<PAGE>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR QUARTER ENDED SEPTEMBER 30, 1997 COMMISSION FILE NUMBER 1-3034
NORTHERN STATES POWER COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
MINNESOTA 41-0448030
(State of other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
414 NICOLLET MALL, MINNEAPOLIS, MINNESOTA 55401
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (612) 330-5500
None
Former name, former address and former fiscal year, if changed since last report
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at October31, 1997
Common Stock, $2.50 par value 74,460,438 shares
<PAGE>
PART 1. FINANCIAL INFORMATION
Northern States Power Company(Minnesota) and Subsidiaries
Consolidated Statements ofIncome (Unaudited)
<TABLE>
Three Months Ended Nine Months Ended
September 30 September 30
1997 1996 1997 1996
<S <C> <C> <C> <C>
Utility operating revenues
Electric $645,268 $586,001 $1,682,445 $1,605,708
Gas 52,175 47,257 351,818 338,518
Total 697,443 633,258 2,034,263 1,944,226
Utility operating expenses
Fuel for electric generation 82,936 74,110 232,377 220,331
Purchased and interchange power 82,231 70,453 212,542 193,148
Cost of gas purchased and 27,974 22,057 222,372 207,088
transported
Other operation 93,942 78,452 276,401 243,510
Maintenance 38,737 33,411 122,975 120,804
Administrative and general 37,549 41,220 108,493 116,579
Conservation and energy management 19,342 17,224 52,650 47,203
Depreciation and amortization 81,469 76,899 241,960 227,644
Taxes: Property and general 58,571 62,975 176,169 182,889
Current income 52,550 52,626 125,710 139,946
Deferred income 5,822 566 (3,392) (13,855)
Investment tax credits recognized (2,220) (2,191) (6,576) (6,596)
Total 578,903 527,802 1,761,681 1,678,691
Utility operating income 118,540 105,456 272,582 265,535
Other income (expense)
Income from nonregulated 2,223 5,592 13,959 11,021
businesses - before interest and
taxes
Allowance for funds used during 1,382 1,457 5,203 5,579
construction - equity
Merger costs - - (29,005) -
Other utility income (2,383) 373 (7,376) (1,320)
(deductions) - net
Income taxes on nonregulated 9,274 4,018 32,475 11,256
operations and non-operating
items
Total 10,496 11,440 15,256 26,536
Income before financing costs 129,036 116,896 287,838 292,071
Financing costs
Interest on utility long-term debt 25,506 25,440 76,754 75,816
Other utility interest and 4,965 5,776 15,102 16,536
amortization
Nonregulated interest and 9,376 4,875 22,139 13,643
amortization
Allowance for funds used during (2,661) (3,434) (8,595) (8,755)
construction - debt
Total interest charges 37,186 32,657 105,400 97,240
Distributions on redeemable 3,938 - 10,500 -
preferred securities of
subsidiary trust
Total financing costs 41,124 32,657 115,900 97,240
Net Income 87,912 84,239 171,938 194,831
Preferred stock dividends and 2,371 3,061 8,699 9,184
redemption premiums
Earnings available for common $85,541 $81,178 $163,239 $185,647
stock
Average number of common and
equivalent shares
outstanding (000's 69,556 68,948 69,088 68,642
Earnings per average common $1.23 $1.18 $2.36 $2.70
share*
Common dividends declared per $0.705 $0.690 $2.100 $2.055
share
Consolidated Statements of Retained Earnings (Unaudited)
Balance at beginning of period $1,322,265 $1,277,203 $1,340,799 $1,266,026
Net income for period 87,912 84,239 171,938 194,831
Dividends declared:
Preferred stock (2,371) (3,061) (7,551) (9,184)
Common stock (52,165) (47,118) (148,397) (140,410)
Premium on redeemed preferred - - (1,148) -
stock
Balance at end of period $1,355,641 $1,311,263 $1,355,641 $1,311,263
</TABLE>
The Notes to Financial Statements are an integral
part of the Statements of Income and Retained Earnings .
* As described in the Management's Discussion and Analysis,
earnings for the nine months ended September 30, 1997, were
reduced by $0 25 per share due to the write-off of $29 million
in merger related costs.
<PAGE>
Northern States Power Company (Minnesota) and Subsidiaries
Consolidated Balance Sheets (Unaudited)
<TABLE>
September 30, 1997 December 31,1996
ASSETS (Thousands of dollars)
<S> <C> <C>
Utility Plant
Electric $6,943,478 $6,766,896
Gas 802,504 750,449
Other 333,169 331,441
Total 8,079,151 7,848,786
Accumulated provision for depreciation (3,831,480) (3,611,244)
Nuclear fuel 917,031 892,484
Accumulated provision for amortization (821,861) (792,146)
Net utility plant 4,342,841 4,337,880
Current Assets
Cash and cash equivalents 112,521 51,118
Customer accounts receivable - net 241,215 288,330
Unbilled utility revenues 88,988 147,366
Notes receivable from nonregulated projects 61,014 5,753
Other receivables 60,417 77,571
Fossil fuel inventories - at average cost 65,601 45,013
Materials and supplies inventories - at 111,106 109,425
average cost
Prepayments and other 44,606 72,647
Total current assets 785,468 797,223
Other Assets
Equity investments in nonregulated projects 712,968 412,175
External decommissioning fund and other 371,679 299,804
investments
Regulatory assets 351,345 354,128
Nonregulated property - net of accumulated 224,329 192,790
depreciation
Notes receivable from nonregulated projects 75,889 75,811
Other long-term receivables 55,363 63,684
Intangible assets - net 62,398 46,168
Long-term prepayments and deferred charges 76,324 57,237
Total other assets 1,930,295 1,501,797
TOTAL ASSETS $7,058,604 $6,636,900
LIABILITIES AND EQUITY
Capitalization
Common stock equity:
Common stock and premium - authorized
160,000,000 shares of $2 50 par value,
issued shares:
1997, 74,241,545; 1996, 69,063,712 $1,061,680 $811,378
Retained earnings 1,355,641 1,340,799
Leveraged common stock held by ESOP (13,865) (19,091)
Currency translation adjustments - net (30,835) 2,794
Total common stock equity 2,372,621 2,135,880
Cumulative preferred stock and premium -
authorized 7,000,000 shares of $100 par value;
outstanding shares: 1997, 2,000,000; 1996,
2,400,000 without mandatory redemption 200,340 240,469
Mandatorily redeemable preferred securities 200,000
of subsidiary trust - guaranteed BY NSP*
Long-term debt 1,856,479 1,592,568
Total capitalization 4,629,440 3,968,917
Current Liabilities
Long-term debt due within one year 116,935 119,618
Other long-term debt potentially due within 141,600 141,600
one year
Short-term debt - primarily commercial paper 106,680 368,367
Accounts payable 170,852 236,341
Taxes accrued 214,878 204,348
Interest accrued 36,690 34,722
Dividends payable on common and preferred stocks 54,690 50,409
Accrued payroll, vacation and other 76,976 80,995
Total current liabilities 919,301 1,236,400
Other Liabilities
Deferred income taxes 808,333 804,342
Deferred investment tax credits 141,455 149,606
Regulatory liabilities 362,289 302,647
Postretirement and other benefit obligations 129,534 114,312
Other long-term obligations and deferred income 68,252 60,676
Total other liabilities 1,509,863 1,431,583
Commitments and Contingent Liabilities (See Note 4)
TOTAL LIABILITIES AND EQUITY $7,058,604 $6,636,900
</TABLE>
The Notes to Financial Statements are an integral part of the Balance Sheets .
* As described in Note 2 to Financial Statements, the primary asset of
NSP Financing I, a subsidiary trust of NSP, is $200 million principal
amount of the Company' 7.875% Junior Subordinated Debentures due 2037.
