FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)
For the fiscal year ended December 31, 19941995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the transition period from __________ to __________..
Commission File Number 1-5924
TUCSON ELECTRIC POWER COMPANY
(Exact name of registrant as specified in its charter)
ARIZONA 86-0062700
(State or other jurisdiction ofOther Jurisdiction (IRS Employer
incorporation or organization)of Identification No.)
Incorporation or
Organization) P.O. BOX 711
85702
220 WEST SIXTH STREET, (Zip Code)
TUCSON, ARIZONA
P.O. BOX 711
85701 85702
(Address of principal executive offices) (Zip Code)Principal
Executive Offices)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (602)(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 $542,442,494.25$502,084,300.00 based on the
last reported sale price thereof on the consolidated tape on March 6, 1995.1, 1996.
At March 6, 1995, 160,723,7021, 1996, 160,666,976 shares of the registrant's Common Stock, no
par value (the only class of Common Stock), were outstanding.
Documents incorporated by reference: Specified portions of Tucson Electric
Power Company's Proxy Statement relating to the 19951996 Annual Meeting of
Shareholders are incorporated by reference into PART III.
TABLE OF CONTENTS
Page
Definitions viDefinitions....................................................vi
- PART I -
Item 1. ------ Business
The Company 1...................................................1
Certain Risks 1
The Financial Restructuring 1Risks; Forward-Looking Information ....................1
Utility Operations
Peak Demand and Customers 2...................................1
Peak Demand 2Demand................................................1
Sales for Resale 3............................................3
Competition 3
Nations Energy Corporation 4.................................................3
Generating and Other Resources
Company Resources 5...........................................4
Springerville Station 5Station......................................4
Irvington Station 6Station..........................................5
SCE/TEP Power Exchange Agreement 6............................5
Future Generating Resources 6.................................5
Other Purchases 6.............................................6
Rates and Regulation
General 7.....................................................6
1995 Rate Application .......................................7
Notice of Intent to Form a Holding Company ..................8
1994 Rate Order 7.............................................8
Other Rate Matters 8..........................................8
Fuel Supply
General 8.....................................................9
Coal 8........................................................9
Valencia 9...................................................10
Gas 10........................................................11
Water Supply 10.................................................11
Environmental Matters
General 10....................................................11
Four Corners Generating Station 11............................12
Irvington Generating Station 11...............................12
Navajo Generating Station 11..................................13
San Juan Generating Station 11................................13
Springerville Generating Station 11...........................13
Employees 12....................................................13
Discontinued Investment Subsidiary Operations 12................13
Utility Operating Statistics 13.................................14
Item 2. ---- Properties 14-- Properties..........................................15
Item 3. ------ Legal Proceedings
SDGE/FERC Proceedings 15........................................16
Tax Assessments ..............................................16
Water Rights Adjudication 15
Tax Assessments 15....................................16
Item 4. --- Submission of Matters to a Vote of Security Holders 15Holders.16
- PART II -
Item 5. ------ Market for Registrant's Common Equity and Related
Stockholder Matters 16Matters...........................................17
Item 6. ------ Selected Consolidated Financial Data 17
TABLE OF CONTENTS
(CONTINUED)
PageData................18
Item 7. ------ Management's Discussion and Analysis of Financial Condition and
Results of Operations
Overview
18
ProposedGeneral ....................................................19
Competition
Wholesale ..................................................20
Retail .....................................................21
Holding Company 19Proposal .....................................22
Nations Energy Corporation .................................23
Results of Operations ........................................23
Results of Utility Operations
Sales and Revenues 20Revenues........................................23
Operating Expenses 20Expenses........................................24
Other Income (Deductions) 21.................................25
Interest Expense 22
Results of Discontinued Operations 22Expense..........................................25
Accounting for the Effects of Regulation 22.....................26
Dividends 23....................................................26
Liquidity and Capital Resources
Cash Flows 23.................................................27
Financing Developments 24.....................................28
Short-Term Credit Facilities
Revolving Credit 24
Other 24Credit..........................................28
Other.....................................................28
Income Tax Position ..........................................29
Restrictive Covenants
General First Mortgage Covenants 25...........................29
General Second Mortgage Covenants 25
Prepayments 25..........................30
Additional Restrictive Covenants 26...........................30
Construction Expenditures 26....................................30
Item 8. ------ Consolidated Financial Statements and
Supplementary Data 26Data............................................31
Independent Auditors' Report 27.................................32
Consolidated Statements of Income (Loss) 28
Consolidated Balance Sheets 29
Consolidated Statements of Capitalization 30.....................33
Consolidated Statements of Cash Flows 31........................34
Consolidated Balance Sheets ..................................35
Consolidated Statements of Capitalization ....................36
Consolidated Statements of Changes in Stockholders'
Equity (Deficit) 32.............................................37
Notes to Consolidated Financial Statements
Note 1. Nature of Operations and Summary of Significant Accounting Policies
Nature of Operations 33.......................................38
Basis of Presentation 33......................................38
Use of Estimates 33...........................................38
Regulation 33.................................................38
Accounting for the Effects of Regulation 33...................38
Utility Plant 34..............................................40
Utility Plant Under Capital Leases 35
Allowance for.........................40
Springerville Unit 1 35Allowance .............................41
Deferred Common Facility Costs 36.............................41
Utility Operating Revenues 36
Amortization of.................................41
MSR Option Gain Regulatory Liability 36.......................41
Fuel and Purchased Power Costs 36
Financial Restructuring Costs 36.............................42
Income Taxes 37
Debt Expense 37...............................................42
EPA Allowances .............................................42
Fair Value of Financial Instruments 37........................43
Reclassification 37...........................................43
New Accounting Standards ...................................43
Note 2. Rate Matters
1995 Rate Increase Application .............................44
1994 Rate Order 38............................................44
Note 3. 1992 Consummation of the Financial Restructuring 38
Banks 39
TABLE OF CONTENTS
(CONTINUED)
Page
Springerville Unit 1 39
Capital Leases 39
Preferred Stock 39
Other 40Income Taxes ........................................45
Note 4. Income Taxes 40Consolidated Subsidiaries
Nations Energy Corporation..................................47
Discontinued Operations ....................................48
Note 5. Discontinued Operations 42
Note 6. Long and Short-Term Debt and Capital Lease Obligations
Long-Term Debt .............................................48
First Mortgage Bonds and Installment Sale Agreement 43
Restructured Arrangements 43Bonds......................................48
MRA.......................................................48
Dividends - Restrictive Covenants.........................49
Letters of Credit 43Credit.........................................49
Renewable Term Loan 44
Additional Restrictive Covenants 44Loan.......................................49
Fair Value of Long-Term Debt 44Debt..............................50
Authorization To Issue Tax-Exempt Bonds...................50
Capital Lease Obligations ..................................50
Maturities and Sinking Fund Requirements ...................51
Short-Term Debt
Revolving Credit 45
Discontinued Operations 45
Capital Lease Obligations 45Credit..........................................51
Investment Subsidiaries...................................51
Note 7.6. Commitments and Contingencies
Utility Contractual Matters
Coal and Transportation Contracts 45- Reversal of
Accrued Liabilities......................................52
Fuel Purchase Commitments 46Commitments.................................52
Commitments-Environmental Regulation 46.......................52
Contingencies
SDGE/FERC Proceedings 47
San Diego Gas & Electric v. Tucson Electric Power
Company 47Company................................................53
Alamito Company, Docket No ER79-97-009 47..................53
Tax Assessments 48Assessments...........................................53
Note 8. SCECorp/SCE Litigation Settlement 48
Note 9.7. Jointly Owned Facilities 49.............................54
Note 10.8. Employee Benefits Plans
49
Pension Plans 49..............................................54
Postretirement Benefits Other Than Pensions 50
Adoption of FAS 112 50................55
Stock Option Plans 50.........................................56
Note 11.9. Quarterly Financial Data (unaudited) 52.................58
Note 12.10. Supplemental Cash Flow Information 53..................59
Item 9. ------ Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure 54Disclosure...........................................60
- PART III -
Item 10. ------ Directors and Executive Officers of the Registrant
Directors 54....................................................60
Executive Officers 54...........................................60
Item 11. ------ Executive Compensation 56Compensation.............................62
Item 12. ------ Security Ownership of Certain Beneficial Owners and Management
General 56......................................................62
Security Ownership of Certain Beneficial Owners 56..............62
Security Ownership of Management 56.............................62
Item 13. ------ Certain Relationships and Related Transactions 56
TABLE OF CONTENTS
(CONCLUDED)
PageTransactions.....62
- PART IV -
Item 14. ------ Exhibits, Financial Statement Schedules, and
Reports on Form 8-K
578-K...........................................63
Signatures 58...................................................64
Exhibit Index 60................................................66
DEFINITIONS
The abbreviations and acronyms used in the 19941995 Form 10-K are defined below:
ACCACC............... Arizona Corporation Commission.
ACC StaffStaff......... Staff of the Arizona Corporation Commission.
ADEQADEQ.............. Arizona Department of Environmental Quality.
AFDCAFDC.............. Allowance for Funds Used During Construction.
APB11 Accounting Principles Board Opinion #11: Accounting for
Income Taxes.
APSAPS............... Arizona Public Service Company.
ArticlesArticles.......... Company's Restated Articles of Incorporation, as amended.
BanksBanks............. Various banks with which the Company has credit
relationships.
BrooklandBrookland......... Brookland Financial Corporation, a wholly-owned, indirect
subsidiary of SRI.
BTUSRI, which formerly initiated and sold
vehicle contract receivable portfolios.
BTU............... British Thermal Unit(s).
CAAACAAA.............. Federal Clean Air Act Amendments.
CatalystCatalyst.......... Catalyst Energy Corporation, the parent company of
Century.
CenturyCentury........... Century Power Corporation, an indirect subsidiary of
Catalyst and formerly known as Alamito Company.
Citadel Citadel Holding Corporation, a California-based holding
company.
ClosingClosing........... The closing of the transactions contemplated by the
Financial Restructuring, which occurred on December 15,
1992.
Commission or SECSEC. Securities and Exchange Commission.
Common StockStock...... The Company's common stock, without par value.
Company or TEPTEP.... Tucson Electric Power Company.
Creditors Certain of the Company's creditors and lease participants
and Century and the Springerville Unit 1 Leases'
participants.
CWIPCWIP.............. Construction Work In Progress.
Emission
Allowance(s)..... An EPA issued allowance which permits emission of one ton
of sulfur dioxide. Such allowances can be sold.
Energy ActAct........ The Energy Policy Act of 1992.
EPAEPA............... The Environmental Protection Agency.
FAS 13 Statement of Financial Accounting Standards #13:
Accounting for Leases.
FAS 15 Statement of Financial Accounting Standards #15:
Accounting by Debtors and Creditors for Troubled Debt
Financial Restructurings.
FAS 7171............ Statement of Financial Accounting Standards #71:
Accounting for the Effects of Certain Types of Regulation.
FAS 9292............ Statement of Financial Accounting Standards #92:
Regulated Enterprises - Accounting for Phase-In Plans.
FAS 98 Statement of Financial Accounting Standards #98:
Accounting for Leases: Sale Leaseback Transactions
Involving Real Estate, Sales-Type Leases of Real Estate,
Definition of the Lease Term, Initial Direct Costs of
Direct Financing Leases.
FAS 101101........... Statement of Financial Accounting Standards #101:
Regulated Enterprises-Enterprises - Accounting for the Discontinuation
of Application of FAS 71.
FERCFERC.............. The Federal Energy Regulatory Commission.
Financial
RestructuringRestructuring.... The comprehensive financial restructuring of the Company's
obligations to Creditorscertain 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
BondsBonds............ The Company's first mortgage bonds issued under the
General First Mortgage.
Four CornersCorners...... Four Corners Generating Station.
GAAPGAAP.............. Generally Accepted Accounting Principles.
Gallo Wash Gallo Wash Development Company, a wholly-owned subsidiary
of Valencia.
General First
MortgageMortgage......... 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
MortgageMortgage......... The Indenture, dated as of December 1, 1992, of Tucson
Electric Power Company to Bank of Montreal Trust Company
of the City of New York, as trustee, as supplemented.
Holding Company
ActAct............... The Public Utility Holding Company Act of 1935, as
amended.
IBEW 11161116......... International Brotherhood of Electrical Workers labor
union, Local Chapter 1116.
IDBsIDBs.............. Industrial development revenue or pollution control
revenue bonds.
DEFINITIONS
(continued)
Installment Sale
Agreement $52Agreement........ $49 million principal amount of City of Farmington, New
Mexico, 6.25% Pollution Control Revenue Bonds Series
1973.
Interconnection Agreement The Company's agreement with Century for
receiving, delivering and transmitting power.
IRSIRS............... Internal Revenue Service.
IrvingtonIrvington......... Irvington Generating Station.
Irvington LeaseLease... The leveraged lease arrangement relating to Irvington Unit
4.
Irvington Unit 44.. Unit 4 of the Irvington Generating Station.
ITCITC............... Investment Tax Credit.
kWtax credit.
kW................ Kilowatt(s).
kWhkWh............... Kilowatt-hour(s).
kVkV................ Kilovolt(s).
kVAkVA............... Kilovoltampere(s).
LOCLOC............... Letter of Credit.
MRAMRA............... The master financial restructuring agreement completed
during the Financial Restructuring agreement between the Company
and the Banks (other than the Bank providingcertain banks excluding the LOC relating to the 1981
Apache B Bonds) which includes the Renewable Term Loan,
Revolving Credit, Additional
Reimbursement Agreement and Replacement Reimbursement
Agreement.
MSRLOCs.
MSR............... Modesto, Santa Clara and Redding Public Power Agency.
MWMW................ Megawatt(s).
MWhMWh............... Megawatt-hour(s).
Nations EnergyEnergy.... Nations Energy Corporation, a wholly-owned subsidiary of
the Company.
NavajoNavajo............ Navajo Generating Station.
NOL............... Net Operating Losses.
1989 Rate OrderOrder... The ACC's October 24, 1989, Rate Order concerning the
Company's 1988 application for a rate increase.
1981 Apache A Bonds $100 million principal amount of variable rate IDBs
assumed by Century in 1984 from which the Company
released Century as part of the Financial Restructuring.
1981 Apache B
BondsBonds............ $100 million principal amount of variable rate IDBs which
are secured by First Mortgage Bonds.
1990 Pima A BondsBonds. $20 million principal amount of variable rate IDBs which
are secured by First Mortgage Bonds.
1994 Rate OrderOrder... The ACC's January 11, 1994, Rate Order concerning an
increase in the Company's retail base rates and
regulatory write-offs.
1991 Rate OrderOrder... The ACC's October 11, 1991, Rate Order concerning an
increase in the Company's retail base rates, regulatory
write-offs and rate and accounting synchronization.
NPC Nevada Power Company.
NTUANTUA.............. Navajo Tribal Utility Authority.
Palo Verde The Palo Verde Nuclear Generating Station.
Payment Moratorium Payment moratoria implemented by the Company with
respect to certain obligations of the Company commencing
January 31, 1991.
PDEQPDEQ.............. Pima County Department of Environmental Quality.
P&M&M............... Pittsburg & Midway Coal Mining Co.
PNM Public Service Company of New Mexico.
Preferred StockStock... 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.
PNMProposed Settlement
Agreement....... The Agreement between the Company and the ACC Staff that
proposed to settle both the 1995 rate application and the
notice of intent to form a holding company.
PNM............... Public Service Company of New Mexico.
PURPA ............ The Public Utility Regulatory Policies Act of 1978, as
amended.
Reimbursement
AgreementsAgreements....... Eleven separate reimbursement agreements between the
Company and individual Banks pursuant to which LOCs were
issued by such Banks to trustees for issues of tax-exempt
IDBs issued by several government entities to finance
certain facilities of the Company.
Renewable Term
LoanLoan............. The credit facility that replaces the Term Loan pursuant
to the MRA Sixth Amendment, dated as of November 1, 1994,
completed March 7, 1995.
Replacement LOCs The extensions to at least 1997 of the LOCs as part of the
Financial Restructuring.
ReplacementReplacment Reimbursement
AgreementAgreement....... A new master reimbursement agreement entered into among
the Company and all Banks that are parties to the
Reimbursement Agreements with the exception of the Bank
which issued the LOC supporting the 1981 Apache B Bonds.
DEFINITIONS
(concluded)
Restated Century Purchase
Contract Contract pursuant to which the Company was obligated
to purchase the entire capacity of Springerville Unit 1
from Century through December 31, 2014.RUCO.............. Residential Utility Consumer Office.
Revolving CreditCredit.. The $50 million revolving credit facility entered into
between a syndicate of certain of the Banks and the
Company as part of the Financial Restructuring.
RTGsRTGs.............. Regional Transmission Groups.
San CarlosCarlos........ San Carlos Resources Inc., a wholly-owned subsidiary of
the Company.
San JuanJuan.......... San Juan Generating Station.
San Juan Unit 33... Unit 3 of San Juan.
SCESCE............... Southern California Edison Company, a subsidiary of SCECorp.
SDGEEdison
International.
SDGE.............. San Diego Gas & Electric Company.Company, a subsidiary of Enova
Corporation.
Second Mortgage
BondsTheBonds............ The Company's second mortgage bonds issued under the
General Second Mortgage.
Securities Exchange
ActAct.............. The Securities Exchange Act of 1934, as amended.
Southwest GasGas..... Southwest Gas Corporation.
SWRTA ............ Southwest Regional Transmission Association.
SpringervilleSpringerville..... Springerville Generating Station.
Springerville Common
Facilities Leases The leveraged lease arrangement relating to the Company's
undivided one-half interest in certain facilities at
Springerville used in common with Springerville Unit 1
and Springerville Unit 2.
Springerville
Unit 11............ Unit 1 of the Springerville Generating Station.
Springerville
Unit 1 LeasesLeases.... The leveraged lease arrangement pursuant to which Century
leased Springerville Unit 1 and which has been assumed by
the Company.
Springerville
Unit 22........... Unit 2 of the Springerville Generating Station.
SRISRI............... Sierrita Resources Inc., a wholly-owned investment
subsidiary of the Company.
SRPSRP............... Salt River Project Agricultural Improvement and Power
District.
Term LoanLoan......... The $243.4 million original principal amount term loan
provided by a syndicate of certain Banks as part of the
Financial Restructuring.
TRITNP............... Texas New Mexico Power Company.
TRI............... Tucson Resources Inc., a wholly-owned investment
subsidiary of the Company.
Unit 2 First
MortgageMortgage......... First mortgage lien on and security interest in
Springerville Unit 2 which secures, in part, the Term
Loan, the Revolving Credit and the Replacement
Reimbursement Agreement.
ValenciaValencia.......... Valencia Energy Company, a wholly-owned subsidiary of the
Company.
Valencia LeasesLeases... Valencia's leveraged lease arrangement relating to the
coal handling facilities serving Springerville.
WarrantsWarrants.......... Warrants for purchase of the Common Stock which were
issued under the Financial Restructuring to the owner
participants in the Springerville Unit 1 Leases.
WRTA ............. Western Regional Transmission Association.
WSCCWSCC.............. Western Systems Coordinating Council.
PART I
ITEM 1. --- BUSINESS
THE COMPANY
Tucson Electric Power Company was incorporated under the laws of the State
of Arizona on December 16, 1963. The Company is the successor by merger as of
February 20, 1964, to a Colorado corporation which was incorporated on January
25, 1902. The Company is an operating public utility engaged in the generation,
purchase, transmission, distribution and sale of electricity for customers in
the City of Tucson and the surrounding area and to wholesale customers. The
Company holds a franchise which expires in 2001 to provide electric service to
customers in the City of Tucson.
The Company owns all of the outstanding stock of (i) Valencia Energy
Company (Valencia), which supplies coal to the Springerville Generating Station
(see Fuel Supply Valencia), all of the outstanding stock ofValencia ), (ii) San Carlos Resources Inc. (San Carlos),
which holds title to Springerville Unit 2, and all of the
outstanding stock of(iii) Nations Energy Corporation.Corporation
which is active in the development of independent power projects worldwide. See
Competition below for a description of Nations Energy. The Company also owns
all of the outstanding stock of two non-energy related investment subsidiaries,
Tucson Resources Inc. (TRI) and Sierrita Resources Inc. (SRI). See Consolidated Statements of Income (Loss) and Note 5 of Notes to
Consolidated Financial Statements, Discontinued Operations for comparative
financial information relating to the Company's investment business segments.In 1994, TRI and
SRI have substantially completed the process of liquidating their respective
investments.
CERTAIN RISKSRISKS; FORWARD-LOOKING INFORMATION
For descriptions of certain factors affecting the Company, including
commitments and contingencies, which subject the Company to continuing risks,
see (i) 1995 Rate Application and 1994 Rate Order; (ii) Discontinued Investment Subsidiary Operations;
(iii) Item 3., Legal
Proceedings; (iv)(iii) Item 7., Management's Discussion and Analysis of Financial
Condition and Results of Operations, Overview; and (v)(iv) Notes 1, 2 and 76 of
Notes to Consolidated Financial Statements, 1994Nature of Operations and Summary of
Significant Accounting Policies, Rate Order,Matters, and Commitments and
Contingencies, respectively.
THE FINANCIAL RESTRUCTURING
In December 1992,The forward-looking statements contained herein regarding growth in the
number of customers, growth in retail peak demand and retail sales growth are
based, in part, upon publicly available population and demographic studies
conducted by persons or entities unaffiliated with the Company. Such statements
are also based upon various assumptions including, without limitation,
assumptions relating to weather, economic and competitive conditions and the
assumption that the Company consummated a comprehensive restructuringwill incur no significant loss of obligationsretail customers
due to certain creditors and reclassified its preferred stock into
common stock. The Financial Restructuring was concluded following negotiations
with various creditors including, but not limited to, bank lenders and lease
participants. See Note 3 of Notes to Consolidated Financial Statements, 1992
Consummation of the Financial Restructuring. The Company initiated the
Financial Restructuring because it projected that it might have insufficient
liquidity to meet its cash obligations by the end of the first quarter of 1991.
A payment moratorium on certain of the Company's debt, lease, coal and rail
obligations during part of the period of negotiations provided cash flow
sufficient to meet the Company's other obligations.
The Company believes that the Financial Restructuring provides the Company
the opportunity to return gradually to long-term financial viability. However,
the Financial Restructuring itself will not be sufficient to assure the
Company's long-term financial viability. Also, the Company's capital structure
remains highly leveraged and the Company's financial prospects and cash flows
remain subject to significant economic, regulatory and other uncertainties, many
of which are beyond the Company's control.self-generation or retail wheeling. Actual experience may vary
significantly from forward-looking information.
UTILITY OPERATIONS
PEAK DEMAND AND CUSTOMERS
Certain operating and system data related to the Company's utility
operations for each of the last five years were as follows:
PEAK DEMAND
PEAK DEMAND 1995 1994 1993 1992 1991
1990
- MW ----- ---- ---- ---- ----
-MW-
Retail Customers-Net One Hour 1,617 1,585 1,449 1,399 1,319
1,356
Other Utilities-Firm 223 226 225 150 150
100----- ----- ----- ----- -----
Non-Coincident Peak Demand (A) 1,840 1,811 1,674 1,549 1,469
1,456----- ----- ----- ----- -----
Total Generating Resources (B) 2,085 1,975 1,975 1,983 2,048
2,048----- ----- ----- ----- -----
Total Reserves ((B) - (A)) 245 164 301 434 579
592===== ===== ===== ===== =====
Reserve Margin (% of Non-Coincident
Peak Demand) 13% 9% 18% 28% 39%
41%===== ===== ===== ===== =====
The peak demand for the Company's retail service area occurs during the
summer months due to the space cooling requirements of its retail customers.
The Company has experienced growth in peak demand (excluding the demand of its
copper mining customers which fluctuates widely)customers) at an average annual rate of approximately 4.9%3.9% for the
past five years. Including the load of its mining customers, which comprised on
average approximately 8.0%8.5% of the retail peak demand for the past five years,
the Company experienced growth in peak demand of retail customers at an average
annual rate of approximately 4.0%3.6% during the same period.
In 1994,1995, based on non-coincident peak demand, the Company's reserve margin
was only 9%13% compared with 18%9% in the prior year.year due to the addition of the SCE/TEP
power exchange to the Company's available resources. (See SCE/TEP Power
Exchange Agreement below.) The Company seeks to maintain a reserve margin
equal to its largest single hazard plus 5% of its non-
coincidentnon-coincident peak demand in
accordance with guidelines established by the WSCC. The targeted reserve
requirement was 295296 MW in 19941995 or 16% of non-coincident peak demand. The
Company's operations were not adversely affected by the Company's failure to
maintain its targeted reserve requirement in 1994.1995. It is expected that near-termnear-
term growth in demand will be met with existing resources and the additional
capacity provided under a power exchange agreement between the
Company and SCE. See SCE/TEP Power Exchange Agreementresources as discussed in Future Generating Resources below. Also, see
Generating Resources below for a discussion of the Company's electric
generating resources.
The averagegrowth in the number of retail customers servedremained strong in 1995,
increasing by 2.9% compared to the Company increased 2.9%
in 1994 compared with 1993 and 2.1% onfive-year annual average annually over the past five
years.of 2.4%. The Company is currently projecting an average annual customer growth
rate of approximately 2.5% and an average annual
growth rate in the number of customers is expected to be approximately 2.2%
through the year 2000. Retail peak demand of retail customers of approximately 1.4% for the period 1995 through 1999.
Realized growth in customers and retail demand may be affected by factors
discussed under Competition below. Customer growth rates are projectedis expected to exceed historical growth rates because the Company anticipates greater
population and economic growth than occurred in the past five years.
Also, the Company is projecting a 2.3%grow at an average
annual rate of 2.1% during the same period. The average annual rate of growth
rate inof energy sales to retail customers overis anticipated to be in the next five years. Sales to2.3% range for
the remainder of the decade. On average, residential, non-mining industrial,
and mining customersenergy sales are expected to account for approximately 41%34%, 26%28%, and 10%17%,
respectively, of the projected sales.sales for the remainder of the decade.
The Company has two principal copper mining customers. In 1994,1995, the sales to
suchthese customers represented 11% and 6%totaled approximately 16.6% of the Company's total retail energy
sales, and their contract demands were 6% and 5%, respectively,totaled approximately 11% of the Company's 19941995 retail non-
coincident
peak demand. The total coincident peak load for the Company's two mining
customers was 8.6%6.9% of the Company's 1994 retailcoincident peak demand. Revenues from sales to mining
customers have comprised betweenaccounted for an average of approximately 10% and 11% of the Company's
revenues from retail customersrevenues in each of the three years in the
period ended December 31, 1994.
In March 1994, thefrom 1993 to 1995.
The Company and the largeserves its two principal mining customer to which the
Company supplied approximately 50 MW, executed a new contract that included acustomers under reduced rate
contracts designed to induce such customerthem to remain oncontinue to purchase electricity from the
Company's systemCompany rather than self-generate. In April 1994, the ACC approved such contract.
Revenues from this customer were $23.6 million and $22.3 million in 1993 and
1994, respectively. In 1993, the Company entered into a similar contract with
its largest mining customer although at a different rate level. These contracts expire after the year 2000.
However, such contracts contain various provisions allowing the customers to
terminate partially or entirely, under certain circumstances, provided that the
Company has beenis notified at least one and up to two years prior to such termination.
The ability to extend contracts and to avoid early termination will be dependentdepend on
market conditions at the time and alternatives available to customers at that time.alternatives.
Future markets and prices for fuel, access to capital, as well as ACC
decisions regarding rate design, and the timing of rate decisions will affect
the economics of self-generation projects (including cogeneration) and may
ultimately affect whether customers, such as the mining customers described
above, if any, might reduce or terminate their contract demanddemands on the Company's system. Seesystem
(see Competition below.below).
SALES FOR RESALE
The Company makes sales for resale to others on both a firm and an
interruptible basis. To the extent capacity is not providing energy to the
Company's retail customers, such as during off-peak periods, the Company markets
this capacity and energy at wholesale. Surplus energy is sold from time to time
under various power pooling arrangements. The Company currently has contracts
to sell firm capacity as follows:
Minimum
(or Maximum)
Contract
Company Demand MW Contract Term
------- --------- -------------
SRP 100 June 1, 1991 - May 31, 2011
NPC 50 May 16, 1990 - December 31, 1995
NTUA (1) 45 June 1, 1993 - May 31, 1999
TNP 30 January 1, 1996 - December 31, 1996
(1)The agreement with NTUA provides for a minimum contract demand of 45 MW
and requires NTUA to obtain all of its electric power requirements from the
Company. NTUA'sNTUA is a winter peaking utility and their coincident peak demand
is expected to be aboutreach approximately 70 MW.
COMPETITION
Under current law,MW during the Company is not in direct competition with any other
regulated electric utility for electric service in the Company's retail service
territory. Regardlessterm of such regulation, the Company competes for retail
markets against gas service suppliers and others who may provide energy services
which would be substitutes for, or bypass of, the Company's services.this contract.
The Company does compete with other utilities, marketerscontinues to actively market long-term and independent
power producers in the saleshort-term sales of
electricexcess capacity and energy in the wholesale
market. It is expected that competitionenergy. Competition to sell capacity willis expected to remain
vigorous and that prices will remain depressed for severalin the next few years due to increased
competition andas a result of surplus capacity in the
southwesternSouthwestern United States. Competition
for the sale of capacityStates and energy is influenced by many factors, including the
availability of capacity of the 3,810 MW Palo Verde nuclear generating station
and other generating stationsdepressed prices in the southwestern United States, the
availability and prices of natural gas and oil, spot energy prices and
transmission access. In addition, the Energy Act has increased competition in
the wholesale electric power markets.
The Energy Act addresses a wide range of energy issues, including several
matters affecting bulk power competition in the electric utility industry. It
creates exemptions from regulation under the Holding Company Act for persons or
corporations that own and/or operate in the United States certain generating and
interconnecting transmission facilities dedicated exclusively to wholesale
sales, thereby encouraging the participation of utility affiliates, independent
power producers and other non-utility participants in the development of power
generation. In order to facilitate competition in power generation, the Energy
Act also confers expanded authority upon FERC to issue orders requiring electric
utilities to transmit power and energy to or for wholesale purchasers and
sellers, and to require electric utilities to enlarge or construct additional
transmission capacity to provide these services. While the Energy Act prohibits
FERC from issuing any such order that would unreasonably impair the continuing
reliability of affected electric systems or that would be conditioned upon or
require transmission services directly to an ultimate consumer, the Energy Act
creates the potential for utilities and other power producers to gain increased
accessmarket due to the
transmission systemsabundance of other entities to facilitate wholesale
sales. FERC is encouraging all parties interested in transmission access to
form RTGs to facilitate access to and development of transmission service and to
assist in settling disputes regarding such matters. RTGs will not relieve FERC
of its responsibilities related to transmission access; however, such
organizations could provide for more efficient handling of transmission service
requests and planning for regional transmission needs. The Company is currently
involved in the development of two RTGs in the West, SWRTA and WRTA. WRTA and
SWRTA both filed applications for approval with the FERC during 1994 which have
yet to be accepted. The Company currently intends to become a member of SWRTA
and is also considering membership in WRTA.
On the retail level, industrial and large commercial customers may have the
ability to own and operate facilities to generate their own electric energy
requirements and, if such facilities are qualifying facilities, to require the
displaced electric utility to purchase the output of such facilities at "avoided
costs" pursuant to PURPA. Such facilities may be operated by the customers
themselves or by other entities engaged for such purpose.
Finally, the legislatures and/or the regulatory commissions in several
states have considered or are considering "retail wheeling" which, in general
terms, means the transmission by an electric utility of energy produced by
another entity over its transmission and distribution system to a retail
customer in such utility's service territory. A requirement to transmit
directly to retail customers could have the result of permitting retail
customers to purchase electric capacity and energy from, at the election of such
customers, the electric utility in whose service area they are located or from
other electric utilities or independentlow-cost hydroelectric power producers.
In Arizona, the ACC Staff issued its first report on a retail electric
competition workshop held in October of 1994. This report is the first in a
series of reports that will be issued on various workshops that will be held
from time to time to identify and address policy issues related to competition.
While other states are considering competition proposals, the ACC effort is
designed to obtain information about competition. No specific proposals are
currently being considered. The report proposes that Staff develop a
comprehensive set of options to better inform the ACC about its choices. Staff
recommended that three options be considered: 1) encouraging retail
competition, 2) tolerating limited retail competition, and 3) discouraging
retail competition by prohibiting retail wheeling and tolerating distributed
energy services. The ACC has also established a working group on retail
electric competition. Membership in the working group includes ACC Staff,
Arizona utilities, and other interested parties, and the first meeting of the
group took place in January 1995. A report from the group is expected by August
1995. The Company cannot predict what the working group will recommend and
what, if any, changes in electric regulation and competition will be implemented
by the ACC.
See Peak Demand and Customers above for information concerning mining
customers which have considered self-generation and Generating and Other
Resources and Other Purchases and Item 2., Properties below for information
concerning the Company's transmission access to and interchange relationships
with other utilities in the southwestern United States.
The Company continues to assess the impact of the Energy Act and other
possible legislation on the Company's ability to remain competitive in the
electric utility industry. The Company is unable to predict the ultimate impact
the Energy Act or any other possible legislation will have on its operations.
NATIONS ENERGY CORPORATION
The Company's wholly-owned subsidiary Nations Energy Corporation
(previously known as Escalante Resources, Inc.) is pursuing opportunities in the
independent power business. Nations Energy is exploring independent power
prospects in the domestic and foreign energy markets. Such prospects may
include, for instance, the development of cogeneration facilities, the
acquisition of interests in existing power production facilities that sell to
utilities or utility authorities, or the construction of independent power
projects in countries that are privatizing their electric utility industry.
Initially, an emphasis will be placed on exploring opportunities in the Western hemisphere. To date, no projectUnited States.
Regarding the contracts described above, the Company cannot currently make any
predictions about the replacement or extension of such contracts in the future.
However, the Company has been approved for development or
acquisition. Nations Energy's activities may be limited due to various
restrictions including certain restrictions imposed bynotified that TNP will not renew its current
contract with the MRA.Company in 1997.
COMPETITION
See Item 7., -- Management's Discussion and Analysis of Financial Condition
and Results of Operations, Restrictive Covenants, Additional Restrictive Covenants.
In an effort to adapt its structure toCompetition, for a discussion of developments
regarding competition in the new competitive environment,industry at the Company is currently planning to create a holding company. See Item 7.,
Management's Discussion and Analysis of Financial Condition and Results of
Operations, Proposed Holding Company.wholesale as well as at the retail
level.
GENERATING AND OTHER RESOURCES
COMPANY RESOURCES
The total net generating capability currently owned or leased by the
Company at December 31, 19941995 was 1,952 MW as set forth in the table below:
Net
Capa-
Unit Fuel bility Operating Company Share
Generating Source No. Location Type MW Agent % MW
- ----------------- ---- -------- ---- ------ --------- --------------
Springerville Station 1 Springerville, AZ Coal 360 TEP 100.0 360
Springerville Station 2 Springerville, AZ Coal 360 TEP 100.0 360
San Juan Station 1 Farmington, NM Coal 316 PNM 50.0 158
San Juan Station 2 Farmington, NM Coal 312 PNM 50.0 156
Navajo Station 1 Page, AZ Coal 750 SRP 7.5 56
Navajo Station 2 Page, AZ Coal 750 SRP 7.5 56
Navajo Station 3 Page, AZ Coal 750 SRP 7.5 56
Four Corners Station 4 Farmington, NM Coal 784 APS 7.0 55
Four Corners Station 5 Farmington, NM Coal 784 APS 7.0 55
Irvington Station 1 Tucson, AZ Gas/Oil 81 TEP 100.0 81
Irvington Station 2 Tucson, AZ Gas/Oil 81 TEP 100.0 81
Irvington Station 3 Tucson, AZ Gas/Oil 104 TEP 100.0 104
Irvington Station 4 Tucson, AZ Coal/Gas/Oil 156 TEP 100.0 156
Internal Combustion
Turbines Tucson, AZ Gas/Oil 218 TEP 100.0 218
-----
Total Company Capacity(1) 1,952
=====
(1)Excludes 23 MW of additional resources, which consists of certain other
capacity purchases and interruptible retail load. Total Company Capacity(1) 1,952
(1) Excludes 133 MW of additional resources, which consists of certain other
capacity purchases and interruptible retail load. Total Company-owned
capacity is 1,339 MW and Company-leased capacity
owned is 1,339 MW and leased is 613 MW. Internal
combustion turbines with 100 MW of capacity are leased by the Company. At
the end of such lease in 1998, the Company may exercise fair market value
purchase and renewal options.
SPRINGERVILLE STATION
Springerville Station consists of two 360 MW coal fired units.
Springerville Unit 1 began commercial operation in 1985 and is currently leased
and operated by the Company. Springerville Unit 2 commenced commercial
operation in June 1990 and is owned by San Carlos and operated by the Company.
Prior to the Closing, the Springerville Station was operated by Century, Century
leased Springerville Unit 1 and the Company purchased capacity and energy from
Springerville Unit 1 under the Restated Century Purchase Contract.
The primary terms of the Springerville Unit 1 Leases expire on January 1,
2015. At December 31, 1994,1995, the capitalized lease asset related to Springerville
Unit 1, net of allowance and accumulated amortization, was $260 million for
financial statement purposes.$257 million. At the
end of the primary term, the Company may exercise fair market value purchase and
renewal options. Annual lease payments for the Springerville Unit 1 Leases will
range from $33 million to $176 million, but averageaveraging approximately $73$76 million.
The average cash cost to the Company of Springerville Unit 1 capacity
attributable to rent obligations and other operation and maintenance expenses
after December 15, 1992, is estimated to be approximately $18 per kW per month
(approximately $78 million per year), for the period from January 1993 through
December 1997 and willis expected to increase thereafter. However, due to timing
differences between cash and accrued expenses, capacity costs attributable to
rent obligations and other operation and maintenance expenses will be accrued in
the Company's financial statements over the 1993 - 1997 period at an average of
approximately $22 per kW per month (approximately $95 million per year) before
amortization of the regulatory disallowance and interest expense thereon. The
1991 Rate Order allows the Company to recover the cost of the entire 360 MW
capacity of Springerville Unit 1, but limits such recovery to a rate of $15 per
kW per month (approximately $65 million per year). Substantially all of the
present value of disallowed Springerville Unit 1 costs was recorded as a loss in
1990, and as a result of the Financial Restructuring, an additional loss was
recorded in 1992. The losses together reflect the present value of the
difference between projected costs and the amount the Company is allowed to
recover through the lease term ending January 1, 2015. See NotesNote 1 and 3 of Notes to
Consolidated Financial Statements, Nature of Operations and Summary of
Significant Accounting Policies, Allowance for
Springerville Unit 1 and 1992 Consummation of the Financial Restructuring,
Capital Leases, respectively.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, 1994,1995, the capitalized lease asset related to Springerville common
facilities, net of accumulated amortization, was $126 million for financial
statement purposes.$124 million. The initial
lease term for the common facilities expires in 2017 for one owner participant
and 2021 for the other two owner participants, subject to optional renewal
periods and purchase options. Annual lease payments for the common facilities
vary with changes in the interest rate on the underlying debt. In 1993 and 1994, suchSuch lease
payments totalledtotaled $12 million in both 1994 and 1995, and totaled $7 million and
$12 million, respectively.in
1993. Based on current interest rates, annual lease payments would average
approximately $13 million.
Including the cost of leased common facilities (but excluding the cost of
coal-handling facilities at Springerville which are included in recoverable fuel
costs), the total initial cost of Springerville Unit 2 was $838 million, or
$2,328 per kW. Approximately 26% of such cost is attributable to AFDC accrued
prior to July 1, 1989. In the 1991 Rate Order, the ACC disallowed recovery from
retail customers of $175 million of the book value of Springerville Unit 2. The
Company recorded a loss for such disallowance in 1991. The net recoverable
cost, including the leased common facilities, is $1,842 per kW. See Rates and
Regulation, 1994 Rate Order and Note 2 of Notes to Consolidated Financial
Statements, 1994 Rate Order.
