SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 1996
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OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-2987.
NIAGARA MOHAWK POWER CORPORATION
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(Exact name of registrant as specified in its charter)
State of New York 15-0265555
- ------------------ ----------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
300 Erie Boulevard West Syracuse, New York 13202
(Address of principal executive offices) (Zip Code)
(315) 474-1511
Registrant's telephone number, including area code
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements
for the past 90 days.
YES [X] NO [ ]
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Common stock, $1 par value, outstanding at April 30, 1996 -
144,332,855
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
FORM 10-Q - For The Quarter Ended March 31, 1996
INDEX
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PART I. FINANCIAL INFORMATION
Glossary of Terms
Item 1. Financial Statements.
a) Consolidated Statements of Income -
Three Months Ended March 31, 1996 and 1995
b) Consolidated Balance Sheets - March 31,
1996 and December 31, 1995
c) Consolidated Statements of Cash Flows -
Three Months Ended March 31, 1996 and 1995
d) Notes to Consolidated Financial Statements
e) Review by Independent Accountants
f) Independent Accountants' Report on the
Limited Review of the Interim Financial
Information
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of
Operations.
PART II. OTHER INFORMATION
Item 5. Other Events.
Item 6. Exhibits and Reports on Form 8-K.
Signature
NIAGARA MOHAWK POWER CORPORATION
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GLOSSARY OF TERMS
- -----------------
TERM DEFINITION
- ---- ----------
DSM Demand-Side Management
Dth Dekatherms
FAC Fuel Adjustment Clause
FERC Federal Energy Regulatory Commission
GwHrs Gigawatt-hours
HYDRA- HYDRA-CO Enterprises, Inc.
CO
ISO Independent System Operator
Kwh Kilowatt-hour
NOPR Notice of Proposed Rulemaking
PRP Potentially responsible party
PSC New York State Public Service Commission
SFAS Statement of Financial Accounting Standards No. 71
No. 71 "Accounting for the Effects of Certain Types of
Regulation"
SFAS Statement of Financial Accounting Standards No. 121
No. 121 "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed of"
UG Unregulated Generator
Unit 1 Nine Mile Point Nuclear Station Unit No. 1
Unit 2 Nine Mile Point Nuclear Station Unit No. 2
PART 1. FINANCIAL INFORMATION
- -----------------------------
ITEM 1. FINANCIAL STATEMENTS.
- -----------------------------
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
- ---------------------------------------------
THREE MONTHS ENDED MARCH 31,
---------------------------
1996 1995
--------------- -----------
(In thousands of dollars)
OPERATING REVENUES:
Electric $ 851,137 $ 881,920
Gas 311,926 242,893
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1,163,063 1,124,813
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OPERATING EXPENSES:
Operation:
Fuel for electric generation 49,564 44,406
Electricity purchased 287,308 286,871
Gas purchased 189,995 126,479
Other operation expense 162,866 154,814
Maintenance 46,156 44,766
Depreciation and amortization 82,064 78,316
Federal and foreign income taxes 56,623 78,372
Other taxes 130,478 132,384
---------- ----------
1,005,054 946,408
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OPERATING INCOME 158,009 178,405
---------- ----------
OTHER INCOME AND (DEDUCTIONS):
Allowance for other funds used
during construction 408 -
Federal and foreign income taxes 3,804 (8,805)
Other items (net) 2,452 16,075
---------- ----------
6,664 7,270
---------- ----------
INCOME BEFORE INTEREST CHARGES 164,673 185,675
---------- ----------
INTEREST CHARGES:
Interest on long-term debt 68,191 63,349
Other interest 1,382 7,132
Allowance for borrowed funds used
during construction (1,022) (3,542)
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68,551 66,939
NET INCOME 96,122 118,736
Dividends on preferred stock 9,619 10,215
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BALANCE AVAILABLE FOR COMMON STOCK $ 86,503 $ 108,521
========== ==========
Average number of shares of common
stock outstanding
(in thousands) 144,333 144,324
Balance available per average
share of common stock $ .60 $ .75
Dividends paid per share of common
stock $ - $ .28
/TABLE
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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CONSOLIDATED BALANCE SHEETS
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ASSETS
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MARCH 31, 1996
(UNAUDITED) DECEMBER 31, 1995
------------ -----------------
(In thousands of dollars)
UTILITY PLANT:
Electric plant $ 8,549,060 $ 8,543,429
Nuclear fuel 520,593 517,681
Gas plant 1,034,583 1,017,062
Common plant 286,397 281,525
Construction work in progress 266,708 289,604
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Total utility plant 10,657,341 10,649,301
Less-Accumulated depreciation and
amortization 3,682,455 3,641,448
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Net utility plant 6,974,886 7,007,853
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OTHER PROPERTY AND INVESTMENTS 186,003 218,417
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CURRENT ASSETS:
Cash, including temporary cash investments
of $133,097 and $114,415, respectively 182,178 153,475
Accounts receivable (less allowance for
doubtful accounts of $20,000) 501,910 463,234
Electric margin recoverable 8,208 8,208
Materials and supplies, at average cost:
Coal and oil for production of electricity 17,571 27,509
Gas storage 1,647 26,431
Other 139,705 141,820
Prepaid taxes 74,761 17,239
Other 38,712 45,834
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964,692 883,750
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REGULATORY AND OTHER ASSETS (NOTE 3):
Regulatory tax asset 470,198 470,198
Deferred finance charges 239,880 239,880
Deferred environmental restoration
costs (Note 2) 225,000 225,000
Unamortized debt expense 87,964 92,548
Postretirement benefits other than pensions 68,338 68,933
Other 155,478 204,253
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1,246,858 1,300,812
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OTHER ASSETS 86,588 67,037
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$ 9,459,027 $ 9,477,869
=========== ===========
/TABLE
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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CONSOLIDATED BALANCE SHEETS
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CAPITALIZATION AND LIABILITIES
- ------------------------------
MARCH 31, 1996
(UNAUDITED) DECEMBER 31, 1995
-------------- -----------------
(In thousands of dollars)
CAPITALIZATION:
COMMON STOCKHOLDERS' EQUITY:
Common stock - $1 par value; authorized
185,000,000 shares; issued 144,332,855 and
144,332,123 shares, respectively $ 144,333 $ 144,332
Capital stock premium and expense 1,784,547 1,784,247
Retained earnings 671,876 585,373
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2,600,756 2,513,952
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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
258,000 shares 24,000 24,000
CUMULATIVE PREFERRED STOCK, AUTHORIZED 19,600,000
SHARES, $25 PAR VALUE:
Non-redeemable (optionally redeemable),
issued 9,200,000 shares 230,000 230,000
Redeemable (mandatorily redeemable), issued
3,108,005 and 3,208,005 shares, respectively 71,600 72,850
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535,600 536,850
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Long-term debt 3,480,197 3,582,414
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Total capitalization 6,616,553 6,633,216
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CURRENT LIABILITIES:
Long-term debt due within one year 58,571 65,064
Sinking fund requirements on redeemable
preferred stock 7,900 9,150
Accounts payable 222,563 268,603
Payable on outstanding bank checks 24,453 36,371
Customers' deposits 14,320 14,376
Accrued taxes 61,971 14,770
