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
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________ to __________
COMMISSION FILE NUMBER: 1-2987
NIAGARA MOHAWK POWER CORPORATION
(Exact name of registrant as specified in its charter)
STATE OF NEW YORK 15-0265555
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
300 ERIE BOULEVARD WEST
SYRACUSE, NEW YORK 13202
(Address of principal executive offices) (Zip Code)
(315) 474-1511
Registrant's telephone number, including area code
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.
COMMON STOCK, $1 PAR VALUE, OUTSTANDING AT OCTOBER 31, 1998 - 187,364,863
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
FORM 10-Q - For the Quarter Ended September 30, 1998
INDEX
PART I. FINANCIAL INFORMATION
--------------------------------
Glossary of Terms
Item 1. Financial Statements
a) Consolidated Statements of Income - Three Months and
Nine Months Ended September 30, 1998 and 1997
b) Consolidated Balance Sheets - September 30, 1998 and
December 31, 1997
c) Consolidated Statements of Cash Flows - Nine Months Ended
September 30, 1998 and 1997
d) Notes to Consolidated Financial Statements
e) Review by Independent Accountants
f) Independent Accountants' Report on the Limited Review of the
Interim Financial Information
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
PART II. OTHER INFORMATION
----------------------------
Item 1. Legal Proceedings
Item 6. Exhibits and Reports on Form 8-K
Signature
Exhibit Index
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
GLOSSARY OF TERMS
TERM DEFINITION
- ---- ----------
CTC Competitive transition charge: a mechanism established in the
POWERCHOICE agreement to recover stranded costs from customers
Dth Dekatherm: one thousand cubic feet of gas with a heat content of
1,000 British Thermal Units per cubic foot
EBITDA Earnings before interest charges, interest income, income taxes,
depreciation and amortization, amortization of nuclear fuel,
allowance for funds used during construction, non-cash regulatory
deferrals and other amortizations, and extraordinary items.
FAC Fuel Adjustment Clause: a clause in a rate schedule that provides
for an adjustment to the customer's bill if the cost of fuel
varies from a specified unit cost
FERC Federal Energy Regulatory Commission
GAAP Generally Accepted Accounting Principles
GWh Gigawatt-hours: one gigawatt equals one billion watt-hours
GRT Gross Receipts Tax
IPP Independent Power Producer: any person that owns or operates, in
whole or part, one or more Independent Power Facilities
IPP Party Independent Power Producers that were a party to the MRA
IRS Internal Revenue Service
KWh Kilowatt-hour: a unit of electrical energy equal to one kilowatt
of power supplied or taken from an electric circuit steadily for
one hour
MRA Master Restructuring Agreement - the agreement, including
amendments thereto, which terminated, restated or amended certain
IPP Party power purchase agreements effective June 30, 1998
MRA Recoverable costs to terminate, restate or amend IPP Party
Regulatory contracts, which has been deferred and is being amortized and
Asset recovered under the POWERCHOICE agreement
MW Megawatt: one million watts
POWERCHOICE Company's five-year electric rate agreement, which incorporates
agreement the MRA, approved by the PSC in an order dated March 20, 1998
PPA Power Purchase Agreement: long-term contracts under which a
utility is obligated to purchase electricity from an IPP at
specified rates
PRP Potentially Responsible Party
PSC New York State Public Service Commission
SFAS Statement of Financial Accounting Standards No. 71
No. 71 "Accounting for the Effects of Certain Types of Regulation"
SFAS Statement of Financial Accounting Standards No. 121
No. 121 "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of"
Unit 1 Nine Mile Point Nuclear Station Unit No. 1
Unit 2 Nine Mile Point Nuclear Station Unit No. 2
PART I - FINANCIAL INFORMATION
- ------------------------------
ITEM 1. FINANCIAL STATEMENTS
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
------------------- ------------------ ----------- ----------
(In thousands of dollars)
OPERATING REVENUES:
Electric. . . . . . . . . . . . . . . . . $ 859,597 $ 827,697 $2,506,048 $2,509,603
Gas . . . . . . . . . . . . . . . . . . . 71,034 68,873 433,893 496,497
------------------- ------------------ ----------- ----------
930,631 896,570 2,939,941 3,006,100
------------------- ------------------ ----------- ----------
OPERATING EXPENSES:
Fuel for electric generation. . . . . . . 80,045 54,674 178,433 127,331
Electricity purchased . . . . . . . . . . 240,068 293,324 866,677 939,125
Gas purchased . . . . . . . . . . . . . . 39,760 41,625 216,372 253,180
Other operation and maintenance expenses. 223,481 198,805 697,787 605,262
POWERCHOICE charge. . . . . . . . . . . . - - 263,227 -
Amortization of MRA regulatory asset. . . 32,184 - 32,184 -
Depreciation and amortization . . . . . . 88,767 85,148 264,540 254,169
Other taxes . . . . . . . . . . . . . . . 116,039 112,820 356,961 354,218
------------------- ------------------ ----------- ----------
820,344 786,396 2,876,181 2,533,285
------------------- ------------------ ----------- ----------
OPERATING INCOME. . . . . . . . . . . . . . . 110,287 110,174 63,760 472,815
Other income. . . . . . . . . . . . . . . . . 45,024 7,484 47,620 20,853
------------------- ------------------ ----------- ----------
INCOME BEFORE INTEREST CHARGES. . . . . . . . 155,311 117,658 111,380 493,668
Interest charges. . . . . . . . . . . . . . . 133,658 68,380 265,109 205,260
------------------- ------------------ ----------- ----------
INCOME (LOSS) BEFORE FEDERAL AND FOREIGN
INCOME TAXES. . . . . . . . . . . . . . . 21,653 49,278 (153,729) 288,408
Federal and foreign income taxes. . . . . . . 4,000 17,595 (50,337) 112,954
------------------- ------------------ ----------- ----------
NET INCOME (LOSS) (NOTE 1). . . . . . . . . . 17,653 31,683 (103,392) 175,454
Dividends on preferred stock. . . . . . . . . 9,137 9,353 27,531 28,161
------------------- ------------------ ----------- ----------
BALANCE AVAILABLE FOR COMMON STOCK. . . . . . $ 8,516 $ 22,330 $ (130,923) $ 147,293
=================== ================== =========== ==========
Average number of shares of common stock
outstanding (in thousands). . . . . . . . 187,365 144,417 159,049 144,399
BASIC AND DILUTED EARNINGS PER AVERAGE
SHARE OF COMMON STOCK . . . . . . . . . . $ 0.05 $ 0.15 $ (0.82) $ 1.02
The accompanying notes are an integral part of these financial statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30,
1998 December 31,
(UNAUDITED) 1997
------------- -------------
(In thousands of dollars)
UTILITY PLANT:
Electric plant. . . . . . . . . . . . . . . . . . . $ 8,765,664 $ 8,752,865
Nuclear fuel. . . . . . . . . . . . . . . . . . . . 598,888 577,409
Gas plant . . . . . . . . . . . . . . . . . . . . . 1,136,313 1,131,541
Common plant. . . . . . . . . . . . . . . . . . . . 322,042 319,409
Construction work in progress . . . . . . . . . . . 522,658 294,650
-------------- -------------
Total utility plant. . . . 11,345,565 11,075,874
Less - Accumulated depreciation and amortization. . 4,475,732 4,207,830
-------------- -------------
Net utility plant. . . . . 6,869,833 6,868,044
-------------- -------------
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . . . . 400,815 371,709
-------------- -------------
CURRENT ASSETS:
Cash, including temporary cash investments
of $219,307 and $315,708, respectively. . . . 266,946 378,232
Accounts receivable (less allowance for doubtful
accounts of $51,100 and $62,500 respectively) 426,269 492,244
Materials and supplies, at average cost:
Coal and oil for production of electricity. . 27,607 27,642
Gas storage . . . . . . . . . . . . . . . . . 41,808 39,447
Other . . . . . . . . . . . . . . . . . . . . 117,866 118,308
Prepaid taxes . . . . . . . . . . . . . . . . . . . 56,055 15,518
Other . . . . . . . . . . . . . . . . . . . . . . . 21,550 20,309
-------------- -------------
958,101 1,091,700
-------------- -------------
REGULATORY ASSETS (NOTE 3):
MRA regulatory asset . . . . . . . . . . . . . . . 4,133,521 7,516
Regulatory tax asset . . . . . . . . . . . . . . . 405,624 399,119
Deferred finance charges . . . . . . . . . . . . . - 239,880
Deferred environmental restoration costs (Note 2). 220,000 220,000
Unamortized debt expense . . . . . . . . . . . . . 51,814 57,312
Postretirement benefits other than pensions. . . . 53,642 56,464
Other. . . . . . . . . . . . . . . . . . . . . . . 118,866 196,533
-------------- -------------
4,983,467 1,176,824
-------------- -------------
OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . . . . 129,114 75,864
-------------- -------------
$ 13,341,330 $ 9,584,141
============== =============
The accompanying notes are an integral part of these financial statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30,
1998 December 31,
(UNAUDITED) 1997
------------ --------------
(In thousands of dollars)
CAPITALIZATION:
COMMON STOCKHOLDERS' EQUITY:
Common stock - $1 par value; authorized 250,000,000 and 185,000,000 shares,
respectively; issued 187,364,863 and 144,419,351, respectively. . . . . $ 187,365 $ 144,419
Capital stock premium and expense. . . . . . . . . . . . . . . . . . . . . . 2,336,917 1,779,688
Retained earnings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 672,497 803,420
-------------- -------------
3,196,779 2,727,527
-------------- -------------
CUMULATIVE PREFERRED STOCK, AUTHORIZED 3,400,000 SHARES, $100 PAR VALUE:
Non-redeemable (optionally redeemable), issued 2,100,000 shares. . . . . . . 210,000 210,000
Redeemable (mandatorily redeemable), issued 204,000 and
222,000 shares, respectively. . . . . . . . . . . . . . . . . . . . . . 18,600 20,400
CUMULATIVE PREFERRED STOCK, AUTHORIZED 19,600,000 SHARES, $25 PAR VALUE:
Non-redeemable (optionally redeemable), issued 9,200,000 shares. . . . . . . 230,000 230,000
Redeemable (mandatorily redeemable), issued 2,248,403 and
2,581,204 shares, respectively. . . . . . . . . . . . . . . . . . . . 50,390 56,210
-------------- -------------
508,990 516,610
-------------- -------------
Long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,414,340 3,417,381
