<PAGE> 1
February 18, 1994
Securities and Exchange Commission
Washington, D.C. 20549
Gentlemen:
We are filing a copy of the report of Niagara Mohawk Power
Corporation on Form 8-K dated February 18, 1994.
We have also filed this report with the New York State Stock
Exchange.
Very truly yours,
Steven W. Tasker
Vice President -
Controller
SWT:gms
8-K-cvr.edg
<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
DATE OF REPORT - FEBRUARY 18, 1994
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.)
Commission file Number 1-2987
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
<PAGE>
<PAGE> 1
NIAGARA MOHAWK POWER CORPORATION
--------------------------------
ITEM 5. OTHER EVENTS.
Registrant hereby files the following items which will constitute
a portion of its 1993 Annual Report to Stockholders:
PAGE
- Highlights 3
- Market Price of Common Stock and Related Stockholder
Matters 4
- Selected Financial Data for the five years ended
December 31, 1993 6
- Management's Discussion and Analysis of Financial
Condition and Results of Operations 7
- Report of Management 41
- Report of Independent Accountants 43
- Consolidated Statements of Income and Retained
Earnings for each year in the three-year
period ended December 31, 1993 44
- Consolidated Balance Sheets at December 31, 1993 and
1992 45
- Consolidated Statements of Cash Flows for each
year in the three-year period ended December 31,
1993 47
- Notes to Consolidated Financial Statements 48
- Electric and Gas Statistics 95
ITEM 7. FINANCIAL STATEMENT, PROFORMA FINANCIAL INFORMATION AND
EXHIBITS.
Exhibit 11 - Computation of Average Number of
Shares of Common Stock Outstanding 98
Exhibit 12 - Statements Showing Computations
of Certain Financial Ratios 99
Exhibit 24 - Accountant's Consent Letter 100
Exhibit 25 - Form T-1, Statement of Eligibility and
Qualification under the Trust Indenture Act of 1939,
of Marine Midland Bank
- Signature
<PAGE>
<PAGE> 2
%
HIGHLIGHTS 1993 1992 Change
Total operating
revenues $ 3,933,431,000 $ 3,701,527,000 6.3
Income available
for common
stockholders $ 239,974,000 $ 219,920,000 9.1
Earnings per common
share $1.71 $1.61 6.2
Dividends per
common share $0.95 $0.76 25.0
Common shares
outstanding
(average) 140,417,000 136,570,000 2.8
Utility plant
(gross) $10,108,529,000 $ 9,642,262,000 4.8
Construction work
in progress 569,404,000 $ 587,437,000 (3.1)
Gross additions to
utility plant $ 519,612,000 $ 502,244,000 3.5
Public kilowatt-
hour sales 33,750,000,000 33,581,000,000 0.5
Total kilowatt-hour
sales 37,724,000,000 36,611,000,000 3.0
Electric customers
at end of year 1,552,000 1,543,000 0.6
Electric peak load
(kilowatts) 6,191,000* 6,205,000 (0.2)
Natural gas sales
(dekatherms) 83,201,000 79,196,000 5.1
Natural gas
transported
(dekatherms) 67,741,000 65,845,000 2.9
Gas customers at
end of year 501,000 493,000 1.6
Maximum day gas
deliveries 929,285* 905,872 2.6
(dekatherms)
* The Company set an all-time electric peak load on January 19,
<PAGE>
1994, sending out 6,458,000 kilowatts. In addition, a new
maximum day gas delivery of 995,801 dekatherms was set on
January 26, 1994.
<PAGE> 3
NIAGARA MOHAWK POWER CORPORATION
--------------------------------
MARKET PRICE OF COMMON STOCK AND RELATED STOCKHOLDER MATTERS
The Company's common stock and certain of its preferred
series are listed on the New York Stock Exchange. The common
stock is also traded on the Boston, Cincinnati, Midwest, Pacific
and Philadelphia stock exchanges. Common stock options are
traded on the American Stock Exchange. The ticker symbol is
"NMK".
Preferred dividends were paid on March 31, June 30,
September 30 and December 31. Common stock dividends were paid
on February 28, May 31, August 31 and November 30. The Company
presently estimates that none of the 1993 common or preferred
stock dividends will constitute a return of capital and therefore
all of such dividends are subject to Federal tax as ordinary
income.
The table below shows quoted market prices and dividends per
share for the Company's common stock:
Dividends Price Range
Paid
1993 Per Share High Low
1st Quarter $.20 $22 3/8 $18 7/8
2nd Quarter .25 24 1/4 21 5/8
3rd Quarter .25 25 1/4 23 3/4
4th Quarter .25 23 7/8 19 1/4
1992
1st Quarter $.16 $19 $17 5/8
2nd Quarter .20 19 1/4 17 1/2
3rd Quarter .20 20 1/2 18 7/8
4th Quarter .20 19 7/8 18 3/8
OTHER STOCKHOLDER MATTERS: The holders of Common Stock are
entitled to one vote per share and may not cumulate their votes
for the election of Directors. Whenever dividends on Preferred
Stock are in default in an amount equivalent to four full
quarterly dividends and thereafter until all dividends thereon
<PAGE>
are paid or declared and set aside for payment, the holders of
such stock can elect a majority of the Board of Directors.
Whenever dividends on any Preference Stock are in default in an
<PAGE> 4
amount equivalent to six full quarterly dividends and thereafter
until all dividends thereon are paid or declared and set aside
for payment, the holders of such <PAGE> 4
stock can elect two members to the Board of Directors. No
dividends on Preferred Stock are now in arrears and no Preference
Stock is now outstanding. Upon any dissolution, liquidation or
winding up of the Company's business, the holders of Common Stock
are entitled to receive a pro rata share of all of the Company's
assets remaining and available for distribution after the full
amounts to which holders of Preferred and Preference Stock are
entitled have been satisfied.
The indenture securing the Company's mortgage debt provides
that surplus shall be reserved and held unavailable for the
payment of dividends on Common Stock to the extent that
expenditures for maintenance and repairs plus provisions for
depreciation do not exceed 2.25% of depreciable property as
defined therein. Such provisions have never resulted in a
restriction of the Company's surplus.
At year end, about 109,000 stockholders owned common shares
of the Company and about 5,000 held preferred stock. The chart
below summarizes common stockholder ownership by size of holding:
SIZE OF
HOLDING
(SHARES) TOTAL STOCKHOLDERS TOTAL SHARES HELD
1 to 99 43,269 1,401,921
100 to 999 59,329 16,476,333
1,000 or 6,742 124,548,803
more __________________ __________________
109,340 142,427,057
================== ==================
<PAGE>
<PAGE> 5
SELECTED FINANCIAL DATA
As discussed in Management's Discussion and Analysis of Financial
Condition and Results of Operations and Notes to Consolidated
Financial Statements, certain of the following selected financial
data may not be indicative of the Company's future financial
condition or results of operations.
<PAGE>
<TABLE>
<CAPTION>
1993 1992 1991 1990 1989
OPERATIONS: (000's) <C> <C> <C> <C> <C>
<S>
Operating revenues $ 3,933,431 $3,701,527 $3,382,518 $3,154,719 $2,906,043
Net income 271,831 256,432 243,369 82,878 150,783
COMMON STOCK DATA:
Book value per share at $17.25 $16.33 $15.54 $14.37 $14.07
year end
Market price at year 20 1/4 19 1/8 17 7/8 13 1/8 14 3/8
end
Ratio of market price 117.4% 117.1% 115.0% 91.4% 102.2%
to book value at year
end
Dividend yield at year 4.9% 4.2% 3.6% 0.0% 0.0%
end
Earnings per average $ 1.71 $ 1.61 $ 1.49 $ .30 $ .78
common share
Rate of return on 10.2% 10.1% 10.0% 2.1% 5.6%
common equity
Dividends paid per $ .95 $ .76 $ .32 $ .00 $ .60
common share
Dividend payout ratio 55.6% 47.2% 21.5% 0.0% 76.9%
CAPITALIZATION:
(000's)
Common equity $ 2,456,465 $2,240,441 $2,115,542 $1,955,118 $1,914,531
<PAGE>
Non-redeemable 290,000 290,000 290,000 290,000 290,000
preferred stock
Redeemable preferred 123,200 170,400 212,600 241,550 267,530
stock
Long-term debt 3,258,612 3,491,059 3,325,028 3,313,286 3,249,328
Total 6,128,277 6,191,900 5,943,170 5,799,954 5,721,389
First mortgage bonds 190,000 - 100,000 40,000 50,000
maturing within one
year
Total $ 6,318,277 $6,191,900 $6,043,170 $5,839,954 $5,771,389
CAPITALIZATION RATIOS: (including first mortgage bonds maturing within one year):
Common stock equity 38.9% 36.2% 35.0% 33.5% 33.2%
Preferred stock 6.5 7.4 8.3 9.1 9.6
Long-term debt 54.6 56.4 56.7 57.4 57.2
FINANCIAL RATIOS:
Ratio of earnings to 2.31 2.24 2.09 1.41 1.71
fixed charges
Ratio of earnings to 2.26 2.17 2.03 1.35 1.66
fixed charges without
AFC
Ratio of AFC to balance 6.7% 9.7% 9.3% 52.8% 18.3%
available for common
stock
Ratio of earnings to
fixed charges and 2.00 1.90 1.77 1.17 1.41
preferred
stock dividends
Other ratios-% of
operating revenues:
<PAGE>
Fuel, purchased 36.1% 34.1% 32.1% 36.9% 36.5%
power and purchased gas
Other operation 20.9 19.7 20.0 19.9 19.7
expenses
Maintenance, 13.0 13.5 14.4 14.4 14.4
depreciation and
amortization
Total taxes 16.2 17.3 16.4 14.4 15.3
Operating income 13.3 14.2 15.5 14.3 14.2
Balance available 6.1 5.9 6.0 1.3 3.6
for common stock
MISCELLANEOUS: (000's)
Gross additions to $ 519,612 $ 502,244 $ 522,474 $ 431,579 $ 413,492
utility plant
Total utility plant 10,108,529 9,642,262 9,180,212 8,702,741 8,324,112
Accumulated 3,231,237 2,975,977 2,741,004 2,484,124 2,283,307
depreciation and
amortization
Total assets 9,419,077 8,590,535 8,241,476 7,765,406 7,562,472
</TABLE>
<PAGE>
<PAGE> 8
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
-----------------------------------------------------------
AND RESULTS OF OPERATIONS
-------------------------
Overview of 1993
----------------
Earnings improved to $240.0 million or $1.71 per share as
compared to $219.9 million or $1.61 per share in 1992,
principally as a result of rate increases to electric and gas
customers. Although earnings improved, the Company's earned
return on equity of 10.2% was below the allowed return on utility
operations of 11.4%. Expectations for 1994 earnings indicate
only a slight improvement without an increase in electric base
rates and a modest increase in gas rates. Cost sharing
mechanisms for industrial customer discounts and the potential
for loss of industrial customers in 1994 will place earnings at
additional risk.
Even with modest earnings growth, the Company's relatively
low payout ratio, as compared to the rest of the electric and gas
utility industry, permitted an increase in the common stock
dividend to an annual rate of $1.00 from $.80, or 25% in 1993.
The Company is increasingly challenged to maintain its
financial condition under traditional regulation and in the face
of expanding competition. While utilities across the nation must
address these concerns to varying degrees, the Company may be
more vulnerable than others to competitive threats. The
following sections present an assessment of competitive threats
and steps being taken to improve the Company's strategic and
financial position.
Rating agencies, which evaluate the credit-worthiness of
various securities, including the Company's, have expressed
heightened concern about the future business prospects of the
utility industry. Standard & Poors Corporation has included the
Company in its "Below Average," or lowest rated group in its
assessment of business position. A more extensive discussion of
rating agency views is included under "Liquidity and Capital
Resources."
Changing Competitive Environment
--------------------------------
In 1993, the Company continued to address concerns relating
to increasing competition in the utility industry. The enactment
of the 1992 Federal Energy Policy Act (Act) has accelerated the
trend toward competition and deregulation in the wholesale market
(principally sales to others who will resell power to the retail
market), by creating a class of generators, called Exempt
Wholesale Generators (EWGs), which are able to sell power without
the regulatory constraints placed on generators such as the
Company. To further encourage wholesale competition, the Act
<PAGE>
opens access to utility transmission systems. The rules by which
such access will
<PAGE> 9
be prioritized and priced have not been issued, and the potential
impact on the Company, as owner and lessee of significant
transmission assets, cannot be determined. Although the Act
prohibits direct sales to a utility's retail customer, New York
State retains the right to allow retail competition. In view of
these developments, the Company undertook a Comprehensive
Industry Restructuring and Competitive Assessment for the year
2000 (CIRCA 2000) to evaluate the means by which retail
competition may develop and the Company's ability to respond to
the associated threats and opportunities. While the future of
wholesale and retail markets is uncertain, the Company determined
through its CIRCA 2000 study that it must (a) reduce its total
cost of doing business and (b) improve its responsiveness to
changing business conditions.
Under the terms of its 1994 Rate Agreement, the Company is
required to file a "competitiveness" study with the New York
State Public Service Commission (PSC) by April 1, 1994.
Cost Control
------------
Cost control extends beyond those areas traditionally
thought to be under utility control, to all aspects of utility
pricing, including unregulated generator purchases, tax burdens
and mandated social and environmental programs. As a step
towards improving its competitive position, in early 1993 the
Company announced its intent to reduce its workforce by at least
1,400 positions by the end of 1995. While considerable progress
was made toward this goal in 1993, rapidly changing competitive
pressures made it clear that deeper cuts will be necessary.
Consequently, in January 1994, the Company decided that further
and faster workforce reductions would be necessary and announced
a layoff over the next several months of approximately 900
employees, increasing the total reduction to approximately 1,500.
Further reductions may be necessary.
Price Responsiveness
--------------------
As described in more detail below under "1995 Five-Year Rate
Plan Filing," the Company filed a five-year rate plan which would
establish prices for 1995 and a method by which prices would be
set for 1996 through 1999. The plan would cap the average annual
rate at approximately the annual rate of inflation, but would
also allow greater flexibility for Company pricing decisions
within each rate class (e.g., residential, commercial and
industrial) subject to the overall cap. The Company could, at
its discretion, offer discounts to customers that might be able
to leave the Company's system, but would in turn be limited to
<PAGE>
how much, if any, of the discounts could be recouped from other
classes. While the focus of pricing innovation has principally
been to retain industrial customers, the Company is also
evaluating innovative pricing alternatives for residential and
commercial customers.
<PAGE> 10
The flexibility and responsiveness of the plan to changing
business conditions is designed to better position the Company to
meet the challenges of increasing competition to protect
shareholder value. However, the Company must be disciplined in
its spending based upon its projections of price increases, if
any, sales and potential discounts during the five-year period.
The financial success of the Company under its price
indexing rate proposal is dependent on the ability of the Company
to control all of its costs. Because price indexing begins with
base prices set for 1995, inclusive of such things as fuel,
purchased power and taxes, the establishment of an appropriate
base is critical to the financial results of the Company during
the five-year period.
An ongoing generic investigation is being conducted by the
PSC into the issue of how to design rates for customers with
competitive electric and gas service alternatives. The Company
is developing proposals to further permit the necessary rate
flexibility to respond to competitive conditions in the industry.
UNREGULATED GENERATORS
In recent years, a leading factor in the increases in
customer bills and deterioration of the Company's competitiveness
is 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. The Public
Utility Regulatory Policies Act of 1978 (PURPA), New York State
Law and PSC policies and procedures have collectively required
that the Company purchase this power from qualified unregulated
generators. The price used in negotiating purchased power
contracts with unregulated generators (Long Run Avoided Costs or
LRACs) is established periodically by the PSC. Until repeal in
1992, the statute which governed many of these contracts had
established the floor on avoided costs at $0.06/kwh (the Six-Cent
Law). The Six-Cent Law, in combination with other factors,
attracted large numbers of unregulated generators projects to New
York State and, in particular, to the Company's service
territory.
As of December 31, 1993, 147 of these unregulated generators
with a combined capacity of 2,253 MW were on line and selling
power to the Company. The following table illustrates the actual
and estimated growth in capacity, payments and relative magnitude
of unregulated generator purchases compared to Company
requirements:
<PAGE>
<PAGE> 11
ACTUAL
_____________________________
1991 1992 1993
---- ---- ----
MW's 1,027 1,549 2,253
Percent of Total
Capability 13% 19% 25%
Payments $ 268 $ 543 $ 736
(millions)
Percent of Total
Fuel and Purchased
Power Costs 32% 56% 67%
ESTIMATED
_________________________________________
1994 1995 1996 1997 1998
---- ---- ---- ---- ----
MW's 2,354 2,391 2,391 2,391 2,391
Percent of Total
Capability 27% 27% 27% 28% 28%
Payments $ 932 $1,057 $1,111 $1,174 $1,220
(millions)
Percent of Total
Fuel and
Purchased 70% 76% 77% 77% 77%
Power Costs
<PAGE>
<PAGE> 12
Most of the additional capacity will be grandfathered under
the Six-Cent Law. Without any other actions, the Company's
installed capacity reserve margin was projected to grow to 40%-
50% before declining in the late 1990's, as compared to the
minimum mandated requirement of 18%. While the Company favors
the availability of unregulated generators in satisfying its
generating needs, the Company believes it is paying a premium to
unregulated generators for energy it does not currently need. The
Company has initiated a series of actions to address this
situation but expects in large part that the higher costs will
continue.
On August 18, 1992, the Company filed a petition with the
PSC which calls for the implementation of "curtailment
procedures." Under existing Federal Energy Regulatory Commission
(FERC) and PSC policy, this petition would allow the Company to
limit its purchases from unregulated generators when demand is
low. While the Administrative Law Judge has submitted
recommendations to the PSC, the Company cannot now predict the
outcome of this case. Also, the Company has commenced settlement
discussions with certain unregulated generators regarding
curtailments.
On October 23, 1992, the Company also petitioned the PSC to
order unregulated generators to post letters of credit or other
firm security to protect ratepayers' interests in advance
payments made in prior years to these generators. The PSC
dismissed the original petition without prejudice, which the
Company believes would permit reinstatement of its request at a
later date. The Company is conducting discussions with
unregulated generators representing over 1,600 MW of capacity,
addressing the issues contained in its petitions.
On February 4, 1994 the Company notified the owners of nine
projects with contracts that provide for advance payments of the
Company's demand for adequate assurance that the owners will
perform all of their future repayment obligations, including the
obligation to deliver electricity in the future at prices below
the Company's avoided cost and to repay any advance payment which
remains outstanding at the end of the contract. The projects at
issue total 426 MW. The Company's demand is based on its
assessment of the amount of advance payments to be accumulated
under the terms of the contracts, future avoided costs and future
operating costs of the projects. The Company cannot predict the
outcome of this notification.
The Company and certain of its officers and employees have
been named in complaints resulting from the alleged termination,
among other matters, of purchase power contracts with Inter-Power
of New York, Inc. and Fourth Branch Associates Mechanicville.
The Company believes it has substantial defenses to both
complaints but is unable to predict the outcome of these matters
and, accordingly, has not established a provision for liability,
if any, in the Company's financial statements.
<PAGE>
<PAGE> 13
ASSET MANAGEMENT STUDIES - FOSSIL
The Company continually examines its competitive situation
and future strategic direction. Among other things, it has
studied the economics of continued operation of its fossil-fueled
generating plants, given current forecasts of excess capacity.
Growth in unregulated generator supply sources and compliance
requirements of the Clean Air Act are key considerations in
evaluating the Company's internal generation needs. While the
Company's coal-burning plants continue to be cost advantageous,
certain older units and certain gas/oil-burning units are being
carefully assessed to evaluate their economic value and estimated
remaining useful lives. Due to projected excess capacity, the
Company plans to retire or put certain units in long-term cold
standby. A total of 340 MW's of aging coal fired capacity is to
be retired by the end of 1999 and 850 MW's of oil fired capacity
is to be placed in long-term cold standby in 1994. The Company
is also continuing to evaluate under what circumstances the
standby plants would be returned to service, but barring
unforseen circumstances it is not likely that a return would
occur before the end of 1999. This action will permit the
reduction of operating costs and capital expenditures for retired
and standby plants. The Company believes that the remaining
investment in these plants of approximately $300 million at
December 31, 1993, will be fully recoverable in rates.
ASSET MANAGEMENT STUDIES - NINE MILE POINT NUCLEAR STATION
UNIT NO.1
Under the terms of an earlier regulatory agreement, the
Company agreed to prepare and update studies of the advantages
and disadvantages of continued operation of Nine Mile Point
Nuclear Station Unit No. 1 (Unit 1). In the November 1992 study,
the continued operation of the unit under an "improved
performance case" was expected to provide a net present value
benefit in excess of $100 million. The unit operated within the
parameters of the improved performance case in 1993 and the
Company believes that continued operation of the Unit is
warranted. The Company's net investment in Unit 1 is
approximately $580 million and the estimated cost to decommission
the Unit based on the Company's 1989 study is $257 million in
1993 dollars. The next update is due to be submitted to the PSC
in late 1994. See NOTE 7 of Notes to Consolidated Financial
Statements under "Unit 1 Economic Study").
GAS COMPETITION
Portions of the natural gas industry have undergone
significant structural changes. A major milestone in this
process occurred in November 1993 with the implementation of FERC
<PAGE>
Order 636. FERC Order 636 requires interstate pipelines to
unbundle pipeline sales services from pipeline transportation
service. These changes enable the Company to arrange for its gas
supply directly with producers, gas marketers or pipelines, at
its
<PAGE> 14
discretion, as well as to arrange for transportation and gas
storage services. The flexibility provided to the Company by
these changes should enable it to protect its existing market and
still expand its core and non-core market offerings. With these
expanded opportunities come increased competition from gas
marketers and other utilities.
In short, the electric and gas utility industry is
undergoing changes and faces an uncertain future, therefore,
those utilities that succeed must be prepared to respond quickly
to change. Hence, the Company must be successful in, among other
things, managing the economic operation of its nuclear units and
addressing growing electric competition, expanded gas supply
competition, and various cost impacts, which include excess high-
cost unregulated generator power and increasing taxes. In
addition, the Company must implement the requirements of the
Clean Air Act Amendments of 1990 and also remediate hazardous
waste sites. While the Company believes that full recovery of
its investment will be provided through the rate setting process
with respect to all of the issues described herein, a review of
political and regulatory actions during the past 15 years with
respect to industry issues indicates that utility shareholders
may ultimately bear some of the burden of solving these problems.
REGULATORY AGREEMENTS
The Company's results during the past several years have
been strongly influenced by several agreements with the PSC. A
brief discussion of the key terms of certain of these agreements
is provided below.
1991 FINANCIAL RECOVERY AGREEMENT
The 1991 Financial Recovery Agreement (1991 Agreement)
established a $190.0 million electric rate increase effective
January 1, 1991 and also provided for electric rate increases of
2.9% ($75.4 million) effective July 1, 1991 and 1.9% ($55.7
million) effective July 1, 1992. Gas rates increased 1.0% ($5.5
million) on July 1, 1992. The 1991 Agreement also implemented
the Niagara Mohawk Electric Revenue Adjustment Mechanism (NERAM)
and the Measured Equity Return Incentive Term (MERIT), which are
discussed in more detail below.
The NERAM requires the Company to reconcile actual results
to forecast electric public sales gross margin used in
establishing rates. The NERAM produces certainty in the amount
of electric gross margin the Company will receive in a given
<PAGE>
period to fund its operations. While reducing risk during
periods of economic uncertainty and mitigating the variable
effects of weather, the NERAM does not allow the Company to
benefit from unforeseen growth in sales. Recovery or refund of
accruals pursuant to the NERAM is accomplished by a surcharge
(either plus or minus) to customers over a twelve month period,
to begin when cumulative amounts reach certain levels specified
in the 1991 Agreement. As of December 31, 1993, the Company had
a recoverable NERAM balance (amounts subject to reconciliation)
of $21.4 million.
The Company has proposed discontinuation of NERAM beginning
in 1995 in exchange for greater pricing flexibility as discussed
further below under the "1995 Five-Year Rate Plan Filing."
<PAGE> 15
The MERIT program is the incentive mechanism which
originally allowed the Company to earn up to $180 million of
additional return on equity through May 31, 1994. The program
was later amended to extend the performance period through 1995
and add $10 million to the total available award.
