Item 1 - Business
Northern States Power Company (the Company) was incorporated in 1909 under the laws of Minnesota. Its executive offices are located at 414 Nicollet Mall, Minneapolis, Minnesota 55401. (Phone 612-330-5500). The Company has two significant subsidiaries, Northern States Power Company, a Wisconsin corporation (the Wisconsin Company) and NRG Energy, Inc. (NRG), a Delaware corporation; and several other subsidiaries, including Cenergy, Inc. (which changed its name to Cenerprise, Inc. effective Jan. 1, 1996), a Minnesota corporation, and Viking Gas Transmission Company, a Delaware corporation (Viking). (See "Gas Utility Operations - Viking Gas Transmission Company" and "Non-Regulated Subsidiaries" herein for further discussion of these subsidiaries.) The Company and its subsidiaries collectively are referred to herein as NSP.
NSP is predominantly an operating public utility engaged in the generation, transmission and distribution of electricity throughout an approximately 49,000 square mile service area and the transportation and distribution of natural gas in approximately 156 communities within this area. Viking is a regulated natural gas transmission company that operates a 500-mile interstate natural gas pipeline. NRG manages several non-regulated energy subsidiaries.
The Company serves customers in Minnesota, North Dakota and South Dakota. The Wisconsin Company serves customers in Wisconsin and Michigan. Of the approximately 3 million people served by the Company and the Wisconsin Company, the majority are concentrated in the Minneapolis-St. Paul metropolitan area. In 1995, about 63 percent of NSP's electric retail revenue was derived from sales in the Minneapolis-St. Paul metropolitan area and about 55 percent of retail gas revenue came from sales in the St. Paul metropolitan area. (For business segment information, see Note 16 of Notes to Financial Statements under Item 8.)
NSP's utility businesses are currently experiencing some of the challenges common to regulated electric and gas utility companies, namely, increasing competition for customers, increasing pressure to control costs, uncertainties in regulatory processes and increasing costs of compliance with environmental laws and regulations. In addition, there are uncertainties related to permanent disposal of used nuclear fuel. (See Management's Discussion and Analysis under Item 7, Notes 14 and 15 of Notes to Financial Statements under Item 8 and "Electric Utility Operations - Capability and Demand and Nuclear Power Plants - Licensing, Operation and Waste Disposal," herein, for further discussion of this matter.)
PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION
Description of the Merger Transaction
As initially announced in the Company's Current Report on Form 8-K dated April 28, 1995 and filed on May 3, 1995 (the Company's 4/28/95 8-K), NSP, Wisconsin Energy Corporation, a Wisconsin corporation (WEC), Northern Power Wisconsin Corp., a Wisconsin corporation and wholly-owned subsidiary of NSP (New NSP) and WEC Sub Corp., a Wisconsin corporation and wholly owned subsidiary of WEC (WEC Sub), have entered into an Amended and Restated Agreement and Plan of Merger, dated as of April 28, 1995, as amended and restated as of July 26, 1995 (the Merger Agreement), which provides for a strategic business combination involving NSP and WEC in a "merger-of-equals" transaction (the Merger Transaction). The Merger Transaction, which was approved by the respective Boards of Directors and shareholders of the constituent companies, is expected to close shortly after all of the conditions to the consummation of the Merger Transaction, including obtaining applicable regulatory approvals, are met or waived. The goal of the Company and WEC is to receive approvals from all regulatory authorities by the end of 1996; however, some regulatory authorities have not established a timetable for their decisions. Therefore, timing of the approvals necessary to complete the Merger Transaction is not known at this time. See discussion of the regulatory proceedings under the caption "Utility Regulation and Revenues - Rate Matters by Jurisdiction" herein. (See additional discussion of the Merger Transaction under Item 7, Management's Discussion and Analysis, under Item 8, Note 18 of Notes to Financial Statements and pro forma financial statements included in exhibits listed in Item 14.)
In the Merger Transaction, the holding company of the combined enterprise will be registered under the Public Utility Holding Company Act of 1935, as amended. The holding company will be named Primergy Corporation (Primergy) and will be the parent company of both NSP (which, for regulatory reasons, will reincorporate in Wisconsin) and of WEC's principal utility subsidiary, Wisconsin Electric Power Company (WEPCO), which will be renamed "Wisconsin Energy Company." Wisconsin Energy Company will include the operations of WEC's other current utility subsidiary, Wisconsin Natural Gas Company, which was merged into WEPCO effective Jan. 1, 1996. It is anticipated that, following the Merger Transaction, except for certain gas distribution properties transferred to the Company, the Wisconsin Company will be merged into Wisconsin Energy Company.
Incorporated herein as exhibits by reference are the Merger Agreement, filed as an exhibit to New NSP's registration statement on Form S-4, and the press release issued in connection therewith and the related Stock Option Agreements (defined below) filed as exhibits to the Company's 4/28/95 8-K. The descriptions of the Merger Agreement and the Stock Option Agreements set forth herein do not purport to be complete and are qualified in their entirety by the provisions of the Merger Agreement and the Stock Option Agreements, as the case may be, and the other exhibits filed with the Company's 4/28/95 8-K.
Under the terms of the Merger Agreement, the Company will be merged with and into New NSP and immediately thereafter WEC Sub will be merged with and into New NSP, with New NSP being the surviving corporation. Each outstanding share of the Company's common stock, par value $2.50 per share (NSP Common Stock), will be canceled and converted into the right to receive 1.626 shares of common stock, par value $.01 per share, of Primergy (Primergy Common Stock). The outstanding shares of WEC common stock, par value $.01 per share (WEC Common Stock), will remain outstanding, unchanged, as shares of Primergy Common Stock. As of the date of the Merger Agreement, (April 28, 1995) the Company had 67.3 million common shares outstanding and WEC had 109.4 million common shares outstanding. Based on such capitalization, the Merger Transaction would result in the common shareholders of the Company receiving 50 percent of the common stock equity of Primergy and the common shareholders of WEC owning the other 50 percent of the common stock equity of Primergy. Each outstanding share of the Company's cumulative preferred stock, par value $100.00 per share, will be canceled and converted into the right to receive one share of cumulative preferred stock, par value $100.00 per share, of New NSP with identical rights (including dividend rights) and designations. WEPCO's outstanding preferred stock will remain outstanding and be unchanged in the Merger Transaction.
It is anticipated that Primergy will adopt the Company's dividend payment level adjusted for the exchange ratio. The Company currently pays $2.70 per share annually, and WEC's annual dividend rate is currently $1.47 per share. Based on the 1.626 stock exchange ratio and the Company's current dividend rate, the pro forma dividend rate for Primergy Common Stock would be $1.66 per share as of Dec. 31, 1995. However, the amount, declaration, and timing of dividends on Primergy Common Stock will be a business decision to be made by the Primergy Board of Directors from time to time based upon the results of operations and financial condition of Primergy and its subsidiaries and such other business considerations as the Primergy Board considers relevant in accordance with applicable laws.
Merger Consummation Conditions
The Merger Transaction is subject to customary closing conditions, including, without limitation, the receipt of all necessary governmental approvals and the making of all necessary governmental filings, including approvals of state utility regulators in Wisconsin, Minnesota and certain other states, the approval of the Federal Energy Regulatory Commission (FERC), the Securities and Exchange Commission (SEC), the Nuclear Regulatory Commission (NRC), and the filing of the requisite notification with the Federal Trade Commission and the Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the expiration of the applicable waiting period thereunder. (See discussion of the utility regulation proceedings under the caption "Utility Regulation and Revenues - Rate Matters by Jurisdiction" herein.) The Merger Transaction is also subject to receipt of assurances from the parties' independent accountants that the Merger Transaction will qualify as a pooling of interests for accounting purposes under generally accepted accounting principles. In addition, the consummation of the Merger Transaction is conditioned upon the approval for listing of such shares on the New York Stock Exchange.
During 1995, in addition to shareholder and Board of Directors approval, the Company and WEC took the following steps toward fulfilling the conditions to closing:
- Registration statements filed by WEC and the Company with the SEC with respect to the Primergy Common Stock to be issued in the Merger Transaction and New NSP Preferred Stock became effective.
- NSP and WEC received a ruling from the Internal Revenue Service indicating that the proposed merger transactions would qualify as independent tax-free reorganizations under applicable tax law.
- NSP and WEC filed for regulatory approval of the Merger Transaction with the FERC and state commissions. (See "Utility Regulation and Revenues - Rate Matters by Jurisdiction", herein, for further discussion of the status of these filings.)
- The Company filed for the NRC approval of the transfer of nuclear operating licenses from the Company to New NSP.
During 1996 NSP and WEC expect to make the following filings as part of the regulatory approval process for the Merger Transaction:
- NSP and WEC will file for SEC approval of the registration of Primergy under the Public Utility Holding Company Act of 1935, as amended, including a decision on possible divestiture of the existing gas operations and certain non-regulated businesses.
- Notification under the Hart-Scott-Rodino Antitrust Act of 1976, as amended, is expected to be filed in the second quarter of 1996 with the Department of Justice and Federal Trade Commission.
The Merger Agreement
The Merger Agreement contains certain covenants of the parties pending the consummation of the Merger Transaction. Generally, the parties must carry on their businesses in the or- dinary course consistent with past practice, may not increase dividends on common stock beyond specified levels, and may not issue capital stock beyond certain limits. The Merger Agreement also contains restrictions on, among other things, charter and bylaw amendments, capital expenditures, acquisitions, dispositions, incurrence of indebtedness, certain increases in employee compensation and benefits, and affiliate transactions.
In accordance with the Merger Agreement, upon the consummation of the Merger Transaction, James J. Howard, Chairman, President, and Chief Executive Officer of the Company will initially serve as the Chairman and Chief Executive Officer of Primergy for a minimum of 16 months after the effectiveness of the Merger Transaction and will thereafter serve only as Chairman of the Board of Primergy for a minimum of two years. Also, Richard A. Abdoo, Chairman, President and Chief Executive Officer of WEC shall initially hold the positions of Vice Chairman of the Board, President and Chief Operating Officer of Primergy and thereafter shall be entitled to hold the additional position of Chief Executive Officer when Mr. Howard ceases to be Chief Executive Officer. Mr. Abdoo will assume the position of Chairman when Mr. Howard ceases to be Chairman.
The Merger Agreement may be terminated under certain circumstances, including (1) by mutual consent of the parties; (2) by any party if the Merger Transaction is not consummated by April 30, 1997 (provided, however, that such termination date shall be extended to Oct. 31, 1997 if all conditions to closing the Merger Transaction, other than the receipt of certain consents and/or statutory approvals by any of the parties, have been satisfied by April 30, 1997); (3) by any party if either NSP's or WEC's shareholders vote against the Merger Transaction or if any state or federal law or court order prohibits the Merger Transaction; (4) by a non-breaching party if there exist breaches of any representations or warranties contained in the Merger Agreement as of the date thereof which breaches, individually or in the aggregate, would result in a material adverse effect on the breaching party and which is not cured within 20 days after notice; (5) by a non-breaching party if there occur breaches of specified covenants or material breaches of any covenant or agreement which are not cured within 20 days after notice; (6) by either party if the Board of Directors of the other party shall withdraw or adversely modify its recommendation of the Merger Transaction or shall approve any competing transaction; or (7) by either party, under certain circumstances, as a result of a third-party tender offer or business combination proposal which such party's board of directors determines in good faith that their fiduciary duties require be accepted, after the other party has first been given an opportunity to make concessions and adjustments in the terms of the Merger Agreement. In addition, the Merger Agreement provides for the payment of certain termination fees by one party to the other in the event of a willful breach or acceptance of a third-party tender offer or business combination.
Concurrently with the Merger Agreement, the parties have entered into reciprocal stock option agreements (the Stock Option Agreements) each granting the other an irrevocable option to purchase up to that number of shares of common stock of the other company which equals 19.9 percent of the number of shares of common stock of the other company outstanding on April 28, 1995 at an exercise price of $44.075 per share, in the case of NSP Common Stock, or $27.675 per share, in the case of WEC Common Stock, under certain circumstances if the Merger Agree- ment becomes terminable by one party as a result of the other party's breach or as a result of the other party becoming the subject of a third-party proposal for a business combination. Any party whose option becomes exercisable (the Exercising Party) may request the other party to repurchase from it all or any portion of the Exercising Party's option at the price specified in the Stock Option Agreements.
Results of the Merger Transaction
A preliminary estimate indicates that the Merger Transaction will result in net savings of approximately $2.0 billion in costs over 10 years. It is anticipated that the synergies created by the Merger Transaction will allow the companies to implement a modest reduction in electric and gas retail rates as described below followed by a rate freeze for electric and gas retail customers. This rate plan is currently being considered by various regulatory agencies.
The Company has proposed an average retail electric rate reduction of 1.5 percent and a four-year rate freeze in its retail jurisdictions. The electric rate reduction of 1.5 percent would be implemented as soon as reasonably possible following the receipt of the necessary approvals and closing of the Merger Transaction. This proposed rate reduction is made in conjunction with the proposal to recover deferred Merger Transaction costs and costs incurred to achieve merger savings through amortization over the same period. Customers will also receive directly the benefit of any fuel savings through the electric fuel adjustment clause mechanism.
The Company has proposed a two-year freeze for retail natural gas rates in its Minnesota jurisdiction and a 1.25 percent rate reduction along with a four-year freeze in its North Dakota jurisdiction. In addition, 38 percent of the Company's net gas savings available in 1997 are forecasted to be in the purchased cost of gas and would be reflected in customer rates automatically through the purchased gas adjustment clause mechanism. The remaining benefits will support the rate freeze, as well as offset a portion of the rising gas utility costs other than the purchased cost of gas in that time period.
The total savings identified as a result of the Merger Transaction represent aggressive goals which the Company and WEC intend to achieve, but the rate freeze will result in some risk to the shareholders if the anticipated cost savings are not realized. There is uncertainty regarding the timing and levels of the savings and costs associated with the Merger Transaction. The Company's proposal to unilaterally reduce rates and institute a rate freeze is designed to shield customers from these uncertainties. This proposal permits customers the opportunity to immediately begin realizing benefits of the Merger Transaction notwithstanding these uncertainties. Further, the four-year rate freeze permits the companies a reasonable time period to implement the changes necessary to achieve the contemplated savings.
The commitment not to increase electric rates does not prohibit tariff amendments and rate design changes which would not increase electric net income during the moratorium. NSP also proposes to continue to apply the Conservation Investment Program Annual Tracker Mechanism to recover conservation program costs. Finally, as part of this proposal, Primergy's operating utility subsidiaries will work with regulatory commissions to develop a plan for managing merger benefits for the year 2001 and beyond. The Company recognizes that during the four-year rate freeze period, it may experience certain significant but uncontrollable events which necessitate rate changes. Accordingly, as part of the rate plan proposal, the Company has identified certain events (large increases in taxes and government-mandated costs, and extraordinary events) which it believes should be excepted from the rate freeze. The exceptions are necessary in order to protect the Company from major cost increases or events which are beyond its control. The Company proposes that for these uncontrollable events it be allowed to file with the Commission during the rate freeze period for recovery of the costs related to these events.
Both NSP and WEC recognize that the divestiture of their existing gas operations and certain non-utility operations is a possibility under the new registered holding company structure, but have been working with the SEC to retain such businesses. Based on prior decisions and other actions by the SEC, the retention of both the gas and non-regulated businesses seems possible after consummation of the Merger Transaction. If divestiture is ultimately required, the SEC has historically allowed companies sufficient time to accomplish divestitures in a manner that protects shareholder value.
UTILITY REGULATION AND REVENUES
General
Retail sales rates, services and other aspects of the Company's operations are subject to the jurisdiction of the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), and the South Dakota Public Utilities Commission (SDPUC) within their respective states. The MPUC also possesses regulatory authority over aspects of the Company's financial activities including security issuances, property transfers when the asset value is in excess of $100,000, mergers with other utilities, and transactions between the regulated Company and affiliates. In addition, the MPUC reviews and approves the Company's electric resource plans and gas supply plans for meeting customers' future energy needs. The Wisconsin Company is subject to regulation of similar scope by the Public Service Commission of Wisconsin (PSCW) and the Michigan Public Service Commission (MPSC). In addition, each of the state commissions certifies the need for new generating plants and transmission lines of designated capacities to be located within the respective states before the facilities may be sited and built.
Wholesale rates for electric energy sold in interstate commerce, wheeling rates for energy transmission in interstate commerce, the wholesale gas transportation rates of Viking, and certain other activities of the Company, the Wisconsin Company and Viking are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). NSP also is subject to the jurisdiction of other federal, state and local agencies in many of its activities. (See "Environmental Matters" herein.)
The Minnesota Environmental Quality Board (MEQB) is empowered to select and designate sites for new power plants with a capacity of 50 megawatts (Mw) or more, wind energy conversion plants with a capacity of 5 Mw or more, and routes for transmission lines with a capacity of 200 kilovolts (Kv) or more, as well as evaluate such sites and routes for environmental compatibility. The MEQB may designate sites or routes from those proposed by power suppliers or those developed by the MEQB. No such power plant or transmission line may be constructed in Minnesota except on a site or route designated by the MEQB.
NSP is unable to predict the impact on its operating results from the future regulatory activities of any of the above agencies. To the best of its ability, NSP works to understand and comply with all rules and regulations issued by the various agencies.
Revenues
NSP's financial results depend, in part, on its ability to obtain adequate and timely rate relief from the various regulatory bodies, its ability to control costs and the success of its non-regulated activities. NSP's 1995 utility operating revenues, excluding intersystem non-firm electric sales to other utilities of $90 million and miscellaneous revenues of $60 million, were subject to regulatory jurisdiction as follows:
Percent Authorized Return on Common of Total Equity @ Dec. 31, 1995 Revenues (Electric Electric Gas & Gas) Retail: Minnesota Public Utilities Commission 11.47% 11.47% 74.1% Public Service Commission of Wisconsin 11.4** 11.4** 14.7 North Dakota Public Service Commission 11.50 14.0 5.1 South Dakota Public Utilities Commission * 3.1 Michigan Public Service Commission 12.25 14.5 0.6
Sales for Resale - Wholesale, Viking Gas and Interstate Transmission: Federal Energy Regulatory Commission * * 2.4
Total 100.0%
* Settlement proceeding, based upon revenue levels granted with no specified return. ** Return authorized for 1996 is 11.3 percent.
General Rate Filings
General rate increases (other than fuel and resource adjustment rate changes) requested and granted in previous years from various jurisdictions were as follows (note that 1992, 1993, 1994 and 1995 amounts represent annual increases (decreases) effective in those years, while 1991 increases represent annual increases requested in that year even if effective in a subsequent year):
Annual Increase/(Decrease) Year Requested Granted (Millions of dollars)
1991 118.7 68.0 1992 ----- ---- 1993 166.6 101.5 1994 (1.0) (1.0) 1995 (0.8) (0.8)
The following table summarizes the status of general rate increases (decreases) for rates effective in 1995.
Annual Increase/(Decrease) Requested Granted Status (Millions of dollars) Electric North Dakota-Retail* (0.8) (0.8) Order Issued (May 10, 1995) Gas 0.0 0.0 Total 1995 Rate Programs (0.8) (0.8)
* Does not include a refund to residential customers of approximately $1.5 million for the period Jan. 1, 1994, through June 1, 1994.
Ratemaking Principles in Minnesota and Wisconsin
Since the MPUC assumed jurisdiction of Minnesota electric and gas rates in 1975, several significant regulatory precedents have evolved. The MPUC accepts the use of a forecast test year that corresponds to the period when rates are put into effect and allows collection of interim rates subject to refund. The use of a forecast test year and interim rates minimizes regulatory lag.
The MPUC must order interim rates within 60 days of a rate case filing. Minnesota statutes allow interim rates to be set using (1) updated expense and rate base items similar to those previously allowed, and (2) a return on equity equal to that granted in the last MPUC order for the utility. The MPUC must make a determination on the application within 10 months after filing. If the final determination does not permit the full amount of the interim rates, the utility must refund the excess revenue collected, with interest. To the extent final rates exceed interim rates, the final rates become effective at the time of the order and retroactive recovery of the difference is not permitted. Generally, the Company may not increase its rates more frequently than every 12 months.
Minnesota law allows Construction Work in Progress (CWIP) in a utility's rate base instead of recording Allowance for Funds Used During Construction (AFC) in revenue requirements for rate proceedings. The MPUC has exercised this option to a limited extent so that cash earnings are allowed on small and short-term projects that do not qualify for AFC. (For the Company's policy regarding the recording of AFC, see Note 1 of Notes to Financial Statements under Item 8.)
The PSCW has a biennial filing requirement for processing rate cases and monitoring utilities' rates. By June 1 of each odd-numbered year, the Wisconsin Company must submit filings for calendar test years beginning the following January 1. The filing procedure and subsequent review generally allow the PSCW sufficient time to issue an order effective with the start of the test year.
The PSCW reviews each utility's cash position to determine if a current return on CWIP will be allowed. The PSCW will allow either a return on CWIP or capitalization of AFC at the adjusted overall cost of capital. The Wisconsin Company currently capitalizes AFC on production and transmission CWIP at the FERC formula rate and on all other CWIP at the adjusted overall cost of capital.
Fuel and Purchased Gas Adjustment Clauses in Effect
The Company's retail electric rate schedules, and most of the Wisconsin Company's wholesale rate schedules, provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy. Although the lag in implementing the billing adjustment is approximately 60 days, an estimate of the adjustment is recorded in unbilled revenue in the month costs are incurred. The Company's wholesale electric sales customers remaining with NSP do not have a fuel clause provision in their contracts. In lieu of fuel clause recovery, the contracts instead provide a fixed rate with an escalation factor. 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.
In September 1995, the MPUC approved a variance of Minnesota fuel adjustment clause rules to specifically allow for the inclusion of total wind purchase power costs and biomass related energy costs in the fuel adjustment clause. The Company must request approval for renewal of this variance annually. The Company is obligated by legislative mandate to purchase 425 Mw of wind generated energy and 125 Mw of farm-grown closed-loop bio-mass generated energy by 2002.
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, the Wisconsin Company may elect to file or be required to file for a change in rates (limited to the fuel issue) following an annual deviation in fuel costs of 2 percent or more. The adjustment approved is calculated on an annual basis, but applied prospectively. Effective Jan. 1, 1996, the fuel costs that are monitored include certain fuel costs including demand costs for sales and purchased power, which had been excluded prior to that date.
Gas rate schedules for the Company and the Wisconsin Company include a purchased gas adjustment (PGA) clause that provides for rate adjustments for changes in the current unit cost of purchased gas compared to the last costs included in rates.
By September 1 of each year, the Company is required by Minnesota statute to submit to the MPUC an annual report of the Purchased Gas Adjustments (PGA) for each customer class by month for the previous year commencing July 1 and ending June 30. The report verifies whether the utility is calculating the adjustments properly and implementing them in a timely manner. In addition, the MPUC review includes an analysis of procurement policies, cost-minimizing efforts, rule variances in effect or requested, retail transportation gas volumes, independent auditors' reports, and the impact of market forces on gas costs for the coming year. The MPUC has the authority to disallow certain costs if it deems the utility was not prudent in its gas procurement activities. The MPUC allowed full recovery of gas costs in response to the June 30, 1994, filing. The MPUC's determination regarding the filing for the year ended June 30, 1995, is pending.
In August 1995, the MPUC initiated an investigation - -- an industry-wide proceeding which will be open to participation from any interested party -- to examine whether the PGA mechanism is still appropriate for gas utilities based on the recent changes in the competitive environment in the gas utility industry and the authorization of performance-based gas purchasing regulation. The MPUC requested comments on the continued need for the PGA mechanism. The Company has filed comments supporting the continued use of the PGA, but urging the use of performance-based PGA mechanisms. An MPUC decision on the matter is pending.
The PSCW scheduled a generic hearing in March 1996 to consider an incentive-based gas cost recovery adjustment clause to replace the current purchased gas cost recovery adjustment clause. The incentive-based mechanism would allow recovery of fluctuations in gas costs based on an index, such as the spot market price. The new method would allow the Wisconsin Company to absorb the additional charge or benefit related to any difference between actual gas costs incurred and the index used for recovery. A PSCW decision is pending.
The Wisconsin Company's gas and retail electric rate schedules for Michigan customers include Gas Cost Recovery Factors and Power Supply Cost Recovery Factors, which are based on 12 month projections. After each 12 month period, a reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers.
Viking is a transportation-only interstate pipeline and provides no sales services. As a result, Viking terminated its PGA clause effective Nov. 1, 1993. Natural gas fuel for compressor station operations is provided in-kind by transportation service customers.
Resource Adjustment Clauses in Effect
In October 1994, the Company filed with the MPUC a petition for a miscellaneous rate change approving the implementation of an annual recovery mechanism for deferred electric conservation and energy management program expenditures. On Feb. 23, 1995, the MPUC voted to approve recovery of $41 million under a new electric rate adjustment clause for the period May 1995 through June 1996. Thereafter, the Company would be required to request a new cost recovery level annually. This decision allows for accelerated recovery of conservation and energy management program expenditures which is desirable because it lessens the risk for future stranded costs resulting from electric industry restructuring. Beginning in May 1995, a 2.45 percent surcharge to customer's bills appeared as a line item entitled "resource adjustment." A similar rate adjustment clause was approved for an annual recovery rate of $3.7 million in deferred and current gas conservation and energy management program expenditures beginning with November 1995 billings. In January 1996, a number of changes to the Company's regulatory deferral and amortization practices for Minnesota electric conservation program expenditures were approved. These changes allow the Company to expense rather than amortize new conservation expenditures beginning in 1996 and to increase its recovery of electric margins lost due to conservation activity. In addition, the Company received approval for 1996 and 1997 conservation expenditures at levels lower than 1995. On April 1, 1996, the Company expects to file for annual changes to the Minnesota electric conservation rate adjustment clause, incorporating the changes in January 1996, with an effective period of July 1, 1996, through June 30, 1997. These conservation cost recovery changes are intended to avoid a significant delay between the time when costs are incurred and their recovery in rates.
Rate Matters by Jurisdiction
Minnesota Public Utilities Commission (MPUC)
In 1991, the Minnesota legislature passed a law which granted the MPUC discretionary authority to approve a rate adjustment clause for changes in certain costs (including property taxes, fees and permits) incurred by Minnesota public utilities. In addition, the MPUC may approve a utility's use of the rate adjustment clause for billing customers if certain conservation expenditure levels are met. During 1995, the Company filed with the MPUC a request to make use of the rate adjustment clause to recover increased property tax costs from its retail gas customers in Minnesota. The MPUC denied the Company's request. No additional request to make use of the rate adjustment clause for the Company's electric or gas customers is currently pending with the MPUC.
In October 1994, as part of a response to 1994 Minnesota legislation related to fuel storage at the Prairie Island nuclear plant, the Company filed a miscellaneous rate change proposal with the MPUC which reflects a 50 percent discount on the first 300 kilowatt hours (Kwh) consumed each month by qualified low-income residential customers. In December 1994 the MPUC approved the Company filing. As a result, the Low Income Discount Rate became effective beginning with the October 1994 billing month for qualifying customers, with rate adjustments designed to recover from other customers the costs of the discount becoming effective Jan. 4, 1995. The ruling also eliminated the Conservation Rate Break and restructured the rates between customer classes, but did not significantly change overall revenue levels.
Approximately 35,000 of the Company's customers received assistance totaling more than $5 million from federally funded Low Income Household Energy Assistance Programs (LIHEAP) operated by the state of Minnesota in 1995. Other states served by NSP have similar programs. The federal LIHEAP program is currently facing significant opposition in securing funding to continue operations. Qualification for the Company's Low Income Discount Rate is based on eligibility for LIHEAP. The state of Minnesota would continue to certify eligibility even if LIHEAP is not funded. Management believes reductions in federal funding for LIHEAP exceeding 30 percent may result in an increase in the Company's uncollectible accounts for customers who cannot obtain other sources of assistance.
Gas utilities in Minnesota are also required to file for a change in gas supply contract levels to meet peak demand, to redistribute demand costs among classes, or exchange one form of demand for another. The Company filed in October 1995 to increase its demand entitlements due to projected increases in firm customer count, to increase the Minnesota jurisdictional allocation of total demand entitlements, effective Nov. 1, 1995, and to recover the demand entitlement costs associated with the increase in transportation and storage levels in its monthly PGA's. The MPUC approved this filing on March 7, 1996.
In April 1995, the MPUC opened up the rulemaking process to amend, repeal, or replace existing rules governing customer service standards for gas and electric utilities. The MPUC solicited comments from interested parties in June 1995. The MPUC formed an advisory task force in August 1995 representing interests from electric and gas utilities, low and fixed income consumer advocate groups, other state of Minnesota agencies and other various rate payer classes. Certain parties are proposing changes to the MPUC customer service rules that have the potential to increase the Company's costs associated with managing and collecting customer accounts. Examples of proposed changes are provisions to require NSP to have a signed contract for service, restrict collection of past-due bills to only the party(s) named on the bill, and to prohibit the Company from collecting a deposit for utility service from a low-income customer. The ultimate outcome of the rulemaking process is unknown at this time.
On Aug. 4, 1995 the Company filed for MPUC approval of the Merger Transaction with WEC. The Company proposed a rate plan which would reduce electric rates by 1.5 percent starting Jan. 1, 1997, or after receipt of all regulatory approvals and a four-year rate freeze thereafter, except for certain uncontrollable events. The rate plan was modified in March 1996 to also provide for a two-year freeze in gas rates. The proposed rate plan also included a request for deferred accounting and rate recovery of the costs associated with the Merger Transaction. Initial comments from the Department of Public Service, which recommended that the MPUC approve the Merger Transaction, and other interested parties were filed on Jan. 16, 1996. The Company's reply comments were filed on March 1, 1996. The MPUC's decision on the Merger Transaction approval filing is expected in the third or fourth quarter of 1996.
No general rate filings are anticipated in Minnesota in 1996.
North Dakota Public Service Commission (NDPSC)
In August 1994, the Company applied to the NDPSC for an annualized electric rate reduction of $3.6 million to reflect a correction in cost allocations to the North Dakota jurisdiction. In November 1994, the NDPSC approved the Company's request to make refunds to customers, effectively implementing the reduction as of June 1, 1994. These refunds were accrued in 1994 and paid in February 1995. In May 1995, the NDPSC approved a refund to residential customers of approximately $1.5 million for the period Jan. 1, 1994 through June 1, 1994 to reflect corrections to cost allocations for that period. This refund was accrued in 1994 and paid in June 1995. Also,the NDPSC approved an annualized rate reduction of $750,000 for North Dakota commercial and industrial electric customers, which was effective prospectively from June 1, 1995.
On Aug. 4, 1995, the Company filed for NDPSC approval of the Merger Transaction with WEC. The Company proposed a rate plan which would reduce electric rates by 1.5 percent on Jan. 1, 1997, or after the close of the Merger Transaction, and implement a four-year rate freeze thereafter, with certain exceptions. A 1.25 percent rate reduction and a four-year rate freeze in gas rates was also proposed. Public hearings on the Merger Transaction were held in Minot, Grand Forks and Fargo, North Dakota in November and December 1995. A technical hearing was held in March 1996. The NDPSC's decision is expected on the Merger Transaction approval filing later in 1996.
At a hearing in December 1995, the NDPSC approved the phase-out of the use of deferred accounting for conservation program costs. Effective retroactively to Jan. 1, 1995, the Company will expense conservation program costs related to North Dakota operations in the year the costs are incurred. This change increased expenses by $1.7 million in 1995 and is expected to increase 1996 expenses by a similar amount. Costs incurred prior to 1995 will continue to be amortized in jurisdictional expenses.
On Jan. 17, 1996, the Company filed a plan with the NDPSC for a $485,000 annual reduction in base gas rates in North Dakota. This plan responds to a NDPSC staff audit of gas earnings for this jurisdiction for the years 1991 to 1995. The Company also proposed to adjust its base cost of gas to more current levels and make modifications to its PGA and annual gas cost true-up mechanism. The changes are proposed to be effective prospective from the date of the NDPSC order approving the plan. NDPSC action is pending. This reduction would be in addition to the merger-related gas rate reductions.
No other general rate filings are anticipated in North Dakota in 1996.
South Dakota Public Utilities Commission (SDPUC)
There were no general rate filings in South Dakota in 1995. On Sept. 8, 1995, the SDPUC determined that it did not have jurisdiction to approve or deny the Merger Transaction with WEC. However, a rate filing to reflect merger savings in electric rates is expected on or around the time of the consummation of the Merger Transaction. No other general rate filings are anticipated in South Dakota in 1996.
Public Service Commission of Wisconsin (PSCW)
On June 1, 1995, the Wisconsin Company filed with the PSCW for a $2.7 million increase, or 3.6 percent, in natural gas rates and no change in electric rates to be effective Jan. 1, 1996. On Oct. 6, 1995, the PSCW ordered a $4.8 million decrease, or approximately 1.7 percent on an annual basis, in the Wisconsin Company's retail electric rates. The new rates took effect Jan. 1, 1996. On Dec. 21, 1995, the PSCW ordered a $2.5 million increase, or approximately 3.4 percent on an annual basis, in the Wisconsin Company's retail gas rates and a return on common equity of 11.3 percent to be effective Jan. 1, 1996.
