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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
/X/ Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the fiscal year ended December 31, 1993
OR
/ / Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 for the transition period
from ......to......
Commission file number 1-2987
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NIAGARA MOHAWK POWER CORPORATION
(Exact name of registrant as specified in its charter)
State of New York 15-0265555
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
300 Erie Boulevard West Syracuse, New York 13202
(Address of principal executive offices) (zip code)
(315) 474-1511
Registrant's telephone number, including area code
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--
Securities registered pursuant to Section 12(b) of the Act:
(Each class is registered on the New York Stock Exchange)
Title of each class
Common Stock ($1 par value)
Preferred Stock ($100 par Preferred Stock ($25
par
value-cumulative): value - cumulative):
3.40% Series 4.10% Series 6.10% Series 8.75% Series
3.60% Series 4.85% Series 7.72% Series Adjustable Rate
3.90% Series 5.25% Series Series A & Series
C
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--
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes /X/ No / /
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K / X /
State the aggregate market value of the voting stock held by non-
affiliates of the registrant.
Approximately $2,689,000,000 at March 1, 1994.
Indicate the number of shares outstanding of each of the
registrant's classes of common stock, as of the latest
practicable date.
Common stock $1 par 142,596,892 shares outstanding March 1,
1994.
Documents incorporated by reference:
Definitive Proxy Statement in connection with annual meeting of
stockholders to be held May 3, 1994 incorporated in Part III
to
the extent described therein.
NIAGARA MOHAWK POWER CORPORATION
INFORMATION REQUIRED IN FORM 10-K
Part I
Item Number Page
Item 1. Business. 3
Item 2. Properties. 31
Item 3. Legal Proceedings. 35
Item 4. Submission of Matters to a Vote of
Security Holders. 37
Executive Officers of the Registrant 38
Part II
Item 5. Market for the Registrant's Common Equity and
Related Stockholder Matters. 39
Item 6. Selected Financial Data. 39
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations. 39
Item 8. Financial Statements and Supplementary Data. 39
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure. 39
Part III
Item 10. Directors, Executive Officers, Promoters and
Control Persons of the Registrant. 39
Item 11. Executive Compensation. 39
Item 12. Security Ownership of Certain Beneficial
Owners and Management. 39
Item 13. Certain Relationships and Related Transactions. 39
Part IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K. 41
Signatures 43
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NIAGARA MOHAWK POWER CORPORATION
PART I
Item 1. Business.
The Company, organized in 1937 under the laws of New York,
is engaged principally in the business of production and/or
purchase, transmission, distribution and sale of electricity and
the purchase, distribution and sale of gas in New York State.
The Company renders electric service to the public in an area of
New York State having a total population of about 3,500,000,
including, among others, the cities of Buffalo, Syracuse, Albany,
Utica, Schenectady, Niagara Falls, Watertown and Troy. The
Company distributes natural gas in areas of central, northern and
eastern New York having a total population of about 1,700,000,
nearly all within the Company's electric service area. A
Canadian subsidiary owns an electric company with operations in
the Province of Ontario, Canada. A Texas subsidiary has an
interest in a uranium mining operation in Live Oak County, Texas
which is now in the process of reclamation and restoration. A
New York subsidiary owns, develops and operates cogeneration and
small power plants. Another New York subsidiary engages in real
estate development. Each of these subsidiaries is wholly-owned
by the Company.
General. Until recently, the electric and gas utility
industry operated in a relatively stable business environment,
subject to traditional cost-of-service regulation. The
investment community, both shareholders and creditors, considered
utility securities to be of low risk and high quality.
Regulators tended to protect the utility monopoly in exchange for
the utility company's obligation to serve customers in its
franchise. Such protection often encouraged regulators and other
governmental bodies to use utilities as vehicles to advance
social programs and as tax collectors. In general, utilities and
regulators were inclined toward establishing a fair rate of
return and away from particular price considerations or
incentives for aggressive, long-term cost control. Cash flows
were relatively more predictable, as was the industry's ability
to sustain investment grade dividend payout and interest coverage
ratios.
The emergence of competition has recently begun to erode the
utility industry's monopoly position and the regulator's ability
to wholly assure the industry's financial health. For example,
the passage of the National Energy Policy Act of 1992 (NEPA) is
resulting in a rapid increase in wholesale (a sale to another
entity for resale to an end user) competition. NEPA eases the
way for non-utility, unregulated generators to enter the
marketplace and allows the Federal Energy Regulatory Commission
(FERC) to require the utility owners of electricity transmission
systems to transport power for wholesale transactions. The speed
and extent of monopoly erosion will be dependent upon a number of
company specific characteristics, including geographic location
and electric system limitations, cost and price of services in
relation to neighboring utilities, opportunity for alternative
suppliers and fuels to compete, economic vitality of the service
territory, policies of regulators and legislators and electric
supply/demand balances.
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Competition creates a focus on the price of utility
services. As the potential for broad based competition grows,
government mandated social programs, burdensome tax structures
and other regulatory initiatives become cost elements that a
market based pricing system will not necessarily support. For
the Company, the most significant of these incumbent burdens is
mandated payments to unregulated generators discussed below.
During the past several years, the Company's electric
industrial rates have moved from being among the lowest in New
York State and the Northeast to above the middle of the range. A
key contributor to recent price increases has been the
proliferation of unregulated generators, which are aided by
federal and state statutes that provide guaranteed markets at
rates in excess of the Company's internal cost of production.
Such increases in rates are reaching a point where industrial
customers have begun to weigh the benefits and costs of self
generation against the retention of utility service. More
importantly, industrial and commercial customers are also
considering moving operations outside the Company's service
territory. Loss of industrial and commercial customers places
additional cost burdens on remaining customers. In response to
this, the Company has begun a program to offer discounts to
industrial customers that can demonstrate viable self-generation
alternatives. The associated loss of jobs in the Company's
service territory would also put further pressure on rates to
remaining customers.
Although the timing and impact of competition is impossible
to predict, the Company is already experiencing severe
competition in the wholesale market, exacerbated by a capacity
surplus of electricity in the Northeast region and Canada. The
possibility of municipalization, whereby traditional customers
form their own government sponsored supply company, may increase
as prices increase. The Company is aware of at least one public
debate on municipalization involving a city within its service
territory.
Rating agencies and others following utility securities have
recently observed an increase in business risk as a result of
these and other factors. Standard & Poor's Corporation (S&P)
revised its electric utility financial ratio benchmarks in late
1993 to reflect the greater business risk provided by
accelerating competition. With respect to the Company, it also
indicated concern about environmental and nuclear operating cost
pressure and slow earnings growth prospects. S&P also segregated
electric utility companies into 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. Based on these
criteria, on February 23, 1994, S&P reduced the Company's credit
ratings to BBB- for secured debt and BB+ (below investment grade)
for preferred stock, while maintaining a negative ratings outlook
pending demonstrated financial improvement.
Moody's Investor's Services has also indicated that it
expects utility bond ratings to come under increasing pressure
over the next three to five years because of changes in the
business environment, although in February 1994 it maintained its
ratings of Baa2 on all existing secured debt, baa3 for preferred
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stock and P-2 for commercial paper. See also Item 7 --
Management's Discussion and Analysis of Financial Condition and
Results of Operations.
The Company is responding to these competitive threats
through strategies developed in its Comprehensive Industry
Restructuring and Competitiveness Assessment for the 2000's
(CIRCA 2000), begun in 1993. Reducing the total cost of doing
business and solving problems in the regulatory area as they
relate to the Company were identified as critical factors in
addressing the Company's business risk.
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 during 1993, the Company
determined that further and faster workforce reductions were
needed and announced a layoff, to occur in early 1994, of
approximately 900 employees, while increasing total reductions to
1,500. Further reductions may be necessary.
The Company has also proposed a five year electric rate
plan, described under "Regulation and Rates, Innovative Rate Plan
Proposal," which would begin in 1995. The plan proposes a
methodology that would cap rates at approximately the rate of
inflation for each of the years 1996 through 1999, while
providing greater pricing flexibility for Company pricing
decisions within each rate class. The Company could, at its
discretion, offer discounts to customers who might be able to
leave the system, but would, in turn, be limited as to how much
of the discount could be recovered from other customers.
The emphasis on cost control and pricing flexibility is
designed to position the Company to meet the challenges of
competition. However, the competitive threats within the
Company's markets increase the level of risk to be managed, as
evidenced by the developments discussed in this document and no
assurance can be provided that the financial strength of the
Company can be maintained or that its dividends and earnings will
be as predictable as in prior years.
The following topics are discussed under the general heading
of "Business". Where applicable, the discussions make reference
to the various other items of this Form 10-K.
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Topic Page
Regulation and Rates 6
Unregulated Generators 10
New York Power Authority 13
Purchased Power 14
Fuel for Electric Generation:
Coal 14
Natural Gas 15
Residual Oil 15
Nuclear 16
Gas Supply 18
Industry Segment Data 19
Environmental Matters 19
Nuclear Operations 23
Construction Program 24
Electric Supply Planning 24
Electric Delivery Planning 25
Demand-Side Management Programs 26
Research and Development 27
Employee Relations 28
Liability Insurance 28
REGULATION AND RATES. In recent years the nature of rate
regulation in New York State has trended toward negotiated
ratemaking as opposed to fully litigated proceedings. Several
negotiated agreements between the Company, the PSC Staff and
other intervenors have had a positive effect on the Company's
financial condition and results of operations. For a discussion
of these negotiated agreements, including key rat mechanisms
such as the Niagara Mohawk electric adjustment mechanism (NERAM)
and the measured equity return incentive term (MERIT), see Item 7
-- Management's Discussion And Analysis Of Financial Condition
And Results Of Operations.
Under the terms of its 1994 Rate Agreement, the Company is
required to file a "competitiveness" study with the PSC by
April 1, 1994. The filing will address, among other things, the
breadth of potential competitive forces facing the Company, the
economics of the Company's electricity supply, the potential
financial effects of increasing competition and possible methods
for dealing with the transition costs that would arise from
expanding competition.
Rates Responding to Economic Development and Competitive
Threats. 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 in 1993 approved a new rate (referred to
as SC-10) under which the Company is allowed to negotiate
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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 through the use of on-site
generation is an economically viable alternative. At March 1,
1994, the Company estimates that as many as 75 of its 235 largest
customers may be inclined to bypass the its system by making
electricity on their own unless they receive price discounts.
These would cost about $20 million per year, while losing those
75 customers would reduce net revenues by an estimated $80
million per year. The amount of estimated discounts to be
offered has been reduced from previous estimates due to more
detailed information becoming available on specific customer
sites. The decreases are also a result of customers entering
SC-10 negotiations and then choosing to participate in economic
development incentive programs (discussed below) instead of the
SC-10 tariff rate. As of March 1, 1994, the Company has offered
annual SC-10 discounts totaling $9.7 million, of which $4.6
million have been accepted. The Company estimates that by the
end of 1994 there may be as many as 50 customers subscribing to
the rate with a lost margin projection in 1994 of $15 million ($3
million shareholder exposure).
In addition to the SC-10 tariff, the Company has four
electric rate incentive programs. These programs are designed to
make upstate New York more attractive for business relocation and
expansion, and to provide assistance to distressed businesses
already located there. These incentive programs are:
- Economic Development Rider:
discounted electric rates for new or added load;
- Economic Development Zone Rider:
discounted electric rates for new or added load in a
state designated economically distressed area;
- Economic Revitalization Incentive Rider:
discounted electric rates for existing loads, when
customer qualifies as economically and financially
distressed. As a result of the 1994 Electric Settlement
Agreement, this program was expanded and the total cap on
annual discounts was raised from $5 million to $15
million. The Agreement calls for the cost of discounts
to be shared between ratepayer and shareholder as
follows: 1) discounts of up to $5 million will be passed
on to ratepayers, 2) between $5 million and $15 million
the costs will be shared 80% ratepayer and 20%
shareholder and 3) discounts over $15 million will be
borne by Company shareholders; and
- Economic Development Power Rider:
delivery of low-cost electricity generated by the New
York Power Authority for expansion or revitalization
purposes.
The Company has also joined with other investor-owned gas
and electric and telecommunication companies and New York State
in an "Alliance for a New, New York (ANNY)." ANNY has committed
$5.0 million a year in this five-year program to attract and
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retain jobs on a Statewide basis. This commitment is incremental
to the participants' existing economic development efforts.
In March 1993, the PSC began an ongoing investigation to
explore fundamental issues about future competition in the
electric and gas industries. Most recently, this investigation
has focused on the narrow issue of opportunities of large
customers to by-pass the electric system and the extent to which
flexible rates can prevent such by-pass. The Company's position
in this proceeding has been to support the rate flexibility
necessary to respond to competitive conditions in the industry.
Innovative rate plan proposal. Although the rate programs
and agreements discussed above have had a positive effect on the
Company's financial condition and results of operations, the
focus of these actions is too limited to address the broader
risks of competition. Because of this, the Company determined
that a much more flexible regulatory framework is needed to
respond to a diversity of competitive threats. On February 4,
1994, the Company made a combined electric and gas rate filing
for rates to be effective January 1, 1995. The filing seeks a
$250.7 million increase in electric base rates, which would be
offset by a regulatory surcharge of $117.0 million, resulting in
a net increase in electric revenues of $133.7 million (4.3%).
Gas rates would increase $24.8 million (4.1%) and would include
an extension of the weather normalization adjustment mechanism.
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 deferral mechanisms (but not
the amounts already deferred) 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 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 obtain 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.
The flexibility and responsiveness of the rate proposal to
changing business conditions is designed to better position the
Company to meet the challenges of increasing competition and
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protect shareholder value. However, the Company must be
disciplined in its spending based upon its projections of price
increases, if any, sales levels and potential discounts during
the five-year period.
The financial success of the Company under its price
indexing rate proposal will be dependent on the ability of the
Company to control its costs. Because price indexing begins with
base prices set for 1995, inclusive of such items 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.
The Company can provide no assurance that the Company's
proposal will be adopted as submitted. The Consumer Protection
Board (CPB) filed a motion on March 2, 1994, to dismiss the
proposal and consider rates for only 1995 on the grounds that the
PSC could not legally set rates for a five-year period, and the
Company has not provided sufficient basis for evaluating the
effects of years two through five of the proposal. Other
intervenors have generally supported the CPB's position on the
issue of legality. The PSC Staff, in its response, disagreed
with the CPB on the issue of legality, agreed as to the
deficiency of support of years two through five and further
stated that the support for the requested relief for 1995 was
also deficient. The PSC Staff proposed the solution of extending
the period in which the rate proposal would be evaluated by
fourteen weeks, with a make-whole agreement for the financial
effects of the delay for only seven weeks. The Company believes
that the entire proposal has been adequately supported and that
the PSC can legally adopt the five-year proposal. A prehearing
conference with the Administrative Law Judge was held March 28,
1994 during which a date of April 5, 1994, was established for
responses to the PSC Staff's motion to dismiss the entire rate
filing. The Company cannot predict what rate program may
ultimately be implemented or the effect thereof on the Company's
financial condition and results of operations.
