Annual Report (Form 10-K), fiscal year 1993

Item 1. Business
Northern States Power Company ("the Company"), incorporated in 1901 under the laws of Wisconsin as the La Crosse Gas and Electric Company, is an operating public utility company with executive offices at 100 North Barstow Street, Eau Claire, Wisconsin 54702-0008 (Phone: (715) 839-2621). The Company is a wholly- owned subsidiary of Northern States Power Company, a Minnesota corporation ("the Minnesota Company").
The Company is engaged in the production, transmission, distribution, and sale of electric energy to approximately 196,000 retail customers in an area of approximately 18,900 square miles in northwestern Wisconsin, to approximately 9,100 electric retail customers in an area of approximately 300 square miles in the western portion of the Upper Peninsula of Michigan, and to 10 wholesale customers in the same general area. The Company is also engaged in the distribution and sale of natural gas in the same service territory to approximately 60,000 customers in Wisconsin and 4,700 customer. In Wisconsin, some of the larger communities the Company provides Eau Claire, Chippewa Falls, La Crosse, Hudson, Menomonie and Ashland. In the Upper Peninsula of Michigan, the largest community to which the Company provides natural gas is Ironwood.
In 1993 the Company derived 83 percent of its total operating revenues from electric utility operations and 17 percent from gas utility operations. As of December 31, 1993, the Company had 893 full-time employees.
REGULATIONS AND RATES
Regulation
The Public Service Commission of Wisconsin ("PSCW") and Michigan Public Service Commission ("MPSC") regulate the rates and service of the Company with respect to retail sales within the State of Wisconsin and the State of Michigan, respectively, the issuance of new securities by the Company and various other aspects of the Company's operations. The PSCW also exercises jurisdiction over the construction of certain electric and gas facilities. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission ("FERC") with respect to its sales to wholesale electric customers and certain other aspects of its operations, including the licensing and operation of hydro projects and the Company's Interchange Agreement (see Electric Operations- Interchange Agreement). Approximately 96.9 percent of the Company's 1993 electric retail revenues from sales and 93.6 percent of its retail gas revenues from sales were subject to PSCW jurisdiction with the remaining retail revenues subject to MPSC jurisdiction. In 1993, the Company's wholesale revenues from sales were approximately 5.5 percent of the Company's electric revenues from sales.
Prior to construction of all major projects, the Company is required to obtain various licenses, permits and a certificate of public convenience and necessity from the PSCW. As part of this process, advance plan hearings are held by the PSCW, whereby the Company's generation and transmission construction plans and those of several neighboring utilities are reviewed by the PSCW.
For the purpose of rate regulation, all three of the regulatory jurisdic- tions allow a "forward looking" test year corresponding to the time that rates are to be put into effect.
Rate Changes
Wisconsin
On January 14, 1993, the PSCW issued an order approving an $8.0 million (3.1 percent) increase on an annual basis in the Company's electric retail rates and a $1.1 million (1.8 percent) increase on an annual basis in its gas rates. A January 16, 1993 effective date was authorized for these rate changes. On June 3, 1993, the Company filed with the PSCW for a $1.37 million (1.9 percent) increase in gas retail rates to be effective January 1, 1994. On August 18, 1993, the Company increased its request to $1.7 million (2.4 percent) to recover a portion of the acquisition premium paid by the Minnesota Company for Viking Gas Transmission Company in recognition of reduced gas costs. Hearings were held in October 1993 regarding the rate increase request. No change in the retail electric rates was requested. 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.
Wholesale
On February 26, 1993, the Company filed for an increase of $600,000 (3.7 percent) on an annual basis in its wholesale electric rates. The filing consisted of a settlement agreement between the Company and the municipal whole- sale customers. On April 22, 1993, the FERC issued an order approving the settlement agreement. The new wholesale electric rates became effective September 1, 1993.
Michigan
There were no changes in the Michigan electric or gas base rates during 1993.
Fuel and Purchased Gas Adjustment Clauses
Wisconsin
The Wisconsin automatic retail electric fuel adjustment clause was eliminated for the Company in the electric retail rate order issued by the PSCW dated March 11, 1986. The electric fuel adjustment clause has been replaced by a procedure which compares actual monthly and anticipated annual fuel costs with those costs which were included in the latest retail electric rates approved by the PSCW. If the comparison results in a difference a range of eight percent for the first month, five percent for the second month, or two percent for the remainder of the year, the PSCW may hold hearings limited to revise rates. The PSCW will be holding a technical conference and possibly hearings during 1994 to determine the appropriate process to handle fuel costs under a new biennial rate filing procedure that the PSCW adopted in 1993. The Company's retail gas rate schedules include a purchased gas adjustment clause which provides for inclusion of the current unit cost of gas from its gas suppliers. The factors applied under the purchased gas adjustment clause are adjusted on an ongoing basis to reflect a reconciliation of gas costs incurred and recovered.
Michigan
The Company's Michigan retail gas and electric rate schedules include Gas Cost Recovery factors (GCRF) and Power Supply Cost Recovery Factors (PSCRF), respectively, which are based on a twelve-month projection. The MPSC conducts formal hearings because approval must be obtained before implementation of the factors. After each twelve-month period is completed, a reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers.
Wholesale
The Company calculates the fuel adjustment factor for the current month based on estimated fuel costs for that month. The fuel adjustment factor is adjusted for over or under collected resale fuel costs from prior month's actual operations which provide an ongoing true-up mechanism.
