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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to .
Commission File Number 1-5924
TUCSON ELECTRIC POWER COMPANY
(Exact name of registrant as specified in its charter)
ARIZONA 86-0062700
(State or Other Jurisdiction of (IRS Employer
Incorporation or Organization) Identification No.)
220 WEST SIXTH STREET, P.O. BOX 711
TUCSON, ARIZONA 85702
85701 (Zip Code)
(Address of Principal
Executive Offices)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (520) 571-4000
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- -------------------
COMMON STOCK, NO PAR VALUE New York Stock Exchange
Pacific Stock Exchange
FIRST MORTGAGE BONDS
8-1/8% Series due 2001 New York Stock Exchange
7.55% Series due 2002 New York Stock Exchange
7.65% Series due 2003 New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
----- -----
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ X ]
The aggregate market value of the registrant's outstanding voting Common
Stock held by non-affiliates of the registrant is $478,020,278.00 based on the
last reported sale price thereof on the consolidated tape on March 4, 1997.
At March 4, 1997, 32,135,817 shares of the registrant's Common Stock,
no par value (the only class of Common Stock), were outstanding.
Documents incorporated by reference: Specified portions of Tucson Electric
Power Company's Proxy Statement relating to the 1997 Annual Meeting of
Shareholders are incorporated by reference into PART III.
TABLE OF CONTENTS
Page
Definitions....................................................vi
- PART I -
Item 1. -- Business
The Company...................................................1
Certain Risks .................................................1
Utility Operations
Peak Demand and Customers ....................................2
Sales for Resale .............................................3
Competition ..................................................3
Generating and Other Resources
Company Resources ............................................4
Springerville Station ......................................4
Irvington Station ..........................................5
SCE/TEP Power Exchange Agreement .............................5
Future Generating Resources ..................................5
Other Purchases ..............................................6
Rates and Regulation
General ......................................................6
1996 Rate Order ..............................................7
ACC Rules on Retail Competition ..............................7
FERC Orders on Wholesale Transmission Access .................9
Other Rate Matters ...........................................9
Fuel Supply
General ......................................................9
Coal ........................................................10
Springerville Coal Handling Facilities ......................11
Gas .........................................................11
Water Supply .................................................11
Environmental Matters
General .....................................................11
Four Corners Generating Station .............................13
Irvington Generating Station ................................13
Navajo Generating Station ...................................13
San Juan Generating Station .................................13
Springerville Generating Station ............................13
Employees ....................................................13
Energy-Related Ventures ......................................14
Utility Operating Statistics .................................15
Item 2. -- Properties..........................................16
Item 3. -- Legal Proceedings
Tax Assessments ..............................................17
Item 4. -- Submission of Matters to a Vote of Security Holders...17
- PART II -
Item 5. -- Market for Registrant's Common Equity and Related Stockholder Matters
18
Item 6. -- Selected Consolidated Financial Data................19
Item 7. -- Management's Discussion and Analysis of Financial Condition and
Results of Operations
Overview....................................................20
Competition
Wholesale ..................................................21
Retail .....................................................22
Holding Company Proposal .....................................24
Investments in Energy-Related Ventures .......................25
Results of Operations ........................................26
Results of Utility Operations
Sales and Revenues........................................26
Operating Expenses........................................27
Other Income (Deductions).................................27
Interest Expense..........................................28
Accounting for the Effects of Regulation .....................28
Dividends on Common Stock ....................................28
Liquidity and Capital Resources
Cash Flows .................................................29
Financing Developments .....................................30
Short-Term Credit Facilities
Revolving Credit..........................................31
Other.....................................................31
Income Tax Position ..........................................31
Restrictive Covenants
General First Mortgage Covenants ...........................32
General Second Mortgage Covenants ..........................32
Additional Restrictive Covenants ...........................33
Construction Expenditures ....................................33
Safe Harbor for Forward-Looking Statements ...................33
Item 8. -- Consolidated Financial Statements and Supplementary Data...34
Independent Auditors' Report .................................35
Consolidated Statements of Income ............................36
Consolidated Statements of Cash Flows ........................37
Consolidated Balance Sheets ..................................38
Consolidated Statements of Capitalization ....................39
Consolidated Statements of Changes in Stockholders' Equity (Deficit)...40
Notes to Consolidated Financial Statements
Note 1. Nature of Operations and Summary of Significant Accounting Policies
Nature of Operations .......................................41
Basis of Presentation ......................................41
Use of Estimates ...........................................41
Regulation .................................................41
Accounting for the Effects of Regulation ...................41
Utility Plant ..............................................43
Utility Plant Under Capital Leases .........................43
Springerville Unit 1 Allowance .............................44
Deferred Common Facility Costs .............................44
Utility Operating Revenues .................................44
MSR Option Gain Regulatory Liability .......................45
Fuel and Purchased Power Costs .............................45
Income Taxes ...............................................45
EPA Allowances .............................................45
Fair Value of Financial Instruments ........................46
Reclassification ...........................................46
Common Stock Reverse Split .................................46
Impact of FAS 121 ..........................................46
Note 2. 1996 Rate Order ......................................46
Note 3. Income Taxes ........................................48
Note 4. Consolidated Subsidiaries
Nations Energy Corporation .................................50
Advanced Energy Technologies, Inc. .........................50
Valencia Energy Company ....................................50
Investment Subsidiaries ....................................51
Note 5. Long and Short-Term Debt and Capital Lease Obligations
Long-Term Debt .............................................51
First Mortgage Bonds......................................51
MRA.......................................................51
Dividends - Restrictive Covenants.........................52
Letters of Credit.........................................52
Renewable Term Loan.......................................52
Fair Value of Long-Term Debt..............................52
Authorization To Issue Tax-Exempt Bonds...................53
Capital Lease Obligations ..................................53
Maturities and Sinking Fund Requirements ...................53
Short-Term Debt
Revolving Credit..........................................54
Investment Subsidiaries...................................54
Note 6. Commitments and Contingencies
Utility Contractual Matters
Coal and Transportation Contracts - Reversal of Accrued Liabilities ...54
Fuel Purchase Commitments.................................54
Commitments-Environmental Regulation .......................55
Contingencies
Ruling on Arizona Sales Tax Assessments - Coal Sales......56
Arizona Sales Tax Assessments - Leases....................56
Note 7. Jointly Owned Facilities .............................57
Note 8. Employee Benefits Plans
Voluntary Severance Plan (VSP) .............................57
Pension Plans ..............................................57
Postretirement Benefits Other Than Pensions ................58
Stock Option Plans .........................................59
Note 9. Quarterly Financial Data (unaudited) .................61
Note 10. Supplemental Cash Flow Information ..................62
Item 9. -- Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure...........................................63
- PART III -
Item 10. -- Directors and Executive Officers of the Registrant
Directors ....................................................63
Executive Officers ...........................................63
Item 11. -- Executive Compensation.............................65
Item 12. -- Security Ownership of Certain Beneficial Owners and Management
General ......................................................65
Security Ownership of Certain Beneficial Owners ..............65
Security Ownership of Management .............................65
Item 13. -- Certain Relationships and Related Transactions ....65
- PART IV -
Item 14. -- Exhibits, Financial Statement Schedules, and Reports on Form 8-K 66
Signatures ...................................................67
Exhibit Index ................................................69
DEFINITIONS
The abbreviations and acronyms used in the 1996 Form 10-K are defined below:
ACC............ Arizona Corporation Commission.
ACC Staff...... Staff of the Arizona Corporation Commission.
ADEQ........... Arizona Department of Environmental Quality.
Advanced Energy Advanced Energy Technologies, Inc., a wholly-owned
subsidiary of the Company.
AFDC........... Allowance for Funds Used During Construction.
APS............ Arizona Public Service Company.
Banks.......... Various banks with which the Company has credit
relationships.
Brookland...... Brookland Financial Corporation, a wholly-owned, indirect
subsidiary of SRI, which formerly initiated and sold
vehicle contract receivable portfolios.
BTU............ British Thermal Unit(s).
CAAA........... Federal Clean Air Act Amendments.
Century........ Century Power Corporation, an indirect subsidiary of the
Catalyst Corporation and formerly known as Alamito
Company.
Commission or SEC Securities and Exchange Commission.
Common Stock... The Company's common stock, without par value.
Company or TEP. Tucson Electric Power Company.
CWIP........... Construction Work In Progress.
Emission Allowance(s) An EPA issued allowance which permits emission of one
ton of sulfur dioxide. Such allowances can be sold.
EPA............ The Environmental Protection Agency.
FAS 71......... Statement of Financial Accounting Standards No. 71:
Accounting for the Effects of Certain Types of
Regulation.
FAS 92......... Statement of Financial Accounting Standards No. 92: Regulated
Enterprises - Accounting for Phase-In Plans.
FAS 101........ Statement of Financial Accounting Standards No. 101: Regulated
Enterprises - Accounting for the Discontinuation of
Application of FAS 71.
FAS 121........ Statement of Financial Accounting Standards No. 121:
Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of.
FAS 123........ Statement of Financial Accounting Standards No. 123:
Accounting for Stock-Based Compensation.
FERC.............. Federal Energy Regulatory Commission.
FERC Order No. 888 An Order of the FERC issued in April 1996 pertaining to
open access transmission service.
Financial Restructuring The comprehensive financial restructuring of the
Company's obligations to certain of the Company's
creditors and lease participants and Century and the
Springerville Unit 1 Leases' participants and the
reclassification of all shares of the Preferred Stock into
Common Stock which occurred on December 15, 1992.
First Mortgage Bonds First mortgage bonds issued under the General First
Mortgage.
Four Corners...... Four Corners Generating Station.
GAAP.............. Generally Accepted Accounting Principles.
General First Mortgage The Indenture, dated as of April 1, 1941, of Tucson
Gas, Electric Light and Power Company to The Chase
National Bank of the City of New York, as trustee, as
supplemented and amended.
General Second Mortgage The Indenture, dated as of December 1, 1992, of
Tucson Electric Power Company to Bank of Montreal Trust
Company of the City of New York, as trustee, as
supplemented.
Global Solar...... Global Solar Energy, LLC, a corporation in which a 50%
interest is owned by Advanced Energy.
Holding Company Act The Public Utility Holding Company Act of 1935, as
amended.
IBEW 1116......... International Brotherhood of Electrical Workers labor
union, Local Chapter 1116.
IDBs.............. Industrial development revenue or pollution control
revenue bonds.
Installment Sale Agreement $48 million principal amount of City of
Farmington, New Mexico, 6.25% Pollution Control Revenue
Bonds Series 1973.
IRS............... Internal Revenue Service.
Irvington......... Irvington Generating Station.
Irvington Lease... The leveraged lease arrangement relating to Irvington Unit
4.
ITC............... Investment tax credit.
kW................ Kilowatt(s).
kWh............... Kilowatt-hour(s).
kV................ Kilovolt(s).
kVA............... Kilovoltampere(s).
LOC............... Letter of Credit.
