UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2006
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________.
Commission File Number | Registrant; State of Incorporation; Address; and Telephone Number | IRS Employer Identification Number |
| 1-13739 | UNISOURCE ENERGY CORPORATION (An Arizona Corporation) One South Church Avenue, Suite 100 Tucson, AZ 85701 (520) 571-4000 | 86-0786732 |
| 1-5924 | TUCSON ELECTRIC POWER COMPANY (An Arizona Corporation) One South Church Avenue, Suite 100 Tucson, AZ 85701 (520) 571-4000 | 86-0062700 |
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 a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
| UniSource Energy Corporation | Large Accelerated Filer X | Accelerated Filer__ | Non-accelerated filer__ |
| Tucson Electric Power Company | Large Accelerated Filer__ | Accelerated Filer__ | Non-accelerated filer X |
| Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). | |||
| UniSource Energy Corporation | Yes | No X | |
| Tucson Electric Power Company | Yes | No X | |
At August 4, 2006, 35,162,573 shares of UniSource Energy Corporation Common Stock, no par value (the only class of Common Stock), were outstanding.
At August 4, 2006, 32,139,435 shares of Tucson Electric Power Company’s common stock, no par value, were outstanding, all of which were held by UniSource Energy Corporation.
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.
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The abbreviations and acronyms used in the 2006 second quarter 10-Q are defined below:
| 1992 Mortgage | TEP’s Indenture of Mortgage and Deed of Trust, dated as of December 1, 1992, to the Bank of New York, successor trustee, as supplemented. |
| 1992 Mortgage Bonds | Bonds issued under the 1992 Mortgage. |
| ACC | Arizona Corporation Commission. |
| ACC Holding Company Order | The order approved by the ACC in November 1997 allowing TEP to form a holding company. |
| AMT | Alternative Minimum Tax. |
| Btu | British thermal unit(s). |
| 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. |
| 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. |
| Company or UniSource Energy | UniSource Energy Corporation. |
| 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. |
| 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. |
| Energy | The amount of power produced over a given period of time; measured in MWh. |
| EPA | The Environmental Protection Agency. |
| 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, as amended. |
| FAS 143 | Statement of Financial Accounting Standards No. 143: Accounting for Asset Retirement Obligations. |
| FERC | Federal Energy Regulatory Commission. |
| Fixed CTC | Competitive Transition Charge representing $0.009 that is included in TEP’s average retail rate of $0.083 per kWh. |
| Four Corners | Four Corners Generating Station. |
| Global Solar | Global Solar Energy, Inc., a company that develops and manufactures thin-film photovoltaic cells. Millennium sold its interest in Global Solar in March 2006. |
| Haddington | Haddington Energy Partners II, LP, a limited partnership that funds energy-related investments. |
| IPS | Infinite Power Solutions, Inc., a company that develops thin-film batteries. Millennium owns 31.4% of IPS. |
| IRS | Internal Revenue Service. |
| kWh | Kilowatt-hour(s). |
| kV | Kilovolt(s). |
| LIBOR | London Interbank Offered Rate. |
| Luna | Luna Energy Facility. |
| MEG | Millennium Environment Group, Inc., a wholly-owned subsidiary of Millennium, which manages and trades emission allowances and related financial instruments. |
| MicroSat | MicroSat Systems, Inc., a company formed to develop and commercialize small-scale satellites. Millennium sold its investment in MicroSat in January 2006. |
| Millennium | Millennium Energy Holdings, Inc., a wholly-owned subsidiary of |
| UniSource Energy. | |
| MMBtus | Million British Thermal Units. |
| MW | Megawatt(s). |
| MWh | Megawatt-hour(s). |
| Navajo | Navajo Generating Station. |
| NOL | Net Operating Loss carryback or carryforward for income tax purposes. |
| Phelps Dodge Decision | An Arizona Court of Appeals decision issued in 2005 that invalidated portions of the ACC’s Retail Electric Competition Rules. |
| PGA | Purchased Gas Adjuster, a retail rate mechanism designed to recover the cost of gas purchased for retail gas customers. |
| PPFAC | Purchased Power and Fuel Adjustment Clause. |
| PWCC | Pinnacle West Capital Corporation. |
| Rules | Retail Electric Competition Rules. |
| San Juan | San Juan Generating Station. |
| Settlement Agreement | TEP’s Settlement Agreement approved by the ACC in November 1999 that provided for electric retail competition and transition asset recovery. |
| Springerville | Springerville Generating Station. |
| Springerville Coal Handling Facilities Leases | Leveraged lease arrangements relating to the coal handling facilities serving Springerville. |
| Springerville Common Facilities | Facilities at Springerville used in common with Springerville Unit 1 and Springerville Unit 2 and partly by Springerville Unit 3. |
| Springerville Common Facilities Leases | Leveraged lease arrangements relating to an undivided one-half interest in certain Springerville Common Facilities. |
| Springerville Unit 1 | Unit 1 of the Springerville Generating Station. |
| Springerville Unit 1 Leases | Leveraged lease arrangements relating to Springerville Unit 1 and an undivided one-half interest in certain Springerville Common Facilities. |
| Springerville Unit 2 | Unit 2 of the Springerville Generating Station. |
| Springerville Unit 3 | Unit 3 of the Springerville Generating Station. |
| SRP | Salt River Project Agricultural Improvement and Power District. |
| Sundt | H. Wilson Sundt Generating Station (formerly known as the Irvington Generating Station). |
| SWG | Southwest Gas Corporation. |
| TEP | Tucson Electric Power Company, the principal subsidiary of UniSource Energy. |
| TEP Credit Agreement | Credit Agreement between TEP and a syndicate of banks, dated as of May 4, 2005. |
| TEP Guarantee Home Program | The TEP Home Guarantee Program provides incentives to new home builders to construct homes that meet the highest construction and energy-efficient standards available. |
| TEP Revolving Credit Facility | $60 million revolving credit facility entered into under the TEP Credit Agreement, dated as of May 4, 2005, between a syndicate of banks and TEP. |
| Therm | A unit of heating value equivalent to 100,000 British thermal units (Btu). |
| Track A | An order issued by the ACC in 2002 which eliminated the requirement in TEP’s Settlement Agreement that TEP transfer its generating assets to a subsidiary. |
| Track B | An order issued by the ACC in 2003 which defined a 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. |
| Tri-State | Tri-State Generation and Transmission Association. |
| 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 in 2003. | |
| UES 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 Citizens’ Arizona gas and electric assets. |
| UniSource Credit Agreement | Credit Agreement between UniSource Energy and a syndicate of banks, dated as of April 15, 2005. |
| UniSource Energy | UniSource Energy Corporation. |
| UNS Electric | UNS Electric, Inc., a wholly-owned subsidiary of UES, which acquired the Citizens Arizona electric utility assets in 2003. |
| UNS Gas | UNS Gas, Inc., a wholly-owned subsidiary of UES, which acquired the Citizens Arizona gas utility assets in 2003. |
| Valencia | Valencia power plant owned by UNS Electric. |
To the Board of Directors and Stockholders of
UniSource Energy Corporation:
We have reviewed the accompanying comparative condensed consolidated balance sheet of UniSource Energy Corporation and its subsidiaries (the Company) as of June 30, 2006, and the related comparative condensed consolidated statements of income for each of the three-month and six-month periods ended June 30, 2006 and 2005 and the comparative condensed consolidated statement of cash flows for the six-month periods ended June 30, 2006 and 2005 and the condensed consolidated statement of changes in stockholders' equity and comprehensive income for the six-month period ended June 30, 2006. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to 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 have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2005, and the related consolidated statements of income, of cash flows, of capitalization, of changes in stockholders' equity and comprehensive income for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005; and in our report dated March 3, 2006, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Chicago, Illinois
August 2, 2006
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Tucson Electric Power Company:
We have reviewed the accompanying comparative condensed consolidated balance sheet of Tucson Electric Power Company and its subsidiaries (the Company) as of June 30, 2006 and the related comparative condensed consolidated statements of income for each of the three-month and six-month periods ended June 30, 2006 and 2005 and the comparative condensed consolidated statement of cash flows for the six-month periods ended June 30, 2006 and 2005 and the condensed consolidated statement of changes in stockholder's equity and comprehensive income for the six-month period ended June 30, 2006. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to 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 the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2005, and the related consolidated statements of income, of cash flows, of capitalization, of changes in stockholders' equity and comprehensive income for the year then ended, and in our report dated March 3, 2006 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Chicago, Illinois
August 2, 2006
COMPARATIVE CONDENSED CONSOLIDATED STATEMENTS OF INCOME
| Three Months Ended | Six Months Ended | |||||||
| June 30, | June 30, | |||||||
2006 | 2005 | 2006 | 2005 | |||||
(Unaudited) | (Unaudited) | |||||||
| -Thousands of Dollars- | - Thousands of Dollars - | |||||||
Operating Revenues | ||||||||
$ 247,387 | $ 231,785 | Electric Retail Sales | $ 430,056 | $ 403,375 | ||||
34,639 | 37,871 | Electric Wholesale Sales | 91,302 | 77,051 | ||||
25,720 | 26,058 | Gas Revenue | 88,535 | 72,607 | ||||
10,650 | 3,579 | Other Revenues | 13,456 | 6,932 | ||||
318,396 | 299,293 | Total Operating Revenues | 623,349 | 559,965 | ||||
Operating Expenses | ||||||||
69,143 | 55,863 | Fuel | 119,359 | 103,154 | ||||
77,408 | 68,897 | Purchased Energy | 159,090 | 133,304 | ||||
61,735 | 58,133 | Other Operations and Maintenance | 115,550 | 117,916 | ||||
32,680 | 32,596 | Depreciation and Amortization | 63,437 | 66,664 | ||||
17,279 | 14,136 | Amortization of Transition Recovery Asset | 29,121 | 23,623 | ||||
12,360 | 12,402 | Taxes Other Than Income Taxes | 24,913 | 25,789 | ||||
270,605 | 242,027 | Total Operating Expenses | 511,470 | 470,450 | ||||
47,791 | 57,266 | Operating Income | 111,879 | 89,515 | ||||
Other Income (Deductions) | ||||||||
5,142 | 5,076 | Interest Income | 10,069 | 10,037 | ||||
1,987 | 1,649 | Other Income | 3,622 | 2,803 | ||||
(246) | (998) | Other Expense | (974) | (2,242) | ||||
6,883 | 5,727 | Total Other Income (Deductions) | 12,717 | 10,598 | ||||
Interest Expense | ||||||||
19,208 | 19,744 | Long-Term Debt | 37,892 | 40,096 | ||||
18,526 | 19,401 | Interest on Capital Leases | 37,073 | 39,147 | ||||
- | 5,427 | Loss on Reacquired Debt | - | 5,427 | ||||
1,267 | 664 | Other Interest Expense | 2,573 | 1,504 | ||||
(1,436) | (1,561) | Interest Capitalized | (3,348) | (2,390) | ||||
37,565 | 43,675 | Total Interest Expense | 74,190 | 83,784 | ||||
17,109 | 19,318 | Income from Continuing Operations before Income Taxes | 50,406 | 16,329 | ||||
7,111 | 8,239 | Income Tax Expense | 20,917 | 7,627 | ||||
9,998 | 11,079 | Income from Continuing Operations | 29,489 | 8,702 | ||||
- | (1,611) | Discontinued Operations - Net of Tax | (2,669) | (3,017) | ||||
$ 9,998 | $ 9,468 | Net Income | $ 26,820 | $ 5,685 | ||||
35,245 | 34,755 | Weighted-average Shares of Common Stock Outstanding (000) | 35,181 | 34,669 | ||||
Basic Earnings (Loss) per Share | ||||||||
$ 0.28 | $ 0.32 | Income from Continuing Operations | $ 0.84 | $ 0.25 | ||||
- | (0.05) | Discontinued Operations - Net of Tax | (0.08) | (0.09) | ||||
$ 0.28 | $ 0.27 | Net Income | $ 0.76 | $ 0.16 | ||||
Diluted Earnings (Loss) per Share | ||||||||
$ 0.28 | $ 0.28 | Income from Continuing Operations | $ 0.80 | $ 0.25 | ||||
- | (0.04) | Discontinued Operations - Net of Tax | (0.07) | (0.09) | ||||
$ 0.28 | $ 0.24 | Net Income | $ 0.73 | $ 0.16 | ||||
$ 0.21 | $ 0.19 | Dividends Declared per Share | $ 0.42 | $ 0.38 | ||||
See Notes to Condensed Consolidated Financial Statements.
UNISOURCE ENERGY CORPORATION
| Six Months Ended | |||||||
| June 30, | |||||||
2006 | 2005 | ||||||
(Unaudited) | |||||||
| -Thousands of Dollars- | |||||||
Cash Flows from Operating Activities | |||||||
Cash Receipts from Electric Retail Sales | $ | 438,716 | $ | 417,057 | |||
Cash Receipts from Electric Wholesale Sales | 132,098 | 104,229 | |||||
Cash Receipts from Gas Sales | 115,687 | 95,382 | |||||
MEG Cash Receipts from Trading Activity | 194 | 61,640 | |||||
Interest Received | 11,705 | 11,239 | |||||
Performance Deposits | 5,083 | 7,193 | |||||
Sale of Excess Emission Allowances | 3,716 | 5,018 | |||||
Income Tax Refunds Received | 553 | 1,484 | |||||
Other Cash Receipts | 3,608 | 4,041 | |||||
Fuel Costs Paid | (115,683 | ) | (99,108 | ) | |||
Purchased Energy Costs Paid | (187,974 | ) | (160,582 | ) | |||
Wages Paid, Net of Amounts Capitalized | (50,177 | ) | (50,483 | ) | |||
Payment of Other Operations and Maintenance Costs | (68,156 | ) | (81,992 | ) | |||
MEG Cash Payments for Trading Activity | (812 | ) | (63,943 | ) | |||
Capital Lease Interest Paid | (39,862 | ) | (39,744 | ) | |||
Taxes Paid, Net of Amounts Capitalized | (72,101 | ) | (69,699 | ) | |||
Interest Paid, Net of Amounts Capitalized | (33,724 | ) | (39,132 | ) | |||
Income Taxes Paid | (12,312 | ) | (5,689 | ) | |||
Excess Tax Benefit from Stock Option Exercises | (869 | ) | (1,874 | ) | |||
Net Cash Used by Operating Activities of Discontinued Operations | (2,710 | ) | (3,395 | ) | |||
Other Cash Payments | (2,014 | ) | (2,309 | ) | |||
Net Cash Flows – Operating Activities | 124,966 | 89,333 | |||||
Cash Flows from Investing Activities | |||||||
Capital Expenditures | (113,463 | ) | (89,910 | ) | |||
Sale of Subsidiary | 16,000 | - | |||||
Proceeds from Investment in Springerville Lease Debt | 10,028 | 8,251 | |||||
Return of Investment from Millennium Energy Business | 4,743 | 299 | |||||
Other Cash Receipts | 2,178 | 8,094 | |||||
Payments for Investment in Springerville Lease Equity | (48,025 | ) | - | ||||
Investment in and Loans to Equity Investees | (3,876 | ) | (1,150 | ) | |||
Net Cash Used by Investing Activities of Discontinued Operations | (46 | ) | (44 | ) | |||
Other Cash Payments | (1,487 | ) | - | ||||
Net Cash Flows - Investing Activities | (133,948 | ) | (74,460 | ) | |||
Cash Flows from Financing Activities | |||||||
Proceeds from Borrowings under Revolving Credit Facilities | 117,000 | 40,000 | |||||
Payments on Borrowings under Revolving Credit Facilities | (57,000 | ) | - | ||||
Proceeds from Issuance of Long-Term Debt | - | 240,000 | |||||
Repayments of Long-Term Debt | (2,500 | ) | (283,016 | ) | |||
Payments on Capital Lease Obligations | (50,580 | ) | (48,600 | ) | |||
Proceeds from Stock Options Exercised | 2,961 | 7,104 | |||||
Other Cash Receipts | 6,506 | 5,452 | |||||
Payment of Debt Issue/Retirement Costs | (140 | ) | (12,336 | ) | |||
Common Stock Dividends Paid | (14,715 | ) | (13,108 | ) | |||
Excess Tax Benefit from Stock Option Exercises | 869 | 1,874 | |||||
Other Cash Payments | (2,800 | ) | (3,032 | ) | |||
Net Cash Flows - Financing Activities | (399 | ) | (65,662 | ) | |||
| Net Decrease in Cash and Cash Equivalents | (9,381 | ) | (50,789 | ) | |||
| Cash and Cash Equivalents, Beginning of Year | 144,679 | 154,028 | |||||
Cash and Cash Equivalents, End of Period | $ | 135,298 | $ | 103,239 | |||
See Note 15 for supplemental cash flow information.
See Notes to Condensed Consolidated Financial Statements.
UNISOURCE ENERGY CORPORATION
| June 30, | December 31, | ||||||
2006 | 2005 | ||||||
(Unaudited) | |||||||
ASSETS | - Thousands of Dollars - | ||||||
Utility Plant | |||||||
Plant in Service | $ | 3,324,118 | $ | 3,167,900 | |||
Utility Plant under Capital Leases | 705,609 | 723,900 | |||||
Construction Work in Progress | 98,131 | 160,186 | |||||
Total Utility Plant | 4,127,858 | 4,051,986 | |||||
Less Accumulated Depreciation and Amortization | (1,445,620 | ) | (1,408,158 | ) | |||
Less Accumulated Amortization of Capital Lease Assets | (486,460 | ) | (472,367 | ) | |||
Total Utility Plant - Net | 2,195,778 | 2,171,461 | |||||
Investments and Other Property | |||||||
Investments in Lease Debt and Equity | 193,825 | 156,301 | |||||
Noncurrent Assets of Subsidiary Held for Sale | - | 13,065 | |||||
Other | 60,035 | 57,860 | |||||
Total Investments and Other Property | 253,860 | 227,226 | |||||
Current Assets | |||||||
Cash and Cash Equivalents | 135,298 | 144,679 | |||||
Trade Accounts Receivable | 112,120 | 99,338 | |||||
Unbilled Accounts Receivable | 57,226 | 53,920 | |||||
Allowance for Doubtful Accounts | (15,959 | ) | (15,037 | ) | |||
Materials and Fuel Inventory | 68,685 | 65,716 | |||||
Trading Assets | 15,549 | 36,418 | |||||
Current Regulatory Assets | 10,047 | 15,563 | |||||
Deferred Income Taxes - Current | 17,097 | 9,104 | |||||
Interest Receivable - Current | 8,869 | 9,830 | |||||
Current Assets of Subsidiary Held for Sale | - | 5,100 | |||||
Other | 15,871 | 17,717 | |||||
Total Current Assets | 424,803 | 442,348 | |||||
Regulatory and Other Assets | |||||||
Transition Recovery Asset | 138,490 | 167,611 | |||||
Income Taxes Recoverable Through Future Revenues | 38,040 | 39,936 | |||||
Other Regulatory Assets | 20,186 | 20,944 | |||||
Other Assets | 49,042 | 57,254 | |||||
Total Regulatory and Other Assets | 245,758 | 285,745 | |||||
Total Assets | $ | 3,120,199 | $ | 3,126,780 | |||
See Notes to Condensed Consolidated Financial Statements.
(Comparative Condensed Consolidated Balance Sheets Continued)
UNISOURCE ENERGY CORPORATION
COMPARATIVE CONDENSED CONSOLIDATED BALANCE SHEETS
| June 30, | December 31, | ||||||
2006 | 2005 | ||||||
(Unaudited) | |||||||
CAPITALIZATION AND OTHER LIABILITIES | - Thousands of Dollars - | ||||||
Capitalization | |||||||
Common Stock | $ | 694,184 | $ | 689,185 | |||
Accumulated Deficit | (53,756 | ) | (65,861 | ) | |||
Accumulated Other Comprehensive Loss | (14,532 | ) | (6,583 | ) | |||
Common Stock Equity | 625,896 | 616,741 | |||||
Capital Lease Obligations | 601,281 | 665,737 | |||||
Long-Term Debt | 1,209,920 | 1,212,420 | |||||
Total Capitalization | 2,437,097 | 2,494,898 | |||||
Current Liabilities | |||||||
Current Obligations under Capital Leases | 55,130 | 48,804 | |||||
Borrowing Under Revolving Credit Facilities | 65,000 | 5,000 | |||||
Current Maturities of Long-Term Debt | 5,000 | 5,000 | |||||
Accounts Payable | 81,481 | 98,085 | |||||
Income Taxes Payable | 27,051 | 29,826 | |||||
Interest Accrued | 44,610 | 57,386 | |||||
Trading Liabilities | 13,533 | 27,300 | |||||
Taxes Accrued | 35,702 | 34,978 | |||||
Accrued Employee Expenses | 17,177 | 16,052 | |||||
Customer Deposits | 16,818 | 15,463 | |||||
Current Liabilities of Subsidiary Held for Sale | - | 2,206 | |||||
Other | 7,881 | 3,933 | |||||
Total Current Liabilities | 369,383 | 344,033 | |||||
Deferred Credits and Other Liabilities | |||||||
Deferred Income Taxes - Noncurrent | 106,051 | 106,820 | |||||
Regulatory Liability - Net Cost of Removal for Interim Retirements | 83,152 | 78,535 | |||||
Noncurrent Liabilities of Subsidiary Held for Sale | - | (11,539 | ) | ||||
Other | 124,516 | 114,033 | |||||
Total Deferred Credits and Other Liabilities | 313,719 | 287,849 | |||||
Commitments and Contingencies (Note 6) | |||||||
Total Capitalization and Other Liabilities | $ | 3,120,199 | $ | 3,126,780 | |||
See Notes to Condensed Consolidated Financial Statements.
(Comparative Condensed Consolidated Balance Sheets Concluded)
UNISOURCE ENERGY CORPORATION
| Common Shares Issued* | Common Stock | Accumulated Deficit | Accumulated Other Comprehensive Loss | Total Stockholders' Equity | ||||||||||||
(Unaudited) - Thousands of Dollars - | ||||||||||||||||
Balances at December 31, 2005 | 34,874 | $ | 689,185 | $ | (65,861 | ) | $ | (6,583 | ) | $ | 616,741 | |||||
| Comprehensive Income: | ||||||||||||||||
| 2006 Year-to-Date Net Income | - | - | 26,820 | - | 26,820 | |||||||||||
| Unrealized Loss on Cash Flow Hedges | ||||||||||||||||
| (net of $5,082 income taxes) | - | - | - | (7,751 | ) | (7,751 | ) | |||||||||
| Reclassification of Unrealized Gain on | ||||||||||||||||
| Cash Flow Hedges to Net Income | ||||||||||||||||
| (net of $130 income taxes) | - | - | - | (198 | ) | (198 | ) | |||||||||
| Total Comprehensive Income | 18,871 | |||||||||||||||
| Dividends Declared | - | - | (14,715 | ) | - | (14,715 | ) | |||||||||
| Shares Issued under Stock Compensation Plans | 11 | - | - | - | - | |||||||||||
| Shares Issued for Stock Options | 196 | 2,960 | - | - | 2,960 | |||||||||||
| Tax Benefit Realized from Stock Options Exercised | - | 869 | - | - | 869 | |||||||||||
| Other | - | 1,170 | - | - | 1,170 | |||||||||||
Balances at June 30, 2006 | 35,081 | $ | 694,184 | $ | (53,756 | ) | $ | (14,532 | ) | $ | 625,896 | |||||
* UniSource Energy has 75 million authorized shares of common stock.
See Notes to Condensed Consolidated Financial Statements.
| Three Months Ended | Six Months Ended | |||||||
| June 30, | June 30, | |||||||
2006 | 2005 | 2006 | 2005 | |||||
(Unaudited) | (Unaudited) | |||||||
| - Thousands of Dollars - | - Thousands of Dollars - | |||||||
Operating Revenues | ||||||||
$ 208,093 | $ 195,470 | Electric Retail Sales | $ 357,027 | $ 335,676 | ||||
34,573 | 37,802 | Electric Wholesale Sales | 91,176 | 76,930 | ||||
9,967 | 3,607 | Other Revenues | 12,772 | 6,179 | ||||
252,633 | 236,879 | Total Operating Revenues | 460,975 | 418,785 | ||||
Operating Expenses | ||||||||
69,142 | 55,863 | Fuel | 119,358 | 103,154 | ||||
32,849 | 27,190 | Purchased Power | 46,004 | 40,051 | ||||
49,824 | 47,213 | Other Operations and Maintenance | 91,994 | 95,190 | ||||
28,231 | 27,934 | Depreciation and Amortization | 54,732 | 57,954 | ||||
17,279 | 14,136 | Amortization of Transition Recovery Asset | 29,121 | 23,623 | ||||
10,353 | 10,418 | Taxes Other Than Income Taxes | 20,840 | 21,567 | ||||
207,678 | 182,754 | Total Operating Expenses | 362,049 | 341,539 | ||||
44,955 | 54,125 | Operating Income | 98,926 | 77,246 | ||||
Other Income (Deductions) | ||||||||
4,301 | 4,903 | Interest Income | 8,590 | 9,719 | ||||
- | - | Interest Income - Note Receivable from UniSource Energy | - | 1,684 | ||||
1,309 | 1,142 | Other Income | 2,374 | 1,798 | ||||
(110) | (676) | Other Expense | (784) | (999) | ||||
5,500 | 5,369 | Total Other Income (Deductions) | 10,180 | 12,202 | ||||
Interest Expense | ||||||||
13,055 | 14,458 | Long-Term Debt | 25,704 | 31,437 | ||||
18,525 | 19,392 | Interest on Capital Leases | 37,064 | 39,129 | ||||
- | 5,427 | Loss on Reacquired Debt | - | 5,427 | ||||
897 | 467 | Other Interest Expense | 1,866 | 1,217 | ||||
(1,140) | (1,349) | Interest Capitalized | (2,761) | (2,009) | ||||
31,337 | 38,395 | Total Interest Expense | 61,873 | 75,201 | ||||
19,118 | 21,099 | Income Before Income Taxes | 47,233 | 14,247 | ||||
7,898 | 8,951 | Income Tax Expense | 19,426 | 6,789 | ||||
$ 11,220 | $ 12,148 | Net Income | $ 27,807 | $ 7,458 | ||||
See Notes to Condensed Consolidated Financial Statements.
