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 June 30, 1994
---------------------------------------------
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 July 31, 1994 - 143,431,306
<PAGE>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
FORM 10-Q - For The Quarter Ended June 30, 1994
INDEX
Part I. Financial Information Page
Item 1. Financial Statements.
a) Consolidated Statements of Income -
Three Months and Six Months Ended
June 30, 1994 and 1993 3
b) Consolidated Balance Sheets - June 30,
1994 and December 31, 1993 5
c) Consolidated Statements of Cash Flows -
Six Months Ended June 30, 1994 and 1993 7
d) Notes to Consolidated Financial Statements 8
e) Review by Independent Accountants 17
f) Independent Accountants' Report on the
Limited Review of the Interim Financial
Information 18
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of
Operations. 19
Part II. Other Information
Item 1. Legal Proceedings. 36
Item 5. Other Events. 38
Item 6. Exhibits and Reports on Form 8-K. 45
Signature 46
<PAGE>
<TABLE>
PART 1. FINANCIAL INFORMATION
-----------------------------
ITEM 1. FINANCIAL STATEMENTS.
-----------------------------
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
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<CAPTION>
THREE MONTHS ENDED JUNE 30,
---------------------------
1994 1993
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(In thousands of dollars)
<S> <C> <C>
OPERATING REVENUES:
Electric $ 846,856 $ 801,444
Gas 132,844 127,801
979,700 929,245
OPERATING EXPENSES:
Operation:
Fuel for electric generation 52,647 53,272
Electricity purchased 269,770 204,470
Gas purchased 65,098 64,340
Other operation expense 174,024 195,703
Maintenance 46,491 51,966
Depreciation and amortization 76,942 68,616
Federal and foreign income taxes 44,982 42,854
Other taxes 119,122 115,355
849,076 796,576
OPERATING INCOME 130,624 132,669
OTHER INCOME AND (DEDUCTIONS):
Allowance for other funds used
during construction 893 1,890
Federal and foreign income taxes 2,132 4,748
Other items (net) 3,434 (2,288)
6,459 4,350
<PAGE>
INCOME BEFORE INTEREST CHARGES 137,083 137,019
INTEREST CHARGES:
Interest on long-term debt 67,277 71,440
Other interest 4,136 2,416
Allowance for borrowed funds used
during construction (1,889) (2,162)
69,524 71,694
NET INCOME 67,559 65,325
Dividends on preferred stock 7,072 8,084
BALANCE AVAILABLE FOR COMMON STOCK $ 60,487 $ 57,241
Average number of shares of common
stock outstanding
(in thousands) 142,912 140,170
Balance available per average
share of common stock $ .42 $ .41
Dividends paid per share of common
stock .28 .25
</TABLE>
<PAGE>
<TABLE>
PART 1. FINANCIAL INFORMATION
-----------------------------
ITEM 1. FINANCIAL STATEMENTS.
-----------------------------
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
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<CAPTION>
SIX MONTHS ENDED JUNE 30,
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1994 1993
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(In thousands of dollars)
<S> <C> <C>
OPERATING REVENUES:
Electric $1,780,573 $1,678,069
Gas 434,685 387,215
2,215,258 2,065,284
OPERATING EXPENSES:
Operation:
Fuel for electric generation 114,772 117,620
Electricity purchased 545,130 410,662
Gas purchased 240,182 219,343
Other operation expense 346,708 390,530
Maintenance 93,984 102,296
Depreciation and amortization 152,348 136,278
Federal and foreign income taxes 133,286 124,309
Other taxes 254,876 243,908
1,881,286 1,744,946
OPERATING INCOME 333,972 320,338
OTHER INCOME AND (DEDUCTIONS):
Allowance for other funds used
during construction 1,658 3,961
Federal and foreign income taxes 4,472 3,397
Other items (net) 6,400 2,184
12,530 14,542
<PAGE>
INCOME BEFORE INTEREST CHARGES 346,502 334,880
INTEREST CHARGES:
Interest on long-term debt 135,861 141,542
Other interest 8,121 5,525
Allowance for borrowed funds used
during construction (3,503) (4,468)
140,479 142,599
NET INCOME 206,023 192,281
Dividends on preferred stock 14,088 16,383
BALANCE AVAILABLE FOR COMMON STOCK $ 191,935 $ 175,898
Average number of shares of common
stock outstanding
(in thousands) 142,706 138,697
Balance available per average
share of common stock $ 1.34 $ 1.27
Dividends paid per share of common
stock .53 .45
</TABLE>
<PAGE>
<TABLE>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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CONSOLIDATED BALANCE SHEETS
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<CAPTION>
JUNE 30,
1994 DECEMBER 31,
(UNAUDITED) 1993
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(In thousands of dollars)
<S> <C> <C>
UTILITY PLANT:
Electric plant $ 8,140,283 $7,991,346
Nuclear fuel 457,195 458,186
Gas plant 878,168 845,299
Common plant 273,113 244,294
Construction work in progress 480,219 569,404
Total utility plant 10,228,978 10,108,529
Less-Accumulated depreciation and
amortization 3,356,338 3,231,237
Net utility plant 6,872,640 6,877,292
OTHER PROPERTY AND INVESTMENTS 254,617 221,008
CURRENT ASSETS:
Cash, including temporary cash investments
of $84,814 and $100,182, respectively 133,431 124,351
Accounts receivable (less-allowance for
doubtful accounts of $3,600) 296,022 258,137
Unbilled revenues 181,900 197,200
Electric margin recoverable 35,122 21,368
Materials and supplies, at average cost:
Coal and oil for production of electricity 22,362 29,469
Gas storage 25,776 31,689
Other 163,968 163,044
Prepaid taxes 62,808 23,879
Prepaid pension expense 39,933 37,238
Other prepayments 30,548 29,498
991,870 915,873
<PAGE>
REGULATORY AND OTHER ASSETS:
Unamortized debt expense 154,901 154,210
Deferred recoverable energy costs 27,924 67,632
Deferred finance charges 239,880 239,880
Income taxes recoverable (Note 1) 527,995 527,995
Recoverable environmental restoration costs 240,000 240,000
Other 190,099 175,187
1,380,799 1,404,904
$ 9,499,926 $9,419,077
</TABLE>
<PAGE>
<TABLE>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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CONSOLIDATED BALANCE SHEETS
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CAPITALIZATION AND LIABILITIES
------------------------------
<CAPTION>
JUNE 30, 1994 DECEMBER 31,
(UNAUDITED) 1993
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(In thousands of dollars)
<S> <C> <C>
CAPITALIZATION:
COMMON STOCKHOLDERS' EQUITY:
Common stock - $1 par value; authorized
185,000,000 and 150,000,000 shares,
respectively; issued 143,316,804 and
142,427,057 shares, respectively $ 143,317 $ 142,427
Capital stock premium and expense 1,772,607 1,762,706
Retained earnings 667,680 551,332
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2,583,604 2,456,465
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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 and 294,000 shares, respectively 25,800 27,600
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
4,340,005 shares and 4,840,005 shares,
respectively 83,100 95,600
398,900 413,200
Long-term debt 3,246,215 3,258,612
Total capitalization 6,228,719 6,128,277
<PAGE>
CURRENT LIABILITIES:
Short-term debt 324,001 368,016
Long-term debt due within one year 218,331 216,185
Sinking fund requirements on redeemable
preferred stock 27,200 27,200
Accounts payable 183,261 299,209
Payable on outstanding bank checks 35,342 35,284
Customers' deposits 14,591 14,072
Accrued taxes 135,565 56,382
Accrued interest 68,552 70,529
Accrued vacation pay 40,973 40,178
Other 123,093 82,145
1,170,909 1,209,200
REGULATORY AND OTHER LIABILITIES:
Accumulated deferred income taxes (Note 1) 1,356,447 1,313,483
Deferred finance charges 239,880 239,880
Unbilled revenues 79,668 94,968
Deferred pension settlement gain 56,271 62,282
Customers refund for replacement power cost
disallowance 11,541 23,081
Other 116,491 107,906
1,860,298 1,841,600
COMMITMENTS AND CONTINGENCIES (NOTE 2):
Liability for environmental restoration 240,000 240,000
$9,499,926 $9,419,077
</TABLE>
<PAGE>
<TABLE>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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CONSOLIDATED STATEMENTS OF CASH FLOWS
-------------------------------------
INCREASE (DECREASE) IN CASH (UNAUDITED)
----------------------------------------
<CAPTION>
SIX MONTHS ENDED JUNE 30,
1994 1993
------------- ------------
(In thousands of dollars)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 206,023 $ 192,281
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 152,348 136,278
Amortization of nuclear fuel 19,366 17,248
Provision for deferred Federal income taxes 42,964 7,250
Electric margin recoverable (13,754) (10,237)
Allowance for other funds used during construction (1,658) (3,961)
Deferred recoverable energy costs 39,708 39,093
Amortization of nuclear replacement power cost
disallowance (11,540) (11,860)
(Gain) loss on investments 0 (1,566)
Increase in net accounts receivable (37,885) (26,070)
Decrease in materials and supplies 12,466 25,635
Decrease in accounts payable and accrued expenses (91,773) (90,981)
Increase in accrued interest and taxes 77,206 78,153
Changes in other assets and liabilities (3,726) (12,224)
NET CASH PROVIDED BY OPERATING ACTIVITIES 389,745 339,039
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction additions (165,125) (160,796)
Nuclear fuel 991 (11,698)
Less: Allowance for other funds used during
construction 1,658 3,961
Acquisition of utility plant (162,476) (168,533)
Increase in materials and supplies
related to construction ( 370) (1,606)
Decrease in accounts payable and accrued
expenses related to construction (22,943) (22,745)
<PAGE>
Proceeds from sale of investment in oil and
gas subsidiary 0 95,408
Increase in other investments (33,188) (5,118)
Other (10,599) (2,517)
NET CASH USED IN INVESTING ACTIVITIES (229,576) (105,111)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the sale of common stock 15,386 106,663
Redemption of preferred stock (14,300) (14,300)
Issuance of long-term debt 210,000 295,000
Reductions in long-term debt (218,914) (293,383)
Net change in short-term debt (44,015) (149,597)
Dividends paid (89,675) (79,268)
Other (9,571) (16,973)
NET CASH USED IN FINANCING ACTIVITIES (151,089) (151,858)
NET INCREASE IN CASH 9,080 82,070
Cash at beginning of period 124,351 43,894
CASH AT END OF PERIOD $ 133,431 $ 125,964
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid $ 149,087 $ 152,180
Income taxes paid 63,720 63,104
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND
FINANCING ACTIVITIES:
Liability for environmental restoration - 10,000
</TABLE>
<PAGE>
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 1994 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, 1993, 1992 and 1991 included in the Company's
1993 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
and six-month periods ended
June 30, 1994, should not be taken as an indication of
earnings for all or any part of the balance of the year.
