-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, iowOeHk6Uvw5ZYfXMVD+JpkrE4bOgPzBxryKL405dTl4iQtm4stUq+up9qqdWVLG S0348bu0fR2YsMRMtfEitg== 0000072903-95-000006.txt : 199507120000072903-95-000006.hdr.sgml : 19950711 ACCESSION NUMBER: 0000072903-95-000006 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19941231 FILED AS OF DATE: 19950328 SROS: CSE 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-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03034 FILM NUMBER: 95523739 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-K 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (Mark One) X ANNUAL 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 the fiscal year ended December 31, 1994 Commission file number: 1-3034 NORTHERN STATES POWER COMPANY (Exact name of Registrant as specified in its charter) Minnesota 41-0448030 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 414 Nicollet Mall, Minneapolis, Minnesota 55401 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: 612-330-5500 Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Name of each exchange on which registered Common Stock, $2.50 Par Value New York Stock Exchange, Chicago Stock Exchange and Pacific Stock Exchange Cumulative Preferred Stock, $100 Par Value each Preferred Stock $ 3.60 Cumulative New York Stock Exchange Preferred Stock $ 4.08 Cumulative New York Stock Exchange Preferred Stock $ 4.10 Cumulative New York Stock Exchange Preferred Stock $ 4.11 Cumulative New York Stock Exchange Preferred Stock $ 4.16 Cumulative New York Stock Exchange Preferred Stock $ 4.56 Cumulative New York Stock Exchange Preferred Stock $ 6.80 Cumulative New York Stock Exchange Preferred Stock $ 7.00 Cumulative New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. _______ 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 _____ _____ As of March 15, 1995, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $2,907,829,319 and there were outstanding 66,931,937 shares of common stock, $2.50 par value. Documents Incorporated by Reference None Index Page No. PART I Item 1 - Business. .. . . . . . . . . . . . . . . . . . . . . . . . . . .1 UTILITY REGULATION AND REVENUES General. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1 Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2 Rate Programs. . . . . . . . . . . . . . . . . . . . . . . . . . .2 Rate Matters by Jurisdiction . . . . . . . . . . . . . . . . . . .3 Ratemaking Principles in Minnesota and Wisconsin . .. . . . . . . .6 Fuel and Purchased Gas Adjustment Clauses. . . . . . . . . . . . .6 ELECTRIC UTILITY OPERATIONS Competition. . . . . . . . . . . . . . . . . . . . . . . . . . . .7 Capability and Demand. .. . . . . . . . . . . . . . . . . . . . . .8 Energy Sources . . . . .. . . . . . . . . . . . . . . . . . . . . 10 Fuel Supply and Costs. .. . . . . . . . . . . . . . . . . . . . . 10 Nuclear Power Plants - Licensing, Operation and Waste Disposal. . 12 Electric Operating Statistics . . . . . . . . . . . . . . . . 14 GAS UTILITY OPERATIONS Competition. . . . . . . . . . . . . . . . . . . . . . . . . . . .14 Capability and Demand . . . . . . . . . . . . . . . . . . . . . 16 Gas Supply and Costs . . . . . . . . . . . . . . . . . . . . . . .16 Gas Operating Statistics . . . . . . . . . . . . . . . . . . . . 18 NRG ENERGY, INC . . . . . . . . . . . . . . . . . . . . . . . . . . .18 OTHER SUBSIDIARIES. . . . . . . . . . . . . . . . . . . . . . . . . .20 ENVIRONMENTAL MATTERS . . . . . . . . . . . . . . . . . . . . . . . .21 CAPITAL SPENDING AND FINANCING. . . . . . . . . . . . . . . . . . . .25 EMPLOYEES AND EMPLOYEE BENEFITS . . . . . . . . . . . . . . . . . . .26 EXECUTIVE OFFICERS. . . . . . . . . . . . . . . . . . . . . . . . . .27 Item 2 - Properties. . . . . . . . . . . . . . . . . . . . . . . . . . .29 Item 3 - Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . .29 Item 4 - Submission of Matters to a Vote of Security Holders . . . . . .30 PART II Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .30 Item 6 - Selected Financial Data . . . . . . . . . . . . . . . . . . . .31 Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . .32 Item 8 - Financial Statements and Supplementary Data . . . . . . . . . .44 Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . . . . .70 PART III Item 10 - Directors and Executive Officers of the Registrant . . . . . .71 Item 11 - Executive Compensation . . . . . . . . . . . . . . . . . . . .74 Item 12 - Security Ownership of Certain Beneficial Owners and Management 78 Item 13 - Certain Relationships and Related Transactions . . . . . . . .78 PART IV Item 14 - Exhibits, Financial Statement Schedules, and Reports on Form 8-K. . . . . . . . . . . . . . . . . . . . . . . . . . .79 SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .85 PART I Item 1 - Business Northern States Power Company (the Company) was incorporated in 1909 under the laws of Minnesota. Its executive offices are located at 414 Nicollet Mall, Minneapolis, Minnesota 55401. (Phone 612-330-5500). The Company has two significant subsidiaries, Northern States Power Company, a Wisconsin corporation (the Wisconsin Company) and NRG Energy, Inc (NRG), a Delaware corporation; and several other subsidiaries, including Cenergy, Inc, a Minnesota corporation, and Viking Gas Transmission Company, a Delaware corporation (Viking). (See "NRG Energy, Inc." and "Other Subsidiaries" herein for further discussion of these subsidiaries.) The Company and its subsidiaries collectively are referred to herein as NSP. NSP is predominantly an operating public utility engaged in the generation, transmission and distribution of electricity throughout a 49,000 square mile service area and the transportation and distribution of natural gas in approximately 148 communities within this area. Viking is a regulated natural gas transmission company that operates a 500-mile interstate natural gas pipeline. In addition to utility businesses, NRG manages several of NSP's non-regulated energy subsidiaries. The Company serves customers in Minnesota, North Dakota and South Dakota. The Wisconsin Company serves customers in Wisconsin and Michigan. Of the approximately 3 million people served by the Company and the Wisconsin Company, the majority are concentrated in the Minneapolis-St. Paul metropolitan area. In 1994, about 61% of NSP's electric retail revenue was derived from sales in the Minneapolis-St. Paul metropolitan area and about 56% of retail gas revenue came from sales in the St. Paul area. (For business segment information, see Note 18 of Notes to Financial Statements under Item 8.) NSP's utility businesses are experiencing some of the challenges currently common to regulated electric and gas utility companies, namely, increasing competition for customers, increasing pressure to control costs to operate and construct facilities, uncertainties in regulatory processes, increasing costs of compliance with environmental laws and regulations, and uncertainties related to permanent disposal of nuclear fuel. In May 1994, the Minnesota Legislature approved a plan for temporary storage of used nuclear fuel, if the Company satisfies certain responsibilities, which should eliminate for several years the uncertainty surrounding continued operation of its nuclear plants. (See Management's Discussion and Analysis under Item 7 and Notes 16 and 17 of Notes to Financial Statements under Item 8 for further discussion of this matter.) NRG was active in the international energy market through partnership and joint venture investments in 1994. NRG acquired partial ownership positions in the MIBRAG mbh coal and power complex and in the 900 megawatt (Mw) Schkopau power plant both near Leipzig, Germany. NRG is also the operator and 37.5% owner of the 1,680 Mw Gladstone Power Station in Queensland, Australia. (See additional discussions of business acquisitions and non-regulated operations in the "NRG Energy, Inc." and "Other Subsidiaries" sections, herein, and in Notes 4 and 5 of Notes to Financial Statements under Item 8.) UTILITY REGULATION AND REVENUES General Retail sales rates, services and other aspects of the Company's operations are subject to the jurisdiction of the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), and the South Dakota Public Utilities Commission (SDPUC) within their respective states. The MPUC also possesses regulatory authority over aspects of the Company's financial activities including security issuances, property transfers when the asset value is in excess of $100,000, mergers with other utilities, and transactions between the regulated Company and non-regulated affiliates. In addition, the MPUC reviews and approves the Company's electric resource plans for meeting customers' future electric energy needs. The Wisconsin Company is subject to regulation of similar scope by the Public Service Commission of Wisconsin (PSCW) and the Michigan Public Service Commission (MPSC). In addition, each of the state commissions certifies the need for new generating plants and transmission lines of designated capacities to be located within the respective states before the facilities may be sited and built. Wholesale rates for electric energy sold in interstate commerce, wheeling rates for energy transmission in interstate commerce, the wholesale gas transportation rates of Viking, and certain other activities of the Company, the Wisconsin Company and Viking are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). NSP also is subject to the jurisdiction of other federal, state and local agencies in many of its activities. (See "Environmental Matters" herein.) The Minnesota Environmental Quality Board (MEQB) is empowered to select and designate sites for new power plants with a capacity of 50 Mw or more and routes for transmission lines with a capacity of 200 kilovolts (Kv) or more, and to evaluate such sites and routes for environmental compatibility. The MEQB may designate sites or routes from those proposed by power suppliers or those developed by the MEQB. No such power plant or transmission line may be constructed in Minnesota except on a site or route designated by the MEQB. NSP is unable to predict the impact on its operating results from the future regulatory activities of any of the above agencies. To the best of its ability, NSP works to understand and comply with all rules and regulations issued by the various agencies. Revenues NSP's financial results depend on its ability to obtain adequate and timely rate relief from the various regulatory bodies, its ability to control costs and the success of its non-regulated activities. NSP's 1994 utility operating revenues, excluding intersystem non-firm electric sales to other utilities of $89 million and miscellaneous revenues of $58 million, were subject to regulatory jurisdiction as follows: Authorized Return on Percent of Common Equity @ Total December 31, 1994 Revenues Electric Gas (Electric & Gas) Retail: Minnesota Public Utilities Commission 11.47% 11.47% 73.3% Public Service Commission of Wisconsin 11.4 11.4 14.7 North Dakota Public Service Commission 11.50 14.0 5.3 South Dakota Public Utilities Commission * 3.1 Michigan Public Service Commission 12.25 0.6 Sales for Resale - Wholesale, Viking Gas and Interstate Transmission: Federal Energy Regulatory Commission * * 3.0 Total 100.0% * Settlement proceeding, based upon revenue levels granted with no specified return. Rate Programs Rate increases requested and granted in previous years from various jurisdictions were as follows (note that 1992, 1993 and 1994 amounts represent annual increases effective in these years, while previous years represent annual increases requested in those years even if effective in a subsequent year): Annual Increase/(Decrease) Year Requested Granted (Millions of dollars) 1990 19.5 11.2 1991 118.7 68.0 1992 ----- ----- 1993 166.6 101.5 1994 (1.0) (1.0) The following table summarizes the status of rate increases for rates effective in 1994.
Annual Increase/(Decrease) Updated Requested Request Granted Status (Millions of dollars) Electric North Dakota-Retail 1.2 1.2 Order Issued 12/29/93 North Dakota-Refund (3.6) (3.6) Order Issued 11/09/94 Gas Wisconsin-Retail 1.4 1.7 1.4 Order Issued 12/23/93 Total 1994 Rate Program (1.0) (1.0)
Rate Matters by Jurisdiction Minnesota Public Utilities Commission (MPUC) On Jan. 31, 1994, the Minnesota Department of Public Service, the Office of the Minnesota Attorney General and the Minnesota Energy Consumers intervenor groups filed an appeal with the Minnesota Court of Appeals of the MPUC's determination on the allowed return on equity granted to the Company in final 1993 electric and gas rate orders. On Aug. 2, 1994, the Court affirmed the final rate orders issued in January 1994 for these rate cases. This appeal process is now completed. As a result of this decision, no adjustments or changes are required to rates charged to customers or to revenues recorded by the Company. In 1991, the Minnesota legislature passed a law which granted the MPUC discretionary authority to approve a rate adjustment clause for changes in certain costs (including property taxes, fees and permits) incurred by Minnesota public utilities. The MPUC may approve a utility's use of the rate adjustment clause for billing customers if certain conservation expenditure levels are met. On Oct. 4, 1994, the Company filed for approval of the use of the adjustment clause for billing its gas customers, beginning in January 1995, for increases in property taxes. The potential gas revenue increase from this filing was approximately $2.0 million. At a hearing held on Feb. 23, 1995, the MPUC turned down the Company's request. The Company may ask the MPUC to reconsider this decision. On Oct. 28, 1994 the Company filed with the MPUC a petition for a miscellaneous rate change approving the implementation of an annual recovery mechanism for deferred electric Conservation Improvement Program (CIP) expenses. On Feb. 23, 1995, the MPUC voted to approve recovery of $41 million under a new rate adjustment clause for the period May 1995 through June 1996. Thereafter, the Company would be required to request a new cost recovery level annually. The Company estimates it will receive an additional $24 million in revenues in 1995. This increased recovery results from a corresponding increase in conservation expenses and avoids a significant delay between the incurring of costs and recovery in rates. On Oct. 5, 1994, as part of a response to 1994 legislation related to fuel storage at the Prairie Island nuclear plant, the Company filed a miscellaneous rate change proposal with the MPUC which reflects a 50% discount on the first 300 kilowatt hours (Kwh) consumed each month by qualified low- income residential customers. The Company proposed that the discount be effective beginning with the October 1994 billing month for qualifying customers, and that rate adjustments designed to recover from other customers the costs of the discount be effective Jan. 4, 1995. The MPUC approved the filing on Dec. 5, 1994. The ruling also eliminated the Conservation Rate Break and restructured the rates between customer classes, but does not significantly change overall revenue levels. By September 1 of each year, the Company is required by Minnesota statute to submit to the MPUC an annual report of the Purchased Gas Adjustments (PGA) for each customer class by month for the previous year commencing July 1 and ending June 30. The report verifies whether the utility is calculating the adjustments properly and implementing them in a timely manner. In addition, the MPUC review includes an analysis of procurement policies, cost-minimizing efforts, rule variances in effect or requested, retail transportation gas volumes, independent auditors' reports, and the impact of market forces on gas costs for the coming year. The MPUC has the authority to disallow certain costs if it deems the utility was not prudent in its gas procurement activities. The Department of Public Service (DPS) has recommended a $1.1 million cost recovery disallowance. This filing is pending MPUC action. Gas utilities in Minnesota are also required to file for a change in design day demand, to redistribute demand percentages among classes, or exchange one form of demand for another. The Company filed in October 1994 to increase its demand entitlements due to projected increases in firm customer count, to decrease the Minnesota jurisdictional allocation of total demand entitlements and to recover the demand entitlement costs associated with the increase in transportation and storage levels in its monthly PGA's. This filing is pending MPUC approval. No general rate filings are anticipated in Minnesota in 1995. North Dakota Public Service Commission (NDPSC) On Dec. 29, 1993, the Company received approval from the NDPSC to increase base rates $1.2 million, or 1.2%, to recover 1994 cost increases associated with power purchased from the Manitoba Hydro-Electric Board. The additional costs consist of demand charges related to 500 Mw of firm capacity for four months. Eight months of the annual demand costs, which took effect May 1, 1993, were included in the Company's previous rate increase granted in April 1993. The $1.2 million annual increase was implemented Jan. 5, 1994. On Aug. 9, 1994 the Company applied to the NDPSC for a rate reduction of $3.6 million in annual electric revenues. The reduction reflects a correction in cost allocations to the North Dakota jurisdiction. The Company also requested authority to make refunds to customers to effectively implement the reduction as of June 1, 1994. On Nov. 9, 1994, the NDPSC approved the proposed rate reduction. In January 1995, the NDPSC held a hearing on the possibility of retroactive refunds for the period Jan. 1, 1989, through June 1, 1994, but has not yet reached a decision. The ultimate outcome of this proceeding is not determinable at this time. On Nov. 1, 1994 NSP received approval of its proposed Economic Development Rider (EDR) by the NDPSC. The rider allows NSP's North Dakota operations (NSP-ND) to offer discounted rates to new customers, or on load expansions by existing customers, for a period of five years. The customer's load must be at least 50 kilowatts (Kw). The rider is closely tied to the state's Partnership in Assisting Community Expansion (PACE) program, which offers low interest rates on business development loans. The EDR will enable NSP-ND to remain competitive with neighboring energy providers, most of which have rate discount incentives to attract new customers. At this time, the amount of the discounts is not expected to have a material affect on the Company's financial results. No general rate filings are anticipated in North Dakota in 1995. South Dakota Public Utilities Commission (SDPUC) There were no general rate filings in South Dakota in 1994 and none are anticipated in 1995. Public Service Commission of Wisconsin (PSCW) In June 1993, the Wisconsin Company filed with the PSCW for a $1.4 million annual increase in gas retail rates to be effective Jan. 1, 1994. In Aug. 1993, the Wisconsin Company increased its request to $1.7 million to amortize recovery of a portion of the acquisition premium paid by the Company for Viking in recognition of reduced delivered gas costs. In Dec. 1993, the PSCW issued an order approving a $1.4 million increase on an annual basis in the Wisconsin Company's gas rates, including the amortization. These rate changes took effect on Jan. 1, 1994. The Wisconsin Company filed a proposal for a new high load factor rate with the PSCW in November 1994 to be effective Jan. 1, 1995. Under the proposal, qualifying customers would receive a credit on their bills of up to 3 percent, depending on load factor. This is expected to reduce 1995 revenues for the Wisconsin Company by approximately $1.0 million. The Wisconsin Company will file a general rate case in June 1995, for rates effective in 1996, as required by the PSCW biennial filing requirement. Retail Rate Recovery of Viking Acquisition Costs During 1993, the Company and the Wisconsin Company requested regulatory approval in Minnesota, North Dakota, Wisconsin and Michigan to recover in retail gas rates a portion of the acquisition cost paid for Viking in recognition of reduced retail delivered gas costs made possible by the acquisition of Viking. The PSCW approved in the Wisconsin Company's gas rates recovery of a total of $1.8 million over the five-year period 1994-98. On March 23, 1994, the NDPSC authorized, without any change in rates, the amortization of $150,000 in annual jurisdictional expense for Viking acquisition costs over a 15 year period starting in June of 1993. On Nov. 21, 1994 the MPUC rejected PGA recovery of jurisdictional expense for Viking acquisition costs (amounting to $1.5 million annually), but ruled the Company could seek recovery in its next gas general rate case. Viking's expenses will include approximately $2 million in annual acquisition cost amortization each year until 2008. Electric Transmission Tariffs and Settlement (FERC) In 1990, the Company filed a transmission services tariff for certain transmission customers. New rates were effective under the filing, subject to refund, for the period Dec. 29, 1990 through Oct. 31, 1994. The Company has recorded an estimated liability at Dec. 31, 1994 for potential transmission rate refunds under this tariff based on the FERC order dated Sept. 21, 1993. Since a rehearing of the order was granted and is currently pending, transmission rates for this period are not yet final. The FERC announced a new transmission pricing policy effective Oct. 26, 1994. The new policy introduces greater flexibility in transmission pricing structure. It established five principles of transmission pricing including guidelines on coverage of revenue requirements, comparability of transmission service, balance of efficiency, fairness and practicality. In March 1994, the Company filed a revised open access transmission tariff with the FERC. On May 25, 1994, the FERC accepted the filing with the new rates effective Nov. 1, 1994, subject to refund. The FERC also ruled the tariff would be subject to the requirement that the Company offer transmission service using terms and conditions comparable to its own use of the system. The Company recently reached a settlement in principle with several parties involved in this proceeding. The settlement agreement includes a transmission tariff that complies with the FERC transmission pricing policy which calls for comparability of service and pricing, network service, and unbundling of ancillary charges such as scheduling and load following. The Company anticipates acceptance of the settlement offer in 1995. The revenue effect on the Company is an increase of approximately $200,000 per year. The new tariff allows the Company to comply with transmission pricing provisions of open access transmission required by the Energy Policy Act of 1992. Minnesota Wholesale Rate Proceedings (FERC) In 1990, 16 of the Company's 19 municipal wholesale customers in Minnesota began reviewing their long-term power supply options. Eight customers created a joint action group, the Minnesota Municipal Power Agency (MMPA), to serve their future power supply needs. An additional wholesale customer became an associate member of the MMPA. In 1992 these nine municipal customers notified the Company of their intent to terminate their power supply agreements with the Company effective July 1995 or July 1996. These nine customers represent approximately $29 million in annual revenues and a maximum demand load of approximately 155 Mw. In Oct. 1993, the MMPA filed a complaint with the FERC under new Section 211 of the Federal Power Act alleging that the Company had not bargained in good faith toward a transmission service agreement which would allow MMPA to deliver power supply to its members starting July 1, 1995, when some of the municipalities' supply agreements with the Company expire. On Jan. 26, 1994, the FERC in a proposed order ruled that the Company had bargained in good faith, as required by Section 211, but ordered the Company and MMPA to negotiate for sixty days to attempt to resolve remaining issues. The Commission accepted a settlement agreement in 1994. The MMPA customers agreed to pay the rate then in effect for firm transmission service. Following FERC acceptance of the pending transmission tariff, the MMPA customers will be charged the new tariff unit rates. In 1992 and 1993, the Company signed long-term power supply agreements with the remaining 10 of its current 19 municipal customers in Minnesota. The agreements commit the customers to purchase power from the Company for up to 13 years (through 2005) at fixed rates to increase by up to 3% per year. The 10 customers represent a maximum demand load of approximately 59 Mw and provide approximately $10 million in annual revenue. The FERC accepted formula rates effective Jan. 1, 1994, by order dated Feb. 23, 1994. Other Wholesale Rate Proceedings (FERC) In Dec. 1993 the Company, in compliance with a FERC order in the Central Maine case requiring that the Commission approve all interstate, inter-utility contracts, filed over 300 such contracts with the FERC for review. The Commission established 76 separate dockets for review. Absent FERC acceptance, the contracts could have been declared null and void, possibly resulting in full refunds for all amounts paid. The FERC has accepted 75 dockets with little or no change. The remaining docket is expected to be accepted. The Company anticipates full resolution of the Central Maine compliance filings in 1995. The Wisconsin Company plans to announce market-based pricing options for existing and potential wholesale customers in 1995. The wholesale customers have new opportunities to purchase power from power suppliers other than NSP. With open transmission access, they have the opportunity to purchase power from any producer and request that, on a comparable basis, the power be delivered from the producer to their municipality. In May, 1994, the Wisconsin Company offered its municipal wholesale customers a discount of one to two percent off the FERC authorized rate for a long-term full requirements commitment between five and ten years with comparable cancellation notices. Five of the ten municipal wholesale customers signed up for the discounts. The total annual decrease in revenues is approximately $0.1 million. Ratemaking Principles in Minnesota and Wisconsin Since the MPUC assumed jurisdiction of Minnesota electric and gas rates in 1975, several significant regulatory precedents have evolved. The MPUC accepts the use of a forecast test year that corresponds to the period when rates are put into effect and allows collection of interim rates subject to refund. The use of a forecast test year and interim rates minimizes regulatory lag. The MPUC must order interim rates within 60 days of a rate case filing. Minnesota statutes allow interim rates to be set using (1) updated expense and rate base items similar to those previously allowed, and (2) a return on equity equal to that granted in the last MPUC order for the utility. The MPUC must make a determination on the application within 10 months after filing. If the final determination does not permit the full amount of the interim rates, the utility must refund the excess revenue collected, with interest. To the extent final rates exceed interim rates, the final rates become effective at the time of the order and retroactive recovery of the difference is not permitted. Generally, the Company may not increase its rates more frequently than every 12 months. Minnesota law allows Construction Work in Progress (CWIP) in a utility's rate base instead of recording Allowance for Funds Used During Construction (AFC) in revenue requirements for rate proceedings. The MPUC has exercised this option to a limited extent so that cash earnings are allowed on small and short-term projects that do not qualify for AFC. (For the Company's policy regarding the recording of AFC, see Note 1 of Notes to Financial Statements under Item 8.) The PSCW has a biennial filing requirement for processing rate cases and monitoring utilities' rates. By June 1 of each odd-numbered year, the Wisconsin Company must submit filings for calendar test years beginning the following January 1. The filing procedure and subsequent review generally allow the PSCW sufficient time to issue an order effective with the start of the test year. The PSCW reviews each utility's cash position to determine if a current return on CWIP will be allowed. The PSCW will allow either a return on CWIP or capitalization of AFC at the adjusted overall cost of capital. The Wisconsin Company currently capitalizes AFC on production and transmission CWIP at the FERC formula rate and on all other CWIP at the adjusted overall cost of capital. Fuel and Purchased Gas Adjustment Clauses in Effect The Company's retail electric and Wisconsin Company wholesale rate schedules provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy. Although the lag in implementing the billing adjustment is approximately 60 days, an estimate of the adjustment is recorded in unbilled revenue in the month costs are incurred. The Company's wholesale customers remaining with NSP do not have a fuel clause provision in their contracts. The contracts instead provide a fixed rate with an escalation factor. The Wisconsin Company calculates the wholesale electric fuel adjustment factor for the current month based on estimated fuel costs for that month. The estimated fuel cost is adjusted to actual the following month. The Wisconsin Company's automatic retail electric fuel adjustment clause for Wisconsin customers was eliminated effective in 1986. The clause was replaced by a limited-issue filing procedure. Under the procedure, an annual deviation in fuel costs of 2% and a monthly deviation of 8% will allow filing for a change in rates limited to the fuel issue. The adjustment approved is calculated on an annual basis, but applied prospectively. Gas rate schedules for the Company and the Wisconsin Company include a purchased gas adjustment (PGA) clause that provides for rate adjustments for changes in the current unit cost of purchased gas compared to the last costs included in rates. The Wisconsin Company's gas and retail electric rate schedules for Michigan customers include Gas Cost Recovery Factors and Power Supply Cost Recovery Factors, which are based on 12 month projections. After each 12 month period, a reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers. Viking is a transportation-only interstate pipeline and provides no sales services. As a result, Viking terminated its PGA clause effective Nov. 1, 1993. Natural gas fuel for compressor station operations is provided in-kind by transportation service customers. ELECTRIC UTILITY OPERATIONS Competition NSP's electric sales are subject to competition in some areas from municipally owned systems, rural cooperatives and, in certain respects, other private utilities and cogenerators. Electric service also increasingly competes with other forms of energy. The degree of competition may vary from time to time, depending on relative costs and supplies of other forms of energy. Although NSP cannot predict the extent to which its future business may be affected by supply, relative cost or promotion of other electricity or energy suppliers, NSP believes that it will be in a position to compete effectively. NSP has proposed to fill future needs for new generation through competitive bid solicitations. The use of competitive bidding to select future generation sources allows the Company to take advantage of the developing competition in this sector of the industry. The Company's proposal, which has been approved by the MPUC, allows NRG to bid in response to Company solicitations for proposals and the Company is seeking permission to include an NSP regulated alternative in the future. Management intends to obtain regulatory approval in all retail jurisdictions to use a single bid process to meet resource needs for the entire integrated system. The Company's competitive bidding proposal has been approved by both the MPUC and PSCW. In Oct. 1992, the President signed into law the Energy Policy Act of 1992 (Energy Act). The Energy Act amends the Public Utility Holding Company Act of 1935 (1935 Act) and the Federal Power Act. Among many other provisions, the Energy Act is designed to promote competition in the development of wholesale power generation in the electric utility industry. It exempts a new class of independent power producers from regulation under the 1935 Act. The Energy Act also allows the FERC to order wholesale "wheeling" by public utilities to provide utility and non-utility generators access to public utility transmission facilities. The provision allows the FERC to set prices for wheeling, which will allow utilities to recover certain costs. The costs would be recovered from the companies receiving the services, rather than the utilities' retail customers. The market-based power agreement filings with FERC (as discussed in "Utility Regulation and Revenues", herein) reflect the trend toward increasing transmission access under the Energy Act. The Energy Act's ultimate impact on NSP cannot be predicted. In 1994, the FERC issued proposed rulemaking to address the rate treatment of potential "stranded investment" costs which may result as the electric energy market becomes more competitive. The FERC is soliciting comments on options for recovery of transition costs associated with existing electric investments for which competitive market pricing might not provide recovery. NSP is evaluating the FERC proposal to determine the potential effects on operating results and customer rates and has responded to the FERC individually and through an industry group. The FERC has not reached a final decision, and the effects of the proposed rulemaking currently are not known. Many states are currently considering retail competition. While the topic of retail competition has been discussed in the Company's jurisdictions, no legislation or regulatory initiatives have been formally introduced. The PSCW has asked each utility in the state for comments regarding retail competition. In response to the request, the Wisconsin Company filed the following recommendations. Competition should be phased in for retail markets by customer classes, with all customers having choice of supplier by 2001. The generation segment of the industry should be deregulated by 2001. Prudent stranded costs should be recovered prior to the advent of retail wheeling. Finally, utilities and other competitors should have a level playing field for issues such as obligation to serve, eminent domain, requirements for demand side management, funding of social programs, opening of retail markets to competition and other issues. Also, as an outcome of the responses to the PSCW, a task force was formed by the PSCW to analyze the industry restructuring necessary in the state of Wisconsin. A goal of this task force is to have a list of recommended legislative changes to the Wisconsin Legislature for the 1996 session. The Michigan Public Service Commission has determined that Michigan should recodify statutes governing energy production. They will be working with the governor's office to initiate that process. Michigan also has a retail wheeling experiment, limited to its two largest utilities and customers larger than $50 million, currently underway. The Wisconsin Company's customers are not included in this experiment which is currently being challenged in court. Retail competition represents yet another development of a competitive electric industry. Management plans to continue its ongoing efforts to be a low-cost supplier of electricity and an active participant in the more competitive market for electricity expected as a result of the Energy Act. Actions the Company is pursuing to position for the competitive environment include: creative partnership solutions with strategic customers including communities; focusing on the unique needs of national account customers; competitive pricing alternatives; improved reliability; implementation of the first service guarantees in the region; ease of customer access including 24 hour, 7 days/week operation; substantial customer convenience and flexibility improvements via a new Customer Service System which includes appointment scheduling upon first contact, improved outage call response, and a wide array of new billing options; and aggressive cost management. Capability and Demand Assuming normal weather, NSP expects its 1995 summer peak demand to be 7,229 Mw. NSP's 1995 summer capability is estimated to be 8,942 Mw, net of contract sales including 1,153 Mw (including reserves) of contracted purchases from the Manitoba Hydro-Electric Board, a Canadian Crown Corporation (Manitoba Hydro) and 868 Mw of other contracted purchases. The estimate assumes 7,682 Mw of thermal generating capability and 1,438 Mw of hydro and wind generating capability. Of the total summer capability, NSP has committed 178 Mw for sales to other utilities. Of the estimated net capability, including the interconnection with Manitoba Hydro, 30% has been installed during the last 10 years. NSP's 1994 maximum demand of 7,101 Mw occurred on June 14, 1994. Resources available at that time included 6,859 Mw of Company-owned capability and 1,860 Mw of purchased capability net of contracted sales. Due to the Mid- Continent Area Power Pool's (MAPP) penalty for reserve margin shortfalls and to be prepared for weather uncertainty at the lowest potential cost, NSP carried a reserve margin for 1994 of 23%. The minimum reserve margin requirement as determined by the members of the MAPP, of which NSP is a member, is 15%. (See Note 17 of Notes to Financial Statements under Item 8 for more discussion of power agreement commitments.) The Company added to its generating facilities in 1994. On Sept. 24, 1994, the Angus Anson 232 Mw gas-fired combustion turbines were placed in service near Sioux Falls, South Dakota. The total cost of this project was approximately $72 million. The Company is continuing an extensive reliability program that includes preventive maintenance on transmission and distribution power lines, improvements to existing equipment, and testing and implementing new technology. Reliability to NSP's large customers improved 14% in 1994, through a focused program to reduce the number of outages caused by lightning, human errors, animals and trees. In 1994, a service guarantee program was implemented to ensure on-time service installation and construction site restoration. In 1994, NSP signed a long term power purchase contract with LSP-Cottage Grove for 245 Mw of annual capacity for thirty years. LSP-Cottage Grove was awarded the contract from a competitive negotiated process ordered by the MPUC which considered six different vendors and projects. The purchase will be from a natural gas- fired combined cycle facility that NSP can dispatch as system requirements dictate. The MPUC requested the Minnesota Department of Public Service (DPS) to review the reasonableness of the price NSP is paying LSP-Cottage Grove for the capacity and energy. In December 1994 the DPS issued its report concluding that the contract prices are appropriate. On Feb. 2, 1995 the MPUC determined that the contract was at or below NSP's avoided cost. The pricing considers both capacity and energy. NSP expects the LSP-Cottage Grove facility to be available in May 1997. The Company filed an electric resource plan with the MPUC in 1993. The plan shows how the Company intends to meet the increased energy needs of its electric customers and includes an approximate schedule of the timing of such needs. The plan contains: conservation programs to reduce the Company's peak demand and conserve overall electricity use; economic purchases of power; and programs for maintaining reliability of existing plants. It also includes an approximate schedule of timing of such needs. The plan does not anticipate the need for additional base-load generating plants during the balance of this century and assumes that all existing generating facilities will continue operating through their license period or useful life. The MPUC approved the Company's resource plan on July 15, 1994, but directed the Company to make a compliance filing addressing the MPUC's proposed modifications. These modifications reflect changes due to the Prairie Island legislation enacted in 1994 and the inclusion of updated information that became available after the resource plan was filed. The Company submitted the compliance filing on Dec. 13, 1994. The revisions submitted in the compliance filing do not significantly alter the Company's resource plan filed in 1993. The following resource needs were included in the resource plan. The plan does not specify the precise technology to meet these needs, but does suggest energy source options.
