United States
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark one)
X Quarterly report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Transition report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For Quarter Ended June 30, 1998 Commission File Number 10-3140
NORTHERN STATES POWER COMPANY, A WISCONSIN CORPORATION, MEETS THE
CONDITIONS SET FORTH IN GENERAL INSTRUCTION H (1) AND (2) OF FORM 10-Q
AND IS THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE FORMAT.
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 No.)
incorporation or organization)
100 North Barstow Street, Eau Claire, Wisconsin 54703
(Address of principal executive officers) (Zip Code)
Registrant's telephone number, including area code (715)839-2578
NONE
Former name, former address and former fiscal year, if changed since
last report
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such period
that the Registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes X No
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Class Outstanding at August 14, 1998
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.
PART 1. FINANCIAL INFORMATION
Item 1. Financial Statements
<TABLE>
<CAPTION>
Northern States Power Company (Wisconsin)
Statements of Income (Unaudited)
Three Months Ended Six Months Ended
June 30 June 30
1998 1997 1998 1997
(Thousands of dollars)
<S> <C> <C> <C> <C>
Operating revenues
Electric..................................................... $95,432 $90,162 $193,738 $189,035
Gas.......................................................... 11,650 13,634 43,413 53,011
Total...................................................... 107,082 103,796 237,151 242,046
Operating expenses
Purchased and interchange power.............................. 48,263 44,086 96,380 90,799
Fuel for electric generation................................. 3,521 1,667 5,701 3,917
Gas purchased for resale..................................... 7,359 8,420 29,105 36,212
Other operation.............................................. 12,266 11,781 23,308 24,228
Maintenance.................................................. 6,584 5,615 10,743 9,284
Administrative and general................................... 4,737 4,456 9,807 9,127
Conservation and demand side management...................... 2,234 2,234 4,467 4,467
Depreciation and amortization................................ 9,734 9,428 19,048 18,778
Taxes: Property and general.................................. 3,634 3,580 7,305 7,218
Current income tax................................ 1,340 2,867 7,998 10,366
Deferred income tax............................... 526 529 1,036 1,478
Investment tax credits recognized................. (215) (220) (429) (440)
Total...................................................... 99,983 94,443 214,469 215,434
Operating income.............................................. 7,099 9,353 22,682 26,612
Other income (expense)
Allowance for funds used during construction - equity........ 81 48 142 98
Other income and deductions - net of applicable income taxes. 95 302 81 314
Merger costs - net of applicable income taxes................ 0 (523) 0 (523)
Total other income (expense) net............................ 176 (173) 223 (111)
Income before interest charges................................ 7,275 9,180 22,905 26,501
Interest charges
Interest on long-term debt................................... 4,046 4,078 8,117 8,158
Other interest and amortization.............................. 581 531 1,277 1,236
Allowance for funds used during construction - debt.......... (82) (74) (155) (146)
Total interest charges..................................... 4,545 4,535 9,239 9,248
Net Income ................................................... $2,730 $4,645 $13,666 $17,253
Statements of Retained Earnings (Unaudited)
Balance at beginning of period................................ $248,556 $240,360 $244,171 $234,751
Net income for period......................................... 2,730 4,645 13,666 17,253
Dividends paid to parent...................................... (6,551) (7,000) (13,102) (13,999)
Balance at end of period...................................... $244,735 $238,005 $244,735 $238,005
</TABLE>
The Notes to Financial Statements are an integral part of the Statements of
Income and Retained Earnings.
<TABLE>
<CAPTION>
Northern States Power Company (Wisconsin)
Statements of Cash Flows (Unaudited)
Six Months Ended
June 30
1998 1997
(Thousands of dollars)
<S> <C> <C>
Cash Flows from Operating Activities:
Net Income... ............................................... . . . . . $13,666 $17,253
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization........................................ 19,513 19,373
Deferred income taxes................................................ 1,030 563
Deferred investment tax credits recognized........................... (430) (440)
Allowance for funds used during construction - equity................ (143) (98)
Cash provided by changes in certain working capital items.............. 18,914 21,839
Cash (used for) provided by changes in other assets and liabilities.... (1,187) 337
Net cash provided by operating activities............................... 51,363 58,827
Cash Flows from Investing Activities:
Capital expenditures................................................... (24,803) (20,623)
Increase (decrease) in construction payables........................... (212) 595
Allowance for funds used during construction - equity.................. 143 98
Other.................................................................. (144) (560)
Net cash used for investing activities.................................. (25,016) (20,490)
Cash Flows from Financing Activities:
Repayment of notes payable to parent - net............................. (12,000) (23,400)
Dividends paid to parent............................................... (13,102) (13,999)
Net cash used for financing activities.................................. (25,102) (37,399)
Net increase in cash and cash equivalents................................. 1,245 938
Cash and cash equivalents at beginning of period.......................... 31 208
Cash and cash equivalents at end of period................................ $1,276 $1,146
</TABLE>
The Notes to Financial Statements are an integral part of the Statements of
Cash Flows.