IRVINGTON STATION
In January 1988, the Company began coal-fired commercial operation and
entered into a sale and leaseback arrangement for Irvington Unit 4 pursuant to
the Irvington Lease. The unit was sold at its cost of $152 million. At
December 31, 1994,1995, the capitalized lease asset related to Irvington Unit 4, net
of accumulated amortization, was $128 million for financial statement purposes.$123 million. This lease calls for annual
payments which will range from approximately $9 million to $28 million and which
average approximately $13 million. The lease term expires in 2011, but the
lease provisions have optional renewal periods and purchase options.
With the addition of coal firing capability, Irvington Unit 4 (156 MW
capability) has the flexibility to operate on coal, gas or fuel oil. Coal has
been the primary fuel and natural gas the secondary fuel.
SCE/TEP POWER EXCHANGE AGREEMENT
As part of a 1992 litigation settlement, the Company and SCE have agreed to a
ten-year power exchange agreement. Under the agreement, beginningwhich began in May
1995, SCE will provideprovides firm system capacity of 110 MW to the Company during summer
months, for which the Company will paypays an annual capacity charge of approximately $1
million increasing annually after the first five years to a maximum of
approximately $2 million annually. The Company will beis entitled to schedule firm
energy deliveries from SCE during the summer (May 15 through September 15) of up
to 36,300 MWh per month, and will beis obligated to return to SCE on an interruptible
basis the same amount of energy the following winter season (November 1 through
February 28). The Company will incur fuel expense
relatedenergy provided pursuant to the exchange in an amount equal tois expensed based
upon the cost of interruptible energy provided to SCE. The Company believes the
agreement may reduce the Company's overall system fuel costs, allow it to sell
additional capacity on the wholesale market, and/or permit it to defer the
construction of future generating resources. The agreement has been accepted for filing by the FERC. The 1994 Rate Order directed the
Company to propose an allocation of the benefits of this agreement with its
retail customers. The Company expects to includeincluded such an allocation proposal in its next1995
rate filing.application and in the Proposed Settlement Agreement. See Rates and
Regulation, 19941995 Rate Order.Application. In 1995, pursuant to the exchange
agreement, the Company received 91,000 MWh, and as of the end of January 1996,
the Company had provided 72,255 MWh SCE.
FUTURE GENERATING RESOURCES
In December 1992,1995, the Company filed an integrated resource plan pursuant to
the ACC's regulations governing resource planning. In its filing the Company
projected nothe need for any newan additional 128 MW of peaking or intermediate generation facilities
until afterresources in 1998 and
additional peaking resources in the year 2000 or2002 and beyond. No need for
additional base load generation facilities until afterwas forecast through the year 2007.2010.
The Company has begun a program to determine whether the 1998 peaking resource
should be constructed by the Company or purchased. In addition, the Company
projected that demand-side management programs should reduce peak demand and,
therefore, capacity requirements, from what they would be without such programs
by 7660 MW by the year 2000. As part of the integrated resource plan, the Company
has committed to adding 5 MW of renewable generation resources generation by the year 2000. Also as mentioned above, the
Company has a power exchange agreement with SCE; such exchange will provide
additional generating resources to the Company.
OTHER PURCHASES
In addition to generating electricity at generating stations owned or
leased by the Company 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 74130 electric systems or suppliers, including those in the
southern California markets. The Company is a member of the Inland Power Pool,
which is comprised of a group of utilities serving customers in portions of the
western United States. The Inland Power Pool membership facilitates interchange
with companies having system peak periods different from those of the Company.
The Company is also a member of the WSCC, a group of western electric systems
and suppliers that works cooperatively to assure the reliability of the region's
interconnected generation and transmission systems. In 1990, the Company joined
the Western Systems Power Pool which is a voluntary power pooling experiment to
achieve more efficient use of electric generation and transmission facilities
among its members. See Competition for a discussion of possible changes in
transmission issues.
RATES AND REGULATION
GENERAL
The Company is subject to the jurisdiction of the ACC, which has authority,
among other things, to prescribe the classifications of accounts to be used and
the rates and charges to be made and collected from retail customers, and to
regulate the issuance of securities. The ACC also has authority to approve
affiliate transactions and the establishment of holding companies and
subsidiaries under ACC promulgated Affiliated Interest Rules. The Company is
also subject to regulation by FERC in certain respects, including the terms and
prices of sales to other utilities.
Arizona statutelaw 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
judgementjudgment by the ACC regarding prudency and recoverability.
The Company's rates for wholesale sales of capacity and energy, generally,
are not permitted by FERC to exceed rates determined on a cost of service basis.
In all
instances,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 any eventall instances, rates exceed the level necessary to recover fuel and
other variable costs.
The ACC consists of three commissioners, each serving a six-year term. One
of the three is elected at each general election except when a vacancy occurs
prior to the expiration of a commissioner's term. The present commissioners
are:
- - Renz D. Jennings (Democrat), Chairman, was elected to a third term in 1992.
His term expires in 1999.
- - Marcia Weeks (Democrat) was elected to a second term in 1990. Her term
expires in 1997.
- - Carl Kunasek (Republican) was elected to a first term in 1994. His term
expires in 2001.
Under a 1992 Arizona law, commissioners cannot serve consecutive terms and
can be elected to another term only after the passing of six years after the end
of their previous term as commissioners.
1995 RATE APPLICATION
On June 13, 1995, the Company filed an application with the ACC requesting
an overall 4.9% increase in retail rates (approximately $28.4 million in annual
revenues). The Company's request was based on original cost rate base of
approximately $1.17 billion, a rate of return on original cost rate base of
8.2%, a rate of return on common equity of 11.5%, and a 1994 test period.
The proposed rate structure was a continuation of the Company's effort to
insure that retail customer classes pay their appropriate allocated share of the
cost of providing service. The Company proposed increases of 7.5% for
residential customers, 3.6% for commercial customers, and 5.0% for industrial
customers. The proposed increase would result in an increase of $5.37 in the
average monthly residential bill, from $70.92 (9.46 cents per kWh) to $76.29
(10.17 cents per kWh) for residential customers using an average 750 kilowatt-
hours per month.
The application requested recovery of the costs associated with the
remaining 37.5% (135 MW) of Springerville Unit 2 that is "used and useful" in
accordance with ACC methodologies. Currently, the Company is only allowed to
recover 62.5% of the costs related to Springerville Unit 2. In 1994, the
Company's system peak demand was 139 MW over the demand upon which current rates
are based. Total proposed additions to rate base due to the inclusion of the
remaining 37.5% of Springerville Unit 2, including related deferrals of
previously incurred costs, amounted to approximately $191 million.
The Company's request contained elements of traditional cost of
service/rate of return ratemaking as well as several proposals designed to
increase the Company's competitiveness. Such proposals included, among others,
the flexibility to enter into special contracts with customers without specific
ACC approval at prices below previously approved tariff levels; allocation of
the savings resulting from improved operating efficiencies between the Company
and its customers; allocation of the benefits of the 110 MW added generating
capacity related to the SCE/TEP Power Exchange solely to the retail customers;
and allocation of new long-term wholesale sales based on marginal costs of a
wholesale transaction rather than the Company's average costs.
The Company further proposed that, if the ACC approved the Company's
request and proposals as filed, the Company would not file another rate case
until the year 2000, absent any emergencies.
On November 30, 1995, the Company reached an agreement with the ACC Staff
proposing to resolve the Company's application for a rate increase, and the
Company's notice of intent to form a holding company. The Proposed Settlement
Agreement was subject to final approval by the full ACC following a hearing
which started on January 17, 1996. At the conclusion of such hearings, on
January 19, 1996, the ACC denied the Proposed Settlement Agreement by a 2 to 1
vote. On January 24, 1996, the Company filed a motion for reconsideration with
the ACC. On February 13, 1996, the motion for reconsideration was deemed denied
by operation of law. Although the Company's application for a rate increase
remains pending, the Company intends to propose and seek approval of a revised
settlement agreement in March 1996.
The Proposed Settlement Agreement called for a one-time base rate increase
of 1.8%, or $8.4 million annually. Also, the Company agreed not to seek another
increase in base rates before January 1, 2000. The agreement also would have
permitted the Company to invest up to $50 million annually in energy-related
businesses. Although the agreement would not have approved the holding company
structure, it did provide that the Company could re-file for authority to
establish a holding company in 18 months from the approval of the Proposed
Settlement Agreement. See Notice of Intent to Form a Holding Company below
for a description of further action taken by the ACC with respect to the
formation of a holding company.
NOTICE OF INTENT TO FORM A HOLDING COMPANY
In February 1995, the Company filed a Notice of Intent to Form a Holding
Company with the ACC. In June 1995, the ACC Staff filed testimony recommending
that the ACC deny the Company's request on the basis that retail customers would
be exposed to certain risks resulting from diversification. However, ACC Staff
recommended that, in the event that the ACC approves formation of the holding
company, the ACC impose various operating and financial conditions on the
Company and the holding company. In concurrently filed testimony, RUCO, an
intervenor in the matter, did not oppose the formation of the holding company.
The Company filed rebuttal testimony on July 27, 1995, and a public hearing was
held on August 22, 1995.
In November 1995, the Company and the ACC Staff entered into the Proposed
Settlement Agreement which included a proposal to resolve the Company's holding
company application. On January 19, 1996, the Proposed Settlement Agreement was
denied (see 1995 Rate Application above). Following the denial of the Proposed
Settlement Agreement, the ACC Hearing Officer submitted a recommended order on
the holding company proposal.
On February 22, 1996, the ACC denied the formation of a holding company.
However, the ACC granted the Company a waiver for the authority to invest in
subsidiaries that will engage in energy related projects in an amount equal to
the lesser of $25 million or the maximum amount allowed by the MRA. To the
extent that the Company obtains retroactive approval or waiver of projects from
the ACC, the energy related diversification amount will be reinstated up to the
$25 million limit. This investment authority is subject to the conditions that
(i) the total waiver amount shall not exceed $50 million annually, (ii) 60% of
net profits from diversified activities be applied to repay the Company's debt
and (iii) total investment in such diversified activities does not exceed 15% of
the Company's capitalization.
1994 RATE ORDER
On January 11, 1994, the ACC issued a decision approving a 4.2% retail rate
increase for the Company. The new rates were effective as of January 11, 1994.
According to the 1994 Rate Order, the new rates were intended to produce an
annual increase in gross revenues of approximately $21.6 million based upon a
test year ended June 30, 1992. This reflects an allowed original cost rate base
of approximately $1.0 billion and a return on original cost rate base (after
write-offs) of 8.51% based upon a rate of return on common equity of 11%. The
Company requested in its January 1993 filing a $49 million increase in gross
revenues based on an original cost rate base of approximately $1.1 billion and a
rate of return base of 9.17% based upon 12.5% return on equity. In determining
the required return on rate base, the 1994 Rate Order utilized a hypothetical
capital structure of 49.8% long-term debt, 44.1% common equity, 4.7% preferred
equity and 1.4% short-term debt as contemplated under a 1991 rate settlement
agreement.
The decision authorized the inclusion of an additional 17.5% of
Springerville Unit 2 in rate base, for a total of 62.5%. The 1994 Rate Order
also allowed inclusion of 62.5% of the Springerville Unit 2 rate synchronization
and excess capacity deferred expenses in rate base. Amortization of those rate
synchronization deferred expenses allowed in rate base was authorized to be
recovered from retail customers over a three-year period. However, amortization
of the excess capacity deferred expenses allowed in rate base was authorized to
be recovered from retail customers over 37.4 years. The 37.5% of the rate
synchronization and excess capacity expenses not currently being recovered
continue to accrue at a 7.19% interest carrying charge. See Note 2 of Notes
to Consolidated Financial Statements, 1994 Rate Order.
Based on the 1994 Rate Order, the Company recorded an additional $13.6
million in write-offs related to previously capitalized Springerville Unit 2
costs and certain other minor costs for which recovery was permanently
disallowed. See Note 2 of Notes to Consolidated Financial Statements, 1994 Rate
Order.
The Company's filing also discussed a proposal for the allocation of the
future benefits of the 1992 settlement of a lawsuit brought against SCECorp. and
SCE for interference with the Company's 1988 attempted merger with SDGE. SCE
paid the Company a $40 million cash settlement and entered into a ten-year, 110-
megawatt power exchange agreement to begin in 1995 which FERC has accepted for
filing. The ACC stipulated in the 1994 Rate Order that the Company use $27
million of the litigation settlement, which is equal to the $40 million less
costs of litigation, to prepay debt. Also, the ACC ordered the Company to
submit a proposal for the sharing of the benefits of the SCE power exchange
agreement. The Company expects to include such benefit sharing proposal in its
next rate filing.
The Company intends to seek rate recovery of the costs associated with the
remaining 37.5% of Springerville Unit 2 that is not in base rates. This rate
request is expected to be filed in 1995.
See Note 2 of Notes to Consolidated Financial Statements, 1994 Rate Order,
for additional discussion concerning theMatters, 1994 Rate Order.
OTHER RATE MATTERS
See Utility Operations, Peak Demand and Customers for a discussion of the
Company's contracts and negotiations with certain of its mining customers.
FUEL SUPPLY
GENERAL
The Company's principal fuel for electric generation is low-sulfur coal.
The following table provides fuel cost information for the years 19941995 through
1990:
Cost Per Million BTU Consumed Percentage of Total BTU Consumed
1994 1993 1992 1991 1990 1994 1993 1992 1991 1990
Coal(A)(B) $2.06 $2.01 $1.89 $2.04 $1.94 98% 99% 99% 99% 99%
Gas 1.86 2.76 2.39 2.14 2.67 2 1 1 1 1
--- --- --- --- ---
All Fuels 2.05 2.02 1.90 2.05 1.95 100% 100% 100% 100% 100%
=== === === === ===1991:
Cost Per Million BTU Consumed Percentage of Total BTU Consumed
----------------------------- --------------------------------
1995 1994 1993 1992 1991 1995 1994 1993 1992 1991
---- ---- ---- ---- ---- ---- ---- ---- ---- ----
Coal (A) $1.89 $2.06 $2.01 $1.89 $2.04 99% 98% 99% 99% 99%
Gas 1.69 1.86 2.76 2.39 2.14 1 2 1 1 1
--- --- --- --- ---
All Fuels 1.89 2.05 2.02 1.90 2.05 100% 100% 100% 100% 100%
==== ==== ==== ==== ====
(A)The average cost per ton of coal for each of the last five years (1994(1995 -
1990)1991) was $35.53, $38.93, $37.60, $36.46 $39.55 and $37.90, respectively.
(B) Includes the cost of fuel handling facilities at Springerville. Such costs
per million BTU consumed were: $0.36, $0.37, $0.26, $0.35 and $0.25 for 1994
to 1990,$39.55, respectively.
COAL
The Company is the operator for the Springerville and Irvington generating
stations. Their coal supplies are transported from northwestern New Mexico by
railroad. The coal contract for Springerville is for the remaining lives of
Units 1 and 2 with a bilateral option to renegotiate the contract price and
escalation procedures in 2009 and every five years thereafter. At Irvington,
the contract termination date is the earlier of 2015 or the remaining life of
Unit 4. The Springerville and Irvington contracts have various adjustment
clauses which will affect the future cost of coal delivered. Coal reserves are
expected to be sufficient to supply the estimated requirements of Springerville
and Irvington for their presently estimated remaining lives. TEP is a
participant in the San Juan Generation Station and shares a 50/50 responsibility
split of the coal agreement. The coal quantities for the San Juan Station, a
mine mouth operation, are partially contracted through the year 2017. The
Company also participates in jointly owned generating facilities under long-term
contracts entered into by the operating agents. Coal supplies are surface-mined
in northern Arizona and northwestern New Mexico. The coal quantities under
contract for Four Corners terminate in 2005. The coal quantities under contract
for the Navajo and Four Corners mine-mouth coal fired generating stationsstation are expected to be
sufficient to supply the estimated requirements for theirits presently estimated
remaining lives. The coal quantities for San
uan, also a mine-mouth generating station, are partially contracted through the
year 2017.life. Additional information concerning the coal contracts is set
forth below:on the following page:
Year Average Cost Per
Year Average Million
Contract Sulfur BTU inMillion BTU(A)
Station Coal Supplier Terminates Content 1994(A)1995 1994 1993 Coal Obtained From(B)
- ------- ------------- ----------- ------- ---- ---- ---- ---------------------
Four Corners BHP Utah International, Inc. 2005 0.8% $1.15 $1.28 $1.15 Navajo Indian Tribe
San Juan San Juan Coal Company 2017 0.8% $1.76 $1.81 $1.89 Federal and State Agencies
Navajo Peabody Coal Company 2011 0.6% $1.12 $1.09 $1.11 Navajo and Hopi Indian Tribes
Springerville Hanson Natural Resources Company (C) 0.7% $2.33(C)$2.20(D) $2.47(D) $2.33(D) Lee Ranch Coal Company
Irvington The Pittsburg & Midway Coal
Mining Company 2015 0.4% $2.20 $2.21 $2.50 Navajo Indian Tribe and
Federal and Federal and State Agencies
(A)Includes costs of transportation and handling in addition to the purchase
price under the basic contract.
(B) Substantially all of the suppliers' leases extend at least as long as coal
is being mined in economic quantities.
(C) The coal contract for Springerville is for the remaining lives of Units 1
and 2 with a bilateral option to renegotiate the contract price and
escalation procedures in 2009.
(D) The Springerville costs include approximately $0.93 per million BTU for costs associated with Valencia operations,
including the costs of the Valencia Leases. Such costs were 65 cents, 60
cents, and 56 cents for 1995, 1994 and 1993, respectively. Valencia is
responsible for the handling of fuel for the Springerville Station.
In 1991, 1992, 1993 and 1994, the Company obtained various amendments to
its contracts with the Springerville and Irvington coal and rail transportation
suppliers. The Company estimates that such amendments produced aggregate
savings of $59.6 million, $42.7 million, and $27.8 million in 1994, 1993 and
1992, respectively, compared with the costs which would have been incurred had
such amendments not been obtained.
Some of the 1991 amendments provided for the repayment of certain amounts
withheld during the Payment Moratorium and the forgiveness of other amounts in
exchange for certain land. All of the 1991 amendments provide for the
preservation of the suppliers' claims under the original contracts, as though
such contracts had not been amended, for a period of four years from the
amendments if the Company does not perform under the terms of the amended
contracts. See Note 7 of Notes to Consolidated Financial Statements,
Commitments and Contingencies.
Also, in July 1992 the contract with the San Juan coal suppliersupply agreement was amended to, among
other things, reduce operations and maintenance pass-through costs by 10%,
reduce ash handling costs and also to provide price reduction incentives for
coal purchased above certain minimum quantities. Such amendment provides yearly
savings to the Company of approximately 6%, or $1.4 million. On September 1,
1995, the San Juan agreement was amended to allow the mines the flexibility of
mining more economical leases. The reductions will be passed on to TEP in the
form of lower unit costs.
The Company intends to continue to actively negotiate its fuel and
transportation contracts in 19951996 and in the future.
VALENCIA
Valencia is responsible for the acquisition, transportation and handling of
fuel for Springerville. Pursuant to a fuel burn agreement with the Company,
Valencia has the exclusive right and obligation to provide all of the fuel
requirements for Springerville.
Pursuant to the Valencia Leases, Valencia is the lessee of the coal-
handling facilities at Springerville under a capital lease with a remaining
initial lease term of approximately 2120 years with incremental extensions of five
to six years depending on certain criteria at the date of each extension. At
December 31, 1994,1995, the capitalized lease asset related to Springerville coal-
handlingValencia coal-handling
facilities, net of accumulated amortization, was $184 million for
financial statement purposes.$181 million. Annual rental
payments range from approximately $15$10 million to $25$28 million but average $21
million. Rental payments and other obligations of Valencia under the leases are
guaranteed by the Company.
Valencia allocates portions of its costs to deferred expense for future
recovery through sales of fuel. See Note 1 of Notes to Consolidated
Financial Statements, Nature of Operations and Summary of Significant
Accounting Policies, for a description of the accounting for Valencia lease
costs.
GAS
In 1994,1995, the Company purchased a small amount of natural gas for power
generation (less than 2% of total Company generation) from Southwest Gas,
Anthem
Energy, BridgeGas, Chevron, Natural Gas Clearinghouse, Mobil and USGT. During 1994,1995, the Company
received natural gas sufficient to meet all of its gas fuel requirements; however, as in the past, the Company's supply of natural gas for
boiler fuel may be limited occasionally in the future.requirements.
WATER SUPPLY
Arrangements have been made for water sufficient to supply the requirements
of existing and planned units of all electric generating stations in which the
Company has an interest for their estimated lives.
ENVIRONMENTAL MATTERS
GENERAL
The Company must operate its generating stations in accordance with
numerous local, state and federal guidelines, laws, regulations and ordinances
designed to preserve and enhance environmental integrity. Resource extraction
and waste disposal operations are also regulated for environmental
compatibility. Generally, air quality and water quality are under the most
stringent regulations. Land use is also carefully regulated.
Various federal, state and local laws, regulations and requirements for air
quality control continue to have a significant impact on the Company. Due to
theirthe proximity toof national parks, monuments, wilderness areas and Indian
reservations and due to the relatively high air quality at such locations, the principal
generating units of the Company are subject to control standards of best
available control technology (BACT) and best available retrofit technology
(BART). Such standards relate to the "prevention of significant deterioration"
of visibility and tall stack limitation rules.
Certain other generating units of the Company are located in areas which
have been designated by federal and state agencies as "non-attainment" areas
(where federal ambient air quality standards are not achieved). This
designation requires such 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 $6.2$11 million during 19941995 for environmental construction
costs in maintaining compliance with environmental requirements. The Company
estimates that it will make expenditures for environmental facilities of
approximately $9.8$12 million in 19951996 and $8.8$9 million in 1996.1997. These amounts include
the Company's estimated share of initial expenditures for improvements to the
pollution control facilities at the Navajo station which are associated with the
final rule issued by EPA on October 3, 1991, regarding visibility impairment in
Grand Canyon National Park (see Navajo Generating Station below for information
regarding the projected total cost of such facilities), and
procurement of continuous emission monitors for Irvington Units 1, 2, 3, and 4
and Springerville Units 1 and 2. With the construction expenditures described
above, the. The Company believes
that all existing generating facilities are or will be in compliance with all
existing or expected environmental regulations except as described below.
In the fall of 1990, Congress adopted certain Federal Clean Air Act
Amendments (CAAA) with respect to reductions in sulfur dioxide and nitrogen
oxide emissions which will affect the Company's operation. The nitrogen oxide
reductions will be based upon EPA regulations expected to be finalized in 1995 for certain
boilers and expected to be finalized by 1997 for all remaining boilers. In
addition, the rules expected to be promulgated in 1995 may be revised in 1997. The required
reductions of sulfur dioxide emissions will be implemented in two phases which
will beare effective in 1995 and 2000, respectively.
The Company is not affected by the requirements for sulfur dioxide
emissions and nitrogen oxide reductions which gowent into effect in 1995 (Phase
I), but is subject to the requirements that go into effect January 1, 2000
(Phase II). In Phase II, the maximum sulfur dioxide emission rates are set at
1.2 pounds per million BTU. Because of the Company's general use of low-sulfur
coal and installed scrubbers at certain units, the Company's coal-fired
generating stations already meet the sulfur dioxide emission rate requirements
for Phase II. Additionally, further reductions are to be met through a proposed market-
based system. Affected Company generating units will be allocated allowancesEmission
Allowances based on required emission reductions and past use. An allowance permits
emission of one ton of sulfur dioxide and may be sold. Generating
station units must hold allowancesEmission Allowances equal to their level of emissions or
face penalties and a requirement to offset excess tons in future years. On March 23,In
1993, the EPA published the final sulfur dioxide allowance allocationsallocated Emission Allowances for all Phase I and Phase II
affected utility units, including the allowances that will be allocated
to all Company units. An analysis of the sulfur dioxide allowancesEmission Allowances that were
allocated to the Company shows that the Company would have sufficient allowances
to permit normal plant operation and be in compliance with the sulfur dioxide
regulations once the Phase II requirements become effective. However, until all
the rulemaking regulation processes for implementing the CAAA are completed, the
Company is unable to predict the specific impacts of all such amendments.
The CAAA also introduced the concept of an organized market for the trading
of Emission Allowances. This market would have allowed utilities to buy and
sell the right to emit sulfur dioxide and served as the mechanism to enforce
compliance with the new standards promulgated under the CAAA. The CAAA also
required the EPA to hold or sponsor an auction for Emission Allowances within
the first three months of each year. The first of such auction was held in
March 1993, following the allocation of Emission Allowances to Utilities in
January 1993.
Title V of the CAAA established a new air quality permitting system that
will be administered in Arizona by the ADEQ. Electric utilities in the state
were required to submit applications for Title V permits by February 1, 1995;
processing1995.
Processing and issuance of thesesuch permits is expected to take at least 18 months.
Until a Title V permit is issued, permits that expire during that period will
either be honored or will be reissued by ADEQ with additional requirements
reflecting Title V regulations.
The CAAA also require multi-year studies of visibility impairment in
specified areas and studies of hazardous air pollutants which relate to the
necessity of future regulations of electric utility generating units. Since
these activities involve the gathering of information not currently available,
the Company cannot predict the outcome of these studies.
As a result of recent and possible future changes in federal and state
environmental laws, regulations and permit requirements, the Company may incur
additional costs for the purchase or upgrading of pollution control emission
monitoring equipment on existing electric generating facilities and may
experience a reduction in operating efficiency. There may be a need for
variances from certain environmental standards and operating permit conditions
until required equipment and processes for control, handling and disposal of
emissions are operational and reliable. Failure to comply with any EPA or state
compliance requirements may result in substantial penalties or fines which are
provided for by law and which in some cases are mandatory.
FOUR CORNERS GENERATING STATION
The Company believes that all units at Four Corners are presently operating
in compliance with federal and state regulations.
IRVINGTON GENERATING STATION
The Company has anCompany's ADEQ operating permit for Irvington Unit 4 which
expiresexpired on
February 8, 1996. By law, the permit remains in effect until ADEQ issues a new
facility-wide Title V permit in 1996. The other facilities at the Irvington
station were under the jurisdiction of the PDEQ until 1993. However, because of
1990 CAAA requirements which require the facility to obtain a Title V permit,
the entire facility was placed under the jurisdiction of ADEQ in April 1994.
The Company hastimely filed a Title V permit application for the Irvington facility
on February 1, 1995.1995, thus providing the facility with a permit application
shield. Each major source requiring a Title V permit must pay an annual
emission-
basedemission-based fee. The 1995 emission fee in 1996 for emissions at the Irvington facility was
assessed at $179,000$191,000 and is expected to range between $150,000 to $250,000 for
1996.1997.
NAVAJO GENERATING STATION
In 1991, the EPA adopted a rule for the reduction of Navajo's sulfur
dioxide emissions on an annual averaging basis by 90% to address visibility
impairment at Grand Canyon National Park. The Company estimates that its share
of the required capital expenditures remaining as of December 31, 19941995 relating
to the rule's implementation will be approximately $44$31 million, including AFDC,
through 1999.
SAN JUAN GENERATING STATION
The Company believes that all units at San Juan are presently operating in
compliance with federal and state regulations.
SPRINGERVILLE GENERATING STATION
Springerville Units 1 and 2 meet all existing federal and state regulations
pertaining to environmental quality. Springerville Units 1 and 2 are operating
under an operating permit issued by ADEQ on December 19, 1994, which expires on
December 19, 1999. Springerville Generating Station is a major source requiring
a Title V permit, and the Company filed a Title V permit application for the
Springerville facility on February 1, 1995. As a result of requirements imposed
by the CAAA of 1990, each major source requiring a Title V permit must pay an
annual emission-based fee. The 1995 emission fee in 1996 for emissions at the Springerville
Generating Station Units 1 and 2 was assessed at $316,000$328,000 and is expected to be
approximately the same for 1996.1997.
EMPLOYEES
The Company and the IBEW 1116, which represents about 63% of the 1,3961,366
employees of the Company and its subsidiaries at December 31, 1994,1995, are parties
to a two-year collective bargaining agreement for the period from December 1,
1994 through November 30, 1996. The collective bargaining agreement, which was
negotiated with and approved by the IBEW 1116 in November 1994, includes annual
wage increases of 3.6% and 4.0% in 1995 and 1996, respectively, and
modifications to the pension, health and supplemental retirement plans. The
Company expects to begin negotiations to extend and modify the collective
bargaining agreement after June 1996.
DISCONTINUED INVESTMENT SUBSIDIARY OPERATIONS
The Company directly owns two non-energy related investment subsidiaries,
TRI and SRI. TRI and SRI each wholly own several subsidiaries both directly and
indirectly.
In July 1990, each of the Board of Directors of TRI and SRI adopted
resolutions for the liquidation of substantially all of the assets of these
subsidiaries. As a consequence, the investment subsidiaries were reclassified
as discontinued operations for financial statement purposes. This
reclassification required the Company to estimate the net realizable value of
the investment subsidiary assets in light of the projected time frame of the
liquidation and in accordance therewith, the Company established appropriate
reserves for losses. The estimated net realizable value of the investment
subsidiaries' net assets as of December 31, 1994 was approximately $8.5 million.
The Company intends to continue to liquidate the remaining assets.
The investment subsidiaries have been in the process of liquidating their
assets and have dividended available asset-sale proceeds to the Company.purposes through 1994.
During 1994, the investment subsidiaries sold all of their remaining interests
in cogeneration and independent power projects, as well as the hotels located in
Louisville, Kentucky and Woodland Hills, California.California, substantially completing
the liquidation of the investment subsidiary assets. In January and February
1995, the remaining equity securities were sold. The Company intends to
continue to liquidate the remaining assets. The Company received cash dividends
from TRI of $10$50 million in April 1994 $15and $13 million in June 1994 and
$25 million in December 1994.March 1995. Since July 1990,
a total of $97$110 million of cash dividends has been received by the Company from
the investment subsidiaries.
See Item 7. - Management's Discussion and Analysis of Financial Condition and
Results of Operations, Restrictive Covenants, Prepayments.
See Note 5 of Notes to Consolidated Financial Statements, Discontinued
Operations.
UTILITY OPERATING STATISTICS
For Years Ended December 31,
1995 1994 1993 1992 1991
1990
Generation and Purchased
Power-kWh (000)- --------------------------------------------------------------------------------------------------------
Generation and Purchased
Power-kWh (000)
Remote Generation (Coal) 8,716,513 9,341,342 8,986,350 6,148,825 5,518,543 5,191,186
Local Generation (Oil, Gas
& Coal) 500,958 825,385 615,100 527,405 314,441
692,651
Purchased Power 692,769 501,269 335,897 2,436,152 2,736,620
2,685,647--------- ---------- --------- --------- --------- ---------
Total Generation and
Purchased Power 9,910,240 10,667,996 9,937,347 9,112,382 8,569,604 8,569,484
Less Losses and Company Use 661,901 639,278 591,412 610,040 585,964
584,101--------- ---------- --------- --------- --------- ---------
Total Energy Sold 9,248,339 10,028,718 9,345,935 8,502,342 7,983,640
7,985,383========= ========== ========= ========= ========= =========
Sales-kWh (000)
Residential 2,330,191 2,374,868 2,223,479 2,146,268 2,081,476
2,069,718
Commercial 1,280,752 1,281,050 1,242,367 1,215,179 1,182,599
1,193,964
Large Users 1,979,317 1,948,331 1,832,278 1,771,937 1,756,887
1,751,263
Mining 1,147,281 1,135,424 1,090,061 1,081,791 951,646
898,584
Public Authorities 204,746 183,525 159,310 165,922 164,380
162,575--------- ---------- --------- --------- --------- ---------
Total-Retail Customers 6,942,287 6,923,198 6,547,495 6,381,097 6,136,988
6,076,104
Sales to Other Utilities 2,306,052 3,105,520 2,798,440 2,121,245 1,846,652
1,909,279--------- ---------- --------- --------- ---------
---------
Total 9,248,339 10,028,718 9,345,935 8,502,342 7,983,640
7,985,383========= ========== ========= ========= ========= =========
Operating Revenues (000)
(A)
Residential $218,208 $220,341 $197,368 $190,089 $174,054
$159,813
Commercial 138,294 137,508 128,688 125,655 114,826
107,373
Large Users 146,409 144,677 131,858 127,456 121,269
109,236
Mining 54,948 53,821 53,510 57,266 49,996
46,365
Public Authorities 14,952 13,435 11,464 11,757 11,273
10,079
Other 2,114 1,651 1,925 1,791 1,583 1,475
-------- -------- -------- -------- --------
Total-Retail Customers 574,925 571,433 524,813 514,014 473,001 434,341
Amortization of MSR Option Gain
Regulatory Liability 20,053 20,053 6,053 6,053 16,553 -
Sales to Other Utilities 75,591 99,987 93,273 70,026 65,441 60,199
-------- -------- -------- -------- --------
Total $670,569 $691,473 $624,139 $590,093 $554,995 $494,540
======== ======== ======== ======== ========
Customers (End of Period)
Residential 273,976 266,060 258,168 251,656 246,538
242,539
Commercial 27,858 27,360 26,838 26,441 26,144
25,938
Large Users 620 588 551 527 531 516
Mining 4 4 4 4 34
Public Authorities 59 59 59 59 59
------- ------- ------- ------- -------
Total Retail Customers 302,517 294,071 285,620 278,687 273,276 269,055
======= ======= ======= ======= =======
Average Revenue per kWh Sold (cents)
(A)
Residential 9.4 9.3 8.9 8.9 8.4
7.7
Commercial 10.8 10.7 10.4 10.3 9.7
9.0
Large Users and Mining 6.4 6.4 6.3 6.5 6.3 5.9
Total - Retail Customers 8.3 8.3 8.0 8.1 7.7 7.1
Average Revenue per
Residential Customer $809 $841 $776 $765 $714 $666
Average kWh Sales per
Residential Customer 8,641 9,066 8,739 8,632 8,534 8,621
(A) Amounts for 1993-1990 have been restated to eliminate revenue related taxes. See
Note 1 of Notes to Consolidated Financial Statements, Nature of Operations and
Summary of Significant Accounting Policies, Reclassification.
ITEM 2. --- PROPERTIES
The Company's transmission facilities are located within the states of
Arizona and New Mexico. The primary purpose of the Company's transmission
facilities is to transmit electricity from the Company's remote electric
generating stations at Four Corners, Navajo, San Juan and Springerville to the
Tucson area for use by the Company's retail customers.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 74130 companies, including
the five listed above, which are utilized to interchange capacity and energy.
As of December 31, 1994,1995, the Company owned or participated in an overhead
electric transmission and distribution system consisting of 511 circuit-miles of
500 kV lines, 1,122 circuit-miles of 345 kV lines, 335 circuit-miles of 138 kV
lines, 454 circuit-miles of 46 kV lines and 8,9479,233 circuit-miles of lower voltage
primary lines. The underground electric distribution system was comprised of
4,2234,514 cable-miles. Approximately 25%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 165166 substations
with a total installed transformer capacity of 5,209,3555,258,355 kVA.
The electric generating stations (except as noted below), the Company's
general office building, operating headquarters and the warehouse and service
center are located on land owned by the Company in fee. The electric
distribution and transmission facilities owned by the Company are located (1) on
property owned in fee by the Company, (2) under or over streets, alleys,
highways and other public places, the public domain and national forests and
state lands under franchises, easements or other rights which, with some
exceptions, are subject to termination, (3) under or over private property by
virtue of easements obtained for the most part from the record holder of title,
and (4) under Indian reservations under grant of easement by the Secretary of
Interior or lease by Indian tribes. In most instances, no examination has been
made by counsel for the Company as to the title to easements of the Company from
the record holder or to the property over which the easement has been granted,
or as to possible liens, encumbrances, reservations or restrictions thereon.
Therefore, some of the easements and the property over which the easements have
been secured may be subject to title defects and encumbered by, or subject to,
mortgages and liens existing at the time the easements were acquired.
Most of the land parcels comprising Springerville are held by the Company
under a long-term surface ownership agreement with the State of Arizona. The
Company's 50% interest in the common facilities of Springerville and its 100%
interest in Irvington Unit 4 and related common facilities were sold and are
leased back by the Company. The coal-handling facilities at Springerville were
sold and leased back by Valencia. The Company leases Springerville Unit 1 and
the remaining 50% interest in the common facilities at Springerville.
Four Corners and Navajo are located on properties held under easements from
the United States and under leases from the Navajo Indian Tribe. The Company,
individually and in conjunction with PNM in connection with San Juan, has
acquired easements and leases for transmission lines and a water diversion
facility located on the Navajo Indian Reservation. The Company has also
acquired easements for transmission facilities, related to San Juan and Navajo,
across the Zuni, Navajo and Tohono O'odham Indian Reservations.
The Company's rights under the various easements and leases described under
this heading may be subject to possible defects (including conflicting grants or
encumbrances not ascertainable because of absence of or inadequacies in the
recording laws or the record systems of the Bureau of Indian Affairs and the
Indian tribes, the possible inability of the Company to resort to legal process
to enforce its rights against certain possible adverse claimants and the Indian
tribes without Congressional consent, the possible failure or inability of the
Indian tribes to protect the Company's interests in, and use and occupancy of,
these facilities from interference or interruption, and, in the case of the
leases, possible impairment or termination under certain circumstances by
Congress, the Secretary of the Interior or certain possible adverse claimants).
However, these possible defects have not and are not expected to materially
interfere with the Company's interest in and operation of its facilities.
With the exception of Springerville Unit 2, substantially all of the
utility assets of the Company are subject to the lien of the General First
Mortgage and the General Second Mortgage. Legal title to Springerville Unit 2,
which is not subject to such lien,liens, is held by San Carlos. Springerville Unit 2
is subject to the Unit 2 First Mortgage.
The Company provided to certain banks, at the time of the Closing, the Unit
2 First Mortgage, a first mortgage lien on and security interest in
Springerville Unit 2, and $50 million in principal amount of collateral bonds
issued under the General Second Mortgage, a second mortgage, junior to the lien
of the General First Mortgage, on all the utility assets (other than excepted
property).
ITEM 3. --- LEGAL PROCEEDINGS
SDGE/FERC PROCEEDINGS
See SDGE/FERC Proceedings in Note 76 of Notes to Consolidated Financial
Statements.
TAX ASSESSMENTS
See Tax Assessments in Note 6 of Notes to Consolidated Financial
Statements.
WATER RIGHTS ADJUDICATION
On March 13, 1975, the State of New Mexico filed an action entitled State
of New Mexico v. United States, et al., in the District Court of San Juan
County, New Mexico, to adjudicate all water rights in the San Juan River Stream
System. The action is expected to adjudicate certain water rights applicable to
the water supply for San Juan and Four Corners. The Company was made a party to
this action in June 1976 and an answer was filed on behalf of the Company and
others in May 1978. For the past several years, the State of New Mexico
Engineer's Office has reportedly been completing reports on hydrographic surveys
performed in conjunction with the litigation. It is anticipated that once those
reports are completed, offers of judgment will be issued to the Company and
other parties. The Company is unable to predict the effect, if any, of any
adjudication on its present arrangements for a water supply to these stations.
However, pursuant to an agreement reached in 1985, the Navajo Tribe will provide
sufficient water to Four Corners from its own allocation to offset any portion
of the water rights affected by this proceeding.
TAX ASSESSMENTS
See Tax Assessments in Note 7 of Notes to Consolidated Financial
Statements.
ITEM 4. --- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable.
PART II
ITEM 5. --- MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The following table sets forth, for the periods indicated, the high and low
sale prices of the Company's Common Stock on the consolidated tape as reported
by The Wall Street Journal.Dow Jones. No dividends were paid on Common Stock during such periods.
