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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 September 30, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period From __________ to __________.
Commission Registrant; State of Incorporation; IRS Employer
File Number Address; and Telephone Number Identification Number
----------- ----------------------------------- ---------------------
1-13739 UNISOURCE ENERGY CORPORATION 86-0786732
(An Arizona Corporation)
One South Church Avenue, Suite 100
Tucson, AZ 85701
(520) 571-4000
1-5924 TUCSON ELECTRIC POWER COMPANY 86-0062700
(An Arizona Corporation)
One South Church Avenue, Suite 100
Tucson, AZ 85701
(520) 571-4000
Indicate by check mark whether each registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yes X No
--- ---
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act).
UniSource Energy Corporation Yes X No
--- ---
Tucson Electric Power Company Yes No X
--- ---
At November 6, 2003, 33,675,356 shares of UniSource Energy
Corporation's Common Stock, no par value (the only class of Common Stock),
were outstanding.
At November 6, 2003, 32,139,555 shares of Tucson Electric Power
Company's common stock, no par value, were outstanding, of which 32,139,434
were held by UniSource Energy Corporation.
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This combined Form 10-Q is separately filed by UniSource Energy Corporation
and Tucson Electric Power Company. Information contained in this document
relating to Tucson Electric Power Company is filed by UniSource Energy
Corporation and separately by Tucson Electric Power Company on its own
behalf. Tucson Electric Power Company makes no representation as to
information relating to UniSource Energy Corporation or its subsidiaries,
except as it may relate to Tucson Electric Power Company.
TABLE OF CONTENTS
Page
Definitions................................................................ iv
Report of Independent Accountants.......................................... 1
PART I - FINANCIAL INFORMATION
Item 1. - Financial Statements
UniSource Energy Corporation
Comparative Condensed Consolidated Statements of Income............... 2
Comparative Condensed Consolidated Statements of Cash Flows........... 3
Comparative Condensed Consolidated Balance Sheets..................... 4
Condensed Consolidated Statement of Changes in Stockholders' Equity... 5
Tucson Electric Power Company
Comparative Condensed Consolidated Statements of Income............... 6
Comparative Condensed Consolidated Statements of Cash Flows........... 7
Comparative Condensed Consolidated Balance Sheets..................... 8
Condensed Consolidated Statement of Changes in Stockholders' Equity... 9
Notes to Condensed Consolidated Financial Statements
Note 1. Nature of Operations, Basis of Accounting Presentation
and Stock-Based Compensation.................................. 10
Note 2. Establishment of UES.......................................... 12
Note 3. Regulatory Accounting......................................... 14
Note 4. Accounting Change: Accounting for Asset Retirement Obligations 15
Note 5. Stock-Based Compensation Plans................................ 17
Note 6. Accounting for Derivative Instruments and Trading Activities.. 18
Note 7. Business Segments............................................. 19
Note 8. Millennium.................................................... 20
Note 9. Commitments and Contingencies................................. 22
Note 10. TEP Wholesale Accounts Receivable and Allowances.............. 25
Note 11. UniSource Energy Earnings per Share (EPS)..................... 25
Note 12. Income and Other Taxes........................................ 26
Note 13. New Accounting Pronouncements................................. 27
Note 14. Subsequent Events............................................. 28
Note 15. Review by Independent Accountants............................. 28
Item 2. - Management's Discussion and Analysis of Financial
Condition and Results of Operations
Overview of Consolidated Business....................................... 30
UniSource Energy Consolidated
Results of Operations................................................. 30
Contribution By Business Segment...................................... 32
Liquidity and Capital Resources....................................... 32
Tucson Electric Power Company
Results of Operations................................................. 34
Factors Affecting Results of Operations............................... 38
Liquidity and Capital Resources....................................... 42
UniSource Energy Services
Results of Operations................................................. 44
Factors Affecting Results of Operations............................... 45
Liquidity and Capital Resources....................................... 46
ii
TABLE OF CONTENTS
(concluded)
Millennium Energy Holdings, Inc.
Results of Operations................................................. 48
Liquidity and Capital Resources....................................... 48
UniSource Energy Development Company
Results of Operations................................................. 49
Springerville Generating Station Expansion............................ 50
Outlook and Strategies.................................................. 50
Critical Accounting Policies............................................ 51
New Accounting Pronouncements........................................... 55
Safe Harbor for Forward-Looking Statements.............................. 56
Item 3. - Quantitative and Qualitative Disclosures about Market Risk..... 57
Item 4. - Controls and Procedures........................................ 59
PART II - OTHER INFORMATION
Item 1. - Legal Proceedings.............................................. 60
Item 5. - Other Information
Director Resignation.................................................... 61
Additional Financial Data............................................... 61
Approval of Non-Audit Services.......................................... 61
SEC Reports Available on UniSource Energy's Website..................... 61
Item 6. - Exhibits and Reports on Form 8-K............................... 62
Signatures................................................................. 63
Exhibit Index.............................................................. 64
iii
DEFINITIONS
The abbreviations and acronyms used in the 2003 Third Quarter Form 10-Q are
defined below:
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ACC.......................... Arizona Corporation Commission.
ACC Holding Company Order.... The order approved by the ACC in November
1997 allowing TEP to form a holding company.
Capacity..................... The ability to produce power; the most power
a unit can produce or the maximum that can be
taken under a contract; measured in MWs.
CISO......................... California Independent System Operator.
Citizens..................... Citizens Communications Company.
Citizens Settlement Agreement An agreement with the ACC Staff dated
April 1, 2003, addressing rate case and
financing issues in the acquisition by
UniSource Energy of the Citizens' Arizona
gas and electric assets.
Common Stock................. UniSource Energy's common stock, without par
value.
Cooling Degree Days.......... An index used to measure the impact of
weather on energy usage calculated by
subtracting 75 from the average of the high
and low daily temperatures.
CPX.......................... California Power Exchange.
Credit Agreement............. Credit Agreement between TEP and a syndicate
of banks, dated as of November 14, 2002.
Emission Allowance(s)........ An allowance issued by the Environmental
Protection Agency which permits emission of
one ton of sulfur dioxide or one ton of
nitrogen oxide. These allowances can be
bought and sold.
ESP.......................... Energy Service Provider.
FAS 71....................... Statement of Financial Accounting Standards
No. 71: Accounting for the Effects of Certain
Types of Regulation.
FAS 133...................... Statement of Financial Accounting Standards
No. 133: Accounting for Derivative Instruments
and Hedging Activities.
FAS 143...................... Statement of Financial Accounting Standards
No. 143: Accounting for Asset Retirement
Obligations.
FERC......................... Federal Energy Regulatory Commission.
GAAP......................... Generally Accepted Accounting Principles.
Global Solar................. Global Solar Energy, Inc., a company that
develops and manufactures thin-film
photovoltaic cells. Millennium currently owns
99% of Global Solar.
Heating Degree Days.......... An index used to measure the impact of
weather on energy usage calculated by
subtracting the average of the high and low
daily temperatures from 65.
IPS.......................... Infinite Power Solutions, Inc., a company
that develops thin-film batteries. Millennium
currently owns 72% of IPS.
ITN.......................... ITN Energy Systems, Inc., a company formed to
provide research, development, and other
services. Millennium finalized a 2002
Restructure Agreement and a share exchange
agreement reducing its ownership in ITN to
zero.
kWh.......................... Kilowatt-hour(s).
MEG.......................... Millennium Environmental Group, Inc., a wholly-
owned subsidiary of Millennium, which
manages and trades Emission Allowances, coal,
and related financial instruments.
MicroSat..................... MicroSat Systems, Inc., a company formed to
develop and commercialize small-scale
satellites. Millennium currently owns 35% of
MicroSat.
Millennium................... Millennium Energy Holdings, Inc., a wholly-
owned subsidiary of UniSource Energy.
MW........................... Megawatt(s).
MWh.......................... Megawatt-hour(s).
PGA.......................... Purchased Gas Adjuster, a retail rate mechanism
designed to recover the cost of gas purchased
for retail gas customers.
PWCC......................... Pinnacle West Capital Corporation.
PG&E......................... Pacific Gas and Electric Company.
Revolving Credit Facility.... $60 million revolving credit facility entered
into under the Credit Agreement between a
syndicate of banks and TEP.
Rules........................ Retail Electric Competition Rules.
SCE.......................... Southern California Edison Company.
iv
DEFINITIONS
(concluded)
Springerville................ Springerville Generating Station.
Springerville Common
Facilities Leases.......... Leveraged lease arrangements relating to an
undivided one-half interest in certain
Springerville facilities used in common by
Springerville Unit 1 and Springerville Unit 2.
Springerville Unit 1......... Unit 1 of the Springerville Generating
Station.
Springerville Unit 2......... Unit 2 of the Springerville Generating
Station.
SRP.......................... Salt River Project Agricultural Improvement
and Power District.
Sundt Generating Station..... H. Wilson Sundt Generating Station (formerly
known as the Irvington Generating Station).
TEP.......................... Tucson Electric Power Company, the principal
subsidiary of UniSource Energy.
TEP Settlement Agreement..... TEP's Settlement Agreement approved by the ACC
in November 1999 that provided for electric
retail competition and transition asset
recovery.
Therm........................ A unit of heating value equivalent to 100,000
British thermal units (Btu).
Tri-State.................... Tri-State Generation and Transmission
Association.
TruePricing.................. TruePricing, Inc., a start-up company
established to market energy related products.
Millennium and TEP collectively own 57% of the
outstanding shares of TruePricing.
UED.......................... UniSource Energy Development Company, a
wholly-owned subsidiary of UniSource Energy,
which engages in developing generation
resources and other project development
services and related activities.
UES.......................... UniSource Energy Services, Inc., an intermediate
holding company established to own the
operating companies (UNS Gas and UNS Electric)
which acquired the Citizens Arizona gas and
electric utility assets.
UniSource Energy............. UniSource Energy Corporation.
UNS Electric................. UNS Electric, Inc., a wholly-owned subsidiary
of UES, which acquired the Citizens Arizona
electric utility assets.
UNS Gas...................... UNS Gas, Inc., a wholly-owned subsidiary of
UES, which acquired the Citizens Arizona gas
utility assets.
v
Report of Independent Accountants
To the Board of Directors and Stockholders of
UniSource Energy Corporation and
to the Board of Directors and Stockholder of
Tucson Electric Power Company
We have reviewed the accompanying condensed consolidated balance sheets of
UniSource Energy Corporation and its subsidiaries (the Company) and Tucson
Electric Power Company and its subsidiaries (TEP) as of September 30, 2003,
and the related condensed consolidated statements of income for each of the
three-month and nine-month periods ended September 30, 2003 and 2002 and the
condensed consolidated statement of stockholders' equity for the nine-month
period ended September 30, 2003, and the condensed consolidated statements of
cash flows for the nine-month periods ended September 30, 2003 and 2002.
These financial statements are the responsibility of the Company's and TEP's
management.
We conducted our reviews 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 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 reviews, we are not aware of any material modifications that
should be made to the accompanying condensed consolidated interim financial
statements for them to be in conformity with accounting principles
generally accepted in the United States of America.
We previously audited in accordance with auditing standards generally
accepted in the United States of America, the consolidated balance sheets
and statements of capitalization of the Company and TEP as of December 31,
2002, and the related consolidated statements of income, of stockholders'
equity, and of cash flows for the year then ended (not presented herein),
and in our report dated February 6, 2003 we expressed an unqualified
opinion on those consolidated financial statements. In our opinion, the
information set forth in the accompanying condensed consolidated balance
sheets as of December 31, 2002 is fairly stated in all material respects
in relation to the consolidated balance sheets from which it has been
derived.
PricewaterhouseCoopers LLP
Los Angeles, California
November 5, 2003
1
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
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UNISOURCE ENERGY CORPORATION
COMPARATIVE CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended
September 30,
2003 2002
(Unaudited)
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-Thousands of Dollars-
Operating Revenues
Electric Retail Sales $253,391 $214,432
Electric Wholesale Sales 32,297 41,125
Gas Revenue 10,336 -
Net Gain on TEP Forward Contracts and MEG
Trading Activities 863 375
Other Revenues 5,911 2,833
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Total Operating Revenues 302,798 258,765
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Operating Expenses
Fuel 64,247 58,422
Purchased Energy 47,200 23,345
Coal Contract Termination Fee - 11,250
Other Operations and Maintenance 48,597 46,668
Depreciation and Amortization 34,032 31,107
Amortization of Transition Recovery Asset 13,472 10,790
Taxes Other Than Income Taxes 12,676 11,753
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Total Operating Expenses 220,224 193,335
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Operating Income 82,574 65,430
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Other Income (Deductions)
Interest Income 5,090 5,231
Other Income 1,358 2,113
Other Expense (950) (2,571)
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Total Other Income (Deductions) 5,498 4,773
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Interest Expense
Long-Term Debt 20,532 16,025
Interest on Capital Leases 21,257 21,944
Other Interest Expense, Net of Amounts Capitalized 603 208
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Total Interest Expense 42,392 38,177
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Income Before Income Taxes and Cumulative Effect
of Accounting Change 45,680 32,026
Income Tax Expense 18,996 9,207
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Income Before Cumulative Effect of Accounting Change 26,684 22,819
Cumulative Effect of Accounting Change - Net of Tax - -
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Net Income $ 26,684 $ 22,819
===============================================================================
Average Shares of Common Stock Outstanding (000) 33,838 33,692
===============================================================================
Basic Earnings per Share
Income Before Cumulative Effect of Accounting Change $0.79 $0.68
Cumulative Effect of Accounting Change - Net of Tax - -
Net Income $0.79 $0.68
===============================================================================
Diluted Earnings per Share
Income Before Cumulative Effect of Accounting Change $0.78 $0.67
Cumulative Effect of Accounting Change - Net of Tax - -
Net Income $0.78 $0.67
===============================================================================
Dividends Paid per Share $0.15 $0.125
===============================================================================
See Notes to Condensed Consolidated Financial Statements.
UNISOURCE ENERGY CORPORATION
COMPARATIVE CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Nine Months Ended
September 30,
2003 2002
(Unaudited)
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-Thousands of Dollars-
Operating Revenues
Electric Retail Sales $557,174 $521,064
Electric Wholesale Sales 107,994 125,911
Gas Revenue 10,336 -
Net Gain on TEP Forward Contracts and MEG
Trading Activities 318 936
Other Revenues 12,850 10,672
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Total Operating Revenues 688,672 658,583
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Operating Expenses
Fuel 162,512 164,937
Purchased Energy 80,898 46,909
Coal Contract Termination Fee - 11,250
Other Operations and Maintenance 150,243 140,890
Depreciation and Amortization 95,472 96,075
Amortization of Transition Recovery Asset 24,842 20,311
Taxes Other Than Income Taxes 35,419 34,704
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Total Operating Expenses 549,386 515,076
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Operating Income 139,286 143,507
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Other Income (Deductions)
Interest Income 15,380 14,913
Other Income 3,440 4,657
Other Expense (3,242) (6,213)
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Total Other Income (Deductions) 15,578 13,357
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Interest Expense
Long-Term Debt 58,917 48,115
Interest on Capital Leases 62,791 65,896
Other Interest Expense, Net of Amounts Capitalized 903 799
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Total Interest Expense 122,611 114,810
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Income Before Income Taxes and Cumulative Effect
of Accounting Change 32,253 42,054
Income Tax Expense 15,187 13,661
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Income Before Cumulative Effect of Accounting Change 17,066 28,393
Cumulative Effect of Accounting Change - Net of Tax 67,471 -
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Net Income $ 84,537 $ 28,393
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Average Shares of Common Stock Outstanding (000) 33,799 33,654
===============================================================================
Basic Earnings per Share
Income Before Cumulative Effect of Accounting Change $0.50 $0.84
Cumulative Effect of Accounting Change - Net of Tax $2.00 -
Net Income $2.50 $0.84
===============================================================================
Diluted Earnings per Share
Income Before Cumulative Effect of Accounting Change $0.50 $0.83
Cumulative Effect of Accounting Change - Net of Tax $1.97 -
Net Income $2.47 $0.83
===============================================================================
Dividends Paid per Share $0.45 $0.375
===============================================================================
See Notes to Condensed Consolidated Financial Statements.
2
UNISOURCE ENERGY CORPORATION
COMPARATIVE CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Nine Months Ended
September 30,
2003 2002
(Unaudited)
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-Thousands of Dollars-
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales $584,028 $550,291
Cash Receipts from Electric Wholesale Sales 155,505 191,468
Cash Receipts from Gas Sales 10,634 -
MEG Cash Receipts from Trading Activity 64,657 41,734
Interest Received 22,248 13,018
Other Cash Receipts 5,256 18,119
Fuel Costs Paid (158,327) (157,179)
Purchased Power Costs Paid (124,897) (108,875)
Wages Paid, Net of Amounts Capitalized (58,769) (57,378)
Payment of Other Operations and Maintenance Costs (83,260) (93,984)
MEG Cash Payments for Trading Activity (62,548) (46,039)
Capital Lease Interest Paid (74,142) (68,329)
Taxes Paid, Net of Amounts Capitalized (70,071) (69,040)
Debt Interest Paid, Net of Amounts Capitalized (62,301) (52,925)
Income Taxes Paid (4,616) (10,416)
MEG Performance Deposits (4,804) 4,632
Coal Contract Termination Fee - (11,250)
Other (5,189) (7,692)
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Net Cash Flows - Operating Activities 133,404 136,155
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Cash Flows from Investing Activities
Capital Expenditures (101,389) (81,728)
Purchase of Citizens Assets (224,138) -
Investment in Springerville Lease Debt and Equity 12,078 (134,989)
Investment in and Loans to Equity Investees (1,661) (23,262)
Other (3,869) (425)
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Net Cash Flows - Investing Activities (318,979) (240,404)
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Cash Flows from Financing Activities
Proceeds from Borrowings under Revolving
Credit Facility 45,000 -
Repayments on Revolving Credit Facility (25,000) -
Proceeds from Issuance of Short-Term Debt 35,850 957
Repayments of Short-Term Debt (960) (853)
Proceeds from Issuance of Long-Term Debt 160,000 -
Repayments of Long-Term Debt (1,826) (1,879)
Common Stock Dividends Paid (15,139) (12,602)
Payments on Capital Lease Obligations (42,444) (19,620)
Other 1,689 2,704
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Net Cash Flows - Financing Activities 157,170 (31,293)
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Net Decrease in Cash and Cash Equivalents (28,405) (135,542)
Cash and Cash Equivalents, Beginning of Year 90,928 228,154
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Cash and Cash Equivalents, End of Period $ 62,523 $ 92,612
===============================================================================
SUPPLEMENTAL CONDENSED CONSOLIDATED CASH FLOW INFORMATION
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Net Income $ 84,537 $ 28,393
Adjustments to Reconcile Net Income to Net Cash Flows
Cumulative Effect of Accounting Change - Net of Tax (67,471) -
Depreciation and Amortization Expense 95,472 96,075
Depreciation Recorded to Fuel and Other O&M Expense 4,300 4,190
Amortization of Transition Recovery Asset 24,842 20,311
Net Unrealized Gain on Forward Electric Sales
and Purchases and MEG Trading Activities (2,683) (1,206)
Amortization of Deferred Debt-Related Costs included
in Interest Expense 2,223 1,428
Provision for Bad Debts 4,018 1,753
Deferred Income Taxes 16,941 14,521
Losses from Equity Method Entities 2,391 3,888
Other, Net 3,187 (6,541)
Changes in Current Assets and Liabilities which
Provided (Used) Cash Exclusive of Changes Shown
Separately:
Accounts Receivable (21,441) 16,361
Materials and Fuel Inventory (2,332) 705
Accounts Payable (10,231) (40,011)
Interest Accrued (16,976) (9,817)
Taxes Accrued 11,094 7,728
Other Current Assets (9,888) 2,640
Other Current Liabilities 15,421 (4,263)
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Net Cash Flows - Operating Activities $133,404 $136,155
===============================================================================
See Notes to Condensed Consolidated Financial Statements.
3
UNISOURCE ENERGY CORPORATION
COMPARATIVE CONDENSED CONSOLIDATED BALANCE SHEETS
September 30, December 31,
2003 2002
(Unaudited)
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ASSETS -Thousands of Dollars-
Utility Plant
Plant in Service $ 2,868,462 $ 2,598,884
Utility Plant under Capital Leases 747,533 747,556
Construction Work in Progress 120,017 59,926
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Total Utility Plant 3,736,012 3,406,366
Less Accumulated Depreciation and Amortization (1,296,775) (1,346,101)
Less Accumulated Depreciation of Capital Lease
Assets (413,741) (391,915)
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Total Utility Plant - Net 2,025,496 1,668,350
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Investments and Other Property
Investments in Lease Debt and Equity 179,010 191,867
Other 122,974 123,238
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Total Investments and Other Property 301,984 315,105
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Current Assets
Cash and Cash Equivalents 62,523 90,928
Trade Accounts Receivable 91,436 75,787
Unbilled Accounts Receivable 31,880 9,910
Allowance for Doubtful Accounts (12,184) (9,062)
Materials and Fuel Inventory 53,476 46,657
Trading Assets 29,199 15,150
Current Regulatory Assets 16,577 11,778
Deferred Income Taxes - Current 11,593 15,917
Interest Receivable - Current 6,210 12,178
Other 20,179 15,762
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Total Current Assets 310,889 285,005
- -------------------------------------------------------------------------------
Regulatory and Other Assets
Transition Recovery Asset 282,278 307,120
Income Taxes Recoverable Through Future Revenues 51,648 57,044
Other Regulatory Assets 12,890 10,504
Other Assets 47,619 47,606
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Total Regulatory and Other Assets 394,435 422,274
- -------------------------------------------------------------------------------
Total Assets $ 3,032,804 $ 2,690,734
===============================================================================
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity $ 508,078 $ 438,229
Capital Lease Obligations 761,855 801,611
Long-Term Debt 1,286,685 1,128,963
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Total Capitalization 2,556,618 2,368,803
- -------------------------------------------------------------------------------
Current Liabilities
Current Obligations under Capital Leases 50,280 42,960
Current Maturities of Long-Term Debt 1,771 1,840
Borrowings under Revolving Credit Facility 20,000 -
Term Loan Payable 35,000 -
Accounts Payable 63,337 48,934
Interest Accrued 33,408 60,238
Trading Liabilities 23,184 10,255
Taxes Accrued 44,741 33,850
Accrued Employee Expenses 11,995 13,644
Other 18,056 7,659
- -------------------------------------------------------------------------------
Total Current Liabilities 301,772 219,380
- -------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred Income Taxes - Noncurrent 86,009 34,552
Other 88,405 67,999
- -------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 174,414 102,551
- -------------------------------------------------------------------------------
Commitments and Contingencies (Note 9)
- -------------------------------------------------------------------------------
Total Capitalization and Other Liabilities $ 3,032,804 $ 2,690,734
===============================================================================
See Notes to Condensed Consolidated Financial Statements.
4
UNISOURCE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
Accumulated
Common Accumulated Other Total
Shares Common Earnings Comprehensive Stockholders'
Outstanding* Stock (Deficit) Income (Loss) Equity
- -------------------------------------------------------------------------------
(Unaudited)
-In Thousands-
Balances at
December 31, 2002 33,579 $661,185 $(218,932) $ (4,024) $438,229
- -------------------------------------------------------------------------------
Comprehensive Income:
2003 Year-to-Date Net
Income - - 84,537 - 84,537
---------
Total Comprehensive
Income 84,537
---------
Dividends Declared - - (15,139) - (15,139)
Shares Issued under Stock
Compensation Plans 7 75 - - 75
Shares Distributed by
Deferred Compensation
Trust 3 50 - - 50
Shares Issued for Stock
Options 24 326 - - 326
- -------------------------------------------------------------------------------
Balances at
September 30, 2003 33,613 $661,636 $(149,534) $ (4,024) $508,078
===============================================================================
*UniSource Energy has 75 million authorized shares of common stock.
See Notes to Condensed Consolidated Financial Statements.
5
TUCSON ELECTRIC POWER COMPANY
COMPARATIVE CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended
September 30,
2003 2002
(Unaudited)
- -------------------------------------------------------------------------------
-Thousands of Dollars-
Operating Revenues
Electric Retail Sales $229,735 $214,432
Electric Wholesale Sales 32,297 41,125
Net Unrealized Gain on Forward Electric Sales and
Purchases 148 85
Other Revenues 2,235 1,601
- -------------------------------------------------------------------------------
Total Operating Revenues 264,415 257,243
- -------------------------------------------------------------------------------
Operating Expenses
Fuel 64,247 58,422
Purchased Power 22,826 23,345
Coal Contract Termination Fee - 11,250
Other Operations and Maintenance 36,676 39,712
Depreciation and Amortization 30,592 30,203
Amortization of Transition Recovery Asset 13,472 10,790
Taxes Other Than Income Taxes 10,732 11,467
- -------------------------------------------------------------------------------
Total Operating Expenses 178,545 185,189
- -------------------------------------------------------------------------------
Operating Income 85,870 72,054
- -------------------------------------------------------------------------------
Other Income (Deductions)
Interest Income 5,055 5,159
Interest Income - Note Receivable from UniSource
Energy 2,581 2,352
Other Income 590 1,877
Other Expense (255) (447)
- -------------------------------------------------------------------------------
Total Other Income (Deductions) 7,971 8,941
- -------------------------------------------------------------------------------
Interest Expense
Long-Term Debt 18,999 16,025
Interest on Capital Leases 21,254 21,923
Other Interest Expense, Net of Amounts Capitalized 144 93
- -------------------------------------------------------------------------------
Total Interest Expense 40,397 38,041
- -------------------------------------------------------------------------------
Income Before Income Taxes and Cumulative Effect
of Accounting Change 53,444 42,954
Income Tax Expense 21,942 16,392
- -------------------------------------------------------------------------------
Income Before Cumulative Effect of Accounting Change 31,502 26,562
Cumulative Effect of Accounting Change - Net of Tax - -
- -------------------------------------------------------------------------------
Net Income $ 31,502 $ 26,562
===============================================================================
See Notes to Condensed Consolidated Financial Statements.