<TABLE>
<CAPTION>
Northern States Power Company (Wisconsin)
Balance Sheets (Unaudited)
June 30, December 31,
1998 1997
(Thousands of dollars)
<S> <C> <C>
ASSETS
Utility Plant
Electric..................................................................... $945,926 $931,752
Gas.......................................................................... 107,530 105,362
Other........................................................................ 75,385 70,892
Total.................................................................... 1,128,841 1,108,006
Accumulated provision for depreciation..................................... (441,876) (426,723)
Net utility plant........................................................ 686,965 681,283
Current Assets
Cash......................................................................... 1,276 31
Accounts receivable - net.................................................... 28,797 38,102
Unbilled utility revenues.................................................... 10,151 16,376
Fuel inventories - at average cost........................................... 6,076 12,073
Other materials and supplies inventories - at average cost................... 6,466 5,604
Prepayments and other........................................................ 12,605 12,135
Total current assets....................................................... 65,371 84,321
Other Assets
Regulatory assets............................................................ 35,756 35,634
Other investments............................................................ 8,528 8,166
Federal income tax receivable................................................ 3,307 3,307
Nonutility property - net of accumulated depreciation........................ 2,776 2,752
Unamortized debt expense..................................................... 1,715 1,761
Long-term prepayments and deferred charges................................... 9,749 7,411
Total other assets........................................................ 61,831 59,031
TOTAL ASSETS............................................................. $814,167 $824,635
LIABILITIES AND EQUITY
Capitalization
Common stock - authorized 1,000,000 shares of $100 par value,
issued shares: 1998 and 1997, 862,000................................... $86,200 $86,200
Premium on common stock.................................................... 10,461 10,461
Retained earnings.......................................................... 244,735 244,171
Total common stock equity................................................ 341,396 340,832
Long-term debt............................................................... 231,819 231,775
Total capitalization..................................................... 573,215 572,607
Current Liabilities
Notes payable - parent company............................................... 33,300 45,300
Accounts payable............................................................. 9,565 13,844
Payable to affiliate companies (principally parent).......................... 19,971 15,682
Salaries, wages, and vacation pay accrued.................................... 5,286 6,089
Taxes accrued................................................................ 0 1,775
Interest accrued............................................................. 4,094 4,187
Other........................................................................ 5,657 4,897
Total current liabilities................................................ 77,873 91,774
Other Liabilities
Accumulated deferred income taxes............................................ 107,448 105,850
Accumulated deferred investment tax credits.................................. 18,539 18,970
Regulatory liabilities....................................................... 20,183 19,306
Customer advances............................................................ 8,701 8,192
Benefit obligations and other................................................ 8,208 7,936
Total other liabilities.................................................. 163,079 160,254
Commitments and Contingent Liabilities (see Note 3)
TOTAL LIABILITIES AND EQUITY........................................... $814,167 $824,635
</TABLE>
The Notes to Financial Statements are an integral part of the Balance Sheets.
Northern States Power Company (Wisconsin)
NOTES TO FINANCIAL STATEMENTS
The Company is a wholly owned subsidiary of Northern States Power Company,
a Minnesota corporation (NSPM).
In the opinion of management, the accompanying unaudited financial
statements contain all adjustments necessary to present fairly the financial
position of Northern States Power Company, a Wisconsin corporation (the
Company), as of June 30, 1998 and Dec. 31, 1997, the results of its operations
for the three and six months ended June 30, 1998 and 1997 and its cash flows for
the six months ended June 30, 1998 and 1997. Due to the seasonality of the
Company's electric and gas sales, operating results on a quarterly and year-to-
date basis are not necessarily an appropriate base from which to project annual
results.
The accounting policies followed by the Company are set forth in Note 1 to
the Company's financial statements in its Annual Report on Form 10-K for the
year ended Dec. 31, 1997 (1997 Form 10-K). The following notes should be read in
conjunction with such policies and other disclosures in the Form 10-K.
1. Business Developments
Union Negotiations - Five locals of the International Brotherhood of
Electrical Workers have accepted NSPM's and the Company's proposal to begin
midterm contract negotiations to modify or create new work rules, practices and
operations to improve work force productivity. If these midterm negotiations are
successfully completed by Dec. 31, 1998, NSPM and the Company will then propose
a three-year contract extension with changes to wages and benefits. If the
contract extension is ratified, new terms and conditions will become effective
Jan. 1, 2000. The existing agreements will stay in effect through Dec. 31, 1999
unless they are extended or modified in response to these negotiations.
