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

Item 1: Business-Electric Operations). The company's increased electric sales during 1994 over 1993, combined with increased costs per MWH for nuclear and fossil fuels and increased costs associated with capacity charges from the power purchase agreements with Manitoba Hydro-Electric Board, which went into effect in May 1993, resulted in the company's purchased power and fuel purchased under its interchange agreement with its parent to increase by approximately $10.7 million. Total interchange power also increased by $0.4 million as a result of increased operation and maintenance expenses and by $0.5 million as a result of increased fixed charges such as depreciation and property taxes.
Fuel for Electric Generation Fuel for electric generation, which represents the Company's portion of the NSP System's fuel generation, increased $2.2 million or 70.0 percent in 1994 from 1993. This is due to the Minnesota Company's decreased fuel generation combined with the Company's increased requirements due to the increased sales in 1994.
Gas Purchased for Resale This cost increased $2.0 million or 3.9 percent. A seven percent increase in total gas deliveries was responsible for $3.6 million of increase in 1994. A 1.3 percent decrease in prices resulted in the balance of the change from 1993.
Administrative and General, Other Operation and Maintenance The $1.6 million increase in Other Operation expense is partially due to demand side management expense increases ($0.7 million) and increases in transmission expenses charged from the Minnesota Company ($0.3 million). The remaining increases were related to postemployment benefit costs and general increases in operating expenses.
Depreciation and Amortization The increase in depreciation between 1994 and 1993 primarily reflects higher levels of depreciable plant, particularly shorter-lived computer equipment.
Property and General Taxes The property and general taxes increase is primarily due to higher gross receipts tax (a tax assessed on prior year revenues) as a result of 1993 revenues increasing over 1992 revenues.
Income Taxes $2.2 million of the decrease in income taxes in 1994 below 1993 is the result of a non-recurring adjustment to the balance of the tax accruals for prior years due to the recent conclusion by the Internal Revenue Service of audits of all the Company's tax years through 1988. The balance of the change is primarily attributable to the decrease in pretax book income. See Note 8 to the Financial Statements for a detailed reconciliation of effective tax rates and statutory rates.
Allowances for Funds Used During Construction (AFC) The differences in AFC for the reported periods are attributable to varying levels of qualifying construction and lower AFC rates associated with increased use of low-cost short-term borrowings.
Interest Charges In March 1993, the Company issued $110.0 million of first mortgage bonds due March 1, 2023 with an interest rate of 7-1/4%. The proceeds from these bonds were used to redeem $47.5 million of 9-1/4% bonds, $38.4 million of 9- 3/4%bonds, and $7.8 million of 9-1/4% bonds. In October 1993, the Company issued $40.0 million of first mortgage bonds due October 1, 2003 with an interest rate of 5-3/4%. The proceeds from these bonds were used to redeem $24.3 million of 7-3/4% bonds and $10.8 million of 4-1/2% bonds. These transactions caused decreases in the 1994 interest and amortization charges compared to the charges of 1993 because in 1993 for one year only, all costs associated with the redemption of these bonds were treated on a basis by which all savings of interest due to refinancing was offset by the amortization of the costs as required and approved by the PSCW.
In February 1995, the Company purchased $2.9 million of it's 9 1/8 Series bonds at the rate of 101 1/8.
Item 8 Financial Statements and Supplementary Data
See Item 14(a)-1 in Part IV for financial statements included herein.
See Note 12 to the financial statements for summarized quarterly financial data.
INDEPENDENT AUDITORS' REPORT
Northern States Power Company (Wisconsin):
We have audited the accompanying financial statements, of Northern States Power Company (Wisconsin), listed in the accompanying table of contents of Item 14(a)1. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements 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 financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1994 and 1993 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles.
Minneapolis, Minnesota January 27, 1995
Item 8 Financial Statements and Supplementary Data
Statements of Income and Retained Earnings Year Ended December 31
(Thousands of dollars) 1994 1993 1992
Operating Revenues Electric $ 374 777 $ 362 473 $ 345 289 Gas 76 715 72 760 61 071
Total 451 492 435 233 406
Operating Expenses Purchased and interchange power 174 144 162 510 156 196 Fuel for electric generation 5 414 3 185 2 034 Gas purchased for resale 53 484 51 501 41 814 Administrative and general 26 487 26 842 21 610 Other operation 44 260 43 351 42 254 Conservation 7 211 6 556 5 216 Maintenance 22 385 21 703 21 806 Depreciation and amortization 30 736 28 585 26 832 Property and general taxes 13 710 13 091 12 925 Income taxes 19 077 23 103 22 184
Total operating expenses 396 908 380 427 352 871
Operating Income 54 584 54 806 53 489
Other Income and Deductions Allowance for funds used during construction-equity 671 694 907 Other income and deductions 864 844 1 361
Total Other Income 1 535 1 538 2 268
Income Before Interest Charges 56 119 56 344 55 757
Interest Charges Interest on long-term debt 15 995 16 343 17 269 Other interest and amortization 2 060 2 406 857 Allowance for funds used during construction-debt (481) (411) (569) Total interest charges 17 574 18 338 17 557
Net Income 38 545 38 006 38 200 Retained Earnings, January 1 205 114 192 816 179 510 Dividends (24 826) (25 708)(24 894)
Retained Earnings, December 31 $ 218 833 $ 205 114 $ 192 816
See Notes to Financial Statements.
