Annual Report (Form 10-K), fiscal year 1994

Item 1 - Business
Northern States Power Company (the Company) was incorporated in 1909 under the laws of Minnesota. Its executive offices are located at 414 Nicollet Mall, Minneapolis, Minnesota 55401. (Phone 612-330-5500). The Company has two significant subsidiaries, Northern States Power Company, a Wisconsin corporation (the Wisconsin Company) and NRG Energy, Inc (NRG), a Delaware corporation; and several other subsidiaries, including Cenergy, Inc, a Minnesota corporation, and Viking Gas Transmission Company, a Delaware corporation (Viking). (See "NRG Energy, Inc." and "Other Subsidiaries" herein for further discussion of these subsidiaries.) The Company and its subsidiaries collectively are referred to herein as NSP.
NSP is predominantly an operating public utility engaged in the generation, transmission and distribution of electricity throughout a 49,000 square mile service area and the transportation and distribution of natural gas in approximately 148 communities within this area. Viking is a regulated natural gas transmission company that operates a 500-mile interstate natural gas pipeline. In addition to utility businesses, NRG manages several of NSP's non-regulated energy subsidiaries.
The Company serves customers in Minnesota, North Dakota and South Dakota. The Wisconsin Company serves customers in Wisconsin and Michigan. Of the approximately 3 million people served by the Company and the Wisconsin Company, the majority are concentrated in the Minneapolis-St. Paul metropolitan area. In 1994, about 61% of NSP's electric retail revenue was derived from sales in the Minneapolis-St. Paul metropolitan area and about 56% of retail gas revenue came from sales in the St. Paul area. (For business segment information, see Note 18 of Notes to Financial Statements under Item 8.)
NSP's utility businesses are experiencing some of the challenges currently common to regulated electric and gas utility companies, namely, increasing competition for customers, increasing pressure to control costs to operate and construct facilities, uncertainties in regulatory processes, increasing costs of compliance with environmental laws and regulations, and uncertainties related to permanent disposal of nuclear fuel. In May 1994, the Minnesota Legislature approved a plan for temporary storage of used nuclear fuel, if the Company satisfies certain responsibilities, which should eliminate for several years the uncertainty surrounding continued operation of its nuclear plants. (See Management's Discussion and Analysis under Item 7 and Notes 16 and 17 of Notes to Financial Statements under Item 8 for further discussion of this matter.)
NRG was active in the international energy market through partnership and joint venture investments in 1994. NRG acquired partial ownership positions in the MIBRAG mbh coal and power complex and in the 900 megawatt (Mw) Schkopau power plant both near Leipzig, Germany. NRG is also the operator and 37.5% owner of the 1,680 Mw Gladstone Power Station in Queensland, Australia. (See additional discussions of business acquisitions and non-regulated operations in the "NRG Energy, Inc." and "Other Subsidiaries" sections, herein, and in Notes 4 and 5 of Notes to Financial Statements under Item 8.)
UTILITY REGULATION AND REVENUES
General
Retail sales rates, services and other aspects of the Company's operations are subject to the jurisdiction of the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), and the South Dakota Public Utilities Commission (SDPUC) within their respective states. The MPUC also possesses regulatory authority over aspects of the Company's financial activities including security issuances, property transfers when the asset value is in excess of $100,000, mergers with other utilities, and transactions between the regulated Company and non-regulated affiliates. In addition, the MPUC reviews and approves the Company's electric resource plans for meeting customers' future electric energy needs. The Wisconsin Company is subject to regulation of similar scope by the Public Service Commission of Wisconsin (PSCW) and the Michigan Public Service Commission (MPSC). In addition, each of the state commissions certifies the need for new generating plants and transmission lines of designated capacities to be located within the respective states before the facilities may be sited and built.
Wholesale rates for electric energy sold in interstate commerce, wheeling rates for energy transmission in interstate commerce, the wholesale gas transportation rates of Viking, and certain other activities of the Company, the Wisconsin Company and Viking are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). NSP also is subject to the jurisdiction of other federal, state and local agencies in many of its activities. (See "Environmental Matters" herein.)
The Minnesota Environmental Quality Board (MEQB) is empowered to select and designate sites for new power plants with a capacity of 50 Mw or more and routes for transmission lines with a capacity of 200 kilovolts (Kv) or more, and to evaluate such sites and routes for environmental compatibility. The MEQB may designate sites or routes from those proposed by power suppliers or those developed by the MEQB. No such power plant or transmission line may be constructed in Minnesota except on a site or route designated by the MEQB.
NSP is unable to predict the impact on its operating results from the future regulatory activities of any of the above agencies. To the best of its ability, NSP works to understand and comply with all rules and regulations issued by the various agencies.
Revenues
NSP's financial results depend on its ability to obtain adequate and timely rate relief from the various regulatory bodies, its ability to control costs and the success of its non-regulated activities. NSP's 1994 utility operating revenues, excluding intersystem non-firm electric sales to other utilities of $89 million and miscellaneous revenues of $58 million, were subject to regulatory jurisdiction as follows:
Authorized Return on Percent of Common Equity @ Total December 31, 1994 Revenues Electric Gas (Electric & Gas) Retail: Minnesota Public Utilities Commission 11.47% 11.47% 73.3% Public Service Commission of Wisconsin 11.4 11.4 14.7 North Dakota Public Service Commission 11.50 14.0 5.3 South Dakota Public Utilities Commission * 3.1 Michigan Public Service Commission 12.25 0.6
Sales for Resale - Wholesale, Viking Gas and Interstate Transmission: Federal Energy Regulatory Commission * * 3.0
Total 100.0%
* Settlement proceeding, based upon revenue levels granted with no specified return.
Rate Programs
Rate increases requested and granted in previous years from various jurisdictions were as follows (note that 1992, 1993 and 1994 amounts represent annual increases effective in these years, while previous years represent annual increases requested in those years even if effective in a subsequent year):
Annual Increase/(Decrease) Year Requested Granted (Millions of dollars)
1990 19.5 11.2 1991 118.7 68.0 1992 ----- ----- 1993 166.6 101.5 1994 (1.0) (1.0)
The following table summarizes the status of rate increases for rates effective in 1994.
Rate Matters by Jurisdiction
Minnesota Public Utilities Commission (MPUC)
On Jan. 31, 1994, the Minnesota Department of Public Service, the Office of the Minnesota Attorney General and the Minnesota Energy Consumers intervenor groups filed an appeal with the Minnesota Court of Appeals of the MPUC's determination on the allowed return on equity granted to the Company in final 1993 electric and gas rate orders. On Aug. 2, 1994, the Court affirmed the final rate orders issued in January 1994 for these rate cases. This appeal process is now completed. As a result of this decision, no adjustments or changes are required to rates charged to customers or to revenues recorded by the Company.
In 1991, the Minnesota legislature passed a law which granted the MPUC discretionary authority to approve a rate adjustment clause for changes in certain costs (including property taxes, fees and permits) incurred by Minnesota public utilities. The MPUC may approve a utility's use of the rate adjustment clause for billing customers if certain conservation expenditure levels are met. On Oct. 4, 1994, the Company filed for approval of the use of the adjustment clause for billing its gas customers, beginning in January 1995, for increases in property taxes. The potential gas revenue increase from this filing was approximately $2.0 million. At a hearing held on Feb. 23, 1995, the MPUC turned down the Company's request. The Company may ask the MPUC to reconsider this decision.
On Oct. 28, 1994 the Company filed with the MPUC a petition for a miscellaneous rate change approving the implementation of an annual recovery mechanism for deferred electric Conservation Improvement Program (CIP) expenses. On Feb. 23, 1995, the MPUC voted to approve recovery of $41 million under a new rate adjustment clause for the period May 1995 through June 1996. Thereafter, the Company would be required to request a new cost recovery level annually. The Company estimates it will receive an additional $24 million in revenues in 1995. This increased recovery results from a corresponding increase in conservation expenses and avoids a significant delay between the incurring of costs and recovery in rates.
On Oct. 5, 1994, as part of a response to 1994 legislation related to fuel storage at the Prairie Island nuclear plant, the Company filed a miscellaneous rate change proposal with the MPUC which reflects a 50% discount on the first 300 kilowatt hours (Kwh) consumed each month by qualified low- income residential customers. The Company proposed that the discount be effective beginning with the October 1994 billing month for qualifying customers, and that rate adjustments designed to recover from other customers the costs of the discount be effective Jan. 4, 1995. The MPUC approved the filing on Dec. 5, 1994. The ruling also eliminated the Conservation Rate Break and restructured the rates between customer classes, but does not significantly change overall revenue levels.
By September 1 of each year, the Company is required by Minnesota statute to submit to the MPUC an annual report of the Purchased Gas Adjustments (PGA) for each customer class by month for the previous year commencing July 1 and ending June 30. The report verifies whether the utility is calculating the adjustments properly and implementing them in a timely manner. In addition, the MPUC review includes an analysis of procurement policies, cost-minimizing efforts, rule variances in effect or requested, retail transportation gas volumes, independent auditors' reports, and the impact of market forces on gas costs for the coming year. The MPUC has the authority to disallow certain costs if it deems the utility was not prudent in its gas procurement activities. The Department of Public Service (DPS) has recommended a $1.1 million cost recovery disallowance. This filing is pending MPUC action.
Gas utilities in Minnesota are also required to file for a change in design day demand, to redistribute demand percentages among classes, or exchange one form of demand for another. The Company filed in October 1994 to increase its demand entitlements due to projected increases in firm customer count, to decrease the Minnesota jurisdictional allocation of total demand entitlements and to recover the demand entitlement costs associated with the increase in transportation and storage levels in its monthly PGA's. This filing is pending MPUC approval.
No general rate filings are anticipated in Minnesota in 1995.
North Dakota Public Service Commission (NDPSC)
On Dec. 29, 1993, the Company received approval from the NDPSC to increase base rates $1.2 million, or 1.2%, to recover 1994 cost increases associated with power purchased from the Manitoba Hydro-Electric Board. The additional costs consist of demand charges related to 500 Mw of firm capacity for four months. Eight months of the annual demand costs, which took effect May 1, 1993, were included in the Company's previous rate increase granted in April 1993. The $1.2 million annual increase was implemented Jan. 5, 1994.
On Aug. 9, 1994 the Company applied to the NDPSC for a rate reduction of $3.6 million in annual electric revenues. The reduction reflects a correction in cost allocations to the North Dakota jurisdiction. The Company also requested authority to make refunds to customers to effectively implement the reduction as of June 1, 1994. On Nov. 9, 1994, the NDPSC approved the proposed rate reduction. In January 1995, the NDPSC held a hearing on the possibility of retroactive refunds for the period Jan. 1, 1989, through June 1, 1994, but has not yet reached a decision. The ultimate outcome of this proceeding is not determinable at this time.
On Nov. 1, 1994 NSP received approval of its proposed Economic Development Rider (EDR) by the NDPSC. The rider allows NSP's North Dakota operations (NSP-ND) to offer discounted rates to new customers, or on load expansions by existing customers, for a period of five years. The customer's load must be at least 50 kilowatts (Kw). The rider is closely tied to the state's Partnership in Assisting Community Expansion (PACE) program, which offers low interest rates on business development loans. The EDR will enable NSP-ND to remain competitive with neighboring energy providers, most of which have rate discount incentives to attract new customers. At this time, the amount of the discounts is not expected to have a material affect on the Company's financial results.
No general rate filings are anticipated in North Dakota in 1995.
South Dakota Public Utilities Commission (SDPUC)
There were no general rate filings in South Dakota in 1994 and none are anticipated in 1995.
Public Service Commission of Wisconsin (PSCW)
In June 1993, the Wisconsin Company filed with the PSCW for a $1.4 million annual increase in gas retail rates to be effective Jan. 1, 1994. In Aug. 1993, the Wisconsin Company increased its request to $1.7 million to amortize recovery of a portion of the acquisition premium paid by the Company for Viking in recognition of reduced delivered gas costs. In Dec. 1993, the PSCW issued an order approving a $1.4 million increase on an annual basis in the Wisconsin Company's gas rates, including the amortization. These rate changes took effect on Jan. 1, 1994.
The Wisconsin Company filed a proposal for a new high load factor rate with the PSCW in November 1994 to be effective Jan. 1, 1995. Under the proposal, qualifying customers would receive a credit on their bills of up to 3 percent, depending on load factor. This is expected to reduce 1995 revenues for the Wisconsin Company by approximately $1.0 million.
The Wisconsin Company will file a general rate case in June 1995, for rates effective in 1996, as required by the PSCW biennial filing requirement.
Retail Rate Recovery of Viking Acquisition Costs
During 1993, the Company and the Wisconsin Company requested regulatory approval in Minnesota, North Dakota, Wisconsin and Michigan to recover in retail gas rates a portion of the acquisition cost paid for Viking in recognition of reduced retail delivered gas costs made possible by the acquisition of Viking. The PSCW approved in the Wisconsin Company's gas rates recovery of a total of $1.8 million over the five-year period 1994-98. On March 23, 1994, the NDPSC authorized, without any change in rates, the amortization of $150,000 in annual jurisdictional expense for Viking acquisition costs over a 15 year period starting in June of 1993. On Nov. 21, 1994 the MPUC rejected PGA recovery of jurisdictional expense for Viking acquisition costs (amounting to $1.5 million annually), but ruled the Company could seek recovery in its next gas general rate case. Viking's expenses will include approximately $2 million in annual acquisition cost amortization each year until 2008.
Electric Transmission Tariffs and Settlement (FERC)
In 1990, the Company filed a transmission services tariff for certain transmission customers. New rates were effective under the filing, subject to refund, for the period Dec. 29, 1990 through Oct. 31, 1994. The Company has recorded an estimated liability at Dec. 31, 1994 for potential transmission rate refunds under this tariff based on the FERC order dated Sept. 21, 1993. Since a rehearing of the order was granted and is currently pending, transmission rates for this period are not yet final.
The FERC announced a new transmission pricing policy effective Oct. 26, 1994. The new policy introduces greater flexibility in transmission pricing structure. It established five principles of transmission pricing including guidelines on coverage of revenue requirements, comparability of transmission service, balance of efficiency, fairness and practicality.
In March 1994, the Company filed a revised open access transmission tariff with the FERC. On May 25, 1994, the FERC accepted the filing with the new rates effective Nov. 1, 1994, subject to refund. The FERC also ruled the tariff would be subject to the requirement that the Company offer transmission service using terms and conditions comparable to its own use of the system. The Company recently reached a settlement in principle with several parties involved in this proceeding. The settlement agreement includes a transmission tariff that complies with the FERC transmission pricing policy which calls for comparability of service and pricing, network service, and unbundling of ancillary charges such as scheduling and load following. The Company anticipates acceptance of the settlement offer in 1995. The revenue effect on the Company is an increase of approximately $200,000 per year. The new tariff allows the Company to comply with transmission pricing provisions of open access transmission required by the Energy Policy Act of 1992.
Minnesota Wholesale Rate Proceedings (FERC)
In 1990, 16 of the Company's 19 municipal wholesale customers in Minnesota began reviewing their long-term power supply options. Eight customers created a joint action group, the Minnesota Municipal Power Agency (MMPA), to serve their future power supply needs. An additional wholesale customer became an associate member of the MMPA. In 1992 these nine municipal customers notified the Company of their intent to terminate their power supply agreements with the Company effective July 1995 or July 1996. These nine customers represent approximately $29 million in annual revenues and a maximum demand load of approximately 155 Mw.
In Oct. 1993, the MMPA filed a complaint with the FERC under new Section 211 of the Federal Power Act alleging that the Company had not bargained in good faith toward a transmission service agreement which would allow MMPA to deliver power supply to its members starting July 1, 1995, when some of the municipalities' supply agreements with the Company expire. On Jan. 26, 1994, the FERC in a proposed order ruled that the Company had bargained in good faith, as required by Section 211, but ordered the Company and MMPA to negotiate for sixty days to attempt to resolve remaining issues. The Commission accepted a settlement agreement in 1994. The MMPA customers agreed to pay the rate then in effect for firm transmission service. Following FERC acceptance of the pending transmission tariff, the MMPA customers will be charged the new tariff unit rates.
In 1992 and 1993, the Company signed long-term power supply agreements with the remaining 10 of its current 19 municipal customers in Minnesota. The agreements commit the customers to purchase power from the Company for up to 13 years (through 2005) at fixed rates to increase by up to 3% per year. The 10 customers represent a maximum demand load of approximately 59 Mw and provide approximately $10 million in annual revenue. The FERC accepted formula rates effective Jan. 1, 1994, by order dated Feb. 23, 1994.
Other Wholesale Rate Proceedings (FERC)
In Dec. 1993 the Company, in compliance with a FERC order in the Central Maine case requiring that the Commission approve all interstate, inter-utility contracts, filed over 300 such contracts with the FERC for review. The Commission established 76 separate dockets for review. Absent FERC acceptance, the contracts could have been declared null and void, possibly resulting in full refunds for all amounts paid. The FERC has accepted 75 dockets with little or no change. The remaining docket is expected to be accepted. The Company anticipates full resolution of the Central Maine compliance filings in 1995.
The Wisconsin Company plans to announce market-based pricing options for existing and potential wholesale customers in 1995. The wholesale customers have new opportunities to purchase power from power suppliers other than NSP. With open transmission access, they have the opportunity to purchase power from any producer and request that, on a comparable basis, the power be delivered from the producer to their municipality.
In May, 1994, the Wisconsin Company offered its municipal wholesale customers a discount of one to two percent off the FERC authorized rate for a long-term full requirements commitment between five and ten years with comparable cancellation notices. Five of the ten municipal wholesale customers signed up for the discounts. The total annual decrease in revenues is approximately $0.1 million.
Ratemaking Principles in Minnesota and Wisconsin
Since the MPUC assumed jurisdiction of Minnesota electric and gas rates in 1975, several significant regulatory precedents have evolved. The MPUC accepts the use of a forecast test year that corresponds to the period when rates are put into effect and allows collection of interim rates subject to refund. The use of a forecast test year and interim rates minimizes regulatory lag.
The MPUC must order interim rates within 60 days of a rate case filing. Minnesota statutes allow interim rates to be set using (1) updated expense and rate base items similar to those previously allowed, and (2) a return on equity equal to that granted in the last MPUC order for the utility. The MPUC must make a determination on the application within 10 months after filing. If the final determination does not permit the full amount of the interim rates, the utility must refund the excess revenue collected, with interest. To the extent final rates exceed interim rates, the final rates become effective at the time of the order and retroactive recovery of the difference is not permitted. Generally, the Company may not increase its rates more frequently than every 12 months.
Minnesota law allows Construction Work in Progress (CWIP) in a utility's rate base instead of recording Allowance for Funds Used During Construction (AFC) in revenue requirements for rate proceedings. The MPUC has exercised this option to a limited extent so that cash earnings are allowed on small and short-term projects that do not qualify for AFC. (For the Company's policy regarding the recording of AFC, see Note 1 of Notes to Financial Statements under Item 8.)
The PSCW has a biennial filing requirement for processing rate cases and monitoring utilities' rates. By June 1 of each odd-numbered year, the Wisconsin Company must submit filings for calendar test years beginning the following January 1. The filing procedure and subsequent review generally allow the PSCW sufficient time to issue an order effective with the start of the test year.
The PSCW reviews each utility's cash position to determine if a current return on CWIP will be allowed. The PSCW will allow either a return on CWIP or capitalization of AFC at the adjusted overall cost of capital. The Wisconsin Company currently capitalizes AFC on production and transmission CWIP at the FERC formula rate and on all other CWIP at the adjusted overall cost of capital.
Fuel and Purchased Gas Adjustment Clauses in Effect
The Company's retail electric and Wisconsin Company wholesale rate schedules provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy. Although the lag in implementing the billing adjustment is approximately 60 days, an estimate of the adjustment is recorded in unbilled revenue in the month costs are incurred. The Company's wholesale customers remaining with NSP do not have a fuel clause provision in their contracts. The contracts instead provide a fixed rate with an escalation factor. The Wisconsin Company calculates the wholesale electric fuel adjustment factor for the current month based on estimated fuel costs for that month. The estimated fuel cost is adjusted to actual the following month.
The Wisconsin Company's automatic retail electric fuel adjustment clause for Wisconsin customers was eliminated effective in 1986. The clause was replaced by a limited-issue filing procedure. Under the procedure, an annual deviation in fuel costs of 2% and a monthly deviation of 8% will allow filing for a change in rates limited to the fuel issue. The adjustment approved is calculated on an annual basis, but applied prospectively.
Gas rate schedules for the Company and the Wisconsin Company include a purchased gas adjustment (PGA) clause that provides for rate adjustments for changes in the current unit cost of purchased gas compared to the last costs included in rates.
The Wisconsin Company's gas and retail electric rate schedules for Michigan customers include Gas Cost Recovery Factors and Power Supply Cost Recovery Factors, which are based on 12 month projections. After each 12 month period, a reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers.
Viking is a transportation-only interstate pipeline and provides no sales services. As a result, Viking terminated its PGA clause effective Nov. 1, 1993. Natural gas fuel for compressor station operations is provided in-kind by transportation service customers.
ELECTRIC UTILITY OPERATIONS
Competition
NSP's electric sales are subject to competition in some areas from municipally owned systems, rural cooperatives and, in certain respects, other private utilities and cogenerators. Electric service also increasingly competes with other forms of energy. The degree of competition may vary from time to time, depending on relative costs and supplies of other forms of energy. Although NSP cannot predict the extent to which its future business may be affected by supply, relative cost or promotion of other electricity or energy suppliers, NSP believes that it will be in a position to compete effectively.
NSP has proposed to fill future needs for new generation through competitive bid solicitations. The use of competitive bidding to select future generation sources allows the Company to take advantage of the developing competition in this sector of the industry. The Company's proposal, which has been approved by the MPUC, allows NRG to bid in response to Company solicitations for proposals and the Company is seeking permission to include an NSP regulated alternative in the future.
Management intends to obtain regulatory approval in all retail jurisdictions to use a single bid process to meet resource needs for the entire integrated system. The Company's competitive bidding proposal has been approved by both the MPUC and PSCW.
In Oct. 1992, the President signed into law the Energy Policy Act of 1992 (Energy Act). The Energy Act amends the Public Utility Holding Company Act of 1935 (1935 Act) and the Federal Power Act. Among many other provisions, the Energy Act is designed to promote competition in the development of wholesale power generation in the electric utility industry. It exempts a new class of independent power producers from regulation under the 1935 Act. The Energy Act also allows the FERC to order wholesale "wheeling" by public utilities to provide utility and non-utility generators access to public utility transmission facilities. The provision allows the FERC to set prices for wheeling, which will allow utilities to recover certain costs. The costs would be recovered from the companies receiving the services, rather than the utilities' retail customers. The market-based power agreement filings with FERC (as discussed in "Utility Regulation and Revenues", herein) reflect the trend toward increasing transmission access under the Energy Act. The Energy Act's ultimate impact on NSP cannot be predicted.
In 1994, the FERC issued proposed rulemaking to address the rate treatment of potential "stranded investment" costs which may result as the electric energy market becomes more competitive. The FERC is soliciting comments on options for recovery of transition costs associated with existing electric investments for which competitive market pricing might not provide recovery. NSP is evaluating the FERC proposal to determine the potential effects on operating results and customer rates and has responded to the FERC individually and through an industry group. The FERC has not reached a final decision, and the effects of the proposed rulemaking currently are not known.
Many states are currently considering retail competition. While the topic of retail competition has been discussed in the Company's jurisdictions, no legislation or regulatory initiatives have been formally introduced. The PSCW has asked each utility in the state for comments regarding retail competition. In response to the request, the Wisconsin Company filed the following recommendations. Competition should be phased in for retail markets by customer classes, with all customers having choice of supplier by 2001. The generation segment of the industry should be deregulated by 2001. Prudent stranded costs should be recovered prior to the advent of retail wheeling. Finally, utilities and other competitors should have a level playing field for issues such as obligation to serve, eminent domain, requirements for demand side management, funding of social programs, opening of retail markets to competition and other issues. Also, as an outcome of the responses to the PSCW, a task force was formed by the PSCW to analyze the industry restructuring necessary in the state of Wisconsin. A goal of this task force is to have a list of recommended legislative changes to the Wisconsin Legislature for the 1996 session.
The Michigan Public Service Commission has determined that Michigan should recodify statutes governing energy production. They will be working with the governor's office to initiate that process. Michigan also has a retail wheeling experiment, limited to its two largest utilities and customers larger than $50 million, currently underway. The Wisconsin Company's customers are not included in this experiment which is currently being challenged in court.
Retail competition represents yet another development of a competitive electric industry. Management plans to continue its ongoing efforts to be a low-cost supplier of electricity and an active participant in the more competitive market for electricity expected as a result of the Energy Act. Actions the Company is pursuing to position for the competitive environment include: creative partnership solutions with strategic customers including communities; focusing on the unique needs of national account customers; competitive pricing alternatives; improved reliability; implementation of the first service guarantees in the region; ease of customer access including 24 hour, 7 days/week operation; substantial customer convenience and flexibility improvements via a new Customer Service System which includes appointment scheduling upon first contact, improved outage call response, and a wide array of new billing options; and aggressive cost management.
Capability and Demand
Assuming normal weather, NSP expects its 1995 summer peak demand to be 7,229 Mw. NSP's 1995 summer capability is estimated to be 8,942 Mw, net of contract sales including 1,153 Mw (including reserves) of contracted purchases from the Manitoba Hydro-Electric Board, a Canadian Crown Corporation (Manitoba Hydro) and 868 Mw of other contracted purchases. The estimate assumes 7,682 Mw of thermal generating capability and 1,438 Mw of hydro and wind generating capability. Of the total summer capability, NSP has committed 178 Mw for sales to other utilities. Of the estimated net capability, including the interconnection with Manitoba Hydro, 30% has been installed during the last 10 years.
NSP's 1994 maximum demand of 7,101 Mw occurred on June 14, 1994. Resources available at that time included 6,859 Mw of Company-owned capability and 1,860 Mw of purchased capability net of contracted sales. Due to the Mid- Continent Area Power Pool's (MAPP) penalty for reserve margin shortfalls and to be prepared for weather uncertainty at the lowest potential cost, NSP carried a reserve margin for 1994 of 23%. The minimum reserve margin requirement as determined by the members of the MAPP, of which NSP is a member, is 15%. (See Note 17 of Notes to Financial Statements under Item 8 for more discussion of power agreement commitments.)
The Company added to its generating facilities in 1994. On Sept. 24, 1994, the Angus Anson 232 Mw gas-fired combustion turbines were placed in service near Sioux Falls, South Dakota. The total cost of this project was approximately $72 million.
The Company is continuing an extensive reliability program that includes preventive maintenance on transmission and distribution power lines, improvements to existing equipment, and testing and implementing new technology. Reliability to NSP's large customers improved 14% in 1994, through a focused program to reduce the number of outages caused by lightning, human errors, animals and trees. In 1994, a service guarantee program was implemented to ensure on-time service installation and construction site restoration.