<PAGE>
Northern States Power Company (Minnesota) and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
<TABLE>
Nine Months Ended
September 30,
1997 1996
(Thousands of dollars)
<S> <C> <C>
Cash Flows from Operating Activities:
Net Income $171,938 $194,831
Adjustments to reconcile net income to cash
from operating activities:
Depreciation and amortization 265,994 249,429
Nuclear fuel amortization 30,242 32,843
Deferred income taxes (9,396) (16,935)
Deferred investment tax credits recognized (6,343) (6,827)
Allowance for funds used during construction - (5,203) (5,579)
equity
Undistributed equity in earnings of (7,086) (16,312)
unconsolidated affiliates
Write-off of prior year merger costs 25,289 -
Cash provided by changes in certain working 51,669 828
capital items
Cash provided by (used for) changes in other (8,240) 4,651
assets and liabilities
Net cash provided by operating activities 508,864 436,929
Cash Flows from Investing Activities:
Capital expenditures (319,904) (311,028)
Increase (decrease) in construction payables (1,051) 6,646
Allowance for funds used during construction - 5,203 5,579
equity
Investment in external decommissioning fund (30,750) (28,964)
Equity investments, loans and deposits for (353,078) (181,662)
nonregulated projects
Collection of loans made to nonregulated projects 3,840 111,800
Other investments - net (6,625) 477
Net cash used for investing activities (702,365) (397,152)
Cash Flows from Financing Activities:
Change in short-term debt - net issuances (261,716) 6,407
(repayments)
Proceeds from issuance of long-term debt - net 266,348 126,472
Repayment of long-term debt, including (6,650) (15,754)
reacquisition premiums
Proceeds from issuance of common stock - net 256,560 41,770
Proceeds from issuance of redeemable preferred 193,307 -
securities - net
Redemption of preferred stock, including -
reacquisition premiums (41,278)
Dividends paid (151,667) (148,068)
Net cash provided by financing activities 254,904 10,827
Net increase in cash and cash equivalents 61,403 50,604
Cash and cash equivalents at beginning of period 51,118 28,794
Cash and cash equivalents at end of period $112,521 $79,398
</TABLE>
The Notes to Financial Statements are an integral part of the
Statements of Cash Flows.
NORTHERN STATES POWER COMPANY (MINNESOTA) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In the opinion of management, the accompanying unaudited financial statements
contain all adjustments necessary to present fairly the financial position of
Northern States Power Company (Minnesota) (the Company) and its subsidiaries
(collectively, NSP) as of Sept. 30, 1997 and Dec. 31, 1996, the results of its
operations for the three and nine months ended Sept. 30, 1997 and 1996, and its
cash flows for the nine months ended Sept. 30, 1997 and 1996. Due to the
seasonality of NSP's electric and gas sales and variability of nonregulated
operations, operating results on a quarterly basis are not necessarily an
appropriate base from which to project annual results.
The accounting policies followed by NSP are set forth in Note 1 to the
financial statements in NSP's Annual Report on Form 10-K for the year ended
December 31, 1996 (1996 Form 10-K). The following notes should be read in
conjunction with such policies and other disclosures in the 1996 Form 10-K.
Certain reclassifications have been made to 1996 financial information to
conform with the 1997 presentation. These reclassifications had no effect on
net income or earnings per share as previously reported.
1. CHANGE IN REPORTING OF EARNINGS PER SHARE
Effective for year-end 1997 financial statements, NSP will be required to
present its results of operations on a per share basis in accordance with
Statement of Financial Accounting Standards (SFAS) No. 128, Earnings Per Share
(EPS). This new reporting standard requires a dual presentation of EPS on the
face of the income statement, with one calculation assuming no dilution and
another assuming full dilution from potential issuance of unexercised stock
awards. The SFAS No. 128 method differs from the current approach, under which
some dilution from common stock equivalents is assumed in the "primary" EPS
calculation. Applying the new standard to the results for the three and nine
month periods ended Sept. 30, 1996 and 1997 would change reported EPS by less
than one cent per share. The impact of applying SFAS No. 128 to other historical
periods is expected to be immaterial.
2. BUSINESS DEVELOPMENTS
TERMINATION OF PROPOSED MERGER - As discussed in the Company's Form 8-K filed
on May 19, 1997, NSP and Wisconsin Energy Corporation (WEC) announced on May 16,
1997 that they mutually agreed to terminate their plans to merge the two
companies. As a result of the merger termination, NSP charged to expense in the
second quarter of 1997 its share of deferred merger-related costs.
Minnesota Public Utilities Commission (MPUC) procedures required that NSP
formally request closure of the merger application docket filed with them. In
July 1997, the MPUC approved NSP's request to withdraw its merger application.
The MPUC also determined in the third quarter of 1997 that it did not need to
further pursue issues raised during the merger proceedings relating to NSP's
rates, service quality, and ratemaking treatment of a contract settlement
related to a prior period.
BUSINESS INTERRUPTIONS - The Company experienced several events in the second
and early third quarters that resulted in interruptions to normal business
operations, including flooding, unscheduled plant outage and unusual storm
damage. See Management's Discussion and Analysis for discussion of the financial
effects of these items.
UNION AGREEMENTS - A new three-year collective-bargaining agreement was
ratified by the Company's union membership on April 10, 1997. All provisions of
this new agreement are effective retroactively to Jan. 1, 1997. The prior
agreement had expired Dec. 31, 1996, but was extended to April 30, 1997.
ISSUANCE OF TRUST ORIGINATED PREFERRED SECURITIES (TOPRS) - As previously
reported, on Jan. 31, 1997, 8,000,000 shares of 7.875 percent TOPrS were issued
and sold through NSP Financing I, a statutory business trust formed under
Delaware law. The Company owns all of the common equity securities of the trust
and, accordingly, the trust is treated as a subsidiary of NSP, with its accounts
included in NSP's consolidated financial statements. The business trust was
formed for the sole purpose of issuing the TOPrS, and the primary asset of the
trust is $200 million of 7.875 percent unsecured Junior Subordinated Debentures
issued by the Company and maturing in 2037. NSP Financing I used the proceeds
from the sale of $200 million of TOPrS to purchase such Debentures, which are
eliminated in NSP's consolidation. The Company used the proceeds from the
issuance of such Debentures to redeem $40 million of preferred stock and to
repay a portion of outstanding short-term borrowings.
The quarterly interest and other payment dates for the Debentures coincide
with the distribution and other payment dates for the TOPrS. NSP has the right
to defer payments of interest on the Debentures by extending the interest
payment period, at any time, for up to 20 consecutive quarters. If interest
payments on the Debentures are so deferred, distributions on the TOPrS will also
be deferred. During any deferral, distributions will continue to accrue with
interest thereon. In addition, during any such deferral, NSP may not, except in
certain limited circumstances, declare or pay any dividend or other distribution
on, or redeem or purchase, any of its capital stock.
The TOPrS are redeemable by NSP (in whole or in part) from time to time,
beginning in 2002, or at any time in the event of certain income tax
circumstances. If the debentures are redeemed, the trust must redeem TOPrS
having an aggregate liquidation amount equal to the aggregate principal amount
of the debentures so redeemed. Upon redemption, holders of the TOPrS are
generally entitled to receive a liquidation amount of $25 per share plus accrued
and unpaid distributions. The TOPrS must be fully redeemed when the Debentures
mature in 2037.
The payment of distributions related to the TOPrS by NSP Financing I and
payments on liquidation of NSP Financing I or the redemption of the TOPrS are
guaranteed by NSP (the "Guarantee"), to the extent set forth therein. The
Guarantee covers payments of distributions and other payments on the TOPrS only
to the extent NSP makes a payment of interest or principal on the Debentures.
NSP's obligations under the Debentures and the Guarantee are subordinate and
junior in right of payment to certain indebtedness of NSP.
NRG INVESTMENTS - In May 1997, the Company's wholly owned subsidiary NRG
Energy, Inc. (NRG), as part of a consortium with CMS Energy Corporation (CMS)
and Horizon Energy Australia Investments, closed on its acquisition of the
Australian State of Victoria's Loy Yang A power plant (Loy Yang), Victoria's
largest and Australia's lowest-cost electric generating facility. Loy Yang is a
2,000 megawatt (MW), brown coal-fired power station. The acquisition included
an adjacent coal mine. The total purchase price was approximately 4.7 billion
Australian dollars (or US$3.7 billion as of May 12, 1997). NRG holds a 25.37
percent ownership interest in the consortium. While most of the purchase price
was raised through project-financed loans and leveraged leases that are non-
recourse to the three partners, NRG paid $257 million for its equity interest in
Loy Yang.
Loy Yang is one of the newest and most modern of Victoria's brown coal-fired
generating plants, with a portion of its electric output committed under power
supply contracts through the year 2000. The coal mine has two billion tons of
proven coal reserves, enough to serve the coal supply needs for 50 years of the
Loy Yang plant acquired by the consortium and the Loy Yang B plant not included
in the acquisition. The mine has a supply contract with the 1,000 MW Loy Yang B
electric generating plant and the exclusive rights to provide coal supplies for
a third Loy Yang generating plant, should it be built. Loy Yang is jointly
managed and operated by CMS and NRG.
