UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO
SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended June 30, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO
SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________.
Commission File Number 1-5924
TUCSON ELECTRIC POWER COMPANY
(Exact Name of Registrant as Specified in its Charter)
ARIZONA 86-0062700
(State or Other Jurisdiction of (IRS Employer
Incorporation or Organization) Identification No.)
220 WEST SIXTH STREET, TUCSON, ARIZONA P.O. BOX 711
85701 85702
(Address of Principal Executive Offices) (Zip Code)
(520) 571-4000
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
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 _____
At August 7, 1997, 32,135,207 shares of the registrant's Common Stock,
no par value (the only class of Common Stock), were outstanding.
TABLE OF CONTENTS
Page
Definitions..............................................................ii
Independent Accountants' Report...........................................1
PART I - FINANCIAL INFORMATION
Item 1. -- Financial Statements
Comparative Condensed Consolidated Statements of Income..............2
Comparative Condensed Consolidated Statements of Cash Flows..........3
Comparative Condensed Consolidated Balance Sheets....................4
Notes to Condensed Consolidated Financial Statements
Note 1. Tax Assessments.............................................5
Note 2. Rate Matters................................................6
Note 3. Springerville Coal Contract.................................6
Note 4. Consolidated Subsidiaries...................................6
Note 5. Long-Term Debt..............................................6
Note 6. Income Taxes................................................7
Note 7. New Accounting Standard.....................................8
Note 8. Reclassifications...........................................8
Item 2. -- Management's Discussion and Analysis of Financial Condition and
Results of Operations
Overview.............................................................9
Competition
Wholesale.......................................................10
Retail..........................................................11
Holding Company Proposal............................................13
Retail Rate Proposal................................................13
Accounting for the Effects of Regulation............................14
Dividends on Common Stock...........................................15
Earnings............................................................15
Results of Operations
Results of Utility Operations
Sales and Revenues..............................................16
Operating Expenses..............................................17
Other Income....................................................17
Events Affecting Future Results of Utility Operations
NTUA Wholesale Power Contract...................................18
Springerville Coal Supply Contract..............................18
Liquidity and Capital Resources..........................................19
Cash Flows..........................................................19
Financing Developments
Sale of New Bonds...............................................19
Financing Application Filed with ACC............................20
Safe Harbor for Forward-Looking Statements...............................20
PART II - OTHER INFORMATION
Item 1. -- Legal Proceedings
Tax Assessments..................................................22
Item 4. -- Submission of Matters to a Vote of Security Holders...........22
Item 6. -- Exhibits and Reports on Form 8-K..............................22
Signature Page...........................................................23
DEFINITIONS
The abbreviations and acronyms used in the 1997 Second Quarter Form 10-Q are
defined below:
ACC............... Arizona Corporation Commission.
ADOR.............. Arizona Department of Revenue.
Common Stock...... The Company's common stock, without par value.
Company or TEP.... Tucson Electric Power Company.
EITF.............. Emerging Issues Task Force of the Financial Accounting
Standards Board.
FAS 71............ Statement of Financial Accounting Standards #71:
Accounting for the Effects of Certain Types of
Regulation.
FAS 101........... Statement of Financial Accounting Standards #101:
Regulated Enterprises - Accounting for the
Discontinuation of Application of FAS 71.
FAS 121........... Statement of Financial Accounting Standards #121:
Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed Of.
FERC.............. Federal Energy Regulatory Commission.
First Mortgage
Bonds............ First mortgage bonds issued under the General First
Mortgage.
General First
Mortgage......... The Indenture, dated as of April 1, 1941, of Tucson Gas,
Electric Light and Power Company to The Chase National
Bank of the City of New York, as trustee, as supplemented
and amended.
IDBs.............. Industrial development revenue or pollution control bonds.
Irvington......... Irvington Generating Station.
Irvington Lease... The leveraged lease arrangement relating to Irvington Unit
4.
kWh............... Kilowatt-hour(s).
MRA............... Master restructuring agreement between the Company and the
Banks which includes the Renewable Term Loan, Revolving
Credit and certain replacement reimbursement agreements.
MSR............... Modesto, Santa Clara and Redding Public Power Agency.
MW................ Megawatt(s).
1994 Rate Order... ACC Rate Order concerning an increase in the Company's
retail base rates and certain regulatory write-offs,
issued January 11, 1994.
1996 Rate Order......ACC Rate Order concerning an increase in the Company's
retail base rates and the recovery of Springerville Unit
2 costs, issued March 29, 1996.
NTUA.............. Navajo Tribal Utility Authority.
NOL............... Net Operating Loss carryforward for income tax purposes.
Renewable Term
Loan............. Credit facility that replaced the Term Loan pursuant to
the MRA Sixth Amendment, dated as of November 1, 1994,
and effective March 7, 1995.
Revolving Credit.. $50 million revolving credit facility entered into between
a syndicate of banks and the Company.
SEC............... Securities and Exchange Commission.
Shareholders...... Holders of Common Stock.
Springerville..... Springerville Generating Station.
Springerville Coal
Handling Facilities
Leases........... Leveraged lease arrangements relating to the coal handling
facilities serving Springerville.
Springerville Common
Facilities
Leases........... Leveraged lease arrangements relating to one-half interest
in certain facilities at Springerville used in common
with Springerville Unit 1 and Springerville Unit 2.
Springerville
Unit 1 Leases..... Leveraged lease arrangements relating to Springerville
Unit 1, and one half interest in certain facilities at
Springerville used in common with Springerville Unit 1
and Springerville Unit 2.
SSP............... Shared Savings Proposal filed with the ACC July 9, 1997
requesting a 1.1% annual retail rate reduction.
Valencia.......... Valencia Energy Company, previously a wholly-owned
subsidiary of the Company, merged into the Company on May
31, 1996.
VSP............... Voluntary Severance Plan offered to Company employees and
implemented in May 1996.
INDEPENDENT ACCOUNTANTS' REVIEW REPORT
Tucson Electric Power Company and its Stockholders
220 West Sixth Street
Tucson, Arizona 85701
We have reviewed the accompanying condensed consolidated balance sheet of
Tucson Electric Power Company and subsidiaries (the Company) as of June 30,
1997 and the related condensed consolidated statements of income for the
three-month and six-month periods ended June 30, 1997 and 1996 and cash flows
for the six-month periods ended June 30, 1997 and 1996. These financial
statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established by the
American Institute of Certified Public Accountants. A review of interim
financial information consists principally of applying analytical procedures
to financial data and of making inquiries of persons responsible for financial
and accounting matters. It is substantially less in scope than an audit
conducted in accordance with generally accepted auditing standards, the
objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to such condensed consolidated financial statements for them to be in
conformity with generally accepted accounting principles.
We have previously audited, in accordance with generally accepted auditing
standards, the consolidated balance sheet and statement of capitalization of
the Company as of December 31, 1996 and the related consolidated statements of
income, cash flows, and changes in stockholders' equity (deficit) for the year
then ended (not presented herein); and in our report dated January 27, 1997, we
expressed an unqualified opinion on those consolidated financial statements. In
our opinion, the information set forth in the accompanying condensed
consolidated balance sheet as of December 31, 1996 is fairly stated, in all
material respects, in relation to the consolidated balance sheet from which it
has been derived.
DELOITTE & TOUCHE LLP
Tucson, Arizona
July 31, 1997
PART I - FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
- -----------------------------------------------------------------------------
The June 30 condensed consolidated financial statements are unaudited
but reflect all normal recurring accruals and other adjustments which are, in
the opinion of management, necessary for a fair presentation of the results
for the interim periods covered. Due to seasonal fluctuations in sales, the
quarterly results are not indicative of annual operating results. Also see
Item 2. - Management's Discussion and Analysis of Financial Condition and
Results of Operations.
COMPARATIVE CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended
June 30,
1997 1996
-Thousands of Dollars-
Operating Revenues
Retail Customers $159,249 $162,040
Amortization of MSR Option Gain Regulatory Liability 3,092 5,013
Sales for Resale 20,629 17,480
--------- ---------
Total Operating Revenues 182,970 184,533
--------- ---------
Operating Expenses
Fuel and Purchased Power 51,493 50,106
Capital Lease Expense 26,388 26,444
Amortization of Springerville Unit 1 Allowance (7,010) (7,272)
Other Operations 28,087 24,360
Maintenance and Repairs 11,384 8,820
Depreciation and Amortization 21,445 24,797
Taxes Other Than Income Taxes 13,093 14,686
Voluntary Severance Plan Expense - 13,998
Income Taxes 4,260 1,484
--------- ---------
Total Operating Expenses 149,140 157,423
--------- ---------
Operating Income 33,830 27,110
--------- ---------
Other Income (Deductions)
Income Taxes 11,385 6,504
Reversal of Loss Provision 10,154 -
Interest Income 2,643 1,429
Other Income (Deductions) (925) 631
--------- ---------
Total Other Income (Deductions) 23,257 8,564
--------- ---------
Interest Expense
Long-Term Debt - Net 16,453 15,113
Interest Imputed on Losses Recorded at Present Value 8,175 8,223
Other Interest Expense 2,558 2,049
--------- ---------
Total Interest Expense 27,186 25,385
--------- ---------
Net Income $ 29,901 $ 10,289
========= =========
Average Shares of Common Stock Outstanding (000) 32,135 32,133
========= =========
Net Income per Average Share $ 0.93 $ 0.32
========= =========
See Notes to Condensed Consolidated Financial Statements.
COMPARATIVE CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Six Months Ended
June 30,
1997 1996
-Thousands of Dollars-
Operating Revenues
Retail Customers $289,186 $287,250
Amortization of MSR Option Gain Regulatory Liability 8,105 10,026
Sales for Resale 39,960 35,285
--------- ---------
Total Operating Revenues 337,251 332,561
--------- ---------
Operating Expenses
Fuel and Purchased Power 97,139 95,930
Capital Lease Expense 52,664 52,249
Amortization of Springerville Unit 1 Allowance (14,019) (14,545)
Other Operations 54,383 48,448
Maintenance and Repairs 21,615 18,354
Depreciation and Amortization 43,219 48,550
Taxes Other Than Income Taxes 25,718 29,737
Voluntary Severance Plan Expense - 13,998
Income Taxes 1,912 (4,388)
--------- ---------
Total Operating Expenses 282,631 288,333
--------- ---------
Operating Income 54,620 44,228
--------- ---------
Other Income (Deductions)
Income Taxes 25,943 13,861
Reversal of Loss Provision 10,154 -
Interest Income 4,399 2,902
Other Income (Deductions) (1,935) 69
--------- ---------
Total Other Income (Deductions) 38,561 16,832
--------- ---------
Interest Expense
Long-Term Debt - Net 30,570 29,757
Interest Imputed on Losses Recorded at Present Value 16,454 16,586
Other Interest Expense 4,764 4,009
--------- ---------
Total Interest Expense 51,788 50,352
--------- ---------
Net Income $ 41,393 $ 10,708
========= =========
Average Shares of Common Stock Outstanding (000) 32,135 32,134
========= =========
Net Income per Average Share $ 1.29 $ 0.33
========= =========
See Notes to Condensed Consolidated Financial Statements.
COMPARATIVE CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Six Months Ended
June 30,
1997 1996
-Thousands of Dollars-
Cash Flows from Operating Activities
Cash Receipts from Retail Customers $293,113 $288,828
Cash Receipts from Sales for Resale 42,635 35,319
Fuel and Purchased Power Costs Paid (90,574) (84,282)
Wages Paid, Net of Amounts Capitalized (32,899) (37,364)
Payment of Other Operations and Maintenance Costs (45,359) (36,099)
Capital Lease Interest Paid (40,774) (41,233)
Interest Paid, Net of Amounts Capitalized (34,777) (35,450)
Taxes Paid, Net of Amounts Capitalized (48,559) (53,361)
Contract Termination Fee Paid (30,000) -
Emission Allowance Inventory Sale - 4,120
Interest Received 3,958 2,920
Other 660 (2,355)
--------- ---------
Net Cash Flows - Operating Activities 17,424 41,043
--------- ---------
Cash Flows from Investing Activities
Construction Expenditures (33,870) (36,690)
Investments in Joint Ventures (2,117) (4,600)
Other 980 233
--------- ---------
Net Cash Flows - Investing Activities (35,007) (41,057)
--------- ---------
Cash Flows from Financing Activities
Proceeds from Issuance of Long-Term Debt 124,122 31,400
Payments to Retire Long-Term Debt (112,310) (25,200)
Payments on Renewable Term Loan (31,000) -
Payments to Retire Capital Lease Obligations (4,751) (4,787)
Other (568) (234)
--------- ---------
Net Cash Flows - Financing Activities (24,507) 1,179
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (42,090) 1,165
Cash and Cash Equivalents, Beginning of Year 130,291 85,094
--------- ---------
Cash and Cash Equivalents, End of Period $ 88,201 $ 86,259
========= =========
See Notes to Condensed Consolidated Financial Statements.
SUPPLEMENTAL CONDENSED CONSOLIDATED CASH FLOW INFORMATION
Six Months Ended
June 30,
1997 1996
-Thousands of Dollars-
Net Income $ 41,393 $ 10,708
Adjustments to Reconcile Net Income
to Net Cash Flows
Depreciation and Amortization Expense 43,219 48,550
Deferred Income Taxes and
Investment Tax Credits - Net (24,280) (18,286)
Lease Payments Deferred 17,750 16,600
Regulatory Amortizations, Net of Interest Imputed
on Losses Recorded at Present Value (5,669) (7,985)
Contract Termination Fee (30,000) -
Other (11,399) (3,084)
Changes in Assets and Liabilities which
Provided (Used) Cash Exclusive of
Changes Shown Separately
Accounts Receivable (16,314) (18,096)
Materials and Fuel (7,342) 428
Accounts Payable 9,113 8,214
Taxes Accrued 9 2,025
Other Current Assets and Liabilities (2,998) (6,127)
Other Deferred Assets and Liabilities 3,942 8,096
--------- ---------
Net Cash Flows - Operating Activities $ 17,424 $ 41,043
========= =========
See Notes to Condensed Consolidated Financial Statements.
COMPARATIVE CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, December 31,
1997 1996
- Thousands of Dollars -
Utility Plant
Plant in Service $2,151,022 $2,129,205
Utility Plant Under Capital Leases 893,064 893,064
Construction Work in Progress 83,001 74,210
----------- -----------
Total Utility Plant 3,127,087 3,096,479
Less Accumulated Depreciation and Amortization (955,207) (922,947)
Less Accumulated Amortization of Capital Leases (64,839) (56,240)
Less Springerville Unit 1 Allowance (165,572) (163,388)
----------- -----------
Total Utility Plant - Net 1,941,469 1,953,904
----------- -----------
Investments and Other Property 70,999 69,289
----------- -----------
Current Assets
Cash and Cash Equivalents 88,201 130,291
Accounts Receivable 82,219 65,905
Materials and Fuel 37,698 30,356
Deferred Income Taxes - Current 13,653 10,223
Other 15,519 14,026
----------- -----------
Total Current Assets 237,290 250,801
----------- -----------
Deferred Debits - Regulatory Assets
Income Taxes Recoverable Through Future Rates 170,912 173,731
Deferred Common Facility Costs 59,492 60,762
Deferred Contract Termination Fee 50,000 -
Deferred Springerville Unit 2 Costs 16,235 21,260
Deferred Lease Expense 13,118 15,067
Other Deferred Regulatory Assets 8,679 8,004
Deferred Debits - Other 15,725 15,723
----------- -----------
Total Deferred Debits 334,161 294,547
----------- -----------
Total Assets $2,583,919 $2,568,541
=========== ===========
See Notes to Condensed Consolidated Financial Statements.
COMPARATIVE CONDENSED CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND OTHER LIABILITIES
June 30, December 31,
1997 1996
- Thousands of Dollars -
Capitalization
Common Stock $ 645,230 $ 645,243
Capital Stock Expense (6,357) (6,357)
Accumulated Deficit (464,205) (505,598)
----------- -----------
Common Stock Equity 174,668 133,288
Capital Lease Obligations 892,020 895,867
Long-Term Debt 1,204,967 1,223,025
----------- -----------
Total Capitalization 2,271,655 2,252,180
----------- -----------
Current Liabilities
Short-Term Debt - 3,567
Current Obligations Under Capital Leases 16,427 10,383
Current Maturities of Long-Term Debt 500 1,635
Accounts Payable 37,919 28,806
Interest Accrued 58,968 57,404
Taxes Accrued 24,016 24,007
Contract Termination Fee Payable 20,000 -
Other 14,924 15,614
----------- -----------
Total Current Liabilities 172,754 141,416
----------- -----------
Deferred Credits and Other Liabilities
Deferred Income Taxes - Noncurrent 74,693 96,422
Accumulated Deferred Investment Tax Credits
Regulatory Liability 13,246 15,188
MSR Option Gain Regulatory Liability - 7,853
Other Regulatory Liabilities 17,574 17,596
Other 33,997 37,886
----------- -----------
Total Deferred Credits and Other Liabilities 139,510 174,945
----------- -----------
Total Capitalization and Other Liabilities $2,583,919 $2,568,541
=========== ===========
See Notes to Condensed Consolidated Financial Statements.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
- -----------------------------------------------------------------------------
NOTE 1. TAX ASSESSMENTS
- ------------------------
Ruling on Arizona Sales Tax Assessments - Coal Sales
The Arizona Department of Revenue (ADOR) issued transaction privilege
(sales) tax assessments to the Company alleging that Valencia was liable for
sales tax on gross income received from coal sales, transportation and coal-
handling services to the Company for the period November 1985 through May
1993. The Company protested these assessments. On September 12, 1996, the
Arizona Court of Appeals upheld the validity of the assessment issued for the
period November 1985 through March 1990. On July 1, 1997, the Arizona
Supreme Court granted a Petition for Review filed by the Company.
Additionally, the Company is protesting the assessments for the period April
1990 through May 1993.
Previously, the Company had recorded an expense through the Consolidated
Statements of Income (Loss) and related liability for the amount of sales
taxes and interest thereon which the Company believed was probable of
incurrence. The amounts recorded by the Company included estimates for the
period June 1993 through May 1996, the period for which the Company has not
yet been assessed. Generally, Arizona law requires payment of an assessment
prior to pursuing the appellate process. The Company has previously paid,
under protest, a total of $23 million of the disputed sales tax assessments,
subject to refund in the event the Company prevails.