In 1994, NSP signed a long term power purchase contract with LSP-Cottage Grove for 245 Mw of annual capacity for thirty years. LSP-Cottage Grove was awarded the contract from a competitive negotiated process ordered by the MPUC which considered six different vendors and projects. The purchase will be from a natural gas- fired combined cycle facility that NSP can dispatch as system requirements dictate. The MPUC requested the Minnesota Department of Public Service (DPS) to review the reasonableness of the price NSP is paying LSP-Cottage Grove for the capacity and energy. In December 1994 the DPS issued its report concluding that the contract prices are appropriate. On Feb. 2, 1995 the MPUC determined that the contract was at or below NSP's avoided cost. The pricing considers both capacity and energy. NSP expects the LSP-Cottage Grove facility to be available in May 1997.
The Company filed an electric resource plan with the MPUC in 1993. The plan shows how the Company intends to meet the increased energy needs of its electric customers and includes an approximate schedule of the timing of such needs. The plan contains: conservation programs to reduce the Company's peak demand and conserve overall electricity use; economic purchases of power; and programs for maintaining reliability of existing plants. It also includes an approximate schedule of timing of such needs. The plan does not anticipate the need for additional base-load generating plants during the balance of this century and assumes that all existing generating facilities will continue operating through their license period or useful life.
The MPUC approved the Company's resource plan on July 15, 1994, but directed the Company to make a compliance filing addressing the MPUC's proposed modifications. These modifications reflect changes due to the Prairie Island legislation enacted in 1994 and the inclusion of updated information that became available after the resource plan was filed. The Company submitted the compliance filing on Dec. 13, 1994. The revisions submitted in the compliance filing do not significantly alter the Company's resource plan filed in 1993.
The following resource needs were included in the resource plan. The plan does not specify the precise technology to meet these needs, but does suggest energy source options.
The resource plan proposes to satisfy the above resource needs through a combination of the following options:
Sources of Energy to Meet Needs
- Continued operation of existing generation facilities. - Demand reduction of 2,000 Mw by 2008 through conservation and load management. - 425 Mw of wind generation in service by 2002. - 125 Mw of biomass generation in service by 2002. - Increased reliance on hydro power under contracts from Manitoba Hydro. - Standby generation and cogeneration at customer sites when mutually beneficial to both NSP and the customer. - Purchase of 245 Mw of natural gas-fired combined cycle generation. - Competitive bidding to fill additional needs for new generation.
In connection with the approval of fuel storage facilities at the Company's Prairie Island generation plant, legislation was enacted in 1994 which established certain resource commitments, as discussed in Note 17 to the Financial Statements under Item 8. The Company has taken steps to comply with the requirements of these resource commitments. 25 Mw of third party wind generation has been fully operational since May 1, 1994 and is performing as expected. All significant permit applications have been filed for another 100 Mw to be in service by November of 1996. The Company filed a proposal with the MPUC in January 1995 for the first 50 Mw of biomass generation. In addition, the Company announced its plan to seek significant public input in its exploration for an alternate interim used nuclear fuel storage site in Goodhue County, Minnesota. The Company's construction commitments disclosed in Note 17 to the Financial Statements include the known effects of the 1994 Prairie Island legislation. The impact of the legislation on power purchase commitments is not yet determinable.
The MPUC has begun a proceeding to establish values representing environmental costs imposed by electric generation that are not part of the price of electricity. These values are known as environmental externalities. The values, expected to be established later in 1995, will be applied by the MPUC in resource planning proceedings to determine the total social cost of different generating options to supply the growing demand for electricity. Depending on the values established and the manner in which they are applied, externalities could significantly affect resources available to NSP to meet future demands for electricity.
The Company continues to implement various Demand Side Management (DSM) programs designed to improve load factor and reduce the Company's power production cost and system peak demands, thus reducing or delaying the need for additional investment in new generation and transmission facilities. The Company currently offers a broad range of DSM programs to all customer sectors, including information programs, rebate and financing programs, and rate incentive programs. These programs are designed to respond to customer needs and focus on increasing value of service that, over the long term, will help its customer base become more stable, energy efficient and competitive. During 1994, the Company's programs accomplished approximately 183 Mw of system peak demand reduction. Since 1986, the Company's DSM programs have achieved 1,012 Mw of summer peak demand reduction, which is equivalent to 14% of its 1994 summer peak demand. The Company's operating goals, which go beyond the resource plan guideline above, are to offset peak electric demand by 1,100 Mw by 1995 and 1,700 Mw by 2000. The Company continues to focus on improving the cost-effectiveness of its DSM programs through market research studies, program evaluations and changes to its program mix.
In 1994, the MPUC improved the Company's cost recovery and incentives for DSM by allowing recovery of a portion of the lost margins due to DSM impacts on electric revenues. This lost margin recovery, subject to annual review by the MPUC, was approximately $3 million in 1994. In addition, the MPUC allowed the Company to earn another $4 million in DSM investment returns through an incentive program that rewards the attainment of specified conservation goals.
Energy Sources
For the year ended Dec. 31, 1994, 47% of NSP's Kwh requirements was obtained from coal generation and 28% was obtained from nuclear generation. Purchased and interchange energy provided 21%, including 15% from Manitoba Hydro; NSP's hydro and other fuels provided the remaining 4%. The fuel resources for NSP's generation based on Kwh were coal (59%), nuclear (36%), renewable and other fuels (5%).
The following is a summary of NSP's electric power output in millions of Kwh for the past three years:
1994 1993 1992 Thermal plants 32,710 33,130 30,467 Hydro plants 922 1,001 1,024 Purchased and interchange 9,054 8,541 8,187 Total 42,686 42,672 39,678
Many of NSP's power purchases from other utilities are coordinated through the regional power organization MAPP, pursuant to an agreement dated March 31, 1972, with amendments filed in 1994. NSP is one of 49 participants in MAPP consisting of 10 investor-owned systems, eight generation and transmission cooperatives, three public power districts, seven municipal systems, the Department of Energy's Western Area Power Administration and 20 Associate Participants. The MAPP agreement provides for the members to coordinate the installation and operation of generating plants and transmission line facilities. The terms and conditions of the MAPP agreement and transactions between MAPP members are subject to the jurisdiction of the FERC. The 1972 MAPP agreement, as amended, was accepted for filing by the FERC on Dec. 15, 1994.
Fuel Supply and Costs
Coal and nuclear fuel will continue to dominate NSP's regulated utility fuel requirements for generating electricity. It is expected that approximately 98 percent of NSP's fuel requirements, on a Btu basis, will be provided by these two fuels over the next several years, leaving 2 percent of NSP's annual fuel requirements for generation to be provided by other fuels (including natural gas, oil, refuse derived fuel, waste materials, renewable sources and wood). The actual fuel mix for 1994 and the estimated fuel mix for 1995 and 1996 are as follows:
Fuel Use on Btu Basis (Est) (Est) 1994 1995 1996
Coal 60.9% 61.1% 63.1% Nuclear 37.4% 37.1% 35.1% Other 1.7% 1.8% 1.8%
The Company normally maintains between 20 and 45 days of coal inventory depending on the plant site. The Company has long-term contracts providing for the delivery of up to 100 percent of its 1995 coal requirements. Coal delivery may be subject to short-term interruptions or reductions due to transportation problems, weather and availability of equipment.
The Company expects that more than 98% of the coal it burns in 1995 will have a sulfur content of less than 1 percent. The Company has contracts with three Montana coal suppliers, Westmoreland Resources, Western Energy, Big Sky Coal Company and three Wyoming suppliers, Rochelle Coal Company, Antelope Coal Company and Black Thunder Coal Company, for a maximum total of 60 million tons of low-sulfur coal for the next 5 years. These arrangements are sufficient to meet the requirements of existing coal-fired plants. They also permit the Company to purchase additional coal when such purchase would improve fuel economics and operations. The Company has options from suppliers for over 100 million tons of coal with a sulfur content of less than 1 percent that could be available for future generating needs. The plants in the Minneapolis-St. Paul area are about 800 miles from the mines in Montana and 1,000 miles from the mines in Wyoming. Coal delivered by rail provides the Company with an economical source of fuel.
The estimated coal requirements of the Company at its major coal-fired generating plants for the periods indicated and the coal supply for such requirements are as follows:
*MBTU = Million British Thermal Units
Notes:
(1) Contract expiration dates vary between 1995 and 2005 for western coal, which can provide up to 100% of the required fuel supply for the designated generating unit. Spot market purchases of other western coal, and other fuels will provide the remaining fuel requirements when such purchases would improve fuel economics. The Company is also burning petroleum coke as a source of fuel.
(2) This percentage represents the average blended sulfur content of the combination of fuels typically burned at each plant.
(3) The Black Dog Fluidized Bed (Unit 2) SO2 limit is 1.2 lb/MBTU.
(4) The SO2 limitation at Riverside Unit 8 is 2.5 lb/MBTU. The limitation for units 6 and 7 is currently 0.9 lb SO2 /MBTU.
(5) Compliance with air pollution control permit and applicable air quality regulations requires use of limestone scrubbers to achieve 70% SO2 removal and a maximum limit of SO2 emission to 0.96 lb/MBTU during any 90-day period for Units 1 and 2. For Unit 3, the SO2 emission limit is 0.60 lb/MBTU.
(6) Annual requirements are expected to range from 11.0 to 13.3 million.
The Company's current fuel oil inventory is adequate to meet anticipated 1995 requirements. Additional oil may be provided through spot purchases from two local refineries and other domestic sources.
To operate the Company's nuclear generating plants, the Company secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication. The contract strategy involves a portfolio of spot, medium and long-term contracts for uranium, conversion and enrichment. Current contracts are flexible and cover between 70% and 100% of uranium, conversion and enrichment requirements through the year 1997. These contracts expire at varying times between 1997 and 2005. The overlapping nature of contract commitments will allow the Company to maintain 70% to 100% coverage beyond 1997, if appropriate. The Company expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants. Fuel fabrication is 100% committed through the year 2003. The Company expects the unit cost of fuel to produce electricity with these nuclear facilities will be lower than the comparable cost of fuel to produce electricity with any other currently available fuel sources for the sustained operation of a generation facility. The cost of nuclear fuel, including disposal, is recovered in the customer price of the electricity sold by the Company.
The Company's fuel costs for the past three years are shown below:
Fuel Costs * Per Million Btu Year Ended December 31 1992 1993 1994
Coal** $ 1.22 $ 1.17 $1.22 Nuclear*** .43 .41 .47 Composite All Fuels .93 .90 .93
* Fuel adjustment clauses in its electric rate schedules or statutory provisions enable NSP to adjust for fuel cost changes. (See "Utility Regulation and Revenues - Fuel and Purchased Gas Adjustment Clauses" under Item 1.)
** Includes refuse-derived fuel and wood.
*** See Note 1 to the Financial Statements under Item 8 for an explanation of the Company's nuclear fuel amortization policies.
Nuclear Power Plants - Licensing, Operation and Waste Disposal
The Company operates two nuclear generating plants: the single unit, 539 Mw Monticello Nuclear Generating Plant and the Prairie Island Nuclear Generating Plant with two units totaling 1,025 Mw. The Monticello Plant received its 40-year operating license from the Nuclear Regulatory Commission (NRC) on Sept. 8, 1970, and commenced operation on June 30, 1971. Prairie Island Units 1 and 2 received their 40-year operating licenses on Aug. 9, 1973, and Oct. 29, 1974, respectively, and commenced operation on Dec. 16, 1973, and Dec. 21, 1974, respectively.
The Prairie Island and Monticello nuclear plants currently hold the Institute of Nuclear Power Operations' (INPO) top rating for plant operations and training. The Company is one of only two utilities in the nation to achieve INPO's top rating simultaneously at all of its nuclear plants.
The Company previously operated the Pathfinder Plant near Sioux Falls, SD as a nuclear plant from 1964 until 1967, after which it was converted to an oil and gas-fired peaking plant. The nuclear portions were placed in a safe storage condition in 1971, and the Company began decommissioning in 1990. Most of the plant's nuclear material, which was contained in the reactor building and fuel handling building, was removed during 1991. Decommissioning activities cost approximately $13 million and have been expensed. A few millicuries of residual contamination remains in the operating plant.
Operating nuclear power plants produce gaseous, liquid and solid radioactive wastes. The discharge and handling of such wastes are controlled by federal regulation. For commercial nuclear power plants, high-level radioactive waste includes used nuclear fuel. Low-level radioactive wastes are produced from other activities at a nuclear plant. They consist principally of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in the plant.
A 1980 federal law places responsibility on each state for disposal of its low-level radioactive waste. The law encourages states to form regional agreements or compacts to dispose of regionally generated waste. Minnesota is a member of the Midwest Interstate Low-Level Radioactive Waste Compact Commission. Following the expulsion of Michigan from the Midwest Compact in 1991 for failing to make progress, Ohio was designated the host state. The State of South Carolina closed its disposal facility to out-of-region waste on July 1, 1994. Ohio is projecting completion of the low-level radioactive waste disposal facility in 2005. The Company, along with all other low-level radioactive waste generators in the Midwest Compact, will need to store low- level radioactive waste onsite in the interim.
The federal government has the responsibility to dispose of domestic used nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act of 1982 requires the Department of Energy (DOE) to implement a program for nuclear waste management including the siting, licensing, construction and operation of repositories for domestically produced used nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes.
The Company has contracted with the DOE for the disposal of used nuclear fuel. The DOE charges a quarterly disposal fee based on nuclear electric generation sold. This fee ranges from approximately $10 million to $12 million per year, which NSP recovers from its customers in cost-of-energy rate adjustments. In 1985, NSP paid the DOE a one-time fee of $95 million for fuel used prior to April 7, 1983.
In 1979 the Company began expanding the used nuclear fuel storage facilities at its Monticello Plant by replacement of the racks in the storage pool. Also, in 1987, the Company completed the shipment of 1,058 spent fuel assemblies from the Monticello Plant to a General Electric storage facility in Morris, Illinois. As a result, the plant now has sufficient pool storage capacity to operate until 2008. Storage availability for operation beyond 2008 is not assured at this time.
In 1976 the Company began expanding the used nuclear fuel storage facilities at its Prairie Island Plant by replacement of the racks in the storage pool. Total capacity was increased from 210 fuel assemblies to 1,386 fuel assemblies. The used nuclear fuel storage facilities at the Company's Prairie Island Plant are expected to reach full capacity during 1995. In May 1994 additional on-site dry cask fuel storage facilities were approved by the Minnesota Legislature which are expected to provide sufficient storage capacity to operate the plant until at least 2002, provided the Company satisfies certain responsibilities. Seventeen dry cask containers, each of which can store approximately one-half year's used fuel, can become available as follows: five immediately in 1994; four more in 1996 if an application for an alternative storage site is filed, an effort to locate such a site is made and 100 MW of wind generation is available or contracted for construction; and the final eight in 1999 unless the specified alternative site is not operational or under construction, certain resource commitments are not met or the Minnesota Legislature revokes its approval.
An updated nuclear decommissioning study and nuclear plant depreciation capital recovery request was filed with the MPUC in July 1994 for the Company's nuclear power plants. Although management expects to operate the Prairie Island plant units through the end of its useful lives, the requested capital recovery would allow for the plant to be fully depreciated, including the accrual and recovery of decommissioning costs, about six years earlier than the end of its useful life. The proposed cost recovery period has been reduced because of the uncertainty regarding the spent fuel storage situation. On Jan. 25, 1995 the MPUC issued an order approving this filing. On Feb. 14, 1995 the North American Water Office (NAWO) filed a petition for reconsideration with the MPUC to change the capital recovery period for Prairie Island, so that the plant is fully depreciated by 2002. The petition concerns the issue of used nuclear fuel storage after 2002. A decision by the MPUC is expected by the end of 1995.
During the past several years, the NRC has issued a number of regulations, bulletins and orders that require analyses, modification and additional equipment at commercial nuclear power plants. The Company has spent $528 million since 1971, and approximately $6 million, $11 million and $53 million for 1994, 1993 and 1992, respectively. In addition, the Company expects to expend an additional $2 million for currently required NRC analyses, modification and additional equipment. The NRC is engaged in various ongoing studies and rulemaking activities that may impose additional requirements upon commercial nuclear power plants. Management is unable to predict any new requirements or their impact on the Company's facilities and operations.
See Note 16 to the Financial Statements under Item 8 for further discussion of nuclear fuel disposal issues and information on decommissioning of the company's nuclear facilities. Also, see Note 17 to the Financial Statements under Item 8 for a discussion of the Company's nuclear insurance and potential liabilities under the Price-Anderson liability provisions of the Atomic Energy Act of 1954.
Electric Operating Statistics
The following table summarizes the revenues, sales and customers from NSP's electric transmission and distribution business:
GAS UTILITY OPERATIONS
Competition
NSP provides retail gas service in portions of eastern North Dakota and northwestern Minnesota, the eastern portions of the Twin Cities metro area, and other regional centers in Minnesota (Mankato, St. Cloud and Winona) and Wisconsin (Eau Claire, La Crosse and Ashland). NSP is directly connected to four interstate natural gas pipelines serving these regions: Northern Natural Gas Company (Northern), Viking, Williston Basin Interstate Pipeline Company (Williston) and Great Lakes Transmission Limited Partnership (Great Lakes). Approximately 90 percent of NSP's retail gas customers are served from the Northern pipeline system.
During 1992 and 1993, the FERC issued a series of orders (together called Order 636) that addressed interstate natural gas pipeline restructuring. This restructuring required all interstate pipelines, including those serving NSP, to "unbundle" each of the services they provide: sales, transportation, storage and ancillary services. To comply with Order 636, NSP executed new pipeline transportation service and gas supply agreements effective Nov. 1, 1993, as discussed below. While these new agreements create a new form of contractual obligation, NSP believes the new agreements provide flexibility to respond to future changes in the retail natural gas market. NSP expects its financial risk under the new transportation agreements to be no greater than the risk faced under the previous long-term full requirements gas supply contracts with interstate pipelines.
As a result of the changes in the natural gas industry in the last decade, culminating in Order 636, the natural gas supply network throughout North America has been transformed into an integrated gas supply grid where NSP purchases natural gas from numerous suppliers, directly contracts for transportation service on directly connected and upstream pipelines, and is able to flexibly deliver the supplies to any NSP retail gas service territory. In addition, NSP directly contracts for underground storage and owns and operates several liquified natural gas and propane-air peak shaving facilities. NSP's diversified supply and transportation contracts, as well as underground storage and peak shaving facilities, provide NSP with the ability to meet customer needs with a reliable and economic natural gas supply.
Order 636 ended the traditional pipeline sales service function effective Nov. 1, 1993. This is a significant change for the natural gas industry. Traditionally, the pipeline sales function met two important needs for local distribution companies (LDCs) such as NSP, which serve primarily weather- sensitive space heating markets: (1) reliability of supply and (2) flexibility to meet varying load conditions in response to day-to-day weather variations. NSP believes the new unbundled services under Order 636 have to date proved to be as reliable and flexible as the traditional sales service.
The implementation of Order 636 applies additional competitive pressure on all LDCs to keep gas supply and transmission prices for their large customers competitive because of the alternatives now available to these customers. Like gas LDCs, these customers now have expanded ability to buy gas directly from suppliers and arrange pipeline and LDC transportation service. NSP has provided unbundled transportation service since 1987. Transportation service does not currently have an adverse effect on earnings because NSP's sales and transportation rates have been designed to make NSP economically indifferent as to whether it sells or transports gas. However, some transportation customers may have greater opportunities or incentives to physically bypass the LDC distribution system. NSP has arranged its gas supply and transportation portfolio in anticipation that it may be required to terminate its retail merchant sales function. Overall, NSP expects Order 636 will enhance its ability to remain competitive and allow it to increase certain of its margins by providing an increased selection of services to its customers.
Order 636 allows interstate pipelines to negotiate with customers to recover up to 100 percent of prudently incurred "transition costs" attributable to Order 636 restructuring. Recoverable transition costs can include "buy down" and "buy out" costs for remaining gas supply and upstream pipeline transportation agreements, unrecovered deferred gas purchase costs, and the cost to dispose of regulated assets no longer needed because of the termination of the merchant function (e.g., financial losses on the sale of regulated storage facilities).
NSP's primary gas supplier, Northern, is in the process of determining the final amount of transition costs to be passed on to customers as a result of Order 636 restructuring. Northern's restructuring provided for the assignment of a significant portion of Northern's gas supply and upstream contract obligations. This solution was beneficial because Northern's customers contracted directly for obligations, rather than paying to buy out of those obligations and then contracting with the same gas suppliers and pipelines to replace the merchant function. The total transition costs recoverable for the remaining unassigned agreements is limited to $78 million. In addition, Northern may seek transition cost recovery for certain other costs, subject to prudency review. Northern's total Order 636 transition costs, to be passed on to all of its customers, are estimated to be approximately $100 million. Northern will recover the prudent transition costs by amortizing the amount over a period of several years, and including the amortized costs as a component of its transportation charges. NSP estimates that it will be responsible for less than $12 million of Northern's transition costs, spread over a period of approximately five years, which began Nov. 1, 1993. To date, NSP's regulatory commissions have approved recovery of restructuring charges in retail gas rates.
NSP has no significant Order 636 transition cost responsibilities to its other pipeline suppliers. FERC has ruled that NSP has no transition cost obligation to Williston for its primary transportation service since it was never a gas sales customer of that pipeline. Viking incurred no Order 636 transition costs. NSP does not have significant transportation service on ANR Pipeline and Great Lakes subject to transportation cost charges under pricing in effect after Order 636.
The gas services available to NSP's customers were enhanced beginning in 1993 through the acquisitions of Viking in June 1993 and the assets of a gas marketing business by a new NSP subsidiary, Cenergy, Inc, in October 1993. Viking provides NSP with continued access to competitive interstate natural gas transportation. Cenergy can provide more customized value-added energy services to retail gas customers without increasing costs within the regulated retail gas distribution business. See the Other Subsidiaries section herein for further discussion of Viking and Cenergy.
The NSP gas operations area has taken significant steps to position itself to take on the additional responsibilities and take advantage of the new market opportunities resulting from the restructuring of the natural gas industry. In addition to construction of new pipeline interconnections, modernization of its propane-air peaking facilities, and fundamental changes to its supply portfolio including underground storage, NSP installed a state- of-the-art delivery management system in July 1994.
NSP's gas utility took advantage of opportunities to expand into new service territory during 1994. NSP extended service to 15,300 customers in 13 new communities. In addition to exploring new growth opportunities available, NSP is also focusing on conversion of potential customers who are located near NSP's gas mains but are not hooked up to receive the service. NSP estimates there are approximately 18,000 potential customers that fall into this category.
The largest 1994 expansion project occurred in Crow Wing and Cass counties in north central Minnesota. Outside the St Paul-Minneapolis area, these counties are experiencing the fastest growth of all counties in Minnesota. The project included laying approximately 550 miles of pipeline in 10 of the cities in the Brainerd Lakes area. The project's net capitalized investment cost was approximately $23 million. Construction began in June 1994 and was completed in November 1994. There were 6,300 new customers signed up under this project as of Dec 31, 1994. The MPUC approved a "new town" rate surcharge for customers in this area to support NSP's capital investment in the project. Subject to continued regulatory approval, the surcharge will be in effect for up to 15 years.
The Company's gas operation has organized a non-utility service offering individuals service contracts on a variety of home appliances. Working in partnership with local independent service contractors, NSP Advantage Service offers 24 hour service. Depending on the level of service contracted, Advantage Service customers have coverage to help avoid the expense and inconvenience of unexpected appliance repairs. This service is being offered to individuals within NSP's service territory.
Capability and Demand
NSP categorizes its gas supply requirements as firm (primarily for space heating customers) or interruptible (commercial/industrial customers with an alternate energy supply). NSP's maximum daily sendout (firm and interruptible) of 686,130 MMBtu for 1994 occurred on Jan. 17, 1994.
NSP's primary gas supply sources are purchases of third-party gas which are delivered under gas transportation service agreements with interstate pipelines. In addition, NSP has contracted with four providers of underground natural gas storage services to meet the heating season and peak day requirements of NSP gas customers. These agreements provide for firm deliverable pipeline capacity of approximately 540,396 MMBtu/day. Using storage reduces the need for firm gas supplies. These storage agreements provide NSP storage for approximately 16% of annual and 32% of peak daily firm requirements. NSP also owns and operates three liquified natural gas (LNG) plants with a storage capacity of 2.53 Bcf equivalent and four propane-air plants with a storage capacity of 1.42 Bcf equivalent to help meet the peak requirements of its firm residential, commercial and industrial customers. These peak shaving facilities have production capacity equivalent to 242,300 Mcf of natural gas per day, or approximately 35% of peak day firm requirements. NSP's LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the "needle peaks" caused by firm space heating demand on extremely cold winter days.
The cost of gas supply, transportation service and storage service is recovered through the purchased gas adjustment. The average cost of gas and propane held in inventory for the latest test year is allowed in rate base by the MPUC and the PSCW.
A number of NSP's interruptible industrial customers purchase their natural gas requirements directly from producers or brokers for transportation and delivery through NSP's distribution system. The transportation rates have been designed to make NSP economically indifferent as to whether NSP sells and transports gas or only transports gas. However, to the extent contractual terms allow, rates would increase based on changes in transportation and other costs.
Gas Supply and Costs
As a result of Order 636 restructuring, NSP's natural gas supply commitments have been unbundled from its gas transportation and storage commitments. NSP's gas utility actively seeks gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased risk and economical rates. This diversification involves numerous domestic and Canadian supply sources, varied contract lengths, and transportation contracts with seven natural gas pipelines.
The Company's supply options were enhanced in 1992 with the successful completion of a direct interconnection to the Williston system near Fargo, North Dakota. The addition of this direct connection allows the Company more direct access to additional productive gas supply basins in western North Dakota and Wyoming, and provides the Company an alternative to its two traditional pipeline suppliers (Northern and Viking).
Among other things, Order 636 provides for the use of the "straight fixed/variable" rate design that allows pipelines to recover all their fixed costs through demand charges. NSP has firm gas transportation contracts with the following seven pipelines. The contracts expire in various years from 1995 through 2012.
Northern Natural Gas Great Lakes Transmission Limited Partnership Williston Basin Interstate Northern Border Pipeline Viking Gas Transmission ANR Pipeline TransCanada Gas Pipeline
The agreements with Great Lakes, Northern Border, ANR and TransCanada provide for firm transportation service upstream of Northern Natural and Viking, allowing competition among suppliers at supply pooling points, minimizing commodity gas costs.
In addition to these fixed transportation charge obligations, NSP has entered into firm gas supply agreements that provide for the payment of monthly or annual reservation charges irrespective of the volume of gas purchased. The total annual obligation is approximately $20.4 million. These agreements are beneficial because they allow NSP to purchase the gas commodity at a high load factor at rates below the prevailing market price reducing the total cost per Mcf.
NSP has certain gas supply and transportation agreements, which include obligations for the purchase and/or delivery of specified volumes of gas, or to make payments in lieu thereof. At Dec. 31, 1994, NSP was committed to approximately $376.5 million in such obligations under these contracts, over the remaining contract terms, which range from the years 1995-2013. These obligations include some of the effects of contract revisions made to comply with Order 636. NSP has negotiated "market out" clauses in its new supply agreements, which reduce NSP's purchase obligations if NSP no longer provides merchant gas service.
