Back to GetFilings.com
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, 1995
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
- ------------------------------------------------------------------
NIAGARA MOHAWK POWER CORPORATION
(Exact name of registrant as specified in its charter)
State of New York 15-0265555
- ----------------- ----------
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
300 Erie Boulevard West, Syracuse, New York 13202
(Address of principal executive offices) (zip code)
(315) 474-1511
Registrant's telephone number, including area code
- -----------------------------------------------------------------
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 9.50% Series
3.60% Series 4.85% Series 7.72% Series Adjustable Rate
3.90% Series 5.25% Series Series A & Series C
Securities registered pursuant to Section 12(g) of the Act: None
- -----------------------------------------------------------------
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 / /
State the aggregate market value of the voting stock held by non-
affiliates of the registrant.
Approximately $1,082,000,000 at March 1, 1996.
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 144,332,855 shares outstanding March 1,
1996.
Documents incorporated by reference:
Definitive Proxy Statement in connection with annual meeting of
stockholders to be held May 7, 1996 incorporated in Part III to
the extent described therein.
NIAGARA MOHAWK POWER CORPORATION
INFORMATION REQUIRED IN FORM 10-K
PART I
- ------
Item Number
- -----------
Glossary of Terms
Item 1. Business.
Item 2. Properties.
Item 3. Legal Proceedings.
Item 4. Submission of Matters to a Vote of Security Holders.
Executive Officers of the Registrant
PART II
- -------
Item 5. Market for the Registrant's Common Equity and
Related Stockholder Matters.
Item 6. Selected Consolidated Financial Data.
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.
Item 8. Financial Statements and Supplementary Data.
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.
PART III
- --------
Item 10. Directors and Executive Officers of the Registrant.
Item 11. Executive Compensation.
Item 12. Security Ownership of Certain Beneficial Owners and
Management.
Item 13. Certain Relationships and Related Transactions.
PART IV
- -------
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K.
Signatures
NIAGARA MOHAWK POWER CORPORATION
GLOSSARY OF TERMS
- -----------------
TERM DEFINITION
- ---- ----------
ALJ New York PSC Administrative Law Judge
BTU British Thermal Unit
Clean Air
Act Clean Air Act Amendments of 1990
CNG CNG Transmission Corporation
CNP Canadian Niagara Power Company, Limited
COPS Competitive Opportunities Proceeding
CWIP Construction Work in Progress
DEC New York State Department of Environmental Conservation
DSM Demand-Side Management
Dth Dekatherms
EPA U. S. Environmental Protection Agency
EPAct National Energy Policy Act of 1992
FAC Fuel Adjustment Clause
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
Fitch Fitch Investors Services, Inc.
GAC Gas Adjustment Clause
GAAP Generally accepted accounting principles
GRT Gross Receipts Tax
GwHrs Gigawatt-hours
HYDRA-CO HYDRA-CO Enterprises, Inc.
IERP Integrated Electric Resource Plan
IRS Internal Revenue Service
ISO Independent System Operator
Kwh Kilowatt-hour
MERIT Measured Equity Return Incentive Term
MGP Manufactured gas plant
MOODY'S Moody's Investors Service
MW Megawatt
Mwh Megawatt-hour
NERAM Niagara Mohawk Electric Revenue Adjustment Mechanism
NYS Supreme
Court Supreme Court of the State of New York, Albany County
NOPR Notice of Proposed Rulemaking
NOx Nitrogen oxide
NPL Federal National Priorities List for Uncontrolled
Hazardous Waste Sites
NRC Nuclear Regulatory Commission
NYPA New York Power Authority
NYPP New York Power Pool
NYSERDA New York State Energy and Development Authority
PRP Potentially responsible party
PSC New York State Public Service Commission
PURPA Public Utility Regulatory Policies Act of 1978
QFs Qualifying Facilities
R&D Research and Development
RACT Reasonably Available Control Technology
SFAS Statement of Financial Accounting Standards No. 71
No. 71 "Accounting for the Effects of Certain Types of
Regulation"
SFAS Statement of Financial Accounting Standards No. 106
No. 106 "Employers' Accounting for Postretirement Benefits
Other Than Pensions"
SFAS Statement of Financial Accounting Standards No. 109
No. 109 "Accounting for Income Taxes"
SFAS Statement of Financial Accounting Standards No. 112
No. 112 "Employers' Accounting for Postemployment Benefits"
SFAS Statement of Financial Accounting Standards No. 121
No.121 "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed of"
Six-Cent
Law Section 66-c of the New York State Public Service Law
SO2 Sulfur dioxide
S&P Standard & Poor's
UG Unregulated Generator
Unit 1 Nine Mile Point Nuclear Station Unit No. 1
Unit 2 Nine Mile Point Nuclear Station Unit No. 2
VERP Voluntary Employee Reduction Program
NIAGARA MOHAWK POWER CORPORATION
PART I
- ------
ITEM 1. BUSINESS.
The Company, incorporated in 1937 under the laws of New York
State, is engaged principally in the business of generation,
purchase, transmission, distribution and sale of electricity and
the purchase, distribution, sale and transportation of gas in New
York State. (See Item 8 - Financial Statements and Supplementary
Data, Note 11).
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
providing universal service to customers in its franchise area.
Such protection often encouraged regulators and other governmental
bodies to use utilities as vehicles to advance social programs and
collect taxes. 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 predictable, as was the
industry's ability to sustain investment grade dividend payout and
interest coverage ratios.
Consequently, the Company's current electricity and gas prices
reflect traditional utility regulation. As such, the Company's
electricity prices include state-mandated purchased power costs
from UGs, at costs far exceeding the Company's actual avoided
costs, as well as the costs of high taxes in New York. Avoided
costs are the costs the Company would otherwise incur to generate
power if it did not purchase electricity from another source.
Without legislative or regulatory action, the Company is severely
limited in its ability to control or reduce these purchased power
costs and taxes, which are major causes of the Company's recent
increases in prices.
While the Company is experiencing rising prices, rapid
technological advances are significantly reducing the price of new
generation and significantly improving the performance of smaller
scale generating unit technology. In addition, the current excess
supply of generating capacity has driven down the prices a
competitive market would support. Actions taken by other utilities
throughout the country to lower their prices, including those in
areas with already relatively low prices, increase the threat of
industrial relocation and the need to offer discounts to industrial
customers.
The Company continues to take aggressive action to both
prevent the loss of certain industrial customers, and to attract
new business. In 1995, the Company granted approximately $62
million of discounts. Discounts are expected to increase in 1996
and 1997, but will depend on energy price levels in the marketplace
and other competitive activity.
The Company also faces the continued threat of
municipalization. A growing number of municipalities within the
Company's service territory are investigating the possibility of
acquiring less expensive sources of electricity by forming their
own utility operations. If successfully established as legitimate
wholesale entities, these new utilities would have open access to
transmission and would be able to by-pass the Company's generation
system. The municipalities exploring this possibility are
generally in the early stages of inquiry and represent a small
percentage of Company sales. Municipalization has the potential to
adversely affect the Company's customer base and profitability,
although rules proposed by FERC would greatly mitigate any negative
economic effects on the Company.
For a detailed discussion of events that occurred during 1995
in the competitive environment, federal and state regulatory
initiatives and the Company's efforts to address its competitive
disadvantages and deteriorating financial condition, see Part II,
Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations.
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.
Topic
-----
Regulation and Rates
Unregulated Generators
New York Power Authority
Purchased Power
Fuel for Electric Generation:
Coal
Natural Gas
Residual Oil
Nuclear
Gas Supply
Financial Information About Industry Segments
Environmental Matters
Nuclear Operations
Construction Program
Electric Supply Planning
Electric Delivery Planning
Demand-Side Management Programs
Research and Development
Employee Relations
Liability Insurance
In addition, for a discussion of the Company's methods of
distribution and the extent to which the Company's business is or
may be seasonal, see Item 2 - Properties - Electric Service and Gas
Service. For a discussion of the Company's treatment of working
capital items, see Part II, Item 7 - Management's Discussion and
Analysis of Financial Condition and Results of Operations -
Financial Position, Liquidity and Capital Resources.
REGULATION AND RATES. POWERCHOICE PROPOSAL. The PSC's 1995
rate order directed the Company and other interested parties to
address several key issues regarding long-range rate proposals.
These issues were to include: improving the Company's competitive
position by addressing uneconomic utility generation and the high
price of many UG contracts; eliminating, if possible, the fuel
adjustment clause and other billing mechanisms; addressing property
tax issues with local authorities; improving operating efficiency;
and identifying governmental mandates that are no longer warranted
in a competitive environment. No proposal under this directive
could create anti-competitive effects or lead to a deterioration in
safe and adequate service. The PSC also said any multi-year plan
should ensure that the Company has an investment-grade bond rating
(although the Company is currently below investment grade), and
include protection for low-income customers. Finally, the PSC
directed that the plan should propose changes in the regulatory
approach for the Company that support fair competition in the
electric generation market consistent with the PSC's determination
in its generic competitive opportunities proceeding.
On October 6, 1995, the Company filed its PowerChoice proposal
with the PSC. The proposal was offered as an integrated package
(although certain details are subject to modification) and included
these key elements:
* Creation of a competitive wholesale electricity market and
direct access by retail customers.
* Separation of the Company's power generation business.
* Relief from overpriced UG contracts that were mandated by
public policy, along with equitable write-downs of above-
market Company assets.
* A price freeze or cut for all customer classes.
For a detailed discussion of this proposal, see Part II, Item
7 - Management's Discussion and Analysis of Financial Condition and
Results of Operations - PowerChoice Proposal.
1996 AND 1997 RATE FILING. When PowerChoice was announced,
the Company said that failure to approve the plan would mean
continued price escalation under traditional regulation, or failing
that, further deterioration in the Company's financial condition.
While negotiations are continuing on PowerChoice, in view of
increasing UG payments, price discounts and continued weak sales
expectations, the Company has found it necessary to seek price
increases. The Company filed for price increases of 4.1% for 1996
and 4.2% for 1997 and earnings for these years will depend on the
outcome of the rate requests. The 1996 rate filing is for
temporary rate relief for which the Company has asked for immediate
action. On February 16, 1996, the PSC issued an order that, among
other things, established a schedule with respect to temporary
rates that would have the case certified directly to the PSC within
60 days of the order. In early March, the PSC staff and other
parties filed testimony recommending that the request for temporary
rate relief be denied. The 1997 filing will preserve the Company's
right to traditional cost-based rates in the event that an
acceptable regulatory solution cannot be achieved through
negotiation of the PowerChoice proposal. The Company expects that
the PSC will approve cost-of-service based rate increases until
such time as implementation of a new competitive market model
becomes probable.
PSC COMPETITIVE OPPORTUNITIES PROCEEDING - GAS. In December
1994, the PSC issued an Order that established a policy framework
to guide the transition of the natural gas distribution industry
into a more competitive environment. In addition, the PSC required
the Company, and other utilities, to file restructuring tariffs
that would support the implementation of the Order. The Company
filed a new tariff with the PSC in November 1995 that would
restructure its gas services. The Company proposed several changes
in its gas service offerings, as well as in its gas rate design, to
better align its rates with its cost of service and to provide the
Company with greater flexibility to price services on a competitive
basis. Based on the results of the Company's most recent rate
case, the restructured rates would be revenue neutral in total. In
addition, the Company's proposed tariff includes an aggregation
proposal whereby utilities and marketers would be allowed to group
into a pool smaller customers who are not individually eligible to
buy gas from an alternative supplier.
Under the aggregation proposal, the Company would continue to
deliver the gas through its pipes as it does for current
transportation customers. The actual commodity cost for natural
gas is passed through to the customer without margin. The
Company's margins come from the delivery of natural gas.
Therefore, the Company will continue to earn a profit by providing
delivery service to all of its customers. The Company believes
that this unbundling of services will provide customers with better
service by giving them a greater number of choices.
On March 14, 1996, the PSC approved utility restructuring
plans to allow aggregation services for residential and small
commercial gas customers, which will become effective later this
year. The remaining proposals in the Company's restructuring
tariff are being addressed in its current rate case, as filed in
November 1995.
The Company's November 1995 rate filing requested a 5.8% gas
rate increase, under traditional cost-based regulation. If
approved, such rates would become effective on October 1, 1996. In
addition, the Company proposed the adoption of a "performance-based
regulation" mechanism, including a gas cost incentive mechanism for
its gas operations. The proposal provides for a complete
unbundling of the Company's sales service to become effective
October 1, 1997, allowing customers to choose alternative gas
suppliers. Increases for gas distribution services would be
subject to a price index through the year 2001. The price index,
which is based on inflation associated with gas service-related
costs, would be applied to prices approved by the PSC for the rate
year ending September 30, 1997 after consideration of the service
restructuring. The service restructuring proposes a move to a rate
structure for the transportation of gas which mitigates throughput
risk, simplifies rates and allows other gas suppliers to aggregate
customers on the Company's system for the supply of gas. A gas
cost incentive mechanism is also being proposed, along with
discontinuation of the weather normalization clause. Flexibility
in pursuing unregulated opportunities related to the gas business
is also being sought. The Company believes its gas operations will
continue to be cost-of-service, rate regulated.
PRICE DISCOUNTS. Competition has been increasing in the
Company's wholesale and retail markets. In the wholesale markets,
the Company competes directly with other U.S. utilities, Canadian
utilities, the NYPA, and UGs. While it has always competed with
other utilities in wholesale markets, recent events have increased
competition. For example, the PSC has been increasing the share of
deviations from forecast fuel targets, including sales for resale,
that shareholders must absorb. Thus, utilities have larger
financial incentives to achieve reduced fuel costs and increased
sales for resale, making wholesale markets more competitive. In
addition, a prolonged recession in the New York State economy,
combined with successful energy conservation programs, has
contributed to the region's (including Canadian) excess capacity,
putting downward pressure on wholesale prices. The Company also
faces enormous competition, and upward pressure on prices due to
mandated subsidies to UGs. Federal PURPA and the New York State
implementation of PURPA coupled with its now repealed Six-Cent Law,
combined with low gas prices and low interest rates, have created
a large and thriving unregulated power industry. The Company has
virtually all UG capacity on line, amounting to approximately 2,708
MW of capacity at December 31, 1995. Of this amount 2,390 MW is
considered firm.
In retail markets, the Company faces competition from on-site,
self- and cogeneration, UGs who wish to sell electricity directly
to the Company's retail customers, other fuels, industrial
relocation, potential municipalization and NYPA. Generally, on-
site generation is uneconomic today when compared to a utility's
incremental or marginal cost of serving additional load.
Unfortunately, on-site generation, however, compares favorably to
traditional retail prices, which are based on average embedded
costs and which traditionally are designed to collect fixed costs
volumetrically assuming monopoly franchise. The result is that
large volume customers have subsidized small customers both within
and between classes.
For the reasons mentioned above, the Company is experiencing
a loss of industrial load across its system. In addressing the
threat of further loss of industrial load, the PSC established
guidelines to govern flexible electric rates offered by utilities
to retain qualified industrial customers. Under these guidelines,
the Company filed for a new service tariff in August 1994, under
which all new contract rates are administered based on demonstrated
industrial and commercial competitive pricing situations including,
but not limited to, on-site generation, fuel switching, facility
relocation and partial plant production shifting. Contracts are
for terms not to exceed seven years without PSC approval.
For a detailed discussion of discounts offered to customers
and the terms of discount agreements, see Part II, Item 7 -
Management's Discussion and Analysis of Financial Condition and
Results of Operations - Other Company Efforts to Address
Competitive Challenges - Customer Discounts.
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 purchase
electricity from UGs at prices in excess of the Company's internal
cost of production and in volumes greater than the Company's
customers' needs. PURPA, New York State law and PSC policies and
procedures have collectively required that the Company purchase
this power from "qualified" UGs. The prices used in negotiating
purchased power contracts with UGs (Long Run Avoided Costs) are
established periodically by the PSC. Until its modification in
1992, the Six-Cent Law which governed many of these contracts had
established the floor on avoided costs at $0.06/Kwh. The Six-Cent
Law, in combination with other factors, attracted large numbers of
UG projects to New York State and, in particular, to the Company's
service territory due to the availability of numerous thermal hosts
and hydroelectric sites.
For a detailed discussion of Company efforts to reduce its UG
costs, see Item 3 - Legal Proceedings, Part II, Item 7 -
Management's Discussion and Analysis of Financial Condition and
Results of Operations - Unregulated Generators and Item 8 -
Financial Statements and Supplementary Data, Note 9.
NEW YORK POWER AUTHORITY. 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 1995, these purchases amounted to 7,756,000
Mwh, or about 18% 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. Refer to Part II, Item 8 -
Financial Statements and Supplementary Data, Note 9 for a summary
table that includes the types and amounts of NYPA power which the
Company was entitled to purchase as of January 1, 1996 and the
termination dates of its contracts with respect to each NYPA
generating facility.
PURCHASED POWER. Total purchased power in 1995 amounted to
23,486,000 Mwh, including UG and NYPA purchases discussed above,
representing approximately 56% of the Company's total power supply
requirements. The Company purchases electricity from the NYPP and
other neighboring utilities as needed for economic operation. The
price paid for that power is determined by specific contractual
terms. See Item 8 - Financial Statements and Supplementary Data,
Note 1. Physical limitations of existing transmission facilities,
as well as competition with other utilities and availability of
energy, impact the amount of power the Company is able to purchase
or sell. Wholesale power marketing efforts will continue to be an
important activity in a highly competitive environment, in order to
maximize the value of the Company's surplus capacity.
FUEL FOR ELECTRIC GENERATION. COAL. The C. R. Huntley and
Dunkirk Steam Stations, the Company's only coal fired generating
stations, are expected to burn about 1.5 million and 1.3 million
tons of coal, respectively, in 1996. The Company currently
anticipates obtaining its total 1996 coal requirements under short-
term contracts.
The annual average cost of coal burned from 1993 through 1995
was $1.54, $1.52 and $1.42, respectively, per million BTU, or
$39.85, $39.15, and $36.81 respectively, per ton. Changes in the
cost of coal burned, part of which are transportation expenses, are
included in the Company's FAC.
See Environmental Matters - Air.
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 1993, 1994 and 1995, natural gas was the
predominant fuel used, although generation at this station was
curtailed significantly during this period for economic reasons
because of the requirement to purchase UG power. In early 1995,
modifications were completed at the Oswego Steam Station that
provided a limited capability for using natural gas for electric
generation. Oswego's primary fuel is residual oil. In January
1995, the Company used the natural gas capability at the Oswego
Steam Station for the first time.
The Company currently purchases all natural gas for the Albany
and Oswego Steam Stations on a spot basis. This gas is purchased
as an interruptible supply; and therefore, colder than normal
weather and increased demand for capacity on interstate pipelines
by other firm (non-interruptible) gas customers could restrict the
amount of gas supplied to the stations. During the period 1993
through 1995, the Company, including the Roseton Steam Station
(described below), burned 6.0 million, 7.8 million and 12.3 million
Dth of natural gas, respectively, at an average cost per Dth of
$2.07, $2.07 and $1.65, respectively.
The Company has a 25% ownership interest in Roseton Steam
Station Units No. 1 and 2. Both Roseton Units were modified to
dual fuel capability with natural gas as the alternate fuel in the
early 1990's.
Central Hudson Gas and Electric Corporation, co-owner and
operator of the Roseton Steam Station, has three contracts for the
supply of up to 100,000 mcf (or approximately 102,000 Dth) of
natural gas for use at the Roseton plant as a fuel alternative to
residual oil. The natural gas supply is used primarily during off
peak months, April through October of each year. In 1995,
approximately 3.6 million Dth (the Company's share) of gas were
used at the Roseton plant.
RESIDUAL OIL. The Company's total requirements for residual
oil in 1996 for its Albany and Oswego Steam Stations are estimated
at approximately 1.3 million barrels. Fuel sulfur content
standards instituted by New York State require 1.5% sulfur content
fuel oil to be burned at Albany. Oswego Unit No. 6 requires low
sulfur fuel oil (0.7%). Oswego Unit No. 5, which burns 1.5% sulfur
fuel oil was placed on long term cold standby effective March 1994.
All oil requirements are met on the spot market. At December 31,
1995, there were approximately 470,000 barrels, or more than a 33-
day supply of oil, at the Oswego Steam Station and approximately
115,000 barrels of oil, or a 15-day supply, at the Albany Steam
Station, based on maximum burn projections.
The average price of Oswego Unit No. 6 oil at January 1, 1996
was approximately $27.50 per barrel for 0.7% sulfur oil. For 1.5%
sulfur oil, the average price was approximately $25.85 per barrel
at the Albany Steam Station. The fuel oil prices quoted include
the $2.95 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.
Contract arrangements for residual oil for the Roseton Steam
Station have been made by Central Hudson Gas and Electric
Corporation. Global Petroleum/Montello Oil supplies 1.5% sulfur
residual oil under contract for the majority of the fuel
requirements of the plant. The contract has provisions that
include certain options regarding contract extensions.
The annual average cost of residual oil burned at the Albany,
Oswego and Roseton Steam Stations from 1993 through 1995 was $3.11,
$3.16 and $3.41, respectively, per million BTU, or $19.84, $19.45
and $21.66, respectively, per barrel.
NUCLEAR. The supply of fuel for the Company's Nine Mile Point
nuclear generating plants involves: (1) the procurement of uranium
concentrates, (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 Unit 1 and Unit 2 (in which the Company has a 41%
interest), have been made through the following years:
Unit No. 1 Unit No. 2
Uranium Concentrates 2002 2002
Conversion 2002 2002
Enrichment 2003 2003
Fabrication 2001 2004
Arrangements have been made for procuring a portion of the
uranium, conversion and enrichment requirements through the years
listed above, leaving the remaining portion of the requirements
uncommitted. Enrichment services are under contract with the U. S.
Enrichment Corporation for up to 100% of the requirements through
the year 2003. Fuel fabrication services are under contract
through the year 2001 and 2004, for Unit 1 and Unit 2,
respectively. Up to approximately 95% and 90% of the uranium and
conversion requirements are under contract through the year 2002
for Unit 1 and Unit 2, respectively. The uncommitted requirements
for nuclear fuel materials and services are expected to be obtained
through long-term contracts or secondary market purchases.
The cost of fuel utilized at Unit 1 for 1995, 1994 and 1993
was $0.61, $0.62 and $0.56 per million BTU, respectively. The cost
of fuel utilized at Unit 2 for 1995, 1994 and 1993 was $0.51, $0.48
and $0.54 per million BTU, respectively.
The Company currently has contracts with the Department of
Energy for the disposal of spent nuclear fuel for both Units 1 and
2. Spent nuclear fuel storage facilities at Units 1 and 2 are
expected to accommodate spent nuclear fuel discharges, while also
having sufficient space available to accept fuel in the core at
that time, through the years 2009 and 2012, respectively. For a
detailed discussion of nuclear fuel disposal costs, 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 3.
GAS SUPPLY. The Company distributes and transports natural
gas to a geographic territory that generally 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, an interstate natural gas pipeline
regulated by the FERC, via seventeen delivery stations. The
Company also has one direct connect with Iroquois Gas Transmission
and one with Empire State Pipeline. 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.
FERC Order 636, effective November 1993, changed the structure
of interstate natural gas pipeline services and completed the
"evolution of competition, in the natural gas industry." The
Company has actively pursued, through the negotiation process
established by the FERC, pipeline services which provide the
Company with an appropriate combination of firm transportation on
several upstream pipelines, CNG transportation and substantial
storage rights. FERC Order 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-FERC Order 636 services to meet
peak load requirements on its system through a portfolio of firm
contracts and peak shaving contracts capable of delivering
approximately 966,000 Dths per day to its service area. This
portfolio includes firm transportation totaling approximately
306,000 Dths on the CNG system, 50,000 Dths on the Iroquois system,
as well as four pipelines upstream of CNG, with firm supplies
purchased under 23 different contracts from a variety of producers
and marketers in the Gulf of Mexico, the Southwest and Canada. An
additional 434,000 Dths of peak day requirement capacity is
provided by firm storage withdrawal rights coupled with firm winter
season transportation service on CNG. Finally, within the peak
load of 966,000 Dths is approximately 176,000 Dths available to the
Company under peak shaving contracts with cogenerators on the
Company's system.
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS. See Item 7 -
Management's Discussion and Analysis of Financial Condition and
Results of Operations and Item 8 - Financial Statements and
Supplementary Data, Note 11.
ENVIRONMENTAL MATTERS. GENERAL. The Company's operations and
facilities are subject to numerous federal, state and local laws
and regulations relating to the environment including, among other
things, requirements concerning air emissions, water discharges,
site remediation, hazardous materials handling, waste disposal and
employee health and safety. While the Company devotes considerable
resources to environmental compliance and promoting employee health
and safety, the impact of future environmental laws and regulations
on the Company cannot be predicted with certainty.
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, including, among other things, effluent
monitoring instrumentation and materials storage/handling
facilities designed to prevent or minimize releases of potentially
harmful substances. Expenditures for environmental matters for
1995 totaled approximately $51.2 million, of which approximately
$19.7 million was capitalized as pollution control equipment or new
plant environmental surveillance and approximately $31.5 million
was charged to operating expense for operation of environmental
monitoring and waste disposal programs. Expenditures for 1996 are
estimated to total $44.5 million, of which $12.6 million is
expected to be capitalized and $31.9 million charged to operating
expense. Anticipated expenditures for 1997 are estimated to total
$36.0 million, of which $4.4 million is expected to be capitalized
and $31.6 million charged to operating expense. The expenditures
for 1996 and 1997 include the estimated costs for the Company's
expected proportionate share of the costs for site investigation
and cleanup of waste sites discussed under "Solid/Hazardous Waste"
below.
Although and as further discussed below, the Company was
subject to 80%/20% (ratepayer/Company) sharing for costs incurred
with its solid/hazardous waste program in 1995, historically, rate
recovery has been authorized for 100% of the costs incurred to
comply with environmental laws and regulations. The Company
believes that if traditional rate treatment applies, then it is
probable that costs associated with environmental compliance will
continue to be recovered through the ratemaking process. For a
discussion of the uncertainty regarding the Company's continued
ability to recover these types of expenditures in rates, see Item
8 - Financial Statements and Supplementary Data, Note 2.
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 air emission sources. The Company's four fossil-fired
generating stations (Albany, Huntley, Oswego and Dunkirk) are
operated in accordance with the provisions of Certificates to
Operate issued by the DEC.
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 items. The Clean Air Act
is likely to have a substantial and increasing impact upon the
operation of electric utility fossil-fired power plants in future
years.
The acid rain provisions of the Clean Air Act require that SO2
emissions from utilities and certain other sources 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 has two units (Dunkirk 3 and 4) affected in Phase
I. Beginning in 1995, the Company was required to reduce SO2
emissions by approximately 10,000 - 15,000 tons per year and the
Company is complying with these requirements by substituting non-
Phase I units and relying on reduced utilization of these units to
satisfy its emission reduction requirements at Dunkirk 3 and 4.
With respect to NOx, Title IV of the Clean Air Act requires
emission reductions at Dunkirk 3 and 4. Low NOx burner technology
has been installed 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) required the installation of 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
was achieved by installing low NOx burners or other combustion
control technology.
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 SO2 and NOx emissions at
all of its fossil generating units. 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 use
of emission allowances created under the Clean Air Act.