On May 31, 1996, Valencia was merged into the Company. Effective with
the merger, Valencia no longer supplies coal to the Company. Instead the
Company acquires coal directly from the supplier. As a result, the Company
believes it is not liable for transaction privilege tax computed on a basis
similar to the assessments described above subsequent to May 31, 1996. For
periods subsequent to May 31, 1996, the Company continues to record an
estimated interest expense on the above assessments.
Arizona Sales Tax Assessments - Leases
The ADOR has issued transaction privilege (sales) tax assessments to the
lessors from whom the Company leases certain property. The assessments
allege sales tax liability on a component of rents paid by the Company on the
Springerville Unit 1 Leases, Springerville Common Facilities Leases,
Irvington Lease and Springerville Coal Handling Facilities Leases.
Assessments cover the period August 1, 1988 to September 30, 1993. Under the
terms of the lease agreements, if the ADOR prevails the Company must
reimburse the lessors for taxes paid by them pursuant to indemnification
provisions.
In the opinion of management, the Company has recorded, through the
Consolidated Statements of Income (Loss) in current and prior years, a
liability for the amount of state taxes and interest thereon for which the
Company believes incurrence is probable as of June 30, 1997. In the event
that the assessments by the ADOR are sustained, an additional liability would
result. Although it is reasonably possible that the ultimate resolution of
such matter could result in an additional sales tax expense of up to
approximately $21 million in excess of amounts recorded, management and
outside tax counsel believe that the Company has meritorious defenses to
mitigate or eliminate the assessed amounts.
Based on the current status of the legal proceedings, the Company
believes that the ultimate resolution of such dispute will occur over a
period of two to four years. Based on consultations with counsel and
considering the amounts already accrued, the Company believes that the
resolution of this tax matter should not have a material adverse effect on
the Company's Consolidated Financial Statements.
NOTE 2. RATE MATTERS
- ---------------------
On July 9, 1997, the Company filed with the ACC a request for an annual
rate reduction of $6.8 million (or 1.1%) for retail customers. This filing
is in the form of a Shared Savings Proposal (SSP) which promotes a sharing of
benefits with customers of cost containment efforts and the mitigation of
potential stranded costs associated with the introduction of retail electric
competition in Arizona. The cost containment savings were realized primarily
from renegotiated fuel contracts and the Company's Voluntary Severance
Program, which reduced the Company's workforce by approximately 15%. No date
has been set for formal consideration of the matter by the ACC.
The Company proposed that additional savings be used by the Company to
mitigate potential stranded costs through accelerated amortization of retail
excess capacity deferrals. Retail excess capacity deferrals represent those
operating and capital costs associated with Springerville Unit 2 capacity,
which were deemed by the ACC to not be recoverable in retail rates prior to
the 1994 and 1996 Rate Orders. Such retail excess capacity deferrals totaled
$91.1 million and $93.6 million at June 30, 1997 and December 31, 1996,
respectively. Such deferrals are not reflected in the accompanying Condensed
Consolidated Balance Sheets because such retail excess capacity deferrals,
while deferred for regulatory purposes, were not deferred for financial
reporting purposes but were expensed as incurred. The proposed $7.2 million
increase in annual amortization expense for such excess capacity deferrals
would decrease the amortization period from 20 years to 7.76 years. The
proposed increase in amortization expense would be reflected in the Company's
regulatory accounting records but would have no impact on the expenses
included in the Company's financial accounting statements.
NOTE 3. SPRINGERVILLE COAL CONTRACT
- ------------------------------------
On June 27, 1997, the Company signed an agreement with the coal supplier
for the Springerville Generating Station to terminate the existing coal
supply contract and enter into a new, more cost effective contract with the
same supplier. A $50 million termination fee was incurred by the Company and
is payable in three installments: $30 million paid on June 30, 1997, $10
million due September 30, 1997, and $10 million due March 31, 1998. The
previous coal supply contract covered the useful lives of Springerville Units
1 and 2 and contained a bilateral option to renegotiate the contract price
and escalation procedures in 2009 and every five years thereafter. The new
coal contract has an initial term of 13 years, beginning July 1, 1997, with
an extended term of ten years thereafter. The new contract also contains more
favorable terms to the Company for certain volume, incremental volume, base
price, incremental price and price adjustment mechanism requirements.
The Company applied, as part of the SSP, to the ACC requesting that the
termination fee be recorded as a regulatory asset and amortized to fuel
expense over the 13-year term of the new agreement. On July 29, 1997, the
ACC issued an interim accounting order allowing the Company to defer the $50
million termination fee as a regulatory asset in the Company's Condensed
Consolidated Balance Sheet until the ACC decides whether the $50 million
termination fee should be recovered through retail rates. The interim
accounting order also allows the Company to begin amortizing the termination
fee to fuel expense. If the ACC ultimately disallows recovery, the
unamortized portion of the $50 million termination fee would immediately be
expensed. The Company expects that the ACC will make a final determination
as to the regulatory treatment for the termination fee before the end of
1997.
NOTE 4. CONSOLIDATED SUBSIDIARIES
- ----------------------------------
Upon dissolution of certain subsidiaries which formed a part of the
Company's former investment operations, in June 1997, the Company reversed a
provision for loss, recorded in prior years, resulting in income of
approximately $10.2 million.
NOTE 5. LONG-TERM DEBT
- -----------------------
In February 1997, the Company repaid the outstanding Renewable Term Loan
balance of $31 million thereby reducing its Long-Term Debt. At June 30,
1997, the Company had $134 million available for borrowing under the
Renewable Term Loan.
In April 1997, the City of Farmington, New Mexico issued $80.4 million
of Pollution Control Revenue Bonds for the benefit of the Company. The
proceeds were used in June 1997 to redeem $47.9 million principal amount of
previously issued 6.25% bonds that matured in 2003 and $32.5 million
principal amount of previously issued 6.10% bonds that matured in 2007. The
new bonds, which are unsecured, bear interest at 6.95% and mature in 2020.
In April 1997, the Coconino County, Arizona Pollution Control
Corporation issued $36.7 million of Pollution Control Revenue Bonds for the
benefit of the Company. The net proceeds loaned to the Company were used, in
part, to redeem, in June 1997, $16.7 million principal amount of previously
issued variable rate bonds that matured in 2031 and the remaining portion
will be used to fund $20 million of construction costs of additional
pollution abatement facilities at Navajo Generating Station. The new bonds,
which are unsecured, bear interest at 7.125% and mature in 2032.
In April 1997, the Coconino County, Arizona Pollution Control
Corporation issued $14.7 million of Pollution Control Revenue Bonds for the
benefit of the Company. The net proceeds loaned to the Company were used in
June 1997 to redeem $14.7 million principal amount of previously issued
variable rate bonds that matured in 2031. The new bonds, which are
unsecured, bear interest at 7.00% and mature in 2032.
NOTE 6. INCOME TAXES
- ---------------------
The benefit for income taxes included in the Comparative Condensed
Consolidated Statements of Income consists of the following:
Three Months Ended
June 30,
1997 1996
---------- ----------
- Thousands of Dollars -
Operating Expenses:
Deferred Tax Expense (Benefit)
Federal $ 3,387 $ 1,192
State 873 307
---------- ----------
Total 4,260 1,499
Investment Tax Credit Amortization - (15)
---------- ----------
Total Expense (Benefit) Included in
Operating Expenses 4,260 1,484
---------- ----------
Other Income (Deductions):
Deferred Tax Expense (Benefit)
Federal 3,622 646
State 934 225
---------- ----------
Total 4,556 871
Reduction in Valuation Allowance (14,975) (6,164)
Investment Tax Credit Amortization (966) (1,211)
---------- ----------
Total Benefit Included in
Other Income (Deductions) (11,385) (6,504)
---------- ----------
Total Benefit for Federal and State
Income Taxes $ (7,125) $ (5,020)
========== ==========
Six Months Ended
June 30,
1997 1996
---------- ----------
- Thousands of Dollars -
Operating Expenses:
Deferred Tax Expense (Benefit)
Federal $ 1,528 $ (3,465)
State 394 (893)
---------- ----------
Total 1,922 (4,358)
Investment Tax Credit Amortization (10) (30)
---------- ----------
Total Expense (Benefit) Included in
Operating Expenses 1,912 (4,388)
---------- ----------
Other Income (Deductions):
Deferred Tax Expense (Benefit)
Federal 4,199 (383)
State 1,083 (41)
---------- ----------
Total 5,282 (424)
Reduction in Valuation Allowance (29,293) (11,013)
Investment Tax Credit Amortization (1,932) (2,424)
---------- ----------
Total Benefit Included in
Other Income (Deductions) (25,943) (13,861)
---------- ----------
Total Benefit for Federal and State
Income Taxes $ (24,031) $ (18,249)
========== ==========
The differences between the income tax benefit and the amount obtained
by multiplying income before income taxes by the U.S. statutory federal
income tax rate are as follows:
Three Months Ended
June 30,
1997 1996
---------- ----------
- Thousands of Dollars -
Federal Income Tax Expense (Benefit) at
Statutory Rate $ 7,972 $ 1,844
State Income Tax Expense (Benefit),
Net of Federal Deduction 1,225 284
Investment Tax Credit Amortization (966) (1,226)
Reduction in Valuation Allowance (14,975) (6,164)
Other (381) 242
---------- ----------
Total Benefit for Federal and
State Income Taxes $ (7,125) $ (5,020)
========== ==========
Six Months Ended
June 30,
1997 1996
---------- ----------
- Thousands of Dollars -
Federal Income Tax Expense (Benefit) at
Statutory Rate $ 6,077 $ (2,640)
State Income Tax Expense (Benefit),
Net of Federal Deduction 934 (406)
Investment Tax Credit Amortization (1,942) (2,454)
Reduction in Valuation Allowance (29,293) (11,013)
Use of Capital Loss Carryforwards - (1,663)
Other 193 (73)
---------- ----------
Total Benefit for Federal and
State Income Taxes $ (24,031) $ (18,249)
========== ==========
NOTE 7. NEW ACCOUNTING STANDARD
- --------------------------------
In February 1997, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 128 (FAS 128), Earnings per
Share. This Statement simplifies the standards for computing earnings per
share (EPS) and replaces the presentation of primary EPS with a presentation
of basic EPS. It requires a dual presentation of basic and diluted EPS on
the face of the income statement. The Company is required to adopt FAS
128 in the fourth quarter of 1997. The Company does not expect the adoption
of FAS 128 to have a material impact on the Company's calculation of EPS.
NOTE 8. RECLASSIFICATIONS
- --------------------------
Minor reclassifications have been made to the prior year financial
statements to conform to the current year's presentation.
ITEM 2. - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
- -------------------------------------------------------------------------------
The following contains information regarding the results of the Company's
operations during the second quarter and first six months of 1997 compared with
the second quarter and first six months of 1996, the outlook for dividends on
Common Stock, and changes in liquidity and capital resources of the Company
during the second quarter and first six months of 1997. Also management's
expectations of identifiable material trends are discussed.
OVERVIEW
- --------
Earnings for the Company improved during the second quarter and first six
months of 1997 relative to the same periods in 1996. Net income increased from
$10.3 million in the second quarter of 1996 to $29.9 million in the second
quarter of 1997. This improvement was due primarily to a $10.2 million pre-tax
reversal of loss provision resulting from the dissolution of certain
subsidiaries which formed a part of the Company's former investment operations,
a $14.0 million pre-tax Voluntary Severance Plan expense recorded in the second
quarter of 1996, and an increase of $8.8 million in non-cash income tax
benefits recognized by the Company associated with expected future utilization
of federal and state net operating loss carryforwards generated in prior
periods. These same factors contributed to an improvement in net income for
the first six months of 1997 compared with the same period in 1996. Net income
increased to $41.4 million in the first half of 1997 from $10.7 million in the
first half of 1996. In addition to the factors discussed above, revenues for
the first half of 1997 benefited from growth in the number of customers in the
Company's retail service area, increased revenues from the 1.1% retail rate
increase implemented in March 1996, and from increased wholesale energy sales.
See Results of Utility Operations below.
Despite such improvements, the Company's financial prospects continue to
be subject to significant economic, regulatory and other uncertainties, some of
which are beyond the Company's control. These uncertainties include the extent
to which the Company, due to continued high financial and operating leverage,
can alter operations and reduce costs in response to industry changes or
unanticipated economic downturns. The Company's success will depend, in part,
on the Company's ability to contain the costs of serving retail customers and
the level of sales to such customers. Although the Company anticipates
continued growth in sales over the next five years primarily as a result of
anticipated population and economic growth in the Tucson area, a number of
factors such as changes in the economic and regulatory environment and the
increasingly competitive electric markets could affect the Company's levels of
sales.
The Company is developing strategies to address the uncertainties
discussed above as well as to position itself to benefit from the changing
regulatory environment. Such strategies include the implementation of enhanced
cost measurement and management techniques, organizational realignment and
staffing reductions, and the development of new entities to provide energy
services to markets beyond the Company's retail service territory. Based on
cost containment measures implemented by the Company, a proposal to share
savings with the Company's retail customers was recently filed by the Company
with the ACC. See Retail Rate Proposal below. Additionally, the Company
successfully extended the power sale agreement with a key wholesale customer
and has taken steps to reduce the cost of fuel supplied to the Company's
largest generating facility. See Results of Operations, Events Affecting
Future Results of Utility Operations below.
If the Company is unable to make sales at prices adequate to recover its
costs or if, for other reasons, the Company fails to maintain or improve its
cash flows, the Company's ability to meet its obligations may be jeopardized.
During the period 1999-2003, $192 million of the Company's long-term debt
obligations will mature. Letters of credit supporting $774 million of the
Company's long-term variable rate debt obligations also have scheduled
expiration dates between December 31, 1999 and December 31, 2002. See
Financing Developments below. Should the credit ratings on the Company's
senior debt securities reach investment grade levels on certain dates or during
certain periods subsequent to January 1, 1998, the expiration dates for such
letters of credit would move forward to the period December 31, 1998 to
December 31, 2000. In the event that expiring letters of credit are not
replaced or extended, the corresponding variable rate debt obligations would be
subject to mandatory redemption. While the Company intends to pay or refinance
maturing bonds, and to replace or extend expiring letters of credit, there can
be no assurance that the Company will be able to pay such debt or replace or
extend such letters of credit. The Company's future cash flows will also be
affected by the level of interest rates due to the significant amount of
variable rate debt outstanding. See Liquidity and Capital Resources below.
The Company's capital structure is highly leveraged and the Company's
ability to raise capital (through either public or private financings) is
limited. The Company's ability to obtain debt financing is limited due to the
restrictive covenants contained in existing obligations to creditors. To the
extent the Company refinances its debt obligations in order to repay them when
due, such refinancing may be made on terms which may be adverse to the Company.
Such terms could include, among other things, higher interest rates and various
restrictive covenants, such as dividend payment restrictions. Access to equity
capital may be limited because of the Company's present inability to pay
dividends. See Dividends on Common Stock below.
As described in Liquidity and Capital Resources, Financing Developments,
the Company recently filed an application with the ACC for authority to
implement various financings intended to address the financial uncertainties
outlined above. This strategy includes the proposed refinancing of certain
variable rate tax-exempt obligations on a fixed-rate basis, the proposed
replacement of the credit facilities provided under the MRA with one or more
new credit facilities, the proposed refinancing of certain first mortgage
bonds, and the proposed implementation of a direct stock purchase plan.
During the next twelve months, the Company expects to be able to fund
operating activities and construction expenditures with internal cash flows,
existing cash balances, and, if necessary, drawdowns under the Renewable Term
Loan and/or borrowings under the Revolving Credit. As discussed in Liquidity
and Capital Resources below, there are a variety of factors that could cause
actual cash flows to differ materially from projected cash flows. As of August
7, 1997, the Company's cash balance including cash equivalents was
approximately $80.2 million. Cash balances are invested in investment grade,
money-market securities with an emphasis on preserving the principal amount
invested.
COMPETITION
- -----------
WHOLESALE
The Company competes with other utilities, marketers and independent power
producers in the sale of electric capacity and energy in the wholesale market.
The Company's prices for wholesale sales of capacity and energy, generally, are
not permitted to exceed rates determined on a cost of service basis. In the
current market, wholesale prices are substantially below costs determined on a
fully allocated cost of service basis, but, in all instances, wholesale sales
have been made at prices which exceed the level necessary to recover fuel and
other variable costs. It is expected that competition to sell capacity will
remain vigorous, and that prices may remain at or near current levels for at
least the next several years, due to increased competition and surplus capacity
in the southwestern United States. Competition for the sale of capacity
and energy is influenced by many factors, including the availability of
capacity in the southwestern United States, the availability and prices of
natural gas and oil, spot energy prices and transmission access. In addition,
the Energy Policy Act of 1992 has promoted increased competition in the
wholesale electric power markets by encouraging the participation of utility
affiliates, independent power producers and other non-utility participants in
the development of power generation.
The FERC issued two orders pertaining to transmission access in April
1996. FERC Order No. 888, among other things, requires all public utilities
that own, control, or operate interstate transmission facilities to offer
transmission service to others under a single tariff that incorporates certain
minimum terms and conditions of transmission service established by the FERC.
This tariff must also be used by public utilities for their own wholesale
market transactions. Transmission and generation services for new wholesale
service are to be unbundled and priced separately. A Phase I open access
tariff containing the terms and conditions outlined in the Order was filed by
the Company on July 9, 1996. The Company subsequently filed a Stipulation in
Offer of Settlement regarding the proposed tariff. On July 17, 1997, the FERC
approved the settlement. That settlement approves the Company's rates for
service, makes amendments to certain wholesale contracts and requires the
Company to make a Section 205 filing for its 69kV-138kV transmission system,
the rates for which were agreed upon in the settlement.