Certain amounts have been reclassified on the accompanying
Consolidated Financial Statements to conform with the 1994
presentation.
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. These wastes or by-products may not have
previously been considered hazardous, and may not be
considered hazardous currently, but may be identified as
such by Federal, state or local authorities in the future.
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
<PAGE>
determined that the Company contributed. The Company has
been advised that various Federal, state or local agencies
believe that certain properties require investigation and
has prioritized the sites based on available information in
order to enhance the management of investigation and
remediation, if determined to be necessary.
The Company is currently aware of 92 sites with which it
has been or may be associated, including 50 which are
Company-owned. The Company-owned sites include 23 former
coal gasification (MGP) sites, 15 industrial waste sites
and 12 operating property sites where corrective actions
may be deemed necessary to prevent, contain and/or
remediate contamination of soil and/or water in the
vicinity. Of these Company-owned sites, Saratoga Springs
is on the Federal National Priorities List for Uncontrolled
Hazardous Waste Sites (NPL) published by the Environmental
Protection Agency (EPA). The 42 non-owned sites with which
the Company has been or may be associated are generally
industrial disposal waste sites where some of the disposed
waste materials are alleged to have originated from the
Company's operations. Pending the results of
investigations, the Company may be required to contribute
some proportionate share of remedial costs. Not included
in the 92 sites are seven sites for which the Company has
reached final settlement agreements with other potentially
responsible parties (PRP) and three sites where remediation
activities have been completed. The Company is also aware
of approximately 20 formerly-owned MGP sites with which the
Company has been or may be associated and which may require
future investigation and possible remediation. Also,
approximately 11 fire training sites used by the Company
have been identified but not investigated. Presently, the
Company has not determined its potential involvement with
such sites and has made no provision for potential
liabilities associated therewith.
Investigations at each of the Company-owned sites are
designed to (1) determine if environmental contamination
problems exist, (2) determine the extent, rate of movement
and concentration of pollutants, (3) if necessary,
determine the appropriate remedial actions required for
site restoration and (4) 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
have been completed, the Company expects to determine site-
specific remedial actions necessary and to estimate the
attendant costs for restoration. However, since
technologies are still developing and the Company has not
yet undertaken any full-scale remedial actions following
regulatory requirements at any identified sites, nor have
any detailed remedial designs been prepared or submitted to
appropriate regulatory
<PAGE>
agencies, the ultimate cost of remedial actions may change
substantially as investigation and remediation progresses.
The Company estimates that 44 of the 50 owned sites will
require some degree of remediation and post-remedial
monitoring. This conclusion is based upon a number of
factors, including the nature of the identified or
potential contaminants, the location and size of the site,
the proximity of the site to sensitive resources, the
status of regulatory investigation and knowledge of
activities at similarly situated sites. Although the
Company has not extensively investigated many of those
sites, it believes it has sufficient information to
estimate a range of cost of investigation and remediation.
As a consequence of site characterizations and assessments
completed to date, the Company has accrued a liability of
$210 million for these owned sites, representing the low
end of the range of the estimated cost for investigation
and remediation. The high end of the range is presently
estimated at approximately $520 million.
The majority of these cost estimates relate to the MGP
sites. Of the 23 MGP sites, the Harbor Point (Utica, NY)
and Saratoga Springs sites are being investigated and
remediated pursuant to separate regulatory Consent Orders.
The remaining 21 MGP sites are the subject of an Order on
Consent executed with the New York State Department of
Environmental Conservation (DEC) providing for an
investigation and remediation program over approximately
ten years. Preliminary site assessments have been
conducted or are in process at eight of these 21 sites,
with remedial investigations either currently in process or
scheduled for five sites in 1994. Remedial investigations
have been conducted or are in process for nine industrial
waste sites and for three operating properties where
corrective actions were considered necessary.
The Company recently completed preliminary assessments at
the fire training sites which it owns and determined five
sites will require further investigation. These sites and
the costs to investigate them are included in the sites
discussed above and the amounts accrued at June 30, 1994.
The Company does not currently believe that a clean-up will
be required at the six remaining Company-owned sites,
although some degree of investigation of these sites is
included in its investigation and remediation program.
With respect to the 42 sites with which the Company has
been or may be associated as a PRP, nine are listed on the
NPL. Total costs to investigate and remediate these sites
are estimated to be approximately $590 million; however,
the
<PAGE>
Company estimates its share of this total at approximately
$30 million and this amount has been accrued at June 30,
1994.
The seven sites for which final settlement agreements have
been executed resulted in payment by the Company of amounts
not considered to be material. For the 9 sites included on
the NPL, the estimated aggregate liability for these sites
is not material and is included in the determination of the
amounts accrued.
Estimates of the Company's potential liability for sites
not owned by the Company, but for which the Company has
been identified as a PRP, have been derived by estimating
the total cost of site clean-up and then applying the
related Company contribution factor to that estimate.
Estimates of the total clean-up costs are determined by
using all available information from investigations
conducted to date, negotiations with other PRPs and, where
no other basis is available at the time of estimate, the
EPA figure for average cost to remediate a site listed on
the NPL as disclosed in the Federal Register of June 23,
1993 (58 FR No. 119). The contribution factor is then
calculated using either a per capita share based upon the
total number of PRPs named or otherwise identified, which
assumes all PRPs will contribute equally, or the percentage
agreed upon with other PRPs through steering committee
negotiations or by other means. Actual Company
expenditures for these sites 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 PRP sites and is
contesting liability accordingly.
The EPA advised the Company by letter that it is one of 833
PRPs under Superfund for the investigation and cleanup of
the Maxey Flats Nuclear Disposal Site in Morehead,
Kentucky. The Company has contributed to a study of this
site and estimates that the cost to the Company for its
share of investigation and remediation based on its
contribution factor of 1.3% would approximate $1 million,
which the Company believes will be recoverable in the
ratesetting process.
On July 21, 1988, the Company received notice of a motion
by Reynolds Metals Company to add the Company as a third
party defendant in an ongoing Superfund lawsuit in Federal
District Court, Northern District of New York. This suit
involves PCB oil contamination at the York Oil Site in
Moira, New York. Waste oil was transported to the site
during the 1960's and 1970's by contractors of Peirce Oil
<PAGE>
Company (owners/operators
<PAGE>
of the site) who picked up waste oil at locations
throughout Central New York, allegedly including one or
more Company facilities. On May 26, 1992, the Company was
formally served in a Federal Court action initiated by the
government against 8 additional defendants. Pursuant to
the requirements of a case management order issued by the
Court on March 13, 1992, the Company has also been served
in related third and fourth-party actions for contribution
initiated by other defendants. These actions have been
consolidated into a single action filed in February 1994 by
the federal government against several entities, including
the Company, which did not accept the government's final
terms of settlement. The Company intends to vigorously
oppose and defend against the government's characterization
of its liability in this matter.
The Company believes that costs incurred in the
investigation and restoration process for both Company-
owned sites and sites with which it is associated will be
recoverable in the ratesetting process. Rate agreements in
effect since 1991 provide for recovery of anticipated
investigation and remediation expenditures. The Company's
1994 rate settlement includes $21.7 million for site
investigation and remediation. The Staff of the New York
State Public Service Commission (PSC Staff) reserves the
right to review the appropriateness of the costs incurred.
While the PSC Staff has not challenged any remediation
costs to date, the PSC Staff asserted in the recently-
decided gas rate proceeding that the Company must, in
future rate proceedings, justify why it is appropriate that
remediation costs associated with non-utility property
owned by the Company be recovered from ratepayers. Based
upon management's assessment that remediation costs will be
recovered from ratepayers, a regulatory asset has been
recorded representing the future recovery of remediation
obligations accrued to date.
The Company is also in the process of providing notices of
insurance claims to carriers with respect to the
investigation and remediation costs for manufactured gas
plant and industrial waste sites. 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
the 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 2 (Unit 2). The Company
<PAGE>
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 New York State
Public Service Commission (PSC) in 1990, to the extent the
IRS is able to sustain disallowances, the Company will be
required to absorb a portion of any disallowance. The
Company believes any such disallowance will not have a
material impact on its financial position or results of
operations.
Litigation: On March 22, 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 power
purchase agreement was entered into in early 1988 in
connection with a 200 MW cogeneration project to be
developed by Inter-Power in Halfmoon, New York. 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.
On July 19, 1994, the New York Supreme Court issued an
order granting the Company's request for a summary
judgment, dismissing the complaint for lack of merit and
denying Inter-Power's cross motion to compel disclosure.
Inter-Power has indicated it will appeal this order, but
the Company believes it has meritorious defenses and
intends to defend the lawsuit vigorously.
On November 12, 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.
On January 3, 1994, the defendants filed a joint motion to
dismiss Fourth Branch's complaint. This motion has yet to
be decided. On March 16, 1994, the Court denied Fourth
Branch's motion for preliminary judgment. The Company also
notified Fourth Branch by letter dated March 1, 1994, that
the Licensing Agreement between Fourth Branch and the
Company is terminated. On March 15, 1994, Fourth Branch
<PAGE>
petitioned the Federal Energy Regulatory Commission (FERC)
<PAGE>
for Extraordinary Relief. The Company has opposed this
petition before the FERC. On March 18, 1994, Fourth Branch
filed a petition for bankruptcy and, on April 4, 1994, the
bankruptcy court granted relief from the automatic
bankruptcy stay to allow the pending litigation to go
forward. On
April 27, 1994, the Company served an answer and
counterclaim in the Albany Supreme Court litigation seeking
$1 million in damages and removal of Fourth Branch from the
Mechanicville site. The Company believes that it has
substantial defenses to Fourth Branch's claims, but is
unable to predict the outcome of this litigation.
No provision for liability, if any, that may result from
either of these suits has been made in the Company's
financial statements.