Demand Side Management
The Company continues to implement various Demand Side Management (DSM) programs designed to improve load factor and reduce the Company's power production cost and system peak demands, thus reducing or delaying the need for additional investment in new generation and transmission facilities. The Company currently offers a broad range of DSM programs to all customer sectors, including information programs, rebate and financing programs, and rate incentive programs. In management's opinion, these programs respond to customer needs and focus on increasing value of service which, over the long term, will reduce the Company's capital requirements and help its customer base become more stable, energy efficient and competitive.
During 1993, the Company's programs accomplished over 19 Megawatts (MW) of system peak demand reduction in the commercial, industrial and agricultural customer sectors and over 3 MW in the residential sector. These impacts were obtained through appliance lighting, motor, and cooling efficiency improvements, peak curtailable and time of use rate applications, and direct load control of water heaters and air conditioners.
Since 1986, the Company's DSM programs have achieved 126 MW of summer peak demand reduction, which is equivalent to 13% of its 1993 summer peak demand A cumulative goal of 200 MW of peak demand reduction by 1997 has been established. The Company continues to focus on improving the cost-effectiveness of its DSM programs through market research studies and program evaluations.
ELECTRIC OPERATION
NSP System
The Company's electric production and transmission systems are interconnected with the production and transmission system of the Minnesota Company. The combined electric production and transmission systems of the Company and the Minnesota Company are hereinafter called the "NSP System."
The facilities of the NSP system include coal and nuclear generating plants, hydro, waste wood, and waste wood/refuse derived fuel ("RDF") generating plants, an interconnection with Manitoba Hydro Electric Board for the purpose of exchanging power, and extra-high voltage transmission facilities for inter- connection to Kansas City, Milwaukee and St. Louis to provide the necessary back up for the large plants.
Capability and Demand
The Company's record peak demand occurred on August 26, 1993, and was recorded at 982 MW.
The NSP System's net generating capability, plus commitments for capacity purchases, less commitments for capacity sales, must be at least equal to the NSP System obligation which is the sum of its maximum demand and its reserve requirements. Being a member of the Mid-Continent Area Power Pool ("MAPP"), NSP's reserve requirement is determined jointly with the other parties to the MAPP Agreement.
Currently, the reserve requirement equals 15 percent of the NSP System's maximum demand. The reserve requirement reflects the benefit of MAPP members sharing their reserves to protect against equipment failures on their systems (See Electric Power Pooling Agreements).
The Company primarily relies on the Minnesota Company, through the Inter- change Agreement (see Electric Operations - Interchange Agreement), for base load generation. Approximately 77 percent of the total kilowatt hour requirements of the Company were provided by the Minnesota Company generating facilities or purchases made by the Minnesota Company for system uses in the year 1993.
The Company also has two electric steam generating facilities. One is the Bay Front Generating Plant which is located in Ashland, Wisconsin. The plant is fueled primarily by coal and wood residue. Recent modifications to the facility allow for more effective utilization of additional waste wood fuel supplies and have extended the useful life of the facility approximately 20 years from their completion in 1992. In 1992 the Company received authorization from the Wisconsin Department of Natural Resources ("burn tire derived fuel on a regular basis.
The Company's second electric steam generating plant is the French Island plant located in La Crosse, Wisconsin, which has two fluidized bed boilers installed for the purpose of burning a mixture of waste wood and RDF. The Bay Front plant in Ashland and the French Island steam plant are primarily used on an intermediate load basis.
The Company's thermal peaking capability consists of two oil-fired gas turbine peaking plants and a gas and oil turbine peaking plant. The Company also has 19 hydro plants that operate as peaking facilities or run-of-river facilities.
Interchange Agreement
The electric production and transmission costs of the NSP System are shared by the Company and the Minnesota Company. The cost-sharing arrangement between the companies is the Agreement to Coordinate Planning and Operation and Interchange Power and Energy between Northern States Power (Minnesota) and Northern States Power (Wisconsin) ("Interchange Agreement"). It is a FERC regulated agreement and has been accepted by the PSCW and the MPSC for determination of costs recoverable in rates by the Company for charges from the Minnesota Company in rate cases.
Historically the Company's share of the NSP System annual production and transmission costs has been in the 14 to 17 percent range. Revenues received from billings to the Minnesota Company for its share of the Company's production and transmission costs are recorded as electric operating revenues on the Company's income statement. The portions of the Minnesota Company's production and transmission costs that were charged to the Company were recorded as purchased and interchange power expenses and other operation expenses, respectively, on the Company's income statement. (See Note 6 Financial Statements).
Under the Interchange Agreement, the Company could be charged a portion of the cost of an assessment made against the Minnesota Company pursuant to the Price-Anderson liability provisions of the Atomic Energy Act of 1954. (See Note 3 to Financial Statements).
Electric Power Pooling Agreements
The Company is included with the Minnesota Company as one of 12 investor- owned utilities, 9 rural electric generation and transmission cooperatives, 3 public power districts, 18 municipal electric systems, 3 municipal power agencies, the Western Area Power Authority (Department of Energy) and 2 Canadian Crown corporations that are members of MAPP pursuant to an agreement, as amended , dated March 31, 1972. The agreement provides for the members to coordinate the installation and operation of generating plants and transmission line facilities. The MAPP agreement was accepted for filing by has been effective since December 1, 1972.