Item 8 Financial Statements and Supplementary Data
Statements of Cash Flow Year Ended December 31
(Thousands of dollars) 1994 1993 1992
Cash Flows from Operating Activities: Net Income $38 545 $38 006 $38 200 Adjustments to reconcile net income to cash from operating activities: Depreciation and amortization 32 382 33 580 28 179 Deferred income taxes 7 614 7 228 3 089 Investment tax credit adjustments (943) (948) (956) AFC-equity (671) (694) (907) Insurance receivable (3 091) Other (6 076) (2 440) Cash (used for) provided by changes in certain working capital items (9 568) 299 2 438
Net Cash Provided by Operating Activities58 192 77 471 67 603
Cash Flows from Financing Activities: Proceeds from issuance of long-term debt 0 146 587 0 Proceeds from issuance of notes payable-parent company 17 800 0 12 600 Repayment of notes payable-parent company 0 (800) 0 Repayment of long-term debt (990) (136 090) (1 415) Dividends paid to parent (24 826) (25 708) (24 894)
Net Cash Used for Financing Activities (8 016) (16 011) (13 709)
Cash Flows from Investing Activities: Construction expenditures capitalized (52 639) (59 954) (54 588) Decrease in construction payables (633) (2 143) (2 013) AFC-equity 671 694 907 Other 2 037 (489) 0
Net Cash Used for Investing Activities (50 564) (61 892) (55 694)
Net Decrease in Cash (388) (432) (1 800) Cash at Beginning of Period 449 881 2 681
Cash at End of Period $ 61 $ 449 $ 881
Cash (used for) provided by changes in certain working capital items: Accounts receivable-net $ 770 $ (1 597) $ 921 Materials and supplies( (4 708) (453) (647) Accounts payable and accrued liabilities 332 7 633 412 Payables to affiliated companies (2 655) 127 2 444 Income and other taxes accrued (4 174) (2 762) 634 Other 867 (2 649) (1 326)
Net $ (9 568) $ 299 $ 2 438
Supplemental Disclosures of Cash Flow Information: Cash paid during the year for: Interest (net of amount capitalized) $ 15 870 $ 17 440 $ 17 136 Income taxes $18 773 $ 18 825 $ 19 256 See Notes to Financial Statements.
Item 8 Financial Statements and Supplementary Data
Balance Sheets December 31
(Thousands of dollars) 1994 1993
Assets Utility Plant Electric-including construction work in progress: 1994, $14,599; 1993, $16,697 $ 836 665 $ 810 691 Gas 88 350 81 567 Other 54 675 43 279
Total 979 690 935 537
Accumulated provision for depreciation (344 675) (320 938)
Net utility plant 635 015 614 599
Other Property and Investments Nonutility property - at cost 3 082 3 157 Accumulated provision for depreciation (365) (364) Other investments - at cost which approximates market 3 974 4 094
Total other property and investments 6 691 6 887
Assets Cash 61 449 Accounts receivable 37 484 38 424 Accumulated provision for uncollectible accounts (538) (708) Materials and supplies - at average cost Fuel 3 413 2 293 Other 12 280 8 692 Accrued utility revenues 16 409 17 230 Prepayments and other 11 030 9 855 Deferred tax asset 1 415 1 254
Total current assets 81 554 77 489
Other Assets Unamortized debt expense 2 928 3 078 Regulatory assets 31 376 30 036 Federal Income tax receivable 3 307 0 Insurance receivable 3 091 0 Other 4 338 4 890
Total deferred debits 45 040 38 004
Total $ 768 300 $ 736 979
See Notes to Financial Statements.
Item 8 Financial Statements and Supplementary Data
December 31
(Thousands of dollars) 1994 1993
Liabilities and Equity Capitalization Common stock-authorized 870,000 shares of $100 par value; issued shares: 1994 and 1993, 862,000 $ 86 200 $ 86 200 Premium on common stock 10 461 10 461 Retained earnings 218 833 205 114
Total common equity 315 494 301 775
Long-term debt 213 700 217 600
Total capitalization 529 194 519 375
Current Liabilities Notes payable - parent company 41 300 23 500 Long-term debt due within one year 2 910 0 Accounts payable 14 415 15 264 Salaries, wages, and vacation pay accrued 6 028 5 481 Payables to affiliated companies (principally parent) 8 982 11 636 Federal income taxes accrued 0 1 606 Other taxes accrued 936 2 492 Interest accrued 5 485 4 823 Other 1 463 1 917
Total current liabilities 81 519 66 719
Deferred Credits Accumulated deferred income taxes 99 748 88 426 Accumulated deferred investment tax credits 22 332 23 653 Regulatory liability 17 961 22 416 Customer advances 5 543 5 071 Other 12 003 11 319
Total deferred credits 157 587 150 885
Commitments and Contingent Liabilities
Total $ 768 300 $ 736 979
See Notes to Financial Statements. NORTHERN STATES POWER COMPANY (WISCONSIN) NOTES TO FINANCIAL STATEMENTS
1. Summary of Accounting Policies
System of Accounts Northern States Power Company (Wisconsin), ("the Company"), maintains the accounting records in accordance with either the uniform system of accounts prescribed by the Federal Energy Regulatory Commission (FERC) or those prescribed by the Public Service Commission of Wisconsin (PSCW) and the Michigan Public Service Commission (MPSC), which systems are the same in all material respects.
Investment in Subsidiaries The Company carries its investment in its subsidiaries (Chippewa and Flambeau Improvement Company, 75.86% owned; NSP Lands, Incorporated, 100% owned; and Clearwater Investments, Incorporated, 100% owned) at cost plus equity in earnings since acquisition. The impact of consolidation of these subsidiaries is considered immaterial to the Company's financial position.
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 overheads and allowance for funds used during construction (AFC). 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.
Insurance Receivable The Company has incurred repair costs on a gas turbine that will be recovered from insurance. These costs have caused the Company to pay out approximately $ 3 million.