TUCSON ELECTRIC POWER COMPANY
| Six Months Ended | |||||||
| June 30, | |||||||
2006 | 2005 | ||||||
(Unaudited) | |||||||
| -Thousands of Dollars- | |||||||
Cash Flows from Operating Activities | |||||||
Cash Receipts from Electric Retail Sales | $ | 363,390 | $ | 345,352 | |||
Cash Receipts from Electric Wholesale Sales | 132,098 | 104,165 | |||||
Interest Received | 9,522 | 10,906 | |||||
Interest Received -- UniSource | - | 11,013 | |||||
Sale of Excess Emission Allowances | 3,716 | 5,018 | |||||
Other Cash Receipts | 2,617 | 1,831 | |||||
Income Taxes Refunds Received | - | 713 | |||||
Fuel Costs Paid | (115,683 | ) | (99,108 | ) | |||
Purchased Power Costs Paid | (73,503 | ) | (59,609 | ) | |||
Wages Paid, Net of Amounts Capitalized | (38,880 | ) | (41,486 | ) | |||
Payment of Other Operations and Maintenance Costs | (59,782 | ) | (71,456 | ) | |||
Capital Lease Interest Paid | (39,853 | ) | (39,726 | ) | |||
Taxes Paid, Net of Amounts Capitalized | (51,657 | ) | (50,148 | ) | |||
Interest Paid, Net of Amounts Capitalized | (21,834 | ) | (33,948 | ) | |||
Income Taxes Paid | (10,675 | ) | (8,000 | ) | |||
Other Cash Payments | (1,283 | ) | (1,797 | ) | |||
Net Cash Flows – Operating Activities | 98,193 | 73,720 | |||||
Cash Flows from Investing Activities | |||||||
Capital Expenditures | (81,635 | ) | (67,410 | ) | |||
Payments for Investment in Springerville Lease Equity | (48,025 | ) | - | ||||
Proceeds from Investment in Springerville Lease Debt | 10,028 | 8,251 | |||||
Other Cash Payments | (1,004 | ) | - | ||||
Other Cash Receipts | - | 6,708 | |||||
Net Cash Flows - Investing Activities | (120,636 | ) | (52,451 | ) | |||
Cash Flows from Financing Activities | |||||||
Proceeds from Borrowings under Revolving Credit Facility | 105,000 | 40,000 | |||||
Equity Investment from UniSource Energy | - | 110,000 | |||||
Proceeds from Repayment of UniSource Energy Note | - | 95,393 | |||||
Repayments of Long-Term Debt | - | (281,766 | ) | ||||
Payments on Capital Lease Obligations | (50,538 | ) | (48,560 | ) | |||
Payments on Borrowings under Revolving Credit Facility | (45,000 | ) | - | ||||
Other Cash Receipts | 9,209 | 2,863 | |||||
Payment of Debt Issue/Retirement Costs | (140 | ) | (5,203 | ) | |||
Other Cash Payments | (494 | ) | (858 | ) | |||
Net Cash Flows - Financing Activities | 18,037 | (88,131 | ) | ||||
| Net Decrease in Cash and Cash Equivalents | (4,406 | ) | (66,862 | ) | |||
| Cash and Cash Equivalents, Beginning of Year | 53,433 | 113,207 | |||||
Cash and Cash Equivalents, End of Period | $ | 49,027 | $ | 46,345 | |||
See Note 15 for supplemental cash flow information.
See Notes to Condensed Consolidated Financial Statements.
TUCSON ELECTRIC POWER COMPANY
| June 30, | December 31, | ||||||
2006 | 2005 | ||||||
(Unaudited) | |||||||
ASSETS | - Thousands of Dollars - | ||||||
Utility Plant | |||||||
Plant in Service | $ | 2,978,218 | $ | 2,861,511 | |||
Utility Plant under Capital Leases | 704,904 | 723,195 | |||||
Construction Work in Progress | 79,247 | 132,427 | |||||
Total Utility Plant | 3,762,369 | 3,717,133 | |||||
Less Accumulated Depreciation and Amortization | (1,407,649 | ) | (1,378,362 | ) | |||
Less Accumulated Amortization of Capital Lease Assets | (486,195 | ) | (472,149 | ) | |||
Total Utility Plant - Net | 1,868,525 | 1,866,622 | |||||
Investments and Other Property | |||||||
Investments in Lease Debt and Equity | 193,825 | 156,301 | |||||
Other | 27,360 | 26,405 | |||||
Total Investments and Other Property | 221,185 | 182,706 | |||||
Current Assets | |||||||
Cash and Cash Equivalents | 49,027 | 53,433 | |||||
Trade Accounts Receivable | 94,888 | 78,487 | |||||
Unbilled Accounts Receivable | 43,682 | 29,658 | |||||
Allowance for Doubtful Accounts | (14,861 | ) | (14,528 | ) | |||
Intercompany Accounts Receivable | 5,882 | 5,807 | |||||
Materials and Fuel Inventory | 60,571 | 57,815 | |||||
Current Regulatory Assets | 10,047 | 9,663 | |||||
Deferred Income Taxes - Current | 15,771 | 10,684 | |||||
Interest Receivable - Current | 8,651 | 9,747 | |||||
Trading Assets | 6,856 | 12,338 | |||||
Other | 11,094 | 10,240 | |||||
Total Current Assets | 291,608 | 263,344 | |||||
Regulatory and Other Assets | |||||||
Transition Recovery Asset | 138,489 | 167,611 | |||||
Income Taxes Recoverable Through Future Revenues | 38,040 | 39,936 | |||||
Other Regulatory Assets | 19,809 | 20,634 | |||||
Other Assets | 32,127 | 34,582 | |||||
Total Regulatory and Other Assets | 228,465 | 262,763 | |||||
Total Assets | $ | 2,609,783 | $ | 2,575,435 | |||
See Notes to Condensed Consolidated Financial Statements.
(Comparative Condensed Consolidated Balance Sheets Continued)
TUCSON ELECTRIC POWER COMPANY
COMPARATIVE CONDENSED CONSOLIDATED BALANCE SHEETS
| June 30, | December 31, | ||||||
2006 | 2005 | ||||||
(Unaudited) | |||||||
CAPITALIZATION AND OTHER LIABILITIES | - Thousands of Dollars - | ||||||
Capitalization | |||||||
Common Stock | $ | 795,971 | $ | 795,971 | |||
Capital Stock Expense | (6,357 | ) | (6,357 | ) | |||
Accumulated Deficit | (196,578 | ) | (224,385 | ) | |||
Accumulated Other Comprehensive Loss | (14,126 | ) | (6,583 | ) | |||
Common Stock Equity | 578,910 | 558,646 | |||||
Capital Lease Obligations | 600,887 | 665,299 | |||||
Long-Term Debt | 821,170 | 821,170 | |||||
Total Capitalization | 2,000,967 | 2,045,115 | |||||
Current Liabilities | |||||||
Current Obligations under Capital Leases | 55,041 | 48,718 | |||||
Borrowing Under Revolving Credit Facility | 60,000 | - | |||||
Accounts Payable | 62,288 | 62,974 | |||||
Intercompany Accounts Payable | 12,437 | 9,362 | |||||
Income Taxes Payable | 18,615 | 17,111 | |||||
Interest Accrued | 37,292 | 50,230 | |||||
Taxes Accrued | 29,623 | 27,260 | |||||
Accrued Employee Expenses | 15,574 | 14,585 | |||||
Trading Liabilities | 7,532 | 2,923 | |||||
Other | 11,946 | 10,687 | |||||
Total Current Liabilities | 310,348 | 243,850 | |||||
Deferred Credits and Other Liabilities | |||||||
Deferred Income Taxes - Noncurrent | 125,388 | 119,895 | |||||
Regulatory Liability - Net Cost of Removal for Interim Retirements | 78,560 | 74,825 | |||||
Other | 94,520 | 91,750 | |||||
Total Deferred Credits and Other Liabilities | 298,468 | 286,470 | |||||
Commitments and Contingencies (Note 6) | |||||||
Total Capitalization and Other Liabilities | $ | 2,609,783 | $ | 2,575,435 | |||
See Notes to Condensed Consolidated Financial Statements.
(Comparative Condensed Consolidated Balance Sheets Concluded)
TUCSON ELECTRIC POWER COMPANY
Common Stock | Capital Stock Expense | Accumulated Deficit | Accumulated Other Comprehensive Loss | Total Stockholder's Equity | ||||||||||||
(Unaudited) - Thousands of Dollars - | ||||||||||||||||
Balances at December 31, 2005 | $ | 795,971 | $ | (6,357 | ) | $ | (224,385 | ) | $ | (6,583 | ) | $ | 558,646 | |||
| Comprehensive Income: | ||||||||||||||||
| 2006 Year-to-Date Net Income | - | - | 27,807 | - | 27,807 | |||||||||||
| Unrealized Loss on Cash Flow Hedges | ||||||||||||||||
| (net of $4,816 income taxes) | - | - | - | (7,345 | ) | (7,345 | ) | |||||||||
| Reclassification of Unrealized Gain on | ||||||||||||||||
| Cash Flow Hedges to Net Income | ||||||||||||||||
| (net of $130 income taxes) | - | - | - | (198 | ) | (198 | ) | |||||||||
| Total Comprehensive Income | 20,264 | |||||||||||||||
Balances at June 30, 2006 | $ | 795,971 | $ | (6,357 | ) | $ | (196,578 | ) | $ | (14,126 | ) | $ | 578,910 | |||
See Notes to Condensed Consolidated Financial Statements.
UniSource Energy Corporation (UniSource Energy) is a holding company that has no significant operations of its own. Operations are conducted by UniSource Energy’s subsidiaries, each of which is a separate legal entity with its own assets and liabilities. UniSource Energy owns the common stock of Tucson Electric Power Company (TEP), 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 84% of UniSource Energy’s assets as of June 30, 2006. TEP generates, transmits and distributes electricity. TEP serves 385,000 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.
UES holds the common stock of UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric). UES has no significant operations of its own. UNS Gas is a gas distribution company serving approximately 142,000 retail customers in Mohave, Yavapai, Coconino, and Navajo Counties in northern Arizona, as well as Santa Cruz County in southeast Arizona. UNS Electric is an electric transmission and distribution company serving approximately 92,000 retail customers in Mohave and Santa Cruz Counties.
Millennium invests in unregulated businesses. On March 31, 2006, UniSource Energy completed the sale of all of the capital stock of Global Solar Energy, Inc. (Global Solar), previously Millennium’s largest holding. See Note 7. UED engages in developing generating resources and other project development activities, including facilitating the expansion of the Springerville Generating Station, but has no significant operations.
We conduct our business in three primary business segments - TEP’s Electric Utility segment, UNS Gas, and UNS Electric.
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 2005 Annual Report on Form 10-K.
Weather, among other factors, causes seasonal fluctuations in TEP, UNS Gas and UNS Electric’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. The sale of Global Solar is reflected as discontinued operations in UniSource Energy’s financial statements and prior periods have been restated to conform to the current presentation. See Note 7. These reclassifications had no effect on Net Income.
REGULATORY ACCOUNTING
TEP, UNS Gas and UNS Electric 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, UNS Gas and UNS Electric’s retail rates, the Arizona Corporation Commission (ACC) may not allow TEP, UNS Gas or UNS Electric to currently charge their customers to recover certain expenses, but instead may require that these expenses be charged to customers in the future. In this situation, FAS 71 requires
that TEP, UNS Gas and UNS Electric defer these items and show them as regulatory assets on the balance sheet until TEP, UNS Gas and UNS Electric are allowed to charge their customers. TEP, UNS Gas and UNS Electric then amortize these items as expense to the income statement as these 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.
IMPLICATIONS OF DISCONTINUING APPLICATION OF FAS 71
TEP
Upon approval by the ACC of a settlement agreement (Settlement Agreement) in November 1999, TEP discontinued application of FAS 71 for its generation operations. TEP continues to apply FAS 71 to its cost-based rate regulated operations, which include the transmission and distribution portions of its business.
TEP’s transmission and distribution regulatory assets, net of regulatory liabilities, totaled $128 million at June 30, 2006 and $163 million at December 31, 2005. Regulatory assets of $30 million are not presently included in rate base and consequently are not earning a return on investment. These regulatory assets are being recovered through the cost of service or are authorized to be collected in future base rates.
TEP regularly assesses whether it can continue to apply FAS 71 to its cost-based rate regulated operations. If TEP stopped applying FAS 71 to these operations, it would write off the related balances of its regulatory assets as an expense and its regulatory liabilities as income on its income statement. Based on the regulatory asset balances, net of regulatory liabilities, at June 30, 2006, if TEP had stopped applying FAS 71 to its remaining cost-based rate regulated operations, it would have recorded an extraordinary after-tax loss of $77 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.
UNS Gas and UNS Electric
UNS Gas and UNS Electric’s regulatory liabilities exceeded their regulatory assets by $14 million at June 30, 2006. At December 31, 2005, UNS Gas and UNS Electric’s regulatory liabilities exceeded their regulatory assets by $4 million. As of June 30, 2006, UNS Electric has $7 million of regulatory liabilities that are not included in rate base. If UNS Gas and UNS Electric stopped applying FAS 71 to their regulated operations, they would write off the related balances of their regulatory assets as an expense and would write off their regulatory liabilities as income on their income statements. Based on the regulatory asset and liability balances, if UNS Gas and UNS Electric had stopped applying FAS 71 to their regulated operations, they would have recorded an extraordinary after-tax gain of $9 million at June 30, 2006. UNS Gas and UNS Electric’s cash flows would not be affected if they stopped applying FAS 71.
RECENT REGULATORY ACTION
TEP
Settlement Agreement
In 1999, the ACC approved the Rules that provided a framework for the introduction of retail electric competition in Arizona, as well as the Settlement Agreement between TEP and certain customer groups related to the implementation of retail electric competition in Arizona.
The Rules and the Settlement Agreement established:
| · | a period from November 1999 through 2008 for TEP to transition its generation assets from a cost of service based rate structure to a market, or competitive, rate structure; |
| · | the recovery through rates during the transition period of $450 million of stranded generation costs through a fixed competitive transition charge (fixed CTC); |
| · | capped rates for TEP retail customers through 2008; |
| · | an ACC interim review of TEP retail rates in 2004; |
| · | unbundling of electric services with separate rates or prices for generation, transmission, distribution, metering, meter reading, billing and collection, and ancillary services; |
| · | a process for energy service providers (ESPs) to become licensed by the ACC to sell generation services at market prices to TEP retail customers; |
| · | access for TEP retail customers to buy market priced generation services from ESPs beginning in 2000 (currently, no TEP customers are purchasing generation services from ESPs); |
| · | transmission and distribution services would remain subject to regulation on a cost of service basis; and |
| · | beginning in 2009, TEP’s generation would be market based and its retail customers would pay the market rate for generation services. |
2004 General Rate Case Information
In June 2004, as required by the Settlement Agreement, TEP filed general rate case information with the ACC. TEP’s filing did not propose any change in retail rates, and under the terms of the Settlement Agreement, no rate case filed by TEP through 2008 may result in a net rate increase. However, absent the restriction on raising rates, TEP believes that the data in its filing would justify an increase in retail rates of 16%.
The general rate case information used a historical test year ended December 31, 2003 and established, based on TEP’s standard offer service, that TEP was experiencing a revenue deficiency of $111 million. None of the intervenor testimony filed proposed any increase or decrease to TEP’s rates. Testimony filed by the ACC Staff, Residential Utility Consumer Office and Arizonans for Electric Choice and Competition indicated revenue deficiencies for TEP of $67 million, $32 million and $38 million, respectively. In July 2005, the ALJ issued a procedural order suspending the remaining testimony filing deadlines and hearing in the 2004 rate review.
ACC Order to Review the Settlement Agreement
In response to the recent court ruling related to retail competition and related market pricing and a lack of agreement as to the interpretation of the Settlement Agreement by a number of participants in TEP’s rate proceedings, TEP filed a series of pleadings with the ACC beginning in May 2005 to resolve the uncertainty surrounding the methodology that will be applied to determine TEP’s rates for generation service after 2008.
In September 2005, TEP filed a motion and supporting testimony with the ACC to amend the Settlement Agreement. In the motion, TEP proposed amendments to extend the benefits and protections set forth in the Settlement Agreement and provide additional price stability for TEP customers.
In April 2006, the ACC ordered that a procedure be established to allow for an expeditious and complete review of the Settlement Agreement; its effect on how TEP’s rates for generation services will be determined after December 31, 2008; TEP’s proposed amendments to the Settlement Agreement; and demand side management, renewable energy standards, and time of use tariffs.
The ALJ issued a procedural order on June 2, 2006, adopting the following schedule:
Filing | Date |
| TEP testimony | August 18, 2006 |
| ACC staff and intervenor testimony | November 17, 2006 |
| TEP rebuttal testimony | December 6, 2006 |
| ACC staff and intervenor rebuttal testimony | December 18, 2006 |
| TEP rejoinder testimony | December 29, 2006 |
| Hearings before ALJ | January 8, 2007 |
The procedural order states that the hearing shall consider the legal argument and factual basis of whether TEP is entitled to charge market-based rates or cost-of-service based generation rates commencing in 2009,
whether TEP’s proposal as outlined in its application to amend the Settlement Agreement is in the public interest, and how the ACC can/should implement demand-side management, renewable energy standards and time of use tariffs.
The procedural order also states that, at this juncture, it is uncertain that the ACC can make a final determination that would implement rates in a single proceeding. Much will depend on whether the parties are able to reach agreement and the decision whether market or cost-of-service rates will be implemented in 2009. The procedural order states that, by proceeding as quickly as possible, there should be ample time to resolve all issues prior to December 31, 2008.
The procedural order directs TEP to file testimony which at a minimum shall include:
| · | a complete explanation of its proposal, including an identification of all rate elements that it believes would apply to each of its standard offer customers effective January 1, 2009; |
| · | projected rate impacts on standard offer customers’ total bills having market-based generation rates as compared with cost-of-service generation rates; |
| · | an explanation of how its proposals could be effective and lawful under the Track A, Track B and Phelps Dodge decisions; and |
| · | how TEP proposes to implement demand side management, renewable energy standards and time of use tariffs. |
TEP cannot predict the outcome of the proceedings.
UNS Gas
Energy Cost Adjustment Mechanism
In August 2005, UNS Gas filed a request with the ACC to approve an increase in the PGA surcharge from $0.03 per therm to $0.27 per therm to be effective October 1, 2005. An increase was necessary to allow for the recovery of the existing PGA bank balance and recover projected costs of gas during the winter season.
In October 2005, the ACC approved the following PGA surcharges:
Surcharge Amount Per Therm | Period In Effect |
| $0.15 | November 2005 - February 2006 |
| $0.25 | March 2006 - April 2006 |
| $0.30 | May 2006 - June 2006 |
| $0.35 | July 2006 - September 2006 |
| $0.25 | October 2006 - November 2006 |
| $0.20 | December 2006 - February 2007 |
| $0.25 | March 2007 - April 2007 |
Changes in the market price for gas, sales volumes and surcharge changes could significantly change the PGA bank balance in the future. At June 30, 2006, the PGA bank balance was over collected by $3 million.
General Rate Case Filing
UNS Gas current rates have been in place since August 2003, and were designed to provide a 9.05% return on original cost rate base of $118 million. As a result of increased growth in UNS Gas’ service territory and the related increase in capital expenditures and operating costs, such current rates are inadequate for UNS Gas to recover its costs and earn a reasonable rate of return on its investment. In July 2006, UNS Gas filed a general rate case. Below is a table that summarizes UNS Gas’ request:
| Test year | Year ended December 31, 2005 |
| Original cost rate base | $162 million |
| Revenue deficiency | $10 million |
| Total rate increase (over test year revenues) | 7% |
| Cost of debt | 6.60% |
| Cost of equity | 11.00% |
| Hypothetical capital structure | 50% equity / 50% debt |
| Weighted average cost of capital | 8.80% |
UNS Gas also requested modifications to its PGA mechanism to help address problems posed by volatile gas prices, inappropriate price signals to customers and the potential for over or under collections to result in the accumulation of large bank balances. UNS Gas expects the ACC to rule on its rate case in the second half of 2007. Under the terms of the UES Settlement Agreement, new rates cannot go into effect before August 1, 2007.
SPRINGERVILLE UNIT 1 LEASE EQUITY
In June 2006, TEP purchased a 14% equity ownership interest in the Springerville Unit 1 Lease for $48 million. TEP is now an owner participant under the leveraged lease arrangements relating to such undivided interest. As a result, TEP amended the Springerville Unit 1 Lease relating to such undivided interest to reduce TEP’s rent payable to equal the scheduled amount of principal and interest payable on the debt issued by the owner trustee, and recorded a $19 million reduction to the capital lease obligation and capital lease asset.
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 was required to arrange for refinancing or refunding of the secured notes underlying the leases prior to June 30, 2006 in order to avoid a special event of loss. A special event of loss results in a termination of the leases and would require TEP to repurchase the facilities for approximately $125 million. TEP refinanced the lease debt totaling $68 million in June 2006, and the leases were amended to remove the requirement that the notes be periodically refinanced to avoid the occurrence of a special event of loss. The notes were amended to provide that interest will be payable at LIBOR plus 1.5% for the next three years with the spread over LIBOR increasing every three years thereafter to 2% by June 2018. Prior to the refinancing, the interest rate was LIBOR plus 4%. The refinancing had no impact on the Springerville Common Facilities capital lease obligation or asset.
A portion of the rent payable by TEP pursuant to the Springerville Common Facilities Leases is determined by the amount of interest payable on the variable rate lease debt. In June 2006, TEP entered into an interest rate swap to hedge a portion of the interest rate risk associated with the portion of rent determined by the interest rate on this debt. This swap has the effect of fixing the interest portion of rent at a rate of 7.27% on $37 million of the lease debt. The interest rate swap has been recorded by TEP as a cash flow hedge for financial reporting purposes. See Note 5.
TEP CREDIT AGREEMENT
In June 2006, TEP borrowed $45 million under the $60 million revolving credit facility available under its Credit Agreement. Together with the $15 million previously outstanding, the facility was fully drawn at June 30, 2006.
UNS GAS/UNS ELECTRIC REVOLVER
In June 2006, UniSource Energy made a $10 million equity contribution to UNS Electric, and UNS Electric repaid $7 million under the UNS Gas/UNS Electric Revolver. At June 30, 2006, $5 million remained outstanding under the UNS Gas/UNS Electric Revolver.
Based on the way we organize our operations and evaluate performance, we have three reportable segments:
(1) TEP, a vertically integrated electric utility business, is UniSource Energy’s largest subsidiary.
(2) UNS Gas is a regulated gas distribution utility business.
(3) UNS Electric is a regulated electric distribution utility business.
UniSource Energy, UES and Millennium are holding companies. UED and several other subsidiaries and equity investments, which are not considered reportable segments, are included in All Other. All Other also includes the results of operations of Global Solar. As discussed in Note 7, at March 31, 2006, all of the common stock of Global Solar was sold and the results of operations of Global Solar are reported as discontinued operations. Prior period segment information has been restated to conform to the current period presentation.
Significant reconciling adjustments consist of the elimination of inter-company activity and balances. Millennium subsidiaries recorded revenue from transactions with TEP of $4 million and $7 million during the three-month and six-month periods ended June 30, 2006 and $3 and $6 million during the three-month and six-month periods ended June 30, 2005. 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 investments in subsidiaries held by UniSource Energy, the inter-company note between UniSource Energy and TEP repaid in March 2005, the related interest income and expense on the note and reclassifications of deferred tax assets and liabilities.
We disclose selected financial data for our reportable segments in the following table:
| Reportable Segments | |||||||||||||||||||
| TEP | UNS Gas | UNS Electric | All Other | Reconciling Adjustments | UniSource Energy Consolidated | ||||||||||||||
| Income Statement | -Millions of Dollars- | ||||||||||||||||||
Three months ended June 30, 2006: | |||||||||||||||||||
Operating Revenues - External | $ | 253 | $ | 26 | $ | 39 | $ | - | $ | - | $ | 318 | |||||||
Operating Revenues - Intersegment | - | - | - | 4 | (4 | ) | - | ||||||||||||
Income (Loss) from Continuing Operations Before Income Taxes | 19 | (2 | ) | 2 | (2 | ) | - | 17 | |||||||||||
| Discontinued Operations - Net of Tax | - | - | - | - | - | - | |||||||||||||
| Net Income (Loss) | 11 | (1 | ) | 1 | (1 | ) | - | 10 | |||||||||||
Three months ended June 30, 2005: | |||||||||||||||||||
Operating Revenues - External | $ | 236 | $ | 27 | $ | 36 | $ | - | $ | - | $ | 299 | |||||||
Operating Revenues - Intersegment | 1 | - | - | 3 | (4 | ) | - | ||||||||||||
Income (Loss) from Continuing Operations Before Income Taxes | 21 | - | 2 | (4 | ) | - | 19 | ||||||||||||
| Discontinued Operations - Net of Tax | - | - | - | (2 | ) | - | (2 | ) | |||||||||||
| Net Income (Loss) | 12 | - | 1 | (4 | ) | - | 9 | ||||||||||||
Six months ended June 30, 2006: | |||||||||||||||||||
| Operating Revenues - External | $ | 460 | $ | 90 | $ | 73 | $ | - | $ | - | $ | 623 | |||||||
| Operating Revenues - Intersegment | 1 | - | - | 7 | (8 | ) | - | ||||||||||||
Income (Loss) from Continuing Operations Before Income Taxes | 47 | 6 | 3 | (6 | ) | - | 50 | ||||||||||||
| Discontinued Operations - Net of Tax | - | - | - | (3 | ) | - | (3 | ) | |||||||||||
| Net Income (Loss) | 28 | 3 | 2 | (6 | ) | - | 27 | ||||||||||||
Six months ended June 30, 2005: | |||||||||||||||||||
| Operating Revenues - External | $ | 418 | $ | 74 | $ | 68 | $ | - | $ | - | $ | 560 | |||||||
| Operating Revenues - Intersegment | 1 | - | - | 6 | (7 | ) | - | ||||||||||||
Income (Loss) from Continuing Operations Before Income Taxes | 14 | 7 | 2 | (7 | ) | - | 16 | ||||||||||||
| Discontinued Operations - Net of Tax | - | - | - | (3 | ) | - | (3 | ) | |||||||||||
| Net Income (Loss) | 7 | 4 | 1 | (6 | ) | - | 6 | ||||||||||||
Balance Sheet | |||||||||||||||||||
Total Assets, June 30, 2006 | $ | 2,610 | $ | 228 | $ | 181 | $ | 1,016 | $ | (915 | ) | $ | 3,120 | ||||||
Total Assets, December 31, 2005 | 2,575 | 233 | 161 | 1,032 | (874 | ) | 3,127 | ||||||||||||
TEP INTEREST RATE SWAP
In June 2006, TEP entered into an interest rate swap in order to reduce the exposure to variability in interest rate payments attributable to changes in LIBOR. The swap has the effect of converting approximately $37 million of variable rate lease payments to a fixed rate and is designated as a cash flow hedge. There was no ineffectiveness recorded during the quarter ended June 30, 2006 and the swap is expected to be completely effective in achieving offsetting cash flows attributable to future changes in the LIBOR rate. At June 30, 2006, the fair value of the swap, which is less than $1 million, is recorded in Other Liabilities and the effective portion of the swap’s unrealized gain or loss is recorded in Other Comprehensive Income, a component of Common Stock Equity. Amounts accumulated in Other Comprehensive Income will be reclassified to Interest on Capital Leases over the term of the lease. At June 30, 2006, we expect less than $1 million to be reclassified into earnings over the next 12 months.
TEP FUEL AND POWER TRANSACTIONS
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, within established limits to take advantage of favorable market opportunities and reduce exposure to energy price risk resulting from generation and procurement of power. In general, TEP enters into forward power purchase contracts when market conditions provide the opportunity to purchase energy for its load at prices that are below the marginal cost of its supply resources or to supplement its own resources (e.g., during plant outages and summer peaking periods). TEP enters into forward power sales contracts when it forecasts that it has excess supply and the market price of energy exceeds its marginal cost. In addition, TEP has a natural gas supply agreement under which it purchases all of its gas requirements at spot market prices from Southwest Gas Corporation (SWG). In an effort to minimize price risk on these purchases, TEP enters into price swap agreements under which TEP purchases gas at fixed prices and simultaneously sells gas at spot market prices.
