================================================================================ 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, 1997 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 ------------------- ------------------------------ 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 Trust Originated Preferred Securities 7 7/8% 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. _X_ 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, 1998, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $4,307,021,119 and there were 74,867,560 shares of common stock outstanding, $2.50 par value. DOCUMENTS INCORPORATED BY REFERENCE The Registrant's Definitive Proxy Statement for its 1998 meeting of Shareholders to be held on April 22, 1998, is incorporated by reference into Part III of Form 10-K ================================================================================
INDEX ================================================================================ Page No. -------- PART I - ------ Item 1 - Business..............................................................1 TERMINATION OF PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION............1 UTILITY REGULATION AND REVENUES General..................................................................2 Revenues.................................................................2 General Rate Filings.....................................................3 Ratemaking Principles in Minnesota and Wisconsin.........................3 Fuel and Purchased Gas Adjustment Clauses in Effect......................4 Resource Adjustment Clauses in Effect....................................5 Rate Matters by Jurisdiction.............................................5 ELECTRIC UTILITY OPERATIONS Competition..............................................................8 Technological Improvements..............................................11 Capability and Demand...................................................11 Energy Sources..........................................................14 Fuel Supply and Costs...................................................14 Nuclear Power Plants - Licensing, Operation and Waste Disposal..........16 Electric Operating Statistics...........................................19 GAS UTILITY OPERATIONS Competition/Regulation..................................................20 Business Growth.........................................................21 Business Standards......................................................21 Standards of Conduct/Restructuring......................................22 Capability and Demand...................................................22 Gas Supply and Costs....................................................23 Viking Gas Transmission Company ........................................24 Gas Operating Statistics ...............................................25 NON-REGULATED SUBSIDIARIES NRG Energy, Inc. .......................................................26 Energy Masters International, Inc. .....................................29 Eloigne Company.........................................................29 Seren Innovations, Inc..................................................30 Ultra Power Technologies, Inc...........................................30 Non-Regulated Business Information......................................31 ENVIRONMENTAL MATTERS......................................................32 CAPITAL SPENDING AND FINANCING.............................................34 EMPLOYEES AND EMPLOYEE BENEFITS............................................34 EXECUTIVE OFFICERS.........................................................35 Item 2 - Properties...........................................................37 Item 3 - Legal Proceedings....................................................38 Item 4 - Submission of Matters to a Vote of Security Holders..................39 PART II - ------- Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters............................................................39 Item 6 - Selected Financial Data..............................................40 Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations..............................41 Item 8 - Financial Statements and Supplementary Data..........................50 Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..............................72 PART III - -------- Item 10 - Directors and Executive Officers of the Registrant..................72 Item 11 - Executive Compensation..............................................72 Item 12 - Security Ownership of Certain Beneficial Owners and Management......72 Item 13 - Certain Relationships and Related Transactions......................72 PART IV - ------- Item 14 - Exhibits, Financial Statement Schedules, and Reports on Form 8-K....73 SIGNATURES....................................................................78 - ---------- EXHIBIT (EXCERPT) - ----------------- Statement Pursuant to Private Securities Litigation Reform Act of 1995........79
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., a Delaware corporation (NRG). The Company also has several other subsidiaries, including Energy Masters International, Inc. (EMI) (formerly known as Cenerprise, Inc.), a Minnesota corporation; Viking Gas Transmission Company, a Delaware corporation (Viking); and Eloigne Company, a Minnesota corporation (Eloigne). (See "Gas Utility Operations - Viking Gas Transmission Company" and "Non-Regulated 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 an approximately 49,000 square mile service area and the transportation, storage, and distribution of natural gas in approximately 151 communities within this area. Viking is a regulated natural gas transmission company that operates a 500-mile interstate natural gas pipeline. NRG operates several non-regulated energy businesses and is an equity investor in many non-regulated energy affiliates throughout the world. 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 1997, about 62 percent of NSP's electric retail revenue was derived from sales in the Minneapolis-St. Paul metropolitan area and about 54 percent of retail gas revenue came from sales in the St. Paul metropolitan area. (For business segment information, see Note 15 of Notes to Financial Statements under Item 8.) NSP's utility businesses are currently experiencing some of the challenges common to regulated electric and gas utility companies, namely, increasing competition for customers, increasing pressure to control costs, uncertainties in regulatory processes and increasing costs of compliance with environmental laws and regulations. In addition, there are uncertainties related to permanent disposal of spent nuclear fuel. (See Management's Discussion and Analysis under Item 7, Notes 13 and 14 of Notes to Financial Statements under Item 8 and "Electric Utility Operations - Capability and Demand and Nuclear Power Plants - Licensing, Operation and Waste Disposal," herein, for further discussion of this matter.) A significant portion of NSP's earnings comes from non-regulated operations. The non-regulated projects in which NRG has invested carry a higher level of risk than NSP's traditional utility businesses. (See Management's Discussion and Analysis under Item 7 herein, for further discussion of this matter.) Except for the historical information contained herein, the matters discussed in this Form 10-K, are forward looking statements that are subjects to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "estimate," "expect," "objective," "possible," "potential" and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including their impact on capital expenditures; business conditions in the energy industry; competitive factors; unusual weather; changes in federal or state legislation; regulation; and the other risk factors listed from time to time by the Company in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.01 to this report on Form 10-K. TERMINATION OF PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION As discussed in the Company's Form 8-K filed on May 19, 1997, NSP and Wisconsin Energy Corporation (WEC) announced on May 16, 1997 that they mutually agreed to terminate their plans to merge the two companies. As a result of the merger termination, NSP charged to expense in the second quarter of 1997 its share of deferred merger-related costs. (See Management's Discussion and Analysis under Item 7 herein, for discussion of the financial effects of the merger termination.) The Minnesota Public Utilities Commission (MPUC) required NSP to formally request closure of the merger application docket filed with them. In July 1997, the MPUC approved NSP's request to withdraw its merger application. The MPUC also determined in the third quarter of 1997 that it did not need to further pursue issues raised during the merger proceedings relating to NSP's rates, service quality and ratemaking treatment of a contract settlement related to a prior period.
UTILITY REGULATION AND REVENUES General Retail sales rates, services and other aspects of the Company's operations are subject to the jurisdiction of the 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 within the state of Minnesota when the asset value is in excess of $100,000, mergers with other utilities, and transactions between the regulated Company and its affiliates. In addition, the MPUC reviews and approves the Company's electric resource plans and gas supply plans for meeting customers' future 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 electric and retail gas 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, the siting and construction of facilities by 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 "Electric Utility Operations - Nuclear Power Plants - Licensing, Operation and Waste Disposal" and "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 megawatts (Mw) or more, wind energy conversion plants with a capacity of 5 Mw or more, and routes for electric transmission lines with a capacity of 200 kilovolts (Kv) or more, as well as 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. NSP strives to understand and comply with all rules and regulations issued by the various agencies. Revenues NSP's financial results depend, in part, 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 1997 utility operating revenues, excluding intersystem non-firm electric sales to other utilities of $84 million and miscellaneous revenues of $77 million, were subject to regulatory jurisdiction as follows: <TABLE> <CAPTION> Authorized Return on Common Percent of Total Equity @ Dec. 31,1997 1997 Revenues --------------------------- ---------------- ELECTRIC GAS (Electric & Gas) <S> <C> <C> <C> Retail: Minnesota Public Utilities Commission 11.47% 11.47% 75.1% Public Service Commission of Wisconsin 11.3 11.3 14.3 North Dakota Public Service Commission 11.5 12.0** 5.4 South Dakota Public Utilities Commission * 3.1 Michigan Public Service Commission 12.25 14.5 0.5 Sales for Resale - Wholesale, Viking Gas and Interstate Transmission: Federal Energy Regulatory Commission * * 1.6 --- Total 100.0% ===== </TABLE> * Settlement proceeding, based upon revenue levels granted with no specified return. ** Reflects ROE underlying the August 1996 rate settlement.
General Rate Filings ================================================================================ General rate increases (other than fuel and resource adjustment rate changes) requested and granted in the last five years from various jurisdictions were as follows (note that amounts represent annual increases (decreases) effective in those years): Annual Increase/(Decrease) -------------------------- Year Requested Granted ---- --------- ------- (Millions of dollars) 1993 166.6 101.5 1994 (1.0) (1.0) 1995 (0.8) (0.8) 1996 2.2 (2.8) 1997 --- --- ================================================================================ The following table summarizes the status of general rate increases (decreases) for rates effective in 1997: Annual Increase/(Decrease) ------------------------------ Requested Granted Status --------- ------- ------ (Millions of dollars) Electric: Wisconsin-Retail No Change No Change Order Issued Nov. 26, 1996 Gas Wisconsin-Retail No Change No Change Order Issued Nov. 26, 1996 Total 1997 Rate Programs No Change No Change ================================================================================ 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 common 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. Minnesota law allows Construction Work in Progress (CWIP) in a utility's rate base. The MPUC has generally included Allowance for Funds Used During Construction (AFC) in revenue requirements for rate proceedings. However, 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 deviated from this biennial filing requirement while the proposed merger of NSP and WEC was pending. 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 rate schedules, and most of the Wisconsin Company's 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 electric sales customers do not have a fuel clause provision in their contracts. In lieu of fuel clause recovery, the contracts instead provide a fixed rate with an escalation factor. For eight Wisconsin Company customers on the W-1 wholesale rate, the wholesale electric fuel adjustment factor is calculated 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 other two wholesale customers have fixed rate contracts which do not have a fuel adjustment factor. In 1995, the MPUC approved a variance of Minnesota fuel adjustment clause rules to specifically allow for the inclusion of total wind purchase power costs and biomass related energy costs in the fuel adjustment clause. The Company must request approval for renewal of this variance on a continuing basis. The Company is obligated by legislative mandate to purchase 425 Mw of wind generated energy and 125 Mw of farm-grown closed-loop biomass generated energy by 2002. (See Note 14 to the Financial Statements under Item 8 for a discussion of the Company's legislative resource commitments.) The Wisconsin Company's automatic retail electric fuel adjustment clause for Wisconsin customers was eliminated in 1986. The electric fuel adjustment clause was replaced by a procedure which compares actual monthly and anticipated annual fuel costs with those costs which were included in the latest retail electric rates approved by the PSCW. If the comparison results in a difference outside a range of eight percent for the first month, five percent for the second month, or two percent for the remainder of the year, the PSCW may hold hearings limited to fuel costs and revise rates. Any revised rates would be effective until the next biennial rate case. The adjustment approved is calculated on an annual basis, but applied prospectively. Effective Jan. 1, 1996, the fuel costs that are monitored include demand costs for sales, purchased power and transmission wheeling expenses, which had been excluded prior to that date. 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 factor is calculated for the current month based on the estimated purchased gas costs for that month. By September 1 of each year, the Company is required by Minnesota statute to submit to the MPUC an annual report of the PGA factors used to bill 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 reviews 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 finds the utility was not prudent in its gas procurement activities. On Sept. 11, 1997 the MPUC allowed full recovery of gas costs in response to the filing for the year ended June 30, 1996. The MPUC's determination regarding the filing for the year ended June 30, 1997 is pending. Approval is anticipated in the latter half of 1998. In 1996, the PSCW conducted a generic hearing to consider alternative incentive-based gas cost recovery mechanisms to replace the current PGA. In November 1996, the PSCW issued an order with general guidelines for incentive-based gas cost recovery mechanisms as well as "modified one-for-one" gas cost recovery mechanism. All major gas utilities in Wisconsin were required to file a proposal to replace their current PGA. In September 1997 the Wisconsin Company filed its proposal with the PSCW. In the Wisconsin Company's proposal, allowable gas commodity cost recovery would be based on a benchmark index which is, in turn, based on the market price of gas. The allowable cost recovery of the remaining components of the cost of gas (for example, fixed pipeline transportation costs, supply reservation costs, and other costs approved by the FERC) would be based on actual costs incurred, as is the case with the Wisconsin Company's current PGA. The PSCW's decision is expected in June 1998. If the Wisconsin Company's proposal is approved, the financial impact of the new gas cost recovery mechanism will be substantially the same as with the current PGA. Approximately 70 percent of the Wisconsin Company's gas revenues represent recovery of gas costs through the PGA mechanism. 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. For 1997 the Gas Cost Recovery Factor was in place; however, the Power Supply Cost Recovery (PSCR) factor was waived in 1997 due to the proposed merger with WEC. The PSCR was reinstated effective in 1998 as discussed under "Rate Matters by Jurisdiction". Viking provides interstate gas transportation services only through its pipelines and does not sell gas. Thus, Viking has no need for a PGA mechanism. Natural gas fuel for Viking's compressor station operations is provided by transportation service customers. On Feb. 27, 1998 Viking filed to
increase its fuel retention rates to reflect current compressor operations, to be effective April 1, 1998. Resource Adjustment Clauses in Effect In 1995, the MPUC approved the implementation of an annual recovery mechanism for electric and gas conservation and energy management program expenditures, including annual gas program costs and an amortization of electric program costs, reimbursement of gas margins and a portion of electric margins lost due to conservation activity, and returns on capital used to finance electric conservation programs. This decision allows for accelerated recovery of conservation and energy management program expenditures which is desirable because it allows more timely rate recovery of cost changes outside general rate cases and lessens the risk for future stranded costs resulting from electric industry restructuring. A surcharge to customer's bills is included as a line item entitled "resource adjustment". The Company is required to request a new cost recovery level annually. Current cost recovery levels were approved effective in July 1997 for electric and September 1996 for gas. The 1997 proposed gas change (filed May 1, 1997) is pending final MPUC action. In January 1996, a number of changes to the Company's regulatory deferral and amortization practices for Minnesota electric conservation program expenditures were approved. These changes allow the Company to expense rather than defer and amortize new conservation expenditures beginning in 1996 and to increase its recovery of electric margins lost due to conservation activity. These conservation cost recovery changes are intended to avoid a significant delay between the time when costs are incurred and when they are recovered in rates. In addition, the Company received approval for 1996 and 1997 conservation expenditures at levels lower than 1995. In 1997, the Company received approval to further reduce electric conservation expenditure levels in 1998 and 1999 to 2 percent of Minnesota revenues, the minimum allowed by current Minnesota law. Rate Matters by Jurisdiction MINNESOTA PUBLIC UTILITIES COMMISSION (MPUC) On Dec. 2, 1997 the Company filed for a general increase in gas retail rates in the state of Minnesota. The Company requested an annualized increase of $18.5 million or 5.5 percent. The Company requested an interim annualized rate increase of $15.6 million or 4.6 percent effective Feb. 1, 1998. An interim rate increase totaling $13.9 million on an annual basis has been approved, subject to refund, effective Feb. 1, 1998. If the final rate level is less than the interim rate level, the difference will be refunded to customers with interest. The MPUC has ten months from the date of the filing to reach a decision on the Company's rate increase request. Since 1995, the Company has offered, with MPUC approval, a 50 percent discount on the first 300 kilowatt-hours (Kwh) consumed each month by qualified low-income residential customers. These low-income discounts are recovered from other customers. Approximately 33,000 of the Company's customers received assistance, totaling $7.5 million for the 1996-97 heating season, from federally funded Low Income Home Energy Assistance Programs (LIHEAP) operated by the State of Minnesota. Other states served by NSP have similar programs. Qualification for the Company's Low Income Discount Rate is based on eligibility for LIHEAP. The federal LIHEAP program is facing some opposition and funding could be lost in the future. In a January 1998 agreement with the Minnesota Office of the Attorney General, the Company has agreed to provide up to $2.8 million in supplemental grants over the next three years to NSP customers receiving aid from the LIHEAP program. Gas utilities in Minnesota are required to file for a change in gas supply contract levels to meet peak demand, to redistribute demand costs among classes, or exchange one form of demand for another. The Company filed in October 1996 to increase its demand entitlements due to projected increases in firm customer count, to decrease the Minnesota jurisdictional allocation of total demand entitlements, effective Nov. 1, 1996, and to recover the demand entitlement costs associated with the increase in transportation and storage levels in its monthly PGAs. In February 1997, the MPUC approved NSP's 1996-97 entitlement levels. In October 1997, the Company filed for approval of its 1997-98 demand entitlements. This filing is pending MPUC approval. In 1995, the MPUC initiated a rulemaking process to amend, repeal, or replace existing rules governing customer service standards for gas and electric utilities. The MPUC formed an advisory task force representing interests from electric and gas utilities, low and fixed-income consumer advocate groups, other Minnesota State agencies and other various rate payer classes. The ultimate outcome of the rulemaking process is unknown at this time. The task force currently is not actively meeting. In response to customer requests and concerns, the Company initiated several changes and clarifications to its tariff options through miscellaneous filings in 1997. In February 1998, the MPUC approved the Company's "group billing" proposal, which will allow customers with multiple accounts (e.g., municipalities, fast food restaurants, chain stores, etc.) to receive a single aggregated bill.
In November 1997, the MPUC approved the Company's gas Predictable Commodity Price Service, which allows eligible customers to elect a gas service option with a predetermined price for an annual period, rather than traditional pricing which varies from month to month based on current wholesale gas prices. On Oct. 9 1997, the MPUC voted to approve NSP's request for fuel clause adjustment (FCA) treatment for costs incurred under the gas supply management agreement between NSP Gas and NSP Generation (two business areas within NSP). NSP's electric utility will recover approximately $2 million under the FCA, and NSP Gas will earn approximately $20,000 in margin. The MPUC deferred any decision on the issue of whether a transaction between business units within the same utility corporation is an affiliated interest agreement under the 1993 amendments to Minnesota statute 216B.48. No electric general rate filing is anticipated in Minnesota in 1998. NORTH DAKOTA PUBLIC SERVICE COMMISSION (NDPSC) In its August 1996 order approving the Company's North Dakota base rate adjustment, the NDPSC also opened an investigation to examine gas cost of service allocations and rate design criteria for the Company. In May 1997, the NDPSC voted to close this investigation. The NDPSC did not order any cost allocation or rate design changes, but encouraged NSP to file new tariffs to increase the availability of transportation-only services to more classes of customers. No general rate filings are anticipated in North Dakota in 1998. SOUTH DAKOTA PUBLIC UTILITIES COMMISSION (SDPUC) Coincident with initial natural gas deliveries, NSP filed a request with the SDPUC on Dec. 16, 1997 for a declaratory order establishing NSP as a regulated gas utility in South Dakota. Included in the filing is also a request for approval of initial large volume retail intrastate gas transportation rates. NSP has not previously provided natural gas service in South Dakota. In August 1997, Hutchinson Technologies, Inc. (HTI) chose NSP to provide gas service, in addition to electric service, to its new 700 employee facility in Sioux Falls, South Dakota. NSP tapped the Angus C. Anson combustion turbine gas supply line and constructed a 3.5 mile 4 inch diameter steel pipeline to the Sioux Empire Development Park 5 and the new HTI facility. NSP will provide natural gas transportation service. Gas supply arrangements will be made by the customer. HTI transportation revenues will not be material. However, the Company will work to expand its South Dakota gas operations in the future. No general rate filings are anticipated in South Dakota in 1998. PUBLIC SERVICE COMMISSION OF WISCONSIN (PSCW) To facilitate its review of the Wisconsin Company's application to merge with WEC, in 1995 the PSCW deviated from its normal biennial rate case filing requirements and directed the Wisconsin Company to file complete electric and gas rate cases in early 1996 for the test year beginning January 1, 1997. On March 15, 1996, the Wisconsin Company filed a full rate case for the 1997 test year on a stand alone basis as requested by the PSCW. The Wisconsin Company's filing described revenue deficiencies for both electric and gas utilities. However, no rate increases were requested. Technical hearings for the Wisconsin Company's electric and gas rate cases were held before the PSCW on July 8, 1996. On Nov. 26, 1996, the PSCW issued an order approving the Wisconsin Company's application for no change in rates. However, certain classes of customers experienced small changes in rates as a result of rate design revisions requested by the Wisconsin Company. These changes to electric rates for certain customers classes had an offsetting effect on overall revenues. There were no significant changes to gas rates. In its order, the PSCW approved a capital structure composed of 45 percent debt and 55 percent common equity, and granted an 11.3 percent return on common equity. On June 9, 1997 the Wisconsin Company filed for a fuel cost surcharge to its retail electric rates under the fuel rules provisions of the Wisconsin Statutes. The surcharge was requested because fuel and purchased power costs had risen beyond the amount included in the Company's current rates due to unplanned and extended outages at the Company's nuclear generating stations and higher than projected costs to transmit electricity purchased from other utilities to the Wisconsin Company's service territory. Effective Sept. 25, 1997, the PSCW authorized the Company to charge a fuel cost surcharge of $0.00043 per Kwh to all Wisconsin retail electric customers, which produced approximately $574,000 of additional electric revenue in 1997. The surcharge represents less than one percent of current rates and is the first rate increase requested since January 1993. The surcharge will continue in effect on an interim basis until the next rate order is issued and is subject to refund pending final PSCW review. The Wisconsin Company filed retail electric and gas rate cases with the PSCW on Nov. 14, 1997
for the test year 1998. The Wisconsin Company requested a 4.3 percent increase, approximately $12.7 million annually, in retail electric rates and a 1.9 percent or $1.7 million decrease in retail gas rates. The Wisconsin Company has requested that these changes take effect during the second quarter of 1998. The electric rate filing includes a request for recovery of network transmission service costs of which $1.7 million had been deferred at Dec. 31, 1997 as approved by the PSCW. MICHIGAN PUBLIC SERVICE COMMISSION (MPSC) In August 1997, the MPSC approved the Wisconsin Company's application to reinstate a PSCR factor for Michigan electric customers in 1998. On Sept. 29, 1997, the Wisconsin Company filed its request for a 1998 PSCR factor of $.00172 per Kwh which would produce about $250,000 of additional revenue in 1998. There were no changes in the Michigan electric and gas base rates during 1997. The Wisconsin Company is currently reviewing the need to file for a change in Michigan rates in 1998. OPEN ACCESS TRANSMISSION PROCEEDINGS (FERC) In April 1996, the FERC issued two final rules, Order Nos. 888 and 889, which have had a significant impact on wholesale electric markets by giving competitors the ability to transmit electricity through utilities' transmission systems. Order No. 888, which was effective on July 9, 1996, granted nondiscriminatory open access to transmission service to promote wholesale competition and requires utilities and other transmission users to abide by comparable terms, conditions and pricing in transmitting power. Order No. 889, effective Jan. 3, 1997, requires public utilities to implement Standards of Conduct and use an electronic bulletin board called Open Access Same Time Information System ("OASIS", formerly known as "Real-Time Information Networks"). These rules require transmission system operation personnel to provide the same information about the transmission system to all transmission customers using the OASIS, and required separation of the wholesale power supply ("merchant") function from the transmission system operation function. In 1997, the FERC issued clarifying final orders in response to rehearing requests by numerous market participants regarding Orders No. 888 and 889. These FERC clarifying final orders are currently being appealed in federal court. A new proposed rule on Capacity Reservation Open Access Transmission Tariffs also was issued in April 1996. This proposed rule requested comments on a new proposed tariff to be in effect no later than Dec. 31, 1997. The FERC has since postponed this rulemaking indefinitely. With regard to compliance with the first phase of FERC Order No. 888, in July 1996, NSP submitted its transmission tariff compliance filing and an information filing that unbundled the transmission component of the full requirements municipal wholesale customers' rates. In October 1996, in response to the final rule, NSP filed the FERC Order No. 888 proforma tariff using the rates from the NSP tariff, approved in February 1996. The tariff approved in February 1996 complies with the transmission pricing policies provisions of open access requirement of the Energy Policy Act of 1992 which calls for comparability of service and pricing, network service, an unbundling of ancillary charges such as scheduling and load following. With regard to the second phase, in December 1996 NSP submitted its compliance filing which unbundled the transmission component of its coordination agreements. For transactions under these agreements, these customers became NSP transmission service customers. In October 1996, the FERC accepted NSP's information filing. NSP also is taking steps to comply with FERC Order No. 889, including submission of the requisite Standards of Conduct filing in January 1997 and training employees on these standards in January 1997. In 1997, NSP separated personnel who perform the merchant function, which includes power and energy marketing and trading, from personnel who perform the transmission system operation function. In addition, a significant effort was put forth in 1997 to enter current and all new requests for transmission service into the electronic bulletin board. In December 1997, the FERC issued an order clarifying issues regarding FERC Order No. 889 standards of conduct. On Feb. 12, 1998, the FERC issued an order requiring modifications to NSP's January 1997 Standards of Conduct compliance filing, including requirements for additional separation of functions. NSP submitted revised standards on March 16, 1998. NSP continues to be generally supportive of the FERC's efforts to increase competition. ELECTRIC TRANSMISSION TARIFFS (FERC) On Feb. 17, 1998, the Company and the Wisconsin Company jointly filed a Section 205 wholesale transmission rate case with the FERC requesting changes to its point-to-point Open Access Transmission Tariff (Tariff). The requested Tariff is based largely on the pro forma tariffs included in the FERC's Order No. 888. Rates requested are based on a projected test year consisting of 1998 budget data, and included updated rates, proposing an 11 percent increase, for firm point-to-point transmission service. The request, if approved, would increase transmission revenues approximately $3 million annually. In addition, the nonfirm point-to-point maximum rate would decrease by approximately eight percent under the proposed tariff. Because NSP's present transmission rates are based on a
1992 historical test year, the major reason for the increase is additional transmission investment capitalized since 1992. NSP has requested rates to become effective May 1, 1998, subject to refund. FERC action is pending. In addition, the filing includes new rates for the six ancillary services required by FERC Order No. 888. If approved, these new rates will result in additional revenues of approximately $1 million annually. The terms and conditions in the proposed tariff are largely unchanged from the Order 888 proforma tariff. The rate changes will affect transmission service prices to most wholesale transmission customers, including municipals, cooperatives and utilities who buy electric supply from NSP. It will also affect the prices utilities and power marketers pay for using NSP's transmission lines to transmit power across NSP's system. Such power marketers include: the Company's new merchant power marketing arm, NSP Energy Marketing, which sells NSP's surplus energy; and a subsidiary of NRG, which received power marketing approval from the FERC in 1997. On March 2, 1998, the Company and the Wisconsin Company also filed a separate Section 205 rate change to the Network Integration Transmission Service (NTS) provisions of NSP's Tariff. NSP requested a May 1, 1998 effective date. Under the FERC Order No. 888, NSP is required to offer, among other services, NTS service to qualifying customers, who are neighboring non-jurisdictional electric utilities (primarily cooperative or municipal utilities) who own transmission facilities within the NSP electrical control area. Under NTS, NSP and other qualifying regional utilities share the total annual costs of operating and maintaining the regional transmission network that NSP uses, net of related network revenues, based on each company's share of the total network load. The transmission tariff filed with the FERC is used as the cost basis for FERC-regulated utilities in determining NTS rates. NSP expects that the new Tariff changes, if approved, and settlement negotiations will result in lower NTS costs in 1998. (For more information on NTS, see Management's Discussion and Analysis under Item 7 herein.) 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 independent power producers. 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 it will be in a position to compete effectively. In October 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, as amended (PUHCA) 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 PUHCA. 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 FERC Orders No. 888 and 889 (as discussed in "Utility Regulation and Revenues", herein) reflect the trend toward increasing transmission access under the Energy Act. As discussed previously, in compliance with FERC Orders No. 888 and 889, NSP has separated personnel who perform the merchant function, which includes power and energy marketing, from personnel who perform the transmission system operation function. In 1997, NSP's merchant function, NSP Energy Marketing, expanded its power trading to focus on new market opportunities created by open transmission access. NSP Energy Marketing performs power and energy marketing (both sales and purchases). The sales and revenue provided by this function includes what NSP is currently classifying as sales for resale, which includes both municipal power sales and sales to other utilities. Because of Orders No. 888 and 889, NSP Energy Marketing must pay the same rates as other utilities for use of NSP's transmission system in connection with its wholesale power and energy sales. NSP's merchant function includes sales to municipal power supply customers, which was formerly referred to as wholesale sales. The municipal power supply market has continued to be competitive. Rate discounts and negotiated rates are being offered to current and potential municipal power supply customers to allow the municipals to prepare themselves for competition. NSP has attracted new customers and is retaining customers through this strategy. In the past several years, these customers have been evaluating a variety of energy sources to provide their electric supply. NSP's revenues from sales of electrical power and energy to municipal power supply customers totaled approximately $23 million in 1997, $29 million in 1996 and $44 million in 1995. The reduction in revenues is attributed mainly to the nine municipal
power supply customers whose contracts terminated in 1995 and 1996. These nine customers remain transmission service customers. The Company currently has nine municipal power supply customers and the Wisconsin Company has ten municipal supply customers. All ten municipal power supply customers have current power supply arrangements and are expected to purchase the majority of their power supply requirements from the Wisconsin Company. Even though NSP has contracts with several municipal power supply customers, because of competition in the sales for resale markets, NSP will need to continue to be competitive in the entire wholesale market as many parties, including power marketers, are now able to use its transmission lines to transport electricity. In 1997, NSP filed 61 transmission service agreements for FERC approval. In 1996, this number was 58. Currently, 76 customers, including power marketers (independent brokers who buy and sell wholesale electricity as a commodity at market prices), and NSP's Energy Marketing area, were registered to buy transmission service from NSP. NSP still has the first right to use its transmission system for sales to retail customers. NSP has also reserved the right to use its transmission system to serve its firm (guaranteed delivery) municipal power customers. But for non-firm (delivery subject to utility's discretion to curtail without liability) wholesale transactions, NSP Energy Marketing must compete with others to use the NSP transmission system. The process of making a wholesale energy sale is now much more detailed, but the sale can also now be contingent upon the availability of transmission service. NSP is no longer competing with only regional utilities when it buys and sells excess power to wholesale customers, but is also competing with power marketers from all over the United States. As more participants join this market, margins are driven down. NSP is developing its wholesale power marketing capabilities to compete on a national basis and not risk losing customers and declining margins. NSP is also developing risk management practices to respond to the rapidly growing electric commodity market. Some states, such as Michigan in which NSP has service territory, have begun to allow retail customers to choose their electricity suppliers, and many other states are considering proposals to increase competition in the supply of electricity. NSP believes competition among suppliers to serve retail customers will result in more innovative services and lower prices for all consumers if the transition is managed in a thoughtful manner. NSP supports fair and equal treatment for all competitors. Of particular importance are the recovery of utilities' investments made under traditional regulation and resolution of Minnesota's property tax issues. Currently, NSP pays property taxes in Minnesota that are two to three times higher than they would be in neighboring states, and investor-owned utilities also pay taxes that are significantly higher than those paid by other types of utilities within Minnesota. NSP advocates tax reform to eliminate the severe interstate and intrastate disparities as a prerequisite to opening access to retail customers. In Minnesota, the MPUC developed and adopted principles for electric industry restructuring. One of the principles supports the establishment of a robust competitive wholesale market. As a follow-up to the principles, the MPUC convened the Electric Competition Workgroup, which included NSP, to examine possible changes in industry regulation and structure to foster wholesale competition. In 1996, the MPUC accepted the workgroup's report and expanded its charter to examine issues related to retail competition. In 1997, the MPUC accepted the retail competition report and ordered their staff to prepare a plan to address the issues identified in the report in response to a hypothetical legislative mandate to open up retail access. To date, the MPUC staff has not yet submitted the plan to the MPUC. Minnesota's Governor and legislative leadership have indicated that electric utility restructuring will not be a priority in the 1998 session. Nevertheless, legislative hearings on the issue were held in 1997. At the end of the hearings, the joint House and Senate subcommittee decided that they needed more technical information before making a policy recommendation to the full legislature. Currently, two versions of an electric industry restructuring study bill have passed the Senate and the House subcommittees and are being reviewed for consolidation. Both bills would establish a Technical Advisory Work Group composed of a wide range of stakeholders to examine, over a several month period, a set of technical issues including reliability, consumer protections and level playing field issues. Passage of a final version is expected sometime in April 1998. In February 1996, the PSCW issued its report to the state legislature on restructuring the electric industry. The report was the culmination of over a year of work by representatives from a wide range of interests, including low income advocates, environmental groups, regulators and the utilities. NSP played an active role in the efforts. Key elements of the report include: 1) unbundling the vertically-integrated utility functions into generation, transmission, distribution and energy services; 2) improving competition in electric generation while insuring consumer access to the low costs associated with existing power plants; 3) preventing the exercise of market power by large companies; 4) revising Wisconsin's regulatory processes while protecting the environment; 5) working to transform the transmission system into a common carrier; 6) developing distribution and retail service
