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 September 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 October 31, 1994 - 143,972,960
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
FORM 10-Q - For The Quarter Ended September 30, 1994
INDEX
Part I. Financial Information Page
Item 1. Financial Statements.
a) Consolidated Statements of Income -
Three Months and Nine Months Ended
September 30, 1994 and 1993 3
b) Consolidated Balance Sheets - September 30,
1994 and December 31, 1993 5
c) Consolidated Statements of Cash Flows -
Nine Months Ended September 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. 39
Item 5. Other Events. 41
Item 6. Exhibits and Reports on Form 8-K. 44
Signature 45
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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THREE MONTHS ENDED
SEPTEMBER 30,
---------------------------
1994 1993
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(In thousands of dollars)
OPERATING REVENUES:
Electric $ 861,002 $ 812,323
Gas 57,808 67,629
918,810 879,952
OPERATING EXPENSES:
Operation:
Fuel for electric generation 47,155 57,454
Electricity purchased 285,013 210,378
Gas purchased 20,487 33,202
Other operation expense 177,033 191,958
Maintenance 51,252 59,003
Depreciation and amortization 77,456 69,281
Federal and foreign income taxes 28,487 31,631
Other taxes 122,990 118,506
809,873 771,413
OPERATING INCOME 108,937 108,539
OTHER INCOME AND (DEDUCTIONS):
Allowance for other funds used
during construction 854 2,129
Federal and foreign income taxes 787 3,472
Other items (net) 5,838 4,613
7,479 10,214
INCOME BEFORE INTEREST CHARGES 116,416 118,753
INTEREST CHARGES:
Interest on long-term debt 65,543 69,733
Other interest 5,265 2,845
Allowance for borrowed funds used
during construction (2,775) (2,420)
68,033 70,158
NET INCOME 48,383 48,595
Dividends on preferred stock 9,070 7,808
BALANCE AVAILABLE FOR COMMON STOCK $ 39,313 $ 40,787
Average number of shares of common
stock outstanding
(in thousands) 143,540 142,012
Balance available per average
share of common stock $ .27 $ .29
Dividends paid per share of common
stock .28 .25
/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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NINE MONTHS ENDED
SEPTEMBER 30,
---------------------------
1994 1993
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(In thousands of dollars)
OPERATING REVENUES:
Electric $2,641,575 $2,490,392
Gas 492,493 454,844
3,134,068 2,945,236
OPERATING EXPENSES:
Operation:
Fuel for electric generation 161,927 175,074
Electricity purchased 830,143 621,040
Gas purchased 260,669 252,545
Other operation expense 523,741 582,488
Maintenance 145,236 161,299
Depreciation and amortization 229,804 205,559
Federal and foreign income taxes 161,773 155,940
Other taxes 377,866 362,414
2,691,159 2,516,359
OPERATING INCOME 442,909 428,877
OTHER INCOME AND (DEDUCTIONS):
Allowance for other funds used
during construction 2,512 6,090
Federal and foreign income taxes 5,259 11,869
Other items (net) 12,238 6,797
20,009 24,756
INCOME BEFORE INTEREST CHARGES 462,918 453,633
INTEREST CHARGES:
Interest on long-term debt 201,404 211,275
Other interest 13,386 8,370
Allowance for borrowed funds used
during construction (6,278) (6,888)
208,512 212,757
NET INCOME 254,406 240,876
Dividends on preferred stock 23,158 24,191
BALANCE AVAILABLE FOR COMMON STOCK $ 231,248 $ 216,685
Average number of shares of common
stock outstanding
(in thousands) 142,987 139,814
Balance available per average
share of common stock $ 1.62 $ 1.55
Dividends paid per share of common
stock .81 .70
/TABLE
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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CONSOLIDATED BALANCE SHEETS
---------------------------
SEPTEMBER 30,
1994 DECEMBER 31,
(UNAUDITED) 1993
------------ ------------
(In thousands of dollars)
UTILITY PLANT:
Electric plant $ 8,196,173 $7,991,346
Nuclear fuel 468,613 458,186
Gas plant 894,563 845,299
Common plant 273,771 244,294
Construction work in progress 528,945 569,404
Total utility plant 10,362,065 10,108,529
Less-Accumulated depreciation and
amortization 3,429,124 3,231,237
Net utility plant 6,932,941 6,877,292
OTHER PROPERTY AND INVESTMENTS 266,975 221,008
CURRENT ASSETS:
Cash, including temporary cash investments
of $88,004 and $100,182, respectively 145,894 124,351
Accounts receivable (less-allowance for
doubtful accounts of $3,600) 230,498 258,137
Unbilled revenues 185,800 197,200
Electric margin recoverable 48,423 21,368
Materials and supplies, at average cost:
Coal and oil for production of electricity 25,723 29,469
Gas storage 37,597 31,689
Other 159,569 163,044
Prepaid taxes 48,825 23,879
Prepaid pension expense 39,933 37,238
Other prepayments 27,928 29,498
950,190 915,873
REGULATORY AND OTHER ASSETS (Note 3):
Unamortized debt expense 157,266 154,210
Deferred recoverable energy costs 48,935 67,632
Deferred finance charges 239,880 239,880
Income taxes recoverable 527,995 527,995
Recoverable environmental restoration costs 240,000 240,000
Other 190,908 175,187
1,404,984 1,404,904
$ 9,555,090 $9,419,077
/TABLE
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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CONSOLIDATED BALANCE SHEETS
---------------------------
CAPITALIZATION AND LIABILITIES
------------------------------
SEPTEMBER 30,
1994 DECEMBER 31,
(UNAUDITED) 1993
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(In thousands of dollars)
CAPITALIZATION:
COMMON STOCKHOLDERS' EQUITY:
Common stock - $1 par value; authorized
185,000,000 shares; issued 143,886,104 and
142,427,057 shares, respectively $ 143,886 $ 142,427
Capital stock premium and expense 1,778,894 1,762,706
Retained earnings 666,833 551,332
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2,589,613 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
10,290,005 shares and 4,840,005 shares,
respectively 231,850 95,600
547,650 413,200
Long-term debt 3,244,472 3,258,612
Total capitalization 6,381,735 6,128,277
CURRENT LIABILITIES:
Short-term debt 359,001 368,016
Long-term debt due within one year 68,078 216,185
Sinking fund requirements on redeemable
preferred stock 27,200 27,200
Accounts payable 225,158 299,209
Payable on outstanding bank checks 63,151 35,284
Customers' deposits 14,741 14,072
Accrued taxes 63,880 56,382
Accrued interest 68,458 70,529
Accrued vacation pay 41,370 40,178
Other 133,794 82,145
1,064,831 1,209,200
REGULATORY AND OTHER LIABILITIES:
Accumulated deferred income taxes 1,373,246 1,313,483
Deferred finance charges 239,880 239,880
Unbilled revenues 83,568 94,968
Deferred pension settlement gain 53,266 62,282
Customers refund for replacement power cost
disallowance 5,770 23,081
Other 112,794 107,906
1,868,524 1,841,600
COMMITMENTS AND CONTINGENCIES (NOTE 2):
Liability for environmental restoration 240,000 240,000
$9,555,090 $9,419,077
/TABLE