The PSC granted the full $30 million of MERIT award the
Company claimed for the period January 1991 through May 1991,
which was reflected in earnings in the third quarter of 1991
($.14 per common share). The second MERIT period, June 1991
through December 1991, had a maximum award of $30 million. Of
this amount, the PSC granted $22.8 million, or approximately $.11
per share, which the Company included in June 1992 earnings.
Measurement criteria for the $25 million of MERIT for 1992
focused on implementation of self-assessment recommendations,
including measurements of responsiveness to customers, nuclear
performance, cost management and environmental performance. The
Company claimed, and the PSC approved in 1993, a MERIT award of
approximately $14.3 million of which $4 million was included in
1992 earnings. The shortfall from the full award available
reflected the increasing difficulty of achieving the targets
established in customer service and cost management, as well as
lower than anticipated nuclear operating performance.
Overall goal targets and criteria for the 1993-1995 MERIT
periods are results-oriented and are intended to measure change
in key overall performance areas. The targets emphasize three
main areas: (1) responsiveness to customer needs, (2) efficiency
through cost management, improved operations and employee
empowerment, and (3) aggressive, responsible leadership in
addressing environmental issues.
A report supporting the achievement of MERIT goals for 1993
is anticipated to be submitted in February 1994 to the parties to
the 1991 Agreement. The Company anticipates claiming an award of
approximately $20 million, which would be expected to be billed
to customers over a twelve-month period, after PSC confirmation
of the earned award. The Company recorded $10 million of this
award in 1993 based on management's assessment of the achievement
<PAGE>
of objectively measured criteria. The shortfall from the full
award reflects the increasing difficulty of achieving the targets
established in customer service and cost benchmarking with other
utilities.
1993 RATE AGREEMENT
On January 27, 1993, the PSC approved a 1993 Rate Agreement
authorizing a 3.1% increase in the Company's electric and gas
rates providing for additional annual revenues of $108.5 million
(electric $98.4 million or 3.4%; gas $10.1 million or 1.8%).
Retroactive application of the new rates to January 1, 1993 was
authorized by the PSC.
The increase reflected an allowed return on equity of 11.4%,
as compared to 12.3% authorized for 1992. The agreement also
included extension of the NERAM through December 1993 and
provisions to defer expenses related to mitigation of unregulated
generator costs, (aggregating $50.7 million at December 31, 1993)
including contract buyout costs and certain other items.
<PAGE> 16
The Company and the local unions of the International
Brotherhood of Electrical Workers, agreed on a two-year nine-
month labor contract effective June 1, 1993. The new labor
contract includes general wage increases of 4% on each June 1st
through 1995 and changes to employee benefit plans including
certain contributions by employees. Agreement was also reached
concerning several work practices which should result in improved
productivity and enhanced customer service. The PSC approved a
filing resulting from the union settlement and authorized $8.1
million in additional revenues ($6.8 million electric and $1.3
million gas) for 1993.
1994 RATE AGREEMENT
On February 2, 1994, the PSC approved an increase in gas
rates of $10.4 million or 1.7%. The gas rates became effective
as of January 1, 1994 and include for the first time a weather
normalization clause.
The PSC also approved the Company's electric supplement
agreement with the PSC Staff and other parties to extend certain
cost recovery mechanisms in the 1993 Rate Agreement without
increasing electric base rates for calendar year 1994. The goal
of the supplement is to keep total electric bill impacts for 1994
at or below the rate of inflation. Modifications were made to
the NERAM and MERIT provisions which determine how these amounts
are to be distributed to various customer classes and also
provide for the Company to absorb 20% of margin variances (within
certain limits) originating from SC-10 rate discounts (as
described below) and certain other discount programs for
industrial customers as well as 20% of the gross margin variance
from NERAM targets for industrial customers not subject to
<PAGE>
discounts. The Company estimates its total exposure on such
variances for 1994 to be approximately $10 million, depending on
the amount of discounts given. The supplement also allows the
Company to begin recovery over three years of approximately $15
million of unregulated generator buyout costs, subject to final
PSC determination with respect to the reasonableness of such
costs.
The Company is experiencing a loss of industrial load
through bypass across its system. Several substantial industrial
customers, constituting approximately 85 MW of demand, have
chosen to purchase generation from other sources, either from
newly constructed facilities or under circumstances where they
directly use the power they had been generating and selling to
the Company under power purchase contracts mandated by PURPA and
New York laws and PSC programs.
As a first step in addressing the threat of a loss of
industrial load, the PSC approved a new rate (referred to as SC-
10) under which the Company is allowed to negotiate individual
contracts with some of its largest industrial and commercial
customers to provide them with electricity at lower prices.
Under the new rate, customers must demonstrate that leaving the
Company's system is an economically viable alternative. The
Company estimates that as many as 75 of its 235 largest customers
may be inclined to bypass the utility's system by making
electricity on
<PAGE> 17
their own unless they receive price discounts, which would cost
about $26 million per year, while losing those 75 customers would
reduce net revenues by an estimated $100 million per year. As of
January 1994, the Company has offered annual SC-10 discounts to
customers totaling $6.6 million, of which $2.7 million have been
accepted.
On July 28, 1993, the Company petitioned the PSC for
permission to offer competitively priced natural gas to customers
who presently purchase gas from non-utility sources. The new
rate is designed to regain a share of the industrial and
commercial sales volume the Company lost in the 1980's when large
customers were allowed to buy gas from non-utility sources. The
Company will delay any implementation of this rate until the
issues are further addressed in a comprehensive generic
investigation, currently being conducted by the PSC, into the
issue of how to design rates for customers with competitive
electric and gas service alternatives.
1995 FIVE-YEAR RATE PLAN FILING
-------------------------------
On February 4, 1994, the Company made a combined electric
and gas rate filing for rates to be effective January 1, 1995
seeking a $133.7 million (4.3%) increase in electric revenues and
a $24.8 million (4.1%) increase
in gas revenues. The electric filing includes a proposal to
institute a methodology to establish rates beginning in 1996 and
<PAGE>
running through 1999. The proposal would provide for rate
indexing to a quarterly forecast of the consumer price index as
adjusted for a productivity factor. The methodology sets a price
cap, but the Company may elect not to raise its rates up to the
cap. Such a decision would be based on the Company's assessment
of the market. NERAM and certain expense deferrals would be
eliminated, while the fuel adjustment clause would be modified to
cap the Company's exposure to fuel and purchased power cost
variances from forecast at $20 million annually. However,
certain items which are not within the Company's control would be
outside of the indexing; such items would include legislative,
accounting, regulatory and tax law changes as well as
environmental and nuclear decommissioning costs. These items and
the existing balances of certain other deferral items such as
MERIT and demand-side management (DSM), would be recovered or
returned using a temporary rate surcharge. The proposal would
also establish a minimum return on equity which, if not achieved,
would permit the Company to refile and reset base rates subject
to indexing or to seek some other form of rate relief.
Conversely, in the event earnings exceed an established maximum
allowed return on equity, such excess earnings would be used to
accelerate recovery of regulatory or other assets. The proposal
would provide the Company with greater flexibility to adjust
prices within customer classes to meet competitive pressures from
alternative electric suppliers while increasing the risk that the
Company will earn less than its allowed rate of return. Gas rate
adjustments beyond 1995 would follow traditional regulatory
methodology.
<PAGE> 18
RESULTS OF OPERATIONS
---------------------
Earnings for 1993 were $240.0 million or $1.71 per share
compared with $219.9 million or $1.61 per share in 1992 and
$203.0 million or $1.49 per share in 1991. The primary factor
contributing to the increase in earnings in 1993 as compared to
1992 was the impact of electric and gas rate increases effective
January 1, 1993 and July 1, 1992. The 1992 increase over 1991
was due primarily to the rate increases for gas and electric
customers effective July 1, 1992 and July 1, 1991, and cost
management of operating expenses relative to amounts provided in
rates, offset by oil and gas writeoffs.
In 1993, the Company's return on common equity improved
slightly to 10.2% from 10.1% in 1992 and 10.0% in 1991. The
Company's return on common equity for utility operations
authorized in the rate setting process was 11.4% for the year
ended December 31, 1993. Factors contributing to the earnings
deficiency in 1993 included lower than anticipated results from
the Company's subsidiaries, certain operating expenses which were
not included in rates and exclusion of Nine Mile Point Nuclear
Station Unit No. 2 (Unit 2) tax assets from the Company's rate
base (upon which the Company would otherwise earn a return) as a
<PAGE>
consequence of prior year write-off of disallowed Unit 2 costs.
The earnings deficiency experienced in 1992 resulted from similar
causes, as well as from write-downs of Canadian oil and gas
investments.
Non-cash earnings in 1993 were only about 3% of earnings
available to common stockholders as compared to 16% in 1992. The
Company estimates non-cash earnings will represent approximately
9% of total earnings in 1994.
The Company anticipates a return on equity of about 10% in
1994. The ability to achieve or exceed this level of earnings is
dependent upon a number of key factors, including the ongoing
control of expenses, earning MERIT and DSM incentives and
realization of an anticipated growth in gas sales.
The following discussion and analysis highlights items
having a significant effect on operations during the three-year
period ended December 31, 1993. It may not be indicative of
future operations or earnings. It also should be read in
conjunction with the Notes to Consolidated Financial Statements
and other financial and statistical information appearing
elsewhere in this report.
ELECTRIC REVENUES increased $663.2 million or 24.8% over the
three-year period. This increase results primarily from rate
increases, NERAM revenues and other factors as indicated in the
table below. Approximately one-half of the increase in base
rates in 1991 through 1993 is the result of an increase in the
base cost of fuel, which would typically result in a similar
decrease in fuel and purchased power cost revenues, thus having a
revenue neutral impact. However, purchased power costs have
increased
<PAGE> 19
significantly during this period, offsetting much of the
otherwise expected decrease in Fuel Adjustment Clause (FAC)
revenues. See "Regulatory Agreements" above for a discussion of
the rate increases and provisions of the regulatory agreements in
effect during this period.
<PAGE> 20
Increase (decrease) from prior year
(In millions of dollars)
Electric revenues 1993 1992 1991 Total
Increase in base rates $193.1 $250.6 $181.3 $ 625.0
Fuel and purchased (42.6) (6.4) (83.0) (132.0)
power cost revenues
<PAGE>
Sales to ultimate 11.0 39.7 2.6 53.3
consumers
Sales to other electric 11.7 (12.8) 36.2 35.1
systems
DSM revenue (30.3) (24.3) 17.2 (37.4)
Miscellaneous operating 23.9 (11.3) 17.6 30.2
revenues
NERAM revenues 24.0 7.8 38.8 70.6
MERIT revenues (6.0) (2.9) 27.3 18.4
_______ ______ ______ ________
$184.8 $240.4 $238.0 $ 663.2
======= ======= ======= =========
<PAGE> 21
While sales to ultimate customers in 1993 were up slightly
from 1992, this level of sales was substantially below the
forecast used in establishing rates for the year. As a result,
the Company accrued NERAM revenues of $65.7 million ($.31 per
share) during 1993 as compared to $41.7 million ($.20 per share)
of NERAM revenues in 1992.
Changes in fuel and purchased power cost revenues are
generally margin-neutral, while sales to other utilities, because
of regulatory sharing mechanisms, generally result in low margin
contribution to the Company. Thus, fluctuations in these revenue
components do not generally have a significant impact on net
operating income. Electric revenues reflect the billing of a
separate factor for DSM programs which provide for the recovery
of program related rebate costs and a Company incentive based on
10% of total net resource savings.
Electric kilowatt-hour sales were 37.7 billion in 1993, an
increase of 3.0% from 1992 and an increase of 2.7% over 1991.
The 1993 increase reflects increased sales to other electric
systems, while sales to ultimate consumers were generally flat.
(See Electric and Gas Statistics - Electric Sales). The Company
expects growth of approximately 1.2% in sales to ultimate
consumers in 1994. The effects of the recession that began in
1990 are expected to continue to put downward pressure on
industrial sales, which may be offset by growth in commercial and
residential sales. The electric margin effect of actual sales in
1994 will be adjusted by the NERAM except for the large
industrial customer class within which the Company will absorb
20% of the variance from the NERAM sales forecast. Industrial-
Special sales are New York State Power Authority allocations of
low-cost power to specified customers.
<PAGE> 22
<PAGE>
Details of the changes in electric revenues and kilowatt-hour
sales by customer group are highlighted in the table below:
<PAGE>
<TABLE>
<CAPTION>
1993 % Increase (decrease) from prior years
% of
Electric 1993 1992 1991
Class of service Revenues Revenues Sales Revenues Sales Revenues Sales
<S> <C> <C> <C> <C> <C> <C> <C>
Residential 35.2% 6.9% 0.8% 11.3% 0.7% 7.4% 0.1%
Commercial 37.3 7.0 3.9 11.1 (0.5) 6.7 0.5
Industrial 16.6 (6.0) (5.2) 13.0 (1.3) 2.4 (2.6)
Industrial-Special 1.3 9.1 .8 11.8 1.9 4.8 (7.6)
Municipal service 1.5 .6 (3.1) 5.8 (0.4) 6.1 0.9
Total to ultimate 91.9 4.3 0.5 11.4 0.0 6.1 (1.3)
consumers
Other electric systems 3.1 12.6 31.2 (12.1) (3.5) 51.9 107.9
Miscellaneous 5.0 40.6 - (29.0) - 44.2 -
Total 100.0% 5.9% 3.0% 8.3% 8.9% 3.4%
(0.3)%
</TABLE>
<PAGE>
<PAGE> 23
As indicated in the table below, internal generation from
fossil fuel sources continued to decline in 1993, principally at
the Oswego oil-fired facility and Albany gas-fired station,
corresponding to the increase in required unregulated generator
purchases. Nuclear generation levels increased due to fewer
unscheduled outages. Despite scheduled refueling and maintenance
outages for both units during 1993, Unit 1 operated at a capacity
factor of approximately 81% for 1993, while Unit 2 operated at
approximately 78%. The next nuclear refueling outages at each
unit are scheduled for 1995.
<PAGE>
<PAGE> 24
<TABLE>
<CAPTION>
1993 1992 1991
_______________ ______________ ________________
FUEL FOR ELECTRIC GENERATION:
(in millions of dollars)
GwHrs. Cost GwHrs. Cost GwHrs. Cost
------ ----- ------ ---- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Coal 7,088 $ 113.0 8,340 $128.8 8,715 $139.6
Oil 2,177 74.2 3,372 106.6 5,917 187.6
Natural gas 548 12.5 1,769 44.6 1,980 54.6
Nuclear 7,303 43.3 5,031 28.9 6,561 45.2
Hydro 3,530 - 3,818 - 3,468 -
______ _______ ______ ______ ______ ______
20,646 243.0 22,330 308.9 26,641 427.0
______ _______ ______ ______ ______ ______
ELECTRICITY PURCHASED:
Unregulated generators 11,720 735.7 8,632 543.0 4,303 268.1
Other 9,046 118.1 8,917 115.7 9,067 125.6
______ ________ ______ ______ ______ _______
20,766 853.8 17,549 658.7 13,370 393.7
Fuel adjustment clause - (2.2) - 6.0 - 17.2
<PAGE>
Losses/Company use 3,688 - 3,268 - 3,273 -
______ ________ ______ ______ ______ ______
37,724 1,094.6 36,611 $973.6 36,738 $837.9
====== ======== ====== ====== ====== =======
</TABLE>
<PAGE>
<PAGE> 25
<TABLE>
<CAPTION>
% Change from prior year
_________________________________
1993 to 1992 1992 to 1991
_________________ _____________
FUEL FOR ELECTRIC GENERATION:
(in millions of dollars)
GwHrs. Cost GwHrs. Cost
----- ---- ----- ----
<S> <C> <C> <C> <C>
Coal (15.0)% (12.3)% (4.3)% (7.7)%
Oil (35.4) (30.4) (43.0) (43.2)
Natural gas (69.0) (72.0) (10.7) (18.4)
Nuclear 45.2 49.8 (23.3) (36.2)
Hydro (7.5) - 10.1 -
_____ ______ ______ _____
(7.5) (21.3) (16.2) (27.7)
______ _______ ______ ______
ELECTRICITY PURCHASED:
Unregulated generators 35.8 35.5 100.6 102.5
Other 1.5 2.1 (1.7) (7.9)
_____ ______ ______ ______
18.3 29.6 31.3 67.3
Fuel adjustment clause - (136.7) - (65.1)
<PAGE>
Losses/Company use 12.9 - (0.2) -
_____ ______ ______ _____
3.0 % 12.4 % (0.3)% 16.2%
====== ======= ======= ======
</TABLE>
<PAGE>
<PAGE> 26
GAS REVENUES increased $115.5 million or 23.8% over the
three-year period. As shown by the table below, this increase is
primarily attributable to increased sales to ultimate customers,
increased base rates and increased spot market sales. While spot
market sales activity produced much of the revenue growth in
1993, these sales are generally from the higher priced gas
available and therefore yield margins substantially lower than
traditional sales to ultimate customers. Deregulation in the gas
production and pipeline sectors has enabled the Company to expand
into this activity. Rates for transported gas also yield lower
margins than gas sold directly by the Company, therefore changes
in gas revenues from transportation services have not had a
significant impact on earnings. Also, changes in purchased gas
adjustment clause revenues are generally margin-neutral.
<PAGE> 27
<TABLE>
<CAPTION>
Increase (decrease) from
prior year
(In millions of dollars)
Gas revenues 1993 1992 1991 Total
<C> <C> <C> <C>
<S>
Increase in base $ 7.3 $ 4.7 $ 22.6 $ 34.6
rates
Transportation of
customer-owned gas (9.7) 6.3 14.4 11.0
Purchased gas
adjustment clause
revenues 12.2 12.4 (25.7) (1.1)
Spot market sales 27.2 2.6 - 29.8
MERIT revenues (0.4) (0.3) 2.7 2.0
Miscellaneous
operating revenues (4.6) - 3.5 (1.1)
Sales to ultimate
consumers and other
sales 15.1 52.9 (27.7) 40.3
------ ------ ------- ------
$ 47.1 $ 78.6 $(10.2) $115.5
====== ====== ====== ======
</TABLE>
GAS SALES, excluding transportation of customer-owned gas
<PAGE>
and spot market sales, were 83.2 million dekatherms in 1993, a
5.1% increase from 1992 and a 16.0% increase from 1991. (See
Electric and Gas Statistics - Gas Sales.) The increase in 1993
includes a 1.8% increase in residential sales, a 6.5% increase in
commercial sales, which were strongly influenced by weather, and
a 143.6% increase in industrial sales. The Gas SBU has added
19,000 new customers since 1991, primarily in the residential
class, an increase of 3.9%, and expects a continued increase in
new customers in 1994. During 1993, there also was a shift from
the transportation sales class to the industrial sales class
resulting from the implementation of a stand-by industrial rate.
The increase for 1992 included a 12.0% increase in sales in the
residential class and a 10.2% increase in sales in the commercial
class, reflecting milder weather factors, offset by a 2.2%
decrease in sales in the industrial class reflecting the
recession and fuel switching.
In 1993, the Company transported 67.8 million dekatherms (a
slight increase from 1992) for customers purchasing gas directly
from producers but expects a substantial increase in such
transportation volumes in 1994 leading to a forecast increase in
total gas deliveries in 1994 of 13.2% above 1993 weather-adjusted
deliveries. Public sales are expected to decrease almost 1.0%.
<PAGE> 28
Factors affecting these forecasts include the economy, the
relative price differences between oil and gas in combination
with the relative availability of each fuel, the expanded number
of cogeneration projects served by the Company and increased
marketing efforts. As authorized by the PSC, the Company accrued
$20.9 million of unbilled gas revenues as of December 31, 1993,
which have been deferred and are expected to be used to reduce
future gas revenue requirements. Changes in gas revenues and
dekatherm sales by customer group are detailed in the table
below:
<PAGE>
<PAGE> 29
<TABLE>
<CAPTION>
1993 % Increase (decrease) from prior years
% of
Gas 1993 1992 1991
Class of service Revenues Revenues Sales Revenues Sales Revenues Sales
<S> <C> <C> <C> <C> <C> <C> <C>
Residential 61.6% 4.6% 1.8% 17.0% 12.0% (1.4)% (3.6)%
Commercial 24.1 9.2 6.5 16.6 10.2 (11.5) (11.4)
Industrial 3.1 84.8 143.6 18.6 (2.2) (56.4) (56.0)
Total to 88.8 7.4 6.4 16.9 11.1 (6.6) (8.7)
ultimate
consumers
Other gas .2 (77.5) (80.3) (32.0) (21.7) (11.9) (11.8)
systems
Transportation
of customer- 5.8 (18.5) 2.9 17.2 30.0 65.0 47.9
owned gas
Spot market 5.0 1,056.1 1,053.8 - - - -
sales
Miscellaneous 0.2 (79.4) - 0.4 - 574.1 -
Total 100.0% 8.5% 12.3% 16.5% 19.5% (2.1)% 8.4%
</TABLE>
<PAGE>
<PAGE> 30
The cost of gas purchased increased 13.6% in 1993 and 16.1%
in 1992 after having decreased 13.4% in 1991. The cost
fluctuations generally correspond to sales volume changes,
particularly in 1993, as spot market sales activity increased.
The Company sold 13.2 million dekatherms on the spot market in
1993 as compared to 1.1 million in 1992. This activity accounted
for two-thirds of the 1993 purchased gas expense increase. The
purchase gas cost increase associated with purchases for ultimate
consumers in 1993 resulted from a 8.7% increase in dekatherms
purchased combined with a 2.1% increase in rates charged by
suppliers offset by a $17.8 million decrease in purchased gas
costs and certain other items recognized and recovered through
the purchased gas adjustment clause. The increase associated
with purchases for ultimate consumers for 1992 was the result of
a 10.0% increase in dekatherms purchased, a 2.7% increase in
rates charged by the Company's suppliers, combined with an
increase of $5.2 million in purchased gas costs and certain other
items recognized and recovered through the purchased gas
adjustment clause. The Company's net cost per dekatherm
purchased for sales to ultimate consumers decreased to $3.34 in
1993 from $3.47 in 1992 which was higher than the net cost of
$3.31 in 1991.
Through the electric and purchased gas adjustment clauses,
costs of fuel, purchased power and gas purchased, above or below
the levels allowed in approved rate schedules, are billed or
credited to customers. The Company's electric fuel adjustment
clause provides for partial pass-through of fuel and purchased
power cost fluctuations from those forecast in rate proceedings,
with the Company absorbing a specific portion of increases or
retaining a portion of decreases to a maximum of $15 million per
rate year. The amounts absorbed in 1991 through 1993 are not
material.
OTHER OPERATION expense, including wage increases in each
year, increased $73.2 million or 9.8% in 1993 as compared to
increases of 5.9% in 1992 and 7.8% in 1991. The 1993 increase is
otherwise due to an increase in DSM program expenses, nuclear
expenses related to increased production at Unit 1 and Unit 2 and
refueling outages, amortization of regulatory assets deferred in
prior years, increased recognition of other postretirement
benefit costs and inflation. The 1992 increase was also due to
increased computer software expenses and higher medical benefits
paid. The 1991 increase was also due to increases in bad debt
expense, environmental site investigation and remediation costs,
DSM program expenses and research and development costs. Bad
debts have increased during the recession and increased
collection efforts and innovative collection management also
contributed to the increased writeoffs.
MAINTENANCE EXPENSE increased 4.5% in 1993 principally due
to nuclear expenses incurred during the refueling outages at Unit
1 and Unit 2 offset by lower expenses on the fossil stations
because of economically driven shutdowns at the Oswego and Albany
plants as described above. Maintenance expense decreased
<PAGE>
slightly in 1992 as increased costs associated with outages at
Unit 1 and refueling
<PAGE> 31
Unit 2 were offset by reduced transmission line maintenance
expenses. Maintenance expense decreased 1.8% in 1991 due to
lower Unit 2 maintenance partly offset by transmission line ice
storm damage.
DEPRECIATION AND AMORTIZATION expense for 1993 and 1992
increased 0.9% and 5.9% over 1992 and 1991, respectively. The
increase is attributable to normal plant growth.
