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, 1996
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 October 31, 1996
Common Stock, $2.50 par value 69,063,712 shares
PART 1. FINANCIAL INFORMATION
Item 1. Financial Statements
Northern States Power Company (Minnesota) and Subsidiaries
Consolidated Statements of Income (Unaudited)
Three Months Ended Nine Months Ended
September 30 September 30
1996 1995 1996 1995
(Thousands of dollars)
Utility operating revenues
Electric........................................... $586,001 $619,238 $1,605,708 $1,636,169
Gas................................................ 47,257 45,738 338,518 279,647
Total ........................................... 633,258 664,976 1,944,226 1,915,816
Utility operating expenses
Fuel for electric generation....................... 74,110 86,983 220,331 250,920
Purchased and interchange power.................... 69,492 74,364 190,569 194,575
Cost of gas purchased and transported.............. 22,057 26,302 207,088 165,914
Other operation.................................... 79,413 78,115 246,089 236,590
Maintenance........................................ 33,411 38,155 120,804 119,180
Administrative and general......................... 41,220 45,277 116,579 128,769
Conservation and energy management................. 17,224 16,395 47,203 36,047
Depreciation and amortization...................... 76,899 72,776 227,644 216,676
Taxes: Property and general....................... 62,975 63,816 182,889 188,169
Current income tax expense................. 52,626 52,720 139,946 120,593
Deferred income tax expense................ 566 710 (13,855) (2,364)
Investment tax credit adjustments - net.... (2,191) (2,229) (6,596) (6,705)
Total.......................................... 527,802 553,384 1,678,691 1,648,364
Utility operating income............................ 105,456 111,592 265,535 267,452
Other income (expense)
Equity in earnings of unconsolidated affiliates:
Earnings from operations......................... 6,257 8,174 18,388 23,098
Gain from contract termination................... 0 0 0 29,850
Allowance for funds used during construction -
equity........................................... 1,457 1,460 5,579 4,658
Other income (deductions) - net.................... (292) (2,223) (8,687) (6,323)
Income taxes on non-regulated operations and
non-operating items.............................. 4,018 1,600 11,256 (8,107)
Total.......................................... 11,440 9,011 26,536 43,176
Income before interest charges....................... 116,896 120,603 292,071 310,628
Interest charges
Interest on utility long-term debt................. 25,440 26,875 75,816 77,589
Other utility interest and amortization............ 5,695 4,400 16,290 15,824
Non-regulated interest and amortization............ 4,956 2,562 13,889 7,234
Allowance for funds used during construction - debt (3,434) (2,037) (8,755) (6,823)
Total.......................................... 32,657 31,800 97,240 93,824
Net income .......................................... 84,239 88,803 194,831 216,804
Preferred stock dividends............................ 3,061 3,061 9,184 9,388
Earnings available for common stock ................. $81,178 $85,742 $185,647 $207,416
Average number of common and equivalent
shares outstanding (000's)......................... 68,948 67,496 68,642 67,233
Earnings per average common share.................... $1.18 $1.27 $2.70 $3.09
Common dividends declared per share.................. $0.690 $0.675 $2.055 $2.010
Consolidated Statements of Retained Earnings (Unaudited)
Balance at beginning of period....................... $1,277,203 $1,215,505 $1,266,026 $1,183,191
Net income for period................................ 84,239 88,803 194,831 216,804
Dividends declared:
Cumulative preferred stock......................... (3,061) (3,061) (9,184) (9,388)
Common stock....................................... (47,118) (45,462) (140,410) (134,822)
Balance at end of period............................. $1,311,263 $1,255,785 $1,311,263 $1,255,785
The Notes to Financial Statements are an integral part of the Statements of Income and Retained Earnings.
Northern States Power Company (Minnesota) and Subsidiaries
Consolidated Balance Sheets (Unaudited)
September 30, December 31,
1996 1995
(Thousands of dollars)
ASSETS
Utility Plant
Electric........................................................ $6,739,374 $6,553,383
Gas............................................................. 735,341 710,035
Common.......................................................... 321,319 299,585
Total....................................................... 7,796,034 7,563,003
Accumulated provision for depreciation........................ (3,556,491) (3,343,760)
Nuclear fuel.................................................... 889,033 843,919
Accumulated provision for amortization........................ (784,085) (752,821)
Net utility plant........................................... 4,344,491 4,310,341
Current Assets
Cash and cash equivalents....................................... 79,398 28,794
Short-term investments.......................................... 209 149
Customer accounts receivable - net.............................. 257,527 281,584
Unbilled utility revenues....................................... 80,825 112,650
Other receivables............................................... 68,730 78,993
Fossil fuel inventories - at average cost....................... 56,801 43,941
Materials and supplies inventories - at average cost............ 108,553 100,607
Prepayments and other........................................... 64,844 57,745
Total current assets.......................................... 716,887 704,463
Other Assets
Regulatory assets............................................... 371,628 374,212
Equity investments in non-regulated projects and other
investments................................................... 335,911 289,495
External decommissioning fund investments....................... 239,797 203,625
Non-regulated property - net.................................... 180,599 177,598
Long-term receivables........................................... 111,993 83,065
Intangible and other assets..................................... 93,630 85,786
Total other assets........................................... 1,333,558 1,213,781
TOTAL ASSETS................................................ $6,394,936 $6,228,585
LIABILITIES AND EQUITY
Capitalization
Common stock equity:
Common stock and premium - authorized 160,000,000
shares of $2.50 par value, issued shares:
1996, 69,063,712; 1995, 68,175,934.......................... $811,498 $769,534
Retained earnings............................................. 1,311,263 1,266,026
Leveraged common stock held by ESOP........................... (20,719) (10,657)
Currency translation adjustments - net........................ 3,406 2,488
Total common stock equity................................... 2,105,448 2,027,391
Cumulative preferred stock and premium - authorized
7,000,000 shares of $100 par value; outstanding
shares: 1996 and 1995, 2,400,000
without mandatory redemption.................................. 240,469 240,469
Long-term debt.................................................. 1,673,145 1,542,286
Total capitalization........................................ 4,019,062 3,810,146
Current Liabilities
Long-term debt due within one year.............................. 18,240 25,760
Other long-term debt potentially due within one year............ 141,600 141,600
Short-term debt - primarily commercial paper.................... 222,601 216,194
Accounts payable................................................ 187,682 246,051
Taxes accrued................................................... 219,331 202,777
Interest accrued................................................ 33,987 31,806
Dividends payable on common and preferred stocks................ 50,402 48,875
Accrued payroll, vacation and other............................. 72,186 78,310
Total current liabilities................................... 946,029 991,373
Other Liabilities
Deferred income taxes........................................... 834,596 841,153
Deferred investment tax credits................................. 152,753 161,513
Regulatory liabilities.......................................... 269,983 242,787
Pension and other benefit obligations........................... 106,957 115,797
Other long-term obligations and deferred income................. 65,556 65,816
Total other liabilities..................................... 1,429,845 1,427,066
Commitments and Contingent Liabilities (See Note 5)
TOTAL LIABILITIES AND EQUITY.............................. $6,394,936 $6,228,585
The Notes to Financial Statements are an integral part of the Balance Sheets.