3. Regulatory and Other Assets.
Certain expenses and credits, normally reflected in income
as incurred, are recognized when included in rates and
recovered from or refunded to customers. As such, the
Company has recorded the following regulatory assets which
are expected to result in future revenues as these costs
are recovered through the ratemaking process.
Historically, all costs of this nature which are not
determined by the PSC to have been imprudently incurred
have been recoverable through rates in the course of normal
ratemaking procedures and the Company believes that the
items detailed below should be afforded similar treatment.
Additionally, the Company's rate plan described below under
"1995 Five-Year Rate Plan Filing" contemplates no change in
this approach to such recoverability, 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.
<PAGE>
June 30, December
31,
1994 1993
(In thousands)
Income taxes recoverable $ 527,995 $ 527,995
Deferred finance charges 239,880 239,880
Recoverable environmental
restoration costs 240,000 240,000
Unamortized debt expense 154,901 154,210
Deferred unregulated generators
contract termination costs 48,852 50,680
Deferred postemployment benefit
costs 46,285 30,741
Deferred gas pipeline costs 31,000 31,000
Deferred recoverable energy
costs 27,924 67,632
Deferred costs of decommissioning
federal uranium enrichment
facilities 17,594 17,594
Other 46,368 45,172
Total $1,380,799 $1,404,904
Income taxes recoverable represents the expected tax
consequences of temporary differences between the recorded
book bases and the tax bases of assets and liabilities.
These amounts are amortized and recovered as the related
temporary differences reverse.
Deferred finance charges represent the deferral of the
discontinued allowance for funds used during construction
(AFC) related to construction work in process at Unit 2.
This amount is offset by a corresponding deferred credit.
Both amounts await future disposition by the PSC.
Recoverable environmental restoration costs represent the
Company's share of the estimated costs to investigate and
perform certain remediation activities at both Company-
owned sites and sites with which it may be associated.
Current rates provide an annual allowance to recover
anticipated annual expenditures.
Unamortized debt expense represents the cost associated
with issuing and/or reacquiring debt. These costs are
being amortized and recovered over the lesser of the life
of the debt issued to finance the reacquisitions or the
remaining life of the reacquired debt.
Deferred unregulated generators contract termination costs
represent the Company's cost to buy out certain unregulated
generator projects. Approximately one-third of these costs
are currently being recovered over a three-year period
<PAGE>
beginning in 1994. The remaining costs are being addressed
in the Company's current rate filing.
Deferred postemployment benefit costs represent the excess
of such costs recognized in accordance with SFAS No. 106
over the amount received in rates. These costs are being
amortized and recovered over a 20 year period.
Deferred gas pipeline costs represent the estimated
restructuring costs the Company anticipates incurring as a
result of FERC Order No. 636. These costs are treated as a
cost of purchased gas and are recoverable through the
operation of the gas adjustment clause mechanism over a
period of approximately 7 years, with recovery more heavily
weighted in the first 3 years.
Deferred recoverable energy costs represent the difference
between actual fuel costs and the fuel revenues received
through the Company's fuel adjustment clause (FAC). These
costs are amortized as they are collected from customers.
Deferred costs of decommissioning federal uranium
enrichment facilities represents the unamortized portion of
the Company's mandated contribution to the Department of
Energy's (DOE) uranium enrichment facilities. The Energy
Policy Act of 1992 calls for domestic utilities to
contribute amounts, escalated for inflation, based upon the
amount of uranium enriched by the DOE for each utility.
These costs are being amortized and recovered, as a fuel
cost, over a fifteen year period.
<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 June 30, 1994 and the unaudited
Consolidated Statements of Income for the three-month and six-
month periods ended June 30, 1994 and 1993 and of Cash Flows for
the six-months ended June 30, 1994 and 1993. 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>
PRICE WATERHOUSE LLP
ONE MONY PLAZA
SYRACUSE NY 13202
TELEPHONE 315-474-6571
REPORT OF INDEPENDENT ACCOUNTANTS
August 11, 1994
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, 1994, and the related condensed consolidated statements
of income for the three-month and six-month periods ended June
30, 1994 and 1993 and of cash flows for the six months ended June
30, 1994 and 1993. 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, 1993, and the related consolidated statements of income and
retained earnings and of cash flows for the year then ended (not
presented herein); and in our report dated January 27, 1994, 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, 1993 is
fairly stated, in all material respects, in relation to the
consolidated balance sheet from which it has been derived.
/s/ Price Waterhouse LLP
<PAGE>
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations
Financial Position, Liquidity and Capital Resources
The potential intensity and accelerating pace of competition may
be the most significant factor driving fundamental changes in the
way utilities, including the Company, are being managed. The
Company believes that the price of electricity may be the most
important element of future success in the industry and has
intensified its efforts to reduce various costs that
significantly influence the price of electricity. As described
below, the Company is offering an early retirement program to its
management employees and is negotiating with its union to extend
the program to its members. Efforts to reduce tax burdens
continue, with the state senate having passed a measure to phase
out the gross receipts tax. While this measure was not enacted
into law, real change may be possible in the next legislative
session. The Company is also making progress in reducing
excessive property tax levies. The dismissal of the Inter-power
lawsuit and developments in the Sithe/Alcan proceeding as
described in the Notes to Financial Statements and Part II of the
10Q, respectively, also demonstrate the Company's commitment to
reduce excessive unregulated generator payments. While not
completely relieving the Company's competitive pressures, these
steps exemplify the Company's resolve to reduce its cost
structure.
Early Retirement and Voluntary Separation Program
On July 29, 1994, the Company announced a plan to achieve further
substantial reductions in its staffing levels in an effort to
bring the Company's staffing levels and work practices more into
line with other peer group utilities and become more competitive
in its cost structure. The plan for management employees
includes an early retirement program and a voluntary separation
program for those not eligible for early retirement. A variety
of issues remain to be resolved before the overall program is put
into place, including completion of negotiations with the union
representing approximately 70% of the Company's work force as to
a similar plan for union employees. In addition to negotiating
an early retirement program, the Company is also discussing work
practice changes that would facilitate a reduction in employee
levels. Management employees now have until October 17, 1994 to
choose to participate in the program. The Company is unable to
predict the size of the reduction of staff and associated cost
reductions or the cost of the early retirement and voluntary
separation programs. While the Company generally intends to pass
the savings from the program back to customers in 1995, it has
not determined the method by which the passback would be
accomplished. Based on current Company estimates, 1994 cash
outlays in connection with the program are not expected to be
material. Although the staffing reductions are expected to
produce long term savings, the Company may record
<PAGE>
a charge against earnings in the fourth quarter of 1994. In the
event a charge against income would otherwise be required, the
Company may decide to seek recovery from customers of all or a
portion of the cost of the program, but can provide no assurance
that the PSC will approve such recovery.
Competition
The Company is experiencing a loss of industrial load through
bypass across its system. Several substantial industrial
customers, constituting approximately 85 MW of demand, have
chosen to purchase generation from other sources, either from
newly constructed facilities or under circumstances where they
directly use the power they had been generating and selling to
the Company under power purchase contracts mandated by the Public
Utility Regulatory Policies Act of 1978 (PURPA), New York laws
and PSC programs.
As a first step in addressing the threat of further loss of
industrial load, the PSC approved a rate (referred to as SC-10)
under which the Company is allowed to negotiate individual
contracts with some of its largest industrial and commercial
customers to provide them with electricity at lower prices.
Under this rate, customers must demonstrate that leaving the
Company's system is an economically viable alternative. At July
31, 1994, the Company estimated that as many as 75 of its 235
largest customers may be inclined to bypass the utility's system
by making electricity on their own unless they receive price
discounts. Granting discounts would cost an estimated $20
million per year, while losing those 75 customers would reduce
net revenues by an estimated $80 million per year. As of July
31, 1994, the Company has offered annual SC-10 discounts to
customers totaling $10.2 million, of which $7.9 million have been
accepted.
As discussed below under "PSC's Flexible Rates Guidelines;
Wholesale Market Proceeding", the PSC issued an order for Phase I
of its generic competitiveness proceeding, requiring the Company
(and other New York utilities with flexible tariffs) to file
amendments to SC-10. On August 10, 1994, the Company filed for a
new service classification, SC-11, for Individually Negotiated
Contract Rates. The tariffs for SC-11 are effective immediately.
While all existing contracts under SC-10 will continue in place,
all new contract rates will be administered under the new SC-11
service classification. SC-11 was created to respond to
demonstrated non-residential competitive pricing scenarios
including, but not limited to, on-site generation, fuel
switching, facility relocation and partial plant production
shifting. Contracts will be negotiated on a case-by-case basis,
for a term not to exceed seven years, with prices generally
subject to a floor of the marginal cost of service plus one cent
per kilowatt hour. The Company will apply the sharing provisions
of SC-10 to SC-11 in 1994.
<PAGE>
Under the terms of its 1994 Rate Agreement, the Company filed a
"competitiveness" study with the PSC on April 7, 1994, entitled
"The Impacts of Emerging Competition in the Electric Utility
Industry." The assessment of competition contained in the report
describes the initial results of the Company's CIRCA 2000
(Comprehensive Industry Restructuring and Competitive Assessment
for the 2000s) studies. Although there is considerable debate
about what changes should occur in the electric industry and even
more uncertainty about what will actually happen, the study
explores the Company's best estimate of how impacts would vary
depending on the extent of changes in the industry and the pace
at which those changes are allowed to unfold.
The report presents a brief review of federal energy policy and
the current debate over industry restructuring as background
information. A discussion of the competitive forces that the
Company faces is followed by an assessment of the competitiveness
of the Company's electricity supply costs and an explanation of
the potential financial effects of increased competition.
Certain adversaries of the Company in New York State and certain
governmental officials have recently stated that the best way for
the Company to address competitive issues would be to take
substantial but unspecified writedowns of its assets,
particularly its nuclear and fossil generating plants. The
Company's position is that any proper solution to the problems
posed by increasing competition and deregulation must be
substantially more evenhanded, and will necessarily be more
complicated, than any such proposal. With respect to writedowns,
the Company's position continues to be that any revaluation of
its assets needs to address the entire catalogue of assets,
including generation, transmission and distribution assets.