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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CONSOLIDATED STATEMENTS OF CASH FLOWS
-------------------------------------
INCREASE (DECREASE) IN CASH (UNAUDITED)
----------------------------------------
NINE MONTHS ENDED
SEPTEMBER 30,
1994 1993
------------- ------------
(In thousands of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 254,406 $ 240,876
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 229,804 205,559
Amortization of nuclear fuel 29,316 27,917
Provision for deferred Federal income taxes 59,763 27,127
Electric margin recoverable (27,055) (14,216)
Allowance for other funds used during construction (2,511) (6,090)
Deferred recoverable energy costs 18,697 28,853
Amortization of nuclear replacement power cost
disallowance (17,311) (17,790)
Increase in net accounts receivable 27,639 622
(Increase) Decrease in materials and supplies (76) 21,959
Decrease in accounts payable and accrued expenses (37,251) (42,819)
Increase in accrued interest and taxes 5,427 40,339
Changes in other assets and liabilities 21,800 (8,954)
NET CASH PROVIDED BY OPERATING ACTIVITIES 562,648 503,383
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction additions (294,582) (282,235)
Nuclear fuel (10,427) (17,327)
Less: Allowance for other funds used during
construction 2,512 6,090
Acquisition of utility plant (302,497) (293,472)
Increase in materials and supplies
related to construction 1,390 1,177
Decrease in accounts payable and accrued
expenses related to construction (9,313) (10,705)
Proceeds from sale of investment in oil and
gas subsidiary - 95,408
Increase in other investments (45,413) (21,168)
Other (15,557) (8,979)
NET CASH USED IN INVESTING ACTIVITIES (371,390) (237,739)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the sale of common stock 23,765 110,337
Issuance of preferred stock 150,000 -
Issuance of long-term debt 325,705 635,000
Reductions in long-term debt (486,586) (416,990)
Redemption of preferred stock (15,550) (15,550)
Net change in short-term debt (9,015) (262,698)
Dividends paid (136,768) (122,569)
Other (21,266) (26,090)
NET CASH USED IN FINANCING ACTIVITIES (169,715) (98,560)
NET INCREASE IN CASH 21,543 167,084
Cash at beginning of period 124,351 43,894
CASH AT END OF PERIOD $ 145,894 $ 210,978
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid $ 221,482 $ 216,952
Income taxes paid 93,001 90,347
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND
FINANCING ACTIVITIES:
Liability for environmental restoration - 10,000
/TABLE
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 nine-month periods ended
September 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 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 89 sites with which it
has been or may be associated, including 46 which are
Company-owned. The Company-owned sites include 23 former
coal gasification (MGP) sites, 11 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 43 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 89 sites are seven sites for which the Company has
reached final settlement agreements with other potentially
responsible parties (PRP), five sites where further
remedial activity is not considered necessary 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 agencies, the ultimate cost of
remedial actions may change substantially as investigation
and remediation progresses.
The Company estimates that 40 of the 46 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 $515 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 five 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 September 30,
1994.
With respect to the 43 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 $570 million; however,
the Company estimates its share of this total at
approximately $30 million and this amount has been accrued
at September 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
Company (owners/operators 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 proposed 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, see Note 3. 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
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 currently 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 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 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 granted the
Company's motion for an order directing dismissal of Inter-
Power's complaint for lack of merit and denied Inter-
Power's cross-motion to compel disclosure. The order was
entered July 26, 1994. On August 23, 1994, Inter-Power
filed a notice of appeal of this decision which was
rejected on November 2, 1994. The Company cannot predict
whether Inter-Power will pursue further appeals of this
decision. The Company believes it has meritorious defenses
and will continue 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
petitioned the Federal Energy Regulatory Commission (FERC)
for Extraordinary Relief. The Company responded in
opposition to this petition before FERC. FERC has taken no
action on Fourth Branch's petition other than to seek
information and plans relating to the continued safe
operation of existing facilities. The Company supplied
such information. The Company understands that Fourth
Branch has filed for bankruptcy.
On October 26, 1994, Fourth Branch, through its attorneys
filed a petition with the PSC requesting the PSC to direct
the Company to sell the Mechanicville facility to Fourth
Branch for fair value and to relinquish its colicensee
status on the FERC license, or in the alternative, to
require the Company to turn over its investment in the
plant from rate base. The Company will strongly oppose
this petition.
The Company believes it has meritorious defenses and
intends to defend the lawsuit vigorously. The Company can
neither provide any judgment regarding the likely outcome
of this litigation, nor provide any estimate or range of
possible loss it might incur as a result of such
litigation.
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 determined
by the PSC to have been prudently incurred have been
recoverable through rates in the course of normal
ratemaking procedures and the Company believes that the
items detailed below will 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.
September 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 157,266 154,210
Deferred unregulated generators
contract termination costs 47,493 50,680
Deferred postemployment benefit
costs 53,946 30,741
Deferred gas pipeline costs 28,000 31,000
Deferred recoverable energy
costs 48,935 67,632
Other 61,469 62,766
Total $1,404,984 $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 portion of allowance for funds used during
construction (AFC) related to construction work in process
at Unit 2 which was included in rate base. 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 non-owned sites with which it may be
associated. Current rates provide an annual allowance to
recover anticipated annual expenditures.