-------------- -------------
TOTAL CAPITALIZATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,120,109 6,661,518
-------------- -------------
CURRENT LIABILITIES:
Long-term debt due within one year . . . . . . . . . . . . . . . . . . . . . . . 306,665 67,095
Sinking fund requirements on redeemable preferred stock. . . . . . . . . . . . . 7,620 10,120
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 163,075 263,095
Payable on outstanding bank checks . . . . . . . . . . . . . . . . . . . . . . . 58,224 23,720
Customers' deposits. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,505 18,372
Accrued taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75,677 9,005
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126,260 62,643
Accrued vacation pay . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38,178 36,532
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79,822 64,756
-------------- -------------
874,026 555,338
-------------- -------------
REGULATORY AND OTHER LIABILITIES (NOTE3):
Deferred finance charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . - 239,880
Accumulated deferred income taxes. . . . . . . . . . . . . . . . . . . . . . . . 1,491,175 1,387,032
Employee pension and other benefits. . . . . . . . . . . . . . . . . . . . . . . 238,095 240,211
Deferred pension settlement gain . . . . . . . . . . . . . . . . . . . . . . . . 3,178 12,438
Unbilled revenues. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,952 43,281
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 381,795 224,443
-------------- -------------
2,127,195 2,147,285
-------------- -------------
COMMITMENTS AND CONTINGENCIES (NOTES 2 AND 3):
Liability for environmental restoration . . . . . . . . . . . . . . . . . . . . 220,000 220,000
-------------- -------------
$ 13,341,330 $ 9,584,141
============== =============
The accompanying notes are an integral part of these financial statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
INCREASE (DECREASE) IN CASH
(UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30,
1998 1997
----------------- ----------
(In thousands of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (103,392) $ 175,454
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
POWERCHOICE charge. . . . . . . . . . . . . . . . . . . . . . 263,227 -
Depreciation and amortization . . . . . . . . . . . . . . . . 264,540 254,169
Amortization of MRA regulatory asset. . . . . . . . . . . . . 32,184 -
Amortization of nuclear fuel. . . . . . . . . . . . . . . . . 22,007 20,598
Provision for deferred income taxes . . . . . . . . . . . . . 97,638 33,050
Net accounts receivable . . . . . . . . . . . . . . . . . . . 35,646 57,569
Materials and supplies. . . . . . . . . . . . . . . . . . . . (2,061) 2,879
Accounts payable and accrued expenses . . . . . . . . . . . . (50,175) (1,709)
Accrued interest and taxes. . . . . . . . . . . . . . . . . . 130,289 34,737
MRA regulatory asset. . . . . . . . . . . . . . . . . . . . . (4,107,118) -
Changes in other assets and liabilities . . . . . . . . . . . 147,377 (29,721)
----------------- ----------
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES. (3,269,838) 547,026
----------------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction additions. . . . . . . . . . . . . . . . . . . . . . . . . (268,645) (183,831)
Nuclear fuel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (21,479) (2,877)
----------------- ----------
Acquisition of utility plant. . . . . . . . . . . . . . . . . . . . . . (290,124) (186,708)
Materials and supplies related to construction. . . . . . . . . . . . . 177 617
Accounts payable and accrued expenses related to construction . . . . . (12,544) (427)
Other investments . . . . . . . . . . . . . . . . . . . . . . . . . . . (29,077) (4,054)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (949) 5,505
----------------- ----------
NET CASH USED IN INVESTING ACTIVITIES. . . . . . . . (332,517) (185,067)
----------------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of senior notes. . . . . . . . . . . . . . . . . . . . . . . . 3,268,528 -
Issuance of common stock. . . . . . . . . . . . . . . . . . . . . . . . 316,389 -
Reductions of preferred stock . . . . . . . . . . . . . . . . . . . . . (10,120) (8,870)
Increase (reduction) in long-term debt. . . . . . . . . . . . . . . . . 17,650 (4,600)
Reductions in mortgage bonds. . . . . . . . . . . . . . . . . . . . . . (60,000) (40,000)
Dividends paid. . . . . . . . . . . . . . . . . . . . . . . . . . . . . (27,531) (28,161)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (13,847) 963
----------------- ----------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES. 3,491,069 (80,668)
----------------- ----------
NET INCREASE (DECREASE) IN CASH . . . . . . . . . . . . . . . . . . . . . . . . (111,286) 281,291
Cash at beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . 378,232 325,398
----------------- ----------
CASH AT END OF PERIOD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 266,946 $ 606,689
================= ==========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 205,496 $ 199,460
Income taxes paid (refunded). . . . . . . . . . . . . . . . . . . . . . $ (7,318) $ 63,116
SUPPLEMENTAL SCHEDULE OF NONCASH FINANCING ACTIVITIES:
Issued 20,546,264 shares of common stock, valued at $14.75
per share to the IPP Parties on June 30, 1998 or $303.1 million
The accompanying notes are an integral part of these financial statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
Niagara Mohawk Power Corporation and subsidiary companies (the "Company"), in
the opinion of management, has included all adjustments (which include normal
recurring adjustments) necessary for a fair statement of the results of
operations for the interim periods presented. The consolidated financial
statements for 1998 are subject to adjustment at the end of the year when they
will be audited by independent accountants. The consolidated financial
statements and notes thereto should be read in conjunction with the financial
statements and notes for the years ended December 31, 1997, 1996 and 1995
included in the Company's 1997 Annual Report on Form 10-K as amended.
The Company's electric sales tend to be substantially higher in summer and
winter months as related to weather patterns in its service territory; gas sales
tend to peak in the winter. Notwithstanding other factors, the Company's
quarterly net income will generally fluctuate accordingly. Therefore, the
earnings for the three-month and nine-month periods ended September 30, 1998,
should not be taken as an indication of earnings for all or any part of the
balance of the year. It is expected that the closing of the MRA, which occurred
on June 30, 1998, and the implementation of POWERCHOICE will result in
substantially depressed earnings during the five-year term of POWERCHOICE, but
that operating cash flows will substantially improve.
Effective January 1, 1998, the Company adopted Statement of Financial Accounting
Standards No. 130 "Reporting Comprehensive Income," which establishes standards
for reporting comprehensive income. Comprehensive income is the change in the
equity of a company, not including those changes that result from shareholder
transactions. While the primary component of comprehensive income is the
Company's reported net income or loss, the other components of comprehensive
income relate to foreign currency translation adjustments and unrealized gains
and losses associated with certain investments held as available for sale.
Total comprehensive income (loss) for the three months and nine months ended
September 30, 1998 and 1997 is as follows:
(in millions)
September 30,. 1998 1997
- -------------- -------------- ------
3 months ended $ 13.3 $ 31.8
9 months ended $ (110.2) $174.8
In June of 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 133 "Accounting for Derivative
Instruments and Hedging Activities." The new standard requires companies to
record derivatives on the balance sheet as assets or liabilities, measured at
fair value. Gains or losses resulting from the changes in the values of the
derivatives would be accounted for depending on the use of the derivative and
whether it qualifies for hedge accounting. The Company will be required to
adopt this standard by fiscal year beginning January 1, 2000. The Company is
currently assessing the impact of this new standard on its financial position
or results of operation.
Certain amounts have been reclassified on the accompanying Consolidated
Financial Statements to conform with the 1998 presentation.
NOTE 2. CONTINGENCIES
ENVIRONMENTAL ISSUES: The public utility industry typically utilizes and/or
generates in its operations a broad range of hazardous and potentially hazardous
wastes and by-products. The Company believes it is handling identified wastes
and by-products in a manner consistent with federal, state and local
requirements and has implemented an environmental audit program to identify any
potential areas of concern and aid in compliance with such requirements. The
Company is also currently conducting a program to investigate and remediate, as
necessary to meet current environmental standards, certain properties associated
with former gas manufacturing and other properties which the Company has learned
may be contaminated with industrial waste, as well as investigating identified
industrial waste sites as to which it may be determined that the Company
contributed. The Company has also been advised that various federal, state or
local agencies believe certain properties require investigation and has
prioritized the sites based on available information in order to enhance the
management of investigation and remediation, if necessary.
The Company is currently aware of 131 sites with which it has been or may be
associated, including 79 which are Company-owned. With respect to non-owned
sites, the Company may be required to contribute some proportionate share of
remedial costs. Although one party can, as a matter of law, be held liable for
all of the remedial costs at a site, regardless of fault, in practice costs are
usually allocated among PRPs.
