental Indenture, dated as of October 1,
1981. (Form 10-Q for quarter ended September 30, 1982, File No. 1-5924-
-Exhibit 4(c).)
*4(a)(29)-- Twenty-eighth Supplemental Indenture, dated as of June 1, 1990.
(Form 10-Q for quarter ended June 30, 1990, File No. 1-5924--Exhibit
4(a)(1).)
*4(a)(30)-- Twenty-ninth Supplemental Indenture, dated as of December 1,
1992. (Form S-1, Registration No. 33-55732--Exhibit 4(a)(30).)
*4(a)(31)-- Thirtieth Supplemental Indenture, dated as of December 1, 1992.
(Form S-1, Registration No. 33-55732--Exhibit 4(a)(31).)
*4(b)(1) -- Installment Sale Agreement, dated as of December 1, 1973, among
the City of Farmington, New Mexico, Public Service Company of New
Mexico and the Registrant. (Form 8-K for the month of January 1974,
File No. 0-269--Exhibit 3.)
*4(b)(2) -- Ordinance No. 486, adopted December 17, 1973, of the City of
Farmington, New Mexico. (Form 8-K for the month of January 1974, File
No. 0-269--Exhibit 4.)
*4(c)(1) -- Loan Agreement, dated as of September 15, 1981, between the
Industrial Development Authority of the County of Apache, Arizona and
the Registrant, relating to Floating Rate Monthly Demand Pollution
Control Revenue Bonds, 1981 Series B (Tucson Electric Power Company
Project). (Form 10-K for year ended December 31, 1981, File No. 1-
5924--Exhibit 4(d)(1).)
*4(c)(2) -- Indenture of Trust, dated as of September 15, 1981, between the
Apache County Authority and Morgan Guaranty Trust Company of New York,
authorizing Floating Rate Monthly Demand Pollution Control Revenue
Bonds, 1981 Series B (Tucson Electric Power Company Project). (Form
10-K for year ended December 31, 1981, File No. 1-5924--Exhibit
4(d)(2).)
*4(d)(1) -- Second Supplemental Loan Agreement, dated as of October 1, 1981,
between the Apache County Authority and the Registrant, relating to
Floating Rate Monthly Demand Pollution Control Revenue Bonds, 1981
Series B (Tucson Electric Power Company Project). (Form 10-K for year
ended December 31, 1982, File No. 1-5924--Exhibit 4(f)(1).)
*4(d)(2) -- Second Supplemental Indenture, dated as of October 1, 1981,
between the Apache County Authority and Morgan Guaranty, relating to
Floating Rate Monthly Demand Pollution Control Revenue Bonds, 1981
Series B (Tucson Electric Power Company Project). (Form 10-K for year
ended December 31, 1982, File No. 1-5924--Exhibit 4(f)(2).)
*4(d)(3) -- Third Supplemental Loan Agreement, dated as of December 1, 1985,
between the Apache County Authority and the Registrant, relating to
Floating Rate Monthly Demand Pollution Control Revenue Bonds, 1981
Series B (Tucson Electric Power Company Project). (Form 10-K for the
year ended December 31, 1987, File No. 1-5924--Exhibit 4(d)(3).)
*4(d)(4) -- Third Supplemental Indenture, dated as of December 1, 1985,
between the Apache County Authority and Morgan Guaranty, relating to
Floating Rate Monthly Demand Pollution Control Revenue Bonds, 1981
Series B (Tucson Electric Power Company Project). (Form 10-K for the
year ended December 31, 1987, File No. 1-5924--Exhibit 4(d)(4).)
*4(d)(5) -- Fourth Supplemental Indenture of Trust, dated as of March 31,
1992, between the Apache County Authority and Morgan Guaranty,
relating to Pollution Control Revenue Bonds, 1981 Series B (Tucson
Electric Power Company Project). (Form S-4, Registration No. 33-52860-
-Exhibit 4(d)(5).)
*4(d)(6) -- Fourth Supplemental Loan Agreement, dated as of March 31, 1992,
between the Apache County Authority and the Registrant, relating to
Pollution Control Revenue Bonds, 1981 Series B (Tucson Electric Power
Company Project). (Form S-4, Registration No. 33-52860--Exhibit
4(d)(6).)