Federal Income Tax Receivable The Company has filed an amended tax return for the year 1992 which has resulted in a reduction in taxes owed of approximately $3.3 million. The two major items for the Wisconsin Company were the additional deduction for the prepaid Wisconsin Annual License Fee and an additional deduction for a change in Depreciation Expense.
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 fund utility construction, to qualified Construction Work in Progress (CWIP). The rates used for the FERC calculation were 7.55 percent in 1994, 7.93 percent in 1993 and 8.78 percent in 1992. The rates used for the PSCW calculation were 10.13 percent in 1994, 10.84 percent in 1993 and 11.52 percent in 1992. The amount of AFC capitalized as a construction cost in CWIP is credited to other income and interest charges. AFC amounts capitalized in CWIP are included in utility rate base for establishing utility service rates.
Related Party Transactions 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 Minnesota Company and Viking, which are allowed in utility rates.
Depreciation For financial reporting purposes, depreciation is computed on the straight-line method based on the annual rates certified by the PSCW and MPSC for the various classes of property. Depreciation provisions, as a percentage of the average balance of depreciable property in service, were 3.45% in 1994, 3.40% in 1993, and 3.38% in 1992.
Revenues Customers' meters are read and bills rendered on a cycle basis. The Company accrues the amount of estimated unbilled revenues for services provided from the monthly meter reading date to month-end. The current asset, accrued utility revenues, is being adjusted monthly, with a corresponding adjustment to revenues, to reflect changes in unbilled revenues.
Regulatory Deferrals As a regulated utility, the Company accounts for certain income and expense items under the provisions of SFAS No. 71 - Accounting for the Effects of Certain Types of Regulation. In doing so, certain costs which would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates. Likewise, certain credits which would otherwise be reflected as income are deferred as regulatory liabilities based on expected flowback to customers in future rates. Management's expected recovery of deferred costs and expected flowback of deferred credits is generally based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are being amortized consistent with ratemaking treatment as established by regulators.
Income Taxes The Company records income taxes in accordance with Statement of Financial Accounting Standards No. 109 (SFAS 109) - Accounting For Income Taxes. SFAS 109 requires the use of the liability method of accounting for deferred income taxes. Before 1993, the Company followed Statement of Accounting Standards No. 96 (SFAS 96) - Accounting for Income Taxes, resulting in substantially the same accounting for the Company as SFAS No. 109.
Income taxes are deferred for 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 tax law to be in effect when the temporary differences reverse. Due to the effects of regulation, income tax expense is provided for the reversal of some temporary differences previously accounted for by the flow-through method. Deferred income tax expense for 1994, 1993, and 1992 consists primarily of excess tax depreciation over book depreciation of $4,800,000, $5,413,000, and $5,526,000, respectively.
Investment tax credits are deferred and amortized over the estimated lives of the related property.
Purchased Tax Benefits The Company purchased tax-benefit transfer leases under the Safe Harbor Lease provisions of the Economic Recovery Tax Act of 1981. For both financial reporting and regulatory purposes, the Company is amortizing the difference between the cost of the purchased tax benefits and the amounts to be realized through reduced current income tax liabilities over the remaining terms of the lease after the initial investments have been recovered.
Environmental Costs Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. When a single estimate of the liability cannot be determined, the low end of the estimated range is recorded. Costs are charged to expense (or deferred as a regulatory asset based on expected recovery from customers in future rates) if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures related to facilities currently in use (such as pollution control equipment), the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised, and remediation efforts proceed. For sites where NSP has been designated as one of several potentially responsible parties, the amount accrued represents NSP's estimated share of the cost. NSP intends to treat any future costs related to decommissioning and restoration of its power plants and substation sites as a removal cost of retirement through plant depreciation expense.
2. Rate Matters
The Company filed a proposal for a new high load factor rate with the PSCW in November, 1994, that becomes effective January 1, 1995. Under the proposal, qualifying customers would receive a credit on their bills of up to 3.0% depending on their load factor. This is expected to reduce 1995 revenues by approximately $1.5 million.
On December 23, 1993, the PSCW issued an order approving a $1.41 million (2.0 percent) increase on an annual basis in the Company's gas rates. A January 1, 1994 effective date was authorized for these rate changes. No change in the retail electric rates was requested.
The Company will file a submittal in June 1995 as required by the PSCW biennial filing requirement.
In May, 1994, the Company offered its municipal wholesale customers a discount of one to two percent off the FERC authorized rate for a long-term full requirements commitment between five and ten years with comparable cancellation notices. Five of the ten municipal wholesale customers signed up for the discounts. The total annual decrease in revenues is approximately $80,000.
3. Accounting Changes
Postemployment Benefits Effective January 1, 1994, the Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 112---Employer's Accounting for Postemployment Benefits. This standard required the accrual of certain postemployment costs (such as injury compensation and severance) that are payable in future time periods. The annual expense for costs accrued under SFAS No. 112 is not materially different than amounts recognized under the Company's prior accounting method. The Company has recorded as expense its full liability related to such costs in 1994.
4. Investments Accounted for by the Equity Method
NSP has subsidiaries with investments in domestic affordable housing and real estate projects. The equity method of accounting is applied to such investments.
5. Long-Term Debt
First Mortgage Bonds - less reacquired bonds of $490 and $0 at December 31, 1994 and 1993, respectively:
December 31 December 31 Series due: 1994 1993
Apr. 1, 2021, 9-1/8% $ 48 010 $ 49 000 Mar. 1, 2023, 7 1/4% 110 000 110 000 Oct. 1, 2003, 5 3/4% 40 000 40 000
Total $198 010 $199 000
Less April 1, 2021, 9 1/8% bonds redeemed in February 1995 2 910
Net $195 100 $199 000
City of LaCrosse Resource Recovery Revenue Bonds - Series due Nov. 1, 2011, 7 3/4% 18 600 18 600
Total long-term debt $ 213 700 $ 217 600
The Supplemental and Restated Trust Indenture dated March 1, 1991, permits an amount of established Permanent Additions to be deemed equivalent to the payment of cash necessary to redeem 1% of the highest principal amount of each series of first mortgage bonds (other than pollution control financing) at any time outstanding. This Supplemental and Restated Trust Indenture became effective for the Company on October 1, 1993.
