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 one significant subsidiary, Northern States Power Company, a Wisconsin Corporation (the Wisconsin Company) and several other subsidiaries, including NRG Energy, Inc. (NRG), and Viking Gas Transmission Company (Viking), both Delaware corporations. NRG manages several of the Company's non-regulated energy subsidiaries. Viking is a regulated utility that operates a 500-mile interstate natural gas pipeline. (See "NRG Energy, Inc." and "Other Subsidiaries" herein for further discussion of these two 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 133 communities within this area. The Company formerly supplied telephone service in the Minot, North Dakota, area. The telephone operation was sold on Jan. 31, 1991. (See "Telephone Operations" herein.) For business segment information, see Note 16 of Notes to Financial Statements under Item 8.
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 is concentrated in the Minneapolis-St. Paul metropolitan area. In 1993, about 62% of NSP's electric retail revenue was derived from sales in the Minneapolis-St. Paul metropolitan area and about 57% of retail gas revenue came from sales in the St. Paul area.
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 costs to operate and construct facilities, uncertainties in regulatory processes and increasing costs of compliance with environmental laws and regulations. In particular, NSP is experiencing problems with the storage of spent nuclear fuel from the Company's Prairie Island nuclear facility. Without additional storage or significant modification of normal plant operations, the plant will be shutdown in early 1996, which could have a significant financial impact on NSP. (See "Environmental Matters" herein, Management's Discussion and Analysis of Financial Condition and Results of Operations under Item 7 and Note 15 of Notes to Financial Statements under Item 8 for further discussion of this matter.)
NSP made three strategically important business acquisitions in 1993 to operate more effectively in an increasingly competitive marketplace. NSP acquired an interstate gas pipeline, purchased assets of a non-regulated gas marketing business and expanded its non-regulated steam business. In 1993, NSP acquired Viking Gas Transmission Company and selected assets of the Centran Corporation. These Centran Corporation assets were reorganized into Cenergy, Inc., which provides NSP a vehicle to offer customized gas and energy services to fit customers' individual needs, both inside and outside the NSP service territory. The Viking pipeline allows NSP to lower its cost and to increase supply and storage flexibility. These two acquisitions together substantially increase our ability to compete in a more competitive business environment created by FERC Order 636. (See discussion at "Gas Operations" herein.) In addition, NRG purchased the Minneapolis Energy Center to position NSP as the major provider of central heating and cooling in Minnesota's largest city.
NRG has also been active in the international market through partnership investments. NRG acquired part ownership in the MIBRAG Gmbh coal and power complex and the 900 megawatt (Mw) Schkopau power plant near Leipzig, Germany. In addition, NRG also plans to become the operator and 37.5% owner of the 1680 Mw Gladstone Power Station in Queensland, Australia. (See additional discussions of business acquisitions and partnership investments in the "NRG Energy, Inc." and "Other Subsidiaries" sections, herein, and in Note 4 of Notes to Financial Statements under Item 8.)
Business Realignment
In order for the Company to be prepared to successfully meet challenges in the changing utility industry and to compete effectively in an increasingly competitive environment, the Company began a functional restructuring of its organization in 1992. During 1993, the Company completed several phases of the functional restructuring. The Company is now organized around three core, customer-focused businesses: electric power generation, electric transmission and distribution, and gas distribution. The new organization will use shared services, agreements or service contracts between all businesses, and centralized support groups throughout the Company. This restructuring is expected to improve the Company's competitive position by reducing costs, expediting decision-making and improving operating efficiencies.
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" under Item 1.)
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 kilovolt (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 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. NSP's 1993 utility operating revenues, excluding intersystem non-firm electric sales to other utilities of $110 million and miscellaneous revenues of $39 million, were subject to regulatory jurisdiction as follows:
Authorized Return on Percent of Total Common Equity @ Revenues December 31, 1993 (Electric & Gas) (Electric Operations) Retail: Minnesota Public Utilities Commission 11.47% 73.4% Public Service Commission of Wisconsin 12.00** 14.7 North Dakota Public Service Commission 11.50 5.6 South Dakota Public Utilities Commission * 3.1 Michigan Public Service Commission 12.25 0.6
Sales for Resale - Wholesale and Interstate Transmission: Federal Energy Regulatory Commission * 2.6
Total 100.0%
* Settlement proceeding, based upon revenue levels granted with no specified return. ** Return authorized for 1994 is 11.4%.
Rate Programs
Rate increases requested and granted in previous years from various jurisdictions were as follows (Note that 1992 and 1993 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 Year Requested Granted (Millions of dollars)
1987 $122.0 $ 83.9 1988 4.4 3.0 1989 129.0 8.0 1990 19.5 11.2 1991 118.7 68.0 1992 ----- ----- 1993 166.6 101.5
The following table summarizes the status of rate increases filed during 1992 and 1993 for rates effective in 1993.
Annual Increase Updated Requested Request Granted Status (Millions of dollars)
Electric Minnesota-Retail $119.1 $112.3 $ 72.2 Order Issued 1/14/94 North Dakota-Retail 8.8 7.1 4.8 Order On Reconsideration Issued 4/7/93 South Dakota-Retail 6.3 4.2 Order Approving Settlement Agreement Issued 12/09/92 Wisconsin-Retail 10.8 8.0 Order Issued 1/14/93 Minnesota Wholesale 2.3 .9 (1) Wisconsin Wholesale .6 .6 (1)
Gas Minnesota-Retail 14.9 12.4 10.0 Order Issued 12/30/93 Wisconsin-Retail 1.4 1.1 Order Issued 1/14/93 Viking Wholesale 2.4 (.3) (2) Total 1993 Rate Program $166.6 $101.5
(1) Order filed with a settlement agreement with rates effective in 1993. (2) Rate increase request filed 1991. Rates effective under a settlement agreement in 1993.
The following table summarizes the status of rate increases filed in 1993 for rates effective in 1994.
Annual Increase Updated Requested Request Granted Status (Millions of dollars)
Electric North Dakota-Retail 1.2 1.2 Order Issued 12/29/93
Gas Wisconsin-Retail 1.4 1.7 1.4 Order Issued 12/23/93 Total 1994 Rate Program 2.6 2.6
Rate Matters by Jurisdictions
Minnesota Public Utilities Commission (MPUC)
In November 1992, the Company filed applications for rate increases totaling $119.1 million and $14.9 million for its Minnesota electric and natural gas customers, respectively. This represented annual increases of approximately 9% and 5.8%, respectively. In December 1992, the MPUC issued orders granting interim rate increases (subject to refund) of $71.2 million (5.4%) for electric service and $8.4 million (3.3%) for gas service, effective Jan. 1, 1993. In June 1993, the Company adjusted its proposed annual electric rate increase to $112.3 million and its gas rate request to $12.4 million. The Company received initial orders from the MPUC in September 1993 allowing an annual retail electric rate increase of $54.3 million (4.1%) and an annual retail gas rate increase of $8.3 million (3.3%). On Nov. 10, 1993, the MPUC reconsidered several issues common to both the electric and gas rate cases and on Dec. 2, 1993, reconsidered a number of other issues in the electric rate order. The Company received a final gas rate order after reconsideration on Dec. 30, 1993, granting an overall gas rate increase of $10.0 million (3.9%). The Company received a final electric rate order after reconsideration on Jan. 14, 1994, granting an overall electric rate increase of $72.2 million (5.4%). The return on equity granted in both cases was 11.47%. Electric rate refunds of interim rates collected are required in the amount of approximately $12 million, which were accrued in 1993 and are expected to be paid in May 1994. No refunds of interim gas rates collected are required. Final rates for gas customers were implemented in March 1994. Implementation of final rates for electric customers is expected in April 1994. The effects of reconsideration were recorded in the fourth quarter 1993, when reconsideration occurred. However, the Company restated its third quarter 1993 earnings for the effects of reconsideration. (See additional discussion in Note 17 of Notes to Financial Statements under Item 8.)
On Jan. 31, 1994, an appeal of the MPUC's determination on the allowed return on equity was filed with the Minnesota Court of Appeals by the Minnesota Department of Public Service, the Office of the Minnesota Attorney General and the Minnesota Energy Consumers intervenor groups. The appeal concerns the method of calculating the rate of return on common equity for both the electric and gas cases. The amount at issue is approximately $7 million in annual revenues for the Company. The ultimate financial impact of this appeal, if any, is not determinable at this time. A decision by the court is expected by the end of 1994.
No general rate filings are anticipated in Minnesota in 1994.
North Dakota Public Service Commission (NDPSC)
On May 1, 1992, the Company filed with the NDPSC a general retail electric rate increase of $8.8 million, or 9.7%. The request was later reduced to $7.1 million or 7.9%. The NDPSC issued its order on Dec. 15, 1992, granting an increase of $2.7 million or 3%. On Dec. 31, 1992, the Company filed a petition for reconsideration of several issues contained in the order. On Jan. 27, 1993, the NDPSC agreed to reconsider the issues contained in the Company's reconsideration petition. On April 7, 1993, the NDPSC issued its final order after reconsideration. The final annual rate increase authorized totaled $4.8 million (5.3%) with rates effective April 21, 1993.
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 increase granted in April 1993. The $1.2 million annual increase was implemented Jan. 5, 1994.
No general rate filings are anticipated in North Dakota in 1994.
South Dakota Public Utilities Commission (SDPUC)
On June 29, 1992, the Company filed with the SDPUC an application for a general retail electric rate increase of $6.3 million or about 9.8%. A proposed settlement agreement was reached between Company officials and the SDPUC staff and filed with the SDPUC on Nov. 10, 1992. The proposed increase was $4.2 million, or 6.5%. It was effective in two stages: the first stage on Jan. 1, 1993, equal to $3.8 million, or 5.8%; and the second stage on May 1, 1993, equal to $0.4 million, or 0.7%. In addition, the Company agreed to a one-year moratorium on rate increases, which means the Company could not implement further rate increases until Jan. 1, 1995. On Dec. 9, 1992, the SDPUC issued its order approving the settlement. The settlement agreement did not address the rate treatment of accrual accounting for postretirement health care benefits. On Jan. 26, 1993, the SDPUC ordered the Company to continue to use the pay-as-you-go accounting method, and not the accrual method, for ratemaking purposes. The Company requested reconsideration of the Commission's decision on accrued benefits on Feb. 25, 1993. On April 12, 1993, the Commission denied the Company's request for reconsideration. The Company will seek an accounting order to permit the use of deferred accounting for such benefits until such treatment is requested in the next general rate filing. Although the ultimate rate recovery of the accrued benefits is unresolved, the impact is immaterial to the Company's operating results ($620,000 on an annual basis).
No general rate filings are anticipated in South Dakota in 1994.
Public Service Commission of Wisconsin (PSCW)
On June 1, 1992, the Wisconsin Company filed with the PSCW for an overall annual electric rate increase of $10.8 million, or 4.2%, and an overall annual gas rate increase of $1.4 million, or 2.1%. The PSCW issued an order dated Jan. 14, 1993, effective on Jan. 16, 1993 granting an increase in annual electric rates of $8.0 million and an increase in annual gas rates of $1.1 million. These orders represented a 3.1% increase in electric operating revenues and a 1.8% increase in gas operating revenues. The authorized return on common equity in these orders was 12.0%.
On June 3, 1993, as a part of its biennial filing requirement, the Wisconsin Company filed with the PSCW for an overall annual gas rate increase of $1.37 million, or 1.9%, and no annual electric rate increase. On Aug. 18, 1993, the Wisconsin Company increased its gas rate request to $1.7 million, or 2.4%, to recover its allocated share of the acquisition cost of Viking. The PSCW issued an order dated Dec. 23, 1993, effective Jan. 1, 1994, granting an increase in annual gas rates of $1.41 million, or 2.0%. The authorized return on common equity in this order was 11.4%.
Retail Rate Recovery of Viking Acquisition Costs
During 1993, the Company and the Wisconsin Company requested from regulators in Minnesota, North Dakota, and Wisconsin recovery in retail rates of a portion of the acquisition cost paid for Viking in recognition of reduced retail delivered gas costs related to the acquisition of Viking. The PSCW approved in the Wisconsin Company's rates the pass-through from Viking and recovery of $1.8 million, related to NSP's acquisition cost of Viking, over the five-year period 1994-1998. On March 23, 1994, the NDPSC authorized, without any change in rates, the amortization in jurisdictional expenses of approximatley $2 million of Viking acquisition costs over a 15 year period starting June 11, 1993. Recovery of such amortization in base rates would not commence until approval in the next general rate filing for North Dakota gas operations. A request for similar recovery is still pending before the MPUC. If this request is not approved, Viking would continue to expense until 2008 approximately $2 million in acquisition cost amortization each year with partial rate recovery.
Transmission Access Tariff and Settlement (FERC)
On Oct. 9, 1990, NSP filed an "open access" electric transmission services tariff with the FERC. The filing was contested by several parties, including the FERC staff. In April 1992, the FERC Administrative Law Judge issued an initial decision generally favorable to NSP's positions. On Sept. 21, 1993, the FERC issued an order that affirmed in part, modified in part and reversed in part the April 1992 initial decision of the Administrative Law Judge. On Oct. 21, 1993, NSP requested rehearing of the FERC's order. On Nov. 18, 1993, the FERC granted a tolling order delaying the decision on NSP's request. The case is currently pending rehearing with the FERC. If the order is not reversed by the FERC, refunds to customers would be required. Although the financial impact of this case is immaterial, it is noteworthy because it is one of the first FERC rulings concerning rates and terms of contracts for open access of transmission systems.
Minnesota Wholesale Rate Proceedings (FERC)
On Feb. 19, 1993, the Company filed with the FERC a request for increase in Minnesota wholesale electric rates of $2.3 million, or about 8.7% (Docket No. ER93-385-000). The Company requested that the new rates become effective on April 19, 1993, subject to refund with interest pending the FERC approval of the overall request. On April 20, 1993, the FERC issued an order accepting the filing and suspending the rate increase for five months. On August 26, 1993 the Company filed a settlement agreement with the FERC. The agreement specifies an increase of $0.9 million or about 3.6% effective Sept. 21, 1993. On Nov. 19, 1993, the FERC issued a final order accepting the settlement agreement and allowing the rates to become effective. The nine customers affected by this rate increase have all provided the Company with notices of termination of their resale power contracts effective in July 1995 (seven customers) and 1996 (two customers) as discussed below. The settlement calls for no further increases for the duration of service under the current contracts.
In 1990, 16 of the Company's 19 municipal wholesale customers began reviewing their long-term power supply options. Nine customers created a joint action group, Minnesota Municipal Power Agency (MMPA), to serve their future power supply needs and in 1992 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 $24 million in annual revenues and a maximum demand load of approximately 150 Mw.
On Oct. 21, 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 the municipalities' supply agreements with the Company expire. On Jan. 26, 1994, the FERC 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. If the parties are unable to reach agreement, the dispute will be submitted to the FERC for a hearing. The outcome of the case is not expected to have a material financial impact on the Company's operating results or financial condition.
In 1992 and 1993, the Company signed long-term power supply agreements with the remaining 10 of its current 19 municipal customers. 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 55 Mw and provide approximately $8 million in annual revenue. The FERC approved formula rates effective Jan. 1, 1994, by order dated Feb. 23, 1994.
Other Wholesale Rate Proceedings (FERC)
In January 1993, the Wisconsin Company proposed a settlement offer to increase rates for its 10 municipal wholesale customers. On Feb. 26, 1993, the Wisconsin Company filed with the FERC a settlement agreement with its 10 wholesale customers calling for a general wholesale rate increase. The agreements called for a $600,000, or 3.7% overall increase in wholesale electric rates. FERC accepted the settlement, and the new wholesale electric rate became effective Sept. 1, 1993.
On May 6, 1993, Viking filed a settlement agreement with the FERC that called for a $.3 million, or 1.0% overall decrease in wholesale gas transportation rates. FERC accepted the settlement, and the new wholesale gas transportation rates became effective July 1, 1993.
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. 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
The Company's wholesale and retail electric 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 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. The PSCW will be holding a technical conference and possibly hearings in 1994 to determine the appropriate process to handle fuel costs under the new biennial rate filing process.
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.
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 operations is provided in-kind by transportation suppliers.
ELECTRIC OPERATIONS
Capability and Demand
Assuming normal weather, NSP expects its 1994 summer peak demand to be 7,218 Mw. NSP's 1994 summer capability is estimated to be 8,866 Mw, including 1,340 Mw (including reserves) of contracted purchases from the Manitoba Hydro-Electric Board, a Canadian Crown Corporation (Manitoba Hydro) and 677 Mw of other contracted purchases. The estimate assumes 7,241 Mw of thermal generating capability and 1,625 Mw of hydro generating capability. Of the total summer capability, NSP has committed 109 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 1993 maximum demand of 6,990 Mw occurred on August 25, 1993. Resources available at that time included 6,816 Mw of Company-owned capability and 1,787 Mw of purchased capability net of contracted sales. The reserve margin for 1993 was 23%. The minimum reserve margin requirement as determined by the members of the Mid-Continent Area Power Pool (MAPP), of which NSP is a member, is 15%. (See Note 15 of Notes to Financial Statements under Item 8 for more discussion of power agreement commitments.)
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 energy 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 the Company's Prairie Island nuclear generating facility will continue operating through its license period.
The following resource needs were included in the resource plan. The plan does not specify the precise technology to meet these needs, but does suggest energy source options.
Cumulative MW Resource Needs By Type vs. Base of 1993
1996 2000 2004 2008
Peak 0-500 0-500 300-1,100 600-1,800 Intermediate 0-0 0-700 300-1,000 900-1,000 Base 0 0 0-300 200-1,400 DSM 500 1,200 1,700 2,000 Total 300-1,000 1,200-2,400 2,300-4,100 3,700-6,200
The resource plan proposes to satisfy the above resource needs through a combination of the following options:
Sources of Energy to Meet Needs
- Continued operation of existing generation. - Demand reduction of 2000 Mw by 2008 through conservation and load management. - 100 Mw of wind generation. - 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. - Installation of 210 Mw of natural gas-fired combustion turbines with an in-service date expected in September 1994. - Purchase of 232 Mw of natural gas-fired combined cycle generation. - Competitive bidding to fill additional needs for new generation.
In October 1993, the Company signed a 25-year agreement for the purchase of 25 Mw of wind-generated electric capacity and associated energy to be produced in Minnesota. The wind generating plant is expected to be fully operational by May 1994. This contract is the first phase of the Company's plan to obtain 100 megawatts of wind-generated electricity by 1997. The Company can recover the cost of energy purchases through cost-of-energy adjustment clauses in electric rates.
With respect to conservation, NSP is actively involved in numerous demand-side management programs. NSP's operating goals, which go beyond the resource plan guidelines above, are to offset peak electric demand by 1,100 Mw by 1995 and 1,700 Mw by 2000.
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 favorably.
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 proposal contemplates that NSP's regulated business will not construct new regulated generation facilities within its service area. However, the Company has proposed that its subsidiary, NRG, be allowed to bid in response to Company solicitations for proposals. The Company's competitive bidding proposal is being reviewed by the MPUC along with the 1993 resource plan. The Company anticipates an MPUC decision during the second quarter of 1994.
The Company intends to make similar competitive bidding proposal filings in North Dakota and South Dakota during 1994. Management intends to obtain regulatory approval in all retail jurisdictions to use a single bid process to meet resource needs for the entire system. The Wisconsin Commission has approved the use of competitive bidding for new resources for all Wisconsin utilities.
On Oct. 24, 1992, President Clinton 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 (See discussion in "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.
Many states are currently considering retail wheeling. While the topic of retail wheeling has been discussed in NSP jurisdictions, no legislation or regulatory initiatives have been formally introduced. Retail wheeling 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.
Through the functional restructuring discussed on page 1, the Company has moved responsibility for customer service, product reliability and profitability to the jurisdictional level within each business sector. This restructuring and business realignment will continue within each business sector through 1994. The Customer Operations Delivery system is being streamlined by consolidating similar functions. The Company is continuing an extensive reliability project that includes preventive maintenance on transmission and distribution power lines, improvements to existing equipment, and testing and implementing new technology. Reliability efforts are focusing on reducing the number of outages caused by lightning, human errors, animals and trees.
NSP created the Delivery Operations Department in 1993 to consolidate operation of its transmission and distribution systems. This department monitors the flow of electricity on the transmission network in NSP's five- state service area. It directs all switching of the Company's transmission equipment in Minnesota. In the Twin Cities metropolitan area, it monitors the flow of electricity on the distribution network, directs field switching, and directs field personnel to respond to trouble events.
Energy Sources
For the year ended Dec. 31, 1993, 48 percent of NSP's Kwh requirements was obtained from coal generation and 28 percent was obtained from nuclear generation. Purchased and interchange energy provided 20 percent, including 13 percent from Manitoba Hydro; NSP's hydro and other fuels provided the remaining 4 percent. The fuel resources for NSP's generation based on Kwh were coal (60 percent), nuclear (35 percent), renewable and other fuels (5 percent).
The following is a summary of NSP's electric power output in millions of kilowatt-hours for the past three years:
1993 1992 1991
Thermal plants 33 130 30 467 31 335 Hydro plants 1 001 1 024 1 153 Purchased and interchange 8 541 8 187 7 019 Total 42 672 39 678 39 507
Many of NSP's power purchases from other utilities are coordinated through the regional power organization MAPP. NSP is one of 29 participants in MAPP consisting of 10 investor-owned systems, eight generation and transmission cooperatives, three public power districts, seven municipal systems and the Department of Energy's Western Area Power Administration. MAPP membership also includes 15 Liaisons/Associate Participants consisting of two Canadian Crown Corporations, 12 municipal systems, and one investor- owned system, which are members of MAPP, pursuant to an agreement dated March 31, 1972. This 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 was accepted for filing by the FERC, effective Dec. 1, 1972.
As discussed in Note 15 of Notes to Financial Statements in Item 8, significant increases in purchased power may be required beginning in 1995 if the Prairie Island generating facility can not continue operating.
Fuel Supply and Costs
Coal and nuclear fuel will continue to dominate NSP's 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 two 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 1993 and the estimated fuel mix for 1994 and 1995 are as follows:
Fuel Use on Btu Basis (Est) (Est) 1993 1994 1995
Coal 62.3% 62.9% 61.2% Nuclear 36.2% 35.4% 37.1% Other 1.5% 1.7% 1.7%
The Company normally maintains approximately 30 days of coal inventory (between 20 and 45 days, depending on plant site). The Company has long-term contracts providing for the delivery of up to 99 percent of its 1994 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 96 percent of the coal it burns in 1994 will have a sulfur content of less than 1 percent. The Company has contracts with two Montana coal suppliers, Westmoreland Resources and Western Energy, and three Wyoming suppliers, Rochelle Coal Company, Antelope Coal Company and Black Thunder Coal Company, for a maximum total of 85 million tons of low-sulfur coal for the next 10 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 plants. 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 Wisconsin Company's electric generating plants are primarily hydro plants.
The estimated coal requirements of the Company at its major existing coal-fired generating plants for the periods indicated and the coal supply for such requirements are as follows:
State Sulfur Dioxide Maximum Amount Contract Approximate Emission Limit Annual Covered by Expiration Sulfur Pounds Per Plant Demand Contract Date Content(%)(2) MBTU*Input (Tons) (Tons)
Black Dog 1 000 000 1 000 000 (1) 0.5 3.0(3) High Bridge 800 000 800 000 (1) 0.5 3.0 Allen S. King 2 000 000 2 000 000 (1) 0.9 1.6(4) Riverside 1 200 000 1 200 000 (1) 0.7 2.5(5) Sherco 8 000 000 8 000 000 (1) 0.5 0.9(6) 13 000 000 13 000 000(7)
*MBTU = Million British Thermal Units
Notes:
(1) Contract expiration dates vary between 1995 and 2005 for western coal, which can provide more than 95% of the required fuel supply for the designated generating unit. Spot purchases of western and midwestern coal, and other fuels will provide the remaining fuel requirements. The Company is also test burning petroleum coke as a potential fuel.
(2) This figure 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 King Plant SO2 limitation of 1.9 lb/MBTU expired in January 1991, but the Minnesota Pollution Control Agency (MPCA) approved a short- term extension during permit negotiations. This interim limit was lowered to 1.8 lb/MBTU in May 1993. A final decision from the MPCA was reached in February 1994 setting a limit of 1.6 lb/MBTU.
(5) 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.
(6) Compliance with air pollution control permit and applicable air quality regulations requires use of limestone scrubbers to achieve 70% SO2 removal and to limit 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 0.61 lb/MBTU.
(7) Required annual deliveries are no less than 6.0 million tons per year. Annual requirements are expected to range from 11.0 to 12.5 million.
NSP's current fuel oil inventory is adequate to meet anticipated 1994 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 agreements for complete nuclear fuel cycles, which include uranium concentrate (yellowcake), uranium conversion, uranium enrichment services and fuel fabrication.
The Company's current nuclear fuel contractual commitments are summarized below:
Nuclear Fuel Services Contract Duration Monticello Prairie Island No. 1 Prairie Island No. 2
Yellowcake 1998 (1) 1998 (1) 1998 (1) Conversion 1999 (2) 1999 (2) 1999 (2) Enrichment 2005 (3) 2005 (3) 2005 (3) Fabrication 1998 (4) 2004 2004
(1) The yellowcake requirements are approximately 60% under contract for 1994-1997 and 15% for 1998.
(2) The uranium concentrate conversion services are approximately 60% under contract for 1994-1997 and 35% for 1998-1999.
(3) 100% of enrichment requirements are under contract for 1994-1995. The enrichment requirements are approximately 45% covered under a combination of firm contracts plus options for 1996-2005.
(4) The Company has options to supply its needs through 2001.
The Company expects sufficient uranium to be available for the total fuel requirements of its existing plants. The nuclear fuel contract strategy involves a portfolio of long- and medium-term contracts, as well as spot purchases. There are no assurances regarding the ultimate costs of any of the components of the fuel cycle or what impact any governmental legislation may have. However, 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 an electrical generation facility. The cost of nuclear fuel, including disposal, is recovered in the customer price of the electricity sold by the Company.