requirements and 7) developing alternative means for funding and providing social benefits to customers. The report included a 32 step plan to achieve these elements with the ultimate goal of opening the retail market to competition by the year 2001. The PSCW began implementing the 32 step plan in 1996. In September 1996, the PSCW issued an order setting minimum standards for creating an independent system operator (ISO) for the electric transmission system of NSP. This order was issued as part of a generic electric utility restructuring process the PSCW started in 1995. As of the end of 1996, parties had filed plans with the PSCW to unbundle utility functions; completed hearings on revising the State's Advance Plan and Certificate of Public Convenience and Necessity processes; developed proposals regarding the funding and delivery of low income, energy efficiency, renewable resource and environmental research services; and began to work on initial distribution and retail service requirements. After receiving comments on the restructuring work plan in July 1997, the PSCW consolidated the 32-step work plan into a 7-step work plan. However, due to the summer of 1997's electrical reliability concerns in eastern Wisconsin, the PSCW indicated that industry restructuring efforts be subordinate to, and compatible with, reliable electric supply. The PSCW maintains that the development of a strong ISO remains of a primary importance to retail competition. As a result of the reliability issue in 1997, the PSCW has indicated it intends to focus on the development of a utility infrastructure necessary to assure reliable electric service and the removal of barriers to competition at the wholesale level first. In late 1997, the PSCW stated that although many parties have concluded that retail competition is a foregone conclusion, the PSCW never indicated that retail competition was inevitable, nor that it was in the public interest. At present, a definite timeline has not yet been established for the implementation of retail competition in Wisconsin. In March 1998, the Governor of Wisconsin proposed reliability legislation that, if enacted, will make dramatic changes in the state's energy industry and take a number of steps toward industry restructuring. This proposal will streamline the state's regulatory process and authorize some form of a merchant plant market. This proposal will also require, prior to June 30, 2000, transmission system owners to either transfer control of transmission system assets to an ISO or divest of assets to an independent transmission owning entity. NSP cannot predict the final contents of any such legislation or ultimate impact on NSP. In North Dakota, the NDPSC, in 1997, adopted the National Association of Regulatory Utility Commissioners' Principles to Guide the Restructuring of the Electric Industries, which suggest that industry changes should only occur when they result in economic efficiency and serve the broader public interest. Specific principles address protecting network reliability, providing customers with meaningful choice, sharing benefits and stranded costs between ratepayers and shareholders, protecting the environment and reaffirming state commission responsibility for determining restructuring policies. Since that time, the NDPSC has taken no further action on this issue. Also in North Dakota, the 1997 legislative session established a committee of six legislators charged with studying the impact of competition on the electric industry. By statute, the committee has a six-year time frame to study the impact of competition on the generation, transmission and distribution of electric energy in the state. To date, there has been no legislation drafted and no consensus on the need to change the current environment. On Jan. 14, 1998, the MPSC issued an order regarding electric retail competition. The MPSC concluded that all customers who want to participate in open access should have the opportunity to do so and that those customers who do not participate should not pay higher rates because of open access. The order directed the large Michigan utilites to make 2.5 percent of their electric load eligible for open access in each year from 1997 through 2001. All remaining Michigan electric customers would be given access in 2002. It also stated that the phase-in schedule applied to all customer classes, a bidding process would be used to allocate the open access capacity, loads of less than one Mw would be allowed to participate through an aggregator, and that prudently incurred stranded costs would be recovered. This order was unsuccessfully challenged by the affected Michigan utilities, and the courts upheld the MPSC's authority to implement retail competition. In July 1996, NSP executed a long term electric service contract with one of its largest electric customers, Koch Refining Company. Previously, Koch had planned to construct a 180 Mw cogeneration plant, leave the NSP retail system, and sell its excess electricity supply in the wholesale market in competition with NSP. Under the agreement, Koch will remain an NSP retail customer, and will participate in NSP's electric supply bidding process before constructing any new generating plant. The agreement complies with a Minnesota law enacted in 1996. NSP filed for MPUC approval of the agreement in September 1996. In early 1997, the MPUC ruled the agreement is consistent with the statute but deferred action on cost recovery until the Company's next electric general rate case. In June 1996, the City Council for the City of St. Paul, Minnesota (the City), approved new ten year electric and natural gas franchise agreements between NSP and the City. Under Minnesota law,
utilities are required to obtain franchises from the municipalities where they serve. In the new agreements, NSP and the City agreed to a "unit charge" mechanism where the City's franchise fee is collected on the units of energy (Kw, Kwh or CCF) of electricity or gas delivered by NSP regardless of the supplier. The new fee structure will generate about the same total fee revenue for the City each year, but is "supplier neutral" and will not create uneconomic price incentives for customers to leave the NSP system. To NSP's knowledge, the new St. Paul franchise agreements are the first in the United States where all utility franchise fees are collected on a unit of delivery basis. 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 and NSP's own generation business unit to bid in response to Company solicitations for proposals. The PSCW also allows this process through the granting of waivers. 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 in the future. NSP will continue to work with regulators to complete the tariff and infrastructure that will support an electric competitive environment. Additional actions the Company is pursuing to position itself 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 service guarantees; ease of customer access, including 24 hour, seven days per week operation; metering automation; and centralization of common services and aggressive cost management. In addition, NSP will compete for service outside its traditional service area. This process has begun via NSP's NRG and EMI subsidiaries. Technological Improvements In order to improve customer service, increase productivity, and respond to the changing needs of both the electric and gas markets, NSP has made, or is in the process of making, several major technological improvements. In 1996, the Company implemented a new customer service system that supports customer information and billing. NSP is also making modifications to its computer software and other technology to address the year 2000 issues. (See Management's Discussion and Analysis under Item 7 herein, for further discussion of the year 2000 changes.) In 1996, the Company implemented a "feeder management system", which is part of NSP's electric distribution automation effort, that allows NSP to monitor, control and communicate with and make better decisions about its electric distribution system. It allows NSP to perform engineering studies quickly, thus customers out of service can be restored faster. It also assists NSP in using its capacity and avoid damaging equipment. This system is interfaced with a new energy management system, which controls NSP's electric transmission, distribution and generation facilities, and became fully operational in 1997, improving system performance and customer service. This system is also assisting NSP to comply with FERC Order Nos. 888 and 889, as discussed previously, and to compete in the changed environment as a result of these orders. In 1997, NSP also implemented a portion of a new Geographic Information System (GIS). GIS is a design and automated mapping tool providing a single system for updating maps of gas and electric facilities. Additions, changes and deletions are done quickly and efficiently after construction, thereby making the maps as current as possible. GIS will assist NSP in the design of construction projects and services. Current and accurate information will be available on-line. This is critical in NSP's daily operations, not only for the productivity and safety of its construction crews, but for the improved quality of service NSP can provide to its customers. NSP expects to complete implementation in 1998. Also in 1997, NSP began installing a wireless automated meter reading system that will allow the Company to remotely read customer meters in the Minneapolis - St. Paul metro area every month which will almost eliminate estimated customer bills. The project, Automated Energy Services (AES), is designed to improve customer service in the Minneapolis - St. Paul metro area. More than one million electric and gas meters are expected to be automated by the year 2000. As part of the AES project, NSP has contracted with an affiliate of CellNet Data Systems, Inc. (CellNet), a company based in San Carlos, California, which owns the technology. CellNet will own and operate a communication network that can provide daily meter readings to NSP for automated electric and gas meters. Capability and Demand Assuming normal weather, NSP expects its 1998 summer peak demand to be 7,427 Mw. NSP's 1998 summer capability is estimated to be 8,775 Mw, (net of contract sales) including 903 Mw (including reserves) of contracted purchases from the Manitoba Hydro-Electric Board, a Canadian Crown
Corporation (Manitoba Hydro) and 724 Mw of other contracted purchases. The estimate assumes 7,460 Mw of thermal generating capability and 1,315 Mw of renewable source generating capability. Of the total summer capability, NSP has committed 186 Mw for sales to other utilities. NSP's 1997 maximum demand of 7,353 Mw occurred on July 16, 1997. Resources available at that time included 7,117 Mw of Company-owned capability and 1,706 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 overall cost, NSP carried a reserve margin for 1997 of 19.7 percent. The minimum reserve margin requirement as determined by the members of the MAPP, of which NSP is a member, is 15 percent. In March 1996, the members of MAPP approved a proposal to convert MAPP into a Regional Transmission Group (RTG). As a result of this approval, a restated agreement, "Restated Mid-Continent Area Power Pool Agreement Jan. 12, 1996" was approved by the FERC in Docket No. ER96-1447, effective Nov. 1, 1996. Converting MAPP to an RTG is consistent with the 1992 Energy Policy Act and FERC policies. (See Note 14 of Notes to Financial Statements under Item 8 for more discussion of power agreement commitments.) In November 1997, MAPP provided to members drafts of its revised restated agreement indicating the changes necessary to accommodate an ISO, and a Transmission System Control Agreement through which transmission owners would give up operational authority of their Regional Transmission Facilities to the MAPP ISO. Some of the provisions include governance structure of the ISO, with a nine-member board of directors, new bylaws and a code of conduct. In addition, the MAPP Regional Transmission Committee (RTC) would be responsible for establishing the ISO as a non-profit membership corporation. An advisory group would be formed under the RTC to provide technical advice, review disputes between the ISO and members, and to make recommendations to the RTC. A vote by MAPP members is expected by mid-1998. The proposal would be filed with the FERC after the vote. NSP is considering alternatives to ISOs including the formation of an independent transmission company. In October 1997, officials from MAPP and the Southwest Power Pool (SPP) met to coordinate the investigation of a possible consolidation of the two regions. SPP, based in Little Rock, Arkansas, consists of 72 members that serve more than 6.6 million customers in all or part of eight southwestern states. The group identified functional areas to be investigated for possible consolidation: ISO filing, tariff administration, engineering, information technology, operations, training, policy and administration. The group has provided a written report to the regional governing bodies who will vote on the recommendations in April 1998. The Company, in conjunction with the Wisconsin Company and LaCrosse, Wisconsin - based Dairyland Power Cooperative (DPC), proposes to construct, operate and maintain 230- and 115- kilovolt (Kv) transmission line and substations to improve and maintain electric service to northwestern Wisconsin and eastern Minnesota. There is a need for additional electrical service to eastern Minnesota and a critical need to construct facilities to prevent potential future widespread blackouts in northwestern Wisconsin. The 230-Kv line would run from a substation in eastern Minnesota, cross the St. Croix River and terminate near Amery, Wisconsin. The 115-Kv line would end near Taylors Falls, Minnesota. The proposal also includes a 161-Kv line between Hayward and Ashland, Wisconsin. The project needs review and approval by the MEQB, PSCW and Rural Utilities Services. The major issue is the location and aesthetics of crossing the St. Croix River, which is a designated National Scenic Riverway. Assuming regulatory approvals, the companies expect the project to be in service by 2003. The Company is continuing an extensive performance-based transmission and distribution reliability program. This program includes preventative maintenance on transmission and distribution power lines, improvements to existing equipment and implementation of new technology. The Company has invested more than $350 million in transmission facility upgrades since 1992. The program focuses on the leading causes of outages consisting of lightning, trees and underground cable cuts, and also concentrates on reducing the number of human-error related outages. In 1997, the reliability program resulted in a 17 percent reduction in the total number of non-storm related outages to the Company's feeders, from 1,696 in 1996 to 1,409 in 1997, a new record low. In addition, outages to critical customer sites remained steady and maintained the low average achieved in 1996, allowing the Company to exceed its 1997 year end goal. Reliability goals for 1998 include emphasis on reliability-focused maintenance programs, improved restoration processes, and improved customer communication/access. The Company filed its most recent Resource Plan with the MPUC on Jan. 5, 1998, for the period 1998 to 2012. 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 resource solicitation to meet such needs. The plan contains conservation programs to reduce the Company's peak demand and conserve overall electricity use, an approximate schedule of power purchase solicitations to meet increasing demand, and programs and plans to maintain the reliable operation of existing resources.
In summary, the plan: * Forecasts slower growth in energy and peak demand requirements. The plan forecasts 1.7 percent growth in NSP's energy and peak demand requirements, which is down from the 2.9 percent growth NSP experienced in 1985 to 1995. * Outlines NSP's efforts to continue to help our customers use electricity wisely through demand side management and conservation programs. * Shows a need for 140 Mw of new capacity in 2003. NSP will use a competitive bid process to acquire the capacity. * Describes the programs for achieving the mandated renewable energy sources of 425 Mw of wind and 125 Mw of biomass. NSP's program is the largest commitment to renewables in the region. NSP recommends no new commitments to renewables. * Updates the MPUC on the status of spent nuclear fuel at the Prairie Island plant and describes how it can continue to operate until the year 2007 with the number of casks that have been authorized. ================================================================================ The following resource needs were identified in the Resource Plan filing: Cumulative Mw Resource Needs By Type vs. Base of 1997 2000 2004 2008 2012 ------- --------- ----------- ---------- Renewables* 0 160 (32) 160 (32) 160 (32) Peak 0 0-500 500-1,000 600-1,300 Intermediate 0 0-500 400-600 500-700 Base 0 0 0-800 300-1,600 Demand Side Management 352 697 994 1,243 Total 0-352 729-1,729 1,926-3,426 2,675-4,875 * Renewables include wind generation and biomass generation. The 1994 Minnesota legislative mandates related to these are discussed in Note 14 to the Financial Statements under Item 8 and "Electric Utility Operations - Nuclear Power Plants - - Licensing, Operation and Waste Disposal," herein . The Company considers 265 Mw of the 425 Mw windpower mandate and all 125 Mw of the biomass generation mandate to be committed capacity. (Including 25 Mw of windpower which was installed in 1994.) The amounts shown in parentheses are the estimated MAPP accredited capacity values at the time of system peak demand. The MAPP accreditation procedure for wind is intended to measure wind generation's contribution to system reliability at the time of system peak demand. Because wind generation is a variable resource, the accredited capacity is less than the installed capacity. ================================================================================ The resource plan proposed to satisfy the above resource needs through a combination of the following energy source options: - - Continued operation of existing generation facilities. - - Demand reduction of an additional 1,080 Mw by 2012 through conservation and load management. - - 425 Mw of wind energy and 125 Mw of biomass energy under contract by 2002. - - Acquisition of competitively priced resources to meet changing needs, i.e. competitive bidding. The Resource Plan also included an update of the Company's competitive bid schedule. The Company plans to seek proposals as follows: Proposal Resource Nominal In-Service Date Type Amount Date - ---------------------------------------------------------- 1998 Mandated 160 Mw Year-End Wind 2002 1999 All-Source with 100-1,200 Mw 2003-2005 Flexibility Options 2000 All-Source with 300-1,200 Mw 2004-2006 Flexibility Options 2001 All-Source with 200-1,100 Mw 2005-2007 Flexibility Options and Contingent Bid + 1,100 Mw 2002 All-source with 200-500 Mw 2006-2008 Flexibility Options 2003 All-source with 200-500 Mw 2007-2009 Flexibility Options The resource plan is now subject to public review and comment. The Company expects that the
MPUC will probably take action in early 1999, to approve or modify the plan. Minnesota utilities are required under a 1993 Minnesota law to use values established by the MPUC, which assign a range of environmental costs for each method of electricity generation that is not a part of the price of electricity, when evaluating and selecting generation resource options. These values are known as environmental externalities. NSP, along with several other parties, participated in a proceeding initiated by the MPUC to establish such values. The MPUC issued its order in January 1997. The high end of the range of externality values ordered by the MPUC add about 0.55 cents per Kwh to a typical new coal plant and about 0.15 cents per kwh to a natural gas fired plant. The carbon dioxide value comprises about 60 percent to 80 percent of these amounts. On Feb. 24, 1998, NSP and several other parties argued their appeal of the MPUC order before the Minnesota Court of Appeals, which will rule on the appeal within 90 days. NSP continues to implement various Demand Side Management (DSM) programs designed to improve load factor and reduce NSP's power production cost and system peak demands, thus reducing or delaying the need for additional investment in new generation and transmission facilities. NSP 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 NSP's value of service that, over the long term, will help its customer base become more energy efficient and competitive. During 1997, NSP's programs reduced system peak demand by approximately 130 Mw. Since 1982, NSP's DSM programs have reduced system peak demand by approximately 1,284 Mw, which is equivalent to 17 percent of its 1997 summer peak demand. In its 1997 Conservation Improvement Program Filing with the Minnesota Department of Public Service, the Company received approval to reduce its DSM expenditures in Minnesota to 2 percent of Minnesota revenues in 1998 and 1999, the minimum allowed by current Minnesota law. As recently as 1995, the Company spent approximately 3.5 percent of its Minnesota revenues on DSM. In 1994, the MPUC increased 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 and DSM investment returns and performance bonuses. The performance bonuses are awarded through an incentive program that rewards the attainment of specified conservation goals. The lost margin recovery, subject to annual review by the MPUC, was approximately $20 million in 1997, $14 million in 1996, and $7 million in 1995. The DSM investment returns and performance bonuses, subject to annual review by the MPUC, were $8 million in 1996 and $7 million in 1995. In addition, in April 1998 the Company will file for approval of approximately $7 million of DSM investment returns and performance bonuses for 1997. Energy Sources For the year ended Dec. 31, 1997, 47 percent of NSP's Kwh requirements was obtained from coal generation and 25 percent was obtained from nuclear generation. Purchased and interchange energy provided 24 percent, including 14 percent from Manitoba Hydro; NSP's hydro and other fuels provided the remaining 4 percent. The fuel resources for NSP's generation based on Kwh were coal (63 percent), nuclear (33 percent), renewable and other fuels (4 percent). The following is a summary of NSP's electric power output in millions of Kwh for the past three years: 1997 1996 1995 ---- ---- ---- Thermal plants 31,896 32,657 33,802 Hydro plants 1,015 1,194 1,049 Purchased and interchange 10,660 9,065 9,189 ------ ------ ----- Total 43,571 42,916 44,040 ============================ Many of NSP's power purchases from other utilities are coordinated through the regional power organization MAPP. NSP is one of 70 members, 21 associate members and 8 regulatory participants in MAPP. 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. Fuel Supply and Costs Coal and nuclear fuel will continue to dominate NSP's regulated utility fuel requirements for generating electricity by NSP owned generating capacity. It is expected that approximately 96 percent of NSP's fuel requirements, on a Btu basis, will be provided by these two fuels over the next several years, leaving 4 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 1997 and the estimated fuel mix for 1998 and 1999 are as follows: Fuel Use on Btu Basis --------------------- (Est) (Est) 1997 1998 1999 ----- ----- ---- Coal 62.2% 60.4% 59.6% Nuclear 33.9% 36.0% 36.8% Other 3.9% 3.6% 3.6%
The Company normally maintains between 20 and 40 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 1998 coal requirements. Coal delivery may be subject to short-term interruptions or reductions due to transportation problems, weather and availability of equipment. Based on existing coal contracts, the Company expects more than 98 percent of the coal it burns in 1998 will have a sulfur content of less than one percent. The Company has contracts with two Montana coal suppliers (Westmoreland Resources and Big Sky Coal Company) and four Wyoming suppliers (Rochelle Coal Company, Antelope Coal Company, Black Thunder Coal Company and Jacobs Ranch Mine) for a maximum total of 35 million tons of low-sulfur coal for the next three years. These arrangements are sufficient to meet approximately 80 percent of the requirements of existing coal-fired plants after 1998. The Company is able to purchase the remaining 20 percent of its coal requirements in a large active spot market. The Company has options from suppliers for over 100 million tons of coal with a sulfur content of less than one 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: ================================================================================ <TABLE> <CAPTION> State Sulfur Dioxide Maximum Amount Contract Approximate Emission Limit Annual Covered by Expiration Sulfur Pounds Per Plant Demand Contract in 1998 Date Content (%)(2) MBTU* Input - -------------------------------------------------------------------------------------------- (Tons) (Tons) <S> <C> <C> <C> <C> <C> Black Dog 1,000,000 1,000,000 (1) 0.5 1.3(3) High Bridge 800,000 800,000 (1) 0.5 1.95 Allen S. King 2,000,000 2,000,000 (1) 0.9 1.6 Riverside 1,400,000 1,400,000 (1) 0.7 2.5(4) Sherco 7,700,000 7,700,000 (1) 0.5 0.9(5) ---------- ------------ 12,900,000 12,900,000(6) </TABLE> *MBTU = Million British Thermal Units Notes: (1) Contract expiration dates vary between 1998 and 2005 for western coal. Spot market purchases of other western coal, and other fuels will provide the remaining fuel requirements after 1998. 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) 1.2 lb./MBTU when Unit 2 is operating. (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) The SO2 limitation at Units 1 and 2 ranges from 70 percent removal with a maximum emission rate of 0.48 lbs SO2/MBTU to 60 percent removal with a maximum emission rate of 0.96 lb. SO2/MBTU averaged over 90 days. The SO2 limitation at Unit 3 is 70 percent removal of SO2 input and a maximum emission rate of 0.60 lb. SO2/MBTU averaged over 30 days. The use of lime and/or limestone in the plant's scrubbers may be necessary to achieve these limits. (6) Annual requirements are expected to range from 11.4 to 12.9 million. ================================================================================ The Company's current fuel oil inventory is adequate to meet anticipated 1998 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 purchases and medium and long-term contracts for uranium, conversion and enrichment. Current
contracts are flexible and cover between 70 percent and 100 percent of uranium, conversion and enrichment requirements through the year 1998. These contracts expire at varying times between 1998 and 2005. The overlapping nature of contract commitments will allow the Company to maintain 70 percent to 100 percent coverage beyond 1998, 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 percent committed through the year 2003 and 30 percent covered through 2010. 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 average electric fuel costs for the past three years are shown below: Fuel Costs * Per Million Btu --------------- Year Ended December 31 1995 1996 1997 ------- ------ ---- Coal** $ 1.11 $ 1.02 $1.05 Nuclear*** .48 .47 .47 Composite All Fuels .87 .83 .88 * 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, 543 Mw Monticello Nuclear Generating Plant (Monticello) and the Prairie Island Nuclear Generating Plant (Prairie Island) with two units totaling 1,028 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. In its most recent ratings of Company nuclear facilities, the NRC rated the overall performance of both the Prairie Island and Monticello Plants as excellent. On a scale of 1 to 3 (1 being the highest), the plants both rate at 1.25, which is the average of ratings in the areas of plant operations, maintenance, engineering, and plant support. These ratings of the NRC's Systematic Assessment of Licensee Performance (SALP) place the plants in the top quarter of the 18 plants located in the Midwest. The Prairie Island and Monticello nuclear plants currently hold the Institute of Nuclear Power Operations' (INPO) top rating for plant operations and training. In addition, INPO has awarded both of the plants the INPO Excellence Award, which is a rigorous peer review process that recognizes plants with the highest levels of excellence in operational safety and reliability and which have no significant weaknesses. The Company previously operated the Pathfinder Plant near Sioux Falls, South Dakota 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 remain at the operating plant site. 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 (Compact). The development costs were to be paid by the generators of low-level radioactive waste within the Compact. In June 1997, the Compact abandoned efforts to find a disposal site due to decreased low-level waste generation and increased costs to build a facility. In November 1997, the Compact approved the return of funds contributed for development costs to Midwest nuclear utilities. Currently, the Barnwell facility, located in South Carolina, has been given authorization by South Carolina to accept low-level radioactive waste and the Compact has authorized its generators to use the Barnwell facility.
The federal government has the responsibility to dispose of or permanently store domestic spent 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 a repository for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent storage or disposal facility by 1998. The Company has contracted with the DOE for the future disposal of spent nuclear fuel. The DOE is currently charging a 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 electric customers in cost-of-energy rate adjustments. To date, NSP has paid the DOE $250 million in assessments for disposal of spent nuclear fuel. None of the Company's spent nuclear fuel has been accepted by the DOE for disposal. Further, the DOE has indicated that a permanent federal facility will not be ready to accept used nuclear fuel from utilities until approximately 2010. The Company, along with a group of other utilities and state agencies, initiated a series of lawsuits against the DOE. The primary purpose of the lawsuits is to insure that the Company and its customers receive timely storage and disposal of used nuclear fuel in accordance with the terms of the Company's contract with the DOE. (See Item 3 - Legal Proceedings for further discussion of this matter.) NSP, with regulatory and legislative approval, has been providing on-site storage at its Monticello and Prairie Island nuclear plants. 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 used fuel assemblies from the Monticello plant to a General Electric storage facility in Morris, Illinois. As a result, the Monticello plant does not expect to run out of storage capacity prior to the end of its current operating license in 2010. The on-site storage pool for spent nuclear fuel at 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 on-site dry cask storage facility for spent 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. In May 1994, the Governor of the State of Minnesota (Governor) signed into law a bill passed by the Legislature. The law authorizes the Company to install 17 dry casks at Prairie Island. Based on the assumptions and conditions in the original Certificate of Need from the MPUC, the Company determined the 17 casks would allow operation until at least 2003 and 2004 for units 1 and 2 respectively. After review of the 1994 Legislation the Company has determined 17 casks will allow facility operation until 2007. The Company executed an agreement with the Governor concerning the renewable energy and alternative siting commitments contained in the new law. The law authorized immediately the installation of the first increment of five casks. The second increment of four casks were authorized on Oct. 2, 1996 by the MEQB certifying that by Dec. 31, 1996: (i) the Company had applied to the NRC for an alternative site license for an off-site temporary used nuclear fuel storage facility in Goodhue County (but not on the Prairie Island nuclear generating plant site), (ii) the Company had used good faith in pursuing development of the alternative site, and (iii) 100 Mw of wind generation was under contract. As part of fulfilling the commitments required to secure the use of additional casks, in August 1996, the Company filed the application for the Goodhue County facility. The MEQB terminated an alternative siting process which was one of the legislative requirements. The Company's certification by the MEQB for the use of casks six through nine was legally challenged by the Prairie Island Tribe (Tribe). In July 1997, the Minnesota Supreme Court denied further review of the Tribe's petition. As a result of the decision, the Company withdrew it's application to the NRC for the Goodhue County facility. In 1996, the Company took steps for its wind and biomass resource commitments as discussed under the caption "Electric Utility Operations-Capability and Demand", herein. Other commitments resulting from the legislation include a low-income discount for electric customers, additional required conservation improvement expenditures and various study and reporting requirements to a legislative electric energy task force. In January 1995, the MPUC approved the Company's low-income discount programs in accordance with the statute. The Company has implemented programs to meet the other legislative commitments. (See "Electric Utility Operations - Capability and Demand", herein and Notes 13 and 14 of Notes to Financial Statements under Item 8 for further discussion of this matter.) The final increment of eight casks are available unless prior to June 1, 1999, the Legislature specifically revokes the authorization for the final eight casks. As of Jan. 31, 1998, seven storage casks are loaded and stored on the Prairie Island nuclear generating plant site. To address the issue of continued temporary storage of spent nuclear fuel until the DOE
provides for permanent storage or disposal, the Company is leading a consortium working with various private parties to establish a private facility for interim storage of spent nuclear fuel. In June 1997, the Private Fuel Storage Limited Liability Co. (PFS) filed a license application with the NRC for a national temporary storage site for spent nuclear fuel. The PFS, a consortium of utilities including the Company, will undertake the development, licensing, construction and operation of a storage facility on the Skull Valley Indian Reservation in Utah. The full NRC review process could take up to three years and will consist of formal evidentiary hearings and opportunity for public input. Storage cask certification efforts are continuing with the two vendors on track to meet the project goals. The interim used fuel storage facility could be operational and able to accept the first shipment of spent nuclear fuel by mid-2002. However, due to uncertainty regarding pending regulatory and governmental approvals, it is possible that this interim storage may be delayed or not available at all. On Jan. 23, 1997, the NRC issued Prairie Island a Severity Level III violation and a $50,000 civil penalty stemming from design issues with the Cooling Water Emergency Intake Line. The Cooling Water Emergency Intake Line is the dedicated safety-related water source for the Cooling Water Pumps in the event of a seismic occurrence rendering the normal intake bay inoperable. The NRC determined that a violation of the safety evaluation process occurred because an unreviewed safety question existed, due to these changed assumptions on the non-seismic canal and operator action. The NRC contends NSP's response to this regulatory issue was not promptly and adequately addressed. In January 1997 the NRC issued a notice of an apparent violation for the Company's Monticello plant. The notice regarded whether the Monticello plant should have submitted to the NRC issues about safety questions when it approved a reduction in the number of safety-related pumps used for containment cooling. On March 5, 1997, the Company presented to the NRC the facts and history of the case, and further discussions centered on corrective actions. At this time the Company does not know the outcome of this apparent violation and whether a civil penalty will be incurred. On Oct. 16, 1997 the NRC assessed Prairie Island a Severity Level III violation and $50,000 civil penalty for pump testing violations and untimely updating of licensing documents. The NRC determined the criteria for measuring the flow of auxiliary feedwater pumps did not accurately reflect the design requirements for the pumps. The pumps are the backup system to provide cooling water to the plant's steam generators. Prairie Island used a standard criterion of ten percent below design flow to evaluate test results wherein the NRC determined three percent was a more accurate criterion. Past test results stated none of the pumps exceeded the three percent criterion and would have provided the necessary waterflow if needed. The testing procedures were corrected during the inspection. The Company filed its triennial nuclear decommissioning study in 1996, and the MPUC approved it in April 1997. The filing requested continuance of the accruals, funding and other parameters approved in the last decommissioning study filed in 1993. Although the Company expects to operate the Prairie Island plant units through the end of their useful lives, the approved capital recovery would allow for the plant to be fully depreciated, including the accrual and recovery of decommissioning costs by 2008, about six years earlier than the end of its licensed life. The approved cost recovery period has been reduced because of the uncertainty regarding spent fuel storage. 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 approximately $530 million since 1971, including approximately $5 million in 1997 and approximately $1 million in 1996 and 1995 under such requirements. 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 13 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 14 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: <TABLE> <CAPTION> 1997 1996 1995 1994 1993 ---- ---- ---- ---- ---- <S> <C> <C> <C> <C> <C> REVENUES (THOUSANDS) Residential $ 739 684 $ 727 145 $ 735 743 $ 683 783 $ 651 593 Small commercial and industrial 379 848 376 797 362 521 351 287 327 888 Medium commercial and industrial 433 526 401 137 399 259 * * Large commercial and industrial 468 404 450 811 448 226 824 195 780 444 Streetlighting and other 30 826 30 033 29 162 28 936 29 214 ---------- ---------- ---------- ---------- ---------- Total retail 2 052 288 1 985 923 1 974 911 1 888 201 1 789 139 Sales for resale 107 464 98 961 133 961 146 239 159 498 Miscellaneous 58 798 42 529 33 898 32 204 26 279 ---------- ---------- ---------- ---------- ---------- Total $2 218 550 $2 127 413 $2 142 770 $2 066 644 $1 974 916 ========== ========== ========== ========== ========== SALES (MILLIONS OF KILOWATT-HOURS) Residential 9 791 9 847 9 956 9 303 9 092 Small commercial and industrial 5 907 6 091 5 763 5 585 5 307 Medium commercial and industrial 8 263 7 470 7 511 * * Large commercial and industrial 11 059 11 089 10 941 17 874 17 117 Streetlighting and other 335 336 329 334 344 ---------- ---------- ---------- ---------- ---------- Total retail 35 355 34 833 34 500 33 096 31 860 Sales for resale 4 658 4 929 6 500 6 733 8 044 ---------- ---------- ---------- ---------- ---------- Total 40 013 39 762 41 000 39 829 39 904 ========= ========= ======== ========= ========= CUSTOMER ACCOUNTS (AT DEC. 31) ** Residential 1 273 161 1 252 476 1 238 576 1 222 628 1 207 572 Small commercial and industrial 150 103 149 134 144 774 142 858 141 446 Medium commercial and industrial 9 142 7 962 7 906 * * Large commercial and industrial 695 669 652 8 172 8 114 Streetlighting and other 6 276 5 030 4 883 4 836 4 813 ---------- ---------- ---------- ---------- ---------- Total retail 1 439 377 1 415 271 1 396 791 1 378 494 1 361 945 Sales for resale 59 54 67 70 71 ---------- ---------- ---------- ---------- ---------- Total 1 439 436 1 415 325 1 396 858 1 378 564 1 362 016 =========== ========== ========== ========= ========= </TABLE> * Beginning in 1995, the commercial and industrial customer class was segmented into small (less than 100 kw in demand per year), medium (100 kw up to 1,000 kw) and large (1,000 kw or more). The estimated medium group was reported as large prior to 1995. ** Customers accounts for 1996 and 1997 may not be fully comparable to prior years due to differences in meter accumulation in a new billing system implemented in 1996.