In June 1997, loan financing was obtained for the refurbishment and expansion
of the Energy Center Kladno (Kladno) plant in Kladno, the Czech Republic. NRG
owns a 34 percent interest in the existing coal-fired electric and thermal
energy generating facility that can supply 28 MW of electricity and 150 MW-
thermal of steam and heated water. This project financing will fund the
refurbishment of the existing facility as well as the expansion project to add
354 MW of new capacity, of which 282 MW will be coal-fired and 72 MW will be
gas-fired. NRG currently holds a 57.85 percent interest in the expansion
project and El Paso Energy International and Stredoceska Energeticka (STE), the
regional Czech electric distribution company, own the remaining percentage of
the expansion. Kladno has executed a 20-year agreement to supply electricity to
STE and thermal energy to the district heating company in the city of Kladno.
Long-term fuel supply agreements have been made with local Kladno mining
companies.
In June 1997, P.T. Dayalistrik Pratama (PTDP), a limited liability company of
which NRG owns 45 percent, signed a coal supply agreement and purchased land for
the 400 MW coal-fired Cilegon power generation facility to be built in West
Java, Indonesia. NRG's expected equity investment in PTDP is $65 million, with
the total project cost of $560 million to be financed by a combination of equity
investments, commercial bank debt and capital markets funding. During September
1997, the government of Indonesia stated its intention to review or postpone a
number of infrastructure projects, and NRG was notified that the Cilegon project
is under review.
In July 1997, an NRG affiliate signed an agreement with Millennium
Petrochemicals Inc. (Millennium) to develop, finance, construct and operate a
117 MW cogeneration plant at Millennium's Morris, Ill. polyethylene
manufacturing facility. The plant will provide the facility's steam and
electrical needs pursuant to a 25-year contract and would market the excess
electric capacity. Construction began in September 1997 with anticipated
operations beginning the end of 1998. Millennium will have the right to buy out
the contract at fair market values at certain defined points in the contract
term. Millennium, a subsidiary of Millennium Chemicals Inc., is the largest
domestic producer of polyethylene and a major supplier of performance polymers
and select chemicals. During the third quarter of 1997, NRG obtained $16 million
in project financing for Millennium with additional financing anticipated in
late 1997 or early 1998.
Since late 1996, NRG has had a right to acquire a 27.75 percent interest in
the 390 MW Alto Cachapoal hydroelectric complex that is under development in
central Chile. Alto Cachapoal is a two-stage "greenfield" project. In the
first 195 MW stage, Alto Cachapoal plans to sell all of its firm energy to
Codelco-El Teniente, the world's largest underground copper mine, pursuant to a
20-year power sales contract. Closing of the first stage has been delayed
beyond 1997. Along with NRG, Nordic Power Invest AB also has a right to acquire
a 27.75 percent interest in the Alto Cachapoal facility from Construction
Andrade Gutierrez, the current owner of the project.
As discussed in the 1996 Form 10-K, an NRG subsidiary has a 50 percent
interest in the Sunnyside cogeneration joint venture in Utah, which sells energy
and capacity to PacifiCorp under a power purchase agreement with an initial term
expiring in 2023. Under the agreement, PacifiCorp is obligated to pay for:
energy at prices based on PacifiCorp's avoided cost, base capacity at a
levelized fixed price, and additional capacity at escalating fixed prices. The
Sunnyside facility has experienced a shortfall in project cash flow attributable
primarily to decreased revenues due to avoided energy rates being significantly
lower than originally forecasted. In addition, higher fuel costs than
originally forecasted may be incurred in the future. These changes in the
economic performance of the Sunnyside project have caused NRG to explore its
options. In particular, the joint venture has negotiated with PacifiCorp to
restructure payments under the power purchase agreement, and the joint venture
has discussed a restructuring of the project debt with its bondholders. In the
absence of a restructuring of the project's debt, a debt service reserve fund,
which has been used to make up cash shortfalls, is expected to be depleted by
the end of 1997. There can be no assurance that either PacifiCorp or the
bondholders will agree to any restructuring, nor can there be any assurances as
to the actions the joint venture may take when and if the debt service reserve
fund is depleted. NRG's investment in Sunnyside is approximately $12.5
million.
In September 1997, the Estonian government announced it would not accept
various aspects of NRG's proposed business plan for a joint project in Estonia
for the acquisition, refurbishment and operations of 3,000 MW of generation and
the associated fossil fuel supplies. NRG and government officials are in
discussions to determine if a mutually acceptable business plan can be
developed.
During September 1997, NRG and its joint venture partners revised its previous
bid to acquire certain assets of the Cajun Electric Power Cooperative in
Louisiana. The revised acquisition bid was filed with and is subject to the
approval of the federal bankruptcy court.
In October 1997, NRG Generating (U.S.) Inc., a subsidiary of NRG Energy, Inc.,
completed a controlled startup of the combustion turbine at the 150 MW natural-
gas-fired Grays Ferry Cogeneration project in Philadelphia. The project, which
is on schedule and within budget, is expected to begin commercial operation in
early December. The Grays Ferry project will sell electricity to PECO Energy
Company and heating steam to Trigen-Philadelphia Energy Corporation.
In October 1997, NRG purchased Pacific Generation Co. (PGC), an indirect
subsidiary of PacifiCorp, for $151 million, subject to final post-closing
adjustments. PGC is an independent power producer with an interest in 11 power
generating facilities located throughout North America that have a total
capacity of 737 MW. The facilities, located in California, Washington, Maine,
New York, Massachusetts, and Kingston, Ontario, are diverse in terms of fuel
type, including natural gas, hydro, refuse-derived fuel, coal and wind.
As discussed in the 1996 Form 10-K, in 1996 NRG purchased, at a substantial
discount, the senior secured debt of Mid-Continent Power Company, Inc. (MCPC).
In June 1997, MCPC filed a Chapter 11 petition in federal bankruptcy court in
Tulsa, Okla. and concurrently filed a plan of reorganization proposing to
transfer ownership of all of MCPC's assets to NRG in exchange for forgiveness of
a portion of MCPC's debt. In October 1997, this plan was confirmed by the
bankruptcy court. The project is a gas-fired cogeneration plant with a rated
capacity of 110 MW located in Pryor, Okla. which sells steam to several
industrial customers and electricity to two Oklahoma utilities.
CHANGE IN NRG HEDGING POLICY - In July 1997, NRG changed its policy of hedging
foreign currency denominated investments as they were made, to a policy of
hedging foreign currency cash flows over a projected 12-month period. As a
result of this change in hedging policy, NRG terminated its seven existing
foreign currency swap agreements on July 29, 1997. These terminations resulted
in cash payments to NRG without any earnings impact. Consistent with prior
policies, NRG is not hedging future earnings and does not speculate in foreign
currencies.
ENERGY MASTERS INTERNATIONAL - In July 1997, Cenerprise, Inc. (Cenerprise)
acquired Energy Solutions International, Inc. (ESI) of Mendota Heights, Minn.,
and the remaining 20 percent of Energy Masters Corporation (EMC) that Cenerprise
did not already own. Effective Sept. 1, 1997, Cenerprise Inc., changed its name
to Energy Masters International Inc. (EMI) and established its headquarters in
Mendota Heights. EMI, now with 300 employees in more than 25 offices
nationwide, delivers energy supply and energy performance products and services
to commercial and industrial customers, utilities, municipalities, and energy
marketers.
VIKING VOYAGEUR - The Company's subsidiary, Viking Gas Transmission Company,
and TransCanada PipeLines Limited (TransCanada) announced plans earlier in 1997
to become equal partners in the Viking Voyageur Gas Transmission Company, LLC
(Viking Voyageur) which is seeking to build a natural gas transmission pipeline
extending from Emerson, Manitoba, to northeastern Illinois. The line would
serve markets in Minnesota, Wisconsin and northeastern llinois.
In June 1997, Viking Voyageur completed the "open season" for firm gas
transportation service requests on its proposed gas pipeline project. During
the open season, prospective natural gas shippers submitted requests for firm
gas transportation capacity. At the conclusion of the open season, the project
received requests for firm capacity of more than 1.8 billion cubic feet (bcf)
per day. As a result, Viking Voyageur proposed to increase the size of the
pipeline from 36 to 42 inches in diameter and volume from 1.2 to approximately
1.4 bcf per day.
In July 1997, Nicor Inc. became a 20 percent owner in the Viking Voyageur
project, joining partners NSP and TransCanada who each now have a 40 percent
ownership interest. The partners also agreed to extend the pipeline an
additional 60 miles to Joliet, Ill. to access Nicor's storage and transmission
facilities. Nicor is a holding company based in Naperville, Ill. One of its
principal businesses is Northern Illinois Gas, one of the nation's largest gas
distribution companies.
