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 JUNE 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 JULY 31, 1998 - 187,364,863
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
FORM 10-Q - For the Quarter Ended June 30, 1998
INDEX
PART I. FINANCIAL INFORMATION
----------------------------------
Glossary of Terms
Item 1. Financial Statements
a) Consolidated Statements of Income - Three Months and
Six Months Ended June 30, 1998 and 1997
b) Consolidated Balance Sheets - June 30, 1998 and
December 31, 1997
c) Consolidated Statements of Cash Flows - Six Months Ended
June 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 4. Submission of Matters to a Vote of Security Holders
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 will be amortized and
Asset recovered under the POWERCHOICE agreement
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 STATEMENT OF INCOME
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
1998 1997 1998 1997
---- ---- ---- ----
(In thousands of dollars)
OPERATING REVENUES:
Electric. . . . . . . . . . . . . . . . . . . . . . . . . $ 783,282 $804,537 $1,646,451 $1,681,906
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . 127,624 141,161 362,859 427,624
--------- -------- --------- ---------
910,906 945,698 2,009,310 2,109,530
--------- --------- --------- ---------
OPERATING EXPENSES:
Fuel for electric generation. . . . . . . . . . . . . . . 51,190 35,192 98,388 72,657
Electricity purchased . . . . . . . . . . . . . . . . . . 302,259 316,998 626,609 645,801
Gas purchased . . . . . . . . . . . . . . . . . . . . . . 61,160 62,924 176,612 211,555
Other operation and maintenance expenses. . . . . . . . . 211,944 199,792 474,306 406,457
POWERCHOICE charge. . . . . . . . . . . . . . . . . . . . 263,227 - 263,227 -
Depreciation and amortization . . . . . . . . . . . . . . 87,823 84,799 175,773 169,021
Other taxes . . . . . . . . . . . . . . . . . . . . . . . 114,127 115,289 240,922 241,398
---------- ------- ------- -------
1,091,730 814,994 2,055,837 1,746,889
--------- ------- --------- ---------
OPERATING INCOME (LOSS) . . . . . . . . . . . . . . . . . . . (180,824) 130,704 (46,527) 362,641
Other income (deductions) . . . . . . . . . . . . . . . . . . (1,629) 6,269 2,596 13,369
---------- ------- --------- --------
INCOME (LOSS) BEFORE INTEREST CHARGES . . . . . . . . . . . . (182,453) 136,973 (43,931) 376,010
Interest charges. . . . . . . . . . . . . . . . . . . . . . . 65,861 69,342 131,451 136,880
--------- ------- --------- --------
INCOME (LOSS) BEFORE FEDERAL AND FOREIGN
INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . . (248,314) 67,631 (175,382) 239,130
Federal and foreign income taxes. . . . . . . . . . . . . . . (106,906) 26,882 (54,337) 95,359
---------- -------- --------- --------
NET INCOME (LOSS) (NOTE 1). . . . . . . . . . . . . . . . . . (141,408) 40,749 (121,045) 143,771
Dividends on preferred stock. . . . . . . . . . . . . . . . . 9,171 9,409 18,394 18,808
--------- -------- -------- --------
BALANCE AVAILABLE FOR COMMON STOCK. . . . . . . . . . . . . . $(150,579) $ 31,340 $ (139,439) $ 124,963
========== ======== =========== ==========
Average number of shares of common stock
outstanding (in thousands). . . . . . . . . . . . . . . . 144,891 144,391 144,657 144,390
BASIC AND DILUTED EARNINGS PER AVERAGE
SHARE OF COMMON STOCK . . . . . . . . . . . . . . . . . . $ (1.04) $ 0.22 $ (0.96) $ 0.87
The accompanying notes are an integral part of these financial statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
JUNE 30,
1998 December 31,
(UNAUDITED) 1997
----------- ----
(In thousands of dollars)
UTILITY PLANT:
Electric plant. . . . . . . . . . . . . . . . . . . . . . . . . $ 8,761,422 $ 8,752,865
Nuclear fuel. . . . . . . . . . . . . . . . . . . . . . . . . . 598,888 577,409
Gas plant . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,131,557 1,131,541
Common plant. . . . . . . . . . . . . . . . . . . . . . . . . . 319,124 319,409
Construction work in progress . . . . . . . . . . . . . . . . . 487,228 294,650
---------- -----------
Total utility plant. . . . . . . . . . 11,298,219 11,075,874
Less - Accumulated depreciation and amortization. . . . . . . . 4,394,884 4,207,830
---------- -----------
Net utility plant. . . . . . . . . . . 6,903,335 6,868,044
---------- -----------
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . . . . . . . . . . 318,432 371,709
---------- -----------
CURRENT ASSETS:
Cash, including temporary cash investments
of $212,786 and $315,708, respectively. . . . . . . . . . 262,711 378,232
Accounts receivable (less allowance for doubtful
accounts of $58,500 and $62,500 respectively) . . . . . . 320,857 492,244
Materials and supplies, at average cost:
Coal and oil for production of electricity. . . . . . . . 19,731 27,642
Gas storage . . . . . . . . . . . . . . . . . . . . . . . 29,023 39,447
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 121,003 118,308
Prepaid taxes . . . . . . . . . . . . . . . . . . . . . . . . . 59,767 15,518
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21,144 20,309
--------- ----------
834,236 1,091,700
--------- ----------
REGULATORY ASSETS (NOTE 3):
MRA regulatory asset . . . . . . . . . . . . . . . . . . . . . 4,002,603 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 . . . . . . . . . . . . . . . . . . . 53,463 57,312
Postretirement benefits other than pensions. . . . . . . . . . 54,583 56,464
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117,496 196,533
--------- ----------
4,853,769 1,176,824
--------- ----------
OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138,334 75,864
--------- -----------
$ 13,048,106 $ 9,584,141
============ ===========
The accompanying notes are an integral part of these financial statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
JUNE 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,341,352 1,779,688
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 663,981 803,420
------------ -----------
3,192,698 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 2,481,204 and
2,581,204 shares, respectively . . . . . . . . . . . . . . . . . . . . . . . . . 56,210 56,210
------------ -----------
514,810 516,610
------------ -----------
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,684,377 3,417,381
------------ -----------
TOTAL CAPITALIZATION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,391,885 6,661,518
------------ -----------
CURRENT LIABILITIES:
Long-term debt due within one year. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67,065 67,095