NET FEDERAL AND FOREIGN INCOME TAXES for 1993 decreased due
to the tax benefit derived from the Company's Canadian subsidiary
upon the sale of its oil and gas investments. Net Federal and
foreign income taxes for 1992 and 1991 increased because of
increases in book taxable income. The increase in
OTHER TAXES in the three-year period is due principally to higher
property taxes resulting from property additions combined with
increased payroll and revenue-based taxes.
OTHER ITEMS, NET, excluding Federal income taxes and
allowance for funds used during construction (AFC), increased
$23.4 million in 1993 and decreased $2.7 million in 1992. The
1993 increase was the effect of the recording in 1992 of a $45
million reserve against the carrying value of Canadian subsidiary
oil and gas reserves, offset in part by the recognition of the
Company's share of Unit 2 contractor litigation proceeds and
increased earnings by the Company's independent power subsidiary.
The 1991 decrease is primarily the result of a similar $22.7
million write-down of oil and gas reserves.
Net INTEREST CHARGES decreased $9.3 million in 1993 and
$10.9 million in 1992, primarily as the result of the refinancing
of debt at lower interest rates. Dividends on preferred stock
decreased $4.7 million, $3.9 million and $1.9 million in 1993,
1992 and 1991, respectively, because of reductions in amounts of
stock outstanding. The weighted average long-term debt interest
rate and preferred dividend rate paid, reflecting the actual cost
of variable rate issues, changed to 7.97% and 6.70%,
respectively, in 1993, from 8.29% and 7.04%, respectively, in
1992, and from 8.74% and 7.53%, respectively, in 1991.
EFFECTS OF CHANGING PRICES
The Company is especially sensitive to inflation because of
the amount of capital it typically needs and because its prices
are regulated using a rate base methodology that reflects the
historical cost of utility plant.
The Company's consolidated financial statements are based on
historical events and transactions when the purchasing power of
the dollar was substantially different from the present. The
effects of inflation on most utilities, including the Company,
are most significant in the areas of depreciation and utility
plant. The Company could not replace its utility plant and
equipment for the historical cost value at which they are
<PAGE>
recorded on the Company's books. In addition, the Company would
not replace these assets with identical ones due to technological
advances and regulatory changes that have occurred. In light of
these considerations, the
<PAGE> 32
depreciation charges in operating expenses do not reflect the
current cost of providing service. The Company, however, will
seek additional revenue or reallocate resources to cover the
costs of maintaining service as assets are replaced or retired.
FINANCIAL POSITION, LIQUIDITY AND CAPITAL RESOURCES
___________________________________________________
FINANCIAL POSITION
The Company's capital structure at December 31, 1993 was
54.6% long-term debt, 6.5% preferred stock and 38.9% common
equity, as compared to 56.4%, 7.4% and 36.2%, respectively, at
December 31, 1992. Book value of the common stock was $17.25 per
share at December 31, 1993 as compared to $16.33 per share at
December 31, 1992. The improvement in the capital structure and
book value is attributable primarily to reinvested earnings and
sales of common stock, although preferred stock redemptions also
contributed.
The 1993 ratio of earnings to fixed charges was 2.31 as
compared to an average ratio nationally of approximately 3.0 for
electric and gas utilities. The ratios of earnings to fixed
charges for 1992 and 1991 were 2.24 and 2.09, respectively.
Firms which publish securities ratings have begun to impute
certain items into the Company's interest coverage calculations
and capital structure, the most significant of which is the
inclusion of a "leverage" factor for unregulated generator
contracts. These firms believe that the financial structure of
the unregulated generators (which typically have very high debt-
to-equity ratios) and the character of their power purchase
agreements increase the financial risk of utilities. The
Company's reported interest coverage and debt-to-equity ratios
have recently been discounted by varying amounts for purposes of
establishing credit ratings. Because of growing commitments for
unregulated generator purchases, the imputation can have a
material negative impact on the Company's financial indicators.
CONSTRUCTION AND OTHER CAPITAL REQUIREMENTS
-------------------------------------------
The Company's total capital requirements consist of amounts
for the Company's construction program, working capital needs,
maturing debt issues and sinking fund provisions on preferred
stock, and have been affected by the Company's efforts in recent
years to lower capital costs through refinancing. Annual
expenditures for the years 1991 to 1993 for construction and
<PAGE>
nuclear fuel, including related AFC and overheads capitalized,
were $522.5 million, $502.2 million and $519.6 million,
respectively.
The 1994 estimate for construction additions, including
overheads capitalized, nuclear fuel and AFC, is approximately
$510 million, of which approximately 90% is expected to be funded
by cash provided from operations. Mandatory and optional debt
and
<PAGE> 33
preferred stock retirements and other requirements are expected
to add approximately another $545 million (expected to be
refinanced from external sources) to the Company's capital
requirements, for a total of $1,055 million. Current estimates
of total capital requirements for the years 1995 to 1998 decrease
considerably to $442, $474, $401 and $483 million, respectively,
of which $363, $405, $351, and $413 million relates to expected
construction additions. The reductions are linked to the
completion of debt refinancings as well as the reduced
construction spending. The estimate of construction additions
included in capital requirements for the period 1995 to 1998 will
be reviewed by management during 1994 with the objective of
further reducing these amounts where possible.
The provisions of the Clean Air Act Amendments of 1990
(Clean Air Act) are expected to have an impact on the Company's
fossil generation plants during the period through 2000 and
beyond. The Company is studying options for compliance with
Phase I of the Clean Air Act, which becomes effective January 1,
1995 and continues through 1999.
With respect to meeting sulfur dioxide emission limits in
Phase I of the Clean Air Act, only Dunkirk units 3 and 4 are
affected. Options under evaluation to comply with sulfur dioxide
emission limits at these units include switching to a lower
sulfur coal, reducing utilization of the units, and the purchase
of emission allowances. The Company also must lower its nitrous
oxide (NOx) emissions in Phase I. The Company spent
approximately $19 million in 1993 and has included $46 million in
its construction forecast for 1994 through 1997 to make
combustion modifications at its fossil fired plants including the
installation of low NOx burners at the Dunkirk and Huntley
plants. With respect to Phase II, greater reductions will be
required for both sulfur dioxide and NOx emissions. The Company
has conducted studies on its fossil fired units to examine
compliance options. Preliminary estimates for Phase II
compliance anticipate approximately $124 million in capital costs
and $21 million in annual expenses. The Company believes that
these capital costs, as well as incremental annual operating and
maintenance costs and fuel costs, will be recoverable from
ratepayers.
LIQUIDITY AND CAPITAL RESOURCES
Cash flows to meet the Company's requirements for operating,
<PAGE>
investing and financing activities during the past three years
are reported in the Consolidated Statements of Cash Flows.
During 1993, the Company raised approximately $892 million
from external sources, consisting of $635 million of First
Mortgage Bonds, $116.7 million of common stock and a net increase
of $140.3 million of short and intermediate term debt. The
proceeds of the $635 million of First Mortgage Bonds were used to
provide for the early redemption of approximately $602 million of
higher coupon First Mortgage Bonds. The Company continues to
investigate options
<PAGE> 34
to reduce its embedded cost of long-term debt by taking advantage
of current lower interest rates.
External financing of approximately $750 million is expected
for 1994, of which approximately $545 million would be used for
scheduled and optional refundings. This external financing is
projected to consist of $425 million in long-term debt, $200
million from sales of common stock, $200 million of preferred
stock and a $75 million decrease in short-term debt. Common
stock sales at this amount will require shareholder approval to
increase the Company's common shares authorized and are
consistent with management's goal to improve the Company's
capital structure. External financing plans for 1995 to 1998 are
subject to periodic revision as underlying assumptions are
changed to reflect developments; still, the Company currently
anticipates external financing over this period will diminish in
the aggregate to approximately $420 million. Substantially all
financing is for refunding, as cash provided by operations is
expected to continue to provide funds for the Company's
construction program. The ultimate level of financing during
this four year period will reflect, among other things, the
Company's competitive positioning, uncertain energy demand due to
economic conditions and capital expenditures relating to
distribution and transmission load reliability projects, as well
as expansion of the gas business. Environmental standards
compliance costs, the effects of rate regulation and various
regulatory initiatives, the level of internally generated funds
and dividend payments, the availability and cost of capital and
the ability of the Company to meet its interest and preferred
stock dividend coverage requirements, to satisfy legal
requirements and restrictions in governing instruments and to
maintain an adequate credit rating also will impact the amount
and type of future external financing.
The Company has initiated a ten to fifteen year site
investigation and remediation program that seeks a) to identify
and remedy environmental contamination hazards in a proactive and
cost-effective manner and b) to ensure financial participation by
other responsible parties. The program involves sponsorship of
investigation, remediation and selected research projects for 42
Company-owned waste sites and, where appropriate, participation
in remedial action at 40 waste sites owned by others but where
the Company is one of a number of potentially responsible parties
(PRP).
<PAGE>
The Company has accrued a minimum liability of $240 million
at December 31, 1993 for its estimated liability for
investigation and remediation of certain Company-owned and
Company-associated hazardous waste sites, which represents the
low end of a range of estimates developed from the Company's
ongoing site investigation and remediation program. Of the $240
million accrued, $210 million relates to Company-owned sites and
$30 million represents the Company's estimated cost contribution
to sites with which it may be associated. The accrual of the
Company's cost contribution for PRP sites is derived by
estimating the total cost of clean-up of the sites and then
applying a contribution factor to the estimated
<PAGE> 35
total cost. Total costs to investigate and remediate sites with
which the Company is associated as a PRP are estimated to be
approximately $590 million.
The Company believes that costs incurred in the
investigation and remediation process are recoverable in the
ratesetting process as currently in effect. (See Note 8 of Notes
to Consolidated Financial Statements under "Environmental
Contingencies"). Rate agreements since 1991 have included a
recovery mechanism and an annual allowance for costs expected to
be incurred for waste site investigation and remediation. The
recovery mechanism provides that expenditures over or under the
allowance be deferred for future rate consideration. The Company
does not expect these costs to impact external financing,
although any such impact is dependent upon the timing of
expenditures and associated recovery.
The Company also is undertaking environmental compliance
audits at many of its facilities. These audits may result in
additional expenditures for investigation and remediation that
the Company cannot currently estimate.
The Nuclear Regulatory Commission (NRC) issued regulations
in 1988 requiring owners of nuclear power plants to place costs
associated with decommissioning activities for contaminated
portions of nuclear facilities into an external trust. Further,
the NRC established guidelines for determining minimum amounts
that must be available in the trust for these specified
decommissioning activities at the time of decommissioning.
Applying the NRC guidelines, the Company has estimated that the
minimum requirements for Unit 1 and its share of Unit 2,
respectively, will be $372 million and
$169 million in 1993 dollars. The Company is seeking an increase
in its rate allowance for Unit 1 and Unit 2 decommissioning in
1995 to reflect new NRC minimum requirements. Amounts collected
for the NRC minimum are being placed in an external trust. (See
Note 7 of Notes to Consolidated Financial Statements under
"Nuclear Plant Decommissioning").
The Company believes that traditionally available sources of
financing should be sufficient to satisfy the Company's external
financing needs during the period 1994 through 1998. As of
<PAGE>
December 31, 1993, the Company could issue an additional $1,899
million aggregate principal amount of First Mortgage Bonds. This
includes approximately $921 million from retired bonds without
regard to an interest coverage test and approximately $978
million supported by additional property currently certified and
available, assuming an 8% interest rate, under the applicable
tests set forth in the Company's mortgage trust indenture. The
Company also has authorized unissued Preferred Stock totaling
approximately $390 million and a total of $200 million of
Preference Stock is currently authorized for sale. The Company
will continue to explore and use, as appropriate, other methods
of raising funds.
Ordinarily, construction related short-term borrowings are
refunded with long-term securities on a regular basis. This
approach generally results in the Company showing a working
capital deficit. Working capital deficits also may be
temporarily created
<PAGE> 36
because of the seasonal nature of the Company's operations as
well as timing differences between the collection of customer
receivables and the payment of fuel and purchased power costs.
However, the Company has sufficient borrowing capacity to fund
such a deficit as necessary. Bank credit arrangements which, at
December 31, 1993, totaled $461 million are used by the Company
to enhance flexibility as to the type and timing of its long-term
security sales.
The Company's charter restricts the amount of unsecured
indebtedness that may be incurred by the Company to 10% of
consolidated capitalization plus $50 million. The Company has
not reached this restrictive limit.
The Company's securities ratings at December 31, 1993, were:
Secured Preferred Commercial
Debt Stock Paper
Standard & Poors
Corporation BBB BBB- A-2
Moody's Investors
Service Baa2 baa3 P-2
Duff & Phelps BBB BBB- Not applicable
Fitch Investors
Service BBB BBB- Not applicable
The security ratings set forth above are subject to revision
and/or withdrawal at any time by the respective rating
organizations and should not be considered a recommendation to
buy, sell or hold securities of the Company.
The Company's cost of financing and access to markets could
be negatively affected by events outside its control. The
Company's securities ratings could be negatively affected by,
<PAGE>
among other things, the continued growth in and its reliance on
unregulated generator purchase power requirements. Rating
agencies have expressed concern about the impact on Company
financial indicators and risk that unregulated generator
financial leveraging may have.
On October 27, 1993, Standard & Poors Corporation (S&P)
issued their revised electric utility financial ratio benchmarks.
S&P has made its benchmarks more stringent to counter increasing
business risk caused by accelerating competition in the electric
power industry as well as environmental and nuclear operating
cost pressure and slow earnings growth prospects. While the
Company was not downgraded (currently rated BBB), S&P revised the
Company's rating outlook from "stable" to "negative." Moody's
Investors Service also has indicated that it expects utility bond
ratings will come under increasing pressure over the next three
to five years because of changes in the business environment.
These assessments may increase the cost to issue new securities.
S&P also observed that because of the more disparate
business prospects for electric utilities, it was segregating
companies into <PAGE> 37
groups based upon competitive position, business prospects and
predictability of cash flows to withstand greater financial
risks. The Company was included in the "Below Average," or
lowest rated group in S&P's assessment of business position.
While the Company has not been informed of the specific reasons
for the classification, the Company's high cost structure, driven
principally by required unregulated generator purchases, sunk
costs of assets for serving customer load and operating taxes,
may be viewed as a significant disadvantage, particularly if and
to the extent that large portions of its business may be opened
up to competition. S&P's views are shared by others who follow
the Company and the electric utility industry. The Company is
taking a number of steps to address this matter as stated
elsewhere in this report.
REPORT OF MANAGEMENT
____________________
The consolidated financial statements of Niagara Mohawk Power
Corporation and its subsidiaries were prepared by and are the
responsibility of management. Financial information contained
elsewhere in this Annual Report is consistent with that in the
financial statements.
To meet its responsibilities with respect to financial
information, management maintains and enforces a system of
internal accounting controls, which is designed to provide
reasonable assurance, on a cost effective basis, as to the
integrity, objectivity and reliability of the financial records
and protection of assets. This system includes communication
through written policies and procedures, an organizational
structure that provides for appropriate division of
responsibility and the training of personnel. This system is
also tested by a comprehensive internal audit program. In
<PAGE>
addition, the Company has a Corporate Policy Register and a Code
of Business Conduct which supply employees with a framework
describing and defining the Company's overall approach to
business and requires all employees to maintain the highest level
of ethical standards as well as requiring all management
employees to formally affirm their compliance with the Code.
The financial statements have been audited by Price
Waterhouse, the Company's independent accountants, in accordance
with generally accepted auditing standards. In planning and
performing their audit, Price Waterhouse considered the Company's
internal control structure in order to determine auditing
procedures for the purpose of expressing an opinion on the
financial statements, and not to provide assurance on the
internal control structure. The independent accountants' audit
does not limit in any way management's responsibility for the
fair presentation of the financial statements and all other
information, whether audited or unaudited, in this Annual Report.
The Audit Committee of the Board of Directors, consisting of five
outside directors who are not employees, meets regularly with
management, internal auditors and Price Waterhouse to review and
discuss internal accounting controls, audit examinations and
financial reporting matters. Price Waterhouse and the Company's
internal auditors have free access to meet individually with the
Audit Committee at any time, without management being present.
<PAGE> 39
REPORT OF INDEPENDENT ACCOUNTANTS
--------------------------------
To the Stockholders and
Board of Directors of
Niagara Mohawk Power Corporation
In our opinion, the accompanying consolidated balance sheets
and the related consolidated statements of income and retained
earnings and of cash flows present fairly, in all material
respects, the financial position of Niagara Mohawk Power
Corporation and its subsidiaries at December 31, 1993 and 1992,
and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1993, in
conformity with generally accepted accounting principles. These
financial statements are the responsibility of the Company's
management; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted
auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the
<PAGE>
opinion expressed above.
As discussed in Notes 1 and 5 to the financial statements,
the Company adopted the provisions of Statements of Financial
Accounting Standards No. 109, Accounting for Income Taxes, and
No. 106, Accounting for Postretirement Benefits Other Than
Pensions, respectively, in 1993.
As discussed in Note 8, the Company is a defendant in
lawsuits relating to its actions with respect to certain
purchased power contracts. Management is unable to predict
whether the resolution of these matters will have a material
effect on its financial position or results of operations.
Accordingly, no provision for any liability that may result upon
resolution of this uncertainty has been made in the accompanying
1993 financial statements.
/s/ PRICE WATERHOUSE
--------------------
Syracuse, New York
January 27, 1994
<PAGE>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
---------------------------------------------------------
Consolidated Statements of Income and Retained Earnings
-------------------------------------------------------
<TABLE>
<CAPTION>
In thousands of dollars
For the year ended December 31, 1993 1992 1991
Operating revenues:
<S> <C> <C> <C>
Electric $3,332,464 $3,147,676 $2,907,293
Gas 600,967 553,851 475,225
3,933,431 3,701,527 3,382,518
Operating expenses:
Operation:
Fuel for electric generation 231,064 323,200 438,957
Electricity purchased 863,513 650,379 398,882
Gas purchased 326,273 287,316 247,502
Other operation expenses 821,247 748,023 706,400
Maintenance 236,333 226,127 227,812
Depreciation and amortization 276,623 274,090 258,816
(Note 1)
Federal and foreign income 162,515 183,233 158,137
taxes (Note 6)
Other taxes 491,363 484,833 420,578
<PAGE>
3,408,931 3,177,201 2,857,084
Operating income 524,500 524,326 525,434
Other income and deductions:
Allowance for other funds used
during construction 7,119 9,648 8,251
(Note 1)
Federal and foreign income 15,440 27,729 24,242
taxes (Note 6)
Other items (net) 7,035 (16,338) (13,599)
29,594 21,039 18,894
Income before interest charges 554,094 545,365 544,328
Interest charges:
Interest on long-term debt . 279,902 290,734 302,062
Other interest 11,474 9,982 9,577
Allowance for borrowed funds
used during construction (9,113) (11,783) (10,680)
282,263 288,933 300,959
Net income 271,831 256,432 243,369
Dividends on preferred stock 31,857 36,512 40,411
Balance available for common 239,974 219,920 202,958
stock
Dividends on common stock 133,908 103,784 43,552
106,066 116,136 159,406
Retained earnings at beginning 445,266 329,130 169,724
of year
<PAGE>
Retained earnings at end of $ 551,332 $ 445,266 $ 329,130
year
Average number of shares of
Common stock outstanding (in 140,417 136,570 136,100
thousands)
Balance available per average $ 1.71 $ 1.61 $ 1.49
share of common stock
Dividends paid per share $ .95 $ .76 $ .32
() Denotes deduction
</TABLE>
<PAGE>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
<TABLE>
<CAPTION>
Consolidated Balance Sheets In thousands of dollars
At December 31, 1993 1992
ASSETS
Utility plant (Note 1):
<S> <C> <C>
Electric plant . . . . . . . . . . . . . . . . . . . $ 7,991,346 $7,590,062
Nuclear fuel . . . . . . . . . . . . . . . . . . . . 458,186 445,890
Gas plant . . . . . . . . . . . . . . . . . . . . . 845,299 787,448
Common plant . . . . . . . . . . . . . . . . . . . . 244,294 231,425
Construction work in progress . . . . . . . . . . . 569,404 587,437
Total utility plant . . . . . . . . . . . . . . . 10,108,529 9,642,262
Less: Accumulated depreciation and amortization . . 3,231,237 2,975,977
Net utility plant . . . . . . . . . . . . . . . . 6,877,292 6,666,285
Other property and investments . . . . . . . . . . . 221,008 274,169
Current assets:
Cash, including temporary cash investments of
$100,182 and $4,121, respectively. . . . . . . . . 124,351 43,894
<PAGE>
Accounts receivable (less allowance for doubtful
accounts of $3,600) (Note 8) . . . . . . . . . . . 258,137 221,165
Unbilled revenues (Note 1) . . . . . . . . . . . . . 197,200 180,000
Electric margin recoverable. . . . . . . . . . . . . 21,368 11,595
Materials and supplies, at average cost:
Coal and oil for production of electricity . . . 29,469 78,517
Gas storage . . . . . . . . . . . . . . . . . . . 31,689 20,466
Other . . . . . . . . . . . . . . . . . . . . . . 163,044 172,637
Prepayments:
Taxes . . . . . . . . . . . . . . . . . . . . . . 23,879 14,414
Pension expense (Note 5) . . . . . . . . . . . . 37,238 33,631
Other . . . . . . . . . . . . . . . . . . . . . . . 29,498 32,522
915,873 808,841
Regulatory and other assets:
Unamortized debt expense . . . . . . . . . . . . . . 154,210 140,803
Deferred recoverable energy costs . . . . . . . . . 67,632 61,944
Deferred finance charges (Note 1) . . . . . . . . . 239,880 239,880
Income taxes recoverable (Note 6). . . . . . . . . . 527,995 -
Recoverable environmental restoration costs (Note 8) 240,000 215,000
Other . . . . . . . . . . . . . . . . . . . . . . . 175,187 183,613
1,404,904 841,240
$ 9,419,077 $8,590,535
<PAGE>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets In thousands of dollars
At December 31, 1993 1992
CAPITALIZATION AND LIABILITIES
Capitalization (Note 4):
Common stockholders' equity:
<S> <C> <C>
Common stock, issued 142,427,057 and $ 142,427 $ 137,160
137,159,607 shares, respectively. . . . . . . . . .
1,762,706 1,658,015
Capital stock premium and expense . . . . . . . . . .
