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
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
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,
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.
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
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
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 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
================== ==================
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.
1993 1992 1991 1990 1989
OPERATIONS: (000'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
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:
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
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
opens access to utility transmission systems. The rules by which
such access will
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
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.
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:
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
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.
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
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
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
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."
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
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.
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
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
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
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.
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
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
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.
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
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
======= ======= ======= =========
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.
22
Details of the changes in electric revenues and kilowatt-hour
sales by customer group are highlighted in the table below:
1993 % Increase (decrease) from prior years
% of
Electric 1993 1992 1991
Class of service Revenues Revenues Sales Revenues Sales Revenues Sales
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)%
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.
24
1993 1992 1991
_______________ ______________ ________________
FUEL FOR ELECTRIC GENERATION:
(in millions of dollars)
GwHrs. Cost GwHrs. Cost GwHrs. Cost
------ ----- ------ ---- ----- ----
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
Losses/Company use 3,688 - 3,268 - 3,273 -
______ ________ ______ ______ ______ ______
37,724 1,094.6 36,611 $973.6 36,738 $837.9
====== ======== ====== ====== ====== =======
25
% Change from prior year
_________________________________
1993 to 1992 1992 to 1991
_________________ _____________
FUEL FOR ELECTRIC GENERATION:
(in millions of dollars)
GwHrs. Cost GwHrs. Cost
----- ---- ----- ----
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)
Losses/Company use 12.9 - (0.2) -
_____ ______ ______ _____
3.0 % 12.4 % (0.3)% 16.2%
====== ======= ======= ======
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.
27
Increase (decrease) from
prior year
(In millions of dollars)
Gas revenues 1993 1992 1991 Total
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
====== ====== ====== ======
GAS SALES, excluding transportation of customer-owned gas
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%.
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:
29
1993 % Increase (decrease) from prior years
% of
Gas 1993 1992 1991
Class of service Revenues Revenues Sales Revenues Sales Revenues Sales
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%
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
slightly in 1992 as increased costs associated with outages at
Unit 1 and refueling
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
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
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
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
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,
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
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).
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
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
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
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,
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 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
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.
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
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