-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Bcrum8RLHvEtqGD/mIlh3zpYf7DLdCd0C02Dcd0BUYOiTWwoEB/v5rqifpCwVNe4 xqNVARhZnHmCKPxMywH36A== 0000072903-96-000008.txt : 19960517 0000072903-96-000008.hdr.sgml : 19960517 ACCESSION NUMBER: 0000072903-96-000008 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19960331 FILED AS OF DATE: 19960515 SROS: CSX SROS: NYSE SROS: PSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHERN STATES POWER CO /MN/ CENTRAL INDEX KEY: 0000072903 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 410448030 STATE OF INCORPORATION: MN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-03034 FILM NUMBER: 96566676 BUSINESS ADDRESS: STREET 1: 414 NICOLLET MALL 4TH FL CITY: MINNEAPOLIS STATE: MN ZIP: 55401 BUSINESS PHONE: 6123305500 MAIL ADDRESS: STREET 1: 414 NICOLLET MALL STREET 2: 4TH FLOOR CITY: MINNEAPOLIS STATE: MN ZIP: 55401 10-Q 1 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q X Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 or Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For Quarter Ended March 31, 1996 Commission File Number 1-3034 NORTHERN STATES POWER COMPANY (Exact name of registrant as specified in its charter) Minnesota 41-0448030 (State of other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 414 Nicollet Mall, Minneapolis, Minnesota 55401 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (612) 330-5500 None Former name, former address and former fiscal year, if changed since last report Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No _____ _____ Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Class Outstanding at April 30, 1996 Common Stock, $2.50 par value 68,707,003 shares Item 1. Financial Statements Northern States Power Company (Minnesota) and Subsidiaries Consolidated Statements of Income (Unaudited)
Three Months Ended March 31 1996 1995 (Thousands of dollars) Utility operating revenues Electric................................................. $512,943 $497,314 Gas...................................................... 205,766 163,853 Total.................................................. 718,709 661,167 Utility operating expenses Fuel for electric generation............................. 76,092 83,338 Purchased and interchange power.......................... 62,209 51,733 Cost of gas purchased and transported.................... 133,525 99,415 Other operation.......................................... 83,961 78,994 Maintenance.............................................. 47,068 37,767 Administrative and general............................... 34,941 43,749 Conservation and energy management....................... 16,190 7,770 Depreciation and amortization............................ 74,651 71,831 Taxes: Property and general.............................. 60,129 62,279 Current income tax expense........................ 54,827 40,122 Deferred income tax expense....................... (11,954) (1,290) Investment tax credit adjustments - net........... (2,207) (2,239) Total.................................................. 629,432 573,469 Utility operating income.................................. 89,277 87,698 Other income (expense) Equity in earnings of unconsolidated affiliates.......... 5,989 8,838 Allowance for funds used during construction - equity.... 2,580 1,338 Other income (deductions) - net.......................... (3,426) 2,025 Income taxes on non-regulated operations and non-operating items................................. 4,029 (934) Total .................................................. 9,172 11,267 Income before interest charges............................ 98,449 98,965 Interest charges Interest on utility long-term debt....................... 25,021 25,266 Other utility interest and amortization.................. 4,999 5,117 Non-regulated interest and amortization.................. 4,065 2,285 Allowance for funds used during construction - debt...... (2,846) (1,893) Total.................................................. 31,239 30,775 Net Income ............................................... 67,210 68,190 Preferred stock dividends ................................ 3,061 3,201 Earnings available for common stock....................... $64,149 $64,989 Average number of common and equivalent shares outstanding (000's).............................. 68,308 67,004 Earnings per average common share......................... $0.94 $0.97 Common dividends declared per share....................... $0.675 $0.660 Statements of Retained Earnings (Unaudited) Balance at beginning of period............................ $1,266,026 $1,183,191 Net income for period..................................... 67,210 68,190 Dividends declared: Cumulative preferred stock............................... (3,061) (3,201) Common stock............................................. (45,659) (44,198) Balance at end of period.................................. $1,284,516 $1,203,982 The Notes to Financial Statements are an integral part of the Statements of Income and Retained Earnings.
Northern States Power Company (Minnesota) and Subsidiaries Consolidated Balance Sheets (Unaudited)
March 31, December 31, 1996 1995 (Thousands of dollars) ASSETS Utility Plant Electric................................................ $6,608,730 $6,553,383 Gas..................................................... 712,259 710,035 Common.................................................. 312,511 299,585 Total............................................... 7,633,500 7,563,003 Accumulated provision for depreciation................ (3,414,077) (3,343,760) Nuclear fuel............................................ 864,404 843,919 Accumulated provision for amortization................ (762,397) (752,821) Net utility plant................................... 4,321,430 4,310,341 Current Assets Cash and cash equivalents............................... 94,740 28,794 Short-term investments.................................. 224 149 Customer accounts receivable - net...................... 279,347 281,584 Unbilled utility revenues............................... 123,262 112,650 Other receivables....................................... 71,846 78,993 Fossil fuel inventories - at average cost............... 26,482 43,941 Materials and supplies inventories - at average cost.... 103,050 100,607 Special deposits - non-regulated projects............... 97,989 9,773 Prepayments and other................................... 40,738 47,972 Total current assets.................................. 837,678 704,463 Other Assets Regulatory assets....................................... 365,265 374,212 Equity investments in non-regulated projects and other investments.................................. 299,892 289,495 External decommissioning fund investments............... 214,437 203,625 Non-regulated property - net............................ 176,684 177,598 Long-term receivables................................... 67,848 83,065 Intangible and other assets............................. 97,980 85,786 Total other assets................................... 1,222,106 1,213,781 TOTAL ASSETS........................................ $6,381,214 $6,228,585 LIABILITIES AND EQUITY Capitalization Common stock equity: Common stock and premium - authorized 160,000,000 shares of $2.50 par value, issued shares: 1996, 68,499,928; 1995, 68,175,934.................. $786,067 $769,534 Retained earnings..................................... 1,284,516 1,266,026 Leveraged common stock held by ESOP................... (9,033) (10,657) Currency translation adjustments - net................ 4,717 2,488 Total common stock equity........................... 2,066,267 2,027,391 Cumulative preferred stock and premium - authorized 7,000,000 shares of $100 par value; outstanding shares: 1996 and 1995, 2,400,000 without mandatory redemption.......................... 240,469 240,469 Long-term debt.......................................... 1,667,951 1,542,286 Total capitalization................................ 3,974,687 3,810,146 Current Liabilities Long-term debt due within one year...................... 15,089 25,760 Other long-term debt potentially due within one year.... 141,600 141,600 Short-term debt - primarily commercial paper............ 169,077 216,194 Accounts payable........................................ 230,393 246,051 Taxes accrued........................................... 277,421 202,777 Interest accrued........................................ 33,984 31,806 Dividends payable on common and preferred stocks........ 48,721 48,875 Accrued payroll, vacation and other..................... 82,169 78,310 Total current liabilities........................... 998,454 991,373 Other Liabilities Deferred income taxes................................... 818,216 841,153 Deferred investment tax credits......................... 159,196 161,513 Regulatory liabilities.................................. 245,083 242,787 Pension and other benefit obligations................... 120,610 115,797 Other long-term obligations and deferred income......... 64,968 65,816 Total other liabilities............................. 1,408,073 1,427,066 Commitments and Contingent Liabilities (See Note 4) TOTAL LIABILITIES AND EQUITY...................... $6,381,214 $6,228,585 The Notes to Financial Statements are an integral part of the Balance Sheets.
Northern States Power Company (Minnesota) and Subsidiaries CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Three Months Ended March 31, 1996 1995 (Thousands of dollars) Cash Flows from Operating Activities: Net Income................................................. $67,210 $68,190 Adjustments to reconcile net income to cash from operating activities: Depreciation and amortization............................ 81,643 79,517 Nuclear fuel amortization................................ 9,576 12,817 Deferred income taxes.................................... (13,494) (780) Deferred investment tax credits recognized............... (2,284) (2,349) Allowance for funds used during construction - equity.... (2,580) (1,338) Undistributed equity in earnings of unconsolidated affiliate operations.................................... (4,761) (6,241) Cash provided by changes in certain working capital items........................................... 79,077 68,532 Conservation program expenditures - net of amortization.. (403) (3,953) Cash provided by changes in other assets and liabilities. 4,821 17,483 Net cash provided by operating activities................... 218,805 231,878 Cash Flows from Investing Activities: Capital expenditures ...................................... (98,571) (77,989) Decrease in construction payables.......................... (5,485) (14,724) Allowance for funds used during construction - equity...... 2,580 1,338 Purchase of short-term investments - net................... (75) (1,000) Investment in external decommissioning fund................ (10,036) (6,981) Equity investments in and deposits for non-regulated projects and other........................................ (75,933) (7,096) Net cash used for investing activities...................... (187,520) (106,452) Cash Flows from Financing Activities: Change in short-term debt - net issuances (repayments)..... (47,117) (80,791) Proceeds from issuance of long-term debt - net............. 125,333 3,171 Loan to ESOP............................................... 0 (15,000) Repayment of long-term debt, including reacquisition premium................................................... (11,017) (5,656) Proceeds from issuance of common stock - net............... 16,337 15,400 Dividends paid............................................. (48,875) (47,080) Net cash provided by (used for) financing activities........ 34,661 (129,956) Net increase (decrease) in cash and cash equivalents.......... 65,946 (4,530) Cash and cash equivalents at beginning of period.............. 28,794 41,055 Cash and cash equivalents at end of period.................... $94,740 $36,525 The Notes to Financial Statements are an integral part of the Statements of Cash Flows.
Northern States Power Company (Minnesota) and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS In the opinion of management, the accompanying unaudited financial statements contain all adjustments necessary to present fairly the financial position of Northern States Power Company (Minnesota) (the Company) and its subsidiaries (collectively, NSP) as of March 31, 1996 and December 31, 1995, the results of its operations for the three months ended March 31, 1996 and 1995, and its cash flows for the three months ended March 31, 1996 and 1995. Due to the seasonality of NSP's electric and gas sales, operating results on a quarterly basis are not necessarily an appropriate base from which to project annual results. The accounting policies followed by NSP are set forth in Note 1 to NSP's financial statements in NSP's Annual Report on Form 10-K for the year ended December 31, 1995 (1995 Form 10-K). The following notes should be read in conjunction with such policies and other disclosures in the 1995 Form 10-K. Certain reclassifications have been made to 1995 financial information to conform with the 1996 presentation. These reclassifications had no effect on net income or earnings per share as previously reported. 1. Summary of Significant Accounting Policies 1996 Accounting Change - Wisconsin Gas Costs - While fixed costs (demand charges) from gas suppliers and transporters are incurred fairly evenly throughout the year, such costs are recovered in customer rates on a per unit basis (using average annual costs per unit), primarily in the winter heating season when sales volumes are highest. Also, the energy price of gas purchased (excluding demand charges) can vary from estimated levels included in customer rates. As a result, gas costs for both demand and energy charges are incurred throughout the year at a different time than when such costs are recovered from customers. The purchased gas adjustment (PGA) clause allows customer rates to be adjusted periodically to ensure full recovery of all gas costs incurred. Effective Jan. 1, 1996, NSP's subsidiary, Northern States Power Company, a Wisconsin corporation (the Wisconsin Company) changed its method of accounting for the regulatory effects of costs recovered through the PGA rate adjustment clause. Previously, the Wisconsin Company expensed gas costs as incurred. Beginning in 1996, the cost of gas expensed is adjusted to equal the level of cost recovery in customer rates, with such adjustments being reflected as regulatory deferrals on the balance sheet. This accounting change results in a better matching of revenues and expenses, and conforms to the cost recognition method used by the Company. This change affects the timing of expense recognition within the year but will not change total annual gas expense for 1996 or any prior years. The effect of the change on first quarter 1996 results was an increase in gas costs recognized and a decrease in pretax operating income of approximately $6.5 million, and a decrease in net income of $3.9 million (six cents per share). Consistent with accounting requirements, prior year quarterly results have not been restated for this change. Had the change been implemented as of Jan. 1, 1995, the effect of the change on first quarter 1995 results would have been an increase in gas costs and a decrease in pretax operating income of $3.7 million, and a decrease in net income of $2.2 million (three cents per share). 2. Proposed Business Combination On April 28, 1995 NSP and Wisconsin Energy Corporation (WEC) entered into an Agreement and Plan of Merger, which provides for a strategic business combination involving NSP and WEC in a "merger-of-equals" transaction to form Primergy Corporation (Primergy). See further discussion of the proposed business combination in the 1995 Form 10-K and Part II, Item 5- Other Information of this report. On April 5, 1996, NSP and WEC submitted the initial filing to the Securities and Exchange Commission to facilitate registration of Primergy under the Public Utility Holding Company Act of 1935, as amended. On April 10, 1996, the Michigan Public Service Commission approved the merger application, through a settlement agreement containing terms consistent with the merger application. This is the first of four states to act where approval of the merger is required. The merger filings with each state included a request for deferred accounting treatment and rate recovery of costs incurred associated with the proposed merger. At March 31, 1996, $16.3 million of costs associated with the proposed merger and incurred by NSP had been deferred as a component of Intangible Assets and Other. 3. Business Developments Non-regulated Acquisitions - On April 30, 1996, NSP's wholly owned non-regulated subsidiary, NRG Energy, Inc. (NRG), closed its acquisition of a 41.86-percent interest in O'Brien Environmental Energy, Inc. (O'Brien) from bankruptcy. O'Brien has been renamed NRG Generating (U.S.) Inc., and the former shareholders of O'Brien own the remaining 58.14 percent of NRG Generating, which will be publicly traded. As a result of the purchase, approximately $107.3 million was made available to O'Brien and its creditors by NRG consisting of the following: (i) a $30.8 million equity investment by NRG for its 41.86 percent interest in O'Brien; (ii) a $7.5 million investment by NEO Corporation, a wholly owned subsidiary of NRG, for all of O'Brien's interest in certain biogas projects; and (iii) loans totaling $69 million from NRG to O'Brien. Approximately $87 million of these investments in and loans to O'Brien were reflected as Special Deposits - Non-regulated Projects in current assets on the consolidated balance sheet at March 31, 1996. In connection with the closing on its O'Brien acquisition, NRG was released from its $100 million letter of credit obtained in January 1996 to secure its obligation to complete its proposed investment in O'Brien. O'Brien has interests in eight domestic operating power generation facilities with aggregate capacity of approximately 230 megawatts, and in one 150-megawatt facility in the contract stage of development. 4. Commitments and Contingent Liabilities Nuclear Insurance - The circumstances set forth in Note 15 to NSP's financial statements contained in the 1995 Form 10-K appropriately represent the current status of commitments and contingent liabilities regarding public liability for claims resulting from any nuclear incident. Item 2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION On April 28, 1995, the Company and WEC entered into an Agreement and Plan of Merger which provides for a strategic business combination involving the two companies in a "merger- of-equals" transaction. Further information concerning this agreement and proposed transaction and pro forma financial information with respect thereto is included in the 1995 Form 10-K and Part II of this report. The following discussion and analysis is based on the financial condition and operations of NSP and does not reflect the potential effects of its combination with WEC. The following discussion and analysis contains forward- looking statements. When used in this document, the words "anticipate", "estimate", "expect", "objective" and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks, uncertainties and assumptions, including those that are described in Exhibit 99.01 to this report. Results of Operations Northern States Power Company's earnings per share for the first quarter ended March 31, 1996, were $.94, down $.03 from the $.97 earned for the same period a year ago. In addition to items noted in the 1995 Form 10-K, the historical and future trends of NSP's operating results have been and are expected to be affected by the following factors: Non-regulated Business Results - Quarterly results include earnings contributions from non-regulated businesses of $0.04 per share in 1996 and $0.13 per share in 1995. The following summarizes the earnings contributions of NSP's non-regulated businesses: 3 Mos. Ended 3/31/96 3/31/95 NRG $0.04 $0.11 Eloigne Company 0.01 0.01 Cenerprise, Inc. (Cenerprise) (0.03) 0.00 Other 0.02 0.01 Total $0.04 $0.13 Due to the nature of these non-regulated businesses, NSP anticipates that the earnings from non-regulated operations will experience more variability than regulated utility businesses. As discussed below, NSP's non-regulated earnings in the three- month period ended March 31, 1996 are experiencing such variability. NRG - NRG's first quarter earnings were down from a year ago due to a combination of higher business development expenses, which increased overall operating expenses, and lower equity in earnings of projects. NRG experienced an increased level of business development costs in late 1995 and early in 1996 as it pursued several significant international and domestic projects. Until there is substantial assurance that a project in development will come to financial closure, such costs are expensed. Equity in earnings of projects decreased in 1996, as lower equity in earnings from the MIBRAG and Gladstone projects were only partially offset by higher earnings from Schkopau. Equity in earnings from MIBRAG decreased due to an expected decline in heating briquette and coal sales, while Gladstone incurred higher labor costs. Partially offsetting these decreases, one unit of the Schkopau power generation facility began commercial operation in March 1996, with the second unit scheduled to come on line later in 1996. Cenerprise - Cenerprise's first quarter earnings were down due largely to unusually high gas costs incurred to meet customer demand requirements, and to losses incurred from gas trading activities. With the extremely cold weather experienced throughout the U.S. in the first quarter of 1996, several of Cenerprise's gas suppliers and transporters curtailed product availability. Other, more expensive sources of spot gas supply were needed to meet sales commitments to Cenerprise's customers. Cenerprise is investigating legal action against suppliers who may not have met their contractual obligations to supply gas. Also, Cenerprise has curtailed its gas trading activities and will trade only to support its end-use customer sales in the future. Estimated Impact of Weather on Regulated Earnings - NSP estimates sales levels under normal weather conditions and analyzes the approximate effect of variations from historical average temperatures on actual sales levels. The following summarizes the estimated impact of weather on actual utility operating results (in relation to sales under normal weather conditions): Increase (Decrease) Actual Actual Actual 1996 vs Normal 1995 vs Normal 1996 vs 1995 Earnings per Share for Quarter Ended March 31 $0.09 ($0.06) $0.15 The estimated impact of weather on the first quarter of 1996 considers only the impacts of variations from average temperatures, including the extremely cold temperatures in late January and early February of 1996. Although such cold weather in this period would be expected to result in increased energy sales, an ice storm immediately preceding the cold weather resulted in as many as 200,000 customers being temporarily out of service, and bitterly cold temperatures resulted in some customers shutting down or curtailing their operations. Because these secondary weather impacts are not reliably quantifiable, their expected effects (an offset to the energy sales increase from cold weather) have not been included in the estimated impact of weather on 1996 operating results. Competition - On April 24, 1996, the Federal Energy Regulatory Commission (FERC) issued two final rules regarding an earlier proposal (called the "Mega-NOPR") for electric utilities to offer open access transmission service to wholesale transmission users. The ruling, which will take effect later this year, requires utilities and other transmission users to abide by the same terms and conditions in transmitting power and is intended to promote competition. A new proposed rule, Capacity Reservation Open Access Transmission Tariffs, was also issued. While NSP is still reviewing the provisions of these new rules and is unable at this time to precisely determine their impact on future operations, NSP continues to be generally supportive of the FERC's efforts to increase competition. First Quarter 1996 Compared with First Quarter 1995 Utility Operating Results Electric revenues for