The Wisconsin Company and WEC filed for approval of the Merger Transaction on Aug. 4, 1995. WEC requested deferred accounting treatment and rate recovery of costs associated with the proposed merger. Rate plans were filed that proposed a 1.5 percent annual retail electric rate reduction and a $4.2 million annual reduction in gas rates (of which $.2 million relates to the Wisconsin Company) at the time of the merger and four-year rate freezes thereafter with certain exceptions. On March 15, 1996, the Wisconsin Company filed full stand-alone rate cases for a 1997 test year on an unmerged basis. This special filing was requested by the PSCW to set a baseline cost for evaluating savings associated with the Merger Transaction. The Wisconsin Company filing described revenue deficiencies for both electric and gas utilities, however no rate increases were requested. The Wisconsin Company intends to attempt to manage its cost levels to avoid such rate increases. On March 18, 1996, the Wisconsin Company filed testimony and exhibits supporting the original Aug. 4, 1995 Merger Transaction filing. Technical hearings on the merger are expected in July 1996. The PSCW's decision on the merger approval filing is expected in the fourth quarter of 1996.
The Wisconsin Company is scheduled to file a general rate case in June 1997, for rates effective in 1998, as required by the PSCW biennial filing requirement.
Michigan Public Service Commission (MPSC)
The Wisconsin Company and WEC filed for MPSC approval of the Merger Transaction on Aug. 4, 1995. Electric and gas rate plans were filed that proposed a rate reduction and a four-year rate freeze. The MPSC's decision on the Merger Transaction is expected in the first half of 1996.
Electric Transmission Tariffs and Settlement (FERC)
In 1990, NSP filed a transmission services tariff for certain transmission customers. New rates were effective under the filing, subject to refund, for the period Dec. 29, 1990, through Oct. 31, 1994. NSP has recorded an estimated liability at Dec. 31, 1995, for potential transmission rate refunds under this tariff based on the FERC order dated Sept. 21, 1993. On Feb. 5, 1996, the FERC denied NSP's request for rehearing and required NSP to submit a refund compliance filing in the amount of $1.7 million. This refund amount is approximately the same as estimated liabilities recorded.
In March 1994, NSP filed a revised open access transmission tariff with the FERC. On May 25, 1994, the FERC accepted the filing, with the new rates effective Nov. 1, 1994, subject to refund. The FERC also ruled the tariff would be subject to the requirement that NSP offer transmission service using terms and conditions comparable to its own use of the system. On April 11, 1995, an Offer of Settlement (the Settlement) was entered into by a majority of the parties involved in this proceeding. The settlement agreement includes a transmission tariff that complies with the FERC transmission pricing policy which calls for comparability of service and pricing, network service, and unbundling of ancillary charges such as scheduling and load following. On May 25, 1995, the Administrative Law Judge (ALJ) issued to the FERC a Certification of Contested Order of Settlement. Although there are no genuine issues of material fact and all parties support certification of the Settlement, the ALJ stated the Settlement is contested since FERC Staff and Electric Clearinghouse list numerous provisions that need to be modified in response to the issuance of proposed rulemaking referred to as the Mega NOPR. (See discussion and definition of Mega-NOPR below.) The ALJ further stated the Settlement is not affected by the issuance of the Mega-NOPR, even though the FERC in the Mega-NOPR stated that any settlement approved prior to the issuance of the Final Rule will be made subject to the outcome of the final rule. The FERC approved the Settlement on Feb. 14, 1996, subject to the outcome of the final rule, in 1996. The revenue effect on the Company is an increase of approximately $200,000 per year. The new tariff allows NSP to comply with transmission pricing provisions of open access transmission requirements of the Energy Policy Act of 1992.
Open Access Transmission Proceedings (FERC)
In March 1995, the FERC issued a Notice of Proposed Rulemaking on Open Access Non-Discriminatory Transmission Services and a Supplemental Notice of Proposed Rulemaking on Stranded Investment (together called the "Mega-NOPR"); and a proposal to require Real-Time Information Networks (RIN).
The stated purpose for the Mega-NOPR is to create a vigorous wholesale electric market by requiring transmission providers to offer open access to their transmission systems. The FERC is proposing to require utilities to unbundle power sales from transmission. This "unbundling service" requirement would apply only to new requirements contracts and new coordination trade contracts. The FERC did not require utilities to divest or separate their generation businesses from their transmission businesses. The FERC also proposes to not disrupt any existing power or transmission contracts.
The Mega-NOPR would apply to all utilities under the FERC's jurisdiction and would require each utility to file individual tariffs. The FERC also seeks to require non- jurisdictional transmission providing entities (such as municipals and cooperatives) to offer open access by including a reciprocity clause in their individual tariffs, so that those who take service from a FERC jurisdictional utility must offer the open access. The rule will be implemented in two stages. In the first stage, generic pro forma tariffs rates would take effect under financial data filed with the FERC on Form 1. In the second stage, utilities and their customers could file to modify the tariffs and rates within the limits of non- discriminatory open access. A Procedural Order which was concurrently issued with the Mega-NOPR grandfathers NSP's transmission tariff into the second stage.
The Mega-NOPR would require transmission providers to offer network, point-to-point and ancillary services. Ancillary services would include scheduling and dispatching, load following,imbalance resolution, reactive power support and system protection.
In the Mega-NOPR, the FERC further clarified its guidelines for utilities to recover stranded investment costs due to facilitation of open access to a competitive market. The FERC stated that it recognized the vital link between the prior stranded cost proposal issued in 1994 and the open access initiative. In the Mega-NOPR, the FERC has proposed a "backstop" position, whereby it will only entertain stranded cost filings when a state regulatory commission does not have authority under state law to address stranded costs at the time retail wheeling (which is the transmission to retail customers of power generated by a third party, in competition with supplies from the host utility) takes place. The Mega-NOPR also provides that the FERC will entertain utilities' requests for stranded-cost recovery even after a state has addressed the case. However, if a state commission has authority to act, but does not do so, a utility may not seek recovery from the FERC.
With regard to the RIN proposal, FERC is considering requiring that each public utility create an electronic bulletin board to ensure that potential purchasers of transmission services have access to information to enable them to obtain open access transmission services on a non-discriminatory basis from the public utility. The proposed RIN would include a wide range of information such as: availability of transmission services (including ancillary services); rates; hourly transfer capacities; hourly amounts scheduled; transmission and unit outages; load flow data; and transaction specific information on all requests for transmission service, including requests by transmission owner's wholesale power marketing department.
In its response to the RIN and Mega NOPR proposals, NSP filed comments which indicated support for FERC's open access objective and for FERC's position that it should be a backstop for the recovery of stranded costs. NSP also asserted that its open access transmission tariffs filed in 1994 comply with the spirit of the Mega-NOPR.
Proposed Merger Approval Proceedings (FERC)
On July 10, 1995, the Company and WEC filed an application and supporting testimony with the FERC seeking approval of the Merger Transaction to form Primergy Corporation. The filing consisted of the merger application, the proposed joint transmission tariff, and an amendment to the Company's Interchange Agreement with the Wisconsin Company. On Sept. 11, 1995, several parties, who had previously filed for intervenor status in the FERC Merger Transaction approval application filing, filed interventions and protests. On Oct. 10, 1995, the Company and WEC replied to petitions for intervention and requests for hearings. On or about Oct. 25, 1995, intervenors filed responses to the Company and WEC's reply. On Nov. 9, 1995, the Company and WEC filed a response to the intervenors reply comments. Additional intervenor comments were filed on Nov. 22, 1995. The Company has met all previously stated FERC criteria for merger approvals.
The issues raised by intervenors with respect to the merger application at the FERC are primarily related to two areas: the impact on competition and the nature of the cost savings. The Company has settled with several intervenors and is continuing to meet with interested parties in the FERC proceeding, seeking resolution of the intervenor issues.
On Jan. 31, 1996, the FERC issued a ruling which put the merger approval filing on an accelerated schedule. The FERC set only one of six merger issues raised by intervenors to a hearing. The FERC ordered a hearing regarding the effect of the proposed merger on bulk power competition. The FERC commissioners ordered the judge's initial decision by Aug. 30, 1996, and briefs on exception by Sept. 30, 1996. In March 1996, the PSCW requested that the FERC broaden the scope of the merger application hearing to evaluate whether the proposed merger will impair effective state oversight of retail rates. While the Company expects the FERC's decision on the merger approval filing in the fourth quarter of 1996, the approval process may extend beyond 1996.
In February 1996, the Company and WEC agreed to freeze wholesale rates for four years subsequent to the Merger Transaction.
Intervenors argue that competition will be adversely affected because the Company and WEC will constrain the transmission system at the interconnections between the NSP system and a group of upper Wisconsin and northern Michigan utilities, allowing the Company and WEC to increase the price they charge for energy. In response to the intervenor concerns, the Company and WEC have committed to make whatever changes are required by FERC in its open access proceeding to ensure the appropriate level of access is achieved. The Company and WEC have filed to expand the capacity of the interconnections and further expansion is being pursued. When the interface is constrained, any economic energy sales that the Company and WEC make into the upper Wisconsin and northern Michigan utilities will be at incremental cost. The Company and WEC will waive their AES (native load) and Mid-Continent Area Power Pool (MAPP) line loading relief procedure priorities for internal and economy transactions through the interface. To the extent that a regional transmission operator has not been established by the time of the merger, the Company and WEC are willing to establish an unaffiliated entity as an Independent Tariff Administrator that will schedule transmission use and otherwise ensure that transmission is provided on a nondiscriminatory basis. (See discussion of the negotiations to convert MAPP to a Regional Transmission Group at the "Electric Utility Operations - Capability and Demand" section herein.)
Other Wholesale Rate Proceedings (FERC)
In December 1993, the Company, in compliance with a FERC order in the Central Maine case requiring that the FERC approve all interstate, inter-utility contracts, filed over 300 such contracts with the FERC for review. The FERC established 76 separate dockets for review. Absent FERC acceptance, the contracts could have been declared null and void, possibly resulting in full refunds for all amounts paid. The FERC has accepted each of the 76 dockets with little or no change. The Company completed full resolution of the Central Maine compliance filings in 1995.
ELECTRIC UTILITY OPERATIONS
Competition
NSP's electric sales are subject to competition in some areas from municipally owned systems, rural cooperatives and, in certain respects, other private utilities and independent power producers. Electric service also increasingly competes with other forms of energy. The degree of competition may vary from time to time, depending on relative costs and supplies of other forms of energy. Although NSP cannot predict the extent to which its future business may be affected by supply, relative cost or promotion of other electricity or energy suppliers, NSP believes that it will be in a position to compete effectively.
In October 1992, the President signed into law the Energy Policy Act of 1992 (Energy Act). The Energy Act amends the Public Utility Holding Company Act of 1935 (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 the FERC and the Mega-NOPR issued by the FERC (as discussed in "Utility Regulation and Revenues," herein) reflect the trend toward increasing transmission access under the Energy Act. The FERC Mega-NOPR seeks to standardize the terms, conditions and rate development approaches to ensure fundamental principles underlie open access tariffs. NSP shares the FERC view that such tariffs are a necessary step to support functional unbundling of generation and transmission and the evolution of a competitive electric power market place. NSP's tariff filed in 1994 and settled in 1995, preceded the FERC's pro-forma tariff and provided significant input to its development. The final rules the FERC will issue as a result of the Mega-NOPR are expected to be aligned with the pro-forma tariff. The use of pro-forma tariffs in merger filings enables the FERC to separate and exclude open access transmission from other issues in the Primergy merger docket. This treatment was requested in the Primergy merger filing that included the pro-forma tariff. The Energy Act's ultimate impact on NSP cannot be predicted at this time.
NSP had municipal wholesale revenues from sales of electricity of approximately $44 million in 1995 and approximately $57 million in 1994. The trend of increased competition has resulted in changes in the negotiation of contracts with municipal wholesale customers. In the past several years, these customers have begun to evaluate a variety of energy sources to provide their power supply. While the full impact of competition on this part of NSP's business is unknown at this time, the following changes have occurred.
In 1990, 16 of the Company's 19 municipal wholesale customers in Minnesota began reviewing their long-term power supply options. Eight customers created a joint action group, the Minnesota Municipal Power Agency (MMPA), to serve their future power supply needs. An additional wholesale customer became an associate member of the MMPA. In 1992, these nine municipal customers notified the Company of their intent to terminate their power supply agreements with the Company effective July 1995 or July 1996. In July 1995, seven of these nine customers took power supply service from MMPA and are now transmission only customers of the Company. The loss of these seven customers in 1995 resulted in a revenue decrease of approximately $12 million from 1994 levels. The two other wholesale customers will terminate their power supply service with the Company in July 1996 and are expected to become wheeling customers of the Company. These two customers provided revenues of $3.6 million in 1995. These nine customers affiliated with MMPA are expected to provide estimated annual wheeling revenues of nearly $3 million.
Of the remaining 10 municipal wholesale customers of the Company, nine have full requirements contracts with terms expiring in the years 1999 through 2005, with three- to four- year cancellation notice provisions. The other customer became a member of Central Minnesota Municipal Power Agency (CMMPA) in 1995. CMMPA currently has seven members and the Company has provided the energy requirements to CMMPA since it was formed in 1992. The Company recently won a bid to continue supplying energy to CMMPA for six years beginning in March 1996. In addition, during 1995, the Company signed contracts with three other municipals to provide energy and some capacity for terms ranging from five to 10 years, beginning in the years 1995 through 1998. The annual revenues from these three contracts are estimated to be approximately $1 million.
The Wisconsin Company had 10 wholesale customers at Dec. 31, 1995, with revenues of approximately $18 million in 1995. In 1995, the Wisconsin Company offered its wholesale customers discounts from the FERC authorized rate. Seven of the 10 municipal customers elected to renew or extend their contracts to receive these discounts. As part of the settlement agreement between NSP, WEC and the Wisconsin intervenors in the Merger Transaction approval filing, the cities of Medford and Rice Lake have a five year power supply agreement. For the first year the two cities receive discounted full requirements service, for the remaining four years, they receive service at a negotiated, fixed rate. Upon completion of the term, NSP will have no further obligation to service these two customers. The other customer did not elect to sign a new contract, but continues with its existing contract. Due to these changes, 1996 revenues are estimated to decrease from 1995 revenues by approximately $0.6 million.
In 1993, the Company signed an electric power agreement with Michigan's Upper Peninsula Power Company with service beginning in 1998. (See Management's Discussion and Analysis under Item 7 for more discussion.)
In addition, with the development of the electric industry competition, the Company has experienced an increase in requests for the use of its transmission system. A large portion of these requests can be identified as due to the increase in FERC approved power marketers. In 1995, the Company filed 23 transmission service agreements for FERC approval, including 10 with power marketers. The annual transmission revenue in 1995 from this activity was immaterial. However, in 1996 revenues are expected to increase due to growth of power market activity in this region. Competition from FERC approved power marketers is expected to increase. As of Dec. 31, 1995, power marketers had filed 175 applications with the FERC and 151 of the applications had been approved by the FERC including 24 from utility affiliates (one of which is Cenergy). For the year 1995, power marketers in the United States made transactions of 26 million megawatt hours. The ultimate impact on NSP's sales and purchases of power, and NSP's power marketing revenue (from Cenergy activity) due to power marketing activity is not determinable.
Many states are currently considering retail competition. Regulators in Minnesota, Wisconsin and North Dakota are currently considering what actions they should take regarding electric industry competition. In 1994, the PSCW asked each utility in the state for comments regarding retail competition. In response to the request, the Wisconsin Company filed the following recommendations: (i) competition should be phased in for retail markets by customer classes, with all customers having choice of supplier by 2001, (ii) the generation segment of the industry should be deregulated by 2001, (iii) prudent stranded costs should be recovered prior to the advent of retail wheeling and (iv) utilities and other competitors should have a level playing field for issues such as obligation to serve, eminent domain, requirements for demand side management, funding of social programs, opening of retail markets to competition and other issues. Also, as an outcome of the responses to the PSCW, a task force was formed by the PSCW to analyze the industry restructuring necessary in the state of Wisconsin. In 1995, the PSCW voted to adopt an electric utility restructuring plan which includes a 32-step phase-in of retail wheeling by the year 2001. A key component of the plan is to provide the protections necessary to ensure that consumers are not harmed in an increasingly competitive environment. One component of the plan is to have an independent system operator to control transmission access.
In Minnesota, regulators have developed draft principles for electric industry restructuring to provide a framework from which to proceed. One of the principles supports an open transmission system and the establishment of a robust wholesale competitive market. At this time, Minnesota regulators have not established definitive timelines for industry restructuring or changes. NSP believes the transition to a more competitive electric industry is inevitable and beneficial for all consumers. NSP supports an orderly and efficient transition to an open, fair and competitive energy market for all customers and suppliers. The timing of regulatory actions and their impact on NSP cannot be predicted and may be significant.
Michigan also has a retail wheeling experiment, which is currently being challenged in court. The experiment is limited to its two largest utilities and customers larger than $50 million. The Wisconsin Company's customers are not included in this experiment.
The Company is facing potential competition from a retail customer's proposed cogeneration project. Koch Refining Co. (Koch), the Company's largest customer which provides approximately $30 million in annual revenues to NSP, proposes to build a cogeneration plant that would burn petroleum coke, a refinery byproduct, to produce between 180 and 250 Mw of electricity. This would be enough supply for Koch's own use plus an additional 80 to 150 Mw to be sold on the wholesale market. Koch is requesting a legislative exemption from Minnesota personal property tax for its plant. While NSP supports the reduction of taxes on generating facilities, it believes any reduction should be applied to all generating facilities so that there are no unfair tax advantages available to some generators. This project has several implications for NSP: 1) Koch could become a competitor as it seeks markets for its excess capacity; 2) Koch's capacity would also represent a potential power source for NSP; and 3) Koch's plan represents a potential loss of a large retail customer. The project's anticipated three-year lead time will allow NSP to respond appropriately.
NSP has proposed to fill future needs for new generation through competitive bid solicitations. The use of competitive bidding to select future generation sources allows the Company to take advantage of the developing competition in this sector of the industry. The Company's proposal, which has been approved by both the MPUC and the PSCW, allows NRG to bid in response to Company solicitations for proposals. The Company is also seeking permission from the MPUC to include its own generation construction department as a bidder in the competitive process.
Retail competition represents yet another development of a competitive electric industry. Management plans to continue its ongoing efforts to be a low-cost supplier of electricity and an active participant in the more competitive market for electricity expected as a result of the Energy Act. NSP will continue to work with regulators to complete the tariff and infrastructure that will support an electric competitive environment. The proposed merger with WEC is a key strategy in ensuring competitive prices and high-quality services for customers. Additional actions the Company is pursuing to position itself for the competitive environment include: creative partnership solutions with strategic customers including communities; focusing on the unique needs of national account customers; competitive pricing alternatives; improved reliability; implementation of service guarantees; ease of customer access including 24 hour, 7 days/week operation; substantial customer convenience and flexibility improvements via a new Customer Service System which includes appointment scheduling upon first contact, improved outage call response, and a wide array of new billing options; and centralization of common services and aggressive cost management. In addition, NSP will compete for service outside its traditional service area. This process has begun via NSP's Cenergy subsidiary.
Capability and Demand
Assuming normal weather, NSP expects its 1996 summer peak demand to be 7,326 Mw. NSP's 1996 summer capability is estimated to be 8,843 Mw, (net of contract sales) including 1,153 Mw (including reserves) of contracted purchases from the Manitoba Hydro-Electric Board, a Canadian Crown Corporation (Manitoba Hydro) and 899 Mw of other contracted purchases. The estimate assumes 7,731 Mw of thermal generating capability and 1,440 Mw of hydro and wind generating capability. Of the total summer capability, NSP has committed 328 Mw for sales to other utilities. Of the estimated net capability, including the interconnection with Manitoba Hydro, 30 percent has been installed during the last 10 years.
NSP's 1995 maximum demand of 7,519 Mw occurred on July 13, 1995. Resources available at that time included 7,100 Mw of Company-owned capability and 1,910 Mw of purchased capability net of contracted sales. Due to the MAPP's penalty for reserve margin shortfalls and to be prepared for weather uncertainty at the lowest potential cost, NSP carried a reserve margin for 1995 of 20 percent. The minimum reserve margin requirement as determined by the members of the MAPP, of which NSP is a member, is 15 percent. In March 1996, the members of MAPP approved a proposal to convert MAPP into a Regional Transmission Group (RTG). This proposal will now be submitted to the FERC for approval before April 1, 1996. By converting MAPP to an RTG, members will have more input into transmission access within other member's territories. This is one of the proposals in response to intervenor concerns in the FERC regulatory approval proceeding of the Company's proposed merger with WEC. (See "Utility Regulation and Revenues - Rate Matters by Jurisdiction" herein for more information and Note 15 of Notes to Financial Statements under Item 8 for more discussion of power agreement commitments.)
The Company is continuing an extensive performance- based transmission and distribution reliability program. This program includes preventative maintenance on transmission and distribution power lines, improvements to existing equipment and implementation of new technology. The program focuses on the leading causes of outages consisting of lightning, trees and underground cable and also concentrates on reducing the number of human-error outages. In 1995, the reliability program resulted in a reduction in the number of outages to the Company's feeders, which had been the most likely to experience an outage, from 600 in 1994 to 425 in 1995. The outage count on the one feeder most likely to experience an outage was reduced from 24 in 1994 to 12 in 1995. Reliability goals for 1996 have already been formulated, and include emphasis on reliability- focused maintenance programs, improved restoration processes, and improved customer communication/access.
In 1994, NSP signed a long term power purchase contract for 245 Mw of annual capacity for 30 years. The purchase will be from a natural gas-fired combined cycle facility that NSP can dispatch as system requirements dictate. NSP expects the facility to be available in May 1997.
The Company filed an electric resource plan with the MPUC on July 3, 1995. 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 resources to meet such needs. The plan contains: conservation programs to reduce the Company's peak demand and conserve overall electricity use; economic purchases of power; and programs for maintaining reliability of existing plants. It also includes an approximate schedule of the timing of such resource needs. The plan does not anticipate the need for additional base-load generating plants during the balance of this century and assumes that all existing generating facilities will continue operating through their license period or useful life. The plan also assumes that modifications will be made to the Monticello nuclear generating facility to increase its capacity by 46 Mw by 1997.
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 1995
1998 2002 2006 2010
Renewables* 200 (40) 525 (212) 525 (212) 525 (212) Peak 0-71 63-505 415-822 415-1,067 Intermediate 0-148 0-581 579-734 579-889 Base 0 0 247-1,253 927-2,176 Demand Side Management 512 968 1,348 1,657 Total 552-771 1,243-2,266 2,801-4,369 3,790-6,001
* Includes the Prairie Island legislation mandate of an additional 400 Mw of wind generation and 125 Mw of biomass generation. The amounts shown in parentheses are the estimated MAPP accredited capacity values at the time of system peak demand. The MAPP accreditation procedure for wind is intended to measure wind generation's contribution to system reliability at the time of system peak demand. Because wind generation is a variable resource the accredited capacity is less than the installed capacity.
The resource plan proposes to satisfy the above resource needs through a combination of the following options:
Sources of Energy to Meet Needs
- Continued operation of existing generation facilities. - Demand reduction of an additional 1,400 Mw by 2010 through conservation and load management. - 425 Mw of wind generation in service by 2002. - 125 Mw of biomass generation in service by 2002. - Acquisition of competitively priced resources to meet changing needs, i.e. competitive bidding.
The Company intends to seek competitive bids in 1996 for the following resources: 100 Mw of wind generation; 75 Mw of biomass generation; 100 Mw of peaking generation; 200 Mw of intermediate generation and 600 Mw of baseload generation. If the Koch Refining Co. proposed cogeneration project is built, as discussed previously, the Company's resource plan and bidding schedules might be affected.
In connection with the approval of used nuclear fuel storage facilities at the Company's Prairie Island generation plant, legislation was enacted in 1994 which established certain resource commitments, as discussed in Note 15 to the Financial Statements under Item 8 and "Electric Utility Operations - Nuclear Power Plants - Licensing, Operation and Waste Disposal," herein. The Company has taken steps to comply with the requirements of these resource commitments. Twenty-five Mw of third party wind generation has been fully operational since May 1, 1994. With respect to the additional 100 Mw of wind energy to be under contract by the end of 1996, the Company has obtained a site designation from the Minnesota Environmental Quality Board (MEQB), and selected Zond Systems, Inc. to supply the wind energy. The Company must now secure wind rights from an unsuccessful bidder, which has indicated it will not voluntarily transfer the wind rights. The Company has commenced litigation to expedite resolution of the wind rights dispute. Siting and design activities are proceeding while wind rights acquisition efforts continue. The Company also used a competitive bid solicitation to acquire 50 Mw of farm-grown closed-loop biomass generation. An independent evaluator reviewed proposals from bidders regarding this 50 Mw of farm- grown closed-loop biomass generation and made a recommendation to the Company in January 1996. On March 7, 1996, the Company submitted a filing with the MPUC rejecting all bids primarily due to price concerns. The Minnesota Legislature is considering several bills which could affect the existing biomass resource commitment. In order to include any legislative changes, the Company is deferring its decision on future biomass generation plans until after the expected close of the current Minnesota legislative session in April 1996. The Company's construction commitments disclosed in "Capital Spending and Financing", herein, include the known effects of the 1994 Prairie Island legislation. The impact of the legislation on power purchase commitments is not yet determinable.
Minnesota utilities are required under a 1993 Minnesota law to use values established by the MPUC, which assign a range of environmental costs with each method of electricity generation that is not part of the price of electricity, when evaluating and selecting generation resource options. These values are known as environmental externalities. NSP, along with several other parties, is currently participating in a proceeding initiated by the MPUC to establish final externality values. An order from this proceeding is not expected until mid-1996. Pending the outcome of this proceeding, utilities are required to use interim externality values which were set by the MPUC in early 1994. The critical issue and uncertainty for NSP is the extent to which the use of these externality values will cause NSP to select higher priced generation resources and increase NSP's cost to provide electricity. The value assigned to the carbon dioxide factor will most likely have the greatest impact on NSP in terms of costs added for new coal or gas-fired plants. The high end of the range of interim externality values add about 1.75 cents per kwh to a typical new coal plant and about .65 cents per kwh to a natural gas-fired plant. The carbon dioxide value comprises about 80 percent to 90 percent of these amounts. NSP will be affected in 1996 when it issues a Request for Proposal for peak, intermediate and base plants. Depending on the values established and how they are applied, externalities could significantly affect resources available to NSP to meet future demands for electricity.
NSP continues to implement various Demand Side Management (DSM) programs designed to improve load factor and reduce NSP's power production cost and system peak demands, thus reducing or delaying the need for additional investment in new generation and transmission facilities. NSP currently offers a broad range of DSM programs to all customer sectors, including information programs, rebate and financing programs, and rate incentive programs. These programs are designed to respond to customer needs and focus on increasing NSP's value of service that, over the long term, will help its customer base become more stable, energy efficient and competitive. During 1995, NSP's programs reduced system peak demand by approximately 202 Mw. Since 1986, NSP's DSM programs have achieved 1,224 Mw of summer peak demand reduction, which is equivalent to 16 percent of its 1995 summer peak demand. In its 1995 Resource Plan and Conservation Improvement Program (CIP) Filings with the MPUC and the Minnesota Department of Public Service respectively, the Company proposed to reduce its DSM expenditures from approximately 3.5 percent of revenues in 1995 to 2.2 percent of revenues by 1997. The corresponding long-term energy savings goals would be reduced by approximately 50 percent, while the long-term demand savings goals would be reduced by approximately 25 percent. The CIP filing was approved with modification, requiring the Company to spend 2.8 percent and 2.6 percent of its annual revenues on DSM in 1996 and 1997, respectively. A decision on the long-term energy savings goal in the resource plan is anticipated later in 1996.
In 1994, the MPUC increased the Company's cost recovery and incentives for DSM by allowing recovery of a portion of the lost margins due to DSM impacts on electric revenues. This lost margin recovery, subject to annual review by the MPUC, was approximately $7 million in 1995 and $3 million in 1994. In addition, the MPUC allowed the Company to earn $5 million in 1995 and $4 million in 1994 for DSM investment returns through an incentive program that rewards the attainment of specified conservation goals.
Energy Sources
For the year ended Dec. 31, 1995, 45 percent of NSP's Kwh requirements was obtained from coal generation and 30 percent was obtained from nuclear generation. Purchased and interchange energy provided 21 percent, including 15 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 (57 percent), nuclear (38 percent), renewable and other fuels (5 percent).
The following is a summary of NSP's electric power output in millions of Kwh for the past three years:
1995 1994 1993
Thermal plants 33,802 32,710 33,130 Hydro plants 1,049 922 1,001 Purchased and interchange 9,189 9,054 8,541 Total 44,040 42,686 42,672
Many of NSP's power purchases from other utilities are coordinated through the regional power organization MAPP, pursuant to an agreement dated March 31, 1972, with amendments filed in 1994. NSP is one of 58 members in MAPP consisting of eight investor-owned systems, eight generation and transmission cooperatives, three public power districts, eight municipal systems, the Department of Energy's Western Area Power Administration and 30 Associate Participants. The MAPP agreement provides for the members to coordinate the installation and operation of generating plants and transmission line facilities. The terms and conditions of the MAPP agreement and transactions between MAPP members are subject to the jurisdiction of the FERC. The 1972 MAPP agreement, as amended, was accepted for filing by the FERC on Dec. 15, 1994.
Fuel Supply and Costs
Coal and nuclear fuel will continue to dominate NSP's regulated utility fuel requirements for generating electricity. It is expected that approximately 97 percent of NSP's fuel requirements, on a Btu basis, will be provided by these two fuels over the next several years, leaving 3 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 1995 and the estimated fuel mix for 1996 and 1997 are as follows:
Fuel Use on Btu Basis (Est) (Est) 1995 1996 1997
Coal 57.9% 59.9% 59.7% Nuclear 39.0% 36.8% 36.6% Other 3.1% 3.3% 3.7%
The Company normally maintains between 20 and 50 days of coal inventory depending on the plant site. The Company has long-term contracts providing for the delivery of up to 100 percent of its 1996 coal requirements. Coal delivery may be subject to short-term interruptions or reductions due to transportation problems, weather and availability of equipment.
The Company expects that more than 98 percent of the coal it burns in 1996 will have a sulfur content of less than 1 percent. The Company has contracts with three Montana coal suppliers (Westmoreland Resources, Decker Coal Company, and Big Sky Coal Company) and four Wyoming suppliers (Rochelle Coal Company, Antelope Coal Company, Kerr-McGee Coal and Black Thunder Coal Company) for a maximum total of 65 million tons of low-sulfur coal for the next 5 years. These arrangements are sufficient to meet the requirements of existing coal-fired plants. They also permit the Company to purchase additional coal when such purchase would improve fuel economics and operations. The Company has options from suppliers for over 100 million tons of coal with a sulfur content of less than 1 percent that could be available for future generating needs. The plants in the Minneapolis-St. Paul area are about 800 miles from the mines in Montana and 1,000 miles from the mines in Wyoming. Coal delivered by rail provides the Company with an economical source of fuel.
The estimated coal requirements of the Company at its major coal-fired generating plants for the periods indicated and the coal supply for such requirements are as follows:
State Sulfur Dioxide Emission Maximum Amount Contract Approximate Limit Annual Covered by Expiration Sulfur Pounds Per Plant Demand Contract Date Content(%)(2) MBTU* Input (Tons) (Tons)
Black Dog 1,200,000 1,200,000 (1) 0.5 1.3(3) High Bridge 800,000 800,000 (1) 0.5 3.0 Allen S. King 2,000,000 2,000,000 (1) 0.9 1.6 Riverside 1,300,000 1,300,000 (1) 0.7 2.5(4) Sherco 8,000,000 8,000,000 (1) 0.5 0.9(5) 13,300,000 13,300,000(6)
*MBTU = Million British Thermal Units
Notes:
(1) Contract expiration dates vary between 1996 and 2005 for western coal, which can provide up to 100 percent of the required fuel supply for the designated generating unit. Spot market purchases of other western coal, and other fuels will provide the remaining fuel requirements when such purchases would improve fuel economics. The Company is also burning petroleum coke as a source of fuel.
(2) This percentage represents the average blended sulfur content of the combination of fuels typically burned at each plant.
(3) The Black Dog Fluidized Bed (Unit 2) SO2 limit is 1.2 lb/MBTU.
(4) The SO2 limitation at Riverside Unit 8 is 2.5 lb/MBTU. The limitation for units 6 and 7 is currently 0.9 lb SO2/MBTU.
(5) The SO2 limitation at Units 1 and 2 is 70 percent removal of SO2 input and a maximum emission rate of 0.96 lb SO2/MBTU averaged over 90 days. The SO2 limitation at Unit 3 is 70 percent removal of SO2 input and a maximum emission rate of 0.60 lb SO2/MBTU averaged over 30 days. The use of lime and/or limestone in the plant's scrubbers may be necessary to achieve these limits.
(6) Annual requirements are expected to range from 11.0 to 13.3 million.
The Company's current fuel oil inventory is adequate to meet anticipated 1996 requirements. Additional oil may be provided through spot purchases from two local refineries and other domestic sources.
To operate the Company's nuclear generating plants, the Company secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication. The contract strategy involves a portfolio of spot, medium and long- term contracts for uranium, conversion and enrichment. Current contracts are flexible and cover between 70 percent and 100 percent of uranium, conversion and enrichment requirements through the year 1997. These contracts expire at varying times between 1997 and 2005. The overlapping nature of contract commitments will allow the Company to maintain 70 percent to 100 percent coverage beyond 1997, if appropriate. The Company expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants. Fuel fabrication is 100 percent committed through the year 2003. The Company expects the unit cost of fuel to produce electricity with these nuclear facilities will be lower than the comparable cost of fuel to produce electricity with any other currently available fuel sources for the sustained operation of a generation facility. The cost of nuclear fuel, including disposal, is recovered in the customer price of the electricity sold by the Company.
