SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1996
- ---------------------------------------------
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
- ------------------ ----------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
300 Erie Boulevard West Syracuse, New York 13202
(Address of principal executive offices) (Zip Code)
(315) 474-1511
Registrant's telephone number, including area code
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements
for the past 90 days.
YES [X] NO [ ]
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Common stock, $1 par value, outstanding at July 31, 1996 -
144,365,214
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
FORM 10-Q - For The Quarter Ended June 30, 1996
INDEX
- -----
PART I. FINANCIAL INFORMATION
Glossary of Terms
Item 1. Financial Statements.
a) Consolidated Statements of Income -
Three Months and Six Months ended
June 30, 1996 and 1995
b) Consolidated Balance Sheets - June 30,
1996 and December 31, 1995
c) Consolidated Statements of Cash Flows -
Six Months ended June 30, 1996 and 1995
d) Notes to Consolidated Financial Statements
e) Review by Independent Accountants
f) Independent Accountant's Report on the
Limited Review of the Interim Financial
Information
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of
Operations.
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security
Holders.
Item 5. Other Information.
Item 6. Exhibits and Reports on Form 8-K.
Signature
Exhibit Index
NIAGARA MOHAWK POWER CORPORATION
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GLOSSARY OF TERMS
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TERM DEFINITION
- ---- ----------
COPS Competitive Opportunities Proceeding
DSM Demand-Side Management
Dth Dekatherms
FAC Fuel Adjustment Clause
FERC Federal Energy Regulatory Commission
GwHrs Gigawatt-hours
HYDRA-CO HYDRA-CO Enterprises, Inc.
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 JUNE 30,
---------------------------
1996 1995
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(In thousands of dollars)
OPERATING REVENUES:
Electric $ 804,457 $ 811,565
Gas 156,314 127,251
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960,771 938,816
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OPERATING EXPENSES:
Operation:
Fuel for electric generation 36,937 33,934
Electricity purchased 301,057 292,533
Gas purchased 80,557 57,178
Other operation expense 155,105 141,468
Maintenance 45,238 50,888
Depreciation and amortization 82,142 79,148
Federal and foreign income taxes 29,392 30,312
Other taxes 116,980 131,370
---------- ----------
847,408 816,831
---------- ----------
OPERATING INCOME 113,363 121,985
---------- ----------
OTHER INCOME AND (DEDUCTIONS):
Allowance for other funds used
during construction 794 312
Federal and foreign income taxes 857 1,207
Other items (net) 6,731 2,397
---------- ----------
8,382 3,916
---------- ----------
INCOME BEFORE INTEREST CHARGES 121,745 125,901
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INTEREST CHARGES:
Interest on long-term debt 68,597 66,020
Other interest 789 7,445
Allowance for borrowed funds used
during construction (633) (2,049)
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68,753 71,416
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NET INCOME 52,992 54,485
Dividends on preferred stock 9,532 10,046
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BALANCE AVAILABLE FOR COMMON STOCK $ 43,460 $ 44,439
========== ==========
Average number of shares of common
stock outstanding (in thousands) 144,337 144,330
Balance available per average
share of common stock $ .30 $ .31
Dividends paid per share of common
stock $ .00 $ .28
SIX MONTHS ENDED JUNE 30,
-------------------------
1996 1995
--------- ----------
(In thousands of dollars)
OPERATING REVENUES:
Electric $1,655,594 $1,693,485
Gas 468,240 370,144
---------- ----------
2,123,834 2,063,629
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OPERATING EXPENSES:
Operation:
Fuel for electric generation 86,501 78,340
Electricity purchased 588,365 579,404
Gas purchased 270,552 183,657
Other operation expense 317,971 296,282
Maintenance 91,394 95,654
Depreciation and amortization 164,206 157,464
Federal and foreign income taxes 86,015 108,684
Other taxes 247,458 263,754
---------- ----------
1,852,462 1,763,239
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OPERATING INCOME 271,372 300,390
---------- ----------
OTHER INCOME AND (DEDUCTIONS):
Allowance for other funds used
during construction 1,202 312
Federal and foreign income taxes 4,661 (7,598)
Other items (net) 9,183 18,472
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15,046 11,186
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INCOME BEFORE INTEREST CHARGES 286,418 311,576
---------- ----------
INTEREST CHARGES:
Interest on long-term debt 136,788 129,369
Other interest 2,171 14,577
Allowance for borrowed funds used
during construction (1,655) (5,591)
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137,304 138,355
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NET INCOME 149,114 173,221
Dividends on preferred stock 19,151 20,261
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BALANCE AVAILABLE FOR COMMON STOCK $ 129,963 $ 152,960
========== ==========
Average number of shares of common
stock outstanding (in thousands) 144,335 144,327
Balance available per average
share of common stock $ .90 $ 1.06
Dividends paid per share of common
stock $ .00 $ .56
/TABLE
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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CONSOLIDATED BALANCE SHEETS
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ASSETS
- ------ JUNE 30, 1996
(UNAUDITED) DECEMBER 31, 1995
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(In thousands of dollars)
UTILITY PLANT:
Electric plant $ 8,564,705 $ 8,543,429
Nuclear fuel 524,027 517,681
Gas plant 1,055,615 1,017,062
Common plant 280,221 281,525
Construction work in progress 252,943 289,604
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Total utility plant 10,677,511 10,649,301
Less-Accumulated depreciation and
amortization 3,726,076 3,641,448
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Net utility plant 6,951,435 7,007,853
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OTHER PROPERTY AND INVESTMENTS 194,059 218,417
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CURRENT ASSETS:
Cash, including temporary cash investments
of $275,002 and $114,415, respectively 338,518 153,475
Accounts receivable (less allowance for
doubtful accounts of $20,000) 420,723 471,442
Materials and supplies, at average cost:
Coal and oil for production of electricity 21,917 27,509
Gas storage 22,305 26,431
Other 136,239 141,820
Prepaid taxes 60,823 17,239
Other 47,743 45,834
---------- ----------
1,048,268 883,750
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REGULATORY ASSETS (Note 3):
Regulatory tax asset 470,198 470,198
Deferred finance charges 239,880 239,880
Deferred environmental restoration costs (Note 2) 225,000 225,000
Unamortized debt expense 85,040 92,548
Postretirement benefits other than pensions 67,744 68,933
Other 150,379 204,253
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1,238,241 1,300,812
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OTHER ASSETS 79,461 67,037
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$ 9,511,464 $ 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
- ------------------------------
JUNE 30, 1996
(UNAUDITED) DECEMBER 31, 1995
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(In thousands of dollars)
CAPITALIZATION:
COMMON STOCKHOLDERS' EQUITY:
Common stock - $1 par value; authorized
185,000,000 shares; issued 144,349,839 and
144,332,123 shares, respectively $ 144,350 $ 144,332
Capital stock premium and expense 1,784,259 1,784,247
Retained earnings 715,336 585,373
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2,643,945 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
240,000 and 258,000 shares, respectively 22,200 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
3,008,005 and 3,208,005 shares,
respectively 69,100 72,850
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531,300 536,850
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Long-term debt 3,505,896 3,582,414
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TOTAL CAPITALIZATION 6,681,141 6,633,216
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CURRENT LIABILITIES:
Long-term debt due within one year 48,524 65,064
Sinking fund requirements on redeemable
preferred stock 7,900 9,150
Accounts payable 198,697 268,603
Payable on outstanding bank checks 31,743 36,371
Customers' deposits 14,451 14,376
Accrued taxes 77,837 14,770
Accrued interest 63,840 64,448
Accrued vacation pay 35,825 35,214
Other 65,298 57,748
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544,115 565,744
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REGULATORY LIABILITIES (NOTE 3):
Deferred finance charges 239,880 239,880
Other 2,787 2,712
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242,667 242,592