FERC Order No. 889 requires transmission service providers to establish or
participate in an open access same-time information system (OASIS) that
provides information on the availability of transmission capacity to wholesale
market participants. The order also establishes standards of conduct that are
designed to prevent employees of a public utility engaged in marketing
functions from obtaining preferential access to OASIS-related information or
from engaging in unduly discriminatory business practices. The Company is in
compliance with these requirements.
On March 4, 1997, the FERC issued Orders 888-A and 889-A which require the
Company to make an additional compliance filing of its tariff and to comply
with certain additional OASIS requirements. The Company has made its
compliance tariff filing and is in the process of complying with the additional
OASIS requirements.
The Company and several other electric utilities located in the
southwestern United States have recently begun to investigate the feasibility
of forming an independent system operator for the region. It is presently
contemplated that such an organization, if formed, would be responsible for
ensuring transmission reliability and nondiscriminatory access to the regional
transmission grid. Other utilities involved in the feasibility study include
Arizona Public Service Company, El Paso Electric Company, Nevada Power Company,
Public Service Company of New Mexico, Salt River Project, Texas-New Mexico
Power Company, and the Western Area Power Administration - Desert Southwest
Region. Several public meetings have been held in order to obtain public input
to the study. The feasibility study is expected to be completed by the end of
1997. The formation of an independent system operator would be subject to
approval by the FERC and state regulatory authorities in the region. The
financial aspects of forming an independent system operator, including the
potential effects on the Company's future results of operations, are being
examined as part of the feasibility study.
Given the level of competition already present in the wholesale market for
electricity, the Company does not believe that FERC Order No. 888 or Order No.
889 will have a material effect on the Company's future results of operations.
However, such orders could assume greater significance if the Company's retail
service territory were to be opened to competing suppliers of electricity.
RETAIL
Under current law, the Company is not in direct competition with any other
regulated electric utility for electric service in the Company's retail service
territory. However, the Company does compete against gas service suppliers and
others who may provide energy services which would be substitutes for, or
permit bypass of, the Company's services. In addition, the ACC recently
adopted rules that require a phase-in of retail electric competition in Arizona
over a four year period beginning January 1, 1999.
Currently, 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. If such facilities meet
certain technical and operational standards, they may be eligible for treatment
under federal law as "qualifying facilities", which in turn would permit the
owner to require the local electric utility to purchase the output of such
facilities at the latter's "avoided cost" pursuant to the Public Utility
Regulatory Policies Act of 1978, as amended. Such facilities may be operated
by the customers themselves or by other entities engaged for such purpose. The
company presently does not have any contracts which require it to purchase the
output of qualifying facilities.
The Company actively markets energy and customized energy-related services
to meet customer needs. The Company has to date lost no customers to self-
generation in part because of such efforts. For example, the Company's two
principal mining customers, which provide approximately 10% of the Company's
total annual revenues from retail customers, each have considered self-
generation. However, following negotiations with the Company in 1993 and 1994,
new contracts were executed that included, among other things, price reductions
and term extensions. In 1996, the Company negotiated contract amendments with
its largest mining customer. The contract amendments include, among other
things, price reductions, a market pricing mechanism covering a portion of the
customer's electrical load, and a change in service from a firm basis to an
interruptible basis. Such contract is scheduled to expire in January 2003.
The contract with the Company's other principal mining customer is scheduled to
expire in March 2001. In June 1997, the Company entered into an electric
service agreement with this customer to furnish additional load to a new copper
solvent extraction plant. Early terminations of the contracts by mining
customers require at least one and up to two years prior notice. To date, no
such notice has been received. The ability to enter into or extend contracts,
to avoid early termination, and to retain customers will be dependent on, among
other things, the Company's ability to contain its costs, market conditions and
alternatives available to customers. Changes in service requirements (from a
firm basis to an interruptible basis) may also permit the Company to delay
additions to peaking capacity.
In December 1996, the ACC voted to adopt rules on retail electric
competition. The rules require each "Affected Utility" (defined below) to open
its retail service area to competing electric service providers on a phased-in
basis over the period 1999 to 2003. Beginning no later than January 1, 1999,
retail customers representing at least 20% of each Affected Utility's 1995 peak
demand will be eligible to choose their electric service provider from
companies certificated by the ACC. Such service providers would include
Affected Utilities as well as other entities (including power marketers and
out-of-state utilities) that apply for and receive a certificate of convenience
and necessity from the ACC. Beginning no later than January 1, 2001, retail
customers representing at least 50% of each Affected Utility's 1995 peak demand
will be eligible to choose their service provider. All remaining retail
customers would then be eligible to choose from certificated service providers
by January 1, 2003. Under the rules, Affected Utilities will be required to
provide distribution wheeling services (i.e., retail wheeling) at rates
approved by the ACC in order to facilitate sales by competing energy providers.
Such wheeling services would involve the transmission of energy produced by
other entities over the Company's transmission and distribution system to
consumers located in the Company's present retail service area. While retail
wheeling will expose the Company's service area to increased competition, it
will also open additional retail markets into which the Company may sell its
electric power.
The Affected Utilities whose service territories will be open to competing
service providers under the rules include the Company, Arizona Public Service
Company, Citizens Utilities Company, and several electric cooperatives.
However, electric cooperatives will be permitted to request a modification to
the phase-in schedule in order to preserve their tax exempt status or to modify
power supply arrangements and related loan agreements. Each of the Affected
Utilities will be eligible to offer electric service to customers of other
certificated entities within Arizona. Participation in competitive retail
markets by other electric utilities which are not regulated by the ACC, such as
the Salt River Project and certain municipal utilities, will be permitted under
the rules on a similar reciprocal basis (i.e., these utilities would have to
allow their service territories to be similarly open to competing service
providers).
The rules require new market entrants to obtain a certificate of
convenience and necessity from the ACC prior to offering retail electric
service. New market entrants will be required to demonstrate adequate
technical and financial capabilities to the ACC prior to certification. In
addition, by January 1, 1999, all competitive market participants, including
Affected Utilities, will be required to obtain at least one-half of one percent
of the energy sold competitively in the Arizona retail market from new solar
generating resources. This required percentage will increase to one percent on
January 1, 2002. New solar resources are defined under the rules as
photovoltaic or solar thermal resources that are installed on or after January
1, 1997. Electric service providers not in compliance with these solar
resource standards will be subject to a penalty of up to 30 cents per kWh to be
applied to the kWh deficiency in solar energy provided.
The rules specify that the ACC will allow the recovery of unmitigated
stranded costs by Affected Utilities. Stranded cost is defined in the rules as
the net difference between the value of prudent jurisdictional assets and
obligations under traditional regulation and the market value of those assets
and obligations in a competitive retail market. In order to recover stranded
costs, utilities would have to demonstrate to the ACC that they have taken
every feasible, cost effective measure to mitigate or offset stranded costs,
and utilities would have to file estimates of unmitigated stranded costs with
the ACC which are fully supported by analyses and records of market
transactions undertaken by willing buyers and sellers. Furthermore, Affected
Utilities would have to seek ACC approval of distribution charges or other
means of recovering unmitigated stranded costs from customers who reduce or
terminate service as a direct result of retail competition. The rules specify
that other issues related to the analysis and recovery of stranded costs would
be examined by a working group following adoption of the rules. Until such
time as the ACC adopts specific guidelines for quantifying unmitigated stranded
costs, including the methods used to identify and value jurisdictional assets
and obligations, the Company believes that any estimate of unmitigated stranded
costs would be highly speculative.
Each Affected Utility will be required to file unbundled service tariffs
with the ACC by December 31, 1997, for the following services: distribution
wheeling service, metering and meter reading services, billing and collection
services, open access transmission service (as approved by the FERC, if
applicable), ancillary services (as defined by FERC Order No. 888), information
services such as the provision of customer information to other service
providers, and other ancillary services necessary for safe and reliable system
operation. Until such time as the ACC determines that retail competition has
been substantially implemented, each Affected Utility will also have to provide
standard offer bundled service equivalent to the services currently being
provided at regulated rates to all consumers located in their current retail
service areas.
Pursuant to the rules, working groups have been formed to analyze various
issues related to retail competition. Each working group consists of members
representing a wide variety of interests including the ACC Staff, consumers,
Affected Utilities, and potential new service providers. Separate working
groups have been established to investigate issues related to the
quantification and recovery of stranded costs, the unbundling of utility
services and rates, the maintenance of system reliability and safety, the
methods to be used in determining consumer participation during the early
phase-in periods, and certain legal issues related to the rules. Reports
describing the activities and recommendations of working group members are
scheduled to be provided to the ACC by the fourth quarter of 1997. The Company
is actively participating in each of the working groups investigating retail
competition issues.
On January 10, 1997, the Company filed with the ACC a motion for
reconsideration and request for stay of the rules. Concerns expressed by the
Company in its motion included the potential impact on system reliability,
mechanisms for stranded cost quantification and recovery, the ability to
compete fairly with public power entities and recipients of federal preference
power, and certain legal deficiencies which would likely result in legal
appeals and litigation. On January 30, 1997, the Company's motion for
reconsideration was deemed denied by the ACC by operation of law. On February
28, 1997, the Company filed an appeal of the ACC order in both the Arizona
Superior Court and the Arizona Court of Appeals. On June 19, 1997, the Arizona
Court of Appeals dismissed the appeal at the request of the Company. At the
same time, the Company filed a motion for Summary Judgment in the Arizona
Superior Court. At the present time, the Company is unable to predict the
outcome of the Superior Court appeal or the effects such rules, in their
present form, would have on the Company's future results of operations.
The Arizona Legislature is also investigating the potential merits of
retail electric competition. Legislation was passed in 1996 requiring the
establishment of a joint legislative study committee on electric industry
competition. This committee is charged with studying and making
recommendations on a wide variety of issues related to electric industry
competition. The committee is to complete a report to the legislature no
later than December 31, 1997. Such report is to contain a proposal for
electric utility competition for implementation by December 31, 1999. An
advisory committee on electric industry competition was also created,
consisting of members representing electric consumers, electric utilities,
various State offices and agencies, and other interested parties. The Company
has a representative on such advisory committee who is actively participating
as a committee member. Three subcommittees of the advisory committee were
recently formed for purposes of evaluating the timing of retail competition,
reviewing tax issues related to retail competition and identifying specific
legislative actions necessary to implement retail competition.
The Company cannot predict whether or not there will be competing or
conflicting initiatives on industry restructuring from both the ACC and the
Arizona Legislature. However, the Company believes that certain matters
contained in the ACC's rules on retail competition may require legislative
changes, while other matters may require constitutional amendments.
Additionally, several federal initiatives regarding retail electric competition
have been introduced in Congress which, if passed, could modify, augment or
preempt the actions taken by the ACC or the Arizona Legislature. The Company
will continue to assess the likely impact of the ACC's rules on retail
competition, proposed legislation on retail competition, and other potential
market reforms on the Company. At the present time the Company is unable to
predict the ultimate impact of increased retail competition on the Company's
future results of operations. See Accounting for the Effects of Regulation
below for a discussion of the potential impact of increased competition on the
Company's accounting policies.
HOLDING COMPANY PROPOSAL
- ------------------------
On April 4, 1997, the Company filed with the ACC a notice of intent to
organize a public utility holding company. If approved by the ACC and the
FERC, the Company intends to establish through a one-for-one share exchange a
new corporate structure in which the Company will be a subsidiary of a new
holding company named UniSource Energy Corporation. The Company is seeking 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 facilitated and enhanced by
the holding company structure, a structure commonly used in the electric
industry and other industries to conduct different lines of business. In May
1995, Shareholders approved the formation of a holding company and the related
one-for-one share exchange. If regulatory approvals are received, it is likely
that no further Shareholder approval would be required to effect the share
exchange.
If the holding company structure is established, substantially all of the
assets of the holding company initially following the share exchange would
consist of the Company's Common Stock. The holding company would rely
primarily on funding sources other than TEP to fund its operations and to
capitalize affiliate companies because the Company is currently prohibited from
paying dividends (see Dividends on Common Stock below) and because the Company
may be prohibited from making investments in the holding company or affiliated
companies. Also, the ACC's affiliated interest rules would limit certain
transactions between the holding company and the Company unless
approved by the ACC. Accordingly, funds for the holding company would be
limited until the holding company obtains outside financing or until the
affiliate companies are able to pay cash dividends to the holding company. The
Company is reviewing various methods for the holding company to obtain outside
financing, including the issuance of new equity by the holding company.
In the unlikely event the holding company incurs liabilities in excess of
cash flow available from the Company, the affiliate companies or outside
financings, the holding company might not have sufficient cash available to
meet such liabilities. Under such circumstances the Company may be required to
seek waivers of the provisions of certain of its credit agreements and leases
and the affiliated interest rules in order to permit the Company to provide
interim financing to the holding company. There can be no assurance that a
holding company structure will be implemented in the future, that the holding
company will be able to obtain outside financing, or that the Company would be
able to obtain necessary waivers if so required.
RETAIL RATE PROPOSAL
- --------------------
On July 9, 1997, the Company filed with the ACC a request for an annual
rate reduction of $6.8 million (or 1.1%) for retail customers. Previously,
pursuant to the March 1996 Rate Order by the ACC, the Company implemented a
1.1% retail rate increase, and agreed to a rate moratorium period whereby the
Company committed not to file for a change in base rates prior to January 1,
2000, except under certain circumstances which include the sharing with
customers of benefits of cost containment efforts.
The July 1997 filing is in the form of a Shared Savings Proposal (SSP)
which promotes a sharing of benefits with customers of cost containment efforts
and the mitigation of potential stranded costs associated with the
introduction of retail electric competition in Arizona. In the SSP, the
Company identified approximately $23 million in annual pre-tax cost containment
measures of which $20.8 million is allocable to ACC jurisdictional operation.
These savings were realized primarily from renegotiated fuel contracts and the
Company's Voluntary Severance Program, which reduced the Company's workforce by
approximately 15%.
The Company proposed that additional savings be used by the Company to
mitigate potential stranded costs through accelerated amortization of retail
excess capacity deferrals. Retail excess capacity deferrals represent those
operating and capital costs associated with Springerville Unit 2 capacity,
which were deemed by the ACC to not be recoverable in retail rates prior to the
1994 and 1996 Rate Orders. Such retail excess capacity deferrals totaled $91.1
million and $93.6 million at June 30, 1997 and December 31, 1996, respectively.
The proposed $7.2 million increase in annual amortization expense for such
retail excess capacity deferrals would decrease the amortization period from 20
years to 7.76 years. The proposed increase in amortization expense would be
reflected in the Company's regulatory accounting records but would have no
impact on the expenses included in the Company's financial accounting
statements. See Note 2 of Notes to Condensed Consolidated Financial
Statements, Rate Matters.
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 June 30,
1997, and at December 31, 1996, contain certain line items (for example,
Deferred Debits - Regulatory Assets, Accumulated Deferred Investment Tax
Credits Regulatory Liability, MSR Option Gain Regulatory Liability, and Other
Regulatory Liabilities) solely as a result of the application of FAS 71. In
addition, a number of line items in the Company's Consolidated Statements of
Income for the quarters ended June 30, 1997 and 1996, and the six months ended
June 30, 1997 and 1996, also reflect the application of FAS 71.
As noted in Competition, Retail above, on December 23, 1996, the ACC voted
to adopt rules on retail electric competition. However, the ACC has not yet
adopted specific guidelines for quantifying unmitigated stranded costs,
including the methods used to identify and value jurisdictional assets and
obligations. The Company, in reliance on previous rate orders, believes that
it will recover the full costs of its investments in utility plant assets and
regulatory assets. If less than full recovery is provided, write-offs of
assets may occur and the Company may be unable to continue to apply FAS 71.
Further, in response to the legislation adopted by the State of California
in 1996 establishing competitive markets for electricity in that state, the SEC
is reported to have questioned the continued applicability of FAS 71 by the
generation operations of California investor-owned utilities even though the
recovery of stranded costs is provided through a statutory funding mechanism.
In May and July 1997 the Financial Accounting Standards Board Emerging Issues
Task Force considered this issue, as similar legislation has been passed or
initiated in states other than California. Based on the conclusions of the
EITF, at some point in the future, the Company may be unable to continue to
apply FAS 71 to the generation portion of the business, even if it believes it
will recover the full amount of its costs under the ACC competition phase-in
plan. The Company is unable to predict the outcome of these matters
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 June 30, 1997, the Company estimates
that if FAS 101 were adopted and applied to all segments of the Company's
operations, an extraordinary loss of $186 million, which includes a reduction
for the related deferred income taxes of $102 million, would be required. The
Company's cash flows would not be affected by the adoption of FAS 101.
At the present time, the Company recovers the costs of its plant assets
through its regulated revenues. If in the future the Company discontinues
accounting according to the provisions of FAS 71, the Company would also need
to consider whether the markets in which the Company is then selling power will
allow the Company to recover the costs of its plant assets. At that time, if
market prices and other recoveries are not expected to allow the Company to
recover the costs of its plant assets, additional write-downs may be required
in accordance with the provisions of FAS 121.
DIVIDENDS ON COMMON STOCK
- -------------------------
The Company is precluded by restrictive covenants in certain debt
agreements from declaring or paying dividends. No dividend on common stock has
been declared or paid since 1989.
Under the applicable provisions of amendments to the Arizona General
Corporation Law, a company is permitted to make distributions to shareholders
unless, after giving effect to such distribution, either (i) the company would
not be able to pay its debts as they come due in the usual course of business,
or (ii) the company's total assets would be less than the sum of its total
liabilities plus the amount necessary to satisfy any liquidation preferences of
shareholders with preferential rights. The Company is not currently prevented
from declaring and paying a dividend under such provisions.
The Company's ability to pay a dividend is restricted by certain covenants
of the General First Mortgage. So long as certain series of First Mortgage
Bonds (aggregating $184 million in principal amount) are outstanding, these
covenants restrict the payment of dividends on Common Stock if certain cash
flow coverage and retained earnings tests are not met. The cash flow coverage
test would prevent the Company from paying dividends on its Common Stock until
such time as the Company's cash flow coverage ratio, as defined therein, is
greater or equal to a ratio of 2 to 1, and the retained earnings test would
permit dividend payments if the Company has positive retained earnings rather
than an accumulated deficit. As of June 30, 1997, the Company had a cash flow
coverage ratio in excess of 2 to 1 and the Company's accumulated deficit was
$464 million. Such covenants will remain in effect until the First Mortgage
Bonds of such series have been paid or redeemed. The latest maturity of such
First Mortgage Bonds is in 2003.