NSP purchases firm gas supply from a total of approximately 20 domestic and Canadian suppliers under contracts with durations of one year to 10 years. NSP purchases no more than 20% of its total daily supply from any single supplier. This diversity of suppliers and contract lengths allows NSP to maintain competition from suppliers and minimize supply costs. NSP's objective is to be able to terminate its retail merchant sales function, if either demanded by the marketplace or mandated by regulatory agencies, with no financial cost to NSP.
The state utility commissions in Minnesota, North Dakota, Wisconsin and Michigan allowed NSP to fully recover the costs of these restructured services through purchased gas adjustments to customer rates.
Purchases of gas supply or services by NSP from its Viking pipeline affiliate and Cenergy gas marketing affiliate are subject to approval by the MPUC. The MPUC has approved all the Company's transportation contracts with Viking and a spot gas purchase agreement with Cenergy. Requests for approval between the Company and the Wisconsin Company and between the Company and NSP's generating plants are pending MPUC approval.
The following table summarizes the average cost per MMBtu of gas purchased for resale by NSP's gas distribution business which excludes Viking and Cenergy:
The Company Wisconsin Company 1991 $2.50 $2.73 1992 $2.71 $2.80 1993 $3.11 $3.02 1994 $2.59 $3.13
Gas Operating Statistics
The following table summarizes the revenue, sales and customers from NSP's gas business:
NRG ENERGY, INC.
NRG Energy, Inc. (NRG) is the Company's subsidiary that develops, builds, acquires, owns and operates several non-regulated energy-related businesses. It was incorporated in Delaware on May 29, 1992 and assumed ownership of the assets of NRG Group, Inc., including its subsidiary companies. The businesses that NRG currently owns or operates generated 1994 revenues of $81 million and had assets of $407 million at Dec. 31, 1994.
NRG conducts business through various subsidiaries, including: NRG International, Inc.; Graystone Corporation; Scoria Incorporated; San Joaquin Valley Energy I, Inc.; San Joaquin Valley Energy IV, Inc.; NRG Energy Jackson Valley I, Inc.; NRG Energy Jackson Valley II, Inc.; NEO Corporation; NRG Energy Center, Inc.; NRG Sunnyside Inc. and NRG Operating Services, Inc.
Operating Businesses
In Dec. 1993, NRG, through a wholly owned foreign subsidiary, agreed to acquire a 33% interest in the coal mining, power generation and associated operations of Mitteldeutsche Braunkohlengesellschaft mbh (MIBRAG), located south of Leipzig, Germany. MIBRAG is a German corporation formed by the German government to hold two open-cast brown coal (lignite) mining operations, a lease on an additional mine, the associated mining rights and rights to future mining reserves, two small industrial power plants and a circulating fluidized bed power plant, a district heating system and coal briquetting and dust production facilities. Under the acquisition agreement, Morrison Knudsen Corporation and PowerGen plc also each acquired a 33% interest in MIBRAG, while the German government retained a one-percent interest in MIBRAG. The investor partners began operating MIBRAG effective Jan. 1, 1994 and the legal closing occurred Aug. 11, 1994. NRG's acquisition investment in MIBRAG, including capitalized development costs, was approximately $16 million.
In March of 1994, NRG, through wholly owned foreign subsidiaries, as part of an unincorporated joint venture with Comalco Limited of Australia (Comalco) and other parties, acquired a 37.5% interest in the Gladstone Power Station, a 1680 Mw coal-fired plant in Gladstone, Queensland, Australia from the Queensland Electricity Commission. A large portion of the electricity generated by the station is sold to Comalco for use in its aluminum smelter, pursuant to long-term power purchase agreements. NRG, through an Australian subsidiary, operates the Gladstone plant. NRG's acquisition investment in the Gladstone project, including capitalized development costs, was approximately $70 million.
NRG operates two refuse-derived fuel (RDF) processing plants and an ash disposal site in Minnesota. The ownership of one plant was transferred by the Company to NRG at the end of 1993. The legal transfer of ownership of the Company's 85% share of the other RDF plant and of the ash disposal site was approved by the serviced counties with transfer to NRG expected in 1995. In 1994, workers at the RDF plants processed more than 730,000 tons of municipal solid waste into approximately 640,000 tons of RDF that was burned at two NSP power plants and at a power plant owned by United Power Association.
NRG also owns and operates three steam lines in Minnesota that provide steam from the Company's power plants to the Waldorf Corporation, the Andersen Corporation and the Minnesota Correctional Facility in Stillwater.
During 1993, the Company formed NEO Corporation, a wholly owned subsidiary, which owns a 50% interest in Minnesota Methane LLC. Minnesota Methane LLC is developing small scale waste to energy facilities utilizing landfill gas. During 1994, the ownership of NEO Corporation was transferred by the Company to NRG. On Dec. 20, 1994, NEO acquired a 50% ownership in STS HydroPower Limited, an independent power producer with 21 Mw of hydroelectric facilities throughout the United States. NEO's acquisition investment in STS was approximately $4 million.
NRG, through wholly owned subsidiaries, owns 45% of the San Joaquin Valley Energy partnership, (SJVEP), which owns four power plants located near Fresno, California with a total capacity of 55 Mw. Through February 1995, the plants operated under long-term Standard Offer 4 (SO4) power sales contracts with Pacific Gas & Electric (PG&E) which expire in 2017. On February 28, 1995 PG&E reached basic agreements with SJVEP to acquire the SO4 contracts. The parties entered into a bridging agreement to cover the period until all regulatory approvals are received for the transaction. The bridging agreement required SJVEP to cease power deliveries to PG&E as of February 28, 1995. The negotiated agreements will result in cost savings for PG&E customers as well as economic benefits for SJVEP. The final impact of this transaction on the financial results of NSP will not be known until the agreements have been approved and all costs associated with the idling of the facilities are known. It is expected that a one-time gain from the transaction will be recorded in the first half of 1995. SJVEP will continue to own and maintain the facilities and will explore all available options.
NRG, through wholly owned subsidiaries, owns 50% of the Jackson Valley Energy partnership, which owns and operates a 15 Mw cogeneration power plant near Sacramento, California. The plant has a long-term power sales agreement with Pacific Gas & Electric through 2014.
NRG, through a wholly owned subsidiary, purchased the assets of the Minneapolis Energy Center (MEC), a downtown Minneapolis district heating and cooling system in August of 1993. The system utilizes steam and chilled water generating facilities to heat and cool buildings for approximately 90 heating and 30 cooling customers. The primary assets include the main plant, with 800,000 lbs/hour of steam capacity and 22,000 tons/hour of chilled water capacity, three satellite plants, two standby plants, six miles of steam lines and two miles of chilled water distribution lines. Existing long-term contracts with MEC customers remain in effect under NRG's ownership.
On Dec. 31, 1994 NRG, through a wholly owned subsidiary, purchased a 50% ownership interest in Sunnyside Cogeneration Associates (SCA), a Utah joint venture (partnership), which owns and operates a 51 Mw waste coal plant in Utah. The acquisition investment by NRG was approximately $11 million. The waste coal plant is currently being operated by a 50% owned NRG partnership.
Scoria Incorporated and Western SynCoal Co., a subsidiary of Montana Power Co., completed construction in January 1992 of a demonstration coal conversion plant designed to improve the heating value of coal by removing moisture, sulfur and ash. The plant, located in Montana, has the ability to produce 300,000 tons of clean coal annually which, when burned, produces emissions in compliance with the Clean Air Act. The fuel may be an alternative to scrubbers for some energy companies. Testing of the plant ended in August 1993 and commercial operations began at that time. NRG's net capitalized investment in the Scoria coal project was written down by $3.5 million in 1994 to reflect reductions in the expected future operating cash flows from the project. NRG continues to evaluate the recoverability of its remaining investment in the Scoria project.
New Business Development
NRG is pursuing several energy-related investment opportunities, including those discussed below, and continues to evaluate other opportunities as they arise. Potential capital requirements for these opportunities are discussed in the "Capital Spending and Financing" section.
On Dec. 10, 1993, NRG, through a wholly owned foreign subsidiary, acquired a 50% interest in a German corporation, Saale Energie GmbH (Saale). Saale owns a 400 Mw share of a 900 Mw power plant currently under construction in Schkopau, Germany, which is near Leipzig. PowerGen plc of the United Kingdom acquired the remaining 50% interest in Saale. Saale was formed to acquire a 41.1% interest in the power plant. VEBA Kraftwerke Ruhr AG of Gelsenkirchen, Germany (VKR), is the builder of the Schkopau plant. VKR owns the remaining 58.9% interest in the power plant and will operate the plant. The plant will be fired by brown coal (lignite) mined by MIBRAG under a long- term contract. Saale has a long-term power sales agreement for its 400 Mw share of the Schkopau facility with VEAG of Berlin, Germany, the company that controls the high-voltage transmission of electricity in the former East Germany. The first unit of the plant is due to be completed by the end of 1995 and the second unit is due to be completed in mid-1996. Through Dec. 31, 1994 NRG had invested $20 million to acquire its interest in Saale including capitalized development costs. NRG's future equity commitment to Saale through 1996 is expected to be no more than $50 million.
On June 10, 1993, NRG, together with the International Finance Corporation (an affiliate of the World Bank), CMS Energy Corporation (the parent company of Consumers Power Company) and later Corporation Andina de Fomento (CAF) formed the Scudder Latin American Trust for Independent Power (Scudder), an investment fund which is intended to invest in the development of new power plants and privatization of existing power plants in Latin America and the Caribbean. The fund has retained Scudder Stevens & Clark as its investment manager. The fund commenced its investment development efforts in September 1993. Each of the four investors has committed $25 million which the fund is seeking to invest over the next five years. The fund has commenced private placement activities to obtain additional investors in the fund, particularly other utility affiliates and institutional investors. As of Dec. 31, 1994, NRG has invested $4 million in Scudder. Scudder has reached agreements to purchase shares of two power plant projects in Latin America.
Graystone Corporation, with several other companies, continues with permitting plans to build the first privately owned uranium enrichment plant in the United States. Construction of the Louisiana plant, which would provide fuel for the nuclear power industry, could begin in 1995. Because of the uncertainty surrounding the ultimate successful operation of this plant, NRG wrote off its $1.5 million investment in Graystone during 1994.
Other
In July 1994, Michigan Congeneration Partners Limited Partnership (MCP), a partnership between subsidiaries of NRG and Cogentrix Energy, Inc., reached an agreement with Consumers Power Company (Consumers), an electric utility headquartered in Jackson, Michigan, to terminate the power sales contract related to a 65 megawatt congeneration facility being developed by MCP in Parchment, Michigan. The agreement to terminate the contract required Consumers to make a payment to MCP of $29.8 million. As a result, NRG has recorded a net pretax gain from the termination of this contract of $9.7 million, which increased NSP's earnings by approximately nine cents per share in the third quarter of 1994.
OTHER SUBSIDIARIES
Viking Gas Transmission Company
In June 1993, the Company acquired 100 percent of the stock of Viking Gas Transmission Company (Viking) from Tenneco Gas, a unit of Tenneco Inc., in Houston, Texas. Viking, which is now a wholly owned subsidiary of the Company, owns and operates a 500-mile interstate natural gas pipeline serving portions of Minnesota, Wisconsin and North Dakota with a capacity of approximately 400 million cubic feet per day. The Viking pipeline currently serves 10 percent of NSP's gas distribution system needs. Viking currently operates exclusively as a transporter of natural gas for third-party shippers under authority granted by the FERC. Rates for Viking's transportation services are regulated by FERC. See "Rate Matters by Jurisdiction" herein regarding rate recovery requested for a portion of the acquisition cost paid by NSP to acquire Viking.
Cenergy, Inc.
NSP's non-regulated wholly owned subsidiary, Cenergy, Inc., commenced operations in October 1993 through the acquisition from bankruptcy of selected assets of Centran Corporation, a natural gas marketing company. Cenergy, in addition to marketing natural gas, provides customized value-added energy services to retail customers, both inside NSP service territory and on a national basis through its offices in Houston, TX; Louisville, KY; Chesapeake, VA; Dallas, TX; Corpus Christi, TX; Chicago, IL; and Pittsburgh, PA. Cenergy offers customers many energy products and services including: utility billing analysis, end-use gas marketing, risk management, construction, energy services consulting and administrative services. The MPUC has approved an affiliate transaction contract, whereby Cenergy may make natural gas sales at market based rates (determined by competitive bids) to NSP for resale to retail gas customers.
On Dec. 1, 1994 the FERC approved Cenergy's application to sell electric power (except electricity generated by NSP) in the United States, giving NSP an opportunity to enter the increasingly deregulated and competitive electric market. Cenergy is one of the first utility affiliates to obtain this approval from FERC. NSP is allowing open access to its electric transmission lines by other electric power providers throughout North America. Cenergy's initiative to buy and sell deregulated electricity is consistent with NSP's objective to embrace competition, which will benefit NSP customers and shareholders.
On January 19, 1995 Cenergy and Atlantic Energy Enterprises signed a memorandum of understanding to establish Atlantic CNRG Services LLC, a new subsidiary of both companies. Each company will own 50% of the new venture that will develop new and expanded natural gas and electric energy products and services, primarily in the Northeast region.
Eloigne Company
In 1993, the Company established Eloigne Company (Eloigne), to identify and develop affordable housing investment opportunities. Eloigne's principal business is the acquisition of a broadly diversified portfolio of rental housing projects which qualify for low income housing tax credits under federal tax law. As of Dec. 31, 1994, approximately $19 million had been invested in Eloigne projects. Tax credits recognized in 1994 as a result of these investments were approximately $2.0 million.
ENVIRONMENTAL MATTERS
NSP's policy is to proactively prevent adverse environmental impacts by regularly monitoring operations to ensure the environment is not adversely affected, and take timely corrective actions where past practices have had a negative impact on the environment. Significant resources are dedicated to environmental training, monitoring and compliance matters. NSP strives to maintain compliance with all applicable environmental laws.
In general, the Company has been experiencing a trend toward increasing environmental monitoring and compliance costs, which has caused and may continue to cause slightly higher operating expenses and capital expenditures. The Company has spent approximately $700 million on capitalized environmental improvements to new and existing facilities since 1968. The Company expects to incur approximately $15 million in capital expenditures and approximately $9 million in operating expenses for compliance with environmental regulations in 1995. The precise timing and amount of future environmental costs are currently unknown. (For further discussion of environmental costs, see "Environmental Matters" under Management's Discussion and Analysis of Financial Condition and Results of Operations under Item 7, and Note 17 to the Financial Statements under Item 8.)
Permits
NSP is required to seek renewals of environmental operating permits for its facilities at least every five years. NSP believes that it is in compliance, in all material respects, with environmental permitting requirements.
Waste Disposal
The onsite storage pool for used nuclear fuel at the Company's Monticello Nuclear Generating Plant is expected to provide sufficient storage capacity to operate the plant until 2008.
The onsite storage pool for used nuclear fuel at the Company's Prairie Island Nuclear Generating Plant (Prairie Island) was filled during refueling in June 1994, so adequate space for a subsequent refueling was no longer available. In anticipation of this, the Company, in 1989, proposed construction of a temporary onsite dry cask storage facility for used nuclear fuel at Prairie Island. The Minnesota Legislature (Legislature) considered the dry cask storage issue during its 1994 legislative session as required by a Minnesota Court of Appeals ruling in June 1993.
On May 10, 1994, the Governor of the State of Minnesota (Governor) signed into law a bill passed by the Legislature on May 6, 1994. The law authorizes the Company to install 17 dry casks at Prairie Island, which should provide storage capacity to allow operation until at least 2002 and 2003 for units 1 and 2 respectively, if the Company satisfies certain responsibilities. The Company executed an agreement with the governor concerning the renewable energy and alternative siting commitments contained in the new law and is now authorized to install the first increment of five casks. The second increment of four casks would be available if the Minnesota Environmental Quality Board finds that by Dec. 31, 1996, the Company has applied to the Nuclear Regulatory Commission for an alternative site license for the temporary used nuclear fuel storage facility, used good faith in locating an alternative site and has committed to build or purchase 100 megawatts of wind generation. The final increment of eight casks would be available unless prior to June 1, 1999, the Legislature specifically revokes the authorization for the final eight casks. The Legislature can revoke the authorization if an alternative storage site is not operational or under construction, or the Company fails to meet certain renewable energy commitments, including the increased use of wind power and biomass generation facilities by Dec. 31, 1998. (See Notes 16 and 17 of Notes to Financial Statements under Item 8 for further discussion of this matter.)
During 1994, NSP and a group of 30 other utilities and two private firms formed a consortium to establish a temporary used nuclear waste storage site. On March 9, 1995 the Mescalero Apache tribal members, in a second referendum, voted in favor of proceeding with a temporary used nuclear fuel storage site on reservation lands in New Mexico. The consortium is preparing to invest $135 million to prepare a license application, conduct environmental studies, pay host fees to the Mescalero tribe and construct a storage facility that could open in 2002.
The Company and NRG have contractual commitments to convert municipal solid waste to boiler fuel and burn the fuel to generate electricity. NRG owns and/or operates two resource recovery plants that produce RDF from the waste. The RDF is burned at the Company's Red Wing and Wilmarth plants in the Company's service area, the French Island plant in the Wisconsin Company's service area, and the Elk River plant owned by United Power Association. Processing and burning RDF provides an additional economical source of electric capacity and energy, which is beneficial to NSP's electric customers. The Company's commitment to this program enables counties to meet state- mandated goals to reduce the amount of solid waste now going to landfills. In addition, the program provides for increased materials recovery and increased use of municipal solid waste as an energy source.
NSP has met or exceeded the removal and disposal requirements for polychlorinated biphenyl (PCB) equipment as required by state and federal regulations. NSP has removed nearly all known PCB capacitors from its distribution system. NSP also has removed nearly all known network PCB transformers and equipment in power plants containing PCBs. NSP continues to test and dispose of PCB-contaminated mineral oil and equipment in accordance with regulations. PCB-contaminated mineral oil is detoxified and reused or burned for energy recovery at permitted facilities. Any future cleanup or remediation costs associated with past PCB disposal practices is unknown at this time.
Air Emissions Control And Monitoring
In September 1994, the U.S Environmental Protection Agency (EPA) proposed new air emission guidelines for municipal waste combustors. These proposed guidelines are expected to be finalized in September 1995. Once the federal guidelines are finalized, the MPUC will update Minnesota state waste combustor rules to meet or be more restrictive than the final federal guidelines. The deadline for complying with these rules is June 1997. To meet the new federal and state requirement, the Company must install additional pollution control and monitoring equipment at the Red Wing plant and additional monitoring equipment at the Wilmarth plant. The Company is evaluating equipment to meet the requirements. Equipment may cost between $6 million and $10 million.
The Clean Air Act, including the Amendments of 1990, (the "Clean Air Act") impose stringent limits on emissions of sulfur dioxide and nitrogen oxides by electric utility generating plants. These limits will be phased in beginning in 1995. The majority of the rules implementing this complex legislation are finalized. No capital expenditures are anticipated to comply with the sulfur dioxide emission limits of the Clean Air Act. Based on revisions to the sulfur dioxide portion of the program, NSP's emission allowance allocations for the years 1995-1999 were dramatically reduced from prior rulemaking. In 1994, $5 million was spent and it is expected that approximately $7 million will be spent on equipment at generation facilities to reduce emissions of nitrogen oxides for compliance with the Clean Air Act over the next 4 years. The Sherburne County Generating Plant's (Sherco) unit 2 Low Nox Burner Technology was upgraded in 1994 to further reduce its emissions of nitrogen oxides. The same upgrade is scheduled for Sherco unit 1 in 1998. Other expenditures may be necessary upon EPA's finalization of remaining rules. Capital expenditures will be required for opacity compliance in 1995-1999 at certain facilities as discussed below.
As a part of its Clean Air Act compliance effort, the Company will test a type of air quality control device called a wet electrostatic precipitator at the Sherco generating plant. The equipment will be installed in 1995 inside one of the existing acid gas scrubber modules. Testing, anticipated to be completed in 1996, will determine the equipment's operational requirements and ability to reduce particulate emissions and opacity. The equipment is being examined as one option to lower opacity from Sherco units 1 and 2, as required by the EPA. Until testing is completed, it is unknown whether the equipment will result in full compliance with air quality standards. Total costs for equipment to reduce particulate emissions and opacity range from $90 million for the equipment being tested to approximately $300 million for other technology options.
In December 1994, the Wisconsin Company completed installation of a control center monitoring system at the Bay Front generating plant in Ashland, Wisconsin. The control center which will monitor emission from the four generating units, was mandated by the Clean Air Act. The total cost of the project was approximately $1.3 million.
The Company has conducted testing for air toxics at its major facilities and shared these results with state and federal agencies. The Company also conducted research on ways to reduce mercury emissions. This information has also been shared with state and federal agencies. The Clean Air Act requires the EPA to look at issuing rules for air toxic emissions from electric utilities. A report on this is due from the EPA to Congress in 1995. There is continued interest at the Minnesota Legislature to pass legislation restricting emissions of air toxics in the state. The Company cannot predict what impact these rules will have if passed.
Water Quality Monitoring
In compliance with federal and state laws and state regulatory permit requirements, and also in conformance with the Company's corporate environmental policy, the Company has installed environmental monitoring systems at all coal and RDF ash landfills and coal stockpiles to assess and monitor the impact of these facilities on the quality of ground and surface waters. Degradation of water quality in the state is prohibited by law and requires remedial action for restoration to an agreed upon acceptable clean-up level. Estimates of the cost of implementation of overall water quality monitoring does not have a material impact on NSP's operating results.
The pending reauthorization of the Federal Clean Water Act will probably result in more stringent water quality rules, regulations and standards that will result in slightly greater operating costs for NSP facilities.
Site Remediation
Through the end of 1994, the Company had been designated by the EPA or state environmental agencies as a "potentially responsible party" (PRP) for 10 waste disposal sites to which the Company allegedly sent hazardous materials. Under applicable law, the Company, along with each PRP, could be held jointly and severally liable for the total site remediation costs. Those costs have been estimated at $122 million for all 10 PRP sites. In the event additional remediation is necessary or unexpected costs are incurred, the amount could be in excess of $122 million. The Company is not aware of the other parties inability to pay, nor does it know if responsibility for any of the sites is disputed by any party.
Settlement with the EPA, state environmental agencies and other PRPs has been reached for six of these waste disposal sites for reimbursement of the past costs and expected future costs of remedial action. By reaching early settlement, the Company avoided litigation costs, increased costs of investigation and remediation and possible penalties that could have resulted and substantially increased the Company's allocation.
For the remaining four sites, neither the amount of cleanup costs nor the final method of their allocation among all designated PRP's has been determined. However, the current estimate of the Company's share of future remediation costs for all four sites is approximately $1.0 million, which was recorded as a liability at Dec. 31, 1994.
Until final settlement, neither the amount of cleanup costs nor the final method of their allocation among all designated PRPs can be determined. While it is not feasible to determine the precise outcome of these matters, amounts accrued represent the best current estimate of the Company's future liability for the cleanup costs of these sites. It is the Company's practice to vigorously pursue and, if necessary, litigate with insurers to recover costs. Through litigation, the Company has recovered from other PRPs a portion of the remedial costs paid to date. Management also believes that costs incurred in connection with the sites, which are not recovered from insurance carriers or other parties, may be recoverable in future ratemaking.
In February 1995 a settlement was reached regarding one of the four sites for which the Company had been designated a PRP. The Company's allocation of costs approximated the liability accrued at Dec. 31, 1994.
Both the Company and the Wisconsin Company have received notices for requests for information concerning groundwater contamination at a landfill site in Wisconsin. While neither the Company nor the Wisconsin Company have been named PRP's, both companies voluntarily joined a group of other parties to address the contamination at this site. A preliminary estimate of total remediation costs at the site is approximately $6 million. The Company's and Wisconsin Company's share of this cost is currently estimated to be approximately 1%. In addition, the administrator of a group of PRP's has notified the Wisconsin Company that it might be responsible for cleanup of a solid and hazardous waste landfill site. The Wisconsin Company contends that it did not dispose of hazardous wastes in the subject landfill during the time period in question. Because neither the amount of cleanup costs nor the final method of their allocation among all designated PRP's has been determined, it is not feasible to predict the outcome of the matter at this time.
On March 2, 1995, the Wisconsin Department of Natural Resources (WDNR) notified the Wisconsin Company that it is a PRP at a creosote/coal tar contamination site in Ashland, WI. The Wisconsin Company has informed the WDNR of its belief that two sites exist. The first site, formerly a coal gas plant site, is NSP property. The second site is adjacent to the NSP site and is not owned by the Wisconsin Company. An existing condition report has been completed on an adjacent site. An estimate of site remediation costs, and the extent of the Wisconsin Company's responsibility, if any, for sharing such costs, is not known at this time. Investigations are underway to determine the Wisconsin Company's responsibility as well as that of predecessor companies contributing to the contamination on the adjacent site. The current estimate of the Wisconsin Company's share of future remediation costs at the NSP site is less than $750,000. This estimate is not based upon a formal remediation investigation and feasibility study. To the Wisconsin Company's knowledge, no study has been completed for the adjacent site, that describes remedial alternatives and clean-up cost estimates. The Wisconsin Company intends to seek rate recovery of significant costs it incurs associated with the clean-up of either Ashland Site.
On March 13, 1995, the Minnesota Pollution Control Agency (MPCA) notified the Company that it intends to seek reimbursement from the Company for costs incurred at a disposal site in Rosemount, Minnesota. The Company has commenced an investigation to determine its involvement with the site. The MPCA has sought reimbursement of $139,000 from all parties. The extent of the Company's responsibility, if any, for sharing such costs, is not known at this time.
The Company is continuing to investigate 15 properties either presently or previously owned by the Company that were, at one time, sites of gas manufacturing or storage plants, or coal gas pipelines. The purpose of this investigation is to determine if waste materials are present, if such materials constitute an environmental or health risk, if the Company has any responsibility for remedial action and if recovery under the Company's insurance policies can contribute to any remediation costs. The total cost of remediation of these sites is expected to range from $14 million to approximately $18 million, including $5.3 million which has been paid to date. The Company has commenced remediation efforts at five of the 15 sites. One of the active sites has been completed, while the remaining four are in various stages of remediation. Monitoring continues at the completed site. In addition, the Company has been notified that two other sites will require remediation, and a study will be conducted to determine the cost of clean up. No agreement or consent order has been negotiated to perform any extensive site investigations or clean-up at the other eight sites. Based upon information currently available with regard to these sites, management believes that accruals recorded represent the best current estimate of the costs of any required clean-up or remedial actions for former gas operating sites of the Company. Management believes costs incurred in connection with the sites that are not recovered from insurance carriers or other parties may be allowable costs for future ratemaking purposes. In 1994 the Company received approval of deferred accounting for certain investigation and remediation expenses. The ultimate rate treatment of any costs deferred will be determined in the Company's next general gas rate case. (See Note 17 of Notes to the Financial Statements under Item 8 for further discussion of this matter.)
NSP has not developed any specific site restoration and exit plans for its fossil fuel plants, hydroelectric plants or substation sites as it currently intends to operate at these sites indefinitely. If such plans were developed in the future, NSP would intend to treat the costs as a removal cost of retirement in utility plant and include them in depreciation accruals. Removal cost estimates used to record depreciation expense are designed to recover the future cost to remove existing plant assets. Factors used to develop these estimates include historical expenses as well as engineering estimates.