All of TEP’s forward power sale contracts and forward power purchase contracts meet the definition of a derivative. A portion of TEP’s forward power contracts are considered to be normal purchases and sales and, therefore, are not required to be marked to market. However, some of TEP’s forward power contracts and all of the gas swap agreements are considered to be derivatives, which are required to be marked to market each reporting period. Certain of these forward power contracts, as well as the gas swaps, are accounted for as cash flow hedges. Unrealized gains and losses resulting from the change in the fair value of derivatives that meet the criteria for cash flow hedge accounting are recorded in Other Comprehensive Income, rather than in current earnings. Unrealized gains and losses are reclassified into earnings when the related transactions settle or terminate.
The change in fair value of forward power contracts, which are not accounted for as cash flow hedges, is recorded in Net Income. There were no gains or losses recognized in Net Income related to hedge ineffectiveness because all cash flow hedges are considered to be effective.
The settlement of forward power purchase and sales contracts that do not result in physical delivery are recorded net as a component of Electric Wholesale Sales in TEP’s income statement. For the three months ended June 30, 2006, approximately $12 million in sales were netted against approximately $11 million in purchases. For the three months ended June 30, 2005, $4 million in sales were netted against $4 million in purchases. For the six months ended June 30, 2006, approximately $28 million in sales were netted against approximately $26 million in purchases. For the six months ended June 30, 2005, $9 million in sales were netted against $8 million in purchases.
The net unrealized gains and losses from TEP’s fuel and power related derivative activities were as follows:
| Three Months Ended | Six Months Ended | ||||||||||||
| June 30, | June 30, | ||||||||||||
2006 | 2005 | 2006 | 2005 | ||||||||||
| -Millions of Dollars- | |||||||||||||
Net Unrealized Gain (Loss) on Forward Power Sales - Derivative Contracts | $ | 1 | $ | - | $ | 1 | $ | (1 | ) | ||||
Net Unrealized Loss on Forward Power Purchases - Derivative Contracts | (2 | ) | (1 | ) | (1 | ) | - | ||||||
Pre-Tax Unrealized Loss on Derivative Contracts Recorded in Earnings | $ | (1 | ) | $ | (1 | ) | $ | - | $ | (1 | ) | ||
Net Unrealized Gain on Forward Power Sales - Cash Flow Hedges | $ | - | $ | - | $ | 2 | $ | - | |||||
Net Unrealized (Loss) Gain on Gas Price Swaps - Cash Flow Hedges | (7 | ) | (1 | ) | (14 | ) | 4 | ||||||
Pre-Tax Unrealized (Loss) Gain on Cash Flow Hedges | $ | (7 | ) | $ | (1 | ) | $ | (12 | ) | $ | 4 | ||
After Tax Unrealized (Loss) Gain on Cash Flow Hedges Recorded in OCI | $ | (4 | ) | $ | - | $ | (7 | ) | $ | 2 | |||
The fair value of TEP’s fuel and power related derivative assets and liabilities were as follows:
| June 30, | December 31, | ||||||||||||
2006 | 2005 | ||||||||||||
Derivative Contracts | Cash Flow Hedges | Derivative Contracts | Cash Flow Hedges | ||||||||||
| -Millions of Dollars- | |||||||||||||
| Derivative Assets - Current | $ | 4 | $ | 3 | $ | 2 | $ | 10 | |||||
| Derivative Liabilities - Current | (4 | ) | (3 | ) | (2 | ) | (1 | ) | |||||
Net Current Derivative Assets | $ | - | $ | - | $ | - | $ | 9 | |||||
| Derivative Assets - Noncurrent | $ | - | $ | 2 | $ | - | $ | 4 | |||||
| Derivative Liabilities - Noncurrent | - | (1 | ) | - | (1 | ) | |||||||
Net Noncurrent Derivative Assets | $ | - | $ | 1 | $ | - | $ | 3 | |||||
At June 30, 2006, the settlement dates of contracts accounted for as cash flow hedges extended through the third quarter of 2009. Amounts presented as Cash Flow Hedges, Derivative Assets - Current and Derivative Liabilities - Current, are expected to be reclassified into earnings within the next 12 months. TEP reclassified less than $1 million of unrealized gains and losses into earnings from Other Comprehensive Income during each of the three-month and six-month periods ended June 30, 2006 and June 30, 2005.
UNS GAS SUPPLY TRANSACTIONS
UNS Gas does not currently have any contracts that are required to be marked to market. UNS Gas has 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. This enables UNS Gas to provide more stable prices to its customers. These purchases are made up to three years in advance with the goal of locking in fixed prices on at least 45% 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 and therefore are not required to be marked to market.
UNS ELECTRIC POWER SUPPLY TRANSACTIONS
UNS Electric presently has a full requirements power supply agreement that enables it to meet its load. The agreement expires May 31, 2008 and UNS Electric is in the process of replacing this energy resource. In order to reduce exposure to energy price risk resulting from the procurement of power, UNS Electric has entered into forward power purchase contracts for specified amounts of energy at specified prices over a given period of time, within established limits. UNS Electric’s forward power purchase contracts meet the definition of a derivative and are required to be marked to market each reporting period. Some of these forward power contracts are accounted for as cash flow hedges. Unrealized gains and losses resulting from the change in the fair value of derivatives that meet the criteria for cash flow hedge accounting are recorded in Other Comprehensive Income rather than in current earnings. The unrealized gains and losses are reclassified into earnings when the related transactions settle or terminate. Unrealized gains and losses resulting from the change in fair value of derivatives not accounted for as cash flow hedges are recorded in Net Income.
For the three-month and six-month periods ended June 30, 2006, UNS Electric recorded unrealized losses of less than $1 million in Other Comprehensive Income and unrealized gains of less than $1 million in Net Income. UNS Electric did not have any derivatives during 2005.
The fair value of UNS Electric’s derivative assets and liabilities were as follows:
| June 30, | December 31, | ||||||||||||
2006 | 2005 | ||||||||||||
Derivative Contracts | Cash Flow Hedges | Derivative Contracts | Cash Flow Hedges | ||||||||||
| Derivative Assets - Noncurrent | $ | 2 | $ | 1 | $ | - | $ | - | |||||
| Derivative Liabilities - Noncurrent | (2 | ) | (1 | ) | - | - | |||||||
Net Noncurrent Derivative Assets | $ | - | $ | - | $ | - | $ | - | |||||
At June 30, 2006, the settlement dates of contracts accounted for as cash flow hedges extended through the fourth quarter of 2013. UNS Electric does not have any current Derivative Assets or Liabilities that are expected to be reclassified into earnings within the next twelve months. No unrealized gains and losses were reclassified into earnings from Other Comprehensive Income during the three months ended June 30, 2006 or the six months ended June 30, 2006.
MEG TRADING TRANSACTIONS
MEG, a wholly-owned subsidiary of Millennium, enters into swap agreements, options and forward contracts relating to Emissions Allowances. MEG marks its trading contracts to market 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.
For the three months ended June 30, 2006, MEG had a net gain from trading activities of less than $1 million and for the three months ended June 30, 2005, MEG had a net loss from trading activities of less than $1 million. MEG had a net loss from trading activities of less than $1 million for each of the six-month periods ended June 30, 2006 and June 30, 2005.
The fair value of MEG’s derivative assets and liabilities were as follows:
June 30, 2006 | December 31, 2005 | ||||||
| -Millions of Dollars- | |||||||
| MEG: | |||||||
| Trading Assets - Current | $ | 9 | $ | 24 | |||
| Trading Liabilities - Current | (6 | ) | (24 | ) | |||
Net Current Trading Assets | $ | 3 | $ | - | |||
| Trading Assets - Noncurrent | $ | 6 | $ | 14 | |||
| Trading Liabilities - Noncurrent | - | (1 | ) | ||||
Net Noncurrent Trading Assets | $ | 6 | $ | 13 | |||
TEP COMMITMENTS
Power Purchase from Springerville Unit 3
Tri-State Generation and Transmission Association, Inc. (Tri-State) will lease Springerville Unit 3, a 400 MW coal-fired generating facility at TEP’s existing Springerville Generating Station, from a financial owner through a 34-year leveraged lease arrangement. TEP executed contracts to provide operating, maintenance and other services to Unit 3. TEP also agreed to purchase up to 100 MW of Tri-State system capacity for no more than five years after Unit 3 begins commercial operation. This contract begins September 1, 2006. Tri-State may reduce the 100 MW available to TEP in 25 MW increments by submitting written notice to TEP at least 90 days in advance. To date, TEP has received no such notice and expects to begin taking the power in the third quarter.
TEP Guarantee Home Program
TEP provides incentives to new home builders to construct TEP Guarantee Homes that meet the highest construction and energy-efficiency standards available. TEP inspects these homes to ensure that specific energy-efficiency standards are met. TEP then guarantees the home's heating and cooling operating costs for five years. At June 30, 2006, TEP has commitments to pay various home builders $3 million in builder incentives through 2007.
UNS ELECTRIC COMMITMENTS
In May 2006, UNS Electric entered into a 25 MW power supply agreement for the period June 2008 through December 2013. The 25 MW consists of 10 MW at a fixed price with the remaining 15 MW price indexed to natural gas prices. UNS Electric’s minimum expected annual payment under this contract is $9 million based on natural gas prices at the date of contract.
TEP CONTINGENCIES
Litigation and Claims Related to San Juan Generating Station
Public Service Company of New Mexico, operator of San Juan, and the coal supplier to San Juan have been participating in sessions sponsored by the Environmental Protection Agency (EPA) to consider rulemaking for the disposal of coal combustion products because of claims by third parties that San Juan has contaminated water resources in the region as a result of disposing of fly ash in the surface mine pits adjacent to the generating station. In November 2004, a contractor for the EPA released a non-binding preliminary determination that any contamination at San Juan cannot be conclusively attributed to the disposal of fly ash; however, the EPA has not made a final determination. TEP owns 50% of San Juan Units 1 and 2, which equates to 19.8% of the total San Juan Generating Station. TEP does not believe that this issue will have an adverse impact on TEP or its operations.
Claims Related to San Juan Coal Company
San Juan Coal Company, the coal supplier to San Juan, through leases with the federal government and the State of New Mexico, owns coal interests with respect to an underground mine. Certain gas producers have oil and gas leases with the federal government, the State of New Mexico and private parties in the area of the underground mine. These gas producers allege that San Juan Coal Company’s underground coal mining operations have or will interfere with their gas production and will reduce the amount of natural gas that they would otherwise be entitled to recover. San Juan Coal Company has compensated certain gas producers for any remaining gas production from a well when it was determined that mining activity was close enough to warrant shutting down the well. These settlements, however, do not resolve all potential claims by gas producers in the underground mine area. TEP cannot estimate the outcome of any future claims by these gas producers on the cost of coal at San Juan.
Litigation and Claims Related to Navajo Generating Station
On October 15, 2004, Peabody Western Coal Company (Peabody), the coal supplier to the Navajo Generating Station, filed a complaint in the Circuit Court for the City of St. Louis, Missouri (Circuit Court) against the participants at Navajo, including TEP, for reimbursement of royalties and other costs and breach of the coal supply agreement. The case was removed to Federal District Court Eastern District of Missouri but remanded to the Circuit Court. Because TEP owns 7.5% of the Navajo Generating Station, its share of the current claimed damages would be approximately $35 million. TEP believes these claims are without merit and intends to continue to contest them.
Postretirement and Pension Benefit Costs at Navajo Generating Station
In 1996, Peabody filed a lawsuit in Maricopa County Superior Court against the participants at Navajo Generating Station, including TEP, for postretirement benefit costs payable to the coal supplier’s employees under the coal supply agreements. The Navajo participants and Peabody have agreed to stay the discovery process in this litigation to allow the parties additional time to negotiate a potential settlement. To the extent that amounts
become estimable and payment probable, TEP will record a liability for additional postretirement benefit costs at the Navajo Generating Station. TEP believes any claim for postretirement benefits payable to the coal supplier's employees will be settled and included in the cost of coal at the time the coal supply agreement is extended; the current coal supply agreement expires in October 2010.
TEP has previously settled claims for postretirement benefit costs with the coal suppliers at Springerville Generating Station and Four Corners Generating Station. The cost of postretirement benefits is included in the cost of coal to San Juan.
Environmental Reclamation at Remote Generating Stations
TEP currently pays on-going reclamation costs related to the coal mines which supply the remote generating stations, and it is probable that TEP will have to pay a portion of final reclamation costs upon mine closure. When a reasonable estimate of final reclamation costs is available, the liability is recognized as a cost of coal over the remaining term of the respective coal supply agreement. TEP estimates its undiscounted final reclamation liability to be $41 million, and the present value of TEP’s liability for final reclamation approximates $11 million at the expiration dates of the coal supply agreements. At June 30, 2006 and December 31, 2005, TEP had recorded $2 million of its post-term reclamation liability, which is included in Other Liabilities in the balance sheets.
Amounts recorded for final 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 final reclamation obligations will be material to TEP in any single year since recognition occurs over the remaining lives of its coal supply agreements.
RESOLUTION OF SPRINGERVILLE COMMON FACILITIES LEASES CONTINGENCY
TEP refinanced the variable rate debt underlying the Springerville Common Facilities Leases prior to the June 30, 2006 special event of loss date. See Note 3.
GUARANTEES AND INDEMNITIES
In the normal course of business, UniSource Energy and certain subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. We enter into these agreements primarily to support or enhance the creditworthiness of a subsidiary on a stand-alone basis. 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 utility assets, |
| · | UES’ guarantee of a $40 million unsecured revolving credit agreement for UNS Gas and UNS Electric, and |
| · | UniSource Energy’s guarantee of approximately $6 million in natural gas transportation and supply payments in addition to building and equipment lease payments for UNS Gas, UNS Electric, and subsidiaries of Millennium. |
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 of such investments. 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, UES, or Millennium would be required to perform or otherwise incur any significant losses associated with any of these guarantees or indemnities is remote.
On March 31, 2006, UniSource Energy sold all of the capital stock of Global Solar to a German producer of photovoltaic modules and a European financial investor. UniSource Energy received $16 million in cash as part of the transaction; a portion of the proceeds were used to satisfy $10 million of secured promissory notes held by a UniSource Energy subsidiary. In addition to the cash purchase price, UniSource Energy received a ten-year option to purchase between 5 and 10 percent of the common stock of Global Solar. The option is only exercisable after the seventh anniversary of the closing or upon the occurrence of certain events including a sale of all or substantially all of the assets of Global Solar, a merger, a change of control transaction, an initial public offering of Global Solar common stock or the payment by Global Solar of dividends in excess of specified amounts. No value was assigned to this repurchase option.
For the three months and six months ended June 30, 2006, the results of Global Solar are reported as discontinued operations. Prior periods have been restated to conform to the current period presentation. The following summarizes the amounts included in Discontinued Operations - Net of Tax for all periods presented:
| Three Months Ended | Six Months Ended | ||||||||||||
| June 30, | June 30, | ||||||||||||
2006 | 2005 | 2006 | 2005 | ||||||||||
| -Millions of Dollars- | |||||||||||||
| Revenues from Discontinued Operations | $ | - | $ | 1 | $ | 1 | $ | 2 | |||||
| Loss from Discontinued Operations | $ | - | $ | (3 | ) | $ | (4 | ) | $ | (5 | ) | ||
| Loss on Sale of Discontinued Operations | - | - | (1 | ) | - | ||||||||
| Loss from Discontinued Operations Before Income Taxes | - | (3 | ) | (5 | ) | (5 | ) | ||||||
| Income Tax Benefit | - | (1 | ) | (2 | ) | (2 | ) | ||||||
| Discontinued Operations - Net of Tax | $ | - | $ | (2 | ) | $ | (3 | ) | $ | (3 | ) | ||
The Loss from Discontinued Operations for the six months ended June 30, 2006 includes a $1 million write-down of the net assets to fair value less cost to sell and $3 million of operating losses recorded during the first quarter of 2006.
TEP’s Accounts Receivable from Electric Wholesale Sales, included in Trade Accounts Receivable on the balance sheet, totaled $21 million at June 30, 2006 and $30 million at December 31, 2005, net of allowances. TEP’s Allowance for Doubtful Accounts on the balance sheet includes $13 million at June 30, 2006 and December 31, 2005 related to sales to the California Power Exchange (CPX) and the California Independent System Operator (CISO) in 2001 and 2000.
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. In 2004, the FERC issued two separate orders addressing numerous issues in the refund calculation and the fuel cost allowance calculation (an offset to the refund obligation). Based on these orders, TEP has an additional reserve for sales to the CPX and the CISO of $3 million.
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. We cannot predict the outcome of these issues or lawsuits. We believe, however, that TEP is adequately reserved for its transactions with the CPX and the CISO.
Basic EPS is computed by dividing Net Income by the weighted average number of common shares outstanding during the period. Except when the effect would be anti-dilutive, the diluted EPS calculation includes the impact of shares that could be issued upon exercise of outstanding stock options, contingently issuable shares
under equity-based awards or common shares that would result from the conversion of convertible notes. The numerator in calculating diluted earnings per share is Net Income adjusted for the interest on convertible notes (net of tax) that would not be paid if the notes were converted to common shares.
The following table shows the effects of potential dilutive common stock on the weighted average number of shares:
| Three Months Ended | Six Months Ended | ||||||||||||
| June 30, | June 30, | ||||||||||||
2006 | 2005 | 2006 | 2005 | ||||||||||
| - In Thousands - | - In Thousands - | ||||||||||||
| Numerator: | |||||||||||||
Net Income | $ | 9,998 | $ | 9,468 | $ | 26,820 | $ | 5,685 | |||||
Income from Assumed Conversion of Convertible Senior Notes | 1,097 | 1,097 | 2,195 | - | |||||||||
| Adjusted Numerator | $ | 11,095 | $ | 10,565 | $ | 29,015 | $ | 5,685 | |||||
| Denominator: | |||||||||||||
Weighted-average Shares of Common Stock Outstanding: | |||||||||||||
Common Shares Issued | 35,051 | 34,560 | 34,989 | 34,476 | |||||||||
Fully Vested Deferred Stock Units | 194 | 195 | 192 | 193 | |||||||||
Total Weighted-average Shares of Common Stock Outstanding | 35,245 | 34,755 | 35,181 | 34,669 | |||||||||
| Effect of Dilutive Securities: | |||||||||||||
Convertible Senior Notes | 4,000 | 4,000 | 4,000 | - | |||||||||
Options and Stock Issuable under Employee Benefit Plans and the Directors’ Plan | 550 | 698 | 584 | 722 | |||||||||
| Total Shares | 39,795 | 39,453 | 39,765 | 35,391 | |||||||||
Stock options to purchase an average of 109,000 shares of Common Stock were outstanding during the six-month period ended June 30, 2006 but were not included in the computation of EPS because the stock option’s exercise price was greater than the average market price of the Common Stock. Dilutive shares for the six-month period ended June 30, 2005 exclude 2,689 average incremental common shares related to Convertible Senior Notes because they are antidilutive.
PENSION BENEFIT PLANS
TEP, UNS Gas and UNS Electric maintain noncontributory, defined benefit pension plans for substantially all regular employees and certain affiliate employees. Benefits are based on years of service and the employee's average compensation. TEP, UNS Gas and UNS Electric fund the plans by contributing at least the minimum amount required under Internal Revenue Service regulations. Additionally, we provide supplemental retirement benefits to certain employees whose benefits are limited by Internal Revenue Service benefit or compensation limitations.
OTHER POSTRETIREMENT BENEFIT PLANS
TEP provides limited health care and life insurance benefits for retirees. All regular employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate. UNS Gas and UNS Electric provide postretirement medical benefits for current retirees and a small group of active employees. The majority of UNS Gas and UNS Electric employees do not participate in the postretirement medical plan.
The ACC allows TEP, UNS Gas and UNS Electric to recover postretirement costs through rates only as benefit payments are made to or on behalf of retirees. The postretirement benefits are currently funded entirely on a pay-as-you-go basis. Under current accounting guidance, TEP, UNS Gas and UNS Electric cannot record a
regulatory asset for the excess of expense calculated per Statement of Financial Accounting Standards No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, over actual benefit payments.
COMPONENTS OF NET PERIODIC BENEFIT COST
The components of net periodic benefit costs are as follows:
Pension Benefits | Other Postretirement Benefits | ||||||||||||
| Three Months Ended | Three Months Ended | ||||||||||||
| June 30, | June 30, | ||||||||||||
2006 | 2005 | 2006 | 2005 | ||||||||||
| -Millions of Dollars - | |||||||||||||
Components of Net Periodic Benefit Cost | |||||||||||||
Service Cost | $ | 2 | $ | 2 | $ | - | $ | 1 | |||||
Interest Cost | 3 | 3 | 1 | 1 | |||||||||
Expected Return on Plan Assets | (4 | ) | (3 | ) | - | - | |||||||
Prior Service Cost Amortization | 1 | - | (1 | ) | - | ||||||||
Recognized Actuarial Loss | 1 | 1 | 1 | - | |||||||||
Net Periodic Benefit Cost | $ | 3 | $ | 3 | $ | 1 | $ | 2 | |||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||
| Six Months Ended | Six Months Ended | ||||||||||||
| June 30, | June 30, | ||||||||||||
2006 | 2005 | 2006 | 2005 | ||||||||||
| -Millions of Dollars - | |||||||||||||
Components of Net Periodic Benefit Cost | |||||||||||||
Service Cost | $ | 4 | $ | 3 | $ | 1 | $ | 1 | |||||
Interest Cost | 6 | 6 | 2 | 2 | |||||||||
Expected Return on Plan Assets | (7 | ) | (6 | ) | - | - | |||||||
Prior Service Cost Amortization | 1 | 1 | (1 | ) | (1 | ) | |||||||
Recognized Actuarial Loss | 2 | 2 | 1 | 1 | |||||||||
Net Periodic Benefit Cost | $ | 6 | $ | 6 | $ | 3 | $ | 3 | |||||
On May 5, 2006, UniSource Energy shareholders approved the 2006 Omnibus Stock and Incentive Plan (Plan), a new share-based compensation plan. This Plan supersedes and replaces prior equity compensation plans or programs maintained by UniSource Energy. Any prior stock option plans of UniSource Energy remain nominally in effect until all stock options granted under such prior plans have been exercised, forfeited, canceled, expired or otherwise terminated in accordance with the terms of such grants. The total number of shares which may be awarded under the Plan cannot exceed 2.25 million shares.
Awards granted under these compensation plans are described below. We recorded compensation expense of $1 million for these plans for the three months ended and six months ended June 30, 2006, respectively. We recorded compensation expense of less than $1 million for these plans for the three months ended and six months ended June 30, 2005, respectively.
STOCK OPTIONS
On May 5, 2006, the Compensation Committee of the UniSource Energy Board of Directors granted 187,640 stock options to officers with an exercise price of $30.55. The stock options are granted on a scheduled basis with an exercise price equal to the average market price of the stock on the date of grant, 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. Compensation expense is recorded on a straight-line basis over the requisite service period for the total award based on the grant date fair value of the options less estimated forfeitures. For awards granted to retirement eligible officers, compensation expense is recorded immediately.
The fair value of each option award is estimated on the date of grant using the Black-Scholes-Merton option pricing model with the assumptions noted in the following table. The expected term of options granted is derived using the “simplified” method in accordance with Staff Accounting Bulletin 107, Topic 14: Share-Based Payment where the expected term equals the time from grant to reaching the midpoint between vesting and the contractual term considering the vesting tranches. The risk-free rate is based on the rate available on a U.S. Treasury Strip with a maturity equal to the expected term of the option at the time of the grant. Expected volatility is based on historical volatility for UniSource Energy’s stock. The expected dividend yield on a share of stock is calculated using the historical dividend yield with the implicit assumption that current dividend yields will continue in the future.
| 2006 | ||
| Expected term (years) | 6 | |
| Risk-free rate | 4.97% | |
| Expected volatility | 22.57% | |
| Expected dividend yield | 2.45% | |
Weighted-average grant-date fair value of options granted during the period | $7.38 |
A summary of stock option activity follows:
| Six Months Ended June 30, | |||||||||||||
2006 | 2005 | ||||||||||||
Weighted | Weighted | ||||||||||||
Average | Average | ||||||||||||
Exercise | Exercise | ||||||||||||
Shares | Price | Shares | Price | ||||||||||
| Options Outstanding, | |||||||||||||
Beginning of Period | 1,537,041 | $ | 16.75 | 2,076,055 | $ | 16.19 | |||||||
Granted | 187,640 | $ | 30.55 | - | - | ||||||||
Exercised | (196,189 | ) | $ | 15.09 | (366,409 | ) | $ | 16.12 | |||||
Forfeited | (1,646 | ) | $ | 14.95 | (7,198 | ) | $ | 18.08 | |||||
| Options Outstanding, | |||||||||||||
End of Period | 1,526,846 | $ | 18.66 | 1,702,448 | $ | 16.20 | |||||||
| Options Exercisable, | |||||||||||||
End of Period | �� | 1,289,206 | $ | 16.35 | 1,694,976 | $ | 16.19 | ||||||
| Weighted Average Remaining Contractual Life at June 30, 2006: | 5.31 years | ||||||||||||
Exercise prices for stock options outstanding and exercisable as of June 30, 2006 ranged from $11.00 to $33.55, summarized as follows:
Options Outstanding | Options Exercisable | ||||
Range of Exercise Prices | Number of Shares | Weighted-Average Remaining Contractual Life | Weighted-Average Exercise Price | Number of Shares | Weighted-Average Exercise Price |
| $11.00 - $15.56 | 574,103 | 3.3 years | $14.29 | 574,103 | $14.29 |
| $16.69 - $18.84 | 715,103 | 5.4 years | $18.01 | 715,103 | $18.01 |
| $30.55 - $33.55 | 237,640 | 9.7 years | $31.18 | - | - |
Stock options awarded on January 1, 2002 accrue dividend equivalents that are paid in cash on the earlier of the date of exercise of the underlying option or the date the option expires. Compensation expense is recognized as dividends are paid.
RESTRICTED STOCK AND STOCK UNITS
For the six months ended June 30, 2006, we granted stock units to directors representing 15,529 shares at an average grant date fair value of $30.59 per share. For the six months ended June 30, 2005, we granted restricted stock to directors totaling 3,264 shares at a grant date fair value of $24.51 per share and stock units representing 8,544 shares at an average grant date fair value of $28.09 per share. Directors may elect to receive stock units in lieu of restricted stock. Restricted stock generally vests over periods ranging from one to three years. Stock units vest either immediately or over periods ranging from one to three years. Compensation expense equal to the fair market value on the grant date is recognized over the vesting period. Fully vested but undistributed stock unit awards accrue dividend equivalent stock units based on the fair market value of common shares on the date the dividend is paid. Compensation expense is recognized when dividends are paid.