TUCSON ELECTRIC POWER COMPANY
COMPARATIVE CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Nine Months Ended
September 30,
2003 2002
(Unaudited)
- -------------------------------------------------------------------------------
-Thousands of Dollars-
Operating Revenues
Electric Retail Sales $ 533,518 $ 521,064
Electric Wholesale Sales 107,994 125,911
Net Unrealized Gain on Forward Electric Sales and
Purchases 39 807
Other Revenues 6,734 6,819
- -------------------------------------------------------------------------------
Total Operating Revenues 648,285 654,601
- -------------------------------------------------------------------------------
Operating Expenses
Fuel 162,512 164,937
Purchased Power 56,524 46,909
Coal Contract Termination Fee - 11,250
Other Operations and Maintenance 122,757 123,605
Depreciation and Amortization 89,976 93,048
Amortization of Transition Recovery Asset 24,842 20,311
Taxes Other Than Income Taxes 32,678 33,735
- -------------------------------------------------------------------------------
Total Operating Expenses 489,289 493,795
- -------------------------------------------------------------------------------
Operating Income 158,996 160,806
- -------------------------------------------------------------------------------
Other Income (Deductions)
Interest Income 15,259 14,388
Interest Income - Note Receivable from UniSource
Energy 7,660 6,978
Other Income 1,713 2,798
Other Expense (790) (1,273)
- -------------------------------------------------------------------------------
Total Other Income(Deductions) 23,842 22,891
- -------------------------------------------------------------------------------
Interest Expense
Long-Term Debt 57,384 48,115
Interest on Capital Leases 62,781 65,843
Other Interest Expense, Net of Amounts Capitalized 211 273
- -------------------------------------------------------------------------------
Total Interest Expense 120,376 114,231
- -------------------------------------------------------------------------------
Income Before Income Taxes and Cumulative Effect
of Accounting Change 62,462 69,466
Income Tax Expense 26,962 27,367
- -------------------------------------------------------------------------------
Income Before Cumulative Effect of Accounting Change 35,500 42,099
Cumulative Effect of Accounting Change - Net of Tax 67,471 -
- -------------------------------------------------------------------------------
Net Income $ 102,971 $ 42,099
===============================================================================
See Notes to Condensed Consolidated Financial Statements.
6
TUCSON ELECTRIC POWER COMPANY
COMPARATIVE CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Nine Months Ended
September 30,
2003 2002
(Unaudited)
- -------------------------------------------------------------------------------
-Thousands of Dollars-
Cash Flows from Operating Activities
Cash Receipts from Electric Retail Sales $ 560,668 $ 550,291
Cash Receipts from Electric Wholesale Sales 155,505 191,468
Interest Received 22,004 12,527
Fuel Costs Paid (158,327) (157,179)
Purchased Power Costs Paid (92,762) (108,875)
Wages Paid, Net of Amounts Capitalized (46,101) (45,745)
Payment of Other Operations and Maintenance Costs (72,947) (78,967)
Capital Lease Interest Paid (74,131) (68,276)
Taxes Paid, Net of Amounts Capitalized (66,081) (65,526)
Debt Interest Paid, Net of Amounts Capitalized (62,095) (52,902)
Income Taxes Paid (3,718) (10,306)
Coal Contract Termination Fee - (11,250)
Other 259 93
- -------------------------------------------------------------------------------
Net Cash Flows - Operating Activities 162,274 155,353
- -------------------------------------------------------------------------------
Cash Flows from Investing Activities
Capital Expenditures (97,105) (72,181)
Purchase of North Loop Gas Turbine from UED - (14,853)
Investment in Springerville Lease Debt and Equity 12,078 (134,989)
Other (1,902) (789)
- -------------------------------------------------------------------------------
Net Cash Flows - Investing Activities (86,929) (222,812)
- -------------------------------------------------------------------------------
Cash Flows from Financing Activities
Proceeds from Borrowings under Revolving Credit
Facility 45,000 -
Repayments on Revolving Credit Facility (25,000) -
Repayments of Long-Term Debt (1,725) (1,879)
Dividends Paid to UniSource Energy (58,500) (10,000)
Payments on Capital Lease Obligations (42,379) (19,384)
Other (14,614) 6,926
- -------------------------------------------------------------------------------
Net Cash Flows - Financing Activities (97,218) (24,337)
- -------------------------------------------------------------------------------
Net Decrease in Cash and Cash Equivalents (21,873) (91,796)
Cash and Cash Equivalents, Beginning of Year 55,778 159,680
- -------------------------------------------------------------------------------
Cash and Cash Equivalents, End of Period $ 33,905 $ 67,884
===============================================================================
SUPPLEMENTAL CONDENSED CONSOLIDATED CASH FLOW INFORMATION
- -------------------------------------------------------------------------------
Net Income $ 102,971 $ 42,099
Adjustments to Reconcile Net Income to Net Cash Flows
Cumulative Effect of Accounting Change - Net of Tax (67,471) -
Depreciation and Amortization Expense 89,976 93,048
Depreciation Recorded to Fuel and Other O&M Expense 4,300 4,190
Amortization of Transition Recovery Asset 24,842 20,311
Net Unrealized Gain on Forward Electric Sales and
Purchases (39) (807)
Amortization of Deferred Debt-Related Costs included
in Interest Expense 2,199 1,428
Provision for Bad Debts 3,910 1,753
Deferred Income Taxes 25,504 25,557
(Income) Losses from Equity Method Entities (132) 279
Interest on Note Receivable from UniSource Energy (7,660) (6,978)
Other, Net 8,652 (894)
Changes in Current Assets and Liabilities which
Provided (Used) Cash Exclusive of Changes Shown
Separately:
Accounts Receivable (19,111) 18,625
Materials and Fuel Inventory (801) 1,338
Accounts Payable (1,046) (39,080)
Interest Accrued (18,661) (9,817)
Taxes Accrued 10,778 9,702
Other Current Assets 7,541 (4,981)
Other Current Liabilities (3,478) (420)
- -------------------------------------------------------------------------------
Net Cash Flows - Operating Activities $ 162,274 $ 155,353
===============================================================================
See Notes to Condensed Consolidated Financial Statements.
7
TUCSON ELECTRIC POWER COMPANY
COMPARATIVE CONDENSED CONSOLIDATED BALANCE SHEETS
September 30, December 31,
2003 2002
(Unaudited)
- -------------------------------------------------------------------------------
ASSETS -Thousands of Dollars-
Utility Plant
Plant in Service $ 2,635,379 $ 2,598,884
Utility Plant under Capital Leases 747,533 747,556
Construction Work in Progress 107,493 59,926
- -------------------------------------------------------------------------------
Total Utility Plant 3,490,405 3,406,366
Less Accumulated Depreciation and Amortization (1,294,586) (1,346,101)
Less Accumulated Depreciation of Capital Lease
Assets (413,741) (391,915)
- -------------------------------------------------------------------------------
Total Utility Plant - Net 1,782,078 1,668,350
- -------------------------------------------------------------------------------
Investments and Other Property
Investments in Lease Debt and Equity 179,010 191,867
Other 20,968 21,358
- -------------------------------------------------------------------------------
Total Investments and Other Property 199,978 213,225
- -------------------------------------------------------------------------------
Note Receivable from UniSource Energy 70,132 79,462
- -------------------------------------------------------------------------------
Current Assets
Cash and Cash Equivalents 33,905 55,778
Trade Accounts Receivable 66,228 66,826
Unbilled Accounts Receivable 22,104 9,910
Allowance for Doubtful Accounts (11,828) (9,012)
Intercompany Accounts Receivable 20,999 14,851
Materials and Fuel Inventory 45,301 44,500
Interest on Note Receivable from UniSource Energy 16,990 -
Current Regulatory Assets 10,944 11,778
Deferred Income Taxes - Current 12,337 15,917
Interest Receivable - Current 6,210 12,178
Other 8,736 8,407
- -------------------------------------------------------------------------------
Total Current Assets 231,926 231,133
- -------------------------------------------------------------------------------
Regulatory and Other Assets
Transition Recovery Asset 282,278 307,120
Income Taxes Recoverable Through Future Revenues 51,648 57,044
Other Regulatory Assets 11,596 10,504
Other Assets 45,890 46,752
- -------------------------------------------------------------------------------
Total Regulatory and Other Assets 391,412 421,420
- -------------------------------------------------------------------------------
Total Assets $ 2,675,526 $ 2,613,590
===============================================================================
CAPITALIZATION AND OTHER LIABILITIES
Capitalization
Common Stock Equity $ 382,018 $ 337,463
Capital Lease Obligations 761,805 801,508
Long-Term Debt 1,126,685 1,128,410
- -------------------------------------------------------------------------------
Total Capitalization 2,270,508 2,267,381
- -------------------------------------------------------------------------------
Current Liabilities
Current Obligations under Capital Leases 50,205 42,872
Current Maturities of Long-Term Debt 1,725 1,725
Borrowings under Revolving Credit Facility 20,000 -
Accounts Payable 40,088 41,704
Intercompany Accounts Payable 8,522 12,478
Interest Accrued 31,568 60,238
Taxes Accrued 43,655 35,772
Accrued Employee Expenses 11,786 13,370
Other 7,954 7,543
- -------------------------------------------------------------------------------
Total Current Liabilities 215,503 215,702
- -------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred Income Taxes - Noncurrent 119,122 67,490
Other 70,393 63,017
- -------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 189,515 130,507
- -------------------------------------------------------------------------------
Commitments and Contingencies (Note 9)
- -------------------------------------------------------------------------------
Total Capitalization and Other Liabilities $ 2,675,526 $ 2,613,590
===============================================================================
See Notes to Condensed Consolidated Financial Statements.
8
TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
Accumulated
Capital Accumulated Other Total
Common Stock Earnings Comprehensive Stockholders'
Stock Expense (Deficit) Income (Loss) Equity
- -------------------------------------------------------------------------------
(Unaudited)
-Thousands of Dollars-
Balances at
December 31, 2002 $ 653,529 $ (6,357) $(305,685) $ (4,024) $ 337,463
- -------------------------------------------------------------------------------
Comprehensive Income:
2003 Year-to-Date
Net Income - - 102,971 - 102,971
---------
Total Comprehensive
Income 102,971
---------
Dividends Declared - - (58,500) - (58,500)
Other 84 - - - 84
- -------------------------------------------------------------------------------
Balances at
September 30, 2003 $ 653,613 $ (6,357) $(261,214) $ (4,024) $ 382,018
===============================================================================
See Notes to Condensed Consolidated Financial Statements.
9
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
- ------------------------------------------------------------------------------
NOTE 1. NATURE OF OPERATIONS, BASIS OF ACCOUNTING PRESENTATION AND STOCK-
BASED COMPENSATION
- ------------------------------------------------------------------------------
UniSource Energy Corporation (UniSource Energy) is an exempt holding
company under the Public Utility Holding Company Act of 1935. UniSource
Energy has no significant operations of its own, but owns substantially all of
the common stock of Tucson Electric Power Company (TEP) and all of the common
stock of UniSource Energy Services, Inc. (UES), Millennium Energy Holdings,
Inc. (Millennium) and UniSource Energy Development Company (UED).
TEP, a regulated public utility incorporated in Arizona since 1963, is
UniSource Energy's largest operating subsidiary and represented approximately
86% of UniSource Energy's assets as of September 30, 2003. TEP generates,
transmits and distributes electricity. TEP serves retail electric customers
in a 1,155 square mile area in Southern Arizona. TEP also sells electricity
to other utilities and power marketing entities primarily located in the
western U.S.
On August 11, 2003, UniSource Energy completed the purchase of the
Arizona gas and electric system assets from Citizens Communications Company
(Citizens). This acquisition adds approximately 127,000 retail gas customers
and 80,000 retail electric customers in Arizona to UniSource Energy's customer
base. UniSource Energy formed two new operating companies called UNS Gas,
Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric) to acquire these assets,
as well as an intermediate holding company, UES, to hold the common stock of
UNS Gas and UNS Electric. See Note 2.
Millennium's unregulated businesses are described in Note 8 and UED's
services are described in Note 7.
References to "we" and "our" are to UniSource Energy and its
subsidiaries, collectively.
The accompanying quarterly financial statements of UniSource Energy and
TEP are unaudited but reflect all normal recurring accruals and other
adjustments which we believe are necessary for a fair presentation of the
results for the interim periods presented. These financial statements are
presented in accordance with the Securities and Exchange Commission's (SEC)
interim reporting requirements which do not include all the disclosures
required by accounting principles generally accepted in the United States of
America (GAAP) for audited annual financial statements. The year-end
condensed balance sheet data was derived from audited financial statements,
but does not include disclosures required by GAAP for audited annual financial
statements. This quarterly report should be reviewed in conjunction with
UniSource Energy and TEP's 2002 Annual Report on Form 10-K.
Weather, among other factors, causes seasonal fluctuations in TEP and
UES's sales; therefore, quarterly results are not indicative of annual
operating results. UniSource Energy and TEP have made minor reclassifications
to the prior year financial statements for comparative purposes. These
reclassifications had no effect on net income.
STOCK-BASED COMPENSATION
UniSource Energy has two stock-based compensation plans, the 1994 Outside
Director Stock Option Plan (Directors' Plan) and the 1994 Omnibus Stock and
Incentive Plan (Omnibus Plan). We account for those plans under the
recognition and measurement principles of APB Opinion No. 25, Accounting for
Stock Issued to Employees (APB 25), and related interpretations. No
compensation cost is reflected in net income for stock options, as all options
granted had an exercise price equal to the market value of the underlying
common stock on the date of grant. The following table illustrates the effect
on UniSource Energy's net income and earnings per share and TEP's net income
if we had applied the fair value recognition provisions of Statement of
Financial Accounting Standards No. 123, Accounting for Stock-Based
Compensation, to stock-based employee compensation:
10
UniSource Energy:
- ----------------
Three Months Ended September 30,
2003 2002
--------------------------------------------------------------------
-Thousands of Dollars-
(except per share data)
Net Income - As Reported $ 26,684 $ 22,819
Deduct: Total stock-based employee
compensation expense determined under
fair value based method, net of
related tax effects (248) (318)
--------------------------------------------------------------------
Pro Forma Net Income $ 26,436 $ 22,501
====================================================================
Basic Earnings per Share:
As Reported $0.79 $0.68
Pro Forma $0.78 $0.67
====================================================================
Diluted Earnings per Share:
As Reported $0.78 $0.67
Pro Forma $0.77 $0.66
====================================================================
Nine Months Ended September 30,
2003 2002
--------------------------------------------------------------------
-Thousands of Dollars-
(except per share data)
Net Income - As Reported $ 84,537 $ 28,393
Deduct: Total stock-based employee
compensation expense determined under
fair value based method, net of
related tax effects (733) (953)
--------------------------------------------------------------------
Pro Forma Net Income $ 83,804 $ 27,440
====================================================================
Basic Earnings per Share:
As Reported $2.50 $0.84
Pro Forma $2.48 $0.82
====================================================================
Diluted Earnings per Share:
As Reported $2.47 $0.83
Pro Forma $2.45 $0.81
====================================================================
TEP:
- ---
Three Months Ended September 30,
2003 2002
--------------------------------------------------------------------
-Thousands of Dollars-
Net Income - As Reported $ 31,502 $ 26,562
Deduct: Total stock-based employee
compensation expense determined under
fair value based method, net of
related tax effects (244) (314)
--------------------------------------------------------------------
Pro Forma Net Income $ 31,258 $ 26,248
====================================================================
Nine Months Ended September 30,
2003 2002
--------------------------------------------------------------------
-Thousands of Dollars-
Net Income - As Reported $102,971 $ 42,099
Deduct: Total stock-based employee
compensation expense determined under
fair value based method, net of
related tax effects (723) (942)
--------------------------------------------------------------------
Pro Forma Net Income $102,248 $ 41,157
====================================================================
11
The fair value of each stock option grant is estimated on the date of
grant using the Black-Scholes option-pricing model with the following weighted
average assumptions:
2003 2002
---------------------------------------------------------------
Expected life (years) 5 5
Interest rate 2.78% 1.45%
Volatility 23.38% 23.74%
Dividend yield 3.44% 2.83%
Weighted-average grant-date fair value
of options granted during the period $2.92 $2.90
---------------------------------------------------------------
NOTE 2. ESTABLISHMENT OF UES
- -----------------------------
On August 11, 2003, UniSource Energy acquired the Arizona gas and
electric system assets from Citizens for $224 million, comprised of the base
purchase price plus other operating capital adjustments. The results of UNS
Gas, UNS Electric, and UES have been included in UniSource Energy's
consolidated financial statements since the acquisition date.
The purchase price and the allocation of the assets acquired and the
liabilities assumed based on their estimated fair market values as of the
acquisition date are as follows:
Purchase Price (in thousands):
Cash Paid $224,138
Transaction Costs 4,891
---------------------------------------------------------
Total Purchase Price $229,029
=========================================================
Allocation of Purchase Price (in thousands):
Property, Plant & Equipment $242,421
Current Assets 29,388
Regulatory Assets 1,321
Other Assets 580
Current Liabilities (30,962)
Deferred Credits and Other Liabilities (13,719)
---------------------------------------------------------
Total Purchase Price $229,029
=========================================================
UniSource Energy is in the process of evaluating the allocation of post-
closing purchase price adjustments. Potential adjustments to the purchase
price allocation are not expected to be material.
The investment was funded by $160 million in senior unsecured notes
issued by UNS Electric and UNS Gas in a private placement, $35 million from
short-term bridge financing debt issued by UniSource Energy (see Note 14),
and approximately $50 million in cash from UniSource Energy. UNS Gas issued
$50 million of 6.23% Notes due August 11, 2011 and $50 million of 6.23% Notes
due August 11, 2015. UNS Electric issued $60 million of 7.61% Notes due
August 11, 2008. All three series of notes may be prepaid with a make-whole
call premium reflecting a discount rate equal to an equivalent maturity U.S.
Treasury security yield plus 50 basis points. The notes are guaranteed by
UES.
RATES AND REGULATION
Concurrent with the closing of the acquisition, retail rate increases for
customers of both UNS Electric and UNS Gas went into effect on August 11,
2003. These rate increases were approved by the Arizona Corporation
Commission (ACC) on July 3, 2003, when it approved the acquisition and the
terms of the April 1, 2003 settlement agreement (Citizens Settlement
Agreement) among UniSource Energy, Citizens, and the ACC Staff.
12
UNS Gas
UNS Gas is regulated by the ACC with respect to retail gas rates, the
issuance of securities, and transactions with affiliated parties. UNS Gas'
retail gas rates include a monthly customer charge, a base rate charge for
delivery services and the cost of gas (expressed in cents per therm), and a
Purchased Gas Adjustor (PGA) mechanism.
The PGA mechanism is intended to address the volatility of natural gas
prices and allows UNS Gas to recover its costs through a price adjustor. The
PGA charge may be changed monthly based on an ACC approved mechanism that
compares the twelve-month rolling average gas cost to the base cost of gas,
subject to limitations on how much the price per therm may change in a twelve
month period. The difference between the actual cost of UNS Gas' gas supplies
and transportation contracts and that currently allowed by the ACC are
deferred and recovered or repaid through the PGA mechanism. When under or
over recovery trigger points are met, UNS Gas may request a PGA surcharge or
surcredit with the goal of collecting or returning the amount deferred from or
to customers over a twelve month period.
The related ACC order and the Citizens Settlement Agreement include the
following terms related to UNS Gas rates:
- An increase in retail delivery base rates, effective August 11, 2003,
equivalent to a 20.9% overall increase over 2001 test year retail revenues
through a base rate increase.
- Fair value rate base of $142 million and allowed rate of return of
7.49%, based on a cost of capital of 9.05%, derived from a cost of equity of
11.00% and a cost of debt of 7.75% (based on a capital structure of 60% debt
and 40% equity).
- The existing PGA rate may not change more than $0.15 per therm through
July 2004. Thereafter, the PGA rate may not change more than $0.10 per therm.
Under the terms of the ACC order, UNS Gas may not file a general rate
increase until August 2006 and any resulting rate increase shall not become
effective prior to August 1, 2007.
The Citizens Settlement Agreement also limits dividends payable by UNS
Gas to UniSource Energy to 75% of earnings until the ratio of common equity to
total capitalization reaches 40%. The ratio of common equity to total
capitalization for UNS Gas is 34% at September 30, 2003.
On September 9, 2003, the ACC approved a new PGA surcharge of $0.1155 per
therm that took effect on October 1, 2003.
UNS Electric
UNS Electric is regulated by the ACC with respect to retail electric
rates, the issuance of securities, and transactions with affiliated parties,
and by the FERC with respect to wholesale power contracts and interstate
transmission service.
UNS Electric's retail electric rates include a Purchased Power and Fuel
Adjustment clause (PPFAC), that allows for a separate surcharge or surcredit
to the base rate for delivered purchased power to collect or return under or
over recovery of costs. As part of the July 3, 2003 Order, the ACC approved a
new PPFAC surcharge of $0.01825 per kWh to fully recover the cost of the
current full-requirements power supply agreement with Pinnacle West Capital
Corporation (PWCC).
The ACC order and Citizens Settlement Agreement include the following
terms related to UNS Electric rates:
- A 22% overall increase in retail rates effective August 11, 2003 from
the rates previously in effect for Citizens. This reflects the implementation
of a PPFAC surcharge of $0.01825 per kWh, which combined with the current base
rate of $0.05194 per kWh, results in a new delivered purchase power price of
$0.07019. This allows UNS Electric to fully recover the cost of purchased
power under its current contract with its sole energy supplier, PWCC.
13
- UNS Electric must attempt to renegotiate the PWCC purchase power
contract, and any savings that result from a renegotiated contract must be
allocated in a ratio of 90% to ratepayers and 10% to shareholders.
- UNS Electric and Citizens forfeited all rights to recover from
ratepayers any of the under-collected PPFAC balance in the approximate amount
of $135 million through August 11, 2003.
The ACC order also requires that TEP submit in its next general rate case
filing in June 2004, a feasibility study and consolidation plan, or a plan for
coordination of operations of UNS Electric's operations in Santa Cruz County
with those of TEP.
Under the terms of the ACC order, UNS Electric may not file a general
rate increase until August 2006 and any resulting rate increase shall not
become effective prior to August 1, 2007.
The Citizens Settlement Agreement also limits dividends payable by UNS
Electric to UniSource Energy to 75% of earnings until the ratio of common
equity to total capitalization reaches 40%. The ratio of common equity to
total capitalization for UNS Electric was 37.5% at September 30, 2003.
UES COMMITMENTS
UNS Gas has firm transportation agreements with El Paso Natural Gas
(EPNG) and Transwestern Pipeline Company (Transwestern) with combined capacity
sufficient to meet its load requirements. EPNG provides gas transportation
service under a converted full requirements contract in which UNS Gas pays a
fixed reservation charge. This contract expires in August 2011. In July
2003, FERC required the conversion of UNS Gas' full requirements status under
the EPNG agreement to contract demand starting on September 1, 2003. Upon
conversion to contract demand status, UNS Gas now has specific volume limits
in each month and specific receipt point rights from the available supply
basins (San Juan and Permian). These changes will reduce the amount of less
expensive San Juan gas available to UNS Gas. The impact, however, is not
expected to be material. The annual cost of the EPNG capacity after
conversion to contract demand will not change. The Transwestern contract
expires in January 2007. The aggregate annual minimum transportation charges
are expected to be approximately $3.5 million and $3.0 million for the EPNG
and Transwestern contracts, respectively.
UNS Electric imports the power it purchases over the Western Area Power
Administration's (WAPA) transmission lines. UNS Electric's transmission
capacity agreements with WAPA provide for annual rate adjustments and expire
in February 2008 and June 2011. The contract that expires in 2008 also
contains a capacity adjustment clause. Under the terms of the agreements, UNS
Electric's aggregate minimum fixed transmission charges are expected to be
approximately $2 million for the last five months of 2003, $6 million in 2004,
and $1 million in 2005 through 2011.
NOTE 3. REGULATORY ACCOUNTING
- ------------------------------
TEP and UES generally use the same accounting policies and practices used
by unregulated companies for financial reporting under GAAP. However,
sometimes these principles, such as Statement of Financial Accounting
Standards No. 71, Accounting for the Effects of Certain Types of Regulation
(FAS 71), require special accounting treatment for regulated companies to show
the effect of regulation. For example, in setting TEP's and UES' retail
rates, the ACC may not allow TEP or UES to currently charge their customers to
recover certain expenses, but instead requires that these expenses be charged
to customers in the future. In this situation, FAS 71 requires that TEP and
UES defer these items and show them as regulatory assets on the balance sheet
until TEP and UES are allowed to charge their customers. TEP and UES then
amortize these items as expense to the income statement as those charges are
recovered from customers. Similarly, certain revenue items may be deferred as
regulatory liabilities, which are also eventually amortized to the income
statement as rates to customers are reduced.
The conditions a regulated company must satisfy to apply the accounting
policies and practices of FAS 71 include:
- an independent regulator sets rates;
- the regulator sets the rates to recover specific costs of delivering
service; and
- the service territory lacks competitive pressures to reduce rates below
the rates set by the regulator.
14
IMPLICATIONS OF DISCONTINUING APPLICATION OF FAS 71
TEP
In November 1999, upon approval by the ACC of a settlement agreement (TEP
Settlement Agreement) relating to recovery of TEP's transition costs and
standard retail rates, TEP discontinued application of FAS 71 to its
generation operations.
TEP's distribution regulatory assets total $356 million at September 30,
2003, $23 million of which are not presently included in the rate base and
consequently are not earning a return on investment.
TEP continues to apply FAS 71 to its regulated operations, which are the
distribution and transmission portions of its business. TEP regularly
assesses whether it can continue to apply FAS 71 to these operations. If TEP
stopped applying FAS 71 to its remaining regulated operations, it would write
off the related balances of its regulatory assets as an expense on its income
statement. Based on the regulatory asset balances at September 30, 2003, if
TEP had stopped applying FAS 71 to its remaining regulated operations, it
would have recorded an extraordinary loss, after-tax, of approximately $215
million. While regulatory orders and market conditions may affect cash flows,
TEP's cash flows would not be affected if it stopped applying FAS 71 unless a
regulatory order limited its ability to recover the cost of that regulatory
asset.
UES
UES' regulatory assets, net of regulatory liabilities, total $5 million
at September 30, 2003. If UES stopped applying FAS 71 to its regulated
operations, it would write off the related balances of its regulatory assets
as an expense and would write off its regulatory liabilities as income on its
income statement. Based on the balances of UES' regulatory assets and
liabilities at September 30, 2003, if UES had stopped applying FAS 71 to its
regulated operations, it would have recorded an extraordinary loss, after-tax,
of approximately $3 million. UES' cash flows would not be affected if it
stopped applying FAS 71 unless a regulatory order limited its ability to
recover the cost of that regulatory asset.
NOTE 4. ACCOUNTING CHANGE: ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
- ------------------------------------------------------------------------
In June 2001, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 143, Accounting for Asset
Retirement Obligations (FAS 143). It requires entities to record the fair
value of a liability for a legal obligation to retire an asset in the period
in which the liability is incurred. A legal obligation is a liability that a
party is required to settle as a result of an existing or enacted law,
statute, ordinance or contract. When the liability is initially recorded, the
entity should capitalize a cost by increasing the carrying amount of the
related long-lived asset. Over time, the liability is adjusted to its present
value by recognizing accretion expense as an operating expense in the income
statement each period, and the capitalized cost is depreciated over the useful
life of the related asset. Upon settlement of the liability, an entity either
settles the obligation for its recorded amount or incurs a gain or loss if the
actual costs differ from the recorded amount.
Prior to adopting FAS 143, costs for final removal of all owned
generation facilities were accrued as an additional component of depreciation
expense. Under FAS 143, only the costs to remove an asset with legally
binding retirement obligations will be accrued over time through accretion of
the asset retirement obligation and depreciation of the capitalized asset
retirement cost.