Market Price per
Quarter Share of Common Stock
High Low
1995
First...... $3.75 $3.00
Second..... 3.50 3.00
Third...... 3.25 2.63
Fourth..... 3.25 2.88
1994
FirstFirst..... $4.13 $3.38
SecondSecond..... 3.88 2.88
ThirdThird...... 3.75 2.88
FourthFourth..... 3.88 3.00
1993
First $3.75 $1.88
Second 4.50 2.75
Third 4.63 3.63
Fourth 4.38 3.25
The closing price of the Common Stock on March 6, 19951, 1996 was $3.375.$3.125.
The Common Stock is traded on the New York Stock Exchange and the Pacific
Stock Exchange. At March 6, 1995,1, 1996, there were 39,19935,870 shareholders of record of
the Common Stock.
See Item 7., Management's Discussion and Analysis of Financial Condition
and Results of Operations, Dividends on Common Stock.
ITEM 6. - SELECTED CONSOLIDATED FINANCIAL DATA
1995 1994 1993 1992 1991 1990
(In thousands - except per share data and ratios)
Summary of Operations
- ----------------------------------------------------------------------------------------------------------------
Operating Revenues (A)$670,569 $691,473 $624,139 $590,093 $554,995
$494,540Regulatory Disallowances and Adjustments - - (13,777) - (239,232)
Income Taxes-Net 20,436 4,911 5,277 5,745 6,638
Loss on Restructuring - - - (26,669) -
Income (Loss) from:
Continuing Operations 54,905 20,740 (21,816) (79,022) (421,493) (269,643)
Discontinued Operations - - - - (12,659)
Provision for Loss on Disposal of
Discontinued Operations - - (4,000) (44,047) (36,000)
(104,727)
Net Income (Loss) 54,905 20,740 (25,816) (123,069) (457,493) (387,029)
Net Income (Loss) for Common Stock $20,740 $(25,816) $(123,069) $(465,339) $(397,226)54,905 20,740 (25,816) (123,069) (465,339)
Income (Loss) per Average Share of
Common Stock from:
Continuing Operations $0.34 $0.13 $(0.14) $(2.48) $(16.70) $(10.92)
Discontinued Operations - - - - (0.49)
Provision for Loss on Disposal of
Discontinued Operations - - (0.02) (1.38) (1.40) (4.09)
Total Net Income (Loss) per Average
Share of Common Stock $0.34 $0.13 $(0.16) $(3.86) $(18.10) $(15.50)
Shares of Common Stock Outstanding
Average 160,691 160,724 160,544 31,872 25,716
25,633
End of Year 160,671 160,724 160,724 160,430 25,716
25,716
Rate of Return on Average Common Equity N/M N/M N/M N/M (79.26)%- ----------------------------------------------------------------------------------------------------------------
Financial Position
- ----------------------------------------------------------------------------------------------------------------
Total Utility Plant-NetPlant - Net $1,978,126 $2,007,422 $2,029,764 $2,052,695 $1,351,729
$1,599,707
Total Investments 52,116 12,992 62,850 98,126 203,712
229,328
Total Assets 2,701,936 2,714,0962,530,930 2,699,593 2,711,753 2,656,089 2,004,336
2,214,497
Long-Term Debt - Net 1,207,460 1,381,935 1,416,352 1,466,555 500,060
500,915
Capital Lease Obligations 897,958 922,735 927,201 931,163 5,836 6,646
Total
Preferred Stock - - - - 82,793
82,793
Total Common Stock Equity (Deficit) 12,488 (42,233) (62,973) (38,209) (191,903)
265,590
Total Capitalization 2,117,906 2,262,437 2,280,580 2,359,509 396,786 855,944
Defaulted Long-Term Debt - Due on Demand - - - - 760,966 661,909
Defaulted Short-Term Debt - Due on Demand - - - - 219,800 219,800
Regulatory Liabilities 41,214 54,924 53,910 226,645 249,610
Reserve for Litigation and Contract Disputes - - - 27,500 27,219
17,219
Total Capitalization and Other Liabilities and Stockholders' Equity $2,701,936 $2,714,0962,530,930 2,699,593 $2,711,753 $2,656,089 $2,004,336
$2,214,497- ----------------------------------------------------------------------------------------------------------------
Selected Cash Flow Data
- ----------------------------------------------------------------------------------------------------------------
Cash Flow Interest Coverage (A) 2.5x 3.0x 2.3x 2.0x 3.2x
Cash & Cash Equivalents/Current Liabilities (B) 0.48 1.29 0.91 1.06 N/M
Construction Expenditures
(including AFDC) $62,317 $64,479 $48,375 $30,207 $48,728 $66,147
Cash Generated as a Percent of
Construction ExpendituresExpenditures:
Internally Generated (B)(C) 191.6% 222.7% 184.7% 293.4%(C) 232.6%(C) (110.8)%
Internally Generated (B)(C), Including
Drawdowns of Funds Held in Trust 191.6% 222.7% 226.0% 348.8%(C) 232.6%(C) (59.0)%
- ----------------------------------------------------------------------------------------------------------------
Note: Total investments, assets and liabilities and stockholders' equity have
been restated to reflect the adoption of discontinued operations. Also, seeSee Item 7., Management's Discussion and Analysis of Financial Condition and Results of Operations.
(A) Due to the adoption of FERC Order No. 529 interchange sales of electricity have
been reclassified to Sales to Other Utilities for all periods. Revenue related
taxes were removedCash from Operating Revenues for all periods.Continuing Operations plus Interest Paid divided by Interest Paid.
(B) Excludes Cash from Discontinued Operations.
(C) Cash generated is cash provided from continuing operations less cash dividends. (C)Ratios for 1992 and 1991 ratios
include cash conserved under the Payment Moratorium.payment moratoria implemented by the Company on certain obligations during
1992 and 1991.
N/M - Not meaningful.
ITEM 7. --- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following contains information regarding the Company's continuing and
discontinued operations during 1995 compared with 1994 and 1994 compared with
1993 and 1993 compared with
1992 and changes in liquidity and capital resources of the Company during 1994.1995.
Also, management's expectations of identifiable material trends are discussed
herein.
OVERVIEW
In December 1992, the Company consummated a comprehensive Financial
Restructuring of obligations to certain creditors and reclassified its preferred
stock into common stock. The Financial Restructuring was concluded following
nearly two years of negotiations with various creditors including, but not
limited to, bank lenders and lease participants.GENERAL
The Company initiatedclosed 1995 with positive earnings for the Financial Restructuring because it projected that it might have insufficient
liquiditysecond consecutive
year and with positive common stock equity (instead of a deficit) for the first
time since 1990. In addition to meet its cash obligations byunderlying growth, results reflect the
endCompany's efforts to lower operating costs as well as reduce capital costs and
strengthen the balance sheet. The results also reflect a one-time $12.2 million
non-cash accounting reversal of fuel expenses and the non-cash recognition of
$23 million of defined tax benefits based on the expectation of the first quarterrealization
of 1991.
A payment moratorium on certain ofsuch benefits in the Company's debt, lease, coal and rail
obligations during part of the period of negotiations provided cash flow
sufficient to meet the Company's other obligations.
The Company believes that the Financial Restructuring provides the Company
the opportunity to return gradually to long-term financial viability. However,
the Financial Restructuring itself is not sufficient to assure the Company's
long-term financial viability.
The Company's capital structure remains highly leveraged andfuture from net operating loss carryforwards.
Despite such improvements, the Company's financial prospects and cash flows remaincontinue to be
subject to significant economic, regulatory and other uncertainties, some of
which are beyond the Company's control. These uncertainties include the degree
of utilization of generation capacity through either retail electric service or
wholesale sales and the extent to which the Company, due to continued high
financial and operating leverage, can alter operations and reduce costs in
response to unanticipated economic downturns or industry changes due to continued high financial and operating
leverage.changes. The Company's
ability to recover the costs of serving retail customers is dependent upon
pricing of the Company's services, which requires ACC approval, and the level of
sales to such customers. The Company anticipates continued growth in sales over
the next five years primarily as a result of anticipated population and economic
growth in the Tucson area. However, a number of factors such as changes in
economic conditions and the increasingly competitive electric markets could
affect the Company's levels of sales.
Increased revenues, including increases for the recovery of plant and
operating costs associated with the remaining 37.5% of Springerville Unit 2,
which is not currently included in rate base, may be required in order for the
Company to maintain its existing level of liquidity over the longer term as
obligations become due. See Item 1., Business, Rates and Regulation, 1994 Rate
Order. Also, see Notes 2 and 7 of Notes to Consolidated Financial Statements,
1994 Rate Order and Commitments and Contingencies, respectively. The level of
cash flow from wholesale sales is affected generally by factors affecting the
market for such sales, including the availability of capacity and energy in the
western United States with pricing and procurement processes influenced by the
ongoing review of bulk power markets by FERC and the various state public
utility commissions. In addition, because the Company has a significant amount
of variable rate debt, the Company's future cash flows are also affected by the
level of interest rates. See Liquidity and Capital Resources, Cash Flows
below.
If the Company is unable to make sales at prices adequate to recover its
costs or if for other reasons the Company fails to maintain or improve its cash
flows, the Company's ability to meet its obligations may be jeopardized. The
Company hasDuring
the 1997-2001 period, approximately $1.1 billion of the Company's long-term debt
will be maturing, including approximately $774 million in reimbursement
agreements relating to letters of credit which expire, during the 1997-2001 period. See Consolidated Statements
of Capitalization and Note 6 of Notes to Consolidated Financial Statements.will expire. The Company intends
to pay or refinance maturing bonds and bank loans and to replace or extend such
reimbursement agreements. There can be no assurance, however, that the Company
will be able to pay such debt or replace or extend such reimbursement
agreements. In addition, the Company has a significant amount of variable rate
debt and, as a result, the Company's future cash flows are also affected by the
level of interest rates. See Liquidity and Capital Resources below.
The Company's capital structure is highly leveraged and its ability to
raise capital (through either public or private financings) is limited. The
Company's ability to obtain debt financing will beis limited by reason of limited free
cash flow available to meet additional interest expense and due to the
restrictive covenants contained in itsexisting obligations to creditors. Further, ifTo the
extent the Company is required to refinancerefinances its debt obligations in order to repay them when
due, such refinancing may be made on terms which aremay be adverse to the Company.
Such terms could include, among other things, higher interest rates and various
restrictive covenants, such as dividend payment restrictions. Access to equity
capital may be limited because of the Company's likely limited future
profitability and its present inability to pay dividends for the foreseeable future.dividends. See Dividends on
Common Stock below. During the next twelve months, the Company does not expect any needexpects to obtain new debt financingbe
able to fund continuing operating activities and construction expenditures. The Company instead will rely onexpenditures with
internal cash flows, existing cash balances, and, if necessary, borrowingsdrawdowns under
the Renewable Term Loan and/or a revolving credit line providedborrowings under the MRA. TheRevolving Credit. However,
the Company may issue debt to take advantage of lower interest rates resulting
from tax-exempt financings. At December 31, 1995, the Company's cash balance
excluding the cash of the investment subsidiaries, but including cash equivalents at December 31, 1994, was approximately $233$85 million. Cash balances are
invested in investment grade, money-market securities with an emphasis on
preserving the principal amount invested.
COMPETITION
WHOLESALE
The Company competes with other utilities, marketers and independent power
producers in the sale of electric capacity and energy in the wholesale market.
The Company's rates for wholesale sales of capacity and energy, generally, are
not permitted to exceed rates determined on a cost of service basis. In 1993the
current market, wholesale prices are substantially below costs determined on a
fully allocated cost of service basis, but, in all instances, prices exceed the
level necessary to recover fuel and other variable costs. It is expected that
competition to sell capacity will remain vigorous, and that prices will remain
depressed for at least the next several years, due to increased competition and
surplus capacity in the southwestern United States. Competition for the sale of
capacity and energy is influenced by many factors, including the availability of
capacity in the southwestern United States, the availability and prices of
natural gas and oil, spot energy prices and transmission access. In addition,
the Energy Act has promoted increased competition in the wholesale electric
power markets.
The Energy Policy Act of 1992 addresses a wide range of energy issues,
including several matters affecting bulk power competition in the electric
utility industry. It creates exemptions from regulation under the Holding
Company Act for persons or corporations that own and/or operate in the United
States certain generating and interconnecting transmission facilities dedicated
exclusively to wholesale sales, thereby encouraging the participation of utility
affiliates, independent power producers and other non-utility participants in
the development of power generation. In order to facilitate competition in
power generation, the Energy Act also confers expanded authority upon FERC to
issue orders requiring electric utilities to transmit power and energy to or for
wholesale purchasers and sellers, and to require electric utilities to enlarge
or construct additional transmission capacity to provide these services. While
the Energy Act prohibits FERC from issuing any such order that would
unreasonably impair the continuing reliability of affected electric systems or
that would be conditioned upon or require transmission services directly to an
ultimate consumer, the Energy Act creates the potential for utilities and other
power producers to gain increased access to the transmission systems of other
entities to facilitate wholesale sales.
FERC is encouraging all parties interested in transmission access to form
RTGs to facilitate access to and development of transmission service and to
assist in settling disputes regarding such matters. RTGs will not relieve FERC
of its responsibilities related to transmission access; however, such
organizations could provide for more efficient handling of transmission service
requests and planning for regional transmission needs. The Company is currently
involved in the development of two RTGs in the West, SWRTA and WRTA. WRTA was
approved by FERC on May 16, 1995 and SWRTA was approved on October 31, 1995.
The Company is a member of SWRTA and is also considering membership in WRTA. As
a condition of its approval of WRTA and SWRTA as RTGs the FERC has required all
transmitting utility members of each RTG to offer comparable transmission
services at least to other members of such RTG through tariffs that set forth
the rates, terms and conditions of service.
On March 29, 1995, the FERC issued a Notice of Proposed Rulemaking (NOPR)
on Open Access Non-Discriminatory Transmission Services by Public Utilities and
Transmitting Utilities (the Open Access NOPR) and a supplemental NOPR on
Recovery of Stranded Costs (the Stranded Costs NOPR).
The rules proposed in the Open Access NOPR are intended to facilitate
competition among electric generators for sales in the bulk power market. If
adopted, the NOPR on open access transmission would require public utilities
under the Federal Power Act to provide third party access to their transmission
systems and would establish guidelines for their doing so. Under the Open
Access NOPR, each public utility would also be required to establish separate
rates for its transmission and generation services for new wholesale service,
and to take transmission services, including ancillary services, under the same
tariffs that would be applicable to third-party users for all of its new
wholesale sales and purchases of energy. In addition, the FERC requested
comment on the desirability of unified standards for both wholesale and retail
transmission services, suggesting, as a possible approach, the establishment by
each vertically integrated electric utility of a distribution function which
would, for ratemaking purposes, be treated as a wholesale customer taking
transmission services under the utility's filed wholesale transmission tariff.
The FERC recognized, and numerous comments received by the FERC confirm, that
such an approach would change the traditional approach of state-federal
allocation of transmission costs.
The Stranded Costs NOPR would provide a basis for recovery by regulated
public utilities of legitimate and verifiable stranded costs associated with
existing wholesale requirements customers and retail customers who become
unbundled wholesale transmission customers of the utility. The FERC would
provide public utilities a mechanism for recovery of stranded costs that result
from municipalization, former retail customers becoming wholesale customers, or
the loss of a wholesale customer. The FERC would consider allowing recovery of
stranded investment costs associated with retail wheeling only if a state
regulatory commission lacks the authority to consider that issue.
The Company does not believe that the Open Access NOPR or the Stranded
Costs NOPR will have a material effect on the Company's results from continuingof operations,
were
affected by certain unusualassuming that the final rule is adopted substantially as proposed.
On December 13, 1995, FERC issued a third and infrequent adjustmentssupplemental NOPR on Real-
Time Information Networks and accruals.Standards of Conduct. This NOPR proposes that
each public utility that owns and/or controls transmission facilities would be
required to create or participate in an electronic information network which
would provide customers with information regarding, among other things, the
availability and pricing of transmission capacity. Additionally, FERC is
proposing that a code of conduct be established which would govern the
relationships between the transmission and generation marketing functions of all
regulated public utilities. FERC is proposing that these functions should be
separated and that the generation marketing function be required to follow the
same procedures to acquire transmission access that third party competitors are
required to utilize.
The table
below showsFERC is currently expected to issue final rules on these NOPRs in the
second or third quarter of 1996.
RETAIL
Under current law, the Company is not in direct competition with any other
regulated electric utility for electric service in the Company's incomeretail service
territory. Nevertheless, the Company competes for retail markets against gas
service suppliers and others who may provide energy services which would be
substitutes for, or lossesbypass of, the Company's services.
Electric energy for meeting retail customers' needs primarily competes with
natural gas, an alternative fuel source for certain retail energy uses. Such
uses may include heating, cooling and a limited number of other energy
applications. In most applications, electric energy is a cost effective source
of energy compared with natural gas. Also, customers, particularly industrial
and large commercial customers, may own and operate facilities to generate
their own electric energy requirements and, if such facilities are qualifying
facilities, to require the displaced electric utility to purchase the output of
such facilities at "avoided costs" pursuant to PURPA. Such facilities may be
operated by the customers themselves or by other entities engaged for such
purpose.
The Company actively markets energy and customized energy-related services
to meet customer needs. The Company has to date lost no customers to self-
generation in part because of such efforts and in part because such self-
generation alternatives have proven to be uneconomic in comparison with Company-
provided electric service. For example, the Company's two mining customers,
which provide approximately 10% of the Company's total annual revenues from
continuing operationsretail customers, each have considered self-generation. However, following
negotiations with the Company in 1993 and income/loss1994, new contracts were executed that
included, among other things, rate reductions and term extensions. These
contracts expire after the year 2000, subject to various provisions allowing the
customers to terminate partially or entirely, under certain circumstances upon
at least one and up to two years prior notice. To date, no such notice has been
received. The ability to enter into or extend contracts, to avoid early
termination, and to retain customers will be dependent on, among other things,
the Company's ability to contain its costs, market conditions and alternatives
available to customers from continuing operations per average sharetime to time.
The legislatures and/or the regulatory commissions in several states have
considered or are considering "retail wheeling" which, in general terms, means
the transmission by an electric utility of Common Stock hadenergy produced by another entity
over its transmission and distribution system to a retail customer in such
unusualutility's service territory. A requirement to transmit directly to retail
customers could have the result of permitting retail customers to purchase
electric capacity and infrequent adjustmentsenergy from, at the election of such customers, the
electric utility in whose service area they are located or from other electric
utilities or independent power producers. While retail wheeling would expose
the Company's service territory to increased competition, it would also open
additional markets into which the Company may sell its electric power.
In Arizona, the ACC Staff issued its first report on a retail electric
competition workshop held in October of 1994. This report is the first in a
series of reports that will be issued on various workshops that will be held
from time to time to identify and accruals not been recorded.
December 31,
1994 1993 1992
- Thousandsaddress policy issues related to competition.
While other states are considering competition proposals, the ACC effort is
designed to obtain information about competition. No specific proposals are
currently being considered. The report proposes that Staff develop a
comprehensive set of Dollars -
Income (Loss) From Continuing Operations $20,740 $(21,816) $(79,022)
------- -------- --------
Regulatory Disallowancesoptions to better inform the ACC about its choices. Staff
recommended that three options be considered: 1) encouraging retail
competition, 2) permitting limited retail competition, and Adjustments-Net - 13,177 -
Financial Restructuring Costs - 1,498 29,511
Loss3) discouraging
retail competition by prohibiting retail wheeling and allowing distributed
energy services. The ACC has also established a working group on Financial Restructuring - - 26,669
SCECorp/SCE Litigation Settlement - - (40,000)
------- -------- --------
Total Adjustmentsretail
electric competition. Membership in the working group includes ACC Staff,
Arizona utilities, and other interested parties, and the first meeting of the
group took place in January 1995. A report from the group was issued in October
1995. This report concludes Phase I of the Commission's investigation into
retail electric competition. In February 1996, Phase II started and is focusing
on obtaining more information from interested parties and recommendations on
policy. The Company cannot predict what the working group will recommend and
what, if any, changes in electric regulation and competition will be implemented
by the ACC.
The Company continues to Income (Loss)
From Continuing Operations - 14,675 16,180
------- -------- --------
Adjusted Income (Loss) From Continuing
Operations $20,740 $ (7,141) $(62,842)
======= ======== ========
Adjusted Income (Loss) From Continuing
Operations Per Average Shareassess the impact of Common Stock $0.13 $(0.04) $(1.97)
===== ====== ======
PROPOSEDthe Energy Act and other
possible legislation on the Company's ability to remain competitive in the
electric utility industry. The Company is unable to predict the ultimate impact
the Energy Act or any other possible legislation will have on its operations.
HOLDING COMPANY ThePROPOSAL
In 1995, the Company intendssought approvals to establish in early 1996through a one-for-one
share exchange a new corporate structure in which the Company will bewould have been a
subsidiary of a new holding company, UniSource Energy Corporation (UniSource).
The Company proposessought to establish a holding company structure because the Company
believes that it is in the best interests of its shareholders for the Company
to participate in various segments of the evolving and expanding electric energy
business. The Company believes that such participation would be enhanced by the
holding company structure, a commonly used structure in the electric and other
industries, to conduct different lines of business. ApprovalIn May 1995, shareholders
of athe Company approved the proposed holding company structure will require the affirmative vote
of holders of shares of common stock representing not less than a majority of
all votes entitled to be cast by all holders of shares of common stock. Incompany.
However, in addition to shareholder approval, consummationimplementation of the holding
company plan iswas predicated upon receiving approval from the ACC and FERC.
TheAlso, on September 27, 1995, the Company will also
seekreceived a "no action" position from
the Staffstaff of the SEC under the Public Utility Holding Company Act of 1935, as
amended, or,amended. Also, on April 26, 1995, the Company filed an application with FERC
requesting approval to form a holding company.
In February 1995, the Company filed a Notice of Intent to Form a Holding
Company with the ACC. In June 1995, the ACC Staff filed testimony recommending
that the ACC deny the Company's request on the basis that retail customers would
be exposed to certain risks resulting from diversification. However, ACC Staff
recommended that, in the alternative,event that the ACC approves formation of the holding
company, the ACC impose various operating and financial conditions on the
Company and the holding company. In concurrently filed testimony, RUCO, an
intervenor in the matter, did not oppose the formation of the holding company.
The Company filed rebuttal testimony on July 27, 1995, and a public hearing was
held on August 22, 1995.
In November 1995, the Company and the ACC Staff entered into the Proposed
Settlement Agreement which included a proposal to resolve the holding company
application. On January 19, 1996, the ACC denied the Proposed Settlement
Agreement. Following the denial of the Proposed Settlement Agreement, the ACC
Hearing Officer submitted a recommended order on the holding company proposal.
On February 22, 1996, the ACC denied the formation of a holding company.
However, the ACC granted the Company a waiver authorizing it to invest in
subsidiaries that will engage in energy related projects in an amount equal to
the lesser of $25 million or the maximum amount allowed by the MRA. To the
extent that the Company obtains retroactive approval or waiver of projects from
the ACC, the energy related diversification amount will be reinstated up to the
$25 million limit. This investment authority is subject to the conditions that
(i) the total waiver amount shall not exceed $50 million annually, (ii) 60% of
net profits from diversified activities be applied to repay the Company's debt
and (iii) total investment in such diversified activities does not exceed 15% of
the Company's capitalization.
As a result of the ACC order, the Company will not establish the holding
company proposal structure at this time and will withdraw its holding company
application with FERC. The Company may, in the future, seek the approval of the
SEC under such Act. The Company is inACC for the processestablishment of obtaining
such approvals.
If approved by the requisite vote of the Company shareholders and if
required regulatory approvals are satisfactorily obtained, the outstanding
shares of the Company common stock would be exchanged, on a share-for-share
basis, for shares of UniSource. As a result, the holders of the Company common
stock will become the owners of UniSource common stock, and UniSource will
become the owner of the Company common stock.
During the second quarter of 1995, the Company intends to provide a proxy
statement-prospectus to all shareholders which will set forth in detail the holding company structure and could, upon the
receipt of the requisite regulatory approvals, effect the plan of exchange.
NATIONS ENERGY CORPORATION
In 1995, the share exchangeCompany established Nations Energy (formerly known as
Escalante Resources Inc.) for the purpose of investing in independent power
projects in the domestic and foreign energy markets. The 1995 consolidated
financial statements reflect the accounts of Nations Energy, a shareholder
meeting date. Accompanying the proxy statement-prospectus will be a form of
proxy solicited on behalf of the Board of Directorswholly-owned
subsidiary of the Company.
In September 1995, Nations Energy and Trigen Energy Corporation formed a
limited partnership which purchased Coors Brewing Company's energy production
(utility) assets. Nations Energy has a 49% interest in such partnership. The
partnership will provide electricity and steam for the brewery operation in
Golden, Colorado. In addition, the partnership expects to upgrade Coors' power
plant to improve fuel efficiency and increase capacity. The investment of
aproximately $12 million by Nations Energy is included in the Company's
Consolidated Balance Sheet at December 31, 1995 under Investments and Other
Property and in the Company's Consolidated Statement of Cash Flows for the year
ended December 31, 1995 as Investment in Partnership.
RESULTS OF OPERATIONS
In 1995, the Company had net income of $54.9 million or $0.34 per average
share of common stock compared with $20.7 million or $0.13 per average share of
common stock in 1994 and a net loss of $25.8 million or $0.16 per average share
of common stock in 1993.
The improved positive earnings for the second consecutive year resulted
from strong growth in the Company's service territory, an increase in income tax
benefits due to the recognition of net operating loss carryforwards which will
likely be realized in the future, a one time $12.2 million reduction in fuel
expenses due to the satisfaction of certain requirements under fuel and
transportation agreements restructured in 1991, and the Company's efforts to
contain costs.
RESULTS OF UTILITY OPERATIONS
SALES AND REVENUES
Sales and revenues are affected principally by price changes, consumption
and growth factors. In 1995, much of the changes were attributable to growth,
as the average number of retail customers grew 2.9% which led to a slight
increase in consumption. Consumption was affected by milder temperatures in
1995 than the ten-year average. Prices did not change in 1995, and the change
in revenues is also attributable to strong growth in the Company's retail
customer base.
Revenues from sales to retail customers increased 9.0%0.6% in 1995 compared
with 1994 and 8.9% in 1994 compared with 1993 and 2.1% in 1993 compared with 1992.1993. The table below identifies the
components of the increases in 19941995 and 1993.1994.
1995 1994 1993
- Millions of Dollars -
1994 Price Change $ 3 $17 $(3)
Consumption Change (13) 15 3
Customer Growth 13 15 12
--- ---
Increase in Retail Revenues $ 3 $47
$12
=== ===KWh sales to retail customers increased less than 1% in 1995 compared with
1994. The revenuekWh sales increase in 1994 resulted from greater kWh sales due to
continued growtha 2.9% increase in the average
number of retail customers, increase inpartially offset by decreased usage due to warmercooler
temperatures in 1995 than normal temperatures, and increased prices as a result of the
1994 Rate Order. There were 289,697 electric customers on average during 1994,
an increase of 2.9% over 1993.in 1994. Based on billed cooling degree days, a
commonly used measure in the electric industry that areis calculated by subtracting
75 degrees from the daily average of the high and low daily temperatures, the Tucson area
registered a 26% increasean approximate 24% decrease in such billed cooling degree days infor
1995 compared with 1994, over 1993, and a 33% increase4% decrease in such billed cooling degree days
in 1994 overfor 1995 compared with the 10 year average for the same period from 19841985 to
1993.1994. Specifically, billed cooling degree days were 1,399, 1,844, and 1,454 for
1995, 1994, and the 10 year average, respectively. The Company had 297,939
retail customers on average in 1995. KWh sales in 1994 compared with 1993
revenue decreaseincreased as a result of a 2.9% increase in the average number of customers and
increased usage as a result of warmer than normal temperatures.
Revenues from sales to retail customers increased in 1995 compared with
1994 due to changeslightly higher kWh sales discussed above and the rate increase
allowed under the 1994 Rate Order being in price, shown in the
table above, resulted from lower rates charged undereffect throughout 1995. In 1994,
revenues increased 9% over 1993 due to greater kWh sales and increased prices as
a renegotiated contract
with oneresult of the Company's mining customers.1994 Rate Order.
Amortization of the MSR Option Gain Regulatory Liability increased in 1994
compared with 1993 as a result of the 1991 Rate Order which set the non-cash
operating revenue for the amortization of the regulatory liability for the MSR
option gain at $6 million for 1992 and 1993, $20 million in 1994, 1995 and 1996, and $8
million in 1997 at which point the MSR Option Gain will be fully amortized. See
Note 1 of Notes to Consolidated Financial Statements, Nature of Operations and
Summary of Significant Accounting Policies.
The Company makes sales for resale to the extent capacity is not needed for
providing energy to the Company's retail customers. Rates for such sales are
substantially below rates determined on a fully allocated cost of service basis,
but, in all instances, rates exceed the level necessary to recover fuel and
other variable costs. Lower kWh sales to other utilities in 1995 compared with
1994 resulted from lower regional loads due to mild weather conditions and the
increased availability of lower cost hydroelectric power in the western United
States. Lower revenues from sales to other utilities resulted from lower sales
and lower spot market prices in 1995 than in 1994. Revenues from other
utilities decreased by 24% compared with 1994. In 1994, revenues from Other Utilitiessales to
other utilities increased 7.2%7% over 1993 as a result of a 13% increase in revenues
from firm sales of energy, offset by a 4% decrease in revenues from economy
sales.
Revenues from Other Utilities increased 33%OPERATING EXPENSES
Fuel and purchased power expense decreased in 19931995 compared with 1992 primarily due to a 56% increase in revenues from firm
sales of energy and a 12% increase in the average revenue per kWh sold on a non-
firm basis. In 1994 firm sales accounted for 37% of sales to Other Utilities
and 58% of revenues from Other Utilities. In 1993, firm sales accounted for 33%
of sales to Other Utilities and 56% of revenues from Other Utilities. The
Company's ability to market available capacity and energy in the future, at
levels comparable with 1994, may be limited due to lower prevailing prices and
other market conditions.
OPERATING EXPENSES
Asas a
result of the Financial Restructuring, the Company's Irvington Lease,
Valencia Leases and the Springerville Common Facilities Leases were reclassified
from operating leases to capital lease obligations. The effect of this
reclassification significantly increased recorded assets and liabilities
relating to these leases and resultedlower generation requirements in the reallocations of the lease1995 than in 1994, a one time $12.2
million reduction in fuel expenses relatingdue to the Irvington and Springerville Common Facilities Leases from Other
Operations expense to Capital Lease Expense. The Valencia Leases expense
continues to be expensed as a component of Fuel expense. In addition, as part
of the Financial Restructuring, the Company became the direct lessee under the
Springerville Unit 1 Leases which is also stated as a capital lease obligation.
The assumption of the Springerville Unit 1 Leases and the termination of the
Restated Century Purchase Contract increased assets and liabilities relating to
capital leases and, for periods subsequent to the Financial Restructuring,
result in the recognitionsatisfaction of certain
expenses, which were previously includedrequirements under fuel and transportation agreements restructured in Purchased Power-Demand expense, as Capital Lease Expense1991 and
various other
operating expenses.lower incremental fuel costs resulting from fuel contracts negotiations. Fuel
expenses increased 6.4% in 1994 over 1993 as a result of the fourth
quarter 1994 reallocation
of a reserve for sales tax disputes from Taxes Other than Income Taxes. See
Note 76 of Notes to Consolidated Financial Statements, Commitments and
Contingencies, Tax Assessments. Aggregate fuel expense
increased 48.6% in 1993 compared with 1992 due to greater generation to
accommodate increased sales to Other Utilities and Retail Customers and fuel
expenses from Springerville Unit 1, which were previously accounted for as
Purchased Power-Energy. Average cost per kWh of fuel and its transportation
only, excluding accounting adjustments, were 1.55 cents, 1.71 cents and 1.79
cents infor 1995, 1994 and 1.76 cents in 1993. Following the Financial
Restructuring, the Company no longer makes purchases under the Restated Century
Purchase Contract, which was terminated, but purchases fuel directly from
Valencia. Increased generation requirements were met primarily through
increased generation at Springerville Unit 1.
Purchased Power-Energy increased in 1994 over 1993, as a result of greater
kWh requirements to provide for increased sales. Purchased Power-Energy expense
decreased in 1993 compared with 1992 as a result of the termination of the
Restated Century Purchase Contract and the change in the status of Springerville
Unit 1 described above.
Purchased Power-Demand expense decreased in 1993 compared with 1992 due to
the termination of the Restated Century Purchase Contract.
The increase in Capital Lease Expense in 1993 compared with 1992 reflects
the reclassification of the Irvington Lease and Springerville Common Facilities
Leases to capital lease obligations and the assumption of the Springerville Unit
1 Leases.respectively.
Amortization of Springerville Unit 1 Allowance, a non-cash item, decreased
in 1994 compared with 1993 due to lower projected operation and maintenance
expenses included in the calculation of the Springerville Unit 1 Allowance. The
Springerville Unit 1 Allowance was originally calculated by projecting the
yearly costs associated with Springerville Unit 1 over the remaining life of the
Springerville Unit 1 Leases and takingrecording the present value of the difference
between such costs and the ACC allowed level of recovery. Such costs are then
recognized in each period along with a corresponding interest accrual and
amortization of the allowance as a credit to operating expenses. The interest
accrual is included in the Consolidated Statements of Income (Loss) as Regulatory Interest. Amortization of Springerville Unit 1 Allowance, a non-
cash credit originally resulting from the write-off of the portion of
Springerville Unit 1 demand charges under the Restated Century Purchase Contract
in excess of the $15 per kW per month allowed by the ACC, increased in 1993
compared with 1992 due to increased Springerville Unit 1 Leases expense. As a
result of the assumption of the Springerville Unit 1 Leases, the Company's
levelized amortization of lease expenses is basedInterest
Imputed on rents over the full primary
term of the leases rather than through 2001, the date utilized when the rents
were paid by Century and passed through under the Restated Century Purchase
Contract.Losses Recorded at Present Value. See Note 1 of Notes to
Consolidated Financial Statements, Nature of Operations and Summary of
Significant Accounting Policies.
Other Operations expense decreased in 1995 due to cost containment measures
implemented by the Company and increased in 1994 compared with 1993 as a result
of the accrual of increased employee expenses related to compensation and
pension benefits. Other Operations expense decreased in 1993 compared with 1992
primarily due to the reclassification of the Irvington Lease and the
Springerville Common Facilities Leases expenses to Capital Lease Expense.
Maintenance and Repairs expense was higher in 1993 compared with 1992
because of the change in the status of Springerville Unit 1 described above.benefits expenses.
Depreciation and Amortization increased in 1994 over 1993 as a result of
the amortization of 62.5% of the Springerville Unit 2 rate synchronization
deferral costs over 3 years (beginning in January 1994) pursuant to the 1994
Rate Order.
Depreciation expense increased in 1993 compared with 1992 primarily
reflecting various additions to plant and equipment and a one-time adjustment
decreasing depreciation expense mandated by FERC which was recorded in the
second quarter of 1992.
Taxes Other than Income Taxes decreasedincreased in 19941995 compared with 19931994 as a
result of the fourth quarter 1994 reallocation of aan $8 million reserve for sales tax disputes
to Fuel.Fuel in 1994. See Note 76 of Notes to Consolidated Financial Statements,
Commitments and Contingencies, Tax Assessments. The increaseSuch reallocation caused taxes
other than income taxes expense to decrease in Taxes Other
than Income Taxes in 19931994 compared with 1992 reflects that property1993.
Income tax expense related toincreased in 1995 compared with 1994 because the
Company's assumption ofoperations produced taxable operating income for the Springerville Unit 1 Leases, which
expense previously had been part of demand charges paid under the Restated
Century Purchase Contract and included in Purchased Power-Demand is currently
recorded as Taxes Other than Income Taxes.
Financial Restructuring costs decreased in 1993 compared with 1992 as a
result of the completion of the Financial Restructuring in December 1992.first time since
1988.
OTHER INCOME (DEDUCTIONS)
Regulatory Disallowances and Adjustments in 1993 reflect primarily the
write-off of Springerville Unit 2 deferred expenses mandated by the 1994 Rate
Order.
Deferred Springerville Unit 2 Carrying Costs decreased in 1994 compared
with 1993 as a result of the incorporation into rate base of 62.5% of
Springerville Unit 2.
The Loss on Financial Restructuring in 1992 was based on, among other
things, the excess of the fair value of the Common Stock and Warrants issued, at
values of $2.33 per share and $0.82 per warrant, respectively, compared to the
amount of plant, materials and supplies inventories received by the Company from
Century and accrued rent under the Springerville Unit 1 Leases, reflected on the
Company's financial statements as of December 15, 1992 as demand charges payable
to Century. In addition, the Company reversed a reserve of approximately $9
million due to the dismissal of related regulatory matters as a part of the
Financial Restructuring. The restructuring of Bank obligations gave rise to a
deferred gain of $21 million, which is being amortized as a reduction of
interest expense over an eight-year period. See Note 3 of Notes to Consolidated
Financial Statements, 1992 Consummation of the Financial Restructuring.
Litigation Settlement income in 1993 decreased compared with 1992 due to
the settlement of litigation against SCE in the third quarter of 1992. See Item
1., Business, SCE/TEP Power Exchange Agreement.
OtherInterest Income increased in 1994 compared with 1993 due to greater
interest earned on cash and cash equivalents.
Income Tax benefits included in Other Income decreased(Deductions) increased in 19931995
compared with 1992 due to1994 and 1993. In 1994 and 1993, the collectionCompany was in 1992 of approximately $8 million in interest
income on a Federalnet
operating loss carryforward position and generating tax losses; therefore, the
income tax refund.benefits included in the Consolidated Statements of Income (Loss) for
the years 1994 and 1993 reflected only ITC amortization. In 1995, income tax
benefits include the recognition of a portion of the Company's deferred tax
benefits based on the expectation of realization of such benefits in the future
from net operating loss carryforwards, as well as ITC amortization.
Other income increased in 1995 compared with 1994 as a result of gains
realized on the sales of equity securities held by the investment subsidiaries.
As of January 1, 1995, the Company ceased to account for the investment
subsidiaries as discontinued operations. Previously, when the investment
subsidiaries were classified as discontinued operations for financial statement
purposes, no income or loss related to discontinued operations was recorded
unless the estimates of proceeds from disposition of investment subsidiary
assets changed materially.
INTEREST EXPENSE
Interest expense on Long-Term Debt-NetDebt increased in 1994 compared with 1993 as
a result of slightly higher interest rates. InterestAlthough interest rates increased
in 1995, interest expense on Long-Term
Debt-Net decreased in 1993 compared with 1992did not increase due to the prepaymentlower amounts of $68
million of long-term debt
combined with significantly lower interest rates on
the Company's obligations in the first quarter of 1993 compared with interest
rates during the same period of 1992. The lower rates reflect primarily the
elimination of default rates on such obligations in 1993 as a result of the
Financial Restructuring (discussed below), and in part, lower market rates. The
effect of lower rates was partly offset by the reclassification of previously
outstanding short-term debt into the Term Loan which is classified as Long-Term
Debt.
In the first quarter of 1992, the Payment Moratorium was in effect on most
obligations of the Company. Therefore, the Company accrued interest on such
obligations at default rates, which were substantially higher than market rates.
Interest at default rates was accrued on approximately $900 million of bank
credit obligations including approximately $650 million of reimbursement
obligations related to LOCs that provide credit support for variable-rate tax-
exempt bond issues. The irrevocable LOCs were fully drawn through the first
quarter of 1992. In March 1992, such issues were remarketed and the proceeds
were used to pay reimbursement obligations for the drawn LOCs and interest was
no longer accrued at default rates.
There was no interest expense on Short-Term Debt in 1994 and 1993 as a
result of the reclassification of previously outstanding short-term debt into
the Term Loan which is classified as Long-Term Debt.outstanding.
Interest Expense - Other decreased in 1994 compared with 1993 due to an
accrual in 1993 for interest on contested tax payments and litigation
settlement. Interest Expense - Other increased in 1993 compared with 1992
primarily due to the reinstatement of LOC fees and remarketing fees related to
the remarketing of the tax exempt bonds supported by the LOCs. LOC fees and
remarketing fees were not paid for part of 1992 because the LOCs were drawn and
the IDBs were held by the banks.