In October 1997, Viking Voyageur submitted an application to the Federal
Energy Regulatory Commission for approval to construct a 42-inch diameter, 773
mile long pipeline. If the necessary regulatory approvals are obtained
promptly, the project could be in service in late 1999.
3. REGULATION AND RATE MATTERS
RATE FILINGS - As a result of the termination of the proposed merger with WEC
as discussed in Note 2, the Company has revised its regulatory plan and is
considering rate filings in several jurisdictions. The Company is planning to
file an application for a retail gas rate increase in its Minnesota jurisdiction
later in 1997. In addition, the Company is planning to file, before 1997 year
end, a rate application with the FERC to update its rates for transmission
service. Northern States Power Company, a Wisconsin corporation, (the Wisconsin
Company) filed retail electric and gas rate applications on Nov. 14, 1997, for
1998 rates as required by the Public Service Commission of Wisconsin (PSCW)
biennial filing requirements. The applications requested an annual increase of
$12.7 million in retail electric rates and a decrease of $1.7 million in retail
gas rates. Any rate changes approved by PSCW would likely not take effect until
the second quarter of 1998.
NETWORK TRANSMISSION SERVICE COSTS (NTS) - In July 1997, the Wisconsin
Company, received authorization from the PSCW to defer its share of network
transmission service (NTS) costs incurred after May 23, 1997. Beginning in the
third quarter 1997, the Wisconsin Company began deferring these costs, including
a retroactive adjustment to May 23, 1997. Approximately $1.4 million of NTS
costs had been deferred at Sept. 30, 1997.
Under NTS, the Company and participating utilities share the total annual
transmission cost for their combined joint-use systems, net of related
transmission revenues, based upon each company's share of the total network
load. The Company offers NTS service to qualifying transmission customers as
mandated in FERC Order No. 888. The Wisconsin Company's share of this expense
is billed through the Interchange Agreement with the Company.
4. COMMITMENTS AND CONTINGENT LIABILITIES
LEGISLATIVE RESOURCE COMMITMENTS - In 1994, the Minnesota Legislature
established several energy resource and other commitments for NSP to fulfill as
part of its approval of NSP's Prairie Island nuclear generating plant's
temporary nuclear fuel storage facility, as discussed in NSP's 1996 Annual
Report on Form 10-K. Steps have been taken to fulfill certain of these
commitments during 1997 as described below.
The 1994 Prairie Island legislation requires NSP to have under contract, or in
operation, 225 MW of wind generation by Dec. 31, 1998 and a total of 425 MW by
Dec. 31, 2002. NSP is currently purchasing generation from a 25 MW wind farm.
The Company has a contract, which has been approved by MPUC, with Zond Minnesota
Development Corporation II (Zond), a wind developer, to purchase 107 MW which is
expected to be operating by June 1998. In March 1997, the Company signed two
power purchase agreements, which have been approved by the MPUC, with Northern
Alternative Energy, Inc. for the development of 22.65 MW of wind-generated
electricity. In September 1997, the Company signed an agreement with Woodstock
Windfarm, LLC for the development of 10.2 MW of wind-generated electricity. In
July 1997, after a competitive bid process to supply 100 MW of wind energy by
mid-1999, the Company selected Zond to supply this wind energy. These
agreements are subject to approval by the MPUC. When these increments are
completed, the Company's purchases of wind generation will be approximately
265 MW.
The 1994 Prairie Island legislation also requires NSP to have under contract a
total of 125 megawatts of biomass generation by the end of 1998. In October
1997, NSP began Phase II of its legislative commitment by selecting District
Energy St. Paul Inc. and Lindroc Energy to each supply 25 MW of biomass power
beginning in the summer of 2002. Phase I began in July 1996, with the selection
of Minnesota Agri-Power Project to supply 75 MW of farm-grown, closed-loop
biomass generation by the end of 2001.
In May 1997, the Minnesota Court of Appeals (the Court) affirmed an Order of
the Minnesota Environmental Quality Board (MEQB) which authorized the Company to
use four additional casks for the storage of spent nuclear fuel at the Prairie
Island nuclear generating plant. The Court also affirmed the MEQB's Order which
denied a certificate of site comparability for an alternative site for the
storage of spent nuclear fuel in Goodhue County. The Prairie Island Indian
Tribe (the Tribe) had filed suit with the Court challenging the MEQB actions in
October 1996. In June 1997, the Tribe petitioned the Minnesota Supreme Court
for review. In July 1997, the Minnesota Supreme Court denied further review and
the Company subsequently withdrew its application to the Nuclear Regulatory
Commission to construct and operate an alternative site for the storage of spent
nuclear fuel.
NETWORK TRANSMISSION COSTS - In October 1997, another regional utility with
integrated transmission facilities who participates in FERC's transmission cost-
sharing network provided information to the Company which, if accurate and
reliable, could increase NSP's anticipated annual NTS expense by approximately
$7 million, effective in 1997. This is an increase over the Company's prior $27
million estimate of 1997 NTS expense. The Company intends to review and
evaluate the information provided, assess its reliability and compliance with
FERC guidelines, and, if necessary, dispute amounts that the Company believes
represent increases due to inappropriately claimed facilities or inaccurate
costs related to claimed facilities. Pending the outcome of this review, none
of the potential NTS cost increase has been recognized as of Sept. 30, 1997.
NUCLEAR INSURANCE - The circumstances set forth in Note 14 to NSP's financial
statements contained in the 1996 Form 10-K appropriately represent, in all
material respects, the current status of commitments and contingent liabilities
regarding public liability for claims resulting from any nuclear incident.
Item 2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATION
Except for the historical statements contained herein, the matters discussed
in the following discussion and analysis are forward looking statements that are
subject to certain risks, uncertainties and assumptions. Such forward-looking
statements are intended to be identified in this document by the words
"anticipate", "estimate", "expect", "objective", "possible", "potential" and
similar expressions. Actual results may vary materially. Factors that could
cause actual results to differ materially include, but are not limited to:
general economic conditions, including their impact on capital expenditures;
business conditions in the energy industry; competitive factors; unusual
weather; changes in federal or state legislation; the higher degree of risk
associated with the Company's nonregulated businesses as compared to the
Company's regulated business; the items set forth below under "Factors Affecting
Results of Operations"; and the other risk factors listed from time to time by
the Company in reports filed with the Securities and Exchange Commission (SEC),
including Exhibit 99.01 to this report on Form 10-Q for the quarter ended Sept.
30, 1997.
RESULTS OF OPERATIONS
NSP's earnings for the periods ending Sept. 30, 1997 and 1996 were as follows:
<TABLE>
3 Mos. Ended 9 Mos. Ended
9/30/97 9/30/96 9/30/97 9/30/96
------- ------- ------- --------
<S> <C> <C> <C> <C>
Earnings per average common share:
Ongoing operations $1.23 $1.18 $2.61 $2.70
Merger costs * 0.00 0.00 (0.25) 0.00
Total $1.23 $1.18 $2.36 $2.70
</TABLE>
*net of applicable income tax
The changes in revenues and expenses of the regulated utility businesses and
nonregulated businesses underlying the variances in financial results are
discussed in more detail later. In addition to the revenue and expense changes,
earnings per share have been affected by an increasing average number of common
and equivalent shares outstanding due to a public stock offering in September
1997 and stock issuances for the Company's dividend reinvestment and stock
ownership plans.
FACTORS AFFECTING RESULTS OF OPERATIONS
In addition to items noted in the 1996 Form 10-K, the historical and future
trends of NSP's operating results have been and are expected to be affected by
the following factors:
TERMINATION OF PROPOSED MERGER - As discussed in Note 2, during May 1997 NSP
and WEC terminated their plans to merge. NSP's year-to-date operating results
for 1997 include a charge to nonoperating expense of approximately $29 million,
or 25 cents per share, to write off its cumulative merger-related costs
incurred. This charge, which is being reported as a non-recurring item outside
of earnings from ongoing operations, includes estimates for certain regulatory
and other costs which NSP will be required to pay but which have not yet been
finalized.
NONREGULATED BUSINESS RESULTS - The following summarizes the earnings
contributions of NSP's nonregulated businesses:
<TABLE>
3 Mos. Ended 9 Mos. Ended
9/30/97 9/30/96 9/30/97 9/30/96
------- ------- ------- -------
<S> <C> <C> <C> <C>
NRG Energy, Inc. $0.04 $0.07 $0.21 $0.16
Eloigne Company 0.01 0.01 0.05 0.03
Energy Masters International, Inc* (0.04) (0.02) (0.08) (0.08)
Other 0.01 0.01 0.00 0.02
Total $0.02 $0.07 $0.18 $0.13
</TABLE>
* formerly Cenerprise, Inc.