GAS UTILITY OPERATIONS Competition/Regulation NSP provides retail gas service in the eastern portions of the Twin Cities metropolitan area, portions of eastern North Dakota and northwestern Minnesota, and other regional centers in Minnesota (Faribault, St. Cloud and Winona) and Wisconsin (Eau Claire, LaCrosse and Ashland). As discussed in the "Rate Matters by Jurisdiction" section herein, NSP has requested a declaratory order from the SDPUC establishing the Company as a regulated gas utility in South Dakota. 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 84 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 No. 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. The implementation of Order No. 636 applies additional competitive pressure on all local distribution companies (LDCs) including NSP, 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 to sales or transportation of 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 believes Order 636 has enhanced its ability to remain competitive and allowed it to increase certain of its margins by providing an increased selection of services to its customers. Order No. 636 allows interstate pipelines to negotiate with customers to recover up to 100 percent of prudently incurred "transition costs" (also known as stranded costs) attributable to Order 636 restructuring. In February 1997, the FERC upheld this decision after appeals of Order No. 636 were remanded by the United States Court of Appeals for the District of Columbia Circuit. In addition, the FERC ruled existing shippers need only agree to a five-year contract extension to obtain a right of first refusal on continued access to the shipper's expiring capacity; the original rule was a 20-year commitment. 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 No. 636 restructuring. Northern's total Order No. 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 FERC regulated transportation charges. NSP estimates that it will be responsible for approximately $13 million of Northern's transition costs, spread over a period of approximately six 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 No. 636 transition cost responsibilities to its other pipeline suppliers. In response to the additional competitive pressures as a result of Order No. 636, the Company has aggressively pursued alternative pricing strategies and service enhancements to provide additional value to customers. In 1996, NSP's retail gas utility operations were faced with the threat of physical bypass by large industrial customers. Previously, NSP had used its flexible gas rate discounting authority to compete to retain these customers. However, reductions in natural gas pipeline construction costs (which benefit NSP when it constructs its own facilities) made it economical for some customers to consider bypassing NSP. In response, NSP filed a new Negotiated Transportation Service Tariff with the MPUC. The MPUC voted to approve the tariff on March 6, 1997. The new tariff provides additional flexibility in gas rates discounting for potential bypass customers. On June 19, 1997, the Company filed a proposal for a Predictable Commodity Price Service (PCPS) Rider which would allow firm gas commercial and industrial customers a choice to purchase firm "fixed price" gas supplies rather than gas supplies whose price changes monthly through the PGA clause. The PCPS will be offered as a two-year pilot program to determine the extent of interest in the Minnesota service territory. The MPUC approved the rider in October 1997, and the program commenced in January 1998. In September 1996, NSP filed for FERC approval to "abandon" FERC's jurisdiction over two liquefied natural gas (LNG) plants which the
Company and the Wisconsin Company operate near St. Paul, Minnesota, and Eau Claire, Wisconsin, respectively. FERC asserted jurisdiction over the plants in the late 1970s, and NSP has provided FERC regulated LNG services from the two plants since that time. Under the NSP filings, the plants would remain in service but FERC would terminate its jurisdiction under Section 7 (c) of the Natural Gas Act, and the plants would be subject only to MPUC and PSCW jurisdiction, respectively. The filings were initially required to complete the canceled Primergy merger, but NSP requested the filings be approved irrespective of the merger. In October 1997, the FERC granted Part 157 abandonment. Business Growth NSP's gas utility extended service to approximately 14,000 new customers during 1997. In addition to exploring new growth opportunities, 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 20,000 potential customers in this category. In 1997, the Wisconsin Company signed a 10-year contract with the U.S. Army to build, own, and operate a natural gas system at Fort McCoy, a regional U.S. Army training center near Sparta, Wisconsin. At the end of January 1998, $820,000 of the approximately $2.0 million total cost of the project had been spent. On Feb. 2, 1998, the Wisconsin Company began providing gas to 169 buildings that were already served by the Fort's existing natural gas distribution system, and by July 1998 an additional 746 buildings should be added as the Fort's propane equipment is converted to use natural gas. The contract should produce about $1.7 million of additional revenue each year. The Wisconsin Company has received orders from the PSCW allowing the Wisconsin Company to treat the investment as utility property and to include the cost of gas purchased for the project in the PGA. The project is expected to be complete in July 1998. NSP has constructed a new town border station adjacent to Fort McCoy off the Northern Natural pipeline, removed eight miles of old steel gas piping, and installed 14 miles of new gas distribution main. Prior to the Wisconsin Company's contract, some of Fort McCoy's 1,000 buildings were served by liquid propane; others received natural gas supplied by Wisconsin Gas Co. through a fort-owned distribution system. NSP is the electric supplier to the fort-owned electric distribution system. In 1997, the NDPSC approved two NSP applications for certificates of public convenience and necessity to extend gas service to Horace, North Dakota, and three additional small cities outside Fargo. As a result, gas service will be made available to about 350 customers in areas not previously served with natural gas. In late 1997, the Wisconsin Company signed a purchase agreement to acquire Natural Gas Inc. (NGI) of New Richmond, Wisconsin. The companies have filed an application with the PSCW and expect to receive approval for the transaction in the spring of 1998. New Richmond is located in St. Croix County the fastest growing county in Wisconsin in 1996 with a 15 percent growth rate. NGI, a privately owned natural gas utility, founded in 1962, serves 1,900 natural gas customers in New Richmond and has revenues of approximately $2.3 million. The transaction will be structured as a tax-free reorganization for income tax purposes and a pooling of interests for accounting purposes. On Dec. 31, 1997, the Company announced an agreement and plan of merger with Black Mountain Gas Company of Cave Creek, Arizona (Black Mountain). The agreement is dependent upon regulatory approval and Black Mountain shareholder approval. Black Mountain Gas Co. is a natural gas and propane distribution company with natural gas operations in Cave Creek, Carefree, North Phoenix and North Scottsdale, and propane operations in the city of Page, Arizona. Black Mountain currently serves 6,500 customers and had 1997 annual revenues of approximately $6 million. The transaction will be structured as a tax-free reorganization for income tax purposes and a pooling of interests for accounting purposes. The Company's gas operation maintains a non-utility service which sells service contracts on a variety of home appliances. Working in partnership with local independent service contractors, NSP Advantage Service offers 24 hour appliance repair service. This service is offered to individuals within the Company's service territory. Business Standards In July 1996, FERC adopted new rules (in its Order No. 587) which adopt by reference 140 standard natural gas business practices approved by the Gas Industry Standards Board ("GISB"). GISB is the independent standards organization of the natural gas industry. The new rules and standards apply to interstate gas pipelines like Viking, and are intended to simplify transportation of natural gas across the interstate gas pipeline "grid". However, NSP's retail natural gas operations must change their information systems and operations to comply with the pipeline changes. The new FERC rules went into effect in the second quarter of 1997. NSP and Viking estimate their total compliance cost will be approximately $1 million. NSP invested approximately $0.6 million through Dec. 31, 1997 to make its systems compatible with the new pipeline systems. Viking will seek rate recovery of the rule compliance costs in future rate proceedings.
Standards of Conduct/Restructuring In January 1997, the PSCW adopted "Standards of Conduct" for gas local distribution companies (LDCs) serving Wisconsin consumers. The standards are similar to, but much more extensive than, the standards of conduct FERC has imposed on Viking under FERC Order No. 497 and on NSP's wholesale electric transmission functions under FERC Order No. 889. The PSCW standards require separation of the LDC delivery function from any affiliate which engages in "gas functions" and impose extensive reporting and other administrative requirements. The Wisconsin Company filed its compliance plan in February 1997. In restructuring the natural gas industry, the PSCW reviewed four proposed models. The chosen model included deregulation of the gas purchasing and transportation functions by market segment as competition becomes effective and sustainable. The PSCW then separated restructuring into three phases. In Phase I, the PSCW found it necessary to completely separate the gas purchasing activities associated with providing regulated services from those associated with providing unregulated services and to develop standards of conduct to apply to opportunity gas sales and utilities' relationships with their affiliates. The focus of Phase II was to develop Standards of Conduct (SOC) intended to ensure that interested market participants have the opportunity to purchase released pipeline capacity and gas supply, and that the releasing utility receives the best price for the sale. In situations in which a gas utility has a gas marketing affiliate, additional restrictions between the utility and its affiliate are necessary to ensure fair treatment of all market participants and to prevent cross-subsidization. Phase III focused on three main issues: (1) identifying regulatory or structural barriers that may prohibit competition; (2) identifying standards to determine the level of competitiveness of the market and the level of necessary regulations and; (3) identifying conditions to impose on marketers serving formerly regulated markets. In this phase, the PSCW decided that gas marketers should be registered and that consumer protection and customer service policy issues must be addressed before any markets are deregulated. The PSCW then ordered the formation of six work groups to address the following: Capacity Policy, Market Registration/Certification, Legislation, End-Use Price Reporting, Market-Based Pricing for Large Volume Customers, and Consumer Protection and Essential Services. These groups will continue to meet over the coming years to address the various issues. On Aug. 29, 1997, Enron Capital & Trade et al. filed a petition for a rulemaking with the MPUC which would have required all Minnesota gas LDCs to (i) file unbundling plans to be implemented in early 1998, and (ii) terminate their regulated merchant sales function by 2002. On Oct. 16, 1997 the MPUC voted to dismiss the Enron petition and reconvene its LDC unbundling work group. The MPUC ordered the work group to submit an LDC unbundling decision matrix to the MPUC by June 1, 1998. The Company is participating in the work group process. The MPUC also solicited comments from gas utilities on questions concerning Affiliated Interest Contract Issues and has established a Chair's Round Table to address these concerns. The Round Table is engaged in ongoing discussions. The SDPUC and NDPSC also initiated dockets in 1996 to examine whether to adopt standards of conduct for natural gas LDCs serving the two states. The rulemaking in Wisconsin, South Dakota and North Dakota could create precedent for future rules affecting NSP's retail electric operations in those states. 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 662,025 MMBtu for 1997 occurred on Jan. 27, 1997. NSP's gas supply sources are purchases of third-party gas which are delivered under gas transportation service agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 594,003 MMBtu/day. In addition, NSP has contracted with six providers of underground natural gas storage services to meet the heating season and peak day requirements of NSP gas customers. Using storage reduces the need for firm pipeline capacity. These storage agreements provide NSP storage for approximately 20 percent of annual and 30 percent of peak daily firm requirements. NSP also owns and operates two 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 245,420 Mcf of natural gas per day, or approximately 33 percent 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 and can be used to minimize daily imbalance fees on interstate pipelines. 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. Transportation rates have been designed to make NSP economically indifferent as to whether NSP sells and transports gas, or only transports gas.
Gas Supply and Costs As a result of FERC Order No. 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 interruption and financial risk, and economical rates. This diversification involves numerous domestic and Canadian supply sources, varied contract lengths, and transportation contracts with seven natural gas pipelines. NSP has firm gas transportation contracts with the following seven pipelines. The contracts expire in various years from 1998 through 2013: Northern Northern Border Pipeline Company Williston Basin ANR Pipeline Company Viking TransCanada Gas Pipeline Ltd. Great Lakes The agreements with Great Lakes, Northern Border, ANR and TransCanada provide for firm transportation service upstream of Northern and Viking, allowing competition among suppliers at supply pooling points, and 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 $14.5 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, 1997, NSP was committed to approximately $290.7 million in such obligations under these contracts, over the remaining contract terms, which range from the years 1998-2013. These obligations include some of the effects of contract revisions made to comply with Order No. 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 25 domestic and Canadian suppliers under contracts with durations of one year to 10 years. NSP purchases no more than 20 percent 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 cost of gas supply, transportation service and storage service is recovered through the PGA cost recovery adjustment mechanism discussed previously under "Utility Regulation and Revenues". 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. In July 1997, NSP and thirteen other parties appealed a July 1995 FERC order regarding rate treatment of two Great Lakes expansion projects. In the early 1990's, Great Lakes completed two expansion projects which did not improve service to the Company but which quadrupled its "rate base", which is a factor in calculating the rates the Company pays Great Lakes for transporting gas. The FERC's July 1995 order allowed Great Lakes to increase all rates to recover the cost of these expansion projects which increased the Company's transport costs on Great Lakes' system by 61 percent annually. Great Lakes was also allowed to surcharge for services received since November 1991. The Company and other parties to the appeal requested the cost of the expansion projects be recovered only from customers who benefit from them. In January 1998, the District of Columbia Court of Appeals ruled the July 1995 FERC order was lawful. The additional transportation costs have been recovered through the Purchased Gas Adjustment clause to the Company's rates, so there was no impact on the Company's earnings. In September 1997, the FERC ruled that Kansas natural gas producers must refund Kansas ad valorem tax collected improperly collected from 1983 to 1988 plus interest. During this period, Northern had bought gas from Kansas producers and resold it to NSP. In December 1997, Northern received one $30 million refund and, in turn, refunded $4.2 million to NSP. However, the Kansas producers are appealing the FERC order and are also pursuing federal legislation to overturn the FERC order. In February 1998, the FERC ruled that the Kansas producers could place disputed refunds in escrow and pipelines such as Northern could recollect refunded amounts if final refunds are less than those already paid. The Company and the Wisconsin Company are requesting rule waivers from their respective regulatory agencies to retain any refunds received from Northern pending resolution of the litigation and legislation. Purchases of gas supply or services by the Company from the Wisconsin Company, its Viking pipeline affiliate and its EMI gas marketing affiliate are subject to approval by the MPUC. The MPUC has approved all the Company's transportation contracts with Viking and a 1994 spot gas purchase agreement with EMI. In January 1998, NSP sought MPUC approval of a new agreement with EMI which would
allow both purchases from and sales to EMI. This agreement is pending MPUC approval. The following table summarizes the average cost per MMBtu of gas purchased for resale by NSP's regulated retail gas distribution business, which excludes Viking and EMI: Wisconsin The Company Company ----------- ------- 1993 $3.11 $3.02 1994 $2.59 $3.13 1995 $2.29 $2.78 1996 $2.88 $2.93 1997 $3.33 $3.22 Viking Gas Transmission Company (Viking) 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 480 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. In addition to revenue derived from FERC-approved rates, which are reported in NSP's consolidated Operating Revenues, Viking is receiving intercompany revenues from the Company and the Wisconsin Company for jurisdictional allocations of the acquisition adjustment paid by NSP (in excess of Tenneco's pipeline carrying value) to acquire Viking. The Company is not currently recovering this cost in retail gas rates in Minnesota, but is recovering this cost in North Dakota. The Company has requested recovery of this cost in its 1998 Minnesota gas rate case. The Wisconsin Company is recovering this cost in its retail gas rates. As a natural gas pipeline, Viking is subject to FERC standards of conduct in its transactions with the Company, the Wisconsin Company and EMI, pursuant to FERC Order No. 497. Viking must transact with EMI on a non-discriminatory basis, and certain restrictions are imposed on the retail gas operations of the Company and the Wisconsin Company. The Order No. 497 restrictions on Viking are similar to the Order No. 889 restrictions on NSP's wholesale electric transmission operations. In November 1997, Viking placed a major expansion project in service. The project expanded Viking's mainline capacity by 61,000 MMBtu/day (about 14 percent). The project will cost approximately $26 million. Viking expects to recover the project costs through additional long term transportation service revenues. In October 1996, Viking placed two expansion projects in service. The projects expanded Viking's mainline capacity by 19,400 MMBtu/day (about 5 percent), the first major Viking expansion since the 1960's, and constructed a second pipeline lateral to increase capacity to serve NSP's growing retail gas operations in the Grand Forks area. The two projects, which were not related but constructed at the same time, cost approximately $8 million. Viking expects to recover the project costs through additional long term transportation service revenues. On June 3, 1997, Viking, in partnership with TransCanada PipeLines, Ltd. (TransCanada), formed Viking Voyageur Gas Transmission Company LLC (Voyageur). In December 1997, NICOR, Inc. (NICOR) joined Voyageur so that it is 40 percent owned by Viking, 40 percent by TransCanada, and 20 percent by NICOR. The parties are continuing negotiations toward a definitive agreement regarding the contribution and possible merger of Viking into Voyageur as part of the transaction, subject to certain conditions. On October 31, 1997, Voyageur filed with the FERC for a certificate of public convenience and necessity (CPCN) to install a new 773 mile, 42 inch diameter pipeline parallel to the existing Viking pipeline and extending into the Chicago area. If constructed, the new pipeline could transport approximately 1.45 billion cubic feet of natural gas per day to markets in Minnesota, Wisconsin, North Dakota and Illinois. The anticipated project cost is approximately $1.24 billion (U.S. currency), and the new pipeline would be placed in service in late 1999 or 2000. The project would be constructed only if sufficient market demand exists, and would be subject to extensive pre-construction regulatory and environmental reviews by the FERC and other appropriate government agencies. If the project proceeds, the Voyageur partners would jointly own and operate the expanded pipeline entity. The Voyageur project is currently undergoing extensive regulatory reviews with respect to need, cost and environmental matters. As of Dec. 31, 1997, NSP has incurred $5.8 million related to negotiating the Voyageur agreements and its share of the CPCN application preparation costs, including various engineering and environmental studies, legal and other costs. Of this amount, $0.3 million was expensed by Viking, and $5.5 million was deferred for recovery in Voyageur's regulated gas transportation rates. The Company expects to spend approximately $6 million in 1998 in additional project planning, engineering, environmental, legal and other matters, to be recorded for deferred recovery in Voyageur rates.
Although many parties have intervened in support of the Voyageur project, the CPCN application has also been protested by various parties, including competing interstate pipelines. In addition, another pipeline project to deliver western Canadian gas to near Chicago (the Alliance project) is also pending FERC review. Thus there is some risk the Voyageur project may not be constructed. If the Voyageur project is ultimately not constructed for any reason, the Company would be required to expense the deferred project-related costs in the year of project cancellation. ================================================================================ Gas Operating Statistics The following table summarizes the revenue, sales and customers from NSP's regulated gas businesses: <TABLE> <CAPTION> REVENUE (THOUSANDS) 1997 1996 1995 1994 1993 ---- ---- ---- ---- ---- <S> <C> <C> <C> <C> <C> Residential $253 065 $267 130 $215 543 $207 506 $223 543 Commercial and industrial Firm 144 539 146 145 119 863 120 912 131 431 Interruptible 79 135 63 585 48 646 49 384 52 216 Other 34 153 1 686 3 688 630 -------- -------- -------- -------- -------- Total Retail 476 773 477 013 385 738 381 490 407 820 Interstate transmission (Viking) 19 809 17 553 16 328 16 307 10 247 Agency, transportation and off-system sales 21 287 34 662 26 122 24 338 12 237 Elimination of Viking sales to NSP (2 673) (2 435) (2 374) (2 232) (1 228) -------- -------- -------- -------- -------- Total $515 196 $526 793 $425 814 $419 903 $429 076 ======== ======== ======== ======== ======== SALES (THOUSANDS OF MCF) Residential 42 428 48 149 42 294 38 750 41 277 Commercial and industrial Firm 28 880 31 748 28 275 27 342 28 622 Interruptible 25 898 23 210 22 408 19 373 18 559 Other 33 394 772 212 186 -------- -------- -------- -------- -------- Total retail 97 239 103 501 93 749 85 677 88 644 ========= ======= ====== ====== ====== OTHER GAS DELIVERED (THOUSANDS OF MCF) Interstate transmission (Viking) 166 588 161 972 152 952 147 919 83 613 Agency, transportation and off-system sales 11 701 17 535 19 679 13 466 8 128 Elimination of Viking sales to NSP (17 145) (19 311) (20 440) (16 845) (8 425) -------- -------- -------- -------- -------- Total other gas delivered 161 144 160 196 152 191 144 540 83 316 ======= ======= ======= ======= ======= CUSTOMER ACCOUNTS (AT DEC. 31)* Residential 410 773 398 723 386 007 370 734 357 276 Commercial and industrial 41 905 40 244 38 575 37 140 36 185 -------- -------- -------- -------- -------- Total retail 452 678 438 967 424 582 407 874 393 461 Other gas delivered 36 30 62 18 40 -------- -------- -------- -------- -------- Total 452 714 438 997 424 644 407 892 393 501 ======= ======= ======= ======= ======= </TABLE> * Customers accounts for 1996 and 1997 may not be fully comparable to prior years due to differences in meter accumulation in a new billing system implemented in 1996. ================================================================================
NONREGULATED SUBSIDIARIES 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. In 1997 NRG filed a S-1 registration statement with the Securities and Exchange Commission. The following summary describes NRG's most significant projects. Additional information is included in Item 1 of NRG's 1997 Form 10-K which is incorporated herein by reference via Exhibit 99.03. NRG businesses generated 1997 operating revenues of $92 million and equity income of $26 million, and had assets of $1.2 billion at Dec. 31, 1997. NRG intends to continue to grow through combination of acquisitions and greenfield development of power generation and thermal energy production and transmission facilities and related assets in the United States and abroad. In the United States, NRG's near-term focus will be primarily on the acquisition of existing power generation capacity and thermal energy production and transmission facilities, particularly in situations in which its expertise can be applied to improve the operating and financial performance of the facilities. In the international market, NRG will continue to pursue development and acquisition opportunities in those countries in which it believes the legal, political and economic environment is conducive to foreign investment. NRG conducts business domestically and internationally through various subsidiaries, including: NRG International, Inc.; NEO Corporation; NRG Energy Center, Inc; NRG Operating Services, Inc.; and other businesses and affiliates, the more significant of which are discussed below. OPERATING BUSINESSES - EQUITY INVESTMENTS In May 1997, NRG as part of a consortium with CMS Energy Corporation (CMS) and Horizon Energy Australia Investments, acquired the Australian State of Victoria's Loy Yang A power plant (Loy Yang), Victoria's largest and Australia's lowest-cost electric generating facility. Loy Yang is a 2,000 Mw, brown coal-fired power station. The acquisition included an adjacent coal mine. NRG holds a 25.37 percent ownership interest in the consortium. Loy Yang is one of the newest and most modern of Victoria's brown coal-fired generating plants, with a portion of its electric output committed under power supply contracts through the year 2000. The coal mine has two billion tons of proven coal reserves, enough to serve the coal supply needs for 50 years of the Loy Yang plant acquired by the consortium and the Loy Yang B plant not included in the acquisition. The mine has a supply contract with the 1,000 Mw Loy Yang B electric generating plant and the exclusive rights to provide coal supplies for a third Loy Yang generating plant, should it be built. Loy Yang is jointly managed and operated by CMS and NRG. In 1994, NRG, through wholly owned foreign subsidiaries, acquired a 37.5 percent interest in the Gladstone Power Station, a 1,680 Mw coal-fired plant in Gladstone, Queensland, Australia from the Queensland Electricity Commission. Other members of the unincorporated joint venture, including Comalco Limited of Australia (Comalco), acquired the remaining interest. 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. In 1993, NRG, through a wholly owned foreign subsidiary, acquired a 50 percent interest in a German corporation, Saale Energie GmbH (Saale). Saale owns a 400 Mw share of a 960 Mw power plant (60 Mw of which is sold directly to an independent railroad) located in Schkopau, Germany, which is near Leipzig. PowerGen plc of the United Kingdom acquired the remaining 50 percent interest in Saale. VEBA Kraftwerke Ruhr AG of Gelsenkirchen, Germany (VKR), the builder of the Schkopau plant, owns the remaining 58.9 percent interest and operates the plant. The plant is fired by brown coal (lignite) mined by MIBRAG (discussed later) 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 425 Mw unit of the plant began operation in January of 1996, and the second unit came on line in July of 1996. In 1993, NRG, through a wholly owned foreign subsidiary, agreed to acquire a 33.33 percent 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, 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 percent 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. In December 1996, each of the investor
partners purchased one third of the remaining one percent interest held by the German government. In 1996 NRG and Nordic Power Invest AB (NPI), a wholly-owned subsidiary of Vattenfall AB, purchased 96.6 percent (4,060,732 shares) of the common stock of Bolivian Power Company Limited (COBEE) for $43 per share through Tosli Investment BV, the holding company jointly owned by NRG and NPI. In October 1997, the ownership of Tosli changed to 50 percent each for NRG and Vattenfall AB as NRG sold 10 percent of Tosli to Vattenfall AB. COBEE is the second largest generator of electricity in Bolivia with 171 Mw of capacity, which includes 136 Mw of hydro capacity and a 17 Mw gas-fired peaking unit. COBEE is incorporated in Canada, with a local office in La Paz, Bolivia and a headquarters located in Minneapolis, Minnesota. COBEE is in the process of expanding its hydroelectric facilities in the Zongo Valley and upon completion, total generating capacity will be 218 Mw. In November 1997, NRG acquired 100 percent of the outstanding shares of Pacific Generation Company (PGC), a wholly-owned indirect subsidiary of PacifiCorp Company, Inc. PGC has ownership interests in 11 projects with a total capacity of 737 Mw with operational responsibility for 312 Mw and net ownership interests of 166 Mw. One of the projects is located in Canada and the other ten are located throughout the United States. The projects are diverse in terms of fuel type, including natural gas, hydro, refuse-derived fuel, coal and wind. In April 1996, NRG purchased a 41.86 percent interest in O'Brien Environmental Energy, Inc. (O'Brien). O'Brien was renamed NRG Generating (U.S.) Inc. (NRGG). NRG currently holds 45.21 percent of the common stock of NRGG and the remaining 54.79 percent is held publicly. NRGG is traded on the NASDAQ small capital market under the ticker symbol NRGG. NRGG is the 100 percent owner of power cogeneration facilities in Newark and Parlin, New Jersey. These two facilities have an aggregate operating capacity of approximately 196 Mw. NRGG also has a 33.3 percent interest in the 150 Mw Grays Ferry cogeneration project in Philadelphia, Pennsylvania. NRGG and one of its partners in this project recently commenced litigation seeking to enjoin PECO Energy Company (PECO) from terminating its power purchase agreement with the project and to compel PECO to pay the rate set forth in the existing agreements. NRGG's position is that the actions of PECO are without merit and the existing agreements should be enforced. On March 19, 1998 the federal court dismissed the action for lack of jurisdiction. In addition to an equity interest in NRGG, in the purchase NRG also acquired certain biogas projects which were transferred to its subsidiary, NEO Corporation, and also made loans to NRGG and entered into project commitments. (See Note 14 of the Financial Statements Under Item 8 for further discussion of NRG's capital commitments related to NRGG.) During 1997, NRGG purchased the Millennium project from NRG, resulting in a gain of approximately 3 cents per share. NRG also owns various domestic and international equity interests in independent power production and cogeneration facilities, and thermal energy production and transmission facilities with total equity of 560 Mw and 156.7 Megawatt therms (MWt), respectively, at Dec. 31, 1997. OPERATING BUSINESSES - WHOLLY-OWNED NRG participates in several energy businesses which are managed as a thermal business group. The Minneapolis Energy Center (MEC) provides steam and chilled water to customers in downtown Minneapolis, Minnesota. MEC currently provides 90 customers with 1.6 billion pounds of steam per year and 34 customers with 39.1 million ton hours of chilled water per year. NRG, through its wholly-owned subsidiary NRG Energy Center, Inc., acquired MEC in August 1993 for approximately $110 million. MEC's assets include two steam and chilled water plants, three chilled water plants, two combined steam plants, six miles of steam and two miles of chilled water distribution lines. The MEC plants have a combined steam capacity of 1,323 mmBtus per hour (388 Mwt) and cooling capacity of 35,550 tons per hour. In addition, NRG owns and operates three steam lines in Minnesota that provide steam from the Company's power plants to Rock-Tenn Company, the Andersen Corporation and the Minnesota Correctional Facility in Stillwater. 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. NRG manages the operation of the other RDF plant, of which the Company owns 85 percent, and of the ash disposal site. The Company pays NRG a fee to manage its RDF facility under an operation and maintenance agreement approved by the MPUC. In 1997, the RDF plants processed approximately 800,000 tons of municipal solid waste into approximately 650,000 tons of RDF that was burned at two NSP power plants and at a power plant owned by United Power Association. NRG also owns 204 MWt of thermal energy production through several additional wholly-owned subsidiaries operating in Minnesota and North Dakota. 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 Management's Discussion and Analysis under Item 7 herein. A joint venture among NRG, Ansaldo Energia SpA, Italy and P.T. Kiani Metra, Indonesia, is developing a 400 Mw coal-fired power generation facility in West Java, Indonesia through P.T. Dayalistrik Pratama ("PTDP"), a limited liability company created by the joint venturers. NRG and Ansaldo each have an ownership interest of 45 percent in PTDP and P.T. Kiani Metra has an ownership interest of 10 percent. In November 1996, PTDP signed a Power Purchase Agreement with P.T. PLN (Persero), an instrumentality of the Government of Indonesia. NRG Energy plans to have a 45 percent equity interest in the project and would operate and maintain the power plant for the 30 year life of the project. Ansaldo will have responsibility for construction. The coal-fired power plant will sell its entire output to the local Java-Bali grid. In September 1997, the government of Indonesia placed the project on review. All project development efforts have been temporarily halted until the economic issues of Indonesia are stabilized and the project is allowed to proceed by the government. In December 1996, NRG reached agreement with Indeck Energy Services (Europe) to purchase a 50 percent equity interest in the Enfield Energy Centre, a 350 Mw power project located in the North London Borough of Enfield, England in the United Kingdom (UK). The power station is planned to begin commercial operations in 1999 and would be jointly developed by NRG and Indeck. The power station will sell its output to the UK grid. Natural gas will fuel the plant, which will use an air-cooled condensing system to eliminate any visible water vapor plume. Because of its proximity to London, local underground cables will be used to distribute the electricity rather than large overhead transmission lines. NRG expects to invest approximately $60 million in this project. Financial commitments were obtained from lenders in 1997. In December 1996, representatives of the Estonian Government, the state-owned Eesti Energia ("EE"), and NRG signed a Development Cooperation Agreement ("DCA"). The DCA defines the terms under which the parties are to establish a plan to develop and refurbish the Balti and Eesti Power Plants. Pursuant to the DCA, a business plan for the joint project was submitted in June 1997. NRG has stated its willingness to invest up to $67.25 million of equity in this project and to assist the joint project in obtaining non-recourse debt in an amount necessary to fund the required capital improvements to the Balti and Eesti Power Plants. Recently, the Estonian Government announced it had rejected the business plan of NRG and EE and offered to work on a new plan in early 1998. NRG's policy is to expense all costs until there is a signed contract and Board of Directors approval. All such costs with respect to Estonia have been expensed. Discussions are continuing with the Estonian Government as management continues to evaluate the Estonian situation. NRG, together with two other parties and the Chapter 11 trustees, have filed a plan with the United States Bankruptcy Court for the Middle District of Louisiana to acquire the fossil generating assets of Cajun Electric Power Cooperative of Baton Rouge, Louisiana ("Cajun") for approximately $1.2 billion. The NRG consortium has the support of the Chapter 11 trustee and Cajun's secured creditors. The Court has also received two other competing reorganization plans, all of which are subject to a confirmation hearing which began in December 1996. NRG expects the confirmation process to conclude in the second quarter of 1998. Under the plan filed with the Court, NRG would hold a 30 percent equity interest in Louisiana Generating LLC, which would acquire Cajun's 1,706 Mw net of non-nuclear generating assets. The plan of reorganization for Cajun contemplates an equity investment from NRG of approximately $75-100 million. In 1996, a new wholly owned subsidiary of NRG purchased the senior debt of Mid-Continent Power Company (MCPC) of Pryor, Oklahoma. In 1997, NRG received all of MCPC's assets in exchange for forgiveness of a portion of the debt. In December 1997, NRG sold a portion of its interest in MCPC resulting in a gain of 3 cents per share. MCPC owns a 120 Mw cogeneration facility in Pryor, Oklahoma. PROJECTS WITH NONRECURRING EARNINGS EFFECTS In 1994, NRG, through a wholly owned subsidiary, purchased a 50 percent ownership interest in Sunnyside Cogeneration Associates, a Utah joint venture, which owns and operates a 58 Mw waste coal plant in Utah. The waste coal plant is currently being operated by a partnership that is 50 percent owned by an NRG affiliate. As of year-end 1997, NRG and its partner's effort to restructure the debt of the Sunnyside cogeneration project was not successful. Due to a lack of progress in restructuring the project's debt, NRG's net capitalized investment in the Sunnyside project was written down by $9 million (8 cents per share after tax) in the fourth quarter of 1997. NRG's remaining investment in the project was $1 million at Dec. 31, 1997. NRG, through wholly owned subsidiaries, owns 45 percent of the San Joaquin Valley Energy Partnerships (SJVEP), which owns four power plants located near Fresno, California with a total capacity of 55 Mw. The plants previously operated under long-term Standard Offer 4 (SO4) power sales contracts with Pacific Gas and Electric (PG&E) which expire in 2017. In early 1995, PG&E reached basic agreements with SJVEP to acquire the SO4
contracts. The negotiated agreements resulted in cost savings for PG&E customers as well as economic benefits for SJVEP. Under the terms of the agreements, PG&E has been released from its contractual obligation to purchase power generated by SJVEP. Proceeds received from PG&E under the agreements were used to repay SJVEP debt obligations and recover investments in the facilities. SJVEP continues to own and maintain the facilities and to evaluate opportunities to market power without the prior costs incurred for plant depreciation and interest on debt, or to sell the assets. All regulatory approvals for the agreements were received in the second quarter of 1995. NRG's share of the pretax gain realized by SJVEP from this transaction, which was recorded in June 1995, was approximately $30 million (26 cents per share after tax). Settlement distributions were paid to NRG from SJVEP in 1995 and 1996. SJVEP's 10 Mw facility was sold to NEO in late 1996. In 1994, Michigan Cogeneration 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 Mw cogeneration 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 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. NRG's subsidiary, 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, began commercial operation in August 1993. NRG's net capitalized investment in the Scoria coal project was written down by $3.5 million in 1994, $5 million in 1995 and $1.5 million in 1996 to reflect reductions in the expected future operating cash flows from the project. NRG has no remaining investment to recover in the Scoria project. NRG's subsidiary Graystone Corporation, and several other companies were to build the first privately owned uranium enrichment plant in the United States. Because of the uncertainty surrounding the ultimate successful operation of this plant, NRG wrote off its $1.5 million investment in Graystone during 1994. Energy Masters International, Inc. (EMI) (formerly Cenerprise, Inc.) NSP's non-regulated wholly owned subsidiary, EMI, commenced operations in October 1993 through the acquisition from bankruptcy of selected assets of Centran Corporation, a natural gas marketing company. EMI, in addition to marketing natural gas to end-use customers, provides customized value-added energy services to customers, both inside NSP service territory and on a national basis. EMI 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 a 1994 contract whereby EMI may make natural gas sales at market based rates (determined by competitive bids) to NSP for resale to retail gas customers. As described previously under the caption "Gas Utility Operations - Capability and Demand", herein, a new 1998 agreement is pending MPUC approval. In 1995, EMI and Atlantic Energy Enterprises (AEE) established Enerval LLC (formerly known as Atlantic CNRG Services LLC). EMI and AEE each own 50 percent of the venture, which develops new and expanded natural gas and electric energy products and services, primarily in the northeast United States. EMI is currently in the process of evaluating proposals for the sale of its interest in Enerval and expects to finalize the sale during the second quarter of 1998. In late 1997, EMI's investment in and advances to Enerval were written down to an estimate of their net realizable value. In 1995, EMI acquired an 80 percent ownership interest in Kansas City-based Energy Masters Corporation (EMC). In 1997, EMI acquired the remaining 20 percent of EMC. EMC has offices in seven states nationwide and specializes in energy efficiency improvement services for commercial, industrial and institutional customers. EMC continues to operate as a separate legal entity, as a subsidiary of EMI. In 1997, EMI acquired 100 percent of Energy Solutions International Inc. (ESI). ESI, based in St. Paul, Minnesota, is a full-service energy management firm operating in 15 states nationwide. ESI continues to operate as a separate legal entity, as a subsidiary of EMI. 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 current federal tax law. As of Dec. 31, 1997, approximately $56 million had been invested in Eloigne projects, including approximately $18 million in wholly owned properties (at net book value) and approximately $38 million in equity interests in jointly-owned projects. These investments and related working capital requirements have been financed with approximately $27 million of long-term debt (including current maturities) and the remainder with equity capital. Completed Eloigne projects as of Dec. 31, 1997, are expected to generate tax credits of $71.1 million over the ten-year period 1998-2007. Tax credits recognized in 1997 as a result of these investments were approximately $6.7 million. A proposed "phase-out" of these tax credits was passed by the United States Congress but vetoed by the President in 1995. The legislation would have sunset the low-income housing tax credit allocation after Dec. 31, 1997. Under the vetoed proposal, projects with credits allocated prior to that date would continue to generate tax credits over the remainder of the 10-year credit period allowed. No legislation was reintroduced into Congress during 1996 or 1997 to phase-out low income tax credits. Seren Innovations, Inc. Seren Innovations, Inc. (Seren) was formed in November, 1996 to pursue communications and data services business in the upper Midwest. Seren invested $6 million in a fixed wireless network now being deployed in the Minneapolis - St. Paul metro area by an affiliate of CellNet Data Systems, Inc. In return, Seren will receive contracted payments from the use of the network. Seren also has the potential to receive additional royalties for data services added to the network. Seren is pursuing additional network development opportunities in other markets, which may result in potential equity investments of up to $50 million in 1998-1999. Ultra Power Technologies, Inc. Ultra Power Technologies Inc., (Ultra Power), a new NSP subsidiary formed in late 1997, will market a proactive, non-destructive, power-cable testing technology, for which NSP has been instrumental in the research and development. The predictive tool was developed by Dr. Matt Mashikian of Instrument Manufacturing Co. (IMCORP). Dr. Mashikian and IMCORP have entered into a contract with Ultra Power to provide equipment and software to Ultra Power. Ultra Power has exclusive marketing rights to this technology throughout the United States and Canada. The diagnostic cable testing package includes the cable test, data analysis, a comprehensive written report and computer data on each cable. Ultra Power will market this service to utilities and commercial customers with underground cable.
