SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1995
- -------------------------------------------------
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 October 31, 1995 - 144,332,123
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
FORM 10-Q - For The Quarter Ended September 30, 1995
INDEX
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
a) Consolidated Statements of Income -
Three Months and Nine Months Ended
September 30, 1995 and 1994
b) Consolidated Balance Sheets - September 30,
1995 and December 31, 1994
c) Consolidated Statements of Cash Flows -
Nine Months Ended September 30, 1995 and 1994
d) Notes to Consolidated Financial Statements
e) Review by Independent Accountants
f) Independent Accountants' Report on the
Limited Review of the Interim Financial
Information
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of
Operations.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
Item 6. Exhibits and Reports on Form 8-K.
Signature
PART 1. FINANCIAL INFORMATION
- -----------------------------
ITEM 1. FINANCIAL STATEMENTS.
- -----------------------------
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
- ----------------------------------------------
THREE MONTHS ENDED SEPTEMBER 30,
--------------------------------
1995 1994
--------- ----------
(In thousands of dollars)
OPERATING REVENUES:
Electric $ 829,303 $ 861,002
Gas 57,928 57,808
---------- ----------
887,231 918,810
---------- ----------
OPERATING EXPENSES:
Operation:
Fuel for electric generation 78,577 47,155
Electricity purchased 243,462 285,013
Gas purchased 17,171 20,487
Other operation expense 150,830 177,033
Maintenance 49,296 51,252
Depreciation and amortization 79,850 77,456
Federal and foreign income taxes 28,606 28,487
Other taxes 125,313 122,990
---------- ----------
773,105 809,873
---------- ----------
OPERATING INCOME 114,126 108,937
---------- ----------
OTHER INCOME AND (DEDUCTIONS):
Allowance for other funds used
during construction 756 854
Federal and foreign income taxes 301 787
Other items (net) 1,222 5,838
---------- ----------
2,279 7,479
---------- ----------
INCOME BEFORE INTEREST CHARGES 116,405 116,416
---------- ----------
INTEREST CHARGES:
Interest on long-term debt 68,330 65,543
Other interest 2,850 5,265
Allowance for borrowed funds used
during construction (1,716) (2,775)
---------- ----------
69,464 68,033
---------- ----------
NET INCOME 46,941 48,383
Dividends on preferred stock 9,691 9,070
---------- ----------
BALANCE AVAILABLE FOR COMMON STOCK $ 37,250 $ 39,313
========== ==========
Average number of shares of common
stock outstanding (in thousands) 144,330 143,540
Balance available per average
share of common stock $ .26 $ .27
Dividends paid per share of common
stock $ .28 $ .28
/TABLE
PART 1. FINANCIAL INFORMATION
- -----------------------------
ITEM 1. FINANCIAL STATEMENTS.
- -----------------------------
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
- ----------------------------------------------
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------
1995 1994
--------- ----------
(In thousands of dollars)
OPERATING REVENUES:
Electric $2,522,788 $2,641,575
Gas 428,072 492,493
---------- ----------
2,950,860 3,134,068
---------- ----------
OPERATING EXPENSES:
Operation:
Fuel for electric generation 153,724 161,927
Electricity purchased 826,059 830,143
Gas purchased 200,828 260,669
Other operation expense 447,112 523,741
Maintenance 144,950 145,236
Depreciation and amortization 237,314 229,804
Federal and foreign income taxes 137,290 161,773
Other taxes 389,067 377,866
---------- ----------
2,536,344 2,691,159
---------- ----------
OPERATING INCOME 414,516 442,909
---------- ----------
OTHER INCOME AND (DEDUCTIONS):
Allowance for other funds used
during construction 1,068 2,512
Federal and foreign income taxes (7,297) 5,259
Other items (net) 19,694 12,238
---------- ----------
13,465 20,009
---------- ----------
INCOME BEFORE INTEREST CHARGES 427,981 462,918
---------- ----------
INTEREST CHARGES:
Interest on long-term debt 197,699 201,404
Other interest 17,427 13,386
Allowance for borrowed funds used
during construction (7,307) (6,278)
---------- ----------
207,819 208,512
---------- ----------
NET INCOME 220,162 254,406
Dividends on preferred stock 29,952 23,158
---------- ----------
BALANCE AVAILABLE FOR COMMON STOCK $ 190,210 $ 231,248
========== ==========
Average number of shares of common
stock outstanding (in thousands) 144,328 142,987
Balance available per average
share of common stock $ 1.32 $ 1.62
Dividends paid per share of common
stock $ .84 $ .81
/TABLE
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
CONSOLIDATED BALANCE SHEETS
- ---------------------------
ASSETS
- ------
SEPTEMBER 30,
1995 DECEMBER 31,
(UNAUDITED) 1994
------------ ------------
(In thousands of dollars)
UTILITY PLANT:
Electric plant $ 8,454,948 $ 8,285,263
Nuclear fuel 512,046 504,320
Gas plant 986,714 922,459
Common plant 260,543 291,962
Construction work in progress 355,912 481,335
----------- -----------
Total Utility Plant 10,570,163 10,485,339
Less-Accumulated depreciation and
amortization 3,570,441 3,449,696
----------- -----------
Net Utility Plant 6,999,722 7,035,643
----------- -----------
OTHER PROPERTY AND INVESTMENTS 174,484 224,039
----------- -----------
CURRENT ASSETS:
Cash, including temporary cash investments
of $84,671 and $50,052, respectively 104,046 94,330
Accounts receivable (less-allowance for
doubtful accounts of $3,600) (Note 2) 263,049 317,282
Unbilled revenues 183,500 196,700
Electric margin recoverable 36,796 66,796
Materials and supplies, at average cost:
Coal and oil for production of electricity 21,380 31,652
Gas storage 33,545 30,931
Other 143,328 150,186
Prepaid taxes 51,104 43,249
Other 37,353 45,189
----------- -----------
874,101 976,315
----------- -----------
REGULATORY AND OTHER ASSETS (NOTE 3):
Unamortized debt expense 144,556 153,047
Deferred recoverable energy costs 13,196 62,884
Deferred finance charges 239,880 239,880
Income taxes recoverable 465,109 465,109
Recoverable environmental restoration costs 238,610 240,000
Other 246,689 252,522
----------- -----------
1,348,040 1,413,442
----------- -----------
$ 9,396,347 $ 9,649,439
=========== ===========
/TABLE
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ----------------------------------------------------------
CONSOLIDATED BALANCE SHEETS
- ---------------------------
CAPITALIZATION AND LIABILITIES
- ------------------------------
SEPTEMBER 30, DECEMBER 31,
1995 (UNAUDITED) 1994
---------------- ---------
(In thousands of dollars)
CAPITALIZATION:
COMMON STOCKHOLDERS' EQUITY:
Common stock - $1 par value; authorized
185,000,000 shares; issued 144,330,482 and
144,311,466 shares, respectively $ 144,330 $ 144,311
Capital stock premium and expense 1,785,944 1,779,504
Retained earnings 607,555 538,583
---------- ----------
2,537,829 2,462,398
---------- ----------
CUMULATIVE PREFERRED STOCK, AUTHORIZED 3,400,000
SHARES, $100 PAR VALUE:
Non-redeemable (optionally redeemable),
issued 2,100,000 shares 210,000 210,000
Redeemable (mandatorily redeemable), issued
258,000 and 276,000 shares, respectively 24,000 25,800
CUMULATIVE PREFERRED STOCK, AUTHORIZED 19,600,000
SHARES, $25 PAR VALUE:
Non-redeemable (optionally redeemable),
issued 3,200,000 shares 80,000 80,000
Redeemable (mandatorily redeemable), issued
9,274,005 and 9,574,005 shares, respectively 226,450 230,200
---------- ----------
540,450 546,000
---------- ----------
Long-term debt 3,456,676 3,297,874
---------- ----------
Total Capitalization 6,534,955 6,306,272
---------- ----------
CURRENT LIABILITIES:
Short-term debt 46,001 416,750
Long-term debt due within one year 70,111 77,971
Sinking fund requirements on redeemable
preferred stock 7,200 10,950
Accounts payable 256,872 277,782
Payable on outstanding bank checks 26,424 64,133
Customers' deposits 14,703 14,562
Accrued taxes 52,309 43,358
Accrued interest 75,394 63,639
Accrued vacation pay 35,781 36,550
Other 55,196 77,818
---------- ----------
639,991 1,083,513
---------- ----------
REGULATORY AND OTHER LIABILITIES:
Accumulated deferred income taxes 1,353,940 1,258,463
Deferred finance charges 239,880 239,880
Employee pension and other benefits 237,169 235,741
Unbilled revenues 20,028 93,668
Deferred pension settlement gain 37,679 50,261
Other 92,705 141,641
---------- ----------
1,981,401 2,019,654
---------- ----------
COMMITMENTS AND CONTINGENCIES (NOTES 2 AND 3):
Liability for environmental restoration 240,000 240,000
---------- ----------
$9,396,347 $9,649,439
========== ==========
/TABLE
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
- -------------------------------------
INCREASE (DECREASE) IN CASH (UNAUDITED)
- ----------------------------------------
NINE MONTHS ENDED SEPTEMBER 30,
1995 1994
------------- ---------
(In thousands of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 220,162 $ 254,406
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 237,314 229,804
Amortization of nuclear fuel 23,141 29,316
Provision for deferred Federal income taxes 82,791 59,763
Electric margin recoverable 30,000 (27,055)
Gain on sale of subsidiary (8,901) -
Deferred recoverable energy costs 49,688 18,697
Amortization of nuclear replacement power cost
disallowance - (17,311)
Unbilled revenues (60,440) -
Decrease in net accounts receivable 54,233 27,639
(Increase) decrease in materials and supplies 11,773 (76)
Decrease in accounts payable and accrued expenses (45,096) (37,251)
Increase in accrued interest and taxes 20,706 5,427
Changes in other assets and liabilities (65,759) 19,289
---------- ----------
NET CASH PROVIDED BY OPERATING ACTIVITIES 549,612 562,648
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction additions (231,111) (292,070)
Nuclear Fuel (7,726) (10,427)
---------- ----------
Acquisition of utility plant (238,837) (302,497)
Decrease in materials and supplies
related to construction 2,743 1,390
Decrease in accounts payable and accrued
expenses related to construction (11,274) (9,313)
Proceeds from sale of subsidiary (net of cash sold) 161,087 -
Increase in other investments (85,331) (45,413)
Other 9,236 (15,557)
---------- ----------
NET CASH USED IN
INVESTING ACTIVITIES (162,376) (371,390)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the sale of common stock 284 23,765
Issuance of preferred stock - 150,000
Redemption of preferred stock (9,300) (15,550)
Issuance of long-term debt 275,000 325,705
Reductions in long-term debt (114,000) (486,586)
Net change in short-term debt (370,749) (9,015)
Dividends paid (151,190) (136,768)
Other (7,565) (21,266)
---------- ----------
NET CASH USED IN FINANCING ACTIVITIES (377,520) (169,715)
---------- ----------
NET INCREASE IN CASH 9,716 21,543
Cash at Beginning of Period 94,330 124,351
---------- ----------
CASH AT END OF PERIOD $ 104,046 $ 145,894
========== ==========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid $ 207,357 $ 221,482
Income taxes paid $ 35,376 $ 93,001
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. The Company, in the opinion of management, has included
adjustments (which include normal recurring adjustments)