Other Electric rate initiatives. In March 1994, the Company
filed optional tariff rates for the vast majority of its
customers. The optional pricing arrangements, which are proposed
to become effective January 1, 1995, are designed to meet
existing and evolving forms of competition (on-site generation
and otherwise). They also provide secondary benefits in the form
of reduced energy rates for incremental consumption.
The Company will also be submitting revisions to SC-8, a
real time pricing program, which should advance the program from
its current pilot status to permanent rate status. The
adjustments are being introduced to address the dynamics of each
customer's changing business cycle as well as competitive
adjustments to react to the alternatives available to contestable
customers.
Gas rate initiatives. 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-
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utility sources. In October 1993, the PSC approved the filing
generally, but rejected several key features on the grounds that
they involved issues that the PSC preferred to consider on a
generic basis in the proceeding referred to above. The Company
considered the rate unworkable as approved, and withdrew its
filing to await completion of the generic proceeding.
On May 5, 1993, the Company's Natural Gas Vehicle Service-SC
11 rate became effective, allowing the Company to make sales of
natural gas for natural gas vehicles.
Because of the broad scope of the rate and service issues
encompassed by the PSC's ongoing generic investigation of
"restructuring of the emerging competitive gas market," the
Company does not anticipate pursuing any major gas rate
initiatives until the PSC's order in that proceeding has been
issued. That order is currently scheduled for issuance on or
about July 1, 1994.
State Regulatory Response to FERC Order 636. With the
implementation of FERC Order 636, many state regulatory agencies
have begun to consider whether, and to what extent, the advent of
restructured services on the interstate pipelines will require
changes in the way that local gas distribution services are
regulated. In New York, the PSC on October 28, 1993 initiated a
"generic proceeding" applicable to all gas utilities in the state
for the purpose of addressing "issues associated with the
restructuring of the emerging competitive natural gas market."
Among the issues under consideration are: (1) should utilities
be regulated differently in their core (traditional) markets than
in their non-core (open to competition) markets; (2) should
utilities be permitted to discontinue traditional sales services
to customers who have access to alternative suppliers; (3) what
service obligation should utilities have toward customers who do
not purchase their gas supplies from the utilities; (4) should
utilities be permitted to participate in competitive markets and,
if so, on what terms; and (5) should utilities be required to
unbundle their systems further by making storage and other
services available to their customers?
The current schedule for this proceeding calls for the
issuance of an order by the PSC on or about July 1, 1994, and for
the filing by utilities of tariff changes implementing the order
by around November 1, 1994, the beginning of the winter heating
season. Because the Company's gas services are already
substantially unbundled, with the majority of its non-core
customers currently purchasing their gas supplies from
independent marketers and brokers, the Company does not believe
that the outcome of this proceeding is likely to have a negative
impact on revenues from gas services. The possibility does
exist, however, that the Company will be required to offer new
and different services, or to delete or modify existing services.
Such changes could require substantial revisions in the Company's
gas rates structure. The Company is, therefore, participating
actively in the proceeding.
UNREGULATED GENERATORS. In recent years, a leading factor
in the increases in customer bills and the deterioration of the
Company's competitive position has been the requirement to
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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 New York State Public
Service Commission (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) 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 generator
projects to New York State and, in particular, to the Company's
service territory.
For the year ended December 31, 1993, unregulated generator
purchases were approximately $736 million (11,720,000 MWHrs.)
compared to approximately $543 million (8,632,000 MWHrs.) in 1992
and approximately $268 million (4,303,000 MWHrs.) in 1991. In
1993, unregulated generator purchases provided approximately 28%
of the Company's power supply while comprising 67% of the
Company's fuel and purchased power costs. 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. Another 438 MW are under construction, including 300 MW
from the Sithe-Independence 2 project under an energy-only
contract. An additional 72 MW are awaiting construction and have
not been included in any Company forecasts regarding future
capacity. The Company is projecting that, in 1994, payments to
unregulated generators will represent 27% of each electric
revenue dollar billed, as compared with 22% in 1993.
Without any other action, the Company's installed capacity
reserve margin is 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 also
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 that in
large part 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 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 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 the Company to reinitiate its
request at a later date. The Company is conducting discussions
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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 front-end loaded
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 the repayments of 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
payment to be accumulated under the terms of the contracts,
future avoided costs and future operating costs of the projects.
As of March 25, 1994, the Company has received the following
responses to these notifications:
On March 4, 1994, Encogen Four Partners, L.P. filed a
complaint in the United States District Court for the Southern
District of New York alleging breach of contract and prima
facie tort by the Company. Encogen seeks compensatory damages
of approximately $1 million and unspecified punitive damages.
In addition, Encogen seeks a declaratory judgment that the
Company is not entitled to assurances of future performance
from Encogen;
On March 4, 1994, Sterling Power Partners, L.P., Seneca
Power Partners, L.P., Power City Partners, L.P. and AG-
Energy, L.P. filed a complaint in the Supreme Court of the
State of New York, County of New York seeking a declaratory
judgment that: (a) the Company does not have any legal right
to demand assurances of plaintiffs' future performance; (b)
even if such a right existed, the Company lacks reasonable
insecurity as to plaintiffs' future performance; (c) the
specific forms of assurances sought by the Company are
unreasonable; and (d) if the Company is entitled to any form
of assurances, plaintiffs have provided adequate assurances;
and
On March 7, 1994, NorCon Power Partners, L.P. filed a
complaint in the United States District Court for the Southern
District of New York seeking to enjoin the Company from
terminating a power purchase agreement between the parties and
seeking a declaratory judgment that the Company has no right to
demand additional security or other assurances of NorCon's
future performance under the power purchase agreement. NorCon
sought a temporary restraining order against the Company to
prevent the Company from taking any action on its February 4
letter. On March 14, 1994, the Court entered the interim
relief sought by NorCon.
The Company cannot predict the outcome of these actions or
the response otherwise to its February 4, 1994 notifications, but
will continue to press for adequate assurance that the owners of
these projects will honor their repayment obligations.
Also see Item 3--Legal Proceedings, Item 7--Management's
Discussion and Analysis of Financial Condition and Results of
Operations, and Item 8--Financial Statements and Supplementary
Data, Note 8.
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NEW YORK POWER AUTHORITY (NYPA). The Company presently has
contractual rights to purchase various types and amounts of
electric power and energy from a number of generating facilities
owned by the NYPA. In 1993, these purchases amounted to
7,008,000 MWH, or about 17% of the Company's total power supply
requirements. Under the agreement for hydroelectric power
service, the Company credits to its residential customers,
subject to review by the PSC, any savings derived from the
purchase of an aggregate of 405 MW of firm and peaking hydro
power from NYPA. The following table indicates the types and
amounts of NYPA power which the Company was entitled to purchase
as of January 1, 1994 and the termination dates of its contracts
with NYPA with respect to each generating facility:
Contract
NYPA Facility and Type of Expiration
Power Purchase Rights Date
Niagara Hydroelectric
Project on the Niagara
River near Niagara Falls,
N.Y.
(capacity 2,190,000 kw.):
Firm 126,000 kw. 2007
Replacement 445,000 kw. 2006
Expansion 182,000 kw. 2007
Peaking 175,000 kw. 2007
St. Lawrence Hydroelectric
Project on the St.
Lawrence River near
Massena, N.Y.
(capacity 912,000 kw.) 104,000 kw. 2007
Blenheim-Gilboa Pumped
Storage Generating
Station in Schoharie
County, N.Y.
(capacity 1,000,000 kw.):
Pumped Storage Service 270,000 kw. 2002
FitzPatrick Nuclear Plant
near Oswego, N.Y.
(capacity 821,000 kw.):
Allocation of available
Plant Capacity 40,000 kw. (a) Year-to
year basis
Total 1,342,000 kw.
(a) 40,000 kw. for summer of 1994; 63,000 kw. for winter of
1994-1995.
-13-
The Company also transmits power from NYPA projects to
NYPA's preference and other customers and to other public and
municipal utilities within New York.
PURCHASED POWER. Total purchased power in 1993 amounted to
20,766,000 MWH, including unregulated generators and NYPA
purchases discussed above, representing approximately 50% of the
Company's total power supply requirements. The Company purchases
electricity from the New York Power Pool (NYPP) and other
neighboring utilities on an hour-to-hour basis as needed for
economic operation. The price paid for that power is determined
at the time of purchase. Changes in the cost of purchased power
are included in the Company's fuel adjustment clause (FAC).
Physical limitations of existing transmission facilities, as well
as competition with other utilities and unavailability of energy,
impact the amount of power the Company is able to purchase.
As previously discussed, as more unregulated generator
capacity and energy comes on line over the next several years,
wholesale power purchases from other utilities may decrease.
Wholesale power marketing efforts will also become increasingly
important, in a highly competitive environment, in order to
utilize the Company's surplus capacity.
FUEL FOR ELECTRIC GENERATION. COAL - The C. R. Huntley and
Dunkirk Steam Stations, the Company's only coal fired stations,
are expected to burn about 1.6 and 1.0 million tons of coal,
respectively, in 1994. The Company has two coal supply
contracts, one of which is scheduled to expire at the end of 1994
and the other in 1995.
The annual average cost of coal burned from 1991 through
1993 was $1.59, $1.51 and $1.54, respectively, per million BTU,
or $41.40, $39.42 and $39.85, respectively, per ton. Changes in
the cost of coal burned, part of which are shipping expenses, are
included in the Company's FAC. See also "Regulation and Rates"
for a further discussion of the fuel adjustment clause.
As a result of amendments to the Clean Air Act approved in
November 1990, the Company will be faced with reducing certain
emissions over the next decade. The Dunkirk Steam Station was
identified as requiring reductions of certain emissions in Phase
I. See "Environmental Matters - Air".
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 850 MWs of oil fired capacity is to be
placed in long-term cold standby in 1994 and 340 MWs of aging
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coal fired capacity is to be retired by the end of 1999. The
Company is also continuing to evaluate under what circumstances
the standby plants would be returned to service, but, barring
unforeseen 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.
NATURAL GAS - The Albany Steam Station has the capability to
use natural gas, as well as residual oil, as a fuel for electric
generation. This dual-fuel capability permits the use of lower
cost fuel. During 1991, 1992 and 1993, natural gas was the
predominant fuel used although generation at this station was
curtailed significantly in 1993 for economic reasons because of
the requirement to purchase unregulated generator power. The
Company contracts with various suppliers for the purchase of
natural gas for Albany station. This is an interruptible supply;
colder than normal weather and increased demand for capacity on
interstate pipelines by other firm gas customers could restrict
the amount of gas supplied. Other natural gas used included the
operation of two combustion turbines at the Albany Steam Station
(two additional Albany turbines were placed in long-term cold
standby effective April 1992). During the period 1991 through
1993, the Company, including the Roseton station, burned 22.0,
19.4 and 6.0 million dekatherms (Dt) of natural gas,
respectively, at an average cost per million BTU or Dt of $2.48,
$2.31 and $2.07, respectively.
RESIDUAL OIL - The Company's total requirements for residual
oil in 1994 for its Albany and Oswego Steam Stations are
estimated at approximately 1.7 million barrels. Fuel sulfur
content standards instituted by New York State require 1.5%
sulfur content oil to be burned at Albany and Oswego Unit No. 5.
Oswego Unit No. 6 requires low sulfur fuel (0.7%). All oil
requirements are met on the spot market. At December 31, 1993,
there were approximately 0.7 million barrels, or more than a 45-
day supply of oil, at the Oswego Steam Station and approximately
0.2 million barrels of oil, or a 45-day supply, at the Albany
Steam Station, based on maximum burn projections. The average
price of No.6 oil at January 1, 1994 was approximately $18.30 per
barrel for 0.7% sulfur oil. For 1.5% sulfur oil, the average
price was approximately $16.40 per barrel at the Oswego Steam
Station and $15.20 per barrel at the Albany Steam Station. The
fuel oil prices quoted include the $3.1122 per barrel petroleum
business tax imposed by New York State. Changes in the cost of
oil burned, part of which are shipping expenses, are included in
the FAC. See also "Regulation and Rates" for a further
discussion of the fuel adjustment clause.
Contract arrangements for residual oil for the Roseton Steam
Station, in which the Company has a 25% ownership interest, have
been made by Central Hudson Gas and Electric Corporation, co-
owner and operator of the plant. Two suppliers, the Sun Oil
Trading Company and Global Petroleum Corporation, are supplying
1.5% sulfur residual oil under contract for the fuel requirements
of the plant. Both contracts have arrangements that include
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certain options regarding contract extensions. The Roseton Steam
Station's first unit was modified to dual-fuel capability with
natural gas as the alternative fuel in December 1991. The second
unit's modification was completed in July 1992 and it now has the
ability to burn natural gas as an alternate fuel.
Central Hudson Gas and Electric has in place three term
contracts (for 15 years each) for the supply of up to 100,000 mcf
of natural gas for use at the Roseton plant as a boiler fuel
alternative to residual oil. The natural gas supply is used
primarily during off peak months, April through October of each
year.
The annual average cost of residual oil burned at the
Albany, Oswego and Roseton Steam Stations from 1991 through 1993
was $3.07, $2.98 and $3.11, respectively, per million BTU, or
$19.49, $18.93 and $19.84, respectively, per barrel.
NUCLEAR - The supply of fuel for nuclear generating plants
involves: (1) the procurement of uranium concentrates
(yellowcake) (U3O8), (2) the conversion of uranium concentrates
to uranium hexafluoride, (3) the enrichment of the uranium
hexafluoride, (4) the fabrication of fuel assemblies and (5) the
disposal of spent fuel and radioactive wastes. Agreements for
nuclear fuel materials and services for Nine Mile Point Nuclear
Station Unit No. 1 (Unit 1) and Nine Mile Point Nuclear Station
Unit No. 2 (Unit 2) (in which the Company has a 41% interest),
have been made through the following years:
Nine Mile Nine Mile
Point Nuclear Point Nuclear
Station Unit Station Unit
No. 1 No. 2
Uranium Concentrates (a) 2000 (b) 2000 (b)
Conversion 2000 (b) 2000 (b)
Enrichment (c) (c)
Fabrication 1994 2003
(a) Includes uranium concentrates transferred from wholly-
owned subsidiary, N M Uranium, Inc. (NMU) - see below.
(b) Arrangements have been made for procuring a portion of
the uranium and conversion requirements through the year
2000, leaving the remaining portion of the requirements
uncommitted.
(c) An enrichment contract is in place with the Department
of Energy (DOE) through the year 2014 or the life of the
reactor, whichever is less.
The uncommitted requirements for nuclear fuel materials and
services are expected to be obtained through long-term contracts
or secondary market purchases. The foregoing table includes
uranium concentrates produced by NMU. NMU has a 50% interest in
an in-situ uranium mining operation in Live Oak County, Texas,
which ceased production in 1987. Site restoration is ongoing and
is expected to continue into the late 1990's. At December 31,
-16-
1993, the NMU inventory was approximately 31,355 pounds (U3O8),
which is expected to be transferred to the Company in mid-1994.
The Company currently has in place contracts with the DOE
for the disposal of spent fuel for both Units 1 and 2. The spent
fuel storage facilities at Units 1 and 2 are expected to
accommodate spent fuel discharges while also having sufficient
space available to accept fuel in the core at that time, through
the years 1999 and 2014, respectively.