Cumulative Mw Resource Needs By Type vs. Base of 1993 1996 2000 2004 2008 Peak 0-500 0-500 300-1,100 600-1,800 Intermediate 0-0 0-700 300-1,000 900-1,000 Base 0 0 0-300 200-1,400 Demand Side Management 500 1,200 1,700 2,000 Total 500-1,000 1,200-2,400 2,300-4,100 3,700-6,200
The resource plan proposes to satisfy the above resource needs through a combination of the following options: Sources of Energy to Meet Needs - Continued operation of existing generation facilities. - Demand reduction of 2,000 Mw by 2008 through conservation and load management. - 425 Mw of wind generation in service by 2002. - 125 Mw of biomass generation in service by 2002. - Increased reliance on hydro power under contracts from Manitoba Hydro. - Standby generation and cogeneration at customer sites when mutually beneficial to both NSP and the customer. - Purchase of 245 Mw of natural gas-fired combined cycle generation. - Competitive bidding to fill additional needs for new generation. In connection with the approval of fuel storage facilities at the Company's Prairie Island generation plant, legislation was enacted in 1994 which established certain resource commitments, as discussed in Note 17 to the Financial Statements under Item 8. The Company has taken steps to comply with the requirements of these resource commitments. 25 Mw of third party wind generation has been fully operational since May 1, 1994 and is performing as expected. All significant permit applications have been filed for another 100 Mw to be in service by November of 1996. The Company filed a proposal with the MPUC in January 1995 for the first 50 Mw of biomass generation. In addition, the Company announced its plan to seek significant public input in its exploration for an alternate interim used nuclear fuel storage site in Goodhue County, Minnesota. The Company's construction commitments disclosed in Note 17 to the Financial Statements include the known effects of the 1994 Prairie Island legislation. The impact of the legislation on power purchase commitments is not yet determinable. The MPUC has begun a proceeding to establish values representing environmental costs imposed by electric generation that are not part of the price of electricity. These values are known as environmental externalities. The values, expected to be established later in 1995, will be applied by the MPUC in resource planning proceedings to determine the total social cost of different generating options to supply the growing demand for electricity. Depending on the values established and the manner in which they are applied, externalities could significantly affect resources available to NSP to meet future demands for electricity. The Company continues to implement various Demand Side Management (DSM) programs designed to improve load factor and reduce the Company's power production cost and system peak demands, thus reducing or delaying the need for additional investment in new generation and transmission facilities. The Company currently offers a broad range of DSM programs to all customer sectors, including information programs, rebate and financing programs, and rate incentive programs. These programs are designed to respond to customer needs and focus on increasing value of service that, over the long term, will help its customer base become more stable, energy efficient and competitive. During 1994, the Company's programs accomplished approximately 183 Mw of system peak demand reduction. Since 1986, the Company's DSM programs have achieved 1,012 Mw of summer peak demand reduction, which is equivalent to 14% of its 1994 summer peak demand. The Company's operating goals, which go beyond the resource plan guideline above, are to offset peak electric demand by 1,100 Mw by 1995 and 1,700 Mw by 2000. The Company continues to focus on improving the cost-effectiveness of its DSM programs through market research studies, program evaluations and changes to its program mix. In 1994, the MPUC improved the Company's cost recovery and incentives for DSM by allowing recovery of a portion of the lost margins due to DSM impacts on electric revenues. This lost margin recovery, subject to annual review by the MPUC, was approximately $3 million in 1994. In addition, the MPUC allowed the Company to earn another $4 million in DSM investment returns through an incentive program that rewards the attainment of specified conservation goals. Energy Sources For the year ended Dec. 31, 1994, 47% of NSP's Kwh requirements was obtained from coal generation and 28% was obtained from nuclear generation. Purchased and interchange energy provided 21%, including 15% from Manitoba Hydro; NSP's hydro and other fuels provided the remaining 4%. The fuel resources for NSP's generation based on Kwh were coal (59%), nuclear (36%), renewable and other fuels (5%). The following is a summary of NSP's electric power output in millions of Kwh for the past three years: 1994 1993 1992 Thermal plants 32,710 33,130 30,467 Hydro plants 922 1,001 1,024 Purchased and interchange 9,054 8,541 8,187 Total 42,686 42,672 39,678 Many of NSP's power purchases from other utilities are coordinated through the regional power organization MAPP, pursuant to an agreement dated March 31, 1972, with amendments filed in 1994. NSP is one of 49 participants in MAPP consisting of 10 investor-owned systems, eight generation and transmission cooperatives, three public power districts, seven municipal systems, the Department of Energy's Western Area Power Administration and 20 Associate Participants. The MAPP agreement provides for the members to coordinate the installation and operation of generating plants and transmission line facilities. The terms and conditions of the MAPP agreement and transactions between MAPP members are subject to the jurisdiction of the FERC. The 1972 MAPP agreement, as amended, was accepted for filing by the FERC on Dec. 15, 1994. Fuel Supply and Costs Coal and nuclear fuel will continue to dominate NSP's regulated utility fuel requirements for generating electricity. It is expected that approximately 98 percent of NSP's fuel requirements, on a Btu basis, will be provided by these two fuels over the next several years, leaving 2 percent of NSP's annual fuel requirements for generation to be provided by other fuels (including natural gas, oil, refuse derived fuel, waste materials, renewable sources and wood). The actual fuel mix for 1994 and the estimated fuel mix for 1995 and 1996 are as follows: Fuel Use on Btu Basis (Est) (Est) 1994 1995 1996 Coal 60.9% 61.1% 63.1% Nuclear 37.4% 37.1% 35.1% Other 1.7% 1.8% 1.8% The Company normally maintains between 20 and 45 days of coal inventory depending on the plant site. The Company has long-term contracts providing for the delivery of up to 100 percent of its 1995 coal requirements. Coal delivery may be subject to short-term interruptions or reductions due to transportation problems, weather and availability of equipment. The Company expects that more than 98% of the coal it burns in 1995 will have a sulfur content of less than 1 percent. The Company has contracts with three Montana coal suppliers, Westmoreland Resources, Western Energy, Big Sky Coal Company and three Wyoming suppliers, Rochelle Coal Company, Antelope Coal Company and Black Thunder Coal Company, for a maximum total of 60 million tons of low-sulfur coal for the next 5 years. These arrangements are sufficient to meet the requirements of existing coal-fired plants. They also permit the Company to purchase additional coal when such purchase would improve fuel economics and operations. The Company has options from suppliers for over 100 million tons of coal with a sulfur content of less than 1 percent that could be available for future generating needs. The plants in the Minneapolis-St. Paul area are about 800 miles from the mines in Montana and 1,000 miles from the mines in Wyoming. Coal delivered by rail provides the Company with an economical source of fuel. The estimated coal requirements of the Company at its major coal-fired generating plants for the periods indicated and the coal supply for such requirements are as follows:
State Sulfur Dioxide Maximum Amount Contract Approximate Emission Limit Annual Covered by Expiration Sulfur Pounds Per Plant Demand Contract Date Content (%)(2) MBTU* Input (Tons) (Tons) Black Dog 1,200,000 1,200,000 (1) 0.5 1.3(3) High Bridge 800,000 800,000 (1) 0.5 3.0 Allen S. King 2,000,000 2,000,000 (1) 0.9 1.6 Riverside 1,300,000 1,300,000 (1) 0.7 2.5(4) Sherco 8,000,000 8,000,000 (1) 0.5 0.9(5) 13,300,000 13,300,000(6)
*MBTU = Million British Thermal Units Notes: (1) Contract expiration dates vary between 1995 and 2005 for western coal, which can provide up to 100% of the required fuel supply for the designated generating unit. Spot market purchases of other western coal, and other fuels will provide the remaining fuel requirements when such purchases would improve fuel economics. The Company is also burning petroleum coke as a source of fuel. (2) This percentage represents the average blended sulfur content of the combination of fuels typically burned at each plant. (3) The Black Dog Fluidized Bed (Unit 2) SO2 limit is 1.2 lb/MBTU. (4) The SO2 limitation at Riverside Unit 8 is 2.5 lb/MBTU. The limitation for units 6 and 7 is currently 0.9 lb SO2 /MBTU. (5) Compliance with air pollution control permit and applicable air quality regulations requires use of limestone scrubbers to achieve 70% SO2 removal and a maximum limit of SO2 emission to 0.96 lb/MBTU during any 90-day period for Units 1 and 2. For Unit 3, the SO2 emission limit is 0.60 lb/MBTU. (6) Annual requirements are expected to range from 11.0 to 13.3 million. The Company's current fuel oil inventory is adequate to meet anticipated 1995 requirements. Additional oil may be provided through spot purchases from two local refineries and other domestic sources. To operate the Company's nuclear generating plants, the Company secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication. The contract strategy involves a portfolio of spot, medium and long-term contracts for uranium, conversion and enrichment. Current contracts are flexible and cover between 70% and 100% of uranium, conversion and enrichment requirements through the year 1997. These contracts expire at varying times between 1997 and 2005. The overlapping nature of contract commitments will allow the Company to maintain 70% to 100% coverage beyond 1997, if appropriate. The Company expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants. Fuel fabrication is 100% committed through the year 2003. The Company expects the unit cost of fuel to produce electricity with these nuclear facilities will be lower than the comparable cost of fuel to produce electricity with any other currently available fuel sources for the sustained operation of a generation facility. The cost of nuclear fuel, including disposal, is recovered in the customer price of the electricity sold by the Company. The Company's fuel costs for the past three years are shown below: Fuel Costs * Per Million Btu Year Ended December 31 1992 1993 1994 Coal** $ 1.22 $ 1.17 $1.22 Nuclear*** .43 .41 .47 Composite All Fuels .93 .90 .93 * Fuel adjustment clauses in its electric rate schedules or statutory provisions enable NSP to adjust for fuel cost changes. (See "Utility Regulation and Revenues - Fuel and Purchased Gas Adjustment Clauses" under Item 1.) ** Includes refuse-derived fuel and wood. *** See Note 1 to the Financial Statements under Item 8 for an explanation of the Company's nuclear fuel amortization policies. Nuclear Power Plants - Licensing, Operation and Waste Disposal The Company operates two nuclear generating plants: the single unit, 539 Mw Monticello Nuclear Generating Plant and the Prairie Island Nuclear Generating Plant with two units totaling 1,025 Mw. The Monticello Plant received its 40-year operating license from the Nuclear Regulatory Commission (NRC) on Sept. 8, 1970, and commenced operation on June 30, 1971. Prairie Island Units 1 and 2 received their 40-year operating licenses on Aug. 9, 1973, and Oct. 29, 1974, respectively, and commenced operation on Dec. 16, 1973, and Dec. 21, 1974, respectively. The Prairie Island and Monticello nuclear plants currently hold the Institute of Nuclear Power Operations' (INPO) top rating for plant operations and training. The Company is one of only two utilities in the nation to achieve INPO's top rating simultaneously at all of its nuclear plants. The Company previously operated the Pathfinder Plant near Sioux Falls, SD as a nuclear plant from 1964 until 1967, after which it was converted to an oil and gas-fired peaking plant. The nuclear portions were placed in a safe storage condition in 1971, and the Company began decommissioning in 1990. Most of the plant's nuclear material, which was contained in the reactor building and fuel handling building, was removed during 1991. Decommissioning activities cost approximately $13 million and have been expensed. A few millicuries of residual contamination remains in the operating plant. Operating nuclear power plants produce gaseous, liquid and solid radioactive wastes. The discharge and handling of such wastes are controlled by federal regulation. For commercial nuclear power plants, high-level radioactive waste includes used nuclear fuel. Low-level radioactive wastes are produced from other activities at a nuclear plant. They consist principally of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in the plant. A 1980 federal law places responsibility on each state for disposal of its low-level radioactive waste. The law encourages states to form regional agreements or compacts to dispose of regionally generated waste. Minnesota is a member of the Midwest Interstate Low-Level Radioactive Waste Compact Commission. Following the expulsion of Michigan from the Midwest Compact in 1991 for failing to make progress, Ohio was designated the host state. The State of South Carolina closed its disposal facility to out-of-region waste on July 1, 1994. Ohio is projecting completion of the low-level radioactive waste disposal facility in 2005. The Company, along with all other low-level radioactive waste generators in the Midwest Compact, will need to store low- level radioactive waste onsite in the interim. The federal government has the responsibility to dispose of domestic used nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act of 1982 requires the Department of Energy (DOE) to implement a program for nuclear waste management including the siting, licensing, construction and operation of repositories for domestically produced used nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes. The Company has contracted with the DOE for the disposal of used nuclear fuel. The DOE charges a quarterly disposal fee based on nuclear electric generation sold. This fee ranges from approximately $10 million to $12 million per year, which NSP recovers from its customers in cost-of-energy rate adjustments. In 1985, NSP paid the DOE a one-time fee of $95 million for fuel used prior to April 7, 1983. In 1979 the Company began expanding the used nuclear fuel storage facilities at its Monticello Plant by replacement of the racks in the storage pool. Also, in 1987, the Company completed the shipment of 1,058 spent fuel assemblies from the Monticello Plant to a General Electric storage facility in Morris, Illinois. As a result, the plant now has sufficient pool storage capacity to operate until 2008. Storage availability for operation beyond 2008 is not assured at this time. In 1976 the Company began expanding the used nuclear fuel storage facilities at its Prairie Island Plant by replacement of the racks in the storage pool. Total capacity was increased from 210 fuel assemblies to 1,386 fuel assemblies. The used nuclear fuel storage facilities at the Company's Prairie Island Plant are expected to reach full capacity during 1995. In May 1994 additional on-site dry cask fuel storage facilities were approved by the Minnesota Legislature which are expected to provide sufficient storage capacity to operate the plant until at least 2002, provided the Company satisfies certain responsibilities. Seventeen dry cask containers, each of which can store approximately one-half year's used fuel, can become available as follows: five immediately in 1994; four more in 1996 if an application for an alternative storage site is filed, an effort to locate such a site is made and 100 MW of wind generation is available or contracted for construction; and the final eight in 1999 unless the specified alternative site is not operational or under construction, certain resource commitments are not met or the Minnesota Legislature revokes its approval. An updated nuclear decommissioning study and nuclear plant depreciation capital recovery request was filed with the MPUC in July 1994 for the Company's nuclear power plants. Although management expects to operate the Prairie Island plant units through the end of its useful lives, the requested capital recovery would allow for the plant to be fully depreciated, including the accrual and recovery of decommissioning costs, about six years earlier than the end of its useful life. The proposed cost recovery period has been reduced because of the uncertainty regarding the spent fuel storage situation. On Jan. 25, 1995 the MPUC issued an order approving this filing. On Feb. 14, 1995 the North American Water Office (NAWO) filed a petition for reconsideration with the MPUC to change the capital recovery period for Prairie Island, so that the plant is fully depreciated by 2002. The petition concerns the issue of used nuclear fuel storage after 2002. A decision by the MPUC is expected by the end of 1995. During the past several years, the NRC has issued a number of regulations, bulletins and orders that require analyses, modification and additional equipment at commercial nuclear power plants. The Company has spent $528 million since 1971, and approximately $6 million, $11 million and $53 million for 1994, 1993 and 1992, respectively. In addition, the Company expects to expend an additional $2 million for currently required NRC analyses, modification and additional equipment. The NRC is engaged in various ongoing studies and rulemaking activities that may impose additional requirements upon commercial nuclear power plants. Management is unable to predict any new requirements or their impact on the Company's facilities and operations. See Note 16 to the Financial Statements under Item 8 for further discussion of nuclear fuel disposal issues and information on decommissioning of the company's nuclear facilities. Also, see Note 17 to the Financial Statements under Item 8 for a discussion of the Company's nuclear insurance and potential liabilities under the Price-Anderson liability provisions of the Atomic Energy Act of 1954. Electric Operating Statistics The following table summarizes the revenues, sales and customers from NSP's electric transmission and distribution business: 1994 1993 1992 1991 1990 Revenues (thousands) Residential With space heating $ 66 962 $ 68 222 $ 63 376 $ 67 878 $ 62 823 Without space heating 616 821 583 371 534 676 568 672 522 580 Small commercial and industrial 351 287 327 888 312 581 315 946 299 392 Large commercial and industrial 824 195 780 444 718 712 713 177 671 621 Street lighting and other 28 936 29 214 29 764 30 720 29 549 Total retail 1 888 201 1 789 139 1 659 109 1 696 393 1 585 965 Sales for resale 146 239 159 498 137 962 145 008 137 965 Miscellaneous 32 204 26 279 26 245 21 837 25 161 Total $ 2 066 644 $1 974 916 $ 1 823 316 $ 1 863 238 $ 1 749 091 Sales (millions of kilowatt-hours) Residential With space heating 1 076 1 094 1 041 1 141 1 068 Without space heating 8 227 7 998 7 640 8 226 7 805 Small commercial and industrial 5 585 5 307 5 224 5 330 5 180 Large commercial and industrial 17 874 17 117 16 365 16 286 15 867 Street lighting and other 334 344 372 386 385 Total retail 33 096 31 860 30 642 31 369 30 305 Sales for resale 6 733 8 044 6 530 6 083 6 281 Total 39 829 39 904 37 172 37 452 36 586 Customer accounts (Dec. 31) Residential With space heating 76 050 75 644 74 939 74 646 74 623 Without space heating 1 146 578 1 131 928 1 119 354 1 104 772 1 091 291 Small commercial and industrial 142 858 141 446 140 768 139 266 138 066 Large commercial and industrial 8 172 8 114 7 904 7 758 7 442 Street lighting and other 4 836 4 813 4 627 7 662 7 435 Total retail 1 378 494 1 361 945 1 347 592 1 334 104 1 318 857 Sales for resale 70 71 74 72 78 Total 1 378 564 1 362 016 1 347 666 1 334 176 1 318 935
GAS UTILITY OPERATIONS Competition NSP provides retail gas service in portions of eastern North Dakota and northwestern Minnesota, the eastern portions of the Twin Cities metro area, and other regional centers in Minnesota (Mankato, St. Cloud and Winona) and Wisconsin (Eau Claire, La Crosse and Ashland). NSP is directly connected to four interstate natural gas pipelines serving these regions: Northern Natural Gas Company (Northern), Viking, Williston Basin Interstate Pipeline Company (Williston) and Great Lakes Transmission Limited Partnership (Great Lakes). Approximately 90 percent of NSP's retail gas customers are served from the Northern pipeline system. During 1992 and 1993, the FERC issued a series of orders (together called Order 636) that addressed interstate natural gas pipeline restructuring. This restructuring required all interstate pipelines, including those serving NSP, to "unbundle" each of the services they provide: sales, transportation, storage and ancillary services. To comply with Order 636, NSP executed new pipeline transportation service and gas supply agreements effective Nov. 1, 1993, as discussed below. While these new agreements create a new form of contractual obligation, NSP believes the new agreements provide flexibility to respond to future changes in the retail natural gas market. NSP expects its financial risk under the new transportation agreements to be no greater than the risk faced under the previous long-term full requirements gas supply contracts with interstate pipelines. As a result of the changes in the natural gas industry in the last decade, culminating in Order 636, the natural gas supply network throughout North America has been transformed into an integrated gas supply grid where NSP purchases natural gas from numerous suppliers, directly contracts for transportation service on directly connected and upstream pipelines, and is able to flexibly deliver the supplies to any NSP retail gas service territory. In addition, NSP directly contracts for underground storage and owns and operates several liquified natural gas and propane-air peak shaving facilities. NSP's diversified supply and transportation contracts, as well as underground storage and peak shaving facilities, provide NSP with the ability to meet customer needs with a reliable and economic natural gas supply. Order 636 ended the traditional pipeline sales service function effective Nov. 1, 1993. This is a significant change for the natural gas industry. Traditionally, the pipeline sales function met two important needs for local distribution companies (LDCs) such as NSP, which serve primarily weather- sensitive space heating markets: (1) reliability of supply and (2) flexibility to meet varying load conditions in response to day-to-day weather variations. NSP believes the new unbundled services under Order 636 have to date proved to be as reliable and flexible as the traditional sales service. The implementation of Order 636 applies additional competitive pressure on all LDCs to keep gas supply and transmission prices for their large customers competitive because of the alternatives now available to these customers. Like gas LDCs, these customers now have expanded ability to buy gas directly from suppliers and arrange pipeline and LDC transportation service. NSP has provided unbundled transportation service since 1987. Transportation service does not currently have an adverse effect on earnings because NSP's sales and transportation rates have been designed to make NSP economically indifferent as to whether it sells or transports gas. However, some transportation customers may have greater opportunities or incentives to physically bypass the LDC distribution system. NSP has arranged its gas supply and transportation portfolio in anticipation that it may be required to terminate its retail merchant sales function. Overall, NSP expects Order 636 will enhance its ability to remain competitive and allow it to increase certain of its margins by providing an increased selection of services to its customers. Order 636 allows interstate pipelines to negotiate with customers to recover up to 100 percent of prudently incurred "transition costs" attributable to Order 636 restructuring. Recoverable transition costs can include "buy down" and "buy out" costs for remaining gas supply and upstream pipeline transportation agreements, unrecovered deferred gas purchase costs, and the cost to dispose of regulated assets no longer needed because of the termination of the merchant function (e.g., financial losses on the sale of regulated storage facilities). NSP's primary gas supplier, Northern, is in the process of determining the final amount of transition costs to be passed on to customers as a result of Order 636 restructuring. Northern's restructuring provided for the assignment of a significant portion of Northern's gas supply and upstream contract obligations. This solution was beneficial because Northern's customers contracted directly for obligations, rather than paying to buy out of those obligations and then contracting with the same gas suppliers and pipelines to replace the merchant function. The total transition costs recoverable for the remaining unassigned agreements is limited to $78 million. In addition, Northern may seek transition cost recovery for certain other costs, subject to prudency review. Northern's total Order 636 transition costs, to be passed on to all of its customers, are estimated to be approximately $100 million. Northern will recover the prudent transition costs by amortizing the amount over a period of several years, and including the amortized costs as a component of its transportation charges. NSP estimates that it will be responsible for less than $12 million of Northern's transition costs, spread over a period of approximately five years, which began Nov. 1, 1993. To date, NSP's regulatory commissions have approved recovery of restructuring charges in retail gas rates. NSP has no significant Order 636 transition cost responsibilities to its other pipeline suppliers. FERC has ruled that NSP has no transition cost obligation to Williston for its primary transportation service since it was never a gas sales customer of that pipeline. Viking incurred no Order 636 transition costs. NSP does not have significant transportation service on ANR Pipeline and Great Lakes subject to transportation cost charges under pricing in effect after Order 636. The gas services available to NSP's customers were enhanced beginning in 1993 through the acquisitions of Viking in June 1993 and the assets of a gas marketing business by a new NSP subsidiary, Cenergy, Inc, in October 1993. Viking provides NSP with continued access to competitive interstate natural gas transportation. Cenergy can provide more customized value-added energy services to retail gas customers without increasing costs within the regulated retail gas distribution business. See the Other Subsidiaries section herein for further discussion of Viking and Cenergy. The NSP gas operations area has taken significant steps to position itself to take on the additional responsibilities and take advantage of the new market opportunities resulting from the restructuring of the natural gas industry. In addition to construction of new pipeline interconnections, modernization of its propane-air peaking facilities, and fundamental changes to its supply portfolio including underground storage, NSP installed a state- of-the-art delivery management system in July 1994. NSP's gas utility took advantage of opportunities to expand into new service territory during 1994. NSP extended service to 15,300 customers in 13 new communities. In addition to exploring new growth opportunities available, NSP is also focusing on conversion of potential customers who are located near NSP's gas mains but are not hooked up to receive the service. NSP estimates there are approximately 18,000 potential customers that fall into this category. The largest 1994 expansion project occurred in Crow Wing and Cass counties in north central Minnesota. Outside the St Paul-Minneapolis area, these counties are experiencing the fastest growth of all counties in Minnesota. The project included laying approximately 550 miles of pipeline in 10 of the cities in the Brainerd Lakes area. The project's net capitalized investment cost was approximately $23 million. Construction began in June 1994 and was completed in November 1994. There were 6,300 new customers signed up under this project as of Dec 31, 1994. The MPUC approved a "new town" rate surcharge for customers in this area to support NSP's capital investment in the project. Subject to continued regulatory approval, the surcharge will be in effect for up to 15 years. The Company's gas operation has organized a non-utility service offering individuals service contracts on a variety of home appliances. Working in partnership with local independent service contractors, NSP Advantage Service offers 24 hour service. Depending on the level of service contracted, Advantage Service customers have coverage to help avoid the expense and inconvenience of unexpected appliance repairs. This service is being offered to individuals within NSP's service territory. Capability and Demand NSP categorizes its gas supply requirements as firm (primarily for space heating customers) or interruptible (commercial/industrial customers with an alternate energy supply). NSP's maximum daily sendout (firm and interruptible) of 686,130 MMBtu for 1994 occurred on Jan. 17, 1994. NSP's primary gas supply sources are purchases of third-party gas which are delivered under gas transportation service agreements with interstate pipelines. In addition, NSP has contracted with four providers of underground natural gas storage services to meet the heating season and peak day requirements of NSP gas customers. These agreements provide for firm deliverable pipeline capacity of approximately 540,396 MMBtu/day. Using storage reduces the need for firm gas supplies. These storage agreements provide NSP storage for approximately 16% of annual and 32% of peak daily firm requirements. NSP also owns and operates three liquified natural gas (LNG) plants with a storage capacity of 2.53 Bcf equivalent and four propane-air plants with a storage capacity of 1.42 Bcf equivalent to help meet the peak requirements of its firm residential, commercial and industrial customers. These peak shaving facilities have production capacity equivalent to 242,300 Mcf of natural gas per day, or approximately 35% of peak day firm requirements. NSP's LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the "needle peaks" caused by firm space heating demand on extremely cold winter days. The cost of gas supply, transportation service and storage service is recovered through the purchased gas adjustment. The average cost of gas and propane held in inventory for the latest test year is allowed in rate base by the MPUC and the PSCW. A number of NSP's interruptible industrial customers purchase their natural gas requirements directly from producers or brokers for transportation and delivery through NSP's distribution system. The transportation rates have been designed to make NSP economically indifferent as to whether NSP sells and transports gas or only transports gas. However, to the extent contractual terms allow, rates would increase based on changes in transportation and other costs. Gas Supply and Costs As a result of Order 636 restructuring, NSP's natural gas supply commitments have been unbundled from its gas transportation and storage commitments. NSP's gas utility actively seeks gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased risk and economical rates. This diversification involves numerous domestic and Canadian supply sources, varied contract lengths, and transportation contracts with seven natural gas pipelines. The Company's supply options were enhanced in 1992 with the successful completion of a direct interconnection to the Williston system near Fargo, North Dakota. The addition of this direct connection allows the Company more direct access to additional productive gas supply basins in western North Dakota and Wyoming, and provides the Company an alternative to its two traditional pipeline suppliers (Northern and Viking). Among other things, Order 636 provides for the use of the "straight fixed/variable" rate design that allows pipelines to recover all their fixed costs through demand charges. NSP has firm gas transportation contracts with the following seven pipelines. The contracts expire in various years from 1995 through 2012. Northern Natural Gas Great Lakes Transmission Limited Partnership Williston Basin Interstate Northern Border Pipeline Viking Gas Transmission ANR Pipeline TransCanada Gas Pipeline The agreements with Great Lakes, Northern Border, ANR and TransCanada provide for firm transportation service upstream of Northern Natural and Viking, allowing competition among suppliers at supply pooling points, minimizing commodity gas costs. In addition to these fixed transportation charge obligations, NSP has entered into firm gas supply agreements that provide for the payment of monthly or annual reservation charges irrespective of the volume of gas purchased. The total annual obligation is approximately $20.4 million. These agreements are beneficial because they allow NSP to purchase the gas commodity at a high load factor at rates below the prevailing market price reducing the total cost per Mcf. NSP has certain gas supply and transportation agreements, which include obligations for the purchase and/or delivery of specified volumes of gas, or to make payments in lieu thereof. At Dec. 31, 1994, NSP was committed to approximately $376.5 million in such obligations under these contracts, over the remaining contract terms, which range from the years 1995-2013. These obligations include some of the effects of contract revisions made to comply with Order 636. NSP has negotiated "market out" clauses in its new supply agreements, which reduce NSP's purchase obligations if NSP no longer provides merchant gas service. NSP purchases firm gas supply from a total of approximately 20 domestic and Canadian suppliers under contracts with durations of one year to 10 years. NSP purchases no more than 20% of its total daily supply from any single supplier. This diversity of suppliers and contract lengths allows NSP to maintain competition from suppliers and minimize supply costs. NSP's objective is to be able to terminate its retail merchant sales function, if either demanded by the marketplace or mandated by regulatory agencies, with no financial cost to NSP. The state utility commissions in Minnesota, North Dakota, Wisconsin and Michigan allowed NSP to fully recover the costs of these restructured services through purchased gas adjustments to customer rates. Purchases of gas supply or services by NSP from its Viking pipeline affiliate and Cenergy gas marketing affiliate are subject to approval by the MPUC. The MPUC has approved all the Company's transportation contracts with Viking and a spot gas purchase agreement with Cenergy. Requests for approval between the Company and the Wisconsin Company and between the Company and NSP's generating plants are pending MPUC approval. The following table summarizes the average cost per MMBtu of gas purchased for resale by NSP's gas distribution business which excludes Viking and Cenergy: The Company Wisconsin Company 1991 $2.50 $2.73 1992 $2.71 $2.80 1993 $3.11 $3.02 1994 $2.59 $3.13 Gas Operating Statistics The following table summarizes the revenue, sales and customers from NSP's gas business:
1994 1993 1992 1991 1990 Revenues (thousands) Residential With space heating $ 204 668 $ 220 828 $ 178 164 $ 179 161 $ 164 039 Without space heating 2 838 2 715 2 523 2 614 2 711 Commercial and industrial Firm 120 912 131 431 105 829 105 703 97 015 Interruptible 49 384 52 216 41 612 40 768 43 779 Interstate transmission (Viking)* 14 075 9 019 0 0 0 Miscellaneous ** 28 026 12 867 8 078 9 674 7 913 Total $ 419 903 $ 429 076 $ 336 206 $ 337 920 $ 315 457 Sales (thousands of mcf) Residential With space heating 38 427 40 946 35 136 37 493 33 445 Without space heating 323 331 323 359 370 Commercial and industrial Firm 27 342 28 622 24 273 25 429 22 793 Commercial and industrial 19 373 18 559 15 823 15 813 16 730 Miscellaneous 212 186 108 325 555 Total 85 677 88 644 75 663 79 419 73 893 Other gas delivered (thousands of mcf) Interstate transmission (Viking) * 131 074 75 188 0 0 0 Agency, transportation and off-system sales 13 466 8 128 7 332 7 549 6 298 Total 144 540 83 316 7 332 7 549 6 298 Customer accounts (at Dec. 31) Residential With space heating 351 773 337 868 326 439 314 843 303 402 Without space heating 18 961 19 408 19 841 20 294 21 004 Commercial and industrial 37 140 36 185 35 458 34 663 33 749 Total 407 874 393 461 381 738 369 800 358 155 * Excludes $2.2 million of revenues (16,845 thousands of mcfs) for intercompany sales in 1994. ** Includes NSP revenues for agency and transportation services and off-system sales.
NRG ENERGY, INC. NRG Energy, Inc. (NRG) is the Company's subsidiary that develops, builds, acquires, owns and operates several non-regulated energy-related businesses. It was incorporated in Delaware on May 29, 1992 and assumed ownership of the assets of NRG Group, Inc., including its subsidiary companies. The businesses that NRG currently owns or operates generated 1994 revenues of $81 million and had assets of $407 million at Dec. 31, 1994. NRG conducts business through various subsidiaries, including: NRG International, Inc.; Graystone Corporation; Scoria Incorporated; San Joaquin Valley Energy I, Inc.; San Joaquin Valley Energy IV, Inc.; NRG Energy Jackson Valley I, Inc.; NRG Energy Jackson Valley II, Inc.; NEO Corporation; NRG Energy Center, Inc.; NRG Sunnyside Inc. and NRG Operating Services, Inc. Operating Businesses In Dec. 1993, NRG, through a wholly owned foreign subsidiary, agreed to acquire a 33% interest in the coal mining, power generation and associated operations of Mitteldeutsche Braunkohlengesellschaft mbh (MIBRAG), located south of Leipzig, Germany. MIBRAG is a German corporation formed by the German government to hold two open-cast brown coal (lignite) mining operations, a lease on an additional mine, the associated mining rights and rights to future mining reserves, two small industrial power plants and a circulating fluidized bed power plant, a district heating system and coal briquetting and dust production facilities. Under the acquisition agreement, Morrison Knudsen Corporation and PowerGen plc also each acquired a 33% interest in MIBRAG, while the German government retained a one-percent interest in MIBRAG. The investor partners began operating MIBRAG effective Jan. 1, 1994 and the legal closing occurred Aug. 11, 1994. NRG's acquisition investment in MIBRAG, including capitalized development costs, was approximately $16 million. In March of 1994, NRG, through wholly owned foreign subsidiaries, as part of an unincorporated joint venture with Comalco Limited of Australia (Comalco) and other parties, acquired a 37.5% interest in the Gladstone Power Station, a 1680 Mw coal-fired plant in Gladstone, Queensland, Australia from the Queensland Electricity Commission. A large portion of the electricity generated by the station is sold to Comalco for use in its aluminum smelter, pursuant to long-term power purchase agreements. NRG, through an Australian subsidiary, operates the Gladstone plant. NRG's acquisition investment in the Gladstone project, including capitalized development costs, was approximately $70 million. NRG operates two refuse-derived fuel (RDF) processing plants and an ash disposal site in Minnesota. The ownership of one plant was transferred by the Company to NRG at the end of 1993. The legal transfer of ownership of the Company's 85% share of the other RDF plant and of the ash disposal site was approved by the serviced counties with transfer to NRG expected in 1995. In 1994, workers at the RDF plants processed more than 730,000 tons of municipal solid waste into approximately 640,000 tons of RDF that was burned at two NSP power plants and at a power plant owned by United Power Association. NRG also owns and operates three steam lines in Minnesota that provide steam from the Company's power plants to the Waldorf Corporation, the Andersen Corporation and the Minnesota Correctional Facility in Stillwater. During 1993, the Company formed NEO Corporation, a wholly owned subsidiary, which owns a 50% interest in Minnesota Methane LLC. Minnesota Methane LLC is developing small scale waste to energy facilities utilizing landfill gas. During 1994, the ownership of NEO Corporation was transferred by the Company to NRG. On Dec. 20, 1994, NEO acquired a 50% ownership in STS HydroPower Limited, an independent power producer with 21 Mw of hydroelectric facilities throughout the United States. NEO's acquisition investment in STS was approximately $4 million. NRG, through wholly owned subsidiaries, owns 45% of the San Joaquin Valley Energy partnership, (SJVEP), which owns four power plants located near Fresno, California with a total capacity of 55 Mw. Through February 1995, the plants operated under long-term Standard Offer 4 (SO4) power sales contracts with Pacific Gas & Electric (PG&E) which expire in 2017. On February 28, 1995 PG&E reached basic agreements with SJVEP to acquire the SO4 contracts. The parties entered into a bridging agreement to cover the period until all regulatory approvals are received for the transaction. The bridging agreement required SJVEP to cease power deliveries to PG&E as of February 28, 1995. The negotiated agreements will result in cost savings for PG&E customers as well as economic benefits for SJVEP. The final impact of this transaction on the financial results of NSP will not be known until the agreements have been approved and all costs associated with the idling of the facilities are known. It is expected that a one-time gain from the transaction will be recorded in the first half of 1995. SJVEP will continue to own and maintain the facilities and will explore all available options. NRG, through wholly owned subsidiaries, owns 50% of the Jackson Valley Energy partnership, which owns and operates a 15 Mw cogeneration power plant near Sacramento, California. The plant has a long-term power sales agreement with Pacific Gas & Electric through 2014. NRG, through a wholly owned subsidiary, purchased the assets of the Minneapolis Energy Center (MEC), a downtown Minneapolis district heating and cooling system in August of 1993. The system utilizes steam and chilled water generating facilities to heat and cool buildings for approximately 90 heating and 30 cooling customers. The primary assets include the main plant, with 800,000 lbs/hour of steam capacity and 22,000 tons/hour of chilled water capacity, three satellite plants, two standby plants, six miles of steam lines and two miles of chilled water distribution lines. Existing long-term contracts with MEC customers remain in effect under NRG's ownership. On Dec. 31, 1994 NRG, through a wholly owned subsidiary, purchased a 50% ownership interest in Sunnyside Cogeneration Associates (SCA), a Utah joint venture (partnership), which owns and operates a 51 Mw waste coal plant in Utah. The acquisition investment by NRG was approximately $11 million. The waste coal plant is currently being operated by a 50% owned NRG partnership. Scoria Incorporated and Western SynCoal Co., a subsidiary of Montana Power Co., completed construction in January 1992 of a demonstration coal conversion plant designed to improve the heating value of coal by removing moisture, sulfur and ash. The plant, located in Montana, has the ability to produce 300,000 tons of clean coal annually which, when burned, produces emissions in compliance with the Clean Air Act. The fuel may be an alternative to scrubbers for some energy companies. Testing of the plant ended in August 1993 and commercial operations began at that time. NRG's net capitalized investment in the Scoria coal project was written down by $3.5 million in 1994 to reflect reductions in the expected future operating cash flows from the project. NRG continues to evaluate the recoverability of its remaining investment in the Scoria project. New Business Development NRG is pursuing several energy-related investment opportunities, including those discussed below, and continues to evaluate other opportunities as they arise. Potential capital requirements for these opportunities are discussed in the "Capital Spending and Financing" section. On Dec. 10, 1993, NRG, through a wholly owned foreign subsidiary, acquired a 50% interest in a German corporation, Saale Energie GmbH (Saale). Saale owns a 400 Mw share of a 900 Mw power plant currently under construction in Schkopau, Germany, which is near Leipzig. PowerGen plc of the United Kingdom acquired the remaining 50% interest in Saale. Saale was formed to acquire a 41.1% interest in the power plant. VEBA Kraftwerke Ruhr AG of Gelsenkirchen, Germany (VKR), is the builder of the Schkopau plant. VKR owns the remaining 58.9% interest in the power plant and will operate the plant. The plant will be fired by brown coal (lignite) mined by MIBRAG under a long- term contract. Saale has a long-term power sales agreement for its 400 Mw share of the Schkopau facility with VEAG of Berlin, Germany, the company that controls the high-voltage transmission of electricity in the former East Germany. The first unit of the plant is due to be completed by the end of 1995 and the second unit is due to be completed in mid-1996. Through Dec. 31, 1994 NRG had invested $20 million to acquire its interest in Saale including capitalized development costs. NRG's future equity commitment to Saale through 1996 is expected to be no more than $50 million. On June 10, 1993, NRG, together with the International Finance Corporation (an affiliate of the World Bank), CMS Energy Corporation (the parent company of Consumers Power Company) and later Corporation Andina de Fomento (CAF) formed the Scudder Latin American Trust for Independent Power (Scudder), an investment fund which is intended to invest in the development of new power plants and privatization of existing power plants in Latin America and the Caribbean. The fund has retained Scudder Stevens & Clark as its investment manager. The fund commenced its investment development efforts in September 1993. Each of the four investors has committed $25 million which the fund is seeking to invest over the next five years. The fund has commenced private placement activities to obtain additional investors in the fund, particularly other utility affiliates and institutional investors. As of Dec. 31, 1994, NRG has invested $4 million in Scudder. Scudder has reached agreements to purchase shares of two power plant projects in Latin America. Graystone Corporation, with several other companies, continues with permitting plans to build the first privately owned uranium enrichment plant in the United States. Construction of the Louisiana plant, which would provide fuel for the nuclear power industry, could begin in 1995. Because of the uncertainty surrounding the ultimate successful operation of this plant, NRG wrote off its $1.5 million investment in Graystone during 1994. Other In July 1994, Michigan Congeneration Partners Limited Partnership (MCP), a partnership between subsidiaries of NRG and Cogentrix Energy, Inc., reached an agreement with Consumers Power Company (Consumers), an electric utility headquartered in Jackson, Michigan, to terminate the power sales contract related to a 65 megawatt congeneration facility being developed by MCP in Parchment, Michigan. The agreement to terminate the contract required Consumers to make a payment to MCP of $29.8 million. As a result, NRG has recorded a net pretax gain from the termination of this contract of $9.7 million, which increased NSP's earnings by approximately nine cents per share in the third quarter of 1994. OTHER SUBSIDIARIES Viking Gas Transmission Company In June 1993, the Company acquired 100 percent of the stock of Viking Gas Transmission Company (Viking) from Tenneco Gas, a unit of Tenneco Inc., in Houston, Texas. Viking, which is now a wholly owned subsidiary of the Company, owns and operates a 500-mile interstate natural gas pipeline serving portions of Minnesota, Wisconsin and North Dakota with a capacity of approximately 400 million cubic feet per day. The Viking pipeline currently serves 10 percent of NSP's gas distribution system needs. Viking currently operates exclusively as a transporter of natural gas for third-party shippers under authority granted by the FERC. Rates for Viking's transportation services are regulated by FERC. See "Rate Matters by Jurisdiction" herein regarding rate recovery requested for a portion of the acquisition cost paid by NSP to acquire Viking. Cenergy, Inc. NSP's non-regulated wholly owned subsidiary, Cenergy, Inc., commenced operations in October 1993 through the acquisition from bankruptcy of selected assets of Centran Corporation, a natural gas marketing company. Cenergy, in addition to marketing natural gas, provides customized value-added energy services to retail customers, both inside NSP service territory and on a national basis through its offices in Houston, TX; Louisville, KY; Chesapeake, VA; Dallas, TX; Corpus Christi, TX; Chicago, IL; and Pittsburgh, PA. Cenergy offers customers many energy products and services including: utility billing analysis, end-use gas marketing, risk management, construction, energy services consulting and administrative services. The MPUC has approved an affiliate transaction contract, whereby Cenergy may make natural gas sales at market based rates (determined by competitive bids) to NSP for resale to retail gas customers. On Dec. 1, 1994 the FERC approved Cenergy's application to sell electric power (except electricity generated by NSP) in the United States, giving NSP an opportunity to enter the increasingly deregulated and competitive electric market. Cenergy is one of the first utility affiliates to obtain this approval from FERC. NSP is allowing open access to its electric transmission lines by other electric power providers throughout North America. Cenergy's initiative to buy and sell deregulated electricity is consistent with NSP's objective to embrace competition, which will benefit NSP customers and shareholders. On January 19, 1995 Cenergy and Atlantic Energy Enterprises signed a memorandum of understanding to establish Atlantic CNRG Services LLC, a new subsidiary of both companies. Each company will own 50% of the new venture that will develop new and expanded natural gas and electric energy products and services, primarily in the Northeast region. Eloigne Company In 1993, the Company established Eloigne Company (Eloigne), to identify and develop affordable housing investment opportunities. Eloigne's principal business is the acquisition of a broadly diversified portfolio of rental housing projects which qualify for low income housing tax credits under federal tax law. As of Dec. 31, 1994, approximately $19 million had been invested in Eloigne projects. Tax credits recognized in 1994 as a result of these investments were approximately $2.0 million. ENVIRONMENTAL MATTERS NSP's policy is to proactively prevent adverse environmental impacts by regularly monitoring operations to ensure the environment is not adversely affected, and take timely corrective actions where past practices have had a negative impact on the environment. Significant resources are dedicated to environmental training, monitoring and compliance matters. NSP strives to maintain compliance with all applicable environmental laws. In general, the Company has been experiencing a trend toward increasing environmental monitoring and compliance costs, which has caused and may continue to cause slightly higher operating expenses and capital expenditures. The Company has spent approximately $700 million on capitalized environmental improvements to new and existing facilities since 1968. The Company expects to incur approximately $15 million in capital expenditures and approximately $9 million in operating expenses for compliance with environmental regulations in 1995. The precise timing and amount of future environmental costs are currently unknown. (For further discussion of environmental costs, see "Environmental Matters" under Management's Discussion and Analysis of Financial Condition and Results of Operations under Item 7, and Note 17 to the Financial Statements under Item 8.) Permits NSP is required to seek renewals of environmental operating permits for its facilities at least every five years. NSP believes that it is in compliance, in all material respects, with environmental permitting requirements. Waste Disposal The onsite storage pool for used nuclear fuel at the Company's Monticello Nuclear Generating Plant is expected to provide sufficient storage capacity to operate the plant until 2008. The onsite storage pool for used nuclear fuel at the Company's Prairie Island Nuclear Generating Plant (Prairie Island) was filled during refueling in June 1994, so adequate space for a subsequent refueling was no longer available. In anticipation of this, the Company, in 1989, proposed construction of a temporary onsite dry cask storage facility for used nuclear fuel at Prairie Island. The Minnesota Legislature (Legislature) considered the dry cask storage issue during its 1994 legislative session as required by a Minnesota Court of Appeals ruling in June 1993. On May 10, 1994, the Governor of the State of Minnesota (Governor) signed into law a bill passed by the Legislature on May 6, 1994. The law authorizes the Company to install 17 dry casks at Prairie Island, which should provide storage capacity to allow operation until at least 2002 and 2003 for units 1 and 2 respectively, if the Company satisfies certain responsibilities. The Company executed an agreement with the governor concerning the renewable energy and alternative siting commitments contained in the new law and is now authorized to install the first increment of five casks. The second increment of four casks would be available if the Minnesota Environmental Quality Board finds that by Dec. 31, 1996, the Company has applied to the Nuclear Regulatory Commission for an alternative site license for the temporary used nuclear fuel storage facility, used good faith in locating an alternative site and has committed to build or purchase 100 megawatts of wind generation. The final increment of eight casks would be available unless prior to June 1, 1999, the Legislature specifically revokes the authorization for the final eight casks. The Legislature can revoke the authorization if an alternative storage site is not operational or under construction, or the Company fails to meet certain renewable energy commitments, including the increased use of wind power and biomass generation facilities by Dec. 31, 1998. (See Notes 16 and 17 of Notes to Financial Statements under Item 8 for further discussion of this matter.) During 1994, NSP and a group of 30 other utilities and two private firms formed a consortium to establish a temporary used nuclear waste storage site. On March 9, 1995 the Mescalero Apache tribal members, in a second referendum, voted in favor of proceeding with a temporary used nuclear fuel storage site on reservation lands in New Mexico. The consortium is preparing to invest $135 million to prepare a license application, conduct environmental studies, pay host fees to the Mescalero tribe and construct a storage facility that could open in 2002. The Company and NRG have contractual commitments to convert municipal solid waste to boiler fuel and burn the fuel to generate electricity. NRG owns and/or operates two resource recovery plants that produce RDF from the waste. The RDF is burned at the Company's Red Wing and Wilmarth plants in the Company's service area, the French Island plant in the Wisconsin Company's service area, and the Elk River plant owned by United Power Association. Processing and burning RDF provides an additional economical source of electric capacity and energy, which is beneficial to NSP's electric customers. The Company's commitment to this program enables counties to meet state- mandated goals to reduce the amount of solid waste now going to landfills. In addition, the program provides for increased materials recovery and increased use of municipal solid waste as an energy source. NSP has met or exceeded the removal and disposal requirements for polychlorinated biphenyl (PCB) equipment as required by state and federal regulations. NSP has removed nearly all known PCB capacitors from its distribution system. NSP also has removed nearly all known network PCB transformers and equipment in power plants containing PCBs. NSP continues to test and dispose of PCB-contaminated mineral oil and equipment in accordance with regulations. PCB-contaminated mineral oil is detoxified and reused or burned for energy recovery at permitted facilities. Any future cleanup or remediation costs associated with past PCB disposal practices is unknown at this time. Air Emissions Control And Monitoring In September 1994, the U.S Environmental Protection Agency (EPA) proposed new air emission guidelines for municipal waste combustors. These proposed guidelines are expected to be finalized in September 1995. Once the federal guidelines are finalized, the MPUC will update Minnesota state waste combustor rules to meet or be more restrictive than the final federal guidelines. The deadline for complying with these rules is June 1997. To meet the new federal and state requirement, the Company must install additional pollution control and monitoring equipment at the Red Wing plant and additional monitoring equipment at the Wilmarth plant. The Company is evaluating equipment to meet the requirements. Equipment may cost between $6 million and $10 million. The Clean Air Act, including the Amendments of 1990, (the "Clean Air Act") impose stringent limits on emissions of sulfur dioxide and nitrogen oxides by electric utility generating plants. These limits will be phased in beginning in 1995. The majority of the rules implementing this complex legislation are finalized. No capital expenditures are anticipated to comply with the sulfur dioxide emission limits of the Clean Air Act. Based on revisions to the sulfur dioxide portion of the program, NSP's emission allowance allocations for the years 1995-1999 were dramatically reduced from prior rulemaking. In 1994, $5 million was spent and it is expected that approximately $7 million will be spent on equipment at generation facilities to reduce emissions of nitrogen oxides for compliance with the Clean Air Act over the next 4 years. The Sherburne County Generating Plant's (Sherco) unit 2 Low Nox Burner Technology was upgraded in 1994 to further reduce its emissions of nitrogen oxides. The same upgrade is scheduled for Sherco unit 1 in 1998. Other expenditures may be necessary upon EPA's finalization of remaining rules. Capital expenditures will be required for opacity compliance in 1995-1999 at certain facilities as discussed below. As a part of its Clean Air Act compliance effort, the Company will test a type of air quality control device called a wet electrostatic precipitator at the Sherco generating plant. The equipment will be installed in 1995 inside one of the existing acid gas scrubber modules. Testing, anticipated to be completed in 1996, will determine the equipment's operational requirements and ability to reduce particulate emissions and opacity. The equipment is being examined as one option to lower opacity from Sherco units 1 and 2, as required by the EPA. Until testing is completed, it is unknown whether the equipment will result in full compliance with air quality standards. Total costs for equipment to reduce particulate emissions and opacity range from $90 million for the equipment being tested to approximately $300 million for other technology options. In December 1994, the Wisconsin Company completed installation of a control center monitoring system at the Bay Front generating plant in Ashland, Wisconsin. The control center which will monitor emission from the four generating units, was mandated by the Clean Air Act. The total cost of the project was approximately $1.3 million. The Company has conducted testing for air toxics at its major facilities and shared these results with state and federal agencies. The Company also conducted research on ways to reduce mercury emissions. This information has also been shared with state and federal agencies. The Clean Air Act requires the EPA to look at issuing rules for air toxic emissions from electric utilities. A report on this is due from the EPA to Congress in 1995. There is continued interest at the Minnesota Legislature to pass legislation restricting emissions of air toxics in the state. The Company cannot predict what impact these rules will have if passed. Water Quality Monitoring In compliance with federal and state laws and state regulatory permit requirements, and also in conformance with the Company's corporate environmental policy, the Company has installed environmental monitoring systems at all coal and RDF ash landfills and coal stockpiles to assess and monitor the impact of these facilities on the quality of ground and surface waters. Degradation of water quality in the state is prohibited by law and requires remedial action for restoration to an agreed upon acceptable clean-up level. Estimates of the cost of implementation of overall water quality monitoring does not have a material impact on NSP's operating results. The pending reauthorization of the Federal Clean Water Act will probably result in more stringent water quality rules, regulations and standards that will result in slightly greater operating costs for NSP facilities. Site Remediation Through the end of 1994, the Company had been designated by the EPA or state environmental agencies as a "potentially responsible party" (PRP) for 10 waste disposal sites to which the Company allegedly sent hazardous materials. Under applicable law, the Company, along with each PRP, could be held jointly and severally liable for the total site remediation costs. Those costs have been estimated at $122 million for all 10 PRP sites. In the event additional remediation is necessary or unexpected costs are incurred, the amount could be in excess of $122 million. The Company is not aware of the other parties inability to pay, nor does it know if responsibility for any of the sites is disputed by any party. Settlement with the EPA, state environmental agencies and other PRPs has been reached for six of these waste disposal sites for reimbursement of the past costs and expected future costs of remedial action. By reaching early settlement, the Company avoided litigation costs, increased costs of investigation and remediation and possible penalties that could have resulted and substantially increased the Company's allocation. For the remaining four sites, neither the amount of cleanup costs nor the final method of their allocation among all designated PRP's has been determined. However, the current estimate of the Company's share of future remediation costs for all four sites is approximately $1.0 million, which was recorded as a liability at Dec. 31, 1994. Until final settlement, neither the amount of cleanup costs nor the final method of their allocation among all designated PRPs can be determined. While it is not feasible to determine the precise outcome of these matters, amounts accrued represent the best current estimate of the Company's future liability for the cleanup costs of these sites. It is the Company's practice to vigorously pursue and, if necessary, litigate with insurers to recover costs. Through litigation, the Company has recovered from other PRPs a portion of the remedial costs paid to date. Management also believes that costs incurred in connection with the sites, which are not recovered from insurance carriers or other parties, may be recoverable in future ratemaking. In February 1995 a settlement was reached regarding one of the four sites for which the Company had been designated a PRP. The Company's allocation of costs approximated the liability accrued at Dec. 31, 1994. Both the Company and the Wisconsin Company have received notices for requests for information concerning groundwater contamination at a landfill site in Wisconsin. While neither the Company nor the Wisconsin Company have been named PRP's, both companies voluntarily joined a group of other parties to address the contamination at this site. A preliminary estimate of total remediation costs at the site is approximately $6 million. The Company's and Wisconsin Company's share of this cost is currently estimated to be approximately 1%. In addition, the administrator of a group of PRP's has notified the Wisconsin Company that it might be responsible for cleanup of a solid and hazardous waste landfill site. The Wisconsin Company contends that it did not dispose of hazardous wastes in the subject landfill during the time period in question. Because neither the amount of cleanup costs nor the final method of their allocation among all designated PRP's has been determined, it is not feasible to predict the outcome of the matter at this time. On March 2, 1995, the Wisconsin Department of Natural Resources (WDNR) notified the Wisconsin Company that it is a PRP at a creosote/coal tar contamination site in Ashland, WI. The Wisconsin Company has informed the WDNR of its belief that two sites exist. The first site, formerly a coal gas plant site, is NSP property. The second site is adjacent to the NSP site and is not owned by the Wisconsin Company. An existing condition report has been completed on an adjacent site. An estimate of site remediation costs, and the extent of the Wisconsin Company's responsibility, if any, for sharing such costs, is not known at this time. Investigations are underway to determine the Wisconsin Company's responsibility as well as that of predecessor companies contributing to the contamination on the adjacent site. The current estimate of the Wisconsin Company's share of future remediation costs at the NSP site is less than $750,000. This estimate is not based upon a formal remediation investigation and feasibility study. To the Wisconsin Company's knowledge, no study has been completed for the adjacent site, that describes remedial alternatives and clean-up cost estimates. The Wisconsin Company intends to seek rate recovery of significant costs it incurs associated with the clean-up of either Ashland Site. On March 13, 1995, the Minnesota Pollution Control Agency (MPCA) notified the Company that it intends to seek reimbursement from the Company for costs incurred at a disposal site in Rosemount, Minnesota. The Company has commenced an investigation to determine its involvement with the site. The MPCA has sought reimbursement of $139,000 from all parties. The extent of the Company's responsibility, if any, for sharing such costs, is not known at this time. The Company is continuing to investigate 15 properties either presently or previously owned by the Company that were, at one time, sites of gas manufacturing or storage plants, or coal gas pipelines. The purpose of this investigation is to determine if waste materials are present, if such materials constitute an environmental or health risk, if the Company has any responsibility for remedial action and if recovery under the Company's insurance policies can contribute to any remediation costs. The total cost of remediation of these sites is expected to range from $14 million to approximately $18 million, including $5.3 million which has been paid to date. The Company has commenced remediation efforts at five of the 15 sites. One of the active sites has been completed, while the remaining four are in various stages of remediation. Monitoring continues at the completed site. In addition, the Company has been notified that two other sites will require remediation, and a study will be conducted to determine the cost of clean up. No agreement or consent order has been negotiated to perform any extensive site investigations or clean-up at the other eight sites. Based upon information currently available with regard to these sites, management believes that accruals recorded represent the best current estimate of the costs of any required clean-up or remedial actions for former gas operating sites of the Company. Management believes costs incurred in connection with the sites that are not recovered from insurance carriers or other parties may be allowable costs for future ratemaking purposes. In 1994 the Company received approval of deferred accounting for certain investigation and remediation expenses. The ultimate rate treatment of any costs deferred will be determined in the Company's next general gas rate case. (See Note 17 of Notes to the Financial Statements under Item 8 for further discussion of this matter.) NSP has not developed any specific site restoration and exit plans for its fossil fuel plants, hydroelectric plants or substation sites as it currently intends to operate at these sites indefinitely. If such plans were developed in the future, NSP would intend to treat the costs as a removal cost of retirement in utility plant and include them in depreciation accruals. Removal cost estimates used to record depreciation expense are designed to recover the future cost to remove existing plant assets. Factors used to develop these estimates include historical expenses as well as engineering estimates. Contingencies In October 1992, the Company disclosed to the MPCA, the EPA and the NRC that its reports on halogen content of water discharged at the Company's Prairie Island nuclear generating plant were based on estimates of halogen content rather than actual physical samples of water discharged as required by the plant's permit. Even though the water discharges at the plant did not exceed the halogen levels allowed under the permit, the applicable state and federal statutes would permit the imposition of fines, the institution of criminal sanctions, and/or injunctive relief for the reporting violations. Corrective actions were taken by the Company. The Company and the MPCA are currently negotiating a Stipulation Agreement to address monitoring procedures used at Prairie Island between January and September 1992 that allegedly did not comply with the permits. The MPCA is alleging noncompliance with permit terms and conditions and is proposing a civil penalty of $105,436. Electric and magnetic fields (sometimes referred to as EMF) surround electric wires and conductors of electricity such as electrical tools, household wiring, appliances, electric distribution lines, electric substations and high-voltage electric transmission lines. NSP owns and operates many of these types of facilities. Some studies have found statistical associations between surrogates of EMF and some forms of cancer. The nation's electric utilities, including NSP, have participated in the sponsorship of more than $50 million in research to determine the possible health effects of EMF. Through its participation with the Electric Power Research Institute, NSP will continue its investigation and research with regard to possible health effects posed by exposure to EMF. No litigation has been commenced or claims asserted against NSP for adverse health effects related to EMF. However, several immaterial claims have been asserted against NSP for diminution of property values due to EMF. No litigation has commenced or is expected from these claims. Both regulatory requirements and environmental technology change rapidly. Accordingly, NSP cannot presently estimate the extent to which it may be required by law, in the future, to make additional capital expenditures or to incur additional operating expenses for environmental purposes. NSP also cannot predict whether future environmental regulations might result in significant reductions in generating capacity or efficiency or otherwise affect NSP's income, operations or facilities. CAPITAL SPENDING AND FINANCING NSP's capital spending program is designed to assure that there will be adequate generating and distribution capacity to meet the future electric and gas needs of its utility service area, and to fund investments in non- regulated businesses. NSP continually reassesses needs and, when necessary, appropriate changes are made in the capital expenditure program. Total NSP capital expenditures (including allowance for funds used during construction and excluding business acquisitions) totaled $409 million in 1994, compared to $362 million in 1993 and $428 million in 1992 These capital expenditures include gross additions to utility property of $387 million, $357 million (excluding Viking property acquired) and $423 million for years ended 1994, 1993 and 1992, respectively. Internally generated funds could have provided approximately 69% of all capital expenditures for 1994, 99% for 1993 and 49% for 1992. NSP's utility capital expenditures (including allowance for funds used during construction) are estimated to be $383 million for 1995 and $1.9 billion for the five years ended Dec. 31, 1999. Included in NSP's projected utility capital expenditures is $51 million in 1995 and $267 million during the five years ended Dec. 31, 1999, for nuclear fuel for NSP's three existing nuclear units. The remaining capital expenditures through 1999 are for many utility projects, none of which are extraordinarily large relative to the total capital expenditure program. Internally generated funds from utility operations are expected to equal approximately 85% of the 1995 utility capital expenditures and approximately 95% of the 1995-1999 utility capital expenditures. Internally generated funds from all operations are expected to equal approximately 60% and 80% respectively, of the total capital expenditures anticipated for 1995 and the five-year period 1995-1999. The foregoing estimates of utility capital expenditures and internally generated funds may be subject to substantial changes due to unforeseen factors, such as changed economic conditions, competitive conditions, resource planning, new government regulations, changed tax laws and rate regulation. In addition to capital expenditures, NSP invested $137 million in 1994 and $184 million in 1993 to acquire interests in non-regulated businesses and Viking. Investments in 1993 included business acquisitions of $159 million. (See "NRG Energy, Inc." and "Other Subsidiaries" herein.) NSP continues to evaluate opportunities to enhance its competitive position and shareholder returns through strategic acquisitions of existing businesses. Long-term financing may be required for acquisitions that NSP consummates. Although they may vary depending on the success, timing, and level of involvement in planned and future projects, potential capital requirements for investments in existing and additional non-regulated projects are estimated to be $153 million in 1995 and $623 million for the five-year period 1995- 1999. The majority of these non-regulated capital requirements relate to equity investments (excluding costs financed by project debt) in NRG's projects, as discussed previously. The remainder consists mainly of affordable housing investments by Eloigne Company. Equity investments by NRG and Eloigne would be funded through their own internally generated funds, equity investments by NSP, or long-term debt issued by the subsidiary. Such equity investments by NSP are expected to be financed on a long-term basis through NSP's internally generated funds or through NSP's issuance of common stock. EMPLOYEES AND EMPLOYEE BENEFITS At year end 1994 the total number of full- and part-time employees of NSP was approximately 7,670. NSP is represented by five local IBEW labor unions. On May 2, 1994 the IBEW members voted to ratify a three year labor agreement retroactive to Jan. 1, 1994. Labor and employee benefit costs are not expected to be materially affected by the terms of the new agreement. NSP recently reviewed employee and retiree benefits and implemented the following changes effective in 1994. These changes support NSP's goal of providing market-based benefits. Active nonbargaining medical premium increases: A two-year cost sharing strategy for medical benefits for nonbargaining employees was implemented in 1994. The strategy consisted of employees contributing 10% in 1994 and 20% in 1995 of the total medical cost. Retiree medical premium increases: Retiree medical premiums were increased in 1994 for existing and future retirees. For existing qualifying retirees, pension benefits have been increased to offset some of the premium increase. For future retirees, a six-year cost-sharing strategy was implemented with retirees paying 15 percent of the total cost of health care in 1994, increasing to a total of 40% in 1999. Nonbargaining pension plan lump sum option changes: Prior to 1994, nonbargaining employees had the option to receive their pension in either a lump sum or in monthly installments. Beginning in 1994, nonbargaining employees can choose a lump sum distribution in 25% increments upon termination of employment. Employees taking less than 100 percent will receive the rest of their benefits in monthly installments. At the end of 1994, this benefit was modified to allow a lump sum option only on the portion of pension benefit earned through Dec. 31, 1994. 401(k) changes: NSP currently offers eligible employees a 401(k) Retirement Savings Plan. In 1994, NSP matched employees' pre-tax 401(k) contribution up to $500 per year for nonbargaining employees and up to $400 per year for bargaining employees. In 1994, NSP's matching contribution was $2.6 million. In 1995, NSP's annual match will increase to $700 for nonbargaining employees. Under the terms of the bargaining agreement implemented in 1994, NSP's annual match for bargaining employees will increase to $500 in 1995 and $600 in 1996. Wage increases: No base wage scale increases were implemented in January 1994. Effective in 1994, NSP implemented a market-based pay structure for nonbargaining employees. NSP's new pay system uses salary surveys that indicate how local and regional companies pay their employees for comparable positions. In January 1995, nonbargaining employees received an average wage scale increase of 3.5%, while bargaining employees received a 2% base wage increase and 1.5% lump sum payment. As part of the new labor agreement, bargaining employees are no longer included in the Company's incentive compensation plan.