RESULTS OF DISCONTINUED OPERATIONS
See Note 5 of Notes to Consolidated Financial Statements.
ACCOUNTING FOR THE EFFECTS OF REGULATION
The Company prepares its financial statements in accordance with the
provisions of FAS 71. This statement requires a cost-based rate-regulated
utility to reflect the effect of regulatory decisions in its financial
statements. In certain circumstances, FAS 71 requires that certain costs and/or
obligations be reflected in a deferral account in the balance sheet and not be
reflected in the statement of income or loss until matching revenues are
recognized. Therefore, the Company's Consolidated Balance Sheets at December
31, 1995, 1994 and 1993 contain certain line items (showing on the balance sheet
under Deferred Debits - Regulatory Assets and MSR Option Gain Regulatory
Liability, Accumulated Deferred Investment Tax Credits Regulatory Liability, and
Other Regulatory Liabilities) solely as a result of the application of FAS 71.
In addition, a number of line items in the Company's Consolidated Statements of
Income (Loss) for the years ended December 31, 1995, 1994 1993 and 19921993 also reflect
the application of FAS 71. See Note 1 of Notes to Consolidated Financial
Statements, Nature of Operations and Summary of Significant Accounting
Policies, Accounting for the Effects of Regulation.
If, at some point in the future, the Company determines that all or a
portion of the Company's regulated operations no longer meet the criteria for
continued application of FAS 71, the Company would be required to adopt the
provisions of FAS 101 for that portion of the operations for which FAS 71 no
longer applied. Adoption of FAS 101 would require the Company to write off its
regulatory assets and liabilities as of the date of adoption of FAS 101 and
would preclude the future deferral in the balance sheet of costs not recovered
through rates at the time such costs were incurred, even if such costs were
expected to be recovered in the future. Based on the balances of the Company's
regulatory assets and liabilities as of December 31, 1994,1995, the Company estimates
that future adoption of FAS 101 for all of the Company's regulated operations
would result in an extraordinary loss of $142$145 million, which includes a
reduction for the related deferred income taxes. The Company's cash flows would
not be affected by the adoption of FAS 101.
DIVIDENDS
The Company does not expect to be able to pay cash dividends on its Common
Stock for the foreseeable future. The Company is currently precluded by State
statute and restrictive covenants in certain debt
agreements from declaring or paying dividends. No dividendsdividend on Common Stock havecommon stock has
been declared or paid since 1989.
Under current applicable provisions of the Arizona General Corporation Law,
the Company is permitted to declare and pay dividends on its shares in cash,
property, or its own shares, only out of unreserved and unrestricted earned
surplus or out of the unreserved and unrestricted net earnings of the current
fiscal year and the immediately preceding fiscal year taken as a single period,
except that the Company may not declare or pay dividends when the Company is
insolvent (unable to pay its debts as they become due in the ordinary course of
business) or when the payment of the dividend would render the Company
insolvent, or when the declaration or payment of the dividend would be contrary
to any restriction contained in the Articles.
At December 31, 1994, the Company had no earned surplus (its accumulated
deficit on that date was $681 million), and the Company had no net earnings for
the two fiscal years then ended taken together. Also, the Company expects to
have no earned surplus and limited net earnings and cash flow for several years.
Under applicable provisions of amendments to the Arizona General
Corporation Law, which will be effectivein effect starting in 1996, a company will beis permitted to make
distributions to shareholders unless, after giving effect to such distribution,
either (i) the company would not be able to pay its debtsdebt as they come due in the
usual course of business, or (ii) the company's total assets would be less than
the sum of its total liabilities plus the amount necessary to satisfy any
liquidation preferences of shareholders with preferential rights. As of December 31, 1994, the Company's common stock deficit was $42 million.
AlthoughUnder such
provisions, the Company expectsis currently able to meet the requirements under the amended
corporation law for making distributions to shareholders within several years,
restrictive covenants in certain existing debt agreements may continue to
precludedeclare and pay a dividend.
However, the Company from declaringmay not declare or paying dividends.
Thepay dividends pursuant to covenants
under both the MRA and the General First Mortgage.
The Company's ability to pay a dividend is restricted by certain covenants
of the General First Mortgage contains covenants, applicable so long as certain series of First
Mortgage Bonds (aggregating $194$184 million in principal amount) are outstanding, whichoutstanding.
These covenants restrict the payment of dividends on Common Stock if certain
cash flow coverage and retained earnings tests are not met. The cash flow
coverage and retained earnings test will prevent the Company from paying
dividends on its Common Stock until such time as the Company's cash flow
coverage ratio, as defined therein, is greater or equal to a ratio of 2 to 1,
and the Company has positive retained earnings rather than an accumulated
deficit. As of December 31, 1995, the Company had a cash flow coverage ratio
slightly above 2 to 1 and the Company's accumulated deficit was $626 million.
Such covenants will remain in effect until the First Mortgage Bonds of such
series have been paid or redeemed. The latest maturity of such First Mortgage
Bonds is in 2003.
The MRA includescontains a similar dividend restriction based on retained earnings.
Such restriction will no longer apply if (i) the Renewable Term Loan and the
Revolving Credit have been paid in full and the commitments relating thereto
have been terminated and (ii) the Company's senior long-term debt is rated
investment grade. Currently, the Company's total outstanding amounts under the
Renewable Term Loan are $31 million and to date no amounts have been borrowed
under the Revolving Credit. Commitments relating to such facilities permit the
Company to borrow $133 million under the Renewable Term Loan and $50 million
under the Revolving Credit. Also, the Company's senior debt is currently rated
below investment grade.
In order for the Company to pay a dividend when such covenants would
otherwise restrict such payment, the Company would have to (i) obtain a waiver
or an amendment to the MRA's retained earnings covenant and (ii) redeem all
outstanding First Mortgage Bonds of the series that contain dividend
restrictions or amend the General First Mortgage. Such amendment would require
approval by holders of 75% of all First Mortgage Bonds.
In addition to such restrictive covenants, the Company may also be
restricted under the Federal Power Act from paying dividends from funds properly
included in the capital account. The provisions of the Federal Power Act leaves
the scope of any such restriction and its potential applicability to the Company
unclear.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS
TheDue to growth in retail sales and cost containment efforts, the Company's
net cash flows from continuing operations were more than sufficient, in all
three years from 1993 to 1995, to cover all construction expenditures and debt
maturities.
Net cash equivalents, including such amounts heldflows from continuing operating activities decreased in aggregate
$24 million in 1995 compared with 1994 due primarily to a $14.6 million tax
payment in 1995 made by the Company's investment subsidiaries,Company relating to an appeal of a transaction
privilege tax assessment (see Note 6 of Notes to Consolidated Financial
Statements, Commitments and Contingencies, Tax Assessments); increased
$86 million or 53%, over the 1993
year end balance of $162 million,compensation paid relating to the 1994 year end balanceincentive plan and increased employee
compensation and pension benefits expenses; and lower cash receipts from sales
to other utilities. Cash receipts from sales to other utilities decreased due
to lower kWh sales and lower energy prices as a result of $248 million.
Receiptslower regional loads
and an abundance of hydroelectric power in the western United States.
Increased cash expenditures were partially offset in 1995 by lower fuel and
purchased power expenses and by revenues from retail customers increased $55 million over 1993 reflecting the sales and customers growth discussed above. Cash expenditures for
continuing operatingof Emission Allowances.
Net cash flows from investing activities increased,decreased in aggregate, $10 million, due
primarily to increased sales levels. As1995 compared with
1994 as a result Net Cash Flow - Continuing
Operating Activities increased 61% to $144 million for 1994.
Construction expenditures, primarily for expansion and reinforcement of the Company's transmissionpurchase of lease debt securities described below
under Financing Developments , and distribution systems, increased $14the investment in the Coors Energy project by
Nations Energy through a partnership interest.
Net cash flows from financing activities decreased $159 million over 1993
levels. In addition,in 1995
compared with 1994 as a result of the Company continued reducing its outstanding debt and lease
obligations by retiring $3713% or $180 million in 1995. Such reduction was comprised of $17
million of such obligations in 1994.first mortgage bond and Installment Sale Agreement maturities, a $19
million permanent prepayment of the Term Loan and $143 million payment of the
Renewable Term Loan of which $133 million can be reborrowed.
During 1995,1996, the Company expects to generate sufficient internal cash flows
to fund its continuing operating activities and construction expenditures
providedexpenditures. Cash
flow levels are subject to short-term interest rates remain near current levels and revenues from wholesale
sales are similar to last year.remaining near current levels. An increase in short-term interest rates
of 100 basis points (1%) would result in an approximate $10 million increase in
interest expense. If 19941996 cash flows fall short of expectations, the Company
would expect to usefund its cash requirements by reducing cash balances and/or borrowing
under its Renewable Term Loan and/or the Revolving Credit.
As a revolving credit line provided underresult of activities described above, the MRACompany's cash and cash
equivalents, including such amounts held by the Company's investment
subsidiaries, decreased $163 million or 66%, from the 1994 year-end balance of
$248 million, to meet operating and
capital requirements.the 1995 year-end balance of $85 million. The Company's cash
balance including cash equivalents at March 7, 19951, 1996 was approximately $185 million (including the cash and cash equivalents of the
investment subsidiaries).$52
million. Cash balances are invested in investment grade, money-market
securities with an emphasis on preserving the principal amounts invested.
FINANCING DEVELOPMENTS
On December 30, 1994, the Company purchased and cancelled $17.25 million
principal amount of its First Mortgage Bonds 12.22% Series due June 1, 2000.
The payment was made to fulfill the Company's requirement under the MRA to
utilize Extraordinary Cash to reduce outstanding indebtedness. The
Extraordinary Cash was generated from cash dividends paid to the Company by the
investment subsidiaries. See Restrictive Covenants, Prepayments.
OnIn March 7, 1995, the Company and its banks completed the Sixth Amendmentan amendment to the
MRA which eased certain debt prepayment restrictions and modified theallowed reborrowing of
certain Renewal Term Loan to allow reborrowing of amounts which will have been previously
prepaid (Renewable Term Loan).prepayments. The amendment will allow the Company to better
manage its cash position and reduce capital costs while maintaining liquidity.
Prior to the amendment the Company was not permitted to prepay non-MRA debt
except to the extent that Excess Cash and Extraordinary Cash were generated, see
Restrictive Covenants, Prepayments below for the description of such terms. The
amendment, now in effect, renders the Excess Cash and Extraordinary Cash
provisions inapplicable and allows the Company to
optionally prepay outstandingnon-MRA debt of the Company provided certain conditions are met. Such
conditions include that $1 of principal outstanding under the Renewable Term
Loan is permanently prepaid and the commitment therefore terminated for every $2
used to permanently prepay other debt such as First Mortgage Bonds. The
Renewable Term Loan allows the Company to reborrow amounts paid down to the
extent of the remaining outstanding loan commitment. The commitment fee on the
Renewable Term Loan will beis 0.5% of the unused portion of such commitment.
As a condition to the amendment becoming effective, the Company permanently
prepaid $19.3$19 million of the Term Loan reducing the outstanding balance from $193.4$193
million to approximately $174 million. Thus, the initial commitment and
outstanding balance of the Renewable Term Loan was approximately $174 million.
In May 1995, the Company purchased approximately $18 million of
Springerville Unit 1 lease debt securities. The Company expects yearly cash
earnings of approximately $2 million as a result of the above-mentioned
purchase. This purchase is shown on the balance sheet under Investments and
Other Property and the interest earned is included in Interest Income on the
income statement. Also, as a result of the debt securities purchase, the
Renewable Term Loan commitment was decreased by $10 million, to $164 million, to
meet the prepayment provisions of the MRA. In aggregate, in 1995, the Company
made payments on the Renewable Term Loan totaling $162 million. The Company can
currently reborrow $133 million under the Renewable Term Loan.
Also, in 1995, the Company reduced its long-term debt by $17 million, as a
result of scheduled maturities.
In January 1996, the Company obtained a tax-exempt volume cap allocation
from the state of Arizona. The Company's allocation is for approximately $16.7
million to be issued by the Pollution Control Corporation of the county of
Coconino in Arizona, for the benefit of the Company. The Company expects to
issue such bonds in early April 1996. If the Company were to fail to issue the
bonds by such time, the Company would lose its volume cap allocation. The
proceeds will be used to reimburse the Company for expenditures relating to the
Company's interest in pollution control facilities at the Navajo Generating
Station. Also, in order for the Company to issue such bonds, the Company will
need approval from the ACC. The Company filed a financing application with the
ACC on February 14, 1996. See C onstruction Expenditures below.
SHORT-TERM CREDIT FACILITIES
REVOLVING CREDIT
TheUnder the MRA, the Banks provided as part of the MRA a $50 million Revolving Credit for
working capital purposes. To date, the Company had not borrowed any funds under
the $50 million Revolving Credit. The Revolving Credit has a termination and
maturity date of December 31, 1999, and bearsborrowings, if any, thereunder bear
interest at a variable rate based upon, at the option of the Company, either (i)
prime rate or (ii) an adjusted eurodollar rate plus a percentage ranging from 0.75%1%
during 1994,1996, gradually increasing to 2% by 1998 and thereafter. The Company is
required to repay loans under the Revolving Credit in full for at least 30
consecutive days in each twelve-month period prior to November 30 of each year.
The annual commitment fee for the Revolving Credit equals 0.5% of the unused
portion. The Revolving Credit is secured and contains restrictive covenants.
See Restrictive Covenants below.
As of December 31, 1994 the Company had not borrowed any funds under the
$50 million Revolving Credit.
OTHER
The balancesbalance of $12 million, $12 million and $18 million of short-term debt of the investment
subsidiaries as of December 31, 1995, and 1994, 1993 and 1992,
respectively, werewas associated
with wholly-owned subsidiaries indirectly owned by SRI and, therefore, suchSRI. Such debt is reflected
in net assets of discontinued
operations. Such debtShort-Term Debt and is without recourse to SRI or the Company.
Approximately
$220INCOME TAX POSITION
At December 31, 1995, the Company had, for federal income tax purposes,
approximately $508 million of utilitynet operating loss carryforwards expiring in 2004
through 2009 and utility-related short-term debt$148 million of alternative minimum tax loss carryforwards
expiring in 2006 through 2008. For state income tax purposes, the Company has
approximately $215 million of net operating loss carryforwards expiring in 1996
through 1999. In addition, for federal income tax purposes the Company has $26
million of unused ITC, the use of which will expire during 2002 through 2005, $3
million of alternative minimum tax credit which will carry forward to future
years, and $21 million of capital loss carryforwards which expire during 1996
through 1999.
Due to the Company's Financial Restructuring, the Company experienced a
change in ownership under section 382 of the Internal Revenue Code in December
1991. As a result of that change, the amount of the taxable income for any
post-change year which may be offset by pre-change net operating losses will be
limited based on the value of the Company on the ownership change date. The
Company estimates an annual limit of such offset by prechange losses of
approximately $23 million. The total limitation may be increased to the extent
of gain recognized on sales of assets whose fair market value was restructured
upongreater than
tax basis at the Closingownership change date, thereby representing a built-in-gain as
of that date. The limitation may increase by built-in-gain recognized within a
period of five years after the change in ownership. During 1992 through 1995,
the limitation increased by approximately $102 million of built-in-gain
recognized due to asset sales. Unused limitation may be carried forward until
the pre-change tax attributes expire. At December 31, 1995, the Company had
pre-change federal net operating loss, ITC, capital loss and reclassified as long-term debt.alternative minimum
tax loss carryforwards of approximately $351 million, $26 million, $7 million
and $115 million, respectively.
Because the Company's results from operations have been steadily improving
and have been positive for the last two years, the Company now believes it is
more likely than not that it will realize at least $66.5 million of the total
federal NOL carryforwards of $508 million. Accordingly, the Company recognized
a $23 million income tax benefit related to the expected utilization of $66.5
million of tax operating loss carryforwards which is included in Income Taxes in
Other Income (Deductions) in the Consolidated Statement of Income (Loss).
Furthermore, the Company expects to record similar or greater amounts in 1996
provided the Company's results of operations continue to improve.
RESTRICTIVE COVENANTS
GENERAL FIRST MORTGAGE COVENANTS
The Company's General First Mortgage places limits on the amount of
additional First Mortgage Bonds which can be issued. Under the General First
Mortgage, the Company may issue additional First Mortgage Bonds (a) to the
extent of 60% of net additions to utility property if net earnings, as defined
therein, for a specified period of 12 consecutive calendar months out of the 15
calendar months preceding the date of issuance are at least two (2.0) times the
annual interest requirements on all First Mortgage Bonds to be outstanding and
(b) to the extent of the principal amount of retired bonds. The net earnings
test specified in clause (a) above generally need not be satisfied prior to the
issuance of bonds in accordance with clause (b) above unless (x) (i) the new
bonds are issued within one year after the issuance of, or more than two years
prior to the stated maturity of, the retired bonds and (ii) the new bonds bear a
greater rate of interest than the retired bonds or (y) the new bonds are issued
in respect of retired bonds the interest charges on which have been excluded
from any net earnings certificate filed with the indenture trustee since the
retirement of such bonds. At December 31, 1994,1995, the Company had the ability to
issue approximately $152$107 million of new First Mortgage Bonds on the basis of
property additions, as described above, and, in addition, the Company had the
ability to issue approximately $74$90 million of new First Mortgage Bonds on the
basis of retired bonds. However, issuance of such amounts may be limited by MRA
covenants. See Additional Restrictive Covenants below.
See Dividends above for a discussion of restrictions on the payment of
Common Stock dividends under the General First Mortgage.
GENERAL SECOND MORTGAGE COVENANTS
The General Second Mortgage establishes a second mortgage lien on and
security interest in substantially all of the utility assets of the Company,
subordinate only to the first mortgage lien and security interest. At December
31, 1994,1995, $50 million of such General Second Mortgage bonds had been issued and
provided to the Banks as collateral for the Revolving Credit and, subsequent to
January 2, 1997, subject to certain conditions, the Renewable Term Loan and the
Replacement Reimbursement Agreement.
The Company's General Second Mortgage allows the issuance of additional
Second Mortgage Bonds under certain circumstances. The Company may issue
additional Second Mortgage Bonds (a) to the extent of 70% of net additions to
utility property if net earnings as defined therein, for a specified period of
12 consecutive calendar months within the 16 calendar months preceding the date
of issuance are at least one and three-quarter (1-3/4) times the annual interest
requirements on all First Mortgage Bonds and Second Mortgage Bonds to be
outstanding and (b) to the extent of the principal amount of retired Second
Mortgage Bonds and First Mortgage Bonds. Issuance of Second Mortgage Bonds on
the basis of an amount of retired First Mortgage Bonds reduces by the same
amount of First Mortgage Bonds which could be issued under the General First
Mortgage on the basis of retired bonds. The net earnings test specified in
clause (a) above generally need not be satisfied prior to the issuance of bonds
in accordance with clause (b) above unless (x) (i) the new bonds are issued
within one year after the issuance of, or more than two years prior to the
stated maturity of, the retired bonds and (ii) the new bonds bear a greater rate
of interest than the retired bonds or (y) the new bonds are issued in respect of
retired bonds the interest charges on which have been excluded from any net
earnings certificate filed with the indenture trustee since the retirement of
such bonds. At December 31, 1994,1995, the amount of net additions and retired bonds
would permit (and the net earnings test would not prohibit) the issuance of $455$596
million aggregate principal amount of new Second Mortgage Bonds (at an assumed
interest rate of 12% per annum). The issuance of such amount of Second Mortgage
Bonds assumes that the $226$197 million of First Mortgage Bonds available to be
issued at December 31, 19941995 would be issued first at a rate of 11%. However,
issuance of such amounts may be limited by MRA covenants. See Additional
Restrictive Covenants below.
PREPAYMENTS
Prior to the Sixth Amendment to the MRA becoming effective on March 7,
1995, see Financing Developments above, certain prepayments of indebtedness were
required. The required prepayment equaled the Company's adjusted operating
income, as defined in the MRA, less certain capital expenditures and charges,
for the preceding twelve-month period as of June 30 of each year; provided,
however, that the prepayment amount (Excess Cash) was limited to the excess (if
any) over $25 million of (i) the Company's cash balance, including cash
equivalents, as of each June 30 plus (ii) the cumulative amount of all
dividends, if any, paid on Common Stock from December 15, 1992 to such June 30.
The Company was required to apply the Excess Cash to the prepayment of
indebtedness. For the period ended June 30, 1994, the Company had $31 million
which constituted Excess Cash. The Company had no such Excess Cash for the
period ended June 30, 1993.
The Company was also required to apply other funds as defined in the MRA
(Extraordinary Cash) to the prepayment of its indebtedness. Extraordinary Cash
included the net proceeds from the issuance of equity and certain debt
securities of the Company or any subsidiary; provided, however, that upon
prepayment of the Term Loan in a principal amount of $50 million, Extraordinary
Cash did not include proceeds from the issuance of equity securities, and
included only 50% of the proceeds from the issuance of debt securities.
Extraordinary Cash also included all cash dividends received by the Company from
its investment subsidiaries, TRI and SRI, or any subsidiary thereof. In 1993
and 1994, the Company received cash dividends of $6 million and $50 million,
respectively, from TRI which constituted Extraordinary Cash.
In April 1993, the MRA lenders waived, to the extent of $68 million, as
consideration for certain prepayments, the requirement that the Company use
Excess Cash and Extraordinary Cash to prepay debt as described above.
Therefore, no mandatory prepayments were made during 1993 as a result of such
prepayment provisions and although $81 million of excess cash and extraordinary
cash was generated in 1994 ($87 million for 1993 and 1994 combined), the Company
was required to prepay only $19 million of indebtedness in 1994. See Financing
Developments above.
ADDITIONAL RESTRICTIVE COVENANTS
In addition to the prepayment provisions described above, the MRA contains
a number of restrictive covenants including, but not limited to, covenants
limiting, with certain exceptions, (i) the incurrence of additional
indebtedness, including lease obligations, or the prepayment of existing
indebtedness, or the guarantee of any such indebtedness, (ii) the incurrence of
liens, (iii) the sale of assets or the merger with or into any other entity,
(iv) the declaration or payment of dividends on Common Stock or any other class
of capital stock, (v) the making of capital expenditures beyond those
contemplated in the Company's 1992 ten-year capital budget, and (vi) the
Company's ability to enter into sale-leaseback arrangements, operating lease
arrangements and coal and railroad arrangements. All of these restrictive
covenants described above, other than (i), (iv) and (vi), will be in effect
until at least December 1997. The covenants described in (i), (iv) and (vi)
will cease to be binding on the Company when both the Renewable Term Loan and
the Revolving Credit are paid in full and commitments thereunder terminate and
the Company's senior long-term debt is rated at least investment grade. In addition, the
Company is required pursuant to the MRA to maintain an interest coverage ratio
of (a) operating cash flows plus interest paid to (b) interest paid, through the
year 2003, ranging from 1.21.40 to 1 in 19941995 and gradually increasing to 2 to 1 in
2000 continuing through the year 2003. For the year ended December 31, 1994,1995,
the Company's MRA interest coverage ratio was 2.982.52 to 1. With respect to
dividends, the MRA incorporates, until the Renewable Term Loan and the Revolving
Credit are paid in full and commitments thereunder terminate and the Company's
senior debt is rated investment grade, a restrictive covenant similar to that
currently in the General First Mortgage which limits the Company's ability to
pay dividends on Common Stock until it has positive retained earnings (through
future earnings or otherwise) rather than an accumulated deficit (such
accumulated deficit was $681$626 million at December 31, 1994). The Company does not anticipate being able1995. (See Dividends for
a discussion of the effects of such covenants on the Company's ability to
satisfy the
test of this and other dividend restrictions (see Dividends above) and
therefore, does not anticipate being permitted todeclare or pay cash dividends on its
Common Stock for the foreseeable future.dividends.)
CONSTRUCTION EXPENDITURES
Estimated construction expenditures of the Company, including AFDC, for the
five years 19951996 through 1999,2000, respectively, are $74$80 million, $67$97 million, $81$91
million, $85$52 million and $62$84 million. These amounts include the following: $190$180
million for transmission and distribution facilities in the Tucson area; $44$31
million for expenditures which are necessary to upgrade pollution control
facilities at Navajo (see Item 1., Business, Environmental Matters, Navajo
Generating Station); $85 million for new generation equipment; and $135$108 million
for modifications to existing production facilities. These estimated
construction expenditures include costs to comply with current federal and
state environmental regulations. All of these estimates are subject to
continuing review and adjustment. Actual construction expenditures may vary
from these estimates due to factors such as changes in business conditions,
construction schedules and environmental requirements. Due to the limitation
on the Company's ability to issue debt or equity capital at economically
feasible rates, and to apply such proceeds, if any, to capital requirements,
the Company must financefund these construction expenditures and any Nations Energy
equity investment funding with internally generated funds, tax-exempt debt when
available, and/or reductions of its cash and short-term investments. In the event that funds from
such sources are unavailable, the Company would be unable to expend the amounts
shown above.cash equivalents.
Also, see NoteNotes 5 and 6 of Notes to Consolidated Financial Statements,
Long and Short-Term Debt and Capital Lease Obligations.Obligations, and Commitments and
Contigencies, respectively.
ITEM 8. --- CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See Item 14, page 57,63, for a list of the Consolidated Financial Statements
which are included in the following pages. See Note 119 of Notes to Consolidated
Financial Statements.
INDEPENDENT AUDITORS' REPORT
TUCSON ELECTRIC POWER COMPANY
We have audited the accompanying consolidated balance sheets and statements of
capitalization of Tucson Electric Power Company and its subsidiaries (the
Company) as of December 31, 19941995 and 1993,1994, and the related consolidated
statements of income (loss), cash flows, and changes in stockholders'stockholders equity (deficit), and cash
flows for each of the three years in the period ended December 31, 1994.1995. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Company at December 31, 19941995
and 1993,1994, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 19941995 in conformity with
generally accepted accounting principles.
As discussed in Note 2 to the financial statements, the timing of the recovery
of the costs associated with 37.5% of Springerville Unit 2 cannot presently be
determined because the Company has not yet received rate relief for such costs.
DELOITTE & TOUCHE LLP
Tucson, Arizona
January 31, 1995
(March 7, 1995 as to Note 6)29, 1996
CONSOLIDATED STATEMENTS OF INCOME (LOSS) For the Years Ended December 31,
1995 1994 1993 1992
- Thousands of Dollars -
Operating Revenues
Retail Customers $ 574,925 $ 571,433 $ 524,813 $ 514,014
Amortization of MSR Option Gain
Regulatory Liability 20,053 6,05320,053 6,053
Other Utilities 75,591 99,987 93,273 70,026
---------- ---------- ----------
Total Operating Revenues 670,569 691,473 624,139 590,093
---------- ---------- ----------
Operating Expenses
Fuel 209,889 197,323 132,775
Purchased Power - Energy 13,878 9,032 62,726
Purchased Power - Demand - - 88,288
Deferred Fuel and Purchased Power 7,359 10,716 7,030186,330 231,126 217,071
Capital Lease Expense 95,441 93,056 92,844 19,854
Amortization of Springerville
Unit 1 Allowance (28,432) (26,204) (33,398)
(31,228)
Other Operations 100,948 90,880 95,21899,493 101,039 92,469
Maintenance and Repairs 38,943 42,122 42,300 34,386
Depreciation and Amortization 92,179 89,905 74,184 69,445
Taxes Other than Income Taxes 55,640 46,118 54,814
48,632
Financial Restructuring Costs - 1,498 29,511Income Taxes 8,920 (91) (91)
---------- ---------- ----------
Total Operating Expenses 548,514 577,071 540,193 556,637
---------- ---------- ----------
Operating Income 122,055 114,402 83,946 33,456
---------- ---------- ----------
Other Income (Deductions)
Regulatory Disallowances and Adjustments - - (13,777) -
Deferred Springerville Unit 2 Carrying
Costs 1,127 1,133 5,359
4,143
Loss on Financial Restructuring - - (26,669)
Litigation Settlement - - 27,576
Interest Income 8,222 7,556 3,909
4,568
Income Taxes 29,356 4,820 5,186
5,654
Other Income 2,826 489 805 7,744
---------- ---------- ----------
Total Other Income (Deductions) 41,531 13,998 1,482 23,016
---------- ---------- ----------
Interest Expense
Long-Term Debt - Net69,174 69,353 68,053
72,687
Regulatory Interest Imputed on Losses Recorded at
Present Value 32,633 32,280 31,303
29,781
Short-Term Debt - - 26,311
Other 7,997 7,118 8,604 7,770
Allowance for Borrowed Funds Used
During Construction (1,123) (1,091) (716) (1,055)
---------- ---------- ----------
Total Interest Expense 108,681 107,660 107,244 135,494
---------- ---------- ----------
(continued on next page)
CONSOLIDATED STATEMENTS OF INCOME (LOSS) (Continued)
For the Years Ended December 31,
1995 1994 1993 1992
- Thousands of Dollars -
Income (Loss) from Continuing Operations 54,905 20,740 (21,816) (79,022)
Provision for Loss on Disposal of
Discontinued Operations - - (4,000) (44,047)
---------- ---------- ----------
Net Income (Loss) $ 54,905 $ 20,740 $ (25,816) $(123,069)
========== ========== ==========
Average Shares of
Common Stock Outstanding (000) 160,691 160,724 160,544 31,872
========== ========== ==========
Net Income (Loss) per Average Share
Continuing Operations $ 0.34 $ 0.13 $ (0.14)
$ (2.48)
Discontinued Operations - - (0.02) (1.38)
---------- ---------- ----------
Total Net Income (Loss) per
Average Share $ 0.34 $ 0.13 $ (0.16)
$ (3.86)
========== ========== ==========
See Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31,
1995 1994 1993
- Thousands of Dollars -
Cash Flows from Continuing Operating Activities
Cash Receipts from Retail Customers $616,064 $611,917 $557,222
Cash Receipts from Other Utilities 80,415 99,198 91,799
Fuel and Purchased Power Costs Paid (167,672) (187,130) (167,691)
Wages Paid, Net of Amounts Capitalized (63,412) (51,960) (47,073)
Payment of Other Operations and
Maintenance Costs (75,504) (73,036) (86,582)
Capital Lease Interest Paid (83,986) (82,511) (81,932)
Interest Paid, Net of Amounts Capitalized (78,743) (72,556) (70,316)
Taxes Paid, Net of Amounts Capitalized (120,759) (107,594) (105,748)
Income Taxes Paid (1,960) - -
Litigation Settlement - - (5,000)
Emission Allowance Inventory Purchases (4,190) - -
Emission Allowance Inventory Sales 11,255 - -
Interest Received 7,882 7,288 4,652
--------- --------- ---------
Net Cash Flows -
Continuing Operating Activities 119,390 143,616 89,331
--------- --------- ---------
Net Cash Flows - Discontinued Operations - 42,685 5,677
--------- --------- ---------
Cash Flows from Investing Activities
Construction Expenditures (59,097) (62,599) (48,162)
Purchase of Debt Securities (17,697) - -
Investment in Partnership (12,429) - -
Other Investments - Net 3,321 103 (286)
--------- --------- ---------
Net Cash Flows - Investing Activities (85,902) (62,496) (48,448)
--------- --------- ---------
Cash Flows from Financing Activities
Proceeds from Long-Term Debt - - 20,000
Payments to Retire Long-Term Debt (36,507) (19,424) (72,187)
Payments on Renewable Term Loan (143,060) - -
Payments to Retire Capital Lease Obligations (17,231) (17,747) (10,690)
Other - Net 252 (478) 862
--------- --------- ---------
Net Cash Flows - Financing Activities (196,546) (37,649) (62,015)
--------- --------- ---------
Net Increase (Decrease) in
Cash and Cash Equivalents (163,058) 86,156 (15,455)
Cash and Cash Equivalents, Beginning of Year * 248,152 161,996 177,451
--------- --------- ---------
Cash and Cash Equivalents, End of Year ** $ 85,094 $248,152 $161,996
========= ========= =========
(continued on next page)
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
* Beginning of year balance includes cash and cash equivalents from
discontinued operations of $14,852,000 for 1995, $22,179,000 for 1994
and $22,502,000 for 1993
** End of year balance includes cash and cash equivalents from discontinued
operations of $14,852,000 for 1994 and $22,179,000 for 1993.
See Notes to Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
1995 1994 1993
- Thousands of Dollars -
Utility Plant
Plant in Service $2,095,679 $2,053,123 $2,004,112
Utility Plant Under Capital Leases 893,064 894,508893,064
Construction Work in Progress 50,898 40,870 33,568
----------- -----------
Total Utility Plant 3,039,641 2,987,057 2,932,188
Less Accumulated Depreciation and Amortization (859,227) (791,617) (727,101)
Less Accumulated Amortization of Capital Leases (40,113) (25,595)
(12,634)
Less Allowance for Springerville Unit 1 Allowance (162,175) (162,423) (162,689)
----------- -----------
Total Utility Plant - Net 1,978,126 2,007,422 2,029,764
----------- -----------
Investments
Investments and Other Property 52,116 4,307
Net Assets of Discontinued Operations - 8,685 58,480
Other Investments 4,307 4,370
----------- -----------
Total Investments 52,116 12,992 62,850
----------- -----------
Current Assets
Cash and Cash Equivalents 85,094 233,300 139,817
Accounts Receivable 61,717 66,332 65,212
Materials and Fuel 42,168 36,109 36,312
Deferred Income TaxTaxes - Current 18,250 12,870
8,927
Other 10,719 10,5387,565 8,376
----------- -----------
Total Current Assets 359,330 260,806214,794 356,987
----------- -----------
Deferred Debits - Regulatory Assets
Income Taxes Recoverable Through Future Rates 135,957 143,372 149,508
Deferred Common Facility Costs 63,303 65,843 68,383
Deferred Springerville Unit 2 Costs 42,039 54,983 67,543
Deferred Lease Expense 19,808 25,228 32,602
Deferred Fuel and Purchased Power Expense 5,872 13,231
Other Deferred Regulatory Assets 9,362 8,1658,576 15,234
Deferred Debits - Other 16,211 17,532 21,244
----------- -----------
Total Deferred Debits 285,894 322,192 360,676
----------- -----------
Total Assets $2,701,936 $2,714,096$2,530,930 $2,699,593
=========== ===========
See Notes to Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND OTHER LIABILITIES
December 31,
1995 1994 1993
- Thousands of Dollars -
Capitalization
Common Stock Equity (Deficit) $ (42,233)12,488 $ (62,973)(42,233)
Capital Lease Obligations 897,958 922,735 927,201
Long-Term Debt 1,207,460 1,381,935 1,416,352
----------- -----------
Total Capitalization 2,117,906 2,262,437 2,280,580
----------- -----------
Current Liabilities
Short-Term Debt 12,039 -
Current Obligations Under Capital Leases 33,389 12,803
Current Maturities of Long-Term Debt 12,075 17,167 2,203
Accounts Payable 25,178 39,777 40,190
Interest Accrued 57,389 59,480 65,738
Taxes Accrued 15,696 29,215 20,269
Accrued Employee Expenses 13,680 15,247
4,222
Current Obligations Under Capital Leases 12,803 14,825
Other 7,989 6,624 6,389
----------- -----------
Total Current Liabilities 177,435 180,313 153,836
----------- -----------
Deferred Credits and Other Liabilities
MSR Option Gain Regulatory Liability 25,610 41,214 54,924
Accumulated Deferred Investment Tax Credits
Regulatory Liability 19,603 24,368
29,279
AccumulatedOther Regulatory Liabilities 10,343 469
Deferred Income Taxes 166,684 168,833- Noncurrent 145,982 164,341
Other 26,920 26,64434,051 26,451
----------- -----------
Total Deferred Credits and Other Liabilities 259,186 279,680235,589 256,843
----------- -----------
Total Capitalization and Other Liabilities $2,701,936 $2,714,096$2,530,930 $2,699,593
=========== ===========
See Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
1995 1994 1993
COMMON STOCK EQUITY (DEFICIT) - Thousands of Dollars -
Common Stock--No Par Value 1995 1994 1993
----------- -----------
Shares Authorized 200,000,000 200,000,000
Shares Outstanding 160,671,157 160,723,702
160,723,702Warrants Outstanding * 12,054,278 12,054,278 $ 645,479645,295 $ 645,479
Capital Stock Expense (6,357) (6,357)
Accumulated Deficit (626,450) (681,355) (702,095)
----------- -----------
Total Common Stock Equity (Deficit) 12,488 (42,233) (62,973)
----------- -----------
PREFERRED STOCK, No Par Value,
1,000,000 Shares Authorized, None Outstanding - -
CAPITAL LEASE OBLIGATIONS
Springerville Unit 1 466,187 458,092 449,984
Springerville Common Facilities 136,128 139,076 144,114
Irvington Unit 4 142,878 143,407 143,909
Valencia Coal Handling Facilities 179,990 187,523 195,309
Other Leases 6,164 7,440 8,710
----------- -----------
Total Capital Lease Obligations 931,347 935,538 942,026
Less Current Maturities (33,389) (12,803) (14,825)
----------- -----------
Total Long-Term Capital Lease Obligations 897,958 922,735 927,201
----------- -----------
LONG-TERM DEBT Interest
Issue Maturity Rate
- -----------------------------------------------------
First Mortgage Bonds
Corporate 1995 - 2009 4.55% to 12.22% 253,750 269,750 287,000
Industrial Development 2005 - 2025 6.10% to 8.25%
Revenue Bonds (IDBs) and variable** 232,200 232,200
Loan Agreements (IDBs) 2003 - 2022 6.25% and
variable** 702,585 703,600
704,555Renewable Term Loan 1997 - 1999 variable* 193,400* 31,000 -
Term Loan (See Note 5) variable** - 193,400
Promissory Note 1992 - 1995 8.00% - 152 1,400
----------- -----------
Total Stated Principal Amount 1,219,535 1,399,102
1,418,555(continued on next page)
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Continued)
Less Current Maturities (12,075) (17,167) (2,203)
----------- -----------
Total Long-Term Debt 1,207,460 1,381,935 1,416,352
----------- -----------
Total Capitalization $2,117,906 $2,262,437 $2,280,580
=========== ===========
* The Warrants to purchase Common Stock at an exercise price of $3.20 per
share, are exercisable and expire in 2002.
** Interest rates on variable rate tax-exempt (IDB) debt (IDBs) ranged from 1.50%1.65%
to 5.75% during 19941995 and 1993,1994, and the average interest rate on such debt
was 3.91% in 1995 and 2.96% in 1994 and 2.65% in 1993.1994. Interest rates on the Term Loan
ranged from 3.63% to 6.69%6.75% in 19941995 and 1993,1994, and the average interest
rate on such debt was 6.50% in 1995 and 4.92% in 1994 and 4.03% in 1993.
See Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
1994 1993 1992
- Thousands of Dollars -
Cash Flows from Continuing Operating Activities
Cash Receipts from Retail Customers $611,917 $557,222 $546,801
Cash Receipts from Other Utilities 99,198 91,799 68,775
Purchased Power - Energy (15,829) (9,610) (7,896)
Purchased Power - Demand - (1,006) (34,114)
Fuel Costs Paid (171,301) (157,075) (139,146)
Wages Paid, Net of Amounts Capitalized (49,284) (44,394) (37,275)
Payment of Other Operations and
Maintenance Costs (78,808) (91,924) (110,993)
Capital Lease Interest Paid (82,511) (81,932) -
Interest Paid, Net of
Amounts Capitalized (72,556) (70,316) (91,531)
Taxes Paid, Net of Amounts Capitalized (104,498) (103,005) (92,673)
Litigation Settlements - Net - (5,000) 35,000
Lease Payments, Net of
Amounts Capitalized - - (61,328)
Interest Received 7,288 4,652 11,588
Federal Income Tax Refund Received - - 1,440
Other - (80) (18)
--------- --------- ---------
Net Cash Flows -
Continuing Operating Activities 143,616 89,331 88,630
--------- --------- ---------
Net Cash Flows - Discontinued Operations 42,685 5,677 41,878
--------- --------- ---------
Cash Flows from Capital Transactions
Construction Expenditures (62,599) (48,162) (34,512)
Other Investments 103 (286) 58
--------- --------- ---------
Net Cash Flows - Capital Transactions (62,496) (48,448) (34,454)
--------- --------- ---------
Cash Flows from Financing Activities
Proceeds from Long-Term Debt - 20,000 16,732
Payments to Retire Long-Term Debt (19,424) (72,187) (32,908)
Payments to Retire Capital Lease Obligations (17,747) (10,690) (320)
Other (478) 862 (306)
--------- --------- ---------
Net Cash Flows - Financing Activities (37,649) (62,015) (16,802)
--------- --------- ---------
Net Increase (Decrease) in
Cash and Cash Equivalents 86,156 (15,455) 79,252
Cash and Cash Equivalents, Beginning of Year * 161,996 177,451 98,199
--------- --------- ---------
Cash and Cash Equivalents, End of Year ** $248,152 $161,996 $177,451
========= ========= =========
* Beginning of year balance includes cash and cash equivalents from
discontinued operations of $22,179,000 for 1994, $22,502,000 for 1993 and
$11,856,000 for 1992.
** End of year balance includes cash and cash equivalents from discontinued
operations of $14,852,000 for 1994, $22,179,000 for 1993 and $22,502,000
for 1992.1994.
See Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT)
Premium
on Capital Accumulated
Preferred Common Capital Stock Earnings
Stock Stock Stock Expense (Deficit)
--------------------------------------------------------------------------------
- Thousands of Dollars -
Balances at December 31, 1991 $82,793 $357,782 $7,007 $(3,482) $(553,210)
1992 Net Loss - - - - (123,069)
1992 Issuances: 134,713,860
Shares of Common Stock,
including the reclassification
of all Preferred Stock to
Common Stock. See Note 3. (82,793) 286,645 (7,007) (2,875) -
-------- -------- ------- -------- ----------
Balances at December 31, 1992 - 644,427 - (6,357) (676,279)$644,427 $(6,357) $(676,279)
1993 Net Loss - - - - (25,816)
1993
Sale of Treasury Stock: 294,050 Shares of
CommonTreasury Stock - 1,052 - -
-
-------- -------- ---------------- -------- ----------
Balances at December 31, 1993 - 645,479 - (6,357) (702,095)
1994 Net Income - - - - 20,740
-------- -------- ---------------- -------- ----------
Balances at December 31, 1994 $645,479 (6,357) (681,355)
1995 Net Income - $645,479 $ - 54,905
52,545 Shares Purchased by Deferred
Compensation Trust (184) - -
--------- -------- ----------
Balances at December 31, 1995 $645,295 $(6,357) $(681,355)
======== ======== =======$(626,450)
========= ======== ==========
See Note 6.5. Long-Term Debt - AdditionalDividends - Restrictive Covenants for discussion
of restrictions on the Company's ability to pay dividends.
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ----------------------------------------------------------------------------
NATURE OF OPERATIONS
The Company is a public utility engaged in the business of generation,
transmission, distribution and sale of electricity. The Company's retail
service area encompasses 1,155 square miles in Pima and Cochise counties in
Southern Arizona. The Company also engages in wholesale sales to other
utilities in Arizona, California, Colorado, New Mexico, Oregon, Texas and
Utah. Approximately 63% of the Company's work force is subject to a
collective bargaining unit. The collective bargaining agreement in place at
December 31, 19941995 terminates on December 1, 1996.
BASIS OF PRESENTATION
The consolidated financial statements include the accounts of the
Company, and threefour wholly-owned, utility-related subsidiaries and two investment
subsidiaries on a consolidated basis. All significant intercompany balances
and transactions have been eliminated in the consolidation. The results of
operations, estimated net realizable value of net assets and cash flows of
the Company's two investment subsidiaries have beenwere classified as discontinued
operations sincefrom June 30, 1990.1990 until December 31, 1994. See Note 4.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
REGULATION
The Company's utility accounting practices and electricity rates are
subject to regulation by the ACC and, in certain areas, by the FERC.
ACCOUNTING FOR THE EFFECTS OF REGULATION
The Company prepares its financial statements in accordance with the
provisions of FAS 71. A regulated enterprise can prepare its financial
statements in accordance with FAS 71 only if (i) the enterprise's rates for
regulated services are established by or subject to approval by an
independent third-party regulator, (ii) the regulated rates are designed to
recover the enterprise's costs of providing the regulated services and (iii)
in view of demand for the regulated services and the level of competition, it
is reasonable to assume that rates set at levels that will recover the
enterprise's costs can be charged to and collected from customers. FAS 71
requires a cost-based, rate-regulated enterprise to reflect the impact of
regulatory decisions in its financial statements. In certain circumstances,
FAS 71 requires that certain costs and/or obligations (such as incurred costs
not currently recovered through rates, but expected to be so recovered in the
future) be reflected in a deferral account in the balance sheet and not be
reflected in the statement of income or loss until matching revenues are
recognized. It is the Company's policy to assess the recoverability of costs
recognized as regulatory assets and the Company's ability to continue to
account for its activities in accordance with FAS 71, based on each rate
action and the criteria set forth in FAS 71.
The Company's Consolidated Balance Sheets at December 31, 19941995 and 19931994
contain certain amounts solely as a result of the application of FAS 71:
Assets (Liabilities) 1995 1994 1993
-------------------- ----- -----
- Millions of Dollars -
Income Taxes Recoverable Through Future Rates $136 $143 $150
Deferred Common Facility Costs 63 66 68
Deferred Springerville Unit 2 Costs 42 55 68
Deferred Lease Expense 20 25 33
Deferred Fuel and Purchased Power Expense 6 13
Other Deferred Charges 9 815
MSR Option Gain Regulatory Liability (26) (41) (55)
Deferred Investment Tax Credits (20) (24) (29)
Other Deferred Credits (1)(10) (1)
Regulatory assets are recorded based on prior rate orders issued by the
ACC which provide a mechanism for recovery in regulated rates or historical
rate treatment which provides evidence as to the probability of future rate
recovery. The material regulatory assets listed above earn either a return
on investment through inclusion in rate base or earn a set rate of interest
stipulated by the ACC.
A number of accounts in the Company's Consolidated Statements of Income
(Loss) for the three years in the period ended December 31, 19941995 also reflect
the application of FAS 71:
Income (Expense) 1995 1994 1993 1992
---------------- ----- ----- -----
- Millions of Dollars -
Amortization of MSR Option Gain
Regulatory Liability $ 20 $ 620 $ 6
Amortization of Springerville Unit 2
Rate Synchronization (14) -(14) -
Deferred Fuel and Purchased Power (6) (7) (11) (7)
Amortization of Deferred Common Facility Costs (3) (3) (4)(3)
Deferred Springerville Unit 2 Carrying Costs 1 1 5 4
Regulatory Disallowances and Adjustments - (14) - Amortization of(14)
Investment Tax Credit Amortization 5 5 6
Regulatory5
Interest Relating to MSRImputed on Loss (MSR Option Gain
Regulatory LiabilityLiability) Recorded at Present Value (4) (6) (7) (7)
If the Company had not applied the provisions of FAS 71 in these years,
each of these amounts appearing in the Consolidated Statements of Income
(Loss) would have been reflected in the Consolidated Statements of Income or
Loss in prior periods, except for two items which would not have been
recorded: 1) the amortization of the MSR Option Gain Regulatory Liability,
including regulatory interest;interest imputed on the loss recorded at present value; and 2) the
Springerville Unit 2 carrying cost deferrals. Lease expense relating to the
capital leases, while the same over the life of the leases, would be
recognized at different annual amounts if the Company were to discontinue the
application of FAS 71. See Utility Plant Under Capital Leases below.
If at some point in the future the Company determines that it no longer
meets the criteria for continued application of FAS 71 to all or a portion of
the Company's regulated operations, the Company would be required to adopt
the provisions of FAS 101 for that portion of the operations for which FAS 71
no longer applied. Adoption of FAS 101 would require the Company to write
off its regulatory assets and liabilities as of the date of adoption of FAS
101 and would preclude the future deferral in the Consolidated Balance Sheet
of costs not recovered through rates at the time such costs were incurred,
even if such costs were expected to be recovered in the future. Based on the
balances of the Company's regulatory assets and liabilities as of December
31, 1994,1995, the Company estimates that future adoption of FAS 101, if applied
to all of the Company's regulated operations, would result in an
extraordinary loss of $142$145 million, which includes a reduction for the
related deferred income taxes.taxes of $69 million. The Company's cash flows would
not be affected by the adoption of FAS 101.
UTILITY PLANT
Utility Plant by major classes at December 31, 19941995 and 19931994 is as
follows:
1995 1994 1993
---------- ----------
- Thousands of Dollars -
Utility Plant:
Production Plant $1,013,171 $1,002,409 $ 988,241
Transmission Plant 460,986 460,055 454,105
Distribution Plant 517,999 495,336 473,830
General Plant 92,069 84,441 77,874
Intangible Plant 10,441 10,238 8,685
Electric Plant Held for Future Use 1,013 644 1,377
---------- ----------
Total Utility Plant $2,095,679 $2,053,123 $2,004,112
========== ==========
Utility plant is stated at original cost. In accordance with the
Uniform System of Accounts prescribed by the FERC and accepted by the ACC,
the Company capitalizes AFDC based on the cost of borrowed funds and a
reasonable rate upon equity funds used to finance CWIP, when recovery of such
costs from ratepayers is probable. The component of AFDC attributable to
borrowed funds is presented as a reduction of Interest Expense. The
Consolidated Statements of Income (Loss) reflect no AFDC - Equity as all
construction expenditures were deemed under FERC prescribed rules to be
financed with debt. In accordance with FERC Accounting Release No. 13, AFDC
is recorded on construction expenditures1995, 1994 and on the balances of construction
funds held in trust, if any are held. Interest income from construction
funds held in trust, if any, net of income taxes, is credited to CWIP.
Interest Expense on Long-Term Debt - Net reflects interest expense on the
stated principal amount of bonds in excess of the average month-end balance
of construction funds held in trust during the period. Interest expense on
stated bond principal equal to the average month-end balance of construction
funds held in trust is charged against AFDC. In 1994, 1993, and 1992, gross AFDC rates of 4.94%5.59%, 4.85%4.94%
and 8.01%4.85%, respectively, were used for all CWIP.
Depreciation is computed on a straight-line basis at component rates
which are based on the economic lives of the assets. These component rates,
which are authorized by the ACC, averaged 3.73%3.79%, 3.73% and 3.68% in 1995,
1994 and 3.71% in 1994,
1993, and 1992, respectively. The economic lives for production plant are
based on remaining lives. The economic lives for transmission plant,
distribution plant, general plant and intangible plant are based on average
lives. The component rates also reflect estimated removal costs, net of
estimated salvage value. Minor replacements and repairs are expensed as
incurred. Retirements of utility plant, together with removal costs less
salvage, are charged to accumulated depreciation.
UTILITY PLANT UNDER CAPITAL LEASES
As described in Note 3, since December 15, 1992, the date of closing of
the Company's Financial Restructuring, theThe Company's leases of the Springerville Common Facilities,
Springerville Unit 1, Valencia coal handling facilities and Irvington Unit 4
have beenare classified as capital leases in the Consolidated Balance Sheets. For
rate making purposes, the ACC treats these leases as operating leases and has
allowed for recovery of the lease costs by straight-line amortization of the
total amount of lease rent payments over the primary term of the leases,
except for the Valencia coal handling facilities lease. The Valencia coal
handling facilities lease is being amortized on a straight-line basis over
the primary term of the lease plus the first optional renewal period of six
years to reflect the recovery period mandated by the ACC. Under GAAP, the
lease term would have been only the primary term of the lease. Interest and
depreciation relating to the leases are recorded as expense on a basis which
reflects the regulatory straight-
linestraight-line treatment. The amount of lease
amortization incurred for the four above-
describedabove-described leases, as well as the
Company's remaining leases, for the years 1995, 1994 1993 and 19921993 amounted to:
Years Ended December 31,
1995 1994 1993 1992
----- ----- -----
- Millions of Dollars -
Lease Amortization:
Interest $ 97 $ 94 $ 93
$ 22
Depreciation 14 13 12 2
---- ---- ----
Total Lease Amortization $111 $107 $105 $ 24
==== ==== ====
Lease Amortization Included In:
Operating Expenses - Fuel and
Purchased Power $ 20 $ 20 $ 17 $ 1
Operating Expenses - Capital Lease Expense 95 93 93 20
Balance Sheet - Deferred Lease Expense (4) (6) (5) 3
----- ----- ----
Total Lease Amortization $111 $107 $105 $ 24
===== ===== ====
The Deferred Lease Expense of $25$20 million and $33$25 million at December
31, 19941995 and 1993,1994, respectively, reflects: 1) the cumulative difference
between the straight-line method of amortizing the leases for regulatory
purposes and capital lease amortization as promulgated by GAAP; and 2) the
balance of the deferred costs described under Fuel and Purchased Power Costs
below. Also, see Allowance for Springerville Unit 1 Allowance below.
ALLOWANCE FOR
SPRINGERVILLE UNIT 1 TheALLOWANCE
In the 1989 Rate Order the ACC limited recovery through retail rates of
Century
demand charges fornon-fuel expenses of Springerville Unit 1 under the Restated Century Purchase
Contract to a rate of only $15 per kW per
month. From inception through
termination of such contract on December 15, 1992, capacitySuch costs for
Springerville Unit 1 averaged approximately $20 per kW per month.
Prior to its termination as a part of the Financial Restructuring
described in Note 3, the Restated Century Purchase Contract required the
Company to purchase all of Springerville Unit 1 capacity through 2014, but
was subject to cancellation by Century after 2001 on five years' advance
notice. In addition, in 1990, industry and Company projections for the
demand for power in the western United States indicated that excess capacity
conditions would be likely to continue for a few years, but should not exist
by the year 2000. Due to the significant uncertainties regarding the power
markets beyond 2001 and the existence of Century's cancellation option, the
amount of loss, if any, which may have been incurred as a result of the $15$22 per kW per month limitation beyond such date appeared significantly
uncertain. In Decemberduring 1995,
1994 and 1993. Consequently, in 1990 and 1992, the Company therefore, recognized a loss of
approximately $178 million and established a deferred liability for this
estimated loss, the Allowance forrecorded losses,
Springerville Unit 1 Allowance, equal to the present value of the excess of
the Company's costs estimated to be incurred during the period through 20012014,
the term of the lease, over $15 per kW per month using a discount rate of
13%.
In connection with the Financial Restructuring, the Company assumed
Century's lease ofThe balance sheet contra asset Springerville Unit 1 under a capital lease agreement
extending to January 1, 2015. Accordingly, in December 1992, the remaining
unamortized balance of the Allowance for Springerville Unit 1 was
recalculated based on the $15 per kW rate currently permitted pursuant to the
1991 Rate Order and current cost estimates through the year 2014. This
resulted in an additional loss of approximately $7 million, which was
recorded as a component of the Loss on Financial Restructuring in the
Consolidated Statement of Income (Loss) for the year ended December 31, 1992.
In addition, the liability was reclassified to a contra-asset, Allowance for
Springerville Unit 1. The Allowance for Springerville Unit 1 increases
each year by the accrual of interest and decreases by the amount which is
being
amortized to income as a contra-expense, through 2014.Amortization of Springerville Unit 1
Allowance. In 1995, 1994 and 1993, the accrual of such interest was $28.2
million, $25.9 million and $24.2 million, respectively, and the amount
amortized was $28.4 million, $26.2 million and $33.4 million, respectively.
The imputed interest expense associated with this liability, calculated using
a 13% discount rate, associated with this liability
is included as part of Regulatory Interest Imputed on Losses
Recorded at Present Value in the Interest Expense section in the Consolidated
Statements of Income (Loss).
DEFERRED COMMON FACILITY COSTS
Springerville Common Facility Costs are lease costs and operating costs
incurred for the Springerville Common Facilities during the period after
Springerville Unit 1 was placed in service and before Springerville Unit 2
was placed in service. Pursuant to an accounting order from the ACC, these
costs were deferred and are being amortized, as depreciation, over the
primary term of the Springerville Common Facilities Leases. The ACC has
allowed for the recovery of the amortization costs plus a return on
investment.
UTILITY OPERATING REVENUES
Operating Revenues include accruals for unbilled revenues, thereby
recognizing revenue that is earned, but not billed, at the end of an
accounting period.
AMORTIZATION OF MSR OPTION GAIN REGULATORY LIABILITY
TheIn the 1989 Rate Order the ACC allocated to retail customers a portion
of the price paid to the Company upon the 1982 sale of an option to purchase
a 28.8% interest in San Juan Unit 4, asserting that such option was related
to an interconnection agreement which the Company also entered into with MSR
at that time. InThe ACC ordered the 1989 Rate Order, the ACC orderedCompany to recognize the MSR Option Gain be
amortized over a six-year periodby
amortizing amounts to operating revenue through 1995 as a $20 million per year
revenue credit, and1997. Therefore, in 1990,
the Company establishedrecorded a deferred liability forloss, MSR Option Gain Regulatory Liability, equal to
the present value of the amount to be amortized to operating revenues through
1997, calculated using a 13% discount rate. Such deferred liabilityThe MSR Option Gain Regulatory
Liability increases each year by the accrual of interest at 13% and decreases by the
amount which is amortized to operating revenues. In 1995, 1994 and 1993, the
accrual of revenue credit prescribed bysuch interest was $4.4 million, $6.4 million and $7.1 million,
respectively, and the ACC. Such revenue credit is included in Operating Revenues.amount amortized was $20.1 million, $20.1 million and
$6.1 million, respectively. The imputed interest accrualexpense associated with
this liability, calculated using a 13% discount rate, is included as part of
Regulatory Interest Imputed on Losses Recorded at Present Value in the Interest Expense
section ofin the Consolidated Statements of Income (Loss). The 1991
Rate Order deferred amortization of a portion of the regulatory liability to
1996 and 1997.
FUEL AND PURCHASED POWER COSTS
Fuel inventory, primarily coal, is stated on a basis which approximates
weighted average cost. The Company utilizes full absorption costing.
Certain lease and interest costs incurred by Valencia, the Company's
fuel-handling and procurement subsidiary for Springerville, are accounted for
as deferred costs. These costs which were allocatedare being amortized to fuel inventory based on fuel
quantities purchased and then amortized to Fuel expense and, prior to the
closing of the Financial Restructuring on December 15, 1992, to Purchased
Power - Energy, based on the rate of fuel burn at Springerville through
December 31, 1992. Effective January 1, 1993, these costs are amortized to
Fuel expense on a
straight-line basis over 37.4 yearsthrough the year 2030 pursuant to the 1994 Rate Order.
FINANCIAL RESTRUCTURING COSTSINCOME TAXES
In January 1993, the Company adopted Statement of Financial Restructuring costs include costs incurredAccounting
Standards No. 109 (FAS 109), Accounting for legal,
accountingIncome Taxes, on a prospective
basis. FAS 109 requires the recognition of deferred income tax liabilities
and assets for the expected future income tax consequences of temporary
differences between the carrying amounts and the tax bases of other consulting services in connection with the restructuringassets
and liabilities. The adoption of FAS 109 increased both total assets and
total liabilities of the Company's obligations, as describedCompany by $149 million in Note 3.
INCOME TAXES1993. The increase in
assets results primarily from the recording of a regulatory asset, Income
Taxes Recoverable Through Future Rates. Such regulatory asset consists
primarily of the right to recover income taxes relating to previously flowed-
through differences, both timing and permanent, which provided rate benefits
to past ratepayers. The increase in liabilities is primarily the net
increase in deferred income tax assets and deferred income tax liabilities
resulting from the adoption of FAS 109.
Reductions in federal income taxes resulting from ITC relating to
utility operations have been deferred. As authorized by the ACC, these
amounts are amortized over the tax lives of the related property. As the
Company has beenwas in a net operating loss carryforward position and generating tax
losses, the income tax benefits reflected in the Consolidated Statements of
Income (Loss) resultfor the years 1994 and 1993 resulted only from such ITC
amortization. In 1995, income tax benefits include the recognition of a
portion of the Company's net operating loss carryforwards, as well as ITC
amortization. See Note 3.
Income taxes are allocated to the subsidiaries based on contributions to
the consolidated tax return liability. The investment subsidiaries' losses
in 1994 1993 and 19921993 provided no tax benefits to the consolidated group and,
therefore, no tax benefits are recorded as a reduction of the 1993 and
1992 ProvisionsProvision
for Loss on Disposal of Discontinued Operations in the Consolidated
Statements of Income (Loss).
DEBT EXPENSE
Debt discountEPA ALLOWANCES
Purchased Emission Allowances are recorded in a noncurrent inventory
account included in Investments and issuance costsOther Property on the Consolidated
Balance Sheet at December 31, 1995. Emission Allowance inventory is recorded
using the weighted average cost method. Gains on sales of Emission
Allowances are deferred (included as part of Other Deferred Credits and Other
Liabilities in the Consolidated Balance Sheet at December 31, 1995) and will
be amortized overas income in 2000 - 2024, the lives ofperiod the related issues orCompany expects to use
the related refunding issues.Emission Allowance inventory to meet EPA regulations. The amortization
reflects the expected regulatory treatment for the gains.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying value and fair value at December 31, 19941995 and 19931994 of the
Company's financial instruments are as follows:
1995 1994 1993
------ ------
Carrying Fair Carrying Fair
Value Value Value Value
-------- ----- -------- -----
- Thousands of Dollars -
Assets:
Cash and Cash Equivalents $ 85,094 $ 85,094 $ 233,300 $ 233,300
$ 139,817 $ 139,817
Accounts Receivable 66,332 66,332 65,212 65,212Debt Securities (Included
in Investments and Other
Investments 4,307 4,307 4,370 4,370Property) 17,713 18,267 - -
Liabilities:
Accounts Payable (39,777) (39,777) (40,190) (40,190)Short-Term Debt (12,039) (12,039) - -
Long-Term Debt, Including
Current Portion
(See Note 6)5) (1,219,535) (1,233,457) (1,399,102) (1,372,236) (1,418,555) (1,397,838)
The carrying amounts of all financial instruments, except Long-TermCash and Cash Equivalents and Short-Term Debt
are considered to be reasonable estimates of the fair value of each because
of the short maturity of those instruments. The Company intends to hold the
investment in Debt Securities to maturity (January 1, 2013.) Such Debt
Securities are stated at amortized cost, adjusted for the amortization of the
discount to maturity, and the fair value is based on current transactions for
the same or similar debt.
RECLASSIFICATION
Minor reclassifications have been made to the prior year financial
statements presented to conform to the current year's presentation.
BeginningNEW ACCOUNTING STANDARDS
In March 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 121 (FAS 121), Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.
This statement requires that an asset be reviewed for impairment whenever
events or changes in circumstances indicate that the carrying amount of an
asset may not be recoverable. The Company adopted FAS 121 on January 1,
1996, and does not expect the application of FAS 121 to have a material
impact on the Company's financial statements. This conclusion may change in
the fourth quarter of 1994, state and city sales taxes
and similar taxes collected on revenues were removed from Operating
Revenues and Taxes Other Than Income Taxesfuture depending on the Consolidated Statementsextent that the Company's regulated and non-
regulated operations are influenced by an increasingly competitive
environment.
In October 1995, the Financial Accounting Standards Board issued
Statement of Income (Loss). These taxes are included as part of Accounts Receivable
and Taxes AccruedFinancial Accounting Standards No. 123 (FAS 123), Accounting for
Stock-Based Compensation. This statement encourages, but does not require,
companies to adopt a new accounting method for stock-based compensation
awards. Under the new method, an expense is recorded for stock compensation
awards based on the Consolidated Balance Sheets. Such
reclassification was made to enhance the comparabilityestimated fair value of the Company'saward at the grant date. The
cost of the award is reflected as an expense over the period that the stock
option vests. Companies that continue to follow existing standards and do
not adopt the valuation method prescribed by FAS 123 are required to disclose
pro forma net income and earnings per share as if the company had recognized
expense based on FAS 123. Beginning with the 1996 financial statements,
with thosecompanies will be required to meet these disclosure requirements for any
awards made in 1995 and after. The Company plans to continue to follow
existing standards (APB Opinion 25), rather than adopt FAS 123, for
measurement and recognition of other companies. All financial
information presented has been restated to conform to this presentation.stock-based compensation. The tax amounts reclassified were as follows:
Years Ended December 31,
1994 1993 1992
------- ------- -------
- ThousandsCompany will
adopt the disclosure requirements of Dollars -
State Sales Taxes $28,392 $26,027 $25,379
City Sales and Franchise Taxes 12,585 11,351 11,052
ACC Assessment Fee 934 920 952
------- ------- -------
Total Taxes Reclassified $41,911 $38,298 $37,383
======= ======= =======FAS 123 in 1996.
NOTE 2. 1994 RATE ORDERMATTERS
- ------------------------
Effective January 11, 1994,---------------------
1995 RATE INCREASE APPLICATION
On June 13, 1995, the Company filed an application with the ACC authorized a 4.2% increase in base
rates.for an
overall 4.9% or approximately $28.4 million rate increase. The 1994 Rate Order recognized that an additional 17.5%Company's
rate request sought recovery of the operating and capital costs of the
remaining 37.5% of Springerville Unit 2 capacity was used and useful for the retail
jurisdiction, which lowered the percentage of that unit's capacity that is not incurrently being
recovered. On November 30, 1995, the Company entered into the Proposed
Settlement Agreement with the ACC Staff, subject to final approval by the
ACC, that would have provided an overall 2% or approximately $10.4 million
rate base toincrease including recovery of the remaining 37.5%. Therefore, the of Springerville Unit
2. The Company is not presently recovering through retail rates the
depreciation, property taxes, operating and maintenance expenses other than
fuel, or interest costs associated with the 37.5% of Springerville Unit 2
capacity which was not then considered to be used and useful for the retail
jurisdiction at the time of the 1994 Rate Order and therefore was not
included in rate base (hereinafter referred to as "retail excess capacity
deferrals"). These expenses are being expensed as incurred. However, the
1994 Rate Order permits such costs to be deferred for future recovery over
the remaining useful life of Springerville Unit 2. This phase-in plan does
not qualify under FAS 92 and, therefore, such retail excess capacity
deferrals, while deferred for regulatory purposes, cannot be deferred for
financial reporting purposes. Such regulatory deferrals associated with the
excluded Springerville Unit 2 capacity, not included in the financial
statements, totaled $63$78 million at December 31, 1994.1995. Either inclusion in
costs recoverable through retail rates or additional wholesale sales at
sufficient prices of an equivalent amount of capacity (or a combination
thereof) will be required to recover these retail excess capacity deferrals.
The ACC denied the Proposed Settlement Agreement on January 19, 1996.
The Company's application for a rate increase remains pending. The Company
intends to propose and seek ACC approval of a revised settlement agreement in
March 1996.
1994 RATE ORDER
Effective January 11, 1994, the ACC authorized a 4.2% increase in base
rates. The 1994 Rate Order recognized that an additional 17.5% of the
Springerville Unit 2 capacity was used and useful for the retail
jurisdiction, which lowered the percentage of that unit's capacity that is
not in rate base to 37.5%.
As a result of the 1994 Rate Order, the retail excess capacity deferrals
allocable to the 62.5% of Springerville Unit 2 capacity allowed in rate base
was also included in rate base. At December 31, 1993, the retail excess
capacity deferrals allocable to the 17.5% of the Springerville Unit 2
capacity amounted to $17 million. As specified in the 1994 Rate Order, for
rate purposes, these costs are being recovered over a 37.4 year period.
The 1994 Rate Order allowed in rate base 62.5% of deferred Springerville
Unit 2 rate synchronization costs, $42 million at December 31, 1993, which
were non-fuel costs of Springerville Unit 2 incurred from January 1, 1991
through October 14, 1991, including an interest carrying charge, deferred
pursuant to the 1991 Rate Order. For rate making purposes, such costs are
being recovered over a three-year period and are included in Depreciation and
Amortization on the Consolidated Statements of Income (Loss), in accordance
with the 1994 Rate Order. The Company is not presently recovering through
retail rates 37.5% of the deferred Springerville Unit 2 rate synchronization
costs ($2628 million at December 31, 1994)1995). This amount, together with the
balance of such costs ($2914 million at December 31, 1994)1995) that the Company is
presently recovering through rates, are reported in the Company's
consolidated financial statementsConsolidated Balance Sheets as Deferred Springerville Unit 2 Costs.
The 1994 Rate Order provided that the rate synchronization and retail
excess capacity deferrals associated with the 37.5% of Springerville Unit 2
capacity not found to be used and useful for the retail jurisdiction will
continue to incur an interest charge of 7.19% until authorized to be included
in rate base or for a period of three years ending in 1997, whichever occurs
first.
The 1994 Rate Order disallowed recovery of $13.6 million of previously
capitalized Springerville Unit 2 rate synchronization costs and certain other
minor costs. The $13.6 million is comprised of $5.2 million for wholesale power
sale revenue credits which the Company had offset against the off-
balanceoff-balance
sheet retail excess capacity deferrals which the ACC stated should have been
offset against the rate synchronization deferrals. The remaining $8.4
million of disallowance results from the ACC's finding that the Company
should have calculated the 7.19% carrying charge on a net-of-tax basis rather
than pre-tax, as calculated by the Company. Such disallowances were recorded
in December 1993 and are reflected
in Regulatory Disallowances and Adjustments in the Consolidated Statement of
Income (Loss) for the year ended December 31, 1993.
In connection with the 1994 Rate Order, on August 26, 1993, the ACC
authorized the Company to collect the sum of $2.1 million through a temporary
fuel surcharge of .96 mills per kWh beginning September 1, 1993 until further
order of the ACC. The Company had requested a temporary rate surcharge to
recover $4 million of previously authorized but uncollected deferred fuel
expenses. The Company wrote-off $1.9 million of unrecovered deferred fuel
costs in 1993.
NOTE 3. 1992 CONSUMMATION OF THE FINANCIAL RESTRUCTURING
- ---------------------------------------------------------
On December 15, 1992, the Company consummated the transactions required
to finalize its financial restructuring plan, including the comprehensive
restructuring of obligations to certain of its creditors, lease participants,
Century and the Springerville Unit 1 lease participants and the
reclassification of all outstanding Preferred Stock into Common Stock.
Approximately 135 million shares of Common Stock were issued in the Financial
Restructuring, increasing the number of common shares outstanding to
approximately 160 million. In addition, warrants to purchase an additional
12 million shares of Common Stock at an exercise price of $3.20 per share
were issued in the Financial Restructuring. The issuance of Common Stock and
Warrants is further discussed below. In accordance with FAS 15 such stock
(other than the 55 million shares of Common Stock into which the Preferred
Stock was reclassified) was recorded at fair value as determined by the
Company on or about the date of issuance. In the accompanying financial
statements, the Common Stock issued pursuant to the Financial Restructuring
was recorded based on a fair value of $2.33 per share, which was the average
of the high and low trading price reported by the Dow Jones Stock Quote
Reporter Service during the period December 16, 1992 through December 31,
1992, the period immediately following the Closing. The Warrants were valued
for purposes of these financial statements at an estimated value of $0.82 per
share, calculated using an option pricing model and the $2.33 estimated fair
value per share of Common Stock. Losses and deferred gains related to the
issuance of the Common Stock and Warrants in the Financial Restructuring
described in the succeeding paragraphs were determined using these values for
such Common Stock and Warrants. Such values are not intended to be
indicative of current or future trading values for either the Common Stock or
the Warrants.
BANKS
The Company provided the banks approximately 32 million shares of Common
Stock, a first mortgage lien on Springerville Unit 2, $50 million of bonds
issued under a second mortgage as collateral, and $20.8 million in first
mortgage bonds as collateral and became subject to certain restrictive
financial and operating covenants. In exchange, the Company received the
waiver of $96 million in accrued interest payments, more favorable credit
terms, extensions of LOCs and related agreements, the restructuring of
several prior debt agreements into the Term Loan, a new $20 million LOC and a
new $50 million working capital revolving credit facility. The restructuring
of these Bank obligations gave rise to a deferred gain of $21 million, which
is being amortized as a reduction of interest expense over an eight-year
period, the weighted average life of the restructured credit arrangements.
These restructured bank credit arrangements also increased Common Stock
Equity $75 million. See the Consolidated Statements of Changes in
Stockholders' Equity (Deficit).
SPRINGERVILLE UNIT 1
The Company provided the participants in the Springerville Unit 1 Leases
approximately 48 million shares of Common Stock and Warrants to purchase
12,054,278 shares of Common Stock at an exercise price of $3.20 per share.
The Warrants were exercisable at the Closing of the Financial Restructuring
and expire in 2002. In addition, the Company assumed Century's former
obligations under the Springerville Unit 1 Leases and released Century from
its obligations relating to the 1981 Apache A Bonds. Amendments were also
made to the Interconnection Agreement which the Company has with Century. In
exchange, the Company received Century's leasehold interests in Springerville
Unit 1, Century's investment in plant and inventories at Springerville Unit 1
and the Restated Century Purchase Contract was terminated. The Company also
received the waiver of demand charge payments due under the Restated Century
Purchase Contract equivalent to $57 million, the release from certain tax
indemnification liabilities related to Springerville Unit 1, and the
dismissal with prejudice of certain actions which had been filed against the
Company by some of the Springerville Unit 1 owner participants.
The restructuring of these obligations gave rise to approximately $31
million of the Loss on Financial Restructuring appearing in the Consolidated
Statement of Income (Loss) for the year ended December 31, 1992. These
transactions also increased Common Stock Equity by $122 million. See the
Consolidated Statements of Changes in Stockholders' Equity (Deficit). Also,
see Note 1 regarding the loss of approximately $7 million, which was recorded
as a component of the Loss on Financial Restructuring in the Consolidated
Statement of Income (Loss) for the year ended December 31, 1992, as a result of
the assumption of the Springerville Unit 1 Leases.
CAPITAL LEASES
The terms of the Irvington Lease, the Valencia Leases, the Springerville
Common Facilities Leases and the assumed Springerville Unit 1 Leases (see
Note 1) were amended to waive certain accrued payment obligations, defer
certain lease payments due in the next several years to later years, and
extend the terms of certain leases. As a result of the lease amendments, in
accordance with FAS 13, as amended by FAS 98, these leases are accounted for
as capital leases subsequent to December 15, 1992. Amendment of these leases
increased rent expense by $18 million in the Consolidated Statement of Income
(Loss) for the year ended December 31, 1992.
PREFERRED STOCK
All of the Company's outstanding Preferred Stock was reclassified into
approximately 55 million shares of newly issued Common Stock. The
reclassification was recorded at the book value of the Preferred Stock. This
increased Common Stock Equity by $90 million, decreased the Premium on
Capital Stock by $7 million and decreased Preferred Stock by $83 million.
See the Consolidated Statements of Changes in Stockholders' Equity (Deficit).
OTHER
The reversal of other reserves and accruals that were resolved by the
Closing, primarily through the dismissal of certain regulatory proceedings,
reduced the Loss on Financial Restructuring included in the Consolidated
Statement of Income (Loss) for the year ended December 31, 1992 by $11
million.
NOTE 4. INCOME TAXES
- ---------------------
In January 1993, the Company adopted Statement of Financial Accounting
Standards No. 109 (FAS 109), Accounting for Income Taxes, on a prospective
basis. The adoption of FAS 109 changed the Company's method of accounting
for income taxes from the deferred method (APB 11) to an asset and liability
approach. Previously, the Company deferred the past income tax effects of
timing differences between financial reporting and taxable income. The asset
and liability approach requires the recognition of deferred income tax
liabilities and assets for the expected future income tax consequences of
temporary differences between the carrying amounts and the tax bases of other
assets and liabilities.
The adoption of FAS 109 increased both total assets and total
liabilities of the Company by $149 million in 1993. The increase in assets
results primarily from the recording of a regulatory asset for the recovery
of income taxes from future ratepayers. See Note 1. Such regulatory asset
consists primarily of the right to recover income taxes relating to
previously flowed-through differences, both timing and permanent, which
provided rate benefits to past ratepayers. The increase in liabilities is
primarily the net increase in deferred income tax assets and deferred income
tax liabilities resulting from the adoption of FAS 109.
Deferred tax assets (liabilities) are comprised of the following:
December 31,
1995 1994 1993
----------- ----------
- Thousands of Dollars -
Gross Deferred Income Tax Liabilities:
Electric Plant - Net $(563,884) $(558,509) $(554,441)
Regulatory Asset (Income Taxes
Recoverable Through Future Rates) (54,904) (57,902) (60,615)
Deferred Springerville Unit 2 Costs (16,974) (22,206) (27,384)
Deferred Valencia Inventory Costs (21,654) (21,780) (21,628)
Deferred Lease Payments (14,791) (15,510) (16,329)
Property Taxes (10,476) (10,465) (10,340)
Deferred Fuel - (2,372)
(5,364)
Other (7,357) (6,016) (7,371)
---------- ----------
Gross Deferred Income Tax Liability (690,040) (694,760) (703,472)
---------- ----------
Gross Deferred Income Tax Assets:
Capital Lease Obligations 375,897 377,825 384,506
Tax Operating Loss Carryforwards 197,100 199,564 181,200
Springerville Unit 1 Disallowed Costs 65,491 65,597 65,959
Investment in Loans and Partnerships 12,576 7,757 34,205
Investment Tax Credit Carryforwards 26,396 28,088 28,100
MSR Option Gain Regulatory Liability 10,342 16,645 22,268
Capital Loss Carryforwards 8,572 19,078 20,700
Lease Interest Payable 17,626 17,429 17,570
Deferred Regulatory Capital Lease Expense 13,980 11,397 8,213
Financial Restructuring Costs Not Yet
Deductible for Tax Purposes 7,907 8,034 7,773
Gain on Financial Restructuring of
Long-Term Debt 5,374 6,458
7,571Alternative Minimum Tax 3,044 2,343
Other 26,789 27,166 29,492
---------- ----------
Gross Deferred Income Tax Asset 785,038 807,557771,094 787,381
Deferred Tax Assets Valuation Allowance (208,786) (244,092) (263,991)
---------- ----------
Net Deferred Income Tax Liability $(153,814) $(159,906)$(127,732) $(151,471)
========== ==========
The decrease of approximately $35 million in the gross deferred tax
assets valuation allowance in 1995 is primarily due to an increase in the
estimate of future income to be earned and the utilization of tax operating
loss carryforwards and capital loss carryforwards. This adjustment reduced
income tax expense for the current year. Previously the Company had provided
a full deferred tax assets valuation allowance against the tax operating loss
carryforwards, investment tax credit carryforwards and capital loss
carryforwards due to the uncertainty of their future use. Because the
Company's results from operations have been steadily improving and have been
positive for the last two years, the Company believes it is more likely than
not that the Company will realize at least $66.5 million of the total federal
NOL carryforwards of $508 million. Accordingly, the Company recognized a $23
million income tax benefit related to the expected utilization of $66.5
million of tax operating loss carryforwards which is included in Income Taxes
in Other Income (Deductions) in the Consolidated Statement of Income (Loss).
The decrease of approximately $20 million in the gross deferred tax
assets valuation allowance in 1994 primarily resulted from the sale of the
discontinued operation's assets (see Note 5)4) which had corresponding deferred
tax assets, which were fully reserved by the valuation allowance.