Increase in Common Stock Authorized - On May 6, 1998, the Company's sole
shareholder approved an increase in the number of common shares authorized from
870,000 to one million.
Loss of Customer - In early 1998, officials of the Fort James Corp.
announced that its Ashland, Wis. paper mill would close on or about March 21,
1998. The mill was the third largest employer in Ashland County and was one of
the Company's ten largest electric and gas customers. The mill purchased in
excess of $2 million of utility services from the Company annually. The effect
of losing this customer was incorporated into the Company's 1998 Wisconsin rate
filing.
Acquisition of Natural Gas, Inc. (NGI) - On July 1, 1998, the Company
completed the acquisition of NGI, a natural gas utility serving approximately
1,900 customers in the New Richmond, Wis. area.
2. Regulation and Rate Matters
1997 Wisconsin Rate Filings - The Company continues to collect an interim
surcharge of $0.00043 per kilowatt-hour (Kwh) from its Wisconsin customers for
the recovery of certain fuel and purchased power costs. The surcharge was
requested because fuel and purchased power costs had risen beyond the amount
included in the Company's current base rates due to unplanned and extended
outages at NSPM's nuclear generating stations and higher than projected wheeling
costs associated with power purchases. The surcharge will continue in effect on
an interim basis until the next rate order is issued and is subject to refund
pending final Public Service Commission of Wisconsin (PSCW) review.
In its order regarding the Company's 1997 rates, the PSCW denied current
rate recovery of the federal government's assessment for the decommissioning and
decontamination of federal uranium enrichment facilities based on a court
decision involving another utility that these assessments were unlawful. The
PSCW, however, did state that it would allow future rate recovery of these costs
with interest if the courts ultimately decided the assessments must be paid.
While the case was under appeal, the Company continued to pay the assessments
and defer the cost as a regulatory asset. At June 30, 1998, $857,000 had been
deferred. On May 6, 1997, the United States Court of Appeals reversed the lower
court's earlier decision that these assessments were unlawful. Accordingly, the
Company has requested recovery of current and deferred assessments in its 1998
retail electric rate filing as discussed below.
1998 Wisconsin Rate Filings - During November 1997, the Company filed retail
electric and gas rate cases with the PSCW requesting an annual increase of
approximately $12.7 million, or 4.3 percent, in retail electric rates and an
annual decrease of $1.7 million, or 1.9 percent, in retail gas rates. In April
1998, the PSCW staff filed testimony recommending an annual rate increase of
$3.8 million in retail electric rates and an annual rate decrease of $2.5
million in retail gas rates based on a much lower recommended return on common
equity of 11.25 percent. In a recent rate case decision by the PSCW for a large
Wisconsin utility, a 12.2 percent return was found reasonable. Although the
Company requested that the rates become effective in the second quarter of 1998,
a final decision by the PSCW has not yet been received, which will delay the
implementation of the new rates. The Company estimates that a final order will
be received during the third quarter of 1998.
Recovery of Network Transmission Service Costs (NTS) - In July 1997, the
Company received authorization from the PSCW to defer its share of NTS costs
incurred after May 23, 1997. Beginning in the third quarter of 1997, the Company
began deferring these costs, including a retroactive adjustment to May 23, 1997.
Through June 30, 1998, $2.9 million of NTS costs had been deferred. Recovery of
deferred NTS costs was requested in the Company's 1998 retail electric rate
case.
Federal Energy Regulatory Commission (FERC) - On Feb. 17, 1998 NSP filed an
application with the FERC to increase its rates for point-to-point transmission
service. As filed, the proposed rates are expected to increase the Company's
annual transmission revenues by approximately $600,000.
FERC Order No. 888 requires utilities to offer, among other services, NTS to
qualifying customers. Under NTS, NSP and other qualifying regional utilities
share the costs of operating and maintaining the regional transmission network
which NSP uses, net of related network revenues, based on each company's share
of the total network load. Each FERC regulated utility files a transmission
tariff containing cost information that is used as the basis for NTS rates. In
March 1998 NSP filed a revision to update its NTS information with the FERC,
which is expected to support reductions in NSP's NTS costs.
In April 1998, the FERC voted to accept the rates, consolidate both the point-
to-point and NTS transmission filings, and defer the effective date of the rate
changes to Oct. 1, 1998. The proposed rate increases would be placed into
effect subject to refund. An administrative law judge and a settlement judge
were appointed to hear arguments and facilitate possible settlements in the
case. As of early August 1998, the cases were in the initial hearing stage.