NSP's fuel costs for the past three years are shown below:
Fuel Costs * Per Million Btu Year Ended December 31 1991 1992 1993
Coal** $ 1.24 $ 1.22 $1.17 Nuclear*** .47 .43 .41 All Fuels .95 .93 .90
* Fuel adjustment clauses in its electric rate schedules or statutory provisions enable NSP to adjust for fuel cost changes. (See "Regulation and Revenues - Fuel and Purchased Gas Adjustment Clauses" under Item 1.)
** Includes refuse-derived fuel and wood.
*** See Note 1 of Notes to 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 the only utility 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 them 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 millicurie of residual contamination remain 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 wastes include only spent 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.
The primary purpose of in-plant storage of low-level radioactive waste is to accumulate an inventory of material for economical shipment. Low-level waste disposal sites have been licensed in New York, Kentucky, Illinois, South Carolina, Nevada and Washington. At present, only South Carolina has an operating site that accepts commercial wastes from Minnesota.
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 1980 law, as amended in 1985, requires disposal sites to be operational after 1992. The South Carolina site has extended its closure date to out-of-region waste until June 30, 1994. Ohio is projecting completion of the low-level radioactive waste disposal facility in 2001. 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 spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act of 1982 requires the Department of Energy (DOE) to implement a program for nuclear waste management including the siting, licensing, construction and operation of repositories for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes.
The Company has contracted with the DOE for the disposal of spent 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. Revisions to the DOE's basis of charging customers will result in fee reductions of $8.3 million, including reductions of $3.7 million already realized in 1992 and $3.6 million in 1993. 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 spent 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. For discussion of spent nuclear fuel storage facilities at the Company's Prairie Island Plant, see "Environmental Matters" herein, Management's Discussion and Analysis of Financial Condition and Results of Operations under Item 7 and Note 15 of Notes to Financial Statements under Item 8.
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 $523 million since 1971, and expects to expend an additional $9 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 15 of Notes to 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.
GAS OPERATIONS
Capability and Demand
NSP catagorizes 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 642,684 MMBtu for 1993 occurred on Dec. 27, 1993. This was also NSP's all time maximum daily sendout through Dec. 31, 1993.
As discussed below, NSP's primary gas supply sources are purchases of third-party gas which are delivered under gas transportation service agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 511,000 MMBtu/day. 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. Using storage reduces the need for firm gas supplies. These storage agreements provide NSP storage for approximately 15% of annual and 28% of peak daily firm requirements at an annual fixed cost of $5.1 million. NSP also owns and operates three liquefied 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 237,900 Mcf of natural gas per day, or approximately 42% of peak day firm requirements. The Company expanded this daily deliverability by approximately 16,000 Mcf/day in 1993 through minor capital additions to a propane-air peaking plant. Recovery of the capital cost of this addition was included in the Company's Minnesota retail gas rates approved by the MPUC on Dec. 30, 1993. These LNG and propane-air plants provide a cost-effective alternative to annual 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.
Competition
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: gathering, transportation, storage, sales and pipeline delivery management. 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 agreements to be no greater than the risk faced under the previous long-term full requirements gas supply contracts.
As a result of the changes in the natural gas industry in the last decade, culminating in Order 636, NSP's natural gas supply network 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 contracted 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 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 some uncertainty remains as to whether the new unbundled services under Order 636 will prove to be as reliable and flexible as the traditional sales service.
The implementation of Order 636 will apply 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's 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 maximize 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 Natural Gas Company (Northern), is currently in the process of determining the amount of transition costs to be passed on to customers, as a result of Order 636 restructuring. Northern's restructuring has 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 customer demand charges. NSP estimates that it will be billed for approximately 10 percent of Northern's transition costs, spread over a period of approximately five years. NSP's regulatory commissions have previously approved recovery of similar restructuring charges in retail gas rates.
NSP has no Order 636 transition cost responsibilities to its other pipeline suppliers. FERC has ruled that NSP has no transition cost obligation to Williston Basin Interstate Pipeline Company (Williston) since it was never a gas sales customer of that pipeline. Viking incurred no Order 636 transition costs.
The gas services available to NSP's customers were expanded 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. The acquisition of Viking allows NSP increased access to natural gas transportation. Cenergy's acquisition of a gas marketing business will allow NSP to provide more customized value-added energy services to retail gas customers without increasing costs within the regulated retail gas distribution business. (See Note 4 of Notes to Financial Statements in Item 8 and 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 is installing a state-of-the-art delivery management system.
Gas Supply and Costs
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, Viking, Williston and Great Lakes Transmission Pipeline. Approximately 90 percent of NSP's retail gas customers are served from the Northern pipeline system. As recently as 1987, NSP was able to purchase only "full requirements" pipeline sales supply, where NSP purchased the full requirements of its retail customers in a particular NSP gas service territory from the directly interconnected pipeline, and resold this gas to retail customers.
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 1994 through 2012.
Northern Natural Gas Great Lakes Transmission 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 $11.7 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, 1993, NSP was committed to approximately $607 million in such obligations under these contracts, over the remaining contract terms, which range from the years 1994-2013. These obligations include some of the effects of contract revisions made to comply with Order 636.
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. The MPUC and the PSCW also have allowed NSP to reflect in rate base the average cost of gas inventory held in underground storage.
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. A request for approval of the NSP/Viking transportation agreements is pending approval. NSP currently does not purchase system gas supply or services from Cenergy, but anticipates requesting such authority in 1994. The MPUC has previously approved similar affiliate gas supply transactions between Minnegasco, which is another Minnesota LDC, and Arkla, Inc., an affiliated interstate pipeline and gas marketing company.
The following table details selected operating information for NSP's gas distribution business which excludes Viking and Cenergy:
Average Total Customers Cost Deliveries * at Per MMBtu Bcf Year-End Minnesota 1990 $2.76 66.1 303,189 1991 $2.50 72.6 311,354 1992 $2.71 68.1 319,673 1993 $3.11 79.8 328,306 Wisconsin 1990 $2.65 14.1 54,966 1991 $2.73 14.4 58,446 1992 $2.80 14.9 62,065 1993 $3.02 17.0 65,155
* Includes sales and transportation services.
TELEPHONE OPERATIONS
On Jan. 31, 1991, the Company sold its telephone properties and operations located in North Dakota to Rochester Telephone Corporation of Rochester New York for $48 million in cash. The net of tax gain on the sale of $16.8 million (27 cents per average common share) was recorded in the first quarter of 1991. The telephone operations historically accounted for less than 2% of NSP's earnings.
NRG ENERGY, INC.
NRG Energy, Inc. (NRG) is the Company's subsidiary that develops, builds, acquires, owns and operates several of the Company's 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 1993 revenues of $66 million and had assets of $275 million at Dec. 31, 1993. These assets include $37 million of investments in and capitalized development costs for projects NRG is currently pursuing, as discussed in the "New Business Development" section.
The subsidiaries of NRG Energy, Inc., which currently conduct business are: 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., and NRG Energy Center, Inc.
Operating Businesses
NRG operates two refuse-derived fuel (RDF) processing plants and an ash disposal site. The ownership of one plant was transferred by the Company to NRG at the end of 1993, while legal transfer of ownership of the Company's 85% share of the other RDF plant and the ash disposal site is pending contract approval by the serviced counties. In 1993, workers at the RDF plants processed more than 820,000 tons of municipal solid waste into approximately 660,000 tons of refuse-derived fuel 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.
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, is expected 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.
San Joaquin Valley Energy I, Inc.; San Joaquin Valley Energy IV, Inc., and NRG Energy Jackson Valley II, Inc. own 45% of the San Joaquin Valley Energy partnership, which owns four power plants located near Fresno, California with a total capacity of 45 Mw. The facilities are operating fluidized-bed biomass, waste-fueled cogeneration plants. All four plants have long-term power sales agreements with Pacific Gas & Electric through 2017.
NRG Energy Jackson Valley I, Inc., and NRG Energy Jackson Valley II, Inc. own 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.
On Aug. 20, 1993, NRG Energy Center, Inc. purchased the assets of the Minneapolis Energy Center (MEC), a downtown Minneapolis district heating and cooling system. The system utilizes steam and chilled water generating facilities to heat and cool buildings for approximately 85 heating and 25 cooling customers in downtown Minneapolis. The primary assets include the main plant, three satellite plants, two standby plants, six miles of steam lines and two miles of chilled water distribution lines. The MEC was purchased from Energy Center Partners. Existing long-term contracts with MEC customers will remain in effect under NRG's ownership. The purchase price was $110 million, financed mainly with $84 million of project debt. The purchase price primarily included facilities, long-term service agreements and goodwill. (See Note 4 of Notes to Financial Statements under Item 8 for further discussion).
New Business Development
NRG is pursuing several energy-related investment opportunities, as discussed below. Many of these opportunities are joint venture projects, which would be financed primarily through debt at the project level. The remaining project costs are expected to be funded through equity investments from NRG and other investors. Depending on NRG's ultimate involvement in such opportunities, these projects could require equity investments of approximately $390 million by NRG for the five year period 1994-1998.
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.
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, 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 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.
On Dec. 10, 1993, NRG International, Inc., through a wholly owned foreign subsidiary, acquired a 50% interest in a German corporation, Saale Energie GmbH (Saale). Saale owns a 400 Mw share in the 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 Gelsen-Kirchen, Germany (VEBA), is the builder of the Schkopau plant. VEBA, which will own the remaining 59.9% interest in the power plant and the remaining 500 Mw share in the plant, will operate the plant. The plant will be fired by brown coal (lignite) mined by MIBRAG GmbH (MIBRAG) under a long-term contract. Saale has a long-term power sales agreement for its 400 Mw share 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.
On Dec. 19, 1993, NRG International, Inc., through another wholly owned foreign subsidiary, agreed to acquire a 33% interest in the coal mining, power generation and associated operations of MIBRAG, located south of Leipzig, Germany. MIBRAG is a German corporation newly 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, three small industrial power plants and a circulating fluidized bed power plant presently under construction and scheduled for completion in 1994, a district heating system and coal briquetting and dust production facilities. Under the acquisition agreement, Morrison Knudsen Corporation and PowerGen plc each agreed to also acquire a 33% interest in MIBRAG, while the German government retains a one-percent interest in MIBRAG. The acquisition is expected to close in 1994.
NRG's equity commitment to the two German projects through 1996 is expected to be no more than $100 million.
On March 4, 1993, NRG International, Inc. signed a letter of intent pursuant to which it agrees, on behalf of it or a wholly owned subsidiary, to join an unincorporated joint venture with Comalco Limited of Australia (Comalco) and other parties. The joint venture is currently in negotiations for the acquisition, from the Queensland Electricity Commission, of the Gladstone Power Station, a 1680-Mw coal-fired plant in Gladstone, Queensland, Australia. A large portion of the electricity would be sold to Comalco for use in its aluminum smelter, pursuant to long-term power purchase agreements. NRG International, Inc. expects to acquire a 37.5% interest in the Gladstone plant. A wholly owned subsidiary of NRG International, Inc. will operate the Gladstone plant. Closing of the transaction is expected in 1994. NRG's total equity investment in the Gladstone project is expected to range from approximately $60 million to $70 million.
In 1992, NRG had investment writedowns and losses from unsuccessful non-regulated energy projects of $6.8 million before income taxes. This included an investment in Cypress Energy Partners, a limited partnership formed between NRG and Black and Veatch Power Development Corporation. Cypress Energy Partners was denied permission by the Florida Public Service Commission to build two, 400 Mw electric generating plants for Florida Power and Light. An appeal with the Florida Supreme Court against the Commission was filed and subsequently withdrawn.
OTHER SUBSIDIARIES
Viking Gas Transmission Company
On June 10, 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, for $45 million, $32 million of which was financed with project debt. 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 400 million cubic feet per day. The Viking pipeline currently serves 12% of NSP's gas distribution system needs. Approximately 75% of NSP's gas customers are located within 40 miles of the Viking pipeline. 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 Note 4 of Notes to Financial Statements under Item 8 for further discussion.)
Cenergy, Inc.
On Oct. 1, 1993, Cenergy, Inc., a non-regulated subsidiary of the Company, acquired from bankruptcy certain assets of Centran Corporation, a natural gas marketing company, for approximately $4 million. The acquisition was completed to offer a variety of energy options, to increase natural gas supply flexibility for existing NSP customers and to expand NSP's energy services nationwide. The energy services marketing company will offer a broad range of energy services, while focusing on commercial and industrial end-users of natural gas. Cenergy serves approximately 300 customers. (See Note 4 of the Notes to Financial Statements under Item 8 for further discussion.)
Eloigne Company
In 1993, the Company established a new subsidiary, 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. Elogine's capital investments and operating results for 1993 were not material.
NEO Corporation
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 opportunities utilizing landfill gas. NEO Corporation's capital investments and equity in the 1993 operating results of Minnesota Methane were not material.
ENVIRONMENTAL MATTERS
NSP's policy is to proactively prevent adverse environmental impacts, regularly monitor 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 believes that it is in compliance, in all material respects, with applicable environmental laws.
The Company has spent approximately $685 million on environmental improvements to new and existing facilities since 1968. Historically, the Company has spent an average of approximately $26 million annually in connection with environmental improvements for existing and new facilities. The Company expects to incur approximately $9 million in capital expenditures for compliance with environmental regulations in 1994. In general, the Company has been experiencing a trend toward more environmental monitoring and compliance costs, which has caused and may continue to cause slightly higher operating expenses and capital expenditures. The precise timing and amount of environmental costs are currently unknown. (For further discussion of costs, see Note 15 of Notes to 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 Company has proposed construction of an onsite dry cask (container) storage facility for spent nuclear fuel at its Prairie Island Nuclear Generating Plant (Prairie Island) near Red Wing, Minnesota that will provide additional onsite storage. At current operating levels, the current Prairie Island onsite storage pool will be filled in 1994. Without additional onsite storage, operations at Prairie Island, which supply about 20% of the Company's output, will begin to be curtailed in mid-1995 and the plant will cease operating by early 1996. The design and operation of the proposed facility will be regulated by the Nuclear Regulatory Commission (NRC) and must meet applicable health and safety standards. Application for a Part 72 license was submitted to the NRC in August 1990. The NRC published a favorable Environmental Assessment for the project in June 1992. In October 1993, the NRC issued the Company a 20-year license to store fuel in up to 48 casks at the Prairie Island facility. In addition to the NRC license, the Company is required to obtain state approval for the proposed facility. In May 1991, the Minnesota Environmental Quality Board voted to declare the environmental impact statement prepared for the project, which found no significant environmental impacts, adequate. A Certificate of Need Application (CON) for 48 containers for temporary storage of spent nuclear fuel was filed with the MPUC and hearings were held during the latter part of 1991. A decision to grant the CON was announced by the MPUC in 1992. Seventeen containers for temporary storage of spent nuclear fuel were approved, which would provide adequate storage at least through the year 2001. In November 1992, the Minnesota Court of Appeals received a joint petition from several parties seeking a reversal of the MPUC's decision. In June 1993, the Minnesota Court of Appeals ruled that the Prairie Island spent fuel storage facility falls under the requirements of the Minnesota Radioactive Waste Management Act and, therefore, requires legislative approval before the Company can begin to store fuel. Petitions by the Company, MPUC, and the Minnesota Department of Public Service to the Minnesota Supreme Court to review the Appeals Court decision were denied. Upon denial by the Supreme Court to review the case, the Company immediately halted all construction and fabrication activities in order to bring the Company in compliance with the law. The Company has requested approval for the facility from the Minnesota Legislature during the 1994 session which began on Feb. 22, 1994.
The bill allowing NSP to construct an onsite dry cask storage facility at Prairie Island is being considered by two committees of the Minnesota State House of Representatives (House) and two committees of the Minnesota State Senate (Senate). Both the House and Senate energy committees have passed the bill. The Senate environmental committee defeated the bill and refused to refer it to the Senate floor by a 10-8 vote. A hearing of the House environmental committee has not been scheduled. The time limit for consideration of the bill by the House and Senate committees expires March 25, 1994. If these committees do not approve the bill by that time, efforts will be made to obtain approval on the House and Senate floors.
The consequences of not receiving legislative approval would include premature shutdown of the Prairie Island plant, the need to obtain replacement power to meet customer needs, and the need to seek rate recovery of the plant investment and decommissioning costs. Specifically, Prairie Island Unit 2 would be shutdown in May 1995 and Prairie Island Unit 1 would be shutdown in February 1996 without significant modification of normal plant operations. If operations at Prairie Island cease, the Company estimates that the present value of the cost of supplying replacement power and recovering its investment in the plant and unrecognized decommissioning costs will be at least $1.8 billion. The Company would request recovery of these costs, including a return on its investment, through utility rates. However, at this time the amount of such costs and the regulators' ultimate response to such a request is unknown. (See Note 15 of Notes to Financial Statements under Item 8 regarding the possible effects on operating results of the potential shutdown of the Company's Prairie Island nuclear power generating facility.)
The Company and NRG made contractual commitments to convert municipal solid waste to boiler fuel and burn the fuel to generate electricity. NRG operates 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 all known PCB capacitors from its distribution system. NSP also has removed 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 beneficially 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 July 1986, the Minnesota Pollution Control Agency (MPCA) board voted to accept an Administrative Law Judge's recommendation regarding an acid deposition control plan. The control plan set a sulfur dioxide emissions cap of 1.3 times the Company's 1984 system-wide emissions, commencing in 1990. The plan also required a sulfur dioxide emission rate based upon Reasonably Available Control Technology (RACT) to be determined for the Allen S. King Plant. In 1989, the Company reached agreement with the MPCA on an interim emissions rate of 1.9 lbs/MBTU. This interim rate was lowered to 1.8 lbs/MBTU in May 1993. In September 1993 a hearing before an Administrative Law Judge (ALJ) took place to set a final RACT limit. In December 1993 the ALJ recommended a final RACT limit of 1.6 lbs/MBTU. A final decision from the MPCA was reached in February 1994 adopting the ALJ recommendation. The limit of 1.6 lbs/MBTU may require the Allen S. King Plant to modify its current fuel blend and to conduct more frequent boiler cleanings.
The U.S. Environmental Protection Agency (EPA) in 1991 issued waste combustor air quality regulations. As of Feb. 11, 1996, the regulations impose new restrictions on currently permitted emissions. The MPCA expects to issue statewide waste combustor rules in 1994 that would be more restrictive than the new federal requirements beginning in 1997. To meet the new federal and state requirements, 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. Further regulations that could affect pollution control equipment are expected to be approved by the EPA in 1995.
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. The legislation enacted in 1990 is extremely complex and its overall financial impact on NSP will depend on the final interpretation and implementation of rules to be issued by the EPA. NSP is participating in the rulemaking process for the development of regulations that achieve the goals of the legislation in a reasonable and cost-effective manner. NSP has expended significant funds over the years to reduce sulfur dioxide emissions at its plants. Additional construction expenditures may be required to comply with parts of the Clean Air Act. Based on revised emission standards proposed by the EPA in 1993, NSP's excess emission allowances available under the Clean Air Act may be significantly reduced. Because the Company is only beginning to implement some provisions of the Clean Air Act, its overall financial impact is unknown at this time. The majority of the Company's power plants meet state and federal limits for opacity and air quality. Capital expenditures will be required for opacity compliance in 1994-1998 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 Sherburne County Generating Plant (Sherco). The equipment will be installed in 1994 inside one of the existing acid gas scrubber modules. Testing, anticipated to be completed by the end of 1995, 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 $300 million for other technology options.
The Company has completed testing for air toxics at its major facilities and shared these results with state and federal agencies. The Company also is engaged in research to reduce levels of mercury emissions. The Clean Air Act requires the EPA to look at issuing rules for air toxics for electric utilities. The MPCA is considering the development of air toxic rules in 1994. There also is interest in the Minnesota Legislature to pass a bill further restricting the emissions of mercury in the state. The Company cannot predict at this time what additional actions, if any, it may need to take if any such rules are 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 present 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
The Company has been designated by the EPA as a "potentially responsible party" (PRP) for eight waste disposal sites to which the Company sent 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 $85 million for all eight PRP sites. However the amount could be in excess of $85 million.
Settlement with the EPA and other PRPs has been reached for two of these disposal sites for reimbursement of the federal government's past costs of remedial action. One of the sites, South Andover Salvage Yards, in Andover, Minnesota, is contaminated by several chemicals, including PCBs. The contamination was attributed to past disposal by the Company and 13 other PRPs. The Company's total allocation for both sites was approximately $1.4 million, which has already been paid. Of that amount, approximately $1.3 million was paid in 1993 related to the Andover site. 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. The Company instituted legal action to recover costs from non-participating PRPs at the South Andover site and recovered a portion of its costs. The Company has reached tentative settlement with the EPA, state agencies and other parties at a third site. The Company's allocation for remediation of this site is estimated to be approximately $150,000. For the remaining five 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 five sites is approximately $0.9 million.
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.
The Wisconsin Company has been notified by a group of PRPs of possible responsibility 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 PRPs has been determined, it is not feasible to determine the outcome of this matter at this time.
The Company is continuing to investigate 14 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 $10 million to approximately $16 million, including $3.1 million which has been paid to date. The Company has commenced remediation efforts at five of the 14 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. No agreement or consent order has been negotiated to perform any extensive site investigations or clean-up at the other nine sites. The Company currently estimates its liability for the 14 sites to be approximately $7 million. 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. The Company has requested approval of deferred accounting of investigation and remediation expenses. The request is pending MPUC approval.
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 and include it in depreciation expense. Removal costs are estimated based on historical experience and a amount is currently included in depreciation expense.
Contingencies
In October 1992, the Company disclosed to the Minnesota Pollution Control Agency (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, and the Company cooperated with state and federal authorities in the investigation of the reporting violations. In November 1993, the United States Attorney's Office announced that three chemistry technicians responsible for reporting halogen content in discharge water would be charged with misdemeanor violations of the Federal Clean Water Act. No civil or criminal actions against the Company have been announced.
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 electric and magnetic fields 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 electric and magnetic fields. 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 $362 million in 1993, compared to $428 million and $350 million expended in 1992 and 1991, respectively. These capital expenditures include gross additions to utility property of $357 million (excluding Viking property acquired), $419 million and $339 million for the three years ended 1993, 1992 and 1991 respectively. Internally generated funds provided approximately 99% of the capital expenditures for 1993, 49% for 1992 and 58% for 1991. In addition to capital expenditures, NSP invested $159 million in 1993 to acquire three energy- related businesses. (See Note 4 of Notes to Financial Statements under Item 8.)
NSP's utility capital expenditures (including allowance for funds used during construction) are estimated to be $396 million for 1994 and $1.8 billion for the five years ended Dec. 31, 1998. Included in NSP's projected utility capital expenditures is $55 million in 1994 and $282 million during the five years ended Dec. 31, 1998, for nuclear fuel for NSP's three existing nuclear units. The remaining capital expenditures through 1998 are for many utility projects, none of which are extraordinarily large relative to the total capital expenditure program. Approximately 80% of the 1994 utility capital expenditures and approximately 95% of the 1994-1998 utility capital expenditures are expected to be provided by internally generated funds. 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. Further, the estimates assume the continued operation of the Company's Prairie Island generating facility. (See Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations and "Environmental Matters" herein.)
Although they 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 are estimated to be $130 million in 1994 and $540 million for the five-year period 1994-1998. The majority of these non-regulated capital requirements relate to equity investments (excluding project debt) in NRG's international projects, as discussed previously. The remainder consists mainly of affordable housing investments by Eloigne Company, most of which are expected to be financed through project debt. Equity investments by NRG and Eloigne would be funded through their own internally generated funds or through equity investments by NSP. 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 and debt.
NSP continues to evaluate opportunities to enhance shareholder returns through business acquisitions. Long-term financing may be required for acquisitions that NSP consummates.
EMPLOYEES AND EMPLOYEE BENEFITS
The total number of full- and part-time employees of NSP is approximately 7,880. About 3,150 employees of NSP are represented by five local IBEW labor unions. The labor contracts with the unions expired on Dec. 31, 1993. On March 14, 1994, a three-year contract offer was rejected and an authorization to strike was approved by the IBEW membership by nearly a 2-to-1 margin. Representatives from the union and NSP resumed discussions on March 21, 1994. An interim agreement between NSP and the unions is in place with an expiration date of March 31, 1994. Negotiations are continuing and NSP is unable to predict the outcome of negotiations at this time.
In 1993, NSP reviewed employee and retiree benefits and implemented the following changes that are effective for 1994. These changes will support NSP's goal of providing market-based benefits and are expected to keep employee compensation and benefit costs close to 1993 levels.
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 outlined.
Nonbargaining pension plan lump sum option changes: Currently, nonbargaining employees have the option to receive their pension in either a lump sum or in monthly installments. Beginning in 1994, nonbargaining employees will be able to 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.
Nonbargaining 401(k) changes: NSP currently offers eligible employees a 401(k) Retirement Savings Plan. NSP will match up to $500 of nonbargaining employees pre-tax 401(k) contributions.
Nonbargaining 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 the latest salary surveys that indicate how local and regional companies pay their employees for comparable positions.
EXECUTIVE OFFICERS *
Present Positions and Business Experience Name Age During the Past Five Years
James J Howard 58 Chairman of the Board and Chief Executive Officer since 7/01/90; and prior thereto Chairman of the Board, President and Chief Executive Officer.
Edwin M Theisen 63 President and Chief Operating Officer since 7/01/90; and prior thereto President and Chief Executive Officer of Northern States Power Company (a Wisconsin corporation), a wholly owned subsidiary of the Company.
Leon R Eliason 54 President - NSP Generation since 1/01/93; Vice President - Nuclear Generation from 7/01/90 to 12/31/92; and prior thereto General Manager - Nuclear Plants.
Keith H Wietecki 44 President - NSP Gas since 1/11/93; Vice President - Corporate Strategy from 1/01/93 to 1/10/93; Vice President - Electric Marketing & Sales from 4/25/90 to 12/31/92; and prior thereto Vice President - Electric Marketing and Customer Service.