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OTHER LIABILITIES:
Accumulated deferred income taxes 1,407,987 1,388,799
Employee pension and other benefits 248,280 245,047
Deferred pension settlement gain 25,861 32,756
Unbilled revenues 16,181 28,410
Other 120,232 116,305
---------- ----------
1,818,541 1,811,317
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COMMITMENTS AND CONTINGENCIES (NOTES 2 AND 3):
Liability for environmental restoration 225,000 225,000
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$9,511,464 $9,477,869
========== ==========
/TABLE
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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CONSOLIDATED STATEMENTS OF CASH FLOWS
- -------------------------------------
INCREASE (DECREASE) IN CASH (UNAUDITED)
- ---------------------------------------
SIX MONTHS ENDED JUNE 30,
1996 1995
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(In thousands of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 149,114 $ 173,221
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 164,206 157,464
Amortization of nuclear fuel 21,058 12,727
Provision for deferred income taxes 22,442 60,126
Gain on sale of subsidiary - (11,257)
(Increase) decrease in net accounts receivable 38,490 (6,616)
Decrease in materials and supplies 13,067 13,928
Decrease in accounts payable and accrued expenses (58,728) (86,933)
Increase in accrued interest and taxes 62,459 49,517
Changes in other assets and liabilities 11,206 10,023
---------- ----------
NET CASH PROVIDED BY OPERATING ACTIVITIES 423,314 372,200
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction additions (115,986) (149,386)
Nuclear Fuel (6,346) (8,543)
---------- ----------
Acquisition of utility plant (122,332) (157,929)
Decrease in materials and supplies related
to construction 2,232 1,722
Decrease in accounts payable and accrued
expenses related to construction (14,682) (21,733)
(Increase) decrease in other investments 24,919 (72,079)
Proceeds from sale of subsidiary (net of cash sold) - 161,087
Other (7,629) 2,661
---------- ----------
NET CASH USED IN INVESTING ACTIVITIES (117,492) (86,271)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in long-term debt 105,000 275,000
Net change in revolving credit agreements (170,000) (99,000)
Reductions of preferred stock (6,800) (9,300)
Reductions in long-term debt (29,341) (21,447)
Net change in short-term debt - (306,750)
Dividends paid (19,151) (101,086)
Other (487) (11,527)
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NET CASH USED IN FINANCING ACTIVITIES (120,779) (274,110)
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NET INCREASE IN CASH 185,043 11,819
Cash at beginning of period 153,475 94,330
---------- ----------
CASH AT END OF PERIOD $ 338,518 $ 106,149
========== ==========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid $141,743 $146,118
Income taxes paid $52,219 $29,997
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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NOTE 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
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
and six-month periods ended June 30, 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.
NOTE 2. CONTINGENCIES
ENVIRONMENTAL CONTINGENCIES: 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 44 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 June 30, 1996 and December 31, 1995. This
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 $905 million, including approximately $400
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 (SIR).
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."
In July 1996, the Administrative Law Judge (ALJ) issued a
Recommended Decision in the Company's November 1995 gas
rate filing that recommended 100% recovery of its SIR
costs. (See Item 2. Management's Discussion and Analysis
of Financial Condition and Results of Operations - "1996
Gas Rate Filing"). 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 and, if successful, what the ratemaking
disposition will be.
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 Company's 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 finalize 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 a
tracking account. A tracking account represents amounts
the PSC required the Company to pay UGs that are in excess
of the Company's actual avoided costs, including a carrying
charge. The IRS proposes to disallow a current deduction
for amounts paid in excess of the avoided costs of the
Company. Although the Company believes that any such
disallowances for the years 1989 and 1990 will not have a
material impact on its financial position or results of
operations, it believes that a disallowance for these
above-market payments for the years subsequent to 1990
could have a material adverse affect on its cash flows.
The Company is vigorously defending its position on this
issue. The IRS has commenced its examination of the
Company's Federal income tax returns for the years 1991
through 1993.
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.
The Company and Fourth Branch recently entered into
negotiations under a FERC mediation process. As a
result of these negotiations, the Company and Fourth
Branch have entered into an agreement in principle
which would result in a transfer of the hydroelectric
plant to Fourth Branch for $1 million. In addition,
the agreement in principle includes a provision that
would require the discontinuance of all litigation
between the parties. The agreement in principle is
scheduled to be finalized in late September 1996.
However, the appeal is still scheduled to be argued in
the Fall 1996.
(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 June 30, 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.
NOTE 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 $996 million, net of
approximately $243 million of regulatory liabilities at
June 30, 1996. The portion of the $996 million which
relates to the electric business is approximately $882
million, net of approximately $243 million of regulatory
liabilities. Generally, regulatory assets and liabilities
are allocated to the portion of the business that incurred
the underlying transaction that resulted in the recognition
of the regulatory asset or liability. The allocation
methods used between electric and gas are consistent with
those used in prior regulatory proceedings.
While the allocation of regulatory assets and liabilities
at June 30, 1996 is based on management's assessment,
should the Company discontinue the application of SFAS No.
71, for all or a portion of its business, a final
allocation would be made by evaluating circumstances at
that time. 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 service. 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 1996 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 ALJ 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.
Originally, the Company expected an ALJ Recommended
Decision in early October and a PSC decision in January
1997. However, in late May 1996 and July 1996, the Company
and the PSC staff jointly requested 60-day and 30-day
extensions, respectively, so parties can focus on the
negotiations related to the Company's PowerChoice proposal,
including its negotiations with UGs. These extensions will
reduce the amount of revenues and significantly reduce the
amount of earnings the Company would realize in 1997 from
any price increases granted, absent additional cost
reductions. The ALJ approved the 60-day extension and the
request for the additional 30-day extension is pending.
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 that provide for a reasonable rate of return
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.
For the reasons noted above, the Company believes that it
continues to meet the requirements for the application of
SFAS No. 71 to the electric business. However, there are a
number of events that could change that conclusion during
the third 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 as filed;
significant unanticipated reduction in electricity usage by
customers; significant unanticipated customer discounts;
unsuccessful results in UG negotiations; adverse results of
litigation; and a change in the regulatory model becoming
probable.
As discussed in Part II, 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 $715 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 Information - "NRC Advanced
NOPR.")
COMPETITION: The public utility industry in general, and
the Company in particular, is facing increasing competitive
threats. As competition increases in 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 will 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.") The PowerChoice
proposal, as amended by the Company's August 1, 1996
announcement discussed below, would:
- Create a competitive wholesale electricity market and
allow direct access by retail customers.
- Separate the Company's non-nuclear power generation
business from the remainder of the business.