Unamortized debt expense represents the costs to issue
long-term debt securities including premiums on certain
debt retirements prior to maturity. These amounts are
amortized ratably over the lives of the related issues in
accordance with PSC directives.
Deferred unregulated generators contract termination costs
represent the Company's cost to buy out certain unregulated
generator projects. Approximately $15 million of these
costs are currently being recovered over a three-year
period 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
phased-in to rates and amounts deferred will be amortized
and recovered, in accordance with the PSC's policy
statement, over a period not to exceed 20 years.
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 includes the difference
between actual fuel costs and the fuel revenues received
through the Company's fuel adjustment clause (FAC) and the
unamortized portion of the Company's mandated contribution
to decommission the Department of Energy's (DOE) uranium
enrichment facilities. The fuel costs are amortized as
they are collected from customers while the costs to
decommission the DOE facilities are being amortized and
recovered, as a fuel cost, over a fifteen year period. The
costs to decommission DOE facilities result from the Energy
Policy Act of 1992, which requires domestic utilities to
contribute amounts, escalated for inflation, based upon the
amount of uranium enriched by DOE for each utility.
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 September 30, 1994 and the
unaudited Consolidated Statements of Income for the three-month
and nine-month periods ended September 30, 1994 and 1993 and of
Cash Flows for the nine months ended September 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.
PRICE WATERHOUSE LLP
ONE MONY PLAZA
SYRACUSE NY 13202
TELEPHONE 315-474-6571
REPORT OF INDEPENDENT ACCOUNTANTS
November 10, 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
September 30, 1994, and the related condensed consolidated
statements of income for the three-month and nine-month periods
ended September 30, 1994 and 1993 and of cash flows for the nine-
months ended September 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
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, as part of its downsizing efforts, is
completing an early retirement and voluntary separation program
under which 1,380 employees elected to participate. Efforts to
reduce tax burdens continue, with the New York 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 this 10-Q, respectively, also
demonstrate the Company's commitment to reducing excessive
unregulated generator payments. These steps exemplify the
Company's resolve to reduce its cost structure and are part of
the overall effort to address the many issues confronting the
Company as further described herein.
Early Retirement and Voluntary Separation Programs
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 included an early retirement
program and a voluntary separation program. On August 30, 1994,
union employees, representing approximately 70% of the Company's
workforce, approved amendments to the current labor agreement
with the Company which offered union employees the early
retirement and voluntary separation plans, in exchange for a
negotiated package of work rule changes.
Elections under the programs became final on October 26, 1994 and
1,380 employees have taken advantage of the early retirement and
voluntary separation program. Most of the participants in the
programs terminated their employment as of October 31, 1994.
While the Company does not have a final cost estimate for the
programs, it believes the cost will be in the range of $100 to
$130 million. The programs are expected to yield labor cost
savings of approximately $75 million in 1995, which includes
capital and expense. While the Company generally intends to
share the savings from the programs with customers in 1995, it
has not determined the method by which the sharing would be
accomplished. Although the staffing reductions are expected to
produce long term savings, the Company may be required to record
a charge against earnings in the fourth quarter of 1994. 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 would approve such recovery.
Competition
The Company is experiencing a loss of industrial load across its
system for a variety of reasons. In some cases, customers have
found alternative suppliers or are generating their own power.
In other cases a weakened economy has forced customers to
relocate or shut down.
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 was 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 had to demonstrate that they could
generate power more economically than the Company's service. The
SC-10 tariff has now been superseded by SC-11 as described below.
During the year that SC-10 was in place, eighteen contracts were
signed, and seventeen are still in effect. Most of the existing
contracts are three year fixed price agreements expiring in late
1996 and early 1997. The total annual SC-10 discounts amount to
$7.9 million, which preserve $32 million in net revenue.
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 as described under the 1994 Rate Agreement for SC-11 in
1994.
The Company expects a significant number of industrial customers
to negotiate contracts and many of these contracts should be
revenue enhancing. As of October 31, 1994, approximately 40
customers had active requests to the Company for an SC-11
contract. Of the ten customers that entered into negotiations
with the Company, three have accepted offers. Those three
contracts provide additional net revenues to the Company of
$122,000 annually. Incremental load is priced at competitive
rates based on current market conditions. Contract lengths are
from three to seven years.
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 stated that the best way for the
Company to address competitive issues would be to take
substantial, but unspecified in amount, 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 of the Company's systems 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.
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.
On November 1, 1994, Governor Cuomo requested the State Energy
Planning Board, in cooperation with other state agencies, the
Energy Association, the Independent Power Producers of New York
and other public interest groups to convene a series of public
forums across the state. The purpose of the public forums is to
pursue, from a broad public policy perspective, all opportunities
to reduce electricity costs while assuring, to the extent
possible, that the transition to a more competitive electric
industry proceeds in a fair and equitable manner. A report on
additional actions to be considered in reducing electricity rates
and bills is due to the governor by July 1, 1995. The Company
believes this to be an appropriate beginning to the process of
managing the transition to a more competitive market, but is
unable to predict the outcome of the process.
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
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.
In response to these competitive forces and changes in regulation
being faced by the Company, the Company has from time to time
considered, and expects to continue to consider, various
strategies designed to enhance its competitive position and to
increase its ability to adapt to and anticipate changes in its
utility business. These strategies may include business
combinations with other companies, internal restructurings
involving the potential separation of its generation,
transmission and/or distribution businesses, on a wholesale or
retail basis, acquisitions of related or unrelated businesses,
and additions to or disposition of portions of its franchised
service territories. The Company may from time to time be
engaged in preliminary discussions, either internally or with
third parties, regarding one or more of these potential
strategies. No assurances can be given as to whether, when or on
what terms any potential transaction of the type described above
may actually occur, or as to the ultimate effect thereof on the
financial condition or competitive position of the Company.
With respect to the foregoing, the New York State Energy Plan
(SEP), issued October 31, 1994 and referred to in Part II. Item 5
Other Events, calls upon the New York Power Authority and the
state's investor-owned utilities to study the feasibility of
creating a joint entity to operate and maintain the nuclear
generating stations in the state and to provide a preliminary
report within six months of the issuance of the final SEP. The
report also calls for the development of a fully competitive
wholesale generation market in the state within five years and
observes that if utility generation is separated from
transmission, the PSC "should consider carefully the valuation
and allocation of utility assets in the regulated and competitive
sectors".
