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Atc Management Inc – ‘U-13E-1’ on 4/26/05 re: Atc Management Inc

On:  Tuesday, 4/26/05, at 2:09pm ET   ·   Effective:  4/26/05   ·   Accession #:  1133387-5-7   ·   File #:  62-02797

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  As Of                Filer                Filing    For·On·As Docs:Size              Issuer

 4/26/05  Atc Management Inc                U-13E-1     4/26/05    1:137K Atc Management Inc

Transaction Statement by an Affiliate or Independent Service Company   —   Form U-13E-1
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: U-13E-1     Transaction Statement by an Affiliate or              53    223K 
                          Independent Service Company                            


Document Table of Contents

Page (sequential) | (alphabetic) Top
 
11st Page   -   Filing Submission
11Independent Auditors' Report
12Statements of Operations for the Years Ended December 31, 2004, 2003 and 2002
13Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002
14Balance Sheets as of December 31, 2004 and 2003
15Statements of Changes in Members' Equity for the Years Ended December 31, 2004, 2003 and 2002
16Notes to Financial Statements
22Management Inc
38Management's Discussion and Analysis of Financial Condition and Results of Operations
42Rate Determination and Revenue Recognition
53Qualitative Disclosures about Market Risks
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__________________________ OMB APPROVAL -------------------------- UNITED STATES OMB Number: 3235-0162 SECURITIES AND EXCHANGE Expires: March 31, 2007 COMMISSION Estimated average burden Washington, D.C. 20549 hours per response...2.00 -------------------------- FORM U-13E-1 REPORT TO BE FILED PURSUANT TO RULE 95 UNDER THE PUBLIC HOLDING COMPANY ACT BY AN AFFILLIATE SERVICE COMPANY OR A COMPANY PRINCIPALLY ENGAGED IN THE PERFORMANCE OF SERVICES File No. ___________________________ Date of Filing: __________________________ 1. Name of company filing report (hereinafter called "Service Company"). American Transmission Company LLC 2. Address of the principal executive office of the Service Company. N19 W23993 Ridgeview Parkway West Waukesha, Wisconsin 53188 3. Name and address of person authorized to receive notices and communications from the Commission. Walter T. Woelfle Vice President, Legal and Secretary American Transmission Company LLC P.O. Box 47 Waukesha, WI 53187-0047 4. Form of organization of the Service Company (as: corporation, partnership, business trust, etc.). Wisconsin limited liability company. 5. State or other sovereign power under the laws of which the Service Company was organized, and date of organization. On June 13, 2000, the Articles of Organization were filed with the State of Wisconsin, Department of Financial Institutions 6. If the Service Company is a partnership or business trust, give the names and addresses of all partners (including limited partners) or all trustees, respectively, and give as to each partner, his share in the partnership. 7. If the Service Company is a corporation, business trust, or any other form of company, give names and addresses of the twenty largest holders of record of its outstanding voting securities and the number of shares held by each. Please see Attachment A.
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8. Names and addresses of all officers and directors of the Service Company and annual rate of compensation to each. Please see Attachment B for Names and Addresses of all officers and directors. Please see Attachment C for Annual Rate of Compensation to each director for the year 2004 (filed in connection herewith with a request for confidential treatment). Please see Attachment D for Annual Rate of Compensation to each officer for the year 2004 (filed in connection herewith with a request for confidential treatment). 9. With respect to every registered holding company and subsidiary company for which the service company is performing, or proposes to perform, services, construction or sale of goods, state: (a) Name of the company and address of its principal office; Wisconsin Power and Light Company 4902 N. Biltmore Lane P.O. Box 77007 Madison, WI 53707-1007 Alliant Energy Corporate Services 4902 N. Biltmore Lane P.O. Box 77007 Madison, WI 53707-1007 South Beloit Water, Gas and Electric Company 4902 N. Biltmore Lane P.O. Box 77007 Madison, WI 53707-1007 (b) Name of its top registered holding company; Alliant Energy Corporation (c) Whether it is a public-utility company. Yes. 10. With respect to every company which the Service Company is an affiliate and for which the Service Company is performing, or proposes to perform, services, construction or sale of goods, state: (a) Name of the company and address of its principal office; Wisconsin Power and Light Company 4902 N. Biltmore Lane P.O. Box 77007 Madison, WI 53707-1007 South Beloit Water, Gas and Electric Company 4902 N. Biltmore Lane P.O. Box 77007 Madison, WI 53707-1007 (b) The facts which cause the Service Company to be an affiliate of such company. A total of 28 investor-owned and cooperative systems, including Wisconsin Power and Light Company, and South Beloit Water, Gas and Electric Company, contributed some combination of transmission assets or cash in the process of forming American Transmission Company LLC.
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11. If the Service Company performs services, construction, or sale of goods for companies not named in Item 9, state approximately the proportion of the total income of the Service Company derived from such services or sale of goods. N/A 12. If the Service Company performs any business other than a service business, state approximately the proportion of the total income of the Service Company derived from such other businesses. Approximately 99 percent. 13. Check the classes of work performed by the Service Company. |_| Managerial |_| Construction |_| Statistical |_| Financial |_| Supervision of Construction |_| Publicity |_| Legal |_| Advertising |_| Research |_| Engineering |_| Insurance |_| Sale of Goods |_| Tax |_| Purchasing |_| Auditing |_| Marketing Describe briefly the nature of any services performed by the Service Company which are not named above: Control and Operation Services and Emergency Response Services. 14. As to each class of work checked or described in Item 13, state whether such class of work is performed or is proposed to be performed: (1) Entirely by officers and employees of the Service Company. No. (2) In part by officers and employees of the Service Company and in part by another person or company engaged or to be engaged by the Service Company for that purpose. No. (3) Entirely by other persons or companies engaged or to be engaged by the Service Company for that purpose. Yes. 15. (a) Name and address of the principal executive office, of each person or company engaged by the Service Company in connection with the performance of any service, sales or construction as indicated in subparagraphs (2) and (3) of Item 14. ATC Management Inc. N19 W23993 Ridgeview Parkway West Waukesha, Wisconsin 53188 (b) As to each such person or company indicate the services for which such person or company is engaged by the Service Company. All services described in Item 13.
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16. Attach to this report a balance sheet and a profit and loss statement of the Service Company as of a date not more than three months prior to the date of filing this report, together with any additional information necessary to reflect any major changes in the condition of the Service Company since the date of such financial statements. (The following is the form for signature and verification where the Service Company is a corporation. Suitable changes should be made for other kinds of companies.) Please see Attachment E. The Service Company has caused this instrument to be duly executed on its behalf by its authorized officer on this 22 day of April 2005 American Transmission Company By its corporate manager ATC Management Inc. /s/ Walter T. Woelfle ---------------------------------------------------------- Walter T. Woelfle Vice President, Legal and Secretary State of Wisconsin County of Waukesha The undersigned being duly sworn deposes and says that he has duly executed the attached instrument for and on behalf of Service Company named therein; that he is the Vice President, Legal and Secretary of the corporate manager of such Service Company; And that all action by stockholders, directors, and other bodies necessary to authorize deponent to execute and file such instrument has been taken. Deponent further says that he is familiar with such instrument and the transactions referred to therein, and that to the best of his knowledge, information and belief the statements made in such instrument are true. /s/ Walter T. Woelfle --------------------------------------------- Walter T. Woelfle Vice President, Legal and Secretary Subscribed and sworn to before me at this 22 day of April 2005 /s/ John J. Schulze Jr. ------------------------------ John J. Schulze Jr. Attorney My commission is permanent
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Attachment A: American Transmission Company LLC - Members Names and Addresses of the Twenty Largest Holders of Record As of March 31, 2005 Percentage No. Member Number of Units Interest ------------------------------------------------------------------------------- 1. Wisconsin Electric Power Company 12,528,569 32.31% 231 West Michigan Street Milwaukee, WI 53203 2. WPS Investments, LLC 9,570,875 24.68% c/o Wisconsin Public Service Corporation 700 North Adams Street Green Bay, WI 54034 3. WPL Transco LLC 8,876,828 22.89% 4902 N. Biltmore Lane Madison, WI 53718-2132 4. Wisconsin Public Power Inc. 2,035,798 5.25% 1425 Corporate Center Drive Sun Prairie, WI 53590-9109 5. Madison Gas and Electric Company 1,875,849 4.84% 133 South Blair Street Madison, WI 53703 6. Edison Sault 1,740,601 4.49% 725 East Portage Avenue Sault Ste. Marie, MI 49783 7. Cloverland Electric Cooperative 276,731 0.71% 2916 West M-28 Dafter, MI 49724 8. Manitowoc Public Utilities 246,039 0.63% 1303 South Eighth Street Manitowoc, WI 54221 9. Upper Peninsula Public Power Agency 209,511 0.54% c/o Marquette Board of Light and Power 2200 Wright Street Marquette, MI 49855 10. Adams-Columbia Electric Cooperative 201,407 0.52% 401 East Lake Street Friendship, WI 53934-0070 11. Marshfield Electric and Water Department 185,262 0.48% of the City of Marshfield 2000 South Roddis Avenue Marshfield, WI 54449 12. City of Sun Prairie 172,946 0.45% 125 West Main Street Sun Prairie, WI 53590
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Percentage No. Member Number of Units Interest -------------------------------------------------------------------------------- 13. City of Menasha 145,097 0.37% 321 Milwaukee Street Menasha, WI 54952 14. City of Wisconsin Rapids 123,551 0.32% 221 16th Street South Wisconsin Rapids, WI 54495-0399 15. Badger Power Marketing Authority 106,976 0.28% 122 North Sawyer Street Shawano, WI 54166 16. City of Plymouth 99,603 0.26% 12 South Milwaukee Street Plymouth, WI 53073-0277 17. City of Sturgeon Bay 61,679 0.16% 230 East Vine Street Sturgeon Bay, WI 54235 18. Reedsburg Utility Commission 58,693 0.15% PO Box 230 501 Utility Court Reedsburg, WI 53959 19. City of Kaukauna 56,255 0.15% 777 Island Street Kaukauna, WI 54130 20. Central Wisconsin Electric Cooperative 44,517 0.11% 150 Depot Street Iola, WI 54945-0255 Page 2 of 2 Attachment A American Transmission Company LLC - Members Names and Addresses of the Twenty Largest Holders of Record - As of March 31, 2005
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Attachment B ATC Management Inc. - Officers & Directors -------------------------------------------------------------------------------- No. Name Address -------------------------------------------------------------------------------- Officers -------------------------------------------------------------------------------- 1 DELGADO, Jose M. President and Chief Executive Officer ATC Management Inc. N19 W23993 Ridgeview Parkway West P.O. Box 47 Waukesha, WI 53187-0047 -------------------------------------------------------------------------------- 2 DOYLE, Daniel A. Vice President, Chief Financial Officer and Treasurer ATC Management Inc. Two Fen Oak Court Madison, WI 53718 -------------------------------------------------------------------------------- 3 LANDGREN, Dale A. Vice President and Chief Strategic Officer ATC Management Inc. N19 W23993 Ridgeview Parkway West P.O. Box 47 Waukesha, WI 53187-0047 -------------------------------------------------------------------------------- 4 TERHUNE, Harry L. Vice President - Operations ATC Management Inc. N19 W23993 Ridgeview Parkway West P.O. Box 47 Waukesha, WI 53187-0047 -------------------------------------------------------------------------------- 5 WILLIAMSON, Mark C. Vice President, Major Projects ATC Management Inc. Two Fen Oak Court Madison, WI 53718 -------------------------------------------------------------------------------- 6 WOELFLE, Walter T. Vice President, Legal and Secretary ATC Management Inc. N19 W23993 Ridgeview Parkway West P.O. Box 47 Waukesha, WI 53187-0047 -------------------------------------------------------------------------------- Directors -------------------------------------------------------------------------------- 1 DELGADO, Jose M. President and Chief Executive Officer ATC Management Inc. N19 W23993 Ridgeview Parkway West P.O. Box 47 Waukesha, WI 53187-0047 -------------------------------------------------------------------------------- 2 EARL, Anthony S. Attorney and Partner Quarles & Brady One South Pinckney Street, Suite 600 P.O. Box 2113 Madison, WI 53703 -------------------------------------------------------------------------------- 3 HARVEY, William D. President and Chief Operating Officer Wisconsin Power and Light Company 4902 North Biltmore Lane P.O. Box 77007 Madison, WI 53718 -------------------------------------------------------------------------------- Wednesday, April 20, 2005 ATC Management Inc. - Officers & Directors Page 1 of 2
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-------------------------------------------------------------------------------- No. Name Address -------------------------------------------------------------------------------- 4 RAMIREZ, Agustin A. Chairman and Chief Executive Officer Husco International W239 N218 Pewaukee Road Waukesha, WI 53188 ------------------------------------------------------------------------------- 5 THILLY, J. Leroy President and Chief Executive Officer Wisconsin Public Power Inc. 1425 Corporate Center Drive Sun Prairie, WI 53590 ------------------------------------------------------------------------------- 6 VERRETTE, William C. Chairman and Chief Executive Officer Champion Inc. 105 East A Street P.O. Box 490 Iron Mountain, MI 49801 ------------------------------------------------------------------------------- 7 WEST, Jeffrey P. Treasurer Wisconsin Electric Power Company 231 West Michigan Avenue Milwaukee, WI 53203 ------------------------------------------------------------------------------- 8 WEYERS, Larry L. Chairman, President & Chief Executive Officer Wisconsin Public Service Corporation 700 N. Adams Street P.O. Box 19001 Green Bay, WI 54301 ------------------------------------------------------------------------------- 9 WOLTER, Gary J, Chairman, President and Chief Executive Officer Madison Gas and Electric Company 133 South Blair Street P.O. Box 1231 Madison, WI 53703 ------------------------------------------------------------------------------- 10 YANISCH, Stephen J. Managing Director, Public Finance Department RBC Dain Rauscher Inc. 60 South Sixth Street Minneapolis, MN 55402-4422 ------------------------------------------------------------------------------- Wednesday, April 20, 2005 ATC Management Inc. - Officers & Directors Page 2 of 2
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ATTACHMENT E AMERICAN TRANSMISSION COMPANY LLC Financial Statements for the Years Ended December 31, 2004, 2003 and 2002 and Independent Auditors' Report
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American Transmission Company LLC Table of Contents Financial Statements Independent Auditors' Report .......................................... 3 Statements of Operations for the Years Ended December 31, 2004, 2003 and 2002......................................................... 4 Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002......................................................... 5 Balance Sheets as of December 31, 2004 and 2003 ....................... 6 Statements of Changes in Members' Equity for the Years Ended December 31, 2004, 2003 and 2002...................................... 7 Notes to Financial Statements ......................................... 8-29 Management's Discussion and Analysis of Financial Condition and Results of Operations............................................................ 30-45 Qualitative Disclosures about Market Risks ............................... 45 2