On March 16, 1993 the Company issued $110.0 million of first mortgage bonds due March 1, 2023, with an interest rate of 7 1/4%. NSP entered into an interest rate swap agreement with $20.0 million of this first mortgage bonds. This agreement effectively converts the interest costs of this debt issue from fixed to variable rates based on six-month London Interbank Offered Rates (LIBOR) with the rates changing semi-annually, March 1 and September 1. This Series is due March 1, 2023, has a Swap Agreement Term dated March 1, 1998 and had a net effective interest rate of 7.43% at December 31, 1994.
Market risks associated with this agreement results 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. While such agreements are not reflected on NSP's balance sheets, interest rate swap transactions are recognized as an adjustment of interest expense over the terms of the agreements. 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 swap. If the interest rate swap had been terminated at Dec. 31, 1994, $1.7 million would have been payable by NSP while the present value of the fixed rate debt issued with the swaps was $3.1 million below par value.
On February 1, 1995, the Company redeemed $2.9 million of its 9 1/8% bonds at 101-1/8%; this amount has, therefore, been classified as current on the December 31, 1994 financial statements.
Maturities on capital leases in the next five years are approximately $943,000, $1,034,000, $724,000, $409,000, and $92,000, respectively for the years 1995-1999.
Except for minor exclusions, all real and personal property is subject to the lien of the Company First Mortgage Bond Trust Indenture.
6. Commitments and Contingent Liabilities
The Company presently estimates capital expenditures will be $55.2 million in 1995 and $286 million for 1995-99.
Rentals under operating leases were approximately $1,792,000, $2,651,000, and $2,547,000, for 1994, 1993, and 1992, respectively.
Although the Company does not own a nuclear facility, any assessment made against Northern States Power Company (Minnesota), the parent company, ("Minnesota Company") and under the Price- Anderson liability provisions of the Atomic Energy Act of 1954, would be a cost included under the Interchange Agreement (Note 9) and the Company would be charged its proportion of the assessment. Such provisions set a limit of $8.9 billion for public liability claims that could arise from a nuclear incident. The parent company has secured insurance of $200 million to satisfy such claims. The remaining $8.7 billion of exposure is funded by the Secondary Financial Protection Fund, a fund available from assessments by the Federal government in the event of nuclear incidents. The parent company is subject to an assessment of $79.3 million for each of its three licensed reactors to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States with a maximum funding requirement of $10 million per reactor during any one year.
The NSP Wisconsin policy is to proactively prevent adverse environmental impacts, regularly monitor operations to ensure the environment is not adversely affected, and take timely corrective actions where past practices have had a negative impact on the environment. Significant resources are dedicated to environmental training, monitoring and compliance matters. The Company strives to maintain compliance with all applicable environmental laws. A preliminary allocation has been established for one of the landfills for those contributing any type of wastes to it. Based on the preliminary allocation of costs, the Company's share of one of the landfills would be less than $20,000. An allocation has not yet been made on the second landfill site.
On March 2, 1995, the Wisconsin Department of Natural Resources (WDNR) notified the Company that it is a PRP on a creosote/coal tar contamination site in Ashland, WI. The Company has informed the WDNR of its belief that two sites exist. The first site, formerly a coal gas plant site, is NSP property. The second site is adjacent to the NSP site and is not owned by the Company. An existing condition report has been completed on an adjacent site. An estimate of site remediation costs, and the extent of the Company's responsibility, if any, for sharing such costs, is not known at this time. Investigations are underway to determine the Company's responsibility as well as that of predecessor companies contributing to the contamination on the adjacent site. The current estimate of the Company's share of future remediation costs at the NSP site is less than $750,000. This estimate is not based upon a formal remediation investigation and feasability study. To the Company's knowledge, no study has been completed for the adjacent site, that describes remedial alternatives and clean-up cost estimates. The Company intends to seek rate recovery of significant costs it incurs associated with the clean-up of either Ashland Site.
7. Fair Value of Financial Instruments
Statement of Financial Accounting Standards No. 107 (SFAS 107) - Disclosures About Fair Value of Financial Instruments became effective in 1992. For cash and investments, the carrying amount approximates fair value. The fair value of the Company's long term debt is estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities. The estimated fair value of the Company's long term debt (including debt due within one year classified as current) of $216.6 million at December 31, 1994, and $217.6 million at December 31, 1993, is $196.2 million and $233.3 million, respectively.
8. Pension Plans and Other Post Retirement Benefits
Employees of the Company participate in the Northern States Power Company Pension Plan. This noncontributory defined benefit pension plan covers substantially all employees. Benefits are based on a combination of years of service, the employees highest average pay for 48 consecutive months and Social Security benefits. The Company's portion of annual pension costs was $(631,000) for 1994, $1,236,000 for 1993, and $2,400,000 for 1992.
Until 1993, for financial reporting and regulatory purposes, the Company's pension expense was determined and recorded under the aggregate cost method, using market value of assets of the trust fund. Statement of Financial Accounting Standards No. 87 - Employers' Accounting for Pensions (SFAS 87) provides that any difference between the pension expense recorded for rate making purposes and the amounts determined under SFAS 87 should be recorded as an asset or liability on the balance sheet.
Effective January 1, 1993, for financial reporting and regulatory purposes, the Company's pension expense was determined and recorded under the SFAS-87 method and the Company's accumulated SFAS-87 asset is being amortized over a 15-year period.