In September, 1994, the states comprising the Northeast Ozone
Transport Commission (New York State included) signed a Memorandum
of Understanding that calls for each member state to develop
regulations for two additional phases of NOx reduction beyond RACT
(referred to as Phase II and Phase III, NOx reductions). In Phase
II, sources located in upstate New York (which includes all of the
Company's sources) will have to reduce NOx emissions by May, 1999
by 55 percent relative to 1990 levels or meet an emission limit of
0.2 lb./mmBtu. In Phase III, these sources will have to reduce NOx
emissions in May 2003 by 75 percent relative to 1990 levels or meet
an emission limit of 0.15 lb/mmBtu. With respect to the Phase III
program, the Memorandum of Understanding provides that the
specified reductions may be modified if additional modeling and
other scientific analysis shows that alternative NOx reductions,
together with volatile organic compound emission reductions, will
achieve attainment of the ozone ambient air quality standard across
the region. Until details are available on how the Phase II and
Phase III NOx reductions will be implemented, definitive compliance
plans for the Company's fossil generating stations and reliable
compliance cost estimates cannot be developed. However, it is
anticipated that further major capital expenditures will not be
required until Phase III (i.e. the year 2003), at which time post-
combustion NOx control technology such as selective catalytic
reduction may have to be installed to achieve compliance.
The Company spent approximately $5 million, $32 million and
$19 million in capital expenditures in 1995, 1994 and 1993,
respectively, on projects at the fossil generation plants
associated with Phase I compliance. The Company has included $15
million in its 1996 through 1999 construction forecast for Phase II
compliance which will become effective January 1, 2000. The
Company anticipates that additional expenditures of approximately
$74 million may be necessary for Phase III to be incurred beyond
2000.
With respect to all of these costs, the Company believes, that
if traditional and historical rate treatments continue to apply,
then it is probable that all additional expenditures and costs will
be fully recoverable through rates. For a discussion of the
uncertainty regarding the Company's continued ability to recover
these types of expenditures in rates, see Item 8 - Financial
Statements and Supplementary Data, Note 2.
See Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations.
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 wastewaters 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 must be 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 if traditional and historical
rate treatments continue to apply, then any additional expenditures
relating to or resulting from these studies will be fully
recoverable through rates. For a discussion of the uncertainty
regarding the Company's continued ability to recover these types of
expenditures in rates, see Item 8 - Financial Statements and
Supplementary Data, Note 2.
LOW LEVEL RADIOACTIVE WASTE. See Item 8 - Financial
Statements and Supplementary Data, Note 3.
SOLID/HAZARDOUS WASTE. The public utility industry typically
utilizes and/or generates in its operations a broad range of
potentially hazardous wastes and by-products. The Company believes
it is handling identified wastes and by-products in a manner
consistent with federal, state and local requirements and has
implemented an environmental audit program to identify any
potential areas of concern and assure compliance with such
requirements. The Company is also currently conducting a program
to investigate and restore, as necessary to meet current
environmental standards, certain properties associated with its
former gas manufacturing process and other properties which the
Company has learned may be contaminated with industrial waste, as
well as investigating identified industrial waste sites as to which
it may be determined that the Company contributed. The Company has
also been advised that various federal, state or local agencies
believe certain properties require investigation and has
prioritized the sites based on available information in order to
enhance the management of investigation and remediation, if
necessary.
The Company is currently aware of 88 sites with which it has
been or may be associated, including 46 which are Company-owned.
The Company-owned sites include 22 former MGP sites, 11 industrial
waste sites and 13 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 NPL published
by the EPA. The 42 non-owned sites with which the Company has been
or may be associated are generally industrial disposal waste sites
where some of the disposed waste materials are alleged to have
originated from the Company's operations. Pending the results of
investigations at the non-owned sites, the Company may be required
to contribute some proportionate share of remedial costs.
Investigations at each of the Company-owned sites are designed
to (1) determine if environmental contamination problems exist, (2)
if necessary, determine the appropriate remedial actions required
for site restoration and (3) where appropriate, identify other
parties who should bear some or all of the cost of remediation.
Legal action against such other parties will be initiated where
appropriate. After site investigations are completed, the Company
expects to determine site-specific remedial actions and to estimate
the attendant costs for restoration. However, since technologies
are still developing, the ultimate cost of remedial actions may
change substantially.
Estimates of the cost of remediation and post-remedial
monitoring are based upon a variety of factors, including
identified or potential contaminants, location, size and use of the
site, proximity to sensitive resources, status of regulatory
investigation and knowledge of activities at similarly situated
sites, and the EPA figure for average cost to remediate a site.
Actual Company expenditures are dependent upon the total cost of
investigation and remediation and the ultimate determination of the
Company's share of responsibility for such costs, as well as the
financial viability of other identified responsible parties since
clean-up obligations are joint and several. The Company has denied
any responsibility in certain of these PRP sites and is contesting
liability accordingly.
As a consequence of site characterizations and assessments
completed to date, the Company has accrued a liability of $195
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 $500
million. The liability accrual with respect to these owned sites
was reduced $15 million in 1995, from $210 million, to reflect the
Company's current estimate, which incorporates the availability of
information regarding the cost to remediate the Saratoga Springs
site, based on an approved remedial plan in a Record of Decision
issued by the EPA at this site in the fourth quarter of 1995.
The majority of cost estimates for currently or formerly owned
or operated properties relate to the MGP sites. The Saratoga
Springs and Harbor Point (Utica, NY) MGP sites are being
investigated and remediated pursuant to separate regulatory Consent
Orders with the EPA and the DEC, respectively. The remaining MGP
sites are the subject of a multi-site Order on Consent, executed in
1992 with the DEC, providing for an investigation and remediation
program over approximately ten years.
Estimates of the Company's potential liability for sites not
owned by the Company, but for which the Company has been identified
as a PRP, have been derived by estimating the total cost of site
clean-up and then applying a Company contribution factor to that
estimate. Estimates of the total clean-up costs are determined by
using all available information from investigations conducted by
the Company and other parties, negotiations with other PRPs and,
where no other basis is available at the time of estimate, the EPA
figure for average cost to remediate a site listed on the NPL as
disclosed in the Federal Register of June 23, 1993 (58 FR No. 119).
A contribution factor is then calculated using either a per capita
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 PRPs since clean-up obligations are joint and several.
The Company has denied any responsibility for certain of these PRP
sites and is contesting liability accordingly.
With respect to the 42 sites with which the Company has been
or may be associated as a PRP, the Company has recorded a liability
of $30 million, representing the estimate of its share of the total
cost to investigate and remediate these sites. Total costs to
investigate and remediate these sites are estimated to be
approximately $430 million in the unlikely event the Company is
required to assume 100% responsibility. Seven of the PRP sites are
included on the NPL. The Company estimates its share of the
liability for these seven sites is not material and has included
the amount in the determination of the amounts accrued.
The Company is also aware of approximately 25 formerly-owned
MGP sites and 11 fire training sites used, but not owned by the
Company, which it has been or may be associated and which may
require future investigation and possible remediation. Presently,
the Company has not determined its potential involvement with such
sites and accordingly has made no provision for potential
liabilities associated therewith. In the event the Company is
notified of its potential involvement at such sites by regulatory
agencies and/or PRPs, the Company will determine its potential
liability in the same manner described previously for PRP sites in
general.
Prior to 1995, the Company recovered 100% of its costs
associated with site investigation and restoration. In the
Company's 1995 rate order, costs incurred during 1995 for the
investigation and restoration of Company-owned sites and sites with
which it is associated were subject to 80%/20% (ratepayer/Company)
sharing. In 1995, the Company incurred $11.5 million of such
costs, resulting in a disallowance of $2.3 million (before tax),
which the Company has recognized as a loss in Other items (net) on
the Consolidated Statements of Income. The PSC stated in its
opinion, dated December 1995, its decision to require sharing was
"on a one-time, short-term basis only, pending its further
evaluation of the issue in future proceedings." Based upon
management's assessment that remediation costs will be fully
recovered from ratepayers, a regulatory asset has been recorded
representing the future recovery of remediation obligations accrued
to date. Therefore, the Company does not believe the costs to
comply with environmental laws and regulations will have a material
adverse effect on its results of operations or financial condition.
For a discussion of the Company's continued ability to recover
these types of expenditures in rates, see Item 8 - Financial
Statements and Supplementary Data, Note 2.
Where appropriate, the Company has provided notices of
insurance claims to carriers with respect to the investigation and
remediation costs for manufactured gas plant, industrial waste
sites and sites for which the Company has been identified as a PRP.
The Company is unable to predict whether such insurance claims will
be successful.
For a discussion of additional environmental legal
proceedings, see Item 3 - Legal Proceedings.
NUCLEAR OPERATIONS. See Item 8 - Financial Statements and
Supplementary Data, Note 3.
CONSTRUCTION PROGRAM. See Item 7 - Management's Discussion
and Analysis of Financial Condition and Results of Operations -
CONSTRUCTION AND OTHER CAPITAL REQUIREMENTS and Item 8 - Financial
Statements and Supplementary Data, Note 9 - Construction Program.
ELECTRIC SUPPLY PLANNING. The Company filed an IERP with the
PSC and the State Energy Planning Board in 1995. While recognizing
that uncertainty exists in forecasting future load, the IERP
projects that the Company will not require generating capacity to
fulfill its installed reserve requirements until the winter of
1999/2000. Included in the IERP is the planned retirement of 340
MWs of coal capacity. It is expected that the return to operation
of Oswego Unit 5 (850 MW) from long term cold standby status will
be the most economical option for meeting the Company's needs at
that time. With Oswego Unit 5 in operation, the need for
additional capacity would not be expected until the winter of
2009/2010 or beyond. For this and other reasons, the Company need
not commit to the construction or acquisition of large new
generation projects for many years.
Currently, the Company's intentions are to use a resource
bidding process to confirm that the return to operation of Oswego
Unit 5 represents the most economic alternative. A Request for
Proposal (RFP) would be issued and bids evaluated prior to making
a decision to restart that unit in 1999. The RFP process will also
be used periodically to confirm that operating plants provide the
least costly means of serving customer needs. A solicitation for
capacity and energy in 1995 supported the Company's current
generation portfolio.
Under the Company's PowerChoice proposal, the obligation to
meet NYPP installed reserve requirements would shift to an ISO.
The PowerChoice proposal would replace the current planning/RFP
process with a competitive market. Future supply decisions would
be based on market forces. The ISO would periodically go out for
bid for capacity with an RFP process that is similar to what is
described above. Although competition will replace the planning
process described above, the units providing energy and capacity in
the competitive market could be quite similar to those described in
the supply plan above.
ELECTRIC DELIVERY PLANNING. As of January 1, 1996, the
Company had approximately 130,000 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 continuing to evaluate new
planning tools and methods to quantify the adequacy and reliability
of its electric delivery facilities. The Company believes these
new tools and methods will aid it in prioritizing reinforcements to
its electric delivery infrastructure in order to maximize value.
The Company has reviewed the adequacy of its electric delivery
facilities and has determined that capital requirements to support
new load growth will be below previous years' expenditures.
Interconnection studies for all major UG projects have been
completed. Additional UG projects which would impose significant
technical, economic and construction burdens on the Company are not
anticipated.
The EPAct 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 EPAct, 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 the utility's ability to recover all
costs of providing these services. Transmission studies of
operating under open transmission access indicate that the
Company's transmission system is adequate to meet national and
regional reliability criteria. Any further expansion of the
transmission capability as a result of the EPAct would require an
investment allocation method linked to the beneficiaries. The
Company, however, remains committed to a policy of providing
adequate transmission service that protects the economic well-being
of the Company's customers.
DEMAND-SIDE MANAGEMENT PROGRAMS. The Company's DSM programs
continue to promote energy efficiency by providing customers
information, technology demonstrations, seminars and assistance
with energy efficiency improvement projects. The evolving
competitive market for energy efficiency services is providing
customers with many alternative sources for DSM products and
services. The Company will continue to foster the development of
this market and provide information and assistance to customers so
they can make informed choices.
The Company spent approximately $8.1 million on DSM programs
in 1995. Preliminary results for 1995, estimate annual energy
reductions of 173,000 Mwh compared with a goal of 160,000 Mwh. The
cumulative effect of the Company's DSM programs from 1990 through
1995 are estimated to have reduced annual energy consumption by
1,324 Gwh and reduced peak demand by approximately 300 Mw.
The Company's DSM programs are an integrated approach of
information, customer education, financing assistance and
facilitation for residential and commercial and industrial
customers. Energy efficiency activities are an integral part of
the Company's marketing plan for meeting customer needs. The
Company will not have specific DSM programs in the future but will
continue to pursue the promotion of energy efficiency as a key
strategy of its marketing plans.
RESEARCH AND DEVELOPMENT. Research and development is focused
to directly benefit the Company's shareholders and customers by
obtaining a return on R&D investments. The Company maintains an
R&D program aimed at improving the delivery and use of energy
products and finding practical applications for new and existing
technologies in the energy business. These efforts include (1)
improving efficiency; (2) minimizing environmental impacts; (3)
improving facility availability; (4) minimizing maintenance costs;
and (5) developing renewable energy technologies.
R&D expenditures in 1995, 1994 and 1993 were approximately
$14.0 million, $37.3 million and $39.0 million, respectively. A
reduction in expenses occurred in 1995 as a result of a planned
cost containment by the Company. R&D expenditures for 1996 are
expected to be approximately the same level as 1995. Historically
the Company has received rate recovery under traditional ratemaking
for R&D expenditures. Therefore, the Company believes that it will
continue to receive rate recovery under traditional ratemaking for
these types of expenditures.
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, expired on February 29, 1996, but is being
extended while a new agreement is negotiated. The Company expects
a new five-year-three-month agreement to be entered into by early
April, 1996.
The Company's work force at December 31, 1995 numbered
approximately 8,800, of whom approximately 6,100 are union members.
It is estimated that approximately 77% of the Company's total labor
costs are applicable to operation and maintenance and approximately
23% are applicable to construction (and accordingly are
capitalized) and other accounts.
LIABILITY INSURANCE. As of January 31, 1996, 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
Directors and officers against liabilities for which they may not
be indemnified by the Company, except for a dishonest act or breach
of trust.
ITEM 2. PROPERTIES.
ELECTRIC SERVICE. As of January 1, 1996, 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 diesel generating units and 70
hydroelectric plants, as well as having a majority interest in
Beebee Island and Feeder Dam Hydro Plants and their output. The
Company also purchases substantially all of the output of 96 other
hydroelectric facilities. 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 and a windmill generator in the Province of Alberta. In
addition, the Company has contracts to purchase electric energy
from NYPA and other sources. See Item 1 - Business. - Unregulated
Generators, New York Power Authority and Purchased Power and Item
8 - Financial Statements and Supplementary Data, Note 9 and also
Electric and Gas Statistics.
The following is a list of the Company's major operating
generating stations at February 1, 1996:
Company's Share of
Station, Location Net Capability
and Percent Ownership Energy Source In Megawatts
- ----------------------------------------------------------------
Huntley, Niagara River (100%) Coal 740
Dunkirk, Lake Erie (100%) Coal 576
Albany, Hudson River (100%) Oil/Natural Gas 400
Oswego, Lake Ontario (76%)
(Unit 6) Oil/Natural Gas 636
Roseton, Hudson River (25%) Oil/Natural Gas 300
Nine Mile Point, Lake Ontario (100%)
(Unit 1) Nuclear 613
Nine Mile Point, Lake Ontario (41%)
(Unit 2) Nuclear 469
As of December 31, 1995, the Company's electric transmission
and distribution systems were comprised of 961 substations with a
rated transformer capacity of approximately 28,600,000 kva., about
8,000 circuit miles of overhead transmission lines, about 1,100
cable miles of underground transmission lines, about 113,900
conductor miles of overhead distribution lines and about 5,900
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, 1995 occurred on February 6,
1995 and was 6,211,000 kw., of which 429,000 kw. was generated in
hydroelectric plants, 2,857,000 kw. was generated in thermal
electric plants and 3,448,000 kw. (of which 3,299,000 kw. was firm)
was purchased. Economy and emergency sales to other utilities on
such date were 523,000 kw. For a detailed breakdown of the
Company's electric capability at December 31, 1995, see Item 8 -
Financial Statements and Supplementary Data - Electric and Gas
Statistics.
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. For a discussion on
potential changes to NYPP, see Part II, Item 7 - Management's
Discussion and Analysis of Financial Condition and Results of
Operations - Federal and State Regulatory Initiatives - FERC NOPR
on Stranded Investment and POWERCHOICE PROPOSAL.
NUCLEAR PROPERTY AND LIABILITY INSURANCE. See Part II - Item
8. Financial Statements and Supplementary Data - Note 3.
GAS SERVICE. The Company distributes gas purchased from
suppliers and transports gas owned by others. As of December 31,
1995, the Company's natural gas system was comprised of
approximately 7,700 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, 1995 was 1,211,252 dekatherms set
on February 6, 1995.
SUBSIDIARIES. One of the Company's subsidiaries, Opinac
Energy Corporation, owns an electric company, Canadian Niagara
Power Company, Limited (CNP), with operations in the Province of
Ontario, Canada, a wind power company, Cowley Ridge Wind Power
Company, with operations in the Province of Alberta, Canada and an
unregulated company, Plum Street Enterprises, that will offer
energy-related services with operations in New York State. CNP
generates electricity at its Niagara Falls, Ontario Hydro plant for
the wholesale market and for its distribution system in Fort Erie,
Ontario. A Texas subsidiary, NM Uranium, Inc. has an interest in
a uranium mining operation in Live Oak County, Texas which is now
in the process of reclamation and restoration. Another New York
State subsidiary engages in real estate development, NM Holdings,
Inc. Each of these subsidiaries is wholly-owned by the Company.
MORTGAGE LIENS. Substantially all of the Company's operating
properties are subject to a mortgage lien securing its mortgage
debt.
ITEM 3. LEGAL PROCEEDINGS.
For a detailed discussion of additional legal proceedings, see
Item 8 - Financial Statements and Supplementary Data, Note 9 -
Commitments and Contingencies - Tax Assessments, Litigation and
Environmental Contingencies. See also Item 1 - Business -
Environmental Matters - Solid/Hazardous Waste, and Part II, Item 7
- - Management's Discussion and Analysis of Financial Condition and
Results of Operations - Unregulated Generators. The Company is
unable to predict the ultimate disposition of the matters referred
to below in (1), (2) and (3). However, the Company has previously
been allowed to recover these types of expenditures in rates, and
the Company believes that if traditional rate treatment continues
to apply, then it is probable that the Company will continue to
recover these types of expenditures in rates. For a discussion of
the uncertainty regarding the Company's continued ability to
recover these types of expenditures in rates, see Item 8 -
Financial Statements and Supplementary Data, Note 2.
1. The Company was notified by the EPA in November 1986 that
it is one of 833 PRPs under Superfund for the
investigation and cleanup of the Maxey Flats Nuclear
Disposal Site in Morehead, Kentucky. This was a low
level nuclear waste disposal site which was operated
between 1963 and 1977. It is estimated the Company sent
approximately 114,500 cubic yards of various radiated
materials to the site for disposal. In response to the
EPA notice, the Company participated in funding a
Remedial Investigation/Feasibility Study for the site,
which resulted in EPA's selection in 1991 of an
appropriate remedial action. The Company is also a
signatory party to the participation/cost sharing
agreement and Consent Decree by which the remedial action
will be carried out by the participating parties: The
Consent Decree was lodged in federal court on June 5,
1995 and is expected to be entered prior to mid-1996. It
provides for design and implementation of the selected
remedial action and for reimbursement of $5.3 million in
response costs incurred by EPA. Parties to the Decree
are the United States, including EPA, the U.S. Air Force,
the U.S. Army, the U.S. Navy, the Department of Defense,
the Department of Energy, the National Institute of
Health, and NASA; the Commonwealth of Kentucky ; and 43
private parties including the Company. The Company
estimates its share of total anticipated costs to be in
the range of $1 million, based on its allocated
percentage of shared costs.
2. On July 21, 1988, the Company became a defendant in an
ongoing Superfund lawsuit in Federal District Court,
Northern District of New York (Federal District Court)
brought by the Federal Government. 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.
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 who also elected not to accept the terms of
the government's final settlement demand. The Company,
in conjunction with the Buffalo Sewer Authority, filed a
Fourth Party Complaint in March 1994 against several
additional PRP's which had not been included in the
government's action. In February 1996, the Federal
District Court entered a scheduling order providing for
the resumption of discovery on April 1, 1996, unless the
government and the defendants have reached agreement on
a settlement figure, and the defendants have submitted to
the Federal District Court a binding allocation
agreement. Negotiations regarding this issue are
ongoing.
3. On June 22, 1993, the Company and twenty other industrial
entities and the owner/operator of the Pfohl Brothers
Landfill near Buffalo, New York, were sued in New York
Supreme Court, Erie County, by a group of residents
living in the vicinity of the landfill seeking
compensation and damages for economic loss and property
damages claimed to have resulted from contamination
emanating from the landfill. In addition, on January 18,
1995, the Company was served a Summons and Complaint as
one of 17 defendants named in a toxic tort action filed
in the Erie County Supreme Court (Frazer, et al. v.
Westinghouse Electric Corp., et al.). The suit alleges
exposure on the part of the plaintiffs to toxic chemicals
emanating from the Pfohl Brothers Landfill, resulting in
the alleged causation of cancer in each of the
plaintiffs. The plaintiffs seek compensatory and
punitive damages in the amount of approximately $60
million. The Company was notified by the DEC in 1986 of
its status as a PRP in connection with the contamination
of this landfill, but did not initially take an active
role in the remediation process because of the existence
of minimal evidence that any hazardous substances
generated by the Company were disposed of there. It has
been alleged, however, that another defendant (Downing
Container Division of Waste Mgt. of N.Y.) transported
waste materials to the landfill from the Company's Dewey
Avenue Service Center during the 1960's. Therefore, in
July 1995, the Company elected to become a member of the
Steering Committee consisting of identified PRPs, and
thereby participate in the development of an appropriate
remedial action for the site and an equitable allocation
of liability among responsible parties. To date, no
governmental action has been taken against the Company as
a PRP. The Company has undertaken to establish defenses
to the allegations in both lawsuits, and is investigating
its alleged connection to the landfill to determine an
appropriate level of participation in the ongoing
voluntary remedial program conducted by the Steering
Committee.
4. On October 23, 1992, the Company petitioned the PSC to
order UGs 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.
In December 1995, the Company filed a petition with the
PSC similar to the one that the Company filed in October
1992. The Company cannot predict the outcome of this
action.
On February 4, 1994, the Company notified the owners of
nine projects with contacts 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 as required by agreements and the
repayment 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 for the
projects. The Company has received the following
responses to these notifications:
On March 4, 1994, Encogen Four Partners, L.P. (Encogen)
filed a complaint in the United States District Court for
the Southern District of New York (U.S. District Court)
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 assurance of
future performance from Encogen. On April 4, 1994, the
Company filed its answer and counterclaim for declaratory
judgment relating to the Company's exercise of its right
to demand adequate assurance. Encogen has amended its
complaint, rescinded its prima facie tort claim, and
filed a motion of judgment on the pleadings. On February
6, 1996, the U.S. District Court granted Encogen's motion
for judgment on the pleadings and ruled that under New
York law, the Company did not have the right to demand
adequate assurances of future performance. In addition,
the U. S. District Court did not award any damages. The
Company plans to appeal this decision.
On March 4, 1994, Sterling Power Partners, L.P.
(Sterling), 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 assurance
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. On April
4, 1994, the Company filed its answer and counterclaim
for declaratory judgment relating to the Company's
exercise of its right to demand adequate assurance. On
October 5, 1994, Sterling moved for summary judgment and
the Company opposed and cross moved for summary judgment.
On February 16, 1996, Sterling supplemented its motion,
claiming that the February 6, 1996 ruling in the Encogen
case is dispositive. On February 29, 1996, the New York
State Supreme Court granted Sterling's motion for summary
judgment and ruled that under New York law, the Company
did not have the right to demand adequate assurances of
future performance. The Company plans to appeal this
decision.
On March 7, 1994, NorCon Power Partners, L.P. (NorCon)
filed a complaint in the U.S. District Court 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. On April 4,
1994, the Company filed its answer and counterclaim for
declaratory judgment relating to the Company's exercise
of its right to demand adequate assurance. On November
2, 1994, NorCon filed for summary judgment. On February
6, 1996, the U.S. District Court granted NorCon's motion
for summary judgment and ruled that under New York law,
the Company did not have the right to demand adequate
assurances of future performance. The Company plans to
appeal this decision.
While the Company will continue to press for adequate
assurance that the owners of these projects will honor
their repayment obligations, the Company can neither
provide any judgement regarding the likely outcome nor
any estimate or range of possible loss or reduction of
exposure in these cases. Accordingly, no provision for
liability, if any, that may result from any of these
suits has been made in the Company's financial
statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
The Company has nothing to report for this item.
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 or upon the filling of a vacancy. 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 or she was selected as an
officer.
Age at
Executive 12/31/95 Current and Prior Positions Date Commenced
--------- -------- --------------------------- --------------
William E. Davis 53 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
John M. Endries 53 Retired May 1995
President June 1988
Albert J. Budney, 48 President and Chief Operating Officer April 1995
Jr. Managing Vice President - UtiliCorp Power Prior to Join-
Services Group (a unit of UtiliCorp United, Inc.) ing the Company
President-Missouri Public Service (Operating
Division of UtiliCorp United, Inc.) January 1993
Vice President - Stone & Webster Engineering Corp. January 1990
B. Ralph Sylvia 55 Executive Vice President - Electric Generation and
Chief Nuclear Officer December 1995
Executive Vice President - Nuclear Operations November 1990
David J. Arrington 44 Senior Vice President - Human Resources December 1990
Darlene D. Kerr 44 Senior Vice President - Energy Distribution December 1995
Senior Vice President - Electric Customer Service January 1994
Vice President - Electric Customer Service July 1993
Vice President - Gas Marketing and Rates February 1991
Gary J. Lavine 45 Senior Vice President - Legal & Corporate Relations May 1993
Senior Vice President - Legal & Corporate Relations
and General Counsel October 1992
Senior Vice President - Legal & Corporate Relations,
General Counsel and Secretary May 1991
Senior Vice President - Legal & Corporate Relations October 1990
John W. Powers 57 Senior Vice President and Chief Financial Officer January 1996
Senior Vice President - Finance & Corporate Services October 1990
Michael P. Ranalli 62 Retired October 1995
Senior Vice President - Electric Supply & Delivery October 1990
Theresa A. Flaim 46 Vice President - Corporate Strategic Planning May 1994
Vice President - Corporate Planning April 1993
Manager - Gas Rates & Integrated Resource Planning June 1991
Director - Demand-Side Planning November 1987
Kapua A. Rice 44 Corporate Secretary September 1994
Assistant Secretary October 1992
Manager - Legal & Corporate Relations July 1991
Office Administrator - Law November 1989
Steven W. Tasker 38 Vice President - Controller December 1993
Controller May 1991
Assistant Controller October 1988
/TABLE
PART II
- -------
ITEM 5. MARKET FOR THE 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 (NYSE). 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 estimates that
none of the 1995 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 (NYSE) and
dividends per share for the Company's common stock:
DIVIDENDS PAID PRICE RANGE
1995 PER SHARE HIGH LOW
- --------------------------------------------------------------
1st Quarter $.28 $15 5/8 $13 3/8
2nd Quarter .28 15 1/8 13 5/8
3rd Quarter .28 14 3/4 11 1/4
4th Quarter .28 13 3/8 9 1/2
1994
- --------------------------------------------------------------
1st Quarter $.25 $20 5/8 $17 3/4
2nd Quarter .28 19 14 5/8
3rd Quarter .28 17 1/2 12
4th Quarter .28 14 3/8 12 7/8
On January 25, 1996, the board of directors omitted the common
stock dividend for the first quarter of 1996. This action was
taken to help stabilize the Company's financial condition and
provide flexibility as the Company addresses growing pressure from
mandated power purchases and weaker sales. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" below. In making future dividend decisions, the board
will evaluate, along with standard business considerations, the
level and timing of future rate relief, the progress of
renegotiating contracts with unregulated generators (UGs) within
the context of its PowerChoice proposal, the degree of competitive
pressure on its prices, and other strategic considerations.