MRA............... Master restructuring agreement between the Company and the
Banks which includes the Renewable Term Loan, Revolving
Credit, and certain replacement reimbursement agreements.
MSR............... Modesto, Santa Clara and Redding Public Power Agency.
MW................ Megawatt(s).
MWh............... Megawatt-hour(s).
Nations Energy.... Nations Energy Corporation, a wholly-owned subsidiary of
the Company.
Navajo............ Navajo Generating Station.
NEV............... New Energy Ventures, Inc.
NOL............... Net Operating Losses.
1981 Apache B Bonds $100 million principal amount of variable rate IDBs which
are secured by First Mortgage Bonds.
1990 Pima A Bonds. $20 million principal amount of variable rate IDBs which
are secured by First Mortgage Bonds.
1996 Rate Order... ACC Rate Order concerning an increase in the Company's
retail base rates and the recovery of Springerville Unit
2 costs, issued March 29, 1996.
1994 Rate Order... ACC Rate Order concerning an increase in the Company's
retail base rates and regulatory write-offs, issued
January 11, 1994.
1991 Rate Order... ACC Rate Order concerning an increase in the Company's
retail base rates, regulatory write-offs and rate and
accounting synchronization, issued October 11, 1991.
1989 Rate Order... The ACC's October 24, 1989, Rate Order concerning the
Company's 1988 application for a rate increase.
NTUA.............. Navajo Tribal Utility Authority.
PDEQ.............. Pima County Department of Environmental Quality.
Preferred Stock... The Company's previously outstanding Cumulative Preferred
Stock, $100 Par Value, and Cumulative Preferred Stock (No
Par) which were reclassified into Common Stock pursuant
to the Financial Restructuring.
PNM............... Public Service Company of New Mexico.
Renewable Term Loan Credit facility that replaces the Term Loan pursuant to
the MRA Sixth Amendment, dated as of November 1, 1994,
and effective March 7, 1995.
Revolving Credit.. $50 million revolving credit facility entered into between
a syndicate of certain of the Banks and the Company.
San Carlos........ San Carlos Resources Inc., a wholly-owned subsidiary of
the Company.
San Juan.......... San Juan Generating Station.
San Juan Unit 3... Unit 3 of San Juan.
SCE............... Southern California Edison Company, a subsidiary of Edison
International.
Second Mortgage Bonds The Company's second mortgage bonds issued under the
General Second Mortgage.
Securities Exchange Act The Securities Exchange Act of 1934, as amended.
Shareholders...... Holders of Common Stock.
Southwest Energy.. Southwest Energy Solutions, Inc., a wholly-owned
subsidiary of the Company.
Springerville.. Springerville Generating Station.
Springerville Coal Handling
Facilities Leases Leveraged lease arrangements relating to the coal
handling facilities serving Springerville.
Springerville Common
Facilities Leases Leveraged lease arrangements relating to the Company's
undivided one-half interest in certain facilities at
Springerville used in common with Springerville Unit 1
and Springerville Unit 2.
Springerville Unit 1 Unit 1 of the Springerville Generating Station.
Springerville Unit 1 Leases Leveraged lease arrangement pursuant to which
Century leased Springerville Unit 1 and which has been
assumed by the Company.
Springerville Unit 2 Unit 2 of the Springerville Generating Station.
SRI............ Sierrita Resources Inc., a wholly-owned investment subsidiary
of the Company.
SRP............ Salt River Project Agricultural Improvement and Power
District.
SWPP........... SWPP Investment Company, a wholly-owned subsidiary of the
Company.
Term Loan...... $243.4 million original principal amount term loan entered
into by a syndicate of certain Banks and the Company.
TNP............ Texas New Mexico Power Company.
TRI............ Tucson Resources Inc., a wholly-owned investment subsidiary of
the Company.
Unit 2 First Mortgage First mortgage lien on and security interest in
Springerville Unit 2 which secures, in part, the
Renewable Term Loan, the Revolving Credit and the
Replacement Reimbursement Agreement.
Valencia....... Valencia Energy Company, previously a wholly-owned subsidiary
of the Company, merged into the Company on May 31, 1996.
VSP............ Voluntary Severance Plan offered to Company employees and
implemented in May 1996.
Warrants....... Warrants for purchase of the Common Stock which were issued
under the Financial Restructuring to the owner
participants in the Springerville Unit 1 Leases.
WSCC........... Western Systems Coordinating Council.
PART I
This Annual Report on Form 10-K contains forward-looking statements as
defined by the Private Securities Litigation Reform Act of 1995. Forward-
looking statements should be read with the cautionary statements and important
factors included in this Form 10-K. (See Item 7. - Management's Discussion and
Analysis of Financial Condition and Results of Operations, Safe Harbor for
Forward-Looking Statements.) Forward-looking statements include statements
concerning plans, objectives, goals, strategies, future events or performance
and underlying assumptions and other statements which are other than statements
of historical facts. Such forward-looking statements may be identified, without
limitation, by the use of the words "anticipates," "estimates," "expects,"
"intends," "plans," "predicts," "projects," and similar expressions. The
Company's expectations, beliefs and projections are expressed in good faith and
are believed by the Company to have a reasonable basis, including without
limitation, management's examination of historical operating trends, data
contained in the Company's records and other data available from third parties,
but there can be no assurance that management's expectations, beliefs or
projections will result or be achieved or accomplished.
ITEM 1. -- BUSINESS
THE COMPANY
Tucson Electric Power Company was incorporated under the laws of the State
of Arizona on December 16, 1963. The Company is the successor by merger as of
February 20, 1964, to a Colorado corporation which was incorporated on January
25, 1902. The Company is an operating public utility engaged in the
generation, purchase, transmission, distribution and sale of electricity for
customers in the City of Tucson and the surrounding area and to wholesale
customers. The Company holds a franchise which expires in 2001 to provide
electric service to customers in the City of Tucson.
The Company owns all of the outstanding stock of (i) San Carlos Resources
Inc. (San Carlos), which holds title to Springerville Unit 2, (ii) Nations
Energy Corporation (Nations Energy), which is active in the development of
independent power projects worldwide, (iii) Advanced Energy Technologies, Inc.
(Advanced Energy), formerly known as TEP Solar Energy Corporation, which holds a
50% interest in a manufacturer of thin-film photovoltaic cells, (iv) SWPP
Investment Company (SWPP), which was formed to hold an ownership interest in a
business engaged in the manufacture and sale of concrete power poles, and (v)
Southwest Energy Solutions Inc. (Southwest Energy), which was formed to provide
ancillary energy services to electric consumers. See Energy-Related Ventures
below for a description of these subsidiaries. The Company also owns all of the
outstanding stock of two non-energy related subsidiaries, Tucson Resources Inc.
(TRI) and Sierrita Resources Inc. (SRI). In 1994, TRI and SRI substantially
completed the process of liquidating their respective investments.
CERTAIN RISKS
For descriptions of certain factors affecting the Company, including
commitments and contingencies, which subject the Company to continuing risks,
see (i) Item 3., Legal Proceedings; (ii) Item 7., Management's Discussion and
Analysis of Financial Condition and Results of Operations, Overview and Safe
Harbor for Forward-Looking Statements; and (iii) Notes 1 and 6 of Notes to
Consolidated Financial Statements, Nature of Operations and Summary of
Significant Accounting Policies and Commitments and Contingencies, respectively.
UTILITY OPERATIONS
PEAK DEMAND AND CUSTOMERS
Certain operating and system data related to the Company's utility
operations for each of the last five years are summarized in the following
table:
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
PEAK DEMAND - MW -
Retail Customers-Net One Hour 1,619 1,617 1,585 1,449 1,399
Other Utilities-Firm 177 223 226 225 150
----- ----- ----- ----- -----
Non-Coincident Peak Demand (A) 1,796 1,840 1,811 1,674 1,549
----- ----- ----- ----- -----
Total Generating Resources (B) 2,085 2,085 1,975 1,975 1,983
Total Reserves ((B) - (A)) 289 245 164 301 434
===== ===== ===== ===== =====
Reserve Margin (% of Non-Coincident
Peak Demand) 16% 13% 9% 18% 28%
===== ===== ===== ===== =====
The peak demand for the Company's retail service area occurs during the
summer months due to the space cooling requirements of its retail customers.
The Company has experienced growth in peak demand of retail customers at an
average annual rate of approximately 4.2% for the past five years. The load of
its mining customers comprised on average approximately 8.5% of the retail peak
demand for the past five years.
In 1996, based on non-coincident peak demand, the Company's reserve margin
increased to 16% compared with 13% in the prior year. This increase was due to
lower demand from firm wholesale customers. The Company seeks to maintain a
reserve margin equal to its largest single hazard plus 5% of its non-coincident
peak demand in accordance with guidelines established by the WSCC. The targeted
reserve requirement in 1996 was 302 MW, or 17% of non-coincident peak demand.
The Company's operations have not been adversely affected by having an actual
reserve margin lower than the targeted reserve requirement. It is expected that
near-term growth in demand will be met with existing resources and additional
resources as discussed in Future Generating Resources below. Also, see Company
Resources below for a discussion of the Company's electric generating resources.
The growth in the number of retail customers remained strong in 1996, with
year-end customers increasing by 2.8% compared to the five-year annual average
of 2.6%. The growth rate in the number of customers is expected to be
approximately 2.4% annually through the year 2001. Retail peak demand is
expected to grow at an average annual rate of 2.5% during the same period. The
average annual rate of growth of energy sales to retail customers is anticipated
to be in the 2.3% range for the remainder of the decade. On average,
residential, non-mining industrial, and mining energy sales are expected to
account for 34%, 28%, and 17%, respectively, of the projected sales for the
remainder of the decade. The expected growth in the number of customers, retail
peak demand and retail sales is based, in part, upon publicly available
population and demographic studies conducted by persons or entities unaffiliated
with the Company. Such statements are also based upon various assumptions
including, without limitation, assumptions relating to weather, economic and
competitive conditions, including the assumption that the Company will incur no
significant loss of retail customers due to self-generation or retail wheeling.
The Company has two principal mining customers. In 1996, the sales to
these customers totaled approximately 16% of the Company's total retail energy
sales, and their contract demands totaled approximately 11% of the 1996 retail
peak demand. The total coincident peak load for the Company's two mining
customers was only 7.2% of the coincident peak demand due to temporary non-
mandated demand reductions at certain mining facilities. Based on normal
electrical loads for these customers, the Company's coincident peak demand would
have increased by 34 MW to 1,651 MW, or 2.1%, over the 1995 retail peak demand.
Revenues from sales to mining customers accounted for approximately 9% of the
Company's retail revenues in 1996 and approximately 10% in 1995 and 1994. Sales
to mining customers are expected to grow as approximately 20 MW of additional
mining load is scheduled for 1997. However, sales to mining customers are
dependent on a variety of factors including, but not limited to, changes in the
international copper market and the economics of self-generation.
The Company serves its two principal mining customers under reduced rate
contracts designed to induce them to continue to purchase electricity from the
Company rather than self-generate. These contracts expire after the year 2000.