necessary for a fair statement of the results of operations
for the interim periods presented. The consolidated
financial statements for 1995 are subject to adjustment at
the end of the year when they will be audited by
independent accountants. The consolidated financial
statements and notes thereto should be read in conjunction
with the financial statements and notes for the years ended
December 31, 1994, 1993 and 1992 included in the Company's
1994 Annual Report to Shareholders on Form 10-K.
The Company's electric sales tend to be substantially
higher in summer and winter months as related to weather
patterns in its service territory; gas sales tend to peak
in the winter. Notwithstanding other factors, the
Company's quarterly net income will generally fluctuate
accordingly. Therefore, the earnings for the three-month
and nine-month periods ended September 30, 1995, should not
be taken as an indication of earnings for all or any part
of the balance of the year.
2. COMMITMENTS AND CONTINGENCIES.
SALE OF CUSTOMER RECEIVABLES: (See Form 10-K for fiscal
year ended December 31, 1994, Item 8., Notes to
Consolidated Financial Statements - Note 9. Commitments and
Contingencies.) The Company has an agreement whereby it
can sell an undivided interest in a designated pool of
customer receivables, including accrued unbilled electric
revenues. The agreement was amended in September 1995 to
allow for sale of an additional $50 million of customer
receivables. The Company plans to sell this additional $50
million amount by the end of the year, which will bring the
total amount of receivables sold under the agreement to
$250 million. For receivables sold, the Company has
retained collection and administrative responsibilities as
agent for the purchaser. As collections reduce previously
sold undivided interests, new receivables are customarily
sold.
The undivided interest in the designated pool of
receivables was sold with limited recourse. The agreement
provides for a loss reserve pursuant to which additional
customer receivables are assigned to the purchaser to
protect against bad debts. Under the terms of the
agreement, a formula determines the amount of the
loss reserve. At September 30, 1995, the amount of additional
receivables assigned to the purchaser, as a loss reserve, was
approximately $62 million. Although this represents the
formula-based amount of credit exposure at
September 30, 1995 under the agreement, historical losses
have been substantially less.
To the extent actual loss experience of the pool
receivables exceeds the loss reserve, the purchaser absorbs
the excess. Concentrations of credit risk to the purchaser
with respect to accounts receivable are limited due to the
Company's large, diverse customer base within its service
territory. The Company generally does not require
collateral, i.e. customer deposits.
ENVIRONMENTAL ISSUES: The public utility industry
typically utilizes and/or generates in its operations a
broad range of potentially hazardous wastes and by-
products. The Company believes it is handling identified
wastes and by-products in a manner consistent with Federal,
state and local requirements and has implemented an
environmental audit program to identify any potential areas
of concern and assure compliance with such requirements.
The Company is also currently conducting a program to
investigate and restore, as necessary to meet current
environmental standards, certain properties associated with
its former gas manufacturing process and other properties
which the Company has learned may be contaminated with
industrial waste, as well as investigating identified
industrial waste sites as to which it may be determined
that the Company contributed. The Company has also been
advised that various Federal, state or local agencies
believe certain properties require investigation and has
prioritized the sites based on available information in
order to enhance the management of investigation and
remediation, if necessary.
The Company is currently aware of 90 sites with which it
has been or may be associated, including 47 which are
Company-owned. With respect to non-owned sites, the
Company may be required to contribute some proportionate
share of remedial costs.
Investigations at each of the Company-owned sites are
designed to (1) determine if environmental contamination
problems exist, (2) if necessary, determine the appropriate
remedial actions required for site restoration and (3)
where appropriate, identify other parties who should bear
some or all of the cost of remediation. Legal action
against such other parties, if necessary, will be
initiated. After site investigations are completed, the
Company expects to determine site-specific remedial actions
and to estimate the attendant costs for restoration.
However, since technologies are still developing and the
Company has not yet undertaken full-scale remedial actions
at any identified sites, nor have any detailed remedial
designs been prepared or submitted to appropriate
regulatory agencies, the ultimate cost of remedial actions
may change substantially.
Estimates of the cost of remediation and post-remedial
monitoring are based upon a variety of factors, including
identified or potential contaminants, location, size and
use of the site, proximity to sensitive resources, status
of regulatory investigation and knowledge of activities at
similarly situated sites, and the Environmental Protection
Agency figure for average cost to remediate a site. Actual
Company expenditures are dependent upon the total cost of
investigation and remediation and the ultimate
determination of the Company's share of responsibility for
such costs, as well as the financial viability of other
identified responsible parties since clean-up obligations
are joint and several. The Company has denied any
responsibility in certain of these Potentially Responsible
Party (PRP) sites and is contesting liability accordingly.
As a consequence of site characterizations and assessments
completed to date and negotiations with PRP's, the Company
has accrued a liability of $240 million, representing the
low end of the range of its share of the estimated cost for
investigation and remediation. The potential high end of
the range is presently estimated at approximately $1
billion, including approximately $500 million assuming the
unlikely event the Company is required to assume 100%
responsibility at non-owned sites.
In the Company's 1995 rate order, costs incurred during
1995 for the investigation and restoration of Company-owned
sites and sites with which it is associated are subject to
80%/20% (ratepayer/Company) sharing. In 1995, the Company
estimates it will incur $13.5 million of such costs,
resulting in a potential disallowance of approximately $2.7
million (before tax), which the Company has accrued as a
loss in Other items (net) on the Consolidated Statements of
Income. The accrued loss will be subject to adjustment
based on actual expenditures made in 1995. The Public
Service Commission of the State of New York (PSC) stated in
its order that the decision to require sharing will be
revisited for 1996 and beyond in multi-year rate
negotiations. Accordingly, if the 80%/20% (ratepayer/
Company) sharing were to continue to be applied to rate
years beyond 1995, the Company would be required to write
off 20% of its regulatory asset associated with
environmental restoration costs. While the PSC is
conducting a generic study on this issue, the Company is
unable to predict whether sharing will be proposed or
adopted in its pending multi-year rate case. However, the
Company believes rate case treatment of environmental
restoration costs will continue to be reviewed by the PSC
in the context of future rate proceedings. The Company has
recorded a regulatory asset representing the remediation
obligations to be recovered from ratepayers.
The Company has provided notices of insurance claims to
carriers with respect to the investigation and remediation
costs for manufactured gas plant, industrial waste sites
and sites for which the Company has been identified as a
PRP. The Company is unable to predict whether such
insurance claims will be successful.
TAX ASSESSMENTS: The Internal Revenue Service (IRS) has
conducted an examination of the Company's Federal income
tax returns for the years 1987 and 1988 and has submitted a
Revenue Agents' Report to the Company. The IRS has
proposed various adjustments to the Company's federal
income tax liability for these years which could increase
Federal income tax liability by approximately $80 million,
before assessment of penalties and interest. Included in
these proposed adjustments are several significant issues
involving Nine Mile Point Nuclear Station Unit No. 2 (Unit
2). The Company is vigorously defending its position on
each of the issues, and submitted a protest to the IRS in
1993. Pursuant to the Unit 2 settlement entered into with
the PSC in 1990, to the extent the IRS is able to sustain
adjustments, the Company will be required to absorb a
portion of any assessment. The Company believes any such
disallowance will not have a material impact on its
financial position or results of operations. The Company
is currently attempting to negotiate a settlement of these
issues with the Appeals Division of the IRS.
LITIGATION: 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. In
August 1995, the Company filed a motion to reargue or
for leave to appeal to the Court of Appeals. The
Company's motion was denied on October 25, 1995.
(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. Appeals from the order might be
pursued. Fourth Branch has filed for protection under
Chapter 11 of the Bankruptcy Code in the Bankruptcy
Court for the Northern District of New York.
(c) On June 8, 1994, Medina Power Company (Medina) filed a
lawsuit against the Company in the U.S. District Court
for the Western District of New York. Medina alleges,
among other claims, that the Company violated various
New York State antitrust laws in connection with a
contract that the Company has with Medina. On July
11, 1995 Medina amended its complaint and removed the
allegation of antitrust violations, and is now seeking
unspecified damages.
The Company had previously entered into a contract
with Medina, an unregulated generator, for the
purchase of electricity. The original contract
required Medina to be a qualifying facility (QF) under
federal law or face a contractual penalty. Having
come on-line without a thermal host, Medina did not
meet this QF requirement, subjecting it to a 15% rate
reduction. The Company advised Medina that it had
exercised its contract right and reduced the rate
accordingly. The Company believes Medina's lawsuit is
without merit, but cannot predict the outcome of this
action.
(d) The Company is involved in a number of court cases
regarding the price of energy it is required to
purchase in excess of contract levels from certain
unregulated generators ("overgeneration"). The
Company has paid the unregulated generators based on
its short-run avoided cost (under Service Class No. 6)
for all such overgeneration rather than the price
which the unregulated generators contend is applicable
under the contracts. At October 31, 1995, this amount
of overgeneration adjustments in dispute that the
Company estimates it has not paid or accrued is
approximately $20 million. The Company cannot predict
the outcome of these actions, but will continue to
aggressively press its position.
3. RATE AND REGULATORY ISSUES AND CONTINGENCIES.
(See Item 2., Management's Discussion and Analysis of
Financial Condition and Results of Operations - "1995 Rate
Order" and "Multi-Year Electric Rate Proceeding.")
On March 29, 1995, the Federal Energy Regulatory Commission
(FERC) issued a Notice of Proposed Rulemaking (NOPR) on
Open Access Non-Discriminatory Transmission Services by
Public Utilities and Transmitting Utilities and a
supplemental NOPR on Recovery of Stranded Costs.
