SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 1995
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OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-2987.
NIAGARA MOHAWK POWER CORPORATION
- --------------------------------
(Exact name of registrant as specified in its charter)
State of New York 15-0265555
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(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 April 30, 1995 - 144,330,482<PAGE>
<PAGE>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
FORM 10-Q - For The Quarter Ended March 31, 1995
INDEX
- -----
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
a) Consolidated Statements of Income -
Three Months Ended March 31, 1995 and 1994
b) Consolidated Balance Sheets - March 31,
1995 and December 31, 1994
c) Consolidated Statements of Cash Flows -
Three Months Ended March 31, 1995 and 1994
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 4. Submission of Matters to a Vote
of Security Holders.
Item 6. Exhibits and Reports on Form 8-K.
Signature
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<TABLE>
PART 1. FINANCIAL INFORMATION
- -----------------------------
ITEM 1. FINANCIAL STATEMENTS.
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NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
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<CAPTION>
THREE MONTHS ENDED MARCH 31,
---------------------------
1995 1994
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(In thousands of dollars)
<S> <C> <C>
OPERATING REVENUES:
Electric $ 881,920 $ 933,717
Gas 242,893 301,841
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1,124,813 1,235,558
OPERATING EXPENSES:
Operation:
Fuel for electric generation 39,278 62,125
Electricity purchased 291,999 275,360
Gas purchased 126,479 175,084
Other operation expense 154,814 172,684
Maintenance 44,766 47,493
Depreciation and amortization 78,316 75,406
Federal and foreign income taxes 78,372 88,304
Other taxes 132,384 135,754
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946,408 1,032,210
OPERATING INCOME 178,405 203,348<PAGE>
<PAGE>
OTHER INCOME AND (DEDUCTIONS):
Allowance for other funds used
during construction - 765
Federal and foreign income taxes (8,805) 2,340
Other items (net) 16,075 2,966
---------- ----------
7,270 6,071
INCOME BEFORE INTEREST CHARGES 185,675 209,419
INTEREST CHARGES:
Interest on long-term debt 63,349 68,584
Other interest 7,132 3,985
Allowance for borrowed funds used
during construction (3,542) (1,614)
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66,939 70,955
NET INCOME 118,736 138,464
Dividends on preferred stock 10,215 7,016
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BALANCE AVAILABLE FOR COMMON STOCK $ 108,521 $ 131,448
Average number of shares of common
stock outstanding
(in thousands) 144,324 142,498
Balance available per average
share of common stock $ .75 $ .92
Dividends paid per share of common
stock .28 .25
/TABLE
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<TABLE>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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CONSOLIDATED BALANCE SHEETS
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<CAPTION>
MARCH 31, 1995
(UNAUDITED) DECEMBER 31, 1994
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(In thousands of dollars)
<S> <C> <C>
UTILITY PLANT:
Electric plant $ 8,364,434 $ 8,285,263
Nuclear fuel 510,884 504,320
Gas plant 938,285 922,459
Common plant 298,824 291,962
Construction work in progress 426,419 481,335
Total utility plant 10,538,846 10,485,339
Less-Accumulated depreciation and 3,518,842 3,449,696
amortization ---------- ----------
Net utility plant 7,020,004 7,035,643
OTHER PROPERTY AND INVESTMENTS 136,975 224,039
<PAGE>
<PAGE>
CURRENT ASSETS:
Cash, including temporary cash investments
of $82,674 and $50,052, respectively 100,186 94,330
Accounts receivable (less-allowance for
doubtful accounts of $3,600) 344,049 317,282
Unbilled revenues 189,000 196,700
Electric margin recoverable 66,796 66,796
Materials and supplies, at average cost:
Coal and oil for production of electricity 26,086 31,652
Gas storage 12,493 30,931
Other 148,119 150,186
Prepaid taxes 78,215 43,249
Other prepayments 32,361 45,189
997,305 976,315
REGULATORY AND OTHER ASSETS (Note 3):
Unamortized debt expense 148,785 153,047
Deferred recoverable energy costs 37,291 62,884
Deferred finance charges 239,880 239,880
Income taxes recoverable 465,109 465,109
Recoverable environmental restoration costs 237,300 240,000
Other 268,808 252,522
1,397,173 1,413,442
$ 9,551,457 $ 9,649,439
/TABLE
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<TABLE>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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CONSOLIDATED BALANCE SHEETS
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CAPITALIZATION AND LIABILITIES
- ------------------------------
<CAPTION>
MARCH 31, 1995 DECEMBER
(UNAUDITED) 31, 1994
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(In thousands of dollars)
<S> <C> <C>
CAPITALIZATION:
COMMON STOCKHOLDERS' EQUITY:
Common stock - $1 par value; authorized
185,000,000 shares; issued 144,330,482 and
144,311,466 shares, respectively $ 144,330 $ 144,311
Capital stock premium and expense 1,780,299 1,779,504
Retained earnings 606,691 538,583
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2,531,320 2,462,398
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<PAGE>
<PAGE>
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
276,000 shares 25,800 25,800
CUMULATIVE PREFERRED STOCK, AUTHORIZED 19,600,000
SHARES, $25 PAR VALUE:
Non-redeemable (optionally redeemable),
issued 3,200,000 shares 80,000 80,000
Redeemable (mandatorily redeemable), issued
9,574,005 shares 230,200 230,200
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546,000 546,000
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Long-term debt 3,190,174 3,297,874
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Total capitalization 6,267,494 6,306,272
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<PAGE>
<PAGE>
CURRENT LIABILITIES:
Short-term debt 379,000 416,750
Long-term debt due within one year 77,337 77,971
Sinking fund requirements on redeemable
preferred stock 10,950 10,950
Accounts payable 223,287 277,782
Payable on outstanding bank checks 26,008 64,133
Customers' deposits 14,534 14,562
Accrued taxes 93,672 43,358
Accrued interest 68,489 63,639
Accrued vacation pay 36,915 36,550
Other 80,040 77,818
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1,010,232 1,083,513
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REGULATORY AND OTHER LIABILITIES:
Accumulated deferred income taxes 1,321,175 1,258,463
Deferred finance charges 239,880 239,880
Employee pension and other benefits 237,418 235,741
Unbilled revenues 60,411 93,668
Deferred pension settlement gain 50,261 50,261
Other 124,586 141,641
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2,033,731 2,019,654