However, such contracts contain various provisions allowing the customers to
terminate partially or entirely, under certain circumstances, provided that the
Company is notified at least one and up to two years prior to such termination.
No termination notices have been received by the Company. The ability to extend
contracts and to avoid early termination will depend on market conditions and
available alternatives.
Future markets and prices for fuel, access to capital, as well as ACC
decisions regarding rate design and retail wheeling, will affect the economics
of self-generation projects (including cogeneration) and potential purchases
from competing energy suppliers. Such factors may ultimately affect whether
customers, such as the mining customers described above, might reduce or
terminate their demands on the Company's system (see Competition below).
SALES FOR RESALE
The Company makes sales for resale to others on both a firm and an
interruptible basis. To the extent capacity is not providing energy to the
Company's retail customers, such as during off-peak periods, the Company markets
this capacity and energy at wholesale. Surplus energy is sold from time to time
under various power pooling arrangements. The Company currently has contracts
to sell firm capacity as follows:
Minimum
Contract
Company Demand MW Contract Term
------- --------- -------------
SRP 100 June 1, 1991 - May 31, 2011
NTUA (1) 45 June 1, 1993 - May 31, 1999
- -------------
(1)The agreement with NTUA provides for a minimum contract demand of 45 MW and
requires NTUA to obtain all of its electric power requirements from the
Company. NTUA is a winter peaking utility and their coincident peak demand
is expected to reach approximately 70 MW during the term of this contract.
The Company continues to actively market available excess energy in the
short-term markets (hourly up to one year) and, to the extent that it is
economic, commitments for available generating capacity and energy in the longer
term markets (one year and longer). Competition to sell capacity is expected to
remain vigorous in the next few years as a result of surplus capacity in the
Southwestern United States, the restructuring of the electric utility industry
in California and other western states, and the presence of a highly competitive
spot market in the Western United States. Regarding the contracts described
above, the Company cannot currently make any predictions about the replacement
or extension of such contracts in the future.
COMPETITION
See Rates and Regulation, ACC Rules on Retail Competition and FERC Orders
on Wholesale Transmission Access below, and Item 7. -- Management's Discussion
and Analysis of Financial Condition and Results of Operations, Competition, for
a discussion of developments regarding competition in the industry at the
wholesale as well as at the retail level.
GENERATING AND OTHER RESOURCES
COMPANY RESOURCES
The total net generating capability owned or leased by the Company at
December 31, 1996, was 1,952 MW as set forth in the following table:
Net Capa- Company Share
Unit Fuel bility Operating -------------
Generating Source No. Location Type MW Agent % MW
----------------- ---- -------- ---- ------- --------- ---- ----
Springerville Station (1) 1 Springerville, AZ Coal 360 TEP 100.0 360
Springerville Station (1) 2 Springerville, AZ Coal 360 TEP 100.0 360
San Juan Station 1 Farmington, NM Coal 316 PNM 50.0 158
San Juan Station 2 Farmington, NM Coal 312 PNM 50.0 156
Navajo Station 1 Page, AZ Coal 750 SRP 7.5 56
Navajo Station 2 Page, AZ Coal 750 SRP 7.5 56
Navajo Station 3 Page, AZ Coal 750 SRP 7.5 56
Four Corners Station 4 Farmington, NM Coal 784 APS 7.0 55
Four Corners Station 5 Farmington, NM Coal 784 APS 7.0 55
Irvington Station 1 Tucson, AZ Gas/Oil 81 TEP 100.0 81
Irvington Station 2 Tucson, AZ Gas/Oil 81 TEP 100.0 81
Irvington Station 3 Tucson, AZ Gas/Oil 104 TEP 100.0 104
Irvington Station 4 Tucson, AZ Coal/Gas/Oil 156 TEP 100.0 156
Internal Combustion Turbines Tucson, AZ Gas/Oil 218 TEP 100.0 218
-----
Total Company Capacity (2) 1,952
=====
- ---------------------------------------------
(1) As of January 1, 1997, the net generating capability at Springerville was
increased to 380 MW for each unit. See Springerville Station below.
(2) Excludes 215 MW of additional resources, which consists of certain other
capacity purchases and interruptible retail load. At December 31, 1996,
total Company-owned capacity was 1,339 MW and Company-leased capacity was
613 MW. Internal combustion turbines with 96 MW of capacity are leased by
the Company. At the end of such lease in 1998, the Company may exercise
fair market value purchase and renewal options.
SPRINGERVILLE STATION
The Springerville Station consists of two coal fired units. Springerville
Unit 1 began commercial operation in 1985 and is currently leased and operated
by the Company. Springerville Unit 2 commenced commercial operation in June
1990 and is owned by San Carlos and operated by the Company. Based on a review
of generating unit capabilities and changes in certain operating procedures, the
net capacity rating for each unit was increased from 360 MW to 380 MW as of
January 1, 1997. Under emergency conditions, such units may be operated for up
to eight hours at a net capacity of 400 MW each.
The primary terms of the Springerville Unit 1 Leases expire on January 1,
2015. At December 31, 1996, the capitalized lease asset related to Springerville
Unit 1, net of allowance and accumulated amortization, was $252 million, or $663
per kW based on a 380 MW capacity rating. At the end of the primary term, the
Company may exercise fair market value purchase and renewal options. Annual
lease payments for the Springerville Unit 1 Leases will range from $33 million
to $176 million, averaging approximately $77 million. In 1996, the cash cost to
the Company of Springerville Unit 1 capacity attributable to rent obligations
and other operation and maintenance expenses was $76 million, or an average of
approximately $17 per kW per month based on a 380 MW capacity rating. Such
average cash cost is estimated to be approximately $19 per kW per month
(approximately $87 million per year) for the period from January 1997 through
December 2001 and will increase thereafter. However, due to timing differences
between cash and accrued expenses, capacity costs attributable to rent
obligations and other operation and maintenance expenses were accrued in the
Company's financial statements during 1996 at an average of approximately $20
per kW per month, or $92 million for the year, before amortization of the
regulatory disallowance and related interest expense. The estimated cost is
expected to average approximately $21 per kW per month (approximately $96
million per year) for the period from January 1997 through December 2001 and is
expected to increase slightly thereafter. The 1991 Rate Order allowed the
Company to recover the cost of 360 MW of capacity for Springerville Unit 1, but
limited such recovery to a rate of $15 per kW per month (approximately $65
million per year). Substantially all of the present value of disallowed
Springerville Unit 1 costs was recorded as a loss in 1990, and as a result of
the Financial Restructuring, an additional loss was recorded in 1992. The
losses together reflect the present value of the difference between projected
costs and the amount the Company is allowed to recover through the lease term
ending January 1, 2015. See Note 1 of Notes to Consolidated Financial
Statements, Nature of Operations and Summary of Significant Accounting Policies,
Springerville Unit 1 Allowance.
In December 1985, pursuant to the Springerville Common Facilities Leases,
the Company sold and leased back its 50% interest in the common facilities at
Springerville. The sales price of such facilities was $132 million. At
December 31, 1996, the capitalized lease asset related to Springerville common
facilities, net of accumulated amortization, was $122 million. The initial
lease term for the common facilities expires in 2017 for one owner participant
and 2021 for the other two owner participants, subject to optional renewal
periods and purchase options. Annual lease payments for the common facilities
vary with changes in the interest rate on the underlying debt. Such lease
payments totaled approximately $12 million per year in 1994, 1995 and 1996.
Based on current interest rates, average annual lease payments would total
approximately $11 million.
Including the cost of leased common facilities (but excluding the cost of
coal-handling facilities at Springerville which were included in recoverable
fuel costs), the total initial cost of Springerville Unit 2 was $838 million, or
$2,328 per kW based on the previous 360 MW capacity rating. In the 1991 Rate
Order, the ACC disallowed recovery from retail customers of $175 million of the
book value of Springerville Unit 2. The Company recorded a loss for such
disallowance in 1991. The net recoverable cost, including the leased common
facilities, is $663 million.
IRVINGTON STATION
In January 1988, the Company began coal-fired commercial operation and
entered into a sale and leaseback arrangement for Irvington Unit 4 pursuant to
the Irvington Lease. The unit was sold at its cost of $152 million. At
December 31, 1996, the capitalized lease asset related to Irvington Unit 4, net
of accumulated amortization, was $118 million. This lease calls for annual
payments which will range from approximately $9 million to $14 million and which
average approximately $13 million. The lease term expires in 2011, but the
lease has optional renewal and purchase option provisions.
Irvington Unit 4 (156 MW capability) has the flexibility to operate on
coal, gas or fuel oil. Coal has been the primary fuel and natural gas the
secondary fuel.
SCE/TEP POWER EXCHANGE AGREEMENT
As part of a 1992 litigation settlement, the Company and SCE agreed to a
ten-year power exchange agreement. Under the agreement, which began in May
1995, SCE provides firm system capacity of 110 MW to the Company during summer
months, for which the Company pays an annual capacity charge of
approximately $1 million increasing annually after the first five years to a
maximum of approximately $2 million annually. The Company is entitled to
schedule firm energy deliveries from SCE during the summer (May 15 through
September 15) of up to 36,300 MWh per month, and is obligated to return to SCE
on an interruptible basis the same amount of energy the following winter season
(November 1 through February 28). The energy provided pursuant to the exchange
is expensed based upon the estimated cost of interruptible energy to be provided
to SCE. Pursuant to the exchange agreement the Company received 104,028 MWh
from SCE in 1996 and had returned 51,855 MWh to SCE as of December 31, 1996.
FUTURE GENERATING RESOURCES
In December 1995, the Company filed an integrated resource plan pursuant to
the ACC's regulations governing resource planning. In its filing the Company
projected the need for an additional 128 MW of peaking resources in 1998 and
additional peaking resources in the year 2002 and beyond. No need for
additional base load generation facilities was forecast through the year 2010.
Subsequently, the Company has delayed the need for peaking resources to 2001
through a review of net generating capabilities at Springerville and an increase
in the percentage of retail load served now on an interruptible basis.
In the 1995 integrated resource plan the Company projected that demand-
side management programs should reduce peak demand and, therefore, capacity
requirements, from what they would be without such programs by 60 MW by the year
2000. As part of the integrated resource plan, the Company has committed to
adding 5 MW of renewable generation resources by the year 2000.
The need for all of these future resources may be affected by the ACC's
rules on retail competition and the Company's ability to retain and attract
customers. See Rates and Regulation, ACC Rules on Retail Competition below and
Item 7. - Management's Discussion and Analysis of Financial Condition and
Results of Operations, Competition.
OTHER PURCHASES
In addition to generating electricity at generating stations owned or
leased by the Company and the SCE/TEP Power Exchange, the Company participates
in a number of interchange agreements through which it can purchase additional
electric energy from other utilities. The amount of energy purchased from other
utilities varies substantially from time to time depending on both the cost of
purchased energy as compared to the Company's cost of generating energy and the
availability of such energy. Through these same agreements, the Company may
also sell its surplus electric energy from time to time.