On June 29, 1998 the FERC issued an order requiring NSP to curtail service to
its own retail sales customers proportionally with curtailments of wholesale
transmission-only customers taking service under NSP's Order 888 transmission
tariff. The effect of FERC's order would require that, in a situation where
NSP's transmission lines are constrained or about to become overloaded, NSP
would reduce or curtail service to retail customers on a comparable basis with
curtailment of wholesale transactions. On July 1, 1998, NSP filed an emergency
request for clarification and rehearing on FERC's June 29 order and a motion to
stay its effective date. On July 31, 1998, the FERC issued a second order,
denying NSP's request.
On Aug. 3, 1998, NSP filed an appeal of the FERC orders with the U.S. Court of
Appeals, Eighth Circuit (Court). NSP believes FERC exceeded its legal authority
because service to retail customers is subject to state regulation, not FERC
regulation. In addition, NSP believes FERC has issued inconsistent orders which
NSP cannot fully comply with and which places reliability of service to NSP's
retail customers at risk. In its petition, NSP requested a court order
delaying enforcement of the FERC orders and authorizing NSP to comply with the
regional transmission service interruption procedures developed by the Mid-
Continent Area Power Pool, pending a final Court decision. NSP also requested
an expedited Court review and ultimate reversal of the FERC orders. On Aug. 6,
1998, the Court denied the motion for stay and expedited consideration. The
underlying appeal will be considered by the Court using its normal procedures.
NSP believes a final decision will be issued later in 1998.
In April 1998 testimony before FERC, NSP proposed to form an Independent
Transmission Company (ITC), as an alternative to an Independent System Operator
(ISO). The ITC would own and operate transmission facilities independent from
vertically integrated utilities and other market participants and satisfy the
regulatory requirements for control of transmission facilities. The ITC
would operate transmission facilities as a for-profit entity. NSP is currently
in discussion with other utilities to form an ITC and is seeking to reach an
agreement to proceed within the next several months. However there can be no
assurance that such an agreement will be reached. In the event NSP is
successful in forming an ITC, NSP anticipates at the present time that as
part of such transaction, it would divest its electric transmission assets
through a sale, spin-off or other means. At June 30, 1998, the net book value of
the Company's transmission assets was approximately $147 million.
Construction Authorization - On April 7, 1998, the PSCW approved the
Company's request to construct a new 161 kilovolt electric transmission line
between Stone Lake, Wis. and the Bay Front Generating Plant in Ashland, Wis.
The new line is needed to maintain reliable electric service to northwestern
Wisconsin. Construction is scheduled to begin in 1999 and the line is expected
to be in service by 2001. The estimated cost is $37 million.
On Sept. 21, 1996, the Company and Dairyland Power Cooperative (DPC) filed
an application for approval to construct a 230 kilovolt electric transmission
line between the Chisago County substation near North Branch, Minn., and the
Apple River substation near Amery, Wis. with the Minnesota Environmental Quality
Board and the PSCW. These two agencies are preparing environmental review
documents which will be released during the third quarter of 1998 and hearings
will occur in the fall of 1998. The total project cost is estimated to be
approximately $50 million, part of which will be paid by DPC.
Industry Restructuring - On April 28, 1998, 1997 Wisconsin Act 204 (Act 204)
became law. Act 204 includes provisions which require the PSCW to order a public
utility that owns transmission facilities to transfer control of its
transmission facilities to an independent system operator (ISO), or divest the
public utility's interest in its transmission facilities to an independent
transmission owner (ITO) if the public utility has not already transferred
control to an ISO, or divested to an ITO by June 30, 2000. Under certain
circumstances the PSCW has authority to waive imposition of such an order on
June 30, 2000. At Dec. 31, 1997, the Company owned approximately 2,390 miles
of transmission lines with a book value of $87.9 million and transmission
substations with a book value of $59.5 million. The Company may attempt to
obtain a legislative amendment in 1999 of the mandatory transfer or divestiture
requirements and is also considering whether to judicially challenge the trans-
mission transfer or divestiture requirements of the new law. See the previous
discussion under the heading "FERC" for more discussion of NSP's possible
divestiture of its transmission assets through the formation of an ITC.