Sinking fund requirements on redeemable preferred stock . . . . . . . . . . . . . . . . . . 7,620 10,120
Accounts payable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 229,238 263,095
Payable on outstanding bank checks. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48,224 23,720
Customers' deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,867 18,372
Accrued taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83,000 9,005
Accrued interest. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63,247 62,643
Accrued vacation pay. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37,630 36,532
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100,784 64,756
------------ ---------
655,675 555,338
------------ ---------
REGULATORY AND OTHER LIABILITIES (NOTE3):
Deferred finance charges. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - 239,880
Accumulated deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,346,597 1,387,032
Employee pension and other benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . 242,285 240,211
Deferred pension settlement gain. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,161 12,438
Unbilled revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,652 43,281
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 180,851 224,443
------------ ----------
1,780,546 2,147,285
------------ ----------
COMMITMENTS AND CONTINGENCIES (NOTES 2 AND 3):
Liability for environmental restoration. . . . . . . . . . . . . . . . . . . . . . . . . . 220,000 220,000
------------ ----------
$ 13,048,106 $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)
SIX MONTHS ENDED JUNE 30,
1998 1997
---- ----
(In thousands of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (121,045) $ 143,771
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
POWERCHOICE charge. . . . . . . . . . . . . . . . . . . . . . . . . . . . 263,227 -
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . 175,773 169,021
Amortization of nuclear fuel. . . . . . . . . . . . . . . . . . . . . . . 12,975 12,944
Provision for deferred income taxes . . . . . . . . . . . . . . . . . . . (46,940) 31,181
Net accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . 144,387 31,444
Materials and supplies. . . . . . . . . . . . . . . . . . . . . . . . . . 16,718 22,166
Accounts payable and accrued expenses . . . . . . . . . . . . . . . . . . (5,394) (80,179)
Accrued interest and taxes. . . . . . . . . . . . . . . . . . . . . . . . 74,599 87,699
MRA regulatory asset. . . . . . . . . . . . . . . . . . . . . . . . . . . (3,955,256) -
Changes in other assets and liabilities . . . . . . . . . . . . . . . . . (59,206) 12,558
----------- ---------
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES. . . . . . . (3,500,162) 430,605
----------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction additions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (200,642) (115,825)
Nuclear fuel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (21,479) (2,710)
----------- ----------
Acquisition of utility plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . (222,121) (118,535)
Materials and supplies related to construction. . . . . . . . . . . . . . . . . . . (1,078) 368
Accounts payable and accrued expenses related to construction . . . . . . . . . . . (1,349) (20,045)
Other investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53,459 5,012
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,823) 5,538
----------- ---------
NET CASH USED IN INVESTING ACTIVITIES. . . . . . . . . . . . . . (172,912) (127,662)
----------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Reductions of preferred stock . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,300) (4,300)
Reductions in long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,300) (3,300)
Dividends paid. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (18,394) (18,808)
Issuance of senior notes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,279,769 -
Issuance of common stock. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 316,389 -
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (12,611) 313
----------- ----------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES. . . . . . . 3,557,553 (26,095)
----------- ----------
NET INCREASE (DECREASE) IN CASH . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (115,521) 276,848
Cash at beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 378,232 325,398
----------- ---------
CASH AT END OF PERIOD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 262,711 $ 602,246
========== =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 140,670 $ 138,954
Income taxes paid (refunded). . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (7,840) $ 47,116
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 six-month periods ended June 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 subsequent 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 six months ended
June 30, 1998 and 1997 was $(144.9) million and $42.6 million, respectively, and
$(123.5) million and $143.0 million, respectively.
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 125 sites with which it has been or may be
associated, including 78 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
June 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 June 30, 1998 and
December 31, 1997 incorporates a change in the method used to estimate the
liability for 27 of the Company's largest sites to rely 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 June 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 Company anticipates receiving comments from
the DEC on the draft feasibility study by the summer 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 it 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 $37 million, net of costs incurred in pursuing recoveries. Under
POWERCHOICE approximately $33 million related to the electric business will be
amortized over 10 years. Approximately $4 million relates to the gas business
and is being amortized over the three year settlement period. 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
$4,853 million at June 30, 1998. These regulatory assets are probable of
recovery. The portion of the $4,853 million which has been allocated to the
nuclear generation and electric transmission and distribution business is
approximately $4,755 million. Regulatory assets allocated to the rate-regulated
gas distribution business are $98 million. As discussed below, the increase in
the Company's regulatory assets is attributed to the MRA Regulatory Asset of
$4,003 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.
