-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, MQvz3QnCW68oYCvx+LOFmhAP6uVqldExif3SZ5aDHfMVGAK9ydY2pJlwx9J9KE3A T5S6KQtLb+tcUmBnAGClDQ== 0000072903-97-000028.txt : 19971117 0000072903-97-000028.hdr.sgml : 19971117 ACCESSION NUMBER: 0000072903-97-000028 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19970930 FILED AS OF DATE: 19971114 SROS: CSX SROS: NYSE SROS: PSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHERN STATES POWER CO /MN/ CENTRAL INDEX KEY: 0000072903 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 410448030 STATE OF INCORPORATION: MN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-03034 FILM NUMBER: 97722174 BUSINESS ADDRESS: STREET 1: 414 NICOLLET MALL 4TH FL CITY: MINNEAPOLIS STATE: MN ZIP: 55401 BUSINESS PHONE: 6123305500 MAIL ADDRESS: STREET 1: 414 NICOLLET MALL STREET 2: 4TH FLOOR CITY: MINNEAPOLIS STATE: MN ZIP: 55401 10-Q 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR QUARTER ENDED SEPTEMBER 30, 1997 COMMISSION FILE NUMBER 1-3034 NORTHERN STATES POWER COMPANY (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) MINNESOTA 41-0448030 (State of other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 414 NICOLLET MALL, MINNEAPOLIS, MINNESOTA 55401 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (612) 330-5500 None Former name, former address and former fiscal year, if changed since last report Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Class Outstanding at October31, 1997 Common Stock, $2.50 par value 74,460,438 shares PART 1. FINANCIAL INFORMATION Northern States Power Company(Minnesota) and Subsidiaries Consolidated Statements ofIncome (Unaudited) Three Months Ended Nine Months Ended September 30 September 30 1997 1996 1997 1996 Utility operating revenues Electric $645,268 $586,001 $1,682,445 $1,605,708 Gas 52,175 47,257 351,818 338,518 Total 697,443 633,258 2,034,263 1,944,226 Utility operating expenses Fuel for electric generation 82,936 74,110 232,377 220,331 Purchased and interchange power 82,231 70,453 212,542 193,148 Cost of gas purchased and 27,974 22,057 222,372 207,088 transported Other operation 93,942 78,452 276,401 243,510 Maintenance 38,737 33,411 122,975 120,804 Administrative and general 37,549 41,220 108,493 116,579 Conservation and energy management 19,342 17,224 52,650 47,203 Depreciation and amortization 81,469 76,899 241,960 227,644 Taxes: Property and general 58,571 62,975 176,169 182,889 Current income 52,550 52,626 125,710 139,946 Deferred income 5,822 566 (3,392) (13,855) Investment tax credits recognized (2,220) (2,191) (6,576) (6,596) Total 578,903 527,802 1,761,681 1,678,691 Utility operating income 118,540 105,456 272,582 265,535 Other income (expense) Income from nonregulated 2,223 5,592 13,959 11,021 businesses - before interest and taxes Allowance for funds used during 1,382 1,457 5,203 5,579 construction - equity Merger costs - - (29,005) - Other utility income (2,383) 373 (7,376) (1,320) (deductions) - net Income taxes on nonregulated 9,274 4,018 32,475 11,256 operations and non-operating items Total 10,496 11,440 15,256 26,536 Income before financing costs 129,036 116,896 287,838 292,071 Financing costs Interest on utility long-term debt 25,506 25,440 76,754 75,816 Other utility interest and 4,965 5,776 15,102 16,536 amortization Nonregulated interest and 9,376 4,875 22,139 13,643 amortization Allowance for funds used during (2,661) (3,434) (8,595) (8,755) construction - debt Total interest charges 37,186 32,657 105,400 97,240 Distributions on redeemable 3,938 - 10,500 - preferred securities of subsidiary trust Total financing costs 41,124 32,657 115,900 97,240 Net Income 87,912 84,239 171,938 194,831 Preferred stock dividends and 2,371 3,061 8,699 9,184 redemption premiums Earnings available for common $85,541 $81,178 $163,239 $185,647 stock Average number of common and equivalent shares outstanding (000's 69,556 68,948 69,088 68,642 Earnings per average common $1.23 $1.18 $2.36 $2.70 share* Common dividends declared per $0.705 $0.690 $2.100 $2.055 share Consolidated Statements of Retained Earnings (Unaudited) Balance at beginning of period $1,322,265 $1,277,203 $1,340,799 $1,266,026 Net income for period 87,912 84,239 171,938 194,831 Dividends declared: Preferred stock (2,371) (3,061) (7,551) (9,184) Common stock (52,165) (47,118) (148,397) (140,410) Premium on redeemed preferred - - (1,148) - stock Balance at end of period $1,355,641 $1,311,263 $1,355,641 $1,311,263
The Notes to Financial Statements are an integral part of the Statements of Income and Retained Earnings . * As described in the Management's Discussion and Analysis, earnings for the nine months ended September 30, 1997, were reduced by $0 25 per share due to the write-off of $29 million in merger related costs. Northern States Power Company (Minnesota) and Subsidiaries Consolidated Balance Sheets (Unaudited) September 30, 1997 December 31,1996 ASSETS (Thousands of dollars) Utility Plant Electric $6,943,478 $6,766,896 Gas 802,504 750,449 Other 333,169 331,441 Total 8,079,151 7,848,786 Accumulated provision for depreciation (3,831,480) (3,611,244) Nuclear fuel 917,031 892,484 Accumulated provision for amortization (821,861) (792,146) Net utility plant 4,342,841 4,337,880 Current Assets Cash and cash equivalents 112,521 51,118 Customer accounts receivable - net 241,215 288,330 Unbilled utility revenues 88,988 147,366 Notes receivable from nonregulated projects 61,014 5,753 Other receivables 60,417 77,571 Fossil fuel inventories - at average cost 65,601 45,013 Materials and supplies inventories - at 111,106 109,425 average cost Prepayments and other 44,606 72,647 Total current assets 785,468 797,223 Other Assets Equity investments in nonregulated projects 712,968 412,175 External decommissioning fund and other 371,679 299,804 investments Regulatory assets 351,345 354,128 Nonregulated property - net of accumulated 224,329 192,790 depreciation Notes receivable from nonregulated projects 75,889 75,811 Other long-term receivables 55,363 63,684 Intangible assets - net 62,398 46,168 Long-term prepayments and deferred charges 76,324 57,237 Total other assets 1,930,295 1,501,797 TOTAL ASSETS $7,058,604 $6,636,900 LIABILITIES AND EQUITY Capitalization Common stock equity: Common stock and premium - authorized 160,000,000 shares of $2 50 par value, issued shares: 1997, 74,241,545; 1996, 69,063,712 $1,061,680 $811,378 Retained earnings 1,355,641 1,340,799 Leveraged common stock held by ESOP (13,865) (19,091) Currency translation adjustments - net (30,835) 2,794 Total common stock equity 2,372,621 2,135,880 Cumulative preferred stock and premium - authorized 7,000,000 shares of $100 par value; outstanding shares: 1997, 2,000,000; 1996, 2,400,000 without mandatory redemption 200,340 240,469 Mandatorily redeemable preferred securities 200,000 of subsidiary trust - guaranteed BY NSP* Long-term debt 1,856,479 1,592,568 Total capitalization 4,629,440 3,968,917 Current Liabilities Long-term debt due within one year 116,935 119,618 Other long-term debt potentially due within 141,600 141,600 one year Short-term debt - primarily commercial paper 106,680 368,367 Accounts payable 170,852 236,341 Taxes accrued 214,878 204,348 Interest accrued 36,690 34,722 Dividends payable on common and preferred stocks 54,690 50,409 Accrued payroll, vacation and other 76,976 80,995 Total current liabilities 919,301 1,236,400 Other Liabilities Deferred income taxes 808,333 804,342 Deferred investment tax credits 141,455 149,606 Regulatory liabilities 362,289 302,647 Postretirement and other benefit obligations 129,534 114,312 Other long-term obligations and deferred income 68,252 60,676 Total other liabilities 1,509,863 1,431,583 Commitments and Contingent Liabilities (See Note 4) TOTAL LIABILITIES AND EQUITY $7,058,604 $6,636,900
The Notes to Financial Statements are an integral part of the Balance Sheets . * As described in Note 2 to Financial Statements, the primary asset of NSP Financing I, a subsidiary trust of NSP, is $200 million principal amount of the Company' 7.875% Junior Subordinated Debentures due 2037. Northern States Power Company (Minnesota) and Subsidiaries CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Nine Months Ended September 30, 1997 1996 (Thousands of dollars) Cash Flows from Operating Activities: Net Income $171,938 $194,831 Adjustments to reconcile net income to cash from operating activities: Depreciation and amortization 265,994 249,429 Nuclear fuel amortization 30,242 32,843 Deferred income taxes (9,396) (16,935) Deferred investment tax credits recognized (6,343) (6,827) Allowance for funds used during construction - (5,203) (5,579) equity Undistributed equity in earnings of (7,086) (16,312) unconsolidated affiliates Write-off of prior year merger costs 25,289 - Cash provided by changes in certain working 51,669 828 capital items Cash provided by (used for) changes in other (8,240) 4,651 assets and liabilities Net cash provided by operating activities 508,864 436,929 Cash Flows from Investing Activities: Capital expenditures (319,904) (311,028) Increase (decrease) in construction payables (1,051) 6,646 Allowance for funds used during construction - 5,203 5,579 equity Investment in external decommissioning fund (30,750) (28,964) Equity investments, loans and deposits for (353,078) (181,662) nonregulated projects Collection of loans made to nonregulated projects 3,840 111,800 Other investments - net (6,625) 477 Net cash used for investing activities (702,365) (397,152) Cash Flows from Financing Activities: Change in short-term debt - net issuances (261,716) 6,407 (repayments) Proceeds from issuance of long-term debt - net 266,348 126,472 Repayment of long-term debt, including (6,650) (15,754) reacquisition premiums Proceeds from issuance of common stock - net 256,560 41,770 Proceeds from issuance of redeemable preferred 193,307 - securities - net Redemption of preferred stock, including - reacquisition premiums (41,278) Dividends paid (151,667) (148,068) Net cash provided by financing activities 254,904 10,827 Net increase in cash and cash equivalents 61,403 50,604 Cash and cash equivalents at beginning of period 51,118 28,794 Cash and cash equivalents at end of period $112,521 $79,398