Fuel Supply
In 1993 the Company shared in the fuel supply costs incurred by the Minnesota Company in accordance with the Interchange Agreement. Coal and nuclear fuel will continue to dominate the NSP System fuel requirements for the generation of electricity. It is expected that approximately 98 percent of the NSP System annual fuel requirements in 1994 will be provided by these two sources and that 2 percent of NSP's annual fuel requirements for generation will be provided by other fuels (including natural gas, refuse derived fuel, waste materials, and wood) over the next several years.
Fuel Use on Btu Basis (Est.) (Est.) 1993 1994 1995
Coal 62.3% 62.9% 61.2% Nuclear 36.2% 35.4% 37.1% Other * 1.5% 1.7% 1.7%
* Includes oil, gas, refuse derived fuel and wood
Environmental Matters
The Wisconsin DNR has been authorized by the United States Environmental Protection Agency to administer the National Pollutant Discharge Elimination System Permits under the Federal Water Pollution Control Act Amendments of 1977. Such permits are required for the lawful discharge of any pollutant into navigable waters from any point source (e.g. power plants). Permits have been issued for all of the Company's affected plants and all plants are in compliance with permit requirements.
The DNR has jurisdiction over emissions to the atmosphere from the Company's power plants. The operation of the Company's generating plants substantially conforms to federal and state limitations pertaining to discharges to the air. Occasional, infrequent exceedances of Wisconsin DNR air emission limitations occurred in 1993 at the Company's Bay Front and French Island facilities. These are being resolved through operating changes or permit modifications and no agency enforcement action is anticipated. presently operates hydro, coal, natural gas, oil-fired, wood and RDF equipment.
Regulatory approval is required for the construction of generating plants and major transmission lines. Also additional regulations have been instituted governing the use, transport, disposal and inspection of hazardous material and electrical equipment containing polychlorinated biphenyls. The Company has procedures in place to comply with these regulations.
The Company has been identified as a "Potentially Responsible Party" (PRP) for a solid and hazardous waste landfill. The Company contends that it did not dispose of hazardous wastes in the subject landfill during the time period in question. Because neither the amount of cleanup costs nor the final method of their allocation among all designated PRPs has been determined, it is not feasible to determine the outcome of this matter time.
GAS OPERATIONS
In 1993, the Company continued its strategy of holding a diversified portfolio of natural gas supplies and transportation arrangements. The Company complied with the requirements of FERC's Order 636, which significantly changed the services available to, and provided by, local distribution companies and interstate pipelines. The Company is now relying almost entirely on third party suppliers for its natural gas supply needs, and is utilizing the pipelines only for transportation and storage services.
The Company continues to hold annual and/or winter peaking transportation contracts from Northern Natural Gas Company (NNG), Great Lakes Transmission Limited Partnership, Viking Gas Transmission Company, and TransCanada Pipeline, LTD.
The Company picked up three new gas supply contracts in 1993 from assignment of NNG's supply under Order 636, and purchased additional baseload and peaking supplies from two new third party suppliers.
The Company is continuing its pursuit of growth and profitability through expansion of its distribution system and services both inside and outside of its existing service territories.
CONSTRUCTION AND FINANCING
Expenditures for the Company's construction program in 1993 totaled $60 million. The 1994 construction expenditures are estimated to be $60.7 million with approximately $38.3 million for electric facilities, $8.6 million for gas facilities and $13.8 million for general plant and equipment.
Expenditures for the Company's construction programs for the next five- year period 1994-1998, are estimated to be as follows:
Year Estimated Construction Expenditures
1994 $ 61 million 1995 $ 60 million 1996 $ 59 million 1997 $ 62 million 1998 $ 60 million
TOTAL $302 million
It is presently estimated that approximately 83 percent of the 1994-1998 construction expenditures will be provided by internally generated funds and the remainder from short-term and long-term external financing. At December 31, 1993, the Company's short-term borrowings outstanding were $23.5 million.
The foregoing estimates of construction expenditures, internally generated funds and external financing requirements can be affected by numerous factors, including load growth, inflation, changes in the tax laws, rate relief, earnings and regulatory actions. Major electric and gas utility projects are subject to the jurisdiction of the PSCW and require it Hence, the above estimated construction program and financing program could change from time to time due to variations in these other factors.
During the five years ended December 31, 1993, the Company had gross additions to utility plant in service of approximately $249 million. Included in the Company's gross additions is $38.5 million for electric production facilities, $155 million for other electric properties, $35 million for gas utility properties, and $20.5 million for other utility properties. Retirements during the same period were approximately $37.5 million. Based on studies made by the Company, the weighted average age of depreciable property was 13 years at December 31, 1993.
Item 2.



Item 2. Properties
Electric Utility
The Company's major electric generating facilities consist of the following:
Projected Year 1993-4 Winter Station and Units Fuel Installed Capability (MW) Combustion Turbine: Flambeau Station Gas/Oil 1969 17 (1 unit) Wheaton Oil 1973 440 (6 units) French Island Oil 1974 192 (2 units) Steam: Bay Front Coal/Wood/ 1974-1960 73 (3 units) Gas French Island Wood/RDF 1940-1948 29 (2 units) Hydro Plants: (19 plants) - Various dates 248
TOTAL 999
At December 31, 1993, the Company owned approximately 2,382 pole miles of overhead electric lines, 8,029 pole miles of overhead electric distribution lines, 38 conduit miles and 976 direct buried cable miles of underground electric lines.