Contingencies
In October 1992, the Company disclosed to the MPCA, the EPA and the NRC that its reports on halogen content of water discharged at the Company's Prairie Island nuclear generating plant were based on estimates of halogen content rather than actual physical samples of water discharged as required by the plant's permit. Even though the water discharges at the plant did not exceed the halogen levels allowed under the permit, the applicable state and federal statutes would permit the imposition of fines, the institution of criminal sanctions, and/or injunctive relief for the reporting violations. Corrective actions were taken by the Company. The Company and the MPCA are currently negotiating a Stipulation Agreement to address monitoring procedures used at Prairie Island between January and September 1992 that allegedly did not comply with the permits. The MPCA is alleging noncompliance with permit terms and conditions and is proposing a civil penalty of $105,436.
Electric and magnetic fields (sometimes referred to as EMF) surround electric wires and conductors of electricity such as electrical tools, household wiring, appliances, electric distribution lines, electric substations and high-voltage electric transmission lines. NSP owns and operates many of these types of facilities. Some studies have found statistical associations between surrogates of EMF and some forms of cancer. The nation's electric utilities, including NSP, have participated in the sponsorship of more than $50 million in research to determine the possible health effects of EMF. Through its participation with the Electric Power Research Institute, NSP will continue its investigation and research with regard to possible health effects posed by exposure to EMF. No litigation has been commenced or claims asserted against NSP for adverse health effects related to EMF. However, several immaterial claims have been asserted against NSP for diminution of property values due to EMF. No litigation has commenced or is expected from these claims.
Both regulatory requirements and environmental technology change rapidly. Accordingly, NSP cannot presently estimate the extent to which it may be required by law, in the future, to make additional capital expenditures or to incur additional operating expenses for environmental purposes. NSP also cannot predict whether future environmental regulations might result in significant reductions in generating capacity or efficiency or otherwise affect NSP's income, operations or facilities.
CAPITAL SPENDING AND FINANCING
NSP's capital spending program is designed to assure that there will be adequate generating and distribution capacity to meet the future electric and gas needs of its utility service area, and to fund investments in non- regulated businesses. NSP continually reassesses needs and, when necessary, appropriate changes are made in the capital expenditure program.
Total NSP capital expenditures (including allowance for funds used during construction and excluding business acquisitions) totaled $409 million in 1994, compared to $362 million in 1993 and $428 million in 1992 These capital expenditures include gross additions to utility property of $387 million, $357 million (excluding Viking property acquired) and $423 million for years ended 1994, 1993 and 1992, respectively. Internally generated funds could have provided approximately 69% of all capital expenditures for 1994, 99% for 1993 and 49% for 1992.
NSP's utility capital expenditures (including allowance for funds used during construction) are estimated to be $383 million for 1995 and $1.9 billion for the five years ended Dec. 31, 1999. Included in NSP's projected utility capital expenditures is $51 million in 1995 and $267 million during the five years ended Dec. 31, 1999, for nuclear fuel for NSP's three existing nuclear units. The remaining capital expenditures through 1999 are for many utility projects, none of which are extraordinarily large relative to the total capital expenditure program. Internally generated funds from utility operations are expected to equal approximately 85% of the 1995 utility capital expenditures and approximately 95% of the 1995-1999 utility capital expenditures. Internally generated funds from all operations are expected to equal approximately 60% and 80% respectively, of the total capital expenditures anticipated for 1995 and the five-year period 1995-1999. The foregoing estimates of utility capital expenditures and internally generated funds may be subject to substantial changes due to unforeseen factors, such as changed economic conditions, competitive conditions, resource planning, new government regulations, changed tax laws and rate regulation.
In addition to capital expenditures, NSP invested $137 million in 1994 and $184 million in 1993 to acquire interests in non-regulated businesses and Viking. Investments in 1993 included business acquisitions of $159 million. (See "NRG Energy, Inc." and "Other Subsidiaries" herein.) NSP continues to evaluate opportunities to enhance its competitive position and shareholder returns through strategic acquisitions of existing businesses. Long-term financing may be required for acquisitions that NSP consummates.
Although they may vary depending on the success, timing, and level of involvement in planned and future projects, potential capital requirements for investments in existing and additional non-regulated projects are estimated to be $153 million in 1995 and $623 million for the five-year period 1995- 1999. The majority of these non-regulated capital requirements relate to equity investments (excluding costs financed by project debt) in NRG's projects, as discussed previously. The remainder consists mainly of affordable housing investments by Eloigne Company. Equity investments by NRG and Eloigne would be funded through their own internally generated funds, equity investments by NSP, or long-term debt issued by the subsidiary. Such equity investments by NSP are expected to be financed on a long-term basis through NSP's internally generated funds or through NSP's issuance of common stock.
EMPLOYEES AND EMPLOYEE BENEFITS
At year end 1994 the total number of full- and part-time employees of NSP was approximately 7,670. NSP is represented by five local IBEW labor unions. On May 2, 1994 the IBEW members voted to ratify a three year labor agreement retroactive to Jan. 1, 1994. Labor and employee benefit costs are not expected to be materially affected by the terms of the new agreement.
NSP recently reviewed employee and retiree benefits and implemented the following changes effective in 1994. These changes support NSP's goal of providing market-based benefits.
Active nonbargaining medical premium increases: A two-year cost sharing strategy for medical benefits for nonbargaining employees was implemented in 1994. The strategy consisted of employees contributing 10% in 1994 and 20% in 1995 of the total medical cost.
Retiree medical premium increases: Retiree medical premiums were increased in 1994 for existing and future retirees. For existing qualifying retirees, pension benefits have been increased to offset some of the premium increase. For future retirees, a six-year cost-sharing strategy was implemented with retirees paying 15 percent of the total cost of health care in 1994, increasing to a total of 40% in 1999.
Nonbargaining pension plan lump sum option changes: Prior to 1994, nonbargaining employees had the option to receive their pension in either a lump sum or in monthly installments. Beginning in 1994, nonbargaining employees can choose a lump sum distribution in 25% increments upon termination of employment. Employees taking less than 100 percent will receive the rest of their benefits in monthly installments. At the end of 1994, this benefit was modified to allow a lump sum option only on the portion of pension benefit earned through Dec. 31, 1994.
401(k) changes: NSP currently offers eligible employees a 401(k) Retirement Savings Plan. In 1994, NSP matched employees' pre-tax 401(k) contribution up to $500 per year for nonbargaining employees and up to $400 per year for bargaining employees. In 1994, NSP's matching contribution was $2.6 million. In 1995, NSP's annual match will increase to $700 for nonbargaining employees. Under the terms of the bargaining agreement implemented in 1994, NSP's annual match for bargaining employees will increase to $500 in 1995 and $600 in 1996.
Wage increases: No base wage scale increases were implemented in January 1994. Effective in 1994, NSP implemented a market-based pay structure for nonbargaining employees. NSP's new pay system uses salary surveys that indicate how local and regional companies pay their employees for comparable positions. In January 1995, nonbargaining employees received an average wage scale increase of 3.5%, while bargaining employees received a 2% base wage increase and 1.5% lump sum payment. As part of the new labor agreement, bargaining employees are no longer included in the Company's incentive compensation plan.
Item 2



Item 2 - Properties
The Company's major electric generating facilities consist of the following:
NSP's electric generating facilities provided 79% of its Kwh requirements in 1994. The current generating facilities are expected to be adequate base load sources of electric energy until 2004-2008, as detailed in the Company's electric resource plan filed with the MPUC in 1993. All of NSP's major generating stations are located in Minnesota on land owned by the Company.
At Dec. 31, 1994, NSP had transmission and distribution lines as follows:
Voltage Length (Pole Miles) 500Kv 265 345Kv 730 230Kv 285 161Kv 340 115Kv 1,560 Less than 115 Kv 31,530
NSP also has approximately 300 transmission and distribution substations with capacities greater than 10,000 kilovoltamperes (Kva) and approximately 270 with capacities less than 10,000 Kva.
Manitoba Hydro, Minnesota Power Company and the Company completed the construction of a 500-Kv transmission interconnection between Winnipeg, Manitoba, Canada, and the Minneapolis-St Paul, Minnesota, area in May 1980. NSP has a contract with Manitoba Hydro-Electric Board for 500 Mw of firm power utilizing this transmission line. In addition, the Company is interconnected with Manitoba Hydro through a 230 Kv transmission line completed in 1970. (Also see Note 17 of Notes to Financial Statements under Item 8.)
The gas properties of NSP include about 7,756 miles of natural gas transmission and distribution mains. NSP natural gas mains include approximately 102 miles with a capacity in excess of 275 pounds per square inch (psi) and approximately 7,654 miles with a capacity of less than 275 psi. In addition, Viking owns a 500-mile interstate natural gas pipeline serving portions of Minnesota, Wisconsin and North Dakota.
Virtually all of the utility plant of the Company and the Wisconsin Company are subject to the lien of their first mortgage bond indentures pursuant to which they have issued first mortgage bonds.
Item 3

Item 3 - Legal Proceedings
In the normal course of business, various lawsuits and claims have arisen against NSP. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters.
On July 22, 1993, a natural gas explosion occurred on the Company's distribution system in St. Paul, Minn. Total damages are estimated to exceed $1 million. The Company has a self-insured retention deductible of $1 million, with general liability coverage of $150 million, which includes coverage for all injuries and damages. While 12 lawsuits have been filed, including one proposed class action suit, the litigation following this incident is in a preliminary stage pending a report from the National Transportation Safety Board and the ultimate costs to the Company are unknown at this time.
On July 14, 1993, the Company filed a lawsuit in U.S. District Court for the District of Minnesota. The suit was filed in the interest of the Company's ratepayers against Westinghouse Electric Corp. (Westinghouse), the manufacturer of the Prairie Island steam generators, because of problems with the steam generators' susceptibility to corrosion. The Company seeks to recover the past and future costs of inspections, maintenance, modifications and repairs made to the Prairie Island steam generators and related systems as a result of Westinghouse defects. The defects are "serious" in that they have caused the Company to incur significant expenditures in order to ensure that Prairie Island is a safe and economically efficient generating station. The scheduling order requires discovery to be completed by Oct. 1, 1995. NSP and Westinghouse must be ready for trial by Feb. 1, 1996. Safety has not been, nor will be, compromised in any way as a result of the defects because the plant has been and continues to be well-maintained. The steam generator problem is less severe at Prairie Island than at most other plants with the same model steam generator. This is due to specific plant design features, including a lower reactor coolant water temperature than most of the other plants. Other reasons are due to the higher standards used at Prairie Island in such areas as water chemistry and preventative maintenance. Based on analysis done, it is the Company's best estimate that the steam generators can be maintained so replacement will not be necessary before the units' 40-year operating licenses expire.
On June 20, 1994, the Company and 13 other major utilities filed a lawsuit against the Department of Energy (DOE) in an attempt to clarify the DOE's obligation to accept spent nuclear fuel beginning in 1998. The suit was filed in the U.S. Court of Appeals, Washington, D.C. The primary purpose of the lawsuit is to insure the Company and its customers receive timely storage of used nuclear fuel.
For a discussion of other environmental proceedings, see "Environmental Matters" under Item 1, incorporated herein by reference. For a discussion of proceedings involving NSP's utility rates, see "Utility Regulation and Revenues" under Item 1, incorporated herein by reference.
Item 4

Item 4 - Submission of Matters to a Vote of Security Holders
None
PART II Item 5

Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters
Quarterly Stock Data
The Company's common stock is listed on the New York Stock Exchange (NYSE), Chicago Stock Exchange (CHX) and the Pacific Stock Exchange (PSE). Following are the reported high and low sales prices based on the NYSE Composite Transactions for the quarters of 1994 and 1993 and the dividends declared per share during those quarters:
Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters
The Company's Restated Articles of Incorporation and First Mortgage Bond Trust Indenture provide for certain restrictions on the payment of cash dividends on common stock. At Dec. 31, 1994, the payment of cash dividends on common stock was not restricted.
Item 6

Item 6 - Selected Financial Data
Item 7

Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations
Northern States Power Company, a Minnesota corporation (the Company), has two significant subsidiaries, Northern States Power Company, a Wisconsin corporation (the Wisconsin Company), and NRG Energy, Inc., a Delaware corporation (NRG). The Company also has several other subsidiaries, including Viking Gas Transmission Company (Viking) and Cenergy, Inc., (Cenergy). The Company and its subsidiaries collectively are referred to herein as NSP.
FINANCIAL RESULTS AND OBJECTIVES
1994 Financial Results
NSP's 1994 earnings per share were $3.46, an increase of 44 cents, or 14.6 percent, over the $3.02 earned in 1993. Sales growth in the core electric and gas utility businesses offset continuing unfavorable weather and higher operating costs, for a modest increase in utility earnings. In 1994, non- regulated businesses contributed a material portion of NSP's earnings for the first time, with 14.2 percent of NSP's earnings per share being derived from non-regulated operations. Most of this non-regulated earnings growth was generated from investments in energy projects in Germany and Australia. Investor returns also were enhanced in 1994 by an increase in the dividend rate, as discussed below.
NSP remained financially strong in 1994, as evidenced by continued high operating cash flows and interest coverage. NSP maintained its double A first mortgage bond ratings with all rating agencies during 1994 except Moody's Investors Services (Moody's). Moody's downgraded NSP's first mortgage bond ratings to A1 based on its interpretation of provisions of a Minnesota law enacted in 1994 regarding the Prairie Island nuclear generating plant used fuel storage project. (See discussion of this legislation in Notes 16 and 17 to the Financial Statements.)
Total Return
Dividend increases plus stock price appreciation comprise total return to NSP's investors. NSP increased its common dividend rate by more than 2 percent in 1994 and maintained a steady stock price despite a general industry decline in utility stock prices. Since the beginning of 1985, the total return on NSP's common stock has averaged 14.3 percent per year. The total return for the Standard & Poor's (S&P) composite stock index for 500 industrial companies has averaged 14.4 percent per year for the same period.
Financial Objectives
NSP's financial objectives are:
- To provide investor returns in the top one-fourth of the utility industry as measured by a three-year average return on equity. NSP's average return on equity (including the cumulative effect of the 1992 accounting change for unbilled revenues) for the three years ending in 1994 was 11.9 percent. Due largely to unusually mild weather in 1992, this return was below the three-year average of the top one-fourth of the industry (approximately 12.8 percent).
- To increase dividends on a regular basis and maintain a long-term average payout ratio in the range of 65 to 75 percent. The objective payout ratio is based on long-term earnings expectations. In June 1994, NSP's annualized common dividend rate was increased by 6 cents per share, or 2.3 percent, from $2.58 to $2.64. The dividend payout ratio was 76 percent in 1994. NSP's goal is to return to the objective range through growth in earnings.
- To maintain continued financial strength with a double A bond rating. The Company's first mortgage bonds continued to be rated AA- by S&P, AA- by Duff & Phelps, Inc., and AA by Fitch Investors Service, Inc. In 1994, Moody's downgraded NSP's first mortgage bond ratings from Aa2 to A1 based on its interpretations of a Minnesota law enacted in 1994 regarding the Prairie Island nuclear generating plant used fuel storage project. First mortgage bonds issued by the Wisconsin Company carry comparable ratings. NSP's pretax interest coverage ratio, based on income without Allowance for Funds Used During Construction (AFC), was 3.9 in 1994. A capital structure consisting of 47.5 percent common equity at year-end 1994, including both regulated and non-regulated operations, contributes to NSP's financial flexibility and strength.
- To provide 20 percent of NSP earnings from non-regulated businesses by the year 2000. NSP expects to meet this goal through growing profitability of existing non-regulated businesses and through the addition of new non-regulated businesses. Non-regulated businesses provided 14.2 percent of NSP's earnings in 1994.
- To maintain long-term average annual earnings growth of 5 percent. Non- regulated operations are expected to provide a significant portion of NSP's earnings growth in the foreseeable future. In 1994, total earnings increased 14.6 percent over 1993, with non-regulated earnings contributing most of that earnings growth.
Business Strategies
NSP's management is proactive in shaping the new business environment in which it will be operating. Management's business strategies include:
- Focusing on the core energy business. The electric utility industry is becoming more complex as customers, as well as utilities and federal and state regulators, promote competition. To remain successful in this more complex environment, NSP will maintain its focus on its core energy-related activities.
- Providing reliable, low-cost, environmentally responsible energy. Whether energy is produced through NSP's regulated utility or through its non-regulated businesses, three general concepts provide a focus for its energy businesses: reliable energy, low-cost energy and environmentally responsible energy.
- Responding to customer needs. Customers will have an increasing number of options for meeting their energy needs, and there will be competition among energy companies for the privilege of serving those customers. NSP will work with its customers to develop innovative products and services that benefit both the customer and NSP.
- Increasing non-regulated investments and earnings. As evidenced by the financial objectives for earnings growth, non-regulated businesses will be an important part of NSP's future. Deregulation in the utility industry is expected to provide new investment opportunities in non- regulated businesses. Participation in these opportunities is expected to improve the profitability of NSP.
RESULTS OF OPERATIONS AND LIQUIDITY AND CAPITAL RESOURCES
The following discussion and analysis by management focuses on those factors that had a material effect on NSP's financial condition and results of operations during 1994 and 1993. It should be read in conjunction with the accompanying Financial Statements and Notes thereto. Trends and contingencies of a material nature are discussed to the extent known and considered relevant.
RESULTS OF OPERATIONS
1994 Compared with 1993 and 1992
NSP's 1994 earnings per share were $3.46, up 44 cents from the $3.02 earned in 1993 and up $1.15 from the $2.31 earned before accounting changes in 1992. Regulated utility businesses generated earnings per share of $2.97 in 1994, $2.93 in 1993, and $2.33 (before accounting changes) in 1992. Non-regulated businesses generated earnings per share of 49 cents in 1994 and 9 cents in 1993, and a loss per share of 2 cents in 1992. The results of the regulated utility businesses and the non-regulated businesses are discussed in more detail below. In addition to the revenue and expense changes, 1994 earnings per share were impacted by a higher average number of common and equivalent shares outstanding. Common and equivalent shares increased in 1994 and 1993 due to stock issuances, including a general offering of 2.6 million shares in May 1993.
Utility Operating Results
Electric Revenues - Sales to retail customers, which account for more than 90 percent of NSP's electric revenue, increased 3.9 percent in 1994 and 4.0 percent in 1993. Cool summer weather reduced sales in 1992 and, to a lesser extent, in 1994 and 1993. During 1994, NSP added 16,549 retail electric customers, a 1.2-percent increase. Total sales of electricity decreased 0.2 percent in 1994. The decrease is due to lower sales to other utilities (as discussed later), mostly offset by increases in sales to retail customers and municipal utilities.
On a weather-adjusted basis, sales to retail customers increased an estimated 3.4 percent in 1994 and 2.1 percent in 1993. Retail sales growth for 1995 is estimated to be 3.0 percent over 1994, or 2.2 percent on a weather- adjusted basis.
Sales to other utilities decreased 21.6 percent in 1994 after increasing 30.5 percent in 1993 when there was higher demand from utilities in flood- stricken Midwestern states. The 1993 increase also reflected the impact of ice damage to transmission lines in Iowa, which limited sales in 1992.
The table below summarizes the principal reasons for the electric revenue changes during the past two years.
NSP's electric revenues are adjusted for changes in fuel and purchased energy costs from amounts currently included in approved base rates through fuel adjustment clauses in all jurisdictions, except as noted below for Wisconsin. While the lag in implementing these billing adjustments is approximately 60 days, an estimate of the adjustments is recorded in unbilled revenue in the month in which costs are incurred. In Wisconsin, the biennial retail rate review process considers changes in electric fuel and purchased energy costs in lieu of a fuel adjustment clause.
Electric Production Expenses - Fuel expense for electric generation increased $5.6 million, or 1.8 percent, in 1994 compared with an increase of $19.4 million, or 6.6 percent, in 1993. Total output from NSP's generating plants decreased 1.5 percent in 1994 and increased 8.4 percent in 1993. Fuel expenses were higher in 1994 because of the higher cost of nuclear fuel per megawatt- hour (MWH) due to increased payments to the U.S. Department of Energy (DOE) for decommissioning and decontamination of the DOE's uranium enrichment facilities and nuclear fuel disposal costs. In addition, fossil fuel costs were higher as a result of fewer purchases of coal at the lowest contractual prices due to lower fossil plant output in 1994. These increases were somewhat offset by cost decreases from lower output due to more scheduled fossil plant maintenance outages. The fuel expense increase in 1993 was due to higher output to meet sales demand, partially offset by lower cost of fuel per MWH, which reflects increased use of low-cost purchases, as discussed below.
Purchased power costs increased $41.1 million, or 19.7 percent, in 1994 and $53.0 million, or 34.1 percent, in 1993. The increase in 1994 primarily was due to additional demand expenses of $21 million for the full-year impact of capacity charges from the power purchase agreements with Manitoba Hydro- Electric Board (MH), which went into effect in May 1993, as discussed in Note 17 to the Financial Statements. In addition to demand expenses, purchased power costs increased from more energy purchases and higher prices. Energy purchases increased due to more scheduled plant maintenance outages in 1994. The market pricing of energy purchases increased in 1994 compared to more favorable market pricing in 1993. The increase in purchased power costs in 1993 over 1992 was largely due to a demand expense increase of $42 million for the capacity charges under power purchase agreements with MH. Energy purchased from other utilities increased in 1993 due to economically priced energy available to meet growing retail demand and resale opportunities to other utilities.
Gas Revenues - The majority of NSP's gas sales are categorized as firm (primarily space heating customers) and interruptible (commercial/industrial customers with an alternate energy supply). Firm sales in 1994 decreased 5.4 percent compared with 1993 sales, while firm sales in 1993 increased 17.0 percent over 1992 sales. The 1994 decrease is due largely to warm weather in the last quarter of 1994. Warm weather in the first quarter of 1992 is the main cause for the increase in 1993. NSP added 14,402 firm gas customers in 1994, a 3.7-percent increase.
On a weather-adjusted basis, firm sales are estimated to have decreased 0.7 percent in 1994 and increased 0.9 percent in 1993 (excluding a one-time unbilled revenue adjustment). Firm gas sales in 1995 are estimated to increase by 7.2 percent relative to 1994, with a 5.9-percent increase on a weather- adjusted basis. The 1995 increase includes the impact of additional revenues of approximately $6 million due to a 1994 gas expansion project in north central Minnesota, where 6,300 new customers were signed up for new service as of Dec. 31, 1994.
Interruptible sales of gas increased 4.4 percent in 1994 and 17.3 percent in 1993. Other gas deliveries, including Viking's transmission volumes, increased 73.5 percent in 1994 due to a full year of Viking activity and to sales of gas to off-system customers. Other gas deliveries increased dramatically in 1993 due to the acquisition of Viking.
The table below summarizes the principal reasons for the gas revenue changes during the past two years.
NSP's gas revenues are adjusted for changes in purchased gas costs from amounts currently included in approved base rates through purchased gas adjustment clauses in all jurisdictions.
Cost of Gas Sold - The cost of gas purchased and transported decreased $18.6 million, or 6.6 percent, in 1994. The decrease reflects lower gas prices and cost recovery adjustments, partially offset by higher sendout volumes primarily for sales of gas to off-system customers. The cost of gas associated with 1994 off-system sales was $12.7 million. In 1993, the cost of gas purchased and transported increased $61.7 million, or 28.0 percent, due to higher sendout volumes and higher purchased gas prices. The average cost per thousand cubic feet (mcf) of NSP-owned gas sold in 1994 was 8.4 percent lower than it was in 1993, when the cost was 8.7 percent higher than it was in 1992. The decrease in 1994 is due mainly to lower market pricing of gas. NSP views most of the increases in 1993 and 1992 as a recovery from unsustainably low wellhead gas prices in 1990 and 1991.
Other Operation, Maintenance and Administrative and General - These expenses, in total, increased by $26.5 million, or 4.1 percent, in 1994 compared with a decrease of $27.2 million, or 4.0 percent, in 1993. The 1994 increase is primarily due to higher postretirement health care costs, including amounts deferred from 1993, and higher postemployment costs, as discussed in Note 3 to the Financial Statements. The 1993 decrease was the result of fewer scheduled plant maintenance outages, reduced employee levels and lower administrative costs. The 1993 decrease is net of a $14 million cost increase because wages in 1992 did not include accruals for incentive compensation. (See Note 14 to the Financial Statements for a summary of administrative and general expenses.)
Conservation and Energy Management - Costs in 1994 remained comparable with 1993. Costs in 1993 were higher than in 1992 because NSP's regulators approved higher expense levels for conservation and demand-side management efforts.
Depreciation and Amortization - The increases in depreciation in 1994 and 1993 reflect higher levels of depreciable plant for all periods and changes in the depreciable lives of certain property in 1994 and 1993. (See Note 1 to the Financial Statements for discussion of depreciation changes and rate filings.)
Property and General Taxes - Property and general taxes increased in 1994 and 1993 primarily as a result of higher property tax rates and property additions. In addition, the increase in 1994 partially is due to higher gross earnings taxes, which are a result of higher sales levels.
Utility Income Taxes - The variations in income taxes primarily are attributable to fluctuations in pretax book income. Taxes in 1993 also increased about $3 million due to a 1-percent increase in the federal tax rate. (See Note 11 to the Financial Statements for a detailed reconciliation of the statutory tax rate to the effective tax rate.)
Non-operating Items Related to Utility Businesses
Allowance for Funds Used During Construction (AFC) - The differences in AFC for the reported periods are attributable to varying levels of construction work in progress and lower AFC rates associated with increased use of lower-cost, short-term borrowings to fund construction.
Other Income and Expense - Note 14 to the Financial Statements lists the components of Other Income and Deductions-Net reported on the Consolidated Statements of Income. Other than the operating revenues, expenses and income taxes of non-regulated businesses, as discussed in the next section, non- operating income and expense items related to utility businesses decreased $2.5 million in 1994 and increased $0.8 million in 1993, net of associated income taxes. The 1994 decrease primarily is due to higher expenses for environmental and regulatory contingencies and higher public and government affairs expenses associated with the Prairie Island fuel storage issue, partially offset by interest income associated with the Company's settlement of a federal income tax dispute. The increase in 1993 was due to higher investment income and lower expenses for regulatory contingencies.
Interest Charges (Before AFC) - Interest costs recognized for NSP's utility businesses, including amounts capitalized to reflect the financing costs of construction activities, were $107.8 million in 1994, $111.2 million in 1993 and $109.1 million in 1992. The decrease in 1994 reflects the impact of refinancing several higher-rate long-term debt issues in 1993 and 1994. These interest savings were partially offset by interest on higher short-term debt balances and new Viking debt (issued late in 1993). The average short-term debt balance was $204.5 million in 1994, $77.0 million in 1993 and $81.0 million in 1992. The increase in 1993 is due to amortization of refinancing costs, partially offset by interest savings from refinancing long-term debt at lower rates.
Accounting Change - Earnings in 1992 included a net-of-tax income item of $45.5 million for the cumulative effect (related to prior years) of changing the Company's revenue recognition method to begin recording estimated unbilled revenues for utility service.