Due to the nature of these nonregulated businesses, NSP anticipates that the
earnings from nonregulated operations will experience more variability than
regulated utility businesses. As discussed later, NSP's nonregulated earnings
in the three- and nine-month periods ended Sept. 30, 1997 are experiencing such
variability.
ESTIMATED IMPACT OF WEATHER ON REGULATED EARNINGS - NSP estimates utility
sales levels under normal weather conditions and analyzes the approximate effect
of variations from historical average temperatures on actual sales levels. The
following summarizes the estimated impact of weather on actual utility operating
results (in relation to sales under normal weather conditions):
<TABLE>
INCREASE (DECREASE)
Actual Actual Actual
1997 VS NORMAL 1996 VS NORMAL 1997 VS 1996
-------------- --------------- -------------
<S> <C> <C> <C>
Earnings per Share for:
Quarter Ended September 30 ($0.06) ($0.06) $0.00
Nine Months Ended September 30 ($0.02) $0.08 ($0.10)
</TABLE>
BUSINESS INTERRUPTIONS
Service Area Flooding - In the Grand Forks area (North Dakota and
Minnesota), flood damage and precautionary shut-downs cut off service to many of
NSP's 21,000 electric and 13,000 gas customers in the area on or about April
21, 1997. Most customers have been reconnected however the Company anticipates
that gas service may not be fully restored until late 1997.
NSP estimates that its year-to-date operating results for 1997 have been
reduced by approximately 4 to 5 cents per share due to flooding, mainly in the
Grand Forks area. This estimate includes approximately $3 million of lost
electric and gas margins compared to expected customer usage under normal
weather conditions, and approximately $2 million in additional operating and
maintenance expenses, net of estimated insurance recovery of $1.4 million. The
Company does not expect that additional flood-related operating expenses
incurred and revenues lost after Sept. 30, 1997 will be significant to operating
results. In addition, the Company expects to incur approximately $4 million of
capital expenditures to rebuild the area's delivery systems, of which
approximately $2.6 million had been spent through Sept. 30, 1997. The amount of
any additional insurance recovery or disaster relief available to NSP for
potential reimbursement of expenses incurred and revenues lost as a result of
flooding is not fully determinable at this time. Depreciation and return on
investment related to capital expenditures incurred would be subject to recovery
in future rate proceedings.
Unscheduled Plant Outage - The Company's Monticello nuclear generating plant
was taken out of service effective May 9, 1997 and returned to service at full-
power on Aug. 1, 1997. The unscheduled outage represents an acceleration of a
design change originally planned to be made in January 1998 during the unit's
scheduled refueling outage. During the plant outage, NSP continued to serve its
customers with electricity generated at other NSP facilities and through power
purchases from other sources. The majority of the incremental costs incurred by
the Company from replacing the plant's generation was recovered via fuel
adjustment clause rate mechanisms. The costs of replacement power not recovered
through the fuel clause (mainly in Wisconsin), and incremental maintenance costs
related to the outage resulted in an adverse impact to NSP's 1997 earnings. For
the three- and nine-month periods ended Sept. 30, 1997, NSP estimates that its
operating results have been reduced by approximately 2 cents and 4 cents per
share, respectively. See the Utility Operating Results sections herein for
further discussion of the financial effects of the unscheduled plant outage.
Storms - The Company experienced several storms in April, June and July 1997.
Portions of two NSP high voltage transmission lines connecting NSP's Monticello
and Sherco plants to the Minneapolis-St. Paul metro area were damaged. The
Company avoided transmission-related outages but had to temporarily reduce
production at its plants. The first Company-owned line was repaired and in
service by July 29, 1997 and the second by Sept. 16, 1997. Reduced
transmission capability until repairs were completed, in addition to reduced
generating capability as a result of the unscheduled Monticello outage, limited
NSP's opportunity to sell power to other utilities. The majority of the
incremental costs for replacement generation (purchased power and running NSP
peaking facilities) was recovered through fuel adjustment clause rate
mechanisms. The costs for repairs attributable to all of the storms is
estimated to be approximately $4 million of operating and maintenance expenses,
most of which has been recognized in the third quarter, and approximately $10
million in capital expenditures. Depreciation and return on investment related
to capital expenditures incurred would be subject to recovery in future rate
proceedings.
1997 FINANCIAL OUTLOOK - Management believes that, primarily as a result of
the business interruptions and network transmission service costs described
previously, it is likely that NSP's 1997 earnings from ongoing operations
(excluding merger costs) will be below 1996 results.
THIRD QUARTER 1997 COMPARED WITH THIRD QUARTER 1996
UTILITY OPERATING RESULTS
ELECTRIC REVENUES for the third quarter of 1997 compared with the third
quarter of 1996 increased $59.3 million or 10.1 percent. Retail revenue
increased approximately $40.8 million or 7.5 percent largely due to
increases in retail electric sales and higher average prices. The increase in
retail electric sales reflects sales growth compared to 1996. Average retail
prices increased as a result of rate adjustments for higher fuel and purchased
power costs, reflecting the impacts of the business interruptions discussed
previously, and increased recovery of deferred conservation and energy
management costs. Revenue from sales to other utilities increased $7.8 million
in 1997 primarily due to an increase in average prices reflecting more favorable
market conditions. Other electric revenues increased by $10.6 million largely
due to the recognition of a transmission settlement and increases in the
transmission of electricity for others.
GAS REVENUES for the third quarter of 1997 increased $4.9 million or 10.4
percent compared with the third quarter of 1996 primarily due to rate
adjustments related to estimated purchased gas cost recovery and higher
interruptible sales volumes, partially offset by a decline in firm sales volume
and lower transportation revenues. The firm sales volume decrease is primarily
due to lower sales growth and less favorable weather in 1997 in comparison to
1996.
FUEL FOR ELECTRIC GENERATION and PURCHASED AND INTERCHANGE POWER costs
combined increased $20.6 million or 14.3 percent for the third quarter of 1997
compared with the third quarter of 1996. Fuel expense increased $8.8 million
primarily due to higher average fossil fuel prices from the use of higher cost
plants and increased plant output due to higher sales. Purchased and
interchange power costs increased $11.8 million primarily due to higher market
prices for purchased power and increased purchases. The operation of higher
cost plants and an increased level of power purchases were necessary due to
plant outages and lower generation from a baseload plant as a result of
transmission line limitations, as discussed previously.
COST OF GAS PURCHASED AND TRANSPORTED for the third quarter of 1997 compared
with the third quarter of 1996 increased $5.9 million or 26.8 percent due to
increased gas costs partially offset by reduced off-system and agency gas sales.
The higher cost of gas reflects adjustments to match rate recovery under the
purchased gas adjustment mechanism and higher gas costs due to market changes in
natural gas prices charged by suppliers.
OTHER OPERATION and MAINTENANCE expenses increased and ADMINISTRATIVE AND
GENERAL expenses decreased combining for a net increase of $17.1 million or 11.2
percent compared with the third quarter of 1996. The costs associated with
providing network transmission service (NTS) to qualifying transmission
customers, as a result of FERC Order No. 888 (see Notes 3 and 4 to the Financial
Statements), added $6.2 million to other operation expenses. Costs incurred for
plant outages, storm and flood damage, (as discussed previously), electric
technology improvements, customer service and provisions for uncollectibles also
increased operating and maintenance expenses. Partially offsetting these
increases were lower costs for employee benefits and property insurance.
CONSERVATION AND ENERGY MANAGEMENT costs increased $2.1 million or 12.3
percent in the third quarter of 1997 compared to the same period in the prior
year due to higher amortization levels and concurrent rate recovery of deferred
electric and gas conservation and energy management program costs. These higher
amortization levels are consistent with retail electric and gas rate recovery
levels in the Company's Minnesota jurisdiction which increased in August 1996
for electric and September 1996 for gas.
DEPRECIATION AND AMORTIZATION expense increased $4.6 million or 5.9 percent
compared with the third quarter of 1996. The increase is mainly due to
increased plant in service between the two periods.
PROPERTY AND GENERAL TAXES for the third quarter of 1997 compared with the
third quarter of 1996 decreased $4.4 million or 7.0 percent due to lower 1997
property taxes in Minnesota as a result of legislation enacted in May 1997 and
higher property tax accruals in 1996. The 1996 accrual levels were ultimately
adjusted downward at year-end 1996 based on final property tax notices
received.