In January 1983, the Nuclear Waste Policy Act of 1982 (Act)
was enacted. The Act established a cost of $.001 per kilowatt-
hour of net generation to fund disposal of nuclear fuel
irradiated after 1982 and provided for a determination of the
Company's liability to the DOE for the disposal of nuclear fuel
irradiated prior to 1983. The Act also provides three payment
options for liquidating such liability (approximately $93.5
million at December 31, 1993) and the Company has, for Unit 1,
elected to delay payment, with interest, until 1998, the year in
which the Company had initially planned to ship irradiated fuel
to an approved DOE disposal facility. The Company has no such
retroactive liability for Unit 2. Progress in developing the
permanent DOE repository has been slow and it is unlikely that
the DOE's latest projection for opening this facility in 2010 can
be met. In the interim, DOE is proposing to begin acceptance of
some spent fuel from the electric utility industry as early as
1998 at a proposed Monitored Retrievable Storage (MRS) facility.
However, in view of the very limited progress made to date, it is
unlikely that this facility will begin operation in 1998. A more
probable date for operation of the MRS facility cannot be
accurately forecast at this time. Further, the projected
capacity for this MRS facility is such that any interim relief
provided to Unit 1 before the permanent repository opens is
likely to be small.
The Company has been studying spent fuel storage
alternatives and has in place a contract to rerack the Unit 1
spent fuel pool. Half of the pool will be reracked in 1998,
thereby providing significant core offload space until the year
2004. Some of the alternatives will require Nuclear Regulatory
Commission (NRC) review and/or approval and related state
approval. The present licensed storage capacity for Unit 2 will
meet the needs of the Unit sufficiently far into the future that
storage alternatives are not believed to be needed at this time.
Thus, the Company does not believe that the possible
unavailability of a DOE facility in 1998 will inhibit operation
of either Unit.
The cost of fuel utilized at Unit 1 for 1993, 1992 and 1991
was $.56, $.55 and $.68 per million BTU, respectively. The cost
of fuel utilized at Unit 2 for 1993, 1992 and 1991 was $.54, $.53
and $.62 per million BTU, respectively.
For the recovery of nuclear fuel costs through rates and for
further information concerning costs relating to decommissioning
of the Company's nuclear generating plants, see Item 8 --
Financial Statements and Supplementary Data, Note 1 -
Depreciation, Amortization and Nuclear Generating Plant
Decommissioning Costs and Note 7 - Nuclear Plant Decommissioning.
-17-
GAS SUPPLY. The Company distributes natural gas to a
geographic territory that extends from Syracuse to Albany. The
northern reaches of the system extend to Watertown and Glens
Falls. Not all of the Company's distribution areas are
physically interconnected with one another by Company-owned
facilities. Presently, nine separate distribution areas are
connected directly with CNG Transmission Corporation (CNG), an
interstate natural gas pipeline regulated by the FERC, via
seventeen delivery stations. The majority of the Company's gas
sales are for residential and commercial space and water heating.
Consequently, the demand for natural gas by the Company's
customers is seasonal and influenced by weather factors.
Under a twenty-year contract, the primary term of which
ended in March 1990, CNG was obligated, within broad limits, to
meet the full requirements of the Company as they would change
from time to time. Since 1986, the Company has exercised its
right, obtained in negotiation, to purchase part of its supply
from other sources and has aggressively pursued access to
alternative supplies of gas that are less expensive than pipeline
supply.
FERC Order No. 636, issued in April 1992, changed the
structure of interstate natural gas pipeline services and
completed the "evolution of competition, in the natural gas
industry." During 1992 and 1993, the Company actively pursued,
through the negotiation process established by the FERC, pipeline
services which would provide the Company with an appropriate
combination of firm transportation on several upstream pipelines,
CNG transportation and substantial storage rights. Negotiations
to implement Order No. 636, with CNG and the major upstream
pipelines, were essentially completed in November 1993 when the
last of the pipelines placed its revised service plans in effect.
Order No. 636 also helped complete the Company's primary
objective of replacing dependence on CNG sales service with
independently contracted gas supplies delivered through a
combination of firm transportation and storage.
The Company revised its post-Order No. 636 services to meet
peak load requirements on its system through a portfolio of firm
contracts capable of delivering approximately 903,000 dekatherms
per day to its service area. This portfolio includes firm
transportation totaling approximately 356,000 dekatherms on the
CNG system as well as five upstream pipelines, with firm supplies
purchased under 24 different contracts from a variety of
producers and marketers in the Gulf of Mexico, the Southwest and
Canada. An additional 434,000 dekatherms of peak day requirement
capacity is provided by firm storage withdrawal rights coupled
with firm winter season transportation service on CNG. Finally,
approximately 113,000 dekatherms is available to the Company
under peak shaving contracts with cogenerators on the Company's
system.
Transition Costs Under FERC Order 636. As a result of
structural changes under Order 636, 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
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assets needed to implement the Order (such as meters, valves,
etc.). Under the Order, pipelines are allowed to recover 100% of
eligible and prudently incurred costs from customers.
Eligibility and prudence will be determined by FERC review.
The amount of restructuring costs ultimately billed to the
Company will be determined in accordance with a number of
proceedings currently underway before the FERC. There are four
pipelines to which the Company has some liability. The Company
is actively participating in FERC proceedings 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, 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 purchased gas adjustment clause mechanism.
INDUSTRY SEGMENT DATA. The percentages of the total
revenues and operating income before income taxes, exclusive of
an Allowance for Funds Used During Construction (AFC), derived
from electric and gas operations for the past three years were as
follows:
Operating Income
Before Income Taxes
Total Revenues (Excluding AFC)
Year Electric Gas Electric Gas
1993 85% 15% 91% 9%
1992 85% 15% 91% 9%
1991 86% 14% 94% 6%
See also "Item 8--Financial Statements and Supplementary
Data," Note 10.
ENVIRONMENTAL MATTERS. General - The protection and
restoration of the environment remains a strategic concern of the
-19-
Company. In response to the issues facing the Company,
management has taken a number of actions specifically designed to
mobilize Company resources. The operations of the Company are
regulated by Federal and state governmental agencies and, to some
extent, by local governments in New York, with respect to air and
water quality and other environmental matters.
In compliance with environmental statutes and consistent
with its strategic philosophy, the Company performs environmental
investigations and analyses and installs, as required, pollution
control equipment, effluent monitoring instrumentation and
materials storage/handling facilities designed to prevent or
minimize releases of potentially harmful substances.
Expenditures for environmental matters for 1993 totaled
approximately $66 million, of which approximately $29 million was
capitalized as pollution control equipment or new plant
environmental surveillance and approximately $37 million was
charged to operating expense for operation of environmental
monitoring and waste disposal programs. Expenditures for 1994
are estimated to total $95 million, of which $58 million is
expected to be capitalized and $37 million charged to operating
expense. Similar expenditures for 1995 are estimated to total
$58 million, of which $14 million is expected to be capitalized
and $44 million charged to operating expense. The expenditures
for 1994 and 1995 include the estimated costs for the Company's
proportionate share of site investigation and cleanup of waste
sites discussed under "Solid/Hazardous Waste" below.
There are growing concerns about the effects of electric and
magnetic fields (EMFs), including those produced by distribution,
transmission and substation installations, as well as household
wiring and appliances. Numerous studies on the effects of EMFs
have been done and are continuing throughout the world, with
results that are often hard to interpret and sometimes
conflicting. On February 26, 1993, the Environmental Protection
Agency (EPA) called for significant additional research on EMFs.
The Company is taking a proactive approach and has worked with
school officials to identify magnetic field levels at school
buildings near its transmission lines. The Company is taking
steps to mitigate magnetic fields at these locations. It is
impossible to predict what further effect, if any, continued
research and epidemiological studies on EMFs could have on the
Company and the electric utility industry. The role of the
utility industry in addressing these environmental matters will
be prominent and could be costly.
Air - The Company is required to comply with applicable
Federal and State air quality requirements pertaining to
emissions into the atmosphere from its fossil-fuel generating
stations and other potential air pollution sources. The
Company's four fossil-fired generating stations (Albany, Huntley,
Oswego and Dunkirk) are operated in accordance with the
provisions of Certificates of Operation issued by the New York
State Department of Environmental Conservation (DEC).
On November 15, 1990, then President Bush signed into law
the Clean Air Act. The provisions of the Clean Air Act address
attainment and maintenance of ambient air quality standards,
mobile sources of air pollution, hazardous air pollutants, acid
rain, permits, enforcement, clean air research and other
-20-
miscellaneous items. The Clean Air Act will have a substantial
impact upon the operation of electric utility fossil-fired power
plants.
The acid rain provisions of the Clean Air Act require that
sulfur dioxide (SO2) emissions be reduced nationwide by 10
million tons from their 1980 levels and that NOx emissions be
reduced by two million tons from 1980 levels. Emission
reductions will be achieved in two phases - Phase I by January 1,
1995 and Phase II by January 1, 2000.
The Company filed its Phase I acid rain permit application
and compliance plan with the Environmental Protection Agency on
February 15, 1993. The Company has two units (Dunkirk 3 and 4)
affected in Phase I. Beginning in 1995, SO2 reductions of
approximately 10,000-15,000 tons per year must be achieved.
Among the options being considered by the Company for compliance
with the Phase I SO2 emission reduction requirements are fuel
switching, reduced utilization of Phase I affected units,
switching to a lower sulfur content coal and the purchase of
emission allowances.
With respect to NOx, Title IV of the Clean Air Act will
require emission reductions at the Company's Phase I affected
coal units. Installation of low NOx burners or equivalent
technology will be required to meet the new emission limitations.
In addition, Title I of the Clean Air Act (Provisions for the
Attainment and Maintenance of National Ambient Air Quality
Standards) will require the installation of "Reasonably Available
Control Technology" (RACT) on all of the Company's coal, oil and
gas-fired units by May 31, 1995. Compliance with Title I RACT
requirements at the Company's units will be achieved by
installing low NOx burners or other combustion control
technology.
The Company spent approximately $19 million in capital
expenditures in 1993 on Clean Air Act compliance and has included
approximately $46 million in its construction forecast for 1994
through 1997.
Phase II requirements associated with Title I and Title IV
of the Clean Air Act (targeted for the year 2000 and beyond) will
require the Company to further reduce its sulfur dioxide and
nitrogen oxide emissions at all of its fossil generating units.
Regulatory uncertainty surrounding these requirements precludes
an accurate assessment of compliance options and costs. Possible
options for Phase II SO2 compliance beyond those considered for
Phase I compliance include additional fuel switching,
installation of flue gas desulfurization or clean coal
technologies, repowering and the trading of emission allowances.
Compliance with Phase II NOx emission limits may require
installation of post-combustion NOx control technology such as
Selective Catalytic Reduction. States in the Northeast Ozone
Transport Region may determine that such controls are required on
fossil-fired electric generating units in order to attain Ambient
Air Quality Standards for ozone. This determination is expected
to be made in late 1994.
The Company's preliminary assessment of Phase II SO2 and NOx
compliance costs is that additional capital expenditures on the
-21-
order of $124 million (1994 dollars) will be required and
incremental annual fuel costs and operating expenses of
approximately $21 million will be incurred. However, there are a
number of uncertainties that make it difficult to project these
costs definitively at this time. See Construction Program below.
With response to all of these costs the Company believes,
based on traditional and historical rate treatment, that it is
probable that all additional expenditures and costs will be fully
recoverable through rates.
Water - The Company is required to comply with applicable
Federal and State water quality requirements, including the
Federal Clean Water Act, in connection with the discharge of
condenser cooling water and other waste waters from its steam-
electric generating stations and other facilities. Wastewater
discharge permits have been issued by DEC for each of its steam-
electric generating stations. These permits are renewed every
five years. Conditions of the permits require that studies be
performed to determine the effects of station operation on the
aquatic environment in the station vicinity and to evaluate
various technologies for mitigating losses of aquatic life.
Studies are ongoing and the Company believes that any additional
expenditures relating to or resulting from these studies will be
fully recoverable through rates.
The zebra mussel was identified in the United States in 1986
and has become an increasing concern, as it has rapidly
multiplied throughout the Great Lakes and adjoining inland
waters. The mussels colonize in large numbers, attaching to
almost any underwater surface and causing serious restriction of
the flow of water intake structures and plant piping systems.
All of the Company's steam electric stations and some of its
hydroelectric facilities have experienced infestation of zebra
mussels. The Company, in cooperation with other electric
utilities and research organizations, is developing short and
long-term control strategies to prevent or at least minimize
zebra mussels related operational problems at its generating
facilities. The Company believes that additional expenditures
and costs of operations caused by the zebra mussels problem will
be fully recoverable through rates.
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
-22-
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.
Solid/Hazardous Waste - See Item 8--Financial Statements and
Supplementary Data, Note 8.
NUCLEAR OPERATIONS. The Company is the owner and operator
of Unit 1 and the operator and 41% co-owner of Unit 2. Ownership
of Unit 2 is shared with Long Island Lighting Company (18%), New
York State Electric & Gas Corporation (18%), Rochester Gas and
Electric Corporation (14%), and Central Hudson Gas & Electric
Corporation (9%). Output of Unit 2, which has a capability of
1,062,000 kw., and the cost of operation and capital improvements
are shared in the same proportions as the cotenants' respective
ownership interests. For regulatory purposes, April 5, 1988 has
been recognized as the commercial operation date for Unit 2.
Unit 1 has a design capability of 613,000 kw. and was placed in
commercial operation in 1969.
The Company's nuclear operations are within the jurisdiction
of numerous federal and state regulatory agencies. The extent of
regulation by each agency varies, as does the impact such
regulation may have on plant operations. The principal agencies
include:
NRC: has primary and preemptive jurisdiction over all
health and safety aspects, operations and
decommissioning activities related to commercial
nuclear power plants.
PSC: has jurisdiction over the economic, regulatory
and rate aspects of nuclear power generation.
EPA: has jurisdiction over the discharge of airborne
effluents from generating power plants.
DEC: regulates the handling, disposition and
concentrations of "by-product" nuclear material at and
from the Unit sites, as ceded to it by the NRC.
DOE: has ultimate custody and control over all U.S.
origin spent nuclear fuel.
Federal Emergency Management Agency: has some
jurisdiction over emergency planning.
There are other agencies that have limited jurisdiction over
various aspects of nuclear plant operations.
The Company also participates in the Nuclear Management &
Resources Council (a trade association) and the Institute for
Nuclear Power Operations (an industry-formed group which
promulgates and monitors voluntary operating, maintenance and
performance standards).
Unit 1 Economic Study. See Item 8--Financial Statements and
Supplementary Data, Note 7.
-23-
Unit 1 Status. On February 20, 1993, Unit 1 was taken out
of service for a planned 55-day refueling and maintenance outage.
Unit 1 returned to service after a 55 day outage on April 15,
1993. The next refueling outage is scheduled to begin in
February 1995. Unit 1's capacity factor for 1993 was
approximately 81%. Using NRC guidelines, Unit 1's capacity
factor was approximately 88% (see below).
