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PART I
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. 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. 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. 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. 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. 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. 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 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.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.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, 1993. 14
Statements of Cash Flows for the three
years ended December 31, 1993. 15
Balance Sheets, December 31, 1993 and 1992. 16
Notes to Financial Statements. 18
2.Financial Statement Schedules
Included in Part IV of this Report:
Schedules for the three years ended December 31, 1993.
V - Utility Plant and Non-utility Property 32
VI - Accumulated Provision for Depreciation and
Amortization for Utility Plant and Non-utility
Property 35
Notes to Schedules V and VI 38
IX - Short-term borrowings 39
X - Supplementary Income Statement Information 40
Schedules other than those listed above are omitted because of the absence of
the conditions under which they are required or because the information required
is included in the financial statements or the notes.
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
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 March 4, 1993, a Form 8-K was filed reporting (as Item 5, Other Events and
Item 7, Financial Statements, Pro Forma Financial Information and Exhibits), the
Company's financial statements due to long term debt refinancing.
On September 21, 1993, a Form 8-K was filed reporting (as Item 5, Other Events
and Item
7, Financial Statements and Exhibits), the Company's financial statements due to
long term debt refinancing.
Item 14.Exhibits, Financial Statement Schedules and Reports on Form 8-K
Notes to Schedule V and VI (Thousands of dollars)
1.Column E of Schedule V
For the year ended December 31, 1993:
Represents transfers charged from nonutility property additions $ 35
Reclassifications (1)
$ 34
For the year ended December 31, 1992:
Represents transfers charged to nonutility property additions $(410)
Reclassifications (3)
$(413)
For the year ended December 31, 1991:
Represents transfers charged to nonutility property additions $ (25)
Depreciation is computed on the straight-line method based on estimated useful
lives of the various classes of property. Such provisions as a percentage of
the average balance of depreciable property in service were 3.40%
in 1993, 3.38% in 1992, and 3.36% in 1991.
Item 14.Exhibits, Financial Statement
Schedules and Reports on Form 8-K
Schedule IX, Short-Term Borrowings
Column A Column B Column C Column D Column E Column F
Maximum Average Weighted
Weighted amount amount average
Balance at average Outstanding Outstanding interest
Short-term borrowings end of interest during the during the rate during
(thousands of dollars) period rate period period the period
For the year ended
December 31, 1993 $23 500 3.3% $28 200 $10 693 3.4%
For the year ended
December 31, 1992 24 300 3.5% 24 300 8 837 3.7%
For the year ended
December 31, 1991 11 700 5.2% 41 200 12 982 6.7%
Item 14.Exhibits, Financial Statement Schedules and Reports on Form 8-K
Schedule X, Supplementary Income Statement Information
Column A Column B
Charged to
costs and expenses
Item 1993 1992 1991
(thousands of dollars)
1.Maintenance and repairs N.A. N.A. N.A.
2.Depreciation and amortization of intangible
assets, preoperating costs and similar deferral N.A. N.A. N.A.
3.Taxes, other than payroll and income taxes:
Real and personal property $ 9 607 $ 9 638 $ 9 116
Other 606 494 438
4.Royalties None None None
5.Advertising costs N.A. N.A. N.A.
The amount of maintenance and depreciation charged to expense accounts other
than those set forth in the statement of income are not significant. All other
items required by this schedule are less than 1% of total revenue.