Douglas D Antony 51 Vice President - Nuclear Generation since 1/01/93; General Manager - Monticello Nuclear Site from 9/01/90 to 12/31/92; Plant Manager - Monticello from 8/15/89 to 8/31/90; and prior thereto General Superintendent - Training Center.
Vincent E Beacom 64 Vice President - Minnesota Electric since 1/01/93; Senior Vice President - Gas Operations from 7/01/90 to 12/31/92; and prior thereto Vice President - Commercial and Division Operations Northern States Power Company (a Wisconsin corporation), a wholly owned subsidiary Company.
Arland D Brusven 61 Vice President - Finance and Treasurer since 1/01/93; Vice President and Treasurer from 9/01/90 to 12/31/92; and prior thereto Secretary and Financial Counsel.
Jackie A Currier 42 Vice President - Corporate Strategy since 1/11/93; Director - Corporate Finance and Assistant Treasurer from 9/17/92 to 1/10/93; Director - Corporate Finance from 6/01/90 to 9/16/92; General Manager - Budget & Control from 4/01/89 to 5/31/90; and prior thereto Manager - Departmental & Capital Budgets.
Gary R Johnson 47 Vice President & General Counsel since 11/01/91; and prior thereto Vice President - Law.
Cynthia L Lesher 45 Vice President - Human Resources since 3/01/92; Director - Power Supply Human Resources from 8/15/91 to 2/29/92; Manager - White Bear Lake Area from 5/21/90 to 8/14/91; Manager - Metro Credit from 1/15/89 to 5/20/90; and prior thereto Manager - Occupational Health/Safety.
Edward J McIntyre 43 Vice President and Chief Financial Officer since 1/01/93; President and Chief Executive Officer of Northern States Power Company (a Wisconsin corporation), a wholly owned subsidiary of the Company from 7/01/90 to 12/31/92; an prior thereto Vice President - Gas Utility.
Roger D Sandeen 48 Vice President, Controller and Chief Information Officer since 4/22/92; Vice President and Controller from 7/01/89 to 4/21/92; and prior thereto Vice President and Treasurer of KVI Associates, Inc. (a real estate development company managing assets in excess of $150 million).
Robert H Schulte 41 Vice President - Customer Service since 1/01/93; Vice President - Rates and Corporate Strategy from 7/01/90 to 12/31/92; and prior thereto General Manager - South Dakota Region.
Loren L Taylor 47 Vice President - Customer Operations since 1/01/93; Vice President - Transmission and Inter-Utility Services from 11/01/89 to 12/31/92; and prior thereto Vice President - Human Resources.
*As of 3/01/94
Item 2
Item 2 - Properties
The Company's major electric generating facilities consist of the following:
Projected Summer Net Capability Station and Unit Fuel Installed (MW)
Sherburne Unit 1 Coal 1976 712 Unit 2 Coal 1977 712 Unit 3 Coal 1987 514 Prairie Island Unit 1 Nuclear 1973 513 Unit 2 Nuclear 1974 512 Monticello Nuclear 1971 539 King Coal 1968 567 Black Dog 4 Units Coal 1952-1960 463 High Bridge 2 Units Coal 1956-1959 262 Riverside 2 Units Coal 1964-1987 366
All of NSP's major generating stations are located in Minnesota on land owned by the Company. At December 31, 1993, NSP's electric transmission and distribution system consisted of 6,534 miles of overhead transmission lines, 28,100 miles of overhead distribution pole lines, 396 miles of underground conduit and 13,872 miles of underground cable.
The gas properties of NSP include about 6,785 miles of natural gas distribution mains. Viking owns a 500-mile gas pipeline.
Manitoba Hydro, Minnesota Power Company and the Company completed the construction of a 500-Kv transmission interconnection 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. (See Note 15 of Notes to Financial Statements under Item 8.) In addition, the Company is interconnected with Manitoba Hydro through a 230 Kv transmission line completed in 1970.
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. Four personal injury lawsuits have been filed by individuals injured in the explosion with Ramsey County, Minnesota District Court. The litigation is in a preliminary stage and the ultimate costs to the Company are unknown at this time.
On July 14, 1993, the Company filed a lawsuit in US 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.
For a discussion of environmental proceedings, see "Environmental Matters" under Item 1, incorporated herein by reference. For a discussion of proceedings involving NSP's utility rates, see "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 1993 and 1992 and the dividends declared per share during those quarters:
1993 1992 High Low Dividends High Low Dividends
First Quarter $47 $42 1/4 $.630 $43 $39 1/4 $.605 Second Quarter 46 7/8 42 7/8 .645 42 38 1/2 .630 Third Quarter 47 7/8 44 3/4 .645 45 5/8 41 .630 Fourth Quarter 46 3/8 40 1/8 .645 45 3/8 41 5/8 .630
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 December 31, 1993, the payment of cash dividends on common stock was not restricted.
1993 1992 1991 1990 1989
Shareholders at year-end 86 404 72 525 72 704 73 867 75 396
Book value per share at year-end $27.32 $25.91 $25.21 $24.42 $23.76
Shareholders as of March 18, 1994 were 86,775.
Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations
Northern States Power Company, a Minnesota corporation (the Company), has one significant subsidiary, Northern States Power Company, a Wisconsin corporation (the Wisconsin Company), and several other subsidiaries, including Viking Gas Transmission Company (Viking) and NRG Energy, Inc. (NRG), both Delaware corporations. The Company and its subsidiaries collectively are referred to herein as NSP.
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 1993 and 1992 and should be read in connection with the Financial Statements and Notes thereto. Trends and contingencies of a material nature are discussed to the extent known and considered relevant.
Liquidity and Capital Resources
Financial Condition and Cash Flows - With rate increases granted in 1993, NSP's financial condition remained strong and its cash flows and earnings from operations improved from 1992, despite cooler-than-average summer weather. NSP's 1992 cash flows and earnings before accounting changes were significantly reduced by unusual weather, including the coolest summer in 77 years. The 1992 earnings included $45.5 million from a change in accounting for unbilled revenues, which did not affect cash flows or customer rates. During 1993, NSP continued to meet its long-range objectives for capital structure of approximately 45-50 percent common equity and 40-45 percent debt. The pretax interest coverage ratio before accounting changes, excluding AFC, was 3.9 in 1993 and 3.1 in 1992. NSP's objective range for interest coverage is 3.5-5.0.
Financing Requirements - NSP's need for capital funds is primarily related to the construction of plant and equipment to meet the needs of its electric and gas utility customers and to fund equity commitments or other investments in its non-regulated businesses. Total NSP capital expenditures (including AFC and excluding business acquisitions) were $362 million in 1993. Of that amount, $284 million related to replacements and improvements of NSP's electric system and $36 million involved construction of natural gas distribution facilities. Internally generated funds provided 99 percent of NSP's capital expenditures for 1993 and 85 percent of the $1.8 billion in capital expenditures incurred for the five-year period 1989-1993. NSP estimates that its utility capital expenditures will be $396 million in 1994. Of that amount, $316 million is scheduled for electric facilities and $43 million for natural gas facilities. Internally generated funds from utility operations are expected to provide approximately 80 percent of 1994 utility capital expenditures and approximately 95 percent of the $1.8 billion in utility capital expenditures estimated for the five-year period 1994-1998. These utility capital expenditure estimates include approximately $100 million of anticipated expenditures for pollution control facilities required under the Clean Air Act. In addition to utility capital expenditures, expected financing requirements for the 1994-1998 period include approximately $390 million to retire long-term debt and meet first mortgage bond sinking fund requirements.
NSP expects to obtain external capital for these requirements by issuing long-term debt, common stock and preferred stock. Utility financing requirements for the period 1994-1998 may be affected by factors such as load growth, changes in capital expenditure levels, rate increases allowed by regulatory agencies, new legislation, changes in environmental regulations and other regulatory requirements.
NSP expects to invest significant amounts in non-regulated projects, including domestic and international power projects. Projects currently being pursued include joint ventures to acquire electric generating plants in Australia and Germany, and open-cast coal mining operations in Germany. Non-regulated projects are expected to be financed primarily through project debt. The remaining project costs are expected to be funded through equity investments from NSP and other investors. Over the long-term, NSP's equity investments are expected to be financed through internally generated funds or NSP's issuance of common stock and debt. Although they 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 are estimated to be approximately $130 million in 1994 and approximately $540 million for the five-year period 1994-1998. These amounts include expected equity investments by NSP of approximately $60 million for the Australia project in 1994 and up to $100 million for the Germany projects through 1996.
In addition to capital expenditures, NSP invested $159 million in 1993 to acquire three energy-related businesses. (See Note 4 to the Financial Statements.) NSP continues to evaluate opportunities to enhance shareholder returns through business acquisitions. Long-term financing may be required for such acquisitions.
Financing Flexibility - 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 earn a fair return on investors' capital. Financing flexibility is enhanced by providing working capital needs and a high percentage of total capital requirements from internal sources, and having the ability, if necessary, to issue long-term securities and obtain short-term credit. 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, Aa2 by Moody's Investors Service, Inc., AA- by Duff & Phelps, Inc., and AA by Fitch Investors Service, Inc. Ratings for the Wisconsin Company's first mortgage bonds are generally comparable. These ratings reflect only the views of such organizations and an explanation of the significance of these ratings may be obtained from each agency. The Company's and the Wisconsin Company's first mortgage indentures place limits on the amount of first mortgage bonds that may be issued. The Minnesota Public Utilities Commission (MPUC) and the Public Service Commission of Wisconsin (PSCW) have jurisdiction over securities issuance. At Dec. 31, 1993, with an assumed interest rate of 8 percent, the Company could have issued about $1.8 billion of additional first mortgage bonds under its indenture and the Wisconsin Company could have issued about $280 million of additional first mortgage bonds under its indenture. NSP expects to maintain adequate access to long-term and short-term debt markets in 1994.
The Company registered $600 million of first mortgage bonds with the Securities and Exchange Commission (SEC) in December 1993. Depending on capital market conditions, the Company expects to issue approximately $450 million of this debt in 1994, primarily for refinancings, with the remainder issued over the next several years, for the purpose of raising additional capital or redeeming 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. The Company had approximately $106 million in commercial paper debt outstanding as of Dec. 31, 1993. The Company plans to keep its credit lines at or above the level of commercial paper borrowings. Commercial banks presently provide credit lines of approximately $215 million. 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, 1993, 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 1,650,000 shares of common stock under the Company's Dividend Reinvestment and Stock Purchase Plan, Executive Long-Term Incentive Award Stock Plan, and Employee Stock Ownership Plan (ESOP) as of Dec. 31, 1993. The Company may issue new shares or purchase shares on the open market for its stock plans. (See Note 6 to the Financial Statements for discussion of stock awards outstanding.) As discussed below, the Company issued new common stock in 1993 under a general stock offering and under its shareholder, employee and customer stock programs. At Dec. 31, 1993, the total number of common shares outstanding was 66,879,577. The Company does not plan any general stock offerings for 1994.
1993 Financing Activity - During 1993, NSP engaged in numerous financing activities. The Company issued 4,281,217 shares of common stock. Of these shares, 2.6 million were sold to a group of underwriters on May 20, 1993. The offering price to the public was $43.625 per share, with net proceeds of $110 million to the Company. Of the remaining new shares, 940,000 shares were issued under the Dividend Reinvestment and Stock Purchase Plan, 174,308 shares were issued under the Executive Long-Term Incentive Award Stock Plan and 566,909 shares were issued to the ESOP.
On Oct. 30, 1993, the Company redeemed all 350,000 shares of its $7.84 series Cumulative Preferred Stock at $103.12 per share, plus accrued dividends through Oct. 31, 1993.
During 1993, the Company issued $350 million, and the Wisconsin Company issued $150 million, of long-term debt to refinance higher rate debt, redeem preferred stock, repay scheduled maturities of debt and extend the term of short-term borrowings. In addition, $116 million of long-term debt was issued by subsidiaries to finance the acquisitions of Viking and the Minneapolis Energy Center. (See Note 4 to the Financial Statements.) In connection with the early redemption of $453 million of long-term debt, NSP incurred approximately $14 million in reacquisition premiums, which will be amortized over the term of the newly issued debt.
Results of Operations
NSP's results of operations during 1993 and 1992 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 are dependent on customer usage which varies with weather conditions, general business conditions, the state of the economy and the cost of energy services, the recovery of which is determined by various regulatory authorities. The historical and future trends of NSP's operating results have been and are expected to be impacted by the following factors:
Weather - NSP's earnings can be dramatically impacted by unusual weather. Mild weather, mainly a cool summer, reduced 1993 earnings by an estimated 18 cents. 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.
Operating Contingency - The Company is experiencing uncertainty regarding its ability to store used nuclear fuel from its Prairie Island nuclear generating facility. The facility stores its used nuclear fuel on an interim basis in a storage pool in the plant, pending the availability of a U. S. Department of Energy high-level radioactive waste storage or permanent disposal facility, or a private interim storage facility. At current operating levels, the pool will be filled in 1994 so the Company has proposed to augment Prairie Island's interim storage capacity by using steel containers for dry storage of used nuclear fuel on the plant site. Without additional onsite storage or significant modification of normal plant operations, Prairie Island Unit 2 would be shutdown in May 1995 and Prairie Island Unit 1 would be shutdown in February 1996. These two units supply about 20 percent of the Company's output. The Company has obtained a Certificate of Need from the MPUC allowing use of a limited number of steel containers, providing adequate storage at least through the year 2001. The Nuclear Regulatory Commission has also issued a license approving a dry storage facility on the plant site for Prairie Island's used fuel. However, in June 1993, the Minnesota Court of Appeals decided that the additional temporary storage facilities must be approved by the Minnesota Legislature. The Company has requested such approval from the Legislature and expects a decision on this issue during the current session, which began on Feb. 22, 1994. Although hearings have begun, the Company cannot predict what action the Minnesota Legislature will take. If operations at Prairie Island cease, the Company estimates that the present value of the cost of supplying replacement power and recovering its investment in the plant and unrecognized decommissioning costs will be $1.8 billion. The Company would request recovery of these costs, including a return on its investment, through utility rates. However, at this time the need for such costs and the regulators' ultimate response to such a request is unknown. (See Note 15 to the Financial Statements regarding the possible effects on operating results of the potential shutdown of the Company's Prairie Island nuclear power generating facility.)
Regulation - NSP's utility rates are approved by the Federal Energy Regulatory Commission (FERC) and state commissions. Rates are designed to recover plant and operating costs and an allowed return, using an annual period upon which rate case filings are based. NSP's utility companies request increases in customers' rates as needed and file them with the governing commissions. The rates charged to retail customers in Wisconsin are reviewed and adjusted biennially. Because rate increases are not requested annually in Minnesota, NSP's primary jurisdiction, the impact of inflation on operating costs continues to be a factor affecting 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 power 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 programs and demand-side management efforts.
Rate Increases - During 1992 and 1993, 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 wholesale customers in Minnesota and Wisconsin. These rate changes increased 1993 revenues by approximately $83 million; the full impact of these increases will be realized in 1994. On Jan. 31, 1994, three intervenors filed an appeal of the MPUC's decision concerning the method of calculating the rate of return on common equity granted in the Minnesota electric and gas rate cases. The amount at issue is approximately $7 million in annual revenues for the Company. (See Note 2 to the Financial Statements for further discussion of 1993 rate case results.)
In 1993, NSP filed for 1994 rate increases for North Dakota retail electric and Wisconsin retail gas customers. NSP received approval for approximately $2.6 million of rate increases in these two jurisdictions, effective January 1994. No significant rate filings in other jurisdictions are expected for 1994.
Acquisitions - NSP made three strategically important business acquisitions in 1993. These include a gas pipeline, an energy services marketing business, and a steam heating and chilled water cooling system business. (See Note 4 to the Financial Statements for more discussion of these acquisitions, including the pro forma results of these acquisitions on an annual basis.)
Competition - The Energy Policy Act of 1992 (the Act) is expected to bring comprehensive and significant changes to the electric utility industry. Many provisions of the Act are expected to increase competition in the industry in the next few years. The Act's reform of the Public Utility Holding Company Act (PUHCA) promotes creation of wholesale power generators and authorizes the 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. Other producers may compete for NSP's customers as a result of such PUHCA reform. Management believes this legislation will promote the continued trend of increased competition in the electric energy markets.
Many states are considering proposals to require "retail wheeling", which is the delivery of power generated by a third party to retail customers. Retail wheeling represents yet another development of a competitive electric industry. NSP management plans to continue its efforts to be a low-cost supplier of electricity and an active participant in the competitive market for electricity.
During 1992 and 1993, the FERC issued a series of orders (together called Order 636) addressing interstate natural gas pipeline service restructuring. This restructuring will "unbundle" each of the services - sales, transportation, storage and ancillary services - traditionally provided by the 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. NSP believes some uncertainty remains as to whether the new unbundled services under Order 636 will prove to be as reliable and flexible as the traditional sales service. The implementation of Order 636 also will apply 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 will be allowed to recover, subject to negotiations with customers, 100 percent of prudently incurred transition costs attributable to Order 636 restructuring. Although negotiations are in process, NSP estimates that it will be responsible for less than $10 million of transition costs, over a proposed five-year period. NSP's regulatory commissions have previously approved recovery of similar restructuring charges in retail gas rates. 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 (as discussed in Note 4 to the Financial Statements) have enhanced the ability to participate in the more competitive gas transportation business. In implementing Order 636, Viking incurred no restructuring costs.
Impact of Non-Regulated Investments - NSP expects to invest significant amounts in non-regulated projects, including domestic and international power production projects through NRG, as described previously under "Financing Requirements". Depending on the success and timing of involvement in these projects, NSP's non-regulated earnings are expected to increase materially in the next few years. However, the projects generating the increased earnings may present additional risk. Current and future investments in international projects are subject to uncertainties prior to final legal closing, and continuing operations are subject to foreign government and partnership actions. NRG plans to hedge its exposure to currency fluctuations to the extent permissible by hedge accounting requirements. NRG will use well-established financial instruments of sufficient credit quality to protect the economic value of foreign-currency denominated assets. (With respect to risk of potential losses from unsuccessful non-regulated projects, see Note 1 to the Financial Statements for discussion of capitalized expenditures for projects under development.)
Employee Compensation and Benefits - In 1993, NSP conducted an extensive review of its employee compensation and benefits, and retiree benefits. As a result, several changes will be implemented, commencing in 1994, that will support NSP's goal of providing market-based compensation and benefits. These changes, which include no base wage increase for non-union employees in 1994, are expected to keep compensation and benefit costs comparable to 1993 levels. NSP's labor agreements with its five local unions expired on Dec. 31, 1993. An interim agreement with the unions expires March 31, 1994. Although NSP's final offer for settlement (made on Feb. 4, 1994) was rejected by the union membership on March 14, 1994 and an authorization to strike was approved, the parties resumed discussions on March 21, 1994. NSP is not able to predict the outcome of negotiations at this time.
Environmental Matters - Like other utilities, the Company has been named as a potentially responsible party at eight waste disposal sites and is in the process of investigating the remediation of 14 former coal-gasification and other sites. The Company has recorded an estimate of the probable costs to be incurred in connection with remediation of these sites. To the extent costs are not recovered from insurers or other parties, the Company expects to seek recovery of such costs in future ratemaking proceedings.
In general, NSP has been experiencing a trend toward more environmental monitoring and compliance costs. This trend has caused and may continue to cause slightly higher operating expenses and capital expenditures. The timing and amount of environmental costs, including those for site remediation, are currently unknown. In 1993, 1992 and 1991, the Company spent about $15 million, $20 million and $6 million, respectively, for capital expenditures on environmental improvements at utility facilities. The Company expects to incur approximately $9 million in capital expenditures for compliance with environmental regulations in 1994. (See Note 15 to the Financial Statements for further discussion of these and other environmental contingencies that could affect NSP.)
Wholesale Customers - In 1992, nine of the Company's 19 municipal wholesale electric customers created a joint action municipal power agency to serve their future power supply needs and notified the Company of their intent to terminate their power supply agreements with the Company effective in July 1995 or July 1996. These nine customers currently represent approximately $24 million in annual revenues and a maximum demand load of approximately 150 megawatts.
In 1992 and 1993, the Company signed long-term power supply agreements with the remaining 10 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 $8 million in current annual revenue and a maximum demand load of approximately 55 megawatts. The rates contained in the agreements were accepted by the FERC on Feb. 23, 1994.
During October 1993, the Company signed an electric power agreement to provide Michigan's Upper Peninsula Power Company (UPPCO) with up to 90 megawatts of baseload service, peaking service options and load regulation service options for 20 years beginning in 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. The rates, terms and conditions of the agreement are subject to FERC approval. The Michigan Public Utilities Commission must also approve the transaction. Beginning in 1998, annual revenues of approximately $12 million-$16 million are expected to be provided under the agreement, depending on contract options that UPPCO can exercise.
Legislative Changes - The Omnibus Budget Reconciliation Act of 1993 (the Act) was signed into law on Aug. 10, 1993. The only provision of the Act that had a significant effect on NSP was the increase in the federal corporate income tax rate from 34 percent to 35 percent retroactive to Jan. 1, 1993. The effect of the higher tax rate was an increase of about $3.2 million in income tax expense. Most of this cost increase was offset by higher revenues from 1993 rate increases approved in Minnesota. (See Note 2 to the Financial Statements.) Deferred tax liabilities were increased for the rate change by approximately $32 million. However, due to regulatory deferral of utility tax adjustments, earnings were reduced only by immaterial adjustments to deferred tax liabilities for non-regulated operations.
Wind-Generated Power - In October 1993, the Company signed a 25-year agreement for the purchase of 25 megawatts of wind-generated electric capacity, and associated energy to be produced in Minnesota. The wind generating plant is expected to be fully operational by May 1994. This contract is the first phase of the Company's plan to obtain 100 megawatts of wind-generated electricity by 1997. The Company can recover the cost of energy purchases through cost-of-energy adjustment clauses in electric rates.
Accounting Changes - As discussed in Note 13 to the Financial Statements, in 1993, NSP adopted Statement of Financial Accounting Standards (SFAS) No. 106 - - Employers' Accounting for Postretirement Benefits Other than Pensions and began recording postretirement 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 above, NSP's utility companies obtained rate recovery for substantially all of the increased costs (approximately $20 million) accrued under 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. Recent changes in interest rates have resulted in different actuarial assumptions used in the benefit cost calculations for postretirement benefits. Due to offsetting changes in other actuarial assumptions and demographics, NSP's benefit costs for such plans are not expected to increase from these changes in 1994. (See Note 13 to the Financial Statements for more information on changes in actuarial assumptions.)
NSP also adopted in 1993 SFAS No. 109 - Accounting for Income Taxes. Because the provisions of SFAS No. 109 are not materially different than the tax accounting procedures previously used by NSP, there was virtually no impact on earnings or financial condition.
In 1992, the Company changed its accounting method for recognizing revenue. Earnings in 1992 increased by 88 cents per share, including 73 cents related to prior years, from recording estimated unbilled revenues for utility service in Minnesota, North Dakota and South Dakota. (See Note 3 to the Financial Statements for more information on the effects of this accounting change.)
In 1994, NSP will be required to adopt SFAS No. 112 - Employers' Accounting for Postemployment Benefits. This standard will require the accrual of certain postemployment costs (such as injury compensation and severance) that are payable in future periods. The impact of adopting SFAS No. 112 is expected to be immaterial.
The Financial Accounting Standards Board (FASB) has announced preliminary plans to change the accounting for stock compensation expense effective in 1997 with disclosure requirements effective in 1994. Also, the FASB has approved a proposed change in employers' accounting for employee stock ownership plans effective in 1994. Based on NSP's review of these future accounting changes, NSP does not expect a material impact on its results of operations or financial condition.
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 FERC and the SEC currently are evaluating the financial presentation of these obligations, which could require a reporting reclassification as early as 1994.
1993 Compared with 1992 and 1991
NSP's 1993 earnings per share were $3.02, up 71 cents from the $2.31 earned before accounting changes in 1992 and equal to the $3.02 earned from continuing operations in 1991. In addition to the revenue and expense changes discussed below, 1993 earnings were impacted by a higher average number of common and equivalent shares outstanding for earnings-per-share calculations in 1993 due to the stock issuances discussed previously under "1993 Financing Activity."
Electric Revenues and Production Expenses
Revenues - Sales to retail customers, which account for more than 90 percent of NSP's electric revenue, increased 4.0 percent in 1993 and decreased 2.3 percent in 1992. Cool summer weather reduced sales in 1992 and, to a lesser extent, in 1993. During 1993, NSP added 14,353 retail customers, a 1.1-percent increase. Total sales of electricity, including wholesale, increased 7.3 percent in 1993.
On a weather-adjusted basis, sales to retail customers are estimated to have increased 2.1 percent in 1993 and 2.8 percent in 1992. Retail sales growth for 1994 is estimated to be 3.4 percent over 1993, or 2.2 percent on a weather-adjusted basis.
Sales to other utilities increased 22.2 percent in 1993 due to higher demand from utilities in flood-stricken Midwestern states.
The table below summarizes the principal reasons for the electric revenue changes during the past two years.
(Millions of dollars) 1993 vs 1992 1992 vs 1991 Retail sales growth (excluding weather impacts) $32 $34 Estimated impact of weather on retail sales volume 34 (85) Rate changes 74 20 Sales to other utilities 20 (2) Cost of energy clauses and other (8) (7) Total revenue increase (decrease) $152 $(40)
The 1992 sales growth is net of a $1.4-million revenue decrease, and 1992 cost-of-energy clause change is net of an $11 million revenue increase from recording unbilled revenues, which were not recorded in 1991.
Electric Production Expenses - Fuel expense for electric generation increased $19.4 million, or 6.6 percent, in 1993, compared with a decrease of $20.4 million, or 6.5 percent, in 1992. Total output from NSP's generating plants increased 8.4 percent in 1993 and decreased 3.1 percent in 1992. The fuel expense increase in 1993 was due to higher output to meet sales demand, partially offset by lower cost of fuel. The fuel expense decrease in 1992 was due to lower output (because the cool summer reduced demand) and lower cost of fuel. The lower cost of fuel per megawatt hour of generation in 1993 and 1992 reflects the increased use of low-cost purchases as discussed below.