The net deferred income tax liability is included in the Consolidated
Balance Sheets in the following accounts:
December 31,
1995 1994 1993
---------- ----------
- Thousands of Dollars -
Deferred Income TaxTaxes - Current $ 12,87018,250 $ 8,927
Accumulated12,870
Deferred Income Taxes (166,684) (168,833)- Noncurrent (145,982) (164,341)
---------- ----------
Net Deferred Income Tax Liability $(153,814) $(159,906)$(127,732) $(151,471)
========== ==========
Income Tax Benefit isThe benefit for income taxes included in the Consolidated Statements of
Income (Loss) inconsists of the following accounts:following:
Years Ended December 31,
1995 1994 1993 1992
---------- ---------- ----------
- Thousands of Dollars -
Operating Expenses - Other OperationsCurrent Tax Expense
Federal $ 91 $ 91 $ 91
Other Income (Deductions) - Income Taxes 4,820 5,186 5,654(4,439)
State (683)
---------- ---------- ----------
Total IncomeCurrent Tax Expense (5,122)
---------- ---------- ----------
Deferred Tax Expense
Federal (4,429)
State (681)
---------- ---------- ----------
Total Deferred Tax Expense (5,110)
---------- ---------- ----------
Reduction in Valuation Allowance - Benefit 23,282
Investment Tax Credit Amortization 4,766 $ 4,911 $ 5,277
Other 2,620 - -
---------- ---------- ----------
Total Benefit for Federal and State
Income Taxes $ 5,74520,436 $ 4,911 $ 5,277
========== ========== ==========
The differences between income tax benefit and the amount obtained by
multiplying income (loss) before income taxes by the U.S. statutory federal
income tax rate for each of the three years in the period ended December 31,
1994, are as follows:
Years Ended December 31,
1995 1994 1993 1992
---------- ---------- ----------
- Thousands of Dollars -
Federal Income Tax (Expense) Benefit
at Statutory Rate $ (12,064) $ (5,540) $ 10,883
$ 43,797State Income Tax Expense, Net of
Federal Deduction (1,364) - -
Investment Tax Credit amortizationAmortization 4,766 4,911 5,277
5,745Reduction in Valuation Allowance - Benefit 23,282 - -
Loss for Which No Tax Benefit
is Available - - (10,883) (43,797)
Net Operating Loss Carryforwards 5,122 5,540 -
Capital Loss Carryforwards 1,045 - -
Other (351) - -
---------- ---------- ----------
Total Benefit for Federal and
State Income Taxes $ 20,436 $ 4,911 $ 5,277
$ 5,745
========== ========== ==========
On August 10, 1993, the Revenue Reconciliation Act of 1993 was signed
into law which, among other things, raised the maximum corporate U.S.
statutory federal income tax rate from 34% to 35%, retroactively effective to
January 1, 1993. The Company increased its deferred tax balances and the
corresponding deferred tax asset valuation allowance at December 31, 1993 as
a result of this rate change.
At December 31, 1994,1995, the Company had, for federal income tax purposes,
$28approximately $508 million of net operating loss carryforwards expiring in
2004 through 2009 and $148 million of alternative minimum tax loss
carryforwards expiring in 2006 through 2008. For state income tax purposes,
the Company has approximately $215 million of net operating loss
carryforwards expiring in 1996 through 1999. In addition, for federal income
tax purposes the Company has $26 million of unused ITC, the use of which will
expire during 20012002 through 2005, $2$3 million of alternative minimum tax credit
which will carry forward to future years, and $47$21 million of capital loss
carryforwards which expire during 1995 through 1999. In addition, for federal income tax purposes the
Company has approximately $494 million of net operating loss carryforwards
expiring in 2004 through 2009 and $169 million of alternative minimum tax
loss carryforwards expiring in 2005 through 2007. For state income tax
purposes, the Company has approximately $352 million of net operating loss
carryforwards expiring in 19951996 through 1999.
Due to the Company's Financial Restructuring, as described in Note 3, the Company experienced a change in
ownership under section 382 of the Internal Revenue Code in December 1991.
As a result of that change, the amount of the taxable income for any post-changepost-
change year which may be offset by pre-change lossnet operating losses will be
limited to the section 382 limitation. The section 382 limitation is based
on the value of the Company on the ownership change date. The Company
estimates an annual section 382 limit of approximately $23 million. This limitThe
total section 382 limitation may be increased to the extent of gain
recognized on sales of assets whose fair market value was greater than tax
basis at the ownership change date, the built-in-gain. The section 382
limitation may increase by built-in-gain recognized within a period of five
years after the change in ownership. TheDuring 1992 through 1995, the section
382 limitation increased by approximately $84$102 million of built-in-gain
recognized due to asset sales. Unused section 382 limitation may be carried
forward until the pre-change tax attributes expire. At December 31, 1994,1995,
the Company had pre-change federal net operating loss, ITC, capital loss and
alternative minimum tax loss carryforwards of approximately $365$351 million, $28$26
million, $31$7 million and $136$115 million, respectively.
NOTE 4. CONSOLIDATED SUBSIDIARIES
- ----------------------------------
NATIONS ENERGY CORPORATION
In 1995 the Company established Nations Energy (formerly known as
Escalante Resources Inc.) for the purpose of investing in independent power
projects in the domestic and foreign energy markets. The 1980 through 1985 Federal Income Tax Audit resulted1995 consolidated
financial statements reflect the accounts of Nations Energy, a wholly-owned
subsidiary of the Company.
In September 1995, Nations Energy and Trigen Energy Corporation formed a
limited partnership and purchased Coors Brewing Company's energy production
(utility) assets. Nations Energy has a 49% interest in a 1992
federal tax refundsuch partnership.
The partnership will provide electricity and steam for the brewery operation
in Golden, Colorado. In addition, the partnership expects to upgrade Coors'
power plant to improve fuel efficiency and increase capacity. The investment
of approximately $1$12 million and approximately $8 million
in interest. The interest income had not been previously accrued andby Nations Energy is included asin the Company's
Consolidated Balance Sheet at December 31, 1995 under Investments and Other
IncomeProperty and in the Company's Consolidated Statement of Income (Loss)Cash Flows for the
year ended December 31, 1992.
NOTE 5.1995 as Investment in Partnership.
DISCONTINUED OPERATIONS
- --------------------------------
In July 1990, the Boards of Directors of the Company's investment
subsidiaries adopted formal plans of liquidation of the investment
operations. Pursuant to such actions, investment subsidiaries' results of
operations, estimated net realizable value of net assets and cash flows have
beenwere
classified as discontinued operations in the Company's consolidated financial
statements since June 30, 1990. The Company recorded a provision
for losses on disposal of discontinued operations of $105 million in 1990 to
reduce the carrying values of the assets to their then-estimated net
realizable values. The financial results of activities from discontinued
operations subsequent to June 30, 1990 have been recorded as an adjustment tothrough December 31, 1994, the reservedate that the
liquidation was substantially complete. The Company's Consolidated Statement
of Income (Loss) for losses. Additional provisions for losses on disposal of
discontinued operations of $36 million in 1991, $44 million in 1992, and1993 includes a $4 million in 1993 wereProvision for Loss on
Disposal of Discontinued Operations made to reflect further weakening of
markets for certain subsidiary investments and increased estimates of holding-periodholding-
period costs for those assets and a $10assets.
At December 31, 1994, the Company's Consolidated Balance Sheet reflected
$9 million addition to the reserve for litigation in 1992.
The components of net assets of discontinued operations are summarized
as follows:
December 31,
1994 1993
--------- ---------
- Thousands of Dollars -
Cash and Cash Equivalents $ 14,852 $ 22,179
Investment in Citadel - 23,374
Real Estate Investments 17,127 65,119
Vehicle Contracts Receivable 17,509 17,509
Other Assets and Investments 6,859 19,403
Reserve for Loss on Disposal of
Discontinued Operations (34,494) (74,109)
--------- ---------
Total Assets 21,853 73,475
Current Liabilities (13,168) (14,995)
--------- ---------
Net Assets of Discontinued Operations $ 8,685 $ 58,480
========= =========
Loss from discontinued operations is as follows:
Years Ended December 31
1994 1993 1992
--------- --------- ---------
- Thousands of Dollars -
Investment Losses $(35,447) $(20,403) $(27,473)
Hotel Revenues 13,171 13,930 13,669
Hotel Depreciation and Other Expense (16,242) (17,129) (16,914)
Other Investment Expense (1,097) (2,289) (1,927)
--------- --------- ---------
Operating Loss (39,615) (25,891) (32,645)
Reduction in Reserve for Losses 39,615 25,891 32,645
--------- --------- ---------
Loss from Discontinued Operations $ - - $ -
========= ========= =========
Net assets of discontinued operations declined by approximately $50
million between December 31, 1993 and December 31, 1994 as a result of
dividends paid by TRI to the Company.
Gross investment losses during 1994 included losses of: $21 million on
salescomprised mainly of real
estate; $21 million onestate investments. Beginning January 1, 1995, the sale of the remaining Citadel common
stock; and $5 million on the sale of two small power projects. Offsetting
these losses were gains of: $9 million on the sale of various marketable
securities and $1 million on the sale of a vehicle contracts receivable
portfolio. The resulting net losses reduced the Reserve for Losses by an
equal amount. Also included in Investment Losses is $2 million of other
investment income.
As of December 31, 1994, Real Estate Investments consist of 1) loans
collateralized by real property and 2) land held for sale in Arizona.
Vehicle Contracts Receivable consists principally of automobile installment
sales contracts of Brookland, a financial services company. In January 1991,
the Board of Directors of Brookland elected to discontinue its business
operations. Brookland remains liable for credit obligations to outside
lenders of $12 million. These credit obligations are collateralized by
Brookland's vehicle contracts portfolio and other interests in Vehicle
Contracts Receivable.
As of December 31, 1994, the Company has substantially completed its
disposal of discontinued operations. The losses from discontinued operations
for the period June 30, 1990 through December 31, 1994 of $139 million have
been recorded as reductions in the Reserve for Losses. The gross proceeds
from the sale of assets, excluding scheduled collections on loans and notes
receivable, for the period June 30, 1990 through December 31, 1994 amounted
to $498 million. The remaining assets and
liabilities will beare accounted for as a part of continuing operations beginning January 1, 1995.and are
included in the Company's consolidated financial statements. As a result,
Short-Term Debt of $12 million on the Consolidated Balance Sheet at December
31, 1995 was previously classified as Net Assets of Discontinued Operations.
NOTE 6.5. LONG AND SHORT-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
- ---------------------------------------------------------------
LONG-TERM-DEBT
First Mortgage Bonds and Installment Sale Agreement
First Mortgage BondLONG-TERM DEBT
During 1995 the Company reduced its long-term debt as a result of $17
million of bond and Installment Sale Agreement maturities, and cash
sinking fund requirements for the next five years include $17 million in 1995,
$12 million in 1996, $2 million in 1997, $3 million in 1998, anda $19 million
in
1999. In addition, certainpermanent repayment of the Term Loan and payments totaling $143 million on
the Renewable Term Loan. Pursuant to the terms of the Renewable Term Loan,
$133 million of the payments on the Renewable Term Loan may be reborrowed, as
needed by the Company.
First Mortgage Bonds have additional annual sinking
fund requirements which total approximately $3 million for each of the next
five years. These sinking fund requirements can be and have been satisfied to
date primarily by pledges of additional property.
The Company's utility plant, with the exception of Springerville Unit 2,
is subject to the lien of the General First Mortgage and the General Second
Mortgage.
Restructured Arrangements
Approximately $900 millionMRA
At December 31, 1995, the obligations covered by the provisions of the
Company's previous bank obligations
including bank lines, LOCs and related reimbursement agreements (excludingMRA were the reimbursement agreement relating to the 1981 Apache B Bonds) were
combined and restructured into a master restructuring agreement between the
Company and the Banks (the MRA) on December 15, 1992. The MRA provided for a
$243.3$164 million Renewable Term Loan Replacementcommitment (of which $31
million was borrowed), LOCs supporting $674 million of IDBs, and athe $50
million Revolving Credit.Credit commitment (of which no amounts are borrowed).
Obligations under the MRA are secured by a first mortgage lien on and
security interest in Springerville Unit 2, and, under certain conditions, are
secured by $50 million in principal amount of collateral bonds issued under
the General Second Mortgage, junior to the General First Mortgage securing
the Company's First Mortgage Bonds.
Additionally, the MRA provided for an additional $20 million LOC which
was issued in March 1993 to the indenture trustee for industrial development
revenue bonds originally issued in 1990. The reimbursement agreement related
to that LOC, which is secured by first mortgage bonds, allowed the debt
proceeds to be released to the Company which reimbursed the Company for costs
of qualifying facilities. See Letters of Credit below.
In March 1995, the Company and its banks completed an amendment to the
MRA which eased certain debt prepayment restrictions and modified theallowed reborrowing
of certain Renewable Term Loan to allow reborrowing of amounts which will have been previously prepaid
(Renewable Term Loan)prepayments (see Renewable Term Loan below).
The amendment will allow the
Company to better manage its cash position and reduce capital costs while
maintaining liquidity. Prior to the amendment the Company was not permitted
to prepay non-MRA debt except to the extent that certain cash amounts, as
defined in the MRA, were generated. The amendment, now in effect, allows the Company to optionally prepay non-MRA debt provided
certain conditions are met. Such conditions include that $1 of principal
outstanding under the Renewable Term Loan is permanently prepaid and the
commitment therefore terminated for every $2 used to permanently prepay other
debt such as First Mortgage Bonds.
To comply with provisions of the MRA prior to the March 7, 1995
amendment, the Company prepaid $17.25 million of First Mortgage Bonds during
1994. During 1993 the Company, under a bank waiver to certain restrictions
of the MRA, voluntarily prepaid $49 million of First Mortgage Bonds and $19
million of the Term Loan.
Additional details regarding the components and covenants of the MRA are
described below.
Letters of Credit
At December 31, 1994 there were $774 million principal amount of
variable rate tax-exempt IDBs outstanding. Payment of principal and interest
on these bonds is secured by LOCs. The LOCs expire at various dates during
the period December 31, 1999 through December 31, 2002. However, all the
LOCs could expire by December 31, 2000, including an expiration as early as
August 1997, if the Company's senior long-term debt is rated investment grade
on certain dates or during certain periods subsequent to December 31, 1996.
The reimbursement agreement related to the 1981 Apache B Bonds is secured by
First Mortgage Bonds. The weighted average commitment fee on the Replacement
LOCs is approximately 0.53% through 1997 and increases to 0.82% in 1998,
1.07% in 1999 and thereafter.
Term Loan
The Term Loan, on March 7, 1995, was amended and renamed the Renewable
Term Loan. As a condition to the amendment becoming effective the Company
permanently prepaid $19.34 million of the Term Loan reducing the outstanding
balance from $193.4 million to approximately $174 million at March 7, 1995.
Thus, the initial commitment and outstanding balance of the Renewable Term
Loan was approximately $174 million.
The Renewable Term Loan commitment amount at March 31, 1997 will be
reduced as follows: 20% in 1997, 40% in 1998 and 40% in 1999. Any
outstanding Renewable Term Loan balance in excess of the commitment will be
payable immediately. The Renewable Term Loan bears interest at a variable
rate based on an adjusted eurodollar rate plus 0.5% and the commitment fee is
0.5% of the unused portion. The adjusted eurodollar rate was approximately
4.92% per annum and 4.03% per annum for the years ended December 31, 1994 and
1993, respectively, and was approximately 3.66% for the one month period
ended December 31, 1992. During 1993 and 1992 the Company prepaid $19
million and $31 million, respectively, of the outstanding balance.
Additional Restrictive Covenants
In addition to the prepayment provisions, described above, the MRA contains a number of
restrictive covenants including, but not limited to, covenants limiting, with
certain exceptions, (i) the incurrence of additional indebtedness, including
lease obligations, or the prepayment of existing indebtedness, or the
guarantee of any such indebtedness, (ii) the incurrence of liens, (iii) the
sale of assets or the merger with or into any other entity, (iv) the
declaration or payment of dividends on Common Stock or any other class of
capital stock, (v) the making of capital expenditures beyond those
contemplated in the Company's 1992 ten-year capital budget, and (vi) the
Company's ability to enter into sale-leaseback arrangements, operating lease
arrangements and coal and railroad arrangements. All of these restrictive
covenants described above, other than (i), (iv) and (vi), will be in effect
until at least December 1997. The covenants described in (i), (iv) and (vi)
will cease to be binding on the Company when both the Renewable Term Loan and
the Revolving Credit are paid in full and commitments thereunder terminate,
and the Company's senior long-term debt is rated at least
investment grade. In
addition, the Company is required pursuant to the MRA to maintain an interest
coverage ratio of (a) operating cash flows plus interest paid to (b) interest
paid, through the year 2003, ranging from 1.21.40 to 1 in 19941995 and gradually
increasing to 2 to 1 in 2000 continuing through the year 2003. For the year
ended December 31, 1994,1995, the Company's MRA interest coverage ratio was 2.982.52
to 1.
With respectDividends - Restrictive Covenants
The Company's ability to dividends,pay a dividend is restricted by certain
covenants in the MRA
incorporates, until the Renewable Term Loan and the Revolving Credit are paid
in full and commitments thereunder terminate, a restrictive covenant similar
to that currently in theagreements of certain General First Mortgage which limitsBonds ($184
million at December 31, 1995). These covenants limit the Company's ability
to pay dividends on Common Stock until it has positive retained earnings
(through future earnings or otherwise) rather than an accumulated deficit
(such accumulated deficit was $681$626 million at December 31, 1994).
For1995) and the
foreseeable future,Company's cash flow coverage ratio is greater or equal to a ratio of 2 to 1.
As of December 31, 1995, the Company's cash flow coverage ratio was slightly
above 2 to 1.
The MRA contains, until the Renewable Term Loan and the Revolving Credit
are paid in full and commitments thereunder terminate and the Company's
senior long-term debt is rated investment grade, a similar dividend
restriction based on retained earnings. The Company's senior long-term debt
is currently rated below investment grade.
Letters of Credit
At December 31, 1995 there were $774 million principal amount of
variable rate tax-exempt IDBs outstanding. Payment of principal and interest
on these bonds is secured by LOCs. The LOCs expire at various dates during
the period December 31, 1999 through December 31, 2002. However, all the
LOCs could expire by December 31, 2000, including an expiration as early as
August 1997, if the Company's senior long-term debt is rated investment grade
on certain dates or during certain periods subsequent to December 31, 1996.
The reimbursement agreement related to the 1981 Apache B Bonds is secured by
First Mortgage Bonds. The weighted average commitment fee on the LOCs is
approximately 0.53% through 1997 and increases to 0.82% in 1998, 1.07% in
1999 and thereafter.
Renewable Term Loan
The Term Loan, on March 7, 1995, was amended and renamed the Renewable
Term Loan. As a condition to the amendment becoming effective the Company
does not anticipate being ablepermanently prepaid $19 million of the Term Loan reducing the outstanding
balance from $193 million to satisfyapproximately $174 million at March 7, 1995.
Thus, the testsinitial commitment and outstanding balance of this restrictive covenant,the Renewable Term
Loan was approximately $174 million. In May 1995, following the Company's
purchase of approximately $18 million of debt securities, the Renewable Term
Loan commitment was decreased by $10 million to approximately $164 million to
meet the prepayment provisions of the MRA.
The Renewable Term Loan commitment amount at March 31, 1997 will be
reduced as follows: 20% in 1997, 40% in 1998 and therefore, does not
anticipate being permitted to pay cash dividends40% in 1999. Any
outstanding Renewable Term Loan balance in excess of the commitment will be
payable immediately. The Renewable Term Loan bears interest at a variable
rate based on its Common Stock.an adjusted eurodollar rate plus 0.5% and the commitment fee is
0.5% of the unused portion. Such rates averaged approximately 6.50%, 4.92%
and 4.03% for the years ended December 31, 1995, 1994 and 1993, respectively.
Fair Value of Long-Term Debt
1995 1994 1993
Carrying Fair Carrying Fair
Value Value Value Value
-------- ----- -------- -----
- Thousands of Dollars -
First Mortgage Bonds:
Corporate $ 253,750 $ 267,902 $ 269,750 $ 256,009 $ 287,000 $ 275,687
IDBs
1981 Apache B Bonds 100,000 100,000 100,000 100,000
Pollution Control Financing
Bonds 112,200 102,944112,276 112,200 106,030102,944
1990 Pima A Bonds 20,000 20,000 20,000 20,000
Loan Agreements:
Installment Sale Agreement 48,985 48,679 50,000 46,131 50,955 47,646
IDBs 653,600 653,600 653,600 653,600
Renewable Term Loan 193,400 193,40031,000 31,000 - -
Term Loan - - 193,400 193,400
Promissory Note - - 152 152 1,400 1,475
---------- ---------- ---------- ----------
$1,219,535 $1,233,457 $1,399,102 $1,372,236 $1,418,555 $1,397,838
========== ========== ========== ==========
The principal amount of variable rate debt outstanding at December 31,
19941995 and 19931994 of the 1981 Apache B Bonds, the 1990 Pima A Bonds, the Loan
Agreements-IDBs, and the Renewable Term Loan (Term Loan at December 31, 1994)
are considered reasonable estimates of their fair value as these are variable
interest rate liabilities. The fair value of the Company's fixed rate
obligations including the Corporate First Mortgage Bonds, the Pollution
Control Financing Bonds, the Installment Sale Agreement and Promissory Note
was determined by calculating the present value of the cash flows of each
fixed rate obligation. The discount rate used for each calculation was a
rate consistent with market yields generally available as of December 1995
for 1995 amounts and December 1994 for 1994 amounts and December 1993 for 1993 amounts,
obtained from the Moody's Bond Survey report, for bonds with similar
characteristics with respect to: credit rating, time-to-maturity, and the
tax status of the bond coupon for Federal income tax purposes. The use of
different market assumptions and/or estimation methodologies may yield
different estimated fair value amounts.
SHORT-TERM DEBT
Revolving CreditAuthorization To Issue Tax-Exempt Bonds
In January 1996, the Company obtained a tax-exempt volume cap allocation
from the state of Arizona. The $50Company's allocation is for approximately
$16.7 million Revolving Credit, provided as partto be issued by the Pollution Control Corporation of the MRA, has a
termination and maturity datecounty
of December 31, 1999. No amounts have been
borrowed byCoconino in Arizona, for the benefit of the Company. The Company expects
to issue such bonds in early April 1996. If the Company under this facility. Revolving Credit borrowingswere to fail to
issue the bonds by such time, the Company would bear interest at variable rates based upon,lose its volume cap
allocation. The proceeds will be used to reimburse the Company for expenses
relating to pollution control facilities at the option ofCompany's Navajo generating
station. Also, in order for the Company either (i) prime rate or (ii) an adjusted eurodollar rate plus a
margin of 0.75% in 1994 and 1995 which gradually increases to 2% by 1998 and
thereafter.issue such bonds, the Company
will need approval from the ACC. The Company is required to repayfiled a financing application
with the Revolving Credit in full
for at least 30 consecutive days in each twelve-month period prior to
November 30 of each year. The annual commitment fee for the Revolving Credit
equals 0.5% of the unused portion.
Discontinued Operations
Vehicle contracts receivable and other interests in vehicle contracts
receivable held by Brookland are financed through a warehouse line of credit
and a loan which totaled approximately $12 million at December 31, 1994 and
1993. The weighted average interest rate applicable to the warehouse line of
credit at December 31, 1994 and 1993 was 17%.ACC on February 14, 1996.
CAPITAL LEASE OBLIGATIONS
A schedule by years of future minimum lease payments under capital
leases together with the present value of the net minimum lease payments
(Capital Lease Obligations) as of December 31, 1994 follows:
Years ending December 31, - Thousands of Dollars -
1995.......................... $ 99,262
1996.......................... 119,155
1997.......................... 95,019
1998.......................... 97,200
1999.......................... 103,277
Thereafter.................... 1,913,905
------------
2,427,818
Imputed Interest.............. (1,492,280)
------------
Capital Lease Obligations..... $ 935,538
============
The Irvington Lease has an initial term to January 2011 and provides for
renewal periods of two or more years through 2020. The Springerville Common
Facilities Leases have an initial term of 2017 for one owner participant and
2021 for the other two owner participants, subject to optional renewal
periods of two or more years through 2025. The Springerville Unit 1 Leases
have an initial term to January 2015 and provide for renewal periods of three
or more years through 2030. The Valencia Leases have an initial term to
April 2015 and provide for an initial renewal period of six years, then
additional renewal periods of five or more years through 2035.
MATURITIES AND SINKING FUND REQUIREMENTS
A schedule by years of the aggregate amount of maturities and sinking
fund requirements for all long-term borrowings as of December 31, 1995
follows:
Expiring Scheduled
LOCs Long-Term
Supporting Debt Capital Lease
IDBs Retirements Obligations Total
-------- -------- ------------ ----------
Years ending
December 31, - Thousands of Dollars -
1996 $ 12,075 $ 119,155 $ 131,230
1997 8,335 95,019 103,354
1998 15,605 97,200 112,805
1999 $100,000 31,900 120,815 252,715
2000 364,900 83,325 164,121 612,346
-------- -------- ----------- -----------
Total 1996 - 2000 464,900 151,240 596,310 1,212,450
Thereafter 308,700 294,695 1,732,246 2,335,641
Imputed Interest - - (1,397,209) (1,397,209)
-------- -------- ----------- -----------
Total $773,600 $445,935 $ 931,347 $2,150,882
======== ======== =========== ===========
The Company expects to refinance the LOCs supporting IDBs at expiration.
The above schedule does not include sinking fund requirements for certain
First Mortgage Bonds of approximately $1.6 million for each of the next five
years. The Company expects to satisfy these sinking fund requirements with
pledges of additional property of approximately $3 million each year.
Maturities under capital lease obligations for 1999 and 2000 include $25
million and $45 million, respectively, of maturing lease debt that the
Company expects to refinance so that the debt payments are extended over the
remaining lease term. The capital lease obligations were recorded assuming
completion of such refinancing.
SHORT-TERM DEBT
Revolving Credit
The $50 million Revolving Credit, which is part of the MRA, has a
termination and maturity date of December 31, 1999. No amounts have been
borrowed by the Company under this facility. Revolving Credit borrowings
would bear interest at variable rates based upon, at the option of the
Company, either (i) prime rate or (ii) an adjusted eurodollar rate plus a
margin of 1% in 1996 which gradually increases to 2% by 1998 and thereafter.
The Company is required to repay the Revolving Credit in full for at least 30
consecutive days in each twelve-month period prior to November 30 of each
year. The annual commitment fee for the Revolving Credit equals 0.5% of the
unused portion.
Investment Subsidiaries
Vehicle contracts receivable and other interests in vehicle contracts
receivable held by Brookland are financed through a warehouse line of credit
and a loan which totaled approximately $12 million at December 31, 1995 and
1994. The weighted average interest rate applicable to the warehouse line of
credit at December 31, 1995 and 1994 was 17%.
NOTE 7.6. COMMITMENTS AND CONTINGENCIES
- -------------------------------------
UTILITY CONTRACTUAL MATTERS
Coal and Transportation Contracts On October 14,- Reversal of Accrued Liabilities
In 1991 amendments to the contractcontracts with the Springerville coal
supplier, the Irvington coal supplier and the Springerville rail
transportation suppliers were entered into and became effective, which, among other things,
reduced the price of coal shipments at Springerville. The amended
contract containscontained provisions which protectprotected the claims of the Springerville
coal suppliersuppliers under the
original agreementagreements in the event that the Company doesdid not perform its obligations
under the terms of the amended agreement at any
time prior to August 23, 1995. If such a failure to perform occurs,agreements during the subsequent four year
period. In 1995, the Company would be responsible for approximately $7 million per year in
additional payments to the Springerville coal supplier. Also, at December
31, 1994, a $3 million accrued liability remained on the Company's
Consolidated Balance Sheet which will be forgiven ifsatisfied all conditions are met
during the four years subsequent to the amendment of the Springerville coal
agreement.conditions of the amended
contracts and, consequently, reversed $12 million of accrued liabilities.
The reversal of the accrued liabilities reduced Fuel and Purchased Power
expense by $12 million in the third quarter of 1995.
Fuel Purchase Commitments
The Company has contractedcontracts to purchase coal for use at Springerville and
Irvington. The Springerville coal contract is for the remaining lives of the
units with P&Ma bilateral option to supplyrenegotiate the contract price and
escalation procedures in 2009 and every five years thereafter. The Irvington
contract termination date is the earlier of 2015 or the remaining life of the
coal-fired unit. Both contracts have various adjustment clauses that will
affect the future cost of coal to Irvington.
Originally, all units at Irvington were scheduled to be converted and coal
supplies were contracted for those units.delivered. The original contract required
annual minimum quantities of 650,000 tons. However,contracts, in the conversion of Units
1, 2 and 3 at Irvington was canceled. The then-existing P&M contract
contained minimum take-or-pay provisions which requiredaggregate,
require the Company to pay
one-half of the base price of coal for any contract quantities not scheduled
and delivered. On November 5, 1991, amendments to the contract with P&M were
entered into and became effective, which, among other things, substantially
reduced the minimum annual coal quantities to levels which the Company
estimates can be utilized by Irvington Unit 4 alone (Irvington Unit 4 is
expected to burn approximately 225,000take 2.1 million tons of coal per year), amended
contract price adjustment procedures, extended the expiration date of the
agreement from 2002 to 2015 and provided for an exchange of the proceeds of
the sale of undeveloped land for the $8 million 1990 penalty payment which
was withheld during the period of the Payment Moratorium (the $8 million 1990
penalty payment remains an accrued liability on the Company's Consolidated
Balance Sheet at December 31, 1994). Additionally, the penalty provisions of
the contract were amended. P&M maintains their claim under the prior contract
if the Company does not perform its obligations under the terms of the amended
agreement at any time prior to November 4, 1995. If the Company fails to
perform, the Company would be required, pursuant to the prior contract, to
pay for approximately 5.1 million tons, that would not be delivered to the
Company, at one-half the base price of coal through 2002,year at an estimated
aggregateannual cost of $98 million.
Amendments$70 million from 1996 to transportation agreements have also been executed,
effective October 18, 1991, with the Springerville and Irvington rail
transportation suppliers which, among other things, reduced the price for
coal shipments and limited annual changes in the contract price. As
discussed above with respect to the coal contracts, the Springerville amended
rail transportation agreement includes provisions which protect the
supplier's claims under the original contract in the event the Company does
not perform its obligations under the terms of the amended agreement at any
time during the four years subsequent to the amendment. If such a failure to
perform occurs, the Company would be responsible for approximately $3 million
per year to the Springerville transportation supplier at current contract
prices. At December 31, 1994, a $3 million accrued liability remained on the
Company's Consolidated Balance Sheet which will be forgiven, if all conditions
are met during the four years subsequent to amendment of the Springerville
agreement.2009.
The Company's contracts to purchase coal for use at the joint projects
in which the Company participates expire at various dates from 2005 to 2017
and, in the aggregate, require the Company to take 1.5 million tons of coal
per year at an estimated annual cost of $16 million.
Fuel Purchase Commitments$45 million from 1996 to 2005.
The Company's contracts to purchase coal for use at Springerville,
Irvington and each of the joint projects in which the Company participates
contain various provisions calling for the payment of a take-or-pay amount,
if certain minimum quantities of coal are not scheduled and delivered. The
Company's present fuel requirements are generally in excess of the stated
take-or-pay minimum amounts; however, from time to time, the Company has
purchased spot market alternative fuels or switched fuel burn from one
generating station to another in order to achieve lower overall fuel costs,
while incurring take-or-pay minimum charges. As a result, the Company
incurred take-or-pay minimum charges of approximately $1 million during 1993
and 1992.1993.
The Company incurred no take-or-pay charges in 1995 or 1994.
COMMITMENTS - ENVIRONMENTAL REGULATION
In the fall of 1990, Congress adopted certain Federal Clean Air Act
Amendments (CAAA) with respect to reductions in sulfur dioxide and nitrogen
oxide emissions which will affect the Company's operation. The nitrogen
oxide reductions will be based upon EPA regulations expected to be finalized in 1995 for
certain boilers and expected to be finalized by 1997 for all remaining
boilers. In addition, the rules expected to be promulgated in 1995 may be revised in 1997.
The required reductions of sulfur dioxide emissions will be implemented in
two phases which will beare effective in 1995 and 2000, respectively.
The Company is not affected by the requirements for sulfur dioxide
emissions and nitrogen oxide reductions which gowent into effect in 1995 (Phase
I), but is subject to the requirements that go into effect January 1, 2000
(Phase II). In Phase II, the maximum sulfur dioxide emission rates are set
at 1.2 pounds per million BTU. Because of the Company's general use of low-
sulfur coal and installed scrubbers at certain units, the Company's coal-
fired generating stations already meet the sulfur dioxide emission rate
requirements for Phase II. Additionally, further reductions are to be met
through a proposed market-based system. Affected Company generating units
will be allocated allowancesEmission Allowances based on required emission reductions
and past use. An allowance permits emission of one ton of sulfur dioxide and may be
sold. Generating station units must hold allowancesEmission Allowances equal to
their level of emissions or face penalties and a requirement to offset excess
tons in future years. On March 23,In 1993, the EPA published the final sulfur dioxide
allowance allocationsallocated Emission Allowances for all
Phase I and Phase II affected utility units,
including the allowances that will be allocated to all Company units. An analysis of the sulfur dioxide allowancesEmission
Allowances that were allocated to the Company shows that the Company would
have sufficient allowances to permit normal plant operation and be in
compliance with the sulfur dioxide regulations once the Phase II requirements
become effective. However, until all the rulemaking regulation processes for
implementing the CAAA are completed, the Company is unable to predict the
specific impacts of all such amendments.
The CAAA also require multi-year studies of visibility impairment in
specified areas and studies of hazardous air pollutants which relate to the
necessity of future regulations of electric utility generating units. Since
these activities involve the gathering of information not currently
available, the Company cannot predict the outcome of these studies.
As a result of recent and possible future changes in federal and state
environmental laws, regulations and permit requirements, the Company may
incur additional costs for the purchase or upgrading of pollution control
emission monitoring equipment on existing electric generating facilities and
may experience a reduction in operating efficiency. There may be a need for
variances from certain environmental standards and operating permit
conditions until required equipment and processes for control, handling and
disposal of emissions are operational and reliable. Failure to comply with
any EPA or state compliance requirements may result in substantial penalties
or fines which are provided for by law and which in some cases are mandatory.
In 1991, the EPA adopted a rule for the reduction of Navajo's sulfur
dioxide emissions on an annual averaging basis by 90% to address visibility
impairment at Grand Canyon National Park. The Company estimates that its
share of the required capital expenditures remaining as of December 31, 19941995
relating to the rule's implementation will be approximately $44$34 million,
including AFDC, through 1999.
CONTINGENCIES
SDGE/FERC Proceedings
San Diego Gas & Electric v. Tucson Electric Power Company
On February 11, 1993, SDGE filed a complaint and motion for summary
disposition against the Company and Century before the FERC (San Diego Gas &
Electric Company v. Tucson Electric Power Company and Century Power
Corporation, Docket No. EL93-13-000)EL93-19-001). The complaint allegesalleged that the Company
and Century overbilled SDGE during Phases 3 through 5 of the Ten Year Power
Sale Agreement (Ten Year Agreement) and requestsrequested that the FERC order refunds
by the Company of an aggregate amount of approximately $14.5 million, plus
interest. On April 23, 1993,The Company and SDGE have agreed to resolve this dispute by
waiving all claims under the Company filed an answer denying the
allegationsTen Year Agreement and dismissing all
proceedings relating thereto. An Offer of the complaint. The matter is pending.Settlement was approved by FERC on
January 18, 1996.
Alamito Company, Docket No. ER79-97-009
On September 27, 1993, SDGE filed a motion for decision by the FERC in
Alamito Company, Docket No. ER79-97-009. This proceeding involved the proper
capital structure and rate of return for rates under which Century Power
Corporation (formerly Alamito Company) sold Company system power to SDGE
during Phase 5 of the Ten Year Agreement, from June 1, 1987 through May 31,
1989. An initial decision of an administrative law judge in January 1986,
found the Company's capital structure was inflated and its return on equity
excessive. SDGE claimed that the Company would owe Century on SDGE's behalf up to
approximately $12 million, plus interest.
On October 8, 1993, the
Company filed an answer opposing SDGE's motion. It was the Company's
position that the FERC's order of July 19, 1991 approving a settlement
between SDGE and Century in Docket No. ER79-97-009, as well as the Company's
and Century's mutual release ofmoved to dismiss all claims against each other as part of
their Financial Restructuring, bars SDGE's claim. On December 23, 1993, the
FERC issued an order confirming that the July 19, 1991 order disposed of this
case, and denied SDGE's September 27, 1993 motion. On January 21, 1994, SDGE
requested rehearing of the FERC's order. That request is pending.
Based on consultations with counsel, the Company believes that the
resolution ofappeals relating to the SDGE/FERC Proceedings
described herein should not have a
material adverse effect, if any, on the Company's Consolidated Financial
Statements.February 23, 1996.
Tax Assessments
During the first quarter of 1993, the IRS completed an examination of
the Company's consolidated federal income tax returns for tax years 1986
through 1990. The Company has reached a tentative settlement with the IRS,
pending final approval, which would result in the Company paying additional
taxes and interest, of approximately $5.4 million, as of December 31, 1994.
The Arizona Department of Revenue has issued transaction privilege tax
assessments to the Company for the period November 1985 through May 1993
alleging that Valencia is liable for sales tax on gross income received from
coal sales, transportation, and coal-handling services to the Company during
such period. The Company protested the assessments. On March 11, 1994, the
Arizona Tax Court issued a Minute Entry granting Summary Judgment to the
Arizona Department of Revenue and upholding the validity of the assessment
issued for the period November 1985 through March 1990. The Company appealed
this decision to the Court of Appeals. Generally, Arizona law requires
payment of the assessment due prior to the appellate process. To date the
Company has paid, under protest, a total of $23 million ($14.6 million in
1995, $2.8 million in 1994 and $5.6 million in 1993) of the disputed sales
tax assessments, subject to refund in the event the Company prevails.
Also, the Arizona Department of Revenue has issued transaction privilege
tax assessments to the lessors from whom the Company leases certain property
allegingproperty.
The assessments allege sales tax liability on a component of rents paid by
the Company on the Springerville Unit 1 Leases, Springerville Common
Facilities Leases, Irvington Lease and Valencia Leases. Assessments cover
the period August 1, 1988 to September 30, 1993. Under the terms of the
lease agreements, if the Arizona Department of Revenue prevails the Company
must indemnifyreimburse the lessors for taxes paid.paid by them pursuant to indemnification
provisions.
In the opinion of management, the Company has recorded, through the
Consolidated StatementStatements of Income (Loss) in current and prior years, a
liability for the amount of federal and state taxes and interest thereon for
which the Company feels incurrence is probable of incurrence as of December 31, 1994.1995. In
the event that all or most of the Arizona Department of Revenue's proposed
assessments are sustained, additional liabilities would result. Based on the
current status of the legal proceedings, the Company believes that the
ultimate resolution of such disputes will occur over a period of one and a
half to four
years. Although it is reasonably possible that the ultimate resolution of
such matters could result in a loss of up to approximately $25$27 million in
excess of amounts accrued, management and outside tax counsel believe that
the Company has meritorious defenses to mitigate or eliminate the assessed
amounts. Based on consultations with counsel, the Company believes that the
resolution of the tax matters described herein should not have a material
adverse effect on the Company's Consolidated Financial Statements.
NOTE 8. SCECorp/SCE LITIGATION SETTLEMENT
- ------------------------------------------
On September 5, 1990, the Company commenced an action against SCECorp
and SCE in the Superior Court of California for the County of San Diego. On
September 15, 1992, the action was settled. Under the terms of the
settlement agreement, SCECorp paid the Company $25 million in settlement of
claims of interference with the proposed merger between the Company and SDGE,
plus $15 million to cover the Company's litigation and related expenses.
Pursuant to the terms of the settlement agreement, the lawsuit was dismissed
with prejudice on September 28, 1992. In the Consolidated Statement of
Income (Loss) for the year ended December 31, 1992, the proceeds from the
settlement agreement are included as a reduction of Other Operations to the
extent of litigation expenses incurred by the Company in pursuit of its claim
(approximately $12 million as of December 31, 1992) and the remainder of the
proceeds are included as Litigation Settlement.