The Notes to Financial Statements are an integral part of the Statements of Cash Flows. NORTHERN STATES POWER COMPANY (MINNESOTA) AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS In the opinion of management, the accompanying unaudited financial statements contain all adjustments necessary to present fairly the financial position of Northern States Power Company (Minnesota) (the Company) and its subsidiaries (collectively, NSP) as of Sept. 30, 1997 and Dec. 31, 1996, the results of its operations for the three and nine months ended Sept. 30, 1997 and 1996, and its cash flows for the nine months ended Sept. 30, 1997 and 1996. Due to the seasonality of NSP's electric and gas sales and variability of nonregulated operations, operating results on a quarterly basis are not necessarily an appropriate base from which to project annual results. The accounting policies followed by NSP are set forth in Note 1 to the financial statements in NSP's Annual Report on Form 10-K for the year ended December 31, 1996 (1996 Form 10-K). The following notes should be read in conjunction with such policies and other disclosures in the 1996 Form 10-K. Certain reclassifications have been made to 1996 financial information to conform with the 1997 presentation. These reclassifications had no effect on net income or earnings per share as previously reported. 1. CHANGE IN REPORTING OF EARNINGS PER SHARE Effective for year-end 1997 financial statements, NSP will be required to present its results of operations on a per share basis in accordance with Statement of Financial Accounting Standards (SFAS) No. 128, Earnings Per Share (EPS). This new reporting standard requires a dual presentation of EPS on the face of the income statement, with one calculation assuming no dilution and another assuming full dilution from potential issuance of unexercised stock awards. The SFAS No. 128 method differs from the current approach, under which some dilution from common stock equivalents is assumed in the "primary" EPS calculation. Applying the new standard to the results for the three and nine month periods ended Sept. 30, 1996 and 1997 would change reported EPS by less than one cent per share. The impact of applying SFAS No. 128 to other historical periods is expected to be immaterial. 2. BUSINESS DEVELOPMENTS TERMINATION OF PROPOSED MERGER - As discussed in the Company's Form 8-K filed on May 19, 1997, NSP and Wisconsin Energy Corporation (WEC) announced on May 16, 1997 that they mutually agreed to terminate their plans to merge the two companies. As a result of the merger termination, NSP charged to expense in the second quarter of 1997 its share of deferred merger-related costs. Minnesota Public Utilities Commission (MPUC) procedures required that NSP formally request closure of the merger application docket filed with them. In July 1997, the MPUC approved NSP's request to withdraw its merger application. The MPUC also determined in the third quarter of 1997 that it did not need to further pursue issues raised during the merger proceedings relating to NSP's rates, service quality, and ratemaking treatment of a contract settlement related to a prior period. BUSINESS INTERRUPTIONS - The Company experienced several events in the second and early third quarters that resulted in interruptions to normal business operations, including flooding, unscheduled plant outage and unusual storm damage. See Management's Discussion and Analysis for discussion of the financial effects of these items. UNION AGREEMENTS - A new three-year collective-bargaining agreement was ratified by the Company's union membership on April 10, 1997. All provisions of this new agreement are effective retroactively to Jan. 1, 1997. The prior agreement had expired Dec. 31, 1996, but was extended to April 30, 1997. ISSUANCE OF TRUST ORIGINATED PREFERRED SECURITIES (TOPRS) - As previously reported, on Jan. 31, 1997, 8,000,000 shares of 7.875 percent TOPrS were issued and sold through NSP Financing I, a statutory business trust formed under Delaware law. The Company owns all of the common equity securities of the trust and, accordingly, the trust is treated as a subsidiary of NSP, with its accounts included in NSP's consolidated financial statements. The business trust was formed for the sole purpose of issuing the TOPrS, and the primary asset of the trust is $200 million of 7.875 percent unsecured Junior Subordinated Debentures issued by the Company and maturing in 2037. NSP Financing I used the proceeds from the sale of $200 million of TOPrS to purchase such Debentures, which are eliminated in NSP's consolidation. The Company used the proceeds from the issuance of such Debentures to redeem $40 million of preferred stock and to repay a portion of outstanding short-term borrowings. The quarterly interest and other payment dates for the Debentures coincide with the distribution and other payment dates for the TOPrS. NSP has the right to defer payments of interest on the Debentures by extending the interest payment period, at any time, for up to 20 consecutive quarters. If interest payments on the Debentures are so deferred, distributions on the TOPrS will also be deferred. During any deferral, distributions will continue to accrue with interest thereon. In addition, during any such deferral, NSP may not, except in certain limited circumstances, declare or pay any dividend or other distribution on, or redeem or purchase, any of its capital stock. The TOPrS are redeemable by NSP (in whole or in part) from time to time, beginning in 2002, or at any time in the event of certain income tax circumstances. If the debentures are redeemed, the trust must redeem TOPrS having an aggregate liquidation amount equal to the aggregate principal amount of the debentures so redeemed. Upon redemption, holders of the TOPrS are generally entitled to receive a liquidation amount of $25 per share plus accrued and unpaid distributions. The TOPrS must be fully redeemed when the Debentures mature in 2037. The payment of distributions related to the TOPrS by NSP Financing I and payments on liquidation of NSP Financing I or the redemption of the TOPrS are guaranteed by NSP (the "Guarantee"), to the extent set forth therein. The Guarantee covers payments of distributions and other payments on the TOPrS only to the extent NSP makes a payment of interest or principal on the Debentures. NSP's obligations under the Debentures and the Guarantee are subordinate and junior in right of payment to certain indebtedness of NSP. NRG INVESTMENTS - In May 1997, the Company's wholly owned subsidiary NRG Energy, Inc. (NRG), as part of a consortium with CMS Energy Corporation (CMS) and Horizon Energy Australia Investments, closed on its acquisition of the Australian State of Victoria's Loy Yang A power plant (Loy Yang), Victoria's largest and Australia's lowest-cost electric generating facility. Loy Yang is a 2,000 megawatt (MW), brown coal-fired power station. The acquisition included an adjacent coal mine. The total purchase price was approximately 4.7 billion Australian dollars (or US$3.7 billion as of May 12, 1997). NRG holds a 25.37 percent ownership interest in the consortium. While most of the purchase price was raised through project-financed loans and leveraged leases that are non- recourse to the three partners, NRG paid $257 million for its equity interest in Loy Yang. Loy Yang is one of the newest and most modern of Victoria's brown coal-fired generating plants, with a portion of its electric output committed under power supply contracts through the year 2000. The coal mine has two billion tons of proven coal reserves, enough to serve the coal supply needs for 50 years of the Loy Yang plant acquired by the consortium and the Loy Yang B plant not included in the acquisition. The mine has a supply contract with the 1,000 MW Loy Yang B electric generating plant and the exclusive rights to provide coal supplies for a third Loy Yang