the first quarter 1996 compared with the first quarter 1995 increased $15.6 million or 3.1%. Retail revenues increased approximately $31.9 million or 7.0% largely due to a 4.1% increase in retail electric sales. The increase in retail electric sales is due to colder-than-normal weather (as discussed above) and sales growth. In addition, retail prices increased 2.8% primarily due to increased recovery of deferred conservation and energy management costs and fuel expense recovery (as discussed below). Wholesale revenues were impacted by the effects of expected contract terminations for seven municipal customers in July 1995, resulting in a $5.4 million decrease. Revenues from sales to other utilities decreased by $11.0 million mainly due to decreases in sales volume. This decrease in sales to other utilities reflects higher retail sales requirements and less plant availability due to more major planned outages in 1996 (as discussed below). Gas revenues for the first quarter 1996 increased $41.9 million or 25.6% compared with the first quarter of 1995. Gas revenues increased due to a 18.8% increase in gas sales volume and a 6.3% average price increase. The sales volume increase is due primarily to weather impacts (as discussed previously) and firm sales growth. The price increase is mainly due to rate adjustments for increased purchased gas costs resulting from changes in natural gas market conditions. Fuel for electric generation and Purchased and interchange power combined for a net increase of $3.2 million or 2.4% for the first quarter of 1996 compared with the first quarter of 1995. Purchased and interchange power increased $10.5 million due primarily to higher cost of purchases, reflecting market conditions and higher purchases due to less plant availability (as discussed previously). The increased purchased power cost was partially offset by lower fuel expense of $7.2 million mainly due to less nuclear output in 1996 because of a planned nuclear maintenance outage, and lower average fossil fuel cost due to a new coal transportation contract in July 1995. Cost of gas purchased and transported for first quarter 1996 compared with first quarter 1995 increased $34.1 million or 34.3% due to higher gas sendout and higher per unit cost of purchased gas. The higher gas sendout reflects increased gas sales, while the higher cost of purchased gas reflects changes in market conditions and gas cost adjustments. (See Note 1 to the Financial Statements for discussion of the accounting change for Wisconsin gas costs to more accurately match cost recovery in revenues.) Other operation, Maintenance and Administrative and general expenses together increased $5.5 million or 3.4% compared with the first quarter 1995. The higher costs are largely due to the timing of scheduled plant maintenance outages and an ice storm, partially offset by lower administrative and general costs. Planned maintenance outages occurred at two major plants in the first quarter of 1996 compared with only one major plant in the first quarter of 1995. Of the $14.3 million increase in Other operation and Maintenance expenses, $9.5 million is due to additional costs related to the timing of planned outages at generating plants. Due to an ice storm in late January 1996, an additional $2 million in maintenance costs were incurred to bring customers back into service and to repair other damage to NSP's transmission and distribution system. Conservation and energy management increased $8.4 million in the three-month period ended March 31, 1996 compared to the same period in the prior year due to higher amortization levels and concurrent rate recovery of deferred electric and gas conservation and energy management program costs. These higher amortization levels are consistent with new retail electric and gas rate adjustment clauses in the Company's Minnesota jurisdiction effective May 1, 1995, and Nov. 1, 1995, respectively. Higher amortization levels reflect higher costs incurred due to increased participation in NSP's conservation and energy management programs. Depreciation and amortization increased $2.8 million or 3.9% compared with the first quarter of 1995. The increase is mainly due to increased plant in service between the two periods. Property and general taxes for the first quarter 1996 compared with the first quarter of 1995 decreased $2.2 million or 3.5% due primarily to property tax adjustments for 1995 which are payable in 1996. Utility income taxes for first quarter 1996 compared with first quarter 1995 increased $4.1 million primarily due to higher pretax operating income (after interest charges) between the two periods. Other income (deductions) - net decreased mainly due to non-regulated items discussed below. Allowance for funds used during construction (AFC) increased $2.2 million to $5.4 million in 1996 largely due to returns allowed on higher conservation and energy management expenditures. Non-regulated Business Results NSP's non-regulated operations include many diversified businesses, such as independent power production, gas marketing, industrial heating and cooling, and energy-related refuse- derived fuel production. NSP also has investments in affordable housing projects and several income-producing properties. The following discusses NSP's diversified business results in the aggregate. Operating Revenues and Expenses - The net results of non- regulated businesses are reported in Other Income (Deductions)- Net on the Consolidated Statements of Income. Non-regulated operating revenues increased $38.7 million in 1996, to $121.3 million, largely due to increased gas marketing sales by Cenerprise. Non-regulated operating expenses increased $46.7 million in 1996 to $127.7 million due to higher gas costs corresponding with Cenerprise gas sales and increased NRG project development costs being expensed on potential projects in 1996, as discussed previously. Equity Income - NSP has a less-than-majority equity interest in many non-regulated projects. Consequently, a large portion of NSP's non-regulated earnings is reported as Equity in Earnings of Unconsolidated Affiliates on the Consolidated Statements of Income. Equity income decreased in the first quarter of 1996 by $2.8 million primarily due to NRG energy projects in Australia and Germany as discussed previously, and to lower earnings from a domestic NRG cogeneration project whose contracts were effectively terminated in late February 1995. Non-regulated interest and amortization increased $1.8 million to $4.1 million due to the issuance of $125 million of long term debt by NRG in January 1996 and issuance of debt for Eloigne Company projects. Income Taxes - Income Taxes on Non-regulated Operations and Non-operating Items reported on the Consolidated Statements of Income includes income taxes related to non-regulated businesses. Such income taxes for the first quarter of 1996 were a net benefit of $5.0 million, a $5.0 million decrease over a net tax expense of $0 in the first quarter of 1995. The decrease in 1996 is due mainly to lower income from NRG and Cenerprise, as discussed previously, and to higher income tax credits from Eloigne Company's affordable housing projects. NSP's management intends to reinvest the earnings of international operations indefinitely. Accordingly, U.S. income taxes and foreign withholding taxes have not been provided on the earnings of international projects. Liquidity and Capital Resources The Company had approximately $168 million in commercial paper debt outstanding as of March 31, 1996. The Company plans to keep credit lines of at least 85% of the highest anticipated level of commercial paper borrowings. Commercial banks currently provide credit lines of approximately $306 million to the Company. These credit lines make short-term financing available in the form of bank loans and support for commercial paper sales. The Company has regulatory approval for up to $445 million in short-term borrowing levels. Commercial banks currently provide credit lines of $17 million to wholly owned subsidiaries of the Company. However, $5.4 million in letters of credit were outstanding, which reduced the available credit lines at March 31, 1996. Approximately $11.6 million of those credit lines remained available at March 31, 1996. In January 1996, stock options for the purchase of 263,039 shares were awarded under the Company's Executive Long-Term Incentive Award Stock Plan (the Plan). These options are not exercisable for approximately twelve months after the award date. As of March 31, 1996, a total of 1,149,326 stock options were outstanding, which were considered as potential common stock equivalents for earnings per share purposes. During the first three months of 1996, the Company has issued 103,348 new shares of common stock under the Plan pursuant to the exercise of options and awards granted in prior years. Under NSP's Dividend Reinvestment and Stock Purchase Plan, the Company has issued 161,025 shares of common stock during the first three months of 1996. During 1996, the Company has issued an additional 59,621 shares of new common stock to the Employee Stock Ownership Plan for dividends on Company shares held. On January 29, 1996, NRG issued $125 million of 7.625 percent unsecured Senior Notes maturing in 2006 to support equity requirements for projects currently under way and in development. The Senior Notes were assigned ratings of BBB- by Standard & Poor's Rating Group and Baa3 by Moody's Investors Services. See discussion of NRG's recent project developments at Note 3 to the Financial Statements. The Wisconsin Company registered $65 million of first mortgage bonds with the Securities and Exchange Commission in May 1996. Depending on capital market conditions, the Wisconsin Company may issue all or a portion of this debt in 1996, for purchase or redemption of one or more series of outstanding first mortgage bonds and repayment of outstanding short-term borrowings incurred in connection with the Wisconsin Company's continuing construction program. The remainder of the proceeds would be added to the general funds of the Wisconsin Company. Part II. OTHER INFORMATION Item 1. Legal Proceedings As discussed in the Environmental Contingencies section of Note 15 to the Company's financial statements in the 1995 Form 10-K, the Environmental Protection Agency or state environmental agencies have designated the Company as a "potentially responsible party" (PRP) at several waste disposal sites to which the Company allegedly sent hazardous materials. In March 1996, the federal government filed suit in U.S. District Court in Minneapolis seeking to collect at least $1.5 million that federal agencies have spent investigating and cleaning up a Brooklyn Park site. The Company is among a group of five parties designated as a PRP in the suit. The Company has recorded an estimate of its potential liability for the clean up of this site. In April 1996, the Company received a General Notice Letter from the United States Environmental Protection Agency regarding the Third Site Superfund Site in Zionsville, Indiana. The letter alleges the Company is a PRP at the site. The Company is among over 500 parties designated as a PRP. Management anticipates that it is likely the Company will be considered de minimis and qualify for a cash-out payment. The payment is not expected to be material. Item 4. Submission of Matters to a Vote of Security Holders The Annual Meeting of Shareholders of the Company was held on April 24, 1996, for the purpose of voting on the matters listed below. Proxies for the meeting were solicited pursuant to Section 14(a) of the Securities Exchange Act of 1934, as amended, and there was no solicitation in opposition to management's solicitations. All of management's nominees for directors as listed in the proxy statement were elected. The matters before the meeting and the voting results were as follows: 1. A proposal to elect four directors to Class I to serve until the 1999 Annual Meeting of Shareholders and until their successors are elected and have qualified; Election Shares of Directors Voted For Withheld Authority W. John Driscoll 58,930,004 1,902,677 Dale L. Haakenstad 58,892,682 1,939,999 John E. Pearson 58,918,233 1,914,448 James J. Howard 58,762,373 2,070,307 2. A proposal to elect a director to Class II to serve until the 1997 Annual Meeting of Shareholders and until a successor is elected and has qualified; Election Shares of Directors Voted For Withheld Authority G. M. Pieschel 58,973,759 1,858,922 3. A proposal to ratify the appointment of Price Waterhouse LLP as independent accountants for NSP for 1996; Shares Voted For Voted Against Voted Abstain 59,853,138 488,236 491,307 4. A "Shareholder Resolution on Public Image" Shares Voted For Voted Against Voted Abstain 4,901,693 44,931,572 2,674,868 The number of broker non-votes on the Shareholder Resolution was 8,324,547. Item 5. Other Information MERGER AGREEMENT WITH WISCONSIN ENERGY CORPORATION As previously reported in the Company's Current Report on Form 8-K, dated April 28, 1995 and filed on May 3, 1995, and the 1995 Form 10-K, NSP; WEC; Northern Power Wisconsin Corp., a wholly owned subsidiary of NSP (New NSP); and WEC Sub Corp., a Wisconsin corporation and a wholly owned subsidiary of WEC (WEC Sub) have entered into an Agreement and Plan of Merger (the "Merger Agreement"), which provides for a strategic business combination involving NSP and WEC in a "merger-of-equals" transaction (the Merger Transaction). The Merger Transaction, which was approved by the shareholders of the constituent companies at meetings held on September 13, 1995, is expected to close shortly after all of the conditions to the consummation of the Merger Transaction, including obtaining applicable regu- latory approvals, are met or waived. Although the goal of NSP and WEC is to receive approvals from the regulatory authorities by the end of 1996, some regulatory authorities have not established a timetable for their decision. Therefore, it is possible that the approvals necessary to consummate the merger may not be obtainable until after 1996. In the Merger Transaction, as the holding company of the combined enterprise, Primergy will be registered under the Public Utility Holding Company Act of 1935, as amended and will be the parent company of the operations of both NSP (which, for regulatory reasons, will reincorporate in Wisconsin) and of WEC's present principal utility subsidiary, Wisconsin Electric Power Company (WEPCO) which will be renamed "Wisconsin Energy Company." It is anticipated that, following the Merger Transaction, the Wisconsin Company will be merged into Wisconsin Energy Company and that NSP's other subsidiaries will become subsidiaries of Primergy. As noted above, pursuant to the Merger Transaction, NSP will reincorporate in Wisconsin for regulatory reasons. This reincorporation will be accomplished by the merger of NSP into New NSP, with New NSP being the surviving corporation and succeeding to the business of NSP as an operating public utility. Following such merger, WEC Sub will be merged with and into New NSP, with New NSP being the surviving corporation and becoming a subsidiary of Primergy. Both New NSP and WEC Sub were created to effect the Merger Transaction and will not have any significant operations, assets or liabilities prior to such mergers. Under the proposed business combination, current common stockholders of NSP would receive 1.626 shares of Primergy common stock for each share of NSP common stock owned, and current bondholders and preferred stockholders of NSP will become investors in New NSP. SUMMARIZED PRO FORMA FINANCIAL INFORMATION (UNAUDITED) The following summary of unaudited pro forma financial information reflects the adjustment of the historical consolidated balance sheets and statements of income of NSP and WEC to give effect to the Merger Transaction to form Primergy and a new subsidiary structure. The unaudited pro forma balance sheet information gives effect to the Merger Transaction as if it had occurred on that date. The unaudited pro forma income statement information gives effect to the Merger Transaction as if it had occurred at the beginning of the period presented. This pro forma information was prepared from the historical consolidated financial statements of NSP and WEC on the basis of accounting for the Merger Transaction as a pooling of interests and should be read in conjunction with such historical consolidated financial statements and related notes thereto of NSP and WEC. The allocation between NSP and WEC and their customers of the estimated cost savings, resulting from the Merger Transaction, net of the costs incurred to achieve such savings, will be subject to regulatory review and approval. None of the estimated cost savings, the costs to achieve such savings or the transaction costs have been reflected in the summarized pro forma financial information. A $143 million pro forma adjustment has been made to conform the presentations of noncurrent deferred income taxes in the summarized pro forma combined balance sheet information as a net liability. The pro forma combined earnings per common share reflect pro forma adjustments to average common shares outstanding in accordance with the stock conversion provisions of the Merger Agreement. The following information is not necessarily indicative of the financial position or operating results that would have occurred had the Merger Transaction been consummated on the date, or at the beginning of the periods, for which the Merger Transaction is being given effect nor is it necessarily indicative of future operating results or financial position. The summarized Primergy pro forma financial information reflects the combination of the historical financial statements of NSP and WEC after giving effect to the Merger Transaction to form Primergy. The summarized New NSP pro forma financial information reflects the adjustment of the historical financial statements of NSP to give effect to the Merger Transaction, including the reincorporation of NSP in Wisconsin, the merger of the Wisconsin Company into Wisconsin Energy Company, and the transfer of ownership of all of the current NSP subsidiaries to Primergy. Pro Forma PRIMERGY CORP: NSP WEC Combined (in millions, except per share amounts) As of March 31, 1996: Utility Plant-Net $4,321 $2,907 $7,228 Current Assets 838 502 1,340 Other Assets 1,222 1,129 2,208 Total Assets $6,381 $4,538 $10,776 Common Stockholders' Equity $2,066 $1,893 $3,959 Preferred Stockholders' Equity 241 30 271 Long-Term Debt 1,668 1,356 3,024 Total Capitalization 3,975 3,279 7,254 Current Liabilities 998 400 1,398 Other Liabilities 1,408 859 2,124 Total Equity & Liabilities $6,381 $4,538 $10,776 For the Three Months Ended March 31, 1996: Utility Operating Revenues $719 $495 $1,214 Utility Operating Income $89 $85 $174 Net Income, after Preferred Dividend Requirements $64 $63 $127 Earnings per Common Share: As reported $.94 $.57 -- NSP Equivalent Shares -- -- $.93 Primergy Shares -- -- $.57 Merger Divestitures Pro Forma NEW NSP: NSP Net New NSP (in millions) As of March 31, 1996: Utility Plant-Net $4,321 ($695) $3,626 Current Assets 838 (295) 543 Other Assets 1,222 (527) 695 Total Assets $6,381 ($1,517) $4,864 Common Stockholder's Equity $2,066 ($722) $1,344 Preferred Stockholder's Equity 241 -- 241 Long-Term Debt 1,668 (482) 1,186 Total Capitalization 3,975 (1,204) 2,771 Current Liabilities 998 (134) 864 Other Liabilities 1,408 (179) 1,229 Total Equity & Liabilities $6,381 ($1,517) $4,864 For the Three Months Ended March 31, 1996: Utility Operating Revenues $719 ($72) $647 Utility Operating Income $89 ($19) $70 Net Income, after Preferred Dividend Requirements $64 ($15) $49 Item 6. Exhibits and Reports on Form 8-K (a) Exhibits The following Exhibits are filed with this report: 10.01 Mid-continent Area Power Pool (MAPP) Agreement, dated March 31, 1972, with amendments in 1994 and 1996, between the local power suppliers in the North Central States area. 27.01 Financial Data Schedule for the three months ended March 31, 1996. 99.01 Statement pursuant to Private Securities Litigation Reform Act of 1995. (b) Reports on Form 8-K The following reports on Form 8-K were filed either during the three months ended March 31, 1996, or between March 31, 1996 and the date of this report: January 18, 1996 (Filed January 18, 1996) - Item 5. Other Events. Release of 1995 financial results of NRG Energy, Inc., a wholly owned subsidiary of the Company. March 1, 1996 (Filed March 1, 1996)- Item 5. Other Events. Disclosure of new reporting category for the Company's electric commercial and industrial customers, and electric and gas operating statistics for 1995. April 16, 1996 (Filed April 18, 1996) - Item 5. Other Events. Disclosure of suspension of negotiations with the Mescalero Apache Tribe (the Tribe) by a consortium of utilities, including the Company, for interim storage of used nuclear fuel on the Tribe's reservation in New Mexico. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. NORTHERN STATES POWER COMPANY (Registrant) (Roger D. Sandeen) Roger D. Sandeen Vice President, Controller and Chief Information Officer (Edward J. McIntyre) Edward J. McIntyre Vice President and Chief Financial Officer Date: May 15, 1996 EXHIBIT INDEX Method of Exhibit Filing No. Description DT 10.01 Mid-continent Area Power Pool (MAPP) Agreement with amendments DT 27.01 Financial Data Schedule DT 99.01 Statement pursuant to Private Securities Litigation Reform Act of 1995 DT = Filed electronically with this direct transmission. EX-10 2 MID-CONTINENT AREA POWER POOL AGREEMENT AS AMENDED EXHIBIT 10.01 MID-CONTINENT AREA POWER POOL AGREEMENT PREAMBLE THIS AGREEMENT, made and entered into as of the 31st day of MARCH, 1972, by and between the signatories hereto, herein referred to individually as a "Party" or collectively as "Parties" and with the Parties further herein referred to as "Participants" and "Associate Participants" as defined in Article IV, as amended thereafter including additional signatories since 1972. WITNESSETH 0.01 WHEREAS the Parties are engaged in the electric utility business; and 0.02 WHEREAS the systems of the Parties are interconnected by transmission facilities and are operated in synchronism pursuant to a number of power pooling interconnection agreements; and 0.03 WHEREAS an extensive network of high voltage transmission facilities has been developed by the interconnection of such transmission facilities between the systems of the Parties; and 0.04 WHEREAS the Parties desire to continue to participate in a regional power pool coextensive with such interconnected transmission facilities to further enhance the reliability and other benefits of interconnected operations and to provide further opportunities to coordinate the installation and operation of generation and transmission facilities on the respective systems of the Parties; and 0.05 WHEREAS all the present Parties that were signatory to the Mid-Continent Area Reliability Coordination Agreement (MARCA) are also Participants of the Mid-Continent Area Power Pool; and 0.06 WHEREAS the Parties that are members of MARCA have dissolved that Agreement and have included the necessary functions from MARCA in the Mid-Continent Area Power Pool Agreement; NOW, THEREFORE, the Parties agree to enter into this Agreement for the operation of the Mid-Continent Area Power Pool, hereinafter call "MAPP," in accordance herewith. ARTICLE I OBJECTIVES 1.01 The objective of this Agreement is to provide reliable and economical electric service to the customers of each of the Parties consistent with reasonable utilization of natural resources and effect on the environment. In order to accomplish such purposes, the Parties shall endeavor to coordinate the installation and operation of generation and transmission facilities. However, each Party has the right and obligation, regardless of size or type of organization, to own or otherwise provide the facilities required to provide its electric service requirements. Each and all of the provisions of this Agreement are considered reasonably necessary in order to furnish a basis for the Parties reaching an agreement to accomplish these objectives. ARTICLE II TERM OF AGREEMENT 2.01 This Agreement shall become effective on the first of the month next following sixty (60) days after acceptance for filing of this Agreement by the Federal Energy Regulatory Commission and shall not become effective if such acceptance is not received within 180 days of the execution of this Agreement. 