The PSC, in its written order issued March 20, 1998 approving POWERCHOICE,
determined to limit the estimated value of the MRA Regulatory Asset that can be
recovered from customers to approximately $4,000 million. As of June 30, 1998,
the Company had recorded an MRA Regulatory Asset of $4,003 million, which
represents the recoverable costs of the MRA consisting of: (a) the cash
compensation of $3,631 million paid to the IPP Parties; (b) the issuance of
42.9 million shares of common stock valued at an aggregate of $343.6 million or
$8.00 per share, based on the limitation on the amount of the MRA Regulatory
Asset, as set forth in the PSC Order; and (c) expenses of $28.4 million related
to the MRA. As a result of the PSC Order limitation, the Company recorded a
non-cash POWERCHOICE charge to earnings of $263.2 million, or $1.18 per share,
in the second quarter of 1998, upon the closing of the MRA, which represents the
sum of (1) the difference between the net proceeds from the public sale of 22.4
million shares or $303.7 million and the $8 per share multiplied by 22.4 million
shares or $179.2 million and (2) the difference between the Company's common
stock price of $14.75 at the time of issuance and $8 per share multiplied by the
20.5 million shares issued.
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. Although the Company
has not yet implemented the tariffs related to POWERCHOICE, it has reflected
these changes in its June 30, 1998 balance sheet.
The 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
recoverable, 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 cost-of-service
regulated, 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. In the event the proceeds
resulting from the sale of the fossil and hydro assets are not sufficient to
avoid a loss, under the terms of POWERCHOICE the Company would be able to
recover such loss through the CTC. 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 June 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 June 30, 1998
and the unaudited Consolidated Statements of Income for the three-month and
six-month periods ended June 30, 1998 and 1997 and the unaudited Consolidated
Statements of Cash Flows for the six-months ended June 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 June 30, 1998 and the related
condensed consolidated statements of income for the three-month and six-month
periods ended June 30, 1998 and 1997 and of cash flows for the six months ended
June 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 (containing explanatory paragraphs
with respect to the Company's application of Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of Regulation"
[SFAS No. 71] for its nuclear generation, electric transmission and distribution
and gas businesses and discontinuation of SFAS No. 71 for its non-nuclear
generation business in 1996). 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
August 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, including the improvement in the Company's cash flow upon the
implementation of the MRA and POWERCHOICE, a reduction in IPP payments as a
result of the consummation of the MRA, the Company's planned repayment of debt,
the consideration of the tariffs implementing POWERCHOICE by the PSC, the
timing and outcome of the future sale of the Company's fossil and hydro
generation assets, and the PSC's approval of the incentive in the City of
Oswego's tax settlement agreement. Other forward looking statements included
in this report are the costs and potential recoveries associated with the
January 1998 ice storm and recoveries on capital requirements, the structural
soundness of the reactor core shroud and continued safe operation of Unit 2, and
the potential recoveries associated with a counterparty default. The Company's
actual results and developments may differ materially from the results discussed
in or implied by such forward-looking statements, due to risks and uncertainties
that exist in the Company's operations, and business and regulatory environment,
including, but not limited to, matters described in the context of such
forward-looking statements, as well as such other factors as set forth in the
Notes to Consolidated Financial Statements contained herein.
MASTER RESTRUCTURING AGREEMENT AND POWERCHOICE AGREEMENT
(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, Part I, Item 2.
Management's Discussion and Analysis of Financial Condition and Results of
Operation - "Master Restructuring Agreement and the POWERCHOICE Agreement").
MASTER RESTRUCTURING AGREEMENT. The MRA was consummated on June 30, 1998 with
14 IPPs. The MRA allowed the Company to terminate, restate or amend 27 PPAs
which represented approximately three quarters of the Company's over-market
purchase power obligations. In exchange, the IPPs received approximately $3.6
billion in cash, approximately 20.5 million shares of the Company's common stock
and proceeds from the sale of 22.4 million shares of the Company's common stock.
The MRA will reduce the Company's IPP payments by more than $500 million
annually. The improved cash flow will allow the Company to reduce electricity
prices and pay off the debt required to finance the MRA. Without the MRA, the
Company's IPP payments, which have exceeded $1 billion annually, were projected
to increase by $50 million per year until 2002. Because the MRA closed on June
30, 1998, the Company's results of operations for the first six months of 1998
do not yet reflect these impacts.
POWERCHOICE AGREEMENT. The PSC's written order issued on March 20, 1998
approving POWERCHOICE, limited the estimated value of the MRA Regulatory Asset
that can be recovered from customers to approximately $4,000 million. As a
result of this PSC Order limitation, the Company recorded a non-cash charge to
earnings of $263.2 million, or $1.18 per share in the second quarter of 1998.
(See Item 1. Financial Statements - "Note 3. Rate and Regulatory Issues and
Contingencies").
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 rate plan will take effect upon approval by the PSC of
the tariffs implementing POWERCHOICE. The reduction in prices will include
certain savings that will result from partial reductions of the GRT. Industrial
customers will see average reductions of 25% relative to 1995 price levels;
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.
The Company believes that the PSC will consider the tariffs implementing
POWERCHOICE in August 1998 but cannot predict the outcome of that consideration.