generating plant, should it be built. Loy Yang is jointly managed and operated by CMS and NRG. In June 1997, loan financing was obtained for the refurbishment and expansion of the Energy Center Kladno (Kladno) plant in Kladno, the Czech Republic. NRG owns a 34 percent interest in the existing coal-fired electric and thermal energy generating facility that can supply 28 MW of electricity and 150 MW- thermal of steam and heated water. This project financing will fund the refurbishment of the existing facility as well as the expansion project to add 354 MW of new capacity, of which 282 MW will be coal-fired and 72 MW will be gas-fired. NRG currently holds a 57.85 percent interest in the expansion project and El Paso Energy International and Stredoceska Energeticka (STE), the regional Czech electric distribution company, own the remaining percentage of the expansion. Kladno has executed a 20-year agreement to supply electricity to STE and thermal energy to the district heating company in the city of Kladno. Long-term fuel supply agreements have been made with local Kladno mining companies. In June 1997, P.T. Dayalistrik Pratama (PTDP), a limited liability company of which NRG owns 45 percent, signed a coal supply agreement and purchased land for the 400 MW coal-fired Cilegon power generation facility to be built in West Java, Indonesia. NRG's expected equity investment in PTDP is $65 million, with the total project cost of $560 million to be financed by a combination of equity investments, commercial bank debt and capital markets funding. During September 1997, the government of Indonesia stated its intention to review or postpone a number of infrastructure projects, and NRG was notified that the Cilegon project is under review. In July 1997, an NRG affiliate signed an agreement with Millennium Petrochemicals Inc. (Millennium) to develop, finance, construct and operate a 117 MW cogeneration plant at Millennium's Morris, Ill. polyethylene manufacturing facility. The plant will provide the facility's steam and electrical needs pursuant to a 25-year contract and would market the excess electric capacity. Construction began in September 1997 with anticipated operations beginning the end of 1998. Millennium will have the right to buy out the contract at fair market values at certain defined points in the contract term. Millennium, a subsidiary of Millennium Chemicals Inc., is the largest domestic producer of polyethylene and a major supplier of performance polymers and select chemicals. During the third quarter of 1997, NRG obtained $16 million in project financing for Millennium with additional financing anticipated in late 1997 or early 1998. Since late 1996, NRG has had a right to acquire a 27.75 percent interest in the 390 MW Alto Cachapoal hydroelectric complex that is under development in central Chile. Alto Cachapoal is a two-stage "greenfield" project. In the first 195 MW stage, Alto Cachapoal plans to sell all of its firm energy to Codelco-El Teniente, the world's largest underground copper mine, pursuant to a 20-year power sales contract. Closing of the first stage has been delayed beyond 1997. Along with NRG, Nordic Power Invest AB also has a right to acquire a 27.75 percent interest in the Alto Cachapoal facility from Construction Andrade Gutierrez, the current owner of the project. As discussed in the 1996 Form 10-K, an NRG subsidiary has a 50 percent interest in the Sunnyside cogeneration joint venture in Utah, which sells energy and capacity to PacifiCorp under a power purchase agreement with an initial term expiring in 2023. Under the agreement, PacifiCorp is obligated to pay for: energy at prices based on PacifiCorp's avoided cost, base capacity at a levelized fixed price, and additional capacity at escalating fixed prices. The Sunnyside facility has experienced a shortfall in project cash flow attributable primarily to decreased revenues due to avoided energy rates being significantly lower than originally forecasted. In addition, higher fuel costs than originally forecasted may be incurred in the future. These changes in the economic performance of the Sunnyside project have caused NRG to explore its options. In particular, the joint venture has negotiated with PacifiCorp to restructure payments under the power purchase agreement, and the joint venture has discussed a restructuring of the project debt with its bondholders. In the absence of a restructuring of the project's debt, a debt service reserve fund, which has been used to make up cash shortfalls, is expected to be depleted by the end of 1997. There can be no assurance that either PacifiCorp or the bondholders will agree to any restructuring, nor can there be any assurances as to the actions the joint venture may take when and if the debt service reserve fund is depleted. NRG's investment in Sunnyside is approximately $12.5 million. In September 1997, the Estonian government announced it would not accept various aspects of NRG's proposed business plan for a joint project in Estonia for the acquisition, refurbishment and operations of 3,000 MW of generation and the associated fossil fuel supplies. NRG and government officials are in discussions to determine if a mutually acceptable business plan can be developed. During September 1997, NRG and its joint venture partners revised its previous bid to acquire certain assets of the Cajun Electric Power Cooperative in Louisiana. The revised acquisition bid was filed with and is subject to the approval of the federal bankruptcy court. In October 1997, NRG Generating (U.S.) Inc., a subsidiary of NRG Energy, Inc., completed a controlled startup of the combustion turbine at the 150 MW natural- gas-fired Grays Ferry Cogeneration project in Philadelphia. The project, which is on schedule and within budget, is expected to begin commercial operation in early December. The Grays Ferry project will sell electricity to PECO Energy Company and heating steam to Trigen-Philadelphia Energy Corporation. In October 1997, NRG purchased Pacific Generation Co. (PGC), an indirect subsidiary of PacifiCorp, for $151 million, subject to final post-closing adjustments. PGC is an independent power producer with an interest in 11 power generating facilities located throughout North America that have a total capacity of 737 MW. The facilities, located in California, Washington, Maine, New York, Massachusetts, and Kingston, Ontario, are diverse in terms of fuel type, including natural gas, hydro, refuse-derived fuel, coal and wind. As discussed in the 1996 Form 10-K, in 1996 NRG purchased, at a substantial discount, the senior secured debt of Mid-Continent Power Company, Inc. (MCPC). In June 1997, MCPC filed a Chapter 11 petition in federal bankruptcy court in Tulsa, Okla. and concurrently filed a plan of reorganization proposing to transfer ownership of all of MCPC's assets to NRG in exchange for forgiveness of a portion of MCPC's debt. In October 1997, this plan was confirmed by the bankruptcy court. The project is a gas-fired cogeneration plant with a rated capacity of 110 MW located in Pryor, Okla. which sells steam to several industrial customers and electricity to two Oklahoma utilities. CHANGE IN NRG HEDGING POLICY - In July 1997, NRG changed its policy of hedging foreign currency denominated investments as they were made, to a policy of hedging foreign currency cash flows over a projected 12-month period. As a result of this change in hedging policy, NRG terminated its seven existing foreign currency swap agreements on July 29, 1997. These terminations resulted in cash payments to NRG without any earnings impact. Consistent with prior policies, NRG is not hedging future earnings and does not speculate in foreign currencies. ENERGY MASTERS INTERNATIONAL - In July 1997, Cenerprise, Inc. (Cenerprise) acquired Energy Solutions International, Inc. (ESI) of Mendota Heights, Minn., and the remaining 20 percent of Energy Masters Corporation (EMC) that Cenerprise did not already own. Effective Sept. 1, 1997, Cenerprise Inc., changed its name to Energy Masters International Inc. (EMI) and established its headquarters in Mendota Heights. EMI, now with 300 employees in more than 25 offices nationwide, delivers energy supply and energy performance products and services to commercial and industrial customers, utilities, municipalities, and energy marketers. VIKING VOYAGEUR - The Company's subsidiary, Viking Gas Transmission Company, and TransCanada PipeLines Limited (TransCanada) announced plans earlier in 1997 to become equal partners in the Viking Voyageur Gas Transmission Company, LLC (Viking Voyageur) which is seeking to build a natural gas transmission pipeline extending from Emerson, Manitoba, to northeastern Illinois. The line would serve markets in Minnesota, Wisconsin and northeastern llinois. In June 1997, Viking Voyageur completed the "open season" for firm gas transportation service requests on its proposed gas pipeline project. During the open season, prospective natural gas shippers submitted requests for firm gas transportation capacity. At the conclusion of the open season, the project received requests for firm capacity of more than 1.8 billion cubic feet (bcf) per day. As a result, Viking Voyageur proposed to increase the size of the pipeline from 36 to 42 inches in diameter and volume from 1.2 to approximately 1.4 bcf per day. In July 1997, Nicor Inc. became a 20 percent owner in the Viking Voyageur project, joining partners NSP and TransCanada who each now have a 40 percent ownership interest. The partners also agreed to extend the pipeline an additional 60 miles to Joliet, Ill. to access Nicor's storage and transmission facilities. Nicor is a holding company based in Naperville, Ill. One of its principal businesses is Northern Illinois Gas, one of the nation's largest gas distribution companies. In October 1997, Viking Voyageur submitted an application to the Federal Energy Regulatory Commission for approval to construct a 42-inch diameter, 773 mile long pipeline. If the necessary regulatory approvals are obtained promptly, the project could be in service in late 1999. 