NONREGULATED BUSINESS INFORMATION <TABLE> <CAPTION> December 31 ============================================================================================================ (Thousands of dollars) 1997 1996 - ------------------------------------------------------------------------------------------------------------ <S> <C> <C> Equity investment by nonregulated businesses in unconsolidated projects (Including undistributed earnings and capitalized development costs) Australian projects $320 069 $91 350 European projects 105 925 108 091 South American and Latin American projects 81 712 92 257 Other international projects 9 534 3 316 Affordable housing projects (U.S.) 38 230 32 034 Other U.S. projects 185 264 82 681 - ------------------------------------------------------------------------------------------------------------ Total equity investment in unconsolidated nonregulated projects $740 734 $409 729 Nonregulated property of consolidated subsidiaries (net of accumulated depreciation) - primarily U.S. projects 256 726 192 790 Notes receivable from unconsolidated projects, including current portion 133 426 81 564 Intangible assets, including goodwill 110 218 101 496 Current and other assets 108 229 52 080 - ------------------------------------------------------------------------------------------------------------ Total assets of nonregulated businesses $1 349 333 $837 659 ============================================================================================================ Long-term debt, including current maturities $555 843 $269 486 Short-term debt 122 637 7 030 Other current liabilities 47 775 45 957 Other liabilities 66 283 23 954 - ------------------------------------------------------------------------------------------------------------ Total liabilities of nonregulated businesses 792 538 346 427 NSP's equity investment in nonregulated businesses 619 682 488 438 Cumulative currency translation adjustments (62 887) 2 794 - ------------------------------------------------------------------------------------------------------------ Total equity of nonregulated businesses 556 795 491 232 - ------------------------------------------------------------------------------------------------------------ Total liabilities and equity of nonregulated businesses $1 349 333 $837 659 ============================================================================================================ </TABLE> SIGNIFICANT NONREGULATED GENERATION PROJECTS OPERATING AT DEC. 31, 1997 <TABLE> <CAPTION> Total NRG Mw- Generation Projects Operating Location Mw Ownership Equity Operator - --------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> Gladstone Power Station Australia 1680 37.50% 630 NRG Loy Yang Australia 2000 25.37% 507 NRG/CMS Generation Pacific Generation Company USA/Canada 776 8.50%-100.00% 203 Various/AES Schkopau Power Station (1) Germany 960 20.55% 200 Veba Kraftwerke Ruhr A.G. NRG Generation (U.S.) Inc. (NRGG) (2) New Jersey, USA 196 45.21% 87 NRG COBEE Bolivia 171 48.30% 83 COBEE MIBRAG mbH Germany 200 33.33% 67 MIBRAG Energy Development Limited Australia 237 19.97% 38 Energy Development Limited Scudder Latin American Power Projects(Scudder) (3) Latin America 254 25.00% 19 Stewart & Stevenson/Wartsila </TABLE> 1. Through a lease agreement, NRG has ownership of 200 Mw. 2. NRGG owns various percentages of projects (15.07%-37.52%) making NRG's share of ownership 87 Mw. 3. Scudder owns various percentages of projects (6.45%-8.78%) making NRG's share of ownership 19 Mw.
ENVIRONMENTAL MATTERS NSP proactively prevents adverse environmental impacts by regularly monitoring operations to ensure the environment is not adversely affected, and takes 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. NSP is potentially liable for remediation of waste disposal sites owned by others, and for decommissioning and restoration of present and former plant sites, which is discussed in Notes 1, 13 and 14 to the Financial Statements under Item 8. In general, NSP has been experiencing greater environmental monitoring and compliance requirements, which have caused and may continue to cause slightly higher operating expenses and capital expenditures. The Company has spent approximately $727 million on capitalized environmental improvements to new and existing facilities since 1968. NSP expects to incur approximately $18 million in capital expenditures and approximately $34 million in operating expenses for compliance with environmental regulations in 1998. 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 14 to the Financial Statements under Item 8.) Permits NSP's regulated businesses are required to renew 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 Spent nuclear fuel storage and disposal issues are discussed in "Electric Utility Operations - Nuclear Power Plants - Licensing, Operation and Waste Disposal and Capability and Demand," herein, in Management's Discussion and Analysis under Item 7 and in Notes 13 and 14 of Notes to Financial Statements under Item 8. The Company and NRG have contractual commitments to convert municipal solid waste to boiler fuel (called Refuse-Derived Fuel or RDF) and to burn the fuel to generate electricity. NRG owns and/or operates two resource recovery plants that produce RDF from the waste. The RDF from NRG's plants is burned at the Company's Red Wing and Wilmarth plants in the Company's service area, and the Elk River plant owned by United Power Association. In addition, the Wisconsin Company owns a RDF plant and the RDF produced by this plant is burned at the French Island plant in the Wisconsin Company's service area. Processing and burning RDF is an additional economical source of electricity, 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 which would otherwise go 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 1994, the U.S. Environmental Protection Agency (EPA) proposed new air emission guidelines for municipal waste combustors. These proposed guidelines were finalized in December 1995. In November 1997, the state of Minnesota put a new draft waste combustor rule on public notice. This rule, when finalized, will replace the old state waste combustor rule and will be more restrictive than the federal guidelines. 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. The required equipment will likely cost between $4 million and $12 million. The Clean Air Act, including 1990 Amendments, (Clean Air Act) calls for reductions in emissions of sulfur dioxide and nitrogen oxides from electric generating plants. These reductions, which will be phased in, began in 1995. The majority of the rules implementing this complex legislation are 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 from prior rulemaking. Burners at the Company's Sherburne County Generating Plant (Sherco) unit 2 were upgraded in 1994 to further reduce emissions of nitrogen oxides. Other expenditures will be necessary on the NSP system for compliance in the year 2000. Evaluations are currently underway to determine if changing operating procedures could reduce or eliminate future capital expenditures. In 1997, the EPA revised the National Ambient Air Quality Standards for ozone and particulate matter. It is anticipated, based on historical monitoring, that the Company will be in compliance with the new standards and therefore will not be impacted by the new standards. If however, an area is determined to not be in compliance with the new standards, reductions in emissions of sulfur dioxide and oxides of nitrogen could be required. As part of its Clean Air Act compliance effort, testing of a full scale prototype wet electrostatic precipitator ("wet" ESP) was completed at Sherco in 1996. The "wet" ESP equipment was installed in 1995 into one of the plant's existing scrubber modules to determine its effectiveness in reducing particulate emissions and lowering opacity. Based on operating test results, the Company has chosen to convert multiple scrubber modules on Units 1 and 2 to the "wet" ESP design. Capital investment to date for the prototype has been $4 million. The Company estimates total capital expenditures for this project of $47 million through 2001. The Company has conducted testing for air toxics at its major facilities and has shared these results with state and federal agencies. The Company also conducted research on ways to further reduce mercury emissions. This information has also been shared with state and federal agencies. The Clean Air Act requires the EPA to investigate the impact of air toxic emissions from utilities and if appropriate, recommend regulations to control those emissions. The EPA delivered a report to Congress in early 1998 which recommended additional investigation on air toxics emissions. The report did not recommend any controls on utility boilers at this time. In 1997, NSP worked proactively with the Minnesota Pollution Control Agency (MPCA) and key legislators to pass legislation requiring the annual reporting of mercury emissions from utility boilers to the MPCA. NSP is also working with the MPCA on their Mercury Reduction Initiative. The Initiative is evaluating various strategies to reduce mercury contamination in fish. On March 11 and October 7, 1996, the Wisconsin Company received Notices of Violation (NOV) from the Wisconsin Department of Natural Resources (WDNR) stating that emissions from unit 2 at the Wisconsin Company's French Island generating facility had exceeded allowable levels for dioxin. The Company responded by providing a written response to the WDNR setting forth the Wisconsin Company's plans for bringing the emission levels back into compliance. By year end 1997, subsequent compliance tests had demonstrated that dioxins no longer exceeded acceptable limits. The Wisconsin Company expects that by early 1998 the WDNR will formally close out the NOV. No fines are expected. In 1996, the Wisconsin Company received a Letter of Non-compliance (LON) from the WDNR for failing to meet the emission guidelines for carbon monoxide (CO) at its Bay Front generating facility. The Wisconsin Company worked with the WDNR to establish mutually agreed-upon CO emission limits for the Bay Front facility. The Wisconsin Company has been advised by WDNR staff that, based on monitoring during 1997, that the plant is in compliance with the new emission limits. The Wisconsin Company has now been advised in writing that the LON has been formally closed. No enforcement action or fines resulted from the LON. In December 1997, nearly 160 nations adopted the "Kyoto Protocol to the United Nations Framework Convention on Climate Change" (Kyoto Protocol). Kyoto Protocol obligates developed nations to meet certain emissions targets; specific limits vary from country to country. If the Kyoto Protocol is approved internationally and the U.S. is a party, the Kyoto Protocol would impose, during the first commitment period of 2008-2012, a binding obligation on the U.S. to reduce its emissions of carbon dioxide, methane and nitrous oxide to a level of seven percent below 1990 levels and its emissions of hydrofluorocarbons, perfluorocarbons and sulfur hexaflouride by seven percent below 1990 or 1995 levels. The Kyoto Protocol must be ratified by the U.S. Senate in order for the U.S. to become a party to the protocol. Major provisions of the Kyoto Protocol, such as an international emissions trading program, have yet to be developed. Until they are developed, the impact on NSP cannot be determined. 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. The cost of overall water quality monitoring is not material in relation to NSP's operating results. Electromagnetic Fields
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 $115 million in research to determine the possible health effects of EMF. Through its participation with the Electric Power Research Institute and the EMF Research and Public Information Dissemination Program, sponsored by the National Institute of Environmental Health Sciences and the U.S. Department of Energy, NSP continues its investigation and research with regard to possible health effects posed by exposure to EMF. No litigation has been commenced or material claims asserted against NSP for adverse health effects or diminution of property values due to EMF. Contingencies 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, transmission 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 Current year capital spending activity and future financing requirements and sources are discussed in the Management's Discussion and Analysis under Item 7 herein. On March 11, 1998, the Company issued $100 million of 5.875 percent First Mortgage Bonds due March 1, 2003 and $150 million of 6.5 percent First Mortgage Bonds due March 1, 2028. The proceeds will be used to redeem its $50 million 7.375 percent and $50 million 7.5 percent First Mortgage Bonds on April 27, 1998; 300,000 shares of its cumulative preferred stock adjustable rate series A and 650,000 shares of its cumulative preferred stock adjustable rate series B both at $100 per share plus accrued dividends on March 31, 1998; and to reduce short-term debt balances. EMPLOYEES AND EMPLOYEE BENEFITS At year end 1997 the total number of full- and part-time employees of NSP was 7,455 and the total number of benefit employees was 6,718. Of this number approximately 2,800 employees are represented by five local IBEW labor unions under a three year collective bargaining agreement which expires Dec. 31, 1999. 401(k) CHANGES: NSP currently offers eligible employees a 401(k) Retirement Savings Plan. In 1994, NSP began matching employees' pre-tax 401(k) contributions. NSP's matching contributions were $4.4 million in 1997, based on matching up to $900 for each nonbargaining employee and up to $700 for each bargaining employee. WAGE INCREASES: Under a market-based pay structure implemented for nonbargaining employees in 1994, NSP uses salary surveys that indicate how other relevant companies pay their employees for comparable positions. In January 1997, nonbargaining employees received an average wage increase of 4 percent, and bargaining employees received a 2 percent base wage scale increase. In January 1998, nonbargaining employees received an average wage scale increase of 3.4 percent. Base wage scale increases for bargaining employees in 1998 were 2 percent.
EXECUTIVE OFFICERS * -------------------- Present Positions and Business Experience Name Age During the Past Five Years - -------------------------------------------------------------------------------- JAMES J HOWARD 62 Chairman of the Board, President and Chief Executive Officer since 12/01/94; and prior thereto Chairman of the Board and Chief Executive Officer. - -------------------------------------------------------------------------------- LOREN L TAYLOR 51 President - NSP Electric since 10/27/94; and prior thereto Vice President - Customer Operations. - -------------------------------------------------------------------------------- EDWARD L WATZL 58 President - NSP Generation since 02/03/97; Vice President - Nuclear Generation from 09/07/94 to 02/02/97; and prior thereto Prairie Island Site General Manager. - -------------------------------------------------------------------------------- CYNTHIA L LESHER 49 President - NSP Gas since 07/01/97 and prior thereto Vice President - Human Resources. - -------------------------------------------------------------------------------- GARY R JOHNSON 51 Vice President & General Counsel since 11/01/91. - -------------------------------------------------------------------------------- GRADY P BUTTS 51 Vice President - Human Resources since 07/01/97; Area Leader - Human Resources Management Services from 08/01/93 to 06/30/97; and prior thereto Director of Human Resources - Electric Utility. - -------------------------------------------------------------------------------- * As of 3/01/98
EXECUTIVE OFFICERS * -------------------- Present Positions and Business Experience Name Age During the Past Five Years - -------------------------------------------------------------------------------- EDWARD J MCINTYRE 47 Vice President and Chief Financial Officer since 01/01/93. - -------------------------------------------------------------------------------- THOMAS A MICHELETTI 51 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 05/11/94 to 10/26/94; Vice President-General Counsel, NRG from 09/15/93 to 05/10/94; and prior thereto Group Vice President for Minnesota Power and Light Company, a public utility located in Duluth, MN. - -------------------------------------------------------------------------------- ROGER D SANDEEN 52 Vice President and Controller since 07/01/89; and Chief Information Officer from 04/22/92 to 04/30/97. - -------------------------------------------------------------------------------- PAUL E PENDER 43 Vice President - Finance and Treasurer since 05/01/97; Assistant Treasurer and Director, Corporate Finance from 07/01/94 to 04/30/97; Director, Corporate Finance from 02/01/93 to 06/30/94; and prior thereto Manager, Financial and Investment Analysis. - -------------------------------------------------------------------------------- MICHAEL D WADLEY 41 Vice President - Nuclear Generation since 02/03/97; Nuclear Plant Manager - Prairie Island from 10/26/95 to 02/02/97; Plant Manager - Prairie Island from 02/01/93 to 10/25/95; and prior thereto General Superintendent of Operations - Prairie Island. - -------------------------------------------------------------------------------- JOHN P MOORE, JR 51 Corporate Secretary since 07/01/97; and prior thereto General Counsel and Corporate Secretary for the Wisconsin Company. - -------------------------------------------------------------------------------- PAUL E ANDERS 54 Vice President and Chief Information Officer since 05/01/97; and prior thereto Vice President - Information Services at Chrysler Financial Corporation located in Detroit, MI. - -------------------------------------------------------------------------------- * As of 3/01/98
ITEM 2 - PROPERTIES ================================================================================ The Company's major electric generating facilities consist of the following: 1997 Capability Output Station and Unit Fuel Installed (Mw) (Millions of Kwh) - ---------------- ---- --------- ---- ----------------- Sherburne Unit 1 Coal 1976 712 4 440.5 Unit 2 Coal 1977 721 3 853.7 Unit 3 Coal 1987 514 3 743.3 Prairie Island Unit 1 Nuclear 1973 514 3 521.9 Unit 2 Nuclear 1974 513 3 640.5 Monticello Nuclear 1971 545 3 656.7 King Coal 1968 571 3 501.3 Black Dog 4 Units Coal/Natural 1952-1960 462 1 350.8 Gas High Bridge 2 Units Coal 1956-1959 263 1 153.8 Riverside 2 Units Coal 1964-1987 372 2 231.9 Other Various Various 1 945 1 816.3 NSP's electric generating facilities provided 76 percent of its Kwh requirements in 1997. The current generating facilities are expected to be adequate base load sources of electric energy until 2003-2006, as detailed in the Company's electric resource plan filed with the MPUC in 1998. All of NSP's major generating stations are located in Minnesota on land owned by the Company. ================================================================================ At Dec. 31, 1997, NSP had overhead transmission and distribution lines as follows: Voltage Length (Pole Miles) ------- ------------------- 500Kv 265 345Kv 734 230Kv 283 161Kv 350 115Kv 1,609 Less than 115Kv 32,095 NSP also has approximately 280 transmission and distribution substations with capacities greater than 10,000 kilovoltamperes (Kva) and approximately 280 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 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. In 1995 a project was completed to increase the Manitoba-US transmission interconnection by a nominal 400 Mw to 1900 Mw. This project was undertaken as part of a contract where NSP and Manitoba Hydro have established an additional 150 Mw of seasonal power exchange. (See Note 14 of Notes to Financial Statements under Item 8 for further discussion of power purchase commitments.) The electric delivery system utilization has increased during recent years due to better analytical methods and enhanced Energy Management System monitoring and control capability. This increased utilization has been achieved while continuing to operate within reliability parameters established by MAPP and North American Electric Reliability Council (NERC). Plans are currently being implemented for electric delivery system upgrades to accommodate load growth expected in the Minneapolis-St. Paul geographic area through 2010. Recent studies have indicated load growth of approximately two percent per year. As the least cost option to accommodate the load growth, portions of the 69 Kv transmission facilities, especially located on the outskirts of the Twin Cities, are being reconductored and operated at 115 Kv; distribution development in these areas have been converted to 34.5 Kv. By reconductoring on existing right-of-ways and increasing distribution voltage, the requirements for new right-of-ways and substation sites are minimized as compared with other alternatives for serving the load growth. The natural gas properties of NSP include about 8,986 miles of natural gas transmission and distribution mains. NSP natural gas mains include
approximately 116 miles with a capacity in excess of 275 pounds per square inch (psi) and approximately 8,870 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. For discussion and information concerning nonregulated properties, see "Nonregulated Subsidiaries", under Item 1, incorporated herein by reference. 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. In 1993, a natural gas explosion occurred on the Company's distribution system in St. Paul, Minnesota. As a result of this explosion, eighteen lawsuits, including one lawsuit with multiple plaintiffs, were filed against the Company and the City of St. Paul. By September 1997, the Company reached a settlement on all of the lawsuits, and also resolved all known claims that had not advanced to litigation. The Company's total costs for legal fees, disbursements, and resolution of claims and lawsuits were $1 million. All expenditures paid by the Company in excess of $1 million were reimbursed by its insurance provider through the Company's general liability coverage policy. On June 20, 1994, the Company along with other major utilities filed a lawsuit against the DOE in an attempt to clarify the DOE's obligation to dispose of spent nuclear fuel beginning not later than Jan. 31, 1998. The suit was filed in the U.S. Court of Appeals for the District of Columbia Circuit (Court). The primary purpose of the lawsuit was to insure that the Company and its customers receive timely storage and disposal of spent nuclear fuel in accordance with the terms of the Company's contract with the DOE. On July 23, 1996, the Court affirmed the federal government's obligation. The Court unanimously ruled that the Nuclear Waste Policy Act creates an unconditional obligation for the DOE to begin acceptance of spent nuclear fuel by Jan. 31, 1998. The DOE did not seek U.S. Supreme Court review. On Jan. 31, 1997, the Company, along with 30 other electric utilities and 45 state agencies, filed another lawsuit against the DOE requesting authority to withhold payments to the DOE for the permanent disposal program. On May 7, 1997, the Company asked the Court to order the DOE to take spent nuclear fuel by the Jan. 31, 1998 deadline. On Nov. 14, 1997, the Court reiterated the unconditional obligation of the DOE to begin acceptance of spent nuclear fuel by the 1998 deadline. The Court confirmed the obligation exists under the statute and contract, but denied the request directing the DOE to accept spent nuclear fuel by the deadline finding the contractual remedies under the contract may be adequate. The Court also held that the DOE cannot use its own delays or the unavailability of a permanent disposal or temporary storage facility as a defense to utilities' actions. On Feb. 19, 1998, the Company and other utilities asked the Court to order the DOE to develop a disposal program to dispose of nuclear fuel beginning immediately; relief from an obligation to pay fees to the Nuclear Waste Fund (Fund) and allow escrow of the funds until the DOE is in compliance; prohibition of any suspension or termination of the DOE's disposal contract; prevention of the DOE from paying damages related to the breach of obligation from the Fund. The Company is analyzing and preparing continuing legal actions against the DOE to enforce its statutory and contractual obligations. NSP and other utilities are currently analyzing claims against the DOE for the costs incurred as a result of the DOE's failure to meet its statutory and contractual obligations. In October 1996, the Company was named in a class action lawsuit commenced by two commercial customers, who claimed that the expected energy savings from NSP's lighting efficiency program were misrepresented. On Jan. 22, 1998, a Hennepin County District Court Judge granted NSP's motion for summary judgment and dismissed the class action lawsuit in its entirety. The plaintiffs have until June 1, 1998 to appeal the Hennepin County District Court decision. On June 10, 1997, the Minnesota Office of the Attorney General (OAG) petitioned the MPUC to investigate the Company's meter reading and billing practices and to authorize the OAG to pursue civil penalties. The Company contested the claims before the MPUC. On Jan. 29, 1998, the parties reached an agreement on settlement terms which will obligate NSP to provide approximately $3 million in immediate customer credits, up to $3 million of additional assistance to low-income customers over the next three years, and to meet certain agreed-to performance standards. The settlement agreement was approved by the MPUC on March 3, 1998. The Company continues to deny any liability, and entered into the agreement to avoid potentially significant litigation costs. The Company recorded an estimated liability for the customer credits in its 1997 financial statements. On Sept. 15, 1997, NSP sought a determination in which the city of Oakdale,
Minnesota (City) must abide by the Company's tariffs filed with the MPUC in the Washington County District Court. The tariffs require the City to pay the additional cost of undergrounding electrical facilities prior to installation. On Feb. 18, 1998, the judge held that NSP must abide by the City's undergrounding ordinance which is silent on the issue of responsibility for payment of additional costs. The judge also ruled the tariff requiring the City to incur the additional costs was not binding on the City. As the judge's ruling is contrary to prior decisions of the Minnesota Court of Appeals, NSP will appeal the decision to that court in 1998. If the decision is not overruled, NSP would have to include the additional costs of undergrounding facilities in future rate cases or the costs would reduce earnings. Currently, the City has allowed NSP to construct its facilities overhead and no construction project will be delayed due to the appeal. On Jan. 23, 1998, Commonwealth Edison Company (ComEd) filed a complaint with the FERC against MAPP and its individual members (including the Company and the Wisconsin Company). The complaint alleged that the electric transmission curtailment procedures applied under the restated MAPP agreement and the NSP Open Access Transmission Tariff do not comply with FERC Order No. 888. The complaint alleges application of the MAPP procedure caused curtailment of certain ComEd transactions during May 1997, to the detriment of ComEd. On March 9, 1998, MAPP filed an answer denying the ComEd allegations, and NSP submitted a separate filing asking FERC to dismiss the complaint. ComEd requested that the FERC order MAPP and its members to revise their procedures and ComEd seeks such other and further relief that the FERC deems proper, including modifications to rate schedules or tariffs, if necessary. For a discussion of 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" and "Gas Utility Operations" under Item 1, incorporated herein by reference. ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ================================================================================ None during the fourth quarter of 1997. 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 (PCX). Following are the reported high and low sales prices based on the NYSE Composite Transactions for the quarters of 1997 and 1996 and the dividends declared per share during those quarters: 1997 1996 ----- ---- High Low Dividends High Low Dividends ------------------------------------------------------------ First Quarter $49 1/8 $45 1/2 $.690 $53 3/8 $47 5/8 $.675 Second Quarter 52 44 1/2 .705 49 5/8 45 1/2 .690 Third Quarter 52 15/16 48 .705 49 3/4 44 1/2 .690 Fourth Quarter 58 7/8 48 7/16 .705 49 1/8 45 1/2 .690
1997 1996 1995 1994 1993 ----- ------ ------ ------ ------ Shareholders of record at year-end 83 232 86 337 83 902 85 263 86 404 Book value per share at year-end $31.78 $30.93 $29.74 $28.35 $27.32 Shareholders of record as of March 15, 1998 were 82,955. 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, 1997, the payment of cash dividends on common stock was not restricted except as described in Note 3 to the Financial Statements under Item 8 herein. ITEM 6 - SELECTED FINANCIAL DATA ================================================================================ <TABLE> <CAPTION> 1997 1996 1995 1994 1993 ---- ---- ---- ---- ---- (Dollars in millions except per share data) <S> <C> <C> <C> <C> <C> Utility operating revenues $2 734 $2 654 $2 569 $2 487 $2 404 Utility operating expenses $2 372 $2 288 $2 223 $2 178 $2 100 Net income (1) $237 $275 $276 $243 $212 Earnings available for common stock (1) $226 $262 $263 $231 $197 Average number of common shares outstanding (000) 70 297 68 561 67 323 66 775 65 116 Average number of common and potentially dilutive shares outstanding (000's) 70 435 68 679 67 416 66 845 65 211 Earnings per average common share: Basic (1) $3.22 $3.83 $3.91 $3.46 $3.03 Assuming Dilution (1) $3.21 $3.82 $3.91 $3.46 $3.02 Dividends declared per share $2.805 $2.745 $2.685 $2.625 $2.565 Total assets $7 144 $6 637 $6 229 $5 950 $5 588 Long-term debt $1 879 $1 593 $1 542 $1 463 $1 292 Ratio of earnings (excluding undistributed equity income and including AFC) to fixed charges 2.9 3.8 3.9 4.0 4.0 </TABLE> Notes: AFC - Allowance for Funds Used During Construction (1) Net income and earnings per share include nonrecurring items in 1997 and 1995, as discussed in Management's Discussion and Analysis under Item 7. Excluding these nonrecurring items, earnings per share, assuming dilution, from ongoing operations were $3.54 and $3.69, respectively, and the average annual growth rate in earnings per share since 1993 was 4.1 percent.