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/ /s/
John A. Noer Jean Gitz Bassett
President and Director Director
(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 Jean Gitz Bassett
President and Director 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, 1993Commission 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 reduced 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
(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 28, 1994
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 1Business 1
REGULATION AND RATES 1
Regulation 1
Rate Changes 2
Fuel and Purchased Gas Adjustment Clauses 2
Demand Side Management 3
ELECTRIC OPERATIONS 4
NSP System 4
Capability and Demand 4
Interchange Agreement 5
Electric Power Pooling Agreements 5
Fuel Supply 5
Environmental Matters 6
GAS OPERATIONS 7
CONSTRUCTION AND FINANCING 7
Item 2 Properties 8
Item 3 Legal Proceedings 9
Item 4 Submission of Matters to a Vote of
Security Holders 9
PART II
Item 5 Market for the Registrant's Common Equity
and Related Stockholder Matters10
Item 6 Selected Financial Data10
Item 7 Management's Discussion and Analysis10
Item 8 Financial Statements and Supplementary Data13
Item 9 Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure27
PART III
Item 10 Directors and Executive Officers of the
Registrant28
Item 11 Executive Compensation28
Item 12 Security Ownership of Certain Beneficial
Owners and Management28
Item 13 Certain Relationships and Related Transactions28
PART IV
Item 14 Exhibits, Financial Statement Schedules and
Reports on Form 8-K29
SIGNATURES 41
Item 14. Exhibits, financial Statement Schedules and Reports on Form 8-K
Financial Statement Schedule V, Property, Plant and Equipment
UTILITY PLANT AND NONUTILITY PROPERTY
FOR THE YEAR ENDED DECEMBER 31, 1993
(Thousands of dollars)
Column A Column B Column C Column D Column E Column F
Other Changes And
Balance at Additions Reclassification Balance At
Beginning At Add Or (Deduct) End Of
Classification Of Year Cost Retirements (Note 1) Year
UTILITY PLANT:
Electric:
Electric plant in service:
Steam production $66,420 $1,742 $103 ($4) $68,055
Hydraulic production 178,678 1,380 34 11 180,035
Other production plant 49,916 425 1,034 2 49,309
Transmission 180,061 11,630 728 (19) 190,944
Distribution 264,033 17,828 4,106 28 277,783
General 25,062 829 724 (132) 25,035
Leased to others 2,833 0 0 0 2,833
Construction WIP 14,571 2,126 0 0 16,697
Total 781,574 35,960 6,729 (114) 810,691
Gas:
Gas plant in service:
Production 0 0 0 0 0
Storage 4,943 503 0 0 5,446
Distribution 63,485 9,438 796 0 72,127
General 2,210 149 24 1 2,336
Construction WIP 4,611 (2,953) 0 0 1,658
Total 75,249 7,137 820 1 81,567
Common:
Common plant in servic 23,192 12,790 644 112 35,450
Construction WIP 5,373 2,456 0 0 7,829
Total Common 28,565 15,246 644 112 43,279
TOTAL UTILITY 885,388 58,343 8,193 (1) 935,537
NONUTILITY PROPERTY 3,119 5 2 35 3,157
TOTAL $888,507 $58,348 $8,195 $34 $938,694
( ) Denotes negative.
See Notes To Schedules V And VI
Item 14. Exhibits, financial Statement Schedules and Reports on Form 8-K
Financial Statement Schedule V, Property, Plant and Equipment
UTILITY PLANT AND NONUTILITY PROPERTY
FOR THE YEAR ENDED DECEMBER 31, 1992
(Thousands of dollars)
Column A Column B Column C Column D Column E Column F
Other Changes And
Balance at Additions Reclassification Balance At
Beginning At Add Or (Deduct) End Of
Classification Of Year Cost Retirements (Note 1) Year
UTILITY PLANT:
Electric:
Electric plant in service:
Steam production $65,938 $557 $76 $1 $66,420
Hydraulic production 174,320 4,362 (9) (13) 178,678
Other production plan 48,954 1,747 787 2 49,916
Transmission 169,395 12,408 1,635 (107) 180,061
Distribution 250,529 17,297 3,911 118 264,033
General 25,051 721 657 (53) 25,062
Leased to others 2,833 0 0 0 2,833
Construction WIP 14,963 (392) 0 0 14,571
Total 751,983 36,700 7,057 (52) 781,574
Gas:
Gas plant in service:
Production 0 0 0 0 0
Storage 4,827 116 0 0 4,943
Distribution 55,469 8,742 726 0 63,485
General 2,087 200 91 14 2,210
Construction WIP 3,975 636 0 0 4,611
Total 66,358 9,694 817 14 75,249
Common:
Common plant in servic 19,393 4,302 538 35 23,192
Construction WIP 3,195 2,178 0 0 5,373
Total Common 22,588 6,480 538 35 28,565
TOTAL UTILITY 840,929 52,874 8,412 (3) 885,388
NONUTILITY PROPERTY 2,879 705 55 (410) 3,119
TOTAL $843,808 $53,579 $8,467 ($413) $888,507
( ) Denotes negative.