TEP has identified legal obligations to retire generation plant assets
specified in land leases for its jointly-owned Navajo and Four Corners
Generating Stations. The land on which these stations reside is leased from
the Navajo Nation. The provisions of the leases require the lessees to remove
the facilities upon request of the Navajo Nation at the expiration of the
leases. TEP also has certain environmental obligations at the San Juan
Generating Station (San Juan). TEP has estimated that its share of the cost
to remove the Navajo and Four Corners facilities and to settle the San Juan
environmental obligations will be approximately $38 million at the date of
retirement. No other legal obligations to retire generation plant assets were
identified. UES, Millennium and UED have no asset retirement obligations.
15
TEP has various transmission and distribution lines that operate under
land leases and rights of way that contain end dates and restorative clauses.
TEP operates its transmission and distribution lines as if they will be
operated in perpetuity and would continue to be used or sold without land
remediation. As a result, TEP is not recognizing the costs of final removal
of the transmission and distribution lines in the financial statements.
Upon adoption of FAS 143 on January 1, 2003, TEP recorded an asset
retirement obligation of $38 million at its net present value of $1.1 million,
increased depreciable assets by $0.1 million for asset retirement costs,
reversed $112.8 million of costs previously accrued for final removal from
accumulated depreciation, reversed previously recorded deferred tax assets of
$44.2 million and recognized the cumulative effect of accounting change as a
gain of $111.7 million ($67.5 million net of tax). TEP expects that adopting
FAS 143 will result in a reduction to current depreciation expense charged
throughout the year as well because asset retirement costs are no longer
recorded as a component of depreciation expense. For the first nine months of
2003, this amount is approximately $4 million.
The following table illustrates on a pro forma basis the amount of the
asset retirement obligation as if FAS 143 had been applied during all periods
presented:
Nine Months Ended September 30,
2003 2002
Actual Pro Forma
-----------------------------------------------------------------------
-Thousands of Dollars-
Asset Retirement Obligation - beginning
of period $ 1,119 $ 1,017
Accretion Expense 83 76
-----------------------------------------------------------------------
Asset Retirement Obligation - end
of period $ 1,202 $ 1,093
=======================================================================
The following table illustrates on a pro forma basis the effect on
UniSource Energy's net income and earnings per share and TEP's net income as
if FAS 143 had been in effect for all income statement periods presented:
UniSource Energy:
- ----------------
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
- -----------------------------------------------------------------------------
-Thousands of Dollars-
(except per share data)
Net Income - As Reported $ 22,819 $ 28,393
Adjustment to accrued expense (net
of tax) as if FAS 143 had been
applied effective January 1, 2002 721 2,603
- -----------------------------------------------------------------------------
Pro Forma Net Income $ 23,540 $ 30,996
=============================================================================
Basic Earnings per Share:
As Reported $ 0.68 $ 0.84
Adjustment to accrued expense (net
of tax) as if FAS 143 had been
applied effective January 1, 2002 0.02 0.08
- -----------------------------------------------------------------------------
Pro Forma $ 0.70 $ 0.92
=============================================================================
Diluted Earnings per Share:
As Reported $ 0.67 $ 0.83
Adjustment to accrued expense (net
of tax) as if FAS 143 had been
applied effective January 1, 2002 0.02 0.08
- -----------------------------------------------------------------------------
Pro Forma $ 0.69 $ 0.91
=============================================================================
16
TEP:
- ---
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
- -----------------------------------------------------------------------------
-Thousands of Dollars-
Net Income - As Reported $ 26,562 $ 42,099
Adjustment to accrued expense (net
of tax) as if FAS 143 had been
applied effective January 1, 2002 721 2,603
- -----------------------------------------------------------------------------
Pro Forma Net Income $ 27,283 $ 44,702
=============================================================================
Amounts recorded under FAS 143 are subject to various assumptions and
determinations, such as determining whether a legal obligation exists to
remove assets, estimating the fair value of the costs of removal, estimating
when final removal will occur, and the credit-adjusted risk-free interest
rates to be used to discount future liabilities. Changes that may arise over
time with regard to these assumptions and determinations will change amounts
recorded in the future as expense for asset retirement obligations.
If TEP retires any asset at the end of its useful life, without a legal
obligation to do so, it will record retirement costs at that time as incurred
or accrued. TEP does not believe that the adoption of FAS 143 will result in
any change in retail rates since all matters relating to the rate-making
treatment of TEP's generating assets were determined pursuant to the TEP
Settlement Agreement.
NOTE 5. STOCK-BASED COMPENSATION PLANS
- ---------------------------------------
We account for UniSource Energy's two stock-based compensation plans, the
Directors' Plan and the Omnibus Plan, under the recognition and measurement
principles of APB 25 and related interpretations (see
Note 1).
STOCK OPTIONS
The Directors' Plan granted a total of 22,418 stock options and 22,000
stock options, respectively, during the nine-month periods ended September 30,
2003 and 2002. Additionally, the UniSource Energy Board of Directors granted
97,818 stock options and 568,000 stock options, respectively, to key employees
under the Omnibus Plan during the nine-month periods ended September 30, 2003
and 2002. These options vest over three years, become exercisable in one-third
increments on each anniversary date of the grant and expire on the tenth
anniversary of the grant.
A summary of the stock option activity of the Directors' Plan and Omnibus
Plan is as follows:
Nine Months Ended September 30,
2003 2002
------------------------------------------------------------------
Weighted Weighted
Average Average
Exercise Exercise
Shares Price Shares Price
------------------------------------------------------------------
Options Outstanding,
Beginning of Period 2,576,282 $15.77 2,075,234 $15.05
Granted 120,236 $17.77 590,000 $18.14
Exercised (24,569) $13.47 (59,685) $14.47
Forfeited (14,529) $14.24 (12,087) $14.21
---------- ----------
Options Outstanding,
End of Period 2,657,420 $15.89 2,593,462 $15.77
========== =========
Options Exercisable,
End of Period 1,851,543 $15.13 1,450,822 $14.47
Weighted Average Remaining
Contractual Life at September 30, 2003: 6.39
------------------------------------------------------------------
17
RESTRICTED STOCK UNITS
During the nine months ended September 30, 2003, 573 restricted shares or
stock units were awarded under the Directors' Plan to each of nine directors,
for a total of 5,157 shares or units. The restricted shares or stock units
become 100% vested on the third anniversary of the grant date. Compensation
expense equal to the fair market value on the date of award is recognized over
the vesting period. The fair market value on the award date was $17.44.
LONG-TERM INCENTIVE COMPENSATION
In May 2003, the Board of Directors approved a grant of performance
shares and performance units to key employees under the Omnibus Plan. The
shares and units may be awarded at the end of a three-year performance period
based on goal attainment. Compensation expense is recorded over the
performance period based on the anticipated number and market value of shares
to be awarded. Compensation expense of $415,000 was recorded for the nine-
month period ended September 30, 2003 for this new incentive plan.
NOTE 6. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND TRADING ACTIVITIES
- ---------------------------------------------------------------------
TEP enters into forward contracts to purchase or sell a specified amount
of capacity or energy at a specified price over a given period of time,
typically for one month, three months, or one year, within established limits
to take advantage of favorable market opportunities. In general, TEP enters
into forward purchase contracts when market conditions provide the opportunity
to purchase for its load at prices that are below the marginal cost of its
supply resources or to supplement TEP's own resources (i.e., during plant
outages and summer peaking periods). TEP enters into forward sales contracts
when TEP forecasts that it has excess supply and the market price of energy
exceeds its marginal cost. The majority of TEP's forward contracts are
considered normal purchases and sales under Statement of Financial Accounting
Standards No. 133, Accounting for Derivative Instruments and Hedging
Activities (FAS 133) and, therefore, are not required to be marked to market.
However, some of these forward contracts are considered to be derivatives,
which TEP marks to market under FAS 133, by recording unrealized gains and
losses and adjusting the related assets and liabilities on a monthly basis to
reflect the market prices at the end of the month.
TEP manages the risk of counterparty default by performing financial
credit reviews, setting limits, monitoring exposures, requiring collateral
when needed, and using a standard agreement which allows for the netting of
current period exposures to and from a single counterparty.
UNS Gas and UNS Electric do not currently have any contracts that are
required to be marked to market under FAS 133. UNS Gas does have a natural
gas supply and management agreement under which it purchases substantially all
of its gas requirements at market prices from BP Energy Company (BP).
However, the contract terms allow UNS Gas to lock in fixed prices on a portion
of its gas purchases by entering into fixed price forward contracts with BP at
various times during the year, which enables UNS Gas to provide more stable
prices to its customers. These purchases are made up to a year in advance with
the goal of locking in fixed prices on at least 30% of the expected monthly
gas consumption prior to entering into the month. These forward contracts, as
well as the main gas supply contract, meet the definition of normal purchases
under FAS 133 and therefore are not required to be marked to market.
Millennium Environmental Group, Inc. (MEG), a wholly-owned subsidiary of
Millennium, enters into swap agreements, options and forward contracts
relating to Emission Allowances and coal. MEG marks its trading contracts to
market under FAS 133 by recording unrealized gains and losses and adjusting
the related assets and liabilities on a monthly basis to reflect the market
prices at the end of the month.
The market prices used to determine fair value for TEP and MEG's
derivative instruments are estimated based on various factors including broker
quotes, exchange prices, over the counter prices and time value.
Statement of Financial Accounting Standards No. 149, Amendment of
Statement 133 on Derivative Instruments and Hedging Activities (FAS 149), was
issued by the FASB in April 2003. FAS 149 amends and clarifies accounting for
derivative instruments, including certain derivative instruments embedded in
other contracts, and for hedging activities under FAS 133. The adoption of
FAS 149 did not have a significant impact on our financial statements. See
Note 13.
18
TEP and MEG's derivative activities are reported as follows:
- TEP's unrealized gain/loss on forward sales and purchase contracts is a
component of Operating Revenues;
- TEP's realized gain/loss on forward sales contracts is a component of
Electric Wholesale Sales;
- TEP's realized gain/loss on forward purchase contracts is a component
of Purchased Power; and
- MEG's unrealized and realized gain/loss on trading activities are
components of Operating Revenues. Although MEG's realized gain/loss on
trading activities are reported net on UniSource Energy's income statement,
the related cash receipts and cash payments are reported separately on
UniSource Energy's statement of cash flows.
MEG physically settled the following transaction volumes under its
trading contracts in 2003 and 2002:
Three Months Ended Nine Months Ended
September 30, September 30,
2003 2002 2003 2002
- -----------------------------------------------------------------------------
-in Thousands-
Emission Allowances Purchased 270 66 648 294
Emission Allowances Sold 248 113 586 329
Coal Purchase (in tons) 173 - 211 -
Coal Sold (in tons) 173 - 211 -
- -----------------------------------------------------------------------------
The net pre-tax gains were as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
2003 2002 2003 2002
- -----------------------------------------------------------------------------
-Millions of Dollars-
TEP Net Unrealized Gain on
Derivative Forward Contracts $ 0.2 $ 0.1 $ - $ 0.8
MEG Net Unrealized and Realized
Gain on Trading Activities 0.7 0.3 0.3 0.1
- -----------------------------------------------------------------------------
UniSource Energy Net Gain on
TEP Forward Contracts and MEG
Trading Activities $ 0.9 $ 0.4 $ 0.3 $ 0.9
=============================================================================
At September 30, 2003, the fair value of TEP's derivative assets was less
than $0.1 million and is reported in Other Current Assets on TEP's balance
sheet. At December 31, 2002, TEP had no open forward contracts that were
considered derivatives. MEG's trading assets and liabilities are reported in
Trading Assets and Trading Liabilities on UniSource Energy's balance sheet.
The fair value of MEG's trading assets, including its Emission Allowance
inventory, was $29.2 million at September 30, 2003 and $15.1 million at
December 31, 2002. The fair value of MEG's trading liabilities was $23.2
million at September 30, 2003 and $10.3 million at December 31, 2002.
NOTE 7. BUSINESS SEGMENTS
- --------------------------
Based on the way we organize our operations and evaluate performance, we
have four reportable business segments:
(1) TEP, a vertically integrated electric utility business, is UniSource
Energy's largest subsidiary.
(2) UES is the holding company for UNS Gas, a regulated gas distribution
business; and UNS Electric, a regulated electric distribution utility business
(see Notes 1 and 2).
(3) Millennium holds interests in unregulated businesses (see Note 8).
(4) UED engages in developing generating resources and other project
development activities, including facilitating the expansion of the
Springerville Generating Station. Prior to September 2002, UED owned a 20 MW
gas turbine, which it leased to TEP. In September 2002, UED sold the turbine
to TEP for its net book value of $15 million.
UniSource Energy's significant reconciling adjustments consist of the
elimination of intercompany activity and balances. Millennium recorded
revenue from transactions with TEP of $4 million and $6 million during the
three-month periods ended September 30, 2003 and September 30, 2002, and $11
million and $13 million during
19
the nine-month periods ended September 30, 2003 and September 30, 2002. TEP's
related expense is reported in Other Operations and Maintenance expense on its
income statement. Millennium's revenue and TEP's related expense are
eliminated in UniSource Energy consolidation. Other significant reconciling
adjustments include the elimination of the intercompany note between UniSource
Energy and TEP, as well as the related interest income and expense; and the
elimination of UED's rental income and TEP's rental expense from UED's turbine
lease to TEP prior to UED's sale of the turbine to TEP in September 2002.
We record our percentage share of the earnings of affiliated companies,
except for investments where we provide all of the financing, in which case we
recognize 100% of the losses. See Note 8.
We disclose selected financial data for our business segments in the
following tables:
Segments UniSource
------------------------------------------ Reconciling Energy
TEP UES Millennium UED Adjustments Consolidated
- ------------------------------------------------------------------------------------------------------
-Thousands of Dollars-
Income Statement
- ----------------
Three Months Ended
September 30, 2003:
- ------------------------------------------------------------------------------------------------------
Operating Revenues
- External $ 264,221 $ 34,265 $ 4,312 $ - $ - $ 302,798
- ------------------------------------------------------------------------------------------------------
Operating Revenues
- Intersegment 194 - 3,948 - (4,142) -
- ------------------------------------------------------------------------------------------------------
Income (Loss)Before
Income Taxes 53,444 244 (4,226) (90) (3,692) 45,680
- ------------------------------------------------------------------------------------------------------
Net Income (Loss) 31,502 141 (2,708) (50) (2,201) 26,684
- ------------------------------------------------------------------------------------------------------
Three Months Ended
September 30, 2002:
- ------------------------------------------------------------------------------------------------------
Operating Revenues
- External $ 257,189 $ - $ 1,576 $ - $ - $ 258,765
- ------------------------------------------------------------------------------------------------------
Operating Revenues
- Intersegment 54 - 5,622 840 (6,516) -
- ------------------------------------------------------------------------------------------------------
Income (Loss) Before
Income Taxes 42,954 - (9,428) 852 (2,352) 32,026
- ------------------------------------------------------------------------------------------------------
Net Income (Loss) 26,562 - (2,828) 518 (1,433) 22,819
- ------------------------------------------------------------------------------------------------------
Nine Months Ended
September 30, 2003:
- ------------------------------------------------------------------------------------------------------
Operating Revenues
- External $ 647,973 $ 34,265 $ 6,434 $ - $ - $ 688,672
- ------------------------------------------------------------------------------------------------------
Operating Revenues
- Intersegment 312 - 11,198 - (11,510) -
- ------------------------------------------------------------------------------------------------------
Income (Loss) Before
Income Taxes and
Cumulative Effect of
Accounting Change 62,462 238 (19,764) (277) (10,406) 32,253
- ------------------------------------------------------------------------------------------------------
Net Income (Loss) 102,971 135 (12,141) (163) (6,265) 84,537
- ------------------------------------------------------------------------------------------------------
Nine Months Ended
September 30, 2002:
- ------------------------------------------------------------------------------------------------------
Operating Revenues
- External $ 654,216 $ - $ 4,367 $ - $ - $ 658,583
- ------------------------------------------------------------------------------------------------------
Operating Revenues
- Intersegment 385 - 12,578 2,520 (15,483) -
- ------------------------------------------------------------------------------------------------------
Income (Loss) Before
Income Taxes 69,466 - (22,184) 1,750 (6,978) 42,054
- ------------------------------------------------------------------------------------------------------
Net Income (Loss) 42,099 - (10,539) 1,061 (4,228) 28,393
- ------------------------------------------------------------------------------------------------------
Balance Sheet
- -------------
Total Assets,
September 30, 2003 $2,675,526 $ 294,044 $ 149,029 $ 45,526 $ (131,321) $3,032,804
Total Assets,
December 31, 2002 2,613,590 - 151,468 37,839 (112,163) 2,690,734
- ------------------------------------------------------------------------------------------------------
NOTE 8. MILLENNIUM
- -------------------
ENERGY AND TECHNOLOGY INVESTMENTS
We refer to Global Solar Energy, Inc. (Global Solar), Infinite Power
Solutions, Inc. (IPS), MicroSat Systems, Inc. (MicroSat) and ITN Energy
Systems, Inc. (ITN) as our Energy and Technology Investments. As described
below, as of July 3, 2003 Millennium owns no interest in ITN.
- Global Solar - Millennium funded $7.9 million to Global Solar in the
first nine months of 2003 and $0.4 million in October 2003. Millennium's
unfunded commitment to Global Solar is $1.5 million of a $5 million line of
credit committed in May 2003. In the third quarter, Millennium exchanged its
9% interest in ITN and other consideration for additional shares of Global
Solar. In October 2003, Millennium converted a $7 million loan, plus interest
to equity in Global Solar. Millennium's interest in Global
20
Solar is now 99%. As sole funder, Millennium recognizes 100% of Global
Solar's losses. Global Solar has a $0.5 million research and development
funding commitment to ITN in 2004.
- IPS - Millennium funded $1.5 million of equity and $0.5 million of debt
to IPS in the first nine months of 2003. Dow Corning Enterprises, Inc. funded
$1.5 million of equity contributions and $0.5 million of debt to IPS in the
first nine months of 2003. Millennium owns approximately 72% of IPS. In 2003,
Millennium has recorded its ratable share of IPS' losses. IPS has a $0.5
million annual research and development funding commitment to ITN through
2004.
- MicroSat - Millennium owns 35% of MicroSat. As sole funder, Millennium
continues to recognize 100% of MicroSat's losses.
- ITN - During the third quarter of 2003, Millennium exchanged its 9%
interest in ITN and other consideration for additional shares of Global Solar
which decreased Millennium's ownership in ITN to zero.
Millennium has a $2 million remaining commitment to its Energy Technology
Investments. Additional commitments may be made. A significant portion of
this funding is for manufacturing costs, administrative, research and
development costs primarily at Global Solar. Funding for administrative,
research and development costs are expensed as amounts are spent.
OTHER MILLENNIUM INVESTMENTS AND COMMITMENTS
Millennium has a $15 million capital commitment, excluding fees, to
Haddington Energy Partners II LP (Haddington), a limited partnership which
funds energy-related investments. Millennium has invested $8.1 million of
this commitment, $2 million of which was funded in 2003. The remaining $6.9
million is expected to be funded within the next three years. A member of the
UniSource Energy Board of Directors has an investment in the limited
partnership and is also a managing director of the general partner of the
limited partnership.
Millennium has a $5 million commitment, excluding fees, to a venture
capital fund that focuses on information technology, microelectronics and
biotechnology, primarily within the southwestern U.S. At September 30, 2003,
Millennium has funded approximately $1.2 million of this commitment.
Millennium expects to fund the remaining $3.8 million by the end of 2007. A
member of the UniSource Energy Board of Directors is a general partner of the
company that manages the fund.
During 2003, Millennium contributed $1.2 million to TruePricing, Inc.
(TruePricing) and began accounting for TruePricing under the consolidation
method. Millennium and TEP collectively now own approximately 57% of the
outstanding shares of TruePricing. Prior to this investment, Millennium
accounted for TruePricing under the equity method. Millennium, as sole
funder, recognizes 100% of TruePricing's losses.
During 2003, Millennium contributed approximately $2.1 million to
POWERTRUSION International, Inc. (Powertrusion), most of which was contributed
in the third quarter. This investment brings Millennium's share of ownership
in Powertrusion to almost 77%. Millennium accounts for Powertrusion under the
consolidation method.
NATIONS ENERGY CONTINGENCY
In September 2001, Nations Energy Corporation (Nations Energy) sold its
26% equity interest in a power project located in Curacao, Netherlands
Antilles to Mirant Curacao Investments, Ltd. (Mirant Curacao) a subsidiary of
Mirant Corporation (Mirant). Nations Energy received $5 million in cash and
an $11 million note receivable from Mirant Curacao. The note was recorded at
its net present value of $8 million using an 8% discount rate, the discount
being recognized as interest income over the five-year life of the note. As
of September 30, 2003, Nations Energy's receivable from Mirant Curacao is
approximately $9.7 million. The note is included in Investments and Other
Property - Other on UniSource Energy's balance sheet. Payments on the note
receivable are expected as follows: $2 million in July 2004, $4 million in
July 2005, and $5 million in July 2006.
The note is guaranteed by Mirant Americas, Inc., a subsidiary of Mirant.
On July 14, 2003, Mirant, Mirant Americas, Inc. and various other Mirant
companies filed for Chapter 11 bankruptcy protection. Mirant Curacao was not
included in the Chapter 11 filings. Based on a review of the projected cash
flows for the power project, it
21
appears Mirant Curacao will have sufficient future cash flows to pay the note
receivable and any applicable interest. However, we cannot predict the
ultimate outcome that Mirant's bankruptcy will have on the collectibility of
the note from Mirant Curacao. Nations Energy will continue to evaluate the
collectibility of the receivable, but currently expects to collect the note in
its entirety and has not recorded any reserve for this note.
NOTE 9. COMMITMENTS AND CONTINGENCIES
- --------------------------------------
TEP CONTINGENCIES
Springerville Generating Station Complaint
Environmental activist groups have expressed concerns regarding the
construction of any new units at the Springerville Generating Station. In
January 2003, environmental activist groups appealed an ACC Order affirming
the ACC's approval of the expansion at the Springerville Generating Station to
the Superior Court of the State of Arizona. On October 22, 2003, the Superior
Court affirmed the ACC's issuance of the Certificate of Environmental
Compatibility for Springerville. The Court granted TEP and the ACC's motion
for summary judgment in all respects and denied the motion for summary
judgment from the environmental activist groups. The environmental activist
groups have the right to appeal the Superior Court decision to the Court of
Appeals within 30 days after the date the judgment is entered. It is not
known at this time whether the environmental activist groups will choose to
file such an appeal.
Additionally, in November 2001, the Grand Canyon Trust (GCT), an
environmental activist group, filed a complaint in U.S. District Court, for
the District of Arizona, against TEP for alleged violations of the Clean Air
Act at the Springerville Generating Station. The complaint alleged that more
stringent emission standards should apply to Units 1 and 2 and that new
permits and the installation of additional facilities meeting Best Available
Control Technology standards are required for the continued operation of Units
1 and 2 in accordance with applicable law. In 2002, the U.S. District Court
granted TEP's motion for summary judgment on one of the primary issues in the
case: whether TEP commenced construction within 18 months and/or by March 19,
1979, after the original 1977 air permit covering Units 1 and 2 was issued.
The Court found that TEP had commenced construction of the Springerville
Generating Station in the time periods required by the original permits.
There were two remaining allegations: that (a) TEP discontinued construction
for a period of 18 months or longer and did not complete construction in a
reasonable period of time, and (b) TEP did not commence construction, for
purposes of New Source Performance Standard applicability, by September 18,
1978. On March 4, 2003, the U.S. District Court determined that the GCT had
not commenced the case on a timely basis and dismissed the case. The GCT has
appealed this decision to the U.S. Court of Appeals. TEP believes this claim
is without merit and intends to vigorously contest it.
Litigation and Claims Related to San Juan Generating Station
On May 16, 2002, the GCT and the Sierra Club filed a citizen lawsuit
under the Clean Air Act in federal district court in New Mexico against Public
Service Company of New Mexico (PNM), as operator of San Juan. TEP owns 50% of
San Juan Units 1 and 2, which equates to 19.8% of the total San Juan Station.
The lawsuit alleges two violations of the Clean Air Act and related
regulations and permits. One of the two claims, concerning the initial
permitting of San Juan, was dismissed by the court in August. The remaining
claim is scheduled to go to trial in November 2003 and contends that PNM
violated its present Title V operating permit by exceeding the 20% opacity
standard on numerous occasions between 1998 and 2002; opacity is a means to
monitor the particulate matter contained in an emission.
In September 2003, the New Mexico Environment Department (NMED) notified
PNM, operator of San Juan, of alleged excess emissions and opacity in
violation of the permits at San Juan. The NMED issued a draft compliance
order assessing unspecified civil penalties. PNM was invited and will enter
into discussions with the NMED concerning the alleged excess emissions and
opacity violations in the draft compliance order.
Based on the information available to date, we do not believe resolution
of these matters will be material to TEP.
22
Postretirement and Pension Benefit Costs at Various Generating Stations
The coal suppliers to Springerville and each of TEP's remote generating
stations have submitted demands for payment by TEP of postretirement and
pension benefit costs for these coal suppliers' employees under the coal
supply agreements with TEP. Peabody Western Coal Company (Peabody), the coal
supplier to the Navajo Generating Station, has filed a lawsuit against the
participants at Navajo, including TEP, for retiree postretirement benefit
costs. TEP owns 7.5% of the Navajo Generating Station. This claim is
scheduled to go to trial in June 2004. To the extent that amounts become
known and payment probable, TEP will record a liability for additional
postretirement and pension benefit costs at the Springerville, Navajo, and San
Juan Generating Stations. TEP does not expect any settlement to be material
to TEP.
The claim for postretirement at Four Corners was settled as part of the
coal contract extension, which is discussed more fully below. TEP paid $0.3
million for postretirement benefits in settlement in September 2003.
Environmental Reclamation at Remote Generating Stations
TEP pays on-going reclamation costs at each of its remote generating
stations, and it is probable that TEP will have to pay a portion of final
reclamation costs at the coal mines which supply the remote generating
stations. In June 2003, TEP received an estimate of the reclamation liability
at the coal mine that supplies San Juan from PNM, operator of San Juan, in
which post-term reclamation activities are assumed to occur over a 13-year
period beginning in 2028. The expected aggregate undiscounted reclamation
liability totals $163 million of which TEP's portion of the liability based on
its ownership of San Juan totals $32 million. The present value, at December
31, 2017, of TEP's liability for post-term reclamation at a 10% credit-
adjusted risk free rate approximates $7 million and will be recognized through
2017, the remaining life of the coal supply agreement. Amounts recorded for
post-term reclamation are subject to various assumptions and determinations,
such as estimating the costs of reclamation, estimating when final reclamation
will occur, and the credit-adjusted risk-free interest rate to be used to
discount future liabilities. Changes that may arise over time with regard to
these assumptions and determinations will change amounts recorded in the
future as expense for post-term reclamation. TEP does not believe that
recognition of its post-term reclamation obligation at San Juan will be
material to TEP in any single year since recognition occurs over the remaining
14 year life of its coal supply agreement.