The MRA contains a dividend restriction based on the amount of retained
earnings. Such restriction will no longer apply if (i) the Renewable Term Loan
and the Revolving Credit have been paid in full and the commitments relating
thereto have been terminated and (ii) the Company's senior long-term debt is
rated investment grade. At August 7, 1997, there was no outstanding balance
due under the Renewable Term Loan, and to date no amounts have been borrowed
under the Revolving Credit. Commitments relating to such facilities permit the
Company to borrow $134 million under the Renewable Term Loan and $50 million
under the Revolving Credit. The Company's senior long-term debt is currently
rated below investment grade.
In order for the Company to pay a dividend when such covenants would
otherwise restrict such payment, the Company would have to (i) obtain a waiver
or an amendment to the MRA's retained earnings covenant and (ii) redeem all
outstanding First Mortgage Bonds of the series that contain dividend
restrictions or amend the General First Mortgage. Such General First Mortgage
amendment would require approval by holders of 75% of all First Mortgage Bonds.
In addition to such restrictive covenants, the Federal Power Act states
that dividends shall not be paid out of funds properly included in the capital
account. It is unclear whether such provisions of the Federal Power Act
restrict the Company from paying dividends.
EARNINGS
- --------
The Company recorded net income of $29.9 million in the second quarter of
1997 compared with net income of $10.3 million in the second quarter of 1996.
The net income per average share of Common Stock was $0.93 for the second
quarter of 1997 compared with net income per average share of Common Stock of
$0.32 for the second quarter of 1996.
For the first six months of 1997, the Company recorded net income of $41.4
million, compared with net income of $10.7 million for the first six months of
1996. The net income per average share of Common Stock was $1.29 for the first
six months of 1997, compared with a net income per average share of Common
Stock of $0.33 for the first six months of 1996.
RESULTS OF OPERATIONS
- ---------------------
RESULTS OF UTILITY OPERATIONS
Sales and Revenues
Comparisons of kilowatt-hour sales and electric revenues are shown below:
Three Months Ended June 30
--------------------------
Increase/(Decrease)
--------------------
1997 1996 Amount Percent
------ ------ -------- ---------
Electric kWh Sales (000):
Retail Customers 1,886,216 1,896,118 (9,902) (0.5)%
Sales for Resale 749,074 675,287 73,787 10.9
---------- ---------- --------
Total 2,635,290 2,571,405 63,885 2.5
========== ========== ========
Electric Revenues (000):
Retail Customers $159,249 $162,040 $(2,791) (1.7)%
Amortization of MSR Option
Gain Regulatory
Liability 3,092 5,013 (1,921) (38.3)
Sales for Resale 20,629 17,480 3,149 18.0
-------- -------- --------
Total $182,970 $184,533 $(1,563) (0.8)
========== ========= ========
Six Months Ended June 30
------------------------
Increase/(Decrease)
--------------------
1997 1996 Amount Percent
------ ------ -------- ---------
Electric kWh Sales (000):
Retail Customers 3,508,657 3,477,543 31,114 0.9%
Sales for Resale 1,464,261 1,394,351 69,910 5.0
---------- ---------- --------
Total 4,972,918 4,871,894 101,024 2.1
========== ========== ========
Electric Revenues (000):
Retail Customers $289,186 $287,250 $1,936 0.7%
Amortization of MSR Option
Gain Regulatory
Liability 8,105 10,026 (1,921) (19.2)
Sales for Resale 39,960 35,285 4,675 13.2
-------- -------- ------
Total $337,251 $332,561 $4,690 1.4
======== ======== ======
KWh sales to retail customers decreased by 0.5% in the second quarter of
1997 compared with the second quarter of 1996 due to cooler weather conditions
in the 1997 quarter despite a 2.4% increase in average number of retail
customers. KWh sales to retail customers increased by 0.9% in the first six
months of 1997 compared with the same period in 1996. The sales impact of the
2.5% increase in average number of retail customers for the six month period
was offset by cooler weather conditions in the second quarter. Based on
cooling degree days, a commonly used measure in the electric industry that is
calculated by subtracting 75 from the average of the high and low daily
temperatures, the Tucson area registered a decrease of approximately 26% in
such cooling degree days for the second quarter of 1997 compared with the same
period in 1996, and a decrease of approximately 7% in such cooling degree days
compared with the ten year average for the same period from 1987 to 1996.
Cooling degree days for the second quarter of 1997 were 402, compared to 544
for the second quarter of 1996 and 434 for the ten year average.
Revenues from sales to retail customers decreased by 1.7% in the second
quarter of 1997 compared to the second quarter of 1996 due to the lower kWh
sales discussed above as well as a 9% decrease in revenues per kWh sold to
mining customers. The change in average price of sales to mining customers
reflects the impact of the renegotiation of the contract with the Company's
largest mining customer in 1996. Revenues from sales to retail customers in
the first six months of 1997 increased by 0.7% compared with the same period in
1996. The increase in kWh sales for the first half of the year, combined with
the first quarter impact of the 1.1% retail rate increase implemented on March
31, 1996, offset the average price decrease to mining customers discussed
above.
Sales for resale increased by 10.9% in the second quarter and by 5.0% in
the first six months of 1997 relative to the same periods in 1996. Higher
energy sales to the Company's firm wholesale customers accounted for the second
quarter increase. Revenues from sales for resale were 18.0% higher in the
second quarter and 13.2% higher in the first six months of 1997 compared to the
same periods in 1996 due to higher market prices for wholesale economy energy
in both the first and second quarters of 1997. Factors contributing to higher
market prices included an increase in natural gas prices and a reduction in
regional generating capability due to planned and forced outages of generating
facilities in the southwestern United States.
Revenue from the Amortization of the MSR Option Gain Regulatory Liability
was 38.3% lower in the second quarter and 19.2% lower in the first half of 1997
compared to the same period in 1996. This Regulatory Liability was fully
amortized as of May 1997.
Operating Expenses
Fuel and Purchased Power expense increased in the second quarter and first
six months of 1997 compared with the same period in 1996. The increase in fuel
and purchased power expense for the second quarter of 1997 slightly outpaced
the growth in kWh sales for the period. Increased purchases of higher cost
economy energy in the second quarter contributed to the higher expense for both
periods. These increases in purchased power expense were partially offset by
the absence of take-or-pay payments for fuel in either the second quarter or
first half of 1997, compared to take-or-pay payments of $1.1 million and $2.2
million for the same periods in 1996.
Other Operations expense increased by $3.7 million in the second quarter
and $5.9 million in the first half of 1997 relative to the same periods in
1996. These increases include higher expenses recorded for increased funding
of new energy-related businesses, as well as an adjustment related to post-
retirement benefits other than pensions.
Maintenance and Repairs expense increased by $2.6 million in the second
quarter and $3.3 million in the first half of 1997 compared to the same periods
in 1996 due primarily to scheduled maintenance work at the Springerville
station in 1997.
Depreciation and Amortization expense decreased by $3.4 million in the
second quarter and $5.3 million in the first six months of 1997 compared with
the same periods in 1996. These decreases were attributable to the completion
in January 1997 of a three year amortization for Springerville Unit 2 Rate
Synchronization Costs established in the 1994 Rate Order, as well as an
extension of the depreciable life for pollution control facilities as required
by the Company's 1996 Rate Order.
Taxes Other Than Income Taxes decreased by $1.6 million in the second
quarter and $4.0 million in the first six months of 1997 compared with the same
periods in 1996. Property tax rates and property valuations for tax purposes
were lower in 1997.
Voluntary Severance Plan Expense of $14.0 million was recorded in the
second quarter of 1996.
Income Tax expense included in Operating Expenses increased by $2.8
million in the second quarter and by $6.3 million in the first six months of
1997 compared with the same periods in 1996 due to an increase in pre-tax
operating income, net of interest expense.
Other Income
Income Tax benefits included in Other Income increased $4.9 million in the
second quarter and $12.1 million in the first six months of 1997 compared with
the same periods of 1996 due primarily to increased NOL benefit recognition
resulting from a revision in the expectation for future utilization of NOLs
generated in prior periods. The Company recognizes benefits related to prior
period NOLs based on changes in the estimated amount of NOLs that in the
Company's judgment are more likely than not to be realized in the future. A
significant factor, among others, considered in estimating such amount is the
average annual book income before taxes for the prior three years.
If the Company's operating results continue to improve, the three year
historical average net book income would continue to increase.
Correspondingly, the Company would likely recognize additional NOL benefits
totaling up to approximately $13 million over the next two years relating to
prior period NOLs unrecognized at June 30, 1997. The amount of NOL benefits
recognized in periods subsequent to June 30, 1997, if any, and the timeframe in
which such benefits are recognized, may vary significantly from the estimate
described in this paragraph. In addition, in future periods when such NOLs are
utilized for income tax purposes to offset taxable income, income tax expense
shown on the Company's Consolidated Statements of Income will not be reduced to
reflect such utilization.
A Reversal of Loss Provision in the amount of $10.2 million was recorded
in the second quarter of 1997. The reversal of loss provision relates to the
dissolution of certain subsidiaries which formed part of the Company's former
investment operations. See Note 4 of Notes to Condensed Consolidated Financial
Statements, Consolidated Subsidiaries.
EVENTS AFFECTING FUTURE RESULTS OF UTILITY OPERATIONS
NTUA Wholesale Power Contract
On June 26, 1997, the Company signed an agreement to extend and
restructure its current wholesale power sale agreement with the Navajo Tribal
Utility Authority (NTUA). NTUA has purchased approximately 60 MW of power
annually since 1993. Under the terms of the Amended and Restated Power Supply
Agreement, firm capacity sales will be provided in two phases. The first phase
runs through May 31, 1999, the original termination date under the replaced
agreement. The second phase will extend through December 31, 2009. During
phase one, the Company will continue to serve NTUA's full power requirements in
excess of energy and capacity from NTUA's hydroelectric resource. The new
contract also provides NTUA the opportunity and ability to serve new industrial
loads through purchases in the wholesale marketplace. Phase two of the
agreement calls for NTUA to continue purchasing firm power from the Company,
while becoming a partial requirements customer with a variety of options to
serve its remaining needs. The Company will provide 40 MW of firm power to
NTUA in the summer months and 50 MW of firm power in the winter months.
The Company's annual revenues from wholesale sales to NTUA under the
previous terms of the sales agreement are approximately $16.5 million per year.
In phase one of the restructured agreement, the Company's annual revenues from
sales to NTUA are estimated to be approximately $15 million per year. In the
first year of phase two, revenues from sales to NTUA are estimated to range
from $9 million to $16 million.
The new agreement is subject to approval by the FERC. Under the new
agreement, the Company will provide generation service pursuant to the Power
Supply Agreement, while providing the transmission and ancillary services
necessary to actually deliver power pursuant to separate network service and
operating agreements in accordance with the requirements of FERC Order 888.
Springerville Coal Supply Contract
On June 27, 1997, the Company signed an agreement with Peabody Coalsales
to terminate the then existing coal supply contract for the Springerville
Generating Station, and enter into a new contract with the same supplier. A
$50 million termination fee was incurred by the Company, payable in three
installments: $30 million paid on June 30, 1997, $10 million due September 30,
1997, and $10 million due March 31, 1998. The new contract contains more
favorable terms to the Company than the previous contract for certain volume,
incremental volume, base price, incremental price and price adjustment
mechanism requirements. The Company estimates that savings under the new
contract will be approximately $10 million per year initially and will increase
thereafter, resulting in approximately $97.5 million of savings on a present
value basis over the life of the contract.
The Springerville Generating Station consists of two 380 MW coal fired
generating units which account for 38% of the Company's total net generating
capability. The previous coal supply contract covered the useful lives of
Springerville Units 1 and 2 and contained a bilateral option to renegotiate the
contract price and escalation procedures in 2009 and at intervals of every five
years thereafter, with various adjustment clauses which would affect the future
cost of delivered coal. The new coal contract has an initial term of 13 years,
beginning July 1, 1997, and ending June 30, 2010, with an extended term of ten
years thereafter. During the extension term, the coal supplier has the right
of first refusal to match competing offers for a portion of Springerville coal
requirements.
On July 29, 1997, the ACC issued an interim accounting order allowing the
Company to defer the $50 million termination fee as a regulatory asset until
the ACC decides whether the termination fee should be recovered through retail
rates. The interim accounting order also allows the Company to begin
amortizing the termination fee to fuel expense over the 13 year initial term of
the agreement. See Note 3 of Notes to Condensed Consolidated Financial
Statements, Springerville Coal Contract.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
The Company expects to generate sufficient cash flows during 1997 to fund
its continuing operating activities and construction expenditures. However,
the Company's projected cash flows are subject to variation due to changes in
wholesale revenues, changes in short-term interest rates, and other factors.
For example, an increase in short-term interest rates of 100 basis points (1%)
would result in an approximate $9 million increase in annual interest payments.
If cash flows were to fall short of expectations, the Company would rely on
existing cash balances, borrowings under the Renewable Term Loan and, if
necessary, borrowings under the Revolving Credit.
At August 7, 1997, there was no outstanding balance due under the
Renewable Term Loan, and to date, no amount has been borrowed under the
Revolving Credit. The Renewable Term Loan commitment decreased from $156
million at March 31, 1997 to $134 million at June 30, 1997. The commitment was
reduced by $16 million at April 29, 1997 due to MRA provisions regarding the
optional prepayment of debt obligations, and the April 1997 refinancing of
$31.4 million of floating rate IDBs (see Financing Developments below). A
mandatory quarterly commitment reduction of $6 million was effective as of June
30, 1997 in accordance with the terms of the MRA, whereby the commitment is
scheduled to decrease by approximately 5% per quarter during 1997 and by 10%
per quarter in 1998 and 1999. The Revolving Credit commitment remained at $50
million as of August 7, 1997.
The Company's cash and cash equivalents balance at August 7, 1997 was
approximately $80.2 million. Cash balances are invested in investment grade
money-market securities with an emphasis on preserving the principal amounts
invested.
CASH FLOWS
The Company's cash and cash equivalents increased $1.9 million or 2%, from
the June 30, 1996 ending balance to the June 30, 1997 ending balance of $88.2
million. This increase was due to the receipt of net cash flows from operating
activities in excess of the net cash flows required for investing and financing
activities for the twelve month period ended June 30, 1997.
Net cash flows from operating activities decreased in aggregate by $23.6
million in the first six months of 1997 compared with the same period in 1996.
This decrease was due to the $30.0 million contract termination fee paid to a
major coal supplier in the second quarter of 1997. Excluding the impact of
this contract termination fee, net cash flows from operating activities
increased by $6.4 million in the first six months of 1997 compared with the
same period in 1996. This increase was due primarily to an increase in cash
receipts from retail and wholesale customers, a $4.5 million reduction in wages
paid (net of amounts capitalized), and a $4.8 million decrease in taxes paid
(net of amounts capitalized) during the first quarter of 1997 compared with the
same period in 1996. These increases to net cash flows were partially offset
by higher fuel and purchased power costs, a $9.3 million increase in payment of
other operations and maintenance costs in the first half of 1997, and the
receipt of $4.1 million in cash related to the sale of emission allowances in
the first quarter of 1996.
Net cash outflows from investing activities decreased in aggregate by $6.1
million in the first six months of 1997 compared with the same period in 1996,
due to a reduction in construction expenditures and in investments in joint
ventures.
Net cash outflows from financing activities increased in aggregate by
$25.7 million in the first six months of 1997 compared with the same period in
1996 as a result of the Company's repayment of the $31 million Renewable Term
Loan balance during the first quarter of 1997.
FINANCING DEVELOPMENTS
Sale of New Bonds
On April 29, 1997, the City of Farmington, New Mexico issued $80.41
million aggregate principal amount of its 1997 Series A Pollution Control
Revenue Bonds (Tucson Electric Power Company San Juan Project) for the benefit
of the Company. The proceeds from this issuance were made available to the
Company under an installment sale agreement and were used on June 12, 1997 to
redeem all of the City of Farmington's Series 1973 Pollution Control Revenue
bonds (Tucson Gas & Electric Company San Juan Project), 6.25% due in 2003
($47.91 million aggregate principal amount) and all of the City of Farmington's
1977 Series A Collateralized Pollution Control Revenue bonds (Tucson Gas &
Electric Company San Juan Project), 6.10% due 2007 ($32.5 million aggregate
principal amount). The Farmington 1977 Series A bonds were secured by an equal
principal amount of First Mortgage Bonds, which were cancelled. The new bonds,
which are unsecured, bear interest at a fixed annual rate of 6.95% and mature
in October 2020.
On April 29, 1997, the Coconino County, Arizona Pollution Control
Corporation issued $36.7 million aggregate principal amount of its 1997 Series
A Pollution Control Revenue Bonds (Tucson Electric Power Company Navajo
Project) for the benefit of the Company. The proceeds from this issuance were
loaned to the Company and were used on June 4, 1997 to (i) redeem all of the
1996 Series A Pollution Control Revenue Bonds (Tucson Electric Power Company
Project), variable rate due 2031 ($16.7 million aggregate principal amount) and
(ii) fund the construction of additional pollution abatement facilities at the
Navajo Generating Station. The new bonds, which are unsecured, bear interest
at a fixed annual rate of 7.125% and mature in October 2032.
On April 29, 1997, the Coconino County, Arizona Pollution Control
Corporation also issued $14.7 million aggregate principal amount of its 1997
Series B Pollution Control Revenue Bonds (Tucson Electric Power Company Navajo
Project) for the benefit of the Company. The proceeds from this issuance were
loaned to the Company and were used on June 4, 1997 to redeem all of the 1996
Series B Pollution Control Refunding Revenue Bonds (Tucson Electric Power
Company Project), variable rate due 2031 ($14.7 million aggregate principal
amount). The new bonds, which are unsecured, bear interest at a fixed annual
rate of 7.00% and mature in October 2032.
The redeemed Coconino bonds were backed by letters of credit. The issuers
of such letters of credit held First Mortgage Bonds in the aggregate principal
amount of $34.5 million to secure the Company's reimbursement obligations.