Purchased power costs increased $53.0 million, or 34.1 percent, in 1993 and $20.0 million, or 14.7 percent, in 1992. The increase in 1993 was largely due to a demand expense increase of $42 million for the capacity charges from the power purchase agreements with Manitoba Hydro-Electric Board (MH), as discussed in Note 15 to the Financial Statements. Energy purchased from other utilities increased in both 1993 and 1992 due to economically priced energy available to meet growing retail demand and sales opportunities to other utilities that provided net ratepayer benefit. Demand expenses in 1994 are expected to increase $22 million over 1993 levels due to the MH agreements.
Revenues are adjusted for changes in electric 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 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.
Gas Revenues and Purchases
Revenues - NSP categorizes gas sales as firm (primarily space heating customers) and interruptible (commercial/industrial customers with an alternate energy supply). Firm sales in 1993 increased 17.0 percent over 1992 sales, while firm sales in 1992 decreased 5.6 percent from 1991. Warm weather in the first quarter of 1992 is the main cause for both of these variations. NSP added 11,728 firm gas customers in 1993, a 3.1-percent increase.
On a weather-adjusted basis, firm sales are estimated to have increased 7.2 percent in 1993 and 3.6 percent in 1992. NSP estimates 1994 firm gas sales to decrease by 2.9 percent relative to 1993, with a 2.2-percent decrease on a weather-adjusted basis due to an unbilled revenue adjustment in 1993. Without this adjustment, estimated weather-adjusted firm gas sales would have increased 0.9 percent in 1993 and would be estimated to increase 0.7 percent in 1994.
Interruptible gas deliveries, including sales of gas purchased for resale and customer-owned gas that NSP transported, increased 15.3 percent in 1993 and decreased 0.9 percent in 1992.
The table below summarizes the principal reasons for the gas revenue changes during the past two years.
(Millions of dollars) 1993 vs 1992 1992 vs 1991 Sales growth $17 $7 Estimated impact of weather on sales volume 28 (24) Acquisition of Viking Gas 9 Rate changes 9 Purchased gas adjustment and other 30 15 Total revenue increase (decrease) $93 $(2)
The 1992 sales growth is net of a $1.5-million decrease from recording unbilled revenues, which were not recorded in 1991.
Purchased Gas - The cost of gas purchased and transported increased $61.7 million, or 28.0 percent, in 1993 due to higher sendout and higher purchased gas prices. In 1992, the cost of gas purchased and transported increased $9.0 million, or 4.3 percent, due to higher purchased gas prices, somewhat offset by lower sendout relative to 1991. The average cost per thousand cubic feet (mcf) of gas sold in 1993 was 13.3 percent higher than it was in 1992, when the cost was 7.1 percent higher than it was in 1991. NSP views the increases in 1992 and 1993 as a recovery from unsustainably low wellhead gas prices in the 1990-91 period. Revenues are adjusted for changes in purchased gas costs from amounts currently included in approved base rates through purchased gas adjustment clauses.
Other Operating Expenses and Factors
Other Operation, Maintenance and Administrative and General - These expenses, in total, decreased by $27.2 million, or 4.0 percent, compared with an increase of 1.8 percent in 1992. The 1993 decrease was the result of fewer scheduled plant maintenance outages, reduced employee levels and lower administrative costs. The 1992 increase was the result of higher levels of scheduled plant and distribution system maintenance and higher employee wages. Wages in 1993 included an accrual of $14 million for incentive compensation. Due to lower earnings as a result of mild weather, compensation in 1992 did not include incentive amounts. (See Note 7 to the Financial Statements for a summary of administrative and general expenses.)
Conservation and Energy Management - Costs in 1993 were higher than in 1992 and 1991 because NSP's regulators have approved higher expenditure levels for conservation and demand-side management efforts.
Depreciation and Amortization - The increases in depreciation for all periods reflect higher levels of depreciable plant and, in 1993, changes in the depreciable lives of certain property. (See Note 1 to the Financial Statements.)
Property and General Taxes - Property and general taxes increased in each of the reported periods primarily as a result of higher property tax rates and property additions. Property taxes in 1992 were reduced by $4.5 million due to revisions to accrued 1991 taxes (payable in 1992) based on final tax statements.
Income Taxes - The variations in income taxes are primarily 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 9 to the Financial Statements for a detailed reconciliation of the statutory tax rate to the actual effective tax rate.)
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 low-cost short-term borrowings.
Other Income and Deductions-Net - Other income and deductions increased $9.7 million in 1993 and decreased $0.8 million in 1992. The increase in 1993 was due to higher non-regulated operating income from improved refuse-derived fuel (RDF) operations and acquired businesses. Non-regulated operating income in 1992 reflects one-time expenses from unsuccessful energy projects and reduced profitability of RDF operations. Decreases in interest income and non-regulated operating income in 1992 were offset by lower expenses for regulatory compliance and legal contingencies. Interest income declined in 1992 due to decreases in the amount of investments held. (See Note 7 to the Financial Statements for a summary of amounts included in other income and deductions.)
Interest Charges - Interest on long-term debt increased in 1993 due to new debt issued to finance business acquisitions and to refinance short-term borrowings. The increase was partially offset by interest savings from refinancing debt at lower rates. Other interest charges have increased due to amortization of refinancing costs, including debt issuance costs and reacquisition premiums.
Item 8 - Financial Statements and Supplementary Data
See Item 14(a)-1 in Part IV for financial statements included herein.
See Note 17 of Notes to Financial Statements for summarized quarterly financial data.
INDEPENDENT AUDITORS' REPORT
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. Our audits also included the financial statement schedules listed in the accompanying table of contents in Item 14(a)2. 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, 1993 and 1992 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As discussed in Note 3 to the consolidated financial statements, the Companies changed their method of accounting for postretirement health care costs in 1993 and revenue recognition in 1992.
(Deloitte & Touche) DELOITTE & TOUCHE Minneapolis, Minnesota February 7, 1994
Notes to Financial Statements
1. Summary of 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 significant subsidiary companies. All significant intercompany transactions and balances have been eliminated in consolidation. The Company and its subsidiaries collectively are referred to herein as NSP.
Revenues - Revenues are recognized based on services provided to customers each month. Because customer utility 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. In 1991, revenues of the Company were recorded for billings rendered to customers on a monthly cycle billing basis and estimated unbilled revenues were not recorded. (See Note 3 for discussion of accounting change in 1992.)
The Company's rate schedules, applicable to substantially all of its customers, include cost-of-energy adjustment clauses, under which rates are adjusted to reflect changes in average costs of fuels, purchased power 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 power. 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 for construction, to qualified Construction Work in Progress (CWIP). The rates were 7.4 percent in 1993, 8.0 percent in 1992 and 10.0 percent in 1991. The amount of AFC capitalized as a construction cost in CWIP is credited to other income and interest charges. AFC amounts capitalized in CWIP are included in utility rate base for establishing utility service rates.
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 1993 study, as approved by the MPUC, recommended an increase of approximately $0.9 million in annual depreciation accruals. The 1992 study, as approved by the MPUC, recommended no change in 1992 depreciation. The Company also submitted in 1993 an average service life filing for transmission, distribution and general properties, which is filed every five years. The filing, as approved by the MPUC, increased depreciation by approximately $4.7 million from 1992 levels. Depreciation provisions, as a percentage of the average balance of depreciable property in service, were 3.47 percent in 1993, 3.36 percent in 1992 and 3.35 percent in 1991.
Decommissioning - The annual provision for the estimated decommissioning costs for the Company's nuclear plants has been calculated using an internal/external sinking fund method. The calculation, which results in annual charges to depreciation expense, is designed to provide for full accrual and rate recovery of the future decommissioning costs, including reclamation and removal, over the estimated operating lives of the Company's nuclear plants. Decommissioning of all nuclear facilities is planned to occur in the years 2010-2022 using the prompt dismantlement method, and the total obligation for decommissioning is expected to be funded approximately 45 percent by internal funds and 55 percent by external funds. Based on a 1990 study, the Company estimates total decommissioning costs will approximate $750 million in 1993 dollars, for which the Company has recorded $302 million in the accumulated provision for depreciation; $101 million of this balance has been deposited in external trust funds. An updated study will not be used for recording decommissioning accruals until approved by the MPUC. Such approval is not expected to occur until after the Minnesota Legislature makes its decision on fuel storage at the Company's Prairie Island nuclear plant. (See Note 15.) Decommissioning costs recorded for 1993, 1992 and 1991 were $43 million, $40 million and $40 million, respectively.
Nuclear Fuel Expense - The original cost of nuclear fuel is amortized to fuel expense on the basis of energy expended. Nuclear fuel expense also includes a disposal cost of 0.1 cent per kilowatt-hour sold from nuclear generation, as required by the Nuclear Waste Policy Act of 1982. Disposal expenses were $8.7 million, $6.8 million and $11.9 million for 1993, 1992 and 1991, respectively. Disposal expenses reflect reductions of $2.6 million in 1993 and $3.7 million in 1992 due to a change in the basis of charging customers, retroactive to 1983. Nuclear fuel expense in 1993 also includes about $1 million for a portion of the assessment from the U.S. Department of Energy (DOE) for the decommissioning and decontamination of the DOE's uranium enrichment facility. (See Note 8.)
Environmental Costs - Costs related to environmental remediation are accrued 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 benefit future operations. Where the expenditure relates to facilities currently in use (such as pollution control equipment), the costs are capitalized and depreciated over the future service periods. Estimated costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience. Accrued obligations are regularly adjusted as new information is received. 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. SFAS No. 109 requires the use of the liability method of accounting for deferred income taxes. Before 1993, NSP followed SFAS No. 96 - Accounting for Income Taxes, resulting in substantially the same accounting as 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 results in the creation of certain regulatory assets and liabilities related to income taxes as discussed in Note 8.
Investment tax credits are deferred and amortized over the estimated lives of the related property.
Cash Equivalents - NSP considers investments in certain debt instruments (primarily commercial paper) with a remaining 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 being amortized consistent with ratemaking treatment as established by regulators. Note 8 describes in more detail the nature and amounts of these regulatory deferrals.
Other Assets - NSP and its various subsidiaries have invested in many non-regulated projects whose earnings are reported on the equity method of accounting. Several of these projects are still in the development stage. Other investments include project development expenditures of $16.5 million as of Dec. 31, 1993, which have been capitalized based on expected recovery from cash flows of future project operations.
The purchase of the Minneapolis Energy Center by NRG in 1993 (see Note 4) at a price exceeding the underlying fair value of net assets acquired resulted in goodwill. This goodwill and other intangible assets acquired are being amortized using the straight-line method over 30 years. NSP will periodically evaluate 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 $12.6 million at Dec. 31, 1993, which are being amortized over the remaining maturity period of the related debt.
Reclassifications - Certain reclassifications have been made to the 1992 and 1991 income statement to conform with the 1993 presentation. In addition, the 1992 balance sheet has been reclassified to conform with the 1993 presentation of regulatory deferrals. These reclassifications had no effect on net income or earnings per share.
2. Rate Matters - 1993 Rate Increases
Minnesota Jurisdiction - In November 1992, the Company filed applications for 1993 rate increases with the MPUC totaling $119.1 million and $14.9 million for Minnesota retail electric and natural gas customers, respectively. This represented annual increases of approximately 9 percent and 5.8 percent, respectively. In December 1992, the MPUC issued orders granting interim increases (subject to refund) of $71.2 million (5.4 percent) for electric service and $8.4 million (3.3 percent) for gas service, effective Jan. 1, 1993. In June 1993, the Company adjusted its proposed electric rate increase to $112.3 million and its gas rate request to $12.4 million.
The Company received initial orders from the MPUC in September 1993 for both the gas and electric cases. Final orders came in December 1993 for the gas case and in January 1994 for the electric case, allowing annualized retail rate increases of $10.0 million (3.9 percent) for gas and $72.2 million (5.4 percent) for electric. The return on equity granted in both cases was 11.47 percent. Refunds of interim electric rates collected are required in the amount of approximately $12 million and are expected to be paid in May 1994. No refunds of interim gas rates collected are required. Final gas and electric rates are expected to be implemented in March and April 1994, respectively.
On Jan. 31, 1994, an appeal of the MPUC's determination on the allowed return on equity was filed with the Minnesota Court of Appeals by the Minnesota Department of Public Service, the Office of the Minnesota Attorney General and the Minnesota Energy Consumers intervenor groups. The appeal concerns the method of calculating the rate of return on common equity for both the electric and gas cases. The amount at issue is approximately $7 million in annual revenues for the Company. The ultimate financial impact of this appeal, if any, is not determinable at this time. A decision by the court is expected by the end of 1994.
Other Jurisdictions - The Wisconsin Company received approval of annualized retail rate increases of $8.0 million (3.1 percent) for Wisconsin electric customers and $1.1 million (1.8 percent) for Wisconsin gas customers. The new rates have been in effect since January 1993. The Company's approved annualized rate increase of $4.8 million (5.3 percent) for North Dakota electric customers was effective April 21, 1993. The Company's approved annualized rate increase of $4.2 million (6.5 percent) for South Dakota electric customers has been in effect since May 1, 1993. Increased annualized wholesale electric rates of $0.9 million (3.6 percent) were accepted by the FERC for nine Minnesota Company wholesale customers, effective Sept. 21, 1993. Increased annualized wholesale electric rates of $0.6 million (3.7 percent) were accepted by the FERC for the Wisconsin Company's 10 wholesale municipal utilities effective Sept. 1, 1993.
3. Accounting Changes
Postretirement Benefits - (See Note 13 for discussion of NSP's 1993 change in accounting for postretirement medical and death benefits.) There was no material effect on net income due to rate recovery of the expense increases. 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.
Income Taxes - As discussed in Note 1, NSP adopted SFAS No. 109 - Accounting for Income Taxes, effective Jan. 1, 1993. Adoption of SFAS No. 109 had no effect on earnings or financial condition due to its similarity to SFAS No. 96 - Accounting for Income Taxes, which NSP adopted in 1988 and which SFAS No. 109 supersedes.
Revenue Recognition - Effective Jan. 1, 1992, the Company changed its revenue recognition method to include the accrual of estimated unbilled revenues for electric and gas service in its Minnesota, North Dakota and South Dakota operations. This accounting practice has been used by the Wisconsin Company since 1977. This change resulted in a better matching of revenues and expenses, and is consistent with predominant utility industry practice and the ratemaking principles in NSP's two major jurisdictions (Minnesota and Wisconsin). The effect on 1992 income before accounting changes was an increase of approximately $9.8 million (16 cents per share), while the effect on total 1992 earnings was an increase of approximately $55.3 million (88 cents per share). If the accounting change had been applied retroactively to Jan. 1, 1991, income from continuing operations for 1991 would have been $204.4 million ($2.98 per share).
1994 Changes - In 1994, NSP will adopt SFAS No. 112 - Accounting for Postemployment Benefits and a new accounting standard for employers' transactions with ESOP plans. SFAS No. 112 requires the accrual of certain employee costs (such as injury compensation and severance) to be paid in future periods. The adoption of these new accounting standards is not expected to have a material effect on NSP's results of operations or financial condition.
4. Business Acquisitions
Viking Gas Transmission Company - On June 10, 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, for approximately $45 million, $32 million of which was financed with project debt. 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. Viking presently 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 the FERC.
Minneapolis Energy Center - On Aug. 20, 1993, NRG Energy, Inc. (NRG), a wholly owned subsidiary of the Company, acquired the assets of the Minneapolis Energy Center (MEC), a district heating and cooling system in downtown Minneapolis, Minn. The system uses steam and chilled water generating facilities to heat and cool buildings for about 85 heating and 25 cooling customers. The purchase price was $110 million, $84 million of which was financed with project debt. The purchase price primarily included facilities, long-term service agreements and goodwill.
Cenergy, Inc. - On Oct. 1, 1993, Cenergy, Inc., a non-regulated subsidiary of the Company, acquired certain assets of Centran Corporation (Centran), a natural gas marketing company. Cenergy, Inc., a national marketer of energy services with approximately 30 employees and approximately 300 customers, is headquartered in Minneapolis, Minn., and has additional offices in Houston and Corpus Christi, Texas; Louisville, Ky.; and Chesapeake, Va. The purchase price was $4 million. Assets purchased included proven oil and gas reserves, office equipment and a customer marketing data base.
Operating Results - The following represents unaudited operating results presented on a pro forma basis as if the acquisitions described above occurred on Jan. 1, 1992. Actual results, including Viking since June 10, 1993, MEC since Aug. 20, 1993, and the acquired Centran operations since Oct. 1, 1993, are shown for comparative purposes.
Year Ended Dec. 31 (Dollars in millions except EPS) 1993 1992
Actual Results Utility operating revenues $2 404.0 $2 159.5 Non-regulated operating revenues and sales $90.7 $62.6 Net income $211.7 $206.4 Earnings per share $3.02 $3.04
Pro Forma Amounts Utility operating revenues $2 411.9 $2 176.0 Non-regulated operating revenues and sales $161.2 $272.6 Net income $212.6 $204.9* Earnings per share $3.04 $3.01*
*Includes pretax writedown of $2.3 million (2 cents per share) of deferred environmental costs for Viking.
5. Cumulative Preferred Stock
The Company has two series of adjustable rate preferred stock. The dividend rates are calculated quarterly and based on prevailing rates of certain taxable government debt securities indices. At Dec. 31, 1993, the annualized dividend rates were $5.50 for series A and $5.50 for series B.
At Dec. 31, 1993, 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.
6. 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, 1993, the payment of cash dividends on common stock was not restricted.
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 other awards for restricted stock, stock appreciation rights and other performance awards. Performance awards are valued in dollars, but are paid in shares based on market price at the time of payment. Transactions under the various stock incentive programs, which may result in the issuance of new shares, were as follows:
Stock Awards (Thousands of shares) 1993 1992 1991
Outstanding Jan. 1 528.7 403.3 161.0 Options granted 196.9 201.8 232.2 Other stock awards 9.5 .8 16.9 Options and awards exercised (174.3) (57.0) 0 Options and awards forfeited (22.2) (20.1) (6.8) Other (1.5) (.1) 0 Outstanding at Dec. 31 537.1 528.7 403.3 Option price ranges: Unexercised at Dec. 31 $33.25-$43.50 $33.25-$40.94 $33.25-$36.44 Exercised during the year $33.25-$40.94 $33.25-$36.44
Using the treasury stock method of accounting for outstanding stock options, the weighted average number of shares of common stock outstanding for the calculation of primary earnings per share includes any dilutive effects of stock options and other stock awards as common stock equivalents. The differences between shares used for primary and fully diluted earnings per share were not material.
7. Detail of Certain Income and Expense Items
Administrative and general (A&G) expense for utility operations consists of the following:
(Thousands of dollars) 1993 1992 1991
A&G salaries and wages $52 085 $49 096 $48 710 Pensions and benefits - all utility employees 63 938 65 278 58 306 Information technology, facilities and administrative support 30 504 35 139 33 698 Insurance and claims 18 598 20 512 21 404 Other 17 410 17 950 17 742 Total $182 535 $187 975 $179 860
Other income and deductions - net consist of the following:
(Thousands of dollars) 1993 1992 1991
Non-regulated operations: Operating revenues and sales $90 654 $62 616 $76 342 Operating expenses (excluding income taxes) 81 403 65 744* 69 327 Pretax operating income (loss) 9 251 (3 128) 7 015 Interest and investment income 4 522 3 452 6 489 Equity in earnings of non-regulated projects 3 030 2 382 226 Charitable contributions (4 752) (4 585) (4 231) Costs disallowed recovery by regulators (296) (1 603) (6 100) Legal and regulatory contingencies (100) (1 300) (5 100) Other - net (excluding income taxes) (643) (752) (494) Income tax (expense) benefit (2 394) 4 493 1 905 Total $8 618 $(1 041) $(290)
*Includes $6.8 million in writedowns and losses from unsuccessful non-regulated projects.
8. Regulatory Assets and Liabilities
The following summarizes the individual components of unamortized regulatory assets and liabilities shown on the Balance Sheet at Dec. 31:
(Thousands of dollars) 1993 1992
AFC recorded in plant on a net-of-tax basis $165 915 $164 740 Losses on reacquired debt 48 529 33 185 Conservation and energy management programs 46 939 25 754 Environmental costs 45 568 505 Deferred postretirement benefit costs 15 514 2 112 State commission accounting adjustments 6 246 5 954 Unrecovered purchased gas costs and other 5 643 7 237 Total regulatory assets $334 354 $239 487 Excess deferred income taxes collected from customers $113 276 $106 975 Investment tax credit deferrals 120 123 119 847 Pension costs 6 969 2 017 Fuel refunds and other 3 512 3 627 Total regulatory liabilities $243 880 $232 466
The environmental costs item includes an assessment from the DOE for the Company's allocated share of decontamination and decommissioning costs related to the DOE's uranium enrichment facility. The Company's total DOE assessment of $46 million was made in 1993. This assessment will be payable in annual installments (currently $3.1 million) for up to 15 years and will be expensed on a monthly basis in the 12 months following each payment. 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 fully conform to the FERC's cost-of-energy adjustment clause procedures, management also expects recovery of these DOE assessments in retail ratemaking as payments are made each year.
The AFC regulatory asset and the tax-related regulatory liabilities result from NSP's income tax accounting practices as discussed in Note 1. The excess deferred income tax liability represents the net amount expected to be reflected in future customer rates based on the collection in prior ratemaking of deferred income tax amounts in excess of the actual liabilities recorded by NSP. This excess is the net effect of the use of flow-through tax accounting in prior ratemaking and the impact of changes in statutory tax rates in 1981, 1986-87 and 1993. This regulatory liability will change each year as the related deferred income tax liabilities change.
9. 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 1993 and 34 percent in 1992 and 1991) to net income before income tax expense. The reasons for the difference are as follows:
(Thousands of dollars) 1993 1992 1991
Tax Computed at Statutory Federal Rate $119 868 $84 015 $118 829 Increases (decreases) in tax from: State income taxes net of federal income tax benefit 20 838 13 421 20 822 Tax credits recognized (9 545) (8 846) (9 511) Nontaxable AFC - equity included in book income (2 565) (3 058) (2 562) Net-of-tax AFC included in book depreciation 4 403 4 518 4 594 Use of the flow-through method for depreciation in prior years 7 004 5 884 6 163 Effect of tax rate changes for plant-related items (4 648) (5 202) (6 798) Dividends paid on ESOP shares (3 009) (3 245) (3 199) Other - net (1 606) (1 311) (2 888) Total income tax expense from operations $130 740 $86 176 $125 450 Effective federal and state income tax rate 38.2% 34.9% 35.9% Composite federal and state statutory tax rate 40.9% 39.9% 39.9% Income taxes are comprised of the following expense (benefit) items: Included in utility operating expenses: Current federal tax expense $92 099 $69 198 $72 197 Current state tax expense 25 787 18 535 21 081 Deferred federal tax expense 15 010 8 518 25 157 Deferred state tax expense 4 431 2 533 7 779 Tax credits recognized (8 981) (8 115) (8 878) Total 128 346 90 669 117 336 Included in other income and expense: Current federal tax expense 7 853 1 490 3 708 Current state tax expense 2 289 613 1 128 Deferred federal tax expense (6 736) (4 518) (5 580) Deferred state tax expense (449) (1 347) (850) Tax credits recognized (563) (731) (311) Total 2 394 (4 493) (1 905) Included in discontinued operations: Current federal tax expense - operations 129 Current federal tax expense - gain 10 193 Current state tax expense - operations 28 Current state tax expense - gain 2 921 Deferred federal tax expense (2 271) Deferred state tax expense (539) Tax credits recognized (442) Total 10 019 Total income tax expense from operations $130 740 $86 176 $125 450
The components of NSP's net deferred tax liability at Dec. 31 were as follows:
(Thousands of dollars) 1993 1992 Deferred tax liabilities: Differences between book and tax bases of property $792 542 $765 957 Regulatory assets 128 991 90 856 Tax benefit transfer leases 87 924 97 852 Other 7 050 5 791 Total deferred tax liabilities $1 016 507 $960 456 Deferred tax assets: Regulatory liabilities $95 504 $92 165 Deferred investment tax credits 73 648 74 047 Deferred compensation, vacation and other accrued liabilities not currently deductible 62 811 29 715 Other 11 341 Total deferred tax assets $243 304 $195 927 Net deferred tax liability $773 203 $764 529
The Omnibus Budget Reconciliation Act of 1993 (the Act) was signed into law on Aug. 10, 1993, and increased the federal corporate income tax rate from 34 percent to 35 percent retroactive to Jan. 1, 1993. Deferred tax liabilities were increased for the rate change by approximately $32 million. However, due to regulatory deferral of utility tax adjustments, earnings were reduced by immaterial adjustments to deferred tax liabilities related to non-regulated operations.
10. 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 $320 million. The Company may, and has, applied property additions in lieu of cash payments on all series except for the 91/8 percent Series due July 1, 2019, as permitted by its First Mortgage Indenture. The Wisconsin Company may also 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 variable rate First Mortgage Bonds Series due March 1, 2011, and the variable rate City of Becker Pollution Control Revenue Bonds Series due March 1, 2019, and Sept. 1, 2019, are redeemable upon seven days' notice at the option of the bondholder. Thus, the principal amount of these bonds outstanding at Dec. 31, 1993, is reported under current liabilities on the balance sheet. Their tax-exempt interest rates are subject to change, weekly or at various periods, and are based on prevailing rates for similar issues. The interest rates applicable to these issues averaged 3.0 percent, 2.6 percent and 2.5 percent, respectively, at Dec. 31, 1993.
The Company and the Wisconsin Company have entered into interest rate swap agreements with the underwriters of certain first mortgage bond issues, which effectively convert the interest cost for this debt from fixed to variable rate as summarized below:
Amount of Term of Net Effective Swap (millions Swap Interest Cost at Series of dollars) Agreement Dec. 31, 1993
5 7/8% Series due Oct. 1, 1997 $100 Maturity 3.38%
7 1/4% Series due March 1, 2023 $20 March 1, 1998 5.56%
The variable rates change semiannually. Interest rate swap transactions are recognized as an adjustment of interest expense over the terms of the agreements.