Gas Utility
The gas properties of the Company include approximately 1,313 miles of natural gas distribution mains. The Company owns two liquefied natural gas facilities with a combined storage capacity of the equivalent of 400,000 Mcf to supplement the available pipeline supply of natural gas during periods of peak demands. In January of 1993, the Company installed propane air facilities with a capacity of 144,000 gallons to further supplement gas supply in the La Crosse, Wisconsin area during peak periods.
Item 3.

Item 3. Legal Proceedings
The Company is currently involved in various claims and lawsuits incidental to its business. In the opinion of management, if the Company were ultimately found to be liable in these claims and lawsuits, such liability would not have a material effect on the financial statements of the Company.
Item 4.

Item 4. Submission of Matters to a Vote of Security Holders
Omitted per conditions set forth in general instruction J (1) and (a) and (b) of Form 10-K for wholly-owned subsidiaries (reduced disclosure format).
PART II
Item 5.

Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters
This is not applicable as the Company is a wholly owned subsidiary.
Item 6.

Item 6. Selected Financial Data
This is omitted per conditions set forth in general instructions J (1) (a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Item 7.

Item 7. Management Discussion and Analysis
Management's Discussion and Analysis of Financial Condition and Results of Operations is omitted per conditions as set forth in general instructions J (1) (a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management's narrative analysis of the results of operations set forth in general instructions J (2) (a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format). This analysis will primarily forth the Company's accounting changes and compare its revenue and expens year ended December 31, 1993 with the year ended December 31, 1992.
The Company's net income for the year ended December 31, 1993 was $38.0 million, down from the $38.2 million earned in the same period of 1992. The 1993 operating income increased by $1.3 million from the 1992 level.
Accounting Changes
Postretirement Benefits See Note 5 for discussion of the 1993 change in accounting for postretirement medical and death benefits. There was no material effect on net income due to rate recovery of the expense increases.
Income Taxes The Company adopted SFAS No. 109 - Accounting for Income Taxes, effective Jan. 1, 1993. See Note 1 for discussion of the adoption of SFAS No. 109. Adoption of SFAS No. 109 had no effect on earnings and no material effect on financial condition due to its similarity to SFAS No. 96 - Accounting for Income Taxes, which the Company adopted in 1988, and which SFAS No. 109 supersedes.
1994 Changes In 1994, the Company will adopt SFAS No. 112 - Accounting for Postemployment Benefits. SFAS No. 112 requires the accrual of certain employee costs (such as injury compensation and severance) to be paid in future periods. Its adoption in 1994 is not expected to have a material effect on the Company's results of operations or financial condition.
Electric Sales and Revenues
Electric revenues for 1993 increased $17.2 million, a 5.0 percent increase from the 1992 revenues. Revenues from retail sales, which accounted for 75 percent of the electric revenues in 1993, increased $14.6 million or 5.7 percent. Included in the 1993 retail increase is $6.2 million directly related to the rate changes discussed in Part I, Item 1: Business-Regulation and Rates. Also reflected in the 1993 retail revenue increase increase of $8.4 million due to increased sales. The cool summer weather of 1992 was a major cause of this increase in sales. Our wholesale customers accounted for 4.4 percent of the total electric revenues. Wholesale revenues increased $1.3 million or 8.5 percent in 1993. This increase is also largely a result of 1992's cool summer weather. Another major component of electric revenues is charges billed to the Minnesota Company through the Interchange Agreement (see Part I, Item 1; Business-Electric Operations). Interchange Agreement billings charged to the Minnesota Company increased $1.5 million primarily as a result of added transmission investment. Other electric revenues decreased $0.2 million in 1993.
Gas Sales and Revenues
Gas revenues in 1993 increased by $11.7 million or 19.1 percent as compared with 1992. This is the net impact of increased revenues due to the rate increase effective January 1993, increased revenues due to sales growth, increased revenues due to higher gas costs passed through the purchased gas adjustment clause, and increased revenues of $8.2 million due to 1992's warm winter weather.
Operating Expenses and Other Factors
Electric Production The cost of interchange power increased $6.3 million or 4.0 percent in 1993 compared to the same period one year ago. This expense represents charges billed from the Minnesota Company through the Interchange Agreement (see Part I, Item 1: Business-Electric Operations). The company's increased electric sales during 1993 over 1992, combined with increased costs associated with the NSP system's new contract with Manitoba Hydro resulted in the company's purchased power and fuel purchased under its interchange agreement with its parent to increase by approximately $7.6 million. Total interchange power is offset by decreases in operation and maintenance expenses in the charges. Fuel for electric generation, which represents the Company's fuel generation, increased $1.2 million or 56.6 percent in 1993 from 1992. This is primarily due to increased requirements due to the increased sales in 1993.
Gas Purchased for Resale This cost increased $9.7 million or 23.2 percent. $3.5 million of this increase in 1993 is a result of increased volumes purchased. Increased transportation prices resulted in $4.2 million of the increase with the balance of the increase due to commodity and demand price increases.
Administrative and General, Other Operation and Maintenance The $5.2 million increase in administrative and general expense is partially due to the Company having had no disbursement of the employee incentive pay program (which is dependent upon corporate earnings) in 1992, but incurring its disbursement in 1993. This accounted for $1.7 million of the $5.2 million increase. An increase of $2.1 million was due to the SFAS 106 accruals of postretirement benefits. The remaining increases were general increase and general expenses.
Depreciation and Amortization The increase in depreciation between 1993 and 1992 primarily reflects higher levels of depreciable plant.
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 1992 revenues increasing over 1991 revenues.