Accrued interest 73,740 64,448
Accrued vacation pay 35,520 35,214
Other 50,809 57,748
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549,847 565,744
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REGULATORY LIABILITIES (NOTE 3):
Deferred finance charges 239,880 239,880
Other 2,695 2,712
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242,575 242,592
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OTHER LIABILITIES:
Accumulated deferred income taxes 1,405,514 1,388,799
Employee pension and other benefits 253,648 245,047
Deferred pension settlement gain 27,133 32,756
Unbilled revenues 19,211 28,410
Other 119,546 116,305
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1,825,052 1,811,317
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COMMITMENTS AND CONTINGENCIES (NOTES 2 AND 3):
Liability for environmental restoration 225,000 225,000
---------- ----------
$9,459,027 $9,477,869
========== ==========
/TABLE
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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CONSOLIDATED STATEMENTS OF CASH FLOWS
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INCREASE (DECREASE) IN CASH (UNAUDITED)
- ---------------------------------------
THREE MONTHS ENDED MARCH 31,
1996 1995
------------ --------------
(In thousands of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 96,122 $ 118,736
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 82,064 78,316
Amortization of nuclear fuel 10,917 5,233
Provision for deferred income taxes 16,715 50,026
Gain on sale of subsidiary - (11,257)
Unbilled revenues - (25,557)
Increase in net accounts receivable (47,875) (26,767)
Decrease in materials and supplies 35,991 25,244
Decrease in accounts payable and accrued expenses (45,933) (64,563)
Increase in accrued interest and taxes 56,493 55,164
Changes in other assets and liabilities (15,670) (14,831)
---------- ----------
NET CASH PROVIDED BY OPERATING ACTIVITIES 188,824 189,744
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction additions (51,792) (68,100)
Nuclear Fuel (2,912) (6,564)
---------- ----------
Acquisition of utility plant (54,704) (74,664)
Decrease in materials and supplies
related to construction 846 827
Decrease in accounts payable and accrued
expenses related to construction (11,483) (16,141)
(Increase) decrease in other investments 33,971 (51,245)
Proceeds from sale of subsidiary (net of cash sold) - 161,087
Other (6,895) 1,316
---------- ----------
NET CASH PROVIDED BY (USED IN)
INVESTING ACTIVITIES (38,265) 21,180
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in long-term debt 80,000 -
Net change in revolving credit agreements (170,000) (99,000)
Reductions of preferred stock (2,500) -
Reductions in long-term debt (19,341) (6,447)
Net change in short-term debt - (37,750)
Dividends paid (9,619) (50,628)
Other (396) (11,243)
---------- ----------
NET CASH USED IN FINANCING ACTIVITIES (121,856) (205,068)
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NET INCREASE IN CASH 28,703 5,856
Cash at beginning of period 153,475 94,330
---------- ----------
CASH AT END OF PERIOD $ 182,178 $ 100,186
========== ==========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid $ 61,291 $ 67,047
Income taxes paid (refunded) $ 17,367 $ (19,210)
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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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 1996 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, 1995, 1994 and 1993 included in the Company's
1995 Annual Report to Shareholders on Form 10-K.
The Company's electric sales tend to be substantially
higher in summer and winter months as related to weather
patterns in its service territory; gas sales tend to peak
in the winter. Notwithstanding other factors, the
Company's quarterly net income will generally fluctuate
accordingly. Therefore, the earnings for the three-month
period ended March 31, 1996, 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 1996
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. The Company believes it is handling identified
wastes and by-products in a manner consistent with federal,
state and local requirements and has implemented an
environmental audit program to identify any potential areas
of concern and assure compliance with such requirements.
The Company is also currently conducting a program to
investigate and restore, as necessary to meet current
environmental standards, certain properties associated with
its former gas manufacturing process and other properties
which the Company has learned may be contaminated with
industrial waste, as well as investigating identified
industrial waste sites as to which it may be determined
that the Company contributed. The Company has also been
advised that various federal, state or local agencies
believe certain properties require investigation and has
prioritized the sites based on available information in
order to enhance the management of investigation and
remediation, if necessary.
The Company is currently aware of 88 sites with which it
has been or may be associated, including 45 which are
Company-owned. With respect to non-owned sites, the
Company may be required to contribute some proportionate
share of remedial costs.
Investigations at each of the Company-owned sites are
designed to (1) determine if environmental contamination
problems exist, (2) if necessary, determine the appropriate
remedial actions required for site restoration and (3)
where appropriate, identify other parties who should bear
some or all of the cost of remediation. Legal action
against such other parties will be initiated where
appropriate. After site investigations are completed, the
Company expects to determine site-specific remedial actions
and to estimate the attendant costs for restoration.
However, since technologies are still developing the
ultimate cost of remedial actions may change substantially.
Estimates of the cost of remediation and post-remedial
monitoring are based upon a variety of factors, including
identified or potential contaminants, location, size and
use of the site, proximity to sensitive resources, status
of regulatory investigation and knowledge of activities at
similarly situated sites, and the United States
Environmental Protection Agency figure for average cost to
remediate a site. Actual Company expenditures are
dependent upon the total cost of investigation and
remediation and the ultimate determination of the Company's
share of responsibility for such costs, as well as the
financial viability of other identified responsible parties
since clean-up obligations are joint and several. The
Company has denied any responsibility in certain of these
PRP sites and is contesting liability accordingly.
As a consequence of site characterizations and assessments
completed to date and negotiations with PRP's, the Company
has accrued a liability in the amount of $225 million,
which is reflected in the Company's Consolidated Balance
Sheets at March 31, 1996 and December 31, 1995. This
liability represents the low end of the range of its share
of the estimated cost for investigation and remediation.
The potential high end of the range is presently estimated
at approximately $930 million, including approximately $430
million in the unlikely event the Company is required to
assume 100% responsibility at non-owned sites.
Prior to 1995, the Company recovered 100% of its costs
associated with site investigation and restoration. In the
Company's 1995 rate order, costs incurred during 1995 for
the investigation and restoration of Company-owned sites
and sites with which it is associated were subject to
80%/20% (ratepayer/Company) sharing. In 1995, the Company
incurred $11.5 million of such costs, resulting in a
disallowance of $2.3 million (before tax), which the
Company recognized as a loss in Other items (net) on the
Consolidated Statements of Income. The PSC stated in its
opinion, dated December 1995, its decision to require
sharing was "on a one-time, short-term basis only, pending
its further evaluation of the issue in future proceedings."