Northern States Power Company (Minnesota) and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Nine Months Ended
September 30,
1996 1995
(Thousands of dollars)
Cash Flows from Operating Activities:
Net Income.................................................................. $194,831 $216,804
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization............................................. 249,429 240,971
Nuclear fuel amortization................................................. 32,843 36,929
Deferred income taxes..................................................... (16,935) (140)
Deferred investment tax credits recognized................................ (6,827) (6,937)
Allowance for funds used during construction - equity..................... (5,579) (4,658)
Undistributed equity in earnings of unconsolidated affiliate operations... (16,312) (17,421)
Undistributed equity in gain from non-regulated contract termination
settlement.............................................................. (17,565)
Cash provided by changes in certain working capital items................. 828 39,559
Cash provided by (used for) changes in other assets and liabilities....... 4,651 7,983
Net cash provided by operating activities.................................... 436,929 495,525
Cash Flows from Investing Activities:
Capital expenditures ....................................................... (311,028) (283,342)
Increase (decrease) in construction payables................................ 6,646 (15,001)
Allowance for funds used during construction - equity....................... 5,579 4,658
Sale (purchase) of short-term investments - net............................. (60) 738
Investment in external decommissioning fund................................. (28,964) (23,541)
Equity investments, loans and deposits for non-regulated projects and other. (181,125) (44,476)
Collection of loans made to non-regulated projects.......................... 111,800
Net cash used for investing activities....................................... (397,152) (360,964)
Cash Flows from Financing Activities:
Change in short-term debt - net issuances (repayments)...................... 6,407 (98,991)
Proceeds from issuance of long-term debt.................................... 126,472 274,949
Loan to ESOP................................................................ (15,000)
Repayment of long-term debt, including reacquisition premium................ (15,754) (191,571)
Proceeds from issuance of common stock...................................... 41,770 43,681
Dividends paid.............................................................. (148,068) (142,813)
Net cash provided by (used for) financing activities......................... 10,827 (129,745)
Net increase in cash and cash equivalents...................................... 50,604 4,816
Cash and cash equivalents at beginning of period............................... 28,794 41,055
Cash and cash equivalents at end of period..................................... $79,398 $45,871
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 September 30, 1996 and December 31,
1995, the results of its operations for the three and nine months ended
September 30, 1996 and 1995, and its cash flows for the nine months ended
September 30, 1996 and 1995. Due to the seasonality of NSP's electric and gas
sales, 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 NSP's
financial statements in NSP's Annual Report on Form 10-K for the year ended
December 31, 1995 (1995 Form 10-K). The following notes should be read in
conjunction with such policies and other disclosures in the 1995 Form 10-K.
Certain reclassifications have been made to 1995 financial information
to conform with the 1996 presentation. These reclassifications had no effect
on net income or earnings per share as previously reported.
1. Summary of Significant Accounting Policies
1996 Accounting Change - Wisconsin Gas Costs - While fixed costs (demand
charges) from gas suppliers and transporters are incurred fairly evenly
throughout the year, such costs are recovered in customer rates on a per unit
basis (using average annual costs per unit), primarily in the winter heating
season when sales volumes are highest. Also, the energy price of gas
purchased (excluding demand charges) can vary from estimated levels included
in customer rates. As a result, gas costs for both demand and energy charges
are incurred throughout the year at a different time than when such costs are
recovered from customers. The purchased gas adjustment (PGA) clause allows
customer rates to be adjusted periodically to ensure full recovery of all gas
costs incurred.
Effective January 1, 1996, NSP's subsidiary, Northern States Power
Company, a Wisconsin corporation (the Wisconsin Company) changed its method
of accounting for the regulatory effects of costs recovered through the PGA
rate adjustment clause. Previously, the Wisconsin Company expensed gas costs
as incurred. Beginning in 1996, the cost of gas expensed is adjusted to equal
the level of cost recovery in customer rates, with such adjustments being
reflected as regulatory deferrals on the balance sheet. This accounting
change results in a better matching of revenues and expenses, and conforms to
the cost recognition method used by the Company.
This change affects the timing of expense recognition within the year but
will not change total annual gas expense for 1996 or any prior years. The
effect of the change on third quarter 1996 results was a decrease in gas costs
recognized and an increase in pretax operating income of approximately $3.7
million, and an increase in net income of $2.2 million (three cents per
share). The effect of the change on the first nine months of 1996 results was
a decrease in gas costs recognized and an increase in pretax operating income
of approximately $0.3 million, and an increase in net income of $0.2 million
(with no impact on earnings per share). Consistent with accounting
requirements, prior year quarterly results have not been restated for this
change. Had the change been implemented as of January 1, 1995, the effect of
the change on third quarter 1995 results would have been a decrease in gas
costs recognized and an increase in pretax operating income of approximately
$4.2 million, and an increase in net income of $2.5 million (four cents per
share). The effect of the change on results for the first nine months of 1995
results would have been a decrease in gas costs recognized and an increase in
pretax operating income of approximately $1.7 million, and an increase in net
income of $1.0 million (one cent per share).
2. Proposed Business Combination
On April 28, 1995 NSP and Wisconsin Energy Corporation (WEC) entered into
an Agreement and Plan of Merger (the Merger Agreement), which provides for a
strategic business combination involving NSP and WEC in a "merger-of-equals"
transaction to form Primergy Corporation (Primergy). See further discussion
of the proposed business combination in the 1995 Form 10-K and Part II, Item
5-Other Information of this report. The 1996 developments, related to merger
filings made in 1995, are discussed below. The goal of NSP and WEC was to
receive approvals from all required regulatory authorities by the end of 1996.
However, (as discussed below) it appears that all necessary regulatory
approvals will not be obtained by the end of 1996, and as a result, the merger
will not be completed during 1996. If this is the case, NSP and WEC will
continue to pursue regulatory approvals and completion of the merger as soon
as possible in 1997.
In July 1995, WEC and NSP filed an application and supporting testimony
with the Federal Energy Regulatory Commission (FERC) seeking approval of the
Merger Agreement. On May 28, 1996, WEC and NSP filed additional evidence with
the FERC, providing a detailed analysis of generation "market power" and more
specific information about the independent system operator (ISO) proposal
included in earlier filings. This additional information was provided to the
FERC in response to concerns raised by intervenors in the merger proceeding
and by the FERC staff.