3. REGULATION AND RATE MATTERS RATE FILINGS - As a result of the termination of the proposed merger with WEC as discussed in Note 2, the Company has revised its regulatory plan and is considering rate filings in several jurisdictions. The Company is planning to file an application for a retail gas rate increase in its Minnesota jurisdiction later in 1997. In addition, the Company is planning to file, before 1997 year end, a rate application with the FERC to update its rates for transmission service. Northern States Power Company, a Wisconsin corporation, (the Wisconsin Company) filed retail electric and gas rate applications on Nov. 14, 1997, for 1998 rates as required by the Public Service Commission of Wisconsin (PSCW) biennial filing requirements. The applications requested an annual increase of $12.7 million in retail electric rates and a decrease of $1.7 million in retail gas rates. Any rate changes approved by PSCW would likely not take effect until the second quarter of 1998. NETWORK TRANSMISSION SERVICE COSTS (NTS) - In July 1997, the Wisconsin Company, received authorization from the PSCW to defer its share of network transmission service (NTS) costs incurred after May 23, 1997. Beginning in the third quarter 1997, the Wisconsin Company began deferring these costs, including a retroactive adjustment to May 23, 1997. Approximately $1.4 million of NTS costs had been deferred at Sept. 30, 1997. Under NTS, the Company and participating utilities share the total annual transmission cost for their combined joint-use systems, net of related transmission revenues, based upon each company's share of the total network load. The Company offers NTS service to qualifying transmission customers as mandated in FERC Order No. 888. The Wisconsin Company's share of this expense is billed through the Interchange Agreement with the Company. 4. COMMITMENTS AND CONTINGENT LIABILITIES LEGISLATIVE RESOURCE COMMITMENTS - In 1994, the Minnesota Legislature established several energy resource and other commitments for NSP to fulfill as part of its approval of NSP's Prairie Island nuclear generating plant's temporary nuclear fuel storage facility, as discussed in NSP's 1996 Annual Report on Form 10-K. Steps have been taken to fulfill certain of these commitments during 1997 as described below. The 1994 Prairie Island legislation requires NSP to have under contract, or in operation, 225 MW of wind generation by Dec. 31, 1998 and a total of 425 MW by Dec. 31, 2002. NSP is currently purchasing generation from a 25 MW wind farm. The Company has a contract, which has been approved by MPUC, with Zond Minnesota Development Corporation II (Zond), a wind developer, to purchase 107 MW which is expected to be operating by June 1998. In March 1997, the Company signed two power purchase agreements, which have been approved by the MPUC, with Northern Alternative Energy, Inc. for the development of 22.65 MW of wind-generated electricity. In September 1997, the Company signed an agreement with Woodstock Windfarm, LLC for the development of 10.2 MW of wind-generated electricity. In July 1997, after a competitive bid process to supply 100 MW of wind energy by mid-1999, the Company selected Zond to supply this wind energy. These agreements are subject to approval by the MPUC. When these increments are completed, the Company's purchases of wind generation will be approximately 265 MW. The 1994 Prairie Island legislation also requires NSP to have under contract a total of 125 megawatts of biomass generation by the end of 1998. In October 1997, NSP began Phase II of its legislative commitment by selecting District Energy St. Paul Inc. and Lindroc Energy to each supply 25 MW of biomass power beginning in the summer of 2002. Phase I began in July 1996, with the selection of Minnesota Agri-Power Project to supply 75 MW of farm-grown, closed-loop biomass generation by the end of 2001. In May 1997, the Minnesota Court of Appeals (the Court) affirmed an Order of the Minnesota Environmental Quality Board (MEQB) which authorized the Company to use four additional casks for the storage of spent nuclear fuel at the Prairie Island nuclear generating plant. The Court also affirmed the MEQB's Order which denied a certificate of site comparability for an alternative site for the storage of spent nuclear fuel in Goodhue County. The Prairie Island Indian Tribe (the Tribe) had filed suit with the Court challenging the MEQB actions in October 1996. In June 1997, the Tribe petitioned the Minnesota Supreme Court for review. In July 1997, the Minnesota Supreme Court denied further review and the Company subsequently withdrew its application to the Nuclear Regulatory Commission to construct and operate an alternative site for the storage of spent nuclear fuel. NETWORK TRANSMISSION COSTS - In October 1997, another regional utility with integrated transmission facilities who participates in FERC's transmission cost- sharing network provided information to the Company which, if accurate and reliable, could increase NSP's anticipated annual NTS expense by approximately $7 million, effective in 1997. This is an increase over the Company's prior $27 million estimate of 1997 NTS expense. The Company intends to review and evaluate the information provided, assess its reliability and compliance with FERC guidelines, and, if necessary, dispute amounts that the Company believes represent increases due to inappropriately claimed facilities or inaccurate costs related to claimed facilities. Pending the outcome of this review, none of the potential NTS cost increase has been recognized as of Sept. 30, 1997. NUCLEAR INSURANCE - The circumstances set forth in Note 14 to NSP's financial statements contained in the 1996 Form 10-K appropriately represent, in all material respects, the current status of commitments and contingent liabilities regarding public liability for claims resulting from any nuclear incident. Item 2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION Except for the historical statements contained herein, the matters discussed in the following discussion and analysis are forward looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate", "estimate", "expect", "objective", "possible", "potential" and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including their impact on capital expenditures; business conditions in the energy industry; competitive factors; unusual weather; changes in federal or state legislation; the higher degree of risk associated with the Company's nonregulated businesses as compared to the Company's regulated business; the items set forth below under "Factors Affecting Results of Operations"; and the other risk factors listed from time to time by the Company in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.01 to this report on Form 10-Q for the quarter ended Sept. 30, 1997. RESULTS OF OPERATIONS NSP's earnings for the periods ending Sept. 30, 1997 and 1996 were as follows: 3 Mos. Ended 9 Mos. Ended 9/30/97 9/30/96 9/30/97 9/30/96 ------- ------- ------- -------- Earnings per average common share: Ongoing operations $1.23 $1.18 $2.61 $2.70 Merger costs * 0.00 0.00 (0.25) 0.00 Total $1.23 $1.18 $2.36 $2.70
*net of applicable income tax The changes in revenues and expenses of the regulated utility businesses and nonregulated businesses underlying the variances in financial results 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 due to a public stock offering in September 1997 and stock issuances for the Company's dividend reinvestment and stock ownership plans. FACTORS AFFECTING RESULTS OF OPERATIONS In addition to items noted in the 1996 Form 10-K, the historical and future trends of NSP's operating results have been and are expected to be affected by the following factors: TERMINATION OF PROPOSED MERGER - As discussed in Note 2, during May 1997 NSP and WEC terminated their plans to merge. NSP's year-to-date operating results for 1997 include a charge to nonoperating expense of approximately $29 million, or 25 cents per share, to write off its cumulative merger-related costs incurred. This charge, which is being reported as a non-recurring item outside of earnings from ongoing operations, includes estimates for certain regulatory and other costs which NSP will be required to pay but which have not yet been finalized. NONREGULATED BUSINESS RESULTS - The following summarizes the earnings contributions of NSP's nonregulated businesses: 3 Mos. Ended 9 Mos. Ended 9/30/97 9/30/96 9/30/97 9/30/96 ------- ------- ------- ------- NRG Energy, Inc. $0.04 $0.07 $0.21 $0.16 Eloigne Company 0.01 0.01 0.05 0.03 Energy Masters International, Inc* (0.04) (0.02) (0.08) (0.08) Other 0.01 0.01 0.00 0.02 Total $0.02 $0.07 $0.18 $0.13