Responding to competitive pressures in the industry and
changes in statutes applicable to the industry, the FERC
seeks to encourage lower electricity rates by structuring
an orderly transition to a competitive wholesale power
market. To accomplish this goal, the NOPR seeks to ensure
non-discriminatory access to the transmission system grid
for all wholesale buyers and sellers of electric energy in
interstate commerce, and to address the transition costs
associated with open transmission access. Thus, a final
rule would define the non-discriminatory terms and
conditions under which unregulated generators (UGs),
neighboring utilities, and other suppliers could gain
access to a utility's transmission grid to deliver power to
wholesale customers such as municipal distribution systems,
rural electric cooperatives, or other utilities.
In a supplemental NOPR on stranded costs, the FERC has
promulgated the principle that utilities are entitled to
full recovery of "legitimate, prudent, and verifiable"
stranded costs at both the state and federal level. The
NOPR also concludes that the FERC should be the principal
forum for addressing the recovery of stranded costs due to
potential municipalization or similar situations where
former retail customers become wholesale customers, as well
as for wholesale stranded costs. With respect to stranded
costs that result from retail wheeling, the FERC proposes
that state regulatory authorities assume responsibility,
except in the narrow circumstance where state regulatory
authorities lack the authority to address the recovery of
such costs.
The FERC continues to seek comments with respect to the
complex issues raised by power pools. The New York Power
Pool (NYPP), of which the Company is a member, is actively
evaluating the effect of wholesale competition and the NOPR
on NYPP operations and pricing policies. While changes to
existing NYPP arrangements are expected, the extent and
nature of these changes and their possible effects on the
Company are uncertain.
Comments and reply comments on the NOPR were due August 7,
1995 and October 4, 1995, respectively. The Company
responded, both individually and as a member of several
utility groups, in support of the FERC's position with
respect to the recovery of stranded costs occasioned by
both wholesale and retail wheeling, but has urged the FERC
not to abdicate its responsibility for retail stranded
costs. The FERC has scheduled a number of technical
conferences over the remainder of 1995 to elicit public
involvement. It is anticipated that a final rule could
take effect in early 1996. However, the Company cannot
predict the outcome of this matter or its effects on the
Company's results of operations or financial condition.
The NOPR is indicative of regulatory and structural changes
besetting the electric utility industry and the Company,
which accounts for the effects of regulation in accordance
with Statement of Financial Accounting Standards No. 71,
"Accounting for the Effects of Certain Types of
Regulation," (SFAS No. 71). The Company's financial
statements reflect assets and costs based on ratemaking
conventions, as approved by the PSC and the FERC, under
which certain expenses and credits, normally reflected in
income as incurred, are only recognized when included in
rates and recovered from or refunded to customers.
Virtually all costs of this nature which were determined by
the regulators to have been prudently incurred have been
and continue to be recoverable through rates in the course
of normal ratemaking procedures and the Company believes
that the items currently deferred on its consolidated
balance sheet should be afforded similar treatment.
Continued accounting under SFAS No. 71 requires, among
other things, that rates be designed to recover specific
costs of providing regulated services and products and that
it be reasonable to assume that rates are set at levels
that will recover a utility's costs and can be charged to
and collected from customers. When a utility determines it
can no longer apply the provisions of SFAS No. 71 to all or
a part of its operations, it must eliminate from its
balance sheet the effects of actions of regulators that had
been recorded previously as assets and liabilities pursuant
to SFAS No. 71, but which would have not been so accounted
for by enterprises in general. The PSC's April 21, 1995
Order (1995 rate order) contemplates no change in this
approach to such reporting. The 1995 rate order directed
the parties to the Proceeding to address a broad spectrum
of issues that are raised as New York State and the nation
move from energy markets that are highly regulated to
markets that are governed by increasing competition and
market forces. The Company filed a proposal with the PSC
on October 6, 1995, called PowerChoice in response to the
broad issues raised by the transition to a more competitive
market. PowerChoice provides for a corporate restructuring
designed to facilitate a transition to a competitive
electric generation market. (See Item 2., Management's
Discussion and Analysis of Financial Condition and Results
of Operations - "Multi-Year Electric Rate Proceeding").
The PowerChoice proposal, which is offered as an integrated
package and not piecemeal, although the details are subject
to compromise, includes these key provisions:
* Creation of a competitive wholesale electricity market
and direct access by retail customers.
* Separation of the Company's power generation business.
* Relief from overpriced unregulated generator contracts
that were mandated by public policy, along with
equitable write-downs of above-market Company assets.
* A price freeze or cut for all the Company's electric
customers.
The Company believes the PowerChoice proposal is the best
course for dealing with the problems it is encountering as
the electric energy industry is deregulated. Traditional,
cost-based rate making would otherwise require the Company
to seek in excess of a 5% increase in electric revenues for
1996, driven largely by increases in UG payments, taxes and
lower sales. The Company currently forecasts about a 3.9%
decline in annual public sales from levels assumed in
setting 1995 rates. Price increases of this magnitude
would further erode the Company's ability to be competitive
in open energy markets and to continue to apply certain
fundamental accounting standards applicable to regulated
businesses, as discussed below. In the context of the
PowerChoice proposal negotiations and other initiatives
being pursued by the Company, reduction or cessation of
common and preferred stock dividends and, as a last resort,
the ultimate possibility of restructuring under Chapter 11
of the U.S. Bankruptcy Code cannot be ruled out.
The price freeze and restructuring of the Company's markets
and business envisioned in the PowerChoice proposal are
contingent on critical cost reductions, which depend in
turn on the willingness of the UGs and the Company to
absorb the losses required to make substantial reductions
in the Company's embedded cost structure (i.e., sunk costs
of the Company's generation and future obligations for UG
contracts). The Company's PowerChoice proposal would
reduce its embedded cost structure through substantial
write-offs if, and only if, the UGs agree to cost
reductions that are proportional to their relative
responsibility for strandable costs (i.e., those embedded
costs that would not be recovered at competitive market
prices). The Company proposes reduction in its fixed costs
of service be made by mutual contribution of the Company's
shareholders and UGs that are in the same proportion as the
contribution of each to the problem of strandable costs,
which the Company calculates to be $4 of UG strandable cost
for every $1 of Company strandable cost. The Company has
proposed that the remaining strandable costs be recoverable
by the Company and the UGs through surcharges on rates for
remaining monopoly (i.e., distribution and transmission)
services. Recovery of remaining strandable costs by the
new owner of the Company's generation facilities is
intended to be structured so as not to impede each unit
from being an efficient participant in the competitive
generation market.
The Company is pursuing other courses of action to support
the objectives in restructuring. Certain UG projects have
received very large front-end-loaded payments in order to
obtain financing. Those projects are obligated to repay
those advance payments after their financing is paid off.
The Company seeks to ensure as part of its PowerChoice
proposal that its ratepayers are repaid these funds by
requiring the project owners to provide the Company
commercially acceptable, firm security for these
obligations (estimated to be worth $1.3 billion in today's
dollars).
The successor to all the Company's assets and businesses
other than generation would be an unregulated holding
company which would provide fully regulated transmission,
distribution and gas services through one subsidiary and,
through a second subsidiary, would provide competitive
unregulated services such as energy marketing. The Company
believes the regulated subsidiary would continue to account
for its assets and costs, based on ratemaking conventions
as approved by the PSC and FERC, in accordance with SFAS
No. 71.
Effective for the year commencing January 1, 1996, this
accounting standard, under which the Company reports its
financial condition and results of operations, will be
amended by Statement of Financial Accounting Standards No.
121, "Accounting for the Impairment of Long-Lived Assets
and Long-Lived Assets to be Disposed Of" (SFAS No. 121).
While the Company has not completed analyzing all the
changes which may be occasioned by SFAS No. 121, these
changes, more likely than not, may have a significant
adverse effect on the Company's financial statements, in
particular with regard to the continued recording of
regulatory assets on the Company's balance sheet with
respect to the Company's electric business. The Company
anticipates having electric regulatory assets of
approximately $1.3 billion and electric regulatory
liabilities of approximately $.4 billion as of January 1,
1996, for a net amount of approximately $.9 billion that
would be at risk if accounting under SFAS No. 71 were to be
discontinued for the Company's entire electric business.
Of this amount, approximately $.3 billion relates to the
generation portion of its electric business. No impact on
the Company's gas business is anticipated. The essence of
the change in accounting standards is that the Company will
need to conclude that the regulatory assets in question
continue to be probable of recovery. The current
accounting standard requires a conclusion only that such
assets are not probable of loss. Current conditions in the
generation portion of the Company's business, relating to
market costs of power, erosion of margins because of
inadequate rate relief and the incursion of unregulated
generators on the Company's customer base, when taken
together with the Company's PowerChoice proposal described
above, may call into question the continued recording of
such assets and may require material downward adjustments
in those accounts related to the generation portion of the
Company's business. Lack of progress in adopting and
implementing the PowerChoice proposal may also raise
questions about the continued applicability of SFAS No. 71
for the entire electric business. Any such adjustments
would result in a reduction of retained earnings, whose
balance is currently approximately $600 million. Various
tests under applicable law and corporate instruments,
including those with respect to issuance of debt and equity
securities, payment of preferred and common dividends and
certain types of transfers of assets could be adversely
implicated by any such writedowns. The Company cannot
currently predict whether, when, or to what extent the new
accounting standard will require such adjustments, or the
impact on its financial flexibility and operations.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
REVIEW BY INDEPENDENT ACCOUNTANTS
The Company's independent accountants, Price Waterhouse LLP, have
made limited reviews (based on procedures adopted by the American
Institute of Certified Public Accountants) of the unaudited
Consolidated Balance Sheet of Niagara Mohawk Power Corporation
and Subsidiary Companies as of September 30, 1995 and the
unaudited Consolidated Statements of Income for the three-month
and nine-month periods ended September 30, 1995 and 1994 and the
unaudited Consolidated Statements of Cash Flows for the nine-
months ended September 30, 1995 and 1994. The accountants'
report regarding their limited reviews of the Form 10-Q of
Niagara Mohawk Power Corporation and its subsidiaries appears on
the next page. That report does not express an opinion on the
interim unaudited consolidated financial information. Price
Waterhouse LLP has not carried out any significant or additional
audit tests beyond those which would have been necessary if their
report had not been included. Accordingly, such report is not a
"report" or "part of the Registration Statement" within the
meaning of Sections 7 and 11 of the Securities Act of 1933 and
the liability provisions of Section 11 of such Act do not apply.