The Company has recorded a regulatory asset representing
the remediation obligations to be recovered from
ratepayers.
Where appropriate, the Company has provided notices of
insurance claims to carriers with respect to the
investigation and remediation costs for manufactured gas
plant, industrial waste sites and sites for which the
Company has been identified as a PRP. 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 Unit 2. The Company is
vigorously defending its position on each of the issues,
and submitted a protest to the IRS in 1993. Pursuant to
the Unit 2 settlement entered into with the PSC in 1990, to
the extent the IRS is able to sustain adjustments, the
Company will be required to absorb a portion of any
assessment. The Company believes any such disallowance
will not have a material impact on its financial position
or results of operations under traditional ratemaking. The
Company is currently attempting to negotiate a settlement
of these issues with the Appeals Division of the IRS.
In addition, the IRS has conducted an examination of the
Company's Federal income tax returns for the years 1989 and
1990. The Company received a Revenue Agents' Report in
late January 1996. The IRS has raised the issue concerning
the deductibility of payments made to UGs in accordance
with certain contracts that include a provision for an
Advance Payment Account. The IRS proposes to disallow a
current deduction for amounts paid in excess of the avoided
costs of the Company. Although the Company believes that
any such disallowance for the years 1989 and 1990 will not
have a material impact on its financial position or results
of operations, it believes that a disallowance for these
above-market payments for the years subsequent to 1990
could have a material adverse affect on its cash flows.
The IRS has begun its examination of the Company's Federal
income tax returns for the years 1991 through 1993. The
Company is vigorously defending its position on this issue.
LITIGATION: The Company is unable to predict the ultimate
disposition of the lawsuits referred to below. However,
the Company believes it has meritorious defenses and
intends to defend these lawsuits vigorously, but can
neither provide any judgment regarding the likely outcome
nor provide any estimate or range of possible loss.
Accordingly, no provision for liability, if any, that may
result from these lawsuits has been made in the Company's
financial statements.
(a) In March 1993, Inter-Power of New York, Inc.
(Inter-Power), filed a complaint against the
Company and certain of its officers and employees
in the Supreme Court of the State of New York,
Albany County (NYS Supreme Court). Inter-Power
alleged, among other matters, fraud, negligent
misrepresentation and breach of contract in
connection with the Company's alleged termination
of a power purchase agreement in January 1993. The
plaintiff sought enforcement of the original
contract or compensatory and punitive damages in an
aggregate amount that would not exceed $1 billion,
excluding pre-judgment interest.
In early 1994, the NYS Supreme Court dismissed two
of the plaintiff's claims; this dismissal was
upheld by the Appellate Division, Third Department
of the NYS Supreme Court. Subsequently, the NYS
Supreme Court granted the Company's motion for
summary judgment on the remaining causes of action
in Inter-Power's complaint. In August 1994, Inter-
Power appealed this decision and on July 27, 1995,
the Appellate Division, Third Department affirmed
the granting of summary judgment as to all counts,
except for one dealing with an alleged breach of
the power purchase agreement relating to the
Company's having declared the agreement null and
void on the grounds that Inter-Power had failed to
provide it with information regarding its fuel
supply in a timely fashion. This one breach of
contract claim was remanded to the NYS Supreme
Court for further consideration.
(b) In November 1993, Fourth Branch Associates
Mechanicville (Fourth Branch) filed an action
against the Company and several of its officers and
employees in the NYS Supreme Court, seeking
compensatory damages of $50 million, punitive
damages of $100 million and injunctive and other
related relief. The lawsuit grows out of the
Company's termination of a contract for Fourth
Branch to operate and maintain a hydroelectric
plant the Company owns in the Town of Halfmoon, New
York. Fourth Branch's complaint also alleges
claims based on the inability of Fourth Branch and
the Company to agree on terms for the purchase of
power from a new facility that Fourth Branch hoped
to construct at the Mechanicville site. In January
1994, the Company filed a motion to dismiss Fourth
Branch's complaint. By order dated November 7,
1995, the court granted the Company's motion to
dismiss the complaint in its entirety. Fourth
Branch has filed an appeal from the Court's order.
Fourth Branch has filed for protection under
Chapter 11 of the Bankruptcy Code in the Bankruptcy
Court for the Northern District of New York. On
January 5, 1996, Fourth Branch vacated the
Mechanicville site.
(c) 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
UGs (overgeneration). The Company has paid the UGs
based on its short-run avoided cost (under Service
Class No. 6) for all such overgeneration rather
than the price which the UGs contend is applicable
under the contracts. At March 31, 1996, the amount
of overgeneration adjustments in dispute that the
Company estimates it has not paid or accrued is
approximately $29 million, exclusive of interest.
The Company cannot predict the outcome of these
actions, but will continue to aggressively press
its position.
3. Rate and Regulatory Issues and Contingencies.
The Company's financial statements conform to generally
accepted accounting principles, as applied to regulated
public utilities and reflect the application of SFAS No.
71. Substantively, SFAS No. 71 permits a public utility
regulated on a cost-of-service basis to defer certain costs
when authorized to do so by the regulator which would
otherwise be charged to expense. These deferred costs are
known as regulatory assets, which in the case of the
Company are approximately $1,004 million, net of
approximately $243 million of regulatory liabilities at
March 31, 1996. The portion of the $1,004 million which
relates to the electric business is approximately $888
million. Generally, regulatory assets and liabilities were
allocated to the portion of the business that incurred the
underlying transaction that resulted in the recognition of
the regulatory asset or liability. The allocation methods
used between electric and gas were consistent with those
used in prior regulatory proceedings.
While the allocation of regulatory assets and liabilities
at March 31, 1996 is based on management's assessment, a
final determination would be made by evaluating
circumstances at the time should the Company discontinue
the application of SFAS No. 71, for all or a portion of its
business. Currently, substantially all of the Company's
regulatory assets have been approved by the PSC and are
being amortized to expense as they are being recovered in
rates as last established in April 1995.
RATE FILING. The Company filed in February 1996 a request
to increase electric rates. This rate increase request of
4.1% for 1996 and 4.2% for 1997 was based on the Company's
cost of providing services. The Company requested that its
4.1% increase for 1996 be implemented immediately with a
provision that rates charged will be subject to refund if
later it is determined that some portion of the request is
not allowed by the PSC. These rate increases are
predicated on a requested rate of return on common stock
equity (ROE) of approximately 11% on an annual basis and
recover the Company's cost of providing electric service.