EXECUTIVE OFFICERS * Present Positions and Business Experience Name Age During the Past Five Years James J Howard 59 Chairman of the Board, President and Chief Executive Officer since 12/1/94; Chairman of the Board and Chief Executive Officer from 7/01/90 to 11/30/94; and prior thereto Chairman of the Board, President and Chief Executive Officer. Douglas D Antony 52 President - NSP Generation since 9/07/94; Vice President - Nuclear Generation from 1/01/93 to 9/06/94; General Manager - Monticello Nuclear Sitefrom 9/01/90 to 12/31/92; and prior thereto Plant Manager - Monticello. Loren L Taylor 48 President - NSP Electric since 10/27/94; Vice President - Customer Operations from 1/01/93 to 10/26/94; Vice President - Transmission and Inter-Utility Services from 11/01/89 to 12/31/92: and prior thereto Vice-President Human Resources. Keith H Wietecki 45 President - NSP Gas since 1/11/93; Vice President - Corporate Strategy from 1/01/93 to 1/10/93; Vice President - Electric Marketing & Sales from 4/25/90 to 12/31/92; and prior thereto Vice President - Electric Marketing and Customer Service. Arland D Brusven 62 Vice President - Finance since 7/01/94; Vice President - Finance and Treasurer from 1/01/93 to 6/30/94; Vice President and Treasurer from 9/01/90 to 12/31/92; and prior thereto Secretary and Financial Counsel. Jackie A Currier 43 Vice President and Treasurer since 7/01/94; Vice President - Corporate Strategy from 1/11/93 to 6/30/94; Director - Corporate Finance and Assistant Treasurer from 9/17/92 to 1/10/93; Director - Corporate Finance from 6/01/90 to 9/16/92; and prior thereto General Manager - Budget & Control. Gary R Johnson 48 Vice President & General Counsel since 11/01/91; and prior thereto Vice President - Law. Cynthia L Lesher 46 Vice President - Human Resources since 3/01/92; Director - Power Supply Human Resources from 8/15/91 to 2/29/92; Manager - White Bear Lake Area from 5/21/90 to 8/14/91; and prior thereto Manager -Metro Credit. Edward J McIntyre 44 Vice President and Chief Financial Officer since 1/01/93; President and Chief Executive Officer of Northern States Power Company (a Wisconsin corporation), a wholly owned subsidiary of the Company from 7/01/90 to 12/31/92; and prior thereto Vice President - Gas Utility. Thomas A Micheletti 48 Vice President - Public and Government Affairs since 10/27/94; Vice President - General Counsel and Secretary of NRG Energy, Inc. a wholly owned subsidiary of the Company from 5/11/94 to 10/26/94; Vice President-General Counsel, NRG from 9/15/93 to 5/10/94; and prior thereto Group Vice President for Minnesota Power and Light Company, a public utility located in Duluth, MN. Roger D Sandeen 49 Vice President, Controller and Chief Information Officer since 4/22/92; and prior thereto Vice President and Controller. Robert H Schulte 42 Vice President - Customer Service since 1/01/93; Vice President - Rates and Corporate Strategy from 7/01/90 to 12/31/92; and prior thereto General Manager - South Dakota Region. Edward L Watzl 55 Vice President - Nuclear Generation since 9/07/94; Prairie Island Site General Manager from 9/01/90 to 9/07/94; and prior thereto Plant Manager - Prairie Island. * As of 3/01/95
Item 2 - Properties The Company's major electric generating facilities consist of the following:
1994 1994 Capability Output Station and Unit Fuel Installed (Mw) (Millions of Kwh) Sherburne Unit 1 Coal 1976 712 3 988.2 Unit 2 Coal 1977 712 3 981.4 Unit 3 Coal 1987 514 4 139.6 Prairie Island Unit 1 Nuclear 1973 513 3 715.5 Unit 2 Nuclear 1974 512 4 552.9 Monticello Nuclear 1971 539 3 956.3 King Coal 1968 567 3 561.7 Black Dog 4 Units Coal 1952-1960 463 1 371.4 High Bridge 2 Units Coal 1956-1959 262 1 056.6 Riverside 2 Units Coal 1964-1987 366 1 745.9 Other Various Various 1,921 1 562.3
NSP's electric generating facilities provided 79% of its Kwh requirements in 1994. The current generating facilities are expected to be adequate base load sources of electric energy until 2004-2008, as detailed in the Company's electric resource plan filed with the MPUC in 1993. All of NSP's major generating stations are located in Minnesota on land owned by the Company. At Dec. 31, 1994, NSP had transmission and distribution lines as follows: Voltage Length (Pole Miles) 500Kv 265 345Kv 730 230Kv 285 161Kv 340 115Kv 1,560 Less than 115 Kv 31,530 NSP also has approximately 300 transmission and distribution substations with capacities greater than 10,000 kilovoltamperes (Kva) and approximately 270 with capacities less than 10,000 Kva. Manitoba Hydro, Minnesota Power Company and the Company completed the construction of a 500-Kv transmission interconnection between Winnipeg, Manitoba, Canada, and the Minneapolis-St Paul, Minnesota, area in May 1980. NSP has a contract with Manitoba Hydro-Electric Board for 500 Mw of firm power utilizing this transmission line. In addition, the Company is interconnected with Manitoba Hydro through a 230 Kv transmission line completed in 1970. (Also see Note 17 of Notes to Financial Statements under Item 8.) The gas properties of NSP include about 7,756 miles of natural gas transmission and distribution mains. NSP natural gas mains include approximately 102 miles with a capacity in excess of 275 pounds per square inch (psi) and approximately 7,654 miles with a capacity of less than 275 psi. In addition, Viking owns a 500-mile interstate natural gas pipeline serving portions of Minnesota, Wisconsin and North Dakota. Virtually all of the utility plant of the Company and the Wisconsin Company are subject to the lien of their first mortgage bond indentures pursuant to which they have issued first mortgage bonds. Item 3 - Legal Proceedings In the normal course of business, various lawsuits and claims have arisen against NSP. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters. On July 22, 1993, a natural gas explosion occurred on the Company's distribution system in St. Paul, Minn. Total damages are estimated to exceed $1 million. The Company has a self-insured retention deductible of $1 million, with general liability coverage of $150 million, which includes coverage for all injuries and damages. While 12 lawsuits have been filed, including one proposed class action suit, the litigation following this incident is in a preliminary stage pending a report from the National Transportation Safety Board and the ultimate costs to the Company are unknown at this time. On July 14, 1993, the Company filed a lawsuit in U.S. District Court for the District of Minnesota. The suit was filed in the interest of the Company's ratepayers against Westinghouse Electric Corp. (Westinghouse), the manufacturer of the Prairie Island steam generators, because of problems with the steam generators' susceptibility to corrosion. The Company seeks to recover the past and future costs of inspections, maintenance, modifications and repairs made to the Prairie Island steam generators and related systems as a result of Westinghouse defects. The defects are "serious" in that they have caused the Company to incur significant expenditures in order to ensure that Prairie Island is a safe and economically efficient generating station. The scheduling order requires discovery to be completed by Oct. 1, 1995. NSP and Westinghouse must be ready for trial by Feb. 1, 1996. Safety has not been, nor will be, compromised in any way as a result of the defects because the plant has been and continues to be well-maintained. The steam generator problem is less severe at Prairie Island than at most other plants with the same model steam generator. This is due to specific plant design features, including a lower reactor coolant water temperature than most of the other plants. Other reasons are due to the higher standards used at Prairie Island in such areas as water chemistry and preventative maintenance. Based on analysis done, it is the Company's best estimate that the steam generators can be maintained so replacement will not be necessary before the units' 40-year operating licenses expire. On June 20, 1994, the Company and 13 other major utilities filed a lawsuit against the Department of Energy (DOE) in an attempt to clarify the DOE's obligation to accept spent nuclear fuel beginning in 1998. The suit was filed in the U.S. Court of Appeals, Washington, D.C. The primary purpose of the lawsuit is to insure the Company and its customers receive timely storage of used nuclear fuel. For a discussion of other environmental proceedings, see "Environmental Matters" under Item 1, incorporated herein by reference. For a discussion of proceedings involving NSP's utility rates, see "Utility Regulation and Revenues" under Item 1, incorporated herein by reference. Item 4 - Submission of Matters to a Vote of Security Holders None PART II Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters Quarterly Stock Data The Company's common stock is listed on the New York Stock Exchange (NYSE), Chicago Stock Exchange (CHX) and the Pacific Stock Exchange (PSE). Following are the reported high and low sales prices based on the NYSE Composite Transactions for the quarters of 1994 and 1993 and the dividends declared per share during those quarters:
1994 1993 High Low Dividends High Low Dividends First Quarter $43 7/8 $40 1/8 $.645 $47 $42 1/4 $.630 Second Quarter 43 5/8 38 3/4 .660 46 7/8 42 7/8 .645 Third Quarter 43 7/8 40 3/8 .660 47 7/8 44 3/4 .645 Fourth Quarter 47 41 7/8 .660 46 3/8 40 1/8 .645
Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters The Company's Restated Articles of Incorporation and First Mortgage Bond Trust Indenture provide for certain restrictions on the payment of cash dividends on common stock. At Dec. 31, 1994, the payment of cash dividends on common stock was not restricted.
1994 1993 1992 1991 1990 Shareholders of record at year-end 85 263 86 404 72 525 72 704 73 867 Book value per share at year-end $28.35 $27.32 $25.91 $25.21 $24.42 Shareholders of record as of March 15, 1995 were 85,256.
Item 6 - Selected Financial Data
1994 1993 1992 1991 1990 1984 (Dollars in millions except per share data) Utility operating revenues $2 486.5 $2 404.0 $2 159.5 $2 201.1 $2 064.5 $1 775.6 Utility operating expenses $2 178.2 $2 100.1 $1 903.5 $1 895.6 $1 775.7 $1 532.4 Income from continuing operations before accounting change $243.5 $211.7 $160.9 $207.0 $193.0 $189.8 Net income $243.5 $211.7 $206.4 $224.1 $195.5 $192.1 Earnings available for common stock $231.1 $197.2 $190.3 $206.1 $177.3 $178.8 Average number of common and equivalent shares outstanding (000's) 66 845 65 211 62 641 62 566 62 541 61,663 Earnings per average common share: Continuing operations before accounting change $3.46 $3.02 $2.31 $3.02 $2.79 $2.86 Total $3.46 $3.02 $3.04 $3.29 $2.83 $2.90 Dividends declared per share $2.625 $2.565 $2.495 $2.395 $2.295 $1.585 Total assets $5 953.6 $5 587.7 $5 142.5 $4 918.8 $4 931.6 $3 741.7 Long-term debt $1 463.4 $1 291.9 $1 299.9 $1 233.9 $1 239.5 $1 142.5 Ratio of earnings (from continuing operations before accounting change, excluding undistributed equity income 4.0 4.0 3.2 3.9 3.7 5.0 and including AFC) to fixed charges Notes: 1) Operating revenues and operating expenses in all years prior to 1992 have been restated to exclude the results of discontinued telephone operations. 2) In 1992, the Company changed its method of accounting for revenue recognition to begin recording unbilled revenue.
Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations Northern States Power Company, a Minnesota corporation (the Company), has two significant subsidiaries, Northern States Power Company, a Wisconsin corporation (the Wisconsin Company), and NRG Energy, Inc., a Delaware corporation (NRG). The Company also has several other subsidiaries, including Viking Gas Transmission Company (Viking) and Cenergy, Inc., (Cenergy). The Company and its subsidiaries collectively are referred to herein as NSP. FINANCIAL RESULTS AND OBJECTIVES 1994 Financial Results NSP's 1994 earnings per share were $3.46, an increase of 44 cents, or 14.6 percent, over the $3.02 earned in 1993. Sales growth in the core electric and gas utility businesses offset continuing unfavorable weather and higher operating costs, for a modest increase in utility earnings. In 1994, non- regulated businesses contributed a material portion of NSP's earnings for the first time, with 14.2 percent of NSP's earnings per share being derived from non-regulated operations. Most of this non-regulated earnings growth was generated from investments in energy projects in Germany and Australia. Investor returns also were enhanced in 1994 by an increase in the dividend rate, as discussed below. NSP remained financially strong in 1994, as evidenced by continued high operating cash flows and interest coverage. NSP maintained its double A first mortgage bond ratings with all rating agencies during 1994 except Moody's Investors Services (Moody's). Moody's downgraded NSP's first mortgage bond ratings to A1 based on its interpretation of provisions of a Minnesota law enacted in 1994 regarding the Prairie Island nuclear generating plant used fuel storage project. (See discussion of this legislation in Notes 16 and 17 to the Financial Statements.) Total Return Dividend increases plus stock price appreciation comprise total return to NSP's investors. NSP increased its common dividend rate by more than 2 percent in 1994 and maintained a steady stock price despite a general industry decline in utility stock prices. Since the beginning of 1985, the total return on NSP's common stock has averaged 14.3 percent per year. The total return for the Standard & Poor's (S&P) composite stock index for 500 industrial companies has averaged 14.4 percent per year for the same period. Financial Objectives NSP's financial objectives are: - To provide investor returns in the top one-fourth of the utility industry as measured by a three-year average return on equity. NSP's average return on equity (including the cumulative effect of the 1992 accounting change for unbilled revenues) for the three years ending in 1994 was 11.9 percent. Due largely to unusually mild weather in 1992, this return was below the three-year average of the top one-fourth of the industry (approximately 12.8 percent). - To increase dividends on a regular basis and maintain a long-term average payout ratio in the range of 65 to 75 percent. The objective payout ratio is based on long-term earnings expectations. In June 1994, NSP's annualized common dividend rate was increased by 6 cents per share, or 2.3 percent, from $2.58 to $2.64. The dividend payout ratio was 76 percent in 1994. NSP's goal is to return to the objective range through growth in earnings. - To maintain continued financial strength with a double A bond rating. The Company's first mortgage bonds continued to be rated AA- by S&P, AA- by Duff & Phelps, Inc., and AA by Fitch Investors Service, Inc. In 1994, Moody's downgraded NSP's first mortgage bond ratings from Aa2 to A1 based on its interpretations of a Minnesota law enacted in 1994 regarding the Prairie Island nuclear generating plant used fuel storage project. First mortgage bonds issued by the Wisconsin Company carry comparable ratings. NSP's pretax interest coverage ratio, based on income without Allowance for Funds Used During Construction (AFC), was 3.9 in 1994. A capital structure consisting of 47.5 percent common equity at year-end 1994, including both regulated and non-regulated operations, contributes to NSP's financial flexibility and strength. - To provide 20 percent of NSP earnings from non-regulated businesses by the year 2000. NSP expects to meet this goal through growing profitability of existing non-regulated businesses and through the addition of new non-regulated businesses. Non-regulated businesses provided 14.2 percent of NSP's earnings in 1994. - To maintain long-term average annual earnings growth of 5 percent. Non- regulated operations are expected to provide a significant portion of NSP's earnings growth in the foreseeable future. In 1994, total earnings increased 14.6 percent over 1993, with non-regulated earnings contributing most of that earnings growth. Business Strategies NSP's management is proactive in shaping the new business environment in which it will be operating. Management's business strategies include: - Focusing on the core energy business. The electric utility industry is becoming more complex as customers, as well as utilities and federal and state regulators, promote competition. To remain successful in this more complex environment, NSP will maintain its focus on its core energy-related activities. - Providing reliable, low-cost, environmentally responsible energy. Whether energy is produced through NSP's regulated utility or through its non-regulated businesses, three general concepts provide a focus for its energy businesses: reliable energy, low-cost energy and environmentally responsible energy. - Responding to customer needs. Customers will have an increasing number of options for meeting their energy needs, and there will be competition among energy companies for the privilege of serving those customers. NSP will work with its customers to develop innovative products and services that benefit both the customer and NSP. - Increasing non-regulated investments and earnings. As evidenced by the financial objectives for earnings growth, non-regulated businesses will be an important part of NSP's future. Deregulation in the utility industry is expected to provide new investment opportunities in non- regulated businesses. Participation in these opportunities is expected to improve the profitability of NSP. RESULTS OF OPERATIONS AND LIQUIDITY AND CAPITAL RESOURCES The following discussion and analysis by management focuses on those factors that had a material effect on NSP's financial condition and results of operations during 1994 and 1993. It should be read in conjunction with the accompanying Financial Statements and Notes thereto. Trends and contingencies of a material nature are discussed to the extent known and considered relevant. RESULTS OF OPERATIONS 1994 Compared with 1993 and 1992 NSP's 1994 earnings per share were $3.46, up 44 cents from the $3.02 earned in 1993 and up $1.15 from the $2.31 earned before accounting changes in 1992. Regulated utility businesses generated earnings per share of $2.97 in 1994, $2.93 in 1993, and $2.33 (before accounting changes) in 1992. Non-regulated businesses generated earnings per share of 49 cents in 1994 and 9 cents in 1993, and a loss per share of 2 cents in 1992. The results of the regulated utility businesses and the non-regulated businesses are discussed in more detail below. In addition to the revenue and expense changes, 1994 earnings per share were impacted by a higher average number of common and equivalent shares outstanding. Common and equivalent shares increased in 1994 and 1993 due to stock issuances, including a general offering of 2.6 million shares in May 1993. Utility Operating Results Electric Revenues - Sales to retail customers, which account for more than 90 percent of NSP's electric revenue, increased 3.9 percent in 1994 and 4.0 percent in 1993. Cool summer weather reduced sales in 1992 and, to a lesser extent, in 1994 and 1993. During 1994, NSP added 16,549 retail electric customers, a 1.2-percent increase. Total sales of electricity decreased 0.2 percent in 1994. The decrease is due to lower sales to other utilities (as discussed later), mostly offset by increases in sales to retail customers and municipal utilities. On a weather-adjusted basis, sales to retail customers increased an estimated 3.4 percent in 1994 and 2.1 percent in 1993. Retail sales growth for 1995 is estimated to be 3.0 percent over 1994, or 2.2 percent on a weather- adjusted basis. Sales to other utilities decreased 21.6 percent in 1994 after increasing 30.5 percent in 1993 when there was higher demand from utilities in flood- stricken Midwestern states. The 1993 increase also reflected the impact of ice damage to transmission lines in Iowa, which limited sales in 1992. The table below summarizes the principal reasons for the electric revenue changes during the past two years.
1994 vs 1993 1993 vs 1992 (Millions of dollars) Retail sales growth (excluding weather impacts) $56 $32 Estimated impact of weather on retail sales volume 8 34 Rate changes 17 74 Sales to other utilities (20) 20 Fuel adjustment clause 23 (2) Other 8 (6) Total revenue increase $92 $152
NSP's electric revenues are adjusted for changes in fuel and purchased energy costs from amounts currently included in approved base rates through fuel adjustment clauses in all jurisdictions, except as noted below for Wisconsin. While the lag in implementing these billing adjustments is approximately 60 days, an estimate of the adjustments is recorded in unbilled revenue in the month in which costs are incurred. In Wisconsin, the biennial retail rate review process considers changes in electric fuel and purchased energy costs in lieu of a fuel adjustment clause. Electric Production Expenses - Fuel expense for electric generation increased $5.6 million, or 1.8 percent, in 1994 compared with an increase of $19.4 million, or 6.6 percent, in 1993. Total output from NSP's generating plants decreased 1.5 percent in 1994 and increased 8.4 percent in 1993. Fuel expenses were higher in 1994 because of the higher cost of nuclear fuel per megawatt- hour (MWH) due to increased payments to the U.S. Department of Energy (DOE) for decommissioning and decontamination of the DOE's uranium enrichment facilities and nuclear fuel disposal costs. In addition, fossil fuel costs were higher as a result of fewer purchases of coal at the lowest contractual prices due to lower fossil plant output in 1994. These increases were somewhat offset by cost decreases from lower output due to more scheduled fossil plant maintenance outages. The fuel expense increase in 1993 was due to higher output to meet sales demand, partially offset by lower cost of fuel per MWH, which reflects increased use of low-cost purchases, as discussed below. Purchased power costs increased $41.1 million, or 19.7 percent, in 1994 and $53.0 million, or 34.1 percent, in 1993. The increase in 1994 primarily was due to additional demand expenses of $21 million for the full-year impact of capacity charges from the power purchase agreements with Manitoba Hydro- Electric Board (MH), which went into effect in May 1993, as discussed in Note 17 to the Financial Statements. In addition to demand expenses, purchased power costs increased from more energy purchases and higher prices. Energy purchases increased due to more scheduled plant maintenance outages in 1994. The market pricing of energy purchases increased in 1994 compared to more favorable market pricing in 1993. The increase in purchased power costs in 1993 over 1992 was largely due to a demand expense increase of $42 million for the capacity charges under power purchase agreements with MH. Energy purchased from other utilities increased in 1993 due to economically priced energy available to meet growing retail demand and resale opportunities to other utilities. Gas Revenues - The majority of NSP's gas sales are categorized as firm (primarily space heating customers) and interruptible (commercial/industrial customers with an alternate energy supply). Firm sales in 1994 decreased 5.4 percent compared with 1993 sales, while firm sales in 1993 increased 17.0 percent over 1992 sales. The 1994 decrease is due largely to warm weather in the last quarter of 1994. Warm weather in the first quarter of 1992 is the main cause for the increase in 1993. NSP added 14,402 firm gas customers in 1994, a 3.7-percent increase. On a weather-adjusted basis, firm sales are estimated to have decreased 0.7 percent in 1994 and increased 0.9 percent in 1993 (excluding a one-time unbilled revenue adjustment). Firm gas sales in 1995 are estimated to increase by 7.2 percent relative to 1994, with a 5.9-percent increase on a weather- adjusted basis. The 1995 increase includes the impact of additional revenues of approximately $6 million due to a 1994 gas expansion project in north central Minnesota, where 6,300 new customers were signed up for new service as of Dec. 31, 1994. Interruptible sales of gas increased 4.4 percent in 1994 and 17.3 percent in 1993. Other gas deliveries, including Viking's transmission volumes, increased 73.5 percent in 1994 due to a full year of Viking activity and to sales of gas to off-system customers. Other gas deliveries increased dramatically in 1993 due to the acquisition of Viking. The table below summarizes the principal reasons for the gas revenue changes during the past two years.
1994 vs 1993 1993 vs 1992 (Millions of dollars) Sales growth (excluding weather impacts) $0 $ 17 Estimated impact of weather on firm sales volume (8) 28 Viking Gas (acquired in June 1993) 5 9 Rate changes 3 9 Sales to off-system customers 14 Purchased gas adjustment and other (23) 30 Total revenue increase (decrease) $(9) $ 93
NSP's gas revenues are adjusted for changes in purchased gas costs from amounts currently included in approved base rates through purchased gas adjustment clauses in all jurisdictions. Cost of Gas Sold - The cost of gas purchased and transported decreased $18.6 million, or 6.6 percent, in 1994. The decrease reflects lower gas prices and cost recovery adjustments, partially offset by higher sendout volumes primarily for sales of gas to off-system customers. The cost of gas associated with 1994 off-system sales was $12.7 million. In 1993, the cost of gas purchased and transported increased $61.7 million, or 28.0 percent, due to higher sendout volumes and higher purchased gas prices. The average cost per thousand cubic feet (mcf) of NSP-owned gas sold in 1994 was 8.4 percent lower than it was in 1993, when the cost was 8.7 percent higher than it was in 1992. The decrease in 1994 is due mainly to lower market pricing of gas. NSP views most of the increases in 1993 and 1992 as a recovery from unsustainably low wellhead gas prices in 1990 and 1991. Other Operation, Maintenance and Administrative and General - These expenses, in total, increased by $26.5 million, or 4.1 percent, in 1994 compared with a decrease of $27.2 million, or 4.0 percent, in 1993. The 1994 increase is primarily due to higher postretirement health care costs, including amounts deferred from 1993, and higher postemployment costs, as discussed in Note 3 to the Financial Statements. The 1993 decrease was the result of fewer scheduled plant maintenance outages, reduced employee levels and lower administrative costs. The 1993 decrease is net of a $14 million cost increase because wages in 1992 did not include accruals for incentive compensation. (See Note 14 to the Financial Statements for a summary of administrative and general expenses.) Conservation and Energy Management - Costs in 1994 remained comparable with 1993. Costs in 1993 were higher than in 1992 because NSP's regulators approved higher expense levels for conservation and demand-side management efforts. Depreciation and Amortization - The increases in depreciation in 1994 and 1993 reflect higher levels of depreciable plant for all periods and changes in the depreciable lives of certain property in 1994 and 1993. (See Note 1 to the Financial Statements for discussion of depreciation changes and rate filings.) Property and General Taxes - Property and general taxes increased in 1994 and 1993 primarily as a result of higher property tax rates and property additions. In addition, the increase in 1994 partially is due to higher gross earnings taxes, which are a result of higher sales levels. Utility Income Taxes - The variations in income taxes primarily are attributable to fluctuations in pretax book income. Taxes in 1993 also increased about $3 million due to a 1-percent increase in the federal tax rate. (See Note 11 to the Financial Statements for a detailed reconciliation of the statutory tax rate to the effective tax rate.) Non-operating Items Related to Utility Businesses Allowance for Funds Used During Construction (AFC) - The differences in AFC for the reported periods are attributable to varying levels of construction work in progress and lower AFC rates associated with increased use of lower-cost, short-term borrowings to fund construction. Other Income and Expense - Note 14 to the Financial Statements lists the components of Other Income and Deductions-Net reported on the Consolidated Statements of Income. Other than the operating revenues, expenses and income taxes of non-regulated businesses, as discussed in the next section, non- operating income and expense items related to utility businesses decreased $2.5 million in 1994 and increased $0.8 million in 1993, net of associated income taxes. The 1994 decrease primarily is due to higher expenses for environmental and regulatory contingencies and higher public and government affairs expenses associated with the Prairie Island fuel storage issue, partially offset by interest income associated with the Company's settlement of a federal income tax dispute. The increase in 1993 was due to higher investment income and lower expenses for regulatory contingencies. Interest Charges (Before AFC) - Interest costs recognized for NSP's utility businesses, including amounts capitalized to reflect the financing costs of construction activities, were $107.8 million in 1994, $111.2 million in 1993 and $109.1 million in 1992. The decrease in 1994 reflects the impact of refinancing several higher-rate long-term debt issues in 1993 and 1994. These interest savings were partially offset by interest on higher short-term debt balances and new Viking debt (issued late in 1993). The average short-term debt balance was $204.5 million in 1994, $77.0 million in 1993 and $81.0 million in 1992. The increase in 1993 is due to amortization of refinancing costs, partially offset by interest savings from refinancing long-term debt at lower rates. Accounting Change - Earnings in 1992 included a net-of-tax income item of $45.5 million for the cumulative effect (related to prior years) of changing the Company's revenue recognition method to begin recording estimated unbilled revenues for utility service. Preferred Dividends - Dividends on NSP's preferred stock decreased in 1994 and 1993 primarily due to redemptions of the $7.84 Series Cumulative Preferred Stock in October 1993 and the $8.80 Series Cumulative Preferred Stock in April 1992. 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 (RDF) 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 - Because non-regulated operating revenues are less than 10 percent of NSP's consolidated revenues, the net results of non- regulated businesses are reported in Other Income and Deductions-Net on the Consolidated Statements of Income. (Note 14 to the Financial Statements lists the individual components of this line item.) Non-regulated operating revenues increased $151.3 million, or 167 percent in 1994, and $28.1 million, or 45 percent in 1993, due mainly to the impact of gas marketing and industrial heating and cooling businesses acquired during 1993. Non-regulated operating expenses had corresponding increases in 1994 due to the effects of 1993 acquisitions. In addition, such expenses increased in 1994 due to fewer project development costs being capitalized on pending projects in 1994 compared with 1993, and project write-downs, as discussed below. The increase in 1993 non-regulated operating income was due to improved RDF operations, acquired businesses and 1992 project write-downs that did not recur in 1993. Non-regulated operating expenses include charges of $5.0 million in 1994 and $6.8 million in 1992 for previously capitalized development and investment costs to reflect a decrease in the expected future cash flows of certain energy projects. Equity Income - NSP has a less-than-majority equity interest in many non- regulated projects, as discussed in Notes 4 and 5 to the Financial Statements. Consequently, a large portion of NSP's non-regulated earnings is reported as Equity in Earnings of Unconsolidated Investees on the Consolidated Statements of Income. The 1994 increase in equity income primarily is due to new energy projects NRG entered into during 1994 (as discussed in Notes 4 and 5 to the Financial Statements) and to more profitable operations of other energy projects in which NRG has been an investor for several years. Non-operating Gain - In 1994, a cogeneration project in which NRG was a 50- percent investor received a payment from an unrelated utility company that had agreed to purchase the project cogeneration energy as compensation for terminating the energy purchase agreement. Other Income and Deductions-Net includes a pretax gain of $9.7 million for NRG's share of the termination settlement, net of project investment costs. Interest Expense - Interest charges on the Consolidated Statements of Income include interest expense related to non-regulated businesses of $7.3 million in 1994, $2.3 million in 1993 and $0.1 million in 1992. The increases in 1994 and 1993 relate primarily to new non-utility long-term debt issued to finance the 1993 acquisitions of NRG's industrial heating and cooling business (Minneapolis Energy Center), a gas marketing business now operated by Cenergy, and 1994 investments in affordable housing projects by Eloigne Company (a wholly owned subsidiary of the Company). In addition, during 1994 and late 1993, United Power & Land and First Midwest Auto Park, wholly owned subsidiaries of the Company, issued long-term debt secured by non-regulated properties and lowered NSP's equity investment. Income Taxes - Other Income and Deductions-Net reported on the Consolidated Statements of Income (and as shown in Note 14 to the Financial Statements) includes income tax expense (credits) related to non-regulated businesses of $6.4 million in 1994, $3.5 million in 1993 and $(0.3) million in 1992. The increase in 1994 is due mainly to higher income and gains from NRG's energy projects, as discussed above. The 1994 effective tax rate is substantially less than the U.S. federal tax rate due mainly to the tax treatment of income from NRG's international projects and to energy and low-income housing tax credits, as shown in Note 11 to the Financial Statements. Factors Affecting Results of Operations NSP's results of operations during 1994 and 1993 were primarily dependent on the operations of the Company's and Wisconsin Company's utility businesses consisting of the generation, transmission and sale of electricity and the distribution, transportation and sale of natural gas. NSP's utility revenues depend on customer usage, which varies with weather conditions, general business conditions, the state of the economy and the cost of energy services. Various regulatory agencies determine the prices for electric and gas service within their respective jurisdictions. In addition, NSP's non-regulated businesses are beginning to contribute significantly to NSP's earnings. The historical and future trends of NSP's operating results have been and are expected to be affected by the following factors: Competition - The Energy Policy Act of 1992 (the Act) is a catalyst for comprehensive and significant changes in the operation of electric utilities, including increased competition. The Act's reform of the Public Utility Holding Company Act (PUHCA) promotes creation of wholesale non-utility power generators and authorizes the Federal Energy Regulatory Commission (FERC) to require utilities to provide wholesale transmission services to third parties. The legislation allows utilities and non-regulated companies to build, own and operate power plants nationally and internationally without being subject to restrictions that previously applied to utilities under the PUHCA. Management believes this legislation will promote the continued trend of increased competition in the electric energy markets. In 1994, the FERC issued proposed rulemaking to address the rate treatment of potential "stranded investment" costs that could occur as wholesale electric markets become more competitive. The FERC is soliciting comments on options for recovery of transition costs associated with existing electric investments for which competitive market pricing might not provide recovery. NSP is evaluating the FERC proposal to determine the potential effects on operating results and customer rates and has responded to the FERC individually and through an industry group. The FERC has not reached a final decision, and the effects of the proposed rulemaking currently are not known. NSP filed open access transmission tariffs with the FERC in March 1994. In accepting the filing, the FERC ruled NSP's tariff would be subject to the requirement that NSP offer transmission service to third parties using terms and conditions comparable to its own use of the system on behalf of NSP's traditional retail sales customers. NSP also addressed the following open access issues in its filing: timely responses to good faith transmission requests; unbundling energy services; and establishing appropriate pricing mechanisms to ensure that cost allocation prevents inter-class subsidies. In addition, the filing allows NSP and its affiliates to use market-based rates to sell capacity and energy. The FERC also announced a new transmission pricing policy statement in October 1994. The new policy introduces greater flexibility in transmission pricing structure. NSP's revenues and earnings are not expected to be materially affected by the FERC's new pricing policies for transmission services. NSP management plans to continue its efforts to be a competitively priced supplier of electricity and an active participant in the competitive market for electricity. In response to the developing electric industry competition, Cenergy applied for and was granted permission by the FERC to market electricity (except electricity generated by NSP) in the United States, effective Dec. 1, 1994. Cenergy is one of the first affiliates of an electric utility to obtain this approval from the FERC. Some states are considering proposals to require "retail wheeling", which is the transmission of power generated by a third party to retail customers of another utility. In 1994, NSP filed a response to a proposal by its regulator in Wisconsin outlining the transitional steps necessary to create an open and fair competitive electric market. NSP's position is that all customers should be able to choose their electric supplier by 2001, and that generation also should be deregulated by 2001. NSP proposes that utilities retain operational control of their transmission and distribution systems, and that utilities should be permitted to recover the cost of investments that were authorized under traditional regulation. Regulators in Wisconsin are currently considering what action, if any, they should take regarding electric industry competition. During 1992 and 1993, the FERC issued a series of orders (together called Order 636) addressing interstate natural gas pipeline service restructuring. This restructuring has "unbundled" each of the services (sales, transportation, storage and ancillary services) traditionally provided by gas pipeline companies. Order 636 ended the traditional pipeline sales service function, which in the past had met local distribution companies' (LDCs) needs for reliability of supply and flexibility for meeting varying load conditions. The implementation of Order 636 has applied more pressure on all LDCs to keep gas supply and transmission pricing for large customers competitive in light of the alternatives now available to these customers. Interstate pipelines have been allowed to recover from their customers 100 percent of prudently incurred transition costs attributable to Order 636 restructuring. NSP estimates that it will be responsible for less than $12 million of transition costs over a five-year period beginning Nov. 1, 1993. To date, NSP's regulatory commissions have approved recovery of these restructuring charges in retail gas rates through the purchased gas adjustment. New service agreements went into effect between NSP and its pipeline transporters on Nov. 1, 1993. NSP does not expect these new agreements under Order 636 to materially affect its cost of gas supply. NSP's acquisitions of Viking and a gas marketing business in 1993 have enhanced its ability to participate in the more competitive gas transportation business. In implementing Order 636, Viking incurred no transition costs. Regulation - NSP's utility rates are approved by the FERC, the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission, the Public Service Commission of Wisconsin (PSCW), the Michigan Public Service Commission and the South Dakota Public Utilities Commission. Rates are designed to recover plant investment and operating costs and an allowed return on investment, using an annual period upon which rate case filings are based. NSP requests changes in rates for utility services as needed through filings with the governing commissions. The rates charged to retail customers in Wisconsin are reviewed and adjusted biennially. Because rate changes are not requested annually in Minnesota, NSP's primary jurisdiction, changes in operating costs can affect NSP's earnings, shareholders' equity and other financial results. Except for Wisconsin electric operations, NSP's rate schedules provide for cost-of-energy adjustments to billings and revenues for changes in the cost of fuel for electric generation, purchased energy and purchased gas. For Wisconsin electric operations, the biennial retail rate review process considers changes in electric fuel and purchased energy costs in lieu of a cost-of-energy adjustment clause. In addition to changes in operating costs, other factors affecting rate filings are sales growth, conservation and demand-side management efforts and cost of capital. Rate Changes - NSP filed for 1993 rate increases in Minnesota, North Dakota, South Dakota and Wisconsin to offset increasing costs for purchased power commitments, depreciation, property taxes, postretirement benefits and other expenses. NSP received approvals for approximately $102 million of annualized rate increases for retail customers in those states as well as for wholesale customers in Minnesota and Wisconsin. These rate changes increased revenues by approximately $83 million in 1993 and an additional $19 million in 1994. As discussed in Note 2 to the Financial Statements, filings for rate changes in 1994 did not have a material impact on financial results. No significant general rate filings in any of NSP's utility jurisdictions are expected for 1995. However, the Company requested that the MPUC approve a new rate adjustment clause designed to accelerate recovery of 1994 and expected 1995 deferred electric conservation program costs. This adjustment clause could help reduce the need for filing a general rate increase request for recovery of increases in conservation expenditures. In February 1995, the MPUC voted to approve the new rate adjustment clause for the period May 1995 through June 1996. Thereafter, the Company would be required to request a new cost recovery level annually. The Company estimates it will receive an additional $24 million in revenues in 1995. This increased recovery will result in a corresponding increase in conservation expenses. A final order is expected in March 1995. Legislative Changes - In May 1994, NSP received legislative authorization for dry cask fuel storage facilities at the Company's Prairie Island nuclear generating facility. As a condition of this authorization, the Legislature established several resource commitments for NSP, including wind and biomass generation sources. (See Notes 16 and 17 to the Financial Statements for more information.) Wholesale Customers - In 1992, nine of the Company's 19 municipal wholesale electric customers notified the Company of their intent to terminate their power supply agreements with the Company, effective July 1995 or July 1996. These nine customers currently represent approximately $29 million in annual revenues and a maximum demand load of approximately 155 megawatts (MW). In 1992 and 1993, the Company signed long-term power supply agreements with the 10 remaining municipal customers. The agreements commit the customers to purchase power from the Company for up to 13 years (through 2005) at fixed rates rising at up to 3 percent per year. The 10 customers represent approximately $10 million in current annual revenue and a maximum demand load of approximately 59 MW. The rates contained in the agreements were accepted by the FERC. During 1993, the Company signed an electric power agreement to provide Michigan's Upper Peninsula Power Company (UPPCO) with up to 150 MW of baseload service, peaking service options and load regulation service options for 20 years from January 1998 through December 2017. Load regulation service is designed to change the level of power delivery during each hour to match UPPCO's load requirements. UPPCO has nominated 50 MW of base load and 5 MW of winter season peaking power purchases from NSP beginning Jan. 1, 1998. The annual revenue for 1998 is projected to be approximately $11 million to $14 million. The interchange agreement between UPPCO and NSP for this sale was accepted by the FERC. The Michigan Public Utilities Commission must also approve the transaction. Environmental Matters - NSP incurs several types of environmental costs, including nuclear plant decommissioning, storage and ultimate disposal of used nuclear fuel, disposal of hazardous materials and wastes, remediation of contaminated sites and monitoring of discharges into the environment. NSP is recording costs for environmental monitoring and accruals for nuclear plant decommissioning and used nuclear fuel disposal as an ongoing operating expense and has recorded its best estimate of the full obligation for environmental remediation. Because of the continuing trend toward greater environmental awareness and increasingly stringent regulation, NSP has been experiencing a trend toward increasing environmental costs. This trend has caused and may continue to cause slightly higher operating expenses and capital expenditures. Costs charged to NSP's operating expenses for environmental monitoring and disposal of hazardous materials and wastes in 1994 were approximately $7 million and are currently expected to increase to an average annual amount of approximately $12 million for the five-year period 1995-1999. However, the precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are currently unknown. In 1994, 1993 and 1992, the Company spent about $15 million, $15 million and $20 million, respectively, for capital expenditures on environmental improvements at its utility facilities. In 1995, the Company expects to incur approximately $15 million in capital expenditures for compliance with environmental regulations. (See Notes 16 and 17 to the Financial Statements for further discussion of these and other environmental contingencies that could affect NSP.) Weather - NSP's earnings can be dramatically affected by unusual weather. Mild weather, mainly cool summers, reduced earnings by an estimated 13 cents per share in 1994 and 18 cents per share in 1993. However, this was an improvement over 1992, when a warm winter and the coolest summer in 77 years reduced earnings by an estimated 51 cents per share. Acquisitions - In 1994, NRG acquired ownership interests in three significant international energy projects (as discussed in Note 4 to the Financial Statements), which increased 1994 earnings by approximately 38 cents per share. NSP also made three other strategically important business acquisitions in 1993, including an interstate natural gas pipeline (Viking), an energy services marketing business (Cenergy) and a steam heating and chilled water cooling system business (Minneapolis Energy Center, now an NRG subsidiary). NSP continues to evaluate opportunities to enhance its competitive position and shareholder returns through strategic business acquisitions. Impact of Non-regulated Investments - NSP's net income in 1994 includes after- tax earnings of $33.0 million, or 49 cents per share, from all non-regulated businesses. As discussed previously, NRG acquired equity interests in three significant energy projects in 1994. NSP expects to continue investing significant amounts in non-regulated projects, including domestic and international power production projects through NRG, as described under "Future Financing Requirements". Depending on the success and timing of involvement in these projects, NSP expects that non-regulated earnings could increase in the future to contribute at least 20 percent of NSP's earnings by the year 2000. The non-regulated projects in which NSP has invested carry a higher level of risk than NSP's traditional utility businesses. Current and future investments in non-regulated projects are subject to uncertainties prior to final legal closing, and continuing operations are subject to foreign government actions, partnership actions or both. The 1994 operating results of NSP's non-regulated businesses may not necessarily be indicative of future operating results. Accounting Changes - Effective Jan. 1, 1994, NSP adopted three new accounting standards for postemployment benefits, fair value accounting for certain investments and employee stock ownership plan transactions. These accounting changes had an immaterial impact on earnings in 1994. (See Note 3 to the Financial Statements for more information on these accounting changes.) As discussed in Notes 3 and 10 to the Financial Statements, in 1993 NSP changed its accounting for certain postretirement benefits and began recording such benefits on an accrual basis. NSP's utility companies had previously been allowed rate recovery for postretirement benefits as paid. In the 1993 rate increases discussed previously, NSP's utility companies obtained rate recovery for substantially all of the increased costs (approximately $20 million) accrued under Statement of Financial Accounting Standards (SFAS) No. 106 in 1993. Due to rate recovery of higher costs, there was no material impact on NSP's operating results from this accounting change. NSP currently follows predominant industry practice in recording its environmental liabilities for plant decommissioning and site exit costs as a component of utility plant. The Financial Accounting Standards Board (FASB) is evaluating the financial presentation of these obligations and the related expense accruals, which could require reporting reclassifications as early as 1995. The effects of regulation are expected to minimize or eliminate any impact on operating expenses from potential accounting changes for decommissioning costs. (For further discussion, see Note 16 to the Financial Statements.) Use of Derivatives - Through its subsidiaries, NSP uses derivative financial instruments to manage the risks of fluctuations in foreign currencies and natural gas prices. At Dec. 31, 1994, $93 million in notional amount (i.e. no transfer of principal) of hedge instruments were in place to hedge international investments subject to foreign currency exchange fluctuations, and $16 million in notional amount of futures contracts were in place to hedge the sale of natural gas. NSP also uses interest rate swap agreements to convert fixed rate debt to variable rate debt. At Dec. 31, 1994, NSP had $320 million in notional amount of interest rate swap agreements. (See Note 13 to the Financial Statements for further discussion of NSP's financial instruments and derivatives.) Non-recurring Items - NSP's earnings for 1994 include several non-recurring items. Although their net effect was an earnings increase of only 1 cent per share, individually significant non-recurring items included a gain on termination of a non-regulated cogeneration contract, interest income from the settlement of a federal income tax dispute, a charge for pre-1994 postemployment costs associated with adopting SFAS No. 112, and asset impairment write-downs for certain non-regulated energy projects. Inflation - Historically, certain operating costs, mainly labor and property taxes, have been affected by inflation. Also, inflation has tended to increase the replacement cost of operating facilities, which has increased depreciation expense when replacement facilities are constructed. However, several significant expense items have been less sensitive to inflation, including fuel costs, income taxes and interest expense. Overall, inflation at the levels currently being experienced is not expected to materially affect NSP's prices to customers or returns to shareholders. LIQUIDITY AND CAPITAL RESOURCES 1994 Financing Requirements - NSP's need for capital funds is primarily related to the construction of plant and equipment to meet the needs of electric and gas utility customers and to fund equity commitments or other investments in non-regulated businesses. Total NSP utility capital expenditures (including AFC) were $387 million in 1994. Of that amount, $304 million related to replacements and improvements of NSP's electric system and $60 million involved construction of natural gas distribution facilities. NSP companies invested $159 million in non-regulated projects and property in 1994, mainly for equity investments in domestic and international power projects. NRG invested in joint venture projects that acquired electric generating plants in Australia and Germany, and open-cast coal mining operations in Germany. Eloigne Company invested in affordable housing projects, including wholly owned and limited partnership ventures. 1994 Financing Activity - During 1994, NSP's primary sources of capital included internally generated funds, long-term debt and short-term debt. The allocation of financing requirements between these capital options is based on the relative cost of each option, regulatory restrictions and the constraints of NSP's long-range capital structure objectives. During 1994, NSP continued to meet its long-range regulated capital structure objective of 45-50 percent common equity and 42-50 percent debt. Funds generated internally from operating cash flows in 1994 remained sufficient to meet working capital needs, debt service, dividend payout requirements and non-regulated investment commitments, as well as fund a significant portion of construction expenditures. NSP's 1993 cash flows improved over 1992 mainly due to more favorable weather and rate increases. The pretax interest coverage ratio, excluding AFC, was 3.9 in 1994 and 3.9 in 1993. These ratios met NSP's objective range of 3.5-5.0 for interest coverage. Internally generated funds could have provided financing for 69 percent of NSP's capital expenditures for 1994 and 77 percent of the $1.9 billion in capital expenditures incurred for the five-year period 1990-1994. The Company had approximately $238 million in short-term borrowings outstanding as of Dec. 31, 1994. Throughout 1994, short-term borrowings were used to finance utility capital expenditures and provide for other NSP cash needs. In 1994, the Company issued $350 million of first mortgage bonds to refinance higher-cost debt issues and reduce short-term debt levels. In addition, United Power & Land issued $10 million of non-utility long-term debt to recapitalize the Company's prior equity investment in the subsidiary. Eloigne Company also issued approximately $8 million of long-term debt to finance affordable housing project investments. The Company issued 42,567 new shares of common stock in 1994 under NSP's Executive Long-Term Incentive Award Stock Plan. At Dec. 31, 1994, the total number of common shares outstanding was 66,922,144. NSP's equity investments in non-regulated projects during 1994 were financed through internally generated funds. Project financing requirements, in excess of equity contributions from investors, were satisfied with project debt. Project debt associated with many of NSP's non-regulated investments is not reflected in NSP's balance sheet because the equity method of accounting is used for such investments. (See Note 5 to the Financial Statements.) Future Financing Requirements - Utility financing requirements for 1995-1999 may be affected in varying degrees by numerous factors including load growth, changes in capital expenditure levels, rate increases allowed by regulatory agencies, new legislation, market entry of competing electric power generators, changes in environmental regulations and other regulatory requirements. NSP currently estimates that its utility capital expenditures will be $383 million in 1995 and $1.9 billion for the five-year period 1995- 1999. Of the 1995 amount, $322 million is scheduled for electric facilities and $31 million for natural gas facilities. These utility capital expenditure estimates include approximately $190 million of anticipated expenditures for environmental improvements at utility facilities for the five-year period 1995-1999. In addition to utility capital expenditures, expected financing requirements for the 1995-1999 period include approximately $369 million to retire long-term debt and meet first mortgage bond sinking fund requirements. Through its subsidiaries, NSP expects to invest significant amounts in non-regulated projects in the future. Financing requirements for non-regulated project investments may vary depending on the success, timing and level of involvement in projects currently under consideration. Potential capital requirements for NSP's non-regulated projects and property are estimated to be approximately $153 million in 1995 and approximately $623 million for the five-year period 1995-1999. These amounts include expected NRG investments through 1996 of up to $46 million for an existing German project and Eloigne Company investments of up to $23 million in 1995 and $13 million annually in 1996-1999 for affordable housing projects. Eloigne Company expects to finance approximately 65 percent of these investments in affordable housing projects with equity and approximately 35 percent with long-term debt. In addition to investments in non-regulated projects, NSP continues to evaluate opportunities to enhance shareholder returns and achieve long-term financial objectives through acquisitions of existing businesses. Long-term financing may be required for such investments. The Company will also have future financing requirements for the portion of nuclear plant decommissioning costs not funded externally. Based on the most recent decommissioning study, these amounts are expected to be approximately $363 million, and are expected to be paid during the years 2010 to 2022. Future Sources of Financing - NSP expects to obtain external capital for future financing requirements by periodically issuing long-term debt, common stock and preferred stock as needed to maintain desired capitalization ratios. Over the long-term, NSP's equity investments in non-regulated projects are expected to be financed through internally generated funds or NSP's issuance of common stock. Financing requirements for the non-regulated projects, in excess of equity contributions from investors, are expected to be fulfilled through project debt. Decommissioning expenses not funded by an external trust are expected to be financed through a combination of internally generated funds, long-term debt and common stock. The extent of external capital required for nuclear decommissioning costs is not known at this time. NSP's ability to finance its utility construction program at a reasonable cost and to provide for other capital needs depends on its ability to meet investors' return expectations. Financing flexibility is enhanced by providing working capital needs and a high percentage of total capital requirements from internal sources, and having the ability to issue long-term securities and obtain short-term credit. NSP expects to maintain adequate access to securities markets in 1995. Access to securities markets at a reasonable cost is determined in a large part by credit quality. The Company's first mortgage bonds are rated AA- by Standard & Poor's Corporation, A1 by Moody's Investors Service, Inc. (Moody's), AA- by Duff & Phelps, Inc., and AA by Fitch Investors Service, Inc. Ratings for the Wisconsin Company's first mortgage bonds are generally comparable. These ratings reflect the views of such organizations, and an explanation of the significance of these ratings may be obtained from each agency. Moody's downgraded NSP's first mortgage bond ratings to A1 based on its interpretation of provisions of a Minnesota law enacted in 1994 for used nuclear fuel storage at the Prairie Island generating plant. (The other three rating agencies reaffirmed their ratings of NSP's bonds after considering the impact of the legislation on NSP.) As discussed in Notes 16 and 17 to the Financial Statements, the legislation requires NSP to increase its use of renewable energy sources such as wind and biomass power. Moody's has indicated that it believes these sources of power are considerably more costly than the power currently generated and that NSP's electric production costs will increase materially over current levels. NSP acknowledges that electric production costs may increase as a result of the Prairie Island legislation. The Company's and the Wisconsin Company's first mortgage indentures limit the amount of first mortgage bonds that may be issued. The MPUC and the PSCW have jurisdiction over securities issuance. At Dec. 31, 1994, with an assumed interest rate of 8.5 percent, the Company could have issued about $1.9 billion of additional first mortgage bonds under its indenture, and the Wisconsin Company could have issued about $248 million of additional first mortgage bonds under its indenture. The Company registered first mortgage bonds with the Securities and Exchange Commission (SEC) in December 1993. Depending on capital market conditions, the Company expects to issue the remaining $250 million of registered but unissued bonds over the next several years to raise additional capital or redeem outstanding securities. The Company's Board of Directors has approved short-term borrowing levels up to 10 percent of capitalization. The Company has received regulatory approval for $350 million in short-term borrowing levels and plans to keep its credit lines at or above its average level of commercial paper borrowings. Commercial banks presently provide credit lines to the Company of approximately $299 million, which excludes $11 million of credit lines provided to subsidiaries of the Company. These credit lines make short-term financing available in the form of bank loans. The Company's Articles of Incorporation authorize the maximum amount of preferred stock that may be issued. Under these provisions, the Company could have issued all $460 million of its remaining authorized, but unissued, preferred stock at Dec. 31, 1994, and remained in compliance with all interest and dividend coverage requirements. The level of common stock authorized under the Company's Articles of Incorporation is 160 million shares. Registration Statements filed with the SEC provide for the sale of up to 1.6 million shares of common stock under the Company's Dividend Reinvestment and Stock Purchase Plan (DRSPP), Executive Long-Term Incentive Award Stock Plan, and Employee Stock Ownership Plan (ESOP) as of Dec. 31, 1994. The Company may issue new shares or purchase shares on the open market for its stock plans. (See Note 7 to the Financial Statements for discussion of stock awards outstanding.) The Company does not plan any general public stock offerings in 1995, but may issue new shares for its DRSPP and ESOP plans. Internally generated funds from utility operations are expected to equal approximately 85 percent of anticipated utility capital expenditures for 1995 and approximately 95 percent of the $1.9 billion in anticipated utility capital expenditures for the five-year period 1995-1999. Internally generated funds from all operations are expected to equal approximately 60 percent and 80 percent, respectively, of the anticipated total capital expenditures for 1995 and the five-year period 1995-1999. Because of NSP's intention to reinvest foreign cash flows in non-U.S. operations, the equity income from international investments currently does not provide operating cash available for U.S. cash requirements such as payment of dividends, domestic capital expenditures and domestic debt service. NSP intends to pursue a diverse portfolio of foreign energy projects with varying levels of cash flows, income and foreign taxation to allow maximum flexibility of foreign cash flows. Item 8 - Financial Statements and Supplementary Data See Item 14(a)-1 in Part IV for index of financial statements included herein. See Note 19 of Notes to Financial Statements for summarized quarterly financial data. INDEPENDENT AUDITORS' REPORT To The Shareholders of Northern States Power Company: We have audited the accompanying consolidated financial statements of Northern States Power Company (Minnesota) and its subsidiaries, listed in the accompanying table of contents in Item 14(a)1. These consolidated financial statements and financial statement schedules are the responsibility of the Companies' management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedules based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Companies at December 31, 1994 and 1993 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. As discussed in Note 3 to the consolidated financial statements, the Companies changed their method of accounting for postretirement health care costs in 1993. DELOITTE & TOUCHE LLP Minneapolis, Minnesota February 8, 1995