Investigations at each of the Company-owned sites are designed to (1) determine
if environmental contamination problems exist, (2) if necessary, determine the
appropriate remedial actions and (3) where appropriate, identify other parties
who should bear some or all of the cost of remediation. Legal action against
such other parties will be initiated where appropriate. After site
investigations are completed, the Company expects to determine site-specific
remedial actions and to estimate the attendant costs for restoration. However,
since investigations are ongoing for most sites, the estimated cost of remedial
action is subject to change.
Estimates of the cost of remediation and post-remedial monitoring are based upon
a variety of factors, including identified or potential contaminants; location,
size and use of the site; proximity to sensitive resources; status of regulatory
investigation and knowledge of activities at similarly situated sites.
Additionally, the Company's estimating process includes an initiative where
these factors are developed and reviewed using direct input and support obtained
from the New York State Department of Environmental Conservation ("DEC").
Actual Company expenditures are dependent upon the total cost of investigation
and remediation and the ultimate determination of the Company's share of
responsibility for such costs, as well as the financial viability of other
identified responsible parties since clean-up obligations are joint and several.
The Company has denied any responsibility at certain of these PRP sites and is
contesting liability accordingly.
As a consequence of site characterizations and assessments completed to date and
negotiations with PRPs, the Company has accrued a liability in the amount of
$220 million, which is reflected in the Company's Consolidated Balance Sheets at
September 30, 1998 and December 31, 1997. The potential high end of the range
is presently estimated at approximately $650 million, including approximately
$285 million in the unlikely event the Company is required to assume 100%
responsibility at non-owned sites. The amount accrued at September 30, 1998 and
December 31, 1997 incorporates a method to estimate the liability for 27 of the
Company's largest sites which relies upon a decision analysis approach. This
method includes developing several remediation approaches for each of the 27
sites, using the factors previously described, and then assigning a probability
to each approach. The probability represents the Company's best estimate of the
likelihood of the approach occurring using input received directly from the DEC.
The probable costs for each approach are then calculated to arrive at an
expected value. While this approach calculates a range of outcomes for each
site, the Company has accrued the sum of the expected values for these sites.
The amount accrued for the Company's remaining sites is determined through
feasibility studies or engineering estimates, the Company's estimated share of a
PRP allocation or where no better estimate is available, the low end of a range
of possible outcomes is used. In addition, the Company has recorded a
regulatory asset representing the remediation obligations to be recovered from
ratepayers. POWERCHOICE provides for the continued application of deferral
accounting for cost differences resulting from this effort.
In October 1997, the Company submitted a draft feasibility study to the DEC,
which included the Company's Harbor Point site and five surrounding non-owned
sites. The study indicates a range of viable remedial approaches, however, a
final determination has not been made concerning the remedial approach to be
taken. This range consists of a low end of $22 million and a high end of $230
million, with an expected value calculation of $51 million, which is included
in the amounts accrued at September 30, 1998 and December 31, 1997. The range
represents the total costs to remediate the properties and does not consider
contributions from other PRPs, the amount of which the Company is unable to
estimate. The Company has received comments from the DEC on the draft
feasibility study, which will facilitate completion of the Feasibility Study
phase in the Spring of 1999. At this time, the Company cannot definitively
predict the nature of the DEC proposed remedial action plan or the range of
remediation costs DEC will require. While the Company does not expect to be
responsible for the entire cost to remediate these properties, it is not
possible at this time to determine its share of the cost of remediation. In May
1995, the Company filed a complaint, pursuant to applicable Federal and New York
State law, in the U.S. District Court for the Northern District of New York
against several defendants seeking recovery of past and future costs associated
with the investigation and remediation of the Harbor Point and surrounding
sites. The New York State Attorney General moved to dismiss the Company's
claims against the State of New York, the New York State Department of
Transportation and the Thruway Authority and Canal Corporation under the
Comprehensive Environmental Response, Compensation and Liability Act. The
Company opposed this motion. On April 3, 1998, the Court denied the New York
State Attorney General's motion as it pertains to the Thruway Authority and
Canal Corporation, and granted the motion relative to the State of New York and
the Department of Transportation. The case management order presently calls for
the close of discovery on December 31, 1998. As a result, the Company cannot
predict the outcome of the pending litigation against the defendants or the
allocation of the Company's share of the costs to remediate the Harbor Point and
surrounding sites.
Where appropriate, the Company has provided notices of insurance claims to
carriers with respect to the investigation and remediation costs for
manufactured gas plant, industrial waste sites and sites for which the Company
has been identified as a PRP. To date, the Company has reached settlements with
a number of insurance carriers, resulting in payments to the Company of
approximately $38 million, net of costs incurred in pursuing recoveries.
Approximately $33 million of these insurance proceeds related to the electric
business will be amortized over 10 years in accordance with POWERCHOICE.
Approximately $5 million relates to the gas business, a portion of which will be
amortized in the current three-year gas rate case, and the remainder will be
subject to future disposition. Settlements received during the POWERCHOICE and
gas settlement periods will be deferred, net of costs, and used to offset future
costs of environmental remediation.
TAX ASSESSMENTS: The Internal Revenue Service ("IRS") has conducted an
examination of the Company's federal income tax returns for the years 1989 and
1990 and issued a Revenue Agents' Report (RAR). The IRS has raised an issue
concerning the deductibility of payments made to IPPs in accordance with certain
contracts that include a provision for a tracking account. A tracking account
represents amounts that these mandated contracts required the Company to pay
IPPs in excess of the Company's avoided costs, including a carrying charge. The
IRS proposes to disallow a current deduction for amounts paid in excess of the
avoided costs of the Company. Although the Company believes that any such
disallowances for the years 1989 and 1990 will not have a material impact on its
financial position or results of operations, it believes that a disallowance for
these above-market payments for the years subsequent to 1990 could have a
material adverse affect on its cash flows. To the extent that contracts
involving tracking accounts were terminated or restated or amended under the MRA
with IPP Parties as described in Note 3, the effects of any proposed
disallowance has been eliminated with respect to the IPP Parties covered under
the MRA for periods subsequent to June 30, 1998. The Company is vigorously
defending its position on this issue. The IRS also conducted an examination of
the Company's federal income tax returns for the years 1991 through 1993 and
recently issued a RAR. Based upon the Company's review of the report (which did
not raise the IPP tracking account issue, although the issue could still be
raised), the Company does not believe that the findings will have a material
impact on its financial position or results of operation.
NOTE 3. RATE AND REGULATORY ISSUES AND CONTINGENCIES
The Company's financial statements conform to GAAP, including the accounting
principles for rate-regulated entities with respect to its regulated operations.
As discussed below, the Company discontinued application of regulatory
accounting principles to the Company's fossil and hydro generation business.
Substantively, SFAS No. 71 permits a public utility, regulated on a
cost-of-service basis, to defer certain costs which would otherwise be charged
to expense, when authorized to do so by the regulator. These deferred costs are
known as regulatory assets, which in the case of the Company are approximately
$4,983 million at September 30, 1998. The increase in the Company's regulatory
assets is attributed to the MRA Regulatory Asset of $4,134 million. These
regulatory assets are probable of recovery. The portion of the $4,983 million
which has been allocated to the nuclear generation and electric transmission and
distribution business is approximately $4,883 million. Regulatory assets
allocated to the rate-regulated gas distribution business are $100 million.
Generally, regulatory assets and liabilities were allocated to the portion of
the business that incurred the underlying transaction that resulted in the
recognition of the regulatory asset or liability. The allocation methods used
between electric and gas are consistent with those used in prior regulatory
proceedings.
Under POWERCHOICE, the Company's remaining electric business (nuclear generation
and electric transmission and distribution business) will continue to be
rate-regulated on a cost-of-service basis and, accordingly, the Company
continues to apply SFAS No. 71 to these businesses. Also, the Company's IPP
contracts, including those restructured under the MRA, will continue to be the
obligations of the regulated business. Under POWERCHOICE, the Company is
required to net certain regulatory assets and liabilities and has reflected
these changes in its September 30, 1998 balance sheet.
The Emerging Issues Task Force (EITF) of the FASB reached a consensus on Issue
No. 97-4 "Deregulation of the Pricing of Electricity - Issues Related to the
Application of SFAS No. 71 and SFAS No. 101" in July 1997. EITF 97-4 does not
require the Company to earn a return on regulatory assets that arise from a
deregulating transition plan in assessing the applicability of SFAS No. 71. The
Company believes that the regulated cash flows to be derived from prices it will
charge for electric service over the next 10 years, including the Competitive
Transition Charge ("CTC") assuming no unforeseen reduction in demand or bypass
of the CTC or exit fees, will be sufficient to recover the MRA Regulatory Asset
and to provide recovery of and a return on the remainder of its assets, as
appropriate. In the event the Company determines, either as a result of lower
than expected revenues or higher than expected costs, that its net regulatory
assets are not probable of recovery, it can no longer apply the principals of
SFAS No. 71 and would be required to record an after-tax non-cash charge against
income for any remaining unamortized regulatory assets and liabilities. If the
Company could no longer apply SFAS No. 71, the resulting charge would be
material to the Company's reported financial condition and results of operations
and adversely effect the Company's ability to pay dividends. It is expected
that the POWERCHOICE agreement, while having the effect of substantially
depressing earnings during its five-year term, will substantially improve
operating cash flows.