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Independent Auditors' Report To the Board of Directors of ATC Management Inc., Corporate Manager of American Transmission Company LLC: We have audited the accompanying balance sheets of American Transmission Company LLC (the "Company") as of December 31, 2004 and 2003, and the related statements of operations, changes in members' equity, and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. DELOITTE & TOUCHE LLP Milwaukee, Wisconsin January 27, 2005 3
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[Enlarge/Download Table] American Transmission Company LLC Statements of Operations For the Years Ended December 31, 2004, 2003 and 2002 (In Thousands) 2004 2003 2002 --------- --------- --------- Operating Revenues Transmission Service Revenue $ 261,763 $ 224,453 $ 202,856 Other Operating Revenue 800 1,155 2,442 --------- --------- --------- Total Operating Revenues 262,563 225,608 205,298 Operating Expenses Operations and Maintenance 105,377 93,681 86,556 Depreciation and Amortization 46,636 40,694 38,407 Taxes Other than Income 5,717 5,174 6,096 --------- --------- --------- Total Operating Expenses 157,730 139,549 131,059 --------- --------- --------- Operating Income 104,833 86,059 74,239 Other Income (Expense) Other Income (Expense), net (78) 81 (269) Allowance for Equity Funds Used During Construction 3,136 2,474 1,675 --------- --------- --------- Total Other Income (Expense) 3,058 2,555 1,406 --------- --------- --------- Earnings Before Interest and Tax 107,891 88,614 75,645 Interest Expense Interest Expense 32,439 27,730 22,655 Allowance for Borrowed Funds Used During Construction (2,494) (1,822) (1,067) --------- --------- --------- Net Interest Expense 29,945 25,908 21,588 --------- --------- --------- Earnings Before Tax $ 77,946 $ 62,706 $ 54,057 ========= ========= ========= The accompanying notes are an integral part of these financial statements. 4
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[Enlarge/Download Table] American Transmission Company LLC Statements of Cash Flows For the Years Ended December 31, 2004, 2003 and 2002 (In Thousands) 2004 2003 2002 --------- --------- --------- Cash Flows from Operating Activities Earnings Before Tax $ 77,946 $ 62,706 $ 54,057 Adjustments to Reconcile Earnings Before Tax to Net Cash Provided by Operating Activities Depreciation and Amortization 46,636 40,694 38,407 Bond Discount and Debt Issuance Cost Amortization 570 457 418 Allowance for Equity Funds Used During Construction (3,136) (2,474) (1,675) Change in Accounts Receivable (4,674) 2,212 (6,709) Other Current Assets (1,442) (299) (429) Accounts Payable 9,790 (4,230) 6,140 Accrued Liabilities 8,607 5,370 1,787 Other 3,549 (7,025) 4,332 --------- --------- --------- Total Adjustments 59,900 34,705 42,271 --------- --------- --------- Net Cash Provided by Operating Activities 137,846 97,411 96,328 Cash Flows from Investing Activities Capital Expenditures for Property, Plant and Equipment (241,562) (193,574) (123,447) Allowance for Borrowed Funds Used During Construction (2,494) (1,822) (1,067) --------- --------- --------- Net Cash Used in Investing Activities (244,056) (195,396) (124,514) Cash Flows from Financing Activities Distribution of Earnings to Members (59,090) (47,850) (48,189) Issuance of Membership Units for Cash 85,156 17,194 578 Redemption of Membership Units (53) (1,078) (523) Issuance of Shod-term Debt, Net 58,300 -- -- Issuance of Long-term Debt, Net of Issuance Costs -- 99,198 49,377 Advances under Interconnection Agreements 25,943 26,217 3,776 Payments under Interconnection Agreements (13,047) (1,361) -- --------- --------- --------- Net Cash Provided by Financing Activities 97,209 92,320 5,019 Net Change in Cash and Cash Equivalents (9,001) (5,665) (23,167) Cash and Cash Equivalents, Beginning of Period 9,165 14,830 37,997 --------- --------- --------- Cash and Cash Equivalents, End of Period $ 164 $ 9,165 $ 14,830 ========= ========= ========= Supplemental Disclosures of Cash Flows Information Cash Paid for Interest $ 31,601 $ 25,091 $ 21,479 Significant Non-cash Transactions- Issuance of Membership Units for Transmission Assets $ 121 $ 8,219 $ 1,928 The accompanying notes are an integral part of these financial statements. 5
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[Enlarge/Download Table] American Transmission Company LLC Balance Sheets As of December 31, 2004 and 2003 (In Thousands) ASSETS 2004 2003 ----------- ----------- Transmission and General Plant Properly, Plant and Equipment $ 1,521,441 $ 1,354,377 Less-Accumulated Depreciation (589,096) (558,267) ----------- ----------- 932,345 796,110 Construction Work in Progress 207,975 113,057 ----------- ----------- Net Transmission and General Plant 1,140,320 909,167 Current Assets Cash and Cash Equivalents 164 9,165 Accounts Receivable 27,199 22,525 Other Current Assets 2,829 1,387 ----------- ----------- Total Current Assets 30,192 33,077 Regulatory and Other Assets Regulatory Assets 3,014 8,512 Other Assets 10,387 9,595 ----------- ----------- Total Regulatory and Other Assets 13,401 18,107 ----------- ----------- Total Assets $ 1,183,913 $ 960,351 =========== =========== MEMBERS' EQUITY AND LIABILITIES Capitalization Members' Equity $ 536,774 $ 432,693 Long-term Debt 448,483 448,215 ----------- ----------- Total Capitalization 985,257 880,908 Current Liabilities Accounts Payable 59,731 21,821 Accrued Liabilities 37,582 28,974 Short-term Debt 58,361 -- Current Portion of Advances Under Interconnection Agreements 36,618 15,797 ----------- ----------- Total Current Liabilities 192,292 66,592 Long-term Liabilities 6,364 12,851 Commitments and Contingencies (see Notes) -- -- ----------- ----------- Total Members' Equity and Liabilities $ 1,183,913 $ 960,351 =========== =========== The accompanying notes are an integral part of these financial statements. 6
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American Transmission Company LLC Statements of Changes in Members' Equity For the Years Ended December 31, 2004, 2003 and 2002 (In Thousands) Members' Equity as of December 31, 2001 $ 385,652 ========= Membership Units Outstanding at December 31, 2001 27,974 ========= Issuance of Membership Units 2,505 Redemption of Membership Units (523) Earnings Before Tax 54,057 Distribution of Earnings to Members (48,189) --------- Members' Equity as of December 31, 2002 $ 393,502 ========= Membership Units Outstanding at December 31, 2002 28,127 ========= Issuance of Membership Units 25,413 Redemption of Membership Units (1,078) Earnings Before Tax 62,706 Distribution of Earnings to Members (47,850) --------- Members' Equity as of December 31, 2003 $ 432,693 ========= Membership Units Outstanding at December 31, 2003 30,319 ========= Issuance of Membership Units 85,278 Redemption of Membership Units (53) Earnings Before Tax 77,946 Distribution of Earnings to Members (59,090) --------- Members' Equity as of December 31, 2004 $ 536,774 ========= Membership Units Outstanding at December 31, 2004 37,710 ========= The accompanying notes are an integral part of these financial statements, 7
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American Transmission Company LLC Notes to Financial Statements December 31, 2004 (1) Nature of Operations and Summary of Significant Accounting Policies ------------------------------------------------------------------- (a) General ------- American Transmission Company LLC ("the Company") was organized on June 12, 2000 as a limited liability company under the Wisconsin Limited Liability Company Act as a single purpose, for-profit electric transmission company. The Company's purpose is to plan, construct, operate, own and maintain electric transmission facilities to provide for an adequate and reliable transmission system that meets the needs of all users on the system and supports equal access to a competitive, wholesale electric energy market. The Company owns and operates the electric transmission system, under the direction of the Midwest Independent Transmission System Operator, Inc. ("MISO"), in parts of Wisconsin, Illinois and the Upper Peninsula of Michigan. The Company is subject to regulation by the Federal Energy Regulatory Commission ("FERC") as to rates, terms of service and financing and by state regulatory commissions as to other aspects of business, including the construction of electric transmission assets. (b) Corporate Manager ----------------- The Company is managed by a corporate manager, ATC Management Inc. ("Management Inc."). The Company and Management Inc. have common ownership and operate as a single functional unit. Under the Company's operating agreement, Management Inc. has complete discretion over the business of the Company and provides all management services to the Company at cost. The Company itself has no employees. The Company's operating agreement establishes that all expenses of Management Inc. are the responsibility of the Company. These expenses consist primarily of payroll, benefits, payroll-related taxes and other employee related expenses. All such expenses are recorded in the Company's accounts as if they were direct expenses of the Company. As of December 31, the following net (receivables from)/payables to Management Inc, were included in the Company's balance sheets (in thousands): 2004 2003 Accrued Liabilities $ 9,729 $ 9,142 Other Assets (59) (1,233) ------- ------- Net Amount Payable to Management Inc. $ 9,670 $ 7,909 ======= ======= Amounts included in accrued liabilities are primarily payroll and benefit related accruals. Amounts included in other assets relate primarily to certain long-term compensation arrangements covering Management Inc. employees, as described in Note (2), offset by a $7.7 million and $6.3 million receivable as of December 31, 2004 and 2003, respectively, for income taxes paid on Management Inc.'s behalf by the Company, The income taxes are due to temporary differences relating to the tax deductibility of certain employee-related costs. As these temporary differences reverse in future years, Management Inc. will be refunded the associated income taxes paid and will repay the advances from the Company. 8
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(c) Revenue Recognition ------------------- Wholesale electric transmission service for utilities, municipalities, municipal electric companies, electric cooperatives and other eligible entities is provided through the Company's facilities under the MISO open access transmission tariff regulated by FERC. The Company charges for these services under FERC approved rates. The tariff specifies the general terms and conditions of service on the transmission system and the approved rates set forth the calculation of the amounts to be paid for those services. The Company's revenues are derived from agreements for the receipt and delivery of electricity at points along the transmission system. The Company does not take ownership of the electricity that it transmits. The Company's formula rate tariff includes a true-up provision that meets the requirements of an alternative revenue program set forth in the Financial Accounting Standards Board's ("FASB") Emerging Issues Task Force Issue No. 92, "Accounting by Rate Regulated Utilities for the Effects of Certain Alternative Revenue Programs." Accordingly, revenue is recognized for services provided during the reporting period based on the revenue requirement formula in the tariff. The Company accrues or defers revenues to the extent that the actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed during the reporting period. The true-up amount will automatically be reflected in customer bills within two years. The Company records a reserve for revenue subject to refund when such refund is probable and can be reasonably estimated. (d) Transmission and General Plant and Related Depreciation ------------------------------------------------------- Transmission Plant is recorded at the original cost of construction. Assets transferred to the Company primarily by its members, which include investor-owned utilities, municipalities, municipal electric companies and electric cooperatives, have been recorded at their original cost in property, plant and equipment with the related reserves for accumulated depreciation also recorded. (See Note 9(a) for additional information.) The original cost of construction includes materials, construction overhead, outside contractor costs and, for projects on which construction began prior to December 31, 2003, an allowance for funds used during construction (See Note 1(e)). Additions to and significant replacements of transmission assets are charged to property, plant and equipment at cost; replacement of minor items is charged to maintenance expense. The cost of transmission plant, together with removal cost less salvage value, is charged to accumulated depreciation when assets are retired. The provision for depreciation of transmission assets is an integral part of the Company's cost of service under FERC-approved rates. Depreciation rates include estimates for future removal costs and salvage value. Depreciation expense as a percentage of average transmission plant was 2.68%, 2.64% and 2,65% in 2004, 2003 and 2002, respectively. The reserves for accumulated depreciation as of December 31, 2004 and 2003 included approximately $83 million and $78 million, respectively, of accrued removal costs. 9
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General plant, which includes buildings, office furniture and equipment, computer hardware and software, is recorded at cost. Depreciation is recorded at straight-line rates over the estimated useful lives of the assets, which range from three to forty years. (e) Allowance for Funds Used During Construction -------------------------------------------- Allowance for funds used during construction ("AFUDC ) represents the composite cost of the debt used to fund the construction of transmission assets and a return on members' capital devoted to construction. The portion of the allowance that applies to borrowed funds is presented in the statements of operations as a reduction of interest expense; the return on members' capital is presented as other income. Although the allowance does not represent current cash income, it is recovered under the ratemaking process over the service lives of the related assets. In accordance with FERC Order 561, the Company capitalized AFUDC at the following average rates in 2004, 2003 and 2002: 2004 2003 2002 Debt Rate 3.6% 3.1% 3.3% Equity Rate 4.5% 4.3% 5.1% ------------------------ Total Rate 8.1% 7.4% 8.4% ------------------------ Beginning January 1, 2004 the Company was allowed to include Construction Work in Progress ("CWIP") in its rate base and earn a current return on construction projects that commenced construction after December 31, 2003, in lieu of capitalizing AFUDC to the projects. Accordingly, the Company has not accrued AFUDC on projects earning a current return, nor has it capitalized interest in accordance with SFAS No. 34, "Capitalization of Interest Cost." At December 31, 2004, approximately $119 million of CWIP was accruing AFUDC and $57,9 million of CWIP was earning a current return as a component of rate base. (f) Interconnection Agreements -------------------------- The Company has entered into interconnection agreements with entities planning to build generation plants within the Company's service territory. During construction, the generators will construct the interconnection facilities or finance and bear all financial risk of having the Company construct the interconnection facilities under these agreements. The Company will own and operate the interconnection facilities when the generation plants become operational and will reimburse the generator for construction costs plus interest. If the generation plants do not become operational, the Company has no obligation to reimburse the generator for costs incurred during construction. In cases in which the Company is contracted to construct the interconnection facilities, the Company receives cash advances for construction costs from the generators. During construction, actual costs incurred are included in CWIP. Cash advances from the generators, along with accruals for interest, are recorded as liabilities, The accruals for interest are capitalized, in lieu of AFUDC, and included in CWIP, At December 31, 2004 and 2003, advances and accrued interest totaled $43,0 million and $28,6 million, respectively. Of these amounts, $6.4 million and $12.9 million were included in long-term liabilities at December 31, 2004 and 2003, respectively. 10