Consolidated Statements of Income Year Ended Dec. 31 (Thousands of dollars, except per share data) 1994 1993 1992 Utility Operating Revenues Electric $2 066 644 $1 974 916 $1 823 316 Gas 419 903 429 076 336 206 Total 2 486 547 2 403 992 2 159 522 Utility Operating Expenses Electric production expenses---fuel and purchased power 570 880 524 126 451 696 Cost of gas purchased and transported 263 443 282 028 220 370 Other operation 311 119 304 675 307 232 Maintenance 170 145 161 413 180 585 Administrative and general 193 818 182 535 187 975 Conservation and energy management 31 231 29 358 17 626 Depreciation and amortization 273 801 264 517 242 914 Property and general taxes 234 564 223 108 204 439 Income taxes 129 228 128 346 90 669 Total 2 178 229 2 100 106 1 903 506 Utility Operating Income 308 318 303 886 256 016 Other Income and Expense Equity in earnings of unconsolidated investees 35 863 3 030 2 382 Allowance for funds used during construction---equity 4 548 7 328 8 993 Other income and deductions---net 1 961 5 588 (3 423) Total 42 372 15 946 7 952 Income Before Interest Charges 350 690 319 832 263 968 Interest Charges Interest on long-term debt 97 143 104 714 103 035 Other interest and amortization 17 940 8 848 6 203 Allowance for funds used during construction---debt (7 868) (5 470) (6 198) Total 107 215 108 092 103 040 Income Before Accounting Change 243 475 211 740 160 928 Accounting Change Cumulative effect on prior year of change in accounting principle---unbilled revenues (net of deferred income taxes of $30,594) 45 512 Net Income 243 475 211 740 206 440 Preferred Stock Dividends 12 364 14 580 16 172 Earnings Available for Common Stock $231 111 $197 160 $190 268 Average number of common and equivalent shares outstanding (000's) 66 845 65 211 62 641 Earnings per average common share: Income before accounting change $3.46 $3.02 $2.31 Cumulative effect of unbilled revenue accounting change .73 Total $3.46 $3.02 $3.04 Common Dividends Declared per Share $2.625 $2.565 $2.495 See Notes to Financial Statements
Consolidated Statements of Cash Flows Year Ended Dec. 31 (Thousands of dollars) 1994 1993 1992 Cash Flows from Operating Activities: Net Income $243 475 $211 740 $206 440 Adjustments to reconcile net income to cash from operating activities: Depreciation and amortization 304 583 286 855 261 457 Nuclear fuel amortization 45 553 43 120 45 129 Deferred income taxes from operations (2 262) 12 256 5 186 Deferred investment tax credits recognized (9 501) (9 223) (8 446) Allowance for funds used during construction---equity (4 548) (7 328) (8 993) Undistributed equity in earnings of unconsolidated investees (27 427) (1 142) (1 006) Gain from non-regulated project termination settlement (9 685) Cumulative effect of unbilled revenue accounting change---net of tax (45 512) Cash provided by (used for) changes in certain working capital items (8 627) 33 259 (31 478) Conservation program expenditures - net of amortization (29 963) (21 185) (16 948) Cash provided by (used for) changes in other assets and liabilities (1 042) 12 340 2 767 Net Cash Provided by Operating Activities 500 556 560 692 408 596 Cash Flows from Investing Activities: Capital expenditures: Utility businesses (387 026) (356 836) (423 346) Non-regulated businesses (22 260) (4 859) (4 469) Increase (decrease) in construction payables 11 668 2 598 (2 863) Allowance for funds used during construction---equity 4 548 7 328 8 993 Sale (purchase) of short-term investments---net (866) 62 1 552 Investment in external decommissioning fund (42 677) (32 578) (27 929) Proceeds from non-regulated project termination settlement 14 000 Business acquisitions (159 385) Investments in non-regulated projects and other (136 826) (25 957) 2 554 Net Cash Used for Investing Activities (559 439) (569 627) (445 508) Cash Flows from Financing Activities: Change in short-term debt---net issuances (repayments) 132 239 (40 361) 146 561 Proceeds from issuance of long-term debt 367 184 613 120 126 531 Repayment of long-term debt, including reacquisition premiums (272 097) (489 106) (48 344) Proceeds from issuance of common stock 1 368 183 654 2 940 Redemption of preferred stock, including premium (36 092) (25 838) Dividends paid (186 568) (180 220) (171 355) Net Cash Provided by Financing Activities 42 126 50 995 30 495 Net Increase (Decrease) in Cash and Cash Equivalents (16 757) 42 060 (6 417) Cash and Cash Equivalents at Beginning of Period 57 812 15 752 22 169 Cash and Cash Equivalents at End of Period $41 055 $57 812 $15 752 Cash Provided by (Used for) Changes in Certain Working Capital Items: Accounts receivable and accrued utility revenues $(1 695) $(50 403) $(14 108) Materials and supplies inventories (13 462) 13 911 (5 280) Payables and accrued liabilities (excluding construction payables) 32 550 54 247 5 206 Customer rate refunds (10 410) 12 235 (11 987) Other (15 610) 3 269 (5 309) Net $(8 627) $33 259 $(31 478) Supplemental Disclosures of Cash Flow Information: Cash paid during the year for: Interest (net of amount capitalized) $106 867 $107 037 $99 669 Income taxes $170 474 $120 491 $93 032 See Notes to Financial Statements
Consolidated Balance Sheets Dec. 31 (Thousands of dollars) 1994 1993 Assets Utility Plant Electric---including construction work in progress: 1994, $117,235; 1993, $174,893 $6 372 317 $6 167 670 Gas 677 233 621 871 Other 262 506 237 293 Total 7 312 056 7 026 834 Accumulated provision for depreciation (3 116 811) (2 888 144) Nuclear fuel---including amounts in process: 1994, $12,505; 1993, $15,358 797 097 749 078 Accumulated provision for amortization (718 690) (673 669) Net utility plant 4 273 652 4 214 099 Current Assets Cash and cash equivalents 41 055 57 812 Short-term investments 892 26 Accounts receivable---net of accumulated provision for uncollectible accounts: 1994, $4,072; 1993, $4,476 280 858 266 531 Accrued utility revenues 98 651 111 296 Federal income tax and interest receivable 28 858 20 927 Materials and supplies---at average cost Fuel 56 960 41 776 Other 101 878 103 599 Prepayments and other 56 075 40 885 Total current assets 665 227 642 852 Other Assets Regulatory assets 357 576 334 354 Non-regulated property---net of accumulated depreciation: 1994, $73,296; 1993, $63,351 172 961 157 615 Investments in non-regulated projects 181 330 45 772 External decommissioning fund and other investments 165 466 121 657 Federal income tax and interest receivable 56 358 Intangible assets and other 81 001 71 369 Total other assets 1 014 692 730 767 Total $5 953 571 $5 587 718 Liabilities & Equity Capitalization Common stockholders' equity $1 896 967 $1 827 454 Preferred stockholders' equity 240 469 240 469 Long-term debt 1 463 354 1 291 867 Total capitalization 3 600 790 3 359 790 Current Liabilities Long-term debt due within one year 16 106 90 618 Other long-term debt potentially due within one year 141 600 141 600 Short-term debt---primarily commercial paper 238 439 106 200 Accounts payable 234 905 210 654 Taxes accrued 178 119 177 853 Interest accrued 28 164 24 110 Dividends payable on common and preferred stocks 47 283 46 195 Accrued payroll, vacation and other 79 029 73 792 Total current liabilities 963 645 871 022 Other Liabilities Deferred income taxes 848 870 788 378 Deferred investment tax credits 173 838 187 466 Regulatory liabilities 200 517 243 880 Pension and other benefit obligations 92 514 64 224 Other long-term obligations and deferred income 73 397 72 958 Total other liabilities 1 389 136 1 356 906 Commitments and Contingent Liabilities (See Notes 16 and 17) Total $5 953 571 $5 587 718 See Notes to Financial Statements
Consolidated Statements of Changes in Common Stockholders' Equity Cumulative Currency Number of Retained Shares Held Translation (Dollar amounts in thousands) Shares Issued Par Value Premium Earnings by ESOP Adjustments Balance at Dec. 31, 1991 62 541 404 $156 354 $368 021 $1 066 559 $(14 104) Net income 206 440 Dividends declared: Cumulative preferred stock at required rates (16 172) Common stock (156 109) Exercise of stock options and other stock awards 56 956 142 2 805 Preferred stock redemption and stock issuance costs (7) (822) Repayment of ESOP loan 8 991 Balance at Dec. 31, 1992 62 598 360 $156 496 $370 819 $1 099 896 $(5 113) Net income 211 740 Dividends declared: Cumulative preferred stock at required rates (14 580) Common stock (168 615) Issuances of common stock 4 281 217 10 703 176 296 Preferred stock redemption and stock issuance costs (3 345) (1 069) Loan to ESOP to purchase shares (15 000) Repayment of ESOP loan 9 226 Balance at Dec. 31, 1993 66 879 577 $167 199 $543 770 $1 127 372 $(10 887) Net income 243 475 Dividends declared: Cumulative preferred stock at required rates (12 364) Common stock (175 292) Issuances of common stock 42 567 106 1 342 Stock issuance costs (80) Tax benefit from stock options exercised 843 Repayment of ESOP loan 7 897 Currency translation adjustments $3 586 Balance at Dec. 31, 1994 66 922 144 $167 305 $545 875 $1 183 191 $(2 990) $3 586 See Notes to Financial Statements
Consolidated Statements of Capitalization Dec. 31 (Thousands of dollars) 1994 1993 Common Stockholders' Equity Common stock-authorized 160,000,000 shares of $2.50 par value; issued shares: 1994, 66,922,144; 1993, 66,879,577 $167 305 $167 199 Premium on common stock 545 875 543 770 Retained earnings 1 183 191 1 127 372 Leveraged common stock held by Employee Stock Ownership Plan (ESOP) - shares at cost: 1994, 59,445; 1993, 239,940 (2 990) (10 887) Currency translation adjustments - net 3 586 Total common stockholders' equity $1 896 967 $1 827 454 Cumulative Preferred Stock - authorized 7,000,000 shares of $100 par value; outstanding shares: 1994 and 1993, 2,400,000 Minnesota Company $3.60 series, 275,000 shares $ 27 500 $ 27 500 4.08 series, 150,000 shares 15 000 15 000 4.10 series, 175,000 shares 17 500 17 500 4.11 series, 200,000 shares 20 000 20 000 4.16 series, 100,000 shares 10 000 10 000 4.56 series, 150,000 shares 15 000 15 000 6.80 series, 200,000 shares 20 000 20 000 7.00 series, 200,000 shares 20 000 20 000 Variable Rate series A, 300,000 shares 30 000 30 000 Variable Rate series B, 650,000 shares 65 000 65 000 Total 240 000 240 000 Premium on preferred stock 469 469 Total preferred stockholders' equity $240 469 $240 469 Long-Term Debt First Mortgage Bonds Minnesota Company Series due: June 1, 1995, 6 1/8% $30 000 March 1, 1996, 6.2% $8 800* 8 800* Aug. 1, 1996, 5 7/8% 45 000 Oct. 1, 1997, 5 7/8% 100 000 100 000 Oct. 1, 1997, 6 1/2% 30 000 May 1, 1998, 6 3/4% 45 000 Feb. 1, 1999, 5 1/2% 200 000 Dec. 1, 2000, 5 3/4% 100 000 100 000 Oct. 1, 2001, 7 7/8% 150 000 March 1, 2002, 7 3/8% 50 000 50 000 Feb. 1, 2003, 7 1/2% 50 000 50 000 April 1, 2003, 6 3/8% 80 000 80 000 Jan. 1, 2004, 8 3/8% 75 000 Dec. 1, 2005, 6 1/8% 70 000 70 000 Dec. 1, 1993-2006, 6.57% 22 300** 23 400** March 1, 2011, Variable Rate 13 700* 13 700* July 1, 2019, 9 1/8% 98 000 99 000 June 1, 2020, 9 3/8% 70 000 100 000 Total $1 012 800 $919 900 Less redeemable bonds classified as current (See Note 9) (13 700) (13 700) Less current maturities, including in 1993 the 2004 series bonds redeemed in January 1994 (1 200) (76 100) Net $ 997 900 $830 100 * Pollution control financing ** Resource recovery financing See Notes to Financial Statements Dec. 31 (Thousands of dollars) 1994 1993 Long-Term Debt-continued First Mortgage Bonds Wisconsin Company (less reacquired bonds of $490 at Dec. 31, 1994) Series due: Oct. 1, 2003, 5 3/4% $40 000 $40 000 April 1, 2021, 9 1/8% 48 010 49 000 March 1, 2023, 7 1/4% 110 000 110 000 Total 198 010 199 000 Less current maturities (2 910) Net $195 100 $199 000 Guaranty Agreements - Minnesota Company Series due: Feb. 1, 1993-2003, 5.41% $ 5 900* $ 6 100* May 1, 1993-2003, 5.69% 24 750* 25 250* Feb. 1, 2003, 7.40% 3 500* 3 500* Total 34 150 34 850 Less current maturities (700) (700) Net $33 450 $34 150 Miscellaneous Long-Term Debt City of Becker Pollution Control Revenue Bonds-Series due Dec. 1, 2005, 7.25% $ 9 000* $ 9 000* April 1, 2007, 6.80% 60 000* 60 000* March 1, 2019, Variable Rate 27 900* 27 900* Sept. 1, 2019, Variable Rate 100 000* 100 000* Anoka County Resource Recovery Bond-Series due Dec. 1, 1993-2008, 7.05% 25 150** 26 100** City of La Crosse, Resource Recovery Bond-Series due Nov. 1, 2011, 7 3/4% 18 600** 18 600** Viking Gas Transmission Company Senior Notes-Series due Oct. 31, 2008, 6.4% 29 511 31 644 NRG Energy Center, Inc. (Minneapolis Energy Center) Senior Secured Notes-Series due June 15, 2013, 7.31% 81 498 83 518 United Power & Land First Mortgage Notes due March 31, 2000, 7.62% 9 375 Various Affordable Housing Project Mortgage Notes due 1994-2009, 7.52%-10.0% 7 710 Employee Stock Ownership Plan Bank Loans due 1993-1995, Variable Rate 2 698 10 887 Other 10 736 8 397 Total 382 178 376 046 Less variable rate Becker bonds classified as current (See Note 9) (127 900) (127 900) Less current maturities (11 296) (13 818) Net $242 982 $234 328 Unamortized discount on long-term debt-net (6 078) (5 711) Total long-term debt 1 463 354 1 291 867 Total capitalization $3 600 790 $3 359 790 * Pollution control financing ** Resource recovery financing See Notes to Financial Statements
NOTES TO FINANCIAL STATEMENTS 1. Summary of Significant Accounting Policies System of Accounts Northern States Power Company, a Minnesota corporation (the Company), and two wholly owned subsidiaries of the Company, Northern States Power Company, a Wisconsin corporation (the Wisconsin Company), and Viking Gas Transmission Company (Viking), maintain accounting records in accordance with either the uniform system of accounts prescribed by the Federal Energy Regulatory Commission (FERC) or those prescribed by state regulatory commissions, whose systems are the same in all material respects. Principles of Consolidation - The consolidated financial statements include all material companies in which NSP holds a controlling financial interest, including: the Wisconsin Company; NRG Energy, Inc. (NRG); Viking; Cenergy, Inc. (Cenergy); and Eloigne Company. As discussed in Note 5, NSP has investments in partnerships, joint ventures and projects for which the equity method of accounting is applied. All significant intercompany transactions and balances have been eliminated in consolidation except for intercompany and intersegment profits for sales among the electric and gas utility businesses of the Company, the Wisconsin Company and Viking, which are allowed in utility rates. The Company and its subsidiaries collectively are referred to herein as NSP. Revenues - Revenues are recognized based on products and services provided to customers each month. Because utility customer meters are read and billed on a cycle basis, unbilled revenues (and related energy costs) are estimated and recorded for services provided from the monthly meter-reading dates to month- end. The Company's rate schedules, applicable to substantially all of its utility customers, include cost-of-energy adjustment clauses, under which rates are adjusted to reflect changes in average costs of fuels, purchased energy and gas purchased for resale. As ordered by its primary regulator, Wisconsin Company retail rate schedules include a cost-of-energy adjustment clause for purchased gas but not for electric fuel and purchased energy. The biennial retail rate review process for Wisconsin electric operations considers changes in electric fuel and purchased energy costs in lieu of a cost-of-energy adjustment. Utility Plant and Retirements - Utility plant is stated at original cost. The cost of additions to utility plant includes contracted work, direct labor and materials, allocable overhead costs and allowance for funds used during construction. The cost of units of property retired, plus net removal cost, is charged to the accumulated provision for depreciation and amortization. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses. Allowance for Funds Used During Construction (AFC) - AFC, a non-cash item, is computed by applying a composite pretax rate, representing the cost of capital used to finance utility construction activities, to qualified Construction Work in Progress (CWIP). AFC rates were 5.0 percent in 1994, 7.4 percent in 1993 and 8.0 percent in 1992. The amount of AFC capitalized as a construction cost in CWIP is credited to other income (for equity capital) and interest charges (for debt capital). AFC amounts capitalized in CWIP are included in rate base for establishing utility service rates. In addition to construction- related amounts, AFC is also recorded to reflect returns on capital used to finance conservation programs. Depreciation - For financial reporting purposes, depreciation is computed by applying the straight-line method over the estimated useful lives of various property classes. The Company files with the Minnesota Public Utilities Commission (MPUC) an annual review of remaining lives for electric and gas production properties. The most recent studies, as approved by the MPUC, recommended an increase of approximately $0.5 million and a decrease of approximately $0.9 million for the 1994 and 1993 annual depreciation accruals, respectively. The remaining lives of the Company's nuclear facilities were submitted for review in 1994. The recovery period recommended for the Prairie Island plant was reduced because of the uncertainty regarding used nuclear fuel storage. (See Note 16.) The filing, as approved by the MPUC, increased depreciation by approximately $9.7 million due to the change from previously approved property lives. However, because the annual accruals for projected future decommissioning expenses decreased, the net impact to the Company from 1994 capital recovery filings is a decrease of about $800,000 in annual depreciation and decommissioning expenses, effective Jan. 1, 1994. Every five years, the Company also must file an average service life filing for transmission, distribution and general properties. The most recent filing, as approved by the MPUC, increased 1993 depreciation by approximately $4.7 million from 1992 levels. In 1994, the Company submitted to the MPUC a depreciation study for the general plant accounts requesting a change in the depreciation calculation method. While a straight-line method is still used, the approved method change affects the level of detail at which depreciation expense is calculated. The impact to 1994 depreciation accruals from the change was a decrease of approximately $1.1 million. Depreciation provisions, as a percentage of the average balance of depreciable utility property in service, were 3.55 percent in 1994, 3.47 percent in 1993 and 3.36 percent in 1992. Decommissioning - NSP records the cost of decommissioning the Company's nuclear generating plants through annual depreciation accruals. The provision for the estimated decommissioning costs has been calculated using an annuity approach designed to provide for full expense accrual (with full rate recovery) of the future decommissioning costs, including reclamation and removal, over the estimated operating lives of the Company's nuclear plants. Nuclear Fuel Expense - The original cost of nuclear fuel is amortized to fuel expense based on energy expended. Nuclear fuel expense also includes assessments from the U.S. Department of Energy (DOE) for future fuel disposal and DOE facility decommissioning, as discussed in Note 16. Environmental Costs - Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. When a single estimate of the liability cannot be determined, the low end of the estimated range is recorded. Costs are charged to expense or deferred as a regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of conditions caused by past operations, or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised, and remediation efforts proceed. For sites where NSP has been designated as one of several potentially responsible parties, the amount accrued represents NSP's estimated share of the cost. NSP intends to treat any future costs related to decommissioning and restoration of its power plants and substation sites as a removal cost of retirement through plant depreciation expense. Income Taxes - NSP records income taxes in accordance with Statement of Financial Accounting Standards (SFAS) No. 109 - Accounting for Income Taxes. (Before 1993, NSP followed SFAS No. 96---Accounting for Income Taxes, resulting in substantially the same accounting as SFAS No. 109.) Under the liability method required by SFAS No. 109, income taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by law to be in effect when the temporary differences reverse. Due to the effects of regulation, current income tax expense is provided for the reversal of some temporary differences previously accounted for by the flow-through method. Also, regulation has created certain regulatory assets and liabilities related to income taxes, as summarized in Note 12. Investment tax credits are deferred and amortized over the estimated lives of the related property. Foreign Currency Translation - The local currencies are generally the functional currency of NSP's foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Income, expense and cash flows are translated at weighted-average rates of exchange for the period. The resulting currency translation adjustments are accumulated and reported as a separate component of shareholders' equity. Exchange gains and losses that result from foreign currency transactions (e.g. converting cash distributions made in one currency to another currency) are included in the results of operations as a component of equity in earnings of unconsolidated investees. Through Dec. 31, 1994, NSP had not experienced any material translation gains or losses from foreign currency transactions that have occurred since the respective foreign investment dates. Derivative Financial Instruments - NSP's policy is to hedge foreign currency denominated investments as they are made to preserve their U.S. dollar value. NRG has entered into currency hedging transactions through the use of forward foreign currency exchange agreements. Gains and losses on these contracts offset the effect of foreign currency exchange rate fluctuations on the valuation of the investments underlying the hedges. The effect of hedging gains and losses, net of income taxes, is reported with other currency translation adjustments as a separate component of stockholders' equity. NRG is not hedging currency translation adjustments related to operating results. NSP does not speculate in foreign currencies. A second derivative arrangement is the use of natural gas futures contracts by Cenergy to manage the risk of gas price fluctuations. The cost or benefit of natural gas futures contracts is recorded when related sales commitments are fulfilled as a component of Cenergy's non-regulated operating expenses. A third derivative instrument used by NSP is interest rate swaps that convert fixed rate debt to variable rate debt. The cost or benefit of the interest rate swap agreements is recorded as a component of interest expense. Use of Estimates - In recording transactions and balances resulting from business operations, NSP uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, environmental loss contingencies, unbilled revenues and actuarially determined benefit costs. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. Recent changes in interest rates have resulted in changes to actuarial assumptions used in the benefit cost calculations for postretirement benefits. Also, the depreciable lives of certain plant assets are reviewed and, if appropriate, revised each year, as discussed previously. (See Notes 10 and 16 for more information on the effects of these changes in estimates.) Cash Equivalents - NSP considers investments in certain debt instruments (primarily commercial paper) with an original maturity of three months or less at the time of purchase to be cash equivalents. Regulatory Deferrals - As regulated utilities, the Company, the Wisconsin Company and Viking account for certain income and expense items under the provisions of SFAS No. 71---Accounting for the Effects of Regulation. In doing so, certain costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates. Likewise, certain credits that would otherwise be reflected as income are deferred as regulatory liabilities based on expected flowback to customers in future rates. Management's expected recovery of deferred costs and expected flowback of deferred credits are generally based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with ratemaking treatment established by regulators. Note 12 describes the nature and amounts of these regulatory deferrals. Other Assets - The purchase of the Minneapolis Energy Center by an NRG subsidiary in 1993 at a price exceeding the underlying fair value of net assets acquired resulted in recorded goodwill. This goodwill and other intangible assets acquired are being amortized using the straight-line method over 30 years. NSP periodically evaluates the recovery of goodwill based on an analysis of estimated undiscounted future cash flows. Intangible and other assets also include deferred financing costs of approximately $12.9 million at Dec. 31, 1994, which are being amortized over the remaining maturity period of the related debt. Reclassifications - Certain reclassifications have been made to the 1993 and 1992 financial statements to conform with the 1994 presentation. These reclassifications had no effect on net income or earnings per share. 2. Rate Matters On Aug. 9, 1994, the Company applied to the North Dakota Public Service Commission (NDPSC) for an annual electric rate reduction of $3.6 million. The reduction reflects a correction in cost allocations to the North Dakota jurisdiction. The Company also requested authority to make refunds to customers to effectively implement the reduction as of June 1, 1994. On Nov. 9, 1994, the NDPSC approved the proposed rate reduction, the liability for which has been accrued as of Dec. 31, 1994. In January 1995, the NDPSC held a hearing on the possibility of retroactive refunds for the period Jan. 1, 1989, through June 1, 1994, but has not yet reached a decision. The ultimate outcome of this proceeding is not determinable at this time. Other rate increases filed in Wisconsin and North Dakota that were effective in 1994 increased revenues by approximately $2.6 million. 3. Accounting Changes Postemployment Benefits - Effective Jan. 1, 1994, NSP adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 112---Employers' Accounting for Postemployment Benefits. This standard required the accrual of certain postemployment costs, such as injury compensation and severance, that are payable in the future. Initially, the Company's pre-1994 injury compensation liability was deferred in a regulatory asset based on a preliminary decision to request amortization through rates over future periods. In October 1994, another Minnesota utility was ordered by the MPUC to defer its pre-1994 SFAS No. 112 liability and amortize it to match a three- year rate recovery period. Since the Company may not file a rate case within the deferral period approved by the MPUC, which ends in 1996, the Company's pre-1994 liability of approximately $9.4 million (8 cents per share) was expensed during 1994. Fair Value Accounting for Certain Investments - Effective Jan. 1, 1994, NSP adopted the provisions of SFAS No. 115---Accounting for Certain Investments in Debt and Equity Securities. This new standard resulted in an increase of approximately $1.4 million in decommissioning investments to present such investments at their market value at Dec. 31, 1994. This increase represents an unrealized gain on investments, which has been deferred as a regulatory liability. The Company anticipates offsetting such gains, when realized, against decommissioning costs in future ratemaking. Accounting for Employee Stock Ownership Plans (ESOP) - Effective Jan. 1, 1994, NSP adopted the American Institute of Certified Public Accountants' Statement of Position (SOP) 93-6. This SOP changed the accounting for compensation expense associated with ESOP plans, and changed how ESOP shares were considered for earnings-per-share calculations. No additional compensation expense was recorded by NSP in 1994 due to the adoption of this SOP. The impact of the reduction in average common shares was immaterial to 1994 earnings per share (an increase in earnings per share of less than 1 cent). Postretirement Benefits - As discussed in Note 10, NSP changed its accounting for postretirement medical and death benefits in 1993. Due to rate recovery of the expense increases, there was no material effect on net income in 1993 or 1994. Of the $20 million in 1993 cost increases over 1992 due to adoption of SFAS No. 106, about $5 million was capitalized, $12 million was deferred to be amortized over rate recovery periods in 1994-1996, and about $3 million was expensed, but essentially offset by rate increases. In 1994, administrative and general expenses increased by approximately $16 million due to the full recognition of accrued SFAS No. 106 costs, including amounts deferred from 1993. 4. Business Acquisitions Through its subsidiaries, NRG purchased equity interests during 1994 in three significant international projects, two in Germany and one in Australia. One of the investments is a 33-percent interest in Mitteldeutsche Braunkohlengesellschaft mbh (MIBRAG), a German corporation. MIBRAG was formed by the German government to operate coal mines, electric power plants and other energy-related facilities. The other German investment is a 50-percent interest in Saale Energie GmbH (Saale), also a German corporation. Saale owns a 400-megawatt share of a 900-megawatt power plant currently under construction near Schkopau, Germany. The Australian investment is a 37.5- percent interest in a joint venture that acquired a 1,680-megawatt coal-fired power plant in Gladstone, Queensland, Australia, which is operated by an NRG subsidiary. The total acquisition investments in these three projects through 1994, including capitalized development costs, was approximately $100 million. Earnings from equity interests in NRG international projects acquired in 1994 contributed approximately 38 cents per share to NSP's 1994 earnings. 5. Investments Accounted for by the Equity Method Through its non-regulated subsidiaries, NSP has investments in various international and domestic energy projects and domestic affordable housing and real estate projects. (Before 1994, such investments had been limited to immaterial domestic projects.) The equity method of accounting is applied to such investments because the ownership structure prevents NSP from exercising a controlling influence over operating and financial policies of the projects. A summary of NSP's significant equity-method investments is as follows:
Purchased or Name Geographic Area Economic Interest Placed in Service Various Independent Power Production Facilities U.S.A. 45%-50% July 1991-December 1994 Affordable Housing-Limited Partnerships U.S.A. 50%-99% April 1993-December 1994 Rosebud SynCoal Partnership U.S.A. 50% August 1993 MIBRAG Europe 33% January 1994 Gladstone Power Station Australia 37.5% March 1994 Schkopau Power Station Europe 20.6% Under Construction Scudder Latin American Trust for Independent Power Energy Projects Latin America 6.3%-12.5% December 1994
Summarized Financial Information of Unconsolidated Investees - Summarized financial information for these projects, including interests owned by NSP and other parties, was as follows as of and for the year ended Dec. 31, 1994: Financial Position (Millions of dollars) Results of Operations (Millions of dollars) Current Assets $ 514.9 Operating Revenues $778.4 Other Assets 1,593.8 Operating Income $128.0 Total Assets $2,108.7 Net Income $117.0 Current Liabilities $ 159.6 Other Liabilities 1,480.0 Equity 469.1 Total Liabilities and Equity $2,108.7 6. Cumulative Preferred Stock The Company has two series of adjustable rate preferred stock. The dividend rates are calculated quarterly and are based on prevailing rates of certain taxable government debt securities indices. At Dec. 31, 1994, the annualized dividend rates were $5.82 for series A and $5.97 for series B. At Dec. 31, 1994, the various preferred stock series were callable at prices per share ranging from $102.00 to $103.75, plus accrued dividends. In 1993, the Company redeemed all 350,000 shares of its $7.84 series Cumulative Preferred Stock at $103.12 per share. In 1992, the Company redeemed all 250,000 shares of its $8.80 series Cumulative Preferred Stock at $103.35 per share. 7. Common Stock and Incentive Stock Plans The Company's Articles of Incorporation and First Mortgage Indenture provide for certain restrictions on the payment of cash dividends on common stock. At Dec. 31, 1994, the Company could have paid, without restrictions, additional cash dividends of more than $1 billion on common stock. NSP has an Executive Long-Term Incentive Award Stock Plan that permits granting non-qualified stock options. The options currently granted may be exercised one year from the date of grant and are exercisable thereafter for up to nine years. The plan also allows certain employees to receive restricted stock and other performance awards. Performance awards are valued in dollars, but are paid in shares based on the market price at the time of payment. Transactions under the various incentive stock programs, which may result in the issuance of new shares, were as follows:
Stock Awards (Thousands of shares) 1994 1993 1992 Outstanding Jan. 1 537.1 528.7 403.3 Options granted 304.0 196.9 201.8 Other stock awards .2 9.5 .8 Options and awards exercised (42.6) (174.3) (57.0) Options and awards forfeited (16.1) (22.2) (20.1) Other (.2) (1.5) (.1) Outstanding at Dec. 31 782.4 537.1 528.7 Option price ranges: Unexercised at Dec. 31 $33.25-$43.50 $33.25-$43.50 $33.25-$40.94 Exercised during the year $33.25-$43.50 $33.25-$40.94 $33.25-$36.44
Using the treasury stock method of accounting for outstanding stock options, the weighted average number of shares of common stock outstanding for the calculation of primary earnings per share includes any dilutive effects of stock options and other stock awards as common stock equivalents. The differences between shares used for primary and fully diluted earnings per share were not material. 8. Short-Term Borrowings NSP has approximately $310 million of commercial bank credit lines under commitment fee arrangements. These credit lines make short-term financing available in the form of bank loans and support for commercial paper sales. There were approximately $3.6 million of borrowings against these credit lines, with interest payable at 9.75 percent, at Dec. 31, 1994, and no such borrowings at Dec. 31, 1993. At Dec. 31, 1994 and 1993, the Company had $234.8 million and $106.2 million, respectively, in short-term commercial paper borrowings outstanding. The weighted average interest rate on all short-term borrowings as of Dec. 31, 1994 and Dec. 31, 1993, was 6.1 percent and 3.3 percent, respectively. 9. Long-Term Debt The annual sinking-fund requirements of the Company's and the Wisconsin Company's First Mortgage Indentures are the amounts necessary to redeem 1 percent of the highest principal amount of each series of first mortgage bonds at any time outstanding, excluding those series issued for pollution control and resource recovery financings, and excluding certain other series totaling $740 million. The Company may, and has, applied property additions in lieu of cash payments on all series, except the 9 1/8 percent Series due July 1, 2019, as permitted by its First Mortgage Indenture. The Wisconsin Company also may apply property additions in lieu of cash on all series as permitted by its First Mortgage Indenture. Except for minor exclusions, all real and personal property is subject to the liens of the first mortgage indentures. The Company's First Mortgage Bonds Series due March 1, 2011, and the City of Becker Pollution Control Revenue Bonds Series due March 1, 2019, and Sept. 1, 2019, have variable interest rates, which currently change at various periods up to 270 days, based on prevailing rates for certain commercial paper securities or similar issues. The interest rates applicable to these issues averaged 5.9 percent, 4.1 percent and 4.1 percent, respectively, at Dec. 31, 1994. The 2011 series bonds are redeemable upon seven days notice at the option of the bondholder. The Company also is potentially liable for repayment of the 2019 Series Becker Bonds when the bonds are tendered, which occurs each time the variable interest rates change. The principal amount of all three series of these variable rate bonds outstanding represents potential short- term obligations and, therefore, is reported under current liabilities on the balance sheet. Maturities and sinking-fund requirements on long-term debt are: 1995, $16,106,000; 1996, $18,934,000; 1997, $110,538,000; 1998, $13,541,000; and 1999, $209,888,000. 10. Benefit Plans and Other Postretirement Benefits Pension Benefits - NSP has a non-contributory, defined benefit pension plan that covers substantially all employees. Benefits are based on a combination of years of service, the employee's highest average pay for 48 consecutive months and Social Security benefits. The funded status of NSP's pension plan as of Dec. 31 is as follows:
(Thousands of dollars) 1994 1993 Actuarial present value of benefit obligation: Vested $571 254 $655 002 Non-vested 120 420 139 346 Accumulated benefit obligation $691 674 $794 348 Projected benefit obligation $836 957 $974 160 Plan assets at fair value 1 165 584 1 244 650 Plan assets in excess of projected benefit obligation (328 627) (270 490) Unrecognized prior service cost (21 538) (22 580) Unrecognized net actuarial gain 370 289 315 049 Unrecognized net transitional asset 691 767 Net pension liability recorded $20 815 $22 746
For regulatory purposes, the Company's pension expense is determined and recorded under the aggregate-cost method. As required by SFAS No. 87--- Employers' Accounting for Pensions, the difference between the pension costs recorded for ratemaking purposes and the amounts determined under SFAS No. 87 are recorded as a regulatory liability on the balance sheet. Net annual periodic pension cost includes the following components:
(Thousands of dollars) 1994 1993 1992 Service cost-benefits earned during the period $27 536 $25 015 $24 080 Interest cost on projected benefit obligation 65 107 71 075 69 853 Actual return on assets (12 668) (152 019) (115 455) Net amortization and deferral (82 114) 66 299 39 019 Net periodic pension cost determined under SFAS No. 87 (2 139) 10 370 17 497 Additional costs recognized due to actions of regulators 3 922 5 117 2 741 Net periodic pension cost recognized for ratemaking $1 783 $15 487 $20 238
The weighted average discount rate used in determining the actuarial present value of the projected obligation was 8 percent in 1994 and 7 percent in 1993. The rate of increase in future compensation levels used in determining the actuarial present value of the projected obligation was 5 percent in 1994 and 1993. Changes made to assumptions for the 1993 valuation decreased 1994 pension costs (determined under SFAS No. 87) by approximately $3 million. Changes made to assumptions for the 1994 valuation are expected to increase 1995 pension costs (determined under SFAS No. 87) by approximately $1 million. The assumed long-term rate of return on assets used for cost determinations under SFAS No. 87 was 8 percent for 1994, 1993 and 1992. Plan assets principally consist of common stock of public companies and U.S. government securities. Postretirement Health Care - NSP has a contributory health and welfare benefit plan that provides health care and death benefits to substantially all employees after their retirement. The plan is intended to provide for sharing the costs of retiree health care between NSP and retirees. For employees retiring after Jan. 1, 1994, a six-year cost-sharing strategy was implemented with retirees paying 15 percent of the total cost of health care in 1994, increasing to a total of 40 percent in 1999. Effective Jan. 1, 1993, NSP adopted the provisions of SFAS No. 106--- Employers' Accounting for Postretirement Benefits Other Than Pensions. SFAS No. 106 requires the actuarially determined obligation for postretirement health care and death benefits to be fully accrued by the date employees attain full eligibility for such benefits, which is generally when they reach retirement age. This is a significant change from NSP's pre-1993 policy of recognizing benefit costs on a cash basis after retirement. In conjunction with the adoption of SFAS No. 106, NSP elected to amortize on a straight-line basis over 20 years the unrecognized accumulated postretirement benefit obligation (APBO) of $215.6 million for current and future retirees. This obligation considered 1994 plan design changes, including Medicare integration, increased retiree cost sharing and managed indemnity measures not in effect in 1993. Before 1993, NSP funded payments for retiree benefits internally. While NSP generally prefers to continue using internal funding of benefits paid and accrued, significant levels of external funding have been required by NSP's regulators, as discussed below, including the use of tax-advantaged trusts. Plan assets held in such trusts as of Dec. 31, 1994, consisted of investments in equity mutual funds and cash equivalents. The funded status of NSP's health care plan as of Dec. 31 is as follows:
(Millions of dollars) 1994 1993 APBO: Retirees $132.2 $120.2 Fully eligible plan participants 21.5 18.8 Other active plan participants 79.4 90.8 Total APBO 233.1 229.8 Plan assets at fair value 8.0 6.1 APBO in excess of plan assets 225.1 223.7 Unrecognized net actuarial gain (loss) 2.3 (1.3) Unrecognized transition obligation (194.0) (204.8) Net benefit obligation recorded $ 33.4 $ 17.6
The assumed health care cost trend rates used in measuring the APBO at Dec. 31, 1994 and 1993, respectively, were 11.0 and 14.1 percent for those under age 65, and 7.5 and 8.0 percent for those over age 65. The assumed cost trend rates are expected to decrease each year until they reach 5.5 percent for both age groups in the year 2004, after which they are assumed to remain constant. A 1-percent increase in the assumed health care cost trend rate for each year would increase the APBO by approximately 13 percent as of Dec. 31, 1994. Service and interest cost components of the net periodic postretirement cost would increase by approximately 16 percent with a similar 1-percent increase in the assumed health care cost trend rate. The assumed discount rate used in determining the APBO was 8 percent for Dec. 31, 1994, 7 percent for Dec. 31, 1993, and 8 percent for Jan. 1, 1993, compounded annually. The assumed long-term rate of return on assets used for cost determinations under SFAS No. 106 was 8 percent for 1994 and 1993. While the 1994 assumption changes had no effect on 1994 benefit costs, the effect of the changes in 1995 is expected to be a cost decrease of approximately $1.3 million. Similarly, the assumption changes made for the Dec. 31, 1993, calculations had no effect on 1993 benefit costs, but decreased 1994 costs by approximately $2 million. In 1992, NSP recognized $12.8 million as the cost attributable to postretirement health care and death benefits based on payments made. The net annual periodic postretirement benefit cost recorded for 1994 and 1993 consists of the following components:
(Millions of dollars) 1994 1993 Service cost-benefits earned during the year $5.0 $4.4 Interest cost (on service cost and APBO) 16.1 17.5 Actual return on assets (.2) (.1) Amortization of transition obligation 10.8 10.8 Net amortization and deferral (.3) .1 Net periodic postretirement health care cost under SFAS No. 106 31.4 32.7 Costs recognized (deferred) due to actions of regulators 4.1 (12.1) Net periodic postretirement health care cost recognized for ratemaking $35.5 $20.6
Regulators for NSP's retail and wholesale customers in Minnesota, Wisconsin and North Dakota have allowed full recovery of increased benefit costs under SFAS No. 106, effective in 1993. Increased 1993 accrual costs for Minnesota retail customers are being amortized over the years 1994 through 1996, consistent with approved rate recovery. External funding was required by Minnesota and Wisconsin retail regulators to the extent it is tax advantaged; funding began for Wisconsin in 1993 and must begin by the next general rate filing for Minnesota. For wholesale ratemaking, the FERC has required external funding for all benefits paid and accrued under SFAS No. 106. ESOP - NSP has a leveraged Employee Stock Ownership Plan (ESOP) that covers substantially all employees. Employer contributions to this non-contributory, defined contribution plan are generally made to the extent NSP realizes a tax savings on its income statement from dividends paid on certain shares held by the ESOP. Contributions to the ESOP in 1994, 1993 and 1992, which represent compensation expense, were $5,695,000, $6,281,000 and $6,415,000, respectively. ESOP contributions have no material effect on NSP earnings because the contributions (net of tax) are essentially offset by the tax savings provided by the dividends paid on ESOP shares. (See Note 11.) Leveraged shares held by the ESOP are allocated to participants when dividends on stock held by the plan are used to repay ESOP loans. Of the 5.4 million shares of the Company's stock that NSP's ESOP currently holds, an average of 111,845 uncommitted leveraged ESOP shares were excluded from earnings-per- share calculations in 1994. The fair value of NSP's leveraged ESOP shares approximated cost at Dec. 31, 1994. 401(k) - NSP has a contributory, defined contribution Retirement Savings Plan (the Plan), which complies with section 401(k) of the Internal Revenue Code and covers substantially all employees. Beginning in 1994, NSP matches specified amounts of employee contributions Plan. NSP's matching contributions were $2.6 million in 1994. 11. Income Tax Expense Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate (35 percent in 1994 and 1993, and 34 percent in 1992) to net income before income tax expense. The reasons for the difference are as follows:
(Thousands of dollars) 1994 1993 1992 Tax computed at statutory U.S. federal tax rate $131 860 $119 868 $84 015 Increases (decreases) in tax from: State income taxes net of federal income tax benefit 22 053 20 838 13 421 Tax rate differential on foreign income (6 750) Tax credits recognized (13 049) (9 545) (8 846) Non-taxable AFC-equity included in book income (1 592) (2 565) (3 058) Net-of-tax AFC included in book depreciation 4 860 4 403 4 518 Use of the flow-through method for depreciation in prior years 4 651 7 004 5 884 Effect of tax rate changes for plant-related items (5 715) (4 648) (5 202) Dividends paid on ESOP shares (2 983) (3 009) (3 245) Other---net (69) (1 606) (1 311) Total income tax expense from operations $133 266 $130 740 $86 176 Effective income tax rate 35.4% 38.2% 34.9% Income taxes are comprised of the following expense (benefit) items: Included in utility operating expenses: Current federal tax expense $108 652 $92 099 $69 198 Current state tax expense 34 823 25 787 18 535 Deferred federal tax expense (3 450) 15 010 8 518 Deferred state tax expense (1 606) 4 431 2 533 Deferred investment tax credits (9 191) (8 981) (8 115) Total 129 228 128 346 90 669 Included in other income and expense: Current federal tax expense 3 959 7 853 1 490 Current state tax expense 923 2 289 613 Current foreign tax expense 219 Current federal tax credits (3 548) (321) (400) Deferred federal tax expense (835) (6 736) (4 518) Deferred state tax expense (209) (449) (1 347) Deferred foreign tax expense 3 839 Deferred investment tax credits (310) (242) (331) Total 4 038 2 394 (4 493) Total income tax expense from operations $133 266 $130 740 $86 176
Income before income taxes includes foreign income of $29.7 million in 1994. NSP's management intends to reinvest the earnings of foreign operations indefinitely. Accordingly, U.S. income taxes and foreign withholding taxes have not been provided on the earnings of foreign subsidiary companies. The cumulative amount of undistributed pre-tax earnings of foreign subsidiaries upon which no U.S. income taxes or foreign withholding taxes have been provided is approximately $30.8 million at Dec. 31, 1994. The additional U.S. income tax and foreign withholding tax on the unremitted foreign earnings, if repatriated, would be offset in whole or in part by foreign tax credits. Thus, it is impracticable to estimate the amount of tax that might be payable. The components of NSP's net deferred tax liability at Dec. 31 were:
(Thousands of dollars) 1994 1993 Deferred tax liabilities: Differences between book and tax bases of property $824 332 $792 542 Regulatory assets 144 605 128 991 Tax benefit transfer leases 76 775 87 924 Other 7 854 7 050 Total deferred tax liabilities $1 053 566 $1 016 507 Deferred tax assets: Regulatory liabilities $81 280 $95 504 Deferred investment tax credits 65 812 73 648 Deferred compensation, vacation and other accrued liabilities not currently deductible 50 572 62 811 Other 18 110 11 341 Total deferred tax assets $215 774 $243 304 Net deferred tax liability $837 792 $773 203
12. Regulatory Assets and Liabilities The following summarizes the individual components of unamortized regulatory assets and liabilities shown on the Consolidated Balance Sheets at Dec. 31:
Amortization (Thousands of dollars) Period 1994 1993 AFC recorded in plant on a net-of-tax basis* Plant Lives $155 102 $165 915 Conservation and energy management programs* Up to 10 Years 76 902 46 939 Losses on reacquired debt Term of New Debt 52 514 48 529 Environmental costs Up to 15 Years 47 779 45 568 Deferred postretirement benefit costs 3-15 Years 9 930 15 514 Unrecovered purchased gas costs 1-2 Years 7 601 3 216 State commission accounting adjustments* Plant Lives 5 544 6 246 Other Various 2 204 2 427 Total regulatory assets $357 576 $334 354 Excess deferred income taxes collected from customers $75 277 $113 276 Investment tax credit deferrals 110 831 120 123 Pension costs 11 054 6 969 Unrealized gains from decommissioning investments 1 412 Fuel refunds and other 1 943 3 512 Total regulatory liabilities $200 517 $243 880 * Earns a return on investment in the ratemaking process.