Although a cost is probable at TEP's other remote generating stations, it
is not possible at this time to reasonably estimate the amount of any
obligation for final reclamation because remediation alternatives have not yet
advanced to the stage where a reasonable estimate of any cost can be made. As
amounts become known, TEP will recognize a liability for final reclamation
over the remaining lives of its coal supply agreements.
RESOLUTION OF TEP CONTINGENCIES
Litigation Related to San Juan Coal Company
In August 2003, San Juan Coal Company, the coal supplier to San Juan,
entered into a settlement agreement with Dugan Production Corp. (Dugan). The
San Juan Coal Company, through leases with the federal government and the
State of New Mexico, owns coal interests with respect to an underground mine.
Dugan, through leases with the federal government, the State of New Mexico and
certain private parties, owns certain oil and gas interests in portions of the
land used for the underground mine. Dugan alleged that San Juan Coal
Company's underground coal mining operations have or will interfere with
Dugan's gas production and will reduce the amount of natural gas that Dugan
would otherwise be entitled to recover. The settlement agreement provides
that San Juan Coal Company will compensate Dugan for any remaining gas
production from a well when San Juan Coal Company determines that mining
activity is close enough to warrant shutting down a well. Dugan agreed not to
drill any additional wells. This settlement is not expected to be material to
TEP.
TEP COMMITMENTS
Power Purchase Commitments
In 2003, the ACC issued an order (Track B) that defines the process, for
the period 2003 through 2006, by which TEP will be required to obtain its
capacity and energy requirements beyond what is supplied by its existing
resources, which represents approximately 0.5% of its retail load in the first
year and increases over the period. This order further requires TEP to bid
out short-term energy purchases that it estimates it will make in the 2003 to
23
2006 period; however, it does not require TEP to purchase any power that it
deems to be uneconomical, unreasonable or unreliable. As a result, TEP
entered into the following two agreements to meet TEP's 2003 bid requirements
under the Track B Order for the period 2003 through 2006: (1) PPL EnergyPlus,
LLC will supply 37 MW from June 2003 through December 2003 and 75 MW from
January 2004 through December 2006 under a unit contingent contract; and (2)
TECO Energy's Gila River Generating Station will supply 50 MW on-peak from
June through September of 2003 through 2005 under a unit contingent contract.
Fuel Purchase and Transportation Commitments
UED is facilitating the expansion of the Springerville Generating
Station. The Springerville Generating Station was originally designed for
four units. Unit 3, and if constructed Unit 4, will each consist of a 400 MW
coal-fired, base-load generating facility at the same site as Springerville
Units 1 and 2. Concurrent with the closing of the Springerville expansion
(see Note 14), TEP amended and extended the long-term coal supply contract at
Springerville Units 1 and 2 through 2020. TEP estimates its future minimum
annual payments under this contract to be $45 million through 2010, the
initial contract expiration date, and $14 million in 2011 through 2020. TEP's
coal transportation contract at Springerville runs until June 2011. TEP
estimates its future minimum annual payments under this contract to be $13
million through 2010 and $6.5 million in 2011.
In September 2003, TEP entered into agreements in principle for the
purchase and transportation of coal to Sundt Generating Station through 2006
and expects to execute the associated contracts in November 2003. The total
amount paid under these agreements depends on the number of tons of coal
purchased and transported. The coal agreements require TEP to take 0.3
million tons annually with estimated future minimum payments of $4 million in
2004 and $6 million in 2005 and 2006. The rail agreement requires TEP to
transport 0.3 million tons with estimated future minimum payments of $2
million in each of 2004 through 2006.
Also, in July 2003, the long-term coal supply contract at Four Corners,
where TEP participates in jointly-owned facilities, was extended through July
2016, pursuant to its terms. The contract to purchase coal for use at Four
Corners requires TEP to purchase minimum amounts of coal at an estimated
annual cost of $5 million for the next 12.5 years.
UED COMMITMENTS
See Note 14 for the status of the expansion project at the Springerville
Generating Station.
UES COMMITMENTS
See Note 2 for a description of UES' commitments.
MILLENNIUM COMMITMENTS
See Note 8 for a description of Millennium's commitments.
GUARANTEES AND INDEMNITIES
In the normal course of business, UniSource Energy and certain
subsidiaries, including TEP, enter into various agreements providing financial
or performance assurance to third parties on behalf of certain subsidiaries.
These agreements are entered into primarily to support or enhance the
creditworthiness otherwise attributed to a subsidiary on a stand-alone basis,
thereby facilitating the extension of sufficient credit to accomplish the
subsidiaries' intended commercial purposes. The most significant of these
guarantees are UES' guarantee of $160 million of aggregate principal amount of
senior unsecured notes issued by UNS Gas and UNS Electric to purchase the
Citizens Arizona gas and electric system assets, UniSource Energy's guarantee
of approximately $22 million in natural gas transportation and supply payments
and building lease payments for UNS Gas and UES, and Millennium's guarantee of
approximately $5 million in commodity-related payments for MEG at September
30, 2003. To the extent liabilities exist under the contracts subject to
these guarantees, such liabilities are included in UniSource Energy's
consolidated balance sheets.
In addition, UniSource Energy and its subsidiaries have indemnified the
purchasers of interests in certain investments from additional taxes due for
years prior to the sale. The terms of the indemnifications provide for no
24
limitation on potential future payments; however, we believe that we have
abided by all tax laws and paid all tax obligations. We have not made any
payments under the terms of these indemnifications to date.
We believe that the likelihood UniSource Energy, TEP, UES, or Millennium
would be required to perform or otherwise incur any significant losses
associated with any of these guarantees or indemnities is remote.
NOTE 10. TEP WHOLESALE ACCOUNTS RECEIVABLE AND ALLOWANCES
- ----------------------------------------------------------
At September 30, 2003, TEP's Allowance for Doubtful Accounts on the
balance sheet includes $11 million for uncollectible receivables related to
2000 and 2001 sales to the California Power Exchange (CPX), the California
Independent System Operator (CISO) and Enron Corp. and certain of its
affiliates (Enron). At December 31, 2002, the allowance for these receivables
was $8 million.
TEP's collection shortfall from the CPX and the CISO was approximately $9
million for sales made in 2000 and $7 million for sales made in 2001. Since
that time, the FERC has held hearings and the FERC staff has proposed various
methodologies for calculating amounts of refunds/offsets applicable to
wholesale sales made into the CISO's spot markets from October 2000 to June
2001. As of December 31, 2002, TEP had reserved $8 million, or 50%, of its
outstanding receivable based on the amount TEP believed would be collected.
Based upon a FERC order in March 2003 (as reaffirmed by the FERC on October
16, 2003), TEP estimated that it may receive approximately $6 million of its
$16 million receivable. This represents amounts owed to TEP net of TEP's
estimated refund liability. Therefore, in the first quarter of 2003, TEP
increased its reserve for sales to the CPX and the CISO by $2.2 million by
recording a reduction of wholesale revenues.
Additionally, a FERC order recommended that Enron no longer be allowed to
trade and within a few days thereafter, Enron was delisted from its stock
exchange. As a result, in the first quarter of 2003, TEP increased its
reserve for sales to Enron by $0.4 million, to 100% of its $0.8 million
recorded receivable from Enron.
There are several other outstanding legal issues, complaints and lawsuits
concerning the California energy crisis related to the FERC, wholesale power
suppliers, Southern California Edison Company, Pacific Gas and Electric
Company, the CPX and the CISO, and concerning Enron. We cannot predict the
outcome of these issues or lawsuits. We believe, however, that TEP is
adequately reserved for its transactions with the CPX, the CISO and Enron.
TEP's Accounts Receivable from Electric Wholesale Sales are included in
Trade Accounts Receivable on the balance sheet. TEP's wholesale receivables,
net of allowances, totaled $21 million at September 30, 2003 and $31 million
at December 31, 2002. Excluding the receivables from the CPX, the CISO and
Enron, as described above, substantially all of the September 30, 2003
wholesale receivable balance has been collected as of the date of this filing.
NOTE 11. UNISOURCE ENERGY EARNINGS PER SHARE (EPS)
- ---------------------------------------------------
Basic EPS is computed by dividing net income (loss) by the weighted
average number of common shares outstanding during the period. Diluted EPS
assumes that proceeds from the hypothetical exercise of stock options and
other stock-based awards are used to repurchase outstanding shares of stock at
the average fair market price during the reporting period. The numerator in
calculating both basic and diluted earnings per share for each period is net
income. The following table shows the effects of potential dilutive common
stock on the weighted average number of shares:
25
Three Months Ended Nine Months Ended
September 30, September 30,
2003 2002 2003 2002
- ------------------------------------------------------------------------------
-In Thousands-
Denominator:
Average Shares of Common Stock
Outstanding 33,838 33,692 33,799 33,654
Effect of Dilutive Securities:
Warrants - 26 - 102
Options and Stock Issuable
under Employee Benefit Plans
and the Directors' Plan 532 397 453 514
- ------------------------------------------------------------------------------
Total Shares 34,370 34,115 34,252 34,270
==============================================================================
Options to purchase 20,000 shares of common stock at $18.84 per share
were outstanding during the three months ended September 30, 2003 but were not
included in the computation of diluted EPS because the options' exercise price
was greater than the average market price of the common stock and, therefore,
the effect would be antidilutive. Similarly, 1,030,000 options at $16.56 to
$18.84 per share were excluded from the diluted EPS computation for the three
months ended September 30, 2002.
An average of 365,000 options and 357,000 options were excluded from the
computation of diluted EPS for the nine-month periods ended September 30, 2003
and 2002, respectively, as these options were antidilutive.
At September 30, 2003, UniSource Energy and TEP had no outstanding
warrants. At September 30, 2002, there were 4.6 million warrants outstanding
that were exercisable into TEP common stock at a ratio of five warrants to one
common share. These warrants expired unexercised on December 15, 2002. The
dilutive effect of these warrants was the same as it would have been if the
warrants were exercisable into UniSource Energy Common Stock.
NOTE 12. INCOME AND OTHER TAXES
- --------------------------------
INCOME TAXES
The differences between the income tax expense and the amount obtained
by multiplying pre-tax income before cumulative effect of accounting change
by the U.S. statutory federal income tax rate of 35% are as follows:
UniSource Energy
-----------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
2003 2002 2003 2002
- ------------------------------------------------------------------------------
-Thousands of Dollars-
Federal Income Tax Expense at
Statutory Rate $ 15,988 $ 11,209 $ 11,289 $ 14,719
State Income Tax Expense,
Net of Federal Deduction 2,101 1,473 1,484 1,935
Depreciation Differences
(Flow Through Basis) 1,086 1,154 3,259 3,463
Tax Credits (380) (553) (1,140) (2,472)
Reduction in Valuation
Allowance - (1,300) - (1,300)
Reduction in Deferred
Liability Due to IRS
Audit Outcomes - (1,524) - (1,524)
Foreign Losses Recognized - (1,007) - (1,007)
Other 201 (245) 295 (153)
Tax on Cumulative Effect of
Accounting Change (See Note 4) - - 44,236 -
- ------------------------------------------------------------------------------
Total Expense for Federal and State
Income Taxes $ 18,996 $ 9,207 $ 59,423 $ 13,661
==============================================================================
26
TEP
-------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
2003 2002 2003 2002
- ------------------------------------------------------------------------------
- Thousands of Dollars -
Federal Income Tax Expense at
Statutory Rate $ 18,705 $ 15,034 $ 21,862 $ 24,313
State Income Tax Expense,
Net of Federal Deduction 2,459 1,976 2,873 3,195
Depreciation Differences
(Flow Through Basis) 1,086 1,154 3,259 3,463
Tax Credits (380) (553) (1,140) (2,472)
Reduction in Valuation
Allowance - Benefit - (1,300) - (1,300)
Other 72 81 108 168
Tax on Cumulative Effect of
Accounting Change (See Note 4) - - 44,236 -
- ------------------------------------------------------------------------------
Total Expense for Federal and State
Income Taxes $ 21,942 $ 16,392 $ 71,198 $ 27,367
==============================================================================
OTHER TAXES
TEP, UNS Gas and UNS Electric act as conduits or collection agents for
excise tax (sales tax) as well as franchise fees and regulatory assessments.
They record liabilities payable to governmental agencies when they bill their
customers for these amounts. Neither the amounts billed nor payable are
reflected in the income statement.
NOTE 13. NEW ACCOUNTING PRONOUNCEMENTS
- ---------------------------------------
The FASB recently issued the following Statement of Financial Accounting
Standards (FAS) and FASB Interpretations (FIN):
- FIN 46, Consolidation of Variable Interest Entities, issued January
2003, expands upon existing guidance that addresses when a company should
include in its financial statements the assets and liabilities of another
entity. The primary objectives of FIN 46 are to provide guidance on the
identification of entities for which control is achieved through means other
than through voting rights (variable interest entities) and to determine when
and which business enterprises should consolidate the variable interest entity
(primary beneficiary). FIN 46 requires that both the primary beneficiary and
all other enterprises with a significant variable interest make additional
disclosures. The transitional disclosure requirements of FIN 46 are effective
immediately. The effective date of the consolidation requirements of FIN 46
depends on the date the variable interest entity was created. FIN 46 is
effective for all variable interest entities created after January 31, 2003.
For variable interest entities created before February 1, 2003, the provisions
of FIN 46 were to be applied to a variable interest entity for interim
reporting periods beginning after June 30, 2003. FIN 46 may now be applied to
financial periods beginning after December 15, 2003. Regardless of the
implementation date, the adoption of FIN 46 did not and is not expected to
have a significant impact on our financial statements.
- FAS 149, Amendment of Statement 133 on Derivative Instruments and
Hedging Activities, was issued by the FASB in April 2003. FAS 149 amends and
clarifies accounting for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities under FAS
133. FAS 149 is effective for contracts entered into or modified after June
30, 2003, except as stated below, and for hedging relationships designated
after June 30, 2003. The guidance is to be applied prospectively. The
provisions of FAS 149 that relate to FAS 133 Implementation Issues that have
been in effect for fiscal quarters that began prior to June 15, 2003 are to be
applied in accordance with their respective effective dates. The adoption of
FAS 149 did not have a significant impact on our financial statements.
- FAS 150, Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity, was issued by the FASB in May
2003. FAS 150 improves the accounting for certain financial instruments that,
under previous guidance, issuers could account for as equity. FAS 150's
guidance requires that those instruments be classified as liabilities. FAS
150 is effective immediately for financial instruments entered into or
modified after May 31, 2003 and to all other financial instruments that exist
beginning July 1, 2003. Although we currently have no financial instruments
recorded in
27
equity that are required to be reported as liabilities, should we enter into
any such financial instruments, we will comply with the requirements of FAS
150.
Additionally, the Emerging Issues Task Force (EITF) published Issue No.
01-08, Determining Whether An Arrangement Contains a Lease (EITF 01-08), in
May 2003. EITF 01-08 discusses how to determine whether an arrangement
contains a lease and states that the evaluation of whether an arrangement
conveys the right to use property, plant, or equipment should be based on the
substance of an arrangement and that the property that is the subject of a
lease must be specified (explicitly or implicitly) either at inception of the
arrangement or at the beginning of the lease term. EITF 01-08 is effective
for arrangements entered into or modified after July 1, 2003. Since July 1,
2003, we have not entered into any new arrangements, or modified any
arrangements that would fall under this EITF; however, should we enter into
any such arrangements, we will comply with the requirements of EITF 01-08.
NOTE 14. SUBSEQUENT EVENTS
- ---------------------------
Revolving Credit Facility
In October 2003, TEP's revolving credit lenders agreed to extend the
Revolving Credit Facility under the same terms and conditions to November 11,
2004.
Springerville Expansion
On October 21, 2003 (the Closing Date), UED, TEP, Tri-State Generation
and Transmission Association, Inc. (Tri-State) and Salt River Project
Agricultural Improvement and Power District (SRP) entered into an Amended and
Restated Joint Development Agreement (JDA), which provides for the development
of two 400 MW coal-fired units at TEP's existing Springerville Generating
Station by parties other than TEP.
On the Closing Date, TEP transferred the right to construct Unit 3,
together with associated rights, to Tri-State. Tri-State completed financing
of Unit 3 on that date and immediately began construction. Once the unit is
completed, Tri-State will lease 100% of Unit 3 through a 34-year leveraged
lease agreement with GE Structured Finance and will take 300 MW of the 400 MW
capacity.
Under the JDA, SRP will purchase 100 MW of capacity from Unit 3 under a
30-year power purchase agreement with Tri-State and will have the right to
construct and own Unit 4 at a later date. If SRP decides to construct Unit 4,
TEP and Tri-State would be required to find a replacement purchaser for SRP's
100 MW Unit 3 power purchase obligation. If TEP and Tri-State are unable to
find a replacement purchaser, TEP would then purchase 100 MW of output from
Unit 4, beginning with the commercial operation of Unit 4.
TEP executed contracts to provide operating, maintenance and other
services to Units 3 and 4. TEP also agreed to purchase up to 100 MW of Tri-
State system capacity for no more than five years from the time Unit 3 begins
commercial operation. TEP will benefit from approximately $90 million in
upgraded emissions control equipment for Units 1 and 2 and other facilities at
the Springerville Generating Station that will be paid for by the Unit 3
project. Due to the transfer of Unit 3 rights to Tri-State, in November 2003
TEP deposited $17 million with TEP's Second Mortgage Trustee.
At September 30, 2003, capitalized project development costs on UED's
balance sheet amounted to approximately $28 million. On the Closing Date, UED
received reimbursement of all project development costs (including those
incurred after September 30) which it incurred in connection with Units 3 and
4 of approximately $30 million, plus a development fee (including accrued
interest on development funds advanced) of $11 million. The development fee
will be recognized as income in the fourth quarter of 2003. On October 24,
2003, UniSource Energy repaid its $35 million short-term bridge loan with the
proceeds.
NOTE 15. REVIEW BY INDEPENDENT ACCOUNTANTS
- -------------------------------------------
With respect to the unaudited condensed consolidated financial
information of UniSource Energy and TEP for the three-month and nine-month
periods ended September 30, 2003 and 2002, PricewaterhouseCoopers LLP reported
that they have applied limited procedures in accordance with professional
standards for a review of such
28
information. However, their separate report dated November 5, 2003 appearing
herein states that they did not audit and they do not express an opinion on
that unaudited condensed consolidated financial information. Accordingly, the
degree of reliance on their report on such information should be restricted in
light of the limited nature of the review procedures applied.
PricewaterhouseCoopers LLP is not subject to the liability provisions of
Section 11 of the Securities Act of 1933 (the Act) for their report on the
unaudited condensed consolidated financial information because that report is
not a "report" or a "part" of a registration statement prepared or certified
by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the
Act.
29
ITEM 2. - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
- -------------------------------------------------------------------------------
OVERVIEW OF CONSOLIDATED BUSINESS
- ---------------------------------
UniSource Energy Corporation (UniSource Energy) is a holding company
that owns substantially all of the outstanding common stock of Tucson
Electric Power Company (TEP), and all of the outstanding common stock of
UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc.
(Millennium), and UniSource Energy Development Company (UED).
On August 11, 2003, UniSource Energy completed the purchase of the
Arizona gas and electric system assets from Citizens Communications Company
(Citizens) for a total of $224 million, comprised of the base purchase
price plus other operating capital adjustments. UniSource Energy formed
two new operating companies called UNS Electric, Inc. (UNS Electric) and
UNS Gas, Inc. (UNS Gas) to acquire these assets, as well as UES, an
intermediate holding company that holds the common stock of UNS Electric
and UNS Gas.
TEP, an electric utility, has provided electric service to the
community of Tucson, Arizona, for over 100 years. UES, through its two
operating subsidiaries, provides gas and electric service to 30 communities
in northern and southern Arizona. Millennium invests in unregulated
businesses, including a developer of thin-film batteries and a developer
and manufacturer of thin-film photovoltaic cells. UED engages in
developing generating resources and other project development activities,
including facilitating the expansion of the Springerville Generating
Station. We conduct our business in these four primary business segments -
TEP's Electric Utility Segment, UES' Gas and Electric Utility Segment, the
Millennium Businesses Segment, and the UED Segment.
Management's Discussion and Analysis explains the results of
operations, the general financial condition, and the outlook for UniSource
Energy and its four primary business segments and includes the following:
- operating results during the third quarter and first nine months of
2003 compared with the same periods in 2002,
- factors which affect our results and outlook,
- our outlook and strategy, and
- our liquidity, capital needs, capital resources, and contractual
obligations.
TEP is the principal operating subsidiary of UniSource Energy and, at
September 30, 2003, represented approximately 86% of its assets. The
seasonal nature of TEP's business causes operating results to vary
significantly from quarter to quarter. UniSource Energy's results for the
three months and nine months ended September 30, 2003 include 51 days of
operations of UES. Due to the sale of both gas and electricity, UES'
consolidated operating results are expected to be less seasonal than TEP's.
Income and losses from Millennium's unregulated businesses have had a
significant impact on earnings reported by UniSource Energy for the three
months and nine months ended September 30, 2003 and 2002. UED's
unregulated business segment, which was established in February 2001, may
have a significant impact on consolidated net income and cash flows in the
fourth quarter of 2003 since the financial closing of Springerville Unit 3
occurred on October 21, 2003.
Management's Discussion and Analysis should be read in conjunction
with UniSource Energy and TEP's 2002 Form 10-K and with the Condensed
Consolidated Financial Statements, beginning on page 2, which present the
results of operations for the three months and nine months ended September
30, 2003 and 2002. Management's Discussion and Analysis explains the
differences between periods for specific line items of the Condensed
Consolidated Financial Statements.
References in this report to "we" and "our" are to UniSource Energy
and its subsidiaries, collectively.
UNISOURCE ENERGY CONSOLIDATED
RESULTS OF OPERATIONS
- ---------------------
Three Months Ended September 30, 2003 Compared with the Three Months
Ended September 30, 2002
UniSource Energy recorded net income of $27 million, or $0.79 per
average share of Common Stock, in the third quarter of 2003 compared with
net income of $23 million, or $0.68 per average share of Common Stock last
year. The following factors contributed to the change in net income:
30
- A $39 million increase in revenues from Electric Retail Sales
resulting from warmer summer weather, a 2.2% increase in TEP's average
number of retail customers and $24 million of retail electric revenues at
UES.
- $10 million of Gas Revenues at UES.
- A $9 million decline in TEP's revenues from Electric Wholesale Sales
primarily due to higher retail kWh demand and unfavorable wholesale
opportunities for its gas generation resources.
- A $6 million increase in Fuel expense resulting from higher natural
gas prices and an adjustment to accrued fuel expense in the third quarter
of 2002.
- Purchased Energy expense, which includes Purchased Power expense and
purchased gas expense, was higher by $24 million resulting from $24 million
of Purchased Energy expense at UES.
- A $2 million increase in Other Operations and Maintenance expense
(O&M) due primarily to $4 million of O&M at UES, which was partially offset
by lower incentive compensation.
- Interest expense increased $4 million related to higher interest rates
under TEP's Credit Agreement, interest expense at UES, and interest expense
related to UniSource Energy's borrowing under a bridge loan for the
Citizens Acquisition.
- Third quarter 2002 results included a coal contract termination fee of
$11 million. In July of 2002, TEP terminated a coal contract related to
the Sundt Generating Station, eliminating annual take-or-pay payments of $3
million.
Nine Months Ended September 30, 2003 Compared with the Nine Months
Ended September 30, 2002
UniSource Energy recorded Net Income of $85 million, or $2.50 per
average share of Common Stock, in the first nine months of 2003, including
an after-tax gain of $67 million, or $2.00 per average share of Common
Stock, for the Cumulative Effect of Accounting Change from the adoption of
Statement of Financial Accounting Standards No. 143, Accounting for Asset
Retirement Obligations (FAS 143). Net Income Before Cumulative Effect of
Accounting Change was $17 million, or $0.50 per average share of Common
Stock. This compares with net income of $28 million, or $0.84 per average
share of Common Stock, in the first nine months of 2002. The following
factors contributed to the change in Income Before Cumulative Effect of
Accounting Change:
- A $36 million increase in revenues from Electric Retail Sales
resulting from warm weather in the third quarter of 2003 compared with
2002, a 2.3% increase in TEP's average number of retail customers and $24
million of retail electric revenues at UES. The benefits of warm third
quarter weather were partially offset by mild weather during the first six
months of 2003.
- $10 million of Gas Revenues at UES.
- An $18 million decline in TEP's revenues from Electric Wholesale Sales
primarily attributable to unplanned outages at several of TEP's coal-fired
generating facilities during the first half of 2003, unfavorable wholesale
opportunities for its gas generation resources and record retail kWh demand
in the third quarter. In addition, a $3 million increase in TEP's reserve
against receivables from California wholesale sales and from Enron Corp.
(Enron) was recorded in the first quarter of 2003.
- Fuel expense decreased by $2 million in the first nine months of 2003,
due primarily to lower fuel consumption at TEP's generating facilities
during planned and unplanned outages at TEP's generating facilities during
the first half of 2003.
- Purchased Energy expense, which includes Purchased Power expense and
purchased gas expense, was higher by $34 million, resulting from $24
million of Purchased Energy expense at UES, replacement power costs in the
first half of 2003 related to planned and unplanned outages at TEP's
generating facilities, and increased reliance on wholesale electric
purchases in lieu of running more expensive gas-fired generation.
- Other O&M was higher by $9 million. Increased costs resulting from
planned and unplanned outages at TEP's generating facilities and $4 million
of O&M at UES were partially offset by lower incentive compensation.
31
- Higher interest expense of $8 million related to higher interest rates
under TEP's Credit Agreement, interest expense at UES, and interest
expense related to UniSource Energy's borrowing under a bridge loan for the
Citizens Acquisition.
- 2002 results included a coal contract termination fee of $11 million.
TEP terminated a coal contract related to the Sundt Generating Station,
eliminating annual take-or-pay payments of $3 million.
CONTRIBUTION BY BUSINESS SEGMENT
- --------------------------------
The table below shows the contributions to our consolidated after-tax
earnings by our four business segments, as well as parent company expenses,
for the third quarter and first nine months of 2003 and 2002:
Three Months Ended Nine Months Ended
September 30, September 30,
2003 2002 2003 2002
- --------------------------------------------------------------------------------
Business Segment - Millions of Dollars -
TEP $31.5 $26.6 $103.0 (1) $42.1
UES 0.1 - 0.1 -
Millennium (2.7) (2.8) (12.1) (10.5)
UED - 0.5 (0.2) 1.0
UniSource Energy Standalone(2) (2.2) (1.5) (6.3) (4.2)
- --------------------------------------------------------------------------------
Consolidated Net Income $26.7 $22.8 $ 84.5 $28.4
================================================================================
(1) Includes an after-tax gain of $67.5 million for the Cumulative
Effect of Accounting Change from the adoption of FAS 143 in the
first quarter of 2003.