In addition to the ISO / ITC provision in Act 204, there are also provisions
which require the PSCW to promulgate rules on a number of topics including the
owning, operating, and controlling of wholesale merchant plants in Wisconsin by
Wisconsin investor owned utility affiliates; the cost treatment of electricity
to customers that the utility does not have an obligation to serve including in-
state wholesale contracts and out-of-state retail sales; the reporting
requirements of utilities necessary for the commission to develop a strategic
energy assessment and the setting of service standards for electric generation,
transmission and distribution facilities. The PSCW has subsequently developed
dockets for wholesale sales and wholesale merchant plants, and anticipates
recommendations and decision on all topics by late 1999.
Wisconsin Purchased Gas Adjustment Clause - In March 1996, the PSCW conducted a
generic hearing to consider alternative incentive-based gas cost recovery
mechanisms to replace the current purchased gas adjustment clause (PGA). In
November 1996, the PSCW issued an order with general guidelines for incentive-
based gas cost recovery mechanisms as well as "modified one-for-one" gas cost
recovery mechanisms. All major gas utilities in Wisconsin were required to file
a proposal to replace their current PGA. On Sept. 29, 1997 the Company filed
its proposal with the PSCW. The PSCW has decided to review the Company's
proposal in conjunction with its 1998 rate case.
In the Company's proposal, allowable gas commodity cost recovery would be based
on a benchmark index which is, in turn, based on the market price of gas. The
allowable cost recovery of the remaining components of the cost of gas (for
example, fixed pipeline transportation costs, supply reservation costs, and
other costs approved by the FERC) would be based on actual costs incurred, as is
the case with the Company's current PGA.
The PSCW's decision on the Company's 1998 rate case, including the gas cost
recovery mechanism, is expected in the third quarter of 1998. If the Company's
proposal is approved, the financial impact of the new gas cost recovery
mechanism will be substantially the same as with the current PGA. Approximately
70 percent of the Company's gas revenues represent recovery of gas costs through
the PGA mechanism.
Producer Refund - In September 1997, the FERC ruled that Kansas natural gas
producers must refund improperly collected Kansas ad valorem tax collected
from 1983 to 1988 plus interest to their customers. During this period,
Northern Natural Gas (NNG) had bought gas from Kansas producers and resold it
to the Company under terms that require NNG to pass any refund from the
producers back to the Company. In December 1997, NNG received one $30 million
refund and, in turn, refunded $538,000 to the Company. In March, 1998, NNG
received an additional $4.2 million of which $69,000 was refunded to the
Company. However, the Kansas producers are appealing the FERC order and are also
pursuing federal legislation to overturn the FERC order. In February 1998, the
FERC ruled that the Kansas producers could place disputed refunds in escrow
and that pipelines such as NNG could recollect refunded amounts if final refunds
are less than those already paid.
Because regulators have not yet decided whether the refunds must be returned
to the Kansas gas producers, the Company has not yet passed the refunds back to
its customers. A regulatory liability of $607,000 has been recorded for the
Company's responsibility to pay the refund either to its customers or NNG.
3. Commitments and Contingent Liabilities
Environmental Contingencies - As discussed in Note 8 to the Financial
Statements in the 1997 Form 10-K, the Company has been named as one of three
potentially responsible parties in connection with environmental contamination
at a site in Ashland, Wis.
During the second quarter of 1998, the Company entered into a Spill Response
Agreement with the Wisconsin Department of Natural Resources (WDNR) formalizing
its commitment to participate in further investigation of the site. On July 6,
1998, the WDNR issued their report of the first of two risk assessments which
will determine the scope of the remediation effort. During the last half of
1998, the Company expects that the second risk assessment will be completed and
that the WDNR will then issue their report of remediation options. The Company
may need to revise its estimate of future remediation costs after the
remediation option report is issued.
At June 30, 1998, the Company had recorded a regulatory asset of
approximately $1,320,000 related to the estimated future remediation costs of
the Ashland site, plus the amount actually paid to date for remediation at that
site less the amount which the PSCW has allowed the Company to recover from its
customers. The PSCW authorized recovery of amounts paid through 1995, $353,000,
over a two year period beginning in 1997. In its 1998 rate case, the Company
has asked to continue recovery of an additional $293,000 over a two year
period.
4. Pension Costs
Effective Jan. 1, 1998, the Company changed its method of recognizing
actuarial gains and losses included in pension costs under SFAS No. 87. The new
method was adopted to reduce the volatility of accrued pension costs by
amortizing actuarial gains and losses related to pension asset performance over
the longest period allowed by SFAS No. 87. The effect of this change is
expected to be a decrease in pension costs (represented by an increase in
pension accrual credits) of approximately $2.5 million for the full year 1998,
including $1.8 million related to periods prior to the change.
Item 2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATION
Discussion of financial condition and liquidity is omitted per conditions
set forth in general instructions H (1) and (2) of Form 10-Q for wholly-owned
subsidiaries (reduced disclosure format).