The Company sells electricity generated from diverse supply
sources, to reduce sensitivity to changes in the economics of any
single fuel source. However, the average cost of these diverse
sources may be greater than any single fuel source. While the
Company's average generation costs are competitive with costs of
new suppliers of electricity, the current excess supply of
capacity in the Northeast and Canada has significantly depressed
wholesale prices, which may be indicative of retail prices in the
near term if competition quickly expands. Under these
circumstances, by-pass is a growing threat, although no
regulatory structure for bypass currently exists in New York
State. There is increasing public debate within several
municipalities in the Company's service territory on the issue of
by-pass. While municipalities across the country have long been
able to form municipal utilities, the Energy Policy Act of 1992
might increase the appeal of municipalization because the law
allows FERC to mandate open wholesale access to transmission.
Municipalization has the potential to adversely affect the
Company's customer base and profitability.
<PAGE>
From a broader industry perspective, the assessment concludes
that selective discounting to avoid uneconomic by-pass is likely
to be effective in the current regulatory and competitive regime.
Full retail competition, if not managed appropriately and
consistently, could create significantly higher prices for core
customers, jeopardize the financial viability of the electric
utility industry and devastate the social programs delivered by
the industry. While aggressive cost management must be part of
any response to competition, it alone cannot address the
financial consequences that may arise from a sudden and dramatic
policy change. Regulators, legislators, and utilities must
collaborate to create a fair and equitable transition to
increased competition that addresses the obligation to serve,
incumbent burdens, transition costs, and exit fees. See Item 5.
Other Events, 1. California Open Competition Plan.
1995 Five-Year Rate Plan Filing
On February 4, 1994, the Company made a combined electric and gas
rate filing for rates to be effective January 1, 1995 seeking a
$133.7 million (4.3%) increase in electric revenues and a $24.8
million (4.1%) increase in gas revenues. The electric filing
includes a proposal to institute a methodology to establish rates
beginning in 1996 and running through 1999. The proposal would
provide for rate indexing to a quarterly forecast of the consumer
price index as adjusted for a productivity factor. The
methodology sets a price cap, but the Company may elect not to
raise its rates up to the cap. Such a decision would be based on
the Company's assessment of the market. NERAM and certain
expense deferrals would be eliminated, while the fuel adjustment
clause would be modified to cap the Company's exposure to fuel
and purchased power cost variances from forecast at $20 million
annually. However, certain items which are not within the
Company's control would be outside of the indexing; such items
would include legislative, accounting, regulatory and tax law
changes as well as environmental and nuclear decommissioning
costs. These items and the existing balances of certain other
deferral items, such as MERIT and demand-side management (DSM),
would be recovered or returned using a temporary rate surcharge.
The proposal would also establish a minimum return on equity
which, if not achieved, would permit the Company to refile for
new base rates subject to indexing or to seek some other form of
rate relief, although there would be no assurance as to the form
or amount of such rate relief, if any. Conversely, in the event
earnings exceed an established maximum allowed return on equity,
such excess earnings would be used to accelerate recovery of
regulatory assets. The proposal would provide the Company with
greater flexibility to adjust prices within customer classes to
meet competitive pressures from alternative electric suppliers
while increasing the risk that the Company will earn less than
its allowed rate of return. Gas rate adjustments beyond 1995
would follow traditional regulatory methodology.
<PAGE>
The Company settled a motion filed by the PSC Staff to reject the
filing as deficient in support by agreeing to extend the date by
which the PSC must rule on the Company's rate request by twelve
weeks, to March 29, 1995. The Company will absorb one-half of
the costs (the lost margin) arising because of the extension.
The remainder of the costs will be recovered through a noncash
credit to income, and is dependent upon the amount of rate relief
ultimately granted by the PSC for 1995. Based on its filing, the
Company would absorb approximately $28 million. Temporary gas
rates will be instituted for the full twelve weeks. This
settlement of the PSC Staff's motion must ultimately be approved
by the PSC.
1994 Rate Agreement
On February 2, 1994, the PSC approved an increase in gas rates of
$10.4 million or 1.7%. To comply with this rate order, the
Company filed tariffs with an effective date of February 12,
1994. The Company was allowed to collect the revised rates
retroactive to January 1, 1994, through the implementation of a
surcharge factor. The rate order also permitted the Company to
implement for the first time a weather normalization clause with
an effective date of February 12, 1994.
The PSC also approved the Company's electric supplement agreement
with the PSC Staff and other parties to extend certain cost
recovery mechanisms in the 1993 Rate Agreement without increasing
electric base rates for calendar year 1994. On May 12, 1994, the
PSC issued a final order approving the 1994 electric supplement
agreement and the $10.4 million (1.7%) gas rate increase. The
goal of the supplement is to keep total electric bill impacts for
1994 at or below the rate of inflation. Modifications were made
to the Niagara Mohawk Electric Revenue Adjustment Mechanism
(NERAM) and Measured Equity Return Incentive Term (MERIT)
provisions, which determine how these amounts are to be
distributed to various customer classes and also provide for the
Company to absorb 20% of margin variances (within certain limits)
originating from SC-10 rate discounts (as described below) and
certain other discount programs for industrial customers as well
as 20% of the gross margin variance from NERAM targets for
industrial customers. The Company estimated its maximum
shareholder exposure at June 30, 1994, on such variances for 1994
to be approximately $13 million. The supplement also allows the
Company to begin recovery over three years of approximately $15
million of unregulated generator buyout costs, subject to final
PSC determination as to the reasonableness of such costs.
PSC's Flexible Rates Guidelines; Wholesale Market Proceeding
On June 2, 1994, the PSC announced the adoption of guidelines to
govern flexible electric rates offered by utilities to retain
qualified customers in the face of growing competition from
<PAGE>
unregulated generators. The guidelines concluded, among other
things: (i) that such rates should be available for customers
who have "realistic competitive alternatives," (ii) that
utilities should not be mandated to offer such rates, (iii) that
there should be a sharing between stockholders and ratepayers of
the lost revenues resulting from such discounts, (iv) that a
floor should be calculated by each utility, which should
generally be no lower than the marginal cost of service plus one
cent per kilowatt hour ($0.01/kWh), and (v) that such flexible
rate contracts should not be fixed for periods longer than seven
years. The PSC noted that the flexible rates being offered by
the Company, as well as New York State Electric and Gas
Corporation and Rochester Gas and Electric Corporation, should
serve as models.
On June 20, 1994, the PSC announced the commencement of Phase II
of its proceeding, which will examine issues related to the
establishment of a "wholesale competitive market" to provide
power that would be wheeled to local utilities over the
interconnected transmission line system in the state. The PSC
also asked parties to the proceeding, who include the PSC's
staff, independent power producers and industrial customer groups
as well as traditional utilities: (i) to explore the pros and
cons of different market structures, (ii) to identify the most
efficient structure for competition among electric providers and
(iii) to help determine "whether or not utilities as providers of
transmission and distribution services should divest themselves
of their generating assets."
Similar rate initiatives on competitively priced natural gas are
being addressed in a comprehensive generic investigation,
currently being conducted by the PSC, into issues involving the
restructuring of gas utility services to respond to emerging
competition.
Common Stock Dividend
On July 28, 1994, the Board of Directors authorized a common
stock dividend of $.28 per share, which will be paid on August
31, 1994 to shareholders of record on August 8, 1994.
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.
While the Company favors the presence of unregulated generators
in satisfying its generating needs, the Company also believes it
is paying a premium to unregulated generators for energy and
capacity it does not currently need. The Company estimates that
it paid a premium of $206 million in 1993 and expects to overpay
<PAGE>
by $352
<PAGE>
million in 1994 and $421 million in 1995. The Company has
initiated a series of actions to address this situation, but
expects that in large part the higher costs will continue.
In order to control the growth of excess supply, the Company has
taken numerous actions to realign its supply with demand. These
actions include mothballing and retirement of Company owned
generating facilities and buy outs of unregulated generator
projects, as well as the implementation of an aggressive
wholesale marketing effort. Such actions have been successful in
bringing installed capacity reserve margins down to levels in
line with normal planning criteria.
By the end of 1994, the Company expects virtually all unregulated
generator capacity to be on line and unregulated generator
payments are thereafter projected to grow at less than 6%
annually during the rest of the decade.
On August 18, 1992, the Company filed a petition with the PSC
which calls for the implementation of "curtailment procedures."
Under existing FERC and PSC policy, this petition would allow the
Company to limit its purchases from unregulated generators when
demand is low. While the Administrative Law Judge has submitted
recommendations to the PSC, the Company cannot predict the
outcome of this case. Also, the Company has commenced settlement
discussions with certain unregulated generators regarding
curtailments. On April 5, 1994, after informing the PSC of its
progress in settlement, the Company requested the PSC to expedite
the consideration of its petition.
On October 23, 1992, the Company also petitioned the PSC to order
unregulated generators to post letters of credit or other firm
security to protect ratepayers' interests in advance payments
made in prior years to these generators. The PSC dismissed the
original petition without prejudice, which the Company believes
would permit the Company to reinitiate its request at a later
date.
As of June 30, 1994, the Company was conducting discussions with
24 unregulated generator projects representing approximately 661
MW of capacity, addressing the issues contained in its petitions
and the Company has settled the issues discussed above with 35
projects amounting to 1,089 MW of generating capacity.
On February 4, 1994, the Company notified the owners of nine
projects with contracts that provide for front-end loaded
payments of the Company's demand for adequate assurance that the
owners will perform all of their future repayment obligations,
including the obligation to deliver electricity in the future at
prices below the Company's avoided cost and the repayment of any
advance payment balance which remains outstanding at the end of
the contract. See
<PAGE>
Part II. Item 1. Legal Proceedings, for responses to the
Company's notifications.
Financing Plans and Financial Positions
Long-term financing for 1994, originally expected to approximate
$750 million is now expected to be approximately $675 million, of
which approximately $545 million will be used for scheduled and
optional refundings. This external financing is projected to
consist of $325 million in long-term debt (which has been
completed and is described below), $100 million from sales of
common stock and $200 million of preferred stock ($150 million of
which has been completed and is also described below), and a $50
million increase in short-term debt. The original projection of
long-term financing was reduced during the second quarter of 1994
because the Company announced the sale of its unregulated
subsidiary HYDRA-CO Enterprises, Inc. (expected to close prior to
year-end), proceeds from which will reduce the Company's capital
requirements enabling the Company to reduce the amount of its
common equity financing and delaying its plans for a previously
announced underwritten public offering of common stock.