2.02 This Agreement and amendments thereto shall be of no force or effect for a Participant which is a borrower from the Rural Electrification Administration and which requires Rural Electrification Administration approval thereof unless such approval is obtained within 180 days of the date of execution thereof by such borrower. 2.03 Any Participant may terminate its participation in this Agreement by four years written notice to the other Parties hereto. Any Associate Participant may terminate its participation in this Agreement by ninety (90) days written notice to the other Parties hereto. 2.04 In the event a Participant fails to perform its obligations pursuant to this Agreement, the Management Committee shall give written notice to such Participant specifying such failure to perform and establishing such reasonable period as such Participant shall have to fulfill its obligations pursuant to this Agreement. In accordance with such notice, the Management Committee shall review the performance of such Participant and if the failure to perform its obligation is continuing, the Management Committee may thereupon terminate such Participant's participation. This provision shall not limit the right of any other Participant to enforce the rights and obligations established pursuant to this Agreement. 2.05 If any of the transmission facilities of a terminating Participant are required for the continuing stability and reliability of the interconnected systems of the remaining Participants, such terminating Participant as to the affected facilities shall continue to be subject to the requirements relating to stability and reliability which are in effect at the time of termination. This obligation shall continue only for as long as the affected facilities continue to be interconnected, directly or indirectly, with the system of any continuing Participant, but for no longer a period than the remaining Participants may reasonably and with due diligence require to permit the establishment of alternative arrangements for stability and reliability, but for no longer than four years from the date of notice issued pursuant to Paragraph 2.03 or from the date of termination by the Management Committee pursuant to Paragraph 2.04. 2.06 Any Participant terminated as provided in Paragraph 2.04 shall continue to fulfill its obligations pursuant to any power transaction under the Service Schedules until the completion of such power transaction. 2.07 Any terminated or terminating Participant will continue, or enter into, an agreement contemplated by Article XV on such terms and conditions and for such annual payment as shall be established between the Management Committee and the Contractor. The annual payment shall be such share of the total payment for services provided by the Contractor reasonably related to the continuing obligation of the terminated or terminating Participant and shall include for a period not exceeding ten (10) years any unsatisfied portion of any payment measured by investment in facilities or equipment committed by such Contractor to provide services from the Coordination Center when such commitment was made and the measure of payment established between the Management Committee and the Contractor prior to notice of default or termination. ARTICLE III DEFINITIONS For the purposes of this Agreement and of the Service Schedules which are a part hereof, the following definitions shall apply: 3.01 Firm Energy shall mean energy intended to be supplied at all times. 3.02 System Demand of a Party shall mean that number of kilowatts which is equal to the kilowatt-hours required in any clock hour, attributable to energy required by such Party during such hour for supply of Firm Energy to the Party's consumers, including system losses, and also including any transmission losses occurring on other systems supplied by such party for transmission of such Firm Energy, but excluding generating station uses, excluding transmission losses supplied by another system, and excluding Interruptible Load Replacement Energy as provided for in Service Schedule "L." 3.03 Annual System Demand of a Party shall mean the highest System Demand of such Party occurring during the 12-month period ending with the current month. 3.04 Certified Interruptible Demand shall mean the quantity of kilowatts which is equal to the kilowatt-hours in any clock hour that can be removed from a Party's system under control of the Party. Such quantities shall be certified by the Party to the Engineering Committee for each month according to requirements the Engineering Committee may establish. 3.05 Net Generating Capability of a Participant for any month shall mean that amount of kilowatts, less station use, that all the generating facilities of such Participant could normally supply simultaneously to its system and the interconnected systems of the Participants at the time of such Participant's maximum System Demand for such month under such conditions as may be established by the Engineering Committee. The capability of the generating units of a Participant which are temporarily out of service for maintenance or repair shall be included in the Net Generating Capability of such Participant. 3.06 Accredited Capability of a Participant for any month shall mean (a) the Net Generating Capability of such Participant, plus (b) the value in kilowatts assigned to such Participant's purchases under Service Schedules "A," "B," "H," "I," "J," and "K," hereof, and to commitments for power from electric suppliers under separate contracts now existing or hereafter created, and minus (c) the value in kilowatts assigned to any commitment of such Participant to deliver power to another Participant under Service Schedules "A," "B," "H," "I," "J," and "K," hereof, or to any electric supplier or suppliers pursuant to any valid order or under separate contract or contracts now existing or hereafter created. The Accredited Capability of such Participant will be determined and assigned by the Engineering Committee in accordance with the provisions of Paragraph 16.03 hereof. 3.07 Available Accredited Capability of a Participant shall mean its Accredited Capability adjusted for generating capacity out of service for maintenance or repair. 3.08 Reserve Capacity of a Participant for any month shall mean the excess in kilowatts of each Participant's Accredited Capability above such Participant's maximum System Demand for such month. 3.09 Reserve Capacity Obligation of a Participant shall be the capacity which that Participant is obligated to reserve and use for the purpose of maintaining continuity of service. 3.10 Spinning Reserve shall mean the amount of unloaded generating capability of a Participant connected to and synchronized with the interconnected system of the Participants and ready to take load. Spinning Reserve allocation to any generator shall not exceed the amount of generation increase that can be realized in ten (10) minutes. 3.11 Non-Spinning Reserve shall mean all unloaded generating capability not meeting the Spinning Reserve criteria (Paragraph 3.10) that can be made fully effective in ten (10) minutes. 3.12 Operating Reserve shall mean the sum of Spinning and Non-Spinning Reserve. 3.13 Operating Reserve Obligation shall mean that amount of Spinning Reserve and Non-Spinning Reserve which a Participant is obligated under the terms of this Agreement to provide for the purpose of maintaining continuity of service. 3.14 Total Operating Reserve Obligation shall be that amount of Spinning Reserve and Non-Spinning Reserve of the Participants collectively required to maintain continuity of service. 3.15 An Emergency Outage shall mean any unanticipated, unscheduled outage of generating or transmission facilities; however, such outage classification shall not exceed a period of six hours. 3.16 A Scheduled Outage shall mean any outage of generating or transmission facilities which is scheduled in advance for maintenance and shall include the remainder of an Emergency Outage which is rescheduled as a Scheduled Outage. Such rescheduling shall be required within six hours of the initiation of the Emergency Outage. 3.17 Participation Power shall mean power and associated energy which is sold or purchased by Participants as provided for in Service Schedule "A." 3.18 Seasonal Participation Power shall mean power and associated energy which is sold or purchased by Participants as provided for in Service Schedule "B." 3.19 System Participation Power shall mean power and associated energy which is sold or purchased by Participants as provided for in Service Schedule "K." 3.20 Peaking Power shall mean power and associated energy which is sold or purchased by Participants as provided for in Service Schedule "H." 3.21 Short Term Power shall mean power and associated energy which is sold or purchased by the Participants and intended to be available at all times during the period covered by the commitment as provided for in Service Schedule "I." 3.22 Emergency Energy shall mean energy which is supplied under Service Schedule "C" of this Agreement by any Participant to any other Participant during and as required by an Emergency Outage on such other Participant's system which is not supplied under another provision of this Agreement. 3.23 Scheduled Outage Energy shall mean energy which is supplied under Service Schedule "C" of this Agreement by any Participant to any other Participant as a result of a Scheduled Outage which is not supplied under another provision of this Agreement. 3.24 Economy Energy shall mean energy which one Participant may deliver under Service Schedule "E" to another Participant for the purpose of replacing more expensive energy. 3.25 Interruptible Load Replacement Energy shall mean energy which is supplied under Service Schedule "L" of this Agreement by any Participant to another Participant for the purpose of serving interruptible load. 3.26 Operational Control Energy shall mean energy which is sold or purchased by the Participants to improve electric system control and reliability as provided for in Service Schedule "G." 3.27 General Purpose Energy shall mean energy which is supplied under Service Schedule "M" by any Participant to any other Participant to enhance economic system operation. 3.28 Average Production Cost per kilowatt-hour of a generating unit for a month shall be: a. The total cost of all fuel consumed by the unit in such month divided by the net kilowatt-hours produced by the unit in such month, plus b. An amount, established by the Operating Committee after annual review, which shall represent the average monthly production cost, other than fuel, of the unit, plus c. An amount, established by the Operating Committee, which shall represent the cost per kilowatt-hour of incremental losses on the supplying Participant's system and on any other system or systems of electric suppliers not Participants hereto incurred in delivering power and energy hereunder. 3.29 Incremental Cost of a supplying Participant to supply energy to another Participant shall be: a. The cost of the fuel, operating labor and maintenance required to generate the energy necessary to supply (1) the scheduled delivery to the receiving Participant's system, plus (2) the incremental losses incurred on the supplying Participant's system, plus (3) the energy supplied to any intervening system or systems as compensation for losses. b. The cost of starting and operating any generating units which must be started as a result of supplying such energy. c. The supplying Participant's cost of purchased energy if the purchase is made as a result of supplying such energy. The incremental cost per kilowatt-hour for any particular transaction shall be the total of such costs divided by the kilowatt-hours scheduled for delivery to the receiving Participant either directly by the supplying Participant or through an intervening system or systems. 3.30 Decremental Cost of a receiving Participant for avoiding the operation of generating facilities through the purchase of energy from another Participant shall be: a. The cost of the fuel, operating labor and maintenance which such Participant avoided using by means of such purchase. b. The cost of starting and operating of a generating unit or units which such Participant avoided by means of such purchase. The decremental cost per kilowatt-hour shall be the total of such costs divided by the number of kilowatt-hours scheduled for delivery to the receiving Participant either directly by the supplying Participant or through an intervening system or systems. 3.31 Latest Base Load Unit shall mean a single turbine generator unit declared by the Participant to be either its most recent wholly owned or leased and controlled capacity addition, or its most recent wholly owned or leased and controlled share of a jointly owned unit. 3.32 Transmission Service is the transfer of electricity by a Participant over its transmission system for another Participant, pursuant to Service Schedule "F." 3.33 Contractor shall be MAPPCOR, a Minnesota non-profit corporation, or other such entity as may be selected by the Management Committee pursuant to Paragraph 15.01 of this Agreement. 3.34 Coordination Transactions are transactions between electric utility systems for the purpose of achieving short-term cost savings, providing assistance in emergency situations, or coordinating operating procedures and maintenance schedules. 3.35 Control Area shall mean a system capable of regulating its generation in order to maintain its interchange schedule with other systems and contribute its frequency bias obligation to the interconnected system. A system shall qualify as a Control Area by meeting the criteria for control areas established by the North American Electric Reliability Council and by being recognized by the North American Electric Reliability Council as a control area. ARTICLE IV PARTICIPANTS AND ASSOCIATE PARTICIPANTS 4.01 Any entity engaged in the electric utility business: a. Which owns or leases and controls the operation of one or more generating units, and which regularly operates such unit or units to meet all or part of its system load; and b. Whose system is normally operated directly interconnected with one or more Participants at a voltage level and interconnection capacity so as to enable it to meet its obligations under this Agreement or enters into contractual arrangements to have its system so interconnected; and c. Which operates or participates in the operation of a twenty-four hour dispatch center with a terminal on the MAPP communication network connecting the Participants or enters into contractual arrangements for such service; and d. Which maintains during each month Accredited Capability in an amount equal to or greater than its maximum System Demand for such month plus Participant's Reserve Capacity Obligation as defined and determined pursuant to the terms of this Agreement; may become a Party to this Agreement as a Participant. 4.02 Electric utilities which meet the qualifications for Participant membership as set forth in Paragraph 4.01 but elect not to become a Participant and electric utilities which do not meet the qualifications for Participant membership as set forth in Paragraph 4.01 may execute this Agreement as Associate Participants and participate herein as set forth for Associate Participant. ARTICLE V PARTICIPATION IN NORTH-AMERICAN ELECTRIC RELIABILITY COUNCIL (NERC) 5.01 The North-American Electric Reliability Council which was incorporated on October 15, 1975, has nine member regions, one of which is MARCA. Each region is responsible to appoint two members to the NERC Board of Trustees and other representatives to Engineering and Operating Committees and working groups as established by the Board of Trustees. Since MARCA has been terminated and MAPP has assumed the reliability functions of MARCA, MAPP shall assume the previous MARCA membership in NERC and will participate in NERC activities as required to adequately represent the MAPP membership. Representatives to the NERC Board of Trustees and other NERC committees shall be appointed by the MAPP Management Committee. Expenses of those representatives while representing MAPP at NERC functions shall be reimbursed from funds provided by the MAPP Coordination Center and allocation procedure. ARTICLE VI RELATION TO OTHER AGREEMENTS AND OBLIGATIONS 6.01 Each Party represents that there are no conditions in such Party's existing agreements, including financing agreements, which will preclude such Party from performance of all obligations hereunder; and further, each Party agrees not to enter into an agreement which will preclude performance hereunder. The failure by any Party to get approval under any financing agreement for entering into a contract, or amending or terminating any existing agreement, shall not excuse performance hereunder. 6.02 The execution of this Agreement shall not impair, amend, or change any previous contracts or agreements and such contracts and agreements shall continue, including all rates, terms and conditions until the expiration of such contracts and agreements. ARTICLE VII COMMITTEE ORGANIZATION 7.01 The committee organization under this Agreement shall include a Management Committee, Executive Committee, Engineering Committee, Operating Committee, Design Review Committee, Environmental Committee, Area Relations Committee and such other committees as may be established by the Management Committee from time to time. 7.02 The expenses of each committee member shall be borne by the represented Party. 7.03 Committee expenses, other than those described in Paragraphs 5.01 and 7.02 shall be shared in a manner agreed to by the affected Parties. 7.04 Minutes of all committee meetings shall be recorded and copies thereof distributed in accordance with procedures established by the Management Committee. ARTICLE VIII MANAGEMENT COMMITTEE 8.01 The Management Committee shall consist of one representative selected by each Participant. Each Participant shall designate the person who shall act as its representative by written notice to the MAPP Secretary provided under Paragraph 8.04. By similar notice, a Participant may change its representative on the Management Committee and also designate an alternate representative to act in the absence of the designated representative. Each Associate Participant may designate, by written notice to the MAPP Secretary, a representative as a non- voting member of the Management Committee. 8.02 The Management Committee shall administer this Agreement to accomplish the objectives of MAPP. 8.03 The Management Committee shall hold an annual meeting during the last month of the fiscal year at such time and place as the Chairman shall designate and shall hold meetings at other times at the call of the Chairman or upon call of three or more Committee members. At least ten (10) days written notice shall be given to each member of the Management Committee of any meeting of such Committee. The notice shall state the time and place of the meeting and shall include an agenda of the items to be considered. Except by unanimous consent of those present, no action shall be taken on any item other than those included on the agenda. 8.04 The Management Committee, at its annual meeting, shall elect three officers who shall serve until the next annual meeting. They shall be a Chairman and a Vice Chairman elected from the representatives of the Participants on the Committee, also, a secretary, herein called "MAPP Secretary," who need not be a member of the Committee. The Chairman shall not serve for more than two consecutive terms. 8.05 The duties of the Management Committee include but are not limited to the following: a. Supervise the development of plans and procedures that will result in attainment of the objectives of this Agreement. b. Specify the duties and authority, other than set forth herein, of the Engineering Committee, the Operating Committee, the Design Review Committee, the Environmental Committee, the Area Relations Committee and other committees which may be established by the Management Committee. c. Make such administrative arrangements as may be required pertaining to matters which are pertinent to this Agreement but which are not specifically covered herein including the establishment of a fiscal year. d. Review and rule on appeals from Executive Committee decisions filed pursuant to the provisions of Paragraph 9.04. e. Review and rule on appeals from Engineering and Operating Committees as provided for in Paragraphs 10.08 and 11.06 respectively. f. Provide representation to the NERC Board of Trustees and participate in its functions. g. Review and approve an annual operating budget for the MAPP Coordination Center and Committee activities. h. Establish the Reserve Capacity Obligation of each Participant. i. Establish total Operating Reserve Obligation and formula for the Operating Reserve Obligation of each Participant. j. Review and approve recommendations of the Design Review Committee. 8.06 Each Participant on the Management Committee shall be entitled to the number of votes determined by the following formula: a. One vote for each 25 megawatts, or fraction thereof, of Annual System Demand up to 300 megawatts. b. One vote for each 50 megawatts, or fraction thereof, of Annual System Demand from 301 to 600 megawatts. c. One vote for each 100 megawatts, or fraction thereof, of Annual System Demand over 600 megawatts. A Participant's Annual System Demand shall be counted only once in determining voting allocation. 8.07 A majority affirmative vote of the total authorized votes is required to authorize any action, determination, or recommendation of the Management Committee. Any such action, determination, or recommendation of the Management Committee shall be binding on the Parties thirty (30) days after the vote thereon unless any Participant or Participants who vote against such action, determination, or recommendation invoke the arbitration provision set forth in Article XXX. ARTICLE IX EXECUTIVE COMMITTEE 9.01 The Executive Committee shall consist of not less than nine voting members including the Chairman and Vice Chairman of the Management Committee, a representative from the Western Area Power Administration, a representative of the MAPP Participant utility allocated the largest portion of the MAPP Annual Budget and a representative from each of any other MAPP Participant utilities allocated 20% or more of the MAPP Annual Budget, plus additional voting members elected by and from the Management Committee representatives. The other number of voting members of the Executive Committee shall be elected by and determined by the Management Committee. The Executive Committee shall be representative of the membership; factors to be considered are size and type of corporate organization and geographic area covered. Any state or province in which at least ten percent (10%) of the pool load is located shall be represented by not less than one Participant representative on the Executive Committee. The Chairman and Vice Chairman of the Management Committee shall also be the Chairman and Vice Chairman of the Executive Committee. The MAPP Secretary and a representative of the Contractor under Article XV shall be non- voting members of the Executive Committee. 9.02 Between meetings of the Management Committee, the Executive Committee shall have the duties of the Management Committee except those under Article XV and Paragraph 8.05 b, d, e, f, g, h, i and j, subject to appeal pursuant to the provisions of Paragraph 9.04. 9.03 The Executive Committee shall hold an annual meeting within six months after the annual meeting of the Management Committee at such time and place as the Chairman shall designate and shall hold other meetings in accordance with a schedule adopted by the Executive Committee or at the call of the Chairman or upon call of two or more members of the Executive Committee. At least ten (10) days written notice shall be given to each member of the Executive Committee of any meeting of such Committee. 