The Company's net income for the quarter and six months ended June 30, 1998
was $2.7 million and $13.7 million, respectively, a decrease of $1.9 million and
$3.6 million, respectively from the comparable periods a year ago. The
following analysis summarizes the specific revenue and expense items impacting
these results.
Except for the historical statements contained herein, the matters
discussed in the following discussion and analysis are forward-looking
statements that are subject to certain risks, uncertainties and assumptions.
Such forward-looking statements are intended to be identified in this document
by the words "anticipate", "estimate", "expect", "objective", "possible",
"potential" and similar expressions. Actual results may vary materially.
Factors that could cause actual results to differ materially include, but are
not limited to: general economic conditions, including their impact on capital
expenditures; business conditions in the energy industry; competitive factors;
unusual weather; changes in federal or state legislation; issues relating to
year 2000 remediation efforts; and the other risk factors listed from time to
time by the Company in reports filed with the SEC, including Exhibit 99.01 to
this report on Form 10-Q for the quarter ended June 30, 1998.
Second Quarter 1998 Compared with Second Quarter 1997
Electric revenues in total increased $5.3 million or 5.8 percent in the
second quarter of 1998 compared with the second quarter of 1997. Electric
revenues from sales to customers increased $3.2 million largely due to sales
growth. On a weather-normalized basis, sales increased 4.0 percent in the
second quarter of 1998 compared to the same period in 1997. The remaining
$2.1 million increase in electric revenues relates to higher Interchange Agree-
ment billings to NSPM in 1998, reflecting an increase in the Company's fuel and
transmission expenses.
Gas revenues decreased $2.0 million or 14.6 percent in the second quarter of
1998 compared with the second quarter of 1997 due to lower sales levels
partially offset by natural gas related price increases. Total gas sales
volumes decreased 15.5 percent in the second quarter of 1998 compared to the
same period in 1997 due to less favorable weather and lower interruptible sales.
Higher costs per unit of gas, as discussed below, are reflected in customer
rates through the purchased gas adjustment clause mechanism.
Purchased and Interchange Power and Fuel for Electric Generation together
increased $6.0 million or 13.2 percent for second quarter 1998 compared to
second quarter 1997 due to additional generation and power purchases to support
increased sales levels and higher demand expenses billed from NSPM in 1998.
Gas purchased for resale decreased $1.1 million or 12.6 percent in the second
quarter 1998 compared to the second quarter 1997 due to lower sales volumes
partially offset by higher costs per unit of gas charged by suppliers.
Other Operation, Maintenance, and Administrative and General expenses
together increased $1.7 million or 7.9 percent in the second quarter of 1998
compared to the same period in 1997 due to higher customer service expenses,
fixed transmission expenses, distribution maintenance expenses including those
related to storm damage, and employee benefit expenses in 1998. Partially
offsetting these increased costs in second quarter 1998 were lower hydro
regulatory and transmission operating expenses. Transmission operating expenses
decreased in 1998 mainly due to $0.9 million in NTS costs incurred in the second
quarter of 1997, before the PSCW approved deferral of such costs as discussed in
Note 2.
Depreciation and amortization increased $0.3 million or 3.2 percent in the
second quarter of 1998 compared with the same period in 1997 due to increases in
the Company's plant in service.
Income tax decreased $1.5 million in the second quarter 1998 as compared to
the second quarter 1997 reflecting lower pretax operating income in 1998.
Other income (expense) - net income increased $0.3 million in the second
quarter of 1998 as compared with the same quarter in 1997 largely due to an
expense write-off in 1997 for $0.5 million in deferred merger costs offset
partially by lower subsidiary company earnings in 1998.
Interest expense was approximately the same for both periods.
First Six Months of 1998 Compared with First Six Months of 1997
Electric revenues in total increased $4.7 million or 2.5 percent for the
first six months of 1998 compared with the first six months of 1997. Electric
revenues from sales to customers increased $3.2 million largely due to sales
growth, partially offset by less favorable weather in 1998. On a weather-
normalized basis, sales increased 3.8 percent in the first six months of 1998
compared with the first six months of 1997. The remaining $1.5 million increase
in electric revenues relates to higher Interchange Agreement billings to NSPM in
1998, reflecting an increase in the Company's fuel and transmission expenses.
Gas revenues for the first six months of 1998 decreased $9.6 million or 18.1
percent as compared with the first six months of 1997 due to lower sales levels,
partially offset by natural gas related price increases. Total gas sales
volumes decreased 14.8 percent in the first six months of 1998 compared to the
same period in 1997 due to less favorable weather and lower interruptible sales.