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 could elect not to
raise its rates up to the cap. Such a decision would be based on
the Company's assessment of the market. The Niagara Mohawk
Electric Revenue Adjustment Mechanism (NERAM) and certain expense
deferral mechanisms 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 (so-called "Z factors")
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 Measured Equity
Return Incentive Term (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
that, 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 exceeded 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.
The PSC must rule on the Company's rate request by twelve weeks,
to March 29, 1995. The Company would absorb one-half of the
costs (the lost margin) arising because of the extension from
January 1, 1995. The remainder of the costs would 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 would be instituted for the full
twelve weeks.
On August 31, 1994, the PSC Staff proposed an overall decrease in
electric revenues from 1994 levels of approximately $146 million,
excluding anticipated sales growth. This contrasts with the
Company's proposed total revenue increase, excluding sales
growth, of $146 million for 1995 (which reflects corrections and
updates filed with the PSC in May 1994). Because the Company's
proposed total revenue increase reflects an effective date of
March 29, 1995, while the PSC Staff's proposal is an annualized
amount, the difference between the two positions is approximately
$366 million. The more significant adjustments proposed by the
PSC Staff include disallowance of $90 million in purchased power
payments made principally to unregulated generators; additional
adjustments to the 1995 unregulated generator forecast for
prices, capacity levels and in-service dates of certain projects,
reductions in operating and maintenance expenses stemming largely
from the PSC Staff's contention that the Company's forecast was
unsupported; and assumed increases in revenues from sales to
other utilities and transmission revenues. The PSC Staff also
proposes to disallow certain unregulated generator buyout costs
equal to approximately $12 million in 1995 and to set the
electric return on equity at 10.5%, as compared to the Company's
request of 11%. The PSC Staff recommends that gas revenues be
reduced by $5 million in 1995, while also recommending a return
on equity of 10.5% (as opposed to the Company's request of
11.59%). The reduction from the Company's gas proposal relates
principally to lower departmental expenses and higher expected
sales in 1995.
In response to the Company's electric indexing proposal for 1996
through 1999, the PSC Staff proposed the use of a different index
based on the annual change in a national average electricity
price, elimination of all of the Company-proposed Z-factors
including those for fuel and purchased power costs, environmental
costs, nuclear decommissioning and accounting and tax law
changes, and elimination of the minimum and maximum return on
equity limit. The PSC Staff went well beyond the Company's
proposal by recommending a "regulatory regime that accepts market
based prices for utility generation." The PSC Staff's plan would
limit, in increasing amounts, the amount of embedded generation
costs (including certain plant and unregulated generator costs)
that could be charged to customers. The reference price each
year would be based initially upon the Company's marginal cost of
generation until a reliable market price becomes available.
After a 10 year phase-down, the Company would only be able to
charge a market-related price for generation. The Company would
be forced to absorb the difference between its embedded costs and
what it could charge customers, regardless of whether its past
practices were prudent or even mandated by government action.
While the PSC Staff's case contains no financial modelling of the
potential consequences of its proposal on the Company, such
consequences, if the plan is adopted as proposed could be
substantial. The PSC Staff's plan is based on a price ceiling
rather than a cost of service theory of ratemaking--a departure
from the Company's case and all prior New York State rate-making
principles in the modern era. It in effect also proposes a
substantial but unquantified disallowance with respect to the
Company's generating plants and a similar but undifferentiated
disallowance with respect to the difference between estimated
market costs of power and the amount the Company is required by
law and PSC mandate to pay for unregulated generator power. If
those elements of the PSC Staff's case were to be implemented as
proposed, the Company would also be required to discontinue the
application of Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of
Regulation" and incur substantial writeoffs. These writeoffs
would arise not only from disallowed plant costs and purchased
power costs, but also because the departure from cost-based
ratemaking would result in a writeoff of a substantial portion of
the $1.4 billion of regulatory assets on the Company's balance
sheet no longer being recoverable. The Company has not
quantified all of the amounts which might be involved, but
estimates appear to be of an order of magnitude that would
adversely affect the Company's ability to access the capital
markets on reasonable and customary terms, its dividend paying
capacity, its ability to continue to make payments to unregulated
generators and its ability to maintain current levels of service
to its customers. Senior members of the PSC Staff and other
senior public officials in Albany have made it clear that the PSC
trial staff's proposal was developed independent of consultation
with Commissioners, that the trial staff functions independently
of those individuals and that the process in this proceeding is
far from complete. In the meantime, the Company is continuing to
aggressively advocate its own position.
The continued application of SFAS No. 71 to the financial reports
and financial statements of electric utilities, including the
Company, as competition continues to expand in the industry will
be an issue during this transition period. The Company is unable
to predict the outcome of these proceedings, or the possible
attendant financial consequences. However, the Company strongly
believes that its unregulated generator administrative practices
were prudent and should not be disallowed, that the Company's
unregulated generator purchases are in large part the result of
government policy and should be recovered at no penalty to the
shareholders and that a transition plan to a more competitive
environment must provide for an equitable allocation of
transition costs. In addition, the Company believes that any
transition to a more competitive rate structure should be
addressed in a generic proceeding rather than the Company's
current rate filing. See the last paragraph of "Competition"
under Item 2. above. The ultimate impact on the Company's
financial condition will depend on the pace of change in the
marketplace, the actions of regulators in response to that change
and the actions of the Company in controlling costs
and competing effectively while remaining in substantial part a
regulated enterprise. The Company is unable to predict the
results of the interaction of these factors.
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 NERAM and 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 September 30, 1994,
on such variances for 1994 to be approximately $9 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.
Common Stock Dividend
On October 27, 1994, the Board of Directors authorized a common
stock dividend of $.28 per share, which will be paid on November
30, 1994 to shareholders of record on November 7, 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
by $352 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 deal with 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 projected to grow 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.