See Notes To Schedules V And VI
Item 14. Exhibits, financial Statement Schedules and Reports on Form 8-K
Financial Statement Schedule V, Property, Plant and Equipment
UTILITY PLANT AND NONUTILITY PROPERTY
FOR THE YEAR ENDED DECEMBER 31, 1991
(Thousands of dollars)
Column A Column B Column C Column D Column E Column F
Other Changes And
Balance at Additions Reclassification Balance At
Beginning At Add Or (Deduct) End Of
Classification Of Year Cost Retirements (Note 1) Year
UTILITY PLANT:
Electric:
Electric plant in service:
Steam production $63,178 $3,328 $568 $0 $65,938
Hydraulic production 174,117 2,320 2,124 7 174,320
Other production plan 49,172 86 306 2 48,954
Transmission 157,126 13,209 930 (10) 169,395
Distribution 235,675 18,831 3,980 3 250,529
General 23,406 2,196 604 53 25,051
Leased to others 2,833 0 0 0 2,833
Construction WIP 18,854 (3,891) 0 0 14,963
Total 724,361 36,079 8,512 55 751,983
Gas:
Gas plant in service:
Production 0 0 0 0 0
Storage 4,543 284 0 0 4,827
Distribution 50,690 5,411 632 0 55,469
General 2,074 56 47 4 2,087
Construction WIP 1,542 2,433 0 0 3,975
Total 58,849 8,184 679 4 66,358
Common:
Common plant in service 17,417 2,174 139 (59) 19,393
Construction WIP 430 2,765 0 0 3,195
Total Common 17,847 4,939 139 (59) 22,588
TOTAL UTILITY 801,057 49,202 9,330 0 840,929
NONUTILITY PROPERTY 2,883 39 18 (25) 2,879
TOTAL $803,940 $49,241 $9,348 ($25) $843,808
( ) Denotes negative.
See Notes To Schedules V And VI
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
Financial Statement Schedule VI, Accumulated Depreciation, Depletion and Amortization of
Property, Plant and Equipment
ACCUMULATED PROVISION FOR DEPRECIATION AND AMORTIZATION OF
UTILITY PLANT AND NONUTILITY PROPERTY
FOR THE YEAR ENDED DECEMBER 31, 1993
(Thousands of dollars)
Column A Column B Column C Column D Column E Column F
Depreciation And
Amortization Charged To Deductions
Balance At Clearing Reclassificat'n Balance At
Beginning And Other Property Net Add Or (Deduct) End Of
Description Of Year Income Accounts Retired Salvage Year
UTILITY PLANT:
Electric:
Electric plant in service:
Steam production $30,050 $2,382 $0 $103 ($8) $1 $32,338
Hydraulic production 34,848 4,043 0 34 72 5 38,790
Other production plt 39,922 2,016 0 1,034 3 3 40,904
Transmission 48,065 5,079 0 723 (12) 66 52,499
Distribution 96,377 8,894 0 4,106 280 (62) 100,823
General 12,744 1,034 821 724 (31) (115) 13,791
Leased to others 319 38 0 0 0 0 357
Retirement WIP (869) 0 0 0 572 0 (1,441)
Total 261,456 23,486 821 6,724 876 (102) 278,061
Gas:
Gas plant in service:
Production 0 0 0 0 0 0 0
Storage 3,156 212 0 0 0 0 3,368
Distribution 26,526 2,840 0 796 161 0 28,409
General 998 68 78 24 (3) 1 1,124
Retirement WIP (53) 0 0 0 4 0 (57)
Total 30,627 3,120 78 820 162 1 32,844
Common:
General 6,582 1,958 107 458 4 102 8,287
Retirement WIP (9) 0 0 0 (15) 0 6
Total Common 6,573 1,958 107 458 (11) 102 8,293
Reclassify deferred taxes
included in deprec'n 0 0 0 0 0 0 0
TOTAL UTILITY 298,656 28,564 1,006 8,002 1,027 1 319,198
Limited-term Investmt 1,738 2 0 0 0 0 1,740
Total 300,394 28,566 1,006 8,002 1,027 1 320,938
NONUTILITY PLANT 362 1 0 0 0 0 363
TOTAL $300,756 $28,567 $1,006 $8,002 $1,027 $1 $321,301
( ) Denotes negative.