The FERC administrative law judge (ALJ), in the merger proceeding, issued
an initial decision on August 29, 1996 recommending approval of the merger
application, subject to NSP and WEC meeting eight conditions. A significant
part of the ALJ's initial decision involves establishing an ISO. The ALJ's
initial decision specifically rejected the need for divestiture of any
generation or transmission facilities as a requirement for ensuring open and
equal access to the transmission system. In October 1996, in response to the
FERC staff and intervenor opposition to the merger based on the claim that
Primergy would be able to exercise transmission market power after the merger,
NSP and WEC filed a Unilateral Offer of Settlement (UOS) with the FERC. The
UOS includes a transmission system control agreement and articles and bylaws
for establishing an ISO. NSP and WEC are hopeful that the FERC will
simultaneously approve the UOS and the pending merger application in late
1996.
On April 10, 1996, the Michigan Public Service Commission approved the
merger application through a settlement agreement containing terms consistent
with the merger application. On June 26, 1996, the North Dakota Public
Service Commission (NDPSC) approved the merger application. These state
commission approvals represent two of the four states where approval of the
merger is required.
In June 1996, the Minnesota Public Utilities Commission (MPUC) issued an
order which established the procedural framework for the MPUC's consideration
of the merger. The issues of merger-related savings, electric rate freeze
characteristics, NSP's pre-merger revenue requirements, Primergy's ability to
control the transmission interface between the Mid-Continent Area Power Pool
and the Wisconsin and upper Michigan area, and the impact of control of this
interface on Minnesota utilities were set for contested case hearings.
Administrative law judges have scheduled evidentiary hearing dates from
November 20 through December 6, 1996. Unless the MPUC proceedings are
settled, the MPUC's decision will not be obtained until early 1997.
On July 24, 1996, the Public Service Commission of Wisconsin (PSCW) held
a prehearing conference on the merger proceeding. At the prehearing
conference the parties agreed upon an extensive issues list and a schedule for
the hearing. The schedule originally required staff and intervenor case
filings and applicants rebuttal filing in September 1996, and three weeks of
hearings commencing on September 24, 1996. At its open meeting on August 8,
1996, the PSCW revised the schedule and set hearing dates to begin October 30,
1996. The resulting schedule should lead to a PSCW decision on the merger in
early 1997 and a written order in the first quarter of 1997. In October 1996,
the PSCW staff filed testimony with the PSCW proposing various conditions,
including potential divestiture of certain transmission and generation assets
and a larger reduction in electric rates. These recommendations differ
materially from the merger terms and conditions included in the application
which NSP and WEC originally filed with the PSCW.
In a related matter, the PSCW in September 1996 issued an order that set
minimum standards for creating an ISO that differs from NSP's and WEC's
proposal for an ISO. This order was issued as part of a generic electric
utility restructuring process the PSCW started in 1995. Although the
restructuring process is separate from the merger proceedings, the order is
related because the PSCW staff, in its testimony filed in the merger
proceeding (as discussed above), recommended establishing an ISO that meets
the standards of the PSCW's order as a condition to approving the merger. In
addition, in September 1996, the PSCW submitted its ISO order to the FERC with
a request that the FERC require the establishment of an ISO satisfying the
PSCW minimum standards as a condition to its approval of the NSP/WEC merger
application. In October 1996, NSP and WEC filed with the PSCW, as
supplemental testimony and exhibits in the merger proceeding, the same ISO
proposal included with the UOS filed with the FERC (as discussed previously).
On April 5, 1996, NSP and WEC submitted the initial filing to the
Securities and Exchange Commission (SEC) to facilitate registration of
Primergy under the Public Utility Holding Company Act of 1935, as amended.
Notification under the Hart-Scott-Rodino Antitrust Improvements Act of 1976,
as amended, will be filed prior to completion of the proposed merger.
The merger filings, with each state, included a request for deferred
accounting treatment and rate recovery of costs incurred associated with the
proposed merger. At September 30, 1996, NSP had incurred $20.7 million of
costs associated with the proposed merger which have been deferred as a
component of Intangible Assets and Other.
Under the Merger Agreement, completion of the merger is conditioned upon
the prior receipt of all necessary regulatory approvals without the imposition
of materially adverse terms.
3. Business Developments
Non-regulated Acquisitions - On April 30, 1996, NSP's wholly owned
subsidiary NRG Energy, Inc. (NRG) closed on its acquisition of a 41.86 percent
interest in O'Brien Environmental Energy, Inc. (O'Brien) as discussed in the
Company's 1995 Annual Report on Form 10-K and the Company's reports on Form
10-Q for the quarters ended March 31 and June 30, 1996. O'Brien has been
renamed NRG Generating (U.S.) Inc. (NRGG). The former shareholders of O'Brien
own the remaining 58.14 percent of NRGG, which will be publicly traded under
the ticker symbol NRGG. NRGG has interests in three domestic operating power
generation facilities with aggregate capacity of approximately 180 megawatts,
and in one 150-megawatt facility in the development stage.
As a result of the purchase, on April 30, 1996 approximately $107.3
million was made available to O'Brien and its creditors by NRG consisting of
the following: (i) a $7.5 million payment to the original shareholders of
O'Brien to acquire their equity interest; (ii) an additional $28.7 million
equity investment by NRG, which includes $7.5 million for the acquisition of
certain biogas projects; and (iii) loans totalling $71.1 million from NRG to
O'Brien, which were made to pay off O'Brien creditors. In connection with the
closing on its O'Brien acquisition, NRG was released from its $100 million
letter of credit obtained in January 1996 to secure its obligation to complete
its proposed investment in O'Brien. At September 30, 1996, approximately
$12.7 million of the $71.1 million in loans, from NRG to NRGG, were
outstanding and recorded as a long-term receivable.
On September 29, 1996, a new wholly owned subsidiary of NRG purchased the
senior debt of Mid-Continent Power Company of Pryor, Oklahoma. Mid-Continent
Power Company supported the transaction and views NRG's acquisition of its
senior debt as a first step in what it hopes will be a successful
restructuring of its finances.
4. Rate Matters
North Dakota - On August 7, 1996, the NDPSC approved an annual reduction
of $491,000 or 1.4 percent in natural gas rates, effective September 1, 1996.
In January 1996, the Company had filed for an annual gas rate reduction of
$485,000, in response to the NDPSC staff audit of gas earnings for the North
Dakota jurisdiction for the years 1991 to 1995. The approval also allows the
Company to set class rates so that prices are more consistent with costs to
serve and are more competitive with other alternatives. In addition, the
approval also restates the base cost of gas stated in the Company's tariffs
and eliminates three items unrelated to purchased gas costs from the purchased
gas adjustment recovery mechanism. This reduction is in addition to the 1.25
percent gas rate reduction, or $375,000, approved by the NDPSC in June 1996,
to be implemented upon completion of the proposed business combination (as
discussed previously in the 1995 Form 10-K). Electric rates will also be
reduced by 1.5 percent, or $1,454,000 on an annual basis, upon completion of
the proposed business combination.
Wisconsin - Technical hearings for the Wisconsin Company's electric and
gas rate cases, based on a 1997 pre-merger test year, were held before the
PSCW on July 8, 1996. On October 10, 1996, at its open meeting, the PSCW made
decisions on the issues in the Wisconsin Company's 1997 rate cases. Although
a final order has not yet been issued by the PSCW, the PSCW made the following
preliminary decisions.