Retained earnings . . . . . . . . . . . . . . . . . . 551,332 445,266
2,456,465 2,240,441
Non-redeemable preferred stock . . . . . . . . . . . . . 290,000 290,000
Mandatorily redeemable preferred stock . . . . . . . . . 123,200 170,400
Long-term debt . . . . . . . . . . . . . . . . . . . . . 3,258,612 3,491,059
Total capitalization . . . . . . . . . . . . . . . . 6,128,277 6,191,900
Current liabilities:
Short-term debt (Note 2) . . . . . . . . . . . . . . . . 368,016 227,698
<PAGE>
Long-term debt due within one year (Note 4). . . . . . . 216,185 57,722
Sinking fund requirements on redeemable preferred
stock (Note 4) . . . . . . . . . . . . . . . . . . . . 27,200 27,200
Accounts payable . . . . . . . . . . . . . . . . . . . . 299,209 275,744
Payable on outstanding bank checks . . . . . . . . . . . 35,284 41,738
Customers' deposits . . . . . . . . . . . . . . . . . . 14,072 13,059
Accrued taxes . . . . . . . . . . . . . . . . . . . . . 56,382 52,033
Accrued interest . . . . . . . . . . . . . . . . . . . . 70,529 70,882
Accrued vacation pay . . . . . . . . . . . . . . . . . . 40,178 38,515
Other . . . . . . . . . . . . . . . . . . . . . . . . . 82,145 40,220
1,209,200 844,811
Regulatory and other liabilities:
Accumulated deferred income taxes (Notes 1 and 6). . . . 1,313,483 755,421
Deferred finance charges (Note 1) . . . . . . . . . . . 239,880 239,880
Unbilled revenues (Note 1) . . . . . . . . . . . . . . . 94,968 77,768
Deferred pension settlement gain (Note 5) . . . . . . . 62,282 68,292
Customers refund for replacement power cost
disallowance.. . . . . . . . . . . . . . . . . . . . . 23,081 46,801
Other . . . . . . . . . . . . . . . . . . . . . . . . . 107,906 150,662
1,841,600 1,338,824
Commitments and contingencies (Note 8):
Liability for environmental restoration. . . . . . . . . 240,000 215,000
$9,419,077 $8,590,535
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Statements of Cash Flows
Increase (Decrease) in Cash
In thousands of dollars
For the year ended December 31, 1993 1992 1991
Cash flows from operating activities:
<S> <C> <C> <C>
Net income . . . . . . . . . . . . . . . . . . . . . . . . . $ 271,831 $ 256,432 $ 243,369
Adjustments to reconcile net income to net cash
provided by operating activities:
Amortization of nuclear replacement power cost disallowance. (23,720) (39,547) (28,820)
Depreciation and amortization. . . . . . . . . . . . . . . . 276,623 274,090 258,816
Amortization of nuclear fuel . . . . . . . . . . . . . . . . 35,971 26,159 38,687
Provision for deferred income taxes. . . . . . . . . . . . . 30,067 55,929 68,138
Electric margin recoverable. . . . . . . . . . . . . . . . . (9,773) 3,670 (20,173)
Allowance for other funds used during construction . . . . . (7,119) (9,648) (8,251)
Deferred recoverable energy costs. . . . . . . . . . . . . . (5,688) (14,329) 4,931
(Gain)\loss on investments - net . . . . . . . . . . . . . . (5,490) 44,296 30,680
Deferred operating expenses. . . . . . . . . . . . . . . . . 15,746 20,257 31,176
Increase in net accounts receivable . . . . . . . . . . . . (36,972) (44,969) (25,900)
(Increase) decrease in materials and supplies. . . . . . . . 43,581 (28,293) 7,022
Increase in accounts payable and accrued expenses. . . . . . 15,716 31,025 4,221
Increase in accrued interest and taxes . . . . . . . . . . . 3,996 10,133 447
Changes in other assets and liabilities. . . . . . . . . . . 22,581 39,565 17,052
Net cash provided by operating activities . . . . . . . 627,350 624,770 621,395
<PAGE>
Cash flows from investing activities:
Construction additions . . . . . . . . . . . . . . . . . . . (506,267) (452,497) (504,485)
Nuclear fuel . . . . . . . . . . . . . . . . . . . . . . . . (12,296) (37,247) (13,236)
Less: Allowance for other funds used during
construction . . . . . . . . . . . . . . . . . . . . . . . 7,119 9,648 8,251
Acquisition of utility plant . . . . . . . . . . . . . . . . (511,444) (480,096) (509,470)
(Increase) decrease in materials and supplies related to
construction. . . . . . . . . . . . . . . . . . . . . . . 3,837 (7,359) 4,682
Increase in accounts payable and accrued expenses
related to construction. . . . . . . . . . . . . . . . . . 3,929 7,756 1,055
Increase in other investments. . . . . . . . . . . . . . . . (38,731) (11,615) (69,648)
Proceeds from sale of investment in oil and gas subsidiary . 95,408 - -
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . (15,260) (31,588) (13,721)
Net cash used in investing activities . . . . . . . . . (462,261) (522,902) (587,102)
Cash flows from financing activities:
Proceeds from sale of common stock . . . . . . . . . . . . . 116,764 13,340 -
Sale of mortgage bonds . . . . . . . . . . . . . . . . . . . 635,000 835,000 195,600
Issuance of preferred stock. . . . . . . . . . . . . . . . . - - 22,850
Redemption of preferred stock. . . . . . . . . . . . . . . . (47,200) (41,950) (42,830)
Reductions of long-term debt . . . . . . . . . . . . . . . . (641,990) (796,795) (231,941)
Net change in short-term debt and revolving credit
agreements . . . . . . . . . . . . . . . . . . . . . . . . 50,318 90,130 76,606
Dividends paid . . . . . . . . . . . . . . . . . . . . . . . (165,765) (140,296) (83,963)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . (31,759) (44,781) (6,808)
Net cash used in financing activities . . . . . . . . . (84,632) (85,352) (70,486)
Net increase (decrease) in cash . . . . . . . . . . . . . . . . 80,457 16,516 (36,193)
Cash at beginning of year . . . . . . . . . . . . . . . . . . . 43,894 27,378 63,571
Cash at end of year . . . . . . . . . . . . . . . . . . . . . . $ 124,351 $ 43,894 $ 27,378
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest. . . . . . . . . . . . . . . . . . . . . . . . $ 300,791 $ 323,972 $ 331,828
Income taxes. . . . . . . . . . . . . . . . . . . . . . 106,202 76,519 67,509
<PAGE>
Supplemental schedule of noncash investing and
financing activities:
Liability for environmental restoration . . . . . . . . . . . . 25,000 15,000 200,000
During June 1992, the Company acquired all of the common stock of Syracuse Suburban Gas Company, Inc. in
exchange for 353,775 shares of the Company's common stock having a value of $6,120,000.
</TABLE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Company is subject to regulation by the PSC and FERC
with respect to its rates for service under a methodology which
establishes prices based on the Company's cost. The Company
maintains its accounting records on the basis of such regulation,
which it believes complies with generally accepted accounting
principles. The Company's accounting policies conform to
generally accepted accounting principles, as applied to regulated
public utilities, and are in accordance with the accounting
requirements and ratemaking practices of the regulatory
authorities.
Principles of Consolidation: The consolidated financial
statements include the Company and its wholly-owned subsidiaries.
All significant intercompany balances and transactions have been
eliminated. Assets and liabilities of its Canadian energy
subsidiary, Opinac Energy Corporation, are translated into U.S.
dollars at the exchange rate in effect at the balance sheet date.
Revenue and expense accounts are translated at the average
exchange rate in effect during the year. Currency translation
adjustments are recorded as a component of equity and do not have
a significant impact on financial condition. The results of
operations of the Company's oil and gas subsidiary are included
in other income and deductions on the Consolidated Statements of
Income and Retained Earnings.
Subsidiary oil and gas properties: During 1993, the Company sold
its interest in its Canadian oil and gas company, Opinac
Exploration Limited. This was done to streamline the Company's
business and focus on its core electric and gas utility assets.
The sale did not have a material impact on the Company's results
of operations or financial condition. The Company retained its
ownership of Opinac Energy Corporation and the Company's
subsidiary, Canadian Niagara Power Limited, an Ontario electric
utility company.
The net book value of oil and gas properties and equipment,
less related deferred income taxes, was limited to the sum of the
after tax present value of net revenues from proved oil and gas
reserves and the lower of cost or fair value of unproved
properties. The calculation of future net revenues was based
upon prices and costs in effect at the end of the year. Based
upon the calculation of this "ceiling test" at December 31, 1991
and March 31, 1992, the Company recorded reserves of
approximately $23 million and $21 million, or an after tax effect
of $.07 and $.09 per share, respectively. At December 31, 1992,
the Company recorded a valuation reserve of $24 million, or an
after tax effect of $.09 per share, in light of a significant
decline in previous estimates of proved reserves as indicated by
lower than expected production volumes. The net investment in
such properties was approximately $101 million at December 31,
1992.
Utility Plant: The cost of additions to utility plant and of
<PAGE>
replacements of retirement units of property is capitalized.
Cost includes direct material, labor, overhead and AFC.
Replacement of minor items of utility plant and the cost of
current repairs and maintenance is charged to expense. Whenever
utility plant is retired, its original cost, together with the
cost of removal, less salvage, is charged to accumulated
depreciation.
Allowance for Funds Used During Construction: The Company
capitalizes AFC in amounts equivalent to the cost of funds
devoted to plant under construction. AFC rates are determined in
accordance with FERC and PSC regulations. The AFC rate in effect
at December 31, 1993 was 6.5%. AFC is segregated into its two
components, borrowed funds and other funds, and is reflected in
the Interest Charges section and the Other Income and Deductions
section, respectively, of the Consolidated Statements of Income.
In 1985, pursuant to PSC authorization, the Company
discontinued accruing AFC on construction work in progress (CWIP)
for which a cash return was being allowed through inclusion in
rate base of that portion of the investment in Unit 2. Amounts
equal to Unit 2's AFC which was no longer accrued have been
accumulated in deferred debit and credit accounts up to the
commercial operation date of Unit 2, (each amounting to $239.9
million at December 31, 1993 and 1992), and await future
ratemaking disposition by the PSC. A portion of the deferred
credit could be utilized to reduce future revenue requirements
over a period shorter than the life of Unit 2, with a like amount
of deferred debit amortized and recovered in rates over the
remaining life of Unit 2.
Depreciation, Amortization and Nuclear Generating Plant
Decommissioning Costs: For accounting and regulatory purposes,
depreciation is computed on the straight-line basis using the
average or remaining service lives by classes of depreciable
property. The total provision for depreciation and amortization,
including amounts charged to clearing accounts, was $277.9
million for 1993, $275.3 million for 1992, and $260.2 million for
1991. The percentage relationship between the total provision
for depreciation and average depreciable property was 3.2% for
1993, 3.3% for 1992 and 3.2% for 1991. The Company performs
depreciation studies on a continuing basis and, upon approval by
the PSC, periodically adjusts the rates of its various classes of
depreciable property.
Estimated decommissioning costs (costs to remove a nuclear
plant from service in the future) for the Company's Unit 1 and
its share of decommissioning costs of Unit 2 are being accrued
over the service life of the Unit, recovered in rates through an
annual allowance and charged to operations through depreciation
(See Note 7. "Nuclear Plant Decommissioning"). The Company
expects to commence decommissioning shortly after cessation of
operations using a method which removes or decontaminates Unit
components promptly.
Amortization of the cost of nuclear fuel is determined on
the basis of the quantity of heat produced for the generation of
electric energy. The cost of disposal of nuclear fuel, which
presently is $.001 per kilowatt-hour of net generation available
<PAGE>
for sale, is based upon a contract with the U.S. Department of
Energy. These costs are charged to operating expense and
recovered from customers through base rates or through the fuel
adjustment clause.
Revenues: Revenues are based on cycle billings rendered to
certain customers monthly and others bi-monthly. Although the
Company commenced the practice in 1988 of accruing electric
revenues for energy consumed and not billed at the end of the
fiscal year, the impact of such accruals has not yet been fully
recognized in the Company's results of operations. At December
31, 1993 and 1992, approximately $95.0 million and $77.8 million,
respectively, of unbilled revenues remained unrecognized in
results of operations and are included in Deferred Credits, and
may be used to reduce future revenue requirements. The amount of
the remaining deferred credit balance fluctuates as the amount of
accrued electric unbilled revenues is recalculated each year end.
At December 31, 1993, pursuant to PSC authorization the Company
accrued $20.9 million of unbilled gas revenues which will
similarly be used to reduce future gas revenue requirements, with
a portion to be used in 1994.
The Company's tariffs include electric and gas adjustment
clauses under which energy and purchased gas costs, respectively,
above or below the levels allowed in approved rate schedules, are
billed or credited to customers. The Company, as authorized by
the PSC, charges operations for energy and purchased gas cost
increases in the period of recovery. The PSC has periodically
authorized the Company to make changes in the level of allowed
energy and purchased gas costs included in approved rate
schedules. As a result of such periodic changes, a portion of
energy costs deferred at the time of change would not be
recovered or may be overrecovered under the normal operation of
the electric and gas adjustment clauses. However, the Company
has been permitted to defer and bill or credit such portions to
customers, through the electric and gas adjustment clauses, over
a specified period of time from the effective date of each
change.
The Company's electric fuel adjustment clause provides for
partial pass-through of fuel and purchased power cost
fluctuations from amounts forecast, with the Company absorbing a
specific portion of increases or retaining a portion of decreases
up to a maximum of $15 million per rate year. Thereafter, 100%
of the fluctuation is to be passed on to ratepayers. The Company
also shares with ratepayers fluctuations from amounts forecast
for net resale margin and transmission benefits, with the Company
retaining/absorbing 20% and passing 80% through to ratepayers.
The amounts absorbed in 1991 through 1993 are not material.
Beginning in 1991, the Company's rate agreements provide for
NERAM, which requires the Company to reconcile actual results to
forecast electric public sales gross margin as defined and
utilized in establishing rates. Depending on the level of actual
sales, a liability to customers is created if sales exceed the
forecast and an asset is recorded for a sales shortfall, thereby
generally holding recorded electric gross margin to the level
forecast in establishing rates. The 1994 rate settlement
<PAGE>
provides for the operation of the NERAM through December 31,
1994. Recovery or refund of accruals pursuant to the NERAM is
accomplished by a surcharge (either plus or minus) to customers
over a twelve month period, to begin when cumulative amounts
reach certain specified levels.
Rate agreements since 1991 also include MERIT, under which
the Company has the opportunity to achieve earnings above its
allowed return on equity based on attainment of specified goals
associated with its self-assessment process. The MERIT program
provides for specific measurement periods and reporting for PSC
approval of MERIT earnings. Approved MERIT awards are billed to
customers over a period not greater than twelve months. The
Company records MERIT earnings when attainment of goals is
approved by the PSC or when objectively measured criteria are
achieved.
Federal Income Taxes: In accordance with PSC requirements, the
tax effect of book and tax timing differences is flowed through
except as required by the Internal Revenue Code or unless
authorized by the PSC to be deferred. As directed by the PSC,
the Company defers any amounts payable pursuant to the
alternative minimum tax rules. The Company has claimed
investment tax credits and deferred the benefits of such credits
as realized in accordance with PSC directives. Deferred
investment credits are amortized to Other Income and Deductions
over the useful life of the underlying property. For purposes of
computing capital cost recovery deductions and normalization, the
asset basis has been reduced by all or a portion of the credit
claimed consistent with then current tax laws.
Since it is the Company's intention to reinvest the
undistributed earnings of its foreign subsidiaries, no provision
is made for federal income taxes on these earnings. At December
31, 1993, the cumulative amount of undistributed earnings of
foreign subsidiaries on which the Company has not provided
deferred taxes was approximately $109 million. It is expected
that the federal income taxes associated with these undistributed
earnings would be substantially reduced by foreign tax credits.
On January 1, 1993, the Company adopted Statement of
Financial Accounting Standards (SFAS) No. 109, Accounting for
Income Taxes. The adoption of SFAS 109 changes the Company's
method of accounting for income taxes from the deferred method to
an asset and liability approach. The asset and liability
approach requires the recognition of deferred tax liabilities and
assets for the expected future tax consequences of temporary
differences between the recorded book bases and the tax bases of
assets and liabilities. The adoption of SFAS 109 did not have a
significant impact on the Company's 1993 results of operations,
and accordingly the effect of adoption has been included in
federal and foreign income taxes.
Amortization of Debt Issue Costs: The premium or discount and
debt expenses on long-term debt issues and on certain debt
retirements prior to maturity are amortized ratably over the
lives of the related issues and included in interest on long-term
debt in accordance with PSC directives.
Statement of Cash Flows: The Company considers all highly liquid
<PAGE>
investments, purchased with a remaining maturity of three months
or less, to be cash equivalents.
Reclassifications: Certain amounts from prior years have been
reclassified on the accompanying Consolidated Financial
Statements to conform with the 1993 presentation.
NOTE 2. BANK CREDIT ARRANGEMENTS
---------------------------------
At December 31, 1993, the Company had $461 million of bank
credit arrangements with 19 banks. These credit arrangements
consisted of $220 million in commitments under Revolving
Credit Agreements (including a Revolving Credit Agreement for
HYDRA-CO Enterprises, Inc., a wholly-owned subsidiary of the
Company), $140 million in one-year commitments under Credit
Agreements, $1 million in lines of credit and $100 million under
a Bankers Acceptance Facility Agreement. The Revolving Credit
Agreements which extend into 1994 are renewed annually, and the
interest rate applicable to borrowing is based on certain rate
options available under the Agreements. All of the other bank
credit arrangements are subject to review on an ongoing basis
with interest rates negotiated at the time of use. The Company
also issues commercial paper. Unused bank credit facilities are
held available to support the amount of commercial paper
outstanding. In addition to these credit arrangements, the
Company obtained $100 million in bank loans which will expire in
1994.
The Company pays fees for substantially all of its bank
credit arrangements. The Bankers Acceptance Facility Agreement,
which is used to finance the fuel inventory for the Company's
generating stations, provides for the payment of fees only at the
time of issuance of each acceptance.
The following table summarizes additional information
applicable to short-term debt:
<PAGE>
<TABLE>
<CAPTION>
In thousands of dollars
At December 31: 1993 1992
Short-term debt:
<S> <C> <C>
Commercial paper $210,016 $ 93,248
Notes payable 153,000 104,450
Bankers acceptances 5,000 30,000
$368,016 $227,698
Weighted average interest rate (a) 3.60% 4.33%
For Year Ended December 31:
Daily average outstanding $165,458 $110,313
Monthly weighted average interest rate (a)
3.72% 4.80%
Maximum amount outstanding $368,016 $227,698
(a) Excluding fees.
</TABLE>
<PAGE>
NOTE 3. JOINTLY-OWNED GENERATING FACILITIES
The following table reflects the Company's share of jointly-
owned generating facilities at December 31, 1993. The Company is
required to provide its respective share of financing for any
additions to the facilities. Power output and related expenses
are shared based on proportionate ownership. The Company's share
of expenses associated with these facilities is included in the
appropriate operating expenses in the Consolidated Statements of
Income.
<PAGE>
<TABLE>
<CAPTION>
In thousands of dollars
Percentage Accumulated Construction
Ownership Utility Plant depreciation work in
progress
<S> <C> <C> <C> <C>
Roseton Steam Station 25 $ 87,691 $ 40,263 $ 760
Units No. 1 and 2 (a). . . . .
Oswego Steam Station
Unit No. 6 (b) . . . . . . . . 76 $ 270,301 $ 97,856 $ 4,207
Nine Mile Point Nuclear
Station Unit No. 2 (c) . . . . 41 $1,504,703 $214,825 $11,434
(a) The remaining ownership interests are Central Hudson Gas and Electric Corporation, the operator of the plant (35%)
and Consolidated Edison Company of New York, Inc. (40%). Central Hudson Gas and Electric Corporation has agreed
to acquire the Company's 25% interest in the plant in ten equal installments of 2.5% (30 mw.) starting on December
31, 1994 and on each December 31 thereafter. The Company then has the option to repurchase its 25% interest in 2004.
The agreement is subject to PSC approval. Output of Roseton Units No. 1 and 2, which have a capability of 1,200,000
kw., is shared in the same proportions as the cotenants' respective ownership interests.
(b) The Company is the operator. The remaining ownership interest is Rochester Gas and Electric Corporation (24%).
Output of Oswego Unit No. 6, which has a capability of 850,000 kw., is shared in the same proportions as the
cotenants' respective ownership interests.
(c) The Company is the operator. The remaining ownership interests are Long Island Lighting Company (18%), New York
State Electric and Gas Corporation (18%), Rochester Gas and Electric Corporation (14%), and Central Hudson Gas and
Electric Corporation (9%). Output of Unit 2, which has a capability of 1,062,000 kw., is shared in the same proportions
as the cotenants' respective ownership interests.
</TABLE>
<PAGE>
NOTE 4. CAPITALIZATION
CAPITAL STOCK
The Company is authorized to issue 150,000,000 shares of
common stock, $1 par value; 3,400,000 shares of preferred stock,
$100 par value; 19,600,000 shares of preferred stock, $25 par
value; and 8,000,000 shares of preference stock, $25 par value.
The table below summarizes changes in the capital stock issued
and outstanding and the related capital accounts for 1991, 1992
and 1993:
<PAGE>
<TABLE>
<CAPTION>
Common Stock Preferred Stock
$1 par value $100 par value
Non-
Shares Amount* Shares Redeemable* Redeemable*
<S> <C> <C> <C> <C> <C>
December 31, 1990: 136,099,654 $136,100 2,548,000 $210,000 $44,800(a)
Issued - - - - -
Redemptions (58,000) - (5,800)
Foreign currency
translation adjustment
December 31, 1991: 136,099,654 136,100 2,490,000 210,000 39,000(a)
Issued 1,059,953 1,060 - - -
Redemptions (78,000) - (7,800)
Foreign currency
translation adjustment
December 31, 1992: 137,159,607 137,160 2,412,000 210,000 31,200(a)
Issued 5,267,450 5,267 - - -
Redemptions (18,000) (1,800)
Foreign currency
translation adjustment
December 31, 1993: 142,427,057 $142,427 2,394,000 $210,000 $29,400 (a)
* In thousands of dollars
(a) Includes sinking fund requirements due within one year.
The cumulative amount of foreign currency translation adjustment at December 31, 1993 was $(7,099).
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Preferred Stock
$25 par value
Non- Capital Stock Premium
Shares Redeemable* Redeemable* and Expense (Net)*
<S> <C> <C> <C> <C>
December 31, 1990: 11,789,204 $80,000 $214,730 (a) $1,649,294
Issued 914,005 - 22,850 -
Redemptions (1,481,204) - (37,030) 340
Foreign currency
translation adjustment 678
December 31, 1991: 11,222,005 80,000 200,550 (a) 1,650,312
Issued - - - 18,401
Redemptions (1,366,000) - (34,150) 796
Foreign currency
translation adjustment (11,494)
December 31, 1992: 9,856,005 80,000 166,400 (a) 1,658,015
Issued - - - 111,497
Redemptions (1,816,000) (45,400) (2,471)
Foreign currency
translation adjustment (4,335)
December 31, 1993: 8,040,005 $80,000 $121,000 (a) $1,762,706
* In thousands of dollars
(a) Includes sinking fund requirements due within one year.
The cumulative amount of foreign currency translation adjustment at December 31, 1993 was $(7,099).
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NON-REDEEMABLE PREFERRED STOCK (Optionally Redeemable)
The Company has certain issues of preferred stock which provide for optional redemption at December 31, as follows:
In thousands of dollars Redemption price per share
(Before adding accumulating dividends)
Series Shares 1993 1992
Preferred $100 par value:
<S> <C> <C> <C> <C>
3.40% 200,000 $ 20,000 $ 20,000 $103.50
3.60% 350,000 35,000 35,000 104.85
3.90% 240,000 24,000 24,000 106.00
4.10% 210,000 21,000 21,000 102.00
4.85% 250,000 25,000 25,000 102.00
5.25% 200,000 20,000 20,000 102.00
6.10% 250,000 25,000 25,000 101.00
7.72% 400,000 40,000 40,000 102.36
Preferred $25 par
value:
Adjustable Rate
Series A 1,200,000 30,000 30,000 25.00
Series C 2,000,000 50,000 50,000 25.75(1)
$290,000 $290,000
(1) Eventual minimum $25.00.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
MANDATORILY REDEEMABLE PREFERRED STOCK
The Company has certain issues of preferred stock which provide for mandatory and optional redemption at December 31,
as follows:
Redemption price per
Shares In thousands of share
dollars (Before adding
accumulated dividends)
Eventual
Series 1993 1992 1993 1992 1993 minimum
Preferred $100 par value:
<S> <C> <C> <C> <C> <C> <C>
7.45% 294,000 312,000 $ 29,400 $ 31,200 $102.65 $100.00
Preferred $25 par value:
7.85% 914,005 914,005 22,850 22,850 (a) 25.00
8.375% 500,000 600,000 12,500 15,000 25.44 25.00
8.70% 600,000 1,000,000 15,000 25,000 25.50 25.00
8.75% 600,000 1,800,000 15,000 45,000 25.50 25.00
9.75% 276,000 342,000 6,900 8,550 25.26 25.00
Adjustable Rate
Series B 1,950,000 2,000,000 48,750 50,000 25.75 25.00
150,400 197,600
Less sinking fund requirements 27,200 27,200
$123,200 $170,400
(a) Not redeemable until 1996.
</TABLE>
<PAGE>
These series require mandatory sinking funds for annual
redemption and provide optional sinking funds through which the
Company may redeem, at par, a like amount of additional shares
(limited to 120,000 shares of the 7.45% series and 300,000 shares
of the 9.75% series). The option to redeem additional amounts is
not cumulative.
The Company's five year mandatory sinking fund redemption
requirements for preferred stock, in thousands, for 1994 through
1998 are as follows: $27,200; $12,200; $14,150; $10,120; and
$10,120, respectively.