The Company is experiencing a reduction in power purchase costs between the MRA
closing date and the POWERCHOICE implementation date. The Company will propose
that those reductions, net of increased financing costs, be deferred for future
disposition, consistent with the treatment of other deferrals as set forth in
POWERCHOICE.
In April 1998, the cities of Oswego, Fulton, Cohoes and the New York Conference
of Mayors and Municipal Officials sought a temporary restraining order and
preliminary injunction in New York State Supreme Court against the PSC to enjoin
the implementation of the POWERCHOICE settlement, the MRA and the Company's
contemplated auction of its fossil and hydro generation assets on the grounds
that the PSC failed to comply with the provisions of the State Environmental
Quality Review Act. They were joined in their petition by the chairman of the
Buffalo City Council Energy Committee (see Part II, Item 1. Legal Proceedings -
"City of Oswego Litigation"). In addition, the City of Oswego and others
petitioned the PSC for rehearing of the March 20, 1998 Order approving
POWERCHOICE. On June 5, 1998, the PSC denied such petition for rehearing. (See
Part II, Item 1. Legal Proceedings - "PULP Litigation").
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. The Company has received non-binding preliminary bids
from 37 bidders. Final bids are expected in September 1998 and definitive
agreements will be completed shortly thereafter. Transaction closings are
anticipated to occur in mid-1999 after the Company and the buyers have received
the necessary regulatory approvals. On June 5, 1998, the City of Oswego and
others petitioned the PSC for rehearing of the May 6, 1998 Order approving the
Company's plan to divest its fossil and hydroelectric generating plants, which
the PSC subsequently denied. The Company is unable to predict the outcome or
timing of the divestiture of the fossil and hydroelectric assets.
In August 1998, the Company entered into a tax settlement agreement with the
City of Oswego. Under that agreement, the total tax revenues received by the
city, county and school district will be reduced from $28.79 million in 1998 to
$2 million in 2003 if the Company's Oswego generating plant is successfully sold
or $3 million in 2002 if the Company does not receive a positive bid for the
sale of the plant. In addition, subject to the approval of the PSC, the city,
county and school district shall receive 5 percent of any portion of the sale
price of the station greater than $100 million and 7-1/2 percent of the portion
of any sale price greater than $300 million. The Company believes that the PSC
will approve such an incentive.
At the 1998 annual meeting, the Company's shareholders gave the Company approval
to form a holding company, the implementation of which will only occur following
various regulatory approvals.
JANUARY 1998 ICE STORM
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
$141 million. As of June 30, 1998, the Company recorded $75.3 million in
expense associated with the January 1998 ice storm (of which $66.4 million was
considered incremental) and $65.7 million was capitalized. The Company is
continuing to inspect and survey the work completed.
The Company continues to pursue federal disaster relief assistance and is
working with its insurance carriers to assess what portion of the rebuild costs
are covered by insurance policies. The Company is also analyzing potential
available options for state financial aid. The Company is unable to determine
what recoveries, if any, it may receive from these sources.
NUCLEAR MATTERS
UNIT 1 OUTAGE. On April 28, 1998, Unit 1 was taken out of service to fix design
deficiencies related to the control room emergency ventilation system. Unit 1
returned to service May 26, 1998.
UNIT 2 OUTAGE. On May 2, 1998, Unit 2 was taken out of service for a planned
refueling and maintenance outage. During the outage the Company performed
scheduled inspections of the plant's reactor core shroud and identified cracking
in the welds of the shroud. The scope of the inspection was expanded once the
cracking was found, which extended the length of outage. The Company and the
NRC have agreed that the plant's reactor core shroud continues to be
structurally sound and does not pose any concern to the continued operation of
the plant. Unit 2 returned to service on July 5, 1998 after completing the
64-day refueling and maintenance outage.
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 April 1996, the FERC issued FERC Order 888. Order 888 promotes competition
by requiring that public utilities owning, operating, or controlling interstate
transmission facilities file tariffs which offer others the same transmission
services they provide for themselves, under comparable terms and conditions.
As part of FERC Order 888, the New York Power Pool (NYPP) was required to file
reformed power pooling agreements that establish open, non-discriminatory
membership provisions and modify any provisions that are unduly discriminatory
or preferential. On June 24, 1998, FERC gave New York utilities a conditional
approval to form an Independent System Operator (ISO), however, FERC did defer
action on the rates, terms and conditions of the ISO's open access tariff. As
part of their ruling the NYPP will be dissolved and its functions assumed by the
ISO. In addition two additional entities will be formed: a New York State
Reliability Council to develop bulk power reliability standards; and a New York
Power Exchange designed to facilitate transactions open to all market
participants.
The Company considers this approval another positive step towards competition in
New York State and further enhances the Company's POWERCHOICE program.
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 has responded
in opposition to this petition and is unable to predict the outcome of this
matter.
FINANCIAL POSITION
The Company's capital structure at June 30, 1998 was 64.5% long-term debt, 5.0%
preferred stock and 30.5% 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 $17.04 per share at June 30, 1998, as compared to $18.89 at
December 31, 1997. With the issuance of equity 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 twelve months ended June 30, 1998, was $800
million, and upon implementation of the MRA and POWERCHOICE 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, which would increase significantly
upon consummation of the MRA. 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
Under the MRA, the Company paid an aggregate of $3.631 billion in cash, of which
$3.212 billion obtained was through a public market offering of senior unsecured
debt and the remainder from cash on hand. In addition, the Company issued 20.5
million shares of common stock to the IPP Parties and gave them the net proceeds
of $303.7 million from the public sale of 22.4 million shares of common stock.