UTILITY INCOME TAXES for the third quarter of 1997 compared with the third
quarter of 1996 were $5.2 million higher primarily due to higher operating
income in the third quarter of 1997.
OTHER UTILITY INCOME (DEDUCTIONS) - NET decreased $2.8 million mainly due to
lower interest income compared to 1996, which included interest from settlement
of tax disputes .
UTILITY INTEREST AND AMORTIZATION decreased $0.7 million or 2.4 percent
primarily due to interest adjustments related to settlement of a state tax
dispute.
DISTRIBUTIONS ON REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST increased
$3.9 million due to the issuance of new securities in 1997 as discussed in Note
2 to the Financial Statements.
PREFERRED STOCK DIVIDENDS AND REDEMPTION PREMIUMS decreased $0.7 million in
the third quarter of 1997 compared with 1996 primarily due to reductions in
dividends resulting from the redemption of two issues of preferred stock in
February 1997.
NONREGULATED BUSINESS RESULTS
NSP's nonregulated operations include many diversified businesses, such as
independent power production, energy sales and services, industrial heating and
cooling, and energy-related refuse-derived fuel production. NSP also has
investments in affordable housing projects and several income-producing
properties. The following summarizes NSP's diversified business results in the
aggregate, including consolidated subsidiaries and unconsolidated affiliates.
<TABLE>
3 MOS. ENDED
(Thousands of dollars, except EPS) 9/30/97 9/30/96
------- -------
<S> <C> <C>
Operating revenues $48,918 $56,051
Equity in earnings of unconsolidated affiliates 2,807 6,234
Operating and development expenses (53,618) (58,803)
Interest and other income 4,116 2,110
Income from nonregulated businesses before
interest and taxes $2,223 $5,592
Interest expense (9,376) (4,875)
Income tax benefit 8,580 3,869
Net income $1,427 $4,586
Contribution of nonregulated businesses to NSP
earnings per share $0.02 $0.07
</TABLE>
NRG - NRG's third quarter earnings decreased by 3 cents per share in 1997 from
the same period one year ago primarily due to increased interest costs from a
June 1997 debt financing and lower project earnings which were partially offset
by higher tax credits for new projects. The operating results of NRG projects
in 1997 reflect higher earnings from new projects, including interests in Loy
Yang in Australia (acquired in May 1997) and COBEE in Bolivia (acquired in
December 1996), which were offset by lower earnings at MIBRAG in Germany. NRG's
landfill gas subsidiary, NEO, has entered into projects since 1996 that are
generating higher levels of energy tax credits.
EMI - EMI's third quarter losses increased by 2 cents per share in 1997
compared 1996, primarily due to equity in losses incurred by its 50 percent-
owned joint venture, Enerval, and increased expenses related to combining
operations with Energy Solutions International, Inc. (ESI) and Energy Masters
Corporation (EMC), both purchased in July 1997.
FIRST NINE MONTHS OF 1997 COMPARED WITH FIRST NINE MONTHS OF 1996
UTILITY OPERATING RESULTS
ELECTRIC REVENUES for the first nine months of 1997 compared with the first
nine months of 1996 increased $76.7 million or 4.8 percent. Retail revenues
increased approximately $50.6 million or 3.4 percent due to an increase in
average retail prices and a 1.6 percent increase in retail electric sales. The
increase in retail electric sales reflects sales growth compared to 1996,
partially offset by less favorable weather in 1997. Average retail prices
increased as a result of rate adjustments for higher fuel and purchased power
costs, reflecting the impacts of the business interruptions discussed
previously, and increased recovery of deferred conservation and energy
management costs. Revenue from sales to other utilities increased $12.5 million
primarily due to price increases resulting from more favorable market
conditions. Other electric revenues increased $13.6 million largely due to the
recognition of a transmission settlement in the third quarter of 1997 and
increases in the transmission of electricity for others.
GAS REVENUES for the first nine months of 1997 compared with the first nine
months of 1996 increased $13.3 million or 3.9 percent. Gas revenues increased
due to an increase in average gas prices despite a 2.3 percent decrease in gas
sales volume and decreased transportation and off-system sales,. The sales
volume decrease is due primarily to less favorable weather in 1997 in comparison
to 1996, partially offset by growth in gas sales. The price increase is mainly
due to rate adjustments for increased purchased gas costs in the first quarter
of 1997, resulting from market changes in natural gas prices charged by
suppliers, and an annual adjustment to rate recovery of estimated purchased gas
costs in Minnesota.
FUEL FOR ELECTRIC GENERATION and PURCHASED AND INTERCHANGE POWER costs
combined increased $31.4 million or 7.6 percent for the first nine months of
1997 compared with the first nine months of 1996. Fuel expense increased $12.0
million primarily due to higher average fossil fuel prices, mainly reflecting
the increased use of higher cost plants due to plant outages and lower
generation from a baseload plant as a result of transmission line limitations,
as discussed previously, and more plant output due to higher sales. Purchased
and interchange power costs increased $19.4 million primarily due to increased
costs due to market conditions and higher purchases as a result of higher sales
and lower plant availability during the second and third quarters, as discussed
previously.
COST OF GAS PURCHASED AND TRANSPORTED for the first nine months of 1997
compared with the first nine months of 1996 increased $15.3 million or 7.4
percent due to higher cost of gas, partly offset by lower gas sendout. The
higher cost of purchased gas, occurring mainly in the first quarter of 1997,
reflects changes in market conditions and gas cost adjustments to match expense
with rate recovery. The lower sendout is primarily a result of decreased gas
sales and lower off-system sales.
OTHER OPERATION and MAINTENANCE expenses increased and ADMINISTRATIVE AND
GENERAL expenses decreased, combining for a net increase of $27.0 million or
5.6 percent compared with the first nine months of 1996. The cost associated
with offering NTS to qualifying transmission customers, as a result of FERC
Order No. 888, added approximately $18 million to other operation expenses.
Expenditures for electric technology improvements, customer service initiatives,
provisions for uncollectibles, storm damage, flooding and outage costs also
increased operating and maintenance expenses. Partially offsetting these
increases were lower costs for employee benefits, insurance and line maintenance
costs unrelated to the storm damage.
CONSERVATION AND ENERGY MANAGEMENT expenses increased $5.4 million in the
first nine months of 1997 compared to the same period in the prior year due
mainly to higher amortization levels and concurrent rate recovery of deferred
electric and gas conservation and energy management program costs. These higher
amortization levels are consistent with retail electric and gas rate recovery
levels in the Company's Minnesota jurisdiction which increased in August 1996
for electric and September 1996 for gas.
DEPRECIATION AND AMORTIZATION increased $14.3 million or 6.3 percent compared
with the first nine months of 1996. The increase is mainly due to increased
plant in service between the two periods.
PROPERTY AND GENERAL TAXES for the first nine months of 1997 compared with the
first nine months of 1996 decreased $6.7 million or 3.7 percent due to lower
1997 property taxes in Minnesota a result of legislation enacted in May 1997 and
higher property tax accruals in 1996. The 1996 accrual levels were ultimately
adjusted downward at year-end 1996 based on final property tax notices received.
This decrease is partly offset by higher payroll and franchise taxes.
UTILITY INCOME TAXES for the first nine months of 1997 compared with the first
nine months of 1996 decreased $3.8 million primarily due to lower pre-tax
income.
OTHER UTILITY INCOME (DEDUCTIONS) - NET decreased $6.1 million for the first
nine months of 1997 compared with the first nine months of 1996 primarily due to
lower interest income associated with the settlement of tax disputes and with
customer financing, and non-recurring 1996 refund adjustments. Other income
(expense) also includes the second quarter write-off of $29 million in merger
costs (as discussed previously) and the related tax effects.
UTILITY INTEREST AND AMORTIZATION for the first nine months of 1997 compared
with the first nine months of 1996 decreased by $0.5 million primarily due to
interest adjustments related to a settlement of a state tax dispute, and
offsetting changes in other interest.
DISTRIBUTIONS ON REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST increased
$10.5 million due to the issuance of new securities in 1997 as discussed in Note
2 to the Financial Statements.
PREFERRED STOCK DIVIDENDS AND REDEMPTION PREMIUMS decreased $0.5 million for
the first nine months of 1997 compared with the first nine months of 1996 due to
reductions in dividends as a result of the redemption of two issues of
preferred stock in February 1997, partially offset by a $1.1 million redemption
premium.