The Company and SCE also agreed to a ten-year power exchange agreement
beginning in 1995. Under the agreement, beginning in 1995 SCE will provide
firm system capacity of 110 MW to the Company during summer months, for which
the Company will pay an annual capacity charge of approximately $1 million
annually increasing to a maximum of approximately $2 million annually. The
Company will be entitled to schedule firm energy deliveries from SCE during
the summer of up to 36,300 MWh per month, and will be obligated to return to
SCE on an interruptible basis the same amount of energy the following winter
season.
NOTE 9.7. JOINTLY OWNED FACILITIES
- ---------------------------------
At December 31, 1994,1995, the Company's interests in jointly owned
generating and transmission facilities were as follows:
Percent Plant Construction
Owned By in Work in Accumulated
Company Service Progress Depreciation
----------- -------- ------------ ------------
- Thousands of Dollars -
San Juan Units 1 and 2 50.0 $294,156$294,456 $ 1,712 $190,7214,492 $204,250
Navajo Station 7.5 77,963 6,524 36,81978,016 16,082 39,165
Four Corners Units 4 and 5 7.0 75,725 1,520 47,56577,078 264 51,535
Transmission Facilities 7.5 to 95.0 204,930 1,166 90,159204,213 1,853 95,182
-------- ------- --------
Total $652,774 $10,922 $365,264$653,763 $22,691 $390,132
======== ======= ========
The Company has financed or provided funds for the above facilities and
its share of operating expenses is included in the Consolidated Statements of
Income (Loss).
NOTE 10.8. EMPLOYEE BENEFITS PLANS
- -----------------------------------------------------------------
PENSION PLANS
The Company has noncontributory pension plans for all regular employees.
Benefits are based on years of service and the employee's average
compensation. The Company makes annual contributions to the plans that are
not greater than the maximum tax deductible contribution and not less than
the minimum funding requirement by the Employee Retirement Income Security
Act of 1974. Contributions are intended to provide for both current and
future accrued benefits.
The following table sets forth the plans' funded status and amount
recognized in the Company's Consolidated Financial Statements at December 31,
19941995 and 1993.1994. The actuarial present value of the benefit obligationsobligation and
reconciliation of funding status at October 1, were as follows:
1995 1994 1993
-------- --------
- Thousands of Dollars -
Accumulated Benefit ObligationsObligation
Vested $75,014 $46,679
$51,955
Non-Vested 5,447 6,318 6,497
-------- --------
Total $80,461 $52,997 $58,452
======== ========
Plan Assets at Fair Value, Principally Equity and
Fixed Income Securities $93,317 $77,021 $78,478
Projected Benefit ObligationsObligation (91,414) (67,393) (78,997)
-------- --------
Plan Assets in Excess of (Less Than) Projected Benefit ObligationsObligation 1,903 9,628 (519)
Unrecognized Net (Gain) LossGain from Past Experience (8,136) (10,549) 568
Prior Service Cost Not Yet Recognized in Net Periodic
Pension Cost 9,410 5,198 5,404
Unrecognized Net Assets at Transition Being Amortized
Over 15 Years (1,729) (2,017) (2,305)
-------- --------
Prepaid Pension Cost Included in the Balance Sheet $ 2,2601,448 $ 3,1482,260
======== ========
The increases in the Accumulated Benefit Obligation and Projected
Benefit Obligation from 1994 to 1995 reflect the decrease in the discount
rate used from 8.5% in 1994 to 7.5% in 1995 and amendments to the plans which
now generally allow an employee to receive a normal retirement benefit if his
age and credited years of service equal at least 85.
Years Ended December 31,
1995 1994 1993 1992
-------- -------- --------
- Thousands of Dollars -
Components of Net Pension Cost
Service Cost of Benefits Earned During Period $ 3,236 $ 2,680 $ 1,558
$ 1,390
Interest Cost ofon Projected Benefit Obligation 6,752 5,615 4,689 4,283
Actual (Gain) Loss on Plan Assets (8,417) 492 (14,508) (4,075)
Net Amortization and Deferral 532 (6,214) 10,187 54
-------- -------- --------
Net Periodic Pension Cost $ 2,103 $ 2,573 $ 1,926
$ 1,652
======== ======== ========
Assumed Rates Used to Determine Pension CostActuarial Assumptions: 1995 1994 1993 1992
---- ---- ----
Discount Rate - Funding Status 7.5% 8.5% 7.0% 8.0%
Average Compensation Increase 5.0 5.55.0 5.5
Expected Long-Term Rate of Return on Plan Assets 9.0 7.59.0 7.5
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Health care and life insurance benefits are provided for retired
employees. All regular employees may become eligible for those benefits if
they reach retirement age while working for the Company. Those and similar
benefits are provided through an independent administrator handling health
claims and a life insurance companycompanies that hasoffer premiums based on group rates.
The Company adopted FAS 106, Employers' Accounting for Postretirement
Benefits Other Than Pensions, in 1993. Adoption of FAS 106 resulted in an
increase in the Company's annual expense for postretirement benefits of
approximately $3 million in 1993. The accumulated postretirement benefit
obligation as of January 1, 1993 of $19 million is being amortized to expense
over a twenty-year period, in accordance with the provisions of FAS 106. The
Company recognizes the FAS 106 periodic benefit cost as expense. In January
1994, the Company was authorized by the ACC to recover through rates the
costs of benefits only as payments are made to retired employees; the
postretirement benefits are currently funded entirely on a pay-as-you-go
basis. Therefore, the Company has not recorded a regulatory asset for the
excess of FAS 106 expense over actual benefit payments.
1995 1994 1993
--------- ---------
- Thousands of Dollars -
Accumulated Postretirement BenefitsBenefit Obligation
Retirees $ (5,270)(6,993) $ (5,832)(5,270)
Fully Eligible Active Plan Participants (4,273) (3,286) (3,130)
Other Active Participants (13,885) (9,849) (11,295)
--------- ---------
Total Accumulated Postretirement BenefitsBenefit Obligation (25,151) (18,405) (20,257)
Unrecognized Net GainLoss (Gain) from Past Experience 732 (4,429) (786)
Unrecognized Portion of the Transition Obligation
Being Amortized Over 20 Years 16,289 17,247 18,205
--------- ---------
Accrued Postretirement Benefit Cost Included in the
Balance Sheet $ (8,130) $ (5,587) $(2,838)
========= =========
Years Ended December 31,
1995 1994 1993
--------- ---------------- ------- -------
- Thousands of Dollars -
Components of Net Postretirement Benefit Cost
Service Cost of Benefits Earned During Period $ 838 $ 931 $ 950
Interest Cost of Projectedon Postretirement Benefit
Obligation 1,541 1,395 1,491
Amortization of the Unrecognized Transition
Obligation 958 958 --------- ---------958
Amortization of the Unrecognized Gain (152) - -
------- ------- -------
Net Periodic Postretirement Benefit Cost $ 3,284 $ 3,399
========= =========$3,185 $3,284 $3,399
======= ======= =======
The accumulated postretirement benefit obligation was determined using ana
7.0% and 8.5% and 7% discount rate for 19941995 and 1993,1994, respectively. The health care
cost trend rates were assumed to be 10%9.21% and 11%10.33% for 19941995 and 1993,1994,
respectively, gradually declining to 3.88% and 5%, respectively, in 2003 and
thereafter. The effect of a one percentage point increase in the assumed
health care cost trend rate would increase the accumulated postretirement
benefit obligation as of December 31, 19941995 by approximately $2.8$4 million and
the net periodic cost by $0.4 million for the year.
ADOPTION OF FAS 112
In January 1994 the Company adopted FAS 112, Employers' Accounting for
Postemployment Benefits. Prior to 1994, postemployment benefits other than
those related to retirement benefits were recognized on a pay-as-you-go
basis. The effect of this change was an increase in postemployment benefits
expense of $0.6 million for the year ended December 31, 1994.1995.
STOCK OPTION PLANS
On May 20, 1994, the Shareholders of the Company approved two stock
option plans, the 1994 Outside Director Stock Option Plan (Directors' Plan)
and the 1994 Omnibus Stock and Incentive Plan (Omnibus Plan).
The Directors' Plan provides for the annual grant of 6,000 non-
qualified stock options to each eligible director. Under the Directors'
Plan, the first grant on January 3, 1995 consisted of 48,000 optionsdirector, at an exercise price
equal to the market price of $3.125; thesethe Company's Common Stock at the grant date,
beginning January 3, 1995. These options vest ratably and become
exercisable in one-third increments on each anniversary date of the grant
and expire in 2005.on the tenth anniversary.
The Omnibus Plan allows the Compensation Committee, a committee
comprised solely of non-employee directors, to grant any or all of the
following types of awards to each eligible employee of the Company: stock
options, including incentive stock options, non-qualified stock options and
discounted stock options; stock appreciation rights; restricted stock;
performance units; performance shares; and dividend equivalents. The total
number of shares of the Company's stock which may be awarded under the
Omnibus Plan cannot exceed eight million.
During 1995 and 1994, the Compensation Committee granted stock options
intended to qualify as incentive stock options under the Internal Revenue
Code to key employees and to all employees, withrespectively, at exercise prices
greater than or equal to the market price of $3.25 - $3.50. Thethe Company's Common Stock at
the grant date. These options vest ratably over a three year period, with the first third becomingand become exercisable in 1995,one-
third increments on each anniversary date of the grant and expire in 2004. The aggregate number of
shares attributable toon the
1994 grants is 2,214,205.
The Company'stenth anniversary.
Options outstanding under the 1985 Stock Option Plan remains in effect andhave exercise
prices equal to the options outstanding thereunder, whichmarket price of the Company's Common Stock at the grant
date, are fully exercisable and expire in
1995 to 1997.
No options were exercised and the Company incurredrecorded no compensation
expense for the 1985 Planplans during 19921993 through 1994.1995. The following summarizes
the stock option transactions during the period December 31,
1992 through December 31, 1994:
Number of Exercise
Options Price
-------1993, 1994 and 1995:
1994 1994
1985 Stock Omnibus Directors'
Option Plan Plan Plan
----------- ---------- ----------
Options Outstanding,
December 31, 1992 and 1993:
1985 Plan1993 37,803 - Primary 23,750 $40.375 to $58.625
Dividend Equivalents 14,053 ----
Granted During 1994:
1994 Omnibus Plan 2,214,205 $3.25 to $3.50
---------- 2,212,364 -
Canceled (2,706) - -
----------- ---------- ----------
Options Outstanding,
December 31, 1994 2,252,008
=========35,097 2,212,364 -
Granted - 414,579 54,000
Canceled or Expired (26,980) (50,466) (6,000)
----------- ---------- ----------
Options Outstanding,
December 31, 1995 8,117 2,576,477 48,000
=========== ========== ==========
Option Price Per Share $58.625 $3.25 to $3.125 to
$3.563 $3.313
Options Exercisable
At December 31, 1993 37,803 - -
At December 31, 1994 35,097 - -
At December 31, 1995 8,117 720,207 -
NOTE 11.9. QUARTERLY FINANCIAL DATA (unaudited)
- ----------------------------------------------
First Second Third Fourth
--------- --------- --------- ---------
- Thousands of Dollars -
(except per share data)
1995
Operating Revenue $142,745 $162,305 $217,787 $147,732
Operating Income 6,748 26,970 84,357 3,980
Net Income (Loss) (14,960) 3,014 60,729 6,122
Net Income (Loss) per Average Share (0.09) 0.02 0.37 0.04
1994
Operating Revenue $146,579 $171,097 $220,486 $153,311
Operating Income 8,259 27,951 64,310 13,882
Net Income (Loss) (14,580) 4,432 40,688 (9,800)
Net Income (Loss) per Average Share (0.09) 0.03 0.25 (0.06)
1993
Operating Revenue $136,149 $148,349 $189,432 $150,209
Operating Income 4,511 14,179 44,902 20,354
Income (Loss) from
Continuing Operations (18,522) (7,978) 22,386 (17,702)
Provision for Loss on Disposal of
Discontinued Operations - - - (4,000)
Net Income (Loss) (18,522) (7,978) 22,386 (21,702)
Net Income (Loss) per Average Share
Continuing Operations (0.12) (0.05) 0.14 (0.11)
Provision for Loss on Disposal of
Discontinued Operations - - - (0.02)
Total Net Income (Loss) per
Average Share (0.12) (0.05) 0.14 (0.13)
Due to seasonal fluctuations in sales, recognition of regulatory
disallowancesa $16 million net increase in
income tax benefits and adjustments, and provisions for loss on discontinued
operations,a one-time $12 million reduction in fuel expenses,
the quarterly results are not indicative of annual operating results. See
Notes 2 and 5Note 3 regarding significantthe income tax adjustments which were recorded during the fourth
quarter of 1993.
Beginning1995 and Note 6 regarding the one-time reduction in fuel expenses
recorded during the fourththird quarter of 1994, state and city sales taxes and
similar taxes collected on revenues were removed from Operating Revenues and
Taxes Other Than Income Taxes on the Consolidated Statement of Income (Loss).
See Note 1. The tax amounts reclassified were as follows:
First Second Third Fourth
--------- --------- --------- ---------
- Thousands of Dollars -
1994
Operating Revenue - Historical $155,475 $180,671 $234,083 N/A
Total Taxes Reclassified (8,896) (9,574) (13,597) N/A
--------- --------- --------- ---------
Operating Revenue - Restated $146,579 $171,097 $220,486 N/A
========= ========= ========= =========
1993
Operating Revenue - Historical $144,424 $157,434 $201,204 $159,375
Total Taxes Reclassified (8,275) (9,085) (11,772) (9,166)
--------- --------- --------- ---------
Operating Revenue - Restated $136,149 $148,349 $189,432 $150,209
========= ========= ========= =========1995.
NOTE 12.10. SUPPLEMENTAL CASH FLOW INFORMATION
- --------------------------------------------
For purposes of this statement, the Company defines Cash and Cash
Equivalents as cash (unrestricted demand deposits) and all highly liquid
investments purchased with a maturity of three months or less related to all
of the Company's operations, including discontinued operations (see below).operations. A
reconciliation of net income (loss) to net cash flows from continuing
operating activities for the three years ended December 31, 19941995 follows:
1995 1994 1993 1992
---------- ---------- ----------
- Thousands of Dollars -
Income (Loss) from Continuing Operations $ 54,905 $ 20,740 $ (21,816) $ (79,022)
Adjustments to Reconcile Income (Loss) from
Continuing Operations to Net Cash FlowFlows
Depreciation Expense 92,179 89,905 74,184
69,445
Capital Lease Rent Expense - - 13,161
Taxes Accrued (13,519) 8,946 (2,303) 6,578
Deferred Income Taxes and Investment
Tax Credits - Net (21,136) (4,911) (5,277) (11,194)
Deferred Fuel and Purchased Power 5,872 7,359 10,716
7,030
Litigation SettlementsSettlement - Net - (5,000) (5,000)
Lease Payments Deferred 32,977 32,024 29,870 10,830
Deferred Springerville Unit 2 Costs (1,127) (1,133) (5,359)
(4,143)Regulatory Amortizations, Net of Interest
Imputed on Losses Recorded at
Present Value (15,852) (13,977) (8,148)
Regulatory Disallowances and
Adjustments, Net of Amortization (13,977) 5,629 (4,501)
Loss on Financial Restructuring - - 26,669
Payments Withheld due to Payment
Moratorium - - 46,66513,777
Other (4,457) (506) 314 13,188
Changes in Assets and Liabilities which
Provided (Used) Cash Exclusive of
Changes Shown Separately
Accounts Receivable - Other (375) 1,119 4,5264,615 (1,120) (6,014)
Accounts Payable (14,599) (413) 1,634
Materials and Fuel (5,973) 343 6,484 (629)
Unbilled Revenues 625 (1,438) (631)
Other Current Assets and Liabilities 601 (2,029) 3,034(6,751) 2,384 2,032
Other Deferred Assets and Liabilities 12,256 3,975 4,237 (7,376)
---------- ---------- ----------
Net Cash Flows - Continuing Operating
Activities $ 119,390 $ 143,616 $ 89,331 $ 88,630
========== ========== ==========
Non-cash capital transactionsinvesting and financing activities of the Company that affected
recognized assets and liabilities but did not result in cash receipts or
payments during the three years ended December 31, 19941995 were:
1995 1994 1993 1992
---------- ---------- ----------
- Thousands of Dollars -
Capital Lease Obligations $ 8,095 $ 8,107 $ 10,523 $ 926,169
Acquisition of Leased Assets - 3,385 883,607
Issuance of Common Stock and Warrants - - 197,128
Acquisition of Springerville Assets - - 30,6453,385
ITEM 9. --- CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10. --- DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS
Information concerning Directors is contained under Election of Directors
in the Company's Proxy Statement relating to the 19951996 Annual Meeting of
Shareholders, which information is incorporated herein by reference.
EXECUTIVE OFFICERS
Executive Officers of the Company who are elected annually by the Company's
Board of Directors, are as follows:
Executive
Officer
Name Age Title Since
- ------------------ --- ------------------------------- ---------
Charles E. Bayless 5253 Chairman of the Board, President
and Chief Executive Officer (a) 1989
Ira R. Adler 4445 Senior Vice President and Chief
Financial Officer (b) 1988
James S. Pignatelli 5152 Senior Vice President - Business
Development (c) 1994
Thomas A. Delawder 4849 Vice President - Energy
Resources (d) 1985
Gary L. Ellerd 4445 Vice President - Operations (e) 1985
Steven J. Glaser 3738 Vice President - Wholesale
/RetailWholesale/Retail
Pricing and System Planning (f) 1994
Thomas N. Hansen 4445 Vice President - Technical
Advisor (g) 1992
Karen G. Kissinger 4041 Vice President and
Controller (h) 1991
George W. Miraben 5354 Vice President - Human Resources
and Public Affairs (i) 1990
Dennis R. Nelson 4445 Vice President, General Counsel
and Corporate Secretary (j) 1991
Gerald A. O'Brien 5354 Vice President - Customer
Services & Marketing (k) 1990
Romano Salvatori 5758 Vice President - Independent
Power (l) 1994
Susan R. Wallach 4748 Vice President - BusinessPlanning and
Development (m) 1990
Kevin P. Larson 3839 Treasurer (n) 1994
(a) Charles E. Bayless: Mr. Bayless joined the Company as Senior Vice
President and Chief Financial Officer in December 1989. He was elected
President and Chief Executive Officer in July 1990 and was elected to the Board
of Directors in June 1990. On January 28, 1992, Mr. Bayless was named Chairman
of the Board of Directors. Prior to joining the Company, he was Senior Vice
President and Chief Financial Officer of Public Service Company of New Hampshire
from 1981 through 1989.
(b) Ira R. Adler: Mr. Adler joined the Company in 1986 as Manager of Financial
Planning. In 1987 he was elected as Vice President and Treasurer of TRI, one of
the Company's investment subsidiaries, from which position he resigned in
October 1988, when he was elected Treasurer of the Company. He was elected Vice
President - Finance and Treasurer in July 1989 and was elected Senior Vice
President and Chief Financial Officer in July 1990 and President of TRI and SRI
in April 1992. Prior to joining the Company, he was Vice President - Finance of
US WEST Financial Services, Inc.
(c) James S. Pignatelli: Mr. Pignatelli joined the Company as Senior Vice
President in August 1994. Prior to joining the Company, he was President and
Chief Executive Officer from 1988 to 1993 of Mission Energy Company, a
subsidiary of SCE Corp.
(d) Thomas A. Delawder: Mr. Delawder joined the Company in 1974 and thereafter
served in various engineering and operations positions. In April 1985 he was
named Manager, Systems Operations and was elected Vice President - Power Supply
and System Control in November 1985. In February 1991, he became Vice President
- - Engineering and Power Supply and in January 1992 he became Vice President -
System Operations. In 1994, he became Vice President - Energy Resources.
(e) Gary L. Ellerd: Mr. Ellerd joined the Company as Vice President and
Controller in January 1985. He was elected Vice President - Services and Chief
Information Officer in January 1991 and in January 1992 he became Vice President
- - Corporate Information Services and Chief Information Officer. In 1994, he was
named Vice President - Retail Customers. In 1995, he was named Vice President -
- Operations.
(f) Steven J. Glaser: Mr. Glaser joined the Company in 1990 as a Senior
Attorney in charge of Regulatory Affairs. He was Manager of the Company's Legal
department from 1992 to 1994, and Manager of Contracts and Wholesale Marketing
from 1994 until elected Vice President - Business Development. In 1995, he was
named Vice President - Wholesale/Retail Pricing and System Planning.
(g) Thomas N. Hansen: Mr. Hansen joined the Company in December 1992 as Vice
President - Power Production. Prior to joining the Company, Mr. Hansen was
Century's Vice President - Operations from 1989 and Plant Manager at
Springerville from 1987 through 1988. In 1994, he was named Vice President -
Technical Advisor.
(h) Karen G. Kissinger: Ms. Kissinger joined the Company as Vice President and
Controller in January 1991. Prior to joining the Company, she was a Manager
with Deloitte & Touche from 1986 through 1989 and a Senior Manager through 1990.
(i) George W. Miraben: Mr. Miraben was elected Vice President, Public Affairs,
effective March 1990, and named Vice President - Human Resources and Public
Affairs in 1994. Prior to joining the Company, he was Director of External
Affairs for US WEST Communications' Arizona operation from 1981 through March
1990.
(j)j) Dennis R. Nelson: Mr. Nelson joined the Company in 1976. He was manager of
the Legal Department from 1985 to 1990. He was elected Vice President, General
Counsel and Corporate Secretary in January 1991.
(k) Gerald A. O'Brien: Mr. O'Brien joined the Company in 1961. Formerly
Manager, Customer and Corporate Services, he was elected Vice President -
- Customer Services and Human Resources in May 1990 and in January 1992 he became
Vice President - Customer Operations. In 1994, he was named Vice President -
Operations Support. In 1995, he was named Vice President - - Customer Services &
Marketing.
(l)Romano Salvatori: Mr. Salvatori joined the Company as Vice President -
Independent Power in December 1994. Prior to joining the Company, he was Deputy
General Manager, Power Generation Business Unit and General Manager, Power
Generation Strategic Affairs Division of Westinghouse Electric Corporation from
1990 to 1994, and General Manager, Power Generation Commercial Operations
Division from 1990 to 1993. In 1995, he was named President of Nations Energy
Corporation, in addition to his responsibilities as Vice President - Independent
Power.
(m) Susan R. Wallach: Ms. Wallach joined the Company in 1974. Formerly
Manager of Accounting Services and Assistant Controller, she was elected Vice
President and Treasurer in July 1990. She was named Vice President - Future
Marketing/Sales/Planning in 1994. In 1995, she was named Vice President -
BusinessPlanning and Development.
(n) Kevin P. Larson: Mr. Larson joined the Company in 1985 and thereafter held
various positions in its finance department and at the Company's investment
subsidiaries. In January 1991, he was elected Assistant Treasurer of the
Company and named Manager of Financial Programs. He was elected Treasurer in
August 1994.
ITEM 11. --- EXECUTIVE COMPENSATION
Information concerning Executive Compensation is contained under
Executive Compensation and Other Information in the Company's Proxy Statement
relating to the 19951996 Annual Meeting of Shareholders, which information is
incorporated herein by reference.
ITEM 12. --- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
GENERAL
At March 6, 1995,1, 1996, the Company had outstanding 160,723,702160,666,976 shares of Common
Stock. As of March 6, 1995,1, 1996, the number of shares of Common Stock beneficially
owned by all directors and officers of the Company as a group amounted to less
than 1% of the outstanding Common Stock.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Information concerning the security ownership of certain beneficial owners
of the Company is contained under Security Ownership of Certain Beneficial
Owners in the Company's Proxy Statement relating to the 19951996 Annual Meeting of
Shareholders, which information is incorporated herein by reference.
SECURITY OWNERSHIP OF MANAGEMENT
Information concerning the security ownership of the Directors and
Executive Officers of the Company is contained under Security Ownership of
Certain Beneficial Owners in the Company's Proxy Statement relating to the 19951996
Annual Meeting of Shareholders, which information is incorporated herein by
references.reference.
ITEM 13. --- CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. --- EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Page
(a) 1. Consolidated Financial Statements as of
December 31, 19941995 and 19931994 and for Each
of the Three Years in the Period Ended
December 31, 1994.1995.
Independent Auditors' Report 2732
Consolidated Statements of Income (Loss) 28
Consolidated Balance Sheets 29
Consolidated Statements of Capitalization 3033
Consolidated Statements of Cash Flows 3134
Consolidated Balance Sheets 35
Consolidated Statements of Capitalization 36
Consolidated Statements of Changes in Stockholders'
Equity (Deficit) 3237
Notes to Consolidated Financial Statements 3338
2. Supplemental Consolidated Schedules for the Years
Ended December 31, 19921993 to 1994.1995.
Schedules I to V, inclusive, are omitted because they are not applicable or
not required.
3. Exhibits.
Reference is made to the Exhibit Index commencing on page 6066
(b) Reports on Form 8-K.
The Company has not filed any Current Reports on Form 8-K duringas follows:
- Dated December 8, 1995 reporting on a settlement agreement between the
last
quarterCompany and the ACC proposing to resolve the Company's application for
rate increase and the Company's notice of intent to form a holding
company.
- Dated January 26, 1996 reporting on the ACC's denial of the period covered in this report.Proposed
Settlement Agreement.
- Dated February 9, 1996 disclosing the ACC's Chief Hearing Officer
recommendation regarding the Company's notice of intent to form a
holding company.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
TUCSON ELECTRIC POWER COMPANY
Date: March 8, 19955, 1996 By Ira R. Adler
-----------------------------------------------
IRA R. ADLER
Senior Vice President and Principal
Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Date: March 8, 19955, 1996 Charles E. Bayless*
-------------------------------------------------------------------------
Charles E. Bayless
Chairman of the Board, President and
Principal Executive Officer
Date: March 8, 19955, 1996 Ira R. Adler
---------------------------------------------------------------
Ira R. Adler
Principal Financial Officer
Date: March 8, 19955, 1996 Karen G. Kissinger*
----------------------------------------------------------------
Karen G. Kissinger
Principal Accounting Officer
Date: March 8, 19955, 1996 Elizabeth Alexander*
-------------------------
Elizabeth Alexander
Director
Date: March 5, 1996 Jose Canchola*
-------------------------------------------------------
Jose Canchola
Director
Date: March 8, 1995 Kathryn N. Dusenberry*
------------------------------------
Kathryn N. Dusenberry
Director
Date: March 8, 19955, 1996 John A. Jeter*
-------------------------------------------------------
John A. Jeter
Director
Date: March 8, 19955, 1996 R. B. O'Rielly*
--------------------------------------------------------
R. B. O'Rielly
Director
Date: March 8, 19955, 1996 Martha R. Seger*
---------------------------------------------------------
Martha R. Seger
Director
Date: March 8, 19955, 1996 Donald G. Shropshire*
--------------------------------------------------------------
Donald G. Shropshire
Director
Date: March 8, 19955, 1996 H. Wilson Sundt*
---------------------------------------------------------
H. Wilson Sundt
Director
Date: March 8, 19955, 1996 J. Burgess Winter*
-----------------------
J. Burgess Winter
Director
Date: March 5, 1996 By Ira R. Adler
-----------------------------------------------
Ira R. Adler
as attorney-in-fact for each
of the persons indicated
EXHIBIT INDEX
*3(a) -- Restated Articles of Incorporation, filed with the ACC on August 11,
1994. (Form 10-Q for the quarter ended September 30, 1994, File No.
1-5924--Exhibit 3).)
*3(b) -- Bylaws of the Registrant, as amended May 20, 1994. (Form 10-Q for the
quarter ended June 30, 1994, File No. 1-5924--Exhibit 3).)
*4(a)(1)-- Indenture dated as of April 1, 1941, to The Chase National Bank of
the City of New York, as Trustee. (Form S-7, File No. 2-59906--
Exhibit2-59906--Exhibit
2(b)(1).)
*4(a)(2)-- First Supplemental Indenture, dated as of October 1, 1946. (Form S-7,S-
7, File No. 2-59906--Exhibit 2(b)(2).)
*4(a)(3)-- Second Supplemental Indenture dated as of October 1, 1947. (Form S-7,S-
7, File No. 2-59906--Exhibit 2(b)(3).)
*4(a)(4)-- Third Supplemental Indenture, dated as of April 1, 1949. (Form S-7,
File No. 2-59906--Exhibit 2(b)(4).)
*4(a)(5)-- Fourth Supplemental Indenture, dated as of December 1, 1952. (Form
S-7, File No. 2-59906--Exhibit 2(b)(5).)
*4(a)(6)-- Fifth Supplemental Indenture, dated as of January 1, 1955. (Form S-7,S-
7, File No. 2-59906--Exhibit 2(b)(6).)
*4(a)(7)-- Sixth Supplemental Indenture, dated as of January 1, 1958. (Form S-7,S-
7, File No. 2-59906--Exhibit 2(b)(7).)
*4(a)(8)-- Seventh Supplemental Indenture, dated as of November 1, 1959. (Form
S-7, File No. 2-59906--Exhibit 2(b)(8).)
*4(a)(9)-- Eighth Supplemental Indenture, dated as of November 1, 1961. (Form
S-7, File No. 2-59906--Exhibit 2(b)(9).)
*4(a)(10)-- Ninth Supplemental Indenture, dated as of February 20, 1964.
(Form S-7, File No. 2-59906--Exhibit 2(b)(10).)
*4(a)(11)-- Tenth Supplemental Indenture, dated as of February 1, 1965.
(Form S-7, File No. 2-59906--Exhibit 2(b)(11).)
*4(a)(12)-- Eleventh Supplemental Indenture, dated as of February 1, 1966.
(Form S-7, File No. 2-59906--Exhibit 2(b)(12).)
*4(a)(13)-- Twelfth Supplemental Indenture, dated as of November 1, 1969.
(Form S-7, File No. 2-59906--Exhibit 2(b)(13).)
*4(a)(14)-- Thirteenth Supplemental Indenture, dated as of January 20, 1970.
(Form S-7, File No. 2-59906--Exhibit 2(b)(14).)
*4(a)(15)-- Fourteenth Supplemental Indenture, dated as of September 1,
1971. (Form S-7, File No. 2-59906--Exhibit 2(b)(15).)
*4(a)(16)-- Fifteenth Supplemental Indenture, dated as of March 1, 1972.
(Form S-7, File No. 2-59906--Exhibit 2(b)(16).)
*4(a)(17)-- Sixteenth Supplemental Indenture, dated as of May 1, 1973. (Form
S-7, File No. 2-59906--Exhibit 2(b)(17).)
*4(a)(18)-- Seventeenth Supplemental Indenture, dated as of November 1,
1975. (Form S-7, File No. 2-59906--Exhibit 2(b)(18).)
*4(a)(19)-- Eighteenth Supplemental Indenture, dated as of November 1, 1975.
(Form S-7, File No. 2-59906--Exhibit 2(b)(19).)
*4(a)(20)-- Nineteenth Supplemental Indenture, dated as of July 1, 1976.
(Form S-7, File No. 2-59906--Exhibit 2(b)(20).)
*4(a)(21)-- Twentieth Supplemental Indenture, dated as of October 1, 1977.
(Form S-7, File No. 2-59906--Exhibit 2(b)(21).)
*4(a)(22)-- Twenty-first Supplemental Indenture, dated as of November 1,
1977. (Form 10-K for year ended December 31, 1980, File No. 1-5924--
Exhibit 4(v).)
*4(a)(23)-- Twenty-second Supplemental Indenture, dated as of January 1,
1978. (Form 10-K for year ended December 31, 1980, File No. 1-5924--
Exhibit 4(w).)
*4(a)(24)-- Twenty-third Supplemental Indenture, dated as of July 1, 1980.
(Form 10-K for year ended December 31, 1980, File No. 1-5924--Exhibit
4(x).)
*4(a)(25)-- Twenty-fourth Supplemental Indenture, dated as of October 1,
1980. (Form 10-K for year ended December 31, 1980, File No. 1-5924--
Exhibit 4(y).)
*4(a)(26)-- Twenty-fifth Supplemental Indenture, dated as of April 1, 1981.
(Form 10-Q for quarter ended March 31, 1981, File No. 1-5924--Exhibit
4(a).)
*4(a)(27)-- Twenty-sixth Supplemental Indenture, dated as of April 1, 1981.
(Form 10-Q for quarter ended March 31, 1981, File No. 1-5924--Exhibit
4(b).)
*4(a)(28)-- Twenty-seventh Supplemental Indenture, dated as of October 1,
1981. (Form 10-Q for quarter ended September 30, 1982, File No. 1-5924-
-Exhibit1-
5924--Exhibit 4(c).)
*4(a)(29)-- Twenty-eighth Supplemental Indenture, dated as of June 1, 1990.
(Form 10-Q for quarter ended June 30, 1990, File No. 1-5924--Exhibit
4(a)(1).)
*4(a)(30)-- Twenty-ninth Supplemental Indenture, dated as of December 1,
1992. (Form S-1, Registration No. 33-55732--Exhibit 4(a)(30).)
*4(a)(31)-- Thirtieth Supplemental Indenture, dated as of December 1, 1992.
(Form S-1, Registration No. 33-55732--Exhibit 4(a)(31).)
*4(b)(1)-- Installment Sale Agreement, dated as of December 1, 1973, among the
City of Farmington, New Mexico, Public Service Company of New Mexico
and the Registrant. (Form 8-K for the month of January 1974, File No.
0-269--Exhibit 3.)
*4(b)(2)-- Ordinance No. 486, adopted December 17, 1973, of the City of
Farmington, New Mexico. (Form 8-K for the month of January 1974, File
No. 0-269--Exhibit 4.)
*4(c)(1)-- Loan Agreement, dated as of September 15, 1981, between the
Industrial Development Authority of the County of Apache, Arizona and
the Registrant, relating to Floating Rate Monthly Demand Pollution
Control Revenue Bonds, 1981 Series B (Tucson Electric Power Company
Project). (Form 10-K for year ended December 31, 1981, File No. 1-
5924--Exhibit 4(d)(1).)
*4(c)(2)-- Indenture of Trust, dated as of September 15, 1981, between the
Apache County Authority and Morgan Guaranty Trust Company of New York,
authorizing Floating Rate Monthly Demand Pollution Control Revenue
Bonds, 1981 Series B (Tucson Electric Power Company Project). (Form
10-K for year ended December 31, 1981, File No. 1-5924--Exhibit
4(d)(2).)
*4(d)(1)-- Second Supplemental Loan Agreement, dated as of October 1, 1981,
between the Apache County Authority and the Registrant, relating to
Floating Rate Monthly Demand Pollution Control Revenue Bonds, 1981
Series B (Tucson Electric Power Company Project). (Form 10-K for year
ended December 31, 1982, File No. 1-5924--Exhibit 4(f)(1).)
*4(d)(2)-- Second Supplemental Indenture, dated as of October 1, 1981, between
the Apache County Authority and Morgan Guaranty, relating to Floating
Rate Monthly Demand Pollution Control Revenue Bonds, 1981 Series B
(Tucson Electric Power Company Project). (Form 10-K for year ended
December 31, 1982, File No. 1-5924--Exhibit 4(f)(2).)
*4(d)(3)-- Third Supplemental Loan Agreement, dated as of December 1, 1985,
between the Apache County Authority and the Registrant, relating to
Floating Rate Monthly Demand Pollution Control Revenue Bonds, 1981
Series B (Tucson Electric Power Company Project). (Form 10-K for the
year ended December 31, 1987, File No. 1-5924--Exhibit 4(d)(3).)
*4(d)(4)-- Third Supplemental Indenture, dated as of December 1, 1985, between
the Apache County Authority and Morgan Guaranty, relating to Floating
Rate Monthly Demand Pollution Control Revenue Bonds, 1981 Series B
(Tucson Electric Power Company Project). (Form 10-K for the year
ended December 31, 1987, File No. 1-5924--Exhibit 4(d)(4).)
*4(d)(5)-- Fourth Supplemental Indenture of Trust, dated as of March 31, 1992,
between the Apache County Authority and Morgan Guaranty, relating to
Pollution Control Revenue Bonds, 1981 Series B (Tucson Electric Power
Company Project). (Form S-4, Registration No. 33-52860-
-Exhibit33-52860--Exhibit
4(d)(5).)
*4(d)(6)-- Fourth Supplemental Loan Agreement, dated as of March 31, 1992,
between the Apache County Authority and the Registrant, relating to
Pollution Control Revenue Bonds, 1981 Series B (Tucson Electric Power
Company Project). (Form S-4, Registration No. 33-52860--Exhibit
4(d)(6).)
*4(e)(1)-- Loan Agreement, dated as of October 1, 1981, between The Industrial
Development Authority of the County of Pima, Arizona (the Pima County
Authority) and the Registrant, relating to Floating Rate Monthly
Demand Pollution Control Revenue Bonds, 1981 Series A (Tucson Electric
Power Company Project). (Form 10-K for year ended December 31, 1981,
File No. 1-5924--Exhibit 4(f)(1).)
*4(e)(2)-- Indenture of Trust, dated as of October 1, 1981, between the Pima
County Authority and Morgan Guaranty, authorizing Floating Rate
Monthly Demand Pollution Control Revenue Bonds, 1981 Series A (Tucson
Electric Power Company Project). (Form 10-K for year ended December
31, 1981, File No. 1-5924--Exhibit 4(f)(2).)
*4(f)(1)-- Loan Agreement, dated as of July 1, 1982, between the Pima County
Authority and the Registrant, relating to Floating Rate Monthly Demand
Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric
Power Company General Project). (Form 10-Q for quarter ended June 30,
1982, File No. 1-5924--Exhibit 4(a).)
*4(f)(2)-- Indenture of Trust, dated as of July 1, 1982, between the Pima
County Authority and Morgan Guaranty, authorizing Floating Rate
Monthly Demand Industrial Development Revenue Bonds, 1982 Series A
(Tucson Electric Power Company General Project). (Form 10-Q for
quarter ended June 30, 1982, File No. 1-5924--Exhibit 4(b).)
*4(f)(3)-- First Supplemental Loan Agreement, dated as of March 31, 1992,
between the Pima County Authority and the Registrant relating to
Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric
Power Company General Project). (Form S-4, Registration No. 33-52860-
-Exhibit 4(f)(3).)
*4(f)(4)-- First Supplemental Indenture of Trust, dated as of March 31, 1992,
between the Pima County Authority and Morgan Guaranty relating to
Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric
Power Company General Project). (Form S-4, Registration No. 33-52860--Exhibit33-52860--
Exhibit 4(f)(4).)
*4(g)(1)-- Loan Agreement, dated as of July 1, 1982, between the Pima County
Authority and the Registrant, relating to Quarterly Tender Industrial
Development Revenue Bonds, 1982 Series A (Tucson Electric Power
General Project). (Form 10-Q for quarter ended June 30, 1982, File No.
1-5924--Exhibit 4(c).)
*4(g)(2)-- Indenture of Trust, dated as of July 1, 1982, between the Pima
County Authority and Morgan Guaranty, authorizing Quarterly Tender
Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric
Power Company General Project). (Form 10-Q for quarter ended June 30,
1982, File No. 1-5924--Exhibit 4(d).)
*4(g)(3)-- First Supplemental Loan Agreement, dated as of March 31, 1992,
between the Pima County Authority and the Registrant relating to
Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric
Power Company General Project). (Form S-4, Registration No. 33-52860-
-Exhibit 4(g)(3).)
*4(g)(4)-- First Supplemental Indenture of Trust, dated as of March 31, 1992,
between the Pima County Authority and Morgan Guaranty relating to
Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric
Power Company General Project). (Form S-4, Registration No. 33-52860--Exhibit33-52860--
Exhibit 4(g)(4).)
*4(h)(1)-- Loan Agreement, dated as of October 1, 1982, between the Pima County
Authority and the Registrant relating to Floating Rate Monthly Demand
Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric
Power Company Irvington Project). (Form 10-Q for quarter ended
September 30, 1982, File No. 1-5924--Exhibit 4(a).)
*4(h)(2)-- Indenture of Trust, dated as of October 1, 1982, between the Pima
County Authority and Morgan Guaranty authorizing Floating Rate Monthly
Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson
Electric Power Company Irvington Project). (Form 10-Q for quarter
ended September 30, 1982, File No. 1-5924--Exhibit 4(b).)