At a public session on May 2, 1996, the PSC rejected the
Company's request for a temporary rate increase primarily
on the basis that the request did not meet the PSC's legal
standard for approving emergency rate increases. In their
remarks, the Chairman of the PSC and the Administrative Law
Judge assigned to the proceeding indicated that emergency
rate relief requires meeting a higher standard than
traditional cases and that a financial crisis did not exist
that would jeopardize the provision of safe and adequate
service. In addition, the Chairman of the PSC stated that
an increase in electric rates would have a negative impact
on economic conditions in the regions served by the
Company, which he stated that the Company itself recognized
in its PowerChoice proposal. The PSC Chairman also stated
that the PowerChoice proposal better addresses the long-
term viability of the Company, whereas a temporary rate
increase does not. Accordingly, results for 1996 will
reflect regulatory lag and resulting reduced ROE; however,
the Company believes that the rejection of a temporary rate
increase does not indicate that the Company is no longer
regulated on a cost-of-service basis.
Until the Company's PowerChoice proposal or another
acceptable alternative is implemented, the Company will
continue to pursue its traditional rate request for 1997.
It expects an Administrative Law Judge Recommended Decision
in early October and a PSC decision in January 1997.
Without temporary rate relief in 1996, the Company
estimates that its 1997 rate request will require an
overall electric price increase of nearly 9%. The Company
expects that the PSC will approve cost-of-service based
rate increases until such time as the implementation of the
PowerChoice proposal or a new competitive market model
becomes probable. As a result the Company believes that it
will continue to be regulated on a cost-of-service basis
which will enable it to continue to apply SFAS No. 71 and
that its regulatory assets are currently probable of
recovery. While various proposals have been made to develop
a new regulatory model, including the Company's PowerChoice
proposal, none of these proposals are currently probable of
implementation since a number of parties are required to
act on the change in the regulatory model.
While the Company believes that it continues to meet the
requirements for the application of SFAS No. 71 to the
electric business, there are a number of events that could
change that conclusion during the second quarter of 1996
and beyond. Those future events include: inaction or
inadequate action on the Company's 1997 rate request by the
PSC; a decision by the Company in the future not to pursue
the rate request filed; significant unanticipated reduction
in electricity usage by customers; significant
unanticipated customer discounts; lack of progress or
unsuccessful result in UG negotiations; adverse results of
litigation; and a change in the regulatory model becoming
probable.
As discussed in Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations
in the Company's Form 10-K for the fiscal year ended
December 31, 1995, the Company was unable to earn its
allowed ROE in 1995 and expects to earn substantially below
its allowed ROE in 1996. In addition, if the Company's
rate increase proposals with respect to 1997 and future
years under traditional ratemaking are not approved, then
the Company will, more likely than not, be unable to earn a
reasonable ROE for such years. The inability of the
Company to earn a reasonable ROE over a sustained period
would indicate that its rates are not based on its cost of
service. In such a case, application of SFAS No. 71 would
be discontinued. The resulting after-tax charges against
income would reduce retained earnings, the balance of which
is currently approximately $672 million. Various
requirements under applicable law and regulations and under
corporate instruments, including those with respect to
issuance of debt and equity securities, payment of common
dividends and certain types of transfers of assets could be
adversely impacted by any such write-downs. (See the
discussion in Item 5. Other Events.)
COMPETITION. The public utility industry in general, and
the Company in particular, is facing increasing competitive
threats. As competition penetrates the marketplace, it is
possible that the Company may no longer be able to continue
to apply the fundamental accounting principles of SFAS No.
71. The Company believes that in the future some form of
market-based pricing may replace cost-based pricing in
certain aspects of its business. In that regard, in
October 1995, the Company filed its PowerChoice proposal
with the PSC. (See Form 10-K for fiscal year ended
December 31, 1995, Part II, Item 7. Management's
Discussion and Analysis of Financial Condition and Results
of Operations- "PowerChoice Proposal"). PowerChoice would:
* Create a competitive wholesale electricity market and
allow direct access by retail customers.
* Separate the Company's power generation business from
the remainder of the business.
* Provide relief from overpriced unregulated generator
contracts that were mandated by public policy, along
with equitable write-downs of above-market company
assets.
* Freeze or cut average prices for all Company electric
customers for a period of 5 years.
The separated generation business proposed in PowerChoice
would no longer be rate-regulated and, accordingly,
existing regulatory assets related to the generation
business, amounting to $390 million, net of approximately
$242 million of regulatory liabilities at March 31, 1996,
would be charged against income if and when PowerChoice (or
a similar proposal) is probable of implementation. Under
PowerChoice, the Company's electric transmission and
distribution business is proposed to continue to be rate
regulated on a cost-of-service basis and, accordingly,
continue to apply SFAS No. 71. The PowerChoice proposal
also includes provisions for recovery of "stranded costs"
by the generation business and unregulated generators
through surcharges on rates for retail transmission and
distribution customers. Stranded costs are those costs of
utilities that may become unrecoverable due to a change in
the regulatory environment and include costs related to the
Company's generating plants, regulatory assets and
overpriced unregulated generator contracts.
Critical to the price freeze and restructuring of the
Company's markets and business envisioned in the
PowerChoice proposal are substantial reductions in the
Company's embedded cost structure. Such cost reductions
depend in turn on the willingness of the UGs and the
Company to absorb substantial write-offs. The Company's
proposal expresses its willingness if, and only if, the UGs
agree to cost reductions that are proportional to their
relative responsibility for strandable cost. The Company
proposes a reduction in its fixed costs of service be made
by mutual contribution of the Company's shareholders and
UGs that are in the same proportion as the contribution of
each to the problem of strandable costs, which the Company
calculates to be $4 of UG strandable cost for every $1 of
Company strandable cost. Under the Company's proposal, the
aggregate contribution over the five year period would be
approximately $2 billion, consisting of $400 million by the
Company and $1.6 billion by the UGs. The Company's
PowerChoice proposal faces opposition, principally from
unregulated generators. However, the Company has commenced
negotiations with UGs under the auspices of New York State.
The Company hopes to reduce UG costs as a result of these
negotiations but is unable to predict whether they will be
successful. The Company does not presently expect that its
PowerChoice proposal or any other alternative proposal
could be fully effective before sometime in 1997, at the
earliest.
There are also other proposals to introduce competition
into the utility marketplace presently before the PSC.
In April 1996, FERC issued its final rules on open
transmission access and stranded cost issues. (See Item
2., Management's Discussion and Analysis of Financial
Condition and Results of Operations - "FERC NOPR on
Stranded Investment.")