PRICE WATERHOUSE LLP
ONE MONY PLAZA
SYRACUSE NY 13202
TELEPHONE 315-474-6571
REPORT OF INDEPENDENT ACCOUNTANTS
November 14, 1995
To the Stockholders and Board of Directors of
Niagara Mohawk Power Corporation
300 Erie Boulevard West
Syracuse NY 13202
We have reviewed the condensed consolidated balance sheet of
Niagara Mohawk Power Corporation and its subsidiaries as of
September 30, 1995, and the related condensed consolidated
statements of income for the three-month and nine-month periods
ended September 30, 1995 and 1994 and of cash flows for the nine
months ended September 30, 1995 and 1994. These financial
statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established
by the American Institute of Certified Public Accountants. A
review of interim financial information consists principally of
applying analytical procedures to financial data and making
inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit
conducted in accordance with generally accepted auditing
standards, the objective of which is the expression of an opinion
regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material
modifications that should be made to the condensed consolidated
financial statements referred to above for them to be in
conformity with generally accepted accounting principles.
We have previously audited, in accordance with generally accepted
auditing standards, the consolidated balance sheet at December
31, 1994, and the related consolidated statements of income,
retained earnings and cash flows for the year then ended (not
presented herein); and in our report dated February 1, 1995, we
expressed an unqualified opinion (containing an explanatory
paragraph relating to the Company's involvement as a defendant in
lawsuits relating to actions with respect to certain purchased
power contracts and an explanatory paragraph with respect to the
Company's multi-year electric rate proceeding) on those
consolidated financial statements. In our opinion, the
information set forth in the accompanying condensed consolidated
balance sheet as of December 31, 1994 is fairly stated, in all
material respects, in relation to the consolidated balance sheet
from which it has been derived.
As discussed in Note 3, the Company filed a proposal
("PowerChoice") on October 6, 1995 with the Public Service
Commission in connection with its multi-year electric rate
proceedings which could result in material changes in the form of
regulation which is applied to the Company. PowerChoice provides
for a corporate restructuring designed to facilitate a transition
to a competitive electric generation market. If the proposal is
approved and certain other conditions are met by third parties,
the Company would discontinue application of Financial Accounting
Standards No. 71, Accounting for the Effects of Certain Types of
Regulation (SFAS No. 71), with respect to its electric generation
business and write off a substantial portion of its embedded cost
structure associated with that business. Such an outcome would
have a material adverse effect on the Company's results of
operations and financial condition. As also discussed in Note 3,
SFAS No. 71 has been amended, effective January 1, 1996, by
Statement of Financial Accounting Standards No. 121, Accounting
for the Impairment of Long-Lived Assets and Long-Lived Assets to
be Disposed Of (SFAS No. 121). While the Company has not yet
fully assessed the financial consequences of applying the
provisions of SFAS No. 121, its application could have a material
adverse effect on the Company's results of operations and
financial condition if rates established in the future are no
longer cost-based or if management can no longer conclude that
existing regulatory assets are probable of recovery due to lack
of progress in adopting and implementing the PowerChoice
proposal. Because a number of other parties are involved in the
decision making process associated with the proposal, the Company
is unable to predict whether or when this matter will be
resolved. As a result, the Company cannot rule out cessation of
common and preferred stock dividends and the ultimate possibility
of restructuring under Chapter 11 of the U.S. Bankruptcy Code.
Because the outcome of these uncertainties cannot be predicted,
the accompanying financial statements do not include any
adjustments that might result from the resolution of these
matters.
/s/ Price Waterhouse LLP
- ------------------------
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations
UNREGULATED GENERATORS
(See Form 10-K for fiscal year ended December 31, 1994, Item 1.
Business - "Unregulated Generators," and "Multi-Year Electric
Rate Proceeding.")
In recent years, a leading factor in the increases in customer
bills and the deterioration of the Company's competitive position
has been the requirement to purchase power from unregulated
generators at prices in excess of the Company's internal cost of
production and in volumes greater than the Company's needs.
For the three months and nine months ended September 30, 1995,
unregulated generator purchases were approximately $225.9 million
and $727.5 million, respectively, compared to approximately
$238.3 million and $716.5 million, respectively, for the same
periods in 1994. For the three months and nine months ended
September 30, 1995, unregulated generator purchases provided
about one-third of the Company's power supply while constituting
about three-fourths of the Company's fuel and purchased power
costs.
On January 11, 1995, FERC issued an order in a case involving
Connecticut Light & Power (CL&P) that the Public Utility
Regulatory Policy Act forbids the states from requiring utilities
to pay more than avoided cost to QFs for electric power. FERC,
however, also ruled that it would not invalidate any pre-existing
contracts, but only would apply its ruling prospectively or to
contracts that were subject to a pending challenge (instituted at
the time of signing) by a utility. On the same day, FERC issued
an order that an ongoing challenge by the Company to the New York
Law requiring utilities to pay QFs a minimum of six cents for
electric power (the Six Cent Law) was moot in light of amendment
of that law in 1992 to prohibit future power purchase contracts
requiring the utility to pay more than its avoided cost. This
latter proceeding had been initiated in 1987. In April 1988,
FERC had ruled in the Company's favor, finding that the states
could not impose rates exceeding avoided cost for purchases from
QFs, but then stayed that decision in light of a rulemaking it
was instituting to address the issue. That rulemaking was never
completed.
On February 10, 1995, the Company filed a petition for rehearing
of both orders, which was subsequently denied. Thereafter, the
Company filed with the U.S. Court of Appeals for the District of
Columbia its petitions for review of FERC's denials of its
petitions for rehearing, which FERC and other parties moved to
dismiss for lack of jurisdiction. These motions remain pending.
On May 11, 1995, the Company filed complaints in the U.S.
District Court for the Northern District of New York against the
FERC and the PSC, contending that the FERC unlawfully ruled that
its decision in CL&P does not apply to purchases of power under
existing agreements. The PSC was named in this complaint on the
basis that its policies compelled the Company to enter into the
above market value agreements. In July 1995, various parties to
these actions, including the FERC and the PSC, moved to dismiss
this case. Those motions remain pending.
During April 1995, FERC also ruled against New York State
Electric and Gas Corp. (NYSEG) in a case involving contracts with
unregulated generators, despite NYSEG's position that the
unregulated generators' rates exceeded avoided costs. The PSC
supported NYSEG in the case, in which the utility sought to
revise long-term contracts signed in 1990 to buy up to 417
megawatts from two unregulated generators. NYSEG argued that the
costs it used to calculate the rates were no longer valid because
cheaper power was now available and the excess contract prices
impose a harsh burden on its electric customers. On May 11,
1995, NYSEG requested rehearing of the FERC's ruling which was
subsequently denied.
Despite the lengthy and multi-faceted campaign that the Company
has mounted with respect to unregulated generator contracts over
the past five years, the courts and regulatory agencies with whom
the Company's complaints have been lodged have provided little
relief. (See Form 10-K for fiscal year ended December 31, 1994,
Item 3., Legal Proceedings). For the most part, these bodies
have either rejected the Company's position or postponed
addressing the merits of the cases in question. This delay has
not relieved the Company or its ratepayers of the substantial
burden of these contracts. Although the Company will continue
with its challenges, there can be no assurance that any success
will be achieved or, if it is achieved, that it will occur in the
next several years.
1995 RATE ORDER
(See Note 3 of Notes to the Consolidated Financial Statements -
"Rate and Regulatory Issues and Contingencies," and Form 10-K for
fiscal year ended December 31, 1994, Item 1. Business - "1995
Five-Year Rate Plan.")
Through its Brief Opposing Exceptions dated March 2, 1995, the
Company had requested an increase in 1995 electric revenues of
approximately $110 million (3.5%) and an increase in 1995 gas
revenues of $16.4 million (2.7%).
On April 21, 1995, the Company received a rate decision (1995
rate order) from the PSC which approved an approximately $47
million increase in electric revenues and a $4.9 million increase
in gas revenues. The expected bill impact to customers is a 1.5%
increase for electric (a 3.4% increase for residential and a 1.6%
decrease for large industrial) and an 0.8% increase for gas. A
full opinion explaining the bases for determinations and
conclusions in the 1995 rate order has not yet been issued by the
PSC.
The 1995 rate order allows the Company to retain its fuel
adjustment clause mechanism, but the electric revenue adjustment
mechanism (NERAM), which permitted the Company to recover revenue
shortfalls during future periods, was discontinued (See "Results
of Operations").
The 1995 rate order includes performance-based penalties related
to customer service quality and demand-side management programs,
which the Company does not believe will have a material adverse
affect on its results of operations or financial condition.
Further, the 1995 rate order allocates to ratepayers all of the
$58.4 million of savings associated with the Company's 1994
voluntary employee reduction program. This allocation of
savings, in combination with other adjustments made by the PSC,
puts considerable pressure on the Company's 1995 earnings levels.
Although the 1995 rate order establishes allowed returns on
equity of 11.0% in the electric case and 11.4% in the gas case,
the Company's original analysis of the 1995 rate order
anticipated that its overall return on equity in 1995, including
the impact related to the elimination of the NERAM, expected
Measured Equity Return Incentive Term (MERIT) awards and Nine
Mile Point Nuclear Station Unit No. 1 (Unit 1) performance
incentive, would range between 8.5% and 9.5%. However, due to
even weaker kilowatt-hour (Kwh) sales and resulting lower
revenues experienced in 1995 than previously anticipated, the
Company now believes that it will be extremely difficult for it
to achieve equity returns in this range. In addition, the
Company originally anticipated that it would receive MERIT awards
of approximately $28 million related to its performance in 1994.
However, based on current calculations, it now believes that it
will receive approximately $19 million.
The 1995 rate order also addresses the Company's multi-year
electric rate proceeding, which is discussed below.
On May 22, 1995, the Company filed a Request for Rehearing and
Clarification concerning ten issues addressed in the 1995 rate
order, including reconsideration by the Commission of the 80%/20%
ratepayer/Company sharing of site investigation and remediation
costs in 1995 (See Note 2 of the Notes to the Consolidated
Financial Statements - Contingencies - "Environmental issues"),
and reserving the right to file requests for rehearing or
clarification within 30 days of issuance of the full opinion.