Income Taxes $0.7 million of the increase in income taxes in 1993 over 1992 is the result of the Federal Rate increasing from 34% to 35% and the balance of the increase is primarily attributable to changes 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 During Construction (AFC) The differences in AFC for the reported periods are attributable to varying levels of construction work in progress and lower AFC rates associated with increased use of low-cost short- term borrowings.
Other Income and Deductions The decrease in other income is primarily due to a greater number of sales of certain land and land rights in 1992 by NSP Lands, Inc., a wholly owned subsidiary of the Company.
Interest Charges 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%. The Company entered into an interest rate swap agreement with the underwriters of this bond issue relating to $20.0 million of the principal, which effectively converted the interest cost of this debt from fixed rate to variable rate, with the variable rate changing on March 1 and September each year until March 1, 1998. The net interest rate for the entire $110 millio approximately 6.9% in 1993. The proceeds from these bonds were used to redeem $47.5 million in principal amount of its First Mortgage Bonds, Series due July 1, 2016, 9-1/4% at a redemption price of 105.78%, to redeem $38.4 million in principal amount of its First Mortgage Bonds, Series due March 1, 2018, 9-3/4%, at the redemption price of 107.31% and to repay outstanding short-term borrowings, including short - -term borrowings incurred to redeem on January 20, 1993 $7.8 million in principal amount of its First Mortgage Bonds, Series due December 1, 1999, 9-1/4%, at the redemption price of 102.2%.
On October 5, 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 in principal amount of its First Mortgage Bonds, Series due October 1, 2003, 7-3/4% at a redemption price of 102.49%, to redeem $10.8 million in principal amount of its First Mortgage Bonds, Series due August 1, 1994, 4-1/2%, at the redemption price of 100.00% and to repay outstanding short-term borrowings.
These transactions had no material impact on the 1993 interest charges compared to the charges of 1992 because in 1993, 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.
Item 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), (the Company) listed in the accompanying table of contents of Item 14(a)1. Our audits also included the financial statement schedules listed in Item 14(a)2. These financial statements and the financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1993 and 1992 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedules , when considered in relation to the basic financial statements taken as a whole , present fairly, in all material respects, the information set forth therein.
As discussed in Note 5 to the financial statements, the Company changed its method of accounting for postretirement health care costs in 1993.
Minneapolis, Minnesota February 4, 1994
Item 8 Financial Statements and Supplementary Data
Statements of Income and Retained Earnings Year-Ended December 31
(Thousands of dollars) 1993 1992 1991
Operating Revenues Electric $362 473 $345 289 $349 027 Gas 72 760 61 071 56 348
Total 435 233 406 360 405 375
Operating Expenses Purchased and interchange power 162 510 156 196 160 324 Fuel for electric generation 3 185 2 034 2 696 Gas purchased for resale 51 501 41 814 39 332 Administrative and general 26 842 21 610 21 761 Other operation 49 907 47 470 47 054 Maintenance 21 703 21 806 23 487 Depreciation and amortization 28 585 26 832 25 321 Property and general taxes 13 091 12 925 12 107 Income taxes 23 103 22 184 21 641
Total operating expenses 380 427 352 871 353 723
Operating Income 54 806 53 489 51 652
Other Income and Deductions Allowance for funds used during construction-equity 694 907 514 Other income and deductions 844 1 361 1 128
Total Other Income 1 538 2 268 1 642
Income Before Interest Charges 56 344 55 757 53 294
Interest Charges Interest on long-term debt 16 343 17 269 15 863 Other interest and amortization 2 406 857 1 396 Allowance for funds used during construction-debt (411) (569) (517)
Total interest charges 18 338 17 557 16 742
Net Income 38 006 38 200 36 552 Retained Earnings, January 1 192 816 179 510 173 508 Dividends (25 708) (24 894) (30 550)
Retained Earnings, December 31 $ 205 114 $192 816 $179 510
See Notes to Financial Statements. Item 8 Financial Statements and Supplementary Data
Statements of Cash Flows Year Ended December 31
(Thousands of dollars) 1993 1992 1991
Cash Flows from Operating Activities: Net Income $38 006 $38 200 $36 552 Adj to recon. net income to cash from op activities: Depreciation and amortization 33 580 28 179 26 852 Deferred income taxes 7 228 3 089 4 319 Investment tax credit adjustments (948) (956) (971) AFC-equity (694) (907) (514) Gain on sale of land (681) Other (2 440) (643) Cash used for changes in certain working capital items 299 2 438 (1 571)
Net Cash Provided by Operating Activities 77 471 67 603 63 343
Cash Flows from Financing Activities: Proceeds from issuance of long-term debt 146 587 48 563 Proceeds from issuance of notes payable-parent company 12 600 Repayment of notes payable-parent company (800) (31 800) Repayment of long-term debt (136 090) (1 415) (557) Dividends paid to parent (25 708)(24 894) (30 550)
Net Cash provided by (used for) Financing Activities (16 011)(13 709) (14 344)
Cash Flows from Investing Activities: Construction expenditures capitalized (59 954)(54 588) (50 832) Increase (decrease) in construction payables (2 143) (2 013) 1 115 AFC-equity 694 907 514 Other (489) Net Cash Used for Investing Activities (61 892)(55 694) (48 467)
Net Increase (Decrease) in Cash and Cash Equivalents (432) (1 800) 532 Cash and Cash Equivalents at Beginning of Period 881 2 681 2 149
Cash and Cash Equivalents at End of Period $449 $881 $2 681
Working Capital Changes: Accounts receivable-net $(1 597) $921 $(4 414) Materials and supplies (453) (647) (241) Accounts payable and accrued liabilities 7 633 412 1 450 Payables to affiliated companies 127 2 444 (2 899) Income and other taxes accrued (2 762) 634 3 528 Other (2 649) (1 326) 1 005
Net $299 $2 438 $(1 571)
Supplemental Disclosures of Cash Flow Information: Cash paid during the year for: Interest (net of amount capitalized) $17 440 $17 136 $15 424 Income taxes $18 825 $19 256 $14 905
See Notes to Financial Statements.