*4(e)(1) -- Loan Agreement, dated as of October 1, 1981, between The
Industrial Development Authority of the County of Pima, Arizona (the
Pima County Authority) and the Registrant, relating to Floating Rate
Monthly Demand Pollution Control Revenue Bonds, 1981 Series A (Tucson
Electric Power Company Project). (Form 10-K for year ended December
31, 1981, File No. 1-5924--Exhibit 4(f)(1).)
*4(e)(2) -- Indenture of Trust, dated as of October 1, 1981, between the
Pima County Authority and Morgan Guaranty, authorizing Floating Rate
Monthly Demand Pollution Control Revenue Bonds, 1981 Series A (Tucson
Electric Power Company Project). (Form 10-K for year ended December
31, 1981, File No. 1-5924--Exhibit 4(f)(2).)
*4(f)(1) -- Loan Agreement, dated as of July 1, 1982, between the Pima
County Authority and the Registrant, relating to Floating Rate Monthly
Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson
Electric Power Company General Project). (Form 10-Q for quarter ended
June 30, 1982, File No. 1-5924--Exhibit 4(a).)
*4(f)(2) -- Indenture of Trust, dated as of July 1, 1982, between the Pima
County Authority and Morgan Guaranty, authorizing Floating Rate
Monthly Demand Industrial Development Revenue Bonds, 1982 Series A
(Tucson Electric Power Company General Project). (Form 10-Q for
quarter ended June 30, 1982, File No. 1-5924--Exhibit 4(b).)
*4(f)(3) -- First Supplemental Loan Agreement, dated as of March 31, 1992,
between the Pima County Authority and the Registrant relating to
Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric
Power Company General Project). (Form S-4, Registration No. 33-52860-
-Exhibit 4(f)(3).)
*4(f)(4) -- First Supplemental Indenture of Trust, dated as of March 31,
1992, between the Pima County Authority and Morgan Guaranty relating
to Industrial Development Revenue Bonds, 1982 Series A (Tucson
Electric Power Company General Project). (Form S-4, Registration No.
33-52860--Exhibit 4(f)(4).)
*4(g)(1) -- Loan Agreement, dated as of July 1, 1982, between the Pima
County Authority and the Registrant, relating to Quarterly Tender
Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric
Power General Project). (Form 10-Q for quarter ended June 30, 1982,
File No. 1-5924--Exhibit 4(c).)
*4(g)(2) -- Indenture of Trust, dated as of July 1, 1982, between the Pima
County Authority and Morgan Guaranty, authorizing Quarterly Tender
Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric
Power Company General Project). (Form 10-Q for quarter ended June 30,
1982, File No. 1-5924--Exhibit 4(d).)
*4(g)(3) -- First Supplemental Loan Agreement, dated as of March 31, 1992,
between the Pima County Authority and the Registrant relating to
Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric
Power Company General Project). (Form S-4, Registration No. 33-52860-
-Exhibit 4(g)(3).)
*4(g)(4) -- First Supplemental Indenture of Trust, dated as of March 31,
1992, between the Pima County Authority and Morgan Guaranty relating
to Industrial Development Revenue Bonds, 1982 Series A (Tucson
Electric Power Company General Project). (Form S-4, Registration No.
33-52860--Exhibit 4(g)(4).)
*4(h)(1) -- Loan Agreement, dated as of October 1, 1982, between the Pima
County Authority and the Registrant relating to Floating Rate Monthly
Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson
Electric Power Company Irvington Project). (Form 10-Q for quarter
ended September 30, 1982, File No. 1-5924--Exhibit 4(a).)
*4(h)(2) -- Indenture of Trust, dated as of October 1, 1982, between the
Pima County Authority and Morgan Guaranty authorizing Floating Rate
Monthly Demand Industrial Development Revenue Bonds, 1982 Series A
(Tucson Electric Power Company Irvington Project). (Form 10-Q for
quarter ended September 30, 1982, File No. 1-5924--Exhibit 4(b).)
*4(h)(3) -- First Supplemental Loan Agreement, dated as of March 31, 1992,
between the Pima County Authority and the Registrant relating to
Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric
Power Company Irvington Project). (Form S-4, Registration No. 33-
52860--Exhibit 4(h)(3).)
*4(h)(4) -- First Supplemental Indenture of Trust, dated as of March 31,
1992, between the Pima County Authority and Morgan Guaranty relating
to Industrial Development Revenue Bonds, 1982 Series A (Tucson
Electric Power Company Irvington Project). (Form S-4, Registration No.