Maturities and sinking-fund requirements on long-term debt are as follows: 1994, $90,618,000; 1995, $41,348,000; 1996, $61,931,000; 1997, $138,401,000; and 1998, $57,352,000.
On Jan. 24, 1994, the Company notified bondholders that $150 million of first mortgage bonds would be redeemed on Feb. 24, 1994. These bonds have been classified as long-term debt based on the refinancing of such debt using first mortgage bond proceeds obtained in February 1994.
11. Short-Term Borrowings
NSP has approximately $215 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 no borrowings against these credit lines at Dec. 31, 1993 and 1992. At Dec. 31, 1993, the Company had $106.2 million in short-term commercial paper borrowings outstanding at interest rates varying from 3.3 to 3.5 percent.
12. Fair Value of Financial Instruments
SFAS No. 107 - Disclosures About Fair Value of Financial Instruments requires disclosure of the estimated fair value of financial instruments. 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. 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. The estimated Dec. 31 fair values of NSP's financial instruments are as follows:
1993 1992 Carrying Fair Carrying Fair (Thousands of dollars) Amount Value Amount Value
Cash, cash equivalents and short-term investments $57 838 $57 838 $15 840 $15 840 Long-term decommissioning investments $101 378 $110 130 $68 800 $72 180 Long-term debt including current portion $1 524 085 $1 584 435 $1 373 876 $1 437 999
13. 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.
For regulatory purposes, the Company's pension expense is determined and recorded under the aggregate-cost method. SFAS No. 87 - Employers' Accounting for Pensions provides that any difference between the pension expense recorded for ratemaking purposes and the amounts determined under SFAS No. 87 should be recorded as assets or liabilities on the balance sheet.
Net annual periodic pension cost includes the following components:
(Thousands of dollars) 1993 1992 1991
Service cost-benefits earned during the period $25 015 $24 080 $22 097 Interest cost on projected benefit obligation 71 075 69 853 65 557 Actual return on assets (152 019) (115 455) (246 678) Net amortization and deferral 66 299 39 019 181 543 Net periodic pension cost determined under SFAS No. 87 10 370 17 497 22 519 Costs recognized (deferred) due to actions of regulators 5 117 2 741 (1 549) Total pension costs recorded during the period 15 487 20 238 20 970 Less costs recognized for 1988 early retirement program (165) (165) Net periodic pension cost recognized for ratemaking $15 487 $20 073 $20 805
The funded status of the plan as of Dec. 31 is as follows:
(Thousands of dollars) 1993 1992 Actuarial present value of benefit obligation: Vested $655 002 $614 446 Nonvested 139 346 129 183 Accumulated benefit obligation $794 348 $743 629 Projected benefit obligation $974 160 $914 019 Plan assets at fair value 1 244 650 1 156 782 Plan assets in excess of projected benefit obligation (270 490) (242 763) Unrecognized prior service cost (22 580) (14 790) Unrecognized net actuarial gain 315 049 269 086 Unrecognized net transitional asset 767 843 Net pension liability included in other liabilities $22 746 $12 376
The weighted average discount rate used in determining the actuarial present value of the projected obligation was 7 percent in 1993 and 8 percent in 1992. The rate of increase in future compensation levels used in determining the actuarial present value of the projected obligation was 5 percent in 1993 and 6 percent in 1992. While the 1993 assumption changes had no effect on 1993 pension costs, the effect of the changes in 1994 is expected to be a cost decrease of approximately $3 million. The assumed long-term rate of return on assets used for cost determinations under SFAS No. 87 was 8 percent in 1993 and 1992 and 8.5 percent in 1991. The effect of the 1992 change in the assumed rate of return was an increase of $4.3 million in the estimated SFAS No. 87 net periodic pension cost in 1992. Plan assets principally consist of common stock of public companies and U.S. government securities.
Postretirement Health Care - 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 prior 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 considers anticipated 1994 plan design changes, including Medicare integration, increased retiree cost sharing and managed indemnity measures not in effect in 1993.
Prior to 1993, NSP funded benefit payments to retirees internally. While NSP generally prefers to continue using internal funding of benefits paid and accrued, significant levels of external funding have been imposed by NSP's regulators, as discussed below, including the use of tax-advantaged trusts. Plan assets held in such trusts as of Dec. 31, 1993, consisted of investments in equity mutual funds and cash equivalents.
The following table sets forth the health care plan's funded status in 1993.
(Millions of dollars) Dec. 31, 1993 Jan. 1, 1993
APBO: Retirees $120.2 $105.8 Fully eligible plan participants 18.8 18.8 Other active plan participants 90.8 91.0 Total APBO 229.8 215.6 Plan Assets 6.1 0 APBO in excess of plan assets 223.7 215.6 Unrecognized net actuarial loss (1.3) Unrecognized transition obligation (204.8) (215.6) Postretirement benefit obligation included in other liabilities $17.6 $0
The assumed health care cost trend rate used in measuring the APBO at Dec. 31, 1993, was 14.1 percent for those under age 65 and 8.0 percent for those over age 65. The assumed cost trend rates are expected to decrease each year until they reach 4.5 percent for both age groups in the year 2004, after which they are assumed to remain constant. The trend rates used in the Jan. 1, 1993, calculations were 15.1 percent and 9.0 percent, respectively, eventually decreasing to 5.5 percent in 2004. A 1-percent increase in the assumed health care cost trend rate for each year would increase the APBO as of Dec. 31, 1993, by approximately 17 percent, and service and interest cost components of the net periodic postretirement cost by approximately 20 percent. The assumed discount rate used in determining the APBO was 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 both measurement dates. While the assumption changes made for the Dec. 31 calculations had no effect on 1993 benefit costs, the effect of the changes in 1994 is expected to be a cost decrease of approximately $2 million.
In 1992 and 1991, NSP recognized $12.8 million and $11.2 million, respectively, as the cost attributable to postretirement health care and death benefits based on payments made. The net annual periodic postretirement benefit cost recorded for 1993 consists of the following components:
(Millions of dollars) 1993 Service cost-benefits earned during the year $4.4 Interest cost (on service cost and APBO) 17.5 Actual return on assets (.1) Amortization of transition obligation 10.8 Net amortization and deferral .1 Net periodic postretirement health care cost under SFAS No. 106 32.7 Costs deferred due to actions of regulators (12.1) Net periodic postretirement health care cost recognized for ratemaking $20.6
Regulators of NSP's retail rates in Minnesota, Wisconsin and North Dakota have allowed full recovery of increased benefit costs under SFAS No. 106, effective in 1993. Expense recognition and rate recovery of increased 1993 accrual costs for Minnesota have been deferred until 1994 through 1996, consistent with rate orders received. External funding was required in Minnesota and Wisconsin to the extent it is tax advantaged; funding began for Wisconsin in 1993 and must begin by the next general rate filing for Minnesota.
Rate increases for Minnesota and Wisconsin wholesale electric customers were approved by the FERC and provided recovery of accrued SFAS No. 106 benefits under new rates beginning in September 1993. A rate increase for Viking wholesale gas customers was approved by the FERC, before Viking's acquisition by the Company, and provided recovery of accrued benefits beginning in July 1993. The FERC has required external funding for all benefits paid and accrued under SFAS No. 106.
The impact of adopting SFAS No. 106 on other utility jurisdictions and non-regulated operations was not material.
ESOP - NSP also has a leveraged Employee Stock Ownership Plan (ESOP) that covers substantially all employees. Employer contributions to this plan are generally made to the extent NSP realizes a tax savings on its income statement from dividends paid on shares held by the ESOP. Contributions to the ESOP in 1993, 1992 and 1991, which approximate expenses determined under the shares-allocated method, were $6,281,000, $6,415,000 and $6,326,000, 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 9.)
14. 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, 1993 and 1992, was $584,822,000 and $582,799,000, respectively. The corresponding accumulated provisions for depreciation were $114,251,000 and $96,035,000.
15. Commitments and Contingent Liabilities
Commitments - NSP estimates utility capital expenditures, including acquisitions of nuclear fuel, will be $396 million in 1994 and $1.8 billion for 1994-1998. There also are contractual commitments for the disposal of spent nuclear fuel.
Rentals under operating leases were approximately $27.5 million, $25.1 million and $22.7 million for 1993, 1992 and 1991, 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 1994 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 purchase and receipt of approximately $374 million of coal, $129 million of nuclear fuel and $607 million of natural gas, or to make payments in lieu thereof, under these contracts. 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 Purchases 1994-2005 500 Seasonal Participation Power Purchase 1994-1996 1994 150 1995-1996 250 Seasonal Peaking Power Purchases 1994-1996 200 Seasonal Diversity Exchanges: Summer exchanges from MH 1994 400 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 participation power purchase commitment is based on 80 percent of the costs of owning and operating Sherco 3 (adjusted to 1993 dollars). The total estimated annual costs for all MH agreements are $68.2 million for 1994 and approximately $70 million thereafter. These commitments, which represent about 38 percent of MH's output capability in 1993, account for approximately 13 percent of the Company's 1993 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 megawatts 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 Company and MH began construction in early 1992, received all the necessary approvals in 1993 and expect to complete construction in 1995.
The Company has an agreement with Minnkota Power Cooperative (MPC) for the purchase of summer season capacity and energy. From 1994 through 2001, the Company will buy 150 megawatts of summer season capacity for $12.4 million annually. From 2002 through 2015, the Company will purchase 100 megawatts of capacity for $10.0 million annually. Energy under the agreement 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 Rochester Public Utility, for the purchase of 270 megawatts in 1994 and 250 megawatts in 1995 and 1996. The annual cost of this capacity will be approximately $3 million.
The Company has agreements with several non-regulated entities to purchase electric capacity and associated energy. The total annual cost of current commitments for non-regulated installed capacity ranges from approximately $18 million for 119 megawatts in each of the years 1994-2011, decreasing thereafter to $0.8 million in 2033. The Company is negotiating a new power-purchase agreement with an independent power producer, which is expected to provide an additional 232 megawatts of electric capacity and associated energy, beginning in 1997.
Nuclear Insurance - The Company's public liability for claims resulting from any nuclear incident is limited to $9.4 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 $9.2 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 clean-up costs with coverage limits of $2.35 billion for the Prairie Island nuclear plant site and $2.15 billion for the Monticello nuclear plant site. The Prairie Island coverage consists of $950 million from American Nuclear Insurers/ Mutual Atomic Energy Liability Underwriters (ANI/MAELU) and $1.4 billion from Nuclear Electric Insurance Limited (NEIL). The Monticello coverage consists of $750 million from ANI/MAELU and $1.4 billion from NEIL. Under the insuring agreement with NEIL, the Company is subject to assessments of up to $23.3 million in each calendar year, 7.5 times the amount of its annual premium.
NEIL also provides insurance coverage for increased costs of generation and purchased power resulting from an accidental outage of a nuclear generating unit. Under the policy, the Company is subject to assessments of up to $6.7 million in each calendar year, five times the amount of its annual premium.
Environmental Contingencies - Other long-term liabilities include an accrual of $48 million at Dec. 31, 1993, for estimated costs associated with environmental reclamation, restoration and cleanup activities. Approximately $40 million of the liability relates to a 1993 DOE assessment as discussed in Note 8 to the Financial Statements. 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 decommissioning costs related to the Company's nuclear generating plants. Consistent with predominant industry practice, the Company's decommissioning accruals are included in Utility Plant-Accumulated Depreciation as discussed in Note 1 of the Financial Statements. The FERC, the FASB and the SEC currently are reviewing the accounting and reporting guidelines for decommissioning cost accruals. Until such guidelines require a different presentation, the Company plans to continue its current reporting of plant decommissioning obligations as accumulated depreciation.
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 and include it in depreciation expense.
(See Note 1 for discussion of NSP's pre-funding of the federal nuclear fuel disposal program.)
NSP has met or exceeded the removal and disposal requirements for polychlorinated biphenyls (PCB) equipment as required by state and federal regulations. NSP has removed nearly all PCB capacitors, transformers and equipment from its distribution system and power plants. Any future cleanup or remediation costs for past PCB disposal is unknown at this time. Minimal costs are expected to be incurred for future removal and disposal of PCB equipment. PCB-contaminated mineral oil is detoxified and beneficially reused or burned for energy recovery at a permitted facility.
The Company has been designated by the Environmental Protection Agency (EPA) as a "potentially responsible party" (PRP) for eight waste disposal sites to which the Company sent materials. Under applicable law, the Company, along with each PRP, could be held jointly and severally liable for the total remediation costs of all eight sites, which are estimated to approximate $85 million. However, the amount could be in excess of $85 million. The Company is not aware of the other parties' inability to pay or if responsibility for any of the sites is disputed by any party. The Company's share of the costs associated with these eight sites is approximately $2.5 million. Of this amount, about $1.4 million has already been paid in connection with two of the eight sites for which the Company has settled with the EPA and other PRPs. For the remaining six sites, neither the amount of cleanup costs nor the final method of their allocation among all designated PRPs has been determined. However, the Company has recorded an estimate of future costs of approximately $1 million for all six sites. 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 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 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 has been notified by a group of PRPs for possible responsibility 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 PRPs has been determined, it is not feasible to determine the outcome of this matter at this time.
The Company also is continuing to investigate 14 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 14 gas sites under investigation, the Company has already remediated one site and is actively taking remedial action at four of the sites. The Company has paid $3.1 million to date on these sites. The one remediated site continues to be monitored. The Company currently estimates its liability for these four sites to be approximately $5 million with payment expected over the next one to five years. The estimate is based on prior experience and includes investigation, remediation and litigation costs. The possible range of the liability for these four sites could be from $5 million to approximately $11 million, depending on the extent of contamination. As for the other nine sites, the Company currently estimates its liability to be approximately $2 million. This estimate assumes the development and remediation of one site with the remaining eight sites requiring only monitoring. The time frame for payment of these costs currently is undeterminable. 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 the Company's 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.
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 utility generating plants. The legislation enacted in 1990 is extremely complex and its overall financial impact on NSP will depend on the final interpretation and implementation of rules to be issued by the EPA. NSP is participating in the rulemaking process for the development of regulations that achieve the goals of the legislation in a reasonable and cost-effective manner. NSP has expended significant funds over the years to reduce sulfur dioxide emissions at its plants. Additional construction expenditures may be required to comply with parts of the Clean Air Act. Based on revised emission standards proposed by the EPA in 1993, NSP's excess emission allowances available under the Clean Air Act may be significantly reduced. Because NSP is only beginning to implement some provisions of the Clean Air Act, its overall financial impact is unknown at this time. The majority of NSP's power plants meet state and federal limits for opacity and air quality. Capital expenditures will be required for opacity compliance in 1994-1998 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.
In October 1992, the Company disclosed to the Minnesota Pollution Control Agency, the EPA and the Nuclear Regulatory Commission that 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, and the Company cooperated with state and federal authorities in the investigation of the reporting violations. No civil or criminal actions against the Company have been announced.
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. 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 four lawsuits have been filed, the litigation following this incident is in a preliminary stage and the ultimate costs to the Company are unknown at this time.
Operating Contingency - The Company is experiencing uncertainty regarding its ability to store used nuclear fuel from its Prairie Island nuclear generating facility. The facility stores its used nuclear fuel on an interim basis in a storage pool in the plant, pending the availability of a U.S. Department of Energy high-level radioactive waste storage or permanent disposal facility, or a private interim storage facility. At current operating levels, the pool will be filled in 1994 so the Company has proposed to augment Prairie Island's interim storage capacity by using steel containers for dry storage of used nuclear fuel on the plant site. Without additional onsite storage or significant modification of normal plant operations, Prairie Island Unit 2 would be shutdown in May 1995 and Prairie Island Unit 1 would be shutdown in February 1996. These two units supply about 20 percent of the Company's output. The Company has obtained a Certificate of Need from the MPUC allowing use of a limited number of steel containers, providing adequate storage at least through the year 2001. The Nuclear Regulatory Commission has also issued a license approving a dry storage facility on the plant site for Prairie Island's used fuel. However, in June 1993, the Minnesota Court of Appeals decided that the additional temporary storage facilities must be approved by the Minnesota Legislature. The Company has requested such approval from the Legislature and expects a decision on this issue during the current session, which began on Feb. 22, 1994. Although hearings have begun, the Company cannot predict what action the Minnesota Legislature will take.
The Company's net investment in the Prairie Island generating facility at Dec. 31, 1993, was $520 million. Future plant decommissioning costs in excess of amounts not accrued and collected in rates were $247 million at Dec. 31, 1993. Should the facility need to be shut down due to the full utilization of spent fuel storage capacity, the Company would request recovery of, and a return on, its investment and unrecorded plant decommissioning costs through utility rates. However, at this time the regulators' ultimate response to such a request is unknown. Without the generating capability of the Prairie Island facility, the Company estimates that an incremental increase in purchased power and fuel expenses of at least $200 million per year could be incurred. To the extent such additional costs represent energy purchases, current rate treatment provides recovery through cost-of-energy adjustments to customer rates. The Company will request recovery of costs associated with additional capacity purchases or investments in new plants through general rate filings. However, at this time the need for such costs and the regulators' ultimate response to such a request is unknown. The Company estimates that the present value of the cost of supplying replacement power and recovering its investment in the plant and unrecognized decommissioning costs will be $1.8 billion.
16. Segment Information
Year Ended Dec. 31 (Thousands of dollars) 1993 1992 1991
Utility operating revenues Electric $1 974 916 $1 823 316 $1 863 238 Gas 429 076 336 206 337 920 Total operating revenues $2 403 992 $2 159 522 $2 201 158 Utility operating income before income taxes* Electric $393 758 $321 837 $383 049 Gas 38 474 24 848 39 748 Total operating income before income taxes $432 232 $346 685 $422 797 Utility depreciation and amortization Electric $245 200 $225 134 $217 625 Gas 19 317 17 780 16 538 Total depreciation and amortization $264 517 $242 914 $234 163 Capital expenditures Electric $284 239 $367 522 $290 793 Gas 36 312 42 850 32 576 Other 41 144 17 443 26 493 Total capital expenditures $361 695 $427 815 $349 862 Net utility plant Electric $3 834 131 $3 812 688 $3 709 811 Gas 379 968 313 002 287 167 Total net utility plant 4 214 099 4 125 690 3 996 978 Other corporate assets 1 373 619 1 016 771 921 860 Total assets $5 587 718 $5 142 461 $4 918 838
*1992 amounts include an increase from the operating income impact of the 1992 change in accounting for revenues of $9.6 million for electric and $6.8 million for gas.
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
During 1993 there were no changes in or disagreements with the Company's independent public accountants on accounting procedures or accounting and financial disclosures.
PART III Item 10 - Directors and Executive Officers of the Registrant
Information required under this Item with respect to Directors is set forth in the Registrant's 1994 Proxy Statement for its Annual Meeting of Shareholders to be held April 27, 1994 on pages 2 through 7 under the caption "Election of Directors", which is incorporated herein by reference. Information with respect to Executive Officers is included under the caption "Executive Officers" in Item 1 of this report, and is incorporated herein by reference.
Item 11 - Executive Compensation
Information required under this Item is set forth in the Registrant's 1994 Proxy Statement for its Annual Meeting of Shareholders to be held April 27, 1994 on pages 8 through 20 under the caption "Compensation of Executive Officers", which is incorporated herein by reference.
Item 12 - Security Ownership of Certain Beneficial Owners and Management
Information required under this Item is set forth in the Registrant's 1994 Proxy Statement for its Annual Meeting of Shareholders to be held April 27, 1994 on page 7 under the caption "Share Ownership of Directors, Nominees and Named Executive Officers", which is incorporated herein by reference.
Item 13 - Certain Relationships and Related Transactions
Information required under this Item is set forth in the Registrant's 1994 Proxy Statement for its Annual Meeting of Shareholders to be held April 27, 1994 on pages 3 through 5 under the captions "Class I - Directors Whose Terms Expire in 1996", "Class II - Nominees for Terms Expiring in 1997", "Class III - Directors Whose Terms, Expire in 1995", which is incorporated herein by reference.
PART IV Item 14 - Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) 1. Financial Statements
Included in Part II of this report:
Independent Auditors' Report.
Consolidated Statements of Income for the three years ended December 31, 1993.
Consolidated Statements of Cash Flows for the three years ended December 31, 1993.
Consolidated Balance Sheets, December 31, 1993 and 1992.
Consolidated Statements of Changes in Common Stockholders' Equity for the three years ended December 31, 1993
Consolidated Statements of Capitalization, December 31, 1993 and 1992.
Notes to Financial Statements.
(a) 2. Financial Statement Schedules
Included in Part IV of this report:
Schedules for the three years ended December 31, 1993:
V - Utility Plant and Non-regulated Property VI - Accumulated Provision for Depreciation and Amortization of Utility Plant and Non-regulated Property.
Notes to Schedules V and VI.
IX - Short-Term Borrowings X - Supplementary Income Statement Information
Schedules other than those listed above 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* 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:
4.46* Mar. 1, 1949 (Exhibit 7.02 to File No. 2-7825).
4.47* Jun. 1, 1957 (Exhibit 2.13 to File No. 2-13463).
4.48* Aug. 1, 1964 (Exhibit 4.20 to File No. 2-23726).
4.49* Dec. 1, 1969 (Exhibit 2.03E to File No. 2-36693).
4.50* Sep. 1, 1973 (Exhibit 2.01F to File No. 2-48805).
4.51* Feb. 1, 1982 (Exhibit 4.01G to File No. 2-76146).
4.52* Mar. 1, 1982 (Exhibit 4.39 to Form 10-K for the year 1982, File No. 10-3140).
4.53* Jun. 1, 1986 (Exhibit 4.01I to File No. 33-6269).
4.54* Mar. 1, 1988 (Exhibit 4.01J to File No. 33-20415).
4.55* 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)
4.56* Apr. 1, 1991 (Exhibit 4.01L to File No. 33-39831).
4.57* Mar. 1, 1993 (Exhibit 4.01 to Form 8-K dated March 4, 1993, File No. 10-3140).
4.58* Oct. 1, 1993 (Exhibit 4.01 to Form 8-K dated September 21, 1993, File No. 10-3140).
10.01* Mid-continent Area Power Pool (MAPP) Agreement, dated March 31, 1972, between the local power suppliers in the North Central States area. (Exhibit 5.06B to File No. 2-44530).
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 10.35 to Form 10-K for the Year 1982, 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 10.40 to Form 10-K for the Year 1982, 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 10.45 to Form 10-K for the Year 1984, 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.
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 (Exhibit 10.14 to Form 10-K for the Year 1992, File No. 1-3034).
10.13* NSP Pension Plan (Exhibit 10.15 to Form 10-K for the Year 1992, File No. 1-3034).
10.14* NSP Employee Stock Ownership Plan (Exhibit 4.03, 4.04, 4.05 and 4.06 to Post-effective Amendment No. 5 to File No. 2- 61264).
10.15* NSP Retirement Savings Plan (Exhibit 10.17 to Form 10-K for the Year 1992, File No. 1-3034).
10.16 NSP Deferred Compensation Plan amended effective January 1, 1993.
12.01 Statement of Computation of Ratio of Earnings to Fixed Charges.
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.
(b) Reports on Form 8-K. The following reports on Form 8-K were filed either during the three months ended December 31, 1993, or between December 31, 1993 and the date of this report:
October 1, 1993 (Filed October 8, 1993) - Item 5. Other Events. Re: Disclosure of the purchase of certain assets of Centran Corporation, a natural gas marketing company, by a non-regulated subsidiary of the Company.
December 7, 1993 (Filed December 9, 1993) - Item 5. Other Events. Re: Disclosure of Underwriting Agreement and filing of a prospectus supplement relating to $170,000,000 First Mortgage Bonds ($100,000,000, Series due December 1, 2000) ($70,000,000, Series due December 1, 2005). 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 December 1, 2000 and Series Due December 1, 2005, and the computation of ratio of earnings to fixed charges.
December 10, 1993 (Filed December 27, 1993) - Item 5. Other Events. Re: Disclosure of a partnership agreement, in which a non-regulated subsidiary of the Company is a party of, to purchase a 400-megawatt share of the 900-megawatt Schkopau power plant near Leipzig, Germany. Disclosure of a partnership agreement, in which a non-regulated subsidiary of the Company is a party of, to acquire a portion of the mining, power generation and associated operations of the former state-owned, Mitleldeutsche Vereinigte Braunkohlenwerke Aktiengesellschaft.
January 31, 1994 (Filed February 9, 1994) - Item 5. Other Events. Re: Disclosure of an appeal filed with the Minnesota Court of Appeals by rate case intervenors concerning the method of calculating the rate of return on common equity. Disclosure that the Company has been named as a potentially responsible party at a Superfund site. Disclosure of the Company's Unaudited Consolidated Financial Statements for 1993. Item 7. Financial Statements, Pro Forma Financial Information and Exhibits. Filing of the Company's Unaudited Financial Statements for 1993.
February 10, 1994 (Filed February 14, 1994) - Item 5. Other Events. Re: Disclosure of Underwriting Agreement and filing of a prospectus supplement relating to $200,000,000 First Mortgage Bonds, Series due February 1, 1999. 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 due February 1, 1999, and the computation of ratio of earnings to fixed charges.
March 15, 1994 (Filed March 16, 1994) - Item 5. Other Events. Re: Disclosure of the results of Minnesota State Legislative Committee votes on the Company's plan to store additional spent nuclear fuel at its Prairie Island Nuclear Generating Plant. Disclosure of the International Brotherhood of Electrical Workers rejection of NSP's contract offer and the continuation of negotiations.