13. Financial Instruments The estimated Dec. 31 fair values of NSP's recorded financial instruments are as follows:
1994 1993 Carrying Fair Carrying Fair (Thousands of dollars) Amount Value Amount Value Cash, cash equivalents and short-term investments $41 947 $41 947 $57 838 $57 838 Long-term decommissioning investments $145 467 $145 467 $101 378 $110 130 Long-term debt, including current portion $1 621 060 $1 540 595 $1 524 085 $1 584 435
For cash, cash equivalents and short-term investments, the carrying amount approximates fair value because of the short maturity of those instruments. The fair values of the Company's long-term investments in an external nuclear decommissioning fund are estimated based on quoted market prices for those or similar investments. As discussed in Note 3, NSP adopted in 1994 SFAS No. 115, which required certain debt and equity securities to be recorded at their market value. NSP began recording decommissioning fund investments at their market value at that time. The fair value of NSP's long- term debt is estimated based on the quoted market prices for the same or similar issues, or the current rates offered to NSP for debt of the same remaining maturities. NRG has entered into three forward foreign currency exchange contracts with a counterparty to hedge exposure to currency fluctuations to the extent permissible by hedge accounting requirements. Pursuant to these contracts, transactions have been executed that are designed to protect the economic value in U.S. dollars of NRG's equity investments, denominated in Australian dollars and German deutsche marks (DM). NRG's forward foreign currency exchange contracts, in the notional amount of $93 million, hedge approximately $94 million of foreign currency denominated investments at Dec. 31, 1994. These forward foreign currency exchange contracts are not reflected on NSP's balance sheet. The contracts do require compensating balances of $7 million, which are reflected as other current assets on NSP's balance sheet. The contracts terminate in 2004 and require foreign currency interest payments by either party during each year of the contract. If the contracts had been terminated at Dec. 31, 1994, $4.3 million would have been payable by NRG for currency exchange rate changes to date. Management believes NRG's exposure to credit risk due to non-performance by the counterparty to its forward exchange contracts is not significant, based on the investment grade rating of the counterparty. Cenergy has entered into natural gas futures contracts in the notional amount of $16.1 million at Dec. 31, 1994. The contract terms range from one month to three years. The contracts are intended to mitigate risk from fluctuations in the price of natural gas that will be required to satisfy sales commitments for future deliveries to customers in excess of Cenergy's natural gas reserves. Cenergy's futures contracts hedge the sale of $16.6 million of natural gas. These futures contracts are not reflected on NSP's balance sheet. Margin balances of $3.4 million at Dec. 31, 1994, were maintained on deposit with brokers and recorded as cash and cash equivalents on NSP's balance sheet. The counterparties to the futures contracts are the New York Mercantile Exchange and major gas pipeline operators. Management believes that the risk of non-performance by these counterparties is not significant. If the contracts had been terminated at Dec. 31, 1994, $1.7 million would have been payable by Cenergy for natural gas price fluctuations to date. NSP has three interest rate swap agreements with notional amounts totalling $320 million. These swaps were entered into in conjunction with first mortgage bonds. As summarized below, these agreements effectively convert the interest costs of these debt issues from fixed to variable rates based on six-month London Interbank Offered Rates (LIBOR), with the rates changing semiannually.
Net Effective Notional Amount Term of Interest Cost Series (millions of dollars) Swap Agreement at Dec. 31, 1994 5 7/8% Series due Oct. 1, 1997 $100 Maturity 5.69% 5 1/2% Series due Feb. 1, 1999 $200 Maturity 6.68% 7 1/4% Series due March 1, 2023 $ 20 March 1, 1998 7.43% Market risks associated with these agreements result from short-term interest rate fluctuations. Credit risk related to non-performance of the counterparties is not deemed significant, but would result in NSP terminating the swap transaction and recognizing a gain or loss, depending on the fair market value of the swap. Such agreements are not reflected on NSP's balance sheets. The interest rate swaps serve to hedge the interest rate risk associated with fixed rate debt in a declining interest rate environment. This hedge is produced by the tendency for changes in the fair market value of the swap to be offset by changes in the present value of the liability attributable to the fixed rate debt issued in conjunction with the interest rate swaps. If the interest rate swaps had been discontinued on Dec. 31, 1994, the present value of NSP's additional obligation would have been $26 million, which is offset by a reduction in the present value of the related debt of $27.5 million below carrying value. 14. Detail of Certain Income and Expense Items Administrative and general (A&G) expense for utility operations consists of the following:
(Thousands of dollars) 1994 1993 1992 A&G salaries and wages $49 726 $51 601 $48 608 Postretirement medical and injury compensation benefits 41 901 14 995 13 776 Other benefits---all utility employees 38 792 51 860 54 410 Information technology, facilities and administrative support 29 751 30 504 35 139 Insurance and claims 16 771 16 165 18 092 Other 16 877 17 410 17 950 Total $193 818 $182 535 $187 975 Other income and deductions---net consist of the following: (Thousands of dollars) 1994 1993 1992 Non-regulated operations: Operating revenues and sales $242 019 $90 654 $62 616 Operating expenses 241 479* 81 403 65 744* Pretax operating income (loss) 540 9 251 (3 128) Interest and investment income 10 839 4 522 3 452 Gain on cogeneration contract termination 9 685 Charitable contributions (5 037) (4 752) (4 585) Environmental and regulatory contingencies (4 568) (100) (1 300) Other---net (excluding income taxes) (5 460) (939) (2 355) Income tax related to all non-operating items---(expense) benefit (4 038) (2 394) 4 493 Total $ 1 961 $ 5 588 $(3 423)
*Includes non-regulated energy project write-downs of $5.0 million in 1994 and $6.8 million in 1992. 15. Joint Plant Ownership The Company is a participant in a jointly owned 855-megawatt coal-fired electric generating unit, Sherburne County generating station unit No. 3 (Sherco 3), which began commercial operation Nov. 1, 1987. Undivided interests in Sherco 3 have been financed and are owned by the Company (59 percent) and Southern Minnesota Municipal Power Agency (41 percent). The Company is the operating agent under the joint ownership agreement. The Company's share of related expenses for Sherco 3 since commercial operations began are included in Utility Operating Expenses. The Company's share of the gross cost recorded in Utility Plant at Dec. 31, 1994 and 1993, was $585,783,000 and $584,822,000, respectively. The corresponding accumulated provisions for depreciation were $132,092,000 and $114,251,000. 16. Nuclear Obligations Fuel Disposal - NSP is responsible for the temporary storage of used nuclear fuel from the Company's nuclear generating plants. Under a contract with the Company, the DOE is obligated to assume the responsibility for permanent storage or disposal of NSP's used nuclear fuel. The Company has been funding its portion of the DOE's permanent disposal program since 1981. Funding took place through an internal sinking fund until 1983, when the DOE began assessing fuel disposal fees under the Nuclear Waste Policy Act of 1982 based on 0.1 cent per kilowatt-hour sold to customers from nuclear generation. The cumulative amount of such assessments from the DOE to NSP through Dec. 31, 1994, is $218.5 million. Currently, it is not determinable if the amount and method of the DOE's assessments to all utilities will be sufficient to fully fund the DOE's permanent storage or disposal facility. The DOE has stated in statute and by contract that a storage or permanent disposal facility would be ready to accept used nuclear fuel by 1998. Accordingly, NSP has been, with regulatory and legislative approval, providing its own temporary on-site storage facilities at its Monticello and Prairie Island plants, with a capacity sufficient for used fuel from the plants until at least that date. However, indications from the DOE are that a permanent federal facility will not be ready to accept used fuel from utilities until approximately 2010. Accordingly, NSP is investigating all of its alternatives for used fuel storage until the DOE facility is available. When on-site temporary storage at NSP's nuclear plants reaches approved capacity, the Company could seek interim storage at a contracted private facility. The Company received Minnesota legislative approval in 1994 for additional on-site storage facilities at its Prairie Island plant, provided the Company satisfies certain responsibilities. Seventeen dry cask containers, each of which can store approximately one-half year's used fuel, can become available as follows: five immediately in 1994; four more in 1996 if an application for an alternative storage site is filed, an effort to locate such a site is made and 100 megawatts (MW) of wind generation is available or contracted for construction; and the final eight in 1999 unless the specified alternative site is not operational or under construction, certain resource commitments are not met, or the Minnesota Legislature revokes its approval. (See additional discussion of legislative commitments in Note 17.) With the dry cask storage facilities approved in 1994 for the Prairie Island nuclear generating plant, the Company believes it has adequate storage capacity to continue operation of its nuclear plants until at least 2002 and 2003 for Prairie Island Units 1 and 2, respectively, and 2008 for Monticello. Storage availability for operation beyond these dates is not assured at this time. Fuel expense includes DOE fuel disposal assessments of $10.6 million, $8.7 million and $6.8 million for 1994, 1993 and 1992, respectively. Disposal expenses reflect reductions of $0.7 million in 1994, $2.6 million in 1993 and $3.7 million in 1992 due to a change in the DOE's basis of charging customers, retroactive to 1983. Nuclear fuel expenses in 1994 and 1993 also include about $5 million and $1 million, respectively, for payments to the DOE for the decommissioning and decontamination of the DOE's uranium enrichment facilities. The DOE's initial assessment of $46 million to the Company was recorded in 1993. This assessment will be payable in annual installments from 1993-2008 and will be expensed on a monthly basis in the 12 months following each payment. The most recent installment paid in 1994 was $3.9 million; future installments are subject to inflation adjustments under DOE rules. The FERC has approved wholesale ratemaking recovery of these assessments as paid through the cost-of-energy adjustment clause. Since the Company's retail regulators currently conform to the FERC's cost-of-energy adjustment clause procedures, the Company also expects recovery of these DOE assessments in retail ratemaking as payments are made each year. Plant Decommissioning - Decommissioning of all Company nuclear facilities is planned for the years 2010-2022, using the prompt dismantlement method. The Company is following industry practice by ratably accruing the costs for decommissioning over the approved cost recovery period and including the accruals in Utility Plant---Accumulated Depreciation, as discussed in Note 1. The Financial Accounting Standards Board is reviewing the accounting and reporting guidelines for decommissioning cost accruals. Until such guidelines require a different presentation, the Company plans to continue reporting plant decommissioning obligations as accumulated depreciation. Consequently, the total decommissioning cost obligation and corresponding asset currently are not recorded in NSP's financial statements. In addition, the Company cannot predict whether new guidelines, if issued, would increase or decrease decommissioning expenses or if the income statement presentation of such expenses would change. Consistent with cost recovery in utility customer rates, the Company records annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. Since the costs are expected to be paid in 2010-2022, funding presumes that current costs will escalate in the future at a rate of 4.5 percent per year. The total estimated decommissioning costs that will ultimately be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved plant recovery period. Under this approach, escalated future costs are discounted to current year dollars using the assumed rate of return on funding, which is currently 6 percent (net of tax) for external funding and approximately 8 percent (net of tax) for internal funding. The total obligation for decommissioning is currently expected to be funded approximately 82 percent by external funds and 18 percent by internal funds, as approved by the MPUC. Rate recovery of internal funding began in 1971 through depreciation rates for removal expense, and was changed to a sinking fund recovery in 1981. Contributions to the external fund started in 1990 and are expected to continue until plant decommissioning begins. Costs not funded by external trust contributions and related earnings will be funded through internally generated funds and issuance of Company debt or stock. The assets held in trusts as of Dec. 31, 1994, primarily consisted of investments in tax-exempt municipal bonds, common stock of public companies and U.S. government securities. The following table summarizes the funded status of the decommissioning obligation at Dec. 31, 1994: (Millions of dollars) Estimated future decommissioning costs (undiscounted) $1 838.1 Effect of discounting future payments 1 053.5 Present value of decommissioning obligation 784.6 External trust fund assets at fair value 145.5 Decommissioning obligation in excess of assets currently held in external trust $639.1 Decommissioning expenses recognized include the following components:
(Millions of dollars) 1994 1993 1992 Annual decommissioning cost accrual reported as depreciation expense: Externally funded $33.2 $28.4 $27.8 Internally funded (including interest costs) 1.1 14.5 11.9 Interest cost on externally funded decommissioning obligation 3.5 3.7 0.6 Earnings from external trust funds-net (3.5) (3.7) (0.6) Current year decommissioning accruals-net $34.3 $42.9 $39.7
At Dec. 31, 1994, the Company has recorded and recovered in rates cumulative decommissioning accruals of $340 million; $138 million has been deposited into external trust funds for such accruals. The Company believes future decommissioning cost accruals will continue to be recovered in customer rates. Decommissioning and interest accruals are included with the accumulated provision for depreciation on the balance sheet. Interest costs and trust earnings are reported in Other Income and Expense on the income statement. A revision to NSP's 1993 nuclear decommissioning study and nuclear plant depreciation capital recovery request was filed with the MPUC and approved in 1994. Although management expects to operate the Prairie Island units through the end of their licensed lives, the requested capital recovery would allow for the plant to be fully depreciated, including the accrual and recovery of decommissioning costs, about six years earlier than the end of its licensed life. The approved recovery period for Prairie Island has been reduced because of the uncertainty regarding used fuel storage, discussed previously. The updated nuclear decommissioning study supports a decrease in annual cost accruals for decommissioning as well as the shortened recovery period. The combined impact of the request as approved, including the shorter depreciation period and lower decommissioning costs, is a net decrease of about $800,000 in annual depreciation and decommissioning expenses. The revised cost levels approved by the MPUC were recorded in 1994. 17. Commitments and Contingent Liabilities Legislative Resource Commitments - In 1994, the Minnesota Legislature established several energy resource and other commitments for NSP to fulfill to obtain the Prairie Island temporary nuclear fuel storage facility approval, as discussed in Note 16. The additional resource commitments, which can be built, purchased or (in the case of biomass generation) converted, can be summarized as follows: Power Type Megawatts Deadline Wind 100* (Additional) 12/31/96 Wind 225 (Cumulative) 12/31/98 Biomass 50 (Additional) 12/31/98 Wind 200 (Additional) 12/31/02 Biomass 75 (Additional) 12/31/02 Wind 400** (Additional) 12/31/02 * In addition to 25 MW of wind generation currently installed. ** If required by least-cost planning and resource planning. Other commitments include applying for, locating and licensing an alternative used fuel storage site, a low-income discount for electric customers, additional required conservation improvement expenditures and various study and reporting requirements to a newly formed legislative electric energy task force. NSP has implemented programs to begin meeting these legislative commitments. Capital Commitments - NSP estimates utility capital expenditures, including acquisitions of nuclear fuel, will be $383 million in 1995 and $1.9 billion for 1995-1999. There also are contractual commitments for the disposal of used nuclear fuel. (See Note 16.) NRG is contractually committed to additional equity investments in an existing German energy project. Such commitments are for approximately DM 36 million in 1995 and DM 35 million in 1996. The 1995 and 1996 commitments would be approximately $23 million each year, based on exchange rates in effect at Dec. 31, 1994. Leases - Rentals under operating leases were approximately $24.0 million, $27.5 million and $25.1 million for 1994, 1993 and 1992, respectively. Fuel Contracts - NSP has long-term contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements. These contracts, which expire in various years between 1995 and 2013, require minimum contractual purchases and deliveries of fuel, and additional payments for the rights to purchase coal in the future. In total, NSP is committed to the minimum purchase of approximately $600 million of coal, $35 million of nuclear fuel and $377 million of natural gas, or to make payments in lieu thereof, under these contracts. In addition, NSP is required to pay additional amounts depending on actual quantities shipped under these agreements. As a result of FERC Order 636, NSP has been very active in developing a mix of gas supply contracts designed to meet its needs for retail gas sales. The contracts are with several suppliers and for various periods of time. Because NSP has other sources of fuel available, and because suppliers are expected to continue to provide reliable fuel supplies, risk of loss from non-performance under these contracts is not considered significant. In addition, NSP's risk of loss (in the form of increased costs) from market price changes in fuel is mitigated through the cost-of-energy adjustment provision of the ratemaking process, which provides for recovery of nearly all fuel costs. Power Agreements - The Company has executed several agreements with the Manitoba Hydro-Electric Board (MH) for hydroelectricity. A summary of the agreements is as follows: Years Megawatts Participation Power Purchase 1995-2005 500 Seasonal Participation Power Purchase 1995-1996 250 Seasonal Peaking Power Purchase 1995-1996 200 Seasonal Diversity Exchanges: Summer exchanges from MH 1995-2014 150 1997-2016 200 Winter exchanges to MH 1995-2014 150 1996-2015 200 2015-2017 400 2018 200 The cost of the 500-megawatt participation power purchase commitment is based on 80 percent of the costs of owning and operating the Company's Sherco 3 generating plant (adjusted to 1993 dollars). The total estimated future annual capacity costs for all MH agreements range from approximately $66 million to $69 million. Negotiations are under way regarding the interpretation of specific contractual factors relating to the annual cost of the 500-megawatt participation agreement. These commitments, which represent about 21 percent of MH's output capability in 1995, account for approximately 13 percent of the Company's 1995 system capability. The risk of loss from non- performance by MH is not considered significant, and the risk of loss from market price changes is mitigated through cost-of-energy rate adjustments. The Company and MH jointly have made commitments to provide additional transmission capacity to accomplish the seasonal diversity exchanges and to provide 200 MW of transmission capacity for United Power Association. The Company's agreements with MH call for the addition of facilities that will allow the Company's existing 500-kilovolt line from Winnipeg to the Twin Cities to accommodate the additional levels of transactions. The first two phases of construction, which provide the majority of the benefits to NSP, were completed in 1994. The final phase, which primarily benefits MH, is expected to be completed in May 1995. The Company has an agreement with Minnkota Power Cooperative (MPC) for the purchase of summer season capacity and energy. From 1995 through 2001, the Company will buy 150 MW of summer season capacity for $12.4 million annually. From 2002 through 2015, the Company will purchase 100 MW of capacity for $10.0 million annually. Under the agreement, energy will be priced against the cost of fuel consumed per megawatt-hour at the Coyote Generating Station in North Dakota. The Company also has three seasonal (summer) purchase power agreements with MPC, Minnesota Power and Iowa-Illinois Gas and Electric Company for the purchase of 331 MW in 1995 and 388 MW in 1996, including reserves. The annual cost of this capacity will be approximately $4 million. The Company has agreements with several non-regulated power producers to purchase electric capacity and associated energy. The total annual cost of current commitments for non-regulated installed capacity is approximately $20 million for 107 MW in 1995 and 119 MW in 1996. This annual cost will increase to approximately $37 million-$45 million for 1997-2018 and to approximately $25 million-$29 million for 2019-2027 due to a new power purchase agreement. Under this agreement, which was approved by the MPUC in February 1995, the Company will purchase an additional 245 to 262 MW of electric capacity and associated energy from 1997 through 2027. Nuclear Insurance - The Company's public liability for claims resulting from any nuclear incident is limited to $8.9 billion under the 1988 Price-Anderson amendment to the Atomic Energy Act of 1954. The Company has secured $200 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $8.7 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. The Company is subject to assessments of $79.3 million for each of its three licensed reactors to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $10 million per reactor during any one year. The Company purchases insurance for property damage and decontamination cleanup costs with coverage limits of $2.0 billion for each of the Company's two nuclear plant sites. The coverage consists of $500 million from American Nuclear Insurers/Mutual Atomic Energy Liability Underwriters (ANI/MAELU) and $1.5 billion from Nuclear Electric Insurance Limited (NEIL). As of Jan. 1, 1995, insurance with ANI/MAELU will change to Nuclear Mutual Limited. The coverage amounts will remain unchanged. NEIL provides insurance coverage for the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units and coverage for property losses in excess of $500 million occurring at nuclear stations. Premiums billed to NSP from NEIL are expensed as paid each year. All companies insured with NEIL are subject to retrospective premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that the Company would have no exposure in case of a single incident under the replacement power coverage and the property damage coverage. However, in each calendar year, the Company could be subject to maximum assessments of approximately $4.6 million (five times the amount of its annual premium) and $26.1 million (7.5 times the amount of its annual premium) if losses exceed accumulated reserve funds under the replacement power and property damage coverages, respectively. Environmental Contingencies - Other long-term liabilities include an accrual of $49 million at Dec. 31, 1994, for estimated costs associated with environmental remediation. Approximately $40 million of the liability relates to a DOE assessment for decommissioning of a federal uranium enrichment facility, as discussed in Note 16. Other estimates have been recorded for expected environmental costs associated with manufactured gas plant sites formerly used by the Company and other waste disposal sites, as discussed below. These environmental liabilities do not include accruals recorded (and collected from customers in rates) for future nuclear fuel disposal costs or decommissioning costs related to the Company's nuclear generating plants. (See Note 16 for further discussion.) NSP has not developed any specific site restoration and exit plans for its fossil fuel plants, hydroelectric plants or substation sites because the Company intends to operate at these sites indefinitely. If such plans were developed in the future, NSP would intend to treat restoration and exit costs as a removal cost of retirement in utility plant and include them in depreciation accruals. An estimated removal cost (based on historical experience) is currently included in depreciation expense. NSP has met or exceeded state and federal removal and disposal requirements for polychlorinated biphenyls (PCB) equipment. NSP has removed nearly all PCB capacitors, transformers and equipment from its distribution system and power plants. Minimal costs are expected to be incurred for future removal and disposal of PCB equipment. PCB-contaminated mineral oil is detoxified and reused or burned for energy recovery at a permitted facility, with minimal cost to NSP. Other than described below, any potential future cleanup or remediation costs for past PCB disposal is unknown at this time. The Environmental Protection Agency (EPA) or state environmental agencies have designated the Company as a "potentially responsible party" (PRP) for 10 waste disposal sites to which the Company allegedly sent hazardous materials. Under applicable law, the Company, along with each PRP, could be held jointly and severally liable for the total remediation costs of all 10 sites, which are currently estimated at $122 million. If additional remediation is necessary or unexpected costs are incurred, the amount could be in excess of $122 million. The Company is not aware of the other parties' inability to pay, nor does it know if responsibility for any of the sites is disputed by any party. The Company's share of the costs associated with these 10 sites is approximately $2.5 million. Of this amount, about $1.4 million has already been paid in connection with six of the 10 sites for which the Company has settled with the EPA and other PRPs. For the remaining four sites, neither the amount of remediation costs nor the final method of their allocation among all designated PRPs has been determined. However, the Company has recorded an estimate of approximately $1 million for future costs for all four sites, with the estimated payment dates not determinable at this time. While it is not feasible to determine the outcome of these matters, amounts accrued represent the best current estimate of the Company's future liability for the remediation costs of these sites. It is the Company's practice to vigorously pursue and, if necessary, litigate with insurers to recover incurred remediation costs whenever possible. Through litigation, the Company has recovered from other PRPs a portion of the remedial costs paid to date. Management believes costs incurred in connection with the sites, which are not recovered from insurance carriers or other parties, might be allowed recovery in future ratemaking. Until the Company is identified as a PRP, it is not possible for the Company to predict the timing or amount of any costs associated with cleanup sites other than those discussed above. The Wisconsin Company potentially may be involved in the cleanup and remediation at three sites. One site is a solid and hazardous waste landfill site in Eau Claire, Wis. The Wisconsin Company contends that it did not dispose of hazardous wastes in the subject landfill during the time period in question. Because neither the amount of cleanup costs nor the final method of their allocation among all designated PRPs has been determined, it is not feasible to predict the outcome of this matter at this time. The second site, in Ashland, Wis., contains creosote/coal tar contamination. The Wisconsin Company is discussing its potential involvement with the Wisconsin Department of Natural Resources. Investigations are under way to determine the Wisconsin Company's responsibility as well as that of predecessor companies contributing to the contamination. The investigation should also determine the extent and source of the contamination and potential methods for remediation. An estimate of cleanup and remediation costs at these two sites and the extent of the Wisconsin Company's responsibility, if any, for sharing such costs are not known at this time. The third site is a landfill site in Hudson, Wis. which is one of the 10 waste disposal sites discussed previously. The Company also is continuing to investigate 15 properties, either presently or previously owned by the Company, which were at one time sites of gas manufacturing, gas storage plants or gas pipelines. The purpose of this investigation is to determine if waste materials are present, if such materials constitute an environmental or health risk, if the Company has any responsibility for remedial action and if recovery under the Company's insurance policies can contribute to any remediation costs. Of the 15 gas sites under investigation, the Company already has remediated one site and is actively taking remedial action at four of the sites. In addition, the Company has been notified that two other sites eventually will require remediation, and a study will be conducted to determine the cost of cleanup. The Company has paid $5.3 million to date on these seven active sites. The one remediated site continues to be monitored. The Company currently estimates its liability for the other six active sites to be approximately $8.4 million, with payment expected over the next 11 years. The estimate is based on prior experience and includes investigation, remediation and litigation costs. The possible range of the liability for these six sites could be from $8.4 million to approximately $12 million, depending on the extent of contamination. As for the other eight inactive sites, no liability has been recorded for remediation since at this time the sites require only monitoring. While it is not feasible to determine the precise outcome of all of these matters, the accruals recorded represent the current best estimate of the costs of any required cleanup or remedial actions at these former gas operating sites. Management also believes that costs incurred in connection with the sites, which are not recovered from insurance carriers or other parties, might be allowed recovery in future ratemaking. During 1994, the Company's gas utility received approval for deferred accounting for certain gas remediation costs incurred at four active sites, with final rate treatment of such costs to be determined in the next general gas rate case. The Clean Air Act, including the Amendments of 1990 (the Clean Air Act), imposes stringent limits on emissions of sulfur dioxide and nitrogen oxides by electric generating plants. These limits will be phased in beginning in 1995. The majority of the rules implementing this complex legislation have been finalized. No additional capital expenditures are anticipated to comply with the sulfur dioxide emission limits of the Clean Air Act. NSP has expended significant amounts over the years to reduce sulfur dioxide emissions at its plants. Based on revisions to the sulfur dioxide portion of the program, NSP's emission allowance allocations for the years 1995-1999 were dramatically reduced. The Company's capital expenditures include some costs for ensuring compliance with the Clean Air Act's other emission requirements; other expenditures may be necessary upon EPA's finalization of remaining rules. Because NSP is only beginning to implement some provisions of the Clean Air Act, its overall financial impact is unknown at this time. Capital expenditures will be required for opacity compliance commencing in 1995 at certain facilities, and such costs are considered in the capital expenditure commitments disclosed previously. NSP plans to seek recovery of these expenditures in future rate proceedings. Several of NSP's operating facilities have asbestos-containing material, which represents a potential health hazard to people who come in contact with it. Governmental regulations specify the required timing and nature of disposal of asbestos-containing materials. Under such requirements, asbestos not readily accessible to the environment need not be removed until the facilities containing the material are demolished. NSP estimates its future asbestos removal costs will approximate $43 million. Most of these costs will not need to be incurred until current operating facilities are demolished and will be included in the costs of removal for the facilities. Environmental liabilities are subject to considerable uncertainties that affect NSP's ability to estimate its share of the ultimate costs of remediation and pollution control efforts. Such uncertainties involve the nature and extent of site contamination, the extent of required cleanup efforts, varying costs of alternative cleanup methods and pollution control technologies, changes in environmental remediation and pollution control requirements, the potential effect of technological improvements, the number and financial strength of other potentially responsible parties at multi-party sites and the identification of new environmental cleanup sites. NSP has recorded and/or disclosed its best estimate of expected future environmental costs and obligations, as discussed previously. Legal Claims - In the normal course of business, NSP is a party to routine claims and litigation arising from prior and current operations. NSP is actively defending these matters and has recorded an estimate of the probable cost of settlement or other disposition. In July 1993, a natural gas explosion occurred on the Company's distribution system in St. Paul, Minn. Total damages are estimated to exceed $1 million. The Company has a self-insured retention deductible of $1 million, with general liability coverage of $150 million, which includes coverage for all injuries and damages. While 12 lawsuits have been filed, including one proposed class action, the litigation following this incident is in a preliminary stage, pending a report from the National Transportation Safety Board, and the ultimate costs to the Company are unknown at this time. 18. Segment Information
Year Ended Dec. 31 (Thousands of dollars) 1994 1993 1992 Utility operating income before income taxes Electric $399 185 $ 393 758 $ 321 837 Gas 38 361 38 474 24 848 Total operating income before income taxes $437 546 $ 432 232 $ 346 685 Utility depreciation and amortization Electric $252 322 $ 245 200 $ 225 134 Gas 21 479 19 317 17 780 Total depreciation and amortization $273 801 $ 264 517 $ 242 914 Capital expenditures Electric utility $303 896 $ 284 239 $ 367 522 Gas utility 60 183 36 312 42 850 Common utility and non-regulated businesses 45 207 41 144 17 443 Total capital expenditures $409 286 $ 361 695 $ 427 815 Identifiable assets Electric utility $4 634 511 $4 543 286 $4 421 151 Gas utility 556 975 521 595 428 192 Total identifiable assets 5 191 486 5 064 881 4 849 343 Other corporate assets 762 085 522 837 293 118 Total assets $5 953 571 $5 587 718 $5 142 461
19. Summarized Quarterly Financial Data (Unaudited)
Quarter Ended (Thousands of dollars) March 31, 1994 June 30, 1994 Sept. 30, 1994 Dec. 31, 1994 Utility operating revenues $683 462 $581 963 $612 328 $608 794 Utility operating income 85 795 65 526 88 932 68 065* Net income 65 794 52 808 76 065 48 808* Earnings available for common stock 62 737 49 751 72 968 45 655* Earnings per common share $.94 $.74 $1.09 $.68* Dividends declared per common share $.645 $.660 $.660 $.660 Stock prices---high $43 7/8 $43 5/8 $43 7/8 $47 ---low $40 1/8 $38 3/4 $40 3/8 $41 7/8 Quarter Ended (Thousands of dollars) March 31, 1993 June 30, 1993 Sept. 30, 1993 Dec. 31, 1993 Utility operating revenues $640 753 $545 263 $601 924 $616 052 Utility operating income 81 046 59 547 90 076 73 217 Net income 54 481 35 892 67 655 53 712 Earnings available for common stock 50 679 32 149 63 912 50 420 Earnings per common share $.81 $.50 $.96 $.75 Dividends declared per common share $.630 $.645 $.645 $.645 Stock prices---high $47 $46 7/8 $47 7/8 $46 3/8 ---low $42 1/4 $42 7/8 $44 3/4 $40 1/8
* Net of expense recognized of $8.7 million ($5.1 million net of tax), or 8 cents per share, to write off the unamortized deferred costs associated with adopting SFAS No. 112 (See Note 3). Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure During 1994 there were no disagreements with the Company's independent public accountants on accounting procedures or accounting and financial disclosures. As discussed in the Company's Form 8-K filed Dec. 16, 1994, on Dec. 14, 1994 the Company's Board of Directors approved the appointment of the accounting firm of Price Waterhouse LLP as independent accountants for the Registrants beginning in fiscal year 1995, subject to ratification by the shareholders. PART III Item 10. Directors and Executive Officers of the Registrant (a) CLASS III -- Nominees for Terms Expiring in 1998 H. Lyman Bretting President and Chief Executive Officer, C.G. Bretting Age 58 Manufacturing Company, Inc., Ashland, Wisconsin, a Director Since 1990 manufacturer of napkin and paper towel folding machines. Member of Finance Also director of M&I National Bank of Ashland and and Power Supply Northern States Power Company (Wisconsin), Committees a wholly-owned subsidiary of the Company. David A. Christensen President and Chief Executive Officer, Raven Age 60 Industries, Inc., Sioux Falls, South Dakota, a Director Since 1976 manufacturer of reinforced plastics, electronic Member of Corporate equipment and sewn products. Also director of Norwest Management and Power Bank South Dakota, N.A., Norwest Corporation and Raven Supply Committees Industries, Inc. Allen F. Jacobson Retired effective November 1, 1991 as Chairman and Age 68 Chief Executive Officer, Minnesota Mining and Director Since 1983 Manufacturing Company (3M). Also director of Abbot Member of Corporate Laboratories, Deluxe Corporation, Minnesota Mining Management and and Manufacturing Company, Mobil Corporation, Power Supply Potlatch Corporation, Prudential Insurance Company Committees of America, Sara Lee Corporation, Silicon Graphics, Inc., U.S. West, Inc., and Valmont Industries, Inc. Margaret R. Preska Distinguished Service Professor, Minnesota State Age 57 Universities, since February 1, 1992. Prior thereto, Director Since 1980 President, Mankato State University, Mankato, Member of Corporate Minnesota, an educational institution. Also director Management and Power of Norwest Bank Minnesota South Central, N.A. Supply Committees CLASS I -- Directors Whose Terms Expire In 1996 W. John Driscoll Retired effective June 30, 1994 as Chairman of the Age 65 Board, Rock Island Company, St. Paul, Minnesota, a Director Since 1974 private investment company, in which capacity he had Member of Audit and served since May 15, 1993. Prior thereto, President. Corporate Management Also director of Comshare Inc., The John Nuveen Committees Company, MIP Properties, Inc., The St. Paul Companies, Inc. and Weyerhaeuser Company. Dale L. Haakenstad Retired effective December 31, 1989 as President and Age 67 Chief Executive Officer, Western States Life Insurance Director Since 1978 Company, Fargo, North Dakota. Member of Audit and Power Supply Committees James J. Howard Chairman, President and Chief Executive Officer of the Age 59 Company since December 1, 1994. Prior thereto, Director Since 1987 Chairman of the Board and Chief Executive Officer of Ex-officio member the Company since July 1, 1990. Also director of Ecolab of all Committees Inc., Honeywell Inc., ReliaStar Financial Corp. and Walgreen Company. John E. Pearson Retired effective January 31, 1992 as Chairman, The Age 68 NWNL Companies, Inc. and Northwestern National Life Director Since 1983 Insurance Company, a wholly-owned subsidiary of The Member of Corporate NWNL Companies, Inc. in which capacity he had served Management and since July 1, 1991. Prior thereto, Chairman and Chief Finance Committees Executive Officer, The NWNL Companies, Inc., and Northwestern National Life Insurance Company. Also director of Norwest Corporation. G. M. Pieschel Chairman of the Board, Farmers and Merchants State Age 67 Bank, Springfield, Minnesota, a commercial bank, since Director Since 1978 January 14, 1993. Prior thereto, Chief Executive Member of Audit and Officer and President of Farmers and Merchants State Finance Committees Bank. CLASS II -- Directors Whose Terms Expire in 1997 Richard M. Kovacevich President and Chief Executive Officer, Norwest Age 51 Corporation, Minneapolis, Minnesota, a holding company Director Since 1990 for banking institutions, since January 1, 1993. Prior Member of Finance thereto, President and Chief Operating Officer. Also Power Supply director of Fingerhut Companies, Inc., Northwestern Committees National Life Insurance Company, Norwest Corporation and ReliaStar Financial Corp. Douglas W. Leatherdale Chairman of the Board, President and Chief Executive Age 58 Officer, The St. Paul Companies, Inc., a worldwide Director Since 1991 property and liability insurance organization, since Member of Audit and May 1, 1990. Also director of The John Nuveen Company Corporate Management and United HealthCare Corporation. Committees A. Patricia Sampson Consultant, Dr. Sanders and Associates, a management Age 46 and diversity consulting company, since January 1, Director Since 1985 1995. Prior thereto, Chief Executive Officer, until Member of Audit and December 31, 1994 and Executive Director, until June Finance Committees 1, 1993, Greater Minneapolis Area Chapter of the American Red Cross. Edwin M. Theisen Retired effective November 30, 1994 as President and Age 64 Chief Operating Officer of the Company. Also director Director Since 1990 of Firstar Bank of Minnesota, N.A. Member of Finance and Power Supply Committees (b) Reference is made to "Executive Officers" as of March 1, 1995, in Part I. (c) The information called for with respect to the identification of certain significant employees is not applicableto the registrant. (d) There are no family relationships between the directors and executive officers listed above. There are no arrangements nor understandings between any named officer and any other person pursuant to which such person was selected as an officer. (e) Each of the officers named in Part I was elected to serve in the office indicated until the meeting of the Board of Directors preceding the Annual Meeting of Shareholders in 1995 and until his or her successor is elected and qualified. (f) There are no legal proceedings involving directors, nominees for directors, or officers. Compliance with Section 16(a) of the Exchange Act The Securities Exchange Act of 1934 requires all executive officers and directors to report any changes in the ownership of common stock of the Company to the Securities and Exchange Commission, The New York Stock Exchange and the Company. Based solely upon a review of these report and written representations that no additional reports were required to be filed in 1994, the Company believes that all reports were filed on a timely basis. Item 11. Executive Compensation COMPENSATION OF EXECUTIVE OFFICERS The following table sets forth cash and noncash compensation for each of the last three fiscal years ended December 31, 1994, for services in all capacities to the Company and its subsidiaries, to the Chief Executive Officer, the next four highest compensated executive officers of the Company who were serving as executives at December 31, 1994, and one former executive officer who would have been one of the four most highly compensated officers of the Company during 1994 had he not resigned from the Company before the end of the year. SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION AWARDS PAYOUTS (a) (b) (c) (d) (e) (f) (g) (h) (i) NUMBER OF OTHER RESTRICTED SECURITIES ALL OTHER ANNUAL STOCK UNDERLYING LTIP COMPEN- COMPENSATION AWARDS OPTIONS PAYOUTS SATION NAME AND PRINCIPAL POSITION YEAR SALARY($) BONUS($)(4) ($)(5) ($)(6) AND SARS(#)($)(7) ($)(8) JAMES J. HOWARD 1994 511,300 317,800 3,504 240,311 15,150 0 9,056 Chairman, President & 1993 511,300 231,931 0 129,075 12,782 23,925 11,324 Chief Executive Officer 1992 485,000 0 2,934 0 13,541 0 44,052 EDWARD J. MCINTYRE 1994 205,600 102,700 2,465 61,680 5,117 0 6,438 Vice President & Chief 1993 205,600 71,395 7,339 35,595 4,508 7,461 5,081 Financial Officer 1992 199,000 0 5,037 0 4,753 0 27,981 GARY R. JOHNSON 1994 183,600 81,700 9,945 55,080 4,570 0 3,672 Vice President, General 1993 183,600 53,424 1,315 28,380 3,648 4,525 5,831 Counsel and 1992 168,450 0 6,005 0 3,889 0 6,922 Corporate Secretary LOREN L. TAYLOR(1) 1994 174,583 55,000 1,046 40,942 3,455 0 3,166 President, NSP Electric 1993 171,500 32,347 1,202 18,290 2,737 2,728 5,685 1992 152,750 0 5,361 0 2,669 0 6,609 DOUGLAS D. ANTONY(2) 1994 163,893 75,100 1,025 41,837 2,942 0 4,419 President, NSP Generation 1993 146,300 61,329 6,517 17,210 2,493 2,087 3,490 1992 103,344 0 5,097 0 1,168 0 1,982 EDWIN M. THEISEN(3) 1994 297,367 283,516 10,681 0 8,843 0 7,775 Former President & 1993 324,400 129,452 1,271 65,620 7,240 10,650 6,267 Chief Operating Officer 1992 306,500 0 6,870 0 7,606 0 55,324
(1) Mr. Taylor was elected President, NSP Electric on October 27, 1994 after having served as a vice president in various areas of the Company since 1989. (2) Mr. Antony was elected President, NSP Generation effective September 7, 1994 after having served as Vice President - Nuclear Generation since January 1993. Prior thereto, Mr. Antony was not an executive officer. (3) Mr. Theisen retired as President & Chief Operating Officer of the Company on November 30, 1994. (4) This column consists of awards made to each named executive under the Company's Executive Incentive Plan. Due to Mr. Theisen's retirement during 1994, he additionally received the cash equivalent of the restricted stock award for 1994 in accordance with the Company's LTIP, in the amount of $126,516. (5) This column consists of reimbursements for taxes on certain personal benefits received by the named executives. (6) Amounts shown in this column reflect the market value of the shares of restricted stock awarded under the LTIP, except with respect to Mr. Antony's additional award (discussed below) and are based on the closing price of the Company's common stock on the date that the awards were made. Restricted shares earned for 1994 under the Company's LTIP were granted on January 25, 1995 based on the performance period ending September 30, 1994. As of December 31, 1994, the named executives held the following as a result of grants under the LTIP: Mr. Howard held 3,097 restricted shares at a market value of $136,268; Mr. McIntyre held 854 restricted shares at a market value of $37,576; Mr. Antony held 413 restricted shares at a market value of $18,172; Mr. Taylor held 454 restricted shares at a market value of $19,976, Mr. Johnson held 680 restricted shares at a market value of $29,957 and Mr. Theisen held 0 restricted shares at a market value of $0. The restricted stock awards vest one year after the date of grant with respect to fifty (50%) of the shares and two years after such date with respect to the remaining shares, conditioned upon the continued employment of the recipient with the Company. Non-preferential dividends are paid on the restricted shares. Mr. Antony received an additional 2,200 shares of restricted stock during 1994, which as of December 31, 1994, had a market value of $96,800. These additional shares vest with respect to 50% of the shares if Mr. Antony has been continually employed by the Company on October 26, 1996 and with respect to the remainder of the shares if he has been continually employed with the Company on October 26, 1998. The total number of restricted shares awarded during the years 1992, 1993 and 1994 are as follows: 7,191 shares for Mr. Howard, 1,910 shares for Mr. McIntyre, 2,594 shares for Mr. Antony, 982 shares for Mr. Taylor, 1,473 shares for Mr. Johnson and 3,671 for Mr. Theisen. (7) The Company had no LTIP payouts in 1994 due to the replacement, by the Corporate Management Committee of the Company's Board of Directors, of dividend equivalent stock appreciation rights (DESARs) formerly awarded under the Company's LTIP, in favor of increased stock options and restricted stock levels. (8) This column consists of the following: $4,031 was contributed by the Company for the Employee Stock Ownership Plan (ESOP) for Messrs. Howard and Theisen, respectively, $3,807 for Mr. McIntyre, $2,297 for Messrs. Johnson and Taylor, respectively, and $2,642 for Mr. Antony; (The Company contribution on behalf of all ESOP participants, including the named executive officers, was equal to 1.3% of their covered compensation.); the value to each named executive of the remainder of insurance premiums paid under the Officer Survivor Benefit Plan by the Company: $2,320 for Mr. Howard, $227 for Mr. McIntyre, $476 for Mr. Johnson, $0 for Mr. Taylor, $837 for Mr. Antony and $1,418 for Mr. Theisen; imputed income as a result of life insurance paid by the Company on behalf of each named executive: $2,205 for Mr. Howard, $341 for Mr. McIntyre, $399 for Mr. Johnson, $369 for Mr. Taylor, $440 for Mr. Antony and $1,826 for Mr. Theisen; Company matching 401(k) plan contribution of $500 to each named executive; and, earnings accrued under the Company Deferred Compensation Plan to the extent such earnings exceeded the market rate of interest (as prescribed pursuant to the SEC rules), which was $1,563 for Mr. McIntyre and $0 for all other named executives. OPTIONS AND STOCK APPRECIATION RIGHTS (SARs) The following table indicates for each of the named executives (i) the extent to which the Company used stock options and SARs for executive compensation purposes in 1994 and (ii) the potential value of such options and SARs as determined pursuant to the SEC rules. OPTIONS AND SARS GRANTED IN 1994
POTENTIAL REALIZABLE VALUE AT ASSUMED ANNUAL RATES OF STOCK PRICE APPRECIATION INDIVIDUAL GRANTS FOR OPTION TERM (a) (b) (c) (d) (e) (f) (g) % OF TOTAL OPTIONS AND OPTIONS/ SARS EXERCISE SARS GRANTED TO OR BASE GRANTED(1) EMPLOYEES PRICE EXPIRATION NAME (#) IN 1994 ($/SH) DATE 5%($)(3) 10%($)(3) J. Howard 15,150 options 4.9% 42.187 1-26-04 401,952 1,018,626 E. McIntyre 5,117 options 1.7% 42.187 1-26-04 135,762 344,047 G. Johnson 4,570 options 1.5% 42.187 1-26-04 121,249 307,269 L. Taylor 3,455 options 1.1% 42.187 1-26-04 91,666 232,300 D. Antony 2,942 options 1.0% 42.187 1-26-04 78,056 197,808 E. Theisen 8,843 options 2.9% 42.187 1-26-04 234,618 594,568 All Shareholders(2) N/A N/A N/A N/A 1,774,775,230 4,497,470,638