- Provide relief from overpriced UG contracts that were
mandated by public policy.
- Stabilize average prices for Company electric customers,
with reductions to industrial customers to facilitate
economic and job growth in the service territory.
The separated non-nuclear generation business would no
longer be rate-regulated and, accordingly, existing
regulatory assets related to the non-nuclear power
generation business, amounting to $100 million, net of
approximately $2 million of regulatory liabilities at June
30, 1996, would be charged against income if and when
PowerChoice (or a similar proposal) becomes probable of
implementation. Of the remaining electric business, under
PowerChoice, the Company has proposed that its electric
transmission and distribution business continue to be rate-
regulated on a cost-of-service basis (but with performance
objectives) and, accordingly, it would continue to apply
SFAS No. 71. The Company currently expects to retain
ownership of its nuclear assets, but will continue to
investigate various options that may be available to
mitigate the risk of ownership of these assets. While the
Company expects to pursue performance based cost-of-service
regulation, the ultimate form and substance of rate
regulation applied to nuclear operations will determine
whether SFAS No. 71 can continue to be applied. If the
Company determines it could no longer apply SFAS No. 71,
existing nuclear regulatory assets of $281 million, net of
nuclear regulatory liabilities of $240 million at June 30,
1996 would be charged against income.
The PowerChoice proposal also includes provisions for
recovery of "stranded costs" by the generation business
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 UG contracts. As discussed below, the Company
has offered to buy out 44 UG contracts for a combination of
cash and securities. While the Company believes that buy
out costs should be recoverable as part of the
implementation of PowerChoice, or a form thereof,
resolution of this issue is subject to negotiation and
approval of the PSC as discussed below. Until resolved, no
assurance can be given as to the total amount recoverable
or whether the criteria of SFAS No. 71 can be met to record
a regulatory asset for the amount recoverable.
Critical to the stabilization of average prices and
restructuring of the Company's markets and business
envisioned in the PowerChoice proposal are substantial
reductions in the Company's embedded cost structure. The
Company has commenced negotiations with the UGs under the
broad supervision of representatives of the New York State
government. The Company's objective is to reduce UG costs
as a result of these negotiations. On August 1, 1996 the
Company announced it had offered to terminate 44 UG
contracts in exchange for a combination of cash and
securities from a new restructured Niagara Mohawk Power
Corporation. The offer, if accepted, would clear the way
for implementation of PowerChoice, or a form thereof, which the
Company has indicated depends upon reducing the cost of power the
Company is required to purchase from UGs. Under the plan,
the Company would terminate contracts which account for
more than 90% of the above-market power costs that the
Company is required to buy from UGs in exchange for a
combination of cash and securities to be issued by a
restructured Niagara Mohawk Power Corporation, which would
include electric and gas transmission and distribution
assets and nuclear assets. The new securities would be
subordinate to existing first mortgage bonds and not impair
the rights of first mortgage bondholders. The plan would
also create a separate non-nuclear generating company. The
offer is subject to negotiation and is conditioned on
receipt of appropriate regulatory and other approvals
including PSC approval of an appropriate price structure
consistent with the levels envisioned by the PowerChoice
proposal. The Company cannot predict whether the offer
will be accepted and implemented as proposed. The
Company's desire is to conclude negotiations on the offer
in the fourth quarter of 1996.
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. In
addition, the Company cannot predict whether the
PowerChoice proposal, in its current or a modified form, or
an alternative proposal will be implemented.
PSC AND FERC REGULATORY PROCEEDINGS: On May 16, 1996, the
PSC issued its decision in its COPS case to restructure New
York State's electric industry. (See Item 2. Management's
Discussion and Analysis of Financial Condition and Results
of Operations - "PSC Competitive Opportunities Proceeding -
Electric.") Although the PSC's decision outlines its
overall vision of how the electricity industry should be
deregulated and restructured for competition, it did not
provide a detailed plan for implementation and instead
ordered filings from the major utilities, except the
Company and Long Island Lighting Company (LILCO), by
October 1, 1996. The October 1 filings are required to
address the corporate structure of each utility both in the
short and long term and the schedule for and cost of
attaining that structure; a schedule for introducing retail
access to all of the utility's customers and a set of
unbundled tariffs that are consistent with the retail
access program; and a rate plan to be effective for the
transition to a competitive market, including mechanisms to
reduce rates and address stranded costs. The Company was
exempted from the October 1 filing by the PSC because the
PSC determined that the Company's PowerChoice restructuring
proposal met the requirements of the PSC's decision in its
COPS proceeding.
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 Rulemaking on Open Access
and Stranded Cost Recovery.")
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 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. However, to the extent the
PowerChoice proposal is significantly altered or an
alternative proposal is implemented, a new asset impairment
analysis must be performed, with no assurance as to whether
an impairment might exist. 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.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
REVIEW BY INDEPENDENT ACCOUNTANTS
- ---------------------------------
The Company's independent accountants, Price Waterhouse LLP, have
made limited reviews (based on procedures adopted by the American
Institute of Certified Public Accountants) of the unaudited
Consolidated Balance Sheet of Niagara Mohawk Power Corporation
and Subsidiary Companies as of June 30, 1996 and the unaudited
Consolidated Statements of Income for the three-month and six-
month periods ended June 30, 1996 and 1995 and the unaudited
Consolidated Statements of Cash Flows for the six-months ended
June 30, 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.
PRICE WATERHOUSE LLP
ONE MONY PLAZA
SYRACUSE, NY 13202
TELEPHONE 315-474-6571
REPORT OF INDEPENDENT ACCOUNTANTS
August 12, 1996
To the Stockholders and Board of Directors of
Niagara Mohawk Power Corporation
300 Erie Boulevard West
Syracuse, NY 13202
We have reviewed the condensed consolidated balance sheet of
Niagara Mohawk Power Corporation and its subsidiaries as of June
30, 1996, and the related condensed consolidated statements of
income for the three-month and six-month periods ended June 30,
1996 and 1995 and of cash flows for the six months ended June 30,
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
August 12, 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 third 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's PowerChoice proposal, in its current
form, would restructure 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
non-nuclear portion of its electric generation business and
write-off the related net regulatory assets, currently
approximately $100 million. While the Company expects to pursue
performance based cost-of-service regulation, the form and
substance of rate regulation applied to nuclear operations will
determine whether SFAS No. 71 can continue to be applied. If the
Company determines it could no longer apply SFAS No. 71, existing
nuclear net regulatory assets, currently approximately $281
million, would be written-off. Such actions, in the aggregate,
could have a material adverse effect on the Company's results of
operations and financial condition.
/s/ Price Waterhouse LLP
- ------------------------
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.
FINANCIAL CHALLENGES
The Company faces significant challenges in its efforts to
maintain its financial condition in the face of expanding
competition. 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.
COMPANY PROPOSAL TO BUY OUT UG CONTRACTS
On August 1, 1996 the Company announced it had offered to
terminate 44 UG contracts in exchange for a combination of cash
and securities from a newly restructured Niagara Mohawk Power
Corporation. The offer, if accepted, would clear the way for the
implementation of PowerChoice, which the Company has indicated
depends upon reducing the cost of power the Company is required
to purchase from UGs.