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(g) Cash and Cash Equivalents ------------------------- Cash and cash equivalents include highly liquid investments with original maturities of three months or less. (h) Regulatory Assets and Liabilities --------------------------------- The Company's accounting policies conform to Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation." Accordingly, assets and liabilities that result from the regulated ratemaking process are recorded that would otherwise not be recorded under accounting principles generally accepted in the United States of America for non-regulated companies. Certain costs and credits are recorded as regulatory assets and liabilities as incurred and are recognized in the statements of operations at the time they are reflected in rates. Under a rate settlement agreement approved by FERC in November 2001, the Company has been recovering in rates, over a five-year period, certain start-up and development costs incurred in 2000 and 2001. The Company also earns its allowed rate of return on the unamortized portion of the start-up costs during each year. Accordingly, deferred start-up costs of $15.1 million are being amortized to expense over a five-year period beginning in 2001, Amortization expense of $3.0 million is included in 2004, 2003 and 2002 depreciation and amortization. Unamortized start-up costs of $3.0 million and $6.0 million were included in regulatory assets at December 31, 2004 and 2003, respectively. As discussed in Note 1(c), the Company's formula rate tariff approved by FERC provides for a true-up mechanism. Under the true-up mechanism, the Company is authorized to include an under-collected amount of approximately S2.5 million during 2003, plus interest, in its billings in 2005. This amount was included in regulatory assets at December 31, 2003. During 2004, the Company over-collected approximately $6.8 million. Under the terms of the tariff, this amount would ordinarily be refunded, with interest to customers in 2006; however, the Company filed an application with FERC on December 22, 2004 for an amendment to the rates which would allow the Company to accelerate this refund by one year and return it to customers, net of the 2003 under-collection, in 2005. FERC issued an order authorizing this treatment, as filed, on February 17, 2005. Accordingly, the net amount of $4.3 million is included in accrued liabilities at December 31, 2004. The Company continually assesses whether regulatory assets continue to meet the criteria for probability of future recovery. This assessment includes consideration of factors such as changes in the regulatory environment, recent rate orders to other regulated entities under the same jurisdiction and the status of any pending or potential deregulation legislation. If future recovery of certain regulatory assets becomes improbable, the affected assets would be written off in the period in which such determination is made. 11
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(i) Other Assets ------------ As of December 31, other assets were comprised of the following (in thousands): 2004 2003 Preliminary Survey and Investigation Costs $ 6,455 $ 4,297 Unamortized Debt Issuance Costs 3,758 4,065 Unamortized Line of Credit Fees 115 -- Net Receivable from Management Inc. (see Note 1(b)) 59 1,233 ------- ------- $10,387 $ 9,595 ======= ======= Preliminary survey and investigation costs relate to study and planning costs in the early stages of construction projects. Costs directly attributable to the construction of transmission assets, for projects started prior to December 31, 2003 and generation interconnection projects, are capitalized as other assets until all required regulatory approvals are obtained and construction begins, at which time the costs are transferred to construction work in progress. As discussed in Note 7, beginning January 1, 2004, the Company was allowed to expense and recover in rates preliminary survey and investigation costs in the year incurred for projects that started after December 31, 2003. Approximately $1.5 million of preliminary survey and investigation costs are included in operations and maintenance expense for 2004. (j) Impairment of Long-lived Assets ------------------------------- The Company reviews the carrying values of long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying values may not be recoverable. Impairment would be determined based upon a comparison of the undiscounted future operating cash flows to be generated during the remaining life of the assets to their carrying values An impairment loss would be measured by the amount that an asset's carrying amount exceeds its fair value. As long as its assets continue to be recovered through the ratemaking process, the Company believes that such impairment is unlikely. (k) Income Taxes ------------ The Company is a limited liability company that has elected to be treated as a partnership under the Internal Revenue Code and applicable state statutes. As such, it is not liable for federal or state income taxes. The Company's members (except certain tax-exempt members) report their share of the Company's earnings, gains, losses, deductions and tax credits on their respective federal and state income tax returns. Accordingly, these financial statements do not include a provision for federal and state income tax expense. Earnings before tax reported on the statements of operations is the Company's net income. See Note (6) for further discussion of income taxes. 12
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(i) Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to apply policies and make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates are used for items such as depreciable lives of property, plant and equipment, removal costs and salvage associated with asset retirements, tax provisions included in rates, actuarially determined benefit costs and accruals for construction costs and operations and maintenance expenses. As additional information becomes available, or actual amounts are determined, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. (m) New Accounting Pronouncements ----------------------------- In January 2003, the FASB issued Financial Interpretation No. 46, "Consolidation of Variable Interest Entities". This interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", addresses consolidation by business enterprises of variable interest entities. The Company has no association with any variable interest entities that would require the Company to consolidate another entity. In December 2003, the FASB issued SFAS No. 132," Employers' Disclosures about Pensions and Other Postretirement Benefits". This statement revises employers' disclosures about pension plans and other postretirement benefit plans to present more information about the economic resources and obligations of such plans. The statement was effective for non-public companies for fiscal years ended after June 15, 2004. See Note 2 for the expanded disclosures required by the statement. On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 ("the Act") was signed into law. The Act introduced a prescription drug benefit program under Medicare ("Medicare Part D") as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. During the second quarter of 2004, the FASB issued FASB Staff Position SFAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003." The Company has determined that a substantial part of the postretirement health care plan is actuarially equivalent to the Medicare Prescription Drug Plan. The Company anticipates being eligible for the subsidy available from Medicare. 13
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The effects of the Act are reflected in the financial statements with a reduction in the Company's accumulated postretirement benefit obligation of $0.6 million, and a reduction of other postretirement expense in 2004 of $0.1 million. The assumptions used to develop the reductions include those used in the determination of the annual postretirement benefit expense under SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions", and also include expectations of how the federal program will operate. There are no written regulations that provide detail regarding the operation of the subsidy program. It is expected that final regulations will be published in early 2005. (2) Benefits -------- Management Inc. sponsors several benefit plans for its employees. These plans include certain postretirement health care benefits. The weighted average assumptions as of the measurement date of October 1 are as follows: 2004 2003 2002 Discount Rate 6.00% 6.25% 6.75% Medical Cost Trend: Initial Range 11.00% 11.00% 18.00% Ultimate Range 5.00% 5.00% 5.50% Long-term Rate of Return on Plan Assets 5.50% - % - % The components of Management Inc.'s postretirement benefits expense for 2004, 2003 and 2002 are as follows (in thousands): 2004 2003 2002 Service Cost $ 887 $ 934 $ 658 Interest Cost 399 413 292 Amortization of Prior Service Cost 250 250 250 Net Actuarial Loss - 60 Expected Return on Plan Assets (241) - - ------------------------ Net Periodic Postretirement Cost $1,295 $1,657 $1,200 ======================== 14
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The assumed medical cost trend rates are critical assumptions in determining the service and interest cost and accumulated postretirement benefit obligation, A one percent change in the medical cost trend rates, holding all other assumptions constant, would have the following effects for 2004 (in thousands): One Percent One Percent Increase Decrease ----------- ----------- Effect on Total of Service and Interest $ 406 $ (203) Cost Components Effect on Postretirement Benefit Obligation at the End of Year $ 2,115 $(1,638) A reconciliation of the change in the benefit obligation during 2004 and 2003 is as follows (in thousands): 2004 2003 Accumulated Postretirement Benefit Obligation at the Beginning of Year $ 6,258 $ 7,940 Service Cost 887 934 Interest Cost 399 413 Actuarial (Gains)/Losses 1,831 (3,029) ------- ------- Benefit Obligation at End of Year $ 9,375 $ 6,258 ======= ======= Retiree claims paid during 2004, 2003 and 2002 were not significant. The Company anticipates retiree benefit payments for the next five years to be as follows (in thousands): 2005 $29 2006 58 2007 83 2008 120 2009 182 --------- Total $472 ========= In December 2003, Management Inc. established a Voluntary Employee Benefit Association ("VEBA") trust and a 401(h) trust that will be funded as the Company recognizes postretirement medical expense. On December 30, 2003, the Company transferred $3.9 million in cash as an initial funding of the VEBA. No amounts were contributed to the 401(h) trust in 2003 The Company transferred $0.4 million and $0.6 million to the VEBA and 401(h) trust, respectively, to fund postretirement medical obligations during 2004. The trusts are discretionary trusts with a long-term investment objective to preserve and, if possible, enhance the post-inflation value of the trusts' assets, subject to cash flow requirements, while maintaining an acceptable level of volatility. The targeted allocation percentages for each major category of plan assets for the trusts is as follows: Target Range ------ ----- U.S. Equities 50% +/-5% Non-U.S. Equities 15% +/-4% Fixed Income 35% +/-5% ------------ 100% ------------ 15
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The fair value of total plan assets held in the trusts as of December 31, 2004 and 2003 consist of the following: 2004 2003 Cash/Money Market - 100% U.S. Equity Index Fund 50% - International Equity Fund 16% - Intermediate Bond Fund 34% - ------- ------- 100% 100% A reconciliation of the change in the fair value of plan assets designated for postretirement medical obligations, for the combined trusts, is as follows (in thousands): 2004 2003 Fair Value of Plan Assets at the Beginning of the Year $ 3,873 $ - Employer Contributions 1,026 3,873 Employee Contributions 9 - Return on Plan Assets 380 - Taxes and Administrative Expenses (19) - Net Benefits Paid (25) - ------- ------- Fair Value at End of Year $ 5,244 $ 3,873 ======= ======= The Company anticipates contributing $1.4 million to the plan for postretirement medical obligations during 2005. A reconciliation of the funded status of the plan to the amounts recognized by the Company as long-term liabilities (payable to Management Inc.) in the December 31, 2004 and 2003 balance sheets is as follows (in thousands): 2004 2003 Funded Status as of December 31 $(4,461) $(2,385) Unrecognized Prior Service Cost 2,002 2,252 Unrecognized Net Actuarial Loss 2,178 120 ------- ------- Net Amount Recognized as of December 31 $ (281) $ (13) ======= ======= Management Inc. sponsors a defined contribution money-purchase pension plan, in which substantially all employees participate, and makes contributions to the plan for each participant based on several factors. Contributions made by Management Inc. to the plan totaled $2.1 million in 2004, $1.6 million in 2003, and $1.4 million in 2002. Certain management employees who agreed to leave their prior employers and become employees of Management Inc. receive pension benefits from Management Inc. that are at least equal to the benefits the employees would have received under the pension plans of their prior employers. The Company accounts for the benefits as deferred compensation arrangements under APB 12, "Omnibus Opinion". As of December 31, 2004 and 2003, $2.0 million and $1,3 million, respectively, was included in long-term liabilities related to this plan. 16
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Management Inc. also provides a deferred compensation plan for certain employees. The plan allows for the elective deferral of a portion of an employee's base salary and incentive compensation and also contains a supplemental retirement and 401(k) component. Deferred amounts are taxable to the employee when paid, but the Company recognizes compensation expense in the period earned. As of December 31, 2004 and 2003, $4.5 million and $3.1 million, respectively, was included in long-term liabilities related to this deferred compensation plan. Amounts charged to expense, including interest accruals, in 2004, 2003, and 2002 were $1.4 million, $.9 million, and $.9 million, respectively. (3) Members' Equity --------------- The Company's members include investor-owned utilities, municipalities, municipal electric companies and electric cooperatives. Each member was issued membership interests in proportion to the value of transmission assets and/or cash it contributed to the Company. Distribution of earnings to members is at the discretion of Management Inc. The operating agreement of the Company established a target for distribution of 80% of annual earnings before tax. During 2004, 2003 and 2002, the Company distributed $59.1 million, $47.9 million, and $48.2 million, respectively, of its earnings before tax to its members in proportion to each member's ownership interest in the Company. The board of directors approved a distribution for the fourth quarter of 2004, in the amount of $16,0 million, on January 27, 2005, bringing the total distributions for 2004 to 80% of earnings before tax. (4) Debt ---- (a) Credit Facilities ----------------- On May 24, 2004, the Company replaced its $75 million 364-day backup line of credit with a $125 million three-year revolving credit facility. The Company may request that the aggregate commitment be increased to $200 million either by having one or more existing lenders increase their commitment or by adding additional lenders. The revolving credit facility provides back-up liquidity to the Company's $125 million commercial paper program. While the Company does not intend to borrow under the revolving credit facility, interest rates on outstanding borrowings under the facility would be based on a floating rate plus a margin. The applicable margin is based on the Company's debt rating from Moody's and S&P and ranges from 0.35% to 1.25%, The revolving credit facility contains restrictive covenants, including restrictions on liens, certain mergers, sales of assets, acquisitions, investments, transactions with affiliates, change of control, conditions on prepayment of other debt, certain financial ratios and requires certain financial reporting. The revolving credit facility provides for certain customary events of default. The Company had no borrowing outstanding under the credit facility as of December 31, 2004 and 2003. 17