(1) Options were granted on January 26, 1994 and vested on January 26, 1995. No SARs were awarded for 1994. (2) Potential realizable values during the ten year period commencing January 26, 1994, are based on the market price ($42.187) and the outstanding shares (66,893,377) of common stock of the Company on that date. (3) The hypothetical potential appreciation shown in columns (f) and (g) for the named executives is required by the SEC rules. The amounts in these columns do not represent either the historical or anticipated future performance of the Company's common stock level of appreciation. The following table indicates for each of the named executives the number and value of exercisable and unexercisable options and SARs as of December 31, 1994. AGGREGATED OPTION AND SAR EXERCISES IN 1994 AND FY-END OPTION/SAR VALUE
(a) (b) (c) (d) (e) NUMBER OF UNEXERCISED VALUE OF UNEXERCISED IN-THE-MONEY SHARES OPTIONS AND SARS AT 12/31/94 OPTIONS AND SARS AT ACQUIRED ON REALIZED (#) -- EXERCISABLE (EX)/ 12/31/94 ($) -- EXERCISABLE (EX)/ NAME EXERCISE(#) VALUE($) UNEXERCISABLE (UNEX) UNEXERCISABLE (UNEX)* J. Howard N/A N/A 52,423 (ex) 291,519 (ex) 15,150 (unex) 27,459 (unex) E. McIntyre N/A N/A 17,401 (ex) 94,769 (ex) 5,117 (unex) 9,274 (unex) G. Johnson N/A N/A 10,559 (ex) 36,588 (ex) 4,570 (unex) 8,281 (unex) L. Taylor N/A N/A 7,673 (ex) 26,687 (ex) 3,455 (unex) 6,262 (unex) D. Antony N/A N/A 5,938 (ex) 26,196 (ex) 2,942 (unex) 5,332 (unex) E. Theisen 66 3,005 25,529 (ex) 139,385 (ex) 8,843 (unex) 16,023 (unex)
* Share price on December 30, 1994 was $44. Company common stock was not traded on December 31, 1994. PENSION PLAN TABLE The following table illustrates the approximate retirement benefits payable to employees retiring at the normal retirement age of 65 years:
ESTIMATED ANNUAL BENEFITS FOR YEARS OF SERVICE INDICATED AVERAGE COMPENSATION YEARS OF SERVICE (4 YEARS) 5 10 15 20 25 30 $ 50,000 $ 3,500 $ 7,000 $ 10,500 $ 14,500 $ 18,000 $ 21,500 100,000 7,500 15,500 23,000 30,500 38,500 46,000 150,000 11,500 23,500 35,000 47,000 58,500 70,500 200,000 16,000 31,500 47,500 63,500 79,000 95,000 250,000 20,000 40,000 59,500 79,500 99,500 119,500 300,000 24,000 48,000 72,000 96,000 120,000 144,000 350,000 28,000 56,000 84,000 112,500 140,500 168,500 400,000 32,000 64,500 96,500 128,500 161,000 193,000 450,000 36,000 72,500 108,500 145,000 181,000 217,500 500,000 40,500 80,500 121,000 161,500 201,500 242,000 550,000 44,500 89,000 133,000 177,500 222,000 266,500 600,000 48,500 97,000 145,500 194,000 242,500 291,000 650,000 52,500 105,000 157,500 210,500 263,000 315,500 700,000 56,500 113,500 170,000 226,500 283,500 340,000 750,000 60,500 121,500 182,000 243,000 303,500 364,500 800,000 65,000 129,500 194,500 259,500 324,000 389,000 850,000 69,000 138,000 206,500 275,500 344,500 413,500 900,000 73,000 146,000 219,000 292,000 365,000 438,000 950,000 77,000 154,000 231,000 308,500 385,500 462,500
After an employee has reached 30 years of service, no additional years are used in determining pension benefits. The annual compensation used to calculate the average compensation shown in this table is based on the participant's base salary for the year (as shown on the Summary Compensation Table at column (c)) and bonus compensation paid in that same year (as shown on the Summary Compensation Table at column (d); see figure for prior year). The benefit amounts shown are amounts computed in the form of a straight-life annuity. The amounts are not subject to offset for social security or otherwise, except as provided in the employment agreement with Mr. Howard, as described below. At the end of 1994, each of the executive officers named in the Summary Compensation Table had the following credited service: Mr. Howard, 7.92 years, Mr. Antony, 25.5 years, Mr. Johnson, 16.08 years, Mr. McIntyre, 21.83 years, Mr. Taylor, 21.58 years and Mr. Theisen, 30 years. An employment agreement with Mr. Howard provides that if employment terminates prior to age 60, he will receive payments from the Company equivalent to benefits he would have earned under the Pension Plan without regard to service and compensation limitations in a minimum annual amount of $22,535. If employment continues past age 60, he and his spouse, if she survives him, will receive combined benefits from the Pension Plan and supplemental Company payments as though he had completed 30 years of service, less the pension benefits earned from a former employer. SEVERANCE PLAN The Company's Severance Plan covers the full-time regular-benefit, nonbargaining employees of the Company, including the named executives, and participating subsidiaries. The Severance Plan provides severance benefits to covered employees whose termination of employment is involuntary and unrelated to unsatisfactory performance. Subject to a maximum of 24 months of pay, a covered employee is eligible to receive monthly payments of two months of base pay plus the greater of two weeks of base pay for each year of service or one week of base pay for each $2,000 of base annual salary. Covered employees are also eligible to receive incentive pay, group insurance benefits and service and compensation credit under the Pension Plan for the period they receive monthly severance benefits. Outplacement services are also provided under the Plan. DIRECTOR COMPENSATION Directors not employed by the Company receive a $20,000 annual retainer, or a pro rata portion thereof if service is less than 12 months, and $1,200 for attendance at each Board meeting and $1,000 for each Committee meeting attended. A $2,500 annual retainer is paid to each elected Committee Chairperson. Employees of the Company receive no separate compensation for services as a director. In addition, directors have a deferred compensation and retirement plan in which they can participate. The deferred compensation plan provides for deferral of the director fees until after retirement from the Board of Directors. The retirement plan continues payment of the director's retainer, at the rate in effect for the calendar quarter immediately preceding the director's retirement multiplied by 1.2. Benefits continue for a period equal to the number of calendar quarters served on the Board, up to 40 calendar quarters. Item 12. Security Ownership of Certain Beneficial Owners and Management Security Ownership of Directors, Nominees and Named Executive Officers Set forth in the following table is the beneficial ownership of common stock of the Company as of March 15, 1995 for all directors and each of the named executive officers of the Company as defined in the rules of the Securities and Exchange Commission. As of March 15, 1995, the directors and executive officers as a group beneficially owned 85,286 shares, less than 0.14 percent, of the Company's common stock (including shares allocated to the accounts of executive officers in the Executive Long-Term Incentive Award Stock Plan (LTIP) and the Employee Stock Ownership Plan for which they have voting power but not investment power). H. Lyman Bretting 1,355 David A. Christensen 500 W. John Driscoll 2,000 Dale L. Haakenstad 682 James J. Howard* 25,875 Allen F. Jacobson 712 Richard M. Kovacevich 1,000 Douglas W. Leatherdale 300 John E. Pearson 1,353 G. M. Pieschel 683 Margaret R. Preska 600 A. Patricia Sampson 372 Douglas D. Antony* 6,721 Gary R. Johnson* 5,773 Edward J. McIntyre* 8,430 Loren L. Taylor* 4,893 Edwin M. Theisen* 13,098 *Shares shown for Messrs. Howard, McIntyre, Johnson, Taylor, Antony and Theisen do not include options to purchase common stock of the Company which are exercisable within 60 days under the Company's LTIP: 65,577 option shares for Mr. Howard, 21,881 option shares for Mr. McIntyre, 14,676 option shares for Mr. Johnson, 10,787 option shares for Mr. Taylor, 8,666 option shares for Mr. Antony and 34,372 option shares for Mr. Theisen. Item 13. Certain Relationships and Related Transactions Edwin M. Theisen, a director and former employee of the Company, is currently performing certain consulting services for the Company pursuant to a one-year agreement whereby he receives $15,000 per month in return for such services. PART IV Item 14 - Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) 1. Financial Statements Page Included in Part II of this report: Independent Auditors' Report. 44 Consolidated Statements of Income for the three years ended December 31, 1994. 45 Consolidated Statements of Cash Flows for the three years ended December 31, 1994. 46 Consolidated Balance Sheets, December 31, 1994 and 1993. 47 Consolidated Statements of Changes in Common Stockholders' Equity for the three years ended December 31, 1994 48 Consolidated Statements of Capitalization, December 31, 1994 and 1993. 49 Notes to Financial Statements. 51 (a) 2. Financial Statement Schedules Schedules are omitted because of the absence of the conditions under which they are required or because the information required is included in the financial statements or the notes. (a) 3. Exhibits * Indicates incorporation by reference 3.01* Restated Articles of Incorporation and Amendments, effective as of April 2, 1992. (Exhibit 3.01 to Form 10-Q for the quarter ended March 31, 1992, File No. 1-3034). 3.02* Bylaws of the Company as amended January 22, 1992. (Exhibit 3.02 to Form 10-K for the year 1991, File No. 1- 3034). 4.01* Trust Indenture, dated February 1, 1937, from the Company to Harris Trust and Savings Bank, as Trustee. (Exhibit B- 7 to File No. 2-5290). 4.02* Supplemental and Restated Trust Indenture, dated May 1, 1988, from the Company to Harris Trust and Savings Bank, as Trustee. (Exhibit 4.02 to Form 10-K for the year 1988, File No. 1-3034). Supplemental Indenture between the Company and said Trustee, supplemental to Exhibit 4.01, dated as follows: 4.03* Jun. 1, 1942 (Exhibit B-8 to File No. 2-97667). 4.04* Feb. 1, 1944 (Exhibit B-9 to File No. 2-5290). 4.05* Oct. 1, 1945 (Exhibit 7.09 to File No. 2-5924). 4.06* Jul. 1, 1948 (Exhibit 7.05 to File No. 2-7549). 4.07* Aug. 1, 1949 (Exhibit 7.06 to File No. 2-8047). 4.08* Jun. 1, 1952 (Exhibit 4.08 to File No. 2-9631). 4.09* Oct. 1, 1954 (Exhibit 4.10 to File No. 2-12216). 4.10* Sep. 1, 1956 (Exhibit 2.09 to File No. 2-13463). 4.11* Aug. 1, 1957 (Exhibit 2.10 to File No. 2-14156). 4.12* Jul. 1, 1958 (Exhibit 4.12 to File No. 2-15220). 4.13* Dec. 1, 1960 (Exhibit 2.12 to File No. 2-18355). 4.14* Aug. 1, 1961 (Exhibit 2.13 to File No. 2-20282). 4.15* Jun. 1, 1962 (Exhibit 2.14 to File No. 2-21601). 4.16* Sep. 1, 1963 (Exhibit 4.16 to File No. 2-22476). 4.17* Aug. 1, 1966 (Exhibit 2.16 to File No. 2-26338). 4.18* Jun. 1, 1967 (Exhibit 2.17 to File No. 2-27117). 4.19* Oct. 1, 1967 (Exhibit 2.01R to File No. 2-28447). 4.20* May 1, 1968 (Exhibit 2.01S to File No. 2-34250). 4.21* Oct. 1, 1969 (Exhibit 2.01T to File No. 2-36693). 4.22* Feb. 1, 1971 (Exhibit 2.01U to File No. 2-39144). 4.23* May 1, 1971 (Exhibit 2.01V to File No. 2-39815). 4.24* Feb. 1, 1972 (Exhibit 2.01W to File No. 2-42598). 4.25* Jan. 1, 1973 (Exhibit 2.01X to File No. 2-46434). 4.26* Jan. 1, 1974 (Exhibit 2.01Y to File No. 2-53235). 4.27* Sep. 1, 1974 (Exhibit 2.01Z to File No. 2-53235). 4.28* Apr. 1, 1975 (Exhibit 4.01AA to File No. 2-71259). 4.29* May 1, 1975 (Exhibit 4.01BB to File No. 2-71259). 4.30* Mar. 1, 1976 (Exhibit 4.01CC to File No. 2-71259). 4.31* Jun. 1, 1981 (Exhibit 4.01DD to File No. 2-71259). 4.32* Dec. 1, 1981 (Exhibit 4.01EE to File No. 2-83364). 4.33* May 1, 1983 (Exhibit 4.01FF to File No. 2-97667). 4.34* Dec. 1, 1983 (Exhibit 4.01GG to File No. 2-97667). 4.35* Sep. 1, 1984 (Exhibit 4.01HH to File No. 2-97667). 4.36* Dec. 1, 1984 (Exhibit 4.01II to File No. 2-97667). 4.37* May 1, 1985 (Exhibit 4.36 to Form 10-K for the year 1985, File No. 1-3034). 4.38* Sep. 1, 1985 (Exhibit 4.37 to Form 10-K for the year 1985, File No. 1-3034). 4.39* Jul. 1, 1989 (Exhibit 4.01 to Form 8-K dated July 7, 1989, File No. 1-3034). 4.40* Jun. 1, 1990 (Exhibit 4.01 to Form 8-K dated June 1, 1990, File No. 1-3034). 4.41* Oct. 1, 1992 (Exhibit 4.01 to Form 8-K dated October 13, 1992, File No. 1-3034). 4.42* April 1, 1993 (Exhibit 4.01 to Form 8-K dated March 30, 1993, File No. 1-3034). 4.43* Dec. 1, 1993 (Exhibit 4.01 to Form 8-K dated December 7, 1993, File No. 1-3034). 4.44* Feb. 1, 1994 (Exhibit 4.01 to Form 8-K dated February 10, 1994, File No. 1-3034). 4.45* Oct. 1, 1994 (Exhibit 4.01 to Form 8-K dated October 5, 1994, File No. 1-3034). 4.46* Trust Indenture, dated April 1, 1947, from the Wisconsin Company to Firstar Trust Company (formerly First Wisconsin Trust Company), as Trustee. (Exhibit 7.01 to File No. 2- 6982). Supplemental Indentures between the Wisconsin Company and said Trustee, supplemental to Exhibit 4.45 dated as follows: 4.47* Mar. 1, 1949 (Exhibit 7.02 to File No. 2-7825). 4.48* Jun. 1, 1957 (Exhibit 2.13 to File No. 2-13463). 4.49* Aug. 1, 1964 (Exhibit 4.20 to File No. 2-23726). 4.50* Dec. 1, 1969 (Exhibit 2.03E to File No. 2-36693). 4.51* Sep. 1, 1973 (Exhibit 2.01F to File No. 2-48805). 4.52* Feb. 1, 1982 (Exhibit 4.01G to File No. 2-76146). 4.53* Mar. 1, 1982 (Exhibit 4.39 to Form 10-K for the year 1982, File No. 10-3140). 4.54* Jun. 1, 1986 (Exhibit 4.01I to File No. 33-6269). 4.55* Mar. 1, 1988 (Exhibit 4.01J to File No. 33-20415). 4.56* Supplemental and Restated Trust Indenture dated March 1, 1991, from the Wisconsin Company to Firstar Trust Company (formerly First Wisconsin Trust Company), as Trustee. (Exhibit 4.01K to File No. 33-39831) 4.57* Apr. 1, 1991 (Exhibit 4.01L to File No. 33-39831). 4.58* Mar. 1, 1993 (Exhibit 4.01 to Form 8-K dated March 4, 1993, File No. 10-3140). 4.59* Oct. 1, 1993 (Exhibit 4.01 to Form 8-K dated September 21, 1993, File No. 10-3140). 4.60 NSP Employee Stock Ownership Plan. 10.01 Mid-continent Area Power Pool (MAPP) Agreement, dated March 31, 1972, with amendments in 1994, between the local power suppliers in the North Central States area. 10.02* Facilities agreement, dated July 21, 1976, between the Company and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 Kv Line. (Exhibit 5.06I to file No. 2-54310). 10.03* Transactions agreement, dated July 21, 1976, between the Company and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 Kv Line. (Exhibit 5.06J to File No. 2-54310). 10.04* Co-ordinating agreement, dated July 21, 1976, between the Company and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 Kv Line. (Exhibit 5.06K to File No. 2-54310). 10.05* Ownership and Operating Agreement, dated March 11, 1982, between the Company, Southern Minnesota Municipal Power Agency and United Minnesota Municipal Power Agency concerning Sherburne County Generating Unit No. 3. (Exhibit 10.01 to Form 10-Q for the Quarter Ended September 30, 1994, File No. 1-3034). 10.06* Transmission agreement, dated April 27, 1982, and Supplement No. 1, dated July 20, 1982, between the Company and Southern Minnesota Municipal Power Agency. (Exhibit 10.02 to Form 10-Q for the Quarter Ended September 30, 1994, File No. 1-3034). 10.07* Power agreement, dated June 14, 1984, between the Company and the Manitoba Hydro-Electric Board, extending the agreement scheduled to terminate on April 30, 1993, to April 30, 2005. (Exhibit 10.03 to Form 10-Q for the Quarter Ended September 30, 1994, File No. 1-3034). 10.08* Power Agreement, dated August 1988, between the Company and Minnkota Power Company. (Exhibit 10.08 to Form 10-K for the Year 1988, File No. 1-3034). 10.09* Energy Supply Agreement, dated October 26, 1993, between the Company and Liberty Paper, Inc., relating to the supply of steam and electricity to the LPI container-board facility in Becker, MN. (Exhibit 10.09 to Form 10-K for the Year 1993, File No. 1-3034). Executive Compensation Arrangements and Benefit Plans Covering Executive Officers 10.10* Executive Long-Term Incentive Award Stock Plan. (Exhibit 10.10 to Form 10-K for 1988, File No. 1-3034). 10.11* Terms and Conditions of Employment - James J Howard, President and Chief Executive Officer, effective February 1, 1987. (Exhibit 10.11 to Form 10-K for the Year 1986, File No. 1-3034). 10.12 NSP Severance Plan. 10.13* NSP Deferred Compensation Plan amended effective January 1, 1993. (Exhibit 10.16 to Form 10-K for the Year 1993, File No. 1-3034). 10.14* Annual Executive Incentive Plan for 1994 (Exhibit 10.01 to Form 10-Q for the Quarter Ended March 31, 1994, File No. 1-3034). 12.01 Statement of Computation of Ratio of Earnings to Fixed Charges. 16.01* Independent Auditors' Letter re: Change in Certifying Accountant (Exhibit 16.01 to Form 8-K dated December 13, 1994, File No. 1-3034). 18.01* Independent Auditors' Preferability Letter. (Exhibit 18.01 to Form 10-Q for the quarter ended March 31, 1992, File No. 1-3034). 21.01 Subsidiaries of the Registrant. 23.01 Independent Auditors' Consent. 27.01 Financial Data Schedule (b) Reports on Form 8-K. The following reports on Form 8-K were filed either during the three months ended December 31, 1994, or between December 31, 1994 and the date of this report: October 4, 1994 (Filed October 4, 1994) - Item 5. Other Events. Re: Disclosure of an agreement by a joint venture between one of the Company's non-regulated subsidiaries and Cogentrix, Inc., had agreed to terminate a contract for power sales from a cogeneration project in Michigan. Disclosure negotiations by the Company and the Minnesota Pollution Control Agency (MPCA) of a Stipulation Agreement to address monitoring procedures used at the Company's Prairie Island Generating Plant between January and September of 1992 that allegedly did not comply with National Pollution Discharge System permits, limiting the halogen content of water discharges at the Plant. October 5, 1994 (Filed October 7, 1994) - Item 5. Other Events. Re: Disclosure of Underwriting Agreement and filing of a prospectus supplement relating to $150,000,000 First Mortgage Bonds, Series due October 1, 2001. Item 7. - Financial Statements and Exhibits. Filing of Underwriting Agreement between the Company and various underwriters, Supplemental Trust Indenture between the Company and Harris Trust and Savings Bank as Trustee, creating First Mortgage Bonds, Series due October 1, 2001 and the computation of ratio of earnings to fixed charges. December 13, 1994 (Filed December 16, 1994) - Item 4. Change in Registrant's Certifying Accountant. Re: Disclosure of the Company's change in independent accountants for 1995. Deloitte & Touche LLP was informed that the firm would no longer be engaged as independent accountants for the Registrant and its subsidiaries after the completion of audit work for the fiscal year ended December 31, 1994. The Company's Board of Directors approved the appointment of the accounting firm of Price Waterhouse LLP as independent accountants for the Registrant for 1995, subject to ratification by the shareholders. Item 7. - Financial Statements and Exhibits. Exhibit No. 16 - Letter from Deloitte & Touche LLP. January 30, 1995 (Filed February 2, 1995) - Item 5. Other Events. Disclosure of the Company receiving a notice of violation from the United States Nuclear Regulatory Commission (NRC), regarding the inspection of the quality assurance programs at the Company and PX Engineering Company, Inc., a subcontractor responsible for the fabrication and assembly of certain components for the TN-40 spent fuel storage containers which will be used at the Prairie Island Nuclear Generating Plant. Disclosure of the Mescalero Apache Tribe vote against participation in a joint Mescalero-Utility Spent Nuclear Fuel Storage Initiative. February 28, 1995 (Filed March 2, 1995) - Item 5. Other Events. Disclosure of a basic agreement between San Joaquin Valley Energy Partners (SJVEP) and Pacific Gas & Electric Company (PG&E) regarding the acquisition of existing Standard Offer 4 (SO4) contracts by PG&E from SJVEP. The parties entered into a bridging agreement to cover the period until all approvals are received for the transaction. NRG Energy, Inc., a wholly owned subsidiary of the Company, has a 45 percent interest in SJVEP, through wholly owned subsidiaries. Signatures Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized. NORTHERN STATES POWER COMPANY March 24, 1995 (E J McIntyre) E J McIntyre Vice President and Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. (James J Howard) (E J McIntyre) James J Howard E J McIntyre Chairman of the Board and Director Vice President (Principal Executive Officer) (Principal Financial Officer) (Roger D Sandeen) (H Lyman Bretting) Roger D Sandeen H Lyman Bretting Vice President & Controller Director (Principal Accounting Officer) (David A Christensen) (W John Driscoll) David A Christensen W John Driscoll Director Director (Dale L Haakenstad) (Allen F Jacobson) Dale L Haakenstad Allen F Jacobson Director Director (Douglas W Leatherdale) (John E Pearson) Douglas W Leatherdale John E Pearson Director Director (G M Pieschel) (Margaret R Preska) G M Pieschel Margaret R Preska Director Director (A Patricia Sampson) (Edwin M Theisen) A Patricia Sampson Edwin M Theisen Director Director EXHIBIT INDEX Method of Exhibit Filing No. Description DT 4.60 NSP Employee Stock Ownership Plan DT 10.01 Mid-continent Area Power Pool Agreement DT 10.12 NSP Severance Plan DT 12.01 Statement of Computation of Ratio of Earnings to Fixed Charges DT 21.01 Subsidiaries of the Registrant DT 23.01 Independent Auditor's Consent DT 27.01 Financial Data Schedule EX-4 2 Exhibit 4.60 12-15-94 NORTHERN STATES POWER COMPANY EMPLOYEE STOCK OWNERSHIP PLAN Amended and Restated Effective as of December 31, 1988 NORTHERN STATES POWER COMPANY EMPLOYEE STOCK OWNERSHIP PLAN Amended and Restated Effective as of December 31, 1988 TABLE OF CONTENTS Page ARTICLE I. NATURE OF THE PLAN . . . . . . . . . . . . 1 Section 1.1 Purpose. . . . . . . . . . . . . . . . . . 1 Section 1.2 History. . . . . . . . . . . . . . . . . . 1 Section 1.3 General Information. . . . . . . . . . . . 1 Section 1.4 Benefits Determined Under Provisions in effect at Termination of Employment . . . 1 ARTICLE II. DEFINITIONS. . . . . . . . . . . . . . . . 2 Section 2.1 Definitions. . . . . . . . . . . . . . . . 2 ARTICLE III. ELIGIBILITY FOR PARTICIPATION . . . . . . . . . 7 Section 3.1 Eligibility. . . . . . . . . . . . . . . . 7 Section 3.2 Re-employment. . . . . . . . . . . . . . . 8 Section 3.3 Excluded Employees.. . . . . . . . . . . . 9 ARTICLE IV. CONTRIBUTIONS . . . . . . . . . . . . . . . . . 10 Section 4.1 Discretionary Contributions. . . . . . . . 10 Section 4.2 Employee Contributions.. . . . . . . . . . 10 ARTICLE V. ACCOUNTS AND ALLOCATIONS . . . . . . . . . 11 Section 5.1 Separate Accounts. . . . . . . . . . . . . 11 Section 5.2 Allocation of Contributions. . . . . . . . 11 Section 5.3 Limitation on Allocations. . . . . . . . . 12 Section 5.4 Trust Income . . . . . . . . . . . . . . . 13 Section 5.5 Statement of Account . . . . . . . . . . . 14 Section 5.6 Immediate Vesting. . . . . . . . . . . . . 14 Section 5.7 Voting of Shares and Exercise of Other Rights 14 Section 5.8 Tender or Exchange Offers Regarding Company Stock 14 ARTICLE VI. DISTRIBUTION. . . . . . . . . . . . . . . . . . 16 Section 6.1 Termination of Employment. . . . . . . . . 16 Section 6.2 Effect of Re-Employment After Distribution Has Been Made or Commenced . 17 Section 6.3 Withdrawals of Common Stock. . . . . . . . 17 Section 6.4 Diversification Options. . . . . . . . . . 19 Section 6.5 Rollovers and Transfers to Other Qualified Plans 20 ARTICLE VII. BENEFICIARIES . . . . . . . . . . . . . . . . . 22 Section 7.1 Surviving Spouse as Required Beneficiary . 22 Section 7.2 Other Beneficiaries. . . . . . . . . . . . 22 Section 7.3 Presumptions . . . . . . . . . . . . . . . 22 Section 7.4 Waiver of Interest . . . . . . . . . . . . 23 ARTICLE VIII. ADMINISTRATIVE PROVISIONS . . . . . . . . . . . 24 Section 8.1 Company as "Named Fiduciary" May Delegate Powers and Authorities. . . . . . 24 Section 8.2 Facility of Payment. . . . . . . . . . . . 24 Section 8.3 Spendthrift Trust and Qualified Domestic Relations Order 24 Section 8.4 Source of Payment. . . . . . . . . . . . . 25 Section 8.5 Company to Pay Administration Expenses . . 25 Section 8.6 Record Address . . . . . . . . . . . . . . 25 Section 8.7 Required Information to be Furnished . . . 25 Section 8.8 Company Rules. . . . . . . . . . . . . . . 25 Section 8.9 Claims Procedure . . . . . . . . . . . . . 26 ARTICLE IX. AMENDMENT AND TERMINATION . . . . . . . . . . . 27 Section 9.1 Amendment. . . . . . . . . . . . . . . . . 27 Section 9.2 Discontinuance of Contributions and Termination of the Plan 27 Section 9.3 Limitations. . . . . . . . . . . . . . . . 27 Section 9.4 Merger, Etc., with Another Plan. . . . . . 27 Section 9.5 Election to Participate by New Employer. . 27 ARTICLE X. TRUSTEE. . . . . . . . . . . . . . . . . . 28 Section 10.1 Trust Agreement. . . . . . . . . . . . . . 28 Section 10.2 Trust Investments. . . . . . . . . . . . . 28 Section 10.3 Exclusive Benefit of Participants. . . . . 28 Section 10.4 Borrowed Funds . . . . . . . . . . . . . . 28 Section 10.5 Dividends Applied to Loan Repayment. . . . 29 Section 10.6 Release from Suspense Account and Allocation of Shares 29 Section 10.7 Non-Tradable Company Stock . . . . . . . . 30 ARTICLE XI. MISCELLANEOUS PROVISIONS. . . . . . . . . . . . 32 Section 11.1 No Contract of Employment. . . . . . . . . 32 Section 11.2 No Guarantees on Value . . . . . . . . . . 32 Section 11.3 Fiduciary Responsible Only For Own Acts. . 32 Section 11.4 Company Indemnification. . . . . . . . . . 32 Section 11.5 Laws of Minnesota. . . . . . . . . . . . . 32 Section 11.6 Securities Regulations . . . . . . . . . . 32 Section 11.7 Contributions Conditioned on Tax Deductions 32 Section 11.8 Top Heavy Contingency. . . . . . . . . . . 33 Section 11.9 Tax Credit Rules . . . . . . . . . . . . . 33 NORTHERN STATES POWER COMPANY EMPLOYEE STOCK OWNERSHIP PLAN (Amended and Restated, Effective as of December 31, 1988) ARTICLE I. NATURE OF THE PLAN Section 1.1 Purpose. The purpose of this Plan is to provide Employees who become Participants in the Plan with an opportunity to acquire ownership of Company Stock, thereby promoting Employee interest in the business endeavors of the Company and its subsidiaries and enhancing the Employees' welfare. Section 1.2 History. The Plan was originally adopted, effective January 1, 1975, to take advantage of an investment tax credit available to employers with respect to certain employee stock ownership plan contributions. The investment tax credit expired December 31, 1982, and the Plan was amended to take advantage of a payroll based tax credit available from January 1, 1983 through December 31, 1986. After 1986, the Plan remained in effect, both to hold shares acquired previously, and to acquire additional shares of Company Stock in leveraged and non-leveraged transactions. Section 1.3 General Information. The Plan is intended to qualify as a "tax credit employee stock ownership plan" under Code Section 409, as an "employee stock ownership plan" as defined by Code Section 4975(e), and as a qualified stock bonus plan under Code Section 401(a). The Plan consists of the Plan and the Trust Agreement. It is administered by the Company for the exclusive benefit of Participants and their Beneficiaries, pursuant to the Plan and the Trust Agreement. A copy of the Trust Agreement is available for review by Participants and their Beneficiaries in the Company's Benefits Department. The administrative costs of the Plan, other than taxes, if any, on assets held by the Trustee, will be borne by the Company, except to the extent indirectly reimbursed by a reduction in a Discretionary Contribution under Section 4.1. The Plan is designed to invest primarily in qualifying employer securities meeting the requirements of Code Sections 4975(e)(8) and 409(l). Section 1.4 Benefits Determined Under Provisions in effect at Termination of Employment. Except as may be specifically provided herein to the contrary, with respect to a Participant whose Termination of Employment has occurred, benefits under the Plan attributable to service prior to his or her Termination of Employment shall be determined and paid in accordance with the provisions of the Plan as in effect on the date the Termination of Employment occurred. Except where an earlier or later effective date is specified, this amended and restated Plan is effective as of December 31, 1988. ARTICLE II. DEFINITIONS Section 2.1 Definitions. Unless the context clearly implies otherwise, as used in this Plan the following terms shall have the meanings set forth below: "Account" refers to the records maintained by the Company to record the proportional amount of the Trust Fund credited to an individual under the Plan. "Basic Account" refers to the entire Account of a Participant exclusive of the Company Stock or other interest credited to the Participant's Savings Account. "Beneficiary" means the designated person, persons, trust, or estate to whom all or a portion of the decedent's Account is to be distributed in the event of death as provided in Article VII, except that, in the event of homicide, the provisions of Section 524.2-803 of Minnesota Statutes shall be applied. "Board of Directors" means the Board of Directors of the Company. "Code" refers to the Internal Revenue Code of 1986, as amended. "Committee" shall mean the committee provided for in Section 8.1. "Common Control" - a trade or business entity (whether a corporation, partnership, sole proprietorship or otherwise) is under "Common Control" with another trade or business entity (i) if both entities are corporations which are members of a controlled group of corporations as defined in Code Section 414(b) , (ii) if both entities are trades or businesses (whether or not incorporated) under common control as defined in Code Section 414(c), (iii) if both entities are members of an affiliated service group as defined in Code Section 414(m), or (iv) if both entities are required to be aggregated pursuant to regulations under Code Section 404(o). Service for all entities under Common Control shall be treated as service for a single employer to the extent required by the Code. In applying the preceding sentence for purposes of Section 5.3, the provisions of Code Section 414(b) and (c) are deemed to be modified as provided in Code Section 415(h). "Company" means Northern States Power Company, a Minnesota corporation. "Company Stock" means common stock of the Company. "Converted Pay" is a dollar amount which the Employee elected to have the Employer make as a contribution on behalf of the Employee to a trust under a plan adopted by the Company in accordance with Code Section 401(k) or which the Employee directed the Employer to apply to the acquisition of benefits under a written plan established by the Company under Code Section 125. "Covered Compensation" means the total compensation received from the Employer during a Plan Year as stated in the payroll records of the Employer, including overtime, bonus or incentive pay, and Converted Pay, subject to the following: (a) Covered Compensation does not include expense allowances, per diem payments and other special payments not classified as regular compensation. (b) Covered Compensation does not include Employer contributions to this Plan or another employee benefit plan, nor does it include any benefits from an employee benefit plan. (c) Covered Compensation does not include any compensation in excess of the maximum annual amount specified in Code Section 401(a)(17), subject to any applicable cost of living adjustments. (d) In applying the annual limits under Code Section 401(a)(17), the spouse of a Highly Compensated Employee who is more than a 5% owner or who is among the 10 highest paid Highly Compensated Employees and any lineal descendants of such a Highly Compensated Employee who have not attained age 18 before the end of the Plan Year shall not be treated as a separate participant, and any Covered Compensation of said family member shall be treated as Covered Compensation of the Highly Compensated Employee. (e) The term "Covered Compensation" includes compensation received from an Employer in the entire Plan Year in which participation commences. "Disability" means a total and permanent disability of a Participant. A Participant will be deemed to be totally and permanently disabled when, on the basis of medical evidence satisfactory to the Company, such Participant is found to be unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or to be of long-continued and indefinite duration. "Discretionary Contribution" refers to an Employer contribution under Section 4.1. "Effective Date" means the date on which the Plan became effective, that is, January 1, 1975. "Employee" refers to an employee of an Employer as defined herein. "Employer" means the Company, Northern States Power Company, a Wisconsin corporation, and any other corporation under Common Control with the Company which, with the consent of the Company, is participating pursuant to Section 9.5. "ERISA" refers to the Employee Retirement Income Security Act of 1974. "Highly Compensated Employee" for any Plan Year means an individual described in Code Section 414(q), including Employees meeting the following requirements: (a) The Employee at any time during the current or prior Plan Year was a 5 percent owner as defined in Code Section 414(q)(3). (b) The Employee received Testing Wages in excess of $75,000 (adjusted for cost of living increases as provided by regulation) for the prior Plan Year. (c) The Employee both received Testing Wages in excess of $50,000 (adjusted for cost of living increases as provided by regulation) for the prior Plan Year and was in the top paid 20 percent of Employees, determined in accordance with Code Section 414(q)(8). (d) The Employee was an officer receiving Testing Wages in excess of $45,000 (adjusted for cost of living increases as provided by regulation) for the prior Plan Year. However, no more than the greater of 50 persons or 10 percent of Employees shall be treated as officers for purposes of this subsection. (e) The employee would meet the requirements of subsections (b), (c), or (d) in the current Plan Year (but not in the prior Plan Year) and is among the 100 Employees paid the greatest Testing Wages. "Hour of Service" means an hour for which an Employee is directly or indirectly paid, or entitled to payment, by the Employer prior to termination of service, including overtime and paid "time-off" such as paid vacation days, holidays, or days on jury duty. An "Hour of Service" includes each hour for which back pay, irrespective of mitigation of damage, has been awarded or agreed to by the Employer; such hours shall be credited to the Employee for the computation period or periods to which the award or agreement pertains rather than the computation period in which the award, agreement, or payment was made. Credit for payments made for or during periods of time in which no duties are performed shall be determined in accordance with Department of Labor Regulation Sections 2530.200b-2(b) and (c). "Investment Date" is the 20th day of each month if shares of Company Stock are traded on the New York Stock Exchange on that day; if not, the Investment Date shall be the first succeeding day during which shares of such stock are traded on such Exchange. For purposes of section 4.2(B) only, "10th" shall be substituted for "20th" in the preceding sentence. "Investment Price" shall be a price equal to the average of the reported high and low prices for the Company Stock as of the Investment Date preceding the applicable transaction as reported in the Wall Street Journal for the New York Stock Exchange-Composite Transactions. (In the event Company Stock should not be readily tradeable on an established security market, then the Investment Price shall be determined by an independent appraiser meeting requirements similar to those contained under regulations issued under Code Section 170(a)(1).) "Leased Employee" is any person who is not otherwise an Employee and who, pursuant to an agreement between the recipient Employer and any other person or organization, has performed services for an Employer, or for an Employer and related persons (determined in accordance with Code Section 414(n)(6)), who completes 1000 Hours of Service either in the initial computation year referred to in Section 3.1(B)(2) or any Plan Year thereafter, and such services are of a type historically performed by employees in the business field of the Employer; provided, that a person shall not be treated as a Leased Employee for any Plan Year if, during such Plan Year: (i) such person is covered by a money purchase pension plan described in Code Section 414(n)(5)(B), and (ii) not more than 20% of the Employees who are not Highly Compensated Employees are Leased Employees. Once a person is classified as a Leased Employee, such person shall remain a Leased Employee for every Plan Year for which the person completes at least 1000 Hours of Service. "Matching Employee Contributions" refer to contributions made by a Participant prior to 1987 under Plan provisions which at that time resulted in a matching contribution from the Employer. "Participant" refers to an Employee who has become eligible to participate under Article III and any former Employee who is still entitled to benefits under the Plan. "Plan Entry Date" refers to December 31 or June 30 of each Plan Year. "Plan Year" means the twelve month period beginning each December 31 and ending the following December 30. "Retirement or Retirees" refers to normal (age 65), late (after age 65), or early (after age 55 but before age 65), retirement under the Company's defined benefit pension plan, or termination of service after attainment of age 65 for Participants entitled to no benefits from said pension plan. "Savings Account" refers to the subaccount which separately accounts for a Participant's contributions made pursuant to Section 4.2. "Suspense Account" refers to an unallocated account maintained by the Trustee under Section 10.4 in regard to Company Stock acquired with the proceeds of a loan. "Termination of Employment" means any termination of the employment relationship pursuant to the Employer's practices and procedures. Termination of Employment generally does not occur until termination of any leave of absence granted to an Employee who leaves the service of an Employer, except that a "leave of absence for third party service" will be deemed a "termination of employment." A "leave of absence for third party service" is an unpaid leave of absence of indefinite duration, but expected to exceed one year, granted the Employee either by the Employer or by operation of law for the purpose of allowing the Employee to perform services for a third party (such as full-time government, military or union service). No distribution shall be made to an Employee during a "leave of absence for third party service" unless the Employee delivers to the Company a written request for such distribution. "Testing Wages" for a Plan Year means the Employee's wages for the Plan Year as defined for purposes of federal income tax withholding, subject to the following: (a) The Committee may, on a uniform and nondiscriminatory basis, modify the definition of Testing Wages in any way that satisfies the definition of "compensation" under Code Section 414(s). (b) Except for purposes of Section 5.3, the Committee shall determine whether Testing Wages for a Plan Year shall include Converted Pay. For purposes of Section 5.3, Testing Wages shall not include Converted Pay. (c) Testing Wages does not include any compensation in excess of the maximum annual limit applicable under Code Section 401(a)(17), subject to any applicable cost of living adjustments. (d) In applying the annual limits under Code Section 401(a)(17), the spouse of a Highly Compensated Employee who is more than a 5% owner or who is among the 10 highest paid Highly Compensated Employees and any of the lineal descendants of such a Highly Compensated Employee who have not attained age 18 before the end of the Plan Year shall not be treated as a separate participant, and any Testing Wages of said family member shall be treated as Testing Wages of the Highly Compensated Employee. "Trust" is the trust created by the Trust Agreement entered between the Company and the Trustee. "Trust Agreement" is the agreement, as provided in Article X, entered into by the Company and the Trustee, or any successor Trustee, establishing the Trust and specifying the duties of the Trustee. "Trustee" means the Trustee (which can be more than one individual or corporation) under the Plan and related Trust Agreement. "Trust Fund" shall mean the Trust Fund provided for in Article X. "Year of Service" means any Plan Year, calendar year or other applicable 12-month computation period during which an Employee completes at least 1,000 Hours of Service. ARTICLE III. ELIGIBILITY FOR PARTICIPATION Section 3.1 Eligibility. (A) An Employee in the employ of an Employer shall become a Participant on the first Plan Entry Date which occurs after the earlier of the following: (1) the date the Employee completes one continuous Year of Service; or (2) the date the Employee completes two Years of Service without a Break in Service, unless such Employee is no longer in the employ of an Employer on the date such Employee would otherwise become a Participant. (B) For the purpose of Subsection (A), the following rules and definitions apply: (1) No period of employment with an Employer prior to January 1, 1972, shall be considered to determine eligibility. (2) The computation period for determining a Year of Service for eligibility shall be a consecutive 12-month period measured from the date of the first Hour of Service commencing on or after January 1, 1972. (3) "One continuous Year of Service" means that the Employee completes a Year of Service in a consecutive 12-month computation period measured from the date of the first Hour of Service commencing on or after January 1, 1974, and remains in the employ of an Employer throughout such entire computation period. (4) A "Break in Service" means a failure by an Employee who is not a Participant under the Plan to complete more than 500 Hours of Service for the Employer in the computation period, or in any immediately succeeding 12-month period, being used to account for such Employee's Hours of Service. If an Employee incurs a Break in Service, all service for the Employer prior to the Break in Service shall be disregarded. After a Break in Service by an Employee, the computation period for determining a Year of Service for eligibility shall be a consecutive 12 month period commencing with the first date such Employee completes an Hour of Service following the computation period in which the Break in Service occurred. (5) A "Break in Service" shall not occur as to a computation period during which the Employee completes less than 500 Hours of Service if such failure to complete 500 Hours of Service was due to a maternity or paternity leave (assuming the greater of the Employee's usual Hours of Service or eight Hours a day during the portion of the computation period for which the Employee is absent from service by reason of a maternity or paternity leave). However, a "Break in Service" shall occur in any succeeding computation period for failure to complete 500 Hours of Service even if the maternity or paternity leave extends into such succeeding computation period. "Maternity or paternity leave" means a period of absence by an Employee from the Employer's service by reason of (1) the Employee's pregnancy; (2) the birth of a child of the Employee; (3) the adoption of a child by the Employee; or (4) the caring for such a child for a period beginning immediately following birth or placement for adoption. The Company may require the Employee to furnish timely and adequate information that an absence, or the total period of absence, was for one of the foregoing reasons before crediting all or a portion of an absence as a maternity or paternity leave. (C) Notwithstanding (A) above, an Employee of an Employer which became an Employer pursuant to an election under Section 9.5, shall become a Participant as of the effective date of such an Employer's election to participate in the Plan if: (1) Such an Employee was a participant in a defined contribution plan of such an Employer which plan was merged into this Plan effective as of the date such Employer's participation in this Plan commenced; or (2) Such an Employee would have been eligible under (A) above, prior to such effective date if such Employer had become a participating employer as of the first day of the third Plan Year preceding the Plan Year in which such Employer actually commenced participation in this Plan. In all other situations, such an Employee shall become a Participant upon meeting the requirements of (A) above, disregarding any service for the Employer more than three Plan Years prior to the Plan Year in which the Employer's participation in this Plan commenced. (D) Once an Employee becomes a Participant, all Hours of Service for all purposes shall be accounted for on a Plan Year basis only. (E) In addition to the service credited pursuant to subsection (C) above, certain Employees shall receive additional service credit as follows: (1) Employees who were employed by Viking Gas Transmission Co. at the time it was acquired by the Company from Tenneco Inc. shall be credited with additional service equal to their pre-acquisition service for Tenneco Inc. and its subsidiaries. (2) Employees who were employees of Centran Corporation immediately prior to the acquisition of certain of its assets by a subsidiary of the Company on October 1, 1993 shall be credited with additional service equal to their service prior to that date for Centran Corporation. Section 3.2 Re-employment. If a Participant ceases to participate due to a termination of employment and is re-employed by an Employer such former Participant shall immediately reenter the Plan as a Participant. Section 3.3 Excluded Employees. Notwithstanding any other provisions hereof, the following Employees are excluded from coverage under the Plan: (A) An Employee who is a member of a union which has a collective bargaining agreement through or with an employers' association, which agreement is followed by the Employer and the Employee is eligible for coverage under a retirement plan established by negotiations between such union and association, or if there is other evidence that retirement benefits were the subject of good faith bargaining between such employer association and such union. (B) Any Leased Employee as defined in Section 2.1. (C) Prior to January 1, 1994, certain Employees participating in work study arrangements. ARTICLE IV. CONTRIBUTIONS Section 4.1 Discretionary Contributions. For each Plan Year the Company shall determine whether a Discretionary Contribution to the Plan shall be made and the amount of any such contribution. Said contribution will be made by the Participating Employers in proportions determined by the Company. Such contribution will normally be made on or before the 31st day following the end of the Plan Year; but the Company may, in its discretion, delay such contribution until the due date (including extension) for filing the federal income tax return for the taxable year of the Company with respect to which the contribution is made. The contribution may be made in the form of cash or Company Stock, or any combination thereof. All cash contributions shall be applied by the Trustee within 30 days of receipt in one or more of the following ways, as determined by the Company: (1) to purchase Company Stock in market transactions, (2) to purchase Company Stock directly from the Company at the Investment Price, or (3) to redeem fractional shares of terminating Participants at the Investment Price. Section 4.2 Employee Contributions. (A) Except as hereafter provided, a Participant who is an Employee may elect to make Employee contributions to the Plan to be held in such Participant's Savings Account, which will be reflected by the sub-accounts established by Sections 5.1(D) and 5.1(E), as applicable. However, Participants who are Highly Compensated Employees or who the Company determines are exempt employees for purposes of the federal wage and hour laws are not eligible to make Employee contributions pursuant to this Section. If the Company determines that it has accepted a contribution from such a Participant, the Company Stock acquired with such a contribution, including stock acquired by the reinvestment of dividends relating thereto, shall be distributed to the Participant as soon as practical after the determination is made by the Company. Contributions may be made by payroll deductions or cash contributions. Such contributions may be made up to an amount equal to ten percent of the aggregate Covered Compensation received by the Participant for all years during which the Participant participated in this Plan, less the amount of previous voluntary contributions to this Plan under this Section 4.2 or to the NSP Retirement Savings Plan or any other plan qualified under Code Section 401(a) maintained by the Employer. (B) All Employee contributions shall be applied monthly by the Trustee in one or more of the following ways, as determined by the Company: (1) to purchase Company Stock in market transactions, (2) to purchase such stock directly from the Company at the Investment Price, or (3) to redeem fractional shares of terminating Participants at the Investment Price. (C) Participants may elect to make Employee contributions by signing a form provided by the Company for such purpose. The Employer may require, on a nondiscriminatory basis, that no payroll deduction will be made, changed or terminated for any payroll period which commences less than 15 days after delivery by a Participant of such election, change or termination to the Employer's Payroll Department. No payroll deduction shall be in an amount less than $5.00 per month and no cash contribution shall be less than $10.00. The Employer may require that the payroll deduction be in a specific dollar amount, and, if permitted as a percent of eligible compensation, the authorization may be rounded to the next highest dollar amount divisible by twelve. The Employer may require that payroll deductions for the Savings Account be collected in the same payroll period each month and may specify a specific payroll period for such payroll deductions. ARTICLE V. ACCOUNTS AND ALLOCATIONS Section 5.1 Separate Accounts. The Company shall create a separate Account for each Participant. The Company shall also maintain separate subaccounts reflecting: (A) Company Stock acquired with Discretionary Contributions; (B) Company Stock acquired with Matching Employee Contributions; (C) Company Stock acquired directly (or indirectly through repayment of a loan to the Plan) due to reinvestment of dividends or other income which does not relate to the shares of stock allocated to the subaccount established pursuant to Sections 5.1(D) and 5.1(E). (D) Company Stock acquired with Employee contributions (other than Matching Employee Contributions) made prior to January 1, 1987, as well as with the dividends on stock allocated to such subaccount; and (E) Company Stock acquired with other Employee contributions made after December 31, 1986, as well as with the dividends on stock allocated to such subaccount. Additional subaccounts may be established in the Company's discretion. Section 5.2 Allocation of Contributions. (A) Allocation Using Covered Compensation. Except to the extent otherwise provided in Section 10.6, the Discretionary Contributions for a given Plan Year shall be allocated to the Accounts of Participants who meet the eligibility requirements of subsection (B) in the ratio which the Covered Compensation of each Participant for such Plan Year bears to the Covered Compensation of all such Participants, provided that if any portion of the contribution is allocated before the end of a Plan Year, such allocation may be based on either Covered Compensation paid to the date of the allocation or Covered Compensation projected for the Plan Year. The shares of Company Stock acquired with a Discretionary Contribution shall be allocated within 90 days after the end of the Plan Year for which the contribution is made or, if later, within 60 days after the date on which the contribution is made. (B) Participants Entitled to Receive Allocations. (1) Except for those Participants who commence participation during the Plan Year, or who terminate their employment with the Employer during the Plan Year by reason of death or retirement or under circumstances that entitle them to receive benefits under the NSP Severance Plan for non-bargaining employees, no portion of the Discretionary Contribution for a Plan Year shall be allocated to the Account of a Participant unless such Participant