The 44 contracts represent more than 90% of the above-market cost
of mandated purchases by the Company. The securities included in
the offer would be issued by a restructured Niagara Mohawk Power
Corporation, which would include electric and gas transmission
and distribution assets and nuclear assets. The new securities
would be subordinate to the existing first mortgage bonds of the
Company. The proposed buy out would not impair the rights of the
Company's existing first mortgage bondholders.
The buy out offer is conditioned on receipt of appropriate
regulatory and other approvals including PSC approval of an
appropriate price structure consistent with the levels envisioned
by the PowerChoice proposal. The Company cannot predict whether
the offer will be accepted and implemented as proposed. The
Company's desire is to conclude negotiations on the offer in the
fourth quarter of 1996, with the appropriate approvals following
in early 1997.
1996 AND 1997 ELECTRIC RATE FILING
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 in order 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.
PSC COMPETITIVE OPPORTUNITIES PROCEEDING - ELECTRIC
(See Form 10-K for the fiscal year ended December 31, 1995, Part
II, Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - "PSC Competitive
Opportunities Proceeding - Electric.")
On May 16, 1996 the PSC issued its decision in its COPS case to
restructure New York State's electric industry. The decision
calls for a competitive wholesale power market in early 1997 and
the introduction of retail access for all electric customers in
early 1998.
The goals cited in its decision included lowering consumer rates,
increasing choice, continuing reliability of service, continuing
environmental and public policy programs, mitigating concerns
about market power and continuing customer protections and the
obligation to serve.
To implement its policies, the PSC directed major utilities,
excluding the Company and LILCO, to file restructuring proposals
and rate plans by October 1, 1996, consistent with these goals.
The Company was exempt from this filing since it had already
filed its PowerChoice restructuring proposal. Subsequent to
these October 1 filings, all parties in the COPS proceeding will
be able to review and comment on the documents. The PSC will
then review each filing.
In addition, the PSC decision states that recovery of utility
stranded costs may be accomplished by a non-bypassable "wire
charge" to be imposed by distribution companies. Stranded costs
are utility costs that may become unrecoverable due to a change
in the regulatory environment. The calculation of the amount of
stranded costs, and the timing of recovery, will be determined
individually for each utility as part of the October 1 filings.
The PSC decision suggests that a careful balancing of customer
and utility interests and expectations is necessary, and the
level of stranded cost recovery will ultimately depend upon the
particular circumstances of each utility.
Between now and October 1, the PSC stated that collaborative
efforts would take place to accomplish the following:
- distinguish and classify transmission and distribution
facilities;
- continue reviewing the role of Energy Service Companies
(ESCOs) in a competitive retail market, including the
development of licensing requirements and consumer
safeguards, policies relating to the transfer of the
obligation to serve, funding mechanisms that might be
needed to assure fairness among all ESCOs and matters
related to billing and metering functions;
- address transmission pricing; and
- set forth the structure of the ISO, and the Market
Exchange. The PSC stated that the ISO must have the
authority and the means to ensure reliability of the
bulk power system.
The Company believes that the PSC's objectives in its COPS
decision are consistent with the Company's PowerChoice proposal.
The Company cannot predict the outcome of this matter or its
effects on the Company's results of operations or financial
condition.
FERC RULEMAKING ON OPEN ACCESS AND STRANDED COST RECOVERY
(See Form 10-K for the 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 and a NOPR. The
first rule addresses open transmission access and stranded cost
issues. The second rule requires utilities to establish
electronic systems to share information about available
transmission capacity and 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 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, the first rule provides for the full
recovery of stranded wholesale costs, leaving it up to the states
to decide the issue of recovery of stranded retail costs, unless
the state regulators lack authority to decide this issue.
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 did not require the divestiture of generation
from transmission, nor did it require an ISO to run the
transmission grid. However, 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 stated its belief that the proposed reservation-based
service appears to be more compatible with open access systems.
In May 1996, the New York Power Pool's (NYPP) Executive Committee
approved the restructuring of the NYPP, of which the Company is a
member, into an ISO in order to comply with FERC's guidelines.
The NYPP plans to file an ISO tariff with the FERC by September
1996. The Company is actively involved in the restructuring of
the NYPP into a statewide ISO.
In late May 1996, the Company was among a number of parties which
filed petitions with the FERC seeking rehearing of certain
portions of its first rule. The Company stated that various
exceptions to the principle of full recovery of stranded costs
adopted in that rule would distort competition in the markets for
electric power which the rule was designed to promote. In
addition, the Company stated that these limitations on the
recovery of stranded costs may deprive utilities of a reasonable
opportunity to recover their prudently incurred costs,
particularly in the case of utilities, including the Company,
that face high levels of stranded costs due to past government
mandates. The Company also urged the FERC to make certain
technical changes to its rules for the recovery of stranded costs
in the municipalization context. The Company is unable to
predict the outcome of this matter.
MULTI-YEAR GAS RATE PROPOSAL
In November 1995, the Company filed for a 5.8% gas rate increase
to be effective October 1, 1996. (See Form 10-K for the fiscal
year ended December 31, 1995, Part II, Item 7. Management's
Discussion and Analysis of Financial Condition and Results of
Operations - "PowerChoice Proposal - Multi-Year Gas Rate
Proposal.") In addition, the Company proposed a performance-
based regulation (PBR) mechanism, including a gas cost incentive
mechanism for gas operations to become effective October 1, 1997.
This filing also included a complete unbundling of the Company's
sales service allowing customers to choose alternative gas
suppliers plus a move to a rate structure for the transportation
of gas that would mitigate the throughput risk to the Company.
It also proposed the discontinuation of the weather normalization
clause and sought flexibility in pursuing unregulated
opportunities related to the gas business.
In March 1996, in a generic rate proceeding, the PSC ordered all
New York utilities to refile their tariffs to implement a service
unbundling by May 1996. The Company refiled its tariff on April
29, 1996 which became effective on a temporary basis on June 1,
1996. Under the approved tariff, all of the Company's gas
customers, including residential and commercial customers, have
the opportunity to buy natural gas from other sources with the
company providing delivery service for a separate fee. These
changes have not had nor would be expected to have a material
impact on the Company's natural gas throughput risk since the
Company sells gas at cost and the margins derived from the
delivery service are essentially the same as the sales service.
The revised rate structure that had been proposed by the Company
to reduce the throughput risk has been transferred into the
Company's November 1995 rate proceeding.
In addition to the tariff filing to implement service unbundling,
the Company and other utilities filed a petition for rehearing of
certain of the determinations made in the PSC's March 1996 Order.
These determinations included the PSC's requirement that
converting customers are responsible for pipeline capacity held
by the utility on their behalf for only a three-year period
rather than for the remaining life of the pipeline contract. In
addition, the March 1996 Order states that the utility is
obligated to provide back-up service to a converting customer or
provide service to a new customer even if the utility does not
currently have sufficient pipeline capacity needed to serve that
customer. However, the March 1996 Order is unclear as to how the
costs of such capacity would be recovered by the utility after
the three-year period. The Company also asked for clarification
regarding the "test" the PSC would use to determine whether the
utility has adequately demonstrated its efforts to relieve itself
of "excess" capacity. In July 1996, the PSC staff recommended no
substantive changes to the PSC's March 1996 Order.