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[Enlarge/Download Table] (b) Commercial Paper ---------------- The Company has a $125 million unsecured, private placement, commercial paper program. Investors are limited to qualified institutional buyers and institutional accredited investors. Maturities may be up to 364 days from date of issue, with proceeds to be used for working capital and other capital expenditures. Pricing is par less a discount or, if interest bearing, at par. As of December 31, 2004, the Company had $58.3 million of commercial paper outstanding. The Company did not have any borrowings under the program as of December 31, 2003. (c) Long-term Debt -------------- The following table summarizes the Company's long-term debt commitments as of December 31, (in thousands) 2004 2003 Senior Notes at stated rate of 7.125%, due March 15, 2011 $ 300,000 $ 300,000 Unamortized Discount (1,589) (1,785) --------- --------- 298,411 298,215 Senior Notes at stated rate of 7.02%, due August 31, 2032 50,000 50,000 Senior Notes at stated rate of 6.79%, due on dates ranging from 100,000 100,000 August 31, 2024 to August 31, 2043 Other Long-term Notes Payable 72 -- --------- --------- Net Long-term Debt $ 448,483 $ 448,215 ========= ========= The senior notes rank equivalent in right of payment with all of the Company's existing and future unsubordinated, unsecured indebtedness and senior in right of payment to all subordinated indebtedness of the Company. The senior notes contain restrictive covenants, which include restrictions on liens, certain mergers and sales of assets and require certain financial reporting. The notes also provide for certain customary events of default. No principal amounts of the senior notes become due in the next five years. The notes contain an optional redemption provision whereby the Company is required to make the note holders whole on any redemption prior to maturity. The notes may be redeemed at any time, at a redemption price equal to the greater of one hundred percent of the principal amount of the notes plus any accrued interest or the present value of the remaining scheduled payments of principal and interest from the redemption date to the maturity date discounted to the redemption date on a semi-annual basis at the then existing treasury rate plus 30 basis points, plus any accrued interest. 18
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(5) Fair Value of Financial Instruments ----------------------------------- The carrying amount and estimated fair value of the Company's long-term debt at December 31 are as follows (in millions): 2004 2003 Carrying amount $448.5 $448.2 Estimated fair value $515.5 $500.2 The carrying amount of the Company's financial instruments included in current assets and current liabilities approximates fair value due to the short maturity of such financial instruments. The fair value of the Company's long-term debt is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the Company's bond rating. (6) Income Taxes ------------ Income tax liabilities are the responsibility of the Company's members (except certain tax-exempt members) and are not reflected in these financial statements. However, the Company is allowed to recover in rates, as a component of its cost of service, the amount of income taxes that are the responsibility of its members. Accordingly, the Company includes a provision for its members' federal and state current and deferred income tax expenses and amortization of the excess deferred tax reserves and deferred investment tax credits associated with assets transferred to the Company by its members in its regulatory financial reports and rate filings. For purposes of determining the Company's revenue requirement under FERC-approved rates, rate base is reduced by an amount equivalent to net accumulated deferred taxes, including excess deferred tax reserves. Such amounts were approximately $93.2 million, $72.2 million, and $67.7 million in 2004, 2003 and 2002, respectively, and are primarily related to accelerated tax depreciation and other plant-related differences. 2004, 2003 and 2002 revenues include recovery of $25.9 million, $20.9 million, and $17.4 million, respectively, of income tax expense. In July 2004, the D.C. Circuit of the U.S. Court of Appeals issued an opinion in a FERC rate proceeding involving an oil pipeline company. The case involved complaints filed by the pipeline's customers regarding several issues related to its tariff, including the recovery of income taxes as a component of its cost of service. The pipeline was formed as a non-taxable limited partnership. In its cost of service, FERC had allowed the pipeline to recover the income taxes paid by the partnership's corporate owners on their respective shares of partnership earnings. The Court found that FERC had not provided a compelling argument to justify including in the pipeline's cost of service the taxes paid by its owners. The Court vacated that portion of the FERC opinion and order that allowed the recovery of income taxes in the pipeline's rates and remanded it to FERC for further consideration, On December 2, 2004, FERC issued a Request for Comments on the implications of the D.C. Circuit's opinion. The Company has filed comments with FERC in support of maintaining an income tax allowance for partnerships. The Company continues to monitor developments in this case closely. The Company believes any changes in FERC policy that might result from this case would likely only impact revenues prospectively. 19
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The Internal Revenue Service completed an examination of the Company's 2001 federal partnership income tax return during 2004. This was the Company's first tax examination since it commenced operations. No adjustments were identified in this examination that will have a material impact on the Company's past or future revenues or earnings. (7) Regulatory Proceedings ---------------------- On October 30, 2003, the Company filed an application with FERC for approval to modify its rate formula in Attachment 0 of the MISO Open Access Transmission Tariff. The Company sought authorization to make the following modifications to the rate formula: a) Include Construction Work in Progress for new transmission investment in rate base to earn a current return in lieu of capitalizing an Allowance for Funds Used During Construction. b) Allow current year expensing of preliminary survey and investigation costs for new transmission investment. Such costs were previously capitalized as a component of the associated transmission assets' cost and recovered, with a return on investment, over the life of the asset. c) Increase the allowed return on equity from 12.20% to 12.38% to correspond to the rate FERC has allowed for other MISO transmission owners and adopt a 50% debt, 50% equity capital structure. On December 29, 2003, FERC issued an order that conditionally accepted for filing and nominally suspended the Company's proposed modifications, to become effective January 1, 2004, subject to refund. The order also established hearing and settlement judge procedures. Based on concerns raised by intervenors in the case, several issues were set for hearing, including the proposed capital structure and the rate impact of expensing preliminary survey and investigation costs for certain transmission projects. The Company filed a settlement agreement that was approved by FERC on May 6, 2004, that resolved all issues set for hearing in the December 29th order. The settlement agreement allows the Company to include Construction Work in Progress in rate base, to expense preliminary survey and investigation costs if the project meets specified requirements (generally if a project is approved by MISO as part of its planning process), and to adopt a 50% debt, 50% equity capital structure The Company agreed to maintain the 12.20% return on equity and agreed to refund the difference between the 12.38% approved in the December 29th order and the 12.20% in the settlement agreement for the period between January 1, 2004 and the settlement agreement date approved by FERC. This refund, which is approximately $.4 million, is included in the Company's true-up calculation for 2004. In the future, the Company's return on equity will float at 18 basis points below the rate approved by FERC for other MISO transmission owners ("the MISO ROE"). Several intervening parties have challenged the methodology used by FERC in determining the current MISO ROE The matter is currently pending before the D.C. Circuit of the U.S. Court of Appeals and a resolution is expected in 2005. The settlement agreement reached in the Company's rate filing provides that, to the extent that there is a reduction of the MISO ROE below the current 12.38%, the Company will be obligated to refund an additional amount, retroactive to January 1, 2004, equal to 50% of the difference between the 12.20% return on equity and 18 basis points below the reduced MISO ROE, subject to a limit of $2 million. The Company cannot predict whether or not such reduction in the return on equity and associated refund will occur. 20
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(8) Commitments and Contingencies ----------------------------- (a) Operating Leases ---------------- The Company leases office space under non-cancelable operating leases. Amounts incurred during 2004, 2003 and 2002 totaled approximately $2.0 million, $1.3 million and $1.0 million, respectively. Future minimum lease payments, which will be expensed as incurred, under non-cancelable operating leases are as follows for the years ending December 31 (in thousands): 2005 $2,346 2006 2,304 2007 2,230 2008 1,016 2009 225 Thereafter - ---------- $8,121 ========== (b) Transfer of Operational Control of Transmission System ------------------------------------------------------ In compliance with Wisconsin statutes and FERC requirements, operational control of the Company's transmission system was transferred to MISO, a FERC-approved regional transmission organization ("RTO"), effective February 1, 2002. MISO has operational control over the Company's system and has the authority to direct the manner in which the Company performs operations. The Company is also required to seek direction from MISO for certain operational actions the Company seeks to perform within its system. MISO is responsible for monitoring congestion, directing the associated operations to overcome congestion, approving transmission maintenance outages, as well as negotiating with generators on the timing of generator maintenance outages within the entire MISO system, including that portion representing the Company's system. The Company is required to coordinate planning activities for new projects or system upgrades with MISO. Certain projects may require review and approval by MISO before implementation. In accordance with FERC Order 2000, MISO is the tariff administrator for all of its transmission-owning members. MISO and the Company made a joint Section 205 filing with FERC that created a separate pricing zone for the Company within MISO's tariff. The Company's rates for service are now administered under MISO's tariff; however, the Company continues to file with FERC for approval of changes to the formula that determines its revenue requirements. 21
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(c) Regulatory Changes that may Affect the Company's Future ---------------------------------------------------------------------- Responsibilities and Relationship with MISO ------------------------------------------- On April 1, 2005, MISO is scheduled to operate Day-Ahead and Real-Time energy markets ("the Day-two market"). These markets will develop a joint transmission service and energy schedule of operation on a day-ahead basis and a dispatch schedule in real time. The markets will use a security constrained, centralized dispatch methodology to optimize power flows over the MISO footprint. Since MISO does not have a history of centralized power dispatch, the FERC has established specific operational reporting requirements. While MISO is planning for the Day-two market to become operational on April 1, 2005, there is uncertainty on whether the operational requirements will be sufficiently met. The inability of MISO to become operational on April 1, 2005, would imply that the Company would have to continue with the current operating methods. In the Day-two market, market participants can acquire Financial Transmission Rights ("FTRs") to hedge against congestion costs that arise due to "congestion" on the transmission grid. The Company's customers, rather than the Company, will be responsible for congestion costs and will be allocated FTRs. The FTRs do not represent a physical right for delivery of energy, rather a financial right to the congestion revenues that are generated. Any resulting shortfall in congestion revenues will reduce payments to FTR holders on a pro-rata basis and, as a result, poses no risk to the Company, as it will not hold any FTRs and will not be responsible for congestion costs. Once the Day-two market is operational, revenue from both the energy market settlement process and the transmission billing process will be commingled, thereby exposing the Company to revenue recovery uncertainty. This uncertainty takes two forms. The first uncertainty is the underpayment by transmission or energy market customers, thereby creating a revenue shortfall. The shortfall will be allocated to the transmission owners on a prorated basis that uses revenue requirements. The second uncertainty is the possibility of an energy market participant filing for bankruptcy. A bankruptcy court would be required to determine whether transmission revenues collected by MISO could be used to satisfy claims of other creditors. On February 15, 2003, FERC issued a notice of proposed pricing policy for efficient operation and expansion of the transmission grid. The proposed policy would provide certain financial incentives related to divestiture of transmission assets from vertically integrated utilities, placement of assets under the control of a RTO and investment in new transmission facilities. The Company has evaluated the potential impact this policy could have on its operations and determined that the modifications to the rate formula contained in its rate filing with FERC would be more beneficial to the Company and proposed such changes as an alternative incentive mechanism to the incentives contained in FERC's proposed pricing policy, Subsequently, the Company and its customers entered into a settlement agreement that largely codifies these revisions to its revenue requirements. On May 6, 2004, FERC approved the settlement agreement. See Note 7 for more information. 22
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On November 18, 2004, FERC issued an order eliminating the Regional Through and Out Rates ("RTOR") for point-to-point transmission services between MISO and the PJM Interconnection ("PJM"), effective December 1, 2004. The Company had received RTOR revenues from MISO, for services that crossed the PJM-MISO seam, which served as a reduction in the amount of the Company's revenue requirement that is borne by its network transmission customers. A transitional revenue replacement mechanism, the Seams Elimination Cost Assignment ("SECA"), is expected to be in place from December 1, 2004 through March 31, 2006. The purpose of the SECA is to protect the financial position of the transmission owners by preserving their revenue stream during the transition period, after which this revenue source will be permanently eliminated. Due to the nature of the Company's revenue requirement formula, including the true-up mechanism described in Note 1(c), management does not expect the elimination of RTOR revenues to have a significant impact on the Company's results of operations. The Company expects that any revenue shortfall associated with the SECA will be made up by the true-up mechanism during the transition period, Similarly, after the transition period, the elimination of RTOR revenues will result in a net increase in the revenues collected from the Company's network transmission customers. The Company is participating in a MISO stakeholder process to determine the appropriate cost allocation for new transmission infrastructure development. As a result of the expected outcome of this process, it is possible that a much greater portion of the Company's revenues for investment in new transmission infrastructure may ultimately be derived from outside the Company's service territory. Similarly, on November 18, 2004, the FERC gave PJM and MISO and their respective transmission owners until May 18, 2005 to file a proposal to share the cost of new transmission facilities that benefit customers in both RTOs. Finally, the FERC has directed MISO and its transmission owners to investigate the continued efficacy of using the existing "license plate" rate design and report their findings to the Commission no later than February 1, 2008. (d) MISO Point-to-Point Revenue Dispute ----------------------------------- In December 2003, MISO notified the Company of a dispute filed by another transmission owner regarding the distribution of revenues for certain point-to-point transactions during 2002 and 2003. MISO had originally distributed 100% of the revenue, in the amount of $8.7 million, related to these transactions to the Company, but now asserts that the Company should only have received a portion of the revenue, in the amount of $2.3 million. MISO indicated it would be seeking return of the remaining $6.4 million, Commencing December 1, 2003, MISO started allocating revenues under its new methodology. The Company disagrees with MISO's determination and has formally disputed it It was determined by the MISO dispute resolution committee that the MISO dispute process, involving mediation, was not expected to yield a resolution to the matter, so the Company pursued arbitration. The arbitration proceeding began in July 2004 and is expected to be complete by the first quarter of 2005. The Company is currently receiving its allocation of revenues under the new methodology, with the remainder held in trust until the dispute is formally resolved. The Company cannot predict how much, if any, of the disputed amount it will ultimately have to refund to MISO; accordingly, no reserve has been recorded in the Company's financial statements at this time. Any amount that the Company would refund to MISO would reduce the revenue credits for point-to-point receipts in the Company's revenue requirement calculation and should be recovered as part of the revenue true-up for the year in which such refund is determined. As such, the Company does not expect this matter to materially impact its results of operations. 23