Upon the redemption of such Coconino bonds, the aggregate principal amount of
Company debt backed by letters of credit was reduced from $805 million to $774
million. The aggregate principal amount of First Mortgage Bonds outstanding
was also reduced by $34.5 million.
Financing Application Filed with ACC
On July 11, 1997, the Company filed an application with the ACC requesting
authority to enter into certain financing transactions. The proposed financing
transactions are intended to extend debt maturities and letter of credit
expiration dates, gain additional financial and operating flexibility through
the replacement or modification of certain credit agreements, reduce exposure
to variable interest rates, reduce dependence on letters of credit and
strengthen the Company's balance sheet by raising additional equity capital.
The application requests authorization for four financings. First, the Company
seeks authority to refinance up to $450 million of existing tax-exempt variable
rate debt obligations currently backed by letters of credit. These
refinancings are expected to be on a fixed rate, unsecured basis. Second, the
Company seeks authority to replace its current bank credit facility under the
MRA, with one or more new bank credit facilities. The Company anticipates that
the new credit facilities will be reduced in size (due to the refinancing
activity described above), will have extended maturities or termination dates,
and will contain less restrictive covenants than the MRA. Third, the Company
requests authority to refinance up to $184 million in first mortgage bonds,
scheduled to mature between 1999 and 2003, with the issuance of new securities
consisting of debt/and or equity securities. Fourth, the Company seeks
authority to establish a direct stock purchase plan, which would allow small
investors to purchase shares directly from the Company. Pursuant to this plan,
the Company would issue from time to time up to 1,000,000 shares of Common
Stock, without par value.
The financial transactions contemplated by the application represent the
Company's current plan to meet certain of its financial obligations. Subject
to the receipt of ACC authorization, the Company intends to pursue the
negotiation and consummation of such transactions over the next two years.
Even if the requested ACC authorization is granted, there can be no assurance
that any of the contemplated transactions will be consummated or that the terms
of any transactions which are consummated will result in the realization of
such objectives.
The Company expects to incur increased financing costs as a result of the
completion of the proposed financings. The Company believes, however, that
such costs are outweighed by the related benefits, including the extension of
maturities, reduction in volatility of capital costs, elimination of certain
restrictions on dividends and increases in equity.
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
- ------------------------------------------
This Quarterly Report on Form 10-Q contains forward-looking statements as
defined by the Private Securities Litigation Reform Act of 1995. The Company
is including the following cautionary statements to make applicable and take
advantage of the safe harbor provisions of the Private Securities Litigation
Reform Act of 1995 for any forward-looking statements made by, or on behalf, of
the Company in this Quarterly Report on Form 10-Q. Forward-looking statements
include statements concerning plans, objectives, goals, strategies, future
events or performance and underlying assumptions and other statements which are
other than statements of historical facts. Such forward-looking statements may
be identified, without limitation, by the use of the words "anticipates,"
"estimates," "expects," "intends," "plans," "predicts," "projects," and similar
expressions. From time to time, the Company may publish or otherwise make
available forward-looking statements of this nature. All such forward-looking
statements, whether written or oral, and whether made by or on behalf of the
Company, are expressly qualified by these cautionary statements and any other
cautionary statements which may accompany the forward-looking statements. In
addition, the Company disclaims any obligation to update any forward-looking
statements to reflect events or circumstances after the date hereof.
Forward-looking statements involve risks and uncertainties which could
cause actual results or outcomes to differ materially from those expressed in
the forward-looking statements. The Company's expectations, beliefs and
projections are expressed in good faith and are believed by the Company to have
a reasonable basis, including without limitation, management's examination of
historical operating trends, data contained in the Company's records and other
data available from third parties, but there can be no assurance that
management's expectations, beliefs or projections will result or be achieved or
accomplished. In addition to other factors and matters discussed elsewhere
herein, some of the important factors that, in the view of the Company, could
cause actual results to differ materially from those discussed in the forward-
looking statements include the following:
1. Effects of restructuring initiatives in the electric industry and other
energy-related industries.
2. Changes in economic conditions, demographic patterns and weather conditions
in the Company's retail service area.
3. Changes affecting the Company's cost of providing electrical service
including, but not limited to, changes in fuel costs, generating unit
operating performance, interest rates, tax laws, environmental laws, and
the general rate of inflation.
4. Changes in governmental policies and regulatory actions with respect to
allowed rates of return, financings, and rate structures.
5. Changes affecting the cost of competing energy alternatives, including
changes in available generating technologies and changes in the cost of
natural gas.
6. Changes in accounting principles or the application of such principles to
the Company.
PART II - OTHER INFORMATION
ITEM 1. -- LEGAL PROCEEDINGS
- -------------------------------------------------------------------------------
TAX ASSESSMENTS
See Note 1 of Notes to Condensed Consolidated Financial Statements, Tax
Assessments.
ITEM 4. -- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- -------------------------------------------------------------------------------
The Company conducted its Annual Meeting of Shareholders on May 9, 1997.
At that meeting, the shareholders of the Company elected members of the Board
of Directors.
The total votes were as follows:
Against Broker
(i) Election of Directors or Abstain Non-Votes
For Withheld
Charles E. Bayless 28,812,056 532,775 -- --
Elizabeth T. Bilby (a) 28,838,640 506,191 -- --
Jose L. Canchola 28,803,065 541,766 -- --
John L. Carter 28,870,854 473,977 -- --
John Jeter 28,826,193 518,638 -- --
R. B. O'Rielly 28,810,229 534,602 -- --
Martha R. Seger 28,771,856 572,975 -- --
Donald G. Shropshire 28,792,609 552,222 -- --
H. Wilson Sundt 28,822,961 521,870 -- --
(a) Formerly Elizabeth Alexander
ITEM 6. -- EXHIBITS AND REPORTS ON FORM 8-K
- -------------------------------------------------------------------------------
(a) Exhibits.
10 - Amended and Restated Wholesale Power Supply Agreement between Tucson
Electric Power Company and Navajo Tribal Utility Authority, dated
June 25, 1997.
15 - Letter regarding unaudited interim financial information.
27 - Financial Data Schedule.
(b) Reports on Form 8-K.
- Dated July 3, 1997, reporting on Springerville Coal Contract and
Wholesale Power Contract with NTUA.
- Dated July 10, 1997, reporting on Shared Savings Proposal filed
with the Arizona Corporation Commission.
- Dated July 16, 1997, reporting on Financing Application filed with
the Arizona Corporation Commission.
SIGNATURE
Pursuant to the requirements 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
(Registrant)
Date: August 12, 1997 Ira R. Adler
-----------------------------------
Ira R. Adler
Senior Vice President and Principal
Financial Officer
Exhibit 15
Tucson Electric Power Company
220 West Sixth Street
Tucson, Arizona 85701
We have made a review, in accordance with standards established
by the American Institute of Certified Public Accountants, of
the unaudited interim financial information of Tucson Electric
Power Company and subsidiaries (the Company) for the three-
month and six-month periods ended June 30, 1997 and 1996, as
indicated in our report dated July 31, 1997; because we did not
perform an audit, we expressed no opinion on that information.
We are aware that our report referred to above, which is
included in your Quarterly Report on Form 10-Q for the
quarter ended June 30, 1997, is incorporated by reference in
Post-Effective Amendment No. 1 to Registration Statement No. 33-
55732 of the Company on Form S-3, Registration Statement No. 33-
58173 of UniSource Energy Corporation on Form S-4, Registration
Statements No. 33-56523, No. 33-57233 and No. 33-57231 of the
Company on Form S-8 and Registration Statement No. 33-31043 on
Form S-3.
We are also aware that the aforementioned report, pursuant to
Rule 436(c) under the Securities Act of 1933, is not considered
a part of the Registration Statement prepared or certified by
an accountant or a report prepared or certified by an
accountant within the meaning of Sections 7 and 11 of that Act.
DELOITTE & TOUCHE LLP
Tucson, Arizona
August 11, 1997
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Exhibit 10
AMENDED AND RESTATED
WHOLESALE POWER SUPPLY AGREEMENT
BETWEEN
TUCSON ELECTRIC POWER COMPANY
AND
NAVAJO TRIBAL UTILITY AUTHORITY
DATED JUNE 25, 1997
TABLE OF CONTENTS
-----------------
SECTION
I. PARTIES .................................................1
II. DEFINITIONS..............................................1
III. TERM, TERMINATION AND RIGHT TO REOPEN....................6
A. Term .................................................6
B. Effective Date .......................................6
C. Termination ..........................................6
D. Right to Reopen ......................................6
E. Filing of Amended and Restated Agreement .............7
F. Representations of the Parties ...................7
IV. PHASE I: 1997 - 1999 ENERGY AND CAPACITY................8
A. Hourly Requirements ..................................8
1. Generation Billing Demand ........................8
2. Loss of Coal Mining Load .........................9
3. Generation Demand Charge .........................9
4. Energy Charges ...................................9
5. Transmission Losses ..............................9
B. Wholesale Market Purchases - New Industrial Load .....9
C. CRSP Allocation ......................................9
D. Energy Scheduling and Dispatching ....................10
V. PHASE I: 1997 - 1999 TRANSMISSION.......................10
A. Hourly Requirements ..................................10
B. CRSP Allocation ......................................10
C. Wholesale Market Purchases - New Industrial Load .....11
i
D. Billing for Transmission Service .....................11
E. Transmission Losses ..................................11
VI. PHASE II: 1999 - 2009 ENERGY AND CAPACITY...............11
A. TEP Firm Power Supply ................................11
1. Generation Billing Demand ........................11
2. Generation Demand Charges ........................11
3. Energy Charges ...................................11
4. Energy Scheduling ................................11
5. Transmission Losses .............................12
B. Resource Management of CRSP Allocation ...............12
C. Wholesale Market Purchases ...........................12
1. Initial Selection of Option ......................12
2. Options ..........................................12
a. Option 1 .....................................12
b. Option 2 .....................................12
c. Option 3 .....................................12
3. Subsequent Selection of Options ..................13
4. Coordination of NTUA Resources Under Option 3 ...13
a. Description ..................................13
b. TEP Supplemental Service .....................14
(i) Energy Price.............................14
(ii) Other Charges ...........................14
c. Market Access Service ........................14
(i) Contracts with Third-Party Suppliers.....14
(ii) Contracts with TEP ......................14
(iii)Pricing .................................14
5. Firm Backup Power Supply .........................15
a. Pricing ......................................15
b. Energy .......................................15
6. Management Fee for Market Services ...............15
a. Service Provided .............................15
ii
(i) Fee.......................................15
(ii)Billing ..................................15
D. Combustion Turbine Option ............................16
E. Local Generation .....................................16
VII. PHASE II: 1999 - 2009 TRANSMISSION......................16
A. TEP Firm Power Supply ................................16
B. CRSP Allocation ......................................16
C. Wholesale Market Purchases ...........................16
D. Billing for Transmission Service .....................17
E. Transmission Losses ..................................17
VIII.INDUSTRIAL LOAD RETENTION ...............................17
IX. BILLING AND PAYMENT......................................17
A. Billing ..............................................17
1. Bill Format ......................................17
2. Billing Inquiries ................................18
B. Payment ..............................................18
C. Disputed Bills .......................................18
D. Taxes ................................................19
E. Audit Rights .........................................19
X. AUTHORIZED REPRESENTATIVES...............................19
A. Designation ..........................................19
B. Duties ...............................................20
XI. UNCONTROLLABLE FORCES....................................20
XII. ASSIGNMENT OF AGREEMENT..................................20
XIII.NO DEDICATION OF FACILITIES..............................21
iii
XIV. NOTICES..................................................21
XV. GOVERNING LAW............................................22
XVI. NO THIRD PARTY RIGHTS....................................22
XVII.WAIVERS..................................................22
XVIII.RESOLUTION OF DISPUTES..................................23
XIX. LIABILITY AND INDEMNITY..................................23
XXX. INTERPRETATION...........................................24
A. Prior Negotiations ...................................24
B. Descriptive Headings .................................24
C. Governing Agreement ..................................24
EXHIBIT A Phase I Rate Schedule 1997 - 1999..................A-1
EXHIBIT B Phase II Rate Schedule 1999 - 2009.................B-1
EXHIBIT C Control Area Services..............................C-1
EXHIBIT D Firm Backup Power Supply Demand Charges............D-1
EXHIBIT E NTUA - TEP Network Transmission Agreement..........E-1
iv
I. PARTIES
The Parties to this Amended and Restated Wholesale Power Supply Agreement
("Agreement") are TUCSON ELECTRIC POWER COMPANY, an Arizona Corporation
("Tucson" or "TEP") and the NAVAJO TRIBAL UTILITY AUTHORITY ("NTUA"), an
enterprise and public agency of the Navajo Nation. Tucson and NTUA may
collectively be referred to herein as "Parties" or singularly as a "Party."
Tucson is engaged in the generation and distribution of electric power and
energy in the states of Arizona and New Mexico. Tucson also sells at wholesale
throughout the western United States and provides transmission service pursuant
to its Open Access Transmission Tariff.
NTUA is engaged in the distribution of power and energy on the Navajo
Reservation in northern Arizona, southern Utah and northwest New Mexico.
Electrical system interconnections exist which permit Tucson to sell and
deliver to NTUA, and NTUA to purchase and receive power and energy.
Tucson and NTUA previously entered into a Wholesale Power Supply Agreement
dated January 5, 1993, effective June 1, 1993, FERC Rate Schedule No. 93. The
Parties wish to amend and restate that Agreement to provide for the firm sale
and purchase of energy and capacity under different terms, and to separate and
unbundle transmission service from the sale of capacity and energy, as required
by FERC Orders 888 and 888-A. This amended and restated Agreement, once
accepted by FERC, shall replace in its entirety the January 5, 1993, Wholesale
Power Supply Agreement.
Tucson desires to sell and NTUA desires to purchase firm capacity and
energy from Tucson. NTUA will purchase, pursuant to a separate NTUA-TEP Network
Transmission Agreement, transmission for delivery of power and energy to stated
Delivery Points pursuant to this Agreement. The Parties therefore, agree as
follows:
II. DEFINITIONS
AGGREGATE DEMAND CHARGE: The charge per kilowatt-month for capacity TEP
delivers and NTUA receives at the Delivery Points, which includes the price of
1
generation and the price of basic transmission service and ancillary services.
AGREEMENT: This Tucson-NTUA Amended and Restated Wholesale Power Supply
Agreement, including all exhibits, attachments and any written amendments to
which the Parties may agree from time to time.
AUTHORIZED REPRESENTATIVE: The representative of a Party designated in
accordance with Section X.
CAPACITY LOSSES: The capacity required to compensate for transmission
losses on third party transmission systems pursuant to Sections IV.A.5, V.E,
VI.A.5 and VII.E.
COLLECTED FUNDS: Funds that have been deemed by the recipient bank, in
accordance with standard banking practice, to be cleared and therefore
immediately available for investment or disbursement.
COMBUSTION TURBINE: A peaking resource planned for and installed by TEP
in the Tucson vicinity.
CONTROL AREA SERVICES: The FERC defined Ancillary Services included in
Tucson's Open Access Tariff and as detailed in Exhibit C.
CONTRACT YEAR: January 1 through December 31, after the first seven
months of Phase II.
CRSP ALLOCATION: Capacity and energy available to NTUA pursuant to
Contract No.87-SLC-0013, as amended, between WAPA and NTUA; such Scheduled CRSP
Capacity and Energy is delivered directly to NTUA at the Kayenta and Longhouse
Valley substations over WAPA's transmission system.
DELIVERY POINTS: The points at which Tucson shall deliver NTUA's
capacity and energy as per Exhibit E, NTUA-TEP Network Transmission Agreement,
which shall be WAPA's Shiprock 345-kV, San Juan 345-kV, McKinley 345-kV, Four
Corners 345-kV, Springerville 345-kV and Saguaro 500-kV. Other Delivery Points
may be agreed upon by the Authorized Representatives.
ENERGY CHARGE: The charge per kilowatt-hour for energy TEP delivers and
NTUA receives at the Delivery Points.
ENERGY LOSSES: The energy required to compensate for transmission losses
on third-party transmission systems pursuant to Section IV.A.5, V.E., VI.A.5,
and VII.E.
2
Firm Backup Power Supply: The provision of capacity and energy to
NTUA to satisfy WSCC and NERC reliability requirements and to backup Market
Access Service, TEP Supplemental Service, as well as participation in a
combustion turbine project with Tucson or Local Generation resources. See
Western Systems Coordinating Council Power Supply Design Criteria, revised
March 1997.
GENERATION BILLING DEMAND ("GBD"): The kilowatt demand for which NTUA
shall pay the Generation Demand Charge.
GENERATION DEMAND CHARGE: The charge per kilowatt-month for generating
capacity TEP delivers and NTUA receives at the Delivery Points.
HOURLY LOAD: The coincident kilowatt demand in any hour as measured at
the Metering Points except Other Load.
INDEPENDANT SYSTEM OPERATOR ("ISO"): A regulated organization that may
be established in the desert southwest region to, among other things: (i)
operate or coordinate the operation of the bulk power transmission in the
region so as to assure its reliable and efficient use; and (ii) facilitate non-
discriminatory, open access to the regional transmission system.
LOCAL GENERATION: An electric generating resource, the output to which
NTUA is solely or partially entitled and which is located in NTUA's service
territory and connected to its distribution system.
MANAGEMENT FEE: An assessed charge for the coordination of all market
services provided under Section VI.C.6.
MARKET ACCESS SERVICE: Service that allows NTUA to directly access the
energy market to serve its retail and wholesale requirements customers at
prices that are determined, from time to time, by the energy marketplace.
METERED HIGH DEMAND: The highest Hourly Load during the month.
METERED POINTS: The points at which NTUA shall receive its hourly
requirements for purposes of billing and load control and may include the
following points: Nenahnezhad 69-kV, Kayenta 230-kV, Long House Valley 69-kV,
Yah-Ta-Hey 115-kV, Gray Mountain 69-kV, WAPA's Shiprock 115-kV, Indian Wells
69-kV, Jedditto 69-kV, Leupp 12.5-kV, Gap 69-kV, Copper Mine 69-kV, Lechee 69-
kV, Churchrock 13.8-kV, and other metering points as agreed to by the
3
Authorized Representatives.