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS ================================================================================ MANAGEMENT'S DISCUSSION AND ANALYSIS 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), Energy Masters International, Inc. (EMI), which changed its name from Cenerprise, Inc., effective Sept. 1, 1997, and Eloigne Company (Eloigne). The Company and its subsidiaries collectively are referred to herein as NSP. FINANCIAL OBJECTIVES AND RESULTS 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 common equity for the three years ending in 1997 was 12.0 percent. Based on a three-year average, this return places NSP below the top one-fourth of the industry, which was approximately 12.7 percent, and above the median three-year industry average of approximately 11.3 percent. The total return to investors (measured by dividends plus stock price appreciation) on NSP common stock for the most recent five-year period averaged 12.4 percent per year. For the same period, the total return for the electric industry averaged 10.7 percent. NSP's stock price rose 27.0 percent over the year, well above the 22.1 percent average increase of other utilities rated AA by Standard & Poor's (S&P). * TO INCREASE DIVIDENDS ON A REGULAR BASIS AND MAINTAIN A LONG-TERM AVERAGE PAYOUT RATIO IN THE RANGE OF 65 TO 75 PERCENT. NSP has increased its dividend for 23 consecutive years. In June 1997, NSP's annualized common dividend rate was increased by 6 cents per share, or 2.2 percent, from $2.76 to $2.82. The dividend payout ratio was 89.4 percent in 1997, above the objective range due to the unusual events that adversely affected NSP's earnings in 1997. (See discussion under Results of Operations.) The objective payout ratio is based on long-term earnings expectations. * TO MAINTAIN LONG-TERM AVERAGE ANNUAL EARNINGS PER SHARE GROWTH OF 5 PERCENT FROM ONGOING OPERATIONS, AS DESCRIBED BELOW. Excluding the nonrecurring items discussed later under Factors Affecting Results of Operations, NSP's earnings per share have grown by an average annual rate of 4.1 percent since 1993. 1997 1996 1995 --------------------------------------------------------------------------- EARNINGS PER SHARE FROM ONGOING OPERATIONS $3.54 $3.82 $3.69 Earnings (losses) from nonrecurring items (.33) 0.22 --------------------------------------------------------------------------- Total earnings per share $3.21 $3.82 $3.91 =========================================================================== * TO PROVIDE AT LEAST 20 PERCENT OF NSP EARNINGS FROM NRG BUSINESSES BY THE YEAR 2000. NRG expects to meet this goal through the growing profitability of existing businesses and the addition of new businesses. Businesses owned by NRG provided 39 cents, or 11 percent, of NSP's earnings per share from ongoing operations in 1997, and 29 cents, or 7.6 percent, of NSP's earnings per share from ongoing operations in 1996. * TO MAINTAIN CONTINUED FINANCIAL STRENGTH WITH A AA RATING FOR UTILITY BONDS. The Company's first mortgage bonds continued to be rated AA by Fitch Investors Service, Inc. In October 1997, S&P's raised NSP's bond rating to AA, as a part of an industry re-evaluation. In July 1997, Moody's Investors Services (Moody's) upgraded its rating on NSP's first mortgage bonds to Aa3. Moody's rating action reflects NSP's progress in satisfying legislative requirements associated with spent-fuel storage at Prairie Island and various other factors. Moody's also cited NSP's healthy competitive position and strong financial condition. Duff & Phelps, Inc. raised the Company's bond rating to AA in February 1998. First mortgage bonds issued by the Wisconsin Company carry comparable ratings. NSP's pretax interest coverage ratio for utility operations, based on income excluding Allowance for Funds Used During Construction (AFC), was 3.5 in 1997. A capital structure consisting of 46.7 percent common equity at year-end 1997 contributes to NSP's financial flexibility and strength.
BUSINESS STRATEGIES NSP's mission is to be a recognized leader in the energy industry by increasing the value provided to our customers with energy-related products and services. We will utilize the skills and talents of our people to thrive in a dynamic and competitive energy environment that provides increased value for our customers and shareholders and significant growth opportunities for our company. Strategies to achieve this mission include: * EXCEEDING CUSTOMER REQUIREMENTS. Anticipate and exceed customer requirements by balancing costs, benefits and expectations to maximize value for each customer. * IMPROVE COMPETITIVENESS. Achieve and maintain best quartile status in the service and price of providing our electric and gas products. * SUPPORT EMPLOYEES. Gain competitive advantage by fully utilizing the diversity, skills and talents of our people. * SUPPORT THE COMMUNITY AND THE ENVIRONMENT. Preserve and enhance NSP's name and reputation by protecting the environment and helping to meet the social and economic needs of the community, thereby contributing to the growth of the community and creating support for our business requirements. * GROW THE BUSINESS PROFITABLY. Build on our core businesses, subsidiaries and strategic acquisitions to profitably grow our company, enhance shareholder value and excel in a dynamic industry environment. FINANCIAL REVIEW 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 1997 and 1996. 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. Material changes in balance sheet items are discussed below and in the accompanying Notes to Financial Statements. Except for the historical information contained herein, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "estimate," "expect," "objective," "possible," "potential" and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including their impact on capital expenditures; business conditions in the energy industry; competitive factors; unusual weather; changes in federal or state legislation; regulation; the items discussed under "Factors Affecting Results of Operations"; and the other risk factors listed from time to time by the Company in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.01 to the Company's 1997 report on Form 10-K.
RESULTS OF OPERATIONS 1997 COMPARED WITH 1996 AND 1995 NSP's 1997 earnings per share from ongoing operations (assuming dilution) were $3.54, down 28 cents, or 7.3 percent, from the $3.82 earned in 1996 and down 15 cents, or 4.1 percent, from the $3.69 earned in 1995. NSP's total earnings per share (assuming dilution), including nonrecurring transactions in 1997 and 1995 (as discussed later), were $3.21 in 1997, $3.82 in 1996 and $3.91 in 1995. Nonrecurring transactions in 1997 include the write-off of costs incurred prior to the termination of NSP's proposed merger with Wisconsin Energy Corporation (WEC) and NRG's write-down of a cogeneration project. Regulated utility businesses generated earnings of $3.24 per share from ongoing operations in 1997, $3.58 in 1996 and $3.41 in 1995. Earnings from ongoing regulated operations were lower in 1997, primarily due to higher utility operations, maintenance and depreciation expenses, the impacts of less favorable weather, and dilutive effects of stock issuances. Partially offsetting these earnings decreases were growth in electric sales and reduced administrative costs. Nonregulated businesses generated earnings from ongoing operations of 30 cents per share in 1997, 24 cents in 1996 and 28 cents in 1995. Nonregulated earnings increased in 1997 primarily due to higher NRG earnings from new projects, including tax credits. Increased financing costs at NRG and losses incurred by EMI partially offset these increases. UTILITY OPERATING RESULTS ELECTRIC REVENUES Sales to retail customers, which account for more than 90 percent of NSP's electric revenue, increased 1.5 percent in 1997 and 1.0 percent in 1996. Sales in 1997 included unfavorable weather impacts compared with normal average temperatures, and sales in 1996 and 1995 included favorable weather impacts compared with normal average temperatures, with the retail sales impact for 1996 being less favorable than it was in 1995. Total electric sales volumes increased 0.6 percent in 1997 and decreased 3.0 percent in 1996. Lower sales volumes to other utilities in 1997 and 1996 and the loss of several municipal power customers in 1995 and 1996 partially offset the retail sales growth in 1997 and contributed to the 1996 decrease. On a weather-adjusted basis, retail electric sales volumes are estimated to have increased 2.6 percent in 1997 and 1.5 percent in 1996. Retail electric sales growth for 1998 is estimated to be 2.0 percent over 1997, or 1.5 percent, on a weather-adjusted basis. Sales volumes to other utilities decreased 5.2 percent in 1997, while revenues increased in 1997 (as shown in the following table). Constraints on NSP's system due to unscheduled plant outages and storms (as discussed later) contributed to the decrease in volumes in 1997, while higher market prices due to market conditions contributed to the revenue increase in 1997. Market conditions and regional transmission system constraints contributed to the sales decrease in 1996. The table below summarizes the principal reasons for the electric revenue changes during the past two years: (Millions of dollars) 1997 VS. 1996 1996 vs. 1995 - -------------------------------------------------------------------------------- Retail sales growth (excluding weather impacts) $47 $ 29 Estimated impact of weather on retail sales volume (23) (15) Sales to other utilities 14 (20) Municipal power sales (6) (15) Conservation cost recovery 10 13 Fuel cost recovery 31 (10) Other rate changes (1) (5) Transmission and other electric revenues 19 8 - -------------------------------------------------------------------------------- Total revenue increase (decrease) $91 $(15) ================================================================================
ELECTRIC PRODUCTION EXPENSES Fuel expense for electric generation in 1997 increased $8.8 million, or 2.9 percent, compared with a decrease of $24.5 million, or 7.5 percent, in 1996. The 1997 increase is primarily due to higher average fossil fuel prices, mainly reflecting the increased use of higher-cost plants due to plant outages and transmission line and plant limitations, as discussed later. In 1997, management decided to take the Company's Monticello nuclear generating plant, a baseload plant, out of service to accelerate implementation of a design change originally planned for 1998. In addition, during the summer of 1997, portions of transmission lines connecting two of NSP's baseload generating plants, the Monticello nuclear and Sherco fossil plants, to the Minneapolis-St. Paul metro area were damaged by storms. Until repairs were completed later in 1997, the Company's generating and transmission capabilities were temporarily reduced. As a result, NSP increased generation at its more expensive peaking plants and purchased more power to meet 1997 sales requirements. The 1996 decrease was primarily due to lower average fuel costs resulting from a new coal transportation contract in July 1995, and lower plant output caused by decreased electric sales, planned maintenance outages and conversion of two plants to peaking status. Purchased power costs increased $42.7 million, or 17.5 percent, in 1997 after decreasing $4.1 million, or 1.7 percent, in 1996. The 1997 increase was primarily due to higher purchases, higher average market prices and higher demand expenses. The higher purchases were a result of lower plant availability due to the unplanned nuclear plant outage and storms, as discussed previously, and higher 1997 sales requirements. The 1996 decrease primarily was due to lower demand expenses. GAS REVENUES The majority of NSP's retail gas sales are categorized as firm (primarily heating customers) and interruptible (commercial/industrial customers with an alternate energy supply). Firm sales in 1997 decreased 10.8 percent compared with 1996 sales, while firm sales in 1996 increased 13.2 percent compared with 1995 sales. The decrease in 1997 was primarily due to the impacts of favorable weather in 1996 and unfavorable weather in 1997, partially offset by sales growth. The increase in 1996 primarily was due to strong sales growth and favorable impacts of weather. On a weather-adjusted basis, firm gas sales are estimated to have increased 2.2 percent in 1997 and increased 5.1 percent in 1996. The firm sales increase in 1997 was partially offset by lost gas sales as a result of flooding in the Grand Forks area. Firm gas sales in 1998 are estimated to be 7.0 percent higher compared with 1997 sales, or 3.3 percent higher on a weather-adjusted basis. Interruptible sales of gas increased 11.6 percent in 1997 and 3.6 percent in 1996. The increases in both years are the result of favorable gas market prices compared with alternate fuels that caused large interruptible customers with alternate fuel sources to use more natural gas. Other gas deliveries, including Viking sales, increased 0.6 percent in 1997 and 5.3 percent in 1996. Viking gas transmission deliveries to parties other than NSP increased 4.8 percent in 1997 and 7.7 percent in 1996. The table below summarizes the principal reasons for the gas revenue changes during the past two years: (Millions of dollars) 1997 VS. 1996 1996 vs. 1995 - -------------------------------------------------------------------------------- Sales growth (excluding weather impacts) $13 $ 25 Estimated impact of weather on firm sales volume (41) 13 Purchased gas adjustment clause recovery 28 52 Conservation cost recovery and other rate changes (1) 6 Transportation and other (11) 5 - -------------------------------------------------------------------------------- Total revenue increase (decrease) $(12) $101 ================================================================================ COST OF GAS PURCHASED AND TRANSPORTED The cost of gas purchased and transported decreased $4.2 million, or 1.2 percent, in 1997, primarily due to lower gas sendout partially offset by a 6.7 percent increase in the per unit cost of purchased gas. The lower sendout reflects decreased gas sales, as discussed previously, while the increase in cost per unit of purchased gas, occurring mainly in the first quarter of 1997, reflects changes in market conditions. The cost of gas purchased and transported increased $78.7 million, or 30.6 percent, in 1996, primarily due to a 20.5 percent increase in the per unit cost of purchased gas and higher gas sendout. The increase in gas sendout reflects increased gas sales, while the increase in cost per unit of purchased gas reflects changes in market conditions.
OTHER OPERATION, MAINTENANCE AND ADMINISTRATIVE AND GENERAL These expenses, in total, increased by $37.4 million, or 5.9 percent, in 1997, compared with a decrease of $24.9 million, or 3.8 percent, in 1996. The higher costs in 1997 are primarily due to increased operating expenses associated with 1997 business interruptions, higher customer service expenses, increased network transmission service (NTS) costs, as discussed under Factors Affecting Results of Operations, higher scheduled plant maintenance outage expenses and higher technology improvement expenses. Business interruptions in 1997 included flooding in the Company's service area, the unscheduled Monticello plant outage and storm damage to transmission lines. Technology improvements included development of customer information, automated meter reading and other systems, including preparation for the year 2000. These cost increases were partially offset by a $6.9 million decrease in administrative and general expenses, reflecting decreases in insurance and employee benefit costs. The lower costs in 1996 largely are due to lower administrative and general costs, partly offset by higher scheduled plant maintenance outage expenses and provisions for uncollectible accounts. Administrative and general expenses in 1996 reflect fewer employees and decreases in insurance and claims, employee benefit and other corporate costs. (See Note 8 to the Financial Statements for a summary of administrative and general expenses.) CONSERVATION AND ENERGY MANAGEMENT Expenses increased in both 1997 and 1996 mainly due to higher amortization levels of deferred electric and gas conservation and energy management program costs. Higher cost levels in 1996 also include the effects of expensing currently (rather than amortizing over a period of time) new conservation expenditures beginning in 1996. These higher amortization and cost levels are recovered concurrently through retail rate adjustment clauses in the Company's Minnesota jurisdiction, which are discussed later under Factors Affecting Results of Operations. DEPRECIATION AND AMORTIZATION The increases in 1997 and 1996 reflect higher levels of depreciable plant, including new information systems and equipment in 1997 and 1996 with relatively short useful lives. Information technology improvements are expected to continue in 1998. PROPERTY AND GENERAL TAXES Property and general taxes decreased in 1997 and 1996, primarily due to lower property tax rates partially offset by increases due to property additions. UTILITY INCOME TAXES The variations in income taxes primarily are attributable to fluctuations in taxable income and changes to effective tax rates. (See Note 7 to the Financial Statements for a detailed reconciliation of the statutory tax rate to NSP's effective tax rate.) NONOPERATING ITEMS RELATED TO UTILITY BUSINESSES MERGER COSTS In May 1997, NSP and WEC mutually terminated their plans to merge. NSP's earnings for 1997 include a pretax charge to nonoperating expense of $29 million, or 25 cents per share, to write off its cumulative merger-related costs incurred. This charge is being reported as a nonrecurring item outside of earnings from ongoing operations. UTILITY FINANCING COSTS Interest costs recognized for NSP's utility businesses, including amounts capitalized to reflect the financing costs of construction activities, were $120.3 million in 1997, $123.1 million in 1996 and $123.4 million in 1995. The 1997 decrease is due primarily to lower average short-term borrowing levels, and the retirement of $100 million of first mortgage bonds in October 1997. The slight 1996 decrease is largely due to lower interest costs on variable rate long-term debt, partially offset by higher average short-term borrowing levels. The average short-term debt balance was $208.3 million in 1997, $265.4 million in 1996 and $208.7 million in 1995. In addition to interest expense, beginning in 1997, financing costs of NSP's utility businesses include distributions on redeemable preferred securities.
NONREGULATED BUSINESS RESULTS NSP's nonregulated operations include diversified businesses such as NRG's businesses, which are primarily independent power production, commercial and industrial heating and cooling, and energy-related refuse-derived fuel production. In addition, EMI's primary business is energy sales and service. NSP also has investments in affordable housing projects through Eloigne and several income-producing properties through other subsidiaries. Due to the nature of these nonregulated businesses, NSP anticipates that the earnings from nonregulated operations will experience more variability than regulated utility businesses. As discussed below and shown in Note 8 to the Financial Statements, NSP's nonregulated earnings for these periods are experiencing such variability. The following summarizes the earnings contributions of NSP's nonregulated businesses: CONTRIBUTION TO NSP'S EARNINGS PER SHARE 1997 1996 1995 - -------------------------------------------------------------------------------- NRG: Ongoing operations $0.39 $0.29 $0.24 Nonrecurring items (0.08) 0.00 0.22 Eloigne 0.06 0.05 0.02 EMI (0.15) (0.12) (0.02) Seren Innovations (0.02) .00 .00 Other (1) 0.02 0.02 0.04 - ------------------------------------------------------------------------------- Total $0.22 $0.24 $0.50 =============================================================================== (1) Includes NSP-owned refuse-derived fuel operations managed by NRG NRG NRG's earnings from ongoing operations (excluding the nonrecurring transaction discussed later) increased in 1997, compared with 1996, primarily due to income from new projects, including tax credits. New projects contributing to NRG's earnings increase include: Bolivian Power Company Ltd. (COBEE); Pacific Generation Company (PGC); the Schkopau power generating facility in Germany, which began operation in July 1996; and the Australian State of Victoria's Loy Yang A power plant in which NRG, through affiliates, purchased a 25.37 percent interest in May 1997. NRG's landfill gas subsidiary, NEO, has entered into projects in 1996 and 1997 that are generating higher levels of energy tax credits. Also contributing to NRG's increased earnings were the gains on the sale of equity interests in two projects late in 1997. Higher interest costs due to the $250 million senior notes issued in mid-1997 partially offset the increased earnings. NRG's earnings in 1997 were adversely affected by declines in the value of the Australian dollar and German deutsche mark in relation to the U.S. dollar. Had exchange rates throughout 1997 stayed the same as the beginning of the year, NRG's 1997 earnings would have been higher by approximately 4 cents per share. As of year-end 1997, NRG and its partner's effort to restructure the debt of the 58-megawatt Sunnyside cogeneration project in Utah was not successful. Due to a lack of progress in restructuring the project's debt, NRG recorded a nonrecurring expense of 8 cents per share to write down its investment in the Sunnyside project late in 1997. This write-down reduced income from nonregulated businesses before interest and taxes by $9 million for 1997 and is considered a nonrecurring item. Excluding the nonrecurring items discussed later, NRG's earnings from ongoing operations increased in 1996, compared with 1995, due primarily to higher equity in earnings of projects. Equity in earnings of projects increased in 1996, primarily due to first-time earnings from Schkopau and NRG Generating (U.S.) Inc. and higher income from Scudder Latin American Power Projects. These earnings were partially offset by lower equity earnings from the MIBRAG project. Equity in earnings from MIBRAG decreased, primarily due to an expected decline in heating briquette and coal sales. NRG's earnings from ongoing operations were higher in 1996, as compared with 1995, despite experiencing an increased level of business development costs in 1996 as it pursued several international and domestic projects. Until there is substantial assurance that a project in development will come to financial closure, such costs are expensed. NRG's earnings for 1995 included two nonrecurring items that added 22 cents to 1995 earnings. A gain of approximately 26 cents per share was recorded for a power sales contract termination settlement, which was partially offset by a domestic energy project write-down of 4 cents per share. Further information on NRG's financial results may be obtained from NRG's annual report on Form 10-K filed with the SEC.
EMI EMI's losses for 1997 were higher than 1996, primarily due to losses incurred by EMI's gas marketing joint venture, Enerval, the partial write-down of EMI's investment in Enerval, and increased expenses related to combining operations with Energy Solutions International, Inc. (ESI) and Energy Masters Corporation (EMC), both purchased by EMI in July 1997. These increased losses were partially offset by increased operating margins, primarily due to the curtailment of gas trading activity in the second quarter of 1996, which had negatively impacted operating margins during the first half of 1996. EMI is currently in the process of evaluating proposals for the sale of its interest in Enerval and expects to finalize the sale during the first quarter of 1998. EMI's investment in and advances to Enerval have been written down to an estimate of their net realizable value. EMI's earnings for 1996 decreased, compared with 1995, largely due to price volatility in the gas market, which adversely affected earnings from Enerval, and losses incurred from the gas trading business. OTHER Eloigne's earnings have continued to grow in 1997 and 1996 due to investments in new affordable housing projects. NSP's new communications and data services subsidiary, Seren Innovations, experienced a loss in its first year, 1997, as it focused on development of its products and services. FACTORS AFFECTING RESULTS OF OPERATIONS NSP's results of operations during 1997, 1996 and 1995 primarily were dependent upon the operations of the Company's and Wisconsin Company's utility businesses, consisting of the generation, transmission, distribution 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 approve the prices for electric and gas service within their respective jurisdictions. In addition, NSP's nonregulated businesses are contributing 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: REGULATION NSP's utility rates are approved by the Federal Energy Regulatory Commission (FERC) and state regulatory commissions in Minnesota, North Dakota, South Dakota, Wisconsin and Michigan. 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 comprehensive 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 retail rate schedules provide for cost-of-energy and resource adjustments to billings and revenues for changes in the cost of fuel for electric generation, purchased energy, purchased gas, and, in Minnesota, conservation and energy management program costs. For Wisconsin electric operations, where cost-of-energy adjustment clauses are not used, the biennial retail rate review process and an interim fuel cost hearing process provide the opportunity for rate recovery of 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 the cost of capital. As discussed in Note 1 to the Financial Statements, regulated public utilities are allowed to record as assets certain costs that would be expensed by nonregulated enterprises, and to record as liabilities certain gains that would be recognized as income by nonregulated enterprises. If deregulation or other changes in the regulatory environment occur, NSP may no longer be eligible to apply this accounting treatment and may be required to eliminate such regulatory assets and liabilities from its balance sheet. Such changes could have a material adverse effect on NSP's results of operations in the period the write-off is recorded. At Dec. 31, 1997, NSP reported on its balance sheet approximately $212 million and $129 million of regulatory assets and liabilities, respectively, that would need to be recognized in the income statement in the absence of regulation. Included in these regulatory assets are $87 million of conservation expenditures that are anticipated to be substantially recovered by the year 2000 based on accelerated recovery available through resource adjustment clauses to customer rates, as discussed previously. In addition to a potential write-off of regulatory assets and liabilities, deregulation and competition (as discussed later) may require recognition of certain "stranded costs" not recoverable under market pricing. NSP currently is
recovering its costs in all regulated jurisdictions and does not expect to write off to expense any "stranded costs" unless and until market price levels change, or unless cost levels increase above market price levels. RATE FILINGS On Dec. 2, 1997, the Company filed a natural gas rate case seeking an annual rate increase of approximately $18.5 million for retail customers in Minnesota. An interim rate increase totaling $13.9 million on an annual basis has been approved, subject to refund, effective Feb. 1, 1998. On Nov. 14, 1997, the Wisconsin Company filed retail electric and natural gas rate cases for Wisconsin customers requesting that the rate changes become effective during the second quarter of 1998. The Wisconsin Company is seeking an annual increase in retail electric rates of approximately $12.7 million and an annual decrease in retail natural gas rates of approximately $1.7 million. On February 17, 1998, NSP filed a rate application with the FERC to update its rates for point to point transmission service. As filed, the proposed rates increase annual transmission revenues by approximately $4 million. In addition, the filing is expected to support reductions in NSP's NTS costs, as discussed later. COMPETITION The Energy Policy Act of 1992 (the Act) has been 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 of 1935 (PUHCA) promoted creation of wholesale nonutility power generators and authorized the FERC to require utilities to provide wholesale transmission services to third parties. The legislation allows utilities and nonregulated companies to build, own and operate power plants nationally and internationally without being subject to restrictions that previously applied to utilities under the PUHCA. NSP plans to continue its efforts to be a competitively priced supplier of electricity and an active participant in the competitive market for electricity. In 1996, the FERC issued Orders No. 888 and 889, which have had a significant impact on wholesale electric markets by giving competitors the ability to transmit electricity through utilities' transmission systems. Order No. 888 granted nondiscriminatory access to transmission service. Order No. 889 ensures a fair market by imposing standards of conduct on transmission system owners, by requiring separation of the wholesale power supply ("merchant") function from the transmission system operation function and by mandating the posting of transmission availability and pricing information on an electronic bulletin board. These new open access rules became effective in 1996 and 1997. In 1997, the FERC issued clarifying final orders in response to rehearing requests by numerous market participants regarding Orders No. 888 and 889. These FERC clarifying final orders are currently being appealed in federal court. NSP has made transmission filings with the FERC and believes it is taking the proper steps to comply with the new rules as they become effective. NSP continues to be generally supportive of the FERC's efforts to increase competition. In compliance with FERC Orders No. 888 and 889, NSP has separated personnel who perform the merchant function, which includes power and energy marketing and trading, from personnel who perform the transmission system operation function. In 1997, NSP's merchant function, NSP Energy Marketing, expanded its power trading to focus on new market opportunities created by open transmission access. NSP is also developing risk management practices to respond to the rapidly growing electric commodity market. In addition, a significant effort was put forth in 1997 to enter current and all new requests for transmission service into the electronic bulletin board, as directed by FERC Order No. 889 and supported by NSP. The FERC Order No. 888 requires utilities to offer, among other services, Network Transmission Service (NTS) to qualifying customers. Under NTS, NSP and other qualifying regional utilities share the total annual costs of operating and maintaining the regional transmission network that NSP uses, net of related network revenues, based on each company's share of the total network load. The transmission tariff filed with the FERC is used as the cost basis for FERC-regulated utilities in determining NTS rates. In 1997, NSP conducted a review of information received from other participating utilities and commenced settlement negotiations with these utilities regarding the final amount of NTS costs to be paid by NSP for 1997. Based on this review and discussion, NSP concluded that its net NTS costs for 1997 were less than the $27 million previously estimated. NSP recorded a liability for what management believes is a reasonable estimate of the net NTS costs for 1997. NSP expects that its transmission tariff filing and settlement negotiations will result in lower NTS costs in 1998. Some states have begun to allow retail customers to choose their electricity supplier, and many other states are considering retail access proposals. NSP believes that retail competition will result in more innovative services and
lower prices for all consumers if the transition is managed in a thoughtful manner. NSP supports fair and equal treatment for all competitors, recovery of utilities' investments made under traditional regulation and a resolution of property tax issues. NSP supports a plan that would take two or three years to resolve these issues and develop infrastructure, and another two to three years to phase in customers' choice. In 1997, the Minnesota Public Utilities Commission (MPUC) approved a report by its staff that identifies issues that must be resolved before retail competition can begin, but did not approve an action plan or schedule for its implementation. The Minnesota Legislature began studying the issues in 1997 and concluded that another year of study was necessary before any action could be taken. The Public Service Commission of Wisconsin (PSCW) revised its restructuring plan, delaying the start of retail competition another year to 2002. The Michigan Public Service Commission (MPSC) approved a plan to begin offering a choice of suppliers to retail customers in selected markets in 1998. That plan was unsuccessfully challenged by the affected Michigan utilities, and the courts upheld the MPSC's authority to implement retail competition. The timing of regulatory actions regarding restructuring and their impact on NSP cannot be predicted at this time and may be significant. USED NUCLEAR FUEL STORAGE AND DISPOSAL In 1994, NSP received legislative authorization from the state of Minnesota for the use of 17 casks for temporary spent-fuel storage at the Company's Prairie Island nuclear generating facility. Based on assumptions in the original Certificate of Need granted by the MPUC, the Company previously estimated that 17 casks would allow operation of the Prairie Island facility to continue to 2003. After review of the 1994 legislative authorization which amends the Certificate of Need, and through the use of longer fuel cycles, the Company has determined 17 casks will allow operation of the facility until 2007. The first nine casks have been authorized by the Minnesota Environmental Quality Board (MEQB). The Company had loaded seven of the casks as of Dec. 31, 1997. As a condition of the authorization, the Minnesota Legislature established several resource commitments for the Company, including wind and biomass generation sources, as well as other requirements. The Company has taken steps to fulfill these requirements. The MEQB has terminated an alternative siting process, which had been one of the original legislative requirements. Regarding permanent fuel storage, in 1996 the Company and other utilities were successful in a lawsuit against the U.S. Department of Energy (DOE) to compel it to fulfill its statutory and contractual obligations to store and dispose of used nuclear fuel as required by the Nuclear Waste Policy Act of 1982. In January 1997, the Company, other utility parties and state parties filed another lawsuit against the DOE, requesting authority to withhold payments to the DOE for the permanent disposal program. In April 1997, the parties filed for additional relief, asking the U.S. Court of Appeals for the District of Columbia (the Court) to order the DOE to take spent nuclear fuel by Jan. 31, 1998. In November, 1997, the Court, in a unanimous ruling, reiterated the unconditional obligation for the DOE to begin acceptance of spent nuclear fuel by Jan. 31, 1998. The Court confirmed this obligation exists under both the statute and the standard contract; however, the Court denied the Company's request for an order directing the DOE to accept spent nuclear fuel by the Jan. 31, 1998 date in the standard contract, finding that the contractual remedies under the standard contract, i.e., damages, may be adequate. The Court also held that the DOE cannot use its own delays or the unavailability of a permanent disposal or temporary storage facility as defense to utilities' actions for damages. In its November 1997 decision, the Court did not discuss the request to escrow payments to the Nuclear Waste Fund. In December 1997, the DOE petitioned the Court for rehearing. Based on the Court's ruling, NSP and other utilities are currently analyzing claims against the DOE for the costs incurred as a result of the DOE's failure to meet its statutory and contractual obligations. However, it is still unknown when the DOE actually will begin accepting used fuel. Consequently, the Company continues to rely on interim on-site storage facilities. Also, the Company is part of a consortium to establish a private facility for interim storage of used nuclear fuel, the availability of which is uncertain at this time. (See Notes 13 and 14 to the Financial Statements for more information.) TECHNOLOGY CHANGES FOR THE YEAR 2000 Like many other companies, NSP expects to incur significant costs to modify or replace existing technology, including computer software, for uninterrupted operation in the year 2000 and beyond. In 1996, NSP's Board of Directors approved funding to address development and remediation efforts related to the year 2000. A committee made up of senior management is leading NSP's initiatives to identify year 2000 related issues and remediate business processes as necessary in 1998. Testing of computer software modifications and other remediated processes is scheduled for 1999. NSP is also working with major suppliers so that NSP does not experience business interruptions due to year 2000 issues in the suppliers' business processes. The amount of additional development and remediation costs necessary after 1997 for NSP to prepare for the year
2000 is estimated to be approximately $20 million, expected mainly in 1998. In 1997 and 1996, NSP expensed approximately $2.3 million and $0.6 million, respectively, for this modification effort. 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. 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 for environmental compliance. In addition to nuclear decommissioning and used nuclear fuel disposal expenses (as discussed in Note 13 to the Financial Statements), costs charged to NSP's operating expenses for environmental monitoring and disposal of hazardous materials and wastes were approximately $31 million in 1997, $31 million in 1996 and $26 million in 1995, and are expected to average approximately $35 million per year for the five-year period 1998-2002. However, the precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are currently unknown. In each of the years 1997, 1996 and 1995, the Company spent about $19 million, $10 million and $13 million, respectively, for capital expenditures on environmental improvements at its utility facilities. In 1998, the Company expects to incur approximately $18 million in capital expenditures for compliance with environmental regulations and approximately $142 million for the five-year period 1998-2002. These capital expenditure amounts include the costs of constructing used nuclear fuel storage casks. (See Notes 13 and 14 to the Financial Statements for further discussion of these and other environmental contingencies that could affect NSP.) WEATHER NSP's earnings can be significantly affected by unusual weather. In 1997, warmer-than-normal weather late in the year decreased earnings over a normal year by an estimated 11 cents per share. In 1996, colder-than-normal weather during the heating season increased earnings over a normal year by an estimated 16 cents per share. In 1995, unusual weather, mainly a hot summer, increased earnings over a normal year by an estimated 21 cents per share. The effect of weather is considered part of NSP's ongoing business operations. IMPACT OF NONREGULATED INVESTMENTS A significant portion of NSP's earnings comes from nonregulated operations, as discussed in the Results of Operations section. NSP expects to continue investing in nonregulated projects, including domestic and international power production projects through NRG, as described under Future Financing Requirements. The nonregulated projects in which NRG has invested carry a higher level of risk than NSP's traditional utility businesses. Current investments in nonregulated projects are subject to competition, operating risks, dependence on certain suppliers and customers, and domestic and foreign environmental and energy regulations. Nonregulated project investments also may be subject to partnership and government actions and foreign government, political, economic and currency risks. Future nonregulated projects will be subject to development risks, including uncertainties prior to final legal closing, in addition to some or all of the previously identified risks. Most of NRG's current project investments (as listed in Note 10 to the Financial Statements) consist of minority interests, and a substantial portion of future investments may take the form of minority interests, which may limit NRG's financial risk and ability to control the development or operation of the projects. In addition, significant expenses may be incurred for projects pursued by NRG that do not materialize. The aggregate effect of these factors creates the potential for volatility in the nonregulated component of NSP's earnings. Accordingly, the historical operating results of NSP's nonregulated businesses may not necessarily be indicative of future operating results. ACCOUNTING CHANGES The Financial Accounting Standards Board (FASB) has proposed new accounting standards that would require the full accrual of nuclear plant decommissioning and certain other site exit obligations. Material adjustments to NSP's balance sheet would occur upon implementation of the FASB's proposal, which does not currently have a scheduled effective date. However, the effects of regulation are expected to minimize or eliminate any impact on operating expenses and earnings from this future accounting change. (For further discussion of the expected impact of this change, see Note 13 to the Financial Statements.) USE OF DERIVATIVES Through its nonregulated subsidiaries, NSP uses derivative financial instruments to mitigate the impact of changes in foreign currency exchange rates and natural gas prices, and changes in interest rates on the cost of borrowing. Also, to mitigate the interest rate risk associated with fixed rate debt in a declining interest rate environment, NSP uses interest rate swap agreements to convert fixed rate debt to variable rate debt. (See Notes 1 and 11 to the Financial Statements for further discussion of NSP's financial instruments and derivatives.)