IMPAIRMENT OF LONG-LIVED ASSETS: In March 1995, the FASB
issued SFAS No. 121. This Statement, which the Company
adopted in 1996, requires that long-lived assets and
certain identifiable intangibles to be held and used by an
entity, be reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount
of an asset may not be recoverable. In performing the
review for recoverability, the Company is required to
estimate future undiscounted cash flows expected to result
from the use of the asset and its eventual disposition.
Furthermore, this Statement amends SFAS No. 71 to clarify
that regulatory assets should be charged against earnings
if the assets are no longer considered probable of recovery
rather than probable of loss. While the Company is unable
to predict the outcome of its PowerChoice proposal, or
various FERC and PSC initiatives, it has analyzed the
provisions of SFAS No. 121, as it relates to the impairment
of its investment in generating plant, under two scenarios:
traditional cost-based rate-making and its PowerChoice
proposal, as filed. As a result of these analyses, the
effects of adopting SFAS No. 121, as it relates to the
impairment of its investment in generating plant, did not
have an effect on its results of operations and financial
condition. In addition, the Company expects that the PSC
will approve cost-of-service based rate increases until
such time as a new competitive regulatory model is
developed. As a result, the Company believes currently
that its regulatory assets are probable of recovery.
However, if in the future management can no longer conclude
that existing regulatory assets are probable of recovery,
then all or a portion of such regulatory assets would have
to be charged to income, which could have a material
adverse effect on the Company's financial position and
results of operations.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
REVIEW BY INDEPENDENT ACCOUNTANTS
- ---------------------------------
The Company's independent accountants, Price Waterhouse LLP, have
made limited reviews (based on procedures adopted by the American
Institute of Certified Public Accountants) of the unaudited
Consolidated Balance Sheet of Niagara Mohawk Power Corporation
and Subsidiary Companies as of March 31, 1996 and the unaudited
Consolidated Statements of Income and Cash Flows for the three-
month periods ended March 31, 1996 and 1995. 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.
REPORT OF INDEPENDENT ACCOUNTANTS
- ---------------------------------
May 14, 1996
To the Stockholders and
Board of Directors of
Niagara Mohawk Power Corporation
300 Erie Boulevard West
Syracuse, New York 13202
We have reviewed the condensed consolidated balance sheet of
Niagara Mohawk Power Corporation and its subsidiaries as of March
31, 1996, and the related condensed consolidated statements of
income and cash flows for the three-month period ended March 31,
1996 and 1995. 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, 1995, and the related consolidated statements of income,
retained earnings and cash flows for the year then ended (not
presented herein); and in our report dated January 25, 1996, we
expressed an unqualified opinion (containing an explanatory
paragraph with respect to the Company's application of Statement
of Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulation" [SFAS No. 71]) on those
consolidated financial statements. In our opinion, the
information set forth in the accompanying condensed consolidated
balance sheet as of December 31, 1995, is fairly stated, in all
material respects, in relation to the consolidated balance sheet
from which it has been derived.
To the Stockholders and
Board of Directors
May 14, 1996
Page 2
As discussed in Note 3, the Company believes that it continues to
meet the requirements for application of SFAS No. 71 and that its
regulatory assets are currently probable of recovery in future
rates charged to customers. There are a number of events that
could change these conclusions in the second quarter of 1996 and
beyond, resulting in material adverse effects on the Company's
financial condition and results of operations. As also discussed
in Note 3, the Company has filed its PowerChoice proposal with
the New York State Public Service Commission for restructuring
the Company to facilitate a transition to a competitive electric
generation market. If it becomes probable that the proposal (or
a similar proposal) will be implemented and certain other
conditions are met by third parties, the Company would
discontinue application of SFAS No. 71 with respect to the
electric generation business and write-off the related regulatory
assets, currently approximately $390 million. Such an outcome
would have a material adverse effect on the Company's results of
operations and financial condition.
/s/ Price Waterhouse LLP
PRICE WATERHOUSE LLP
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
1996 AND 1997 RATE FILING; FINANCIAL CHALLENGES
When PowerChoice was announced, the Company said that failure to
approve the plan would mean continued price escalation under
traditional regulation, or failing that, further deterioration in
the Company's financial condition. While negotiations are
continuing on PowerChoice, in view of increasing UG payments,
discounts and continued weak sales expectations, the Company
found it necessary to seek price increases. The Company filed
for price increases of 4.1% for 1996 and 4.2% for 1997. The 1996
rate filing was for temporary rate relief for which the Company
asked for immediate action. As discussed in Note 3, on May 2,
1996, the PSC rejected the Company's request for a temporary rate
increase primarily on the basis that the request did not meet the
PSC's legal standard for approving emergency rate increases. The
Company is continuing to pursue its traditional rate request for
1997, to preserve the Company's right to traditional cost-based
rates in the event that an acceptable solution cannot be achieved
through negotiation of the PowerChoice proposal. The Company
expects that the PSC will approve cost-of-service based rate
increases until such time as implementation of a new competitive
market model becomes probable.
The Company faces significant challenges in its efforts to
maintain its financial condition in the face of expanding
competition and weak sales. While utilities across the nation
must address these concerns to varying degrees, the Company
believes that it is more financially vulnerable because of its
large industrial customer base, an oversupply of high-cost
mandated power purchases from UGs, an excess supply of wholesale
power at relatively low prices, a high tax burden, a stagnant
economy in the Company's service territory and significant
investments in nuclear plants. Moreover, solving the problems
the Company faces, including the implementation of PowerChoice,
requires the cooperation and agreement of third parties outside
the Company's control and, thus, limits the options available to
solve those problems and keep the Company financially viable.
FERC RULEMAKING ON OPEN ACCESS AND STRANDED COST RECOVERY
(See Form 10-K for fiscal year ended December 31, 1995, Part II,
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - "FERC NOPR on Stranded
Investment.")
In April 1996, the FERC issued two final rules, expected to take
effect in late spring or early summer, and a NOPR. The first
rule addresses open transmission access and stranded cost issues.
Stranded costs are utility costs that may become unrecoverable
due to a change in the regulatory environment. The second rule
requires utilities to establish electronic systems to share
information about available transmission capacity. It also
establishes standards of conduct. The NOPR proposes to establish
a new system for utilities to use in reserving capacity on their
own and others' transmission lines.
The first rule opens wholesale power sales to competition. Under
this rule, public utilities owning, controlling or operating
transmission lines are required to file, in approximately two
months, non-discriminatory open access tariffs that offer others
the same service they provide themselves, and in accordance with
the pro forma tariff issued by the FERC. In addition, it
provides for the full recovery of stranded wholesale costs,
leaving it up to the states to recover stranded retail costs,
unless the state regulators lack authority to do that. However,
the FERC said it will determine stranded cost recovery in the
case where retail customers become wholesale purchasers through
municipalization.