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COMMITMENTS AND CONTINGENCIES (NOTES 2 AND 3):
Liability for environmental restoration 240,000 240,000
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$9,551,457 $9,649,439
========== ==========
/TABLE
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<TABLE>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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CONSOLIDATED STATEMENTS OF CASH FLOWS
- -------------------------------------
INCREASE (DECREASE) IN CASH (UNAUDITED)
- ---------------------------------------
<CAPTION>
THREE MONTHS ENDED MARCH 31,
1995 1994
------------- ------------
(In thousands of dollars)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 118,736 $ 138,464
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 78,316 75,406
Amortization of nuclear fuel 5,233 9,601
Provision for deferred Federal income taxes 50,026 31,218
Electric margin recoverable - (10,679)
Gain on sale of subsidiary (8,901) -
Deferred recoverable energy costs 25,593 28,149
Unbilled revenues (25,557) -
Increase in net accounts receivable (26,767) (93,382)
Decrease in materials and supplies 25,244 28,959
Decrease in accounts payable and accrued expenses (64,563) (62,131)
Increase in accrued interest and taxes 55,164 87,800
Changes in other assets and liabilities (49,227) (52,587)
---------- ----------
NET CASH PROVIDED BY OPERATING ACTIVITIES 183,297 180,818
---------- ----------
<PAGE>
<PAGE>
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction additions (68,100) (64,050)
Nuclear Fuel (6,564) -
---------- ----------
Acquisition of utility plant (74,664) (64,050)
(Increase) decrease in materials and supplies
related to construction 827 (1,374)
Decrease in accounts payable and accrued
expenses related to construction (16,141) (15,533)
Net proceeds from sale of subsidiary 161,087 -
Increase in other investments (51,245) (21,841)
Other 1,316 (3,045)
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NET CASH PROVIDED BY (USED IN)
INVESTING ACTIVITIES 21,180 (105,843)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the sale of common stock 284 5,203
Issuance of long-term debt - 210,000
Net change in short-term debt and revolving
credit agreements (136,750) (191,015)
Dividends paid (50,628) (42,625)
Reductions in long-term debt - (8,414)
Other (11,527) (3,578)
---------- ----------
NET CASH USED IN FINANCING ACTIVITIES (198,621) (30,429)
---------- ----------
<PAGE>
<PAGE>
NET INCREASE IN CASH 5,856 44,546
Cash at beginning of period 94,330 124,351
---------- ----------
CASH AT END OF PERIOD $ 100,186 $ 168,897
========== ==========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid $ 67,047 $ 64,987
Income taxes paid (refunded) (19,210) 11,308
</TABLE>
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NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. The Company, in the opinion of management, has included
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 1995 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, 1994, 1993 and 1992 included in the Company's
1994 Annual Report to Shareholders on Form 10-K.
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
period ended March 31, 1995, should not be taken as an
indication of earnings for all or any part of the balance
of the year.
2. CONTINGENCIES.
ENVIRONMENTAL ISSUES: The public utility industry
typically utilizes and/or generates in its operations a
broad range of 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 assure compliance with such requirements.
The Company is also currently conducting a program to
investigate and restore, as necessary to meet current
environmental standards, certain properties associated with
its former gas manufacturing process 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 89 sites with which it
has been or may be associated, including 47 which are
Company-owned. With respect to non-owned sites, the
Company may be required to contribute some proportionate
share of remedial costs.
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 required for site restoration and (3)
where appropriate, identify other parties who should bear
some or all of the cost of remediation. Legal action
against such other parties, if necessary, will be
initiated. After site investigations are completed, the
Company expects to determine site-specific remedial actions
and to estimate the attendant costs for restoration.
However, since technologies are still developing and the
Company has not yet undertaken full-scale remedial actions
at any identified sites, nor have any detailed remedial
designs been prepared or submitted to appropriate
regulatory agencies, the ultimate cost of remedial actions
may change substantially.
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, and the Environmental Protection
Agency figure for average cost to remediate a site. 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 in certain of these Potentially Responsible
Party (PRP) sites and is contesting liability accordingly.
As a consequence of site characterizations and assessments
completed to date and negotiations with PRP's, the Company
has accrued a liability of $240 million, representing the
low end of the range of its share of the estimated cost for
investigation and remediation. The potential high end of
the range is presently estimated at approximately $1
billion, including approximately $500 million assuming the
unlikely event the Company is required to assume 100%
responsibility at non-owned sites.
In the Company's 1995 rate order, costs incurred during
1995 for the investigation and restoration of Company-owned
sites and sites with which it is associated will be subject
to 80%/20% (ratepayer/Company) sharing. In 1995, the
Company estimates it will incur $13.5 million of such
costs, resulting in a potential disallowance of
approximately $2.7 million (before tax), which the Company
has accrued as a loss in Other items (net) on the
Consolidated Statements of Income. The accrued loss will
be subject to adjustment based on actual expenditures made
in 1995. The New York State Public Service Commission
(PSC) stated in its order that the decision to require
sharing will be revisited for 1996 and beyond in multi-year
negotiations. Accordingly, if the 80%/20% (ratepayer/
Company) sharing were to continue to be applied to rate
years beyond 1995, the Company would be required to write
off 20% of its regulatory asset associated with
environmental restoration costs. A generic PSC study of
this matter is in process, the results of which are
expected to be available for consideration in the Company's
multi-year rate negotiations. At this time the Company is
unable to predict the outcome of the study. The Company
has recorded a regulatory asset representing the
remediation obligations to be recovered from ratepayers.
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. The Company is unable to predict whether such
insurance claims will be successful.