As of October 31, 1994, the Company was conducting discussions
with 31 unregulated generator projects representing approximately
809 MW of capacity. These discussions address the issues
contained in its petitions and disputes. In addition, the Company
has settled the issues discussed above with 39 projects amounting
to 1,093 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 Part II. Item 1. Legal Proceedings, for
responses to the Company's notifications.
Financing Plans and Financial Positions
The Company's financing plan for 1994 has been substantially
completed. 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
October 31, 1994, approximately 1.5 million shares of common
stock have been issued through the Dividend Reinvestment and
Employee Plans for approximately $25 million.
The original projection of long-term financing was reduced during
the third quarter of 1994 because the Company announced the sale
of its unregulated subsidiary HYDRA-CO Enterprises, Inc. (HYDRA-
CO) (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.
Assuming PSC Staff's rate proposals (discussed above) are not
adopted in their entirety, 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 November 1, 1994, the Company could
issue $2,311 million aggregate principal amount of First Mortgage
Bonds under the earnings test set forth in the Company's Mortgage
Trust Indenture assuming a 10% interest rate. This includes
approximately $1,271 million on the basis of retired bonds and
$1,040 million supported by additional property currently
certified and available. A total of $200 million of Preference
Stock is currently authorized and unissued. The Company also has
authorized unissued Preferred Stock totaling $255.2 million. The
Company continues to explore and utilize, as appropriate, other
methods of 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.
On September 8, 1994, Moody's Investors Service placed the credit
ratings of the Company under review for possible downgrade. The
review was prompted by both the PSC's September 8 decision on
Sithe/Alcan and the August 31 proposal from the PSC Staff to
reduce the Company's electric and gas rates over the next five
years. Moody's current rating for the Company's senior secured
debt is Baa2.
On September 9, 1994, Standard and Poor's (S&P) placed its
ratings on the Company, Con Ed and Long Island Lighting Company
on credit watch with negative implications. This action by S&P
reflects continued concern about a shift in the regulatory
environment in New York State that would be even more hostile to
the financial health of the state's utilities. S&P's current
rating for the Company's senior secured debt is BBB-, the lowest
investment grade rating.
Cash flows to meet the Company's requirements for the first nine
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 September 30, 1994 versus Three Months Ended
September 30, 1993
The following discussion presents the material changes in results
of operations for the third 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 third quarter were $39.3 million or $.27 per
share, as compared with $40.8 million or $.29 per share in 1993.
As shown in the table below, electric revenues increased $48.7
million or 6.0% from 1993. This increase resulted primarily from
higher fuel adjustment clause revenues to cover increasing
payments to unregulated generators, 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, 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 $13.5 million and $4.0
million in the third quarters of 1994 and 1993, respectively.
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.
Fuel adjustment clause revenues $45.9 million
Sales to other electric systems 13.3
NERAM revenues 9.5
Increase in base rates 5.3
DSM revenues (1.4)
Sales to ultimate consumers (6.4)
Miscellaneous operating revenues (8.1)
MERIT revenues (9.4)
-----
$48.7 million
=====
Electric kilowatt-hour sales to ultimate consumers were
approximately 8.4 billion in the third quarter of 1994, a 0.9%
increase from 1993. After considering the effects of weather,
the Company estimates sales to ultimate consumers increased 1.3%.
Sales for resale increased 885 million kilowatt-hours (99.1%)
resulting in an increase in total electric kilowatt-hour sales of
963 million (10.4%).
Electric fuel and purchased power costs increased $64.3 million
or 24.0%. This increase is the result of a $70.0 million
increase in purchased power costs (principally payments to
unregulated generators) and a $9.3 million net increase in costs
deferred and recovered through the operation of the fuel
adjustment clause offset by a decrease in fuel costs of $15.0
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 third
quarter of 1994.
Gas revenues decreased $9.8 million or 14.5% in 1994 from the
comparable period in 1993 as set forth in the table below:
Transportation of customer-owned gas $ 1.8 million
Sales to ultimate consumers 1.2
Increase in base rates 0.8
Purchased gas adjustment clause revenues 0.4
Miscellaneous operating revenues (0.7)
MERIT revenues (2.3)
Spot market sales (11.0)
-----
$(9.8) million
=====
Gas sales to ultimate consumers were 5.8 million dekatherms, a
3.1% increase from the third quarter of 1993. After considering
the effects of weather, the Company estimates sales to ultimate
consumers increased 5.7%. Transportation of customer-owned gas
increased 4.3 million dekatherms (28.9%). 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.
As a result of a slight decrease in dekatherms purchased for
ultimate consumer sales coupled with a 11.2 million decrease in
dekatherms purchased for spot market sales, and a $6.8 million
decrease in purchased gas costs and certain other items
recognized and recovered through the purchased gas adjustment
clause, offset by a $4.9 million increase in the cost of
dekatherms purchased, the total cost of gas included in expense
decreased 38.3% in 1994. The Company's net cost per dekatherm
sold, as charged to expense and excluding spot market purchases,
decreased from $3.43 in 1993 to $3.19 in 1994.
Three Months Ended September 30,
(In Millions)
Increase %
1994 1993 (Decrease) Change
Other operation expense $177.0 $ 192.0 $(15.0) (7.8)
Maintenance 51.3 59.0 (7.7) (13.1)
Depreciation and amortization 77.5 69.3 8.2 11.8
Federal and foreign income taxes, net 27.7 28.2 (0.5) (1.8)
Other taxes 123.0 118.5 4.5 3.8
Other items (net) 5.8 4.6 1.2 26.1
Interest charges 70.8 72.6 (1.8) (2.5)
Other operation expense decreased primarily due to the decrease
in nuclear costs and the decrease in amortization of other
regulatory deferrals, which expired in 1993.
Maintenance expense decreased principally due to less expenses on
the fossil stations because of economy shutdowns at the Oswego
and Albany plants coupled with less maintenance performed on
transmission lines during the third quarter of 1994 as compared
to 1993.
Depreciation and amortization increased due to the closing of
major orders to plant in service during late 1993 and early 1994.
Other taxes increased primarily because of higher real estate
taxes.
Interest charges decreased from 1993, primarily due to the
refunding of debt to obtain lower interest rates.