NONREGULATED BUSINESS RESULTS
The following summarizes NSP's diversified business results in the aggregate,
including consolidated subsidiaries and unconsolidated affiliates.
<TABLE>
9 MOS. ENDED
(Thousands of dollars, except EPS) 9/30/97 9/30/96
------- -------
<S> <C> <C>
Operating revenues $159,800 $241,241
Equity in earnings of unconsolidated
affiliates 14,433 18,215
Operating and development expenses (171,521) (255,220)
Interest and other income 11,247 6,785
Income from nonregulated businesses
before interest and taxes $13,959 $11,021
Interest expense (22,139) (13,643)
Income tax benefit 20,671 11,878
Net income $12,491 $9,256
Contribution of nonregulated businesses
to NSP earnings per share $0.18 $0.13
</TABLE>
NRG - NRG's earnings for the nine months ended Sept. 30 increased by 5 cents
per share in 1997 compared with the same period in 1996 primarily due to higher
tax credits from new NEO projects (as discussed previously) and lower business
development costs, partially offset by higher interest costs on new debt
financing issued in January 1996 and June 1997, and lower project income. The
operating results of NRG projects in 1997 reflect lower earnings in MIBRAG,
which were partially offset by higher earnings from new projects, including
interests in Loy Yang and COBEE. Regarding business development costs, NRG
experienced an increased level of such costs in early 1996 as it pursued several
significant international and domestic projects. Until there is substantial
assurance that a project under development will come to financial closure, such
costs are expensed.
EMI - EMI's earnings for the nine months ended Sept. 30, 1997 compared with
the same period in 1996 were about the same. Non-regulated operating revenues
and expenses decreased, while operating margins increased in 1997 compared to
the same period in 1996 primarily due to EMI's curtailment of gas trading
activity in the second quarter of 1996 which had negatively impacted operating
margins during the first half of 1996. The increased margins were offset by
losses incurred by Enerval due to the price volatility in the gas market, the
write-off of a receivable from a customer who entered bankruptcy, and increased
expenses related to the purchase of ESI and EMC, as discussed previously.
Other - Eloigne's earnings for the nine months ended Sept. 30, 1997 were up 2
cents per share compared with the same period in 1996 mainly due to higher tax
credits generated by new projects. Other nonregulated earnings for the nine
month period are down 2 cents per share in 1997 mainly due to start-up costs
incurred by NSP's new communications subsidiary Seren Innovations, Inc.
LIQUIDITY AND CAPITAL RESOURCES
The Company had $65 million in commercial paper debt outstanding as of Sept.
30, 1997. Commercial banks currently provide credit lines of approximately $300
million to the Company. These credit lines make short-term financing available
in the form of bank loans, letters of credit and support for commercial paper
sales. The Company has regulatory approval for up to $528 million in short-term
borrowing levels.
In addition to Company lines, commercial banks currently provide credit lines
of approximately $248 million to wholly owned subsidiaries of the Company,
including the NRG credit facility discussed later. At Sept. 30, 1997,
approximately $38 million in borrowings were outstanding under these credit
lines. In addition, approximately $34 million in letters of credit were
outstanding, which reduced the credit lines available to subsidiaries at Sept.
30, 1997, and therefore left approximately $176 million of unused lines
available at that date.
In January 1997, stock options for the purchase of 286,700 shares were awarded
under the Company's Executive Long-Term Incentive Award Stock Plan (the Plan).
These options are not exercisable for approximately twelve months after the
award date. As of Sept. 30, 1997, a total of 1,252,054 stock options were
outstanding, which were considered as potential common stock equivalents for
earnings per share purposes. During the first nine months of 1997, the Company
has issued 52,328 new shares of common stock under the Plan pursuant to the
exercise of options and awards granted in prior years. Under NSP's Dividend
Reinvestment and Stock Purchase Plan, the Company has issued 156,017 shares
of common stock during the first nine months of 1997. During 1997 the Company
has issued an additional 69,488 shares of common stock to the Employee
Stock Ownership Plan for dividends on Company shares held.
As discussed in Note 2 to the Financial Statements, in January 1997 NSP issued
$200 million in 7.875 percent trust-originated preferred securities that mature
in 2037. Approximately $41 million of the proceeds were used in February 1997
to redeem the Company's $6.80 and $7.00 series of preferred stock. The balance
of the proceeds were used to repay a portion of outstanding short-term
borrowings.
In May 1997, NRG finalized terms with a syndication of banks regarding a
three-year $175 million revolving credit facility. The facility will be used
for general corporate purposes, including letters of credit and interim funding
of NRG project investments. Under the terms of the credit facility, NRG must
maintain compliance with certain financial requirements, including maintenance
of a minimum level of tangible net worth and a minimum ratio of tangible net
worth to capitalization. NRG borrowed under this facility to finance the
acquisition of PGC, as discussed previously.
In June 1997, NRG issued $250 million of 7.5 percent Senior Notes due 2007 in
a private placement under securities laws. NRG used the net proceeds to repay
outstanding debt incurred primarily to fund its equity investment in the Loy
Yang project, and for other general corporate purposes. In August of 1997, NRG
filed with the Securities and Exchange Commission (SEC) a tender offer to
exchange the existing notes for publicly-traded notes with the same interest
rate and maturity. NRG is hopeful that the SEC will allow the filing to become
effective by early December 1997 so that the tender offer can be completed
shortly thereafter.
In July 1997, Moody's Investors Service (Moody's) upgraded the credit ratings
of the Company and its Wisconsin subsidiary. First mortgage and secured
pollution control bonds are now rated `Aa3', unsecured pollution control bonds
and counterparty ratings are now rated `A1', and the Company's preferred stock
is now rated `a1'. In October 1997, Standard & Poor's (S&P) upgraded the credit
ratings of the Company. These ratings reflect the views of Moody's and S&P,
and an explanation of the significance of these ratings may be obtained from
those agencies. A security rating is not a recommendation to buy, sell or hold
securities and is subject to revision or withdrawal at any time by the rating
agency.
NRG's wholly owned subsidiary, NRG Energy Center is negotiating for financing
of approximately $30 million to provide financing for the Minneapolis Energy
Center.
In September 1997, the Company sold 4.9 million shares of its common stock in
a public offering at a price to the public of $49.5625 per share, with net
proceeds to the Company of $237 million. The Company used the proceeds for
general corporate purposes, including the retirement of $100 million of first
mortgage bonds which matured Oct. 1, 1997, expenditures for the Company's
construction program and the repayment of short-term borrowings.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
In the normal course of business, various lawsuits and claims have arisen
against NSP. Management, after consultation with legal counsel, has recorded an
estimate of the probable cost of settlement or other disposition for such
matters.
On July 23, 1996, the U.S. Court of Appeals for the District of Columbia
Circuit (the Court), in a lawsuit filed by the Company along with other major
utilities, unanimously ruled that the Nuclear Waste Policy Act (Act) creates an
unconditional obligation for the United States Department of Energy (DOE) to
begin acceptance of spent nuclear fuel by Jan. 31, 1998. The DOE did not seek
U.S. Supreme Court review. On Jan. 31, 1997, the Company along with 30 other
electric utilities and 45 state agencies, filed a related lawsuit with the Court
against the DOE requesting authority to withhold payments to the DOE under the
Act. On Sept. 25, 1997, in oral arguments to the Court, the Company and the
other parties asked for an order (a) compelling the DOE to begin accepting spent
nuclear fuel, as required by the Act and the standard Contract between the
utilities and the DOE, and to develop an enforceable plan for accepting spent
nuclear fuel by a date certain; and (b) allowing utilities to escrow payments
into the Nuclear Waste Fund until the DOE begins accepting spent nuclear fuel.
The petition if granted, will be significant to NSP and the industry because the
DOE will be mandated to take the above-stated actions concerning spent nuclear
fuel. A ruling from the Court is expected before the end of 1997. In June
1997, the State of Minnesota passed legislation that would allow the State to
begin placing in escrow the payments to the DOE under the Act. This escrow
could be implemented if allowed by the Court in the pending case. Related to
this matter, in June 1997 the DOE notified utilities that it likely will not
meet its Jan. 31, 1998 deadline to accept spent nuclear fuel and that the delay
in accepting spent nuclear fuel is "unavoidable" as defined in the standard
Contract. The Company and other major utilities are challenging this
determination by the DOE Contracting officer.
For discussion of legal proceedings concerning temporary storage of spent
nuclear fuel at the Prairie Island Nuclear Generating Plant, see Note 4 to the
Financial Statements, incorporated herein by reference.