Item 8 Financial Statements and Supplementary Data
Balance Sheets December 31
(Thousands of dollars) 1993 1992
Assets Utility Plant Electric-including construction work in progress: 1993, $16,697; 1992, $14,571 $810 691 $781 573 Gas 81 567 75 250 Other 43 279 28 565
Total 935 537 885 388
Accumulated provision for depreciation (320 938) (300 393)
Net utility plant 614 599 584 995
Other Property and Investments Nonutility property - at cost 3 157 3 119 Accumulated provision for depreciation (364) (363) Other investments - at cost which approximates market 4 094 3 661
Total other property and investments 6 887 6 417
Current Assets Cash and cash equivalents 449 881 Accounts receivable 38 424 36 738 Accumulated provision for uncollectible accounts (708) (646) Materials and supplies - at average cost Fuel 2 293 2 535 Other 8 692 7 996 Accrued utility revenues 17 230 15 990 Prepayments and other 9 855 9 920 Deferred tax asset 1 254 2 980
Total current assets 77 489 76 394
Deferred Debits Unamortized debt expense 3 078 3 031 Regulatory assets 30 036 21 062 Other 4 890 2 570
Total deferred debits 38 004 26 663
Total $736 979 $694 469
See Notes to Financial Statements. Item 8 Financial Statements and Supplementary Data
Balance Sheets December 31
(Thousands of dollars) 1993 1992
Liabilities Capitalization Common stock-authorized 870,000 shares of $100 par value; issued shares: 1993 and 1992, 862,000 $86 200 $86 200 Premium on common stock 10 461 10 461 Retained earnings 205 114 192 816
Total common equity 301 775 289 477
Long-term debt 217 600 187 737
Total capitalization 519 375 477 214
Current Liabilities Notes payable - parent company 23 500 24 300 Long-term debt due within one year 0 9 608 Accounts payable 15 264 12 051 Salaries, wages, and vacation pay accrued 5 481 3 204 Payables to affiliated companies (principally parent) 11 636 11 509 Federal income taxes accrued 1 606 3 862 Other taxes accrued 2 492 2 998 Interest accrued 4 823 5 934 Other 1 917 2 252
Total current liabilities 66 719 75 718
Deferred Credits Accumulated deferred income taxes 88 426 78 434 Accumulated deferred investment tax credits 23 653 24 886 Regulatory liability 22 416 29 395 Other 16 390 11 822
Total deferred credits 150 885 141 537
Commitments and Contingent Liabilities
Total $736 979 $694 469
See Notes to Financial Statements. NORTHERN STATES POWER COMPANY (WISCONSIN) NOTES TO FINANCIAL STATEMENTS
1. Summary of Accounting Policies
System of Accounts 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.
Reclassifications Certain reclassifications have been made to the 1992 financial statements in order to conform to the 1993 presentation of regulatory deferrals. These reclassifications have no effect on the net income or common equity as previously reported.
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 than units of property are charged to operating expenses.
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 3.40% in 1993, 3.38% in 1992, and 3.36% in 1991.
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 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 credits are generally based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are being amortized consistent with ratemaking treatment as established by regulators. See Note 7 for discussion of these regulatory deferrals.
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. Also, regulation results in the creation of certain assets and liabilities related to income taxes as discussed in Note 7.
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.
Cash Equivalents The Company considers certain debt instruments (primarily commercial paper) with a remaining maturity of three months or less at the time of purchase to be cash equivalents.
Environmental Costs Costs related to environmental remediation are accrued when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated.
2. Long-Term Debt
First Mortgage Bonds - less reacquired bonds of $0 and $42 December 31 at December 31, 1993 and 1992, respectively: 1993 1992 (Thousands of dollars) Series due: Aug. 1, 1994, 4-1/2% $10 938 Dec. 1, 1999, 9-1/4% 7 800 Oct. 1, 2003, 7-3/4% 24 570 Jul. 1, 2016, 9-1/4% 47 500 Mar. 1, 2018, 9-3/4% 38 400 Apr. 1, 2021, 9-1/8% $49 000 49 500 Mar. 1, 2023, 7 1/4% 110 000 Oct. 1, 2003, 5 3/4% 40 000
Total $199 000 $178 708
Less Dec. 1, 1999, 9 1/4% bonds redeemed in January 1993 7 800 Less sinking fund requirements not reacquired 1 808 Net $199 000 $169 100
City of LaCrosse Resource Recovery Revenue Bonds - Series due Nov. 1, 2011, 7 3/4% 18 600 18 600 Unamortized premium on long-term debt 0 37 Total long-term debt $217 600 $187 737
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 January 20, 1993, the Company redeemed its $7.8 million of 9 1/4% bonds at 102.2%; this amount has, therefore, been classified as current on the December 31, 1992 financial statements.
Except for minor exclusions, all real and personal property is subject to the lien of the Company First Mortgage Bond Trust Indenture. The Indenture also provides for certain restrictions on the payment of cash dividends on common stock. At December 31, 1993, the payment of cash dividends on common stock was not restricted.