The Company has transmission access to and/or power transaction
arrangements with over 160 electric systems or suppliers, including those in the
southern California markets. The Company is a member of the Inland Power Pool,
which is comprised of a group of utilities serving customers in portions of the
western United States. The Inland Power Pool provides emergency assistance and
reserve sharing among its members in order to enhance system reliability in the
Rocky Mountain region. The Company is also a member of the WSCC, a group of
western electric systems and suppliers that works cooperatively to assure the
reliability of the region's interconnected generation and transmission systems.
In addition, the Company is a member of the Western Systems Power Pool, a
voluntary power pooling arrangement designed to achieve more efficient use of
electric generation and transmission facilities among its members. See
Competition for a discussion of possible changes in transmission issues.
RATES AND REGULATION
GENERAL
The Company is subject to the jurisdiction of the ACC, which has authority,
among other things, to prescribe the classifications of accounts to be used and
the rates and charges to be made and collected from retail customers, and to
regulate the issuance of securities. The ACC also has authority to approve
affiliate transactions and the establishment of holding companies and
subsidiaries under ACC promulgated Affiliated Interest Rules. The Company is
also subject to regulation by FERC in certain respects, including the terms and
prices of sales to other utilities.
Arizona law requires that the Company's rates for retail sales of electric
energy be determined by the ACC on a "cost of service" basis and be designed to
provide, after recovery of allowable operating expenses, an opportunity to earn
a reasonable rate of return on "fair value rate base". Fair value rate base is,
generally, determined by the ACC by reference to the original cost and the
reproduction cost (in each case, net of depreciation) of utility plant in
service to the extent deemed used and useful, and to various adjustments for
deferred taxes and other items, plus a working capital component. Thus, over
time, rate base is increased by additions to utility plant in service and
reduced by depreciation and retirements of utility plant from service. Both
operating expenses and fair value rate base determination are subject to
judgment by the ACC regarding prudence and recoverability. To the extent that
customer choice and retail wheeling are introduced into the Company's retail
service area in the future, retail rates may be changed to reflect market levels
which are different from traditional "cost of service" rate levels.
The Company's rates for wholesale sales of capacity and energy, generally,
are not permitted by FERC to exceed rates determined on a cost of service basis.
With respect to long-term firm sales, the Company's wholesale rates are
substantially below rates determined on a fully allocated cost of service basis,
but, in all instances, rates exceed the level necessary to recover fuel and
other variable costs. Rates have historically been set by the FERC in formal
rate application proceedings.
The ACC consists of three commissioners, each serving a six-year term. One
of the three is elected at each general election except when a vacancy occurs
prior to the expiration of a commissioner's term. The present commissioners
are:
- - Carl Kunasek (Republican), Chairman, began his first term in 1995. His term
expires in 2001.
- - Renz D. Jennings (Democrat), began a third term in 1993. His term expires in
1999.
- - Jim Irvin (Republican) started his first term in 1997. His term expires in
2003.
Under a 1992 Arizona law, commissioners cannot serve consecutive terms and
can be elected to another term only after the passing of six years after the end
of their previous term as commissioners.
1996 RATE ORDER
On June 13, 1995, the Company filed an application with the ACC requesting
an overall 4.9% increase in retail rates (approximately $28.4 million in annual
revenues). On March 27, 1996, the ACC took formal action to resolve the
Company's rate application. In its order dated March 29, 1996, the ACC approved
with certain modifications a rate settlement agreement which was filed with the
ACC on March 8, 1996, and approved a one-time rate increase for the Company of
1.1% (approximately $6.4 million annually). The rate increase was implemented
by the Company on March 31, 1996 for electrical usage on or after such date.
Since the rate increase was not implemented for special contract customers, the
effective rate increase was slightly less than 1.1%.
The 1996 Rate Order recognizes all of Springerville Unit 2 as used
and useful for ratemaking purposes so that the Company is presently recovering
the operating and capital costs associated with that portion of the generating
unit not previously included in rates. See Note 2 of the Notes to Consolidated
Financial Statements, 1996 Rate Order. The 1996 Rate Order and approved
settlement agreement also establish a rate moratorium period for the Company.
The Company has committed not to file for a change in base rates prior to
January 1, 2000, except for conditions or circumstances which constitute an
emergency, for the sharing of benefits with customers of cost containment
efforts where appropriate, or in the event the Company is acquired or merged
with another company. By April 15 of each year the Company is required to
provide the ACC Staff with a report quantifying the Company's cost containment
efforts. Beginning July 1, 1997, the ACC Staff may propose to terminate or
modify the rate moratorium for the purpose of reducing the Company's rates or
shortening capital recovery periods to reflect the Company's cost containment
efforts. In addition to the rate moratorium provisions, the 1996 Rate Order and
approved settlement agreement also contain provisions relating to the
implementation of time-of-use rates for residential customers, increased pricing
flexibility for commercial and industrial customers, the consideration of
incentive regulation and a review of jurisdictional cost allocation procedures
for wholesale sales.
The rates approved in the 1996 Rate Order are based on a rate of return of
6.59% on a fair value rate base of approximately $1.36 billion, or 7.72% on an
original cost rate base of approximately $1.16 billion. The capital structure
adopted by the ACC for rate making purposes assumes 62.5% debt and 37.5% equity.
Consistent with previous ACC rate orders, the Company's leasehold interest in
utility plant was reflected in rates through an allowance for rental expense,
and was therefore not included in rate base.
ACC RULES ON RETAIL COMPETITION
On December 23, 1996, the ACC voted to adopt rules on retail
electric competition. The rules require each "Affected Utility" to open its
retail service area to competing electric service providers on a phased-in basis
over the period 1999 to 2003. Beginning no later than January 1, 1999, retail
customers representing at least 20% of each Affected Utility's 1995 peak demand
will be eligible to choose their electric service provider from companies
certificated by the ACC. Such service providers would include Affected
Utilities as well as other entities that apply for and receive a certificate of
convenience and necessity from the ACC. Beginning no later than January 1,
2001, retail customers representing at least 50% of each Affected Utility's 1995
peak demand will be eligible to choose their service provider. All remaining
retail customers would then be eligible to choose from certificated service
providers by January 1, 2003. Under the rules, Affected Utilities will be
required to provide distribution wheeling services (i.e., retail wheeling) at
rates approved by the ACC in order to facilitate sales by competing energy
providers. Such wheeling services would involve the transmission of energy
produced by other entities over the Company's transmission and distribution
system to consumers located in the Company's present retail service area.
While retail wheeling will expose the Company's service area to increased
competition, it will also open additional markets into which the Company may
sell its electric power.
The Affected Utilities whose service territories will be open to competing
service providers under the rules include Tucson Electric Power Company, Arizona
Public Service Company, Citizens Utilities Company, and several electric
cooperatives. However, electric cooperatives will be permitted to request a
modification to the proposed phase-in schedule in order to preserve their tax
exempt status or to modify power supply arrangements and related loan
agreements. Each of the Affected Utilities will be eligible to offer electric
service to customers of other certificated entities within Arizona.
Participation in competitive retail markets by other electric utilities which
are not regulated by the ACC, such as the Salt River Project and certain
municipal utilities, will be permitted under the rules on a similar
reciprocal basis (i.e., their service territories would be similarly open to
competing service providers).
The rules specify that the ACC shall allow the recovery of unmitigated
stranded costs by Affected Utilities. Stranded cost is defined in the rules
as the net difference between the value of prudent jurisdictional assets
and obligations under traditional regulation and the market value of those
assets and obligations in a competitive retail market. In order to recover
stranded costs, utilities would have to demonstrate to the ACC that they have
taken every feasible, cost effective measure to mitigate or offset stranded
costs, and utilities would have to file estimates of unmitigated stranded
costs with the ACC which are fully supported by analyses and records of
market transactions undertaken by willing buyers and sellers. Furthermore,
Affected Utilities would have to seek ACC approval of distribution charges or
other means of recovering unmitigated stranded costs from customers who reduce
or terminate service as a direct result of retail competition. The rules
specify that other issues related to the analysis and recovery of stranded
costs would be examined by a working group following adoption of the rules.
Until such time as the ACC adopts specific guidelines for quantifying
unmitigated stranded costs, including the methods used to identify and value
jurisdictional assets and obligations, the Company believes that any estimate of
unmitigated stranded costs would be highly speculative.
Each Affected Utility will be required to file unbundled service tariffs
with the ACC by December 31, 1997, for the following services: distribution
wheeling service, metering and meter reading services, billing and collection
services, open access transmission service (as approved by the FERC, if
applicable), ancillary services (as defined by FERC Order No. 888), information
services such as the provision of customer information to other service
providers, and other ancillary services necessary for safe and reliable system
operation. Until such time as the ACC determines that retail competition has
been substantially implemented, each Affected Utility will also have to
regulated rates to all consumers located in their current
retail service areas.
The rules require new market entrants to obtain a certificate of
convenience and necessity from the ACC prior to offering retail electric
service. New market entrants will be required to demonstrate adequate technical
and financial capabilities to the ACC prior to certification. In addition, all
competitive market participants, including Affected Utilities, will be required
to obtain at least one-half of one percent of the energy sold competitively in
the Arizona retail market from new solar generating resources by January 1,
1999. This required percentage will increase to one percent on January 1, 2002.
New solar resources are defined under the proposed rule as photovoltaic or solar
thermal resources that are installed on or after January 1, 1997. Electric
service providers not in compliance with these solar resource standards will be
subject to a penalty of up to 30 cents per kWh to be applied to the kWh
deficiency in solar energy provided.
Under the rules, certain issues pertaining to retail electric competition
will be addressed by the ACC in workshops or proceedings to be held after
adoption of the rule. Such issues include the guidelines to be used for
stranded cost quantification and recovery, the possible formation of an
independent system operator for electrical transmission facilities, issues
related to system reliability and safety, legal issues and the methods to be
used in determining consumer participation during the early phase-in periods.
On January 10, 1997, the Company filed with the ACC a motion for
reconsideration and request for stay of the rules. The motion was filed in
order to provide the ACC with an opportunity to remedy certain procedural and
substantive deficiencies in the rules identified by the Company. Concerns
expressed by the Company in its motion included the potential impact on system
reliability, mechanisms for stranded cost quantification and recovery, the
ability to compete fairly with public power entities and recipients of federal
preference power, and certain legal deficiencies which would likely result in
legal appeals and litigation. On January 30, 1997, the Company's motion for
reconsideration was deemed denied by the ACC by operation of law. On February
28, 1997, the Company filed an appeal of the ACC order in both the Arizona
Superior Court and the Arizona Court of Appeals. At the present time, the
Company is unable to predict the outcome of the appeals or the effects such
rules, in their present form, would have on the Company's future results of
operations. For a discussion of the potential impact of increased competition
on the Company's accounting policies, see Item 7. - Management's Discussion and
Analysis of Financial Condition and Results of Operations, Accounting for the
Effects of Regulation, and Note 1 of Notes to Consolidated Financial Statements,
Nature of Operations and Summary of Significant Accounting Policies, Accounting
for the Effects of Regulation.