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES NOTES TO SCHEDULES V AND VI (Thousands of dollars)
For the year ended December 31, 1993: 1. Represents transfers and adjustments which were charged to the following accounts: Adjustment due to electric and gas meter inventory ($1 157) Adjustment due to gas distribution main inventory (2 252) Miscellaneous adjustments (413) Total ($3 822)
2. Represents transfers and adjustments which were charged to the following accounts: Accumulated depreciation of Viking Gas utility plant acquired $65 087 Adjustment due to gas distribution main inventory (2 252) Miscellaneous adjustments 241 Total $63 076
For the year ended December 31, 1992: 1. Represents transfers and adjustments which were charged to the following accounts: Miscellaneous adjustments ($129)
2. Represents transfers and adjustments which were charged to the following accounts: Miscellaneous adjustments ($634)
For the year ended December 31, 1991: 1. Represents transfers and adjustments which were charged to the following accounts: Adjustment due to spare parts inventory ($6 130) Miscellaneous adjustments (151) Total ($6 281)
2. Represents transfers and adjustments which were charged to the following accounts: Miscellaneous adjustments ($29)
Depreciation is computed on the straight-line method based on estimated useful lives of the various classes of property. Such provisions as a percentage of the average balance of depreciable property in service were 3.47% in 1993, 3.36% in 1992 and 3.35% in 1991. Nuclear fuel is amortized to fuel expense based on energy expended.
SCHEDULE IX
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES
SHORT-TERM BORROWINGS FOR THE THREE YEARS ENDED DECEMBER 31, 1993
Primarily Commercial Paper (Thousands of dollars)
1993 1992 1991
Balance at end of year $106 200 $146 561 $ 0
Weighted average interest rate at end of year 3.3% 3.6% 0
Maximum month-end amount $172 280 $162 000 $ 0 outstanding during the year (1-31-93) (7-31-92)
Average amount outstanding during the period (computed on a daily basis) $ 76 966 $ 80 957 $390
Weighted average interest rate during the year (computed on a daily basis) 3.3% 3.6% 6.0%
SCHEDULE X
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES
SUPPLEMENTARY INCOME STATEMENT INFORMATION FOR THE THREE YEARS ENDED DECEMBER 31, 1993
1993 1992 1991 (Thousands of dollars)
Taxes other than payroll and income taxes charged to operating expenses: Real and personal property $169 881 $154 060 $148 653 Gross earnings $26 292 $24 264 $24 787 Other $3 842 $3 620 $3 526
The amount of maintenance and depreciation charged to expense accounts other than those set forth in the statement of income are not significant.
All other items are less than 1% of total revenues.
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 23, 1994 (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
(Richard M Kovacevich) (Douglas W Leatherdale) Richard M Kovacevich Douglas W Leatherdale 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 President and Director
EXHIBIT INDEX
Method of Exhibit Filing No. Description
DT 10.09 Energy Supply Agreement between the Company and Liberty Paper, Inc.
DT 10.16 NSP Deferred Compensation 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 Auditors' Consent
DT = Filed electronically with this direct transmission.
Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations
Northern States Power Company, a Minnesota corporation (the Company), has one significant subsidiary, Northern States Power Company, a Wisconsin corporation (the Wisconsin Company), and several other subsidiaries, including Viking Gas Transmission Company (Viking) and NRG Energy, Inc. (NRG), both Delaware corporations. The Company and its subsidiaries collectively are referred to herein as NSP.
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 1993 and 1992 and should be read in connection with the Financial Statements and Notes thereto. Trends and contingencies of a material nature are discussed to the extent known and considered relevant.
Liquidity and Capital Resources
Financial Condition and Cash Flows - With rate increases granted in 1993, NSP's financial condition remained strong and its cash flows and earnings from operations improved from 1992, despite cooler-than-average summer weather. NSP's 1992 cash flows and earnings before accounting changes were significantly reduced by unusual weather, including the coolest summer in 77 years. The 1992 earnings included $45.5 million from a change in accounting for unbilled revenues, which did not affect cash flows or customer rates. During 1993, NSP continued to meet its long-range objectives for capital structure of approximately 45-50 percent common equity and 40-45 percent debt. The pretax interest coverage ratio before accounting changes, excluding AFC, was 3.9 in 1993 and 3.1 in 1992. NSP's objective range for interest coverage is 3.5-5.0.
Financing Requirements - NSP's need for capital funds is primarily related to the construction of plant and equipment to meet the needs of its electric and gas utility customers and to fund equity commitments or other investments in its non-regulated businesses. Total NSP capital expenditures (including AFC and excluding business acquisitions) were $362 million in 1993. Of that amount, $284 million related to replacements and improvements of NSP's electric system and $36 million involved construction of natural gas distribution facilities. Internally generated funds provided 99 percent of NSP's capital expenditures for 1993 and 85 percent of the $1.8 billion in capital expenditures incurred for the five-year period 1989-1993. NSP estimates that its utility capital expenditures will be $396 million in 1994. Of that amount, $316 million is scheduled for electric facilities and $43 million for natural gas facilities. Internally generated funds from utility operations are expected to provide approximately 80 percent of 1994 utility capital expenditures and approximately 95 percent of the $1.8 billion in utility capital expenditures estimated for the five-year period 1994-1998. These utility capital expenditure estimates include approximately $100 million of anticipated expenditures for pollution control facilities required under the Clean Air Act. In addition to utility capital expenditures, expected financing requirements for the 1994-1998 period include approximately $390 million to retire long-term debt and meet first mortgage bond sinking fund requirements.
NSP expects to obtain external capital for these requirements by issuing long-term debt, common stock and preferred stock. Utility financing requirements for the period 1994-1998 may be affected by factors such as load growth, changes in capital expenditure levels, rate increases allowed by regulatory agencies, new legislation, changes in environmental regulations and other regulatory requirements.
NSP expects to invest significant amounts in non-regulated projects, including domestic and international power projects. Projects currently being pursued include joint ventures to acquire electric generating plants in Australia and Germany, and open-cast coal mining operations in Germany. Non-regulated projects are expected to be financed primarily through project debt. The remaining project costs are expected to be funded through equity investments from NSP and other investors. Over the long-term, NSP's equity investments are expected to be financed through internally generated funds or NSP's issuance of common stock and debt. Although they 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 are estimated to be approximately $130 million in 1994 and approximately $540 million for the five-year period 1994-1998. These amounts include expected equity investments by NSP of approximately $60 million for the Australia project in 1994 and up to $100 million for the Germany projects through 1996.
In addition to capital expenditures, NSP invested $159 million in 1993 to acquire three energy-related businesses. (See Note 4 to the Financial Statements.) NSP continues to evaluate opportunities to enhance shareholder returns through business acquisitions. Long-term financing may be required for such acquisitions.
Financing Flexibility - 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 earn a fair return on investors' capital. Financing flexibility is enhanced by providing working capital needs and a high percentage of total capital requirements from internal sources, and having the ability, if necessary, to issue long-term securities and obtain short-term credit. 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, Aa2 by Moody's Investors Service, Inc., AA- by Duff & Phelps, Inc., and AA by Fitch Investors Service, Inc. Ratings for the Wisconsin Company's first mortgage bonds are generally comparable. These ratings reflect only the views of such organizations and an explanation of the significance of these ratings may be obtained from each agency. The Company's and the Wisconsin Company's first mortgage indentures place limits on the amount of first mortgage bonds that may be issued. The Minnesota Public Utilities Commission (MPUC) and the Public Service Commission of Wisconsin (PSCW) have jurisdiction over securities issuance. At Dec. 31, 1993, with an assumed interest rate of 8 percent, the Company could have issued about $1.8 billion of additional first mortgage bonds under its indenture and the Wisconsin Company could have issued about $280 million of additional first mortgage bonds under its indenture. NSP expects to maintain adequate access to long-term and short-term debt markets in 1994.
The Company registered $600 million of first mortgage bonds with the Securities and Exchange Commission (SEC) in December 1993. Depending on capital market conditions, the Company expects to issue approximately $450 million of this debt in 1994, primarily for refinancings, with the remainder issued over the next several years, for the purpose of raising additional capital or redeeming 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. The Company had approximately $106 million in commercial paper debt outstanding as of Dec. 31, 1993. The Company plans to keep its credit lines at or above the level of commercial paper borrowings. Commercial banks presently provide credit lines of approximately $215 million. 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, 1993, 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 1,650,000 shares of common stock under the Company's Dividend Reinvestment and Stock Purchase Plan, Executive Long-Term Incentive Award Stock Plan, and Employee Stock Ownership Plan (ESOP) as of Dec. 31, 1993. The Company may issue new shares or purchase shares on the open market for its stock plans. (See Note 6 to the Financial Statements for discussion of stock awards outstanding.) As discussed below, the Company issued new common stock in 1993 under a general stock offering and under its shareholder, employee and customer stock programs. At Dec. 31, 1993, the total number of common shares outstanding was 66,879,577. The Company does not plan any general stock offerings for 1994.
1993 Financing Activity - During 1993, NSP engaged in numerous financing activities. The Company issued 4,281,217 shares of common stock. Of these shares, 2.6 million were sold to a group of underwriters on May 20, 1993. The offering price to the public was $43.625 per share, with net proceeds of $110 million to the Company. Of the remaining new shares, 940,000 shares were issued under the Dividend Reinvestment and Stock Purchase Plan, 174,308 shares were issued under the Executive Long-Term Incentive Award Stock Plan and 566,909 shares were issued to the ESOP.
On Oct. 30, 1993, the Company redeemed all 350,000 shares of its $7.84 series Cumulative Preferred Stock at $103.12 per share, plus accrued dividends through Oct. 31, 1993.
During 1993, the Company issued $350 million, and the Wisconsin Company issued $150 million, of long-term debt to refinance higher rate debt, redeem preferred stock, repay scheduled maturities of debt and extend the term of short-term borrowings. In addition, $116 million of long-term debt was issued by subsidiaries to finance the acquisitions of Viking and the Minneapolis Energy Center. (See Note 4 to the Financial Statements.) In connection with the early redemption of $453 million of long-term debt, NSP incurred approximately $14 million in reacquisition premiums, which will be amortized over the term of the newly issued debt.
Results of Operations
NSP's results of operations during 1993 and 1992 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 are dependent on customer usage which varies with weather conditions, general business conditions, the state of the economy and the cost of energy services, the recovery of which is determined by various regulatory authorities. The historical and future trends of NSP's operating results have been and are expected to be impacted by the following factors:
Weather - NSP's earnings can be dramatically impacted by unusual weather. Mild weather, mainly a cool summer, reduced 1993 earnings by an estimated 18 cents. 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.
Operating Contingency - The Company is experiencing uncertainty regarding its ability to store used nuclear fuel from its Prairie Island nuclear generating facility. The facility stores its used nuclear fuel on an interim basis in a storage pool in the plant, pending the availability of a U. S. Department of Energy high-level radioactive waste storage or permanent disposal facility, or a private interim storage facility. At current operating levels, the pool will be filled in 1994 so the Company has proposed to augment Prairie Island's interim storage capacity by using steel containers for dry storage of used nuclear fuel on the plant site. Without additional onsite storage or significant modification of normal plant operations, Prairie Island Unit 2 would be shutdown in May 1995 and Prairie Island Unit 1 would be shutdown in February 1996. These two units supply about 20 percent of the Company's output. The Company has obtained a Certificate of Need from the MPUC allowing use of a limited number of steel containers, providing adequate storage at least through the year 2001. The Nuclear Regulatory Commission has also issued a license approving a dry storage facility on the plant site for Prairie Island's used fuel. However, in June 1993, the Minnesota Court of Appeals decided that the additional temporary storage facilities must be approved by the Minnesota Legislature. The Company has requested such approval from the Legislature and expects a decision on this issue during the current session, which began on Feb. 22, 1994. Although hearings have begun, the Company cannot predict what action the Minnesota Legislature will take. If operations at Prairie Island cease, the Company estimates that the present value of the cost of supplying replacement power and recovering its investment in the plant and unrecognized decommissioning costs will be $1.8 billion. The Company would request recovery of these costs, including a return on its investment, through utility rates. However, at this time the need for such costs and the regulators' ultimate response to such a request is unknown. (See Note 15 to the Financial Statements regarding the possible effects on operating results of the potential shutdown of the Company's Prairie Island nuclear power generating facility.)
Regulation - NSP's utility rates are approved by the Federal Energy Regulatory Commission (FERC) and state commissions. Rates are designed to recover plant and operating costs and an allowed return, using an annual period upon which rate case filings are based. NSP's utility companies request increases in customers' rates as needed and file them with the governing commissions. The rates charged to retail customers in Wisconsin are reviewed and adjusted biennially. Because rate increases are not requested annually in Minnesota, NSP's primary jurisdiction, the impact of inflation on operating costs continues to be a factor affecting 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 power 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 programs and demand-side management efforts.
Rate Increases - During 1992 and 1993, 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 wholesale customers in Minnesota and Wisconsin. These rate changes increased 1993 revenues by approximately $83 million; the full impact of these increases will be realized in 1994. On Jan. 31, 1994, three intervenors filed an appeal of the MPUC's decision concerning the method of calculating the rate of return on common equity granted in the Minnesota electric and gas rate cases. The amount at issue is approximately $7 million in annual revenues for the Company. (See Note 2 to the Financial Statements for further discussion of 1993 rate case results.)
In 1993, NSP filed for 1994 rate increases for North Dakota retail electric and Wisconsin retail gas customers. NSP received approval for approximately $2.6 million of rate increases in these two jurisdictions, effective January 1994. No significant rate filings in other jurisdictions are expected for 1994.
Acquisitions - NSP made three strategically important business acquisitions in 1993. These include a gas pipeline, an energy services marketing business, and a steam heating and chilled water cooling system business. (See Note 4 to the Financial Statements for more discussion of these acquisitions, including the pro forma results of these acquisitions on an annual basis.)
Competition - The Energy Policy Act of 1992 (the Act) is expected to bring comprehensive and significant changes to the electric utility industry. Many provisions of the Act are expected to increase competition in the industry in the next few years. The Act's reform of the Public Utility Holding Company Act (PUHCA) promotes creation of wholesale power generators and authorizes the 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. Other producers may compete for NSP's customers as a result of such PUHCA reform. Management believes this legislation will promote the continued trend of increased competition in the electric energy markets.
Many states are considering proposals to require "retail wheeling", which is the delivery of power generated by a third party to retail customers. Retail wheeling represents yet another development of a competitive electric industry. NSP management plans to continue its efforts to be a low-cost supplier of electricity and an active participant in the competitive market for electricity.
During 1992 and 1993, the FERC issued a series of orders (together called Order 636) addressing interstate natural gas pipeline service restructuring. This restructuring will "unbundle" each of the services - sales, transportation, storage and ancillary services - traditionally provided by the 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. NSP believes some uncertainty remains as to whether the new unbundled services under Order 636 will prove to be as reliable and flexible as the traditional sales service. The implementation of Order 636 also will apply 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 will be allowed to recover, subject to negotiations with customers, 100 percent of prudently incurred transition costs attributable to Order 636 restructuring. Although negotiations are in process, NSP estimates that it will be responsible for less than $10 million of transition costs, over a proposed five-year period. NSP's regulatory commissions have previously approved recovery of similar restructuring charges in retail gas rates. 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 (as discussed in Note 4 to the Financial Statements) have enhanced the ability to participate in the more competitive gas transportation business. In implementing Order 636, Viking incurred no restructuring costs.
Impact of Non-Regulated Investments - NSP expects to invest significant amounts in non-regulated projects, including domestic and international power production projects through NRG, as described previously under "Financing Requirements". Depending on the success and timing of involvement in these projects, NSP's non-regulated earnings are expected to increase materially in the next few years. However, the projects generating the increased earnings may present additional risk. Current and future investments in international projects are subject to uncertainties prior to final legal closing, and continuing operations are subject to foreign government and partnership actions. NRG plans to hedge its exposure to currency fluctuations to the extent permissible by hedge accounting requirements. NRG will use well-established financial instruments of sufficient credit quality to protect the economic value of foreign-currency denominated assets. (With respect to risk of potential losses from unsuccessful non-regulated projects, see Note 1 to the Financial Statements for discussion of capitalized expenditures for projects under development.)
Employee Compensation and Benefits - In 1993, NSP conducted an extensive review of its employee compensation and benefits, and retiree benefits. As a result, several changes will be implemented, commencing in 1994, that will support NSP's goal of providing market-based compensation and benefits. These changes, which include no base wage increase for non-union employees in 1994, are expected to keep compensation and benefit costs comparable to 1993 levels. NSP's labor agreements with its five local unions expired on Dec. 31, 1993. An interim agreement with the unions expires March 31, 1994. Although NSP's final offer for settlement (made on Feb. 4, 1994) was rejected by the union membership on March 14, 1994 and an authorization to strike was approved, the parties resumed discussions on March 21, 1994. NSP is not able to predict the outcome of negotiations at this time.
Environmental Matters - Like other utilities, the Company has been named as a potentially responsible party at eight waste disposal sites and is in the process of investigating the remediation of 14 former coal-gasification and other sites. The Company has recorded an estimate of the probable costs to be incurred in connection with remediation of these sites. To the extent costs are not recovered from insurers or other parties, the Company expects to seek recovery of such costs in future ratemaking proceedings.
In general, NSP has been experiencing a trend toward more environmental monitoring and compliance costs. This trend has caused and may continue to cause slightly higher operating expenses and capital expenditures. The timing and amount of environmental costs, including those for site remediation, are currently unknown. In 1993, 1992 and 1991, the Company spent about $15 million, $20 million and $6 million, respectively, for capital expenditures on environmental improvements at utility facilities. The Company expects to incur approximately $9 million in capital expenditures for compliance with environmental regulations in 1994. (See Note 15 to the Financial Statements for further discussion of these and other environmental contingencies that could affect NSP.)
Wholesale Customers - In 1992, nine of the Company's 19 municipal wholesale electric customers created a joint action municipal power agency to serve their future power supply needs and notified the Company of their intent to terminate their power supply agreements with the Company effective in July 1995 or July 1996. These nine customers currently represent approximately $24 million in annual revenues and a maximum demand load of approximately 150 megawatts.
In 1992 and 1993, the Company signed long-term power supply agreements with the remaining 10 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 $8 million in current annual revenue and a maximum demand load of approximately 55 megawatts. The rates contained in the agreements were accepted by the FERC on Feb. 23, 1994.
During October 1993, the Company signed an electric power agreement to provide Michigan's Upper Peninsula Power Company (UPPCO) with up to 90 megawatts of baseload service, peaking service options and load regulation service options for 20 years beginning in 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. The rates, terms and conditions of the agreement are subject to FERC approval. The Michigan Public Utilities Commission must also approve the transaction. Beginning in 1998, annual revenues of approximately $12 million-$16 million are expected to be provided under the agreement, depending on contract options that UPPCO can exercise.
Legislative Changes - The Omnibus Budget Reconciliation Act of 1993 (the Act) was signed into law on Aug. 10, 1993. The only provision of the Act that had a significant effect on NSP was the increase in the federal corporate income tax rate from 34 percent to 35 percent retroactive to Jan. 1, 1993. The effect of the higher tax rate was an increase of about $3.2 million in income tax expense. Most of this cost increase was offset by higher revenues from 1993 rate increases approved in Minnesota. (See Note 2 to the Financial Statements.) Deferred tax liabilities were increased for the rate change by approximately $32 million. However, due to regulatory deferral of utility tax adjustments, earnings were reduced only by immaterial adjustments to deferred tax liabilities for non-regulated operations.
Wind-Generated Power - In October 1993, the Company signed a 25-year agreement for the purchase of 25 megawatts of wind-generated electric capacity, and associated energy to be produced in Minnesota. The wind generating plant is expected to be fully operational by May 1994. This contract is the first phase of the Company's plan to obtain 100 megawatts of wind-generated electricity by 1997. The Company can recover the cost of energy purchases through cost-of-energy adjustment clauses in electric rates.
Accounting Changes - As discussed in Note 13 to the Financial Statements, in 1993, NSP adopted Statement of Financial Accounting Standards (SFAS) No. 106 - - Employers' Accounting for Postretirement Benefits Other than Pensions and began recording postretirement 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 above, NSP's utility companies obtained rate recovery for substantially all of the increased costs (approximately $20 million) accrued under 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. Recent changes in interest rates have resulted in different actuarial assumptions used in the benefit cost calculations for postretirement benefits. Due to offsetting changes in other actuarial assumptions and demographics, NSP's benefit costs for such plans are not expected to increase from these changes in 1994. (See Note 13 to the Financial Statements for more information on changes in actuarial assumptions.)
NSP also adopted in 1993 SFAS No. 109 - Accounting for Income Taxes. Because the provisions of SFAS No. 109 are not materially different than the tax accounting procedures previously used by NSP, there was virtually no impact on earnings or financial condition.
In 1992, the Company changed its accounting method for recognizing revenue. Earnings in 1992 increased by 88 cents per share, including 73 cents related to prior years, from recording estimated unbilled revenues for utility service in Minnesota, North Dakota and South Dakota. (See Note 3 to the Financial Statements for more information on the effects of this accounting change.)
In 1994, NSP will be required to adopt SFAS No. 112 - Employers' Accounting for Postemployment Benefits. This standard will require the accrual of certain postemployment costs (such as injury compensation and severance) that are payable in future periods. The impact of adopting SFAS No. 112 is expected to be immaterial.
The Financial Accounting Standards Board (FASB) has announced preliminary plans to change the accounting for stock compensation expense effective in 1997 with disclosure requirements effective in 1994. Also, the FASB has approved a proposed change in employers' accounting for employee stock ownership plans effective in 1994. Based on NSP's review of these future accounting changes, NSP does not expect a material impact on its results of operations or financial condition.
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 FERC and the SEC currently are evaluating the financial presentation of these obligations, which could require a reporting reclassification as early as 1994.
1993 Compared with 1992 and 1991
NSP's 1993 earnings per share were $3.02, up 71 cents from the $2.31 earned before accounting changes in 1992 and equal to the $3.02 earned from continuing operations in 1991. In addition to the revenue and expense changes discussed below, 1993 earnings were impacted by a higher average number of common and equivalent shares outstanding for earnings-per-share calculations in 1993 due to the stock issuances discussed previously under "1993 Financing Activity."
Electric Revenues and Production Expenses
Revenues - Sales to retail customers, which account for more than 90 percent of NSP's electric revenue, increased 4.0 percent in 1993 and decreased 2.3 percent in 1992. Cool summer weather reduced sales in 1992 and, to a lesser extent, in 1993. During 1993, NSP added 14,353 retail customers, a 1.1-percent increase. Total sales of electricity, including wholesale, increased 7.3 percent in 1993.
On a weather-adjusted basis, sales to retail customers are estimated to have increased 2.1 percent in 1993 and 2.8 percent in 1992. Retail sales growth for 1994 is estimated to be 3.4 percent over 1993, or 2.2 percent on a weather-adjusted basis.
Sales to other utilities increased 22.2 percent in 1993 due to higher demand from utilities in flood-stricken Midwestern states.
The table below summarizes the principal reasons for the electric revenue changes during the past two years.
(Millions of dollars) 1993 vs 1992 1992 vs 1991 Retail sales growth (excluding weather impacts) $32 $34 Estimated impact of weather on retail sales volume 34 (85) Rate changes 74 20 Sales to other utilities 20 (2) Cost of energy clauses and other (8) (7) Total revenue increase (decrease) $152 $(40)
The 1992 sales growth is net of a $1.4-million revenue decrease, and 1992 cost-of-energy clause change is net of an $11 million revenue increase from recording unbilled revenues, which were not recorded in 1991.
Electric Production Expenses - Fuel expense for electric generation increased $19.4 million, or 6.6 percent, in 1993, compared with a decrease of $20.4 million, or 6.5 percent, in 1992. Total output from NSP's generating plants increased 8.4 percent in 1993 and decreased 3.1 percent in 1992. The fuel expense increase in 1993 was due to higher output to meet sales demand, partially offset by lower cost of fuel. The fuel expense decrease in 1992 was due to lower output (because the cool summer reduced demand) and lower cost of fuel. The lower cost of fuel per megawatt hour of generation in 1993 and 1992 reflects the increased use of low-cost purchases as discussed below.
Purchased power costs increased $53.0 million, or 34.1 percent, in 1993 and $20.0 million, or 14.7 percent, in 1992. The increase in 1993 was largely due to a demand expense increase of $42 million for the capacity charges from the power purchase agreements with Manitoba Hydro-Electric Board (MH), as discussed in Note 15 to the Financial Statements. Energy purchased from other utilities increased in both 1993 and 1992 due to economically priced energy available to meet growing retail demand and sales opportunities to other utilities that provided net ratepayer benefit. Demand expenses in 1994 are expected to increase $22 million over 1993 levels due to the MH agreements.
Revenues are adjusted for changes in electric 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 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.
Gas Revenues and Purchases
Revenues - NSP categorizes gas sales as firm (primarily space heating customers) and interruptible (commercial/industrial customers with an alternate energy supply). Firm sales in 1993 increased 17.0 percent over 1992 sales, while firm sales in 1992 decreased 5.6 percent from 1991. Warm weather in the first quarter of 1992 is the main cause for both of these variations. NSP added 11,728 firm gas customers in 1993, a 3.1-percent increase.
On a weather-adjusted basis, firm sales are estimated to have increased 7.2 percent in 1993 and 3.6 percent in 1992. NSP estimates 1994 firm gas sales to decrease by 2.9 percent relative to 1993, with a 2.2-percent decrease on a weather-adjusted basis due to an unbilled revenue adjustment in 1993. Without this adjustment, estimated weather-adjusted firm gas sales would have increased 0.9 percent in 1993 and would be estimated to increase 0.7 percent in 1994.
Interruptible gas deliveries, including sales of gas purchased for resale and customer-owned gas that NSP transported, increased 15.3 percent in 1993 and decreased 0.9 percent in 1992.
The table below summarizes the principal reasons for the gas revenue changes during the past two years.
(Millions of dollars) 1993 vs 1992 1992 vs 1991 Sales growth $17 $7 Estimated impact of weather on sales volume 28 (24) Acquisition of Viking Gas 9 Rate changes 9 Purchased gas adjustment and other 30 15 Total revenue increase (decrease) $93 $(2)
The 1992 sales growth is net of a $1.5-million decrease from recording unbilled revenues, which were not recorded in 1991.