FERC's final rules do not require the divestiture of generation
from transmission, nor does it require an ISO to run the
transmission grid. Although, the FERC did offer guidelines for
the creation of ISOs that are subject to its approval.
The NOPR proposes that each utility would replace the open access
pro forma tariff with a capacity reservation tariff (CRT), by
December 31, 1997. Under the proposed CRT, utilities and all
other power market participants would reserve firm rights to
transfer power between designated receipt and delivery points.
FERC believes that the proposed reservation-based service appears
to be more compatible with the open access systems.
The Company is currently evaluating FERC's final rules to
determine their effects on the Company's results of operations
and financial condition. The Company is proceeding with further
study of the FERC orders and their implications. In addition, it
is evaluating the NOPR and plans to file its comments,
individually or as a member of a group, by the August 1, 1996 due
date.
COMMON STOCK DIVIDEND
The board of directors omitted the common stock dividend for the
first and second quarters of 1996. This action was taken to help
stabilize the Company's financial condition and provide
flexibility as the Company addresses growing pressure from
mandated power purchases and weaker sales. In making future
dividend decisions, the board will evaluate, along with standard
business considerations, the level and timing of future rate
relief, the progress of renegotiating contracts with UGs within
the context of its PowerChoice proposal, the degree of
competitive pressure on its prices, and other strategic
considerations.
FINANCING PLANS AND FINANCIAL POSITION
(See Form 10-K for fiscal year ended December 31, 1995, Part II,
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - "Financial Position,
Liquidity and Capital Resources.")
On April 25, 1996, Moody's Investors Service (Moody's) lowered
its ratings on the Company's senior secured debt, to Ba3 from
Ba1; senior unsecured debt to B2 from Ba2; its preferred stock to
b3 from ba3. Moody's "Not Prime" rating for the Company's
commercial paper remains unchanged. Moody's stated that it
downgraded the long-term credit ratings of the Company, based on
the limited progress made in achieving the goals identified in
the Company's PowerChoice proposal, among other financial
concerns, which may ultimately lead to a voluntary bankruptcy
filing. In addition, Moody's stated that due to the level of
uncertainty and potential volatility of the situation, its rating
outlook on the Company remains negative.
Cash flows to meet the Company's requirements for the first three
months of 1996 and 1995 are reported in the Consolidated
Statements of Cash Flows on Page 7.
During March 1996, the Company completed an $804 million senior
debt facility with the bank group for the purpose of
consolidating and refinancing certain of the Company's existing
working capital lines of credit and letter of credit facilities
and providing additional reserves of bank credit. This senior
debt facility will enhance the Company's financial flexibility
during the period 1996 through June 1999. The senior debt
facility consists of a $255 million term loan facility, a $125
million revolving credit facility and $424 million for letters of
credit. The letter of credit facility provides credit support
for the adjustable rate pollution control revenue bonds issued
through the New York State Energy and Development Authority. As
of April 30, 1996, the amount outstanding under the senior debt
facility was $105 million, comprised entirely of borrowing under
the term loan facility, leaving the Company with $275 million of
borrowing capability under the facility. The Company does not
anticipate that it will need to borrow any additional amounts
under the senior debt facility for the remainder of 1996, since
it believes that it will be able to satisfy its financing needs
internally. The facility expires on June 30, 1999 (subject to
earlier termination upon the implementation of the Company's
PowerChoice restructuring proposal or any other significant
restructuring plan).
This facility is collateralized by first mortgage bonds which
were issued on the basis of additional property. As of March 31,
1996, the Company could issue an additional $1,311 million
aggregate principal amount of first mortgage bonds under the
Company's mortgage trust indenture. This amount is based upon
retired bonds without regard to an interest coverage test.
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 a result
of the seasonal nature of the Company's operations as well as
timing differences between the collection of customer receivables
and the payment of fuel and purchased power costs. Recently the
Company has experienced a deterioration in its collections as
compared to prior years' experience and is taking steps to
improve collection. The Company believes it has sufficient
borrowing capacity to fund such deficits as necessary in the near
term.
External financing plans are subject to periodic revision as
underlying assumptions are changed to reflect developments,
market conditions and, most importantly, the Company's rate
proceedings. The ultimate level of financing during the period
1996 through 1999 will reflect, among other things: the outcome
of the 1997 and future traditional rate requests; or the outcome
of the restructuring envisioned in the PowerChoice proposal,
including whether the Company proceeds with exercising its right
of eminent domain with respect to UG contracts; levels of common
dividend payments, if any, and preferred dividend payments; the
Company's competitive position and the extent to which
competition penetrates the Company's markets; uncertain energy
demand due to the weather and economic conditions; and the extent
to which the Company reduces non-essential programs and manages
its cash flow during this period. In the longer term, in the
absence of PowerChoice or some reasonably equivalent solution,
financing will depend on the amount of rate relief that may be
granted.
RESULTS OF OPERATIONS
Three Months Ended March 31, 1996 versus Three Months Ended March
- -----------------------------------------------------------------
31, 1995
- --------
The following discussion presents the material changes in results
of operations for the first quarter of 1996 in comparison to the
same period in 1995. The Company's quarterly results of
operations reflect the seasonal nature of its business, with peak
electric loads in summer and winter periods. Gas sales peak
principally in the winter. The earnings for the three month
period should not be taken as an indication of earnings for all
or any part of the balance of the year.
Earnings for the first quarter were $86.5 million or 60 cents per
share, as compared with $108.5 million or 75 cents per share in
1995. Earnings for the first quarter of 1996 were lower because
1995 earnings included the recording of $26.4 million of
unbilled, non-cash revenues in accordance with the 1995 rate
order and a one-time, non-cash adjustment of prior years' DSM
incentive revenues of $17.0 million that increased 1995 earnings
by 20 cents per share. In addition, Other items (net) decreased
$13.6 million or 6 cents per share, principally because 1995
income included proceeds from the sale of HYDRA-CO. However,
higher electric rates that took effect April 26, 1995, partially
offset those factors that contributed to lower 1996 earnings by
increasing 1996 electric revenues by $30.9 million or 14 cents
per share.
ELECTRIC REVENUES
As shown in the table below, electric revenues, decreased $30.8
million or 3.5% from 1995. FAC revenues decreased $14.8 million,
in part due to a decrease in the purchased power costs, excluding
power purchased from UGs, combined with an increase in
hydroelectric generation. In 1995, the low water supply limited
the amount of hydroelectric power that the Company could produce.
The decrease in FAC revenues also reflects a higher amount of
transmission and resale revenues ($4.5 million) passed on to
customers.