With the implementation of POWERCHOICE, specifically the separation of
non-nuclear generation as an entity that would no longer be regulated on a
cost-of-service basis, the Company is required to assess the carrying amounts of
its long-lived assets in accordance with SFAS No. 121. SFAS No. 121 requires
long-lived assets and certain identifiable intangibles held and used by an
entity to be reviewed for impairment whenever events or changes in circumstances
indicate that the carrying amount of an asset may not be recoverable or when
assets are to be disposed of. In performing the review for recoverability, the
Company is required to estimate future undiscounted cash flows expected to
result from the use of the asset and/or its disposition. The Company has
determined that there is no impairment of such assets. The Company plans to
divest its fossil and hydro generating assets. The POWERCHOICE agreement
provides for deferral and future recovery of losses, if any, resulting from the
sale of the non-nuclear generating assets. The Company believes that it will be
permitted to record a regulatory asset for any such loss in accordance with EITF
97-4. The Company's fossil and hydro generation plant assets had a net book
value of approximately $1.1 billion at September 30, 1998. (See Item 2.
Management's Discussion and Analysis of Financial Condition and Results of
Operations - "POWERCHOICE Agreement").
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
REVIEW BY INDEPENDENT ACCOUNTANTS
The Company's independent accountants, PricewaterhouseCoopers LLP, have made
limited reviews (based on procedures adopted by the American Institute of
Certified Public Accountants) of the unaudited Consolidated Balance Sheet of
Niagara Mohawk Power Corporation and Subsidiary Companies as of September 30,
1998 and the unaudited Consolidated Statements of Income for the three-month and
nine-month periods ended September 30, 1998 and 1997 and the unaudited
Consolidated Statements of Cash Flows for the nine-months ended September 30,
1998 and 1997. The accountants' report regarding their limited reviews of the
Form 10-Q of Niagara Mohawk Power Corporation and its subsidiaries appears on
the next page. That report does not express an opinion on the interim unaudited
consolidated financial information. PricewaterhouseCoopers LLP has not carried
out any significant or additional audit tests beyond those which would have been
necessary if their report had not been included. Accordingly, such report is
not a "report" or "part of the Registration Statement" within the meaning of
Sections 7 and 11 of the Securities Act of 1933 and the liability provisions of
Section 11 of such Act do not apply.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors of
Niagara Mohawk Power Corporation
300 Erie Boulevard West
Syracuse, NY 13202
We have reviewed the condensed consolidated balance sheet of Niagara Mohawk
Power Corporation and its subsidiaries as of September 30, 1998 and the related
condensed consolidated statements of income for the three-month and nine-month
periods ended September 30, 1998 and 1997 and of cash flows for the nine months
ended September 30, 1998 and 1997. These financial statements are the
responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in
accordance with generally accepted auditing standards, the objective of which is
the expression of an opinion regarding the financial statements taken as a
whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the condensed consolidated financial statements referred to above for
them to be in conformity with generally accepted accounting principles.
We previously audited in accordance with generally accepted auditing standards,
the consolidated balance sheet as of December 31, 1997, and the related
consolidated statements of income, of retained earnings and of cash flows for
the year then ended (not presented herein), and in our report dated March 26,
1998, except Note 2 (third paragraph) and Note 15, as to which the date is May
29, 1998, we expressed an unqualified opinion. In our opinion, the information
set forth in the accompanying condensed consolidated balance sheet as of
December 31, 1997, is fairly stated, in all material respects, in relation to
the consolidated balance sheet from which it has been derived.
/s/PRICEWATERHOUSECOOPERS LLP
- -----------------------------
PRICEWATERHOUSECOOPERS LLP
SYRACUSE NY
November 13, 1998
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Certain statements included in this Quarterly Report on Form 10-Q are
forward-looking statements as defined in Section 21E of the Securities Exchange
Act of 1934 that involve risk and uncertainty, including the improvement in the
Company's cash flow upon the implementation of the MRA and POWERCHOICE, the
timing and outcome of the future sale of the Company's fossil and hydro
generation assets, and the costs and potential recoveries associated with the
January 1998 ice storm and September 1998 windstorm. In addition, certain
statements made related to the Company's year 2000 program are also
forward-looking (see "Year 2000 Computer Issue"). These forward-looking
statements are based upon a number of assumptions, including assumptions
regarding the POWERCHOICE agreement and regulatory actions to continue to
support such an agreement, internal assessment of damage related to the 1998
storms and related government and insurance companys' actions with respect to
providing recovery for such damage. Actual future results and developments may
differ materially depending on a number of factors, including regulatory changes
either by the federal government or the PSC, uncertainties regarding the
ultimate impact on the Company as the electric industry is further deregulated
and electricity suppliers gain open access to the Company's retail customers,
challenges to the POWERCHOICE agreement (including the fossil/hydro sale) under
New York laws, the effects of weather, the length and frequency of outages at
the Company's two nuclear plants, and the economic conditions of the Company's
service territory.
POWERCHOICE AGREEMENT
The Company's POWERCHOICE Agreement was approved by the PSC in a written order
issued March 20, 1998. The Company consummated its MRA Agreement with certain
IPP Parties on June 30, 1998 and implemented the rate reductions under
POWERCHOICE effective September 1, 1998 upon PSC approval of the rate tariff
schedules.
(See Form 10-K as amended for fiscal year ended December 31, 1997, Part II, Item
7. Management's Discussion and Analysis of Financial Condition and Results of
Operations - "Master Restructuring Agreement and the POWERCHOICE Agreement" and
Form 10-Q as amended for quarter ended March 31, 1998 and Form 10-Q for quarter
ended June 30, 1998, Part I, Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operation - "Master Restructuring Agreement
and the POWERCHOICE Agreement").
The POWERCHOICE agreement establishes a five-year rate plan that will reduce
class average residential and commercial prices by an aggregate of 3.2% over the
first three years. The reduction in prices includes certain savings that will
result from approved reductions of the GRT. Industrial customers will see
average reductions of 25% relative to 1995 tariffs; these decreases will include
discounts currently offered to some industrial customers through optional and
flexible rate programs. The rate reductions, exclusive of GRT savings and
discounts already awarded by contract, are to be phased in over the first three
years of the agreement, and are estimated to aggregate to approximately $111.8
million.
In early October 1998, the Alliance for Municipal Power, a group of 21 towns and
villages in St. Lawrence and Franklin Counties pursuing municipalization, and
Alfred P. Coppola, a Councilman from the City of Buffalo, commenced an Article
78 Proceeding in Albany County Supreme Court challenging the PSC's decisions
approving POWERCHOICE and denying the petitions of Alliance for Municipal Power
and Coppola for rehearing before the Commission. The Article 78 Petition seeks
to vacate the decision of the PSC approving POWERCHOICE provisions relating to
the determination and recovery of strandable costs through the application of a
competitive transition charge and exit fees. The Company is unable to predict
the outcome of this matter at this time. Suspension of POWERCHOICE or
renegotiation of its material terms could have a material adverse effect on the
Company's results of operations, financial condition, and future cash flows.
Between the MRA closing date and the POWERCHOICE implementation date, the
Company experienced a reduction in power purchase costs of $79.0 million as well
as increased financing costs of $40.4 million as a result of the MRA and the MRA
financing. The net effect of these items was deferred for future disposition
because the time lag between these events was not contemplated in the
POWERCHOICE Agreement. Amortization of the MRA Regulatory Asset began September
1, 1998 coincident with the implementation of the new rates which included
recovery of such costs.
In its written order dated May 6, 1998, the PSC approved the Company's plan to
divest its fossil and hydroelectric generating plants, which is a key component
in the Company's POWERCHOICE agreement to lower average electricity prices and
provide customer choice. During the second quarter of 1998, the Company
received non-binding preliminary bids from 37 bidders. Final bids were
originally due during September 1998. However, at the end of September, the
Company extended the auction by approximately two months in order to maximize
value for customers and shareholders. The Company expects to announce the
auction results by the end of 1998, and it's anticipated that transaction
closings will occur in mid-1999 after receipt of the necessary regulatory
approvals. The Company is unable to predict the outcome or timing of the
divestiture of the fossil and hydroelectric assets.
YEAR 2000 COMPUTER ISSUE
As the year 2000 approaches, the Company, along with other companies, could
experience potentially serious operational problems, since many computer
programs that were developed in the past may not properly recognize calendar
dates beginning with year 2000. Further, there are embedded chips contained
within generation, transmission, distribution, gas, and other equipment that
may be date sensitive. In circumstances where an embedded chip fails to
recognize the correct date, electric, gas and business operations could be
adversely affected.
PLAN: A Company-wide year 2000 project management office has been formed and
year 2000 project managers have been appointed within each business group. A
year 2000 program vice-president and an executive level steering committee have
been put in place to oversee all aspects of the program. In addition to Company
personnel, the Company has retained the services of leading computer service and
consulting firms specializing in computer systems and embedded components, which
are involved in various phases of the project. Also, the Company is working
closely with industry groups such as the Electric Power Research Institute
(EPRI), North American Electric Reliability Council (NERC), and other utilities.