33-52860--Exhibit 4(h)(4).)
*4(i)(1) -- Loan Agreement, dated as of December 1, 1982, between the Pima
County Authority and the Registrant relating to Floating Rate Monthly
Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson
Electric Power Company Projects). (Form 10-K for year ended December
31, 1982, File No. 1-5924--Exhibit 4(k)(1).)
*4(i)(2) -- Indenture of Trust, dated as of December 1, 1982, between the
Pima County Authority and Morgan Guaranty authorizing Floating Rate
Monthly Demand Industrial Development Revenue Bonds, 1982 Series A
(Tucson Electric Power Company Projects). (Form 10-K for year ended
December 31, 1982, File No. 1-5924--Exhibit 4(k)(2).)
*4(i)(3) -- First Supplemental Loan Agreement, dated as of March 31, 1992,
between the Pima County Authority and the Registrant relating to
Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric
Power Company Projects). (Form S-4, Registration No. 33-52860--Exhibit
4(i)(3).)
*4(i)(4) -- First Supplemental Indenture of Trust, dated as of March 31,
1992, between the Pima County Authority and Morgan Guaranty relating
to Industrial Development Revenue Bonds, 1982 Series A (Tucson
Electric Power Company Projects). (Form S-4, Registration No. 33-52860-
-Exhibit 4(i)(4).)
*4(j)(1) -- Loan Agreement, dated as of March 1, 1983, between the Pima
County Authority and the Registrant relating to Floating Rate Monthly
Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson
Electric Power Company General Project). (Form 10-Q for the quarter
ended March 31, 1983, File No. 1-5924--Exhibit 4(a).)
*4(j)(2) -- Indenture of Trust, dated as of March 1, 1983, between the Pima
County Authority and Morgan Guaranty authorizing Floating Rate Monthly
Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson
Electric Power Company General Project). (Form 10-Q for the quarter
ended March 31, 1983, File No. 1-5924--Exhibit 4(b).)
*4(j)(3) -- First Supplemental Loan Agreement, dated as of March 31, 1992,
between the Pima County Authority and the Registrant relating to
Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric
Power Company General Project) (Form S-4 dated October 2, 1992,
Registration No. 33-52860--Exhibit 4(j)(3).)
*4(j)(4) -- First Supplemental Indenture of Trust, dated as of March 31,
1992, between the Pima County Authority and Morgan Guaranty relating
to Industrial Development Revenue Bonds, 1983 Series A (Tucson
Electric Power Company General Project) (Form S-4 dated October 2,
1992, Registration No. 33-52860--Exhibit 4(j)(4).)
*4(k)(1) -- Loan Agreement, dated as of December 1, 1983, between the Apache
County Authority and the Registrant relating to Floating Rate Monthly
Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson
Electric Power Company Springerville Project). (Form 10-K for year
ended December 31, 1983, File No. 1-5924--Exhibit 4(l)(1).)
*4(k)(2) -- Indenture of Trust, dated as of December 1, 1983, between the
Apache County Authority and Morgan Guaranty authorizing Floating Rate
Monthly Demand Industrial Development Revenue Bonds, 1983 Series A
(Tucson Electric Power Company Springerville Project). (Form 10-K for
year ended December 31, 1983, File No. 1-5924--Exhibit 4(l)(2).)
*4(k)(3) -- First Supplemental Loan Agreement, dated as of December 1, 1985,
between the Apache County Authority and the Registrant relating to
Floating Rate Monthly Demand Industrial Development Revenue Bonds,
1983 Series A (Tucson Electric Power Company Springerville Project).
(Form 10-K for the year ended December 31, 1987, File No. 1-5924--
Exhibit 4(k)(3).)
*4(k)(4) -- First Supplemental Indenture, dated as of December 1, 1985,
between the Apache County Authority and Morgan Guaranty relating to
Floating Rate Monthly Demand Industrial Development Revenue Bonds,
1983 Series A (Tucson Electric Power Company Springerville Project).
(Form 10-K for the year ended December 31, 1987, File No. 1-5924--
Exhibit 4(k)(4).)
*4(k)(5) -- Second Supplemental Loan Agreement, dated as of March 31, 1992,
between the Apache County Authority and the Registrant relating to
Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric
Power Company Springerville Project). (Form S-4, Registration No. 33-
52860--Exhibit 4(k)(5).)