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 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 retained earnings 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 retained earnings.
At year end, there were approximately 84,600 holders of record
of common stock of the Company and about 5,700 holders of record of
preferred stock. The chart below summarizes common stockholder
ownership by size of holding:
SIZE OF HOLDING TOTAL STOCKHOLDERS TOTAL SHARES HELD
(SHARES)
- -----------------------------------------------------------------
1 to 99 34,975 977,436
100 to 999 44,871 11,155,890
1,000 or more 4,780 132,198,797
------ -----------
84,626 144,332,123
====== ===========
/TABLE
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
The following table sets forth selected financial information of the Company for each of the
five years during the period ended December 31, 1995, which has been derived from the audited
financial statements of the Company, and should be read in connection therewith. As
discussed in "Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Notes to Consolidated Financial Statements," the following selected
financial data may not be indicative of the Company's future financial condition or results
of operations:
1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------------------
Operations: (000's)
Operating revenues $ 3,917,338 $ 4,152,178 $ 3,933,431 $ 3,701,527 $ 3,382,518
Net income 248,036 176,984 271,831 256,432 243,369
- ------------------------------------------------------------------------------------------
Common stock data:
Book value per share
at year end $17.42 $17.06 $17.25 $16.33 $15.54
Market price at
year end 9 1/2 14 1/4 20 1/4 19 1/8 17 7/8
Ratio of market price to
book value at year end 54.5% 83.5% 117.4% 117.1% 115.0%
Dividend yield at year end 11.8%* 7.9% 4.9% 4.2% 3.6%
Earnings per average
common share $1.44 $1.00 $1.71 $1.61 $1.49
Rate of return on common
equity 8.4% 5.8% 10.2% 10.1% 10.0%
Dividends paid per
common share $1.12* $1.09 $ .95 $ .76 $ .32
Dividend payout ratio 77.8%* 109.0% 55.6% 47.2% 21.5%
- ------------------------------------------------------------------------------------------
Capitalization: (000's)
Common equity $ 2,513,952 $ 2,462,398 $ 2,456,465 $ 2,240,441 $ 2,115,542
Non-redeemable
preferred stock 440,000 440,000 290,000 290,000 290,000
Mandatorily redeemable
preferred stock 96,850 106,000 123,200 170,400 212,600
Long-term debt 3,582,414 3,297,874 3,258,612 3,491,059 3,325,028
- ------------------------------------------------------------------------------------------
TOTAL 6,633,216 6,306,272 6,128,277 6,191,900 5,943,170
Long-term debt maturing
within one year 65,064 77,971 216,185 57,722 175,501
- ------------------------------------------------------------------------------------------
TOTAL $ 6,698,280 $ 6,384,243 $ 6,344,462 $ 6,249,622 $ 6,118,671
- ------------------------------------------------------------------------------------------
Capitalization ratios: (including long-term debt maturing within one year)
Common stock equity 37.5% 38.6% 38.7% 35.8% 34.6%
Preferred stock 8.0 8.5 6.5 7.4 8.2
Long-term debt 54.5 52.9 54.8 56.8 57.2
- ------------------------------------------------------------------------------------------
Financial ratios:
Ratio of earnings to
fixed charges 2.29 1.91 2.31 2.24 2.09
Ratio of earnings to
fixed charges
without AFC 2.26 1.89 2.26 2.17 2.03
Ratio of AFC to balance
available for
common stock 4.3% 6.3% 6.8% 9.7% 9.3%
Ratio of earnings to
fixed charges and
preferred stock
dividends 1.90 1.63 2.00 1.90 1.77
Other ratios - % of
operating revenues:
Fuel, purchased
power and purchased
gas 40.3% 39.6% 36.1% 34.1% 32.1%
Other operation
expenses and maintenance 20.9 23.1 26.9 26.3 27.6
Depreciation and
amortization 8.1 7.4 7.0 7.4 7.7
Total taxes, including
real property, income
and revenue taxes 17.3 14.7 16.2 17.3 16.4
Operating income 13.5 10.4 13.3 14.2 15.5
Balance available for
common stock 5.3 3.5 6.1 5.9 6.0
- ------------------------------------------------------------------------------------------
Miscellaneous: (000's)
Gross additions to
utility plant $ 345,804 $ 490,124 $ 519,612 $ 502,244 $ 522,474
Total utility plant 10,649,301 10,485,339 10,108,529 9,642,262 9,180,212
Accumulated depreciation
and amortization 3,641,448 3,449,696 3,231,237 2,975,977 2,741,004
Total assets 9,477,869 9,649,816 9,471,327 8,590,535 8,241,476
==========================================================================================
* On January 25, 1996, the Board of Directors omitted the common stock dividend.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
- --------
Earnings in 1995 were $208.4 million or $1.44 per share.
Earnings in 1994 were $143.3 million or $1.00 per share and
included $101.2 million or 46 cents per share of electric margin
recorded under the NERAM, as well as a charge of about $197 million
(89 cents per share) for nearly all of the cost of the VERP. NERAM
was a surcharge which assured that the Company's margin on electric
sales would equal the margin assumed in establishing rates. In
January 1995 NERAM was discontinued. 1995 earnings were negatively
impacted by lower sales of electricity and natural gas, compared to
amounts used to establish 1995 prices, due primarily to continuing
weak economic conditions in upstate New York, loss of industrial
load to NYPA and discounts. However, cost reduction efforts begun
in 1994 through the VERP helped 1995 earnings. The Company's 1995
earned return on common equity was 8.4%, which was below the 11.0%
that the PSC authorized on electric utility operations due to,
among other things: sales below those forecast in determining
rates; about $20 million of negotiated customer discounts in excess
of the approximately $42 million reflected in rates; the inability
to achieve stringent wholesale margin targets set by the PSC; and
fuel target penalties caused by low hydro production due to dry
weather. The Company expects the trend of weak sales to continue,
given the poor economic condition of the Company's service
territory.
In the long term, the Company's earnings will depend
substantially on the outcome of the Company's PowerChoice proposal
discussed below, which was filed with the PSC in October 1995. The
Company filed for price increases of 4.1% for 1996 and 4.2% for
1997 and earnings for these years will depend on the outcome of the
rate requests. The 1996 rate filing is for temporary rate relief
for which the Company has asked for immediate action. On February
16, 1996, the PSC issued an order that, among other things,
established a schedule with respect to temporary rates that would
have the case certified directly to the PSC within 60 days of the
order. The 1997 filing will preserve the Company's right to
traditional cost-based rates in the event that an acceptable
regulatory solution cannot be achieved through negotiation of the
PowerChoice proposal. While negotiations are continuing on
PowerChoice, in view of increasing UG payments, discounts and
continued weak sales expectations, the Company has found it
necessary to seek these price increases. Without any form of rate
relief in 1996 and 1997, the Company would expect to earn a return
on equity substantially below that earned in 1995. The Company is
implementing additional reductions in non-essential programs (not
related to safety and reliability) to reduce costs.
On January 25, 1996, the board of directors omitted the common
stock dividend for the first quarter of 1996. This action was
taken to help stabilize the Company's financial condition and
provide flexibility as the Company addresses growing pressure from
mandated power purchases and weaker sales. In making future
dividend decisions, the board will evaluate, along with standard
business considerations, the level and timing of future rate
relief, the progress of renegotiating contracts with UGs within the
context of its PowerChoice proposal, the degree of competitive
pressure on its prices, and other strategic considerations.
Following the announcement of the PowerChoice proposal, S&P
and Moody's downgraded all of the Company's credit ratings to
"below investment grade," and placed the Company's securities on
"Credit Watch" with negative implications. The downgrade of the
Company's security ratings reflects concerns regarding the
uncertainty and potential negative impact of the PowerChoice
proposal on the Company, as well as the potential for bankruptcy.
The Company is committed to pursuing PowerChoice as a positive
response to competitive threats and to stabilize and improve the
financial condition of the Company. The Company will also consider
pursuing other actions, such as requesting rate relief or
evaluating solutions other than PowerChoice, to maintain the
financial viability of the Company.
Due, in part, to the negative response to the PowerChoice
proposal from rating agencies, the prices of the Company's common
stock, preferred stock and bonds declined sharply. The downgrading
of the Company's bonds can be expected to make it more difficult
and expensive for the Company to finance in the manner it has used
in the past. Consequently, the Company is borrowing under its bank
revolving credit agreement. In order to further satisfy
anticipated financing needs, including those which may be necessary
as a result of potential changes to the structure of New York State
electricity markets, the Company is currently renegotiating its
bank credit facilities and filed a petition with the PSC in
December 1995 for authority to enter into a senior debt facility.
(See Note 13 of Notes to the Consolidated Financial Statements).
The proposed senior debt facility totals $815 million and would
consolidate and replace certain of the Company's existing working
capital lines of credit and letter of credit facilities, as well as
provide additional reserves of bank credit. There can be no
assurance that the Company will be successful in putting this
facility in place; in the event the facility is not completed, the
Company believes that the elimination of the common dividend, the
implementation of reductions in non-essential programs and the
year-end 1995 cash position, in combination with alternative
sources of credit the Company believes are available if necessary,
will be sufficient to fund cash requirements for 1996. Current
market conditions preclude the Company from issuing stock in 1996
due to the downgrading of the Company's security ratings. (See
"FINANCIAL POSITION, LIQUIDITY AND CAPITAL RESOURCES").
The Company faces significant challenges in its efforts to
maintain its financial condition in the face of expanding
competition and weak sales. While utilities across the nation must
address these concerns to varying degrees, the Company believes
that it is more financially vulnerable than others to competitive
threats. The factors contributing to this vulnerability include a
large industrial customer base, accounting for about 21% of total
electric Kwh sales, an oversupply of high cost mandated power
purchases from UGs, an excess supply of wholesale power at
relatively low prices, a high tax burden, a stagnant economy in the
Company's service territory and significant investments in nuclear
plants. Moreover, solving the problems the Company faces,
including the implementation of PowerChoice, requires the
cooperation and agreement of third parties. Accordingly, the
outcome cannot be assured and the possibility of restructuring
under Chapter 11 of the U.S. Bankruptcy Code cannot be ruled out.
The following sections present an assessment of competitive
conditions and steps being taken to improve the Company's strategic
and financial condition.
CHANGING COMPETITIVE ENVIRONMENT
The accelerating pace of competition is driving dramatic
changes throughout the utility industry. In addition, the Company
is challenged by state-imposed burdens, especially state-mandated
contracts that require the Company to buy electricity from UGs in
amounts that exceed customer needs and at prices that are above the
Company's own cost of providing electricity. In addition, the
Company and other New York utilities bear an excessive tax burden
that is more than twice the average for utilities nationwide.
The Company has pursued a number of actions to mitigate the
impact of these factors on prices. These actions have included
renegotiating and buying out some UG contracts and canceling others
when contract terms were not being adhered to. The Company has
also been actively seeking reductions in its state and local tax
obligations. Nevertheless, mandated UG purchases and high taxes
have combined to create an irrational energy market in the
Company's service territory - despite an oversupply of generating
capacity, prices are rising. Further price increases would make it
more difficult for the Company to retain its customers in the
longer term and an increasing number of customers are pursuing
other supply options including self-generation, alternate supply
sources, and municipalization. As a result, electric margins are
narrowing and sales are eroding, damaging the Company's financial
condition and putting further pressure on the Company to seek even
more rate increases under traditional cost-of-service ratemaking.
The Company has responded to these factors by, among other
actions, sharply reducing internal costs. The Company has reduced
the size of its work force by about 3,200 employees, or 27%, in the
past three years, and has eliminated, consolidated or modernized
many of its operations. The Company has also sharply reduced
capital spending. Electric construction spending in future years
is expected to be limited to the level of depreciation expense,
thereby resulting in little growth in rate base.
These cost control efforts have produced significant savings.
However, the savings are being outpaced by continuing escalation in
the externally imposed costs discussed above. Recognizing that
major changes in the electricity marketplace in New York State were
needed, the Company undertook an exhaustive analytical process with
the goal of creating a rational energy market that would link
supply, demand and price, provide customers with better and broader
services, and provide greater opportunities for building
shareholder value. That process resulted in the filing of the
Company's PowerChoice proposal on October 6, 1995.
PowerChoice is the Company's proposal for stable retail
prices, customer choice and an open, competitive electric
generation market. The proposal includes, among other things, a
five-year price freeze for residential and commercial customers, a
price cut for industrial customers to help create jobs and spur
economic activity, and restructuring of the Company's businesses.
The Company would separate its electrical generation operations,
along with the UG contracts not restructured, into a different
company that would compete in a deregulated power market. The
remaining company would have regulated and unregulated subsidiaries
that would transmit and distribute power and engage in new business
opportunities with growth potential.
The Company believes that PowerChoice is the best course of
action to deal with emerging competition and address the factors
that have been pushing up prices. However, the success of
PowerChoice and its associated price freeze depends upon the
willingness of UGs and the Company to make substantial reductions
in embedded costs (i.e., sunk generation costs, regulatory assets
and future obligations under UG contracts). In addition, the
Company believes that the state must play a role in reducing costs,
particularly by reducing or eliminating the state gross receipts
tax, which taxes revenue rather than income. State involvement
with the Company's nuclear plants would also be needed for all
aspects of the plan to succeed and achieve a price freeze.
Addressing these issues will be difficult and will almost certainly
require judicial, regulatory and/or legislative action. However,
the Company believes that the implementation of PowerChoice is
achievable.
When PowerChoice was announced, the Company said that failure
to approve the plan would mean continued price escalation under
traditional regulation, or failing that, further deterioration in
the Company's financial condition. The Company filed for price
increases of 4.1% for 1996 and 4.2% for 1997 and earnings for these
years depend on the outcome of the rate requests. The 1996 rate
filing is for temporary rate relief for which the Company has asked
for immediate action. On February 16, 1996, the PSC issued an
order that, among other things, established a schedule with respect
to temporary rates that would have the case certified directly to
the PSC within 60 days of the order. The 1997 filing will preserve
the Company's right to traditional cost-based rates in the event
that an acceptable regulatory solution cannot be achieved through
negotiation of the PowerChoice proposal. While negotiations are
continuing on PowerChoice, in view of increasing UG payments,
discounts and continued weak sales expectations, the Company has
found it necessary to seek these price increases. The Company
expects that the PSC will approve cost-of-service based rate
increases until such time as implementation of a new competitive
market model becomes probable.
The Company's current electricity and gas prices reflect
traditional utility regulation. As such, the Company's electricity
prices include state-mandated purchased power costs from UGs, at
costs far exceeding the Company's actual avoided costs, as well as
the costs of high taxes in New York. Without legislative or
regulatory action, the Company is severely limited in its ability
to control or reduce these purchased power costs and taxes, which
are major causes of the Company's recent increases in prices.
While the Company is experiencing rising prices, rapid
technological advances are significantly reducing the price of new
generation and significantly improving the performance of smaller
scale generating unit technology. In addition, the current excess
supply of generating capacity has driven down the prices a
competitive market would support. Actions taken by other utilities
throughout the country to lower their prices, including those in
areas with already relatively low prices, increase the threat of
industrial relocation and the need to offer discounts to industrial
customers.
The Company continues to take aggressive action to both
prevent the loss of certain industrial customers, and to attract
new business. In 1995, the Company granted approximately $62
million of discounts. Discounts are expected to increase in 1996
and 1997, but will depend on energy price levels in the marketplace
and other competitive activity. (See "Customer Discounts").
The Company also faces the continued threat of
municipalization. A growing number of municipalities within the
Company's service territory are investigating the possibility of
acquiring less expensive sources of electricity by forming their
own utility operations. If successfully established as legitimate
wholesale entities, these new utilities would have open access to
transmission and would be able to by-pass the Company's generation
system. The municipalities exploring this possibility are
generally in the early stages of inquiry and represent a small
percentage of Company sales. Municipalization has the potential to
adversely affect the Company's customer base and profitability,
although rules proposed by the FERC, as discussed below, would
greatly mitigate any negative economic effects on the Company.
POWERCHOICE PROPOSAL
The PSC's 1995 rate order directed the Company and other
interested parties to address several key issues regarding long-
range rate proposals. These issues were to include: improving the
Company's competitive position by addressing uneconomic utility
generation and the high price of many UG contracts; eliminating, if
possible, the fuel adjustment clause and other billing mechanisms;
addressing property tax issues with local authorities; improving
operating efficiency; and identifying governmental mandates that
are no longer warranted in a competitive environment. No proposal
under this directive could create anti-competitive effects or lead
to a deterioration in safe and adequate service. The PSC also said
any multi-year plan should ensure that the Company has an
investment-grade bond rating (although the Company is currently
below investment grade), and include protection for low-income
customers. Finally, the PSC directed that the plan should propose
changes in the regulatory approach for the Company that support
fair competition in the electric generation market consistent with
the PSC's determination in its generic COPS, discussed below.
Following the PSC's directives, the parties engaged in a
collaborative process in which the Company has made a series of
presentations describing its views of the transition to competition
and the options it presents the Company.
On October 6, 1995, the Company filed its PowerChoice proposal
with the PSC. The proposal was offered as an integrated package
(although certain details are subject to modification) and included
these key elements:
* CREATION OF A COMPETITIVE WHOLESALE ELECTRICITY MARKET AND
DIRECT ACCESS BY RETAIL CUSTOMERS. To give customers their
choice of power suppliers and pricing terms, the Company will
open its system to competing electricity generators as early
as 1997. The timing of full implementation depends on
resolution of technical, administrative and regulatory issues.
Envisioned is the formation of a competitive wholesale spot
market in the Company's service area under the supervision of
the FERC that is consistent with proposals announced October
5, 1995 by the Energy Association of New York. Beginning in
1997 with its largest customers, the Company would allow full
direct access to alternative suppliers of electricity. The
Company would deliver that power over its transmission and
distribution system. Access for the remaining customers would
be phased in over the years 1997-2000.
* SEPARATION OF THE COMPANY'S POWER GENERATION BUSINESS. The
Company has initially proposed that one company would own and
operate its present power plants and any unregulated generator
contracts that are not restructured. All the Company's assets
and businesses other than generation would be held by a
holding company that would provide cost-based rate regulated
transmission, distribution and gas services through a
regulated subsidiary and through a second subsidiary would
provide competitive unregulated services, such as energy
marketing and other services. Both companies would be
financially restructured so that stockholders and other
constituencies would be treated in a fair and equitable
fashion. Any release of assets under the Company's mortgage
indenture would involve the substitution of other collateral
of equivalent value. The Company believes NYPA or New York
state can be helpful in this restructuring process, through
the purchasing or refinancing of the Company's nuclear plants
or through the use of other risk-mitigation strategies
associated with those facilities.
* RELIEF FROM OVERPRICED UNREGULATED GENERATOR CONTRACTS THAT
WERE MANDATED BY PUBLIC POLICY, ALONG WITH EQUITABLE WRITE-
DOWNS OF ABOVE-MARKET COMPANY ASSETS. As a result of state
and federal policy, the Company entered into over 220
contracts, of which there are over 150 remaining, to buy power
from UGs at above-market prices, even when the power is not
needed. The Company's payments to UGs have increased from
less than $200 million in 1990 to nearly $1 billion in 1995,
and will continue to grow by an average of approximately $60
million per year over the next five years as contract prices
increase. To create an open and competitive market and
achieve a price freeze, the Company has offered to negotiate
new contracts with UGs.
If negotiations fail, the Company has proposed to take
possession of these projects and compensate their owners
through the Company's power of eminent domain. The Company
would then resell the projects, allowing the projects to sell
electricity into the competitive pool at market prices. Some
of the costs related to the Company and UGs that would be
"stranded" or unrecoverable in a competitive market would be
written off (see discussion below). The remaining stranded
costs would be recovered through a contract with the
distribution company which, in turn, would recover these costs
through a generally non-bypassable fee tied to distribution
services.
* A PRICE FREEZE OR CUT FOR ALL CUSTOMER CLASSES. If the
proposal is agreed to by all necessary parties, the average
prices paid by residential and commercial class customers
could be frozen for five years. Prices for industrial
customers, who now subsidize other customers, would be
reduced.
The price freeze and restructuring of the Company's markets
and business envisioned in the PowerChoice proposal are contingent
on substantial cost reductions, which depend in turn on the
willingness of the UGs and the Company to absorb the losses
required to make substantial reductions in the Company's embedded
cost structure. The Company's PowerChoice proposal would reduce
its embedded cost structure through substantial write-downs if, and
only if, the UGs agree to cost reductions that are proportional to
their relative responsibility for strandable costs. The Company
proposes that reduction in its fixed costs of service be made by
mutual contribution of the Company's shareholders and UGs that are
in the same proportion as the contribution of each to the problem
of strandable costs, which the Company calculates to be $4 of UG
strandable cost for every $1 of Company strandable cost. Achieving
a five-year price freeze, as the Company proposes, would require
financial concessions of approximately $2 billion (in nominal
dollars) over five years, consisting of approximately $400 million
by the Company and $1.6 billion by the UGs. The Company has
proposed that the remaining strandable costs be recoverable by the
Company and the UGs through surcharges on rates for remaining
distribution and transmission services. To ensure full recovery of
these costs, the Company has proposed that the remaining strandable
costs be recovered in rates in a manner which minimizes the
Company's exposure due to sales volume variations. Recovery of
remaining strandable costs by the new owner of the Company's
generation facilities is intended to be structured so as not to
impede each unit from being an efficient participant in the
competitive generation market.
The Company is also pursuing other courses of action to
support the objectives of restructuring. The Company filed a
petition with the PSC in December 1995 seeking an order that
certain projects post firm security to ensure performance of their
obligations (see "Demand for Adequate Assurance"). The Company is
also actively pursuing various forms of tax relief (see "Tax
Initiatives"). The timely and successful implementation of
PowerChoice, including, most importantly, the restructuring of the
energy market and of UG contracts, will most likely occur only
through negotiations and with the full and active support of the
state. The Company is actively negotiating the PowerChoice
proposal with a broad range of interested parties. Separate
negotiations are also under way with the UGs and involve state
representatives. Alternatives to PowerChoice may be proposed
during negotiations that could, in the Company's view, be in the
best interests of shareholders, customers and bondholders. The
outcome of PowerChoice and the Company's other initiatives cannot
be assured and the possibility of restructuring under Chapter 11 of
the U.S. Bankruptcy Code cannot be ruled out.
Under PowerChoice, the successor to all the Company's assets
and businesses other than generation would be an unregulated
holding company that would provide cost-based rate regulated
transmission, distribution and gas services through one subsidiary
and would provide through a second subsidiary competitive
unregulated services, such as energy marketing and other services.
The Company believes the regulated subsidiary would continue to
account for its assets and costs, based on ratemaking conventions
as approved by the PSC and FERC, and in accordance with SFAS No.
71.
Effective for the year commencing January 1, 1996, this
accounting standard, under which the Company reports its financial
condition and results of operations, is amended by SFAS No. 121.
As discussed in Note 2 of Notes to Consolidated Financial
Statements, the Company believes there is no impairment of its
investment in generating plant assets under the provisions of SFAS
No. 121 under either the PowerChoice proposal or traditional cost-
based ratemaking.
As further discussed in Note 2 of Notes to Consolidated
Financial Statements, the Company believes that it continues to
meet the requirements for application of SFAS No. 71 and that its
regulatory assets are currently probable of recovery in future
rates charged to customers. However, the Company's PowerChoice
proposal described above (or a similar proposal) may require a
write off of the approximately $400 million of regulatory assets
related to generation. There are a number of events that could
change these conclusions in 1996 and beyond, which could result in
material adverse effects on the Company's financial condition and
results of operations.
MULTI-YEAR GAS RATE PROPOSAL. The Company also filed a
proposal to adopt a "performance-based regulation" mechanism,
including a gas cost incentive mechanism, for its gas operations.
The proposal provides for a complete unbundling of the Company's
sales service, allowing customers to choose alternative gas
suppliers. Increases for gas distribution services would be
subject to a price index through the year 2000. The price index,
which is based on inflation associated with gas service-related
costs, would be applied to existing 1995 prices after consideration
of the service restructuring. A gas cost incentive mechanism is
also being proposed, along with discontinuation of the weather
normalization clause. Flexibility in pursuing unregulated
opportunities related to the gas business is also being sought. In
November 1995, the Company filed for a 5.8% gas rate increase,
under traditional cost-based regulation, in the event negotiations
on the multi-year gas rate proposal are unsuccessful. If approved,
such rates would become effective on October 1, 1996. In either
case, the Company believes its gas operations will continue to be
cost-of-service rate regulated.
FEDERAL AND STATE REGULATORY INITIATIVES
FERC NOPR on Stranded Investment. In March 1995, the FERC
issued two NOPRs to facilitate the development of competitive
wholesale electric markets by opening up transmission services and
to address the transition costs, or "stranded costs," associated
with open transmission access. Stranded costs are utility costs
that may become unrecoverable due to a change in the regulatory
environment.
In a supplemental NOPR on stranded costs, the FERC has
established the principle that utilities are entitled to the full
recovery of "legitimate, prudent, and verifiable" stranded costs at
both the state and federal level. The NOPR also concludes that the
FERC should be the principal forum for addressing the recovery of
stranded costs due to potential municipalization or similar
situations where former retail customers become wholesale
customers, as well as for wholesale stranded costs. For stranded
costs that result from retail wheeling, the FERC proposes that
state regulatory authorities assume responsibility, except in the
narrow circumstance where state regulatory authorities lack the
authority to address the recovery of such costs.
The FERC continues to seek comments with respect to the
complex issues raised by power pools. The NYPP, of which the
Company is a member, is actively evaluating the effect of wholesale
competition and the NOPR on NYPP operations and pricing policies.
While changes to existing NYPP arrangements are expected, the
extent and nature of these changes and their possible effects on
the Company are uncertain.
The Company responded to the NOPR, both individually and as a
member of several utility groups, in support of the FERC's position
with respect to the recovery of stranded costs caused by wholesale
and retail wheeling, but has urged the FERC not to abdicate its
responsibility for retail stranded costs. It is anticipated that
a final rule will be issued in 1996. The Company cannot predict
the outcome of this matter or its effects on the Company's results
of operations or financial condition.
PSC COMPETITIVE OPPORTUNITIES PROCEEDING - ELECTRIC. In June
1994, the PSC instituted Phase II of COPS with the overall
objective "to identify regulatory and ratemaking practices that
will assist in the transition to a more competitive electric
industry designed to increase efficiency in the provision of
electricity while maintaining safety, environmental affordability,
and service quality goals." In a June 1995 order, the PSC adopted
principles to guide the transition to competition. The first
principle states that competition in the electric power industry
will further the economic and environmental well-being of New York
state. Other adopted principles address various issues, including:
safety and reliability, customer service, economic efficiency,
economic development and stranded costs. The June 1995 order
stated that utilities should have a reasonable opportunity to
recover prudent and verifiable expenditures and commitments made
pursuant to their legal obligations, consistent with all of the
principles. In addition, the June 1995 order encourages "respect"
for the reasonable expectations of UGs and confirms the need for
utilities and UGs to share responsibility for mitigating the costs
of transition to a more competitive market. Issues related to both
wholesale and retail competition are being examined in this
proceeding.