Higher costs per unit of purchased gas, as discussed below, are reflected in
customer rates through the purchased gas adjustment clause mechanism.
Purchased and Interchange Power and Fuel for Electric Generation together
increased $7.4 million or 7.8 percent in the first six months of 1998 compared
with the first six months of 1997 due to additional generation and power
purchases to support increased sales levels in 1998 and higher demand expenses
billed from NSPM in 1998.
Gas purchased for resale decreased $7.1 million or 19.6 percent in the first
six months of 1998 compared with the first six months of 1997 primarily due to
lower sales volumes. Partially offsetting this decrease were higher costs per
unit of gas charged by suppliers.
Other Operation, Maintenance, and Administrative and General expenses
together increased $1.2 million or 2.9 percent in the first six months of 1998
compared with the first six months of 1997. Higher customer service expenses,
fixed transmission expenses, distribution maintenance expenses including those
related to storm damage, and employee benefit expenses in 1998 were partially
offset by lower generating and transmission operating expenses. Transmission
operating expenses decreased in 1998 mainly due to $1.8 million in NTS costs
incurred in the first six months of 1997, before the PSCW approved deferral of
such costs as discussed in Note 2.
Depreciation and amortization increased $0.3 million or 1.4 percent in the
first six months of 1998 compared with the same period in 1997 due to increases
in the Company's plant in service.
Income tax decreased $2.8 million in the first six months of 1998 compared
with the first six months of 1997 reflecting lower pretax operating income in
1998.
Other income (expense) - net income increased $0.3 million in the first six
months of 1998 compared with the same period in 1997 largely due to an expense
write-off in 1997 for $0.5 million in deferred merger costs offset partially by
lower subsidiary company earnings in 1998.
Interest expense was approximately the same for both periods.
Industry Restructure
Efforts are continuing to bring more competition to the electric and gas
industry. Wisconsin has enacted legislation requiring utilities to form an ISO
or to divest its transmission assets to a ITO. NSP is separately considering
the formation of an ITC. See Note 2 of the Financial Statements for a further
discussion of these matters.
Technology Changes for the Year 2000
NSPM and its subsidiaries (NSP) expects to incur significant costs to modify
or replace existing technology, including computer software, for uninterrupted
operation in the year 2000 and beyond. In 1996, NSP's Board of Directors
approved funding to address development and remediation efforts related to the
year 2000. A committee made up of senior management is leading NSP's initiatives
to identify year 2000 related issues and remediate business processes as
necessary in 1998.
NSP's year 2000 program covers not only NSP's computer applications but also
the thousands of hardware and embedded system components in use throughout NSP.
Embedded systems perform mission-critical functions in all parts of operations
including power generation, distribution, communications and business
operations. NSP is on track to remediate critical applications and critical
embedded components by the end of 1998 or during scheduled 1999 plant outages
and to devote 1999 to remediating lower priority items, fine tuning and re-
testing, and contingency planning.
NSP is working with major suppliers to minimize business interruptions due to
year 2000 issues in the suppliers' business processes. NSP is also working
closely with the Electric Power Research Institute, the Mid-Continent Area Power
Pool, the Nuclear Energy Institute, the North American Electric Reliability
Council and other utilities to enhance coordination, system reliability and
compliance with industry and regulatory requirements.
Despite these efforts there can be no assurances that every year 2000 related
issue will be identified and addressed before 2000. An unexpected failure
regarding a year 2000 issue could result in an interruption in certain normal
business activities or operations. However, NSP believes that with the
completion of its year 2000 project, significant interruptions will not be
encountered.
Through June 30, 1998 the Company had spent approximately $430,000 for year
2000 remediation. The total estimate of development and remediation costs
necessary for the Company to prepare for the year 2000 is estimated to be
approximately $1.1 million.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
The following exhibits are filed with this report:
27.01 Financial Data Schedule for the six months ended June 30,
1998.
99.01 Statement pursuant to Private Securities Litigation
Reform Act of 1995.
(b) Reports on Form 8-K
None
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
NORTHERN STATES POWER COMPANY (WISCONSIN)
(Registrant)
/s/
Roger D. Sandeen
Treasurer and Controller
(Principal Financial and Accounting Officer)
Date: August 14, 1998
EXHIBIT INDEX
Method of Exhibit Description
Filing No.
DT 27.01 Financial Data Schedule for the six months
ended June 30, 1998
DT 99.01 Statement pursuant to Private Securities
Litigation Reform Act of 1995.