Preferred Dividends - Dividends on NSP's preferred stock decreased in 1994 and 1993 primarily due to redemptions of the $7.84 Series Cumulative Preferred Stock in October 1993 and the $8.80 Series Cumulative Preferred Stock in April 1992.
Non-regulated Business Results
NSP's non-regulated operations include many diversified businesses, such as independent power production, gas marketing, industrial heating and cooling, and energy-related refuse-derived fuel (RDF) production. NSP also has investments in affordable housing projects and several income-producing properties. The following discusses NSP's diversified business results in the aggregate.
Operating Revenues and Expenses - Because non-regulated operating revenues are less than 10 percent of NSP's consolidated revenues, the net results of non- regulated businesses are reported in Other Income and Deductions-Net on the Consolidated Statements of Income. (Note 14 to the Financial Statements lists the individual components of this line item.) Non-regulated operating revenues increased $151.3 million, or 167 percent in 1994, and $28.1 million, or 45 percent in 1993, due mainly to the impact of gas marketing and industrial heating and cooling businesses acquired during 1993. Non-regulated operating expenses had corresponding increases in 1994 due to the effects of 1993 acquisitions. In addition, such expenses increased in 1994 due to fewer project development costs being capitalized on pending projects in 1994 compared with 1993, and project write-downs, as discussed below. The increase in 1993 non-regulated operating income was due to improved RDF operations, acquired businesses and 1992 project write-downs that did not recur in 1993. Non-regulated operating expenses include charges of $5.0 million in 1994 and $6.8 million in 1992 for previously capitalized development and investment costs to reflect a decrease in the expected future cash flows of certain energy projects.
Equity Income - NSP has a less-than-majority equity interest in many non- regulated projects, as discussed in Notes 4 and 5 to the Financial Statements. Consequently, a large portion of NSP's non-regulated earnings is reported as Equity in Earnings of Unconsolidated Investees on the Consolidated Statements of Income. The 1994 increase in equity income primarily is due to new energy projects NRG entered into during 1994 (as discussed in Notes 4 and 5 to the Financial Statements) and to more profitable operations of other energy projects in which NRG has been an investor for several years.
Non-operating Gain - In 1994, a cogeneration project in which NRG was a 50- percent investor received a payment from an unrelated utility company that had agreed to purchase the project cogeneration energy as compensation for terminating the energy purchase agreement. Other Income and Deductions-Net includes a pretax gain of $9.7 million for NRG's share of the termination settlement, net of project investment costs.
Interest Expense - Interest charges on the Consolidated Statements of Income include interest expense related to non-regulated businesses of $7.3 million in 1994, $2.3 million in 1993 and $0.1 million in 1992. The increases in 1994 and 1993 relate primarily to new non-utility long-term debt issued to finance the 1993 acquisitions of NRG's industrial heating and cooling business (Minneapolis Energy Center), a gas marketing business now operated by Cenergy, and 1994 investments in affordable housing projects by Eloigne Company (a wholly owned subsidiary of the Company). In addition, during 1994 and late 1993, United Power & Land and First Midwest Auto Park, wholly owned subsidiaries of the Company, issued long-term debt secured by non-regulated properties and lowered NSP's equity investment.
Income Taxes - Other Income and Deductions-Net reported on the Consolidated Statements of Income (and as shown in Note 14 to the Financial Statements) includes income tax expense (credits) related to non-regulated businesses of $6.4 million in 1994, $3.5 million in 1993 and $(0.3) million in 1992. The increase in 1994 is due mainly to higher income and gains from NRG's energy projects, as discussed above. The 1994 effective tax rate is substantially less than the U.S. federal tax rate due mainly to the tax treatment of income from NRG's international projects and to energy and low-income housing tax credits, as shown in Note 11 to the Financial Statements.
Factors Affecting Results of Operations
NSP's results of operations during 1994 and 1993 were primarily dependent on the operations of the Company's and Wisconsin Company's utility businesses consisting of the generation, transmission and sale of electricity and the distribution, transportation and sale of natural gas. NSP's utility revenues depend on customer usage, which varies with weather conditions, general business conditions, the state of the economy and the cost of energy services. Various regulatory agencies determine the prices for electric and gas service within their respective jurisdictions. In addition, NSP's non-regulated businesses are beginning to contribute significantly to NSP's earnings. The historical and future trends of NSP's operating results have been and are expected to be affected by the following factors:
Competition - The Energy Policy Act of 1992 (the Act) is a catalyst for comprehensive and significant changes in the operation of electric utilities, including increased competition. The Act's reform of the Public Utility Holding Company Act (PUHCA) promotes creation of wholesale non-utility power generators and authorizes the Federal Energy Regulatory Commission (FERC) to require utilities to provide wholesale transmission services to third parties. The legislation allows utilities and non-regulated companies to build, own and operate power plants nationally and internationally without being subject to restrictions that previously applied to utilities under the PUHCA. Management believes this legislation will promote the continued trend of increased competition in the electric energy markets.
In 1994, the FERC issued proposed rulemaking to address the rate treatment of potential "stranded investment" costs that could occur as wholesale electric markets become more competitive. The FERC is soliciting comments on options for recovery of transition costs associated with existing electric investments for which competitive market pricing might not provide recovery. NSP is evaluating the FERC proposal to determine the potential effects on operating results and customer rates and has responded to the FERC individually and through an industry group. The FERC has not reached a final decision, and the effects of the proposed rulemaking currently are not known.
NSP filed open access transmission tariffs with the FERC in March 1994. In accepting the filing, the FERC ruled NSP's tariff would be subject to the requirement that NSP offer transmission service to third parties using terms and conditions comparable to its own use of the system on behalf of NSP's traditional retail sales customers. NSP also addressed the following open access issues in its filing: timely responses to good faith transmission requests; unbundling energy services; and establishing appropriate pricing mechanisms to ensure that cost allocation prevents inter-class subsidies. In addition, the filing allows NSP and its affiliates to use market-based rates to sell capacity and energy. The FERC also announced a new transmission pricing policy statement in October 1994. The new policy introduces greater flexibility in transmission pricing structure. NSP's revenues and earnings are not expected to be materially affected by the FERC's new pricing policies for transmission services. NSP management plans to continue its efforts to be a competitively priced supplier of electricity and an active participant in the competitive market for electricity.
In response to the developing electric industry competition, Cenergy applied for and was granted permission by the FERC to market electricity (except electricity generated by NSP) in the United States, effective Dec. 1, 1994. Cenergy is one of the first affiliates of an electric utility to obtain this approval from the FERC.
Some states are considering proposals to require "retail wheeling", which is the transmission of power generated by a third party to retail customers of another utility. In 1994, NSP filed a response to a proposal by its regulator in Wisconsin outlining the transitional steps necessary to create an open and fair competitive electric market. NSP's position is that all customers should be able to choose their electric supplier by 2001, and that generation also should be deregulated by 2001. NSP proposes that utilities retain operational control of their transmission and distribution systems, and that utilities should be permitted to recover the cost of investments that were authorized under traditional regulation. Regulators in Wisconsin are currently considering what action, if any, they should take regarding electric industry competition.
During 1992 and 1993, the FERC issued a series of orders (together called Order 636) addressing interstate natural gas pipeline service restructuring. This restructuring has "unbundled" each of the services (sales, transportation, storage and ancillary services) traditionally provided by gas pipeline companies. Order 636 ended the traditional pipeline sales service function, which in the past had met local distribution companies' (LDCs) needs for reliability of supply and flexibility for meeting varying load conditions. The implementation of Order 636 has applied more pressure on all LDCs to keep gas supply and transmission pricing for large customers competitive in light of the alternatives now available to these customers. Interstate pipelines have been allowed to recover from their customers 100 percent of prudently incurred transition costs attributable to Order 636 restructuring. NSP estimates that it will be responsible for less than $12 million of transition costs over a five-year period beginning Nov. 1, 1993. To date, NSP's regulatory commissions have approved recovery of these restructuring charges in retail gas rates through the purchased gas adjustment. New service agreements went into effect between NSP and its pipeline transporters on Nov. 1, 1993. NSP does not expect these new agreements under Order 636 to materially affect its cost of gas supply. NSP's acquisitions of Viking and a gas marketing business in 1993 have enhanced its ability to participate in the more competitive gas transportation business. In implementing Order 636, Viking incurred no transition costs.
Regulation - NSP's utility rates are approved by the FERC, the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission, the Public Service Commission of Wisconsin (PSCW), the Michigan Public Service Commission and the South Dakota Public Utilities Commission. Rates are designed to recover plant investment and operating costs and an allowed return on investment, using an annual period upon which rate case filings are based. NSP requests changes in rates for utility services as needed through filings with the governing commissions. The rates charged to retail customers in Wisconsin are reviewed and adjusted biennially. Because rate changes are not requested annually in Minnesota, NSP's primary jurisdiction, changes in operating costs can affect NSP's earnings, shareholders' equity and other financial results. Except for Wisconsin electric operations, NSP's rate schedules provide for cost-of-energy adjustments to billings and revenues for changes in the cost of fuel for electric generation, purchased energy and purchased gas. For Wisconsin electric operations, the biennial retail rate review process considers changes in electric fuel and purchased energy costs in lieu of a cost-of-energy adjustment clause. In addition to changes in operating costs, other factors affecting rate filings are sales growth, conservation and demand-side management efforts and cost of capital.
Rate Changes - NSP filed for 1993 rate increases in Minnesota, North Dakota, South Dakota and Wisconsin to offset increasing costs for purchased power commitments, depreciation, property taxes, postretirement benefits and other expenses. NSP received approvals for approximately $102 million of annualized rate increases for retail customers in those states as well as for wholesale customers in Minnesota and Wisconsin. These rate changes increased revenues by approximately $83 million in 1993 and an additional $19 million in 1994.
As discussed in Note 2 to the Financial Statements, filings for rate changes in 1994 did not have a material impact on financial results. No significant general rate filings in any of NSP's utility jurisdictions are expected for 1995. However, the Company requested that the MPUC approve a new rate adjustment clause designed to accelerate recovery of 1994 and expected 1995 deferred electric conservation program costs. This adjustment clause could help reduce the need for filing a general rate increase request for recovery of increases in conservation expenditures. In February 1995, the MPUC voted to approve the new rate adjustment clause for the period May 1995 through June 1996. Thereafter, the Company would be required to request a new cost recovery level annually. The Company estimates it will receive an additional $24 million in revenues in 1995. This increased recovery will result in a corresponding increase in conservation expenses. A final order is expected in March 1995.
Legislative Changes - In May 1994, NSP received legislative authorization for dry cask fuel storage facilities at the Company's Prairie Island nuclear generating facility. As a condition of this authorization, the Legislature established several resource commitments for NSP, including wind and biomass generation sources. (See Notes 16 and 17 to the Financial Statements for more information.)
Wholesale Customers - In 1992, nine of the Company's 19 municipal wholesale electric customers notified the Company of their intent to terminate their power supply agreements with the Company, effective July 1995 or July 1996. These nine customers currently represent approximately $29 million in annual revenues and a maximum demand load of approximately 155 megawatts (MW).
In 1992 and 1993, the Company signed long-term power supply agreements with the 10 remaining municipal customers. The agreements commit the customers to purchase power from the Company for up to 13 years (through 2005) at fixed rates rising at up to 3 percent per year. The 10 customers represent approximately $10 million in current annual revenue and a maximum demand load of approximately 59 MW. The rates contained in the agreements were accepted by the FERC.
During 1993, the Company signed an electric power agreement to provide Michigan's Upper Peninsula Power Company (UPPCO) with up to 150 MW of baseload service, peaking service options and load regulation service options for 20 years from January 1998 through December 2017. Load regulation service is designed to change the level of power delivery during each hour to match UPPCO's load requirements. UPPCO has nominated 50 MW of base load and 5 MW of winter season peaking power purchases from NSP beginning Jan. 1, 1998. The annual revenue for 1998 is projected to be approximately $11 million to $14 million. The interchange agreement between UPPCO and NSP for this sale was accepted by the FERC. The Michigan Public Utilities Commission must also approve the transaction.
Environmental Matters - NSP incurs several types of environmental costs, including nuclear plant decommissioning, storage and ultimate disposal of used nuclear fuel, disposal of hazardous materials and wastes, remediation of contaminated sites and monitoring of discharges into the environment. NSP is recording costs for environmental monitoring and accruals for nuclear plant decommissioning and used nuclear fuel disposal as an ongoing operating expense and has recorded its best estimate of the full obligation for environmental remediation. Because of the continuing trend toward greater environmental awareness and increasingly stringent regulation, NSP has been experiencing a trend toward increasing environmental costs. This trend has caused and may continue to cause slightly higher operating expenses and capital expenditures. Costs charged to NSP's operating expenses for environmental monitoring and disposal of hazardous materials and wastes in 1994 were approximately $7 million and are currently expected to increase to an average annual amount of approximately $12 million for the five-year period 1995-1999. However, the precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are currently unknown. In 1994, 1993 and 1992, the Company spent about $15 million, $15 million and $20 million, respectively, for capital expenditures on environmental improvements at its utility facilities. In 1995, the Company expects to incur approximately $15 million in capital expenditures for compliance with environmental regulations. (See Notes 16 and 17 to the Financial Statements for further discussion of these and other environmental contingencies that could affect NSP.)
Weather - NSP's earnings can be dramatically affected by unusual weather. Mild weather, mainly cool summers, reduced earnings by an estimated 13 cents per share in 1994 and 18 cents per share in 1993. However, this was an improvement over 1992, when a warm winter and the coolest summer in 77 years reduced earnings by an estimated 51 cents per share.
Acquisitions - In 1994, NRG acquired ownership interests in three significant international energy projects (as discussed in Note 4 to the Financial Statements), which increased 1994 earnings by approximately 38 cents per share. NSP also made three other strategically important business acquisitions in 1993, including an interstate natural gas pipeline (Viking), an energy services marketing business (Cenergy) and a steam heating and chilled water cooling system business (Minneapolis Energy Center, now an NRG subsidiary). NSP continues to evaluate opportunities to enhance its competitive position and shareholder returns through strategic business acquisitions.
Impact of Non-regulated Investments - NSP's net income in 1994 includes after- tax earnings of $33.0 million, or 49 cents per share, from all non-regulated businesses. As discussed previously, NRG acquired equity interests in three significant energy projects in 1994. NSP expects to continue investing significant amounts in non-regulated projects, including domestic and international power production projects through NRG, as described under "Future Financing Requirements". Depending on the success and timing of involvement in these projects, NSP expects that non-regulated earnings could increase in the future to contribute at least 20 percent of NSP's earnings by the year 2000. The non-regulated projects in which NSP has invested carry a higher level of risk than NSP's traditional utility businesses. Current and future investments in non-regulated projects are subject to uncertainties prior to final legal closing, and continuing operations are subject to foreign government actions, partnership actions or both. The 1994 operating results of NSP's non-regulated businesses may not necessarily be indicative of future operating results.
Accounting Changes - Effective Jan. 1, 1994, NSP adopted three new accounting standards for postemployment benefits, fair value accounting for certain investments and employee stock ownership plan transactions. These accounting changes had an immaterial impact on earnings in 1994. (See Note 3 to the Financial Statements for more information on these accounting changes.)
As discussed in Notes 3 and 10 to the Financial Statements, in 1993 NSP changed its accounting for certain postretirement benefits and began recording such benefits on an accrual basis. NSP's utility companies had previously been allowed rate recovery for postretirement benefits as paid. In the 1993 rate increases discussed previously, NSP's utility companies obtained rate recovery for substantially all of the increased costs (approximately $20 million) accrued under Statement of Financial Accounting Standards (SFAS) No. 106 in 1993. Due to rate recovery of higher costs, there was no material impact on NSP's operating results from this accounting change.
NSP currently follows predominant industry practice in recording its environmental liabilities for plant decommissioning and site exit costs as a component of utility plant. The Financial Accounting Standards Board (FASB) is evaluating the financial presentation of these obligations and the related expense accruals, which could require reporting reclassifications as early as 1995. The effects of regulation are expected to minimize or eliminate any impact on operating expenses from potential accounting changes for decommissioning costs. (For further discussion, see Note 16 to the Financial Statements.)
Use of Derivatives - Through its subsidiaries, NSP uses derivative financial instruments to manage the risks of fluctuations in foreign currencies and natural gas prices. At Dec. 31, 1994, $93 million in notional amount (i.e. no transfer of principal) of hedge instruments were in place to hedge international investments subject to foreign currency exchange fluctuations, and $16 million in notional amount of futures contracts were in place to hedge the sale of natural gas. NSP also uses interest rate swap agreements to convert fixed rate debt to variable rate debt. At Dec. 31, 1994, NSP had $320 million in notional amount of interest rate swap agreements. (See Note 13 to the Financial Statements for further discussion of NSP's financial instruments and derivatives.)
Non-recurring Items - NSP's earnings for 1994 include several non-recurring items. Although their net effect was an earnings increase of only 1 cent per share, individually significant non-recurring items included a gain on termination of a non-regulated cogeneration contract, interest income from the settlement of a federal income tax dispute, a charge for pre-1994 postemployment costs associated with adopting SFAS No. 112, and asset impairment write-downs for certain non-regulated energy projects.
Inflation - Historically, certain operating costs, mainly labor and property taxes, have been affected by inflation. Also, inflation has tended to increase the replacement cost of operating facilities, which has increased depreciation expense when replacement facilities are constructed. However, several significant expense items have been less sensitive to inflation, including fuel costs, income taxes and interest expense. Overall, inflation at the levels currently being experienced is not expected to materially affect NSP's prices to customers or returns to shareholders.
LIQUIDITY AND CAPITAL RESOURCES
1994 Financing Requirements - NSP's need for capital funds is primarily related to the construction of plant and equipment to meet the needs of electric and gas utility customers and to fund equity commitments or other investments in non-regulated businesses. Total NSP utility capital expenditures (including AFC) were $387 million in 1994. Of that amount, $304 million related to replacements and improvements of NSP's electric system and $60 million involved construction of natural gas distribution facilities. NSP companies invested $159 million in non-regulated projects and property in 1994, mainly for equity investments in domestic and international power projects. NRG invested in joint venture projects that acquired electric generating plants in Australia and Germany, and open-cast coal mining operations in Germany. Eloigne Company invested in affordable housing projects, including wholly owned and limited partnership ventures.
1994 Financing Activity - During 1994, NSP's primary sources of capital included internally generated funds, long-term debt and short-term debt. The allocation of financing requirements between these capital options is based on the relative cost of each option, regulatory restrictions and the constraints of NSP's long-range capital structure objectives. During 1994, NSP continued to meet its long-range regulated capital structure objective of 45-50 percent common equity and 42-50 percent debt.
Funds generated internally from operating cash flows in 1994 remained sufficient to meet working capital needs, debt service, dividend payout requirements and non-regulated investment commitments, as well as fund a significant portion of construction expenditures. NSP's 1993 cash flows improved over 1992 mainly due to more favorable weather and rate increases. The pretax interest coverage ratio, excluding AFC, was 3.9 in 1994 and 3.9 in 1993. These ratios met NSP's objective range of 3.5-5.0 for interest coverage. Internally generated funds could have provided financing for 69 percent of NSP's capital expenditures for 1994 and 77 percent of the $1.9 billion in capital expenditures incurred for the five-year period 1990-1994.
The Company had approximately $238 million in short-term borrowings outstanding as of Dec. 31, 1994. Throughout 1994, short-term borrowings were used to finance utility capital expenditures and provide for other NSP cash needs.
In 1994, the Company issued $350 million of first mortgage bonds to refinance higher-cost debt issues and reduce short-term debt levels. In addition, United Power & Land issued $10 million of non-utility long-term debt to recapitalize the Company's prior equity investment in the subsidiary. Eloigne Company also issued approximately $8 million of long-term debt to finance affordable housing project investments.
The Company issued 42,567 new shares of common stock in 1994 under NSP's Executive Long-Term Incentive Award Stock Plan. At Dec. 31, 1994, the total number of common shares outstanding was 66,922,144.
NSP's equity investments in non-regulated projects during 1994 were financed through internally generated funds. Project financing requirements, in excess of equity contributions from investors, were satisfied with project debt. Project debt associated with many of NSP's non-regulated investments is not reflected in NSP's balance sheet because the equity method of accounting is used for such investments. (See Note 5 to the Financial Statements.)
Future Financing Requirements - Utility financing requirements for 1995-1999 may be affected in varying degrees by numerous factors including load growth, changes in capital expenditure levels, rate increases allowed by regulatory agencies, new legislation, market entry of competing electric power generators, changes in environmental regulations and other regulatory requirements. NSP currently estimates that its utility capital expenditures will be $383 million in 1995 and $1.9 billion for the five-year period 1995- 1999. Of the 1995 amount, $322 million is scheduled for electric facilities and $31 million for natural gas facilities. These utility capital expenditure estimates include approximately $190 million of anticipated expenditures for environmental improvements at utility facilities for the five-year period 1995-1999. In addition to utility capital expenditures, expected financing requirements for the 1995-1999 period include approximately $369 million to retire long-term debt and meet first mortgage bond sinking fund requirements.
Through its subsidiaries, NSP expects to invest significant amounts in non-regulated projects in the future. Financing requirements for non-regulated project investments may vary depending on the success, timing and level of involvement in projects currently under consideration. Potential capital requirements for NSP's non-regulated projects and property are estimated to be approximately $153 million in 1995 and approximately $623 million for the five-year period 1995-1999. These amounts include expected NRG investments through 1996 of up to $46 million for an existing German project and Eloigne Company investments of up to $23 million in 1995 and $13 million annually in 1996-1999 for affordable housing projects. Eloigne Company expects to finance approximately 65 percent of these investments in affordable housing projects with equity and approximately 35 percent with long-term debt. In addition to investments in non-regulated projects, NSP continues to evaluate opportunities to enhance shareholder returns and achieve long-term financial objectives through acquisitions of existing businesses. Long-term financing may be required for such investments.
The Company will also have future financing requirements for the portion of nuclear plant decommissioning costs not funded externally. Based on the most recent decommissioning study, these amounts are expected to be approximately $363 million, and are expected to be paid during the years 2010 to 2022.
Future Sources of Financing - NSP expects to obtain external capital for future financing requirements by periodically issuing long-term debt, common stock and preferred stock as needed to maintain desired capitalization ratios. Over the long-term, NSP's equity investments in non-regulated projects are expected to be financed through internally generated funds or NSP's issuance of common stock. Financing requirements for the non-regulated projects, in excess of equity contributions from investors, are expected to be fulfilled through project debt. Decommissioning expenses not funded by an external trust are expected to be financed through a combination of internally generated funds, long-term debt and common stock. The extent of external capital required for nuclear decommissioning costs is not known at this time.
NSP's ability to finance its utility construction program at a reasonable cost and to provide for other capital needs depends on its ability to meet investors' return expectations. Financing flexibility is enhanced by providing working capital needs and a high percentage of total capital requirements from internal sources, and having the ability to issue long-term securities and obtain short-term credit. NSP expects to maintain adequate access to securities markets in 1995. Access to securities markets at a reasonable cost is determined in a large part by credit quality. The Company's first mortgage bonds are rated AA- by Standard & Poor's Corporation, A1 by Moody's Investors Service, Inc. (Moody's), AA- by Duff & Phelps, Inc., and AA by Fitch Investors Service, Inc. Ratings for the Wisconsin Company's first mortgage bonds are generally comparable. These ratings reflect the views of such organizations, and an explanation of the significance of these ratings may be obtained from each agency. Moody's downgraded NSP's first mortgage bond ratings to A1 based on its interpretation of provisions of a Minnesota law enacted in 1994 for used nuclear fuel storage at the Prairie Island generating plant. (The other three rating agencies reaffirmed their ratings of NSP's bonds after considering the impact of the legislation on NSP.) As discussed in Notes 16 and 17 to the Financial Statements, the legislation requires NSP to increase its use of renewable energy sources such as wind and biomass power. Moody's has indicated that it believes these sources of power are considerably more costly than the power currently generated and that NSP's electric production costs will increase materially over current levels. NSP acknowledges that electric production costs may increase as a result of the Prairie Island legislation.
The Company's and the Wisconsin Company's first mortgage indentures limit the amount of first mortgage bonds that may be issued. The MPUC and the PSCW have jurisdiction over securities issuance. At Dec. 31, 1994, with an assumed interest rate of 8.5 percent, the Company could have issued about $1.9 billion of additional first mortgage bonds under its indenture, and the Wisconsin Company could have issued about $248 million of additional first mortgage bonds under its indenture.
The Company registered first mortgage bonds with the Securities and Exchange Commission (SEC) in December 1993. Depending on capital market conditions, the Company expects to issue the remaining $250 million of registered but unissued bonds over the next several years to raise additional capital or redeem outstanding securities.
The Company's Board of Directors has approved short-term borrowing levels up to 10 percent of capitalization. The Company has received regulatory approval for $350 million in short-term borrowing levels and plans to keep its credit lines at or above its average level of commercial paper borrowings. Commercial banks presently provide credit lines to the Company of approximately $299 million, which excludes $11 million of credit lines provided to subsidiaries of the Company. These credit lines make short-term financing available in the form of bank loans.
The Company's Articles of Incorporation authorize the maximum amount of preferred stock that may be issued. Under these provisions, the Company could have issued all $460 million of its remaining authorized, but unissued, preferred stock at Dec. 31, 1994, and remained in compliance with all interest and dividend coverage requirements.
The level of common stock authorized under the Company's Articles of Incorporation is 160 million shares. Registration Statements filed with the SEC provide for the sale of up to 1.6 million shares of common stock under the Company's Dividend Reinvestment and Stock Purchase Plan (DRSPP), Executive Long-Term Incentive Award Stock Plan, and Employee Stock Ownership Plan (ESOP) as of Dec. 31, 1994. The Company may issue new shares or purchase shares on the open market for its stock plans. (See Note 7 to the Financial Statements for discussion of stock awards outstanding.) The Company does not plan any general public stock offerings in 1995, but may issue new shares for its DRSPP and ESOP plans.
Internally generated funds from utility operations are expected to equal approximately 85 percent of anticipated utility capital expenditures for 1995 and approximately 95 percent of the $1.9 billion in anticipated utility capital expenditures for the five-year period 1995-1999. Internally generated funds from all operations are expected to equal approximately 60 percent and 80 percent, respectively, of the anticipated total capital expenditures for 1995 and the five-year period 1995-1999. Because of NSP's intention to reinvest foreign cash flows in non-U.S. operations, the equity income from international investments currently does not provide operating cash available for U.S. cash requirements such as payment of dividends, domestic capital expenditures and domestic debt service. NSP intends to pursue a diverse portfolio of foreign energy projects with varying levels of cash flows, income and foreign taxation to allow maximum flexibility of foreign cash flows.
Item 8


Item 8 - Financial Statements and Supplementary Data
See Item 14(a)-1 in Part IV for index of financial statements included herein.
See Note 19 of Notes to Financial Statements for summarized quarterly financial data.
INDEPENDENT AUDITORS' REPORT
To The Shareholders of Northern States Power Company:
We have audited the accompanying consolidated financial statements of Northern States Power Company (Minnesota) and its subsidiaries, listed in the accompanying table of contents in Item 14(a)1. These consolidated financial statements and financial statement schedules are the responsibility of the Companies' management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Companies at December 31, 1994 and 1993 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles.