TAX ASSESSMENTS: The Internal Revenue Service (IRS) has
conducted an examination of the Company's Federal income
tax returns for the years 1987 and 1988 and has submitted a
Revenue Agents' Report to the Company. The IRS has
proposed various adjustments to the Company's federal
income tax liability for these years which could increase
Federal income tax liability by approximately $80 million,
before assessment of penalties and interest. Included in
these proposed adjustments are several significant issues
involving Nine Mile Point Nuclear Station Unit No. 2 (Unit
2). The Company is vigorously defending its position on
each of the issues, and submitted a protest to the IRS in
1993. Pursuant to the Unit 2 settlement entered into with
the PSC in 1990, to the extent the IRS is able to sustain
adjustments, the Company will be required to absorb a
portion of any assessment. The Company believes any such
disallowance will not have a material impact on its
financial position or results of operations. The Company
is currently attempting to negotiate a settlement of these
issues with the Appeals Division of the IRS.
LITIGATION: In March 1993, a complaint was filed in the
Supreme Court of the State of New York, Albany County,
against the Company and certain of its officers and
employees. The plaintiff, Inter-Power of New York, Inc.
(Inter-Power), alleges, among other matters, fraud,
negligent misrepresentation and breach of contract in
connection with the Company's alleged termination of a
power purchase agreement 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 July 1994, the New York Supreme Court dismissed Inter-
Power's complaint for lack of merit. In August 1994,
Inter-Power filed a notice of appeal from this decision.
Inter-Power filed its Appellant's Brief in February of
1995. The Company submitted its Appellate Brief on March
30, 1995 and Inter-Power submitted its Reply Brief on April
17, 1995. The Appellate Division has scheduled oral
argument on this appeal for June 6, 1995. The Company
believes it has meritorious defenses and will continue to
defend the lawsuit vigorously.
In November 1993, Fourth Branch Associates Mechanicville
(Fourth Branch) filed suit against the Company and several
of its officers and employees in the New York Supreme
Court, Albany County, seeking compensatory damages of $50
million, punitive damages of $100 million and injunctive
and other related relief. The suit 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 defendants filed a motion to dismiss Fourth
Branch's complaint. This motion has yet to be decided.
The Company believes it has meritorious defenses and will
continue to defend the lawsuit vigorously. Fourth Branch
has filed for protection under Chapter 11 of the Bankruptcy
Code in the Bankruptcy Court for the Northern District of
New York.
The Medina Power Company is an independent power project
with a contract requiring it to be a qualifying facility
(QF) under federal law or face a contractual penalty.
Having come on-line without a steam host, Medina did not
meet this QF requirement, subjecting it to a 15% rate
reduction. The Company advised Medina that it had
exercised its contract right and reduced the rate
accordingly. Medina filed suit against the Company on June
8, 1994 in Federal District Court, Western District of New
York seeking $40 million in compensatory damages, a
trebling of this amount to $120 million under the New York
State antitrust laws, and $100 million in punitive damages.
The Company believes Medina's case is without merit, but
cannot predict the outcome of this action.
The Company is involved in a number of court cases
regarding the price of energy it is required to purchase in
excess of contract levels from certain unregulated
generators ("overgeneration"). The Company has paid the
unregulated generators based on its short-run avoided cost
(under Service Class No. 6) for all such overgeneration
rather than the price which the unregulated generators
contend is applicable under the contracts. The Company
cannot predict the outcome of these actions, but will
continue to aggressively press its position.
The Company believes it has meritorious defenses and
intends to defend the above lawsuits vigorously, but can
neither provide any judgment regarding the likely outcome
nor provide any estimate or range of possible loss.
Accordingly, no provision for liability, if any, that may
result from these suits has been made in the Company's
financial statements.
3. RATE AND REGULATORY ISSUES AND CONTINGENCIES.
In accordance with Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation," (SFAS No. 71), the Company's
financial statements reflect assets and costs based on
ratemaking conventions, as approved by the PSC and the
Federal Energy Regulatory Commission (FERC). Certain
expenses and credits, normally reflected in income as
incurred, are only recognized when included in rates and
recovered from or refunded to customers. Virtually all
costs of this nature which were determined by the
regulators to have been prudently incurred have been
recoverable through rates in the course of normal
ratemaking procedures and the Company believes that the
items currently deferred on its consolidated balance sheet
should be afforded similar treatment.
Continued accounting under SFAS No. 71 requires, among
other things, that rates be designed to recover specific
costs of providing regulated services and products and that
it be reasonable to assume that rates are set at levels
that will recover a utility's costs and can be charged to
and collected from customers. When a utility determines it
can no longer apply the provisions of SFAS No. 71 to all or
a part of its operations, it must eliminate from its
balance sheet the effects of actions of regulators that had
been recorded previously as assets and liabilities pursuant
to SFAS No. 71, but which would have not been so accounted
for by enterprises in general.
The Company's proposed multi-year rate plan for 1996-1999
contemplates no change in this approach to such reporting,
even though the plan recognizes that in a more competitive
environment an effective response to the general pressure
to manage costs and preserve or expand markets is vital to
maintaining profitability. The Company's proposed plan
includes the establishment of rates for 1995 on a cost of
service basis, followed by an index-based approach to rates
for 1996 through 1999. The index is based on inflation
factors believed to be indicative of cost increases to be
experienced by the Company. The proposal for 1996-1999
also includes adjustment factors related to events outside
the Company's control and a mechanism for resetting rates
if the expected return on equity falls below a minimum
threshold. Therefore, the Company believes that it can
continue to apply SFAS No. 71 under its multi-year rate
proposal.
The PSC Staff has proposed a multi-year ratesetting plan
which the Company believes would require writing down
certain assets and recognition of a loss on uneconomic
unregulated generator contracts, would not permit the
continued application of SFAS No. 71 to its generation
operations and may similarly jeopardize application of SFAS
No. 71 to its transmission and distribution operations
under certain circumstances. The PSC Staff has proposed
the use of an index based on the annual change in a
national average electricity price. Among other things,
the PSC Staff's plan would limit, in increasing amounts,
the amount of embedded generation costs (including certain
plant and unregulated generator costs) that could be
charged to customers. The Company would be forced to
absorb the difference between its embedded costs and what
it would charge customers, regardless of whether its past
practices were prudent or even mandated by government
action. Rates with respect to the Company's costs of
transmission, distribution and customer service would
continue to be based on cost of service for 1995, but would
be indexed in 1996-1999 by the national average electricity
index. In the event that the Company is required to write
down its assets, recognize a loss on uneconomic unregulated
generator contracts and/or could no longer apply SFAS No.