*4(k)(6) -- Second Supplemental Indenture of Trust, dated as of March 31,
1992, between the Apache County Authority and Morgan Guaranty relating
to Industrial Development Revenue Bonds, 1983 Series A (Tucson
Electric Power Company Springerville Project). (Form S-4,
Registration No. 33-52860--Exhibit 4(k)(6).)
*4(l)(1) -- Loan Agreement, dated as of December 1, 1983, between the Apache
County Authority and the Registrant relating to Variable Rate Demand
Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric
Power Company Springerville Project). (Form 10-K for year ended
December 31, 1983, File No. 1-5924--Exhibit 4(m)(1).)
*4(l)(2) -- Indenture of Trust, dated as of December 1, 1983, between the
Apache County Authority and Morgan Guaranty authorizing Variable Rate
Demand Industrial Development Revenue Bonds, 1983 Series B (Tucson
Electric Power Company Springerville Project). (Form 10-K for year
ended December 31, 1983, File No. 1-5924--Exhibit 4(m)(2).)
*4(l)(3) -- First Supplemental Loan Agreement, dated as of December 1, 1985,
between the Apache County Authority and the Registrant relating to
Floating Rate Monthly Demand Industrial Development Revenue Bonds,
1983 Series B (Tucson Electric Power Company Springerville Project).
(Form 10-K for the year ended December 31, 1987, File No. 1-5924--
Exhibit 4(l)(3).)
*4(l)(4) -- First Supplemental Indenture, dated as of December 1, 1985,
between the Apache County Authority and Morgan Guaranty relating to
Floating Rate Monthly Demand Industrial Development Revenue Bonds,
1983 Series B (Tucson Electric Power Company Springerville Project).
(Form 10-K for the year ended December 31, 1987, File No. 1-5924--
Exhibit 4(l)(4).)
*4(l)(5) -- Second Supplemental Loan Agreement, dated as of March 31, 1992,
between the Apache County Authority and the Registrant relating to
Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric
Power Company Springerville Project). (Form S-4, Registration No. 33-
52860--Exhibit 4(l)(5).)
*4(l)(6) -- Second Supplemental Indenture of Trust, dated as of March 31,
1992, between the Apache County Authority and Morgan Guaranty relating
to Industrial Development Revenue Bonds, 1983 Series B (Tucson
Electric Power Company Springerville Project). (Form S-4,
Registration No. 33-52860--Exhibit 4(l)(6).)
*4(m)(1) -- Loan Agreement, dated as of December 1, 1983, between the Apache
County Authority and the Registrant relating to Variable Rate Demand
Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric
Power Company Springerville Project). (Form 10-K for year ended
December 31, 1983, File No. 1-5924--Exhibit 4(n)(1).)
*4(m)(2) -- Indenture of Trust, dated as of December 1, 1983, between the
Apache County Authority and Morgan Guaranty authorizing Variable Rate
Demand Industrial Development Revenue Bonds, 1983 Series C (Tucson
Electric Power Company Springerville Project). (Form 10-K for year
ended December 31, 1983, File No. 1-5924--Exhibit 4(n)(2).)
*4(m)(3) -- First Supplemental Loan Agreement, dated as of December 1, 1985,
between the Apache County Authority and the Registrant relating to
Floating Rate Monthly Demand Industrial Development Revenue Bonds,
1983 Series C (Tucson Electric Power Company Springerville Project).
(Form 10-K for the year ended December 31, 1987, File No. 1-5924--
Exhibit 4(m)(3).)
*4(m)(4) -- First Supplemental Indenture, dated as of December 1, 1985,
between the Apache County Authority and Morgan Guaranty relating to
Floating Rate Monthly Demand Industrial Development Revenue Bonds,
1983 Series C (Tucson Electric Power Company Springerville Project).
(Form 10-K for the year ended December 31, 1987, File No. 1-5924--
Exhibit 4(m)(4).)
*4(m)(5) -- Second Supplemental Loan Agreement, dated as of March 31, 1992,
between the Apache County Authority and the Registrant relating to
Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric
Power Company Springerville Project). (Form S-4, Registration No. 33-
52860--Exhibit 4(m)(5).)