Increase in base rates $ 30.9 million
Changes in volume and mix of sales
to ultimate customers (1.6)
FAC revenues (14.8)
DSM revenues (18.9)
Unbilled revenues (26.4)
------
$(30.8) million
=======
ELECTRIC SALES
Electric Kwh sales to ultimate consumers were approximately 8.9
billion in the first quarter of 1996, a 1.4% increase from 1995
primarily as a result of colder weather. After adjusting for the
effects of weather, sales to ultimate consumers decreased 1.1%.
Sales for resale increased 259 million Kwh (27.8%) resulting in a
net increase in total electric Kwh sales of 381 million (3.9%).
THREE MONTHS ENDED MARCH 31,
ELECTRIC REVENUES (Thousands) SALES (GwHrs)
---------------------------------- --------------------------
% %
1996 1995 Change 1996 1995 Change
Residential $ 355,778 $ 336,166 5.8 2,991 2,897 3.2
Commercial 309,855 317,395 ( 2.4) 3,021 3,016 0.2
Industrial 125,874 132,139 ( 4.7) 1,754 1,764 ( 0.6)
Industrial - Special 14,524 14,094 3.1 1,093 1,064 2.7
Other 13,126 13,402 ( 2.1) 64 63 1.6
---------- --------- ------ ------ ----- ------
Total to Ultimate
Consumers 819,157 813,196 0.7 8,923 8,804 1.4
Other Electric Systems 28,195 21,974 28.3 1,192 933 27.8
Miscellaneous (2,172) 41,094 (105.3) - - -
Subsidiary 5,957 5,656 5.3 126 123 2.4
---------- --------- ------ ------ ------- ------
TOTAL $ 851,137 $ 881,920 ( 3.5) 10,241 9,860 3.9
========== ========= ====== ====== ====== ======
/TABLE
As indicated in the table below, internal generation increased in
1996, principally at Unit 1. From February 8, 1995 to April 4,
1995, Unit 1 was taken out of service for a planned refueling and
maintenance outage. Although quantities purchased from UGs
decreased approximately 695 GwHrs, total costs escalated
approximately $6.4 million. The $6.4 million increase was
primarily due to a $4.5 million increase in the amount paid to
hydroelectric UGs. In 1995, the low water supply limited the
amount of power the hydroelectric UGs could produce. Quantities
from UGs decreased since the Company reduced, and in some
instances, did not schedule energy deliveries from certain
facilities in accordance with contract terms. Although the terms
of these contracts allow the Company to schedule energy
deliveries from the facilities and then pay for the energy
delivered, the Company is required to make fixed payments. This
includes payments when a facility is not operating but available
for service. These fixed costs have been increasing over the
past few years. (See Form 10-K for fiscal year ended December
31, 1995, Item 8., Notes to Consolidated Financial Statements -
Note 9. Commitments and Contingencies - "Long-term Contracts for
the Purchase of Electric Power.")
THREE MONTHS ENDED MARCH 31,
1996 Fuel &
Purchased
% Change from Power KwHr.
1996 1995 Prior Year Cost
--------------- ---------------- ---------------- ----------
(In millions of dollars)
FUEL FOR ELECTRIC GENERATION:
GwHrs. Cost GwHrs. Cost GwHrs. Cost Cents/KwHr
------ ------ ------ ------ ------ ------ ----------
Coal 1,935 $ 27.6 1,638 $ 24.4 18.1 13.1 1.43
Oil 244 9.9 305 11.8 (20.0) (16.1) 4.06
Natural Gas 1 0.2 281 4.9 (99.6) (95.9) 20.0
Nuclear 2,343 13.1 1,235 6.5 89.7 101.5 0.56
Hydro 1,026 - 907 - 13.1 - -
------ ------ ----- ------ ------ ------ ----
5,549 $ 50.8 4,366 $ 47.6 27.1 6.7 0.92
------ ------ ----- ------ ------ ------ ----
ELECTRICITY PURCHASED:
Unregulated generators:
Capacity - 53.2 - 41.5 - 28.2 -
Energy and taxes 3,407 217.5 4,102 222.8 (16.9) (2.4) 6.38
------ ----- ----- ----- ------ ----- ----
Total UG purchases 3,407 270.7 4,102 264.3 (16.9) 2.4 7.95
Other 2,312 31.7 2,380 32.5 (2.9) (2.5) 1.37
------ ----- ------ ----- ------ ----- ----
5,719 302.4 6,482 296.8 (11.8) 1.9 5.29
------ ----- ------ ----- ------ ----- ----
11,268 353.2 10,848 344.4 3.9 2.6 3.13
------ ----- ------ ----- ------ ----- ----
Fuel adjustment clause - (16.3) - (13.1) - 24.4 -
Losses/Company use 1,027 - 988 - 4.0 - -
------ ------ ------ ------- ------ ----- ----
10,241 $336.9 9,860 $331.3 3.9 1.7 3.29
====== ====== ====== ====== ====== ====== ====
/TABLE
GAS REVENUES
Gas revenues increased $69.0 million or 28.4% in 1996 from the
comparable period in 1995 as set forth in the table below:
Spot market sales $23.3 million
Purchased gas adjustment clause revenues 20.1
Sales to ultimate consumers 25.6
-----
$69.0 million
=====
GAS SALES
Due to colder weather in the first three months of 1996, gas
sales to ultimate consumers increased 5.7 million Dth or a 15.5%
increase from the first quarter of 1995. After adjusting for the
effects of weather, sales to ultimate consumers increased 0.6%.
Spot market sales (sales for resale) which are generally from the
higher priced gas available to the Company and therefore yield
margins that are substantially lower than traditional sales to
ultimate consumers, also increased. In addition, changes in
purchased gas adjustment clause revenues are generally margin-
neutral.
THREE MONTHS ENDED MARCH 31,
GAS REVENUES (Thousands) SALES (Thousands of Dth)
------------------------------- -------------------------------
% %
1996 1995 Change 1996 1995 Change
---- ---- ------ ---- ---- ------
Residential $191,772 $160,462 19.5 28,387 24,795 14.5
Commercial 81,099 66,170 22.6 12,903 11,286 14.3
Industrial 7,189 4,000 79.7 1,476 952 55.0
-------- -------- ------ ------ ------ ------
Total to Ultimate
Consumers 280,060 230,632 21.4 42,766 37,033 15.5
Other Gas Systems - 462 (100.0) - 102 (100.0)
Transportation of
Customer-Owned Gas 14,057 13,158 6.8 32,405 39,428 (17.8)
Spot Market Sales 23,880 551 4,233.9 5,583 272 1,952.6
Miscellaneous (6,071) (1,910) 217.9 - - -
---------- ------- ------ ------ ------ ------
Total to System
Core Customers $311,926 $242,893 28.4 80,754 76,835 5.1
========= ======== ====== ====== ====== ======
/TABLE
The total cost of gas included in expense increased 50.2% in
1996. This was the result of a 7.0 million increase in Dth
purchased and withdrawn from storage for ultimate consumer sales
($18.2 million) and a $17.7 million increase in Dth purchased for
spot market sales, coupled with a 15.8% increase in the average
cost per Dth purchased ($18.3 million) and a $9.3 million
increase in purchased gas costs and certain other items
recognized and recovered through the purchased gas adjustment
clause. The Company's net cost per Dth sold, as charged to
expense and excluding spot market purchases, increased to $3.85
in 1996 from $3.35 in 1995.