Net periodic pension costs for the total (the Company and Minnesota Company) plan include the following components: 1994 1993 1992
(Thousands of dollars)
Service Cost - benefits earned during the period $ 27 536 $ 25 015 $ 24 080
Interest cost on projected benefit obligation 65 107 71 075 69 853
Actual return on assets (12 668)(152 019)(115 455) Net amortization and deferral (82 114) 66 299 39 019
Net periodic pension cost determined under SFAS 87 (2 139) 10 370 17 497
Expenses recognized (deferred) due to actions of regulators 3 922 5 117 2 741 Pension expense recorded during the period 1 783 15 487 20 238
Portion of expense recognized for early retirement program 0 0 ( 165) Net periodic pension cost recognized for ratemaking $ 1 783 $ 15 487 $ 20 073
The funding status for the total plan is as follows:
Actuarial present value of benefit obligation: Vested $ 571 254 $ 655 002 Nonvested 120 420 139 346 Accumulated benefit obligation $ 691 674 $ 794 348
Projected benefit obligation $ 836 957 $974 160 Plan assets at fair value 1 165 584 1 244 650
Plan assets in excess of projected benefit obligation (328 627) (270 490) Unrecognized prior service cost (21 538) (22 580) Unrecognized net (gain) 370 289 315 049 Unrecognized net transitional (asset) 691 767
Net pension liability recorded $ 20 815 $ 22 746
The weighted average discount rate used in determining the actuarial present value of the projected obligation was 8% in 1994 and 7% in 1993. The rate of increase in future compensation levels used in determining the actuarial present value of the projected obligation was 5% in 1994 and 1993. The assumed long-term rate of return on assets used for cost determinations under SFAS 87 was 8% in 1994, 1993 and 1992. Plan assets consist principally of common stock of public companies and U.S. Government Securities.
Effective Jan. 1, 1993, the Company adopted the provisions of SFAS No. 106 - Employers' Accounting for Postretirement Benefits Other Than Pensions. SFAS No. 106 requires that the actuarially determined obligation for postretirement health care and death benefits is 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 the Company's pre-1993 policy of recognizing benefit costs on a cash basis after retirement. In conjunction with the adoption of SFAS No. 106, for financial reporting purposes, NSP elected to amortize on a straight-line basis over 20 years the unrecognized accumulated postretirement benefit obligation (APBO) of approximately $215.6 million (including the Company and Minnesota Company) 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 the Company generally prefers to continue using internal funding of benefits paid and accrued, there have been some external funding requirements imposed by the Company's regulators, as discussed below, including the use of tax advantaged trusts. Plan assets held in such trusts as of Dec. 31, 1994, consisted of investments in equity mutual funds and cash equivalents. The
following table sets forth the total (the Company and Minnesota Company) health care plans funded status at December 31.
(Millions of dollars) 1994 1993
APBO: Retirees $132.2 $120.2 Fully eligible plan participants 21.5 18.8 Other active plan participants 79.4 90.8 Total APBO 233.1 229.8 Plan Assets 8.0 6.1 APBO in excess of plan assets 225.1 223.7 Unrecognized net actuarial gain (loss) 2.3 (1.3) Unrecognized transition obligation (194.0) (204.8) Postretirement benefit obligation included in balance sheet $ 33.4 $ 17.6
The assumed health care cost trend rate used in measuring the APBO at Dec. 31, 1994 and 1993, respectively, were 11.0 and 14.1 percent for those under age 65 and 7.5 and 8.0 percent for those over age 65. The assumed cost trend rates are expected to decrease each year until they reach 5.5 percent for both age groups in the year 2004, after which they are assumed to remain constant. A one percent increase in the assumed health care cost trend rate for each year would increase the APBO as of December 31, 1994, by approximately 13 percent and service and interest cost components of the net periodic postretirement cost by approximately 16 percent. The assumed discount rate used in determining the APBO was 8 percent for Dec. 31, 1994, 7 percent for Dec. 31, 1993 and 7 percent for Jan. 1, 1993, compounded annually. The assumed long- term rate of return on assets used for cost determinations under SFAS No. 106 was 8 percent for all periods. While the 1994 assumption changes had no effect on 1994 benefit costs, the effect of the changes in 1995 is expected to be a cost increase of approximately $0.6 million (for the Company and the Minnesota Company). Similarly, the assumption changes made for the Dec. 31, 1993 calculations had no effect on 1993 benefit costs, but decreased 1994 costs by approximately $2 million (for the Company and the Minnesota Company).
In 1992, the Company recognized $1.9 million as the cost attributable to postretirement health care and death benefits based on payments made. The net annual periodic postretirement benefit cost recorded for 1994 and 1993 consists of the following components (millions of dollars):
1994 1993 Service cost-benefits earned during the year $ 0.6 0.6 Interest cost (on service cost and APBO) 2.3 2.4 Amortization of transition obligation 1.5 1.5
Return on assets (.2) (.1) Net periodic postretirement health care cost under SFAS No. 106 4.2 4.4
The Company's regulators have allowed full recovery of increased benefit costs under SFAS No. 106, effective in 1993. External funding was required in Wisconsin and Michigan to the extent it is tax advantaged. The FERC has required external funding for all benefits paid and accrued under SFAS No. 106. Funding began for both retail and FERC in 1993.