Material Changes in Results of Operations
Nine Months Ended September 30, 1994 versus Nine Months Ended
September 30, 1993
The following discussion presents the material changes in results
of operations for the first nine months 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 nine month
periods should not be taken as an indication of earnings for all
or any part of the balance of the year.
Earnings for the first nine months of 1994 were $231.2 million or
$1.62 per share, as compared with $216.7 million or $1.55 per
share in 1993.
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 million and further adjustments
may be allowed as the 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.
As shown in the table below, electric revenues increased $151.2
million or 6.1% from 1993. This increase results primarily from
higher recoveries through the operation of the fuel adjustment
clause mechanism, the increase in sales to other electric
systems, and the second stage rate increase granted in September
1993. 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 $52.7 million in the first nine months of
1994 as compared with $44.2 million in 1993. Revenues of $8.4
million ($7.7 electric and $.7 gas) were recorded in the nine
months ended September 30, 1994, in accordance with the
preliminary MERIT allowance for 1993. MERIT revenues recorded in
the first nine months of 1993 were $10.3 million.
Fuel adjustment clause revenues $ 83.3 million
Sales to other electric systems 58.0
Increase in base rates 35.0
Sales to ultimate consumers 10.7
NERAM revenues 8.5
MERIT revenues (1.5)
Miscellaneous operating revenues (18.3)
DSM revenues (24.5)
------
$151.2 million
======
Electric kilowatt-hour sales to ultimate consumers were
approximately 25.9 billion in 1994, a 1.2% increase from 1993.
After considering the effects of weather, the Company estimates
sales to ultimate consumers increased slightly (0.2%). During
the first nine months of 1994, industrial sales increased as
shown in the table below. 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 3.1 million kilowatt-hours (116.2%) resulting in a net
increase in total electric kilowatt-hour sales of 3.4 million
(12.2%). 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, the Company retains 40% of the gross margin variance
from the forecast of sales for resale, with the remainder passed
back to ratepayers. On July 21, 1994, the Company set an all-
time electric summer peak load sending out 6,312,000 kilowatts.
Changes in electric revenues and sales by customer group are
detailed in the table below:
Revenues (Thousands) Sales (GwHrs)
% %
1994
Residential . . . . . . . . . . . . . $ 953,803 $ 891,707 7.0 8,086 8,030 0.7
Commercial . . . . . . . . . . . . . 972,878 937,381 3.8 9,055 9,177 (1.3)
Industrial . . . . . . . . . . . . . 433,957 417,225 4.0 5,538 5,309 4.3
Industrial - Special . . . . . . . . 37,901 31,947 18.6 3,048 2,891 5.4
Municipal . . . . . . . . . . . . . . 37,005 37,191 (0.5) 152 155 (1.9)
Total to Ultimate Consumers . . . . . 2,435,544 2,315,451 5.2 25,879 25,562 1.2
Other Electric Systems . . . . . . . 130,399 72,404 80.1 5,807 2,686 116.2
Miscellaneous . . . . . . . . . . . . 75,632 102,537 (26.2) - - -
Total . . . . . . . . . . . . . . . $2,641,575 $2,490,392 6.1 31,686 28,248 12.2
Electric fuel and purchased power costs increased $196.0 million
or 24.6%. This increase is the result of a $218.2 million
increase in purchased power costs (principally payments to
unregulated generators), offset by a $2.4 million net decrease in
costs deferred and recovered through the operation of the fuel
adjustment clause and by a decrease in fuel costs of $19.8
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
nine months of 1994.
Nine Months Ended September 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
------ ------ ------ ------ ------ ------ ----------
Coal 5,147 $ 81.4 5,326 $ 83.9 (3.4) (3.0) 1.58
cents
Oil 1,165 37.6 1,728 57.8 (32.6) (34.9) 3.23
Natural Gas 354 9.4 475 11.2 (25.5) (16.1) 2.66
Nuclear 6,321 37.4 5,708 32.7 10.7 14.4 .59
Hydro 2,634 - 2,627 - 0.3 - -
------ ------ ----- ------ ----- ----- ----
15,621 165.8 15,864 185.6 (1.5) (10.7) 1.06
------ ------ ------ ------ ----- ----- ----
ELECTRICITY PURCHASED:
Unregulated Generators 11,075 716.5 8,277 525.6 33.8 36.3 6.47
Other 7,866 109.6 6,512 82.3 20.8 33.2 1.39
------ ------ ------ ------ ----- ----- ----
18,941 826.1 14,789 607.9 28.1 35.9 4.36
------ ------ ------ ------ ----- ----- ----
34,562 991.9 30,653 793.5 12.8 25.0 2.87
------ ------ ------ ------ ----- ----- ----
Fuel adjustment clause - 0.2 - 2.6 - (92.3) -
Losses/Company use 2,876 - 2,405 - 19.6 - -
------ ------ ------ ------ ----- ----- ----
31,686 $992.1 28,248 $796.1 12.2 24.6 3.13
====== ====== ====== ====== ===== ===== cents
====
Gas revenues increased $37.6 million or 8.3% in 1994 from the
comparable period in 1993 as set forth in the table below:
Sales to ultimate consumers and other sales $39.7 million
Purchased gas adjustment clause revenues 12.0
Increase in base rates 6.2
Miscellaneous operating revenues 4.1
Transportation of customer-owned gas 0.7
MERIT revenues (1.5)
Spot market sales (23.6)
------
$37.6 million
=====
Gas sales, excluding transportation of customer owned gas, were
68.4 million dekatherms, a 9.2% increase from the first nine
months of 1993. After considering the effects of weather, the
Company estimates sales to ultimate consumers increased 4.5%.