<PAGE>
<TABLE>
<CAPTION>
LONG-TERM DEBT
Long-term debt at December 31, consisted of the following:
In thousands of dollars
Series Due 1993 1992
First mortgage bonds:
<S> <C> <C> <C>
8 7/8% 1994 $ 150,000 $ 150,000
4 5/8% 1994 40,000 40,000
5 7/8% 1996 45,000 45,000
6 1/4% 1997 40,000 40,000
**9 7/8% 1998 - 200,000
6 1/2% 1998 60,000 60,000
10 1/4% 1999 100,000 100,000
10 3/8% 1999 100,000 100,000
9 1/2% 2000 150,000 150,000
**7 3/8% 2001 - 65,000
9 1/4% 2001 100,000 100,000
**7 5/8% 2002 - 80,000
**7 3/4% 2002 - 80,000
5 7/8% 2002 230,000 -
6 7/8% 2003 85,000 -
<PAGE>
7 3/8% 2003 220,000 220,000
**8 1/4% 2003 - 80,000
8% 2004 300,000 300,000
6 5/8% 2005 110,000 -
9 3/4% 2005 150,000 150,000
**8.35% 2007 - 66,640
**8 5/8% 2007 - 30,000
*6 5/8% 2013 45,600 45,600
*11 1/4% 2014 75,690 75,690
*11 3/8% 2014 40,015 40,015
9 1/2% 2021 150,000 150,000
8 3/4% 2022 150,000 150,000
8 1/2% 2023 165,000 165,000
7 7/8% 2024 210,000 -
*8 7/8% 2025 75,000 75,000
Total First Mortgage Bonds 2,791,305 2,757,945
Promissory notes:
*Adjustable Rate Series due
July 1, 2015 100,000 100,000
December 1, 2023 69,800 69,800
December 1, 2025 75,000 75,000
December 1, 2026 50,000 50,000
<PAGE>
March 1, 2027 25,760 25,760
July 1, 2027 93,200 93,200
Unsecured notes payable:
Medium Term Notes, Various rates, 55,500 87,700
due 1993-2004
Swiss Franc Bonds due December 15, 50,000 50,000
1995
Oswego Facilities Trust - 90,000
Other 176,888 157,829
Unamortized premium (discount) (12,656) (8,453)
TOTAL LONG-TERM DEBT 3,474,797 3,548,781
Less long-term debt due within one 216,185 57,722
year
$3,258,612 $3,491,059
*Tax-exempt pollution control related issues
**Retired prior to maturity
</TABLE>
<PAGE>
Several series of First Mortgage Bonds and Notes were issued
to secure a like amount of tax-exempt revenue bonds issued by the
New York State Energy Research and Development Authority
(NYSERDA). Approximately $414 million of such notes bear
interest at a daily adjustable interest rate (with a Company
option to convert to other rates including a fixed interest rate
which would require the Company to issue First Mortgage Bonds to
secure the debt) which averaged 2.14% for 1993 and 2.43% for 1992
and are supported by bank direct pay letters of credit. Pursuant
to agreements between NYSERDA and the Company, proceeds from such
issues were used for the purpose of financing the construction of
certain pollution control facilities at the Company's generating
facilities or refund outstanding tax-exempt bonds and notes.
The $115.7 million of tax-exempt bonds due 2014 will be
refinanced at 7.2% during 1994 pursuant to a forward refunding
agreement entered into in 1992.
Notes Payable include a Swiss franc bond issue maturing in
1995 equivalent to $50 million in U.S. funds. Simultaneously
with the sale of these bonds, the Company entered into a currency
exchange agreement to fully hedge against currency exchange rate
fluctuations.
Other long-term debt in 1993 consists of obligations under
capital leases of approximately $45.3 million (See Note 8.
"Lease Commitments"), a liability to the U.S. Department of
Energy for nuclear fuel disposal of approximately $93.5 million
(See Note 7. "Nuclear Fuel Disposal Costs") and liabilities for
unregulated generator contract termination of approximately $38.1
million.
Certain of the Company's debt securities provide for a
mandatory sinking fund for annual redemption. The aggregate
maturities of long-term debt for the five years subsequent to
December 31, 1993, excluding capital leases, are approximately
$211 million, $73 million, $61 million, $46 million and $66
million, respectively.
NOTE 5. PENSION AND OTHER RETIREMENT PLANS
-------------------------------------------
The Company and certain of its subsidiaries have non-
contributory, defined-benefit pension plans covering
substantially all their employees. Benefits are based on the
employee's years of service and compensation level. The pension
cost was $16.9 million for 1993, $23.2 million for 1992 and $23.9
million for 1991 ($5.6 million for 1993, $6.2 million for 1992
and $6.0 million for 1991 was related to construction labor and,
accordingly, was charged to construction projects). The
Company's general policy is to fund the pension costs accrued
with consideration given to the maximum amount that can be
deducted for Federal income tax purposes. Contributions are
intended to provide not only for benefits attributed to service
to date but also for those expected to be earned in the future.
<PAGE>
<TABLE>
<CAPTION>
Net pension cost for 1993, 1992 and 1991 included the following components:
In thousands of dollars
1993 1992 1991
<S> <C> <C> $ <C>
Service cost - benefits earned during the period. . . . $ 30,100 27,100 $ 27,000
Interest cost on projected benefit obligation . . . . . 54,200 48,800 43,500
Actual return on Plan assets . . . . . . . . . . . . . (106,100) (59,600) (116,600)
Net amortization and deferral . . . . . . . . . . . . . 38,700 6,900 70,000
Net pension cost. . . . . . . . . . . . . . . . . . . . $ 16,900 $ 23,200 $ 23,900
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
The following table sets forth the plan's funded status and amounts recognized in the Company's Consolidated
Balance Sheets:
In thousands of dollars
At December 31, 1993 1992
Actuarial present value of accumulated benefit obligations:
<S> <C> <C>
Vested benefits. . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 501,900 $ 419,582
Non-vested benefits. . . . . . . . . . . . . . . . . . . . . . . . . . 64,973 46,563
Accumulated benefit obligations . . . . . . . . . . . . . . . . . . . . . . 566,873 466,145
Additional amounts related to projected pay increases . . . . . . . . . . . 236,906 193,630
Projected benefits obligation for service rendered to date. . . . . . . . . 803,779 659,775
Plan assets at fair value, consisting primarily of listed stocks,
bonds, other fixed income obligations and insurance contracts. . . . . 913,200 796,843
Plan assets in excess of projected benefit obligations. . . . . . . . . . . 109,421 137,068
Unrecognized net obligation at January 1, 1987 being recognized over
approximately 19 years . . . . . . . . . . . . . . . . . . . . . . . . 32,392 35,184
Unrecognized net gain from actual return on plant assets different from
that assumed. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (114,536) (84,077)
Unrecognized net gain from past experience different from that assumed
and effects of changes in assumptions amortized over 10 years. . . . . (39,652) (90,636)
Prior service cost not yet recognized in net periodic pension cost. . . . . 49,613 36,092
<PAGE>
Pension costs included in the consolidated balance sheets . . . . . . . . . $ 37,238 $ 33,631
</TABLE>
<PAGE>
In 1993 and 1992, the discount rate and rate of increase
in future compensation levels used in determining the
actuarial present value of the projected benefit obligations
were 7.3% and 8.25% and 3.25% and 4.25% (plus merit
increases), respectively. The expected long-term rate of
return on plan assets was 9.00% in 1993 and 1992.
In addition to providing pension benefits, the Company and
its subsidiaries provide certain health care and life
insurance benefits for active and retired employees and
dependents. Under current policies, substantially all of the
Company's employees may be eligible for continuation of some
of these benefits upon normal or early retirement. These
benefits are provided through insurance companies whose
charges and premiums are based on the claims paid during the
year.
On January 1, 1993, the Company adopted SFAS No. 106,
Employers' Accounting for Postretirement Benefits Other Than
Pensions (OPEB). This Statement requires accrual accounting
by employers for postretirement benefits other than pensions
reflecting currently earned benefits. During 1993 the
Company established various trust funds to begin the funding
of the OPEB obligation. The Company made an initial
contribution, equal to the amount received in 1993 rates, of
approximately $12 million and anticipates contributing
approximately $23 million in 1994.
Net postretirement benefit cost for 1993 included the
following components:
In
thousands
of dollars
1993
Service cost - benefits attributed to
service during the period $12,300
Interest cost on accumulated
benefit obligation 32,800
Amortization of the transition
obligation over 20 years 20,400
Net postretirement benefit cost
$65,500
<PAGE>
The following table sets forth the plan's funded status
and amounts recognized in the Company's Consolidated Balance
Sheet:
In thousands of dollars
At December 31, 1993
Actuarial present value of accumulated benefit
obligation:
Retired and surviving spouses $224,936
Active eligible 73,474
Active ineligible 220,420
Accumulated benefit obligation 518,830
Plan assets at fair value, consisting primarily of
cash equivalents 11,967
Accumulated postretirement benefit obligation in
excess of plan assets 506,863
Unrecognized net loss from past experience
different from that assumed and effects of changes 82,756
in assumptions
Unrecognized transition obligation to be amortized
over 20 years 388,600
Accrued postretirement benefit liability included $35,507
in the consolidated balance sheet
At December 31, 1993, a pre-65 and post-65 health care
cost trend rate of 10.05% and 7.05%, respectively, was
assumed, trending down to 4.8% by 1999. If the health care
cost trend rate was increased by one percent, the accumulated
postretirement benefit obligation as of December 31, 1993
would increase by approximately 8.7% and the aggregate of the
service and interest cost component of net periodic
postretirement benefit cost for the year would increase by
approximately 7.8%. The discount rate used in determining
the accumulated postretirement benefit obligation was 7.3%.
During 1993, the PSC issued a Statement of Policy (SOP)
regarding the accounting for pension and postretirement
costs. With respect to postretirement benefits, the PSC
mandated a transition to full accrual accounting in rates
over a period not to exceed five years, with recovery of any
resultant deferrals over a period not to exceed twenty years
from the year of adoption. In accordance with its rate
agreement and the SOP, the Company has a $30.7 million
<PAGE>
regulatory asset at December 31, 1993 relating to the rate
transition for postretirement costs. The SOP requires
deferral of the difference between actual costs and rate
allowances and ten year amortization of actuarial gains and
losses for both pensions and postretirement costs effective
January 1, 1993. The 1993 pension cost was reduced by
approximately $8 million to reflect the effect of the change
in the amortization period of an actuarial gain of $90.6
million as of January 1, 1993. The Company does not expect
the true-up requirements or the change to amortization of
actuarial gains and losses to have a material impact on its
periodic benefit costs or results of operations.
In November 1992, the FASB issued SFAS No. 112 "Employees'
Accounting for Postemployment Benefits" which is effective
for fiscal years beginning after December 15, 1993. This
Statement, which the Company will adopt for 1994, requires
employers to recognize the obligation to provide
postemployment benefits if the obligation is attributable to
employees' past services, rights to those benefits are
vested, payment is probable and the amount of the benefits
can be reasonably estimated. The Company typically accounts
for such costs on a cash basis. The Company estimates the
postemployment benefit obligation to be approximately $11.4
million at January 1, 1994. In its 1994 rates, the Company
has included approximately $2.9 million, including capital,
representing the pay-as-you-go portion of the postemployment
benefit. The difference between the postemployment benefit
obligation and the rate allowance will be deferred, with the
proposed recovery occurring equally over three years
beginning in 1995. The Company believes that these costs
will be recovered based on current ratemaking principles.
<PAGE>
NOTE 6. FEDERAL AND FOREIGN INCOME TAXES
Components of United States and foreign income before income
taxes:
In thousands of dollars
1993 1992 1991
United States $438,914 $410,283 $394,596
Foreign (24,845) 18,394 (6,252)
Consolidating eliminations 4,837 (16,741) (11,080)
Income before income taxes $418,906 $411,936 $377,264
Following is a summary of the components of Federal and
foreign income tax and a reconciliation between the amount
of Federal income tax expense reported in the Consolidated
Statements of Income and the computed amount at the
statutory tax rate:
Summary Analysis: In thousands of dollars
COMPONENTS OF FEDERAL AND FOREIGN INCOME TAXES:
1993 1992 1991
Current tax expense:
Federal $118,918 $119,929 $ 75,452
Foreign 8,445 915 597
127,363 120,844 76,049
Deferred tax expense:
Federal 35,152 54,858 74,983
Foreign - 7,531 7,105
35,152 62,389 82,088
Income taxes included in
Operating Expenses: 162,515 183,233 158,137
Current Federal and foreign
income tax credits included
in Other Income and
Deductions (16,061) (31,787) (24,734)
Deferred Federal and foreign
income tax expense
(credits) included in Other
Income and Deductions 621 4,058 492
Total $147,075 $155,504 $133,895
<PAGE>
COMPONENTS OF DEFERRED FEDERAL AND FOREIGN INCOME TAXES
(NOTE 1):
Depreciation related $ 78,467 $ 90,897
Investment tax credit (8,067) (8,137)
Alternative minimum tax (1,197) (27,276)
Recoverable energy and
purchased gas costs (1,926) 8,066
Deferred operating expenses 10,867 (2,179)
Nuclear settlement
disallowance 20,099 12,865
MERIT recovery (4,263) 9,935
Opinac reserve for oil and (19,706) (13,083)
gas properties
Bond reacquisition premium 7,379 -
Other (15,206) 11,492
Deferred Federal income
taxes (net) $ 66,447 $ 82,580
RECONCILIATION BETWEEN FEDERAL AND FOREIGN INCOME TAXES AND
THE TAX COMPUTED AT PREVAILING U.S. STATUTORY RATE ON
INCOME BEFORE INCOME TAXES:
Computed tax $146,617 $140,058 $128,270
Reduction (increase) attributable to flow-through of
certain tax adjustments:
Depreciation
(35,153) (37,543) (36,440)
Allowance for funds used
during construction 2,951 11,205 7,540
Cost of removal 7,822 6,845 5,781
Deferred investment tax
credit amortization 8,018 8,024 7,891
Other 15,904 (3,977) 9,603
(458) (15,446) (5,625)
Federal and foreign income
taxes $147,075 $155,504 $133,895
<PAGE>
The Omnibus Budget Reconciliation Act of 1993 (OBRA of
1993) was signed into law in August 1993. One of the
provisions of the OBRA of 1993 raises the federal corporate
statutory tax rate from 34% to 35%, retroactive to January
1, 1993. A provision of the 1993 Settlement provides for the
deferral of the effects of tax law changes.
SFAS 109 increased the accumulated deferred income tax
liability at January 1, 1993 by approximately $507 million,
represented substantially by tax benefits flowed-through to
rate payers in prior years (in the form of lower rates) upon
which deferred taxes had not been provided. At December 31,
1993, the deferred tax liabilities (assets) were comprised of
the following:
(In thousands)
Alternative minimum tax $ (95,071)
Other (208,217)
Total deferred tax assets (303,288)
Depreciation related 1,318,600
Investment tax credit related 108,140
Other 190,031
Total deferred tax liabilities 1,616,771
Accumulated deferred income taxes $1,313,483
The Company believes that the more significant effects of
adopting this pronouncement are (i) providing deferred taxes
for tax benefits flowed through to ratepayers, (ii)
adjustment of deferred tax assets and liabilities for enacted
changes in tax law or rates and (iii) prohibition of net-of-
tax accounting.
The Company routinely collects the increased tax liability
from previously flowed-through tax benefits. In addition,
the PSC issued effective January 15, 1993 a Statement of
Interim Policy on Accounting and Ratemaking Procedures to
implement SFAS 109. The statement required adoption of SFAS
109 on a revenue-neutral basis, recognizing the PSC's policy
of rate recovery when prior flow-through items reverse. The
Company has recorded income taxes recoverable, a regulatory
asset, in the amount of approximately $528 million, which is
comprised of previously flowed-through tax benefits, and
offset by temporary differences associated with deferred
investment tax credits and excess deferred taxes established
at tax rates greater than 35%. Substantially all of the
excess deferred taxes relate to property and are not subject
to immediate refund to customers in accordance with federal
law.
N O T E 7 . N U C L E A R
<PAGE>
OPERATIONS ----------
The Company is the owner and operator of the 613 MW Unit 1
and the operator and a 41% co-owner of the 1,062 MW Unit 2.
Unit 1 was placed in commercial operation in 1969 and Unit 2
in 1988.
Unit 1 Economic Study: Under the terms of a previous
regulatory agreement, the Company agreed to prepare and
update studies of the advantages and disadvantages of
continued operation of Unit 1 prior to the start of the next
two refueling outages. The first report, which recommended
continued operation of Unit 1 over the remaining term of its
license (2009), was filed with the PSC in March 1990.
On November 20, 1992 the Company submitted to the PSC an
updated economic analysis which indicated that Unit 1 can be
expected to provide value to customers and shareholders
through its next fuel cycle, which will end in early 1995.
The study also indicated that the Unit could continue to
provide benefits for the full term of its license if
operating costs can be reduced and generating output improved
above its historical average.
The study analyzed a number of scenarios resulting in
break-even capacity factors, ranging from 44% to 122%. The
"base case" assumes a capacity factor of 61%, consistent with
the target reflected in the Unit 1 operating incentive
mechanism, and also assumes future operating and capital
costs slightly lower than historical performance. While a
marginal benefit would be realized from operating the Unit
for at least the next two years (one fuel cycle) under the
"base case," there would be a negative net present value in
excess of $100 million if the Unit were to be operated over
its remaining 17-year license period. Under an "improved
performance case", the Unit is assumed to operate at a 70%
capacity factor with future operating and capital costs
consistent with average industry performance. The Company
believes these goals are achievable for Unit 1, as indicated
by Unit 1 operating and financial performance in 1993 that
was better than the improved performance case. The "improved
performance case" results in positive net present value in
excess of $100 million if the Unit is operated over its
remaining life. Such results demonstrate the volatility of
the assumptions and uncertainties involved in developing the
Unit's economic forecast. These assumptions include various
levels of the Unit's capacity factor, operating and capital
costs, demand for electricity, supply of electricity
including unregulated generator power, implementation and
compliance costs of the Clean Air Act and other federal and
state environmental requirements and fuel availability and
prices, especially natural gas. Given the potential for
rapid and substantial change in any or all of these
assumptions, the Company has developed operational and
external criteria, other than refueling, which would initiate
a prompt reassessment of the economic viability of the Unit.
<PAGE>
An agreement with the PSC allows recovery of all
reasonable and prudently-incurred sunk costs and costs of
retirement, should a prudent decision be made to retire Unit
1 before early 1995. All parties to the 1991 Agreement
reserve the right to petition the PSC to institute a formal
investigation to review the prudence of any Company decision
to retire Unit 1. Any such decision by the Company will be
made in consultation with governmental and regulatory
authorities. The Company's net investment in Unit 1 is
approximately $580 million, exclusive of decommissioning
costs. See Nuclear Plant Decommissioning.
Unit 1 Status: On February 20, 1993, Unit 1 was taken out of
service for a planned 55 day refueling and maintenance
outage. On April 15, 1993, Unit 1 returned to service ahead
of schedule. The next refueling outage is scheduled to begin
in February 1995. Unit 1's capacity factor for 1993 was
approximately 81%.
Unit 2 Status: On October 2, 1993, Unit 2 was taken out of
service for a planned 60 day refueling and maintenance
outage. On November 29, 1993, Unit 2 returned to service
ahead of schedule. The next refueling outage is scheduled to
begin in the spring of 1995. Unit 2's capacity factor for
1993 was approximately 78%.
Nuclear Plant Decommissioning: Based on a 1989 study, the
cost of decommissioning Unit 1, which is expected to begin in
the year 2009, is estimated by the Company to be
approximately $416 million at that time ($257 million in 1993
dollars). The Company's 41% share of the total cost to
decommission Unit 2, expected to begin in 2027, is estimated
by the Company to be approximately $316 million ($109 million
in 1993 dollars). The annual decommissioning allowance
reflected in ratemaking is based upon these estimates, which
include amounts for both radioactive and non-radioactive
dismantlement costs. The non-radioactive dismantlement costs
are estimated in the 1989 study to be $24 million for Unit 1
and $18 million for its share of Unit 2, in 1993 dollars.
Decommissioning costs recovered in rates are reflected in
Accumulated Depreciation and Amortization on the Balance
Sheet and amount to $113.9 million and $90.5 million at
December 31, 1993 and 1992, respectively. The annual
allowance for Unit 1 and the Company's share of Unit 2 for
the years ended December 31, 1993, 1992 and 1991 was
approximately $18.7, $23.1 and $23.0 million, respectively.
The Company will update its Unit 1 decommissioning study
in 1994 in support of the update of the Unit 1 economic
study. The Unit 2 decommissioning study is also expected to
be updated in 1994. Rate allowance adjustments will be
sought when appropriate. There is no assurance that the
decommissioning allowance recovered in rates will ultimately
aggregate a sufficient amount to decommission the units.
However, the Company believes that if decommissioning costs
are higher than currently estimated they would ultimately be
recovered in the rate process.
<PAGE>
The NRC issued regulations in 1988 requiring owners of
nuclear power plants to place funds into an external trust to
provide for the cost of decommissioning contaminated portions
of nuclear facilities as well as establishing minimum amounts
that must be available in such a trust for these specified
decommissioning activities at the time of decommissioning.
As of December 31, 1993, the Company has accumulated in an
external trust $63.1 million for Unit 1 and $15.4 million for
its share of Unit 2, which are included in Other Property and
Investments. Earnings on such investments aggregated $8.6
million through December 31, 1993 and, because they are
available to fund decommissioning, have also been included in
Accumulated Depreciation and Amortization. Amounts recovered
for non-radioactive dismantlement are accumulated in an
internal reserve fund which has an accumulated balance of
$35.4 million at December 31, 1993.
Based upon studies applying the 1988 NRC regulations, the
Company had estimated that the minimum funding requirements
for Unit 1 and its share of Unit 2, respectively, would be
$191 million and $87 million in 1993 dollars. In May 1993,
the NRC established new labor, energy and burial cost factors
for determining the NRC minimum funding requirements. A
substantial increase in burial costs, partly offset by
reduced estimates in the volumes of waste to be disposed,
increased the NRC minimum requirement for Unit 1 to $372
million in 1993 dollars and the Company's share of Unit 2 to
$169 million in 1993 dollars. The Company has requested an
annual aggregate increase of approximately $10 million in the
Unit 1 and Unit 2 decommissioning allowances as part of its
1995 rate request, to reflect the increased NRC minimum
requirements.
Nuclear Liability Insurance: The Atomic Energy Act of 1954,
as amended, requires the purchase of nuclear liability
insurance from the Nuclear Insurance Pools in amounts as
determined by the NRC. At the present time, the Company
maintains the required $200 million of nuclear liability
insurance.
In August 1993, the statutory liability limits for the
protection of the public under the Price-Anderson Amendments
Act of 1988 (the Act) were further increased. With respect
to a nuclear incident at a licensed reactor, the statutory
limit, which is in excess of the $200 million of nuclear
liability insurance, was increased to approximately $8.8
billion. This limit would be funded by assessments of up to
$75.5 million for each of the 116 presently licensed nuclear
reactors in the United States, payable at a rate not to
exceed $10 million per reactor per year. Such assessments
are subject to periodic inflation indexing and to a 5%
surcharge if funds prove insufficient to pay claims.
The Company's interest in Units 1 and 2 could expose it to
a potential loss, for each accident, of $106.5 million
through assessments of $14.1 million per year in the event of
a serious nuclear accident at its own or another licensed
U.S. commercial nuclear reactor. The amendments also
<PAGE>
provide, among other things, that insurance and indemnity
will cover precautionary evacuations whether or not a nuclear
incident actually occurs.
Nuclear Property Insurance: The Nine Mile Point Nuclear Site
has $500 million primary nuclear property insurance with the
Nuclear Insurance Pools (ANI/MRP). In addition, there is
$800 million in excess of the $500 million primary nuclear
insurance with the Nuclear Insurance Pools (ANI/MRP) and $1.4
billion, which is also in excess of the $500 million primary
and the $800 million excess nuclear insurance, with Nuclear
Electric Insurance Limited (NEIL). NEIL is a utility
industry-owned mutual insurance company chartered in Bermuda.
The total nuclear property insurance is $2.7 billion. NEIL
also provides insurance coverage against the extra expense
incurred in purchasing replacement power during prolonged
accidental outages. The insurance provides coverage for
outages for 156 weeks after a 21 week waiting period.