*4(h)(3)-- First Supplemental Loan Agreement, dated as of March 31, 1992,
between the Pima County Authority and the Registrant relating to
Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric
Power Company Irvington Project). (Form S-4, Registration No. 33-
52860--Exhibit 4(h)(3).)
*4(h)(4)-- First Supplemental Indenture of Trust, dated as of March 31, 1992,
between the Pima County Authority and Morgan Guaranty relating to
Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric
Power Company Irvington Project). (Form S-4, Registration No. 33-52860--Exhibit33-
52860--Exhibit 4(h)(4).)
*4(i)(1)-- Loan Agreement, dated as of December 1, 1982, between the Pima
County Authority and the Registrant relating to Floating Rate Monthly
Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson
Electric Power Company Projects). (Form 10-K for year ended December
31, 1982, File No. 1-5924--Exhibit 4(k)(1).)
*4(i)(2)-- Indenture of Trust, dated as of December 1, 1982, between the Pima
County Authority and Morgan Guaranty authorizing Floating Rate Monthly
Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson
Electric Power Company Projects). (Form 10-K for year ended December
31, 1982, File No. 1-5924--Exhibit 4(k)(2).)
*4(i)(3)-- First Supplemental Loan Agreement, dated as of March 31, 1992,
between the Pima County Authority and the Registrant relating to
Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric
Power Company Projects). (Form S-4, Registration No. 33-52860--Exhibit
4(i)(3).)
*4(i)(4)-- First Supplemental Indenture of Trust, dated as of March 31, 1992,
between the Pima County Authority and Morgan Guaranty relating to
Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric
Power Company Projects). (Form S-4, Registration No. 33-52860-
-Exhibit33-52860--Exhibit
4(i)(4).)
*4(j)(1)-- Loan Agreement, dated as of March 1, 1983, between the Pima County
Authority and the Registrant relating to Floating Rate Monthly Demand
Industrial Development Revenue Bonds, 1982 Series A (Tucson Electric
Power Company General Project). (Form 10-Q for the quarter ended
March 31, 1983, File No. 1-5924--Exhibit 4(a).)
*4(j)(2)-- Indenture of Trust, dated as of March 1, 1983, between the Pima
County Authority and Morgan Guaranty authorizing Floating Rate Monthly
Demand Industrial Development Revenue Bonds, 1982 Series A (Tucson
Electric Power Company General Project). (Form 10-Q for the quarter
ended March 31, 1983, File No. 1-5924--Exhibit 4(b).)
*4(j)(3)-- First Supplemental Loan Agreement, dated as of March 31, 1992,
between the Pima County Authority and the Registrant relating to
Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric
Power Company General Project) (Form S-4 dated October 2, 1992,
Registration No. 33-52860--Exhibit 4(j)(3).)
*4(j)(4)-- First Supplemental Indenture of Trust, dated as of March 31, 1992,
between the Pima County Authority and Morgan Guaranty relating to
Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric
Power Company General Project) (Form S-4 dated October 2, 1992,
Registration No. 33-52860--Exhibit 4(j)(4).)
*4(k)(1)-- Loan Agreement, dated as of December 1, 1983, between the Apache
County Authority and the Registrant relating to Floating Rate Monthly
Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson
Electric Power Company Springerville Project). (Form 10-K for year
ended December 31, 1983, File No. 1-5924--Exhibit 4(l)(1).)
*4(k)(2)-- Indenture of Trust, dated as of December 1, 1983, between the Apache
County Authority and Morgan Guaranty authorizing Floating Rate Monthly
Demand Industrial Development Revenue Bonds, 1983 Series A (Tucson
Electric Power Company Springerville Project). (Form 10-K for year
ended December 31, 1983, File No. 1-5924--Exhibit 4(l)(2).)
*4(k)(3)-- First Supplemental Loan Agreement, dated as of December 1, 1985,
between the Apache County Authority and the Registrant relating to
Floating Rate Monthly Demand Industrial Development Revenue Bonds,
1983 Series A (Tucson Electric Power Company Springerville Project).
(Form 10-K for the year ended December 31, 1987, File No. 1-5924--
Exhibit 4(k)(3).)
*4(k)(4)-- First Supplemental Indenture, dated as of December 1, 1985, between
the Apache County Authority and Morgan Guaranty relating to Floating
Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series
A (Tucson Electric Power Company Springerville Project). (Form 10-K
for the year ended December 31, 1987, File No. 1-5924--
Exhibit1-5924--Exhibit
4(k)(4).)
*4(k)(5)-- Second Supplemental Loan Agreement, dated as of March 31, 1992,
between the Apache County Authority and the Registrant relating to
Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric
Power Company Springerville Project). (Form S-4, Registration No. 33-
52860--Exhibit 4(k)(5).)
*4(k)(6)-- Second Supplemental Indenture of Trust, dated as of March 31, 1992,
between the Apache County Authority and Morgan Guaranty relating to
Industrial Development Revenue Bonds, 1983 Series A (Tucson Electric
Power Company Springerville Project). (Form S-4, Registration No. 33-52860--Exhibit33-
52860--Exhibit 4(k)(6).)
*4(l)(1)-- Loan Agreement, dated as of December 1, 1983, between the Apache
County Authority and the Registrant relating to Variable Rate Demand
Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric
Power Company Springerville Project). (Form 10-K for year ended
December 31, 1983, File No. 1-5924--Exhibit 4(m)(1).)
*4(l)(2)-- Indenture of Trust, dated as of December 1, 1983, between the Apache
County Authority and Morgan Guaranty authorizing Variable Rate Demand
Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric
Power Company Springerville Project). (Form 10-K for year ended
December 31, 1983, File No. 1-5924--Exhibit 4(m)(2).)
*4(l)(3)-- First Supplemental Loan Agreement, dated as of December 1, 1985,
between the Apache County Authority and the Registrant relating to
Floating Rate Monthly Demand Industrial Development Revenue Bonds,
1983 Series B (Tucson Electric Power Company Springerville Project).
(Form 10-K for the year ended December 31, 1987, File No. 1-5924--
Exhibit 4(l)(3).)
*4(l)(4)-- First Supplemental Indenture, dated as of December 1, 1985, between
the Apache County Authority and Morgan Guaranty relating to Floating
Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series
B (Tucson Electric Power Company Springerville Project). (Form 10-K
for the year ended December 31, 1987, File No. 1-5924--
Exhibit1-5924--Exhibit
4(l)(4).)
*4(l)(5)-- Second Supplemental Loan Agreement, dated as of March 31, 1992,
between the Apache County Authority and the Registrant relating to
Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric
Power Company Springerville Project). (Form S-4, Registration No. 33-
52860--Exhibit 4(l)(5).)
*4(l)(6)-- Second Supplemental Indenture of Trust, dated as of March 31, 1992,
between the Apache County Authority and Morgan Guaranty relating to
Industrial Development Revenue Bonds, 1983 Series B (Tucson Electric
Power Company Springerville Project). (Form S-4, Registration No. 33-52860--Exhibit33-
52860--Exhibit 4(l)(6).)
*4(m)(1)-- Loan Agreement, dated as of December 1, 1983, between the Apache
County Authority and the Registrant relating to Variable Rate Demand
Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric
Power Company Springerville Project). (Form 10-K for year ended
December 31, 1983, File No. 1-5924--Exhibit 4(n)(1).)
*4(m)(2)-- Indenture of Trust, dated as of December 1, 1983, between the Apache
County Authority and Morgan Guaranty authorizing Variable Rate Demand
Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric
Power Company Springerville Project). (Form 10-K for year ended
December 31, 1983, File No. 1-5924--Exhibit 4(n)(2).)
*4(m)(3)-- First Supplemental Loan Agreement, dated as of December 1, 1985,
between the Apache County Authority and the Registrant relating to
Floating Rate Monthly Demand Industrial Development Revenue Bonds,
1983 Series C (Tucson Electric Power Company Springerville Project).
(Form 10-K for the year ended December 31, 1987, File No. 1-5924--
Exhibit 4(m)(3).)
*4(m)(4)-- First Supplemental Indenture, dated as of December 1, 1985, between
the Apache County Authority and Morgan Guaranty relating to Floating
Rate Monthly Demand Industrial Development Revenue Bonds, 1983 Series
C (Tucson Electric Power Company Springerville Project). (Form 10-K
for the year ended December 31, 1987, File No. 1-5924--
Exhibit1-5924--Exhibit
4(m)(4).)
*4(m)(5)-- Second Supplemental Loan Agreement, dated as of March 31, 1992,
between the Apache County Authority and the Registrant relating to
Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric
Power Company Springerville Project). (Form S-4, Registration No. 33-
52860--Exhibit 4(m)(5).)
*4(m)(6)-- Second Supplemental Indenture of Trust, dated as of March 31, 1992,
between the Apache County Authority and Morgan Guaranty relating to
Industrial Development Revenue Bonds, 1983 Series C (Tucson Electric
Power Company Springerville Project). (Form S-4, Registration No. 33-52860--Exhibit33-
52860--Exhibit 4(m)(6).)
*4(n) -- Reimbursement Agreement, dated as of September 15, 1981, as amended,
between the Registrant and Manufacturers Hanover Trust Company. (Form
10-K for the year ended December 31, 1984, File No. 1-
5924--Exhibit1-5924--Exhibit
4(o)(4).)
*4(o)(1)-- Loan Agreement, dated as of December 1, 1985, between the Apache
County Authority and the Registrant relating to Variable Rate Demand
Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric
Power Company Springerville Project). (Form 10-K for the year ended
December 31, 1985, File No. 1-5924---Exhibit 4(r)(1).)
*4(o)(2)-- Indenture of Trust, dated as of December 1, 1985, between the Apache
County Authority and Morgan Guaranty authorizing Variable Rate Demand
Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric
Power Company Springerville Project). (Form 10-K for the year ended
December 31, 1985, File No. 1-5924--Exhibit 4(r)(2).)
*4(o)(3)-- First Supplemental Loan Agreement, dated as of March 31, 1992,
between the Apache County Authority and the Registrant relating to
Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric
Power Company Springerville Project). (Form S-4, Registration No. 33-
52860--Exhibit 4(o)(3).)
*4(o)(4)-- First Supplemental Indenture of Trust, dated as of March 31, 1992,
between the Apache County Authority and Morgan Guaranty relating to
Industrial Development Revenue Bonds, 1985 Series A (Tucson Electric
Power Company Springerville Project). (Form S-4, Registration No. 33-52860--Exhibit33-
52860--Exhibit 4(o)(4).)
*4(p)(1)-- Loan Agreement, dated as of February 22, 1991, between the
Industrial Development Authority of the County of Pima and the
Registrant, amending and restating the Loan Agreement, dated as of May
1, 1990, relating to Industrial Development Revenue Bonds, 1990 Series
A (Tucson Electric Power Company Project). (Form 10-K for the year
ended December 31, 1990, File No. 1-5924--Exhibit 4(p)(1).)
*4(p)(2)-- Indenture of Trust, dated as of February 22, 1991, between the
Industrial Development Authority of the County of Pima and Texas
Commerce Bank National Association, amending and restating the
Indenture of Trust, dated as of May 1, 1990, authorizing Industrial
Development Revenue Bonds, 1990 Series A (Tucson Electric Power
Company Project). (Form 10-K for the year ended December 31, 1990,
File No. 1-5924--Exhibit 4(p)(2).)
*4(q) -- Warrant Agreement and Form of Warrant, dated as of December 15, 1992.
(Form S-1, Registration No. 33-55732--Exhibit 4(q).)
*4(r)(1)-- Indenture of Mortgage and Deed of Trust dated as of December 1,
1992, to Bank of Montreal Trust Company, Trustee. (Form S-1,
Registration No. 33-55732--Exhibit 4(r)(1).)
*4(r)(2)-- Supplemental Indenture No. 1 creating a series of bonds designated
Second Mortgage Bonds, Collateral Series A, dated as of December 1,
1992. (Form S-1, Registration No. 33-55732-Exhibit 4(r)(2).)
*+10(a) -- 1985--1985 Stock Option Plan of the Registrant. (Form 10-K for the year
ended December 31, 1985, File No. 1-5924--Exhibit 10(b).)
*+10(b) -- 1987--1987 Phantom Stock Plan of the Registrant. (Form 10-K for the year
ended December 31, 1987, File No. 1-5924--Exhibit 10(c).)
*10(c)(1)-- Lease Agreements, dated as of December 1, 1984, between Valencia
Energy Company ("Valencia")
and United States Trust Company of New York, as Trustee, and Thomas B.
Zakrzewski, as Co-Trustee, as amended and supplemented. (Form 10-K for
the year ended December 31, 1984, File No. 1-5924--Exhibit 10(d)(1).)
*10(c)(2)-- Guaranty and Agreements, dated as of December 1, 1984, between
the Registrant and United States Trust Company of New York, as
Trustee, and Thomas B. Zakrzewski, as Co-Trustee. (Form 10-K for the
year ended December 31, 1984, File No. 1-5924--Exhibit 10(d)(2).)
*10(c)(3)-- General Indemnity Agreements, dated as of December 1, 1984,
between Valencia and the Registrant, as Indemnitors; General Foods
Credit Corporation, Harvey Hubbell Financial, Inc. and J. C. Penney
Company, Inc. as Owner Participants; United States Trust Company of
New York, as Owner Trustee; Teachers Insurance and Annuity Association
of America as Loan Participant; and Marine Midland Bank, N.A., as
Indenture Trustee. (Form 10-K for the year ended December 31, 1984,
File No. 1-5924--Exhibit 10(d)(3).)
*10(c)(4)-- Tax Indemnity Agreements, dated as of December 1, 1984, between
General Foods Credit Corporation, Harvey Hubbell Financial, Inc. and
J. C. Penney Company, Inc., each as Beneficiary under a separate
Trust Agreement dated December 1, 1984, with United States Trust of
New York as Owner Trustee, and Thomas B. Zakrzewski as Co-Trustee,
Lessor, and Valencia, Lessee, and the Registrant, Indemnitors. (Form
10-K for the year ended December 31, 1984, File No. 1-5924--Exhibit
10(d)(4).)
*10(c)(5)-- Amendment No. 1, dated December 31, 1984, to the Lease
Agreements, dated December 1, 1984, between Valencia and United States
Trust Company of New York, as Owner Trustee, and Thomas B. Zakrzewski
as Co-Trustee. (Form 10-K for the year ended December 31, 1986, File
No. 1-5924--Exhibit 10(e)(5).)
*10(c)(6)-- Amendment No. 2, dated April 1, 1985, to the Lease Agreements,
dated December 1, 1984, between Valencia and United States Trust
Company of New York, as Owner Trustee, and Thomas B. Zakrzewski as Co-
Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-
5924--Exhibit 10(e)(6).)
*10(c)(7)-- Amendment No. 3, dated August 1, 1985, to the Lease Agreements,
dated December 1, 1984, between Valencia and United States Trust
Company of New York, as Owner Trustee, and Thomas Zakrzewski as Co-
Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-
5924--Exhibit 10(e)(7).)
*10(c)(8)-- Amendment No. 4, dated June 1, 1986, to the Lease Agreement,
dated December 1, 1984, between Valencia and United States Trust
Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-
Trustee, under a Trust Agreement dated as of December 1, 1984, with
General Foods Credit Corporation as Owner Participant. (Form 10-K for
the year ended December 31, 1986, File No. 1-5924--Exhibit 10(e)(8).)
*10(c)(9)-- Amendment No. 4, dated June 1, 1986, to the Lease Agreement,
dated December 1, 1984, between Valencia and United States Trust
Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-
Trustee, under a Trust Agreement dated as of December 1, 1984, with J.
C. Penney Company, Inc. as Owner Participant. (Form 10-K for the year
ended December 31, 1986, File No. 1-5924--Exhibit 10(e)(9).)
*10(c)(10) -- Amendment No. 4, dated June 1, 1986, to the Lease Agreement,
dated December 1, 1984, between Valencia and United States Trust
Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-
Trustee, under a Trust Agreement dated as of December 1, 1984, with
Harvey Hubbell Financial Inc. as Owner Participant. (Form 10-K for the
year ended December 31, 1986, File No. 1-5924--Exhibit 10(e)(10).)
*10(c)(11) -- Lease Amendment No. 5 and Supplement No. 2, to the Lease
Agreement, dated July 1, 1986, between Valencia, United States Trust
Company of New York as Owner Trustee, and Thomas Zakrzewski as Co-
Trustee and J. C. Penney as Owner Participant. (Form 10-K for the year
ended December 31, 1986, File No. 1-5924--Exhibit 10(e)(11).)
*10(c)(12) -- Lease Amendment No. 5, to the Lease Agreement, dated June 1,
1987, between Valencia, United States Trust Company of New York as
Owner Trustee, and Thomas Zakrzewski as Co-Trustee and General Foods
Credit Corporation as Owner Participant. (Form 10-K for the year
ended December 31, 1988, File No. 1-5924--Exhibit 10(f)(12).)
*10(c)(13) -- Lease Amendment No. 5, to the Lease Agreement, dated June 1,
1987, between Valencia, United States Trust Company of New York as
Owner Trustee, and Thomas Zakrzewski as Co-Trustee and Harvey Hubbell
Financial Inc. as Owner Participant. (Form 10-K for the year ended
December 31, 1988, File No. 1-5924--Exhibit 10(f)(13).)
*10(c)(14) -- Lease Amendment No. 6, to the Lease Agreement, dated June 1,
1987, between Valencia, United States Trust Company of New York as
Owner Trustee, and Thomas Zakrzewski as Co-Trustee and J. C. Penney
Company, Inc. as Owner Participant. (Form 10-K for the year ended
December 31, 1988, File No. 1-5924--Exhibit 10(f)(14).)
*10(c)(15) -- Lease Supplement No. 1, dated December 31, 1984, to Lease
Agreements, dated December 1, 1984, between Valencia, as Lessee and
United States Trust Company of New York and Thomas B. Zakrzewski, as
Owner Trustee and Co-Trustee, respectively (document filed relates to
General Foods Credit Corporation; documents relating to Harvey Hubbel
Financial, Inc. and JC Penney Company, Inc. are not filed but are
substantially similar). (Form S-4, Registration No. 33-52860--Exhibit
10(f)(15).)
*10(c)(16) -- Amendment No. 1, dated June 1, 1986, to the General Indemnity
Agreement, dated as of December 1, 1984, between Valencia and the
Registrant, as Indemnitors, General Foods Credit Corporation, as Owner
Participant, United States Trust Company of New York, as Owner
Trustee, Teachers Insurance and Annuity Association of America, as
Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee.
(Form 10-K for the year ended December 31, 1986, File No. 1-5924--
Exhibit 10(e)(12).)
*10(c)(17) -- Amendment No. 1, dated June 1, 1986, to the General Indemnity
Agreement, dated as of December 1, 1984, between Valencia and the
Registrant, as Indemnitors, J. C. Penney Company, Inc., as Owner
Participant, United States Trust Company of New York, as Owner
Trustee, Teachers Insurance and Annuity Association of America, as
Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee.
(Form 10-K for the year ended December 31, 1986, File No. 1-5924--
Exhibit 10(e)(13).)
*10(c)(18) -- Amendment No. 1, dated June 1, 1986, to the General Indemnity
Agreement, dated as of December 1, 1984, between Valencia and the
Registrant, as Indemnitors, Harvey Hubbell Financial, Inc., as Owner
Participant, United States Trust Company of New York, as Owner
Trustee, Teachers Insurance and Annuity Association of America, as
Loan Participant, and Marine Midland Bank, N.A., as Indenture
Trustee. (Form 10-K for the year ended December 31, 1986, File No. 1-
5924--Exhibit 10(e)(14).)
*10(c)(19) -- Amendment No. 2, dated as of July 1, 1986, to the General
Indemnity Agreement, dated as of December 1, 1984, between Valencia
and the Registrant, as Indemnitors, J. C. Penney Company, Inc., as
Owner Participant, United States Trust Company of New York, as Owner
Trustee, Teachers Insurance and Annuity Association of America, as
Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee.
(Form S-4, Registration No. 33-52860--Exhibit 10(f)(19).)
*10(c)(20) -- Amendment No. 2, dated as of June 1, 1987, to the General
Indemnity Agreement, dated as of December 1, 1984, between Valencia
and the Registrant, as Indemnitors, General Foods Credit Corporation,
as Owner Participant, United States Trust Company of New York, as
Owner Trustee, Teachers Insurance and Annuity Association of America,
as Loan Participant, and Marine Midland Bank, N.A., as Indenture
Trustee. (Form S-4, Registration No. 33-52860--Exhibit 10(f)(20).)
*10(c)(21) -- Amendment No. 2, dated as of June 1, 1987, to the General
Indemnity Agreement, dated as of December 1, 1984, between Valencia
and the Registrant, as Indemnitors, Harvey Hubbell Financial, Inc., as
Owner Participant, United States Trust Company of New York, as Owner
Trustee, Teachers Insurance and Annuity Association of America, as
Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee.
(Form S-4, Registration No. 33-52860--Exhibit 10(f)(21).)
*10(c)(22) -- Amendment No. 3, dated as of June 1, 1987, to the General
Indemnity Agreement, dated as of December 1, 1984, between Valencia
and the Registrant, as Indemnitors, J. C. Penney Company, Inc., as
Owner Participant, United States Trust Company of New York, as Owner
Trustee, Teachers Insurance and Annuity Association of America, as
Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee.
(Form S-4, Registration No. 33-52860--Exhibit 10(f)(22).)
*10(c)(23) -- Supplemental Tax Indemnity Agreement, dated July 1, 1986,
between J. C. Penney Company, Inc., as Owner Participant, and Valencia
and the Registrant, as Indemnitors. (Form 10-K for the year ended
December 31, 1986, File No. 1-5924--Exhibit 10(e)(15).)
*10(c)(24) -- Supplemental General Indemnity Agreement, dated as of July 1,
1986, among Valencia and the Registrant, as Indemnitors, J. C. Penney
Company, Inc., as Owner Participant, United States Trust Company of
New York, as Owner Trustee, Teachers Insurance and Annuity Association
of America, as Loan Participant, and Marine Midland Bank, N.A., as
Indenture Trustee. (Form 10-K for the year ended December 31, 1986,
File No. 1-5924--Exhibit 10(e)(16).)
*10(c)(25) -- Amendment No. 1, dated as of June 1, 1987, to the Supplemental
General Indemnity Agreement, dated as of July 1, 1986, among Valencia
and the Registrant, as Indemnitors, J. C. Penney Company, Inc., as
Owner Participant, United States Trust Company of New York, as Owner
Trustee, Teachers Insurance and Annuity Association of America, as
Loan Participant, and Marine Midland Bank, N.A., as Indenture Trustee.
(Form S-4, Registration No. 33-52860--Exhibit 10(f)(25).)
*10(c)(26) -- Valencia Agreement, dated as of June 30, 1992, among the
Registrant, as Guarantor, Valencia, as Lessee, Teachers Insurance and
Annuity Association of America, as Loan Participant, Marine Midland
Bank, N.A., as Indenture Trustee, United States Trust Company of New
York, as Owner Trustee, and Thomas B. Zakrzewski, as Co-Trustee, and
the Owner Participants named therein relating to the Restructuring of
Valencia's lease of the coal-handling facilities at the Springerville
Generating Station. (Form S-4, Registration No. 33-52860--Exhibit
10(f)(26).)
*10(c)(27) -- Amendment, dated as of December 15, 1992, to the Lease
Agreements, dated December 1, 1984, between Valencia, as Lessee, and
United States Trust Company of New York, as Owner Trustee, and Thomas
B. Zakrzewski, as Co-Trustee. (Form S-1, Registration No. 33-55732--
Exhibit 10(f)(27).)
*10(d)(1)-- Lease Agreements, dated as of December 1, 1985, between the
Registrant and San Carlos Resources Inc. (San Carlos) (a wholly-owned
subsidiary of the Registrant) jointly and severally, as Lessee, and
Wilmington Trust Company, as Trustee, as amended and supplemented.
(Form 10-K for the year ended December 31, 1985, File No. 1-5924--
Exhibit 10(f)(1).)
*10(d)(2)-- Tax Indemnity Agreements, dated as of December 1, 1985, between
Philip Morris Credit Corporation, IBM Credit Financing Corporation and
Emerson Finance Co., each as beneficiary under a separate trust
agreement, dated as of December 1, 1985, with Wilmington Trust
Company, as Owner Trustee, and William J. Wade, as Co-Trustee, and the
Registrant and San Carlos, as Lessee. (Form 10-K for the year ended
December 31, 1985, File No. 1-5924--Exhibit 10(f)(2).)
*10(d)(3)-- Participation Agreement, dated as of December 1, 1985, among the
Registrant and San Carlos as Lessee, Philip Morris Credit Corporation,
IBM Credit Financing Corporation, and Emerson Finance Co. as Owner
Participants, Wilmington Trust Company as Owner Trustee, The Sumitomo
Bank, Limited, New York Branch, as Loan Participant, and Bankers Trust
Company, as Indenture Trustee. (Form 10-K for the year ended December
31, 1985, File No. 1-5924--Exhibit 10(f)(3).)
*10(d)(4)-- Restructuring Commitment Agreement, dated as of June 30, 1992,
among the Registrant and San Carlos, jointly and severally, as Lessee,
Philip Morris Credit Corporation, IBM Credit Financing Corporation and
Emerson Capital Funding William J. Wade, as Owner Trustee and
Cotrustee, respectively, The Sumitomo Bank, Limited, New York Branch,
as Loan Participant and United States Trust Company of New York, as
Indenture Trustee. (Form S-4, Registration No. 33-52860--Exhibit
10(g)(4).)
*10(d)(5)-- Lease Supplement No. 1, dated December 31, 1985, to Lease
Agreements, dated as of December 1, 1985, between the Registrant and
San Carlos, jointly and severally, as Lessee Trustee and Co-Trustee,
respectively (document filed relates to Philip Morris Credit
Corporation; documents relating to IBM Credit Financing Corporation
and Emerson Financing Co. are not filed but are substantially
similar). (Form S-4, Registration No. 33-52860--Exhibit 10(g)(5).)
*10(d)(6)-- Amendment No. 1, dated as of December 15, 1992, to Lease
Agreements, dated as of December 1, 1985, between the Registrant and
San Carlos, jointly and severally, as Lessee, and Wilmington Trust
Company and William J. Wade, as Owner Trustee and Co-Trustee,
respectively, as Lessor. (Form S-1, Registration No. 33-55732--
Exhibit 10(g)(6).)
*10(d)(7)-- Amendment No. 1, dated as of December 15, 1992, to Tax Indemnity
Agreements, dated as of December 1, 1985, between Philip Morris Credit
Corporation, IBM Credit Financing Corporation and Emerson Capital
Funding Corp., as Owner Participants and the Registrant and San
Carlos, jointly and severally, as Lessee. (Form S-1, Registration No.
33-55732--Exhibit 10(g)(7).)
*10(e)(1)-- Amended and Restated Participation Agreement, dated as of
November 15, 1987, among the Registrant, as Lessee, Ford Motor Credit
Company, as Owner Participant, Financial Security Assurance Inc., as
Surety, Wilmington Trust Company and William J. Wade in their
respective individual capacities as provided therein, but otherwise
solely as Owner Trustee and Co-Trustee under the Trust Agreement, and
Morgan Guaranty, in its individual capacity as provided therein, but
Secured Party. (Form 10-K for the year ended December 31, 1987, File
No. 1-5924--Exhibit 10(j)(1).)
*10(e)(2)-- Lease Agreement, dated as of January 14, 1988, between
Wilmington Trust Company and William J. Wade, as Owner Trust Agreement
described therein, dated as of November 15, 1987, between such parties
and Ford Motor Credit Company, as Lessor, and the Registrant, as
Lessee. (Form 10-K for the year ended December 31, 1987, File No. 1-
5924--Exhibit 10(j)(2).)
*10(e)(3)-- Tax Indemnity Agreement, dated as of January 14, 1988, between
the Registrant, as Lessee, and Ford Motor Credit Company, as Owner
Participant, beneficiary under a Trust Agreement, dated as of November
15, 1987, with Wilmington Trust Company and William J. Wade, Owner
Trustee and Co-Trustee, respectively, together as Lessor. (Form 10-K
for the year ended December 31, 1987, File No. 1-5924--Exhibit
10(j)(3).)
*10(e)(4)-- Loan Agreement, dated as of January 14, 1988, between the Pima
County Authority and Wilmington Trust Company and William J. Wade in
their respective individual capacities as expressly stated, but
otherwise solely as Owner Trustee and Co-Trustee, respectively, under
and pursuant to a Trust Agreement, dated as of November 15, 1987, with
Ford Motor Credit Company as Trustor and Debtor relating to Industrial
Development Lease Obligation Refunding Revenue Bonds, 1988 Series A
(the Registrant's Irvington Project). (Form 10-K for the year ended
December 31, 1987, File No. 1-5924--Exhibit 10(j)(4).)
*10(e)(5)-- Indenture of Trust, dated as of January 14, 1988, between the
Pima County Authority and Morgan Guaranty authorizing Industrial
Development Lease Obligation Refunding Revenue Bonds, 1988 Series A
(Tucson Electric Power Company Irvington Project). (Form 10-K for the
year ended December 31, 1987, File No. 1-5924--Exhibit 10(j)(5).)
*10(e)(6)-- Lease Amendment No. 1, dated as of May 1, 1989, between the
Registrant, Wilmington Trust Company and William J. Wade as Owner
Trustee and Co-trustee, respectively under a Trust Agreement dated as
of November 15, 1987 with Ford Motor Credit Company. (Form 10-K for
the year ended December 31,1990,31, 1990, File No. 1-5924--Exhibit 10(i)(6).)
*10(e)(7)-- Lease Supplement, dated as of January 1, 1991, between the
Registrant, Wilmington Trust Company and William J. Wade as Owner
Trustee and Co-Trustee, respectively, under a Trust Agreement dated as
of November 15, 1987, with Ford. (Form 10K for the year ended December
31, 1991, File No. 1-5924--Exhibit 10(i)(8).)
*10(e)(8)-- Lease Supplement, dated as of March 1, 1991, between the
Registrant, Wilmington Trust Company and William J. Wade as Owner
Trustee and Co-Trustee, respectively, under a Trust Agreement dated as
of November 15, 1987, with Ford. (Form 10-K for the year ended
December 31, 1991, File No. 1-5924--Exhibit 10(i)(9).)
*10(e)(9)-- Lease Supplement No. 4, dated as of December 1, 1991, between
the Registrant, Wilmington Trust Company and William J. Wade as Owner
Trustee and Co-Trustee, respectively, under a Trust Agreement dated as
of November 15, 1987, with Ford. (Form 10-K for the year ended
December 31, 1991, File No. 1-5924--Exhibit 10(i)(10).)
*10(e)(10) -- Supplemental Indenture No. 1, dated as of December 1, 1991,
between the Pima County Authority and Morgan Guaranty relating to
Industrial Lease Development Obligation Revenue Project). (Form 10-K
for the year ended December 31, 1991, File No. 1-5924--Exhibit
10(i)10(I)(11).)
*10(e)(11) -- Restructuring Commitment Agreement, dated as of June 30, 1992,
among the Registrant, as Lessee, Ford Motor Credit Company, as Owner
Participant, Wilmington Trust Company and William J. Wade, as Owner
Trustee and Co-Trustee, respectively, and Morgan Guaranty, as
Indenture Trustee and Refunding Trustee, relating to the restructuring
of the Registrant's lease of Unit 4 at the Irvington Generating
Station. (Form S-4, Registration No. 33-52860--Exhibit 10(i)(12).)
*10(e)(12) -- Amendment No. 1, dated as of December 15, 1992, to Amended and
Restated Participation Agreement, dated as of November 15, 1987, among
the Registrant, as Lessee, Ford Motor Credit Company, as Owner
Participant, Wilmington Trust Company and William J. Wade, as Owner
Trustee and Co-Trustee, respectively, Financial Security Assurance
Inc., as Surety, and Morgan Guaranty, as Indenture Trustee. (Form S-
1, Registration No. 33-55732--Exhibit 10(h)(12).)
*10(e)(13) -- Amended and Restated Lease, dated as of December 15, 1992,
between the Registrant, as Lessee and Wilmington Trust Company and
William J. Wade, as Owner Trustee and Co-Trustee, respectively, as
Lessor. (Form S-1, Registration No. 33-55732--Exhibit 10(h)(13).)
*10(e)(14) -- Amended and Restated Tax Indemnity Agreement, dated as of
December 15, 1992, between the Registrant, as Lessee, and Ford Motor
Credit Company, as Owner Participant. (Form S-1, Registration No. 33-
55732--Exhibit 10(h)(14).)
*10(f)-- Power Sale Agreement for the years 1990 to 2011, dated as of March 10,
1988, between the Registrant and Salt River Project Agricultural
Improvement and Power District. (Form 10-K for the year ended December
31, 1987, File No. 1-5924--Exhibit 10(k).)
*+10(g)(1) -- Employment Agreements between the Registrant and Thomas A.
Delawder and Gary L. Ellerd. (Form 10-K for the year ended December
31, 1987, File No. 1-5924--Exhibit 10(l).)
*+10(g)(2) -- Employment Agreements between the Registrant and currently in
effect with Ira R. Adler, Charles E. Bayless, Karen G. Kissinger,
George W. Miraben, Dennis R. Nelson, Gerald A. O'Brien, Susan R.
Wallach, James S. Pignatelli and Steven J. Glaser. (Form 10-K for the
year ended December 31, 1989, File No. 1-5924--Exhibit 10(n)(2).)
+10(g)*+10(g)(3)-- Release and Proposed Settlement Agreement between the Registrant
and Frederic N. Finney. +10(g)(Form 10-K for the year ended December 31,
1994, File No. 1-5924--Exhibit 10(g)(3).)
*+10(g)(4)-- Release and Proposed Settlement Agreement between the Registrant
and Norman B. Johnsen. (Form 10-K for the year ended December 31,
1994, File No. 1-5924--Exhibit 10(g)(4).)
*10(g)(5)-- Letter, dated February 25, 1992, from Dr. Martha R. Seger to the
Registrant and Capital Holding Corporation. (Form S-4, Registration
No. 33-52860--Exhibit 10(k)(4).)
*+10(g)(6) -- Employment Agreement between the Registrant and Thomas N.
Hansen. (Form 10-K for the year ended December 31, 1993, File No. 1-
5924--Exhibit 10(i)(5).)
*10(h)-- Power Sale Agreement, dated April 29, 1988, for the dates of May 16,
1990 to December 31, 1995, between the Registrant and Nevada Power
Company. (Form 10-K for the year ended December 31, 1988, File No 1-
5924--Exhibit 10(m)(2).)
*10(i)-- Master Restructuring Agreement, dated as of June 30, 1992, among the
Registrant, Escavada Company, Gallo Wash Development Company,
Valencia, Barclays Bank PLC, New York Branch, as administrative agent
and collateral agent and the several banks parties thereto. (Form S-4,
Registration No. 33-52860--Exhibit 10(bb).)
*10(j)-- Amendment No. 1, dated as of December 15 , 1992, to Master
Restructuring Agreement, dated as of June 30, 1992, among the
Registrant, Escavada Company, Gallo Wash Development Company,
Valencia, Barclays Bank PLC, New York Branch, as administrative agent
and collateral agent and the several banks parties thereto. (Form S-
1, Registration No. 33-55732--Exhibit 10(s)(2).)
*10(k)-- Amendment No. 2, dated as of October 12, 1993, to Master Restructuring
Agreement, dated as of June 30, 1992, among the Registrant, Escavada
Company, Gallo Wash Development Company, Valencia, Barclays Bank PLC,
New York Branch, as administrative agent and collateral agent and the
several banks parties thereto. (Form 10-
K10-K for the year ended December
31, 1993, File No. 1-5924--Exhibit 10(n).)
*10(l)-- Amendment No. 3, dated as of December 20, 1993, to Master
Restructuring Agreement, dated as of June 30, 1992, among the
Registrant, Escavada Company, Gallo Wash Development Company,
Valencia, Barclays Bank PLC, New York Branch, as administrative agent
and collateral agent and the several banks parties thereto. (Form 10-
K for the year ended December 31, 1993, File No. 1-5924--Exhibit
10(o).)
*10(m)-- Amendment No. 4, dated as of April 13, 1994, to Master Restructuring
Agreement, dated as of June 30, 1992, among the Registrant, Escavada
Company, Gallo Wash Development Company, Valencia, Barclays Bank PLC,
New York Branch, as administrative agent and collateral agent and the
several banks parties thereto. (Form 10-
Q10-Q for the quarter ended June
30, 1994, File No. 1-5924--Exhibit 10(a).)
*10(n)-- Amendment No. 5, dated as of June 30, 1994, to Master Restructuring
Agreement, dated as of June 30, 1992, among the Registrant, Escavada
Company, Gallo Wash Development Company, Valencia, Barclays Bank PLC,
New York Branch, as administrative agent and collateral agent and the
several banks parties thereto. (Form 10-
Q10-Q for the quarter ended June
30, 1994, File No. 1-5924--Exhibit 10(b).)
10(o) *10(o)-- Amendment No. 6, dated as of November 1, 1994, to Master Restructuring
Agreement, dated as of June 30, 1992, among the Registrant, Escavada
Company, Gallo Wash Development Company, Valencia, Barclays Bank PLC,
New York Branch, as administrative agent and collateral agent and the
several banks parties thereto. (Form 10-K for the year ended December
31, 1994, File No. 1-5924--Exhibit 10(o).)
*10(p)-- Deed of Trust, Assignment of Rents and Leases and Security Agreement,
dated as of June 30, 1992, from San Carlos to Transamerica Title
Insurance Company, as trustee for the use and benefit of Barclays Bank
PLC, New York Branch, as collateral agent. (Form S-1, Registration
No. 33-55732--Exhibit 10(t).)
*10(q)-- Participation Agreement, dated as of June 30, 1992, among the
Registrant, as Lessee, various parties thereto, as Owner Wilmington
Trust Company and William J. Wade, as Owner Trustee and Co-Trustee,
respectively, and LaSalle National Bank, as Indenture Trustee relating
to the Registrant's lease of Springerville Unit 1. (Form S-1,
Registration No. 33-55732--Exhibit 10(u).)
*10(r)-- Lease Agreement, dated as of December 15, 1992, between the
Registrant, as Lessee and Wilmington Trust Company and William J.
Wade, as Owner Trustee and Co-Trustee, respectively, as Lessor. (Form
S-1, Registration No. 33-55732--Exhibit 10(v).)
*10(s)-- Tax Indemnity Agreements, dated as of December 15, 1992, between the
various Owner Participants parties thereto and the Registrant, as
Lessee. (Form S-1, Registration No. 33-55732, Exhibit 10(w).)
*10(t)-- Restructuring Agreement, dated as of December 1, 1992, between the
Registrant and Century Power Corporation. (Form S-1, Registration No.
33-55732--Exhibit 10(x).)
*10(u)-- Voting Agreement, dated as of December 15, 1992, between the
Registrant and Chrysler Capital Corporation (documents relating to
CILCORP Lease Management, Inc., MWR Capital Inc., US West Financial
Services, Inc. and Philip Morris Capital Corporation are not filed but
are substantially similar). (Form S-1, Registration No. 33-55732--
Exhibit 10(y).)
*10(v)-- Wholesale Power Supply Agreement between the Registrant and Navajo
Tribal Utility Authority dated January 5, 1993. (Form 10-K for the
year ended December 31, 1992, File No. 1-5924--Exhibit 10(t).)
11 -- Statement re computation of per share earnings.
21 -- Subsidiaries of the Registrant.
23 -- Consents of experts and counsel.
24 -- Power of Attorney.
2727a -- Financial Data Schedule.
27b -- Financial Data Schedule.
(*)Previously filed as indicated and incorporated herein by reference.
(+)Management contracts or compensatory plans or arrangements required to be
filed as exhibits to this Form 10-K by item 601(10)(iii) of Regulation S-K.