In addition the Nuclear Regulatory Commission is requiring the Company to
certify by July 1, 1999 that the Company's two nuclear plants will be year 2000
ready. A plan was developed that established phases of the work to be done. The
phases are:
- - an inventory of all systems and equipment, (including a physical walkdown
of all of the Company's substations)
- - an assessment of all systems and equipment and definition of next steps,
- - remediation,
- - testing and validation,
- - acceptance and deployment,
- - independent validation, and
- - contingency planning.
As part of the inventory phase, all the systems and equipment have been
prioritized into four categories based upon their functional need and
importance. The priorities are:
- - Priority 1 - Any failure or regulatory breach that can cause an
interruption to the generation or delivery of electric or gas energy to
customers, or can jeopardize the safety of any employee, customer, or the
general public (e.g. the Energy Management System that controls the flow
of electricity and communicates information between the control center
and sub-stations).
- - Priority 2 - Any failure that can cause an interruption to customer
service or breach of significant contractual or financial commitment
(e.g. Meter reading equipment).
- - Priority 3 - Any failure that can inconvenience a business partner or
significantly impact a Company business group productivity (e.g.
electronic payments to vendors).
- - Priority 4 - Any failure that can adversely impact a Company work group or
personal productivity, or other business processes (e.g. applications
used on a desk top computer used to accomplish day-to-day productivity
activities).
Although the Company has identified seven different phases of the project, in
some cases the phases are done concurrently. For example, individual computers
may be completely tested and redeployed while others are still being remediated.
Information obtained within the phases is reviewed by a panel consisting of
employees and consultants. Additional testing may be performed based on the
importance of the component and a recommendation of the panel. Complete
integration and interface testing will be performed on components and systems
whenever possible.
The Company's primary focus is on priorities 1 and 2 because of the direct
impact on customers. Although the Company's plan addresses completion of all
priority items prior to January 1, 2000, some priorities 3 and 4 may not be
addressed completely until after January 1, 2000, and will be remediated as
needed or as problems occur.
The Company's progress with its year 2000 issues for priority items 1 and 2 are
as follows:
PHASE STATUS ESTIMATED COMPLETION DATE
- ---------------------- --------------- --------------------------
- - Inventory Complete September 1998
- - Assessment In-progress June 1998 - November 1998
- - Remediation In-progress December 1998 - April 1999
- - Testing In-progress March 1999 - May 1999
- - Acceptance In-progress March 1999 - June 1999
- - Validation In-progress May 1999
- - Contingency Planning In-progress December 1998 - June 1999
Note: Each business group within the Company has its own schedule. The
estimated completion dates above may show a range due to different schedules
within each business group.
RISKS: The failure to correct for year 2000 problems, either by the Company or
third parties, could result in significant disruptions of the Company's
operations. At this point in time based on the Company's progress to date and
the information received from third parties, the Company is unable to determine
its most reasonably likely worst case scenario.
Like any organization, the Company is dependent upon many third parties,
including suppliers of energy and materials (e.g. independent power producers),
service providers, transporters, and the government. These third parties provide
services vital to the Company and year 2000 problems at these companies could
adversely affect electric and gas operations. One such example is that the
Company expects that by the year 2000, it will be purchasing the majority of its
electric generation needs. If any of these suppliers has a year 2000 failure,
it could interrupt energy supply to the Company's customers. Another example of
such a vital third party is telephone companies. If the telephone companies
have year 2000 failures, this could in turn affect the Company's customer
response capabilities and the Company's ability to operate and maintain the
transmission and distribution system that carries electricity to businesses and
customer homes. To address these third party issues, the Company has requested
certificates of compliance from third parties. To date, the Company has
received some responses, but disclosure has been limited, and the Company cannot
verify accuracy. The inability of suppliers to complete their year 2000
readiness process could materially impact the Company.
The Company is connected to an electric grid that links utilities throughout the
United States and Canada. This interconnection is essential to the reliability
and operational integrity of the connected utilities. If one of the electric
utilities in the grid has a failure, it could cause power fluctuations and
possible interruption of others in the grid. As a result, even if the Company
did an effective job of becoming compliant, it could still have customer
interruptions. The Company is working closely with NERC, other utilities, EPRI,
and other industry groups to address the issue of grid reliability.
The Company's gas distribution system also has the potential to be adversely
impacted by year 2000 noncompliance either by third parties or if the Company's
program fails to identify and remediate all problem areas. From the third party
natural gas production and transmission facilities, to the Company's
distribution pipeline system, and ultimately, to the customer, there are
computer systems and equipment with date sensitive processing. If, despite the
Company's and third party's best efforts, a year 2000 failure occurs, the flow
of gas to the customer could be jeopardized.
As an example, the Company is connected directly to three major transmission
pipelines, and has an indirect connection with a fourth. If these pipelines are
unable to provide full gas delivery to the Company, the Company would implement
standing emergency procedures that could interrupt customers. To avoid such an
event, the Company is working with the pipelines, and state agencies to reduce
the probability of any customer interruptions due to year 2000 problems.
CONTINGENCY PLANS: The Company's year 2000 schedules also include the
development and implementation of contingency plans in the event of year 2000
failures, both within the Company and by third parties. The Company expects to
have these plans completed during 1999 for all priority categories. The
contingency plans will vary by business group and by the various priority levels
for different systems and equipment.
COSTS: The Company estimates that total program costs will approximate $40
million of which approximately $30 million will be expensed and $10 million will
be capitalized. Total program costs incurred through September 30, 1998 are
$4.8 million of which $3.7 million was expensed and $1.1 million was
capitalized. The Company expects to fund the total program costs through
operating cash flows.
Over the last several years as the Company implemented various large computer
projects, the Company was conscious of year 2000 exposures and therefore made
sure the projects were year 2000 compliant. However, these computer projects
were implemented for business reasons rather than to solely comply with year
2000 issues. These projects included replacing the customer
service/billing/revenue system, as well as implementing a project accounting
system, a computer aided dispatch system, and desktop computers for employees,
among others. Through September 30, 1998, the Company has spent approximately
$60 million on these projects in addition to specific year 2000 compliance
spending. In addition, the Company has not deferred any significant computer
projects as a result of the year 2000 project.
Certain statements included in this discussion regarding year 2000 compliance
are forward-looking statements as defined in Section 21E of the Securities
Exchange Act of 1934. These statements include management's best estimates for
completion dates for the various phases and priorities, testing to be performed,
costs to be spent for compliance, and the risks associated with non-compliance
either by the Company or third parties. These forward-looking statements are
subject to various factors which may materially affect the Company's efforts
with year 2000 compliance. Specific factors that might cause such material
differences include, but are not limited to, the availability and cost of
personnel trained in this area, which could cause a change in the estimated
completion date of a particular phase, the ability to locate and correct all
relevant software and embedded components, the compliance of critical vendors,
as well as neighboring utilities, and similar uncertainties. The Company's
assessments of the effects of year 2000 on the Company are based, in part, upon
information received from third parties and other utilities, and the Company's
reasonable reliance on that information. Therefore, the risk that inaccurate
information is supplied by third parties and other utilities upon which the
Company reasonably relied must be considered as a risk factor that might affect
the Company's year 2000 efforts. The Company is attempting to reduce the risks
by utilizing an organized approach, extensive testing, and allowance of ample
contingency time to address issues identified by tests.
1998 STORMS
In early January 1998, a major ice storm and flooding caused extensive damage in
a large area of northern New York. The Company's electric transmission and
distribution facilities in an area of approximately 7,000 square miles were
damaged, interrupting service to approximately 120,000 of the Company's
customers, or approximately 300,000 people. The Company had to rebuild much of
its transmission and distribution system to restore power in this area. By the
end of January 1998, service to all customers was restored.
The total estimated cost of the restoration and rebuild efforts is approximately
$141million. As of September 30, 1998, the Company expensed $75.3 million
associated with the January 1998 ice storm (of which $66.4 million was
considered incremental) and capitalized $65.7 million of costs as utility plant.
The Company continues to pursue federal disaster relief assistance and state
financial aid. During the third quarter of 1998, the Company submitted claims
to its insurance carriers for hydro electric stations and sub-stations damages,
and is continuing to assess electric transmission and distribution damages. The
Company is unable to determine what recoveries it may receive from these
sources.
On September 7, 1998 a severe windstorm passed through a portion of the
Company's service territory interrupting electric service to more than 250,000
customers from Niagara Falls to Albany. Power was restored to the majority of
the customers within one week. The total preliminary estimated cost of
restoration from the September storm is approximately $20 million. However,
final costs of the storm will not be known until all costs and charges are
analyzed and charges from other utilities and contractors have been received.
As of September 30, 1998, the Company recorded $17 million in expense (of which
$13.8 million was considered incremental). The remaining $3 million has been
capitalized. The Company is continuing to inspect and survey the work completed.
NUCLEAR MATTERS
(See Form 10-K as amended for fiscal year ended December 31, 1997, Part II, Item
7. Management's Discussion and Analysis of Financial Condition and Results of
Operations - "NRC and Nuclear Operating Matters.")
UNIT 1 OUTAGE - Some owners of older General Electric Company boiling water
reactors, including the Company, have experienced cracking in horizontal welds
in the plants' core shrouds. In response to industry findings, the Company
installed pre-emptive modifications to the Unit 1 core shroud during a 1995
refueling and maintenance outage. The core shroud, a stainless steel cylinder
inside the reactor vessel, surrounds the fuel and directs the flow of reactor
water through the fuel assemblies.
Inspections conducted as part of the March 1997 refueling and maintenance
outage detected cracking in vertical welds not reinforced by the 1995 repairs.