The ALJ assigned to the Company's gas rate case proceeding issued
a recommended decision in July 1996 which would allow the Company
to increase its base rates $8.4 million or 1.4% and included an
allowed ROE of 11.4%. In addition, the ALJ recommended that the
PBR proposal and rate restructuring be addressed in a second
phase of this gas rate proceeding. The ALJ also recommended the
continuation of the weather normalization clause. With respect
to the Company's site investigation and restoration costs (see
Note 2. Contingencies - "Environmental Contingencies"), the ALJ
recommended 100% recovery of these costs. A PSC decision is
expected in late October 1996. The Company is unable to predict
the outcome of this proceeding.
COMMON STOCK DIVIDEND
The board of directors omitted the common stock dividend for the
first three 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 negotiating 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 the 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.
On May 22, 1996, Standard & Poor's (S&P) lowered its ratings on
the Company's senior secured debt to BB- from BB; senior
unsecured debt to B from B+; its preferred stock to B- from B;
and commercial paper to not rated from B. S&P stated that the
downgrade results from the inability of the financially weak
Company and the UGs to make substantive progress in their
renegotiation of UG contracts. In addition, S&P stated that the
lack of progress after several months of negotiations between the
Company and the UGs increases the uncertainty that a settlement
can be achieved.
Cash flows to meet the Company's requirements for the first six
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 a bank group for the purposes 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 June
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 June 30,
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.
The Company believes that it will spend approximately $290
million for construction in 1996. For the six months ended June
30, 1996, the Company had incurred approximately $116.0 million
for construction additions.
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. The Company
is experiencing a significant 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, implementation of the
Company's PowerChoice proposal or in the alternative, 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 restructuring envisioned in the
PowerChoice proposal (or a similar proposal), including the
Company's recent offer to buy out 44 UG contracts; the
alternatives the Company may pursue if the Company's offer is not
accepted; the outcome of the 1997 and future traditional rate
requests; 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.
The Company could also be affected by the outcome of the NRC's
consideration of new rules for adequate financial assurance of
nuclear decommissioning obligations. (See Item 5. Other
Information - "NRC Advanced NOPR"). 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
The following discussion presents the material changes in results
of operations for the three months and six months ended June 30,
1996 in comparison to the same periods in 1995. The Company's
results of operations reflect the seasonal nature of its
business, with peak electric loads in summer and winter periods.
Gas sales peak principally in the winter. The earnings for the
three months and six months periods should not be taken as an
indication of earnings for all or any part of the balance of the
year.
THREE MONTHS ENDED JUNE 30, 1996 VERSUS THREE MONTHS ENDED JUNE
30, 1995
Earnings for the second quarter were $43.5 million or 30 cents
per share, as compared with $44.4 million or 31 cents per share
in 1995. Earnings for the second quarter were lower because 1995
earnings included the recording of $9.4 million of revenues
earned under the Unit 1 operating incentive sharing mechanism
that increased 1995 earnings by 4 cents per share. However, this
was partially offset by higher electric and natural gas sales due
to the colder weather in 1996.
ELECTRIC REVENUES
As shown in the table below, electric revenues decreased $7.1
million or 0.9 % from 1995, primarily due to a decrease in
miscellaneous electric revenues. Miscellaneous electric revenues
were lower in 1996 because 1995 electric revenues included the
recording of $29.1 million of unbilled, non-cash revenues in
accordance with the 1995 rate order and $9.4 million of revenues
earned under the Unit 1 operating incentive sharing mechanism
established in the 1991 Financial Recovery Agreement. In
addition, FAC revenues decreased $6.4 million, even though the
Company made increased payments to UGs. FAC revenues decreased
in part due to the higher generation from nuclear and hydro
facilities that have lower fuel costs. In 1995, the lower water
supply limited the amount of hydroelectric power that the Company
could produce. In addition, Units 1 and 2 were taken out of
service in early 1995 for planned refueling and maintenance
outages. The decrease in FAC revenues also reflects a higher
amount of transmission and resale revenues ($6.7 million) passed
on to customers. However, higher electric and natural gas sales
due to the colder weather and higher electric rates (effective
April 26, 1995) partly offset those factors that contributed to
lower electric revenues.
Sales to other electric utilities $ 14.5 million
Increase in base rates 14.0
Changes in volume and mix of sales
to ultimate customers 11.0
DSM revenues (1.7)
FAC revenues (6.4)
Unit 1 incentive surcharge (9.4)
Unbilled revenues (29.1)
-------
$ (7.1) million
=======
ELECTRIC SALES
Electric Kwh sales to ultimate consumers were approximately 8.1
billion in the second quarter of 1996, a 3.0% increase from the
same period in 1995 due in part to colder weather. After
adjusting for the effects of weather, sales to ultimate consumers
increased 1.9%, principally to industrial customers. Sales for
resale increased 776 billion kwhs (100.5%) due to an increased
demand for electricity in the northeast, resulting in a net
increase in total electric kwh sales of 1,012 billion (11.6%).
Sales for resale generally result in low margin contribution to
the Company due to regulatory sharing mechanisms and relatively
low prices caused by excess supply.
Electric fuel and purchased power costs increased $11.6 million
or 3.6%. This increase is the result of a $32.2 million
increase in actual purchased power costs (including increased
payments to UGs of $36.4 million or 15.3%), partially offset by a
$19.0 million decrease in costs deferred and recovered through
the operation of the FAC and a $1.6 million decrease in actual
fuel costs. The decrease in fuel costs reflects a 21.9% decrease
in Company generation due to UG purchase requirements, which
reduced the operation of the Company's fossil plants during the
second quarter of 1996.
GAS REVENUES
Gas revenues increased $29.1 million or 22.8% in the second
quarter of 1996 from the comparable period in 1995 as set forth
in the table below:
Sales to ultimate consumers $17.8 million
Purchased gas adjustment clause revenues 6.8
Spot market sales 4.5
-----
$29.1 million
=====
GAS SALES
Due to colder weather in the second quarter of 1996, gas sales to
ultimate consumers increased 2.6 million dth or 15.7% from 1995.
After adjusting for the effects of weather, sales to ultimate
consumers increased 7.0%. 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.
The total cost of gas included in expense increased 40.9% in
1996. This was the result of a 1.3 million increase in Dth
purchased and withdrawn from storage for ultimate consumer sales
($4.8 million) and a $4.1 million increase in Dth purchased for
spot market sales, coupled with an 8.6% increase in the average
cost per Dth purchased ($4.7 million) and a $9.8 million increase
in purchased gas costs and certain other items recognized and
recovered through the purchased gas adjustment clause (GAC). The
Company's net cost per Dth sold, as charged to expense and
excluding spot market purchases, increased to $5.24 in 1996 from
$4.30 in 1995.
Other operation expense increased $13.6 million primarily as a
result of an increase in bad debt expense ($5.0 million). The
Company has experienced a significant increase in past due
accounts receivable and is taking steps to improve its
collections. To the extent these steps are unsuccessful, the
Company will likely experience a higher level of bad debt
expense.