* formerly Cenerprise, Inc. Due to the nature of these nonregulated businesses, NSP anticipates that the earnings from nonregulated operations will experience more variability than regulated utility businesses. As discussed later, NSP's nonregulated earnings in the three- and nine-month periods ended Sept. 30, 1997 are experiencing such variability. ESTIMATED IMPACT OF WEATHER ON REGULATED EARNINGS - NSP estimates utility sales levels under normal weather conditions and analyzes the approximate effect of variations from historical average temperatures on actual sales levels. The following summarizes the estimated impact of weather on actual utility operating results (in relation to sales under normal weather conditions): INCREASE (DECREASE) Actual Actual Actual 1997 VS NORMAL 1996 VS NORMAL 1997 VS 1996 -------------- --------------- ------------- Earnings per Share for: Quarter Ended September 30 ($0.06) ($0.06) $0.00 Nine Months Ended September 30 ($0.02) $0.08 ($0.10)
BUSINESS INTERRUPTIONS Service Area Flooding - In the Grand Forks area (North Dakota and Minnesota), flood damage and precautionary shut-downs cut off service to many of NSP's 21,000 electric and 13,000 gas customers in the area on or about April 21, 1997. Most customers have been reconnected however the Company anticipates that gas service may not be fully restored until late 1997. NSP estimates that its year-to-date operating results for 1997 have been reduced by approximately 4 to 5 cents per share due to flooding, mainly in the Grand Forks area. This estimate includes approximately $3 million of lost electric and gas margins compared to expected customer usage under normal weather conditions, and approximately $2 million in additional operating and maintenance expenses, net of estimated insurance recovery of $1.4 million. The Company does not expect that additional flood-related operating expenses incurred and revenues lost after Sept. 30, 1997 will be significant to operating results. In addition, the Company expects to incur approximately $4 million of capital expenditures to rebuild the area's delivery systems, of which approximately $2.6 million had been spent through Sept. 30, 1997. The amount of any additional insurance recovery or disaster relief available to NSP for potential reimbursement of expenses incurred and revenues lost as a result of flooding is not fully determinable at this time. Depreciation and return on investment related to capital expenditures incurred would be subject to recovery in future rate proceedings. Unscheduled Plant Outage - The Company's Monticello nuclear generating plant was taken out of service effective May 9, 1997 and returned to service at full- power on Aug. 1, 1997. The unscheduled outage represents an acceleration of a design change originally planned to be made in January 1998 during the unit's scheduled refueling outage. During the plant outage, NSP continued to serve its customers with electricity generated at other NSP facilities and through power purchases from other sources. The majority of the incremental costs incurred by the Company from replacing the plant's generation was recovered via fuel adjustment clause rate mechanisms. The costs of replacement power not recovered through the fuel clause (mainly in Wisconsin), and incremental maintenance costs related to the outage resulted in an adverse impact to NSP's 1997 earnings. For the three- and nine-month periods ended Sept. 30, 1997, NSP estimates that its operating results have been reduced by approximately 2 cents and 4 cents per share, respectively. See the Utility Operating Results sections herein for further discussion of the financial effects of the unscheduled plant outage. Storms - The Company experienced several storms in April, June and July 1997. Portions of two NSP high voltage transmission lines connecting NSP's Monticello and Sherco plants to the Minneapolis-St. Paul metro area were damaged. The Company avoided transmission-related outages but had to temporarily reduce production at its plants. The first Company-owned line was repaired and in service by July 29, 1997 and the second by Sept. 16, 1997. Reduced transmission capability until repairs were completed, in addition to reduced generating capability as a result of the unscheduled Monticello outage, limited NSP's opportunity to sell power to other utilities. The majority of the incremental costs for replacement generation (purchased power and running NSP peaking facilities) was recovered through fuel adjustment clause rate mechanisms. The costs for repairs attributable to all of the storms is estimated to be approximately $4 million of operating and maintenance expenses, most of which has been recognized in the third quarter, and approximately $10 million in capital expenditures. Depreciation and return on investment related to capital expenditures incurred would be subject to recovery in future rate proceedings. 1997 FINANCIAL OUTLOOK - Management believes that, primarily as a result of the business interruptions and network transmission service costs described previously, it is likely that NSP's 1997 earnings from ongoing operations (excluding merger costs) will be below 1996 results. THIRD QUARTER 1997 COMPARED WITH THIRD QUARTER 1996 UTILITY OPERATING RESULTS ELECTRIC REVENUES for the third quarter of 1997 compared with the third quarter of 1996 increased $59.3 million or 10.1 percent. Retail revenue increased approximately $40.8 million or 7.5 percent largely due to increases in retail electric sales and higher average prices. The increase in retail electric sales reflects sales growth compared to 1996. Average retail prices increased as a result of rate adjustments for higher fuel and purchased power costs, reflecting the impacts of the business interruptions discussed previously, and increased recovery of deferred conservation and energy management costs. Revenue from sales to other utilities increased $7.8 million in 1997 primarily due to an increase in average prices reflecting more favorable market conditions. Other electric revenues increased by $10.6 million largely due to the recognition of a transmission settlement and increases in the transmission of electricity for others. GAS REVENUES for the third quarter of 1997 increased $4.9 million or 10.4 percent compared with the third quarter of 1996 primarily due to rate adjustments related to estimated purchased gas cost recovery and higher interruptible sales volumes, partially offset by a decline in firm sales volume and lower transportation revenues. The firm sales volume decrease is primarily due to lower sales growth and less favorable weather in 1997 in comparison to 1996. FUEL FOR ELECTRIC GENERATION and PURCHASED AND INTERCHANGE POWER costs combined increased $20.6 million or 14.3 percent for the third quarter of 1997 compared with the third quarter of 1996. Fuel expense increased $8.8 million primarily due to higher average fossil fuel prices from the use of higher cost plants and increased plant output due to higher sales. Purchased and interchange power costs increased $11.8 million primarily due to higher market prices for purchased power and increased purchases. The operation of higher cost plants and an increased level of power purchases were necessary due to plant outages and lower generation from a baseload plant as a result of transmission line limitations, as discussed previously. COST OF GAS PURCHASED AND TRANSPORTED for the third quarter of 1997 compared with the third quarter of 1996 increased $5.9 million or 26.8 percent due to increased gas costs partially offset by reduced off-system and agency gas sales. The higher cost of gas reflects adjustments to match rate recovery under the purchased gas adjustment mechanism and higher gas costs due to market changes in natural gas prices charged by suppliers. OTHER OPERATION and MAINTENANCE expenses increased and ADMINISTRATIVE AND GENERAL expenses decreased combining for a net increase of $17.1 million or 11.2 percent compared with the third quarter of 1996. The costs associated with providing network transmission service (NTS) to qualifying transmission customers, as a result of FERC Order No. 888 (see Notes 3 and 4 to the Financial Statements), added $6.2 million to other operation expenses. Costs incurred for plant outages, storm and flood damage, (as discussed previously), electric