401(k) NSP has a contributory, defined contribution Retirement Savings Plan (the Plan), which complies with section 401-K of the Internal Revenue code and covers substantially all employees. The NSP match to this Plan began in 1994 and is required to match a specified amount of employee contributions. The Company's contribution to the Plan in 1994 was $0.3 million. 9. Parent Company and Intercompany Agreements
The Company is wholly-owned by Northern States Power Company (Minnesota). The electric production and transmission costs of the NSP system are shared by the Company and the Minnesota Company. A FERC approved agreement (Interchange Agreement) between the Company and the Minnesota Company provides for the sharing of all costs of electric generation and transmission facilities of the NSP System, including capital costs. Billings under the Interchange Agreement and an intercompany gas agreement which are included in the statement of income are as follows: Year Ended December 31
1994 1993 1992
(Thousands of dollars) Operating revenues: Electric $ 73 503 $ 72 162 $ 70 671 Gas 50 56 55 Operating expenses: Purchased &interchg power 174 144 162 510 156 196 Gas purchased for resale 227 267 214 Other operation 12 824 12 515 11 668
10. Regulatory Assets and Liabilities
The following summarizes the individual components of unamortized regulatory assets and liabilities shown on the Balance Sheet at Dec. 31:
(Thousands of dollars) Amortization Period 1994 1993
AFC recorded in plant on a net-of-tax basis Plant Lives 8 325 8 795 Losses on reacquired debt Term of Debt 10 303 10 857 Conservation and energy management programs Up to 10 years 10 622 8 291 Pensions and other 3-15 years 2 126 2 093 Total Regulatory Assets 31 376 30 036
Excess deferred income taxes collected from customers 2 853 5 914 Investment tax credit deferrals 14 950 15 841 Fuel refunds and other 158 661
Total Regulatory Liabilities 17 961 22 416
The AFC regulatory asset and the tax-related regulatory liabilities result from the Company's adoption of SFAS No. 96 in 1988 and SFAS No. 109 in 1993. The excess deferred income tax liability represents the net amount expected to be reflected in future customer rates based on the collection in prior ratemaking of deferred income tax amounts in excess of the actual liabilities currently recorded by the Company. This excess is the net effect of the use of "flow through" tax accounting in prior ratemaking and the impact of changes in statutory tax rates in 1981, 1986-87 and 1993. This regulatory liability will change each year as the related deferred income tax liabilities reverse.
11. Income Tax Expense
The Company is included in the consolidated Federal income tax return filed by the Minnesota Company and files separate state returns for Wisconsin and Michigan. The Company records current and deferred income taxes at the statutory rates as if it filed a separate return for Federal income tax purposes. All tax payments are made directly to the taxing authorities.
The total income tax expense differs from the amount computed by applying the Federal income tax statutory rate of 35% to net income before income tax expense. The reasons for the difference are as follows:
1994 1993 1992
(Thousands of dollars)
Tax computed at statutory rate $ 20 074 $ 21 387 $20 434 Increases (decreases) in tax from: State income taxes, net of Federal income tax benefit 2 393 3 165 3 037 Allowance for funds used during construction (235) (243) (284) Investment tax credit adjustments - net (943) (948) (956) Use of the flow-through method for depreciation in prior years 551 474 673 Effect of tax rate changes for plant related items (498) (487) (420) Gain on sale of tax benefit transfer leases 0 (88) 0 Non-recurring adjustment for tax accrual of prior years (2 430) Other - net (101) (162) (583) Total income tax expense $ 18 811 $ 23 098 $ 21 901
Effective income tax rate 32.8% 37.8% 36.4%
Income tax expense is comprised of the following: Included in income taxes: Current Federal tax expense 8 075 $ 12 919 $15 340 Current state tax expense 2 810 3 180 3 598 Deferred Federal tax expense 7 967 6 173 3 075 Deferred state tax expense 1 168 1 778 1 127 Investment tax credit adjustments - net (943) (948) (956) Total 19 077 23 103 22 184
Included in income deductions: Current Federal tax expense 1 039 875 953 Current state tax expense 216 (90) (123) Deferred Federal and state tax expense (1 521) (790) (1 113) Total income tax expense $ 18 811 $ 23 098 $ 21 901 The components of the Company's net deferred tax liability at Dec. 31 were as follows: (Thousands of dollars) 1994 1993
Deferred tax liabilities: Differences between book and tax bases of property $ 98 526 $ 91 195 Tax benefit transfer leases 4 950 6 146 Regulatory assets 11 626 11 371 Other 3 332 398 Total deferred tax liabilities 118 434 109 110
Deferred tax assets: Deferred investment tax credits 7 409 9 487 Regulatory liabilities 8 955 8 726 Deferred compensation accrued vacation and other reserves not currently deductible 3 155 3 193 Other 582 532 Total deferred tax assets 20 101 21 938
Net deferred tax liability $ 98 333 $ 87 172 The Omnibus Budget Reconciliation Act of 1993 (Act) was signed into law on August 10, 1993, and increased the federal corporate income tax rate from 34 percent to 35 percent retroactive to January 1, 1993. Deferred tax liabilities were increased for the rate change by $2.7 million. However, due to the effects of regulation, earnings were reduced only by immaterial adjustments to deferred tax liabilities related to nonutility operations.
12. Segment Information
Year Ended December 31
1994 1993 1992
(Thousands of dollars) Operating revenues: Electric $374 777 $362 473 $345 289 Gas 76 715 72 760 61 071 Total operating revenues $451 492 $435 233 $406 360
Operating income before income taxes: Electric $ 67 164 $ 73 012 $ 70 202 Gas 6 498 4 897 5 471 Total operating income before income taxes $ 73 662 $ 77 909 $ 75 673
Depreciation and amortization: Electric $26 836 $ 25 179 $ 23 870 Gas 3 900 3 406 2 962 Total depreciation & amortization $ 30 736 $ 28585 $26832
Construction expenditures: Electric $ 42 820 $ 49 664 $ 44 332 Gas 9 895 10 258 10 235 Total construction expenditures $ 52 715 $ 59 922 $ 54 567
Net utility plant: Electric $575 059 $560 999 $537 576 Gas 59 956 53 600 47 419 Total net utility plant 635 015 614 599 584 995
Other corporate assets 133 285 122 380 109 474 Total assets $768 300 $736 979 $694 469
13. Short-Term Borrowings
The Company had bank lines of credit aggregating $1,000,000 at December 31, 1994. Compensating balance arrangements in support of such lines of credit were not required. These credit lines make short-term financing available by providing bank loans. During 1994 and 1993 there were no bank loans outstanding as the Company obtained short-term borrowings from the Minnesota Company at the Minnesota Company's average daily interest rate, including the cost of their compensating balance requirements.