had at least 1,000 Hours of Service during such Plan Year. However, if a Participant is an active Employee at the time of allocation and the Company used dividends on the shares allocated to the Employee's Account throughout the Plan Year for the purposes of loan repayment under Section 10.5, such Participant shall share in the allocation of a Discretionary Contribution for the Plan Year even if the Participant did not complete 1,000 Hours of Service in the Plan Year. (2) No allocation of Discretionary Contributions shall be made to an Account for a Participant commencing participation on a date other than the first day of the Plan Year unless such Participant had, during the part of the Plan Year remaining after becoming a Participant, at least that fraction of 1,000 Hours of Service which is equal to the fraction of the Plan Year in which the Participant participated. (3) No allocation of Discretionary Contributions shall be made to an Account of a former Participant who has received a distribution of his or her total account balance before the allocation of the contribution is made, except in the case of an early distribution for which the Participant incurred a payment as provided in Section 6.1(A). Section 5.3 Limitation on Allocations. Notwithstanding any provisions of the Plan to the contrary, allocations to Participants under the Plan shall not exceed the maximum amount permitted under Code section 415. For purposes of the preceding sentence, the following rules shall apply unless otherwise provided in Code section 415: (A) The Annual Additions with respect to a Participant for any Plan Year shall not exceed the lesser of: (1) $30,000, or, if greater, 25% of the defined benefit dollar limitation set forth in Code section 415(b)(1)(A) as in effect for the Plan Year. (2) 25% of the Testing Wages of such Participant for such Plan Year. (B) If for any Plan Year the limitation described in subsection (A) would otherwise be exceeded with respect to any Participant, correction shall be made as follows: (1) The Participant's Employee contributions for said Plan Year will be refunded to him. (2) Any remaining excess amount will be transferred to a suspense account, from which it will be allocated as Employer contributions for all Participants in the next Plan Year. The suspense account will not participate in allocation of the Trust Fund's earnings or losses. (C) If a Participant is also a participant in one or more other defined contribution plans maintained by an Employer, and if the amount of Employer contributions otherwise allocated to the Participant for a Plan Year must be reduced to comply with the limitations under Code section 415, such allocations under this Plan and each of such other plans shall be reduced pro rata to the extent necessary to comply with said limitations, but reductions shall occur first from employee after-tax contributions, next from employee before-tax contributions, and finally from all other allocations. (D) If the Participant is also a participant in one or more defined benefit plans maintained by an Employer, the sum of the Participant's defined benefit plan fraction and defined contribution plan fraction, determined according to Code section 415(e), for any Plan Year may not exceed 1.0, and benefits under said defined benefit pension plan(s) shall be reduced as necessary to reduce the sum of the fractions to 1.0. (E) For purposes of this section, "Annual Additions" means the sum of the following amounts allocated to a Participant for a Plan Year under this Plan and all other defined contribution plans maintained by his Employer in which he participates: (1) Principal payments on exempt loans to the extent such payments are attributable to shares of Company Stock allocated to the Participant. (2) Discretionary Contributions under Section 4.1. (3) Employee Contributions under Section 4.2. (4) Amounts considered to be "Annual Additions" under the terms of the other defined contribution plans. Contributions used to pay interest on an Exempt Loan shall be an annual Addition for any Plan Year that the requirements of subsection (F) are not met. An Annual Addition with respect to a Participant's Account shall be deemed credited thereto with respect to a Plan Year if it is allocated to the Participant's Account under the terms of the Plan as of any date within such Plan Year. (F) The requirements of this subsection (F) are met with respect to a particular Plan Year if no more than one third of the Employer contributions for that year are allocated to the group consisting of Highly Compensated Employees. Section 5.4 Trust Income. Except as provided under Section 10.5, income earned by the Trust will be promptly invested in additional shares of Company Stock. However, any income earned on cash held pending investment in Company Stock will be held in an unallocated account until the next quarterly dividend payment when it shall be commingled, invested and allocated with the dividend income for the applicable Accounts then existing. Trust income shall be applied by the Trustee in one or more of the following ways, as determined by the Company (1) to purchase Company Stock in market transactions, (2) to purchase such stock directly from the Company at the Investment Price, or (3) to redeem fractional shares of terminating Participants at the Investment Price. When the total funds available for investment in shares of Company Stock at a particular time have been fully applied by the Trustee, the acquired shares shall be allocated to Participant Accounts so as to reflect the shares held in a Participant's Account at the time of allocation in relation to the total shares held in all Accounts, subject to a pro rata adjustment for any application by the Trustee of income as authorized herein, including reducing dividends credited to an Account to the extent applied under Section 10.5. The stated price of the shares so allocated shall reflect the weighted average price at which all such shares were acquired. For the purpose of this Section, the terms "Participant's Accounts" or "Participant's Account" refer to any account maintained by the Company including temporarily unallocated accounts and accounts reflecting the amount credited to a former Participant or to an alternate payee. Section 5.5 Statement of Account. As soon as practicable after the end of each Plan Year, the Company shall present to each Participant a statement showing the amount of Company Stock credited to the Participant's Account at the beginning of such Plan Year, any change during the Year, the accrued balance at the end of the Year, and such other information as the Company may determine. However, neither the maintenance of the accounts, the allocation of credits to the accounts, nor the statement of accounts shall operate to vest in any Participant any right or interest in or to any assets of the Trust except as the Plan and Trust specifically provide. Section 5.6 Immediate Vesting. All amounts allocated to a Participant's Accounts shall be fully vested at all times. Notwithstanding the Participant's nonforfeitable right hereunder, no stock in the Account of a Participant shall be distributed to a Participant or Beneficiary prior to a time authorized under Article VI. Section 5.7 Voting of Shares and Exercise of Other Rights. A Participant is entitled to direct the exercise of voting rights or other rights with respect to the number of shares of Company Stock allocated to said Participant's Account. The Company shall provide to each Participant materials pertaining to the exercise of such rights containing all the information distributed to shareholders as part of its distribution of such information to shareholders. A Participant shall have the opportunity to exercise any such rights within the same time period as shareholders of the Company. The Trustee shall vote the shares allocated to a Participant's Account in accordance with the directions given by that Participant. Unallocated shares and allocated shares for which no Participant direction is given will be voted in proportion to the votes cast pursuant to the preceding sentence. Section 5.8 Tender or Exchange Offers Regarding Company Stock. As soon as practicable after the commencement of a tender or exchange offer (an "Offer") for shares of Company Stock, the Company shall use its best efforts to cause each Participant (whose Account has allocated to it any shares of Company Stock) to be advised in writing of the terms of the Offer, and to be provided with forms by which the Participant may instruct the Trustee, or revoke such instruction, to tender or exchange shares of Company Stock, to the extent permitted under the terms of such Offer. The Trustee shall follow the directions of each Participant. In advising Participants of the terms of the Offer, the Company may include statements from the Board of Directors setting forth its position with respect to the Offer. The giving of instructions by a Participant to the Trustee to tender or exchange shares and the tender or exchange thereof shall not be deemed a withdrawal or suspension from the Plan or a forfeiture of any portion of such Participant's interest in the Plan solely by reason of the giving of such instructions and the Trustee's compliance therewith. Instructions by Participants pursuant to this Section shall apply both to allocated shares and to unallocated shares held in the Suspense Account. The number of shares as to which a Participant may provide instructions shall be determined as follows: (A) The Trustee shall determine the aggregate number of shares held by the Plan, including both allocated and unallocated shares. (B) The Company shall determine the number of shares allocated to each Participant's Accounts as a percentage of the aggregate number allocated to Accounts of all Participants. (C) The Participant may provide instructions with respect to a number of shares of Company Stock determined by applying the percentage in (B) to the aggregate number of shares in (A). If the Participant directs tender or exchange of the shares for which he may provide instructions, the Trustee shall follow that instruction. The Trustee shall not tender or exchange the shares for which a Participant may provide instructions if the Participant (i) directs against their tender or exchange or (ii) gives no direction. The determination of the number of shares as to which a Participant may provide instructions shall be as of the close of business on the day preceding the date on which the Offer is commenced or such earlier date as shall be designated by the Company as the Company, in its sole discretion, deems appropriate for reasons of administrative convenience. Any securities received by the Trustee as a result of a tender or exchange of shares of Company Stock shall be held, and any cash so received shall be invested in short-term investments pending any reinvestment by the Trustee, as it may deem appropriate, consistent with the purposes of the Plan. The rights extended to Participants by this Section shall also apply to the Beneficiaries of deceased Participants. If a tender or exchange offer is limited so that all of the shares that the Trustee has been directed to tender or exchange cannot be sold or exchanged, the shares that each Participant directed be tendered or exchanged shall be deemed to have been sold or exchanged in the same ratio that the number of shares actually sold or exchanged bears to the total number of shares that the Trustee was directed to tender or exchange. Shares sold or exchanged at the direction of a Participant shall be deemed to come first out of the shares allocated to the Participant's Accounts and only after all of those shares have been sold or exchanged, out of the Unallocated Reserve. For purposes of this Section, each Participant or Beneficiary who is entitled to give such instructions shall be deemed a "named fiduciary" (within the meaning of ERISA) with respect to such instructions. ARTICLE VI. DISTRIBUTION Section 6.1 Termination of Employment. Upon a Participant's Termination of Employment, the entire amount credited to his or her Account shall be distributed as follows: (A) Distribution Upon Retirement or Disability. Upon Retirement or Disability, a Participant's Account will be distributed at a time directed by the Participant, but not before all allocations to the Participant's account have been completed, subject to the following: (1) However, if requested in writing by the Participant at least 60 days before the desired distribution, the Company will distribute the current balance credited to the Participant's Account at any time after Retirement or Disability that cash funds are available for distributing the fractional share as provided in Section 6.1(D). In the event of such an additional early distribution, the Company may require the Participant to submit a payment in an amount determined by the Company, but not exceeding $100, which payment will be used to offset Plan administration costs incurred by the Company or the Trustee. (2) Unless the Participant elects otherwise, distributions must occur no later than the 60th day after the close of the Plan Year in which he reaches age 65 or in which his Termination of Employment occurs, whichever is later; provided, however, that if the amount of the payment to be made cannot be determined by the later of said dates, payment may be made no later than 60 days after the earliest date on which the amount of such payment can be ascertained. (B) Distribution Upon Termination of Employment for Reasons other than Retirement, Death or Disability. If a Participant's Termination of Employment occurs for a reason other than the Participant's Retirement, Disability or death, the Participant's Account will be distributed at a time directed by the Participant, but not before all allocations to the Participant's Account have been completed, subject to the following: (1) Distributions must occur as soon as administratively feasible after the date the Participant attains age 65. (2) However, if the value of the Participant's Account is $3,500 or less, the distribution must occur promptly after allocations are completed, and may not be deferred. (C) Distribution Upon Death. If a Participant's Termination of Employment is due to his death, his account will be distributed to his Beneficiary in a single sum promptly after all allocations to the Account have been completed. However, if the Beneficiary is the Participant's spouse, the spouse may elect to defer the distribution, but not beyond whichever of the following dates is applicable: (1) If the Participant died after attaining age 55 or after qualifying for disability retirement benefits under the Company-sponsored defined benefit pension plan in which the Participant participates, April 1 following the calendar year in which the Participant would have attained age 70 1/2 if he or she had not died. (2) If paragraph (1) does not apply to the Participant, the date the Participant would have attained age 65 if he or she had not died (or as soon as administratively feasible thereafter). (D) Single Sum Distributions; Distributions In Kind. All distributions under this Section will be made in a single sum consisting of whole shares of Company Stock with cash in lieu of any fractional shares. Such cash may be derived from other cash held by the Plan, in which case the fractional share will be valued at the Investment Price. If cash is not available within the Plan, shares may be sold and the proceeds used to make cash distributions in lieu of fractional shares. (E) Required Distributions At Age 70-1/2. Any amounts remaining in a Participant's Account at the close of the calendar year in which he attains age 70-1/2 shall be distributed to him not later than April 1 of the following calendar year. Any amounts allocated to him thereafter shall be distributed to him not later than April 1 following the close of the calendar year in which the allocation occurs. Such distributions shall occur regardless of whether the Participant has had a Termination of Employment. (F) Code Section 401(a)(9) Requirements. Notwithstanding any provision of the Plan to the contrary, distributions hereunder shall be made in accordance with the minimum distribution requirements of Code section 401(a)(9), including the incidental death benefit requirements of Code section 401(a)(9)(G), and the regulations thereunder. Any provisions of the Plan that are inconsistent with Code section 401(a)(9) and the regulations thereunder shall be deemed to be inoperative. Section 6.2 Effect of Re-Employment After Distribution Has Been Made or Commenced. In the event that a former Participant is re-employed by an Employer before full distribution is accomplished or commenced, distribution of the Account shall be suspended and the undistributed remainder in such Account shall continue to be held until employment is again terminated, it being the intent hereof that no distribution shall be made while a Participant is maintaining an employment relationship with an Employer. Notwithstanding the foregoing and the provisions of Section 3.2, if a retired Employee is re-employed on a part-time basis whereby the Employee is scheduled to work less than 1,000 hours per calendar year, distribution of such Employee's Account will not be suspended and such Employee shall not be eligible to participate in the Plan based on such part-time re-employment. Section 6.3 Withdrawals of Common Stock. (A) A Participant may withdraw full shares of Company Stock allocated to the subaccount maintained pursuant to Section 5.1(D) at any time to the extent such shares were purchased with the Employee's own contributions. Shares purchased with dividends or other income are not subject to withdrawal under this subsection, but may be withdrawn as provided in subsection (D). (B) After the Participant has withdrawn all shares available for withdrawal under subsection (A), the Participant may withdraw full shares of Company Stock allocated to the subaccount maintained pursuant to Section 5.1(B). (C) After the Participant has withdrawn all shares available for withdrawal under subsections (A) and (B), the Participant may withdraw full shares of Company Stock allocated to the subaccount maintained pursuant to Section 5.1(E), but only to the extent such shares were purchased with the Employee's own contributions. (Shares purchased with dividends or other income may not be withdrawn.) (D) Subject to the restrictions described in this subsection, a Participant who has withdrawn or requested withdrawal of all amounts available pursuant to subsections (A), (B), and (C) may withdraw full shares of Company Stock credited to the subaccount established for the Participant under Section 5.1(D) which were acquired as a result of the reinvestment of dividends or other income on the shares of stock allocated to such subaccount. Any such withdrawal must be on account of an immediate and heavy financial need of the Participant and must be necessary to satisfy such financial need. A withdrawal shall be deemed to constitute an "immediate and heavy financial need" if the Company determines that such withdrawal is on account of: (1) Expenses for medical care described in Code Section 213(d) incurred by the Participant, the Participant's spouse or dependent (as defined in Code Section 152), or expenses necessary for such persons to obtain such medical care; (2) Purchase (excluding mortgage payments) of a principal residence for the Participant; (3) Payment of tuition and related educational fees (not room and board) for the next 12 months of post-secondary education for the Participant or the Participant's spouse, children or dependents (as defined in Code Section 152); (4) The need to prevent the eviction of the Participant from the Participant's principal residence or foreclosure on the mortgage on that residence; or (5) Such other events as may be permitted pursuant to regulations promulgated by the Internal Revenue Service. A withdrawal will not be treated as necessary to satisfy an immediate and heavy financial need of a Participant to the extent the amount of such withdrawal exceeds the amount the Company determines is required to meed the financial need or to the extent the Company determines that such need may be satisfied from other resources that are reasonably available to the Participant. In making this determination, the Company may rely upon a Participant's written representation that the financial need cannot reasonably be relieved: (A) through reimbursement or compensation by insurance or otherwise; (B) by liquidation of the Participant's assets, to the extent such liquidation would not itself cause an immediate and heavy financial need; (C) by cessation of the Participant's Pre-Tax or Voluntary Contributions; or (D) by other distributions or nontaxable (at the time of the loan) loans from plans maintained by the Employer or by any other employer, or by borrowing from commercial sources on reasonable commercial terms. Absent such a representation, a withdrawal will be permitted only if the Participant shows to the satisfaction of the Company that the Participant does not have the financial ability to meet the financial hardship with other reasonable means. Such a showing shall not require a Participant to: (i) first withdraw his or her interest in another retirement plan or individual retirement account to the extent there is a tax consequence or penalty, (ii) sell or encumber the Participant's principal residence or the furnishings thereof, (iii) sell or encumber other assets if doing so would increase the amount of the financial need. A hardship withdrawal request shall be submitted in writing signed by the Participant or his legal representative, shall describe fully the circumstances which are deemed to justify the payment and the amounts necessary to alleviate the hardship, and shall be accompanied by such other documentation as may be requested by the Company. Any determination made by the Company with regard to a withdrawal pursuant to this section shall be final and binding upon the Participant. (E) The Company may require that any withdrawal pursuant to this Section 6.3 shall be made by executing a request in writing on a form provided by the Company for such purpose. Section 6.4 Diversification Options. (A) Distribution Election for Post-1986 Shares. A limited distribution to Qualified Participants is available under this Section 6.4 during the Qualified Election Period, subject to the following provisions of this section. (B) Definitions. For the purpose of this Section 6.4, the following definitions apply: (1) "Annual Election Period" refers to December 31 through March 30 of each Plan Year. (2) "Qualified Election Period" means the six-Plan Year period beginning the later of (a) the Plan Year after the Plan Year in which the Participant attains age 55; or (b) the Plan Year after the Plan Year in which the Participant first becomes a Qualified Participant. (3) "Qualified Participant" means a Participant who has attained age 55 and who has completed at least ten years of participation in the Plan. (C) Annual Withdrawal Election. Each Qualified Participant shall be permitted to withdraw whole shares of Company Stock allocated to the Participant's Basic Account due to Employer contributions after 1986, plus any income allocated to the Basic Account after 1986, including amounts contributed for a Plan Year and allocated to the Basic Account within 90 days after the end of the Plan Year. The withdrawal under this Section 6.4 for a Qualified Participant cannot exceed 25 percent of the post-1986 Company Stock in the Participant's Basic Account. In the case of the election year in which the Qualified Participant can make his last election, "50%" shall be substituted for "25%" in the preceding sentence. The maximum percentage that may be distributed for any one Plan Year shall be reduced by any amounts previously distributed pursuant to this section. (D) Election Requirements. The Participant's election to withdraw, or any revocation of such an election, must be delivered in writing to the Company on a form provided by the Company within the applicable Annual Election Period during the Participant's Qualified Election Period. No revocation is effective unless delivered before the end of the Annual Election Period in which an election to withdraw was made. The Company will not make an initial distribution under this Section unless the shares in the Participant's Basic Account as of the Investment Date preceding the applicable Annual Election Period exceed a value of $500. In addition, the first distribution under this Section pursuant to an election which requests less than 25 percent of the post-1986 Basic Account must be of a value of at least $500. The value shall be determined at the Investment Price on the Investment Date last preceding the beginning of the applicable Annual Election Period. Within 90 days after the end of each Annual Election Period the Company shall distribute shares of Company Stock, rounded to the nearest whole share, to each Qualified Participant requesting a withdrawal meeting the requirements of this Section 6.4 provided that the Company will not make such a distribution to a Participant who is no longer an Employee, but if it accidentally does so, the Company shall not be required to seek a return of the distribution, but the Company will allow the former Employee to return the distribution within 60 days after the distribution is received by the former Employee. (E) Sequence of Distribution. Any shares withdrawn from a Participant's Basic Account pursuant to this Section 6.4 shall, to the extent possible, be drawn from the subaccount in which shares acquired with Trust income are recorded. No shares will be withdrawn from a subaccount reflecting shares purchased with Employer contributions unless the whole shares allocated to the income subaccount are not sufficient to complete the distribution. Section 6.5 Rollovers and Transfers to Other Qualified Plans. Notwithstanding any provision of the Plan to the contrary that would otherwise limit a distributee's election under this Section, a distributee may elect, at the time and in the manner prescribed by the Company, to have any portion of an eligible rollover distribution equal to or greater than $200 paid directly to another eligible retirement plan specified by the distributee in a direct rollover. The following definitions shall be used in administering the provisions of this Section. (A) Eligible rollover distribution: An eligible rollover distribution is any distribution of all or any portion of the balance to the credit of the distributee, except that an eligible rollover distribution does not include: any distribution that is one of a series of substantially equal periodic payments (not less frequently than annually) made for the life (or life expectancy) of the distributee or the joint lives (or joint life expectancies) of the distributee and the distributee's designated Beneficiary, or for a specified period of ten years or more; any distribution to the extent such distribution is required under Code section 401(a)(9); and the portion of any distribution that is not includable in gross income (determined without regard to the exclusion for net unrealized appreciation with respect to employer securities). (B) Eligible retirement plan: An eligible retirement plan is an individual retirement account described in Code section 408(a), an individual retirement annuity described in Code section 408(b), an annuity plan described in Code section 403(a), or a qualified trust described in Code section 401(a), that accepts the distributee's eligible rollover distribution. However, in the case of an eligible rollover distribution to the surviving spouse, an eligible retirement plan is limited to an individual retirement account or individual retirement annuity. (C) Distributee: A distributee includes an employee or former employee. In addition, the employee's or former employee's surviving spouse or former spouse who is the alternate payee under a qualified domestic relations order, as defined in Code section 414(p), are distributees with regard to the interest of the spouse or former spouse. (D) Direct rollover: A direct rollover is a payment by the Trustee to the eligible retirement plan specified by the distributee. (E) Effective date: This section applies to distributions on or after January 1, 1993. ARTICLE VII. BENEFICIARIES Section 7.1 Surviving Spouse as Required Beneficiary. If a Participant is married at the time of death, any undistributed amount credited or to be credited to the Participant's Account shall be distributed to such surviving spouse unless the Participant has designated another Beneficiary under Section 7.2 with the contemporaneous or later written consent to such designation by the surviving spouse acknowledging the effect of such consent before a notary public. In the absence of such consent, the designation shall be void upon the death of the Participant. Unless the filed consent specifically permits further changes in a designated Beneficiary, a Participant who has designated a Beneficiary with the consent of the spouse may not subsequently change that Beneficiary without the further consent of the spouse. Section 7.2 Other Beneficiaries. Subject to the requirements of Section 7.1, a Participant may designate a Beneficiary (the Beneficiary may be more than one person or entity) to whom the balance of the Participant's Account is to be distributed in the event of the Participant's death prior to the full receipt thereof. Such a designation may, without notice to the Beneficiary, be changed or revoked by the Participant at any time. The designation of any Beneficiary and any change or revocation thereof shall be made in writing and in a form prescribed by the Company, and delivered to the Company prior to the death of the Participant. If no Beneficiary is designated or a designation is revoked in whole or in part, or if a designated Beneficiary shall not survive to receive all payments due hereunder, all or such part of the Participant's Account as has not been distributed, shall be payable to the first class of the following classes of automatic Beneficiaries then surviving and (except in the case of surviving issue) in equal shares if there are then more than one in each class: (1) Participant's surviving spouse; (2) Participant's surviving issue per stirpes; (3) Participant's surviving parents; (4) Participant's surviving brothers and sisters; (5) Executor or administrator of Participant's estate. For the purpose of the foregoing, "per stirpes" means in equal shares among living children and the issue of deceased children, the latter taking by right of representation, and issue means all persons who are descended from the person referred to, either by legitimate birth to or legal adoption by such person, or any of such person's legitimately born or legally adopted descendants. The foregoing provision shall not preclude the designation of a Beneficiary's estate or other conditional Beneficiaries in the event the first designated Beneficiary does not survive to receive full payment. Notwithstanding the foregoing, when the Beneficiary is the surviving spouse, the contingent Beneficiaries of the Participant will not be applicable as to any balance in the Account upon death of the surviving spouse if the surviving spouse prior to death delivers to the Company a specific written designation of Beneficiary in a form prescribed by the Company. Section 7.3 Presumptions. If a Beneficiary, including a surviving spouse, and the Participant die under circumstances where it is not known who died first, it will be presumed for the purpose of this Article VII, that the Participant survived the Beneficiary. If the Administrator is unable to locate an automatic or designated Beneficiary (other than a surviving spouse) within six months after death, or within 60 days prior to the contemplated initial distribution of the decedent's Account, whichever date shall last occur, the Beneficiary as of that date shall be deemed to have waived the Beneficiary's right to receive a distribution from the Plan. The distribution which would otherwise have been made to such Beneficiary shall then be made from the Plan to the contingent Beneficiary(ies) then surviving as though the missing Beneficiary did not survive the decedent. A surviving spouse who cannot be located within two years of the decedent's death shall be presumed to have not survived the decedent, and distribution of the decedent's Account shall be made to the contingent Beneficiary(ies) surviving at the time of distribution. Section 7.4 Waiver of Interest. If a Beneficiary, including a surviving spouse, waives all right to receive distribution from the Plan in writing delivered to the Administrator, the distribution shall be made to the contingent Beneficiary(ies) surviving at the time of distribution. In addition, if the Beneficiary's social security number or other information required for distribution is not delivered to the Administrator within the time designated (not less than 30 days) in a written notice sent by the Administrator to the last known address of the Beneficiary, the Beneficiary shall be deemed to have waived the Beneficiary's right to receive distribution from the Plan. ARTICLE VIII. ADMINISTRATIVE PROVISIONS Section 8.1 Company as "Named Fiduciary" May Delegate Powers and Authorities. For the purposes of ERISA, the Company shall be the "Named Fiduciary" and "Administrator" of the Plan. Except as expressly otherwise provided herein, the Company shall control and manage the operation and administration of the Plan and make all decisions and determinations incident thereto. In carrying out its Plan responsibilities, the Company shall have discretionary authority to construe the terms of the Plan. The Company may delegate its powers and authorities under the Plan and may designate any person or persons to exercise such powers and authorities in its behalf. In the delegation of such powers and authorities, the Company may authorize or limit the authority of the recipient of the delegated powers and authorities to redelegate such powers and authorities to another person or persons. The Company shall appoint a Committee with authority to deny or grant a request for withdrawal of common stock pursuant to Section 6.3. Such Committee may be contacted through the officer in charge of the Human Resources Department of the Company. Section 8.2 Facility of Payment. In case of incompetency of a Participant (including an Alternate Payee) or Beneficiary entitled to receive any distributions under the Plan, and if the Company shall be advised of the existence of such condition, the Company shall direct distribution to any one of the following: (1) To the duly appointed guardian or other legal representative of such Participant or Beneficiary; (2) To any person designated as a Beneficiary by the Participant if such Beneficiary resides in the same household as the Participant; (3) To a person or institution entrusted with the care and maintenance of the incompetent Participant or Beneficiary, provided such distributed interest will be used for the best interest and assist in the care of such Participant or Beneficiary, and provided further, that no prior claim for said payment has been made by a legal representative of such Participant or Beneficiary. Any distribution made in accordance with the foregoing provisions of this Section shall constitute a complete discharge of any liability or obligation on the part of the Company or the Trustee under the Plan and Trust. Section 8.3 Spendthrift Trust and Qualified Domestic Relations Order. (A) Benefits Unassignable. Except as hereafter provided in this Section 8.3, no Participant or Beneficiary, shall have any transferable interest in any Account nor shall any Participant or Beneficiary have any power to anticipate, alienate, dispose of, pledge or encumber the same while in the possession or control of the Trustee, nor shall the Trustee or the Company recognize any assignment thereof, either in whole or in part, nor shall any account herein be subject to attachment, garnishment, execution following judgment, or other legal process while in possession or control of the Trustee. The power to designate Beneficiaries to receive the Account of a Participant in the event of the Participant's death shall not permit, or be construed as to permit such power or right to be exercised so as thereby to anticipate, pledge, mortgage, or encumber his or her Account, and the right of a Participant to obtain or seek a withdrawal under Section 6.3 shall not permit, or be construed to permit, such a right to be exercised by a receiver, trustee or other person or entity lawfully representing the Participant except as provided by Section 8.2 for the purpose of making distributions to an incompetent former Participant, alternate payee or Beneficiary. (B) Payment Pursuant to a QDRO. Subsection 8.3(A) above shall not apply to any amounts payable with respect to a Participant pursuant to any "qualified domestic relations order" as such term is defined in Code Section 414(p). The Company shall establish reasonable written procedures to determine the qualified status of domestic relations orders and to administer distributions pursuant to such qualified orders. The Company may defer distributions from an account subject to a domestic relations order pending determination that the order is qualified. For purposes of any such order approved by the Company prior to the adoption of this amended and restated Plan document, the provisions of Section 8.3 of the Plan as in effect immediately prior to such adoption shall be deemed to remain in effect. Section 8.4 Source of Payment. Benefits under this Plan shall be payable only out of the Trust Fund. No persons shall have any rights under the Plan with respect to the Trust Fund, or against the Trustee or the Company, except as specifically provided for herein. Section 8.5 Company to Pay Administration Expenses. The Company shall pay all expenses (not including any tax obligation of the Trust) incurred in the administration of the Plan, including the compensation and expenses of the Trustee, if any. If a corporate trustee shall be acting hereunder, the corporate trustee shall be entitled to receive compensation for its services as Trustee hereunder as agreed from time to time between the Trustee and the Company. Any individual trustee who is an Employee of the Company or other Employer shall receive no compensation for services. Other individual trustees shall likewise serve without compensation except by specific agreement with the Company. However, in any event the Trustee (whether corporate or individual) shall be entitled to receive reimbursement for reasonable expenses, fees, costs, and other charges incurred on account of performing duties under the Plan and Trust. Such reimbursement may be paid directly by the Company to the Trustee, but if not so paid, the same shall be payable from and out of the Trust Fund. Section 8.6 Record Address. Each individual or entity with an actual or potential interest in an existing Account shall file and maintain a current record address with the Payroll Department of the Employer. Such record address will be furnished by the Employer to the appropriate personnel of the Company. Mailings by the Company to such record address fulfills any obligation on the part of the Company to provide required information to Participants, including former Employees and Beneficiaries, in regard to the Plan. If no record address is filed, it will be presumed that the address used by the Company in forwarding statements of a Participant's Account balance is the record address. Section 8.7 Required Information to be Furnished. Participants and Beneficiaries who may become entitled to any payment hereunder shall furnish to the Company such information as the Company considers necessary or desirable for purposes of administering the Plan, and the provisions of the Plan with respect to any payment hereunder are conditioned upon the prompt receipt by the Company of such true, full, and complete information as the Company may reasonably request. Section 8.8 Company Rules. Rules consistent with the provisions of the Plan may be adopted by the Company for the purpose of administering the Plan. Section 8.9 Claims Procedure. (A) If a Participant or other person with a claim to benefits under the Plan makes a written request for a Plan benefit, the Company shall treat it as a claim for benefit. All claims for benefits under the Plan should be sent to the officer in charge of the Human Resources Department of the Company. If the Company determines that any individual who has claimed a right to receive benefits under the Plan is not entitled to receive all or any part of the benefits claimed, it will inform the claimant in writing of its determination and the reasons therefore in terms calculated to be understood by the claimant. The notice shall make specific reference to the pertinent Plan provisions on which the denial is based, and describe any additional material or information, if any, necessary for the claimant to perfect the clam and the reason any such additional material or information is necessary. Such notice shall, in addition, inform the claimant what procedure the claimant should follow to take advantage of the review procedures set forth below in the event the claimant desires to contest the denial of the claim. (B) The claimant may within 90 days thereafter submit, in writing to the officer in charge of the Company's Human Resources Department, a notice that the claimant contests the Company's denial of claim and desires a further review. The Company shall within 60 days thereafter review the claim and authorize the claimant to appear personally and review pertinent documents and submit issues and comments relating to the claim to the persons responsible for making the determination on behalf of the Company. The Company will render its final decision with the specific reasons therefor in writing and will transmit it to the claimant within 60 days of the written request for review, unless the claimant and the Company have agreed to an extension of time. (C) No person claiming a benefit under the Plan may initiate a civil action regarding the claim until all steps under the claims procedure (including appeals) have been completed. ARTICLE IX. AMENDMENT AND TERMINATION Section 9.1 Amendment. The Company reserves the right to amend the Plan at any time. Any Plan amendment must be executed by two principal officers of the Company and attested by its Secretary or an Assistant Secretary. No amendment shall reduce or divest the Account of any Participant without the Participant's consent unless the same shall be adopted in order to comply with the applicable provisions of ERISA, the provisions of the Code, and regulations and rulings thereunder, affecting the tax qualified status of the Plan and the deductibility of Employer contributions thereto, or to comply with the provisions of any salary or wage stabilization law, regulations, orders, or directives that may now or hereafter be applicable. Section 9.2 Discontinuance of Contributions and Termination of the Plan. The Company reserves the right, by action of its Board of Directors, to discontinue its contributions to this Plan and to terminate the Plan in its entirety. Section 9.3 Limitations. No power of amendment or of full or partial termination may be exercised so as to discriminate in favor of Highly Compensated Employees or to permit any part of the assets of the Plan to be used for or diverted to purposes other than for the exclusive benefit of Participants or their Beneficiaries prior to the satisfaction of all liabilities with respect to such Participants and their Beneficiaries under this Plan. Section 9.4 Merger, Etc., with Another Plan. In case of merger or consolidation of this Plan with, or transfer of the assets and liabilities of this Plan to, any other plan, each Participant shall be entitled to a benefit immediately after the merger, consolidation, or transfer which is not less than the benefit such Participant would have been entitled to receive immediately before the merger, consolidation, or transfer if this Plan had then terminated. Section 9.5 Election to Participate by New Employer. A subsidiary corporation acquired or organized after the Effective Date which otherwise falls within the definition of Employer in Article I and which elects to participate in the Plan shall become an Employer hereunder as of the effective date of its election. Such a subsidiary corporation may elect to participate, either by action of its board of directors or by written action of two or more of its officers. Any such election shall be contingent upon the approval of the Board of Directors or the written approval of any two principal officers of the Company. The Employees of such subsidiary corporation shall, upon the effective date of such election, become Employees hereunder and shall become Participants as provided in Section 3.1(C). The election to participate in this Plan and any related merger with this Plan of a pre-existing plan of such subsidiary corporation may be contingent upon such subsidiary corporation or the Company, as Plan Administrator, receiving a determination from the Internal Revenue Service that the Plan and related Trust Agreement continue thereafter as a qualified plan and exempt trust under Section 401 and Section 501 of the Code. ARTICLE X. TRUSTEE Section 10.1 Trust Agreement. The Company shall enter into a Trust Agreement with a Trustee to be selected by the Company who shall serve at the pleasure of the Company. The Trust Agreement shall provide, among other things, for a Trust Fund to which all contributions shall be paid, and the Trustee shall have such rights, powers, and duties as are set forth in the Trust Agreement. All assets of the Trust Fund shall be held, invested, and reinvested in accordance with the provisions of the Trust Agreement and the Plan. Section 10.2 Trust Investments. The Trustee shall be responsible solely for the investment and safekeeping of the assets of the Trust Fund and shall have no responsibility for the operation or administration of the Plan, except as expressly provided herein. If the Trustee is a bank or trust company supervised by the United States or a State, assets of the Trust Fund may be invested in deposits which bear a reasonable rate of interest with such bank or trust company to the extent they are not required by the Plan to be invested in Company Stock. The Trustee shall have the authority to pay moneys to or upon the order of the Company for the use of the Plan upon requisition drawn upon the Trustee. Section 10.3 Exclusive Benefit of Participants. The Company contributions shall be held by the Trustee for the benefit of the Participants and their Beneficiaries, and no part of such contributions and no part of the respective Participant's Accounts shall be recoverable by the Company, or used for, or diverted to purposes other than for the exclusive benefit of the Participants and their Beneficiaries in accordance with the provisions of the Plan. Section 10.4 Borrowed Funds. The Trustee, the Company, or both, may enter into loan agreements where the proceeds of the loan shall be applied by the Trustee, no later than the thirtieth day after receipt of the proceeds, to purchase Company Stock or to repay a prior loan which was applied to the acquisition of Company Stock. Purchases direct from the Company shall be made at a price not in excess of the average of the high and low prices of Company Stock on the date of purchase (or if the date of purchase is not a trading date, the price on the last preceding trading date) as reported in the Wall Street Journal. Any such loan and related contracts must be primarily for the benefit of Participants and their Beneficiaries, and shall be subject to the following terms and conditions: (1) The interest rate respecting such loan shall not exceed a reasonable rate of interest. (2) The shares of Company Stock acquired with the proceeds of a loan, which proceeds may include interest earned on cash proceeds of the loan pending investment in shares, shall be held in a Suspense Account and not allocated to Accounts until released from the Suspense Account in accordance with Section 10.6. (3) The only assets of the Trust Fund which may be given as collateral for the loan are the shares of Company Stock acquired with the loan proceeds (or shares acquired with a prior loan repaid with the proceeds of current loan) and held in the Suspense Account. No person entitled to payment under such loan shall have any right to assets of the Trust Fund other than the above referred to stock in the Suspense Account and dividends or other income thereon, and any contributions made by the Company with direction for the Trustee to apply toward repayment of the loan. In the event of default on such loan, the value of Trust Fund assets transferred in satisfaction of the loan must not exceed the amount of default. Section 10.5 Dividends Applied to Loan Repayment. When a loan balance is outstanding, dividends paid on Company Stock that was acquired with the proceeds of the loan (other than dividends on shares that have been allocated to inactive Participants) shall be applied to the repayment of the Loan. Dividends on shares of such stock which are held in the Suspense Account shall be applied to any scheduled loan payment before dividends on shares which have been allocated to Participant's Accounts. To the extent dividends on shares of Company Stock that were acquired with the proceeds of a loan are insufficient to discharge in full any scheduled loan payment, then dividends on shares of Company Stock that were not acquired with the proceeds of the loan (other than dividends on shares that have been allocated to inactive Participants) shall be applied to such payment as follows: (A) Dividends paid on shares of Company Stock that were acquired by the Plan before August 5, 1989, shall be applied to the loan payment; and (B) Dividends paid on such shares of Company Stock that were acquired by the Plan after August 4, 1989, shall be applied to the loan payment to the extent directed by the Company. Dividends applied to the repayment of a loan shall first be applied to any scheduled payment of interest and then to any scheduled payment of principal (to the extent the Trustee shall elect to prepay a loan, such prepayment shall be treated as a scheduled payment for the purposes of this Section). To the extent dividends on shares that would otherwise be applied toward the repayment of the loan are in excess of a scheduled loan payment, the Trustee shall invest such excess dividends in interest bearing accounts or in similar short-term investments for credit to the Suspense Account, unless directed by the Company to acquire additional shares of Company Stock for credit to the Suspense Account. Any short-term investments shall then be applied to subsequent loan payments, provided that if such investments have not been applied prior to the ninetieth day following the end of the Plan Year in which such dividends were paid, the Trustee shall apply the balance of such investments to the purchase of Company Stock. Such stock will then be allocated to Accounts of Participants as follows: (i) shares acquired due to dividends paid on stock that was allocated to a Participant's Account shall be allocated to that Participant's Account as a dividend; and (ii) shares acquired due to dividends paid on stock held in the Suspense Account shall be allocated as a Company contribution under Section 5.2. (The preceding sentence is applicable to Plan Years beginning on or after December 31, 1994; allocations for prior years will be handled as provided in the Plan as previously in effect.) The Trustee shall not apply income from investments or Company contributions toward repayment of a loan until all dividends available for such purpose have been so applied. Section 10.6 Release from Suspense Account and Allocation of Shares. All shares of Company Stock held in the Suspense Account shall be released from the Suspense Account, and allocated to Accounts of Participants, as follows: (A) Release of Shares from Suspense Account. For each Plan Year during the duration of the loan