As discussed in Note 3 to the consolidated financial statements, the Companies changed their method of accounting for postretirement health care costs in 1993.
DELOITTE & TOUCHE LLP Minneapolis, Minnesota February 8, 1995
NOTES TO FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
System of Accounts Northern States Power Company, a Minnesota corporation (the Company), and two wholly owned subsidiaries of the Company, Northern States Power Company, a Wisconsin corporation (the Wisconsin Company), and Viking Gas Transmission Company (Viking), maintain accounting records in accordance with either the uniform system of accounts prescribed by the Federal Energy Regulatory Commission (FERC) or those prescribed by state regulatory commissions, whose systems are the same in all material respects.
Principles of Consolidation - The consolidated financial statements include all material companies in which NSP holds a controlling financial interest, including: the Wisconsin Company; NRG Energy, Inc. (NRG); Viking; Cenergy, Inc. (Cenergy); and Eloigne Company. As discussed in Note 5, NSP has investments in partnerships, joint ventures and projects for which the equity method of accounting is applied. All significant intercompany transactions and balances have been eliminated in consolidation except for intercompany and intersegment profits for sales among the electric and gas utility businesses of the Company, the Wisconsin Company and Viking, which are allowed in utility rates. The Company and its subsidiaries collectively are referred to herein as NSP.
Revenues - Revenues are recognized based on products and services provided to customers each month. Because utility customer meters are read and billed on a cycle basis, unbilled revenues (and related energy costs) are estimated and recorded for services provided from the monthly meter-reading dates to month- end.
The Company's rate schedules, applicable to substantially all of its utility customers, include cost-of-energy adjustment clauses, under which rates are adjusted to reflect changes in average costs of fuels, purchased energy and gas purchased for resale. As ordered by its primary regulator, Wisconsin Company retail rate schedules include a cost-of-energy adjustment clause for purchased gas but not for electric fuel and purchased energy. The biennial retail rate review process for Wisconsin electric operations considers changes in electric fuel and purchased energy costs in lieu of a cost-of-energy adjustment.
Utility Plant and Retirements - Utility plant is stated at original cost. The cost of additions to utility plant includes contracted work, direct labor and materials, allocable overhead costs and allowance for funds used during construction. The cost of units of property retired, plus net removal cost, is charged to the accumulated provision for depreciation and amortization. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses.
Allowance for Funds Used During Construction (AFC) - AFC, a non-cash item, is computed by applying a composite pretax rate, representing the cost of capital used to finance utility construction activities, to qualified Construction Work in Progress (CWIP). AFC rates were 5.0 percent in 1994, 7.4 percent in 1993 and 8.0 percent in 1992. The amount of AFC capitalized as a construction cost in CWIP is credited to other income (for equity capital) and interest charges (for debt capital). AFC amounts capitalized in CWIP are included in rate base for establishing utility service rates. In addition to construction- related amounts, AFC is also recorded to reflect returns on capital used to finance conservation programs.
Depreciation - For financial reporting purposes, depreciation is computed by applying the straight-line method over the estimated useful lives of various property classes. The Company files with the Minnesota Public Utilities Commission (MPUC) an annual review of remaining lives for electric and gas production properties. The most recent studies, as approved by the MPUC, recommended an increase of approximately $0.5 million and a decrease of approximately $0.9 million for the 1994 and 1993 annual depreciation accruals, respectively. The remaining lives of the Company's nuclear facilities were submitted for review in 1994. The recovery period recommended for the Prairie Island plant was reduced because of the uncertainty regarding used nuclear fuel storage. (See Note 16.) The filing, as approved by the MPUC, increased depreciation by approximately $9.7 million due to the change from previously approved property lives. However, because the annual accruals for projected future decommissioning expenses decreased, the net impact to the Company from 1994 capital recovery filings is a decrease of about $800,000 in annual depreciation and decommissioning expenses, effective Jan. 1, 1994.
Every five years, the Company also must file an average service life filing for transmission, distribution and general properties. The most recent filing, as approved by the MPUC, increased 1993 depreciation by approximately $4.7 million from 1992 levels. In 1994, the Company submitted to the MPUC a depreciation study for the general plant accounts requesting a change in the depreciation calculation method. While a straight-line method is still used, the approved method change affects the level of detail at which depreciation expense is calculated. The impact to 1994 depreciation accruals from the change was a decrease of approximately $1.1 million. Depreciation provisions, as a percentage of the average balance of depreciable utility property in service, were 3.55 percent in 1994, 3.47 percent in 1993 and 3.36 percent in 1992.
Decommissioning - NSP records the cost of decommissioning the Company's nuclear generating plants through annual depreciation accruals. The provision for the estimated decommissioning costs has been calculated using an annuity approach designed to provide for full expense accrual (with full rate recovery) of the future decommissioning costs, including reclamation and removal, over the estimated operating lives of the Company's nuclear plants.
Nuclear Fuel Expense - The original cost of nuclear fuel is amortized to fuel expense based on energy expended. Nuclear fuel expense also includes assessments from the U.S. Department of Energy (DOE) for future fuel disposal and DOE facility decommissioning, as discussed in Note 16.
Environmental Costs - Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. When a single estimate of the liability cannot be determined, the low end of the estimated range is recorded. Costs are charged to expense or deferred as a regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of conditions caused by past operations, or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised, and remediation efforts proceed. For sites where NSP has been designated as one of several potentially responsible parties, the amount accrued represents NSP's estimated share of the cost. NSP intends to treat any future costs related to decommissioning and restoration of its power plants and substation sites as a removal cost of retirement through plant depreciation expense.
Income Taxes - NSP records income taxes in accordance with Statement of Financial Accounting Standards (SFAS) No. 109 - Accounting for Income Taxes. (Before 1993, NSP followed SFAS No. 96---Accounting for Income Taxes, resulting in substantially the same accounting as SFAS No. 109.) Under the liability method required by SFAS No. 109, income taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by law to be in effect when the temporary differences reverse. Due to the effects of regulation, current income tax expense is provided for the reversal of some temporary differences previously accounted for by the flow-through method. Also, regulation has created certain regulatory assets and liabilities related to income taxes, as summarized in Note 12.
Investment tax credits are deferred and amortized over the estimated lives of the related property.
Foreign Currency Translation - The local currencies are generally the functional currency of NSP's foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Income, expense and cash flows are translated at weighted-average rates of exchange for the period. The resulting currency translation adjustments are accumulated and reported as a separate component of shareholders' equity.
Exchange gains and losses that result from foreign currency transactions (e.g. converting cash distributions made in one currency to another currency) are included in the results of operations as a component of equity in earnings of unconsolidated investees. Through Dec. 31, 1994, NSP had not experienced any material translation gains or losses from foreign currency transactions that have occurred since the respective foreign investment dates.
Derivative Financial Instruments - NSP's policy is to hedge foreign currency denominated investments as they are made to preserve their U.S. dollar value. NRG has entered into currency hedging transactions through the use of forward foreign currency exchange agreements. Gains and losses on these contracts offset the effect of foreign currency exchange rate fluctuations on the valuation of the investments underlying the hedges. The effect of hedging gains and losses, net of income taxes, is reported with other currency translation adjustments as a separate component of stockholders' equity. NRG is not hedging currency translation adjustments related to operating results. NSP does not speculate in foreign currencies. A second derivative arrangement is the use of natural gas futures contracts by Cenergy to manage the risk of gas price fluctuations. The cost or benefit of natural gas futures contracts is recorded when related sales commitments are fulfilled as a component of Cenergy's non-regulated operating expenses. A third derivative instrument used by NSP is interest rate swaps that convert fixed rate debt to variable rate debt. The cost or benefit of the interest rate swap agreements is recorded as a component of interest expense.
Use of Estimates - In recording transactions and balances resulting from business operations, NSP uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, environmental loss contingencies, unbilled revenues and actuarially determined benefit costs. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. Recent changes in interest rates have resulted in changes to actuarial assumptions used in the benefit cost calculations for postretirement benefits. Also, the depreciable lives of certain plant assets are reviewed and, if appropriate, revised each year, as discussed previously. (See Notes 10 and 16 for more information on the effects of these changes in estimates.)
Cash Equivalents - NSP considers investments in certain debt instruments (primarily commercial paper) with an original maturity of three months or less at the time of purchase to be cash equivalents.
Regulatory Deferrals - As regulated utilities, the Company, the Wisconsin Company and Viking account for certain income and expense items under the provisions of SFAS No. 71---Accounting for the Effects of Regulation. In doing so, certain costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates. Likewise, certain credits that would otherwise be reflected as income are deferred as regulatory liabilities based on expected flowback to customers in future rates. Management's expected recovery of deferred costs and expected flowback of deferred credits are generally based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with ratemaking treatment established by regulators. Note 12 describes the nature and amounts of these regulatory deferrals.
Other Assets - The purchase of the Minneapolis Energy Center by an NRG subsidiary in 1993 at a price exceeding the underlying fair value of net assets acquired resulted in recorded goodwill. This goodwill and other intangible assets acquired are being amortized using the straight-line method over 30 years. NSP periodically evaluates the recovery of goodwill based on an analysis of estimated undiscounted future cash flows.
Intangible and other assets also include deferred financing costs of approximately $12.9 million at Dec. 31, 1994, which are being amortized over the remaining maturity period of the related debt.
Reclassifications - Certain reclassifications have been made to the 1993 and 1992 financial statements to conform with the 1994 presentation. These reclassifications had no effect on net income or earnings per share.
2. Rate Matters
On Aug. 9, 1994, the Company applied to the North Dakota Public Service Commission (NDPSC) for an annual electric rate reduction of $3.6 million. The reduction reflects a correction in cost allocations to the North Dakota jurisdiction. The Company also requested authority to make refunds to customers to effectively implement the reduction as of June 1, 1994. On Nov. 9, 1994, the NDPSC approved the proposed rate reduction, the liability for which has been accrued as of Dec. 31, 1994. In January 1995, the NDPSC held a hearing on the possibility of retroactive refunds for the period Jan. 1, 1989, through June 1, 1994, but has not yet reached a decision. The ultimate outcome of this proceeding is not determinable at this time.
Other rate increases filed in Wisconsin and North Dakota that were effective in 1994 increased revenues by approximately $2.6 million.
3. Accounting Changes
Postemployment Benefits - Effective Jan. 1, 1994, NSP adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 112---Employers' Accounting for Postemployment Benefits. This standard required the accrual of certain postemployment costs, such as injury compensation and severance, that are payable in the future. Initially, the Company's pre-1994 injury compensation liability was deferred in a regulatory asset based on a preliminary decision to request amortization through rates over future periods. In October 1994, another Minnesota utility was ordered by the MPUC to defer its pre-1994 SFAS No. 112 liability and amortize it to match a three- year rate recovery period. Since the Company may not file a rate case within the deferral period approved by the MPUC, which ends in 1996, the Company's pre-1994 liability of approximately $9.4 million (8 cents per share) was expensed during 1994.
Fair Value Accounting for Certain Investments - Effective Jan. 1, 1994, NSP adopted the provisions of SFAS No. 115---Accounting for Certain Investments in Debt and Equity Securities. This new standard resulted in an increase of approximately $1.4 million in decommissioning investments to present such investments at their market value at Dec. 31, 1994. This increase represents an unrealized gain on investments, which has been deferred as a regulatory liability. The Company anticipates offsetting such gains, when realized, against decommissioning costs in future ratemaking.
Accounting for Employee Stock Ownership Plans (ESOP) - Effective Jan. 1, 1994, NSP adopted the American Institute of Certified Public Accountants' Statement of Position (SOP) 93-6. This SOP changed the accounting for compensation expense associated with ESOP plans, and changed how ESOP shares were considered for earnings-per-share calculations. No additional compensation expense was recorded by NSP in 1994 due to the adoption of this SOP. The impact of the reduction in average common shares was immaterial to 1994 earnings per share (an increase in earnings per share of less than 1 cent).
Postretirement Benefits - As discussed in Note 10, NSP changed its accounting for postretirement medical and death benefits in 1993. Due to rate recovery of the expense increases, there was no material effect on net income in 1993 or 1994. Of the $20 million in 1993 cost increases over 1992 due to adoption of SFAS No. 106, about $5 million was capitalized, $12 million was deferred to be amortized over rate recovery periods in 1994-1996, and about $3 million was expensed, but essentially offset by rate increases. In 1994, administrative and general expenses increased by approximately $16 million due to the full recognition of accrued SFAS No. 106 costs, including amounts deferred from 1993.
4. Business Acquisitions
Through its subsidiaries, NRG purchased equity interests during 1994 in three significant international projects, two in Germany and one in Australia. One of the investments is a 33-percent interest in Mitteldeutsche Braunkohlengesellschaft mbh (MIBRAG), a German corporation. MIBRAG was formed by the German government to operate coal mines, electric power plants and other energy-related facilities. The other German investment is a 50-percent interest in Saale Energie GmbH (Saale), also a German corporation. Saale owns a 400-megawatt share of a 900-megawatt power plant currently under construction near Schkopau, Germany. The Australian investment is a 37.5- percent interest in a joint venture that acquired a 1,680-megawatt coal-fired power plant in Gladstone, Queensland, Australia, which is operated by an NRG subsidiary. The total acquisition investments in these three projects through 1994, including capitalized development costs, was approximately $100 million. Earnings from equity interests in NRG international projects acquired in 1994 contributed approximately 38 cents per share to NSP's 1994 earnings.
5. Investments Accounted for by the Equity Method
Through its non-regulated subsidiaries, NSP has investments in various international and domestic energy projects and domestic affordable housing and real estate projects. (Before 1994, such investments had been limited to immaterial domestic projects.) The equity method of accounting is applied to such investments because the ownership structure prevents NSP from exercising a controlling influence over operating and financial policies of the projects. A summary of NSP's significant equity-method investments is as follows:
Summarized Financial Information of Unconsolidated Investees - Summarized financial information for these projects, including interests owned by NSP and other parties, was as follows as of and for the year ended Dec. 31, 1994:
Financial Position (Millions of dollars) Results of Operations (Millions of dollars)
Current Assets $ 514.9 Operating Revenues $778.4 Other Assets 1,593.8 Operating Income $128.0 Total Assets $2,108.7 Net Income $117.0
Current Liabilities $ 159.6 Other Liabilities 1,480.0 Equity 469.1 Total Liabilities and Equity $2,108.7
6. Cumulative Preferred Stock
The Company has two series of adjustable rate preferred stock. The dividend rates are calculated quarterly and are based on prevailing rates of certain taxable government debt securities indices. At Dec. 31, 1994, the annualized dividend rates were $5.82 for series A and $5.97 for series B.
At Dec. 31, 1994, the various preferred stock series were callable at prices per share ranging from $102.00 to $103.75, plus accrued dividends. In 1993, the Company redeemed all 350,000 shares of its $7.84 series Cumulative Preferred Stock at $103.12 per share. In 1992, the Company redeemed all 250,000 shares of its $8.80 series Cumulative Preferred Stock at $103.35 per share.
7. Common Stock and Incentive Stock Plans
The Company's Articles of Incorporation and First Mortgage Indenture provide for certain restrictions on the payment of cash dividends on common stock. At Dec. 31, 1994, the Company could have paid, without restrictions, additional cash dividends of more than $1 billion on common stock.
NSP has an Executive Long-Term Incentive Award Stock Plan that permits granting non-qualified stock options. The options currently granted may be exercised one year from the date of grant and are exercisable thereafter for up to nine years. The plan also allows certain employees to receive restricted stock and other performance awards. Performance awards are valued in dollars, but are paid in shares based on the market price at the time of payment. Transactions under the various incentive stock programs, which may result in the issuance of new shares, were as follows:
Using the treasury stock method of accounting for outstanding stock options, the weighted average number of shares of common stock outstanding for the calculation of primary earnings per share includes any dilutive effects of stock options and other stock awards as common stock equivalents. The differences between shares used for primary and fully diluted earnings per share were not material.
8. Short-Term Borrowings
NSP has approximately $310 million of commercial bank credit lines under commitment fee arrangements. These credit lines make short-term financing available in the form of bank loans and support for commercial paper sales. There were approximately $3.6 million of borrowings against these credit lines, with interest payable at 9.75 percent, at Dec. 31, 1994, and no such borrowings at Dec. 31, 1993. At Dec. 31, 1994 and 1993, the Company had $234.8 million and $106.2 million, respectively, in short-term commercial paper borrowings outstanding. The weighted average interest rate on all short-term borrowings as of Dec. 31, 1994 and Dec. 31, 1993, was 6.1 percent and 3.3 percent, respectively.
9. Long-Term Debt
The annual sinking-fund requirements of the Company's and the Wisconsin Company's First Mortgage Indentures are the amounts necessary to redeem 1 percent of the highest principal amount of each series of first mortgage bonds at any time outstanding, excluding those series issued for pollution control and resource recovery financings, and excluding certain other series totaling $740 million. The Company may, and has, applied property additions in lieu of cash payments on all series, except the 9 1/8 percent Series due July 1, 2019, as permitted by its First Mortgage Indenture. The Wisconsin Company also may apply property additions in lieu of cash on all series as permitted by its First Mortgage Indenture. Except for minor exclusions, all real and personal property is subject to the liens of the first mortgage indentures.
The Company's First Mortgage Bonds Series due March 1, 2011, and the City of Becker Pollution Control Revenue Bonds Series due March 1, 2019, and Sept. 1, 2019, have variable interest rates, which currently change at various periods up to 270 days, based on prevailing rates for certain commercial paper securities or similar issues. The interest rates applicable to these issues averaged 5.9 percent, 4.1 percent and 4.1 percent, respectively, at Dec. 31, 1994. The 2011 series bonds are redeemable upon seven days notice at the option of the bondholder. The Company also is potentially liable for repayment of the 2019 Series Becker Bonds when the bonds are tendered, which occurs each time the variable interest rates change. The principal amount of all three series of these variable rate bonds outstanding represents potential short- term obligations and, therefore, is reported under current liabilities on the balance sheet.
Maturities and sinking-fund requirements on long-term debt are: 1995, $16,106,000; 1996, $18,934,000; 1997, $110,538,000; 1998, $13,541,000; and 1999, $209,888,000.
10. Benefit Plans and Other Postretirement Benefits
Pension Benefits - NSP has a non-contributory, defined benefit pension plan that covers substantially all employees. Benefits are based on a combination of years of service, the employee's highest average pay for 48 consecutive months and Social Security benefits.
The funded status of NSP's pension plan as of Dec. 31 is as follows:
For regulatory purposes, the Company's pension expense is determined and recorded under the aggregate-cost method. As required by SFAS No. 87--- Employers' Accounting for Pensions, the difference between the pension costs recorded for ratemaking purposes and the amounts determined under SFAS No. 87 are recorded as a regulatory liability on the balance sheet. Net annual periodic pension cost includes the following components:
The weighted average discount rate used in determining the actuarial present value of the projected obligation was 8 percent in 1994 and 7 percent in 1993. The rate of increase in future compensation levels used in determining the actuarial present value of the projected obligation was 5 percent in 1994 and 1993. Changes made to assumptions for the 1993 valuation decreased 1994 pension costs (determined under SFAS No. 87) by approximately $3 million. Changes made to assumptions for the 1994 valuation are expected to increase 1995 pension costs (determined under SFAS No. 87) by approximately $1 million. The assumed long-term rate of return on assets used for cost determinations under SFAS No. 87 was 8 percent for 1994, 1993 and 1992. Plan assets principally consist of common stock of public companies and U.S. government securities.
Postretirement Health Care - NSP has a contributory health and welfare benefit plan that provides health care and death benefits to substantially all employees after their retirement. The plan is intended to provide for sharing the costs of retiree health care between NSP and retirees. For employees retiring after Jan. 1, 1994, a six-year cost-sharing strategy was implemented with retirees paying 15 percent of the total cost of health care in 1994, increasing to a total of 40 percent in 1999.
Effective Jan. 1, 1993, NSP adopted the provisions of SFAS No. 106--- Employers' Accounting for Postretirement Benefits Other Than Pensions. SFAS No. 106 requires the actuarially determined obligation for postretirement health care and death benefits to be fully accrued by the date employees attain full eligibility for such benefits, which is generally when they reach retirement age. This is a significant change from NSP's pre-1993 policy of recognizing benefit costs on a cash basis after retirement. In conjunction with the adoption of SFAS No. 106, NSP elected to amortize on a straight-line basis over 20 years the unrecognized accumulated postretirement benefit obligation (APBO) of $215.6 million for current and future retirees. This obligation considered 1994 plan design changes, including Medicare integration, increased retiree cost sharing and managed indemnity measures not in effect in 1993.
Before 1993, NSP funded payments for retiree benefits internally. While NSP generally prefers to continue using internal funding of benefits paid and accrued, significant levels of external funding have been required by NSP's regulators, as discussed below, including the use of tax-advantaged trusts. Plan assets held in such trusts as of Dec. 31, 1994, consisted of investments in equity mutual funds and cash equivalents. The funded status of NSP's health care plan as of Dec. 31 is as follows:
The assumed health care cost trend rates used in measuring the APBO at Dec. 31, 1994 and 1993, respectively, were 11.0 and 14.1 percent for those under age 65, and 7.5 and 8.0 percent for those over age 65. The assumed cost trend rates are expected to decrease each year until they reach 5.5 percent for both age groups in the year 2004, after which they are assumed to remain constant. A 1-percent increase in the assumed health care cost trend rate for each year would increase the APBO by approximately 13 percent as of Dec. 31, 1994. Service and interest cost components of the net periodic postretirement cost would increase by approximately 16 percent with a similar 1-percent increase in the assumed health care cost trend rate. The assumed discount rate used in determining the APBO was 8 percent for Dec. 31, 1994, 7 percent for Dec. 31, 1993, and 8 percent for Jan. 1, 1993, compounded annually. The assumed long-term rate of return on assets used for cost determinations under SFAS No. 106 was 8 percent for 1994 and 1993. While the 1994 assumption changes had no effect on 1994 benefit costs, the effect of the changes in 1995 is expected to be a cost decrease of approximately $1.3 million. Similarly, the assumption changes made for the Dec. 31, 1993, calculations had no effect on 1993 benefit costs, but decreased 1994 costs by approximately $2 million.
In 1992, NSP recognized $12.8 million as the cost attributable to postretirement health care and death benefits based on payments made. The net annual periodic postretirement benefit cost recorded for 1994 and 1993 consists of the following components:
Regulators for NSP's retail and wholesale customers in Minnesota, Wisconsin and North Dakota have allowed full recovery of increased benefit costs under SFAS No. 106, effective in 1993. Increased 1993 accrual costs for Minnesota retail customers are being amortized over the years 1994 through 1996, consistent with approved rate recovery. External funding was required by Minnesota and Wisconsin retail regulators to the extent it is tax advantaged; funding began for Wisconsin in 1993 and must begin by the next general rate filing for Minnesota. For wholesale ratemaking, the FERC has required external funding for all benefits paid and accrued under SFAS No. 106.
ESOP - NSP has a leveraged Employee Stock Ownership Plan (ESOP) that covers substantially all employees. Employer contributions to this non-contributory, defined contribution plan are generally made to the extent NSP realizes a tax savings on its income statement from dividends paid on certain shares held by the ESOP. Contributions to the ESOP in 1994, 1993 and 1992, which represent compensation expense, were $5,695,000, $6,281,000 and $6,415,000, respectively. ESOP contributions have no material effect on NSP earnings because the contributions (net of tax) are essentially offset by the tax savings provided by the dividends paid on ESOP shares. (See Note 11.) Leveraged shares held by the ESOP are allocated to participants when dividends on stock held by the plan are used to repay ESOP loans. Of the 5.4 million shares of the Company's stock that NSP's ESOP currently holds, an average of 111,845 uncommitted leveraged ESOP shares were excluded from earnings-per- share calculations in 1994. The fair value of NSP's leveraged ESOP shares approximated cost at Dec. 31, 1994.
401(k) - NSP has a contributory, defined contribution Retirement Savings Plan (the Plan), which complies with section 401(k) of the Internal Revenue Code and covers substantially all employees. Beginning in 1994, NSP matches specified amounts of employee contributions Plan. NSP's matching contributions were $2.6 million in 1994.
11. Income Tax Expense
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate (35 percent in 1994 and 1993, and 34 percent in 1992) to net income before income tax expense. The reasons for the difference are as follows:
Income before income taxes includes foreign income of $29.7 million in 1994. NSP's management intends to reinvest the earnings of foreign operations indefinitely. Accordingly, U.S. income taxes and foreign withholding taxes have not been provided on the earnings of foreign subsidiary companies. The cumulative amount of undistributed pre-tax earnings of foreign subsidiaries upon which no U.S. income taxes or foreign withholding taxes have been provided is approximately $30.8 million at Dec. 31, 1994. The additional U.S. income tax and foreign withholding tax on the unremitted foreign earnings, if repatriated, would be offset in whole or in part by foreign tax credits. Thus, it is impracticable to estimate the amount of tax that might be payable.
The components of NSP's net deferred tax liability at Dec. 31 were:
12. Regulatory Assets and Liabilities
The following summarizes the individual components of unamortized regulatory assets and liabilities shown on the Consolidated Balance Sheets at Dec. 31:
13. Financial Instruments
The estimated Dec. 31 fair values of NSP's recorded financial instruments are as follows:
For cash, cash equivalents and short-term investments, the carrying amount approximates fair value because of the short maturity of those instruments. The fair values of the Company's long-term investments in an external nuclear decommissioning fund are estimated based on quoted market prices for those or similar investments. As discussed in Note 3, NSP adopted in 1994 SFAS No. 115, which required certain debt and equity securities to be recorded at their market value. NSP began recording decommissioning fund investments at their market value at that time. The fair value of NSP's long- term debt is estimated based on the quoted market prices for the same or similar issues, or the current rates offered to NSP for debt of the same remaining maturities.
NRG has entered into three forward foreign currency exchange contracts with a counterparty to hedge exposure to currency fluctuations to the extent permissible by hedge accounting requirements. Pursuant to these contracts, transactions have been executed that are designed to protect the economic value in U.S. dollars of NRG's equity investments, denominated in Australian dollars and German deutsche marks (DM). NRG's forward foreign currency exchange contracts, in the notional amount of $93 million, hedge approximately $94 million of foreign currency denominated investments at Dec. 31, 1994. These forward foreign currency exchange contracts are not reflected on NSP's balance sheet. The contracts do require compensating balances of $7 million, which are reflected as other current assets on NSP's balance sheet. The contracts terminate in 2004 and require foreign currency interest payments by either party during each year of the contract. If the contracts had been terminated at Dec. 31, 1994, $4.3 million would have been payable by NRG for currency exchange rate changes to date. Management believes NRG's exposure to credit risk due to non-performance by the counterparty to its forward exchange contracts is not significant, based on the investment grade rating of the counterparty.
Cenergy has entered into natural gas futures contracts in the notional amount of $16.1 million at Dec. 31, 1994. The contract terms range from one month to three years. The contracts are intended to mitigate risk from fluctuations in the price of natural gas that will be required to satisfy sales commitments for future deliveries to customers in excess of Cenergy's natural gas reserves. Cenergy's futures contracts hedge the sale of $16.6 million of natural gas. These futures contracts are not reflected on NSP's balance sheet. Margin balances of $3.4 million at Dec. 31, 1994, were maintained on deposit with brokers and recorded as cash and cash equivalents on NSP's balance sheet. The counterparties to the futures contracts are the New York Mercantile Exchange and major gas pipeline operators. Management believes that the risk of non-performance by these counterparties is not significant. If the contracts had been terminated at Dec. 31, 1994, $1.7 million would have been payable by Cenergy for natural gas price fluctuations to date.