The Company had short-term borrowings of the following for the years ended December 31,
1994 1993 1992
Balance at the end of the period 41 300 23 500 24300 Weighted average interest rate 5.0% 3.3% 3.5% Maximum amount outstanding during the period 45 700 28 200 24 300 Average amount outstanding during the period 13 124 10 693 8 837 Weighted average interest rate during the period 5.0% 3.4% 3.7%
14. Common Stock
The Company's common shares have a par value of $100 per share. At December 31, 1994 and 1993, 870,000 shares were authorized and 862,000 shares were issued.
15. Summarized Quarterly Financial Data (Unaudited)
Quarter Ended
March 31, June 30, September 30 December31 1994 1994 1994 1994 (Thousands of dollars)
Operating revenues $ 134 004 $ 100 105 $ 101 100 $ 116 283
Operating income 22 268 7 273 9 416 15 627
Net income 18 306 3 441 4 894 11 904
Quarter Ended
March 31, June 30, September 30 December31 1993 1993 1993 1993 (Thousands of dollars)
Operating revenues $ 124 285 $ 97 107 $ 97 821 $ 116 020
Operating income 20 080 10 199 7 986 16 541
Net income 15 857 6 062 3 762 12 325
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
During 1994 there were no disagreements with the Company's independent certified public accountants on accounting procedures or accounting and financial disclosures.
PART III
Part III of Form 10-K has been omitted from this report in accordance with conditions set forth in general instructions J (1) (a) and (b) of Form 10-K for wholly-owned subsidiaries.
Item 10. Directors and Executive Officers of the Registrant
Item 11. Executive Compensation
Item 12. Security Ownership of certain beneficial Owners and Management
Item 13. Certain Relationships and Related Transactions
PART IV
Item 14. Exhibits, Financial Statement Schedules Page and Reports on Form 8-K
(a) 1. Financial Statements Included in Part II of this report:
Report of Independent Public Accountants. 13
Statements of Income and Retained Earnings for the three years ended December 31, 1994. 14
Statements of Cash Flows for the three years ended December 31, 1994. 15
Balance Sheets, December 31, 1994 and 1993. 16
Notes to Financial Statements. 18
2. Financial Statement Schedules
Schedules above are omitted because of the absence of the conditions under which they are required or because the information required is included in the financial statements or the notes.
3. Exhibits
* indicates incorporation by reference
3.01*Restated Articles of Incorporation as of December 23, 1987. (Filed as Exhibit 30.01 to Form 10-K Report 10-3140 for the year 1987)
3.02* Copy of the By-Laws of the Company as amended August 19, 1992. (Filed as Exhibit 3.02 to Form 10-K Report 10-3140 for the year 1992)
4.01* Copy of Trust Indenture, dated April 1, 1947, From the Wisconsin Company to First Wisconsin Trust Company. (Filed as Exhibit 7.01 to Registration Statement 2-6982)
4.02* Copy of Supplemental Trust Indenture, dated March 1, 1949. (Filed as Exhibit 7.02 to Registration Statement 2- 7825)
4.03* Copy of Supplemental Trust Indenture, dated June 1, 1957. (Filed as Exhibit 2.13 to Registration Statement 2- 13463)
4.04* Copy of Supplemental Trust Indenture, dated August 1, 1964. (Filed as Exhibit 4.20 to Registration Statement 2- 23726)
4.05* Copy of Supplemental Trust Indenture, dated December 1, 1969. (Filed as Exhibit 2.03E to Registration Statement 2- 36693)
4.06* Copy of Supplemental Trust Indenture, dated September 1, 1973. (Filed as Exhibit 2.01F to Registration Statement 2- 48805)
4.07* Copy of Supplemental Trust Indenture, dated February 1, 1982. (Filed as Exhibit 4.01G to Registration Statement 2- 76146)
4.08* Copy of Supplemental Trust Indenture, dated March 1, 1982. (Filed as Exhibit 4.08 to form 10-K Report 10-3140 for the year 1982)
4.09* Copy of Supplemental Trust Indenture, dated June 1, 1986. (Filed as Exhibit 4.09 to Form 10-K Report 10-3140 for the year 1986)
4.10* Copy of Supplemental Trust Indenture, dated March 1, 1988. (Filed as Exhibit 4.10 to Form 10-K Report 10-3140 for the year 1988)
4.11* Copy of Supplemental and Restated Trust Indenture, dated March 1, 1991. (Filed as Exhibit 4.01K to Registration Statement 33-39831)
4.12* Copy of Supplemental Trust Indenture, dated April 1, 1991. (Filed as Exhibit 4.01 to Form 10-Q Report 10-3140 for the quarter ended March 31, 1991)
4.13* Copy of Supplemental Trust Indenture, dated March 1, 1993. (Filed as Exhibit to Form 8-K Report dated March 3, 1993)
4.14* Copy of Supplemental Trust Indenture, dated October 1, 1993. (Filed as Exhibit 4.01 to Form 8-K Report dated September 21, 1993) 10.01 *Copy of MAPP Agreement, dated March 31, 1972, between the local power suppliers in the North Central States area. (Filed as Exhibit 5.06B to Registration Statement 2- 44530)
10.02* Copy of Interchange Agreement dated September 17, 1984, and Settlement Agreement dated May 31, 1985, between the Company, the Minnesota Company and LSDP. (Filed as Exhibit 10.10 to Form 10-K Report 10-3140 for the year 1985)
(b) Reports on Form 8-K
On December 20, 1994, a Form 8-K was filed reporting (as Item 4, Changes in Registrant's Certifying Accountant and Item 7, Financial Statements and Exhibits), the Company's change in Certifying Accountant.