(2) Primarily represents interest expense (net of tax) on the note
payable from UniSource Energy to TEP, as well as costs in 2003
associated with the Citizens acquisition.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
UNISOURCE ENERGY CONSOLIDATED CASH FLOWS
Nine months ended September 30, 2003 September 30, 2002
-------------------------------------------------------------------------
- Millions of Dollars -
Cash Provided by (Used in):
Operating Activities $133 $136
Investing Activities (319) (240)
Financing Activities 157 (31)
-------------------------------------------------------------------------
Net Decrease in Cash $(29) $(135)
=========================================================================
UniSource Energy's primary source of liquidity is its cash flow from
operations, which is provided primarily from retail and wholesale energy
sales at TEP, net of the related payments for Fuel and Purchased Power.
Due to the seasonal nature of TEP's business, cash from operations is
lowest in the first quarter and highest in the third quarter due to TEP's
summer peaking load. We primarily use our available cash to finance
capital expenditures at TEP and UES, to make investments in our energy
technology affiliates, to pay dividends to shareholders, and to reduce
leverage at TEP by repaying high coupon debt and investing in lease debt.
In 2003, cash was used to help fund the Citizens Acquisition.
Investing Activities
Net cash used for Investing Activities was $79 million higher in the
first nine months of 2003, compared with the same period in 2002. In
August 2003, we spent $224 million to acquire the Citizens' Arizona gas and
electric utility assets. During the first nine months of 2003,
construction expenditures were $20 million higher. Approximately $10
million of this increase was spent on completing a new one mile 500-kV
transmission line and related substations to enhance TEP's distribution
system link to the regional high voltage transmission system. In the first
nine months of 2003, TEP received $12 million in principal payments on its
investments in outstanding Springerville lease debt. In contrast, in the
first nine months of 2002, TEP made net investments in Springerville lease
debt of $135 million. Investments and loans to
32
Millennium's equity method investments were approximately $2 million in the
first nine months of 2003, compared with $23 million in 2002.
Financing Activities
Net cash flows from Financing Activities totaled $157 million in the
first nine months of 2003, compared with a $31 million use of cash in the
same period in 2002. In August 2003, UES issued $160 million in notes to
finance the acquisition of the Citizens Arizona gas and electric utility
assets. UniSource Energy also obtained $35 million in short-term bridge
financing in August 2003 to assist in the financing of the acquisition.
Net proceeds from borrowings under TEP's revolving credit facility were $20
million during 2003. In the first nine months of 2003, UniSource Energy
paid approximately $15 million in dividends to its common shareholders and
TEP paid $42 million on its capital lease obligations. In 2002, UniSource
Energy paid approximately $13 million in dividends to its common
shareholders and TEP paid $20 million on its capital lease obligations.
TEP's capital lease payments were higher in 2003 due to a $28 million
scheduled principal payment on the Springerville Unit 1 lease debt in the
first quarter. In October 2003, we paid off the $35 million short-term
bridge financing that was obtained in August 2003.
Our consolidated cash and cash equivalents decreased to $63 million at
September 30, 2003 from $93 million at September 30, 2002. We invest cash
balances in high-grade money market securities with an emphasis on
preserving the principal amounts invested.
In the event that we experience lower cash from operations in 2003, we
may adjust our discretionary uses of cash accordingly. We believe,
however, that we will continue to have sufficient cash flow to cover our
capital needs, as well as required debt payments and dividends to
shareholders.
UNISOURCE ENERGY - PARENT COMPANY
UniSource Energy's primary source of cash is dividends from TEP.
Dividends from TEP are limited to 65% of TEP's net income and accordingly
are dependent on the level and seasonal pattern of TEP earnings. In the
first nine months of 2003, the TEP Board of Directors declared and paid
dividends of $59 million to UniSource Energy. TEP anticipates paying
additional dividends to UniSource in the fourth quarter of 2003.
Our primary uses of cash are to pay quarterly dividends to
shareholders, to pay income taxes, to fund investments in Millennium's
unregulated businesses that vary from quarter to quarter, and to make
interest payments on our promissory note to TEP. Accrued interest on the
promissory note of approximately $19.6 million is payable every two years;
the next payment date is January 3, 2004. Under our tax allocation
procedures our subsidiaries make income tax payments to UniSource Energy
and we make payments on behalf of the consolidated group.
In August 2003, UniSource Energy used approximately $50 million of its
available cash and borrowed $35 million from a financial institution in the
form of short-term bridge financing debt to help finance the purchase of
Citizens Arizona electric and gas utility assets. The funds were used as an
equity contribution in the capitalization of UES. On October 24, 2003, as
required by the agreement, UniSource Energy repaid the $35 million bridge
loan upon the financial close of the Springerville Unit 3 project.
As of November 6, 2003, cash and cash equivalents available to
UniSource Energy was approximately $30 million. To address the seasonal
differences between its cash sources and uses, UniSource Energy may
establish a bank revolver. The revolver may also be used to help fund the
working capital needs of its new subsidiaries UES, UNS Gas and UNS Electric.
In addition, as part of our ACC Holding Company Order, we must invest
at least 30% of any proceeds of equity issuances in TEP until TEP's equity
reaches 37.5% of total capital (excluding capital leases).
GUARANTEES AND INDEMNITIES
In the normal course of business, UniSource Energy and certain
subsidiaries, including TEP, enter into various agreements providing
financial or performance assurance to third parties on behalf of certain
subsidiaries. These agreements are entered into primarily to support or
enhance the creditworthiness otherwise attributed to a subsidiary on a
stand-alone basis, thereby facilitating the extension of sufficient credit
to accomplish the subsidiaries' intended commercial purposes. The most
significant of these guarantees are UES' guarantee of $160 million of
aggregate principal amount of senior unsecured notes issued by UNS Gas and
UNS Electric to purchase the Citizens Arizona gas and electric system
assets, UniSource Energy's guarantee of approximately $22 million in
natural gas transportation and supply payments and
33
building lease payments for UNS Gas and UES, and Millennium's guarantee of
approximately $5 million in commodity-related payments for MEG at September
30, 2003. To the extent liabilities exist under the contracts subject to
these guarantees, such liabilities are included in the consolidated balance
sheets.
In addition, UniSource Energy and its subsidiaries have indemnified
the purchasers of interests in certain investments from additional taxes
due for years prior to the sale. The terms of the indemnifications provide
for no limitation on potential future payments; however, we believe that we
have abided by all tax laws and paid all tax obligations. We have not made
any payments under the terms of these indemnifications to date.
We believe that the likelihood UniSource Energy or TEP would be
required to perform or otherwise incur any significant losses associated
with any of these guarantees or indemnities is remote.
DIVIDENDS ON COMMON STOCK
UniSource Energy began paying dividends to common shareholders in
March 2000. In the first nine months of 2003, common dividends paid
totaled $15 million.
Declaration Record Payable Total Per Share
Date Date Date Dividend Amount
2/7/2003 2/21/2003 3/7/2003 $5 million $0.15
5/9/2003 5/23/2003 6/10/2003 $5 million $0.15
9/4/2003 9/18/2003 9/30/2003 $5 million $0.15
UniSource Energy's Board of Directors will review our dividend level
on a continuing basis, taking into consideration a number of factors
including our results of operations and financial condition, general
economic and competitive conditions and the cash flow from our subsidiary
companies, TEP, UES, Millennium and UED.
TUCSON ELECTRIC POWER COMPANY
RESULTS OF OPERATIONS
- ---------------------
The financial condition and results of operations of TEP are currently
the principal factors affecting the financial condition and results of
operations of UniSource Energy.
TEP kWh Sales and Revenues
Customer growth, weather and other consumption factors affect retail
sales of electricity. Electric wholesale revenues are affected by market
prices in the wholesale energy market, availability of TEP generating
resources, the price of fuel, and the level of wholesale forward contract
activity.
TEP's electric wholesale sales consist primarily of three types of sales:
(1) Sales under long-term contracts for periods of more than one year.
TEP currently has long-term contracts with three entities to sell
firm capacity and energy: Salt River Project Agricultural
Improvement and Power District (SRP), the Navajo Tribal Utility
Authority and the Tohono O'odham Utility Authority. TEP also has
a multi-year interruptible contract with Phelps Dodge Energy
Services, which requires a fixed contract demand of 60 MW at all
times except during TEP's peak customer energy demand period, from
July through September of each year. Under the contract, TEP can
interrupt delivery of power if TEP experiences significant loss of
any electric generating resources.
(2) Other sales include forward sales and short-term sales. Under
forward contracts, TEP commits to sell a specified amount of
capacity or energy at a specified price over a given period of time,
typically for one-month, three-month or one-year periods. Under
short-term sales, TEP sells energy in the daily or hourly markets at
fluctuating spot market prices and other non-firm energy sales.
(3) Sales of transmission service.
34
TEP kWh Sales Delivered and Corresponding Revenues for the Quarter Ended
September 30, 2003 Compared with the Quarter Ended September 30, 2002:
Sales Operating Revenue
- -------------------------------------------------------------------------------------------------------
Three Months Ended September 30, Percent Percent
2003 2002 Change 2003 2002 Change
- -------------------------------------------------------------------------------------------------------
- Millions of kWh - - Millions of Dollars -
Electric Retail Sales:
Residential 1,216 1,105 10% $ 114.6 $ 104.2 10%
Commercial 523 486 8% 55.2 51.3 8%
Industrial 647 644 - 47.4 46.8 1%
Mining 186 171 9% 7.4 6.9 7%
Public Authorities 71 70 1% 5.1 5.2 (2%)
- -------------------------------------------------------------------------------------------------------
Total Electric Retail Sales 2,643 2,476 7% 229.7 214.4 7%
- -------------------------------------------------------------------------------------------------------
Electric Wholesale Sales Delivered:
Long-term Contracts 295 213 38% 13.7 12.1 13%
Other Sales 344 811 (58%) 15.6 27.6 (43%)
Transmission - - - 3.0 1.4 NM
- -------------------------------------------------------------------------------------------------------
Total Electric Wholesale Sales 639 1,024 (38%) 32.3 41.1 (21%)
- -------------------------------------------------------------------------------------------------------
Total 3,282 3,500 (6%) $ 262.0 $ 255.5 3%
=======================================================================================================
TEP's average number of retail customers increased by 2.2% to 364,363,
while kWh sales to retail customers increased by 7% in 2003. Kilowatt-hour
sales to residential customers were up 10% and kWh sales to commercial
customers were up 8%, resulting from customer growth and warmer weather.
Cooling degree days increased by 9% in 2003, and were up 5% compared with
the third quarter ten-year average. TEP set a record retail peak load of
2,060 MW on August 12, 2003, exceeding the previous record peak of 1,899 MW
set in 2002. Revenue from sales to retail customers increased by 7% in
2003, reflecting higher kWh demand.
Electric wholesale revenues decreased by 21% in 2003. The 21% decline
in wholesale revenues is not as large as the 38% decline in wholesale kWh
sales due to higher average power prices. Average-around-the-clock energy
prices for 2003 increased to $46 per MWh compared with $28 per MWh during
2002, primarily due to increased natural gas prices in the region. Gas
prices in 2003 averaged $4.39 per MMBtu, up 76% compared with last year.
The addition of other gas resources in the region and resulting lower
average generating heat rates combined with higher retail kWh sales
resulted in unfavorable wholesale market opportunities.
35
TEP kWh Sales Delivered and Corresponding Revenues for the Nine Months
Ended September 30, 2003 Compared with the Nine Months Ended September 30,
2002:
Sales Operating Revenue
- -------------------------------------------------------------------------------------------------------
Nine Months Ended September 30, Percent Percent
2003 2002 Change 2003 2002 Change
- -------------------------------------------------------------------------------------------------------
- Millions of kWh - - Millions of Dollars -
Electric Retail Sales:
Residential 2,645 2,540 4% $ 240.6 $ 230.7 4%
Commercial 1,295 1,253 3% 135.0 130.8 3%
Industrial 1,714 1,752 (2%) 123.4 124.4 (1%)
Mining 511 509 - 20.4 20.7 (1%)
Public Authorities 194 200 (3%) 14.1 14.5 (3%)
- -------------------------------------------------------------------------------------------------------
Total Electric Retail Sales 6,359 6,254 2% 533.5 521.1 2%
- -------------------------------------------------------------------------------------------------------
Electric Wholesale Sales Delivered:
Long-term Contracts 882 685 29% 39.6 38.1 4%
Other Sales 1,494 2,525 (41%) 62.3 84.9 (27%)
Transmission - - - 6.1 2.9 NM
- -------------------------------------------------------------------------------------------------------
Total Electric Wholesale Sales 2,376 3,210 (26%) 108.0 125.9 (14%)
- -------------------------------------------------------------------------------------------------------
Total 8,735 9,464 (8%) $ 641.5 $ 647.0 (1%)
=======================================================================================================
Total retail kWh sales in 2003 increased by 2% compared with 2002.
Hot summer weather compared with a year ago, and a 2.3% increase in the
average number of retail customers more than offset mild weather during the
first six months of 2003. Cooling degree days increased by 5% in 2003
compared with the same period in 2002, and were up 6% compared with the 10-
year average. Heating degree days decreased by 19% in the first quarter of
2003 compared with the same period in 2002, and also decreased 16% when
compared with the first quarter 10-year average. Kilowatt-hour sales to
residential customers were up 4% and kWh sales to commercial customers were
up 3% in 2003, resulting from customer growth and warmer weather compared
with a year ago. Revenue from sales to retail customers increased by 2% in
2003, reflecting higher kWh demand.
Electric wholesale revenues decreased by 14% in 2003. The 14% decline
in wholesale revenues is not as large as the 26% decline in wholesale kWh
sales due to higher average power prices. Average-around-the-clock energy
prices for 2003 were $43 per MWh compared with $25 per MWh during 2002.
Planned and unplanned outages at TEP's coal-fired generating plants,
particularly in the first six months of 2003, reduced opportunities to sell
wholesale power. Gas prices in 2003 averaged $4.54 per MMBtu, up 89%. The
addition of other gas resources in the region and resulting lower average
generating heat rates, resulted in unfavorable wholesale market
opportunities for TEP's gas-fired generating resources. In addition,
wholesale revenues were reduced by a $2 million reserve for doubtful
accounts recorded in the first quarter related to wholesale sales made to
the California Independent System Operator (CISO) and the California Power
Exchange (CPX) in 2001 and 2000. See Payment Defaults and Allowances for
Doubtful Accounts, below.
Fuel and Purchased Power Expenses
Fuel expense at TEP's generating plants increased by approximately $6
million, or 10%, in the quarter ended September 30, 2003, compared with the
same quarter in 2002, due to increased retail kWh demand and higher natural
gas prices. The average cost of fuel per kWh generated for the third
quarter of 2003 was 2.02 cents compared with 1.84 cents for the third
quarter of 2002. In addition, TEP reversed a fuel expense accrual of $2
million in the third quarter of 2002, related to the elimination of a take-
or-pay payment at the Sundt Generating Station. In the first nine months
of 2003, fuel expense at TEP's generating plants decreased by approximately
$2 million, or 2%, compared with the same period in 2002. The higher cost
of natural gas partially offset lower retail kWh demand in the first half
of 2003. The average cost of fuel per kWh generated for the first nine
months of 2003 was 1.95 cents, compared with 1.89 cents in the same period
of 2002. See Item 3. -Quantitative and Qualitative Disclosures About Market
Risk, below.
TEP's Purchased Power expense decreased approximately $0.5 million, or
2%, in the third quarter of 2003, compared with the same period in 2002.
Purchased Power expense during the first nine months of 2003 was up
approximately $10 million, or 21%, compared with the same period in 2002.
In the first half of 2003, TEP had to purchase replacement power due to
planned and unplanned outages at some of its generating facilities. In
addition, TEP is relying on purchased power in lieu of running its more
expensive gas-fired generation. See Other Operating Expenses, below.
36
Other Operating Expenses
Other Operations and Maintenance expense decreased by $3 million, or
8%, in the third quarter of 2003, compared with the same period in 2002,
primarily attributable to lower incentive compensation and the elimination
of $1 million in rental expense related to a 20 MW turbine that TEP
purchased from UED in September 2002. In the first nine months of 2003,
Other O&M expense increased by $0.8 million, compared with the same period
in 2002.
Depreciation and Amortization expense decreased $3 million in the
first nine months of 2003 compared with the same period in 2002. The
adoption of FAS 143 in the first quarter of 2003 resulted in a $4 million
decrease because asset retirement costs are no longer recorded as a
component of depreciation expense. See Critical Accounting Policies -
Accounting for Asset Retirement Obligations, below.
Amortization of the Transition Recovery Asset (TRA) increased $3
million in the third quarter of 2003 and $5 million in the first nine
months of 2003 compared with the same periods in 2002. Amortization of the
TRA is the result of the 1999 Settlement Agreement (TEP Settlement
Agreement) with the ACC, which changed the accounting method for TEP's
generation operations. This item reflects the recovery, through 2008, of
transition recovery assets which were previously regulatory assets of the
generation business. TEP expects TRA amortization to be $45 million in
2004, $56 million in 2005, $67 million in 2006, $73 million in 2007 and
$38 million in 2008.
Other Income (Deductions)
TEP's income statement includes inter-company Interest Income of $3
million for the third quarter of 2003, and $2 million for the third quarter
of 2002. This represents Interest Income on the promissory note TEP
received from UniSource Energy in exchange for the transfer to UniSource
Energy of its stock in Millennium in 1998. Interest Income on this
promissory note was $8 million in the first nine months of 2003 and was $7
million for the first nine months of 2002. On UniSource Energy's
Consolidated Statement of Income, this Interest Income, as well as
UniSource Energy's related interest expense, is eliminated as an inter-
company transaction.
Interest Income was $5 million in each of the third quarter for 2003
and 2002. Interest Income in the first nine months of 2003 increased $0.9
million compared with the same period in 2002, due to investments in
Springerville lease debt.
Other Income decreased $1 million, while Other Expense decreased $0.2
million in the third quarter of 2003, compared with the same period in
2002. In the first nine months of 2003, Other Income decreased by $1
million, while Other Expense decreased by $0.5 million, compared with the
same period in 2002. Other Income includes non-utility revenue, the cost
of financing construction for transmission and distribution projects
attributable to equity funds and other miscellaneous non-utility income.
Other Expense includes charitable contributions and other miscellaneous non-
utility expenses.
Interest Expense
Long-Term Debt Interest Expense increased in the third quarter and
first nine months of 2003, compared to the same periods in 2002 due to
higher Letter of Credit fees under TEP's Credit Agreement. Interest on
Capital Leases decreased in the third quarter and first nine months of
2003, compared with the same periods in 2002 due to scheduled repayments of
lease debt.
Income Tax Expense
Income Tax Expense increased by $6 million in the third quarter of
2003, compared with the same period in 2002. The increase was due to
higher pre-tax income and a $4 million tax benefit recorded in the third
quarter of 2002, related to the reduction of the valuation allowance, and
the favorable settlement of an IRS audit issue. In the first nine months
of 2003, Income Tax Expense decreased by $0.4 million compared with the
same period in 2002, due to lower pre-tax income.
Cumulative Effect of Accounting Change
TEP adopted FAS 143 on January 1, 2003 and recorded a one-time $67
million after-tax gain. Upon adoption of FAS 143, TEP recorded an asset
retirement obligation of $38 million at its net present value of $1
million, increased depreciable assets by $0.1 million for asset retirement
costs, reversed $113 million of costs previously accrued for final removal
from accumulated depreciation, and reversed previously recorded deferred
tax assets of $44 million. TEP
37
expects that adopting FAS 143 will result in a reduction to depreciation
expense charged throughout the year as well because asset retirement costs are
no longer recorded as a component of depreciation expense. For the year 2003,
this amount is approximately $6 million. See Critical Accounting Policies -
Accounting for Asset Retirement Obligations, below.
FACTORS AFFECTING RESULTS OF OPERATIONS
- ---------------------------------------
COMPETITION
The electric utility industry has undergone significant regulatory
change in the last few years designed to encourage competition in the sale
of electricity and related services. However, the recent experience in
California with deregulation has caused many states, including Arizona, to
re-examine the viability of retail electric deregulation.
As of January 1, 2001, all of TEP's retail customers are eligible to
choose an alternate energy supplier. Although there is one Energy Service
Provider (ESP) certified to provide service in TEP's retail service area,
currently none of TEP's retail customers have opted to receive service from
this ESP. TEP has met all conditions required by the ACC to facilitate
electric retail competition, including ACC approval of TEP's direct access
tariffs. ESPs must meet certain conditions before electricity can be sold
competitively in TEP's service territory. Examples of these conditions
include ACC certification of ESPs, and execution of and compliance with
direct access service agreements with TEP.
TEP also competes against gas service suppliers and others that
provide energy services. Other forms of energy technologies may provide
competition to TEP's services in the future, but to date, are not
financially viable alternatives for TEP's retail customers. Self-
generation by TEP's large industrial customers could also provide
competition for TEP's services in the future, but has not had a significant
impact to date.
In the wholesale market, TEP competes with other utilities, power
marketers and independent power producers in the sale of electric capacity
and energy.
RATES AND REGULATION
TEP's Settlement Agreement and Retail Electric Competition Rules
In September 1999, the ACC approved Rules that provided a framework
for the introduction of retail electric competition in Arizona. In
November 1999, the ACC approved the TEP Settlement Agreement between TEP
and certain customer groups relating to the implementation of retail
electric competition, including TEP's recovery of its transition recovery
assets and the unbundling of tariffs. During 2002, the ACC reexamined
circumstances that had changed since it approved the Rules in 1999. The
outstanding issues were divided into two groups. Track A related primarily
to the divestiture of generation assets while Track B related primarily to
the competitive energy bidding process.
Track A
In September 2002, the ACC issued the Track A Order, which eliminated
the requirement in the TEP Settlement Agreement that TEP transfer its
generation assets to a subsidiary. At the same time, the ACC ordered the
parties, including TEP, to develop a competitive bidding process, and
reduced the amount of power to be acquired in the competitive bidding
process to only that portion not supplied by TEP's existing resources.
Track B
On February 27, 2003, the ACC issued the Track B Order, which defined
the competitive bidding process TEP must use to obtain capacity and energy
requirements beyond what is supplied by TEP's existing resources. For the
period 2003 through 2006, TEP estimates these amounts to be 50,000 MWh of
energy in 2003, or approximately 0.5% of its retail load, gradually
increasing to 104,000 MWh by 2006. The Track B Order further required TEP
to bid out "Economy Energy", or short-term energy purchases, that it
estimates it will make in the 2003 to 2006 period (210,000 to 181,000 MWh).
TEP was also required to bid out its Reliability Must Run (RMR)
generation requirements, which are currently met by its existing local
generation units. TEP's RMR generation requirements are estimated at 471
MW of capacity and 37,000 MWh of energy in 2003 increasing to 687 MW of
capacity and 38,000 MWh of energy in 2005. TEP does not anticipate that
any near-term RMR requirements will be met through this competitive bidding
process because of the locational and operational requirements of TEP's RMR
generation as well as TEP's belief that its existing RMR generation
solutions are economically sound.
38
TEP is not required to purchase any power through this process that it
deems to be uneconomical, unreasonable or unreliable. The Track B bidding
process involved the ACC Staff and an independent monitor. The Track B
Order also confirmed that it is not intended to change the current retail
rates for generation services.
TEP entered into two agreements to meet its 2003 bid requirements
under the Track B Order for the period 2003 through 2006 as listed below:
- PPL Energy Plus, LLC will supply 37 MW from June 2003 through December
2003 and 75 MW from January 2004 through December 2006, under a unit
contingent contract.
- Teco Energy's Gila River generating station will supply 50 MW on-peak
for the June through September time period, from 2003 through 2005, under a
unit contingent contract.
- No RMR bids were received.
Rates
TEP is required to file by June 1, 2004 a general rate case, including
an updated cost of service study. Under the terms of the TEP Settlement
Agreement, no rate case filed by TEP through 2008, including the rate case
to be filed by June 1, 2004, may result in a net rate increase. The ACC
order approving the Citizens acquisition also requires that TEP submit as
part of its June 2004 general rate case filing, a feasibility study and
consolidation plan, or in the alternative, a plan for coordination of
operations of UNS Electric's operations in Santa Cruz County with those of
TEP.
WESTERN ENERGY MARKETS
As a participant in the western U.S. wholesale power markets, TEP is
directly and indirectly affected by changes in market conditions and market
participants. TEP competes with other utilities, power marketers and
independent power producers in the sale of electric capacity and energy at
market-based rates in the wholesale market.
The electric generating capacity in Arizona has grown to approximately
23,000 MW; an increase of more than 48% since 2000. An additional 1,700
MWs of capacity are expected to come on line by the end of 2003. A
majority of the growth over the last three years is the result of 19 new or
upgraded gas-fired generating units with a combined capacity of
approximately 9,300 MW. The new generation increases the state's total
generating capacity to over 25,000 MW at the end of this year. In
addition, the presence of fewer creditworthy counterparties, as well as
legal, political and regulatory uncertainties, has reduced market liquidity
and trading volume.
Market Prices
The average market price for around-the-clock energy based on the Dow
Jones Palo Verde Index increased in 2003 compared with 2002, as did the
average price for natural gas based on the San Juan Index.
Average Market Price for Around-the-Clock Energy $/MWh
--------------------------------------------------------------------
Quarter ended September 30, 2003 $46
Quarter ended September 30, 2002 28
Nine months ended September 30, 2003 43
Nine months ended September 30, 2002 25
--------------------------------------------------------------------
Average Market Price for Natural Gas $/MMBtu
----------------------------------------------------------------------
Quarter ended September 30, 2003 $4.39
Quarter ended September 30, 2002 2.49
Nine months ended September 30, 2003 4.54
Nine months ended September 30, 2002 2.40
----------------------------------------------------------------------
Average market prices for around-the-clock energy began to rise in
February 2003 due to increased demand and higher natural gas prices
resulting from low gas storage levels resulting from colder temperatures in
other regions of the U.S. and reduced gas production. Reduced hydropower
supply in the western U.S. also contributed to the higher market prices.
Starting in October 2003, the average forward around-the-clock market price
for the balance of the year 2003 is
39
estimated at approximately $38 per MWh, based on forward market broker quotes
as of September 30, 2003. As a result of all these factors, we expect TEP's
purchased power expense to be higher in 2003 than in 2002, depending on the
actual volumes purchased. We cannot predict whether these higher prices
will continue, or whether changes in various factors that influence demand
and supply will cause prices to fall again during the remainder of 2003.
We expect the market price and demand for capacity and energy to
continue to be influenced by the following factors during the next few
years:
- continued population growth in the western U.S.;
- economic conditions in the western U.S.;
- availability of generating capacity throughout the western U.S.;
- the extent of electric utility industry restructuring in Arizona,
California and other western states;
- the effect of FERC regulation of wholesale energy markets;
- the availability and price of natural gas;
- availability of hydropower;
- transmission constraints; and
- environmental restrictions and the cost of compliance.