On June 10, 1997, the Minnesota Office of the Attorney General (OAG)
petitioned the MPUC to investigate the Company's meter reading and billing
practices and to authorize the OAG to pursue civil penalties. On Sept. 18,
1997, the MPUC in Docket No. E, G-002/CI-97-863 voted to require the Company to
submit a report about its practices and compliance with MPUC's meter reading and
billing rules within 30 days. The Company expects a ruling by MPUC on the OAG
petition in the first quarter of 1998. While the Company continues to seek to
resolve this matter in a manner acceptable to the parties and MPUC, the Company
cannot at the present time predict the outcome of this matter.
FORM 8-K
(A) EXHIBITS
The following Exhibits are filed with this report:
27.01 Financial Data Schedule for the nine months ended Sept. 30, 1997.
99.01 Statement pursuant to Private Securities Litigation Reform Act of
1995.
(B) REPORTS ON FORM 8-K
The following reports on Form 8-K were filed either during the three months
ended Sept. 30, 1997, or between Sept. 30, 1997 and the date of this report:
July 28, 1997 (Filed July 30, 1997) Item 5. Other Events. Viking Voyageur
Gas Transmission Company, 50 percent owned by Viking Gas Transmission
Company, a wholly owned subsidiary of the Company, and NICOR Inc. announced
agreement on a letter of intent to make NICOR a 20 percent owner of Viking
Voyageur and to change the terminus of the Viking Voyageur natural gas
transmission project from Volo, Illinois to Joliet, Illinois.
Sept. 19, 1997 (Filed Sept. 19, 1997) Item 5. Other Events. On Sept. 17,
1997, the Company sold 4.5 million shares of its common stock in a public
offering at a price of $49.5625 per share.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
NORTHERN STATES POWER COMPANY
(Registrant)
/S/
Roger D. Sandeen
Vice President and Controller
/S/
Edward J. McIntyre
Vice President and Chief Financial Officer
Date: NOVEMBER 14, 1997
EXHIBIT INDEX
METHOD OF FILING EXHIBIT NO. DESCRIPTION
DT 27.01 Financial Data Schedule
DT 99.01 Statement pursuant to Private
Securities Litigation Reform
Act 1995
DT = Filed electronically with this direct transmission.
<TABLE> <S> <C>
<ARTICLE> UT
EXHIBIT 27.01
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Statements of Income, Consolidated Balance Sheets and Consolidated
Statements of Cash Flows and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> SEP-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,342,841
<OTHER-PROPERTY-AND-INVEST> 1,308,976
<TOTAL-CURRENT-ASSETS> 785,468
<TOTAL-DEFERRED-CHARGES> 351,345
<OTHER-ASSETS> 269,974
<TOTAL-ASSETS> 7,058,604
<COMMON> 185,465
<CAPITAL-SURPLUS-PAID-IN> 876,215
<RETAINED-EARNINGS> 1,355,641
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,372,621<F1>
200,000
200,340
<LONG-TERM-DEBT-NET> 1,856,479
<SHORT-TERM-NOTES> 41,680
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 65,000
<LONG-TERM-DEBT-CURRENT-PORT> 258,535
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,019,249<F1>
<TOT-CAPITALIZATION-AND-LIAB> 7,058,604
<GROSS-OPERATING-REVENUE> 2,034,263
<INCOME-TAX-EXPENSE> 83,267<F2>
<OTHER-OPERATING-EXPENSES> 1,645,939
<TOTAL-OPERATING-EXPENSES> 1,761,681
<OPERATING-INCOME-LOSS> 272,582
<OTHER-INCOME-NET> (27,719)<F3>
<INCOME-BEFORE-INTEREST-EXPEN> 277,338
<TOTAL-INTEREST-EXPENSE> 105,400
<NET-INCOME> 171,938
8,699
<EARNINGS-AVAILABLE-FOR-COMM> 163,239
<COMMON-STOCK-DIVIDENDS> 148,397
<TOTAL-INTEREST-ON-BONDS> 96,802
<CASH-FLOW-OPERATIONS> 508,864
<EPS-PRIMARY> 2.36
<EPS-DILUTED> 0
<FN>
<F1>$(44,700) thousand of Common Stockholders' Equity is classified as Other
Items-Capitalization and Liabilities. This represents the net of leveraged
common stock held by the Employee Stock Ownership Plan and the currency
translation adjustments.
<F2>$(32,475) thousand of non-operating income tax benefit is classified as
Income Tax Expense. The financial statement presentation includes this as a
component of Other Income (Expense).
<F3>Includes Income From Nonregulated Businesses Before Interest and Taxes,
Allowance for Funds Used During Construction-Equity, Merger Costs, Other Utility
Income (Deductions)-Net and Distributions on redeemable preferred securities of
subsidiary trust.
</FN>
</TABLE>
EXHIBIT 99.01
Northern States Power Company Cautionary Factors
The Private Securities Litigation Reform Act of 1995 (the Act) provides a
new "safe harbor" for forward-looking statements to encourage such disclosures
without the threat of litigation providing those statements are identified as
forward-looking and are accompanied by meaningful, cautionary statements
identifying important factors that could cause the actual results to differ
materially from those projected in the statement. Forward-looking statements
have been and will be made in written documents and oral presentations of
Northern States Power Company (the Company). Such statements are based on
management's beliefs as well as assumptions made by and information currently
available to management. When used in the Company's documents or oral
presentations, the words "anticipate", "estimate", "expect", "objective",
"possible", "potential" and similar expressions are intended to identify forward
- -looking statements. In addition to any assumptions and other factors referred
to specifically in connection with such forward-looking statements, factors that
could cause the Company's actual results to differ materially from those
contemplated in any forward-looking statements include, among others, the
following:
- - Economic conditions including inflation rates and monetary fluctuations;
- - Trade, monetary, fiscal, taxation, and environmental policies of governments,
agencies and similar organizations in geographic areas where the Company has
a financial interest;
- - Customer business conditions including demand for their products or services
and supply of labor and materials used in creating their products and
services;
- - Financial or regulatory accounting principles or policies imposed by the
Financial Accounting Standards Board, the Securities and Exchange Commission,
the Federal Energy Regulatory Commission and similar entities with regulatory
oversight;
- - Availability or cost of capital such as changes in: interest rates; market
perceptions of the utility industry, the Company or any of its subsidiaries;
or security ratings;
- - Factors affecting utility and nonutility operations such as unusual weather
conditions; catastrophic weather-related damage; unscheduled generation
outages, maintenance or repairs; unanticipated changes to fossil fuel,
nuclear fuel or gas supply costs or availability due to higher demand,
shortages, transportation problems or other developments; nuclear or
environmental incidents; or electric transmission or gas pipeline system
constraints;
- - Employee workforce factors including loss or retirement of key executives,
collective bargaining agreements with union employees, or work stoppages;
- - Increased competition in the utility industry, including: industry
restructuring initiatives; transmission system operation and/or
administration initiatives; recovery of investments made under traditional
regulation; nature of competitors entering the industry; retail wheeling; a
new pricing structure; and former customers entering the generation market;
- - Rate-setting policies or procedures of regulatory entities, including
environmental externalities, which are values established by regulators
assigning environmental costs to each method of electricity generation when
evaluating generation resource options;
- - Nuclear regulatory policies and procedures including operating regulations
and used nuclear fuel storage;
- - Social attitudes regarding the utility and power industries;
- - Cost and other effects of legal and administrative proceedings, settlements,
investigations and claims;
- - Technological developments that result in competitive disadvantages and
create the potential for impairment of existing assets;
- - Factors associated with nonregulated investments including conditions of
final legal closing, foreign government actions, foreign economic and
currency risks, political instability in foreign countries, partnership
actions, competition, operating risks, dependence on certain suppliers and
customers, domestic and foreign environmental and energy regulations;
- - Most of the current project investments made by the Company's subsidiary, NRG
Energy, Inc. (NRG) consist of minority interests, and a substantial portion
of future investments may take the form of minority interests, which limits
NRG's ability to control the development or operation of the project;
- - Other business or investment considerations that may be disclosed from time
to time in the Company's Securities and Exchange Commission filings or in
other publicly disseminated written documents.
EXHIBIT 99.01
The Company undertakes no obligation to publicly update or revise any forward-
looking statements, whether as a result of new information, future events or
otherwise. The foregoing review of factors pursuant to the Act should not be
construed as exhaustive or as any admission regarding the adequacy of
disclosures made by the Company prior to the effective date of the Act.