Overall, electric and gas rates will remain unchanged in 1997. However,
certain classes of customers will experience small changes in rates, as a
result of revisions in rate design. The Wisconsin Company had requested
changes to electric rates for various classes of customers, which would have
an offsetting effect on overall revenues. The Wisconsin Company had requested
no changes to gas rates. The PSCW approved a capital structure composed of
45% debt and 55% common equity. The PSCW granted an 11.3% return on common
equity.
South Dakota - On September 30, 1996, NSP filed for a rate reduction for
its South Dakota customers of 1.5 percent, or $1,178,000 on an annualized
basis. The reduction is to be implemented upon completion of the proposed
Primergy merger. Regulatory action on this request is expected by year-end
1996.
5. 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 1995 Annual
Report on Form 10-K. Steps have been taken to fulfill these commitments
during 1996 as described below.
On August 8, 1996, NSP submitted a license application to the Nuclear
Regulatory Commission (NRC) for an alternative site in Goodhue County to
provide temporary storage for spent nuclear fuel. The application to the NRC
was required before casks six through nine could be used at the existing
facility for temporary spent nuclear fuel storage. On October 2, 1996 the
Minnesota Environmental Quality Board (MEQB) terminated the alternate spent
fuel storage facility siting process in Goodhue County and certified that NSP
has met the requirements necessary to use the casks at the Prairie Island
plant. On October 28, 1996 the Prairie Island Dakota Indian Tribe (the Tribe)
filed suit with the Minnesota Court of Appeals challenging the MEQB actions.
The Tribe has asked that the MEQB actions be stayed during the pendency of the
suit which would prevent NSP from using casks six through nine. NSP is
vigorously contesting this matter. NSP currently anticipates that the sixth
cask will not be needed for used fuel storage until 1998. Since 1994, NSP has
spent nearly $3 million in a good faith effort to locate an alternate spent
fuel storage site in Goodhue County, as required by the 1994 Minnesota State
Legislature.
A conflict has been resolved over wind rights and other issues with
KENETECH Windpower, Inc. and an agreement has been signed between NSP and Zond
Systems, Inc. allowing construction of 100 megawatts (MW) of wind power. This
100 MW increment represents Phase II of NSP's commitment to 425 MW of wind
generation resources. On October 25, 1996, NSP issued a request for proposal
for another 100 MW increment of wind power, which represents Phase III.
Minnesota Agri-Power Project (Minnesota Valley Alfalfa Producers and
Polsky Energy Corporation) have been selected to supply 75 MW of farm-grown,
closed-loop biomass generation resources to the NSP system by December 31,
2000. The 75 MW of biomass generation resources represents Phase I of NSP's
legislative commitment to have 125 MW of such generation by the end of 2002.
Nuclear Insurance - The circumstances set forth in Note 15 to NSP's
financial statements contained in the 1995 Form 10-K appropriately represent
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 OPERATIONS
On April 28, 1995, the Company and WEC entered into an Agreement and Plan
of Merger which provides for a strategic business combination involving the
two companies in a "merger-of-equals" transaction. Further information
concerning this agreement and proposed transaction and pro forma financial
information with respect thereto is included in the 1995 Form 10-K, Note 2 to
the Financial Statements and Part II of this report. The following discussion
and analysis is based on the financial condition and operations of NSP and
does not reflect the potential effects of its combination with WEC.
Except for the historical statements contained herein, the matters
discussed in the following discussion and analysis, including the statements
regarding the anticipated impact of the proposed merger, 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; regulatory decisions regarding the proposed
combination of NSP and WEC; and the other risk factors listed in Exhibit 99.01
to this report on Form 10-Q for the quarter ended September 30, 1996.
Results of Operations
NSP's earnings per share for the third quarter ended September 30, 1996,
were $1.18, down $.09 from the $1.27 earned for the same period a year ago.
For the first nine months of 1996, earnings per share were $2.70, down $0.39
from the $3.09 earned in the comparable period a year ago. As discussed in
the next section, 1995 results for the first nine months include $0.22 in
earnings from non-recurring items. The results of the regulated utility
businesses and the non-regulated businesses 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 mainly to stock issuances for the Company's dividend
reinvestment and stock ownership plans.
Factors Affecting Results of Operations
In addition to items noted in the 1995 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:
Non-regulated Business Results - Quarterly results include earnings
contributions from non-regulated businesses of $0.07 per share in 1996 and
$0.08 per share in 1995. The following summarizes the quarterly and year-to-
date earnings contributions of NSP's non-regulated businesses:
3 Mos. Ended 9 Mos. Ended
9/30/96 9/30/95 9/30/96 9/30/95
NRG $0.07 $0.07 $0.16 $0.46*
Eloigne Company 0.01 0.01 0.03 0.02
Cenerprise, Inc.
(Cenerprise) (0.02) (0.01) (0.08) (0.02)
Other 0.01 0.01 0.02 0.03
Total $0.07 $0.08 $0.13 $0.49
* Includes non-recurring transactions contributing $0.22 per share as
discussed below.
Due to the nature of these non-regulated businesses, NSP anticipates that
the earnings from non-regulated operations will experience more variability
than regulated utility businesses. As discussed below, NSP's non-regulated
earnings in the nine-month period ended September 30, 1996 are experiencing
such variability.
NRG - NRG's third quarter 1996 earnings per share contribution was
unchanged from the same period one year ago, as higher 1996 equity earnings
from the Schkopau and Latin Power projects and NRGG were offset by lower
earnings from MIBRAG. One unit of the Schkopau power generation facility
began commercial operation in March 1996, with the second unit beginning
operation in late July of 1996. Equity in earnings from MIBRAG decreased due
to an expected decline in heating briquette and coal sales.
NRG's earnings for the nine months ended September 30, 1995 included two
non-recurring items which added 22 cents to 1995 earnings. A gain of
approximately 26 cents per share was recorded for a power sales contract
termination settlement, which was partially offset by a domestic energy
project write-down of four cents per share. Excluding these non-recurring
items, NRG's earnings for the nine-month periods ended September 30 declined
in 1996 compared with 1995 due primarily to higher business development
expenses, which increased overall operating expenses, and due to lower equity
in earnings of projects.
NRG has experienced an increased level of business development costs in
the nine-month period ending in 1996 as compared to 1995 as it has pursued
several international and domestic projects. Until there is substantial
assurance that a project under development will come to financial closure,
such costs are expensed. Equity in earnings of projects decreased in the nine
months ended September 30, 1996, as lower equity in earnings from the MIBRAG
and San Joaquin projects were partially offset by first time earnings from
Schkopau and NRGG. Equity in earnings from MIBRAG decreased primarily due to
an expected decline in heating briquette and coal sales, while the equity in
earnings from the San Joaquin project declined because the plant shut down due
to the buyout of the power sales contract in February 1995.