The Company is unable to issue incremental first mortgage bonds under the terms
of the public debt offering. The Company amended its existing $804 million bank
facility as of June 30, 1998. The amendment, which included an extension of the
term from June 30, 1999 to June 1, 2000, also accommodates the holding company
structure and permits the auction of fossil and hydro generating assets.
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 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 carry back unused NOL to the prior two years
which is to result in a refund of approximately $128 million. In addition, the
Company will be able to deduct the remaining $3 billion paid to the IPP Parties
in future years until fully utilized. 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 substantially limited under the rules of section 382 of the Internal Revenue
Code if certain changes in the Company's stock ownership were to occur following
the consummation of the MRA. 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 who
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 prior to consummation of the MRA. Under the
computational rules prescribed by 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 23%. Thus, if the IPP Parties, the purchasers in the public offering, and
any other 5% shareholders collectively experience ownership increases totaling
more than 27% during any three year testing period that includes the
consummation dates of the public offering and the MRA, the 50% 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 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 on a going forward basis would likely be
significantly lower 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 would otherwise be
eliminated or reduced through unrestricted use of the NOL.
NET CASH USED IN OPERATING ACTIVITIES increased $3,930.8 million in the six
months ended June 30, 1998 primarily due to the consummation of the MRA.
NET CASH USED IN INVESTING ACTIVITIES increased $ 45.3 million in the six months
ended June 30, 1998 primarily as a result of an increase in the acquisition of
utility plant of $103.6 million, mainly due to the January 1998 ice storm.
These increases were partially offset by a decrease in other investments of
$48.4 million and by a decrease in accounts payable and accrued construction
related expenses of $18.7 million.
NET CASH PROVIDED BY FINANCING ACTIVITIES increased $3,583.6 million in the six
months ended June 30, 1998 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 six months ended June 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
six 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 pending implementation of POWERCHOICE. It
should also be read in conjunction with other financial and statistical
information appearing elsewhere in this report.
Three Months Ended June 30, 1998 versus Three Months Ended June 30, 1997
- ------------------------------------------------------------------------
The Company experienced a loss during the second quarter of 1998 of $150.6
million or $1.04 per share, as compared with earnings of $31.3 million or 22
cents per share for the second quarter of 1997. Second quarter 1998 earnings
were negatively impacted by a non-cash write-off of $263.2 million or $1.18 per
share associated with the portion of the MRA disallowed in rates by the PSC (see
"Master Restructuring Agreement and the POWERCHOICE Agreement"). In addition
second quarter 1998 earnings were lower due to warmer weather.
ELECTRIC REVENUES decreased $21.3 million or 2.6% from the second quarter of
1997 primarily as a result of a decrease in volume and mix of sales to ultimate
customers of $30.3 million and a $8.4 million decrease in electric fuel
adjustment clause revenues. These decreases were partially offset by an $8.6
million increase in revenue from the delivery of energy to other electric
wholesale customers under the farm and food processor retail access pilot
program and an $8.8 million increase in sales to other electric systems.
ELECTRIC SALES to ultimate consumers were approximately 7.8 billion KWh in the
second quarter of 1998, a 2.9% decrease from the comparable period in 1997
primarily as a result of warmer weather. Residential and commercial sales
declined 6.7% and 1.7%, respectively. After adjusting for the effects of
weather and the farm and food processor retail access pilot program, sales to
ultimate consumers would have been expected to increase 0.7%. Sales for resale
increased 81 million KWh (8.5%), reflecting sales to energy service companies
participating in the Company's farm and food processor retail access pilot
program (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 - "PSC Competitive Opportunities Proceeding - Electric").
Total electric sales decreased 155 million KWh (1.7%).
ELECTRIC FUEL AND PURCHASED POWER COSTS increased $1.3 million or 0.4% in the
second quarter of 1998, primarily as a result of an $18.7 million increase in
actual fuel costs and a $0.5 million increase in other purchased power costs.
This was offset by a $15.3 million decrease in costs deferred and recovered
through the operation of the FAC and decreased payments to IPPs of $2.6 million.
As noted above, Unit 1 and Unit 2 were not in service during a portion of the
second quarter of 1998, which resulted in a 12.5% decrease in nuclear generation
from the second quarter of 1997. In addition hydro generation also decreased
19.1% as compared to the second quarter of 1997, since less snowfall during the
winter resulted in lower than normal spring run-off. As a result, the Company
was required to meet load requirements using coal, oil and natural gas fuels,
which are higher cost fuels.
GAS REVENUES decreased $13.5 million or 9.6% in the second quarter of 1998 from
the comparable period in 1997, primarily as a result of lower sales to ultimate
consumers of $17 million, which was partially offset by a $3.5 million increase
in purchase gas adjustment clause revenues.
Due primarily to warmer weather during the second quarter of 1998, GAS SALES to
ultimate consumers decreased 5.3 million Dth or 28.3% from the second quarter of
1997. After adjusting for the effects of weather, sales to ultimate consumers
decreased 10.9% primarily due to the migration of certain large commercial sales
customers to the transportation class and lower customer usage. 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, also decreased as the warm
weather depressed spot sales opportunities. In addition, changes in purchased
gas adjustment clause revenues are generally margin-neutral.