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 after a 59 day
outage. The next refueling outage is scheduled to begin in the
Spring of 1995. Unit 2's capacity factor for 1993 was
approximately 78%. Using NRC guidelines, Unit 2's capacity
factor was approximately 83% (see below).
There are various methods of measuring capacity factors.
The Company has traditionally used a methodology recognizing net
maximum dependable capacity of its nuclear units under optimum
conditions. In order to report operating indicators on a
consistent basis with other nuclear plants and in accordance with
NRC guidelines, the Company now plans to reflect capacity factors
with net maximum dependable capacity during the most restrictive
seasonal conditions. This will generally result in higher
capacity factors being disclosed than under the prior criteria
based on equivalent performance.
Unit 2 Operating Agreement. The Company and cotenant
companies executed an operating agreement (Agreement) in August
1989 which established the legal relationship between the Company
(as operator and 41% owner of Unit 2) and the other cotenants.
The Agreement outlines the responsibilities and participation of
the cotenants in the overall management of Unit 2, while the
Company remains responsible for day-to-day operations. The
Agreement has continued to be amended to extend the term of the
Agreement, with the latest amendment stating that the Agreement
will lapse on December 31, 1994, but provides for automatic
extensions unless terminated by at least one of the cotenants
after appropriate notice.
CONSTRUCTION PROGRAM. The purpose of the Company's ongoing
construction program is to assure reliable delivery of its
electric and gas services. The Company presently estimates that
its construction program for the years 1994 through 1998 will
require approximately $1.57 billion, excluding AFC, certain
overheads capitalized and nuclear fuel. For the years 1994
through 1998, the estimates are $408 million, $295 million, $287
million, $291 million and $285 million, respectively. The
estimate of construction additions for the period 1994 to 1998 is
reviewed by management as circumstances dictate.
The Company has also included amounts in the construction
forecast for hydro relicensing, as well as for gas system
expansion for the cogeneration market and greater customer
penetration.
ELECTRIC SUPPLY PLANNING. New York State passed energy
legislation in 1992 establishing a four-year cycle for updating
-24-
the State Energy Plan (SEP). The first SEP in this cycle is due
to be finalized in May 1994. In order to consider the
recommendations and policy direction of the 1994 SEP, the Company
has decided to prepare its next full Integrated Electric Resource
Plan (IERP) report during 1994, for completion by early 1995.
The timing will be further coordinated with the filing
requirements expected to be issued by the PSC in Case 92-E-0886,
Proceedings on the Motion of the Commission to Examine the
Integrated Resource Plans of Electric Utilities.
In June 1993, the Company produced an IERP Update to bridge
the gap between its previous IERP (September 1991) and the next
edition. The 1993 Update re-examined the timing requirements for
new resource commitments and found that the Company's current
owned and contracted generating capacity should enable it to meet
reserve requirements until approximately 2003-2004. Extension of
contracts with unregulated generators should postpone this date
until 2007-2008. Thus, from an installed capacity perspective,
there is no need to commit to new generation resources for
several years. This lack of need indicates that the Company's
resource bidding process will not be exercised for large scale
procurements in the near future, except for economy purchases.
In a pending PSC proceeding, the Company has agreed to a
settlement which includes the possible implementation of
renewable resource projects. If the settlement is approved, the
Company will pursue a 6.0 MW wind energy project and will jointly
participate with the other member systems of the NYPP in
considering additional renewable resources. The exact timing,
amount and ownership of these projects is not known at this time.
It is intended that only cost-effective renewable resources will
be acquired in implementing this agreement.
ELECTRIC DELIVERY PLANNING. As of January 1, 1994, the
Company had approximately 9,200 circuit miles of electric
delivery facilities. Evaluation of these facilities relative to
NYPP and Northeast Power Coordinating Council (NPCC) planning
criteria and anticipated Company internal and external demands is
an ongoing process intended to minimize the capital requirements
for expansion of these facilities. The Company is evaluating new
planning tools and methods to determine the adequacy and
reliability of its electric delivery facilities. As the
expansion of the unregulated generator market progresses, these
new generators impose technical, economic and construction
burdens on the Company. The Company is typically able to recover
the cost of interconnections constructed for unregulated
generator access to the Company's system, as well as costs
incurred by the Company to enhance its existing system due to the
unregulated generator tie-ins.
NEPA provides the FERC with broad authority to mandate
wholesale transmission access, which could potentially open the
interstate transmission system to new wholesale power
transactions. Under the Act, any electric utility or wholesale
power producer may apply to FERC for an order requiring a utility
to transmit such energy including enlargement of transmission
facilities. FERC is prohibited from ordering a utility to
transmit power to an end user (retail wheeling). FERC also
cannot order a utility to transmit power if to do so would impair
-25-
the utility's ability to recover all costs of providing these
services.
The Company has reviewed the adequacy of its electric
delivery facilities in the context of the IERP and has
determined, on a regional basis, which delivery facilities are
capable of supporting new unregulated generator resources. The
Company has also entered into wheeling agreements with several
unregulated generation project developers for sales to other
utilities. The projected annual value of this wheeling activity
is $63 million in 1994, increasing to $77 million in 1997. Under
current ratemaking practices, revenues from wheeling are
generally for the benefit of ratepayers.
The Company is committed to a policy of providing
transmission service upon request, provided that the revenue
derived from such services protects the economic well-being of
the Company's customers.
DEMAND-SIDE MANAGEMENT PROGRAMS. Traditionally, the Company
served customer loads by building and operating the supply
resources needed to meet growing demand. More recently, the PSC
has encouraged the Company and other state utilities to market
energy efficient programs as an alternative, lower cost method of
meeting customer energy service needs.
The Company's DSM programs are an important part of the
Company's IERP (see "Electric Supply Planning"), which calls for
DSM to contribute as much as 500 MW, or up to 26% of projected
new capacity resources required for the years 2000-2005. The
IERP is supplemented by a more detailed, long-range DSM plan,
which in turn drives the selection of programs for
implementation. Actual energy reductions for the calendar year
1992 amounted to 312,849 MWH, compared with a goal of 231,257
MWH. The coincident winter peak was reduced by 41 MW compared
with a goal of 38 MW.
Ongoing DSM program implementation in 1993 accounted for an
estimated annual energy reduction of 270,000 MWH. Coincident
winter peak reductions from 1993 program activity are estimated
to be 50 MW. These estimates are subject to adjustment after
actual evaluation results become available in July 1994.
In 1993, the Company invested approximately $40 million in
DSM programs, including $7.6 million procured through the all-
source bidding process. Company sponsored programs addressed
residential electric water and space heating, lighting and new
construction. Commercial and industrial programs addressed
lighting, motors, adjustable speed drives and other custom
conservation measures. Programs directed toward farm customers
addressed water heating, lighting and ventilation. Bidder
sponsored programs for residential customers included
refrigerator recycling and conservation measures for multi-family
dwellings. A third program sponsored by a commercial/industrial
bidder offered a multi-measure program integrated with financing
options. Two additional bid programs were sponsored by an
industrial customer for lighting and other measures installed at
a specific plant site.
-26-
In 1994, the Company expects to invest an additional $41.5
million for demand-side investments.
Individual DSM programs are subject to PSC approval prior to
implementation and the Commission has established a two-year
filing cycle for DSM programs. The Company filed its current
programs for an integrated 1993-1994 DSM Plan in October 1992.
The PSC allows the Company to collect DSM programs costs,
lost net revenue ("lost margin") and a financial incentive for
cost-effective program implementation. Prior to 1993, these
costs were all recovered through the Demand Side Investment and
Revenue Adjustment Mechanism (DIRAM), and reconciled annually.
Starting in 1993, each of these will be recovered in a different
manner. Program costs and development support program costs will
be recovered on a current basis in base rates, distributed among
the classes through accepted cost of service allocations. The
1995 price caps rate proposal would eliminate NERAM and move lost
margin recovery back into DIRAM.
Total electric prices will increase in the near term with
DSM programs in place due to recovery of lost margin, program
costs, and earnings incentive. However, customers who
participate in the programs should see a net benefit due to
reduced consumption and average customer bills should be lower
than without the programs. The allocation of electric price
impacts from DSM programs remains an issue of concern in the
industry and is being addressed through discussions among the
Company, PSC staff, and other intervenors.
As part of the Company's 1993 rate settlement, the Company
has developed an innovative "DSM Subscription Service" in which
its largest commercial and industrial customers will be given the
opportunity to choose between two types of demand-side management
service: 1) the Company's traditional subsidized DSM programs,
or 2) a non-subsidized "shared savings program" in which each
participating customer pays the full cost associated with their
individual DSM projects. Customers selecting the non-subsidized
service would not be required to contribute to the cost of
providing DSM subsidies (rebates).
RESEARCH AND DEVELOPMENT. The Company maintains a
substantial research and development program aimed at supporting
the Company and its customers in the delivery and use of energy
products. The focus of the Company's research effort is and will
be to explore practical applications for new and existing
technologies in the energy business. These efforts are aimed at
(1) improving the efficiency of energy use and delivery; (2)
minimizing environmental impacts of energy production, delivery
and use; (3) minimizing facility maintenance costs; (4) improving
facility availability; and (5) developing renewable energy
technologies. The research effort is also directed towards
earning a return on products developed from research, by
encouraging commercialized applications of research products and
promoting their acceptance by other utilities and industry.
Research and development expenditures are charged to
operating expenses through the Company's research and development
revenue and expenditures matching plan authorized by the PSC.
-27-
Research and development expenditures in 1993, 1992 and 1991 were
approximately $39.0, $35.2 and $29.9 million, respectively. The
increased expenditures reflect an increase in Electric Power
Research Institute dues which had been previously reduced due to
financial problems experienced by the Company.
In addition to an active internal R&D program, these amounts
also include research support to the Electric Power Research
Institute, the Empire State Electric Energy Research Corporation,
the New York State Energy Research and Development Authority and
the Gas Research Institute.
EMPLOYEE RELATIONS. All of the Company's non-supervisory
production and clerical workers subject to collective bargaining
are represented by the International Brotherhood of Electrical
Workers (AFL-CIO). A two-year-nine-month agreement between the
Company and the union, which became effective June 1, 1993,
provides for annual wage increases of 4% through 1995 and
includes modifications to employee pension and health plans and
changes in various work practices. It is estimated that
approximately 75% of the Company's total labor costs are
applicable to operation and maintenance and approximately 25% are
applicable to construction (and accordingly are capitalized).
The Company's work force at December 31, 1993 numbered
approximately 11,500 of whom approximately 8,000 are union
members.
LIABILITY INSURANCE. As of January 31, 1994, the Company's
Directors & Officers liability insurance was renewed. This
coverage includes nuclear operations and insures the Directors
and officers against obligations incurred as a result of their
indemnification by the Company. The coverage also insures the
officers and directors against liabilities for which they may not
be indemnified by the Company, except for a dishonest act or
breach of trust.
-28-
Item 2. Properties.
ELECTRIC SERVICE. As of January 1, 1994, the Company owned
and operated four fossil fuel steam plants (as well as having a
25% interest in the Roseton Steam Station and its output), two
nuclear fuel steam plants, various combustion turbine and diesel
generating units and 71 hydroelectric plants. The Company also
leases small hydroelectric plants and purchases substantially all
of the output of 71 others. The Company's Canadian subsidiary,
Opinac Energy Corporation, owns Canadian Niagara Power Company,
Limited (owner and operator of the 76.8 MW Rankine hydroelectric
plant) which distributes electric power within the Province of
Ontario. In addition, the Company has contracts to purchase
electric energy from NYPA and other sources. See Item 1 --
Business. - "Unregulated Generators", "New York State Power
Authority (NYPA)" and "Other Purchased Power" and Item 8 --
Financial Statements and Supplementary Data, Electric and Gas
Statistics.
The following is a list of the Company's major generating
stations at February 1, 1994:
Company's
Share of
Net
Capability
Station, Location and Percent Energy in
Ownership Source Megawatts
Huntley, Niagara River (100%) Coal 715
Dunkirk, Lake Erie (100%) Coal 570
Albany, Hudson River (100%) Oil/Natural
Gas 400
Oswego, Lake Ontario (100%)
(Unit 5) Oil 850
Oswego, Lake Ontario (76%)
(Unit 6) Oil 646
Roseton, Hudson River (25%) Oil/Natural
Gas 300
Nine Mile Point, Lake Ontario (100%) Nuclear 613
(Unit 1)
Nine Mile Point, Lake Ontario (41%) Nuclear 435
(Unit 2)
Central Hudson Gas and Electric Corporation, the operator of
the Roseton plant, has agreed to acquire the Company's 25%
interest in that plant in ten equal installments of 2.5% (30 MW)
starting on December 31, 1994 and on each December 31 thereafter
through and including December 31, 2003 at depreciated book value
on each purchase date. As part of the agreement, the Company has
the option to purchase up to a 25% (300 MW) interest in the
Roseton plant in December 2004 at depreciated book value on such
date. The agreement is subject to PSC approval.
As of December 31, 1993, the Company's electric transmission
and distribution systems were comprised of 960 substations with a
-29-
rated transformer capacity of approximately 28,500,000 kva.,
about 9,200 circuit miles of overhead transmission lines, about
1,200 cable miles of underground transmission lines, about
110,900 conductor miles of overhead distribution lines and about
8,500 cable miles of underground distribution cables, only a part
of such transmission and distribution lines being located on
property owned by the Company. The electric system of the
Company and Canadian Niagara Power Company, Limited is directly
interconnected with other electric utility systems in Ontario,
Quebec, New York, Massachusetts, Vermont and Pennsylvania, and
indirectly interconnected with most of the electric utility
systems in the United States.
Seasonal variation in electric customer load has been
consistent. Over the last five years, the Company's maximum
hourly demand has occurred in the winter months; however, on
occasion summer peaks have approached the level of the winter
peaks. The maximum simultaneous hourly demand (excluding economy
and emergency sales to other utilities) on the electric system of
the Company for the twelve months ended December 31, 1993
occurred on February 1, 1993 and was 6,191,000 kw., of which
527,000 kw. was generated in hydroelectric plants, 3,274,000 kw.
was generated in thermal electric plants and 2,894,000 kw. (of
which 1,120,000 kw. was firm) was purchased. Economy and
emergency sales to other utilities on such date were 504,000 kw.
The Company set an all-time electric peak load on January 19,
1994 of 6,458,000 kw.
The results of recent litigation in other jurisdictions
indicate that a potentially substantial title problem may exist
with respect to the Company's title and legal rights to gas and
electric facilities on native American reservations across the
Company's system. A longstanding Federal statute was interpreted
to require Federal approval of all conveyances from native
Americans in New York State. The issue is now being raised by
certain native American tribes within the Company's service
territory. The Company is unable to estimate any potential costs
associated with this issue, although it believes any such cost
would be recoverable in rates, based on traditional ratemaking
principles.
NEW YORK POWER POOL. The Company, six other New York
utilities and NYPA comprise the New York Power Pool, through
which they coordinate the planning and operation of their
interconnected electric production and transmission facilities in
order to improve reliability of service and efficiency for the
benefit of customers of their respective electric systems.
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). The total nuclear property insurance is $2.7
billion.