Maintenance expense decreased $5.7 million primarily as the
result of a decrease in nuclear maintenance expenses ($9.0
million). Nuclear maintenance costs were higher in 1995
primarily due to a planned refueling and maintenance outage at
Unit 2 (April 8, 1995 - June 2, 1995).
Other taxes decreased by approximately $14.4 million partly due
to the adjustment of 1995 Dunkirk Generating Steam Station
(Dunkirk Station) real estate tax amortization due to a tax
settlement refund ($5.7 million). In May 1996, the Company
entered into a six year agreement with Chautauqua County and the
City of Dunkirk regarding the real estate taxes paid and to be
paid for its Dunkirk Station. The Company not only received a
tax settlement refund from prior year overassessments, but also
had its annual taxes reduced to an amount that is somewhat less
than pre-litigation levels. In addition, 1996 taxes were lower
because 1995 taxes included the amortization of the New York
State sales tax audit costs ($2.8 million).
SIX MONTHS ENDED JUNE 30, 1996 VERSUS SIX MONTHS ENDED JUNE 30,
1995
Earnings for the first six months of 1996 were $130.0 million or
$0.90 per share, as compared with $153.0 million or $1.06 per
share in 1995. Earnings for the first six months were lower
because 1995 earnings included the recording of a one-time, non-
cash adjustment of prior years' DSM incentive revenues of $17
million, $9.4 million of revenues earned under the Unit 1
operating incentive sharing mechanism and a gain on the sale of
HYDRA-CO of $11.3 million that collectively increased 1995
earnings by 17 cents per share. In addition, increased operating
expenses of $21.7 million or 10 cents per share also contributed
to lower 1996 earnings. However, a decrease in other taxes of
$16.3 million or 7 cents per share and higher electric and
natural gas sales due to the colder weather partially offset
those factors that contributed to lower 1996 earnings. In
addition, 1995 earnings included a fuel target penalty of $10.1
million while 1996 earnings included a fuel target incentive of
$4.7 million, resulting in a net favorable impact on 1996
earnings as compared to 1995 earnings of $14.8 million or 7 cents
per share. The Company is required to share with ratepayers,
subject to certain limitations, fuel and purchased power cost
fluctuations from amounts forecast in rates.
ELECTRIC REVENUES
As shown in the table below, electric revenues, decreased $37.9
million or 2.2% from 1995, primarily due to a decrease in
miscellaneous electric revenues. Miscellaneous electric revenues
were lower in 1996 because 1995 electric revenues included the
recording of $55.5 million of unbilled, non-cash revenues in
accordance with the 1995 rate order, $9.4 million of revenues
earned under the Unit 1 operating incentive sharing mechanism and
a one-time, non-cash adjustment of prior years' DSM incentive
revenues of $17 million. In addition, FAC revenues decreased
$21.2 million, even though the Company made increased payments to
UGs. FAC revenues decreased in part due to the higher generation
from nuclear and hydro facilities that have lower fuel costs. In
1995, the low water supply limited the amount of hydroelectric
power that the Company could produce. In addition, Units 1 and 2
were taken out of service in early 1995 for planned refueling and
maintenance outages. The decrease in FAC revenues also reflects
a higher amount of transmission and resale revenues ($11.2
million) passed on to customers. However, higher electric and
natural gas sales due to the colder weather and higher electric
rates (effective April 26, 1995) partly offset those factors that
contributed to lower electric revenues.
Increase in base rates $ 44.9 million
Sales to other electric utilities 20.7
Changes in volume and mix of sales
to ultimate customers 3.2
Unit 1 incentive surcharge (9.4)
DSM revenues (20.6)
FAC revenues (21.2)
Unbilled revenues (55.5)
------
$(37.9) million
=======
ELECTRIC SALES
Electric kwh sales to ultimate consumers were approximately 17.0
billion in 1996, a 2.1% increase from the same period in 1995
primarily as a result of colder weather. After adjusting for the
effects of weather, sales to ultimate consumers would have
increased 0.3%. Sales for resale increased 1,035 million Kwh
(60.7%) due to increased demand for electricity in the northeast,
resulting in a net increase in total electric Kwh sales of 1,393
million (7.5%). Sales for resale generally result in low margin
contribution to the Company due to regulatory sharing mechanisms
and relatively low prices caused by excess supply.
SIX MONTHS ENDED JUNE 30,
ELECTRIC REVENUES (Thousands) SALES (GwHrs)
---------------------------------- --------------------------
% %
1996 1995 Change 1996 1995 Change
Residential $ 657,485 $ 621,412 5.8 5,402 5,216 3.6
Commercial 610,595 619,364 ( 1.4) 5,789 5,737 0.9
Industrial 256,409 267,044 ( 4.0) 3,553 3,526 0.8
Industrial - Special 29,083 28,388 2.4 2,150 2,067 4.0
Other 25,770 25,468 1.2 113 109 3.7
--------- ---------- ------ ------ ------ -----
Total to Ultimate
Consumers 1,579,342 1,561,676 1.1 17,007 16,655 2.1
Other Electric Systems 57,641 36,979 55.9 2,740 1,705 60.7
Miscellaneous 8,542 85,043 (90.0) - - -
Subsidiary 10,069 9,787 2.9 200 194 3.1
---------- --------- ------ ----- ------ -----
TOTAL $1,655,594 $1,693,485 ( 2.2) 19,947 18,554 7.5
========== ========= ====== ====== ====== =====
/TABLE
As indicated in the table below, internal generation increased in
1996, principally at Unit 1 and Unit 2. From February 8, 1995 to
April 4, 1995, Unit 1 was taken out of service for a planned
refueling and maintenance outage. From April 8, 1995 to June 2,
1995, Unit 2 was taken out for a planned refueling and
maintenance outage.
The amount of electricity delivered to the Company by UGs
decreased by approximately 616 Gwhrs (8.5%), but total UG costs
increased by approximately $42.8 million (8.5%), as explained
below.
HYDROELECTRIC UG PROJECTS
Due to high precipitation and spring run-off levels so far this
year, hydroelectric UG projects increased energy deliveries to
the Company by 425 Gwhrs under Power Purchase Agreements (PPAs)
which compelled increased payments to those UGs of $38.4 million.
The Company's increased payments to hydroelectric UGs was
primarily the result of the UGs' ability to produce more energy
in contrast to 1995, when low water availability limited the
amount of electricity hydroelectric UGs could produce. In
addition, a major new hydroelectric UG came on line in November
1995, contributing to the increase in hydroelectric deliveries.
"MUST RUN" UG COGENERATION PROJECTS
A substantial portion of the Company's portfolio of UG projects
operate on a "must run" basis. This means that they tend to run
to the maximum production levels regardless of the need or
economic value of the electricity produced. With respect to
"must run" UG cogeneration projects, a number of elements
combined to reduce the aggregate deliveries from and payments to
"must run" UGs. In total, "must run" UGs delivered 583 Gwhrs
less, resulting in UG payments of $11.4 million less. These
elements included renegotiation of certain contracts, maintenance
outages at certain UG facilities and lower deliveries from other
facilities.