Subsequently, the PSC notified the Company that the statute of
limitations for filing petitions for rehearing or clarification
of the Commission's determination will be deemed to run from the
date of issuance of the full opinion. Therefore, the PSC
informed the Company, no responses to the Company's petition are
warranted at this time.
MULTI-YEAR ELECTRIC RATE PROCEEDING
With respect to the Proceeding, the PSC's 1995 rate order
directed the Company and other parties to address several key
issues in considering any long-range rate plan proposals. These
were to include improving the Company's competitive position,
without anti-competitive effects, by addressing uneconomic
utility generation and the high price of many UG contracts;
considering elimination of the fuel adjustment clause and certain
other billing mechanisms; addressing property tax issues with
local authorities; improving operational efficiency; and
identifying governmental mandates that are no longer warranted in
a competitive environment without a deterioration in providing
safe and adequate service to customers. The PSC advised that any
multi-year plan should help insure that the Company has an
investment-grade bond rating, guarantee service quality is
maintained in light of cost containment efforts, and include
protection for low-income customers. Finally, the plan should
propose changes in the regulatory approach for the Company which
support fair competition in the electric generation market
consistent with the PSC's determination in its generic
"Competitive Opportunities" case.
Following the PSC's directives, the parties engaged in a
collaborative process in which the Company has made a series of
presentations to the parties describing its views of the
transition to competition and the options it presents the
Company.
On October 6, 1995, the Company filed a proposal, called
PowerChoice, with the PSC which is the culmination of these
activities. The PowerChoice proposal provides for a corporate
restructuring designed to create an open, competitive electricity
market, deregulate electricity generation in the Company's
service area, allow all customers, by the year 2000, to choose
their electricity supplier and freeze or reduce electricity
prices over the next five years. The restructuring would retain
the Company's power plants and UG contracts in the generating
company, with the remaining business being separated into a
holding company with regulated subsidiaries that would transmit
and distribute electricity and natural gas and supply energy
services to core customers. This holding company would also have
unregulated subsidiaries that will engage in marketing, brokering
and service activities.
The PowerChoice proposal, which is offered as an integrated
package and not piecemeal, although the details are subject to
compromise, includes these key provisions:
* Creation of a competitive wholesale electricity market and
direct access by retail customers. To give customers their
choice of power suppliers and pricing terms, the Company
will open its system to competitive power generators
beginning in 1997, with full implementation targeted for
2000. The timing of full implementation is dependent upon
resolution of technical and administrative issues. The
restructuring envisions formation of a competitive
wholesale power pool operating at least in the Company's
service area under the supervision of the FERC and is
consistent with proposals announced October 5, 1995 by the
Energy Association of New York. The Company would give its
customers, phased in over the years 1997-2000 and beginning
with its largest customers, full direct access to
alternative suppliers of electricity with the Company
delivering that power over its transmission and
distribution system.
* Separation of the Company's power generation business. The
Company proposes that one company would own and operate its
power plants, including its nuclear facilities and
unregulated generator contracts. A separate holding
company (distribution company) would own and operate the
regulated, customer-focused business of transmitting and
distributing electricity and gas within its service area.
Both companies would be designed to treat bondholders and
other security holders in a fair and equitable fashion.
Any release of collateral under the Company's mortgage
indenture would involve the substitution of other
collateral of equivalent value, including bonds of the
Company. The Company believes the New York Power Authority
(NYPA) can be helpful in this process, possibly through the
purchase or refinancing of the Company's nuclear plants.
As an interim step, the Company is reorganizing its
business units to create a Generation Group, which will
include all of its power plants as well as unregulated
generator contracts; an Energy Distribution Group, which
will include both electricity and natural gas customer
service functions; and a separate group for existing and
new business ventures.
* Relief from overpriced unregulated generator contracts that
were mandated by public policy, along with equitable write-
downs of above-market Company assets. State and federal
policy required the Company to enter into contracts to buy
power from more than 150 unregulated generators at above-
market prices, even when the power isn't needed. The
Company's payments to UGs have increased from less than
$200 million in 1990 to more than $1 billion in 1995, and
will continue to grow in the future as contract prices
increase. To create an open and competitive market and
achieve a price freeze, the Company has offered to
negotiate new contracts with UGs.
If negotiations fail, the Company proposes to take
possession of these projects and compensate their owners
through the Company's power of eminent domain. The Company
would then resell the projects, allowing the projects to
sell electricity into the competitive pool at market
prices. Some of the costs related to the Company and
unregulated generators that would be "stranded" or
unrecoverable in a competitive market would be written off
(further discussed below). The remaining stranded costs
would be recovered through a contract with the distribution
company which, in turn, would recover these costs through a
non-bypassable fee tied to distribution services.
* A price freeze or cut for all the Company's electric
customers. If the proposal is agreed to by all necessary
parties, the prices paid by residential and commercial
customers could be frozen for five years. Prices for
industrial customers, who now subsidize other customers,
would be reduced. If the proposal is not approved, the
continued growth in payments to unregulated generators and
taxes will exceed the Company's internal cost-cutting
efforts, resulting in substantial price increases. If
substantial progress on the proposal is not made by the end
of the year, the Company will be required to seek emergency
rate relief no later than early 1996. With the long lead
time associated with a traditional rate filing, the Company
will file for a conventional price increase of more than
10% in early February 1996, to be effective on January 1,
1997. This filing will preserve the Company's right to
traditional cost-based rates in the event that an
acceptable restructuring proposal cannot be achieved
through negotiation.
The Company believes the PowerChoice proposal is the best course
for dealing with the problems it is encountering as the electric
energy industry is deregulated. Traditional, cost-based rate
making would otherwise require the Company to seek in excess of a
5% increase in electric revenues for 1996, driven largely by
increases in UG payments, taxes and lower sales. The Company
currently forecasts about a 3.9% decline in public sales from
levels assumed in setting 1995 rates. Price increases of this
magnitude would further erode the Company's ability to be
competitive in open energy markets and continue to apply certain
fundamental accounting standards applicable to regulated
businesses, as discussed below. In the context of the
PowerChoice proposal negotiations and other initiatives being
pursued by the Company, reduction or cessation of common and
preferred stock dividends and the ultimate possibility of
restructuring under Chapter 11 of the U.S. Bankruptcy Code cannot
be ruled out.
The price freeze and restructuring of the Company's markets and
business envisioned in the PowerChoice proposal are contingent on
critical cost reductions, which depend in turn on the willingness
of the UGs and the Company to absorb the losses required to make
substantial reductions in the Company's embedded cost structure
(i.e., sunk costs of the Company's generation and future
obligations for UG contracts). The Company's PowerChoice
proposal would reduce its embedded cost structure through
substantial write-offs if, and only if, the UGs agree to cost
reductions that are proportional to their relative responsibility
for strandable costs (i.e., those embedded costs that would not
be recovered at competitive market prices). The Company proposes
reduction in its fixed costs of service be made by mutual
contribution of the Company's shareholders and UGs that are in
the same proportion as the contribution of each to the problem of
strandable costs, which the Company calculates to be $4 of UG
strandable cost for every $1 of Company strandable cost. The
Company has proposed that the remaining strandable costs be
recoverable by the Company and the UGs through surcharges on
rates for remaining monopoly (i.e., distribution and
transmission) services. Recovery of remaining strandable costs
by the new owner of the Company's generation facilities is
intended to be structured so as not to impede each unit from
being an efficient participant in the competitive generation
market.
The Company is pursuing other courses of action to support the
objectives of restructuring. Certain UG projects have received
very large front-end-loaded payments in order to obtain
financing. Those projects are obligated to repay those advance
payments after their financing is paid off. The Company seeks to
ensure as part of its PowerChoice proposal that its ratepayers
are repaid these funds by requiring the project owners to provide
the Company commercially acceptable, firm security for these
obligations (estimated to be worth $1.3 billion in today's
dollars).
The Company believes there are other opportunities to reduce the
embedded costs of the Company to the benefit of customers. The
Company pays twice the national average in taxes. Reduction of
the state gross receipts tax, which is a tax on revenues rather
than income, would help facilitate a freeze in prices. Other
state involvement, such as through NYPA's participation in the
refinancing or ownership of the Company's nuclear plants, would
also support the objectives of the restructuring proposal.
The successor to all the Company's assets and businesses other
than generation would be an unregulated holding company which
would provide fully regulated transmission, distribution and gas
services through one subsidiary and through a second subsidiary
would provide competitive unregulated services, such as energy
marketing and other services. The Company believes the regulated
subsidiary would continue to account for its assets and costs,
based on ratemaking conventions as approved by the PSC and FERC,
in accordance with SFAS No. 71.
Effective for the year commencing January 1, 1996, this
accounting standard, under which the Company reports its
financial condition and results of operations, will be amended by
Statement of Financial Accounting Standards No. 121, "Accounting
for the Impairment of Long-Lived Assets and Long-Lived Assets to
be Disposed Of" (SFAS No. 121). While the Company has not
completed analyzing all the changes which may be occasioned by
SFAS No. 121, these changes, more likely than not may have a
significant adverse effect on the Company's financial statements,
in particular with regard to the continued recording of
regulatory assets on the Company's balance sheet with respect to
the Company's electric business. The Company anticipates having
electric regulatory assets of approximately $1.3 billion and
electric regulatory liabilities of approximately $.4 billion as
of January 1, 1996, for a net amount of approximately $.9 billion
that would be at risk if accounting under SFAS No. 71 were to be
discontinued for the Company's entire electric business. Of this
amount, approximately $.3 billion relates to the generation
portion of its electric business. No impact on the Company's gas
business is anticipated. The essence of the change in accounting
standards is that the Company will need to conclude that the
regulatory assets in question continue to be probable of
recovery. The current accounting standard requires a conclusion
only that such assets are not probable of loss. Current
conditions in the generation portion of the Company's business,
relating to market costs of power, erosion of margins because of
inadequate rate relief and the incursion of unregulated
generators on the Company's customer base, when taken together
with the Company's PowerChoice proposal described above, may call
into question the continued recording of such assets and may
require material downward adjustments in those accounts related
to the generation portion of the Company's business. Lack of
progress in adopting and implementing the PowerChoice proposal
may also raise questions about the continued applicability of
SFAS No. 71 for the entire electric business. Any such
adjustments would result in a reduction of retained earnings,
which had a balance at September 30, 1995 of approximately $600
million. Various tests under applicable law and corporate
instruments, including those with respect to issuance of debt and
equity securities, payment of preferred and common dividends and
certain types of transfers of assets could be adversely
implicated by any such writedowns. The Company cannot currently
predict whether, when, or to what extent the new accounting
standard will require such adjustments, or the impact on its
financial flexibility and operations.