NSP has three interest rate swap agreements with notional amounts totalling $320 million. These swaps were entered into in conjunction with first mortgage bonds. As summarized below, these agreements effectively convert the interest costs of these debt issues from fixed to variable rates based on six-month London Interbank Offered Rates (LIBOR), with the rates changing semiannually.
*Includes non-regulated energy project write-downs of $5.0 million in 1994 and $6.8 million in 1992.
15. Joint Plant Ownership
The Company is a participant in a jointly owned 855-megawatt coal-fired electric generating unit, Sherburne County generating station unit No. 3 (Sherco 3), which began commercial operation Nov. 1, 1987. Undivided interests in Sherco 3 have been financed and are owned by the Company (59 percent) and Southern Minnesota Municipal Power Agency (41 percent). The Company is the operating agent under the joint ownership agreement. The Company's share of related expenses for Sherco 3 since commercial operations began are included in Utility Operating Expenses. The Company's share of the gross cost recorded in Utility Plant at Dec. 31, 1994 and 1993, was $585,783,000 and $584,822,000, respectively. The corresponding accumulated provisions for depreciation were $132,092,000 and $114,251,000.
16. Nuclear Obligations
Fuel Disposal - NSP is responsible for the temporary storage of used nuclear fuel from the Company's nuclear generating plants. Under a contract with the Company, the DOE is obligated to assume the responsibility for permanent storage or disposal of NSP's used nuclear fuel. The Company has been funding its portion of the DOE's permanent disposal program since 1981. Funding took place through an internal sinking fund until 1983, when the DOE began assessing fuel disposal fees under the Nuclear Waste Policy Act of 1982 based on 0.1 cent per kilowatt-hour sold to customers from nuclear generation. The cumulative amount of such assessments from the DOE to NSP through Dec. 31, 1994, is $218.5 million. Currently, it is not determinable if the amount and method of the DOE's assessments to all utilities will be sufficient to fully fund the DOE's permanent storage or disposal facility.
The DOE has stated in statute and by contract that a storage or permanent disposal facility would be ready to accept used nuclear fuel by 1998. Accordingly, NSP has been, with regulatory and legislative approval, providing its own temporary on-site storage facilities at its Monticello and Prairie Island plants, with a capacity sufficient for used fuel from the plants until at least that date. However, indications from the DOE are that a permanent federal facility will not be ready to accept used fuel from utilities until approximately 2010. Accordingly, NSP is investigating all of its alternatives for used fuel storage until the DOE facility is available. When on-site temporary storage at NSP's nuclear plants reaches approved capacity, the Company could seek interim storage at a contracted private facility. The Company received Minnesota legislative approval in 1994 for additional on-site storage facilities at its Prairie Island plant, provided the Company satisfies certain responsibilities. Seventeen dry cask containers, each of which can store approximately one-half year's used fuel, can become available as follows: five immediately in 1994; four more in 1996 if an application for an alternative storage site is filed, an effort to locate such a site is made and 100 megawatts (MW) of wind generation is available or contracted for construction; and the final eight in 1999 unless the specified alternative site is not operational or under construction, certain resource commitments are not met, or the Minnesota Legislature revokes its approval. (See additional discussion of legislative commitments in Note 17.) With the dry cask storage facilities approved in 1994 for the Prairie Island nuclear generating plant, the Company believes it has adequate storage capacity to continue operation of its nuclear plants until at least 2002 and 2003 for Prairie Island Units 1 and 2, respectively, and 2008 for Monticello. Storage availability for operation beyond these dates is not assured at this time.
Fuel expense includes DOE fuel disposal assessments of $10.6 million, $8.7 million and $6.8 million for 1994, 1993 and 1992, respectively. Disposal expenses reflect reductions of $0.7 million in 1994, $2.6 million in 1993 and $3.7 million in 1992 due to a change in the DOE's basis of charging customers, retroactive to 1983. Nuclear fuel expenses in 1994 and 1993 also include about $5 million and $1 million, respectively, for payments to the DOE for the decommissioning and decontamination of the DOE's uranium enrichment facilities. The DOE's initial assessment of $46 million to the Company was recorded in 1993. This assessment will be payable in annual installments from 1993-2008 and will be expensed on a monthly basis in the 12 months following each payment. The most recent installment paid in 1994 was $3.9 million; future installments are subject to inflation adjustments under DOE rules. The FERC has approved wholesale ratemaking recovery of these assessments as paid through the cost-of-energy adjustment clause. Since the Company's retail regulators currently conform to the FERC's cost-of-energy adjustment clause procedures, the Company also expects recovery of these DOE assessments in retail ratemaking as payments are made each year.
Plant Decommissioning - Decommissioning of all Company nuclear facilities is planned for the years 2010-2022, using the prompt dismantlement method. The Company is following industry practice by ratably accruing the costs for decommissioning over the approved cost recovery period and including the accruals in Utility Plant---Accumulated Depreciation, as discussed in Note 1. The Financial Accounting Standards Board is reviewing the accounting and reporting guidelines for decommissioning cost accruals. Until such guidelines require a different presentation, the Company plans to continue reporting plant decommissioning obligations as accumulated depreciation. Consequently, the total decommissioning cost obligation and corresponding asset currently are not recorded in NSP's financial statements. In addition, the Company cannot predict whether new guidelines, if issued, would increase or decrease decommissioning expenses or if the income statement presentation of such expenses would change.
Consistent with cost recovery in utility customer rates, the Company records annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. Since the costs are expected to be paid in 2010-2022, funding presumes that current costs will escalate in the future at a rate of 4.5 percent per year. The total estimated decommissioning costs that will ultimately be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved plant recovery period. Under this approach, escalated future costs are discounted to current year dollars using the assumed rate of return on funding, which is currently 6 percent (net of tax) for external funding and approximately 8 percent (net of tax) for internal funding.
The total obligation for decommissioning is currently expected to be funded approximately 82 percent by external funds and 18 percent by internal funds, as approved by the MPUC. Rate recovery of internal funding began in 1971 through depreciation rates for removal expense, and was changed to a sinking fund recovery in 1981. Contributions to the external fund started in 1990 and are expected to continue until plant decommissioning begins. Costs not funded by external trust contributions and related earnings will be funded through internally generated funds and issuance of Company debt or stock. The assets held in trusts as of Dec. 31, 1994, primarily consisted of investments in tax-exempt municipal bonds, common stock of public companies and U.S. government securities.
The following table summarizes the funded status of the decommissioning obligation at Dec. 31, 1994:
(Millions of dollars)
Estimated future decommissioning costs (undiscounted) $1 838.1 Effect of discounting future payments 1 053.5 Present value of decommissioning obligation 784.6 External trust fund assets at fair value 145.5 Decommissioning obligation in excess of assets currently held in external trust $639.1
Decommissioning expenses recognized include the following components:
At Dec. 31, 1994, the Company has recorded and recovered in rates cumulative decommissioning accruals of $340 million; $138 million has been deposited into external trust funds for such accruals. The Company believes future decommissioning cost accruals will continue to be recovered in customer rates. Decommissioning and interest accruals are included with the accumulated provision for depreciation on the balance sheet. Interest costs and trust earnings are reported in Other Income and Expense on the income statement.
A revision to NSP's 1993 nuclear decommissioning study and nuclear plant depreciation capital recovery request was filed with the MPUC and approved in 1994. Although management expects to operate the Prairie Island units through the end of their licensed lives, the requested capital recovery would allow for the plant to be fully depreciated, including the accrual and recovery of decommissioning costs, about six years earlier than the end of its licensed life. The approved recovery period for Prairie Island has been reduced because of the uncertainty regarding used fuel storage, discussed previously. The updated nuclear decommissioning study supports a decrease in annual cost accruals for decommissioning as well as the shortened recovery period. The combined impact of the request as approved, including the shorter depreciation period and lower decommissioning costs, is a net decrease of about $800,000 in annual depreciation and decommissioning expenses. The revised cost levels approved by the MPUC were recorded in 1994.
17. Commitments and Contingent Liabilities
Legislative Resource Commitments - In 1994, the Minnesota Legislature established several energy resource and other commitments for NSP to fulfill to obtain the Prairie Island temporary nuclear fuel storage facility approval, as discussed in Note 16. The additional resource commitments, which can be built, purchased or (in the case of biomass generation) converted, can be summarized as follows:
Power Type Megawatts Deadline
Wind 100* (Additional) 12/31/96 Wind 225 (Cumulative) 12/31/98 Biomass 50 (Additional) 12/31/98 Wind 200 (Additional) 12/31/02 Biomass 75 (Additional) 12/31/02 Wind 400** (Additional) 12/31/02
* In addition to 25 MW of wind generation currently installed. ** If required by least-cost planning and resource planning.
Other commitments include applying for, locating and licensing an alternative used fuel storage site, a low-income discount for electric customers, additional required conservation improvement expenditures and various study and reporting requirements to a newly formed legislative electric energy task force. NSP has implemented programs to begin meeting these legislative commitments.
Capital Commitments - NSP estimates utility capital expenditures, including acquisitions of nuclear fuel, will be $383 million in 1995 and $1.9 billion for 1995-1999. There also are contractual commitments for the disposal of used nuclear fuel. (See Note 16.)
NRG is contractually committed to additional equity investments in an existing German energy project. Such commitments are for approximately DM 36 million in 1995 and DM 35 million in 1996. The 1995 and 1996 commitments would be approximately $23 million each year, based on exchange rates in effect at Dec. 31, 1994.
Leases - Rentals under operating leases were approximately $24.0 million, $27.5 million and $25.1 million for 1994, 1993 and 1992, respectively.
Fuel Contracts - NSP has long-term contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements. These contracts, which expire in various years between 1995 and 2013, require minimum contractual purchases and deliveries of fuel, and additional payments for the rights to purchase coal in the future. In total, NSP is committed to the minimum purchase of approximately $600 million of coal, $35 million of nuclear fuel and $377 million of natural gas, or to make payments in lieu thereof, under these contracts. In addition, NSP is required to pay additional amounts depending on actual quantities shipped under these agreements. As a result of FERC Order 636, NSP has been very active in developing a mix of gas supply contracts designed to meet its needs for retail gas sales. The contracts are with several suppliers and for various periods of time. Because NSP has other sources of fuel available, and because suppliers are expected to continue to provide reliable fuel supplies, risk of loss from non-performance under these contracts is not considered significant. In addition, NSP's risk of loss (in the form of increased costs) from market price changes in fuel is mitigated through the cost-of-energy adjustment provision of the ratemaking process, which provides for recovery of nearly all fuel costs.
Power Agreements - The Company has executed several agreements with the Manitoba Hydro-Electric Board (MH) for hydroelectricity. A summary of the agreements is as follows:
Years Megawatts
Participation Power Purchase 1995-2005 500 Seasonal Participation Power Purchase 1995-1996 250 Seasonal Peaking Power Purchase 1995-1996 200 Seasonal Diversity Exchanges: Summer exchanges from MH 1995-2014 150 1997-2016 200 Winter exchanges to MH 1995-2014 150 1996-2015 200 2015-2017 400 2018 200
The cost of the 500-megawatt participation power purchase commitment is based on 80 percent of the costs of owning and operating the Company's Sherco 3 generating plant (adjusted to 1993 dollars). The total estimated future annual capacity costs for all MH agreements range from approximately $66 million to $69 million. Negotiations are under way regarding the interpretation of specific contractual factors relating to the annual cost of the 500-megawatt participation agreement. These commitments, which represent about 21 percent of MH's output capability in 1995, account for approximately 13 percent of the Company's 1995 system capability. The risk of loss from non- performance by MH is not considered significant, and the risk of loss from market price changes is mitigated through cost-of-energy rate adjustments.
The Company and MH jointly have made commitments to provide additional transmission capacity to accomplish the seasonal diversity exchanges and to provide 200 MW of transmission capacity for United Power Association. The Company's agreements with MH call for the addition of facilities that will allow the Company's existing 500-kilovolt line from Winnipeg to the Twin Cities to accommodate the additional levels of transactions. The first two phases of construction, which provide the majority of the benefits to NSP, were completed in 1994. The final phase, which primarily benefits MH, is expected to be completed in May 1995.
The Company has an agreement with Minnkota Power Cooperative (MPC) for the purchase of summer season capacity and energy. From 1995 through 2001, the Company will buy 150 MW of summer season capacity for $12.4 million annually. From 2002 through 2015, the Company will purchase 100 MW of capacity for $10.0 million annually. Under the agreement, energy will be priced against the cost of fuel consumed per megawatt-hour at the Coyote Generating Station in North Dakota. The Company also has three seasonal (summer) purchase power agreements with MPC, Minnesota Power and Iowa-Illinois Gas and Electric Company for the purchase of 331 MW in 1995 and 388 MW in 1996, including reserves. The annual cost of this capacity will be approximately $4 million.
The Company has agreements with several non-regulated power producers to purchase electric capacity and associated energy. The total annual cost of current commitments for non-regulated installed capacity is approximately $20 million for 107 MW in 1995 and 119 MW in 1996. This annual cost will increase to approximately $37 million-$45 million for 1997-2018 and to approximately $25 million-$29 million for 2019-2027 due to a new power purchase agreement. Under this agreement, which was approved by the MPUC in February 1995, the Company will purchase an additional 245 to 262 MW of electric capacity and associated energy from 1997 through 2027.
Nuclear Insurance - The Company's public liability for claims resulting from any nuclear incident is limited to $8.9 billion under the 1988 Price-Anderson amendment to the Atomic Energy Act of 1954. The Company has secured $200 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $8.7 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. The Company is subject to assessments of $79.3 million for each of its three licensed reactors to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $10 million per reactor during any one year.
The Company purchases insurance for property damage and decontamination cleanup costs with coverage limits of $2.0 billion for each of the Company's two nuclear plant sites. The coverage consists of $500 million from American Nuclear Insurers/Mutual Atomic Energy Liability Underwriters (ANI/MAELU) and $1.5 billion from Nuclear Electric Insurance Limited (NEIL). As of Jan. 1, 1995, insurance with ANI/MAELU will change to Nuclear Mutual Limited. The coverage amounts will remain unchanged.
NEIL provides insurance coverage for the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units and coverage for property losses in excess of $500 million occurring at nuclear stations. Premiums billed to NSP from NEIL are expensed as paid each year. All companies insured with NEIL are subject to retrospective premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that the Company would have no exposure in case of a single incident under the replacement power coverage and the property damage coverage. However, in each calendar year, the Company could be subject to maximum assessments of approximately $4.6 million (five times the amount of its annual premium) and $26.1 million (7.5 times the amount of its annual premium) if losses exceed accumulated reserve funds under the replacement power and property damage coverages, respectively.
Environmental Contingencies - Other long-term liabilities include an accrual of $49 million at Dec. 31, 1994, for estimated costs associated with environmental remediation. Approximately $40 million of the liability relates to a DOE assessment for decommissioning of a federal uranium enrichment facility, as discussed in Note 16. Other estimates have been recorded for expected environmental costs associated with manufactured gas plant sites formerly used by the Company and other waste disposal sites, as discussed below.
These environmental liabilities do not include accruals recorded (and collected from customers in rates) for future nuclear fuel disposal costs or decommissioning costs related to the Company's nuclear generating plants. (See Note 16 for further discussion.)
NSP has not developed any specific site restoration and exit plans for its fossil fuel plants, hydroelectric plants or substation sites because the Company intends to operate at these sites indefinitely. If such plans were developed in the future, NSP would intend to treat restoration and exit costs as a removal cost of retirement in utility plant and include them in depreciation accruals. An estimated removal cost (based on historical experience) is currently included in depreciation expense.
NSP has met or exceeded state and federal removal and disposal requirements for polychlorinated biphenyls (PCB) equipment. NSP has removed nearly all PCB capacitors, transformers and equipment from its distribution system and power plants. Minimal costs are expected to be incurred for future removal and disposal of PCB equipment. PCB-contaminated mineral oil is detoxified and reused or burned for energy recovery at a permitted facility, with minimal cost to NSP. Other than described below, any potential future cleanup or remediation costs for past PCB disposal is unknown at this time.
The Environmental Protection Agency (EPA) or state environmental agencies have designated the Company as a "potentially responsible party" (PRP) for 10 waste disposal sites to which the Company allegedly sent hazardous materials. Under applicable law, the Company, along with each PRP, could be held jointly and severally liable for the total remediation costs of all 10 sites, which are currently estimated at $122 million. If additional remediation is necessary or unexpected costs are incurred, the amount could be in excess of $122 million. The Company is not aware of the other parties' inability to pay, nor does it know if responsibility for any of the sites is disputed by any party. The Company's share of the costs associated with these 10 sites is approximately $2.5 million. Of this amount, about $1.4 million has already been paid in connection with six of the 10 sites for which the Company has settled with the EPA and other PRPs. For the remaining four sites, neither the amount of remediation costs nor the final method of their allocation among all designated PRPs has been determined. However, the Company has recorded an estimate of approximately $1 million for future costs for all four sites, with the estimated payment dates not determinable at this time. While it is not feasible to determine the outcome of these matters, amounts accrued represent the best current estimate of the Company's future liability for the remediation costs of these sites. It is the Company's practice to vigorously pursue and, if necessary, litigate with insurers to recover incurred remediation costs whenever possible. Through litigation, the Company has recovered from other PRPs a portion of the remedial costs paid to date. Management believes costs incurred in connection with the sites, which are not recovered from insurance carriers or other parties, might be allowed recovery in future ratemaking. Until the Company is identified as a PRP, it is not possible for the Company to predict the timing or amount of any costs associated with cleanup sites other than those discussed above.
The Wisconsin Company potentially may be involved in the cleanup and remediation at three sites. One site is a solid and hazardous waste landfill site in Eau Claire, Wis. The Wisconsin Company contends that it did not dispose of hazardous wastes in the subject landfill during the time period in question. Because neither the amount of cleanup costs nor the final method of their allocation among all designated PRPs has been determined, it is not feasible to predict the outcome of this matter at this time. The second site, in Ashland, Wis., contains creosote/coal tar contamination. The Wisconsin Company is discussing its potential involvement with the Wisconsin Department of Natural Resources. Investigations are under way to determine the Wisconsin Company's responsibility as well as that of predecessor companies contributing to the contamination. The investigation should also determine the extent and source of the contamination and potential methods for remediation. An estimate of cleanup and remediation costs at these two sites and the extent of the Wisconsin Company's responsibility, if any, for sharing such costs are not known at this time. The third site is a landfill site in Hudson, Wis. which is one of the 10 waste disposal sites discussed previously.
The Company also is continuing to investigate 15 properties, either presently or previously owned by the Company, which were at one time sites of gas manufacturing, gas storage plants or gas pipelines. The purpose of this investigation is to determine if waste materials are present, if such materials constitute an environmental or health risk, if the Company has any responsibility for remedial action and if recovery under the Company's insurance policies can contribute to any remediation costs. Of the 15 gas sites under investigation, the Company already has remediated one site and is actively taking remedial action at four of the sites. In addition, the Company has been notified that two other sites eventually will require remediation, and a study will be conducted to determine the cost of cleanup. The Company has paid $5.3 million to date on these seven active sites. The one remediated site continues to be monitored. The Company currently estimates its liability for the other six active sites to be approximately $8.4 million, with payment expected over the next 11 years. The estimate is based on prior experience and includes investigation, remediation and litigation costs. The possible range of the liability for these six sites could be from $8.4 million to approximately $12 million, depending on the extent of contamination. As for the other eight inactive sites, no liability has been recorded for remediation since at this time the sites require only monitoring. While it is not feasible to determine the precise outcome of all of these matters, the accruals recorded represent the current best estimate of the costs of any required cleanup or remedial actions at these former gas operating sites. Management also believes that costs incurred in connection with the sites, which are not recovered from insurance carriers or other parties, might be allowed recovery in future ratemaking. During 1994, the Company's gas utility received approval for deferred accounting for certain gas remediation costs incurred at four active sites, with final rate treatment of such costs to be determined in the next general gas rate case.
The Clean Air Act, including the Amendments of 1990 (the Clean Air Act), imposes stringent limits on emissions of sulfur dioxide and nitrogen oxides by electric generating plants. These limits will be phased in beginning in 1995. The majority of the rules implementing this complex legislation have been finalized. No additional capital expenditures are anticipated to comply with the sulfur dioxide emission limits of the Clean Air Act. NSP has expended significant amounts over the years to reduce sulfur dioxide emissions at its plants. Based on revisions to the sulfur dioxide portion of the program, NSP's emission allowance allocations for the years 1995-1999 were dramatically reduced. The Company's capital expenditures include some costs for ensuring compliance with the Clean Air Act's other emission requirements; other expenditures may be necessary upon EPA's finalization of remaining rules. Because NSP is only beginning to implement some provisions of the Clean Air Act, its overall financial impact is unknown at this time. Capital expenditures will be required for opacity compliance commencing in 1995 at certain facilities, and such costs are considered in the capital expenditure commitments disclosed previously. NSP plans to seek recovery of these expenditures in future rate proceedings.
Several of NSP's operating facilities have asbestos-containing material, which represents a potential health hazard to people who come in contact with it. Governmental regulations specify the required timing and nature of disposal of asbestos-containing materials. Under such requirements, asbestos not readily accessible to the environment need not be removed until the facilities containing the material are demolished. NSP estimates its future asbestos removal costs will approximate $43 million. Most of these costs will not need to be incurred until current operating facilities are demolished and will be included in the costs of removal for the facilities.
Environmental liabilities are subject to considerable uncertainties that affect NSP's ability to estimate its share of the ultimate costs of remediation and pollution control efforts. Such uncertainties involve the nature and extent of site contamination, the extent of required cleanup efforts, varying costs of alternative cleanup methods and pollution control technologies, changes in environmental remediation and pollution control requirements, the potential effect of technological improvements, the number and financial strength of other potentially responsible parties at multi-party sites and the identification of new environmental cleanup sites. NSP has recorded and/or disclosed its best estimate of expected future environmental costs and obligations, as discussed previously.
Legal Claims - In the normal course of business, NSP is a party to routine claims and litigation arising from prior and current operations. NSP is actively defending these matters and has recorded an estimate of the probable cost of settlement or other disposition. In July 1993, a natural gas explosion occurred on the Company's distribution system in St. Paul, Minn. Total damages are estimated to exceed $1 million. The Company has a self-insured retention deductible of $1 million, with general liability coverage of $150 million, which includes coverage for all injuries and damages. While 12 lawsuits have been filed, including one proposed class action, the litigation following this incident is in a preliminary stage, pending a report from the National Transportation Safety Board, and the ultimate costs to the Company are unknown at this time.
18. Segment Information
19. Summarized Quarterly Financial Data (Unaudited)
* Net of expense recognized of $8.7 million ($5.1 million net of tax), or 8 cents per share, to write off the unamortized deferred costs associated with adopting SFAS No. 112 (See Note 3).
Item 9

Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
During 1994 there were no disagreements with the Company's independent public accountants on accounting procedures or accounting and financial disclosures. As discussed in the Company's Form 8-K filed Dec. 16, 1994, on Dec. 14, 1994 the Company's Board of Directors approved the appointment of the accounting firm of Price Waterhouse LLP as independent accountants for the Registrants beginning in fiscal year 1995, subject to ratification by the shareholders.
PART III Item 10.



Item 10. Directors and Executive Officers of the Registrant
(a)
CLASS III -- Nominees for Terms Expiring in 1998
H. Lyman Bretting President and Chief Executive Officer, C.G. Bretting Age 58 Manufacturing Company, Inc., Ashland, Wisconsin, a Director Since 1990 manufacturer of napkin and paper towel folding machines. Member of Finance Also director of M&I National Bank of Ashland and and Power Supply Northern States Power Company (Wisconsin), Committees a wholly-owned subsidiary of the Company.
David A. Christensen President and Chief Executive Officer, Raven Age 60 Industries, Inc., Sioux Falls, South Dakota, a Director Since 1976 manufacturer of reinforced plastics, electronic Member of Corporate equipment and sewn products. Also director of Norwest Management and Power Bank South Dakota, N.A., Norwest Corporation and Raven Supply Committees Industries, Inc.
Allen F. Jacobson Retired effective November 1, 1991 as Chairman and Age 68 Chief Executive Officer, Minnesota Mining and Director Since 1983 Manufacturing Company (3M). Also director of Abbot Member of Corporate Laboratories, Deluxe Corporation, Minnesota Mining Management and and Manufacturing Company, Mobil Corporation, Power Supply Potlatch Corporation, Prudential Insurance Company Committees of America, Sara Lee Corporation, Silicon Graphics, Inc., U.S. West, Inc., and Valmont Industries, Inc.
Margaret R. Preska Distinguished Service Professor, Minnesota State Age 57 Universities, since February 1, 1992. Prior thereto, Director Since 1980 President, Mankato State University, Mankato, Member of Corporate Minnesota, an educational institution. Also director Management and Power of Norwest Bank Minnesota South Central, N.A. Supply Committees
CLASS I -- Directors Whose Terms Expire In 1996
W. John Driscoll Retired effective June 30, 1994 as Chairman of the Age 65 Board, Rock Island Company, St. Paul, Minnesota, a Director Since 1974 private investment company, in which capacity he had Member of Audit and served since May 15, 1993. Prior thereto, President. Corporate Management Also director of Comshare Inc., The John Nuveen Committees Company, MIP Properties, Inc., The St. Paul Companies, Inc. and Weyerhaeuser Company.
Dale L. Haakenstad Retired effective December 31, 1989 as President and Age 67 Chief Executive Officer, Western States Life Insurance Director Since 1978 Company, Fargo, North Dakota. Member of Audit and Power Supply Committees
James J. Howard Chairman, President and Chief Executive Officer of the Age 59 Company since December 1, 1994. Prior thereto, Director Since 1987 Chairman of the Board and Chief Executive Officer of Ex-officio member the Company since July 1, 1990. Also director of Ecolab of all Committees Inc., Honeywell Inc., ReliaStar Financial Corp. and Walgreen Company.
John E. Pearson Retired effective January 31, 1992 as Chairman, The Age 68 NWNL Companies, Inc. and Northwestern National Life Director Since 1983 Insurance Company, a wholly-owned subsidiary of The Member of Corporate NWNL Companies, Inc. in which capacity he had served Management and since July 1, 1991. Prior thereto, Chairman and Chief Finance Committees Executive Officer, The NWNL Companies, Inc., and Northwestern National Life Insurance Company. Also director of Norwest Corporation.
G. M. Pieschel Chairman of the Board, Farmers and Merchants State Age 67 Bank, Springfield, Minnesota, a commercial bank, since Director Since 1978 January 14, 1993. Prior thereto, Chief Executive Member of Audit and Officer and President of Farmers and Merchants State Finance Committees Bank.