-30-
NEIL is a utility industry-owned mutual insurance company
chartered in Bermuda. NEIL also provides insurance coverage
against the extra expense incurred in purchasing replacement
power during prolonged accidental outages. As summarized below,
the insurance provides coverage for outages for 156 weeks after a
21-week waiting period.
Nine Mile Point
Unit No. 1 Unit No. 2
Weekly indemnity for 52 weeks
after 21 week waiting period $ 894,220 $ 773,582
Weekly indemnity for next 52 weeks 599,127 518,300
Weekly indemnity for next 52 weeks 599,127 518,300
Total aggregate payment available 108,808,648 94,129,464
NEIL insurance is subject to retrospective premium
adjustment for which the Company could be assessed up to
approximately $11.3 million per loss.
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. Presently, 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 excess over 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 provide, among other
things, that insurance and indemnity will cover precautionary
evacuations whether or not a nuclear incident actually occurs.
GAS SERVICE. The Company distributes gas purchased from
suppliers and transports gas owned by others. As of December 31,
1993, the Company's natural gas system was comprised of
approximately 7,400 miles of pipelines and mains, only a part of
which is located on property owned by the Company. The maximum
24-hour coincidental send-out of natural gas by the Company for
the twelve-months ended December 31, 1993 was 929,285 dekatherms
-31-
and occurred on February 6, 1993. A new maximum day gas send-out
of 995,801 dekatherms was set on January 26, 1994.
SUBSIDIARIES. One of the Company's subsidiaries, Opinac
Energy Corporation, a Canadian-based company, owns Canadian
Niagara Power Company, Limited (CNP). CNP generates electricity
at its Niagara Falls, Ontario hydro plant for the wholesale
market and for its distribution system in Fort Erie, Ontario.
On June 30, 1993, the Company sold its interest in its
Canadian oil and gas company, Opinac Exploration Limited, in
order to streamline the Company's business and focus on its core
electric and gas utility assets. The interest was sold for a
cash consideration of $122 million Canadian (approximately $95
million U.S.). The sale did not have a material impact on the
Company's results of operations or financial condition.
Another of the Company's subsidiaries, HYDRA-CO Enterprises,
Inc., develops, owns and/or operates co-generation and small
power plants both within and outside of the Company's service
territory generally in conjunction with other parties. HYDRA-CO
is involved in projects with total assets of more than $900
million. The Company has invested in HYDRA-CO, out of its
retained earnings, approximately $80 million at December 31,
1993.
In January 1993, in a World Bank sponsored bid, a HYDRA-CO
partnership was selected to negotiate final contracts on a 60-
megawatt diesel power station in Kingston, Jamaica. HYDRA-CO is
also working on a project in Canada.
HYDRA-CO now has interests in some 25 plants in operation or
under construction, with an owned interest of about 300
megawatts. The plants use a variety of technologies powered by
diverse fuels, including water, wood, coal, wind and natural gas.
The diversity is by design, reflecting the Company's judgment on
what is required to be a long-term developer, investor and
operator in the independent power market.
MORTGAGE LIENS. Substantially all of the Company's
operating properties are subject to a mortgage lien securing its
mortgage debt.
-32-
Item 3. Legal Proceedings.
See also Item 8 -- Financial Statements and Supplementary
Data, Note 8 and Item 1 -- Unregulated Generators.
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 is 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 pick up waste oil at locations throughout Central New York,
allegedly including one or more Company facilities.
Settlement negotiations, which had been in progress since
1988 with a group of defendants seeking "de minimis" status, were
discontinued near the close of 1991, and the government's
proposed settlement with a small group of major contributor
defendants has been subject to severe objection from the
remaining defendants, including the Company. These negotiations
were related to costs associated with remediation of the "source
control" operable unit at the York Oil Site.
Separate negotiations have resulted in an agreement to
provide for the financing by a group of participating defendants
of the "contamination pathways" operable unit, aimed at
preventing the further spread of contamination. An Order on
Consent in connection with this aspect of the litigation was
lodged with the Court on May 15, 1992, and has been entered in
settlement of this portion of the litigation.
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. All
suits related to this matter have been consolidated into a single
action.
The government issued a final settlement demand upon the
Company in February 1994, including a settlement figure which was
rejected by the Company. Litigation is now proceeding against
the Company and several other PRP defendants which elected not to
accept the terms of the government's final settlement demand.
The Company will also participate in bringing additional PRP
defendants not previously named by the government into the
ongoing litigation as a means of assuring a more equitable
allocation of remaining liability.
-33-
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-judgement 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. 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. This
motion has yet to be decided. On March 16, 1994, the Court
denied Fourth Branch's motion for preliminary judgment. The
Company also notified Fourth Branch by letter dated March 1,
1994, that the Licensing Agreement between Fourth Branch and the
Company is terminated. On March 15, 1994, Fourth Branch
petitioned the FERC for Extraordinary Relief. The Company
intends to oppose this petition before the FERC. 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. Also see Item 1 -- "Unregulated
Generators" for other suits involving unregulated generators.
On June 22, 1993, the Company and twenty other industrial
entities and the owner/operator of the Pfohl Brothers Landfill
near Buffalo, New York, were sued by a group of residents living
in the vicinity of the landfill seeking compensation and damages
for economic loss and property damages claimed to have resulted
-34-
from contamination emanating from the landfill. To date, no
governmental action has been taken against the Company as a
potentially responsible party (PRP). The Company has undertaken
to establish defenses to the allegations in this lawsuit, and is
investigating its alleged connection to the landfill to determine
whether participation in an established and ongoing voluntary
remedial program by identified PRPs is warranted. The Company is
unable to predict the ultimate outcome of this proceeding.
Item 4. Submission of Matters to a Vote of Security Holders.
The Company has nothing to report for this item.
-35-
EXECUTIVE OFFICERS OF REGISTRANT
All executive officers of the Company are elected on an annual basis at the May meeting of the Board of Directors.
There are no family relationships between any of the executive officers. There are no arrangements or understandings between
any of the officers listed below and any other person pursuant to which he was selected as an officer.
Age at
Executive 12/31/93 Current and Prior Positions Date Commenced
William E. Davis 51 Chairman of the Board and Chief Executive Officer May 1993
Vice Chairman of the Board of Directors November 1992
Senior Vice President - Corporate Planning April 1992
Vice President - Corporate Planning February 1990
Executive Deputy Commissioner of the New York Prior to joining
State Energy Office the Company
William J. Donlon 63 Retired July 1993
Chairman of the Board and Chief Executive Officer June 1988
John M. Endries 51 President June 1988
B. Ralph Sylvia 53 Executive Vice President - Nuclear November 1990
Senior Vice President - Nuclear July 1990
Senior Vice President - Nuclear Operations, Prior to joining
Detroit Edison the Company
David J. Arrington 42 Senior Vice President - Human Resources December 1990
Vice President - Human Resources - Worldwide Prior to joining
Operations, Sara Lee Bakery the Company
John P. Hennessey 56 Retired December 1993
Senior Vice President - Electric Customer Service October 1990
Senior Vice President May 1982
Darlene D. Kerr 42 Senior Vice President - Electric Customer Service January 1994
Vice President - Electric Customer Service July 1993
Vice President - Gas Marketing and Rates February 1991
Vice President - System Electric Operations May 1988
-36-
Gary J. Lavine 43 Senior Vice President - Legal & Corporate
Relations May 1993
Senior Vice President - Legal & Corporate
Relations and General Counsel October 1990
Vice President - General Counsel and Secretary November 1987
Robert J. Patrylo 47 Senior Vice President - Gas Customer Service December 1990
President - RJP Associates Prior to joining
Philadelphia Gas Works: the Company
President and Chief Executive Officer 1987 - 1989
John W. Powers 55 Senior Vice President - Finance & Corporate
Services October 1990
Senior Vice President March 1990
Senior Vice President - Treasurer November 1987
Michael P. Ranalli 60 Senior Vice President - Electric Supply &
Delivery October 1990
Senior Vice President February 1987
Theresa A. Flaim 44 Vice President - Corporate Planning April 1993
Manager - Gas Rates & Integrated Resource Planning June 1991
Director - Demand-Side Planning November 1987
Harold J. Bogan 64 Secretary October 1992
Assistant Secretary January 1968
Steven W. Tasker 36 Vice President - Controller December 1993
Controller May 1991
Assistant Controller October 1988
2
PART II
Item 5.
MARKET FOR REGISTRANT'S COMMON EQUITY 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
3
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 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
================== ==================
4
Item 6.
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
9
Item 7.
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 includes the
Company in its "Below Average," or lowest rated group in its
assessment of business position and has recently reduced the
Company's credit ratings. 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
10
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.
11
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:
12
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
13
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.
14
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
unforeseen 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 Item 8. Financial Statements and Supplementary
Data, Note 7 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
15
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."
16
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.
17
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
18
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.
19
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
20
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.
21
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
======= ======= ======= =========
22
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 Item 8. Financial Statements and Supplementary Data -
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.
23
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)%
24
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.
25
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
====== ======== ====== ====== ====== =======
26
% 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%
====== ======= ======= ======
27
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
Item 8. Financial Statements and Supplementary Data - 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%.
29
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:
30
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%
31
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
32
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
33
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
34
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 Item 8. Financial Statements and Supplementary
Data 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 35
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
36
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 Item 8.
Financial Statements and Supplementary Data - Note 8 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 Item 8.
Financial Statements and Supplementary Data - Note 7 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
37
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 February 23, 1994, were:
Secured Preferred Commercial
Debt Stock Paper
Standard & Poors
Corporation BBB- BB+ A-3
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. S&P also
observed that because of the more disparate business prospects
for electric utilities, it was segregating companies into 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.
Based on this criteria, on February 23, 1994, S&P reduced the
Company's credit ratings as disclosed above. In addition, S&P
announced that although the
38
Company has taken steps to control operating expenses and limit
exposure to unregulated generator costs and to otherwise improve
revenues, the ratings outlook for the Company would remain
negative pending demonstrated financial improvement. The Company
is taking a number of steps to address this matter as stated
elsewhere in this report.
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 although it indicated in February 1994 that it would
maintain current ratings on all existing debt.
These developments may increase the cost to issue new securities.
Item 8
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
A. Financial Statements
Report of Management
Report of Independent Accountants
Consolidated Statements of Income and Retained Earnings for
each of the three years in the period ended December 31,
1993.
Consolidated Balance sheets at December 31, 1993 and 1992.
Consolidated Statement of Cash Flows for each of the three
years in the period ended December 31, 1993.
Notes to Consolidated Financial Statements.
Financial Statement Schedules -
The following Financial Statement Schedules are submitted as
part of Item 14, Exhibits, Financial Statement Schedules,
and Reports on Form 8-K, of this Report. (All other
Financial Statement Schedules are omitted because they are
not applicable, or the required information appears in the
Financial Statements or the Notes thereto.)
Schedule V - Utility Plant
Schedule VI - Accumulated Depreciation and Amortization
Schedule VIII - Valuation and Qualifying Accounts and
Reserves
39
Schedules IX - Short-term Borrowings
Schedule X - Supplementary Income Statement Information
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.
40
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
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
---------------------------------------------------------
Consolidated Statements of Income and Retained Earnings
-------------------------------------------------------
In thousands of dollars
For the year ended December 31, 1993 1992 1991
Operating revenues:
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
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
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
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets In thousands of dollars
At December 31, 1993 1992
ASSETS
Utility plant (Note 1):
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
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
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:
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
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
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:
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
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
Supplemental schedule of noncash investing and
financing activities:
Liability for environmental restoration . . . . . . . . . . . . 25,000 15,000 200,000
During 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.
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
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
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
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
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:
In thousands of dollars
At December 31: 1993 1992
Short-term debt:
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.
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.
In thousands of dollars
Percentage Accumulated Construction
Ownership Utility Plant depreciation work in
progress
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.
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:
Common Stock Preferred Stock
$1 par value $100 par value
Non-
Shares Amount* Shares Redeemable* Redeemable*
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).
Preferred Stock
$25 par value
Non- Capital Stock Premium
Shares Redeemable* Redeemable* and Expense (Net)*
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).
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:
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.
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:
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.
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.
LONG-TERM DEBT
Long-term debt at December 31, consisted of the following:
In thousands of dollars
Series Due 1993 1992
First mortgage bonds:
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 -
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
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
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, 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.
Net pension cost for 1993, 1992 and 1991 included the following components:
In thousands of dollars
1993 1992 1991
$
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
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:
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 plan 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
Pension costs included in the consolidated balance sheets . . . . . . . . . $ 37,238 $ 33,631
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
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
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.
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
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
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 of
dollars
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.
NOTE 7. NUCLEAR 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.
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.
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
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
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):
Purchased Estimated annual
Facility Expiration date of capacity capacity cost
contract in kw.
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.
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
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.
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
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
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
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
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.
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:
December 31,
(In thousands of dollars)
1992
1993
Carrying Carrying
Amount Fair Value Amount Fair
Value
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
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.
In thousands of dollars
1993 1992 1991
Operating revenues:
. . . . . . . . . . .
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
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
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. The Company's quarterly results of operations reflect the
seasonal nature of its business, with peak electric loads in summer
and winter periods. Gas sales peak in the winter.
In thousands of dollars
Earnings
Quarter Operating Operating Net per
Ended revenues income income common share
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
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.
ELECTRIC AND GAS STATISTICS
ELECTRIC CAPABILITY
Thousands of kilowatts
December 31, 1993 % 1992 1991
Owned:
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.
ELECTRIC STATISTICS
1993 1992 1991
Electric sales (Millions of kw-hrs.):
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
$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
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
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
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
-37-
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.
The Company has nothing to report for this item.
PART III
The information required by Part III of this Form 10-K, Item
10 (Directors, Executive Officers, Promoters and Control Persons
of the Registrant), Item 11 (Executive Compensation), Item 12
(Security Ownership of Certain Beneficial Owners and Management)
and Item 13 (Certain Relationships and Related Transactions) is
incorporated by reference to such information appearing in the
definitive Proxy Statement dated March 28, 1994, filed with the
Securities and Exchange Commission in connection with the
Company's 1994 Annual Meeting of Shareholders. Further
information regarding Executive Officers as required
under Item 10 (Directors, Executive Officers, Promoters and
Control Persons of the Registrant) appears at the end of Part I
of this Form 10-K Annual Report.
-38-
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K.
(a) Certain documents filed as part of the Form 10-K.
(1) INDEX OF FINANCIAL STATEMENTS
Report of Independent Accountants
Consolidated Statements of Income and Retained Earnings for
each of the three years in the period ended December 31,
1993
Consolidated Balance Sheets at December 31, 1993 and 1992
Consolidated Statements of Cash Flows for each of the three
years in the period ended December 31, 1993
Notes to Consolidated Financial Statements
Separate financial statements of the Company have been
omitted since it is primarily an operating company and all
consolidated subsidiaries are totally held directly or
through subsidiaries.