71 to either its generation operations or to its entire
electric business, a material adverse effect on its
financial condition and results of operations would result.
The Company believes the financial consequences would be of
an order of magnitude that would adversely affect the
Company's financial position and results of operations, its
ability to access the capital markets on reasonable and
customary terms, its dividend paying capacity, its ability
to continue to make payments to unregulated generators and
its ability to maintain current levels of service to its
customers.
In March 1995, the Financial Accounting Standards Board
issued Statement of Financial Accounting Standard No. 121,
"Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of" (SFAS No. 121). SFAS
No. 121 requires companies, including utilities, to assess
the need to recognize a loss whenever events or
circumstances occur which indicate that the carrying amount
of an asset may not be fully recoverable. An impairment
loss would be recognized if the sum of the future
undiscounted net cash flows expected to be generated by an
asset is less than its book value. SFAS No. 121 also
amends SFAS No. 71 to require write off of a regulatory
asset if it is no longer probable that future revenues will
recover the cost of the asset.
SFAS No. 121, which is applicable in 1996, may have
consequences to a number of utilities, including the
Company, which are facing growing competitive threats that
may erode future prices, and which have relatively high-
cost nuclear generating assets and unregulated generator
contracts. As discussed above, the Company is faced with
ratemaking proposals by the PSC Staff in the multi-year
rate case that would likely result in asset impairment
issues under the provisions of SFAS No. 121 such a proposal
is adopted by the PSC. In the context of the Company's
recently issued 1995 rate order, the Company believes the
effects of adoption of SFAS No. 121 to be immaterial.
While the Company has not yet fully assessed the financial
consequences of applying the provisions of SFAS No. 121, if
the PSC Staff's proposal in the multi-year plan is adopted,
it would have a material adverse effect on the Company's
financial position and results of operations.
On March 29, 1995, FERC issued a Notice of Proposed
Rulemaking (NOPR) on Open Access Non-Discriminatory
Transmission Services by Public Utilities and Transmitting
Utilities and a supplemental NOPR on Recovery of Stranded
Costs.
The rules proposed in the NOPR are intended to facilitate
competition among generators for sales to the bulk power
supply market. If adopted, the NOPR on open access
transmission would require public utilities under the
Federal Power Act to provide open access to their
transmission systems and would establish guidelines for
their doing so. All public utilities would provide such
services pursuant to a generic set of transmission tariff
terms and conditions established in the rulemaking
proceeding. Thus, a final rule would define the terms
under which independent power producers, neighboring
utilities, and others could gain access to a utility's
transmission grid to deliver power to wholesale customers,
such as municipal distribution systems, rural electric
cooperatives, or other utilities. Under the NOPR, each
public utility would also be required to establish separate
rates for its transmission and generation services for new
wholesale service, and to take transmission services
(including ancillary services) under the same tariffs that
would be applicable to third-party users for all of its new
wholesale sales and purchases of energy.
The supplemental NOPR on stranded costs provides a basis
for recovery by regulated public utilities of legitimate
and verifiable stranded costs associated with exiting
wholesale customers and retail customers who become
unbundled wholesale transmission customers of the utility.
FERC would provide public utilities a mechanism for
recovery of stranded costs that result from
municipalization, former retail customers becoming
wholesale customers, or the loss of a wholesale customer.
FERC will consider allowing recovery of stranded investment
costs associated with retail wheeling only if a state
regulatory commission lacks the authority to consider that
issue.
The Company is currently evaluating the NOPR to determine
its impact on the Company and its customers. Comments on
the NOPR are due August 7, 1995. It is anticipated that a
final rule could take effect in early 1996. The Company
cannot predict the outcome of this matter or its effect on
the Company's results of operations or financial condition.
<PAGE>
<PAGE>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
REVIEW BY INDEPENDENT ACCOUNTANTS
The Company's independent accountants, Price Waterhouse 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 March 31, 1995 and the unaudited
Consolidated Statements of Income and Cash Flows for the three-
month periods ended March 31, 1995 and 1994. 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. Price
Waterhouse 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.<PAGE>
<PAGE>
PRICE WATERHOUSE LLP
ONE MONY PLAZA
SYRACUSE NY 13202
TELEPHONE 315-474-6571
REPORT OF INDEPENDENT ACCOUNTANTS
May 8, 1995
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 March
31, 1995, and the related condensed consolidated statements of
income and cash flows for the three-month periods ended March 31,
1995 and 1994. 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 have previously audited, in accordance with generally accepted
auditing standards, the consolidated balance sheet at December
31, 1994, and the related consolidated statements of income,
retained earnings and cash flows for the year then ended (not
presented herein); and in our report dated February 1, 1995, we
expressed an unqualified opinion (containing an explanatory
paragraph relating to the Company's involvement as a defendant in
lawsuits relating to actions with respect to certain purchased
power contracts) on those consolidated financial statements. In
our opinion, the information set forth in the accompanying
condensed consolidated balance sheet as of December 31, 1994 is
fairly stated, in all material respects, in relation to the
consolidated balance sheet from which it has been derived.
As discussed in Note 3, certain representatives of the New York
Public Service Commission have proposed a plan to establish the
Company's rates for its electric business based on a transition
plan to market-based prices rather than based on the Company's
costs. If this proposal or certain provisions thereof are
implemented as proposed, the Company would be required to write
down certain assets, recognize a loss on uneconomic unregulated
generator contracts and/or discontinue the application of
Statement of Financial Accounting Standards No. 71, "Accounting
for the Effects of Certain Types of Regulation" (SFAS No. 71),
with respect to portions of the Company's business. Such
writedowns or losses could have a material adverse effect on the
Company's financial position and results of operations. Because
the outcome of these matters cannot be predicted, the
accompanying financial statements do not include any adjustments
that might result from the resolution of these proceedings.