*4(m)(6) -- Second Supplemental Indenture of Trust, dated as of March 31,
1992, between the Apache County Authority and Morgan Guaranty relating
to Industrial Development Revenue Bonds, 1983 Series C (Tucson
Electric Power Company Springerville Project). (Form S-4,
Registration No. 33-52860--Exhibit 4(m)(6).)
*4(n) -- Reimbursement Agreement, dated as of September 15, 1981, as
amended, between the Registrant and Manufacturers Hanover Trust
Company. (Form 10-K for the year ended December 31, 1984, File No. 1-
5924--Exhibit 4(o)(4).)
*4(o)(1) -- Loan Agreement, dated as of December 1, 1985, between the Apache
County Authority and the Registrant relating to Variable Rate Demand
Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric
Power Company Springerville Project). (Form 10-K for the year ended
December 31, 1985, File No. 1-5924---Exhibit 4(r)(1).)
*4(o)(2) -- Indenture of Trust, dated as of December 1, 1985, between the
Apache County Authority and Morgan Guaranty authorizing Variable Rate
Demand Industrial Development Revenue Bonds, 1985 Series A (Tucson
Electric Power Company Springerville Project). (Form 10-K for the year
ended December 31, 1985, File No. 1-5924--Exhibit 4(r)(2).)
*4(o)(3) -- First Supplemental Loan Agreement, dated as of March 31, 1992,
between the Apache County Authority and the Registrant relating to
Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric
Power Company Springerville Project). (Form S-4, Registration No. 33-
52860--Exhibit 4(o)(3).)
*4(o)(4) -- First Supplemental Indenture of Trust, dated as of March 31,
1992, between the Apache County Authority and Morgan Guaranty relating
to Industrial Development Revenue Bonds, 1985 Series A (Tucson
Electric Power Company Springerville Project). (Form S-4,
Registration No. 33-52860--Exhibit 4(o)(4).)
*4(p)(1) -- Loan Agreement, dated as of February 22, 1991, between the
Industrial Development Authority of the County of Pima and the
Registrant, amending and restating the Loan Agreement, dated as of May
1, 1990, relating to Industrial Development Revenue Bonds, 1990 Series
A (Tucson Electric Power Company Project). (Form 10-K for the year
ended December 31, 1990, File No. 1-5924--Exhibit 4(p)(1).)
*4(p)(2) -- Indenture of Trust, dated as of February 22, 1991, between the
Industrial Development Authority of the County of Pima and Texas
Commerce Bank National Association, amending and restating the
Indenture of Trust, dated as of May 1, 1990, authorizing Industrial
Development Revenue Bonds, 1990 Series A (Tucson Electric Power
Company Project). (Form 10-K for the year ended December 31, 1990,
File No. 1-5924--Exhibit 4(p)(2).)
*4(q) -- Warrant Agreement and Form of Warrant, dated as of December 15,
1992. (Form S-1, Registration No. 33-55732--Exhibit 4(q).)
*4(r)(1) -- Indenture of Mortgage and Deed of Trust dated as of December 1,
1992, to Bank of Montreal Trust Company, Trustee. (Form S-1,
Registration No. 33-55732--Exhibit 4(r)(1).)
*4(r)(2) -- Supplemental Indenture No. 1 creating a series of bonds
designated Second Mortgage Bonds, Collateral Series A, dated as of
December 1, 1992. (Form S-1, Registration No. 33-55732-Exhibit
4(r)(2).)
*+10(a) -- 1985 Stock Option Plan of the Registrant. (Form 10-K for the
year ended December 31, 1985, File No. 1-5924--Exhibit 10(b).)
*+10(b) -- 1987 Phantom Stock Plan of the Registrant. (Form 10-K for the
year ended December 31, 1987, File No. 1-5924--Exhibit 10(c).)
*10(c)(1)-- Lease Agreements, dated as of December 1, 1984, between Valencia
Energy Company ("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 10(j)(3).)
*10(e)(4)-- Loan Agreement, dated as of January 14, 1988, between the Pima
County Authority and Wilmington Trust Company and William J. Wade in
their respective individual capacities as expressly stated, but
otherwise solely as Owner Trustee and Co-Trustee, respectively, under
and pursuant to a Trust Agreement, dated as of November 15, 1987, with
Ford Motor Credit Company as Trustor and Debtor relating to Industrial
Development Lease Obligation Refunding Revenue Bonds, 1988 Series A
(the Registrant's Irvington Project). (Form 10-K for the year ended
December 31, 1987, File No. 1-5924--Exhibit 10(j)(4).)