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 authorized. NORTHERN STATES POWER COMPANY
/s/ John A. Noer President and Chief Executive
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.
/s/ John A. Noer (Principal Executive Officer)
/s/ /s/ M. N. Gregerson H. Lyman Bretting Vice President-Customer Services Director
/s/ /s/ A. G. Schuster P. M. Gelatt Vice President Director Power Delivery and Generation
/s/ /s/ Patrick D. Watkins Wayne E. Harrison Vice President-Corporate Services Director
/s/ /s/ John P. Moore, Jr. Loren L. Taylor General Counsel and Secretary Director
/s/ /s/ Kenneth J. Zagzebski Ray A. Larson, Jr. Controller Director (Principal Accounting Officer)
/s/ /s/ Neal A. Siikarla Larry G. Schnack Treasurer Director (Principal Financial Officer) 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 authorized. NORTHERN STATES POWER COMPANY
John A. Noer President and Chief Executive
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.
John A. Noer President and Director (Principal Executive Officer)
M. N. Gregerson H. Lyman Bretting Vice President-Customer Services Director
A. G. Schuster P. M. Gelatt Vice President Director Power Delivery and Generation
Patrick D. Watkins Wayne E. Harrison Vice President-Corporate Services Director
John P. Moore, Jr. Loren L. Taylor General Counsel and Secretary Director
Kenneth J. Zagzebski Ray A. Larson, Jr. Controller Director (Principal Accounting Officer)
Neal A. Siikarla Larry G.Schnack Treasurer Director (Principal Financial Officer) UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-K (Mark One)
X Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (fee required)
or
Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (no fee required)
For the fiscal year ended December 31, 1994 Commission file number: 10-3140
Northern States Power Company, a Wisconsin corporation, meets the conditions set forth in general instruction J (1) (a) and (b) of Form 10-K and is therefore filing this form with the reduce disclosure format. (In general instruction J(2)
Northern States Power Company (Exact name of registrant as specified in its charter) Wisconsin 39-0508315 (State or other jurisdiction of (I.R.S. employer identification number) incorporation or organization) 100 North Barstow Street 54702-0008 (Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code (715) 839-2621
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
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 registrant's classes of common stock as of the latest practicable date.
Class Outstanding at March 23, 1995 Common Stock, $100 Par Value 862,000 Shares
All outstanding common stock is owned beneficially and of record by Northern States Power Company, a Minnesota corporation.
Documents Incorporated by Reference
None
INDEX Page No. PART I Item 1 Business . . . . . . . . . . . . . . . . . . . . . . . 1
REGULATION AND RATES Regulation . . . . . . . . . . . . . . . . . . . .. . 1 Rate Changes . . . . . . . . . . . . . . . . . . .. . 2 Fuel and Purchased Gas Adjustment Clauses. . . . .. . 3 Demand Side Management . . . . . . . . . . . . . .. . 3
ELECTRIC OPERATIONS Competition. . . . . . . . . . . . . . . . . .. . . . 4 NSP System . . . . . . . . . . . . . . . . . .. . . . 4 Capability and Demand. . . . . . . . . . . . .. . . . 5 Interchange Agreement. . . . . . . . . . . . .. . . . 6 Electric Power Pooling Agreements. . . . . . .. . . . 6 Fuel Supply. . . . . . . . . . . . . . . . . .. . . . 6 Electric Operating Statistics . . . . . . . .. . . . 7 GAS OPERATIONS . . . . . . . . . . . . . . . . .. . . . 7
ENVIRONMENTAL MATTERS . . . . . . . . . . . .. . . . . 8
CONSTRUCTION AND FINANCING . . . . . . . . . . . . . . 9
EMPLOYEES AND EMPLOYEE BENEFITS. . . . . . . .. . . . . 10
Item 2



Item 2 Properties . . .. . . . . . . . . . . . . . . . . . . . 12 Item 3

Item 3 Legal Proceedings. . .. . . . . . . . . . . . . . . . . 12 Item 4

Item 4 Submission of Matters to a Vote of Security Holders . . .. . . . . . . . . . . . 13
PART II Item 5

Item 5 Market Price of and Dividends on the Registrant's Common Equity and Related Stockholder Matters. . . . . . . . 14 Item 6

Item 6 Selected Financial Data. . . . . . . . . . . . . . . . . 14 Item 7

Item 7 Management's Discussion and Analysis . . . . . . . . . . 14 Item 8


Item 8 Financial Statements and Supplementary Data. . . . . . . 17 Item 9

Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . 32
PART III Item 10



Item 10 Directors and Executive Officers of the Registrant . . . . . . . . . . . . . . . . . . 33 Item 11

Item 11 Executive Compensation . . . . . . . . . . . . . . . . . 33 Item 12

Item 12 Security Ownership of Certain Beneficial Owners and Management. . . . . . . . . . . . . 33 Item 13

Item 13 Certain Relationships and Related Transactions . . . . . 33
PART IV Item 14

Item 14 Exhibits, Financial Statement Schedules and Reports on Form 8-K. . . . . . . . . . . . . . 34
SIGNATURES . . . .. . . . . . . . . . . . . . . . . . . . . . . . 36