SCHEDULABLE COGENERATION PROJECTS
The Company has renegotiated PPAs with a number of UG
cogeneration projects in order to obtain the right to schedule
the electricity deliveries of the project. In the case of
schedulable UG projects, although the terms of these PPAs allow
the Company to schedule energy deliveries from the facilities and
then pay for the energy delivered, the Company is also required
to make fixed payments. Fixed payments are due whether or not
the plant produces electricity so long as it is available for
service. (See Form 10-K for the fiscal year ended December 31,
1995, Part II, Item 8. Notes to Consolidated Financial
Statements - Note 9. Commitments and Contingencies - "Long-term
Contracts for the Purchase of Electric Power.") Quantities from
schedulable cogeneration UGs decreased 458 Gwhrs. Payments to
schedulable UGs increased by $15.8 million, primarily due to
increased fixed payments of approximately $19.7 million. The
increase in fixed payments are caused by the fixed payments made
to a new schedulable UG whose plant came on line in May 1995 and
due to escalation factors included in the PPAs that the Company
has with the schedulable UGs. In addition, payment rates for
electricity delivered from schedulable UGs increased from last
year's levels due to the increase in the cost of natural gas.
SIX MONTHS ENDED JUNE 30,
GwHrs Cost Cents/KwHr.
-------------------------- ------------------------- ------------
(Millions)
FUEL FOR ELECTRIC GENERATION:
% %
1996 1995 Change 1996 1995 Change 1996 1995
Coal 3,507 3,279 7.0 $49.6 $48.2 2.9 1.4 1.5
Oil 269 347 (22.5) 11.4 14.0 (18.6) 4.2 4.0
Natural Gas 50 492 (89.8) 2.2 9.2 (76.1) 4.4 1.9
Nuclear 4,506 2,763 63.1 25.3 15.5 63.2 0.6 0.6
Hydro 2,156 1,538 40.2 -- -- -- -- --
------ ----- ---- ---- ---- ---- --- ---
10,488 8,419 24.6 88.5 86.9 1.8 0.8 1.0
------ ----- ---- ---- ---- ---- --- ---
ELECTRICITY PURCHASED:
Unregulated
generators:
Capacity -- -- -- 106.5 86.6 23.0 -- --
Energy and
taxes 6,668 7,284 (8.5) 437.9 415.0 5.5 6.6 5.7
------ ------ ---- ----- ----- ---- --- ---
Total UG
purchases 6,668 7,284 (8.5) 544.4 501.6 8.5 8.2 6.9
Other 4,551 4,828 (5.7) 61.4 66.4 (7.5) 1.4 1.4
------ ------ ---- ----- ----- ---- --- ---
11,219 12,112 (7.4) 605.8 568.0 6.7 5.4 4.7
------ ------ ---- ----- ----- ---- --- ---
21,707 20,531 5.7 694.3 654.9 6.0 3.2 3.2
------ ------ ---- ----- ----- ---- --- ---
Fuel adjustment
clause -- -- -- (19.4) 2.8 -- -- --
Losses/Company
use 1,760 1,977 (11.0) -- -- -- -- --
------ ------ ---- ----- ----- ---- ---- ----
19,947 18,554 7.5 $674.9 $657.7 2.6 3.4 3.5
====== ====== ==== ===== ===== ==== ==== ====
/TABLE
GAS REVENUES
Gas revenues increased $98.1 million or 26.5% in 1996 from the
comparable period in 1995 as set forth in the table below:
Sales to ultimate customers $43.4 million
Spot market sales 27.8
Purchased gas adjustment clause revenues 26.9
-----
$98.1 million
=====
GAS SALES
Due to colder weather in 1996, gas sales to ultimate consumers
increased 8.3 million dth or 15.5% from 1995. After adjusting
for the effects of weather, sales to ultimate consumers increased
2.5%. 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.
SIX MONTHS ENDED JUNE 30,
GAS REVENUES (Thousands) SALES (Thousands of Dth)
------------------------------- -------------------------------
% %
1996 1995 Change 1996 1995 Change
Residential $291,938 $242,830 20.2 41,593 36,111 15.2
Commercial 116,252 94,854 22.6 18,261 15,900 14.8
Industrial 9,680 6,548 47.8 1,975 1,501 31.6
-------- -------- --------- ------- ------- -------
Total to Ultimate
Consumers 417,870 344,232 21.4 61,829 53,512 15.5
Other Gas Systems 77 625 (87.7) 17 135 (87.4)
Transportation of
Customer-Owned Gas 25,448 24,179 5.2 63,255 72,793 (13.1)
Spot Market Sales 28,369 551 5,048.6 7,023 272 2,482.0
Miscellaneous (3,524) 557 (732.7) - - -
---------- ------- --------- ------- ------- -------
Total to System
Core Customers $468,240 $370,144 26.5 132,124 126,712 4.3
========= ======== ========= ======= ======= =======
/TABLE
The total cost of gas included in expense increased 47.3%. This
was the result of an 8.3 million increase in Dth purchased and
withdrawn from storage for ultimate consumer sales ($23.9
million) and a $21.8 million increase in Dth purchased for spot
market sales, coupled with a 13.2% increase in the average cost
per Dth purchased ($22.5 million) and an $18.7 million increase
in purchased gas costs and certain other items recognized and
recovered through the purchased GAC. The Company's net cost per
Dth sold, as charged to expense and excluding spot market
purchases, increased to $4.19 in the first six months of 1996
from $3.60 in the same period in 1995.
Other operation expense increased $21.7 million primarily as a
result of an increase in bad debt expense ($9.3 million).
The Company has experienced a significant increase in past due
accounts receivable and is taking steps to improve its
collections. To the extent these steps are unsuccessful, the
Company will likely experience a higher level of bad debt
expense.
In April 1996, the Company and the local unions of the
International Brotherhood of Electrical Workers, representing all
of the Company's 6,100 unionized employees, agreed on a five-
year-three month labor agreement. The agreement includes a 1996
base salary freeze, and moderate salary increases through 2001.
However, represented employees will have up to a 2% incentive
opportunity that will be based upon Company savings achieved in
1996. In addition, changes were made in the new labor agreement
affecting pension and health and retirement benefits. The
Company does not believe that costs of the new contract will have
a material adverse affect on its results of operations or
financial condition.
Maintenance expense decreased $4.3 million primarily as the
result of a decrease in nuclear maintenance expenses ($14.4
million), offset in part, by an increase in amortization of
regulatory deferrals and increased labor expense associated with
storms in January 1996.
On February 8, 1995, Unit 1 was taken out of service for a
planned refueling and maintenance outage and returned to service
on April 4, 1995. Its next refueling and maintenance outage is
scheduled to begin in February 1997. On April 8, 1995, Unit 2
was taken out of service for a planned refueling and maintenance
outage and returned to service on June 2, 1995. Its next
refueling outage is scheduled for Fall 1996.
Other items (net) decreased by $9.3 million in the first six
months of 1996 from the comparable period in 1995 principally
because 1995 includes proceeds from the sale of HYDRA-CO. ($21.6
million), partially offset by certain accounting requirements of
the 1995 rate order.
Federal income taxes (net) decreased by approximately $10.4
million primarily due to a decrease in pre-tax income.