*10(e)(5)-- Indenture of Trust, dated as of January 14, 1988, between the
Pima County Authority and Morgan Guaranty authorizing Industrial
Development Lease Obligation Refunding Revenue Bonds, 1988 Series A
(Tucson Electric Power Company Irvington Project). (Form 10-K for the
year ended December 31, 1987, File No. 1-5924--Exhibit 10(j)(5).)
*10(e)(6)-- Lease Amendment No. 1, dated as of May 1, 1989, between the
Registrant, Wilmington Trust Company and William J. Wade as Owner
Trustee and Co-trustee, respectively under a Trust Agreement dated as
of November 15, 1987 with Ford Motor Credit Company. (Form 10-K for
the year ended December 31,1990, File No. 1-5924--Exhibit 10(i)(6).)
*10(e)(7)-- Lease Supplement, dated as of January 1, 1991, between the
Registrant, Wilmington Trust Company and William J. Wade as Owner
Trustee and Co-Trustee, respectively, under a Trust Agreement dated as
of November 15, 1987, with Ford. (Form 10K for the year ended December
31, 1991, File No. 1-5924--Exhibit 10(i)(8).)
*10(e)(8)-- Lease Supplement, dated as of March 1, 1991, between the
Registrant, Wilmington Trust Company and William J. Wade as Owner
Trustee and Co-Trustee, respectively, under a Trust Agreement dated as
of November 15, 1987, with Ford. (Form 10-K for the year ended
December 31, 1991, File No. 1-5924--Exhibit 10(i)(9).)
*10(e)(9)-- Lease Supplement No. 4, dated as of December 1, 1991, between
the Registrant, Wilmington Trust Company and William J. Wade as Owner
Trustee and Co-Trustee, respectively, under a Trust Agreement dated as
of November 15, 1987, with Ford. (Form 10-K for the year ended
December 31, 1991, File No. 1-5924--Exhibit 10(i)(10).)
*10(e)(10) -- Supplemental Indenture No. 1, dated as of December 1, 1991,
between the Pima County Authority and Morgan Guaranty relating to
Industrial Lease Development Obligation Revenue Project). (Form 10-K
for the year ended December 31, 1991, File No. 1-5924--Exhibit
10(i)(11).)
*10(e)(11) -- Restructuring Commitment Agreement, dated as of June 30, 1992,
among the Registrant, as Lessee, Ford Motor Credit Company, as Owner
Participant, Wilmington Trust Company and William J. Wade, as Owner
Trustee and Co-Trustee, respectively, and Morgan Guaranty, as
Indenture Trustee and Refunding Trustee, relating to the restructuring
of the Registrant's lease of Unit 4 at the Irvington Generating
Station. (Form S-4, Registration No. 33-52860--Exhibit 10(i)(12).)
*10(e)(12) -- Amendment No. 1, dated as of December 15, 1992, to Amended and
Restated Participation Agreement, dated as of November 15, 1987, among
the Registrant, as Lessee, Ford Motor Credit Company, as Owner
Participant, Wilmington Trust Company and William J. Wade, as Owner
Trustee and Co-Trustee, respectively, Financial Security Assurance
Inc., as Surety, and Morgan Guaranty, as Indenture Trustee. (Form S-
1, Registration No. 33-55732--Exhibit 10(h)(12).)
*10(e)(13) -- Amended and Restated Lease, dated as of December 15, 1992,
between the Registrant, as Lessee and Wilmington Trust Company and
William J. Wade, as Owner Trustee and Co-Trustee, respectively, as
Lessor. (Form S-1, Registration No. 33-55732--Exhibit 10(h)(13).)
*10(e)(14) -- Amended and Restated Tax Indemnity Agreement, dated as of
December 15, 1992, between the Registrant, as Lessee, and Ford Motor
Credit Company, as Owner Participant. (Form S-1, Registration No. 33-
55732--Exhibit 10(h)(14).)
*10(f) -- Power Sale Agreement for the years 1990 to 2011, dated as of
March 10, 1988, between the Registrant and Salt River Project
Agricultural Improvement and Power District. (Form 10-K for the year
ended December 31, 1987, File No. 1-5924--Exhibit 10(k).)
*+10(g)(1) -- Employment Agreements between the Registrant and Thomas A.