/s/ Price Waterhouse LLP
- ------------------------<PAGE>
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
1995 FIVE-YEAR RATE PLAN
See Form 10-K for fiscal year ended December 31, 1994, Item 1.,
1995 Five-Year Rate Plan.
Through its Brief Opposing Exceptions dated March 2, 1995, the
Company had requested an increase in 1995 electric revenues of
approximately $110 million (3.5%) and an increase in 1995 gas
revenues of $16.4 million (2.7%).
On April 21, 1995, the Company received a rate decision from the
PSC which approved an approximately $47 million increase in
electric revenues and a $4.9 million increase in gas revenues.
The bill impact to customers is a 1.5% increase for electric (a
3.4% increase for residential and a 1.6% decrease for large
industrial) and an 0.8% increase for gas.
The rate order allows the Company to retain its fuel adjustment
clause mechanism, although the electric revenue adjustment
mechanism (NERAM) was discontinued.
While the decision eliminates the administrative law judges'
recommended disallowance associated with purchases from and
buyouts of unregulated generators, it retains performance-based
penalties related to customer service quality and demand-side
management.
Further, the decision allocates to ratepayers all of the $58.4
million of savings associated with the Company's 1994 voluntary
employee reduction program. While the Company's March 2, 1995
update assumed such an allocation, capturing all of these
savings, in combination with other adjustments made by the PSC,
puts added pressure on the Company's 1995 earnings levels.
The rate decision establishes allowed returns on equity of 11.0
percent in the electric case and 11.4 percent in the gas case.
However, the Company believes, based on its analysis of the rate
order, that its overall return on equity in 1995, including
anticipated Measured Equity Return Incentive Term (MERIT) awards,
will range between 8.5 percent and 9.5 percent.
The rate order also addresses the Company's multi-year electric
rate proceeding. The PSC stated that the parties to this phase
must address how to maintain the Company's investment-grade bond
rating, while contending with uneconomic generation and the high
cost of unregulated generator power purchases, high property
taxes, potential elimination of the fuel-adjustment clause, and
outdated governmental mandates. Rate levels and protection of
customer service quality are other key areas which must be
considered in a multi-year plan.
As evidenced in the results of the first quarter, the combination
of the elimination of NERAM and weak sales results is likely to
negatively affect the Company's revenues and earnings for 1995.
COMMON STOCK DIVIDEND
On April 13, 1995, the Board of Directors authorized a second
quarter common stock dividend of $.28 per share, which will be
paid on May 31, 1995 to shareholders of record on May 1, 1995.
The Board of Directors had previously authorized a quarterly
common stock dividend of $.28 per share on January 26, 1995 which
was paid February 28, 1995. In making future dividend decisions,
the Company must evaluate the results of the multi-year phase of
its pending rate case and the degree of competitive and political
pressure on its prices and, therefore, on its future earnings.
UNREGULATED GENERATORS
See Form 10-K for fiscal year ended December 31, 1994, Item 1.,
Unregulated Generators.
In recent years, a leading factor in the increases in customer
bills and the deterioration of the Company's competitive position
has been the requirement to purchase power from unregulated
generators at prices in excess of the Company's internal cost of
production and in volumes greater than the Company's needs.
For the quarter ended March 31, 1995, unregulated generator
purchases were approximately $264 million compared to
approximately $235 million in 1994. In the first quarter of
1995, unregulated generator purchases provided approximately 38%
of the Company's power supply while constituting 77% of the
Company's fuel and purchased power costs.
On January 11, 1995, FERC issued an order in a case involving
Connecticut Light & Power (CL&P) that Public Utility Regulatory
Policy Act forbids the states from requiring utilities to pay
more than avoided cost to qualifying facilities (QFs) for
electric power. FERC, however, also ruled that it would not
invalidate any pre-existing contracts, but only would apply its
ruling prospectively or to contracts that were subject to a
pending challenge (instituted at the time of signing) by a
utility. On the same day, FERC issued an order that an ongoing
challenge by the Company to the New York Law requiring utilities
to pay QFs a minimum of six cents for electric power (the Six
Cent Law) was moot in light of amendment of that law in 1992 to
prohibit future power purchase contracts requiring the utility to
pay more than its avoided cost. This latter proceeding had been
initiated in 1987. In April 1988, FERC had ruled in the
Company's favor, finding that the states could not impose rates
exceeding avoided cost for purchases from QFs, but then stayed
that decision in light of a rulemaking it was instituting to
address the issue. That rulemaking was never completed.
On February 10, 1995, the Company filed a petition for rehearing
of both orders. The Company argued, among other things, that
Federal law requires FERC to apply the ruling in CL&P in all
pending cases, including its case involving the Six Cent Law, and
that it is entitled to the opportunity, either at FERC or in the
courts, to demonstrate that pre-existing power purchase contracts
resulting from the Six Cent Law should be invalidated. The
Company argued further that amendment of the Six Cent Law did not
render the proceeding addressing that law moot because the
amendment has perpetuated and, in some instances, expanded the
Company's obligation to purchase power from QFs at rates above
avoided cost. On April 12, 1995, FERC denied the Company's
petitions. On April 21, 1995, the Company filed its petitions
for review of FERC's denials of its petitions for rehearing. The
Company otherwise intends to press its rights vigorously in the
courts.
During April 1995, FERC also ruled against New York State
Electric and Gas Corp. (NYSEG) in a case involving contracts with
unregulated generators, despite NYSEG's position that the
unregulated generators' rates exceeded avoided costs. The PSC
supported NYSEG in the case, in which the utility sought to
revise long-term contracts signed in 1990 to buy up to 44
megawatts from two unregulated generators. NYSEG argued that the
costs it used to calculate the rates were no longer valid because
cheaper power was now available and the excess contract prices
impose a harsh burden on its electric customers.