9.04 An affirmative vote of two-thirds of the voting representatives on the Executive Committee is required to authorize any action, determination or recommendation of the Executive Committee. Any action, determination or recommendation adopted by the Executive Committee may be appealed to the Management Committee by one or more of the Participants; provided that, the sum of the Annual System Demands of such appealing Participant or Participants for the immediately preceding fiscal year is at least equal to one percent (1%) of the sum of the Annual System Demand of all Participants for such fiscal year. Such appeal shall be made by filing a notice of appeal with the MAPP Secretary within thirty (30) days after mailing of the written notice under Paragraph 9.05. The filing of a notice of appeal as aforesaid shall suspend such action, determination or recommendation pending action thereon by the Management Committee. 9.05 The MAPP Secretary shall send written notice to each member of the Management Committee of any action taken by the Executive Committee prior to the end of the fifth business day following the meeting of the Executive Committee at which such action was taken. ARTICLE X ENGINEERING COMMITTEE 10.01 The Engineering Committee shall consist of one representative of each Participant designated by such Participant's representative on the Management Committee by written notice to the MAPP Secretary. By similar notice, a Participant may change its Engineering Committee representative and also designate an alternate Engineering Committee representative to act in the absence of the designated representative. Each Associate Participant may designate, by written notice to the MAPP Secretary, a representative as a non- voting member of the Engineering Committee. 10.02 The Engineering Committee, under the direction of the Management Committee, shall administer the planning and design reliability functions for the bulk power supply pursuant to this Agreement. 10.03 The Engineering Committee shall hold an annual meeting in the first quarter of each year and shall hold other meetings at other times upon call of the Chairman or upon request of three or more Participant members. At least ten (10) days written notice shall be given to each member of the Engineering Committee of any meeting of such Committee. The notice shall state the time and place of the meeting and shall include an agenda of items to be considered. Except by unanimous consent of those present, no action shall be taken on any item other than those included on the agenda. 10.04 The Engineering Committee, at its annual meeting, shall elect two officers who shall serve until the next annual meeting. They shall be a Chairman and Vice Chairman elected from the representatives of the Participants on the Committee. The Chairman shall not serve for more than two consecutive terms. A person from the staff of the MAPP Coordination Center shall serve as its Secretary and shall be a non-voting member. 10.05 The duties of the Engineering Committee shall include, but shall not be limited to the following: a. Establish and revise as necessary, design reliability standards for the bulk power supply of MAPP, and coordinate such standards with regional power coordinating groups. b. Conduct periodic overall system reliability studies as required. c. Recommend revisions to the Reserve Capacity Obligation of the Participants as periodically required, to the Management Committee. d. Establish annually a plan for the ensuing ten (10) years or longer period covering: i. The size and type of the generating units to be installed, and the voltage and capacity of each transmission facility 115 Kv and above, where such facilities would have a significant effect upon MAPP area reliability, ii. The location of such facilities, iii. The time when such facilities are to be placed in operation, iv. The entity or entities installing such facilities, and v. The contracted purchases and sales by Participants. e. Review on a continuing basis, the load and capability forecasts which take into account conservation and load management plans of the Parties as reported by the MAPP Coordination Center and take the necessary action therewith in accordance with Article XVI. f. Coordinate the MAPP bulk power production and transmission system development with adjoining systems, pools and regional power coordinating groups. g. Establish and revise rules relating to the effect of abnormal conditions on System Demand and Reserve Capacity Obligation. h. Establish and revise rules for the determination of Accredited Capability of the Participants. i. Cause studies to be made as necessary for administration of its duties hereunder. j. Establish procedures for the use of Service Schedules, including the use of Service Schedule "F" for capacity transactions. k. Review and recommend changes to the Service Schedules to the Management Committee. l. Recommend to the Management Committee, representation to the NERC Engineering Committee and participate in its functions. m. Prepare and publish schedules of the Transmission Service schedule charges, in accordance with Service Schedule "F". 10.06 The Engineering Committee may establish subcommittees and assign duties consistent with this Agreement and policies of the Management Committee. 10.07 The Engineering Committee shall recommend to the Management Committee, planning functions which should be assigned to the MAPP Coordination Center to improve reliability and economy. Such recommendations shall be provided to the General Manager, MAPP Coordination Center to facilitate preparation of budget recommendations. 10.08 Any action of the Engineering Committee shall be taken only if seventy percent (70%) or more of the total authorized votes, as provided in the formula in Paragraph 8.06, are present at a meeting. Any action approved by at least ninety percent (90%) of the total authorized votes present shall become effective immediately. If less than a ninety percent (90%) vote, any action receiving an affirmative vote of at least two-thirds of the total authorized votes present shall become effective after thirty (30) days unless it is appealed to the Management Committee. Within five business days of any action receiving less than ninety percent (90%) vote by the Engineering Committee, the Committee Secretary shall give written notice thereof to the members of the Engineering Committee. Notice of any appeal therefrom shall be filed with the MAPP Secretary within ten (10) days of mailing of said notice of action. The submittal to the Management Committee shall include such alternative proposals as any Participant may request. ARTICLE XI OPERATING COMMITTEE 11.01 The Operating Committee shall consist of one representative of each Participant designated by such Participant's representative on the Management Committee by written notice to the MAPP Secretary. By similar notice, a Participant may change its Operating Committee representative and also designate an alternate representative to act in the absence of the designated representative. Each Associate Participant may designate, by written notice to the MAPP Secretary, a representative as a non-voting member of the Operating Committee. 11.02 The Operating Committee, under the direction of the Management Committee, shall be responsible for establishing such practices, rules and procedures as may be required to coordinate the operations and pool energy accounting of the bulk power generation and transmission facilities of the Parties pursuant to this Agreement. 11.03 The Operating Committee shall hold an annual meeting in the first quarter of each year and shall hold other meetings at others times upon call of the Chairman or upon request of three or more Participant members. At least ten (10) days written notice shall be given to each member of the Operating Committee of any meeting of such Committee. The notice shall state the time and place of the meeting and shall include an agenda of the items to be considered. Except by unanimous consent of those present, no action shall be taken on any item other than those included on the agenda. 11.04 The Operating Committee, at its annual meeting, shall elect two officers who shall serve until the next annual meeting. They shall be a Chairman and Vice Chairman elected from the representatives of the Participants on the Committee. The Chairman shall not serve for more than two consecutive terms. A person from the staff of the MAPP Coordination Center shall serve as its Secretary and shall be a non-voting member. 11.05 The duties of the Operating Committee shall include, but shall not be limited to the following: a. Coordinate the operation of the bulk power generation and transmission facilities of the Parties so as to effect optimum reliability and economy of service. b. Establish methods, standards, and procedures for the determination of costs associated with transactions hereunder. c. Periodically review the Total Operating Reserve Obligation and the formula for establishing the Operating Reserve Obligation of a Participant and make recommendations to the Management Committee for revisions as required. d. Collect and analyze operating data pertinent to the interconnected operation of the systems of the Participants and arrange for conducting such transmission network studies as may be necessary in the performance of its duties hereunder. e. Review and approve the coordinated maintenance schedules of the Participants as provided by the MAPP Coordination Center to assure at all times satisfying the Total Operating Reserve Obligation. f. Establish procedures for the use of the Service Schedules, including the use of Service Schedule "F" for energy transactions. g. Review and recommend changes to the Service Schedules to the Management Committee. h. Determine and periodically review the procedures to be followed by the Participants in restoring the Total Operating Reserve Obligation in the event of a large generator failure or other comparable contingency. i. Coordinate the periods and methods of reporting scheduled and actual power and energy flows. j. Establish methods and procedures for accounting and billing of bulk power and energy interchanges and Transmission Services hereunder. k. Establish operating reliability standards, criteria and rules relating to protective equipment, switching, voltage control, system control performance, load shedding, emergency and restoration procedures and the operation and maintenance of generation and transmission facilities of the Participants necessary to assure the reliable operation of the MAPP systems. l. Establish procedures and practices for coordinating the power pool operation activities of MAPP with adjoining systems, pools and other regional power coordination agencies. m. Recommend to the Management Committee representation to the NERC Operating Committee and participate in its functions. n. Recommend to the Management Committee the power pool operating functions which should be conducted at the MAPP Coordination Center to improve reliability and economy. Such recommendations shall be provided to the General Manager, MAPP Coordination Center to facilitate preparation of budget recommendations. 11.06 Any action of the Operating Committee shall be taken only if seventy percent (70%) or more of the total authorized votes, as provided in the formula in Paragraph 8.06, are present at a meeting. Any action approved by at least ninety percent (90%) of the total authorized votes present shall become effective immediately. If less than a ninety percent (90%) vote, any action receiving an affirmative vote of at least two-thirds of the total authorized votes present shall become effective after thirty (30) days unless it is appealed to the Management Committee. Within five business days of any action receiving less than ninety percent (90%) vote by the Operating Committee, the Committee Secretary shall give written notice thereof to the members of the Operating Committee. Notice of any appeal therefrom shall be filed with the MAPP Secretary within ten (10) days of mailing of said notice of action. The submittal to the Management Committee shall include such alternative proposals as any Participant may request. ARTICLE XII DESIGN REVIEW COMMITTEE 12.01 The Design Review Committee shall consist of members representing various Participants appointed by the Management Committee, one of whom shall be appointed Chairman by the Management Committee. Members appointed should have experience in system operation and analysis and be representative of the geographic area covered. A person from the staff of the MAPP Coordination Center shall serve as its Secretary and shall be a non-voting member. 12.02 The Committee shall meet on call of its Chairman as required to carry out its duties. Committee recommendations to the Management Committee as well as other committee action taken, shall be adopted by two-thirds vote of its members. Minority recommendations may be submitted. 12.03 The Design Review Committee, with assistance of the staff of the MAPP Coordination Center and in conjunction with each Participant, shall review and evaluate such Participant's planning for generation and transmission facilities for conformance to reliability design standards established by the Engineering Committee and report their findings to the Management Committee. Any operating restrictions necessary to make a Participant's planned facilities operate within MAPP reliability design standards will be subject to approval of the Design Review Committee. 12.04 To enable the Design Review Committee to carry out its tasks, the Participants shall furnish such studies and data as it shall reasonably request, including but not limited to, technical studies of system performance, data on current and projected loads, system equipment capabilities, capability margins, spinning reserves, relay settings controlling major facilities, communication facilities, recording facilities and operating procedures. ARTICLE XIIA OPERATING REVIEW COMMITTEE 12A.01 An Operating Review committee is created which, with assistance of the staff of the Contractor and in conjunction with each Participant, shall review and evaluate each Participant's operating studies, guides and practices for compliance with operating reliability standards, criteria, rules, methods, and procedures established by the Operating Committee and report its findings to the Management Committee. Any operating restrictions necessary to make a Participant's facilities operate within MAPP systems operating standards established by the Operating Committee will be subject to approval by the Operating Review Committee. 12A.02 The Operating Review Committee shall be composed of nine members; a Chair and Vice Chair appointed by the Management committee and seven members appointed by the Chair with the approval of the Management Committee. All members shall serve for an indefinite term at the pleasure of the Management Committee. The members of the Operating Review Committee shall have electric system operating knowledge and experience and shall be representative of the geographic area served by MAPP. A staff member of the Contractor shall serve as Secretary of the Operating Review Committee and shall be a non-voting member thereof. 12A.03 The Operating Review Committee shall meet at the call of the Chair as required to carry out its duties, or in case of the disability of the Chair, at the call of the Vice Chair. Recommendations of the Operating Review Committee to the Management Committee and other actions taken shall be by the affirmative vote of 2/3rds of all of the members. Minority recommendations may be submitted to the Management Committee. 12A.04 In cases where the Operating Review Committee determines from available information that a Participant has failed to comply with established operating standards, it shall notify the noncompliant Participant in writing. If the noncompliant Participant does not, within three months after receipt of the notice, propose a plan acceptable to the Operating Review Committee to correct the failure, or fails to comply with the correction plan, the Operating Review Committee shall report such failure to the Management Committee. ARTICLE XIII ENVIRONMENTAL COMMITTEE 13.01 The Environmental Committee shall be appointed by the Management Committee. In selection of such representatives, consideration shall be given to geographic representation. 13.02 The Environmental Committee shall hold an annual meeting in the first quarter of each year and shall hold other meetings at other times upon call of the Chairman or upon request of three or more Participant members. At least ten (10) days written notice shall be given to each member of the Environmental Committee of any meeting of such Committee. The notice shall state the time and place of the meeting and shall include an agenda of the items to be considered. 13.03 The Environmental Committee, at its annual meeting, shall elect two officers who shall serve until the next annual meeting. They shall be a Chairman and Vice Chairman elected from the representatives of the Participants on the Committee. The Chairman shall not serve for more than two consecutive terms. A person from the staff of the MAPP Coordination Center shall serve as its Secretary and shall be a non-voting member. 13.04 Under the direction of the Management Committee, the Environmental Committee shall keep abreast of national and regional matters relating to air quality, water quality, land use and other environmental factors. The Committee shall also carry out other functions and activities as assigned or approved by the Management Committee. Findings and recommendations shall be reported to the Management Committee. 13.05 The Environmental Liaison Group shall consist of one representative of each Participant designated by such Participant's representative on the Management Committee by written notice to the MAPP Secretary. The Liaison representative shall serve as the liaison between the Environmental Committee and each Participant for supplying information and receiving reports. The Environmental Liaison Group shall meet with the Environmental Committee as directed by the Environmental Committee. 13.06 The Environmental Committee may establish subcommittees and task forces and assign duties as necessary to carry out its assigned functions. ARTICLE XIV AREA RELATIONS COMMITTEE 14.01 The Area Relations Committee shall consist of one representative from each Participant designated by such Participant's representative on the Management Committee by written notice to the MAPP Secretary. By similar notice, a Participant may change its representative or designate an alternate to act in place of its representative. 14.02 The Area Relations Committee shall hold an annual meeting in the first quarter of each year and shall hold other meetings at other times upon call of the Chairman or upon request of three or more Participant members. At least ten (10) days written notice shall be given to each member of the Area Relations Committee of any meeting of such Committee. The notice shall state the time and place of the meeting and shall include an agenda of the items to be considered. Except by unanimous consent of those present, no action shall be taken on any item other than those included on the agenda. 14.03 The Area Relations Committee, at its annual meeting, shall elect two officers who shall serve until the next annual meeting. They shall be a Chairman and Vice Chairman elected from the representatives of the Participants on the Committee. The Chairman shall not serve for more than two consecutive terms. A person from the staff of the MAPP Coordination Center shall serve as its Secretary and shall be a non-voting member. 14.04 Under the direction of the Management Committee, the Area Relations Committee shall be responsible for advising the Parties on preparing progress reports, public presentations and educational materials relating to activities of the Parties pursuant to this Agreement and shall carry out other functions and activities as assigned or approved by the Management Committee. 14.05 The Committee shall meet as required on call of the Committee Chairman or the Management Committee. ARTICLE XV MAPP COORDINATION CENTER 15.01 The Management Committee shall select a Contractor which will agree to provide various information and other services, as determined by the Management Committee, to each of the Participants in order to enhance the attainment of the goals of this Agreement. 15.02 Consistent with policy and guidelines provided by the Management Committee, the Contractor shall be an independent contractor with each of the Participants and will be responsible for the establishment and operation of a MAPP Coordination Center hereinafter called "Center." The Contractor shall provide facilities, manpower, and administration necessary for such operation. 15.03 Each Participant shall enter into an agreement with the Contractor providing for services as provided in Paragraph 15.01 under the terms and conditions and such annual payment as may be established from time to time between the Management Committee and the Contractor. 15.04 Each Party shall retain the sole responsibility for the operation of its system and the utilization of the information which may be provided from the Center. 15.05 Subject to a determination by the Management Committee that such action can be taken without prejudicing the Contractor's fulfillment of its obligations to the Participants for services from the Coordination Center, the Contractor may contract with electrical power suppliers which are not parties to this Agreement for services from the Contractor or with parties for other services under conditions approved by the Management Committee. 15.06 In consideration of the services provided by the Contractor inuring to the Associate Participants, the Associate Participants shall make payment directly to the Contractor for their share of the costs of providing such services which shall be as follows or as subsequently established by the Management Committee: $200 for each fiscal year where the Annual System Demand for the previous fiscal year is 5,000 kilowatts or less plus $60 for each 5,000 kilowatts or fraction thereof by which such Annual System Demand exceeds 5,000 kilowatts, with a maximum of $10,000. 15.07 The Contractor shall be responsible to maintain a staff adequate to support the services required by the MAPP Committees. Such services shall include but not be limited to gathering of historical data, maintaining a data base for planning and operating studies, maintaining official records of the MAPP Committees, administering certain contracts with other Parties or entities for studies, publishing reports and filing such reports as required with regulatory bodies, continuously monitoring the operation of the Pool and the MAPP communications system, providing assistance in determining potential operating problems, conducting studies as required, coordinating the operations of the MAPP Region with adjoining coordinated regions and others as appropriate, and carrying out projects of the MAPP Committees as directed. ARTICLE XVI MAINTENANCE OF ADEQUATE CAPABILITY 16.01 Each Participant expects and is expected to maintain utility responsibility for its own load and, as a part of such responsibility, shall maintain during each month Accredited Capability in an amount equal to or greater than its maximum System Demand for such month plus such Participant's Reserve Capacity Obligation, as set forth in Paragraph 16.02. 16.02 The Reserve Capacity Obligation of a Participant, for any month, shall be equal to fifteen percent (ten percent for a predominantly hydro system) of the Annual System Demand of such Participant or as established by the Management Committee. 