3. Commitments and Contingent Liabilities
The Company presently estimates capital expenditures will be $61 million in 1994 and $302 million for 1994-98.
The Company has capital lease obligations of $3.1 million. These leases will require principle payments of $715,000, $780,000, $854,000, $524,000, and $189,000, respectively, for the years 1994 to 1998.
Rentals under operating leases were approximately $2,651,000, $2,547,000 and $1,962,000, for 1993, 1992, and 1991, respectively.
Although the Company does not own a nuclear facility, any assessment made against Northern States Power Company (Minnesota), the parent company, under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, would be a cost included under the Interchange Agreement (Note 6) and the Company would be charged its proportion of the assessment. Such provisions set a limit of $9.4 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 $9.2 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 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 Company has been identified as a "Potentially Responsible Party" (PRP) for a solid and hazardous waste landfill. The Company contends that it did not dispose of hazardous wastes in the subject landfill during the time period in question. Because neither the amount of cleanup costs nor the final method of their allocation among all designated PRPs has been determined, it is not feasible to determine the outcome of this matter at this time.
4. 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 $217.6 million at December 31, 1993 and $197.3 million at December 31, 1992, is $233.3 million and $212.2 million, respectively.
5. 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 years of service, the employees highest average pay for 48 consecutive months and Social Security wage base. Pension costs are determined and funded under the aggregate-cost method, using market value of assets of the trust fund. The portion of annual pension costs was $1,236,000 for 1993, $2,400,000 for 1992, and $2,478,000 for 1991.
Until 1993, for financial reporting and regulatory purposes, the Company's pension expense was determined and recorded under the aggregate cost method. 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: 1993 1992 1991 (Thousands of dollars)
Service Cost - benefits earned during the period $25 015 $24 080 $22 097 Interest cost on projected benefit obligation 71 075 69 853 65 557 Actual return on assets (152 019)(115 455)(246 678) Net amortization and deferral 66 299 39 019 181 543 Net periodic pension cost determined under SFAS 87 10 370 17 497 22 519
Expenses recognized (deferred) due to actions of regulators 5 117 2 741 (1 549) Pension expense recorded during the period 15 487 20 238 20 970 Portion of expense recognized for early retirement program 0 (165) (165) Net periodic pension cost recognized for ratemaking $15 487 $20 073 $20 805
The funding status for the total plan is as follows:
Actuarial present value of benefit obligation: Vested $655 002 $614 446 Nonvested 139 346 129 183 Accumulated benefit obligation $794 348 $743 629
Projected benefit obligation $974 160 $914 019 Plan assets at fair value 1 244 650 1 156 782
Plan assets in excess of projected benefit obli. (270 490) (242 763) Unrecognized prior service cost (22 580) (14 790) Unrecognized net (gain) 315 049 269 086 Unrecognized net transitional (asset) 767 843 Net pension liability recorded $22 746 $12 376
The weighted average discount rate used in determining the actuarial present value of the projected obligation was 7% in 1993 and 8% in 1992. The rate of increase in future compensation levels used in determining the actuarial present value of the projected obligation was 5% in 1993 and 6% in 1992. The assumed long-term rate of return on assets used for cost determinations under SFAS 87 was 8% in 1993 and 1992 and 8.5% in 1991. 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 prior 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 considers anticipated 1994 plan design changes not in effect in 1993, including Medicare integration, increased retiree cost sharing and managed indemnity measures.
In the past, NSP has funded benefit payments to retirees 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, 1993, consisted of investments in equity mutual funds and cash equivalents. The following table sets forth the total (the Company and Minnesota Company) health care plan's funded status in 1993.
(Millions of dollars) Dec. 31, 1993 Jan. 1, 1993
APBO: Retirees $120.2 $105.8 Fully eligible plan participants 18.8 18.8 Other active plant participants 90.8 91.0 Total APBO 229.8 215.6 Plan Assets (6.1) 0 APBO in excess of plant assets 223.7 215.6 Unrecognized net actuarial gain (loss) (1.3) Unrecognized transition obligation (204.8) (215.6) Postretirement benefit obligation $17.6 $0
The assumed health care cost trend rate used in measuring the APBO at Dec. 31 , 1993, was 14.1 percent for those under age 65 and 8.0 percent for those over age 65. The trend rates used in the Jan. 1, 1993 calculations were 15.1 percent and 9.0 percent respectively. The assumed cost trend rates are expected to decrease each year until they reach 4.5 percent for both age groups in the year 2004, after which they are assumed to remain constant. A one percent increase in the assumed health care cost trend rate for each year would increase the APBO as of December 31, 1993, by approximately 17 percent, and service and interest cost components of the net periodic postretirement cost by approximately 20 percent. The assumed discount rate used in determining the APBO was 7 percent for Dec. 31, 1993, and 8 percent for Jan. 1, 1993, compounded annually. The assumed long-term rate of return on assets used for cost determinations under SFAS No. 106 was 8 percent for both measurement dates. While the assumption changes made for the Dec. 31 calculations had no effect on 1993 benefit costs, the effect of the changes in 1994 (for the Company and Minnesota Company) is expected to be a cost decrease of approximately $2 million.
In each 1992 and 1991, 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 1993 consists of the following components (millions of dollars):
Service cost-benefits earned during the year $ 0.6 Interest cost (on service cost and APBO) 2.4 Amortization of transition obligation 1.5 Return on assets (.1) Net periodic postretirement health care cost under SFAS No. 106 4.4
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.