NONRECURRING ITEMS NSP's earnings for 1997 include two significant unusual or infrequently occurring items. As discussed previously, NSP recorded a nonrecurring charge of $29 million, or 25 cents per share, to write off costs previously deferred as a result of the proposed merger with WEC. Also, as discussed in the Nonregulated Business Results section, NRG wrote down a cogeneration project, reducing income from nonregulated businesses before interest and taxes by $9 million, or 8 cents per share. NSP's earnings for 1995 include two significant unusual or infrequently occurring items. As discussed in the Nonregulated Business Results section, NRG recognized a pretax gain of approximately $30 million, or 26 cents per share, from a power sales contract termination settlement. Partially offsetting this gain was an asset impairment write-down of $5 million before taxes, or 4 cents per share, for a nonregulated domestic energy project. INFLATION Inflation at its current level is not expected to materially affect NSP's prices to customers or returns to shareholders. LIQUIDITY AND CAPITAL RESOURCES 1997 FINANCING REQUIREMENTS NSP's need for capital funds primarily is 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 nonregulated businesses. Total NSP utility capital expenditures (including AFC) were $397 million in 1997. Of that amount, $305 million related to replacements and improvements of NSP's electric system and nuclear fuel, and $72 million involved construction of natural gas distribution and transmission facilities. NSP companies invested approximately $591 million in 1997 for equity interests in and loans to nonregulated projects, for the acquisition of existing businesses and for additions to nonregulated property. NRG invested in many energy projects in 1997, including the $149 million purchase of PGC, and several equity investments, the largest of which are listed in Note 10 to the Financial Statements. Eloigne invested in affordable housing projects, including wholly owned properties and limited partnership ventures. 1997 FINANCING ACTIVITY During 1997, NSP's sources of capital included internally generated funds and external financings, as discussed later. The allocation of financing requirements between these capital resources is based on the relative cost of each resource, regulatory restrictions and the constraints of NSP's long-range capital structure objectives. Funds generated internally from operating cash flows in 1997 remained sufficient to meet working capital needs, debt service, dividend payout requirements and nonregulated investment commitments, as well as to fund a significant portion of construction expenditures. NSP's objective pretax interest coverage ratio for utility operations is 3.5 - 5.0. The utility pretax interest coverage ratio, excluding AFC, was 3.6 in 1997, 4.4 in 1996, and 4.1 in 1995, which falls within the objective range. Internally generated funds from utility operations could have provided financing for more than 100 percent of NSP's utility capital expenditures for 1997 and approximately 90 percent of the $1.9 billion in utility capital expenditures incurred for the five-year period 1993-1997. The pretax interest coverage ratio, excluding AFC, for all NSP operations was 2.8 in 1997, 3.7 in 1996 and 3.8 in 1995. The 1997 decline in the coverage ratio is due to the unusual events that adversely affected NSP's earnings in 1997, as discussed previously in the Results of Operations section, and issuance of new debt by NRG, as discussed later. NSP had approximately $260 million in short-term borrowings, including $122 million related to NRG, outstanding as of Dec. 31, 1997. Throughout 1997, the Company used short-term borrowings to temporarily finance a portion of utility capital expenditures and provide for other cash needs. NRG's line of credit borrowings were used for the acquisition of PGC and other corporate purposes. In the utility businesses, during 1997 NSP issued $200 million of 7.875 percent preferred securities through a wholly owned special purpose subsidiary trust and used the proceeds to redeem two preferred stock issues and reduce short-term debt levels. The Company also collateralized $188 million of outstanding pollution control bonds under its first mortgage indenture, and Viking issued $14 million of long-term debt to finance an expansion project. NSP's 1997 business acquisition, equity investments in nonregulated projects, and construction expenditures were primarily financed through internally generated funds and the issuance of debt by nonregulated subsidiaries. NRG issued $250 million of 7.5 percent unsecured publicly traded Senior Notes in 1997 to support equity requirements for projects currently under way and in development. The Senior Notes were assigned ratings of BBB- by S&P and
Baa3 by Moody's. Project financing requirements, in excess of equity contributions from investors, were satisfied with project debt and loans from NSP's nonregulated businesses (mainly NRG). Project debt associated with many of NSP's nonregulated investments is not reflected in NSP's balance sheet because the equity method of accounting is used for such investments. (See Note 10 to the Financial Statements.) Loans made by NSP to nonregulated projects are reflected separately on the balance sheet as Notes Receivable from Nonregulated Projects. During 1997, the Company issued 5.6 million shares of common stock. Of these shares, 4.9 million were sold to a group of underwriters in September 1997 at an offering price to the public of $49.5625 per share. The net proceeds to the Company of $237 million were used for general corporate purposes, including the retirement of $100 million of first mortgage bonds that matured Oct. 1, 1997, expenditures for the Company's construction program and the repayment of short-term borrowings. Of the remaining new shares, 0.3 million were issued under the Dividend Reinvestment and Stock Purchase Plan (DRSPP), 0.2 million were issued under the Employee Stock Ownership Plan (ESOP) and 0.2 million were issued under the Executive Long-Term Incentive Award Stock Plan. FUTURE FINANCING REQUIREMENTS Utility financing requirements for 1998-2002 may be affected in varying degrees by numerous factors, including load growth, changes in capital expenditure levels, rate changes 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 $441 million in 1998 and $2.1 billion for the five-year period 1998-2002. Of the 1998 amount, approximately $371 million is scheduled for electric utility facilities and approximately $49 million for natural gas facilities, including Viking. Approval of the $1.25 billion Viking Voyageur Project, a proposed natural gas transmission pipeline, would increase the total gas expenditures approximately $500 million for the five-year period 1998-2002, with yearly expenditures dependent on FERC approval. In addition to utility capital expenditures, expected financing requirements for the five-year period 1998-2002 include approximately $606 million to retire long-term debt and fund principal maturities. Through its subsidiaries, NSP expects to invest significant amounts in nonregulated projects in the future. Financing requirements for nonregulated project investments will vary depending on the success, timing and level of involvement in projects currently under consideration. NSP's potential capital requirements for nonregulated projects and property are estimated to be approximately $310 million in 1998 and approximately $940 million for the five-year period 1998-2002. These amounts include commitments for NRG investments, as discussed in Note 14 to the Financial Statements, and Eloigne investments of up to $11 million annually in 1998-2002 for affordable housing projects. In addition to the estimated potential investments in nonregulated projects as disclosed above, NSP continues to evaluate opportunities to enhance shareholder returns and achieve long-term financial objectives through investments in projects or acquisitions of existing businesses. These investments could cause significant changes to the capital requirement estimates for nonregulated projects and property. Long-term nonregulated financing may be required for such investments. The Company also will have future financing requirements for the portion of nuclear plant decommissioning costs not funded externally. Based on the most recent decommissioning study approved by regulators, these amounts are anticipated 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, short-term debt, common stock and preferred securities as needed to maintain desired capitalization ratios. Over the long term, NSP's equity investments in nonregulated projects are expected to be financed at the nonregulated subsidiary level, from internally generated funds or the issuance of subsidiary debt. Financing requirements for the nonregulated projects, in excess of equity contributions from project investors, are expected to be fulfilled through project or subsidiary debt. In addition, to provide additional capital to NRG, NSP is considering the public offering of up to 20 percent equity ownership of NRG in late 1998 or 1999. Eloigne expects to finance approximately 60 percent of its estimated five-year investments in affordable housing projects with equity and approximately 40 percent with long-term 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 financing to be required for nuclear decommissioning costs, as discussed above, is unknown 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 1998. Access to securities markets at a reasonable cost is determined in large part by credit quality. The Company's first mortgage bonds are currently rated AA by Standard & Poor's Corporation, Aa3 by Moody's Investors Service, Inc., 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. 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, 1997, with an assumed interest rate of 6.75 percent, the Company could have issued about $2.1 billion of additional first mortgage bonds under its indenture, and the Wisconsin Company could have issued about $351 million of additional first mortgage bonds under its indenture. The Company filed a shelf registration for first mortgage bonds with the SEC in October 1995. Depending on capital market conditions, the Company expects to issue the remaining $300 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 up to $575 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 of $300 million to the Company and an additional $245 million to subsidiaries of the Company, including a $175 million unsecured revolving bank credit facility available to NRG. NSP credit lines make short-term financing available in the form of bank loans, letters of credit and support for commercial paper for utility operations. 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 $500 million of its remaining authorized, but unissued, preferred stock at Dec. 31, 1997, and remained in compliance with all interest and dividend coverage requirements. The Company's Articles of Incorporation authorize an additional 85.4 million shares of common stock in excess of shares issued at Dec. 31, 1997. In 1996, the Company filed a registration statement with the SEC to provide for the sale of up to 1.6 million additional shares of new common stock under the Company's DRSPP and Executive Long-Term Incentive Award Stock Plan. The Company may issue new shares or purchase shares on the open market for its stock-based plans. (See Note 3 to the Financial Statements for discussion of stock awards outstanding.) The Company plans to issue new shares for its DRSPP, ESOP and Executive Long-Term Incentive Award Stock plans in 1998. NSP currently has no plans for any general offerings of common stock in 1998 or 1999. Internally generated funds from utility operations are expected to equal approximately 85 percent of anticipated utility capital expenditures for 1998 and approximately 95 percent of the $2.1 billion in anticipated utility capital expenditures for the five-year period 1998-2002. Internally generated funds from all operations are expected to equal approximately 60 percent and 85 percent of the anticipated total capital requirements for 1998 and the five-year period 1998-2002, respectively. Because NSP has generally been reinvesting foreign cash flows in operations outside the United States, the equity income from foreign investments is not fully available to provide operating cash flows for domestic cash requirements such as payment of NSP dividends, domestic capital expenditures and domestic debt service. Through NRG, NSP is establishing 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 in the future.
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ================================================================================ See Item 14(a)-1 in Part IV for index of financial statements included herein. See Note 16 of Notes to Financial Statements for summarized quarterly financial data. REPORT OF INDEPENDENT ACCOUNTANTS TO THE SHAREHOLDERS OF NORTHERN STATES POWER COMPANY: In our opinion, the accompanying consolidated balance sheets and statements of capitalization and the related consolidated statements of income, of common stockholders' equity and of cash flows present fairly, in all material respects, the financial position of Northern States Power Company, a Minnesota corporation, and its subsidiaries at Dec. 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended Dec. 31, 1997, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. /s/ PRICE WATERHOUSE LLP MINNEAPOLIS, MINNESOTA FEB. 2, 1998
CONSOLIDATED STATEMENTS OF INCOME <TABLE> <CAPTION> Year Ended Dec. 31 ------------------------------------ (Thousands of dollars, except per share data) 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------------ <S> <C> <C> <C> UTILITY OPERATING REVENUES Electric $2 218 550 $2 127 413 $2 142 770 Gas 515 196 526 793 425 814 - ------------------------------------------------------------------------------------------------------------------ Total 2 733 746 2 654 206 2 568 584 - ------------------------------------------------------------------------------------------------------------------ UTILITY OPERATING EXPENSES Fuel for electric generation 309 999 301 201 325 652 Purchased and interchange power 286 239 243 562 247 699 Cost of gas purchased and transported 331 296 335 453 256 758 Other operation 368 545 333 010 318 015 Maintenance 164 542 155 830 158 203 Administrative and general 141 802 148 656 186 147 Conservation and energy management 70 939 69 784 53 466 Depreciation and amortization 325 880 306 432 290 184 Property and general taxes 227 893 232 824 239 433 Income taxes 144 855 161 410 147 148 - ------------------------------------------------------------------------------------------------------------------ Total 2 371 990 2 288 162 2 222 705 - ------------------------------------------------------------------------------------------------------------------ UTILITY OPERATING INCOME 361 756 366 044 345 879 - ------------------------------------------------------------------------------------------------------------------ OTHER INCOME (EXPENSE) Income from nonregulated businesses - before interest and taxes 12 078 18 543 49 611 Allowance for funds used during construction---equity 6 401 7 595 6 794 Merger costs (29 005) Other utility income (deductions)---net (2 886) (1 544) 1 481 Income taxes on nonregulated operations and nonoperating items 48 145 14 600 (5 080) - ------------------------------------------------------------------------------------------------------------------ Total 34 733 39 194 52 806 - ------------------------------------------------------------------------------------------------------------------ INCOME BEFORE FINANCING COSTS 396 489 405 238 398 685 - ------------------------------------------------------------------------------------------------------------------ FINANCING COSTS Interest on utility long-term debt 101 250 101 177 103 298 Other utility interest and amortization 19 063 21 950 20 151 Nonregulated interest and amortization 34 627 18 834 9 879 Allowance for funds used during construction---debt (10 208) (11 262) (10 438) - ------------------------------------------------------------------------------------------------------------------ Total interest charges 144 732 130 699 122 890 Distributions on redeemable preferred securities of subsidiary trust 14 437 - ------------------------------------------------------------------------------------------------------------------ Total Financing Costs 159 169 130 699 122 890 - ------------------------------------------------------------------------------------------------------------------ NET INCOME 237 320 274 539 275 795 Preferred Stock Dividends 11 071 12 245 12 449 - ------------------------------------------------------------------------------------------------------------------ Earnings Available for Common Stock $226 249 $262 294 $263 346 ================================================================================================================== Average Number of Common Shares Outstanding (000's) 70 297 68 561 67 323 Average Number of Common and Potentially Dilutive Shares Outstanding (000's)70 435 68 679 67 416 EARNINGS PER AVERAGE COMMON SHARE - BASIC $3.22 $3.83 $3.91 EARNINGS PER AVERAGE COMMON SHARE - ASSUMING DILUTION $3.21 $3.82 $3.91 Common Dividends Declared per Share $2.805 $2.745 $2.685 - ------------------------------------------------------------------------------------------------------------------ </TABLE> See Notes to Financial Statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS <TABLE> <CAPTION> Year Ended Dec. 31 ------------------------------------ (Thousands of dollars) 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: Net income $237 320 $274 539 $275 795 Adjustments to reconcile net income to cash from operating activities: Depreciation and amortization 358 928 335 605 322 296 Nuclear fuel amortization 40 015 45 774 49 778 Deferred income taxes (5 902) (30 561) (11 076) Deferred investment tax credits recognized (10 061) (9 352) (9 117) Allowance for funds used during construction --- equity (6 401) (7 595) (6 794) Undistributed equity in earnings of unconsolidated affiliates (5 364) (25 976) (24 305) Undistributed equity in gain from nonregulated contract termination (17 565) Write-off of prior year merger costs 25 289 Cash provided by (used for) changes in certain working capital items (see below) 36 117 (58 634) (791) Conservation program expenditures --- net of amortization (9 207) (2 854) (21 668) Cash provided by changes in other assets and liabilities 29 051 23 518 17 234 - ------------------------------------------------------------------------------------------------------------------- NET CASH PROVIDED BY OPERATING ACTIVITIES 689 785 544 464 573 787 - ------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures: Utility plant additions (including nuclear fuel) (396 605) (386 655) (386 022) Additions to nonregulated property (35 928) (25 807) (14 984) Increase (decrease) in construction payables 2 563 (3 716) (12 588) Allowance for funds used during construction --- equity 6 401 7 595 6 794 Investment in external decommissioning fund (41 261) (40 497) (33 196) Equity investments, loans and deposits for nonregulated projects (395 495) (299 173) (55 884) Collection of loans made to nonregulated projects 87 128 116 126 1 766 Business acquisitions (159 600) Other investments --- net (15 692) (15 873) (998) - ------------------------------------------------------------------------------------------------------------------- NET CASH USED FOR INVESTING ACTIVITIES (948 489) (648 000) (495 112) - ------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES: Change in short-term debt --- net issuances (repayments) (108 023) 152 173 (22 245) Proceeds from issuance of long-term debt - net 299 779 197 824 277 174 Loan to ESOP (15 000) Repayment of long-term debt, including reacquisition premiums (141 681) (67 628) (195 683) Proceeds from issuance of preferred securities - net 193 315 Proceeds from issuance of common stock - net 267 965 41 725 56 185 Redemption of preferred stock, including reacquisition premiums (41 278) Dividends paid (207 726) (198 234) (191 367) - ------------------------------------------------------------------------------------------------------------------- NET CASH PROVIDED BY (USED FOR) FINANCING ACTIVITIES 262 351 125 860 (90 936) - ------------------------------------------------------------------------------------------------------------------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 3 647 22 324 (12 261) Cash and Cash Equivalents at Beginning of Period 51 118 28 794 41 055 - ------------------------------------------------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $54 765 $51 118 $28 794 =================================================================================================================== CASH PROVIDED BY (USED FOR) CHANGES IN CERTAIN WORKING CAPITAL ITEMS: Customer accounts receivable and unbilled utility revenues $47 878 $(41 495) $(66 311) Materials and supplies inventories (8 547) (9 891) 14 290 Payables and accrued liabilities (excluding construction payables) (7 342) 1 179 51 316 Other 4 128 (8 427) (86) - ------------------------------------------------------------------------------------------------------------------- Net $36 117 $(58 634) $(791) =================================================================================================================== SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Cash paid during the year for: Interest (net of amount capitalized) $144 062 $121 697 $113 705 Income taxes (net of refunds received) $113 009 $165 146 $131 452 - ------------------------------------------------------------------------------------------------------------------- </TABLE> See Notes to Financial Statements.
CONSOLIDATED BALANCE SHEETS <TABLE> <CAPTION> Dec. 31 ---------------------- (Thousands of dollars) 1997 1996 - --------------------------------------------------------------------------------------------------------------- <S> <C> <C> ASSETS UTILITY PLANT Electric---including construction work in progress: 1997, $92,302; 1996, $132,705 $6 964 888 $6 766 896 Gas 821 119 750 449 Other 343 950 331 441 - --------------------------------------------------------------------------------------------------------------- Total 8 129 957 7 848 786 Accumulated provision for depreciation (3 868 810) (3 611 244) Nuclear fuel---including amounts in process: 1997, $23,381; 1996, $6,916 932 335 892 484 Accumulated provision for amortization (832 162) (792 146) - --------------------------------------------------------------------------------------------------------------- Net utility plant 4 361 320 4 337 880 - --------------------------------------------------------------------------------------------------------------- CURRENT ASSETS Cash and cash equivalents 54 765 51 118 Customer accounts receivable --- net of accumulated provisions for uncollectible accounts: 1997, $10,406; 1996, $10,195 269 455 288 330 Unbilled utility revenues 121 619 147 366 Notes receivable from nonregulated projects 55 787 5 753 Other receivables 80 803 77 571 Materials and supplies inventories---at average cost: Fuel 56 434 45 013 Other 107 254 109 425 Prepayments and other 55 674 72 647 - --------------------------------------------------------------------------------------------------------------- Total current assets 801 791 797 223 - --------------------------------------------------------------------------------------------------------------- OTHER ASSETS Equity investments in nonregulated projects 740 734 409 729 External decommissioning fund and other investments 400 290 302 250 Regulatory assets 340 122 354 128 Nonregulated property---net of accumulated depreciation: 1997, $105,526; 1996, $93,320 256 726 192 790 Notes receivable from nonregulated projects 77 639 75 811 Other long-term receivables 42 600 63 684 Long-term prepayments and deferred charges 30 015 57 237 Intangible assets - net of accumulated amortization 92 829 46 168 - --------------------------------------------------------------------------------------------------------------- Total other assets 1 980 955 1 501 797 - --------------------------------------------------------------------------------------------------------------- TOTAL $7 144 066 $6 636 900 =============================================================================================================== LIABILITIES AND EQUITY CAPITALIZATION (See Consolidated Statements of Capitalization) Common stockholders' equity $2 371 728 $2 135 880 Preferred stockholders' equity 200 340 240 469 Company obligated mandatorily redeemable preferred securities of subsidiary trust holding as its sole asset junior subordinated deferrable debentures of the Company 200 000 Long-term debt 1 878 875 1 592 568 - --------------------------------------------------------------------------------------------------------------- Total capitalization 4 650 943 3 968 917 - --------------------------------------------------------------------------------------------------------------- CURRENT LIABILITIES Long-term debt due within one year 22 820 119 618 Other long-term debt potentially due within one year 141 600 141 600 Short-term debt 260 352 368 367 Accounts payable 249 813 236 341 Taxes accrued 186 369 204 348 Interest accrued 28 724 34 722 Dividends payable on common and preferred stocks 54 778 50 409 Accrued payroll, vacation and other 89 562 80 995 - --------------------------------------------------------------------------------------------------------------- Total current liabilities 1 034 018 1 236 400 - --------------------------------------------------------------------------------------------------------------- OTHER LIABILITIES Deferred income taxes 792 569 804 342 Deferred investment tax credits 138 509 149 606 Regulatory liabilities 305 765 302 647 Postretirement and other benefit obligations 135 612 114 312 Other long-term obligations and deferred income 86 650 60 676 - --------------------------------------------------------------------------------------------------------------- Total other liabilities 1 459 105 1 431 583 - --------------------------------------------------------------------------------------------------------------- COMMITMENTS AND CONTINGENT LIABILITIES (SEE NOTES 13 AND 14) - --------------------------------------------------------------------------------------------------------------- TOTAL $7 144 066 $6 636 900 =============================================================================================================== </TABLE> See Notes to Financial Statements.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY <TABLE> <CAPTION> CUMULATIVE CURRENCY NUMBER OF RETAINED SHARES HELD TRANSLATION (Dollar amounts in thousands) SHARES ISSUED PAR VALUE PREMIUM EARNINGS BY ESOP ADJUSTMENTS - ------------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> BALANCE AT DEC. 31, 1994 66 922 144 $167 305 $545 875 $1 183 191 $(2 990) $3 586 - ------------------------------------------------------------------------------------------------------------------------- Net income 275 795 Dividends declared: Cumulative preferred stock (12 450) Common stock (180 510) Issuances of common stock - net 1 253 790 3 135 53 050 Tax benefit from stock options exercised 169 Loan to ESOP to purchase shares (15 000) Repayment of ESOP loan * 7 333 Currency translation adjustments (1 098) - ------------------------------------------------------------------------------------------------------------------------- BALANCE AT DEC. 31, 1995 68 175 934 $170 440 $599 094 $1 266 026 $(10 657) $2 488 - ------------------------------------------------------------------------------------------------------------------------- Net income 274 539 Dividends declared: Cumulative preferred stock (12 245) Common stock (187 521) Issuances of common stock - net 887 778 2 219 39 256 Tax benefit from stock options exercised 369 Loan to ESOP to purchase shares * (15 000) Repayment of ESOP loan * 6 566 Currency translation adjustments 306 - ------------------------------------------------------------------------------------------------------------------------- BALANCE AT DEC. 31, 1996 69 063 712 $172 659 $638 719 $1 340 799 $(19 091) $2 794 - ------------------------------------------------------------------------------------------------------------------------- Net income 237 320 Dividends declared: Cumulative preferred stock (9 923) Common stock (202 173) Premium on redeemed preferred stock (1,148) Issuances of common stock - net 5 554 670 13 887 253 999 Tax benefit from stock options exercised 1 009 Repayment of ESOP loan * 8 558 Currency translation adjustments (65 681) - ------------------------------------------------------------------------------------------------------------------------- BALANCE AT DEC. 31, 1997 74 618 382 $186 546 $893 727 $1 364 875 $(10 533) $(62 887) ========================================================================================================================= </TABLE> * Did not affect NSP cash flows See Notes to Financial Statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION <TABLE> <CAPTION> Dec. 31 --------------------------- (Thousands of dollars) 1997 1996 - ------------------------------------------------------------------------------------------------------------------- <S> <C> <C> COMMON STOCKHOLDERS' EQUITY Common stock---authorized 160,000,000 shares of $2.50 par value; issued shares: 1997, 74,618,382; 1996, 69,063,712 $186 546 $172 659 Premium on common stock 893 727 638 719 Retained earnings 1 364 875 1 340 799 Leveraged common stock held by Employee Stock Ownership Plan (ESOP) ---shares at cost: 1997, 230,253; 1996, 381,313 (10 533) (19 091) Currency translation adjustments---net (62 887) 2 794 - ------------------------------------------------------------------------------------------------------------------- Total common stockholders' equity $2 371 728 $2 135 880 =================================================================================================================== CUMULATIVE PREFERRED STOCK---authorized 7,000,000 shares of $100 par value; outstanding shares: 1997, 2,000,000; 1996, 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 7.00 series, 200,000 shares 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 200 000 240 000 Premium on preferred stock 340 469 - ------------------------------------------------------------------------------------------------------------------- Total preferred stockholders' equity $200 340 $240 469 =================================================================================================================== MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST (See Note 2) 7 7/8% series, 8,000,000 shares, due Jan. 31, 2037 $200 000 =================================================================================================================== LONG-TERM DEBT First Mortgage Bonds - Minnesota Company Series due: Oct. 1, 1997, 5 7/8% $100 000 Feb. 1, 1999, 5 1/2% $200 000 200 000 Dec. 1, 2000, 5 3/4% 100 000 100 000 Oct. 1, 2001, 7 7/8% 150 000 150 000 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 Dec. 1, 2005, 6 1/8% 70 000 70 000 Dec. 1, 1996-2006, 6.65% 18 400** 19 800** March 1, 2011, Variable Rate 13 700* 13 700* July 1, 2025, 7 1/8% 250 000 250 000 April 1, 2007, 6.80% 60 000* March 1, 2019, Variable Rate 27 900* Sept. 1, 2019, Variable Rate 100 000* - ------------------------------------------------------------------------------------------------------------------- Total 1 170 000 1 083 500 Less redeemable bonds classified as current (See Note 5) (141 600) (13 700) Less current maturities (1 500) (101 400) - ------------------------------------------------------------------------------------------------------------------- Net $1 026 900 $968 400 - ------------------------------------------------------------------------------------------------------------------- </TABLE> * POLLUTION CONTROL FINANCING ** RESOURCE RECOVERY FINANCING See Notes to Financial Statements.
<TABLE> <CAPTION> Dec. 31 ------------------------------- (Thousands of dollars) 1997 1996 - -------------------------------------------------------------------------------------------------------------------- <S> <C> <C> LONG-TERM DEBT---CONTINUED First Mortgage Bonds - Wisconsin Company Series due: Oct. 1, 2003, 5 3/4% $40 000 $40 000 March 1, 2023, 7 1/4% 110 000 110 000 Dec. 1, 2026, 7 3/8% 65 000 65 000 - ------------------------------------------------------------------------------------------------------------------- Total 215 000 $215 000 - ------------------------------------------------------------------------------------------------------------------- Guaranty Agreements---Minnesota Company Series due: Feb. 1, 1997 - 2003, 5.41% $5 300* $ 5 500* May 1, 1997 - 2003, 5.70% 23 250* 23 750* Feb. 1, 2003, 7.40% 3 500* 3 500* - ------------------------------------------------------------------------------------------------------------------- Total 32 050 32 750 Less current maturities (700) (700) - ------------------------------------------------------------------------------------------------------------------- Net $31 350 $32 050 - ------------------------------------------------------------------------------------------------------------------- Other 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* March 1, 2019, Variable Rate 27 900* Sept. 1, 2019, Variable Rate 100 000* Anoka County Resource Recovery Bond---Series due Dec. 1, 1997 - 2008, 7.09% 21 850** 23 050** City of La Crosse Resource Recovery Bond---Series due Nov. 1, 2021, 6% 18 600** 18 600** Viking Gas Transmission Company Senior Notes---Series due Oct. 31, 2008, 6.65% 23 111 25 244 Nov. 30, 2011, 7.1% 5 010 5 370 Sept. 30, 2012, 7.31% 13 767 NRG Energy, Inc. Senior Notes---Series due Feb. 1, 2006, 7.625% 125 000 125 000 June 15, 2007, 7.5% 250 000 NRG Energy Center, Inc. (Minneapolis Energy Center) Senior Secured Notes---Series due June 15, 2013, 7.31% 74 481 76 992 Pacific Generation Company debt due 2000-2007, 4.7% - 9.9% 33 424 Various NEO Corporation debt due Oct. 30, 2000, 6.9% - 9.4% 5 618 United Power & Land Notes due March 31, 2000, 7.62% 6 875 7 708 Various Eloigne Company Affordable Housing Project Notes due 1997 - 2024, 1.0% - 9.9% 27 223 24 755 Employee Stock Ownership Plan Bank Loans due 1997 - 2003, Variable Rate 10 535 17 571 Miscellaneous 7 385 7 533 - ------------------------------------------------------------------------------------------------------------------- Total 631 879 528 723 Less redeemable bonds classified as current (see Note 5) (127 900) Less current maturities (20 620) (17 518) - ------------------------------------------------------------------------------------------------------------------- Net $611 259 $383 305 - ------------------------------------------------------------------------------------------------------------------- Unamortized discount on long-term debt-net (5 634) (6 187) - ------------------------------------------------------------------------------------------------------------------- Total long-term debt $1 878 875 $1 592 568 =================================================================================================================== Total capitalization $4 650 943 $3 968 917 =================================================================================================================== </TABLE> * 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), is predominantly a regulated public utility serving customers in Minnesota, North Dakota and South Dakota. Northern States Power Company, a Wisconsin corporation (the Wisconsin Company), a wholly owned subsidiary of the Company, is a regulated public utility serving customers in Wisconsin and Michigan. Another wholly owned subsidiary, Viking Gas Transmission Company (Viking), is a regulated natural gas transmission company that operates a 500-mile interstate natural gas pipeline. Consequently, the Company, the Wisconsin Company and 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 the Company holds a controlling financial interest, including: the Wisconsin Company; NRG Energy, Inc. (NRG); Viking; Energy Masters International, Inc. (EMI), formerly Cenerprise, Inc.; and Eloigne Company (Eloigne). The Company and its subsidiaries collectively are referred to herein as NSP. As discussed in Note 10, NSP has investments in partnerships, joint ventures and projects for which the equity method of accounting is applied. Earnings from equity in international investments are recorded net of foreign income taxes. 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. 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 and resource adjustment clauses, under which rates are adjusted to reflect changes in average costs of fuels, purchased energy, purchased gas and, in Minnesota, conservation and energy management program costs. 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. For Wisconsin electric operations where cost-of-energy adjustment clauses are not used, the biennial retail rate review process and an interim fuel cost hearing process provide the opportunity for rate recovery of 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 direct labor and materials, contracted work, 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 noncash 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). The AFC rate was 5.75 percent in 1997, 5.5 percent in 1996 and 6.0 percent in 1995. 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 immaterial changes in annual depreciation accruals for 1997 and 1996.