(2) The following financial statement schedules of the Company
for the years ended December 31, 1993, 1992 and 1991 are
included:
Report of Independent Accountants on Financial Statement
Schedules
Consolidated Financial Statement Schedules:
V--Utility Plant
VI--Accumulated Depreciation and Amortization
of Utility Plant
VIII--Valuation and Qualifying Accounts and Reserves
IX--Short Term Borrowings
X--Supplementary Income Statement Information
The Financial Statement Schedules above should be read in
conjunction with the Consolidated Financial Statements in
the 1993 Annual Report to Stockholders.
Schedules other than those mentioned above are omitted
because the conditions requiring their filing do not exist
or because the required information is given in the
financial statements, including the notes thereto.
(b) Reports on Form 8-K:
Form 8-K Reporting Date - February 18, 1994.
Items Reported - Item 5. Other Events.
-39-
Registrant filed certain financial information
substantially constituting a portion of its 1993 Annual
Report to Stockholders including financial statements for
the fiscal year ended December 31, 1993
Form 8-K Reporting Date - February 24, 1994
Items Reported - Item 5. Other Events.
Registrant filed information concerning the Standard &
Poors lowering of the credit rating of the Company's
securities.
(c) Exhibits.
See List of Exhibits.
(d) Financial Statement Schedules.
See (a)(2) above.
-40-
REPORT OF INDEPENDENT ACCOUNTANTS ON
FINANCIAL STATEMENT SCHEDULES
To the Board of Directors
Niagara Mohawk Power Corporation
Our audits of the consolidated financial statements of Niagara
Mohawk Power Corporation referred to in our report dated
January 27, 1994 of this Form 10-K also included an audit of the
Financial Statement Schedules listed in Item 14(a) of this Form
10-K. In our opinion, these Financial Statement Schedules
present fairly, in all material respects, the information set
forth therein when read in conjunction with the related
consolidated financial statements.
PRICE WATERHOUSE
Syracuse, New York
January 27, 1994
-41-
EXHIBIT 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the
Registration Statement on Form S-8 (Nos. 33-36189, 33-42720, 33-
42721 and 33-42771) and to the incorporation by reference in the
Prospectus constituting part of the Registration Statement on
Form S-3 (Nos. 33-45898, 33-50703, 33-51073, 33-55546 and 33-
59594) of Niagara Mohawk Power Corporation of our report dated
January 27, 1994 included in the Company's Form 10-K dated
March 24, 1994. We also consent to the incorporation by
reference of our report on the financial statement schedules of
this Form 10-K.
PRICE WATERHOUSE
Syracuse, New York
March 24, 1994
-42-
. . . . . . . . . . . . . . . . Schedule V - 1993
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE V - UTILITY PLANT
(In Thousands of Dollars)
Column A Column F
Balance at December 31, 1993
Classification Electric Gas Common Total
Plant in service:
Production . . . . . . . . . $4,132,045 $1,910 $ - $4,133,955
Transmission . . . . . . . . 1,222,796 - - 1,222,796
Distribution . . . . . . . . 2,347,646 829,331 - 3,176,977
General. . . . . . . . . . . 282,060 12,591 244,294 538,945
7,984,547 843,832 244,294 9,072,673
Construction work in progress 441,778 85,243 42,383 569,404
Nuclear fuel . . . . . . . . . 458,186 - - 458,186
Plant held for future use. . . 3,348 1,467 - 4,815
Plant leased to others . . . . 3,451 - - 3,451
Total utility plant . . . $8,891,310 $930,452 $286,677 $10,108,529
Neither the total additions nor the total deductions during the year ended December 31, 1993
amounted to more than 10% of the closing balance of total utility plant, and the information
required by Columns B, C, D and E is therefore omitted. A summary of Columns C, D and E for the
year ended December 31, 1993 is as follows:
Column C - Additions at Cost $ 521,864
Column D - Retirements (38,198)
Column E - Other changes as follows:
Amortization of capitalized leases (8,911)
NM Uranium, Inc. write-off (a) (3,300)
Miscellaneous (Net) (5,188)
$ 466,267
-43-
See Note 1 of Notes to the Consolidated Financial Statements.
(a) See Schedule VIII.
-44-
Schedule V - 1992
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE V - UTILITY PLANT
(In Thousands of Dollars)
Column A Column F
Balance at December 31, 1992
Classification Electric Gas Common Total
Plant in service:
Production . . . . . . . . $3,957,720 $ 1,906 $ - $3,959,626
Transmission . . . . . . . 1,163,268 - - 1,163,268
Distribution . . . . . . . 2,200,155 770,822 - 2,970,977
General. . . . . . . . . . 262,791 12,275 231,424 506,490
7,583,934 785,003 231,424 8,600,361
Construction work in progress 487,560 63,366 36,511 587,437
Nuclear fuel . . . . . . . . 445,890 - - 445,890
Plant held for future use. . 3,348 2,445 - 5,793
Plant leased to others . . . 2,781 - - 2,781
Total utility plant . . $8,523,513 $850,814 $267,935 $9,642,262
Neither the total additions nor the total deductions during the year ended December 31, 1992
amounted to more than 10% of the closing balance of total utility plant, and the information
required by Columns B, C, D and E is therefore omitted. A summary of Columns C, D and E for the
year ended December 31, 1992 is as follows:
Column C - Additions at Cost $ 507,089
Column D - Retirements (48,483)
Column E - Other changes as follows:
Amortization of capitalized leases (7,653)
Merger - Syracuse Suburban Gas Company, Inc. 12,991
-45-
Miscellaneous (Net) (1,894)
$ 462,050
See Note 1 of Notes to the Consolidated Financial Statements.
-46-
Schedule V - 1991
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE V - UTILITY PLANT
(In Thousands of Dollars)
Column A Column F
Balance at December 31, 1991
Classification Electric Gas Common Total
Plant in service:
Production . . . . . . . . $3,886,830 $ 1,877 $ - $3,888,707
Transmission . . . . . . . 1,108,068 - - 1,108,068
Distribution . . . . . . . 2,060,479 705,317 - 2,765,796
General. . . . . . . . . . 242,410 11,741 180,456 434,607
7,297,787 718,935 180,456 8,197,178
Construction work in progress 445,301 72,320 51,373 568,994
Nuclear fuel . . . . . . . . . 408,643 - - 408,643
Plant held for future use. . . 3,348 - - 3,348
Plant leased to others . . . . 2,049 - - 2,049
Total utility plant . . . $8,157,128 $791,255 $231,829 $9,180,212
Neither the total additions nor the total deductions during the year ended December 31, 1991
amounted to more than 10% of the closing balance of total utility plant, and the information
required by Columns B, C, D and E is therefore omitted. A summary of Columns C, D and E for the
year ended December 31, 1991 is as follows:
Column C - Additions at Cost $522,475
Column D - Retirements (28,798)
Column E - Other changes as follows:
Amortization of capitalized leases (12,525)
NM Uranium, Inc. write-off (3,000)
Miscellaneous (Net) (681)
$477,471
-47-
See Note 1 of Notes to the Consolidated Financial Statements.
(a) See Schedule VIII.
-48-
Schedule VI - 1993
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF UTILITY PLANT
(In Thousands of Dollars)
Column A Column B Column C Column D Column E Column F
Balance at Additions Balance at
Beginning Charged to Other Charges- End of
of Period Costs and Retirements Add (Deduct)- Period
Description 12/31/92 Expenses (Note a) Describe 12/31/93
Electric $2,366,319 $ 250,630 $ 53,374 $ 473 (b) $2,560,611
556 (c)
(649) (d)
(3,344) (e)
Nuclear Fuel 334,630 35,972 370,602
Gas 224,636 19,228 1,719 4 (b) 242,540
391 (e)
Common 50,392 10,830 4,018 280 (b) 57,484
Total $2,975,977 $ 316,660 $ 59,111 $ (2,289) $3,231,237
Notes:
(a) Amounts represent retirements of utility plant at book value, estimated where actual
amounts are not known, together with cost of removal, less salvage.
(b) Provision for depreciation on transportation equipment, etc. which, together with
operating costs and maintenance thereof, is charged to operations, utility plant and
other accounts on the basis of usage.
(c) Provision for depreciation charged directly to Accounts Receivable.
(d) Represents adjustment relating to currency translation of Canadian subsidiary.
(e) Miscellaneous.
See Note 1 of Notes to the Consolidated Financial Statements.
-49-
Schedule VI - 1992
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF UTILITY PLANT
(In Thousands of Dollars)
Column A Column B Column C Column D Column E Column F
Additions
Balance at Charged Other Balance at
Beginning to Retirements Charges- End of
of Period Costs and (Note a) Add (Deduct)- Period
Description 12/31/91 Expenses Describe 12/31/92
Electric $2,180,065 $251,035 $64,432 $ 509 (b) $2,366,319
600 (c)
(1,573)(d)
115 (e)
Nuclear Fuel 308,471 26,159 - - 334,630
Gas 208,568 17,700 3,885 5 (b) 224,636
2,248 (f)
Common 43,900 7,548 1,261 278 (b) 50,392
(73)(e)
Total $2,741,004 $302,442 $69,578 $ 2,109 $2,975,977
Notes:
(a) Amounts represent retirements of utility plant at book value, estimated where actual
amounts are not known, together with cost of removal, less salvage.
(b) Provision for depreciation on transportation equipment, etc. which, together with operating
costs and maintenance thereof, is charged to operations, utility plant and other accounts
on the basis of usage.
(c) Provision for depreciation charged directly to Accounts Receivable.
(d) Represents adjustment relating to currency translation of Canadian subsidiary.
(e) Miscellaneous.
(f) Represents amount related to Merger with Syracuse Suburban Gas Company, Inc.
See Note 1 of Notes to the Consolidated Financial Statements.
-50-
Schedule VI - 1991
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF UTILITY PLANT
(In Thousands of Dollars)
Column A Column B Column C Column D Column E Column F
Balance at Additions Balance at
Beginning Charged to Other Charges- End of
of Period Costs and Retirements Add (Deduct)- Period
Description 12/31/90 Expenses (Note a) Describe 12/31/91
Electric $1,978,823 $237,273 $37,148 $502 (b) $2,180,065
589 (c)
62 (d)
(36) (e)
Nuclear Fuel 269,784 38,687 - - 308,471
Gas 194,590 17,212 3,241 7 (b) 208,568
Common 40,927 4,822 1,597 365 (b) 43,900
(617) (e)
Total $2,484,124 $297,994 $41,986 $872 $2,741,004
Notes:
(a) Amounts represent retirements of utility plant at book value, estimated where actual
amounts are not known, together with cost of removal, less salvage.
(b) Provision for depreciation on transportation equipment, etc. which, together with
operating costs and maintenance thereof, is charged to operations, utility plant and
other accounts on the basis of usage.
(c) Provision for depreciation charged directly to Accounts Receivable.
(d) Represents adjustment relating to currency translation of Canadian subsidiary.
(e) Miscellaneous.
See Note 1 of Notes to the Consolidated Financial Statements.
-51-
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Page 1 of 3
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
(In Thousands of Dollars)
Column A Column B Column C Column D Column E
Additions
Balance Charged Charged
at Balance
to to
Beginning at End
Costs and Other
Description of Period Deductions of Period
Expenses Accounts
Allowance for Doubtful
Accounts - deducted from
Accounts Receivable in
the Balance Sheet
1993 $3,600 $ 37,200 $ - $ 37,200 (a) $3,600
1992 3,600 27,246 - 27,246 (a) 3,600
1991 3,600 33,887 - 33,887 (a) 3,600
(a) Uncollectible accounts written off net of recoveries of $5,951 and $6,529 and
$9,704 in 1991, 1992 and 1993, respectively.
-52-
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Page 2 of 3
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
(In Thousands of Dollars)
Column A Column B Column C Column D Column E
Additions
Balance Charged Charged
at Balance
to to
Beginning at End
Costs and Other
Description of Period Deductions of Period
Expenses Accounts
Reserve for Loss on
Investment -
NM Uranium, Inc. -
deducted from Utility
Plant, Nuclear Fuel
in the Balance Sheet
1993 $53,000 $ 3,300 $ - $ - $56,300
1992 53,000 - - - 53,000
1991 50,000 3,000 - - 53,000
-53-
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Page 3 of 3
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
(In Thousands of Dollars)
Column A Column B Column C Column D Column E
Additions
Balance Charged Charged
at Balance
to to
Beginning at End
Costs and Other
Description of Period Deductions of Period
Expenses Accounts
Reserve for Loss on
oil and gas operations -
Opinac Energy Corp. -
deducted from
Other Property and
Investments in
the Balance Sheet
1993 65,837 $ - $ - $ 65,837 (b) $ -
1992 22,500 44,958 - 1,621 (c) 65,837
1991 - 22,500 - - 22,500
(b) Represents the reversal of the total reserve upon sale of oil and gas operations
in June 1993.
(c) Amortization of reserve related to sales of oil and gas on which loss was
recorded.
-54-
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Page 1 of 2
SCHEDULE IX - SHORT-TERM BORROWINGS
(In Thousands of Dollars)
Column A Column B Column C Column D Column E Column F
Weighted
Maximum Average Average
Category of Weighted Amount Out- Amount Out- Interest
Aggregate Balance Average standing standing Rate
Short-term at End of Interest During the During During the
Borrowing Period Rate Period the Period Period
(a) (b)
December 31, 1993
$153,000 3.66% $162,001 $ 58,874 3.99%
Notes Payable
Commercial Paper 210,016 3.57% 218,000 92,369 3.38%
Bankers Acceptances 5,000 3.25% 50,635 14,214 4.80%
Total $368,016 3.60% 368,016 $165,457 3.72%
December 31, 1992:
$104,450 4.83% $104,450 $ 31,236 4.69%
Notes Payable
Commercial Paper 93,248 4.02% 100,248 32,342 4.20%
Bankers Acceptances 30,000 3.58% 33,000 46,735 5.29%
Total $227,698 4.33% 227,698 $110,313 4.80%
See Note 2 of Notes to Consolidated Financial Statements.
(a) Computed using daily average outstanding.
(b) Computed using monthly weighted average interest rate.
-55-
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Page 2 of 2
SCHEDULE IX - SHORT-TERM BORROWINGS
(In Thousands of Dollars)
Column A Column B Column C Column D Column E Column F
Weighted
Maximum Average Average
Category of Weighted Amount Out- Amount Out- Interest
Aggregate Balance Average standing standing Rate
Short-term at End of Interest During the During During
Borrowing Period Rate Period the Period the
Period
(a) (b)
December 31, 1991:
$ 28,500 5.57% $ 28,500 $ 7,774 6.54%
Notes Payable
Commercial Paper 53,000 7.09% 55,000 4,269 5.70%
Bankers Acceptances 49,718 6.37% 102,299 56,809 8.82%
Total $131,218 6.49% 131,218 $ 68,852 8.37%
See Note 2 of Notes to Consolidated Financial Statements.
(a) Computed using daily average outstanding.
(b) Computed using monthly weighted average interest rate.