FINANCING PLANS AND FINANCIAL POSITION
The Company's ability to issue more common stock to improve its
capital structure is limited by the uncertainties that have
depressed the stock's price. The Company would not likely pursue
a new issue offering unless the common stock price was closer to
book value. External financing is projected to consist of
approximately $400 to $600 million of First Mortgage Bonds in
1995, including $200 to $300 million, depending on market
conditions, expected to be issued during May 1995. Depending on
the outcome of the multi-year rate case, cash provided by
operations is generally expected to provide sufficient funds for
the Company's anticipated construction program for 1996-1999.
External financing plans are subject to periodic revision as
underlying assumptions are changed to reflect developments, most
importantly in the Company's rate proceedings. The ultimate
level of financing during this four-year period will reflect,
among other things, the extent and timing of rate relief, the
Company's competitive positioning, and the extent to which
competition penetrates the Company's markets, uncertain energy
demand due to economic conditions and capital expenditures
relating to distribution and transmission load reliability
projects, as well as continued expansion of the gas business.
The Company believes that traditionally available sources of
financing should be sufficient to satisfy the Company's external
financing needs during the period 1995 through 1999, depending on
the outcome of the multi-year rate case. At May 1, 1995, the
Company could issue an additional $2,548 million aggregate
principal amount of First Mortgage Bonds. This includes
approximately $1,311 million from retired bonds without regard to
an interest coverage test and approximately $1,237 million
supported by additional property currently certified and
available, assuming a 10% interest rate, under the applicable
tests set forth in the Company's mortgage trust indenture. The
Company also has $200 million of Preference Stock authorized for
sale. Under its Charter, the Company is restricted from issuing
preferred stock at May 1, 1995, due to insufficient coverage
ratios. The Company continues to explore and utilize, as
appropriate, other methods of raising funds. The Company's
Charter restricts the amount of unsecured indebtedness that may
be incurred by the Company to 10% of consolidated capitalization
plus $50 million. The Company has not reached this restrictive
limit.
On May 10, 1995, Moody's Investors Service (Moody's) downgraded
the Company's rating on secured debt from Baa2 to Baa3. This
action changed the Company's security rating on secured debt to
the lowest investment grade rating. The security rating on
preferred stock was changed from baa3 to ba1, which changed the
Company's security rating on preferred stock from a lowest
investment grade rating to a below investment grade rating. The
commercial paper rating was changed from P-2 to P-3. Moody's
cited, among other things, the impact of the Company's high-cost
structure (namely, unregulated generator obligations and taxes)
on its competitive profile which, coupled with a stagnant service
territory economy and excess capacity in the region, limited
sales growth and financial improvement. Moody's also indicated
that the rating outlook remains negative.
On May 12, 1995, Standard and Poors (S&P) affirmed its security
ratings on the Company's securities, which are comparable to
Moody's revised ratings. However, S&P removed the Company from
its "CreditWatch" list in light of recent positive regulatory
actions in New York state. S&P cited similar concerns as those
expressed by Moody's, in retaining a negative rating outlook for
the Company's securities.
Cash flows to meet the Company's requirements for the first three
months of 1995 and 1994 are reported in the Consolidated
Statements of Cash Flows on Page 6. The Company received
approximately $207 million in January 1995 related to the sale of
the Company's subsidiary, HYDRA-CO Enterprises, Inc. (HYDRA-CO).,
which was used to repay short-term debt.
Ordinarily, construction-related short-term borrowings are
refunded with long-term securities on a periodic basis. This
approach generally results in the Company showing a working
capital deficit. Working capital deficits may also be
temporarily created as a result of the seasonal nature of the
Company's operations as well as timing differences between the
collection of customer receivables and the payment of fuel and
purchased power costs. Recently the Company has experienced a
deterioration in its collections as compared to prior years'
experience. However, the Company has sufficient borrowing
capacity to fund such deficits as necessary.
MATERIAL CHANGES IN RESULTS OF OPERATIONS
Three Months Ended March 31, 1995 versus Three Months Ended March
- -----------------------------------------------------------------
31, 1994
- --------
The following discussion presents the material changes in results
of operations for the first quarter of 1995 in comparison to the
same period in 1994. The Company's quarterly 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 month
period should not be taken as an indication of earnings for all
or any part of the balance of the year.
Earnings for the first quarter were $108.5 million or $.75 per
share, including the gain of approximately $9 million on the sale
of HYDRA-CO, as compared with $131.4 million or $.92 per share in
1994. Earnings for the first quarter of 1995 were impacted by
lower sales of electricity and natural gas due in part to warmer-
than-normal weather. As of January 1995, NERAM was discontinued.
First quarter 1994 earnings included $10.7 million of margin
recorded under this mechanism.
As shown in the table below, electric revenues, including
revenues recorded to reflect the rate decision received in April
1995 retroactive to January 1, 1995, decreased $51.8 million or
5.5% from 1994. The revenue recorded reflected the retroactive
portion of the rate decision which was accomplished by recording
$26.4 million of unbilled revenues, which are non-cash revenues.
The increase in demand-side management (DSM) revenues relates to
a one-time, non-cash adjustment of prior years' DSM incentive revenues.
Sales to other electric systems and sales to ultimate consumers
reflect reduced demand associated with the warmer-than-normal
weather experienced during the first quarter of 1995.
Increase in base rates $ 26.4 million
DSM revenues 15.4
NERAM revenues (10.7)
Sales to other electric systems (26.6)
Sales to ultimate consumers (56.3)
------
$(51.8) million
=======
Electric kilowatt-hour sales to ultimate consumers were
approximately 8.9 billion in the first quarter of 1995, a 5.8%
decrease from 1994 primarily as a result of warmer-than-normal
weather. After adjusting for the effects of weather, sales to
ultimate consumers decreased 2.4%. Sales for resale decreased
835 million kilowatt-hours (45.5%) resulting in a net decrease in
total electric kilowatt-hour sales of 1,384 million (12.3%).