Payment Defaults and Allowances for Doubtful Accounts
California claims that it was overcharged by up to $9 billion for
wholesale power purchases in 2000 and 2001, and is seeking refunds from
numerous power generators, including TEP. In early 2001, California's two
largest utilities, Southern California Edison Company (SCE) and Pacific Gas
& Electric Company (PG&E), defaulted on payment obligations owed to various
energy sellers, including the CPX and the CISO. The CPX and the CISO
defaulted on their payment obligations to market participants, including
TEP. While SCE subsequently satisfied its obligations to the CPX, TEP has
not received a corresponding payment from the CPX. The total amount owed
to TEP by the CPX and CISO is $16 million. The FERC has held hearings and
the FERC staff has proposed various methodologies for calculating amounts
of refunds/offsets applicable to wholesale sales made into the California
spot markets from October 2000 to June 2001. Based upon a FERC order in
March 2003 (as reaffirmed by the FERC on October 16, 2003), TEP estimated
that it may receive $6 million of its $16 million receivable. This
represents amounts owed to TEP, plus interest, net of TEP's estimated
refund liability. Therefore, in the first quarter of 2003, TEP increased
its allowance for doubtful accounts for its CPX and CISO receivables by
approximately $2 million, from $8 million to $10 million.
In late 2001, Enron filed for bankruptcy protection. At that time,
TEP had an outstanding receivable from Enron of $0.8 million. A FERC order
recommended that Enron no longer be allowed to trade and within a few days
thereafter, Enron was delisted from its stock exchange. As a result, in
the first quarter of 2003, TEP increased its allowance for doubtful
accounts for its sales to Enron by $0.4 million, to fully reserve its $0.8
million receivable from Enron.
TEP is not able to predict the length and outcome of the FERC hearings
and the outcome of any subsequent lawsuits and appeals that might be filed.
As a participant in the refund proceedings, TEP will be subject to any
final refund orders. TEP does not expect its refund liability, if any, to
have a significant impact on the financial statements. See Critical
Accounting Policies - Payment Defaults and Allowances for Doubtful
Accounts, below.
Market Manipulation Investigations
On June 25, 2003, the FERC alleged that 60 energy companies, including
TEP, may have engaged in manipulative practices that disrupted western
energy markets in 2001 and 2000. The FERC issued an order to show cause to
explain certain transactions. There were 39 hours in which it is alleged
that TEP used a specific trading strategy ("ricochet") in which TEP
purportedly purchased energy out of the California markets on a day-ahead
basis with the intent of re-selling it to the California markets at higher
rates in real-time. The basis of the allegation against TEP are trades in
May through August of 2000 where TEP purchased energy from the CPX in the
day ahead market, and also sold power to the CPX or CISO during the same
hours in the real-time markets the following day. TEP has reviewed the
transactions and believes that every hour had a legitimate operational or
trading explanation and that TEP did not use the "ricochet" strategy. The
total amount of profit supposedly made by TEP in these 39 hours is less
than $9,000, which is below the $10,000 prosecutorial discretion limit set
by the FERC in the same order. On August 29, 2003, the FERC trial staff
filed a motion to dismiss all charges against TEP.
40
FUEL SUPPLY
TEP purchases coal and natural gas in the normal course of business to
fuel its generating plants. The majority of its coal supplies are
purchased under long-term contracts, which result in predictable prices.
Concurrent with the closing of the Springerville expansion, TEP
amended and extended the long-term coal supply contract at Springerville
Units 1 and 2 through 2020. TEP estimates its future minimum annual
payments under this contract to be $45 million through 2010, the initial
contract expiration date, and $14 million in 2011 through 2020. TEP's coal
transportation contract at Springerville runs until June 2011. TEP
estimates its minimum payments under this contract to be $13 million
through 2010 and $6.5 million in 2011.
In September 2003, TEP entered into agreements in principle for the
purchase and transportation of coal to the Sundt Generating Station through
2006 and expects to execute the associated contracts in November 2003. The
total amount paid under these agreements depends on the number of tons of
coal purchased and transported. The coal agreements require TEP to take
0.3 million tons annually with estimated future minimum payments of $4
million in 2004 and $6 million in 2005 and 2006. The rail agreement
requires TEP to transport 0.3 million tons with estimated future minimum
payments of $2 million in each year from 2004 through 2006.
Also, in July 2003, the long-term coal supply contract at Four
Corners, where TEP participates in jointly-owned facilities, was extended
through July 2016, pursuant to its terms. The contract to purchase coal
for use at Four Corners requires TEP to purchase minimum amounts of coal at
an estimated annual cost of $5 million for the next 12.5 years.
TEP typically uses its gas generation to meet the summer peak demands
of its retail customers and to meet local reliability needs. Due to its
limited and historically seasonal usage of natural gas for firm electric
wholesale and retail customers, TEP typically purchases its gas needs in
the spot and short-term markets through its supplier Southwest Gas
Corporation (SWG).
In the first nine months of 2003, natural gas prices were nearly
double those in the first nine months of 2002, due to low gas storage
levels and reductions in gas production. The increase in the regional
supply of gas-generated energy and the completion of a 500 kV transmission
connection however, allowed TEP to decrease use of its less efficient gas
generation units in favor of more economical purchases of energy in the
wholesale market. TEP's generation output fueled by natural gas was
approximately 405,000 MWh, or 5% of total generation in the first nine
months of 2003, compared with approximately 610,000 MWh, or 7% of total
generation in the first nine months of 2002.
TEP obtains its gas supply as a retail customer of the local gas
supplier, SWG. TEP periodically negotiates its contract with its gas
supplier to establish terms relating to pricing and scheduling of gas
delivery. SWG is affected by recent FERC actions relating to its gas
allocations from the San Juan and Permian basins. A FERC order was issued
on this topic on July 9, 2003. TEP is in the process of renegotiating its
gas supply and transportation agreement with SWG and expects to execute the
contract in November 2003. TEP does not anticipate any material difference
in operational or economic terms in the new agreement, which will be
retroactive to November 1, 2003.
GENERATING RESOURCES
Water Supply
Drought conditions in the Four Corners region, combined with water
usage in upper New Mexico, have resulted in decreasing water levels in the
lake that indirectly supplies water to the San Juan and Four Corners
generating stations. These drought conditions may affect the water supply
of the plants in 2004, as well as in later years, if adequate moisture is
not received in the watershed that supplies the area. TEP has a 50%
ownership interest in each of San Juan units 1 and 2 (322 MW capacity) and
a 7% ownership interest in each of Four Corners units 4 and 5 (110 MW
capacity).
PNM, the operating agent for San Juan, has negotiated supplemental
water contracts with the U.S. Bureau of Reclamation and the Jicarilla
Apache Nation to assist San Juan in meeting its water requirements in the
event of a water shortage. TEP does not believe that its operations will
be materially affected by this drought. However, TEP cannot predict the
ultimate outcome of the drought, or whether it will adversely affect the
amount of power available from the San Juan and Four Corners generating
stations.
41
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
TEP CASH FLOWS
September 30, September 30,
Nine months ended 2003 2002
-----------------------------------------------------------------------
- Millions of Dollars -
Cash Provided by (Used in):
Operating Activities $162 $155
Investing Activities (87) (223)
Financing Activities (97) (24)
-----------------------------------------------------------------------
Net Decrease in Cash $(22) $(92)
=======================================================================
TEP's capital requirements consist primarily of capital expenditures
and optional and mandatory redemptions of long-term debt and capital lease
obligations.
During 2003, TEP expects to generate sufficient internal cash flows to
fund its operating activities, construction expenditures, required debt
maturities, and to pay dividends to UniSource Energy. However, due to the
seasonal nature of TEP's business, cash provided by operating activities
varies significantly from quarter to quarter. At September 30, 2003, TEP
had $40 million available under its $60 million Revolving Credit Facility.
As of November 6, 2003, TEP had $60 million available under this facility.
If cash flows fall short of expectations or if monthly cash requirements
temporarily exceed available cash balances, TEP may borrow additional
amounts from its Revolving Credit Facility.
Investing Activities
Net cash used for investing activities was $136 million lower in the
first nine months of 2003, compared with the same period in 2002. During
the first nine months of 2003, construction expenditures were $25 million
higher, which include approximately $10 million for completing a new one
mile 500-kV transmission line and related substations. In the first nine
months of 2003, TEP received $12 million in principal payments on its
investments in outstanding Springerville lease debt. In contrast, in the
first nine months of 2002, TEP made net investments in Springerville lease
debt of $135 million.
TEP's capital expenditures for the nine months ended September 30,
2003 were $97 million. TEP's forecast for capital expenditures for the
year ending December 31, 2003 is approximately $121 million. These
expenditures include costs to comply with current federal and state
environmental regulations. Actual construction expenditures may differ
from these estimates due to changes in business conditions, construction
schedules, environmental requirements and changes to TEP's business arising
from retail competition. TEP plans to fund these expenditures through
internally-generated cash flow.
In January 2001, TEP and Citizens entered into a project development
agreement for the joint construction of a 62-mile transmission line from
Tucson to Nogales, Arizona. In January 2002, the ACC approved the location
and construction of the proposed 345-kV line. Pending federal studies and
approvals for the portion of the line that will pass through a national
forest, construction could begin as early as the first quarter of 2005,
with an expected in-service date at the end of 2005. Construction costs
are expected to be approximately $75 million. TEP has also applied to the
U.S. Department of Energy for a Presidential Permit that would allow
building an extension of the line across the international border with
Mexico to interconnect with Mexico's utility system, providing further
reliability and market opportunities in the region. Through September 30,
2003, approximately $8 million in engineering and environmental expenses
have been capitalized related to this project. If the project does not
proceed, these costs would be immediately expensed.
Financing Activities
Net cash used in financing activities totaled $97 million in the first
nine months of 2003, compared with $24 million during the same period in
2002. TEP spent $42 million to retire scheduled capital lease obligations,
compared with $19 million in 2002. Capital lease payments were higher in
2003 due to a $28 million scheduled principal payment on the Springerville
Unit 1 lease debt in the first quarter of 2003. TEP paid $59 million in
dividends to UniSource Energy in the first nine months of 2003, compared
with $10 million paid in the first nine months of 2002. These cash
outflows were partially offset by $20 million in net borrowings under TEP's
Revolving Credit Facility.
42
TEP Credit Agreement
--------------------
TEP's $401 million Credit Agreement consists of a $60 million
Revolving Credit Facility and two letter of credit (LOC) facilities
(Tranche A and Tranche B) totaling $341 million. The Revolving Credit
Facility is used to provide liquidity for general corporate purposes. The
LOC Facilities support $329 million aggregate principal amount of tax-
exempt variable rate debt obligations. The Revolving Credit Facility is a
364-day facility that expires on November 13, 2003. The Tranche A letters
of credit, totaling $135 million, expire in January 2006, and the Tranche B
letters of credit, totaling $206 million, expire in November 2006. In
October 2003, TEP's revolving credit lenders agreed to extend the Revolving
Credit Facility under the same terms and conditions to November 11, 2004.
The facilities are secured by $401 million in aggregate principal
amount of Second Mortgage Bonds issued under TEP's General Second Mortgage
Indenture. The Credit Agreement contains a number of restrictive
covenants, including restrictions on additional indebtedness, liens, sale
of assets, mergers and sale-leasebacks. The Credit Agreement also contains
several financial covenants including: (a) a minimum Consolidated Tangible
Net Worth, (b) a minimum Cash Coverage Ratio, and (c) a maximum Leverage
Ratio. Under the terms of the Credit Agreement, TEP may pay dividends so
long as it maintains compliance with the Credit Agreement; however,
dividends and certain investments in affiliates may not exceed 65% of TEP's
net income so long as the Tranche B LOCs are outstanding. The Credit
Agreement also provides that under certain circumstances, certain
regulatory actions could result in a required reduction of the commitments.
As of September 30, 2003, TEP was in compliance with these financial
covenants.
In August 2003, the ACC approved TEP's financing application
requesting authority to refinance its Credit Agreement and to refinance up
to $200 million of its tax-exempt variable rate industrial development
revenue bonds with fixed rate industrial development revenue bonds. In
early 2004, TEP expects to refinance such debt.
Springerville Common Facilities Leases
--------------------------------------
In 1985, TEP sold and leased back its undivided one-half ownership
interest in the common facilities at the Springerville Generating Station.
Under the terms of the Springerville Common Facilities Leases, TEP must
periodically refinance or refund the secured notes underlying the leases
prior to the named date in order to avoid a special event of loss. TEP was
required to refinance the lease debt prior to the special event of loss
date of June 30, 2003 or the leases would be terminated and TEP would be
required to repurchase the facilities for $125 million.
TEP refinanced the lease debt on June 26, 2003 and the special event
of loss date was reset for June 30, 2006. Interest on the new debt is
payable at LIBOR plus 4.25%. Prior to the refinancing, the interest rate
was LIBOR plus 2.50%.
CONTRACTUAL OBLIGATIONS
The following section updates the significant changes in TEP's
contractual obligations or other commercial commitments since those
reported in our 2002 Annual Report on Form 10-K:
In May 2003, TEP entered into two purchased power agreements for
periods through 2006 as a result of the competitive bidding process
required by the ACC's Track B order:
- PPL Energy Plus, LLC contracted to supply 37 MW from June 2003 through
December 2003 and 75 MW from January 2004 through December 2006 under a
unit contingent contract.
- TECO Energy's Gila River generating station contracted to supply 50 MW
on-peak for the June through September time period, from 2003 through
2005 under a unit contingent contract.
See Fuel Supply, above, for changes to TEP's coal and gas supply contracts
since those reported in the 2002 Annual Report on Form 10-K.
DIVIDENDS ON COMMON STOCK
In the first nine months of 2003, the TEP Board of Directors declared
and paid dividends of $59 million to its shareholders. UniSource Energy
holds substantially all of TEP's common stock.
TEP can pay dividends if it maintains compliance with the TEP Credit
Agreement and certain financial covenants, including a covenant that
requires TEP to maintain a minimum level of net worth. As of September 30,
2003, the required minimum net worth was $315 million. TEP's actual net
worth at September 30, 2003 was $382 million, and was $352 million as
defined in the Credit Agreement. As of September 30, 2003, TEP was in
compliance with the terms of the Credit
43
Agreement. Under the terms of the Credit Agreement, dividends and certain
investments in affiliates may not exceed 65% of TEP's net income, so long as
the Tranche B LOCs are outstanding. See Financing Activities - TEP Credit
Agreement, above.
The ACC Holding Company Order states that TEP may not pay dividends to
UniSource Energy in excess of 75% of its earnings until TEP's common equity
equals 37.5% of total capitalization (excluding capital lease obligations).
The Citizens Settlement Agreement, as approved by the ACC, modifies this
dividend limitation so that it will remain in place until TEP's common
equity equals 40% of total capitalization (excluding capital lease
obligations). As of September 30, 2003, TEP's common equity equaled 25% of
total capitalization (excluding capital lease obligations).
In addition to these limitations, the Federal Power Act states that
dividends shall not be paid out of funds properly included in the capital
account. Although the terms of the Federal Power Act are unclear, we
believe that there is a reasonable basis to pay dividends from current year
earnings. Therefore, TEP declared its 2003 dividends from its year-to-date
July 2003 earnings since TEP had an accumulated deficit, rather than
positive retained earnings.
UNISOURCE ENERGY SERVICES
RESULTS OF OPERATIONS
- ---------------------
UniSource Energy formed two operating companies, UNS Gas and UNS
Electric, to acquire the Arizona electric and gas assets from Citizens, as
well as an intermediate holding company, UES, to hold the common stock of
UNS Gas and UNS Electric. Results of operations for UNS Electric and UNS
Gas cover the period from August 11, 2003, the date the assets were
acquired from Citizens, to September 30, 2003.
UES' net income for the period was $0.1 million. Similar to TEP's
operations, we expect UNS Electric's operations to be seasonal in nature,
with peak energy demand occurring in the summer months. We also expect
operations at UNS Gas to vary with the seasons, with peak energy usage
occurring in the winter months.
UNS Electric
UNS Electric is an electric transmission and distribution company
serving customers in Mohave County in northern Arizona and Santa Cruz
County in southern Arizona. As of September 30, 2003, UNS Electric served
approximately 80,000 retail customers.
The table below shows UNS Electric's kWh sales and revenues for the
period August 11, 2003 to September 30, 2003.
Sales Operating Revenue
------------------------------------------------------------------------------------------------------
For the Period August 11, 2003 - September 30, 2003 2003 2003
------------------------------------------------------------------------------------------------------
- Millions of kWh - - Millions of Dollars -
Electric Retail Sales:
Residential 153 $15.1
Commercial 58 5.8
Industrial 14 0.9
Other 20 1.8
------------------------------------------------------------------------------------------------------
Total Electric Retail Sales 245 $23.6
======================================================================================================
UNS Gas
UNS Gas is a gas transportation and distribution company serving
retail customers in Mohave, Yavapai, Coconino, and Navajo Counties in
northern Arizona, as well as Santa Cruz County in southeast Arizona. As of
September 30, 2003, UNS Gas served approximately 127,000 retail customers.
UNS Gas supplies natural gas transportation service to the 600 MW
Griffith Power Plant (Griffith), located near Kingman, Arizona, under a 20-
year contract which expires in 2021. Griffith is jointly owned by
subsidiaries of Duke Energy
44
Corporation and PPL Energy Supply, LLC. UNS Gas also supplies natural gas to
some of its large transportation customers, through a Negotiated Sales
Program (NSP) approved by the ACC. Approximately one half of the margin
earned on these NSP sales is retained by UNS Gas, while the remainder benefits
retail customers through a credit to the Purchased Gas Adjustor (PGA)
mechanism.
The table below shows UNS Gas' therm sales and revenues for the period
August 11, 2003 to September 30, 2003.
Sales Operating Revenue
------------------------------------------------------------------------------------------------------
For the Period August 11, 2003 - September 30, 2003 2003 2003
------------------------------------------------------------------------------------------------------
- Thousands of therms - - Millions of Dollars -
Retail Therm Sales:
Residential 2,747 $3.7
Commercial 2,216 2.0
Industrial 279 0.2
Public Authority 263 0.2
------------------------------------------------------------------------------------------------------
Total Retail Therm Sales 5,505 6.1
Transport - 0.4
Negotiated Sales Program (NSP) 7,267 3.8
------------------------------------------------------------------------------------------------------
Total Therm Sales 12,772 $10.3
======================================================================================================
FACTORS AFFECTING RESULTS OF OPERATIONS
- ---------------------------------------
COMPETITION
As required by the ACC Decision approving UniSource Energy's
acquisition of the Citizens Arizona gas and electric assets, on November 3,
2003, UNS Electric filed with the ACC an application for approval of a plan
to open its service territories to retail competition by December 31, 2003.
The plan addresses all aspects of implementation. It includes UNS
Electric's unbundled distribution tariffs for both standard offer customers
and customers that choose competitive retail access, as well as Direct
Access and Settlement Fee schedules. The plan incorporates the Arizona
Independent Scheduling Administrator's (AISA) protocols for must-run
generation. UNS Electric direct access rates for both transmission and
ancillary services will be based upon its FERC Open Access Transmission
Tariff. The plan will not be effective prior to ACC review and approval.
RATES AND REGULATION
ACC Order on Citizens Acquisition
On July 3, 2003, the ACC issued an order approving the acquisition of
Citizens Arizona gas and electric assets. Concurrent with the closing of
the acquisition, retail rate increases for customers of both UNS Electric
and UNS Gas went into effect on August 11, 2003. Key provisions of the
order include:
UNS Gas
- 20.9% overall increase in retail rates through a base rate increase.
- Restricts the filing of a general rate case until August 2006 and any
resulting rate increase shall not become effective prior to August 1, 2007.
- Limits dividends payable by UNS Gas to UniSource Energy to 75% of
earnings until the ratio of common equity to total capitalization reaches
40%.
UNS Electric
- 22% overall increase in retail rates through its Purchased Power Fuel
Adjustor Clause (PPFAC).
- UNS Electric must file a plan with the ACC to open its service
territories to retail competition by no later than December 31, 2003.
- Restricts the filing of a general rate case until August 2006 and any
resulting rate increase shall not become effective prior to August 1, 2007.
- Limits dividends payable by UNS Electric to UniSource Energy to 75% of
earnings until the ratio of common equity
45
to total capitalization reaches 40%.
- Requires UNS Electric to enter into negotiations with Pinnacle West
Capital Corporation (PWCC) to seek to reduce the cost of its purchased
power contract with PWCC.
Power Cost Adjustment Mechanisms
UNS Gas
UNS Gas' retail rates include a PGA mechanism intended to address the
volatility of natural gas prices and allows UNS Gas to recover its costs through
a price adjustor. The PGA charge may be changed monthly based on an ACC
approved mechanism that compares the twelve-month rolling average gas cost to
the base cost of gas, subject to limitations on how much the price per therm may
change in a twelve month period. The difference between the actual cost of UNS
Gas' gas supplies and transportation contracts and that currently allowed by the
ACC are deferred and recovered or repaid through the PGA mechanism. When under
or over recovery trigger points are met, UNS Gas may request a PGA surcharge or
surcredit with the goal of collecting or returning the amount deferred from or
to customers over a twelve month period.
On September 9, 2003, the ACC approved a new PGA surcharge of $0.1155
per therm that took effect October 1, 2003.
UNS Electric
UNS Electric's retail rates include a PPFAC, which allows for a
separate surcharge or surcredit to the base rate for delivered purchased
power to collect or return under or over recovery of costs. As part of the
July 3, 2003 ACC Order, a new PPFAC surcharge of $0.01825 per kWh was
approved to fully recover the cost of the current full-requirements power
supply agreement with PWCC. UNS Electric is required to enter into
negotiations with PWCC to potentially reduce the cost of this purchased
power contract; 90% of any savings from the negotiations is to be passed on
to UNS Electric rate payers.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
UES' capital requirements consist primarily of capital expenditures.
During 2003, UES expects to generate sufficient internal cash flows to fund
its operating activities and its construction expenditures. UES' forecast
for capital expenditures for the year ending December 31, 2003 is
approximately $11 million. UES plans to partially fund these expenditures
through internally generated cash flow. UES intends to obtain, or have
made available to them through UniSource Energy, a revolving credit
facility to use for working capital purposes. This facility is expected to
be in place within the next five months.
Private Placement Notes
On August 11, 2003, UNS Gas and UNS Electric issued a total of $160
million of aggregate principal amount of senior unsecured notes in a
private placement. Proceeds from the note issuance were paid to Citizens to
purchase the Arizona gas and electric system assets. UNS Gas issued $50
million of 6.23% Notes due August 11, 2011 and $50 million of 6.23% Notes
due August 11, 2015. UNS Electric issued $60 million of 7.61% Notes due
August 11, 2008. All three series of notes may be prepaid with a make-whole
call premium reflecting a discount rate equal to an equivalent maturity
U.S. Treasury security yield plus 50 basis points. The notes are guaranteed
by UES.
The note purchase agreements for both UNS Gas and UNS Electric contain
certain restrictive covenants, including restrictions on transactions with
affiliates, mergers, liens to secure indebtedness, restricted payments,
incurrence of indebtedness, and minimum net worth. The required minimum
net worth levels for UES, UNS Gas, and UNS Electric are $50 million, $43
million, and $26 million, respectively. At September 30, 2003, UES' total
common stock equity was $87 million. UNS Gas and UNS Electric reported
common stock equity of $51 million and $36 million, respectively, at
September 30, 2003.
The incurrence of indebtedness covenant requires each of UNS Gas and
UNS Electric to meet certain tests before an additional dollar of
indebtedness may be incurred. These tests include (a) a ratio of
Consolidated Long-Term Debt to Consolidated Total Capitalization of no
greater than 0.67 to 1.00 prior to September 30, 2004, and no greater than
0.65 to 1.00 after September 30, 2004, and (b) an Interest Coverage Ratio
(a measure of cash flow to cover interest expense) of at least 2.50 to
1.00. However, UNS Gas and UNS Electric may, without meeting these tests,
refinance
46
indebtedness and incur short-term debt in an amount not to exceed $7 million
in the case of UNS Gas, and $5 million in the case of UNS Electric.
Neither UNS Gas, nor UNS Electric, may declare or make distributions or
dividends (restricted payments) on their common stock unless (a) immediately
after giving effect to such action no default or event of default would exist
under such company's note purchase agreement and (b) immediately after giving
effect to such action, such company would be permitted to incur an additional
dollar of indebtedness under the debt incurrence test for such company.
CONTRACTUAL OBLIGATIONS
The following section includes UES' significant contractual obligations
or other commercial commitments:
UNS Gas Supply Contracts
UNS Gas has a natural gas supply and management agreement with BP
Energy Company (BP). Under the contract, BP manages UNS Gas' existing
supply and transportation contracts and its incremental requirements. The
initial term of the agreement extends through August 31, 2005. The term of
the agreement is automatically extended one year on an annual basis unless
either party provides 180 days notice of its intent to terminate. Prices
for incremental commodity supplied by BP will vary based upon the period
during which the commodity is delivered. UNS Gas hedges its gas supply
prices by entering into fixed price forward contracts at various times
during the year to provide more stable prices to its customers. These
purchases are made up to a year in advance with the goal of hedging at
least 30% of the expected monthly gas consumption with fixed prices prior
to entering into the month. Currently, UNS Gas has approximately 70% of
its expected monthly consumption hedged for the November 2003 through March
2004 winter season.
UNS Gas has firm transportation agreements with El Paso Natural
Gas (EPNG) and Transwestern Pipeline Company (Transwestern) with combined
capacity sufficient to meet its load requirements. EPNG provides gas
transmission service under a full requirements contract under which UNS Gas
pays a fixed reservation charge. This contract expires in August 2011. In
July 2003, FERC required the conversion of UNS Gas' full requirements
status under the EPNG agreement to contract demand starting on September 1,
2003. Upon conversion to contract demand status, UNS Gas now has specific
volume limits in each month and specific receipt point rights from the
available supply basins (San Juan and Permian). These changes will reduce
the amount of less expensive San Juan gas available to UNS Gas. The
impact, however, is not expected to be material. The annual cost of the
EPNG capacity after conversion to contract demand will not change. The
Transwestern contract expires in January 2007. The aggregate annual
minimum transportation charges are expected to be approximately $3.5
million and $3.0 million for the EPNG and Transwestern contracts,
respectively.
UNS Electric Power Supply and Transmission Contracts
UNS Electric has a full requirements power supply agreement with PWCC.
The agreement expires May 31, 2008. The agreement obligates PWCC to supply
all of UNS Electric's power requirements at a fixed price per MWh. Payments
under the contract are usage based, with no fixed customer or demand
charges.
UNS Electric imports the power it purchases over the Western Area
Power Administration's (WAPA) transmission lines. UNS Electric's
transmission capacity agreements with WAPA expire in February 2008 and June
2011. The contract that expires in 2008 also contains a capacity
adjustment clause. Under the terms of the agreements, the aggregate
minimum fixed transmission charges are expected to be approximately $2
million for the last five months of 2003, $6 million in 2004, and $1
million in 2005 through 2011.