16.03 The Engineering Committee shall determine the Accredited Capability for each Participant on the following basis: a. In respect to Net Generating Capability, the Accredited Capability shall be determined in accordance with Paragraph 3.07. b. In respect to purchases and sales under Service Schedules "A," "B," and "K," the Accredited Capability shall include the amount for which the Participant has contracted provided that such transactions are in accordance with rules and regulations established by the Engineering Committee. c. In respect to purchases and sales under Service Schedules "H," "I," and "J," the Accredited Capability shall include the amount for which the Participant has contracted plus the associated reserve capacity established from the percentage determined by the Management Committee subject to the provisions of Paragraph 2.02 of Service Schedule "I" provided that such transactions are in accordance with rules and regulations established by the Engineering Committee. d. In respect to commitments for power from or to any electric power supplier, which are not under the Service Schedules of this Agreement but are under separate contracts now existing or hereafter created, such commitments shall be reflected in a Participant's Accredited Capability provided that such transactions are in accordance with rules and regulations established by the Engineering Committee. Each Participant shall submit, if requested, copies of its contracts for such commitments to the Engineering Committee for the purpose of such determination. Determinations of Accredited Capability shall be reviewed by the Engineering Committee at least semi-annually and at any other time upon the written request of any Participant and any appropriate changes resulting from such review shall be made. In order to secure consistency and continuity in determining Accredited Capability, the Engineering Committee shall establish rules and regulations as necessary These rules and regulations shall reflect the following understanding: i. Approval of transactions which are associated with a coordinated system development, which may include non-Participants, will be on the basis of reliability considerations. ii. Transactions for capability deficiencies which are residual to subparagraph (i) normally will be made with Pool Participants and Pool surpluses normally will be dedicated to such transactions. iii. Transactions will not be compelled with a Participant for power and energy from generating capacity constructed by a Participant in excess of capacity recommended by the Engineering Committee. 16.04 The Engineering Committee shall continually review the load and capability forecasts for the Participants. If the forecast of a Participant indicates that, during any month of the ensuing period, the length of period being determined by the Engineering Committee, such Participant will not meet its Reserve Capacity Obligation, such Participant shall make arrangements to obtain additional Accredited Capability as approved by the Engineering Committee so that during such month it will have sufficient capacity to meet its Reserve Capacity Obligation. In the event that during any month a Participant did not meet its maximum System Demand plus its Reserve Capacity Obligation, such Participant shall be required to obtain additional Accredited Capability from the other Participants. The amount of Accredited Capability required by the deficient Participant and the source or sources will be determined by the Engineering Committee. If Accredited Capability is not available from Participants, the Engineering Committee may recommend: a. Purchase from non-Participants. b. Other means of sharing Reserve Capacity to effect equalization of reserves. 16.05 Nothing contained in this Agreement shall be interpreted to require a Party to install facilities or to restrict a Party's election of whether to install facilities or purchase power to maintain its Accredited Capability. ARTICLE XVII INSTALLATION OF ADDITIONAL FACILITIES 17.01 It is the intent hereof to provide for an equitable staggering of future investments in generating capacity and other facilities in order to obtain maximum economy and benefits from interconnected system operation. It is understood that the generating units installed by the Participants hereafter should be the most economical size and type practicable, taking into consideration the size of the installing Participants' systems, the loads of the Participants, the anticipated growth of such loads, the transmission facilities required to transmit the output thereof to such loads or to supply such loads when the unit is not in service and the ability of the systems of the Participants and their interconnections with other interconnected systems to withstand the instantaneous loss of such units without causing unstable operation. It is also anticipated, that, in general, the amount and type of additional generating capacity to be installed by any Participant shall take into consideration the load and the load growth of such Participant and that the installation of specific generating units shall be rotated among the Participants so as to accomplish this overall intent. Whenever the recommendation of the Engineering Committee is that a Participant construct and install any additional generating or transmission facilities, such Participant shall not be deemed committed to such construction or installation unless it has elected to accept such recommendation by proper corporate action reported by its representative on the Management Committee. 17.02 It is understood by the Parties that nothing in the Agreement is intended to preclude a Participant from constructing or utilizing generation and transmission facilities other than those recommended by the Engineering Committee; however, such facilities shall be subject to the established reliability standards. ARTICLE XVIII MAINTENANCE OF ADEQUATE OPERATING RESERVE 18.01 Each Participant shall provide Spinning Reserve and Non-Spinning Reserve in the proportions recommended by the Operating Committee and established by the Management Committee, equal to or greater than the Operating Reserve Obligation of the Participant, as provided in Paragraph 18.02. As soon as practicable after the occurrence of an incident which utilizes Operating Reserve, each Participant shall restore its Operating Reserve Obligation by following procedures determined by the Operating Committee. 18.02 The Total Operating Reserve Obligation at any time shall initially be an amount equal to 150 percent of the capability of the largest generating unit in operation on the interconnected systems of the Participants and shall be subject to revision by the Management Committee. The Operating Reserve Obligation of a Participant shall be that percentage of the Total Operating Reserve Obligation determined by the Operating Committee in accordance with formula based on the capability of the largest generating unit of each Participant and the Annual System Demand of such Participant. Initially one-third weight shall be given to unit size and two-thirds weight to Annual System Demand, such weighting shall be subject to revision by the Management Committee. 18.03 The Operating Committee will establish procedures for determining the Operating Reserve that is available on the systems of the Participants at all times. Whenever a Participant is unable to meet its Operating Reserve Obligation, such Participant shall immediately advise all other Participants and make arrangements to restore its Operating Reserve Obligation. ARTICLE XIX SERVICES TO BE RENDERED 19.01 The various specific services to be rendered in furtherance of the purposes of this Agreement are covered by Service Schedules of the Agreement which are listed as follows: "A" Participation Power Interchange Service "B" Seasonal Participation Power Interchange Service "C" Emergency and Scheduled Outage Interchange Service "D" Operating Reserve Interchange Service "E" Economy Energy Interchange Service "F" Transmission Services and Losses "G" Operational Control Energy Interchange Service "H" Peaking Power Interchange Service "I" Short Term Power Interchange Service "J" Firm Power "K" System Participation Power "L" Interruptible Load Replacement Energy Service "M" General Purpose Energy Service 19.02 The Service Schedules are intended to facilitate coordinated daily operation and the staggering of generation additions in accordance with Paragraph 10.05 (d) and Article XVII and shall not be used to provide power supply from a generation source for a greater period than that consistent with Article XVII. 19.03 The providing of Transmission Service under Service Schedule "F" is based on each Participant providing an equitable portion of the transmission facilities required to accomplish the coordinated daily operation and coordinated planning contemplated hereunder. a. Participants meeting the following criteria will be assumed to be providing an equitable share of transmission: i. Whose system is normally operated directly interconnected with two or more Participants systems. ii. Which owns or controls transmission facilities operated at 115 Kv or higher forming an integral part of the regional transmission network. b. All other Participants may meet the qualifications set forth in (a) through contractual arrangements with a Participant which does meet the qualifications and to which it is interconnected. Participants shall negotiate such arrangements in good faith and in doing so shall be expected to permit a Participant to qualify under this subsection by making investment in facilities or by making payments. The investment facilities or payments shall be calculated to compensate the Participant for the use of its facilities for transactions under the Service Schedules. If two Participants are unable to negotiate a mutually satisfactory contracting arrangement within a period of six months after written notice has been received from the Participant expressing a desire to enter into such a contractual arrangement and the Participant receiving such notice is a public utility within the meaning of section 201 (e) of the Federal Power Act, the Participant receiving such notice shall, at the written request of the other Participant, made at any time following the expiration of six month period, file within sixty (60) days thereafter a contractual arrangement with the Federal Energy Regulatory Commission in accordance with the provision of section 205 of the Federal Power Act and the Regulations thereunder. ARTICLE XX SERVICE OBLIGATIONS 20.01 It is recognized that the systems of the Participants are now or may be interconnected with other systems and that other agreements for interconnection, mutual assistance, pooling, power supply and transmission service may exist or may be entered into between Participants or between a Participant and another system. It is understood that the Participants intend to assist each other to the maximum extent of their capabilities, but it is recognized that such agreements may limit the capacities available to Participants under the terms hereof. 20.02 Any Participant, upon request by any other Participant, shall supply to such other Participant Emergency Energy up to the full amount of its Available Accredited Capability provided that such request conforms with the provisions of Service Schedule "C." 20.03 Any Participant, upon request by any other Participant, shall supply to such other Participant Scheduled Outage Energy up to the full amount of its Accredited Capability not required to maintain its Operating Reserve Obligation; provided that the delivery thereof shall conform with the provisions of Service Schedule "C" and provided further that, if the requesting Participant is not using its Total Available Accredited Capability, the Participant requested to supply scheduled Outage Energy shall not be obligated to supply such energy when in the sole judgment of such Participant, the supply of such energy would cause a hardship. 20.04 Any Participant may procure through its interconnection with other electric suppliers, Emergency Energy or Scheduled Outage Energy in addition to that which can be supplied by the Participants which may be available under agreements covering such interconnections from a source or sources which will result in the lowest cost to the receiving Participant and shall arrange for the delivery of such Emergency Energy or Scheduled Outage Energy to such receiving Participant; provided that the delivery thereof can be made, in the sole judgment of the Participant procuring such service, without endangering its facilities or interfering with its obligations to its customers, other Participants, or other electric suppliers. 20.05 Any Participant whose transmission facilities are required to provide Transmission Service for Emergency Energy supplied to a receiving Participant shall transmit such energy up to such amounts as will not, in the sole judgment of the Participant providing the Transmission Service, endanger its facilities or interfere with its obligations to its customers, other Participants, or other electric suppliers. 20.06 Any Participant, upon request by any other Participant, shall supply to such other Participant, Operating Reserve up to the full amount of its Available Accredited Capability not required to maintain its Operating Reserve Obligation; provided that the delivery thereof shall conform with the provisions of Service Schedule "D" and provided further, however, that there shall be no obligation of a Participant to supply Operating Reserve if the requesting Participant is not making full use of its Available Accredited Capability. 20.07 Any Participant, when called upon to do so by any other Participant, may supply Economy Energy to such other Participant provided such call conforms with the provisions of Service Schedule "E." 20.08 Any Participant, when called upon to do so by any other Participant, may supply Interruptible Load Replacement Energy to such other Participant, provided such call conforms with the provisions of Service Schedule "L." 20.09 Any Participant, when called upon to do so by any other Participant, may supply General Purpose Energy to such other Participant, provided such call conforms with the provisions of Service Schedule "M." 20.10 Each Participant agrees that it will provide Transmission Service in accordance with the provisions of Section 19.03 and Service Schedule "F." The Participants shall endeavor to make maximum use of facilities for Pool transactions consistent with MAPP reliability standards. Nothing herein shall be construed as obligating any of the Participants to provide Transmission Service other than for Participants in accordance with Section 19.03 and Service Schedule "F". 20.11 The service obligations set forth in this Article are each subject to the limitations that the Participant on which the request is made as therein stated shall not be obligated to use Available Accredited Capability if it is at the time being used to supply the requirements of its customers including obligations now existing or hereafter created to other Participants or to other electric suppliers. A Participant shall not be obligated to deliver power and energy over its transmission facilities if, in the sole judgment of said Participant, such delivery will: a. Endanger its facilities, or b. Interfere with its obligations, now existing or hereafter created, to its customers or to other electric suppliers. 20.12 The Participant purchasing power and energy under Service Schedules "A," "B," "H," "I," "J," "K," and "L" shall be responsible for initiating scheduled deliveries thereunder and the scheduled rate of delivery shall not exceed the amount being purchased under the Schedule. In the scheduling of deliveries, due consideration shall be given to the rate of change of delivery and the continuity of delivery so as not to cause undue hardship on the system of the supplying Participant. ARTICLE XXI SERVICE CONDITIONS 21.01 The systems of the Participants shall be operated interconnected continuously under normal system conditions and the Participants shall cooperate in keeping the frequency of the interconnected systems of the Parties at 60 Hz as closely as is practicable, in keeping the interchange of power and energy between the systems of the Participants as closely as is practicable to the scheduled amounts and in maintaining mutually satisfactory voltage levels. Each Participant shall be responsible for the reactive volt-ampere requirements of its system. Reactive volt-amperes may be interchanged between systems from time to time, subject to agreement between the Participants involved, when benefit to one system may be gained thereby without causing hardship to another system. 21.02 The systems of the Participants shall normally be so maintained and operated as to minimize, in accordance with good practice, the likelihood of a disturbance originating in the system of one Participant causing impairment to the service of the system of any other Participant or of any other system with which the systems of the Participants are interconnected. 21.03 It is recognized that unintentional interchange of power and energy between interconnected systems will occur because of the impossibility of continuously controlling generation to exactly equal the load. It also is recognized that, due to the manner in which the systems of the Participants are interconnected with each other and with other systems, a portion of the power and energy scheduled for delivery between any two of such interconnected systems may not flow directly from the supplier thereof to the receiver thereof over the intended route through the transmission systems of the Participants, but may result in inadvertent flows through other systems. Therefore, because of these conditions: a. All intentional power and energy deliveries between the system of one Participant and the system of another Participant shall be scheduled in advance. b. It shall be the responsibility of each Participant to maintain the net power and energy flowing into and out of its system during each hour so that deliveries are, as near as practicable, equal to the net scheduled amount. The difference between the net scheduled deliveries and the actual net deliveries shall be balanced out in kind in accordance with principles and practices established by the Operating Committee. c. A Participant shall be entitled to compensation for losses caused by the flow of power and energy scheduled from or to another Participant. Such compensation shall be in the form of an equivalent amount of energy in accordance with methods determined by the Operating Committee. d. It is not the intent to grant any Participant any right generally to use the system of any other Participant as an intermediary in power and energy transactions, nor shall consent by a Participant to any power and energy flows through its system in a particular case create any rights for a Participant to continue such flows; and, where such flows are objectionable to a Participant experiencing such flows, the Participants shall cooperate to prevent such flows from occurring normally and to minimize flows of this character. ARTICLE XXII METERING 22.01 All metering equipment required for recording the deliveries of power and energy between the systems of each Participant and the systems of the other Participants with which it is interconnected shall be maintained by the Parties owning such metering equipment in accordance with good practice and accepted industry standards. 22.02 Should any such metering equipment at any time fail to register or should the registration thereof be so erratic as to be meaningless, the power and energy delivered shall be determined from the best information available. ARTICLE XXIII RECORDS 23.01 In addition to meter records, the Participants shall keep such log sheets and other records (determined by the Operating Committee) as may be needed to afford a clear history of the various movements of power and energy between the systems of the Participants involved both in transactions hereunder and in transactions between Participants hereto under other agreements between such Participants and to effect such differentiation as may be needed in connection with settlements in respect to such transactions. The originals of all such meter records and other records shall be open to inspection by representatives of the Participants concerned and by the Operating Committee. 23.02 Each Party shall furnish to the Operating Committee appropriate data from meter registrations and from other sources on such time basis as are determined by the Operating Committee when such data is needed for settlements, special tests, operating records or for other purposes consistent with the objectives hereof. As promptly as practicable after the end of each month, each Participant shall render to the other Participants concerned, statements setting forth appropriate data from meter registrations and other sources in such detail and with such segregation as may be needed for operating records and for settlements hereunder. ARTICLE XXIV BILLINGS AND PAYMENTS 24.01 For billing purposes, the amount of energy delivered pursuant to this Agreement by a supplying Participant to a receiving Participant, during any period, shall be the amount scheduled for delivery. 24.02 Billing for any transaction involving generation or transmission capacity pursuant to this Agreement, including any Transmission Service charges pertaining to such transaction, shall be based upon the amount of such capacity committed in advance for delivery. 24.03 All bills for services supplied pursuant to this Agreement shall be rendered monthly by the supplying Participant to the purchasing Participant after the end of the period to which such bills are applicable. Unless otherwise agreed upon by the Operating Committee, such period shall be from 12:01 AM on the first day of the month to 12:01 AM of the first day of the succeeding month. Bills shall be due and payable within fifteen days from the date such bills are rendered and payment shall be made when due and without deduction. Bills shall be deemed rendered on the postmark date if deposited in first class mail with postage prepaid and shall be deemed rendered upon receipt if another means of delivery is used. If the due date of any bill falls on Saturday, Sunday or holiday observed by either Party, the bill shall be due and payable on the next following working day of both Parties. Interest shall accrue and be compounded daily on any unpaid amount, from the date due until the date upon which payment is made, using the lowest daily prime rates published in the money rates section of the Wall Street Journal for the applicable time period. Such daily interest shall be computed on the basis of actual days and a 365 day calendar year. 24.04 Billing for Transmission Service shall be rendered monthly in a manner to be determined by the Operating Committee. 24.05 In the event a Participant desires to dispute all or any part of the charges submitted by some other Participant, it shall nevertheless pay the full amount of the charges when due and give notification in writing within sixty (60) days from the date of the statement stating the grounds on which the charges are disputed and the amount in dispute. The complaining Participant will not be entitled to any adjustment on account of any disputed charges which are not brought to the attention of the Participant rendering such charges within the time and in the manner herein specified. If settlement of the dispute results in a refund to the payer, interest shall accrue and be compounded daily on the amount to be refunded from the date of payment until the date upon which refund is made, using the lowest daily prime rates published in the money rates section of the Wall Street Journal for the applicable time period. Such daily interest shall be computed on the basis of a 365 day year. 24.06 All billings under this Agreement shall be determined and stated and all payments shall be made in the currency of the United States of America. For all billings, the rate to be used to convert from the currency of the United States to that of Canada or from the currency of Canada to that of the United States shall be the monthly average noon spot exchange rate for the monthly billing period covered by such billing provided by the Royal Bank of Canada, Winnipeg, Manitoba. ARTICLE XXV TAXES 25.01 Any tax imposed upon the seller and levied upon or measured by power or energy supplied by one Participant to another Participant shall be added to the bill rendered by the Participant supplying the power or energy. ARTICLE XXVI UNCONTROLLABLE FORCES 26.01 A Participant shall not be considered to be in default in respect of any obligation hereunder if prevented from fulfilling such obligation by reason of uncontrollable forces. The term "uncontrollable forces" shall be deemed for the purposes hereof to mean storm, flood, lightning, earthquake, fire, explosion, failure of facilities not due to lack of proper care or maintenance, civil disturbance, labor disturbance, sabotage, war, national emergency, restraint by court or public authority, or other causes beyond the control of the Participant affected which such Participant could not reasonably have been expected to avoid by exercise of due diligence and foresight and by provision of reserves in accordance with the requirements of this Agreement. Any Participant unable to fulfill any obligation by reason of uncontrollable forces will exercise due diligence to remove such disability with reasonable dispatch, but such obligation shall not require the settlement of a labor dispute except in the sole discretion of the Participant experiencing such labor dispute. ARTICLE XXVII WAIVERS 27.01 Any waiver at any time by any Party of its rights with respect to a default under this Agreement, or with respect to any other matter arising in connection with this Agreement, shall not be deemed a waiver with respect to any subsequent default or other matter arising in connection herewith. Any delay short of the statutory period of limitation in asserting or enforcing any right shall not be deemed a waiver of such right, except as provided in Paragraph 24.05 of this Agreement. ARTICLE XXVIII NOTICES 28.01 Any formal notice, demand or request required or authorized by this Agreement shall be deemed properly given if mailed, postage prepaid, to the Management Committee representative of the Party concerned, at the address of such Party shown on the signature pages hereof. 