Purchased Gas - The cost of gas purchased and transported increased $61.7 million, or 28.0 percent, in 1993 due to higher sendout and higher purchased gas prices. In 1992, the cost of gas purchased and transported increased $9.0 million, or 4.3 percent, due to higher purchased gas prices, somewhat offset by lower sendout relative to 1991. The average cost per thousand cubic feet (mcf) of gas sold in 1993 was 13.3 percent higher than it was in 1992, when the cost was 7.1 percent higher than it was in 1991. NSP views the increases in 1992 and 1993 as a recovery from unsustainably low wellhead gas prices in the 1990-91 period. Revenues are adjusted for changes in purchased gas costs from amounts currently included in approved base rates through purchased gas adjustment clauses.
Other Operating Expenses and Factors
Other Operation, Maintenance and Administrative and General - These expenses, in total, decreased by $27.2 million, or 4.0 percent, compared with an increase of 1.8 percent in 1992. The 1993 decrease was the result of fewer scheduled plant maintenance outages, reduced employee levels and lower administrative costs. The 1992 increase was the result of higher levels of scheduled plant and distribution system maintenance and higher employee wages. Wages in 1993 included an accrual of $14 million for incentive compensation. Due to lower earnings as a result of mild weather, compensation in 1992 did not include incentive amounts. (See Note 7 to the Financial Statements for a summary of administrative and general expenses.)
Conservation and Energy Management - Costs in 1993 were higher than in 1992 and 1991 because NSP's regulators have approved higher expenditure levels for conservation and demand-side management efforts.
Depreciation and Amortization - The increases in depreciation for all periods reflect higher levels of depreciable plant and, in 1993, changes in the depreciable lives of certain property. (See Note 1 to the Financial Statements.)
Property and General Taxes - Property and general taxes increased in each of the reported periods primarily as a result of higher property tax rates and property additions. Property taxes in 1992 were reduced by $4.5 million due to revisions to accrued 1991 taxes (payable in 1992) based on final tax statements.
Income Taxes - The variations in income taxes are primarily 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 9 to the Financial Statements for a detailed reconciliation of the statutory tax rate to the actual effective tax rate.)
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 low-cost short-term borrowings.
Other Income and Deductions-Net - Other income and deductions increased $9.7 million in 1993 and decreased $0.8 million in 1992. The increase in 1993 was due to higher non-regulated operating income from improved refuse-derived fuel (RDF) operations and acquired businesses. Non-regulated operating income in 1992 reflects one-time expenses from unsuccessful energy projects and reduced profitability of RDF operations. Decreases in interest income and non-regulated operating income in 1992 were offset by lower expenses for regulatory compliance and legal contingencies. Interest income declined in 1992 due to decreases in the amount of investments held. (See Note 7 to the Financial Statements for a summary of amounts included in other income and deductions.)
Interest Charges - Interest on long-term debt increased in 1993 due to new debt issued to finance business acquisitions and to refinance short-term borrowings. The increase was partially offset by interest savings from refinancing debt at lower rates. Other interest charges have increased due to amortization of refinancing costs, including debt issuance costs and reacquisition premiums.
Item 8
Item 8 - Financial Statements and Supplementary Data
See Item 14(a)-1 in Part IV for financial statements included herein.
See Note 17 of Notes to Financial Statements for summarized quarterly financial data.
INDEPENDENT AUDITORS' REPORT
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. Our audits also included the financial statement schedules listed in the accompanying table of contents in Item 14(a)2. 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, 1993 and 1992 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As discussed in Note 3 to the consolidated financial statements, the Companies changed their method of accounting for postretirement health care costs in 1993 and revenue recognition in 1992.
(Deloitte & Touche) DELOITTE & TOUCHE Minneapolis, Minnesota February 7, 1994
Notes to Financial Statements
1. Summary of 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 significant subsidiary companies. All significant intercompany transactions and balances have been eliminated in consolidation. The Company and its subsidiaries collectively are referred to herein as NSP.
Revenues - Revenues are recognized based on services provided to customers each month. Because customer utility 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. In 1991, revenues of the Company were recorded for billings rendered to customers on a monthly cycle billing basis and estimated unbilled revenues were not recorded. (See Note 3 for discussion of accounting change in 1992.)
The Company's rate schedules, applicable to substantially all of its customers, include cost-of-energy adjustment clauses, under which rates are adjusted to reflect changes in average costs of fuels, purchased power 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 power. 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 for construction, to qualified Construction Work in Progress (CWIP). The rates were 7.4 percent in 1993, 8.0 percent in 1992 and 10.0 percent in 1991. The amount of AFC capitalized as a construction cost in CWIP is credited to other income and interest charges. AFC amounts capitalized in CWIP are included in utility rate base for establishing utility service rates.
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 1993 study, as approved by the MPUC, recommended an increase of approximately $0.9 million in annual depreciation accruals. The 1992 study, as approved by the MPUC, recommended no change in 1992 depreciation. The Company also submitted in 1993 an average service life filing for transmission, distribution and general properties, which is filed every five years. The filing, as approved by the MPUC, increased depreciation by approximately $4.7 million from 1992 levels. Depreciation provisions, as a percentage of the average balance of depreciable property in service, were 3.47 percent in 1993, 3.36 percent in 1992 and 3.35 percent in 1991.
Decommissioning - The annual provision for the estimated decommissioning costs for the Company's nuclear plants has been calculated using an internal/external sinking fund method. The calculation, which results in annual charges to depreciation expense, is designed to provide for full accrual and rate recovery of the future decommissioning costs, including reclamation and removal, over the estimated operating lives of the Company's nuclear plants. Decommissioning of all nuclear facilities is planned to occur in the years 2010-2022 using the prompt dismantlement method, and the total obligation for decommissioning is expected to be funded approximately 45 percent by internal funds and 55 percent by external funds. Based on a 1990 study, the Company estimates total decommissioning costs will approximate $750 million in 1993 dollars, for which the Company has recorded $302 million in the accumulated provision for depreciation; $101 million of this balance has been deposited in external trust funds. An updated study will not be used for recording decommissioning accruals until approved by the MPUC. Such approval is not expected to occur until after the Minnesota Legislature makes its decision on fuel storage at the Company's Prairie Island nuclear plant. (See Note 15.) Decommissioning costs recorded for 1993, 1992 and 1991 were $43 million, $40 million and $40 million, respectively.
Nuclear Fuel Expense - The original cost of nuclear fuel is amortized to fuel expense on the basis of energy expended. Nuclear fuel expense also includes a disposal cost of 0.1 cent per kilowatt-hour sold from nuclear generation, as required by the Nuclear Waste Policy Act of 1982. Disposal expenses were $8.7 million, $6.8 million and $11.9 million for 1993, 1992 and 1991, respectively. Disposal expenses reflect reductions of $2.6 million in 1993 and $3.7 million in 1992 due to a change in the basis of charging customers, retroactive to 1983. Nuclear fuel expense in 1993 also includes about $1 million for a portion of the assessment from the U.S. Department of Energy (DOE) for the decommissioning and decontamination of the DOE's uranium enrichment facility. (See Note 8.)
Environmental Costs - Costs related to environmental remediation are accrued 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 benefit future operations. Where the expenditure relates to facilities currently in use (such as pollution control equipment), the costs are capitalized and depreciated over the future service periods. Estimated costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience. Accrued obligations are regularly adjusted as new information is received. 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. SFAS No. 109 requires the use of the liability method of accounting for deferred income taxes. Before 1993, NSP followed SFAS No. 96 - Accounting for Income Taxes, resulting in substantially the same accounting as 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 results in the creation of certain regulatory assets and liabilities related to income taxes as discussed in Note 8.
Investment tax credits are deferred and amortized over the estimated lives of the related property.
Cash Equivalents - NSP considers investments in certain debt instruments (primarily commercial paper) with a remaining 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 being amortized consistent with ratemaking treatment as established by regulators. Note 8 describes in more detail the nature and amounts of these regulatory deferrals.
Other Assets - NSP and its various subsidiaries have invested in many non-regulated projects whose earnings are reported on the equity method of accounting. Several of these projects are still in the development stage. Other investments include project development expenditures of $16.5 million as of Dec. 31, 1993, which have been capitalized based on expected recovery from cash flows of future project operations.
The purchase of the Minneapolis Energy Center by NRG in 1993 (see Note 4) at a price exceeding the underlying fair value of net assets acquired resulted in goodwill. This goodwill and other intangible assets acquired are being amortized using the straight-line method over 30 years. NSP will periodically evaluate 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 $12.6 million at Dec. 31, 1993, which are being amortized over the remaining maturity period of the related debt.
Reclassifications - Certain reclassifications have been made to the 1992 and 1991 income statement to conform with the 1993 presentation. In addition, the 1992 balance sheet has been reclassified to conform with the 1993 presentation of regulatory deferrals. These reclassifications had no effect on net income or earnings per share.
2. Rate Matters - 1993 Rate Increases
Minnesota Jurisdiction - In November 1992, the Company filed applications for 1993 rate increases with the MPUC totaling $119.1 million and $14.9 million for Minnesota retail electric and natural gas customers, respectively. This represented annual increases of approximately 9 percent and 5.8 percent, respectively. In December 1992, the MPUC issued orders granting interim increases (subject to refund) of $71.2 million (5.4 percent) for electric service and $8.4 million (3.3 percent) for gas service, effective Jan. 1, 1993. In June 1993, the Company adjusted its proposed electric rate increase to $112.3 million and its gas rate request to $12.4 million.
The Company received initial orders from the MPUC in September 1993 for both the gas and electric cases. Final orders came in December 1993 for the gas case and in January 1994 for the electric case, allowing annualized retail rate increases of $10.0 million (3.9 percent) for gas and $72.2 million (5.4 percent) for electric. The return on equity granted in both cases was 11.47 percent. Refunds of interim electric rates collected are required in the amount of approximately $12 million and are expected to be paid in May 1994. No refunds of interim gas rates collected are required. Final gas and electric rates are expected to be implemented in March and April 1994, respectively.
On Jan. 31, 1994, an appeal of the MPUC's determination on the allowed return on equity was filed with the Minnesota Court of Appeals by the Minnesota Department of Public Service, the Office of the Minnesota Attorney General and the Minnesota Energy Consumers intervenor groups. The appeal concerns the method of calculating the rate of return on common equity for both the electric and gas cases. The amount at issue is approximately $7 million in annual revenues for the Company. The ultimate financial impact of this appeal, if any, is not determinable at this time. A decision by the court is expected by the end of 1994.
Other Jurisdictions - The Wisconsin Company received approval of annualized retail rate increases of $8.0 million (3.1 percent) for Wisconsin electric customers and $1.1 million (1.8 percent) for Wisconsin gas customers. The new rates have been in effect since January 1993. The Company's approved annualized rate increase of $4.8 million (5.3 percent) for North Dakota electric customers was effective April 21, 1993. The Company's approved annualized rate increase of $4.2 million (6.5 percent) for South Dakota electric customers has been in effect since May 1, 1993. Increased annualized wholesale electric rates of $0.9 million (3.6 percent) were accepted by the FERC for nine Minnesota Company wholesale customers, effective Sept. 21, 1993. Increased annualized wholesale electric rates of $0.6 million (3.7 percent) were accepted by the FERC for the Wisconsin Company's 10 wholesale municipal utilities effective Sept. 1, 1993.
3. Accounting Changes
Postretirement Benefits - (See Note 13 for discussion of NSP's 1993 change in accounting for postretirement medical and death benefits.) There was no material effect on net income due to rate recovery of the expense increases. 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.
Income Taxes - As discussed in Note 1, NSP adopted SFAS No. 109 - Accounting for Income Taxes, effective Jan. 1, 1993. Adoption of SFAS No. 109 had no effect on earnings or financial condition due to its similarity to SFAS No. 96 - Accounting for Income Taxes, which NSP adopted in 1988 and which SFAS No. 109 supersedes.
Revenue Recognition - Effective Jan. 1, 1992, the Company changed its revenue recognition method to include the accrual of estimated unbilled revenues for electric and gas service in its Minnesota, North Dakota and South Dakota operations. This accounting practice has been used by the Wisconsin Company since 1977. This change resulted in a better matching of revenues and expenses, and is consistent with predominant utility industry practice and the ratemaking principles in NSP's two major jurisdictions (Minnesota and Wisconsin). The effect on 1992 income before accounting changes was an increase of approximately $9.8 million (16 cents per share), while the effect on total 1992 earnings was an increase of approximately $55.3 million (88 cents per share). If the accounting change had been applied retroactively to Jan. 1, 1991, income from continuing operations for 1991 would have been $204.4 million ($2.98 per share).
1994 Changes - In 1994, NSP will adopt SFAS No. 112 - Accounting for Postemployment Benefits and a new accounting standard for employers' transactions with ESOP plans. SFAS No. 112 requires the accrual of certain employee costs (such as injury compensation and severance) to be paid in future periods. The adoption of these new accounting standards is not expected to have a material effect on NSP's results of operations or financial condition.
4. Business Acquisitions
Viking Gas Transmission Company - On June 10, 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, for approximately $45 million, $32 million of which was financed with project debt. 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. Viking presently 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 the FERC.
Minneapolis Energy Center - On Aug. 20, 1993, NRG Energy, Inc. (NRG), a wholly owned subsidiary of the Company, acquired the assets of the Minneapolis Energy Center (MEC), a district heating and cooling system in downtown Minneapolis, Minn. The system uses steam and chilled water generating facilities to heat and cool buildings for about 85 heating and 25 cooling customers. The purchase price was $110 million, $84 million of which was financed with project debt. The purchase price primarily included facilities, long-term service agreements and goodwill.
Cenergy, Inc. - On Oct. 1, 1993, Cenergy, Inc., a non-regulated subsidiary of the Company, acquired certain assets of Centran Corporation (Centran), a natural gas marketing company. Cenergy, Inc., a national marketer of energy services with approximately 30 employees and approximately 300 customers, is headquartered in Minneapolis, Minn., and has additional offices in Houston and Corpus Christi, Texas; Louisville, Ky.; and Chesapeake, Va. The purchase price was $4 million. Assets purchased included proven oil and gas reserves, office equipment and a customer marketing data base.
Operating Results - The following represents unaudited operating results presented on a pro forma basis as if the acquisitions described above occurred on Jan. 1, 1992. Actual results, including Viking since June 10, 1993, MEC since Aug. 20, 1993, and the acquired Centran operations since Oct. 1, 1993, are shown for comparative purposes.
Year Ended Dec. 31 (Dollars in millions except EPS) 1993 1992
Actual Results Utility operating revenues $2 404.0 $2 159.5 Non-regulated operating revenues and sales $90.7 $62.6 Net income $211.7 $206.4 Earnings per share $3.02 $3.04
Pro Forma Amounts Utility operating revenues $2 411.9 $2 176.0 Non-regulated operating revenues and sales $161.2 $272.6 Net income $212.6 $204.9* Earnings per share $3.04 $3.01*
*Includes pretax writedown of $2.3 million (2 cents per share) of deferred environmental costs for Viking.
5. Cumulative Preferred Stock
The Company has two series of adjustable rate preferred stock. The dividend rates are calculated quarterly and based on prevailing rates of certain taxable government debt securities indices. At Dec. 31, 1993, the annualized dividend rates were $5.50 for series A and $5.50 for series B.
At Dec. 31, 1993, 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.
6. 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, 1993, the payment of cash dividends on common stock was not restricted.
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 other awards for restricted stock, stock appreciation rights and other performance awards. Performance awards are valued in dollars, but are paid in shares based on market price at the time of payment. Transactions under the various stock incentive programs, which may result in the issuance of new shares, were as follows:
Stock Awards (Thousands of shares) 1993 1992 1991
Outstanding Jan. 1 528.7 403.3 161.0 Options granted 196.9 201.8 232.2 Other stock awards 9.5 .8 16.9 Options and awards exercised (174.3) (57.0) 0 Options and awards forfeited (22.2) (20.1) (6.8) Other (1.5) (.1) 0 Outstanding at Dec. 31 537.1 528.7 403.3 Option price ranges: Unexercised at Dec. 31 $33.25-$43.50 $33.25-$40.94 $33.25-$36.44 Exercised during the year $33.25-$40.94 $33.25-$36.44
Using the treasury stock method of accounting for outstanding stock options, the weighted average number of shares of common stock outstanding for the calculation of primary earnings per share includes any dilutive effects of stock options and other stock awards as common stock equivalents. The differences between shares used for primary and fully diluted earnings per share were not material.
7. Detail of Certain Income and Expense Items
Administrative and general (A&G) expense for utility operations consists of the following:
(Thousands of dollars) 1993 1992 1991
A&G salaries and wages $52 085 $49 096 $48 710 Pensions and benefits - all utility employees 63 938 65 278 58 306 Information technology, facilities and administrative support 30 504 35 139 33 698 Insurance and claims 18 598 20 512 21 404 Other 17 410 17 950 17 742 Total $182 535 $187 975 $179 860
Other income and deductions - net consist of the following:
(Thousands of dollars) 1993 1992 1991
Non-regulated operations: Operating revenues and sales $90 654 $62 616 $76 342 Operating expenses (excluding income taxes) 81 403 65 744* 69 327 Pretax operating income (loss) 9 251 (3 128) 7 015 Interest and investment income 4 522 3 452 6 489 Equity in earnings of non-regulated projects 3 030 2 382 226 Charitable contributions (4 752) (4 585) (4 231) Costs disallowed recovery by regulators (296) (1 603) (6 100) Legal and regulatory contingencies (100) (1 300) (5 100) Other - net (excluding income taxes) (643) (752) (494) Income tax (expense) benefit (2 394) 4 493 1 905 Total $8 618 $(1 041) $(290)
*Includes $6.8 million in writedowns and losses from unsuccessful non-regulated projects.
8. Regulatory Assets and Liabilities
The following summarizes the individual components of unamortized regulatory assets and liabilities shown on the Balance Sheet at Dec. 31:
(Thousands of dollars) 1993 1992
AFC recorded in plant on a net-of-tax basis $165 915 $164 740 Losses on reacquired debt 48 529 33 185 Conservation and energy management programs 46 939 25 754 Environmental costs 45 568 505 Deferred postretirement benefit costs 15 514 2 112 State commission accounting adjustments 6 246 5 954 Unrecovered purchased gas costs and other 5 643 7 237 Total regulatory assets $334 354 $239 487 Excess deferred income taxes collected from customers $113 276 $106 975 Investment tax credit deferrals 120 123 119 847 Pension costs 6 969 2 017 Fuel refunds and other 3 512 3 627 Total regulatory liabilities $243 880 $232 466
The environmental costs item includes an assessment from the DOE for the Company's allocated share of decontamination and decommissioning costs related to the DOE's uranium enrichment facility. The Company's total DOE assessment of $46 million was made in 1993. This assessment will be payable in annual installments (currently $3.1 million) for up to 15 years and will be expensed on a monthly basis in the 12 months following each payment. 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 fully conform to the FERC's cost-of-energy adjustment clause procedures, management also expects recovery of these DOE assessments in retail ratemaking as payments are made each year.
The AFC regulatory asset and the tax-related regulatory liabilities result from NSP's income tax accounting practices as discussed in Note 1. The excess deferred income tax liability represents the net amount expected to be reflected in future customer rates based on the collection in prior ratemaking of deferred income tax amounts in excess of the actual liabilities recorded by NSP. This excess is the net effect of the use of flow-through tax accounting in prior ratemaking and the impact of changes in statutory tax rates in 1981, 1986-87 and 1993. This regulatory liability will change each year as the related deferred income tax liabilities change.
9. 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 1993 and 34 percent in 1992 and 1991) to net income before income tax expense. The reasons for the difference are as follows:
(Thousands of dollars) 1993 1992 1991
Tax Computed at Statutory Federal Rate $119 868 $84 015 $118 829 Increases (decreases) in tax from: State income taxes net of federal income tax benefit 20 838 13 421 20 822 Tax credits recognized (9 545) (8 846) (9 511) Nontaxable AFC - equity included in book income (2 565) (3 058) (2 562) Net-of-tax AFC included in book depreciation 4 403 4 518 4 594 Use of the flow-through method for depreciation in prior years 7 004 5 884 6 163 Effect of tax rate changes for plant-related items (4 648) (5 202) (6 798) Dividends paid on ESOP shares (3 009) (3 245) (3 199) Other - net (1 606) (1 311) (2 888) Total income tax expense from operations $130 740 $86 176 $125 450 Effective federal and state income tax rate 38.2% 34.9% 35.9% Composite federal and state statutory tax rate 40.9% 39.9% 39.9% Income taxes are comprised of the following expense (benefit) items: Included in utility operating expenses: Current federal tax expense $92 099 $69 198 $72 197 Current state tax expense 25 787 18 535 21 081 Deferred federal tax expense 15 010 8 518 25 157 Deferred state tax expense 4 431 2 533 7 779 Tax credits recognized (8 981) (8 115) (8 878) Total 128 346 90 669 117 336 Included in other income and expense: Current federal tax expense 7 853 1 490 3 708 Current state tax expense 2 289 613 1 128 Deferred federal tax expense (6 736) (4 518) (5 580) Deferred state tax expense (449) (1 347) (850) Tax credits recognized (563) (731) (311) Total 2 394 (4 493) (1 905) Included in discontinued operations: Current federal tax expense - operations 129 Current federal tax expense - gain 10 193 Current state tax expense - operations 28 Current state tax expense - gain 2 921 Deferred federal tax expense (2 271) Deferred state tax expense (539) Tax credits recognized (442) Total 10 019 Total income tax expense from operations $130 740 $86 176 $125 450
The components of NSP's net deferred tax liability at Dec. 31 were as follows:
(Thousands of dollars) 1993 1992 Deferred tax liabilities: Differences between book and tax bases of property $792 542 $765 957 Regulatory assets 128 991 90 856 Tax benefit transfer leases 87 924 97 852 Other 7 050 5 791 Total deferred tax liabilities $1 016 507 $960 456 Deferred tax assets: Regulatory liabilities $95 504 $92 165 Deferred investment tax credits 73 648 74 047 Deferred compensation, vacation and other accrued liabilities not currently deductible 62 811 29 715 Other 11 341 Total deferred tax assets $243 304 $195 927 Net deferred tax liability $773 203 $764 529
The Omnibus Budget Reconciliation Act of 1993 (the Act) was signed into law on Aug. 10, 1993, and increased the federal corporate income tax rate from 34 percent to 35 percent retroactive to Jan. 1, 1993. Deferred tax liabilities were increased for the rate change by approximately $32 million. However, due to regulatory deferral of utility tax adjustments, earnings were reduced by immaterial adjustments to deferred tax liabilities related to non-regulated operations.
10. 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 $320 million. The Company may, and has, applied property additions in lieu of cash payments on all series except for the 91/8 percent Series due July 1, 2019, as permitted by its First Mortgage Indenture. The Wisconsin Company may also 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 variable rate First Mortgage Bonds Series due March 1, 2011, and the variable rate City of Becker Pollution Control Revenue Bonds Series due March 1, 2019, and Sept. 1, 2019, are redeemable upon seven days' notice at the option of the bondholder. Thus, the principal amount of these bonds outstanding at Dec. 31, 1993, is reported under current liabilities on the balance sheet. Their tax-exempt interest rates are subject to change, weekly or at various periods, and are based on prevailing rates for similar issues. The interest rates applicable to these issues averaged 3.0 percent, 2.6 percent and 2.5 percent, respectively, at Dec. 31, 1993.
The Company and the Wisconsin Company have entered into interest rate swap agreements with the underwriters of certain first mortgage bond issues, which effectively convert the interest cost for this debt from fixed to variable rate as summarized below:
Amount of Term of Net Effective Swap (millions Swap Interest Cost at Series of dollars) Agreement Dec. 31, 1993
5 7/8% Series due Oct. 1, 1997 $100 Maturity 3.38%
7 1/4% Series due March 1, 2023 $20 March 1, 1998 5.56%
The variable rates change semiannually. Interest rate swap transactions are recognized as an adjustment of interest expense over the terms of the agreements.
Maturities and sinking-fund requirements on long-term debt are as follows: 1994, $90,618,000; 1995, $41,348,000; 1996, $61,931,000; 1997, $138,401,000; and 1998, $57,352,000.
On Jan. 24, 1994, the Company notified bondholders that $150 million of first mortgage bonds would be redeemed on Feb. 24, 1994. These bonds have been classified as long-term debt based on the refinancing of such debt using first mortgage bond proceeds obtained in February 1994.
11. Short-Term Borrowings
NSP has approximately $215 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 no borrowings against these credit lines at Dec. 31, 1993 and 1992. At Dec. 31, 1993, the Company had $106.2 million in short-term commercial paper borrowings outstanding at interest rates varying from 3.3 to 3.5 percent.
12. Fair Value of Financial Instruments
SFAS No. 107 - Disclosures About Fair Value of Financial Instruments requires disclosure of the estimated fair value of financial instruments. 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. 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. The estimated Dec. 31 fair values of NSP's financial instruments are as follows:
1993 1992 Carrying Fair Carrying Fair (Thousands of dollars) Amount Value Amount Value
Cash, cash equivalents and short-term investments $57 838 $57 838 $15 840 $15 840 Long-term decommissioning investments $101 378 $110 130 $68 800 $72 180 Long-term debt including current portion $1 524 085 $1 584 435 $1 373 876 $1 437 999
13. 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.
For regulatory purposes, the Company's pension expense is determined and recorded under the aggregate-cost method. SFAS No. 87 - Employers' Accounting for Pensions provides that any difference between the pension expense recorded for ratemaking purposes and the amounts determined under SFAS No. 87 should be recorded as assets or liabilities on the balance sheet.