Cenerprise - The earnings of NSP's wholly owned subsidiary, Cenerprise,
Inc., for the nine months ended September 30, 1996 were down compared to the
same period one year ago due largely to losses incurred from the gas trading
business. As a result of the volatility associated with the gas trading
business, Cenerprise curtailed its gas trading activities early in the second
quarter of 1996. Cenerprise will purchase gas only to supply its end-use
customers.
Estimated Impact of Weather on Regulated Earnings - NSP estimates 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):
Increase/Decrease
1996 1995 1996
vs vs vs
Normal Normal 1995
Earnings per Share for:
Quarter Ended
September 30 ($0.06) $0.13 ($0.19)
Nine Months Ended
September 30 $0.08 $0.17 ($0.09)
The estimated impact of weather considers only the impacts of variations
from average temperatures. The first quarter of 1996 (which is included in
the nine months ended September 30, 1996 amounts) includes the effects of
extremely cold temperatures in late January and early February of 1996.
Although such cold weather in this period would be expected to result in
increased energy sales, an ice storm immediately preceding the cold weather
resulted in as many as 200,000 customers being temporarily out of service, and
bitterly cold temperatures resulted in some customers shutting down or
curtailing their operations. Because these secondary weather impacts are not
reliably quantifiable, their expected effects (an offset to the energy sales
increase from cold weather) have not been included in the estimated impact of
weather on 1996 operating results. Also, June and August of 1995 were
significantly warmer than normal, contributing an estimated $0.20 per share
to the weather impact for the first nine months of 1995.
Competition - On April 24, 1996, the FERC issued two final rules, Order
Nos. 888 and 889 which may have a potentially significant impact on wholesale
markets. Order No. 888, which was preceded by a notice of proposed rulemaking
referred to as the "Mega-NOPR", concerns rules on non-discriminatory open
access transmission service to promote wholesale competition. Order No. 888,
which was effective on July 9, 1996, requires utilities and other transmission
users to abide by comparable terms, conditions and pricing in transmitting
power. Order No. 889, which had its effective date extended to January 3,
1997, requires public utilities to implement Standards of Conduct and an Open
Access Same Time Information System ("OASIS", formerly known as "RIN"). These
rules require transmission personnel to provide information about the
transmission system to all transmission customers using the OASIS. A new
proposed rule on Capacity Reservation Open Access Transmission Tariffs, was
also issued on April 24, 1996. This proposed rule requested comments on a new
proposed tariff to be in effect no later than December 31, 1997. With regard
to compliance with the first phase of Order 888, on July 9, 1996, NSP
submitted its transmission tariff compliance filing and an information filing
which unbundled the transmission component of the full requirements municipal
wholesale customers' rates. On October 16, 1996 the FERC accepted NSP's
information filing. NSP is also taking steps to comply with Order 889 and
continues to be generally supportive of the FERC's efforts to increase
competition.
Another impact of complying with the FERC's Order No. 888 is a
requirement for utilities to offer a transmission tariff which includes
network transmission service (NTS) to transmission customers. NTS allows
transmission service customers to fully integrate load and resources on an
instantaneous basis, in a manner similar to how NSP has historically
integrated its load and resources. Customers can elect to participate in the
cost-sharing network by requesting NTS service from NSP. Under NTS, NSP and
participating customers 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 system load. The expected annual expense
increase to NSP, net of cost-sharing revenues, as a result of offering NTS is
estimated to be approximately $20 million with some of the costs beginning as
soon as late 1996.
In response to potential competition from a retail customer's proposed
cogeneration project, on July 29, 1996, the Company signed an electric service
agreement with Koch Refining Co. (Koch), the Company's largest customer.
Under the terms of the agreement, Koch has provided to the Company an option
and right of first refusal in a base load cogeneration unit that Koch has the
discretion to build at the refinery. In exchange for this option, the Company
has provided to Koch an electric service agreement to meet Koch's electric
power needs, subject to agreed upon options by Koch. Under a 1996 change in
Minnesota property tax law, Koch was required to offer such an option to NSP
or another Minnesota utility as a pre-condition to obtaining a property tax
reduction on the plant. The electric service agreement is subject to review
and approval of the MPUC. The Company anticipates a ruling by the MPUC by the
end of 1996.
Computer Software Changes for the Year 2000 - Like many other companies,
NSP expects to incur significant software development costs to modify existing
computer programs to accommodate the year 2000 and beyond. NSP is currently
investigating its alternatives for the most cost-effective means for these
modifications. Assuming NSP's proposed merger with WEC is completed, the
preliminary estimate of NSP's portion of the operating expenses to be spent
on this project, primarily in 1997 and 1998, is expected to range from $20 to
$25 million. The amount of any additional development costs necessary to
prepare for the year 2000 if the merger is not completed has not been
determined at this time.
Third Quarter 1996 Compared with Third Quarter 1995
Utility Operating Results
Electric revenues for the third quarter 1996 compared with the third
quarter 1995 decreased $33.2 million or 5.4%. Retail revenues decreased
approximately $25.4 million or 4.4% largely due to a 2.6% mwh sales decrease.
The lower retail electric sales were mainly due to the impacts of less
favorable weather in 1996 than 1995. The average retail electric price
decreased 1.8%, due to rate adjustments for lower fuel expenses and lower
rates in Wisconsin, but were somewhat offset by increased recovery of
conservation expenditures (as discussed below). On a weather-adjusted basis,
retail sales growth for the third quarter 1996 was 1.2% higher than 1995. All
other electric revenues were down $7.8 million primarily due to lower market
pricing of sales to other utilities and the effects of contract terminations
for municipal customers, which were expected.
Gas revenues for the third quarter 1996 increased $1.5 million or 3.3%
compared with the third quarter of 1995. Gas revenues increased primarily due
to a 1.7% increase in gas sales volume and higher transportation and off
system sales, partly offset by a 7.5% average price decrease. The sales
volume increase is mainly due to growth in firm customer sales. The price
decrease is mainly due to rate adjustments for decreased purchased gas costs
resulting primarily from changes in natural gas market conditions.
Fuel for electric generation and Purchased and interchange power combined
for a net decrease of $17.7 million or 11.0% for the third quarter of 1996
compared with the third quarter of 1995. Fuel expense decreased $12.9 million
due to lower plant output and lower average fuel costs. Plant output was down
due to lower sales, regional system limitations and conversion of two plants
to peaking status. Lower average fuel costs resulted from less use of more
expensive gas and oil facilities in 1996 as a result of cooler weather.
Purchased and interchange power decreased $4.9 million due primarily to lower
average cost of purchases, reflecting market conditions from cooler weather
in 1996 and increased competition due to open access, and lower demand
expenses.
Cost of gas purchased and transported for third quarter 1996 compared
with third quarter 1995 decreased $4.2 million or 16.1% due to lower per unit
cost of purchased gas partly offset by higher sendout. The lower cost of
purchased gas reflects changes in market conditions and gas cost adjustments.