The Company's average electric fuel costs for the past three years are shown below:
Fuel Costs * Per Million Btu Year Ended December 31 1993 1994 1995
Coal** $ 1.12 $ 1.13 $1.11 Nuclear*** .41 .47 .48 Composite All Fuels .87 .89 .87
* Fuel adjustment clauses in its electric rate schedules or statutory provisions enable NSP to adjust for fuel cost changes. (See "Utility Regulation and Revenues - Fuel and Purchased Gas Adjustment Clauses" under Item 1.)
** Includes refuse-derived fuel and wood.
*** See Note 1 to the Financial Statements under Item 8 for an explanation of the Company's nuclear fuel amortization policies.
Nuclear Power Plants - Licensing, Operation and Waste Disposal
The Company operates two nuclear generating plants: the single unit, 539 Mw Monticello Nuclear Generating Plant and the Prairie Island Nuclear Generating Plant with two units totaling 1,025 Mw. The Monticello Plant received its 40-year operating license from the Nuclear Regulatory Commission (NRC) on Sept. 8, 1970, and commenced operation on June 30, 1971. Prairie Island Units 1 and 2 received their 40-year operating licenses on Aug. 9, 1973, and Oct. 29, 1974, respectively, and commenced operation on Dec. 16, 1973, and Dec. 21, 1974, respectively.
In its most recent ratings of Company nuclear facilities, the NRC rated the overall performance of both the Prairie Island and Monticello Plants as excellent. On a scale of 1 to 3 (1 being the highest), the plants both rate at 1.25, which is the average of ratings in the areas of plant operations, maintenance, engineering, and plant support. These ratings of the NRC's Systematic Assessment of Licensee Performance (SALP) place the plants in the top quarter of the 18 plants located in the Midwest.
The Prairie Island and Monticello nuclear plants currently hold the Institute of Nuclear Power Operations' (INPO) top rating for plant operations and training. The Company is one of only three utilities in the nation to achieve INPO's top rating simultaneously at all of its nuclear plants.
The Company previously operated the Pathfinder Plant near Sioux Falls, SD as a nuclear plant from 1964 until 1967, after which it was converted to an oil and gas-fired peaking plant. The nuclear portions were placed in a safe storage condition in 1971, and the Company began decommissioning in 1990. Most of the plant's nuclear material, which was contained in the reactor building and fuel handling building, was removed during 1991. Decommissioning activities cost approximately $13 million and have been expensed. A few millicuries of residual contamination 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 waste includes used nuclear fuel. Low-level radioactive wastes are produced from other activities at a nuclear plant. They consist principally of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in the plant.
A 1980 federal law places responsibility on each state for disposal of its low-level radioactive waste. The law encourages states to form regional agreements or compacts to dispose of regionally generated waste. Minnesota is a member of the Midwest Interstate Low-Level Radioactive Waste Compact Commission. Following the expulsion of Michigan from the Midwest Compact in 1991 for failing to make progress, Ohio was designated the host state. The Ohio legislature in 1995 passed amendments to the Midwest Compact agreement and established procedures for the siting of a compact facility. Other member states must pass the compact amendments. Wisconsin passed the amendments at the end of 1995. Minnesota will seek passage in the 1996 legislative session. Following acceptance of the compact amendments within each member state, Congress is expected to ratify the compact amendments by 1999. Ohio is progressing with development of the low-level radioactive waste disposal facility and expects to complete construction in 2005. The development costs will be paid by the generators of low- level radioactive waste within the compact. Currently, the Barnwell facility, located in South Carolina, has been given authorization by South Carolina to accept low-level radioactive waste and the Midwest Compact has authorized its generators to use the Barnwell facility from July 1, 1995, through June 30, 1996. The use of the Barnwell facility is expected to be reauthorized on an annual basis through 2005.
The federal government has the responsibility to dispose of or permanently store domestic used nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act of 1982 requires the Department of Energy (DOE) to implement a program for nuclear waste management including the siting, licensing, construction and operation of repositories for domestically produced used nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes. The Company has contracted with the DOE for the future disposal of used nuclear fuel. The DOE is currently charging a quarterly disposal fee based on nuclear electric generation sold. This fee ranges from approximately $10 million to $12 million per year, which NSP recovers from its customers in cost-of-energy rate adjustments. In 1985, NSP paid the DOE a one-time fee of $95 million for fuel used prior to April 7, 1983. None of the Company's used nuclear fuel has been accepted by the DOE for disposal due to the unavailability of a planned federal fuel storage facility. The Company, along with a group of other utilities, has commenced litigation against the DOE to ensure that the federal facility will be available as contracted. (See Item 3 - Legal Proceedings.) In addition, because of the DOE's inadequate progress to provide a permanent repository and its recent disavowal of its obligation, the Minnesota Department of Public Service is investigating whether continued payments to fund the DOE's permanent disposal is prudent use of ratepayer dollars. The outcome of this investigation is unknown at this time.
The DOE has stated in statute and by contract that a permanent storage or disposal facility would be ready to accept used nuclear fuel by 1998. However, indications from the DOE are that a permanent federal facility will not be ready to accept used nuclear fuel from utilities until approximately 2010. NSP, with regulatory and legislative approval, has been providing its own temporary on-site storage facilities at its Monticello and Prairie Island nuclear plants. In 1979, the Company began expanding the used nuclear fuel storage facilities at its Monticello Plant by replacement of the racks in the storage pool. Also, in 1987, the Company completed the shipment of 1,058 spent fuel assemblies from the Monticello Plant to a General Electric storage facility in Morris, Illinois. As a result, the Monticello plant does not expect to run out of storage capacity prior to the end of its current operating license in 2010. The on-site storage pool for used nuclear fuel at the Company's Prairie Island Nuclear Generating Plant (Prairie Island) was filled during refueling in June 1994, so adequate space for a subsequent refueling was no longer available. In anticipation of this, the Company, in 1989, proposed construction of a temporary on-site dry cask storage facility for used nuclear fuel at Prairie Island. The Minnesota Legislature (Legislature) considered the dry cask storage issue during its 1994 legislative session as required by a Minnesota Court of Appeals ruling in June 1993.
In May 1994, the Governor of the State of Minnesota (Governor) signed into law a bill passed by the Legislature. The law authorizes the Company to install 17 dry casks at Prairie Island, each capable of holding 40 spent fuel assemblies (approximately one-half year's used fuel) which should provide storage capacity to allow operation until at least 2003 and 2004 for units 1 and 2 respectively, if the Company satisfies certain requirements. The Company executed an agreement with the Governor concerning the renewable energy and alternative siting commitments contained in the new law. The law authorized immediately the installation of the first increment of five casks, three of which have been loaded on site as of Dec. 31, 1995. The second increment of four casks would be authorized in 1996 if the Minnesota Environmental Quality Board (MEQB) finds that by Dec. 31, 1996: (i) the Company has applied to the NRC for an alternative site license for an off-site temporary nuclear fuel storage facility in Goodhue County (but not on the Prairie Island Nuclear generating site), (ii) the Company has used good faith in locating and building the alternative site, and (iii) 100 Mw of wind generation is operational, under construction or under contract. The final increment of eight casks would be available unless prior to June 1, 1999, the Legislature specifically revokes the authorization for the final eight casks or if an alternative storage site is not operational or under construction, or the Company fails to meet certain renewable energy commitments, including the increased use of wind power and biomass generation facilities by Dec. 31, 1998.
The Company continues to make substantial progress toward fulfilling the commitments necessary to secure the use of casks six through nine. On Aug. 17, 1995, the MEQB accepted the Company's application for a site certificate outlining two alternative sites for the alternate spent nuclear fuel storage facility in Goodhue County. The MEQB has begun the 12 to 18 month public siting process to examine these sites and any others that may be proposed. The Company expects to file its application with the NRC by October 1996. In 1995, the Company took steps for its wind and biomass resource commitments as discussed under the caption "Electric Utility Operations- Capability and Demand", herein. Other commitments resulting from the legislation include a low-income discount for electric customers, additional required conservation improvement expenditures and various study and reporting requirements to a legislative electric energy task force. In January 1995, the MPUC approved the Company's low-income discount programs in accordance with the statute. The Company has implemented programs to begin meeting the other legislative commitments. (See "Electric Utility Operations - Capability and Demand", herein and Notes 14 and 15 of Notes to Financial Statements under Item 8 for further discussion of this matter.)
To address the issue of continued temporary storage of used nuclear fuel until the DOE provides for permanent storage or disposal, the Company is leading a consortium working with the Mescalero Apache Tribe to establish a private facility for interim storage of used nuclear fuel on the Tribe's reservation in New Mexico. A core group of more than 20 United States nuclear utilities has agreed to support the construction and operation of the interim storage site. Work on the project is underway in several areas, including environmental assessment, facility design, and drafting of the detailed contracts that will govern the construction and operation of the site. An architect engineering firm and an environmental contractor have been retained to perform the environmental and licensing activities. The consortium is currently scheduled to submit a license application for the facility to the Nuclear Regulatory Commission (NRC) in December 1996. The spent fuel storage facility is expected to be operational and able to accept the first shipment of used nuclear fuel by mid-2002. However, due to pending regulatory and governmental approval uncertainty, it is possible that this interim storage may be delayed or not available at all.
In January 1995, the Company received a notice of violation from the United States Nuclear Regulatory Commission (NRC). The notice was regarding an inspection of the quality assurance programs for the spent nuclear fuel storage containers to be used at the Prairie Island Nuclear Generating Plant. On Feb. 1, 1995, the NRC supplemented the notice, stating, "...the staff has no reason to conclude that the casks could not perform their intended safety functions adequately." On March 21, 1995, the NRC reviewed NSP's responses and concluded that the Company's corrective actions associated with the violation were acceptable, and that no further actions with respect to the violations identified in the January 1995 Inspection Report are required prior to cask use.
On Dec. 28, 1995, the Company received another notice of violation from the NRC. This notice was regarding an improperly positioned valve at the Monticello Nuclear Generating Plant which violated NRC requirements. The valve had been mispositioned since returning to power from the last refueling outage on Oct. 23, 1994. This violation was categorized as a Severity Level III problem. A base civil penalty in the amount of $50,000 is considered for a Severity Level III problem. However, due to Monticello's good past performance and the initiation of immediate corrective actions upon determination of the mispositioned valve, the NRC decided to waive the civil penalty. The Company is continuing follow-up with the NRC to implement any further corrective actions necessary.
A revision to NSP's 1993 nuclear decommissioning study and nuclear plant depreciation capital recovery request was filed with the MPUC and approved in 1994 for the Company's nuclear power plants. Although management expects to operate the Prairie Island plant units through the end of their useful lives, the approved capital recovery would allow for the plant to be fully depreciated, including the accrual and recovery of decommissioning costs by 2008, about six years earlier than the end of its licensed life. The approved cost recovery period has been reduced because of the uncertainty regarding used fuel storage.
During the past several years, the NRC has issued a number of regulations, bulletins and orders that require analyses, modification and additional equipment at commercial nuclear power plants. The Company has spent approximately $530 million since 1971, and approximately $1 million, $6 million and $11 million for 1995, 1994 and 1993, respectively, under such requirements. The Company expects to expend a minimal amount 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 14 to the Financial Statements under Item 8 for further discussion of nuclear fuel disposal issues and information on decommissioning of the Company's nuclear facilities. Also, see Note 15 to the Financial Statements under Item 8 for a discussion of the Company's nuclear insurance and potential liabilities under the Price-Anderson liability provisions of the Atomic Energy Act of 1954.
Electric Operating Statistics
The following table summarizes the revenues, sales and customers from NSP's electric transmission and distribution business:
GAS UTILITY OPERATIONS
Competition
NSP provides retail gas service in portions of eastern North Dakota and northwestern Minnesota, the eastern portions of the Twin Cities metro area, and other regional centers in Minnesota (Mankato, St. Cloud and Winona) and Wisconsin (Eau Claire, La Crosse and Ashland). NSP is directly connected to four interstate natural gas pipelines serving these regions: Northern Natural Gas Company (Northern), Viking, Williston Basin Interstate Pipeline Company (Williston) and Great Lakes Transmission Limited Partnership (Great Lakes). Approximately 90 percent of NSP's retail gas customers are served from the Northern pipeline system.
During 1992 and 1993, the FERC issued a series of orders (together called Order 636) that addressed interstate natural gas pipeline restructuring. This restructuring required all interstate pipelines, including those serving NSP, to "unbundle" each of the services they provide: sales, transportation, storage and ancillary services. To comply with Order 636, NSP executed new pipeline transportation service and gas supply agreements effective Nov. 1, 1993, as discussed below. While these new agreements create a new form of contractual obligation, NSP believes the new agreements provide flexibility to respond to future changes in the retail natural gas market. NSP expects its financial risk under the new transportation agreements to be no greater than the risk faced under the previous long-term full requirements gas supply contracts with interstate pipelines.
The implementation of Order 636 applies additional competitive pressure on all local distribution companies (LDCs) including NSP, to keep gas supply and transmission prices for their large customers competitive because of the alternatives now available to these customers. Like gas LDCs, these customers now have expanded ability to buy gas directly from suppliers and arrange pipeline and LDC transportation service. NSP has provided unbundled transportation service since 1987. Transportation service does not currently have an adverse effect on earnings because NSP's sales and transportation rates have been designed to make NSP economically indifferent to sales or transportation of gas. However, some transportation customers may have greater opportunities or incentives to physically bypass the LDC distribution system. NSP has arranged its gas supply and transportation portfolio in anticipation that it may be required to terminate its retail merchant sales function. Overall, NSP believes Order 636 has enhanced its ability to remain competitive and allowed it to increase certain of its margins by providing an increased selection of services to its customers.
Order 636 allows interstate pipelines to negotiate with customers to recover up to 100 percent of prudently incurred "transition costs" (i.e., stranded 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 gathering or storage facilities).
NSP's primary gas supplier, Northern, is in the process of determining the final amount of transition costs to be passed on to customers as a result of Order 636 restructuring. Northern's restructuring settlement provided for the assignment of a significant portion of Northern's gas supply and upstream contract obligations. This solution was beneficial because Northern's customers contracted directly for obligations, rather than paying to buy out of those obligations and then contracting with the same gas suppliers and pipelines to replace the merchant function. The total transition costs recoverable for the remaining unassigned agreements is limited to $78 million. In addition, Northern may seek transition cost recovery for certain other costs, subject to prudency review. Northern's total Order 636 transition costs, to be passed on to all of its customers, are estimated to be approximately $100 million. Northern will recover the prudent transition costs by amortizing the amount over a period of several years, and including the amortized costs as a component of its transportation charges. NSP estimates that it will be responsible for less than $11 million of Northern's transition costs, spread over a period of approximately five years, which began Nov. 1, 1993. To date, NSP's regulatory commissions have approved recovery of restructuring charges in retail gas rates. NSP has no significant Order 636 transition cost responsibilities to its other pipeline suppliers.
The gas services available to NSP's customers were enhanced beginning in 1993 through the acquisitions of Viking in June 1993 and the assets of a gas marketing business by a new NSP subsidiary, Cenergy, Inc., in October 1993. See the Non- Regulated Subsidiaries section herein for further discussion of Cenergy. See further discussion of Viking below.
NSP's gas utility took advantage of opportunities to expand into new service territory during 1995. NSP extended service to approximately 1,600 customers in 8 new communities. In addition to exploring new growth opportunities, NSP is also focusing on conversion of potential customers who are located near NSP's gas mains but are not hooked up to receive the service. NSP estimates there are approximately 28,000 potential customers that fall into this category.
The most recent large gas expansion project occurred in Crow Wing and Cass counties in north central Minnesota. Outside the St Paul-Minneapolis area, these counties are experiencing the fastest growth of all counties in Minnesota. The project included laying approximately 550 miles of pipeline in 11 of the cities in the Brainerd Lakes area. The project's net capitalized investment cost was approximately $23 million. Construction began in 1994. The MPUC approved a "new town" rate surcharge for customers in this area to support NSP's capital investment in the project. The surcharge will be in effect for up to 15 years.
The Company's gas operation has organized a non- utility service offering individuals service contracts on a variety of home appliances. Working in partnership with local independent service contractors, NSP Advantage Service offers 24 hour appliance repair service. Depending on the level of service contracted, Advantage Service customers have coverage to help avoid the expense and inconvenience of unexpected appliance repairs. This service is being offered to individuals within NSP's service territory.
Capability and Demand
NSP categorizes its gas supply requirements as firm (primarily for space heating customers) or interruptible (commercial/industrial customers with an alternate energy supply). NSP's maximum daily sendout (firm and interruptible) of 659,800 MMBtu for 1995 occurred on Jan. 3, 1995.
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 557,810 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 pipeline capacity. These storage agreements provide NSP storage for approximately 19 percent of annual and 31 percent of peak daily firm requirements. NSP also owns and operates two liquified natural gas (LNG) plants with a storage capacity of 2.53 Bcf equivalent and four propane-air plants with a storage capacity of 1.42 Bcf equivalent to help meet the peak requirements of its firm residential, commercial and industrial customers. These peak shaving facilities have production capacity equivalent to 242,300 Mcf of natural gas per day, or approximately 34 percent of peak day firm requirements. NSP's LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the "needle peaks" caused by firm space heating demand on extremely cold winter days and can be used to minimize daily imbalance fees on interstate pipelines.
The cost of gas supply, transportation service and storage service is recovered through the PGA rate adjustment mechanism. 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.
Gas Supply and Costs
As a result of Order 636 restructuring, NSP's natural gas supply commitments have been unbundled from its gas transportation and storage commitments. NSP's gas utility actively seeks gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk, and economical rates. This diversification involves numerous domestic and Canadian supply sources, varied contract lengths, and transportation contracts with seven natural gas pipelines.
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 1996 through 2013.
Northern Natural Gas Company Great Lakes Transmission Limited Partnership Williston Basin Interstate Pipeline Co. Northern Border Pipeline Company Viking Gas Transmission Company ANR Pipeline Company TransCanada Gas Pipeline Ltd.
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 $34.4 million. These agreements are beneficial because they allow NSP to purchase the gas commodity at a high load factor at rates below the prevailing market price reducing the total cost per Mcf.
NSP has certain gas supply and transportation agreements, which include obligations for the purchase and/or delivery of specified volumes of gas, or to make payments in lieu thereof. At Dec. 31, 1995, NSP was committed to approximately $511.8 million in such obligations under these contracts, over the remaining contract terms, which range from the years 1996-2013. These obligations include some of the effects of contract revisions made to comply with Order 636. NSP has negotiated "market out" clauses in its new supply agreements, which reduce NSP's purchase obligations if NSP no longer provides merchant gas service.
NSP purchases firm gas supply from a total of approximately 20 domestic and Canadian suppliers under contracts with durations of one year to 10 years. NSP purchases no more than 20 percent of its total daily supply from any single supplier. This diversity of suppliers and contract lengths allows NSP to maintain competition from suppliers and minimize supply costs. NSP's objective is to be able to terminate its retail merchant sales function, if either demanded by the marketplace or mandated by regulatory agencies, with no financial cost to NSP.
The 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.
In July 1995, the FERC issued an order on remand in the 1991 and 1992 general rate cases filed by Great Lakes Gas Transmission Limited Partnership, one of NSP's transportation suppliers. The primary issue in the cases involved whether Great Lakes must use "incremental" or "rolled in" pricing for approximately $900 million of pipeline capacity expansion costs. The FERC had initially ruled that Great Lakes' rates should be designed to collect the incremental cost of the new facilities only from the new customers of the expansion project. On remand from the United States Circuit Court of Appeals, FERC reversed its previous order and ruled Great Lakes could include the expansion costs in rates for all transportation customers. The reversal increases NSP's costs for transportation service by approximately $1.1 million annually; the Company and the Wisconsin Company are recovering this increase through the PGA clause. However, the FERC also ruled Great Lakes could collect the higher rates from non-expansion customers retroactive to Nov. 1, 1991. This surcharge for NSP is expected to be approximately $2.8 million. NSP will seek PGA recovery of the surcharges if they are billed. In addition, NSP and numerous other parties have requested rehearing of the July 1995 remand order. A final FERC decision is pending.
On March 1, 1995, Northern Natural Gas filed for FERC approval to implement a general increase in its rates for transportation and other services. Northern implemented the increased rates on Jan. 1, 1996, subject to refund. The rate change is expected to increase the Company's costs by approximately $5.9 million annually. The Company and the Wisconsin Company are recovering this increase through the PGA clause. The FERC hearings are scheduled for August 1996.
Purchases of gas supply or services by the Company from the Wisconsin Company, its Viking pipeline affiliate and its Cenergy gas marketing affiliate are subject to approval by the MPUC. The MPUC has approved all the Company's transportation contracts with Viking and a spot gas purchase agreement with Cenergy. In September 1995, the MPUC approved a settlement authorizing a gas supply management agreement between the Company's gas utility and generating business units. In January 1996, the MPUC approved a three-month capacity release agreement between the Company and the Wisconsin Company, which allowed gas and pipeline capacity sales between the two companies in 1996.
The following table summarizes the average cost per MMBtu of gas purchased for resale by NSP's regulated retail gas distribution business, which excludes Viking and Cenergy:
The Company Wisconsin Company
1992 $2.71 $2.80 1993 $3.11 $3.02 1994 $2.59 $3.13 1995 $2.29 $2.78
Viking Gas Transmission Company
In June 1993, the Company acquired 100 percent of the stock of Viking Gas Transmission Company (Viking) from Tenneco Gas, a unit of Tenneco Inc., in Houston, Texas. Viking, which is now a wholly owned subsidiary of the Company, owns and operates a 500-mile interstate natural gas pipeline serving portions of Minnesota, Wisconsin and North Dakota with a capacity of approximately 400 million cubic feet per day. The Viking pipeline currently serves 10 percent of NSP's gas distribution system needs. Viking currently operates exclusively as a transporter of natural gas for third-party shippers under authority granted by the FERC. Rates for Viking's transportation services are regulated by FERC. In addition to revenue derived from FERC-approved rates, which are reported in Operating Revenues, Viking is receiving intercompany revenues from the Company and the Wisconsin Company for jurisdictional allocations of the acquisition adjustment paid by NSP (in excess of Tenneco's pipeline carrying value) to acquire Viking. The Company is not recovering this cost in retail gas rates in Minnesota, but is recovering this cost in North Dakota. The Wisconsin Company is recovering this cost in its retail gas rates.
In October 1995, Viking filed an application with the FERC for authorization to install 13.5 miles of pipeline looping in northwestern Minnesota to increase Viking's capacity by approximately 19,400 million cubic feet per day. The total expected cost is approximately $8.4 million, with a proposed in- service date of November 1996. This would be Viking's first mainline capacity expansion since the 1960s. This capacity is for four expansion customers: two municipal gas utilities already served by Viking, Perham and Randall, Minn.; and two large industrial customers, American Crystal Sugar and ProGold, LLC. Viking may have further expansion opportunities in 1997. The FERC authorization of the application is pending. A decision is expected in April 1996.
In 1995, the Viking pipeline experienced a leak which may be attributable to stress corrosion cracking (SCC). Permanent repairs were made to correct the problem without impacting service to customers. Viking is reviewing current industry practices and is developing plans to minimize the possibility of future SCC problems. This was the first occurrence since the line went in service in the early 1960s.
Gas Operating Statistics
The following table summarizes the revenue, sales and customers from NSP's regulated gas businesses:
NON-REGULATED SUBSIDIARIES NRG Energy, Inc.
NRG Energy, Inc. (NRG) is the Company's subsidiary that develops, builds, acquires, owns and operates several non- regulated energy-related businesses. It was incorporated in Delaware on May 29, 1992, and assumed ownership of the assets of NRG Group, Inc., including its subsidiary companies. NRG businesses generated 1995 operating revenues of $64 million and had assets of $452 million at Dec. 31, 1995.
NRG conducts business through various subsidiaries, including: NRG International, Inc.; Graystone Corporation; Scoria Incorporated; San Joaquin Valley Energy I, Inc.; San Joaquin Valley Energy IV, Inc.; NRG Energy Jackson Valley I, Inc.; NRG Energy Jackson Valley II, Inc.; NEO Corporation; NRG Energy Center, Inc; NRG Sunnyside Inc. and NRG Operating Services, Inc.
Operating Businesses
In December 1993, NRG, through a wholly owned foreign subsidiary, agreed to acquire a 33 percent interest in the coal mining, power generation and associated operations of Mitteldeutsche Braunkohlengesellschaft mbh (MIBRAG), located south of Leipzig, Germany. MIBRAG is a German corporation formed by the German government to hold two open-cast brown coal (lignite) mining operations, a lease on an additional mine, the associated mining rights and rights to future mining reserves, two small industrial power plants and a circulating fluidized bed power plant, a district heating system and coal briquetting and dust production facilities. Under the acquisition agreement, Morrison Knudsen Corporation and PowerGen plc also each acquired a 33 percent interest in MIBRAG, while the German government retained a one-percent interest in MIBRAG. The investor partners began operating MIBRAG effective Jan. 1, 1994, and the legal closing occurred Aug. 11, 1994.
In December 1993, NRG, through a wholly owned foreign subsidiary, acquired a 50 percent interest in a German corporation, Saale Energie GmbH (Saale). Saale owns a 400 Mw share of a 960 Mw power plant currently under construction in Schkopau, Germany, which is near Leipzig. PowerGen plc of the United Kingdom acquired the remaining 50 percent interest in Saale. Saale was formed to acquire a 41.1 percent interest in the power plant. VEBA Kraftwerke Ruhr AG of Gelsenkirchen, Germany (VKR), is the builder of the Schkopau plant. VKR owns the remaining 58.9 percent interest in the power plant and will operate the plant. The plant will be fired by brown coal (lignite) mined by MIBRAG under a long-term contract. Saale has a long-term power sales agreement for its 400 Mw share of the Schkopau facility with VEAG of Berlin, Germany, the company that controls the high-voltage transmission of electricity in the former East Germany. The first 425 Mw unit of the plant began test operations in January 1996 and the second 425 Mw unit is expected to commence commercial operation in July 1996. The 110 Mw turbine began commercial operations in February 1996. Through Dec. 31, 1995, NRG had invested approximately $31 million to acquire its interest in Saale including capitalized development costs. NRG's future equity commitment to Saale through 1996 is expected to be no more than $25 million.
In March 1994, NRG, through wholly owned foreign subsidiaries, acquired a 37.5 percent interest in the Gladstone Power Station, a 1680 Mw coal-fired plant in Gladstone, Queensland, Australia from the Queensland Electricity Commission. Other members of the unincorporated joint venture, including Comalco Limited of Australia (Comalco), acquired the remaining interest. A large portion of the electricity generated by the station is sold to Comalco for use in its aluminum smelter, pursuant to long-term power purchase agreements. NRG, through an Australian subsidiary, operates the Gladstone plant.
In 1994, NRG signed a Joint Development Agreement with Advanced Combustion Technologies, Inc. (ACT) with respect to the acquisition, upgrading, expansion and development of Energy Center Kladno ("Kladno") in Kladno, Czech Republic. NRG and ACT jointly have acquired a 36.5 percent interest in Kladno, which owns and operates an existing coal-fired power and thermal energy generation facility that can supply 28 Mw of electrical energy to an industrial complex and to the local electric distribution company and 150 megawatts thermal-equivalent steam and heated water to a district heating system and thermal energy to an industrial complex. Kladno also owns certain ancillary utility assets. The acquisition of the existing facility is the first phase of a development project that would include upgrading the existing plant and would explore developing a new power generation facility with up to 240 Mw of coal-fired generation and up to 100 Mw of gas-fired generation depending on the ongoing analysis of the alternatives. The new facility would supply back-up steam to the district heating system and sell electricity to STE, the principal regional electric distribution company in Prague, via an existing 23 kilometer transmission line owned by Kladno.
NRG operates two refuse-derived fuel (RDF) processing plants and an ash disposal site in Minnesota. The ownership of one plant was transferred by the Company to NRG at the end of 1993. NRG manages the operation of the other RDF plant, of which the Company owns 85 percent, and of the ash disposal site. The Company and NRG are currently negotiating a new operation and maintenance agreement for approval by the MPUC. In 1995, workers at the RDF plants processed more than 750,000 tons of municipal solid waste into approximately 660,000 tons of RDF that was burned at two NSP power plants and at a power plant owned by United Power Association.
NRG also owns and operates three steam lines in Minnesota that provide steam from the Company's power plants to the Waldorf Corporation, the Andersen Corporation and the Minnesota Correctional Facility in Stillwater.
During 1993, the Company formed NEO Corporation (NEO), a wholly owned subsidiary, to develop small power generation facilities in the United States. During 1994, the ownership of NEO was transferred by the Company to NRG. NEO owns a 50 percent interest in Minnesota Methane LLC. Minnesota Methane LLC is developing small scale waste to energy facilities utilizing landfill gas. In December 1994, NEO acquired a 50 percent ownership in STS HydroPower Limited, an independent power producer with 21 Mw of hydroelectric facilities throughout the United States. STS HydroPower Limited currently is successfully operating 11 hydroelectric facilities across the United States and four generating plants that use renewable landfill gas as fuel. Minnesota Methane LLC is pursuing 10 additional landfill gas projects.
NRG, through wholly owned subsidiaries, owns 45 percent of the San Joaquin Valley Energy Partnerships (SJVEP), which own four power plants located near Fresno, California with a total capacity of 55 megawatts. Through February 1995, the plants operated under long-term Standard Offer 4 (SO4) power sales contracts with Pacific Gas and Electric (PG&E) which expire in 2017. On February 28, 1995, PG&E reached basic agreements with SJVEP to acquire the SO4 contracts. The negotiated agreements will result in cost savings for PG&E customers as well as economic benefits for SJVEP. Under the terms of the agreements, PG&E has been released from its contractual obligation to purchase power generated by SJVEP. Proceeds received from PG&E under the agreements were used to repay SJVEP debt obligations and recover investments in the facilities. SJVEP continues to own and maintain the facilities and to evaluate opportunities to market power without the prior costs incurred for plant depreciation and interest on debt. All regulatory approvals for the agreements were received in the second quarter of 1995. NRG's share of the pretax gain realized by SJVEP from this transaction, which was recorded in June 1995, was approximately $30 million (26 cents per share after tax). Approximately $12 million in settlement distributions were paid to NRG from SJVEP in 1995, and additional distributions are expected in 1996.
NRG, through wholly owned subsidiaries, owns 50 percent of the Jackson Valley Energy partnership, which owns and operates a 16 Mw cogeneration power plant near Sacramento, California. The plant had a long-term power sales agreement with Pacific Gas & Electric through 2014. On April 1, 1995, Jackson Valley Energy Partners reached an agreement with PG&E regarding the idling of the Jackson Valley plant near Sacramento. Under this agreement, which is similar to the SJVEP agreement, the plant will remain idle until May 1, 1997, and will then restart and sell power to PG&E under a new long term agreement. No gain or cash distribution has resulted or is expected from this transaction.
NRG, through a wholly owned subsidiary, purchased the assets of the Minneapolis Energy Center (MEC), a downtown Minneapolis district heating and cooling system in August 1993. The system utilizes steam and chilled water generating facilities to heat and cool buildings for 86 heating and 29 cooling customers. The primary assets include the main plant, with 800,000 lbs/hour of steam capacity and 22,000 tons/hour of chilled water capacity, two satellite plants, two standby plants, six miles of steam lines and two miles of chilled water distribution lines. Existing long-term contracts with MEC customers remained in effect under NRG's ownership. During 1995, MEC negotiated contracts with two new customers for 25,000 lbs/hour of steam and 2,400 tons/hour of chilled water.
On August 1, 1995, NRG closed on the acquisition of a 49 percent limited partnership interest in the partnerships holding the operating assets of the district and heating and cooling systems in Pittsburgh and San Francisco. The interest was acquired from Thermal Ventures, Inc., which will continue to operate these systems. Current annual revenue of the San Francisco thermal system is approximately $9 million, and the annual steam sales volumes are approximately 700 million pounds. The San Francisco thermal system provides service to more than 200 buildings. The Pittsburgh thermal system currently has $8 million of annual revenue and provides annual steam sales volumes of 300 million pounds, and chilled water sales volumes of 21 million ton-hours to 24 customers.
In December 1994, NRG, through a wholly owned subsidiary, purchased a 50 percent ownership interest in Sunnyside Cogeneration Associates (SCA), a Utah joint venture (partnership), which owns and operates a 58 Mw waste coal plant in Utah. The waste coal plant is currently being operated by a partnership that is 50 percent owned by an NRG affiliate.
Scoria Incorporated and Western SynCoal Co., a subsidiary of Montana Power Co., completed construction in January 1992 of a demonstration coal conversion plant designed to improve the heating value of coal by removing moisture, sulfur and ash. The plant, located in Montana, began commercial operation in August 1993. NRG's net capitalized investment in the Scoria coal project was written down by $3.5 million in 1994 and $5 million in 1995 to reflect reductions in the expected future operating cash flows from the project. NRG continues to evaluate the recoverability of its remaining investment of approximately $2.5 million in the Scoria project.
New Business Development
NRG is pursuing several energy-related investment opportunities, including those discussed below, and continues to evaluate other opportunities as they arise. Potential capital requirements for these opportunities are discussed in the "Capital Spending and Financing" section.
On November 17, 1995, NRG through a wholly owned subsidiary, entered into an agreement with the Aetna Life Insurance Company to acquire a 50 percent interest in Capital District Energy Center Cogeneration Associates, a joint venture general partnership which owns and operates a 56 Mw, natural gas-fired, cogeneration facility located in Hartford, Connecticut. The closing of the transaction is conditioned upon receipt of third party consents.