The Company also submitted in 1997, as required every five years, an average service life filing for transmission, distribution and general properties. The filing, as approved by the MPUC, decreased depreciation approximately $1 million from 1996 levels. Depreciation provisions, as a percentage of the average balance of depreciable utility property in service, were 3.78 percent in 1997, 3.68 percent in 1996 and 3.64 percent in 1995. DECOMMISSIONING As discussed in Note 13, NSP currently is recording the future costs 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 decontamination and removal, over the estimated operating lives of the Company's nuclear plants. The Financial Accounting Standards Board (FASB) has proposed new accounting standards that would require the full accrual of nuclear plant decommissioning and certain other site exit obligations beginning no sooner than 1999. (See Note 13 for more discussion of this proposed standard.) 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 costs of future fuel disposal and DOE facility decommissioning, as discussed in Note 13. 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. Costs are charged to expense 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. Costs may be deferred as a regulatory asset based on expected recovery in future rates. 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 incurred related to decommissioning and restoration of its nonnuclear power plants and substation sites, where operation may extend indefinitely, as a capitalized removal cost of retirement in utility plant. Depreciation expense levels currently recovered in rates include a provision for an estimate of removal costs, based on historical experience. INCOME TAXES Under the liability method used by NSP, 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, 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 9. NSP's policy for income taxes related to international operations is discussed in Note 7. Investment tax credits were deferred and are being 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 stockholders' equity. During 1997, the effects of changes in currency exchange rates on NRG's international project investments, mainly in Australia, reduced equity by $66 million. Exchange gains and losses that result from foreign currency transactions (e.g., converting cash distributions made in one currency to another) and derivative arrangements that do not qualify for hedge accounting (see Note 11) are included in the results of operations as a component of income from nonregulated businesses before interest and taxes. The earnings impact of these items was not material to NSP's results for the periods presented. DERIVATIVE FINANCIAL INSTRUMENTS NSP's policy is to hedge projected foreign currency denominated cash flows, where appropriate hedging instruments are available, to preserve their U.S. dollar value. NRG has entered into currency hedging transactions through the use of forward foreign currency exchange agreements with terms of less than one to three years. Gains and losses on these agreements offset the effect of foreign currency exchange rate fluctuations on NRG's known and anticipated cash flows. Gains on agreements that hedge firm commitments of
cash flows are deferred and included in the measurement of the related foreign currency transaction in the period the transaction occurs, and losses on these agreements are deferred in the same manner unless it is estimated that deferral would lead to recognizing losses in later periods. Gains and losses on agreements that hedge cash flows not meeting the criteria of a firm commitment are recorded in the current period as a component of NSP's nonregulated income before interest and taxes. Prior to July 1997, NSP's policy was to hedge foreign currency denominated investments as they were made, where appropriate hedging instruments were available, to preserve their U.S. dollar value. Gains and losses on these agreements offset the effects of foreign currency exchange rate fluctuations on the valuation of the investments underlying the hedges. Hedging gains and losses, net of income tax effects, on these agreements were reported with other currency translation adjustments as a separate component of stockholders' equity. While NRG is not currently hedging foreign currency denominated investments, NRG will hedge such investments when management believes that preserving the U.S. dollar value of the investment is appropriate. NRG is not hedging currency translation adjustments related to future operating results. NRG does not speculate in foreign currencies. Where appropriate, NRG also uses interest rate hedging instruments to protect against increases in the cost of borrowing at both the corporate and project level. Gains and losses on interest rate hedging instruments are deferred and included in the measurement of the underlying equity investment when made. Another derivative arrangement is the use of natural gas futures contracts by EMI 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 EMI's nonregulated operating expenses. NSP does not speculate in natural gas futures. A final 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. None of these derivative financial instruments are reflected on NSP's balance sheet. 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 costs, 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. The depreciable lives of certain plant assets are reviewed and, if appropriate, revised each year, as discussed previously. CASH EQUIVALENTS NSP considers investments in certain debt instruments, primarily commercial paper and money market funds, with an original maturity to NSP 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 Statement of Financial Accounting Standards (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 otherwise would 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 9 describes the nature and amounts of these regulatory deferrals. STOCK-BASED EMPLOYEE COMPENSATION NSP has several stock-based compensation plans, as described in Note 3. Under the intrinsic-value-based method of accounting followed by NSP, no compensation expense is recorded for stock options because there is no difference between the market price and purchase price at the grant date, which is the measurement date for determining compensation expense. NSP does, however, record compensation expense for stock that is awarded to certain employees, but held by NSP until the restrictions lapse or the stock is forfeited. Effective for 1996, the FASB issued a new accounting standard, SFAS No. 123---Accounting for Stock-Based Compensation, which provides an optional accounting method for compensation from stock option and other stock award programs. NSP did not elect the new optional accounting method. If the provisions of the optional method had been adopted as of the beginning of 1995, the effect on net income and earnings per share for 1997, 1996 and 1995 would have been immaterial.
DEVELOPMENT COSTS As it pursues projects under development, NRG expenses development costs incurred until a sales agreement or letter of intent is signed and the project has received capital authorization. Additional costs incurred after this point are capitalized as part of equity investments in projects. When project operations begin, such capitalized costs are amortized on a straight-line basis over the lesser of the life of the project's related assets or revenue contract period. OTHER ASSETS The purchase of various nonregulated entities at a price exceeding the underlying fair value of net assets acquired has resulted in recorded goodwill of $43 million ($38 million net of accumulated amortization) at Dec. 31, 1997. This goodwill and other intangible assets acquired are being amortized using the straight-line method over periods of three to 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 (net of amortization) of approximately $22 million at Dec. 31, 1997. These financing costs are being amortized over the remaining maturity period of the related debt. RECLASSIFICATIONS Certain reclassifications have been made to the 1996 and 1995 income statements to conform to 1997 presentation. These classifications had no effect on net income or earnings per share. 2. Preferred Securities 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, 1997, the annualized dividend rates were $5.50 for both series A and series B. At Dec. 31, 1997, various preferred stock series were callable at prices per share ranging from $100.00 to $103.75, plus accrued dividends. In January 1997, a wholly owned special purpose subsidiary trust of NSP issued $200 million in 7.875 percent preferred securities that mature in 2037. A portion of the proceeds was used to redeem the Company's $6.80 and $7.00 series of preferred stock in February 1997. Distributions paid to preferred security holders are reflected as a financing cost in the Consolidated Statement of Income along with interest expense. Distributions paid by the subsidiary trust on the preferred securities are financed through interest payments from the Company on debentures issued by the Company and held by the subsidiary trust, which are eliminated in NSP's consolidation. The preferred securities are redeemable at $25 per share beginning in 2002. Distributions and redemption payments are guaranteed by NSP. 3. 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, 1997, the Company could have paid, without restrictions, additional cash dividends of more than $1 billion on common stock. Nonqualified stock options and restricted stock may be granted under NSP's Executive Long-Term Incentive Award Stock Plan. The awards granted in any calendar year cannot exceed 1 percent of the number of outstanding shares of NSP common stock at the end of the previous calendar year. When options are exercised, or restricted stock granted, the Company may either issue new shares or purchase market shares. Using the treasury stock method of accounting for stock options unexercised, the weighted average number of shares of common stock outstanding for the calculation of Earnings Per Share - Assuming Dilution includes any dilutive effects of stock options and other stock awards as potential common shares. Stock options currently granted may be exercised one year from the date of grant and are exercisable thereafter for up to nine years. The options are forfeited if employment ceases before the one-year vesting term. If employment ceases after the one-year vesting term, options will either be forfeited, or would need to be exercised within three or 36 months, depending on the circumstances. The exercise price of an option is the market price of NSP common stock on the date of grant. The plan, in previous years, granted other types of performance awards, some of which are still outstanding. Most of these performance awards were valued in dollars, but paid in shares based on the market price at the time of payment. Transactions under the various incentive stock programs, with the corresponding weighted average exercise price, were as follows:
Stock Option and Performance Awards <TABLE> <CAPTION> 1997 1996 1995 ----------------- ------------------ ------------------ AVERAGE Average Average (Thousands of shares) SHARES PRICE Shares Price Shares Price - ---------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> Outstanding Jan. 1 1 117 43.97 990 $41.97 782 $40.58 Options granted in January 287 47.44 263 $50.94 278 $45.50 Options and awards exercised (260) 42.23 (105) $41.98 (64) $40.26 Options and awards forfeited (30) 47.19 (27) $47.70 (6) $44.58 Options and awards expired (11) 50.94 (4) $40.00 - ---------------------------------------------------------------------------------------------- Outstanding at Dec. 31 1 103 45.13 1 117 $43.97 990 $41.97 Exercisable at Dec. 31 843 44.41 870 $41.96 716 $40.60 ============================================================================================== </TABLE> The following table summarizes information about stock options outstanding at Dec. 31, 1997: Range of Exercise Prices ----------------------------- $33.25-40.94 $42.19-50.94 - -------------------------------------------------------------------------------- Options Outstanding: Number outstanding at Dec. 31, 1997 170 346 923 517 Weighted-average remaining contractual life (years) 3.1 7.4 Weighted-average exercise price $37.15 $46.60 Options Exercisable: Number exercisable at Dec. 31, 1997 170 346 663 156 Weighted-average exercise price $37.15 $46.27 In addition to stock options, restricted stock is granted based on a dollar value of the award. The market price on the date of grant is used to determine the number of restricted shares awarded. The stock is held by NSP until the restrictions lapse: 50 percent of the stock will vest one year from the date of the award and the remaining 50 percent vests two years from the date of the award. Dividends on the shares held while the restrictions are in place are reinvested to obtain additional shares, and the restrictions apply to these additional shares. In each of the years 1995 through 1997, NSP granted restricted stock awards of 15,898, 18,584 and 26,344 shares, respectively, at then-current market prices of NSP stock. Compensation expense related to these awards was immaterial. 4. Short-Term Borrowings As of Dec. 31, 1997 and 1996, the Company had a $300 million revolving credit facility under a commitment fee arrangement. This facility provides short-term financing in the form of bank loans, letters of credit and support for commercial paper sales. There were no borrowings against this facility at Dec. 31, 1997 and 1996. At Dec. 31, 1997 and 1996, credit lines of $245 million and $75 million, respectively, were provided primarily by commercial banks to wholly owned subsidiaries of the Company. There were $122 million and approximately $4 million in outstanding loans against these subsidiary credit lines at Dec. 31, 1997 and 1996, respectively. In addition, at Dec. 31, 1997 and 1996, $49 million and $21 million, respectively, in letters of credit were outstanding (as discussed in Note 11), which reduced the available credit lines. At Dec. 31, 1997 and 1996, the Company had $138 million and $362 million, respectively, in short-term commercial paper borrowings outstanding, and another $122 million and $7 million, respectively, in short-term bank loans outstanding, mainly for nonregulated subsidiaries. The weighted average interest rates on all short-term borrowings were 6.2 percent as of Dec. 31, 1997, and 5.7 percent as of Dec. 31, 1996. 5. Long-Term Debt Except for minor exclusions, all real and personal property of the Company and the Wisconsin Company is subject to the liens of the First Mortgage Indentures. Other debt securities are secured by a lien on the related property, as indicated on the Consolidated Statements of Capitalization. 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 $1 billion. The Company may, and has, applied property additions in lieu of cash payments on all series, 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.
The Company's 2011 and 2019 series First Mortgage Bonds 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 4.0 percent and 3.8 percent, respectively, at Dec. 31, 1997. 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 when the bonds are tendered, which occurs each time the variable interest rates change. The principal amount of all 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 (in millions) are: 1998, $22.8; 1999, $217.3; 2000, $122.4; 2001, $167.8; and 2002, $76.6. 6. Benefit Plans and Other Postretirement Benefits NSP offers the following benefit plans to its benefit employees, of whom approximately 40 percent are represented by five local labor unions under a collective-bargaining agreement, which expires Dec. 31, 1999. PENSION BENEFITS NSP has a noncontributory, 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. NSP's policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations under applicable employee benefit and tax laws. Plan assets principally consist of common stock of public companies, corporate bonds and U.S. government securities. The funded status of NSP's pension plan as of Dec. 31 is as follows: (Thousands of dollars) 1997 1996 - ------------------------------------------------------------------------------- Actuarial present value of benefit obligation: Vested $701 219 $660 920 Nonvested 165 004 147 278 - ------------------------------------------------------------------------------- Accumulated benefit obligation $866 223 $808 198 =============================================================================== Projected benefit obligation $1 048 251 $993 821 Plan assets at fair value 1 978 538 1 634 696 - ------------------------------------------------------------------------------- Plan assets in excess of projected benefit obligation 930 287 640 875 Unrecognized prior service cost 18 663 19 734 Unrecognized net actuarial gain (953 825) (651 368) Unrecognized net transitional asset (463) (539) - ------------------------------------------------------------------------------- Net pension asset (liability) recorded $(5 338) $8 702 =============================================================================== For ratemaking purposes, the Company's pension costs are determined and recorded under the aggregate-cost actuarial 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 is recorded as a regulatory liability on the balance sheet. Net annual periodic pension cost includes the following components: <TABLE> <CAPTION> (Thousands of dollars) 1997 1996 1995 - ---------------------------------------------------------------------------------------------- <S> <C> <C> <C> Service cost-benefits earned during the period $27 680 $29 971 $24 499 Interest cost on projected benefit obligation 72 651 70 863 69 742 Actual return on assets (420 174) (265 370) (344 837) Net amortization and deferral 285 048 139 874 240 458 - ---------------------------------------------------------------------------------------------- Net periodic pension cost determined under SFAS No. 87 (34 795) (24 662) (10 138) Additional costs recognized due to actions of regulators 30 862 23 572 10 454 - ---------------------------------------------------------------------------------------------- Net periodic pension cost recognized for financial reporting $(3 933) $(1 090) $316 ============================================================================================== </TABLE> The weighted average discount rate used in determining the actuarial present value of the projected obligation was 7 percent for Dec. 31, 1997 and 7.5 percent for Dec. 31, 1996. The rate of increase in future compensation levels used in determining the actuarial present value of the projected obligation was 5 percent in 1997 and 1996. The assumed long-term rate of return on assets used for cost determinations under SFAS No. 87 was 9 percent for
1997, 1996 and 1995. Assumption changes decreased 1997 pension costs (determined under SFAS No. 87) by approximately $6.9 million and increased 1996 costs by approximately $12.6 million. However, because the Company's pension expense is determined under the aggregate-cost method (not SFAS No. 87) for ratemaking and financial reporting purposes, the effects of regulation prevented the majority of assumption changes from affecting earnings. 401(k) NSP has a contributory, defined contribution Retirement Savings Plan, which complies with section 401(k) of the Internal Revenue Code and covers substantially all employees. Since 1994, NSP has been matching specified amounts of employee contributions to this plan. NSP's matching contributions were $4.4 million in 1997, $4.3 million in 1996 and $3.7 million in 1995. 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. In conjunction with the 1993 adoption of SFAS No. 106-Employers' Accounting for Postretirement Benefits Other Than Pensions, 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. 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, including the use of tax-advantaged trusts, have been required by NSP's regulators, as discussed later. Plan assets held in such trusts principally consist of investments in equity mutual funds and cash equivalents. The funded status of NSP's retiree health care plan as of Dec. 31 is as follows: (Thousands of dollars) 1997 1996 - ---------------------------------------------------------------------------- APBO: Retirees $149 081 $144 180 Fully eligible plan participants 21 245 23 438 Other active plan participants 108 904 101 065 - ----------------------------------------------------------------------------- Total APBO 279 230 268 683 Plan assets at fair value 19 784 15 514 - ----------------------------------------------------------------------------- APBO in excess of plan assets 259 446 253 169 Unrecognized net actuarial loss (14 408) (12 467) Unrecognized transition obligation (161 700) (172 480) - ------------------------------------------------------------------------------ Net benefit liability recorded $83 338 $ 68 222 ============================================================================= The assumed health care cost trend rates used in measuring the APBO at Dec. 31, 1997 and 1996, were 9.2 percent and 9.8 percent for those under age 65, and 6.8 percent and 7.1 percent for those age 65 and over, respectively. 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 14.5 percent as of Dec. 31, 1997. Service and interest cost components of the net periodic postretirement cost would increase by approximately 15.4 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 7 percent for Dec. 31, 1997, and 7.5 percent for Dec. 31, 1996, compounded annually. The assumed long-term rate of return on assets used for cost determinations under SFAS No. 106 was 8 percent for 1997, 1996 and 1995. Assumption changes decreased costs by approximately $4.0 million in 1997 and approximately $2.0 million in 1996.
The net annual periodic postretirement benefit cost recorded consists of the following components: <TABLE> <CAPTION> (Thousands of dollars) 1997 1996 1995 - ------------------------------------------------------------------------------------------------- <S> <C> <C> <C> Service cost-benefits earned during the year $5 095 $ 6 380 $ 5 206 Interest cost (on service cost and APBO) 18 872 19 283 19 201 Actual return on assets (1 461) (947) (1 046) Amortization of transition obligation 10 780 10 780 10 780 Net amortization and deferral 222 140 406 - ------------------------------------------------------------------------------------------------- Net periodic postretirement health care cost under SFAS No. 106 33 508 35 636 34 547 Additional costs recognized due to actions of regulators 4 033 4 033 - ------------------------------------------------------------------------------------------------- Net postretirement cost recognized for financial reporting $33 508 $39 669 $38 580 ================================================================================================= </TABLE> Regulators for nearly all of NSP's retail and wholesale customers have allowed full recovery of increased benefit costs under SFAS No. 106, effective in 1993. Increased 1993 accrual costs of approximately $12 million for Minnesota retail customers were 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 will begin in 1998 for Minnesota. For wholesale ratemaking, the FERC has required external funding for all benefits paid and accrued under SFAS No. 106 since 1993. 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 1997, 1996 and 1995, which represent compensation expense, were $4.4 million, $4.6 million and $5.0 million, 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. Leveraged shares held by the ESOP are allocated to participants when dividends on stock held by the plan are used to repay ESOP loans. NSP's ESOP held 5.6 million and 5.9 million shares of the Company's common stock as of Dec. 31, 1997 and 1996, respectively. An average of 0.3 million, 0.2 million and 0.2 million uncommitted leveraged ESOP shares were excluded from earnings-per-share calculations in 1997, 1996 and 1995, respectively. The fair value of NSP's leveraged ESOP shares was approximately the same as cost at Dec. 31, 1997 and 1996.
7. Income Taxes Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The reasons for the difference are as follows: <TABLE> <CAPTION> 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------------ <S> <C> <C> <C> Federal statutory rate 35.0% 35.0% 35.0% Increases (decreases) in tax from: State income taxes, net of federal income tax benefit 4.3% 5.2% 5.1% Tax credits recognized (7.9)% (4.1)% (3.4)% Equity income from unconsolidated affiliates (2.5)% (2.6)% (2.5)% Regulatory differences---utility plant items 1.1% 0.9% 1.0% Other---net (1.0)% 0.4% 0.4% - ------------------------------------------------------------------------------------------------------------------ Effective income tax rate 29.0% 34.8% 35.6% ================================================================================================================== (Thousands of dollars) Income taxes are comprised of the following expense (benefit) items: Included in utility operating expenses: Current federal tax expense $125 202 $154 421 $137 011 Current state tax expense 28 812 39 923 33 359 Deferred federal tax expense (88) (19 933) (12 019) Deferred state tax expense (23) (3 958) (2 396) Deferred investment tax credits (9 048) (9 043) (8 807) - ------------------------------------------------------------------------------------------------------------------ Total 144 855 161 410 147 148 - ------------------------------------------------------------------------------------------------------------------ Included in income taxes on nonregulated operations and nonoperating items: Current federal tax expense (19 470) (906) 5 481 Current state tax expense (5 804) 712 1 629 Current foreign tax expense 236 616 233 Current federal tax credits (17 006) (8 044) (5 292) Deferred federal tax expense (2 237) (5 150) 2 646 Deferred state tax expense (662) (1 520) 693 Deferred foreign tax expense (2 892) 0 0 Deferred investment tax credits (310) (308) (310) - ------------------------------------------------------------------------------------------------------------------ Total (48 145) (14 600) 5 080 - ------------------------------------------------------------------------------------------------------------------ Total income tax expense $96 710 $146 810 $152 228 ================================================================================================================== </TABLE> Income before income taxes includes net foreign equity income of $27 million, $28 million and $32 million in 1997, 1996 and 1995, respectively. Except to the extent NSP's earnings from foreign operations are subject to current U.S. income taxes, NSP's management intends to reinvest indefinitely such earnings in its foreign operations. Accordingly, U.S. income taxes and foreign withholding taxes have not been provided on a cumulative amount of unremitted earnings of foreign subsidiaries of approximately $112 million at Dec. 31, 1997. 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 (current and noncurrent portions) at Dec. 31 were: (Thousands of dollars) 1997 1996 - -------------------------------------------------------------------------------- Deferred tax liabilities: Differences between book and tax bases of property $867 155 $850 139 Regulatory assets 100 564 121 232 Tax benefit transfer leases 31 614 43 481 Other 21 715 23 182 - -------------------------------------------------------------------------------- Total deferred tax liabilities $1 021 048 $1 038 034 - -------------------------------------------------------------------------------- Deferred tax assets: Regulatory liabilities $83 765 $90 485 Deferred compensation, vacation and other accrued liabilities not currently deductible 70 765 65 690 Deferred investment tax credits 54 741 57 239 Other 26 557 34 509 - -------------------------------------------------------------------------------- Total deferred tax assets $235 828 $247 923 - -------------------------------------------------------------------------------- Net deferred tax liability $785 220 $790 111 ================================================================================ 8. Detail of Certain Income and Expense Items Administrative and general (A&G) expense for utility operations consists of the following: <TABLE> <CAPTION> (Thousands of dollars) 1997 1996 1995 - ---------------------------------------------------------------------------------------------- <S> <C> <C> <C> A&G salaries and wages $44 514 $47 546 $48 437 Pension, medical and other benefits---all utility employees 57 529 64 733 81 279 Information technology, facilities and administrative support 28 653 21 281 31 863 Insurance and claims 1 087 5 503 13 969 Other 10 019 9 593 10 599 - ---------------------------------------------------------------------------------------------- Total $141 802 $148 656 $186 147 ============================================================================================== </TABLE> Income from nonregulated businesses consists of the following: <TABLE> <CAPTION> (Thousands of dollars, except per share amounts) 1997 1996 1995 - ---------------------------------------------------------------------------------------------------- <S> <C> <C> <C> Operating revenues $217 844 $303 903 $313 082 Equity in earnings of unconsolidated affiliates: Earnings from operations 18 600 30 668 28 055 Gains from contract terminations 29 850 Operating and development expenses * (251 087) (326 332) (327 894) Interest and other income 26 721 10 304 6 518 - ---------------------------------------------------------------------------------------------------- Income from nonregulated businesses before interest and taxes 12 078 18 543 49 611 Interest and amortization expense (34 627) (18 834) (9 879) Income tax benefit (expense) 38 032 16 576 (6 119) - ----------------------------------------------------------------------------------------------------- Net Income $15 483 $16 285 $33 613 ==================================================================================================== Contribution of nonregulated businesses to NSP's earnings per share* $0.22 $0.24 $0.50 ==================================================================================================== </TABLE> * Includes nonrecurring project write-downs of $9 million in 1997 and $5 million in 1995
9. 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: <TABLE> <CAPTION> Remaining (Thousands of dollars) Amortization Period 1997 1996 - ----------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> AFC recorded in plant on a net-of-tax basis * Plant Lives $128 364 $137 412 Conservation and energy management programs * Primarily 3 Years 86 508 95 716 Losses on reacquired debt Term of Related Debt 59 353 63 481 Environmental costs Primarily 10 Years 45 849 42 322 State commission accounting adjustments * Plant Lives 7 286 7 296 Unrecovered purchased gas costs 1-2 Years 8 020 3 885 Other Various 4 742 4 016 - ----------------------------------------------------------------------------------------------------------- Total regulatory assets $340 122 $354 128 =========================================================================================================== Deferred income tax adjustments 88 035 $92 390 Investment tax credit deferrals 91 146 97 636 Unrealized gains from decommissioning investments 85 482 43 008 Pension costs-regulatory differences 27 107 45 080 Fuel costs, refunds and other 13 995 24 533 - ----------------------------------------------------------------------------------------------------------- Total regulatory liabilities $305 765 $302 647 =========================================================================================================== </TABLE> * Earns a return on investment in the ratemaking process 10. Investments Accounted for by the Equity Method Through its nonregulated subsidiaries, NSP has investments in various international and domestic energy projects and domestic affordable housing and real estate projects. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents NSP from exercising a controlling influence over operating and financial policies of the projects. Under this method, equity in the pretax income or losses of domestic partnerships and in the net income or losses of international projects is reflected as Equity in Earnings of Unconsolidated Affiliates. A summary of NSP's significant equity-method investments is as follows: <TABLE> <CAPTION> Name Geographic Area Economic Interest - ------------------------------------------------------------------------------------ <S> <C> <C> Loy Yang Power * Australia 25.37% Pacific Generation Company * USA/Canada 8.50%-28.70% Gladstone Power Station Australia 37.50% COBEE South America 48.30% MIBRAG mbH Europe 33.33% NRG Generating (U.S.) Inc. USA 45.21% Schkopau Power Station Europe 20.55% Energy Development, Limited * Australia 19.97% Scudder Latin American Trust for Independent Power Energy Projects Latin America 25% Various independent power production facilities * USA 45%-50% Various affordable housing limited partnerships * USA 20%-99% </TABLE> *Acquired in 1997
SUMMARIZED FINANCIAL INFORMATION OF UNCONSOLIDATED AFFILIATES Summarized financial information for these projects, including interests owned by NSP and other parties, was as follows for the years ended and as of Dec. 31: RESULTS OF OPERATIONS (Millions of dollars) 1997 1996 1995 ---- ---- ---- Operating Revenues $1 698 $958 $790 Operating Income $ 93 $105 $154 Net Income $ 84 $89 $160 NSP's Equity in Earnings of Unconsolidated Affiliates $19 $31 $59 FINANCIAL POSITION (Millions of dollars) 1997 1996 ---- ---- Current Assets $ 742 $ 681 Other Assets 7 853 3 525 ----- ------ Total Assets $8 595 $4 206 ====== ====== Current Liabilities $ 514 $ 397 Other Liabilities 6 109 2 798 Equity 1 972 1 011 ----- ------ Total Liabilities and Equity $8 595 $4 206 ====== ====== NSP's Equity Investment in Unconsolidated Affiliates $ 741 $410 11. Financial Instruments FAIR VALUES The estimated Dec. 31 fair values of NSP's recorded financial instruments are as follows: <TABLE> <CAPTION> 1997 1996 - ------------------------------------------------------------------------------------------------------------------ CARRYING FAIR Carrying Fair (Thousands of dollars) AMOUNT VALUE Amount Value - ------------------------------------------------------------------------------------------------------------------ <S> <C> <C> <C> <C> Cash, cash equivalents and short-term investments $54 765 $54 765 $51 118 $51 118 Long-term decommissioning investments $344 491 $344 491 $260 756 $260 756 Long-term debt, including current portion $2 043 295 $2 079 123 $1 853 786 $1 838 408 - ------------------------------------------------------------------------------------------------------------------ </TABLE> 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, mainly debt securities in an external nuclear decommissioning fund, are estimated based on quoted market prices for those or similar investments. 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 for debt of the same remaining maturities and credit quality. DERIVATIVES NRG has entered into forward foreign currency exchange contracts with counterparties to hedge certain exposures to currency fluctuations. Pursuant to these contracts, transactions have been executed that are designed to protect the economic value in U.S. dollars of selected known and anticipated NRG cash flows denominated in Australian dollars and German deutsche marks. As of Dec. 31, 1997, NRG had in place contracts with a notional value of $10 million to hedge foreign currency denominated known future cash flows. In addition, NRG has in place forward foreign currency exchange contracts with a net notional value of $8.6 million to hedge projected construction expenditures, which do not qualify for hedge accounting and consequently result in currency fluctuations that can affect earnings. The effect on 1997 earnings from these contracts was immaterial. The forward foreign currency exchange contracts terminate in 1998. If all of the contracts had been terminated at Dec. 31, 1997, $1.0 million would have been payable by NRG for currency exchange rate changes to date. Management believes NRG's exposure to credit risk due to nonperformance by the counterparties to its forward exchange contracts is not significant, based on the investment grade rating of the counterparties.
NRG also has two agreements in place, with a notional amount of $80 million, to fix the interest rate at a rate based on U.S. Treasury obligations for known future borrowings related to project investment commitments. If the agreements had been terminated at Dec. 31, 1997, $4.2 million would have been payable by NRG based on the underlying U.S. Treasury interest rate on that date. EMI has entered into natural gas futures contracts in the notional amount of $23 million at Dec. 31, 1997. The original contract terms range from one month to two 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 EMI's natural gas reserves. EMI's futures contracts hedge $24 million in anticipated natural gas sales in 1998-1999. Margin balances of $3 million at Dec. 31, 1997, 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, investment banks and major gas pipeline operators. Management believes that the risk of nonperformance by these counterparties is not significant. If the contracts had been terminated at Dec. 31, 1997, $0.7 million would have been payable by EMI for natural gas price fluctuations to date. NSP has two interest rate swap agreements with notional amounts totaling $220 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 the six-month London Interbank Offered Rate (LIBOR), with the rates changing semiannually. Term of Net Effective Notional Amount Swap Interest Cost at Series (millions of dollars) Agreement at Dec. 31, 1997 - -------------------------------------------------------------------------------- 5 1/2% Series due Feb. 1, 1999 $200 Maturity 5.49% 7 1/4% Series due March 1, 2023 $ 20 March 1, 1998 7.96% Market risks associated with these agreements result from short-term interest rate fluctuations. Credit risk related to nonperformance 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. The interest rate swaps serve to hedge the market 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, 1997, $0.6 million would have been payable by the Company, while the present value of the related fixed rate debt was $0.6 million below carrying value. LETTERS OF CREDIT NSP uses letters of credit to provide financial guarantees for certain operating obligations, including NSP workers' compensation benefits and ash disposal site costs, and EMI natural gas purchases, generally with terms of one year which are automatically renewed, unless prior written notice of cancellation is provided to NSP and the beneficiary by the issuing bank. In addition, NRG uses letters of credit for nonregulated equity commitments, as collateral for credit agreements, for fuel purchase and operating commitments and bids on development projects. At Dec. 31, 1997, letters of credit of $101 million were outstanding, of which $48 million related to NRG commitments. The contract amounts of these letters of credit approximate their fair value and are subject to fees competitively determined in the marketplace. 12. Joint Plant Ownership The Company is a part owner of an 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, 1997 and 1996, was $603.9 million and $588.0 million, respectively. The corresponding accumulated provisions for depreciation were $196.2 million and $168.6 million.
13. 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 a charge of 0.1 cent per kilowatt-hour sold to customers from nuclear generation. Fuel expense includes DOE fuel disposal assessments of $10.1 million, $11.3 million and $12.3 million in 1997, 1996 and 1995, respectively. The cumulative amount of such assessments paid by NSP to the DOE through Dec. 31, 1997, was approximately $250 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 Nuclear Waste Policy Act stipulated that the DOE execute contracts with utilities that require DOE to begin accepting spent nuclear fuel no later than Jan. 31, 1998. Accordingly, NSP has been providing, with regulatory and legislative approval, its own temporary on-site storage facilities at its Monticello and Prairie Island nuclear plants. In December 1996, the DOE notified commercial spent fuel owners of an anticipated delay in accepting used nuclear fuel by the required date of Jan. 31, 1998, and conceded that a permanent storage or disposal facility will not be available until at least 2010. The Company and other affected parties have commenced lawsuits against the DOE to require the DOE to meet its statutory and contractual obligations, which can include damages for nonperformance. NSP and other utilities are currently analyzing claims against the DOE for the costs incurred as a result of the DOE's failure to meet its statutory and contractual obligations. 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 Prairie Island nuclear plant until at least 2007. The Monticello nuclear plant has storage capacity to continue operations until 2010. Storage availability to permit operation beyond these dates is not assured at this time. In the meantime, NSP is investigating all of its alternatives for used fuel storage until a DOE facility is available, including pursuing the establishment of a private facility for interim storage of used nuclear fuel as part of a consortium of electric utilities. If on-site temporary storage at NSP's nuclear plants reaches approved capacity, the Company could seek interim storage at this or another contracted private facility, if available. Nuclear fuel expenses in 1997, 1996 and 1995 include about $4 million, $4 million and $5 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 each installment is being amortized to expense on a monthly basis in the 12 months following each payment. The most recent installment paid in 1997 was $3.9 million; future installments are subject to inflation adjustments under DOE rules. The Company is obtaining rate recovery of these DOE assessments through the cost-of-energy adjustment clause as the assessments are amortized. Accordingly, the unamortized assessment of $38 million at Dec. 31, 1997, has been deferred as a regulatory asset and is reported under the caption Environmental Costs in Note 9. PLANT DECOMMISSIONING Decommissioning of all Company nuclear facilities is planned for the years 2010-2022, using the prompt dismantlement method. The Company currently 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. Consequently, the total decommissioning cost obligation and corresponding asset currently are not recorded in NSP's financial statements. The FASB has proposed new accounting standards, which, if approved, would require the full accrual of nuclear plant decommissioning and certain other site exit obligations no sooner than 1999. Using Dec. 31, 1997, estimates, NSP's adoption of the proposed accounting would result in the recording of the total discounted decommissioning obligation of $698 million as a liability, with the corresponding costs capitalized as plant and other assets and depreciated over the operating life of the plant. The obligation calculation methodology proposed by the FASB is slightly different from the ratemaking methodology that derives the decommissioning accruals currently being recovered in rates, as discussed later. The Company has not yet determined the potential impact of the FASB's proposed changes in the accounting for site exit obligations other than nuclear decommissioning (such as costs of removal). However, the ultimate decommissioning and site exit costs to be accrued are the same under both methods and, accordingly, the effects of regulation are expected to minimize or eliminate any impact on operating expenses and results of operations from this future accounting 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. This annuity approach uses an 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 currently is 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 assets, including accumulated earnings, will be funded through internally generated funds and issuance of Company debt or stock. The assets held in trusts as of Dec. 31, 1997, primarily consisted of investments in fixed income securities, such as tax-exempt municipal bonds and U.S. government securities, which mature in two to 26 years, and common stock of public companies. The Company plans to reinvest matured securities until decommissioning commences. At Dec. 31, 1997, the Company has recorded and recovered in rates cumulative decommissioning accruals of $465 million. The following table summarizes the funded status of the Company's decommissioning obligation at Dec. 31, 1997: <TABLE> <CAPTION> (Thousands of dollars) 1997 - --------------------------------------------------------------------------------------------------------- <S> <C> Estimated decommissioning cost obligation from most recent approved study (1993 dollars) $750 824 Effect of escalating costs to 1997 dollars (at 4.5% per year) 144 548 - --------------------------------------------------------------------------------------------------------- Estimated decommissioning cost obligation in current dollars 895 372 Effect of escalating costs to payment date (at 4.5% per year) 949 413 - --------------------------------------------------------------------------------------------------------- Estimated future decommissioning costs (undiscounted) 1 844 785 Effect of discounting obligation (using risk-free interest rate) (1 147 177) - --------------------------------------------------------------------------------------------------------- Discounted decommissioning cost obligation 697 608 External trust fund assets at fair value 344 491 - --------------------------------------------------------------------------------------------------------- Discounted decommissioning obligation in excess of assets currently held in external trust $353 117 ========================================================================================================= </TABLE> Decommissioning expenses recognized include the following components: <TABLE> <CAPTION> (Thousands of dollars) 1997 1996 1995 - ---------------------------------------------------------------------------------------------------- <S> <C> <C> <C> Annual decommissioning cost accrual reported as depreciation expense: Externally funded $33 178 $33 178 $33 178 Internally funded (including interest costs) 1 368 1 268 1 174 Interest cost on externally funded decommissioning obligation 7 690 5 246 5 966 Earnings from external trust funds (7 690) (6 294) (5 620) - ----------------------------------------------------------------------------------------------------- Net decommissioning accruals recorded $34 546 $33 398 $34 698 ==================================================================================================== </TABLE> Decommissioning and interest accruals are included with the accumulated provision for depreciation on the balance sheet. Interest costs and trust earnings associated with externally funded obligations are reported in Other Utility Income and Deductions on the income statement. The MPUC last approved a nuclear decommissioning study and related nuclear plant depreciation capital recovery request in April 1997, using cost data from the 1993 study. Although management expects to operate the Prairie Island units through the end of each unit's licensed life, the approved capital recovery would allow for the plant to be fully depreciated, including the accrual and recovery of decommissioning costs, in 2008, about six years earlier than the end of each unit's licensed life. The approved recovery period for Prairie Island has been reduced because of the uncertainty regarding used fuel storage, as discussed previously. The Company believes future decommissioning cost accruals will continue to be recovered in customer rates.