28.02 Any notice or request of a routine character in connection with delivery of power and energy or in connection with operation of facilities, shall be given in such manner as the Operating Committee from time to time shall arrange. ARTICLE XXIX SUCCESSORS AND ASSIGNS 29.01 No Party shall assign this Agreement without the consent, in writing, of the other Parties, except in connection with the sale or merger of a substantial portion of its properties including its high voltage transmission facilities. 29.02 The several provisions of this Agreement are not intended to and shall not create rights of any character whatsoever in favor of any persons, corporations, or associations other than the Parties to this Agreement and the obligations herein assumed are solely for the use and benefits of the Parties to this Agreement. ARTICLE XXX ARBITRATION 30.01 Any controversy or claim arising out of or relating to this Agreement or the breach thereof, or appeal from action of the Management Committee under Paragraph 8.07 of this Agreement, shall be settled by arbitration. Such arbitration shall be conducted before a board of three arbitrators selected by the American Arbitration Association and the arbitration shall be conducted in accordance with the commercial arbitration rules of the American Arbitration Association then in effect, subject to the further qualification that the arbitrators named under said rules shall be competent by virtue of education and experience in the particular matter subject to arbitration. 30.02 The Party or Parties desiring arbitration shall demand such arbitration by giving written notice to the other Party or Parties involved. Such notice shall conform to the procedures of the American Arbitration Association and shall include a statement of the facts or circumstances causing the controversy and the resolution, determination or relief sought by the Party or Parties desiring arbitration. 30.03 Before the matter is presented to the board of arbitrators a conference shall be held to attempt to resolve the controversy or if that is not possible, to stipulate as many facts as possible and to clarify and narrow the issues to be submitted to arbitration. 30.04 The board of arbitrators shall have no authority, power or jurisdiction to alter, amend, change, modify, add to or subtract from any of the provisions of this Agreement nor to consider any issues arising other than from the language in and authority derived from this Agreement. 30.05 The decision or award of the arbitrators shall be final and binding upon the Parties and the Parties shall do such acts as the arbitration decision or award may require of them. Judgment upon any award rendered by the arbitrators may be entered in any court having jurisdiction and execution issued thereon. This provision shall survive the termination of this Agreement. 30.06 The Party or Parties demanding arbitration shall pay the costs incurred in connection with the arbitration. ARTICLE XXXI CHOICE OF LAW 31.01 In order to promote the uniformity of the interpretation of this Agreement, it is agreed that the laws of the State of Minnesota shall control the obligations and procedures established by this Agreement and the performance and enforcement thereof. ARTICLE XXXII REGULATION 32.01 This Agreement is subject to the regulation of any regulatory body having jurisdiction thereof. ARTICLE XXXIII AMENDMENTS 33.01 Any Participant may propose an amendment to this Agreement by filing such proposed amendment with the Chairman of the Management Committee who shall immediately forward copies thereof to the Participants. Each Participant shall forward its vote to the Chairman and said vote must be received by the Chairman within sixty (60) days after the date of filing. 33.02 In voting on any amendment, each Participant shall have the same number of votes as its representative would have under Paragraph 8.06. If seventy-five percent (75%) or more of the total authorized votes favor the amendment, such amendment will become effective 120 days after filing with the Chairman of the Management Committee but no amendment shall affect transactions agreed upon in writing prior to the effective date of such amendment. Abstentions shall be counted as negative votes. 33.03 Notwithstanding Section 33.02 above, amendments that are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) will become effective only upon acceptance without change or condition by the FERC, or if accepted with change or condition by the FERC, upon confirmation and approval of such change or condition by an affirmative vote of seventy- five percent (75%) or more of the total authorized votes of the Management Committee, and unless otherwise provided, will become effective the first day of the MAPP Season following acceptance by the FERC, and if necessary, confirmation by the Management Committee. ARTICLE XXXIV INTRA-CORPORATE RELATIONSHIPS 34.01 Northern States Power Company, a Minnesota corporation, hereinafter called "NSP," as a Participant herein shall include its subsidiary, Northern States Power Company, a Wisconsin corporation. All interchanges of power and energy between said companies and other Participants shall be considered as transactions between such Participants and NSP. 34.02 Minnesota Power & Light Company, a Minnesota corporation, hereinafter called "MP," as a Participant herein shall include its subsidiary Superior Water, Light and Power Company, a Wisconsin corporation. All interchanges of power and energy between said companies and other Participants shall be considered as transactions between such Participants and MP. ARTICLE XXXV PARTICIPATION BY THE WESTERN AREA POWER ADMINISTRATION 35.01 The Parties understand that participation in this Agreement by THE UNITED STATES OF AMERICA, hereinafter called the United States, is limited to application of this Agreement to a specific electric system operated by the Western Area Power Administration. a. Application of this Agreement to the United States is limited to a defined part of the electric system operated by, and of the electric power facilities and resources available to, the EASTERN DIVISION, PICK-SLOAN MISSOURI BASIN PROGRAM, or its successor administrative entities. b. Transactions between said Eastern Division of the Pick-Sloan Missouri Basin Program and other power systems of the United States shall be considered to be internal, one-entity transactions for the purposes of this Agreement. 35.02 The participation by the United States in this Agreement is subject in all respects to acts of Congress and to regulations of the Secretary of Energy established thereunder and rate schedules promulgated by the Secretary of Energy or delegatee. This reservation includes, but is not limited to: a. The operation and administration of provisions of law giving preference to certain classes of customers in the sale of Federal power. b. The final authority of Congress in all matters relating to the installation, construction or operation of facilities. c. The statutory authority of the Secretary of Energy to set rates for the sale of power by the United States. d. The statutory limitations upon the authority of the Secretary of Energy to submit disputes arising under this contract to arbitration. 35.03 Contingent Upon Appropriations: Notwithstanding Article VI, where the operations of this Agreement extend beyond the current fiscal year, participation by the United States is contingent upon Congress making the necessary appropriation for expenditures by the United States after such current year shall have expired. In case such appropriation as may be necessary to carry out obligations of the United States under this Agreement is not made, the Parties release the United States from all liability due to the failure of Congress to make such appropriation. 35.04 Officials Not To Benefit: No member of or Delegate to Congress or Resident Commissioner shall be admitted to any share or part of this Agreement or to any benefit that may arise herefrom, but this restriction shall not be construed to extend to this Agreement if made with corporations or companies for their general benefit. 35.05 Covenant Against Contingent Fees: The Parties warrant that no person or selling agency has been employed or retained to solicit or secure participation by the United States in this Agreement upon an agreement or understanding for a commission, percentage, brokerage or contingent fee, excepting bona fide employees or bona fide established commercial or selling agencies maintained by the Parties for the purpose of securing business. For breach or violation of this warranty, the United States shall have the right to annul its participation in this Agreement without liability or, in its discretion, to deduct from the contract price or consideration due from the United States the full amount of such commission, percentage, brokerage, or contingent fee. 35.06 Utility Responsibility: Any reference in this Agreement to "utility responsibility" of a Participant shall apply to the United States only to the extent, and in the sense, that the United States has responsibility for satisfying its obligations for power service as established by other contracts. 35.07 Membership in Other Groups: It is understood by the Parties that the United States is at present a participant in the Western Systems Coordinating Council (for a small part of its western facilities and operations) and the Missouri Basin Systems Groups (for certain planning coordination and joint transmission activities) and the United States may in the future participate in other similar coordination arrangements. Participation of the United States is dependent on its understanding that nothing in this Agreement would preclude such other participation or commitment of resources thereto, but rather that it remains the responsibility of each Participant to insure that its obligations are not in conflict. 35.08 Rate Schedules: Rate Schedules for rates and conditions of service by the United States shall be governed by rate schedules promulgated by the Secretary of Energy or delegatee: a. The Service Schedules, except for Service Schedule "F" Transmission Services and Losses, shall not apply to the transactions of the United States. Service Schedule "F" will apply to transactions to which the United States is a party and to transactions by other Participants which utilize the transmission system of the United States. b. The United States will initiate discussion with the other Participants as to the future applicability of the Service Schedules to transactions made by the United States. 35.09 Area Relations Committee: It is understood by the Parties that Federal agencies are prohibited by law from participating in or contributing to any activities influencing legislation or involving lobbying. Participation of the United States in this Agreement and especially as to participation in the Area Relations Committee, shall be limited to activities that are clearly legal for an agency of the United States. 35.10 Provisions Relative to Employment: The following provisions governing employment under government contracts are set forth in Article P of the "General Power Contract Provisions" made a part of all current power contracts entered into by the Western Area Power Administration. It is understood by the Parties that these provisions shall be applicable hereunder to transactions between the United States and other Participants. For the purpose of this Paragraph 35.10, the term "contract" shall mean this Agreement and the term "Contractor" shall mean a Participant having transactions with the United States. a. During the performance of this contract, the Contractor agrees as follows: i. The Contractor will not discriminate against any employee or applicant for employment because of race, color, religion, sex or national origin. The Contractor will take affirmative action to ensure that applicants are employed and that employees are treated during employment, without regard to their race, color, religion, sex, or national origin. Such action shall include, but not be limited to, the following: employment, upgrading, demotion or transfer, recruitment or recruitment advertising, layoff or termination, rates of pay or other forms of compensation, and selection for training, including apprenticeship. The Contractor agrees to post in conspicuous places, available to employees and applicants for employment, notices to be provided by the Contracting Officers setting forth the provisions of this Equal Opportunity clause. ii. The Contractor will, in all solicitations or advertisements for employees placed by or on behalf of the Contractor, state that all qualified applicants will receive consideration for employment without regard to race, color, religion, sex, or national origin. iii. The Contractor will send to each labor union or representative of workers with which he has a collective bargaining agreement or other contract or understanding, a notice, to be provided by the agency Contracting Officer, advising the labor union or workers' representative of the Contractor's commitments under this Equal Opportunity clause and shall post copies of the notice in conspicuous places available to employees and applicants for employment. iv. The Contractor will comply with all provisions of Executive Order No. 11246 of September 24, 1965, and the rules, regulations and relevant orders of the Secretary of Labor. v. The Contractor will furnish all information and reports required by Executive Order No. 11246 of September 24, 1965, and by the rules, regulations and orders of the Secretary of Labor or pursuant thereto and will permit access to his books, records and accounts by the contracting agency and the Secretary of Labor for purposes of investigation to ascertain compliance with such rules, regulations and orders. vi. In the event of the Contractor's noncompliance with the Equal Opportunity clause of this contract or with any of the said rules, regulation or orders, this contract may be canceled, terminated or suspended, in whole or in part, and the Contractor may be declared ineligible for further Government contracts in accordance with procedures authorized in Executive Order No. 11246 of September 24, 1965, and such other sanctions may be imposed and remedies invoked as provided in Executive Order No. 11246 of September 24, 1965, or by rule, regulation or order of the Secretary of Labor, or as otherwise provided by law. vii. The Contractor will include the provisions of paragraphs (i) through (vii) in every subcontract or purchase order unless exempted by rules, regulations or orders of the Secretary of Labor issued pursuant to Section 204 of Executive Order No. 11246 of September 24, 1965, so that such provisions will be binding upon each subcontractor or vendor. The Contractor will take such action with respect to any subcontract or purchase as the contracting agency may direct as a means of enforcing such provisions, including sanctions or noncompliance; provided however, that in the event the Contractor becomes involved in, or is threatened with, litigation with a subcontractor or vendor as a result of such direction by the contracting agency, the Contractor may request the United States to enter into such litigation to protect the interests of the United States. b. In the performance of any part of the work contemplated by this contract, the Contractor shall not employ any person undergoing sentence of imprisonment at hard labor. ARTICLE XXXVI PARTICIPATION BY THE MANITOBA HYDRO 36.01 The generating and transmission systems of the Manitoba Hydro and the City of Winnipeg Hydro Electric System are interconnected and operated as a single system. Manitoba Hydro provides any additional generating capacity required to meet the combined needs of Manitoba Hydro and the City of Winnipeg. For the purposes of this Agreement, System Demand and Accredited Capability for Manitoba Hydro shall be determined for the combined systems of Manitoba Hydro and the City of Winnipeg Hydro Electric System. 36.02 The participation by Manitoba Hydro in this Agreement is subject in all respects to legislation of the Governments of Canada and Manitoba. This includes but is not limited to: a. The final authority of the Government of Canada in all matters relating to the export of electric power. b. The final authority of the Government of Manitoba in all matters relating to the installation or construction of facilities. 36.03 It is understood by the Parties that Manitoba Hydro has entered into interconnection agreements with electric utilities in other Provinces of Canada. Under the terms of these agreements, Manitoba Hydro may not make commitments to supply surplus electric power and energy or any other related services to a utility based outside of Canada without first giving utilities based in Canada the prior right to purchase such surplus electric power, energy and other services on the same terms and conditions and at an equivalent price. 36.04 The reliability characteristics of Manitoba Hydro's generating facilities, which are predominantly hydroelectric, shall be considered when establishing Manitoba Hydro's Reserve Capacity Obligation. 36.05 It is an acknowledged condition to the participation by Manitoba Hydro in this Agreement that: a. Nothing in this Agreement shall alter or diminish the rights of other Canadian electric utilities to purchase surplus electric power, energy, and services from Manitoba Hydro. b. Nothing in this Agreement shall preclude participation by Manitoba Hydro in any Canadian electric power pool or the commitment of resources thereto. c. Manitoba Hydro's participation in the Area Relations Committee shall be limited to activities which are clearly nonpolitical inasmuch as Manitoba Hydro does not have the right to participate in or contribute to any activity which is intended to influence legislation. d. Any provision governing employment or production of goods and services enacted by the Congress of the United States of America or enacted by any other legislative body in the United States of America shall not be applicable to any power or other service provided by Manitoba Hydro to the United States of America or to any other party in the United States of America. e. The authority of the Federal Energy Regulatory Commission on matters pertaining to power transactions between Manitoba Hydro and the other Parties shall not be applicable to the transmission or use of such power within Canada. f. The provisions of Article XXX shall not apply to any controversy, claim or dispute arising out of or relating to this Agreement or the breach thereof which involves Manitoba Hydro and any such controversy, claim or dispute shall be referred to the Chief Executive Officer of each of the disputing parties to resolve. g. Notwithstanding Article XXXI, the laws of the Province of Manitoba, Canada, shall apply to any transactions undertaken or services rendered in Canada and the performance and enforcement thereof. Execution. Separate copies of this Agreement are executed by the Parties with the understanding that, when each of the Parties has executed a copy, its separately executed copy will be joined together with all other similarly executed copies and one conformed master copy of said agreement shall be prepared, which shall bind all of the Parties to the same extent and purpose as if all of said Parties had joined in the execution of said master copy. IN WITNESS WHEREOF, each of the Parties has caused this Agreement to be executed by its duly authorized officer as of the day and year of the membership shown below. SIGNATORY PARTICIPANTS (Date of Membership) BASIN ELECTRIC POWER COOPERATIVE ARTHUR JONES (August 14, 1975) President CENTRAL IOWA POWER COOPERATIVE JOSEPH C. ARMBRECHT (March 31, 1972) President COOPERATIVE POWER ASSOCIATION ORVILLE J. LIPKE (March 31, 1972) President CORN BELT POWER COOPERATIVE WARREN C. SNELL (March 31, 1972) President DAIRYLAND POWER COOPERATIVE JOHN P. MADGETT (March 31, 1972) General Manager HEARTLAND CONSUMERS POWER DISTRICT WENDELL J. GARWOOD (February 13, 1979) General Manager HUTCHINSON UTILITIES COMMISSION Thomas B. Lyke (February 25, 1991) Vice President INTERSTATE POWER COMPANY GLENN J. LYSHOJ (March 31, 1972) Vice President IOWA ELECTRIC LIGHT AND POWER COMPANY DUANE ARNOLD (March 31, 1972) Chairman of the Board and President IOWA-ILLINOIS GAS AND ELECTRIC COMPANY C. J. MATH (March 31, 1972) Vice President IOWA POWER AND LIGHT COMPANY D. H. SWANSON (March 31, 1972) President IOWA PUBLIC SERVICE COMPANY F. W. GRIFFITH (March 31, 1972) Chairman and President IOWA SOUTHERN UTILITIES COMPANY R. F. BREWER (March 31, 1972) President LINCOLN ELECTRIC SYSTEM WALTER A. CANNEY (December 1, 1977) Administrator MINNESOTA POWER J. F. ROWE (March 31, 1972) Executive Vice President MINNKOTA POWER COOPERATIVE, INC. TED M. LEE (March 31, 1972) President MISSOURI BASIN MUNICIPAL POWER AGENCY RUSSELL DAU (March 12, 1980) General Manager MONTANA-DAKOTAS UTILITIES CO. DAVID M. HESKETT (March 31, 1972) President MUSCATINE POWER & WATER JAMES P. FULLER (March 19, 1976) General Manager NEBRASKA PUBLIC POWER DISTRICT DON E. SCHAUFELBERGER (March 31, 1972) Deputy General Manager NORTHERN STATES POWER COMPANY EDWARD C. SPETHMANN (March 31, 1972) Vice President - Public Affairs NORTHWEST IOWA POWER COOPERATIVE CARL PAULSON (November 26, 1979) Exec. Vice President and General Manager NORTHWESTERN PUBLIC SERVICE COMPANY A. D. SCHMIDT (March 31, 1972) President OMAHA PUBLIC POWER DISTRICT A. L. MONROE (March 31, 1972) General Manager OTTER TAIL POWER COMPANY DONALD F. VRASPIR (December 27, 1979) Vice President SOUTHERN MINNESOTA MUNICIPAL POWER PIERRE HEROUX AGENCY (November 1, 1982) Executive Director UNITED POWER ASSOCIATION (May 1, 1972) THE UNITED STATES OF AMERICA H. E. ALDRICH (March 31, 1972) Regional Director, Region 6 U.S. Bureau of Reclamation SIGNATORY ASSOCIATE PARTICIPANTS AMES MUNICIPAL ELECTRIC SYSTEM MERLIN C. HOVE (January 5, 1983) Director CEDAR FALLS, IOWA LEONARD J. KEEFE (March 31, 1972) Cedar Falls Utilities Board of Trustees CUMBERLAND MUNICIPAL UTILITY CHARLES CHRISTENSEN (December 30, 1982) Manager DELANO, MINNESOTA LAURENCE RIEDER (March 31, 1972) Mayor FREMONT, NEBRASKA MILTON LAUNER (January 9, 1980) Assistant General Manager GLENCOE, MINNESOTA DONALD A. NELSON (March 31, 1972) Secretary Light & Power Commission GRAND ISLAND, NEBRASKA R. J. OLSON (September 6, 1977) Director of Utility Operation HARLAN MUNICIPAL UTILITIES F. JAMES KALAL (July 14, 1983) General Manager MADELIA, MINNESOTA C. W. SEIBERT (March 31, 1972) Commissioner Public Utilities Commission MUNICIPAL ENERGY AGENCY OF NEBRASKA H. STEVE WACKER (June 26, 1979) General Manager NORTH IOWA MUNICIPAL ELECTRIC RONALD L. DEIBER COOPERATIVE ASSOCIATION (March 9, 1982) President NORTHWESTERN WISCONSIN ELECTRIC CO. FRED E. DAHLBERG (March 31, 1972) President OWATONNA, MINNESOTA TY SINCOCK (November 1, 1972) President Municipal Public Utilities ROCHESTER, MINNESOTA R. JOHN MINER (January 2, 1980) Director SASKATCHEWAN POWER CORPORATION K. D. WELLMAN (February 10, 1981) Corporate Legal Counsel WISCONSIN PUBLIC POWER, INC. David Penn (November 2, 1990) General Manager MID-CONTINENT AREA POWER POOL Service Schedule A Participation Power Interchange Service Section 1. Service to be Provided 1.01 This Schedule provides for the sale of Participation Power by a Participant to any other Participant from a specific generating unit or units. Participation Power shall mean power and energy which is sold from a specific generating unit or units on the basis that it is continuously available except when such unit or units are temporarily out of service for maintenance during which time the delivery of energy from other sources shall be at the seller's option. Section 2. Conditions of Service 2.01 This Schedule shall be available for the sale of Participation Power for a period of six months or more. 2.02 Participation Power shall be supplied through transmission facilities which have adequate capacity for transmitting such power and energy, and Transmission Service shall be arranged in accordance with the procedures established under Service Schedule "F." 2.03 FERC-regulated Participants who enter into transactions to sell power under this schedule shall file the applicable agreement with the FERC as a rate schedule. Section 3. Schedule of Rates 3.01 The rate and term for Participation Power under this Service Schedule "A" shall be negotiated by the Participants arranging the transaction. 