NATIVE WHOLESALE LOAD CUSTOMER: A customer such as NTUA which has
existing transmission service with a term of one year or more who continues to
have the right to take transmission service from Tucson when its contract
expires, rolls over or is renewed, regardless of whether that customer
continues to purchase capacity and energy from Tucson.
NET BACKUP DEMAND: The Metered High Demand less NTUA's CRSP Allocation
less the TEP Firm Power Supply plus the coincident output of Local Generation
and less any capacity that is credited pursuant to Section VI.C.5. Net Backup
Demand is illustrated by the following equation:
NBD = MHD - CRSP - TFP + CLG - CRCT/LG
Where: NBD = Net Backup Demand
MHD = Metered High Demand
CRSP = NTUA's Colorado River Storage Project Allocation
TFP = TEP Firm Power Supply
CLG = Coincident output of Local Generation
CRCT/LG = Capacity credit for Combustion Turbine or Local Generation
pursuant to Section VI.C.5.
NETWORK TRANSMISSION CHARGE ("TN"): The charge per kilowatt-month for
basic transmission service and ancillary services that is calculated monthly
and billed to NTUA in accordance with the NTUA - TEP Network Transmission
Agreement.
NEW INDUSTRIAL LOAD: An industrial load not served by NTUA prior to the
execution of this Agreement with an expected or actual peak hourly demand of at
least 3 MW.
NTUA-TEP NETWORK TRANSMISSION AGREEMENT: An agreement for use of TEP's
transmission system pursuant to TEP's Open Access Transmission Tariff which
allows power to be delivered to NTUA under this Agreement and from other
sources, a copy of this agreement is attached hereto as Exhibit E.
OTHER LOAD: The electric load at one or more of the following locations
where NTUA serves its customers: (i) the electric railroad which is currently
used for hauling coal to the Navajo Generating Station, and (ii) remote
locations which are isolated from NTUA's main electric distribution system such
4
as Bisti, Red Mesa, and Mexican Hat.
PHASE I: July 1, 1997 through May 31, 1999.
PHASE II: June 1, 1999 through December 31, 2009.
PLAN: An operating plan developed by NTUA and TEP which outlines the
acquisition and expected usage of NTUA's resources and the wholesale
marketplace to serve NTUA's load requirements for a specified time period
pursuant to Option 3 under Phase II of this Agreement.
SCHEDULED CRSP CAPACITY: The maximum capacity available to NTUA in a
given month under the CRSP Allocation.
SCHEDULED CRSP ENERGY: The energy available to NTUA from time to time
under the CRSP Allocation, including any surplus energy that is made available
from time to time.
SUMMER MONTHS: The months of June, July, August and September.
TEP FIRM POWER SUPPLY : The firm obligation which Tucson shall have
to supply to NTUA firm capacity and energy at the Delivery Points in the
amounts specified in Section IV.A.1 for Phase I and in the amounts as specified
in Section VI.A.1 for Phase II. This supply will be neither interrupted nor
reduced, unless the integrity of the transmission system or the ability of TEP
to provide service to its retail customers or to Salt River Project under the
1990-2011 Power Sale Agreement is jeopardized, and to the extent that such
interruptions of service to NTUA are in keeping with good utility practices.
TEP SUPPLEMENTAL SERVICE: A service which allows NTUA to purchase energy
from TEP to serve its retail and wholesale requirements customers at prices
that are determined hourly by the energy marketplace.
TRANSMISSION: Either non-firm, firm or network transmission service
provided pursuant to Tucson's Open Access Transmission Tariff as filed with
FERC.
TRANSMISSION BILLING DEMAND ("TBD"): The kilowatt demand for which NTUA
shall pay the Network Transmission Charge in accordance with the NTUA-TEP
Network Transmission Agreement.
UNCONTROLLABLE FORCES: Any event beyond the control of the Party unable
to perform any of its obligations hereunder including, but not limited to,
5
failure of or threat of immediate failure of facilities; flood, earthquake,
storm, fire, lightning and other natural catastrophes; epidemic, war, riot,
civil disturbance or disobedience; labor dispute, labor or material shortage;
sabotage; restraint by court order or public authority; and action or nonaction
by, or failure to obtain the necessary authorizations or approvals from any
governmental agency or authority, which, by exercise of due diligence, such
Party could not reasonably have been expected to avoid and which, by exercise
of due diligence, it is unable to overcome.
WAPA: Western Area Power Administration.
Winter Months: All months other than Summer Months.
III. TERM, TERMINATION, RIGHT TO REOPEN, AND EFFECTIVE DATE
A. TERM
The Agreement shall terminate on December 31, 2009, subject to the
right of either party to reopen the agreement, as set forth in Section III.D.
B. EFFECTIVE DATE
The Agreement shall be effective upon: (i) acceptance for filing of
this Agreement by the Federal Energy Regulatory Commission ("FERC") and (ii)
the written approval of the Administrator of the Rural Utilities Service
("RUS") and of the Governor of the National Rural Electric Cooperative
Finance Corporation ("CFC").
C. TERMINATION
This Agreement shall not be subject to termination except as provided
herein.
D. RIGHT TO REOPEN
1. Each party shall have the right to request reopening of the
Agreement for any reason upon twelve months advance written notice, provided
however, that such notice cannot be given prior to December 31, 2002. Should
the Parties fail to successfully negotiate a new agreement within the twelve-
month period after written notice, this Agreement shall terminate. Subject to
the notice provision above, the earliest effective termination hereunder shall
6
be December 31, 2003.
2. Each Party shall also have the right to request, in writing,
reopening of the Agreement at any time after June 1, 1999, if in any twelve
month period, the twelve month average firm on-peak Palo Verde Index as
published in the Wall Street Journal, is less than 1.2 cents per kWh or greater
than 4.0 cents per kWh. Such request must be made within 180 days of the
occurrence of an average Palo Verde Index price outside the above-described
bandwith. Should the Parties fail to negotiate a new Agreement within twelve
months after written notice is given, this Agreement shall terminate at either
Party's request. If the termination occurs at NTUA's request, then on the tenth
day of each month following the termination of this Agreement, NTUA will make
payment of $60,000 to Tucson in each month from the date of termination through
December 31, 2003; such payments to Tucson are to be separate from other
payments due either Party pursuant to this Agreement.
3. This Agreement recognizes that the formation of an Independent
System Operator ("ISO") may affect certain provisions of this Agreement. The
Parties agree to negotiate in good faith to amend this Agreement as necessary
to accommodate an ISO should such ISO be approved by the FERC.
E. FILING OF AMENDED AND RESTATED AGREEMENT
Tucson shall file this Agreement with FERC. NTUA shall support
Tucson's filing by intervening in support of that filing at FERC. NTUA will
file and seek approval of this Agreement with the RUS and CFC.
If, after filing this Agreement, FERC requires any material modifications
to this Agreement which are unacceptable to either Party, TEP shall cause the
submittal of this Agreement for filing with FERC to be withdrawn. If, after
filing this Agreement, RUS or CFC requires any material modifications to this
Agreement that are unacceptable to either Party, NTUA shall cause the submittal
of this Agreement for filing with such parties to be withdrawn.
However, until all necessary regulatory approvals of this Agreement have
been obtained, the Wholesale Power Sale Agreement, shall remain in full force
and effect, and NTUA shall pay all charges thereunder. If this Agreement does
not receive all necessary approvals, the Wholesale Power Sale Agreement, dated
7
January 5, 1993, shall remain in effect throughout its term. If all regulatory
approvals are obtained, the Agreement shall be deemed to have been effective
July 1, 1997. Within 30 days of receipt of all approvals, TEP shall refund to
NTUA the difference between monies paid under the Wholesale Power Sale
Agreement dated January 5, 1993, since July 1, 1997 and monies that would have
been paid pursuant to this Agreement since July 1, 1997.
F. REPRESENTATIONS OF THE PARTIES
1. Tucson hereby represents, warrants and covenants to NTUA as
follows:
a) Tucson is an Arizona corporation duly organized, validly
existing and in good standing under the laws of the State of Arizona and has
corporate power and authority to execute and deliver this Agreement and perform
its obligations hereunder, and to carry on its business as it is now being
conducted and as it is contemplated hereunder to be conducted during the term
hereof.
b) The execution, delivery and performance of this Agreement by
Tucson has been duly and effectively authorized by all requisite corporate
action.
2. NTUA hereby represents, warrants and covenants to Tucson as
follows:
a) NTUA is an enterprise and public agency of the Navajo Nation;
is duly organized, validly existing and in good standing under the laws of the
Navajo Nation; and has the requisite power and authority to execute this
Agreement, to perform its obligations hereunder, and to carry on its business
as it is now being conducted and as it is contemplated hereunder to be
conducted during the term hereof and this Agreement has been duly executed and
delivered by NTUA and is the legal, valid and binding obligation of NTUA,
enforceable against it in accordance with its terms.
b) Subject to the provisions of Section III.E, the execution,
delivery and performance of this Agreement by NTUA have been duly and effec-
tively authorized by all requisite action.
8
IV. PHASE I: 1997 - 1999 ENERGY AND CAPACITY
During Phase I of this Agreement, the Parties intend that NTUA shall
satisfy its load requirements, except Other Load, from two sources: (i)TEP Firm
Power Supply pursuant to this Agreement, and (ii) its CRSP Allocation. NTUA may
satisfy New Industrial Load through market purchases. To satisfy the first
source, the Parties agree that:
A. HOURLY REQUIREMENTS
The Parties agree that for Phase I, Tucson shall sell and NTUA shall
purchase a TEP Firm Power Supply for NTUA's Hourly Load, excluding market
purchases for New Industrial Load and loads served with NTUA's CRSP Allocation,
upon the following terms:
1. GENERATION BILLING DEMAND: For Phase I, the Generation Billing
Demand shall be 60 MW. For this Generation Billing Demand, Tucson agrees to
deliver TEP Firm Power Supply in amounts up to 69 MW in Summer Months, and
higher amounts, as required, in Winter Months. If the TEP Firm Power Supply in
the Summer Months exceeds 69 MW, the Generation Billing Demand will ratchet on
a twelve-month basis to 60 MW plus any amounts in excess of 69 MW. Generation
Billing Demand in Winter Months shall be the same as the Summer Generation
Billing Demand. In Phase I TEP Firm Power Supply is the actual Hourly Load plus
Capacity Losses, less Scheduled CRSP Capacity, less NTUA market purchases for
New Industrial Load.
2. LOSS OF COAL MINING LOAD: If NTUA anticipates long-term (greater
than six consecutive months) loss of coal mining loads in the aggregate of 9 MW
or greater, NTUA shall give Tucson sixty days prior written notice of the
anticipated date and amounts of load loss. Tucson shall reduce the Generation
Billing Demand effective the next billing period after the reduction in load or
shutdown, by one-half of the amount of load lost. This reduction shall only
apply during Phase I.
3. GENERATION DEMAND CHARGE: The Generation Demand Charges for Phase
I are set forth in Exhibit A, Phase I Rate Schedule.
4. ENERGY CHARGES: For Phase I, the Energy Charge shall be as stated
9
in Exhibit A, for the amount of the total energy usage recorded monthly at all
Metering Points, plus Energy Losses, less Scheduled CRSP Energy, less energy
from NTUA market purchases for New Industrial Load to the extent such energy is
recorded at the Metering Points.
5. TRANSMISSION LOSSES: Tucson shall supply and be responsible for
transmission losses to the Delivery Points. Tucson shall supply Capacity Losses
and Energy Losses to compensate for transmission losses from the Delivery
Points to the Metering Points as specifically required by arrangements between
NTUA and third-party transmission owners.
B. WHOLESALE MARKET PURCHASES - NEW INDUSTRIAL LOAD
NTUA shall have the right to seek alternate suppliers for New
Industrial Load.
C. CRSP ALLOCATION
Tucson shall manage NTUA's CRSP Allocation such that: (i) it satisfies
a portion of NTUA's load, and (ii) NTUA receives full credit in the calculation
of Generation Billing Demand. It is understood that NTUA's CRSP Allocation is
delivered over WAPA's transmission system and does not involve or require the
use of Tucson's transmission system.
D. ENERGY SCHEDULING AND DISPATCHING
1. In Phase I, Tucson shall manage NTUA's CRSP Allocation, TEP Firm
Power Supply, and market purchases for New Industrial Load to serve NTUA's
total load requirements except Other Load. The Authorized Representatives
shall make procedural modifications as necessary for this management, including
all necessary billing procedure modifications.
2. Semiannually, NTUA shall provide Tucson with an estimate of the
monthly energy deliveries under its CRSP Allocation. Tucson shall schedule
NTUA's CRSP Allocation with WAPA.
10
3. In the event that either Party determines that it is adversely
impacted by the scheduling and dispatching procedures, the Authorized
Representatives will agree to modify the procedures if at all possible, or to
discontinue such procedures if it becomes necessary. In the latter case, Tucson
shall schedule and dispatch according to guidelines provided by NTUA. The
Authorized Representatives will coordinate any changes affecting hourly
scheduling requirements.
4. Tucson shall maintain records of Hourly Loads and schedules of
energy transactions for accounting and operating purposes and upon request will
furnish copies of such records to NTUA.
V. PHASE I: 1997 - 1999 TRANSMISSION
A. HOURLY REQUIREMENTS
PROVISION OF TRANSMISSION SERVICE: NTUA, as an existing Native
Wholesale Load Customer, shall continue to have the right to take transmission
service pursuant to Section 2.2 of Tucson's Open Access Tariff. To accomplish
delivery of capacity and energy for Phase I, NTUA shall be responsible for
requesting and obtaining transmission service from Tucson under TEP's Open
Access Tariff for delivery to the Delivery Points.
B. CRSP ALLOCATION
The Parties recognize that NTUA's CRSP allocation is delivered to NTUA
by WAPA from WAPA's facilities, and, therefore, no TEP transmission is required
for TEP's management of CRSP Allocation because NTUA accepts direct delivery of
and title to the Allocation.
C. WHOLESALE MARKET PURCHASES - NEW INDUSTRIAL LOAD
If necessary, NTUA shall be responsible for requesting and obtaining
transmission service from Tucson for delivery to the Delivery Points for any
wholesale market purchases.
D. BILLING FOR TRANSMISSION SERVICE
TEP shall separate the transmission charges on all bills.
E. TRANSMISSION LOSSES
11
Tucson shall supply and be responsible for transmission losses to the
Delivery Points. Tucson shall supply Capacity Losses and Energy Losses to
compensate for transmission losses from the Delivery Points to the Metering
Points as specifically required by arrangements between NTUA and third-party
transmission line owners.
VI. PHASE II: 1999 - 2009 ENERGY AND CAPACITY
During Phase II of the Agreement, the Parties intend that NTUA may satisfy
its load requirements, except Other Load, through a combination of: (i)TEP Firm
Power Supply pursuant to this Agreement, (ii) its CRSP Allocation, (iii)
purchases from the wholesale power market, (iv) participation in a Combustion
Turbine project with Tucson, and (v) through Local Generation behind the
Metering Points. To accomplish this combination, the Parties agree:
A. TEP FIRM POWER SUPPLY
During Phase II, Tucson shall have the firm obligation to supply and
NTUA shall purchase 40 MW of TEP Firm Power Supply at the Delivery Points, in
the Summer Months and 50 MW in the Winter Months:
1. GENERATION BILLING DEMAND: Shall be 40 MW in all months for Phase
II.
2. GENERATION DEMAND CHARGES: The Generation Demand Charges for Phase
II are set forth in Exhibit B, Phase II Rate Schedule.
3. ENERGY CHARGES: The Energy Charges for Phase II shall be as stated
in Exhibit B, for the amount of TEP Firm Power Supply energy delivered at the
Delivery Points.
4. ENERGY SCHEDULING: In Phase II TEP and NTUA will develop
appropriate scheduling procedures and guidelines or shall utilize such
procedures and guidelines as developed and utilized in Phase I.
5. TRANSMISSION LOSSES: Tucson shall supply and be responsible for
transmission losses to the Delivery Points. Tucson shall supply Capacity Losses
and Energy Losses to compensate for transmission losses from the Delivery
Points to the Metering Points as specifically required by arrangements between
12
NTUA and third-party transmission owners. However, TEP's obligation to deliver
TEP Firm Power Supply shall not exceed the amounts described in Section VI.A.
B. RESOURCE MANAGEMENT OF CRSP ALLOCATION
Tucson shall manage NTUA's CRSP Allocation such that it satisfies a
portion of NTUA's load. It is understood that NTUA's CRSP Allocation is
delivered over WAPA's transmission system and does not involve or require the
use of Tucson's transmission system. Semiannually, NTUA shall provide Tucson
with an estimate of the monthly energy deliveries under its CRSP Allocation.
Tucson shall schedule NTUA's CRSP Allocation with WAPA.
C. WHOLESALE MARKET PURCHASES
This Section provides the options upon which the Parties have agreed to
accommodate other resources, allowing NTUA flexibility to manage its remaining
wholesale needs on its own or on a coordinated basis with TEP:
1. INITIAL SELECTION OF OPTION: By January 1, 1999 NTUA must make a
written election of Option 1, 2 or 3. This written election shall comply with
the notice provisions of this Agreement.
2. OPTIONS:
A. OPTION 1: NTUA may operate as an independent control area or
it may acquire Control Area Services from a third party and independently
obtain resources to meet the remainder of its total load requirements.
B. OPTION 2: NTUA may purchase Control Area Services from TEP and
independently obtain resources to meet the remainder of its total load
requirements. See Control Area Services in Exhibit C.
C. OPTION 3: NTUA may purchase Control Area Services from TEP and
in coordination with TEP obtain resources to meet its remaining load
requirements. See TEP Supplemental Service and Market Access Service in Section
VI.C.4, Combustion Turbine in Section VI.D, and Local Generation in Section
VI.E.
3. SUBSEQUENT SELECTION OF OPTIONS:
A. IF AT ANY TIME NTUA ELECTS OPTION 1, it waives its right to
select Options 2 or 3.