On October 25, 1995, the PSC staff filed a proposal in COPS to
restructure New York State's electric industry. Under the PSC
staff's proposal, which is similar in many respects to the
Company's PowerChoice proposal, utilities and UGs would share the
responsibility for reducing the current high electric system costs.
The PSC staff proposed that electric utilities would absorb a
portion of their current generation investments that might become
"stranded" or unrecoverable in a competitive market and that the
UGs would need to cooperatively restructure their high-cost power
contracts with utilities. In addition, the PSC staff's proposal
would allow customers to choose among competing energy suppliers,
beginning the transition to a competitive retail market by early
1998. A key element of the model for wholesale and retail
competition in the proposal is the separation of most generating
operations from transmission and distribution services. However,
it recommended that the electric delivery system, which includes
substations, power lines and a central power pool, continue to be
operated by regulated entities. The Company's PowerChoice proposal
includes the separation of generation from transmission and
distribution into distinct entities.
In December 1995, the ALJ issued a recommended decision in
COPS (ALJ plan), which is similar in many respects to the Company's
PowerChoice proposal. The ALJ plan includes a competitive model in
which an Independent System Operator (ISO) would oversee a spot
market of electricity supplied by generators competing in an open
market which would be functionally separated from other utility
functions. The ISO would dispatch generators selling into the spot
market and acquire services needed to maintain reliability.
The ALJ plan recommends that competition initially be limited
to the wholesale level, largely because of concerns about the
reliability of electricity supply. If wholesale competition works,
the state would extend competition to the retail level.
As with the PowerChoice proposal, transmission and
distribution would remain regulated. Consideration would be given,
during the wholesale phase, to the development of effective
competition among energy service companies.
In addition, the ALJ plan calls for a non-bypassable "wire
charge" to be imposed by distribution companies to help utilities
recover "strandable" costs. It advocates generic rules for
defining and measuring such costs, requirements for possible
reductions, a preferable recovery mechanism, and a standard for
recovery. The actual amount of stranded costs to be recovered by
each utility, and the timing of recovery, would be left to
individual rate cases, to begin in 1996 if the ALJ plan is given
final approval. The ALJ plan requires that strandable costs be
determined to be prudent, verifiable and incapable of being reduced
before recovery is allowed. The ALJ further suggests that a
careful balancing of customer and utility interests and
expectations is necessary, and the level of strandable cost
recovery may vary utility by utility.
The Company responded to the ALJ plan, as a member of the
Energy Association of New York State (Energy Association). The
Energy Association includes the Company and seven other investor
owned utilities as members. The Energy Association expressed
concern that the ALJ's plan might not allow utilities a reasonable
opportunity to fully recover strandable costs and noted the failure
of the plan to address and recommend lawful changes which would
make possible reductions in electric prices, both in the short and
long term.
After a comment period, the Commissioners will review the ALJ
plan and other plans submitted by interested parties, and
ultimately accept, modify or reject it. A decision is expected by
mid-1996.
ASSEMBLYMAN SILVER'S PROPOSED PLANS. New York State Assembly
Speaker Sheldon Silver introduced a plan on January 2, 1996, that
would freeze electric rates immediately and set a goal of cutting
them 25% through the introduction of competition among utilities.
Key components of the proposal include assurances that reliability,
quality and safety levels are maintained, the dislocation of
utility workers is minimized, no guarantee of stranded cost
recovery, a reduction in the costs of UGs and the continued
encouragement of environmental protection efforts. Utilities would
be required to divest generation by 2002. The Company is unable to
predict whether legislation will be introduced in support of this
plan, and if introduced and enacted, the effect, if any, on the
Company's financial condition and results of operations.
FERC ORDER 636 AND PSC COMPETITIVE OPPORTUNITIES PROCEEDING -
GAS. Portions of the natural gas industry have undergone
significant structural changes in recent years. 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 service from pipeline transportation
service. This has enabled the Company to arrange for its gas
supply directly with producers, gas marketers or pipelines, at its
discretion, as well as to arrange for transportation and gas
storage services. Such flexibility should allow the Company to
protect its existing market and to expand its core and non-core
market offerings. With these expanded opportunities come increased
competition from gas marketers and other utilities.
OTHER COMPANY EFFORTS TO ADDRESS COMPETITIVE CHALLENGES
UNREGULATED GENERATOR INITIATIVES are discussed in a separate
section below.
TAX INITIATIVES. The Company is working with utility and
state representatives to explain the negative impact that all
taxes, including the GRT, are having on rates and the state of the
economy. Governor Pataki and other state officials have identified
changes in the GRT as an element in improving the business climate
in New York. At the same time, the Company is contesting the high
real estate taxes it is assessed by many taxing authorities,
particularly compared to the taxes assessed on UGs.
As noted above, the Company has reduced its work force over
the past three years, resulting in a decrease in the amount of
payroll taxes incurred over that period. Meanwhile, the reduction
in revenues experienced by the Company resulting from reduced sales
and an increase in customer discounts, combined with a phase out of
the GRT surcharge, has caused the amount of GRT paid by the Company
to be reduced. The following table sets forth a summary of the
components of other taxes (exclusive of income taxes) incurred by
the Company in the years 1993 through 1995:
In millions of dollars
1995 1994 1993
- ------------------------------------------------------------
Property tax paid $264.8 $262.6 $246.7
Sales tax 20.1 17.5 19.7
Payroll tax 37.3 42.5 44.3
Gross Receipts tax 190.2 198.1 200.7
Other taxes 5.2 4.3 4.2
- ------------------------------------------------------------
Total tax payments 517.6 525.0 515.6
Charged to construction,
subsidiaries and regulatory
recognition (.1) (28.1) (24.2)
- ------------------------------------------------------------
Total Other Taxes $517.5 $496.9 $491.4
CUSTOMER DISCOUNTS. The Company is experiencing a loss of
industrial load across its system for a variety of reasons. In
some cases, customers have found alternative suppliers or are
generating their own power. In other cases a weakened economy or
attractive energy prices elsewhere have contributed to customer
decisions to relocate or close.
In addressing the threat of further loss of industrial load,
the PSC established guidelines to govern flexible electric rates
offered by utilities to retain qualified industrial customers.
Under these guidelines, the Company filed for a new service tariff
in August 1994, under which all new contract rates are administered
based on demonstrated industrial and commercial competitive pricing
situations including, but not limited to, on-site generation, fuel
switching, facility relocation and partial plant production
shifting. Contracts are for terms not to exceed seven years
without PSC approval.
The Company has granted discounts to a number of industrial
customers and expects others to seek discounts through negotiating
long-term contracts. Many of these contracts may result in
increased load that could be revenue enhancing. The Company also
offers economic development rates, which can result in discounts
for existing, as well as, new load. In 1995, the Company granted
approximately $62 million of discounts which exceeded by $20
million the approximately $42 million that were anticipated in
setting rates for 1995. As of January 3, 1996, electric commercial
and industrial customers have signed 67 discount agreements with an
average term of four years. In addition, the average discount
negotiated in 1995 was 21% below tariff prices. The Company
expects discounts to increase in 1996 to approximately $87 million,
80% of which the Company seeks to recover in its February 1996 rate
filing. As was the case in 1995, the Company would absorb the
impact of any discounts in excess of amounts reflected in rates.
The increase in the Company's prices over the past four years,
which is largely due to mandated purchases from UGs, has made
cogeneration and self-generation by many industrial and large
commercial customers more attractive. The Company believes the
pricing flexibility mentioned above was a necessary first step to
prevent erosion of its customer base. Price pressure in the longer
term, however, may limit the recovery of such costs from the
remainder of its customer base.
SITHE/ALCAN. In April 1994, the PSC ruled that, in the event
Sithe Independence Power Partners Inc. (Sithe) ultimately obtained
authority to sell electric power at retail, those retail sales
would be subject to a lower level of regulation than the PSC
presently imposes on the Company. Sithe, which sells electricity
to Consolidated Edison Company of New York, Inc. and to the Company
at wholesale from its 1,040 MW natural gas cogeneration plant, also
provides steam to Alcan Rolled Products (Alcan). As authorized by
the PSC in September 1994, Sithe also sells a portion of its
electricity output on a retail basis to Alcan, previously a
customer of the Company, and is authorized to sell to Liberty
Paperboard (Liberty), a potential new industrial customer. The PSC
ordered that Sithe pay the Company a fee over a period of ten
years, based upon the prices at which Sithe would sell to Alcan,
structured to produce a net present value of approximately $19.6
million. Beginning in 1995, the fee was approximately $3.05
million. The Company had argued for compensation, which would have
assured discounted rates to Alcan, with a net present value of $39
million. The PSC did not authorize a fee in connection with
Sithe's sale to Liberty.
A Company appeal in State Supreme Court, Albany County,
contending that the April 1994 PSC Order is a violation of legal
procedure and precedent and should be reversed, was dismissed in
February 1996. Although the Company's appeal of Sithe's ability to
sell to a retail customer and the level of compensation involved
was denied, the PSC's decision to require compensation to utilities
for costs that would otherwise be stranded has established a
precedent in by-pass situations for some level of recovery of the
Company's investment.
GENERATING ASSET MANAGEMENT STUDIES - The Company continues
as a matter of course to examine the economic and strategic issues
related to operation of all its generating units. As a result of
economic studies that the Company has performed (most recently in
1994), it has presently determined that it is economically
advantageous to continue operation of Nine Mile Point Nuclear
Station Unit No. 1 (Unit 1) over the remaining term of its license.
The Company also has, and continues to, study the economics of
continued operation of its fossil-fueled generating plants, given
current forecasts of excess capacity. Growth in UG supply sources,
compliance requirements of the Clean Air Act and low wholesale
market prices are key considerations in evaluating the Company's
internal generation needs. Due to projected excess capacity and
Clean Air Act requirements, a total of 340 MW's of aging coal fired
capacity is expected to be retired by the end of 1999 and 850 MW's
of oil fired capacity was placed in long-term cold standby in 1994.
These decisions will be revisited as facts and circumstances
change. These actions permit the reduction of operating costs and
capital expenditures for retired and standby plants. The remaining
investment in these plants of approximately $250 million at
December 31, 1995 (of which approximately $180 million relates to
the facility in cold standby) is currently being recovered in rates
through depreciation under traditional ratemaking; recovery would
also be provided under PowerChoice. (See Note 2 of Notes to
Consolidated Financial Statements).
These asset management studies have enabled the Company to
make significant reductions in capital spending, and with increased
output and lower operating costs, to improve the cost-efficiency of
the units which is important as the Company continues to examine
its competitive situation and future strategic direction.
REGULATORY AGREEMENTS/PROPOSALS
1995 RATE ORDER. (See Note 2 of Notes to the Consolidated
Financial Statements).
Through its Brief Opposing Exceptions dated March 2, 1995, the
Company requested an increase in 1995 electric revenues of
approximately $110 million (3.5%) and an increase in 1995 gas
revenues of $16.4 million (2.7%).
On April 21, 1995, the Company received a rate decision (1995
rate order) from the PSC which approved an approximately $47
million increase in electric revenues and a $4.9 million increase
in gas revenues, an expected bill increase of 1.1% for electric
customers (a 3.4% increase for residential and a 1.6% decrease for
large industrial) and an 0.8% increase for gas customers.
The 1995 rate order allows the Company to retain its FAC
mechanism, but NERAM, which permitted the Company to recover
revenue shortfalls during future periods, was discontinued (See
"RESULTS OF OPERATIONS").
The 1995 rate order includes performance-based penalties
related to customer service quality and demand-side management
programs. In December 1995, the Company estimated and recorded a
customer service penalty for 1995 of $4.8 million, or 2 cents per
share, since it did not maintain certain customer service goals at
1994 levels. The final amount of the penalty will be subject to
audit by the PSC.
PRIOR 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.
The 1991 Financial Recovery Agreement implemented NERAM and
the MERIT. (See Note 1 of Notes to the Consolidated Financial
Statements).
NERAM required the Company to reconcile actual results to the
forecasted electric public sales gross margin used in establishing
rates. NERAM was discontinued in 1995. Approximately $101.2
million of NERAM revenues were recorded in 1994 and $65.7 million
in 1993. Substantially all of the remaining balance of NERAM
revenues recorded of approximately $48.8 million will be collected
in 1996.
The MERIT program is an incentive mechanism. Overall goal
targets and criteria for the 1993-1995 MERIT periods were results-
oriented and intended to measure improvement in key performance
areas. The total possible awards are $34 million and $41 million
for 1994 and 1995, respectively. The Company has recognized
approximately $20.3 million, $20.8 million and $16.9 million of
MERIT revenues in 1993, 1994 and 1995, respectively. The recorded
1995 award represents the objectively determinable portion of the
anticipated earned award, with the balance to be recorded in 1996
when approved.
UNREGULATED GENERATORS
In recent years, the leading cause of higher customer bills
and the deterioration of the Company's competitive position has
been the requirement to buy power from UGs in excessive quantities
at an average price which is more than twice as high as the cost of
power that could be purchased in the wholesale market.
By the end of 1994, the Company had virtually all UG capacity
scheduled to come into service on line and selling power, which at
December 31, 1995, consisted of 151 facilities with a combined
capacity of 2,708 MW. Of these, 2,390 MW are considered firm
capacity. UG purchases were approximately $736 million in 1993,
$960 million in 1994 and $980 million in 1995. In the absence of
UG contract restructuring under PowerChoice or any similar
proposal, the Company estimates that purchase power payments to UGs
will continue to escalate at an average annual rate of about 6%
through the year 2000.
The Company has initiated a series of actions to deal with the
growth of supply and to realign its supply with demand, but cannot
predict the outcomes. These actions include mothballing and
retiring Company-owned generating facilities (See "Generating Asset
Management Studies") and buyouts of UG projects, as well as the
implementation of an aggressive wholesale marketing effort. Such
actions have succeeded in reducing installed capacity reserve
margins to normal planning levels. The Company is actively
pursuing other initiatives to reduce its UG costs. The Company
also filed its PowerChoice proposal with the PSC as part of its
multi-year electric rate proceeding (see "POWERCHOICE PROPOSAL") in
an attempt to address this problem.
FERC PROCEEDING. On January 11, 1995, in a case involving
Connecticut Light & Power (CL&P), FERC ruled that the Public
Utility Regulatory Policy Act (PURPA) forbids states from requiring
utilities to pay more than avoided cost to QFs for electric power.
However, FERC also said it would not invalidate any prior
contracts, but would apply its ruling prospectively or to contracts
that were subject to a pending challenge (instituted at the time of
signing) by a utility. On the same day, FERC ordered that an
ongoing challenge by the Company to the New York law requiring
utilities to pay QFs a minimum of six cents per Kwh for electric
power ("Six Cent Law") was moot in light of a 1992 amendment to
that law prohibiting future contracts that require utilities to pay
more than avoided costs. The latter proceeding began in 1987. In
April 1988, FERC had ruled in the Company's favor, finding that
states could not impose rates exceeding avoided cost for purchases
from QFs. FERC then stayed its decision in light of a rulemaking
it was instituting to address the issue. That rulemaking was never
completed.
On February 10, 1995, the Company filed a petition for
rehearing of both orders. The petition was denied. The Company
then asked U.S. Court of Appeals for the District of Columbia to
review FERC's denial. FERC and other parties moved to dismiss for
lack of jurisdiction. These motions remain pending. On May 11,
1995, the Company filed complaints in the U.S. District Court for
the Northern District of New York against the FERC and the PSC,
contending the FERC unlawfully ruled that its decision in CL&P does
not apply to purchases of power under existing agreements. The PSC
was named in this complaint on the basis that its policies required
the Company to enter into the above-market-value agreements. In
July 1995, various parties to these actions, including the FERC and
the PSC, moved to dismiss the case. The motions remain pending.
CURTAILMENT PROCEDURES. On August 18, 1992, the Company filed
a petition with the PSC calling for the implementation of
"curtailment procedures." Under existing FERC and PSC policy, this
petition would allow the Company to limit its purchases from UGs
during light load periods as contemplated in FERC regulations.
Also, the Company has negotiated settlements with certain UGs
regarding curtailment provisions of power purchase agreements. On
April 5, 1994, after informing the PSC of its progress, or lack
thereof, in settlement discussions, the Company asked the PSC to
expedite its review of the petition. The Company cannot predict
the outcome of this action.
DEMAND FOR ADEQUATE ASSURANCE. On February 4, 1994, the
Company notified the owners of nine projects of the Company's
demand for adequate assurance that the owners will fulfill all
future obligations, including the obligation to deliver electricity
at prices below the Company's avoided cost. These nine projects
have contracts that provide for initial purchase of power by the
Company at rates above avoided cost.
The projects at issue total 429 MW. The Company's demand is
based on its assessment of the amount of payments above avoided
cost to be accumulated under the terms of the contracts. The
Company believes it needs adequate assurance because the projects'
future obligations to deliver electricity at prices below avoided
costs to offset these accumulated account balances would involve
operating losses that would cause the owners to abandon the
projects. The Company has been sued in three separate actions by
the owners of six UG projects which challenge the Company's right
to demand adequate assurance. Court decisions in February 1996 in
two of these actions found that the Company does not have the legal
right to demand adequate assurance. The Company intends to appeal
these decisions.
In December 1995, the Company filed a petition with the PSC
seeking an order that eight UGs post firm security to ensure
performance of their obligations and thereby, protect customers'
interests under UG contracts. Alternatively, the Company asked
that the PSC should cancel these contracts if such security is not
provided. The Company estimates that the above-market payments to
these eight UGs, which will amount to more than $100 million in
1996, will grow to approximately $3.3 billion on a cumulative basis
in a little more than a decade.
The Company cannot predict the outcome of its petition or of
the legal actions regarding adequate assurance but because the
Company and its customers continue to bear the substantial burden
these contracts impose, the Company will continue to press for
adequate assurance that the owners of these projects will honor
their obligations.
RESULTS OF OPERATIONS
Earnings for 1995 were $208.4 million, or $1.44 per share, as
compared to $143.3 million, or $1.00 per share, in 1994, and
$240.0 million, or $1.71 per share, in 1993. 1994 earnings
included $101.2 million, or 46 cents per share, of electric margin
recorded under NERAM, but were adversely affected by the charge to
earnings of approximately $197 million (89 cents per share) for
nearly all of the cost of the VERP. The VERP was initiated in 1994
to bring the Company's staff levels and work practices into line
with peer utilities and to create a more competitive cost
structure. Since January 1, 1993, the Company has reduced its
employment by approximately 3,200, or 27%, as of December 31, 1995.
About 70% of the Company's work force is subject to a collective
bargaining agreement with the International Brotherhood of
Electrical Workers. This thirty-three month agreement expired
February 29, 1996, and is currently in negotiation.
1995 earnings were hurt by lower sales quantities of
electricity and natural gas, as compared with amounts used to
establish 1995 prices. Sales were primarily affected by the
continuing weak economic conditions in upstate New York, loss of
industrial customers' load to NYPA and discounts granted. In
January 1995 NERAM was discontinued. The Company's 1995 earned
return on common equity was 8.4%, compared to 5.8% (10.7% without
the VERP charge) in 1994 and 10.2% in 1993. The Company's return
on common equity authorized in the rate setting process for the
year ended December 31, 1995, provided an electric return on equity
of 11.0% and a return on equity for gas of 11.4%. Factors
contributing to earnings below authorized levels in 1995 included,
among other things: sales below those forecasted in determining
rates; about $20 million more in customer discounts than those
reflected in rates; the inability to achieve stringent wholesale
margin targets set by the PSC; and fuel target penalties for low
hydro production caused by dry weather. The Company expects the
trend of weak sales to continue, given weak economic conditions in
the Company's service territory.
The following discussion and analysis highlights items that
significantly affected operations during the three-year period
ended December 31, 1995. This discussion and analysis 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 decreased by $193.4 million, or 5.5%, in
1995, and increased by $196.5 million, or 5.9%, in 1994.
As shown in the following table, electric operating revenues
decreased in 1995 primarily due to the elimination of NERAM after
1994, and the decrease in sales to other electric systems and in
sales to ultimate consumers. In addition, FAC revenues decreased
$86.4 million, in part due to a decrease in fuel and purchased
power costs that are recoverable through the FAC as compared to
1994. Despite a decrease in fuel costs, the Company absorbed a
loss of approximately $11.8 million in 1995, since its actual costs
in 1995 were higher than the amounts forecasted in rates. In 1994,
the Company retained a maximum benefit of $15 million, since its
actual costs were lower than the amounts forecasted in rates. The
amount forecasted in rates in 1995 reflected a lower fuel cost than
1994. The decrease in FAC revenues also reflects a higher amount
of transmission revenues ($21.6 million) passed on to customers.
These decreases were partially offset by higher electric rates that
took effect April 26, 1995, and by the recording of $71.5 million
unbilled, non-cash revenues in 1995 in accordance with the 1995
rate order. The increase in DSM revenues relates to a one-time,
non-cash adjustment of prior years' DSM incentives, partially
offset by a reduction in the DSM rebate cost program.
The $196.5 million, or 5.9%, increase in electric operating
revenues in 1994 was primarily due to higher recoveries through the
operation of the FAC mechanism, increased sales to other electric
systems, NERAM revenues and rate increases (mainly reflecting the
pass through of increases in mandated purchases of UG power and
rising taxes).
INCREASE (DECREASE) FROM PRIOR YEAR
(In millions of dollars)
ELECTRIC REVENUES 1995 1994 1993 TOTAL
- -----------------------------------------------------------------
Amortization of unbilled
revenues $ 71.5 $ - $ - $ 71.5
Increase in base rates 68.2 36.0 193.1 297.3
Fuel adjustment clause
revenues (86.4) 108.3 (42.6) (20.7)
Changes in volume and mix
of sales to ultimate
consumers (57.5) (13.6) 11.0 (60.1)
Sales to other electric
systems (71.3) 62.1 11.7 2.5
DSM revenue 1.4 (27.7) (30.3) (56.6)
Miscellaneous operating
revenues (18.1) (4.1) 17.9 (4.3)
NERAM revenues (101.2) 35.5 24.0 (41.7)
------- ------ ------ ------
$(193.4) $196.5 $184.8 $187.9
======== ====== ====== ======
Changes in FAC revenues are generally margin-neutral (subject
to an incentive mechanism discussed in Note 1 of Notes to
Consolidated Financial Statements), while sales to other utilities,
because of regulatory sharing mechanisms and relatively low prices,
generally result in low margin contributions 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.
ELECTRIC KILOWATT-HOUR SALES were 37.7 billion in both years
1995 and 1993, and 41.6 billion in 1994. The 1995 decrease of 3.9
billion kilowatt-hours (Kwh), or 9.4% as compared to 1994, reflects
a 41.3% decrease in sales to other electric systems and a 2.3%
decrease in sales to ultimate consumers. The decline reflects
reduced demand due to the continued stagnant economy, loss of
several large industrial customers due primarily to relocations and
closings, loss of Alcan to Sithe, loss of sales to NYPA, and more
competitive pricing caused by excess supply. The 1994 increase
reflected increased sales to other electric systems, while sales to
ultimate consumers were generally flat. (See Electric and Gas
Statistics - Electric Sales). The lost electric margin effect of
sales in 1994 was adjusted by NERAM except for the large industrial
customer class, within which the Company absorbed 20% of the
variance from the NERAM sales forecast. This adjustment was not
made in 1995, since NERAM was discontinued. Industrial-Special
sales are NYPA allocations of low-cost power to specified
customers, from which the Company earns a transportation charge.
While these sales decreased slightly in 1995 as compared to 1994,
usage as a percentage of capacity increased resulting in an
increase in revenues.
Details of the changes in electric revenues and kilowatt-hour sales by customer group
are highlighted in the table below:
% INCREASE (DECREASE) FROM PRIOR YEARS
1995 % OF ------------------------------------------------------------
ELECTRIC 1995 1994 1993
CLASS OF SERVICE REVENUES REVENUES SALES REVENUES SALES REVENUES SALES
- ------------------------------------------------------------------------------------------
Residential 36.6% (1.0)% (2.5)% 5.2% (0.6)% 6.9% 0.8%
Commercial 37.2 (2.4) (1.1) 2.5 (2.2) 7.0 3.9
Industrial 15.8 (8.7) (4.3) 4.3 5.0 (6.0) (5.2)
Industrial-Special 1.7 14.3 (1.6) 14.5 5.9 9.1 0.8
Municipal service 1.5 (0.9) - (1.3) (2.3) 0.6 (3.1)
- ------------------------------------------------------------------------------------------
Total to ultimate
consumers 92.8 (2.7) (2.3) 3.9 0.8 4.3 0.5
Other electric
systems 2.9 (42.7) (41.3) 59.1 91.1 12.6 31.2
Miscellaneous 4.3 (19.9) - 8.2 - 40.6 -
- ------------------------------------------------------------------------------------------
TOTAL 100.0% (5.5)% (9.4)% 5.9% 10.3% 5.9% 3.0%
As indicated in the table below, internal generation from
fossil-fuel sources declined in 1995, principally at the Oswego
oil-fired facility. The decrease in fuel costs reflects a decrease
in Company generation due to reduced demand, which reduced the need
to operate the fossil plants, even after taking into account the
1995 Unit 1 and Unit 2 scheduled refueling and maintenance outages.
Quantities purchased from UGs decreased in 1995, due in part to the
low water supply which limited the amount of power the
hydroelectric UGs could produce. Although GwHrs decreased, total
costs escalated due to renegotiated contracts that required
payments to be made to the UGs for schedulable capacity. See Note
9 of Notes to the Consolidated Financial Statements - "Contracts
for the Purchase of Electric Power."