Delawder and Gary L. Ellerd. (Form 10-K for the year ended December
31, 1987, File No. 1-5924--Exhibit 10(l).)
*+10(g)(2) -- Employment Agreements between the Registrant and currently in
effect with Ira R. Adler, Charles E. Bayless, Karen G. Kissinger,
George W. Miraben, Dennis R. Nelson, Gerald A. O'Brien, Susan R.
Wallach, James S. Pignatelli and Steven J. Glaser. (Form 10-K for the
year ended December 31, 1989, File No. 1-5924--Exhibit 10(n)(2).)
+10(g)(3)-- Release and Settlement Agreement between the Registrant and
Frederic N. Finney.
+10(g)(4)-- Release and Settlement Agreement between the Registrant and
Norman B. Johnsen.
*10(g)(5)-- Letter, dated February 25, 1992, from Dr. Martha R. Seger to the
Registrant and Capital Holding Corporation. (Form S-4, Registration
No. 33-52860--Exhibit 10(k)(4).)
*+10(g)(6) -- Employment Agreement between the Registrant and Thomas N.
Hansen. (Form 10-K for the year ended December 31, 1993, File No. 1-
5924--Exhibit 10(i)(5).)
*10(h) -- Power Sale Agreement, dated April 29, 1988, for the dates of May
16, 1990 to December 31, 1995, between the Registrant and Nevada Power
Company. (Form 10-K for the year ended December 31, 1988, File No 1-
5924--Exhibit 10(m)(2).)
*10(i) -- Master Restructuring Agreement, dated as of June 30, 1992, among
the Registrant, Escavada Company, Gallo Wash Development Company,
Valencia, Barclays Bank PLC, New York Branch, as administrative agent
and collateral agent and the several banks parties thereto. (Form S-4,
Registration No. 33-52860--Exhibit 10(bb).)
*10(j) -- Amendment No. 1, dated as of December 15 , 1992, to Master
Restructuring Agreement, dated as of June 30, 1992, among the
Registrant, Escavada Company, Gallo Wash Development Company,
Valencia, Barclays Bank PLC, New York Branch, as administrative agent
and collateral agent and the several banks parties thereto. (Form S-
1, Registration No. 33-55732--Exhibit 10(s)(2).)
*10(k) -- Amendment No. 2, dated as of October 12, 1993, to Master
Restructuring Agreement, dated as of June 30, 1992, among the
Registrant, Escavada Company, Gallo Wash Development Company,
Valencia, Barclays Bank PLC, New York Branch, as administrative agent
and collateral agent and the several banks parties thereto. (Form 10-
K for the year ended December 31, 1993, File No. 1-5924--Exhibit
10(n).)
*10(l) -- Amendment No. 3, dated as of December 20, 1993, to Master
Restructuring Agreement, dated as of June 30, 1992, among the
Registrant, Escavada Company, Gallo Wash Development Company,
Valencia, Barclays Bank PLC, New York Branch, as administrative agent
and collateral agent and the several banks parties thereto. (Form 10-
K for the year ended December 31, 1993, File No. 1-5924--Exhibit
10(o).)
*10(m) -- Amendment No. 4, dated as of April 13, 1994, to Master
Restructuring Agreement, dated as of June 30, 1992, among the
Registrant, Escavada Company, Gallo Wash Development Company,
Valencia, Barclays Bank PLC, New York Branch, as administrative agent
and collateral agent and the several banks parties thereto. (Form 10-
Q for the quarter ended June 30, 1994, File No. 1-5924--Exhibit
10(a).)
*10(n) -- Amendment No. 5, dated as of June 30, 1994, to Master
Restructuring Agreement, dated as of June 30, 1992, among the
Registrant, Escavada Company, Gallo Wash Development Company,
Valencia, Barclays Bank PLC, New York Branch, as administrative agent
and collateral agent and the several banks parties thereto. (Form 10-
Q for the quarter ended June 30, 1994, File No. 1-5924--Exhibit
10(b).)
10(o) -- Amendment No. 6, dated as of November 1, 1994, to Master
Restructuring Agreement, dated as of June 30, 1992, among the
Registrant, Escavada Company, Gallo Wash Development Company,
Valencia, Barclays Bank PLC, New York Branch, as administrative agent
and collateral agent and the several banks parties thereto.
*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.
27 -- 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.