The total COST OF GAS included in expense decreased 2.8% in the second quarter
of 1998. This was the result of a 8.2 million decrease in Dth purchased and
withdrawn from storage for ultimate consumer sales ($23.0 million), partially
offset by an increase in the average cost of Dth purchased ($15.3 million), a
$0.5 million increase in Dth purchased for spot market sales, and a $5.4 million
increase in purchased gas costs and certain other items recognized and recovered
through the purchased gas adjustment clause.
OTHER OPERATION AND MAINTENANCE EXPENSES increased by $12.2 million primarily as
a result of increased nuclear costs of $9.7 million, mostly due to the extended
Unit 2 refueling outage.
OTHER INCOME (DEDUCTIONS) decreased by $7.9 million primarily due to lower
subsidiary earnings. The Company's energy marketing subsidiary recognized an
$8.0 million, after tax charge associated with a counterparty default. The
default was directly related to the volatility experienced in the Midwest
electric markets during the last week of June 1998. The Company is presently
investigating several alternative courses of action to recover this amount, but
is currently unable to predict the outcome of these efforts.
The decrease in FEDERAL AND FOREIGN INCOME TAXES of approximately $133.8 million
was primarily due to a decrease in pre-tax income and a lower percentage
allocation of federal income taxes in the second quarter of 1998.
Six Months Ended June 30, 1998 Versus Six Months Ended June 30, 1997
- --------------------------------------------------------------------
The Company experienced a loss during the first six months of 1998 of $139.4
million or 96 cents per share, as compared with income of $125.0 million or 87
cents per share for the first six months of 1997. Year to date 1998 earnings
were negatively impacted by a write-off of $263.2 million or $1.18 per share
associated with the portion of the MRA Regulatory Asset disallowed in rates by
the PSC (see "Master Restructuring Agreement and the POWERCHOICE Agreement").
The Ice Storm of 1998 also negatively impacted year to date 1998 earnings by a
$66.4 million or 30 cent per share write off, which reflects the Company's
estimate of incremental, non-capitalized costs to restore power and rebuild its
electric system in northern New York. Earnings were also lower due to warmer
weather effects on sales margins, higher capacity payments to IPPs and higher
industrial customer discounts.
ELECTRIC REVENUES for the first six months of 1998 decreased $35.5 million or
2.1% from the same period in 1997 primarily as a result of a decrease in volume
and mix of sales to ultimate customers of $53.5 million and a $8.4 million
decrease in electric fuel adjustment clause tariff sales. These decreases were
partially offset by an $8.6 million increase in revenue from the delivery of
energy to other electric systems and a $17.8 million increase in sales to other
electric systems.
ELECTRIC SALES to ultimate consumers were approximately 16.5 billion KWh in the
first six months of 1998, a 2.0% decrease as compared to the same period in 1997
primarily as a result of warmer weather. Residential and commercial sales
declined 5.7% and 1.4%, respectively. After adjusting for the effects of
weather and the farm and food processor retail access pilot program, sales to
ultimate consumers would have been expected to increase 0.8%. Sales for resale
increased 285 million KWh (13.4%), reflecting sales to energy service companies
participating in the Company's farm and food processor retail access pilot
program. This resulted in a net decrease in total electric sales of 49 million
KWh (0.3%).
SIX MONTHS ENDED JUNE 30,
Electric Revenue (Thousands) Sales (GWh)
---------------------------- -----------
% %
1998 1997 Change 1998 1997 Change
---- ---- ------ ---- ---- ------
Residential. . . . . . $ 612,754 $ 648,347 (5.5) 4,929 5,226 (5.7)
Commercial . . . . . . 600,977 616,722 (2.6) 5,658 5,738 (1.4)
Industrial . . . . . . 246,918 263,818 (6.4) 3,467 3,513 (1.3)
Industrial - Special . 31,501 30,747 2.5 2,290 2,206 3.8
Other. . . . . . . . . 27,500 26,981 1.9 119 114 4.4
---------- ---------- ----- ------ ------ -----
Total to
Ultimate Consumers 1,519,650 1,586,615 (4.2) 16,463 16,797 (2.0)
Other Electric Systems 61,261 43,495 40.8 2,419 2,134 13.4
Miscellaneous. . . . . 65,540 51,796 26.5 - - -
---------- ---------- ----- ------ ------ -----
Total. . . . . . . . . $1,646,451 $1,681,906 (2.1) 18,882 18,931 (0.3)
========== ========== ===== ====== ====== =====
ELECTRIC FUEL AND PURCHASED POWER COSTS increased $6.5 million or 1.1%. This
increase is mainly the result of an $27.4 million increase in actual fuel costs
offset by a $12.7 million decrease in costs deferred and recovered through the
operation of the FAC, decreased payments to IPPs of $2.5 million and a decrease
of $5.7 million in other purchased power costs. Due to a decrease in hydro
generation (13.9%) as compared to the first six months of 1997, the Company was
required to meet load requirements using coal, oil, and natural gas fuels, which
are higher cost fuels.
GAS REVENUES decreased $64.8 million or 15.1% during the first six months of
1998 from the comparable period in 1997, primarily as a result of lower sales to
ultimate consumers of $40.8 million and a decrease in purchased gas adjustment
clause revenues of $23.4 million.
Due primarily to warmer weather during the first six months of 1998, GAS SALES
to ultimate consumers decreased 9.3 million Dth or 16.7% from the first six
months of 1997. After adjusting for the effects of weather, sales to ultimate
consumers decreased 7.8% primarily due to the migration of certain large
commercial sales customers to the transportation class and lower customer usage.