PERFORMANCE SHARES
On May 5, 2006, the Compensation Committee of the UniSource Energy Board of Directors granted 45,520 performance share awards (targeted shares) to Officers at a grant date fair value of $30.55 per share. The performance share awards are paid out in shares of UniSource Energy common stock based on UniSource Energy’s performance over a performance period that is defined in the awards as January 1, 2006 through December 31, 2008. The performance criteria specified in the awards is determined based on targeted UniSource Energy cumulative Earnings per Share and cumulative Cash Flow from Operations during the performance period. The performance shares vest ratably over the performance period and any unearned awards are forfeited. Compensation expense equal to the fair market value on the grant date less the present value of expected dividends is recognized over the vesting period if it is probable that the performance criteria will be met.
INCOME TAXES
The differences between the income tax expense and the amount obtained by multiplying pre-tax income (loss) by the U.S. statutory federal income tax rate of 35% are as follows:
UniSource Energy | |||||||||||||
| Three Months Ended | Six Months Ended | ||||||||||||
| June 30, | June 30, | ||||||||||||
2006 | 2005 | 2006 | 2005 | ||||||||||
| -Thousands of Dollars - | |||||||||||||
Federal Income Tax Expense at Statutory Rate | $ | 5,988 | $ | 5,826 | $ | 16,095 | $ | 3,968 | |||||
| State Income Tax Expense, Net of Federal Deduction | 787 | 766 | 2,115 | 522 | |||||||||
| Depreciation Differences (Flow Through Basis) | 662 | 736 | 1,325 | 1,416 | |||||||||
| Amortization of Excess Deferred Income Tax | (180 | ) | - | (180 | ) | - | |||||||
| Tax Credits | (167 | ) | (130 | ) | (429 | ) | (261 | ) | |||||
| Other | 21 | (20 | ) | 241 | 7 | ||||||||
Total Federal and State Income Tax Expense | $ | 7,111 | $ | 7,178 | $ | 19,167 | $ | 5,652 | |||||
TEP | |||||||||||||
| Three Months Ended | Six Months Ended | ||||||||||||
| June 30, | June 30, | ||||||||||||
2006 | 2005 | 2006 | 2005 | ||||||||||
| -Thousands of Dollars - | |||||||||||||
Federal Income Tax Expense at Statutory Rate | $ | 6,691 | $ | 7,385 | $ | 16,532 | $ | 4,986 | |||||
| State Income Tax Expense, Net of Federal Deduction | 879 | 971 | 2,173 | 655 | |||||||||
| Depreciation Differences (Flow Through Basis) | 662 | 736 | 1,325 | 1,416 | |||||||||
| Amortization of Excess Deferred Income Tax | (180 | ) | - | (180 | ) | - | |||||||
| Tax Credits | (167 | ) | (130 | ) | (429 | ) | (261 | ) | |||||
| Other | 13 | (11 | ) | 5 | (7 | ) | |||||||
Total Federal and State Income Tax Expense | $ | 7,898 | $ | 8,951 | $ | 19,426 | $ | 6,789 | |||||
The total Federal and State Income Tax Expense in the table above is included in UniSource Energy and TEP’s income statements.
OTHER TAX MATTERS
On its 2002 tax return, TEP filed for an automatic change in accounting method relating to the capitalization of indirect costs to the production of electricity and self-constructed assets. The new accounting method was also used on the 2003 and 2004 returns for TEP, UNS Gas and UNS Electric.
In August 2005, the Internal Revenue Service issued a ruling which draws into question the ability of electric and gas utilities to use the new accounting method. TEP believes the IRS position is without merit, and intends to vigorously pursue this issue. However, if the IRS were to prevail and disallow the change in its entirety TEP, UNS Gas and UNS Electric could be required to pay up to $19 million, $1 million and $1 million, respectively, in taxes and interest in the second half of 2006. Such payment would not affect total tax expense.
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.
The following table reconciles the gross investment in utility plant to net investment in utility plant, segregated between regulated and non-regulated utility plant.
TEP | UNS Gas | UNS Electric | UniSource Energy Consolidated | ||||||||||||||||||||||
| As of June 30, 2006 | T&D | Gen* | Total Plant | Total Plant | Total Plant | All Other | TEP Gen* | Total Plant | |||||||||||||||||
| -Millions of Dollars- | |||||||||||||||||||||||||
| Gross Plant in Service | $ | 1,686 | $ | 1,292 | $ | 2,978 | $ | 190 | $ | 156 | $ | 2,032 | $ | 1,292 | $ | 3,324 | |||||||||
Less Accumulated Depreciation and Amortization | 845 | 563 | 1,408 | 12 | 26 | 883 | 563 | 1,446 | |||||||||||||||||
| Net Plant in Service | $ | 841 | $ | 729 | $ | 1,570 | $ | 178 | $ | 130 | $ | 1,149 | $ | 729 | $ | 1,878 |
TEP | UNS Gas | UNS Electric | UniSource Energy Consolidated | ||||||||||||||||||||||
| As of December 31, 2005 | T&D | Gen* | Total Plant | Total Plant | Total Plant | All Other | TEP Gen* | Total Plant | |||||||||||||||||
| -Millions of Dollars- | |||||||||||||||||||||||||
| Gross Plant in Service | $ | 1,629 | $ | 1,233 | $ | 2,862 | $ | 180 | $ | 126 | $ | 1,935 | $ | 1,233 | $ | 3,168 | |||||||||
Less Accumulated Depreciation and Amortization | 817 | 561 | 1,378 | 10 | 20 | 847 | 561 | 1,408 | |||||||||||||||||
| Net Plant in Service | $ | 812 | $ | 672 | $ | 1,484 | $ | 170 | $ | 106 | $ | 1,088 | $ | 672 | $ | 1,760 |
*The ACC does not set rates on TEP’s generation operations on a cost-of-service basis, and, therefore, these operations are not accounted for under the provisions of FAS 71. Rates for the remaining utility operations appearing in this table are set by the ACC on a cost-of-service basis, and are accounted for under the provisions of FAS 71. The category T&D includes all transmission and distribution Plant in Service. The category Gen includes the generation assets.
The FASB recently issued the following Statements of Financial Accounting Standards (FAS), FASB Interpretations (FIN), and FASB Staff Positions (FSP):
· FAS 155, Accounting for Certain Hybrid Financial Instruments, issued February 2006, permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that had previously been bifurcated pursuant to Statement 133 and eliminates a restriction in Statement 140 on the passive derivative instruments that a qualifying special-purpose entity may hold. FAS 155 is effective for all financial instruments acquired or issued or subject to remeasurement in fiscal year that begin after September 15, 2006. We are evaluating the impact of FAS 155 on our financial statements.
· FSP FASB Technical Bulletin 85-4-1, Accounting for Life Settlement Contracts by Third-Party Investors, issued March 2006, allows an investor to account for its investment in a life settlement contract using either the investment method or the fair value method in periods subsequent to the initial recognition of the investment. Investments accounted for under the investment method are initially recorded at transaction price (the amount the investor pays to the insured party) plus any initial direct external costs. Subsequent
costs to keep the policy in force are capitalized to the carrying amount. When the insured dies, the investor recognizes, in the income statement, the difference between the carrying amount of the investment in the life settlement contract and the life insurance proceeds of the underlying life insurance policy. Investments accounted for under the fair value method are initially recorded at transaction price and are subsequently remeasured to fair value each reporting period with changes in fair value recognized in earnings in the period of the change. FSP FASB Technical Bulletin 85-4-1 is effective for fiscal years beginning after June 15, 2006. We are evaluating the impact of FSP FASB Technical Bulletin 85-4-1 on our financial statements.
· Emerging Issues Task Force Issue 06-3 (EITF 06-3), How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (that Is, Gross versus Net Presentation), ratified June 2006, requires disclosure of a company’s accounting policy decision to present taxes on either a gross (included in revenues and costs) or a net (excluded from revenues) basis. Additionally, a company must disclose the amounts of any taxes reported on a gross basis in interim and annual financial statements. EITF 06-3 is effective for interim and annual reporting periods beginning after December 15, 2006. See Note 12.
| · | FIN 48, Accounting for Uncertainty in Income Taxes - an interpretation of FAS 109, issued July 2006, prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken in a tax return. We must determine whether it is "more-likely-than-not" that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. Once it is determined that a position meets the more-likely-than-not recognition threshold, the position is measured to determine the amount of benefit to recognize in the financial statements. Additionally, FIN 48 requires disclosure of a rollforward of total unrecognized tax benefits. We do not believe the adoption of FIN 48 will have a material effect on our financial position or results of operations. In anticipation of FIN 48, we have accounted for significant uncertain tax positions in a manner similar to that prescribed by FIN 48. FIN 48 is effective for fiscal years beginning after December 15, 2006. |
A reconciliation of Net Income to Net Cash Flows - Operating Activities follows:
UniSource Energy | |||||||
| Six Months Ended | |||||||
| June 30, | |||||||
2006 | 2005 | ||||||
| -Thousands of Dollars- | |||||||
Net Income | $ | 26,820 | $ | 5,685 | |||
Adjustments to Reconcile Net Income | |||||||
To Net Cash Flows | |||||||
| Discontinued Operations - Net of Tax | 2,669 | 3,017 | |||||
| Depreciation and Amortization Expense | 63,437 | 66,664 | |||||
| Depreciation Recorded to Fuel and Other O&M Expense | 3,869 | 2,765 | |||||
| Amortization of Transition Recovery Asset | 29,121 | 23,623 | |||||
| Net Unrealized (Gain) Loss on Forward Electric Sales | (1,118 | ) | 1,088 | ||||
| Net Unrealized Loss on Forward Electric Purchases | 970 | - | |||||
| Net Unrealized Loss (Gain) on MEG Trading Activities | 2,945 | (7,143 | ) | ||||
| �� Amortization of Deferred Debt-Related Costs included in Interest Expense | 2,343 | 2,004 | |||||
| Loss on Reacquired Debt | - | 5,427 | |||||
| Provision for Bad Debts | 1,794 | 1,372 | |||||
| Deferred Income Taxes | 10,701 | 10,587 | |||||
| (Income) Loss from Equity Method Entities | (121 | ) | 687 | ||||
| Excess Tax Benefit from Stock Option Exercises | (869 | ) | (1,874 | ) | |||
| Other | 18,335 | 9,887 | |||||
| Changes in Assets and Liabilities which Provided (Used) | |||||||
| Cash Exclusive of Changes Shown Separately | |||||||
| Accounts Receivable | (18,739 | ) | 3,201 | ||||
| Materials and Fuel Inventory | (2,969 | ) | (5,855 | ) | |||
| Accounts Payable | (16,149 | ) | (28,358 | ) | |||
| Income Taxes Payable | (2,775 | ) | (18,755 | ) | |||
| Interest Accrued | (2,035 | ) | (3,767 | ) | |||
| Taxes Accrued | 724 | 308 | |||||
| Other Current Assets | 20,765 | 75,662 | |||||
| Other Current Liabilities | (12,042 | ) | (53,497 | ) | |||
| Net Cash Used by Operating Activities of Discontinued Operations | (2,710 | ) | (3,395 | ) | |||
Net Cash Flows - Operating Activities | $ | 124,966 | $ | 89,333 | |||
TEP | |||||||
| Six Months Ended | |||||||
| June 30, | |||||||
2006 | 2005 | ||||||
| -Thousands of Dollars- | |||||||
Net Income | $ | 27,807 | $ | 7,458 | |||
Adjustments to Reconcile Net Income | |||||||
To Net Cash Flows | |||||||
| Depreciation and Amortization Expense | 54,732 | 57,954 | |||||
| Depreciation Recorded to Fuel and Other O&M Expense | 3,266 | 3,180 | |||||
| Amortization of Transition Recovery Asset | 29,121 | 23,623 | |||||
| Net Unrealized (Gain) Loss on TEP Forward Electric Sales | (1,118 | ) | 1,088 | ||||
| Net Unrealized Loss on TEP Forward Electric Purchases | 1,284 | - | |||||
| Amortization of Deferred Debt-Related Costs included in Interest Expense | 1,709 | 1,823 | |||||
| Loss on Reacquired Debt | - | 5,427 | |||||
| Provision for Bad Debts | 848 | 1,052 | |||||
| Deferred Income Taxes | 7,247 | 10,328 | |||||
| Income from Equity Method Entities | (121 | ) | (45 | ) | |||
| Interest on Note Receivable from UniSource Energy | - | (1,684 | ) | ||||
| Other | 10,704 | 9,673 | |||||
| Changes in Assets and Liabilities which Provided (Used) | |||||||
| Cash Exclusive of Changes Shown Separately | |||||||
| Accounts Receivable | (36,863 | ) | (17,748 | ) | |||
| Materials and Fuel Inventory | (2,756 | ) | (4,068 | ) | |||
| Accounts Payable | (1,689 | ) | (12,438 | ) | |||
| Interest Accrued | (2,197 | ) | (6,668 | ) | |||
| Interest Received from UniSource Energy | - | 11,013 | |||||
| Income Taxes Receivable | - | (1,227 | ) | ||||
| Income Taxes Payable | 1,504 | (17,815 | ) | ||||
| Taxes Accrued | 2,363 | 1,850 | |||||
| Other Current Assets | (142 | ) | 4,118 | ||||
| Other Current Liabilities | 2,494 | (3,174 | ) | ||||
Net Cash Flows - Operating Activities | $ | 98,193 | $ | 73,720 | |||
With respect to the unaudited condensed consolidated financial information of UniSource Energy and TEP for the three-month and six-month periods ended June 30, 2006 and 2005, PricewaterhouseCoopers LLP reported that they have applied limited procedures in accordance with professional standards for a review of such information. However, their separate report dated August 2, 2006 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.
Management’s Discussion and Analysis explains the results of operations, the general financial condition, and the outlook for UniSource Energy and its three primary business segments and includes the following:
| · | outlook and strategies, |
| · | operating results during the second quarter and first six months of 2006 compared with the same periods in 2005, |
| · | factors which affect our results and outlook, |
| · | liquidity, capital needs, capital resources, and contractual obligations, |
| · | dividends, and |
| · | critical accounting estimates. |
Management’s Discussion and Analysis should be read in conjunction with UniSource Energy and TEP’s 2005 Annual Report on Form 10-K and with the Condensed Consolidated Financial Statements, beginning on page 3, which present the results of operations for the three months and six months ended June 30, 2006 and 2005. 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.
OVERVIEW OF CONSOLIDATED BUSINESS
UniSource Energy is a holding company that has no significant operations of its own. Operations are conducted by UniSource Energy’s subsidiaries, each of which is a separate legal entity with its own assets and liabilities. UniSource Energy owns the outstanding common stock of TEP, UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).
TEP, an electric utility, has provided electric service to the community of Tucson, Arizona, for over 100 years. UES began operations in 2003. UES, through its two operating subsidiaries, UNS Gas, Inc. (UNS Gas) and UNS Electric, Inc. (UNS Electric), provides gas and electric service to 30 communities in northern and southern Arizona. Millennium invests in unregulated businesses. UED is facilitating the expansion of the Springerville Generating Station, but currently has no significant operations. We conduct our business in three primary business segments - TEP’s Electric Utility segment, UNS Gas and UNS Electric.
UniSource Energy is in the process of exiting its Millennium investments. On March 31, 2006, Millennium sold its interest in Global Solar Energy, Inc. (Global Solar), its largest holding.
Operating Plans 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:
| · | Efficiently manage our generation, transmission and distribution resources and look for ways to control our operating expenses while maintaining and enhancing reliability and profitability. |
| · | Expand TEP’s and UNS Electric’s portfolio of generating and purchased power resources to meet growing retail energy demand. |
| · | Enhance the value of existing generation assets by working with Salt River Project to support the construction of Springerville Unit 4. |
| · | Enhance the value of TEP’s transmission system while continuing to provide reliable access to generation for TEP and UNS Electric’s retail customers and market access for all generating assets. |
| · | Continue to integrate UNS Gas and UNS Electric with UniSource Energy’s other businesses. |
| · | Reduce debt. |
| · | Promote economic development in our service territories. |
To accomplish our goals, during 2006 we expect to spend the following amounts on capital expenditures:
Actual Year-to-Date June 30, 2006 | Estimate Full Year 2006 | ||||||
| -Millions of Dollars- | |||||||
| TEP | $ | 82 | $ | 163 | |||
| UNS Gas | 12 | 25 | |||||
| UNS Electric | 19 | 40 | |||||
| UniSource Energy Consolidated | $ | 113 | $ | 228 | |||
Executive Overview
Three Months Ended June 30
In the second quarter of 2006, UniSource Energy reported net income from continuing operations of $10 million, compared with net income from continuing operations of $11 million in the same period in 2005. The decrease is due primarily to the lower availability of TEP’s coal-fired generating plants, which off-set a $6 million decrease in interest expense. Planned maintenance outages, a two week unplanned outage at Springerville Unit 2 in May of 2006 and other unplanned outages led to an 11% decline in coal-fired generation. The Luna Energy Facility (Luna), an efficient, combined cycle gas plant came on-line in April 2006 and enabled TEP to rely less on market purchases and less-efficient gas-fired plants when coal-fired generating plants were down and to meet retail demand during the peak summer months. Customer growth and hot weather in TEP’s service area led to a 6% increase in TEP’s retail sales compared with the second quarter of 2005. Interest expense was higher in the second quarter of 2005 due to the write-off of fees associated with TEP’s financial restructuring.
Six Months Ended June 30
In the first six months of 2006, UniSource Energy reported income from continuing operations of $29 million, compared with net income from continuing operations of $9 million in the same period in 2005. The improvement is due primarily to: the higher availability of TEP’s coal-fired generating plants during the first quarter; hot weather during May and June; and retail customer growth. The longer duration and higher frequency of planned coal plant outages in the first quarter of 2005 limited TEP’s wholesale sales opportunities and led to higher replacement power costs to serve retail customers. The availability of Luna also benefited TEP in the first six months of 2006.
On March 31, 2006, Millennium sold Global Solar for $16 million in cash and an option to purchase, under certain conditions, 5% to 10% of Global Solar in the future. In the first quarter of 2006, UniSource Energy recorded an after-tax loss of approximately $3 million related to the discontinued operations and disposal of Global Solar.
The table below shows the contributions to our consolidated after-tax earnings by our three business segments and Other net income (loss).
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||
2006 | 2005 | 2006 | 2005 | ||||||||||
| -Millions of Dollars- | -Millions of Dollars- | ||||||||||||
TEP | $11 | $12 | $28 | $7 | |||||||||
UNS Gas | (1 | ) | - | 3 | 4 | ||||||||
UNS Electric | 1 | 1 | 2 | 1 | |||||||||
Other (1) | (1 | ) | (2 | ) | (4 | ) | (3 | ) | |||||
Consolidated Net Income (Loss) from Continuing Operations | $ | 10 | $ | 11 | $ | 29 | $ | 9 | |||||
Discontinued Operations (2) | - | (2 | ) | (2 | ) | (3 | ) | ||||||
| Consolidated Net Income (Loss) | $ | 10 | $ | 9 | $ | 27 | $ | 6 | |||||
(1) Includes: UniSource Energy parent company expenses; UniSource Energy parent company interest expense (net of tax) on the UniSource Energy Convertible Senior Notes and on the UniSource Energy Credit Agreement; income and losses from Millennium investments; in the first six months of 2005, interest expense (net of tax) on the note payable from UniSource Energy to TEP.
(2) Relates to the discontinued operations and sale of Global Solar by Millennium on March 31, 2006.
Three Months Ended June 30, 2006 Compared with the Three Months Ended June 30, 2005
UniSource Energy recorded income from continuing operations of $10 million, or 28 cents per average basic share of Common Stock, in the second quarter of 2006, compared with income from continuing operations of $11 million, or 32 cents per average basic share of Common Stock, in the same period of 2005. The following factors contributed to the decrease:
2006 included:
| · | a $3 million decrease in TEP’s gross margin (total operating revenues less fuel and purchased power expense) due to the following: |
| · | a $13 million increase in retail revenues due to warmer weather and customer growth; offset by |
| · | a $3 million decrease in wholesale revenues due to lower excess capacity at TEP’s coal-fired generating plants due to outages and higher retail energy demand; and |
| · | a $13 million increase in expenses for fuel for TEP’s generating plants and a $6 million increase in purchased power costs. Scheduled maintenance outages at TEP’s coal-fired plants, a two week unplanned outage at Springerville Unit 2 in May of 2006 and other unplanned outages, combined with increased retail energy demand and wild fire-related transmission outages in northern Arizona, |
| resulted in higher usage of TEP’s gas-fired plants. The availability of Luna helped offset reliance on less-efficient gas plants and power purchases. |
| · | a $4 million increase in other operations and maintenance (O&M) due primarily to outages at TEP coal plants and transmission costs associated with Luna; |
| · | a $3 million increase in the amortization of TEP’s Transition Recovery Asset (TRA); and |
| · | a $6 million decrease in total interest expense due to: costs incurred in the second quarter of 2005 related to various financing activities; lower fees under TEP’s new Credit Agreement entered into in May 2005; the repurchase and redemption of $225 million of TEP debt in May 2005; and lower capital lease obligation balances. |
Six Months Ended June 30, 2006 Compared with the Six Months Ended June 30, 2005
UniSource Energy recorded income from continuing operations of $29 million, or 84 cents per average basic share of Common Stock, in the first six months of 2006, compared with income from continuing operations of $9 million, or 25 cents per average basic share of Common Stock, in the same period of 2005. The following factors contributed to the improvement:
2006 included:
| · | a $20 million increase in TEP’s gross margin (total operating revenues less fuel and purchased power expense) due to the following: |
| · | a $21 million increase in retail revenues due to hot weather in May and June, as well as continued customer growth; |
| · | a $14 million increase in wholesale revenues due to the higher use and availability of TEP’s coal-fired generating plants and increased wholesale activity. The longer duration and higher frequency of planned outages in 2005 led to lower amounts of excess generation to sell into the wholesale market; |
| · | a $16 million increase in fuel expense for TEP’s generating plants and a $6 million increase in purchased power costs due to higher retail energy demand, higher output from TEP’s generating plants and increased purchased power expense during the second quarter of 2006. |
| · | a $2 million decrease in O&M due primarily to fewer TEP coal plant outages in the first half of 2006 compared with the same period last year; |
| · | a $3 million decline in depreciation and amortization due primarily to the extension of useful lives of certain generating assets at TEP in April 2005; |
| · | a $5 million increase in the amortization of TEP’s TRA; and |
| · | a $10 million decrease in total interest expense due to: costs incurred in the second quarter of 2005 related to various financing activities; lower fees under TEP’s new Credit Agreement entered into in May 2005; the repurchase and redemption of $278 million of TEP debt in the first six months of 2005; and lower capital lease obligation balances at TEP. |
Six Months Ended June 30, | 2006 | 2005 | |||||
| -Millions of Dollars- | |||||||
| Cash provided by (used in): | |||||||
Operating Activities | $ | 125 | $ | 89 | |||
Investing Activities | (134 | ) | (75 | ) | |||
Financing Activities | (1 | ) | (66 | ) | |||
UniSource Energy’s consolidated cash flows are provided primarily from retail and wholesale energy sales at TEP, UNS Gas and UNS Electric, net of the related payments for fuel and purchased power. Generally, cash from operations is lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load.
We use our available cash primarily to:
| · | fund capital expenditures at TEP, UNS Gas and UNS Electric; |
| · | pay dividends to shareholders; and |
| · | reduce leverage. |
The primary source of liquidity for UniSource Energy, the parent company, is dividends it receives from its subsidiaries, primarily TEP. Also, under our tax sharing agreement, our subsidiaries make income tax payments to UniSource Energy, which makes payments on behalf of the consolidated group.
As of August 4, 2006, cash and cash equivalents available to UniSource Energy was approximately $129 million.
Executive Overview
In the first six months of 2006, net cash flows from operating activities were $125 million, up $36 million from the same period in 2005. The improvement is due to: the higher availability and use of TEP’s coal-fired generating plants to serve retail customers and for sales of excess energy into the wholesale market; hot weather contributing to higher retail sales in TEP’s service territory; and an increase in UNS Electric’s retail revenues.
Operating Activities
In the first six months of 2006, net cash flows from operating activities increased by $36 million compared with the same period in 2005. The following factors contributed to the change:
2006 included:
| · | a $22 million increase in cash receipts from retail electric sales due primarily to hot weather in May and June and customer growth at TEP and UNS Electric; |
| · | a $20 million increase in cash receipts from UNS Gas’ retail sales due to the Purchased Gas Adjustor (PGA) surcharge adjustments that took effect in November 2005 and customer growth; |
| · | a $28 million increase in cash receipts from wholesale electric sales due to the higher amount of excess output from TEP’s coal-fired generating plants, increased wholesale trading activity and higher wholesale market prices for power; |
| · | a $17 million increase in fuel costs paid due to the higher availability and use of TEP’s coal-fired generating plants, as well as the availability of the gas-fired Luna plant beginning in April 2006; |
| · | a $27 million increase in purchased energy costs paid due to higher wholesale trading activity at TEP and higher retail sales and natural gas prices at UNS Gas; |
| · | a $14 million decrease in payments for O&M costs. O&M costs were higher in the first six months of 2005 due to higher frequency and duration of planned and unplanned outages at TEP’s coal plants; |
| · | a $5 million decrease in total interest costs paid due to lower amounts of outstanding long-term debt and capital lease obligations; and |
| · | a $10 million increase in total taxes paid, net of refunds, due to higher pre-tax income. |
Investing Activities
Net cash used for investing activities was $59 million higher in the first six months of 2006 compared with the same period in 2005 primarily due to the following factors:
| · | a $24 million increase in capital expenditures related to TEP’s share of the construction costs of |
Luna, growth and maintenance of TEP’s electric system, and utility system growth at UNS Gas
UNS Electric; and
| · | TEP’s purchase of a 14% equity interest in the Springerville Unit 1 Lease, which represents approximately 55 MW of capacity; offset by |
| · | a $4 million increase in proceeds from the return on investment from Millennium businesses; and |
| · | $16 million of proceeds from the sale of Global Solar. |
Financing Activities
Net cash flows used for financing activities were $65 million lower in the first six months of 2006 compared with the same period in 2005. The following factors contributed to the change:
2006 included:
| · | a $20 million increase in net proceeds from borrowings under revolving credit facilities; offset by |
| · | a $4 million decrease in proceeds from the exercise of stock options; |
| · | a $2 million increase in TEP’s scheduled payments on capital lease obligations; and |
| · | a $2 million increase in dividends paid to UniSource Energy shareholders. |
2005 included:
| · | $240 million of proceeds related to debt issuances at UniSource Energy; offset by |
| · | $283 million used to repay long-term debt at TEP and UniSource Energy; and |
| · | the use of $12 million for debt issuance and retirement costs. |
As a result of the activities described above, our consolidated cash and cash equivalents decreased to $135 million at June 30, 2006, from $145 million at December 31, 2005. We invest cash balances in high-grade money market securities with an emphasis on preserving the principal amounts invested.
At August 4, 2006, UniSource Energy’s consolidated cash balance, including cash equivalents, was approximately $129 million.