1995 1994 1993
--------------- ---------------- ----------------
(In millions of dollars)
Fuel for electric
generation: GwHrs. Cost GwHrs. Cost GwHrs. Cost
------ ---- ------ ---- ------ ----
Coal 6,841 $ 97.9 6,783 $ 107.3 7,088 $ 113.0
Oil 537 21.3 1,245 40.9 2,177 74.2
Natural gas 996 20.2 700 16.1 548 12.5
Nuclear 7,272 43.3 8,327 49.5 7,303 43.3
Hydro 2,971 - 3,485 - 3,530 -
------- ------ ------ ------- ------ --------
18,617 182.7 20,540 213.8 20,646 243.0
------- ------ ------ ------- ------ --------
Electricity
purchased:
Unregulated
generators:
Capacity - 181.2 - 84.6 - 20.3
Energy and taxes 14,023 798.7 14,794 875.5 11,720 715.4
------ ----- ------ ----- ------ -------
Total UG purchases 14,023 979.9 14,794 960.1 11,720 735.7
Other 9,463 126.5 10,382 140.3 9,046 118.1
------ ------- ------ ------- ------ -------
23,486 1,106.4 25,176 1,100.4 20,766 853.8
------ ------- ------ ------- ------ -------
Total generated
and purchased 42,103 1,289.1 45,716 1,314.2 41,412 1,096.8
Fuel adjustment
clause - 14.8 - 12.7 - (2.2)
Losses/Company use 4,419 - 4,117 - 3,688 -
------ ------- ------ -------- ------ ---------
37,684 $1,303.9 41,599 $1,326.9 37,724 $1,094.6
====== ======= ====== ======== ====== =========
% Change from Prior Year
-------------------------------------
1995 to 1994 1994 to 1993
------------- -------------
(In millions of dollars)
Fuel for electric
generation: GwHrs. Cost GwHrs. Cost
------ ---- ------ ----
Coal 0.9% (8.8)% (4.3)% (5.0)%
Oil (56.9) (47.9) (42.8) (44.9)
Natural gas 42.3 25.5 27.7 28.8
Nuclear (12.7) (12.5) 14.0 14.3
Hydro (14.7) - (1.3) -
------ ------ ------ ------
(9.4) (14.5) (0.5) (12.0)
------ ------ ------ ------
Electricity
purchased:
Unregulated
generators:
Capacity - 114.2 - 316.7
Energy and taxes (5.2) (8.8) 26.2 22.4
----- ----- ---- -----
Total UG purchases (5.2) 2.1 26.2 30.5
Other (8.9) (9.8) 14.8 18.8
----- ----- ---- -----
(6.7) 0.5 21.2 28.9
------ ------ ---- -----
Total generated
and purchased (7.9) (1.9) 10.4 19.8
Fuel adjustment
clause - 16.5 - (677.3)
Losses/Company use 7.3 - 11.6 -
---- ---- ----- -------
(9.4)% (1.7)% 10.3% 21.2%
====== ====== ====== =======
GAS REVENUES decreased by $41.4 million, or 6.6%, in 1995, and
increased by $22.2 million, or 3.7%, in 1994. As shown by the
table below, gas revenues decreased in 1995 primarily due to
decreased sales to ultimate customers, which reflects reduced
demand due to the weak economy and warmer weather, and lower gas
adjustment clause recoveries. This decrease was partially offset
by an increase in revenues from the transportation of customer-
owned gas of approximately $9.9 million which was primarily caused
by the Sithe gas-fired generating project coming on-line in the
Company's service territory and an increase in base rates of $4.7
million in accordance with the 1995 rate order. Rates for
transported gas yield lower margins than gas sold directly by the
Company. Therefore, increases in the volume of gas transportation
services have not had a proportionate impact on earnings. In
addition, changes in purchased gas adjustment clause revenues are
generally margin-neutral.
In 1994, the revenue increase was primarily attributable to
increased sales to ultimate customers, increased base rates, and
gas adjustment clause recoveries. This increase was partially
offset by a decline in spot market sales, because the abundance and
price of spot gas made it more difficult to earn sufficient margins
on these sales. Spot market sales are generally the higher priced
gas available and sold in the wholesale market and yield margins
substantially lower than traditional sales to ultimate customers.
INCREASE (DECREASE) FROM PRIOR YEAR
(In millions of dollars)
GAS REVENUES 1995 1994 1993 TOTAL
- -----------------------------------------------------------------
Increase in base rates $ 4.7 $ 7.1 $ 7.3 $ 19.1
Transportation of
customer-owned gas 9.9 3.5 (9.7) 3.7
Purchased gas adjustment
clause revenues (10.7) 7.7 12.2 9.2
Spot market sales (1.3) (25.4) 27.2 0.5
Miscellaneous operating
revenues (3.5) 6.3 (5.0) (2.2)
Changes in volume and
mix of sales to ultimate
consumers (40.5) 23.0 15.1 (2.4)
------- ------ ------ ------
$(41.4) $ 22.2 $ 47.1 $ 27.9
======= ====== ====== =======
GAS SALES, excluding transportation of customer-owned gas and
spot market sales, were 78.5 million dth in 1995, an 8.3% decrease
from 1994 and a 5.7% decrease from 1993 (See Electric and Gas
Statistics - Gas Sales). The decrease in 1995 was in all ultimate
consumer classes, which reflects the continuing weak economic
conditions in upstate New York. The Company has added
approximately 25,000 new customers since 1992, primarily in the
residential class, an increase of 5.1%, and expects a continued
increase in new customers in 1996 at levels slightly lower than
previous levels. During 1995, there was also a shift from the
industrial sales class to the transportation sales class.
Even though gas sales and revenues decreased in 1995,
corresponding reductions in purchased gas expense enabled a slight
improvement in margin on gas sales.
In 1995, the Company transported 144.6 million dth, or 68.3%
increase, for customers purchasing gas directly from producers. A
continued increase in transportation volumes is expected in 1996,
leading to a forecast increase in total gas transported in 1996 of
approximately 8% above 1995. Factors affecting this forecast
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. Changes in gas revenues and dth sales
by customer group are detailed in the table below:
% INCREASE (DECREASE) FROM PRIOR YEARS
1995 % OF -----------------------------------------------------------
GAS 1995 1994 1993
CLASS OF SERVICE REVENUES REVENUES SALES REVENUES SALES REVENUES SALES
- ------------------------------------------------------------------------------------------
Residential 63.3% (7.5)% (8.2)% 7.5% 2.9% 4.6% 1.8%
Commercial 24.7 (9.7) (7.6) 9.9 8.6 9.2 6.5
Industrial 2.0 (21.0) (14.1) (21.0) (28.2) 84.8 143.6
- ------------------------------------------------------------------------------------------
Total to ultimate
consumers 90.0 (8.5) (8.3) 7.1 2.9 7.4 6.4
Other gas
systems 0.1 (34.3) (34.0) 8.7 4.3 (77.5) (80.3)
Transportation of
customer-owned
gas 8.3 25.9 68.3 10.1 26.8 (18.5) 2.9
Spot market sales 0.5 (29.2) 9.6 (85.3) (88.1) 1,056.1 1,053.8
Miscellaneous 1.1 (16.7) - 423.3 - (79.4) -
- ------------------------------------------------------------------------------------------
TOTAL 100.0% (6.6)% 29.9% 3.7% 5.4% 8.5% 12.3%
==========================================================================================
The total cost of gas purchased decreased 12.5% in 1995 and
3.2% in 1994, and increased 13.6% in 1993. The cost fluctuations
generally correspond to sales volume changes, particularly in 1993,
as spot market sales activity increased. The Company sold 1.7, 1.6
and 13.2 million dth on the spot market in 1995, 1994 and 1993,
respectively. In 1993, this activity accounted for two-thirds of
the 1993 purchased gas expense increase. The purchased gas cost
decrease associated with purchases for ultimate consumers in 1995
resulted from a 4.3 million decrease in dth purchased and withdrawn
from storage for ultimate consumer sales ($15.1 million) and a
10.8% decrease in the average cost per dth purchased ($32.8
million). This was partially offset by an increase of $10.1
million in purchased gas costs and certain other items recognized
and recovered through the purchased GAC. Gas purchased for spot
market sales decreased $1.4 million and $24.4 million in 1995 and
1994, respectively. The purchased gas cost increase associated
with purchases for ultimate consumers in 1994 resulted from a 1.5%
increase in dth purchased, coupled with a .9% increase in rates
charged by suppliers and an increase of $6.4 million in purchased
gas costs and certain other items recognized and recovered through
the purchased GAC. The Company's net cost per dth sold, as charged
to expense and excluding spot market purchases, decreased to $3.17
in 1995 from $3.44 in 1994 and was $3.34 in 1993.
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 FAC provides for a
partial pass-through of fuel and purchased power cost fluctuations
from those forecast in rate proceedings, with the Company absorbing
a portion of increases or retaining a portion of decreases to a
maximum of $15 million per rate year. While the amount absorbed in
1993 was not material, the Company retained the maximum benefit of
$15 million in 1994 and absorbed a loss of approximately $11.8
million in 1995.
Other operation expense decreased in 1995 by $139.8 million,
or 18.5%, as compared to a decrease of $66.6 million, or 8.1% in
1994. Despite the costs related to the 1995 scheduled nuclear
refueling outages of Units 1 and 2 of approximately $36 million,
other operation expense decreased in 1995 primarily as a result of
the Company's cost reduction program. In addition to lower labor
costs, the Company also reduced 1995 non-labor costs, such as
research and development expenditures ($21 million), general office
expenses ($8 million), and DSM rebate costs ($19 million). The
1994 decrease relates primarily to decreases in nuclear costs
associated with the Unit 1 and Unit 2 refueling and maintenance
outages in 1993 ($27 million) and the decrease in amortization of
regulatory deferrals ($49 million) which expired in 1993.
Other items, net decreased by $13.0 million in 1995 and
increased by $8.0 million in 1994. The 1995 decrease was primarily
due to the recognition of customer service penalties, certain other
items disallowed in rates and lower subsidiary earnings, offset in
part by the gain recognized on the sale of HYDRA-CO Enterprises,
Inc. (HYDRA-CO). The 1994 increase primarily related to increased
earnings of subsidiaries which included a nonrecurring gain on the
sale of an investment for $9 million.
Net Federal and foreign income taxes increased in 1995 by
approximately $47.9 million due to an increase in pre-tax income,
which included the increase related to the sale of HYDRA-CO. In
1994, the decrease of approximately $35.6 million was due to lower
pre-tax income, which included a charge to earnings of
approximately $197 million in 1994 for nearly all of the costs of
VERP. The increase in other taxes increased in 1995 primarily as
a result of an increase in the amortization of amounts deferred in
prior years ($19.7 million) related to real estate taxes. This
increase was partially offset by a reduction of approximately $7.9
million in gross receipts taxes as a result of lower revenues in
1995 as compared to 1994, and a reduction in the gross receipts tax
surcharge during 1995, as well as, a reduction in payroll taxes
($5.2 million) due to a decrease in employees. In 1994, the
increase was principally due to an increase in real estate taxes
($15.9 million).
Net interest charges remained fairly constant for the years
1993 through 1995. However, dividends on preferred stock increased
during this time by $1.8 million and $5.9 million in 1994 and 1995,
respectively. Dividends on preferred stock increased $5.9 million
in 1995 primarily as a result of an increase in the cost of
variable rate issues and increased $1.8 million in 1994 due to the
issuance of $150 million of preferred stock issued in August 1994.
The weighted average long-term debt interest rate and preferred
dividend rate paid, reflecting the actual cost of variable rate
issues, changed to 7.77% and 7.19%, respectively, in 1995 from
7.79% and 6.84%, respectively, in 1994, and from 7.97% and 6.70%,
respectively, in 1993.
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 than now. 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 non-nuclear 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 with identical assets due to technological advances and
competitive and regulatory changes that have occurred. In light of
these considerations, the depreciation charges in operating
expenses do not reflect the cost of providing service if new
generating facilities were installed. The Company will seek
additional revenue or reallocate resources, if possible, 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, 1995 was 54.5%
long-term debt, 8.0% preferred stock and 37.5% common equity, as
compared to 52.9%, 8.5% and 38.6%, respectively, at December 31,
1994. Book value of the common stock was $17.42 per share at
December 31, 1995, as compared to $17.06 per share at December 31,
1994. Market analysts have observed that the Company's low market
to book ratio, 54.5% at December 31, 1995, results from a weak New
York State economy and regulatory attitudes, and from uncertainty
about the pace of regulatory change, which could increase
competition and reduce prices, rendering the Company particularly
vulnerable. In addition, market analysts have expressed concern
about the uncertainty and potential negative impact of the
PowerChoice proposal on the Company, as well as the possibility of
bankruptcy. As indicated elsewhere, the Company believes the
PowerChoice proposal is in the best interests of shareholders,
bondholders and customers. However, the Company is committed to
taking necessary courses of action to improve its financial
profile, including consideration of other alternatives to
PowerChoice that may represent better value to these
constituencies.
The 1995 ratio of earnings to fixed charges was 2.29 times.
The ratios of earnings to fixed charges for 1994 and 1993 were 1.91
times and 2.31 times, respectively. Security rating firms 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 UG contracts. The
rating firms believe the financial structure of the UGs (which
typically have very high debt-to-equity ratios) and the character
of their power-purchase agreements increase the financial risk to
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 existing
commitments for UG purchases, the imputation has had, and will
continue to have, a materially negative impact on the Company's
financial ratings. Management expects that the reduced commitments
for UG purchases, as proposed in PowerChoice, would reduce the
inclusion of the "coverage factor" for UG contracts and reduce the
financial risk of the Company.
COMMON STOCK DIVIDEND
On January 25, 1996, the board of directors omitted the common
stock dividend for the first quarter of 1996. This action was
taken to help stabilize the Company's financial condition and
provide flexibility as the Company addresses growing pressure from
mandated power purchases and weaker sales. In making future
dividend decisions, the board will evaluate, along with standard
business considerations, the level and timing of future rate
relief, the progress of renegotiating contracts with UGs within the
context of its PowerChoice proposal, the degree of competitive
pressure on its prices, and other strategic considerations.
CONSTRUCTION AND OTHER CAPITAL REQUIREMENTS
The Company's total capital requirements consist of amounts
for the Company's construction program, compliance with the Clean
Air Act and other environmental requirements (as discussed below
and in Note 9 of Notes to the Consolidated Financial Statements -
"Environmental Contingencies"), nuclear decommissioning funding
requirements (See Note 3 of Notes to the Consolidated Financial
Statements - "Nuclear Plant Decommissioning"), working capital
needs, maturing debt issues and sinking fund provisions on
preferred stock, as well as requirements to accomplish
restructuring contemplated by the PowerChoice proposal. Annual
expenditures for the years 1993 to 1995 for construction and
nuclear fuel, including related allowance for funds used during
construction (AFC) and overheads capitalized, were $519.6 million,
$490.1 million and $345.8 million, respectively, and are expected
to be approximately $347 million for 1996 and to range between $307
million - $372 million for each of the subsequent four years.
Mandatory debt and preferred stock retirements and other
requirements are expected to add approximately another $70 million
to the 1996 estimate of capital requirements and significant
additional capital may be required if the NYSERDA bonds discussed
below need to be refinanced. The estimate of construction
additions included in capital requirements for the period 1996 to
2000 will be reviewed by management during 1996 with the objective
of further reducing these amounts where possible. See discussion
in "LIQUIDITY AND CAPITAL RESOURCES" section below, which describes
how management intends to meet its financing needs for this five-
year period.
The provisions of the 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 has complied with Phase I of
the Clean Air Act, which includes reductions of nitrogen oxides and
sulfur dioxide. Phase I became effective on January 1, 1995 and
will continue through 1999. The Company spent approximately $5
million and $32 million in 1995 and 1994, respectively, on projects
at the fossil generation plants associated with Phase I compliance.
The Company has included $15 million in its 1996 through 1999
construction forecast for Phase II compliance which will become
effective January 1, 2000. The Company anticipates that additional
expenditures of approximately $74 million may be necessary for
Phase III to be incurred beyond 2000. The asset management
studies, described above, consider spending estimates for Clean Air
Act compliance.
LIQUIDITY AND CAPITAL RESOURCES
Following the PowerChoice proposal, S&P lowered its ratings on
the Company's senior secured debt to BB from BBB-, senior unsecured
debt to B+ from BB+, preferred stock to B from BB+, and commercial
paper to B from A-3. The present ratings are "below investment
grade." In addition, S&P's ratings of the Company's securities are
on "CreditWatch" with negative implications. The downgrade of the
Company's security ratings reflects S&P's stated concern regarding
the uncertainty and potential negative impact of the PowerChoice
proposal on the Company. Further, S&P stated that the ultimate
possibility of restructuring under Chapter 11 of the U.S.
Bankruptcy Code cannot be ruled out, based on the Company's
statements in that regard. In December 1995, S&P assigned a
private placement rating of "2-plus" to the Company's first
mortgage bonds. Private placement ratings evaluate the extent of
potential loss to an investor following default, whereas S&P's
traditional debt ratings measure the risk of default in timely
payment. S&P stated the rating (based on a scale of one to six,
with "1-plus" the most favorable) "reflects the strong asset
protection and recovery value and low likelihood that first
mortgage bondholders would suffer any ultimate loss, even in the
event of a default by the issuer."
Moody's lowered its ratings below investment grade for the
Company's senior secured debt, to Ba1 from Baa3; senior unsecured
debt to Ba2 from Ba1; its preferred stock to ba3 from ba1; and its
short-term rating for commercial paper to Not Prime from Prime -3.
Moody's is also maintaining these ratings under review for possible
further downgrade. Moody's cited the necessity for agreement by
third parties significantly diminishes the likelihood that the
PowerChoice proposal will survive intact and increases uncertainty
about the Company's future over the interim period, as related
negotiations proceed. Moody's further stated that the Company's
apparent willingness to consider restructuring under Chapter 11 of
the U.S. Bankruptcy Code raises serious doubts as to the Company's
financial stability. Moody's stated that its continued review will
consider responses to the PowerChoice proposal, the likelihood of
the proposal being adopted and the effect any interim or final
agreement may have on bondholders.
Fitch also downgraded below investment grade the Company's
first mortgage bonds and secured pollution control bonds rating
from BBB to BB and its preferred stock rating from BBB- to B+ and
noted a declining credit trend. Fitch's stated concerns are
similar to those expressed by S&P and Moody's.
A summary of the Company's securities ratings at December 31,
1995, was:
- ----------------------------------------------------------------
SECURED PREFERRED COMMERCIAL UNSECURED
DEBT STOCK PAPER DEBT
- ----------------------------------------------------------------
Standard & Poor's
Corporation BB B B B+
Moody's Investors
Service Ba1 ba3 Not Prime Ba2
Fitch Investors
Service BB B+ Not Not
applicable applicable
- ----------------------------------------------------------------
These rating agencies have cited the increased risk and
uncertainty and the potential for bankruptcy as reasons for
downgrade. The Company believes these reasons likewise increase
the risk to third party UGs and their security ratings. The
Company believes its PowerChoice proposal is in the best interests
of its stockholders, customers and bondholders. In the event
PowerChoice is not adopted, and comparable solutions are not
available, the Company will undertake any other actions necessary
to act in the best interests of stockholders and other
constituencies. To that end, on February 12, 1996, the Company
filed for rate relief for 1996 and 1997 and the Company has
implemented a reduction of non-essential programs to reduce its
costs. (See "CHANGING COMPETITIVE ENVIRONMENT," "POWERCHOICE
PROPOSAL" and "COMMON STOCK DIVIDEND").
Cash flows to meet the Company's requirements for operating,
investing and financing activities during the past three years are
reported in the Consolidated Statements of Cash Flows.
During 1995, the Company raised approximately $346 million
from external sources, consisting of $275 million of 7-3/4% First
Mortgage Bonds due May 2006 issued during May 1995 and an increase
of $71 million issued under the Company's Revolving Credit
Agreement.
The Company received approximately $207 million in January
1995, related to the sale of the Company's subsidiary, HYDRA-CO,
the proceeds of which were used to repay short-term debt. The
after-tax gain on the sale of HYDRA-CO was approximately $11.3
million. In addition, the Company received $50 million from the
sale of customer receivables in the fourth quarter of 1995. (See
Note 9 of Notes to the Consolidated Financial Statements - "Sale of
Customer Receivables").
Ordinarily, construction related short-term borrowings are
refunded with long-term securities on a periodic basis. This
approach generally results in the Company showing a working capital
deficit. Working capital deficits may also be a result of the
seasonal nature of the Company's operations as well as timing
differences between the collection of customer receivables and the
payment of fuel and purchased power costs. Recently the Company
has experienced a deterioration in its collections as compared to
prior years' experience and is taking steps to improve collection.
The Company believes it has sufficient borrowing capacity to fund
such deficits as necessary in the near term. The Company's
existing revolving credit facility, which the Company is in the
process of renegotiating as described below, expires in April 1997.
The Company's capital structure continues to be weak, and the
Company's ability to issue more common stock to improve its capital
structure is essentially precluded by the uncertainties that have
depressed its stock price. The Company is unlikely to pursue a new
issue offering unless the common stock price is closer to book
value and these uncertainties are mitigated. The reduction to
below investment grade ratings on the Company's bonds and preferred
stock can be expected to make it more difficult and expensive for
the Company to finance in the manner it has used in the past.
External financing plans are subject to periodic revision as
underlying assumptions are changed to reflect developments, market
conditions and, most importantly, the Company's rate proceedings.
The ultimate level of financing during the period 1996 through 1999
will reflect, among other things: the outcome of the 1996 and 1997
rate requests; the outcome of the restructuring envisioned in the
PowerChoice proposal, including whether the Company proceeds with
exercising its right of eminent domain with respect to UG
contracts; levels of common dividend payments, if any, and
preferred dividend payments; the Company's competitive position and
the extent to which competition penetrates the Company's markets;
uncertain energy demand due to the weather and economic conditions;
and the extent to which the Company reduces non-essential programs
and manages its cash flow during this period. In the longer term,
in the absence of PowerChoice or some reasonably equivalent
solution, financing will depend on the amount of rate relief that
may be granted.
The Company is renegotiating its bank credit facilities to
insure, to the extent possible, adequate financial resources to
satisfy its financing needs over the period 1996 through June 1999.
These facilities by their terms would terminate upon adoption of
PowerChoice.
As a result of the Company's ongoing negotiations with its
banks, the Company entered into a commitment letter with Citibank,
N.A., Morgan Guaranty Trust Company of New York and Toronto
Dominion Bank, as co-syndication agents (the Agent Banks), for the
provision of a senior debt facility totaling $815 million for the
purpose of consolidating and refinancing certain of the Company's
existing credit agreements and letter of credit facilities and
providing additional reserves of bank credit. The proposed senior
debt facility will consist of a $380 million term loan and
revolving credit facility and a $435 million letter of credit
facility. The letter of credit facility will provide credit
support for $414 million of outstanding pollution control revenue
bonds issued through NYSERDA whose current letter of credit support
expires between April 1996 and January 1997. In the absence of
this support the Company would seek to remarket these NYSERDA bonds
collateralized by its first mortgage bonds.
The interest rate applicable to the senior debt facility will
be variable based on certain rate options available under the
agreement and is currently expected to approximate 8% (but capped
at 15%). The commitment by the Agent Banks to proceed with the
senior debt financing will expire on the earlier of (i) fifteen
days after the senior debt financing is approved by the PSC or (ii)
March 31, 1996. As contemplated by the commitment, the term loan
and revolving credit facility and the letter of credit facility
will be collateralized by the Company's first mortgage bonds and
will expire on the earlier of June 30, 1999 or the implementation
of the Company's PowerChoice restructuring proposal or any other
significant restructuring plan. The Company expects that the first
mortgage bonds to be issued as security will be based on additional
property under the earnings test required under the mortgage trust
indenture; the bonds could also be issued on the basis of
previously retired bonds without regard to an earnings test.
This commitment for the senior debt facility is subject to the
preparation and execution of loan documentation agreeable to the
parties and the approval of the PSC. (See Note 13 of Notes to the
Consolidated Financial Statements).
The Company believes that this commitment on behalf of the
Agent Banks to provide this senior debt facility is an important
step in establishing a firm financial basis for negotiating the
Company's PowerChoice restructuring proposal. The Company is
seeking PSC approval on its petition in March, 1996. In the event
the petition is not approved, the Company believes the elimination
of the common dividend, the implementation of reductions in non-
essential programs and the year-end 1995 cash position, in
combination with alternative sources of credit the Company believes
are available if necessary, will be sufficient to fund cash
requirements for 1996. Sufficient rate relief, if granted, would
provide adequate funds for 1997. The Company can provide no
assurances beyond 1997 as cash flow will depend on sales, the
implementation of PowerChoice, including UG contract renegotiation,
levels of cash rate relief, approval of the senior debt bank
facility agreement, levels of common and preferred dividends and
the ability to further reduce costs, among other things. As of
December 31, 1995, the Company could issue an additional $2,272
million aggregate principal amount of first mortgage bonds under
the applicable tests set forth in the Company's mortgage trust
indenture. This includes approximately $1,311 million from retired
bonds without regard to an interest coverage test and approximately
$961 million supported by additional property currently certified
and available, assuming a 10% interest rate. In the event of a
significant write-down in the future, the Company will likely be
precluded from issuing first mortgage bonds based on additional
property and the earnings test, for at least the twelve months
subsequent to such write-down.
The Company also has $200 million of Preference Stock
authorized for sale. Current market conditions preclude the
Company from issuing preferred or preference stock in 1996 due to
the downgrading of the Company's security ratings. The Company's
charter also limits the amount of unsecured indebtedness that may
be incurred by the Company to 10% of consolidated capitalization
plus $50 million. At December 31, 1995, this charter restriction
is approximately $683 million and the Company's unsecured debt
outstanding is $200 million.
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,
1995.
Consolidated Balance Sheets at December 31, 1995 and 1994.
Consolidated Statement of Cash Flows for each of the three
years in the period ended December 31, 1995.
Notes to Consolidated Financial Statements.
Financial Statement Schedules -
The following Financial Statement Schedule is 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 II - Valuation and Qualifying Accounts and Reserves
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 that 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
LLP, the Company's independent accountants, in accordance with
generally accepted auditing standards. In planning and performing
its 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.
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, 1995 and 1994, and the results of
their operations and their cash flows for each of the three years
in the period ended December 31, 1995, 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 Note 2, the Company believes that it continues to
meet the requirements for application of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation" (SFAS No. 71) and that its regulatory assets
are currently probable of recovery in future rates charged to
customers. There are a number of events that could change these
conclusions in 1996 and beyond, resulting in material adverse
effects on the Company's financial condition and results of
operations. As also discussed in Note 2, the Company has filed its
PowerChoice proposal with the Public Service Commission for
restructuring the Company to facilitate a transition to a
competitive electric generation market. If it becomes probable
that the proposal (or a similar proposal) will be implemented and
certain other conditions are met by third parties, the Company
would discontinue application of SFAS No. 71 with respect to the
electric generation business and write-off the related regulatory
assets, currently approximately $392 million. Such an outcome
would have a material adverse effect on the Company's results of
operations and financial condition.