technology improvements, customer service and provisions for uncollectibles also increased operating and maintenance expenses. Partially offsetting these increases were lower costs for employee benefits and property insurance. CONSERVATION AND ENERGY MANAGEMENT costs increased $2.1 million or 12.3 percent in the third quarter of 1997 compared to the same period in the prior year due to higher amortization levels and concurrent rate recovery of deferred electric and gas conservation and energy management program costs. These higher amortization levels are consistent with retail electric and gas rate recovery levels in the Company's Minnesota jurisdiction which increased in August 1996 for electric and September 1996 for gas. DEPRECIATION AND AMORTIZATION expense increased $4.6 million or 5.9 percent compared with the third quarter of 1996. The increase is mainly due to increased plant in service between the two periods. PROPERTY AND GENERAL TAXES for the third quarter of 1997 compared with the third quarter of 1996 decreased $4.4 million or 7.0 percent due to lower 1997 property taxes in Minnesota as a result of legislation enacted in May 1997 and higher property tax accruals in 1996. The 1996 accrual levels were ultimately adjusted downward at year-end 1996 based on final property tax notices received. UTILITY INCOME TAXES for the third quarter of 1997 compared with the third quarter of 1996 were $5.2 million higher primarily due to higher operating income in the third quarter of 1997. OTHER UTILITY INCOME (DEDUCTIONS) - NET decreased $2.8 million mainly due to lower interest income compared to 1996, which included interest from settlement of tax disputes . UTILITY INTEREST AND AMORTIZATION decreased $0.7 million or 2.4 percent primarily due to interest adjustments related to settlement of a state tax dispute. DISTRIBUTIONS ON REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST increased $3.9 million due to the issuance of new securities in 1997 as discussed in Note 2 to the Financial Statements. PREFERRED STOCK DIVIDENDS AND REDEMPTION PREMIUMS decreased $0.7 million in the third quarter of 1997 compared with 1996 primarily due to reductions in dividends resulting from the redemption of two issues of preferred stock in February 1997. NONREGULATED BUSINESS RESULTS NSP's nonregulated operations include many diversified businesses, such as independent power production, energy sales and services, industrial heating and cooling, and energy-related refuse-derived fuel production. NSP also has investments in affordable housing projects and several income-producing properties. The following summarizes NSP's diversified business results in the aggregate, including consolidated subsidiaries and unconsolidated affiliates. 3 MOS. ENDED (Thousands of dollars, except EPS) 9/30/97 9/30/96 ------- ------- Operating revenues $48,918 $56,051 Equity in earnings of unconsolidated affiliates 2,807 6,234 Operating and development expenses (53,618) (58,803) Interest and other income 4,116 2,110 Income from nonregulated businesses before interest and taxes $2,223 $5,592 Interest expense (9,376) (4,875) Income tax benefit 8,580 3,869 Net income $1,427 $4,586 Contribution of nonregulated businesses to NSP earnings per share $0.02 $0.07
NRG - NRG's third quarter earnings decreased by 3 cents per share in 1997 from the same period one year ago primarily due to increased interest costs from a June 1997 debt financing and lower project earnings which were partially offset by higher tax credits for new projects. The operating results of NRG projects in 1997 reflect higher earnings from new projects, including interests in Loy Yang in Australia (acquired in May 1997) and COBEE in Bolivia (acquired in December 1996), which were offset by lower earnings at MIBRAG in Germany. NRG's landfill gas subsidiary, NEO, has entered into projects since 1996 that are generating higher levels of energy tax credits. EMI - EMI's third quarter losses increased by 2 cents per share in 1997 compared 1996, primarily due to equity in losses incurred by its 50 percent- owned joint venture, Enerval, and increased expenses related to combining operations with Energy Solutions International, Inc. (ESI) and Energy Masters Corporation (EMC), both purchased in July 1997. FIRST NINE MONTHS OF 1997 COMPARED WITH FIRST NINE MONTHS OF 1996 UTILITY OPERATING RESULTS ELECTRIC REVENUES for the first nine months of 1997 compared with the first nine months of 1996 increased $76.7 million or 4.8 percent. Retail revenues increased approximately $50.6 million or 3.4 percent due to an increase in average retail prices and a 1.6 percent increase in retail electric sales. The increase in retail electric sales reflects sales growth compared to 1996, partially offset by less favorable weather in 1997. Average retail prices increased as a result of rate adjustments for higher fuel and purchased power costs, reflecting the impacts of the business interruptions discussed previously, and increased recovery of deferred conservation and energy management costs. Revenue from sales to other utilities increased $12.5 million primarily due to price increases resulting from more favorable market conditions. Other electric revenues increased $13.6 million largely due to the recognition of a transmission settlement in the third quarter of 1997 and increases in the transmission of electricity for others. GAS REVENUES for the first nine months of 1997 compared with the first nine months of 1996 increased $13.3 million or 3.9 percent. Gas revenues increased due to an increase in average gas prices despite a 2.3 percent decrease in gas sales volume and decreased transportation and off-system sales,. The sales volume decrease is due primarily to less favorable weather in 1997 in comparison to 1996, partially offset by growth in gas sales. The price increase is mainly due to rate adjustments for increased purchased gas costs in the first quarter of 1997, resulting from market changes in natural gas prices charged by suppliers, and an annual adjustment to rate recovery of estimated purchased gas costs in Minnesota. FUEL FOR ELECTRIC GENERATION and PURCHASED AND INTERCHANGE POWER costs combined increased $31.4 million or 7.6 percent for the first nine months of 1997 compared with the first nine months of 1996. Fuel expense increased $12.0 million primarily due to higher average fossil fuel prices, mainly reflecting the increased use of higher cost plants due to plant outages and lower generation from a baseload plant as a result of transmission line limitations, as discussed previously, and more plant output due to higher sales. Purchased and interchange power costs increased $19.4 million primarily due to increased costs due to market conditions and higher purchases as a result of higher sales and lower plant availability during the second and third quarters, as discussed previously. COST OF GAS PURCHASED AND TRANSPORTED for the first nine months of 1997 compared with the first nine months of 1996 increased $15.3 million or 7.4 percent due to higher cost of gas, partly offset by lower gas sendout. The higher cost of purchased gas, occurring mainly in the first quarter of 1997, reflects changes in market conditions and gas cost adjustments to match expense with rate recovery. The lower sendout is primarily a result of decreased gas sales and lower off-system sales. OTHER OPERATION and MAINTENANCE expenses increased and ADMINISTRATIVE AND GENERAL expenses decreased, combining for a net increase of $27.0 million or 5.6 percent compared with the first nine months of 1996. The cost associated with offering NTS to qualifying transmission customers, as a result of FERC Order No. 888, added approximately $18 million to other operation expenses. Expenditures for electric technology improvements, customer service initiatives, provisions for uncollectibles, storm damage, flooding and outage costs also increased operating and maintenance expenses. Partially offsetting these increases were lower costs for employee benefits, insurance and line maintenance costs unrelated to the storm damage. CONSERVATION AND ENERGY MANAGEMENT expenses increased $5.4 million in the first nine months of 1997 compared to the same period in the prior year due mainly to higher amortization levels and concurrent rate recovery of deferred electric and gas conservation and energy management program costs. These higher amortization levels are consistent with retail electric and gas rate recovery levels in the Company's Minnesota jurisdiction which increased in August 1996 for electric and September 1996 for gas. DEPRECIATION AND AMORTIZATION increased $14.3 million or 6.3 percent compared with the first nine months of 1996. The increase is mainly due to increased plant in service between the two periods. PROPERTY AND GENERAL TAXES for the first nine months of 1997 compared with the first nine months of 1996 decreased $6.7 million or 3.7 percent due to lower 1997 property taxes in Minnesota a result of legislation enacted in May 1997 and higher property tax accruals in 