FERC ORDERS ON WHOLESALE TRANSMISSION ACCESS
In April 1996, the FERC issued two orders pertaining to wholesale
transmission access. FERC Order No. 888, among other things, requires all
public utilities that own, control, or operate interstate transmission
facilities to offer transmission service to others under a single tariff that
incorporates certain minimum terms and conditions of transmission service
established by the FERC. This tariff must also be used by public utilities for
their own wholesale market transactions. Transmission and generation services
for new wholesale service are to be unbundled and priced separately. A Phase I
open access tariff containing the terms and conditions outlined in the Order was
filed by the Company on July 9, 1996. The FERC has scheduled a hearing on the
rates contained in the Company's Phase I open access tariff for May 1997. The
Company is working with the FERC Staff and intervenors in an attempt to resolve
this matter.
FERC Order No. 889 requires transmission service providers to establish or
participate in an open access same-time information system (OASIS) that provides
information on the availability of transmission capacity to wholesale market
participants. The order also establishes standards of conduct that are designed
to prevent employees of a public utility engaged in marketing functions from
obtaining preferential access to OASIS-related information or from engaging in
unduly discriminatory business practices. As such, public utilities are
required to completely separate their wholesale power marketing and transmission
operation functions. The Company is currently in compliance with these
requirements.
OTHER RATE MATTERS
See Utility Operations, Peak Demand and Customers and Item 7. -
Management's Discussion of Financial Condition and Results of Operations,
Competition, Retail for a discussion of the Company's contracts and negotiations
with certain of its mining customers.
FUEL SUPPLY
GENERAL
The Company's principal fuel for electric generation is low-sulfur coal.
The following table provides fuel cost information for the years 1996 through
1992:
Cost Per Million BTU Consumed Percentage of Total BTU Consumed
-------------------------------- --------------------------------
1996 1995 1994 1993 1992 1996 1995 1994 1993 1992
---- ---- ---- ---- ---- ---- ---- ---- ---- ----
Coal (A) $1.76 $1.71 $1.75 $1.77 $1.51 98% 99% 98% 99% 99%
Gas 2.24 1.69 1.86 2.76 2.39 2 1 2 1 1
---- ---- ---- ---- ----
All Fuels 1.77 1.71 1.75 1.79 1.53 100% 100% 100% 100% 100%
==== ==== ==== ==== ====
- -----------------------------------------------
(A) The average cost per ton of coal for each of the last five years (1996 -
1992) was $32.95, $32.11, $33.12, $33.11, and $29.01, respectively. Coal
costs have been restated to reflect the May 1996 merger of Valencia into the
Company.
COAL
The Company is the operator for the Springerville and Irvington generating
stations. Their coal supplies are transported from northwestern New Mexico by
railroad. The coal contract for Springerville is for the remaining lives of
Units 1 and 2 with a bilateral option to renegotiate the contract price and
escalation procedures in 2009 and at intervals of every five years thereafter.
At Irvington, the contract termination date is the earlier of 2015 or the
remaining life of Unit 4. The Springerville and Irvington contracts have
various adjustment clauses which will affect the future cost of coal delivered.
Coal reserves are expected to be sufficient to supply the estimated requirements
of Springerville and Irvington for their presently estimated remaining lives.
TEP is a participant in the San Juan Generation Station and shares a 50/50
responsibility split of the coal agreement. The coal quantities for the San
Juan Station, a mine-mouth operation, are partially contracted through the year
2017. The Company also participates in jointly owned generating facilities under
long-term contracts entered into by the operating agents. Coal supplies are
surface-mined in northern Arizona and northwestern New Mexico. The contract for
coal for Four Corners terminates in 2005. The coal quantities under contract
for the Navajo mine-mouth coal fired generating station are expected to be
sufficient to supply the estimated requirements for its presently estimated
remaining life. Additional information concerning the coal contracts is set
forth below:
Year Average Cost Per Coal
Contract Sulfur Million BTU (A) Obtained
Station Coal Supplier Terminates Content 1996 1995 1994 From (B)
- ------- ------------- ---------- ------- ---- ---- ---- -------
Four Corners BHP Minerals International, Inc. 2005 0.8% $1.34 $1.15 $1.28 Navajo Indian Tribe
San Juan San Juan Coal Company 2017 0.8% $1.77 $1.76 $1.81 Federal and State Agencies
Navajo Peabody Western Coal Company 2011 0.6% $1.18 $1.12 $1.09 Navajo and Hopi Indian Tribes
Springerville(C) Lee Ranch Coal Company (D) 0.7% $1.84 $1.73 $1.89 Lee Ranch Coal Company
Irvington The Pittsburg & Midway Coal Mining Company 2015 0.4% $2.21 $2.20 $2.21 Navajo Indian Tribe and Federal
and State Agencies
- ----------------------------------------------------------
(A) Includes costs of transportation and handling in addition to the purchase
price under the basic contract.
(B) Substantially all of the suppliers' leases extend at least as long as coal
is being mined in economic quantities.
(C) Fuel handling costs at Springerville have been restated to reflect the May
1996 merger of Valencia into the Company. Coal handling facilities costs
included in Springerville fuel costs above were $0.25 per million BTU in
1996, $0.34 per million BTU in 1995, and $0.33 per million BTU in 1994.
(D) The coal contract for Springerville is for the remaining lives of Units 1
and 2 with a bilateral option to renegotiate the contract price and
escalation procedures in 2009.
The Irvington coal supply contract contains take-or-pay provisions, whereby
the Company is required to make certain minimum payments for a base amount of
tonnage not taken at a rate of 50% of the contract price. Although the
Company's present fuel requirements are generally in excess of the stated take-
or-pay minimum amounts, from time to time the Company has purchased coal and
natural gas in the spot market or switched fuel burn from one generating station
to another in order to achieve lower overall fuel costs, while incurring take-
or-pay minimum charges. During 1996 the Company purchased coal for the
Irvington Station from an alternative supplier. As a result, the Company
incurred take-or-pay minimum charges of approximately $4 million during 1996.
The Company incurred no take-or-pay charges in 1995.
On September 1, 1995, the San Juan agreement was amended to allow the mines
the flexibility of mining more economical leases. The reductions will be passed
on to TEP in the form of lower unit costs. The Company intends to continue to
actively negotiate its fuel and transportation contracts in 1997 and in the
future.
SPRINGERVILLE COAL HANDLING FACILITIES
Prior to May 31, 1996, a former subsidiary of the Company, Valencia Energy
Company, was responsible for the acquisition, transportation and handling of
fuel for Springerville. Pursuant to a fuel burn agreement with the Company,
Valencia had the exclusive right and obligation to provide all of the fuel
requirements for Springerville. Upon the merger of Valencia into the Company on
May 31, 1996, the Company became directly responsible for the acquisition,
transportation and handling of fuel for Springerville.
Pursuant to the Springerville Coal Handling Facilities Leases, the Company
is the lessee of the coal-handling facilities at Springerville under a capital
lease with a remaining initial lease term of approximately 19 years with
incremental extensions of five to six years depending on certain criteria at the
date of each extension. At December 31, 1996, the capitalized lease asset
related to the Springerville coal-handling facilities, net of accumulated
amortization, was $178 million. Annual rental payments range from approximately
$10 million to $28 million but average $21 million.
The Company allocates portions of its Springerville Coal Handling Facility
Lease costs to deferred expense for future recovery through rates. See Note 1
of Notes to Consolidated Financial Statements, Nature of Operations and Summary
of Significant Accounting Policies, for a description of the accounting for
Springerville coal handling facility lease costs. Approximately half of the
expenses of the coal handling facilities, including lease costs and other
operating and maintenance expenses, are charged to fuel expense and amounted to
$15 million, $17 million, and $18 million in 1996, 1995 and 1994, respectively.
Prior to the merger of Valencia into the Company in May 1996, nearly all of the
costs associated with Springerville coal handling facilities were charged to
fuel expense. As discussed in Note 4 of Notes to Consolidated Financial
Statements, Consolidated Subsidiaries, Valencia Energy Company, such costs have
been reclassified on the Company's Consolidated Statements of Income.
GAS
In 1996, the Company purchased a small amount of natural gas for power
generation (approximately 2% of total Company generation) from El Paso Gas
Marketing, Equitable Resources Marketing, Natural Gas Clearinghouse, and Mobil.
During 1996, the Company received natural gas sufficient to meet all of its gas
fuel requirements.
WATER SUPPLY
The Company believes there will be sufficient water to supply the
requirements of existing and planned units of all electric generating stations
in which the Company has an interest for their estimated lives. A federal
contract for water at San Juan expires in 2005, and negotiations for extension
are being overseen by PNM.
ENVIRONMENTAL MATTERS
GENERAL
The Company must operate its generating stations in accordance with
numerous local, state and federal guidelines, laws, regulations and ordinances
designed to preserve and enhance environmental integrity. Resource extraction
and waste disposal operations are also regulated for environmental
compatibility. Generally, air quality and water quality are under the most
stringent regulations. Land use is also regulated.
Various federal, state and local laws, regulations and requirements for air
quality control continue to have a significant impact on the Company. Due to
the proximity of national parks, monuments, wilderness areas and Indian
reservations and relatively high air quality at such locations, the principal
generating units of the Company are subject to control standards of best
available control technology (BACT) and best available retrofit technology
(BART). Such standards relate to the "prevention of significant deterioration"
of visibility and tall stack limitation rules.
Certain other generating units of the Company are located in areas which
have been designated by federal and state agencies as "non-attainment" areas
(where federal ambient air quality standards are not achieved). This
designation requires such generating units to comply with "lowest achievable
emission rate" or "reasonably available control technology" standards or
"offset" requirements. New Mexico has adopted emission regulations restricting
the emissions from both existing and future coal, oil and gas-fired plants
located in New Mexico. Regulations adopted by the New Mexico Environmental
Improvement Board (NMEIB) are in some instances more stringent than those
adopted by the EPA. The NMEIB has adopted regulations, which apply to all units
at the San Juan and Four Corners generating stations, that prohibit emissions of
sulfur dioxide, particulates, and nitrogen oxide above certain levels.
The Company expended $11 million during 1996 for environmental construction
costs in maintaining compliance with environmental requirements. The Company
estimates that it will make expenditures for environmental facilities of
approximately $22 million in 1997 and $15 million in 1998. These amounts
include the Company's estimated share of expenditures for improvements to the
pollution control facilities at the Navajo and San Juan stations, as discussed
below. The Company believes that all existing generating facilities are or
will be in compliance with all existing or expected environmental regulations
except as described below.
In the fall of 1990, Congress adopted certain Federal Clean Air Act
Amendments (CAAA) with respect to reductions in sulfur dioxide and nitrogen
oxide emissions which will affect the Company's operation. The required
reductions of sulfur dioxide emissions will be implemented in two phases which
are effective in 1995 and 2000, respectively. The Company is not
affected by the requirements for sulfur dioxide emissions and nitrogen
oxide reductions which went into effect in 1995 (Phase I), but is subject to
the requirements that go into effect January 1, 2000 (Phase II).