During March 1994, $210 million of 6-7/8% series First Mortgage
Bonds due March 1, 2001 were issued. Proceeds from the issuance
were used in connection with the retirement of $200 million of
outstanding higher-rate First Mortgage Bonds. During July 1994,
$115.7 million of New York State Energy Research and Development
Authority Bonds, 7.20% series were issued to redeem $75.69
million of 11-1/4% series and $40.015 million of 11-3/8% series.
During August 1994, the Company issued $150 million of preferred
stock
9 1/2% series. Through July 31, 1994, approximately 1 million
shares of common stock have been issued through the Dividend
Reinvestment and Employee Plans for approximately $17 million.
The Company is also investigating other options for continuing to
reduce its interest and preferred dividend requirements. Through
the refinancings completed to date, the Company has been able to
reduce its embedded cost of debt on First Mortgage Bonds from
9.25% at December 31, 1991 to 7.84% at July 31, 1994.
The Company believes that traditionally available sources of
financing should be sufficient to satisfy the Company's external
financing needs during the period 1994 through 1998. At August
1, 1994, the Company could issue $2,161 million aggregate
principal amount of First Mortgage Bonds under the earnings test
set forth in the Company's Mortgage Trust Indenture assuming a 8%
interest rate. This includes approximately $1,121 million on the
basis of retired bonds and $1,040 million supported by additional
property currently certified and available. A total $200 million
of Preference Stock is currently available for sale. The Company
also has authorized unissued Preferred Stock totaling $253.9
million. The Company continues to explore and utilize, as
appropriate, other methods of
<PAGE>
raising funds. The Company's Charter restricts the amount of
unsecured indebtedness which may be incurred by the Company to
10% of consolidated capitalization plus $50 million. The Company
has not reached this restrictive limit.
Cash flows to meet the Company's requirements for the first six
months of 1994 and 1993 are reported in the Consolidated
Statements of Cash Flows on Page 7.
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. However, the Company has sufficient
borrowing capacity to fund such deficits as necessary.
Material Changes in Results of Operations
Three Months Ended June 30, 1994 versus Three Months Ended June
30, 1993
The following discussion presents the material changes in results
of operations for the second quarter of 1994 in comparison to the
same period in 1993. 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 second quarter were $60.5 million or $.42 per
share, as compared with $57.2 million or $.41 per share in 1993.
As shown in the table below, electric revenues increased $45.4
million or 5.7% from 1993. This increase resulted primarily from
an increase in sales to other electric systems as the Company's
generation is more available since more of its own load is being
satisfied by unregulated generator purchases, higher fuel
adjustment clause revenues to cover increasing payments to
unregulated generators, and the second stage rate increase
granted in September 1993. Consistent with the terms of the
NERAM, the Company deferred for future recovery the electric
gross margin shortfall from the rate case forecast of $28.5
million and $19.5 million in the second quarters of 1994 and
1993, respectively, for future recovery. The decrease in demand-
side management (DSM) revenues relates to a change in recovery of
certain costs in base rates versus inclusion in a separate DSM
surcharge.
<PAGE>
A report supporting the achievement of the Company's MERIT
program goals for 1993 was submitted in February 1994 to the
parties to the 1991 Financial Recovery Agreement. On June 2,
1994, the PSC allowed the Company to begin recovery of at least
an $18.4 million MERIT award (of a maximum award of $30 million),
to be billed to customers over a twelve-month period. The
Company sought an award of $20.5 and further adjustments may be
allowed as PSC finalizes its review. The Company had previously
recorded $10 million of this award in 1993 based on management's
assessment at that time of the achievement of objectively
measured criteria. The shortfall from the full award reflects
the increasing difficulty of achieving the targets established in
customer service and the introduction of cost benchmarking with
other utilities as a criterion.
Sales to other electric systems $22.9 million
Fuel adjustment clause revenues 19.7
NERAM revenues 9.0
MERIT revenues 7.7
Increase in base rates 5.6
Miscellaneous operating revenues (5.4)
Sales to ultimate consumers (6.3)
DSM revenues (7.8)
-----
$45.4 million
=====
Electric kilowatt-hour sales to ultimate consumers were
approximately 8.0 billion in the second quarter of 1994, a 0.5%
decrease from 1993. After considering the effects of weather,
the Company estimates sales to ultimate consumers decreased 1.0%.
Sales for resale increased 1.323 million kilowatt-hours (151.7%)
resulting in a net increase in total electric kilowatt-hour sales
of 1.3 million (14.3%). On July 21, 1994, the Company set an
all-time electric summer peak load sending out 6,312,00
kilowatts.
Electric fuel and purchased power costs increased $64.8 million
or 25.1%. This increase is the result of a $65.2 million
increase in purchased power costs (principally payments to
unregulated generators) and an increase in fuel costs of $9.3
million, offset by a $9.7 million net decrease in costs deferred
and recovered through the operation of the fuel adjustment
clause. The increase in fuel costs reflects greater nuclear
availability, coupled with increased sales for resale during the
second quarter of 1994.
<PAGE>
Gas revenues increased $5.0 million or 4.0% in 1994 from the
comparable period in 1993 as set forth in the table below:
Increase in base rates $ 2.1 million
Miscellaneous operating revenues 1.9
Sales to ultimate consumers 1.7
Purchased gas adjustment clause revenues .9
MERIT revenues .8
Transportation of customer-owned gas .3
Spot market sales (2.7)
-----
$ 5.0 million
=====
Due in part to cooler weather in the second quarter of 1994, gas
sales to ultimate consumers were 17.6 million dekatherms, a 1.0%
increase from the second quarter of 1993. After considering the
effects of weather, the Company estimates sales to ultimate
consumers decreased 0.9%. Transportation of customer-owned gas
increased 4.5 million dekatherms (29.7%). This increase was
caused by dual fuel customers who switched from alternative fuels
based on market price and availability. These increases were
offset by a decrease in 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. In 1994, the
Company retains only 15% of the profit margin on spot market
sales, compared to 100% in 1993. The other 85% is passed back to
ratepayers. Also due to the colder weather, less spot market gas
was available to purchase and resell economically.
As a result of a 964 thousand increase in dekatherms purchased
and withdrawn from storage for ultimate consumer sales offset by
a 1.1 million decrease in dekatherms purchased for spot market
sales, coupled with a $1.07 million increase in the cost of
dekatherms purchased and a $2.2 million increase in purchased gas
costs and certain other items recognized and recovered through
the purchased gas adjustment clause, the total cost of gas
included in expense increased 1.2% in 1994. The Company's net
cost per dekatherm sold, as charged to expense and excluding spot
market purchases, decreased from $5.05 in 1993 to $4.93 in 1994.
<PAGE>
<TABLE>
<CAPTION>
Three Months Ended June 30,
(In Millions)
Increase %
1994 1993 (Decrease) Change
<S> <C> <C> <C> <C>
Other operation expense $ 174.0 $ 195.7 $ (21.7) (11.1)
Maintenance 46.5 52.0 (5.5) (10.6)
Depreciation and amortization 76.9 68.6 8.3 12.1
Federal and foreign income taxes, net 42.9 38.1 4.8 12.6
Other taxes 119.1 115.4 3.7 3.2
Other items (net) 3.4 (2.3) 5.7 247.8
Interest charges 71.4 73.9 (2.5) (3.4)
</TABLE>
Other operation expense decreased primarily due to decreased DSM
program expenses and the decrease in amortization of other
regulatory deferrals, which expired in 1993.
Maintenance expense decreased principally due to lower nuclear
costs associated with the Nine Mile Point Nuclear Station Unit
No. 1 (Unit 1) refueling outage in the second quarter of 1993.
Depreciation and amortization increased due to the additions to
plant in service during 1993.
Federal income taxes (net) increased as a result of an increase
in pre-tax income. One of the provisions of the Revenue
Reconciliation Act of 1993 raised the federal corporate statutory
tax rate from 34% to 35%, retroactive to January 1, 1993.
Other taxes increased primarily because of higher real estate and
payroll taxes.
Interest charges decreased from 1993, primarily due to the
refunding of debt to obtain lower interest rates.
Material Changes in Results of Operations
Six Months Ended June 30, 1994 versus Six Months Ended
June 30, 1993
The following discussion presents the material changes in results
of operations for the first six months of 1994 in comparison to
the same period in 1993. The Company's quarterly results of
<PAGE>
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 six month periods
should not be taken as an indication of earnings for all or any
part of the balance of the year.
<PAGE>
Earnings for the first six months of 1994 were $191.9 million or
$1.34 per share, as compared with $175.9 million or $1.27 per
share in 1993.
As shown in the table below, electric revenues increased $102.5
million or 6.1% from 1993. This increase results primarily from
the increase in sales to other electric systems, the second stage
rate increase granted in September 1993 (an increase in base
rates of $30.2 million and a decrease in the base cost of fuel of
$.5 million for the six-month period), and higher recoveries
through the operation of the fuel adjustment clause mechanism.
Sales to ultimate customers increased as compared to 1993 but
this level of sales was substantially below the forecast used in
establishing rates. In accordance with the NERAM, the Company
deferred for future recovery the resulting electric gross margin
shortfall of $39.2 million in the first six months of 1994 as
compared with $40.2 million in 1993. Revenues of $8.4 million
($7.7 electric and $.7 gas) were recorded in the six months ended
June 30, 1994, in accordance with the preliminary MERIT allowance
for 1993. $18.4 million was authorized, of which $10.0 million
had been recorded at December 31, 1993.
Sales to other electric systems $ 44.5 million
Fuel adjustment clause revenues 37.4
Increase in base rates 29.7
Sales to ultimate consumers 17.1
MERIT revenues 7.7
NERAM revenues (1.0)
Miscellaneous operating revenues (9.9)
DSM revenues (23.0)
------
$102.5 million
======
Electric kilowatt-hour sales to ultimate consumers were
approximately 17.4 billion in 1994, a 1.4% increase from 1993.