-56-
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
(In Thousands of Dollars)
Column A Column B
Item Charged to Costs and Expenses
1993 1992 1991
Taxes, other than payroll
and income taxes:
Land and improvement, $241,421 $240,242 $220,586
including special
franchise
State and Municipal 169,966 135,262
tax on gross revenues 170,310
New York State 31,252 28,549 27,509
franchise
Other 24,263 22,013 19,601
Taxes charged to (10,969) (9,632) (10,331)
construction
Total taxes, other 456,277 451,138 392,627
than payroll and
income taxes
Payroll taxes 44,866 42,916 37,256
Payroll taxes charged to (9,780) (9,221) (9,305)
construction
Total taxes charged to $491,363 $484,833 $420,578
costs and expenses
Taxes, charged to other $ 627 $ 812 $ 1,159
income accounts
Note: Charges for maintenance expenditures, other than those
set forth in the Consolidated Statements of Income, are
charged to clearing accounts which are subsequently
distributed to various asset and expense accounts on the
basis of usage.
-57-
NIAGARA MOHAWK POWER CORPORATION
List of Exhibits
In the following exhibit list, NMPC refers to the Company
and CNYP refers to Central New York Power Corporation. Each
document referred to below is incorporated by reference to the
files of the Commission, unless the reference to the document in
the list is preceded by an asterisk. Previous filings with the
Commission are indicated as follows:
A--NMPC Registration Statement No. 2-8214;
C--NMPC Registration Statement No. 2-8634;
F--CNYP Registration Statement No. 2-3414;
G--CNYP Registration Statement No. 2-5490;
U--NMPC Registration Statement No. 2-10023;
V--NMPC Registration Statement No. 2-10501;
W--NMPC Registration Statement No. 2-10875;
X--NMPC Registration Statement No. 2-12443;
Y--NMPC Registration Statement No. 2-12973;
Z--NMPC Registration Statement No. 2-13285;
AA--NMPC Registration Statement No. 2-13573;
BB--NMPC Registration Statement No. 2-14114;
CC--NMPC Registration Statement No. 2-16193;
DD--NMPC Registration Statement No. 2-18995;
EE--NMPC Registration Statement No. 2-22904;
GG--NMPC Registration Statement No. 2-25526;
HH--NMPC Registration Statement No. 2-26918;
II--NMPC Registration Statement No. 2-29575;
JJ--NMPC Registration Statement No. 2-35112;
KK--NMPC Registration Statement No. 2-38083;
LL--NMPC Registration Statement No. 2-42811;
MM--NMPC Registration Statement No. 2-45017;
NN--NMPC Registration Statement No. 2-47044;
OO--NMPC Registration Statement No. 2-49570;
PP--NMPC Registration Statement No. 2-51084;
QQ--NMPC Registration Statement No. 2-51934;
SS--NMPC Registration Statement No. 2-52852;
TT--NMPC Registration Statement No. 2-54017;
UU--NMPC Registration Statement No. 2-54291;
VV--NMPC Registration Statement No. 2-59500;
YY--NMPC Registration Statement No. 2-61598;
ZZ--NMPC Registration Statement No. 2-62927;
AAA--NMPC Registration Statement No. 2-65219;
BBB--NMPC Registration Statement No. 2-67914;
CCC--NMPC Registration Statement No. 2-70860;
DDD--NMPC Registration Statement No. 2-74165;
EEE--NMPC Registration Statement No. 2-79921;
FFF--NMPC Registration Statement No. 2-81708;
GGG--NMPC Registration Statement No. 2-85366;
HHH--NMPC Registration Statement No. 2-91527;
III--NMPC Registration Statement No. 2-90568;
JJJ--NMPC Registration Statement No. 33-10743;
KKK--NMPC Registration Statement No. 33-20847;
MMM--NMPC Registration Statement No. 33-24755;
NNN--NMPC Registration Statement No. 33-27401;
OOO--NMPC Registration Statement No. 33-32475;
PPP--NMPC Registration Statement No. 33-38093;
QQQ--NMPC Registration Statement No. 33-47241;
RRR--NMPC Registration Statement No. 33-59594;
-58-
SSS--NMPC Registration Statement No. 33-51073;
a--NMPC Annual Report on Form 10-K for year ended December 31,
1989;
b--NMPC Annual Report on Form 10-K for year ended December 31,
1990; and
c--NMPC Annual Report on Form 10-K for year ended December 31,
1992.
-59-
Incorporation by Reference
Exhibit No. Description of Instrument Previous Filing Previous Exhibit Designation
3(a)(1) --Certificate of Consolidation of New
York Power and Light Corporation,
Buffalo Niagara Electric Corporation
and Central New York Power Corporation,
filed in the office of the New York
Secretary of State, January 5, 1950. A1-1
3(a)(2) --Certificate of Amendment of Certificate
of Incorporation of NMPC, filed in the
office of the New York Secretary of
State, January 5, 1950. A 1-2
3(a)(3) --Certificate of Amendment of Certificate
of Incorporation of NMPC, pursuant to
Section 36 of the Stock Corporation Law
of New York, filed August 22, 1952, in
the office of the New York Secretary
of State. AAA 2-4
3(a)(4) --Certificate of NMPC pursuant to Section
11 of the Stock Corporation Law of New
York filed May 5, 1954 in the office of
the New York Secretary of State. W3-7
3(a)(5) --Certificate of Amendment of Certificate of
Incorporation of NMPC, pursuant to Section
36 of the Stock Corporation Law of New
York, filed January 9, 1957 in the office
of the New York Secretary of State. Y3-5
3(a)(6) --Certificate of NMPC pursuant to Section
11 of the Stock Corporation Law of New
York, filed May 22, 1957 in the office of
the New York Secretary of State. Z3-6
3(a)(7) --Certificate of NMPC pursuant to Section
-60-
11 of the Stock Corporation Law of New
York, filed February 18, 1958 in the office
of the New York Secretary of State. BB3-7
3(a)(8) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York, filed May 5, 1965 in the office
of the New York Secretary of State. HH3-8
3(a)(9) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law
of New York, filed August 24, 1967 in
the office of the New York Secretary
of State. KK 2-50
3(a)(10) --Certificate of Amendment of
Certificate of Incorporation of
NMPC under Section 805 of the
Business Corporation Law of New
York, filed August 19, 1968 in
the office of the New York
Secretary of State. KK 2-51
3(a)(11) --Certificate of Amendment of
Certificate of Incorporation of
NMPC under Section 805 of the
Business Corporation Law of New
York, filed September 22, 1969
in the office of the New York
Secretary of State. KK 2-52
3(a)(12) --Certificate of Amendment of
Certificate of Incorporation of
NMPC under Section 805 of the
Business Corporation Law of New
York, filed May 12, 1971 in the
office of the New York Secretary
of State. MM 2-56
3(a)(13) --Certificate of Amendment of
Certificate of Incorporation of
NMPC under Section 805 of the
-61-
Business Corporation Law of New
York, filed August 18, 1972 in
the office of the New York Secretary
of State. NN 2-57
3(a)(14) --Certificate of Amendment of
Certificate of Incorporation of
NMPC under Section 805 of the
Business Corporation Law of New
York, filed June 26, 1973 in the
office of the New York Secretary
of State. OO 2-59
3(a)(15) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York, filed
May 9, 1974 in the office of the New
York Secretary of State. PP 2-60
3(a)(16) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York, filed
March 12, 1975 in the office of the
New York Secretary of State. TT2-17
3(a)(17) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York, filed
May 7, 1975 in the office of the New
York Secretary of State. TT 2-18
3(a)(18) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York, filed
August 27, 1975 in the office of the
New York Secretary of State. VV2-19
3(a)(19) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
-62-
Corporation Law of New York, filed
May 7, 1976 in the office of the
New York Secretary of State. VV2-20
3(a)(20) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
September 28, 1976 in the office of
the New York Secretary of State. JJJ4(b)(20)
3(a)(21) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
January 27, 1978 in the office of
the New York Secretary of State. YY2-21
3(a)(22) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
May 8, 1978 in the office of the
New York Secretary of State. YY2-22
3(a)(23) --Certificate of Correction of the
Certificate of Amendment filed
May 7, 1976 of the Certificate of
Incorporation under Section 105 of
the Business Corporation Law of New
York filed July 13, 1978 in the office
of the New York Secretary of State. ZZ2-23
3(a)(24) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
July 17, 1978 in the office of the
New York Secretary of State. ZZ2-24
3(a)(25) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
-63-
March 3, 1980 in the office of the
New York Secretary of State. BBB(b)(27)
3(a)(26) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
March 31, 1981 in the office of the
New York Secretary of State. JJJ4(b)(26)
3(a)(27) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
March 31, 1981 in the office of the
New York Secretary of State. JJJ4(b)(27)
3(a)(28) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
April 22, 1981 in the office of the
New York Secretary of State. JJJ4(b)(28)
3(a)(29) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
May 8, 1981 in the office of the
New York Secretary of State. JJJ4(b)(29)
3(a)(30) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
April 26, 1982 in the office of the
New York Secretary of State. JJJ4(b)(30)
3(a)(31) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
January 24, 1983 in the office of
the New York Secretary of State. JJJ4(b)(31)
-64-
3(a)(32) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
August 3, 1983 in the office of the
New York Secretary of State. JJJ4(b)(32)
3(a)(33) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
December 27, 1983 in the office of
the New York Secretary of State. JJJ4(b)(33)
3(a)(34) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
December 27, 1983 in the office of
the New York Secretary of State. JJJ4(b)(34)
3(a)(35) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
June 4, 1984 in the office of the
New York Secretary of State. HHH4(b)(35)
3(a)(36) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
August 29, 1984 in the office of the
New York Secretary of State. JJJ4(b)(36)
3(a)(37) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
April 17, 1985, in the office of the
New York Secretary of State. JJJ4(b)(37)
3(a)(38) --Certificate of Amendment of
Certificate of Incorporation of NMPC
-65-
under Section 805 of the Business
Corporation Law of New York filed
May 3, 1985, in the office of the
New York Secretary of State. JJJ4(b)(38)
3(a)(39) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
December 24, 1986 in the office of
the New York Secretary of State. MMM3(a)(39)
3(a)(40) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
June 1, 1987 in the office of the
New York Secretary of State. MMM3(a)(40)
3(a)(41) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
July 16, 1987 in the office of the
New York Secretary of State. MMM3(a)(41)
3(a)(42) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
May 27, 1988 in the office of the
New York Secretary of State. MMM3(a)(42)
3(a)(43) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
September 27, 1990 in the office of the
New York Secretary of State. PPP3(a)(43)
3(a)(44) --Certificate of Amendment of
Certificate of Incorporation of NMPC
under Section 805 of the Business
Corporation Law of New York filed
-66-
October 18, 1991 in the office of the
New York Secretary of State. QQQ3(a)(44)
3(b) --By-Laws of NMPC. b 3(b)(1)
4(1) --Mortgage Trust Indenture dated as of
October 1, 1937 between NMPC (formerly
CNYP) and Marine Midland Bank, N.A.
