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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 qu