NEIL insurance is subject to retrospective premium
adjustment under which the Company could be assessed up to
approximately $11.3 million per loss.
Low Level Radioactive Waste: The Federal Low Level
Radioactive Waste Policy Act requires states to join compacts
or individually develop their own low level radioactive waste
disposal site. In response to the Federal law, New York
State decided to develop its own site because of the large
volume of low level radioactive waste it generates and
committed by January 1, 1993 to develop a plan for the
management of low level radioactive waste in New York State
during the interim period until a disposal facility is
available.
New York State is developing disposal methodology and
acceptance criteria for a disposal facility. A revised New
York State low level radioactive waste site development
schedule now assumes two possible siting scenarios, a
volunteer approach and a non-volunteer approach, either of
which would begin operation in 2001. An extension of access
to the Barnwell, South Carolina waste disposal facility was
made available to out-of-region low level radioactive waste
generators by the state of South Carolina through June 30,
1994, and New York State has elected to use this option. The
Company has a low level radioactive waste management program
and contingency plan so that Unit 1 and Unit 2 will be
prepared to properly handle interim on-site storage of low
level radioactive waste for at least a 10 year period, if
required.
Nuclear Fuel Disposal Cost: In January 1983, the Nuclear
Waste Policy Act of 1982 (the Nuclear Waste Act) established
a cost of $.001 per kilowatt-hour of net generation for
current disposal of nuclear fuel and provides for a
determination of the Company's liability to the Department of
Energy (DOE) for the disposal of nuclear fuel irradiated
prior to 1983. The Nuclear Waste Act also provides three
payment options for liquidating such liability and the
Company has elected to delay payment, with interest, until
<PAGE>
1998, the year in which the Company had initially planned to
ship irradiated fuel to an approved DOE disposal facility.
Progress in developing the DOE facility has been slow and it
is anticipated that the DOE facility will not be ready to
accept deliveries until at least 2010. The Company does not
anticipate that the DOE will accept all of its spent fuel
immediately upon opening of the facility, but rather expects
a transfer period of as long as 20 years. With Unit 1
expected to be retired in 2009, the Company must consider
some form of storage if it intends to begin immediate
dismantlement. The Company has several alternatives under
consideration to provide additional storage facilities, as
necessary. Each alternative will likely require NRC
approval, may require other regulatory approvals and would
likely require the incurrance of additional costs. The
Company does not believe that the possible unavailability of
the DOE disposal facility until 2006 will inhibit operation
of either Unit.
The Energy Policy Act provides for the establishment of a
federal decontamination and decommissioning fund to provide
for the environmentally safe closure of DOE uranium
processing facilities, funded in part by nuclear utilities.
The Company has recorded its estimated liability to this fund
based on prior DOE nuclear fuel processing services it
received and its initial assessment during 1993. The
liability is expected to be recovered as a fuel expense as
provided by the Act and is payable over 14 years ending in
2007, with annual assessments indexed for inflation.
NOTE 8. COMMITMENTS AND CONTINGENCIES
--------------------------------------
Construction Program: The Company is committed to an ongoing
construction program to assure reliable delivery of its
electric and gas services. The Company presently estimates
that the construction program for the years 1994 through 1998
will require approximately $1.57 billion, excluding AFC,
nuclear fuel and certain overheads capitalized. For the
years 1994 through 1998, the estimates are $408 million, $295
million, $287 million, $291 million and $285 million,
respectively. These amounts are reviewed by management as
circumstances dictate.
Long-term Contracts for the Purchase of Electric Power: At
January 1, 1994,the Company had long-term contracts to
purchase electric power from the following generating
facilities owned by the New York Power Authority (NYPA):
<PAGE>
<TABLE>
<CAPTION>
Purchased Estimated annual
Facility Expiration date of capacity capacity cost
contract in kw.
<S> <C> <C> <C>
Niagara - hydroelectric project . . . . . 2007 928,000 $20,300,000
St. Lawrence - hydroelectric project. . . 2007 104,000 1,300,000
Blenheim-Gilboa - pumped storage
generating station. . . . . . . . . . . 2002 270,000 7,500,000
Fitzpatrick - nuclear plant . . . . . . . year-to-year
basis 40,000 (a) 7,200,000
1,342,000 $36,300,000
(a) 40,000 kw for summer of 1994; 63,000 kw for winter of 1994-95.
</TABLE>
<PAGE>
The purchase capacities shown above are based on the
contracts currently in effect. The estimated annual capacity
costs are subject to price escalation and are exclusive of
applicable energy charges. The total cost of purchases under
these contracts was approximately $72.2 million, $64.4
million and $61.2 million for the years 1993, 1992 and 1991,
respectively.
Under the requirements of the Federal Public Utility
Regulatory Policies Act of 1978, the Company is required to
purchase power generated by unregulated generators, as
defined therein. Of the 147 facilities providing energy to
the Company at December 31, 1993, five require the Company to
make capacity payments, including payments when a production
plant is not operating, and are subject to price escalation.
Each facility must meet certain availability and performance
obligations prior to receiving capacity payments. The terms
of these five contracts allow the Company to schedule energy
deliveries from the facilities and then pay for the energy
that is delivered. These five facilities account for
approximately 380,000 kw of capacity with contract lengths
ranging from 20 to 35 years. The total cost of purchases
under these five contracts in 1993 was $56.6 million and the
1994 estimated annual capacity and energy payments are
estimated to be approximately $105.5 million and $50 million,
respectively, subject to scheduling, the availability and
tested capacity of these facilities, and price escalation.
Capacity payments under these five contracts for 1995 to 1998
would be $109 million, $120 million, $127 million and $130
million, respectively and would aggregate to approximately
$3.5 billion over the terms of the contracts. Contracts
relating to the remaining facilities in service at December
31, 1993, require the Company to pay only when energy is
delivered.
The Company paid approximately $736 million (including the
amount discussed above), $543 million and $268 million in
1993, 1992 and 1991 for 11,720,000 mwhrs, 8,632,000 mwhrs and
4,303,000 mwhrs, respectively, of energy under all
unregulated generator contracts.
Through December 31, 1993, the Company had entered into
agreements with current and prospective unregulated
generators for approximately 2,400 MW of capacity. The
ultimate amount of the commitment and the available capacity
are dependent upon the completion of these projects. Based
upon these contracts as of December 31, 1993, the Company
estimates that it will be obligated to make payments to
unregulated generators of (in millions): $932 in 1994,
$1,057 in 1995, $1,111 in 1996, $1,174 in 1997 and $1,220 in
1998. The Company recovers all payments to unregulated
generators through base rates or through the FAC.
Sale of Customer Receivables: The Company has an agreement
whereby it can sell an undivided interest in a designated
pool of customer receivables, including accrued unbilled
<PAGE>
electric revenues, up to a maximum of $200 million. At
December 31, 1993 and 1992, respectively, $200 million of
receivables had been sold under this agreement. 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. To the extent actual loss experience of the pool
receivables exceeds the loss reserve, the purchaser absorbs
the excess. 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.
Tax assessments: The Internal Revenue Service (IRS) has
conducted an examination of the Company's Federal income tax
returns for the years 1987 and 1988 and has submitted a
Revenue Agents' Report to the Company. The IRS has proposed
various adjustments to the Company's federal income tax
liability for these years which could increase the Federal
income tax liability by approximately $80 million before
assessment of penalties and interest. Included in these
proposed adjustments are several significant issues involving
Unit 2. The Company is vigorously defending its position on
each of the issues, and submitted a protest to the IRS in
1993. Pursuant to the Unit 2 settlement entered into in
1990, to the extent the IRS is able to sustain disallowances,
the Company will be required to absorb a portion of any
disallowance. The Company believes any such disallowance
will not have a material impact on its financial position or
results of operations.
Litigation: On March 22, 1993, a complaint was filed in the
Supreme Court of the State of New York, Albany County,
against the Company and certain of its officers and
employees. The plaintiff, Inter-Power of New York, Inc.
(Inter-Power), alleges, among other matters, fraud, negligent
misrepresentation and breach of contract in connection with
the Company's alleged termination of a power purchase
agreement in January 1993. The power purchase agreement was
entered into in early 1988 in connection with a 200 MW
cogeneration project to be developed by Inter-Power in
Halfmoon, New York. The plaintiff is seeking enforcement of
the original contract or compensatory and punitive damages on
fourteen causes of action in an aggregate amount that would
not exceed $1 billion, excluding pre-judgment interest.
The Company believes it has done no wrong, and intends to
vigorously defend against this action. On May 7, 1993, the
Company filed an answer denying liability and raising certain
affirmative defenses. Thereafter, the Company and Inter-
Power filed cross-motions for summary judgement. The court
dismissed two of Inter-Power's fourteen causes of action but
otherwise denied the Company's motion. The court also
dismissed two of the Company's affirmative defenses and
otherwise denied Inter-Power's cross-motion. Both parties
have filed Notices of Appeals regarding these dismissals.
<PAGE>
Discovery is in progress. The ultimate outcome of the
litigation cannot presently be determined.
On November 12, 1993, Fourth Branch Associates
Mechanicville ("Fourth Branch"), filed suit against the
Company and several of its officers and employees in the New
York Supreme Court, Albany County, seeking compensatory
damages of $50 million, punitive damages of $100 million and
injunctive and other related relief. The suit grows out of
the Company's termination of a contract for Fourth Branch to
operate and maintain a hydroelectric plant the Company owns
in the Town of Halfmoon, New York. Fourth Branch's complaint
also alleges claims based on the inability of Fourth Branch
and the Company to agree on terms for the purchase of power
from a new facility that Fourth Branch hoped to construct at
the Mechanicville site. On January 3, 1994, the defendants
filed a joint motion to dismiss Fourth Branch's complaint.
The Company believes that it has substantial defenses to
Fourth Branch's claims, but is unable to predict the outcome
of this litigation.
Accordingly, no provision for liability, if any, that may
result from either of these suits has been made in the
Company's financial statements. Environmental Contingencies:
The public utility industry typically utilizes and/or
generates in its operations a broad range of potentially
hazardous wastes and by-products. These wastes or by-
products may not have previously been considered hazardous,
and may not be considered hazardous currently, but may be
identified as such by Federal, state or local authorities in
the future. The Company believes it is handling identified
wastes and by-products in a manner consistent with Federal,
state and local requirements and has implemented an
environmental audit program to identify any potential areas
of concern and assure compliance with such requirements. The
Company is also currently conducting a program to investigate
and restore, as necessary to meet current environmental
standards, certain properties associated with its former gas
manufacturing process and other properties which the Company
has learned may be contaminated with industrial waste, as
well as investigating identified industrial waste sites as to
which it may be determined that the Company contributed. The
Company has been advised that various Federal, state or local
agencies believe that certain properties require
investigation and has prioritized the sites based on
available information in order to enhance the management of
investigation and remediation, if determined to be necessary.
The Company is currently aware of 82 sites with which it
has been or may be associated, including 42 which are
Company-owned. The Company-owned sites include 23 former
coal gasification (MGP) sites, 14 industrial waste sites and
5 operating property sites where corrective actions may be
deemed necessary to prevent, contain and/or remediate
contamination of soil and/or water in the vicinity. Of these
Company-owned sites, Saratoga Springs is on the Federal
National Priorities List for Uncontrolled Hazardous Waste
<PAGE>
Sites (NPL) as published by the Environmental Protection
Agency in the Federal Register. The 40 non-owned sites with
which the Company has been or may be associated are generally
industrial waste sites where the Company is alleged to be a
PRP and may be required to contribute some proportionate
share towards investigation and clean-up. Not included in
the 82 sites are seven sites where the Company has reached
settlement agreements with other PRP's and three sites where
remediation activities have been completed. There also exist
approximately 20 formerly-owned MGP sites with which the
Company has been or may be associated that may require future
investigation and remediation. To date, the Company has not
been made aware of any claims. Also, approximately 22 fire
training sites owned or used by the Company have been
identified but not investigated. Presently, the Company is
unable to determine its potential involvement with such sites
and has made no provision for liability, if any, at this
time.
Investigations at each of the Company-owned sites are
designed to (1) determine if environmental contamination
problems exist, (2) determine the extent, rate of movement
and concentration of pollutants, (3) if necessary, determine
the appropriate remedial actions required for site
restoration and (4) where appropriate, identify other parties
who should bear some or all of the cost of remediation.
Legal action against such other parties, if necessary, will
be initiated. After site investigations have been completed,
the Company expects to determine site-specific remedial
actions necessary and to estimate the attendant costs for
restoration. However, since technologies are still
developing and the Company has not yet undertaken any full-
scale remedial actions following regulatory requirements at
any identified sites, nor have any detailed remedial designs
been prepared or submitted to appropriate regulatory
agencies, the ultimate cost of remedial actions may change
substantially as investigation and remediation progresses.
The Company has estimated that it is probable that 36 of
the 42 owned sites will require some degree of investigation,
remediation and monitoring. This conclusion is based upon a
number of factors, including the nature of the identified or
potential contaminants, the location and size of the site,
the proximity of the site to sensitive resources, the status
of regulatory investigation and knowledge of activities at
similarly situated sites. Although the Company has not
extensively investigated many of those sites, it believes it
has sufficient information to estimate a range of cost of
investigation and remediation. As a consequence of site
characterizations and assessments completed to date, the
Company has accrued a liability of $210 million for these
owned sites, representing the low end of the range of the
estimated cost for investigation and remediation. The high
end of the range is presently estimated at approximately $520
million.
The majority of these cost estimates relate to the MGP
<PAGE>
sites. Of the 23 MGP sites, Harbor Point (Utica, NY) and
Saratoga Springs are subject to regulatory enforcement
actions and to date have remedial investigation and/or
feasibility study work in progress. The remaining 21 MGP
sites are the subject of an Order on Consent executed with
the New York State Department of Environmental Conservation
(DEC) providing for an investigation and remediation program
over approximately ten years. Preliminary site assessments
have been conducted or are in process at five of these 21
sites, with remedial investigations either currently in
process or scheduled for 1994. Remedial investigations were
also conducted for two industrial waste sites and for three
operating properties where corrective actions were considered
necessary.
The Company does not currently believe that a clean-up
will be required at the 6 remaining Company-owned sites,
although some degree of investigation of these sites is
included in its investigation and remediation program.
With respect to the 40 sites with which the Company has
been or may be associated as a PRP, 9 are on the NPL. Total
costs to investigate and remediate the sites with which the
Company is associated as a PRP are estimated to be
approximately $590 million; however, the Company estimates
its share of this total at approximately $30 million and this
amount has been accrued at December 31, 1993.
The seven settlement agreements reached with other PRP's
were settled in an amount not material to the Company. Two
of these (Ludlow Landfill and Wide Beach) are on the NPL and
have been settled by the Company in an aggregate amount of
less than $300,000. For the 9 sites included on the NPL, the
Company's potential contribution factor varies for each site.
The estimated aggregate liability for these sites is not
material and is included in the determination of the amounts
accrued.
Estimates of the Company's potential liability for PRP
sites are derived by estimating the total cost of site clean-
up and then applying the related Company contribution factor
to that estimate. Estimates of the total clean-up costs are
determined by using the Company's investigation to date, if
any, discussions with other PRPs and, where no information is
known at the time of estimate, the Environmental Protection
Agency (EPA) estimates based on average costs disclosed in
the Federal Register of June 23, 1993. The contribution
factor is calculated using either the Company's percentage
share based upon the total number of PRPs named or otherwise
identified, which assumes all PRPs will contribute equally,
or the percentage agreed upon with other PRPs through
steering committee negotiations or by other means. Actual
Company expenditures for these sites are dependent upon the
total cost of investigation and remediation and the ultimate
determination of the Company's share of responsibility for
such costs as well as the financial viability of other
identified responsible parties since clean-up obligations are
joint and several. The Company has denied any responsibility
<PAGE>
in certain of these PRP sites and is contesting liability
accordingly.
The EPA advised the Company by letter that it is one of
833 PRPs under Superfund for the investigation and cleanup of
the Maxey Flats Nuclear Disposal Site in Morehead, Kentucky.
The Company has contributed to a study of this site and
estimates that the cost to the Company for its share of
investigation and remediation based on its contribution
factor of 1.3% would approximate $1 million, which the
Company believes will be recoverable in the ratesetting
process.
On July 21, 1988, the Company received notice of a motion
by Reynolds Metals Company to add the Company as a third
party defendant in an ongoing Superfund lawsuit in Federal
District Court, Northern District of New York. This suit
involves PCB oil contamination at the York Oil Site in Moira,
New York. Waste oil was transported to the site during the
1960's and 1970's by contractors of Peirce Oil Company
(owners/operators of the site) who picked up waste oil at
locations throughout Central New York, allegedly including
one or more Company facilities. On May 26, 1992, the Company
was formally served in a Federal Court action initiated by
the government against 8 additional defendants. Pursuant to
the requirements of a case management order issued by the
Court on March 13, 1992, the Company has also been served in
related third and fourth-party actions for contribution
initiated by other defendants. Discovery is now in progress.
The goal of this effort is to provide adequate information to
form a basis for achieving a voluntary allocation of
liability among the parties.
The Company believes that costs incurred in the
investigation and restoration process for both Company-owned
sites and sites with which it is associated will be
recoverable in the ratesetting process. Rate agreements in
effect since 1991 provide for recovery of anticipated
investigation and remediation expenditures, although the PSC
Staff reserves the right to review the appropriateness of the
costs incurred. While the PSC Staff has not challenged any
remediation costs to date, the PSC Staff asserted in the
recently-decided gas rate proceeding that the Company must,
in future rate proceedings, justify why it is appropriate
that remediation costs associated with non-utility property
owned by the Company be recovered from ratepayers. The
Company's 1994 rate settlement includes $21.7 million for
site investigation and remediation. Based upon management's
assessment that remediation costs will be recovered from
ratepayers, a regulatory asset has been recorded representing
the future recovery of remediation obligations accrued to
date.
The Company also agreed in rate agreements to a cost
sharing arrangement with respect to one industrial waste
site. The Company does not believe that this cost sharing
agreement, as it relates to this particular industrial waste
site, will have a material effect on the Company's financial
<PAGE>
position or results of operations.
The Company is also in the process of providing notices of
insurance claims to carriers with respect to the
investigation and remediation costs for manufactured gas
plant and industrial waste sites. The Company is unable to
predict whether such insurance claims will be successful.
Federal Energy Regulatory Commission Order 636: In 1992, the
FERC issued Order 636, which requires interstate pipelines to
unbundle pipeline sales services from pipeline transportation
service. These changes enable the Company to arrange for its
gas supply directly with producers, gas marketers or
pipelines, at its discretion, as well as arrange for
transportation and gas storage services.
As a result of these structural changes, pipelines face
"transition" costs from implementation of the Order. The
principal costs are: unrecovered gas cost that would
otherwise have been billable to pipeline customers under
previously existing rules, costs related to restructuring
existing gas supply contracts and costs of assets needed to
implement the order (such as meters, valves, etc.). Under
the Order, pipelines are allowed to recover 100% of prudently
incurred costs from customers. Prudence will be determined
by FERC review.
The amount of restructuring costs ultimately billed to the
Company will be determined in accordance with pipeline
restructuring plans which have been submitted to the FERC for
approval. There are four pipelines to which the Company has
some liability. The Company is actively participating in
FERC hearings on these matters to ensure an equitable
allocation of costs. The restructuring costs will be
primarily reflected in demand charges paid to reserve space
on the various interstate pipelines and will be billed over a
period of approximately 7 years, with billings more heavily
weighted to the first 3 years.
Based upon information presently available to the Company
from the petitions filed by the pipelines, the Company's
participation in settlement negotiations, and the three
settlements to which it is a party, its liability for the
pipelines' unrecovered gas costs is expected to be as much as
$31 million and its liability for pipeline restructuring
costs could be as much as $38 million. The Company has
recorded a liability of $31 million at December 31, 1993,
representing the low end of the range of such transition
costs. The Company is unable to predict the final outcome of
current pipeline restructuring settlements and the ultimate
amounts for which it will be liable or the period over which
this liability will be billed.
Based upon Management's assessment that transition costs
will be recovered from ratepayers, a regulatory asset has
been recorded representing the future recovery of transition
costs accrued to date. Currently, such costs billed to the
Company are treated as a cost of purchased gas and
recoverable through the operation of the gas adjustment
clause mechanism.
<PAGE>
NOTE 9 - DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL
INSTRUMENTS ------------------------------------------------
------------
The following methods and assumptions were used to estimate
the fair value of each class of financial instruments:
Cash and short-term investments: The carrying amount
approximates fair value because of the short maturity of the
financial instruments.
Long-term investments: The carrying value and market value
are not material to the financial statements.
Mandatorily redeemable preferred stock: Fair value of the
mandatorily redeemable preferred stock has been determined by
one of the Company's brokers or estimated by management based
on discounted cash flows.
Long-term debt: The fair value of the Company's long-term
debt has been estimated by one of the Company's brokers. The
carrying value of NYSERDA bonds, the Oswego Facilities Trust
and other long-term debt are considered to approximate fair
value.
The estimated fair values of the Company's financial
instruments are as follows:
<PAGE>
<TABLE>
<CAPTION>
December 31,
(In thousands of dollars)
1992
1993
Carrying Carrying
Amount Fair Value Amount Fair
Value
<S> <C> <C> <C> <C>
Cash and short-term investments $ 124,351 $ 124,351 $ 43,894 $ 43,894
Mandatorily redeemable preferred stock 150,400 155,326 197,600 199,114
2,791,305 2,969,228 2,757,945 2,888,022
Long-term debt: First Mortgage Bonds
55,500 62,458 87,700 93,890
Medium Term Notes
413,760 413,760 413,760 413,760
NYSERDA bonds
Swiss franc bond 50,000 73,794 50,000 62,374
Other 131,587 131,587 104,665 104,665
Oswego Facilities Trust - - 90,000 90,000
</TABLE>
<PAGE>
NOTE 10. INFORMATION REGARDING THE ELECTRIC AND GAS
BUSINESSES
The Company is engaged in the electric and natural gas
utility businesses. Certain information regarding these
segments is set forth in the following table. General
corporate expenses, property common to both segments and
depreciation of such common property have been allocated to
the segments in accordance with practice established for
regulatory purposes. Identifiable assets include net utility
plant, materials and supplies, deferred finance charges,
deferred recoverable energy costs and certain other deferred
debits. Corporate assets consist of other property and
investments, cash, accounts receivable, prepayments,
unamortized debt expense and other deferred debits.
<PAGE>
<TABLE>
<CAPTION>
In thousands of dollars
1993 1992 1991
Operating revenues:
<S> . . . . . . . . . . . <C> <C> <C>
Electric . . . . . . . . . $3,332,464 $3,147,676 $2,907,293
Gas . . . . . . . . . . . . 600,967 553,851 475,225
Total . . . . . . . . . $3,933,431 $3,701,527 $3,382,518
Operating income before taxes:
Electric . . . . . . . . . $ 625,852 $ 645,696 $ 644,084
Gas . . . . . . . . . . . . 61,163 61,863 39,487
Total . . . . . . . . . $ 687,015 $ 707,559 $ 683,571
Pretax operating income, including AFC:
Electric . . . . . . . . . $ 641,435 $ 666,269 $ 662,258
Gas . . . . . . . . . . . . 61,812 62,721 40,244
Total . . . . . . . . . 703,247 728,990 702,502
Income taxes, included in operating expenses:
Electric . . . . . . . . . 148,695 176,901 152,840
Gas . . . . . . . . . . . 13,820 6,332 5,297
Total . . . . . . . . . 162,515 183,233 158,137
Other (income) and deductions 22,475 (11,391) (10,643)
Interest charges . . . . . 291,376 300,716 311,639
Net income . . . . . . . . $ 271,831 $ 256,432 $ 243,369
Depreciation and amortization:
Electric . . . . . . . . . $ 255,718 $ 255,256 $ 240,887
Gas . . . . . . . . . . . . 20,905 18,834 17,929
Total . .. . . . . . . . . $ 276,623 $ 274,090
$258,816
Construction expenditures
(including nuclear fuel):
Electric . . . . . . . . . $ 429,265 $ 442,741 $ 445,298
<PAGE>
Gas . . . . . . . . . . . . 90,347 59,503 77,176
Total . . . . . . . . . $ 519,612 $ 502,244 $ 522,474
Identifiable assets:
Electric . . . . . . . . . $7,042,762 $7,000,659 $6,760,375
Gas . . . . . . . . . . . . 926,648 783,766 725,553
Total . . . . . . . . . 7,969,410 7,784,425 7,485,928
Corporate assets . . . . 1,449,667 806,110 755,548
Total assets . . . . . $9,419,077 $8,590,535 $8,241,476
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NOTE 11. Quarterly Financial Data (Unaudited)
Operating revenues, operating income, net income and earnings per
common share by quarters from 1993, 1992 and 1991, respectively, are
shown in the following table. The Company, in its opinion, has included
all adjustments necessary for a fair presentation of the results of
operations for the quarters. Due to the seasonal nature of the utility
business, the annual amounts are not generated evenly by quarter during
the year.