CLASS II -- Directors Whose Terms Expire in 1997
Richard M. Kovacevich President and Chief Executive Officer, Norwest Age 51 Corporation, Minneapolis, Minnesota, a holding company Director Since 1990 for banking institutions, since January 1, 1993. Prior Member of Finance thereto, President and Chief Operating Officer. Also Power Supply director of Fingerhut Companies, Inc., Northwestern Committees National Life Insurance Company, Norwest Corporation and ReliaStar Financial Corp.
Douglas W. Leatherdale Chairman of the Board, President and Chief Executive Age 58 Officer, The St. Paul Companies, Inc., a worldwide Director Since 1991 property and liability insurance organization, since Member of Audit and May 1, 1990. Also director of The John Nuveen Company Corporate Management and United HealthCare Corporation. Committees
A. Patricia Sampson Consultant, Dr. Sanders and Associates, a management Age 46 and diversity consulting company, since January 1, Director Since 1985 1995. Prior thereto, Chief Executive Officer, until Member of Audit and December 31, 1994 and Executive Director, until June Finance Committees 1, 1993, Greater Minneapolis Area Chapter of the American Red Cross.
Edwin M. Theisen Retired effective November 30, 1994 as President and Age 64 Chief Operating Officer of the Company. Also director Director Since 1990 of Firstar Bank of Minnesota, N.A. Member of Finance and Power Supply Committees
(b) Reference is made to "Executive Officers" as of March 1, 1995, in Part I.
(c) The information called for with respect to the identification of certain significant employees is not applicableto the registrant.
(d) There are no family relationships between the directors and executive officers listed above. There are no arrangements nor understandings between any named officer and any other person pursuant to which such person was selected as an officer.
(e) Each of the officers named in Part I was elected to serve in the office indicated until the meeting of the Board of Directors preceding the Annual Meeting of Shareholders in 1995 and until his or her successor is elected and qualified.
(f) There are no legal proceedings involving directors, nominees for directors, or officers.
Compliance with Section 16(a) of the Exchange Act
The Securities Exchange Act of 1934 requires all executive officers and directors to report any changes in the ownership of common stock of the Company to the Securities and Exchange Commission, The New York Stock Exchange and the Company.
Based solely upon a review of these report and written representations that no additional reports were required to be filed in 1994, the Company believes that all reports were filed on a timely basis.
Item 11.

Item 11. Executive Compensation
COMPENSATION OF EXECUTIVE OFFICERS
The following table sets forth cash and noncash compensation for each of the last three fiscal years ended December 31, 1994, for services in all capacities to the Company and its subsidiaries, to the Chief Executive Officer, the next four highest compensated executive officers of the Company who were serving as executives at December 31, 1994, and one former executive officer who would have been one of the four most highly compensated officers of the Company during 1994 had he not resigned from the Company before the end of the year.
SUMMARY COMPENSATION TABLE
(1) Mr. Taylor was elected President, NSP Electric on October 27, 1994 after having served as a vice president in various areas of the Company since 1989.
(2) Mr. Antony was elected President, NSP Generation effective September 7, 1994 after having served as Vice President - Nuclear Generation since January 1993. Prior thereto, Mr. Antony was not an executive officer.
(3) Mr. Theisen retired as President & Chief Operating Officer of the Company on November 30, 1994.
(4) This column consists of awards made to each named executive under the Company's Executive Incentive Plan. Due to Mr. Theisen's retirement during 1994, he additionally received the cash equivalent of the restricted stock award for 1994 in accordance with the Company's LTIP, in the amount of $126,516.
(5) This column consists of reimbursements for taxes on certain personal benefits received by the named executives.
(6) Amounts shown in this column reflect the market value of the shares of restricted stock awarded under the LTIP, except with respect to Mr. Antony's additional award (discussed below) and are based on the closing price of the Company's common stock on the date that the awards were made. Restricted shares earned for 1994 under the Company's LTIP were granted on January 25, 1995 based on the performance period ending September 30, 1994. As of December 31, 1994, the named executives held the following as a result of grants under the LTIP: Mr. Howard held 3,097 restricted shares at a market value of $136,268; Mr. McIntyre held 854 restricted shares at a market value of $37,576; Mr. Antony held 413 restricted shares at a market value of $18,172; Mr. Taylor held 454 restricted shares at a market value of $19,976, Mr. Johnson held 680 restricted shares at a market value of $29,957 and Mr. Theisen held 0 restricted shares at a market value of $0. The restricted stock awards vest one year after the date of grant with respect to fifty (50%) of the shares and two years after such date with respect to the remaining shares, conditioned upon the continued employment of the recipient with the Company. Non-preferential dividends are paid on the restricted shares.
Mr. Antony received an additional 2,200 shares of restricted stock during 1994, which as of December 31, 1994, had a market value of $96,800. These additional shares vest with respect to 50% of the shares if Mr. Antony has been continually employed by the Company on October 26, 1996 and with respect to the remainder of the shares if he has been continually employed with the Company on October 26, 1998.
The total number of restricted shares awarded during the years 1992, 1993 and 1994 are as follows: 7,191 shares for Mr. Howard, 1,910 shares for Mr. McIntyre, 2,594 shares for Mr. Antony, 982 shares for Mr. Taylor, 1,473 shares for Mr. Johnson and 3,671 for Mr. Theisen.
(7) The Company had no LTIP payouts in 1994 due to the replacement, by the Corporate Management Committee of the Company's Board of Directors, of dividend equivalent stock appreciation rights (DESARs) formerly awarded under the Company's LTIP, in favor of increased stock options and restricted stock levels.
(8) This column consists of the following: $4,031 was contributed by the Company for the Employee Stock Ownership Plan (ESOP) for Messrs. Howard and Theisen, respectively, $3,807 for Mr. McIntyre, $2,297 for Messrs. Johnson and Taylor, respectively, and $2,642 for Mr. Antony; (The Company contribution on behalf of all ESOP participants, including the named executive officers, was equal to 1.3% of their covered compensation.); the value to each named executive of the remainder of insurance premiums paid under the Officer Survivor Benefit Plan by the Company: $2,320 for Mr. Howard, $227 for Mr. McIntyre, $476 for Mr. Johnson, $0 for Mr. Taylor, $837 for Mr. Antony and $1,418 for Mr. Theisen; imputed income as a result of life insurance paid by the Company on behalf of each named executive: $2,205 for Mr. Howard, $341 for Mr. McIntyre, $399 for Mr. Johnson, $369 for Mr. Taylor, $440 for Mr. Antony and $1,826 for Mr. Theisen; Company matching 401(k) plan contribution of $500 to each named executive; and, earnings accrued under the Company Deferred Compensation Plan to the extent such earnings exceeded the market rate of interest (as prescribed pursuant to the SEC rules), which was $1,563 for Mr. McIntyre and $0 for all other named executives.
OPTIONS AND STOCK APPRECIATION RIGHTS (SARs)
The following table indicates for each of the named executives (i) the extent to which the Company used stock options and SARs for executive compensation purposes in 1994 and (ii) the potential value of such options and SARs as determined pursuant to the SEC rules.
OPTIONS AND SARS GRANTED IN 1994
(1) Options were granted on January 26, 1994 and vested on January 26, 1995. No SARs were awarded for 1994.
(2) Potential realizable values during the ten year period commencing January 26, 1994, are based on the market price ($42.187) and the outstanding shares (66,893,377) of common stock of the Company on that date.
(3) The hypothetical potential appreciation shown in columns (f) and (g) for the named executives is required by the SEC rules. The amounts in these columns do not represent either the historical or anticipated future performance of the Company's common stock level of appreciation.
The following table indicates for each of the named executives the number and value of exercisable and unexercisable options and SARs as of December 31, 1994.
AGGREGATED OPTION AND SAR EXERCISES IN 1994 AND FY-END OPTION/SAR VALUE
* Share price on December 30, 1994 was $44. Company common stock was not traded on December 31, 1994.
PENSION PLAN TABLE The following table illustrates the approximate retirement benefits payable to employees retiring at the normal retirement age of 65 years:
After an employee has reached 30 years of service, no additional years are used in determining pension benefits. The annual compensation used to calculate the average compensation shown in this table is based on the participant's base salary for the year (as shown on the Summary Compensation Table at column (c)) and bonus compensation paid in that same year (as shown on the Summary Compensation Table at column (d); see figure for prior year). The benefit amounts shown are amounts computed in the form of a straight-life annuity. The amounts are not subject to offset for social security or otherwise, except as provided in the employment agreement with Mr. Howard, as described below.
At the end of 1994, each of the executive officers named in the Summary Compensation Table had the following credited service: Mr. Howard, 7.92 years, Mr. Antony, 25.5 years, Mr. Johnson, 16.08 years, Mr. McIntyre, 21.83 years, Mr. Taylor, 21.58 years and Mr. Theisen, 30 years.
An employment agreement with Mr. Howard provides that if employment terminates prior to age 60, he will receive payments from the Company equivalent to benefits he would have earned under the Pension Plan without regard to service and compensation limitations in a minimum annual amount of $22,535. If employment continues past age 60, he and his spouse, if she survives him, will receive combined benefits from the Pension Plan and supplemental Company payments as though he had completed 30 years of service, less the pension benefits earned from a former employer.
SEVERANCE PLAN
The Company's Severance Plan covers the full-time regular-benefit, nonbargaining employees of the Company, including the named executives, and participating subsidiaries. The Severance Plan provides severance benefits to covered employees whose termination of employment is involuntary and unrelated to unsatisfactory performance. Subject to a maximum of 24 months of pay, a covered employee is eligible to receive monthly payments of two months of base pay plus the greater of two weeks of base pay for each year of service or one week of base pay for each $2,000 of base annual salary. Covered employees are also eligible to receive incentive pay, group insurance benefits and service and compensation credit under the Pension Plan for the period they receive monthly severance benefits. Outplacement services are also provided under the Plan.
DIRECTOR COMPENSATION
Directors not employed by the Company receive a $20,000 annual retainer, or a pro rata portion thereof if service is less than 12 months, and $1,200 for attendance at each Board meeting and $1,000 for each Committee meeting attended. A $2,500 annual retainer is paid to each elected Committee Chairperson. Employees of the Company receive no separate compensation for services as a director. In addition, directors have a deferred compensation and retirement plan in which they can participate. The deferred compensation plan provides for deferral of the director fees until after retirement from the Board of Directors. The retirement plan continues payment of the director's retainer, at the rate in effect for the calendar quarter immediately preceding the director's retirement multiplied by 1.2. Benefits continue for a period equal to the number of calendar quarters served on the Board, up to 40 calendar quarters.
Item 12.

Item 12. Security Ownership of Certain Beneficial Owners and Management
Security Ownership of Directors, Nominees and Named Executive Officers
Set forth in the following table is the beneficial ownership of common stock of the Company as of March 15, 1995 for all directors and each of the named executive officers of the Company as defined in the rules of the Securities and Exchange Commission. As of March 15, 1995, the directors and executive officers as a group beneficially owned 85,286 shares, less than 0.14 percent, of the Company's common stock (including shares allocated to the accounts of executive officers in the Executive Long-Term Incentive Award Stock Plan (LTIP) and the Employee Stock Ownership Plan for which they have voting power but not investment power).
H. Lyman Bretting 1,355 David A. Christensen 500 W. John Driscoll 2,000 Dale L. Haakenstad 682 James J. Howard* 25,875 Allen F. Jacobson 712 Richard M. Kovacevich 1,000 Douglas W. Leatherdale 300 John E. Pearson 1,353 G. M. Pieschel 683 Margaret R. Preska 600 A. Patricia Sampson 372 Douglas D. Antony* 6,721 Gary R. Johnson* 5,773 Edward J. McIntyre* 8,430 Loren L. Taylor* 4,893 Edwin M. Theisen* 13,098
*Shares shown for Messrs. Howard, McIntyre, Johnson, Taylor, Antony and Theisen do not include options to purchase common stock of the Company which are exercisable within 60 days under the Company's LTIP: 65,577 option shares for Mr. Howard, 21,881 option shares for Mr. McIntyre, 14,676 option shares for Mr. Johnson, 10,787 option shares for Mr. Taylor, 8,666 option shares for Mr. Antony and 34,372 option shares for Mr. Theisen.
Item 13.

Item 13. Certain Relationships and Related Transactions
Edwin M. Theisen, a director and former employee of the Company, is currently performing certain consulting services for the Company pursuant to a one-year agreement whereby he receives $15,000 per month in return for such services.
PART IV Item 14

Item 14 - Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) 1. Financial Statements Page
Included in Part II of this report:
Independent Auditors' Report. 44
Consolidated Statements of Income for the three years ended December 31, 1994. 45
Consolidated Statements of Cash Flows for the three years ended December 31, 1994. 46
Consolidated Balance Sheets, December 31, 1994 and 1993. 47
Consolidated Statements of Changes in Common Stockholders' Equity for the three years ended December 31, 1994 48
Consolidated Statements of Capitalization, December 31, 1994 and 1993. 49
Notes to Financial Statements. 51
(a) 2. Financial Statement Schedules
Schedules are omitted because of the absence of the conditions under which they are required or because the information required is included in the financial statements or the notes.
(a) 3. Exhibits
* Indicates incorporation by reference
3.01* Restated Articles of Incorporation and Amendments, effective as of April 2, 1992. (Exhibit 3.01 to Form 10-Q for the quarter ended March 31, 1992, File No. 1-3034).
3.02* Bylaws of the Company as amended January 22, 1992. (Exhibit 3.02 to Form 10-K for the year 1991, File No. 1- 3034).
4.01* Trust Indenture, dated February 1, 1937, from the Company to Harris Trust and Savings Bank, as Trustee. (Exhibit B- 7 to File No. 2-5290).
4.02* Supplemental and Restated Trust Indenture, dated May 1, 1988, from the Company to Harris Trust and Savings Bank, as Trustee. (Exhibit 4.02 to Form 10-K for the year 1988, File No. 1-3034).
Supplemental Indenture between the Company and said Trustee, supplemental to Exhibit 4.01, dated as follows:
4.03* Jun. 1, 1942 (Exhibit B-8 to File No. 2-97667).
4.04* Feb. 1, 1944 (Exhibit B-9 to File No. 2-5290).
4.05* Oct. 1, 1945 (Exhibit 7.09 to File No. 2-5924).
4.06* Jul. 1, 1948 (Exhibit 7.05 to File No. 2-7549).
4.07* Aug. 1, 1949 (Exhibit 7.06 to File No. 2-8047).
4.08* Jun. 1, 1952 (Exhibit 4.08 to File No. 2-9631).
4.09* Oct. 1, 1954 (Exhibit 4.10 to File No. 2-12216).
4.10* Sep. 1, 1956 (Exhibit 2.09 to File No. 2-13463).
4.11* Aug. 1, 1957 (Exhibit 2.10 to File No. 2-14156).
4.12* Jul. 1, 1958 (Exhibit 4.12 to File No. 2-15220).
4.13* Dec. 1, 1960 (Exhibit 2.12 to File No. 2-18355).
4.14* Aug. 1, 1961 (Exhibit 2.13 to File No. 2-20282).
4.15* Jun. 1, 1962 (Exhibit 2.14 to File No. 2-21601).
4.16* Sep. 1, 1963 (Exhibit 4.16 to File No. 2-22476).
4.17* Aug. 1, 1966 (Exhibit 2.16 to File No. 2-26338).
4.18* Jun. 1, 1967 (Exhibit 2.17 to File No. 2-27117).
4.19* Oct. 1, 1967 (Exhibit 2.01R to File No. 2-28447).
4.20* May 1, 1968 (Exhibit 2.01S to File No. 2-34250).
4.21* Oct. 1, 1969 (Exhibit 2.01T to File No. 2-36693).
4.22* Feb. 1, 1971 (Exhibit 2.01U to File No. 2-39144).
4.23* May 1, 1971 (Exhibit 2.01V to File No. 2-39815).
4.24* Feb. 1, 1972 (Exhibit 2.01W to File No. 2-42598).
4.25* Jan. 1, 1973 (Exhibit 2.01X to File No. 2-46434).
4.26* Jan. 1, 1974 (Exhibit 2.01Y to File No. 2-53235).
4.27* Sep. 1, 1974 (Exhibit 2.01Z to File No. 2-53235).
4.28* Apr. 1, 1975 (Exhibit 4.01AA to File No. 2-71259).
4.29* May 1, 1975 (Exhibit 4.01BB to File No. 2-71259).
4.30* Mar. 1, 1976 (Exhibit 4.01CC to File No. 2-71259).
4.31* Jun. 1, 1981 (Exhibit 4.01DD to File No. 2-71259).
4.32* Dec. 1, 1981 (Exhibit 4.01EE to File No. 2-83364).
4.33* May 1, 1983 (Exhibit 4.01FF to File No. 2-97667).
4.34* Dec. 1, 1983 (Exhibit 4.01GG to File No. 2-97667).
4.35* Sep. 1, 1984 (Exhibit 4.01HH to File No. 2-97667).
4.36* Dec. 1, 1984 (Exhibit 4.01II to File No. 2-97667).
4.37* May 1, 1985 (Exhibit 4.36 to Form 10-K for the year 1985, File No. 1-3034).
4.38* Sep. 1, 1985 (Exhibit 4.37 to Form 10-K for the year 1985, File No. 1-3034).
4.39* Jul. 1, 1989 (Exhibit 4.01 to Form 8-K dated July 7, 1989, File No. 1-3034).
4.40* Jun. 1, 1990 (Exhibit 4.01 to Form 8-K dated June 1, 1990, File No. 1-3034).
4.41* Oct. 1, 1992 (Exhibit 4.01 to Form 8-K dated October 13, 1992, File No. 1-3034).
4.42* April 1, 1993 (Exhibit 4.01 to Form 8-K dated March 30, 1993, File No. 1-3034).
4.43* Dec. 1, 1993 (Exhibit 4.01 to Form 8-K dated December 7, 1993, File No. 1-3034).
4.44* Feb. 1, 1994 (Exhibit 4.01 to Form 8-K dated February 10, 1994, File No. 1-3034).
4.45* Oct. 1, 1994 (Exhibit 4.01 to Form 8-K dated October 5, 1994, File No. 1-3034).
4.46* Trust Indenture, dated April 1, 1947, from the Wisconsin Company to Firstar Trust Company (formerly First Wisconsin Trust Company), as Trustee. (Exhibit 7.01 to File No. 2- 6982).
Supplemental Indentures between the Wisconsin Company and said Trustee, supplemental to Exhibit 4.45 dated as follows:
4.47* Mar. 1, 1949 (Exhibit 7.02 to File No. 2-7825).
4.48* Jun. 1, 1957 (Exhibit 2.13 to File No. 2-13463).
4.49* Aug. 1, 1964 (Exhibit 4.20 to File No. 2-23726).
4.50* Dec. 1, 1969 (Exhibit 2.03E to File No. 2-36693).
4.51* Sep. 1, 1973 (Exhibit 2.01F to File No. 2-48805).
4.52* Feb. 1, 1982 (Exhibit 4.01G to File No. 2-76146).
4.53* Mar. 1, 1982 (Exhibit 4.39 to Form 10-K for the year 1982, File No. 10-3140).
4.54* Jun. 1, 1986 (Exhibit 4.01I to File No. 33-6269).
4.55* Mar. 1, 1988 (Exhibit 4.01J to File No. 33-20415).
4.56* Supplemental and Restated Trust Indenture dated March 1, 1991, from the Wisconsin Company to Firstar Trust Company (formerly First Wisconsin Trust Company), as Trustee. (Exhibit 4.01K to File No. 33-39831)
4.57* Apr. 1, 1991 (Exhibit 4.01L to File No. 33-39831).
4.58* Mar. 1, 1993 (Exhibit 4.01 to Form 8-K dated March 4, 1993, File No. 10-3140).
4.59* Oct. 1, 1993 (Exhibit 4.01 to Form 8-K dated September 21, 1993, File No. 10-3140).
4.60 NSP Employee Stock Ownership Plan.
10.01 Mid-continent Area Power Pool (MAPP) Agreement, dated March 31, 1972, with amendments in 1994, between the local power suppliers in the North Central States area.
10.02* Facilities agreement, dated July 21, 1976, between the Company and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 Kv Line. (Exhibit 5.06I to file No. 2-54310).
10.03* Transactions agreement, dated July 21, 1976, between the Company and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 Kv Line. (Exhibit 5.06J to File No. 2-54310).
10.04* Co-ordinating agreement, dated July 21, 1976, between the Company and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 Kv Line. (Exhibit 5.06K to File No. 2-54310).
10.05* Ownership and Operating Agreement, dated March 11, 1982, between the Company, Southern Minnesota Municipal Power Agency and United Minnesota Municipal Power Agency concerning Sherburne County Generating Unit No. 3. (Exhibit 10.01 to Form 10-Q for the Quarter Ended September 30, 1994, File No. 1-3034).
10.06* Transmission agreement, dated April 27, 1982, and Supplement No. 1, dated July 20, 1982, between the Company and Southern Minnesota Municipal Power Agency. (Exhibit 10.02 to Form 10-Q for the Quarter Ended September 30, 1994, File No. 1-3034).
10.07* Power agreement, dated June 14, 1984, between the Company and the Manitoba Hydro-Electric Board, extending the agreement scheduled to terminate on April 30, 1993, to April 30, 2005. (Exhibit 10.03 to Form 10-Q for the Quarter Ended September 30, 1994, File No. 1-3034).
10.08* Power Agreement, dated August 1988, between the Company and Minnkota Power Company. (Exhibit 10.08 to Form 10-K for the Year 1988, File No. 1-3034).
10.09* Energy Supply Agreement, dated October 26, 1993, between the Company and Liberty Paper, Inc., relating to the supply of steam and electricity to the LPI container-board facility in Becker, MN. (Exhibit 10.09 to Form 10-K for the Year 1993, File No. 1-3034).
Executive Compensation Arrangements and Benefit Plans Covering Executive Officers
10.10* Executive Long-Term Incentive Award Stock Plan. (Exhibit 10.10 to Form 10-K for 1988, File No. 1-3034).
10.11* Terms and Conditions of Employment - James J Howard, President and Chief Executive Officer, effective February 1, 1987. (Exhibit 10.11 to Form 10-K for the Year 1986, File No. 1-3034).
10.12 NSP Severance Plan.
10.13* NSP Deferred Compensation Plan amended effective January 1, 1993. (Exhibit 10.16 to Form 10-K for the Year 1993, File No. 1-3034).
10.14* Annual Executive Incentive Plan for 1994 (Exhibit 10.01 to Form 10-Q for the Quarter Ended March 31, 1994, File No. 1-3034).
12.01 Statement of Computation of Ratio of Earnings to Fixed Charges.
16.01* Independent Auditors' Letter re: Change in Certifying Accountant (Exhibit 16.01 to Form 8-K dated December 13, 1994, File No. 1-3034).
18.01* Independent Auditors' Preferability Letter. (Exhibit 18.01 to Form 10-Q for the quarter ended March 31, 1992, File No. 1-3034).
21.01 Subsidiaries of the Registrant.
23.01 Independent Auditors' Consent.
27.01 Financial Data Schedule
(b) Reports on Form 8-K. The following reports on Form 8-K were filed either during the three months ended December 31, 1994, or between December 31, 1994 and the date of this report:
October 4, 1994 (Filed October 4, 1994) - Item 5. Other Events. Re: Disclosure of an agreement by a joint venture between one of the Company's non-regulated subsidiaries and Cogentrix, Inc., had agreed to terminate a contract for power sales from a cogeneration project in Michigan. Disclosure negotiations by the Company and the Minnesota Pollution Control Agency (MPCA) of a Stipulation Agreement to address monitoring procedures used at the Company's Prairie Island Generating Plant between January and September of 1992 that allegedly did not comply with National Pollution Discharge System permits, limiting the halogen content of water discharges at the Plant.
October 5, 1994 (Filed October 7, 1994) - Item 5. Other Events. Re: Disclosure of Underwriting Agreement and filing of a prospectus supplement relating to $150,000,000 First Mortgage Bonds, Series due October 1, 2001. Item 7. - Financial Statements and Exhibits. Filing of Underwriting Agreement between the Company and various underwriters, Supplemental Trust Indenture between the Company and Harris Trust and Savings Bank as Trustee, creating First Mortgage Bonds, Series due October 1, 2001 and the computation of ratio of earnings to fixed charges.
December 13, 1994 (Filed December 16, 1994) - Item 4. Change in Registrant's Certifying Accountant. Re: Disclosure of the Company's change in independent accountants for 1995. Deloitte & Touche LLP was informed that the firm would no longer be engaged as independent accountants for the Registrant and its subsidiaries after the completion of audit work for the fiscal year ended December 31, 1994. The Company's Board of Directors approved the appointment of the accounting firm of Price Waterhouse LLP as independent accountants for the Registrant for 1995, subject to ratification by the shareholders. Item 7. - Financial Statements and Exhibits. Exhibit No. 16 - Letter from Deloitte & Touche LLP.
January 30, 1995 (Filed February 2, 1995) - Item 5. Other Events. Disclosure of the Company receiving a notice of violation from the United States Nuclear Regulatory Commission (NRC), regarding the inspection of the quality assurance programs at the Company and PX Engineering Company, Inc., a subcontractor responsible for the fabrication and assembly of certain components for the TN-40 spent fuel storage containers which will be used at the Prairie Island Nuclear Generating Plant. Disclosure of the Mescalero Apache Tribe vote against participation in a joint Mescalero-Utility Spent Nuclear Fuel Storage Initiative.
February 28, 1995 (Filed March 2, 1995) - Item 5. Other Events. Disclosure of a basic agreement between San Joaquin Valley Energy Partners (SJVEP) and Pacific Gas & Electric Company (PG&E) regarding the acquisition of existing Standard Offer 4 (SO4) contracts by PG&E from SJVEP. The parties entered into a bridging agreement to cover the period until all approvals are received for the transaction. NRG Energy, Inc., a wholly owned subsidiary of the Company, has a 45 percent interest in SJVEP, through wholly owned subsidiaries.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.
NORTHERN STATES POWER COMPANY
March 24, 1995 (E J McIntyre) E J McIntyre Vice President and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
(James J Howard) (E J McIntyre) James J Howard E J McIntyre Chairman of the Board and Director Vice President (Principal Executive Officer) (Principal Financial Officer)
(Roger D Sandeen) (H Lyman Bretting) Roger D Sandeen H Lyman Bretting Vice President & Controller Director (Principal Accounting Officer)
(David A Christensen) (W John Driscoll) David A Christensen W John Driscoll Director Director
(Dale L Haakenstad) (Allen F Jacobson) Dale L Haakenstad Allen F Jacobson Director Director
(Douglas W Leatherdale) (John E Pearson) Douglas W Leatherdale John E Pearson Director Director
(G M Pieschel) (Margaret R Preska) G M Pieschel Margaret R Preska Director Director
(A Patricia Sampson) (Edwin M Theisen) A Patricia Sampson Edwin M Theisen Director Director
EXHIBIT INDEX
Method of Exhibit Filing No. Description
DT 4.60 NSP Employee Stock Ownership Plan
DT 10.01 Mid-continent Area Power Pool Agreement
DT 10.12 NSP Severance Plan
DT 12.01 Statement of Computation of Ratio of Earnings to Fixed Charges
DT 21.01 Subsidiaries of the Registrant
DT 23.01 Independent Auditor's Consent
DT 27.01 Financial Data Schedule