See Notes To Schedules V And VI
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
Financial Statement Schedule VI, Accumulated Depreciation, Depletion and Amortization of
Property, Plant and Equipment
ACCUMULATED PROVISION FOR DEPRECIATION AND AMORTIZATION OF
UTILITY PLANT AND NONUTILITY PROPERTY
FOR THE YEAR ENDED DECEMBER 31, 1992
(Thousands of dollars)
Column A Column B Column C Column D Column E Column F
Depreciation And
Amortization Charged To Deductions
Balance At Clearing Reclassificat'ns Balance At
Beginning And Other Property Net Add Or (Deduct) End Of
Description Of Year Income Accounts Retired Salvage Year
UTILITY PLANT:
Electric:
Electric plant in service:
Steam production $27,791 $2,367 $0 $76 $33 $1 $30,050
Hydraulic production 31,216 3,951 0 (56) 369 (6) 34,848
Other production plt 38,749 1,993 0 787 33 0 39,922
Transmission 45,875 4,797 0 1,634 919 (54) 48,065
Distribution 92,493 8,668 0 3,911 933 60 96,377
General 11,422 1,011 891 656 (102) (26) 12,744
Leased to others 281 38 0 0 0 0 319
Retirement WIP (1,517) 0 0 0 (648) 0 (869)
Total 246,310 22,825 891 7,008 1,537 (25) 261,456
Gas:
Gas plant in service:
Production 0 0 0 0 0 0 0
Storage 2,960 196 0 0 0 0 3,156
Distribution 24,872 2,560 0 726 180 0 26,526
General 913 45 84 91 (46) 1 998
Retirement WIP (35) 0 0 0 18 0 (53)
Total 28,710 2,801 84 817 152 1 30,627
Common:
General 5,568 1,215 116 353 (12) 24 6,582
Retirement WIP (4) 0 0 0 5 0 (9)
Total Common 5,564 1,215 116 353 (7) 24 6,573
Reclassify deferred taxes
included in deprec'n 0 0 0 0 0 0 0
TOTAL UTILITY 280,584 26,841 1,091 8,178 1,682 0 298,656
Limited-term Investmt 1,737 2 0 1 0 0 1,738
Total 282,321 26,843 1,091 8,179 1,682 0 300,394
NONUTILITY PLANT 361 1 0 0 0 0 362
TOTAL $282,682 $26,844 $1,091 $8,179 $1,682 $0 $300,756
( ) Denotes negative.
See Notes To Schedules V And VI
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
Financial Statement Schedule VI, Accumulated Depreciation, Depletion and Amortization of
Property, Plant and Equipment
ACCUMULATED PROVISION FOR DEPRECIATION AND AMORTIZATION OF
UTILITY PLANT AND NONUTILITY PROPERTY
FOR THE YEAR ENDED DECEMBER 31, 1991
(Thousands of dollars)
Column A Column B Column C Column D Column E Column F
Depreciation And
Amortization Charged To Deductions
Balance At Clearing Reclassificat'ns Balance At
Beginning And Other Property Net Add Or (Deduct) End Of
Description Of Year Income Accounts Retired Salvage Year
UTILITY PLANT:
Electric:
Electric plant in service:
Steam production $26,123 $2,304 $0 $568 $68 $0 $27,791
Hydraulic production 29,661 3,892 0 2,124 214 1 31,216
Other production plt 37,060 1,996 0 306 1 0 38,749
Transmission 42,551 4,519 0 921 272 (2) 45,875
Distribution 88,791 8,178 0 3,980 497 1 92,493
General 10,141 942 862 604 (58) 23 11,422
Leased to others 243 38 0 0 0 0 281
Retirement WIP (1,355) 0 0 0 162 0 (1,517)
Total 233,215 21,869 862 8,503 1,156 23 246,310
Gas:
Gas plant in service:
Production 0 0 0 0 0 0 0
Storage 2,775 187 0 0 2 0 2,960
Distribution 23,338 2,245 0 632 79 0 24,872
General 820 42 91 47 (7) 0 913
Retirement WIP (12) 0 0 0 23 0 (35)
Total 26,921 2,474 91 679 97 0 28,710
Common:
General 4,612 998 115 139 (5) (23) 5,568
Retirement WIP 1 0 0 0 5 0 (4)
Total Common 4,613 998 115 139 0 (23) 5,564
Reclassify deferred taxes
included in deprec'n 0 0 0 0 0 0 0
TOTAL UTILITY 264,749 25,341 1,068 9,321 1,253 0 280,584
Limited-term Investmt 1,734 3 0 0 0 0 1,737
Total 266,483 25,344 1,068 9,321 1,253 0 282,321
NONUTILITY PLANT 360 1 0 0 0 0 361
TOTAL $266,843 $25,345 $1,068 $9,321 $1,253 $0 $282,682
( ) Denotes negative.
See Notes To Schedules V And VI
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