Reactions to the Company's PowerChoice proposal have generally
included praise and skepticism. While industrial customers
viewed the plan as progressive, some consumer groups fear
residential customers would experience higher electric costs.
Most constituencies have agreed that the proposal is creative and
places the Company among the first in the nation to advocate full
competition for electric supply. The PSC has stated that it will
expedite its review of the proposal. See "Financing Plans and
Financial Position" for reactions of rating agencies and others
to the proposal.
On October 25, 1995, the PSC staff filed a proposal in Phase II
of its competitive opportunities proceeding to restructure New
York State's electric industry. Under the PSC staff's proposal,
which is similar to the Company's PowerChoice proposal,
utilities, unregulated generators and ratepayers would share the
responsibility for reducing the current high electric system
costs. The PSC staff proposed that electric utilities would
absorb a portion of their current generation investments that
might become "stranded" or unrecoverable in a competitive market,
and unregulated generators would need to cooperatively
restructure their high-cost power contracts with utilities.
Furthermore, the PSC staff stated that "absent such cooperation,
the PSC should consider exercising its regulatory authority by:
1) curtailing purchases from nonutility generators where fixed
price contracts cause customers to subsidize those generators;
2) vigorously enforcing state qualifying factor standards; 3)
intervening in proceedings before the FERC concerning compliance
with federal qualifying factor standards; 4) requiring firm
security for payback accounts used by non-utility generators to
repay excess payments to utilities; and/or 5) proposing
legislation that would limit prices charged by UGs."
In addition, the PSC staff's proposal would allow customers to
choose among competing energy suppliers, beginning the transition
to a competitive retail market by early 1998. The proposal
stated that a key element of their model for wholesale and retail
competition was the separation of most generating operations from
transmission and distribution services. However, it recommended
that the electric delivery system, which is comprised of
substations, power lines and a central power pool, would continue
to be operated by regulated utilities. If the PSC staff's
proposal is adopted, utilities would be required to file
restructuring plans with the PSC in 1996 if they have not already
done so.
MULTI-YEAR GAS RATE PROPOSAL
The Company also filed a proposal to adopt a "performance-based
regulation" mechanism, including a gas cost incentive mechanism
for its gas operations. The proposal provides for a complete
unbundling of the Company's sales service, allowing customers to
choose alternative gas suppliers. Increases for gas distribution
services would be subject to a price index through the year 2000.
The price index, which is based on inflation associated with gas
service-related costs, would be applied to existing 1995 prices
after consideration of the service restructuring. A gas cost
incentive mechanism is also being proposed, along with
discontinuation of the weather normalization clause. Flexibility
in pursuing unregulated opportunities related to the gas business
is also being sought. The Company expects to file a formal rate
request in November 1995 for new rates to be effective in the
fourth quarter of 1996 as an alternative in the event
negotiations on the proposal are not fruitful. The filing would
comprise a one-year traditionally-determined rate adjustment,
followed by the implementation of the index proposal.
COMMON STOCK DIVIDEND
(See Form 10-K for fiscal year ended December 31, 1994, Item 7.
Management's Discussion and Analysis of Financial Condition and
Results of Operations - "Changing Competitive Environment.")
On October 26, 1995, the Board of Directors authorized a common
stock dividend of 28 cents per share for the fourth quarter of
1995, payable on November 30, 1995 to shareholders of record on
November 6, 1995. In making future dividend decisions, the
Company will need to evaluate, along with standard business
considerations, the progress on renegotiating contracts with
unregulated generators within the context of its PowerChoice
proposal, the degree of competitive and political pressure on its
prices, and other strategic considerations.
FINANCING PLANS AND FINANCIAL POSITION
(See "Multi-Year Electric Rate Proceeding" and "Common Stock
Dividend.")
In response to the PowerChoice proposal, Standard & Poors (S&P)
lowered its ratings on the Company's senior secured debt to BB
from BBB-, senior unsecured debt to B+ from BB+, preferred stock
to B from BB+, and commercial paper to B from A-3. All such
ratings are "below investment grade." In addition, S&P's ratings
of the Company's securities are on "CreditWatch" with negative
implications. The downgrade of the Company's security ratings
reflects S&P's concern regarding the uncertainty and potential
negative impact of the PowerChoice proposal on the Company's
"already weak financial profile." S&P believes the Company may
need to reduce or eliminate common dividends since discretionary
cash flow is currently negative and declining. Further, S&P
believes the ultimate possibility of restructuring under Chapter
11 of the U.S. Bankruptcy Code cannot be ruled out, based on the
Company's statements in that regard.
Moody's Investors Service (Moody's) lowered its ratings of the
Company's senior secured debt to Ba1 from Baa3; senior unsecured
debt to Ba2 from Ba1; its preferred stock to ba3 from ba1; and
its short-term rating for commercial paper to Not Prime from
Prime -3. Moody's is also maintaining these ratings under review
for possible further downgrade. Moody's believes that the
necessity for agreement by third parties significantly diminishes
the likelihood that the PowerChoice proposal will survive intact
and increases uncertainty about the Company's future over the
interim period, as related negotiations proceed. Moody's fears
the Company's apparent willingness to consider restructuring
under Chapter 11 of the U.S. Bankruptcy Code raises serious
doubts as to the Company's financial stability. Moody's continued
review will consider responses to the proposal, the likelihood of
the proposal being adopted and the effect any interim or final
agreement may have on bondholders.
Fitch Investors Services, Inc. (Fitch) also downgraded the
Company's first mortgage bonds and secured pollution control
bonds rating from BBB to BB and its preferred stock rating from
BBB- to B+ and noted a declining credit trend. Fitch's concerns
are similar to those expressed by S&P and Moody's.
While these rating agencies have cited the increased risk and
uncertainty and the potential for bankruptcy as reasons for
downgrade, the Company believes these reasons likewise increase
the risk to third party unregulated generators and their security
ratings. The Company believes its proposal is in the best
interests of its customers, bondholders and stockholders. The
alternative is to allow the Company's financial and competitive
position to continue to erode.
Cash flows to meet the Company's requirements for the first nine
months of 1995 and 1994 are reported in the Consolidated
Statements of Cash Flows on Page 6. The Company received
approximately $207 million in January 1995 related to the sale of
the Company's subsidiary, HYDRA-CO Enterprises, Inc. (HYDRA-CO),
which was used to repay short-term debt.
Ordinarily, construction-related short-term borrowings are
refunded with long-term securities on a periodic basis. This
approach generally results in the Company showing a working
capital deficit. Working capital deficits may also be
temporarily created as a result of the seasonal nature of the
Company's operations as well as timing differences between the
collection of customer receivables and the payment of fuel and
purchased power costs. Recently the Company has experienced a
deterioration in its collections as compared to prior years'
experience 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.
The Company's capital structure continues to be weak, and the
Company's ability to issue more common stock to improve its
capital structure is essentially precluded by the uncertainties
that have depressed its stock price. The Company would not
pursue a new issue offering unless the common stock price was
closer to book value. The Company originally projected its 1995
external financing would consist of approximately $400 to $600
million of debt securities, including $275 million of 7 3/4%
series First Mortgage Bonds due May 2006 issued during May 1995.
However, due in part to the anticipated sale of an additional $50
million of customer receivables before the end of 1995 (see Note
2 of Notes to the Consolidated Financial Statements -
"Commitments and Contingencies - Sale of Customer Receivables"),
the Company is now projecting that its external financing needs
will be satisfied by bank term loans.
Due to the rapid response to the PowerChoice proposal from rating
agencies as described previously, the prices of the Company's
common stock, preferred stock and bonds declined sharply. The
reduction to below investment grade ratings on the Company's
bonds can be expected to make it more difficult and expensive for
the Company to finance in the manner it has used in the past.
Consequently, the Company plans to borrow under its bank
revolving credit and term loan agreements instead of issuing
first mortgage bonds to satisfy its financing needs in the near
term.
The availability of cash provided by operations to fund the
Company's anticipated construction program for the years 1996-
1999 is substantially dependent upon the outcome of the multi-
year electric rate proceeding. The Company believes that it will
spend as much as $40 million less than its original estimate of
$380 million for its 1995 construction program. For the nine
months ended September 30, 1995, the Company had incurred
approximately $254.0 million for construction additions,
including overheads capitalized, nuclear fuel and allowance for
funds used during construction. External financing plans are
subject to periodic revision as underlying assumptions are
changed to reflect developments, market conditions and, most
importantly, the Company's rate proceedings. The ultimate level
of financing during this four-year period will reflect, among
other things, the outcome of the PowerChoice proposal, levels of
dividend payments, the Company's competitive positioning and the
extent to which competition penetrates the Company's markets,
uncertain energy demand due to the weather and economic
conditions and capital expenditures relating to distribution and
transmission load reliability projects, as well as continued
expansion of the gas business. The stagnant economy in the
Company's service territory and the associated decline in kwh
sales and resulting revenues is significantly increasing the
uncertainty of its future financing program.
With respect to the Company's external financing needs during the
period 1996 through 1999, which are dependent on, among other
things, the outcome of the PowerChoice proposal, current sales
trends and the extent to which competition is permitted to enter
into the Company's electric sales market, the Company is
exploring financing options with its major banks that would be
designed to insure to the extent possible adequate financial
resources to satisfy its financing needs over this time period.
The Company will also attempt to negotiate provisions in its bank
agreements that would permit the restructuring contemplated by
the PowerChoice proposal in the event that it is approved.
The Company believes that bank credit and other sources of
financing should be sufficient to satisfy the Company's external
financing needs, during the period 1996 through 1999, depending
on the outcome of the currently ongoing negotiations with its
banks. As of November 1, 1995, the Company could issue an
additional $1,997 million aggregate principal amount of First
Mortgage Bonds under the applicable tests set forth in the
Company's mortgage trust indenture. This includes approximately
$1,311 million from retired bonds without regard to an interest
coverage test and approximately $686 million supported by
additional property currently certified and available, assuming
an 10% interest rate.
The Company also has $200 million of Preference Stock authorized
for sale. Under its Charter, the Company is precluded from
issuing preferred stock at November 1, 1995, due to insufficient
earnings coverage ratios. The Company's charter also limits the
amount of unsecured indebtedness that may be incurred by the
Company to 10% of consolidated capitalization plus $50 million.