After considering the effects of weather, the Company estimates
sales to ultimate consumers decreased slightly (0.3%). The
prolonged lack of employment opportunities in the State has led
to an emigration of the labor force. New York State Department
of Labor data indicates that this exodus was large enough to
cause a decline in the State's population. During the first six
months of 1994, industrial sales have decreased as shown in the
table below because of the effects of self-generation coupled
with the economic factors previously discussed. Industrial-
Special sales are New York State Power Authority allocations of
low-cost power to specified customers. See detail in table
below. Sales for resale increased 2.2 million kilowatt-hours
(124.7%) resulting in a net increase in total electric kilowatt-
hour sales of 2.5 million (13.0%). Sales for resale increased
due to the availability of Company generation for sale as a
result of an increase in required purchases from unregulated
generators. As established in rates,
<PAGE>
the Company retains 40% of the gross margin variance from the
forecast of sales for resale, with the remainder passed back to
ratepayers. Changes in electric revenues and sales by customer
group are detailed in the table below:
<TABLE>
<CAPTION>
Revenues (Thousands) Sales (GwHrs)
% %
1994 1993 Change 1994 1993 Change
<S> <C> <C> <C> <C> <C> <C>
Residential $ 662,225 $ 617,336 7.3 5,683 5,616 1.2
Commercial 641,065 613,352 4.5 6,055 6,034 0.3
Industrial 288,104 279,319 3.1 3,653 3,522 3.7
Industrial - Special 24,524 20,912 17.3 1,955 1,932 1.2
Municipal 24,875 25,042 (0.7) 104 107 (2.8)
Total to Ultimate Consumers 1,640,793 1,555,961 5.4 17,450 17,211 1.4
Other Electric Systems 94,061 49,513 90.0 4,029 1,793 124.7
Miscellaneous 45,719 72,595 (37.0) - - -
Total $1,780,573 $1,678,069 6.1 21,479 19,004 13.0
</TABLE>
Electric fuel and purchased power costs increased $131.7 million
or 24.9%. This increase is the result of a $148.1 million
increase in purchased power costs (principally payments to
unregulated generators), offset by a $11.6 million net decrease
in costs deferred and recovered through the operation of the fuel
adjustment clause and by a decrease in fuel costs of $4.8
million. The decrease in fuel costs reflects a combination of
greater unregulated generator purchases and nuclear generation
which reduced the need to operate fossil plants during the first
six months of 1994. <PAGE>
<TABLE>
<CAPTION>
Six Months Ended June 30,
1994 Fuel &
% Change from Purchased Power
1994 1993 prior year KwHr. Cost
FUEL FOR ELECTRIC GENERATION:
(IN MILLIONS OF DOLLARS)
GwHrs. Cost GwHrs. Cost GwHrs. Cost Cents/KwHr
------ ------ ------ ------ ------ ------ ----------
<S> <C> <C> <C> <C> <C> <C> <C>
Coal 3,387 $ 55.1 3,550 $ 54.4 (4.6) 1.3 1.63
cents
Oil 1,031 33.0 1,185 38.9 (13.0) (15.2) 3.20
Natural Gas 85 2.7 306 6.7 (72.2) (59.7) 3.18
Nuclear 4,220 25.3 3,565 20.9 18.4 21.1 .60
Hydro 1,906 - 2,046 - (6.8) - -
------ ------ ----- ------ ----- ----- ----
10,629 116.1 10,652 120.9 (0.2) (4.0) 1.09
------ ------ ------ ------ ----- ----- ----
ELECTRICITY PURCHASED:
Unregulated Generators 7,344 478.2 5,481 350.8 34.0 36.3 6.51
Other 5,266 74.3 4,273 53.6 23.2 38.6 1.41
------ ------ ------ ------ ----- ----- ----
12,610 552.5 9,754 404.4 29.3 36.6 4.38
------ ------ ------ ------ ----- ----- ----
23,239 668.6 20,406 525.3 13.9 27.3 2.88
------ ------ ------ ------ ----- ----- ----
Fuel adjustment clause - (8.6) - 3.0 - (386.7) -
Losses/Company use 1,760 - 1,402 - 25.5 - -
------ ------ ------ ------ ----- ----- ----
21,479 $660.0 19,004 $528.3 13.0 24.9 3.07
====== ====== ====== ====== ===== ===== cents
====
</TABLE>
Gas revenues increased $47.5 million or 12.3% in 1994 from the
<PAGE>
comparable period in 1993 as set forth in the table below:
Sales to ultimate consumers and other sales $ 38.5 million
Purchased gas adjustment clause revenues 11.6
Increase in base rates 5.4
Miscellaneous operating revenues 5.0
MERIT revenues 0.7
Transportation of customer-owned gas (1.1)
Spot market sales (12.6)
------
$ 47.5 million
======
<PAGE>
Due in part to cooler weather in the first six months of 1994,
gas sales, excluding transportation of customer owned gas, were
62.6 million dekatherms, a 9.8% increase from the first six
months of 1993. After considering the effects of weather, the
Company estimates sales to ultimate consumers increased 4.4%.
Spot market sales (sales for resale) are generally the higher
priced gas available to the Company and therefore yield margins
that are substantially lower than traditional sales to ultimate
consumers. Dekatherms transported increased by 7.6 million
(22.2%). Changes in gas revenues and dekatherm sales by customer
group are detailed in the table below:
<TABLE>
<CAPTION>
Revenues (Thousands) Sales (Thousands of Dekatherms)
% %
1994 1993 Change 1994 1993 Change
<S> <C> <C> <C> <C> <C> <C>
Residential $287,588 249,669 15.2 42,230 38,968 8.4
Commercial 114,234 96,404 18.5 18,303 16,141 13.4
Industrial 9,484 8,301 14.3 1,873 1,668 12.3
Total to Ultimate Consumers 411,306 354,374 16.1 62,406 56,777 9.9
Other Gas Systems 763 625 22.1 159 188 (15.4)
Transportation of Customer-
Owned Gas 18,677 19,804 (5.7) 42,092 34,445 22.2
Spot Market Sales 3,989 16,660 (76.1) 1,349 7,398 (81.8)
Miscellaneous (50) (4,248) (98.8) - - -
Total $434,685 $387,215 12.3 106,006 98,808 7.3
</TABLE>
As a result of a 6.4 million increase in dekatherms purchased for
ultimate consumer sales offset by a 6.0 million decrease in
dekatherms purchased for spot market sales and withdrawn from
storage, coupled with a $27.0 million increase in the cost of
dekatherms purchased, and a $5.9 million increase in purchased
gas costs and certain other items recognized and recovered
through the purchased gas adjustment clause, the total cost of
gas included in expense increased 9.5% in 1994. The Company's
net cost per dekatherm sold, as charged to expense, excluding
spot market purchases, increased from $3.85 in 1993 to $3.99 in
1994.
<TABLE>
<CAPTION>
Six Months Ended June 30,
(In Millions)
Increase %
1994 1993 (Decrease) Change
<S> <C> <C> <C> <C>
Other operation expense $ 346.7 $390.5 $ (43.8) (11.2)
Maintenance 94.0 102.3 (8.3) (8.1)
<PAGE>
Depreciation and amortization 152.3 136.3 16.0 11.7
Federal and foreign income taxes, net 128.8 115.9 12.9 11.1
Other taxes 254.9 243.9 11.0 4.5
Other items (net) 6.4 2.2 4.2 190.9
Interest charges 144.0 147.1 (3.1) (2.1)
</TABLE>
<PAGE>
Other operation expense decreased primarily due to decreases in
nuclear costs associated with the Unit 1 refueling outage in the
first-half of 1993, decreased DSM program expenses and the
decrease in amortization of other regulatory deferrals, which
expired in 1993.
Maintenance expense decreased principally due to lower nuclear
expenses because of the Unit 1 refueling outage in the first half
of 1993.
Depreciation and amortization increased due to additions to plant
in service during 1993.
Federal income taxes (net) increased as a result of an increase
in pre-tax income.
Other taxes increased primarily because of higher real estate and
payroll taxes.
Interest charges decreased primarily due to the refunding of debt
to obtain lower interest rates.
<PAGE>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
PART II
Item 1. Legal Proceedings.
1. In November 1993, the New York Court of Appeals unanimously
affirmed a Supreme Court, Appellate division (Third
Department) decision invalidating, in part, a New York
State Department of Environmental Conservation (DEC)
Declaratory Ruling that provided the DEC could perform a
full environmental review and condition the operation of
hydroelectric projects under the provisions of Clean Water
Act Section 401 Water Quality Certifications (401
Certifications). The Appellate division held that the
Federal Power Act precluded the DEC from performing a broad
environmental review of federally licensed hydro projects
under the 401 Certification process.
The decision limits the DEC's ability to regulate federally
licensed hydroelectric projects under the guise of 401
Certifications. The Court found that the DEC's attempt to
enlarge its scope of review under the Clean Water Act to
include certain aspects of N.Y. Environmental Conservation
Law (Article 15) was "unfounded."
On May 31, 1994, the U.S. Supreme Court ruled in "PUD No. 1
of Jefferson County and City of Tacoma v. Washington
Department of Ecology" that the Clean Water Act permitted
state environmental authorities to condition hydro licenses
on compliance with specific state water quality criteria.
On June 6, 1994, the U.S. Supreme Court denied DEC's
petition for appeal of the N.Y. Court of Appeals November
1993 decision, leaving intact that ruling and further
suggesting that DEC must confine its review to specified
water quality criteria. Nevertheless, as a result of the
Tacoma case, the DEC may take action to revise its water
quality regulations in an effort to expand the scope of its
review under the guise of 401 certifications.
2. On February 4, 1994, the Company notified the owners of
nine projects with contracts that provide for front-end
loaded payments of the Company's demand for adequate
assurance that the owners will perform all of their future
repayment obligations, including the obligation to deliver
electricity in the future at prices below the Company's
avoided cost and the repayment of any advance payment which
remains outstanding at the end of the contract. The
projects at issue total 426 MW. The Company's demand is
based on its assessment of the amount of advance payment to
be accumulated under the terms
<PAGE>
of the contracts, future avoided costs, and future
operating costs of the projects. As of July 31, 1994, the
Company has received the following responses to these
notifications:
On March 4, 1994, Encogen Four Partners, L.P. filed a
complaint in the U.S. District Court (Southern District of
New York) alleging breach of contract and prima facie tort
by the Company. Encogen seeks compensatory damages of
approximately $1 million and unspecified punitive damages.
In addition, Encogen seeks a declaratory judgment that the
Company is not entitled to assurances of future performance
from Encogen. On April 4, 1994, the Company filed its
answer and counterclaim for declaratory judgment relating to
the Company's exercise of its right to demand adequate
assurance, Encogen has amended its complaint, rescinded its
prima facie tort claim, and filed a motion for judgment on
the pleadings, which is scheduled for December 2, 1994;
On March 4, 1994, Sterling Power Partners, L.P., Seneca
Power Partners, L.P., Power City Partners, L.P. and AG-
Energy, L.P. filed a complaint in New York State Supreme
Court, New York County seeking a declaratory judgment that:
(a) the Company does not have any legal right to demand
assurances of plaintiffs' future performance; (b) even if
such a right existed, the Company lacks reasonable
insecurity as to plaintiffs' future performance; (c) the
specific forms of assurances sought by the Company are
unreasonable; and (d) if the Company is entitled to any form
of assurances, plaintiffs have provided adequate assurances.