In thousands of dollars
Earnings
Quarter Operating Operating Net per
Ended revenues income income common share
<S> <C> <C> <C> <C>
December 31, 1993 $ 988,195 $ 73,466 $ 30,955 $ .16
1992 963,629 119,181 41,835 .24
1991 848,593 117,139 35,111 .18
September 30, 1993 $ 879,952 $108,539 $ 48,595 $ .29
1992 822,530 89,658 40,401 .23
1991 734,446 102,627 40,783 .23
June 30, 1993 $ 929,245 $154,826 $ 65,325 $ .41
1992 881,427 137,515 71,734 .46
1991 807,024 127,159 57,691 .35
March 31, 1993 $1,136,039 $187,669 $ 126,956 $ .86
1992 1,033,941 177,972 102,462 .68
1991 992,455 178,509 109,784 .73
</TABLE>
<PAGE>
In the second quarter of 1992 and the third quarter of 1993
and 1991, the Company recorded $22.8 million ($.11 per common
share), $10.3 million ($.05 per common share) and $30 million
($.14 per common share), respectively, for MERIT earned in
accordance with the 1991 Agreement. In the first quarter of
1992 and the fourth quarter of 1992 and 1991, the Company
recorded $21 million ($.09 per common share), $24 million
($.09 per common share) and $23 million ($.07 per common
share), respectively, to write-down its subsidiary investment
in oil and gas properties.
<PAGE>
<TABLE>
<CAPTION>
ELECTRIC AND GAS STATISTICS
ELECTRIC CAPABILITY
Thousands of kilowatts
December 31, 1993 % 1992 1991
Owned:
<S> <C> <C> <C> <C>
Coal 1,285 14.4 1,285 1,285
Oil 1,496 16.8 1,496 1,961
Dual Fuel - Oil/Gas 700 7.8 700 400
Nuclear 1,048 11.8 1,059 1,059
Hydro 700 7.8 706 708
Natural Gas 74 .8 108 164
5,303 59.4 5,354 5,577
Purchased:
New York Power Authority (NYPA)
- Hydro 1,302 14.6 1,302 1,283
- Nuclear 65 .7 67 76
Unregulated generators 2,253 25.3 1,549 1,027
3,620 40.6 2,918 2,386
Total capability * 8,923 100.0 8,272 7,963
Electric peak load 6,191 6,205 6,093
* Available capability can be increased during heavy load periods by purchases from
neighboring interconnected systems. Hydro station capability is based on average
December stream-flow conditions.
<PAGE>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
ELECTRIC STATISTICS
1993 1992 1991
Electric sales (Millions of kw-hrs.):
<S> <C> <C> <C>
Residential . . . . . . . . . . . . . . . . . . 10,475 10,392 10,321
Commercial . . . . . . . . . . . . . . . . . . 12,079 11,628 11,686
Industrial . . . . . . . . . . . . . . . . . . 7,088 7,477 7,578
Industrial-Special. . . . . . . . . . . . . . . 3,888 3,857 3,784
Municipal service . . . . . . . . . . . . . . . 220 227 228
Other electric systems. . . . . . . . . . . . . 3,974 3,030 3,141
37,724 36,611 36,738
Electric revenues (Thousands of dollars):
Residential . . . . . . . . . . . . . . . . . . $1,171,787 $1,096,418 $ 985,347
Commercial . . . . . . . . . . . . . . . . . . 1,241,743 1,160,643 1,044,725
Industrial . . . . . . . . . . . . . . . . . . 553,921 589,258 521,670
Industrial-Special. . . . . . . . . . . . . . . 42,988 39,409 35,264
Municipal service . . . . . . . . . . . . . . . 50,642 50,327 47,566
Other electric systems . . . . . . . . . . . . 105,044 93,283 106,066
Miscellaneous . . . . . . . . . . . . . . . . . 166,339 118,338 166,655
<PAGE>
$3,332,464 $3,147,676 $2,907,293
Electric customers (Average):
Residential . . . . . . . . . . . . . . . . . . 1,398,756 1,389,470 1,378,484
Commercial. . . . . . . . . . . . . . . . . . . 143,078 142,345 145,098
Industrial. . . . . . . . . . . . . . . . . . . 2,132 2,197 2,220
Industrial-Special. . . . . . . . . . . . . . . 76 72 63
Other . . . . . . . . . . . . . . . . . . . . . 3,438 3,262 3,231
1,547,480 1,537,346 1,529,096
Residential (Average):
Annual kw-hr. use per customer. . . . . . . . . 7,489 7,479 7,487
Cost to customer per kw-hr (cents). . . . . . . 11.19 10.55 9.55
Annual revenue per customer . . . . . . . . . . $837.74 $789.09 $714.80
</TABLE>
<PAGE>
GAS STATISTICS
1993 1992 1991
Gas Sales (Thousands of
dekatherms):
Residential . . . . . . . .
. . . . . . . . 54,908 53,945 48,172
Commercial . . . . . . . .
. . . . . . . . 23,743 22,289 20,226
Industrial . . . . . . . .
. . . . . . . . 4,316 1,772 1,812
Other gas systems . . . . .
. . . . . . . . 234 1,190 1,519
Total sales . . . . .
. . . . . . . . 83,201 79,196 71,729
Spot market . . . . . . . . -
. . . . . . . . 13,223 1,146
Transportation of customer- 50,631
owned gas . . . 67,741 65,845
Total gas delivered .
. . . . . . . . 164,165 146,187 122,360
Gas Revenues (Thousands of
dollars):
Residential . . . . . . . .
. . . . . . . . $370,565 $354,429 $302,900
Commercial . . . . . . . .
. . . . . . . . 144,834 132,609 113,727
<PAGE>
Industrial . . . . . . . .
. . . . . . . . 18,482 10,001 8,430
Other gas systems . . . . .
. . . . . . . . 1,066 4,737 6,964
Spot market . . . . . . . . -
. . . . . . . . 29,782 2,576
Transportation of customer- 36,455
owned gas . . . 34,843 42,726
Miscellaneous . . . . . . .
. . . . . . . . 1,395 6,773 6,749
$600,967 $553,851 $475,225
Gas Customers (Average):
Residential . . . . . . . .
. . . . . . . . 455,629 446,571 438,581
Commercial . . . . . . . .
. . . . . . . . 39,662 38,675 37,727
Industrial . . . . . . . .
. . . . . . . . 233 234 260
Other . . . . . . . . . . .
. . . . . . . . 1 1 2
Transportation . . . . . .
. . . . . . . . 673 673 625
496,198 486,154 477,195
Residential (Average):
Annual dekatherm use per
customer . . . . . 120.5 120.8 109.8
<PAGE>
Cost to customer per
dekatherm . . . . . . $6.75 $6.57 $6.29
Annual revenue per customer
. . . . . . . . $813.30 $793.67 $690.64
Maximum day gas sendout
(dekatherms) . . . 929,285 905,872 852,404
<PAGE>
<TABLE>
<CAPTION> Exhibit 11
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARIES
COMPUTATION OF AVERAGE NUMBER OF SHARES OF COMMON STOCK OUTSTANDING
Average Number
of Shares
(1) (2) Outstanding as
Shares of Number (3) Shown on Consolidated
Common of Days Share Days Statement of Income
Year Ended December 31, Stock Outstanding (2 x 1) (3/Number of days in year)
1993
<S> <C> <C> <C> <C>
January 1 - May 4 137,159,607 124 17,007,791,268
Shares sold May 5 4,494,000
May 5 - December 31 141,653,607 241 34,138,519,287
Shares sold at various times
during the year -
Employee Savings Fund Plan 140,000 22 3,080,000
Dividend Reinvestment Plan 632,341 * 102,395,031
Acquisition - Syracuse
Suburban Gas Company, Inc. 1,109 * 350,374
142,427,057 51,252,135,960 140,416,811
1992
January 1 - December 31 136,099,654 366 49,812,473,364
<PAGE>
Shares sold at various times
during the year -
Employee Savings Fund Plan 240,866 * 45,435,347
Dividend Reinvestment Plan 463,736 * 59,130,626
Acquisition - Syracuse
Suburban Gas Company, Inc. 355,351 * 67,443,538
137,159,607 49,984,482,875 136,569,625
1991
January 1 - December 31 136,099,654 365 49,676,373,710 136,099,654
* Number of days outstanding not shown as shares represent an accumulation of weekly, monthly
and quarterly sales throughout the year. Share days for shares sold are based on
the total number of days each share was outstanding during the year.
Note: Earnings per share calculated on both a primary and fully diluted basis are the same due to the
effects of rounding.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Exhibit 12
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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
Year Ended December 31,
1993 1992 1991 1990 1989
<S> <C> <C> <C> <C> <C>
A. Net Income per Statements of Income (a) $271,831 $256,432 $243,369 $ 82,878 $150,783
B. Taxes Based on Income or Profits 147,075 155,504 133,895 61,119 90,333
C. Earnings, Before Income Taxes 418,906 411,936 377,264 143,997 241,116
D. Fixed Charges (b) 319,197 332,413 346,255 347,957 337,552
E. Earnings Before Income Taxes and Fixed
Charges 738,103 744,349 723,519 491,954 578,668
F. Allowance for Funds Used During
Construction 16,232 21,431 18,931 21,414 19,376
G. Earnings Before Income Taxes and Fixed
Charges without AFC $721,871 $722,918 $704,588 $470,540 $559,292
Preferred Dividend Factor:
H. Preferred Dividend Requirements $ 31,857 $ 36,512 $ 40,411 $ 42,300 $ 45,182
<PAGE>
I. Ratio of Pre-Tax Income to Net Income
(C / A) 1.54 1.61 1.55 1.74 1.60
J. Preferred Dividend Factor (H x I) $ 49,060 $ 58,784 $ 62,637 $ 73,602 $ 72,291
K. Fixed Charges as above (D) 319,197 332,413 346,255 347,957 337,552
L. Fixed Charges and Preferred Dividends
Combined $368,257 $391,197 $408,892 $421,559 $409,843
M. Ratio of Earnings to Fixed Charges
(E / D) 2.31 2.24 2.09 1.41 1.71
N. Ratio of Earnings to Fixed Charges
without AFC (G / D) 2.26 2.17 2.03 1.35 1.66
O. Ratio of Earnings to Fixed Charges and 2.00 1.90 1.77 1.17 1.41
Preferred Dividends Combined (E / L)
(a) Includes the effects of amortization of amounts deferred, under the 1989 Agreement,$15,746 for 1993, $20,257 for
1992 and $31,176 for 1991.
(b) Includes a portion of rentals deemed representative of the interest factor $27,821 for 1993, $31,697 for 1992,
$34,616 for 1991, $29,088 for 1990 and $30,496 for 1989.
</TABLE>
<PAGE>
EXHIBIT 24
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the
Prospectus constituting part of the Registration Statements on
Form S-8 (Nos. 33-36189, 33-42720, 33-42721 and 33-42771) and on
Form S-3 (Nos. 33-45898, 33-50703, 33-51073 and 33-55546) of
Niagara Mohawk Power Corporation of our report dated January 27,
1994 appearing on page 43 of the financial statements included in
the Company's Form 8-K dated February 18, 1994.
PRICE WATERHOUSE
Syracuse, New York
February 18, 1994
<PAGE>
SIGNATURE
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.
Date: February 18, 1994
NIAGARA MOHAWK POWER CORPORATION
By /s/ Steven W. Tasker
-------------------------
Steven W. Tasker
Vice President-Controller
and Principal Accounting
Officer
<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_________________
AMENDMENT NUMBER 1
TO FORM T-1
STATEMENT OF ELIGIBILITY UNDER THE TRUST
INDENTURE ACT OF 1939 OF A CORPORATION
DESIGNATED TO ACT AS TRUSTEE
CHECK IF AN APPlICATION TO DETERMINE
ElIGIBIlITY OF A TRUSTEE PURSUANT TO
SECTION 305(b)(2)
__________________
Marine Midland Bank
(Exact name of trustee as specified in its charter)
16-1057879
(I.R.S. Employer
Identification No.)
140 Broadway, New York, N.Y. 10005-1180
(212) 658-1000 (Zip Code)
(Address of principal executive offices)
Niagara Mohawk Power Corporation
(Exact name of obligor as specified in its charter)
New York 15-0265555
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
300 Erie Boulevard West
Syracuse, New York 13202
(315) 474-1511 (Zip Code)
(Address of principal executive offices)
First Mortgage Bonds
(Title of Indenture Securities)
General
Item 1. General Information.
Furnish the following information as to the trustee:
(a) Name and address of each examining or supervisory authority to
which it is subject.
State of New York Banking Department.
Federal Deposit Insurance Corporation, Washington, D.C.
Board of Governors of the Federal Reserve System, Washington,
D.C.
(b) Whether it is authorized to exercise corporate trust powers.
Yes.
Item 2. Affiliations with Obligor.
If the obligor is an affiliate of the trustee, describe each such
affiliation.
None.
Item 16. List of Exhibits.
T1A(i) - Copy of the Organization Certificate of Marine Midland Bank.
T1A(ii) - Certificate of the State of New York Banking Department dated
December 31,1993 as to the authority of Marine Midland Bank to
commence business.
T1A(iii) - Not applicable.
T1A(iv) - Copy of the existing By-laws of Marine Midland Bank as adopted
on January 20,1994.
T1A(v) - Not applicable.
T1A(vi) - Consent of Marine Midland Bank required by Section 321(b) of
the Trust Indenture Act of 1939.
T1A(vii) - Copy of the latest report of condition of the trustee
(December 31,1993), published pursuant to law or the
requirement of its supervisory or examining authority.
T1A(viii) - Not applicable.
T1A(ix) - Not applicable.
SIGNATURE
Pursuant to the requirements of the Trust Indenture Act of 1939, the Trustee,
Marine Midland Bank, a trust company organized under the laws of the State of
New York, has duly caused this statement of eligibility to be signed on its
behalf by the undersigned, thereunto duly authorized, all in the City of New
York and State of New York on the 10th day of February, 1994.
MARINE MIDLAND BANK
By: /s/ Metin Caner
--------------------------------
Metin Caner
Assistant Vice President
EXHIBIT T1A(i)
ORGANIZATION CERTIFICATE
of
"MARINE MIDLAND BANK"
We, the undersigned, all being of full age, all but one of us being
citizens of the United States and all of us being residents of the State of
New York, having associated ourselves together for the purpose of forming a
trust company under and pursuant to the Banking Law of the State of New York,
do hereby certify:
First. That the name by which the corporation is to be known is
Marine Midland Bank.
Second. That the place where its principal office is to be located
is Buffalo, New York.
Third. That the amount of its capital stock is to be One Hundred
Eighty-five Million and no/100 Dollars ($185,000,000.00) and the number of
shares into which such capital stock is to be divided is 1,850,000 with a par
value of $100.00 each.
Fourth. The shares are not to be classified as preferred and
common.
If the shares are to be so classified,
(a) The number and par value of shares to be included in each
class are as follows: not applicable.
(b) All the designations, preferences, privileges and voting
powers of the shares of each class, and the restrictions or
qualifications thereof are as follows: not applicable.
(c) The number of shares of common stock which are to be
reserved for issuance in exchange for preferred shares or otherwise to
replace any capital stock represented by preferred shares is none.
Fifth. The name, place of residence and citizenship of each
incorporator, and the number of shares subscribed for by each are:
No. of
Full Name Residence *Citizenship Shares
--------- --------- ------------ ------
James H. Cleave New York Canada 0
John M. Endries New York New York 0
Bernard J. Kennedy New York New York 0
Northrup R. Knox New York New York 0
Henry J. Nowak New York New York 0
- ------------------
* If a citizen of New York or a contiguous state, insert name of such
state.
Sixth. The term of existence of the corporation is to be
perpetual.
Seventh. The number of directors is to be not less than seven or
more than thirty.
Eighth. The names of the incorporators who shall be the directors
until the first annual meeting of stockholders are: James H. Cleave, John M.
Endries, Bernard J. Kennedy, Northrup R. Knox and Henry J. Nowak.
Ninth. The corporation is to exercise the powers conferred by
Section 100 of the Banking Law.
IN WITNESS WHEREOF, We have made, signed and acknowledged this
certificate in duplicate, this 16th day of September, 1993.
/s/ James H. Cleave
- -----------------------------
/s/ John M. Endries
- -----------------------------
/s/ Bernard J. Kennedy
- -----------------------------
/s/ Northrup R. Knox
- -----------------------------
/s/ Henry J. Nowak
- -----------------------------
STATE OF NEW YORK )
) ss.:
COUNTY OF ERIE )
On this 16th day of September, 1993, personally appeared before me
James H. Cleave, John M. Endries, Bernard J. Kennedy, Northrup R. Knox and
Henry J. Nowak, to me known to be the persons described in and who executed
the foregoing certificate and severally acknowledged that they executed the
same.
/s/ Helen Kujawa
--------------------------------
Notary Public
(Attach County Clerk's certificate
authenticating signature of Notary [NOTARIAL SEAL]
Public who takes acknowledgement)
Ninth. The corporation is to exercise the powers conferred by
Section 100 of the Banking Law.
IN WITNESS WHEREOF, We have made, signed and acknowledged this
certificate in duplicate, this 16th day of September, 1993.
/s/ James H. Cleave
- ------------------------------
/s/ John M. Endries
- ------------------------------
/s/ Bernard J. Kennedy
- ------------------------------
/s/ Northrup R. Knox
- ------------------------------
/s/ Henry J. Nowak
- ------------------------------
STATE OF NEW YORK )
) ss.:
COUNTY OF ERIE )
I, David J. Swarts, Clerk of the County of Erie, and also Clerk of
the Supreme and County Courts for said County, the same being Courts of
Record, do hereby certify that HELEN KUJAWA, whose name is subscribed to the
deposition certificate of acknowledgement of proof of the annexed instrument,
was at the time of taking the same a NOTARY PUBLIC in and for the State of
New York, duly commissioned and sworn and qualified to act as such throughout
the State of New York; that pursuant to law a commission, or a certificate of
his appointment and qualifications and his autograph signature, have been
filed in my office; that as such Notary Public he was duly authorized by the
laws of the State of New York to administer oaths and affirmations to receive
and certify that acknowledgement of proof of deeds, mortgages, powers of
attorney and other written instruments for lands, tentaments and
heriditaments to be read in evidence or recorded in this State, to protect
notes and to take and certify affidavits and depositions; and that I am well
acquainted with the handwriting of such Notary Public, or have compared the
signature on the annexed instrument and with his autograph signature
deposited in my office, and believe that the signature is genuine.
IN WITNESS WHEREOF, I have hereunto set my hand and affixed the
seal of said County and Courts at Buffalo, this 17th day of September, 1993.
[SEAL]
N.P. No. 7502 /s/ David S. Swarts
------------------------------
David J. Swarts
Clerk
ORGANIZATION CERTIFICATE
of
"MARINE MIDLAND BANK"
Received this _____ day of ______________, 19____.
Superintendent of Banks
Filed for examination this _____ day of ______________, 19____.
Superintendent of Banks
________________________ by the Banking Board at a meeting held on
the _____ day of ______________, 19____.
Secretary of the Banking Board
_____________________________________________________ this _____
day of ______________, 19____.
Superintendent of Banks
Filed in the office of _______________________________ this _____
day of ______________, 19____.
Recorded in the office of ____________________________ this _____
day of ______________, 19____.
EXHIBIT T1A(ii)
STATE OF NEW YORK
BANKING DEPARTMENT
KNOW ALL MEN BY THESE PRESENTS,
WHEREAS, the organization certificate of MARINE MIDLAND BANK of
Buffalo, New York has heretofore been duly approved and said MARINE MIDLAND
BANK has complied with the provisions of Chapter 2 of the Consolidated Laws,
in respect of the conversion of MARINE MIDLAND BANK, N.A. into a State trust
company under the name MARINE MIDLAND BANK,
NOW THEREFORE, I, DERICK D. CEPHAS, as Superintendent of Banks of
the State of New York, do hereby authorize the said MARINE MIDLAND BANK to
transact the business of a Trust Company at One Marine Midland Center,
Buffalo, Erie County, within this State.
IN WITNESS WHEREOF, I have hereunto set my hand and affixed the
official seal of the Banking Department, this 31st day of December in the
year one thousand nine hundred and ninety-three.
[SEAL]
/s/ Derrick D. Cephas
-------------------------------
Superintendent
(Adopted January 20, 1994)
EXHIBIT T1A (iv)
BY-LAWS
of
MARINE MIDLAND BANK
ARTICLE I
STOCKHOLDERS' MEETINGS
Section 1.1 Annual Meeting. The annual meeting of the
stockholders for the election of directors and the transaction of such other
business as may properly come before the meeting shall be held in April each
year at the office of the Bank, One Marine Midland Center, City of Buffalo,
State of New York.
Section 1.2 Special Meetings. Except as otherwise specifically
provided by statute, special meetings of the stockholders may be called for
any purpose at any time by the Board of Directors, the Chairman of the Board,
the President, the Chief Executive Officer or the Secretary at such place and
time and on such day as may be designated in the notice of meeting. Business
transacted at all special meetings of stockholders shall be confined to the
purposes stated in the notice of meeting.
Section 1.3 Quorum. The holders of a majority of the stock issued
and outstanding, and entitled to vote thereat, present in person or
represented by proxy, shall constitute a quorum at all meetings of
stockholders, unless otherwise provided by law.
Section 1.4 Voting.
a. At any meeting of the stockholders each stockholder may vote in
person or by proxy duly authorized in writing. Each stockholder shall at
every meeting of stockholders be entitled to one vote for each share of stock
held by such stockholder. A majority of the votes cast shall decide every
question or matter submitted to the stockholders at any meeting, unless
otherwise provided by law or by the Organization Certificate.
b. Any action required to be taken at an annual or special meeting
of stockholders may be taken without a meeting by written consent setting
forth the action and signed by the holders of all of outstanding shares
entitled to vote thereon.
Section 1.5 Notice of Meeting. Written notice of each meeting of
stockholders stating the place, date and hour of the meeting and, in the case
of a special meeting, the purpose or purposes for which the meeting is called
and the person or persons calling the meeting, shall be delivered personally
or shall be mailed postage prepaid to each stockholder entitled to vote at
such meeting, directed to the stockholder at his or her address as it appears
on the records of the Bank, not less than ten or more than 50 days before the
date of the meeting.
ARTICLE II
DIRECTORS
Section 2.1 Board of Directors. The Board of Directors (the
"Board") shall have power to manage and administer the business and affairs
of the Bank and, except as expressly limited by law, all corporate powers of
the Bank shall be vested in and may be exercised by the Board unless such
powers are required by statute, the Organization Certificate or these By-Laws
to be exercised by the stockholders.
Section 2.2 Number and Term. The Board shall consist of not less
than seven or more than thirty directors, the exact number within such
minimum and maximum limits to be fixed and determined from time to time by
resolution of a majority of the entire Board or by resolution of the
stockholders at any meeting of stockholders. Unless sooner removed or
disqualified, each director shall hold office until the next annual meeting
of the stockholders and until the director's successor has been elected and
qualified.
Section 2.3 Organization Meeting. At its first meeting after each
annual meeting of stockholders, the Board shall choose a Chairman of the
Board, a President and a Chief Executive Officer from its own members and
otherwise organize the new Board and appoint officers of the Bank for the
succeeding year.
Section 2.4 Chairman of the Board. The Chairman of the Board
shall preside at all meetings of the Board and of stockholders and perform
such duties as shall be assigned from time to time by the Board. In the
absence of the Chairman of the Executive Committee, the Chairman of the Board
shall act as Chairman of the Executive Committee. Except as may be otherwise
provided by the By-Laws or the Board, the Chairman of the Board shall be a
member ex officio of all committees authorized by these By-Laws or the Board.