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 11.9 million
(24.2%). Changes in gas revenues and dekatherm sales by customer
group are detailed in the table below:
Revenues (Thousands) Sales (Thousands of Dekatherms)
% %
1994 1993 Change 1994 1993 Change
Residential . . . . . . . . . . . . . $319,995 280,473 14.1 45,369 42,203 7.5
Commercial . . . . . . . . . . . . . 127,012 108,154 17.4 20,378 17,889 13.9
Other Gas Systems . . . . . . . . . . 840 701 19.8 174 203 (14.3)
Transportation of Customer-
Owned Gas . . . . . . . . . . . . . . 26,860 26,164 2.7 61,105 49,194 24.2
Spot Market Sales . . . . . . . . . . 4,204 28,065 (85.0) 1,481 12,500 (88.2)
Miscellaneous . . . . . . . . . . . . 1,771 (104) (1802.9) - - -
Total . . . . . . . . . . . . . . $492,493 $454,844 8.3 130,961 124,296 5.4
As a result of a 6.3 million increase in dekatherms purchased and
withdrawn from storage for ultimate consumer sales offset by a
23.7 million decrease in dekatherms purchased for spot market
sales, coupled with a $31.8 million increase in the cost of
dekatherms purchased and a $.8 million decrease 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 3.2% in 1994. The Company's net
cost per dekatherm sold, as charged to expense, excluding spot
market purchases, increased from $3.81 in 1993 to $3.91 in 1994.
Nine Months Ended September 30,
(In Millions)
Increase %
1994 1993 (Decrease) Change
Other operation expense $ 523.7 $582.5 $ (58.8) (10.1)
Maintenance 145.2 161.3 (16.1) (10.0)
Depreciation and amortization 229.8 205.6 24.2 11.8
Federal and foreign income taxes, net 156.5 144.1 12.4 8.6
Other taxes 377.9 362.4 15.5 4.3
Other items (net) 12.2 6.8 5.4 79.4
Interest charges 214.8 219.6 (4.8) (2.2)
/TABLE
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 and maintenance outage
in the first half of 1993.
Depreciation and amortization increased due to the closing of
major orders to plant in service during late 1993 and early 1994.
Federal income taxes (net) increased as a result of an increase
in pre-tax income.
Other taxes increased primarily because of higher real estate,
payroll and state sales taxes.
Interest charges decreased primarily due to the refunding of debt
to obtain lower interest rates.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
PART II
Item 1. Legal Proceedings.
1. 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 of the contracts, future
avoided costs, and future operating costs of the projects.
As of November 10, 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. On October 5, 1994, Sterling moved for summary
judgment. The court has scheduled a hearing on the motion
for November 16, 1994; 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. On November 2, 1994, NorCon
filed for summary judgment. The court has indicated that it
will advise the Company on December 2, 1994 regarding what,
if any, response is due.
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.
The Company is involved in a number of court cases regarding
the price of energy it is required to purchase in excess of
contract levels from certain unregulated generators
("overgeneration"). The Company has paid the unregulated
generators based on its long-run avoided cost for all such
overgeneration rather than the price which the unregulated
generators contend is applicable under the contracts. The
Company cannot predict the outcome of these actions, but
will continue to aggressively press its position.
Item 5. Other Events.
1. Sithe/Alcan
In April 1994, the New York State Public Service Commission
(PSC) ruled that, in the event Sithe Independence Power
Partners Inc. (Sithe) ultimately obtained authority to sell
electric power at retail, those retail sales would be
subject to a lower level of regulation than the PSC
presently imposes on the Company. Sithe, which will sell
electricity to Consolidated Edison of New York, Inc. (Con
Ed) and the Company on a wholesale basis from its 1,040
megawatt natural gas cogeneration plant, plans to provide
steam to Alcan Rolled Products (Alcan). Sithe also 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 prohibited 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 maintained that if the PSC nevertheless granted
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.
On September 8, 1994, the PSC authorized sales by Sithe of
electricity directly to Alcan and to Liberty Paperboard
(Liberty), a potential new industrial customer. The Company
had opposed such authorizations. In his report to the PSC,
the Administrative Law Judge (ALJ) recommended that Sithe
pay the Company a fee based upon the prices at which Sithe
would sell to Alcan. The ALJ recommended a fee structured
to produce a net present value of approximately $19.6
million based on annual payments tied to long-run avoided
costs (LRACs) to be paid over a period of ten years. On
September 29, 1994, the PSC's decision confirmed the ALJ's
report and fee structure. For 1995, the ALJ's recommended
fee would be approximately $3.9 million. He recommended
against a fee in connection with Sithe's sale to Liberty.
On October 12, 1994, the Company filed an appeal in State
Supreme Court, Albany County, which states that the April
1994 PSC Order is a violation of legal procedure and
precedent and should be reversed. The Company cannot
predict the outcome of this proceeding, but will continue to
press its position.
2. Sale of Subsidiary
During October 1994, the Company announced that it would
sell its wholly-owned subsidiary, HYDRA-CO, and unregulated
generator, to CMS Generation Co., an independent power
subsidiary of CMS Energy Corp., Dearborn, Michigan. The
buyer was determined through a competitive auction and the
sale is expected to realize proceeds of more than $200
million. The Company's goal is to consummate the sale by
the end of 1994. The sale is not expected to have a
material effect on the Company's financial position or
results of operations for 1994.
3. Unit 1 Economic Study
Under the terms of a previous regulatory agreement, the
Company agreed to prepare and update studies of the
advantages and disadvantages of continued operation of Unit
1 prior to the start of the next two refueling outages. The
first report, which recommended continued operation of Unit
1 over the remaining term of its license (2009), was filed
with the PSC in March 1990 and a second study in November
1992 also indicated that the Unit could continue to provide
benefits for the term of its license if operating costs can
be reduced and generating output improved above its then
historical average.
The third study was filed with the PSC on November 1, 1994.
This study agreed with previous studies which confirmed
continued operation over the remaining term of its license.
The Company believes 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 operating experience at Unit 1 has improved
substantially since the prior study. Unit 1's capacity
factor has been about 94% since the last refueling outage.
In connection with the Economic Study, the Company also
updated its estimated costs to decommission Unit 1. The
estimate includes amounts for both radioactive and non-
radioactive dismantlement costs, as well as spent fuel
storage cost estimates until the fuel can be transferred to
a permanent federal repository. The estimate of radioactive
($255 million) and non-radioactive ($50 million)
dismantlement in 1993 dollars is approximately $305 million.
Fuel storage and plant maintenance estimates will increase
the total estimated costs to approximately $515 million (in
1993 dollars), and this amount escalates to $1.4 billion,
largely due to a plan which would delay dismantlement to
coincide with Unit 2's decommissioning, currently scheduled
to begin in 2026.
The company is unable to predict what reaction, if any, may
ensue from its regulators and other parties in connection
with this study.