In 1993 affected Company generating units were allocated Emission
Allowances based on past use. Beginning with the year 2000, Phase II generating
station units must hold Emission Allowances (by January 30 of the year following
the compliance year) equal to the level of emissions in the compliance year, or
face penalties and a requirement to offset excess tons in future years. An
analysis of the Emission Allowances that were allocated to the Company shows
that the Company may not have sufficient allowances to permit normal plant
operation and be in compliance with the sulfur dioxide regulations once the
Phase II requirements become effective due to the increase in the rated capacity
at Springerville. See Generating and Other Resources, Company Resources,
Springerville Station. To the extent that the Company does not have sufficient
allowances, due to increased energy output at Springerville or due to other
factors, the Company would have to purchase additional Emission Allowances.
Based upon current estimates of additional required Emission Allowances and the
current market price of such allowances, the Company believes that it will be
able to acquire additional required allowances and that such purchases will not
have a material effect on the Company.
The nitrogen oxide emission rule finalized in 1995 allows certain Phase II
affected coal-fired boilers to elect by January 1, 1997, and thus be subject to
compliance beginning January 1, 1997, instead of January 1, 2000. Utility
boilers that so elect are exempt until January 1, 2008, from compliance with any
stricter emission regulations that went into effect January 1, 1997, in the
revised nitrogen oxide rule. The Company has placed Springerville Units 1 and 2
into the early election program to take advantage of the exemption, but may
choose to withdraw in future years after the effects of the revised rules are
determined. In order to comply with the nitrogen oxide emission limits,
Irvington Unit 4 may require installation of low nitrogen oxide
burners by January 1, 2000, at a cost of approximately $1 million.
The CAAA also require multi-year studies of visibility impairment in
specified areas and studies of hazardous air pollutants which relate to the
necessity of future regulations of electric utility generating units. Since
these activities involve the gathering of information not currently available,
the Company cannot predict the outcome of these studies.
As a result of recent and possible future changes in federal and state
environmental laws, regulations and permit requirements, because of and in
addition to the CAAA, the Company may incur additional costs for the purchase or
upgrading of pollution control emission monitoring equipment on existing
electric generating facilities and may experience a reduction in operating
efficiency. There may be a need for variances from certain environmental
standards and operating permit conditions until required equipment and processes
for control, handling and disposal of emissions are operational and reliable.
Failure to comply with any EPA or state compliance requirements may result in
substantial penalties or fines which are provided for by law and which in some
cases are mandatory.
FOUR CORNERS GENERATING STATION
The Company believes that all units at Four Corners are presently operating
in compliance with federal and state regulations.
IRVINGTON GENERATING STATION
The Company's ADEQ operating permit for Irvington Unit 4 expired on
February 8, 1996. By law, the permit remains in effect until ADEQ issues a new
facility-wide Title V permit. The other facilities at the Irvington station
were under the jurisdiction of the PDEQ until 1993. However, because of 1990
CAAA requirements which require the facility to obtain a Title V permit,
the entire facility was placed under the jurisdiction of ADEQ in April 1994.
The Company timely filed a Title V permit application for the Irvington facility
on February 1, 1995, thus providing the facility with a permit application
shield. Each major source requiring a Title V permit must pay an annual
emission-based fee. The fee in 1997 for emissions at the Irvington facility was
assessed at $144,000 and is expected to range between $180,000 to $200,000 for
1998. As discussed above, the Company may need to install low nitrogen oxide
burners at Irvington Unit 4 by January 1, 2000, in order to comply with nitrogen
oxide emission limits.
NAVAJO GENERATING STATION
In 1991, the EPA adopted a rule for the reduction of Navajo's sulfur
dioxide emissions on an annual averaging basis by 90% to address visibility
impairment at Grand Canyon National Park. The Company estimates that its share
of the required capital expenditures remaining as of December 31, 1996 relating
to the rule's implementation will be approximately $17 million, including AFDC,
through 1999.
SAN JUAN GENERATING STATION
The Company believes that all units at San Juan are presently operating in
compliance with federal and state regulations. In order to improve the
efficiency of sulfur dioxide removal at the station, the existing removal
process will be replaced with a new process at an estimated cost to the Company
of $20 million, including AFDC, during the period 1997 through 1999.
SPRINGERVILLE GENERATING STATION
Springerville Units 1 and 2 meet all existing federal and state regulations
pertaining to environmental quality. Springerville Units 1 and 2 are operating
under an operating permit issued by ADEQ on December 19, 1994, which
expires on December 19, 1999. Springerville Generating Station is a major
source requiring a Title V permit, and the Company filed a Title V permit
application for the Springerville facility on February 1, 1995. As a result of
requirements imposed by the CAAA of 1990, each major source requiring a Title V
permit must pay an annual emission-based fee. The fee in 1997 for emissions at
the Springerville Generating Station Units 1 and 2 was assessed at $310,000 and
is expected to be approximately the same for 1998.
EMPLOYEES
The Company and its subsidiaries had a combined total of 1,175 employees as
of December 31, 1996. The IBEW 1116, which represents about 62% of the total
employees, and the Company are parties to a two-year collective bargaining
agreement for the period from December 1, 1996 through November 30, 1998. The
collective bargaining agreement, which was negotiated with and approved by the
IBEW 1116 in December 1996 for classified employees in Tucson, includes annual
wage increases of 3.2% in December 1996 and 3.0% in December 1997, as well as
modifications to the pension plan. This same agreement was also approved by the
IBEW 1116 in January 1997 for classified employees at the Springerville
location.
ENERGY-RELATED VENTURES
The Company has established four wholly-owned subsidiaries for the purpose
of pursuing various energy-related investment opportunities. In 1995, the
Company established Nations Energy Corporation for the purpose of investing in
independent power projects in the domestic and foreign energy markets. In
September 1995, Nations Energy and Trigen Energy Corporation formed a limited
partnership which purchased Coors Brewing Company's energy production assets.
Nations Energy has a 49% interest in such partnership. In 1996, a wholly-owned
subsidiary of Nations Energy acquired an ownership interest in two companies
located in the Czech Republic for the purpose of participating in a power
project to be developed near the City of Kladno, Czech Republic. This project
involves the upgrading and expansion of an existing coal-fired thermal and
electric generating plant. Participation in this project will require
additional capital investment by Nations and related investment authority from
the ACC. In addition to these projects, Nations Energy is presently evaluating
several other investment opportunities in the domestic and foreign energy
markets.
In May 1996 the Company established Advanced Energy Technologies, Inc.
(formerly known as TEP Solar Energy Corporation). This wholly-owned subsidiary
is responsible for developing renewable energy and distributed generation
technologies, and in 1996 it acquired a 50% ownership interest in Global Solar
Energy, LLC, an Arizona corporation recently formed for the purpose of
developing and manufacturing flexible thin-film photovoltaic cells. Commercial
production of photovoltaic cells is presently scheduled to commence in mid-1997.
Global Solar's manufacturing facility is initially expected to produce up to
1,500 kW of product, or approximately 255,000 square-feet of photovoltaic
material, per year.
SWPP Investment Company was formed in 1996 for the purpose of holding an
ownership interest in a business engaged in the manufacture and sale of concrete
power poles. Although SWPP has yet to acquire such ownership interest, the
Company currently has a contract with a Mexican corporation for the distribution
and sale of concrete power poles in the United States.
In January 1997, the Company established another wholly-owned subsidiary
known as Southwest Energy Solutions, Inc. It is anticipated that Southwest
Energy will provide a variety of ancillary energy services to retail electric
consumers. Southwest Energy will likely focus its initial marketing efforts on
electric energy consumers in southern Arizona.
In addition to the activities currently underway or planned for each
of these subsidiaries, the Company continues to evaluate potential investment
opportunities in other energy-related markets. For example, the Company
currently has a consulting services contract with New Energy Ventures Inc.
(NEV), a California corporation. NEV, which recently obtained a Federal Power
Marketer's license from the FERC, is a buyer's agent providing load aggregation
and advisory services to energy consumers located primarily in California. The
Company has a currently exercisable option (through February 1998) to purchase
for a nominal amount a 50% interest in NEV.
In comparison to the Company's large investment in regulated utility
assets, the Company's current investments in Nations Energy, Advanced Energy,
SWPP and Southwest Energy are not material in terms of recorded assets or net
income. As of December 31, 1996, the Company's Consolidated Balance Sheet
reflected an investment in energy-related ventures of approximately $22 million
(included in Investments and Other Property). However, depending on the nature
of future investment opportunities, and the ability of the Company to make
additional investments as determined by the ACC and in certain credit
agreements, the Company expects to make additional investments in these
subsidiaries and in other energy-related ventures. Over time, such additional
investments may have a material impact on the Company's future cash flow and
profitability. Pursuant to an ACC order issued in February 1996, the Company is
permitted to invest in subsidiaries that engage in energy-related projects in an
amount equal to the lesser of $25 million or the maximum amount allowed by the
MRA. To the extent that the Company obtains further authority from the ACC, the
Company would be authorized to expend additional funds. This investment
authority is subject to the conditions that (i) the total amount permitted to be
invested in such projects shall not exceed $50 million annually, (ii) 60% of net
profits from such projects be applied to repay the Company's debt, and (iii)
total investment in such projects does not exceed 15% of the Company's
capitalization. Under the MRA, the Company's capital investments are restricted
to assets which are related to the utility business, and are limited in size by
a ceiling on total capital expenditures and investments. The
Company is currently reviewing different alternatives for funding investments in
energy-related ventures.