3.02 In the event that service cannot be supplied on the effective date of an Agreement to sell Participation Power under this Service Schedule "A" due to a delayed in-service date of the associated generating facilities, the demand charge to be paid by the purchasing Participant shall not be effective until the date such facilities are included as Accredited Capability. 3.03 The Transmission Service charge and losses provisions of Service Schedule "F" shall also apply. Service Schedule B Seasonal Participation Power Interchange Service Section 1. Service to be Provided 1.01 This Schedule provides for the sale of Seasonal Participation Power by any Participant to any other Participant from a specific generating unit. Seasonal Participation Power shall mean power and energy which is sold from a base load unit on the basis that it is continuously available except when such unit is temporarily out of service for maintenance during which time the delivery of energy from other sources shall be at the seller's option. Section 2. Conditions of Service 2.01 This Schedule shall be available for the sale of Seasonal Participation Power for six consecutive months beginning on May 1 or November 1 unless other dates are agreed to by the Engineering Committee. 2.02 Seasonal Participation Power shall be supplied through transmission facilities which have adequate capacity for transmitting such power and energy, and Transmission Service shall be arranged in accordance with the procedures established under Service Schedule "F." Section 3. Schedule of Rates 3.01 The receiving Participant shall pay to the supplying Participant for Seasonal Participation Power furnished during any month under this Schedule an amount determined from the following schedule of rates: Demand Charge: For each megawatt or fraction thereof committed by the supplier, a charge per month not more than P, where P = A ___ 12 where A = the value for the applicable year based on ten (10) years of data representing the composite levelized annual fixed charges per megawatt for the units of the Participants which supplied, or are most likely to supply capacity and energy under this Schedule. For each FERC regulated Participant, the levelized annual fixed carrying charge would be the sum of the return requirement, depreciation, income tax, property tax and administrative and general costs. The return requirement shall be calculated in accordance with standard FERC methods using debt costs, preferred stock cost and a percentage rate of return on equity, weighted in accordance with the Participant's capital ratios at the end of the preceding calendar year. The percentage rate of return on equity shall be the FERC benchmark rate of return on equity percentage, which shall be filed annually with the FERC. The income tax requirement which shall include deferred taxes, shall be calculated in accordance with standard FERC methods using federal and state tax rates in effect for the current year. The administrative and general costs in column b on line 167 of page 323 of the FERC Form 1 shall be appropriately allocated to the electric production plant and converted to a percentage of the electric production plant investment. Appendix 1 describes the calculation of the demand charge for this Service Schedule. Participants not regulated by the FERC will file a comparable, reasonable levelized annual carrying charge with the MAPP Coordination Center for use in this calculation. Energy Charge: a. For all energy supplied from the assigned generating unit, a charge per kilowatt-hour of 110 percent of Average Production Cost for the month of the assigned generating unit, for both the energy delivered to the receiving Participant and the energy supplied by the supplying Participant to any intervening Participant or Participants as compensation for losses. b. For all energy supplied when the assigned generating unit is temporarily out of service for maintenance, a charge per kilowatt-hour of 110 percent of Incremental Cost of supplying such energy, for both the energy delivered to the receiving Participant and the energy supplied by the supplying Participant to any intervening Participant or Participants as compensation for losses. c. The percentage adder components contained in the third-party purchase and resale provisions of this rate schedule are hereby limited to recover no more than: i. The FERC Order 84 adder for each FERC- regulated Participant. The FERC Order 84 adder for each FERC-regulated Participant is shown on Appendix 6 to this Agreement. FERC-regulated Participants shall provide the FERC and the MAPP Coordination Center with a revised Appendix 6 whenever a change to their Order 84 adder is filed with the FERC. ii. A value on file at the MAPP Center for Participants not regulated by the FERC. 3.02 In the event that service cannot be supplied on the effective date of an agreement to sell Seasonal Participation Power under this Service Schedule "B" due to a delayed in- service date of the associated generating facilities, the demand charge to be paid by the purchasing Participant shall not be effective until the date such facilities are included as Accredited Capability. 3.03 The Transmission Service charge and losses provisions of Service Schedule "F" shall also apply. Service Schedule C Emergency and Scheduled Outage Energy Interchange Service Section 1. Service to be Provided 1.01 This Schedule provides for the supply of energy by any Participant to any other Participant during Emergency Outages or Scheduled Outages for maintenance of generating or transmission facilities or both. Section 2. Scheduling of Deliveries 2.01 Deliveries of Emergency Energy shall be scheduled as soon as possible after the occurrence of an Emergency Outage in accordance with principles and practices established by the Operating Committee. Transmission Service for Emergency Energy shall be available in accordance with the procedures established under Service Schedule "F." 2.02 Scheduled Outage Energy may be scheduled from a Participant not directly interconnected providing such energy is available at a lower delivered cost than from a directly interconnected Participant. Transmission Service for Scheduled Outage Energy shall be available in accordance with the procedures established under Service Schedule "F." Section 3. Schedule of Rates 3.01 The receiving Participant shall pay to the supplying Participant for Emergency Energy furnished during any month under this Schedule the greater of 3.0 cents per kilowatt-hour or 110 percent of the supplying Participant's Incremental Cost of supplying such energy. 3.02 The receiving Participant shall compensate the supplying Participant for Scheduled Outage Energy furnished during any month under this Schedule in accordance with one of the following subparagraphs: a. The receiving Participant shall pay to the supplying Participant for such Scheduled Outage Energy an amount of whichever is the greater: i. 110 percent of the Incremental Cost of producing such energy, or ii. 110 percent of the average cost of the receiving Participant had it produced such energy with the generating unit which is out of service, which average cost shall include but not be limited to fuel cost and operation and maintenance cost; provided that, if the receiving Participant is not using its Total Available Accredited Capability, the supplying Participant may require the receiving Participant to make an additional payment for any financial loss that accrues to the supplying Participant due to this transaction replacing a sale to another party. For uniformity of application, such additional payment should be calculated assuming that the decremental cost of the other sale would have been an amount equal to the cost of energy from oil- fired generation determined in accordance with principles and practices established by the Operating Committee as follows: The cost of oil-fired generation will be calculated using the least-squares method based on a maximum of seven years' data. For FERC regulated Participants, the data used will be the sum of fuel, operation and maintenance costs divided by net KWH (where net generation is sufficient to demonstrate true operating costs) which is line 35 on page 402 and columns e, h, i and o on pages 410 and 411 of the FERC Form 1. Participants not regulated by the FERC will provide comparable data when cost data is requested for filing at the MAPP Coordination Center. b. The Participant supplying Scheduled Outage Energy may, at its option, require the receiving Participant to return such energy at such times and under such conditions that the supplying Participant will not experience a loss due to the transaction, or under conditions mutually agreeable to both Participants. 3.03 The Transmission Service charge and losses provisions of Service Schedule "F" shall also apply to Scheduled Outage Energy transactions. The Transmission Service charge and losses provisions of Service Schedule "F" shall not apply to Emergency Energy transactions. Service Schedule D Operating Reserve Interchange Service Section 1. Service to be Provided 1.01 A Participant may arrange for some other Participant to supply part or all of its Operating Reserve requirement. Section 2. Scheduling of Rates (See Note No. 1) 2.01 Except as otherwise agreed to by the Participants concerned, a Participant supplying a portion or all of some other Participant's Operating Reserve during any month shall be paid by the purchasing Participant an amount of whichever is greater of the following: a. 110 percent of the incremental cost of supplying such service, or b. The incremental cost of supplying such service plus one-half of the overall savings of such transaction, where overall savings shall be equal to the difference between the incremental cost of the selling Participant and the decremental cost of the purchasing Participant. 2.02 In the event there are repetitive transactions between certain Participants involving similar incremental and decremental costs, flat rates or an exchange arrangements may be established for such transactions by the representatives of the Participants concerned. Note No. 1 Incremental and Decremental Cost for the purpose of this schedule only, shall be determined as follows: Incremental cost of the supplying Participant shall be based on the costs incurred in starting and/or operating any generating unit or units which must be started as a result of supplying such service. Decremental cost of the purchasing Participant shall be based on the cost avoided by not starting and/or operating any generator unit or units as a result of receiving such service. Service Schedule E Economy Energy Interchange Service Section 1. Service to be Provided 1.01 This Schedule provides for the supply of Economy Energy by any Participant to any other Participant when it is economical and practical to do so under the conditions set forth hereinafter and in Paragraph 20.07 of the Agreement. Section 2. Conditions of Service 2.01 It is the intent hereof that, insofar as is practicable, Economy Energy from available sources having the lowest Incremental Costs shall be used to displace generation having the highest Decremental Costs and so on until such transactions are no longer economical; provided that such transactions are not scheduled in amounts which will overload any transmission facility or endanger the operation of the interconnected systems. 2.02 Transmission Service shall be available in accordance with the procedures established under Service Schedule "F." Section 3. Scheduling of Deliveries 3.01 Prior to beginning deliveries, the Participants involved will agree on an hour-by-hour schedule of energy to be delivered. Section 4. Schedule of Rates 4.01 The overall savings of an Economy Energy transaction shall be equal to the difference between the Incremental Cost of the supplying Participant and the Decremental Cost of the receiving Participant. If the transmission system of a non- Participant is involved in an Economy Energy transaction, any transmission fees and losses to be paid for the use of such system shall be deducted from the overall savings in determining the net savings of the transactions. 4.02 The receiving Participant shall pay the supplying Participant for the Economy Energy supplied during each month, an amount equal to the Incremental Cost of the energy so supplied, plus one-half of the net savings of such transactions which remain after deducting the amount paid by the receiving Participant to any parties providing transmission service in accordance with Paragraph 4.01 herein and with Service Schedule "F." 4.03 The Transmission Service charge and losses provisions of Service Schedule "F" shall also apply. Service Schedule F Transmission Services and Losses Section 1. Service to be Provided 1.01 This Schedule provides for Transmission Service in connection with Coordination Transactions scheduled between Participants, or scheduled between a Participant and another utility, in a non-Participant Control Area, with which the Participant has a direct interconnection or has rights to deliver or receive power and energy at such an interconnection. 1.02 This Service Schedule shall not be used for and will not be applied to provide Transmission Service to deliver power and energy from generation owned or leased by a Participant or from which a Participant purchases power and energy pursuant to life-of-unit contracts, to serve load which that Participant has an obligation under law or contract to supply (including preference customers in the case of the United States). This Service Schedule shall also not be used for and will not be applied to provide for Transmission Service to deliver power and energy to an ultimate consumer. 1.03 Service Schedule "F" shall be applicable to transactions, to which a Participant is a party, of four years (eight full seasons) or less from the date notice of the transaction is given to the MAPP Center in accordance with the procedures established by the applicable committee. Transmission Service under Service Schedule "F" may be used for portions of longer term transactions, but only to the extent any such portion occurs within four years (eight full seasons) of the date notice of the transaction is given to the MAPP Center. The eight full seasons are the eight consecutive seasons immediately following notification of the MAPP Center of the transaction, assuming notification is provided before the first season. To the extent the transaction occurs during the first season, the eight seasons shall consist of that season and the following seven seasons. Section 2. Conditions of Service 2.01 Transmission Service for transactions under Service Schedules "A", "B", "H", "I", "J", and "K", and any other capacity transactions, shall be arranged in accordance with procedures established by the Engineering Committee. Transmission Service for transactions under Service Schedules "C", "E", "G", "L", and "M", and any other energy-only transactions, shall be available in accordance with procedures established by the Operating Committee. There shall be no Transmission Service charge applicable to Emergency Energy transactions under Service Schedule "C". 2.02 Nothing contained in this Service Schedule "F" or in the procedures established by the appropriate committee pursuant to Section 2.01 shall be interpreted to require a Party to install or upgrade transmission facilities or to redispatch its generation in order to enable Transmission Service to be arranged or made available for prospective transactions. 2.03 Available transmission capacity for MAPP Service Schedule "F" shall be determined on an integrated system basis considering the combined transfer capability of all Participants' transmission systems. If requests for transmission capacity exceed the available transmission capacity, the available transmission capacity will be allocated under procedures established by the Engineering and Operating Committees. Section 3. Compensation 3.01 Each Participant who provides Transmission Service utilizing transmission facilities of 115kV and higher, except for Service Schedule C Emergency Energy transactions, shall be entitled to compensation in accordance with the Transmission Service charge formulae and methodology set forth in Appendix 7. Participants whose 69kV transmission facilities meet the criteria set forth in Appendix 7 for inclusion in such formulae and methodology of the investments in and flows through such facilities shall also be entitled to compensation in accordance with Appendix 7. 3.02 The buyer shall pay for Transmission Service, unless the buyer is a non-Participant, in which case the selling Participant pays. 3.03 Whenever a Participant schedules the delivery of power and energy pursuant to this Agreement, the amount of power and energy to be furnished to the other Participants as compensation for losses shall be determined in accordance with formulae established by the Operating Committee. Service Schedule G Operational Control Energy Interchange Service Section 1. Service to be Provided 1.01 This Schedule provides for the supply of Operational Control Energy by any Participant to any other Participant to improve electric system control and reliability. 1.02 This Schedule also provides for the supply of energy by any Participant to any other Participant for resale to another electric supplier, not signatory hereto, to enable such other supplier to meet emergency conditions on its own system. Section 2. Conditions of Service 2.01 Operational Control Energy shall not be used in lieu of energy available under any other Service Schedule and shall not be considered in the determination of a Participant's Accredited Capability. 2.02 Transmission Service shall be available in accordance with the procedures established under Service Schedule "F." Section 3. Schedule of Rates 3.01 For all energy supplied under Paragraph 1.01 herein, the receiving Participant shall pay to the supplying Participant for Operational Control Energy, furnished during any month under this Schedule, 110 percent of the Incremental Cost of the supplying Participant when the transaction is initiated by the receiving Participant for its benefit or ninety percent (90%) of the Decremental Cost of the receiving Participant when the transaction is initiated by the supplying Participant for its benefit. The percentage adder components contained in the third- party purchase and resale provisions of this rate schedule are hereby limited to recover no more than: i. The FERC Order 84 adder for each FERC-regulated Participant. The FERC Order 84 adder for each FERC- regulated Participant is shown on Appendix 6 to this Agreement. FERC-regulated Participants shall provide the FERC and the MAPP Coordination Center with a revised Appendix 6 whenever a change to their Order 84 adder is filed with the FERC. ii. A value on file at the MAPP Center for Participants not regulated by the FERC. 3.02 For all energy supplied during any month under Paragraph 1.02, the receiving Participant shall pay to the supplying Participant the rate in effect under Service Schedule "C," Paragraph 3.01. 3.03 The Transmission Service charge and losses provisions of Service Schedule "F" shall also apply. Service Schedule H Peaking Power Interchange Service Section 1. Service to be Provided 1.01 This Schedule provides for the sale of Peaking Power by any Participant to any other Participant. Peaking Power shall mean power and associated energy intended to be available at all times during the period covered by a commitment and which is sold with anticipated low load factor use. Such power shall include required reserve capacity. Section 2. Conditions of Service 2.01 This Schedule shall be available for the sale of Peaking Power for a period of six consecutive months beginning on May 1 or November 1 unless other dates are agreed to by the Engineering Committee. 2.02 Peaking Power shall be supplied through transmission facilities which have adequate capacity for transmitting such power and energy, and Transmission Service shall be arranged in accordance with the procedures established under Service Schedule "F." 2.03 The supplying Participant shall guarantee that Peaking Power purchased hereunder shall be available to the receiving Participant on at least a twenty percent (20%) monthly capacity factor. The supplying Participant of such Peaking Power may limit delivery of energy, above the guaranteed amount. The capacity factor set forth herein shall be subject to change by the Engineering Committee from time to time. Section 3. Schedule of Rates 3.01 The receiving Participant shall pay to the supplying Participant for Peaking Power furnished during any month under this Schedule an amount determined from the following schedule of rates: Demand Charge: For each megawatt or fraction thereof committed by the supplying Participant, a charge per month not more than the greater of: i. Q, where Q = B ___ 12 where B = a value based on all Participant's current levelized annual fixed charges per megawatt for their total peaking generating capacity, or ii. $2,000 For each FERC regulated Participant, the levelized annual fixed carrying charge would be the sum of the return requirement, depreciation, income tax, property tax and administrative and general costs. The return requirement shall be calculated in accordance with standard FERC methods using debt costs, preferred stock cost and a percentage rate of return on equity, weighted in accordance with the Participant's capital ratios at the end of the preceding calendar year. The percentage rate of return on equity shall be the FERC benchmark rate of return on equity percentage which shall be filed annually with the FERC. The income tax requirement, which shall include deferred taxes, shall be calculated in accordance with standard FERC methods using federal and state tax rates in effect for the current year. The administrative and general costs in column b on line 167 of page 323 of the FERC Form 1 shall be appropriately allocated to the electric production plant and converted to a percentage of the electric production plant investment. Appendix 2 describes the calculation of the demand charge for this Service Schedule. Participants not regulated by the FERC will file a comparable, reasonable levelized annual carrying charge with the MAPP Coordination Center for use in this calculation. Energy Charge: For all energy supplied hereunder, a charge per kilowatt- hour of 110 percent of the Incremental Cost of producing or purchasing such energy, whichever is less, for both the energy delivered to the purchasing Participant and the energy supplied by the supplying Participant to any intervening Participant or Participants as compensation for losses. The percentage adder components contained in the third- party purchase and resale provisions of this rate schedule are hereby limited to recover no more than: i. The FERC Order 84 adder for each FERC-regulated Participant. The FERC Order 84 adder for each FERC- regulated Participant is shown on Appendix 6 to this Agreement. FERC-regulated Participants shall provide the FERC and the MAPP Coordination Center with a revised Appendix 6 whenever a change to their Order 84 adder is filed with the FERC. ii. A value on file at the MAPP Coordination Center for Participants not regulated by the FERC. In the event it is desired by the Participants involved, an exchange arrangement may be established by the representatives of the Parties concerned. The supplying Participant of Peaking Power may, at its option, require the return of any energy delivered above the guaranteed monthly capacity factor at such times and under such conditions as agreed to by representatives of the Participants concerned. 