DIVIDENDS ON COMMON STOCK
The Citizens Settlement Agreement, as approved by the ACC, limits
dividends payable by UNS Gas and UNS Electric to 75% of earnings until the
ratio of common equity to total capitalization reaches 40%. At September
30, 2003, the ratio of common equity to total capitalization for UNS Gas
was 34% and for UNS Electric was 37.5%.
The note purchase agreements for both UNS Gas and UNS Electric contain
restrictive covenants including restrictions on dividends. According to
the note purchase agreements, neither UNS Gas, nor UNS Electric, may
declare or make distributions or dividends (restricted payments) on their
common stock unless, (a) immediately after giving effect to such action no
default or event of default would exist under such company's note purchase
agreement and (b) immediately after giving effect to such action, such
company would be permitted to incur an additional dollar of indebtedness
under the debt incurrence test for such company.
47
MILLENNIUM ENERGY HOLDINGS, INC.
RESULTS OF OPERATIONS
- ---------------------
Millennium's Energy Technology Investments include Global Solar
Energy, Inc. (Global Solar), Infinite Power Solutions, Inc. (IPS), MicroSat
Systems, Inc. (MicroSat) and ITN Energy Systems, Inc. (ITN). The major
factors contributing to the losses in 2003 and 2002 are development and
manufacturing costs of Global Solar's photovoltaic products, expenditures
to develop thin-film and solid-state rechargeable batteries by IPS,
research and development work performed by ITN and contract work performed
by MicroSat on satellite development. Results of Other Millennium
Investments include the operating results from Millennium Environmental
Group, Inc. (MEG), POWERTRUSION International, Inc. (Powertrusion) and
TruePricing, Inc. (TruePricing). The table below provides a breakdown of
the net losses recorded by Millennium:
Three Months Ended Nine Months Ended
September 30, September 30,
2003 2002 2003 2002
- -------------------------------------------------------------------------------------------------------------------------
- Millions of Dollars -
Energy Technology Investments
Global Solar and IPS
Research and Development Contract Revenues to Third Parties $ 0.6 $ 0.1 $ 1.6 $ 1.1
Other Third Party Sales 0.9 - 0.9 -
Research and Development Contract Expenses & Losses (1.4) (1.6) (4.0) (3.9)
Research and Development - Internal Development Expenses (0.3) (0.7) (1.4) (3.0)
Depreciation and Amortization Expense (1.0) (0.7) (2.6) (2.1)
Administrative and Other Costs (2.2) (4.1) (7.9) (8.5)
Income Tax Benefits 1.4 2.9 5.4 6.6
- -------------------------------------------------------------------------------------------------------------------------
Global Solar and IPS Loss, after tax (2.0) (4.1) (8.0) (9.8)
MicroSat and ITN Loss, after tax (0.2) (0.1) (1.2) (0.5)
- -------------------------------------------------------------------------------------------------------------------------
Total Energy and Technology Investments Loss, after tax (2.2) (4.2) (9.2) (10.3)
Other Millennium Investments Income (Loss), after tax (0.5) 1.4 (2.9) (0.2)
- -------------------------------------------------------------------------------------------------------------------------
Total Millennium Loss, after tax $ (2.7) $ (2.8) $(12.1) $(10.5)
=========================================================================================================================
Funding Provided by Millennium to Investees $ 5.3 $ 30.3 $ 16.7 $ 49.8
=========================================================================================================================
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
Millennium provided funding to its investments of approximately $16.7
million during the first nine months of 2003 and $49.8 million during the
first nine months of 2002.
Energy Technology Investments and Commitments
We refer to Global Solar, IPS, MicroSat and ITN as our Energy
Technology Investments. As described below, as of the third quarter of
2003, Millennium owns no interest in ITN.
- Global Solar - Millennium funded $7.9 million to Global Solar in the
first nine months of 2003, and $0.4 million in October 2003. Millennium's
unfunded commitment to Global Solar is $1.5 million of a $5 million line
of credit committed in May 2003. In the third quarter, Millennium
exchanged its 9% interest in ITN and other consideration for additional
shares of Global Solar. In October 2003, Millennium converted a $7
million loan, plus interest to equity in Global Solar. Millennium's
ownership in Global Solar is now 99%. As sole funder, Millennium
recognizes 100% of Global Solar's losses. Global Solar has a $0.5 million
research and development funding commitment to ITN in 2004.
- IPS - Millennium funded $1.5 million of equity and $0.5 million of
debt to IPS in the first nine months of 2003. Dow Corning Enterprises,
Inc. funded $1.5 million of equity and $0.5 million of debt to IPS in the
first nine months of 2003. Millennium owns approximately 72% of IPS. In
2003, Millennium has recorded its ratable share of IPS' losses. IPS has
a $0.5 million annual research and development funding commitment to ITN
through 2004.
48
- MicroSat - Millennium owns 35% of MicroSat. As sole funder,
Millennium continues to recognize 100% of MicroSat's losses.
- ITN - During the third quarter of 2003, Millennium exchanged its 9%
interest in ITN and other consideration for additional shares of Global
Solar which decreased Millennium's ownership in ITN to zero.
Millennium has a $2 million remaining commitment to its Energy
Technology Investments. Additional commitments may be made. A significant
portion of this funding is for manufacturing costs, administrative,
research and development costs primarily at Global Solar. Funding for
administrative, research and development costs are expensed as amounts are
spent.
Other Millennium Investments and Commitments
Millennium has a $15 million capital commitment, excluding fees,
to Haddington Energy Partners II LP (Haddington), a limited partnership
which funds energy-related investments. Millennium has invested $8.1 million
of this commitment, $2 million of which was funded in 2003. The remaining $6.9
million is expected to be funded within the next three years. A member of
the UniSource Energy Board of Directors has an investment in the limited
partnership and is also a managing director of the general partner of the
limited partnership.
Millennium has a $5 million commitment, excluding fees, to a venture
capital fund that focuses on information technology, microelectronics and
biotechnology, primarily within the southwestern U.S. At September 30, 2003,
Millennium has funded approximately $1.2 million of this commitment. Millennium
expects to fund the remaining $3.8 million by the end of 2007. A member of
the UniSource Energy Board of Directors is a general partner of the company
that manages the fund.
During 2003, Millennium contributed $1.2 million to TruePricing and
began accounting for TruePricing under the consolidation method.
Millennium and TEP collectively now own approximately 57% of the
outstanding shares of TruePricing. Prior to this investment, Millennium
accounted for TruePricing under the equity method. Millennium, as sole
funder, recognizes 100% of TruePricing's losses.
During 2003, Millennium contributed approximately $2.1 million to
Powertrusion, most of which was contributed in the third quarter. This
investment brings Millennium's share of ownership in Powertrusion to almost
77%. Millennium accounts for Powertrusion under the consolidation method.
CONTRACTUAL OBLIGATIONS
The following section updates the significant changes in Millennium's
contractual obligations or other commercial commitments since those
reported in our 2002 Annual Report on Form 10-K:
- MEG conducts its emissions and coal trading activities using certain
contracts which contain provisions whereby MEG may be required to post
margin collateral due to a change in contract values. As of September 30,
2003, MEG had posted $0.1 million in cash collateral to its trading
counterparties.
- MEG has a $5 million bank line of credit for the purpose of issuing
LOCs to counterparties to support its Emission Allowance and coal marketing
and trading activities. As of September 30, 2003, MEG had approximately $4
million in outstanding LOCs. This facility expires in March 2005.
DIVIDENDS ON COMMON STOCK
Millennium did not pay any dividends to UniSource Energy in 2002 or
during the first nine months of 2003.
UNISOURCE ENERGY DEVELOPMENT COMPANY
RESULTS OF OPERATIONS
- ---------------------
UED recorded a net loss of $0.2 million in the first nine months of
2003, compared with a net gain of $1.1 million in the first nine months of
2002. UED's loss in 2003 represents operating expenses. UED's income in
2002 represented rental income (less expenses) under an operating lease of
the 20 MW North Loop turbine to TEP. The rental income was eliminated from
UniSource Energy's consolidated after-tax earnings as an inter-company
transaction. TEP purchased the
49
turbine from UED in September 2002.
SPRINGERVILLE GENERATING STATION EXPANSION
- ------------------------------------------
UED is responsible as project developer for facilitating the
Springerville Generating Station expansion project construction. The
Springerville Generating Station was originally designed for four units.
Springerville Unit 3 (Unit 3), and if constructed Unit 4, will each consist
of a 400 MW coal-fired, base-load generating facility at the same site as
Springerville Units 1 and 2. When Unit 3 (and possibly Unit 4) is built,
this would allow TEP to spread the fixed costs of the existing common
facilities over the additional generating unit (or units).
On October 21, 2003, Tri-State Generation and Transmission Association
(Tri-State) completed financing of Unit 3 and immediately began
construction. UED received reimbursement of its development costs totaling
$30 million, and an $11 million development fee. On October 24, 2003, the
proceeds were used to repay UniSource Energy's $35 million short-term
bridge loan. The $11 million development fee will be recognized as income
in the fourth quarter of 2003.
Once built, Tri-State will lease 100% of Unit 3 and take 300 MW of the
400 MW capacity. TEP will have operating responsibilities for Unit 3 and
will purchase 100 MW of Tri-State system capacity for no more than five
years from the time the plant begins commercial operation. UED expects
commercial operation of Unit 3 to occur in December 2006. SRP will
purchase 100 MW of capacity from Unit 3 under a 30 year power purchase
agreement and will have the right to construct and own Unit 4 at a later
date. If SRP decides to construct Unit 4, TEP would be required, along
with Tri-State, to exercise best efforts to find a replacement purchaser
for SRP to purchase 100 MW of capacity from Unit 3. If TEP and Tri-State
are unable to find such a replacement purchaser, TEP would then purchase
100 MW of output from Unit 4, beginning with the commercial operation of
Unit 4.
UED will continue to manage the development of Unit 3. Upon the
completion of construction in December 2006, TEP expects to receive annual
pre-tax benefits of approximately $15 million in the form of cost savings,
rental payments, transmission revenues, and other fees. TEP will also
benefit from upgraded emissions controls for Units 1 and 2, totaling
approximately $90 million, which will be paid for by the Unit 3 project.
OUTLOOK AND STRATEGIES
- ----------------------
Our financial prospects and outlook for the next few years will be
affected by many competitive, regulatory and economic factors. Our plans
and strategies include the following:
- Integrate UES' businesses with UniSource Energy's other businesses to
achieve the strategic and financial objectives of the acquisition.
- Oversee the construction of Springerville Unit 3 and continue to
enhance the value of existing assets by working with SRP to facilitate the
development of Springerville Unit 4.
- Enhance the value of TEP's transmission system while continuing to
provide reliable access to generation for TEP's retail customers and market
access for all generating assets. This will include focusing on completing
the Tucson - Nogales transmission line, which could eventually be connected
to Mexico's utility system and improve reliability for customers of UNS
Electric.
- Improve the value of our existing Millennium investments.
- Improve production and sales of Global Solar's thin-film photovoltaic
cells and seek strategic partners.
- Reduce TEP's debt as appropriate, using some of our excess cash flows.
- Efficiently manage TEP's generating resources and look for ways to
reduce or control our operating expenses while maintaining and enhancing
reliability and profitability.
To accomplish our goals, we estimate that during the fourth quarter of
2003, TEP will spend approximately $24 million on capital expenditures, UES
will spend approximately $8 million on capital expenditures, and Millennium
expects to fund its remaining $2 million commitment to its Energy
Technology Investments.
While we believe that our plans and strategies will continue to have a
positive impact on our financial prospects and position, we recognize that
we continue to be highly leveraged, and as a result, our access to the
capital markets may be limited or more expensive than for less leveraged
companies.
50
CRITICAL ACCOUNTING POLICIES
- ----------------------------
In preparing financial statements under Generally Accepted Accounting
Principles (GAAP), management exercises judgment in the selection and
application of accounting principles, including making estimates and
assumptions. UniSource Energy and TEP consider Critical Accounting
Policies to be those that could result in materially different financial
statement results if our assumptions regarding application of accounting
principles were different. UniSource Energy and TEP describe their
Critical Accounting Policies below. Other significant accounting policies
and recently issued accounting standards are discussed in the 2002 Annual
Report on Form 10-K, Note 1 of Notes to Consolidated Financial Statements -
Nature of Operations and Summary of Significant Accounting Policies.
ACCOUNTING FOR RATE REGULATION
TEP and UES generally use the same accounting policies and practices
used by unregulated companies for financial reporting under GAAP. However,
sometimes these principles, such as Statement of Financial Accounting
Standards No. 71, Accounting for the Effects of Certain Types of Regulation
(FAS 71), issued by the Financial Accounting Standards Board (FASB),
require special accounting treatment for regulated companies to show the
effect of regulation. For example, in setting TEP and UES' retail rates,
the ACC may not allow TEP or UES to currently charge its customers to
recover certain expenses, but instead requires that these expenses be
charged to customers in the future. In this situation, FAS 71 requires
that TEP and UES defer these items and show them as regulatory assets on
the balance sheet until TEP and UES are allowed to charge their customers.
TEP and UES then amortize these items as expense to the income statement as
those charges are recovered from customers. Similarly, certain revenue
items may be deferred as regulatory liabilities, which are also eventually
amortized to the income statement as rates to customers are reduced.
The conditions a regulated company must satisfy to apply the
accounting policies and practices of FAS 71 include:
- an independent regulator sets rates;
- the regulator sets the rates to recover specific costs of delivering
service; and
- The service territory lacks competitive pressures to reduce rates
below the rates set by the regulator.
TEP
In November 1999, upon approval by the ACC of the TEP Settlement
Agreement relating to recovery of TEP's transition costs and standard
retail rates, TEP discontinued application of FAS 71 to its generation
operations. TEP's distribution regulatory assets total $356 million at
September 30, 2003, $23 million of which are not presently included in the
rate base and consequently are not earning a return on investment.
TEP continues to apply FAS 71 to its regulated business, distribution
and transmission, and continues to assess whether it can apply FAS 71 to
these operations. If TEP stopped applying FAS 71 to its remaining
regulated operations, it would write off the related balances of its
regulatory assets as an expense on its income statement. Based on
regulatory asset balances at September 30, 2003, if TEP had stopped
applying FAS 71 to its remaining regulated operations, it would have
recorded an extraordinary loss, after-tax, of approximately $215 million.
While regulatory orders and market conditions may affect TEP's cash flows,
its cash flows would not be affected if it stopped applying FAS 71 unless a
regulatory order limited its ability to recover the cost of that regulatory
asset.
UES
UES' regulatory assets, net of regulatory liabilities, total $5
million at September 30, 2003. If UES stopped applying FAS 71 to its
regulated operations, it would write off the related balances of its
regulatory assets as an expense and would write off its regulatory
liabilities as income on its income statement. Based on the balances of
regulatory assets and liabilities at September 30, 2003, if UES had stopped
applying FAS 71 to its regulated operations, it would have recorded an
extraordinary loss, after-tax, of approximately $3 million. UES' cash
flows would not be affected if it stopped applying FAS 71 unless a
regulatory order limited its ability to recover the cost of that regulatory
asset.
TEP - ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
FAS 143, issued by the FASB in June 2001, requires entities to record
the fair value of a liability for a legal obligation to retire an asset in
the period in which the liability is incurred. A legal obligation is a
liability that a party is
51
required to settle as a result of an existing or enacted law, statute,
ordinance or contract. When the liability is initially recorded, the entity
should capitalize a cost by increasing the carrying amount of the related
long-lived asset. Over time, the liability is adjusted to its present value
by recognizing accretion expense as an operating expense in the income
statement each period, and the capitalized cost is depreciated over the useful
life of the related asset. Upon settlement of the liability, an entity either
settles the obligation for its recorded amount or incurs a gain or loss if the
actual costs differ from the recorded amount.
Prior to adopting FAS 143, costs for final removal of all owned
generation facilities were accrued as an additional component of
depreciation expense. Under FAS 143, only the costs to remove an asset
with legally binding retirement obligations will be accrued over time
through accretion of the asset retirement obligation and depreciation of
the capitalized asset retirement cost.
TEP has identified legal obligations to retire generation plant assets
specified in land leases for its jointly-owned Navajo and Four Corners
Generating Stations. The land on which these stations reside is leased
from the Navajo Nation. The provisions of the leases require the lessees
to remove the facilities upon request of the Navajo Nation at the
expiration of the leases. TEP also has certain environmental obligations
at the San Juan Generating Station. TEP has estimated that its share of
the cost to remove the Navajo and Four Corners facilities and settle the
San Juan environmental obligations will be approximately $38 million at the
date of retirement. No other legal obligations to retire generation plant
assets were identified. UES, Millennium and UED have no asset retirement
obligations.
TEP has various transmission and distribution lines that operate under
land leases and rights of way that contain end dates and restorative
clauses. TEP operates its transmission and distribution lines as if they
will be operated in perpetuity and would continue to be used or sold
without land remediation. As a result, TEP is not recognizing the costs of
final removal of the transmission and distribution lines in the financial
statements.
Upon adoption of FAS 143 on January 1, 2003, TEP recorded an asset
retirement obligation of $38 million at its net present value of $1.1
million, increased depreciable assets by $0.1 million for asset retirement
costs, reversed $112.8 million of costs previously accrued for final
removal from accumulated depreciation, reversed previously recorded
deferred tax assets by $44.2 million and recognized the cumulative effect
of accounting change as a gain of $111.7 million ($67.5 million net of
tax). TEP expects that adopting FAS 143 will result in a reduction to
current depreciation expense charged throughout the year as well because
asset retirement costs are no longer recorded as a component of
depreciation expense. For the first nine months of 2003, this amount is
approximately $4 million.
Amounts recorded under FAS 143 are subject to various assumptions and
determinations, such as determining whether a legal obligation exists to
remove assets, estimating the fair value of the costs of removal,
estimating when final removal will occur, and the credit-adjusted risk-free
interest rates to be used to discount future liabilities. Changes that may
arise over time with regard to these assumptions and determinations will
change amounts recorded in the future as expense for asset retirement
obligations.
If TEP retires any asset at the end of its useful life, without a
legal obligation to do so, it will record retirement costs at that time as
incurred or accrued. TEP does not believe that the adoption of FAS 143
will result in any change in retail rates since all matters relating to the
rate-making treatment of TEP's generating assets have been determined
pursuant to the TEP Settlement Agreement.
TEP - PAYMENT DEFAULTS AND ALLOWANCES FOR DOUBTFUL ACCOUNTS
We record an allowance for doubtful accounts when we determine that an
account receivable will not be collected. As a result of payment defaults
made by market participants in California, TEP's collection shortfall from
the CPX and CISO was approximately $9 million for sales made in 2000 and $7
million for sales made in 2001. Prior to 2003 and since December 31, 2001,
TEP had an allowance for doubtful accounts recorded for $8 million, or 50%
of these uncollected amounts based on the amount TEP believed would be
collected. In the first quarter of 2003, as a result of a FERC order, TEP
estimated that $6 million of its $16 million receivable will be collected.
Therefore, in the first quarter of 2003, TEP increased its reserve by $2.2
million by recording a reduction of wholesale revenues. The amount that
TEP ultimately collects would have an impact on earnings if the amount
received is more or less than the $6 million TEP has on its balance sheet.
If TEP collects all of the $16 million, pre-tax income will increase by $10
million. If TEP does not collect any of the $16 million, pre-tax income
will decrease by $6 million. In addition, TEP has cash collateral of
approximately $1 million on deposit in an escrow account with the CPX,
which is currently unavailable to TEP due to the CPX's bankruptcy stay.
Additionally, a FERC order recommended that Enron no longer be allowed
to trade and within a few days
52
thereafter, Enron was delisted from its stock exchange. As a result, in the
first quarter of 2003, TEP increased its reserve for sales to Enron by $0.4
million, to fully recover its $0.8 million receivable from Enron. At
September 30, 2003 and December 31, 2002, TEP's reserve for electric wholesale
accounts receivable on its balance sheet was approximately $11 million and
$8 million, respectively.
PENSION AND OTHER POSTRETIREMENT BENEFIT PLAN ASSUMPTIONS
TEP
TEP records plan assets, obligations, and expenses related to its
pension and other postretirement benefit plans based on actuarial
valuations. These valuations include key assumptions on discount rates,
expected returns on plan assets, compensation increases and health care
cost trend rates. These actuarial assumptions are reviewed annually and
modified as appropriate. The effect of modifications is generally recorded
or amortized over future periods. TEP believes that the assumptions used
in recording obligations under the plans are reasonable based on prior
experience, market conditions and the advice of plan actuaries.
TEP discounted its future pension and other postretirement plan
obligations using a rate of 6.75% at December 31, 2002, compared with 7.25%
at December 31, 2001. TEP determines the discount rate annually based on
the rates currently available on high-quality, long-term bonds. TEP looks
to bonds that receive one of the two highest ratings given by a recognized
rating agency and are expected to be available during the period to
maturity of the pension benefits. The pension liability and future pension
expense both increase as the discount rate is reduced. A decrease in the
discount rate results in an increase in the Projected Benefit Obligation
(PBO) and the service cost component of pension expense. Additionally, the
recognized actuarial loss is significantly impacted by a reduction in the
discount rate. Since the PBO increases with the decrease in discount rate,
the obligation is that much larger than would normally occur due to normal
growth of the plan. This leads to an actuarial loss (or a greater
actuarial loss than would occur in the absence of the discount rate
change), which is amortized over future periods leading to a greater
expense. The resulting change in the interest cost component of pension
expense is dependent on the effect that the change in the discount rate has
on the PBO and will vary based on employee demographics. The effect of the
lower rate used to calculate the interest cost is offset to some degree by
a larger obligation. The relative magnitude of these two changes
determines whether interest cost will increase or decrease. TEP's interest
cost increased slightly as a result of the decrease in the discount rate.
For TEP's pension plans, a 25 basis point decrease in the discount rate
would increase the accumulated benefit obligation by approximately $3.7
million and the related plan expense for 2003 by approximately $0.6
million. A similar increase in the discount rate would decrease the
accumulated benefit obligation by approximately $3.5 million and the
related plan expense for 2003 by approximately $0.6 million. For TEP's
plan for other postretirement benefits, a 25 basis point decrease in the
discount rate would increase the accumulated benefit obligation by
approximately $1.5 million and the related plan expense for 2003 by
approximately $0.1 million. A similar increase in the discount rate would
decrease the accumulated benefit obligation by approximately $1.5 million
and the related plan expense for 2003 by approximately $0.1 million.
TEP calculates the market-related value of plan assets using the fair
value of plan assets on the measurement date. At December 31, 2002, TEP
assumed that its plans' assets would generate a long-term rate of return of
8.75%. This rate is lower than the assumed rate of 9.0% used at December
31, 2001. In establishing its assumption as to the expected return on plan
assets, TEP reviews the plans' asset allocation and develops return
assumptions for each asset class based on advice from the plans' actuaries
that includes both historical performance analysis and forward looking
views of the financial markets. Pension expense increases as the expected
rate of return on plan assets decreases. A 25 basis point decrease in the
expected return on plan assets would increase pension expense for 2003 by
approximately $0.3 million. A similar increase in the expected return on
plan assets would decrease pension expense for 2003 by approximately $0.3
million.
In recognition of significant increases in health care costs, TEP
increased the initial health care cost trend rate used in valuing its
postretirement benefit obligation to 12.0% at December 31, 2002. The rate
assumed at December 31, 2001 was 8.5%. Assumed health care cost trend
rates have a significant effect on the amounts reported for health care
plans. A 1% increase in assumed health care cost trend rates would
increase the postretirement benefit obligation by approximately $5 million
and the related plan expense by approximately $1 million. A similar
decrease in assumed health care cost trend rates would decrease the
postretirement benefit obligation by approximately $4 million and the
related plan expense by approximately $1 million.
As reported in the 2002 Annual Report on Form 10-K, TEP recorded a
minimum pension liability of $6.7 million at December 31, 2002 primarily
due to current stock market conditions and a reduction in the assumed
discount rate.
53
Based on the above assumptions, TEP will record pension expense of
$8.5 million and other postretirement benefit expense of $6.6 million
ratably throughout 2003. TEP will make required pension plan contributions
of $2.8 million in 2003. TEP's other postretirement benefit plan is not
funded. TEP expects to make benefit payments to retirees under the
postretirement benefit plan of approximately $2 million in 2003.
UES
Concurrent with the acquisition of the Arizona gas and electric system
assets from Citizens on August 11, 2003, UES established a pension plan for
substantially all of its employees. UES did not assume the pension
obligation for employees' years of service with Citizens. UES performed an
actuarial valuation, as of the date of acquisition, to determine its
pension expense for the balance of 2003. A discount rate of 6.25% was
assumed based on rates available at that date. UES will record pension
expense of $0.4 million in 2003. The pension plan is not yet funded but all
required contributions will be made in accordance with minimum funding
standards.
On the acquisition date, UES assumed the obligation to provide
postretirement benefits for a small population of former Citizens
employees, both active and retired. The obligation has been recorded at a
discounted value of $2 million using a discount rate of 6.25%. The plan is
not funded. UES does not expect postretirement medical benefit expenses to
have a material impact on its operations. The expense for the remainder of
2003 is less than $0.1 million.
UES will use a measurement date of December 1 for both its pension and
other postretirement benefit plans, consistent with TEP's measurement date.
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND TRADING ACTIVITIES
A derivative financial instrument or other contract derives its value
from another investment or designated benchmark. TEP enters into forward
contracts to purchase or sell a specified amount of capacity or energy at a
specified price over a given period of time, typically for one month, three
months, or one year, within established limits to take advantage of
favorable market opportunities. The majority of TEP's forward contracts
are considered normal purchases and sales under FAS 133 and, therefore, are
not required to be marked to market. However, some of these forward
contracts are considered to be derivatives, which TEP marks to market under
FAS 133 by recording unrealized gains and losses and adjusting the related
assets and liabilities on a monthly basis to reflect the market prices at
the end of the month. TEP manages the risk of counterparty default by
performing financial credit reviews, setting limits monitoring exposures,
requiring collateral when needed, and using a standardized agreement which
allows for the netting of current period exposures to and from a single
counterparty.
UES does not currently have any contracts that are required to be
accounted for under FAS 133. UES does have a natural gas supply and
management agreement under which it purchases substantially all of its gas
requirements at market prices from BP. However, the contract terms allow
UES to lock in fixed prices on a portion of its gas purchases by entering
into fixed price forward contracts with BP at various times during the
year, which enables UES to provide more stable prices to its customers.
These purchases are made up to a year in advance with the goal of locking
in fixed prices on at least 30% of the expected monthly gas consumption
prior to entering into the month. These forward contracts, as well as the
main gas supply contract, meet the definition of normal purchases under FAS
133 and therefore are not required to be marked to market.
Because of the complexity of derivatives, the FASB established a
Derivatives Implementation Group (DIG). To date, the DIG has issued more
than 100 interpretations to provide guidance in applying FAS 133. As the
DIG or the FASB continues to issue interpretations, TEP and UES may change
the conclusions they have reached and, as a result, the accounting
treatment and financial statement impact could change in the future.