On April 8, 1997, the Company filed a comprehensive inspection and analysis
report with the NRC that concluded that the condition of the Unit 1 core shroud
supports the safe operation of the plant. On May 8, 1997, the NRC approved the
Company's request to operate for a specific number of hours at which time Unit
1 would enter a mid-cycle outage, anticipated to occur in late 1998.
Subsequently, the Company determined it had a basis to operate Unit 1 without a
mid-cycle outage and sought the necessary approval from the NRC to postpone the
core shroud inspections until the unit's scheduled refueling and maintenance
outage in spring 1999. A public meeting was held with the NRC on September 24,
1998 during which the Company petitioned the NRC to allow the postponement. On
November 2, 1998, the NRC approved the Company's request to postpone the
inspection until April 1999.
FERC MATTERS
(See Form 10-K as amended for fiscal year ended December 31, 1997, Part II, Item
7. Management's Discussion and Analysis of Financial Condition and Results of
Operation - "FERC Rulemaking on Open Access and Stranded Cost Recovery")
In June 1998, the Village of Lakewood filed a petition with FERC seeking a
determination that it would not be responsible for any of the Company's stranded
costs if it created a new municipal electric system. The Company responded in
opposition to this petition. On September 29, 1998 FERC ordered an
Administrative Law Judge to investigate whether the Company is justified in
recovering stranded costs from the approximately 1,900 customers in the Village
of Lakewood. The Company is scheduled to submit its direct case in this matter
on February 12, 1999, and after a variety of submissions from the various
parties, the evidentiary hearing is scheduled to commence on September 27, 1999.
The Company is unable to predict the outcome of this matter.
FINANCIAL POSITION
The Company's capital structure at September 30, 1998 was 64.4% long-term debt,
5.0% preferred stock and 30.6% common equity, as compared to 51.8%, 7.7% and
40.5%, at December 31, 1997. The culmination of the MRA has significantly
increased the leverage of the Company. Through the anticipated increased
operating cash flow resulting from the MRA and POWERCHOICE agreement, the
planned rapid repayment of debt should deleverage the Company over time. Book
value of the common stock was $17.06 per share at September 30, 1998, as
compared to $18.89 at December 31, 1997. With the issuance of common stock at
below book value as a result of the MRA, book value per share and earnings per
share have been diluted.
The Company's EBITDA for the 12 months ended September 30, 1998, was $885.2
million. After the changes from POWERCHOICE and the MRA are fully reflected in a
consecutive 12 month period, EBITDA is expected to increase to approximately
$1.2 billion to $1.3 billion per year. EBITDA represents earnings before
interest charges, interest income, income taxes, depreciation and amortization,
amortization of nuclear fuel, allowance for funds used during construction,
non-cash regulatory deferrals and other amortizations, and extraordinary items.
EBITDA is a non-GAAP measure of cash flows and is presented to provide
additional information about the Company's ability to meet its future
requirements for debt service. EBITDA should not be considered an alternative
to net income as an indicator of operating performance or as an alternative to
cash flows, as presented on the Consolidated Statement of Cash Flows, as a
measure of liquidity.
LIQUIDITY AND CAPITAL RESOURCES
(See Form 10-K as amended for fiscal year ended December 31, 1997, Part II,
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operation - "Financial Position, Liquidity and Capital Resources.")
Under the MRA, the Company paid an aggregate of $3.934 billion in cash, of which
$3.212 billion was obtained through a public market offering of senior unsecured
debt, $303.7 million from the public sale of 22.4 million shares of common
stock, and the remainder from cash on hand. In addition, the Company issued
20.5 million shares of common stock to the IPP Parties. As of September 30,
1998, the Company has $275 million of borrowing capability under the senior bank
facility that expires on June 1, 2000. Also, the Company has the ability to
issue first mortgage bonds to the extent that there have been redemptions since
June 30, 1998. The Company redeemed $60 million first mortgage bonds in August
1998. In addition, the Company is obligated to use 85 percent of the proceeds
of the sale of the fossil and hydro generation assets to reduce debt
outstanding.
The Company has requested a ruling from the IRS to the effect that the amount of
cash and the value of common stock that was paid to the terminated IPP Parties
will be currently deductible and generate a substantial net operating loss
("NOL") for federal income tax purposes, such that the Company will not have to
pay taxes in 1998. Further, the Company will carryback unused NOL to the prior
two years which is to result in a refund of $122 million. In addition, the
Company anticipates that it will be able to deduct the remaining $3 billion paid
to the IPP Parties prior to the NOL expiration date in 2019. No assurance can
be given that a favorable ruling will be issued. If a favorable ruling is not
received, and the Company's claimed current deductions are challenged on audit
and not ultimately sustained, the amount of tax refunds generated from the NOL
carryback, and thus the amount of cash available to repay the recently issued
senior unsecured debt would be reduced. While any disallowed current tax
deductions would ultimately be allowable in future years, and would likely
create, or increase the amount of NOLs available to offset tax liabilities in
future years, cash flow would be adversely affected in the near term.
The Company's ability to utilize the NOL generated as a result of the MRA could
be limited under the rules of section 382 of the Internal Revenue Code if
certain changes in the Company's common stock ownership were to occur in the
future. In general, the limitation is triggered by a more than 50% change in
stock ownership during a three-year testing period by shareholders who own,
directly or indirectly, 5% or more of the common stock. For purposes of making
the change in ownership computation, the IPP Parties which were issued common
stock pursuant to the MRA are likely to be considered a separate 5% shareholder
group, as will the purchasers of common stock in the public offering completed
immediately prior to the consummation of the MRA. Under the computational rules
prescribed by the applicable Treasury regulations, the aggregate increase in
stock ownership experienced by these shareholder groups as a result of their
participation in the public offering and the MRA was likely no greater than 17%.
Thus, if the IPP Parties, the purchasers in the public offering, and any other
5% shareholders collectively experience ownership increases totaling more than
33% during any three year testing period that includes the consummation dates of
the public offering and the MRA, the statutory threshold could be breached and
the NOL limitation would in that event apply. The rules for determining change
in stock ownership for purposes of Code section 382 are extremely complicated
and in many respects uncertain. A stock ownership change could occur as a
result of circumstances that are not within the control of the Company. If a
more than 50% change in ownership were to occur, the Company's remaining usable
NOL likely would be significantly lower in the future than the NOL amount which
otherwise would be usable absent the limitation. Consequently, the Company's
net cash position could be significantly lower as a result of tax liabilities,
which otherwise would be eliminated or reduced through unrestricted use of the
NOL.
During the third quarter of 1998, the Company received approval to refinance
its 8-7/8% series of tax exempt bonds issued through the New York State Energy
Research and Development Authority. The $75 million bonds are anticipated to
be refinanced in November 1998.
NET CASH USED IN OPERATING ACTIVITIES increased $3,816.9 million in the nine
months ended September 30, 1998 primarily due to the consummation of the MRA.
NET CASH USED IN INVESTING ACTIVITIES increased $ 147.5 million in the nine
months ended September 30, 1998 primarily as a result of an increase in the
acquisition of utility plant of $103.4 million, mainly due to the January
1998 ice storm and September 1998 wind storm.
NET CASH PROVIDED BY FINANCING ACTIVITIES increased $3,571.7 million in the
nine months ended September 30, 1998 primarily due to the issuance of the
senior notes and public sale of common stock used to consummate the MRA.
RESULTS OF OPERATIONS
The following discussion presents the material changes in results of operations
for the three months and nine months ended September 30, 1998 in comparison to
the same periods in 1997. The Company's results of operations reflect the
seasonal nature of its business, with peak electric loads in summer and winter
periods. Gas sales peak principally in the winter. The earnings for the three
months and nine months periods should not be taken as an indication of earnings
for all or any part of the balance of the year. Furthermore, future results of
operations will be different from the past in view of the recent termination,
restatement or amendment of IPP contracts and the implementation of POWERCHOICE.
It should also be read in conjunction with other financial and statistical
information appearing elsewhere in this report.
Three Months Ended September 30, 1998 versus Three Months Ended September 30,
- -----------------------------------------------------------------------------
1997
- ----
Earnings for the third quarter of 1998 were $8.5 million or 5 cents per share,
as compared with earnings of $22.3 million or 15 cents per share for the third
quarter of 1997. Third quarter 1998 earnings were primarily impacted by two
events: the implementation of the MRA and related accounting pursuant to
POWERCHOICE, and the incremental costs of a significant September windstorm.
With the closing of the MRA and related financing on June 30, 1998, the Company
experienced lower IPP payments and higher interest costs in the third quarter.
However, because the POWERCHOICE implementation date did not occur until
September 1, 1998, the Company deferred $79 million of net savings from reduced
IPP Party payments and $40.4 million of increased interest costs from the MRA
financing with respect to July and August business. Beginning September 1,
1998, the Company ceased deferring the net IPP savings from the MRA and
increased interest costs related to the MRA financing and also began
amortization of the MRA Regulatory Asset. In addition, earnings per share for
the third quarter ended September 30, 1998 were diluted by the issuance of 42.9
million shares of common stock in connection with the MRA.
ELECTRIC REVENUES increased $31.9 million or 3.9% from the third quarter of 1997
primarily as a result of an increase in volume and mix of sales of $19.4 million
and a $10.4 million increase in electric fuel adjustment clause revenues.