(See Note 1 to the Financial Statements for discussion of the accounting
change for Wisconsin gas costs to more accurately match cost recovery in
revenues.) The higher gas sendout reflects increased gas sales.
Other operation, Maintenance and Administrative and general expenses
together decreased $7.5 million or 4.6% compared with the third quarter 1995.
The lower costs are largely due to less overhead line maintenance costs, lower
insurance costs and lower employee benefit costs.
Conservation and energy management expenses increased $0.8 million in the
three-month period ended September 30, 1996 compared to the same period in
1995 due mainly to higher amortization levels of
deferred electric and gas conservation and energy management program costs.
Higher cost levels also include the effects of expensing currently (rather
than amortizing over a period of time) new conservation expenditures beginning
in 1996. These higher amortization and cost levels are recovered concurrently
through retail rate adjustments in the Company's Minnesota jurisdiction which
increased cost recovery (relative to the prior year) beginning with August
1996 billings for electric and November 1995 and September 1996 billings for
gas.
Depreciation and amortization increased $4.1 million or 5.7% compared
with the third quarter of 1995. The increase is mainly due to increased plant
in service between the two periods, including a new customer service system
placed in service in March 1996.
Property and general taxes for the third quarter 1996 compared with the
third quarter of 1995 decreased $0.8 million or 1.3% due primarily to higher
property tax accrual levels in 1995, which were ultimately adjusted downward
at year-end 1995 based on final property tax notices received for 1995.
Utility income taxes for third quarter 1996 compared with third quarter
1995 decreased $0.2 million primarily due to lower pretax operating income
(after interest charges) between the two periods partly offset by a slightly
higher effective tax rate expected for 1996.
Other income (deductions) - net largely reflects non-regulated items
discussed below.
Allowance for funds used during construction (AFC) increased $1.4 million
to $4.9 million in 1996 largely due to higher plant in service and timing of
returns recorded for capital used to finance conservation and energy
management programs.
Non-regulated Business Results
NSP's non-regulated operations include many diversified businesses, such
as independent power production, energy 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 discusses NSP's diversified business results in the
aggregate.
Operating Revenues and Expenses - The net results of non-regulated
businesses are reported in Other Income (Deductions)-Net on the Consolidated
Statements of Income. Non-regulated operating revenues decreased $7.3 million
in the third quarter of 1996, to $56.1 million, largely due to Cenerprise's
exit from the gas trading business. Non-regulated operating expenses
decreased $7.7 million in the third quarter of 1996 to $58.8 million due
primarily to lower gas costs corresponding with Cenerprise's exit from gas
trading.
Equity Income - NSP has a less-than-majority equity interest in many non-
regulated projects. Consequently, a large portion of NSP's non-regulated
earnings is reported as Equity in Earnings of Unconsolidated Affiliates on the
Consolidated Statements of Income. Equity income decreased in the third
quarter of 1996 by $1.9 million primarily due to lower income from NRG
projects, as discussed previously.
Other income (deductions) - net increased by $0.8 million to $2.1 million
in the third quarter of 1996 due mainly to higher income from cash
investments.
Non-regulated interest and amortization increased $2.4 million to $5.0
million due to the issuance of new debt by NRG ($125 million in January 1996).
Income Taxes - Income Taxes on Non-regulated Operations and Non-operating
Items reported on the Consolidated Statements of Income includes income taxes
related to non-regulated businesses. Such income taxes for the third quarter
of 1996 were a net benefit of $3.9 million in 1996, compared with a net
benefit of $1.8 million in the third quarter of 1995. The amount of tax
benefits increased in 1996 due mainly to lower domestic income from NRG and
Cenerprise, as discussed previously, and to higher income tax credits from
Eloigne Company's affordable housing projects. NSP's management intends to
reinvest the earnings of international operations indefinitely. Accordingly,
U.S. income taxes and foreign withholding taxes have not been provided on the
earnings of international projects.
First Nine Months of 1996 Compared with First Nine Months of 1995
Utility Operating Results
Electric revenues for the first nine months of 1996 compared with the
first nine months of 1995 decreased $30.5 million or 1.9%. Retail revenues
decreased approximately $1.7 million or 0.1% largely due to lower average
prices, partly offset by higher retail sales. Retail electric sales increased
0.6% due to sales growth, net of less favorable weather in 1996 as compared
to 1995 (as discussed previously). Average retail prices decreased slightly,
by 0.7%, primarily due to lower fuel expense recovery partly offset by
increased recovery of deferred conservation and energy management costs (as
discussed below). Revenues from sales to other utilities decreased by $21.6
million mainly due to decreases in sales volume. This decrease in sales to
other utilities reflects less availability due to higher retail sales
requirements and more major planned plant outages in 1996 (as discussed
below), market conditions and regional transmission system limitations.
Wholesale revenues were impacted by the effects of contract terminations by
municipal customers, which were expected, resulting in a $13.1 million
decrease. Other electric revenues increased $5.9 million primarily due to
increased wheeling revenues and revenues related to recovery of conservation
and energy management costs.
Gas revenues for the first nine months of 1996 increased $58.9 million
or 21.1% compared with the first nine months of 1995. Gas revenues increased
due to a 14.0% increase in gas sales volume and a 5.0% average price increase.
The sales volume increase is due primarily to sales growth and weather
impacts. The price increase is mainly due to rate adjustments for increased
purchased gas costs resulting from changes in natural gas market conditions.
Fuel for electric generation and Purchased and interchange power combined
for a net decrease of $34.6 million or 7.8% for the first nine months of 1996
compared with the first nine months of 1995. Fuel expense decreased $30.6
million primarily due to lower average fuel costs resulting from a new coal
transportation contract in July 1995, and lower plant output caused by planned
outages for maintenance and conversion of two plants to peaking status.
Purchased and interchange power decreased $4.0 million due primarily to lower
demand expenses.
Cost of gas purchased and transported for first nine months of 1996
compared with first nine months of 1995 increased $41.2 million or 24.8% due
to higher gas sendout and higher per unit cost of purchased gas. The 13.5%
increase in gas sendout reflects increased gas sales, while the 9.8% increase
in cost per unit of purchased gas reflects changes in market conditions.
Other operation, Maintenance and Administrative and general expenses
together decreased $1.1 million or 0.2% compared with the first nine months
of 1995. The lower costs are largely due to lower administrative and general
costs partly offset by higher scheduled plant maintenance outages expenses.
Administrative and general expenses reflect decreases in insurance and
employee benefit costs. Planned maintenance outages occurred at three major
plants in the first nine months of 1996 compared with only two major plants
in the first nine months of 1995. Of the $11.1 million increase in Other
operation and Maintenance expenses, $9.0 million is due to additional costs
related to the timing of planned outages at generating plants.