Early in 1996, NRG was negotiating the purchase of a 42 percent interest in O'Brien Environmental Energy, Inc. (O'Brien) from bankruptcy. The remaining 58 percent interest will be held by shareholders of O'Brien and will be publicly traded. O'Brien has interests in eight domestic operating power generation facilities with aggregate capacity of approximately 230 megawatts, and in one 150-megawatt facility in the contract stage of development. O'Brien's principal operating projects have an aggregate capacity of 183 Mw and include: (a) the 52 Mw Newark Boxboard Project (which is owned 100 percent by a wholly owned subsidiary of O'Brien), a gas-fired cogeneration facility that sells electricity to Jersey Central Power and Light Company (JCP&L) and steam to Newark Boxboard Company; (b) the 122 Mw E.I. du Pont Parlin Project (which is owned 100 percent by a wholly owned subsidiary of O'Brien), a gas-fired cogeneration facility that sells electricity to JCP&L and steam to E.I. du Pont de Nemours and Company; and (c) four biogas projects in Pennsylvania and California with total power generation capacity of 9.2 Mw. In addition, at Dec. 31, 1995, O'Brien had a 50 percent interest in the 150 Mw Grays Ferry Project, a proposed cogeneration project that would, upon successful development, sell electricity to Philadelphia Electric Company and district heating steam to Trigen Philadelphia Energy Corporation (TPEC). As a result of the purchase of O'Brien, approximately $107 million would be made available to O'Brien creditors by NRG. See additional discussion of commitments for the O'Brien acquisition in Note 15 to Financial Statements under Item 8.
A joint venture between NRG and Transfield, an Australian infrastructure contractor, signed an 18-year power purchase agreement and an acquisition agreement with the Queensland Transmission and Supply Corporation for the acquisition and refurbishment of the 189 Mw Collinsville coal- fired power generation facility in Queensland, Australia. If successful in the acquisition of this project, NRG would own a 50 percent interest and operate the facility. Transfield would perform the facility refurbishment and environmental remediation under a fixed price turnkey contract and would perform facility maintenance under a subcontract with NRG.
In July 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 Corporation Andina de Fomento (CAF) formed the Scudder Latin American Trust for Independent Power (Scudder), an investment fund which is intended to invest in the development of new power plants and privatization of existing power plants in Latin America and the Caribbean. The fund has retained Scudder Stevens & Clark, Inc. as its investment manager. The fund commenced its investment development efforts in September 1993. Each of the four investors has committed $25 million which the fund is seeking to invest over the five year period 1994 - 1998. The fund has commenced private placement activities to obtain additional investors in the fund, particularly other utility affiliates and institutional investors. Scudder holds investments in two power generation facilities in Latin America and one in the Caribbean. As of Dec. 31, 1995, NRG has invested $9 million in Scudder for equity interests ranging from 7.7 percent to 10.3 percent.
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 the next few years. Because of the uncertainty surrounding the ultimate successful operation of this plant, NRG wrote off its $1.5 million investment in Graystone during 1994.
Cenergy, Inc.
NSP's non-regulated wholly owned subsidiary, Cenergy, Inc. (which changed its name to Cenerprise, Inc. effective Jan. 1, 1996) commenced operations in October 1993 through the acquisition from bankruptcy of selected assets of Centran Corporation, a natural gas marketing company. Cenergy, in addition to marketing natural gas, provides customized value- added energy services to customers, both inside NSP service territory and on a national basis. Cenergy offers customers many energy products and services including: utility billing analysis, end-use gas marketing, risk management, construction, energy services consulting and administrative services. The MPUC has approved an affiliate transaction contract, whereby Cenergy may make natural gas sales at market based rates (determined by competitive bids) to NSP for resale to retail gas customers.
In December 1994, the FERC approved Cenergy's application to sell electric power (except electricity generated by NSP) in the United States, giving NSP an opportunity to enter the increasingly deregulated and competitive electric market. Cenergy was one of the first utility affiliates to obtain this approval from the FERC. NSP is allowing open access to its electric transmission lines by other electric power providers throughout North America. Cenergy's initiative to buy and sell deregulated electricity is consistent with NSP's objective to embrace competition, which will benefit NSP customers and shareholders.
In 1995, Cenergy and Atlantic Energy Enterprises (AEE) established Atlantic CNRG Services LLC (Atlantic CNRG). Cenergy and AEE each own 50 percent of the new venture that will develop new and expanded natural gas and electric energy products and services, primarily in the northeast United States. On Feb. 1, 1996, Atlantic CNRG acquired the natural gas marketing assets of Interstate Gas Marketing (IGM). IGM, which has offices in Scranton and Pittsburgh, Pennsylvania, markets natural gas to customers in the northeastern United States.
On Sept. 1, 1995, a non-regulated subsidiary of NSP was merged with Kansas City-based Energy Masters Corporation (EMC) resulting in the Company's acquisition of an 80 percent ownership interest in EMC. The Company subsequently assigned its interest in EMC to Cenergy. Cenergy has the option to acquire the remaining 20 percent of EMC in three years. EMC has offices in seven states nationwide and specializes in energy efficiency improvement services for commercial, industrial and institutional customers. For its fiscal year ended Oct. 31, 1994 (the latest EMC fiscal year prior to acquisition), EMC, with more than 60 employees, had operating revenues of $5.9 million. EMC will continue to operate as a separate legal entity, as a subsidiary of Cenergy.
On Nov. 15, 1995, Cenergy and its partners sold their oil and gas leasehold interest in approximately 1,000 acres to TransTexas Gas Co. for $5 million. Cenergy purchased the property, located in Zapata County, Texas, in July 1994. Earlier in 1995 Cenergy redirected its oil and natural gas unit to focus on financing flowing production rather than engaging in exploratory and development drilling ventures. The sale of the Zapata County leases is the first step in shifting production area business to more closely follow its corporate energy service focus. The pretax gain recognized in 1995 from the sale of these leases, net of valuation adjustments for investments in remaining oil and gas properties held by Cenergy was approximately $1.1 million.
Eloigne Company
In 1993, the Company established Eloigne Company (Eloigne), to identify and develop affordable housing investment opportunities. Eloigne's principal business is the acquisition of a broadly diversified portfolio of rental housing projects which qualify for low income housing tax credits under current federal tax law. As of Dec. 31, 1995, approximately $38.5 million had been invested in Eloigne projects, including $13.3 million in wholly owned properties (at net book value) and $25.2 million in equity interests in jointly-owned projects. These investments and related working capital requirements have been financed with $25.3 million of equity capital (including undistributed earnings) and $20.7 million of long-term debt (including current maturities). Completed projects as of Dec. 31, 1995, are expected to generate tax credits of $45.6 million over the 10-year period 1996-2005. Tax credits recognized in 1995 as a result of these investments were approximately $3.0 million. A proposed "phase-out" of these tax credits is currently under consideration by the United States Congress. The proposal would sunset the low-income housing tax credit allocation after Dec. 31, 1997. Projects with credits allocated prior to that date would continue to generate tax credits over the remainder of the 10-year credit period allowed.
Non-Regulated Business Information
(Thousands of dollars, except per share data) 1995 1994 1993 Operating Results Operating Revenues $313 082 $241 827 $90 531 Operating Expenses (1) (327 894) (241 480) (81 480) Equity in earnings of unconsolidated affiliates: Earnings from operations (2) 28 055 31 595 2 695 Gains from contract terminations 29 850 9 685 Other income (deductions)---net 6 518 1 843 1 040 Interest expense (9 879) (7 975) (3 146) Income taxes (2) (6 119) (2 591) (3 548) Net income $ 33 613 $ 32 904 $ 6 092
Contribution of Non-regulated Businesses to NSP Earnings per Share NRG Energy, Inc. $0.46 $0.44 $0.04 Eloigne Company 0.02 0.02 0.00 Cenergy, Inc. (Cenerprise, Inc., effective Jan. 1, 1996) (0.02) 0.00 0.00 Other (3) 0.04 0.03 0.05 Total $0.50 $0.49 $0.09
(Thousands of dollars) 1995 1994
Equity Investment by Non-regulated Businesses in Unconsolidated Projects at Dec. 31 (Including undistributed earnings and capitalized development costs)
Australian projects $81 885 $75 108 German projects 87 699 55 337 Other international projects 14 920 4 013 Affordable housing projects (U.S.) 25 211 7 148 Other U.S. projects 54 276 36 152
Total Equity Investment in Unconsolidated Non-regulated Projects $263 991 $177 758
Additional Equity Invested in Consolidated Non-regulated Businesses 115 276 104 011
Total Net Assets of Non-regulated Businesses $379 267 $281 769
Significant Unconsolidated Non-Regulated Projects at Dec. 31, 1995
ENVIRONMENTAL MATTERS
NSP's policy is to proactively prevent adverse environmental impacts by regularly monitoring operations to ensure the environment is not adversely affected, and take timely corrective actions where past practices have had a negative impact on the environment. Significant resources are dedicated to environmental training, monitoring and compliance matters. NSP strives to maintain compliance with all applicable environmental laws.
In general, NSP has been experiencing a trend toward increasing environmental monitoring and compliance costs, which has caused and may continue to cause slightly higher operating expenses and capital expenditures. The Company has spent approximately $700 million on capitalized environmental improvements to new and existing facilities since 1968. NSP expects to incur approximately $20 million in capital expenditures and approximately $28 million in operating expenses for compliance with environmental regulations in 1996. The precise timing and amount of future environmental costs are currently unknown. (For further discussion of environmental costs, see "Environmental Matters" under Management's Discussion and Analysis of Financial Condition and Results of Operations under Item 7, and Note 15 to the Financial Statements under Item 8.)
Permits
NSP is required to seek renewals of environmental operating permits for its facilities at least every five years. NSP believes that it is in compliance, in all material respects, with environmental permitting requirements.
Waste Disposal
Used nuclear fuel storage and disposal issues are discussed in "Electric Utility Operations - Nuclear Power Plants - - Licensing, Operation and Waste Disposal and Capability and Demand," herein, in Management's Discussion and Analysis under Item 7 and in Notes 14 and 15 of Notes to Financial Statements under Item 8.
The Company and NRG have contractual commitments to convert municipal solid waste to boiler fuel and burn the fuel to generate electricity. NRG owns and/or operates two resource recovery plants that produce RDF from the waste. The RDF is burned at the Company's Red Wing and Wilmarth plants in the Company's service area, the French Island plant in the Wisconsin Company's service area, and the Elk River plant owned by United Power Association. Processing and burning RDF provides an additional economical source of electric capacity and energy, which is beneficial to NSP's electric customers. The Company's commitment to this program enables counties to meet state- mandated goals to reduce the amount of solid waste now going to landfills. In addition, the program provides for increased materials recovery and increased use of municipal solid waste as an energy source.
NSP has met or exceeded the removal and disposal requirements for polychlorinated biphenyl (PCB) equipment as required by state and federal regulations. NSP has removed nearly all known PCB capacitors from its distribution system. NSP also has removed nearly all known network PCB transformers and equipment in power plants containing PCBs. NSP continues to test and dispose of PCB-contaminated mineral oil and equipment in accordance with regulations. PCB-contaminated mineral oil is detoxified and reused or burned for energy recovery at permitted facilities. Any future cleanup or remediation costs associated with past PCB disposal practices is unknown at this time.
Air Emissions Control And Monitoring
In 1994, the U.S. Environmental Protection Agency (EPA) proposed new air emission guidelines for municipal waste combustors. These proposed guidelines were finalized in December 1995. The Minnesota Pollution Control Agency has indicated its plans to update Minnesota state waste combustor rules to meet or be more restrictive than the final federal guidelines. The June 1997 effective date for the state waste combustor rules is expected to be extended due to the issuance of the new federal combustor rules. To meet the new federal and state requirement, the Company must install additional pollution control and monitoring equipment at the Red Wing plant and additional monitoring equipment at the Wilmarth plant. The Company is evaluating equipment to meet the requirements. The required equipment may cost between $6 million and $10 million.
The Clean Air Act, including the Amendments of 1990, (the "Clean Air Act") calls for reductions in emissions of sulfur dioxide and nitrogen oxides from electric generating plants. These reductions, which will be phased in, began in 1995. The majority of the rules implementing this complex legislation are finalized. No additional capital expenditures are anticipated to comply with the sulfur dioxide emission limits of the Clean Air Act. NSP has expended significant amounts over the years to reduce sulfur dioxide emissions at its plants. Based on revisions to the sulfur dioxide portion of the program, NSP's emission allowance allocations for the years 1995-1999 were dramatically reduced from prior rulemaking. The Company's Sherburne County Generating Plant (Sherco) unit 2 Low Nox Burner Technology was upgraded in 1994 to further reduce its emissions of nitrogen oxides. It is expected that approximately $7 million will be spent on a similar upgrade at Sherco unit 1 in 1998. Other expenditures may be necessary upon the EPA's finalization of remaining rules. Capital expenditures will be required for opacity compliance in 1996-2000 at certain facilities as discussed below.
As a part of its Clean Air Act compliance effort, the Company is testing a type of air quality control device called a wet electrostatic precipitator at the Sherco generating plant. The equipment was installed in 1995 inside one of the existing scrubber modules. Testing, anticipated to be completed in 1996, will determine the equipment's operational requirements and ability to reduce particulate emissions and opacity. The equipment is being examined as one option to lower opacity from Sherco units 1 and 2, as required by the EPA. Until testing is completed, it is unknown whether the equipment will result in full compliance with air quality standards, however, testing results to date have been favorable. Total costs for equipment to reduce particulate emissions and opacity range from $90 million for the equipment being tested to approximately $300 million for other technology options. As of Dec. 31, 1995, approximately $3 million of these costs had already been incurred and capitalized.
The Company has conducted testing for air toxics at its major facilities and shared these results with state and federal agencies. The Company also conducted research on ways to reduce mercury emissions. This information has also been shared with state and federal agencies. The Clean Air Act requires the EPA to look at issuing rules for air toxic emissions from electric utilities. A report is expected from the EPA to Congress in 1996. There is continued interest at the Minnesota Legislature to pass legislation restricting emissions of air toxics in the state. The Company cannot predict what impact these rules will have if passed.
On March 11, 1996, the Company received a Notice of Violation from the Wisconsin Department of Natural Resources (WDNR) stating that emissions from the Wisconsin Company's French Island facility had exceeded allowable levels for dioxin. The WDNR has requested a written response from the Wisconsin Company no later than April 15, 1996, setting forth the Wisconsin Company's plans for bringing the emissions levels back into compliance. The Wisconsin Company is currently investigating this matter to determine the cause of this unexpected event. At this time, the Wisconsin Company is unable to predict whether any fines will be imposed by the WDNR against the Company or what further corrective action may be required. The Wisconsin Company does not believe any fines, if levied, or corrective actions, if required, will have a material adverse effect on NSP's financial condition or results of operations.
Water Quality Monitoring
In compliance with federal and state laws and state regulatory permit requirements, and also in conformance with the Company's corporate environmental policy, the Company has installed environmental monitoring systems at all coal and RDF ash landfills and coal stockpiles to assess and monitor the impact of these facilities on the quality of ground and surface waters. Degradation of water quality in the state is prohibited by law and requires remedial action for restoration to an agreed upon acceptable clean-up level. The cost of overall water quality monitoring is not material in relation to NSP's operating results.
Site Remediation
Through the end of 1995, the Company had been designated by the EPA or state environmental agencies as a "potentially responsible party" (PRP) for 12 waste disposal sites to which the Company allegedly sent hazardous materials. Under applicable law, the Company, along with each PRP, could be held jointly and severally liable for the total site remediation costs. Those costs have been estimated between $123 and $126 million for all 12 PRP sites. In the event additional remediation is necessary or unexpected costs are incurred, the amount could be in excess of $126 million. The Company is not aware of the other parties inability to pay, nor does it know if responsibility for any of the sites is disputed by any party.
Settlement with the EPA, state environmental agencies and other PRPs has been reached for eight of these waste disposal sites for reimbursement of the past costs and expected future costs of remedial action. By reaching early settlement, the Company avoided litigation costs, increased costs of investigation and remediation and possible penalties that could have resulted and substantially increased the Company's allocation. For the four remaining sites, neither the amount of cleanup costs nor the final method of their allocation among all designated PRP's has been determined. However, the current estimate of the Company's share of future remediation costs for all four sites is approximately $1.0 million, which has been recorded as a liability at Dec. 31, 1995.
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.
Both the Company and the Wisconsin Company have received notices for requests for information concerning groundwater contamination at a landfill site in Wisconsin. While neither the Company nor the Wisconsin Company have been named PRP's, both companies voluntarily joined a group of other parties to address the contamination at this site. This site is included in the description of the 12 Company sites described above. In addition, the administrator of a group of PRP's has notified the Wisconsin Company that it might be responsible for cleanup of a solid and hazardous waste landfill site. The Wisconsin Company contends that it did not dispose of hazardous wastes in the subject landfill during the time period in question. Because neither the amount of cleanup costs nor the final method of their allocation among all designated PRP's has been determined, it is not feasible to predict the outcome of the matter at this time.
On March 2, 1995, the WDNR notified the Wisconsin Company that it is a PRP at a creosote/coal tar contamination site in Ashland, Wisconsin. At this time, the WDNR has determined that the Wisconsin Company is the only PRP at this site. The site has three distinct portions - the Wisconsin Company portion of the site, the Kreher Park portion of the site and the Chequamegon Bay (of Lake Superior) portion of the site. The Wisconsin Company portion of the site, formerly a coal gas plant site, is Wisconsin Company property. The Kreher Park portion of the site is adjacent to the Wisconsin Company site and is not owned by the Wisconsin Company. The Chequamegon Bay portion of the site is adjacent to the Kreher Park portion of the site and is not owned by the Wisconsin Company. The Wisconsin Company is discussing its potential involvement in the Kreher Park and Chequamegon Bay portions of the site with the WDNR and the City of Ashland.
On Feb. 19, 1996, the Wisconsin Company received a draft report from the WDNR's consultant of the results of a remediation action options feasibility study for the Kreher Park portion of the Ashland site. The draft report contains a number of remediation options which were scored by the consultant across a variety of parameters. Two options scored the most technologically and economically feasible and one of those is the lowest cost option for remediation at the Kreher Park portion of the site. The draft report estimates that this option, which would involve capping the property and some limited groundwater treatment, would cost approximately $6.0 million. Currently, the WDNR is conducting an investigation in Chequamegon Bay adjacent to Kreher Park to determine the extent of contamination in the bay. The WDNR has informed the Wisconsin Company that it will not choose or proceed with any remediation options on any portion of the Ashland site until the completion of the Chequamegon Bay investigation in the second half of 1996. Until more information is known concerning the extent of remediation required by the WDNR, the remediation method selected and the related costs, the various parties involved and the extent of the Wisconsin Company's responsibility, if any, for sharing the costs, the ultimate cost to the Wisconsin Company and the expected timing of any payments related to the Ashland site is not determinable. At Dec. 31, 1995, the Wisconsin Company had recorded an estimated liability of $900,000 for future remediation costs at this site and had incurred approximately $400,000 in actual expenditures.
The Company is continuing to investigate 15 properties either presently or previously owned by the Company which 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 Company has commenced remediation efforts at five of the 15 sites. One of the active sites has been completed, while the remaining four are in various stages of remediation. Monitoring continues at the completed site. In addition, the Company has been notified that two other sites will require remediation, and a study will be initiated in 1996 to determine the cost and method of clean up. Clean up is expected to begin in 1997. The total cost of remediation of these sites is expected to be approximately $13 million, including $6.7 million which has been paid to date. As for the eight inactive sites, no liability has been recorded for remediation or investigation because the present land use at each of these sites does not warrant a response action. Management believes costs incurred in connection with the sites that are not recovered from insurance carriers or other parties may be allowable costs for future ratemaking purposes. In 1994 the Company received MPUC approval of deferred accounting for certain investigation and remediation expenses associated with four active gas sites. The ultimate rate treatment of any costs deferred will be determined in the Company's future general gas rate cases. (See Note 15 of Notes to the Financial Statements under Item 8 for further discussion of this matter.)
NSP has not developed any specific site restoration and exit plans for its fossil fuel plants, hydroelectric plants or substation sites as it currently intends to operate at these sites indefinitely. NSP intends to treat any future costs incurred related to decommissioning and restoration of its non- nuclear power plants and substation sites, where operation may extend indefinitely, as a capitalized removal cost of retirement in utility plant. Depreciation expense levels currently recovered in rates include a provision for an estimate of removal costs (based on historical experience).
Contingencies
Electric and magnetic fields (sometimes referred to as EMF) surround electric wires and conductors of electricity such as electrical tools, household wiring, appliances, electric distribution lines, electric substations and high-voltage electric transmission lines. NSP owns and operates many of these types of facilities. Some studies have found statistical associations between surrogates of EMF and some forms of cancer. The nation's electric utilities, including NSP, have participated in the sponsorship of more than $50 million in research to determine the possible health effects of EMF. Through its participation with the Electric Power Research Institute and the EMF Research and Public Information Dissemination Program, sponsored by the National Institute of Environmental Health Sciences and the U.S. Department of Energy, NSP 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 and equity investments in non-regulated projects) totaled $401 million in 1995, compared to $409 million in 1994 and $362 million in 1993. These capital expenditures include gross additions to utility property of $386 million, $387 million and $357 million, (excluding Viking property acquired in 1993) for years ended 1995, 1994 and 1993, respectively. Internally generated funds could have provided approximately 85 percent of all capital expenditures for 1995, 69 percent for 1994 and 99 percent for 1993.
NSP's utility capital expenditures (including allowance for funds used during construction) are estimated to be $410 million for 1996 and $1.9 billion for the five years ended Dec. 31, 2000. Included in NSP's projected utility capital expenditures is $50 million in 1996 and $250 million during the five years ended Dec. 31, 2000, for nuclear fuel for NSP's three existing nuclear units. The remaining capital expenditures through 2000 are for many utility projects, none of which are extraordinarily large relative to the total capital expenditure program. Internally generated funds from utility operations are expected to equal approximately 90 percent of the 1996 utility capital expenditures and approximately 100 percent of the 1996-2000 utility capital expenditures. Internally generated funds from all operations are expected to equal approximately 75 percent and 90 percent respectively, of NSP's total capital requirements (including equity investments in non- regulated projects as discussed below) anticipated for 1996 and the five-year period 1996-2000. The foregoing estimates of utility capital expenditures and internally generated funds may be subject to substantial changes due to unforeseen factors, such as changed economic conditions, competitive conditions, resource planning, new government regulations, changed tax laws and rate regulation.
In addition to capital expenditures, NSP invested $54 million in 1995, $137 million in 1994 and $184 million in 1993 for interests in existing and additional non-regulated businesses and Viking. Investments in 1993 included business acquisitions of $159 million. (See "Gas Utility Operations - Viking Gas Transmission Company" and "Non-Regulated Subsidiaries" herein.) NSP and its subsidiaries continue to evaluate opportunities to enhance its competitive position and shareholder returns through strategic acquisitions of existing businesses. Long-term financing may be required for any such future acquisitions that NSP (including its subsidiaries) consummates.
Although they may vary depending on the success, timing, level of involvement in planned and future projects and other unforeseen factors, potential capital requirements for investments in existing and additional non-regulated projects are estimated to be $140 million in 1996 and $550 million for the five-year period 1996-2000. The majority of these non- regulated capital requirements relate to equity investments (excluding costs financed by project debt) in NRG's projects, as discussed previously and include commitments for certain NRG investments, as discussed in Note 15 of Notes to the Financial Statements under Item 8. The remainder consists mainly of affordable housing investments by Eloigne Company. Equity investments by NRG and Eloigne would be funded through their own internally generated funds, equity investments by NSP, or long- term debt issued by the subsidiary. Such equity investments by NSP are expected to be financed on a long-term basis through NSP's internally generated funds or through NSP's issuance of common stock.
EMPLOYEES AND EMPLOYEE BENEFITS
At year end 1995 the total number of full- and part-time employees of NSP was approximately 7,505. Of this number approximately 2,900 employees are represented by five local IBEW labor unions under a three year collective bargaining agreement expiring Dec. 31, 1996.
Recent changes to NSP's employee and retiree benefits, which support NSP's goal of providing market-based benefits, include:
Active nonbargaining medical premium increases: A cost sharing strategy for medical benefits for nonbargaining employees was implemented in 1994. The strategy consisted of adjusting the employee contribution portion of total medical costs to 10 percent in 1994 and 20 percent in 1995 and 1996.
Retiree medical premium increases: Retiree medical premiums were increased in 1994 for existing and future retirees. For existing qualifying retirees, pension benefits have been increased to offset some of the premium increase. For future retirees, a six-year cost-sharing strategy was implemented with retirees paying 15 percent of the total cost of health care in 1994, increasing gradually each year to a total of 40 percent in 1999.
401(k) changes: NSP currently offers eligible employees a 401(k) Retirement Savings Plan. In 1994, NSP began matching employees' pre-tax 401(k) contribution for a total of $2.6 million. NSP's matching contributions were $3.7 million in 1995, based on matching up to $700 per year for each nonbargaining employee and up to $500 per year for each bargaining employee. In 1996, NSP's annual match will increase to $900 for nonbargaining employees. Under the terms of the bargaining agreement implemented in 1994, NSP's annual match for bargaining employees will increase to $600 in 1996.
Wage increases: Under a market-based pay structure implemented for nonbargaining employees in 1994, NSP uses salary surveys that indicate how local and regional companies pay their employees for comparable positions. In January 1995, nonbargaining employees received an average wage scale increase of 3.5 percent, while bargaining employees received a 2 percent base wage increase and 1.5 percent lump sum payment. In January 1996, nonbargaining employees received an average wage scale increase of 4 percent, while bargaining employees received a 4 percent base wage increase.
EXECUTIVE OFFICERS *
Item 2
Item 2 - Properties
The Company's major electric generating facilities consist of the following:
NSP's electric generating facilities provided 79 percent of its Kwh requirements in 1995. The current generating facilities are expected to be adequate base load sources of electric energy until 2003-2006, as detailed in the Company's electric resource plan filed with the MPUC in 1995. All of NSP's major generating stations are located in Minnesota on land owned by the Company.
In late 1995, NSP converted three of its older, less efficient generating units from an intermediate load status to peaking plant operations. This change is expected to save approximately $3 million annually. The Company's 47 Mw Minnesota Valley generating plant in Granite Falls and the 65 Mw Black Dog Unit 1 in Burnsville will be dispatched as peaking units and fired on 100 percent natural gas. Black Dog Unit 2, with capacity of approximately 100 Mw, will also be dispatched as a peaking unit but will continue to be fired on coal.
At Dec. 31, 1995, NSP had transmission and distribution lines as follows:
Voltage Length (Pole Miles)
500Kv 265 345Kv 733 230Kv 283 161Kv 339 115Kv 1,650 Less than 115 Kv 31,509
NSP also has approximately 300 transmission and distribution substations with capacities greater than 10,000 kilovoltamperes (Kva) and approximately 270 with capacities less than 10,000 Kva.
Manitoba Hydro, Minnesota Power Company and the Company completed the construction of a 500-Kv transmission interconnection between Winnipeg, Manitoba, Canada, and the Minneapolis-St Paul, Minnesota, area in May 1980. NSP has a contract with Manitoba Hydro-Electric Board for 500 Mw of firm power utilizing this transmission line. In addition, the Company is interconnected with Manitoba Hydro through a 230 Kv transmission line completed in 1970. In May of 1995 a project was completed to increase the Manitoba-US transmission interconnection by a nominal 400 Mw, to 1900 Mw. This project was undertaken as part of a contract where NSP and Manitoba Hydro have established an additional 150 Mw of seasonal power exchange. (Also, see Note 15 of Notes to Financial Statements under Item 8.)
The electric delivery system utilization has increased during recent years due to better analytical methods and enhanced Energy Management System monitoring and control capability. This increased utilization has been achieved while continuing to operate within reliability parameters established by MAPP and North American Electric Reliability Council (NERC).
In April 1995, a plan was completed to determine electric delivery system upgrades required to accommodate load growth expected in the Minneapolis/St. Paul geographic area through 2010. The results indicated load growth at a rate of approximately 2 percent per year. To accommodate the load growth, portions of the 69 Kv transmission, especially located on the outskirts of the Twin Cities, will be reconductored and operated at 115 Kv; distribution development in these areas will largely be at 34.5 Kv. By reconductoring on existing right-of- ways and increasing distribution voltage, the requirements for new right-of-ways and substation sites are minimized as compared with other alternatives for serving the load growth.
The natural gas properties of NSP include about 8,060 miles of natural gas transmission and distribution mains. NSP natural gas mains include approximately 116 miles with a capacity in excess of 275 pounds per square inch (psi) and approximately 7,944 miles with a capacity of less than 275 psi. In addition, Viking owns a 500-mile interstate natural gas pipeline serving portions of Minnesota, Wisconsin and North Dakota.
Virtually all of the utility plant of the Company and the Wisconsin Company are subject to the lien of their first mortgage bond indentures pursuant to which they have issued first mortgage bonds.
Item 3
Item 3 - Legal Proceedings
In the normal course of business, various lawsuits and claims have arisen against NSP. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters.
On July 22, 1993, a natural gas explosion occurred on the Company's distribution system in St. Paul, MN. Seventeen lawsuits have been filed against the Company in regard to the explosion, including one suit with multiple plaintiffs. In April 1995, the National Transportation Safety Board concluded the City of St. Paul contractors were largely responsible for the natural gas explosion. The report found little, if any, fault with the actions taken by or conduct of the Company. A trial to decide civil liability and the parties responsible for the explosion has been scheduled for February 1997, with the damages portion of the trial scheduled for six months thereafter.
In February 1996, the Company and Westinghouse Electric Corp. (Westinghouse) reached a settlement in principle of a lawsuit which the Company had filed against Westinghouse related to steam generators installed at the Company's Prairie Island plant. The parties have agreed to keep the specific terms of the settlement confidential. The Company expects to share all of the benefits of the settlement with its customers.
On June 20, 1994, the Company and 13 other major utilities filed a lawsuit against the Department of Energy (DOE) in an attempt to clarify the DOE's obligation to accept spent nuclear fuel beginning in 1998. The suit was filed in the U.S. Court of Appeals, Washington, D.C. The primary purpose of the lawsuit is to insure that the Company and its customers receive timely storage of used nuclear fuel in accordance with the terms of the Company's contract with the DOE. The lawsuit was argued before the United States Circuit Court of Appeals for the District of Columbia on Jan. 17, 1996, and a decision is expected in three to six months from the time of argument.
The Federal Energy Regulatory Commission (FERC) made a favorable decision for the Company regarding its Sherco unit 3 transmission contracts with the Southern Minnesota Municipal Power Agency (SMMPA). A hearing judge had previously issued several rulings in favor of the Company, but had refused to find SMMPA obligated to pay for any transmission service since deliveries had commenced on November 1, 1987. FERC reversed and ordered SMMPA to pay for the 172 megawatts (MW) of transmission service in an amount determined by applying NSP's filed wheeling rate. It is anticipated that SMMPA will appeal. NSP will ask FERC to reconsider its decision as to the total transmission service SMMPA is responsible for because NSP believes SMMPA owes for 56 Mw more than FERC allowed. Until the appeal and reconsideration processes are complete, the ultimate impact of this decision on NSP's results of operation and financial condition are not determinable.
For a discussion of environmental proceedings, see "Environmental Matters" under Item 1, incorporated herein by reference. For a discussion of proceedings involving NSP's utility rates, see "Utility Regulation and Revenues" 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 1995 and 1994 and the dividends declared per share during those quarters:
The Company's Restated Articles of Incorporation and First Mortgage Bond Trust Indenture provide for certain restrictions on the payment of cash dividends on common stock. At Dec. 31, 1995, the payment of cash dividends on common stock was not restricted except as described in Note 5 to the Financial Statements under Item 8.
For a discussion of the anticipated dividend payment level of Primergy, see "Proposed Merger with Wisconsin Energy Corporation" under Item 1, incorporated herein by reference.
1995 1994 1993 1992 1991 Shareholders of record at year-end 83 902 85 263 86 404 72 525 72 704
Book value per share at year-end $29.74 $28.35 $27.32 $25.91 $25.21
Shareholders of record as of March 15, 1996 were 83,517.
Item 6
Item 6 - Selected Financial Data
Item 7
Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations
Northern States Power Company, a Minnesota corporation (the Company), has two significant subsidiaries, Northern States Power Company, a Wisconsin corporation (the Wisconsin Company), and NRG Energy, Inc., a Delaware corporation (NRG). The Company also has several other subsidiaries, including Viking Gas Transmission Company (Viking) and Cenergy, Inc., (Cenergy). The Company and its subsidiaries collectively are referred to herein as NSP.
FINANCIAL RESULTS AND OBJECTIVES
1994 Financial Results
NSP's 1995 earnings per share were $3.91, an increase of 45 cents, or 13.0 percent, over the $3.46 earned in 1994. The effects of sales growth in the core electric and gas utility businesses, favorable weather and reduced operating and maintenance costs more than offset higher costs for depreciation, tax and interest expenses. This provided a regulated utility earnings increase of 44 cents, or 14.8 percent, from 1994. In 1995, non-regulated businesses contributed earnings of 50 cents, up 1 cent, or 2.0 percent, from 1994 earnings. Investor returns also were enhanced in 1995 by an increase in the common dividend rate, as discussed below.