1996. The 1996 accrual levels were ultimately adjusted downward at year-end 1996 based on final property tax notices received. This decrease is partly offset by higher payroll and franchise taxes. UTILITY INCOME TAXES for the first nine months of 1997 compared with the first nine months of 1996 decreased $3.8 million primarily due to lower pre-tax income. OTHER UTILITY INCOME (DEDUCTIONS) - NET decreased $6.1 million for the first nine months of 1997 compared with the first nine months of 1996 primarily due to lower interest income associated with the settlement of tax disputes and with customer financing, and non-recurring 1996 refund adjustments. Other income (expense) also includes the second quarter write-off of $29 million in merger costs (as discussed previously) and the related tax effects. UTILITY INTEREST AND AMORTIZATION for the first nine months of 1997 compared with the first nine months of 1996 decreased by $0.5 million primarily due to interest adjustments related to a settlement of a state tax dispute, and offsetting changes in other interest. DISTRIBUTIONS ON REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST increased $10.5 million due to the issuance of new securities in 1997 as discussed in Note 2 to the Financial Statements. PREFERRED STOCK DIVIDENDS AND REDEMPTION PREMIUMS decreased $0.5 million for the first nine months of 1997 compared with the first nine months of 1996 due to reductions in dividends as a result of the redemption of two issues of preferred stock in February 1997, partially offset by a $1.1 million redemption premium. NONREGULATED BUSINESS RESULTS The following summarizes NSP's diversified business results in the aggregate, including consolidated subsidiaries and unconsolidated affiliates. 9 MOS. ENDED (Thousands of dollars, except EPS) 9/30/97 9/30/96 ------- ------- Operating revenues $159,800 $241,241 Equity in earnings of unconsolidated affiliates 14,433 18,215 Operating and development expenses (171,521) (255,220) Interest and other income 11,247 6,785 Income from nonregulated businesses before interest and taxes $13,959 $11,021 Interest expense (22,139) (13,643) Income tax benefit 20,671 11,878 Net income $12,491 $9,256 Contribution of nonregulated businesses to NSP earnings per share $0.18 $0.13
NRG - NRG's earnings for the nine months ended Sept. 30 increased by 5 cents per share in 1997 compared with the same period in 1996 primarily due to higher tax credits from new NEO projects (as discussed previously) and lower business development costs, partially offset by higher interest costs on new debt financing issued in January 1996 and June 1997, and lower project income. The operating results of NRG projects in 1997 reflect lower earnings in MIBRAG, which were partially offset by higher earnings from new projects, including interests in Loy Yang and COBEE. Regarding business development costs, NRG experienced an increased level of such costs in early 1996 as it pursued several significant international and domestic projects. Until there is substantial assurance that a project under development will come to financial closure, such costs are expensed. EMI - EMI's earnings for the nine months ended Sept. 30, 1997 compared with the same period in 1996 were about the same. Non-regulated operating revenues and expenses decreased, while operating margins increased in 1997 compared to the same period in 1996 primarily due to EMI's curtailment of gas trading activity in the second quarter of 1996 which had negatively impacted operating margins during the first half of 1996. The increased margins were offset by losses incurred by Enerval due to the price volatility in the gas market, the write-off of a receivable from a customer who entered bankruptcy, and increased expenses related to the purchase of ESI and EMC, as discussed previously. Other - Eloigne's earnings for the nine months ended Sept. 30, 1997 were up 2 cents per share compared with the same period in 1996 mainly due to higher tax credits generated by new projects. Other nonregulated earnings for the nine month period are down 2 cents per share in 1997 mainly due to start-up costs incurred by NSP's new communications subsidiary Seren Innovations, Inc. LIQUIDITY AND CAPITAL RESOURCES The Company had $65 million in commercial paper debt outstanding as of Sept. 30, 1997. Commercial banks currently provide credit lines of approximately $300 million to the Company. These credit lines make short-term financing available in the form of bank loans, letters of credit and support for commercial paper sales. The Company has regulatory approval for up to $528 million in short-term borrowing levels. In addition to Company lines, commercial banks currently provide credit lines of approximately $248 million to wholly owned subsidiaries of the Company, including the NRG credit facility discussed later. At Sept. 30, 1997, approximately $38 million in borrowings were outstanding under these credit lines. In addition, approximately $34 million in letters of credit were outstanding, which reduced the credit lines available to subsidiaries at Sept. 30, 1997, and therefore left approximately $176 million of unused lines available at that date. In January 1997, stock options for the purchase of 286,700 shares were awarded under the Company's Executive Long-Term Incentive Award Stock Plan (the Plan). These options are not exercisable for approximately twelve months after the award date. As of Sept. 30, 1997, a total of 1,252,054 stock options were outstanding, which were considered as potential common stock equivalents for earnings per share purposes. During the first nine months of 1997, the Company has issued 52,328 new shares of common stock under the Plan pursuant to the exercise of options and awards granted in prior years. Under NSP's Dividend Reinvestment and Stock Purchase Plan, the Company has issued 156,017 shares of common stock during the first nine months of 1997. During 1997 the Company has issued an additional 69,488 shares of common stock to the Employee Stock Ownership Plan for dividends on Company shares held. As discussed in Note 2 to the Financial Statements, in January 1997 NSP issued $200 million in 7.875 percent trust-originated preferred securities that mature in 2037. Approximately $41 million of the proceeds were used in February 1997 to redeem the Company's $6.80 and $7.00 series of preferred stock. The balance of the proceeds were used to repay a portion of outstanding short-term borrowings. In May 1997, NRG finalized terms with a syndication of banks regarding a three-year $175 million revolving credit facility. The facility will be used for general corporate purposes, including letters of credit and interim funding of NRG project investments. Under the terms of the credit facility, NRG must maintain compliance with certain financial requirements, including maintenance of a minimum level of tangible net worth and a minimum ratio of tangible net worth to capitalization. NRG borrowed under this facility to finance the acquisition of PGC, as discussed previously. In June 1997, NRG issued $250 million of 7.5 percent Senior Notes due 2007 in a private placement under securities laws. NRG used the net proceeds to repay outstanding debt incurred primarily to fund its equity investment in the Loy Yang project, and for other general corporate purposes. In August of 1997, NRG filed with the Securities and Exchange Commission (SEC) a tender offer to exchange the existing notes for publicly-traded notes with the same interest rate and maturity. NRG is hopeful that the SEC will allow the filing to become effective by early December 1997 so that the tender offer can be completed shortly thereafter. In July 1997, Moody's Investors Service (Moody's) upgraded the credit ratings of the Company and its Wisconsin subsidiary. First mortgage and secured pollution control bonds are now rated `Aa3', unsecured pollution control bonds and counterparty ratings are now rated `A1', and the Company's preferred stock is now rated `a1'. In October 1997, Standard & Poor's (S&P) upgraded the credit ratings of the Company. These ratings reflect the views of Moody's and S&P, and an explanation of the significance of these ratings may be obtained from those agencies. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency. NRG's wholly owned subsidiary, NRG Energy Center is negotiating for financing of approximately $30 million to provide financing for the Minneapolis Energy Center. In September 1997, the Company sold 4.9 million shares of its common stock in a public offering at a price to the public of $49.5625 per share, with net proceeds to the Company of $237 million. The Company used the proceeds for general corporate purposes, including the retirement of $100 million of first mortgage bonds which matured Oct. 1, 1997, expenditures for the Company's construction program and the repayment of short-term borrowings. PART II. OTHER INFORMATION ITEM 1. 