UTILITY OPERATING STATISTICS
For Years Ended December 31,
1996 1995 1994 1993 1992
- --------------------------------------------------------------------------------------------------------
Generation and Purchased
Power-kWh (000)
Remote Generation (Coal) 9,784,918 8,716,513 9,341,342 8,986,350 6,148,825
Local Generation (Oil, Gas
& Coal) 723,232 500,958 825,385 615,100 527,405
Purchased Power 925,394 692,769 501,269 335,897 2,436,152
--------- ---------- --------- --------- ---------
Total Generation and
Purchased Power 11,433,544 9,910,240 10,667,996 9,937,347 9,112,382
Less Losses and Company Use 776,436 661,901 639,278 591,412 610,040
--------- ---------- --------- --------- ---------
Total Energy Sold 10,657,108 9,248,339 10,028,718 9,345,935 8,502,342
========= ========== ========= ========= =========
Sales-kWh (000)
Residential 2,516,282 2,330,191 2,374,868 2,223,479 2,146,268
Commercial 1,306,826 1,280,752 1,281,050 1,242,367 1,215,179
Large Users 2,080,763 1,979,317 1,948,331 1,832,278 1,771,937
Mining 1,164,140 1,147,281 1,135,424 1,090,061 1,081,791
Public Authorities 228,800 204,746 183,525 159,310 165,922
--------- ---------- --------- --------- ---------
Total-Retail Customers 7,296,811 6,942,287 6,923,198 6,547,495 6,381,097
Sales for Resale 3,360,297 2,306,052 3,105,520 2,798,440 2,121,245
--------- ---------- --------- --------- ---------
Total 10,657,108 9,248,339 10,028,718 9,345,935 8,502,342
========= ========== ========= ========= =========
Operating Revenues (000)
Residential $237,569 $218,208 $220,341 $197,368 $190,089
Commercial 143,623 138,294 137,508 128,688 125,655
Large Users 154,547 146,409 144,677 131,858 127,456
Mining 56,240 54,948 53,821 53,510 57,266
Public Authorities 16,949 14,952 13,435 11,464 11,757
Other 2,636 2,114 1,651 1,925 1,791
-------- -------- -------- -------- --------
Total-Retail Customers 611,564 574,925 571,433 524,813 514,014
Amortization of MSR Option Gain
Regulatory Liability 20,053 20,053 20,053 6,053 6,053
Sales for Resale 84,256 75,591 99,987 93,273 70,026
-------- -------- -------- -------- --------
Total $715,873 $670,569 $691,473 $624,139 $590,093
======== ======== ======== ======== ========
Customers (End of Period)
Residential 282,060 273,976 266,060 258,168 251,656
Commercial 28,199 27,858 27,360 26,838 26,441
Large Users 626 620 588 551 527
Mining 4 4 4 4 4
Public Authorities 61 59 59 59 59
------- ------- ------- ------- -------
Total Retail Customers 310,950 302,517 294,071 285,620 278,687
======= ======= ======= ======= =======
Average Revenue per kWh Sold (cents)
Residential 9.4 9.4 9.3 8.9 8.9
Commercial 11.0 10.8 10.7 10.4 10.3
Large Users and Mining 6.5 6.4 6.4 6.3 6.5
Total - Retail Customers 8.4 8.3 8.3 8.0 8.1
Average Revenue per
Residential Customer $854 $809 $841 $776 $765
Average kWh Sales per
Residential Customer 9,050 8,641 9,066 8,739 8,632
ITEM 2. -- PROPERTIES
The Company's transmission facilities are located within the states of
Arizona and New Mexico. The primary purpose of the Company's transmission
facilities is to transmit electricity from the Company's remote electric
generating stations at Four Corners, Navajo, San Juan and Springerville to the
Tucson area for use by the Company's retail customers (see Item 1, Business,
Generating and Other Resources for the location of the Company's plants). The
transmission system is directly interconnected with systems operated by the
following utilities:
Utility Location
------- --------
Arizona Public Service Co. Arizona
Arizona Electric Power Cooperative Arizona
El Paso Electric Co. New Mexico, Texas
Public Service Co. of New Mexico New Mexico
Salt River Project Arizona
The Company has arrangements with approximately 160 companies, including the
five listed above, which are utilized to interchange capacity and energy.
As of December 31, 1996, the Company owned or participated in an overhead
electric transmission and distribution system consisting of 511 circuit-miles of
500 kV lines, 1,122 circuit-miles of 345 kV lines, 335 circuit-miles of 138 kV
lines, 454 circuit-miles of 46 kV lines and 9,408 circuit-miles of lower voltage
primary lines. The underground electric distribution system was comprised of
4,771 cable-miles. Approximately 24% of the poles upon which the lower voltage
lines are located are not owned by the Company. Electric substation capacity
associated with the above-described electric system consisted of 169 substations
with a total installed transformer capacity of 5,258,605 kVA.
The electric generating stations (except as noted below), the Company's
general office building, operating headquarters and the warehouse and service
center are located on land owned by the Company in fee. The electric
distribution and transmission facilities owned by the Company are
located (1) on property owned in fee by the Company, (2) under or over streets,
alleys, highways and other public places, the public domain and national forests
and state lands under franchises, easements or other rights which, with some
exceptions, are subject to termination, (3) under or over private property by
virtue of easements obtained for the most part from the record holder of title,
and (4) under Indian reservations under grant of easement by the Secretary of
Interior or lease by Indian tribes. In most instances, no examination has been
made by counsel for the Company as to the title to easements of the Company from
the record holder or to the property over which the easement has been granted,
or as to possible liens, encumbrances, reservations or restrictions thereon.
Therefore, some of the easements and the property over which the easements have
been secured may be subject to title defects and encumbered by, or subject to,
mortgages and liens existing at the time the easements were acquired.
Most of the land parcels comprising Springerville are held by the Company
under a long-term surface ownership agreement with the State of Arizona.
Four Corners and Navajo are located on properties held under easements from
the United States and under leases from the Navajo Indian Tribe. The Company,
individually and in conjunction with PNM in connection with San Juan, has
acquired easements and leases for transmission lines and a water diversion
facility located on the Navajo Indian Reservation. The Company has also
acquired easements for transmission facilities, related to San Juan and Navajo,
across the Zuni, Navajo and Tohono O'odham Indian Reservations.
The Company's rights under the various easements and leases described under
this heading may be subject to possible defects (including conflicting grants or
encumbrances not ascertainable because of absence of or inadequacies in the
recording laws or the record systems of the Bureau of Indian Affairs and the
Indian tribes, the possible inability of the Company to resort to legal process
to enforce its rights against certain possible adverse claimants and the Indian
tribes without Congressional consent, the possible failure or inability of
the Indian tribes to protect the Company's interests in, and use and occupancy
of, these facilities from interference or interruption, and, in the case of the
leases, possible impairment or termination under certain circumstances by
Congress, the Secretary of the Interior or certain possible adverse claimants).
However, these possible defects have not and are not expected to materially
interfere with the Company's interest in and operation of its facilities.
The Company leases under separate sale and leaseback arrangements the
following facilities (which do not include land): (i) the coal handling
facilities at Springerville; (ii) a 50% undivided interest in the other common
facilities at Springerville; (iii) Springerville Unit 1 and the remaining 50%
undivided interest in common facilities at Springerville; (iv) Irvington Unit 4
and related common facilities; and (v) three internal combustion turbines having
a combined net generating capability of 96 MW. See Note 5 of Notes to
Consolidated Financial Statements, Long and Short-Term Debt and Capital Lease
Obligations for additional information on the Company's capital lease
obligations.
Substantially all of the utility assets owned by the Company are subject to
the lien of the General First Mortgage and the General Second Mortgage.
Springerville Unit 2, legal title to which is held by San Carlos, is not subject
to such liens. Springerville Unit 2 is subject to the Unit 2 First Mortgage.
ITEM 3. -- LEGAL PROCEEDINGS
TAX ASSESSMENTS
See Contingencies in Note 6 of Notes to Consolidated Financial Statements.
ITEM 4. -- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable.
PART II
ITEM 5. -- MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The following table sets forth, for the periods indicated, the high and low
sale prices of the Company's Common Stock on the consolidated tape as reported
by Dow Jones. Sale prices prior to May 20, 1996, have been adjusted to reflect
the one-for-five reverse split of the Company's Common Stock in May 1996. No
dividends were paid on Common Stock during such periods.
Market Price per
Quarter Share of Common Stock
------- ---------------------
High Low
1996 ---- ---
----
First $16.88 $14.38
Second 15.00 13.13
Third 17.81 12.25
Fourth 20.75 16.25
1995
----
First $18.75 $15.00
Second 17.50 15.00
Third 16.25 13.13
Fourth 16.25 14.38
The closing price of the Common Stock on the consolidated tape on March 4,
1997 was $14.875.
The Common Stock is traded on the New York Stock Exchange and the Pacific
Stock Exchange. At March 4, 1997, there were 30,821 shareholders of record of
the Common Stock.
See Item 7. - Management's Discussion and Analysis of Financial Condition
and Results of Operations, Dividends on Common Stock.
ITEM 6. - SELECTED CONSOLIDATED FINANCIAL DATA
1996 1995 1994 1993 1992
(In thousands - except per share data and ratios)
Summary of Operations
- ----------------------------------------------------------------------------------------------------------------
Operating Revenues $715,873 $670,569 $691,473 $624,139 $590,093
Regulatory Disallowances and Adjustments - - - (13,777) -
Income Tax Benefit 82,155 20,436 4,911 5,277 5,745
Loss on Restructuring - - - - (26,669)
Income (Loss) from:
Continuing Operations 120,852 54,905 20,740 (21,816) (79,022)
Provision for Loss on Disposal of
Discontinued Operations - - - (4,000) (44,047)
Net Income (Loss) 120,852 54,905 20,740 (25,816) (123,069)
Income (Loss) per Average Share of
Common Stock from:
Continuing Operations (A) $3.76 $1.71 $0.65 $(0.68) $(12.40)
Provision for Loss on Disposal of
Discontinued Operations (A) - - - (0.12) (6.91)
Total Net Income (Loss) per Average
Share of Common Stock (A) $3.76 $1.71 $0.65 $(0.80) $(19.31)
Shares of Common Stock Outstanding
Average (A) 32,134 32,138 32,145 32,109 6,374
End of Year (A) 32,135 32,138 32,145 32,145 32,086
- --------------------------------------------------------------------------------------------------------------
Financial Position
- --------------------------------------------------------------------------------------------------------------
Total Utility Plant - Net $1,953,904 $1,978,126 $2,007,422 $2,029,764 $2,052,695
Investments and Other Property 69,289 52,116 12,992 62,850 98,126
Total Assets 2,568,541 2,563,461 2,730,229 2,742,932 2,656,089
Long-Term Debt 1,223,025 1,207,460 1,381,935 1,416,352 1,466,555
Capital Lease Obligations 895,867 897,958 922,735 927,201 931,163
Common Stock Equity (Deficit) 133,288 12,488 (42,233) (62,973) (38,209)
Total Capitalization 2,252,180 2,117,906 2,262,437 2,280,580 2,359,509
Reserve for Litigation and Contract Disputes - - - - 27,500
Total Capitalization and Other Liabilities 2,568,541 2,563,461 2,730,229 $2,742,932 $2,656,089
- ----------------------------------------------------------------------------------------------------------------
Selected Cash Flow Data
- ----------------------------------------------------------------------------------------------------------------
Cash Flow Interest Coverage (B) 3.2x 2.5x 3.0x 2.3x 2.0x
Cash & Cash Equivalents/Current Liabilities (C) 0.92 0.48 1.29 0.91 1.06
Construction Expenditures
(including AFDC) $66,519 $59,097 $62,599 $48,162 $34,512
Cash Generated as a Percent of
Construction Expenditures:
Internally Generated (D) 227% 202% 229% 186% 257%
Internally Generated (D), Including
Drawdowns of Funds Held in Trust 227% 202% 229% 227% 305%
- ----------------------------------------------------------------------------------------------------------------
Note: See Item 7., Management's Discussion and Analysis of Financial Condition and Results of Operations.
(A) Per share data restated to reflect the one-for-five reverse stock split in May 1996.
(B) Cash from Continuing Operations plus Interest Paid divided by Interest Paid.
(C) Excludes Cash from Discontinued Operations.