14. Commitments and Contingent Liabilities CAPITAL COMMITMENTS NSP estimates utility capital expenditures, including acquisitions of nuclear fuel, will be $441 million in 1998 and $2.1 billion for 1998-2002. There also are contractual commitments for the disposal of used nuclear fuel. (See Note 13.) As of Dec. 31, 1997, NRG is contractually committed to additional equity investments of approximately $35 million in 1998 and approximately $172 million for 1998-2002 for various international power generation projects. In addition, in 1996, NRG executed an agreement whereby NRG is obligated to provide to NRG Generating (U.S.) Inc. (NRGG), an unconsolidated affiliate of NRG, power generation investment opportunities in the United States over a three-year period. These projects must have in aggregate, over the three-year term, an equity value of at least $60 million or a minimum of 150 net megawatts. In addition, NRG has committed to finance NRGG's investment in the projects to the extent funds are not available to NRGG on comparable terms from other sources. As required by the agreement, NRG provided several investment opportunities to NRGG in 1997, and, as a result, NRGG purchased the Millennium project from NRG. NRGG financed the Millennium purchase from sources other than NRG. LEGISLATIVE RESOURCE COMMITMENTS In 1994, the Minnesota Legislature established several energy resource and other commitments for NSP to obtain the Prairie Island temporary nuclear fuel storage facility approval. The commitments, which can be met by building, purchasing or, in the case of biomass, converting generation resources, are: Power Type Megawatts Required Contract Deadline - ---------------------------------------------------------------------------- Wind 100 (Additional) 12/31/96 Wind 100 (Additional) 12/31/98 Wind 200 (Additional) 12/31/02 Total Wind 400 Biomass 50 (Additional) 12/31/98 Biomass 75 (Additional) 12/31/98 -- Total Biomass 125 The Company is complying with the requirements of these resource commitments as follows: Power Type Developer Megawatts Operation Date - -------------------------------------------------------------------------------- Wind Lake Benton Power Partners LLC (1) 107.25 June 1998 (2) Wind Northern Alternative Energy, Inc. 22.65 Oct. 1998 (2) Wind Lake Benton Power Partners II LLC 100.50 Mid-1999 (3) Wind Woodstock Wind Farm, LLC 10.20 Oct. 1998 (2) ------- Total Wind 240.60 Biomass Minnesota Valley Alfalfa Producers (4) 75.00 Dec. 2001 (5) Biomass District Energy St. Paul Inc. 25.00 Summer 2002 (6) Biomass Lindroc Energy 25.00 Summer 2002 (6) ------- Total Biomass 125.00 (1) Formerly Zond Minnesota Development Corporation II (2) Approved by MPUC (3) Selected after a competitive negotiation process (4) Formerly Minnesota Agri-Power Project (5) Agreement signed (6) Selected after a competitive bid process
In 1994, the Company received Minnesota legislative approval for additional on-site temporary storage facilities at NSP's Prairie Island plant, provided the Company satisfies certain requirements. Seventeen dry cask containers, each of which can store approximately one-half year's used fuel, were approved to become available. The first four casks were available in 1994. In late 1996, the MEQB certified that NSP has met the requirements necessary to use the sixth through ninth casks at the Prairie Island nuclear generating facility. The final eight casks become available in 1999 unless the above resource commitments are not met and the Minnesota Legislature revokes its approval. As of Dec. 31, 1997, the Company had loaded seven casks. Other commitments established by the Legislature include a discount for low-income electric customers, required conservation improvement expenditures and various study and reporting requirements to a legislative electric energy task force. In 1995, the MPUC approved the Company's low-income discount programs in accordance with the statute. The Company has implemented programs to begin meeting the other legislative commitments. The Company's capital commitments, disclosed below, include the known effects of the 1994 Prairie Island legislation. The impact of the legislation on power purchase commitments and other operating expenses is not yet determinable. GUARANTEES In 1997 and 1996, the Company sold a portion of its other receivables, consisting of energy loans made to customers, to a third party. The portion of the receivables sold consisted of customer loans to local government entities for energy efficiency improvements under various conservation programs offered by the Company. Under the sale agreements, the Company is required to guarantee repayment to the third party of the remaining loan balances. At Dec. 31, 1997, the outstanding balance of the loans was approximately $28 million. Based on prior collection experience of these loans, the Company believes that losses under the loan guarantees, if any, would have an immaterial impact on the results of operations. LEASES Rentals under operating leases were approximately $32 million, $29 million and $27 million for 1997, 1996 and 1995, respectively. Future commitments under these leases generally decline from current levels. FUEL CONTRACTS NSP has 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 1998 and 2013, require minimum purchases and deliveries of fuel, and additional payments for the right to purchase coal in the future. In total, NSP is committed to the minimum purchase of approximately $341 million of coal, $29 million of nuclear fuel and $291 million of natural gas and related transportation, 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 developed a mix of gas supply, transportation and storage 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 suppliers are expected to continue to provide reliable fuel supplies, risk of loss from nonperformance 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 1998-2005 500 Seasonal Diversity Exchanges: Summer exchanges from MH 1998-2014 150 1998-2016 200 Winter exchanges to MH 1998-2014 150 1998-2015 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 future annual capacity costs for the 500-megawatt MH agreement is estimated to be approximately $55 million. There are no capacity payments for the diversity exchanges. These commitments to MH represent about 17 percent of MH's system capability in 1998 and account for approximately 10 percent of NSP's 1998 electric system capability. The
risk of loss from nonperformance 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 has an agreement with Minnkota Power Cooperative for the purchase of summer season capacity and energy. From 1998 through 2001, the Company will buy 150 megawatts of summer season capacity for $12 million annually. From 2002 through 2015, the Company will purchase 100 megawatts of capacity for $10 million annually. Under the agreement, energy will be priced at the cost of fuel consumed per megawatt-hour at the Coyote Generating Station in North Dakota. The Company also has a seasonal (summer) purchase power agreement with Minnesota Power for the purchase of 173 megawatts, including reserves, from 1998-2000. The annual cost of this capacity will be approximately $2 million. The Company has agreements with several nonregulated power producers to purchase electric capacity and associated energy. The 1998 cost of these commitments for nonregulated capacity is approximately $46 million for 360 megawatts of summer capacity. This commitment is expected to remain at this level until 2012, at which time it will decrease to approximately $39 million annually and then gradually decrease to approximately $26 million in the year 2027 due to the expiration of existing agreements. 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 up to $79 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 site decontamination cleanup costs with coverage limits of $1.5 billion for each of the Company's two nuclear plant sites. The coverage consists of $500 million from Nuclear Mutual Limited (NML) and $1.0 billion from Nuclear Electric Insurance Limited (NEIL). NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums billed to NSP from NML and NEIL are expensed over the policy term. All companies insured with NML and NEIL are subject to retrospective premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NML and NEIL to the extent that the Company would have no exposure for retrospective premium assessments in case of a single incident under the business interruption and the property damage insurance coverages. However, in each calendar year, the Company could be subject to maximum assessments of approximately $4.6 million for business interruption insurance (five times the amount of its annual premium) and $19.0 million for property damage insurance (generally five times the amount of its annual premium) if losses exceed accumulated reserve funds. ENVIRONMENTAL CONTINGENCIES Other long-term liabilities include an accrual of $34 million, and other current liabilities include an accrual of $6 million at Dec. 31, 1997, for estimated costs associated with environmental remediation. Approximately $31 million of the long-term liability and $4 million of the current liability relate to a DOE assessment for decommissioning a federal uranium enrichment facility, as discussed in Note 13. 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 13 for further discussion.) The Environmental Protection Agency (EPA) or state environmental agencies have designated the Company as a "potentially responsible party" (PRP) for 15 waste disposal sites to which the Company allegedly sent hazardous materials. Ten of these 15 sites have been remediated and, consistent with settlements reached with the EPA and other PRPs, the Company has paid $1.7 million for its share of the remediation costs. While these remediated sites will continue to be monitored, the Company expects that future remediation costs, if any, will be immaterial. Under applicable law, the Company, along with each PRP, could be held jointly and severally liable for the total remediation costs of PRP sites. Of the five unremediated sites, the total remediation costs are currently estimated to be approximately $11 million. If additional remediation is necessary or unexpected costs are incurred, the amount
could be higher. The Company is not aware of the other parties' inability to pay, nor does it know if responsibility for any of the sites is in dispute. For these five 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 $750,000 for its share of future costs for these five sites, including $700,000 that is expected to be paid in 1998. While it is not feasible to determine the ultimate impact of PRP site remediation at this time, the amounts accrued represent the best current estimate of the Company's future liability. 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 a portion of the remediation costs paid to date. Management believes remediation costs incurred, but not recovered, from insurance carriers or other parties should be allowed recovery in future ratemaking. Until the Company is identified as a PRP, it is not possible to predict the timing or amount of any costs associated with sites, other than those discussed above. The Wisconsin Company potentially may be involved in the cleanup and remediation at four sites. Three sites are solid and hazardous waste landfill sites in Eau Claire, Rice Lake and Amery, Wis. The Wisconsin Company contends that it did not dispose of hazardous wastes in these landfills 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 these matters at this time. The Wisconsin Department of Natural Resources (WDNR) named the Wisconsin Company as one of three Responsible Parties for creosote and coal tar contamination at a fourth site in Ashland, Wis. WDNR's consultant is preparing a remedial option study for the entire Ashland site, which includes the Wisconsin Company's portion and two other adjacent portions. Until this study is completed and more information is known concerning the extent of the final remediation required by the WDNR, the remediation method selected, the related costs, the various parties involved, and the extent of the Wisconsin Company's responsibility, if any, for sharing the costs, the ultimate cost to the Wisconsin Company and timing of any payments related to the Ashland site are not determinable. At Dec. 31, 1997, the Company had recorded an estimated liability of $880,000 for future remediation costs associated with the Wisconsin Company-owned portion of the Ashland site. Through Dec. 31, 1997, the Wisconsin Company has incurred approximately $646,000 in actual expenditures to date. Based on a recent Public Service Commission of Wisconsin decision to allow recovery of incremental costs incurred for this site beginning in 1997, the Wisconsin Company has recorded a regulatory asset for the accrued and actual expenditures related to the Ashland site. The ultimate cleanup and remediation costs at the Eau Claire, Amery, Rice Lake and Ashland sites and the extent of the Wisconsin Company's responsibility, if any, for sharing such costs are not known at this time, but may be significant. The Company also is continuing to investigate various properties, which it presently or previously owned. The properties were formerly sites of gas manufacturing, gas storage plants or gas pipelines. The purpose of this investigation is to determine if waste materials are present, if they are 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 Company has already remediated one site, which continues to be monitored. The Company has paid $2.5 million to remediate this site and expects to incur in the future only immaterial monitoring costs related to this remediated site. Another 14 gas sites remain under investigation, and the Company 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 was initiated in 1996 to determine the cost and method of cleanup at these two sites, which began in 1997. As of Dec. 31, 1997, the Company has paid $8.1 million for the six active sites and has recorded an estimated liability of approximately $3.0 million for future costs, with payment expected over the next 10 years. This estimate is based on prior experience and includes investigation, remediation and litigation costs. As for the eight inactive sites, no liability has been recorded for remediation or investigation because the present land use at each of these sites does not warrant a response action. While it is not feasible to determine at this time the ultimate costs of gas site remediation, the amounts accrued represent the best current estimate of the Company's future liability for any required cleanup or remedial actions at these former gas operating sites. Environmental remediation costs may be recovered from insurance carriers, third parties, or in future rates. The MPUC allowed the Company to defer certain remediation costs of four active sites in 1994 and the Company requested, in its December 1997 gas rate case, recovery of these accumulated costs. In January 1998, the MPUC allowed the recovery of these gas site remediation costs in the interim gas rates that went into effect in February 1998. Accordingly, the Company has recorded an environmental regulatory asset for these costs (see Note 9). The Company may request recovery of costs to remedy the other two active sites following the completion of preliminary investigations. The Clean Air Act, including the Amendments of 1990 (the Clean Air Act), calls for reductions in emissions of sulfur dioxide and nitrogen oxides from electric generating plants. These reductions, which will be phased in, began in 1995. The majority of the rules implementing this complex legislation have been finalized. NSP has invested significantly over the years to reduce sulfur dioxide emissions at its plants. No additional capital
expenditures are anticipated to comply with the sulfur dioxide emission limits of the Clean Air Act. NSP is still evaluating how best to implement the nitrogen oxides standards. 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 still in the process of implementing some provisions of the Clean Air Act, its total financial impact is unknown at this time. Capital expenditures for opacity compliance are considered in the capital expenditure commitments disclosed previously. The depreciation of these capital costs will be subject to regulatory recovery in future rate proceedings. Several of NSP's facilities have asbestos-containing material, which represents a potential health hazard to people who come in contact with it. Governmental regulations specify the 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. Although the ultimate cost and timing of asbestos removal is not yet known, it is estimated that removal under current regulations would cost $45 million in 1997 dollars. Depending on the timing of asbestos removal, such costs would be recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects, or removal costs for demolition projects. 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. 15. Segment Information <TABLE> <CAPTION> Year Ended December 31 --------------------------------------- (Thousands of dollars) 1997 1996 1995 - ----------------------------------------------------------------------------------------------- <S> <C> <C> <C> Utility operating income before income taxes Electric $456 489 $469 321 $444 687 Gas 50 122 58 133 48 340 - ----------------------------------------------------------------------------------------------- Total utility operating income before income taxes $506 611 $527 454 $493 027 =============================================================================================== Utility depreciation and amortization Electric $299 226 $279 828 $266 231 Gas 26 654 26 604 23 953 - ----------------------------------------------------------------------------------------------- Total utility depreciation and amortization $325 880 $306 432 $290 184 =============================================================================================== Utility capital expenditures Electric $305 292 $323 532 $317 750 Gas 71 386 42 225 37 215 Common 19 927 20 898 31 057 - ----------------------------------------------------------------------------------------------- Total utility capital expenditures $396 605 $386 655 $386 022 =============================================================================================== Identifiable utility assets Electric $4 845 306 $4 735 330 $4 751 650 Gas 675 030 649 218 600 738 - ----------------------------------------------------------------------------------------------- Total identifiable utility assets $5 520 336 $5 384 548 $5 352 388 Other corporate assets * 1 623 730 1 252 352 876 197 - ----------------------------------------------------------------------------------------------- Total assets $7 144 066 $6 636 900 $6 228 585 =============================================================================================== </TABLE> * Includes equity investments for nonregulated energy projects outside of the United States of $517 million in 1997, $295 million in 1996 and $185 million in 1995. Note: The gas utility segment includes Viking.
16. Summarized Quarterly Financial Data (Unaudited) <TABLE> <CAPTION> Quarter Ended - ------------------------------------------------------------------------------------------------------------------ (Thousands of dollars) March 31, 1997 June 30, 1997* Sept. 30,1997 Dec. 31, 1997* - ------------------------------------------------------------------------------------------------------------------ <S> <C> <C> <C> <C> Utility operating revenues $742 496 $594 323 $697 443 699 484 Utility operating income 88 456 65 586 118 540 89 174 Net income 65 773 18 253 87 912 65 382 Earnings available for common stock 61 816 15 882 85 541 63 010 Earnings per average common share: Basic $0.90 $0.23 $1.23 $0.85 Assuming dilution $0.90 $0.23 $1.23 $0.85 Dividends declared per common share $0.690 $0.705 $0.705 $0.705 Stock prices---high $49 1/8 $52 $52 15/16 $58 7/8 ---low $45 1/2 $44 1/2 $48 $48 7/16 Quarter Ended - ------------------------------------------------------------------------------------------------------------------ (Thousands of dollars) March 31, 1996 June 30, 1996 Sept. 30, 1996 Dec. 31, 1996 - ------------------------------------------------------------------------------------------------------------------ Utility operating revenues $718 709 $592 258 $633 258 $709 981 Utility operating income 89 277 70 801 105 456 100 510 Net income 67 210 43 382 84 239 79 708 Earnings available for common stock 64 149 40 321 81 178 76 646 Earnings per average common share: Basic $0.94 $0.59 $1.18 $1.12 Assuming dilution $0.94 $0.59 $1.18 $1.11 Dividends declared per common share $0.675 $0.690 $0.690 $0.690 Stock prices---high $53 3/8 $49 5/8 $49 3/4 $49 1/8 ---low $47 5/8 $45 1/2 $44 1/2 $45 1/2 </TABLE> * 1997 results include two nonrecurring items: a $29 million pretax charge, which reduced second quarter earnings by 25 cents per share, for the write-off of merger costs; and a $9 million pretax charge, which reduced fourth quarter earnings by 8 cents per share, for the write-down of an NRG cogeneration project.
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE ================================================================================ During 1997 there were no disagreements with the Company's independent public accountants on accounting procedures or accounting and financial disclosures. PART III ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ================================================================================ Information required under this Item with respect to directors is set forth in the Registrant's 1998 Proxy Statement for its Annual Meeting of Shareholders to be held April 22, 1998, on pages 2 through 10 under the caption "Election of Directors," which is incorporated herein by reference. Information with respect to Executive Officers is included under the caption "Executive Officers" in Item 1 of this report, and is incorporated herein by reference. ITEM 11 - EXECUTIVE COMPENSATION ================================================================================ Information required under this Item is set forth in the Registrant's 1998 Proxy Statement for its Annual Meeting of Shareholders to be held April 22, 1998, on pages 11 through 19 under the caption "Compensation of Executive Officers," which is incorporated herein by reference. ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT ================================================================================ Information required under this item is set forth in the Registrant's 1998 Proxy Statement for its Annual Meeting of Shareholders to be held April 22, 1998, on page 10 under the caption "Share Ownership of Directors, Nominees and Named Executive Officers," which is incorporated herein by reference. ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ================================================================================ Information required under this Item is set forth in the Registrant's 1998 Proxy Statement for its Annual Meeting of Shareholders to be held April 22, 1998 on pages 3 through 7 under the captions "Class III - Nominees for Terms expiring in 2001," "Class II Directors whose Terms expire in 2000," "Class I - Directors whose Terms Expire in 1999," which is incorporated herein by reference.
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: Report of Independent Accountants for the years ended Dec. 31, 1997, 1996 and 1995. 50 Consolidated Statements of Income for the three years ended Dec. 31, 1997. 51 Consolidated Statements of Cash Flows for the three years ended Dec. 31, 1997 52 Consolidated Balance Sheets, Dec. 31, 1997 and 1996. 53 Consolidated Statements of Changes in Common Stockholders' Equity for the three years ended Dec. 31, 1997. 54 Consolidated Statements of Capitalization, Dec. 31, 1997 and 1996. 55 Notes to Financial Statements. 57 (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 of the Company 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 March 26, 1997 and ratified by the Company's shareholders on June 25, 1997. 4.01* Trust Indenture, dated Feb. 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* June 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* July 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* June 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* Sept. 1, 1956 (Exhibit 2.09 to File No. 2-13463).
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K ================================================================================ 4.11* Aug. 1, 1957 (Exhibit 2.10 to File No. 2-14156). 4.12* July 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* June 1, 1962 (Exhibit 2.14 to File No. 2-21601). 4.16* Sept. 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* June 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* Sept. 1, 1974 (Exhibit 2.01Z to File No. 2-53235). 4.28* Apr. 1, 1975 (Exhibit 4.01 AA 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* June 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* Sept. 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* Sept. 1, 1985 (Exhibit 4.37 to Form 10-K for the year 1985, File No. 1-3034). 4.39* July 1, 1989 (Exhibit 4.01 to Form 8-K dated July 7, 1989, File No. 1-3034). 4.40* June 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 Oct. 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 Dec. 7, 1993, File No. 1-3034).
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K ================================================================================ 4.44* Feb. 1, 1994 (Exhibit 4.01 to Form 8-K dated Feb. 10, 1994, File No. 1-3034). 4.45* Oct. 1, 1994 (Exhibit 4.01 to Form 8-K dated Oct. 5, 1994, File No. 1-3034). 4.46* June 1, 1995 (Exhibit 4.01 to Form 8-K dated June 28, 1995, File No. 1-3034). 4.47 April 1, 1997. 4.48* March 1, 1998 (Exhibit 4.01 to Form 8-K dated March 11, 1998, File No. 1-3034). 4.49* 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 4.49 dated as follows: 4.50* March 1, 1949 (Exhibit 7.02 to File No. 2-7825). 4.51* June 1, 1957 (Exhibit 2.13 to File No. 2-13463). 4.52* Aug. 1, 1964 (Exhibit 4.20 to File No. 2-23726). 4.53* Dec. 1, 1969 (Exhibit 2.03E to File No. 2-36693). 4.54* Sept. 1, 1973 (Exhibit 2.03F to File No. 2-49757). 4.55* Feb. 1, 1982 (Exhibit 4.01G to File No. 2-76146). 4.56* March 1, 1982 (Exhibit 4.08 to Form 10-K for the year 1982, File No. 10-3140). 4.57* June 1, 1986 (Exhibit 4.01I to File No. 33-6269). 4.58* March 1, 1988 (Exhibit 4.01J to File No. 33-20415). 4.59* 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). 4.60* April 1, 1991 (Exhibit 4.01L to File No. 33-39831). 4.61* March 1, 1993 (Exhibit 4.01 to Form 8-K dated March 4, 1993, File No. 10-3140). 4.62* Oct. 1, 1993 (Exhibit 4.01 to Form 8-K dated September 21, 1993, File No. 10-3140). 4.63* Dec. 1, 1996 (Exhibit 4.01 to Form 8-K dated December 12, 1996, File No. 10-3140). 4.64* NSP Employee Stock Ownership Plan. (Exhibit 4.60 to Form 10-K for the year 1994, File No. 1-3034). 4.65* Subordinated Debt Securities Indenture, dated as of Jan. 30, 1997, between the Company and Norwest Bank Minnesota, National Association, as trustee. (Exhibit 4.02 to Form 8-K dated Jan. 28, 1997, File No. 001-03034). 4.66* Preferred Securities Guarantee Agreement, dated as of Jan. 31, 1997, between the Company and Wilmington Trust Company, as Trustee. (Exhibit 4.05 to Form 8-K dated Jan. 28, 1997, File No. 001-03034). 4.67* Amended and Restated Declaration of Trust of NSP Financing I, dated as of Jan. 31, 1997 including form of Preferred Security. (Exhibit 4.10 to Form 8-K dated Jan, 28 1997, File No. 001-03034).
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K ================================================================================ 4.68* Supplemental Indenture, dated as of Jan. 31, 1997, between the Company and Norwest Bank Minnesota, National Association, as trustee, including form of Junior Subordinated Debenture. (Exhibit 4.12 to Form 8-K dated Jan 28, 1997, File No. 001 - 03034). 4.69* Common Securities Guarantee Agreement dated as of Jan. 31, 1997, between the Company and Wilmington Trust Company, as Trustee. (Exhibit 4.13 to Form 8-K dated Jan. 28, 1997, File No. 001 - 03034). 4.70* Subscription Agreement, dated as of Jan. 28, 1997, between NSP Financing I and the Company. (Exhibit 4.14 to Form 8-K dated Jan 28, 1997, File No. 001 - 03034). 10.01* 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). 10.02* 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). 10.03* Coordinating 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). 10.04* 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 Sept. 30, 1994, File No. 1-3034). 10.05* 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 Sept. 30, 1994, File No. 1-3034). 10.06* 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 Sept. 30, 1994, File No. 1-3034). 10.07* 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). Executive Compensation Arrangements and Benefit Plans ----------------------------------------------------- Covering Executive Officers and Directors ----------------------------------------- 10.08* Terms and Conditions of Employment - James J Howard, President and Chief Executive Officer, effective Feb. 1, 1987, as amended. (Agreement filed as Exhibit 10.11 to Form 10-K for the year 1986, File No. 1-3034, Acknowledgement of Amendment to Terms and Conditions of Employment of James J. Howard filed as Exhibit 10.01 to Form 10-Q for the quarter ended June 30, 1995, File No. 1-3034). 10.09* NSP Severance Plan. (Exhibit 10.12 to Form 10-K for the year 1994, File No. 1-3034). 10.10* NSP Deferred Compensation Plan amended effective Jan. 1, 1993. (Exhibit 10.16 to Form 10-K for the year 1993, File No. 1-3034). 10.11* Executive Long-Term Incentive Award Stock Plan. (Exhibit 10.10 to Form 10-K for 1988, File No. 1-3034). 10.14* Annual Executive Incentive Plan for 1997. (Exhibit 10.14 to Form 10-K for the year 1996, File No. 1-3034). 10.15 Stock Equivalent Plan for Non-Employee Directors of Northern States Power Company (As Amended and Restated Effective Oct. 1, 1997).
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K ================================================================================ 12.01 Statement of Computation of Ratio of Earnings to Fixed Charges. 21.01 Subsidiaries of the Registrant. 23.01 Consent of Independent Accountants - Price Waterhouse LLP, Minneapolis, MN. 99.01 Statement pursuant to Private Securities Litigation Reform Act of 1995. 99.02 Description of Common Stock. 99.03* Description of Business of NRG Energy, Inc. (Item 1 of NRG Energy, Inc.'s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 1997, File No. 333-33397). 27.01 Financial Data Schedule for 1997. 27.02 Restated Financial Data Schedule for 1996. 27.03 Restated Financial Data Schedule for 1995. 27.04 Restated Financial Data Schedule for the quarter ended September 1997. 27.05 Restated Financial Data Schedule for the quarter ended June 1997. 27.06 Restated Financial Data Schedule for the quarter ended March 1997. 27.07 Restated Financial Data Schedule for the quarter ended September 1996. 27.08 Restated Financial Data Schedule for the quarter ended June 1996. 27.09 Restated Financial Data Schedule for the quarter ended March 1996. (b) Reports on Form 8-K. The following reports on Form 8-K were filed either during the three months ended Dec. 31, 1997, or between Dec. 31, 1997 and the date of this report. Dec. 19, 1997 (Filed Dec. 19, 1997) - Item 5. Other Events. Re: Disclosure of indication that fourth quarter 1997 earnings per share will be below 1996 results. Dec. 31, 1997 (Filed March 5, 1998) - Item 5. Other Events. Item 7. Financial Statements and Exhibits. Re: Disclosure of agreement and plan of merger with Black Mountain Gas Company of Cave Creek, Arizona. March 4, 1998 (Filed March 4, 1998) - Item 5. Other Events. Item 7. Financial Statements and Exhibits. Re: Disclosure of the Company's consolidated financial statements for the year ended Dec. 31, 1997 and the related management's discussion and analysis. March 5, 1998 (Filed March 5, 1998) - Item 5. Other Events. Item 7. Financial Statements and Exhibits. Re: Disclosure of announcement that the Company will redeem all 300,000 shares of its Cumulative Preferred Stock Adjustable Rate Series A and all 650,000 shares of its Cumulative Preferred Stock Adjustable Rate B on March 31, 1998. March 11, 1998 (Filed March 16, 1998) Item 5. Other Events. Item 7. Financial Statements and Exhibits. Re: Disclosure of the Company entering into two underwriting agreements and filing of two prospectus supplements relating to $350,000,000, in aggregate principal amount of the Company's First Mortgage Bonds.
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 25, 1998 /s/ ------------------------------------------ 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. <TABLE> <CAPTION> <S> <C> /s/ /s/ - ------------------------------------------ ------------------------------------------ JAMES J HOWARD E J MCINTYRE Chairman of the Board, President and Chief Vice President and Chief Financial Officer Executive Officer (Principal Financial Officer) (Principal Executive Officer) /s/ /s/ - ------------------------------------------ ------------------------------------------ ROGER D SANDEEN H LYMAN BRETTING Vice President and Controller Director (Principal Accounting Officer) /s/ /s/ - ------------------------------------------ ------------------------------------------ DAVID A CHRISTENSEN W JOHN DRISCOLL Director Director /s/ /s/ - ------------------------------------------ ------------------------------------------ GIANNANTONIO FERRARI DALE L HAAKENSTAD Director Director /s/ /s/ - ------------------------------------------ ------------------------------------------ RICHARD M KOVACEVICH DOUGLAS W LEATHERDALE Director Director /s/ /s/ - ------------------------------------------ ------------------------------------------ MARGARET R PRESKA A PATRICIA SAMPSON Director Director </TABLE>
EXHIBIT INDEX ------------- Method of Exhibit Filing No. Description --- ----------- DT 3.02 Bylaws of the Company as amended March 26, 1997 and ratified by the Company's shareholders on June 25, 1997. DT 4.47 Supplemental Trust Indenture between the Company and Harris Trust and Savings Bank, as Trustee, dated April 1, 1997. DT 10.15 Stock Equivalent Plan for Non-Employee Directors of Northern States Power Company (As Amended and Restated Effective Oct. 1, 1997). DT 12.01 Statement of Computation of Ratio of Earnings to Fixed Charges. DT 21.01 Subsidiaries of the Registrant. DT 23.01 Consent of Independent Accountants - Price Waterhouse LLP, Minneapolis, MN. DT 99.01 Statement pursuant to Private Securities Litigation Reform Act of 1995. DT 99.02 Description of Common Stock. DT 27.01 Financial Data Schedule for 1997. DT 27.02 Restated Financial Data Schedule for 1996. DT 27.03 Restated Financial Data Schedule for 1995. DT 27.04 Restated Financial Data Schedule for the quarter ended September 1997. DT 27.05 Restated Financial Data Schedule for the quarter ended June 1997. DT 27.06 Restated Financial Data Schedule for the quarter ended March 1997. DT 27.07 Restated Financial Data Schedule for the quarter ended September 1996. DT 27.08 Restated Financial Data Schedule for the quarter ended June 1996. DT 27.09 Restated Financial Data Schedule for the quarter ended March 1996. DT = Filed electronically with this direct transmission.