We believe that we will continue to have sufficient cash flow to cover our capital needs, as well as required debt payments and dividends to shareholders. In the event that we experience lower cash from operations in 2006, we will use our revolving credit facilities to fund our cash needs.
UniSource Credit Agreement
In April 2005, UniSource Energy entered into a $105 million five-year credit agreement with a group of lenders (UniSource Credit Agreement) which expires in April 2010. The UniSource Credit Agreement includes a
term loan facility with an outstanding balance of $84 million as of June 30, 2006, and a $15 million revolving credit facility. Principal payments of $1.25 million are due at each quarter end with the balance due at maturity. As of June 30, 2006, UniSource Energy was in compliance with the terms of the UniSource Credit Agreement.
We expect that we may borrow from time to time under the revolving credit facility to meet temporary cash needs. As of June 30, 2006, we had no borrowings outstanding under the revolving credit facility.
See below for further discussion of Liquidity and Capital Resources for each of UniSource Energy’s reportable segments.
GUARANTEES AND INDEMNITIES
In the normal course of business, UniSource Energy and certain subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. We enter into these agreements primarily to support or enhance the creditworthiness of a subsidiary on a stand-alone basis. The most significant of these guarantees at June 30, 2006 are:
| · | UES’ guarantee of $160 million of senior unsecured notes issued by UNS Gas and UNS Electric to purchase the Citizens Communication Company (Citizens’) Arizona gas and electric system assets; |
| · | UES’ guarantee of a $40 million revolving credit facility available to UNS Gas and UNS Electric; |
| · | UniSource Energy’s guarantee of approximately $6 million in natural gas and supply payments and building lease payments for UNS Gas and UNS Electric and a subsidiary of Millennium. |
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 that UniSource Energy or TEP would be required to perform or otherwise incur any significant losses associated with any of these guarantees is remote.
CONTRACTUAL OBLIGATIONS
There are no significant changes in our contractual obligations or other commercial commitments from those reported in our 2005 Annual Report on Form 10-K, other than:
| · | TEP’s purchased power agreement with Tri-State for 100 MW of system capacity will become effective September 1, 2006. This contract allows Tri-State to reduce the contract capacity in increments of 25 MW with 90 days notice. To date, TEP has received no such notice. If Tri-State does not give notice to reduce capacity, the minimum capacity payments will be $10 million for 2006, $31 million annually in 2007 through 2010, and $21 million in 2011. |
· At June 30, 2006, TEP has commitments to pay various home builders $3 million in builder incentives through 2007 to construct TEP Guarantee Homes that meet the highest construction and energy-efficiency standards available.
| · | In June 2006, TEP refinanced variable rate notes underlying the Springerville Common Facilities Leases. A portion of the rent payable by TEP pursuant to the Springerville Common Facilities Leases is determined by the amount of interest payable on the variable rate lease debt. The notes were amended to provide that interest will be payable at LIBOR plus 1.5% for the next three years with the spread over LIBOR increasing every three years thereafter to 2% by June 2018. Prior to the refinancing, the interest rate was LIBOR plus 4%. TEP estimates its obligation using a forward LIBOR curve. At June 30, 2006, TEP’s obligations under the Springerville Common Facilities Leases total: $7 million in 2006; $6 million in 2007; $6 million in 2008; $6 million in 2009; $6 million in 2010; $6 million in 2011; and $145 million thereafter. TEP’s obligation does not include the impact of the 2006 interest rate swap. |
| · | In June 2006, TEP purchased a 14% equity ownership interest in the Springerville Unit 1 Leases. As a result, TEP amended the Springerville Unit 1 Lease related to such undivided interest to reduce TEP’s rent payable to equal the scheduled amount of principal and interest payable on the debt issued by the owner trustee. At June 30, 2006, TEP’s obligations under the Springerville Unit 1 Leases total: $85 million in 2006; $83 million in 2007; $82 million in 2008; $30 million in 2009; $57 million in 2010; $83 million in 2011; and $317 million thereafter. |
| · | In May 2006, UNS Electric entered into a 25 MW power supply agreement for the period June 2008 through December 2013. The 25 MW consists of 10 MW at a fixed price with the remaining 15 MW price indexed to natural gas prices. UNS Electric’s minimum expected annual payment under this contract is $9 million based on natural gas prices at the date of contract. |
| · | TEP entered into operating leases in the first quarter 2006 for equipment at Springerville totaling $2 million over three years. |
DIVIDENDS ON COMMON STOCK
The following table shows the dividends declared to UniSource Energy shareholders for 2006.
Declaration Date | Record Date | Payment Date | Dividend Amount Per Share of Common Stock |
| February 10, 2006 | February 21, 2006 | March 15, 2006 | $0.21 |
| May 5, 2006 | May 17, 2006 | June 9, 2006 | $0.21 |
INCOME TAX MATTERS
Income Tax Position
At June 30, 2006, UniSource Energy and TEP had, for federal income tax filing purposes, Federal AMT Credit carryforward amounts of $70 million and $55 million, respectively.
Internal Revenue Service Matters
On its 2002 tax return, TEP filed for an automatic change in accounting method relating to the capitalization of indirect costs to the production of electricity and self-constructed assets. The new accounting method was also used on the 2003 and 2004 returns for TEP, UNS Gas and UNS Electric.
In August 2005, the Internal Revenue Service (IRS) issued a ruling which draws into question the ability of electric and gas utilities to use the new accounting method. TEP believes the IRS position is without merit and intends to vigorously pursue this issue. However, if the IRS prevails and disallows the change in its entirety, TEP, UNS Gas and UNS Electric could be required to pay up to $19 million, $1 million and $1 million, respectively, in taxes and pay an appropriate amount of interest in 2006. Such payments would not affect total tax expense.
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 on an annual basis. The following discussion relates to TEP’s utility operations, unless otherwise noted.
Sales | Operating Revenue | ||||||||||||
Three Months Ended June 30, | 2006 | 2005 | 2006 | 2005 | |||||||||
| -Millions of kWh- | -Millions of Dollars- | ||||||||||||
Electric Retail Sales: | |||||||||||||
Residential | 1,012 | 908 | $ | 94 | $ | 84 | |||||||
Commercial | 526 | 498 | 55 | 52 | |||||||||
Industrial | 586 | 596 | 43 | 44 | |||||||||
Mining | 228 | 224 | 11 | 10 | |||||||||
Public Authorities | 77 | 66 | 5 | 5 | |||||||||
Total Electric Retail Sales | 2,429 | 2,292 | $ | 208 | $ | 195 | |||||||
Electric Wholesale Sales Delivered: | |||||||||||||
Long-term Contracts | 245 | 277 | 12 | 12 | |||||||||
Other Sales | 410 | 477 | 20 | 24 | |||||||||
Transmission | - | - | 2 | 2 | |||||||||
Net Unrealized Gain on Forward Sales of Energy | - | - | 1 | - | |||||||||
Total Electric Wholesale Sales | 655 | 754 | 35 | 38 | |||||||||
Total Electric Sales | 3,084 | 3,046 | $ | 243 | $ | 233 | |||||||
Weather Data: | 2006 | 2005 | |||||||||||
Cooling Degree Days | |||||||||||||
| Three Months Ended June 30, | 543 | 454 | |||||||||||
| 10-Year Average | 434 | 434 | |||||||||||
Total revenues from kWh sales to retail customers increased by $13 million, or 7%, in the second quarter of 2006, compared with the same period last year, due to hot summer weather and customer growth. Cooling degree days in the second quarter of 2006 were up 20% compared the same period last year and 25% higher than the 10-year average. The average daily high temperature during the second quarter of 2006 was two degrees above the same period last year and the 10-year average. TEP’s retail customer base grew approximately 2% compared with June 30, 2005.
Wholesale revenues decreased $3 million, or 9%, in the second quarter of 2006 compared with the second quarter of 2005, primarily due to the lower availability of TEP’s coal plants. In the second quarter of 2006, there were planned outages at Springerville Unit 1 and Sundt Unit 4, a two week unplanned outage at Springerville Unit 2 in May of 2006 and other unplanned outages that limited the availability of excess coal-fired energy to sell into the wholesale market. See Factors Affecting Results of Operations, Western Energy Markets, Market Prices, below.
Sales | Operating Revenue | ||||||||||||
Six Months Ended June 30, | 2006 | 2005 | 2006 | 2005 | |||||||||
| -Millions of kWh- | -Millions of Dollars- | ||||||||||||
Electric Retail Sales: | |||||||||||||
Residential | 1,711 | 1,558 | $ | 153 | $ | 140 | |||||||
Commercial | 915 | 849 | 95 | 88 | |||||||||
Industrial | 1,095 | 1,108 | 79 | 79 | |||||||||
Mining | 452 | 444 | 21 | 21 | |||||||||
Public Authorities | 130 | 110 | 9 | 8 | |||||||||
Total Electric Retail Sales | 4,303 | 4,069 | $ | 357 | $ | 336 | |||||||
Electric Wholesale Sales Delivered: | |||||||||||||
Long-term Contracts | 538 | 585 | 26 | 27 | |||||||||
Other Sales | 1,134 | 930 | 60 | 47 | |||||||||
Transmission | - | - | 4 | 4 | |||||||||
Net Unrealized Gain (Loss) on Forward Sales of Energy | - | - | 1 | (1 | ) | ||||||||
Total Electric Wholesale Sales | 1,672 | 1,515 | 91 | 77 | |||||||||
Total Electric Sales | 5,975 | 5,584 | $ | 448 | $ | 413 | |||||||
Weather Data: | 2006 | 2005 | |||||||||||
Cooling Degree Days | |||||||||||||
| Six Months Ended June 30, | 543 | 454 | |||||||||||
| 10-Year Average | 434 | 434 | |||||||||||
Total revenues from kWh sales to retail customers increased by $21 million, or 6%, in the first six months of 2006, compared with the same period last year, due to hot summer weather and customer growth.
Wholesale revenues increased $14 million, or 18%, in the first six months of 2006 compared with the same period last year, primarily due to the higher availability of TEP’s coal plants, higher power sales prices and increased wholesale activity. In the first quarter of 2005, Springerville Unit 2 underwent a six week scheduled outage that limited TEP’s ability to sell excess energy into the wholesale market. Planned outages during the first six months of 2006 were less frequent and shorter in duration than the same period in 2005. The average wholesale market price of energy was $47 per MWh in the first six months of 2006, compared with $45 per MWh in the comparable period in 2005. TEP hedged 270,000 MWh of its first quarter sales in the latter part of 2005 at an average price of $70 per MWh, which was nearly 50% higher than the average wholesale market price. See Factors Affecting Results of Operations, Western Energy Markets, Market Prices, below.
OPERATING EXPENSES
Fuel and Purchased Power Expense
TEP’s fuel and purchased power expense, and energy resources for the second quarters of 2006 and 2005 are shown in the table below.
Generation and Purchased Power | Expense | ||||||||||||
Three Months Ended June 30, | 2006 | 2005 | 2006 | 2005 | |||||||||
| -Millions of kWh- | -Millions of Dollars- | ||||||||||||
| Coal-Fired Generation | |||||||||||||
| Four Corners | 197 | 186 | $ | 3 | $ | 3 | |||||||
| Navajo | 300 | 300 | 4 | 4 | |||||||||
| San Juan | 625 | 588 | 14 | 13 | |||||||||
| Springerville | 1,201 | 1,523 | 20 | 25 | |||||||||
| Sundt 4 | 126 | 170 | 3 | 3 | |||||||||
| Total Coal-Fired Generation | 2,449 | 2,767 | 44 | 48 | |||||||||
| Gas-Fired Generation | |||||||||||||
| Luna | 202 | - | 10 | - | |||||||||
| Other Gas Units | 114 | 89 | 10 | 8 | |||||||||
| Total Gas-Fired Generation | 316 | 89 | 20 | 8 | |||||||||
| Solar and Other | 3 | 3 | - | - | |||||||||
| Total Generation | 2,768 | 2,859 | 64 | 56 | |||||||||
| Purchased Power | 554 | 416 | 33 | 27 | |||||||||
| Springerville 3 | - | - | 5 | - | |||||||||
| Total Resources | 3,322 | 3,275 | $ | 102 | $ | 83 | |||||||
| Less Line Losses and Company Use | (238 | ) | (229 | ) | |||||||||
| Total Energy Sold | 3,084 | 3,046 | |||||||||||
Fuel expense at TEP’s generating plants was $8 million higher in the second quarter of 2006 compared with the same period last year. Coal-fired generation decreased 318,000 MWh, or 11%, compared with the second quarter of 2005 due primarily to: scheduled outages at Springerville 1 and Sundt 4; a two week unplanned outage at Springerville Unit 2 in May of 2006; and other unplanned outages. As a result of lower coal generation, coal-related fuel expense decreased $4 million in the second quarter of 2006 compared with the same period last year. Gas-fired generation increased by 227,000 MWh and gas-related fuel expense was $12 million higher than the second quarter of 2005, due primarily to the start of commercial operation of Luna in April 2006. Luna’s generation output reported in the table above includes energy generated during its test phase; but does not include any associated fuel costs which were capitalized and reported as project costs. Fuel expense in the second quarter of 2006 also includes $5 million related to the use of diesel fuel at Springerville Unit 3. These costs are reimbursed by Tri-State and recorded in Other Revenue.
Purchased power expense was $6 million higher the second quarter of 2006 compared with the same period last year due to lower coal plant availability, higher retail energy demand and increased wholesale trading activity. Total purchases were up 138,000 MWh, or 33%, in the second quarter of 2006 compared with the same period last year.
TEP’s fuel and purchased power expense, and energy resources for the first six months of 2006 and 2005 are shown in the table below.
Generation and Purchased Power | Expense | ||||||||||||
Six Months Ended June 30, | 2006 | 2005 | 2006 | 2005 | |||||||||
| -Millions of kWh- | -Millions of Dollars- | ||||||||||||
| Coal-Fired Generation | |||||||||||||
| Four Corners | 403 | 381 | $ | 6 | $ | 5 | |||||||
| Navajo | 579 | 542 | 8 | 7 | |||||||||
| San Juan | 1,259 | 1,205 | 28 | 26 | |||||||||
| Springerville | 2,728 | 2,667 | 45 | 45 | |||||||||
| Sundt 4 | 279 | 377 | 6 | 7 | |||||||||
| Total Coal-Fired Generation | 5,248 | 5,172 | 93 | 90 | |||||||||
| Gas-Fired Generation | |||||||||||||
| Luna | 225 | - | 10 | - | |||||||||
| Other Gas Units | 125 | 145 | 11 | 13 | |||||||||
| Total Gas-Fired Generation | 350 | 145 | 21 | 13 | |||||||||
| Solar and Other | 5 | 5 | - | - | |||||||||
| Total Generation | 5,603 | 5,322 | 114 | 103 | |||||||||
| Purchased Power | 797 | 681 | 46 | 40 | |||||||||
| Springerville 3 | - | - | 5 | - | |||||||||
| Total Resources | 6,400 | 6,003 | $ | 165 | $ | 143 | |||||||
| Less Line Losses and Company Use | (425 | ) | (419 | ) | |||||||||
| Total Energy Sold | 5,975 | 5,584 | |||||||||||
Fuel expense at TEP’s generating plants was $11 million higher in the first six months of 2006 compared with the same period last year. Coal-fired generation increased 76,000 MWh, or 1%, compared with the second quarter of 2005 primarily due to the planned outage of Springerville Unit 2 during the first quarter of last year. As a result of higher coal generation, coal-related fuel expense increased $3 million in the first six months of 2006 compared with the same period last year. Gas-fired generation increased by 205,000 MWh and gas-related fuel expense was $8 million higher than the first six months of 2005, due to the start of commercial operation of Luna in April 2006. Luna’s generation output reported in the table above includes energy generated during its test phase; but does not include any associated fuel costs which were capitalized and reported as project costs. Fuel expense in the first six months of 2006 includes $5 million related to the use of diesel fuel at Springerville Unit 3. These costs are reimbursed by Tri-State and recorded in Other Revenue.
Purchased power expense increased $6 million, or 15%, in the first six months of 2006 compared with the same period last year. Total purchases were up 116,000 MWh, or 17%, in the first six months of 2006 compared with the same period last year due primarily to the lower availability of TEP’s coal plants during the second quarter of 2006 and increased wholesale trading activity.
The table below shows the average fuel cost per kWh for TEP’s generating plants by fuel type and purchased power.
Three Months Ended June 30, | Six Months Ended June 30, | |||
2006 | 2005 | 2006 | 2005 | |
| -cents per kWh- | -cents per kWh- | |||
| Coal | 1.80 | 1.73 | 1.77 | 1.74 |
| Gas* | 6.41 | 8.99 | 6.48 | 8.97 |
| All fuels | 2.32 | 1.96 | 2.04 | 1.94 |
| Purchased Power | 5.96 | 6.49 | 5.77 | 5.87 |
*In 2006, the average cost of gas generation per kWh excludes test energy produced at Luna and the associated fuel costs.
Other Operating Expenses
Other O&M expense increased $3 million in the second quarter of 2006, compared with the same period last year due primarily to coal plant outages and transmission costs at Luna. TEP sold excess SO2 Emission Allowances and recorded pre-tax gains of $2 million to O&M during the second quarters of 2006 and 2005. See Factors Affecting Results of Operations, Emission Allowances, below.
Other O&M expense decreased $3 million in the first half of 2006, compared with the same period last year. In the first quarter of 2005, O&M included expenses related to an extensive scheduled outage of Springerville Unit 2 as well as several other plant outages. TEP sold excess SO2 Emission Allowances and recorded pre-tax gains of $3 million to O&M during the first six months of 2006 and 2005. See Factors Affecting Results of Operations, Emission Allowances, below.
Depreciation and amortization expense did not change in the second quarter of 2006 compared with the same period last year. Depreciation and amortization expense decreased $3 million in the first six months of 2006 compared with the same period last year, due primarily to changes in depreciation lives of certain generation assets at TEP in April 2005.
Amortization of the TRA increased $3 million in the second quarter of 2006 and $5 million in the first six months of 2006, compared with the same periods last year. Amortization of the TRA is the result of the 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. The amount of amortization is a function of the TRA balance and total kWh consumption by TEP’s distribution customers.
The table below shows estimated annual TRA amortization and unamortized TRA year-end balances for 2006 through 2008.
Estimated | Unamortized | ||||||
TRA Amortization | TRA Balance | ||||||
| -Millions of Dollars- | |||||||
| 2006 | $ | 66 | $ | 102 | |||
| 2007 | 76 | 26 | |||||
| 2008 | 26 | - | |||||
Other Income (Deductions)
In the first six months of 2005, TEP’s Income Statement included inter-company Interest Income of $2 million. This represented Interest Income on a promissory note TEP received from UniSource Energy in exchange for the transfer to UniSource Energy of its stock in Millennium in 1998. UniSource Energy repaid the inter-company promissory note on March 1, 2005. On UniSource Energy’s Consolidated Statement of Income, this Interest Income, as well as UniSource Energy’s related interest expense, was eliminated as an inter-company transaction.
Interest Expense
In the second quarter and first six months of 2006, total interest expense decreased by $7 million and $13 million respectively, primarily due to $5 million of costs incurred in the second quarter of 2005 related to TEP’s financing activities, lower capital lease obligation balances, debt retirements at TEP and lower fees under the TEP Credit Agreement entered into in May 2005.
Income Tax Expense
Income tax expense decreased $1 million in the second quarter of 2006 compared with the second quarter of 2005 due to lower pre-tax income. Income tax expense increased $13 million in the first six months of 2006 compared with the same period in 2005 due to higher pre-tax income.
COMPETITION
In 2001, all of TEP’s retail customers became eligible to choose an alternative energy service provider (ESP), however only a small number of commercial and industrial customers initially chose an ESP. By 2002, none of TEP’s retail customers were served by an alternate ESP.
In January 2005, an Arizona Court of Appeals decision became final in which the Court held invalid certain portions of the ACC rules on retail competition and related market pricing. In February 2006, the ACC Staff requested that a proceeding be opened to address the issue of retail electric competition. We cannot predict what changes, if any, the ACC will make to the competition rules. Unless and until the ACC clarifies the competition rules and ESPs begin to offer to provide energy in TEP’s service area, it may not be possible for TEP’s retail customers to choose other energy providers. TEP has met all conditions required by the ACC to facilitate electric retail competition, including ACC approval of TEP’s direct access tariffs. See Rates, ACC Order to Review the Settlement Agreement, below.
TEP 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 generally not financially viable alternatives for its 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
Settlement Agreement
In 1999, the ACC approved the Rules that provided a framework for the introduction of retail electric competition in Arizona, as well as the Settlement Agreement between TEP and certain customer groups related to the implementation of retail electric competition in Arizona.
The Rules and the Settlement Agreement established:
| · | a period from November 1999 through 2008 for TEP to transition its generation assets from a cost of service based rate structure to a market, or competitive, rate structure; |
| · | the recovery through rates during the transition period of $450 million of stranded generation costs through a fixed competitive transition charge (fixed CTC); |
| · | capped rates for TEP retail customers through 2008; |
| · | an ACC interim review of TEP retail rates in 2004; |
| · | unbundling of electric services with separate rates or prices for generation, transmission, distribution, metering, meter reading, billing and collection, and ancillary services; |
| · | a process for ESPs to become licensed by the ACC to sell generation services at market prices to TEP retail customers; |
| · | access for TEP retail customers to buy market priced generation services from ESPs beginning in 2000 (currently, no TEP customers are purchasing generation services from ESPs); |
| · | transmission and distribution services would remain subject to regulation on a cost of service basis; and |
| · | beginning in 2009, TEP’s generation would be market based and its retail customers would pay the market rate for generation services. |
2004 General Rate Case Information
In June 2004, as required by the Settlement Agreement, TEP filed general rate case information with the ACC. TEP’s filing did not propose any change in retail rates, and under the terms of the Settlement Agreement, no rate case filed by TEP through 2008 may result in a net rate increase. However, absent the restriction on raising rates, TEP believes that the data in its filing would justify an increase in retail rates of 16%.
48
The general rate case information used a historical test year ended December 31, 2003 and established, based on TEP’s standard offer service, that TEP was experiencing a revenue deficiency of $111 million. None of the intervenor testimony filed proposed any decrease to TEP’s rates. Testimony filed by the ACC Staff, Residential Utility Consumer Office and Arizonans for Electric Choice and Competition indicated revenue deficiencies for TEP of $67 million, $32 million and $38 million, respectively. In July 2005, the ALJ issued a procedural order suspending the remaining testimony filing deadlines and hearing in the 2004 rate review.
ACC Order to Review the Settlement Agreement
In response to the recent court ruling related to retail competition and related market pricing and a lack of agreement as to the interpretation of the Settlement Agreement by a number of participants in TEP’s rate proceedings, TEP filed a series of pleadings with the ACC beginning in May 2005 to resolve the uncertainty surrounding the methodology that will be applied to determine TEP’s rates for generation service after 2008. See Competition, above for information regarding the recent court ruling.
In September 2005, TEP filed a motion and supporting testimony with the ACC to amend the Settlement Agreement. In the motion, TEP proposed amendments to extend the benefits and protections set forth in the Settlement Agreement and provide additional price stability for TEP customers.
In April 2006, the ACC ordered that a procedure be established to allow for an expeditious and complete review of the Settlement Agreement; its effect on how TEP’s rates for generation services will be determined after December 31, 2008; TEP’s proposed amendments to the Settlement Agreement; and demand side management, renewable energy standards, and time of use tariffs.
The ALJ issued a procedural order on June 2, 2006, adopting the following schedule:
Filing | Date |
| TEP testimony | August 18, 2006 |
| ACC staff and intervenor testimony | November 17, 2006 |
| TEP rebuttal testimony | December 6, 2006 |
| ACC staff and intervenor rebuttal testimony | December 18, 2006 |
| TEP rejoinder testimony | December 29, 2006 |
| Hearings before ALJ | January 8, 2007 |
The procedural order states that the hearing shall consider the legal argument and factual basis of whether TEP is entitled to charge market-based rates or cost-of-service based generation rates commencing in 2009, whether TEP’s proposal as outlined in its application to amend the Settlement Agreement is in the public interest, and how the ACC can/should implement demand-side management, renewable energy standards and time of use tariffs.
The procedural order also states that, at this juncture, it is uncertain that the ACC can make a final determination that would implement rates in a single proceeding. Much will depend on whether the parties are able to reach agreement and the decision whether market or cost-of-service rates will be implemented in 2009. The procedural order states that, by proceeding as quickly as possible, there should be ample time to resolve all issues prior to December 31, 2008.
The procedural order directs TEP to file testimony which at a minimum shall include:
| · | a complete explanation of its proposal, including an identification of all rate elements that it |
believes would apply to each of its standard offer customers effective January 1, 2009;
| · | projected rate impacts on standard offer customers’ total bills having market-based |
generation rates as compared with cost-of-service generation rates;
| · | an explanation of how its proposals could be effective and lawful under the Track A, Track B and |
Phelps Dodge decisions; and
| · | how TEP proposes to implement demand side-management, renewable energy standards and |
time of use tariffs.
TEP cannot predict the outcome of the proceedings.
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.
By the end of 2006, electric generating capacity in Arizona is expected to be approximately 26,000 MW; an increase of 64% since 2001. A majority of the growth over the last three years is the result of 17 new or upgraded gas-fired generating units with a combined capacity of approximately 9,700 MW. The completion of Springerville Unit 3 provides 400 MW of new coal-fired generation located in Arizona.
Market Prices
The average market price for around-the-clock energy based on the Dow Jones Palo Verde Index increased in the first six months of 2006, as did the average price for natural gas based on the Permian Index. Average market prices for around-the-clock energy have continued to increase since 2003, primarily due to high natural gas prices. We cannot predict whether these higher prices will continue, or whether changes in various factors that influence demand and supply will cause prices to change during the later half of 2006.
Average Market Price for Around-the-Clock Energy | $/MWh | |||
Quarter ended June 30, 2006 | $ | 45 | ||
Quarter ended June 30, 2005 | 45 | |||
Six months ended June 30, 2006 | $ | 47 | ||
Six months ended June 30, 2005 | 45 | |||
Average Market Price for Natural Gas | $/MMBtu | |||
Quarter ended June 30, 2006 | $ | 5.55 | ||
Quarter ended June 30, 2005 | 6.10 | |||
Six months ended June 30, 2006 | $ | 6.34 | ||
Six months ended June 30, 2005 | 5.83 | |||
In addition to energy from its coal-fired facilities, TEP typically uses purchased power, supplemented by generation from its gas-fired units, to meet the summer peak demands of its retail customers. Some of these purchased power contracts are price indexed to natural gas prices. Short-term and spot power purchase prices are also closely correlated to natural gas prices. Due to its increasing seasonal gas and purchased power usage, TEP hedges a portion of its total natural gas exposure from plant fuel and gas-indexed purchased power with fixed price contracts for a maximum of three years. TEP currently has approximately 63% of this exposure hedged for the summer peak period of 2006 at a weighted average price of $6.06 per MMBtu. TEP purchases its remaining gas fuel needs and purchased power in the spot and short-term markets.