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
REVENUES (Thousands) SALES (GwHrs)
---------------------------------- --------------------------
% %
1995 1994 Change 1995 1994 Change
<S> <C> <C> <C> <C> <C> <C>
Residential $ 337,821 $ 372,769 ( 9.4) 2,924 3,268 (10.5)
Commercial 318,411 339,620 ( 6.2) 3,035 3,301 ( 8.1)
Industrial 132,881 138,420 ( 4.0) 1,779 1,782 ( 0.2)
Industrial - Special 14,094 12,317 14.4 1,064 999 6.5
Municipal 12,972 12,853 0.9 59 60 ( 1.7)
Total to Ultimate
Customers 816,179 875,979 ( 6.8) 8,861 9,410 ( 5.8)
Other Electric Systems 24,408 50,981 (52.1) 999 1,834 (45.5)
Miscellaneous 41,333 6,757 511.7 - - -
---------- --------- ------ ----- ------- ------
TOTAL $ 881,920 $ 933,717 ( 5.5) 9,860 11,244 (12.3)
========== ========= ====== ===== ====== ======
/TABLE
<PAGE>
<PAGE>
Electric fuel and purchased power costs decreased $6.2 million or
1.8%. This decrease is the result of a decrease in fuel costs of
$18.4 million and a $6.1 million net decrease in costs deferred
and recovered through the operation of the fuel adjustment
clause, offset by a $18.3 million increase in purchased power
costs (including increased payments to unregulated generators of
$28.9 million or 12.3%). The decrease in fuel costs reflects a
21.2% decrease in Company generation due to greater unregulated
generator purchase requirements and reduced demand, which reduced
the need to operate the fossil plants during the first three
months of 1995, even after taking into account the 1995 Nine Mile
Point Nuclear Station Unit No. 1 (Unit 1) refueling outage.
On February 8, 1995, Unit 1 was taken out of service for a
planned refueling and maintenance outage. On April 4, 1995, Unit
1 returned to service. The next refueling outage is scheduled to
begin in February 1997. On April 8, 1995, Unit 2 was taken out
of service for a planned refueling and maintenance outage. The
outage is projected to last 49 days.
Gas revenues decreased $58.9 million or 19.5% in 1995 from the
comparable period in 1994 as set forth in the table below:
Transportation of customer-owned gas $ 2.7 million
Miscellaneous operating revenues (0.3)
Spot market sales (3.4)
Purchased gas adjustment clause revenues (12.0)
Sales to ultimate consumers (45.9)
--------
$(58.9) million
=======
Due to warmer-than-normal weather in the first three months of
1995, gas sales to ultimate consumers decreased 7.8 million
dekatherms or a 17.4% decrease from the first quarter of 1994.
After adjusting for the effects of weather, sales to ultimate
consumers decreased 1.0%. Transportation of customer-owned gas
increased 17.1 million dekatherms (76.8%) and was primarily
caused by Sithe Independence Power Partners, Inc. gas-fired
generating project coming on-line in the Company's service
territory. 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.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
REVENUES (Thousands) SALES (Thousands of Dekatherms)
------------------------------- -------------------------------
% %
1995 1994 Change 1995 1994 Change
<S> <C> <C> <C> <C> <C> <C>
Residential $160,462 $199,351 (19.5) 24,795 30,277 (18.1)
Commercial 66,170 82,369 (19.7) 11,286 13,287 (15.1)
Industrial 4,000 6,744 (40.7) 952 1,273 (25.2)
-------- -------- ------ ------ ------ ------
Total to Ultimate
Consumers 230,632 288,464 (20.0) 37,033 44,837 (17.4)
Other Gas Systems 462 607 (23.9) 102 129 (20.9)
Transportation of
Customer-Owned Gas 13,158 10,431 26.1 39,428 22,299 76.8
Spot Market Sales 551 3,989 (86.2) 272 1,349 (79.8)
Miscellaneous (1,910) (1,650) 15.8 - - -
---------- ------- ------ ------ ------ ------
Total to System
Core Customers $242,893 $301,841 (19.5) 76,835 68,614 12.0
========= ======== ====== ====== ====== ======
/TABLE
<PAGE>
<PAGE>
The total cost of gas included in expense decreased 27.8% in
1995. This was the result of a 8.5 million decrease in
dekatherms purchased and withdrawn from storage for ultimate
consumer sales ($26.0 million) and a 1.1 million decrease in
dekatherms purchased for spot market sales, coupled with a 15.3%
decrease in the average cost per dekatherm purchased ($17.6
million) and a $1.9 million decrease in purchased gas costs and
certain other items recognized and recovered through the
purchased gas adjustment clause. The Company's net cost per
dekatherm sold, as charged to expense and excluding spot market
purchases, decreased to $3.35 in 1995 from $3.72 in 1994.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31,
(In Millions)
-----------------------------------------------
Increase %
1995 1994 (Decrease) Change
<S> <C> <C> <C> <C>
Other operation expense $154,814 $172,684 $ (17,870) (10.4)
Maintenance 44,766 47,493 (2,727) (5.7)
Depreciation and amortization 78,316 75,406 2,910 3.9
Federal and foreign income taxes, net 87,177 85,964 1,213 1.4
Other taxes 132,384 135,754 (3,370) (2.5)
Other items (net) 16,075 2,966 13,109 442.0
Interest charges 70,481 72,569 (2,088) (2.9)
/TABLE
<PAGE>
<PAGE>
Other operation expense decreased as planned under the Company's
cost reduction effort, offset by an increase in nuclear costs of
approximately $7.0 million from the Unit 1 refueling outage in
the first quarter of 1995.
Maintenance expense also decreased as planned under the Company's
cost reduction effort, offset by higher nuclear costs of
approximately $5.6 million because of the Unit 1 refueling outage
in the first quarter of 1995.
Depreciation and amortization increased due to additions to plant
in service.
The increase in Federal income taxes (net) was related to the
sale of HYDRA-CO ($12.7 million).
Other taxes decreased, primarily due to the decrease in employees
which was reflected in lower payroll taxes ($2.0 million), and
the decrease in revenue which was reflected in lower revenue
taxes ($2.2 million), offset by increased real estate taxes of
approximately $1.4 million for the first quarter of 1995.