These increases were partially offset by a $2.1 million decrease due to lower
rates under POWERCHOICE, which became effective September 1, 1998.
ELECTRIC SALES to ultimate consumers were approximately 8.5 billion KWh in the
third quarter of 1998, a 0.3% increase from the comparable period in 1997, due
primarily to increased sales to residential and commercial customers of 3.4% and
5.6%, respectively. After adjusting for the effects of weather and the farm and
food processor retail access pilot program (which pilot program has the effect
of reducing sales to ultimate consumers and increasing wholesale sales), sales
to ultimate consumers would have been expected to decrease 0.6%. Sales for
resale decreased 269 million KWh (28.9%) primarily reflecting lower sales to
other utilities. In addition, sales to industrial customers decreased 181
million KWh (9.5%). As a result, total electric sales decreased 247 million KWh
(2.6%).
ELECTRIC FUEL AND PURCHASED POWER COSTS decreased $27.9 million or 8.0% in the
third quarter of 1998, primarily as a result of decreased payments to IPPs of
$147.1 million. Of this amount, $79 million relates to net reductions in
payments to IPP Parties in July and August and was deferred for future rate
making disposition. The decrease in the IPP payments is primarily the result of
the MRA Agreement which allowed the Company to terminate 18 PPAs for 1100 MW of
capacity and restate 9 PPAs for 583 MW of capacity. As a result, the Company's
load requirements were met using Company internal generation and other non-IPP
generation sources. These costs increased $23.1 million and $1.6 million,
respectively.
GAS REVENUES increased $2.2 million or 3.1% in the third quarter of 1998 from
the comparable period in 1997, primarily as a result of increased natural gas
sales for resale of $4.3 million, which was partially offset by a $2.1 million
decrease in sales to ultimate consumers.
GAS SALES to ultimate consumers decreased 0.4 million Dth or 7.4% from the third
quarter of 1997 reflecting decreases in all customer classes. After adjusting
for the effects of weather, sales to ultimate consumers decreased 5.4%.
However, spot market sales (sales for resale), which are generally from the
higher priced gas available to the Company and therefore yield margins that are
substantially lower than traditional sales to ultimate consumers, increased.
The total COST OF GAS included in expense decreased 4.5% in the third quarter of
1998. This was the result of a 0.4 million decrease in Dth purchased for
ultimate consumer sales ($3.2 million), a 2.4% decrease in the average cost of
Dth purchased ($1.0 million) and a $2.1 million decrease in purchased gas costs
and certain other items recognized and recovered through the purchased gas
adjustment clause. These decreases were offset by a $4.4 million increase in
the Dth purchased for spot market sales.
OTHER OPERATION AND MAINTENANCE EXPENSES increased by $24.7 million primarily as
a result $13.8 million incurred for the September wind storm.
OTHER INCOME increased by $37.5 million due to the deferral of MRA financing
costs, which are reflected in interest charges, due to the delay in
implementation of POWERCHOICE; partially offset by lower interest income which
reflects the use of cash for the MRA.
INTEREST CHARGES increased by $65.3 million mainly due to the interest charges
on the debt issued in connection with the MRA.
The decrease in FEDERAL AND FOREIGN INCOME TAXES of approximately $13.6 million
was due a lower percentage allocation of federal income taxes in the third
quarter of 1998.
Nine Months Ended September 30, 1998 Versus Nine Months Ended September 30, 1997
- --------------------------------------------------------------------------------
The Company experienced a loss during the first nine months of 1998 of $130.9
million or 82 cents per share, as compared with earnings of $147.3 million or
$1.02 per share for the first nine months of 1997. Year to date 1998 earnings
were negatively impacted by a non-cash write-off of $263.2 million during the
second quarter of 1998 or $1.18 per share associated with the portion of the MRA
Regulatory Asset disallowed in rates by the PSC (see Form 10-Q for the quarter
ended June 30, 1998 Part I, Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operation -"Master Restructuring Agreement
and the POWERCHOICE Agreement"). The January 1998 ice storm and the September
1998 windstorm also negatively impacted year to date 1998 earnings by a $80.2
million or 33 cents per share, which reflects the Company's estimate of
incremental, non-capitalized costs to restore power and rebuild its electric
system. Earnings were also lower due to warmer weather effects on sales
margins, and higher industrial customer discounts. In addition, earnings per
share for the nine months ended September 30, 1998 were diluted by the issuance
of 42.9 million shares of common stock in connection with the MRA.
ELECTRIC REVENUES for the first nine months of 1998 decreased $3.6 million or
0.1% from the same period in 1997 primarily as a result of a decrease in volume
and mix of sales of $24.4 million. The decrease was partially offset by a $16.7
million increase in sales to other electric systems.
ELECTRIC SALES to ultimate consumers were approximately 24.9 billion KWh in the
first nine months of 1998, a 1.2% decrease as compared to the same period in
1997 primarily as a result of warmer weather during winter months. Residential
sales declined 2.9% and commercial sales increased 1.0%. After adjusting for
the effects of weather and the farm and food processor retail access pilot
program (which pilot program has the effect of reducing sales to ultimate
consumers and increasing wholesale sales), sales to ultimate consumers would
have been expected to increase 0.3%.
NINE MONTHS ENDED SEPTEMBER 30,
ELECTRIC REVENUE (THOUSANDS) SALES (GWH)
---------------------------------- ------------------------
% %
1998 1997 Change 1998 1997 Change
----------- ------------ ------ ----- ------ ------
Residential. . . . . . $ 919,117 $ 941,663 (2.4) 7,358 7,574 (2.9)
Commercial . . . . . . 941,355 935,809 0.6 8,824 8,737 1.0
Industrial . . . . . . 370,172 401,774 (7.9) 5,186 5,413 (4.2)
Industrial - Special . 47,583 46,137 3.1 3,378 3,341 1.1
Other. . . . . . . . . 40,811 40,149 1.6 172 165 4.2
----------- ------------ ------ ----- ------ ------
Total to
Ultimate Consumers 2,319,038 2,365,532 (2.0) 24,918 25,230 (1.2)
Other Electric Systems 82,643 65,961 25.3 3,082 3,066 0.5
Miscellaneous. . . . . 104,367 78,110 33.6 - - -
----------- ------------ ------ ------ ------ ------
Total. . . . . . . . . $ 2,506,048 $ 2,509,603 (0.1) 28,000 28,296 (1.0)
=========== ============ ===== ====== ====== =====
ELECTRIC FUEL AND PURCHASED POWER COSTS decreased $21.3 million or 2.0%. This
decrease is mainly the result of decreased payments to IPPs of $149.6 million.
Of this amount, $79 million relates to net reductions in payments to IPP Parties
in July and August and was deferred for future rate making disposition. Other
purchased power costs decreased $4.1 million. The decrease in the IPP payments
is the result of the MRA Agreement which resulted in the termination of 18 PPAs
for 1100 MW and the restructuring of 9 PPAs for 583 MW. As a result, the
Company's load requirements were met from internal sources. This resulted in an
increase in fuel costs of $50.5 million as compared to the same period in 1997.
NINE MONTHS ENDED SEPTEMBER 30,
GWH COST (MILLIONS) CENTS/KWH
--------------------------- ------------------------- ----------
1998 1997 % Chg 1998 1997 % Chg 1998 1997
------ ------ ------ -------- -------- ------ ---- ----
FUEL FOR ELECTRIC GENERATION:
Coal . . . . . . . . . . . 5,873 5,512 6.5 $ 87.8 $ 78.0 12.6 1.5 1.4
Oil. . . . . . . . . . . . 1,338 284 371.1 47.5 15.1 214.6 3.6 5.3
Natural Gas. . . . . . . . 554 352 57.4 15.5 9.0 72.2 2.8 2.6
Nuclear. . . . . . . . . . 5,639 5,150 9.5 27.1 25.3 7.1 0.5 0.5
Hydro. . . . . . . . . . . 2,200 2,329 (5.5) - - - - -
------ ------ ----- -------- -------- ----- ---- ----
15,604 13,627 14.5 177.9 127.4 39.6 1.1 0.9
------ ------ ----- -------- -------- ------ ---- ----
ELECTRICITY PURCHASED:
IPPs:
Capacity. . . . . . . . - - - 126.0 166.6 (24.4) - -
Energy and taxes. . . . 8,014 10,180 (21.3) 554.8 663.8 (16.4) 6.9 6.5
------ ------ ----- -------- -------- ------ ---- ----
Total IPP purchases. 8,014 10,180 (21.3) 680.8 830.4 (18.0) 8.5 8.2
Other. . . . . . . . . . . 6,464 7,008 (7.8) 91.8 95.9 (4.3) 1.4 1.4
------ ------ ------ -------- -------- ------ ---- ----
Total Supply. . . . . . 14,478 17,188 (15.8) 772.6 926.3 (16.6) 5.3 5.4
------ ------ ------ -------- -------- ------ ---- ----
30,082 30,815 (2.4) 950.5 1,053.7 (9.8) 3.2 3.4
Fuel adjustment clause . . - - - 94.6 12.7 644.9 - -
Losses/Company use . . . . 2,082 2,519 (17.3) - - - - -
------ ------ ------ -------- -------- ------ ---- ----
Sales. . . . . . . . . . . 28,000 28,296 (1.0) $1,045.1 $1,066.4 (2.0) 3.7 3.8
====== ====== ====== ======== ======== ====== ==== ====
GAS REVENUES decreased $62.6 million or 12.6% during the first nine months of
1998 from the comparable period in 1997, primarily as a result of lower sales to
ultimate consumers of $43.3 million and a decrease in purchased gas adjustment
clause revenues of $23.4 million.