Market prices may also affect TEP’s wholesale revenues. TEP commits to future sales of energy as part of its ongoing efforts to hedge its excess generation based on projected generation capability, forward prices and generation costs. For 2006 and 2007, TEP has sold forward approximately 50 MW of fixed price energy at an average approximate price of $70 per MWh. In 2006, this energy sale excludes on-peak hours in June through September, and in 2007, excludes on-peak hours in April through September. In addition, TEP has sold forward 80,000 MWh in the fourth quarter of 2006 and 131,000 MWh in the first quarter of 2007, at average prices of $61 per MWh and $72 per MWh, respectively.
We expect the market price and demand for capacity and energy to continue to be influenced by factors including:
| · | the availability and price of natural gas; |
| · | weather; |
| · | 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; |
| · | availability of hydropower; |
| · | transmission constraints; and |
| · | environmental regulations and the cost of compliance. |
LUNA ENERGY FACILITY
In April 2006, the gas-fired combined cycle Luna plant commenced commercial operation. TEP’s one-third share of the plant’s capacity is 190 MW. Luna increases TEP’s total generating capacity by nearly 10%, to 2,194 MW, and allows TEP to displace some of its less efficient gas-fired generation and purchased power requirements. TEP’s total investment of $47 million was funded with internal cash.
COAL SUPPLY
In 2003, TEP entered into an agreement for the purchase of coal to supply Sundt Unit 4 through 2006. TEP issued a Request for Proposal for Sundt coal in March 2006 and expects to negotiate a replacement supply contract by the end of the third quarter of 2006. Based on current coal market conditions, we expect the price TEP pays for coal at Sundt Unit 4 to significantly increase after 2006. TEP’s total coal-related fuel expense across all of its plants is expected to increase by 4-6% in 2007.
EMISSION ALLOWANCES
TEP has SO2 Emission Allowances in excess of what is required to operate its generating units. The excess results primarily from a higher removal rate of SO2 emissions at Springerville Units 1 and 2 following recent upgrades to environmental plant components and related changes to plant operations. From time to time, TEP will sell a portion of its excess SO2 Emission Allowances. The table below summarizes sales in 2005 and forward sales of SO2 Emission Allowances, as of June 30, 2006.
Delivery | Allowances Sold | Estimated Pre-tax Gain (millions) | |||||
| 2005 | 15,000 | $ | 13 | ||||
| 2006 | |||||||
1st Quarter | 2,500 | 2 | |||||
2nd Quarter | 2,500 | 2 | |||||
3rd Quarter | 5,000 | 3 | |||||
| 2007 | 10,000 | 8 | |||||
In addition to the allowances contracted to be sold in 2006 and 2007, TEP expects to have approximately 20,000 excess SO2 Emission Allowances available for sale in future periods.
SPRINGERVILLE UNITS 3 AND 4
Springerville Unit 3, which commenced commercial operation on July 28, 2006, is a 400 MW coal-fired generating facility at the same site as Springerville Units 1 and 2. Tri-State is leasing 100% of Unit 3 from a financial owner. TEP will allocate a portion of the fixed costs of the existing common facilities to the additional generating unit. TEP will operate Unit 3 and expects to receive annual pre-tax benefits of approximately $15 million in the form of cost savings, rental payments, transmission revenues, and other fees. As part of the project, Tri-State provided funding to improve sulfur dioxide scrubbers, low-nitrogen oxide burners and other emission control upgrades for Units 1 and 2, which were completed in 2005.
Salt River Project (SRP) will purchase 100 MW of capacity from Tri-State under a 30-year power purchase agreement. In May 2006, SRP announced its intention to build Unit 4, a 400 MW coal-fired generating facility at the same Springerville site. Construction of Unit 4 is scheduled to begin in January 2007 and is expected to be completed in late 2009. The ACC siting permit for Unit 4 expires at the end of 2009. The EPA permit for Unit 4 requires completion by the end of 2012; however, if Unit 4 is completed by the end of 2009, it will be subject to the same emissions requirements as Unit 3. If Unit 4 is completed after 2009, it may be subject to more stringent emissions requirements. When Unit 4 is complete, TEP may 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. Given the current high level of wholesale power market prices,
we believe that it is unlikely that TEP would be required to find a replacement purchaser or purchase SRP’s 100 MW. Under the terms of existing regulatory permits, Unit 4 is required to be completed by December 31, 2009.
TEP CASH FLOWS
During 2006, 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, TEP’s cash flows may vary during the year. Cash flow from operations typically is the lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load. As of August 4, 2006, TEP had $35 million available under its Revolving Credit Facility which it may borrow if cash flows fall short of expectations or if monthly cash requirements temporarily exceed available cash balances.
The chart below shows the cash available to TEP after capital expenditures, scheduled debt payments and payments on capital lease obligations which are paid at the beginning of January and July:
Six Months Ended June 30, | 2006 | 2005 | |||||
| -Millions of Dollars- | |||||||
| Net Cash Flows - Operating Activities (GAAP) | $ | 98 | $ | 74 | |||
| Amounts from Statements of Cash Flows: | |||||||
| Less: Capital Expenditures | (82 | ) | (67 | ) | |||
| Net Cash Flows after Capital Expenditures (non-GAAP)* | 16 | 7 | |||||
| Amounts from Statements of Cash Flows: | |||||||
Less: Retirement of Capital Lease Obligations | (51 | ) | (49 | ) | |||
Plus: Proceeds from Investment in Springerville Lease Debt and Equity | 10 | 8 | |||||
| Net Cash Flows Available after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (non-GAAP)* | $ | (25 | ) | $ | (34 | ) | |
Six Months Ended June 30 | 2006 | 2005 | |||||
| -Millions of Dollars- | |||||||
| Net Cash Flows - Operating Activities (GAAP) | $ | 98 | $ | 74 | |||
| Net Cash Flows - Investing Activities (GAAP) | (121 | ) | (52 | ) | |||
| Net Cash Flows - Financing Activities (GAAP) | 18 | (88 | ) | ||||
| Net Cash Flows after Capital Expenditures (non-GAAP) | 16 | 7 | |||||
| Net Cash Flows Available after Capital Expenditures and Required Payments on Debt and Capital Lease Obligations (non-GAAP) | (25 | ) | (34 | ) | |||
* Net Cash Flows after Capital Expenditures and Net Cash Flows Available after Required Payments, both non-GAAP measures of liquidity, should not be considered as alternatives to Net Cash Flows - Operating Activities, which is determined in accordance with GAAP as a measure of liquidity. We believe that Net Cash Flows after Capital Expenditures and Net Cash Flows Available after Required Payments provide useful information to investors as measures of liquidity and our ability to fund our capital requirements, make required payments on debt and capital lease obligations, and pay dividends to UniSource Energy.
Operating Activities
In the six months of 2006, net cash flows from operating activities increased by $24 million compared with the same period in 2005. Net cash flows were impacted by:
2006 included:
| · | a $16 million increase in cash receipts from electric retail and wholesale sales, net of fuel and purchased energy costs, due primarily to retail customer growth and hot summer weather, the higher availability of excess power to sell into the wholesale market and higher wholesale power prices; |
| · | a $12 million decrease in payments for O&M costs due to fewer coal plant outages compared with last year; |
| · | a $12 million decrease in total interest paid due to lower capital lease obligation balances, lower long-term debt balances and lower annual fees under TEP’s Credit Agreement that was entered into in May 2005. |
2005 included:
| · | $11 million of interest received from UniSource Energy related to an inter-company note repaid in the first quarter of 2005. |
Investing Activities
Net cash used for investing activities was $68 million higher in the six months of 2006 compared with the same period in 2005 primarily due to:
| · | a $14 million increase in capital expenditures related to TEP’s share of the construction costs of Luna, and growth and maintenance of TEP’s electric system; and |
| · | TEP’s purchase of a 14% equity interest in Springerville Unit 1 Lease, which represents 55 MW of capacity. |
Financing Activities
Net cash used for financing activities was $106 million lower in the first six months of 2006 compared with the same period in 2005. The following factors contributed to the decrease:
2006 included:
| · | a $20 million increase in net proceeds from borrowings under TEP’s Revolving Credit Facility; offset by |
| · | a $2 million increase in scheduled payments made on capital lease obligations; |
2005 included:
| · | a $110 million equity investment by UniSource Energy; and |
| · | proceeds of $95 million from UniSource Energy as a repayment for an inter-company loan; offset by |
| · | the use of $282 million to repay long-term debt; and |
| · | $5 million for debt issuance and retirement costs. |
At June 30, 2006, there were $60 million in outstanding borrowings under TEP’s revolving credit facility. As of August 4, 2006, TEP repaid $35 million of its outstanding borrowings and expects to repay the balance by the end of 2006. As of August 4, 2006, cash and cash equivalents available to TEP were approximately $35 million.
Capital Lease Obligations
At June 30, 2006, TEP had $656 million of total capital lease obligations on its balance sheet. The table below provides a summary of the outstanding lease amounts in each of the obligations.
Leased Asset | Capital Lease Obligation Balance at June 30, 2006 | Expiration | |||||
| - In Millions - | |||||||
| Springerville Unit 1 | $ | 381 | 2015 | ||||
| Springerville Coal Handling Facilities | 123 | 2015 | |||||
| Springerville Common Facilities | 105 | 2020 | |||||
| Sundt Unit 4 | 46 | 2011 | |||||
| Other Leases | 1 | 2008 | |||||
| Total Capital Lease Obligations | $ | 656 | |||||
Except for TEP’s 14% equity ownership in the Springerville Unit 1 Leases and its 13% equity ownership in the Springerville Coal Handling Facilities, TEP will not own these assets at the expiration of the leases. TEP may renew the leases or purchase the leased assets at such time. The renewal and purchase options for Springerville Unit 1 and Sundt Unit 4 are generally for fair market value as determined at that time, while the purchase price option is fixed for the Springerville Coal Handing Facilities and Common Facilities.
Investments in Springerville Lease Debt and Equity
At June 30, 2006, TEP had $194 million of investments in lease debt and equity on its balance sheet. The yields on TEP’s investments in Springerville Lease Debt, at the date of purchase, range from 8.9% to 12.7%. The table below provides a summary of the investment balances in the leases.
Lease Debt and Equity Investment Balance | |||||||
Leased Asset | June 30, 2006 | December 31, 2005 | |||||
| - In Millions - | |||||||
| Springerville Unit 1 | $ | 130 | $ | 91 | |||
| Springerville Coal Handling Facilities | 64 | 65 | |||||
| Total Investment In Lease Debt and Equity | $ | 194 | $ | 156 | |||
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 was required to arrange for refinancing or refunding of the secured notes underlying the leases prior to June 30, 2006 in order to avoid a special event of loss. A special event of loss results in a termination of the leases and would require TEP to repurchase the facilities for approximately $125 million. TEP refinanced the lease debt totaling $68 million in June 2006, and the leases were amended to remove the requirement that the notes be periodically refinanced to avoid the occurrence of a special event of loss. The notes were amended to provide that interest will be payable at LIBOR plus 1.5% for the next three years with the spread over LIBOR increasing every three years thereafter to 2% by June 2018. Prior to the refinancing, the interest rate was LIBOR plus 4%. The refinancing had no impact on the Springerville Common Facilities capital lease obligation or asset.
A portion of the rent payable by TEP pursuant to the Springerville Common Facilities Leases is determined by the amount of interest payable on the floating rate lease debt. On June 8, 2006, TEP entered into an interest rate swap to hedge a portion of the interest rate risk associated with the portion of rent determined by the interest rate on this debt. This swap has the effect of fixing the interest rate portion of rent at 7.27% on $37 million of the lease debt.
The LIBOR rate in effect on June 30, 2006 was 5.31%, and was 3.10% on June 30, 2005, which resulted in a total interest rate on the lease debt of 6.81% at June 30, 2006 and 7.26% at June 30, 2005.
TEP Credit Agreement
In May 2005, TEP entered into a new $401 million Credit Agreement (TEP Credit Agreement) to replace its previous $401 million credit agreement. The TEP Credit Agreement includes a $60 million revolving credit
facility and a $341 million letter of credit facility to support $329 million of tax-exempt variable rate bonds. The TEP Credit Agreement expires in May 2010 and is secured by $401 million of 1992 Mortgage Bonds. As of June 30, 2006, TEP was in compliance with the terms of the TEP Credit Agreement.
***
INCOME TAX MATTERS
See UniSource Energy, Liquidity and Capital Resources, Income Tax Matters, Internal Revenue Service Matters, above.
CONTRACTUAL OBLIGATIONS
There have been no significant changes in TEP’s contractual obligations or other commercial commitments from those reported in TEP’s 2005 Annual Report on Form 10-K, other than:
| · | TEP’s purchased power agreement with Tri-State for 100 MW of system capacity will become effective September 1, 2006. This contract allows Tri-State to reduce the contract capacity in increments of 25 MW with 90 days notice. To date, TEP has received no such notice. If Tri-State does not give notice to reduce capacity, the minimum capacity payments will be $10 million for 2006, $31 million annually in 2007 through 2010, and $21 million in 2011. |
| · | At June 30, 2006, TEP has commitments to pay various home builders $3 million in builder incentives through 2007 to construct TEP Guarantee Homes that meet the highest construction and energy-efficiency standards available. |
| · | In June 2006, TEP refinanced variable rate notes underlying the Springerville Common Facilities Leases. A portion of the rent payable by TEP pursuant to the Springerville Common Facilities Leases is determined by the amount of interest payable on the variable rate lease debt. The notes were amended to provide that interest will be payable at LIBOR plus 1.5% for the next three years with the spread over LIBOR increasing every three years thereafter to 2% by June 2018. Prior to the refinancing, the interest rate was LIBOR plus 4%. TEP estimates its obligation using a forward LIBOR curve. At June 30, 2006, TEP’s obligations under the Springerville Common Facilities Leases total: $7 million in 2006; $6 million in 2007; $6 million in 2008; $6 million in 2009; $6 million in 2010; $6 million in 2011; and $145 million thereafter. TEP’s obligation does not include the impact of the 2006 interest rate swap. |
| · | In June 2006, TEP purchased a 14% equity ownership interest in the Springerville Unit 1 Leases. As a result, TEP amended the Springerville Unit 1 Lease related to such interest to reduce TEP’s rent payable to equal the scheduled amount of principal and interest payable on the debt issued by the owner trustee. At June 30, 2006, TEP’s obligations under the Springerville Unit 1 Leases total: $85 million in 2006; $83 million in 2007; $82 million in 2008; $30 million in 2009; $57 million in 2010; $83 million in 2011; and $317 million thereafter. |
| · | TEP entered into operating leases in the first quarter 2006 for equipment at Springerville totaling $2 million over three years. |
DIVIDENDS ON COMMON STOCK
TEP can pay dividends if it maintains compliance with the TEP Credit Agreement and certain financial covenants. As of June 30, 2006, TEP was in compliance with the terms of the TEP Credit Agreement.
The ACC Holding Company Order, as modified by the UES Settlement Agreement, restricted the amount of dividends that TEP may pay to UniSource Energy. Until TEP’s ratio of common equity to total capitalization (excluding capital lease obligations) equaled 40%, TEP could not pay dividends in excess of 75% of its net income. As of June 30, 2006, TEP’s ratio of common equity to total capitalization (excluding capital lease obligations) was 41.3%.
The Federal Power Act states that dividends shall not be paid out of funds properly included in capital accounts. 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.
Three Months Ended June 30, 2006 Compared with the Three Months Ended June 30, 2005
UNS Gas reported a net loss of $1 million in the second quarter of 2006 and reported net income of less than $1 million in the second quarter of 2005.
As of June 30, 2006, UNS Gas had approximately 142,000 retail customers, a 5% increase from last year. The table below shows UNS Gas’ therm sales and revenues for the second quarters of 2006 and 2005.
Sales | Revenue | ||||||||||||
Three Months Ended June 30, | 2006 | 2005 | 2006 | 2005 | |||||||||
| - Millions of Therms - | - Millions of Dollars - | ||||||||||||
Retail Therm Sales: | |||||||||||||
Residential | 9 | 11 | $ | 14 | $ | 13 | |||||||
Commercial | 5 | 6 | 7 | 6 | |||||||||
Industrial | - | 1 | 1 | 1 | |||||||||
Public Authorities | 1 | 1 | 1 | 1 | |||||||||
Total Retail Therm Sales | 15 | 19 | 23 | 21 | |||||||||
Transport | - | - | 1 | 1 | |||||||||
Negotiated Sales Program (NSP) | 4 | 7 | 2 | 4 | |||||||||
Total Therm Sales | 19 | 26 | $ | 26 | $ | 26 | |||||||
Despite the 5% increase in retail customers, retail therm sales were 21% lower in the second quarter of 2006 compared with the same period last year, due primarily to mild winter weather. Retail revenues were higher by 10% due primarily to the PGA surcharge increase, which became effective in November 2005. See Factors Affecting Results of Operations, Rates and Regulation, Energy Cost Adjustment Mechanism, below.
Through a Negotiated Sales Program (NSP) approved by the ACC, UNS Gas supplies natural gas to some of its large transportation customers. 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 PGA mechanism which reduces the gas commodity price. See Factors Affecting Results of Operations, Rates and Regulation, Energy Cost Adjustment Mechanism, below.
The table below provides summary financial information for UNS Gas.
Three Months Ended June 30, | 2006 | 2005 | |||||
| - Millions of Dollars - | |||||||
| Gas Revenues | $ | 26 | $ | 26 | |||
| Other Revenues | - | 1 | |||||
Total Operating Revenues | 26 | 27 | |||||
| Purchased Gas Expense | 18 | 17 | |||||
| Other Operations and Maintenance Expense | 6 | 5 | |||||
| Depreciation and Amortization | 2 | 2 | |||||
| Taxes other than Income Taxes | 1 | 1 | |||||
Total Other Operating Expenses | 27 | 25 | |||||
Operating Income | (1 | ) | 2 | ||||
| Total Interest Expense | 1 | 2 | |||||
| Income Tax Expense (Benefit) | (1 | ) | - | ||||
Net Income | $ | (1 | ) | $ | - | ||
Six Months Ended June 30, 2006 Compared with the Six Months Ended June 30, 2005
UNS Gas reported net income of $3 million in the first six months of 2006 and net income of $4 million in the same period last year.
The table below shows UNS Gas’ therm sales and revenues for the six months ending June 30, 2006 and 2005.
Sales | Revenue | ||||||||||||
Six Months Ended June 30, | 2006 | 2005 | 2006 | 2005 | |||||||||
| - Millions of Therms - | - Millions of Dollars - | ||||||||||||
Retail Therm Sales: | |||||||||||||
Residential | 39 | 41 | $ | 54 | $ | 44 | |||||||
Commercial | 16 | 16 | 20 | 15 | |||||||||
Industrial | 2 | 2 | 2 | 1 | |||||||||
Public Authorities | 4 | 4 | 5 | 3 | |||||||||
Total Retail Therm Sales | 61 | 63 | 81 | 63 | |||||||||
Transport | - | - | 1 | 2 | |||||||||
Negotiated Sales Program (NSP) | 9 | 12 | 7 | 8 | |||||||||
Total Therm Sales | 70 | 75 | $ | 89 | $ | 73 | |||||||
Retail therm sales were 3% lower in the first six months of 2006 compared with the same period last year, due primarily to mild winter weather. Retail revenues were higher by 29% due primarily to the PGA surcharge increase, which became effective in November 2005. See Factors Affecting Results of Operations, Rates and Regulation, Energy Cost Adjustment Mechanism, below.
The table below provides summary financial information for UNS Gas.
Six Months Ended June 30, | 2006 | 2005 | |||||
| - Millions of Dollars - | |||||||
| Gas Revenues | $ | 89 | $ | 73 | |||
| Other Revenues | 1 | 1 | |||||
Total Operating Revenues | 90 | 74 | |||||
| Purchased Gas Expense | 64 | 48 | |||||
| Other Operations and Maintenance Expense | 12 | 11 | |||||
| Depreciation and Amortization | 3 | 3 | |||||
| Taxes other than Income Taxes | 2 | 2 | |||||
Total Other Operating Expenses | 81 | 64 | |||||
Operating Income | 9 | 10 | |||||
| Total Interest Expense | 3 | 3 | |||||
| Income Tax Expense (Benefit) | 3 | 3 | |||||
Net Income | $ | 3 | $ | 4 | |||
RATES AND REGULATION
Energy Cost Adjustment Mechanism
UNS Gas’ retail rates include a PGA mechanism intended to address the volatility of natural gas prices and allow UNS Gas to recover its actual commodity costs, including transportation, through a price adjustor. The difference between UNS Gas’ actual gas and transportation costs and the cost of gas and transportation recovered through base rates are deferred and recovered or repaid through the PGA mechanism.
The PGA mechanism has two components, the PGA factor and the PGA surcharge or credit. The PGA factor is a mechanism that compares the twelve-month rolling weighted average gas cost to the base cost of gas, and automatically adjusts monthly, subject to limitations on how much the price per therm may change in a twelve month period. The actual gas and transportation costs that are either under or over collected through the base rate of $0.40 per therm or $4.00 per MMBtu and the PGA factor are charged or credited to a balancing account (PGA bank). In the six months ended June 30, 2006, the average PGA factor was approximately $0.32 per therm or $3.20 per MMBtu.
The current annual cap on the maximum increase in the PGA factor is $0.10 per therm in a twelve month period. In January 2006, UNS Gas filed a request with the ACC to increase the cap to allow for more timely recovery of actual gas costs. In July 2006, UNS Gas requested this application be consolidated with its general rate case proceeding. See General Rate Case Filing, below.
When ACC-designated under or over recovery trigger points of $6.2 million and $4.5 million, respectively, are met, UNS Gas may request a PGA surcharge or credit with the goal of collecting or returning the amount deferred from or to customers over a period deemed appropriate by the ACC.
In 2005, the ACC approved the following PGA surcharges:
Surcharge Amount Per Therm | Period In Effect |
| $0.15 | November 2005 - February 2006 |
| $0.25 | March 2006 - April 2006 |
| $0.30 | May 2006 - June 2006 |
| $0.35 | July 2006 - September 2006 |
| $0.25 | October 2006 - November 2006 |
| $0.20 | December 2006 - February 2007 |
| $0.25 | March 2007 - April 2007 |
The PGA bank balance was over-collected by $3 million at June 30, 2006. Changes in the market price for gas, sales volumes and surcharge changes could significantly change the PGA bank balance in the future.
General Rate Case Filing
UNS Gas’ current rates have been in place since August 2003 and were designed to provide a 9.05% return on original cost rate base of $118 million. As a result of increased growth in UNS Gas’ service territory and the related increase in capital expenditures and operating costs, such current rates are inadequate for UNS Gas to recover its costs and earn a reasonable rate of return on its investment. In July 2006, UNS Gas filed a general rate case. Below is a table that summarizes UNS Gas’ request:
| Test year | Year ended December 31, 2005 |
| Original cost rate base | $162 million |
| Revenue deficiency | $10 million |
| Total rate increase (over test year revenues) | 7% |
| Cost of debt | 6.60% |
| Cost of equity | 11.00% |
| Hypothetical capital structure | 50% equity / 50% debt |
| Weighted average cost of capital | 8.80% |
UNS Gas also requested modifications to its PGA mechanism to help address problems posed by volatile gas prices, inappropriate price signals to customers and the potential for over or under collections to result in the accumulation of large bank balances. UNS Gas expects the ACC to rule on its rate case in the second half of 2007. Under the terms of the UES Settlement Agreement, new rates cannot go into effect before August 1, 2007.
UNS Gas’ capital requirements consist primarily of capital expenditures. In the first six months of 2006, capital expenditures were $12 million. During 2006, UNS Gas expects operating cash flows to fund a portion of its construction expenditures. UNS Gas will meet its remaining cash needs through a combination of existing cash,
capital contributions from UniSource Energy and borrowings under the UNS Gas/UNS Electric Revolver (as defined below).
The table below provides summary information for operating cash flow and capital expenditures for the first six months of 2006 and 2005.
Six Months Ended June 30, | 2006 | 2005 | |||||
| - Millions of Dollars - | |||||||
| Net Cash Flows - Operating Activities | $ | 23 | $ | 14 | |||
| Capital Expenditures | 12 | 13 | |||||
UNS Gas/UNS Electric Revolver
In April 2005, UNS Gas and UNS Electric entered into a $40 million three-year unsecured revolving credit agreement due in April 2008, with a group of lenders (the UNS Gas/UNS Electric Revolver). Either borrower may borrow up to a maximum of $30 million; however, the total combined amount borrowed cannot exceed $40 million. UNS Gas and UNS Electric intend to use the proceeds of any loans or letters of credit for general corporate purposes. As of June 30, 2006, UNS Gas and UNS Electric were in compliance with the terms of the agreement.
UNS Gas expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes and to fund a portion of capital expenditures. As of June 30, 2006, UNS Gas had no borrowings outstanding under the UNS Gas/UNS Electric Revolver.
Senior Unsecured Notes
UNS Gas has $100 million of senior unsecured notes that are guaranteed by UES. The note purchase agreement for UNS Gas restricts transactions with affiliates, mergers, liens, restricted payments and incurrence of indebtedness, and also contains a minimum net worth test. As of June 30, 2006, UNS Gas was in compliance with the terms of its note purchase agreement.
UNS Gas must meet a leverage test and an interest coverage test to issue additional debt or to pay dividends. However, UNS Gas may, without meeting these tests, refinance existing debt and incur up to $7 million in short-term debt.
INCOME TAX MATTERS
See UniSource Energy, Liquidity and Capital Resources, Income Tax Matters, Internal Revenue Service Matters, above.
DIVIDENDS ON COMMON STOCK
The ACC limits dividend payments by UNS Gas to 75% of earnings, until the ratio of UNS Gas’ common equity to total capitalization reaches 40%. At June 30, 2006, the ratio of common equity to total capitalization for UNS Gas was 45.4%.
The note purchase agreement for UNS Gas contains restrictions on dividends. UNS Gas may pay dividends so long as (a) no default or event of default exists and (b) it could incur additional debt under the debt incurrence test. See Senior Unsecured Notes, above. It is unlikely; however, that UNS Gas will pay dividends in the next few years due to expected cash requirements for capital expenditures.
Three Months Ended June 30, 2006 Compared with the Three Months Ended June 30, 2005
UNS Electric reported net income of $1 million in the second quarters of 2006 and 2005. 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.
As of June 30, 2006, UNS Electric had approximately 92,000 retail customers, a 5% increase from last year. The table below shows UNS Electric’s kWh sales and revenues for the second quarters of 2006 and 2005.
Sales | Revenue | ||||||||||||
Three Months Ended June 30, | 2006 | 2005 | 2006 | 2005 | |||||||||
| - Millions of kWh - | - Millions of Dollars - | ||||||||||||
Electric Retail Sales: | |||||||||||||
Residential | 193 | 170 | $ | 19 | $ | 17 | |||||||
Commercial | 164 | 156 | 16 | 16 | |||||||||
Industrial | 49 | 45 | 4 | 3 | |||||||||
Other | 1 | 1 | - | - | |||||||||
Total Electric Retail Sales | 407 | 372 | $ | 39 | $ | 36 | |||||||
Retail kWh sales were 9% higher in the second quarter of 2006 compared with the same period last year due to customer growth and warm weather.
The table below provides summary financial information for UNS Electric.