On April 4, 1994, the Company filed its answer and
counterclaim for declaratory judgment relating to the
Company's exercise of its right to demand adequate
assurance. Discovery is ongoing; and
On March 7, 1994, NorCon Power Partners, L.P. filed a
complaint in the District Court (Southern District of New
York) seeking a temporary restraining order against the
Company to prevent the Company from taking any action on its
February 4 letter. On March 14, 1994, the Court entered the
interim relief sought by NorCon. On April 4, 1994, the
Company filed its answer and counterclaim for declaratory
judgment relating to the Company's exercise of its right to
demand adequate assurance. Discovery is ongoing.
The Company cannot predict the outcome of these actions or
the response otherwise to its February 4, 1994
notifications, but will continue to press for adequate
assurance that the owners of these projects will honor their
repayment obligations.
<PAGE>
Item 5. Other Events.
1. California Open Competition Plan
On April 20, 1994, the California Public Utilities
Commission (the CPUC) announced a new electric utility
regulation plan which is intended to create open competition
among power suppliers in the California electric markets by
2002. The plan, which is to be implemented by final rules
to be adopted in August 1994, provides that utility
customers who currently receive more than 50 kilovolts at
the transmission level may choose their power supplier after
January 1, 1996 and that the same choice will be provided to
all other classes of customers on a phased-in basis from
1997 through 2002. Although the announced goals of the
CPUC's plan are to lower energy costs, reduce regulatory
oversight and encourage competition, the CPUC has also
stated that the plan will not saddle remaining customers
with the burden of stranded investment costs from their
traditional utilities but will permit those utilities to
recover all of their prudently incurred costs. The exact
mechanisms through which these goals can be accomplished
have not been set forth and the CPUC has indicated that the
portion of its plan calling for unbundling of retail rates
and assigning of different costs to various services
involves a "gray area" relating to whether the CPUC or the
FERC has jurisdiction over such matters.
Because California is recognized as a leader in utility
regulatory matters, and given that this plan to implement
further deregulation and competition is consistent with
predictions from a wide variety of opinion leaders in the
industry, these initiatives could accelerate the pace of
change from single source provision of electric service to
full competition in the Company's service territory. This
in turn would also accelerate the necessity to determine how
and to what extent cost recovery will be accomplished among
the Company's various classes of customers. However, the
Company is not able to predict at this time what means would
be adopted by regulators, the time period in which these
issues will be addressed or resolved, or the effects thereof
on the Company's financial condition or results of
operations.
2. Sithe/Alcan
In April 1994, the PSC ruled that, in the event that Sithe
Independence Power Partners Inc. (Sithe) ultimately obtains
authority to sell electric power at retail, those retail
sales will be subject to a lower level of regulation than
the PSC presently imposes on the Company. Sithe, which will
sell electricity to Con Ed and the Company on a wholesale
basis from its 1,040 megawatt natural gas cogeneration
plant, will provide steam to Alcan Rolled Products (Alcan).
<PAGE>
Sithe also
<PAGE>
proposes to sell a portion of its electricity output on a
retail basis to Alcan, currently a customer of the Company.
The PSC has previously ruled that, under the Public Service
Law, Sithe must obtain a PSC certificate before it may use
its electricity generating facilities to serve any retail
customers. Although Sithe continues to contend that these
retail sales are not subject to regulation by the PSC, Sithe
has filed an application for authority to provide such
services subject to PSC regulation.
In briefs filed with the PSC on July 26, 1994, the Company
stated that retail sales by Sithe's Independence Plant
should be denied because such transactions would result in
higher electricity bills for the Company's other customers,
would not further economic efficiency and would not provide
economic development benefits.
The Company maintains that if the PSC nevertheless grants
the certificate, the PSC must require that Sithe compensate
the Company for any lost revenue so that the Company's
remaining customers are not harmed. In its briefs, the PSC
Staff has taken no position on whether the PSC should grant
a certificate but has maintained that if the PSC does so it
should require Sithe to compensate the Company for some
portion of the lost revenues the Company otherwise would
have received from Alcan. The Company cannot predict the
outcome of this proceeding, but will continue to press its
position.
3. Sale of Subsidiary
On May 17, 1994, the Company announced that it is seeking a
buyer for its wholly-owned subsidiary, HYDRA-CO Enterprises,
Inc. (HYDRA-Co). HYDRA-Co, an unregulated generator which
develops, owns and operates electric generating power
plants, has equity ownership in 25 projects with a capacity
of about 820 MW in operation or under construction in eight
states, Canada and Jamaica. The existing projects include
14 hydroelectric facilities, five cogeneration plants, four
biomass plants and two Windpower facilities. At June 30,
1994, the Company's investment in HYDRA-CO was approximately
$130 million. The Company's goal is to consummate the sale
by the end of 1994.
4. Nuclear Fuel Storage Initiative
In April 1994, the Company joined a spent nuclear fuel
storage initiative with the Mescalero Apache Tribal Council,
32 other utilities and two nuclear industry contractors on
Mescalero tribal lands. Each of the utility companies has
been guaranteed an opportunity to become an equity partner
with the Mescalero Apache Tribe in their efforts to site a
private
<PAGE>
spent nuclear fuel storage facility on the tribal lands.
The first phase was to determine detailed costs and
schedules for the project. Estimates are now complete and
partners can decide whether or not to continue to phase two,
in which a business entity with the Mescalero's as majority
partner would be established. The Company has decided to
continue to phase two.
The next step would be Tribal and the NRC licensing process.
It is estimated that approximately three to four years will
be required to obtain a license to store used fuel and cost
in the range of $8 to $10 million. During the NRC licensing
process, an environmental impact statement will be developed
in conjunction with extensive public hearings.
The Mescalero Tribe has been involved in studying spent fuel
storage technologies and safety for approximately three
years through the voluntary Monitored Retrievable Storage
(MRS) program authorized by Congress.
5. Decommissioning Costs
The staff of the Securities and Exchange Commission (SEC)
has questioned certain of the current accounting practices
of the electric utility industry, regarding the recognition,
measurement and classification of decommissioning costs for
nuclear generating stations in the financial statements of
electric utilities. In response to these questions, in June
1994 the Financial Accounting Standards Board agreed to
review the accounting for removal costs, including
decommissioning. See Item 8. Financial Statements and
Supplementary Data - Note 1 of Notes to Consolidated
Financial Statements in the Company's Form 10-K Annual
Report to the SEC for the fiscal year ended December 31,
1993.
6. Institute of Nuclear Power Operations Evaluation
During the first half of 1994, the Institute of Nuclear
Power Operations (INPO), an industry sponsored oversight
group, performed a site evaluation of Nine Mile Point
Nuclear Station (Units 1 and 2).
The Company has received observations from INPO as to INPO's
site performance evaluations. INPO grades nuclear
performance from 1 (highest) to 5 (lowest). The INPO team
upgraded the Company to Category 2 (from the previous 3),
which is representative of overall exemplary performance, as
defined by INPO.
<PAGE>
7. Unit 1 Economic Study
The next update of the Company's economic analysis of Unit 1
is scheduled to be filed with the PSC by mid-October 1994.
While nuclear operating performance has continued to improve
and costs have been significantly reduced, the existing
substantial surplus of power in the Northeast and Canada,
combined with a sluggish economy, continue to put upward
pressure on the level of operating efficiency and downward
pressure on the level of costs required to economically
justify the continued operation of any given generating
station, including Unit 1. In addition, costs to take Unit
1 out of service have decreased as compared to the previous
study, as a result of utilizing information from the
experience of other nuclear power plants which have been
shut down.
On July 28, 1994, the Company's Board of Directors approved
the filing of a report which would call for the Unit's
continued operation for the foreseeable future. The report
is in the course of preparation for filing. Since the study
was the second of the two required under the 1989 agreement,
no further economic studies are currently required for this
Unit, although the Company will continue as a matter of
course to examine the economic and strategic issues related
to operation of all its generating units.
The Company is unable to predict what reaction may ensue
from its regulators and other parties in connection with
this study. The study is expected to indicate that the
necessary target capacity factor to economically justify
continued operation of Unit 1 would be approximately 75%.
The study necessarily relies on a number of significant
assumptions which are subject to uncertainty and could
produce a wide range of outcomes. These assumptions include
the Unit's capacity factor, levels of operating and capital
costs, anticipated demand for electricity, anticipated
supply of electricity including unregulated generator power,
implementation and compliance costs of the 1990 Clear Air
Act and other federal and state environmental initiatives,
and fuel availability and prices, especially with respect to
natural gas. The Company's operating experience at Unit 1
has improved substantially since the prior study and the
Unit's capacity factor during its latest fuel cycle has been
in excess of the 75% level. In addition to the improved
performance of Unit 1, factors such as fuel diversity,
reliability and the relative economics of other generating
units in the New York Power Pool (of which the Company is a
member and which dispatches generating units on a statewide
basis for the Company, the New York Power Authority and the
six other investor-owned electric utilities in New York
State) also had an impact on the decision with respect to
Unit 1.
<PAGE>
8. Construction and Financing Program
The following table sets forth certain data, as of July 31,
1994, concerning the Company's estimated sources and uses of
capital for 1994:
1994
(In Thousands)
Uses of Capital:
Construction $ 461,000
Nuclear Fuel 33,000
Allowance for Funds Used
During Construction (AFC) 16,000
Total 510,000
Retirements of Securities, Sinking
Fund Obligations and Other
Requirements 570,000
Total $1,080,000
Sources of Capital:
Long-Term Financing $ 625,000
Changes in Other Credit
Facilities 50,000
Internal Sources, including
sale of subsidiary 405,000
Total $1,080,000
The amounts indicated in the above table for "Nuclear Fuel"
include estimated costs of acquisition, conversion,
enrichment and fabrication, but exclude financing costs.
Consistent with the Company's approach to its 1994 financing
plan, external financing plans for 1995 through 1998 are
subject to revision as underlying assumptions are changed to
reflect new methodologies and developments; however, the
Company currently anticipates that long-term financing over
this period will decrease to approximately $180 million.