Other operation expense increased $8.1 million primarily as a
result of increased labor expense associated with storms in
January 1996 ($5.8 million) and an increase in bad debt expense
($4.3 million), partially offset by a decrease in Unit 1 and Unit
2 operation costs. Unit 1 operating costs were higher in 1995
primarily due to a planned refueling and maintenance outage
(February 8, 1995 - April 4, 1995).
The decrease in Federal income taxes (net) of approximately $34.4
million was primarily due to a decrease in pre-tax income. In
addition, 1995 included $10.3 million related to the sale of
HYDRA-CO.
Other items (net) decreased $13.6 million principally because
1995 includes proceeds from the sale of HYDRA-CO. ($21.6
million).
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
PART II
Item 5. Other Events.
In April 1996, The U.S. Nuclear Regulatory Commission (NRC)
issued an advanced NOPR that proposes a change in the
nuclear decommissioning rules. Current NRC regulations
allow a utility to set aside decommissioning funds annually
over the estimated life of a plant (See Form 10-K for
fiscal year ended December 31, 1995, Part II, Item 8.,
Notes to Consolidated Financial Statements - Note 3.
Nuclear Operations - "Nuclear Plant Decommissioning"). In
light of the growing trend toward deregulation and asset
divestiture, adequate funding will still be required for
decommissioning.
The following are some of the changes that the NRC is
considering:
* Requiring the utility to assure the NRC that they can
finance the total estimated cost of nuclear
decommissioning in the event they are no longer a rate
regulated entity and do not have a guaranteed source of
income.
* Requiring a deregulated utility to periodically report
to the NRC on the status of its nuclear decommissioning
funds.
* Allowing a utility to take a credit for a positive, real
rate of return on nuclear decommissioning trust funds
during a period of safe storage, i.e., a phase in
decommissioning when the plant is maintained in a state
that allows the radioactivity on site to decay.
The Company is currently evaluating the advanced NOPR and
plans to file its comments by the June 24, 1996 due date.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits:
Exhibit 11 - Computation of the Average Number of Shares
of Common Stock Outstanding for the Three Months Ended
March 31, 1996 and 1995.
Exhibit 12 - Statement Showing Computations of Ratio of
Earnings to Fixed Charges, Ratio of Earnings to Fixed
Charges without AFC and Ratio of Earnings to Fixed Charges
and Preferred Stock Dividends for the Twelve Months Ended
March 31, 1996.
Exhibit 15 - Accountants' Acknowledgement Letter.
Exhibit 27 - Financial Data Schedule.
In accordance with Paragraph 4(iii)(A) of Item 601(b) of
Regulation S-K, the Company agrees to furnish to the
Securities and Exchange Commission, upon request, a copy of
the $804 million senior debt facility agreement that it
completed with a bank group during March 1996. The total
amount of long-term debt authorized under such agreement
does not exceed 10 percent of the total consolidated assets
of the Company.
(b) Report on Form 8-K:
Form 8-K Reporting Date - March 5, 1996.
Item Reported - Item 5. Other Events.
Registrant filed certain information concerning financial
information substantially constituting a portion of its
1995 Annual Report to Stockholders including financial
statements for the fiscal year ended December 31, 1995.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
NIAGARA MOHAWK POWER CORPORATION
(Registrant)
Date: May 14, 1996 By /s/ Steven W. Tasker
---------------------------
Steven W. Tasker
Vice President-Controller and
Principal Accounting Officer
EXHIBIT 11
- ----------
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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Computation of the Average Number of Shares of Common Stock Outstanding
For the Three Months Ended March 31, 1996 and 1995
(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 MARCH 31:
JANUARY 1 - MARCH 31, 1996 144,332,123 91 13,134,223,193
SHARES SOLD -
Acquisition - Syracuse
Suburban Gas Company, Inc. -
February 5 732 56 40,992
----------- --------------
144,332,855 13,134,264,185 144,332,573
=========== ============== ===========
JANUARY 1 - MARCH 31, 1995 144,311,466 90 12,988,031,940
SHARES SOLD AT VARIOUS
TIMES DURING THE PERIOD -
DIVIDEND REINVESTMENT PLAN 19,016 * 1,140,960
----------- --------------
144,330,482 12,989,172,900 144,324,143
=========== ============== ===========
NOTE: Earnings per share calculated on both a primary and fully diluted basis are the
same due to the effects of rounding.
* 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
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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 MARCH 31, 1996
(In thousands of dollars)
A. Net Income $225,422
B. Taxes Based on Income or Profits 125,035
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C. Earnings, Before Income Taxes 350,457
D. Fixed Charges (a) 314,173
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E. Earnings Before Income Taxes and Fixed Charges 664,630
F. Allowance for Funds Used During Construction (AFC) 6,938
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G. Earnings Before Income Taxes and Fixed Charges
without AFC $657,692
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PREFERRED DIVIDEND FACTOR:
H. Preferred Dividend Requirements $ 39,000
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I. Ratio of Pre-tax Income to Net Income (C / A) 1.555
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J. Preferred Dividend Factor (H X I) $ 60,645
K. Fixed Charges as Above (D) 314,173
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L. Fixed Charges and Preferred Dividends Combined $374,818
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M. Ratio of Earnings to Fixed Charges (E / D) 2.12
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N. Ratio of Earnings to Fixed Charges without
AFC (G / D) 2.09
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O. Ratio of Earnings to Fixed Charges and
Preferred Dividends Combined (E / L) 1.77
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(a) Includes a portion of rentals deemed representative of the
interest factor ($27,420).
EXHIBIT 15
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May 14, 1996
Securities and Exchange Commission
450 Fifth Street, N.W.
Washington, D.C. 20549
Dear Sirs:
We are aware that Niagara Mohawk Power Corporation has included
our report dated May 14, 1996 (issued pursuant to the provisions
of Statement on Auditing Standards No. 71) in the Registration
Statements on Form S-8 (Nos. 33-36189, 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 and 33-55546). We are also aware of our responsibilities
under the Securities Act of 1933.
Yours very truly,
/s/ Price Waterhouse LLP
PRICE WATERHOUSE LLP