Three Months Ended June 30, | 2006 | 2005 | |||||
| - Millions of Dollars - | |||||||
| Electric Revenues | $ | 39 | $ | 36 | |||
| Other Revenues | 1 | - | |||||
Total Operating Revenues | 40 | 36 | |||||
| Purchased Energy Expense | 27 | 24 | |||||
| Other Operations and Maintenance Expense | 6 | 5 | |||||
| Depreciation and Amortization | 3 | 3 | |||||
| Taxes other than Income Taxes | 1 | 1 | |||||
Total Other Operating Expenses | 37 | 33 | |||||
Operating Income | 3 | 3 | |||||
| Total Interest Expense | 1 | 1 | |||||
| Income Tax Expense | 1 | 1 | |||||
Net Income | $ | 1 | $ | 1 | |||
Six Months Ended June 30, 2006 Compared with the Six Months Ended June 30, 2005
UNS Electric reported net income of $2 million in the first six months of 2006 and $1 million in the same period last year. The table below shows UNS Electric’s kWh sales and revenues for the first six months of 2006 and 2005.
Sales | Revenue | ||||||||||||
Six Months Ended June 30, | 2006 | 2005 | 2006 | 2005 | |||||||||
| - Millions of kWh - | - Millions of Dollars - | ||||||||||||
Electric Retail Sales: | |||||||||||||
Residential | 356 | 321 | $ | 36 | $ | 33 | |||||||
Commercial | 294 | 278 | 29 | 29 | |||||||||
Industrial | 95 | 87 | 7 | 6 | |||||||||
Other | 2 | 2 | 1 | - | |||||||||
Total Electric Retail Sales | 747 | 688 | $ | 73 | $ | 68 | |||||||
Retail kWh sales were 9% higher in the first six months of 2006 compared with the same period last year due to customer growth and warm weather.
The table below provides summary financial information for UNS Electric.
Six Months Ended June 30, | 2006 | 2005 | |||||
| - Millions of Dollars - | |||||||
| Electric Revenues | $ | 73 | $ | 68 | |||
| Other Revenues | 1 | - | |||||
Total Operating Revenues | 74 | 68 | |||||
| Purchased Energy Expense | 49 | 45 | |||||
| Other Operations and Maintenance Expense | 12 | 12 | |||||
| Depreciation and Amortization | 6 | 5 | |||||
| Taxes other than Income Taxes | 2 | 2 | |||||
Total Other Operating Expenses | 69 | 64 | |||||
Operating Income | 5 | 4 | |||||
| Total Interest Expense | 2 | 2 | |||||
| Income Tax Expense | 1 | 1 | |||||
Net Income | $ | 2 | $ | 1 | |||
COMPETITION
As required by the ACC order approving UniSource Energy’s acquisition of the Citizens’ Arizona gas and electric assets, in 2003, UNS Electric filed with the ACC a plan to open its service territories to retail competition by December 31, 2003. The plan addressed all aspects of implementation. It included 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. UNS Electric’s direct access rates for both transmission and ancillary services would be based upon its FERC Open Access Transmission Tariff. The plan is subject to review and approval by the ACC, which has not yet considered the plan. As a result of the court decisions concerning the ACC’s competition Rules, we are unable to predict when and how the ACC will address this plan. See Tucson Electric Power Company, Factors Affecting Results of Operations, Competition, above for information regarding the Arizona Court of Appeals decision.
RATES AND REGULATION
Energy Cost Adjustment Mechanism
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. The ACC has approved a PPFAC surcharge of $0.01825 per kWh to recover transmission costs and the cost of the current full-requirements power supply agreement with PWCC.
General Rate Case Filing
UNS Electric expects to file a general rate case in the fourth quarter of 2006. Under the terms of the UES Settlement Agreement, new rates cannot go into effect until August 2007.
UNS Electric’s capital requirements consist of capital expenditures, which were $19 million in the first six months of 2006.
To improve the reliability of service in Santa Cruz County, in June 2006 UNS Electric completed the installation of a 20 MW gas-fired combustion turbine at the Valencia site, and plans to upgrade its existing 115 kV line over time. In the first six months of 2006, UNS Electric’s capital expenditures included $5 million related to the turbine and expects its capital expenditures for the remainder of 2006 to include approximately $1 million related to the turbine project.
During 2006, UNS Electric expects to generate sufficient operating cash flows to fund approximately 50% of its construction expenditures. In June 2006, UniSource Energy contributed $10 million of capital to UNS Electric. UNS Electric will meet its remaining cash needs through a combination of capital contributions from UniSource Energy and borrowings under the revolving credit facility.
The table below provides summary information for operating cash flow and capital expenditures for the first six months of 2006 and 2005.
Six Months Ended June 30, | 2006 | 2005 | |||||
| - Millions of Dollars - | |||||||
| Net Cash Flows - Operating Activities | $ | 9 | $ | 9 | |||
| Capital Expenditures | 19 | 9 | |||||
UNS Gas/UNS Electric Revolver
See UNS Gas, Liquidity and Capital Resources, UNS Gas/UNS Electric Revolver above for description of UNS Electric’s unsecured revolving credit agreement.
UNS Electric expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes and to fund a portion of its capital expenditures. As of June 30, 2006, UNS Electric had $5 million outstanding under the UNS Gas/UNS Electric Revolver. At August 4, 2006, UNS Electric had $5 million outstanding under the UNS Gas/UNS Electric Revolver.
Senior Unsecured Notes
UNS Electric has $60 million of 7.61% senior unsecured notes outstanding due in 2008 that are guaranteed by UES. The note purchase agreements for 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. As of June 30, 2006, UNS Electric was in compliance with the terms of its note purchase agreement.
UNS Electric must meet a leverage test and an interest coverage test to issue additional debt or to pay dividends. However, UNS Electric may, without meeting these tests, refinance existing debt and incur up to $5 million in short-term debt.
INCOME TAX MATTERS
See UniSource Energy, Liquidity and Capital Resources, Income Tax Matters, Internal Revenue Service Matters, above.
DIVIDENDS ON COMMON STOCK
The ACC limits dividend payments by UNS Electric to 75% of earnings, until the ratio of common equity to total capitalization reaches 40%. At June 30, 2006, the ratio of common equity to total capitalization for UNS Electric was 50.7%.
The note purchase agreement for UNS Electric contains restrictions on dividends. UNS Electric may pay dividends so long as (a) no default or event of default exists and (b) it could incur additional debt under the debt incurrence test. See Senior Unsecured Notes, above. It is unlikely; however, that UNS Electric will pay dividends in the next few years due to expected cash requirements for capital expenditures.
The table below summarizes the income and losses from continuing operations for the Other non-reportable segments for the three and six-month periods ended June 30, 2006 and 2005:
Three Months Ended June 30, | 2006 | 2005 | |||||
| - Millions of Dollars - | |||||||
| Millennium Investments | $ | 1 | $ | - | |||
| UniSource Energy Parent Company | (2 | ) | (2 | ) | |||
Total Other | $ | (1 | ) | $ | (2 | ) | |
Six Months Ended June 30, | 2006 | 2005 | |||||
| - Millions of Dollars - | |||||||
| Millennium Investments | $ | - | $ | (1 | ) | ||
| UniSource Energy Parent Company | (3 | ) | (2 | ) | |||
Total Other | $ | (3 | ) | $ | (3 | ) | |
UniSource Energy Parent Company
In 2006 and 2005, UniSource Energy parent company expenses include interest expense (net of tax) related to the UniSource Energy Convertible Senior Notes, the UniSource Credit Agreement and, in the first three months of 2005, a note payable from UniSource Energy to TEP, which was repaid in March 2005.
Millennium Investments
Millennium Investments, excluding the discontinued operations of Global Solar, recorded after-tax income of $1 million in the second quarter of 2006 and after-tax income of less than $1 million in the first six months of 2006. In the second quarter of 2005, results include after-tax losses of less than $1 million each from several of Millennium’s investments and after-tax losses of $1 million in the first six months of 2005.
FACTORS AFFECTING RESULTS OF OPERATIONS
Millennium Investments
On March 31, 2006, Millennium sold Global Solar for $16 million in cash and an option to purchase, under certain conditions, 5% to 10% of Global Solar at a future date. The option is exercisable, upon the occurrence of certain events, beginning in April 2013 and expires in April 2016. In the first quarter of 2006, UniSource Energy recorded an after-tax loss of approximately $3 million related to the discontinued operations and disposal of Global Solar.
In January 2006, Millennium sold its equity investment in MicroSat, which was written down in December 2005 to the value at which it was sold.
MEG’s activities consist of managing a small number of remaining positions, including a hedge, which are expected to close by early 2008. As of June 30, 2006, the fair value of MEG’s trading assets was $15 million and the fair value of MEG’s trading liabilities was $6 million.
Millennium is in the process of selling its remaining interest in Nations Energy Corporation.
LIQUIDITY AND CAPITAL RESOURCES
In June 2006, Millennium funded $2 million to Haddington under an existing commitment. Millennium’s remaining commitments are $1 million to Valley Ventures and less than $1 million to Haddington.
In June 2006, Millennium received the remaining payment of $5 million on a note receivable from a subsidiary of Mirant Corporation.
In July 2006, Millennium funded the remainder of its commitment to IPS. Millennium’s equity ownership in IPS is less than 10%.
UniSource Energy has ceased making loans or equity contributions to Millennium. We anticipate that the funding required for Millennium’s remaining commitments will be provided only out of existing Millennium cash or cash returns from Millennium investments. We believe such cash and returns will be adequate to fund Millennium’s remaining commitments.
As of August 4, 2006, cash and cash equivalents available to Millennium were approximately $37 million.
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 Estimates 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 Estimates below. Other significant accounting policies and recently issued accounting standards are discussed in the 2005 Annual Report on Form 10-K, Note 1 of Notes to Consolidated Financial Statements - Nature of Operations and Summary of Significant Accounting Estimates.
ACCOUNTING FOR RATE REGULATION
TEP, UNS Gas and UNS Electric generally use the same accounting policies and practices used by unregulated companies for financial reporting under GAAP. However, sometimes these principles, such as the Financial Accounting Standards Board’s (FASB) 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, UNS Gas and UNS Electric’s retail rates, the ACC may not allow TEP, UNS Gas or UNS Electric to currently charge their customers to recover certain expenses, but instead may require that these expenses be charged to customers in the future. In this situation, FAS 71 requires that TEP, UNS Gas and UNS Electric defer these items and show them as regulatory assets on the balance sheet until TEP, UNS Gas and UNS Electric are allowed to charge their customers. TEP, UNS Gas and UNS Electric then amortize these items as expense to the income statement as these 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
Upon approval by the ACC of a settlement agreement (Settlement Agreement) in November 1999, TEP discontinued application of FAS 71 for its generation operations. TEP continues to apply FAS 71 to its cost-based rate regulated operations, which include the transmission and distribution portions of its business.
TEP’s transmission and distribution regulatory assets, net of regulatory liabilities, totaled $128 million at June 30, 2006. Regulatory assets of $30 million are not presently included in the rate base and consequently are not earning a return on investment. These regulatory assets are being recovered through the cost of service or are authorized to be collected in future base rates. TEP’s transmission and distribution regulatory assets, net of regulatory liabilities, totaled $163 million at December 31, 2005.
TEP regularly assesses whether it can continue to apply FAS 71 to its cost-based rate regulated 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 and its regulatory liabilities as income on its income statement. Based on the regulatory asset balances, net of regulatory liabilities, at June 30, 2006, if TEP had stopped applying FAS 71 to its remaining regulated operations, it would have recorded an extraordinary after-tax loss of approximately $77 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.
UNS Gas and UNS Electric
UNS Gas and UNS Electric’s regulatory liabilities, net of regulatory assets, collectively totaled $14 million at June 30, 2006 and $4 million at December 31, 2005. UNS Electric has $7 million of regulatory liabilities that are not included in rate base. UNS Gas and UNS Electric regularly assess whether they can continue to apply FAS 71 to their cost-based rate regulated operations. If UNS Gas and UNS Electric stopped applying FAS 71 to their regulated operations, they would write off the related balances of regulatory assets as an expense and regulatory liabilities as income on their income statements. Based on the balances of regulatory liabilities and assets at June 30, 2006, if UNS Gas and UNS Electric had stopped applying FAS 71 to their regulated operations, UNS Gas would record an extraordinary after-tax gain of $4 million and UNS Electric would record an extraordinary after-tax gain of $5 million. UNS Gas and UNS Electric’s cash flows would not be affected if they stopped applying FAS 71.
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
FASB Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (FAS 143), issued by the FASB, 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. A legal obligation can also be associated with the retirement of a long-lived asset whose timing and/or method of settlement are conditional on a future event. We are required to record a conditional asset retirement obligation at its estimated fair value if that fair value can be reasonably estimated. 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.
TEP
In 2005, TEP implemented FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47). The implementation of FIN 47 required TEP to update an existing inventory, originally created for the implementation of FAS 143, and to determine which, if any, of the conditional asset retirement obligations could be reasonably estimated. The ability to reasonably estimate conditional asset retirement obligations was a matter of management judgment, based upon management’s ability to estimate a settlement date or range of settlement dates, a method or potential method of settlement and probabilities associated with the potential dates and methods of settlement of TEP’s conditional asset retirement obligations. In determining whether its conditional asset retirement obligations could be reasonably estimated, management considered TEP’s past practices, industry practices, management’s intent and the estimated economic life of the assets. The fair value of the conditional asset retirement obligations were then estimated using an expected present value technique. Changes in management’s assumptions regarding settlement dates, settlement methods or assigned probabilities could have a material effect on the liability recorded by TEP at June 30, 2006 as well as the associated cumulative effect of the change in accounting principle recorded. The liabilities associated with conditional asset retirement obligations will be adjusted on an ongoing basis due to the passage of time and revisions to either the timing or amount of the original estimates of undiscounted cash flows. These adjustments could have a significant impact on the Consolidated Balance Sheets and Consolidated Statements of Income.
Prior to implementing 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. As of June 30, 2006, TEP had a liability of $4 million associated with its final asset retirement obligations.
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. In addition, TEP has obligations for its share of Luna to remove certain piping and evaporation ponds and to restore the ground to its original condition. TEP has estimated that its share of the cost to remove the Navajo and Four Corners facilities, to settle the San Juan environmental obligations and its share of costs at Luna will be approximately $40 million at the date of retirement. No other legal obligations to retire generation plant assets were identified.
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.
For the net cost of removal for the interim retirements from its transmission, distribution and general plant, as of June 30, 2006, TEP had accrued $79 million. As of December 31, 2005, TEP had accrued $75 million for the net cost of removal for interim retirements. The amount is recorded as a regulatory liability.
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 estimating 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 implementation 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 Settlement Agreement. See Tucson Electric Power Company, Factors Affecting Results of Operations, Rates, Settlement Agreement, above.
UES
UES has various transmission and distribution lines that operate under land leases and rights of way that contain end dates and restorative clauses. UES 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, UES is not recognizing the cost of final removal of the transmission and distribution lines in the financial statements.
For the net cost of removal for interim retirements from its transmission, distribution and general plant, UES had accrued $5 million as of June 30, 2006 and $4 million as of December 31, 2005. The amount is recorded as a regulatory liability.
PENSION AND OTHER POST RETIREMENT BENEFIT PLAN ASSUMPTIONS
We record plan assets, obligations, and expenses related to 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. We believe 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
TEP discounted its future pension plan obligations at December 31, 2005 using a rate of 5.8% for its Salaried, Union Plans and Excess Benefit Plan. The discount rate used at December 31, 2004 was 6.1% for its Salaried and Union Plans and 6.0% for its Excess Benefit Plan. TEP discounted its other postretirement plan obligations using a rate of 5.8% at December 31, 2005, compared with 5.9% at December 31, 2004. TEP determines the discount rate annually based on the rates currently available on high-quality, non-callable, long-term bonds. TEP looks to bonds that receive one of the two highest ratings given by a recognized rating agency whose future cash flows match the timing and amount of expected future benefit payments.
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. For TEP’s pension plans, a 25 basis point decrease in the discount rate would increase the accumulated benefit obligation (ABO) by approximately $6 million and the related plan expense for 2006 by approximately $1 million. A similar increase in the discount rate would decrease the ABO by approximately $6 million and the related plan expense for 2006 by approximately $1 million. For TEP’s plan for other postretirement benefits, a 25 basis point change in the discount rate would increase or decrease the accumulated postretirement benefit obligation (APBO) by approximately $2 million. A 25 basis point change in the discount rate would not have a significant impact on the related plan expense for 2006.
TEP calculates the market-related value of plan assets using the fair value of plan assets on the measurement date. TEP assumed that its plans’ assets would generate a long-term rate of return of 8.25% at December 31, 2005 and 8.5% at December 31, 2004. 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 an investment consultant and the plans’ actuary 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 change in the expected return on plan assets would not have a significant impact on pension expense for 2006.
TEP used an initial health care cost trend rate of 10.0% in valuing its postretirement benefit obligation at December 31, 2005. This rate reflects both market conditions and the plan’s experience. 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 less than $1 million.
TEP recorded a minimum pension liability in Other Comprehensive Income of approximately $24 million at December 31, 2005, compared with $20 million at December 31, 2004. This increase resulted primarily from a reduction in the assumed discount rate.
Based on the above assumptions, TEP will record pension expense of approximately $10 million and other postretirement benefit expense of $6 million ratably throughout 2006. TEP will make required pension plan contributions of $8 million in 2006. TEP’s other postretirement benefit plan is not funded. TEP expects to make benefit payments to retirees under the postretirement benefit plan of approximately $3 million in 2006.
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 discounted its future pension plan obligations using a rate of 5.9% at December 31, 2005 and 6.1% at December 31, 2004. For UES’ pension plan, a 25 basis point change in the discount rate would have minimal effect on either the ABO or the related pension expense. UES did not record a minimum pension liability or offsetting Intangible Asset at December 31, 2005. At December 31, 2004, UES recorded a minimum pension liability and offsetting Intangible Asset of less than $1 million. UES will record pension expense of $1 million in 2006. UES will make a pension plan contribution of $1 million in 2006.
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 plan is not funded. UES discounted its
other postretirement plan obligations using a rate of 5.8% at December 31, 2005, compared with 5.9% at December 31, 2004. Postretirement medical benefit expenses are insignificant to UES’ operations.
ACCOUNTING FOR DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES AND HEDGING 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. In general, TEP enters into forward purchase contracts when market conditions provide the opportunity to purchase energy for its load at prices that are below the marginal cost of its supply resources or to supplement its own resources (e.g., during plant outages and summer peaking periods). TEP enters into forward sales contracts when it forecasts that it has excess supply and the market price of energy exceeds its marginal cost. A portion of TEP’s forward contracts are considered to be normal purchases and sales 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 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. Some of these forward contracts satisfy the requirements for cash flow hedge accounting and the unrealized gains and losses are recorded in Other Comprehensive Income, a component of Common Stock Equity, rather than being reflected in the income statement.
TEP has a natural gas supply agreement under which it purchases its gas requirements for its generating units located in Tucson, Arizona at spot market prices from Southwest Gas Corporation (SWG). TEP also has agreements to purchase power that are priced using spot market gas prices. These contracts meet the definition of normal purchases and are not required to be marked to market. In an effort to minimize price risk on these purchases, TEP enters into commodity price swap agreements under which TEP purchases gas at fixed prices and simultaneously sells gas at spot market prices. The spot market price in the swap agreements is tied to the same index as the purchases under the SWG and purchased power contracts. These swap agreements, which expire during the summer months through 2009, were entered into with the goal of locking in fixed prices on at least 45% and not more than 80% of TEP’s expected summer monthly gas risk prior to entering into the month. The swap agreements are marked to market on a monthly basis; however, since the agreements satisfy the requirements for cash flow hedge accounting, the unrealized gains and losses are recorded in Other Comprehensive Income rather than being reflected in the income statement.
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.
UNS Gas does not currently have any contracts that are required to be marked to market. 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. This enables UNS Gas to provide more stable prices to its customers. These purchases are made up to three years in advance with the goal of locking in fixed prices on at least 45% and not more than 80% 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 and therefore are not required to be marked to market.
UNS Electric presently has a full requirements power supply agreement that enables it to meet its load. The agreement expires May 31, 2008 and UNS Electric is in the process of replacing this energy resource. In order to reduce exposure to energy price risk resulting from the procurement of power, UNS Electric has entered into forward power purchase contracts for specified amounts of energy at specified prices over a given period of time, within established limits. UNS Electric’s forward power purchase contracts meet the definition of a derivative and are marked to market by recording unrealized gains or losses and adjusting the related assets and liabilities on a monthly basis to reflect the market prices at the end of the month. Certain of these contracts are accounted for as cash flow hedges. Unrealized gains and losses resulting from the change in the fair value of derivatives that meet the criteria for cash flow hedge accounting are recorded in Other Comprehensive Income rather than in current earnings.
MEG, a wholly-owned subsidiary of Millennium, enters into swap agreements, options and forward contracts relating to Emission Allowances. MEG marks its trading contracts to market 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. In accordance with UniSource Energy’s intention to cease making capital contributions to Millennium, Millennium has significantly reduced the holdings and activity of MEG. MEG’s activities consist of managing a small number of remaining positions, including a hedge, which are expected to close by early 2008.
The market prices used to determine fair values for TEP, UNS Electric and MEG’s derivative instruments at June 30, 2006, are estimated based on various factors including broker quotes, exchange prices, over the counter prices and time value. For TEP’s forward power contracts, a 10% decrease in market prices would result in an increase in unrealized net losses of $1 million, while a 10% increase in market prices would result in a decrease in unrealized net losses of $1 million. For TEP’s forward power contracts that are accounted for as cash flow hedges, a 10% decrease in market prices would result in a $2 million increase in unrealized gains reported in Other Comprehensive Income, while a 10% increase in market prices would result in a $2 million decrease in unrealized gains reported in Other Comprehensive Income. For TEP’s gas swap agreements, a 10% decrease in market prices would result in a $4 million increase in unrealized losses reported in Other Comprehensive Income, while a 10% increase in market prices would result in a $4 million decrease in unrealized losses reported in Other Comprehensive Income. For UNS Electric’s forward power contracts, a 10% decrease in market prices would result in a decrease in unrealized net gains of $3 million, while a 10% increase in market prices would result in an increase in unrealized net gains of $3 million. For UNS Electric’s forward power contracts accounted for as cash flow hedges, a 10% decrease in market prices would result in a $2 million increase in unrealized net losses reported in Other Comprehensive Income, while a 10% increase in market prices would result in a $2 million decrease in unrealized net losses reported in Other Comprehensive Income. For MEG’s remaining trading contracts, a 10% decrease in market prices or a 10% increase in market prices would be less than $0.1 million. The unrealized gains and losses are reversed as contracts settle and realized gains or losses are recorded.
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 Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (FAS 133). As the DIG or the FASB continues to issue interpretations, TEP, UNS Gas and UNS Electric may change the conclusions they have reached and, as a result, the accounting treatment and financial statement impact could change in the future.
See Market Risks - Interest Rate Risk and Commodity Price Risk in Item 3.
UNBILLED REVENUE - TEP AND UES
TEP’s, UNS Gas’ and UNS Electric’s retail revenues include an estimate of MWhs/therms delivered but unbilled at the end of each period. Unbilled revenues are dependent upon a number of factors that require management’s judgment including estimates of retail sales and customer usage patterns. The unbilled revenue is estimated by comparing the estimated MWhs/therms delivered to the MWhs/therms billed to TEP, UNS Gas and UNS Electric retail customers. The excess of estimated MWhs/therms delivered over MWhs/therms billed is then allocated to the retail customer classes based on estimated usage by each customer class. TEP, UNS Gas and UNS Electric 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 and summer months and decreases during the fall and winter months. The unbilled revenue amount for UNS Gas sales increases during the fall and winter months and decreases during the spring and summer months, whereas, the unbilled revenue amount for UNS Electric sales increases during the spring and summer months and decreases during the fall and winter months.
PLANT ASSET DEPRECIABLE LIVES - TEP AND UES
We calculate depreciation expense based on our estimate of the useful lives of our plant assets. The estimated useful lives, and resulting depreciation rates used to calculate depreciation expense for the transmission and distribution businesses of TEP, UNS Gas and UNS Electric have been approved by the ACC in prior rate decisions. Depreciation rates for transmission and distribution cannot be changed without ACC approval.
The estimated remaining useful lives of TEP’s generating facilities are based on management’s best estimate of the economic life of the units. These estimates are based on engineering estimates, economic analysis, and statistical analysis of TEP’s past experience in maintaining the stations. Our generation assets are currently depreciated over periods ranging from 23 to 70 years from the original in-service dates.
During the second quarter of 2005, a study requested by the participants in the San Juan Generating Station was completed which indicated San Juan’s economic useful life had changed from previous estimates. As
a result of the study and other analysis performed, TEP lengthened the estimated useful life of San Juan from 40 to 60 years beginning April 1, 2005. TEP’s annual depreciation expense related to San Juan decreased by $6 million beginning in 2006.
DEFERRED TAX VALUATION - TEP AND MILLENNIUM
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.
At June 30, 2006, UniSource Energy had no valuation allowance. At December 31, 2005, UniSource Energy had a valuation allowance of $7 million relating to net operating loss (NOL) carryforward amounts.
The $7 million valuation allowance balance at December 31, 2005, relates to losses generated by the Millennium entities. As a result of the sale of Global Solar the NOL and related valuation allowance were removed from the UniSource Energy consolidated balance sheet. See Note 7 of Notes To Condensed Consolidated Financial Statements.
As of June 30, 2006 and December 31, 2005, UniSource Energy’s deferred income tax assets include $6 million and $9 million, respectively, related to unregulated investment losses of Millennium. These losses have not been reflected on UniSource Energy’s consolidated income tax returns. If UniSource Energy were unable to recognize such losses through its consolidated income tax return in the foreseeable future, UniSource Energy would be required to write off these deferred tax assets.