Conservation and energy management expenses increased $11.2 million in
the nine-month period ended September 30, 1996 compared to the same period in
the prior year due mainly to higher amortization levels of deferred electric
and gas conservation and energy management program costs. Higher cost levels
also include the effects of expensing currently (rather than amortizing
over a period of time) new conservation expenditures beginning in 1996.
These higher amortization and cost levels are recovered concurrently through
retail rate adjustment clauses in the Company's Minnesota jurisdiction
beginning with May 1995 billings for electric and November 1995 billings for
gas. Rate recovery levels were again increased in August 1996 for electric
and September 1996 for gas.
Depreciation and amortization increased $11.0 million or 5.1% compared
with the first nine months of 1995. The increase is mainly due to increased
plant in service between the two periods, including a new customer service
system placed in service in March 1996.
Property and general taxes for the first nine months of 1996 compared
with the first nine months of 1995 decreased $5.3 million or 2.8% due
primarily to higher property tax accrual levels in 1995 which were ultimately
adjusted downward at year-end 1995, based on final property tax notices
received for 1995.
Utility income taxes for the first nine months of 1996 compared with the
first nine months of 1995 increased $8.0 million primarily due to higher
pretax operating income (after interest charges) between the two periods and
a slightly higher effective tax rate expected for 1996.
Other income (deductions) - net largely reflects non-regulated items
discussed below.
Allowance for funds used during construction (AFC) increased $2.9 million
to $14.3 million in 1996 largely due to more construction activity and returns
recorded for capital used to finance conservation and energy management
programs.
Non-regulated Business Results
The following discusses NSP's diversified business results in the
aggregate.
Operating Revenues and Expenses - The net results of non-regulated
businesses are reported in Other Income (Deductions)-Net on the Consolidated
Statements of Income. Non-regulated operating revenues increased $19.8
million in the first nine months of 1996, to $241.2 million, largely due to
market-driven increases in gas prices charged to customers by Cenerprise
during the first two quarters of the year. Non-regulated operating expenses
increased $26.3 million in the first nine months of 1996 to $255.2 million due
to market-driven increases to cost of gas experienced by Cenerprise during the
first two quarters of the year, increased NRG project development costs being
expensed (as discussed previously) and losses incurred from Cenerprise's gas
trading business (as discussed previously).
Equity Income - Equity income decreased in the first nine months of 1996
by $34.6 million primarily due to a $29.9 million gain recorded in 1995 for
a power sales contract termination settlement, as discussed previously. In
addition, equity income from NRG energy projects decreased as discussed
previously.
Non-regulated interest and amortization increased $6.7 million to $13.9
million due to the issuance of new debt by NRG ($125 million in January 1996)
and for Eloigne Company projects.
Other income (deductions) - net - Nonoperating income (net of expense
items) related to non-regulated businesses increased by $4.4 million mainly
due to higher income from cash investments.
Income Taxes - Income taxes related to non-regulated businesses for the
first nine months of 1996 were a net benefit of $11.9 million, a $19.3 million
decrease over a net tax expense of $7.4 million in the first nine months of
1995. The decrease in 1996 is due mainly to lower income from NRG and
Cenerprise, as discussed previously, and to higher income tax credits from
Eloigne Company's affordable housing projects.
Liquidity and Capital Resources
The Company had approximately $216 million in commercial paper debt
outstanding as of September 30, 1996. 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 and support for
commercial paper sales. The Company has regulatory approval for up to $445
million in short-term borrowing levels.
Commercial banks currently provide credit lines of $48.5 million to
wholly owned subsidiaries of the Company. At September 30, 1996,
approximately $6.0 million in loans against these credit lines were
outstanding. In addition, $17.5 million in letters of credit were
outstanding, which reduced the available credit lines at September 30, 1996
and therefore approximately $25.0 million of those credit lines remained
available at September 30, 1996.
In January 1996, stock options for the purchase of 263,039 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 September 30, 1996, a total of 1,115,674 stock
options were outstanding, which were considered as potential common stock
equivalents for earnings per share purposes. During the first nine months of
1996, the Company has issued 118,304 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
587,055 shares of common stock during the first nine months of 1996. During
1996, the Company has issued an additional 182,828 shares of new common stock
to the Employee Stock Ownership Plan for dividends on Company shares held.
In addition, the Company adjusted the number of shares previously issued in
connection with a non-regulated business acquisition.
On January 29, 1996, NRG issued $125 million of 7.625 percent unsecured
Senior Notes maturing in 2006 to support equity requirements for projects
currently under way and in development. The Senior Notes were assigned
ratings of BBB- by Standard & Poor's Rating Group and Baa3 by Moody's
Investors Services. See discussion of NRG's recent project developments at
Note 3 to the Financial Statements.
The Wisconsin Company registered $65 million of first mortgage bonds with
the SEC in July 1996. Depending on capital market conditions, the Wisconsin
Company may issue all or a portion of this debt in 1996, for purchase or
redemption of one or more series of outstanding first mortgage bonds and
repayment of outstanding short-term borrowings incurred in connection with the
Wisconsin Company's continuing construction program. The remainder of the
proceeds would be added to the general funds of the Wisconsin Company. On
November 1, 1996 the Wisconsin Company issued $18.6 million of 6 percent
resource recovery revenue bonds, due November 1, 2021, for the City of
LaCrosse. On the same date, the proceeds were used to refund a $18.6 million,
7 3/4 percent, City of LaCrosse resource recovery bond, due November 1, 2011.
Depending on capital market conditions, the Company may issue
approximately $150 to $200 million in grantor trust originated preferred
securities in late 1996 or early 1997.
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.
As discussed in Item 3 - Legal Proceedings of NSP's 1995 Annual Report
on Form 10-K, the Company, along with other major utilities, filed a lawsuit
against the Department of Energy (DOE) in an attempt to clarify the DOE's
obligation to dispose of spent nuclear fuel beginning not later than January
31, 1998. The primary purpose of the lawsuit was to insure that the Company
and its customers receive timely storage and disposal of spent nuclear fuel
in accordance with the terms of the Company's contract with the DOE. On July
23, 1996, the U.S. Court of Appeals for the District of Columbia Circuit,
affirmed the federal government's obligation. The court unanimously ruled
that the Nuclear Waste Policy Act creates an unconditional obligation for the
DOE to begin acceptance of spent nuclear fuel by January 31, 1998. The DOE
did not seek U.S. Supreme Court review. The ruling is a very positive
development for the industry regarding concerns about the storage and disposal
of used nuclear fuel.
In October of 1996, the Hennepin County District Court (the Court)
granted, in part, plaintiffs' motion for class action certification in Hamline
Park Plaza Partnership, et al v. Northern States Power Company. This lawsuit
was commenced by two NSP commercial customers who participated in NSP's
Lighting Efficiency Program (LEP) and now claim that NSP misrepresented the
expected energy savings from this program. The Court limited the class to
commercial and industrial customers who have participated in the LEP since
February 1993. This decision only addresses the procedural issue concerning
who may participate in the lawsuit, and does not constitute a determination
about the merits of plaintiffs' claims. NSP, which is required to participate
in the LEP by virtue of a Minnesota statute, denies all liability with respect
to plaintiffs' claims. Plaintiffs seek damages in excess of $50,000 for their
claims.