NSP remained financially strong in 1995, as evidenced by continued high operating cash flows and interest coverage. NSP maintained its first mortgage bond ratings with all rating agencies during 1995. NSP bonds are rated double A by all rating agencies except Moody's Investors Services (Moody's). Moody's downgraded NSP's first mortgage bond ratings in May 1994 to A1 based on its interpretation of provisions of a Minnesota law enacted in 1994 regarding the used fuel storage project for the Prairie Island nuclear generating plant. (See discussion of this legislation in Notes 14 and 15 to the Financial Statements.) In 1995, Moody's placed the Company's ratings on credit review for possible upgrade based on anticipated cost savings from the proposed merger with Wisconsin Energy Corporation, which is discussed later.
Total Return
Total return to investors is measured by dividends plus stock price appreciation. NSP's common dividend rate increased by more than 2 percent and its stock price increased by 11.6 percent in 1995. For the most recent 15-, 10- and five-year periods, the total return on NSP common stock averaged 18.1 percent, 12.7 percent and 13.8 percent per year, respectively. For the same periods, the total return for the Standard & Poor's (S&P) composite stock index for 500 industrial companies averaged 14.8 percent, 14.8 percent and 16.5 percent per year, respectively.
Financial Objectives
NSP's financial objectives are:
- To provide investor returns in the top one-fourth of the utility industry as measured by a three-year average return on equity. NSP's average return on common equity for the three years ending in 1995 was 12.5 percent. Based on a three-year average, this return was below the top one-fourth of the industry, which was approximately 13.0 percent, but above the median three-year industry average of approximately 11.6 percent.
- To increase dividends on a regular basis and maintain a long-term average payout ratio in the range of 65 to 75 percent. The objective payout ratio is based on long-term earnings expectations. In June 1995, NSP's annualized common dividend rate was increased by 6 cents per share, or 2.3 percent, from $2.64 to $2.70. The dividend payout ratio was 69 percent in 1995, within the objective range.
- To maintain continued financial strength with a double A bond rating. The Company's first mortgage bonds continued to be rated AA- by S&P, AA- by Duff & Phelps, Inc. and AA by Fitch Investors Service, Inc. Since May 1994, Moody's has rated NSP's first mortgage bonds A1 based on its interpretations of a Minnesota law enacted in 1994 regarding the used fuel storage project for the Prairie Island nuclear generating plant. First mortgage bonds issued by the Wisconsin Company carry comparable ratings. NSP's pretax interest coverage ratio, based on income without Allowance for Funds Used During Construction (AFC), was 3.8 in 1995. A capital structure consisting of 48.4 percent common equity at year-end 1995, including both regulated and non-regulated operations, contributes to NSP's financial flexibility and strength.
- To provide at least 20 percent of NSP earnings from NRG businesses by the year 2000. NRG expects to meet this goal through growing profitability of existing businesses and the addition of new businesses. Businesses owned or managed by NRG provided 12.4 percent of NSP's earnings in 1995 and 13.5 percent in 1994.
- To maintain long-term average annual earnings growth of 5 percent from ongoing operations, as described below. Excluding the non-recurring items discussed later under Factors Affecting Results of Operations, NSP achieved earnings per share growth of 7.0 percent in 1995 over 1994 and an average annual growth of 10.5 percent since 1993.
1995 1994 1993 Total earnings per share $3.91 $3.46 $3.02 Less earnings from non-recurring items 0.22 0.01 Earnings from ongoing operations $3.69 $3.45 $3.02
Total earnings per share increased 13.0 percent in 1995 over 1994.
Business Strategies
NSP's management is proactive in shaping the new business environment in which it will be operating. In April 1995, the Company and Wisconsin Energy Corporation (WEC) entered into a definitive agreement that provides for a strategic business combination in a "merger-of-equals" transaction to operate as Primergy Corporation (Primergy), as discussed further under Factors Affecting Results of Operations. Both companies' management teams view this transaction as creating a combined enterprise well-positioned for an increasingly competitive energy industry environment. The goal of the merger is to achieve continued competitive energy rates over the long term for the companies' respective customers and to enhance value for the shareholders of both companies. In addition to this merger strategy, management's business strategies include:
- Focusing on the core energy business. The electric utility industry is becoming more complex as customers, as well as utilities and federal and state regulators, promote competition. To remain successful in this more complex environment, NSP will maintain its focus on its core energy-related activities.
- Providing reliable, low-cost, environmentally responsible energy. Whether energy is produced or purchased through NSP's regulated utility or its non-regulated businesses, three general concepts provide a focus for its energy businesses: reliable energy, low-cost energy and environmentally responsible energy.
- Responding to customer needs. Customers will have an increasing number of options for meeting their energy needs, and there will be competition among energy companies for the privilege of serving those customers. NSP will work with its customers to develop innovative products and services that benefit both customers and NSP.
- Increasing non-regulated investments and earnings. Non- regulated businesses will be an important part of NSP's future. Deregulation in the utility industry is expected to provide new investment opportunities in non-regulated businesses. Participation in these opportunities is expected to improve NSP's total profitability.
RESULTS OF OPERATIONS AND LIQUIDITY AND CAPITAL RESOURCES
The following discussion and analysis by management focuses on those factors that had a material effect on NSP's financial condition and results of operations during 1995 and 1994. It should be read in conjunction with the accompanying Financial Statements and Notes thereto. Trends and contingencies of a material nature are discussed to the extent known and considered relevant. Material changes in balance sheet items are discussed below and in the accompanying Notes to Financial Statements. The discussion and analysis and the related financial statements do not reflect the impact of the Company's proposed merger with WEC except for pro forma information included in Note 18 to the Financial Statements.
RESULTS OF OPERATIONS
1995 Compared with 1994 and 1993
NSP's 1995 earnings per share were $3.91, up 45 cents from the $3.46 earned in 1994 and up 89 cents from the $3.02 earned in 1993. Regulated utility businesses generated earnings per share of $3.41 in 1995, $2.97 in 1994 and $2.93 in 1993. Non-regulated businesses generated earnings per share of 50 cents in 1995, 49 cents in 1994 and 9 cents in 1993. The results of the regulated utility businesses and the non-regulated businesses are discussed in more detail later. In addition to the revenue and expense changes, earnings per share have been affected by an increasing average number of common and equivalent shares outstanding. Common and equivalent shares increased in 1995 and 1994 due mainly to stock issuances for the Company's dividend reinvestment and stock ownership plans.
Utility Operating Results
Electric Revenues Sales to retail customers, which account for more than 90 percent of NSP's electric revenue, increased 4.2 percent in 1995 and 3.9 percent in 1994. Retail revenues were favorably affected by sales growth, weather and increased cost recovery for conservation expenditures. During 1995, NSP added 18,297 retail electric customers, a 1.3 percent increase. Total sales of electricity increased 2.9 percent in 1995 and decreased 0.2 percent in 1994. Warmer-than-normal summer weather in 1995 contributed to sales growth compared with 1994, which had a cooler-than-normal summer.
On a weather-adjusted basis, sales to retail customers increased an estimated 2.4 percent in 1995 and 3.4 percent in 1994. Retail sales growth for 1996 is estimated to be 0.8 percent over 1995, or 1.9 percent on a weather-adjusted basis.
Sales to other utilities increased 1.0 percent in 1995 after decreasing 21.6 percent in 1994. The 1994 decrease from 1993 largely was due to unusually high demand in 1993 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) 1995 vs. 1994 1994 vs. 1993 Retail sales growth (excluding weather impacts) $ 46 $ 56 Estimated impact of weather on retail sales volume 42 8 Sales to other utilities 1 (20) Wholesale sales (13) 7 Conservation cost recovery 19 2 Fuel adjustment clause recovery (7) 23 Other rate changes (2) 15 Energy management discounts and other (10) 1 Total revenue increase $ 76 $ 92
NSP's electric rates are adjusted for changes in fuel and purchased energy costs from amounts currently included in approved base rates through fuel adjustment clauses in all jurisdictions, except as noted below for Wisconsin. While the lag in implementing these billing adjustments is approximately 60 days, an estimate of the adjustments is recorded in unbilled revenue in the month in which costs are incurred. In Wisconsin, the biennial retail rate review process considers changes in electric fuel and purchased energy costs in lieu of a fuel adjustment clause.
In 1995, a new rate adjustment clause was approved. It accelerated recovery of deferred electric conservation and energy management program costs in the Company's Minnesota jurisdiction. This adjustment clause helps reduce the need for filing a general rate increase request for recovery of increases in conservation expenditures. The Company is required to request a new cost recovery level annually. In January 1996, a number of changes to the Company's regulatory deferral and amortization practices for Minnesota conservation program expenditures were approved. These changes allow the Company to expense rather than amortize new conservation expenditures beginning in 1996 and to increase its recovery of electric margins lost due to conservation activity. In addition, the Company received approval for 1996 and 1997 conservation expenditures at levels lower than 1995. On April 1, 1996, the Company expects to file for annual changes to the Minnesota conservation rate adjustment clause with an effective period of July 1, 1996, through June 30, 1997. Revenues in 1996 are expected to increase by an estimated $17 million, compared with 1995, due to the effects of the rate recovery changes for conservation programs in 1995 and 1996. These revenue increases will be largely offset by a corresponding increase in conservation expenses.
Electric Production Expenses Fuel expense for electric generation increased $4.5 million, or 1.4 percent, in 1995 compared with an increase of $5.6 million, or 1.8 percent, in 1994. The 1995 increase was primarily attributable to an increase in output from NSP's generating plants, resulting from increased sales and fewer scheduled plant maintenance outages. Although output from NSP's generating plants declined slightly in 1994 because of more scheduled fossil plant maintenance outages, fuel expenses were higher in 1994 because of the higher cost of nuclear fuel per megawatt-hour due to increased payments to the U.S. Department of Energy (DOE) for decommissioning and decontamination of the DOE's uranium enrichment facilities and nuclear fuel disposal costs. In addition, the costs of fossil fuel were higher in 1994 because of fewer coal purchases at the lowest contractual prices due to lower fossil plant output.
Purchased power costs decreased $5.2 million, or 2.1 percent, in 1995 after increasing $41.1 million, or 19.7 percent, in 1994. The decrease in 1995 was primarily due to lower average market prices and less energy purchased. The level of purchases declined due to fewer scheduled plant maintenance outages in 1995. The increase in 1994 primarily was due to additional demand expenses of $21 million for the full-year impact of capacity charges from the power purchase agreements with the Manitoba Hydro-Electric Board (MH), which went into effect in May 1993, as discussed in Note 15 to the Financial Statements. In addition to demand expenses, purchased power costs increased from 1993 due to higher average market prices and increased purchases because of more plant maintenance outages in 1994.
Gas Revenues The majority of NSP's retail gas sales are categorized as firm (primarily space heating customers) and interruptible (commercial/industrial customers with an alternate energy supply). Firm sales in 1995 increased 6.8 percent compared with 1994 sales, while firm sales in 1994 decreased 5.4 percent compared with 1993 sales. The 1995 increase primarily is due to increased sales of natural gas resulting from 16,680 additional new firm gas customers, a 4.1 percent increase, and slightly more favorable weather in 1995. The 1994 decrease was due largely to warm weather in the last quarter of 1994.
On a weather-adjusted basis, firm sales are estimated to have increased 4.6 percent in 1995 and decreased 0.7 percent in 1994. Firm gas sales in 1996 are estimated to increase by 2.6 percent relative to 1995, a 3.6 percent increase on a weather- adjusted basis.
Interruptible sales of gas increased 15.7 percent in 1995 and 4.4 percent in 1994. The 1995 increase is the result of favorable gas market prices that caused large interruptible customers with alternate fuel sources to use more natural gas. Other gas deliveries increased 46.1 percent primarily due to additional gas sales to off-system customers. Other gas deliveries increased 65.7 percent in 1994 due to gas sales to off-system customers. Viking wholesale transmission deliveries increased 1.1 percent in 1995. These wholesale deliveries increased 74.3 percent in 1994 due to a full year of Viking activity.
The table below summarizes the principal reasons for the gas revenue changes during the past two years.
(Millions of dollars) 1995 vs 1994 1994 vs 1993 Sales growth (excluding weather impacts) $26 $0 Estimated impact of weather on firm sales volume 7 (8) Sales to off-system customers 2 14 Purchased gas adjustment clause recovery (26) (24) Rate changes and other (3) 4 Viking Gas (acquired in June 1993) 5
Total revenue increase (decrease) $6 $(9)
NSP's retail gas rates are adjusted for changes in purchased gas costs from amounts currently included in approved base rates through purchased gas adjustment clauses in all jurisdictions. Effective November 1995, a new rate adjustment clause was approved that accelerated recovery of deferred gas conservation and energy management program costs in the Company's Minnesota jurisdiction, similar to the retail electric rate clause discussed previously. The Company estimates it will receive an additional $2.7 million in revenues from this new rate mechanism in 1996 compared with 1995. This increased recovery will result in a corresponding increase in conservation expenses.
Cost of Gas Purchased and Transported The cost of gas purchased and transported decreased $7.1 million, or 2.7 percent, in 1995 primarily due to a 12.6 percent decline in the per unit cost of purchased gas, partially offset by higher sendout volumes due to increased sales and off-system deliveries. The lower cost of purchased gas reflects continuing favorable market pricing, while the higher gas sendout reflects sales growth in 1995 and higher gas sales to off-system customers. The cost of gas associated with off-system sales was $14.3 million in 1995 and $12.7 million in 1994. The cost of gas purchased and transported decreased $18.6 million, or 6.6 percent, in 1994. The decrease reflects lower gas prices and cost recovery adjustments, partially offset by higher sendout volumes primarily for gas sales to off-system customers. The average cost per unit of NSP- owned gas sold in 1994 was 8.4 percent lower than it was in 1993, mainly due to lower market prices for gas.
Other Operation, Maintenance and Administrative and General These expenses, in total, decreased by $9.1 million, or 1.4 percent, in 1995 compared with an increase of $26.0 million, or 4.0 percent, in 1994. The 1995 decrease is largely due to fewer employees, fewer scheduled plant maintenance outages, lower property insurance premiums and a one-time charge in 1994 for postemployment benefits. Partially offsetting these decreases were higher employee benefit costs, and higher electric line maintenance costs, mostly for tree trimming and heat-related repairs. The 1994 increase resulted primarily from higher postretirement health care costs, including amounts deferred from 1993, and higher postemployment costs as discussed in Note 2 to the Financial Statements. (See Note 12 to the Financial Statements for a summary of administrative and general expenses.)
Conservation and Energy Management Expenses in 1995 were higher than in 1994 primarily due to higher amortization levels of deferred conservation program costs, consistent with cost recovery under new electric and gas rate adjustment clauses in the Company's Minnesota jurisdiction effective May 1, 1995, and Nov. 1, 1995, respectively. The deferred costs being amortized are higher due to increased customer participation in NSP's conservation and energy management programs.
Depreciation and Amortization The increases in 1995 and 1994 reflect higher levels of depreciable plant.
Property and General Taxes Property and general taxes increased in 1995 and 1994 primarily due to property additions and higher property tax rates.
Utility Income Taxes The variations in income taxes primarily are attributable to fluctuations in taxable income. (See Note 9 to the Financial Statements for a detailed reconciliation of the statutory tax rate to NSP's effective tax rate.)
Non-operating Items Related to Utility Businesses
Allowance for Funds Used During Construction (AFC) The differences in AFC for the reported periods are attributable to varying levels of construction work in progress and changing AFC rates associated with various levels of short-term borrowings to fund construction. In addition, returns allowed on deferred costs for conservation and energy management programs increased AFC-equity by $2.6 million and $2.0 million in 1995 and 1994, respectively, and increased AFC-debt by the amounts of $1.5 million and $0.9 million in 1995 and 1994, respectively.
Other Income (Expense) Note 12 to the Financial Statements lists the components of Other Income (Deductions)- Net reported on the Consolidated Statements of Income. Other than the operating revenues and expenses of non-regulated businesses, as discussed in the next section, non-operating income (net of expense items and associated income taxes) related to utility businesses increased $5.6 million in 1995 and decreased $2.4 million in 1994. The 1995 increase primarily is due to higher expense levels in 1994 for environmental and regulatory contingencies, and public and governmental affairs costs related to the Prairie Island fuel storage issue. These were partly offset by lower interest income associated with the Company's settlement of federal income tax disputes in 1995. The 1994 decrease primarily is due to higher expenses for environmental and regulatory contingencies, and higher public and governmental affairs expenses associated with the Prairie Island fuel storage issue, partially offset by interest income associated with the Company's settlement of federal income tax disputes.
Interest Charges (Before AFC) Interest costs recognized for NSP's utility businesses, including amounts capitalized to reflect the financing costs of construction activities, were $123.4 million in 1995, $107.1 million in 1994 and $110.4 million in 1993. The 1995 increase is largely due to long-term debt issues in 1995 and 1994 (net of retirements) and higher short-term interest rates, which affect commercial paper borrowings and variable rate long-term debt. The 1994 decrease reflects the impact of refinancing several higher-rate long-term debt issues in 1993 and 1994. These interest savings were partially offset by interest on higher short-term debt balances and Viking debt (issued late in 1993). The average short-term debt balance was $208.7 million in 1995, $204.5 million in 1994 and $77.0 million in 1993.
Preferred Dividends Dividends on the Company's preferred stock decreased in 1994 primarily due to redemption of the $7.84 Series Cumulative Preferred Stock in October 1993.
Non-regulated Business Results
NSP's non-regulated operations include many diversified businesses, such as independent power production, gas marketing, industrial heating and cooling, and energy-related refuse- derived fuel (RDF) production. NSP also has investments in affordable housing projects and several income-producing properties. The following discusses NSP's diversified business results in the aggregate.
Operating Revenues and Expenses The net results of non-regulated businesses that are consolidated are reported in Other Income (Deductions)-Net on the Consolidated Statements of Income. (Note 12 to the Financial Statements lists the individual components of this line item.) Non-regulated operating revenues increased $71.3 million, or 29 percent, in 1995, and $151.3 million, or 167 percent, in 1994. The 1995 increase was largely due to increased gas marketing sales by Cenergy. The 1994 increase was mainly due to the impact of Cenergy gas marketing and NRG industrial heating and cooling businesses acquired in 1993. Non- regulated operating expenses increased in 1995 primarily due to higher gas costs associated with Cenergy gas sales and higher project development expenses by NRG on pending projects. Non- regulated operating expenses increased in 1994 consistent with revenue increases resulting from 1993 acquisitions. In addition, such expenses increased in 1994 due to fewer project development costs being capitalized on pending projects in 1994 compared with 1993, and project write-downs. Non-regulated operating expenses include charges of $5.0 million in 1995 and $5.0 million in 1994 for previously capitalized development and investment costs to reflect a decrease in the expected future cash flows of certain energy projects.
Equity in Operating Earnings NSP has a less-than-majority equity interest in many non-regulated projects, as discussed in Note 3 to the Financial Statements. Consequently, a large portion of NSP's non-regulated earnings is reported as Equity in Earnings of Unconsolidated Affiliates on the Consolidated Statements of Income. The 1995 decrease in equity in project operating earnings is due to lower earnings from an NRG cogeneration project contract that was terminated in 1995 and other domestic projects, somewhat offset by higher earnings from NRG international energy projects (one of which did not provide earnings prior to the second quarter of 1994). The 1994 increase in equity in project operating earnings primarily is due to new international energy projects in which NRG entered during 1994 (as discussed in Note 3 to the Financial Statements), and more profitable operations of other energy projects in which NRG had been an investor for several years.
Equity in Gains From Contract Terminations In June 1995, after receiving final regulatory approvals, a power sales contract between a California energy project, in which NRG is a 45 percent investor, and an unaffiliated utility company was terminated. A pretax gain of approximately $30 million was recognized by NRG for its share of the termination settlement. In 1994, a Michigan cogeneration project, in which NRG was a 50 percent investor, received a payment from an unaffiliated utility company as compensation for the termination of an energy purchase agreement. A pretax gain of $9.7 million was recognized by NRG for its share of the contract termination settlement, net of project investment costs.
Other Income (Expense) Other than the operating revenues and expenses of non-regulated businesses, as discussed above, non- operating income (net of expense items) related to non-regulated businesses increased $4.7 million in 1995 and increased $0.8 million in 1994. The 1995 increase primarily is due to a gain on the sale of Cenergy oil and gas properties, higher income from cash investments, and an adjustment to the 1994 contract termination gain recorded by NRG.
Interest Expense Interest charges on the Consolidated Statements of Income include interest and amortization expenses related to non-regulated businesses. The expenses were $9.9 million in 1995, $8.0 million in 1994 and $3.1 million in 1993. The increase in 1995 mainly is due to the issuance of long-term debt on new affordable housing projects by Eloigne Company, a wholly owned subsidiary of the Company. The increase in 1994 relates primarily to non-utility long-term debt issued to finance the 1993 acquisitions of NRG's industrial heating and cooling business (Minneapolis Energy Center), a gas marketing business now operated by Cenergy, and 1994 investments in affordable housing projects by Eloigne Company. In addition, during 1994 and late 1993, United Power & Land and First Midwest Auto Park, wholly owned subsidiaries of the Company, issued long-term debt secured by non-regulated properties and lowered NSP's equity investment in these subsidiaries.
Income Taxes The Consolidated Statements of Income include income tax expense related to non-regulated businesses of $6.1 million in 1995, $2.6 million in 1994 and $3.5 million in 1993. The increase in 1995 mainly is due to a gain from an NRG energy contract termination, as discussed previously, somewhat offset by higher income tax credits from Eloigne Company's affordable housing projects. The decrease in 1994 mainly is due to higher income tax credits from affordable housing projects and energy tax credits related to an NRG project, somewhat offset by higher taxes due to higher operating earnings, as discussed above. The effective tax rate in 1995 and 1994 is substantially less than the U.S. federal tax rate mainly due to the tax treatment of income from unconsolidated international affiliates, and energy and affordable housing tax credits, as shown in Note 9 to the Financial Statements.
Factors Affecting Results of Operations
NSP's results of operations during 1995, 1994 and 1993 were primarily dependent upon the operations of the Company's and Wisconsin Company's utility businesses consisting of the generation, transmission, distribution and sale of electricity and the distribution, transportation and sale of natural gas. NSP's utility revenues depend on customer usage, which varies with weather conditions, general business conditions, the state of the economy and the cost of energy services. Various regulatory agencies approve the prices for electric and gas service within their respective jurisdictions. In addition, NSP's non-regulated businesses are contributing significantly to NSP's earnings. The historical and future trends of NSP's operating results have been and are expected to be affected by the following factors:
Proposed Merger On April 28, 1995, the Company and WEC entered into an Agreement and Plan of Merger that provides for a business combination of NSP and WEC in a "merger-of-equals" transaction. As a result of the mergers contemplated by the merger agreement, Primergy will become the holding company for the regulated operations of both the Company and the utility subsidiary of WEC. The business combination is intended to be tax-free for income tax purposes, and accounted for as a "pooling of interests." On Sept. 13, 1995, more than 95 percent of the respective shareholders of the Company and WEC voting approved the merger plan at their respective shareholder meetings. Under the proposed business combination, shareholders of the Company would receive 1.626 shares of Primergy common stock for each share of the Company's common stock owned at the time of the merger.
After the merger is completed, a transition to a new organization would begin. Anticipated cost savings of the new organization (compared with the continued independent operation of NSP and WEC) are estimated to be $2 billion over a 10-year period, net of transaction costs (about $30 million) and costs to achieve the merger savings (about $122 million). It is anticipated that the proposed merger will allow the companies to implement a modest reduction in electric retail rates and a four-year rate freeze for electric retail customers. In addition, the companies agreed to provide a four-year freeze in wholesale rates. After the merger, the regulated businesses of NSP and WEC would continue to operate as utility subsidiaries of Primergy, which would be registered under the Public Utility Holding Company Act of 1935 (PUHCA), as amended, and some of the Company's subsidiaries would be transferred to direct Primergy ownership. Except for certain gas distribution properties transferred to the Company, the Wisconsin Company will become part of the regulated business of WEC. Although NSP and WEC are working to avoid divestitures, the PUHCA may require the merged entity to divest certain of its gas utility and/or non-regulated operations. Also, regulatory authorities may require the restructuring of transmission system operations or administration. NSP currently cannot determine if such divestitures or restructuring would be required. In addition, Wisconsin state law limits the total assets of non-utility affiliates of Primergy. This could affect the growth of non- regulated operations.
The agreement to merge is subject to a number of conditions, including approval by applicable regulatory authorities. During 1995, NSP and WEC received a ruling from the Internal Revenue Service indicating that the proposed successive merger transactions would not prevent treatment of the business combination as a tax-free reorganization under applicable tax law if each transaction independently qualified. During 1995, NSP and WEC submitted filings to the Federal Energy Regulatory Commission (FERC), applicable state regulatory commissions and other governmental authorities seeking approval of the proposed merger to form Primergy. The FERC has put the merger application on an accelerated schedule, ordering the administrative law judge's initial decision by Aug. 30, 1996, and briefs on exception by Sept. 30, 1996, which makes possible a FERC ruling on the merger application by the end of 1996. Although the goal of NSP and WEC is to receive approvals from all regulatory authorities by the end of 1996, some regulatory authorities have not established a timetable for their decision. Therefore, the timing of the approvals necessary to complete the merger is not known at this time. The state filings included a request for deferred accounting treatment and rate recovery of costs incurred associated with the proposed merger. At Dec. 31, 1995, $13.9 million of costs associated with the proposed merger had been deferred as a component of Intangible and Other Assets. In February 1996, the appropriate committees of the Minnesota Legislature passed legislation that would affect merger approval for electric utilities. The bill, if passed into law, would provide for certain binding commitments regarding minimum levels of staffing and investment for electric service.
In addition to the regulatory and other governmental approvals of the proposed merger, certain NSP financial and other agreements may be construed to require that, in the case of a change in ownership (such as the proposed merger), the other party to the agreement must consent to the change or waive the requirement. Agreements with such provisions at Dec. 31, 1995, include $101.7 million of long-term debt, operating lease agreements with annual payments of $1.3 million in 1996 and a $10 million credit line agreement, under which there were no borrowings at Dec. 31, 1995. Although neither consents nor waivers from the other parties have yet been obtained, NSP will seek to obtain them prior to the completion of the merger. (See further discussion of the proposed business combination in Note 18 to the Financial Statements.)
Regulation NSP's utility rates are approved by the FERC, the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission, the Public Service Commission of Wisconsin (PSCW), the Michigan Public Service Commission and the South Dakota Public Utilities Commission. Rates are designed to recover plant investment and operating costs and an allowed return on investment, using an annual period upon which rate case filings are based. NSP requests changes in rates for utility services as needed through filings with the governing commissions. The rates charged to retail customers in Wisconsin are reviewed and adjusted biennially. Because comprehensive rate changes are not requested annually in Minnesota, NSP's primary jurisdiction, changes in operating costs can affect NSP's earnings, shareholders' equity and other financial results. Except for Wisconsin electric operations, NSP's rate schedules provide for cost-of-energy and resource adjustments to billings and revenues for changes in the cost of fuel for electric generation, purchased energy, purchased gas, and conservation and energy management program costs. For Wisconsin electric operations, the biennial retail rate review process considers changes in electric fuel and purchased energy costs in lieu of a cost-of-energy adjustment clause. In addition to changes in operating costs, other factors affecting rate filings are sales growth, conservation and demand-side management efforts and the cost of capital.
Competition The Energy Policy Act of 1992 (the Act) was a catalyst for comprehensive and significant changes in the operation of electric utilities, including increased competition. The Act's reform of the PUHCA promotes creation of wholesale non-utility 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. Management believes this legislation will promote the continued trend of increased competition in the electric energy markets. NSP management plans to continue its efforts to be a competitively priced supplier of electricity and an active participant in the competitive market for electricity. The proposed merger with WEC is a key strategic initiative designed to facilitate NSP's effective competition in the future energy marketplace.
In March 1995, the FERC issued a Notice of Proposed Rulemaking on Open Access Non-discriminatory Transmission Services and a Supplemental Notice of Proposed Rulemaking on Stranded Investment (together called the Mega-NOPR). The Mega- NOPR is intended to create a vigorous wholesale electric market by requiring transmission providers to offer open access to their transmission systems. The FERC is proposing to require utilities to unbundle power sales from transmission. This "unbundled service" requirement would apply only to new requirements contracts and new coordination trade contracts. The Mega-NOPR would apply to all utilities under the FERC's jurisdiction and would require each utility to file individual tariffs. The FERC also seeks to require non-jurisdictional transmission-providing entities (such as municipals and cooperatives) to offer open access by including a reciprocity clause in their individual tariffs so that those who take service from a FERC jurisdictional utility must also offer open access. Concurrently with the Mega-NOPR, the FERC issued a proposal for a Real-Time Information Network intended to facilitate open access by requiring all public utilities to create an electronic bulletin board of information regarding their transmission system services, availability and rates. Also in the Mega-NOPR, the FERC proposed to consider cases involving stranded costs resulting from open access (a) when a state regulatory commission does not have authority under state law to address such costs at the time retail wheeling (which is the transmission to retail customers of power generated by a third party, in competition with supplies from the host utility) takes place, and (b) after a state commission has addressed such costs. In response to the FERC's proposals, NSP filed comments with the FERC that supported the Mega-NOPR's open access initiative and asserted NSP's intent that open access transmission tariffs filed in 1994 comply with the spirit of the Mega-NOPR. NSP expects the impact of any rulemaking such as the Mega-NOPR to be consistent with its efforts to be a competitively priced supplier of electricity and an active participant in the competitive market for electricity.
With the development of electric industry competition, the Company has experienced an increase in requests for the use of its transmission system. A large portion of these requests is due to the increase in FERC-approved power marketers. In 1995, the Company filed 23 transmission service agreements for FERC approval, including 10 with power marketers. While the annual transmission revenue in 1995 from this activity was immaterial, it is expected that 1996 revenues will increase due to the growth of power marketing activity in this region.
In response to the developing electric industry competition, Cenergy applied for and was granted permission by the FERC to market electricity (except electricity generated by NSP) in the United States, effective Dec. 1, 1994. Cenergy was one of the first affiliates of an electric utility to obtain this approval from the FERC.
Some states are considering proposals to increase competition in the supply of electricity. In response to a proposal in 1994 by its regulator in Wisconsin, NSP outlined the transitional steps necessary to create an open and fair competitive electric market. NSP's position is that all customers should be able to choose their electric supplier by 2001, and that generation also should be deregulated by 2001. NSP proposes that utilities retain operational control of their transmission and distribution systems, and that utilities should be permitted to recover the cost of investments made under traditional regulation. Regulators in Minnesota and Wisconsin are currently considering what actions they should take regarding electric industry competition. In Wisconsin, regulators developed a plan for a phased approach. They voted to adopt a restructuring plan, which includes a 32-step phase-in of retail wheeling by the year 2001. A key component of the plan is to provide the protections necessary to ensure that consumers are not harmed in an increasingly competitive environment. One component of the plan is to have an independent system operator control transmission access. In Minnesota, regulators have developed draft principles to provide a framework for electric industry restructuring. They have not established definitive timelines for industry restructuring or changes. One of the principles supports an open transmission system and establishing a robust wholesale competitive market. NSP believes the transition to a more competitive electric industry is inevitable and beneficial for all consumers. NSP supports an orderly and efficient transition to an open, fair and competitive energy market for all customers and suppliers. The timing of regulatory actions and their impact on NSP cannot be predicted and may be significant.
During 1992 and 1993, the FERC issued a series of orders (together called Order 636) addressing interstate natural gas pipeline service restructuring. This restructuring "unbundled" each of the services (sales, transportation, storage and ancillary services) traditionally provided by gas pipeline companies. Interstate pipelines have been allowed to recover from their customers 100 percent of prudently incurred transition costs attributable to Order 636 restructuring. Under service agreements that went into effect Nov. 1, 1993, NSP estimates that it will be responsible for less than $11 million of transition costs over a five-year period beginning on that date. To date, NSP's regulatory commissions have approved recovery of these restructuring charges in retail gas rates through the purchased gas adjustment. NSP does not believe Order 636 has materially affected its cost of gas supply. NSP's acquisitions of Viking and Cenergy in 1993 have enhanced its ability to participate in the more competitive gas transportation business. In implementing Order 636, Viking incurred no transition costs.
Customer Cogeneration Koch Refining Co. (Koch), the Company's largest customer which provides approximately $30 million in annual revenues to NSP, proposes to build a cogeneration plant to burn petroleum coke, a refinery byproduct, to produce between 180 and 250 megawatts of electricity. This would be enough supply for Koch's own use plus an additional 80 to 150 megawatts to be sold on the wholesale market. Koch is requesting a legislative exemption from Minnesota property tax for its plant. While NSP supports the reduction of taxes on generating facilities, it believes any reduction should be applied to all generating facilities so that there are no unfair tax advantages available to some generators. This project has several implications for NSP: 1) Koch could become a competitor as it seeks markets for its excess capacity; 2) Koch's capacity would also represent a potential power source for NSP; and 3) Koch's plan represents a potential loss of a large retail customer. The project's anticipated three-year lead time will allow NSP to respond appropriately.
Wholesale Customers NSP had wholesale revenues from sales of electricity of approximately $44 million in 1995 and approximately $57 million in 1994. The trend of increased competition, as previously discussed, has resulted in significant changes in the negotiation of contracts with wholesale customers. In the past several years, these customers have begun to evaluate a variety of energy sources to provide their power supply. While the full impact of these changes is unknown at this time, the following changes have been identified.
In 1992, nine of the Company's municipal wholesale electric customers notified the Company of their intent to terminate their power supply agreements with the Company, effective July 1995 or July 1996. The loss of seven of these customers in July 1995 resulted in a revenue decrease of approximately $12 million from 1994 levels. The other two customers, who are expected to terminate their power agreements in July 1996, provided revenues of $3.6 million in 1995. These nine customers are expected to become wheeling customers providing estimated annual revenues of nearly $3 million. NSP's remaining 19 municipal wholesale electric customers are under contracts with terms expiring in the years 1999 through 2008.