DT = Filed electronically with this Direct Transmission
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
EXHIBIT 27.01
This schedule contains summary financial information extracted from the
Statements of Income and Retained Earnings, Balance Sheets and Statements
of Cash Flows and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> JUN-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 686,965
<OTHER-PROPERTY-AND-INVEST> 11,304
<TOTAL-CURRENT-ASSETS> 65,371
<TOTAL-DEFERRED-CHARGES> 50,527
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 814,167
<COMMON> 86,200
<CAPITAL-SURPLUS-PAID-IN> 10,461
<RETAINED-EARNINGS> 244,735
<TOTAL-COMMON-STOCKHOLDERS-EQ> 341,396
0
0
<LONG-TERM-DEBT-NET> 231,819
<SHORT-TERM-NOTES> 33,300
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 207,652
<TOT-CAPITALIZATION-AND-LIAB> 814,167
<GROSS-OPERATING-REVENUE> 237,151
<INCOME-TAX-EXPENSE> 8,605
<OTHER-OPERATING-EXPENSES> 205,864
<TOTAL-OPERATING-EXPENSES> 214,469
<OPERATING-INCOME-LOSS> 22,682
<OTHER-INCOME-NET> 223
<INCOME-BEFORE-INTEREST-EXPEN> 22,905
<TOTAL-INTEREST-EXPENSE> 9,239
<NET-INCOME> 13,666
0
<EARNINGS-AVAILABLE-FOR-COMM> 13,666
<COMMON-STOCK-DIVIDENDS> 13,102
<TOTAL-INTEREST-ON-BONDS> 8,117
<CASH-FLOW-OPERATIONS> 51,363
<EPS-PRIMARY> 15.85
<EPS-DILUTED> 15.85
</TABLE>
<PAGE>
Exhibit 99.01
Northern States Power Company Cautionary Factors
The Private Securities Litigation Reform Act of 1995 (the Act)
provides a new "safe harbor" for forward-looking statements to encourage
such disclosures without the threat of litigation providing those
statements are identified as forward-looking and are accompanied by
meaningful, cautionary statements identifying important factors that
could cause the actual results to differ materially from those projected
in the statement. Forward-looking statements have been and will be made
in written documents and oral presentations of Northern States Power
Company, a Wisconsin Corporation (the Company). Such statements are
based on management's beliefs as well as assumptions made by and
information currently available to management. When used in the
Company's documents or oral presentations, the words "anticipate",
"estimate", "expect", "objective", "possible", "potential" and similar
expressions are intended to identify forward-looking statements. In
addition to any assumptions and other factors referred to specifically
in connection with such forward-looking statements, factors that could
cause the Company's actual results to differ materially from those
contemplated in any forward-looking statements include, among others,
the following:
o Economic conditions including inflation rates and monetary
fluctuations;
o Trade, monetary, fiscal, taxation, and environmental policies of
governments, agencies and similar organizations in geographic areas
where the Company has a financial interest;
o Customer business conditions including demand for their products or
services and supply of labor and materials used in creating their
products and services;
o Financial or regulatory accounting principles or policies imposed by
the Financial Accounting Standards Board, the Securities and Exchange
Commission, the Federal Energy Regulatory Commission and similar
entities with regulatory oversight;
o Availability or cost of capital such as changes in: interest rates;
market perceptions of the utility industry, or the Company; or
security ratings;
o Factors affecting operations such as unusual weather conditions;
catastrophic weather-related damage; unscheduled generation outages,
maintenance or repairs; unanticipated changes to fossil fuel or gas
supply costs or availability due to higher demand, shortages,
transportation problems or other developments; environmental
incidents; or electric transmission or gas pipeline system
constraints;
o Employee work force factors including loss or retirement of key
executives, collective bargaining agreements with union employees, or
work stoppages;
o Increased competition in the utility industry, including: industry
restructuring initiatives; transmission system operation and/or
administration initiatives; recovery of investments made under
traditional regulation; nature of competitors entering the industry;
retail wheeling; a new pricing structure; and former customers
entering the generation market;
o Rate-setting policies or procedures of regulatory entities, including
environmental externalities, which are values established by
regulators assigning environmental costs to each method of electricity
generation when evaluating generation resource options;
o Social attitudes regarding the utility and power industries;
o Cost and other effects of legal and administrative proceedings,
settlements, investigations and claims;
o Technological developments that result in competitive disadvantages
and create the potential for impairment of existing assets;
o Other business or investment considerations that may be disclosed from
time to time in the Company's Securities and Exchange Commission
filings or in other publicly disseminated written documents.
The Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information,
future events or otherwise. The foregoing review factors pursuant to
the Act should not be construed as exhaustive or as any admission
regarding the adequacy of disclosures made by the Company prior to the
effective date of the Act.