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(e) Arrowhead to Weston Line Project -------------------------------- The Arrowhead to Weston Line Project ("Project") is a transmission line construction project originally sponsored by Wisconsin Public Service Corporation ("WPSC") and Minnesota Power, Inc. ("Minnesota Power") under which a new high voltage 345kv electric transmission line would be built from the vicinity of Duluth, Minnesota to the vicinity of Wausau, Wisconsin. The Project was approved, at an estimated total cost of $420 million, by the Public Service Commission of Wisconsin ("PSCW") on December 19, 2003. In addition to the PSCW approval, the Project requires permits from the Army Corps of Engineers. Permission is also required from several county governments for the line to cross their property. One county has refused access to county property for the Project. The Company is pursuing legal action against the county to implement the PSCW's siting order for the Project and, in parallel, is working with the PSCW and the Department of Natural Resources to reroute approximately 1.5 miles of the Project from land owned by the county onto private land instead. The Company does not expect this situation to have a significant impact on the project schedule. The Company has begun to acquire the necessary real estate easements and plans to begin construction on the Wisconsin portion of the line in early 2005. Construction began on the Minnesota portion of the line in February 2004. The Company acquired the current Project assets from WPSC at WPSC's cost of $20 million on June 13, 2003. WPSC will continue its role as the construction contractor on the Wisconsin portion of the Project; however, the Company has assumed primary project management responsibility and will acquire the Project facilities from WPSC, at WPSC's cost, on an as-constructed basis, On July 29, 2004, the Company reached an agreement with Minnesota Power to acquire its interest in the Minnesota portion of the Project. The Company will assume approximately 52.6 million of Project costs incurred by Minnesota Power before the agreement and assume primary project management responsibility. Minnesota Power will continue its role as general construction contractor. Title to materials will transfer to the Company on delivery to the construction site. Title to all remaining parts of the Project will transfer to the Company when construction is complete and assets are placed in service. Minnesota Power will transfer the facilities at its cost. The agreement requires the Company and Minnesota Power to cooperate to obtain approval of the agreement of July 29, 2004, from the Minnesota Public Utility Commission. As of December 31, 2004, the Company has accumulated approximately $71.9 million of costs associated with the Project, including the $20 million acquired from WPSC. To the extent the appropriate regulatory approvals related to the Project are obtained and the transmission line is constructed and placed in service, these costs, as well as the $2.6 million from Minnesota Power, will be included in the Company's rate base or otherwise recovered in rates. In the event the line is not approved or rot constructed, the Company would seek recovery of all costs it has incurred related to the Project, including costs assumed from WPSC and Minnesota Power. If recovery is not permitted, such costs would be charged to expense. 24
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(f) Interconnection Agreements -------------------------- As described in Note 1(f), the Company has entered into interconnection agreements with entities planning to build generation plants within the Company's service territory. The current estimate of the Company's total commitments under these agreements, if the generation plants become operational, is approximately $180 million with expected completion dates ranging from 2005 to 2009. In addition, there may be transmission service requests that require the Company to construct additional, or modify existing, transmission facilities to accommodate such requests. Whether such additions or upgrades to the Company's transmission system are required depends on the state of the transmission system at the time the transmission service is required. On July 23, 2003, FERC issued Order 2003, which adopted new rules relating to generator interconnections. While the rules incorporate a number of changes to interconnection procedures and standardize the interconnection agreements, with some regional transmission organization flexibility, the rules preserve the responsibility of generators to pay the costs associated with interconnecting any generator to the Company's system, with the right to be reimbursed either in cash or through transmission service credits. Under certain circumstances, the rules increase the generators' responsibility to fund a greater range of transmission improvement costs, depending on the type of interconnection service the generators request. The Company believes that any such costs borne by the Company to upgrade or add to the transmission system to fulfill transmission service requests will be recovered in future rates, (g) Arpin Agreement Dispute ----------------------- The Arpin Substation Benefit Area Joint Operating, Planning and Cost Sharing Agreement ("the Agreement"), was entered into by Northern States Power Company ("NSP"), Marshfield Electric & Water Department ("MEWD"), Wisconsin Public Service Corporation ("WPSC"), Wisconsin Power & Light Company ("WPL") and Wisconsin Electric Power Company ("WE") in 1988. The Agreement provided for an annual payment of $295,000 from WPL to NSP for use of a 345kv transmission line owned by NSP. This annual payment was shared by WPL, WPSC and MEWD based on distribution load of the entities in the Arpin area. At the time the Company was formed, WPL transferred the Arpin substation to the Company and attempted to assign the Agreement to the Company. Accordingly, WPL has taken the position that the Company should now be responsible for the $295,000 annual payment. Total charges, including interest, for the period 2001 to 2004 would be approximately $1.2 million. The Company disputes the validity of the assignment of the Agreement, as the Agreement requires the written consent of all parties for any assignment, and such consent was never obtained. In addition, the agreement requires the parties to renegotiate the $295,000 annual payment after ten years (1997). If the parties cannot agree on a new amount, the matter goes to arbitration, with the arbitrator expressly given authority to reestablish the payment back to the ten-year point. The arbitrator is required to take current FERC policy into account in its decision, The Company believes current FERC policy likely would not allow the $295,000 fee. Certain of the parties to the Agreement have indicated they are considering initiating price renegotiation, Xcel, the parent company of NSP, has initiated arbitration proceedings consistent with the Agreement. The Company has taken the position that it is not a proper party to the arbitration since it is not a party to the Agreement. The Company has taken the further position that any dispute with WP&L over the assignability of the Agreement responsibilities must be resolved pursuant to the dispute resolution process established under the Company's Operating Agreement and applicable to the Asset Contribution Agreement. The parties met 25
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for mediation on December 20, 2004, where they agreed to hold the formal arbitration proceeding in abeyance until the end of January 2005 to give the Company and Xcel additional time to come to an agreement to settle the dispute. The Company does not believe that it will ultimately be responsible for the annual payments under the Agreement and has not recorded a liability in its financial statements for any amounts related to the Agreement. In the event arbitration is needed and the outcome is negative, the Company would recover any amounts paid to NSP through its revenue requirement true-up. (h) Potential Adverse Legal Proceedings ----------------------------------- The Company may, in the future, become party to lawsuits, including certain suits that may involve claims for which it may not have sufficient insurance coverage. Such litigation could include suppliers and purchasers of energy transmitted by the Company and others with whom the Company conducts business, This liability exposure is limited by FERC-approved provisions in MISO's tariff that limit potential damages, for which the Company could be held liable for interruption of service, to only direct damages. (9) Related Party Transactions -------------------------- (a) Asset Transfers and Membership Interests ---------------------------------------- On January 1, 2001, Wisconsin Electric Power Company, Edison Sault Electric Company, Wisconsin Power & Light Company, South Beloit Water, Gas & Electric Company, Wisconsin Public Service Corporation and Madison Gas and Electric Company (together "the contributing utilities") transferred transmission assets with a net book value of $554.5 million to the Company in exchange for equity interests in the Company. In addition, Wisconsin Public Power, Inc. and Management Inc. contributed cash of $16.9 million and $95,000, respectively, in exchange for equity interests in the Company. On April 2, 2001, $186.1 million of the initial membership interests of the Company were redeemed for cash. On June 25, 2001, thirteen municipalities transferred transmission assets with net book values of $10.2 million and cash in the amount of $5.3 million to the Company in exchange for equity interests in the Company. On June 29, 2001, four electric cooperatives and Upper Peninsula Power Company ("UPPCo") transferred transmission assets with a net book value of $27.5 million and cash in the amount of $2.1 million to the Company in exchange for equity interests in the Company. Also on June 29, 2001, an additional $73.8 million of the initial ownership interests of the contributing utilities, municipalities, and cooperatives were redeemed for cash. The original asset contribution agreement contained a provision under which WPSC would retain and complete certain construction projects. Upon completion, the assets would be contributed to the Company for additional equity interests. WPSC transferred such projects to the Company in the amount of $1.0 million in October 2002, $0.4 million in January 2003 and $5.8 million in December 2003. 26
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On June 13, 2003, the Company acquired the Arrowhead to Weston Project assets from WPSC, at WPSC's cost of $20 million, in exchange for cash. As part of the agreement to transfer the Project, WPSC agreed to provide equity financing of 50% of the costs of the Project. During 2004 and 2003, WPSC contributed cash of $15.7 million and $13.5 million, respectively, in exchange for additional equity interests in the Company, related to its financing of the Project, During June 2003. Badger Power Marketing Authority transferred approximately $.9 million of transmission assets to the Company in exchange for an additional equity interest in the Company. On December 31, 2003, Upper Peninsula Public Power Agency transferred $.8 million of transmission assets and $1.5 million of cash to the Company in exchange for an equity interest in the Company. During 2004, members contributed $68 million in a voluntary capital call in exchange for membership units. Equal installments were received in January, April, July and October. (b) Operations & Maintenance and Transitional Services Agreements ------------------------------------------------------------- Since inception, the Company has operated under transitional services and operations and maintenance agreements whereby the contributing utilities, municipalities and cooperatives provided certain administrative, operational, maintenance and construction services to the Company at a fully allocated cost, including direct cost, overheads, depreciation and return on assets employed in the services provided to the Company. These agreements automatically renew annually, unless cancelled by either party. Under the original operations and maintenance agreements with the contributing utilities, the Company was obligated to pay each contributing utility a minimum of 85% of the expenses previously incurred by the utility for operations and maintenance activities in a representative year. The amounts paid have exceeded the minimum in each year. Three contributing utilities have signed new operations and maintenance agreements that extend the provision of services. Two of those agreements allow the contributing utilities to decline to perform services for the Company, but require the Company to request a minimum of 90% of the labor hours the contributing utility actually accepted in the previous year. The third agreement does not contain a minimum number of hours that the Company is required to request All other operations and maintenance agreements were automatically extended on a year-to-year basis. The Company plans to continue efforts to renegotiate its operations and maintenance agreements. In the event that the Company is not able to renew these agreements at the end of their current terms, the Company cannot guarantee that it will be able to procure all similar services at similar costs. The Company believes that the costs the Company must incur to provide transmission service will be recoverable in future rates. The terms of these agreements, including pricing, are subject to oversight by the PSCW and the Illinois Commerce Commission. The Company was billed approximately $63.4 million in 2004, $75.2 million in 2003, and $91.4 million in 2002 under these agreements. Accounts payable and accrued liabilities at December 31, 2004 and 2003 include amounts payable to these companies of $10 5 million and $10.3 million, respectively, 27
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(c) Transmission Service -------------------- The contributing utilities, municipalities and cooperatives are the primary parties receiving service utilizing the Company's facilities under the MISO tariff. As such, the Company has entered into distribution transmission interconnection agreements with each of the contributing members interconnected to it. In fewer instances, the Company has also entered into generation-transmission interconnection agreements with certain of these parties. Neither type of interconnection agreement contains a provision for the payment of rates or charges, except to provide that the Company shall offer transmission services pursuant to the applicable FERC-approved tariff. The Company entered into a network integration transmission services agreement and a network operating agreement with each of the contributing utilities. The network integration transmission services agreement specifies the terms of service and the network load that shall be served to each of the contributing members. The obligation to render service under these agreements was transferred to MISO effective February 1, 2002. The network operating agreement specifies the procedures and safeguards each of the contributing members must follow to allow for integration of its load and resources on the Company's system. Revenues from Wisconsin Electric Power Company, Wisconsin Power and Light Company, Wisconsin Public Service Corporation, Madison Gas and Electric Company and Wisconsin Public Power, Inc. ranged from 85-90% of the Company's transmission service revenue for the years ended December 31, 2004, 2003 and 2002, (d) Lease Agreement with Alliant Energy ----------------------------------- Beginning January 1, 2001, the Company entered into a lease agreement with Alliant Energy Corporate Services, Inc., an affiliate of the Company, for a portion of the Company's system operating center in Stoughton, WI and agreed to provide control and operational services at such center to Alliant. Both the lease and the services are being provided to Alliant at cost. Amounts billed under these agreements totaled S2.7 million in 2004, $2.7 million in 2003, and $4.2 million in 2002. (e) Management Inc. --------------- As discussed in Note 1(b), Management Inc manages the Company. Management Inc. charged the Company approximately $52.7 million, $50.1 million, and $39.9 million 2004, 2003 and 2002, respectively, primarily for employee related expenses. These amounts were charged to the applicable operating expense accounts, or capitalized as construction work in progress or other assets, as appropriate. The amounts are recorded in the Company's accounts in the same categories the amounts would have been recorded had the Company incurred the costs directly. 28