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, also decreased as the warm
weather depressed spot sales opportunities. In addition, changes in purchased
gas adjustment clause revenues are generally margin-neutral.
SIX MONTHS ENDED JUNE 30,
Gas Revenue (Thousands) Sales (Thousands of Dth)
----------------------- ------------------------
% %
1998 1997 Change 1998 1997 Change
---- ---- ------ ---- ---- ------
Residential. . . . . . $248,222 $285,246 (13.0) 33,790 39,165 (13.7)
Commercial . . . . . . 77,622 102,342 (24.2) 12,147 15,518 (21.7)
Industrial . . . . . . 2,377 4,819 (50.7) 497 1,047 (52.5)
-------- -------- ------ ------- ------- ------
Total to
Ultimate Consumers 328,221 392,407 (16.4) 46,434 55,730 (16.7)
Transportation of
Customer-Owned Gas . . 29,658 28,037 5.8 73,566 77,287 (4.8)
Spot Market Sales. . . 2,732 5,482 (50.2) 1,390 2,737 (49.2)
Miscellaneous. . . . . 2,248 1,698 32.4 10 13 (23.1)
-------- -------- ------ ------- ------- ------
Total to System
Core Customers . $362,859 $427,624 (15.1) 121,400 135,767 (10.6)
======== ======== ====== ======= ======= ======
The total COST OF GAS included in expense decreased 16.5% in 1998. This was the
result of a 13.7 million decrease in Dth purchased and withdrawn from storage
for ultimate consumer sales ($44.9 million) and a $2.5 million decrease in Dth
purchased for spot market sales. This was partially offset by a $4.5 million
increase in purchased gas costs and certain other items recognized and recovered
through the purchased gas adjustment clause and an 5.8% increase in the average
cost per Dth purchased ($8.0 million). The Company's net cost per Dth sold, as
charged to expense and excluding spot market purchases, increased to $4.14 for
the first six months of 1998 from $3.71 in the first six months of 1997.
OTHER OPERATION AND MAINTENANCE EXPENSES increased by $67.8 million primarily as
a result of costs associated with the January 1998 ice storm (see "January 1998
Ice Storm") and the increased nuclear costs of $9.7 million mostly due to the
extended Unit 2 refueling outage.
OTHER INCOME (DEDUCTIONS) decreased by $10.8 million primarily due to lower
subsidiary earnings. The Company's energy marketing subsidiary recognized an
$8.0 million, after tax charge associated with a counterparty default. The
default was directly related to the volatility experienced in the Midwest
electric markets during the last week of June 1998. The Company is presently
investigating several alternative courses of action to recover this amount, but
is currently unable to predict the outcome of these efforts.
The decrease in FEDERAL AND FOREIGN INCOME TAXES of approximately $149.7 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
City of Oswego Litigation
- -------------------------
In April 1998, the cities of Oswego, Fulton, Cohoes and the New York Conference
of Mayors and Municipal Officials sought a temporary restraining order and
preliminary injunction in New York State Supreme Court against the PSC to enjoin
the implementation of the POWERCHOICE settlement, the MRA and the Company's
contemplated auction of its fossil and hydro generation assets on the grounds
that the PSC failed to comply with the provisions of the State Environmental
Quality Review Act. They were joined in their petition by the chairman of the
Buffalo City Council Energy Committee. The application of the City of Oswego
and the other petitioners for the temporary restraining order was denied at a
Supreme Court hearing held in Albany on April 21, 1998. On May 8, 1998 there
were oral arguments heard in the Supreme Court in Albany and the court did not
grant the cities' request for preliminary injunction but rather reserved ruling
on all of the cities' requests. On May 22, 1998 this request for the injunction
was dismissed in the Supreme Court in Albany and was not appealed by the parties
involved and such time for appeal has expired.
IPP Litigation
- --------------
(See Form 10-K as amended for fiscal year ended December 31, 1997, Part I, Item
3. Legal Proceedings)
As a result of the closing of the MRA on June 30, 1998, filings have been made
with the appropriate courts to end the litigation with Encogen Four Partners,
L.P. and Sterling Power partners, L.P. However, litigation is ongoing with
NorCon Power Partners, L.P., since NorCon dropped out of the MRA. The U.S.
District Court for the Southern District of New York has scheduled arguments in
the NorCon case for October 22, 1998 at the request of the Company.
Fourth Branch Litigation
- ------------------------
In November 1993, Fourth Branch Associates Mechanicville ("Fourth Branch") filed
an action against the Company and several of its officers and employees in the
NYS Supreme Court, seeking compensatory damages of $50 million, punitive damages
of $100 million and injunctive and other related relief. The lawsuit grows out
of the Company's termination of a contract for Fourth Branch to operate and
maintain a hydroelectric plant the Company owns in the Town of Halfmoon, New
York. Fourth Branch's complaint also alleges claims based on the inability of
Fourth Branch and the Company to agree on terms for the purchase of power from a
new facility that Fourth Branch hoped to construct at the Mechanicville site.
In January 1994, the Company filed a motion to dismiss Fourth Branch's
complaint. By order dated November 7, 1995, the Court granted the Company's
motion to dismiss the complaint in its entirety. Fourth Branch filed an appeal
from the Court's order. On January 30, 1997, the Appellate Division modified
the November 7, 1995 court decision by reversing the dismissal of the fourth and
fifth causes of action set forth in Fourth Branch's complaint.