During 1993, the Company signed an electric power agreement to provide Michigan's Upper Peninsula Power Company (UPPCO) with up to 150 megawatts of baseload service, peaking service options and load regulation service options for 20 years from January 1998 through December 2017. Load regulation service is designed to change the level of power delivery during each hour to match UPPCO's load requirements. UPPCO has nominated 50 megawatts of baseload and five megawatts of winter season peaking power purchases from NSP beginning Jan. 1, 1998. The annual revenue for 1998 is projected to be approximately $11 million to $14 million. The interchange agreement between UPPCO and NSP for this sale was accepted by the FERC. The Michigan Public Utilities Commission also must approve the transaction.
Rate Changes As discussed previously under Utility Operating Results, filings for rate changes in 1995 had an immaterial impact on financial results. No significant general rate filings in any of NSP's utility jurisdictions are expected for 1996. However, the Company has proposed rate changes in connection with requested approvals of its proposed business combination with WEC, as discussed previously.
Used Nuclear Fuel Storage and Disposal In 1994, NSP received legislative authorization from the State of Minnesota for dry cask fuel storage facilities at the Company's Prairie Island nuclear generating facility. As a condition of this authorization, the Minnesota Legislature established several resource commitments for the Company, including wind and biomass generation sources, as well as other requirements. In addition, the Company and other utilities filed a lawsuit against the DOE in 1994 to compel the DOE to fulfill its statutory and contractual obligations to store and dispose of used nuclear fuel as required by the Nuclear Waste Policy Act of 1982. Also, the Company is leading a consortium to establish a private facility for interim storage of used nuclear fuel, the outcome of which is uncertain at this time. (See Notes 14 and 15 to the Financial Statements for more information.)
Environmental Matters NSP incurs several types of environmental costs, including nuclear plant decommissioning, storage and ultimate disposal of used nuclear fuel, disposal of hazardous materials and wastes, remediation of contaminated sites and monitoring of discharges into the environment. Because of the continuing trend toward greater environmental awareness and increasingly stringent regulation, NSP has been experiencing a trend toward increasing environmental costs. This trend has caused, and may continue to cause, slightly higher operating expenses and capital expenditures for environmental compliance. In addition to nuclear decommissioning and used nuclear fuel disposal expenses (as discussed in Note 14 to the Financial Statements), costs charged to NSP's operating expenses for environmental monitoring and disposal of hazardous materials and wastes in 1995 were approximately $26 million and are expected to increase to an average annual amount of approximately $30 million for the five-year period 1996-2000. However, the precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are currently unknown. In each of the years, 1995, 1994 and 1993, the Company spent about $15 million for capital expenditures on environmental improvements at its utility facilities. In 1996, the Company expects to incur approximately $20 million in capital expenditures for compliance with environmental regulations and approximately $180 million for the five-year period 1996-2000. These capital expenditure amounts include the costs of constructing used nuclear fuel storage casks. (See Notes 14 and 15 to the Financial Statements for further discussion of these and other environmental contingencies that could affect NSP.)
Weather NSP's earnings can be significantly affected by unusual weather. In 1995, unusual weather, mainly a hot summer, increased earnings over a normal year by an estimated 21 cents per share. Mild weather, mainly cool summers, reduced earnings from a normal year by an estimated 13 cents per share in 1994 and 18 cents per share in 1993. The effect of weather is considered part of NSP's ongoing business operations.
Acquisitions In 1994, NRG acquired ownership interests in three significant international energy projects (listed in Note 3 to the Financial Statements). NSP also made three other strategically important business acquisitions in 1993, including an interstate natural gas pipeline (Viking), an energy services marketing business (Cenergy) and a steam heating and chilled water cooling system business (Minneapolis Energy Center, now an NRG subsidiary). NSP continues to evaluate opportunities to enhance its competitive position and shareholder returns through strategic business acquisitions.
Impact of Non-regulated Investments NSP's net income includes after-tax earnings of $33.6 million, or 50 cents per share, from all of its non-regulated businesses in 1995 and $32.9 million, or 49 cents per share, in 1994. As discussed previously, NRG acquired equity interests in three significant energy projects in 1994. NSP expects to continue investing significant amounts in non-regulated projects, including domestic and international power production projects through NRG, as described under Future Financing Requirements. Depending on the success and timing of involvement in these projects, NSP's goal is for NRG earnings to increase in the future to contribute at least 20 percent of NSP's earnings by the year 2000. The non-regulated projects in which NRG has invested carry a higher level of risk than NSP's traditional utility businesses. Current and future investments in non-regulated projects are subject to uncertainties prior to final legal closing, and continuing operations are subject to foreign government actions, foreign economic and currency risks, partnership actions, competition, operating risks, dependence on certain suppliers and customers, domestic and foreign environmental and energy regulations, or all of these items. Most of NRG's current project investments consist of minority interests, and a substantial portion of future investments may take the form of minority interests, which limits NRG's ability to control the development or operation of the projects. In addition, significant expenses may be incurred for potential projects pursued by NRG that may never materialize. The operating results of NSP's non-regulated businesses in 1995 and 1994 may not necessarily be indicative of future operating results.
Accounting Changes The Financial Accounting Standards Board (FASB) has issued two new accounting standards that become effective in 1996. Statement of Financial Accounting Standards (SFAS) No. 121, Accounting for the Impairment of Long-Lived Assets, establishes standards for measuring and recognizing asset impairments. SFAS No. 123, Accounting for Stock-Based Compensation, provides an optional accounting method for compensation from stock option and other stock award programs that NSP does not intend to use. NSP does not expect the adoption of these new accounting standards to have a material impact on its results of operations or financial condition. However, the principles of SFAS No. 121 will be followed to measure the effects of any stranded investments that could arise from the Act, the FERC's Mega-NOPR proposal or other competitive business developments.
The FASB also has proposed new accounting standards expected to go into effect in 1997. The standards would require the full accrual of nuclear plant decommissioning and certain other site exit obligations. Material adjustments to NSP's balance sheet could occur under the FASB's proposal. However, the effects of regulation are expected to minimize or eliminate any impact on operating expenses and earnings from this future accounting change. (For further discussion of the expected impact of this change, see Note 14 to the Financial Statements.)
Use of Derivatives Through its non-regulated subsidiaries, NSP uses derivative financial instruments to hedge the risks of fluctuations in foreign currencies and natural gas prices. Also, to hedge the interest rate risk associated with fixed rate debt in a declining interest rate environment, NSP uses interest rate swap agreements to convert fixed rate debt to variable rate debt. (See Notes 1 and 11 to the Financial Statements for further discussion of NSP's financial instruments and derivatives.)
Non-recurring Items NSP's earnings for 1995 include two significant unusual or infrequently occurring items. As discussed in the Non-regulated Business Results section, NRG recognized a pretax gain of approximately $30 million (26 cents per share) from a power sales contract termination settlement. Partially offsetting this gain was an asset impairment write- down of $5 million before taxes (4 cents per share) for a non- regulated domestic energy project.
NSP's 1994 earnings also included several significant unusual or infrequently occurring items. Although their net effect was an earnings increase of only 1 cent per share, individually significant non-recurring items included a gain on termination of a non-regulated cogeneration contract, interest income from the settlement of a federal income tax dispute, a charge for pre-1994 postemployment costs associated with adopting SFAS No. 112, and asset impairment write-downs for certain non-regulated energy projects.
Inflation Historically, certain operating costs, mainly labor and property taxes, have been affected by inflation. Also, inflation has tended to increase the replacement cost of operating facilities, which has increased depreciation expense when replacement facilities are constructed. However, several significant expense items, including fuel costs, income taxes and interest expense have been less sensitive to inflation. Overall, inflation at the levels currently being experienced is not expected to materially affect NSP's prices to customers or returns to shareholders.
LIQUIDITY AND CAPITAL RESOURCES
1995 Financing Requirements NSP's need for capital funds is primarily related to the construction of plant and equipment to meet the needs of electric and gas utility customers and to fund equity commitments or other investments in non-regulated businesses. Total NSP utility capital expenditures (including AFC) were $386 million in 1995. Of that amount, $318 million related to replacements and improvements of NSP's electric system and nuclear fuel, and $37 million involved construction of natural gas distribution facilities. NSP companies invested $71 million in non-regulated projects and property in 1995. NRG primarily invested in existing projects. In 1995, Cenergy became a majority investor (80 percent) in Energy Masters Corporation, a firm specializing in energy efficiency improvement services for commercial, industrial and institutional customers. The investment is accounted for on a consolidated basis. Eloigne Company invested in affordable housing projects, including wholly owned and limited partnership ventures.
1995 Financing Activity During 1995, NSP's primary sources of capital included internally generated funds, long-term debt, short-term debt and common stock issuances, as discussed below. The allocation of financing requirements between these capital options is based on the relative cost of each option, regulatory restrictions and the constraints of NSP's long-range capital structure objectives. During 1995, NSP continued to meet its long-range regulated capital structure objective of 45-50 percent common equity and 42-50 percent debt.
Funds generated internally from operating cash flows in 1995 remained sufficient to meet working capital needs, debt service, dividend payout requirements and non-regulated investment commitments, as well as fund a significant portion of construction expenditures. The pretax interest coverage ratio, excluding AFC, was 3.8 in 1995 and 3.9 in 1994. These ratios met NSP's objective range of 3.5-5.0 for interest coverage. Internally generated funds could have provided financing for 85 percent of NSP's total capital expenditures for 1995 and 72 percent of the $1.9 billion in capital expenditures incurred for the five-year period 1991-1995.
NSP had approximately $216 million in short-term borrowings outstanding as of Dec. 31, 1995. Throughout 1995, short-term borrowings were used to finance a portion of utility capital expenditures and provide for other NSP cash needs.
In 1995, the Company issued $250 million of first mortgage bonds to refinance higher-cost debt issues and reduce short-term debt levels. Eloigne Company also issued approximately $12.5 million of long-term debt to finance affordable housing project investments.
During 1995, the Company issued new shares of common stock under various stock plans, including 536,360 new shares under the Employee Stock Ownership Plan (ESOP), 527,671 new shares under the Dividend Reinvestment and Stock Purchase Plan (DRSPP), and 63,780 new shares under the Executive Long-Term Incentive Award Stock Plan. In addition, the Company issued common stock in connection with a non-regulated business acquisition. At Dec. 31, 1995, the total number of common shares outstanding was 68,175,934.
NSP's equity investments in non-regulated projects during 1995 were financed through internally generated funds. Project financing requirements, in excess of equity contributions from investors, were satisfied with project debt. Project debt associated with many of NSP's non-regulated investments is not reflected in NSP's balance sheet because the equity method of accounting is used for such investments. (See Note 3 to the Financial Statements.)
In January 1996, NRG issued $125 million of 7.625 percent unsecured Senior Notes maturing in 2006 to support equity requirements for projects currently under way and in development. The Senior Notes were assigned ratings of BBB- by S&P's Rating Group and Baa3 by Moody's.
Future Financing Requirements Utility financing requirements for 1996-2000 may be affected in varying degrees by numerous factors, including load growth, changes in capital expenditure levels, rate changes allowed by regulatory agencies, new legislation, market entry of competing electric power generators, changes in environmental regulations and other regulatory requirements. NSP currently estimates that its utility capital expenditures will be $410 million in 1996 and $1.9 billion for the five-year period 1996-2000. Of the 1996 amount, approximately $345 million is scheduled for utility electric facilities and approximately $45 million for natural gas facilities including Viking. In addition to utility capital expenditures, expected financing requirements for the 1996-2000 period include approximately $480 million to retire long-term debt and meet first mortgage bond sinking fund requirements.
Through its subsidiaries, NSP expects to invest significant amounts in non-regulated projects in the future. Financing requirements for non-regulated project investments may vary depending on the success, timing and level of involvement in projects currently under consideration. NSP's potential capital requirements for non-regulated projects and property are estimated to be approximately $140 million in 1996 and approximately $550 million for the five-year period 1996-2000. These amounts include commitments for NRG investments, as discussed in Note 15 to the Financial Statements, and Eloigne Company investments of up to $13 million annually in 1996-2000 for affordable housing projects. Eloigne Company expects to finance approximately 65 percent of these investments in affordable housing projects with equity and approximately 35 percent with long-term debt. In addition to investments in non- regulated projects, NSP continues to evaluate opportunities to enhance shareholder returns and achieve long-term financial objectives through acquisitions of existing businesses. Long- term financing may be required for such investments.
The Company also will have future financing requirements for the portion of nuclear plant decommissioning costs not funded externally. Based on the most recent decommissioning study, these amounts are anticipated to be approximately $363 million, and are expected to be paid during the years 2010 to 2022.
Future Sources of Financing NSP expects to obtain external capital for future financing requirements by periodically issuing long-term debt, short-term debt, common stock and preferred stock as needed to maintain desired capitalization ratios. Over the long-term, NSP's equity investments in non- regulated projects are expected to be financed through internally generated funds or the Company's issuance of common stock. Financing requirements for the non-regulated projects, in excess of equity contributions from investors, are expected to be fulfilled through project or subsidiary debt. Decommissioning expenses not funded by an external trust are expected to be financed through a combination of internally generated funds, long-term debt and common stock. The extent of external financing to be required for nuclear decommissioning costs, as discussed above, is unknown at this time.
NSP's ability to finance its utility construction program at a reasonable cost and to provide for other capital needs depends on its ability to meet investors' return expectations. Financing flexibility is enhanced by providing working capital needs and a high percentage of total capital requirements from internal sources, and having the ability to issue long-term securities and obtain short-term credit. NSP expects to maintain adequate access to securities markets in 1996. Access to securities markets at a reasonable cost is determined in large part by credit quality. The Company's first mortgage bonds are rated AA- by Standard & Poor's Corporation, A1 by Moody's Investors Service, Inc. (Moody's), AA- by Duff & Phelps, Inc., and AA by Fitch Investors Service, Inc. Ratings for the Wisconsin Company's first mortgage bonds are generally comparable. These ratings reflect the views of such organizations, and an explanation of the significance of these ratings may be obtained from each agency. In May 1994, Moody's downgraded the Company's first mortgage bond ratings to A1 based on its interpretation of provisions of a Minnesota law enacted in 1994 for used nuclear fuel storage at the Prairie Island generating plant. (The other three rating agencies reaffirmed their ratings of the Company's bonds after considering the potential impact of the legislation on NSP.) As discussed in Notes 14 and 15 to the Financial Statements, the legislation requires the Company to increase its use of renewable energy sources such as wind and biomass power. Moody's has indicated that it believes these sources of power are considerably more costly than the power currently generated and that NSP's electric production costs will increase materially over current levels. NSP acknowledges that electric production costs may increase as a result of the Prairie Island legislation. In 1995, Moody's placed the Company's ratings on credit review for possible upgrade based on anticipated cost savings from the proposed merger with WEC, which was discussed previously.
The Company's and the Wisconsin Company's first mortgage indentures limit the amount of first mortgage bonds that may be issued. The MPUC and the PSCW have jurisdiction over securities issuance. At Dec. 31, 1995, with an assumed interest rate of 7.0 percent, the Company could have issued about $2.5 billion of additional first mortgage bonds under its indenture, and the Wisconsin Company could have issued about $356 million of additional first mortgage bonds under its indenture.
The Company filed a shelf registration for first mortgage bonds with the Securities and Exchange Commission (SEC) in October 1995. Depending on capital market conditions, the Company expects to issue the $300 million of registered, but unissued, bonds over the next several years to raise additional capital or redeem outstanding securities. In addition, depending on market conditions, the Wisconsin Company may issue up to $65 million in first mortgage bonds to redeem outstanding securities or raise additional capital.
The Company's Board of Directors has approved short-term borrowing levels up to 10 percent of capitalization. The Company has received regulatory approval for up to $445 million in short-term borrowing levels and plans to keep its credit lines at or above its average level of commercial paper borrowings. Commercial banks presently provide credit lines of approximately $265 million to the Company and an additional $17 million to subsidiaries of the Company. These credit lines make short-term financing available in the form of bank loans.
The Company's Articles of Incorporation authorize the maximum amount of preferred stock that may be issued. Under these provisions, the Company could have issued all $460 million of its remaining authorized, but unissued, preferred stock at Dec. 31, 1995, 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. In January 1996, the Company filed a registration statement with the SEC to provide for the sale of up to 1.6 million additional shares of new common stock under the Company's Dividend Reinvestment and Stock Purchase Plan (DRSPP) and Executive Long-Term Incentive Award Stock Plan. The Company may issue new shares or purchase shares on the open market for its stock-based plans. (See Note 5 to the Financial Statements for discussion of stock awards outstanding.) The Company plans to issue new shares for its DRSPP, ESOP and Executive Long-Term Incentive Award Stock plans in 1996. While no general public stock offerings are currently anticipated in 1996, such offerings may be necessary to fund significant equity investments in non-regulated projects should they occur.
Internally generated funds from utility operations are expected to equal approximately 90 percent of anticipated utility capital expenditures for 1996 and approximately 100 percent of the $1.9 billion in anticipated utility capital expenditures for the five-year period 1996-2000. Internally generated funds from all operations are expected to equal approximately 75 percent and 90 percent, respectively, of the anticipated total capital expenditures for 1996 and the five- year period 1996-2000. Because NSP intends to reinvest foreign cash flows in non-U.S. operations, the equity income from international investments currently does not provide operating cash available for U.S. cash requirements such as payment of dividends, domestic capital expenditures and domestic debt service. Through NRG, NSP intends to pursue a diverse portfolio of foreign energy projects with varying levels of cash flows, income and foreign taxation to allow maximum flexibility of foreign cash flows.
The merger agreement, as previously discussed, provides for restrictions on certain transactions by both the Company and WEC, including the issuance of debt and equity securities. While the Company currently does not plan to enter into transactions that would not comply with these restrictions, circumstances may arise to make such transactions necessary. Under such circumstances, the Company and WEC would need to mutually agree to amend the merger agreement.
Item 8
Item 8 - Financial Statements and Supplementary Data
See Item 14(a)-1 in Part IV for index of financial statements included herein.
See Note 17 of Notes to Financial Statements for summarized quarterly financial data.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders of Northern States Power Company:
In our opinion, the accompanying consolidated balance sheet and statement of capitalization and the related consolidated statements of income, of common stockholders' equity and of cash flows present fairly, in all material respects, the financial position of Northern States Power Company, a Minnesota corporation, and its subsidiaries at Dec. 31, 1995, and the results of their operations and their cash flows for the year in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for the opinion expressed above. The consolidated financial statements of the Company and its subsidiaries for the years ended Dec. 31, 1994 and 1993 were audited by other independent accountants whose report dated Feb. 8, 1995 expressed an unqualified opinion on those statements and included an explanatory paragraph related to a change in method of accounting for postretirement health care costs in 1993.
(Price Waterhouse LLP)
PRICE WATERHOUSE LLP Minneapolis, Minnesota February 5, 1996 INDEPENDENT AUDITORS' REPORT
To the Shareholders of Northern States Power Company:
We have audited the accompanying consolidated balance sheet and statement of capitalization of Northern States Power Company (Minnesota) and its subsidiaries (the Companies) as of December 31, 1994, and the related consolidated statements of income, changes in common stockholders' equity, and cash flows for each of the two years in the period ended December 31, 1994, listed in the accompanying table of contents in Item 14(a)1. These consolidated financial statements and financial statement schedules are the responsibility of the Companies' management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the 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 financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Companies at December 31, 1994, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
As discussed in Note 2 to the financial statements, the Companies changed their method of accounting for postretirement health care costs in 1993.
(Deloitte & Touche LLP)
DELOITTE & TOUCHE LLP Minneapolis, Minnesota February 8, 1995
NOTES TO FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
System of Accounts Northern States Power Company, a Minnesota corporation (the Company), is predominantly a regulated public utility serving customers in Minnesota, North Dakota and South Dakota. Northern States Power Company, a Wisconsin corporation (the Wisconsin Company), a wholly owned subsidiary of the Company, is a regulated public utility serving customers in Wisconsin and Michigan. Another wholly owned subsidiary, Viking Gas Transmission Company (Viking), is a regulated natural gas transmission company that operates a 500-mile interstate natural gas pipeline. Consequently, the Company, the Wisconsin Company and Viking maintain accounting records in accordance with either the uniform system of accounts prescribed by the Federal Energy Regulatory Commission (FERC) or those prescribed by state regulatory commissions, whose systems are the same in all material respects.
Principles of Consolidation The consolidated financial statements include all material companies in which NSP holds a controlling financial interest, including: the Wisconsin Company; NRG Energy, Inc. (NRG); Viking; Cenergy, Inc. (Cenergy), which changed its name to Cenerprise, Inc. effective Jan. 1, 1996; and Eloigne Company. As discussed in Note 3, NSP has investments in partnerships, joint ventures and projects for which the equity method of accounting is applied. Earnings from equity in international investments are recorded net of foreign income taxes. All significant intercompany transactions and balances have been eliminated in consolidation except for intercompany and intersegment profits for sales among the electric and gas utility businesses of the Company, the Wisconsin Company and Viking, which are allowed in utility rates. The Company and its subsidiaries collectively are referred to herein as NSP.
Revenues Revenues are recognized based on products and services provided to customers each month. Because utility customer meters are read and billed on a cycle basis, unbilled revenues (and related energy costs) are estimated and recorded for services provided from the monthly meter-reading dates to month- end.
The Company's rate schedules, applicable to substantially all of its utility customers, include cost-of-energy adjustment clauses, under which rates are adjusted to reflect changes in average costs of fuels, purchased energy and gas purchased for resale. The Company's rate schedules in Minnesota also include a rate adjustment clause, which is to be adjusted annually, to reflect changes in recovery of electric and gas deferred conservation program costs. As ordered by its primary regulator, Wisconsin Company retail rate schedules include a cost-of-energy adjustment clause for purchased gas but not for electric fuel and purchased energy. The biennial retail rate review process for Wisconsin electric operations considers changes in electric fuel and purchased energy costs in lieu of a cost-of-energy adjustment.
Utility Plant and Retirements Utility plant is stated at original cost. The cost of additions to utility plant includes contracted work, direct labor and materials, allocable overhead costs and allowance for funds used during construction. The cost of units of property retired, plus net removal cost, is charged to the accumulated provision for depreciation and amortization. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses.
Allowance for Funds Used During Construction (AFC) AFC, a non- cash item, is computed by applying a composite pretax rate, representing the cost of capital used to finance utility construction activities, to qualified Construction Work in Progress (CWIP). The AFC rate was 6.0 percent in 1995, 5.0 percent in 1994 and 7.4 percent in 1993. The amount of AFC capitalized as a construction cost in CWIP is credited to other income (for equity capital) and interest charges (for debt capital). AFC amounts capitalized in CWIP are included in rate base for establishing utility service rates. In addition to construction-related amounts, AFC is also recorded to reflect returns on capital used to finance conservation programs.
Depreciation For financial reporting purposes, depreciation is computed by applying the straight-line method over the estimated useful lives of various property classes. The Company files with the Minnesota Public Utilities Commission (MPUC) an annual review of remaining lives for electric and gas production properties. The most recent studies, as approved by the MPUC, recommended a decrease of approximately $0.2 million and an increase of approximately $0.5 million for the 1995 and 1994 annual depreciation accruals, respectively.
Every five years, the Company also must file an average service life filing for transmission, distribution and general properties. The most recent filings approved by the MPUC were in 1994 for general plant and in 1993 for all other facilities. Depreciation provisions, as a percentage of the average balance of depreciable utility property in service, were 3.64 percent in 1995, 3.55 percent in 1994 and 3.47 percent in 1993.
Decommissioning As discussed in Note 14, NSP currently is recording the future costs of decommissioning the Company's nuclear generating plants through annual depreciation accruals. The provision for the estimated decommissioning costs has been calculated using an annuity approach designed to provide for full expense accrual (with full rate recovery) of the future decommissioning costs, including reclamation and removal, over the estimated operating lives of the Company's nuclear plants. The Financial Accounting Standards Board (FASB) has proposed new accounting standards expected to go into effect in 1997. The standards would require the full accrual of nuclear plant decommissioning and certain other site exit obligations beginning in 1997. (See Note 14 for more discussion of this proposed standard.)
Nuclear Fuel Expense The original cost of nuclear fuel is amortized to fuel expense based on energy expended. Nuclear fuel expense also includes assessments from the U.S. Department of Energy (DOE) for costs of future fuel disposal and DOE facility decommissioning, as discussed in Note 14.
Environmental Costs Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. When a single estimate of the liability cannot be determined, the low end of the estimated range is recorded. Costs are charged to expense or deferred as a regulatory asset based on expected recovery in future rates, if they relate to the remediation of conditions caused by past operations, or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised, and remediation efforts proceed. For sites where NSP has been designated as one of several potentially responsible parties, the amount accrued represents NSP's estimated share of the cost. NSP intends to treat any future costs incurred related to decommissioning and restoration of its non-nuclear power plants and substation sites, where operation may extend indefinitely, as a capitalized removal cost of retirement in utility plant. Depreciation expense levels currently recovered in rates include a provision for an estimate of removal costs (based on historical experience).
Income Taxes NSP records income taxes in accordance with Statement of Financial Accounting Standards (SFAS) No. 109--- Accounting for Income Taxes. Under the liability method required by SFAS No. 109, income taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by law to be in effect when the temporary differences reverse. Due to the effects of regulation, current income tax expense is provided for the reversal of some temporary differences previously accounted for by the flow-through method. Also, regulation has created certain regulatory assets and liabilities related to income taxes, as summarized in Note 10. NSP's policy for income taxes related to international operations is discussed in Note 9.
Investment tax credits are deferred and amortized over the estimated lives of the related property.
Foreign Currency Translation The local currencies are generally the functional currency of NSP's foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. The resulting currency translation adjustments are accumulated and reported as a separate component of stockholders' equity. Income, expense and cash flows are translated at weighted-average rates of exchange for the period.
Exchange gains and losses that result from foreign currency transactions (e.g. converting cash distributions made in one currency to another) are included in the results of operations as a component of equity in earnings of unconsolidated affiliates. Through Dec. 31, 1995, NSP had not experienced any material translation gains or losses from foreign currency transactions that have occurred since the respective foreign investment dates.
Derivative Financial Instruments NSP's policy is to hedge foreign currency denominated investments as they are made to preserve their U.S. dollar value, where appropriate hedging instruments are available. NRG has entered into currency hedging transactions through the use of forward foreign currency exchange agreements. Gains and losses on these agreements offset the effect of foreign currency exchange rate fluctuations on the valuation of the investments underlying the hedges. Hedging gains and losses, net of income tax effects, are reported with other currency translation adjustments as a separate component of stockholders' equity. NRG is not hedging currency translation adjustments related to future operating results. NSP does not speculate in foreign currencies. A second derivative arrangement is the use of natural gas futures contracts by Cenergy to manage the risk of gas price fluctuations. The cost or benefit of natural gas futures contracts is recorded when related sales commitments are fulfilled as a component of Cenergy's non- regulated operating expenses. NSP does not speculate in natural gas futures. A third derivative instrument used by NSP is interest rate swaps that convert fixed rate debt to variable rate debt. The cost or benefit of the interest rate swap agreements is recorded as a component of interest expense. None of these three derivative financial instruments is reflected on NSP's balance sheet.
Use of Estimates In recording transactions and balances resulting from business operations, NSP uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, environmental loss contingencies, unbilled revenues and actuarially determined benefit costs. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. Recent changes in interest rates have resulted in changes to actuarial assumptions used in the benefit cost calculations for postretirement benefits. Also, the depreciable lives of certain plant assets are reviewed and, if appropriate, revised each year, as discussed previously. (See Notes 8, 14 and 15 for more information on the effects of these changes in estimates.)
Cash Equivalents NSP considers investments in certain debt instruments (primarily commercial paper) with an original maturity to NSP of three months or less at the time of purchase to be cash equivalents.
Regulatory Deferrals As regulated utilities, the Company, the Wisconsin Company and Viking account for certain income and expense items under the provisions of SFAS No. 71---Accounting for the Effects of Regulation. In doing so, certain costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates. Likewise, certain credits that otherwise would be reflected as income are deferred as regulatory liabilities based on expected flowback to customers in future rates. Management's expected recovery of deferred costs and expected flowback of deferred credits are generally based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with ratemaking treatment established by regulators. Note 10 describes the nature and amounts of these regulatory deferrals.
Other Assets The purchase of various non-regulated entities from 1993-1995 at a price exceeding the underlying fair value of net assets acquired resulted in recorded goodwill of $20.3 million ($19.0 million net of accumulated amortization) at Dec. 31, 1995. This goodwill and other intangible assets acquired are being amortized using the straight-line method over periods of 15 to 30 years. NSP periodically evaluates the recovery of goodwill based on an analysis of estimated undiscounted future cash flows.
Intangible and other assets also include deferred financing costs (net of amortization) of approximately $11.8 million at Dec. 31, 1995. These costs are being amortized over the remaining maturity period of the related debt.
Reclassifications Certain reclassifications have been made to the 1994 and 1993 financial statements to conform with the 1995 presentation. These reclassifications had no effect on net income or earnings per share.
2. Accounting Changes
Postemployment Benefits Effective Jan. 1, 1994, NSP adopted the provisions of SFAS No. 112---Employers' Accounting for Postemployment Benefits. This standard required the accrual of certain postemployment costs, such as injury compensation and severance, that are payable in the future. The Company's pre- 1994 liability of approximately $9.4 million (8 cents per share) was expensed in 1994.
Postretirement Benefits As discussed in Note 8, NSP changed its accounting for postretirement medical and death benefits in 1993. Due to rate recovery of the expense increases, the change had an immaterial effect on net income. Of the 1993 cost increases due to adoption of SFAS No. 106, about $12 million was deferred to be amortized over rate recovery periods in 1994- 1996. In 1994, administrative and general expenses increased by approximately $16 million due to the full recognition of accrued SFAS No. 106 costs, including amounts deferred from 1993.
3. Investments Accounted for by the Equity Method
Through its non-regulated subsidiaries, NSP has investments in various international and domestic energy projects and domestic affordable housing and real estate projects. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents NSP from exercising a controlling influence over operating and financial policies of the projects. Under this method, equity in the pretax income or losses of domestic partnerships and in the net income or losses of international projects is reflected as Equity in Earnings of Unconsolidated Affiliates. A summary of NSP's significant equity-method investments is as follows:
Investments in the MIBRAG and Gladstone projects in 1994 resulted in an increase in the equity in earnings from unconsolidated affiliates of approximately $26 million in 1994.
Summarized Financial Information of Unconsolidated Affiliates Summarized financial information for these projects, including interests owned by NSP and other parties, was as follows (as of and for the years ended Dec. 31, 1995 and 1994):
Financial Position (Millions of dollars) 1995 1994 Current Assets $ 762.1 $ 514.9 Other Assets 2 631.9 1 593.8 Total Assets $3 394.0 $2 108.7
Current Liabilities $ 295.5 $ 159.6 Other Liabilities 2 290.2 1 480.0 Equity 808.3 469.1 Total Liabilities and Equity $3 394.0 $2 108.7
NSP's Equity Investment in Unconsolidated Affiliates $266.0 $179.1
Results of Operations (Millions of dollars)
1995 1994
Operating Revenues $790.2 $778.4 Operating Income $154.2 $128.8 Net Income $160.2 $117.0
4. Cumulative Preferred Stock
The Company has two series of adjustable rate preferred stock. The dividend rates are calculated quarterly and are based on prevailing rates of certain taxable government debt securities indices. At Dec. 31, 1995, the annualized dividend rates were $5.50 for both series A and series B.
At Dec. 31, 1995, 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.
5. 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, 1995, the Company could have paid, without restrictions, additional cash dividends of more than $1 billion on common stock.
NSP has an Executive Long-Term Incentive Award Stock Plan that permits granting non-qualified stock options. The options currently granted may be exercised one year from the date of grant and are exercisable thereafter for up to nine years. The plan also allows certain employees to receive restricted stock and other performance awards. Performance awards are valued in dollars, but paid in shares based on the market price at the time of payment. Transactions under the various incentive stock programs, which may result in the issuance of new shares, were as follows:
Stock Awards (Thousands of shares) 1995 1994 1993 Outstanding Jan. 1 782.4 537.1 528.7 Options granted 278.0 304.0 196.9 Other stock awards .2 9.5 Options and awards exercised (63.8) (42.6) (174.3) Options and awards forfeited (6.5) (16.1) (22.2) Other (.1) (.2) (1.5) Outstanding at Dec. 31 990.0 782.4 537.1
Option price ranges: Unexercised at Dec. 31 $33.25-$45.50 $33.25-$43.50 $33.25-$43.50 Exercised during the year $33.25-$43.50 $33.25-$43.50 $33.25-$40.94
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.
6. Short-Term Borrowings
NSP has approximately $282 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, 1995, and approximately $3.6 million of such borrowings, with interest payable at 9.75 percent, at Dec. 31, 1994. However, $9.6 million in letters of credit were outstanding, which reduced the available credit lines at Dec. 31, 1995.
At Dec. 31, 1995 and 1994, the Company had $215.6 million and $234.8 million, respectively, in short-term commercial paper borrowings outstanding. The weighted average interest rates on all short-term borrowings as of Dec. 31, 1995, and Dec. 31, 1994, were 5.7 percent and 6.1 percent, respectively.