For a discussion of legal proceedings concerning the alternate spent
nuclear fuel storage site, see Part 1, Item 1, Note 5 to Notes to Consolidated
Financial Statements, incorporated herein by reference.
Item 5. Other Information
MERGER AGREEMENT WITH WISCONSIN ENERGY CORPORATION
As previously reported in the Company's Current Report on Form 8-K, dated
April 28, 1995 and filed on May 3, 1995, and the 1995 Form 10-K, NSP and WEC
have entered into an Agreement and Plan of Merger (the "Merger Agreement"),
which provides for a strategic business combination involving NSP and WEC in
a "merger-of-equals" transaction (the Merger Transaction). Under the proposed
business combination, current common stockholders of NSP would receive 1.626
shares of Primergy common stock for each share of NSP common stock owned, and
current bondholders and preferred stockholders of NSP will become investors
in a new company succeeding to the business of NSP as an operating public
utility (New NSP). The Merger Transaction, which was approved by the
shareholders of the constituent companies at meetings held on September 13,
1995, is expected to close shortly after all of the conditions to the
consummation of the Merger Transaction, including obtaining applicable regu-
latory approvals, are met or waived. See Note 2 to the Financial Statements
for 1996 developments on regulatory approvals, and the 1995 Form 10-K for
further discussion of the proposed Merger Transaction.
SUMMARIZED PRO FORMA FINANCIAL INFORMATION (UNAUDITED)
The following summary of unaudited pro forma financial information
reflects the adjustment of the historical consolidated balance sheets and
statements of income of NSP and WEC to give effect to the Merger Transaction
to form Primergy and a new subsidiary structure. The unaudited pro forma
balance sheet information gives effect to the Merger Transaction as if it had
occurred on that date. The unaudited pro forma income statement information
gives effect to the Merger Transaction as if it had occurred at the beginning
of the period presented. This pro forma information was prepared from the
historical consolidated financial statements of NSP and WEC on the basis of
accounting for the Merger Transaction as a pooling of interests and should be
read in conjunction with such historical consolidated financial statements and
related notes thereto of NSP and WEC.
The allocation between NSP and WEC and their customers of the estimated
cost savings resulting from the Merger Transaction, net of the costs incurred
to achieve such savings, will be subject to regulatory review and approval.
None of the estimated cost savings, the costs to achieve such savings or the
transaction costs have been reflected in the summarized pro forma income
statement information. A $140 million pro forma adjustment has been made to
conform the presentations of non-current deferred income taxes in the
summarized pro forma combined balance sheet information as a net liability.
The pro forma combined earnings per common share reflect pro forma adjustments
to average common shares outstanding in accordance with the stock conversion
provisions of the Merger Agreement.
The following information is not necessarily indicative of the financial
position or operating results that would have occurred had the Merger
Transaction been consummated on the date, or at the beginning of the periods,
for which the Merger Transaction is being given effect nor is it necessarily
indicative of future operating results or financial position. The summarized
Primergy pro forma financial information reflects the combination of the
historical financial statements of NSP and WEC after giving effect to the
Merger Transaction to form Primergy. The summarized New NSP pro forma
financial information reflects the adjustment of the historical financial
statements of NSP to give effect to the Merger Transaction, including the
reincorporation of NSP in Wisconsin, the merger of the Wisconsin Company into
Wisconsin Energy Company, and the transfer of ownership of all of the current
NSP subsidiaries to Primergy.
Pro Forma
PRIMERGY CORP: NSP WEC Combined
(in millions, except per share amounts)
As of September 30, 1996:
Utility Plant-Net $4,344 $2,971 $7,315
Current Assets 717 466 1,183
Other Assets 1,334 1,169 2,363
Total Assets $6,395 $4,606 $10,861
Common Stockholders' Equity $2,106 $1,917 $4,023
Preferred Stockholders' Equity 240 30 270
Long-Term Debt 1,673 1,331 3,004
Total Capitalization 4,019 3,278 7,297
Current Liabilities 946 441 1,387
Other Liabilities 1,430 887 2,177
Total Equity & Liabilities $6,395 $4,606 $10,861
For the Nine Months Ended
September 30, 1996:
Utility Operating Revenues $1,944 $1,296 $3,240
Utility Operating Income $266 $230 $496
Net Income, after Preferred
Dividend Requirements $186 $162 $348
Earnings per Common Share:
As reported $2.70 $1.46 --
NSP Equivalent Shares -- -- $2.54
Primergy Shares -- -- $1.56
Merger
Divestitures Pro Forma
NEW NSP: NSP Net New NSP
(in millions)
As of September 30, 1996:
Utility Plant-Net $4,344 ($706) $3,638
Current Assets 717 (190) 527
Other Assets 1,334 (615) 719
Total Assets $6,395 ($1,511) $4,884
Common Stockholder's Equity $2,106 ($711) $1,395
Preferred Stockholder's Equity 240 -- 240
Long-Term Debt 1,673 (492) 1,181
Total Capitalization 4,019 (1,203) 2,816
Current Liabilities 946 (121) 825
Other Liabilities 1,430 (187) 1,243
Total Equity & Liabilities $6,395 ($1,511) $4,884
For the Nine Months Ended
September 30, 1996:
Utility Operating Revenues $1,944 ($154) $1,790
Utility Operating Income $266 ($43) $222
Net Income, after Preferred
Dividend Requirements $186 ($35) $151
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 nine months ended September 30,
1996.
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 September 30, 1996, or between September 30, 1996 and the date
of this report:
July 9, 1996 (Filed July 9, 1996) - Item 5. Other Events. Release of
the audited consolidated financial statements of NRG and its
subsidiaries for the year ended 1995 and the related management's
discussion and analysis. Item 7. Financial Statements and Exhibits.
NRG's 1995 audited consolidated financial statements.
July 19, 1996 (Filed July 19, 1996) - Item 5. Other Events. Disclosure
of the Company's intention to submit an offer, at the request of
Southern Minnesota Municipal Power Agency (SMMPA), to purchase SMMPA's
41 percent interest in the Company's Sherburne County Electric
Generating Plant Unit 3.
September 4, 1996 (Filed September 4, 1996) - Item 5. Other Events.
Disclosure of a mutual agreement between the Company and Michigan Upper
Peninsula Power Company regarding the cancellation of an electric power
supply agreement signed in 1993.
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, Controller and
Chief Information Officer
/s/
Edward J. McIntyre
Vice President and Chief Financial Officer
Date: November 14, 1996
EXHIBIT INDEX
Method of Exhibit
Filing No. Description
DT 27.01 Financial Data Schedule
DT 99.01 Statement pursuant to Private
Securities Litigation Reform
Act of 1995
DT = Filed electronically with this direct transmission.