B. IF AT ANY TIME NTUA ELECTS OPTION 2, then:
13
(i) NTUA waives its right to exercise Option 3 at any time.
(ii) NTUA may elect Option 1 by giving ninety days written
notice to TEP.
C. IF NTUA INITIALLY ELECTS OPTION 3, then; NTUA may elect Option
1 or Option 2 upon ninety days written notice to TEP and NTUA thereby waives
the right to further service under Option 3.
If NTUA elects Options 2 or 3 it is required to purchase Control Area
Services from TEP unless such services are purchased from an ISO. Additionally,
if NTUA chooses Option 3 it is required to purchase Firm Backup Power Supply
from TEP to fulfill WSCC and NERC reliability requirements.
4. COORDINATION OF NTUA'S RESOURCES UNDER OPTION 3:
A. DESCRIPTION: At NTUA's direction, TEP will coordinate the
utilization of NTUA's resources and market purchases using its best efforts to
efficiently provide NTUA's electric supply requirements. Options for providing
service to NTUA include: its CRSP Allocation, TEP Firm Power Supply, TEP
Supplemental Service and Market Access Service, participation in a Combustion
Turbine project with Tucson, and Local Generation resource(s) as discussed
below. The Firm Backup Power Supply described later in Section VI.C.5 firms the
TEP Supplemental Service and Market Access Service, as well as any capacity
from participation in a Combustion Turbine project with Tucson or Local
Generation resource(s).
To coordinate NTUA's resource options to meet NTUA's retail obligations and
wholesale requirements customers' needs,TEP and NTUA Authorized Representatives
will meet periodically to discuss relevant market information, NTUA load
expectations and to jointly develop a Plan. The Plan will be furnished to TEP
in writing and TEP will act as NTUA's agent under the guidance of the Plan. The
Authorized Representatives or their designees will manage the Plan process.
These Authorized Representatives will develop specific procedures which will
guide the process of activating the Plan (in a manner which will try to comply
with the notion that neither Party takes on any risk that is the responsibility
of the other Party in accommodating the Plan).
B. TEP SUPPLEMENTAL SERVICE: Allows NTUA to purchase energy from
14
Tucson to serve any portion of its energy needs at prices determined by the
hourly marketplace. TEP Supplemental Service is priced as follows:
(I) ENERGY PRICE: The price for TEP Supplemental Service shall
be the Palo Verde Index for firm energy as published in the Wall Street Journal
(the index may be changed upon mutual agreement of the Authorized
Representatives) for each hour during which TEP Supplemental Service is
required, plus
(II) OTHER CHARGES: NTUA is also responsible for the
Management Fee as defined in Section VI.C.6 and the Firm Backup Supply charges
as defined in Section VI.C.5.
C. MARKET ACCESS SERVICE: Allows NTUA access to the energy market
through contracts with third parties or with TEP to serve NTUA's resource
requirements in addition to its CRSP Allocation, TEP Firm Power Supply and/or
TEP Supplemental Service.
(I) CONTRACTS WITH THIRD-PARTY SUPPLIERS: TEP agrees to act as
agent for NTUA in evaluating, procuring and scheduling market purchases. TEP
may contract with third parties as directed in the Plan. Any third-party
contracts entered into by TEP on behalf of NTUA must be confirmed by NTUA
pursuant to the Plan developed between the Parties.
(II) CONTRACTS WITH TEP: As directed under the Plan, NTUA may
contract with TEP for quantities of capacity and energy at terms and prices to
be agreed upon from time to time. Any such agreements between TEP and NTUA
maybe done under TEP's Coordination Tariff or some other enabling agreement
allowing TEP and NTUA to do business.
(III) PRICING: Prices associated with Market Access Service
will be determined pursuant to the contracts with TEP or with third parties
entered into pursuant to the Plan. TEP will charge NTUA for the actual costs
billed under those agreements, including any third party transmission costs
necessary to complete the transactions. NTUA is also responsible for the
Management Fee as defined in Section VI.C.6 and the Firm Backup Supply charges
as defined in Section VI.C.5.
15
5. FIRM BACKUP POWER SUPPLY
TEP shall provide Firm Backup Power Supply to NTUA under the
following terms:
A. PRICING: The pricing for Firm Backup Power Supply will be the
demand charge as shown in Exhibit D. The monthly demand associated with Firm
Backup Power Supply will be determined by the highest of the following: (i)
NTUA's Net Backup Demand for the month, or (ii) the highest Net Backup Demand
during the preceding eleven months. In the event NTUA participates in a
Combustion Turbine project with TEP or in Local Generation resource(s), NTUA
will be credited in accordance with Section VI.E.
B. ENERGY: Energy purchased under Firm Backup Power Supply will
be priced at the Palo Verde Index for firm energy as published in the Wall
Street Journal (which index may be changed upon the mutual agreement of the
Authorized Representatives).
6. MANAGEMENT FEE FOR MARKET SERVICES:
A. SERVICE PROVIDED
All market services provided under Section VI.C.4 shall be
coordinated by TEP to efficiently serve NTUA's total load requirements.
(I) FEE: The fee for market services shall reflect 15% of the
savings achieved by NTUA by comparing the actual delivered cost of market
energy (inclusive of charges for transmission, Firm Backup Power Supply and
other ancillary services) and the hypothetical cost of that same energy as if
it were purchased under the same terms and conditions as the sale of energy and
capacity under Section VI.A of this Agreement, but in no event shall the
Management Fee be less than $100,000 per Contract Year. Prior to December 31,
1998, the Authorized Representatives will develop the methodology for
determining the savings upon which the Management Fee is based.
(II) BILLING: The estimated fee shall be billed monthly as a
line item on NTUA's monthly energy and capacity bill. The monthly estimated fee
shall be $8,333. The year end bill for each year will true up the approximated
fee with actual savings achieved.
16
D. COMBUSTION TURBINE OPTION
TEP is willing to consider jointly owning a Combustion Turbine with
NTUA should TEP decide to install a Combustion Turbine in the Tucson vicinity
during the term of this Agreement.
E. LOCAL GENERATION
In the event that NTUA acquires Local Generation, NTUA may choose to
have TEP or another party operate the resource. Should NTUA select TEP to
operate the unit, NTUA and TEP will prepare the agreements necessary for the
operations, dispatch and scheduling of the resource(s). As operating agent, TEP
agrees that if the resource(s) are designed, constructed and operated to meet
good utility practices, TEP will reflect a capacity credit to NTUA for Firm
Backup Power Supply. This capacity credit will not exceed 10 MW, unless
otherwise agreed.
VII. PHASE II 1999 - 2009 TRANSMISSION
A. TEP FIRM POWER SUPPLY
NTUA, as an existing Native Wholesale Load Customer, shall continue to
have the right to take transmission service pursuant to Section 2.2 of Tucson's
Open Access Tariff for its total requirements associated with TEP provided
services.
NTUA shall obtain transmission service pursuant to the NTUA-TEP Network
Transmission Agreement.
B. CRSP ALLOCATION
The Parties recognize that NTUA's CRSP allocation is delivered to NTUA
by WAPA from WAPA's facilities, and, therefore, no TEP transmission is required
for TEP's management of CRSP Allocation because NTUA accepts direct delivery of
and title to the Allocation.
C. WHOLESALE MARKET PURCHASES
Transmission shall be provided pursuant to TEP's Open Access
Transmission Tariff or, when required, from other parties' open access
transmission tariffs. TEP will directly charge NTUA for the costs of any
transmission acquired from TEP or others to deliver energy under Firm Backup
17
Power Supply. To the extent that transmission is utilized for which NTUA
already has acquired rights under VII.A above, no additional charges will be
incurred.
D. BILLING FOR TRANSMISSION SERVICE
TEP shall separately state all the transmission charges on bills.
E. TRANSMISSION LOSSES
Tucson shall supply and be responsible for transmission losses to the
Delivery Points. Tucson shall supply Capacity Losses and Energy Losses to
compensate for transmission losses from the Delivery Points to the Metering
Points as specifically required by arrangements between NTUA and third-party
transmission line owners. TEP's obligation to deliver TEP Firm Power Supply
shall not exceed the amounts described in Section VI.A.
VIII.INDUSTRIAL LOAD RETENTION
TEP and NTUA will work together in good faith to retain any of NTUA's large
industrial coal mining and transportation customers, as well as any federal or
state aggregated loads, which may seek alternative supplies or to move their
electric load elsewhere. In such situations, NTUA and TEP agree to endeavor to
seek solutions that are to their mutual benefit.
IX. BILLING AND PAYMENT
A. BILLING
Tucson shall bill NTUA monthly on or before the tenth day of the month
during Phase I and Phase II. Bills shall be sent electronically to:
Navajo Tribal Utility Authority
Attention: General Manager
Facsimile (602) 729-2135
and with a written copy mailed to:
Navajo Tribal Utility Authority
18
Attention: General Manager
P.O. Box 170
Ft. Defiance, Arizona 86504-0170
1. BILL FORMAT
The bills shall separately state the charges for
(i) capacity and energy supplied in Phase I and Phase II of this
Agreement,
(ii) the charge for any market services provided in Phase II,
(iii) the Management Fee under Phase II, and
(iv) the transmission provided in Phases I and II under a
separate NTUA-TEP Network Transmission Agreement.
2. BILLING INQUIRIES
Billing inquiries concerning either the capacity and energy
supplied in Phases I or II, the market services in Phase II or the Management
Fee in Phase II shall be directed to the Tucson Manager of Contracts and
Wholesale Marketing.
Billing Inquiries concerning the transmission charges provided
under a separate NTUA-TEP Network Transmission Agreement shall be directed to
the Tucson Transmission Coordinator.
B. PAYMENT
NTUA shall pay Tucson by the tenth day after electronic receipt of the
bill. If the due date falls on a weekend or bank holiday, then NTUA shall pay
Tucson on the first subsequent banking day. Payment shall be made by electronic
funds transfer to:
Bank One Arizona
Tucson, Arizona
ABA# 122-100-024
Credit Account #2002-8131
Tucson Electric Power Company
Amounts not paid by the due date shall be payable with interest accrued
19
on each calendar day from the due date to the date of payment. The interest
rate shall be at the effective prime commercial lending rate per annum as
published in the Wall Street Journal, or at the maximum rate permitted by
Arizona law, whichever rate is lower.
Either Party may at any time by written notice change the designation
of any person, address or account specified herein.
C. DISPUTED BILLS
In the event any portion of any bill is disputed, the disputed amount
shall be paid when due under protest. If the disputed portion of the bill is
found to be incorrect, Tucson shall promptly refund to NTUA any amount due,
including interest accrued on such amount due from the date of payment by NTUA
to the date the refund is made by Tucson. The refund shall be made by wire
transfer to a bank of NTUA's choice or by any other method which provides
Collected Funds on the date payment is made. The interest rate shall be at the
rate specified in this Section. No payment made pursuant to this Section shall
constitute a waiver of any right of NTUA to contest the correctness of any
charge or credit by Tucson.
D. TAXES
NTUA shall have the right to appeal to the appropriate taxing authority
any taxes chargeable to NTUA under the provisions of this Agreement.
E. AUDIT RIGHTS
Each Party shall have the right to audit, at its own expense, all books
and records regarding any costs, payments, settlement, or other supporting
information pertaining to this Agreement. Adjustments to any costs, payments or
settlements discovered pursuant to an audit conducted under this section shall
be payable by the responsible Party to the owed Party within a reasonable time,
and shall include interest accrued on such adjustment from the original due
date to the date of receipt of payment of such adjustment by the owed Party at
the rate specified in this Section. All records and supporting documentation
for billings arising under this Agreement shall be retained for three years
beyond the date of the bill.
20
X. AUTHORIZED REPRESENTATIVES:
A. DESIGNATION
Each Party shall designate a person as an Authorized Representative.
Tucson shall designate two Authorized Representatives:A Contracts and Wholesale
Marketing Representative and a Transmission Representative. The Contracts and
Wholesale Marketing Representative shall be authorized to act on the provisions
of this Agreement concerning the sale of energy and capacity and market
services. The Transmission Representative shall be authorized to act on the
provisions of the NTUA-TEP Network Transmission Agreement, Exhibit E. All
Authorized Representatives shall have the authority of the Party designating to
act on its behalf in carrying out the provisions of this Agreement and may
appoint a designee or designee(s) to assist with duties. Each Party shall
notify the other Party within fifteen calendar days after execution of this
Agreement of the designation of its Authorized Representative and shall
promptly notify the other Party of any subsequent changes in such designation.
B. DUTIES
The Authorized Representatives shall develop the Plan and approve
written procedures necessary for implementation of this Agreement including
deliveries, scheduling, metering and billing. The Authorized Representatives
shall have no authority to modify any of the provisions of this Agreement. The
Authorized Representatives shall meet as required to accomplish coordination
with respect to matters which affect the implementation of this Agreement and
to designate appropriate billing and payment addresses.
XI. UNCONTROLLABLE FORCES
Neither Party shall be considered to be in default in the performance of
any of its obligations hereunder, other than the obligations to make payments of
amounts due pursuant to this Agreement, when failure of performance shall be due
to Uncontrollable Forces. The Party claiming Uncontrollable Forces shall
promptly contact the other Party and provide written notice that an
Uncontrollable Force has occurred. Nothing contained herein shall be construed
as to require either Party to settle any strike or labor dispute in which it
21
may be involved.
XII. ASSIGNMENT OF AGREEMENT
This Agreement shall inure to the benefit of and be binding upon the
Parties hereto and their respective successors and assigns, provided, however,
that this Agreement, except as hereinafter provided, may not be assigned by
either Party except with the prior written consent of the other Party, which
consent shall not be unreasonably withheld. NTUA, without the approval of
Tucson, may assign, transfer, mortgage or pledge this Agreement to create a
security interest for the benefit of the United States of America, acting
through the Administrator of RUS. Thereafter, the Administrator of RUS, without
the approval of Tucson, may (i) cause this Agreement to be sold, assigned,
transferred or otherwise disposed of to a third party pursuant to the terms
governing such security interest, or (ii) if the Administrator of RUS first
acquires this Agreement pursuant to 7 U.S.C. Section 907,sell, assign, transfer
or otherwise dispose of this Agreement to a third party,provided, however, that
in either case (i)NTUA is in default of its obligations to the Administrator of
RUS that are secured by such security interest and the Administrator of RUS has
given Tucson notice of such default; and (ii)the Administrator of RUS has given
Tucson thirty days prior notice of its intention to sell, assign, transfer or
otherwise dispose of this Agreement indicating the identity of the intended
third-party assignee or purchaser. In addition, no consent shall be required in
the event of (i)a transfer under or pursuant to a mortgage, security agreement,
deed of trust or other type of security instrument or upon foreclosure or other
action to enforce such mortgage,security agreement, deed of trust or other type
of security instrument or (ii)a transfer pursuant to a collateral assignment or
pledge of this Agreement to a bank, insurance company, or similar financial
institution to secure indebtedness incurred or to be incurred by a Party for
the purpose of or in connection with the performance of this Agreement, or
(iii) an assignment to any financing institution or institutions of any monies
due or to become due under this Agreement, or (iv) a transfer by either Party to
any entity that shall succeed by purchase, merger, consolidation or other
22
transfer of all or substantially all of that Party's assets. In any event, any
such transferee or assignee shall be bound by the terms of this Agreement and
the transferor shall cause an appropriate instrument to be delivered indicating
the transferee's agreement to be bound hereby.
XIII.NO DEDICATION OF FACILITIES
Any undertaking by one Party to the other under any provision of this
Agreement shall not constitute the dedication of ownership or title in the sys-
tem or any portion thereof of either Party to the public or to the other Party,
and it is understood and agreed that any undertaking by either Party shall
cease upon the termination of this Agreement.
XIV. NOTICES
Any notice, demand or request provided for in this Agreement, or served,
given or made in connection with it, shall be in writing and shall be deemed
properly served, given or made if delivered in person, sent by facsimile
transmission, sent electronically or sent by United States mail, postage
prepaid, to the persons specified below:
General Manager
Navajo Tribal Utility Authority
P. O. Box 170
Fort Defiance, Arizona 86504
Telephone: 520-729-6201
Facsimile: (602) 729-2135
Tucson Electric Power Company
c/o Secretary
P. O. Box 711
Tucson, Arizona 85702
23
Facsimile: (520) 884-3991
A Party may at any time, by written notice, change the designation or the
address of the person so specified.
XV. GOVERNING LAW
This Agreement shall be interpreted, governed by and construed under the
laws of the State of Arizona and the laws of the United States, as applicable,
as if executed and to be performed wholly within the State of Arizona.
XVI. NO THIRD PARTY RIGHTS
Unless otherwise specifically provided in this Agreement, the Parties do
not intend to create any duty,covenant, obligation or undertaking to or to cre-
ate any rights in or to grant any remedies to any third party as a beneficiary
of this Agreement or of any of the rights and obligations established
hereunder.
XVII.WAIVERS
The waiver by either Party of any breach of any term, covenant or condition
contained herein shall not be deemed a waiver of any other term, covenant or
condition or of any subsequent breach of the same or any other term, covenant
or condition contained herein.
XVIII.RESOLUTION OF DISPUTES
Should any dispute arise between the Parties hereto concerning the deter-
mination of the charges for power transactions and remain unresolved for a
period of sixty days, a statement of such dispute shall be forwarded by the
Authorized Representatives to the General Manager of NTUA ("GM") and the Chief
Operating Officer of Tucson ("COO") who shall meet within thirty days (or such
24
shorter or longer time as agreed upon between the GM and COO) to discuss and
attempt to reach a resolution of the dispute. Any resolution mutually agreed
upon by the GM and COO of the Parties shall be binding, subject to FERC
approval (if required by applicable law or the terms of this Agreement).
If the GM and COO of the Parties cannot resolve the dispute within thirty
days of its submission to them (or within such longer time as shall be mutually
agreed upon by the respective Parties), either Party may submit the dispute to
arbitration. Unless otherwise agreed by the Parties, the arbitration shall be
governed by the rules and practices of the American Arbitration Association
("AAA"). The award of the arbitrators shall be final and binding, subject to
FERC approval (if required by applicable law or the terms of this Agreement),
and the costs and expenses of the arbitrators shall be shared equally by the
Parties participating in the arbitration, unless otherwise decided by the
arbitrators.