7. 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 $990 million. The Company may, and has, applied property additions in lieu of cash payments on all series, as permitted by its First Mortgage Indenture. The Wisconsin Company also may apply property additions in lieu of cash on all series as permitted by its First Mortgage Indenture. Except for minor exclusions, all real and personal property of the Company and the Wisconsin Company is subject to the liens of the first mortgage indentures. Other debt securities are secured by a lien on the related real or personal property, as indicated on the Consolidated Statements of Capitalization.
The Company's First Mortgage Bonds Series due March 1, 2011, and the City of Becker Pollution Control Revenue Bonds Series due March 1, 2019, and Sept. 1, 2019, have variable interest rates, which currently change at various periods up to 270 days, based on prevailing rates for certain commercial paper securities or similar issues. The interest rates applicable to these issues averaged 5.2 percent, 3.7 percent and 3.8 percent, respectively, at Dec. 31, 1995. The 2011 series bonds are redeemable upon seven days notice at the option of the bondholder. The Company also is potentially liable for repayment of the 2019 Series Becker Bonds when the bonds are tendered, which occurs each time the variable interest rates change. The principal amount of all three series of these variable rate bonds outstanding represents potential short-term obligations and, therefore, is reported under current liabilities on the balance sheet.
Maturities and sinking-fund requirements on long-term debt are: 1996, $25,760,000; 1997, $111,553,000; 1998, $14,457,000; 1999, $210,909,000; and 2000, $115,982,000.
8. Benefit Plans and Other Postretirement Benefits
NSP offers the following benefit plans to its benefit employees, of whom approximately 43 percent are represented by five local labor unions under a collective-bargaining agreement, which expires Dec. 31, 1996.
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.
It is the Company's policy to fully fund the actuarially determined pension costs recognized for ratemaking purposes, subject to the limitations under applicable employee benefit and tax laws. Plan assets principally consist of common stock of public companies, corporate bonds and U.S. government securities. The funded status of NSP's pension plan as of Dec. 31 is as follows:
(Thousands of dollars) 1995 1994 Actuarial present value of benefit obligation: Vested $686 403 $571 254 Non-vested 155 177 120 420
Accumulated benefit obligation $841 580 $691 674
Projected benefit obligation $1 039 981 $836 957 Plan assets at fair value 1 456 530 1 165 584 Plan assets in excess of projected benefit obligation (416 549) (328 627) Unrecognized prior service cost (20 805) (21 538) Unrecognized net actuarial gain 452 699 370 289 Unrecognized net transitional asset 615 691 Net pension liability recorded $15 960 $20 815
For regulatory purposes, the Company's pension expense is determined and recorded under the aggregate-cost method. As required by SFAS No. 87---Employers' Accounting for Pensions, the difference between the pension costs recorded for ratemaking purposes and the amounts determined under SFAS No. 87 is recorded as a regulatory liability on the balance sheet. Net annual periodic pension cost includes the following components:
(Thousands of dollars) 1995 1994 1993
Service cost-benefits earned during the period $24 499 $27 536 $25 015 Interest cost on projected benefit obligation 69 742 65 107 71 075 Actual return on assets (344 837) (12 668) (152 019) Net amortization and deferral 240 458 (82 114) 66 299
Net periodic pension cost determined under SFAS No. 87 (10 138) (2 139) 10 370 Additional costs recognized due to actions of regulators 10 454 3 922 5 117 Net periodic pension cost recognized for ratemaking $316 $1 783 $15 487
The weighted average discount rate used in determining the actuarial present value of the projected obligation was 7 percent in 1995 and 8 percent in 1994. The rate of increase in future compensation levels used in determining the actuarial present value of the projected obligation was 5 percent in 1995 and 1994. The assumed long-term rate of return on assets used for cost determinations under SFAS No. 87 was 9 percent for 1995 and 8 percent for 1994 and 1993. Assumption changes decreased 1995 pension costs (determined under SFAS No. 87) by approximately $21.5 million. Assumption changes are expected to increase 1996 pension costs (determined under SFAS No. 87) by approximately $13.6 million. Because the Company's pension expense is determined under the aggregate-cost method (not SFAS No. 87) for regulatory and financial reporting purposes, the effects of regulation prevent the majority of these assumption changes from affecting earnings.
Postretirement Health Care NSP has a contributory health and welfare benefit plan that provides health care and death benefits to substantially all employees after their retirement. The plan is intended to provide for sharing the costs of retiree health care between NSP and retirees. For employees retiring after Jan. 1, 1994, a six-year cost-sharing strategy was implemented with retirees paying 15 percent of the total cost of health care in 1994, increasing to a total of 40 percent in 1999.
Effective Jan. 1, 1993, NSP adopted the provisions of SFAS No. 106---Employers' Accounting for Postretirement Benefits Other Than Pensions. SFAS No. 106 requires the actuarially determined obligation for postretirement health care and death benefits to be fully accrued by the date employees attain full eligibility for such benefits, which is generally when they reach retirement age. This is a significant change from NSP's pre-1993 policy of recognizing benefit costs on a cash basis after retirement. In conjunction with the adoption of SFAS No. 106, NSP elected to amortize on a straight-line basis over 20 years the unrecognized accumulated postretirement benefit obligation (APBO) of $215.6 million for current and future retirees. This obligation considered 1994 plan design changes, including Medicare integration, increased retiree cost sharing and managed indemnity measures not in effect in 1993.
Before 1993, NSP funded payments for retiree benefits internally. While NSP generally prefers to continue using internal funding of benefits paid and accrued, significant levels of external funding, including the use of tax-advantaged trusts, have been required by NSP's regulators, as discussed below. Plan assets held in such trusts as of Dec. 31, 1995, consisted of investments in equity mutual funds and cash equivalents. The funded status of NSP's health care plan as of Dec. 31 is as follows:
(Millions of dollars) 1995 1994
APBO: Retirees $145.8 $132.2 Fully eligible plan participants 24.4 21.5 Other active plan participants 116.8 79.4 Total APBO 287.0 233.1 Plan assets at fair value 11.6 8.0 APBO in excess of plan assets 275.4 225.1 Unrecognized net actuarial gain (loss) (40.4) 2.3 Unrecognized transition obligation (183.2) (194.0) Net benefit obligation recorded $51.8 $ 33.4
The assumed health care cost trend rates used in measuring the APBO at Dec. 31, 1995 and 1994, respectively, were 10.4 and 11.0 percent for those under age 65, and 7.3 and 7.5 percent for those over age 65. The assumed cost trend rates are expected to decrease each year until they reach 5.5 percent for both age groups in the year 2004, after which they are assumed to remain constant. A 1 percent increase in the assumed health care cost trend rate for each year would increase the APBO by approximately 15 percent as of Dec. 31, 1995. Service and interest cost components of the net periodic postretirement cost would increase by approximately 17 percent with a similar 1 percent increase in the assumed health care cost trend rate. The assumed discount rate used in determining the APBO was 7 percent for Dec. 31, 1995, 8 percent for Dec. 31, 1994, and 7 percent for Dec. 31, 1993, compounded annually. The assumed long-term rate of return on assets used for cost determinations under SFAS No. 106 was 8 percent for 1995 and 1994. Assumption changes decreased 1994 costs by approximately $2.1 million and decreased 1995 costs by approximately $2.0 million. The effect of the changes in 1996 is expected to be a cost increase of approximately $2.1 million.
The net annual periodic postretirement benefit cost recorded consists of the following components:
(Millions of dollars) 1995 1994 1993
Service cost-benefits earned during the year $5.2 $5.0 $4.4 Interest cost (on service cost and APBO) 19.2 16.1 17.5 Actual return on assets (1.0) (.2) (.1) Amortization of transition obligation 10.8 10.8 10.8 Net amortization and deferral 0.4 (.3) .1 Net periodic postretirement health care cost under SFAS No. 106 34.6 31.4 32.7 Costs recognized (deferred) due to actions of regulators 4.0 4.1 (12.1) Net periodic postretirement health care cost recognized for ratemaking $38.6 $35.5 $20.6
Regulators for NSP's retail and wholesale customers in Minnesota, Wisconsin and North Dakota have allowed full recovery of increased benefit costs under SFAS No. 106, effective in 1993. Increased 1993 accrual costs for Minnesota retail customers are being amortized over the years 1994 through 1996, consistent with approved rate recovery. External funding was required by Minnesota and Wisconsin retail regulators to the extent it is tax advantaged; funding began for Wisconsin in 1993 and must begin by the next general rate filing for Minnesota. For wholesale ratemaking, the FERC has required external funding for all benefits paid and accrued under SFAS No. 106.
ESOP NSP has a leveraged Employee Stock Ownership Plan (ESOP) that covers substantially all employees. Employer contributions to this non-contributory, defined contribution plan are generally made to the extent NSP realizes a tax savings on its income statement from dividends paid on certain shares held by the ESOP. Contributions to the ESOP in 1995, 1994 and 1993, which represent compensation expense, were $5,059,000, $5,695,000 and $6,281,000, 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. Leveraged shares held by the ESOP are allocated to participants when dividends on stock held by the plan are used to repay ESOP loans. NSP's ESOP held 5.7 million and 5.4 million shares of the Company's common stock as of Dec. 31, 1995 and 1994, respectively. An average of 221,066 and 111,845 uncommitted leveraged ESOP shares were excluded from earnings-per-share calculations in 1995 and 1994, respectively. The fair value of NSP's leveraged ESOP shares approximated cost at Dec. 31, 1995.
401(k) NSP has a contributory, defined contribution Retirement Savings Plan, which complies with section 401(k) of the Internal Revenue Code and covers substantially all employees. Since 1994, NSP has been matching specified amounts of employee contributions to this plan. NSP's matching contributions were $3.7 million in 1995 and $2.6 million in 1994.
9. Income Taxes
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The reasons for the difference are as follows:
1995 1994 1993
Federal statutory rate 35.0 % 35.0 % 35.0 % Increases (decreases) in tax from: State income taxes, net of federal income tax benefit 5.1 % 5.9 % 6.1 % Tax credits recognized (3.4)% (3.5)% (2.8)% Equity income from unconsolidated international affiliates (2.5)% (2.5)% 0.0 % Regulatory differences - utility plant items 1.0 % 0.5 % 1.3 % Other---net 0.4 % (0.7)% (1.4)%
Effective income tax rate 35.6 % 34.7 % 38.2 %
(Thousands of dollars)
Income taxes are comprised of the following expense (benefit) items: Included in utility operating expenses: Current federal tax expense $137 011 $108 652 $92 099 Current state tax expense 33 359 34 823 25 787 Deferred federal tax expense (12 019) (3 450) 15 010 Deferred state tax expense (2 396) (1 606) 4 431 Deferred investment tax credits (8 807) (9 191) (8 981) Total 147 148 129 228 128 346 Included in other income (expense): Current federal tax expense 5 481 3 959 7 853 Current state tax expense 1 629 923 2 289 Current foreign tax expense 233 219 Current federal tax credits (5 292) (3 548) (321) Deferred federal tax expense 2 646 (835) (6 736) Deferred state tax expense 693 (209) (449) Deferred investment tax credits (310) (310) (242) Total 5 080 199 2 394
Total income tax expense $152 228 $129 427 $130 740
Income before income taxes includes net foreign equity income of $32.3 and $25.9 million in 1995 and 1994, respectively. NSP's management intends to reinvest the earnings of foreign operations indefinitely. Accordingly, U.S. income taxes and foreign withholding taxes have not been provided on the earnings of foreign subsidiary companies. The cumulative amount of undistributed earnings of foreign subsidiaries upon which no U.S. income taxes or foreign withholding taxes have been provided is approximately $61.6 million at Dec. 31, 1995. The additional U.S. income tax and foreign withholding tax on the unremitted foreign earnings, if repatriated, would be offset in whole or in part by foreign tax credits. Thus, it is impracticable to estimate the amount of tax that might be payable.
The components of NSP's net deferred tax liability (current and non-current portions) at Dec. 31 were:
(Thousands of dollars) 1995 1994
Deferred tax liabilities: Differences between book and tax bases of property $866 784 $843 872 Regulatory assets 124 910 120 329 Tax benefit transfer leases 59 579 76 775 Other 13 338 7 854 Total deferred tax liabilities $1 064 611 $1 048 830
Deferred tax assets: Regulatory liabilities $96 935 $80 383 Deferred investment tax credits 61 911 65 812 Deferred compensation, vacation and other accrued liabilities not currently deductible 57 209 50 572 Other 22 658 18 110 Total deferred tax assets $238 713 $214 877 Net deferred tax liability $825 898 $833 953
10. Regulatory Assets and Liabilities
The following summarizes the individual components of unamortized regulatory assets and liabilities shown on the Consolidated Balance Sheets at Dec. 31:
Amortization (Thousands of dollars) Period 1995 1994
AFC recorded in plant on a net-of-tax basis* Plant Lives $146 662 $155 102 Conservation and energy management programs* Up to 10 Years 98 570 76 902 Losses on reacquired debt Term of New Debt 63 209 52 514 Environmental costs Up to 15 Years 45 018 47 779 Deferred postretirement benefit costs 3-15 Years 5 568 9 930 Unrecovered purchased gas costs 1-2 Years 5 932 7 601 State commission accounting adjustments* Plant Lives 7 221 5 544 Other Various 2 032 2 204 Total regulatory assets $374 212 $357 576
Excess deferred income taxes collected from customers $83 066 $75 277 Investment tax credit deferrals 104 371 110 831 Unrealized gains from decommissioning investments 26 374 1 412 Pension costs 21 508 11 054 Fuel costs and other 7 468 1 943 Total regulatory liabilities $242 787 $200 517
* Earns a return on investment in the ratemaking process.
11. Financial Instruments
Fair Values The estimated Dec. 31 fair values of NSP's recorded financial instruments are as follows:
1995 1994 Carrying Fair Carrying Fair (Thousands of dollars) Amount Value Amount Value
Cash, cash equivalents and short-term investments $28 943 $28 943 $41 947 $41 947 Long-term decommissioning investments $203 625 $203 625 $145 467 $145 467 Long-term debt, including current portion $1 709 646 $1 781 066 $1 621 060 $1 540 595
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.
Derivatives NRG has entered into six forward foreign currency exchange contracts with counterparties to hedge exposure to currency fluctuations to the extent permissible by hedge accounting requirements. Pursuant to these contracts, transactions have been executed that are designed to protect the economic value in U.S. dollars of NRG's equity investments and retained earnings, denominated in Australian dollars and German deutsche marks (DM). NRG's forward foreign currency exchange contracts, in the notional amount of $119 million, hedge approximately $123 million of foreign currency denominated assets, and in the notional amount of $47 million, hedge approximately $64 million of foreign currency denominated retained earnings at Dec. 31, 1995. Because the effects of both currency translation adjustments to foreign investments and currency hedge instrument gains and losses are recorded on a net basis in stockholders' equity (not earnings), the impact of significant changes in currency exchange rates on these items would have an immaterial effect on NSP's financial condition and results of operations. The contracts required cash collateral balances of $5.9 million at Dec. 31, 1995, which are reflected as other current assets on NSP's balance sheet. The contracts terminate in 1998 through 2005 and require foreign currency interest payments by either party during each year of the contract. If the contracts had been terminated at Dec. 31, 1995, $5.2 million would have been payable by NRG for currency exchange rate changes to date. Management believes NRG's exposure to credit risk due to non- performance by the counterparties to its forward exchange contracts is not significant, based on the investment grade rating of the counterparties.
Cenergy has entered into natural gas futures contracts in the notional amount of $11.3 million at Dec. 31, 1995. The original contract terms range from one month to three years. The contracts are intended to mitigate risk from fluctuations in the price of natural gas that will be required to satisfy sales commitments for future deliveries to customers in excess of Cenergy's natural gas reserves. Cenergy's futures contracts hedge $11.5 million in anticipated natural gas sales in 1996-1997. Margin balances of $2.3 million at Dec. 31, 1995, were maintained on deposit with brokers and recorded as cash and cash equivalents on NSP's balance sheet. The counterparties to the futures contracts are the New York Mercantile Exchange and major gas pipeline operators. Management believes that the risk of non-performance by these counterparties is not significant. If the contracts had been terminated at Dec. 31, 1995, $0.6 million would have been payable to Cenergy for natural gas price fluctuations to date.
NSP has three interest rate swap agreements with notional amounts totalling $320 million. These swaps were entered into in conjunction with first mortgage bonds. As summarized below, these agreements effectively convert the interest costs of these debt issues from fixed to variable rates based on six-month London Interbank Offered Rates (LIBOR), with the rates changing semiannually. Net Effective Notional Amount Term of Interest Cost Series (millions of dollars) Swap Agreement at Dec. 31, 1995
5 7/8% Series due Oct. 1, 1997 $100 Maturity 5.94% 5 1/2% Series due Feb. 1, 1999 $200 Maturity 5.36% 7 1/4% Series due March 1, 2023 $ 20 March 1, 1998 8.03%
Market risks associated with these agreements result from short-term interest rate fluctuations. Credit risk related to non- performance of the counterparties is not deemed significant, but would result in NSP terminating the swap transaction and recognizing a gain or loss, depending on the fair market value of the swap. The interest rate swaps serve to hedge the interest rate risk associated with fixed rate debt in a declining interest rate environment. This hedge is produced by the tendency for changes in the fair market value of the swap to be offset by changes in the present value of the liability attributable to the fixed rate debt issued in conjunction with the interest rate swaps. If the interest rate swaps had been discontinued on Dec. 31, 1995, the present value benefit to NSP would have been $2.8 million, which is partially offset by an increase in the present value of the related debt of $0.9 million above carrying value.
Letters of Credit NSP uses letters of credit to provide financial guarantees for certain operating obligations, including NSP workers' compensation benefits and ash disposal site costs, and Cenergy natural gas purchases. At Dec. 31, 1995, letters of credit of $46.7 million were outstanding. Generally, the letters of credit have terms of one year and are automatically renewed, unless prior written notice of cancellation is provided to NSP and the beneficiary by the issuing bank. The contract amounts of these letters of credit approximate their fair value and are subject to fees competitively determined in the marketplace.
12. Detail of Certain Income and Expense Items
Administrative and general (A&G) expense for utility operations consists of the following:
(Thousands of dollars) 1995 1994 1993
A&G salaries and wages $48 437 $49 726 $51 601 Postretirement medical and injury compensation benefits 34 112 41 901 14 995 Other benefits---all utility employees 47 167 38 792 51 860 Information technology, facilities and administrative support 31 863 29 751 30 504 Insurance and claims 13 969 16 771 16 165 Other 10 599 11 055 11 492
Total $186 147 $187 996 $176 617
Other income (deductions)---net consist of the following:
(Thousands of dollars) 1995 1994 1993 Non-regulated operations: Operating revenues and sales $313 082 $241 827 $90 531 Operating expenses 327 894* 241 480* 81 480 Pretax operating income** (14 812) 347 9 051 Interest and investment income 11 953 10 839 4 522 Charitable contributions (5 314) (5 037) (4 752) Environmental and regulatory contingencies 1 027 (4 568) (100) Other---net (excluding income taxes) (829) (5 267) (739) Total---net income (expense) $ (7 975) $ (3 686) $ 7 982
*Includes non-regulated energy project write-downs of $5.0 million in 1995 and $5.0 million in 1994. **See Non-Regulated Subsidiaries-Non-Regulated Business Information under Item 1.
13. 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, 1995 and 1994, was $585,625,000 and $585,783,000, respectively. The corresponding accumulated provisions for depreciation were $150,022,000 and $132,092,000.
14. Nuclear Obligations
Fuel Disposal NSP is responsible for the temporary storage of used nuclear fuel from the Company's nuclear generating plants. Under a contract with the Company, the DOE is obligated to assume the responsibility for permanent storage or disposal of NSP's used nuclear fuel. The Company has been funding its portion of the DOE's permanent disposal program since 1981. Funding took place through an internal sinking fund until 1983, when the DOE began assessing fuel disposal fees under the Nuclear Waste Policy Act of 1982 based on a charge of 0.1 cent per kilowatt-hour sold to customers from nuclear generation. The cumulative amount of such assessments from the DOE to NSP through Dec. 31, 1995, is $230.8 million. Currently, it is not determinable if the amount and method of the DOE's assessments to all utilities will be sufficient to fully fund the DOE's permanent storage or disposal facility.
The DOE has stated in statute and by contract that a permanent storage or disposal facility would be ready to accept used nuclear fuel by 1998. Accordingly, NSP has been providing, with regulatory and legislative approval, its own temporary on-site storage facilities at its Monticello and Prairie Island nuclear plants, with a capacity sufficient for used fuel from the plants until at least that date. Recent indications from the DOE are that a permanent federal facility will not be ready to accept used fuel from utilities until approximately 2010. In 1994, the Company and 13 other major utilities filed a lawsuit against the DOE in an attempt to clarify the DOE's obligation to accept spent nuclear fuel beginning in 1998. The primary purpose of the lawsuit is to insure the Company and its customers receive timely storage of used nuclear fuel. The lawsuit was argued before the United States Circuit Court of Appeals for the District of Columbia on Jan. 17, 1996 and a decision is expected in three to six months from the time of argument. In 1995, the DOE published its "Final Interpretations of Nuclear Waste Acceptance Issues" in the Federal Register. In this notice, the DOE concluded that it has neither an unconditional obligation to accept spent nuclear fuel by 1998 nor any authority to provide interim storage. Because of the DOE's inadequate progress to provide a permanent repository and its disavowal of its obligation, the Minnesota Department of Public Service is investigating whether continued payments to fund the DOE's permanent disposal program is prudent use of ratepayer money. The outcome of this investigation is unknown at this time. In the meantime, NSP is investigating all of its alternatives for used fuel storage until a DOE facility is available. When on-site temporary storage at NSP's nuclear plants reaches approved capacity, the Company could seek interim storage at a contracted private facility. The Company received Minnesota legislative approval in 1994 for additional on-site storage facilities at its Prairie Island plant, provided the Company satisfies certain requirements. Seventeen dry cask containers, each of which can store approximately one-half year's used fuel, can become available as follows: five immediately in 1994; four more in 1996 if an application for an alternative storage site is filed, an effort to locate such a site is made and 100 megawatts of wind generation is available or contracted for construction; and the final eight in 1999, unless the specified alternative site is not operational or under construction, certain resource commitments are not met, or the Minnesota Legislature revokes its approval. (See additional discussion of legislative commitments in Note 15.) NSP has loaded used fuel into three of the dry cask containers as of Dec. 31, 1995. With the dry cask storage facilities approved in 1994 for the Prairie Island nuclear generating plant, the Company believes it has adequate storage capacity to continue operation of its nuclear plants until at least 2002 and 2003 for Prairie Island Units 1 and 2, respectively. The Monticello nuclear plant has storage capacity to continue operations until 2010. Storage availability to permit operation beyond these dates is not assured at this time.
Two alternatives to on-site storage of used fuel are currently under consideration. As discussed in Note 15, the Company is investigating alternative sites in Goodhue County, Minnesota, for interim used nuclear fuel storage. Also, the Company is leading a consortium working with the Mescalero Apache Tribe to establish a private facility for interim storage of used nuclear fuel on the Tribe's reservation in New Mexico. A core group of more than 20 United States nuclear utilities has agreed to support the construction and operation of the Mescalaro interim storage site. Work on the project is under way in several areas, including environmental assessment, facility design and drafting the detailed contracts that will govern the construction and operation of the site. An architect engineering firm and an environmental contractor have been retained to perform the environmental and licensing activities. The consortium is currently scheduled to submit a license application for the facility to the Nuclear Regulatory Commission (NRC) in December 1996. The spent fuel storage facility is expected to be operational and able to accept the first shipment of used nuclear fuel by mid-2002. However, due to pending regulatory and governmental approval uncertainty, it is possible that this interim storage may be delayed or not available.
Fuel expense includes DOE fuel disposal assessments of $12.3 million, $10.6 million and $8.7 million for 1995, 1994 and 1993, respectively. Disposal expenses reflect reductions of $0.7 million in 1994 and $2.6 million in 1993 due to a change in the DOE's basis of charging customers, retroactive to 1983. Nuclear fuel expenses in 1995, 1994 and 1993 also include about $5 million, $5 million and $1 million, respectively, for payments to the DOE for the decommissioning and decontamination of the DOE's uranium enrichment facilities. The DOE's initial assessment of $46 million to the Company was recorded in 1993. This assessment will be payable in annual installments from 1993-2008 and each installment is being amortized to expense on a monthly basis in the 12 months following each payment. The most recent installment paid in 1995 was $3.7 million; future installments are subject to inflation adjustments under DOE rules. The Company is obtaining rate recovery of these DOE assessments through the cost-of-energy adjustment clause as the assessments are amortized. Accordingly, the unamortized assessment of $44 million at Dec. 31, 1995, has been deferred as a regulatory asset and is reported under the caption Environmental Costs in Note 10.
Plant Decommissioning Decommissioning of all Company nuclear facilities is planned for the years 2010-2022, using the prompt dismantlement method. The Company is currently following industry practice by ratably accruing the costs for decommissioning over the approved cost recovery period and including the accruals in Utility Plant---Accumulated Depreciation, as discussed in Note 1. Consequently, the total decommissioning cost obligation and corresponding asset currently are not recorded in NSP's financial statements. The FASB has proposed new accounting standards which, if approved as expected in 1996, would require the full accrual of nuclear plant decommissioning and certain other site exit obligations beginning in 1997. If NSP were to adopt the proposed accounting, beginning in 1997 an estimated total discounted decommissioning obligation of $610 million would be recorded as a liability, with the corresponding costs capitalized as a plant asset and depreciated over the operating life of the plant. The obligation calculation methodology proposed by the FASB is slightly different from the ratemaking methodology that derives the decommissioning accruals currently being recovered in rates (as discussed below). The Company has not yet determined the potential impact of the FASB's proposed changes in the accounting for site exit obligations other than nuclear decommissioning (such as costs of removal). However, the ultimate decommissioning and site exit costs to be accrued are the same under both methods and, accordingly, the effects of regulation are expected to minimize or eliminate any impact on operating expenses and results of operations from this future accounting change.
Consistent with cost recovery in utility customer rates, the Company records annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. Since the costs are expected to be paid in 2010-2022, funding presumes that current costs will escalate in the future at a rate of 4.5 percent per year. The total estimated decommissioning costs that will ultimately be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved plant recovery period. This annuity approach uses the assumed rate of return on funding, which is currently 6 percent (net of tax) for external funding and approximately 8 percent (net of tax) for internal funding.
The total obligation for decommissioning currently is expected to be funded approximately 82 percent by external funds and 18 percent by internal funds, as approved by the MPUC. Rate recovery of internal funding began in 1971 through depreciation rates for removal expense, and was changed to a sinking fund recovery in 1981. Contributions to the external fund started in 1990 and are expected to continue until plant decommissioning begins. Costs not funded by external trust contributions and related earnings will be funded through internally generated funds and issuance of Company debt or stock. The assets held in trusts as of Dec. 31, 1995, primarily consisted of investments in tax-exempt municipal bonds, common stock of public companies and U.S. government securities.
The following table summarizes the funded status of the decommissioning obligation at Dec. 31, 1995, under the method currently in use.
(Millions of dollars) 1995
Decommissioning cost estimate from most recent study (1993 dollars) $750.8 Effect of escalating costs to payment date (at 4.5% per year) 1 094.0 Estimated future decommissioning costs (undiscounted) $1 844.8 Estimated decommissioning cost obligation escalated to current dollars $ 819.9 External trust fund assets at fair value 203.6 Decommissioning obligation in excess of assets currently held in external trust $ 616.3
Decommissioning expenses recognized include the following components:
(Millions of dollars) 1995 1994 1993
Annual decommissioning cost accrual reported as depreciation expense: Externally funded $33.2 $33.2 $28.4 Internally funded (including interest costs) 1.2 1.1 14.5 Interest cost on externally funded decommissioning obligation 6.0 3.5 3.7 Earnings from external trust funds---net (6.0) (3.5) (3.7) Current year decommissioning accruals---net $34.4 $34.3 $42.9
At Dec. 31, 1995, the Company has recorded and recovered in rates cumulative decommissioning accruals of $381 million; $177 million has been deposited into external trust funds for such accruals. The Company believes future decommissioning cost accruals will continue to be recovered in customer rates. Decommissioning and interest accruals are included with the accumulated provision for depreciation on the balance sheet. Interest costs and trust earnings associated with externally funded obligations are reported in Other Income and Expense on the income statement.
A revision to NSP's 1993 nuclear decommissioning study and nuclear plant depreciation capital recovery request was filed with the MPUC and approved in 1994. Although management expects to operate the Prairie Island units through the end of their licensed lives, the approved capital recovery would allow for the plant to be fully depreciated, including the accrual and recovery of decommissioning costs in 2008, about six years earlier than the end of its licensed life. The approved recovery period for Prairie Island has been reduced because of the uncertainty regarding used fuel storage. The updated nuclear decommissioning study resulted in a decrease in annual cost accruals for decommissioning due to a reduction in decommissioning cost estimates as well as the shortened recovery period. The combined impact of the request as approved, including the shorter depreciation period and lower decommissioning costs, was a net decrease of about $800,000 in annual depreciation and decommissioning expenses, beginning in 1994.
15. Commitments and Contingent Liabilities
Legislative Resource Commitments In 1994, the Minnesota Legislature established several energy resource and other commitments for NSP to fulfill to obtain the Prairie Island temporary nuclear fuel storage facility approval, as discussed in Note 14. The additional resource commitments, which can be built, purchased or (in the case of biomass generation) converted, can be summarized as follows:
Power Type Megawatts Deadline
Wind 100 (1) (Additional) 12/31/96 (3) Wind 225 (Cumulative) 12/31/98 (4) Biomass 50 (Additional) 12/31/98 (5) Wind 200 (Additional) 12/31/02 Biomass 75 (Additional) 12/31/02 Wind 400 (2) (Additional) 12/31/02
(1) In addition to 25 megawatts of wind generation currently installed (2) If required by least-cost planning and resource planning (3) Power purchase contract awarded to Zond Systems, Inc. (4) Power purchase bids to be received mid-1996 (5) Power purchase bid decision expected in March 1996
The Company has taken steps to comply with the requirements of these resource commitments. Twenty-five megawatts of third party wind generation has been fully operational since May 1, 1994. With respect to the additional 100 megawatts of wind energy to be under contract by the end of 1996, the Company has obtained a site designation from the Minnesota Environmental Quality Board (MEQB), and selected Zond Systems, Inc. to supply the wind energy. The Company must now secure wind rights for the site from an unsuccessful bidder, which has indicated it will not voluntarily transfer the wind rights. The Company has commenced litigation to expedite resolution of the wind rights dispute. Siting and design activities are proceeding while wind rights acquisition efforts continue. An independent evaluator also reviewed proposals from bidders regarding 50 megawatts of farm-grown closed-loop biomass generation and made a recommendation to the Company in January 1996, with a final decision to be made in early 1996. On Jan. 22, 1996, the Company notified the MPUC that due to the price of the various bids and other factors, the Company intended to reject each of the bids. Since legislation may be proposed to change various elements of the biomass mandate, the Company proposed to delay its report detailing the Company's decision and its proposal to meet the statutory mandate until later in 1996.
Other commitments established by the Legislature include applying for, locating and licensing an alternative used fuel storage site, a low-income discount for electric customers, additional required conservation improvement expenditures and various study and reporting requirements to a legislative electric energy task force formed in 1994. In January 1995, the MPUC approved the Company's low-income discount programs in accordance with the statute. In July 1995, the Company filed documents with the MEQB outlining two alternative Goodhue County sites to be considered for the development of an interim used nuclear fuel storage facility, as the Minnesota Legislature required. The MEQB has begun a 12- to 18-month public process to examine these sites and any others that may be proposed. The Company has implemented programs to begin meeting the other legislative commitments. The Company's capital commitments disclosed below include the known effects of the 1994 Prairie Island legislation. The impact of the legislation on power purchase commitments and other operating expenses is not yet determinable.
Capital Commitments NSP estimates utility capital expenditures, including acquisitions of nuclear fuel, will be $410 million in 1996 and $1.9 billion for 1996-2000. There also are contractual commitments for the disposal of used nuclear fuel. (See Note 14.)
NRG is contractually committed to additional equity investments in an existing German energy project. Such commitments are for approximately DM 33 million in 1996. The 1996 commitment would be approximately $23 million, based on exchange rates in effect at Dec. 31, 1995. In addition, NRG is contractually committed to additional equity investments of $17 million in the Scudder Latin American Trust for Independent Power Energy Projects, as of Dec. 31, 1995.
NRG is in the final stages of purchasing a 42 percent interest in O'Brien Environmental Energy, Inc. (O'Brien) from bankruptcy. In connection with its bid for O'Brien, on Jan. 3, 1996, NRG obtained a $100 million letter of credit from a bank, which is secured by a pledge of various NRG assets. NRG delivered the letter of credit to O'Brien on Jan. 18, 1996, to secure its obligation to complete its proposed investment in O'Brien. In January 1996, the United States Bankruptcy Court for the District of New Jersey confirmed the Chapter 11 Plan of Reorganization for O'Brien proposed by NRG and other interested parties. O'Brien has interests in eight domestic operating power generation facilities with aggregate capacity of approximately 230 megawatts, and in one 150-megawatt facility in the contract stage of development. As a result of the purchase, approximately $107 million would be made available to O'Brien's creditors by NRG. At least $81 million of the total made available to the creditors would be provided by NRG as follows: (i) a $28 million equity investment by NRG for its 42 percent interest in O'Brien; (ii) a $7.5 million investment by NRG for all of O'Brien's interest in certain biogas projects; and (iii) a $45 million unsecured loan from NRG to O'Brien. NRG currently is negotiating with an unaffiliated lender to refinance O'Brien's Newark Boxboard project in the amount of $56 million, of which approximately $26 million would be applied for distribution to O'Brien's creditors in reduction of NRG's approximately $107 million obligation. If this financing is not obtained concurrently with the closing of the O'Brien transaction, NRG would be obligated to make a $26 million loan to O'Brien after its reorganization.