At September 30, 1995, this charter restriction is $690 million
and the Company's unsecured debt outstanding is $126 million.
RESULTS OF OPERATIONS
The following discussion presents the material changes in results
of operations for the three months and nine months ended
September 30, 1995 in comparison to the same periods in 1994.
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 nine 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 September 30, 1995 versus Three Months Ended
September 30, 1994
- ---------------
Earnings for the third quarter were $37.3 million or 26 cents per
share, as compared with $39.3 million or 27 cents per share in
1994. Earnings for the third quarter of 1995 were impacted by
lower sales of both electricity and natural gas due in part to
the continuing weak economic conditions in upstate New York. As
of January 1995, NERAM was discontinued (See "1995 Rate Order").
Third quarter 1994 earnings included $13.5 million of electric
margin recorded under this mechanism.
ELECTRIC REVENUES
As shown in the table below, electric revenues, including
revenues recorded to reflect the 1995 rate order retroactive to
January 1, 1995, decreased $31.7 million or 3.7% from 1994. This
decrease resulted primarily from lower fuel adjustment clause
(FAC) revenues of $43.9 million, which reflects a decrease in
energy costs as compared to 1994. Unbilled revenues (which are
non-cash revenues) of $11.0 million were recorded in 1995. Sales
to other electric systems reflect reduced demand associated with
the continued stagnant economy and more competitive pricing due
to excess supply.
Increase in base rates $ 28.3 million
Amortization of unbilled revenues 11.0
Changes in volume and mix of sales to
ultimate consumers 5.0
Miscellaneous operating revenues (7.2)
Other electric systems (11.4)
NERAM revenues (13.5)
Fuel adjustment clause revenues (43.9)
------
$(31.7) million
=======
ELECTRIC SALES
Electric kwh sales to ultimate consumers were approximately 8.4
billion in the third quarters of both 1995 and 1994. After
adjusting for the effects of weather, sales to ultimate consumers
decreased 1.6%. Sales for resale decreased .6 billion kwhs
(34.1%) resulting in a net decrease in total electric kwh sales
of .6 billion (6.0%). 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 decreased $10.1 million
or 3.0%. This decrease is the result of a $15.8 million (5.8%)
decrease in purchased power costs, exclusive of a $25.7 million
decrease in costs deferred and recovered through the operation of
the FAC, which is primarily the result of lower payments being
made to unregulated generators, since the unregulated generators
with hydroelectric plants were limited by the amount of power
they could produce due to a low water supply. This was partially
offset by a $3.2 million (6.6%) increase in generation costs
coupled with a $28.2 million increase in costs deferred and
recovered through the operation of the FAC.
GAS REVENUES
Gas revenues increased $.1 million or .2% in the third quarter of
1995 from the comparable period in 1994 as set forth in the table
below:
Transportation of customer-owned gas $ 2.6 million
Spot market revenues .3
Purchased gas adjustment clause revenues (1.2)
Changes in volume and mix of sales to
ultimate consumers (1.6)
--------
$ .1 million
=======
GAS SALES
Gas sales to ultimate consumers decreased .9 million dekatherms
(dth) or 15.1% from 1994. After adjusting for the effects of
weather, sales to ultimate consumers decreased 9.8%.
Transportation of customer-owned gas increased 15.6 million dth
(82.0%) and was primarily caused by Sithe Independence Power
Partners, Inc. gas-fired generating project coming on-line in the
Company's service territory in 1995. In addition, spot market
sales (sales for resale) increased .1 million dth (111.4%). Spot
market sales are generally from higher priced gas available to
the Company and therefore yield margins that are substantially
lower than traditional sales to ultimate customers.
The total cost of gas included in expense decreased 16.2% as a
result of a 15.0% decrease in the average cost per dth purchased
($6.0 million) and a .6 million decrease in dth purchased and
withdrawn from storage for ultimate consumer sales ($3.8
million), offset by a $6.5 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, decreased to $2.91 in
the third quarter of 1995 from $3.19 in the same period in 1994.
Other operation expense decreased $26.2 million as anticipated
under the Company's cost reduction effort.
Other items (net) decreased by $4.6 million in the third quarter
of 1995 from the comparable period in 1994 primarily as a result
of lower earnings of subsidiary companies of approximately $3.9
million.
Nine Months Ended September 30, 1995 versus Nine Months Ended
September 30, 1994
- ------------------
Earnings for the first nine months were $190.2 million or $1.32
per share, including the gain of approximately $9 million on the
sale of HYDRA-CO, as compared with $231.2 million or $1.62 per
share in 1994. Earnings were also impacted by lower sales
quantities of electricity and natural gas due in part to weather-
related reduced demand and continuing weak economic conditions in
upstate New York. As of January 1995, NERAM was discontinued
(See "1995 Rate Order"). Earnings for the first nine months of
1994 included $52.7 million of electric margin recorded under
this mechanism.
ELECTRIC REVENUES
As shown in the table below, electric revenues, including amounts
recorded to reflect the 1995 rate order retroactive to January 1,
1995, decreased $118.8 million or 4.5% from 1994. Unbilled
revenues (which are non-cash) of $60.8 million were recorded in
1995, including $6.2 million of retroactive amounts mentioned
above. The increase in demand side management (DSM) revenues
relates to a one-time, non-cash adjustment of prior years' DSM
incentives. $9.4 million was recorded in 1995 in accordance with
the Unit 1 operating incentive sharing mechanism. Revenues of
$8.4 million, which includes $7.7 million related to electric
were recorded in the first nine months of 1994 in accordance with
the MERIT allowance for 1993. No revenues were recorded related
to MERIT in the first nine months of 1995. Sales to other
electric systems and sales to ultimate consumers reflect weather-
related reduced demand and the continued stagnant economy, as
well as more competitive pricing caused by excess supply. The
decrease in FAC revenues in the amount of $46.6 million reflects
a decrease in fuel costs as compared to 1994.
Amortization of unbilled revenues $ 60.8 million
Increase in base rates 41.3
Unit 1 incentive surcharge 9.4
DSM revenues 7.7
Miscellaneous operating revenues (4.7)
MERIT revenues (7.7)
Fuel adjustment clause revenues (46.6)
NERAM revenues (52.7)
Changes in volume and mix of sales to
ultimate consumers (61.5)
Sales to other electric systems (64.8)
-------
$(118.8) million
=======
ELECTRIC SALES
As detailed in the table below, electric kwh sales to ultimate
consumers were approximately 25.2 billion in 1995, a 2.7%
decrease from the same period in 1994 primarily as a result of
weather-related reduced demand and sluggish economic conditions.
After adjusting for the effects of weather, sales to ultimate
consumers would have decreased 1.7%. Sales to other electric
systems decreased 2,847 million kwhs (49.0%), resulting in a net
decrease in total electric kwh sales of 3,538 million (11.2%).
NINE MONTHS ENDED SEPTEMBER 30,
ELECTRIC REVENUES (Thousands) SALES (GwHrs)
---------------------------------- --------------------------
% %
1995 1994 Change 1995 1994 Change
Residential $ 926,889 $ 953,803 ( 2.8) 7,719 8,086 ( 4.5)
Commercial 945,464 972,878 ( 2.8) 8,831 9,055 ( 2.5)
Industrial 401,895 433,957 ( 7.4) 5,375 5,538 ( 2.9)
Industrial - Special 42,452 37,901 12.0 3,112 3,048 2.1
Municipal 36,432 37,005 (1.5) 151 152 ( 0.7)
--------- ---------- ------ ------ ------ ------
Total to Ultimate
Consumers 2,353,132 2,435,544 ( 3.4) 25,188 25,879 ( 2.7)
Other Electric Systems 65,585 130,399 (49.7) 2,960 5,807 (49.0)
Miscellaneous 104,071 75,632 37.6 - - -
---------- --------- ------ ----- ------- ------
TOTAL $2,522,788 $2,641,575 ( 4.5) 28,148 31,686 (11.2)
========== ========= ====== ====== ====== ======
/TABLE
Electric fuel and purchased power costs decreased $12.3 million
or 1.2%. This decrease is the result of a decrease in fuel
costs of $25.9 million (15.6%), offset by a $17.7 million
increase in costs deferred and recovered through the operation of
the FAC, and a $.3 million decrease in purchased power costs and
a $3.8 million decrease in costs deferred and recovered through
the operation of the FAC. The decrease in fuel costs reflects a
13.8% decrease in Company generation due to greater unregulated
generator purchase requirements and reduced demand, which reduced
the need to operate the fossil plants, even after taking into
account the 1995 Unit 1 and Unit 2 refueling and maintenance
outages, referred to below. Payments to unregulated generators
increased $11.0 million or 1.5% during this period.
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.
GAS REVENUES
Gas revenues decreased $64.4 million or 13.1% in 1995 from the
comparable period in 1994 as set forth in the table below:
Transportation of customer-owned gas $ 8.1 million
Spot market revenues (3.2)
Purchased gas adjustment clause revenues (17.2)
Changes in volume and mix of sales to
ultimate consumers (52.1)
--------
$(64.4) million
========
GAS SALES
Due to weather-related reduced demand in 1995, gas sales to
ultimate consumers decreased 9.8 million dth or 14.3% from 1994.
After adjusting for the effects of weather, sales to ultimate
consumers decreased 1.2%. Transportation of customer-owned gas
increased 46.3 million dth (75.8%) and was primarily caused by
Sithe Independence Power Partners, Inc. gas-fired generating
project coming on-line in the Company's service territory. Spot
market sales (sales for resale), which are generally from the
higher priced gas available to the Company and therefore yield
margins that are substantially lower than traditional sales to
ultimate consumers, also decreased.