4. Final 1994 New York State Energy Plan
On October 31, 1994, The State Energy Planning Board issued
the final 1994 New York State Energy Plan, which calls for
significant reductions in state energy taxes and endorses
greater competition in utility purchases of electricity.
The plan places increased emphasis on the use of energy
policy as a means to lower electricity costs and to promote
sustained economic development. The plan continues New
York's commitment to narrowing the gap between its
electricity prices and the national averages and supports
the strong consensus that New York should foster the
development of competitive wholesale generation markets. It
also recommends retail competition should occur when fair
treatment of all customer classes, of competitors, of energy
efficiency and renewables, and of capital committed in
prudent response to past government mandates is reasonably
assured. The Company is unable to predict how this plan
will influence regulatory policy.
5. New York State Proposals
During October 1994, the governor of New York announced that
at his request, the president of the New York Power
Authority (NYPA) and the chairman of the Long Island Power
Authority (LIPA) have invited the Long Island Lighting
Company (LILCO) to begin immediate negotiations for the
public purchase of LILCO. The governor stated that the
"bottom line" requirement for undertaking the purchase would
be the immediate realization of a 10 percent reduction in
Long Island electric rates. One of the factors involved in
this action is the increasing amount of competition in the
utility marketplace.
Also during 1994, the NYPA issued a report to its trustees
concerning a restructuring effort for the 21st century.
This report stated that a major step toward a competitive
electric industry would be to separate transmission from
generation. It also stated that another significant advance
toward cutting the price of electricity would be the
creation of a single operating company for all six of New
York State's nuclear power plants. The report recommends
creation of a New York State Electrical Thruway that would
combine all of the State's transmission lines into one
independent entity.
The effect on the Company's financial position or results of
operations based on the above events, if any, cannot be
determined at this time.
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 Nine Months
Ended September 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
September 30, 1994.
Exhibit 15 - Accountants' Acknowledgement Letter.
Exhibit 27 - Financial Data Schedule.
(b) Reports 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.
Form 8-K Reporting Date - September 26, 1994.
Items reported - Item 5. Other Events.
Registrant filed information concerning rate case
proceedings, Early Retirement and Voluntary Separation
Program, and an update on competition, and credit ratings.
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: November 14, 1994 By /s/ Steven W. Tasker
Steven W. Tasker
Vice President-Controller and
Principal Accounting Officer,
in his respective capacities
as such
EXHIBIT 11
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
---------------------------------------------------------
Computation of the Average Number of Shares of Common Stock Outstanding
For the Three and Nine Months Ended September 30, 1994 and 1993
(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)
-------- ----------- ------- ---------------------
FOR THE THREE MONTHS
ENDED SEPTEMBER 30,
JULY 1 - SEPTEMBER 30,
1994 143,316,804 92 13,185,145,968
SHARES SOLD AT VARIOUS
TIMES DURING THE PERIOD -
DIVIDEND REINVESTMENT PLAN 279,100 *<F1> 8,525,566
EMPLOYEE SAVINGS FUND PLAN 290,200 *<F1> 11,995,200
----------- --------------
143,886,104 13,205,666,734 143,539,856
=========== ============== ===========
JULY 1 - SEPTEMBER 30,
1993 141,960,209 92 13,060,339,228
SHARES SOLD AT VARIOUS
TIMES DURING THE PERIOD -
DIVIDEND REINVESTMENT PLAN 151,548 *<F1> 4,732,778
----------- --------------
142,111,757 13,065,072,006 142,011,652
=========== ============== ===========
(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)
-------- ----------- ------- ---------------------
FOR THE NINE MONTHS
ENDED SEPTEMBER 30:
JANUARY 1 - SEPTEMBER 30,
1994 142,427,057 273 38,882,586,561
SHARES SOLD AT VARIOUS
TIMES DURING THE PERIOD -
DIVIDEND REINVESTMENT PLAN 700,447 *<F1> 76,681,828
EMPLOYEE SAVINGS FUND PLAN 758,600 *<F1> 76,225,500
----------- --------------
143,886,104 39,035,493,889 142,987,157
=========== ============== ===========
JANUARY 1 - MAY 4, 1993 137,159,607 124 17,007,791,268
SHARES SOLD MAY 5, 1993 4,494,000
-----------
MAY 5 - SEPTEMBER 30, 1993 141,653,607 149 21,106,387,443
SHARES SOLD AT VARIOUS
TIMES DURING THE PERIOD -
DIVIDEND REINVESTMENT PLAN 457,041 *<F1> 54,818,062
PURCHASE- SYRACUSE SUBURBAN 1,109 *<F1> 248,346
----------- --------------
142,111,757 38,169,245,119 139,814,085
=========== ============== ===========
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
EXHIBIT 12
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
---------------------------------------------------------
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 September 30, 1994 (in thousands of
dollars)
A. Net income $ 285,362
B. Taxes Based on Income or Profits 159,517
----------
C. Earnings, Before Income Taxes 444,879
D. Fixed Charges (a) 314,370
----------
E. Earnings Before Income Taxes and
Fixed Charges 759,249
F. Allowance for Funds Used During
Construction (AFC) 12,044
----------
G. Earnings Before Income Taxes and
Fixed Charges without AFC $ 747,205
=========
PREFERRED DIVIDEND FACTOR:
H. Preferred Dividend Requirements $ 30,825
---------
I. Ratio of Pre-tax Income to Net
Income (C/A) 1.559
----------
J. Preferred Dividend Factor (HxI) $ 48,056
K. Fixed Charges as Above (D) 314,370
----------
L. Fixed Charges and Preferred Dividends
Combined $ 362,426
==========
M. Ratio of Earnings to Fixed
Charges (E/D) 2.42
==========
N. Ratio of Earnings to Fixed Charges
without AFC (G/D) 2.38
==========
O. Ratio of Earnings to Fixed Charges
and Preferred Dividends Combined (E/L) 2.09
==========
(a) Includes a portion of rentals deemed representative of the
interest factor ($27,848).
/TABLE
PRICE WATERHOUSE LLP
ONE MONY PLAZA
SYRACUSE NY 13202
TELEPHONE 315-474-6571
EXHIBIT 15
----------
November 10, 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 November 10, 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