The Company will adopt SFAS No. 112-Accounting for Postemployment Benefits, which requires the accrual of certain employee costs to be paid in future periods, in 1994; its adoption will have no material effect on the Company's results of operations or financial condition.
6. 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 1993 1992 1991 (Thousands of dollars) Operating revenues: Electric $ 72 162 $ 70 671 $ 70 623 Gas 56 55 62 Operating expenses: Purchased and interchange power 162 510 156 196 160 324 Gas purchased for resale 267 214 183 Other operation 12 515 11 668 11 809
7. Regulatory Assets and Liabilities
The following summarizes the individual components of unamortized regulatory assets and liabilities shown on the Balance Sheet at Dec. 31:
(Thousands of dollars) 1993 1992
AFC recorded in plant on a net-of-tax basis 8 795 8 520 Losses on reacquired debt 10 857 5 037 Conservation and energy management programs 8 291 5 738 Pensions and other 2 093 1 767 Total Regulatory Assets 30 036 21 062
Excess deferred income taxes collected from customers 5 914 12 821 Investment tax credit deferrals 15 841 16 038 Fuel refunds and other 661 536 Total Regulatory Liabilities 22 416 29 395
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 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.
8. 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% in 1993 (34% in 1992 and 1991) to net income before income tax expense. The reasons for the difference are as follows:
1993 1992 1991
(Thousands of dollars)
Tax computed at statutory rate $21 387 $20 434 $19 640 Increases (decreases) in tax from: State income taxes, net of Federal income tax benefit 3 165 3 037 3 205 Allowance for funds used during construction (243) (284) (175) Investment tax credit adjustments - net (948) (956) (971) Use of the flow-through method for deprec'n in prior yr 474 673 649 Effect of tax rate changes for plant related items (487) (420) (332) Gain on sale of tax benefit transfer leases (88) Other - net (162) (583) 412 Total income tax expense $23 098 $21 901 $21 211
Effective income tax rate 37.8% 36.4% 36.7%
Income tax expense is comprised of the following: Included in income taxes: Current Federal tax expense $12 919 $15 340 $13 479 Current state tax expense 3 180 3 598 3 286 Deferred Federal tax expense 6 173 3 075 4 270 Deferred state tax expense 1 778 1 127 1 577 Investment tax credit adjustments - net (948) (956) (971) Total 23 103 22 184 21 641 Included in income deductions: Current Federal tax expense 875 953 1 106 Current state tax expense (90) (123) (7) Deferred Federal tax expense (790) (1 113) (1 529) Total income tax expense $23 098 $21 901 $21 211
The components of the Company's net deferred tax liability at Dec. 31 were as follows:
(Thousands of dollars) 1993 1992
Deferred tax liabilities: Differences between book and tax bases of property $91 195 $80 628 Tax benefit transfer leases 6 146 6 935 Regulatory assets 11 371 8 326 Other 398 13 Total deferred tax liabilities 109 110 95 902
Deferred tax assets: Deferred investment tax credits 9 487 9 753 Regulatory liabilities 8 726 11 310 Deferred compensation accrued vacation and other reserves not currently deductible 3 193 1 818 Other 532 567 Total deferred tax assets 21 938 23 448
Net deferred tax liability $87 172 $72 454
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.
9. Segment Information Year Ended December 31 1993 1992 1991
(Thousands of dollars) Operating revenues: Electric $362 473 $345 289 $349 027 Gas 72 760 61 071 56 348 Total operating revenues $435 233 $406 360 $405 375
Operating income before income taxes: Electric $73 012 $70 202 $69 299 Gas 4 897 5 471 3 994 Total operating income before income taxes $77 909 $75 673 $73 293
Depreciation and amortization: Electric $25 179 $23 870 $22 717 Gas 3 406 2 962 2 604 Total depreciation and amortization $28 585 $26 832 $25 321
Construction expenditures: Electric $49 664 $44 332 $44 145 Gas 10 258 10 235 9 362 Total construction expenditures $59 922 $54 567 $51 507
Net utility plant: Electric $560 999 $537 576 $518 788 Gas 53 600 47 419 39 820 Total net utility plant 614 599 584 995 558 608
Other corporate assets 122 380 109 474 95 940 Total assets $736 979 $694 469 $654 548
10.Short-Term Borrowings
The Company had bank lines of credit aggregating $1,000,000 at December 31, 1993. 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 1993 and 1992 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.
11.Common Stock
The Company's common shares have a par value of $100 per share. At December 31, 1993 and 1992, 870,000 shares were authorized and 862,000 shares were issued .
12. Summarized Quarterly Financial Data (Unaudited)
Quarter Ended March 31, June 30, September December 1993 1993 30, 1993 31, 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
Quarter Ended March 31, June 30, September December 1992 1992 30, 1992 31, 1992 (Thousands of Dollars)
Operating revenues $ 113 555 $ 91 496 $ 89 722 $ 111 587
Operating income 18 483 9 171 10 067 15 768
Net income 14 371 5 197 6 133 12 499
Item 9.

Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
During 1993 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.



Item 10 Directors and Executive Officers of the Registrant28 Item 11

Item 11 Executive Compensation28 Item 12

Item 12 Security Ownership of Certain Beneficial Owners and Management28 Item 13

Item 13 Certain Relationships and Related Transactions28
PART IV Item 14

Item 14 Exhibits, Financial Statement Schedules and Reports on Form 8-K29
SIGNATURES 41