(D) Cash generated is cash provided from continuing operations. The ratio for 1992 includes cash
conserved under the payment moratoria implemented by the Company on certain obligations during 1992.
ITEM 7. -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following contains information regarding the Company's continuing and
discontinued operations during 1996 compared with 1995 and 1995 compared with
1994 and changes in liquidity and capital resources of the Company during 1996.
Also, management's expectations of identifiable material trends are discussed
herein.
OVERVIEW
Earnings for the Company improved in 1996 as net income increased to $120.9
million from $54.9 million recorded in 1995 and $20.7 million recorded in 1994.
The improvement over 1995 earnings is due primarily to the recognition of
K-21
substantial non-cash income tax benefits as well as to increased sales and
revenues, reduced operating and capital costs, and a reversal of loss provision
involving the Company's non-energy related subsidiaries. Due to continuing
improvement in the Company's profitability, the Company recognized non-cash
income tax benefits associated with the current and expected future utilization
of federal and state net operating loss carryforwards generated in prior
periods. Such recognized benefits totaled $88.6 million in 1996 and $23.3
million in 1995. See Income Tax Position below. The Company had common stock
equity of $133.3 million at year-end, compared to $12.5 million as of December
31, 1995.
In addition to the income tax benefits described above, items having a one-
time effect on earnings during 1996 include net pre-tax charges of $10.6 million
related to implementation of the Company's Voluntary Severance Plan (VSP),
charges of $9.2 million related to a court ruling on contested sales tax
assessments, and income of $9.5 million attributable primarily to a reversal of
loss provision involving the Company's non-energy related subsidiaries. See
Notes 5, 6, and 8 of Notes to Consolidated Financial Statements for information
pertaining to these items. During 1995 the Company recorded a one-time $12.2
million reduction to fuel and purchased power expense due to the satisfaction of
certain fuel contract provisions. Net income for 1995 was also affected by a
one-time gain of $3.6 million related to sales of securities and a reduction in
loss reserves for the non-energy related subsidiaries. Excluding each of these
one-time items from the periods in which they were recorded, the Company's
income before income taxes increased to $48.9 million in 1996 from $18.6 million
in 1995. The following table compares the Company's operating results in 1996
and 1995 exclusive of these one-time items and the recognition of NOL
carryforward benefits:
1996 1995
- Thousands of Dollars -
Net Income $120,852 $54,905
One-Time Items:
Fuel and Purchased Power 0 (12,245)
Taxes Other Than Income Taxes(1) 7,331 0
Employee Severance Plan Expense - Net 10,555 0
Other Income - Reversal of Loss Provision(2) (8,472) 0
Other Income - Other(2) (1,064) (3,623)
Interest Expense - Other(1) 1,880 0
Estimated Income Taxes Associated
with One-Time Items(3) (4,130) 6,408
------ ------
Net Adjustment for One-Time Items 6,100 (9,460)
NOL Carryforward Benefits (88,638) (23,282)
------ ------
Total Adjustments to Net Income (82,538) (32,742)
Net Income, as Adjusted for One-Time Items
and NOL Carryforward Benefits $38,314 $22,163
======= =======
- --------------------------------------------
(1) Adjustments related to contested sales tax assessments.
(2) Adjustments related to the Company's non-energy related subsidiaries.
(3) Calculated based on composite income tax rate of 40.4%.
Due primarily to increased cash receipts from retail customers, net cash
flows from continuing operating activities also improved in 1996, increasing to
$151.3 million in 1996 from $119.4 million in 1995 and $143.6 million in 1994.
After capital expenditures, scheduled debt maturities and payments to retire
capital lease obligations, net cash flows available for other investing and
financing activities were $36.9 million in 1996, $25.9 million in 1995, and
$61.1 million in 1994.
Despite improvements in the Company's financial performance, the Company's
financial prospects continue to be subject to significant economic, regulatory
and other uncertainties, some of which are beyond the Company's control. These
uncertainties include the degree of utilization of generation capacity through
either retail electric service or wholesale sales and the extent to which the
Company, due to continued high financial and operating leverage, can alter
operations and reduce costs in response to industry changes or unanticipated
economic downturns. The Company's success will depend, in part, on the
Company's ability to contain the costs of serving retail customers and the level
of sales to such customers. Although the Company anticipates continued growth
in sales over the next five years primarily as a result of anticipated
population and economic growth in the Tucson area, a number of factors such as
changes in the economic and regulatory environment and the increasingly
competitive electric markets could affect the Company's levels of sales.
The Company is developing strategies to address the uncertainties discussed
above as well as to position itself to benefit from the changing regulatory
environment. Such strategies include the implementation of enhanced cost
measurement and management techniques, organizational realignment and staffing
reductions, and the development of new entities to provide energy services to
markets beyond the Company's retail service territory. See Note 8 of Notes to
Consolidated Financial Statements, Employee Benefit Plans, Voluntary Severance
Plan (VSP), and Investments in Energy-Related Ventures below.
If the Company is unable to make sales at prices adequate to recover its
costs or if for other reasons the Company fails to maintain or improve its cash
flows, the Company's ability to meet its obligations may be jeopardized. During
the period 1999-2003, approximately $250 million of the Company's long-term debt
obligations will mature. Letters of credit supporting $805 million of the
Company's long-term variable rate debt obligations are also scheduled to expire
during the period 1999-2002. Should the credit ratings on the Company's senior
debt securities reach investment grade levels on certain dates or during certain
periods subsequent to January 1, 1998, the expiration dates for such letters of
credit would move forward to the period 1998-2000. In the event that expiring
letters of credit are not replaced or extended, the corresponding variable rate
debt obligations would be subject to mandatory redemption. While the Company
intends to pay or refinance maturing bonds, and to replace or extend expiring
letters of credit, there can be no assurance that the Company will be able to
pay such debt or replace or extend such letters of credit. The Company's future
cash flows will also be affected by the level of interest rates due to the
significant amount of variable rate debt outstanding. See Liquidity and Capital
Resources below.
The Company's capital structure is highly leveraged and the Company's
ability to raise capital (through either public or private financings) is
limited. The Company's ability to obtain debt financing is limited due to the
restrictive covenants contained in existing obligations to creditors. To the
extent the Company refinances its debt obligations in order to repay them when
due, such refinancing may be made on terms which may be adverse to the Company.
Such terms could include, among other things, higher interest rates and various
restrictive covenants, such as dividend payment restrictions. Access to equity
capital may be limited because of the Company's present inability to pay
dividends. See Dividends on Common Stock below.
During the next twelve months, the Company expects to be able to fund
continuing operating activities and construction expenditures with internal cash
flows, existing cash balances, and, if necessary, drawdowns under the Renewable
Term Loan and/or borrowings under the Revolving Credit. As discussed in
Liquidity and Capital Resources below, there are a variety of factors that could
cause actual cash flows to differ materially from projected cash flows. As of
March 4, 1997, the Company's cash balance including cash equivalents was
approximately $82 million. Cash balances are invested in investment grade,
money-market securities with an emphasis on preserving the principal amount
invested.
COMPETITION
WHOLESALE
The Company competes with other utilities, marketers and independent power
producers in the sale of electric capacity and energy in the wholesale market.
The Company's prices for wholesale sales of capacity and energy, generally, are
not permitted to exceed rates determined on a cost of service basis. In the
current market, wholesale prices are substantially below costs determined on a
fully allocated cost of service basis, but, in all instances, wholesale sales
have been made at prices which exceed the level necessary to recover fuel and
other variable costs. It is expected that competition to sell capacity will
remain vigorous, and that prices may remain depressed for at least the next
several years, due to increased competition and surplus capacity in the
southwestern United States. Competition for the sale of capacity and energy is
influenced by many factors, including the availability of capacity in the
southwestern United States, the availability and prices of natural gas and oil,
spot energy prices and transmission access. In addition, the Energy Policy Act
of 1992 has promoted increased competition in the wholesale electric power
markets by encouraging the participation of utility affiliates, independent
power producers and other non-utility participants in the development of power
generation.
The FERC issued two orders pertaining to transmission access in April 1996.
FERC Order No. 888, among other things, requires all public utilities that own,
control, or operate interstate transmission facilities to offer transmission
service to others under a single tariff that incorporates certain minimum terms
and conditions of transmission service established by the FERC. This tariff
must also be used by public utilities for their own wholesale market
transactions. Transmission and generation services for new wholesale service
are to be unbundled and priced separately. FERC Order No. 889 requires
transmission service providers to establish or participate in an open access
same-time information system (OASIS) that provides information on the
availability of transmission capacity to wholesale market participants. The
order also establishes standards of conduct that are designed to prevent
employees of a public utility engaged in marketing functions from obtaining
preferential access to OASIS-related information or from engaging in unduly
discriminatory business practices.
Given the level of competition already present in the wholesale market for
electricity, the Company does not believe that FERC Order No. 888 or Order No.
889 will have a material effect on the Company's future results of operations.
However, these orders could assume greater significance if the Company's retail
service territory were to be opened to competing suppliers of electricity.
RETAIL
Under current law, the Company is not in direct competition with any other
regulated electric utility for electric service in the Company's retail service
territory. However, the Company does compete against gas service suppliers and
others who may provide energy services which would be substitutes for, or bypass
of, the Company's services. In addition, the ACC recently adopted rules that
require a phase-in of retail electric competition in Arizona over a four year
period beginning January 1, 1999.
Electric energy for meeting retail customers' needs primarily competes with
natural gas, an alternative fuel source for certain retail energy uses. Such
uses may include heating, cooling and a limited number of other energy
applications. In most applications, electric energy is a cost effective source
of energy compared with natural gas. Also, customers, particularly industrial
and large commercial customers, may own and operate facilities to generate their
own electric energy requirements and, if such facilities are qualifying
facilities, to require the displaced electric utility to purchase the output of
such facilities at "avoided costs" pursuant to the Public Utilities Regulatory
Act of 1978, as amended. Such facilities may be operated by the customers
themselves or by other entities engaged for such purpose.
The Company actively markets energy and customized energy-related services
to meet customer needs. The Company has to date lost no customers to self-
generation in part because of such efforts. For example, the Company's two
principal mining customers, which provide approximately 10% of the Company's
total annual revenues from retail customers, each have considered self-
generation. However, following negotiations with the Company in 1993 and 1994,
new contracts were executed that included, among other things, rate reductions
and term extensions. In 1996, the Company negotiated contract amendments with
its largest mining customer. In return for further rate reductions and a market
pricing mechanism covering a portion of the customer's electrical load, service
to this customer was changed from a firm basis to an interruptible basis,
thereby delaying the Company's need for additional peaking capacity. In
addition, the provisions allowing for an early termination of the contract were
substantially narrowed. Such contract is scheduled to expire in January 2003,
while the contract with the Company's other principal mining customer is
scheduled to expire in March 2001. Early terminations of the contracts by
mining customers require at least one and up to two years prior notice. To
date, no such notice has been received. The ability to enter into or extend
contracts, to avoid early termination, and to retain customers will be dependent
on, among other thin