/s/ Price Waterhouse LLP
Syracuse, New York
January 25, 1996
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
In thousands of dollars
For the year ended
December 31, 1995 1994 1993
- -----------------------------------------------------------------
Operating revenues:
Electric $3,335,548 $3,528,987 $3,332,464
Gas 581,790 623,191 600,967
- -----------------------------------------------------------------
3,917,338 4,152,178 3,933,431
- -----------------------------------------------------------------
Operating expenses:
Operation:
Fuel for electric
generation 165,929 219,849 231,064
Electricity purchased 1,137,937 1,107,133 863,513
Gas purchased 276,232 315,714 326,273
Other operation expenses 614,930 754,695 821,247
Employee reduction program - 196,625 -
Maintenance 202,967 202,682 236,333
Depreciation and
amortization (Note 1) 317,831 308,351 276,623
Federal and foreign income
taxes (Note 7) 156,008 117,834 162,515
Other taxes 517,478 496,922 491,363
- -----------------------------------------------------------------
3,389,312 3,719,805 3,408,931
- -----------------------------------------------------------------
Operating income 528,026 432,373 524,500
- -----------------------------------------------------------------
Other income and deductions:
Allowance for other funds
used during construction
(Note 1) 1,063 2,159 7,119
Federal and foreign income
taxes (Note 7) (3,385) 6,365 15,440
Other items (net) 2,006 15,045 7,035
- -----------------------------------------------------------------
(316) 23,569 29,594 -
- ----------------------------------------------------------------
Income before interest
charges 527,710 455,942 554,094
- -----------------------------------------------------------------
Interest charges:
Interest on long-term debt 267,019 264,891 279,902
Other interest 20,642 20,987 11,474
Allowance for borrowed funds
used during construction (7,987) (6,920) (9,113)
- -----------------------------------------------------------------
279,674 278,958 282,263
- -----------------------------------------------------------------
Net income 248,036 176,984 271,831
Dividends on preferred stock 39,596 33,673 31,857
- -----------------------------------------------------------------
Balance available for
common stock 208,440 143,311 239,974
Dividends on common stock 161,650 156,060 133,908
- -----------------------------------------------------------------
46,790 (12,749) 106,066
Retained earnings at
beginning of year 538,583 551,332 445,266
- -----------------------------------------------------------------
Retained earnings at
end of year $ 585,373 $ 538,583 $ 551,332
=================================================================
Average number of shares
of common stock outstanding
(in thousands) 144,329 143,261 140,417
Balance available per average
share of common stock $ 1.44 $ 1.00 $ 1.71
Dividends paid per share $ 1.12 $ 1.09 $ .95
- -----------------------------------------------------------------
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
CONSOLIDATED BALANCE SHEETS
In thousands of dollars
At December 31, 1995 1994
- ---------------------------------------------------------
ASSETS
Utility plant (Note 1):
Electric plant $ 8,543,429 $ 8,285,263
Nuclear Fuel 517,681 504,320
Gas plant 1,017,062 922,459
Common plant 281,525 291,962
Construction work in progress 289,604 481,335
- ---------------------------------------------------------
Total utility plant 10,649,301 10,485,339
Less: Accumulated
depreciation and
amortization 3,641,448 3,449,696
- ---------------------------------------------------------
Net utility plant 7,007,853 7,035,643
- ---------------------------------------------------------
Other property and
investments 218,417 224,039
- ---------------------------------------------------------
Current assets:
Cash, including temporary
cash investments of $114,415
and $50,052, respectively 153,475 94,330
Accounts receivable (less
allowance for doubtful accounts
of $20,000 and $3,600,
respectively) (Notes 1 and 9) 463,234 513,982
Electric margin recoverable 8,208 66,796
Materials and supplies, at
average cost:
Coal and oil for production
of electricity 27,509 31,652
Gas storage 26,431 30,931
Other 141,820 150,186
Prepaid taxes 17,239 43,249
Other 45,834 45,189
- ---------------------------------------------------------
883,750 976,315
- ---------------------------------------------------------
Regulatory assets (Note 2):
Regulatory tax asset 470,198 465,109
Deferred finance charges 239,880 239,880
Deferred environmental
restoration costs (Note 9) 225,000 240,000
Unamortized debt expense 92,548 105,457
Postretirement benefits other
than pensions 68,933 67,486
Other 204,253 227,542
- ---------------------------------------------------------
1,300,812 1,345,474
- ---------------------------------------------------------
Other assets 67,037 68,345
- ---------------------------------------------------------
$9,477,869 $9,649,816
=========================================================
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
CONSOLIDATED BALANCE SHEETS
In thousands of dollars
At December 31, 1995 1994
- ---------------------------------------------------------
CAPITALIZATION AND LIABILITIES
Capitalization (Note 5):
Common stockholders' equity:
Common stock, issued
144,332,123 and 144,311,466
shares, respectively $ 144,332 $ 144,311
Capital stock premium
and expense 1,784,247 1,779,504
Retained earnings 585,373 538,583
- ---------------------------------------------------------
2,513,952 2,462,398
Non-redeemable preferred stock 440,000 440,000
Mandatorily redeemable
preferred stock 96,850 106,000
Long-term debt 3,582,414 3,297,874
- ---------------------------------------------------------
Total capitalization 6,633,216 6,306,272
- ---------------------------------------------------------
Current liabilities:
Short-term debt (Note 6) - 416,750
Long-term debt due within
one year (Note 5) 65,064 77,971
Sinking fund requirements on
redeemable preferred stock
(Note 5) 9,150 10,950
Accounts payable 268,603 277,782
Payable on outstanding bank
checks 36,371 64,133
Customers' deposits 14,376 14,562
Accrued taxes 14,770 43,358
Accrued interest 64,448 63,639
Accrued vacation pay 35,214 36,550
Other 57,748 64,687
- ---------------------------------------------------------
565,744 1,070,382
- ---------------------------------------------------------
Regulatory liabilities (Note 2):
Deferred finance charges 239,880 239,880
Other 2,712 16,580
- ---------------------------------------------------------
242,592 256,460
- ---------------------------------------------------------
Other liabilities:
Accumulated deferred income
taxes (Notes 1 and 7) 1,388,799 1,258,463
Employee pension and other
benefits (Note 8) 245,047 248,872
Deferred pension settlement
gain 32,756 50,261
Unbilled revenues (Note 1) 28,410 93,668
Other 116,305 125,438
- ---------------------------------------------------------
1,811,317 1,776,702
- ---------------------------------------------------------
Commitments and contingencies (Notes 2 and 9):
Liability for environmental
restoration 225,000 240,000
- ---------------------------------------------------------
$9,477,869 $9,649,816
=========================================================
(CAPTION>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
INCREASE (DECREASE) IN CASH
In thousands of dollars
For the year ended December 31, 1995 1994 1993
- -----------------------------------------------------------------
Cash flows from operating activities:
Net income $ 248,036 $ 176,984 $ 271,831
Adjustments to reconcile
net income to net cash
provided by operating
activities:
Amortization of nuclear
replacement power cost
disallowance - (23,081) (23,720)
Depreciation and amortization 317,831 308,351 276,623
Amortization of nuclear fuel 34,295 37,887 35,971
Provision for deferred income
taxes 114,917 7,866 30,067
Electric margin recoverable 58,588 (45,428) (9,773)
Employee reduction program - 196,625 -
Deferred recoverable energy
costs 46,489 4,748 (5,688)
Gain on sale of subsidiary (11,257) - (5,490)
Unbilled revenues (71,258) - -
Sale of accounts receivable 50,000 - -
(Increase) decrease in net
accounts receivable 6,748 (59,145) (36,972)
Decrease in materials
and supplies 13,663 6,290 43,581
Increase (decrease) in accounts
payable and accrued expenses (47,048) (5,991) 15,716
Increase (decrease) in accrued
interest and taxes (35,440) (19,914) 3,996
Changes in other assets and
liabilities (33,974) 12,029 19,251
- -----------------------------------------------------------------
Net cash provided by
operating activities 691,590 597,221 615,393
- -----------------------------------------------------------------
Cash flows from investing activities:
Construction additions (332,443) (439,289) (506,267)
Nuclear fuel (13,361) (46,134) (12,296)
Less: Allowance for other
funds used during construction 1,063 2,159 7,119
- -----------------------------------------------------------------
Acquisition of utility plant (344,741) (483,264) (511,444)
Decrease in materials and
supplies related to con-
struction 3,346 5,143 3,837
Increase (decrease) in accounts
payable and accrued expenses
related to construction (7,112) (1,498) 3,929
Increase in other investments (115,818) (23,375) (26,774)
Proceeds from sale of sub-
sidiary (net of cash sold) 161,087 - 95,408
Other 26,234 (17,979) (15,260)
- -----------------------------------------------------------------
Net cash used in investing
activities (277,004) (520,973) (450,304)
- -----------------------------------------------------------------
Cash flows from financing activities:
Proceeds from sale of common
stock 304 29,514 116,764
Proceeds from long-term debt 346,000 424,705 635,000
Issuance of preferred stock - 150,000 -
Redemption of preferred stock (10,950) (33,450) (47,200)
Reductions of long-term debt (65,000) (526,584) (641,990)
Net change in short-term debt (416,750) 48,734 50,318
Dividends paid (201,246) (189,733) (165,765)
Other (7,799) (9,455) (31,759)
- -----------------------------------------------------------------
Net cash used in financing
activities (355,441) (106,269) (84,632)
- -----------------------------------------------------------------
Net increase (decrease) in cash 59,145 (30,021) 80,457
Cash at beginning of year 94,330 124,351 43,894
- -----------------------------------------------------------------
Cash at end of year $ 153,475 $ 94,330 $ 124,351
=================================================================
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest $ 290,352 $ 300,242 $ 300,791
Income taxes $ 47,378 $ 136,876 $ 106,202
/TABLE
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's
accounting policies conform to GAAP, as applied to regulated public
utilities, and are in accordance with the accounting requirements
and ratemaking practices of the regulatory authorities (see Note
2). In order to be in conformity with GAAP, management is required
to use estimates in the preparation of the Company's financial
statements.
PRINCIPLES OF CONSOLIDATION: The consolidated financial
statements include the Company and its wholly-owned subsidiaries.
Intercompany balances and transactions have been eliminated.
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, 1995 was 7.47%. AFC is segregated into its two
components, borrowed funds and other funds, and is reflected in the
Interest charges and the Other income and deductions sections,
respectively, of the Consolidated Statements of Income.
DEPRECIATION, AMORTIZATION AND NUCLEAR GENERATING PLANT
DECOMMISSIONING COSTS: For accounting and regulatory purposes,
depreciation is computed on the straight-line basis using the
remaining service lives for nuclear and hydro classes of
depreciable property and the average service lives for all other
classes. The percentage relationship between the total provision
for depreciation and average depreciable property was 3.3% for both
years 1995 and 1994, and 3.2% for 1993. The Company performs
depreciation studies to determine service lives of classes of
property and adjusts the depreciation reserves and rates when
necessary.
Estimated decommissioning costs (costs to remove a nuclear
plant from service in the future) for the Company's Unit 1 and its
share of Unit 2 are being accrued over the service lives of the
units, recovered in rates through an annual allowance and currently
charged to operations through depreciation. The Company expects to
commence decommissioning of both units shortly after cessation of
operations at Unit 2 (currently planned for 2026), using a method
which removes or decontaminates Unit components promptly at that
time. See Note 3 - "Nuclear Plant Decommissioning."
The FASB is expected to issue an exposure draft in February
1996 entitled "Accounting for Certain Liabilities Related to
Closure or Removal of Long-Lived Assets." The scope of the
original project has broadened and will now include the Company's
fossil and hydro plants, as well as nuclear plants. If approved as
drafted, the exposure draft would require the cost of closure and
removal obligations to be accounted for as a liability and accrued
as the obligation is incurred. The recognition of the liability
would result in an increase to the cost of the related asset and
would be reported based upon discounted future cash flows as
opposed to current cost. The Company would not be allowed to net
the balance of funds accumulated in the nuclear decommissioning
trust funds against the nuclear plant closure and removal
obligation. Additionally, the exposure draft would allow the
Company to establish a regulatory asset for the difference between
costs of closure and removal obligations recognized and the costs
allowable for rate-making purposes, subject to the provisions of
SFAS No. 71. As noted above, the Company currently recognizes the
liability for nuclear decommissioning over the service life of the
plant and as an increase to accumulated depreciation based on
amounts allowed in rates. The Company currently does not reflect
the closure and removal obligation associated with its fossil and
hydro plants in the financial statements. As such, the annual
provisions for depreciation could increase. Under traditional cost
based regulation such accounting changes would not have an adverse
effect on the results of operations of the Company. However, with
the filing of the Company's PowerChoice proposal and the
expectation the generating assets associated with this obligation
will face competition in the future and the issuance of SFAS No.
121 (discussed in Note 2), the Company cannot currently predict the
impact this exposure draft may have on the Company's future results
of operations.
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 because of
regulatory requirements. At December 31, 1995 and 1994,
approximately $5.2 million and $71.8 million, respectively, of
unbilled electric revenues remained unrecognized in results of
operations, are included in Other liabilities and may be used to
reduce future revenue requirements. In 1995, the Company used
$71.5 million of electric unbilled revenues to reduce the 1995
revenue requirement. At December 31, 1995 and 1994, $23.2 million
and $21.9 million, respectively, of unbilled gas revenues remain
unrecognized in results of operations and may similarly be used to
reduce future gas revenue requirements. The unbilled revenues
included in accounts receivable at December 31, 1995 and 1994, were
$202.7 million and $196.7 million, respectively.
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 to date 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 FAC provides for partial pass-through
of fuel and purchased power cost fluctuations from amounts
forecast, with the Company absorbing a 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 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 40% and passing 60%
through to ratepayers. The amounts retained or absorbed in 1993
through 1995 were not material.
From 1991 through 1994, the Company's rate agreements provided
for NERAM, which permitted 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 was created if sales exceed the
forecast and an asset recorded for a sales shortfall, thereby
generally preserving recorded electric gross margin at the level
forecast in established rates. 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 included MERIT, under which
the Company had 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
provided 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.
MERIT expired at the end of 1995, but collections of allowed awards
will continue into 1997.
The Company's PowerChoice proposal, which the Company filed in
October 1995 as part of its multi-year electric rate proceeding,
proposed to eliminate all surcharges, including the FAC, NERAM and
MERIT surcharges.
In February 1994, the Company implemented a weather
normalization clause for retail customers who use gas for heating
to reflect the impact of variations from normal weather on a
billing month basis for the months of October through May,
inclusive. Normal weather is defined as the 30 year average daily
high and low temperatures for the Company's main gas service
territory. The weather normalization clause will only be activated
if the actual weather deviates 2.2% or more from the normal
weather. Weather normalization clause adjustments were not
significant to 1995 gas revenues. As part of the Company's
PowerChoice proposal, as well as the formal gas rate filing made in
November 1995 (See "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Multi-Year Gas Rate
Proposal"), the Company proposed elimination of the weather
normalization clause. These surcharges would be reflected in base
rates as part of the Company's proposal to freeze overall prices.
ALLOWANCE FOR DOUBTFUL ACCOUNTS: The allowance for doubtful
accounts receivable on the consolidated balance sheets amounted to
$20.0 million and $3.6 million at December 31, 1995 and 1994,
respectively. The Company increased its allowance for doubtful
accounts in 1995 and recorded a regulatory asset of $16.4 million,
which reflects the amount that the Company expects to recover in
rates. Previously, the Company netted expected rate recoveries for
bad debt expense from expected uncollectible accounts in
determining its allowance for doubtful accounts, which was
consistent with the manner in which this item is treated in its
ratemaking.
FEDERAL INCOME TAXES: As directed by the PSC, the Company
defers any amounts payable pursuant to the alternative minimum tax
rules. Deferred investment tax credits are amortized to Other
Income and Deductions over the useful life of the underlying
property.
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 1995 presentation.
NOTE 2. RATE AND REGULATORY ISSUES AND CONTINGENCIES
The Company's financial statements conform to GAAP, as applied
to regulated public utilities and reflect the application of SFAS
No. 71. Substantively, SFAS No. 71 permits a public utility
regulated on a cost-of-service basis to defer certain costs when
authorized to do so by the regulator which would otherwise be
charged to expense. These deferred costs are known as regulatory
assets, which in the case of the Company are approximately $1,058
million, net of approximately $242 million of regulatory
liabilities at December 31, 1995. The portion of the $1,058
million which has been allocated to the electric business is
approximately $890 million. Generally, regulatory assets and
liabilities were allocated to the portion of the business that
incurred the underlying transaction that resulted in the
recognition of the regulatory asset or liability. The allocation
methods used between electric and gas were consistent with those
used in prior regulatory proceedings.
While the allocation of regulatory assets and liabilities at
December 31, 1995 is based on management's assessment, a final
determination can only be made at the time the Company, or a
portion thereof, discontinues the application of SFAS No. 71.
Currently, substantially all of the Company's regulatory assets
have been approved by the PSC and are being amortized to expense as
they are being recovered in rates as last established in April
1995.
RATE FILING. The Company filed in February 1996 a request to
increase electric rates. This rate increase request of 4.1% for
1996 and 4.2% for 1997 was based on the Company's cost of providing
services. The Company requested that its 4.1% increase for 1996 be
implemented immediately with a provision that rates charged will be
subject to refund if later it is determined that some portion of
the request is not allowed by the PSC. These rate increases are
predicated on a requested rate of return on common stock equity of
approximately 11% on an annual basis and recover the Company's cost
of providing electric service. On February 16, 1996, the PSC
issued an Order that, among other things, established a schedule
with respect to temporary rates that would have the case certified
directly to the PSC within 60 days of the order. The Company
believes that the PSC will approve rate increases on a timely basis
in levels sufficient to enable it to earn a reasonable return on
equity in 1996 and 1997. As a result the Company believes that it
will continue to be regulated on a cost-of-service basis which will
enable it to continue to apply SFAS No. 71. Accordingly, the
Company believes its regulatory assets are currently probable of
recovery. While various proposals have been made to develop a new
regulatory model, including the Company's PowerChoice proposal,
none of these proposals are currently probable of implementation
since a number of parties are required to act on the change in the
regulatory model. The Company expects that the PSC will approve
cost-of-service based rate increases that will result in the
Company earning a reasonable return on common equity until such
time as implementation of a new competitive market model becomes
probable.
While the Company believes that it continues to meet the
requirements for the application of SFAS No. 71 to the electric
business, there are a number of events that could change that
conclusion during 1996 and beyond. Those future events include:
inaction or inadequate action on the Company's rate request by the
PSC; a decision by the Company in the future not to pursue the rate
requests filed; unanticipated reduction in electricity usage by
customers; unanticipated customer discounts; adverse results of
litigation; and a change in the regulatory model becoming probable.
As discussed in Management's Discussion and Analysis of
Financial Condition and Results of Operations, the Company has been
unable to earn its allowed rate of return in 1995 and 1994.
Additionally, if the Company's rate increase proposals with respect
to 1996 and 1997 are not approved, then the Company will, more
likely than not, be unable to earn a reasonable return on its
common equity for such years. The inability of the Company to earn
a reasonable rate of return on common equity over a sustained
period would indicate that its rates are not based on its cost of
service. In such a case, application of SFAS No. 71 would be
discontinued. The resulting charges against income would reduce or
possibly eliminate retained earnings, the balance of which is
currently approximately $585 million. Various tests under
applicable law and corporate instruments, including those with
respect to issuance of debt and equity securities, payment of
preferred and common dividends and certain types of transfers of
assets could be adversely impacted by any such write-downs. In
addition, such write-downs could preclude it from borrowing
additional amounts under its current revolving credit facility,
which is planned to be replaced by the proposed senior debt
facility (see Note 6) whose terms are intended to accommodate the
discontinuance of SFAS No. 71 as it applies to the Company's
electric business.
COMPETITION. The public utility industry in general, and the
Company in particular, is facing increasing competitive threats.
As competition penetrates the marketplace, it is possible that the
Company may no longer be able to continue to apply the fundamental
accounting principles of SFAS No. 71. The Company believes that in
the future some form of market-based pricing may replace cost-based
pricing in certain aspects of its business. In that regard, in
October 1995, the Company filed its PowerChoice proposal with the
PSC. PowerChoice, further described in the Management Discussion
and Analysis - "PowerChoice Proposal", would:
* Create a competitive wholesale electricity market and allow
direct access by retail customers.
* Separate the Company's power generation business from the
remainder of the business.
* Provide relief from overpriced unregulated generator contracts
that were mandated by public policy, along with equitable
write-downs of above-market company assets.
* Freeze or cut prices for all Company electric customers for a
period of 5 years.
The separated generation business proposed in PowerChoice
would no longer be rate-regulated and, accordingly, existing
regulatory assets related to the generation business, amounting to
$392 million, net of approximately $242 million of regulatory
liabilities at December 31, 1995 (management's assessment), would
be charged against income if and when PowerChoice (or a similar
proposal) is probable of implementation. Under PowerChoice, the
Company's electric transmission and distribution business is
proposed to continue to be rate regulated on a cost-of-service
basis and, accordingly, continue to apply SFAS No. 71. The
PowerChoice proposal also includes provisions for recovery of
"stranded costs" by the generation business and unregulated
generators through surcharges on rates for transmission and
distribution customers. Stranded costs are those costs of
utilities that may become unrecoverable due to a change in the
regulatory environment and include costs related to the Company's
generating plants, regulatory assets and overpriced unregulated
generator contracts.
Critical to the price freeze and restructuring of the
Company's markets and business envisioned in the PowerChoice
proposal are substantial reductions in the Company's embedded cost
structure. Such cost reductions depend in turn on the willingness
of the UGs and the Company to absorb substantial write-offs. The
Company's proposal expresses its willingness if, and only if, the
UGs agree to cost reductions that are proportional to their
relative responsibility for strandable cost. The Company proposes
a reduction in its fixed costs of service be made by mutual
contribution of the Company's shareholders and UGs that are in the
same proportion as the contribution of each to the problem of
strandable costs, which the Company calculates to be $4 of UG
strandable cost for every $1 of Company strandable cost. Under the
Company's proposal, the aggregate contribution would be
approximately $2 billion, consisting of $400 million by the Company
and $1.6 billion by the UGs. The Company's PowerChoice proposal
faces opposition, principally from unregulated generators. The
Company does not presently expect that its PowerChoice proposal or
any other alternative proposal could be fully effective before
sometime in 1997, at the earliest.
There are also other proposals to introduce competition into
the utility marketplace presently before the PSC. In addition, the
FERC has pending proposals before it relating to open access to the
nation's transmission system and the recovery of stranded costs.
IMPAIRMENT OF LONG-LIVED ASSETS: In March 1995, the FASB
issued SFAS No. 121. This Statement, which the Company will adopt
in 1996, requires that long-lived assets and certain identifiable
intangibles to be held and used by an entity, be reviewed for
impairment whenever events or changes in circumstances indicate
that the carrying amount of an asset may not be recoverable. In
performing the review for recoverability, the Company is required
to estimate future undiscounted cash flows expected to result from
the use of the asset and its eventual disposition. Furthermore,
this Statement amends SFAS No. 71 to clarify that regulatory assets
should be charged against earnings if the assets are no longer
considered probable of recovery rather than probable of loss.
While the Company is unable to predict the outcome of its
PowerChoice proposal, or various FERC and PSC initiatives, it has
analyzed the provisions of SFAS No. 121, as it relates to the
impairment of its investment in generating plant, under two
scenarios: traditional cost-based rate-making and its PowerChoice
proposal, as filed. As a result of these analyses, the Company
does not believe the effects of adopting SFAS No. 121, as it
relates to the impairment of its investment in generating plant,
will currently have an effect on its results of operations and
financial condition. In addition, the Company expects that the PSC
will approve cost-of-service based rate increases until such time
as a new competitive regulatory model is developed. As a result,
the Company believes currently that its regulatory assets are
probable of recovery. However, if in the future management can no
longer conclude that existing regulatory assets are probable of
recovery, then all or a portion of such regulatory assets would
have to be charged to income, which could have a material adverse
effect on the Company's financial position and results of
operations.
The Company has recorded the following regulatory assets on
its Consolidated Balance Sheets reflecting the rate actions of its
regulators:
REGULATORY TAX ASSET represents the expected future recovery
from ratepayers of the tax consequences of temporary differences
between the recorded book bases and the tax bases of assets and
liabilities. This amount is primarily timing differences related
to depreciation. These amounts are amortized and recovered as the
related temporary differences reverse. In January 1993, the PSC
issued a Statement of Interim Policy on Accounting and Ratemaking
Procedures that required adoption of SFAS No. 109 on a revenue-
neutral basis.
DEFERRED FINANCE CHARGES represent the deferral of the
discontinued portion of AFC related to CWIP at Unit 2 which was
included in rate base. In 1985, pursuant to PSC authorization, the
Company discontinued accruing AFC on CWIP for which a cash return
was being allowed. This amount, which was accumulated in deferred
debit and credit accounts up to the commercial operation date of
Unit 2, awaits future 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.
DEFERRED ENVIRONMENTAL RESTORATION COSTS represent the
Company's share of the estimated minimum costs to investigate and
perform certain remediation activities at both Company-owned sites
and non-owned sites with which it may be associated. Prior to
1995, the Company recovered 100% of its costs associated with site
investigation and restoration. In the Company's 1995 rate order,
costs incurred during 1995 for the investigation and restoration of
Company-owned sites and sites with which it is associated
were subject to 80%/20% (ratepayer/Company) sharing. In 1995, the
Company incurred $11.5 million of such costs, resulting in a
disallowance of $2.3 million (before tax), which the Company has
recorded as a loss in Other items (net) on the Consolidated
Statements of Income. The PSC stated in its full opinion, dated
December 1995, its decision to require sharing was "on a one-time,
short-term basis only, pending its further evaluation of the issue
in future proceedings." The Company has recorded a regulatory
asset representing the remediation obligations to be recovered from
ratepayers. See Note 9 - "Environmental Contingencies".
UNAMORTIZED DEBT EXPENSE represents the costs to issue and
redeem certain long-term debt securities which were retired prior
to maturity. These amounts are amortized as interest expense
ratably over the lives of the related issues in accordance with PSC
directives.
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS represent the
excess of such costs recognized in accordance with SFAS No. 106
over the amount received in rates. In accordance with the PSC
policy statement, postretirement benefit costs other than pensions
are being phased-in to rates over a five-year period and amounts
deferred will be amortized and recovered over a period not to
exceed 20 years.
NOTE 3. 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 1,143 MW Unit 2. The
remaining ownership interests are Long Island Lighting Company
(LILCO) - 18%, New York State Electric and Gas Corporation (NYSEG)
- - 18%, Rochester Gas and Electric Corporation (RG&E) - 14%, and
Central Hudson Gas and Electric Corporation (Central Hudson) - 9%.
Unit 1 was placed in commercial operation in 1969 and Unit 2 in
1988.
In December 1995, a state utility board appointed by Governor
George E. Pataki developed a plan to dismantle LILCO. The plan
delayed making any recommendation as to LILCO's ownership interest
in Unit 2, but otherwise recommends the creation of a competitive
generation market on Long Island, through the sale of existing
generating capacity by LILCO. The Company is unable to predict
what effects, if any, this proposal may have on its results of
operations or financial condition, since there are many
uncertainties related to this proposal. It is estimated that the
earliest time such a plan could be completed is one to two years.
UNIT 1 STATUS: On February 8, 1995, Unit 1 was taken out of
service for a planned refueling and maintenance outage and returned
to service on April 4, 1995. Its next refueling and maintenance
outage is scheduled to begin in February 1997. Using the net
design electric rating as a basis, Unit 1's capacity factor for
1995 was approximately 80%. Using NRC guidelines, which reflect
net maximum dependable capacity during the most restrictive
seasonal conditions, Unit 1's capacity factor was approximately
87%.
UNIT 2 STATUS: On April 8, 1995, Unit 2 was taken out of
service for a planned refueling and maintenance outage and returned
to service on June 2, 1995. Its next refueling and maintenance
outage is scheduled for Fall 1996. During the 1995 refueling
outage the Company completed its power uprate project, installed
new turbine rotors and made other operational improvements enabling
the plant to increase its capacity from 1,062 MW to 1,143 MW.
Using the net design electric rating as a basis, Unit 2's capacity
factor for 1995 was approximately 75%. Using NRC guidelines as
described above, Unit 2's capacity factor was approximately 78%.
NUCLEAR PLANT DECOMMISSIONING: The Company's site specific
cost estimates for decommissioning Unit 1 and its ownership
interest in Unit 2 at December 31, 1995 are as follows:
Unit 1 Unit 2
------ ------
Site Study (year) 1995 1995
End of Plant Life (year) 2009 2026
Radioactive Dismantlement
to Begin (year) 2026 2028
Method of Decommissioning Delayed Immediate
Dismantlement Dismantlement
Cost of Decommissioning
(in 1996 dollars) (In millions)
Radioactive Components $409 $187
Non-radioactive Components 111 45
Fuel Dry Storage/Continuing Care 113 40
---- ----
$633 $272
==== ====
The Company estimates that by the time decommissioning is
completed, the above costs will ultimately amount to $1.7 billion
and $1.1 billion for Unit 1 and Unit 2, respectively, using 3.5% as
an annual inflation factor.