Leases Rentals under operating leases were approximately $26.9 million, $24.0 million and $27.5 million for 1995, 1994 and 1993, respectively. Future commitments under these leases generally decline from current levels.
Fuel Contracts NSP has contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements. These contracts, which expire in various years between 1996 and 2013, require minimum contractual purchases and deliveries of fuel, and additional payments for the rights to purchase coal in the future. In total, NSP is committed to the minimum purchase of approximately $529 million of coal, $26 million of nuclear fuel and $512 million of natural gas and related transportation, or to make payments in lieu thereof, under these contracts. In addition, NSP is required to pay additional amounts depending on actual quantities shipped under these agreements. As a result of FERC Order 636, NSP has been very active in developing a mix of gas supply, transportation and storage contracts designed to meet its needs for retail gas sales. The contracts are with several suppliers and for various periods of time. Because NSP has other sources of fuel available and suppliers are expected to continue to provide reliable fuel supplies, risk of loss from non- performance under these contracts is not considered significant. In addition, NSP's risk of loss (in the form of increased costs) from market price changes in fuel is mitigated through the cost-of- energy adjustment provision of the ratemaking process, which provides for recovery of nearly all fuel costs.
Power Agreements The Company has executed several agreements with the Manitoba Hydro-Electric Board (MH) for hydroelectricity. A summary of the agreements is as follows:
Years Megawatts
Participation Power Purchase 1996-2005 500 Seasonal Participation Power Purchase 1996 250 Seasonal Peaking Power Purchase 1996 200 Seasonal Diversity Exchanges: Summer exchanges from MH 1996-2014 150 1997-2016 200 Winter exchanges to MH 1996-2014 150 1996-2015 200 2015-2017 400
2018 200
The cost of the 500-megawatt participation power purchase commitment is based on 80 percent of the costs of owning and operating the Company's Sherco 3 generating plant (adjusted to 1993 dollars). The total estimated future annual capacity costs for all MH agreements is projected to be approximately $65 million. However, the Company and MH have consented to arbitration to finalize interpretations of specific contractual factors relating to the 500-megawatt participation agreement. These commitments to MH, which represent about 22 percent of MH's output capability in 1996, account for approximately 13 percent of NSP's 1996 electric 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 has an agreement with Minnkota Power Cooperative (MPC) for the purchase of summer season capacity and energy. From 1996 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. Under the agreement, energy will be priced against the cost of fuel consumed per megawatt-hour at the Coyote Generating Station in North Dakota. The Company also has three seasonal (summer) purchase power agreements with MPC, Minnesota Power and Mid American Energy Company for the purchase of 388 megawatts in 1996, including reserves. The annual cost of this capacity will be approximately $4 million.
The Company has agreements with several non-regulated power producers to purchase electric capacity and associated energy. The 1996 cost of these commitments for non-regulated installed capacity is approximately $20 million for 115 megawatts. This annual cost will increase to approximately $37 million-$44 million for 1997- 2018 and then decrease to approximately $25 million-$29 million for 2019-2027 due to the expiration of existing agreements and an additional agreement for the purchase of 245 to 262 megawatts.
Nuclear Insurance The Company's public liability for claims resulting from any nuclear incident is limited to $8.9 billion under the 1988 Price-Anderson amendment to the Atomic Energy Act of 1954. The Company has secured $200 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $8.7 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. The Company is subject to assessments of up to $79.3 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 site decontamination cleanup costs with coverage limits of $2.0 billion for each of the Company's two nuclear plant sites. The coverage consists of $500 million from Nuclear Mutual Limited (NML) and $1.5 billion from Nuclear Electric Insurance Limited (NEIL).
NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums billed to NSP from NML and NEIL are expensed over the policy term. All companies insured with NML and NEIL are subject to retrospective premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NML and NEIL to the extent that the Company would have no exposure for retrospective premium assessments in case of a single incident under the business interruption and the property damage insurance coverages. However, in each calendar year, the Company could be subject to maximum assessments of approximately $4.9 million (five times the amount of its annual premium) and $36.8 million (generally 7.5 times the amount of its annual premium) if losses exceed accumulated reserve funds under the business interruption and property damage coverages, respectively.
Environmental Contingencies Other long-term liabilities include an accrual of $42 million, and other current liabilities include an accrual of $6 million at Dec. 31, 1995, for estimated costs associated with environmental remediation. Approximately $37 million of the long-term liability and $4 million of the current liability relate to a DOE assessment for decommissioning of a federal uranium enrichment facility, as discussed in Note 14. Other estimates have been recorded for expected environmental costs associated with manufactured gas plant sites formerly used by the Company and other waste disposal sites, as discussed below.
These environmental liabilities do not include accruals recorded (and collected from customers in rates) for future nuclear fuel disposal costs or decommissioning costs related to the Company's nuclear generating plants. (See Note 14 for further discussion.)
The Environmental Protection Agency (EPA) or state environmental agencies have designated the Company as a "potentially responsible party" (PRP) for 12 waste disposal sites to which the Company allegedly sent hazardous materials. Under applicable law, the Company, along with each PRP, could be held jointly and severally liable for the total remediation costs of all 12 sites, which are currently estimated between $123 million and $126 million. If additional remediation is necessary or unexpected costs are incurred, the amount could be in excess of $126 million. The Company is not aware of the other parties' inability to pay, nor does it know if responsibility for any of the sites is disputed by any party. The Company's share of the costs associated with these 12 sites is approximately $2.5 million. Of this amount, about $1.5 million already has been paid in connection with eight of the 12 sites for which the Company has settled with the EPA and other PRPs. For the remaining four sites, neither the amount of remediation costs nor the final method of their allocation among all designated PRPs has been determined. However, the Company has recorded an estimate of approximately $1 million for future costs for all four sites, with the estimated payment dates not determinable at this time. While it is not feasible to determine the outcome of these matters, amounts accrued represent the best current estimate of the Company's future liability for the remediation costs of these sites. It is the Company's practice to vigorously pursue and, if necessary, litigate with insurers to recover incurred remediation costs whenever possible. Through litigation, the Company has recovered from other PRPs a portion of the remediation costs paid to date. Management believes costs incurred in connection with the sites, which are not recovered from insurance carriers or other parties, should be allowed recovery in future ratemaking. Until the Company is identified as a PRP, it is not possible for the Company to predict the timing or amount of any costs associated with cleanup sites other than those discussed above.
The Wisconsin Company potentially may be involved in the cleanup and remediation at three sites. One site is a solid and hazardous waste landfill site in Eau Claire, Wis. The Wisconsin Company contends that it did not dispose of hazardous wastes in the subject landfill during the time period in question. Because neither the amount of cleanup costs nor the final method of their allocation among all designated PRPs has been determined, it is not feasible to predict the outcome of this matter at this time. The second site, in Ashland, Wis., contains creosote/coal tar contamination. In 1995, the Wisconsin Department of Natural Resources (WDNR) notified the Wisconsin Company that it is a PRP at this site. At this time, the WDNR has determined that the Wisconsin Company is the only PRP at this site. The site has three distinct portions - the Wisconsin Company portion of the site, the Kreher Park portion of the site and the Chequamegon Bay (of Lake Superior) portion of the site. The Wisconsin Company portion of the site, formerly a coal gas plant site, is Wisconsin Company property. The Kreher Park portion of the site is adjacent to the Wisconsin Company site and is not owned by the Wisconsin Company. The Chequamegon Bay portion of the site is adjacent to the Kreher Park portion of the site and is not owned by the Wisconsin Company. The Wisconsin Company is discussing its potential involvement in the Kreher Park and Chequamegon Bay portions of the site with the WDNR and the City of Ashland. At Dec. 31, 1995, the Wisconsin Company had recorded an estimated liability of $900,000 for future remediation costs at the Ashland site and had incurred approximately $400,000 in actual expenditures. Investigations are under way to determine the Wisconsin Company's responsibility as well as that of predecessor companies contributing to the contamination existing at the Ashland site. The investigation also should determine the extent and source of the contamination and potential methods for remediation. (See subsequent event section below.) An estimate of cleanup and remediation costs at the Eau Claire site and any further costs at the Ashland site and the extent of the Wisconsin Company's responsibility, if any, for sharing such costs are not known at this time. The third site is a landfill site in Hudson, Wis., which is one of the 12 waste disposal sites discussed previously.
The Company also is continuing to investigate 15 properties, either presently or previously owned by the Company, which were at one time sites of gas manufacturing, gas storage plants or gas pipelines. The purpose of this investigation is to determine if waste materials are present, if such materials constitute an environmental or health risk, if the Company has any responsibility for remedial action and if recovery under the Company's insurance policies can contribute to any remediation costs. Of the 15 gas sites under investigation, the Company already has remediated one site and is actively taking remedial action at four of the sites. In addition, the Company has been notified that two other sites eventually will require remediation, and a study will be initiated in 1996 to determine the cost and method of cleanup. Cleanup is expected to begin in 1997. The Company has paid $6.7 million to date on these seven active sites. The one remediated site continues to be monitored. The Company has recorded an estimated liability for future costs at the other six active sites of approximately $6.1 million, with payment expected over the next 10 years. This estimate is based on prior experience and includes investigation, remediation and litigation costs. As for the eight inactive sites, no liability has been recorded for remediation or investigation because the present land use at each of these sites does not warrant a response action. While it is not feasible to determine the precise outcome of all of these matters, the accruals recorded represent the current best estimate of the costs of any required cleanup or remedial actions at these former gas operating sites. Management also believes that incurred costs, which are not recovered from insurance carriers or other parties, should be allowed recovery in future ratemaking. During 1994, the Company's gas utility received approval for deferred accounting for certain gas remediation costs incurred at four active sites, with final rate treatment of such costs to be determined in future general gas rate cases.
The Clean Air Act, including the Amendments of 1990 (the Clean Air Act), calls for reductions in emissions of sulfur dioxide and nitrogen oxides from electric generating plants. These reductions, which will be phased in, began in 1995. The majority of the rules implementing this complex legislation have been finalized. No additional capital expenditures are anticipated to comply with the sulfur dioxide emission limits of the Clean Air Act. NSP has expended significant amounts over the years to reduce sulfur dioxide emissions at its plants. Based on revisions to the sulfur dioxide portion of the program, NSP's emission allowance allocations for the years 1995-1999 were dramatically reduced. The Company's capital expenditures include some costs for ensuring compliance with the Clean Air Act's other emission requirements; other expenditures may be necessary upon EPA's finalization of remaining rules. Because NSP is only beginning to implement some provisions of the Clean Air Act, its overall financial impact is unknown at this time. Capital expenditures for opacity compliance, which began in 1995 at certain facilities, are considered in the capital expenditure commitments disclosed previously. NSP plans to seek recovery of these expenditures in future rate proceedings.
Several of NSP's operating facilities have asbestos-containing material, which represents a potential health hazard to people who come in contact with it. Governmental regulations specify the required timing and nature of disposal of asbestos-containing materials. Under such requirements, asbestos not readily accessible to the environment need not be removed until the facilities containing the material are demolished. NSP estimates its future asbestos removal costs will approximate $43 million. Most of these costs will not need to be incurred until current operating facilities are demolished, and will be included in the costs of removal for the facilities.
Environmental liabilities are subject to considerable uncertainties that affect NSP's ability to estimate its share of the ultimate costs of remediation and pollution control efforts. Such uncertainties involve the nature and extent of site contamination, the extent of required cleanup efforts, varying costs of alternative cleanup methods and pollution control technologies, changes in environmental remediation and pollution control requirements, the potential effect of technological improvements, the number and financial strength of other potentially responsible parties at multi-party sites and the identification of new environmental cleanup sites. NSP has recorded and/or disclosed its best estimate of expected future environmental costs and obligations, as discussed previously.
Legal Claims In the normal course of business, NSP is a party to routine claims and litigation arising from prior and current operations. NSP is actively defending these matters and has recorded an estimate of the probable cost of settlement or other disposition. In July 1993, a natural gas explosion occurred on the Company's distribution system in St. Paul, Minn. Total damages are estimated to exceed $1 million. The Company has a self-insured retention deductible of $1 million, with general liability coverage of $150 million, which includes coverage for all injuries and damages. Seventeen lawsuits have been filed, including one suit with multiple plaintiffs. In April 1995, the National Transportation Safety Board found little, if any, fault with the Company's actions or conduct. A trial to decide civil liability and the parties responsible for the explosion has been scheduled for February 1997, with the damages portion of the trial scheduled for six months thereafter. The ultimate costs to the Company are unknown at this time.
Subsequent Event (Unaudited) On Feb. 19, 1996, the Wisconsin Company received from the WDNR's consultant a draft report of the results of a remediation action options feasibility study for the Kreher Park portion of the Ashland site discussed previously. The draft report contains a number of remediation options which were scored by the consultant across a variety of parameters. Two options scored the most technologically and economically feasible and one of those is the lowest cost option for remediation at the Kreher Park portion of the site. The draft report estimates that this option, which would involve capping the property and some limited groundwater treatment, would cost approximately $6.0 million. Currently, the WDNR is conducting an investigation in Chequamegon Bay adjacent to Kreher Park to determine the extent of contamination in the bay. The WDNR has informed the Wisconsin Company that it will not choose or proceed with any remediation options on any portion of the Ashland site until completion of the Chequamegon Bay investigation in the second half of 1996. Until more information is known concerning the extent of remediation required by the WDNR, the remediation method selected and the related costs, the various parties involved and the extent of the Wisconsin Company's responsibility, if any, for sharing the costs, the ultimate cost to the Wisconsin Company and the expected timing of any payments related to the Ashland site is not determinable.
16. Segment Information
Year Ended Dec. 31 (Thousands of dollars) 1995 1994 1993
Utility operating income before income taxes Electric $444 687 $399 185 $393 758 Gas 48 340 38 361 38 474 Total operating income before income taxes $493 027 $437 546 $432 232
Utility depreciation and amortization Electric $266 231 $252 322 $245 200 Gas 23 953 21 479 19 317 Total depreciation and amortization $290 184 $273 801 $264 517
Utility capital expenditures Electric utility $317 750 $303 896 $284 239 Gas utility 37 215 60 183 36 312 Common utility 31 057 22 947 36 285 Total utility capital expenditures $386 022 $387 026 $356 836
Identifiable assets Electric utility $4 751 650 $4 634 511 $4 543 286 Gas utility 600 738 556 975 521 595 Total identifiable assets 5 352 388 5 191 486 5 064 881 Other corporate assets * 876 197 758 246 522 837 Total assets $6 228 585 $5 949 732 $5 587 718
* Includes equity investments of $185 million in 1995 and $134 million in 1994 in non-regulated energy projects outside of the United States.
* An expense of $8.7 million ($5.1 million net of tax), or 8 cents per share, was recognized to write off the unamortized deferred costs associated with adopting SFAS No. 112 (See Note 2.) Such costs had initially been deferred based on a preliminary decision to request amortization through rates over future periods.
18. Merger Agreement with Wisconsin Energy Corporation
As previously reported in the Company's Current Report on Form 8-K, dated April 28, 1995, and filed on May 3, 1995, and Quarterly Reports on Form 10-Q, the Company and Wisconsin Energy Corporation (WEC) have entered into an Agreement and Plan of Merger (Merger Agreement), which provides for a strategic business combination involving the Company and WEC in a "merger-of-equals" transaction (the Transaction). See further discussion of the transaction in the Management's Discussion and Analysis, Factors Affecting Results of Operations-Proposed Merger section.
Primergy Corporation (Primergy), which will be registered under the Public Utility Holding Company Act of 1935, as amended, will be the parent company of both the Company (which, for regulatory reasons, will reincorporate in Wisconsin) and WEC's current principal utility subsidiary, Wisconsin Electric Power Company, which will be renamed "Wisconsin Energy Company." It is anticipated that, following the Transaction, except for certain gas distribution properties transferred to the Company, the Wisconsin Company will be merged into Wisconsin Energy Company and that some of the Company's other subsidiaries will become direct Primergy subsidiaries.
As noted above, pursuant to the Transaction, NSP will reincorporate in Wisconsin. This reincorporation will be accomplished by the merger of the Company into a new company, Northern Power Wisconsin Corporation (New NSP), with New NSP being the surviving corporation and succeeding to the business of the Company as an operating public utility. Following such merger, a new WEC subsidiary, WEC Sub Corporation (WEC Sub), will be merged with and into New NSP, with New NSP being the surviving corporation and becoming a subsidiary of Primergy. Both New NSP and WEC Sub were created to effect the Transaction and will not have any significant operations, assets or liabilities prior to such mergers. After the Transaction is completed, current common stockholders of the Company will own shares of Primergy common stock, and current bondholders and preferred stockholders of the Company will become investors in New NSP.
SUMMARIZED PRO FORMA FINANCIAL INFORMATION (UNAUDITED)
The following summary of unaudited pro forma financial information reflects the adjustment of the historical consolidated balance sheets and statements of income of NSP and WEC to give effect to the Transaction to form Primergy and a new subsidiary structure. The unaudited pro forma balance sheet information gives effect to the Transaction as if it had occurred on Dec. 31, 1995. The unaudited pro forma income statement information gives effect to the Transaction as if it had occurred on Jan. 1, 1995. This pro forma information was prepared from the historical consolidated financial statements of NSP and WEC on the basis of accounting for the Transaction as a pooling of interests and should be read in conjunction with such historical consolidated financial statements and related notes thereto of NSP and WEC. The following information is not necessarily indicative of the financial position or operating results that would have occurred had the Transaction been consummated on the dates, for which the Transaction is being given effect, nor is it necessarily indicative of future Primergy operating results or financial position.
Primergy Information The following summarized Primergy pro forma financial information reflects the combination of the historical financial statements of NSP and WEC after giving effect to the Transaction to form Primergy. A $141 million pro forma adjustment has been made to conform the presentations of noncurrent deferred income taxes in the summarized pro forma combined balance sheet information as a net liability. The pro forma combined earnings per common share reflect pro forma adjustments to average common shares outstanding in accordance with the stock conversion provisions of the Merger Agreement.
Pro Forma Primergy Pro Forma Financial Information NSP WEC Combined (Millions of dollars, except per share amounts)
As of Dec. 31, 1995: Utility Plant---Net $4 310 $2 911 $7 221 Current Assets 705 531 1 236 Other Assets 1 214 1 119 2 192 Total Assets $6 229 $4 561 $10 649
Common Stockholders' Equity $2 028 $1 871 $3 899 Preferred Stockholders' Equity 240 30 270 Long-Term Debt 1 542 1 368 2 910 Total Capitalization 3 810 3 269 7 079 Current Liabilities 992 436 1 428 Other Liabilities 1 427 856 2 142 Total Equity & Liabilities $6 229 $4 561 $10 649
For the Year Ended Dec. 31, 1995: Utility Operating Revenues $2 569 $1 770 $4 339 Utility Operating Income $346 $329 $675 Net Income, after Preferred Dividend Requirements $263 $234 $497 Earnings per Common Share: As reported $3.91 $2.13 Using NSP Equivalent Shares* $3.69 Using Primergy Shares $2.27
* Represents the pro forma equivalent of one share of NSP Common Stock calculated by multiplying the pro forma information by the conversion ratio of 1.626 shares of Primergy Common Stock for each share of NSP Common Stock.
New NSP Information The following summarized New NSP pro forma financial information reflects the adjustment of the historical financial statements of NSP to give effect to the Transaction, including the merger of the Wisconsin Company into Wisconsin Energy Company and the transfer of ownership of all of the other current NSP subsidiaries to Primergy. The transfer of certain Wisconsin Company gas distribution properties to New NSP, which is anticipated as part of the merger, has not been reflected in the pro forma amounts due to immateriality.
Merger Divestitures, Pro Forma New NSP Pro Forma Financial Information NSP Net New NSP (Millions of dollars)
As of Dec. 31, 1995: Utility Plant---Net $4 310 ($692) $3 618 Current Assets 705 (170) 535 Other Assets 1 214 (531) 683 Total Assets $6 229 ($1 393) $4 836
Common Stockholders' Equity $2 028 ($706) $1 322 Preferred Stockholders' Equity 240 240 Long-Term Debt 1 542 (356) 1 186 Total Capitalization 3 810 (1 062) 2 748 Current Liabilities 992 (139) 853 Other Liabilities 1 427 (192) 1 235 Total Equity & Liabilities $6 229 ($1 393) $4 836
For the Year Ended Dec. 31, 1995: Utility Operating Revenues $2 569 ($213) $2 356 Utility Operating Income $346 ($62) $284 Net Income, after Preferred Dividend Requirements $263 ($73) $190
Item 9
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
During 1995 there were no disagreements with the Company's independent public accountants on accounting procedures or accounting and financial disclosures. As discussed in the Company's Current Report on Form 8-K filed Dec. 16, 1994, on Dec. 14, 1994, the Company's Board of Directors approved the appointment of the accounting firm of Price Waterhouse LLP as independent accountants for the Registrant beginning in fiscal year 1995, subject to ratification by the shareholders. On Sept. 13, 1995, the Company's shareholders ratified the appointment of Price Waterhouse LLP as the Company's independent accountants for 1995.
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 1996 Proxy Statement for its Annual Meeting of Shareholders to be held April 24, 1996, on pages 3 through 6 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 1996 Proxy Statement for its Annual Meeting of Shareholders to be held April 24, 1996, on pages 7 through 17 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 1996 Proxy Statement for its Annual Meeting of Shareholders to be held April 24, 1996, on page 6 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 1996 Proxy Statement for its Annual Meeting of Shareholders to be held April 24, 1996, on pages 3 through 4 under the captions "Class I - Nominees for Terms expiring in 1999," "Class II - Nominee for Term expiring in 1997," "Class II - - Directors Whose Terms Expire in 1997," "Class III - Directors Whose Terms Expire in 1998," which is incorporated herein by reference.
PART IV Item 14
Item 14 - Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) 2. Financial Statement Schedules
Schedules are omitted because of the absence of the conditions under which they are required or because the information required is included in the financial statements or the notes.
(a) 3. Exhibits
* Indicates incorporation by reference
2.01* Amended and Restated Agreement and Plan of Merger, dated as of April 28, 1995, as amended and restated as of July 26, 1995, by and among Northern States Power Company, Wisconsin Energy Corporation, Northern Power Wisconsin Corp. and WEC Sub. Corp. (Exhibit (2)-1 to Northern Power Wisconsin Corp.'s Registration Statement on Form S-4 filed on Aug. 7, 1995, File No. 33- 61619-01).
2.02* WEC Stock Option Agreement, dated as of April 28, 1995, by and among Northern States Power Company and Wisconsin Energy Corporation (Exhibit (2)-2 to Form 8-K dated April 28, 1995, File No. 1- 3034).
2.03* NSP Stock Option Agreement, dated as of April 28, 1995, by and among Wisconsin Energy Corporation and Northern States Power Company (Exhibit (2)-3 to Form 8-K dated April 28, 1995, File No. 1-3034).
2.04* Committees of the Board of Directors of Primergy Corporation, Exhibit 7.13 to the Agreement and Plan of Merger (Exhibit (2)-4 to Form 8-K dated April 28, 1995, File No. 1-3034).
2.05* Form of Employment Agreement of James J. Howard, Exhibit 7.15.1 to the Agreement and Plan of Merger (Exhibit (2)-5 to Form 8-K dated April 28, 1995, File No. 1-3034).
2.06* Form of Employment Agreement with Richard A. Abdoo, Exhibit 7.15.2 to the Agreement and Plan of Merger (Exhibit (2)-6 to Form 8-K dated April 28, 1995, File No. 1-3034).
2.07* Form of Amended and Restated Articles of Incorporation of Northern Power Wisconsin Corp., Exhibit 7.20 (b) to the Agreement and Plan of Merger (Exhibit (2)-7 to Form 8-K dated April 28, 1995, File No. 1-3034).
2.08* Form of NSP Senior Executive Severance Policy, Exhibit 7.10 (a) to the Amended and Restated Agreement and Plan of Merger, dated as of April 28, 1995, as amended and restated as of July 26, 1995, by and among Northern States Power Company, Wisconsin Energy Corporation, Northern Power Wisconsin Corp. and WEC Sub. Corp. (Exhibit (2) - 1 to Northern Power Wisconsin Corp.'s Registration on Form S-4 filed Aug. 7, 1995, File No. 33-61619-01).
3.01* Restated Articles of Incorporation of the Company and Amendments, effective as of April 2, 1992. (Exhibit 3.01 to Form 10-Q for the quarter ended March 31, 1992, File No. 1-3034).
3.02* Bylaws of the Company as amended Jan. 22, 1992. (Exhibit 3.02 to Form 10-K for the year 1991, File No. 1-3034).
4.01* Trust Indenture, dated Feb. 1, 1937, from the Company to Harris Trust and Savings Bank, as Trustee. (Exhibit B-7 to File No. 2-5290).
4.02* Supplemental and Restated Trust Indenture, dated May 1, 1988, from the Company to Harris Trust and Savings Bank, as Trustee. (Exhibit 4.02 to Form 10-K for the year 1988, File No. 1-3034).
Supplemental Indenture between the Company and said Trustee, supplemental to Exhibit 4.01, dated as follows:
4.03* 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 Oct. 13, 1992, File No. 1-3034).
4.42* April 1, 1993 (Exhibit 4.01 to Form 8-K dated March 30, 1993, File No. 1-3034).
4.43* Dec. 1, 1993 (Exhibit 4.01 to Form 8-K dated Dec. 7, 1993, File No. 1-3034).
4.44* Feb. 1, 1994 (Exhibit 4.01 to Form 8-K dated Feb. 10, 1994, File No. 1-3034).
4.45* Oct. 1, 1994 (Exhibit 4.01 to Form 8-K dated Oct. 5, 1994, File No. 1-3034).
4.46* Jun. 1, 1995 (Exhibit 4.01 to Form 8-K dated June 28, 1995, File No. 1-3034).
4.47* 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:
4.48* Mar. 1, 1949 (Exhibit 7.02 to File No. 2-7825).
4.49* Jun. 1, 1957 (Exhibit 2.13 to File No. 2-13463).
4.50* Aug. 1, 1964 (Exhibit 4.20 to File No. 2-23726).
4.51* Dec. 1, 1969 (Exhibit 2.03E to File No. 2-36693).
4.52* Sep. 1, 1973 (Exhibit 2.01F to File No. 2-48805).
4.53* Feb. 1, 1982 (Exhibit 4.01G to File No. 2-76146).
4.54* Mar. 1, 1982 (Exhibit 4.39 to Form 10-K for the year 1982, File No. 10-3140).
4.55* Jun. 1, 1986 (Exhibit 4.01I to File No. 33-6269).
4.56* Mar. 1, 1988 (Exhibit 4.01J to File No. 33-20415).
4.57* 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)
4.58* Apr. 1, 1991 (Exhibit 4.01L to File No. 33-39831).
4.59* Mar. 1, 1993 (Exhibit 4.01 to Form 8-K dated March 4, 1993, File No. 10-3140).
4.60* Oct. 1, 1993 (Exhibit 4.01 to Form 8-K dated September 21, 1993, File No. 10-3140).
4.61* NSP Employee Stock Ownership Plan. (Exhibit 4.60 to Form 10-K for the year 1994, File No. 1-3034).
10.01* Mid-continent Area Power Pool (MAPP) Agreement, dated March 31, 1972, with amendments in 1994, between the local power suppliers in the North Central States area. (Exhibit 10.01 to Form 10-K for the year 1994, File No. 1-3034).
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* Coordinating agreement, dated July 21, 1976, between the Company and the Manitoba Hydro- Electric Board relating to the interconnection of the 500 Kv Line. (Exhibit 5.06K to File No. 2-54310).
10.05* Ownership and Operating Agreement, dated March 11, 1982, between the Company, Southern Minnesota Municipal Power Agency and United Minnesota Municipal Power Agency concerning Sherburne County Generating Unit No. 3. (Exhibit 10.01 to Form 10-Q for the quarter ended Sept. 30, 1994, File No. 1-3034).
10.06* Transmission agreement, dated April 27, 1982, and Supplement No. 1, dated July 20, 1982, between the Company and Southern Minnesota Municipal Power Agency. (Exhibit 10.02 to Form 10-Q for the quarter ended Sept. 30, 1994, File No. 1-3034).
10.07* Power agreement, dated June 14, 1984, between the Company and the Manitoba Hydro-Electric Board, extending the agreement scheduled to terminate on April 30, 1993, to April 30, 2005. (Exhibit 10.03 to Form 10-Q for the quarter ended Sept. 30, 1994, File No. 1-3034).
10.08* Power Agreement, dated August 1988, between the Company and Minnkota Power Company. (Exhibit 10.08 to Form 10-K for the year 1988, File No. 1-3034).
10.09* Energy Supply Agreement, dated Oct. 26, 1993, between the Company and Liberty Paper, Inc. (LPI), relating to the supply of steam and electricity to the LPI container-board facility in Becker, MN. (Exhibit 10.09 to Form 10-K for the year 1993, File No. 1-3034).
Executive Compensation Arrangements and Benefit Plans Covering Executive Officers
10.10* Executive Long-Term Incentive Award Stock Plan. (Exhibit 10.10 to Form 10-K for 1988, File No. 1-3034).
10.11* Terms and Conditions of Employment - James J Howard, President and Chief Executive Officer, effective Feb. 1, 1987, as amended. (Agreement filed as Exhibit 10.11 to Form 10-K for the year 1986, File No. 1-3034, Acknowledgement of Amendment to Terms and Conditions of Employment of James J. Howard filed as Exhibit 10.01 to Form 10-Q for the quarter ended June 30, 1995, File No. 1-3034).
10.12* NSP Severance Plan. (Exhibit 10.12 to Form 10-K for the year 1994, File No. 1-3034).
10.13* NSP Deferred Compensation Plan amended effective Jan. 1, 1993. (Exhibit 10.16 to Form 10-K for the year 1993, File No. 1-3034).
10.14 Annual Executive Incentive Plan for 1996.
12.01 Statement of Computation of Ratio of Earnings to Fixed Charges.
16.01* Independent Auditors' Letter re: Change in Certifying Accountant (Exhibit 16.01 to Form 8-K dated Dec. 13, 1994, File No. 1-3034).
21.01 Subsidiaries of the Registrant.
23.01 Consent of Independent Accountants - Price Waterhouse LLP, Minneapolis, MN.
23.02 Independent Auditor's Consent - Deloitte & Touche LLP.
23.03 Consent of Independent Accountants - Price Waterhouse LLP, Milwaukee, WI.
27.01 Financial Data Schedule.
99.01* Press Release, dated May 1, 1995, of NSP (Exhibit (99)-1 to Form 8-K dated April 28, 1995, File No. 1-3034).
99.02 Unaudited Pro Forma Combined Condensed Balance Sheets for Primergy Corporation at Dec. 31, 1995 and Unaudited Pro Forma Combined Condensed Statements of Income for the three years ended Dec. 31, 1995.
99.03 Unaudited Pro Forma Condensed Balance Sheet for New NSP at Dec. 31, 1995 and Unaudited Pro Forma Condensed Statements of Income for the three years ended Dec. 31, 1995.
99.04* Audited Financial Statements of Wisconsin Energy Corporation. (Item 8 of Wisconsin Energy Corporation's Annual Report on Form 10-K for the fiscal year ended Dec. 31, 1995, File No. 1- 9057).
(b) Reports on Form 8-K. The following reports on Form 8-K were filed either during the three months ended Dec. 31, 1995, or between Dec. 31, 1995 and the date of this report.
Jan. 18, 1996 (Filed Jan. 18, 1996) - Item 5. Other Events. Re: Release of 1995 financial results of NRG Energy, Inc., a wholly owned subsidiary of the Company.
March 1, 1996 (Filed March 1, 1996) - Item 5. Other Events. Re: Disclosure of new category of electric commercial and industrial customers, and electric and gas operating statistics for 1995.
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 27, 1996 (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, President Vice President and Chief and Chief Executive Officer Financial Officer (Principal (Principal Executive Officer) Financial Officer
(Roger D Sandeen) (H Lyman Bretting) Roger D Sandeen H Lyman Bretting Vice President, Controller and Chief Director Information Officer (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
(John E Pearson) (G M Pieschel) John E Pearson G M Pieschel Director Director
(Margaret R Preska) (A Patricia Sampson) Margaret R Preska A Patricia Sampson Director Director
EXHIBIT INDEX
Method of Exhibit Filing No. Description
DT 10.14 Annual Executive Incentive Plan for 1996
DT 12.01 Statement of Computation of Ratio of Earnings to Fixed Charges
DT 21.01 Subsidiaries of the Registrant
DT 23.01 Consent of Independent Accountants - Price Waterhouse LLP, Minneapolis, MN
DT 23.02 Independent Auditor's Consent - Deloitte & Touche LLP
DT 23.03 Consent of Independent Accountants - Price Waterhouse LLP, Milwaukee, WI
DT 27.01 Financial Data Schedule
DT 99.02 Unaudited Pro Forma Combined Condensed Balance Sheets for Primergy Corporation at Dec. 31, 1995 and Unaudited Pro Forma Combined Condensed Statements of Income for the three years ended Dec. 31, 1995
DT 99.03 Unaudited Pro Forma Condensed Balance Sheet for New NSP at Dec. 31, 1995 and Unaudited Pro Forma Condensed Statements of Income for the three years ended Dec. 31, 1995
DT = Filed electronically with this direct transmission.