Other taxes decreased by approximately $16.3 million partly due
to the adjustment of 1995 Dunkirk Station real estate tax
amortization due to a tax settlement refund ($5.7 million). In
May 1996, the Company entered into a six year agreement with
Chautauqua County and the City of Dunkirk regarding the real
estate taxes paid and to be paid for its Dunkirk Station. The
Company not only received a tax settlement refund from prior year
overassessments, but also had its annual taxes reduced to an
amount that is somewhat less than pre-litigation levels. In
addition, 1996 taxes were lower because 1995 taxes included the
amortization of the New York State sales tax audit costs ($2.8
million).
PART II. OTHER INFORMATION
- ---------------------------
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
At the Company's annual meeting of shareholders on May
7, 1996, the election of Directors was as follows:
WITHHELD
FOR AUTHORITY
--- ---------
William F. Allyn 114,429,341 6,832,783
William E. Davis 112,556,971 8,705,153
William J. Donlon 111,597,890 9,664,234
Anthony H. Gioia 114,299,992 6,962,132
Dr. Patti McGill Peterson 114,336,046 6,926,078
ITEM 5. OTHER INFORMATION.
NRC ADVANCED NOPR
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 the fiscal year
ended December 31, 1995, Part II, Item 8. Notes to
Consolidated Financial Statements - Note 3. Nuclear
Operations - "Nuclear Plant Decommissioning"). Despite the
growing trend toward deregulation and asset divestiture, the
NRC will take actions to insure adequate funding 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 participated in comments filed by the Nuclear
Energy Institute in June 1996 on behalf of the commercial
nuclear industry in response to the NRC advanced NOPR. As
noted therein, the Company believes that it is appropriate
for the NRC to contemplate rulemaking in this area, but that
any such rulemaking should establish requirements for the
assurance of decommissioning funds availability that are
flexible and not prescriptive as to how licensees attain the
required level of assurance. The Company is unable to
determine the outcome of this matter.
COURT RULING ON DISPOSAL OF SPENT NUCLEAR FUEL
In July 1996, the United States Circuit Court of Appeals for
the District of Columbia ruled that the Department of Energy
(DOE) must begin accepting used fuel from the nuclear industry
by 1998 even though a permanent storage site will not be ready
by then. The Company is unable to determine the outcome of
this matter.
The Company currently has contracts with the DOE for the
disposal of spent nuclear fuel for both Units 1 and 2. Spent
nuclear fuel storage facilities at Units 1 and 2 are expected
to accommodate spent nuclear fuel discharges, while also
having sufficient space available to maintain full core off
load capability, through the years 2009 and 2012,
respectively.
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 and Six
Months Ended June 30, 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
June 30, 1996.
Exhibit 15 - Accountants' Acknowledgement Letter.
Exhibit 27 - Financial Data Schedule.
In accordance with Paragraph 4(iii) of Item 601(b) of
Regulation S-K, the Company agrees to furnish to the
Securities and Exchange Commission, upon request, a copy of
the agreements comprising the $804 million senior debt
facility that the Company completed with a bank group
during March 1996. The total amount of long-term debt
authorized under such agreement does not exceed 10 percent
of the total consolidated assets of the Company and its
subsidiaries.
(b) Reports on Form 8-K:
No reports on Form 8-K were filed during the quarter for
which this report is filed.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
SIGNATURES
- ----------
Pursuant to the requirements of the Securities Exchange Act of
1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
NIAGARA MOHAWK POWER CORPORATION
(Registrant)
Date: August 12, 1996 By /s/ Steven W. Tasker
Steven W. Tasker
Vice President-Controller and
Principal Accounting Officer
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
EXHIBIT INDEX
- -------------
Exhibit Page
Number Description Number
------- ----------- ------
11 Computation of the Average
Number of Shares of Common
Stock Outstanding for the Three
Months and Six Months Ended
June 30, 1996 and 1995.
12 Statement Showing Computations of
Ratio of Earnings to Fixed Charges,
Ratio of Earnings to Fixed Charges
without AFC and Ratio of Earnings
to Fixed Charges and Preferred
Stock Dividends for the Twelve
Months Ended June 30, 1996.
15 Accountants' Acknowledgement
Letter.
27 Financial Data Schedule.
EXHIBIT 11
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
Computation of the Average Number of Shares of Common Stock Outstanding
For the Three and Six Months Ended June 30, 1996 and 1995
(4)
Average Number
of Shares
Outstanding As
Shown on
Consolidated
Statement
(1) (2) (3) of Income
Shares of Number Share (3 divided by
Common of Days Days number of Days
Stock Outstanding (2 x 1) in Period)
--------- ----------- ------- ---------------
FOR THE THREE MONTHS
ENDED JUNE 30:
APRIL 1 - JUNE 30, 1996 144,332,855 91 13,134,289,805
SHARES SOLD -
ACQUISITION - SYRACUSE
SUBURBAN GAS COMPANY, INC. 16,984 20 339,680
----------- --------------
144,349,839 13,134,629,485 144,336,588
=========== ============== ===========
APRIL 1 - JUNE 30, 1995 144,330,482 91 13,134,073,862 144,330,482
=========== ============== ===========
FOR THE SIX MONTHS
ENDED JUNE 30:
JANUARY 1 - JUNE 30, 1996 144,332,123 182 26,268,446,386
SHARES SOLD AT VARIOUS
TIMES DURING THE PERIOD -
ACQUISITION - SYRACUSE
SUBURBAN GAS COMPANY, INC. - 17,716 * 447,284
----------- --------------
144,349,839 26,268,893,670 144,334,581
=========== ============== ===========
JANUARY 1 - JUNE 30, 1995 144,311,466 181 26,120,375,346
SHARES SOLD AT VARIOUS
TIMES DURING THE PERIOD -
DIVIDEND REINVESTMENT PLAN 19,016 * 2,871,416
----------- --------------
144,330,482 26,123,246,762 144,327,330
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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.
EXHIBIT 12
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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Statement Showing Computation of Ratio of Earnings to Fixed
Charges, Ratio of Earnings to Fixed Charges without AFC and Ratio
of Earnings to Fixed Charges and Preferred Stock Dividends for
the Twelve Months Ended June 30, 1996 (in thousands of dollars).
A. Net Income $223,929
B. Taxes Based on Income or Profits 124,465
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C. Earnings, Before Income Taxes 348,394
D. Fixed Charges (a) 309,879
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E. Earnings Before Income Taxes and
Fixed Charges 658,273
F. Allowance for Funds Used During
Construction (AFC) 6,004
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G. Earnings Before Income Taxes and
Fixed Charges without AFC $652,269
=======
PREFERRED DIVIDEND FACTOR:
H. Preferred Dividend Requirements $ 38,486
-------
I. Ratio of Pre-tax Income to Net Income (C/A) 1.556
-------
J. Preferred Dividend Factor (HxI) $ 59,884
K. Fixed Charges as Above (D) 309,879
-------
L. Fixed Charges and Preferred Dividends
Combined $369,763
=======
M. Ratio of Earnings to Fixed Charges (E/D) 2.12
=======
N. Ratio of Earnings to Fixed Charges
without AFC (G/D) 2.10
=======
O. Ratio of Earnings to Fixed Charges and
Preferred Dividends Combined (E/L) 1.78
=======
(a) Includes a portion of rentals deemed representative of the
interest factor ($27,205).
EXHIBIT 15
August 12, 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 August 12, 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
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