In addition to the costs mentioned above, the Company expects
to incur post-shutdown costs for plant rampdown, insurance and
property taxes. In 1996 dollars, these costs are expected to
amount to $99 million and $59 million for Unit 1 and the Company's
share of Unit 2, respectively. The amounts will escalate to $182
million and $190 million for Unit 1 and the Company's share of Unit
2, respectively.
Based upon a 1994 study, the Company had previously estimated
the cost to decommission Unit 1 to be approximately $565 million in
1996 dollars. In addition, post-shutdown costs were estimated to
be $118 million, also in 1996 dollars. While both estimates assume
a delayed dismantlement to coincide with Unit 2, the 1995 estimate
of $633 million differs from the 1994 estimate primarily due to an
increase in burial costs and the labor associated with the non-
radioactive dismantlement, partially offset by lower waste volumes.
The delayed dismantlement approach should be the most economic
after applying the Company's weighted average cost of capital.
The Company had previously estimated the cost to decommission
its share of Unit 2 by extrapolating data from the 1994 Unit 1
decommissioning cost estimate. The extrapolated estimate of $311
million, in 1996 dollars, differs from the 1995 study of $272
million primarily due to the estimate being based upon plant
specifics rather than extrapolated values.
NRC regulations require owners of nuclear power plants to
place funds into an external trust to provide for the cost of
decommissioning radioactive portions of nuclear facilities and
establish minimum amounts that must be available in such a trust at
the time of decommissioning. The annual allowance for Unit 1 and
the Company's share of Unit 2 for the years ended December 31,
1995, 1994 and 1993 was approximately $23.7 million, $18.7 million
and $18.7 million, respectively. The amount for 1995 was based
upon the NRC minimum decommissioning cost requirements of $408
million and $185 million (in 1996 dollars) for Unit 1 and the
Company's share of Unit 2, respectively. The amounts for 1994 and
1993 were based upon site studies performed in 1989. In the 1995
rate order, the Company was authorized, until the PSC orders
otherwise, to continue to fund to the NRC minimum requirements. In
the 1997 rate filing, the Company has requested, for both units,
rate recovery for all radioactive and non-radioactive components
(including post-shutdown costs) based upon the amounts estimated in
the 1995 site specific studies described above. There is no
assurance that the decommissioning allowance recovered in rates
will ultimately aggregate a sufficient amount to decommission the
units. The Company believes that if decommissioning costs are
higher than currently estimated, the costs would ultimately be
included in the rate process under traditional ratemaking and
PowerChoice.
Decommissioning costs recovered in rates are reflected in
Accumulated depreciation and amortization on the Consolidated
Balance Sheets and amount to $183.4 million and $134.1 million at
December 31, 1995 and 1994, respectively for both Units.
Additionally at December 31, 1995, the fair value of funds
accumulated in the Company's external trusts were $108.8 million
for Unit 1 and $28.8 million for its share of Unit 2. The trusts
are included in Other property and investments. Earnings on the
external trust aggregated $20.9 million through December 31, 1995
and, because the earnings 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 $39.8 million at December 31, 1995.
The FASB is expected to issue an exposure draft in February
1996 on accounting for closure and removal of long-lived assets.
See Note 1 - "Depreciation, Amortization and Nuclear Generating
Plant Decommissioning Costs."
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 1993, the statutory limit 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, is currently $8.3
billion without the 5% surcharge discussed below. This limit would
be funded by assessments of up to $75.5 million for each of the 110
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
maximum potential loss, for each accident, of $111.8 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 $2,250
million in excess of the $500 million primary nuclear insurance
with Nuclear Electric Insurance Limited (NEIL). The total nuclear
property insurance is $2.75 billion. 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.
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 $17.7
million per loss.
LOW LEVEL RADIOACTIVE WASTE: The Federal Low Level
Radioactive Waste Policy Act as amended in 1985 requires states to
join compacts or to 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
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 still developing a disposal methodology and
acceptance criteria for a disposal facility. The latest 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. The Company currently uses the Barnwell, South Carolina
waste disposal facility for low level radioactive waste, however
access to Barnwell was denied by the State of South Carolina to out
of region low level waste generators, including New York State from
July 1, 1994 to July 1, 1995. The Company also has implemented a
low level radioactive waste management program so that Unit 1 and
Unit 2 are prepared to properly handle interim on-site storage of
low level radioactive waste for at least a 10 year period.
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 U.S. 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
the year in which the Company initially plans 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 that will extend to the year 2044.
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 incurring additional costs, which the
Company has included in its decommissioning estimates for both Unit
1 and its share of Unit 2. The Company does not believe that the
possible unavailability of the DOE disposal facility until 2010
will inhibit operation of either Unit.
NOTE 4. JOINTLY-OWNED GENERATING FACILITIES
The following table reflects the Company's share of jointly-
owned generating facilities at December 31, 1995. 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
-----------------------------------------------
Percent Utility Accumulated Construction
Ownership Plant Depreciation Work in Progress
- ------------------------------------------------------------------------------------------
Roseton Steam Station
Units No. 1 and 2 (a) 25 $ 95,540 $ 48,385 $ 1,345
Oswego Steam Station
Unit No. 6 (b) 76 $ 271,472 $ 111,631 $ 782
Nine Mile Point Nuclear
Station Unit No. 2 (c) 41 $1,519,351 $ 272,888 $ 5,105
- ------------------------------------------------------------------------------------------
(a) The remaining ownership interests are Central Hudson, the operator of the plant (35%),
and Consolidated Edison Company of New York, Inc. (40%). 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 RG&E (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 LILCO (18%), NYSEG
(18%), RG&E (14%), and Central Hudson (9%). Output of Unit 2, which has a capability
of 1,143,000 kw., is shared in the same proportions as the cotenants' respective
ownership interests.
NOTE 5. CAPITALIZATION
- ----------------------
CAPITAL STOCK
The Company is authorized to issue 185,000,000 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 1993, 1994 and
1995:
COMMON STOCK
$1 PAR VALUE
--------------------------
SHARES AMOUNT*
- --------------------------------------------------------
December 31, 1992: 137,159,607 $137,160
Issued 5,267,450 5,267
Redemptions
Foreign currency
translation adjustment
- --------------------------------------------------------
December 31, 1993: 142,427,057 142,427
Issued 1,884,409 1,884
Redemptions
Foreign currency
translation adjustment
- --------------------------------------------------------
December 31, 1994: 144,311,466 144,311
Issued 20,657 21
Redemptions
Foreign currency
translation adjustment
- --------------------------------------------------------
December 31, 1995: 144,332,123 $144,332
========================================================
* In thousands of dollars
/TABLE
PREFERRED STOCK
$100 PAR VALUE
---------------------------------------
SHARES NON-REDEEMABLE* REDEEMABLE*
- --------------------------------------------------------------
December 31, 1992: 2,412,000 $210,000 $31,200 (a)
Issued - - -
Redemptions (18,000) - (1,800)
Foreign currency
translation adjustment
- --------------------------------------------------------------
December 31, 1993: 2,394,000 210,000 29,400 (a)
Issued - - -
Redemptions (18,000) - (1,800)
Foreign currency
translation adjustment
- --------------------------------------------------------------
December 31, 1994: 2,376,000 210,000 27,600 (a)
Issued - - -
Redemptions (18,000) - (1,800)
Foreign currency
translation adjustment
- --------------------------------------------------------------
December 31, 1995: 2,358,000 $210,000 $25,800 (a)
==============================================================
* In thousands of dollars
(a) Includes sinking fund requirements due within one year.
PREFERRED STOCK
$25 PAR VALUE
---------------------------------------
CAPITAL STOCK
PREMIUM AND
EXPENSE
SHARES NON-REDEEMABLE* REDEEMABLE* (NET)*
- ----------------------------------------------------------------------------
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
Issued 6,000,000 150,000 - 27,630
Redemptions (1,266,000) - (31,650) (4,619)
Foreign currency
translation adjustment (6,213)
- ----------------------------------------------------------------------------
December 31, 1994: 12,774,005 230,000 89,350 (a) 1,779,504
Issued - - - 283
Redemptions (366,000) - (9,150) 1,319
Foreign currency
translation adjustment 3,141
- ----------------------------------------------------------------------------
December 31, 1995: 12,408,005 $230,000 $ 80,200 (a) $1,784,247
============================================================================
* In thousands of dollars
(a) Includes sinking fund requirements due within one year.
The cumulative amount of foreign currency translation adjustment at December 31, 1995 was
$(10,172).
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 Redemption price per
of dollars share (before adding
Series Shares 1995 1994 accumulated dividends)
- --------------------------------------------------------------
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
9.50% 6,000,000 150,000 150,000 25.00 (a)
Series A 1,200,000 30,000 30,000 25.00
Series C 2,000,000 50,000 50,000 25.00
- --------------------------------------------------------------
$440,000 $440,000
==============================================================
(a) Not redeemable until 1999.
/TABLE
MANDATORILY REDEEMABLE PREFERRED STOCK
At December 31, the Company has certain issues of preferred stock, as detailed below,
which provide for mandatory and optional redemption. 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). 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 1996
through 2000 are as follows: $9,150; $10,120; $10,120; $7,620; and $7,620, respectively.
- ---------------------------------------------------------------------------------
Redemption price per
share (before adding
Shares In thousands of dollars accumulated dividends)
Eventual
Series 1995 1994 1995 1994 1995 Minimum
- ---------------------------------------------------------------------------------
Preferred $100 par value:
7.45% 258,000 276,000 $ 25,800 $ 27,600 $102.17 $100.00
Preferred $25 par value:
7.85% 914,005 914,005 22,850 22,850 (a) 25.00
8.375% 300,000 400,000 7,500 10,000 25.22 25.00
8.70% - 200,000 - 5,000 - -
9.75% 144,000 210,000 3,600 5,250 25.00 25.00
Adjustable Rate
Series B 1,850,000 1,850,000 46,250 46,250 25.00 25.00
- ---------------------------------------------------------------------------------
106,000 116,950
Less sinking fund requirements 9,150 10,950
- ---------------------------------------------------------------------------------
$ 96,850 $106,000
=================================================================================
(a) Not redeemable until 1997.
LONG-TERM DEBT
Long-term debt at December 31, consisted of the following:
- -------------------------------------------------------------
In thousands of dollars
-----------------------
SERIES DUE 1995 1994
- -------------------------------------------------------------
First mortgage bonds:
5 7/8% 1996 $ 45,000 $ 45,000
6 1/4% 1997 40,000 40,000
6 1/2% 1998 60,000 60,000
9 1/2% 2000 150,000 150,000
6 7/8% 2001 210,000 210,000
9 1/4% 2001 100,000 100,000
5 7/8% 2002 230,000 230,000
6 7/8% 2003 85,000 85,000
7 3/8% 2003 220,000 220,000
8% 2004 300,000 300,000
6 5/8% 2005 110,000 110,000
9 3/4% 2005 150,000 150,000
7 3/4% 2006 275,000 -
*6 5/8% 2013 45,600 45,600
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 210,000 210,000
*8 7/8% 2025 75,000 75,000
* 7.2% 2029 115,705 115,705
- -------------------------------------------------------------
Total First Mortgage Bonds 2,886,305 2,611,305
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,
due 1995-2004 30,000 45,000
Swiss Franc Bonds due
December 15, 1995 - 50,000
Revolving Credit Agreement 170,000 99,000
Other 159,198 169,421
Unamortized premium (discount) (11,785) (12,641)
- --------------------------------------------------------------
TOTAL LONG-TERM DEBT 3,647,478 3,375,845
Less long-term debt due
within one year 65,064 77,971
- --------------------------------------------------------------
$3,582,414 $3,297,874
==============================================================
*Tax-exempt pollution control related issues
==============================================================
Several series of First Mortgage Bonds and Notes were issued
to secure a like amount of tax-exempt revenue bonds issued by
NYSERDA. Approximately $414 million of such securities 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 3.81% for 1995 and 2.76% for 1994 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 to refund outstanding tax-exempt bonds and notes (see
Note 6).
Other long-term debt in 1995 consists of obligations under
capital leases of approximately $36.8 million, a liability to the
DOE for nuclear fuel disposal of approximately $103.1 million and
liabilities for unregulated generator contract terminations of
approximately $19.3 million.
The aggregate maturities of long-term debt for the five years
subsequent to December 31, 1995, excluding capital leases, are
approximately $61 million, $216 million, $66 million, $0 and $155
million, respectively.
NOTE 6. BANK CREDIT ARRANGEMENTS
At December 31, 1995, the Company had $310 million of bank
credit arrangements with 14 banks. These credit arrangements
consisted of $200 million in commitments under a Revolving Credit
Agreement, $99 million in one-year commitments under Credit
Agreements and $11 million in lines of credit. The Revolving
Credit Agreement extends into 1997 and the interest rate applicable
to borrowing is based on certain rate options available under the
Agreement. All of the other bank credit arrangements are subject
to review on an ongoing basis with interest rates negotiated at the
time of use.
In order to enhance the Company's financial flexibility during
the period 1996 through 1999, the Company entered into a commitment
letter with Citibank, N.A., Morgan Guaranty Trust Company of New
York and Toronto Dominion Bank, as co-syndication agents (Agent
Banks), for the provision of a senior debt facility totaling $815
million for the purpose of consolidating and refinancing certain of
the Company's existing working capital lines of credit and letter
of credit facilities and providing additional reserves of bank
credit. The proposed senior debt facility will consist of a $380
million term loan and revolving credit facility and a $435 million
letter of credit facility, with such letter of credit facility to
provide credit support for the pollution control revenue bonds
issued through NYSERDA, discussed in Note 5. The interest rate
applicable to the facility will be variable based on certain rate
options available under the agreement and is currently expected to
approximate 8% (but capped at 15%). The commitment by the Agent
Banks to proceed with the senior debt financing will expire on the
earlier of (i) fifteen days after the senior debt financing is
approved by the PSC or (ii) March 31, 1996. As contemplated by the
commitment, the term loan and revolving credit facility and the
letter of credit facility will be collateralized by the Company's
first mortgage bonds and will expire on the earlier of June 30,
1999 or the implementation of the Company's PowerChoice
restructuring proposal or any other significant restructuring plan.
This commitment for the senior debt facility will be subject
to the preparation and execution of loan documentation agreeable to
the parties, as well as the approval of the PSC.
The Company is seeking PSC approval on its petition in March,
1996. In the event the petition is not approved, the Company
believes that the elimination of the common dividend, the
implementation of reductions in non-essential programs and the year
end 1995 cash position, in combination with alternative sources of
credit the Company believes are available if necessary, will be
sufficient to fund cash requirements for 1996. Sufficient rate
relief, if granted, would provide adequate funds for 1997. The
Company can provide no assurances beyond 1997 as cash flow will
depend on sales, the implementation of PowerChoice, including UG
contract renegotiations, levels of cash rate relief, approval of
the bank facility agreement, levels of common and preferred
dividends and the ability to further reduce costs.
The Company pays fees for substantially all of its bank credit
arrangements. The following table summarizes additional
information applicable to short-term debt:
- --------------------------------------------------------
In thousands of dollars
At December 31, 1995 1994
- --------------------------------------------------------
Short-term debt:
Commercial paper $ - $ 84,750
Notes payable - 321,000
Bankers acceptances - 11,000
- ---------------------------------------------------------
$ - $416,750
Weighted average interest
rate (a) - 6.21%
- ---------------------------------------------------------
For Year Ended December 31:
- ---------------------------------------------------------
Daily average outstanding $179,505 $342,801
Monthly weighted average
interest rate (a) 6.43% 4.71%
Maximum amount outstanding $459,700 $497,700
- ---------------------------------------------------------
(a) Excluding fees.
- ---------------------------------------------------------
/TABLE
NOTE 7. FEDERAL AND FOREIGN INCOME TAXES
- -----------------------------------------
See Note 9 - "Tax Assessments."
Components of United States and foreign income before income
taxes:
In thousands of dollars
1995 1994 1993
- ---------------------------------------------------------------
United States $400,087 $291,501 $438,914
Foreign 17,609 15,475 (24,845)
Consolidating eliminations (10,267) (18,523) 4,837
- ---------------------------------------------------------------
Income before income taxes $407,429 $288,453 $418,906
===============================================================
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
1995 1994 1993
- --------------------------------------------------------------
Components of Federal and foreign income taxes:
Current tax expense:
Federal $ 67,563 $117,314 $118,918
Foreign 3,900 4,423 8,445
- ---------------------------------------------------------------
71,463 121,737 127,363
- ---------------------------------------------------------------
Deferred tax expense:
Federal 82,323 (6,931) 35,152
Foreign 2,222 3,028 -
- ---------------------------------------------------------------
84,545 (3,903) 35,152
- ---------------------------------------------------------------
Income taxes included in
Operating Expenses 156,008 117,834 162,515
Current Federal and
foreign income tax
credits included in
Other Income and
Deductions (197) (11,507) (16,061)
Deferred Federal and
foreign income tax
expense included in
Other Income and
Deductions 3,582 5,142 621
- ---------------------------------------------------------------
Total $159,393 $111,469 $147,075
===============================================================
Reconciliation between Federal and foreign income taxes and the tax
computed at prevailing U.S. statutory rate on income before income
taxes:
Computed tax $142,601 $100,959 $146,617
- ---------------------------------------------------------------
Reduction (increase) attributable to flow-through of certain tax
adjustments:
Depreciation (31,033) (33,328) (35,153)
Cost of removal 9,247 8,908 7,822
Deferred investment tax
credit amortization 8,589 8,018 8,018
Other (3,595) 5,892 18,855
- ---------------------------------------------------------------
(16,792) (10,510) (458)
- ---------------------------------------------------------------
Federal and foreign
income taxes $159,393 $111,469 $147,075
===============================================================
At December 31, the deferred tax liabilities (assets) were
comprised of the following:
(In thousands)
1995 1994
---- ----
Alternative minimum tax $ (82,869) $ (93,893)
Unbilled revenue (77,675) (98,201)
Other (248,275) (258,621)
---------- ----------
Total deferred tax assets (408,819) (450,715)
---------- ----------
Depreciation related 1,456,949 1,398,695
Investment tax credit related 91,458 95,325
Other 249,211 215,158
---------- ----------
Total deferred tax
liabilities 1,797,618 1,709,178
---------- ----------
Accumulated deferred income
taxes $1,388,799 $1,258,463
========== ===========
NOTE 8. 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 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.
During 1994, the Company offered an early retirement program
and a voluntary separation program (together the VERP) to reduce
the Company's staffing levels and streamline operations. The VERP,
which included both represented and non-represented employees, was
accepted by approximately 1,400 employees. The program cost the
Company approximately $208 million of which $11.4 million, related
to the gas business, was deferred with recovery anticipated to
occur over a five year period, beginning in 1995.
Net pension cost for 1995, 1994 and 1993 included the
following components:
- -----------------------------------------------------------------
In thousands of dollars
-----------------------
1995 1994 1993
- -----------------------------------------------------------------
Service cost - benefits
earned during the period $ 22,500 $ 30,400 $ 30,100
Interest cost on projected
benefit obligation 73,000 62,700 54,200
Actual return on Plan assets (215,600) 7,700 (106,100)
Net amortization and deferral 140,300 (63,600) 38,700
- -----------------------------------------------------------------
Net pension cost 20,200 37,200 16,900
VERP costs - 114,000 -
Regulatory asset - (6,200) -
- -----------------------------------------------------------------
Total pension cost (1) $ 20,200 $145,000 $ 16,900
=================================================================
(1) $4.1 million for 1995, $5.9 million for 1994, and $5.6 million
for 1993 was related to construction labor and, accordingly,
was charged to construction projects.
/TABLE
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, 1995 1994
- --------------------------------------------------------------
Actuarial present value of
accumulated benefit obligations:
Vested benefits $ 777,584 $640,689
Non-vested benefits 64,383 69,642
- --------------------------------------------------------------
Accumulated benefit obligations 841,967 710,331
Additional amounts related to
projected pay increases 135,115 222,667
- --------------------------------------------------------------
Projected benefits obligation for
service rendered to date 977,082 932,998
Plan assets at fair value, consisting
primarily of listed stocks, bonds,
other fixed income obligations
and insurance contracts (1,074,333) (893,313)
- --------------------------------------------------------------
Plan assets (in excess of) less than
projected benefit obligations (97,251) 39,685
Unrecognized net obligation at
January 1, 1987 being recognized
over approximately 19 years (21,500) (27,122)
Unrecognized net gain from actual
return on plan assets different
from that assumed 198,035 58,379
Unrecognized net gain from past
experience different from that
assumed and effects of changes
in assumptions amortized over 10
years 46,982 67,857
Prior service cost not yet recognized
in net periodic pension cost (41,291) (44,421)
- ---------------------------------------------------------------
Pension liability included
in the consolidated balance sheets $ 84,975 $ 94,378
===============================================================
Principle Actuarial Assumptions (%):
Discount Rate 7.50 8.00
Rate of increase in future
compensation levels (plus
merit increases) 2.50 3.25
Long-term rate of return on
plan assets 9.25 8.75
===============================================================
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.
The Company accounts for the cost of these benefits in
accordance with PSC policy requirements which generally comply with
SFAS No. 106. The Company has established various trusts to fund
its future postretirement benefit obligation. In 1995, the Company
made contributions to such trusts of approximately $53.1 million,
which represented the amount received in rates, certain capital
portions of the postretirement benefit obligation and amounts
received from co-tenants. In 1994 and 1993, the Company
contributed $24 million and $12 million, respectively, which
represented the amount received in rates.
Net postretirement benefit cost for 1995, 1994 and 1993
included the following components:
- -----------------------------------------------------------------
In thousands of dollars
----------------------------
1995 1994 1993
- -----------------------------------------------------------------
Service cost - benefits attributed
to service during the period $12,600 $ 15,000 $12,300
Interest cost on accumulated
benefit obligation 45,400 40,200 32,800
Actual return on plan assets (11,200) (900) -
Amortization of the transition
obligation over 20 years 18,800 20,200 20,400
Net amortization 14,600 8,900 -
- -----------------------------------------------------------------
Net postretirement benefit cost 80,200 83,400 65,500
VERP costs - 80,200 -
Regulatory asset - (4,300) -
- -----------------------------------------------------------------
Total postretirement benefit
cost $80,200 $159,300 $65,500
=================================================================
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, 1995 1994
- -----------------------------------------------------------
Actuarial present value of accumulated benefit obligation:
Retired and surviving spouses $214,367 $371,223
Active eligible 24,374 20,400
Active ineligible 397,547 208,900
- ------------------------------------------------------------
Accumulated benefit obligation 636,288 600,523
Plan assets at fair value,
consisting primarily of
listed stocks, bonds and
other fixed obligations (101,721) (36,754)
- -----------------------------------------------------------
Accumulated postretirement
benefit obligation in excess
of plan assets 534,567 563,769
Unrecognized net gain from
actual return on plan assets
different from that assumed 8,713 -
Unrecognized net loss from
past experience different from
that assumed and effects of
changes in assumptions (64,612) (71,939)
Unrecognized transition obligation
being amortized over 20 years (318,596) (337,336)
- -----------------------------------------------------------
Accrued postretirement benefit
liability included in the
consolidated balance sheets $160,072 $154,494
===========================================================
===========================================================
Principal actuarial assumptions (%):
Discount rate 7.50 8.00
Long-term rate of return
on plan assets 9.25 8.75
Health care cost trend rate:
Pre-65 8.25 9.75
Post-65 5.25 6.75
===========================================================
At December 31, 1995, the assumed health cost trend rates
gradually decline to 5.0% in 1999. If the health care cost trend
rate was increased by one percent, the accumulated postretirement
benefit obligation as of December 31, 1995 would increase by
approximately 10.9% and the aggregate of the service and interest
cost component of net periodic postretirement benefit cost for the
year would increase by approximately 13.6%.
On January 1, 1994, the Company adopted SFAS No. 112. This
Statement 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. At December 31, 1995 and 1994, the Company's
postemployment benefit obligation is approximately $12.5 million
and $26.3 million, respectively, including the portion of the
obligation related to the VERP. At December 31, 1995, the Company
has recorded a regulatory asset of approximately $10.4 million, the
majority of which will be recovered over three years beginning in
1995.
NOTE 9. COMMITMENTS AND CONTINGENCIES
See Note 2 and Note 6.
LONG-TERM CONTRACTS FOR THE PURCHASE OF ELECTRIC POWER: At
January 1, 1996, the Company had long-term contracts to purchase
electric power from the following generating facilities owned by
NYPA:
- -----------------------------------------------------------------
Expiration Purchased Estimated
Date of Capacity Annual
Facility Contract in kw. Capacity Cost
- -----------------------------------------------------------------
Niagara - hydroelectric
project 2007 951,000(a) $25,200,000
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(b) 110,000(c) 7,900,000
- -----------------------------------------------------------------
1,435,000 $41,900,000
=================================================================
(a) 943,000 kw for summer of 1996; 951,000 kw for winter of 1996-
97.
(b) The Company has agreed to not terminate or reduce purchases
before May 1, 1997 if NYPA does not increase rates.
(c) 72,000 kw for summer of 1996; 110,000 kw for winter of 1996-
97.
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 $92.5 million, $85.1 million, and $72.2 million for
the years 1995, 1994 and 1993, 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. The Company has virtually all unregulated generator
capacity on line, amounting to approximately 2,708 MW of capacity
at December 31, 1995. Of this amount 2,390 MW is considered firm.
The following table shows the payments for fixed capacity
costs and energy and related taxes the Company estimates it will be
obligated to make under these contracts. The payments are subject
to the tested capacity and availability of the facilities,
scheduling and price escalation.
- ---------------------------------------------------------
(In thousands of dollars)
SCHEDULABLE
FIXED COSTS
------------------
YEAR CAPACITY OTHER ENERGY TOTAL
- ---------------------------------------------------------
1996 $201,000 $40,000 $ 863,000 $1,104,000
1997 213,000 41,000 921,000 1,175,000
1998 237,000 42,000 947,000 1,226,000
1999 241,000 43,000 981,000 1,265,000
2000 229,000 44,000 1,020,000 1,293,000
- ---------------------------------------------------------
The fixed costs relate to contracts with 10 facilities where
the Company is required to make fixed payments, including payments
when a facility is not operating but available for service. These
10 facilities account for approximately 708 MW of capacity, with
contract lengths ranging from 20 to 35 years. The terms of these
contracts allow the Company to schedule energy deliveries from the
facilities and then pay for the energy delivered. The Company
estimates the fixed payments under these contracts will aggregate
to approximately $7.7 billion over their terms, using escalated
contract rates. Contracts relating to the remaining facilities in
service at December 31, 1995, require the Company to pay only when
energy is delivered. The Company currently recovers schedulable
capacity through base rates and energy payments, taxes and other
schedulable fixed costs through the FAC.
The Company paid approximately $980 million, $960 million and
$736 million in 1995, 1994 and 1993 for 14,000,000 MWh, 14,800,000
MWh and 11,720,000 MWh, respectively, of electric power under all
UG contracts.