Net annual periodic pension cost includes the following components:
(Thousands of dollars) 1993 1992 1991
Service cost-benefits earned during the period $25 015 $24 080 $22 097 Interest cost on projected benefit obligation 71 075 69 853 65 557 Actual return on assets (152 019) (115 455) (246 678) Net amortization and deferral 66 299 39 019 181 543 Net periodic pension cost determined under SFAS No. 87 10 370 17 497 22 519 Costs recognized (deferred) due to actions of regulators 5 117 2 741 (1 549) Total pension costs recorded during the period 15 487 20 238 20 970 Less costs recognized for 1988 early retirement program (165) (165) Net periodic pension cost recognized for ratemaking $15 487 $20 073 $20 805
The funded status of the plan as of Dec. 31 is as follows:
(Thousands of dollars) 1993 1992 Actuarial present value of benefit obligation: Vested $655 002 $614 446 Nonvested 139 346 129 183 Accumulated benefit obligation $794 348 $743 629 Projected benefit obligation $974 160 $914 019 Plan assets at fair value 1 244 650 1 156 782 Plan assets in excess of projected benefit obligation (270 490) (242 763) Unrecognized prior service cost (22 580) (14 790) Unrecognized net actuarial gain 315 049 269 086 Unrecognized net transitional asset 767 843 Net pension liability included in other liabilities $22 746 $12 376
The weighted average discount rate used in determining the actuarial present value of the projected obligation was 7 percent in 1993 and 8 percent in 1992. The rate of increase in future compensation levels used in determining the actuarial present value of the projected obligation was 5 percent in 1993 and 6 percent in 1992. While the 1993 assumption changes had no effect on 1993 pension costs, the effect of the changes in 1994 is expected to be a cost decrease of approximately $3 million. The assumed long-term rate of return on assets used for cost determinations under SFAS No. 87 was 8 percent in 1993 and 1992 and 8.5 percent in 1991. The effect of the 1992 change in the assumed rate of return was an increase of $4.3 million in the estimated SFAS No. 87 net periodic pension cost in 1992. Plan assets principally consist of common stock of public companies and U.S. government securities.
Postretirement Health Care - 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 prior 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 considers anticipated 1994 plan design changes, including Medicare integration, increased retiree cost sharing and managed indemnity measures not in effect in 1993.
Prior to 1993, NSP funded benefit payments to retirees internally. While NSP generally prefers to continue using internal funding of benefits paid and accrued, significant levels of external funding have been imposed by NSP's regulators, as discussed below, including the use of tax-advantaged trusts. Plan assets held in such trusts as of Dec. 31, 1993, consisted of investments in equity mutual funds and cash equivalents.
The following table sets forth the health care plan's funded status in 1993.
(Millions of dollars) Dec. 31, 1993 Jan. 1, 1993
APBO: Retirees $120.2 $105.8 Fully eligible plan participants 18.8 18.8 Other active plan participants 90.8 91.0 Total APBO 229.8 215.6 Plan Assets 6.1 0 APBO in excess of plan assets 223.7 215.6 Unrecognized net actuarial loss (1.3) Unrecognized transition obligation (204.8) (215.6) Postretirement benefit obligation included in other liabilities $17.6 $0
The assumed health care cost trend rate used in measuring the APBO at Dec. 31, 1993, was 14.1 percent for those under age 65 and 8.0 percent for those over age 65. The assumed cost trend rates are expected to decrease each year until they reach 4.5 percent for both age groups in the year 2004, after which they are assumed to remain constant. The trend rates used in the Jan. 1, 1993, calculations were 15.1 percent and 9.0 percent, respectively, eventually decreasing to 5.5 percent in 2004. A 1-percent increase in the assumed health care cost trend rate for each year would increase the APBO as of Dec. 31, 1993, by approximately 17 percent, and service and interest cost components of the net periodic postretirement cost by approximately 20 percent. The assumed discount rate used in determining the APBO was 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 both measurement dates. While the assumption changes made for the Dec. 31 calculations had no effect on 1993 benefit costs, the effect of the changes in 1994 is expected to be a cost decrease of approximately $2 million.
In 1992 and 1991, NSP recognized $12.8 million and $11.2 million, respectively, as the cost attributable to postretirement health care and death benefits based on payments made. The net annual periodic postretirement benefit cost recorded for 1993 consists of the following components:
(Millions of dollars) 1993 Service cost-benefits earned during the year $4.4 Interest cost (on service cost and APBO) 17.5 Actual return on assets (.1) Amortization of transition obligation 10.8 Net amortization and deferral .1 Net periodic postretirement health care cost under SFAS No. 106 32.7 Costs deferred due to actions of regulators (12.1) Net periodic postretirement health care cost recognized for ratemaking $20.6
Regulators of NSP's retail rates in Minnesota, Wisconsin and North Dakota have allowed full recovery of increased benefit costs under SFAS No. 106, effective in 1993. Expense recognition and rate recovery of increased 1993 accrual costs for Minnesota have been deferred until 1994 through 1996, consistent with rate orders received. External funding was required in Minnesota and Wisconsin to the extent it is tax advantaged; funding began for Wisconsin in 1993 and must begin by the next general rate filing for Minnesota.
Rate increases for Minnesota and Wisconsin wholesale electric customers were approved by the FERC and provided recovery of accrued SFAS No. 106 benefits under new rates beginning in September 1993. A rate increase for Viking wholesale gas customers was approved by the FERC, before Viking's acquisition by the Company, and provided recovery of accrued benefits beginning in July 1993. The FERC has required external funding for all benefits paid and accrued under SFAS No. 106.
The impact of adopting SFAS No. 106 on other utility jurisdictions and non-regulated operations was not material.
ESOP - NSP also has a leveraged Employee Stock Ownership Plan (ESOP) that covers substantially all employees. Employer contributions to this plan are generally made to the extent NSP realizes a tax savings on its income statement from dividends paid on shares held by the ESOP. Contributions to the ESOP in 1993, 1992 and 1991, which approximate expenses determined under the shares-allocated method, were $6,281,000, $6,415,000 and $6,326,000, 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 9.)
14. 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, 1993 and 1992, was $584,822,000 and $582,799,000, respectively. The corresponding accumulated provisions for depreciation were $114,251,000 and $96,035,000.
15. Commitments and Contingent Liabilities
Commitments - NSP estimates utility capital expenditures, including acquisitions of nuclear fuel, will be $396 million in 1994 and $1.8 billion for 1994-1998. There also are contractual commitments for the disposal of spent nuclear fuel.
Rentals under operating leases were approximately $27.5 million, $25.1 million and $22.7 million for 1993, 1992 and 1991, 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 1994 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 purchase and receipt of approximately $374 million of coal, $129 million of nuclear fuel and $607 million of natural gas, or to make payments in lieu thereof, under these contracts. 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 Purchases 1994-2005 500 Seasonal Participation Power Purchase 1994-1996 1994 150 1995-1996 250 Seasonal Peaking Power Purchases 1994-1996 200 Seasonal Diversity Exchanges: Summer exchanges from MH 1994 400 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 participation power purchase commitment is based on 80 percent of the costs of owning and operating Sherco 3 (adjusted to 1993 dollars). The total estimated annual costs for all MH agreements are $68.2 million for 1994 and approximately $70 million thereafter. These commitments, which represent about 38 percent of MH's output capability in 1993, account for approximately 13 percent of the Company's 1993 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 megawatts 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 Company and MH began construction in early 1992, received all the necessary approvals in 1993 and expect to complete construction in 1995.
The Company has an agreement with Minnkota Power Cooperative (MPC) for the purchase of summer season capacity and energy. From 1994 through 2001, the Company will buy 150 megawatts of summer season capacity for $12.4 million annually. From 2002 through 2015, the Company will purchase 100 megawatts of capacity for $10.0 million annually. Energy under the agreement 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 Rochester Public Utility, for the purchase of 270 megawatts in 1994 and 250 megawatts in 1995 and 1996. The annual cost of this capacity will be approximately $3 million.
The Company has agreements with several non-regulated entities to purchase electric capacity and associated energy. The total annual cost of current commitments for non-regulated installed capacity ranges from approximately $18 million for 119 megawatts in each of the years 1994-2011, decreasing thereafter to $0.8 million in 2033. The Company is negotiating a new power-purchase agreement with an independent power producer, which is expected to provide an additional 232 megawatts of electric capacity and associated energy, beginning in 1997.
Nuclear Insurance - The Company's public liability for claims resulting from any nuclear incident is limited to $9.4 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 $9.2 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 clean-up costs with coverage limits of $2.35 billion for the Prairie Island nuclear plant site and $2.15 billion for the Monticello nuclear plant site. The Prairie Island coverage consists of $950 million from American Nuclear Insurers/ Mutual Atomic Energy Liability Underwriters (ANI/MAELU) and $1.4 billion from Nuclear Electric Insurance Limited (NEIL). The Monticello coverage consists of $750 million from ANI/MAELU and $1.4 billion from NEIL. Under the insuring agreement with NEIL, the Company is subject to assessments of up to $23.3 million in each calendar year, 7.5 times the amount of its annual premium.
NEIL also provides insurance coverage for increased costs of generation and purchased power resulting from an accidental outage of a nuclear generating unit. Under the policy, the Company is subject to assessments of up to $6.7 million in each calendar year, five times the amount of its annual premium.
Environmental Contingencies - Other long-term liabilities include an accrual of $48 million at Dec. 31, 1993, for estimated costs associated with environmental reclamation, restoration and cleanup activities. Approximately $40 million of the liability relates to a 1993 DOE assessment as discussed in Note 8 to the Financial Statements. 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 decommissioning costs related to the Company's nuclear generating plants. Consistent with predominant industry practice, the Company's decommissioning accruals are included in Utility Plant-Accumulated Depreciation as discussed in Note 1 of the Financial Statements. The FERC, the FASB and the SEC currently are reviewing the accounting and reporting guidelines for decommissioning cost accruals. Until such guidelines require a different presentation, the Company plans to continue its current reporting of plant decommissioning obligations as accumulated depreciation.
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 and include it in depreciation expense.
(See Note 1 for discussion of NSP's pre-funding of the federal nuclear fuel disposal program.)
NSP has met or exceeded the removal and disposal requirements for polychlorinated biphenyls (PCB) equipment as required by state and federal regulations. NSP has removed nearly all PCB capacitors, transformers and equipment from its distribution system and power plants. Any future cleanup or remediation costs for past PCB disposal is unknown at this time. Minimal costs are expected to be incurred for future removal and disposal of PCB equipment. PCB-contaminated mineral oil is detoxified and beneficially reused or burned for energy recovery at a permitted facility.
The Company has been designated by the Environmental Protection Agency (EPA) as a "potentially responsible party" (PRP) for eight waste disposal sites to which the Company sent materials. Under applicable law, the Company, along with each PRP, could be held jointly and severally liable for the total remediation costs of all eight sites, which are estimated to approximate $85 million. However, the amount could be in excess of $85 million. The Company is not aware of the other parties' inability to pay or if responsibility for any of the sites is disputed by any party. The Company's share of the costs associated with these eight sites is approximately $2.5 million. Of this amount, about $1.4 million has already been paid in connection with two of the eight sites for which the Company has settled with the EPA and other PRPs. For the remaining six sites, neither the amount of cleanup costs nor the final method of their allocation among all designated PRPs has been determined. However, the Company has recorded an estimate of future costs of approximately $1 million for all six sites. 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 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 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 has been notified by a group of PRPs for possible responsibility 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 PRPs has been determined, it is not feasible to determine the outcome of this matter at this time.
The Company also is continuing to investigate 14 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 14 gas sites under investigation, the Company has already remediated one site and is actively taking remedial action at four of the sites. The Company has paid $3.1 million to date on these sites. The one remediated site continues to be monitored. The Company currently estimates its liability for these four sites to be approximately $5 million with payment expected over the next one to five years. The estimate is based on prior experience and includes investigation, remediation and litigation costs. The possible range of the liability for these four sites could be from $5 million to approximately $11 million, depending on the extent of contamination. As for the other nine sites, the Company currently estimates its liability to be approximately $2 million. This estimate assumes the development and remediation of one site with the remaining eight sites requiring only monitoring. The time frame for payment of these costs currently is undeterminable. 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 the Company's 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.
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 utility generating plants. The legislation enacted in 1990 is extremely complex and its overall financial impact on NSP will depend on the final interpretation and implementation of rules to be issued by the EPA. NSP is participating in the rulemaking process for the development of regulations that achieve the goals of the legislation in a reasonable and cost-effective manner. NSP has expended significant funds over the years to reduce sulfur dioxide emissions at its plants. Additional construction expenditures may be required to comply with parts of the Clean Air Act. Based on revised emission standards proposed by the EPA in 1993, NSP's excess emission allowances available under the Clean Air Act may be significantly reduced. Because NSP is only beginning to implement some provisions of the Clean Air Act, its overall financial impact is unknown at this time. The majority of NSP's power plants meet state and federal limits for opacity and air quality. Capital expenditures will be required for opacity compliance in 1994-1998 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.
In October 1992, the Company disclosed to the Minnesota Pollution Control Agency, the EPA and the Nuclear Regulatory Commission that 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, and the Company cooperated with state and federal authorities in the investigation of the reporting violations. No civil or criminal actions against the Company have been announced.
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. 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 four lawsuits have been filed, the litigation following this incident is in a preliminary stage and the ultimate costs to the Company are unknown at this time.
Operating Contingency - The Company is experiencing uncertainty regarding its ability to store used nuclear fuel from its Prairie Island nuclear generating facility. The facility stores its used nuclear fuel on an interim basis in a storage pool in the plant, pending the availability of a U.S. Department of Energy high-level radioactive waste storage or permanent disposal facility, or a private interim storage facility. At current operating levels, the pool will be filled in 1994 so the Company has proposed to augment Prairie Island's interim storage capacity by using steel containers for dry storage of used nuclear fuel on the plant site. Without additional onsite storage or significant modification of normal plant operations, Prairie Island Unit 2 would be shutdown in May 1995 and Prairie Island Unit 1 would be shutdown in February 1996. These two units supply about 20 percent of the Company's output. The Company has obtained a Certificate of Need from the MPUC allowing use of a limited number of steel containers, providing adequate storage at least through the year 2001. The Nuclear Regulatory Commission has also issued a license approving a dry storage facility on the plant site for Prairie Island's used fuel. However, in June 1993, the Minnesota Court of Appeals decided that the additional temporary storage facilities must be approved by the Minnesota Legislature. The Company has requested such approval from the Legislature and expects a decision on this issue during the current session, which began on Feb. 22, 1994. Although hearings have begun, the Company cannot predict what action the Minnesota Legislature will take.
The Company's net investment in the Prairie Island generating facility at Dec. 31, 1993, was $520 million. Future plant decommissioning costs in excess of amounts not accrued and collected in rates were $247 million at Dec. 31, 1993. Should the facility need to be shut down due to the full utilization of spent fuel storage capacity, the Company would request recovery of, and a return on, its investment and unrecorded plant decommissioning costs through utility rates. However, at this time the regulators' ultimate response to such a request is unknown. Without the generating capability of the Prairie Island facility, the Company estimates that an incremental increase in purchased power and fuel expenses of at least $200 million per year could be incurred. To the extent such additional costs represent energy purchases, current rate treatment provides recovery through cost-of-energy adjustments to customer rates. The Company will request recovery of costs associated with additional capacity purchases or investments in new plants through general rate filings. However, at this time the need for such costs and the regulators' ultimate response to such a request is unknown. The Company estimates that the present value of the cost of supplying replacement power and recovering its investment in the plant and unrecognized decommissioning costs will be $1.8 billion.
16. Segment Information
Year Ended Dec. 31 (Thousands of dollars) 1993 1992 1991
Utility operating revenues Electric $1 974 916 $1 823 316 $1 863 238 Gas 429 076 336 206 337 920 Total operating revenues $2 403 992 $2 159 522 $2 201 158 Utility operating income before income taxes* Electric $393 758 $321 837 $383 049 Gas 38 474 24 848 39 748 Total operating income before income taxes $432 232 $346 685 $422 797 Utility depreciation and amortization Electric $245 200 $225 134 $217 625 Gas 19 317 17 780 16 538 Total depreciation and amortization $264 517 $242 914 $234 163 Capital expenditures Electric $284 239 $367 522 $290 793 Gas 36 312 42 850 32 576 Other 41 144 17 443 26 493 Total capital expenditures $361 695 $427 815 $349 862 Net utility plant Electric $3 834 131 $3 812 688 $3 709 811 Gas 379 968 313 002 287 167 Total net utility plant 4 214 099 4 125 690 3 996 978 Other corporate assets 1 373 619 1 016 771 921 860 Total assets $5 587 718 $5 142 461 $4 918 838
*1992 amounts include an increase from the operating income impact of the 1992 change in accounting for revenues of $9.6 million for electric and $6.8 million for gas.
Item 9
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
During 1993 there were no changes in or disagreements with the Company's independent public accountants on accounting procedures or accounting and financial disclosures.
PART III Item 10
Item 10 - Directors and Executive Officers of the Registrant
Information required under this Item with respect to Directors is set forth in the Registrant's 1994 Proxy Statement for its Annual Meeting of Shareholders to be held April 27, 1994 on pages 2 through 7 under the caption "Election of Directors", which is incorporated herein by reference. Information with respect to Executive Officers is included under the caption "Executive Officers" in Item 1 of this report, and is incorporated herein by reference.
Item 11
Item 11 - Executive Compensation
Information required under this Item is set forth in the Registrant's 1994 Proxy Statement for its Annual Meeting of Shareholders to be held April 27, 1994 on pages 8 through 20 under the caption "Compensation of Executive Officers", which is incorporated herein by reference.
Item 12
Item 12 - Security Ownership of Certain Beneficial Owners and Management
Information required under this Item is set forth in the Registrant's 1994 Proxy Statement for its Annual Meeting of Shareholders to be held April 27, 1994 on page 7 under the caption "Share Ownership of Directors, Nominees and Named Executive Officers", which is incorporated herein by reference.
Item 13
Item 13 - Certain Relationships and Related Transactions
Information required under this Item is set forth in the Registrant's 1994 Proxy Statement for its Annual Meeting of Shareholders to be held April 27, 1994 on pages 3 through 5 under the captions "Class I - Directors Whose Terms Expire in 1996", "Class II - Nominees for Terms Expiring in 1997", "Class III - Directors Whose Terms, Expire in 1995", which is incorporated herein by reference.
PART IV Item 14
Item 14 - Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) 1. Financial Statements
Included in Part II of this report:
Independent Auditors' Report.
Consolidated Statements of Income for the three years ended December 31, 1993.
Consolidated Statements of Cash Flows for the three years ended December 31, 1993.
Consolidated Balance Sheets, December 31, 1993 and 1992.
Consolidated Statements of Changes in Common Stockholders' Equity for the three years ended December 31, 1993
Consolidated Statements of Capitalization, December 31, 1993 and 1992.
Notes to Financial Statements.
(a) 2. Financial Statement Schedules
Included in Part IV of this report:
Schedules for the three years ended December 31, 1993:
V - Utility Plant and Non-regulated Property VI - Accumulated Provision for Depreciation and Amortization of Utility Plant and Non-regulated Property.
Notes to Schedules V and VI.
IX - Short-Term Borrowings X - Supplementary Income Statement Information
Schedules other than those listed above 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* 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:
4.46* Mar. 1, 1949 (Exhibit 7.02 to File No. 2-7825).
4.47* Jun. 1, 1957 (Exhibit 2.13 to File No. 2-13463).
4.48* Aug. 1, 1964 (Exhibit 4.20 to File No. 2-23726).
4.49* Dec. 1, 1969 (Exhibit 2.03E to File No. 2-36693).
4.50* Sep. 1, 1973 (Exhibit 2.01F to File No. 2-48805).
4.51* Feb. 1, 1982 (Exhibit 4.01G to File No. 2-76146).
4.52* Mar. 1, 1982 (Exhibit 4.39 to Form 10-K for the year 1982, File No. 10-3140).
4.53* Jun. 1, 1986 (Exhibit 4.01I to File No. 33-6269).
4.54* Mar. 1, 1988 (Exhibit 4.01J to File No. 33-20415).
4.55* 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)
4.56* Apr. 1, 1991 (Exhibit 4.01L to File No. 33-39831).
4.57* Mar. 1, 1993 (Exhibit 4.01 to Form 8-K dated March 4, 1993, File No. 10-3140).
4.58* Oct. 1, 1993 (Exhibit 4.01 to Form 8-K dated September 21, 1993, File No. 10-3140).
10.01* Mid-continent Area Power Pool (MAPP) Agreement, dated March 31, 1972, between the local power suppliers in the North Central States area. (Exhibit 5.06B to File No. 2-44530).
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 10.35 to Form 10-K for the Year 1982, 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 10.40 to Form 10-K for the Year 1982, 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 10.45 to Form 10-K for the Year 1984, 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.
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 (Exhibit 10.14 to Form 10-K for the Year 1992, File No. 1-3034).
10.13* NSP Pension Plan (Exhibit 10.15 to Form 10-K for the Year 1992, File No. 1-3034).
10.14* NSP Employee Stock Ownership Plan (Exhibit 4.03, 4.04, 4.05 and 4.06 to Post-effective Amendment No. 5 to File No. 2- 61264).
10.15* NSP Retirement Savings Plan (Exhibit 10.17 to Form 10-K for the Year 1992, File No. 1-3034).
10.16 NSP Deferred Compensation Plan amended effective January 1, 1993.
12.01 Statement of Computation of Ratio of Earnings to Fixed Charges.
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.
(b) Reports on Form 8-K. The following reports on Form 8-K were filed either during the three months ended December 31, 1993, or between December 31, 1993 and the date of this report:
October 1, 1993 (Filed October 8, 1993) - Item 5. Other Events. Re: Disclosure of the purchase of certain assets of Centran Corporation, a natural gas marketing company, by a non-regulated subsidiary of the Company.
December 7, 1993 (Filed December 9, 1993) - Item 5. Other Events. Re: Disclosure of Underwriting Agreement and filing of a prospectus supplement relating to $170,000,000 First Mortgage Bonds ($100,000,000, Series due December 1, 2000) ($70,000,000, Series due December 1, 2005). 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 December 1, 2000 and Series Due December 1, 2005, and the computation of ratio of earnings to fixed charges.
December 10, 1993 (Filed December 27, 1993) - Item 5. Other Events. Re: Disclosure of a partnership agreement, in which a non-regulated subsidiary of the Company is a party of, to purchase a 400-megawatt share of the 900-megawatt Schkopau power plant near Leipzig, Germany. Disclosure of a partnership agreement, in which a non-regulated subsidiary of the Company is a party of, to acquire a portion of the mining, power generation and associated operations of the former state-owned, Mitleldeutsche Vereinigte Braunkohlenwerke Aktiengesellschaft.
January 31, 1994 (Filed February 9, 1994) - Item 5. Other Events. Re: Disclosure of an appeal filed with the Minnesota Court of Appeals by rate case intervenors concerning the method of calculating the rate of return on common equity. Disclosure that the Company has been named as a potentially responsible party at a Superfund site. Disclosure of the Company's Unaudited Consolidated Financial Statements for 1993. Item 7. Financial Statements, Pro Forma Financial Information and Exhibits. Filing of the Company's Unaudited Financial Statements for 1993.
February 10, 1994 (Filed February 14, 1994) - Item 5. Other Events. Re: Disclosure of Underwriting Agreement and filing of a prospectus supplement relating to $200,000,000 First Mortgage Bonds, Series due February 1, 1999. 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 due February 1, 1999, and the computation of ratio of earnings to fixed charges.
March 15, 1994 (Filed March 16, 1994) - Item 5. Other Events. Re: Disclosure of the results of Minnesota State Legislative Committee votes on the Company's plan to store additional spent nuclear fuel at its Prairie Island Nuclear Generating Plant. Disclosure of the International Brotherhood of Electrical Workers rejection of NSP's contract offer and the continuation of negotiations.
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES NOTES TO SCHEDULES V AND VI (Thousands of dollars)
For the year ended December 31, 1993: 1. Represents transfers and adjustments which were charged to the following accounts: Adjustment due to electric and gas meter inventory ($1 157) Adjustment due to gas distribution main inventory (2 252) Miscellaneous adjustments (413) Total ($3 822)
2. Represents transfers and adjustments which were charged to the following accounts: Accumulated depreciation of Viking Gas utility plant acquired $65 087 Adjustment due to gas distribution main inventory (2 252) Miscellaneous adjustments 241 Total $63 076
For the year ended December 31, 1992: 1. Represents transfers and adjustments which were charged to the following accounts: Miscellaneous adjustments ($129)
2. Represents transfers and adjustments which were charged to the following accounts: Miscellaneous adjustments ($634)
For the year ended December 31, 1991: 1. Represents transfers and adjustments which were charged to the following accounts: Adjustment due to spare parts inventory ($6 130) Miscellaneous adjustments (151) Total ($6 281)
2. Represents transfers and adjustments which were charged to the following accounts: Miscellaneous adjustments ($29)
Depreciation is computed on the straight-line method based on estimated useful lives of the various classes of property. Such provisions as a percentage of the average balance of depreciable property in service were 3.47% in 1993, 3.36% in 1992 and 3.35% in 1991. Nuclear fuel is amortized to fuel expense based on energy expended.
SCHEDULE IX
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES
SHORT-TERM BORROWINGS FOR THE THREE YEARS ENDED DECEMBER 31, 1993
Primarily Commercial Paper (Thousands of dollars)
1993 1992 1991
Balance at end of year $106 200 $146 561 $ 0
Weighted average interest rate at end of year 3.3% 3.6% 0
Maximum month-end amount $172 280 $162 000 $ 0 outstanding during the year (1-31-93) (7-31-92)
Average amount outstanding during the period (computed on a daily basis) $ 76 966 $ 80 957 $390
Weighted average interest rate during the year (computed on a daily basis) 3.3% 3.6% 6.0%
SCHEDULE X
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES
SUPPLEMENTARY INCOME STATEMENT INFORMATION FOR THE THREE YEARS ENDED DECEMBER 31, 1993
1993 1992 1991 (Thousands of dollars)
Taxes other than payroll and income taxes charged to operating expenses: Real and personal property $169 881 $154 060 $148 653 Gross earnings $26 292 $24 264 $24 787 Other $3 842 $3 620 $3 526
The amount of maintenance and depreciation charged to expense accounts other than those set forth in the statement of income are not significant.
All other items are less than 1% of total revenues.
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 23, 1994 (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
(Richard M Kovacevich) (Douglas W Leatherdale) Richard M Kovacevich Douglas W Leatherdale 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 President and Director
EXHIBIT INDEX
Method of Exhibit Filing No. Description
DT 10.09 Energy Supply Agreement between the Company and Liberty Paper, Inc.
DT 10.16 NSP Deferred Compensation 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 Auditors' Consent
DT = Filed electronically with this direct transmission.