MEG enters into swap agreements, options and forward contracts
relating to Emission Allowances and coal. MEG also marks its trading
contracts to market under FAS 133 by recording unrealized gains and losses
on its trading activities and adjusting the related assets and liabilities
on a monthly basis to reflect the market prices at the end of the month.
The market prices used to determine fair value for TEP and MEG's
derivative instruments are estimated based on various factors including
broker quotes, exchange prices, over the counter prices and time value.
TEP reports its unrealized gain/loss on derivative forward sales net of its
unrealized gain/loss on derivative forward purchases as a component of
Operating Revenues. MEG reports its unrealized gain/loss on trading
activities net of its realized gain/loss on trading activities as a
component of Operating Revenues. The net pre-tax gain on TEP forward
contracts and MEG
54
trading activities for the three and nine months ended September 30, 2003,
was $0.9 million and $0.3 million, respectively. At September 30, 2003, the
fair value of TEP's derivative assets was less than $0.1 million and is
included in Other Current Assets on TEP's balance sheet. MEG's trading assets
and liabilities are reported in Trading Assets and Trading Liabilities on the
balance sheet. At September 30, 2003, the fair value of MEG's trading assets,
including its Emission Allowance inventory, was $29.2 million and the fair
value of MEG's trading liabilities was $23.2 million.
See Market Risks - Commodity Price Risk in Item 3.
UNBILLED REVENUE
TEP's and UES' retail revenues include an estimate of MWhs/therms
delivered but unbilled at the end of each period. The unbilled revenue is
estimated by comparing the actual MWhs/therms consumed to the MWhs/therms
billed to TEP and UES retail customers. The excess of MWhs/therms consumed
over MWhs/therms billed is then allocated to the retail customer classes
based on estimated usage by each customer class. TEP and UES then record
revenue for each customer class based on the various bill rates for each
customer class. Due to the seasonal fluctuations of TEP's actual load, the
unbilled revenue amount increases during the spring months and decreases
during the fall months. The unbilled revenue amount for UES gas sales
increases during the fall months and decreases during the spring months,
whereas, the unbilled revenue amount for UES electric sales increases
during the spring months and decreases during the fall months.
DEFERRED TAX VALUATION
We record deferred tax liabilities for amounts that will increase
income taxes on future tax returns. We record deferred tax assets for
amounts that could be used to reduce income taxes on future tax returns.
We record a valuation allowance, or reserve, for the deferred tax asset
amount that we may not be able to use on future tax returns. We estimate
the valuation allowance based on our interpretation of the tax rules, prior
tax audits, tax planning strategies, scheduled reversal of deferred tax
liabilities, and projected future taxable income.
TEP's valuation allowance of $15 million at September 30, 2003, which
reduces the Deferred Tax Asset balance, relates to net operating loss and
investment tax credit carryforward amounts. In the future, if TEP
determines that TEP would be able to use all or a portion of these amounts
on tax returns, then TEP would reduce the reserve and recognize a tax
benefit up to $15 million. Factors that could cause TEP to recognize the
tax benefit include new or additional guidance through tax regulations, tax
rulings, case law and/or the use of such benefits on future tax returns.
NEW ACCOUNTING PRONOUNCEMENTS
- -----------------------------
The FASB recently issued the following Statement of Financial Accounting
Standards (FAS) and FASB Interpretations (FIN):
- FIN 46, Consolidation of Variable Interest Entities, issued January
2003, expands upon existing guidance that addresses when a company should
include in its financial statements the assets and liabilities of another
entity. The primary objectives of FIN 46 are to provide guidance on the
identification of entities for which control is achieved through means
other than through voting rights (variable interest entities) and to
determine when and which business enterprises should consolidate the
variable interest entity (primary beneficiary). FIN 46 requires that both
the primary beneficiary and all other enterprises with a significant
variable interest make additional disclosures. The transitional disclosure
requirements of FIN 46 are effective immediately. The effective date of
the consolidation requirements of FIN 46 depends on the date the variable
interest entity was created. FIN 46 is effective for all variable interest
entities created after January 31, 2003. For variable interest entities
created before February 1, 2003, the provisions of FIN 46 were to be
applied to a variable interest entity for interim reporting periods
beginning after June 30, 2003. FIN 46 may now be applied to financial
periods beginning after December 15, 2003. Regardless of the
implementation date, the adoption of FIN 46 did not and is not expected to
have a significant impact on our financial statements.
- FAS 149, Amendment of Statement 133 on Derivative Instruments and
Hedging Activities, was issued by the FASB in April 2003. FAS 149 amends
and clarifies accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging
activities under FAS 133. FAS 149 is effective for contracts entered into
or modified after June 30, 2003, except as stated below, and for hedging
relationships designated after June 30, 2003. The guidance is to be
applied prospectively. The provisions of FAS 149 that relate to FAS 133
Implementation Issues that have been in effect for fiscal quarters that
began prior to June 15, 2003 are to
55
be applied in accordance with their respective effective dates. The
adoption of FAS 149 did not have a significant impact on our financial
statements.
- FAS 150, Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity, was issued by the FASB in
May 2003. FAS 150 improves the accounting for certain financial
instruments that, under previous guidance, issuers could account for as
equity. FAS 150's guidance requires that those instruments be classified
as liabilities. FAS 150 is effective immediately for financial instruments
entered into or modified after May 31, 2003 and to all other financial
instruments that exist beginning July 1, 2003. Although we currently have
no financial instruments recorded in equity that are required to be
reported as liabilities, should we enter into any such financial
instruments, we will comply with the requirements of FAS 150.
Additionally, the Emerging Issues Task Force (EITF) published Issue No.
01-08, Determining Whether An Arrangement Contains a Lease (EITF 01-08), in
May 2003. EITF 01-08 discusses how to determine whether an arrangement
contains a lease and states that the evaluation of whether an arrangement
conveys the right to use property, plant, or equipment should be based on
the substance of an arrangement and that the property that is the subject
of a lease must be specified (explicitly or implicitly) either at inception
of the arrangement or at the beginning of the lease term. EITF 01-08 is
effective for arrangements entered into or modified after July 1, 2003.
Since July 1, 2003, we have not entered into any new arrangements, or
modified any arrangements that would fall under this EITF; however, should
we enter into any such arrangements, we will comply with the requirements
of EITF 01-08.
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.
UniSource Energy and TEP are 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 for UniSource Energy or TEP 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 that are not statements of
historical facts. Forward-looking statements may be identified by the use
of words such as "anticipates," "estimates," "expects," "intends," "plans,"
"predicts," "projects," and similar expressions. From time to time, we 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 UniSource Energy or TEP, are expressly
qualified by these cautionary statements and any other cautionary
statements which may accompany the forward-looking statements. In
addition, UniSource Energy and TEP disclaim any obligation to update any
forward-looking statements to reflect events or circumstances after the
date of this report.
Forward-looking statements involve risks and uncertainties that could
cause actual results or outcomes to differ materially from those expressed
in the forward-looking statements. We express our expectations, beliefs
and projections in good faith and believe them to have a reasonable basis.
However, we make no assurances that management's expectations, beliefs or
projections will be achieved or accomplished. We have identified the
following important factors
that could cause actual results to differ materially from those discussed
in our forward-looking statements. These may be in addition to other
factors and matters discussed in other parts of this report:
1. Effects of restructuring initiatives in the electric industry and
other energy-related industries.
2. Effects of competition in retail and wholesale energy markets.
3. Changes in economic conditions, demographic patterns and weather
conditions in our retail service areas.
4. Supply and demand conditions in wholesale energy markets, including
volatility in market prices and illiquidity in markets, which are
affected by a variety of factors. These factors include the
availability of generating capacity in the western U.S., including
hydroelectric resources, weather, natural gas prices, the extent of
utility restructuring in various states, transmission constraints,
environmental restrictions and cost of compliance, and FERC regulation
of wholesale energy markets, and economic conditions in the western
U.S.
5. The creditworthiness of the entities with which we transact business
or have transacted business.
6. Changes affecting our cost of providing electrical and gas service
including changes in fuel costs, generating unit operating
performance, scheduled and unscheduled plant outages, interest rates,
tax laws, environmental laws, and the general rate of inflation.
56
7. Changes in governmental policies and regulatory actions with respect
to financing and rate structures.
8. Changes affecting the cost of competing energy alternatives, including
changes in available generating technologies and changes in the cost
of natural gas.
9. Changes in accounting principles or the application of such principles
to our businesses.
10. Market conditions and technological changes affecting UniSource
Energy's unregulated businesses.
11. Ability to successfully integrate UES' businesses and achieve expected
earnings.
12. Unanticipated changes in future liabilities relating to employee
benefit plans due to changes in market values of its retirement plan
assets and health care costs.
13. The outcome of any ongoing litigation.
14. Ability to obtain financing through debt and/or equity issuance, which
can be affected by various factors, including interest rate
fluctuations and capital market conditions.
15. Ability to develop and operate Springerville Generating Station Unit 3
and achieve anticipated cost savings.
ITEM 3. - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- -------------------------------------------------------------------------------
The information contained in this Item updates, and should be read in
conjunction with, information included in Part II, Item 7A in UniSource
Energy and TEP's Annual Report on Form 10-K for the year ended December 31,
2002, in addition to the interim condensed consolidated financial
statements and accompanying notes presented in Items 1 and 2 of this Form
10-Q.
MARKET RISKS
We are exposed to various forms of market risk. Changes in interest
rates, returns on marketable securities, and changes in commodity prices
may affect our future financial results. The market risks resulting from
changes in interest rates and returns on marketable securities have not
changed materially from the market risks reported in the 2002 Form 10-K.
For additional information concerning risk factors, including market risks,
see Safe Harbor for Forward-Looking Statements, above.
Risk Management Committee
We have a Risk Management Committee responsible for the oversight of
commodity price risk and credit risk related to the wholesale energy
marketing activities of TEP, the emissions and coal trading activities of
MEG, and the fuel procurement activities at TEP and UES. Our Risk
Management Committee consists of officers from the finance, accounting,
legal, wholesale marketing, and the generation operations departments of
UniSource Energy. To limit TEP's, UES' and MEG's exposure to commodity
price risk, the Risk Management Committee sets trading and hedging policies
and limits, which are reviewed frequently to respond to constantly changing
market conditions. To limit TEP's, UES' and MEG's exposure to credit risk,
the Risk Management Committee reviews counterparty credit exposure, as well
as credit policies and limits on a quarterly basis and as needed.
Commodity Price Risk
We are exposed to commodity price risk primarily relating to changes
in the market price of electricity, natural gas, coal and Emission
Allowances. To manage its exposure to energy price risk, TEP enters into
forward contracts to buy or sell energy at a specified price and future
delivery period. Generally, TEP commits to future sales based on expected
excess generating capability, forward prices and generation costs, using a
diversified market approach to provide a balance between long-term, mid-
term and spot energy sales. TEP generally enters into forward purchases
during its summer peaking period to ensure it can meet its load and reserve
requirements and account for other contract and resource contingencies.
TEP also enters into limited forward purchases and sales to optimize its
resource portfolio and take advantage of locational differences in price.
These positions are managed on both a volumetric and dollar basis and are
closely monitored using risk management policies and procedures overseen by
the Risk Management Committee. For
57
example, the risk management policies provide that TEP should not take a short
position in the third quarter and must have owned generation backing up all
forward sales positions at the time the sale is made. TEP's risk management
policies also restrict entering into forward positions with maturities
extending beyond the end of the next calendar year.
UES is also subject to commodity price risk, primarily from the
changes in the price of natural gas purchased for its UNS Gas customers.
This risk is mitigated through the PGA mechanism in UNS Gas' retail rates
which provides an adjustment to recover the actual costs of gas and
transportation. UNS Gas further reduces this risk by purchasing forward
fixed price contracts for a portion of its projected gas needs under its
Price Stabilization Plan. UNS Gas purchases between 30% and 80% of its
estimated gas needs in this manner.
UNS Electric is not exposed to commodity price risk for its purchase
of electricity as it has a fixed price full-requirements supply agreement
with PWCC through May 2008.
The majority of TEP's forward contracts are considered to be "normal
purchases and sales" of electric energy and are not considered to be
derivatives under Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging Activities (FAS 133).
TEP records revenues on its "normal sales" and expenses on its "normal
purchases" in the period in which the energy is delivered. From time to
time, however, TEP enters into forward contracts that meet the definition of a
derivative under FAS 133. When TEP has derivative forward contracts, it marks
them to market on a daily basis using actively quoted prices obtained from
brokers for power traded over-the-counter at Palo Verde and at other
southwestern U.S. trading hubs. TEP believes that these broker quotations used
to calculate the mark-to-market values represent accurate measures of the fair
values of TEP's positions, because of the short-term nature of TEP's positions,
as limited by risk management policies, and the liquidity in the short-term
market. As of September 30, 2003, all of TEP's derivative forward contracts
were for settlement within twelve months. To adjust the value of its derivative
forward contracts to fair value on its income statement, TEP recorded an
unrealized gain of $0.1 million and less than $0.1 million, respectively, on
its income statements for the quarter and nine months ended September 30,
2003. This compares with an unrealized gain of $0.1 million and an unrealized
gain of $0.8 million for the comparable periods in 2002. This demonstrates
the limited derivative forward contract activity conducted by TEP and the
limited impact on TEP's operating results and financial condition.
During the fourth quarter of 2001, MEG began managing and trading
Emission Allowances, coal and related instruments. We manage the market
risk of this line of business by setting notional limits by product, as
well as limits to the potential change in fair market value under a 33%
change in price or volatility. We closely monitor MEG's trading
activities, which include swap agreements, options and forward contracts,
using risk management policies and procedures overseen by the Risk
Management Committee. MEG marks its trading positions to market on a daily
basis using actively quoted prices obtained from brokers and options
pricing models for positions that extend through 2005. As of September 30,
2003 and December 31, 2002, the fair value of MEG's trading assets combined
with Emission Allowances it holds in escrow was $29.2 million and $15.1
million, respectively. During the first nine months of 2003, MEG reflected
a $2.6 million unrealized gain and a $2.4 million realized loss on its
income statement, compared with an unrealized gain of $0.2 million and a
realized loss of $0.3 million in the first nine months of 2002.
Unrealized Gain (Loss) of MEG's Trading Activities
- Millions of Dollars -
--------------------------------------------------------------------
Source of Fair Value Maturity Maturity Maturity over Total Unrealized
At September 30, 2003 0 - 6 mos. 6 - 12 mos. 1 yr. Gain (Loss)
----------------------------------------------------------------------------------------------------
Prices actively quoted $(0.2) $0.1 $0.4 $0.3
Prices provided by other
external sources - - - -
Prices based on models and
other valuation methods 2.0 0.5 0.1 2.6
----------------------------------------------------------------------------------------------------
Total $1.8 $0.6 $0.5 $2.9
====================================================================================================
Fuel Supply Risk
See MD&A, TEP Factors Affecting Results of Operations, Fuel Supply for
information on how TEP manages its fuel supply risks.
Credit Risk
UniSource Energy is exposed to credit risk in its energy-related
marketing and trading activities related to potential nonperformance by
counterparties. We manage the risk of counterparty default by performing
financial credit reviews,
58
setting limits monitoring exposures, requiring collateral when needed, and
using a standard agreement which allows for the netting of current period
exposures to and from a single counterparty. Despite such mitigation efforts,
there is a potential for defaults by counterparties. In the fourth quarter of
2000 and the first quarter of 2001, TEP was affected by payment defaults by SCE
and PG&E for amounts owed to the CPX and CISO. In the fourth quarter of 2001,
Enron defaulted on amounts owed to TEP for energy sales.
We calculate counterparty credit exposure by adding any outstanding
receivable (net of amounts payable if a netting agreement exists) to the
mark-to-market value of any forward contracts. As of September 30, 2003,
TEP's total credit exposure related to its wholesale marketing activities
(excluding defaulted amounts owed by the CPX, the CISO and Enron), was
approximately $4 million and MEG's total credit exposure related to its
trading activities was $7 million. TEP and MEG's credit exposure is
diversified across approximately 29 counterparties. Approximately $1
million of exposure is to non-investment grade companies.
UniSource Energy is also exposed to credit risk related to the sale of
assets owned by Nations Energy Corporation (Nations Energy). In September
2001, Nations Energy sold its 26% equity interest in a power project located
in Curacao, Netherlands Antilles to Mirant Curacao Investments, Ltd. (Mirant
Curacao) a subsidiary of Mirant Corporation (Mirant). Nations Energy received
$5 million in cash and an $11 million note receivable from Mirant Curacao.
The note was recorded at its net present value of $8 million using an 8%
discount rate, the discount being recognized as interest income over the
five-year life of the note. As of September 30, 2003, Nations Energy's
receivable from Mirant Curacao is approximately $9.7 million. The note is
included in Investments and Other Property - Other on UniSource Energy's
balance sheet. Payments on the note receivable are expected as follows:
$2 million in July 2004, $4 million in July 2005, and $5 million in July
2006. The note is guaranteed by Mirant Americas, Inc., a subsidiary of
Mirant. On July 14, 2003, Mirant, Mirant Americas, Inc. and various other
Mirant companies filed for Chapter 11 bankruptcy protection. Mirant Curacao
was not included in the Chapter 11 filings. Based on a review of the
projected cash flows for the power project, it appears Mirant Curacao will
have sufficient future cash flows to pay the note receivable and any
applicable interest. However, we cannot predict the ultimate outcome that
Mirant's bankruptcy will have on the collectibility of the note from Mirant
Curacao. Nations Energy will continue to evaluate the collectibility of the
receivable, but currently expects to collect the note in its entirety and has
not recorded any reserve for this note.
ITEM 4. - CONTROLS AND PROCEDURES
- -------------------------------------------------------------------------------
(a) Evaluation of Disclosure Controls and Procedures
As of September 30, 2003, the principal executive officer and
principal financial officer of UniSource Energy and TEP have evaluated
the effectiveness of the design and operation of UniSource Energy's
and TEP's disclosure controls and procedures (as defined in Rules 13a-
15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended
(Exchange Act)). Based upon that evaluation, the principal executive
officer and principal financial officer of UniSource Energy and TEP
have concluded that such disclosure controls are effective in timely
alerting them to any material information relating to UniSource
Energy's and TEP's reports filed or submitted with the SEC under the
Exchange Act.
(b) Changes in Internal Control Over Financial Reporting
There has been no change in UniSource Energy's or TEP's internal
control over financial reporting that occurred during UniSource
Energy's or TEP's most recent fiscal quarter that has materially
affected, or is reasonably likely to affect, UniSource Energy's or
TEP's internal control over financial reporting.
59
PART II - OTHER INFORMATION
ITEM 1. - LEGAL PROCEEDINGS
- -------------------------------------------------------------------------------
Springerville Generating Station Complaint
Environmental activist groups have expressed concerns regarding the
construction of any new units at the Springerville Generating Station. In
January 2003, environmental activist groups appealed an ACC Order affirming
the ACC's approval of the expansion at the Springerville Generating Station
to the Superior Court of the State of Arizona. On October 22, 2003, the
Superior Court affirmed the ACC's issuance of the Certificate of
Environmental Compatibility for Springerville. The Court granted TEP and
the ACC's motion for summary judgment in all respects and denied the motion
for summary judgment from the environmental activist groups. The
environmental activist groups have the right to appeal the decision of the
Superior Court to the Court of Appeals within 30 days after the date the
judgment is entered. It is not known at this time whether the
environmental activist groups will choose to file such an appeal.
Additionally, in November 2001, the Grand Canyon Trust (GCT) filed a
complaint in U.S. District Court, for the District of Arizona, against TEP
for alleged violations of the Clean Air Act at the Springerville Generating
Station. The complaint alleged that more stringent emission standards should
apply to Units 1 and 2 and that new permits and the installation of additional
facilities meeting Best Available Control Technology standards are required
for the continued operation of Units 1 and 2 in accordance with applicable
law. In 2002, the U.S. District Court granted TEP's motion for summary
judgment on one of the primary issues in the case: whether TEP commenced
construction within 18 months and/or by March 19, 1979, after the original
1977 air permit covering Units 1 and 2 was issued. The Court found that
TEP had commenced construction of the Springerville Generating Station in
the time periods required by the original permits. There were two
remaining allegations: that (a) TEP discontinued construction for a period
of 18 months or longer and did not complete construction in a reasonable
period of time, and (b) TEP did not commence construction, for purposes of
New Source Performance Standard applicability, by September 18, 1978. On
March 4, 2003, the U.S. District Court determined that the GCT had not
commenced the case on a timely basis and dismissed the case. The GCT has
appealed this decision to the U.S. Court of Appeals. TEP believes this
claim is without merit and intends to vigorously contest it.
Litigation and Claims Related to San Juan Generating Station
On May 16, 2002, the GCT and the Sierra Club filed a citizen lawsuit
under the Clean Air Act in federal district court in New Mexico against
Public Service Company of New Mexico (PNM), as operator of San Juan. TEP
owns 50% of San Juan Units 1 and 2, which equates to 19.8% of the total San
Juan Station. The lawsuit alleges two violations of the Clean Air Act and
related regulations and permits. One of the two claims, concerning the
initial permitting of San Juan, was dismissed by the court in August. The
remaining claim is scheduled to go to trial in November 2003 and contends
that PNM violated its present Title V operating permit by exceeding the 20%
opacity standard on numerous occasions between 1998 and 2002; opacity is a
means to monitor the particulate matter contained in an emission.
In September 2003, the New Mexico Environment Department (NMED)
notified PNM, operator of San Juan, of alleged excess emissions and opacity
in violation of the permits at San Juan. The NMED issued a draft
compliance order assessing unspecified civil penalties. PNM was invited
and will enter into discussions with the NMED concerning the alleged excess
emissions and opacity violations in the draft compliance order.
Based on the information available to date, we do not believe
resolution of these matters will be material to TEP.
Litigation Related to San Juan Coal Company
In August 2003, San Juan Coal Company, the coal supplier to San Juan,
entered into a settlement agreement with Dugan Production Corp. (Dugan).
The San Juan Coal Company, through leases with the federal government and
the State of New Mexico, owns coal interests with respect to an underground
mine. Dugan, through leases with the federal government, the State of New
Mexico and certain private parties, owns certain oil and gas interests in
portions of the land used for the underground mine. Dugan alleged that San
Juan Coal Company's underground coal mining operations have or will
interfere with Dugan's gas production and will reduce the amount of natural
gas that Dugan would otherwise be entitled to recover. The settlement
agreement provides that San Juan Coal Company will compensate Dugan for any
remaining gas production from a well when San Juan Coal Company determines
that mining activity is close enough to warrant shutting down a well.
Dugan agreed not to drill any additional wells. This settlement is not
expected to be material to TEP.
60
ITEM 5. - OTHER INFORMATION
- -------------------------------------------------------------------------------
DIRECTOR RESIGNATION
On September 30, 2003, Daniel W. L. Fessler resigned from the
UniSource Energy Corporation (UniSource Energy) and Tucson Electric Power
(TEP) Boards of Directors. Mr. Fessler, age 61, was a Board member since
1998 and served on the Corporate Governance and Nominating Committee and
Finance Committee.
ADDITIONAL FINANCIAL DATA
The following table reflects the ratio of earnings to fixed charges
for TEP:
9 Months Ended 12 Months Ended
September 30, September 30,
2003 2003
---- ----
Ratio of Earnings to Fixed Charges 1.51% 1.51%
APPROVAL OF NON-AUDIT SERVICES
On September 4, 2003, the Audit Committee of the Board of Directors of
UniSource Energy pre-approved an increase in the dollar amount to $575,000
for PricewaterhouseCoopers LLP to perform audit related services of the gas
and electric asset balances and results of operations for Citizens
Communications Company, located in Arizona.
SEC REPORTS AVAILABLE ON UNISOURCE ENERGY'S WEBSITE
UniSource Energy and TEP make available their annual reports on Form
10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all
amendments to those reports as soon as reasonably practicable after they
electronically file them with, or furnish them to, the SEC. These reports
are available free of charge through UniSource Energy's website address:
http://www.unisourceenergy.com. A link from UniSource Energy's website to
these SEC reports is accessible at the UniSource Energy main page.
Information contained at UniSource Energy's website is not part of any
report filed with, or furnished to, the SEC by UniSource Energy or TEP.
The SEC also maintains an Internet site that contains reports, proxy
and information statements, and other information regarding issuers that
file electronically with the SEC. The SEC website address is
http://www.sec.gov. Interested parties may also read and copy any
materials UniSource Energy and TEP file with the SEC at the SEC's Public
Reference Room at 450 Fifth Street, NW, Washington, DC 20549. Information
on the operation of the Public Reference Room is available by calling the
SEC at 1-800-SEC-0030.
61
ITEM 6. - EXHIBITS AND REPORTS ON FORM 8-K
- -------------------------------------------------------------------------------
(a) Exhibits.
See Exhibit Index.
(b) Reports on Form 8-K.
- UniSource Energy and TEP Form 8-K, dated August 20, 2003 regarding the
acquisition by UniSource Energy of the Citizens Arizona gas and
electric assets.
- UniSource Energy Form 8-K dated August 26, 2003 regarding the
acquisition by UniSource Energy of the Citizens Arizona gas and
electric assets.
- UniSource Energy Form 8-K dated October 2, 2003 regarding the
acquisition by UniSource Energy of the Citizens Arizona gas and
electric assets.
- UniSource Energy and TEP Form 8-K, dated October 23, 2003 furnished
pursuant to Item 12 "Disclosure of Results of Operations and Financial
Condition", announcing third quarter 2003 earnings for UniSource
Energy and TEP.
62
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
each registrant has duly caused this report to be signed on its behalf by
the undersigned thereunto duly authorized. The signature for each
undersigned company shall be deemed to relate only to matters having
reference to such company or its subsidiaries.
UNISOURCE ENERGY CORPORATION
------------------------------
(Registrant)
Date: November 10, 2003 /s/ Kevin P. Larson
------------------------------
Kevin P. Larson
Vice President and Principal
Financial Officer
TUCSON ELECTRIC POWER COMPANY
-------------------------------
(Registrant)
Date: November 10, 2003 /s/ Kevin P. Larson
-------------------------------
Kevin P. Larson
Vice President and Principal
Financial Officer
63
EXHIBIT INDEX
12 - Computation of Ratio of Earnings to Fixed Charges - TEP.
15 - Letter regarding unaudited interim financial information.
31(a) - Certification Pursuant to Section 302 of the Sarbanes-Oxley Act -
UniSource Energy, by James S. Pignatelli.
31(b) - Certification Pursuant to Section 302 of the Sarbanes-Oxley Act -
UniSource Energy, by Kevin P. Larson.
31(c) - Certification Pursuant to Section 302 of the Sarbanes-Oxley Act -
TEP, by James S. Pignatelli.
31(d) - Certification Pursuant to Section 302 of the Sarbanes-Oxley Act -
TEP, by Kevin P. Larson.
*32 - Statements of Corporate Officers (pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002).
*Pursuant to Item 601(b)(32)(ii) of Regulation S-k, this certificate is not
being filed for purposes of Section 18 of the Securities Act of 1934.
64