The Company and Fourth Branch had also entered into negotiations under a FERC
mediation process. As a result of these negotiations, the Company had proposed
to sell the hydroelectric plant to Fourth Branch for an amount which would not
be material. In addition, the proposal included a provision that would require
the discontinuance of all litigation between the parties.
Attempts to implement this proposal have been unsuccessful and the Company has
informed FERC that its participation in the mediation efforts has been
concluded. On January 14, 1997, the FERC Administrative Law Judge issued a
report to FERC recommending that the mediation proceeding be terminated, leaving
outstanding a Fourth Branch complaint to FERC that alleges anti-competitive
conduct by the Company. The Company has made a motion to dismiss Fourth
Branch's antitrust complaint before the FERC, which motion was opposed by Fourth
Branch. A decision from FERC on this matter is pending.
Recently, Fourth Branch commenced a condemnation proceeding in Federal District
Court to obtain title to the project property and also has made a unilateral
offer of settlement before FERC. The Company has served an answer with various
affirmative defenses. On July 30, 1998, Fourth Branch moved for Summary
Judgment. The Company intends to oppose Fourth Branch's motion and cross-move
for summary judgment in favor of the Company.
The Company is unable to predict the ultimate disposition of the lawsuit
referred to above. However, the Company believes it has meritorious defenses
and intends to defend this lawsuit vigorously. No provision for liability, if
any, that may result from this lawsuit has been made in the Company's financial
statements.
PULP Litigation
- ---------------
In July 1998, the Public Utility Law Project of New York, Inc. (PULP) and others
sought a declaratory judgement, declaring the Company's POWERCHOICE agreement
unlawful, null and void and injunctive relief in the Supreme Court of the State
of New York, Albany County against the PSC and the Company to enjoin the
defendants to halt all their actions and expenditures to implement the rules for
the provision of retail energy services contained in the POWERCHOICE agreement.
The PSC and the Company will be filing a motion seeking to dismiss this action.
The Company is unable to predict the outcome of this matter.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the Company's annual meeting of shareholders on June 29, 1998,
(1) the election of Directors was as follows:
Shares Shares
Voted Withheld
For Authority
--- ---------
Salvatore H. Alfiero 124,144,360 5,331,083
Albert J. Budney, Jr. 123,930,218 5,545,225
Dr. Bonnie Guiton Hill 124,060,522 5,414,921
Clark A. Johnson 123,859,689 5,615,754
Henry A. Panasci, Jr. 124,007,469 5,467,974
(2) Approval of the issuance of up to 43 million shares of common stock to
the IPP Parties, in accordance with the MRA (see Part I, Item 2. Management's
Discussion and Analysis of Financial Condition and Results of Operations -
"Master Restructuring Agreement and PowerChoice Agreement) was as follows:
104,906,769 shares for, 6,520,132 shares against, 1,816,086 shares abstained,
and 16,232,456 broker non-votes.
(3) Approval to amend the Company's certificate of incorporation to increase
the number of shares of Common Stock to 250 million from 185 million sufficient
to implement the MRA and to preserve flexibility to issue additional shares of
Common Stock was as follows: 103,609,173 shares for, 7,999,441 shares against,
1,634,373 shares abstained and 16,232,456 broker non-votes.
(4) Approval of a binding share exchange, the effect of which is to
restructure Niagara Mohawk so that it will become a separate subsidiary of a new
parent holding company, with the present holders of Common Stock becoming the
holders of the common stock of the new parent was as follows: 106,779,635 shares
for, 4,473,111 shares against, 1,990,241 shares abstained and 16,232,456 broker
non-votes.
(5) A shareholder proposal relating to the Company's endorsement of the
Coalition for Environmentally Responsible Economies Principles as part of its
commitment to be publicly accountable for its environmental impact was rejected
by a vote of 13,444,946 for, 93,922,156 against, 5,875,885 abstentions, and
16,232,456 broker non-votes.
(6) A shareholder proposal relating to the recommendation, with respect to
future contract obligations, that when a dividend is cut, no salaries will be
increased or any stock options allowed to executives or directors until the
dividend is restored to its original amount before the cut, was not presented
for consideration at the meeting and therefore, was not voted upon.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits:
Exhibit 3 - Certificate of Amendment of Certificate of Incorporation of NMPC
under Section 805 of the Business Corporation Law of New York filed June 29,
1998 in the office of the New York Secretary of State.
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 Six Months Ended June 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 June 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 - June 30, 1998
Item reported - Item 7. Financial Statements, Pro Forma Financial Information
and Exhibits.
Exhibits required to be filed by Item 601 of Regulation S-K.
Form 8-K Reporting Date - June 25, 1998
Item reported - Item 7. Financial Statements and Exhibits
Underwriting Agreement, dated June 25, 1998.
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: August 14 , 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
- ------ -----------
3 Certificate of Amendment of Certificate of Incorporation
of NMPC under section 805 of the Business Corporation
Law of New York filed June 29, 1998 in the office of the
New York Secretary of State.
10 Amendment to Deferred Stock Unit Plan for Outside
Directors.
11 Computation of the Average Number of Shares of Common
Stock Outstanding for the Three Months and Six Months
Ended June 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
June 30, 1998.
15 Accountants' Acknowledgement Letter.
27 Financial Data Schedule.