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[Enlarge/Download Table] (f) Interconnection Agreements -------------------------- As discussed in Notes 1(f) and 8(f), the Company has interconnection agreements related to the capital improvements required to connect new generation equipment to the grid. Some of these agreements are with members or affiliates of members of the Company. At December 31, 2004 and 2003, liabilities included $25.1 million and $4.7 million respectively, of amounts received related to these agreements from entities that are also members of the Company. $18.8 million and $3.1 million was included in current liabilities as of December 31, 2004 and 2003, respectively. (10) Quarterly Financial Information (unaudited) Three Months Ended ------------------ 2004 ---- March 31 June 30 September 30 December 31 Total ------------ ------------ ------------ ------------ ------------ Operating Revenues $ 60,200 $ 62,930 $ 69,056 70,377 $ 262,563 Operating Expenses 36,009 37,331 42,369 42,021 157,730 ------------ ------------ ------------ ------------ ------------ Operating Income 24,191 25,599 26,687 28,356 104,833 Other Income 951 907 726 474 3,058 Interest Expense, net 7,163 7,512 7,586 7,684 29,945 ------------ ------------ ------------ ------------ ------------ Earnings Before Tax $ 17,979 $ 18,994 $ 19,827 $ 21,146 $ 77,946 ============ ============ ============ ============ ============ 2003 ---- March 31 June 30 September 30 December 31 Total ------------ ------------ ------------ ------------ ------------ Operating Revenues $ 51,439 $ 55,142 $ 56,717 $ 62,310 $ 225,608 Operating Expenses 31,240 33,777 35,015 39,517 139,549 ------------ ------------ ------------ ------------ ------------ Operating Income 20,199 21,365 21,702 22,793 86,059 Other Income 603 204 567 1,181 2,555 Interest Expense, net 6,092 6,339 6,397 7,080 25,908 ------------ ------------ ------------ ------------ ------------ Earnings Before Tax $ 14,710 $ 15,230 $ 15,872 $ 16,894 $ 62,706 ============ ============ ============ ============ ============ Because of seasonal factors impacting the Company's business, particularly the maintenance and construction programs, quarterly results are not necessarily comparable, In general, due to the Company's rate formula, revenues and operating income will increase throughout the year as newly constructed assets are placed into service and the Company begins to earn a return on those assets. 29
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American Transmission Company LLC Management's Discussion and Analysis of Financial Condition and Results of Operations General ------- The following discussion provides information that management believes is relevant to an assessment and understanding of American Transmission Company LLC's ("the Company") results of operations and financial condition. This discussion should be read in conjunction with the financial statements and notes to financial statements. The Company was organized as a Wisconsin limited liability company on June 12, 2000 and began operations on January 1, 2001. The Company's purpose is to plan, construct, operate, own and maintain electric transmission facilities to provide for an adequate and reliable transmission system that meets the needs of all users on the system and supports equal access to a competitive, wholesale, electric energy market. The Company owns and operates the electric transmission system, under the direction of the Midwest Independent Transmission System Operator, Inc. ("MISO"), in parts of Wisconsin, Illinois and the Upper Peninsula of Michigan. The Company is managed by a corporate manager, ATC Management Inc. ("Management Inc."). The Company and Management Inc, have common ownership and operate as a single functional unit. All employees who serve the Company are employees of Management Inc. The Company pays the expenses of Management Inc. Critical Accounting Policies ---------------------------- The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to apply policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. Because of the inherent uncertainty in the nature of the matters where estimates are used, actual amounts could differ from estimated amounts. The following accounting policies represent those that management believes are particularly important to the financial statements and require the use of judgment in estimating matters that are inherently uncertain. Revenues -------- Wholesale electric transmission service for utilities, municipalities, municipal electric companies, electric cooperatives and other eligible entities is provided through the Company's facilities under the MISO openaccess transmission tariff regulated by the Federal Energy Regulatory Commission ("FERC"), The Company charges for these services under FERC-approved rates. The tariff specifies the general terms and conditions of service on the transmission system and the approved rates set forth the calculation of the amounts to be paid for those services. The Company's revenues are derived from agreements for the receipt and delivery of electricity at points along the transmission system. The Company does not take ownership of the electricity that it transmits. Revenue is recognized based on the amounts billable under the tariff for services provided during the reporting period (see "Rate Determination and Revenue Recognition" below). Based on a true-up provision in the approved rates, the Company accrues or defers revenues to the extent that the actual revenue requirement, as calculated under the rate formula, for the reporting period is higher or lower, 30
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respectively, than the amounts billed during the reporting period. The Company records a reserve for revenue subject to refund when such refund is probable and can be reasonably estimated. The revenue requirement for each year represents the total amount that the Company is entitled to collect from all revenue sources, which include the following: Network Service Revenue consists of charges paid by the Company's network customers to reserve transmission capacity on the Company's system, The annual network revenue requirement is divided among all of the Company's network customers based on their historic usage of the system, known as load ratio share. The charges for an individual customer are billed in even monthly installments during the year and are not dependent upon actual usage. Thus, the Company's network service revenue during a given year, which covers approximately 85-90% of the Company's total revenue requirement, will not vary once the revenue requirement and rates are determined for each year. In the event new network customers join the Company's network during the year, the load ratio share and monthly charges of each customer are adjusted prospectively. Although network service is provided under the MISO tariff, the Company bills and collects its own network service revenue under a billing agreement with MISO. Point-to-Point Revenue relates to charges for delivering energy from specific points on the Company's transmission system to other specific points on the Company's transmission system. All point-to-point transactions are administered and billed by MISO; the Company receives a portion of the revenue from each transaction based on the MISO revenue allocation methodology. The point-to-point service revenue that the Company will realize each year depends on the length, duration and other terms of the firm contracts MISO has for point-to-point service and the volumes of electricity transmitted as non-firm service. Variations in point-to-point service revenues do not affect the Company's results of operations, however, because under the true-up mechanism described above, any over- or under-collection as measured against the Company's point-to-point service revenue projected in the current revenue requirement would be a component of any true-up adjustment recorded for network service revenue. Other Transmission Service Revenue consists of control area service revenue such as scheduling and re-dispatch services and recovery of start-up expenses. Other Operating Revenue is derived from other transmission-related services provided to third parties that are not provided under regulated tariffs and rental of certain transmission and administrative property and equipment by third parties. 31
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The Company's operating revenues for 2004, 2003 and 2002 consisted of: (in Thousands) 2004 2003 2002 ----------------------------------------------------------------------------- Network Service Revenue $226,495 $191,785 $168,454 Point-to-Point Revenue 11,486 8,629 8,611 Other Transmission Service Revenue Scheduling, System Control and Dispatch 6,383 6,805 7,656 Reliability Redispatch 13,082 12,073 11,507 FERC Administrative Assessment -- 388 1,430 Recovery of Start-up Costs 4,291 4,730 5,198 Other 26 43 -- -------- -------- -------- Transmission Service Revenue 261,763 224,453 202,856 Other Operating Revenue 800 1,155 2,442 -------- -------- -------- Total Operating Revenues $262,563 $225,608 $205,298 ======== ======== ======== Regulatory Assets ----------------- Regulatory assets represent costs that have been deferred to future periods when it is at least probable that the regulator will allow future recovery of those costs through rates. The accounting for these regulatory assets is in accordance with the provisions of Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation". The Company continually assesses whether regulatory assets continue to meet the criteria for probability of future recovery. This assessment includes consideration of factors such as changes in the regulatory environment, recent rate orders to other regulated entities under the same jurisdiction, and the status of any pending or potential deregulation legislation. Regulatory assets related to the formula rate true-up are only recorded to the extent such amounts will be billed to customers within the next two years. If future recovery of certain regulatory assets becomes improbable, the affected assets would be written off in the period in which such determination is made. Impairment of Long-lived Assets ------------------------------- The Company reviews the carrying values of long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying values may not be recoverable. Impairment would be determined based upon a comparison of the undiscounted future operating cash flows to be generated during the remaining life of the assets to their carrying values. An impairment loss would be measured by the amount that an asset's carrying amount exceeds its fair value. As long as its assets continue to be recovered through the ratemaking process, the Company believes that such impairment is unlikely. 32
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Allowance for Funds Used During Construction -------------------------------------------- Allowance for funds used during construction ("AFUDC") represents the composite cost of the debt used to fund the construction of transmission assets and a return on members' capital devoted to construction. Although the allowance does not represent current cash income, it is recovered under the ratemaking process over the service lives of the related assets. In accordance with the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation", the Company capitalizes AFUDC to the associated projects in Construction Work in Progress ("CWIP"). Beginning January 1, 2004 the Company was allowed to include CWIP in its rate base and earn a current return on construction projects that commenced construction after December 31, 2003, in lieu of capitalizing AFUDC to the projects. Accordingly, the Company does not accrue AFUDC on projects earning a current return. Interconnection Agreements -------------------------- The Company has entered into interconnection agreements with entities planning to build generation plants within the Company's service territory. During construction, the generators will construct the interconnection facilities or finance and bear all financial risk of having the Company construct the interconnection facilities under these agreements. The Company will own and operate the interconnection facilities when the generation plants become operational and will reimburse the generator for construction costs plus interest. If the generation plants do not become operational, the Company has no obligation to reimburse the generator for costs incurred during construction. In cases in which the Company is contracted to construct the interconnection facilities, the Company receives cash advances for construction costs from the generators. During construction, these costs are included in CWIP. Cash advances from the generators, along with accruals for interest, are recorded as liabilities. These accruals for interest are capitalized, in lieu of AFUDC, and included in CWIP. Preliminary Survey and Investigation Costs ------------------------------------------ The Company incurs certain preliminary survey and investigation ("PSI") costs for studies and planning in the early stages of construction of new transmission assets. For projects started prior to December 31, 2003, the Company capitalizes such PSI costs as other assets until all required regulatory approvals are received, at which time the PSI costs are transferred to construction work in progress. Beginning January 1, 2004, the Company is allowed to expense, and to recover in rates, PSI costs in the year incurred. Accordingly, the Company expenses PSI costs for projects started after December 31, 2003. 33
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Rate Determination and Revenue Recognition ------------------------------------------ The Company's transmission service revenue requirement is determined by a formula approved by FERC and included in Attachment 0 of the M150 Open Access Transmission Tariff. The formula is designed to reimburse the Company for all reasonable operations and maintenance expenses, taxes other than income taxes and depreciation and amortization, and to provide a return on assets employed in the provision of transmission services. The Company's rate base consists of the original cost of assets in service reduced by accumulated depreciation and members' deferred taxes associated with these assets, a working capital allowance and any prepayments. The weighted average cost of capital, or return rate, applied to rate base is intended to cover the cost of any long-term debt financing and provide equity holders a return that is commensurate with the risk involved in their investment. For 2004, 2003 and 2002, the allowed rate of return on common equity has been 12.2%. A provision for taxes on the equity component of the return is also included in the rate formula. Although the Company, as a non-taxable limited liability company, does not pay income taxes itself, it is allowed to include in its revenue requirement an estimate of income taxes that are the responsibility of the Company's taxable members. The D.C. Circuit of the U.S. Court of Appeals recently issued an opinion in a FERC rate proceeding involving an oil pipeline company that may impact the Company's ability to recover taxes in the revenue requirement in the future. The case involved complaints filed by its customers regarding several issues related to the pipeline's tariff, including the recovery of income taxes as a component of the pipeline's cost of service. The pipeline was formed as a nontaxable limited partnership. In its cost of service, FERC had allowed the pipeline to recover the income taxes paid by the partnership's corporate owners on their respective shares of partnership earnings. The Court found that FERC had not provided a compelling argument to justify including in the pipeline's cost of service the taxes paid by its owners. The Court vacated that portion of the FERC opinion and order, which allowed the recovery of income taxes in the pipeline's rates and remanded it to FERC for further consideration. On December 2, 2004, FERC issued a Request for Comments on the implications of the D.C. Circuit's opinion. The Company has filed comments with FERC in support of maintaining an income tax allowance for partnerships. The Company continues to monitor developments in this case closely. At this time, the Company is not able to determine whether and to what extent this case might impact collection of income taxes through its revenue requirement, however, the Company believes any changes in FERC policy that might result from this case would likely only impact revenues prospectively. For the years ended December 31, 2004, 2003 and 2002, the Company included $25.9 million, $20.9 million and $17.4 million, respectively, for income taxes in its revenue requirement. 34