(formerly named The Marine Midland Trust
Company of New York), as Trustee. F**
4(2) --Supplemental Indenture dated as of
December 1, 1938, supplemental to
Exhibit 4(1). VV 2-3
4(3) --Supplemental Indenture dated as of
April 15, 1939, supplemental to
Exhibit 4(1). VV 2-4
4(4) --Supplemental Indenture dated as of
July 1, 1940, supplemental to
Exhibit 4(1). VV 2-5
4(5) --Supplemental Indenture dated as of
January 1, 1942, supplemental to
Exhibit 4(1). VV 2-6
4(6) --Supplemental Indenture dated as of
October 1, 1944, supplemental to
Exhibit 4(1). G 7-6
4(7) --Supplemental Indenture dated as of
June 1, 1945, supplemental to
Exhibit 4(1). VV 2-8
4(8) --Supplemental Indenture dated as of
August 17, 1948, supplemental to
Exhibit 4(1). VV 2-9
4(9) --Supplemental Indenture dated as of
December 31, 1949, supplemental to
Exhibit 4(1). A 7-9
4(10) --Supplemental Indenture dated as of
-67-
January 1, 1950, supplemental to
Exhibit 4(1). A 7-10
4(11) --Supplemental Indenture dated as of
October 1, 1950, supplemental to
Exhibit 4(1). C 7-11
** Filed October 15, 1937 after effective date of Registration Statement No. 2-3414.Filing Previous Exhibit Designation
4(12) --Supplemental Indenture dated as of
October 19, 1950, supplemental to
Exhibit 4(1). C 7-12
4(13) --Supplemental Indenture dated as of
December 1, 1951, supplemental to
Exhibit 4(1). U 4-25
4(14) --Supplemental Indenture dated as of
February 1, 1953, supplemental to
Exhibit 4(1). U 4-26
4(15) --Supplemental Indenture dated as of
February 20, 1953, supplemental to
Exhibit 4(1). V 4-16
4(16) --Supplemental Indenture dated as of
October 1, 1953, supplemental to
Exhibit 4(1). W 4-17
4(17) --Supplemental Indenture dated as of
August 1, 1954, supplemental to
Exhibit 4(1). X 4-18
4(18) --Supplemental Indenture dated as of
April 25, 1956, supplemental to
Exhibit 4(1). X 4-19
4(19) --Supplemental Indenture dated as of
May 1, 1956, supplemental to
Exhibit 4(1). X 4-20
-68-
4(20) --Supplemental Indenture dated as of
September 1, 1957, supplemental to
Exhibit 4(1) AA 2-21
4(21) --Supplemental Indenture dated as of
June 1, 1958, supplemental to
Exhibit 4(1). BB 2-22
4(22) --Supplemental Indenture dated as of
March 15, 1960, supplemental to
Exhibit 4(1). CC 2-23
4(23) --Supplemental Indenture dated as of
April 1, 1960, supplemental to
Exhibit 4(1). CC 2-24
4(24) --Supplemental Indenture dated as of
November 1, 1961, supplemental to
Exhibit 4(1). DD 4-26
4(25) --Supplemental Indenture dated as of
December 1, 1964, supplemental to
Exhibit 4(1). EE 2-26
4(26) --Supplemental Indenture dated as of
October 1, 1966, supplemental to
Exhibit 4(1). GG 2-27
4(27) --Supplemental Indenture dated as of
July 15, 1967, supplemental to
Exhibit 4(1). HH 4-29
4(28) --Supplemental Indenture dated as of
August 1, 1967, supplemental to
Exhibit 4(1). HH 4-30
4(29) --Supplemental Indenture dated as of
August 1, 1968, supplemental to
Exhibit 4(1). II 2-30
4(30) --Supplemental Indenture dated as of
December 1, 1969, supplemental to
Exhibit 4(1). JJ 2-31
-69-
4(31) --Supplemental Indenture dated as of
February 1, 1971, supplemental to
Exhibit 4(1). LL 2-32
4(32) --Supplemental Indenture dated as of
February 1, 1972, supplemental to
Exhibit 4(1). MM 2-33
4(33) --Supplemental Indenture dated as of
August 1, 1972, supplemental to
Exhibit 4(1). NN 2-34
4(34) --Supplemental Indenture dated as of
December 1, 1973, supplemental to
Exhibit 4(1). OO 2-35
4(35) --Supplemental Indenture dated as of
October 1, 1974, supplemental to
Exhibit 4(1). QQ 2-36
4(36) --Supplemental Indenture dated as of
March 1, 1975, supplemental to
Exhibit 4(1). SS 2-37
4(37) --Supplemental Indenture dated as of
August 1, 1975, supplemental to
Exhibit 4(1). UU 2-38
4(38) --Supplemental Indenture dated as of
March 15, 1977, supplemental to
Exhibit 4(1). VV 2-39
4(39) --Supplemental Indenture dated as of
August 1, 1977, supplemental to
Exhibit 4(1). CCC 4(b)(40)
4(40) --Supplemental Indenture dated as of
December 1, 1977, supplemental to
Exhibit 4(1). CCC 4(b)(41)
4(41) --Supplemental Indenture dated as of
March 1, 1978, supplemental to
Exhibit 4(1). CCC 4(b)(42)
-70-
4(42) --Supplemental Indenture dated as of
December 1, 1978, supplemental to
Exhibit 4(1). CCC 4(b)(43)
4(43) --Supplemental Indenture dated as of
September 1, 1979, supplemental to
Exhibit 4(1). CCC 4(b)(44)
4(44) --Supplemental Indenture dated as of
October 1, 1979, supplemental to
Exhibit 4(1). CCC 4(b)(45)
4(45) --Supplemental Indenture dated as of
June 15, 1980, supplemental to
Exhibit 4(1). CCC 4(b)(46)
4(46) --Supplemental Indenture dated as of
September 1, 1980, supplemental to
Exhibit 4(1). CCC 4(b)(47)
4(47) --Supplemental Indenture dated as of
March 1, 1981, supplemental to
Exhibit 4(1). DDD 4(b)(47)
4(48) --Supplemental Indenture dated as of
August 1, 1981, supplemental to
Exhibit 4(1). DDD 4(b)(48)
4(49) --Supplemental Indenture dated as of
March 1, 1982, supplemental to
Exhibit 4(1). KKK 4(b)(49)
4(50) --Supplemental Indenture dated as of
April 1, 1982, supplemental to
Exhibit 4(1). KKK 4(b)(50)
4(51) --Supplemental Indenture dated as of
June 1, 1982, supplemental to
Exhibit 4(1). KKK 4(b)(51)
4(52) --Supplemental Indenture dated as of
August 1, 1982, supplemental to
Exhibit 4(1). EEE 4(b)(52)
-71-
4(53) --Supplemental Indenture dated as of
November 1, 1982, supplemental to
Exhibit 4(1). FFF 4(b)(53)
4(54) --Supplemental Indenture dated as of
March 1, 1983, supplemental to
Exhibit 4(1). KKK 4(b)(54)
4(55) --Supplemental Indenture dated as of
May 1, 1983, supplemental to
Exhibit 4(1). KKK 4(b)(55)
4(56) --Supplemental Indenture dated as of
June 1, 1983, supplemental to
Exhibit 4(1). GGG 4(b)(56)
4(57) --Supplemental Indenture dated as of
March 1, 1984, supplemental to
Exhibit 4(1). III 4(b)(57)
4(58) --Supplemental Indenture dated as of
May 1, 1984, supplemental to
Exhibit 4(1). KKK 4(b)(58)
4(59) --Supplemental Indenture dated as of
July 1, 1984, supplemental to
Exhibit 4(1). KKK 4(b)(59)
4(60) --Supplemental Indenture dated as of
October 1, 1984, supplemental to
Exhibit 4(1). KKK 4(b)(60)
4(61) --Supplemental Indenture dated as of
January 1, 1985, supplemental to
Exhibit 4(1). KKK 4(b)(61)
4(62) --Supplemental Indenture dated as of
February 1, 1985, supplemental to
Exhibit 4(1). KKK 4(b)(62)
4(63) --Supplemental Indenture dated as of
February 15, 1985, supplemental to
Exhibit 4(1). KKK 4(b)(63)
-72-
4(64) --Supplemental Indenture dated as of
November 1, 1985, supplemental to
Exhibit 4(1). III 4(b)(64)
4(65) --Supplemental Indenture dated as of
June 1, 1986, supplemental to
Exhibit 4(1). KKK 4(b)(65)
4(66) --Supplemental Indenture dated as of
August 1, 1986, supplemental to
Exhibit 4(1). KKK 4(b)(66)
4(67) --Supplemental Indenture dated as of
October 1, 1986, supplemental to
Exhibit 4(1). KKK 4(b)(67)
4(68) --Supplemental Indenture dated as of
November 1, 1986, supplemental to
Exhibit 4(1). KKK 4(b)(68)
4(69) --Supplemental Indenture dated as of
July 1, 1987, supplemental to
Exhibit 4(1). KKK 4(b)(69)
4(70) --Supplemental Indenture dated as of
May 1, 1988, supplemental to
Exhibit 4(1). MMM 4(b)(70)
4(71) --Supplemental Indenture dated as of
February 1, 1989, supplemental to
Exhibit 4(1). NNN 4(b)(71)
4(72) --Supplemental Indenture dated as of
April 1, 1989, supplemental to
Exhibit 4(1). OOO 4(b)(72)
4(73) --Supplemental Indenture dated as of
October 1, 1989, supplemental to
Exhibit 4(1). OOO 4(b)(73)
4(74) --Supplemental Indenture dated as of
June 1, 1990, supplemental to
Exhibit 4(1). PPP 4(b)(74)
-73-
4(75) --Supplemental Indenture dated as of
November 1, 1990, supplemental to
Exhibit 4(1). PPP 4(b)(75)
4(76) --Supplemental Indenture dated as of
March 1, 1991, supplemental to
Exhibit 4(1). QQQ 4(b)(76)
4(77) --Supplemental Indenture dated as of
October 1, 1991, supplemental to
Exhibit 4(1). QQQ 4(b)(77)
4(78) --Supplemental Indenture dated as of
April 1, 1992, supplemental to
Exhibit 4(1). QQQ 4(b)(78)
4(79) --Supplemental Indenture dated as of
June 1, 1992, supplemental to
Exhibit 4(1). RRR 4(b)(79)
4(80) --Supplemental Indenture dated as of
July 1, 1992, supplemental to
Exhibit 4(1). RRR 4(b)(80)
4(81) --Supplemental Indenture dated as of
August 1, 1992, supplemental to
Exhibit 4(1). RRR 4(b)(81)
4(82) --Supplemental Indenture dated as of
April 1, 1993, supplemental to
Exhibit 4(1). SSS 4(b)(82)
4(83) --Supplemental Indenture dated as of
July 1, 1993, supplemental to
Exhibit 4(1). SSS 4(b)(83)
4(84) --Supplemental Indenture dated as of
September 1, 1993, supplemental to
Exhibit 4(1). SSS 4(b)(84)
*4(85) --Supplemental Indenture dated as of
March 1, 1994, supplement to
Exhibit 4(1).
-74-
4(86) --Agreement dated as of August 16, 1940,
between CNYP, The Chase National Bank
of the City of New York, as Successor
Trustee, and The Marine Midland Trust
Company of New York, as Trustee. G 7-23
10-1 --Agreement dated March 1, 1957 between
the Power Authority of the State of
New York and NMPC as to sale,
transmission and disposition of St.
Lawrence power. Z 13-11
10-2 --Agreement dated February 10, 1961
between the Power Authority of the
State of New York and NMPC as to sale,
transmission and disposition of
Niagara redevelopment power. DD13-6
10-3 --Agreement dated July 26, 1961
between the Power Authority of the
State of New York and NMPC
supplemental to Exhibit 10-2. DD13-7
10-4 --Agreement dated as of March 23, 1973
between the Power Authority of the
State of New York and NMPC as to
the sale, transmission and disposition
of Blenheim-Gilboa power. OO 5-8
10-5 --Agreement dated January 23, 1970
between Consolidated Gas Supply
Corporation (formerly named New York
State Natural Gas Corporation) and NMPC. KK5-8
10-6a --New York Power Pool Agreement
dated as of February 1, 1974
between NMPC and six other New York
utilities and the Power Authority
of the State of New York. QQ 5-10
10-6b --New York Power Pool Agreement
dated as of April 27, 1975 between
NMPC and six other New York electric
utilities and the Power Authority of
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the State of New York (the parties
to the Agreement have petitioned
the Federal Power Commission for an
order permitting such Agreement,
which increases the reserve factor
of all parties from .14 to .18,
to supersede the New York Power
Pool Agreement dated as of
February 1, 1974). TT 5-10b
10-7 --Agreement dated as of October 31, 1968
between NMPC, Central Hudson Gas &
Electric Corporation and Consolidated
Edison Company of New York, Inc. as
to Joint Electric Generating Plant
(the Roseton Station). JJ 5-10
10-8a --Memorandum of Understanding dated as
of May 30, 1975 between NMPC and
Rochester Gas & Electric Corporation
with respect to Oswego Unit No. 6. SS5-13
10-8b --Memorandum of Understanding dated as
of May 30, 1975 between NMPC and
Rochester Gas and Electric Corporation
with respect to Oswego Unit No. 6. SS5-13
10-8c --Basic Agreement dated as of September 22,
1975 between NMPC and Rochester Gas and
Electric Corporation with respect to
Oswego Unit No. 6. VV 5-13b
10-9a --Memorandum of Understanding dated
as of May 30, 1975 between NMPC and
four other New York electric utili-
ties with respect to Nine Mile
Point Nuclear Station Unit No. 2. SS5-14
10-9b --Basic Agreement dated as of
September 22, 1975 between NMPC and
four other New York electric utilities
with respect to Nine Mile Point
Nuclear Station Unit No. 2. VV5-14b
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10-9c --Nine Mile Point Nuclear Station Unit
No. 2 Interim Operating Agreement. a10-9f
10-10a --Memorandum of Understanding dated as
of May 16, 1974, as amended May 30,
1975, between NMPC and three other
New York electric utilities with respect
to the Sterling Nuclear Station. SS5-15
10-10b --Basic Agreement dated as of
September 22, 1975 between NMPC and
three other New York electric utilities
with respect to the Sterling Nuclear
Stations. VV 5-15b
10-11 --1989 Agreement dated as of August 31, 1989
between NMPC, PSC and other intervenors
with respect to various outstanding Cases,
and PSC Opinion No. 89-37 approving the
1989 Agreement, issued and effective
October 20, 1989. a 10-14
10-12 --NMPC Officers' Incentive Compensation Plan -
Plan Document. b 10-16
10-13 --NMPC Management Incentive Compensation Plan -
Plan Document b 10-17
10-14 --NMPC 1990 Stock Award Plan b10-18
10-15 --Nine Mile Point Nuclear Station Unit
No. 2 Operating Agreement c 10-19
*10-16 --NMPC Deferred Compensation Plan
*10-17 --NMPC Performance Share Unit Plan
*10-18 --NMPC 1992 Stock Option Plan
*10-19 --Employment Agreement between NMPC and
William E. Davis, Chairman of the Board
and Chief Executive Officer, dated January 1,
1993, including letter dated January 24, 1994.
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*10-20 --Employment Agreement between NMPC and John M.
Endries, President, dated January 1, 1993,
including letter dated January 24, 1994.
*10-21 --Employment Agreement between NMPC and B. Ralph
Sylvia, Executive Vice President, Nuclear, dated
January 1, 1993, including letter dated
January 24, 1994.
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Incorporation by Reference
Exhibit No. Description of Instrument Previous Filing Previous Exhibit Designation
*10-22 --Employment Agreement between NMPC and David J.
Arrington, Sr. Vice President, Human
Resources, dated January 1, 1993, including
letter dated January 24, 1994.
*10-23 --Employment Agreement between NMPC and Darlene D.
Kerr, Sr. Vice President, Electric Customer Service,
dated January 1, 1994.
*10-24 --Employment Agreement between NMPC and Gary J.
Lavine, Sr. Vice President, Legal and Corporate
Relations, dated January 1, 1993, including
letter dated January 24, 1994.
*10-25 --Employment Agreement between NMPC and Robert J.
Patrylo, Sr. Vice President, Gas Customer
Service, dated January 1, 1993, including
letter dated January 24, 1994.
*10-26 --Employment Agreement between NMPC and John W.
Powers, Sr. Vice President, Finance and Corporate
Services, dated January 1, 1993, including
letter dated January 24, 1994.
*10-27 --Employment Agreement between NMPC and Michael P.
Ranalli, Sr. Vice President, Electric Supply &
Delivery, dated January 1, 1993, including
letter dated January 24, 1994.
*10-28 --Agreement for Consulting Services between NMPC
and William J. Donlon, effective July 15, 1993.
*10-29 --Employment Agreement between NMPC and John P.
Hennessey, Sr. Vice President, Electric
Customer Service, dated January 1, 1993.
*11 --Statement setting forth the
computation of average number of
shares of common stock outstanding.
*12 --Statements Showing Computations of
-79-
Certain Financial Ratios.
*21 --Subsidiaries of the Registrant.
*23 --Consent of Price Waterhouse.
99(1) --Form 11-K Annual Report of the Employee
Savings Fund Plan for Represented
Employees of Niagara Mohawk Power
Corporation for Fiscal Year Ended To be filed at
December 31, 1993. a later date.
99(2) --Form 11-K Annual Report of the Employee
Savings Fund Plan for Non-represented
Employees of Niagara Mohawk Power
Corporation for Fiscal Year Ended To be filed at
December 31, 1993. a later date.
-80-
SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the
Securities Exchange Act of 1934, the Registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
NIAGARA MOHAWK POWER CORPORATION
(Registrant)
Date March 24, 1994 By/s/ Steven W. Tasker
Steven W. Tasker
Vice President-Controller
and Principal Accounting Officer
Pursuant to the requirements of the Securities Exchange
Act of 1934, this report has been signed below by the following
persons on behalf of the Registrant and in the capacities and on
the dates indicated.
Signature Title Date
/s/ William F. Allyn Director March 24, 1994
William F. Allyn
/s/Lawrence Burkhardt,III Director March 24, 1994
Lawrence Burkhardt, III
/s/ Douglas M. Costle Director March 24, 1994
Douglas M. Costle
/s/ Edmund M. Davis Director March 24, 1994
Edmund M. Davis
Chairman of the
Board of Directors
and Chief Executive
/s/ William E. Davis Officer March 24, 1994
William E. Davis
/s/ William J. Donlon Director March 24, 1994
William J. Donlon
/s/ Edward W. Duffy Director March 24, 1994
Edward W. Duffy
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Signature Title Date
/s/ John M. Endries Director and President March 24, 1994
John M. Endries
/s/ Bonnie Guiton Hill Director March 24, 1994
Dr. Bonnie Guiton Hill
/s/ John G. Haehl, Jr. Director March 24, 1994
John G. Haehl, Jr.
/s/ Henry A. Panasci,Jr. Director March 24, 1994
Henry A. Panasci, Jr.
/s/ Patti McGill Peterson Director March 24, 1994
Dr. Patti McGill Peterson
/s/ Donald B. Riefler Director March 24, 1994
Donald B. Riefler
Director March 24, 1994
Stephen B. Schwartz
/s/ John G. Wick Director March 24, 1994
John G. Wick
Senior Vice President
and Principal Financial
/s/ John W. Powers Officer March 24, 1994
John W. Powers
Vice President-Controller
and Principal Accounting
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/s/ Steven W. Tasker Officer March 24, 1994
Steven W. Tasker
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