The Chairman of the Board shall be kept informed by the executive officers
about the affairs of the Bank.
Section 2.5 Regular Meetings. The regular meetings of the Board
shall be held each month at the time and location designated by the Board.
No notice of a regular meeting shall be required if the meeting is held
according to a schedule of regular meetings approved by the Board.
Section 2.6 Special Meetings. Special meetings of the Board may
be called by the Chairman of the Board, the President, the Chief Executive
Officer or the Secretary or at the written request of any three or more
directors. Each member of the Board shall be given notice stating the time
and place of each such special meeting by telegram, telephone or similar
electronic means or in person at least one day prior to such meeting, or by
mail at least three days prior.
Section 2.7 Quorum. One third of the entire Board shall
constitute a quorum at any meeting, except when otherwise provided by law.
If a quorum is not present at any meeting, a majority of the directors
present may adjourn the meeting, and the meeting may be held, as adjourned,
without further notice provided that a quorum is then present. The act of a
majority of the directors present at any meeting at which there is a quorum
shall be the act of the Board, unless otherwise specifically provided by
statute, the Organization Certificate or these By-Laws.
Section 2.8 Vacancies. When any vacancy occurs among the
directors, the remaining members of the Board may appoint a director to fill
each such vacancy at any regular meeting of the Board or at a special meeting
called for that purpose. Any director so appointed shall hold office until
the next annual meeting of the stockholders and until the director's
successor has been elected and qualified, unless sooner displaced.
Section 2.9 Removal of Directors. Any director may be removed
either with or without cause, at any time, by a vote of the holders of a
majority of the shares of the Bank at any meeting of stockholders called for
that purpose. A director may be removed for cause by vote of a majority of
the entire Board.
Section 2.10 Compensation of Directors. The Board shall fix the
amounts to be paid directors for their services as directors and for their
attendance at the meetings of the Board or of committees or otherwise. No
director who receives a salary from the Bank shall receive any fee for
attending meetings of the Board or of any of its committees.
Section 2.11 Action by the Board. Except as otherwise provided by
law, corporate action to be taken by the Board shall mean such action at a
meeting of the Board or the Executive Committee of the Board. Any one or
more members of the Board or any committee may participate in a meeting of
the Board or committee by means of a conference telephone or similar
communications equipment allowing all persons participating in the meeting to
hear each other at the same time. Participation by such means shall
constitute presence in person at a meeting.
Section 2.12 Waiver of Notice. Notice of a meeting need not be
given to any director who submits a signed waiver of notice before or after
the meeting or who attends the meeting without protesting the lack of such
notice prior to or at the commencement of the meeting.
Section 2.13 Advisory and Regional Boards. The Board, the
Chairman of the Board, the President, the Chief Executive Officer or any
Regional President may establish Advisory Boards or Regional Boards and
committees thereof for any one or more of the Bank's regions, offices, or
departments and make or authorize appointments to be made thereto.
Appointees to such boards and committees need not be stockholders, directors
or officers of the Bank, and they shall have and perform only such functions
as may be assigned to them by, shall serve at the pleasure of, and shall be
compensated by fees fixed by the Board, the Chairman of the Board, the
President, the Chief Executive Officer or the Regional President making the
appointment.
ARTICLE III
COMMITTEES OF THE BOARD
Section 3.1 Executive Committee.
a. There shall be an Executive Committee which shall be composed
of at least five members elected by the Board from among its members at its
first meeting following the annual meeting of stockholders to serve for the
ensuing year and shall include the Chairman of the Board, the President, the
Chief Executive Officer and the Chairman of the Executive Committee, all of
which offices may be held by one person. The Chairman of the Board may
appoint one or more directors as alternate members to serve in place of any
absent members of the Executive Committee. Any vacancy in the Executive
Committee shall be filled by the Board, but until its next regular Board
meeting may be filled temporarily by the Chairman of the Board.
b. The Executive Committee shall possess and exercise all of the
powers of the Board except (i) when the latter is in session and (ii) as
provided otherwise in the New York Banking Law.
Section 3.2 Chairman of the Executive Committee. The Board shall
appoint one of its members to be Chairman of the Executive Committee. The
Chairman of the Board, the President or the Chief Executive Officer may at
the same time be appointed Chairman of the Executive Committee. The Chairman
of the Executive Committee shall preside at all meetings of the Executive
Committee, and the Chairman of the Executive Committee shall, in the absence
of the Chairman of the Board, the President and the Chief Executive Officer,
preside at all meetings of stockholders and the Board. The Chairman of the
Executive Committee shall also perform such other duties and be vested with
such other powers as may from time to time be conferred upon him or her by
these By-Laws or as shall be assigned to him or her from time to time by the
Board or the Chief Executive Officer.
Section 3.3 Meetings of the Executive Committee. Meetings of the
Executive Committee may be called by the Chairman of the Board, the Chairman
of the Executive Committee, the President, the Chief Executive Officer or the
Secretary and may be held at any place and at any time designated in the
notice thereof. Each member of the Executive Committee shall be given notice
stating the time and place of each such meeting, by telegram, telephone or
similar electronic means or in person at least one day prior to such meeting,
or by mail at least three days prior.
Section 3.4 Examining Committee. The Board shall designate an
Examining Committee, which shall hold office until the next annual meeting of
the Board following the annual meeting of stockholders, consisting of not
less than three of its members, other than officers of the Bank, and whose
duty it shall be to make an examination at least once during each calendar
year and within 15 months of the last such examination into the affairs of
the Bank including the administration of fiduciary powers, or cause suitable
examinations to be made by auditors responsible only to the Board and to
report the result of such examination in writing to the Board. Such report
shall state whether the Bank is in a sound condition, whether adequate
internal controls and procedures are being maintained and shall recommend to
the Board such changes in the manner of conducting the affairs of the Bank as
shall be deemed advisable. The Committee shall at such time ascertain
whether the Bank's fiduciary responsibilities have been administered in
accordance with law and sound fiduciary principles.
Section 3.5 Other Committees. The Board may appoint, from time to
time, from its own members, committees of the Board of three or more persons,
for such purposes and with such powers as the Board may determine.
ARTICLE IV
OFFICERS
Section 4.1 Appointment of Officers. At its annual meeting
following the annual meeting of stockholders, the Board shall appoint from
among its members a Chairman of the Board, a President, a Chief Executive
Officer and a Secretary. The Chairman of the Board or the President may also
be appointed as the Chief Executive Officer. At such meeting, the Board
shall also appoint one or more Vice Presidents, and may at such meeting or at
other meetings of the Board appoint such other officers as it may determine
from time to time. The Board may also authorize a committee of the Board to
appoint such officers as are not required to be appointed by the Board at a
meeting.
Section 4.2 Duties of President. In the absence of the Chairman
of the Board, the President shall preside at all meetings of the Board and of
stockholders and in the absence of the Chairman of the Executive Committee
and the Chairman of the Board shall preside at all meetings of the Executive
Committee. Except as may be otherwise provided by the By-Laws or the Board,
the President shall be a member ex officio of all committees authorized by
these By-Laws or the Board. The President shall have general executive
powers, shall participate actively in all major policy decisions and shall
have and may exercise any and all other powers and duties pertaining by law,
regulation or practice to the Office of President or imposed by these By-
Laws. The President shall also have and may exercise such further powers and
duties as from time to time may be conferred or assigned by the Board or the
Chief Executive Officer.
Section 4.3 Duties of Chief Executive Officer. The Chief
Executive Officer shall exercise general supervision over the policies and
business affairs of the Bank and the carrying out of the policies adopted or
approved by the Board. Except as otherwise provided by these By-Laws, the
Chief Executive Officer shall have the power to determine the duties of the
officers of the Bank and to employ and discharge officers and employees.
Except as otherwise provided by the By-Laws or the Board, the Chief Executive
Officer shall be a member ex officio of all committees authorized by these
By-Laws or created by the Board. In the absence of the Chairman of the Board
and the President, the Chief Executive Officer shall preside at all meetings
of the Board and of stockholders.
Section 4.4 Duties of Vice Presidents. Each Vice President shall
have such titles, seniority, powers and duties as may be assigned by the
Board, a committee of the Board, the President or the Chief Executive
Officer.
Section 4.5 Secretary. The Secretary shall be Secretary of the
Board and of the Bank and shall keep accurate minutes of all meetings of
stockholders and of the Board. The Secretary shall attend to the giving of
all notices required to be given by these By-Laws; shall be custodian of the
corporate seal, records, documents and papers of the Bank; shall provide for
the keeping of proper records of all transactions of the Bank; shall have and
may exercise any and all other powers and duties pertaining by law,
regulation or practice to the office of Secretary or imposed by these By-
Laws; and shall also perform such other duties as may be assigned from time
to time by the Board, the president or the Chief Executive Officer.
Section 4.6 Other Officers. The President or the Chief Executive
Officer or his or her designee may appoint all officers whose appointment
does not require approval by the Board or a committee of the Board and assign
to them such titles as from time to time may appear to be required or
desirable to transact the business of the Bank. Each such officer shall have
such powers and duties as may be assigned by the Board, the president or the
Chief Executive Officer.
Section 4.7 Tenure of Office. The Chairman of the Board, the
President, the Chief Executive Officer, the Chairman of the Executive
Committee, the Secretary and the Vice Presidents shall hold office for the
current year for which the Board was elected and until their successors have
been appointed and qualified, unless they shall resign, become disqualified
or be removed. All other officers shall hold office until their successors
have been appointed and qualify, unless they shall resign, become
disqualified or be removed. The Board shall have the power to remove the
Chairman of the Board, the President, the Chief Executive Officer, the
Chairman of the Executive Committee and the Secretary. The Board or the
Chief Executive Officer or his or her designee shall have the power to remove
all other officers and employees. Any vacancy occurring in the offices of
Chairman of the Board, President or Chief Executive Officer shall be filled
promptly by the Board.
Section 4.8 Compensation. The Board shall by resolution determine
from time to time the officers whose compensation will require approval by
the Board or a committee of the Board. The Chief Executive Officer shall fix
the compensation of all officers and employees whose compensation does not
require approval by the Board or a committee of the Board.
Section 4.9 Auditor. The Board or the Chief Executive Officer
shall appoint an officer to fill the position of Auditor for the Bank and
assign to such officer such title as is deemed appropriate. The Auditor
shall perform all duties incident to the audit of all departments and offices
and of all affairs of the Bank. The Auditor shall be responsible to the
Chief Executive Officer. The Auditor may at any time report to the Board any
matter concerning the affairs of the Bank that, in the Auditor's judgment,
should be brought to its attention.
Section 4.10 Regional Presidents. The Board may appoint one or
more Regional Presidents. Each Regional President shall have such powers and
duties as may be assigned by the Board or the Chief Executive Officer.
ARTICLE V
FIDUCIARY POWERS
Section 5.10 Fiduciary Responsibility. The Board shall appoint an
officer or officers or a committee or committees of this Bank whose duties
shall be to manage, supervise and direct the fiduciary activities of the Bank
as assigned by the Board. Such officer or committee shall do or cause to be
done all things necessary or proper in carrying on the assigned activities in
accordance with provisions of law and applicable regulations and shall act
pursuant to opinion of counsel where such opinion is deemed necessary.
Opinions of counsel shall be retained on file in connection with all
important matters pertaining to fiduciary activities. The officer or
committee shall be responsible for all assets and documents held by the Bank
in connection with fiduciary matters assigned by the Board.
Section 5.11 Fiduciary Files. Files shall be maintained
containing all fiduciary records necessary to assure that fiduciary
responsibilities have been properly undertaken and discharged.
Section 5.12 Fiduciary Investments. Funds held in a fiduciary
capacity shall be invested in accordance with the instrument establishing the
fiduciary relationship and applicable law. Where such instrument does not
specify the character and class of investments to be made and does not vest
in the Bank a discretion in the matter, funds held pursuant to such
instrument shall be invested in investments in which corporate fiduciaries
may invest under applicable law.
ARTICLE VI
STOCK AND STOCK CERTIFICATES
Section 6.1 Transfers. Shares of the stock of the Bank shall be
transferable on the books of the Bank, only by the person named in the
certificate or by an attorney, lawfully constituted in writing, and upon
surrender of the certificate therefor. Every person becoming a stockholder
by such transfer shall, in proportion to his or her shares, succeed to all
rights of the prior holder of such shares.
Section 6.2 Stock Certificates. The certificates of stock of the
Bank shall be numbered and shall be entered in the books of the Bank as they
are issued. They shall exhibit the holder's name and number of shares and
shall be signed by the Chairman of the Board, the President, the Chief
Executive Officer or any Vice President and by the Secretary or an Assistant
Secretary.
ARTICLE VII
CORPORATE SEAL
Section 7.1 Corporate Seal. The Chairman of the Board, the
President, the Chief Executive Officer, the Secretary or any Assistant
Secretary, a Vice President or Assistant Vice President or other officer
designated by the Board or the Chief Executive Officer or his or her designee
shall have authority to affix the corporate seal to any document requiring
such seal and to attest the same. Such seal shall be substantially in the
following form:
(impression)
( of )
( seal )
ARTICLE VIII
MISCELLANEOUS PROVISIONS
Section 8.1 Fiscal Year. The fiscal year of the Bank shall be the
calendar year.
Section 8.2 Execution of Instruments.
a. All agreements, indentures, mortgages, deeds, conveyances,
transfers, certificates, declarations, receipts, discharges, releases,
satisfactions, settlements, petitions, schedules, accounts, affidavits,
bonds, undertakings, proxies and other instruments or documents may be
signed, executed, acknowledged, verified, delivered or accepted in behalf of
the Bank or in connection with the exercise of the fiduciary powers of the
Bank, by the Chairman of the Board, the President, the Chief Executive
Officer, the Secretary or any other officer or employee (other than the
Auditor) designated by the Board or the Chief Executive Officer or his or her
designee. Any such instruments may also be executed, acknowledged, verified,
delivered or accepted in behalf of the Bank in such other manner and by such
other officers as the Board may from time to time direct. The provisions of
this Section 8.2 are supplementary to any other provision of these By-Laws.
b. When required, the Secretary or any officer or agent designated
by the Board or the Chief Executive Officer or his designee shall countersign
and certify all bonds or certificates issued by the Bank as trustee, transfer
agent, registrar or depository. The Chief Executive Officer or any officer
designated by the Board or the Chief Executive Officer or his or her designee
shall have the power to accept in behalf of the Bank any guardianship,
receivership, executorship or other special or general trust permitted by
law. Each of the foregoing authorizations shall be at the pleasure of the
Board, and each such authorization by the Chief Executive Officer or his or
her designee also shall be at the pleasure of the Chief Executive Officer.
Section 8.3 Records. The By-Laws and the proceedings of all
meetings of the stockholders, the Board and standing committees of the Board
shall be recorded in appropriate minute books provided for the purpose. The
minutes of each meeting shall be signed by the Secretary or other officer
appointed to act as secretary of the meeting.
Section 8.4 Emergency Operations. In the event of war or warlike
damage or disaster of sufficient severity to prevent the conduct and
management of the affairs, business and property of the Bank by its directors
and officers as contemplated by these By-Laws, any two or more available
members of the then-incumbent Executive Committee shall constitute a quorum
of that committee for the full conduct and management of the affairs,
business and property of the Bank. In the event of the unavailability at
such time of a minimum of two members of the then-incumbent Executive
Committee, any three available directors shall constitute the Executive
Committee for the full conduct and management of the affairs, business and
property of the Bank. This by-law shall be subject to implementation by
resolutions of the Board passed from time to time for that purpose, and any
provisions of these By-Laws (other than this section) and any resolutions
which are contrary to the provisions of this section or to the provisions of
any such implementary resolutions shall be suspended until it shall be
determined by any interim Executive Committee acting under this section that
it shall be to the advantage of the Bank to resume the conduct and management
of its affairs, business and property under all of the other provisions of
these By-Laws.
Section 8.5 Indemnification.
a. The Bank shall indemnify each person made or threatened to be
made a party to any action or proceeding, whether civil or criminal, by
reason of the fact that such person or such person's testator or intestate is
or was a director or officer of the Bank, or, while a director or officer,
serves or served, at the request of the Bank, any other corporation,
partnership, joint venture, trust, employee benefit plan or other enterprise
in any capacity, against judgments, fines, penalties, amounts paid in
settlement and reasonable expenses, including attorney's fees, incurred in
connection with such action or proceeding, or any appeal therein, provided
that no such indemnification shall be made if a judgment or other final
adjudication adverse to such director or officer establishes that his or her
acts were committed in bad faith or were the result of active and deliberate
dishonesty and were material to the cause of action so adjudicated, or that
he or she personally gained in fact a financial profit or other advantage to
which he or she was not legally entitled, and provided further that no such
indemnification shall be required with respect to any settlement or other
nonjudicated disposition of any threatened or pending action or proceeding
unless the Bank has given its prior consent to such settlement or other
disposition.
b. The Bank shall advance or promptly reimburse upon request any
director or officer seeking indemnification hereunder for all expenses,
including attorneys' fees, reasonably incurred in defending any action or
proceeding in advance or the final disposition thereof upon receipt of an
undertaking by or on behalf of such person to repay such amount if such
person is ultimately found not to be entitled to indemnification or, where
indemnification is granted, to the extent the expenses so advanced or
reimbursed exceed the amount to which such person is entitled.
c. This Section 8.5 shall be given retroactive effect, and the
full benefits hereof shall be available in respect of any alleged or actual
occurrences, acts or failures to act prior to the date of the adoption of
this Section 8.5. The right to indemnification of advancement of expenses
under this Section 8.5 shall be a contract right.
Section 8.6 Amendments. These By-Laws may be added to, amended,
altered or repealed at any regular meeting of the Board by a vote of a
majority of the total number of the directors, or at any meeting or
stockholders, duly called and held, by a majority of the stock represented at
such meeting.
I, Helen Kujawa, CERTIFY that I am the duly appointed Secretary of
Marine Midland Bank and, as such officer, have access to its official records
and the foregoing By-Laws are the By-Laws of the Bank, and all of them are
now lawfully in force and effect.
IN TESTIMONY WHEREOF, I have hereunto affixed my official signature
and the seal of the Bank, in New York, on January 27, 1994.
/s/ Helen Kujawa
--------------------------------------
Assistant Corporate Secretary
[SEAL]
EXHIBIT T1A(vi)
Securities and Exchange Commission
Washington, D.C. 20549
Dear Sirs:
Pursuant to Section 321(b) of the Trust Indenture Act of 1939 and
subject to the qualifications and limitation of 321(b) and the other
provisions of the Trust Indenture Act of 1939, the undersigned Marine Midland
Bank consents that reports of examination by Federal, State, Territorial or
District authorities may be furnished by such authorities to the Commission
upon request therefor.
Yours very truly,
MARINE MIDLAND BANK
By: /s/ Metin Caner
--------------------------------
(Metin Caner,
Assistant Vice President)
Attest:
By: /s/ Eileen M. Hughes
-------------------------
(Eileen M. Hughes,
Corporate Trust Officer)
EXHIBIT T1A(vii)
REPORT OF CONDITION
Consolidated Report of Condition of
Marine Midland Bank of Buffalo, New
York and Foreign and Domestic Subsid-
iaries, a member of the Federal Re-
serve System, at the close of bus-
iness on December 31, 1993, pub-
lished in accordance with a call made
by the Federal Reserve Bank of this
District pursuant to the provisions of
the Federal Reserve Act.
(Dollar Amounts in
Thousands)
ASSETS
Cash and balance due from
depositary institutions:
Noninterest-bearing balances
and currency and coin . . . . . . . . . . . . . . . . . $1,071,645
Interest-bearing balances . . . . . . . . . . . . . . . 1,492,007
Securities . . . . . . . . . . . . . . . . . . . . . . 1,919,704
Federal funds sold and
securities purchased under
agreements to resell in
domestic offices of the
bank and of its Edge and
Agreement subsidiaries, and
in IBF's
Federal funds sold . . . . . . . . . . . . . . . . . . . 357,000
Securities purchased
under agreements to resell . . . . . . . . . . . . . . . 593,002
Loans and lease financing
receivables:
Loans and leases, net of
unearned income . . . . . . . . . . . . . . . 9,930,891
LESS: Allowance for loan
and lease losses . . . . . . . . . . 342,089
LESS: Allocated transfer
risk reserve . . . . . . . . . . . . 0
Loans and lease, net of unearned
income, allowance, and reserve . . . . . . . . . . . . . 9,588,802
Assets held in trading accounts . . . . . . . . . . . . . . . 1,615,072
Premises and fixed assets
(including capitalized leases) . . . . . . . . . . . . . 193,194
Other real estate owned . . . . . . . . . . . . . . . . . . . 142,240
Investments in unconsolidated
subsidiaries and associated
companies . . . . . . . . . . . . . . . . . . . . . . 0
Customers' liability to this
bank on acceptances outstanding . . . . . . . . . . . . 15,007
Intangible assets . . . . . . . . . . . . . . . . . . . . . . 69,056
Other assets . . . . . . . . . . . . . . . . . . . . . . 428,500
-----------
Total assets . . . . . . . . . . . . . . . . . . . . . . 17,485,229
===========
LIABILITIES
Deposits:
In domestic offices . . . . . . . . . . . . . . . . . . 12,377,782
Noninterest-bearing . . . . . . . . . . . . . 3,259,659
Interest-bearing . . . . . . . . . . . . . . . 9,118,123
In foreign offices, Edge
and Agreement Subsid-
iaries, and IBF's . . . . . . . . . . . . . . . . . . . 1,002,884
Noninterest-bearing . . . . . . . . . . . . . 0
Interest-bearing . . . . . . . . . . . . . . . 1,002,884
Federal funds purchased
securities sold under
agreements to repurchase
in domestic offices of
the bank and of its Edge
and Agreement subsidiar-
ies, and in IBF's
Federal funds purchased . . . . . . . . . . . . . . . . 1,115,269
Securities sold under
agreements to repurchase . . . . . . . . . . . . . . . . 260,530
Demand notes issued to the U.S.
Treasury . . . . . . . . . . . . . . . . . . . . . . 300,000
Other borrowed money . . . . . . . . . . . . . . . . . . . . 510,549
Mortgage indebtedness and
obligations under capital-
ized leases . . . . . . . . . . . . . . . . . . . . . . 41,852
Bank's liability on acceptances
executed and outstanding . . . . . . . . . . . . . . . . 17,591
Subordinated notes and
debentures . . . . . . . . . . . . . . . . . . . . . . . 225,000
Other liabilities . . . . . . . . . . . . . . . . . . . . . . 317,656
-----------
Total Liabilities . . . . . . . . . . . . . . . . . . . . . . 16,169,113
Limited-Life preferred
stock and related surplus . . . . . . . . . . . . . . . 0
EQUITY CAPITAL
Perpetual preferred stock
and related surplus . . . . . . . . . . . . . . . . . . 0
Common Stock . . . . . . . . . . . . . . . . . . . . . . 185,000
Surplus . . . . . . . . . . . . . . . . . . . . . . 1,182,745
Undivided profits and capital
reserves . . . . . . . . . . . . . . . . . . . . . . (51,629)
LESS: Net unrealized loss
on marketable equity
securities . . . . . . . . . . . . . . . . . . . . . . . 0
Cumulative foreign currency
translation adjustments . . . . . . . . . . . . . . . . 0
Total equity capital . . . . . . . . . . . . . . . . . . . . 1,316,116
------------
Total
Liabilities, limited-life
preferred stock and equity
capital . . . . . . . . . . . . . . . . . . . . . . 17,485,229
============
I, Gerald A. Ronning, Executive Vice President and Controller of
the above-named bank do hereby declare that this Report of Condition has been
prepared in conformance with the instructions issued by the Board of
Governors of the Federal Reserve System and is true to the best of my
knowledge and belief.
GERALD A. RONNING
We the undersigned directors, attest to the correctness of this
Report of Condition and declare that it has been examined by us and to the
best of our knowledge and belief has been prepared in conformance with the
instructions issued by the Board of Governors of the Federal Reserve System
and is true and correct.
James H. Cleave
Director
Bernard J. Kennedy
Director
Northrup R. Knox
Director