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On October 30, 2003, the Company filed an application with FERC for approval to modify its rate formula in Attachment 0 of the MISO Open Access Transmission Tariff. The Company sought authorization to make the following modifications to the rate formula: a) Include Construction Work in Progress for new transmission investment in rate base to earn a current return in lieu of capitalizing an Allowance for Funds Used During Construction. b) Allow current year expensing of preliminary survey and investigation costs for new transmission investment. Such costs were previously capitalized as a component of the associated transmission assets' cost and recovered, with a return on investment, over the life of the asset. c) Increase the allowed return on equity from 12.20% to 12.38% to correspond to the rate FERC has allowed for other MISO transmission owners and adopt a 50% debt, 50% equity capital structure. On December 29, 2003, FERC issued an order that conditionally accepted for filing and nominally suspended the Company's proposed modifications, to become effective January 1, 2004, subject to refund. The order also established hearing and settlement judge procedures. Based on concerns raised by intervenors in the case, several issues were set for hearing, including the proposed capital structure and the rate impact of expensing preliminary survey and investigation costs for certain transmission projects. The Company filed a settlement agreement that was approved by FERC on May 6, 2004, that resolved all issues set for hearing in the December 29'h order. The settlement agreement allows the Company to include Construction Work in Progress in rate base, to expense preliminary survey and investigation costs if the project meets specified requirements (generally if a project is approved by MISO as part of its planning process), and to adopt a 50% debt, 50% equity capital structure. The Company agreed to maintain the 12.20% return on equity and agreed to refund the difference between the 12.38% approved in the December 2911 order and the 12.20% in the settlement agreement for the period between January 1, 2004 and the settlement agreement date approved by FERC. This refund, which is approximately $.4 million, is included in the Company's true-up calculation for 2004. In the future, the Company's return on equity will float at 18 basis points below the rate approved by FERC for other MISO transmission owners ("the MISO ROE"). Several intervening parties have challenged the methodology used by FERC in determining the current MISO ROE, The matter is currently pending before the D.C. Circuit of the U.S. Court of Appeals and a resolution is expected in 2005. The settlement agreement reached in the Company's rate filing provides that, to the extent that there is a reduction of the MISO ROE below the current 12.38%, the Company will be obligated to refund an additional amount, retroactive to January 1, 2004, equal to 50% of the difference between the 12.20% return on equity and 18 basis points below the reduced MISO ROE, subject to a limit of $2 million. The Company cannot predict whether or not such reduction in the return on equity and associated refund will occur. The Company's formula rates, as approved by FERC, contain a true-up mechanism, which uses a three-year cycle to project and true-up rates. Prior to the beginning of each calendar year, the Company prepares a forecast of operating, maintenance, depreciation and tax expenses, as well as the projected rate base resulting from planned construction and other capital expenditures for the upcoming year, From this forecast, the Company computes a projected revenue requirement and projected rates for the year. These rates are billed and collected from network and point-to-point transmission customers throughout the first year. During the second year, after filing annual financial reports with FERC, the Company recalculates the revenue requirement for the first year based on actual results. Any difference from the projected revenue requirement, including any differences in point-to-point revenues collected, is added to, or subtracted from, the revenue requirement and rates computed for the third year. 35
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[Enlarge/Download Table] Under the true-up mechanism, the Company is authorized to include an under-collected amount of approximately $2.5 million from 2003, plus interest, in its billings in 2005. During 2004, the Company over-collected approximately $6.8 million. Under the terms of the tariff, this amount would ordinarily be refunded, with interest to customers in 2006; however, the Company filed an application with FERC on December 22, 2004 for an amendment to the rates which would allow the Company to accelerate this refund by one year and return it to customers, net of the 2003 under-collection, in 2005. FERC issued an order authorizing this treatment, as filed, on February 17, 2005. The revenue requirement calculations for the years ended December 31, 2004, 2003 and 2002 are summarized below: (In Thousands) 2004 2003 2002 Return on Rate Base Average Rate Base, including Unamortized Start-up Costs $ 812,001 $ 684,487 $ 594,704 Weighted Rate of Return 9.72% 9.52% 9.56% --------- --------- --------- Return on Rate Base 78,928 65,175 56,824 Provision for Members' Income Taxes 25,905 20,884 17,415 --------- --------- --------- Total Return and Income Taxes 104,833 86,059 74,239 Expenses Operations and Maintenance 105,377 93,681 86,556 Depreciation and Amortization 46,636 40,694 38,407 Taxes Other than Income 5,717 5,174 6,096 --------- --------- --------- Total Operating Expenses 157,730 139,549 131,059 --------- --------- --------- Total Revenue Requirement 262,563 225,608 205,298 Less: Total Revenue Billed 269,327 223,134 209,909 --------- --------- --------- True-up Collection l (Refund) $ (6,764) $ 2,474 $ (4,611) ========= ========= ========= 36
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Results of Operations --------------------- Earnings Overview ----------------- The Company's earnings before tax and operating income are driven by its rate formula, which defines the Company's revenue requirement and allows it to recover all operating expenses. The Company's earnings before tax for 2004 were $77.9 million, an increase of 24% from earnings of $62.7 million in 2003. Operating income increased by $18.8 million in 2004 as compared to 2003. Offsetting the $18,8 million increase in operating income is a $4.0 million increase in net interest expense resulting from additional long-term debt issued during the second half of 2003. The Company's earnings for 2003 were $62.7 million, an increase of 16% from earnings of $54.1 million in 2002. Operating income increased by $11.8 million in 2003 as compared to 2002. Offsetting the increase in operating income is a$4,3 million increase in net interest expense resulting from additional long-term debt issued in the second half of 2002 and 2003 and short-term debt issued during 2003 to finance construction of transmission assets. Revenues -------- The Company's revenue requirement, which equals total operating revenues, was S262.6 million during 2004, an increase of 16% from $225.6 million in 2003. This increase was due to an increase in the return earned on rate base of $13.8 million, an increase in the provision for members' income taxes of $5.0 million and an increase of operating expenses of $18.2 million, all recoverable under the revenue requirement. The Company's revenue requirement for 2003 was $225.6 million, an increase of 10% from $205.3 million during 2002. The increase was due to an increase in the return on rate base of $8.4 million, an increase in the provision for members' income taxes of $3.5 million and an increase in operating expenses of $8.5 million. The Company's return on rate base for 2004 was $78.9 million, an increase of 21 % from the return on rate base of $65.2 million during 2003. The increase was primarily due to additional assets being placed in service as part of the construction program during 2004. The return also increased due to a change in capital structure from the rate settlement (see Rate Determination and Revenue Recognition above), resulting in an increase in the effective return on equity Slightly offsetting the increase in the return on equity was a decrease in the debt component of the return due to the issuance of $100 million in senior notes during 2003. The notes had an interest rate that was lower than the previous average rate on outstanding debt. The return on rate base increased to $65.2 million during 2003, from $56.8 million in 2002. The increase is primarily due to an increase in assets placed in service as part of the construction program during 2003. 37
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Operating Expenses ------------------ Total operating expenses were $157.7 million; or 13%, higher during 2004 than 2003. Operations and maintenance expenses increased $11.7 million during 2004, due to an increase in maintenance expense related to construction projects, the addition of new facilities and information technology infrastructure and the expensing of $1.5 million of preliminary survey and investigation costs for projects started after December 31, 2003. Depreciation also increased by $5.9 million due to additional assets placed in service throughout 2003 and 2004. Total operating expenses were $8.5 million, or 3%, higher during 2003 than 2002. Operations expenses were $7.1 million higher in 2003, due to an increase in maintenance expense related to construction projects, the addition of new facilities and information technology infrastructure and the development of supply chain capabilities to support the construction program. Depreciation increased by $2.3 million due to additional assets being placed in service by the Company throughout 2002 and 2003. Other Income ------------ Other income increased approximately $0.5 million during 2004, as compared to 2003. The increase was due to a $0.7 million increase in the allowance for equity funds used during construction, driven by a higher average CWIP balance eligible for AFUDC capitalization during 2004 than 2003. Other income increased approximately $1.1 million during 2003, as compared to 2002. The increase was primarily due to a $.8 million increase in the allowance for equity funds during construction caused by a higher average CWIP balance eligible for AFUDC capitalization during 2003 than 2002. Net Interest Expense -------------------- Net interest expense was $4.0 million higher in 2004, as compared with 2003. The increase relates to interest on additional long-term debt issued during 2003 and the increased issuance of commercial paper during 2004. Net interest expense was S4.3 million higher in 2003, as compared with 2002. This increase relates to interest on additional long-term debt issued during the second half of 2002 and 2003 and interest on commercial paper outstanding during 2003 prior to the issuance of long-term debt. 38
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Liquidity and Capital Resources ------------------------------- During 2004, the Company used net cash of $9.0 million as compared to net cash used of $5.7 million in 2003. Net cash provided from operations increased by $40.4 million compared to 2003, primarily due to a$15.2 million increase in earnings before tax and the timing of receipts from customers and payments to vendors. Cash flows used in investing activities increased $48.7 million in 2004 due to an increase in the Company's construction program, as well as a$13,0 million increase in cash outflows relating to the Arrowhead to Weston project (see Note 8(e)). Net cash provided by financing activities increased $4.9 million during 2004 as compared to 2003. The increase was due to an increase of $68.0 million from the issuance of membership units for cash offset by a decrease of $40.9 million in cash received from debt issuances. During 2003, the Company issued $100 million in long-term debt, whereas during 2004, the Company issued no long-term debt, but instead financed its operations through the issuance of $58.3 million in commercial paper. Also offsetting the increase in cash from membership units was an $11.7 million increase in repayments under interconnection agreements. During 2003, the Company used net cash of $5.7 million as compared to net cash used of $23.2 million in 2002. Net cash provided by operations increased $1.1 million, due to an increase in earnings before tax and depreciation and amortization, offset slightly by changes in working capital related to the timing of receipts from customers and payments to vendors. Net cash used in investing activities increased by $70.9 million, primarily due to a general increase in the Company's construction program, as well as work performed during 2003 in support of several generation interconnection projects. Cash provided by financing activities increased $87.3 million during 2003. The increase is due to the Company's net proceeds from long-term debt issuances of $99.2 million during 2003, as compared to net proceeds of $49.4 million during 2002. The Company also received $26.2 million in cash advances under generation interconnection agreements during 2003, compared to $3.8 million received during 2002. The Company received $17.2 million from the issuance of membership units during 2003, compared with $.6 million during 2002. Capital Requirements and Liquidity ---------------------------------- Management believes that to provide adequate and reliable transmission service and to support access to competitive, wholesale energy markets without favoring any participant, it will be necessary to strengthen and expand the Company's transmission system to deliver electricity to customers in Wisconsin, Michigan and Illinois. Expansion will relieve transmission constraints, allow additional generation capacity to be connected to the system, enhance wholesale competition and permit entry by new competitors in electricity generation. The Company has plans for approximately $315 million in new transmission construction projects and other capital spending in 2005, and expects that it could incur approximately $2.8 billion in capital expenditures over the next ten years. These estimates are based on the Company's 2005 capital budget and ten-year transmission planning and needs assessment, much of which remains subject to regulatory approval and continuing analysis of system needs. This estimate does not include additional acquisitions of transmission assets the Company might make. Approximately $39 million of the anticipated capital spending in 2005 is related to generation interconnection agreements and will be funded by the generators, as described in the notes to financial statements. 39