3.02 The Transmission Service charge and losses provisions of Service Schedule "F" shall also apply. Service Schedule I Short Term Power Interchange Service Section 1. Service to be Provided 1.01 This Schedule provides for the sale of Short Term Power by any Participant to any other Participant. Short Term Power shall mean power and associated energy intended to be available at all times during the period covered by a commitment. Such power shall include required reserve capacity. Section 2. Conditions of Service 2.01 This Schedule shall be available for the sale of Short Term Power for periods of seven or more consecutive days each. 2.02 Short Term Power shall be included in the Accredited Capability of a Participant only under special conditions, such as: a. In an instance where a significant new industrial customer load is imposed upon a Participant's system at a time different from the purchase period for which other schedules are applicable. b. In an instance where a generator or transmission line addition does not meet the scheduled in-service date. c. In an instance where it is being purchased for resale to an electric supplier who is not a Participant. d. In an instance where a Participant's October system demand is forecast to exceed the maximum system demand of the previous five months. 2.03 Short Term Power shall be supplied through transmission facilities which have adequate capacity for transmitting such power and energy, and Transmission Service shall be arranged in accordance with the procedures established under Service Schedule "F." Section 3. Schedule of Rates 3.01 The receiving Participant shall pay to the supplying Participant for Short Term Power furnished during any month under this Schedule an amount determined from the following schedule of rates: Demand Charge: For each megawatt or fraction thereof committed by the supplying Participant, a charge per day not more than the greater of: i. R, where R = B ___ 365 where B = a value based on all Participants' current levelized annual fixed charges per megawatt for their total peaking generating capacity, or ii. $66 For each FERC regulated Participant, the levelized annual fixed carrying charge would be the sum of the return requirement, depreciation, income tax, property tax and administrative and general costs. The return requirement shall be calculated in accordance with standard FERC methods using debt costs, preferred stock cost and a percentage rate of return on equity, weighted in accordance with the Participant's capital ratios at the end of the preceding calendar year. The percentage rate of return on equity shall be the FERC benchmark rate of return on equity percentage, which shall be filed annually with the FERC. The income tax requirement, which shall include deferred taxes, shall be calculated in accordance with standard FERC methods using federal and state tax rates in effect for the current year. The administrative and general costs in column b on line 167 of page 323 of the FERC Form 1 shall be appropriately allocated to the electric production plant and converted to a percentage of the electric production plant investment. Appendix 3 describes the calculation of the demand charge for this Service Schedule. Participants not regulated by the FERC will file a comparable, reasonable levelized annual carrying charge with the MAPP Coordination Center for use in this calculation. Energy Charge: For all energy supplied hereunder, a charge per kilowatt- hour of 110 percent of the Incremental Cost of supplying such energy, for both the energy delivered to the receiving Participant and the energy supplied by the supplying Participant to any intervening Participant or Participants as compensation for losses. The percentage adder components contained in the third-party purchase and resale provisions of this rate schedule are hereby limited to recover no more than: i. The FERC Order 84 adder for each FERC-regulated Participant. The FERC Order 84 adder for each FERC- regulated Participant is shown on Appendix 6 to this Agreement. FERC-regulated Participants shall provide the FERC and the MAPP Coordination Center with a revised Appendix 6 whenever a change to their Order 84 adder is filed with the FERC. ii. A value on file at the MAPP Center for Participants not regulated by the FERC. 3.02 The Transmission Service charge and losses provisions of Service Schedule "F" shall also apply. 3.03 For any Short Term Capacity which the supplying Participant procures from electric suppliers not signatory hereto for delivery to the receiving Participant, the receiving Participant shall pay to the supplying Participant the cost of procuring such capacity and 110 percent of the cost of procuring such energy, but not less than the rates specified herein, in addition to compensation as set forth in Service Schedule "F." Service Schedule J Firm Power Interchange Service Section 1. Service to be Provided 1.01 This Schedule provides for the sale of Firm Power by any Participant to any other Participant. Firm Power shall mean power and associated energy intended to be available at all times during the period covered by a commitment. Such power shall include required reserve capacity. Section 2. Conditions of Service 2.01 Firm Power shall be supplied through transmission facilities which have adequate capacity for transmitting such power and energy, and Transmission Service shall be arranged in accordance with the procedures established under Service Schedule "F." 2.02 This Schedule shall be available for the sale of Firm Power for a period of six months or longer. 2.03 FERC-regulated Participants who enter into transactions to sell power under this schedule shall file the applicable agreement with the FERC as a rate schedule. Section 3. Schedule of Rates 3.01 The rate and term for Firm Power shall be negotiated by the Participants to each transaction. 3.02 The Transmission Service charge and losses provisions of Service Schedule "F" shall also apply. Service Schedule K System Participation Power Interchange Service Section 1. Service to be Provided 1.01 This Schedule provides for the sale of System Participation Power by any Participant to any other Participant for a specified period for the purpose of obtaining a supply of power which can be depended upon with the same degree of assurance as that expected from the Purchaser's own generating capacity, but which does not include reserve capacity. Section 2. Conditions of Service 2.01 This Schedule shall be available for the sale of System Participation Power for periods of seven or more consecutive days. 2.02 System Participation Power is intended to be available at all times during the period covered by the commitment; provided, however, that in the event conditions arise during the period covered by the commitment which in the sole judgment of the supplying Participant would otherwise require curtailment of firm power sales or service to its own customers, the supplying Participant has the right to notify and require the receiving Participant to reduce its take of such energy to any amount specified and for any portion of the term of the commitment and the receiving Participant shall promptly comply with the decision of the supplying Participant. 2.03 System Participation Power shall be included in the Accredited Capability of a Participant only under the following conditions: a. In an instance where it is being purchased for resale to an electric supplier who is not a Participant. b. In an instance where a Participant purchases power under this schedule for a period of six consecutive months beginning May 1 or November 1 or such other dates as are agreed to by the Management Committee. 2.04 System Participation Power shall be supplied through transmission facilities which have adequate capacity for transmitting such power and energy, and Transmission Service shall be arranged in accordance with the procedures established under Service Schedule "F". Section 3. Schedule of Rates 3.01 The receiving Participant shall pay to the supplying Participant for System Participation Power furnished during any period under this Schedule an amount determined from the following schedule of rates: Demand Charge: For each megawatt or fraction thereof committed by the supplying Participant, a charge per week of not more than S, where S = C ___ 52 where C = a value based on all Participants' current levelized annual fixed charges per megawatt for their total thermal generating capacity excluding cogeneration, provided however, that should delivery of System Participation Power be curtailed by the supplying Participant, the demand charge shall be reduced by one- sixth per megawatt of curtailment for each day during which there is a curtailment, but such reduction shall not exceed the demand charge for the reservation period. For each FERC regulated Participant, the levelized annual fixed carrying charge would be the sum of the return requirement, depreciation, income tax, property tax and administrative and general costs. The return requirement shall be calculated in accordance with standard FERC methods using debt costs, preferred stock cost and a percentage rate of return on equity, weighted in accordance with the Participant's capital ratios at the end of the preceding calendar year. The percentage rate of return on equity shall be the FERC benchmark rate of return on equity percentage, which shall be filed annually with the FERC. The income tax requirement which shall include deferred taxes, shall be calculated in accordance with standard FERC methods using federal and state tax rates in effect for the current year. The administrative and general costs in column b on line 167 of page 323 of the FERC Form 1 shall be appropriately allocated to the electric production plan and converted to a percentage of the electric production plant investment. Appendix 4 describes the calculation of the demand charge for this Service Schedule. Participants not regulated by the FERC will file a comparable, reasonable levelized annual carrying charge with the MAPP Coordination Center for use in this calculation. Energy Charge: For all energy supplied hereunder, a charge per kilowatt- hour of 110 percent of the Incremental Cost of supplying such energy, for both the energy delivered to the receiving Participant and the energy supplied by the supplying Participant to any intervening Participant or Participants as compensation for losses. The percentage adder components contained in the third- party purchase and resale provisions of this rate schedule are hereby limited to recover no more than: i. The FERC Order 84 adder for each FERC-regulated Participant. The FERC Order 84 adder for each FERC- regulated Participant is shown on Appendix 6 to this Agreement. FERC-regulated Participants shall provide the FERC and the MAPP Coordination Center with a revised Appendix 6 whenever a change to their Order 84 adder is filed with the FERC. ii. A value on file at the MAPP Coordination Center for Participants not regulated by the FERC. 3.02 The Transmission Service charge and losses provisions of Service Schedule "F" shall also apply. 3.03 For any System Participation Capacity which the supplying Participant procures from electric suppliers not signatory hereto for delivery to the receiving Participant, the receiving Participant shall pay to the supplying Participant the cost of procuring such capacity at cost and such associated energy cost at 110 percent of the cost of procuring such energy, in addition to wheeling and loss compensation as set forth in Service Schedule "F." Service Schedule L Interruptible Load Replacement Energy Service Section 1. Services to be Provided 1.01 This Schedule provides for the supply of Interruptible Load Replacement Energy by any Participant to any other Participant when it is economical and practical to do so under the conditions set forth hereinafter and in Paragraph 20.08 of this Agreement. Section 2. Conditions of Service 2.01 It is the intent that Interruptible Load Replacement Energy may be used by Participants to serve interruptible load when that load would otherwise be interrupted. a. In order to be eligible for Interruptible Load Replacement Energy Service, the purchasing Participant must report in advance monthly quantities of Certified Interruptible Demand. b. The rate of delivery of energy supplied under this schedule in any hour shall not exceed the purchasing Participant's Certified Interruptible Demand. c. Deliveries of energy may be received under this schedule only when a Participant's maximum System Demand would otherwise be greater than the Participant's forecast System Demand for the current season and shall not exceed that required to reduce the System Demand to the forecast System Demand. d. Interruptible Load Replacement Energy Service shall not be scheduled in amounts which will overload any transmission facilities or endanger the operation of the interconnected systems of the Participants. e. Interruptible Load Replacement Energy Service transactions between Participants which are directly interconnected shall normally take precedence over transactions between Participants not directly interconnected unless cost differential exceeds the Operating Committee guidelines. 2.02 Transmission Service shall be available in accordance with the procedures established under Service Schedule "F." Section 3. Scheduling Deliveries 3.01 Prior to the scheduling of deliveries, the Participants concerned, including the wheeling Participant or Participants, if any, will agree on hour-by-hour amounts of energy to be delivered. Section 4. Schedule of Rates 4.01 The overall savings of an Interruptible Load Replacement Energy Service transaction shall be equal to the difference between the Incremental Cost of the supplying Participant and the Displaced Cost of the receiving Participant where Displaced Cost shall be determined as in Section 4.04 following. If the transmission facilities of a system not a party hereto is involved in an Interruptible Load Replacement Energy transaction, any transmission fees and losses to be paid for the use of such facilities, shall be deducted from the overall savings of the transactions in determining the net savings of the transactions. 4.02 The receiving Participant shall pay the supplying Participant for the energy supplied during each month an amount equal to the Incremental Cost of the energy so supplied, plus one-half of the overall savings of such transactions. However, the amount paid by the receiving Participant shall not be less than 110 percent of the supplying Participant's Incremental Cost. 4.03 When the receiving Participant's Displaced Cost equals or is lower than the supplying Participants Incremental Cost, transactions may occur with the price being the minimum specified in Paragraph 4.02. 4.04 The Displaced Cost per kilowatt-hour to be used under this schedule shall be determined as the total revenues received in the prior 12 months from retail customers whose load is associated with the Interruptible Load Replacement Energy to be purchased, divided by the kilowatt-hours of energy supplied those customers over the same period. Participants that supply wholesale loads which are associated with Interruptible Load Replacement Energy to be purchased under this schedule shall utilize the revenues received by the retail supplier(s) for the energy supplied these customers in the computation of the Displaced Cost. Service Schedule M General Purpose Energy Service Section 1. Service to be Provided 1.01 This Schedule provides for the supply of General Purpose Energy by any Participant to any other Participant to enhance economic system operation. Section 2. Conditions of Service 2.01 It is the intent hereof that, insofar as is practicable, General Purpose Energy shall be used to improve the overall economy of the systems involved in the transactions; provided that such transactions are not scheduled in amounts which will overload any transmission facility or endanger the operation of the interconnected systems. 2.02 Transmission Service shall be available in accordance with the procedures established under Service Schedule "F." Section 3. Scheduling of Deliveries 3.01 Prior to beginning deliveries, the Participants involved will agree on the terms of the transaction and on an hour-by-hour schedule of energy to be delivered. Section 4. Schedule of Rates 4.01 The receiving Participant shall pay the supplying Participant for the General Purpose Energy supplied a charge of up to 110 percent of the anticipated Incremental Cost of supplying such energy, plus an additional charge per megawatt- hour of up to S/96, where S is the weekly demand charge for System Participation Power Interchange Service as specified in Service Schedule K, Section 3 and, 96 is the number of on-peak hours for a given week. This additional charge shall not exceed S/6 multiplied by the highest number of megawatt-hours delivered in any one hour during that day, where 6 is the number of days in a week containing on-peak hours. The total charge for each transaction shall not be less than 100 percent of the Incremental Cost of supplying the energy for the transaction. 4.02 The Transmission Service charge and losses provisions of Service Schedule "F" shall also apply. EX-27 3
UT EXHIBIT 27.01 This schedule contains summary financial information extracted from the Consolidated Statements of Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows and is qualified in its entirety by reference to such financial statements. 1,000 3-MOS DEC-31-1995 MAR-31-1996 PER-BOOK 4,321,430 691,013 837,678 365,265 165,828 6,381,214 171,250 614,817 1,284,516 2,066,267 0 240,469 1,667,951 577 0 168,500 156,689 0 0 0 2,076,445 6,381,214 718,709 36,637 588,766 629,432 89,277 5,143 98,449 31,239 67,210 3,061 64,149 45,660 27,271 219,146 $0.94 0 $4,029 thousand of non-operating income tax benefit is classified as Income Tax Expense. The financial statement presentation includes this as a component of Other Income (Expense). $(4,316) thousand of Common Stockholders' Equity is classified as Other Items-Capitalization and Liabilities. This represents the net of leveraged common stock held by the Employee Stock Ownership Plan and the currency translation adjustments.
EX-99 4 EXHIBIT 99.01 Northern States Power Company Cautionary Factors The Private Securities Litigation Reform Act of 1995 provides a new "safe harbor" for forward-looking statements to encourage such disclosures without the threat of litigation providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward- looking statements have been and will be made in written documents and oral presentations of Northern States Power Company (the Company). Such statements are based on management's beliefs as well as assumptions made by and information currently available to management. When used in the Company's documents or oral presentations, the words "anticipate", "estimate", "expect", "objective" and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Company's actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following: - - Economic conditions including inflation rates and monetary fluctuations; - - Trade, monetary, fiscal, taxation, and environmental policies of governments, agencies and similar organizations in geographic areas where the Company has a financial interest; - - Customer business conditions including demand for their products or services and supply of labor and materials used in creating their products and services; - - Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities and Exchange Commission, the Federal Energy Regulatory Commission and similar entities with regulatory oversight; - - Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, the Company or any of its subsidiaries; or security ratings; - - Factors affecting utility and non-utility operations such as unusual weather conditions; catastrophic weather- related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, nuclear fuel or gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; nuclear or environmental incidents; or electric transmission or gas pipeline system constraints; - - Employee workforce factors including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages; - - Increased competition in the utility industry, including: industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market; - - Rate-setting policies or procedures of regulatory entities, including environmental externalities; - - Nuclear regulatory policies and procedures including operating regulations and used nuclear fuel storage; - - Social attitudes regarding the utility and power industries; - - Cost and other effects of legal and administrative proceedings, settlements, investigations and claims; - - Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets; - - Numerous matters associated with the proposed combination of the Company and Wisconsin Energy Corporation to form Primergy Corporation (Primergy), including: - Regulatory authorities' decisions regarding business combination issues including the approval of the business combination as proposed, the rate structure of utility operating companies after the merger, transmission system operation and administration, or divestiture of gas utility or non-regulated portions of the Company's business; - Qualification of the transaction as a pooling of interests; - Factors affecting the anticipated cost savings including national and regional economic conditions, national and regional competitive conditions, inflation rates, weather conditions, financial market conditions, and synergies resulting from the business combination; - Allocation of benefits of cost savings between shareholders and customers, which will depend, among other things, upon the results of regulatory proceedings in various jurisdictions; - Regulation of Primergy as a registered public utility holding company and other different or additional federal and state regulatory requirements or restrictions to which Primergy and its subsidiaries may be subject as a result of the business combination (including conditions which may be imposed in connection with obtaining the regulatory approvals necessary to consummate the business combination, such as the possible requirement to divest gas utility and possibly certain non-regulated operations); - Factors affecting dividend policy including results of operations and financial condition of Primergy and its subsidiaries and such other business considerations as the Primergy Board of Directors considers relevant. - - Factors associated with non-regulated investments including conditions of final legal closing, foreign government actions, foreign economic and currency risks, political instability in foreign countries, partnership actions, competition, operating risks, dependence on certain suppliers and customers, domestic and foreign environmental and energy regulations; - - Most of the current project investments made by the Company's subsidiary, NRG Energy, Inc. (NRG) consist of minority interests, and a substantial portion of future investments may take the form of minority interests, which limits NRG's ability to control the development or operation of the project; - - Other business or investment considerations that may be disclosed from time to time in the Company's Securities and Exchange Commission filings or in other publicly disseminated written documents. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. -----END PRIVACY-ENHANCED MESSAGE-----