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 23, 1996, the U.S. Court of Appeals for the District of Columbia Circuit (the Court), in a lawsuit filed by the Company along with other major utilities, unanimously ruled that the Nuclear Waste Policy Act (Act) creates an unconditional obligation for the United States Department of Energy (DOE) to begin acceptance of spent nuclear fuel by Jan. 31, 1998. The DOE did not seek U.S. Supreme Court review. On Jan. 31, 1997, the Company along with 30 other electric utilities and 45 state agencies, filed a related lawsuit with the Court against the DOE requesting authority to withhold payments to the DOE under the Act. On Sept. 25, 1997, in oral arguments to the Court, the Company and the other parties asked for an order (a) compelling the DOE to begin accepting spent nuclear fuel, as required by the Act and the standard Contract between the utilities and the DOE, and to develop an enforceable plan for accepting spent nuclear fuel by a date certain; and (b) allowing utilities to escrow payments into the Nuclear Waste Fund until the DOE begins accepting spent nuclear fuel. The petition if granted, will be significant to NSP and the industry because the DOE will be mandated to take the above-stated actions concerning spent nuclear fuel. A ruling from the Court is expected before the end of 1997. In June 1997, the State of Minnesota passed legislation that would allow the State to begin placing in escrow the payments to the DOE under the Act. This escrow could be implemented if allowed by the Court in the pending case. Related to this matter, in June 1997 the DOE notified utilities that it likely will not meet its Jan. 31, 1998 deadline to accept spent nuclear fuel and that the delay in accepting spent nuclear fuel is "unavoidable" as defined in the standard Contract. The Company and other major utilities are challenging this determination by the DOE Contracting officer. For discussion of legal proceedings concerning temporary storage of spent nuclear fuel at the Prairie Island Nuclear Generating Plant, see Note 4 to the Financial Statements, incorporated herein by reference. On June 10, 1997, the Minnesota Office of the Attorney General (OAG) petitioned the MPUC to investigate the Company's meter reading and billing practices and to authorize the OAG to pursue civil penalties. On Sept. 18, 1997, the MPUC in Docket No. E, G-002/CI-97-863 voted to require the Company to submit a report about its practices and compliance with MPUC's meter reading and billing rules within 30 days. The Company expects a ruling by MPUC on the OAG petition in the first quarter of 1998. While the Company continues to seek to resolve this matter in a manner acceptable to the parties and MPUC, the Company cannot at the present time predict the outcome of this matter. FORM 8-K (A) EXHIBITS The following Exhibits are filed with this report: 27.01 Financial Data Schedule for the nine months ended Sept. 30, 1997. 99.01 Statement pursuant to Private Securities Litigation Reform Act of 1995. (B) REPORTS ON FORM 8-K The following reports on Form 8-K were filed either during the three months ended Sept. 30, 1997, or between Sept. 30, 1997 and the date of this report: July 28, 1997 (Filed July 30, 1997) Item 5. Other Events. Viking Voyageur Gas Transmission Company, 50 percent owned by Viking Gas Transmission Company, a wholly owned subsidiary of the Company, and NICOR Inc. announced agreement on a letter of intent to make NICOR a 20 percent owner of Viking Voyageur and to change the terminus of the Viking Voyageur natural gas transmission project from Volo, Illinois to Joliet, Illinois. Sept. 19, 1997 (Filed Sept. 19, 1997) Item 5. Other Events. On Sept. 17, 1997, the Company sold 4.5 million shares of its common stock in a public offering at a price of $49.5625 per share. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. NORTHERN STATES POWER COMPANY (Registrant) /S/ Roger D. Sandeen Vice President and Controller /S/ Edward J. McIntyre Vice President and Chief Financial Officer Date: NOVEMBER 14, 1997 EXHIBIT INDEX METHOD OF FILING EXHIBIT NO. DESCRIPTION DT 27.01 Financial Data Schedule DT 99.01 Statement pursuant to Private Securities Litigation Reform Act 1995 DT = Filed electronically with this direct transmission. EX-27 2
UT EXHIBIT 27.01 This schedule contains summary financial information extracted from the Consolidated Statements of Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows and is qualified in its entirety by reference to such financial statements. 1,000 9-MOS DEC-31-1996 SEP-30-1997 PER-BOOK 4,342,841 1,308,976 785,468 351,345 269,974 7,058,604 185,465 876,215 1,355,641 2,372,621 200,000 200,340 1,856,479 41,680 0 65,000 258,535 0 0 0 2,019,249 7,058,604 2,034,263 83,267 1,645,939 1,761,681 272,582 (27,719) 277,338 105,400 171,938 8,699 163,239 148,397 96,802 508,864 2.36 0 $(44,700) thousand of Common Stockholders' Equity is classified as Other Items-Capitalization and Liabilities. This represents the net of leveraged common stock held by the Employee Stock Ownership Plan and the currency translation adjustments. $(32,475) thousand of non-operating income tax benefit is classified as Income Tax Expense. The financial statement presentation includes this as a component of Other Income (Expense). Includes Income From Nonregulated Businesses Before Interest and Taxes, Allowance for Funds Used During Construction-Equity, Merger Costs, Other Utility Income (Deductions)-Net and Distributions on redeemable preferred securities of subsidiary trust.
EX-99 3 EXHIBIT 99.01 Northern States Power Company Cautionary Factors The Private Securities Litigation Reform Act of 1995 (the Act) provides a new "safe harbor" for forward-looking statements to encourage such disclosures without the threat of litigation providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward-looking statements have been and will be made in written documents and oral presentations of Northern States Power Company (the Company). Such statements are based on management's beliefs as well as assumptions made by and information currently available to management. When used in the Company's documents or oral presentations, the words "anticipate", "estimate", "expect", "objective", "possible", "potential" and similar expressions are intended to identify forward - -looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Company's actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following: - - Economic conditions including inflation rates and monetary fluctuations; - - Trade, monetary, fiscal, taxation, and environmental policies of governments, agencies and similar organizations in geographic areas where the Company has a financial interest; - - Customer business conditions including demand for their products or services and supply of labor and materials used in creating their products and services; - - Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities and Exchange Commission, the Federal Energy Regulatory Commission and similar entities with regulatory oversight; - - Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, the Company or any of its subsidiaries; or security ratings; - - Factors affecting utility and nonutility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, nuclear fuel or gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; nuclear or environmental incidents; or electric transmission or gas pipeline system constraints; - - Employee workforce factors including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages; - - Increased competition in the utility industry, including: industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market; - - Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options; - - Nuclear regulatory policies and procedures including operating regulations and used nuclear fuel storage; - - Social attitudes regarding the utility and power industries; - - Cost and other effects of legal and administrative proceedings, settlements, investigations and claims; - - Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets; - - Factors associated with nonregulated investments including conditions of final legal closing, foreign government actions, foreign economic and currency risks, political instability in foreign countries, partnership actions, competition, operating risks, dependence on certain suppliers and customers, domestic and foreign environmental and energy regulations; - - Most of the current project investments made by the Company's subsidiary, NRG Energy, Inc. (NRG) 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 project; - - Other business or investment considerations that may be disclosed from time to time in the Company's Securities and Exchange Commission filings or in other publicly disseminated written documents. EXHIBIT 99.01 The Company undertakes no obligation to publicly update or revise any forward- looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors pursuant to the Act should not be construed as exhaustive or as any admission regarding the adequacy of disclosures made by the Company prior to the effective date of the Act. -----END PRIVACY-ENHANCED MESSAGE-----