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The ability to construct transmission assets is subject to the Company obtaining extensive regulatory approvals, including siting, from the Public Service Commission of Wisconsin ("PSCW") and other regulatory bodies. Management believes regulatory and siting issues pose the key risks to completing and placing transmission assets in service. Once approved, constructed and placed in service, the costs of transmission projects are included in the rate formula that determines the Company's revenue requirement; however, it is possible that some of the Company's capital projects will not be completed and placed in service. In such situations there is an additional risk, because while state regulatory bodies have jurisdiction over construction, FERC has jurisdiction over the Company's rates, While costs incurred by the Company for projects that are not completed are generally not significant, there is potential for higher costs to be incurred related to large projects, such as the Arrowhead to Weston project. MISO's tariff contains provisions under which such costs may potentially be recovered if the related project was included in MISO's Transmission Expansion Plan, required by MISO or otherwise approved by MISO. The Arrowhead to Weston Project is included in MISO's Transmission Expansion Plan. If recovery is not realized through the MISO tariff, the Company will seek recovery of such costs through its FERC regulated rate formula; however, there is no guarantee that such recovery will be allowed by FERC. If recovery is not realized through the MISO tariff, or recovered through rates, these costs would be charged to expense. The timing and amount of the Company's construction requirements have a significant impact on the Company's liquidity and its cash requirements. To meet these requirements over the long-term, the Company plans to finance its capital expenditure program through the issuance of long-term debt, reinvested equity and, as necessary, additional equity infusions from current members, private equity investments and/or public equity offerings. In connection with these financing alternatives, management intends to target a debt to total capitalization ratio of 50% to 53% consistent with the maintenance of an "A" credit rating and tier-one commercial paper ratings. In the short run, management intends to finance construction with commercial paper offerings. The Company's commercial paper program is supported by a $125 million three-year revolving credit agreement. The revolving credit agreement can be expanded to $200 million at the Company's option. It is the Company's intent to increase the commercial paper program with any increase in the revolving credit agreement. As the commercial paper borrowing capacity is utilized, management plans to refinance outstanding commercial paper through longterm debt offerings. To the extent that the private placement debt market remains accessible to the Company at attractive rates and on attractive terms, management intends to finance the long-term debt component of its construction requirements in this manner. To maintain its targeted debt to capitalization ratio, the Company issued a voluntary capital call for $68 million to its members in December 2003. The Company received installments of approximately $17 million in January, April, July and October of 2004. The participating members received additional membership units at the current book value per unit at the time of each installment. No capital call is planned for 2005. The majority of members have given a non-binding indication that they expect to continue to provide equity funding for planned capital calls during 2006 through 2009. 40
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As part of the agreement to transfer the Arrowhead to Weston project to the Company, Wisconsin Public Service Corporation ("WPSC") committed to provide equity funding for 50% of the total cost of the project, up to $198 million. WPSC's contributions under this arrangement are made monthly based on project expenditures. In addition, certain of the Company's other members have the right, under the operating agreement, to contribute additional equity to maintain their ownership percentages as WPSC funds the Arrowhead to Weston project. Continual access to the commercial paper and long-term debt markets will be necessary to fund the Company's construction plans. Based on the capital expenditure forecast of $2.8 billion over the period 2005 through 2014, management anticipates, under its new tariff, its credit ratings to remain investment grade with a substantial margin of safety. The rate formula modification that the Company filed with FERC in the settlement agreement provides increased cash flows through the accelerated recovery of preliminary survey and investigation costs in the current period and by allowing the Company to earn a current return on its investment in Construction Work in Progress for new transmission projects. If the Company cannot maintain its current credit rating, future financing costs could increase, future financing flexibility could be reduced, future access to capital could be difficult and future ability to finance capital expenditures demanded by the market could be impaired. Management cannot provide assurance that the Company will be able to secure the additional sources of financing needed to fund the significant capital requirements associated with the Company's transmission system expansions discussed above. In addition, some expenditures may not result in assets on which the Company will earn a return, as discussed above. The Company's operating agreement provides that the board of directors of its corporate manager, Management Inc., will determine the timing and amount of distributions to be made to the Company's members. In this agreement, the corporate manager also declared its intent, subject to certain restrictions, to distribute an amount equal to 80% of the Company's earnings before taxes. The Company's operating agreement also provides that it may not pay, and no member is entitled to receive, any distribution that would generally cause the Company to be unable to pay its debts as they become due. Cash available for distribution for any period consists of cash from operations after provision for capital expenditures, debt service and reserves established by Management Inc. The Company has distributed 80% of its earnings before taxes to its members in each year since inception. 41
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[Enlarge/Download Table] Long-term Contractual Obligations and Commercial Commitments ------------------------------------------------------------ The Company's contractual obligations and other commitments as of December 31, 2004, representing cash obligations that are considered to be firm commitments, are as follows (in thousands): Payment Due Within Due After ------------------------------------------------- ---------- Total 1 Year 2-3 Years 4-5 Years 5 Years ---------- ---------- ---------- ---------- ---------- Long-term Debt $ 450,000 $ -- $ -- $ -- $ 450,000 Interconnection Agreements $ 179,379 47,322 -- 132,057 -- Operating Leases $ 8,121 2,346 4,534 1,241 -- Postretirement Benefit Plan Contributions $ 13,430 1,397 3,829 5,085 3,119 Interest Payments on Long-term Debt $ 486,833 83,773 63,350 63,350 276,360 ---------- ---------- ---------- ---------- ---------- Total Contractual Obligations and Other Commitments $1,137,763 $ 134,838 $ 71,713 $ 201,733 $ 729,479 ========== ========== ========== ========== ========== The Company currently contracts with several utility providers for certain operation and maintenance services. Certain of the agreements contain minimum purchase requirements (as further discussed below). The Company met these obligations in 2004, 2003 and 2002 and management believes it will continue to meet these obligations in the future. Related Party Transactions -------------------------- Since inception, the Company has operated under transitional services and operations and maintenance agreements whereby the contributing utilities, municipalities and cooperatives provided certain administrative, operational, maintenance and construction services to the Company at a fully allocated cost, including direct cost, overheads, depreciation and return on assets employed in the services provided to the Company. These agreements automatically renew annually, unless cancelled by either party. Under the original operations and maintenance agreements with the contributing utilities, the Company was obligated to pay each contributing utility a minimum of 85% of the expenses previously incurred by the utility for operations and maintenance activities in a representative year. The amounts paid have exceeded the minimum in each year. Three contributing utilities have signed new operations and maintenance agreements that extend the provision of services. Two of those agreements allow the contributing utilities to decline to perform services for the Company, but require the Company to request a minimum of 90% of the labor hours the contributing utility actually accepted in the previous year. The third agreement does not contain a minimum number of hours that the Company is required to request. All other operations and maintenance agreements were automatically extended on a year-to-year basis. The Company plans to continue efforts to renegotiate its operations and maintenance agreements. In the event that the Company is not able to renew these agreements at the end of their current terms, the Company cannot guarantee that it will be able to procure all similar services at similar costs. The Company believes that the costs the Company must incur to provide transmission service will be 42
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recoverable in future rates. The terms of these agreements, including pricing, are subject to oversight by the PSCW and the Illinois Commerce Commission. A corporate manager, Management Inc, manages the Company. The Company and Management Inc. have common ownership and operate as a single functional unit. Under the Company's operating agreement, Management Inc. has complete discretion over the business of the Company. Accordingly, Management Inc. provides all management services to the Company at cost. The Company itself has no employees. The Company's operating agreement also establishes that all expenses of Management Inc. are the responsibility of the Company. These expenses consist primarily of payroll, benefits, payroll-related taxes and other employee expenses. All such expenses are recorded in the Company's accounts as if they were direct expenses of the Company. Business and Operating Environment ---------------------------------- In compliance with Wisconsin statutes and FERC requirements, operational control of the Company's transmission system was transferred to MISO, a FERC-approved regional transmission organization ("RTO"), effective February 1, 2002. MISO has operational control over the Company's system and has the authority to direct the manner in which the Company performs operations. The Company is also required to seek direction from MISO for certain operational actions the Company seeks to perform within its system. MISO is responsible for monitoring congestion, directing the associated operations to overcome congestion, approving transmission maintenance outages, as well as negotiating with generators on the timing of generator maintenance outages within the entire MISO system, including that portion representing the Company's system. The Company is required to coordinate planning activities for new projects or system upgrades with MI SO. Certain projects may require review and approval by MISO before implementation. In accordance with FERC Order 2000, MISO is the tariff administrator for all of its transmission-owning members. MISO and the Company made a joint Section 205 filing with FERC that created a separate pricing zone for the Company within MISO's tariff. The Company's rates for service are now administered under MISO's tariff; however, the Company continues to file with FERC for approval of changes to the formula that determines its revenue requirements. On April 1, 2005, MISO is scheduled to operate Day-Ahead and Real-Time energy markets ("the Day-two market"). These markets will develop a joint transmission service and energy schedule of operation on a day-ahead basis and a dispatch schedule in real time. The markets will use a security constrained, centralized dispatch methodology to optimize power flows over the MISO footprint. Since MISO does not have a history of centralized power dispatch, the FERC has established specific operational reporting requirements. While MISO is planning for the Day-two market to become operational on April 1, 2005, there is uncertainty on whether the operational requirements will be sufficiently met. The inability of MISO to become operational on April 1, 2005, would imply that the Company would have to continue with the current operating methods. 43
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In the Day-two market, market participants can acquire Financial Transmission Rights ("FTRs") to hedge against congestion costs that arise due to "congestion" on the transmission grid, The Company's customers, rather than the Company, will be responsible for congestion costs and will be allocated FTRs. The FTRs do not represent a physical right for delivery of energy, rather a financial right to the congestion revenues that are generated. Any resulting shortfall in congestion revenues will reduce payments to FTR holders on a pro-rata basis and, as a result, poses no risk to the Company, as it will not hold any FTRs and will not be responsible for congestion costs. Once the Day-two market is operational, revenue from both the energy market settlement process and the transmission billing process will be commingled, thereby exposing the Company to revenue recovery uncertainty. This uncertainty takes two forms. The first uncertainty is the underpayment by transmission or energy market customers, thereby creating a revenue shortfall. The shortfall will be allocated to the transmission owners on a prorated basis that uses revenue requirements. The second uncertainty is the possibility of an energy market participant filing for bankruptcy. A bankruptcy court would be required to determine whether transmission revenues collected by MISO could be used to satisfy claims of other creditors. On February 15, 2003, FERC issued a notice of proposed pricing policy for efficient operation and expansion of the transmission grid. The proposed policy would provide certain financial incentives related to divestiture of transmission assets from vertically integrated utilities, placement of assets under the control of a RTO and investment in new transmission facilities. The Company has evaluated the potential impact this policy could have on its operations and determined that the modifications to the rate formula contained in its rate filing with FERC would be more beneficial to the Company and proposed such changes as an alternative incentive mechanism to the incentives contained in FERC's proposed pricing policy. Subsequently, the Company and its customers entered into a settlement agreement that largely codifies these revisions to its revenue requirements. On May 6, 2004, FERC approved the settlement agreement. See Note 7 for more information. On November 18, 2004, FERC issued an order eliminating the Regional Through and Out Rates ("RTOR") for pointto-point transmission services between MISO and the PJM Interconnection ("PJM"), effective December 1, 2004. The Company had received RTOR revenues from MISO, for services that crossed the PJM-MISO seam, which served as a reduction in the amount of the Company's revenue requirement that is borne by its network transmission customers. A transitional revenue replacement mechanism, the Seams Elimination Cost Assignment ("SECA"), is expected to be in place from December 1, 2004 through March 31, 2006. The purpose of the SECA is to protect the financial position of the transmission owners by preserving their revenue stream during the transition period, after which this revenue source will be permanently eliminated. Due to the nature of the Company's revenue requirement formula, including the true-up mechanism described in Note 1(c), management does not expect the elimination of RTOR revenues to have a significant impact on the Company's results of operations. The Company expects that any revenue shortfall associated with the SECA will be made up by the true-up mechanism during the transition period. Similarly, after the transition period, the elimination of RTOR revenues will result in a net increase in the revenues collected from the Company's network transmission customers. 44
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The Company is participating in a MISO stakeholder process to determine the appropriate cost allocation for new transmission infrastructure development. As a result of the expected outcome of this process, it is possible that a much greater portion of the Company's revenues for investment in new transmission infrastructure may ultimately be derived from outside the Company's service territory. Similarly, on November 18, 2004, the FERC gave PJM and MISO and their respective transmission owners until May 18, 2005 to file a proposal to share the cost of new transmission facilities that benefit customers in both RTOs. Finally, the FERC has directed MISO and its transmission owners to investigate the continued efficacy of using the existing "license plate" rate design and report their findings to the Commission no later than February 1, 2008, Qualitative Disclosures about Market Risks ------------------------------------------ The Company manages its interest rate risk by limiting its variable rate exposure and continually monitoring the effects of market changes on interest rates. The Company's interest rate risk related to its long-term debt is mitigated by the fact that its long-term debt rate is included as a component of its revenue requirement calculation. The Company has a significant concentration of major customers; its five largest customers generate approximately 85% - 90% of its revenue on an ongoing basis. The Company closely monitors the business and credit risk associated with its major customers. These major customers are all investor-owned utilities that currently have investment grade debt ratings. 45

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