Other items (net) increased, primarily due to the sale of HYDRA-
CO ($21.6 million). The after-tax gain on the sale of HYDRA-CO
was approximately $8.9 million, which takes into account the
$12.7 million included in Federal income taxes above.
Interest charges decreased from 1994, primarily due to the
refunding of debt at lower interest rates.
<PAGE>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
PART II
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
At the Company's annual meeting of shareholders on May
2, 1995, (1) the election of Directors was as follows:
Withheld
For Authority
Albert J. Budney, Jr. 116,047,751 5,615,964
Edmund M. Davis 115,469,544 6,194,171
Dr. Bonnie Guiton Hill 116,904,646 4,759,069
Henry A. Panasci, Jr. 117,086,395 4,577,320
(2) A shareholder proposal relating to the preparation
of a Company report on carbon dioxide and emissions and
related regulations was rejected by a vote of 10,853,775
for, 79,196,069 against, 7,773,932 abstentions, and
23,839,939 broker non-votes.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits:
Exhibit 11 - Computation of the Average Number of Shares
of Common Stock Outstanding for the Three Months Ended
March 31, 1995 and 1994.
Exhibit 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
March 31, 1995.
Exhibit 15 - Accountants' Acknowledgement Letter.
Exhibit 27 - Financial Data Schedule.
(b) Report on Form 8-K:
Form 8-K Reporting Date - January 4, 1995.
Item Reported - Item 5. Other Events.
Registrant filed certain information on rate case status
and competition/restructuring.
Form 8-K Reporting Date - February 15, 1995.
Item Reported - Item 5. Other Events.
Registrant filed certain information concerning financial
information substantially constituting a portion of its
1994 Annual Report to Stockholders including financial
statements for the fiscal year ended December 31, 1994.
<PAGE>
<PAGE>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
NIAGARA MOHAWK POWER CORPORATION
(Registrant)
Date: May 12, 1995 By /s/ Steven W. Tasker
---------------------------
Steven W. Tasker
Vice President-Controller and
Principal Accounting Officer,
in his respective capacities
as such
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT 11
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
Computation of the Average Number of Shares of Common Stock Outstanding
For the Three Months Ended March 31, 1995 and 1994
(4)
Average Number
of Shares
Outstanding As
Shown on
Consolidated
Statement
(1) (2) (3) of Income
Shares of Number of Share (3 Divided by
Common of Days Days Number of Days
Stock Outstanding (2 x 1) in Period)
--------- ----------- ------- ---------------
FOR THE THREE MONTHS
ENDED MARCH 31: <C> <C> <C> <C>
<S>
JANUARY 1 - MARCH 31, 1995 144,311,466 90 12,988,031,940
SHARES SOLD AT VARIOUS
TIMES DURING THE PERIOD -
DIVIDEND REINVESTMENT PLAN 19,016 *<F1> 1,140,960
----------- --------------
144,330,482 12,989,172,900 144,324,143
=========== ============== ===========
<PAGE>
<PAGE>
JANUARY 1 - MARCH 31, 1994 142,427,057 90 12,818,435,130
SHARES SOLD AT VARIOUS
TIMES DURING THE PERIOD -
DIVIDEND REINVESTMENT FUND PLAN 179,301 *<F1> 5,691,034
EMPLOYEE SAVINGS FUND PLAN 100,000 *<F1> 700,000
----------- --------------
142,706,358 12,824,826,164 142,498,068
=========== ============== ===========
NOTE: Earnings per share calculated on both a primary and fully diluted basis are the same due
to the effects of rounding.
<FN>
<F1> Number of days outstanding not shown as shares represent an accumulation of weekly and
monthly sales throughout the quarter. Share days for shares sold are based on the total
number of days each share was outstanding during the quarter.
/TABLE
<PAGE>
<PAGE>
<TABLE>
EXHIBIT 12
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
<CAPTION>
Statement Showing Computation 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
March 31, 1995 (in thousands of dollars)
<S> <C>
A. Net income $ 157,255
B. Taxes Based on Income or Profits 112,682
----------
C. Earnings, Before Income Taxes 269,937
D. Fixed Charges (a) 313,079
----------
E. Earnings Before Income Taxes and
Fixed Charges 583,016
F. Allowance for Funds Used During
Construction (AFC) 10,241
----------
G. Earnings Before Income Taxes and
Fixed Charges without AFC $ 572,775
==========
<PAGE>
<PAGE>
PREFERRED DIVIDEND FACTOR:
H. Preferred Dividend Requirements $ 36,871
----------
I. Ratio of Pre-tax Income to Net
Income (C/A) 1.717
----------
J. Preferred Dividend Factor (HxI) $ 63,308
K. Fixed Charges as Above (D) 313,079
----------
L. Fixed Charges and Preferred Dividends
Combined $ 376,387
==========
M. Ratio of Earnings to Fixed
Charges (E/D) 1.86
==========
N. Ratio of Earnings to Fixed Charges
without AFC (G/D) 1.83
==========
O. Ratio of Earnings to Fixed Charges
and Preferred Dividends Combined (E/L) 1.55
==========
(a) Includes a portion of rentals deemed representative of the
interest factor ($29,289).
/TABLE
<PAGE>
<PAGE>
EXHIBIT 15
- ----------
May 8, 1995
Securities and Exchange Commission
450 Fifth Street NW
Washington D.C. 20549
Dear Sirs:
We are aware that Niagara Mohawk Power Corporation has included
our report dated May 8, 1995 (issued pursuant to the provisions
of Statement on Auditing Standards No. 71) in the Registration
Statements on Form S-8 (Nos. 33-36189, 33-42720, 33-42721, 33-
42771 and 33-54829) and in the Prospectus constituting part of
the Registration Statements on Form S-3 (Nos. 33-45898, 33-50703,
33-51073, 33-54827, 33-55546 and 33-59594). We are also aware of
our responsibilities under the Securities Act of 1933.
Yours very truly,
/s/ Price Waterhouse LLP
- ------------------------
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