Due primarily to warmer weather during the first nine months of 1998, GAS SALES
to ultimate consumers decreased 9.7 million Dth or 15.9% from the first nine
months of 1997. After adjusting for the effects of weather, sales to ultimate
consumers decreased 7.6% primarily due to the migration of certain large
commercial sales customers to the transportation class and lower customer usage.
However, spot market sales (sales for resale), which are generally from the
higher priced gas available to the Company and therefore yield margins that are
substantially lower than traditional sales to ultimate consumers, increased. In
addition, changes in purchased gas adjustment clause revenues are generally
margin-neutral.
NINE MONTHS ENDED SEPTEMBER 30,
GAS REVENUE (THOUSANDS) SALES (THOUSANDS OF DTH)
-------------------------- --------------------------
% %
1998 1997 Change 1998 1997 Change
---------- ---------- ------ ------- ------- ------
Residential. . . . . . $ 291,794 $ 330,096 (11.6) 36,828 42,409 (13.2)
Commercial . . . . . . 87,063 112,995 (22.9) 13,443 16,947 (20.7)
Industrial . . . . . . 2,838 5,343 (46.9) 589 1,154 (49.0)
---------- ---------- ------ ------- ------- ------
Total to
Ultimate Consumers 381,695 448,434 (14.9) 50,860 60,510 (15.9)
Transportation of
Customer-Owned Gas . . 40,519 39,667 2.1 101,987 113,314 (10.0)
Spot Market Sales. . . 7,888 6,300 25.2 4,104 3,053 34.4
Miscellaneous. . . . . 3,791 2,096 80.9 12 19 (36.8)
---------- ---------- ------ ------- ------- ------
Total to System
Core Customers . $ 433,893 $ 496,497 (12.6) 156,963 176,896 (11.3)
========== ========== ====== ======= ======= ======
The total COST OF GAS included in expense decreased 14.5% in 1998. This was
the result of a 14.1 million decrease in Dth purchased and withdrawn from
storage for ultimate consumer sales ($51.3 million). This decrease was offset
by a $2.8 million increase in purchased gas costs and certain other items
recognized and recovered through the purchased gas adjustment clause, a 5.8%
increase in the average cost per Dth purchased ($9.8 million), and a $1.9
million increase in Dth purchased for spot market sales. The Company's net cost
per Dth sold, as charged to expense and excluding spot market purchases,
increased to $4.45 for the first nine months of 1998 from $4.05 in the first
nine months of 1997.
OTHER OPERATION AND MAINTENANCE EXPENSES increased by $92.5 million primarily as
a result of costs associated with the 1998 Storms (see "1998 Storms") and the
increased nuclear costs of $9.7 million mostly due to the extended Unit 2
refueling outage.
OTHER INCOME increased by $26.8 million primarily due to the deferral of MRA
financing costs, which are reflected in interest charges, due to the delay in
implementation of POWERCHOICE.
INTEREST CHARGES increased $59.8 million mainly due to the interest charges
incurred on the debt issued in connection with the MRA.
The decrease in FEDERAL AND FOREIGN INCOME TAXES of approximately $163.3 million
was primarily due to a decrease in pre-tax income.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
PART II - OTHER INFORMATION
---------------------------
ITEM 1. LEGAL PROCEEDINGS
Inter-Power Litigation
- ----------------------
In March 1993, Inter-Power of New York, Inc. ("Inter-Power") filed a complaint
against the Company and certain of its officers and employees in the NYS Supreme
Court. Inter-Power alleged, among other matters, fraud, negligent
misrepresentation and breach of contract in connection with the Company's
alleged termination of a PPA in January 1993. The plaintiff sought enforcement
of the original contract or compensatory and punitive damages in an aggregate
amount that would not exceed $1 billion, excluding pre-judgment interest.
In early 1994, the NYS Supreme Court dismissed two of the plaintiff's claims;
this dismissal was upheld by the Appellate Division, Third Department of the NYS
Supreme Court. Subsequently, the NYS Supreme Court granted the Company's motion
for summary judgment on the remaining causes of action in Inter-Power's
complaint. In August 1994, Inter-Power appealed this decision and on July 27,
1995, the Appellate division, third Department affirmed the granting of summary
judgment as to all counts, except for one dealing with an alleged breach of the
PPA relating to the Company's having declared the agreement null and void on the
grounds that Inter-Power had failed to provide it with information regarding its
fuel supply in a timely fashion. This one breach of contract claim was remanded
to the NYS Supreme Court for further consideration. In January 1998, the NYS
Supreme Court granted the Company's motion for summary judgment on all remaining
claims in this lawsuit in its entirety. In January 1998, Inter-Power filed a
notice of appeal and perfected its appeal in October 1998. The Company is
unable to predict the outcome of this matter.
NorCon Litigation
- -----------------
On February 4, 1994, the Company notified NorCon Partners, LP (NorCon) of the
Company's demand for adequate assurance that NorCon would perform all of their
future repayment obligations as required by agreement (see Form 10-K for fiscal
year ended December 31, 1997, Part I, Item 3. Legal Proceedings).
On March 7, 1994, NorCon filed a complaint in the U.S. District Court seeking to
enjoin the Company from terminating a PPA between the parties and seeking a
declaratory judgment that the Company has no right to demand additional security
or other assurances of NorCon's future performance under the PPA. NorCon sought
a temporary restraining order against the Company to prevent the Company from
taking any action on its February 4, 1994 letter. On March 14, 1994, the Court
entered the interim relief sought by NorCon. On April 4, 1994, the Company
filed its answer and counterclaim for declaratory judgment relating to the
Company's exercise of its right to demand adequate assurance. On November 2,
1994, NorCon filed for summary judgment. On February 6, 1996, the U.S. District
Court granted NorCon's motion for summary judgment and ruled that under New York
Law, the Company did not have the right to demand adequate assurances of future
performance. On March 25, 1997, the U.S. Court of Appeals for the Second
Circuit ordered that the question of whether there exists under New York
commercial law the right to demand firm security on an electric contract should
be certified to the New York Court of Appeals, the highest New York court, for
final resolution. The Second Circuit order effectively stayed the U.S. District
Court's order against the Company, pending final disposition by the New York
Court of Appeals. A motion to stay further proceedings was made since this
contract was included in the MRA.
NorCon subsequently dropped out of the MRA and arguments were held on October
22, 1998 in the New York Court of Appeals at the request of the Company. No
decision has been rendered to date. The Company is unable to predict the timing
and outcome of this matter.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits:
Exhibit 10 - Amendment to the Deferred Stock Unit Plan for Outside
Directors.
Exhibit 11 - Computation of the Average Number of Shares of Common
Stock Outstanding for the Three Months and Nine Months Ended September
30, 1998 and 1997.
Exhibit 12 - Statement Showing Computations of Ratio of Earnings to
Fixed Charges, Ratio of Earnings to Fixed Charges without Allowance
for Funds Used During Construction ("AFC") and Ratio of Earnings to
Fixed Charges and Preferred Stock Dividends for the Twelve Months Ended
September 30, 1998.
Exhibit 15 - Accountants' Acknowledgement Letter.
Exhibit 27 - Financial Data Schedule.
In accordance with Paragraph 4(iii) of Item 601(b) of Regulation S-K,
the Company agrees to furnish to the Securities and Exchange
Commission, upon request, a copy of the agreements comprising the $804
million senior debt facility that the Company completed with a bank
group during March 1996 and subsequently amended (effective June 30,
1998). The total amount of long-term debt authorized under such
agreement does not exceed 10 percent of the total consolidated assets
of the Company and its subsidiaries.
(b) Reports on Form 8-K:
Form 8-K Reporting Date - September 28, 1998
Items reported:
(1) Item 5. Other Events.
(a) Registrant filed information concerning the September 7, 1998
windstorm.
(b) Registrant filed information regarding the two month extension
of its fossil and hydro generating asset auction.
(2) Item 7. Financial Statements and Exhibits.
Exhibits required to be filed by Item 601 of Regulation S-K.
Form 8-K Reporting Date - October 23, 1998
Items reported:
(1) Item 5. Other Events.
Registrant filed a press release regarding earnings for the third
quarter of 1998.
(2) Item 7. Financial Statements and Exhibits.
Exhibits required to be filed by Item 601 of Regulation S-K.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SIGNATURE
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.
NIAGARA MOHAWK POWER CORPORATION
(Registrant)
Date: November 13 , 1998 By /s/Steven W. Tasker
--------------------------------------
Steven W. Tasker
Vice President-Controller and
Principal Accounting Officer
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
EXHIBIT INDEX
Exhibit
Number Description
- ------ -----------
10 Amendment to the Deferred Stock Unit Plan for Outside Directors.
11 Computation of the Average Number of Shares
of Common Stock Outstanding for the Three
Months and Nine Months Ended September 30, 1998 and 1997.
12 Statement Showing Computations of Ratio of
Earnings to Fixed Charges, Ratio of Earnings
to Fixed Charges without AFC and Ratio of
Earnings to Fixed Charges and Preferred Stock
Dividends for the Twelve Months Ended
September 30, 1998.
15 Accountants' Acknowledgement Letter.
27 Financial Data Schedule.