These amounts, taken together with the above-listed amounts
of external financing for 1994, are currently estimated to
be lower than those previously announced by approximately
$415 million. Substantially all financing for the 1995
through 1998 period is expected to be used for refunding, as
cash provided by operations is generally expected to provide
sufficient funds for the Company's anticipated construction
program. The aggregate level of financing during this four
year period will reflect, among other things, the nature,
timeliness and adequacy of rate relief and uncertain energy
demand due to economic conditions and capital expenditures
relating to distribution and transmission load reliability
projects, as well as expansion of the gas business. Costs
associated with compliance with federal and state
<PAGE>
environmental quality standards, including the Clean Air Act
Amendments of 1990 (the Clean Air Act), the effects of rate
regulation and various regulatory initiatives, the level of
internally generated funds and dividend payments, the
availability and cost of capital and the ability of the
Company to meet its interest and preferred stock dividend
coverage requirements, to satisfy legal requirements and
restrictions in governing instruments and to maintain an
adequate credit rating will also impact the amount and type
of future external financing.
The Company presently anticipates that funds required for
its construction program, acquisition of nuclear fuel, AFC,
other capitalized costs and retirements of securities for
the years 1995 through 1998 will be as set forth below. The
Company is currently reviewing its budget for these items
with a view to reducing costs where practicable and,
accordingly, such figures may be subject to upward or
downward revision.
1995 1996 1997 1998
(In Thousands)
Construction $342,000 $342,000 $343,000 $343,000
Nuclear Fuel 13,000 56,000 1,000 62,000
AFC 8,000 7,000 7,000 8,000
Retirements of
Securities, Sinking
Fund Obligations
and Other
Requirements $ 79,000 $ 69,000 $ 50,000 $ 70,000
The provisions of the Clean Air Act are expected to have an
impact on the Company's fossil generation plants during the
period through 2000 and beyond. The Company is studying
options for compliance with the various provisions of Phase
I of the Clean Air Act, which becomes effective January 1,
1995 and continues through 1999, including a possible
strategy that focuses on fuel switching at its facilities.
The potential for changing the coal burned at the Dunkirk
Steam Station to a lower sulfur content is under review.
The Company has included in the construction budget the cost
of converting either Oswego Unit 5 or Unit 6 from oil to
co-firing with natural gas and oil (including construction
of a natural gas pipeline to the facility) and placing the
other Oswego unit in long-term cold standby with an expected
return to service at the end of the century. To meet
compliance requirements, the Company must also lower its
nitrous oxide emissions and plans to install low nitrous
oxide burners at the Huntley and Dunkirk Steam Stations.
For Phase I compliance, the Company has included
approximately $46 million in its construction forecast for
1994 through 1997. Phase II of the Clean Air Act, effective
January 1, 2000, will require further
<PAGE>
reductions in sulfur dioxide emissions. The Company has
conducted studies indicating that the burning of lower
sulfur fuels at all of its coal and oil fired units is a
possible compliance method, but decisions on Phase II have
not yet been made. The Company's preliminary assessment of
Phase II sulfur dioxide and nitrogen oxide emission
compliance costs is that additional capital expenditures on
the order of $124 million (1994 dollars) will be required
and incremental annual fuel costs and operating expenses of
$21 million will be incurred. However, there are a number
of uncertainties that make it difficult to project these
costs at this time. The Company is continuing to study its
options, taking into consideration the impact of emerging
environmental laws and regulations at both the Federal and
State levels and the effect of unregulated generator
purchases and demand-side management initiatives on load
forecasts, as well as continuing to examine the emerging
market for trading emission allowances.
The Company believes that compliance with the new emission
restrictions can be achieved with currently available
control technology and fuel switching alternatives; however,
until specific regulations implementing the Clean Air Act
are issued, the Company can provide no assurance in this
regard. The Company believes that all capital costs, as
well as incremental operating and maintenance costs and fuel
costs, will be recoverable from its ratepayers.
The Company's cost of financing and access to markets could
be negatively impacted by events outside its control. The
Company's securities ratings could be negatively impacted
by, among other things, the growth in its reliance on
unregulated generator purchase power requirements. Rating
agencies have expressed concern about the impact on Company
financial indicators and risk that unregulated generator
financial leveraging may have.
Certain of the Company's bank credit agreements contain a
representation as to earnings coverage and, in the event
such representation ceases to be true, the banks are not
obligated to make loans to the Company under such
agreements. If the Company were unable to utilize its bank
credit arrangements to meet working capital requirements, it
would be forced to issue higher cost, longer-term
securities, which in turn would put further pressure on its
credit ratings.
<PAGE>
Ordinarily, construction related short-term borrowings are
refunded with long-term securities on a continuing basis.
Bank credit arrangements, which, at June 30, 1994 totalled
$445 million (including $260 million of commitments under
revolving credit agreements, $80 million in one-year
commitments under credit agreements, $5 million in lines of
credit and a $100 million bankers acceptance facility
agreement), are used by the Company to enhance flexibility
as to the type and timing of its long-term security sales.
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 and Six Months
Ended June 30, 1994 and 1993.
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
June 30, 1994.
Exhibit 15 - Accountants' Acknowledgement Letter.
(b) Report on Form 8-K:
Form 8-K Reporting Date - August 8, 1994.
Items reported - Item 5. Other Events.
Registrant filed information concerning the filing of the
form of the underwriting agreement dated August 1, 1994.
<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: August 12, 1994 By
Steven W. Tasker
Vice President-Controller and
Principal Accounting Officer,
in his respective capacities
as such
<PAGE>
<TABLE>
EXHIBIT 11
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
---------------------------------------------------------
Computation of the Average Number of Shares of Common Stock Outstanding
For the Three and Six Months Ended June 30, 1994 and 1993
<CAPTION> (4)
Average Number of
Shares Outstanding As
(1) (2) (3) Shown on Consolidated
Shares of Number of Share Statement of Income
Common Days Days (3 divided by number
Stock Outstanding (2 x 1) of Days in Period)
-------- ----------- ------- ---------------------
<S> <C> <C> <C> <C>
FOR THE THREE MONTHS
ENDED JUNE 30:
APRIL 1 - JUNE 30, 1994 142,706,358 91 12,986,278,578
SHARES SOLD AT VARIOUS
TIMES DURING THE PERIOD -
DIVIDEND REINVESTMENT PLAN 242,046 *<F1> 7,384,913
EMPLOYEE SAVINGS FUND PLAN 368,400 *<F1> 11,337,500
----------- --------------
143,316,804 13,005,000,991 142,912,099
=========== ============== ===========
APRIL 1 - MAY 4, 1993 137,295,899 34 4,668,060,566
SHARES SOLD MAY 5, 1993 4,494,000
-----------
MAY 5 - JUNE 30, 1993 141,789,899 57 8,082,024,243
SHARES SOLD AT VARIOUS
TIMES DURING THE PERIOD -
DIVIDEND REINVESTMENT PLAN 169,794 *<F1> 5,340,201
PURCHASE- SYRACUSE SUBURBAN 516 *<F1> 40,764
----------- --------------
141,960,209 12,755,465,774 140,169,954
=========== ============== ===========
<PAGE>
(4)
Average Number of
Shares Outstanding As
(1) (2) (3) Shown on Consolidated
Shares of Number of Share Statement of Income
Common Days Days (3 divided by number
Stock Outstanding (2 x 1) of Days in Period)
-------- ----------- ------- ---------------------
<S> <C> <C> <C> <C>
FOR THE SIX MONTHS
ENDED JUNE 30:
JANUARY 1 - JUNE 30, 1994 142,427,057 181 25,779,297,317
SHARES SOLD AT VARIOUS
TIMES DURING THE PERIOD -
DIVIDEND REINVESTMENT PLAN 421,347 *<F1> 29,392,338
EMPLOYEE SAVINGS FUND PLAN 468,400 *<F1> 21,137,500
----------- --------------
143,316,804 25,829,827,155 142,706,227
=========== ============== ===========
JANUARY 1 - MAY 4, 1993 137,159,607 124 17,007,791,268
SHARES SOLD MAY 5, 1993 4,494,000
-----------
MAY 5 - JUNE 30, 1993 141,653,607 57 8,074,255,599
SHARES SOLD AT VARIOUS
TIMES DURING THE PERIOD -
DIVIDEND REINVESTMENT PLAN 305,493 *<F1> 21,979,928
PURCHASE- SYRACUSE SUBURBAN 1,109 *<F1> 146,318
----------- --------------
141,960,209 25,104,173,113 138,697,089
=========== ============== ===========
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>
<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 June 30, 1994 (in thousands of dollars)
<S> <C>
A. Net income $ 285,573
B. Taxes Based on Income or Profits 159,977
----------
C. Earnings, Before Income Taxes 445,550
D. Fixed Charges (a) 316,024
----------
E. Earnings Before Income Taxes and
Fixed Charges 761,574
F. Allowance for Funds Used During
Construction (AFC) 12,963
----------
G. Earnings Before Income Taxes and
Fixed Charges without AFC $ 748,611
=========
PREFERRED DIVIDEND FACTOR:
H. Preferred Dividend Requirements $ 29,563
---------
I. Ratio of Pre-tax Income to Net
Income (C/A) 1.560
----------
J. Preferred Dividend Factor (HxI) $ 46,118
K. Fixed Charges as Above (D) 316,024
----------
L. Fixed Charges and Preferred Dividends
Combined $ 362,142
==========
M. Ratio of Earnings to Fixed
Charges (E/D) 2.41
==========
N. Ratio of Earnings to Fixed Charges
without AFC (G/D) 2.37
==========
O. Ratio of Earnings to Fixed Charges
and Preferred Dividends Combined (E/L) 2.10
==========
(a) Includes a portion of rentals deemed representative of the
interest factor ($27,733).
</TABLE>
<PAGE>
PRICE WATERHOUSE LLP
ONE MONY PLAZA
SYRACUSE NY 13202
TELEPHONE 315-474-6571
EXHIBIT 15
----------
August 11, 1994
SECURITIES AND EXCHANGE COMMISSION
450 FIFTH STREET NW
WASHINGTON DC 20549
Dear Sirs:
We are aware that Niagara Mohawk Power Corporation has included
our report dated August 11, 1994 (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
<PAGE>