the minimum number of shares of Company Stock acquired with the proceeds of such loan and released from the Suspense Account shall equal the number of shares acquired with the loan held at the beginning of the Plan Year (or when the loan originated if later) multiplied by a fraction. The numerator of the fraction is the amount of principal paid to the lender during the Plan Year, and the denominator of the fraction is the sum of the numerator plus the principal to be paid for all future years. The number of future years under the loan must be definitely ascertainable and must be determined without taking into account any possible extensions or renewal periods. However, the number of shares released will not be less than the number needed to make the allocations in (B). In applying the provisions of this Section 10.6(A), the following special rules shall apply: (1) The loan must provide for annual payments of principal and interest at a cumulative rate that is not less rapid at any time than level annual payments of such amounts for ten years; (2) Interest included in any payment shall be disregarded only to the extent that it does not exceed the interest that would be payable under standard loan amortization tables; and (3) If the loan is renewed, extended, or refinanced, the sum of the expired duration of the loan and the renewal, extension or new loan period shall not exceed ten years. (B) Shares Allocated to Replace Dividends. If dividends from a Participant's Account are used to make loan payments, said Account will receive an allocation of a number of shares of Company Stock equal to the shares which would have been acquired if the dividends had been used to purchase Company Stock for whichever of the following prices is less: (1) The weighted average price at purchase of the shares of Company Stock acquired with the loan proceeds. (2) The current market price of shares of Company Stock at the time the dividends were paid. Allocations at the price described in (B)(1) shall be made as soon as administratively feasible after the dividends are applied to make a loan payment. Any additional allocation required at the price described in (B)(2) shall be made annually. If the shares released under (A) are insufficient to make the foregoing allocation, the balance will be derived from Company contributions. (C) Allocation of Remaining Shares. Any remaining shares of Company Stock released from the Suspense Account after all allocations under (B) have been completed will be allocated as Company contributions as provided in Section 5.2. (D) Transition Rules. The foregoing allocation rules apply to Plan Years beginning on and after December 31, 1994. Allocations for prior years will be handled as provided in the Plan as previously in effect. Section 10.7 Non-Tradable Company Stock. If at the time of distribution, shares of Company Stock distributed from the Trust Fund are not "readily tradeable on an established market" within the meaning of Code section 409(h) and the regulations thereunder, such shares shall be subject to a put option under which all or any part of the distributed shares may be sold to the Company. The put option shall be subject to the following conditions: (1) The put option shall be exercisable only by the distributee (whether the Participant or a Beneficiary), any person to whom the Company Stock has passed by gift from the distributee and any person (including an estate or the distributee from an estate) to whom the Company Stock passed upon the death of the distributee (hereinafter referred to as the "holder"). (2) The put option must be exercised during the 60 day period beginning on the date the Company Stock is first distributed by the Plan, or during a 60 day period designated by the Company during the Plan Year following the Plan Year in which the distribution occurred. (3) To exercise the put option, the holder shall notify the Company in writing that the put option is being exercised. (4) Within 30 days after receipt of such notice, the Company shall tender to the holder a cash payment equal to the fair market value of the Company Stock, said value to be determined as of the Plan valuation date coincident with or immediately preceding exercise of the put option. (5) The Plan is not bound to purchase Company Stock pursuant to the put option, but the Trustee may cause the Plan to assume the Company's rights and obligations to acquire Company Stock under the put option. (6) The put option extended under this section shall continue in force notwithstanding that a loan is repaid or that this Plan ceases to be an employee stock ownership plan. (7) Except as provided in this section, no Company Stock acquired with the proceeds of a loan may be subject to a put, call or other option, or any buy-sell or similar arrangement, while held by or distributed from the Plan. ARTICLE XI. MISCELLANEOUS PROVISIONS Section 11.1 No Contract of Employment. Nothing contained in this Plan shall be construed as a contract of employment between an Employer and any Employee or as a right of any Employee to be continued in the employment of an Employer or as a limitation on the right of an Employer to discharge any Employee with or without cause. Section 11.2 No Guarantees on Value. Neither the Company nor the Trustee guarantees the Trust Fund in any manner against loss or depreciation. Section 11.3 Fiduciary Responsible Only For Own Acts. The Company, the Board of Directors, the Committee, or any other committee assigned by the Company to perform all or some of the administration of the Plan, the Trustee, and any person who is deemed to be a fiduciary under the Plan, will not be liable for a breach of fiduciary responsibility of another fiduciary under the Plan except to the extent (1) it shall have participated knowingly in, or knowingly undertaken to conceal, an act or omission of such fiduciary, knowing such act or omission was a breach of such fiduciary's responsibilities; (2) it shall have, through a breach of its fiduciary responsibilities, enabled such fiduciary to commit a breach of its fiduciary responsibilities; or (3) it shall have knowledge of a breach of fiduciary responsibilities by such fiduciary, unless it has made a reasonable effort to remedy the breach. Section 11.4 Company Indemnification. Employees of the Company designated by the Company to perform acts under the Plan shall be indemnified by the Company or from proceeds under insurance policies purchased by the Company against any and all liabilities arising by reason of any act, or failure to act, made in good faith pursuant to the provisions of the Plan, including expenses reasonably incurred in defense of any claim relating thereto. Section 11.5 Laws of Minnesota. The Plan shall be governed by, and construed in accordance with the laws of the State of Minnesota, except to the extent such laws are preempted by ERISA. Section 11.6 Securities Regulations. The Company reserves the right to withhold authorization of any distribution of an Account or to restrict the transfer of any shares of Company Stock distributed from an Account to the extent necessary to satisfy the requirements of any Federal or State law or regulation applicable to securities of the Company. In compliance with the Securities Act of 1933, no contributions from Participants will be accepted unless a Securities and Exchange Commission Registration Statement, if a Registration Statement is required, is effective for the issuance of securities to be issued for such contributions. Section 11.7 Contributions Conditioned on Tax Deductions. All Company contributions to the Plan are expressly conditioned upon their being deductible under Section 404 of the Code. In addition, the Company's contributions under Section 4.1, is an amount up to the deductions claimed on the Company's United States corporate income tax return pursuant to Code section 404(k), are conditioned upon receiving the deduction. To the extent that a deduction claimed for any Company contribution, or any deduction pursuant to Code section 404(k) is subsequently disallowed, the Company may withdraw its contribution conditioned on the disallowed deduction within one year after the date of disallowance. Section 11.8 Top Heavy Contingency. The provisions of Appendix A relating to a top heavy contingency shall apply if the Plan should ever become a Top Heavy Plan as defined in such Appendix for any Plan Year. Section 11.9 Tax Credit Rules. The Plan will comply with any provisions of the Code or regulations thereunder with respect to tax credit shares contributed in the past in order to qualify for an investment or payroll tax credit. APPENDIX A TOP HEAVY CONTINGENCY Notwithstanding any of the foregoing provisions of the Plan, if, after applying the special definitions set forth in Section 1 of this Appendix, this Plan is determined under Section 2 of this Appendix to be a Top Heavy Plan for a Plan Year, then the special rules set forth in Section 3 of this Appendix shall apply. For so long as this Plan is not determined to be a Top Heavy Plan, the special rules in Section 3 of this Appendix shall be inapplicable to this Plan. Section 1. Special Definitions. Terms defined in the Plan shall have the same meanings when used in this Appendix. In addition, when used in this Appendix, the following terms shall have the following meanings: 1.1 Aggregated Employers -- the Employer and each other corporation, partnership or proprietorship which is a "predecessor" to the Employer, or is under "common control" with the Employer, or is a member of an affiliated service group that includes the Employer, as those terms are defined in section 414(b), (c) or (m) of the Code. 1.2 Aggregation Group -- a grouping of this plan and each other qualified pension, profit sharing or stock bonus plan, regardless of whether the plan has terminated (including any qualified defined benefit plan which, during the five-year period ending on the Determination Date, has or has had any accrued benefits) of the Aggregated Employers: (a) in which a Key Employee is a Participant; and (b) which is required to be taken into account for this Plan to satisfy the qualification requirement that this Plan cover a nondiscriminatory group of employees (i.e., either the so-called "70% test," the "70%/80% test" or the nondiscriminatory classification test"); and (c) which is not included in paragraph (a) or (b) above, but which the Employer elects to include in the Aggregation Group and which, when included, would not cause the Aggregation Group to fail to satisfy the qualification requirement that the Aggregation Group of plans cover a nondiscriminatory group of employees (i.e., either the so-called "70% test", the "70/80% test" or the "nondiscriminatory classification test"). 1.3 Determination Date -- for the first (1st) plan year of a plan, the last day of such first (1st) plan year, and for each subsequent plan year, the last day of the immediately preceding plan year. 1.4 Five Percent Owner -- for each Aggregated Employer that is a corporation, any person who owns (or is considered to own within the meaning of the Shareholder Attribution Rules) more than five percent (5%) of the outstanding stock of the corporation or stock possessing more than five percent (5%) of the total combined voting power of the corporation, any person who owns more than five percent (5%) of the capital interest or the profits interest in such Aggregated Employer. For the purposes of determining ownership percentages, each corporation, partnership and proprietorship otherwise required to be aggregated shall be viewed as a separate entity. 1.5 Key Employee -- each Participant (whether or not then an employee) who at any time during a plan year (or any of the four preceding plan years) is: (a) an officer of any corporate Aggregated Employer having annual Testing Wages for any such plan year in excess of 150% of the amount in effect under Code section 415(c)(1)(A) for any such plan year, or (b) one of the 10 employees (not necessarily Participants) owning (or considered to own within the meaning of the Shareholder Attribution Rules) the largest interests in any of the Aggregated Employers (which are owned by employees) and who has annual Testing Wages in excess of the limitation in effect under section Code 415(c)(1)(A) for any such plan year, or (c) a Five Percent Owner, or (d) a One Percent Owner having an annual Testing Wages of more than $150,000; provided, however, that no more than 50 employees shall be treated as officers. For the purposes of determining ownership percentages, each corporation, partnership and proprietorship otherwise required to be aggregated shall be viewed as a separate entity. For purposes of paragraph (b) above, if two employees have the same interest in any of the Aggregated Employers, the employee having the greatest annual total compensation from that Aggregated Employer shall be treated as having a larger interest. The term "Key Employee" shall include the beneficiaries of a deceased Key Employee. 1.6 One Percent Owner -- for each Aggregated Employer that is a corporation, any person who owns (or is considered to own within the meaning of the Shareholder Attribution Rules) more than one percent (1%) of the outstanding stock of the corporation or stock possessing more than one percent (1%) of the total combined voting power of the corporation, and, for each Aggregated Employer that is not a corporation, any person who owns more than one percent (1%) of the capital or the profits interest in such Aggregated Employer. For the purposes of determining ownership percentages, each corporation, partnership and proprietorship otherwise required to be aggregated shall be viewed as a separate entity. For the purposes of determining Testing Wages, however, all compensation received from all Aggregated Employees shall be taken into account. 1.7 Shareholder Attribution Rules -- the rules of section 318 of the Code, except that subparagraph (C) of section 318(a)(2) of the Code shall be applied by substituting "5 percent" for "50 percent" or, if the Employer is not a corporation, the rules determining ownership in such Employer which shall be set forth in regulations prescribed by the Secretary of the Treasury. 1.8 Top Heavy Aggregation Group -- any Aggregation Group for which, as of the Determination Date, the sum of: (i) the present value of the cumulative accrued benefits for Key Employees under all defined benefit plans included in such Aggregation Group; and (ii) the aggregate of the accounts of Key Employees under all defined contribution plans included in such Aggregation Group, exceed sixty percent (60%) of a similar sum determined for all employees. In applying the foregoing, the following rules shall be observed: (a) For the purpose of determining the present value of the cumulative accrued benefit for any employees under a defined benefit plan, or the amount of the account of any employee under a defined contribution plan, such present value or amount shall be increased by the aggregate distributions made with respect to such employee under the plan during the five (5) year period ending on the Determination Date. (b) Any rollover contribution (or similar transfer) initiated by the employee and made after December 31, 1983, to a plan shall not be taken into account with respect to the transferee plan for the purpose of determining whether such transferee plan is a Top Heavy Plan (or whether any Aggregation Group which includes such plan is a Top Heavy Aggregation Group). (c) If any individual is not a Key Employee with respect to a plan for any plan year, but such individual was a Key Employee with respect to a plan for any prior plan year, the cumulative accrued benefit of such employee and the account of such employee shall not be taken into account. (d) The determination of whether a plan is a Top Heavy Plan shall be made once for each plan year of the plan as of the Determination Date for that plan year. (e) In determining the present value of the cumulative accrued benefits of employees under a defined benefit plan, the determination shall be made as of the actuarial valuation date last occurring during the twelve (12) months preceding the Determination Date and shall be determined on the assumption that the employees terminated employment on the valuation date. In determining this present value, the mortality and interest assumptions shall be those which would be used by the Pension Benefit Guaranty Corporation in valuing the defined benefit plan if it terminated on such valuation date. The accrued benefit to be valued shall be the benefit expressed as a single life annuity. (f) In determining the accounts of employees under a defined contribution plan, the account values determined as of the most recent asset valuation occurring within the twelve (12) month period ending on the Determination Date shall be used. In addition, amounts required to be contributed under either the minimum funding standards or the plan's contribution formula shall be included in determining the account. In the first year of the plan, contributions made or to be made as of the Determination Date shall be included even if such contributions are not required. 1.9 Top Heavy Plan -- a qualified plan under which (as of the Determination Date): (i) If the plan is a defined benefit plan, the present value of the cumulative accrued benefits for Key Employees exceed sixty percent (60%) of the present value of the cumulative accrued benefits for all employees; and (ii) If the plan is a defined contribution plan, the aggregate of the accounts of Key Employees exceeds sixty percent (60%) of the aggregate of all of the accounts of all employees. In applying the foregoing, the following rules shall be observed: (a) Each plan of an Employer required to be included in an Aggregation Group shall be a Top Heavy Plan if such Aggregation Group is a Top Heavy Aggregation Group. (b) For the purpose of determining the present value of the cumulative accrued benefit for any employee under a defined benefit plan, or the amount of the account of any employee under a defined benefit plan, or the amount of the account of any employee under a defined contribution plan, such present value or amount shall be increased by the aggregate distributions made with respect to such employee under the plan during the five (5) year period ending on the Determination Date. (c) The rules in subsections (b) through (f) of Section 1.8 are applicable. (d) For the purpose of determining if the Plan, or any other plan included in a required aggregation group of which this Plan is a part, is top heavy, the accrued benefit of an Employee other than a Key Employee shall be determined under: (i) the method, if any, that uniformly applies for accrual purposes under all plans maintained by the Aggregated Employers, or (ii) if there is no such method, as if such benefit accrued not more rapidly than the slowest accrual rate permitted under the fractional accrual rate of Code section 411(b)(1)(C). Section 2. Determination of Top Heaviness. Once each Plan Year, as of the Determination Date for that Plan Year, the administrator of this Plan shall determine if this Plan is a Top Heavy Plan. Section 3. Contingent Provisions. 3.1 When Applicable. If this Plan is determined to be a Top Heavy Plan for any Plan Year, the following provisions shall apply for that Plan Year (and, to the extent hereinafter specified, for subsequent Plan Years), notwithstanding any provisions to the contrary in the Plan. 3.2 Defined Contribution Plan Minimum Benefit Requirement. 3.2.1 General Rule. If this Plan is a defined contribution plan, then for any Plan Year that this Plan is determined to be a Top Heavy Plan, the Employer shall make a contribution for allocation to the account of each employee who is a Participant for that Plan Year and who is not a Key Employee in an amount (when combined with other Employer contributions and forfeited accounts allocated to his account) which is at least equal to three percent (3%) of such Participant's Testing Wages. This contribution shall be made for each Participant who has not separated from service with the Employer at the end of the Plan Year including, for this purpose, each Participant who, under other Plan provisions, would have received no contribution, or would have received a lesser contribution, for the Plan Year because he or she: (a) completed fewer than one thousand (1,000) Hours of Service (or the equivalent) during the Plan Year, or (b) failed to make mandatory contributions to the Plan, or (c) earned compensation which was less than the stated amount required to receive a full contribution under the Plan, but only if such Participant must be counted as a Participant in order for this Plan to satisfy the qualification requirement that the Plan cover a nondiscriminatory group of employees (i.e., the so-called "70% test," the "70/80% test" or the "nondiscriminatory classification test"). 3.2.2 Special Rule. Subject to the following rules, the percentage referred to in Section 3.2.1 of this Appendix shall not exceed the percentage at which contributions are made (or required to be made) under this Plan for the Plan Year for that Key Employee for whom that percentage is the highest for the Plan Year. (a) The percentage referred to above shall be determined by dividing the Employer contributions for such Key Employee for such Plan Year by his Testing Wages. (b) For the purposes of this Section 3.2, all defined contribution plans required to be included in an Aggregation Group shall be treated as one plan. (c) The exception contained in this Section 3.2.2 shall not apply to (be available to) this Plan if this Plan is required to be included in an Aggregation Group if including this Plan in an Aggregation Group enables a defined benefit plan to satisfy the qualification requirement that the defined benefit plan cover a nondiscriminatory group of employees (i.e., either the so-called "70% test", the "70/80% test" or the nondiscriminatory classification test"). 3.2.3 Salary Reduction. Salary reduction contributions made by key employees under Code section 401(k) are taken into account, but salary reduction contributions by non-key employees are disregarded. 3.3 Priorities Among Plans. In applying the minimum benefit provisions of this Appendix in any Plan Year that this Plan is determined to be a Top Heavy Plan, the following rules shall apply: (a) If an employee participates only in this Plan, the employee shall receive the minimum benefit applicable to this Plan. (b) If an employee participates in both a defined benefit plan and a defined contribution plan and only one (1) of such plans is a Top Heavy Plan for the Plan Year, the employee shall receive the minimum benefit applicable to the plan which is a Top Heavy Plan. (c) If an employee participates in both a defined contribution plan and a defined benefit plan and both are Top Heavy Plans, then the employee, for that Plan Year, shall receive the defined benefit plan minimum benefit unless for that Plan Year the employee has received employer contributions and forfeitures allocated to his account in the defined contribution plan in an amount which is at least equal to five percent (5%) of his total compensation. 3.4 Annual Contribution Limits. If a Participant is also a participant in a defined benefit plan maintained by the employer, with respect to any Plan Year for which the Plan is a Top Heavy Plan, Section 5.3 of the Plan shall be applied by substituting "1.0" for "1.25" in paragraphs (2)(B) and (3)(B) of Code section 415(e), and by substituting "$41,500" for "$51,875" in Code section 415(e)(6)(B)(i). The foregoing provisions of this section shall be suspended with respect to any individual so long as there are no employer contributions or forfeitures allocated to such individual, and no defined benefit plan accruals for such individual, either under this Plan or under any other plan that is in a required aggregation group of plans, within the meaning of Code section 416(g)(2)(A)(i), that includes this Plan. 3.5 Exception For Collective Bargaining Unit. Section 3.2 shall not apply with respect to any employee included in a unit of employees covered by an agreement which the Secretary of Labor finds to be a collective bargaining agreement between employee representatives and one or more employers if there is evidence that retirement benefits were the subject of good faith bargaining between such employee representative and such employer or employers. EX-10 3 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 10.01The 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. 10.02The 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. 10.03The 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. 10.04The 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. 10.05The 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". 10.06The Engineering Committee may establish subcommittees and assign duties consistent with this Agreement and policies of the Management Committee. 10.07The 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. 10.08Any 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 11.01The 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. 11.02The 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. 11.03The 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. 11.04The 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. 11.05The 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. 11.06Any 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 12.01The 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. 12.02The 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. 12.03The 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. 12.04To 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 13.01The Environmental Committee shall be appointed by the Management Committee. In selection of such representatives, consideration shall be given to geographic representation. 13.02The 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. 13.03The 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. 13.04Under 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. 13.05The 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. 13.06The Environmental Committee may establish subcommittees and task forces and assign duties as necessary to carry out its assigned functions. ARTICLE XIV AREA RELATIONS COMMITTEE 14.01The 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. 14.02The 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. 14.03The 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. 14.04Under 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. 14.05The Committee shall meet as required on call of the Committee Chairman or the Management Committee. ARTICLE XV MAPP COORDINATION CENTER 15.01The 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. 15.02Consistent 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. 15.03Each 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. 15.04Each 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. 15.05Subject 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. 15.06In 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. 15.07The 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 16.01Each 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. 16.02The 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. 16.03The 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. 16.04The 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. 16.05Nothing 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 17.01It 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. 17.02It 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 18.01Each 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. 18.02The 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. 18.03The 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 19.01The 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 19.02The 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. 19.03The 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 20.01It 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. 20.02Any 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." 20.03Any 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. 20.04Any 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. 20.05Any 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. 20.06Any 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. 20.07Any 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." 20.08Any 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." 20.09Any 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." 20.10Each 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". 20.11The 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. 20.12The 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 21.01The 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. 21.02The 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. 21.03It 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 22.01All 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. 22.02Should 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 23.01In 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. 23.02Each 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 24.01For 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. 24.02Billing 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. 24.03All 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. 24.04Billing for Transmission Service shall be rendered monthly in a manner to be determined by the Operating Committee. 24.05In 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. 24.06All 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 25.01Any 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 26.01A 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 27.01Any 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 28.01Any 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. 28.02Any 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 29.01No 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. 29.02The 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 30.01Any 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. 30.02The 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 31.01In 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 32.01This Agreement is subject to the regulation of any regulatory body having jurisdiction thereof. ARTICLE XXXIII AMENDMENTS 33.01Any 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. 33.02In 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 34.01Northern 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. 34.02Minnesota 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 35.01The 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. 35.02The 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. 35.03Contingent 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. 35.04Officials 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. 35.05Covenant 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. 35.06Utility 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. 35.07Membership 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. 35.08Rate 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. 35.09Area 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. 35.10Provisions 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 36.01The 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. 36.02The 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. 36.03It 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. 36.04The reliability characteristics of Manitoba Hydro's generating facilities, which are predominantly hydroelectric, shall be considered when establishing Manitoba Hydro's Reserve Capacity Obligation. 36.05It 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 POWERDISTRICT 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 AGENCY PIERRE HEROUX (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 COOPERATIVE ASSOCIATION RONALD L. DEIBER (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-10 4 Exhibit 10.12 FINAL NSP SEVERANCE PLAN (As Amended and Restated Effective November 1, 1989) TABLE OF CONTENTS Section Page 1 Purpose 1 2 Effective Date 1 3 Definitions 1 4 Eligibility for Benefits 2 5 Amount of Benefits 3 6 General Release 5 7 Notice Requirement 5 8 Non-Alienation of Benefits 5 9 Fund 6 10 Employment Rights 6 11 Administration 6 12 Claim Procedure 6 13 Headings 8 14 Amendment and Termination 8 15 Applicable 8 NSP SEVERANCE PLAN Section 1. Purpose. The purpose of the Plan is to provide severance benefits to Employees whose employment with Northern States Power Company, a Minnesota corporation, ("NSP") and its subsidiaries is terminated in accordance with the terms and conditions of the Plan. Section 2. Effective Date. The Plan was established by NSP effective as of June 1, 1987 and was formerly known as the "NSP Transitional Employee Plan." The Plan, as stated herein, is amended, restated and renamed the "NSP Severance Plan," effective November 1, 1989. Section 3. Definitions. As used herein: "Annual Salary" means the Employee's regular annual base salary immediately prior to his or her Termination, including compensation converted to other benefits under a flexible pay arrangement maintained by the Company or deferred pursuant to a written agreement with the Company. The term shall exclude overtime pay, allowance, premium pay, compensation paid or payable under any Company's long-term or short-term incentive plan or any payment found by NSP to be similar thereto. "Company" means Northern States Power Company, a Minnesota corporation ("NSP") and any subsidiary of NSP which makes the Plan available to its Employees. "Employee" means any full-time, regular-benefit, non-bargaining employee of the Company. The term shall exclude an individuals employed as independent contractors, temporary employees, other benefit employees, non-benefit employees, leased employees, even if it is subsequently determined that such classification is incorrect. "Month of Salary" means the Annual Salary of an Employee divided by twelve (12). "Plan" means this NSP Severance Plan, as set forth herein and as amended from time to time. "Termination" means an Employee's termination of employment from NSP and its subsidiaries. "Two Years' Pay" means twice the Employee's "annual compensation" during the calendar year immediately preceding his or her Termination. Such annual compensation will include compensation reported on Form W-2; any compensation converted to other benefits under a flexible pay arrangement maintained by the Company or deferred pursuant to a written agreement with the Company; and any other benefit of monetary value, whether in cash or otherwise, which was paid as consideration for services for the Employee's service during such year. "Week of Salary" means the Annual Salary of an Employee divided by fifty- two (52). "Year of Service" means a year of "pensionable service" under the Northern States Power Company Pension Plan. Section 4. Eligibility for Benefits. An Employee shall be eligible for severance benefits, as described in Section 5, if: (a) the Employee's Termination resulted from (i) the elimination of a job position; (ii) a reorganization, realignment or elimination of certain job functions or activities; (iii) a reduction in workforce; or (iv) the Employee's inability, for reasons beyond his or her control, to perform the duties of his or her job; and (b) such Termination was not caused by (i) death or disability; (ii) voluntary resignation by the Employee, provided, that a Termination shall not be deemed to be a voluntary resignation if an Employee requests Termination under circumstances described in Subsection 4(a) and the Company, in its sole discretion, approves such request; (iii) termination of employment for cause, including but not limited to unsatisfactory performance or behavior; or (iv) the sale of operations to an employer who offers continued employment to the Employee; and (c) the Employee (i) is not a temporary employee or classified as an "other benefit" or "non-benefit employee" or similar classification; (ii) is not covered by a collective bargaining agreement; (iii) has not been re-employed by an Employer; and (iv) is not the recipient of any individual agreement or understanding that provides for severance benefits upon such Termination. Section 5. Amount of Benefits. The severance benefits of an Employee who meets the eligibility requirements of Section 4 shall be subject to a maximum benefit of Two Years' Pay and shall be as follows: (a) Cash Payments: (i) Basic Benefits. An amount equal to two (2) Months of Salary of the Employees. (ii) Enhanced Benefits. An amount equal to the greater of (A) two (2) Weeks of Salary of the Employee for each whole Year of Service and a proportionate share thereof for any partial Year of Service; or (B) one (1) Week of Salary of the Employee for each full $2,000.00 of Annual Salary and a proportionate share thereof of any partial amount thereof; provided, however, that an Employee shall receive the Enhanced Benefits described under this Subsection 5(a)(ii) only if he or she signs a General Release as described in Section 6. The period that an Employee is eligible to receive severance benefits under Subsections 5(a)(i) and (ii) above shall hereafter be referred to as the "Severance Period." (iii) Incentive Pay. An amount, if any, equal to the incentive award an Employee would have received for the Severance Period under the Executive Annual Incentive Compensation Plan, the Management Annual Compensation Plan, or the Power of Performance Incentive Plan, as applicable, if his or her employment with the Company had continued during the Severance Period and such award was based on the applicable plan year-end results and an individual performance level of 1.0. (iv) Form of Payment. Basic and Enhanced Benefits, if any, shall be paid monthly on successive months commencing the month following Termination. Incentive Pay, if any, shall be paid when incentive awards are paid under the applicable incentive plan. Notwithstanding any other provision of the Plan to the contrary, in no event shall cash payments under Subsection 5(a) be paid more than 24 months after an Employee's Termination. (b) Group Insurance. Coverage under the NSP's Medical Plan (or Health Maintenance Organizations), the NSP Group Dental Program and the NSP Group Life Insurance Plan during the Severance Period upon the payment of any required premiums. (c) Outplacement. Outplacement services, as selected by the Company, shall be provided to an Employee. Section 6. General Release. Notwithstanding any other provision of this Plan to the contrary, to receive the Enhanced Benefits described in Subsection 5(a)(ii), an Employee must sign a General Release, in such form as determined by NSP, which releases NSP and its subsidiaries from any and all claims except as such claims relate directly to the payment of any benefit due under this Plan or benefits payable under any other plan or agreement of the Company unrelated to severance benefits. Section 7. Notice Requirement. Receipt by an Employee of the Basic Benefits described in Subsection 5(a)(i) shall, with respect to such Employee, constitute full satisfaction of all termination pay requirements of any kind under any federal or state law, including without limitation, advance notification of layoffs or similar notice requirements. Section 8. Non-Alienation of Benefits. No rights under the Plan shall be assignable, either voluntarily, or involuntarily by way of encumbrance, pledge, attachment, levy or change of any nature, except as may be required by federal or state law. If an Employee receiving cash severance benefits dies before all payments are paid, the remaining of such benefits shall be paid to the Employee's estate. Section 9. Fund. This Plan is unfunded and no fund is being set aside or allocated specifically for the purpose of the Plan. Benefits shall be paid by the Company out of operating funds against which the former Employee shall have no greater claim than any other general creditor of NSP and its subsidiaries. Section 10. Employment Rights. The Plan shall not interfere with the right of the Company to discharge any employee at any time, nor shall the Plan be construed so as to create as to any employee a contract, promise, or guarantee of employment for any particular position or assignment, or at any particular level of compensation or benefits. Section 11. Administration. The Plan shall be administered by NSP which shall have sole and absolute discretion in: (a) determining all questions relating to Plan eligibility and benefits; (b) adopting rules and procedures to administer the Plan; and (c) interpreting Plan provisions. The interpretation by NSP of the terms and provisions of the Plan and the administration thereof, and all action taken by NSP, shall be final, binding and conclusive on all employees and other persons claiming under or through any of them, unless it is found by a court of competent jurisdiction to have been arbitrary and capricious. Section 12. Claim Procedure. If an Employee or former Employee makes a written request alleging a right to receive benefits under this Plan or alleging a right to receive an adjustment in benefits being paid under the Plan, NSP shall treat it as a claim for benefit. All claims for benefit under the Plan shall be sent to the Human Resources Department of NSP and must be received within 30 days after termination of employment. If NSP determines that any individual who has claimed a right to receive benefits, or different benefits, under the Plan is not entitled to receive all or any part of the benefits claimed, it will inform the claimant in writing of its determination and the reasons therefor in terms calculated to be understood by the claimant. The notice will be sent within 90 days of the claim unless NSP determines additional time, not exceeding 90 days, is needed. The notice shall make specific reference to the pertinent Plan provisions on which the denial is based, and describe any additional material or information, if any, necessary for the claimant to perfect the claim and the reason any such additional material or information is necessary. Such notice shall, in addition, inform the claimant what procedure the claimant should follow to take advantage of the review procedures set forth below in the event the claimant desires to contest the denial of the claim. The claimant may within 90 days thereafter submit in writing to NSP a notice that the claimant contests the denial of his or her claim by NSP and desires a further review. NSP shall within 60 days thereafter review the claim and authorize the claimant to appear personally and review pertinent documents and submit issues and comments relating to the claim to the persons responsible for making the determination on behalf of NSP. NSP will render its final decision with specific reasons therefore in writing and will transmit it to the claimant within 60 days of the written request for review, unless NSP determines additional time, not exceeding 60 days, is needed. Section 13. Headings. Headings are given to the Sections of the Plan solely as a convenience to facilitate reference. Such headings nor numbering or paragraphing shall be deemed in any way material or relevant to the construction of the Plan or any provision thereof. Section 14. Amendment and Termination. NSP reserves the right to amend or terminate this Plan at any time by a written instrument executed by any Vice President and by the Secretary or any Assistant Secretary of NSP. Any amendment or termination of the Plan shall be solely prospective in impact and shall not adversely affect any severance benefit in pay status. Section 15. Applicable. The provisions of this Plan shall be governed and enforced in accordance with the laws of Minnesota except to the extent superseded by applicable federal law. IN WITNESS WHEREOF, Northern States Power Company, a Minnesota corporation, has caused this Plan to be made and signed and its corporate seal to be hereunto affixed by its duly authorized officers, effective as of November 1, 1989. NORTHERN STATES POWER COMPANY By (John A. Noer) John A. Noer Vice President, Human Resources Counsel ATTEST: (Arland D. Brusven) Arland D. Brusven Secretary and Financial NSP SEVERANCE PLAN Amendment of Supplement A Pursuant to Section 14 of the NSP Severance Plan ("Plan"), the undersigned officers of Northern States Power Company, a Minnesota corporation, hereby amend the Plan effective January 1, 1993 by deleting Supplement A as in effect immediately prior to that date and by adopting the following Supplement A: SUPPLEMENT A Notwithstanding anything in Section 4 of the Plan to the contrary, an Employee whose Termination occurs on or after January 1, 1993 as a result of a reorganization of all or a portion of the department in which the employee works will not fail to be eligible for severance benefits solely because the Employee is offered a "noncomparable job" after commencement of the reorganization and on or before the date of the Employee's Termination. For purposes of this Supplement A a "noncomparable job" is a job that either: a. has a starting Annual Salary that is less than 90 percent of the Employee's Annual Salary at the time of Termination, or b. relocates the Employee's primary work site to a place that is more than 50 miles from the Employee's previous primary work site. The definitions contained in the Plan shall apply to this Supplement A. Except as expressly provided herein, the terms of the Plan in effect immediately prior to adoption of this Supplement A shall remain unchanged. IN WITNESS WHEREOF, Northern States Power Company, a Minnesota corporation, has caused this amendment to be signed by its duly authorized officers this 17th day of June, 1993. NORTHERN STATES POWER COMPANY By: (Cynthia L. Lesher) Its: Vice President-Human Resources By: (Hollies M. Winston) Its: Vice President, Corporate Secretary & Financial Counsel NSP SEVERANCE PLAN Amendment of Definition of Annual Salary Pursuant to Section 14 of the NSP Severance Plan ("Plan"), the undersigned officers of Northern States Power Company, a Minnesota corporation, hereby amend the definition of Annual Salary in Section 3 of the Plan, effective January 1, 1994, to read as follows: "Annual Salary" means the Employee's regular annual base salary immediately prior to his or her Termination or, in the case of an Employee who is a participant in NSP's Staffing Transition Program at the time of Termination, the Employee's regular annual base salary immediately prior to such participation. "Annual Salary" shall include compensation converted to other benefits under a flexible pay arrangement maintained by the Company or deferred pursuant to a written agreement with the Company. The term shall exclude overtime pay, allowances, premium pay, compensation paid or payable under any Company long-term or short-term incentive plan or any payment found by NSP to be similar thereto. IN WITNESS WHEREOF, Northern States Power Company, a Minnesota corporation, has caused this amendment to be signed by its duly authorized officers this day of February, 1994. NORTHERN STATES POWER COMPANY By: (Cynthia L. Lesher) Its: Vice President of Human Resources By: (Chandra G. Houston) Its: Assistant Corporate Secretary NSP SEVERANCE PLAN Amendment to Eliminate Post-Termination Incentive Compensation Pursuant to Section 14 of the NSP Severance Plan ("Plan"), the undersigned officers of Northern States Power Company, a Minnesota corporation, hereby amend the Plan, effective May 1, 1994, by deleting paragraphs (iii) and (iv) of subsection (a) of Section 5 of the Plan, and by inserting in lieu thereof, the following: (iii) Form of Payment. Basic and Enhanced Benefits, if any, shall be paid monthly on successive months commencing the month following Termination; provided, however, that if earlier commencement is administratively feasible and NSP in its sole discretion consents, such benefits may commence no earlier than the end of the month in which Termination occurred. Notwithstanding any other provision of the Plan to the contrary, in no event shall cash payments under Subsection 5(a) be paid more than 24 months after an Employee's Termination. IN WITNESS WHEREOF, Northern States Power Company, a Minnesota corporation, has caused this amendment to be signed by its duly authorized officers this 28th day of April, 1994. NORTHERN STATES POWER COMPANY By: (Cynthia L. Lesher) Its: Vice President - Human Resources By: (Sutton A. Plombon) Its: Assistant Secretary EX-12 5
Exhibit 12.01 NORTHERN STATES POWER COMPANY AND SUBSIDIARY COMPANIES STATEMENT OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES 1994 1993 1992 1991 1990 (Thousands of dollars) Earnings Income from continuing operations before accounting change $243,475 $211,740 $160,928 $207,012 $192,971 Add Taxes based on income (1) Federal income taxes 114,484 99,952 71,549 75,905 120,686 State income taxes 34,805 28,076 19,148 22,209 34,442 Deferred income taxes-net (2,262) 12,256 5,185 26,506 (31,794) Investment tax credit adjustment - net (13,979) (9,544) (9,708) (9,189) (10,048) Foreign income taxes 219 Fixed charges 115,083 113,562 109,888 110,146 111,826 Deduct Undistributed equity in earnings of unconsolidated investees 27,427 1,142 1,006 0 1,876 Earnings $464,398 $454,900 $355,984 $432,589 $416,207 Fixed charges Interest charges per statement of income $115,083 $113,562 $109,888 $110,146 $111,826 Ratio of earnings to fixed charges 4.0 4.0 3.2 3.9 3.7 (1) Includes income taxes included in Other Income and Deductions - Net.
EX-21 6 Exhibit 21.01 NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES Subsidiaries of Registrant Name State of Incorporation Purpose Northern States Power Company (Wisconsin) Wisconsin Electric and gas utility First Midwest Auto Park, Inc. Minnesota Owns and manages a parking ramp United Power and Land Company Minnesota Real estate holding company Cormorant Corporation Montana Former owner of interest in coal and lignite properties NRG Energy, Inc. Delaware Owns and manages non- regulated energy subsidiaries of the Company Cenergy, Inc. Minnesota Natural gas marketing and energy services Viking Gas Transmission Company Delaware Natural gas transmission Eloigne Company Minnesota Owns and operates affordable housing units EX-23 7 Exhibit 23.01 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement No. 2-74630 on Form S-16 and Registration Statement Nos. 33-43812 and 33-54534 on Form S-3 (relating to the Northern States Power Company Dividend Reinvestment and Stock Purchase Plan), Registration Statement No. 2-61264 on Form S-8 (relating to the Northern States Power Company Employee Stock Ownership Plan), Registration Statement No. 33-38700 on Form S-8 (relating to the Northern States Power Company Executive Long-Term Incentive Award Stock Plan), and in Registration Statement No. 33-51593 on Form S-3 (relating to the Northern States Power Company $600,000,000 Principal Amount of First Mortgage Bonds) of our report dated February 8, 1995, which expresses an unqualified opinion and includes an explanatory paragraph relating to the change in method of accounting for postretirement health care costs in 1993 appearing in this Annual Report on Form 10-K of Northern States Power Company for the year ended December 31, 1994. DELOITTE & TOUCHE LLP Minneapolis, Minnesota March 27, 1995 EX-27 8
UT This schedule contains summary financial information extracted from the Statements of Income, Balance Sheets, Statements of Capitalization, Statements of Changes in Common Stockholders' Equity and Statements of Cash Flows and is qualified in its entirety by reference to such financial statements. 1,000 12-MOS DEC-31-1994 DEC-31-1994 PER-BOOK 4,273,652 519,757 665,227 357,576 137,359 5,953,571 167,305 545,875 1,183,191 1,896,967 0 240,469 1,463,354 3,660 0 234,779 157,706 0 0 0 1,957,232 5,953,571 2,486,547 133,266 2,049,001 2,178,229 308,318 46,410 350,690 107,215 243,475 12,364 231,111 175,292 97,143 500,556 3.46 0 NOTE 1 - $596 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. NOTE 2 - $4.038 million of non-operating income taxes are classified as Income Tax Expense. The financial statement presentation includes them as a component of Other Income and Deductions-Net.
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