The FASB recently issued the following Statements of Financial Accounting Standards (FAS) and FASB Staff Positions (FSP):
| · | FAS 155, Accounting for Certain Hybrid Financial Instruments, issued February 2006, permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that had previously been bifurcated pursuant to Statement 133 and eliminates a restriction in Statement 140 on the passive derivative instruments that a qualifying special-purpose entity may hold. FAS 155 is effective for all financial instruments acquired or issued or subject to remeasurement in fiscal year that begin after September 15, 2006. We are evaluating the impact of FAS 155 on our financial statements. |
| · | FSP FASB Technical Bulletin 85-4-1, Accounting for Life Settlement Contracts by Third-Party Investors, issued March 2006, allows an investor to account for its investment in a life settlement contract using either the investment method or the fair value method in periods subsequent to the initial recognition of the investment. Investments accounted for under the investment method are initially recorded at transaction price (the amount the investor pays to the insured party) plus any initial direct external costs. Subsequent costs to keep the policy in force are capitalized to the carrying amount. When the insured dies, the investor recognizes, in the income statement, the difference between the carrying amount of the investment in the life settlement contract and the life insurance proceeds of the underlying life insurance policy. Investments accounted for under the fair value method are initially recorded at transaction price and are subsequently remeasured to fair value each reporting period with changes in fair value recognized in earnings in the period of the change. FSP FASB Technical Bulletin 85-4-1 is effective fiscal years beginning after June 15, 2006. We are evaluating the impact of FSP FASB Technical Bulletin 85-4-1 on our financial statements. |
| · | Emerging Issues Task Force Issue 06-3 (EITF 06-3), How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (that Is, Gross versus Net Presentation), ratified June 2006, requires disclosure of a company’s accounting policy decision to present taxes on either a gross (included in revenues and costs) or a net (excluded from revenues) basis. Additionally, a company must disclose the amounts of any taxes reported on a gross basis in interim and annual financial statements. EITF 06-3 is effective for interim and annual reporting periods beginning after December 15, 2006. See Note 12. |
| · | FIN 48, Accounting for Uncertainty in Income Taxes - an interpretation of FAS 109, issued July 2006, prescribes a recognition threshold and measurement attribute for the financial statement recognition and |
| measurement of a tax position taken in a tax return. We must determine whether it is “more-likely-than-not” that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. Once it is determined that a position meets the more-likely-than-not recognition threshold, the position is measured to determine the amount of benefit to recognize in the financial statements. Additionally, FIN 48 requires disclosure of a rollforward of total unrecognized tax benefits. We do not believe the adoption of FIN 48 will have a material effect on our financial position or results of operations. In anticipation of FIN 48, we have accounted for significant uncertain tax positions in a manner similar to that prescribed by FIN 48. FIN 48 is effective for fiscal years beginning after December 15, 2006. |
| · | In March 2006, the FASB issued a proposed FAS titled “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106 and 132(R).” The most significant provision of this proposed statement would require us to recognize the overfunded or underfunded status of the defined benefit postretirement plans in our Consolidated Balance Sheet measured as the difference between the fair value of the plans assets and benefit obligation. For a pension plan, the benefit obligation would be the projected benefit obligation; for any other postretirement benefit plans, the benefit obligation would be the accumulated postretirement benefit obligation. An overfunded status would result in the recognition of an asset and an underfunded status would result in the recognition of a liability. The adjustment required to recognize an asset or liability upon adoption of this statement, as currently proposed, would result in an expense or benefit to other comprehensive income. The FASB has indicated that it expects to issue a final statement in the third quarter of 2006 and that the statement would be effective for fiscal years ending after December 15, 2006, which would be the year ended December 31, 2006 for UniSource Energy and TEP. We are evaluating the impact this proposed statement may have on our financial condition and results of operations. Based on our benefit obligations and fair value of plan assets as of December 31, 2005, the adoption of this proposed statement, as currently drafted, could result in the recognition of a substantial liability and a corresponding charge to other comprehensive income. However, the proposed statement would not have a material effect on our results of operations. |
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, which 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. | 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 regulations and cost of compliance, FERC regulation of wholesale energy markets, and economic conditions in the western U.S. |
| 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. | Effects of restructuring initiatives in the electric industry and other energy-related industries. |
| 5. | The creditworthiness of the entities with which we transact business or have transacted business. |
| 6. | Changes affecting our cost of providing electric 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. |
| 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. | Changes in the depreciable lives of our assets. |
| 11. | Unanticipated changes in funding requirements, future liabilities and recorded expense relating to employee benefit plans due to changes in market values of retirement plan assets and health care costs, changes in accounting requirements of the FASB and new legislation. |
| 12. | The outcome of any ongoing or future litigation. |
| 13. | 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. |
MARKET RISKS
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, 2005, in addition to the interim condensed consolidated financial statements and accompanying notes presented in Items 1 and 2 of this Form 10-Q.
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 2005 Annual Report on 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 trading activities of MEG, and the fuel and power procurement activities at TEP and UES. Our Risk Management Committee, which meets on a quarterly basis and as needed, consists of officers from the finance, accounting, legal, wholesale marketing, transmission and distribution operations, 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.
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.
TEP
Purchases and Sales of Energy
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 contracts 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 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 except for approved hedging purposes.
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 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 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.
To adjust the value of its derivative forward power sales to fair value in Other Comprehensive Income and on its income statement, TEP recorded the following net unrealized gains and losses:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||
| 2006 | 2005 | 2006 | 2005 | ||||||||||
| -In Millions- | -In Millions- | ||||||||||||
| Unrealized Gain | $ | - | $ | - | $ | 2 | $ | - | |||||
TEP also recorded the following net unrealized gains and losses on Wholesale Sales and Purchased Power:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||
| 2006 | 2005 | 2006 | 2005 | ||||||||||
| -In Millions- | -In Millions- | ||||||||||||
| Unrealized Loss | $ | (1 | ) | $ | (1 | ) | $ | - | $ | (1 | ) | ||
TEP uses sensitivity analysis to measure the impact of an unfavorable change in market prices on the fair value of its derivative forward contracts. As of June 30, 2006, for TEP’s forward power contracts, a 10% decrease in market prices would result in an increase in unrealized net losses of $1 million, while a 10% increase in market prices would result in a decrease in unrealized net losses of $1 million.
For TEP’s forward power contracts that are accounted for as cash flow hedges, a 10% decrease in market prices would result in a $2 million increase in unrealized gains reported in Other Comprehensive Income, while a 10% increase in market prices would result in a $2 million decrease in unrealized gains reported in Other Comprehensive Income. The unrealized gains and losses are reversed as contracts settle and realized gains or losses are recorded.
Natural Gas
TEP is also subject to commodity price risk from changes in the price of natural gas. In addition to energy from its coal-fired facilities, TEP typically uses purchased power, supplemented by generation from its gas-fired units, to meet the summer peak demands of its retail customers and to meet local reliability needs. Some of these purchased power contracts are price indexed to natural gas prices. Short-term and spot power purchase prices are also closely correlated to natural gas prices. Due to its increasing seasonal gas and purchased power usage, TEP hedges a portion of its total natural gas exposure from plant fuel, gas-indexed purchase power and spot market purchases with fixed price contracts for a maximum of three years. TEP purchases its remaining gas fuel needs and purchased power in the spot and short-term markets.
In the first six months of 2006, the average market price of natural gas was $6.34 per MMBtu, or 9% higher than the same period in 2005. The table below summarizes TEP’s gas generation output and purchased power for the six months ended June 30, 2006 and 2005.
Six Months Ended June 30, | 2006 | 2005 | 2006 | 2005 | |||||||||
| -MWh- | % of Total Resources | ||||||||||||
| Gas-Fired Generation | 350,000 | 145,000 | 5 | % | 2 | % | |||||||
| Purchased Power | 797,000 | 681,000 | 12 | % | 11 | % | |||||||
To adjust the value of its derivative gas swap contracts to fair value in Other Comprehensive Income and on its income statement, TEP recorded the following net unrealized gains and losses:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||
| 2006 | 2005 | 2006 | 2005 | ||||||||||
| -In Millions- | -In Millions- | ||||||||||||
| Unrealized (Loss) Gain | $ | (7 | ) | $ | (1 | ) | $ | (14 | ) | $ | 4 | ||
As of June 30, 2006, for TEP’s gas swap agreements, a 10% decrease in market prices would result in a $4 million increase in unrealized losses reported in Other Comprehensive Income, while a 10% increase in market prices would result in a $4 million decrease in unrealized losses reported in Other Comprehensive Income.
Coal
TEP is subject to commodity price risk from changes in the price of coal used to fuel its coal-fired generating plants. The commodity price risk from changes in the price of coal have not changed materially from the commodity price risks reported in the 2005 Annual Report on Form 10-K.
UES
UES is 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 which provides an adjustment to UNS Gas’ retail rates 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 at least 45% of its estimated gas needs in this manner.
UNS Electric is currently not exposed to commodity price risk for its purchase of electricity as it has a fixed price full-requirements supply agreement with PWCC and a PPFAC mechanism which fully recovers the costs incurred under such contract on a timely basis. This supply agreement with PWCC expires in May 2008 and UNS Electric is in the process of replacing this energy resource.
In May 2006, UNS Electric entered into a 25 MW supply agreement for the period June 2008 through December 2013. The 25 MW consists of 10 MW at a fixed price with the remaining 15 MW price indexed to natural gas prices. UNS Electric’s minimum expected annual payment under this contract is $9 million. Because a portion of the costs under this contract will vary from period to period based on the market price of gas, the PPFAC, as currently structured, may not provide recovery of the costs incurred under the new contract on a timely basis.
MEG
MEG trades emissions allowances and related instruments; however, MEG’s current activities consist of managing a small number of remaining positions, including a hedge, which are expected to close by early 2008. 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 2007. As of June 30, 2006 and December 31, 2005, the fair value of MEG’s trading assets combined with Emissions Allowances it holds in escrow was $15 million and $38 million, respectively. The fair value of MEG’s trading liabilities was $6 million at June 30, 2006 and $25 million at December 31, 2005. For the first six months of 2006, MEG reflected a $3 million unrealized loss and a $3 million realized gain on its income statement, compared with an unrealized gain of $7 million and a realized loss of $7 million in the same period last year. For MEG’s remaining trading contracts at June 30, 2006, a 10% decrease in market prices or a 10% increase in market prices would be less than $0.1 million.
| Unrealized Gain (Loss) of MEG’s Trading Activities | |||||||||||||
| - Millions of Dollars - | |||||||||||||
Source of Fair Value At June 30, 2006 | Maturity 0 - 6 months | Maturity 6 - 12 months | Maturity over 1 yr. | Total Unrealized Gain (Loss) | |||||||||
| Prices actively quoted | $ | 2 | $ | 1 | $ | 2 | $ | 5 | |||||
| Prices based on models and other valuation methods | - | - | 4 | 4 | |||||||||
| Total | $ | 2 | $ | 1 | $ | 6 | $ | 9 | |||||
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, 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.
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 June 30, 2006, TEP’s total credit exposure related to its wholesale marketing and gas hedging activities was approximately $14 million. Approximately $1 million of TEP’s exposure is to non-investment grade companies. TEP had three counterparties with exposures of greater than 10% of its total credit exposure, totaling approximately $8 million. MEG’s total credit exposure related to its trading activities was $7 million and was concentrated primarily with two counterparties. MEG has no credit exposure to non-investment grade counterparties.
UNS Gas is subject to credit risk from non-performance by its supply counterparty, BP Energy (BP), to the extent that this contract has a mark-to-market value in favor of UNS Gas. As of July 31, 2006, UNS Gas has purchased under fixed price contracts approximately 50% of its expected consumption for the 2006/2007 winter season. At June 30, 2006, the supply contract with BP was in a favorable mark-to-market position for UNS Gas. When netted against amounts owed to BP, this credit exposure was approximately $5 million.
UNS Electric has begun to enter into energy purchase agreements to replace the full requirements contract it has with PWCC that expires in May 2008. To the extent that such contracts have a positive mark-to-market value, UNS Electric is exposed to credit risk under those contracts. At June 30, 2006, UNS Electric had no credit exposure under such contracts.
Interest Rate Risk
TEP
As reported in the 2005 Annual Report on Form 10-K, TEP is exposed to interest rate risk resulting from changes in interest rates on certain of its variable rate debt obligations. In June 2006, TEP refinanced variable
rate lease debt totaling $68 million related to its Springerville Common Facilities Leases. The notes underlying the leases mature in June 2017 and January 2020. The notes were amended to provide that interest will be payable at LIBOR plus 1.5% for the next three years with the spread over LIBOR increasing every three years thereafter to 2% by June 2018. Prior to the refinancing, the interest rate was LIBOR plus 4%.
A portion of the rent payable by TEP pursuant to the Springerville Common Facilities Leases is determined by the amount of interest payable on the floating rate lease debt. On June 8, 2006, TEP entered into an interest rate swap to hedge a portion of the interest rate risk associated with the portion of rent determined by the interest rate on this debt. This swap has the effect of fixing the interest rate portion of rent at 7.27% on $37 million of the lease debt.
UniSource Energy and TEP’s Chief Executive Officer and Chief Financial Officer supervised and participated in UniSource Energy and TEP’s evaluation of their disclosure controls and procedures as such term is defined under Rule 13a - 15(e) or Rule 15d - 15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of June 30, 2006. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in UniSource Energy and TEP’s periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. These disclosure controls and procedures are also designed to ensure that information required to be disclosed by UniSource Energy and TEP in the reports that they file or submit under the Act is accumulated and communicated to management, including the principal executive and principal financial officers, or person performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation performed, UniSource Energy and TEP’s Chief Executive Officer and Chief Financial Officer concluded that UniSource Energy and TEP’s disclosure controls and procedures are effective.
While UniSource Energy and TEP continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting, there has been only one change in UniSource Energy or TEP’s internal control over financial reporting during the second quarter of 2006, that has materially affected, or is reasonably likely to materially affect, UniSource Energy or TEP’s internal control over financial reporting. During the second quarter of 2006, TEP implemented a new customer information system which integrates billing, accounts receivable, meter data management and multiple other functions that relate to the provision of customer service.
UniSource Energy’s Management’s Report on Internal Control Over Financial Reporting Under 404 of Sarbanes-Oxley appears as the first report under Item 8 in UniSource Energy’s and TEP’s 2005 Annual Report on Form 10-K and the Report of Independent Registered Public Accounting Firm appears as the second report under Item 8.
We discuss other legal proceedings in Note 6 of Notes to Consolidated Financial Statements, Commitments and Contingencies.
Cross-Complaints in Wholesale Electricity Antitrust Cases I and II
In late 2000, various California municipalities and citizens filed suits against Duke Energy Trading and Marketing, L.L.C., Reliant Energy Services, Inc. and other large suppliers of wholesale electricity alleging that Duke, Reliant, and the other large suppliers violated antitrust laws by colluding to effect the price of electricity in the California wholesale electricity market. These actions were subsequently consolidated in San Diego Superior Court in March 2002 as Wholesale Electricity Antitrust Cases I and II.
Duke and Reliant responded by filing cross-complaints against TEP and numerous other wholesale electricity market participants in April 2002. The cross complaints allege that cross-defendants sold power in significant amounts at prices the plaintiffs allege were excessive, and as participants in power sales, cross-
defendants are also liable for plaintiffs’ alleged damages. The entire action was removed to the United States District Court for the Southern District of California in May 2002. The plaintiffs responded to the removal by filing a motion for remand, and in December 2002, the District Court remanded the case back to state court.
Duke and Reliant appealed the District Court’s remand order and requested that the order be stayed pending resolution of their appeal. In December 2004, the Ninth Circuit affirmed the District Court’s order and the case was remanded to the state court. Once there, the defendants filed a joint motion to dismiss the master complaint and TEP and other cross-defendants filed a joint motion to dismiss the cross-complaints.
On October 3, 2005, the state court sustained defendants’ joint motion to dismiss and dismissed the master complaint without leave to amend. Before a hearing was held on the cross-defendants’ motion to dismiss, Duke and Reliant entered into stipulations for dismissal of their cross-complaints with TEP and the other cross-defendants. The stipulations provided that orders of dismissal would be entered upon final approval of Duke’s and Reliant’s pending settlements with the plaintiffs. On March 14, 2006, the state court granted final approval of the Duke settlement. Accordingly, TEP has been dismissed from the Duke antitrust proceeding, subject to any appeals. In June 2006, the dismissal of TEP from the Reliant proceeding became final. All complaints against TEP with respect to the Duke and Reliant wholesale electricity antitrust proceedings have been dismissed.
City of Tacoma
In June 2004, the City of Tacoma, Washington filed a lawsuit (City of Tacoma v. American Electric Power Services Corporation, et al. (U.S. District Ct. W.D. Wash.)) against TEP and various other electricity generators and marketers alleging that the defendants violated antitrust laws by colluding to affect the price of electricity in the Pacific Northwest from May 2000 through 2001. These claims are similar to those alleged in the antitrust cases against TEP and other wholesale electricity market participants described above in Cross-Complaints in Wholesale Electricity Antitrust Cases I and II. In September 2004, the case was transferred to the United States District Court for the Southern District of California. TEP along with other defendants filed a joint motion to dismiss and the motion was granted on February 11, 2005. The City of Tacoma appealed the dismissal to the Ninth Circuit and the appeal is now pending.
TEP believes these claims are without merit and intends to vigorously contest them.
The business and financial results of UniSource Energy and TEP are subject to numerous risks and uncertainties. The risks and uncertainties have not changed materially from those reported in the 2005 Annual Report on Form 10-K.
UniSource Energy conducted its annual meeting of shareholders on May 5, 2006. At that meeting, shareholders of UniSource Energy elected members of the Board of Directors and approved the UniSource Energy Corporation 2006 Omnibus Stock and Incentive Plan. The vote totals for each proposal are summarized below.
Election of Directors | Votes For | Votes Withheld | ||
| Lawrence J. Aldrich | 31,166,104 | 681,334 | ||
| Barbara M. Baumann | 31,367,626 | 479,812 | ||
| Larry W. Bickle | 31,224,759 | 622,679 | ||
| Elizabeth T. Bilby | 31,493,795 | 353,643 | ||
| Harold W. Burlingame | 31,365,694 | 481,744 | ||
| John L. Carter | 31,357,509 | 489,929 | ||
| Robert A. Elliott | 31,462,261 | 385,177 | ||
| Daniel W.L. Fessler | 31,565,821 | 281,617 | ||
| Kenneth Handy | 31,303,775 | 543,663 | ||
| Warren Y. Jobe | 31,027,851 | 819,587 | ||
| James S. Pignatelli | 31,458,545 | 388,893 | ||
| Joaquin Ruiz | 31,556,795 | 290,643 | ||
Votes For | Votes Against | Abstained | Broker Non-Vote | |
2006 Omnibus Stock and Incentive Plan | 18,890,178 | 1,918,948 | 85,842 | 10,952,470 |
Adjusted EBITDA
Adjusted EBITDA represents EBITDA excluding the cumulative effect of accounting change which is a non-cash item. EBITDA is earnings before interest, taxes, depreciation and amortization. Adjusted EBITDA is presented here as a measure of liquidity because it can be used as an indication of a company’s ability to incur and service debt and is commonly used as an analytical indicator in our industry. Adjusted EBITDA measures presented may not be comparable to similarly titled measures used by other companies. Adjusted EBITDA is not a measurement presented in accordance with United States generally accepted accounting principles (GAAP), and we do not intend Adjusted EBITDA to represent cash flows from operations as defined by GAAP. Adjusted EBITDA should not be considered to be an alternative to cash flows from operations or any other items calculated in accordance with GAAP or an indicator of our operating performance.
UniSource Energy and TEP view Adjusted EBITDA, a non-GAAP financial measure, as a liquidity measure. The most directly comparable GAAP measure to Adjusted EBITDA is Net Cash Flows - Operating Activities.
Adjusted EBITDA and Net Cash Flows - Operating Activities
UniSource Energy | |||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||
2006 | 2005 | 2006 | 2005 | ||||||||||
| - Millions of Dollars - | |||||||||||||
| Adjusted EBITDA (non-GAAP) | $ | 107 | $ | 111 | $ | 221 | $ | 195 | |||||
| Net Cash Flows - Operating Activities (GAAP) | $ | 73 | $ | 49 | $ | 125 | $ | 89 | |||||
| Net Cash Flows - Investing Activities (GAAP) | $ | (83 | ) | $ | (43 | ) | $ | (134 | ) | $ | (74 | ) | |
| Net Cash Flows - Financing Activities (GAAP) | $ | 22 | $ | (107 | ) | $ | - | $ | (66 | ) | |||
TEP | |||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||
2006 | 2005 | 2006 | 2005 | ||||||||||
| - Millions of Dollars - | |||||||||||||
| Adjusted EBITDA (non-GAAP) | $ | 96 | $ | 102 | $ | 196 | $ | 174 | |||||
| Net Cash Flows - Operating Activities (GAAP) | $ | 55 | $ | 37 | $ | 98 | $ | 74 | |||||
| Net Cash Flows - Investing Activities (GAAP) | $ | (84 | ) | $ | (32 | ) | $ | (120 | ) | $ | (53 | ) | |
| Net Cash Flows - Financing Activities (GAAP) | $ | 39 | $ | (78 | ) | $ | 18 | $ | (88 | ) | |||
Reconciliation of Adjusted EBITDA to Cash Flows from Operations
UniSource Energy | |||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||
2006 | 2005 | 2006 | 2005 | ||||||||||
| - Millions of Dollars - | |||||||||||||
Adjusted EBITDA (non-GAAP) (1) | $ | 107 | $ | 111 | $ | 221 | $ | 195 | |||||
| Amounts from the Income Statements: | |||||||||||||
Less: Income Taxes | 7 | 8 | 21 | 8 | |||||||||
Less: Total Interest Expense | 38 | 44 | 74 | 84 | |||||||||
| Changes in Assets and Liabilities and Other Non-Cash Items | 11 | (10 | ) | (1 | ) | (14 | ) | ||||||
Net Cash Flows - Operating Activities (GAAP) | 73 | 49 | 125 | 89 | |||||||||
Net Cash Flows - Investing Activities (GAAP) | (83 | ) | (43 | ) | (134 | ) | (74 | ) | |||||
Net Cash Flows - Financing Activities (GAAP) | 22 | (107 | ) | - | (66 | ) | |||||||
Net Increase (Decrease) in Cash and Cash Equivalents (GAAP) | $ | 12 | $ | (101 | ) | $ | (9 | ) | $ | (51 | ) | ||
TEP | |||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||
2006 | 2005 | 2006 | 2005 | ||||||||||
| - Millions of Dollars - | |||||||||||||
Adjusted EBITDA (non-GAAP) (1) | $ | 96 | $ | 102 | $ | 196 | $ | 174 | |||||
| Amounts from the Income Statements: | |||||||||||||
Less: Income Taxes | 8 | 9 | 19 | 7 | |||||||||
Less: Total Interest Expense | 31 | 38 | 62 | 75 | |||||||||
| Changes in Assets and Liabilities and Other Non-Cash Items | (2 | ) | (18 | ) | (17 | ) | (18 | ) | |||||
Net Cash Flows - Operating Activities (GAAP) | 55 | 37 | 98 | 74 | |||||||||
Net Cash Flows - Investing Activities (GAAP) | (84 | ) | (32 | ) | (120 | ) | (53 | ) | |||||
Net Cash Flows - Financing Activities (GAAP) | 39 | (78 | ) | 18 | (88 | ) | |||||||
Net Increase (Decrease) in Cash and Cash Equivalents (GAAP) | $ | 10 | $ | (73 | ) | $ | (4 | ) | $ | (67 | ) | ||
(1) Adjusted EBITDA was calculated as follows:
UniSource Energy | |||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||
2006 | 2005 | 2006 | 2005 | ||||||||||
| - Millions of Dollars - | |||||||||||||
Net Income (GAAP) | $ | 10 | $ | 9 | $ | 27 | $ | 6 | |||||
| Amounts from the Income Statements: | |||||||||||||
Less: Discontinued Operations - Net of Tax | - | (2 | ) | (3 | ) | (3 | ) | ||||||
Plus: Income Taxes | 7 | 8 | 21 | 8 | |||||||||
Total Interest Expense | 38 | 44 | 74 | 84 | |||||||||
Depreciation and Amortization | 33 | 33 | 63 | 67 | |||||||||
Amortization of Transition Recovery Asset | 17 | 14 | 29 | 24 | |||||||||
Depreciation included in Fuel and Other O&M | |||||||||||||
Expense (see Note 15 of Notes to Consolidated | |||||||||||||
Financial Statements) | 2 | 1 | 4 | 3 | |||||||||
Adjusted EBITDA (non-GAAP) | $ | 107 | $ | 111 | $ | 221 | $ | 195 | |||||
TEP | |||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||
2006 | 2005 | 2006 | 2005 | ||||||||||
| - Millions of Dollars - | |||||||||||||
Net Income (GAAP) | $ | 11 | $ | 12 | $ | 28 | $ | 7 | |||||
| Amounts from the Income Statements: | |||||||||||||
Plus: Income Taxes | 8 | 9 | 19 | 7 | |||||||||
Total Interest Expense | 31 | 38 | 62 | 75 | |||||||||
Depreciation and Amortization | 28 | 28 | 55 | 58 | |||||||||
Amortization of Transition Recovery Asset | 17 | 14 | 29 | 24 | |||||||||
Depreciation included in Fuel and Other O&M | |||||||||||||
Expense (see Note 15 of Notes to Consolidated | |||||||||||||
Financial Statements) | 1 | 1 | 3 | 3 | |||||||||
Adjusted EBITDA (non-GAAP) | $ | 96 | $ | 102 | $ | 196 | $ | 174 | |||||
Net Debt and Total Debt and Capital Lease Obligations - TEP
Net Debt represents the current and non-current portions of TEP’s long-term debt and capital lease obligations less investment in lease debt. Investment in lease debt is subtracted because it represents TEP’s ownership of the debt component of its own capital lease obligations. Net Debt measures presented may not be comparable to similarly titled measures used by other companies. Net Debt is not a measurement presented in accordance with GAAP and is not intended to represent debt as defined by GAAP. Net Debt should not be considered to be an alternative to debt or any other items calculated in accordance with GAAP.
As of June 30, 2006 | As of December 31, 2005 | ||||||
| - Millions of Dollars - | |||||||
| Net Debt (non-GAAP) | $ | 1,331 | $ | 1,379 | |||
| Total Debt and Capital Lease Obligations (GAAP) | $ | 1,477 | $ | 1,535 | |||
Reconciliation of Total Debt and Capital Lease Obligations to Net Debt
As of June 30, 2006 | As of December 31, 2005 | ||||||
| - Millions of Dollars - | |||||||
Total Debt (GAAP) | $ | 821 | $ | 821 | |||
| Capital Lease Obligations | 601 | 665 | |||||
| Current Portion - Capital Lease Obligations | 55 | 49 | |||||
Total Debt and Capital Lease Obligations (GAAP) | 1,477 | 1,535 | |||||
| Investment in Lease Debt | (146 | ) | (156 | ) | |||
Net Debt (non-GAAP) | $ | 1,331 | $ | 1,379 | |||
The following table reflects the ratio of earnings to fixed charges for UniSource Energy and TEP:
6 Months Ended | 12 Months Ended | |
June 30, 2006 | June 30, 2006 | |
| UniSource Energy | 1.65 | 1.78 |
| TEP | 1.73 | 1.88 |
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.uns.com. A link from UniSource Energy’s website to these SEC reports is accessible as follows: at the UniSource Energy main page, select Investor Relations from the menu shown at the top of the page; next select SEC filings from the menu shown on the Investor Relations page.
Information contained at UniSource Energy’s website is not part of any report filed with 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 or TEP file with
the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information on the
operation of the Public Reference Room is available by calling the SEC at 1-800-SEC-0330.
See Exhibit Index.
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: August 8, 2006 | /s/ | Kevin P. Larson |
Kevin P. Larson Senior Vice President and Principal Financial Officer | ||
TUCSON ELECTRIC POWER COMPANY (Registrant) | ||
| Date: August 8, 2006 | /s/ | Kevin P. Larson |
Kevin P. Larson Senior Vice President and Principal Financial Officer |
| 12(a) | -- | Computation of Ratio of Earnings to Fixed Charges - UniSource Energy. |
| 12(b) | -- | 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 Exchange Act of 1934.
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