NINE MONTHS ENDED SEPTEMBER 30,
GAS REVENUES (Thousands) SALES (Thousands of Dekatherms)
------------------------------- -------------------------------
% %
1995 1994 Change 1995 1994 Change
Residential $275,513 $319,995 (13.9) 39,030 45,369 (14.0)
Commercial 105,086 127,012 (17.3) 17,474 20,378 (14.3)
Industrial 8,224 11,811 (30.4) 1,925 2,454 (21.6)
-------- -------- --------- ------- ------- ------
Total to Ultimate
Consumers 388,823 458,818 (15.3) 58,429 68,201 (14.3)
Other Gas Systems 705 840 (16.1) 150 174 (13.8)
Transportation of
Customer-Owned Gas 34,993 26,860 30.3 107,395 61,105 75.8
Spot Market Sales 1,038 4,204 (75.3) 551 1,481 (62.8)
Miscellaneous 2,513 1,771 41.9 - - -
---------- ------- --------- ------- ------- ------
TOTAL $428,072 $492,493 (13.1) 166,525 130,961 27.2
========= ======== ========= ======= ======= ======
The total cost of gas included in expense decreased 23.0%. This
was the result of an 8.9 million decrease in dth purchased and
withdrawn from storage for ultimate consumer sales ($32.7
million) and a .9 million decrease in dth purchased for spot
market sales, coupled with a 13.3% decrease in the average cost
per dth purchased ($27.8 million), partially offset by a $3.5
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, decreased to $3.53 in the first
nine months of 1995 from $3.91 in the same period in 1994.
Other operation expense decreased $76.6 million, as anticipated
under the Company's cost reduction program.
Other items (net) increased by $7.5 million in the first nine
months of 1995 from the comparable period in 1994, primarily due
to the sale of HYDRA-CO ($21.6 million). The after-tax gain on
the sale of HYDRA-CO was approximately $8.9 million.
Federal income taxes (net) decreased by approximately $24.5
million primarily due to a decrease in pre-tax income, partially
offset by the increase related to the sale of HYDRA-CO ($12.7
million).
Other taxes increased by approximately $11.2 million primarily
due to further increases of real estate taxes of approximately
$18.2 million (approximately 10.0%), partially offset by
approximately $5.9 million in payroll taxes due to the decrease
in employees.
As evidenced by the results of the first nine months of 1995, the
combination of the trend of rising payments to UGs, the
elimination of NERAM and further weakening in sales, as well as
approximately $23 million of negotiated customer discounts in
excess of the approximately $42 million reflected in rates in
1995, has affected, and will continue to negatively affect, the
Company's revenues and earnings during the fourth quarter of
1995. The Company expects the trend of weak sales to continue in
the near term, particularly in light of the softening of economic
expectations in the Company's service territory. With respect to
the NERAM, the Company recorded $48.5 million, or 22 cents per
share in the fourth quarter of 1994, which is no longer in place.
In addition, the Company experienced extraordinary storm damage
in July 1995, with total restoration costs of approximately $21
million, which includes a capitalized amount of approximately
$4.4 million relating to reconstruction of facilities destroyed
by the storm. The Company is planning to file a petition with
the PSC before the end of 1995, which will request deferral
accounting treatment, with future recovery, of the incremental,
non-capital costs associated with the storm of approximately
$11.4 million, or 5 cents per share. These types of
extraordinary costs have previously been recoverable in rates.
Depending on the regulatory treatment allowed, these storm costs
may put added pressure on the Company's earnings for 1995.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
PART II
Item 1. Legal Proceedings.
1. On June 22, 1993, the Company and twenty other industrial
entities and the owner/operator of the Pfohl Brothers
Landfill near Buffalo, New York, were sued in New York
Supreme Court, Erie County, by a group of residents living
in the vicinity of the landfill seeking compensation and
damages for economic loss and property damages claimed to
have resulted from contamination emanating from the
landfill. In addition, since January 18, 1995, the Company
has been named as a defendant in a series of toxic tort
actions filed in federal and state courts in the Buffalo
area. Additional suits are expected to be filed until the
number of plaintiffs totals around 200. The suits allege
exposure on the part of the plaintiffs to toxic chemicals
emanating from the Pfohl Brothers Landfill, resulting in
the alleged causation of cancer in each of the plaintiffs.
The plaintiffs seek compensatory and punitive damages. The
Company has filed Answers responding to the claims put
forth in the existing suits, denying liability for any of
the claimed damages. The Company plans to participate in
joint defense efforts among the defendants during the
initial stages of these suits, and intends to vigorously
defend against any claim of a causal relationship between
the Company's activities. The Company is unable to predict
the ultimate outcome of these proceedings.
Regarding the Company's alleged involvement with the
Landfill itself, notification was received from the New
York State Department of Environmental Conservation in 1986
of the Company's status as a potentially responsible party
(PRP) in connection with the contamination of this
landfill. Until recently the Company has not taken an
active role in the remediation process because of the
existence of only minimal evidence that hazardous
substances generated by the Company were disposed at the
Pfohl Brothers Landfill. It has been alleged, however,
that another defendant (Downing Container Division of Waste
Mgt. of N.Y.) transported waste materials to the landfill
from the Company's Dewey Avenue Service Center during the
1960's. Therefore, in July 1995, the Company elected to
become a member of the Steering Committee consisting of
identified PRPs, and thereby participate in the development
of an appropriate remedial action for the site and working
to achieve an equitable allocation of liability among
responsible parties. To date, no governmental action has
been taken against the Company as a PRP. The Company is
investigating its alleged connection to the landfill to
determine an appropriate level of participation in the
ongoing voluntary remedial program conducted by the
Steering Committee.
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 Nine
Months Ended September 30, 1995 and 1994.
Exhibit 12 - Statement Showing Computations of Ratio of
Earnings to Fixed Charges, Ratio of Earnings to Fixed
Charges without AFC and Ratio of Earnings to Fixed Charges
and Preferred Stock Dividends for the Twelve Months Ended
September 30, 1995.
Exhibit 15 - Accountants' Acknowledgement Letter.
Exhibit 27 - Financial Data Schedule.
(b) Report on Form 8-K:
Form 8-K Reporting Date - October 12, 1995.
Items reported - Item 5. Other Events.
Registrant filed information concerning the October 6, 1995
filing with the PSC a proposal for a corporate
restructuring designed to open electricity markets to
competition and deregulate electricity generators in the
Company's service territory. A summary of reactions by
securities rating agencies and others was provided. Also
included was information on the filing of the Company's gas
rate proposal.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
NIAGARA MOHAWK POWER CORPORATION
(Registrant)
Date: November 14, 1995 By /s/ Steven W. Tasker
Steven W. Tasker
Vice President-Controller and
Principal Accounting Officer,
in his respective capacities
as such
EXHIBIT 11
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
Computation of the Average Number of Shares of Common Stock Outstanding
For the Three Months and Nine Months Ended September 30, 1995 and 1994
(4)
Average Number
of Shares
Outstanding as
Shown on
Consolidated
Statement
(1) (2) (3) of Income
Shares of Number of Share (3 divided by
Common Days Days Number of Days
Stock Outstanding (2 X 1) in Period)
--------- ----------- ------- ---------------
FOR THE THREE MONTHS ENDED SEPTEMBER 30:
JULY 1 - SEPTEMBER 30, 1995 144,330,482 92 13,278,404,344 144,330,482
=========== ============== ===========
JULY 1 - SEPTEMBER 30, 1994 143,316,804 92 13,185,145,968
SHARES SOLD AT VARIOUS
TIMES DURING THE PERIOD -
DIVIDEND REINVESTMENT PLAN 279,100 *<F1> 8,525,566
EMPLOYEE SAVINGS FUND PLAN 290,200 *<F1> 11,995,200
----------- --------------
143,886,104 13,205,666,734 143,539,856
=========== ============== ===========
FOR THE NINE MONTHS ENDED SEPTEMBER 30:
JANUARY 1 - SEPTEMBER 30, 1995 144,311,466 273 39,397,030,218
SHARES SOLD AT VARIOUS
TIMES DURING THE PERIOD -
DIVIDEND REINVESTMENT PLAN 19,016 *<F1> 4,620,888
----------- --------------
144,330,482 39,401,651,106 144,328,392
=========== ============== ===========
JANUARY 1 - SEPTEMBER 30, 1994 142,427,057 273 38,882,586,561
SHARES SOLD AT VARIOUS
TIMES DURING THE PERIOD -
DIVIDEND REINVESTMENT PLAN 700,447 *<F1> 76,681,828
EMPLOYEE SAVINGS FUND PLAN 758,600 *<F1> 76,225,500
----------- --------------
143,886,104 39,035,493,889 142,987,157
=========== ============== ===========
NOTE: Earnings per share calculated on both a primary and fully diluted basis are the same due
to the effects of rounding.
<FN>
<F1>* Number of days outstanding not shown as shares represent an accumulation of weekly and
monthly sales throughout the period. Share days for shares sold are based on the total
number of days each share was outstanding during the period.
EXHIBIT 12
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
Statement Showing Computation of Ratio of Earnings to Fixed
Charges, Ratio of Earnings to Fixed Charges without AFC and
Ratio of Earnings to Fixed Charges and Preferred Stock Dividends
for the Twelve Months Ended September 30, 1995 (In thousands of
dollars)
A. Net Income $ 142,740
B. Taxes Based on Income or Profits 99,542
----------
C. Earnings, Before Income Taxes 242,282
D. Fixed Charges (a) 315,336
----------
E. Earnings Before Income Taxes and
Fixed Charges 557,618
F. Allowance for Funds Used During
Construction (AFC) 8,664
----------
G. Earnings Before Income Taxes and
Fixed Charges without AFC $ 548,954
==========
PREFERRED DIVIDEND FACTOR:
H. Preferred Dividend Requirements $ 40,467
----------
I. Ratio of Pre-tax Income to Net
Income (C/A) 1.697
----------
J. Preferred Dividend Factor (HxI) $ 68,672
K. Fixed Charges as Above (D) 315,336
----------
L. Fixed Charges and Preferred Dividends
Combined $ 384,008
==========
M. Ratio of Earnings to Fixed
Charges (E/D) 1.77
==========
N. Ratio of Earnings to Fixed Charges
without AFC (G/D) 1.74
==========
O. Ratio of Earnings to Fixed Charges
and Preferred Dividends Combined (E/L) 1.45
==========
(a) Includes a portion of rentals deemed representative of the
interest factor ($29,122).
/TABLE
EXHIBIT 15
- ----------
November 14, 1995
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 November 14, 1995 (issued pursuant to the
provisions of Statement on Auditing Standards No. 71) in the
Registration Statements on Form S-8 (Nos. 33-36189, 33-42720, 33-
42721, 33-42771 and 33-54829) and in the Prospectus constituting
part of the Registration Statements on Form S-3 (Nos. 33-45898,
33-50703, 33-51073, 33-54827 and 33-55546). We are also aware of
our responsibilities under the Securities Act of 1933.
Yours very truly,
/s/ Price Waterhouse LLP
- ------------------------