The Party submitting the dispute to arbitration shall give written notice
to the other Party, setting forth in such notice in adequate detail the nature
of the dispute, and the remedy sought by such arbitration proceedings. Within
the period specified in the rules of the AAA, the other Party shall prepare its
own statement of the matter at issue and set forth in adequate detail
additional related matters or issues to be arbitrated.
XIX. LIABILITY AND INDEMNITY
Each Party shall indemnify and hold harmless the other Party and the
directors, officers and employees of such other Party from liability,loss, dam-
age, claim, costs and expenses (including attorney fees)on account of injury to
persons (including death)or damage or destruction of property arising out of or
related to the negligence, whether active or passive, of the indemnifying Party
or its officers, directors, employees or contractors in the performance of this
Agreement, provided, however, that:
1. Each Party shall be solely responsible to its own employees for all
claims or benefits due for injuries occurring in the course of their employment
or arising out of any worker's compensation law. Neither Party shall seek
25
reimbursement or subrogation from the other Party for any benefits paid to the
employees of that Party pursuant to any worker's compensation law except as
necessary to prevent double recovery by the employee.
2. Neither Party nor its directors, officers and employees shall be
liable for any loss of earnings, revenues, indirect or consequential damages,or
injury which may be incurred by the other Party as a result of curtailments,
interruptions or outages in delivery of electric services under this Agreement
by reason of any cause whatsoever, other than gross negligence or willful
misconduct.
3. Each Party shall indemnify and hold harmless the other Party and its
directors, officers and employees from any liability, loss, claim, costs and
expenses (including attorney fees) incurred by the indemnified Party in
connection with or arising out of claims made by the indemnifying Party's elec-
tric service customers as a result of any failure of a Party to provide
electric power or energy contemplated by this Agreement for any reason or any
cause whatsoever, other than gross negligence or willful misconduct.
XXX. INTERPRETATION
A. PRIOR NEGOTIATIONS
The complete agreement of the Parties is set forth in this Agreement
and supersedes all prior and contemporaneous communications, whether written or
oral.
B. DESCRIPTIVE HEADINGS
All descriptive headings contained in this Agreement are intended only
a a guidance to the content hereof and shal not be binding with respect to the
interpretation of any provision of this Agreement.
C. GOVERNING AGREEMENT
To the extent of any inconsistency between the provisions of this
Agreement and any tariff, service agreement or exhibit incorporated in this
Agreement be reference or otherwise, the provisions of this Agreement shall
control.
26
IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed this
26 day of June, 1997.
TUCSON ELECTRIC POWER COMPANY
By Steven J. Glaser
Vice President
NAVAJO TRIBAL UTILITY AUTHORITY
By Malcolm P. Dalton
General Manager
27
EXHIBIT A
Phase I Rate Schedule
1997 - 1999
BACKGROUND
For each month in the term of Phase I NTUA and TEP have agreed to an aggregate
price for generation and transmission capacity ( the Aggregate Demand Charge).
Since transmission costs may vary from time to time in the course of Phase I,it
will be necessary for the Generation Demand Charge to fluctuate so as to
accommodate the agreed-upon fixed aggregate price. In addition, the billing
demand for generation capacity may be different than the billing demand for
transmission services. Accordingly, when unbundling transmission from the
Aggregate Demand Charge it will also be necessary to adjust for this difference
in billing demands. This Exhibit will illustrate the calculations needed to
make these adjustments.
GENERATION DEMAND CHARGE
The Generation Demand Charge for the TEP Firm Power Supply in Phase I shall
be calculated each month by unbundling the charges for transmission that are
included in the Aggregate Demand Charge. The process for unbundling is
illustrated in the table below, and is to be accomplished by subtracting from
the Aggregate Demand Charge a transmission charge ("T") (in $/kW-Mo.). The
charge T itself, is a function of the charges for transmission and ancillary
services that are calculated monthly and billed to NTUA in accordance with the
NTUA - TEP Network Transmission Agreement (see Exhibit E), herein referred to
as the Network Transmission Charge ("TN").
T shall be calculated by multiplying the TN by the Transmission Billing
A-1
Demand ("TBD"), and dividing the product by the Generation Billing Demand
("GBD").
T = (TN X TBD) / GBD
This calculation unbundles the transmission included in the Aggregate
Demand Charge for the Phase I TEP Firm Power Supply, for which the Generation
Billing Demand is at 60 MW, subject to the provisions of Section IV.A.1.
TN is the monthly charge, in $/kW-Mo. that is calculated in accordance with
the NTUA - TEP Network Transmission Agreement, which includes the sum of the
charges for the following services on the TEP system: (i) Network Service Basic
Transmission Rate, (ii) Scheduling, System Control and Dispatch Service, (iii)
Reactive Supply and Voltage Control from Generation Sources Service, (iv)
Regulation and Frequency Response Service, (v) Energy Imbalance Service, (vi)
Operating Reserve - Spinning Reserve Service, and (viii) Operating Reserve -
Supplemental Reserve Service.
Generation
Demand Charge
Month/Year $/kW-Mo.
7/97 - 5/98 9.25 - T
6/98 - 5/99 9.55 - T
ENERGY CHARGE
Month/Year $/MWh
7/97 - 5/99 $18.00
No charge shall exceed Tucson's fully allocated cost of service.
A-2
EXHIBIT B
Phase II Rate Schedule
1999 - 2009
BACKGROUND
For each month in the term of Phase II NTUA and TEP have agreed to an
aggregate price for generation and transmission capacity ( the Aggregate Demand
Charge). Since transmission costs may vary from time to time in the course of
Phase II, it will be necessary for the Generation Demand Charge to fluctuate so
as to accommodate the agreed-upon fixed aggregate price.In addition the billing
demand for generation capacity is 40 MW while the Aggregate Demand Charge
includes the costs for 43.33 MW of transmission capacity. Accordingly, when
unbundling transmission from the Aggregate Demand Charge it will also be
necessary to adjust for this difference in billing demands. This Exhibit will
illustrate the calculations needed to make these adjustments.
GENERATION DEMAND CHARGE
The Generation Demand Charge for the TEP Firm Power Supply in Phase II
shall be calculated each month by unbundling the charges for 43.33 MW of
transmission that are included in the Aggregate Demand Charge. The process for
unbundling is illustrated in the table below, and is to be accomplished by
subtracting from the Aggregate Demand Charge a transmission charge(T) (in $/kW-
Mo.). The charge T itself, is a function of the charges for transmission and
ancillary services that are calculated monthly and billed to NTUA in accordance
with the NTUA - TEP Network Transmission Agreement (see Exhibit E), herein
referred to as the Network Transmission Charge (TN).
T = 1.08325 X TN, where the factor 1.08325 is the ratio of 43.33 to 40.
The factor (1.08325) adjusts TN to unbundle 43.33 MW of transmission
included in the Aggregate Demand Charge for the Phase II TEP Firm Power Supply,
B-1
for which the Generation Billing Demand is 40 MW.
TN is the monthly charge, in $/kW-Mo. that is calculated in accordance with
the NTUA - TEP Network Transmission Agreement, which includes the sum of the
charges for the following services on the TEP system: (i) Network Service Basic
Transmission Rate, (ii) Scheduling, System Control and Dispatch Service, (iii)
Reactive Supply and Voltage Control from Generation Sources Service, (iv)
Regulation and Frequency Response Service, (v) Energy Imbalance Service, (vi)
Operating Reserve - Spinning Reserve Service, and (vii) Operating Reserve -
Supplemental Reserve Service.
Generation
Demand Charge
Month/Year $/kW-Mo.
6/99 - 12/99 9.74 - T
1/00 - 12/00 9.86 - T
1/01 - 12/01 10.05 - T
1/02 - 12/02 10.25 - T
1/03 - 12/03 10.46 - T
1/04 - 12/04 10.66 - T
1/05 - 12/05 10.88 - T
1/06 - 12/06 11.10 - T
1/07 - 12/07 11.32 - T
1/08 - 12/08 11.54 - T
1/09 - 12/09 11.64 - T
ENERGY CHARGE
Month/Year $/MWh
6/99 - 12/99 $18.00
B-2
For each twelve-month period beginning in January 2000, Energy Charges will
increase or decrease as determined by the change in TEP's system average fuel
costs (FERC 501 account dollars, which include coal, environmental, handling,
waste and stabilization fuel costs for Four Corners,Irvington, Navajo, San Juan
and Springerville Power Plants; and natural gas costs for the Irvington Steam
units, per MWh of net generation) for the prior twelve months. The annual
increase or decrease in Energy Charge resulting from the above computation will
be capped at 2%.
No charge shall exceed Tucson's fully allocated cost of service.
B-3
EXHIBIT C
Control Area Services
1. General
If NTUA chooses to operate within TEP's control area, TEP shall provide
Control Area Services (including ancillary services as defined in the TEP Open
Access Tariff)as necessary pursuant to its Open Access Tariff at the charges in
effect from time to time in its most currently filed Open Access Tariff. These
charges shall be applied to the capacity required at the time of NTUA's peak
demand for the month, less the capacity from its CRSP Allocation and TEP Firm
Power Supply.
2. Scheduling, System Control and Dispatch Service
This service is required to schedule the movement of power through, out of,
within or into a Control Area. This service can be provided only by the
operator of the Control Area in which the transmission facilities used for
Transmission Service are located. Tucson shall provide Scheduling, System
Control and Dispatch Service pursuant to its Open Access Tariff at the charges
provided in its most currently filed Open Access Tariff.
3. Reactive Supply and Voltage Control from Generation Sources Service
In order to maintain transmission voltage on Tucson's transmission
facilities within acceptable limits, generation facilities (in the Control Area
where Tucson's transmission facilities are located) are operated to produce (or
absorb) reactive power. Thus, Reactive Supply and Voltage Control from
Generation Sources Service must be provided for each transaction on Tucson's
transmission facilities. Tucson shall provide Reactive Supply and Voltage
Control from Generation Sources Service pursuant to its Open Access Tariff at
the charges provided in its most currently filed Open Access Tariff.
4. Requlation and Frequency Response Service
Regulation and Frequency Response Service is necessary to provide for the
continuous balancing of resources with load and for maintaining scheduled
Interconnection frequency at 60 Hz. Regulation and Frequency Response Service
is accomplished by committing on-line generation whose output is raised or
lowered as necessary to follow the moment-by-moment changes in load. Tucson
shall provide Regulation and Frequency Response Service pursuant to its Open
Access Tariff at the charges provided in its most currently filed Open Access
Tariff.
5. Energy Imbalance Service
Energy Imbalance Service is provided when a difference occurs between the
scheduled and the actual delivery of energy to a load located within a Control
Area over a single hour. Tucson shall provide Energy Imbalance Service pursuant
to its Open Access Tariff at the charges provided in its most currently filed
Open Access Tariff.
6. Operating Reserve - Spinning Reserve Service
Spinning Reserve Service is needed to serve load immediately in the event
of a system contingency. Spinning Reserve Service must be provided by
generating units that are on-line and are loaded at less than maximum output.
Tucson shall provide Spinning Reserve Service pursuant to its Open Access
Tariff at the charges provided in its most currently filed Open Access Tariff.
7. Operating Reserve - Supplemental Reserve Service
Supplemental Reserve Service is needed to serve load in the event of a
system contingency; however, it is not available immediately to serve load but
rather within a short period of time. Supplemental Reserve Service must be
provided by generating units that are on-line but unloaded, by quick-start
generation or by interruptible load. Tucson shall provide Supplemental Reserve
Service pursuant to its Open Access Tariff at the charges provided in its most
currently filed Open Access Tariff.
Tucson Electric Power Company Open Access Transmission Tariff
Revised Original Sheet No. 3
EXHIBIT D
Firm Backup Power Supply
Demand Charges
BACKUP DEMAND CHARGES
Rate
Month/Year $/kW-Mo.
6/99 - 12/99 1.46
1/00 - 12/00 1.48
1/01 - 12/01 1.51
1/02 - 12/02 1.54
1/03 - 12/03 1.57
1/04 - 12/04 1.60
1/05 - 12/05 1.63
1/06 - 12/06 1.67
1/07 - 12/07 1.70
1/08 - 12/08 1.73
1/09 - 12/09 1.75
Tucson Electric Power Company Open Access Transmission Tariff
Revised Original Sheet No. 1
EXHIBIT E
ATTACHMENT F
{PRIVATE} SERVICE AGREEMENT FOR
NETWORK INTEGRATION TRANSMISSION SERVICE
1.0 This Service Agreement ("Agreement"),dated as of JUNE 17, 1997, is entered
into by and between Tucson Electric Power Company ("TEP"), an Arizona
corporation, and NAVAJO TRIBAL UTILITY AUTHORITY (NTUA) ("Transmission
Customer").
2.0 Based upon its submitted Completed Application, NAVAJO TRIBAL UTILITY
AUTHORITY has been determined by TEP to be a Transmission Customer under
Part III of this Tariff.
3.0 The Transmission Customer has provided to TEP an Application deposit in
the amount of $ N/A.
4.0 The Transmission Customer has executed a Network Operating Agreement with
TEP.
5.0 Service under this Agreement shall commence on the later of JULY 1, 1997
or FERC Approval. Service under this Agreement shall terminate on DECEMBER
31, 2009.
6.0 TEP agrees to provide and the Transmission Customer agrees to take and pay
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for Network Integration Transmission Service in accordance with the
provisions of Part III of this Tariff, this Agreement, and the Network
Operating Agreement, as they may be amended from time to time. Initially
the Transmission Customer makes the following designations:
Tucson Electric Power Company Open Access Transmission Tariff
Revised Original Sheet No. 2
6.1 Network Resources:
FOUR CORNERS 4 & 5, NAVAJO 1, 2, & 3, SAN JUAN 1 & 2, SPRINGERVILL
1 & 2.
6.2 Network Loads:
APS Four Corners 345 kV Bus, WAPA Shiprock 345 kV Bus, Saguaro 500
kV bus, and PNM San Juan 345 kV Bus.
6.3 Points of interconnection between the Transmission Customer's facilities
and TEP's Transmission System:
APS SAGUARO 500 KV BUS, APS FOUR CORNERS 345 KV BUS, WAPA SHIPROCK
345 KV BUS, AND PNM SAN JUAN 345 KV BUS.
6.4 The Transmission Customer's initial Load Ratio Share:
4.5 %
--------
7.0 TEP agrees to provide and the Transmission Customer agrees to take and pay
for other services as indicated below:
7.1 Scheduling, System Control and Dispatch Service:
FOR PHASE 1, JULY 1, 1997 - MAY 31, 1999, NTUA WILL TAKE ALL
ANCILLARY SERVICES.
FOR PHASE 2, NTUA WILL ADVISE TEP AS TO ITS REQUIREMENTS.
7.2 Reactive Supply and Voltage Control from Generation Sources Service:
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FOR PHASE 1, JULY 1, 1997 - MAY 31, 1999, NTUA WILL TAKE ALL
ANCILLARY SERVICES.
FOR PHASE 2, NTUA WILL ADVISE TEP AS TO ITS REQUIREMENTS.
7.3 Regulation and Frequency Response Service:
YES X NO
-------- --------
Tucson Electric Power Company Open Access Transmission Tariff
Revised Original Sheet No. 3
FOR PHASE 1, JULY 1, 1997 - MAY 31, 1999, NTUA WILL TAKE ALL
ANCILLARY SERVICES.
FOR PHASE 2, NTUA WILL ADVISE TEP AS TO ITS REQUIREMENTS.
7.4 Energy Imbalance Service:
YES X NO
-------- --------
FOR PHASE 1, JULY 1, 1997 - MAY 31, 1999, NTUA WILL TAKE ALL
ANCILLARY SERVICES.
FOR PHASE 2, NTUA WILL ADVISE TEP AS TO ITS REQUIREMENTS.
7.5 Operating Reserves - Spinning Reserve Service:
YES X NO
-------- --------
FOR PHASE 1, JULY 1, 1997 - MAY 31, 1999, NTUA WILL TAKE ALL
ANCILLARY SERVICES.
FOR PHASE 2, NTUA WILL ADVISE TEP AS TO ITS REQUIREMENTS.
7.6 Operating Reserve - Supplemental Reserve Service:
YES X NO
-------- --------
FOR PHASE 1, JULY 1, 1997 - MAY 31, 1999, NTUA WILL TAKE ALL
ANCILLARY SERVICES.
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FOR PHASE 2, NTUA WILL ADVISE TEP AS TO ITS REQUIREMENTS.
8.0 Any notice or request, other than requests to schedule specific
transactions, made to or by either Party regarding this Agreement shall be
made to the representative of the other Party as indicated below:
TUCSON ELECTRIC POWER COMPANY: TRANSMISSION
CUSTOMER:
Tucson Electric Power Company Navajo Tribal
P.O. Box 711 UTILITY AUTHORITY
Tucson, Arizona 85702 P.O. Box 170
Attn:Transmission Coordinator Fort Defiance, AZ
Telephone:(520)745-7193 86504
Facsimile: (520) 571-4036 Attn:General Manager
(520) 729-5721 Phone
(520) 729-2135 FAX
Tucson Electric Power Company Open Access Transmission Tariff
Revised Original Sheet No. 4
9.0 This Tariff is incorporated herein and made a part hereof and all initially
capitalized terms shall have the meanings ascribed to them in the Tariff.
The terms and conditions set forth in Part I,Common Service Provisions and
Part III, Network Integration Transmission Service, of the Tariff are
incorporated into this Agreement and shall govern the services provided
under this Agreement.
10.0 Payments for Network Integration Transmission Service provided to the
Transmission Customer by TEP under this Service Agreement shall be sent to
the name and address indicated on the bill provided to the Transmission
Customer.
Tucson Electric Power Company Open Access Transmission Tariff
Revised Original Sheet No. 5
IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by
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their respective authorized officials.
TUCSON ELECTRIC POWER COMPANY:
By:
Name: Title:
------------------------ ----------------------
Date:
-------------------
TRANSMISSION CUSTOMER:
By:
Name: Title:
------------------------ ----------------------
Date:
-------------------
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