In an effort to reduce the costs associated with UGs, at
December 31, 1995, the Company had agreed to buy out 17 projects
consisting of 457 MW of capacity. Additionally, the Company has
entered into agreements with 41 projects, comprising 1,153 MW of
capacity, which allow the Company to curtail purchases from these
UGs when demand is low or otherwise provide cost reductions or
operational benefits. The Company expects to continue efforts of
these types into the future, to control its power supply and
related costs, but at this time cannot predict the outcome of such
efforts. (See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Unregulated Generators").
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.
The agreement was amended in September 1995 to allow for sale of an
additional $50 million of customer receivables. The Company sold
this additional $50 million in the fourth quarter of 1995, thereby
bringing the total amount of receivables sold under the agreement
to $250 million. For receivables sold, the Company has retained
collection and administrative responsibilities as agent for the
purchaser. As collections reduce previously sold undivided
interests, new receivables are customarily sold.
At December 31, 1995 and 1994, $250 million and $200 million,
respectively, 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. Under the
terms of the agreement, a formula determines the amount of the loss
reserve. At December 31, 1995, the amount of additional
receivables assigned to the purchaser, as a loss reserve, was
approximately $78.3 million. Although this represents the formula-
based amount of credit exposure at December 31, 1995 under the
agreement, historical losses have been substantially less.
To the extent actual loss experience of the pool receivables
exceeds the loss reserve, the purchaser absorbs the excess.
Concentrations of credit risk to the purchaser with respect to
accounts receivable are limited due to the Company's large, diverse
customer base within its service territory. The Company generally
does not require collateral, i.e., customer deposits.
TAX ASSESSMENTS: The IRS has conducted an examination of the
Company's Federal income tax returns for the years 1987 and 1988
and has submitted a Revenue Agents' Report to the Company. The IRS
has proposed various adjustments to the Company's federal income
tax liability for these years which could increase Federal income
tax liability by approximately $80 million, before assessment of
penalties and interest. Included in these proposed adjustments are
several significant issues involving Unit 2. The Company is
vigorously defending its position on each of the issues, and
submitted a protest to the IRS in 1993. Pursuant to the Unit 2
settlement entered into with the PSC in 1990, to the extent the IRS
is able to sustain adjustments, the Company will be required to
absorb a portion of any assessment. The Company believes any such
disallowance will not have a material impact on its financial
position or results of operations under traditional ratemaking.
The Company is currently attempting to negotiate a settlement of
these issues with the Appeals Division of the IRS.
In addition, the IRS is currently examining the years 1989 and
1990. The Company received a Revenue Agents' Report in late
January 1996. The IRS has raised the issue concerning the
deductibility of advance payments made to UGs in accordance with
certain contracts that include a provision for an Advance Payment
Account. The IRS proposes to disallow a current deduction for
amounts paid in excess of the avoided costs by the Company.
Although the Company believes that any such disallowance for the
years 1989 and 1990 will not have a material impact on its
financial position or results of operations, it believes that a
disallowance for these above-market payments for the years
subsequent to 1990 could have a material adverse affect on its cash
flows. The Company is vigorously defending its position on this
issue.
LITIGATION: The Company is unable to predict the ultimate
disposition of the lawsuits referred to below. However, the
Company believes it has meritorious defenses and intends to defend
these lawsuits vigorously, but can neither provide any judgment
regarding the likely outcome nor provide any estimate or range of
possible loss. Accordingly, no provision for liability, if any,
that may result from these lawsuits has been made in the Company's
financial statements.
(a) In March 1993, Inter-Power of New York, Inc. (Inter-
Power), filed a complaint against the Company and certain
of its officers and employees in the NYS Supreme Court.
Inter-Power alleged, among other matters, fraud,
negligent misrepresentation and breach of contract in
connection with the Company's alleged termination of a
power purchase agreement in January 1993. The plaintiff
sought enforcement of the original contract or
compensatory and punitive damages in an aggregate amount
that would not exceed $1 billion, excluding pre-judgment
interest.
In early 1994, the NYS Supreme Court dismissed two of the
plaintiff's claims; this dismissal was upheld by the
Appellate Division, Third Department of the NYS Supreme
Court. Subsequently, the NYS Supreme Court granted the
Company's motion for summary judgment on the remaining
causes of action in Inter-Power's complaint. In August
1994, Inter-Power appealed this decision and on July 27,
1995, the Appellate Division, Third Department affirmed
the granting of summary judgment as to all counts, except
for one dealing with an alleged breach of the power
purchase agreement relating to the Company's having
declared the agreement null and void on the grounds that
Inter-Power had failed to provide it with information
regarding its fuel supply in a timely fashion. In August
1995, the Company filed a motion to reargue or for leave
to appeal to the Court of Appeals. The Company's motion
was denied on October 25, 1995.
(b) In November 1993, Fourth Branch Associates Mechanicville
(Fourth Branch) filed an action against the Company and
several of its officers and employees in the NYS Supreme
Court, seeking compensatory damages of $50 million,
punitive damages of $100 million and injunctive and other
related relief. The lawsuit grows out of the Company's
termination of a contract for Fourth Branch to operate
and maintain a hydroelectric plant the Company owns in
the Town of Halfmoon, New York. Fourth Branch's
complaint also alleges claims based on the inability of
Fourth Branch and the Company to agree on terms for the
purchase of power from a new facility that Fourth Branch
hoped to construct at the Mechanicville site. In January
1994, the Company filed a motion to dismiss Fourth
Branch's complaint. By order dated November 7, 1995, the
court granted the Company's motion to dismiss the
complaint in its entirety. Fourth Branch has filed an
appeal from the Court's order. Fourth Branch has filed
for protection under Chapter 11 of the Bankruptcy Code in
the Bankruptcy Court for the Northern District of New
York. On January 5, 1996, Fourth Branch vacated the
Mechanicville site.
(c) On June 8, 1994, Medina Power Company (Medina) filed a
lawsuit against the Company in the New York State Supreme
Court, Erie County. Medina alleges, among other claims,
that the Company violated various New York State
antitrust laws in connection with a contract that the
Company has with Medina. On July 11, 1995 Medina amended
its complaint and removed the allegation of antitrust
violations, and is now seeking unspecified damages.
The Company had previously entered into a contract with
Medina, an unregulated generator, for the purchase of
electricity. The original contract required Medina to be
a qualifying facility (QF) under federal law or face a
contractual penalty. Having come on-line without a
thermal host, Medina did not meet this QF requirement,
subjecting it to a 15% rate reduction. The Company
advised Medina that it had exercised its contract right
and reduced the rate accordingly. The Company believes
Medina's lawsuit is without merit, but cannot predict the
outcome of this action.
(d) The Company is involved in a number of court cases
regarding the price of energy it is required to purchase
in excess of contract levels from certain unregulated
generators ("overgeneration"). The Company has paid the
unregulated generators based on its short-run avoided
cost (under Service Class No. 6) for all such
overgeneration rather than the price which the
unregulated generators contend is applicable under the
contracts. At December 31, 1995, this amount of
overgeneration adjustments in dispute that the Company
estimates it has not paid or accrued is approximately $32
million, exclusive of interest. The Company cannot
predict the outcome of these actions, but will continue
to aggressively press its position.
ENVIRONMENTAL CONTINGENCIES: The public utility industry
typically utilizes and/or generates in its operations a broad range
of potentially hazardous wastes and by-products. The Company
believes it is handling identified wastes and by-products in a
manner consistent with Federal, state and local requirements and
has implemented an environmental audit program to identify any
potential areas of concern and assure compliance with such
requirements. The Company is also currently conducting a program
to investigate and restore, as necessary to meet current
environmental standards, certain properties associated with its
former gas manufacturing process and other properties which the
Company has learned may be contaminated with industrial waste, as
well as investigating identified industrial waste sites as to which
it may be determined that the Company contributed. The Company has
also been advised that various Federal, state or local agencies
believe certain properties require investigation and has
prioritized the sites based on available information in order to
enhance the management of investigation and remediation, if
necessary.
The Company is currently aware of 88 sites with which it has
been or may be associated, including 46 which are Company-owned.
With respect to non-owned sites, the Company may be required to
contribute some proportionate share of remedial costs.
Investigations at each of the Company-owned sites are designed
to (1) determine if environmental contamination problems exist, (2)
if necessary, determine the appropriate remedial actions required
for site restoration and (3) where appropriate, identify other
parties who should bear some or all of the cost of remediation.
Legal action against such other parties will be initiated where
appropriate. After site investigations are completed, the Company
expects to determine site-specific remedial actions and to estimate
the attendant costs for restoration. However, since technologies
are still developing, the ultimate cost of remedial actions may
change substantially.
Estimates of the cost of remediation and post-remedial
monitoring are based upon a variety of factors, including
identified or potential contaminants, location, size and use of the
site, proximity to sensitive resources, status of regulatory
investigation and knowledge of activities at similarly situated
sites, and the EPA figure for average cost to remediate a site.
Actual Company expenditures are dependent upon the total cost of
investigation and remediation and the ultimate determination of the
Company's share of responsibility for such costs, as well as the
financial viability of other identified responsible parties since
clean-up obligations are joint and several. The Company has denied
any responsibility in certain of these PRP sites and is contesting
liability accordingly.
As a consequence of site characterizations and assessments
completed to date and negotiations with PRP's, the Company has
accrued a liability in the amount of $225 million and $240 million,
which is reflected in the Company's balance sheets at December 31,
1995 and 1994, respectively. The liability was reduced in 1995 to
reflect the Company's current estimate, which incorporates the
recent availability of better information regarding the cost to
remediate one of its major sites, the Saratoga Springs manufactured
gas plant site, since a Record of Decision was issued by the EPA at
that site. The Saratoga Springs site is included on the National
Priority's List. This liability represents the low end of the
range of its share of the estimated cost for investigation and
remediation. The potential high end of the range is presently
estimated at approximately $930 million, including approximately
$430 million in the unlikely event the Company is required to
assume 100% responsibility at non-owned sites.
Prior to 1995, the Company recovered 100% of its costs
associated with site investigation and restoration. In the
Company's 1995 rate order, costs incurred during 1995 for the
investigation and restoration of Company-owned sites and sites with
which it is associated were subject to 80%/20% (ratepayer/ Company)
sharing. In 1995, the Company incurred $11.5 million of such
costs, resulting in a disallowance of $2.3 million (before tax),
which the Company has recognized as a loss in Other items (net) on
the Consolidated Statements of Income. The PSC stated in its
opinion, dated December 1995, its decision to require sharing was
"on a one-time, short-term basis only, pending its further
evaluation of the issue in future proceedings." The Company has
recorded a regulatory asset representing the remediation
obligations to be recovered from ratepayers.
Where appropriate, the Company has provided notices of
insurance claims to carriers with respect to the investigation and
remediation costs for manufactured gas plant, industrial waste
sites and sites for which the Company has been identified as a PRP.
The Company is unable to predict whether such insurance claims will
be successful.
CONSTRUCTION PROGRAM: The Company is committed to an ongoing
construction program to assure delivery of its electric and gas
services. The Company presently estimates that the construction
program for the years 1996 through 2000 will require approximately
$1.5 billion, excluding AFC and nuclear fuel. For the years 1996
through 2000, the estimates are $290 million, $295 million, $307
million, $306 million and $290 million, respectively, which
includes $42 million, $46 million, $58 million, $49 million and
$40 million, respectively, related to generation. These amounts
are reviewed by management as circumstances dictate.
NOTE 10. 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.
SHORT-TERM DEBT: The carrying amount approximates fair value
because of the short-term nature of the borrowings.
LONG-TERM INVESTMENTS: The carrying value and market value
are not material to the financial statements.
LONG-TERM DEBT AND MANDATORILY REDEEMABLE PREFERRED STOCK:
The fair value of fixed rate long-term debt and redeemable
preferred stock is estimated using quoted market prices where
available or discounting remaining cash flows at the Company's
incremental borrowing rate. The carrying value of NYSERDA bonds
and other long-term debt are considered to approximate fair value.
The financial instruments held or issued by the Company are for purposes other than
trading. The estimated fair values of the Company's financial instruments are as follows:
- ------------------------------------------------------------------------------------------
(In thousands of dollars)
-------------------------------------------------
At December 31, 1995 1994
- ------------------------------------ --------------------- ----------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- ------------------------------------ --------------------- ----------------------
Cash and short-term
investments $ 153,475 $ 153,475 $ 94,330 $ 94,330
Short-term debt - - 416,750 416,750
Mandatorily redeemable
preferred stock 106,000 92,676 116,950 134,692
Long-term debt: First Mortgage bonds 2,866,305 2,815,206 2,611,305 2,367,755
Medium Term notes 30,000 31,826 45,000 45,783
NYSERDA bonds 413,760 413,760 413,760 413,760
Swiss franc bond - - 50,000 83,682
Other 292,436 292,436 224,107 224,107
On January 1, 1994, the Company adopted Statement of Financial
Accounting Standards No. 115, "Accounting for Certain Investments
in Debt and Equity Securities." This statement addresses the
accounting and reporting for investments in equity securities that
have readily determinable fair values and for all investments in
debt securities. The Company's investments in debt and equity
securities consist of trust funds for the purpose of funding the
nuclear decommissioning of Unit 1 and its share of Unit 2 (See Note
3 - "Nuclear Plant Decommissioning"), short-term investments held
by Opinac (a subsidiary) and a trust fund for certain pension
benefits. The Company has classified all investments in debt and
equity securities as available for sale and has recorded all such
investments at their fair market value at December 31, 1995. The
proceeds from the sale of investments were $70.3 million and $104.6
million in 1995 and 1994, respectively. Net realized and
unrealized gains and losses related to the nuclear decommissioning
trust are reflected in Accumulated depreciation and amortization on
the Consolidated Balance Sheets, which is consistent with the
method used by the Company to account for the decommissioning costs
recovered in rates. The unrealized gains and losses related to the
investments held by Opinac and the pension trust are included, net
of tax, in stockholders' equity on the Consolidated Balance Sheets,
while the realized gains and losses are included in Other items
(net) on the Consolidated Income Statements. The recorded fair
values and cost basis of the Company's investments in debt and
equity securities is as follows:
- ------------------------------------------------------------------------------------------
(In thousands of dollars)
-----------------------------------------------------------------------
At December 31, 1995 1994
- --------------- ---------------------------------- ---------------------------------
Gross Gross
Unrealized Fair Unrealized Fair
Security Type Cost Gain (Loss) Value Cost Gain (Loss) Value
- --------------- ---------------------------------- ---------------------------------
U.S. Government
Obligations $ 16,271 $ 3,009 $ - $ 19,280 $15,165 $ 19 $ (325) $14,859
Commercial Paper 47,105 1,019 - 48,124 - - - -
Tax Exempt
Obligations 66,155 3,830 (72) 69,913 45,029 659 (1,778) 43,910
Corporate
Obligations 45,279 5,399 (344) 50,334 27,407 9 (1,253) 26,163
Other 10,022 945 - 10,967 8,121 28 (348) 7,801
-------- -------- ----- -------- ------- ---- ------- -----
$184,832 $14,202 $(416) $198,618 $95,722 $715 $(3,704) $92,733
======== ======= ====== ======== ======== ===== ======= =======
Using the specific identification method to determine cost,
the gross realized gains and gross realized losses were:
In thousands of dollars
-----------------------
Year Ended December 31, 1995 1994
- ----------------------- ---- ----
Realized gains $2,523 $1,123
Realized losses $ 328 $1,637
The contractual maturities of the Company's investments in
debt securities is as follows:
- ---------------------------------------------------------
At December 31, 1995
-----------------------------
(In thousands of dollars)
-----------------------------
Fair Value Cost
- ---------------------------------------------------------
Less than 1 year $48,124 $47,105
1 year to 5 years 10,308 9,689
5 years to 10 years 31,759 30,066
Due after 10 years 83,112 75,348
NOTE 11. INFORMATION REGARDING THE ELECTRIC AND GAS BUSINESSES
The Company is engaged principally in the business of
production, purchase, transmission, distribution and sale of
electricity and the purchase, distribution, sale and transportation
of gas in New York State. The Company provides 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 or transports 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. Certain information regarding the Company's electric and
natural gas 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 the practice established for regulatory
purposes. Identifiable assets include net utility plant, materials
and supplies, deferred finance charges, deferred recoverable energy
costs and certain other regulatory and other assets. Corporate
assets consist of other property and investments, cash, accounts
receivable, prepayments, unamortized debt expense and certain other
regulatory and other assets. At December 31, 1995, total plant
assets consisted of 24.1% Nuclear, 16.7% Generation, 41.5%
Transmission and Distribution, 4.5% Hydro and 10.3% Gas and 2.9%
Common.
In thousands of dollars
-----------------------
1995 1994 1993
---- ---- ----
Operating revenues:
Electric $3,335,548 $3,528,987 $3,332,464
Gas 581,790 623,191 600,967
- -----------------------------------------------------------------
Total $3,917,338 $4,152,178 $3,933,431
=================================================================
Operating income before taxes:
Electric $ 587,282 $ 466,978* $ 625,852
Gas 96,752 83,229 61,163
- -----------------------------------------------------------------
Total $ 684,034 $ 550,207 $ 687,015
=================================================================
Pretax operating income, including AFC:
Electric $ 595,970 $ 475,694 $ 641,435
Gas 97,114 83,592 61,812
- -----------------------------------------------------------------
Total 693,084 559,286 703,247
- -----------------------------------------------------------------
Income taxes, included in operating expenses:
Electric 129,861 97,417 148,695
Gas 26,147 20,417 13,820
- -----------------------------------------------------------------
Total 156,008 117,834 162,515
- -----------------------------------------------------------------
Other (income) and
deductions 1,379 (21,410) (22,475)
Interest charges 287,661 285,878 291,376
- -----------------------------------------------------------------
Net income $ 248,036 $ 176,984 $ 271,831
=================================================================
Depreciation and amortization:
Electric $ 292,995 $ 283,694 $ 255,718
Gas 24,836 24,657 20,905
- -----------------------------------------------------------------
Total $ 317,831 $ 308,351 $ 276,623
=================================================================
Construction expenditures (including nuclear fuel):
Electric $ 285,722 $ 376,159 $ 429,265
Gas 60,082 113,965 90,347
- -----------------------------------------------------------------
Total $ 345,804 $ 490,124 $ 519,612
=================================================================
Identifiable assets:
Electric $7,592,287 $7,759,549 $7,700,888
Gas 1,123,045 1,093,812 1,008,272
- -----------------------------------------------------------------
Total 8,715,332 8,853,361 8,709,160
Corporate assets 762,537 796,455 762,167
- -----------------------------------------------------------------
Total assets $9,477,869 $9,649,816 $9,471,327
=================================================================
* Includes $196,625 of VERP expenses.
NOTE 12. QUARTERLY FINANCIAL DATA (UNAUDITED)
Operating revenues, operating income, net income and earnings
per common share by quarters from 1995, 1994 and 1993,
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
OPERATING NET (LOSS)
OPERATING INCOME INCOME PER COMMON
QUARTER ENDED REVENUES (LOSS) (LOSS) SHARE
- ----------------------------------------------------------------
December 31, 1995 $ 966,478 $113,510 $ 27,874 $ .13
1994 1,018,110 (10,536) (77,422) (.61)
1993 988,195 95,623 30,955 .16
- ----------------------------------------------------------------
September 30, 1995 $ 887,231 $114,126 $ 46,941 $ .26
1994 918,810 108,937 48,383 .27
1993 879,952 108,539 48,595 .29
- ----------------------------------------------------------------
June 30, 1995 $ 938,816 $121,985 $ 54,485 $ .31
1994 979,700 130,624 67,559 .42
1993 929,245 132,669 65,325 .41
- ----------------------------------------------------------------
March 31, 1995 $1,124,813 $178,405 $118,736 $ .75
1994 1,235,558 203,348 138,464 .92
1993 1,136,039 187,669 126,956 .86
- ----------------------------------------------------------------
In the fourth quarter of 1994 the Company recorded $196.6
million (89 cents per common share) for the electric expense
allocation of the VERP. In the third quarter of 1993 and the
fourth quarters of 1994 and 1995, the Company recorded $10.3
million (5 cents per common share), $12.3 million (6 cents per
common share), and $16.9 million (8 cents per common share),
respectively, for MERIT earned in accordance with the 1991
Agreement.
NOTE 13. SUBSEQUENT EVENT (UNAUDITED)
On March 14, 1996, the PSC approved the Company's petition
which requested authorization of a senior debt facility for the
purpose of consolidating and refinancing certain of the Company's
existing working capital lines of credit and letter of credit
facilities and providing additional reserves of bank credit. This
senior debt facility will enhance the Company's financial
flexibility during the period 1996 through June 1999.
Subsequently, the Company completed the $813.7 million senior debt
facility with the bank group. The senior debt facility consists of
a $255 million term loan facility, a $125 million revolving credit
facility and $434 million for letters of credit and other purposes.
The letter of credit facility provides credit support for $414
million of outstanding pollution control revenue bonds issued
through NYSERDA. The interest rate applicable to the senior debt
facility currently approximates 7 1/4% and is calculated on the
basis of a percentage margin over either London Interbank Offered
Rates or the agent banks' base rate capped at 15%. The term loan
facility, the revolving credit facility, the letter of credit
facility and certain indemnifications are collateralized by the
Company's first mortgage bonds. The facility expires on June 30,
1999 (subject to earlier termination upon the implementation of the
Company's PowerChoice restructuring proposal or any other
significant restructuring plan).
ELECTRIC AND GAS STATISTICS
ELECTRIC CAPABILITY
Thousands of kilowatts
----------------------
December 31, 1995 % 1994 1993
- ------------------------------------------------------------
Owned:
Coal 1,316 16.0 1,285 1,285
Oil 636 7.7 646 1,496
Dual Fuel - Oil/Gas 700 8.5 700 700
Nuclear 1,082 13.2 1,048 1,048
Hydro 665 8.1 700 700
Natural Gas - - - 74
----- ---- ----- -----
4,399 53.5 4,379 5,303
----- ---- ----- -----
Purchased:
New York Power Authority
- Hydro 1,325 16.1 1,300 1,302
- Nuclear 110 1.3 74 65
Unregulated
generators 2,390 29.1 2,273 2,253
----- ---- ----- -----
3,825 46.5 3,647 3,620
----- ---- ----- -----
Total capability* 8,224 100.0 8,026 8,923
===== ===== ===== =====
Electric peak load 6,211 6,458 6,191
===== ===== =====
* 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
1995 1994 1993
- ----------------------------------------------------------------
Electric sales (Millions of kw-hrs.):
Residential 10,150 10,415 10,475
Commercial 11,684 11,813 12,079
Industrial 7,126 7,445 7,088
Industrial-Special 4,053 4,118 3,888
Municipal service 215 215 220
Other electric systems 4,456 7,593 3,974
- -----------------------------------------------------------------
37,684 41,599 37,724
Electric revenues (Thousands of dollars):
Residential $1,221,105 $1,233,007 $1,171,787
Commercial 1,241,479 1,272,234 1,241,743
Industrial 527,244 577,473 553,921
Industrial-Special 56,250 49,217 42,988
Municipal service 49,543 50,007 50,642
Other electric systems 95,812 167,131 105,044
Miscellaneous 144,115 179,918 166,339
- -----------------------------------------------------------------
$3,335,548 $3,528,987 $3,332,464
Electric customers (Average):
Residential 1,411,953 1,405,343 1,398,756
Commercial 145,965 144,249 143,078
Industrial 2,159 2,105 2,132
Industrial-Special 83 82 76
Other 1,497 2,318 3,438
- -----------------------------------------------------------------
1,561,657 1,554,097 1,547,480
Residential (Average):
Annual kw-hr. use per customer 7,189 7,411 7,489
Cost to customer per kw-hr.
(in cents) 12.03 11.84 11.19
Annual revenue per customer $864.83 $877.37 $837.74
GAS STATISTICS
1995 1994 1993
- -----------------------------------------------------------------
Gas Sales (Thousands of dekatherms):
Residential 51,842 56,491 54,908
Commercial 23,818 25,783 23,743
Industrial 2,660 3,097 4,316
Other gas systems 161 244 234
- -----------------------------------------------------------------
Total sales 78,481 85,615 83,201
Spot market 1,723 1,572 13,223
Transportation of customer-
owned gas 144,613 85,910 67,741
- -----------------------------------------------------------------
Total gas delivered 224,817 173,097 164,165
Gas Revenues (Thousands of dollars):
Residential $ 368,391 $ 398,257 $ 370,565
Commercial 143,643 159,157 144,834
Industrial 11,530 14,602 18,482
Other gas systems 762 1,159 1,066
Spot market 3,096 4,370 29,782
Transportation of customer-
owned gas 48,290 38,346 34,843
Miscellaneous 6,078 7,300 1,395
- -----------------------------------------------------------------
$ 581,790 $ 623,191 $ 600,967
Gas Customers (Average):
Residential 471,948 463,933 455,629
Commercial 40,945 40,256 39,662
Industrial 225 256 233
Other 1 1 1
Transportation 652 661 673
- -----------------------------------------------------------------
513,771 505,107 496,198
Residential (Average):
Annual dekatherm use
per customer 109.8 121.8 120.5
Cost to customer per dekatherm $ 7.11 $ 7.05 $ 6.75
Annual revenue per customer $780.58 $858.44 $813.30
Maximum day gas sendout
(dekatherms) 1,211,252 995,801 929,285
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE.
The Company has nothing to report for this item.
PART III
- --------
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Incorporated herein by reference to the information under the
captions "Business Background of Nominees and Directors" and
"Section 16(a) Compliance" in the Company's Proxy Statement dated
March 25, 1996. The information regarding executive officers
appears at the end of Part I of this Form 10-K Annual Report.
ITEM 11. EXECUTIVE COMPENSATION.
Incorporated herein by reference to the information under the
captions "Board of Directors' Compensation and Succession Committee
Report on Executive Compensation," "Executive Compensation,"
"Compensation of Directors" and "Compensation and Succession
Committee Interlocks and Insider Participation; Certain
Relationships and Related Transactions" in the Company's Proxy
Statement dated March 25, 1996.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT.
Incorporated herein by reference to the information under the
caption "Security Ownership of Certain Beneficial Owners and
Management" in the Company's Proxy Statement dated March 25, 1996.
The Company knows of no arrangements including any pledges by any
person of its securities, the operation of which may at a
subsequent date result in a change of control of the Company.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Incorporated herein by reference to the information under the
captions "Compensation of William E. Davis, Chairman of the Board
and Chief Executive Officer," "Employee Agreements" and
"Compensation and Succession Committee Interlocks and Insider
Participation; Certain Relationships and Related Transactions" in
the Company's Proxy Statement dated March 25, 1996.
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, 1995
Consolidated Balance Sheets at December 31, 1995 and 1994
Consolidated Statements of Cash Flows for each of the
three years in the period ended December 31, 1995
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 wholly-owned directly or by
subsidiaries.
(2) The following financial statement schedules of the Company for
the years ended December 31, 1995, 1994 and 1993 are included:
Report of Independent Accountants on Financial
Statement Schedule
Consolidated Financial Statement Schedule:
II--Valuation and Qualifying Accounts and Reserves
The Financial Statement Schedule above should be read in
conjunction with the Consolidated Financial Statements in Part
II, Item 8 (Financial Statements and Supplementary Data).
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.
(3) List of Exhibits:
See Exhibit Index.
(b) Reports on Form 8-K:
Form 8-K Reporting Date - March 5, 1996.
Items Reported - Item 5. Other Events.
Registrant filed certain financial information substantially
constituting a portion of its 1995 Annual Report to
Stockholders including financial statements for the fiscal
year ended December 31, 1995.
(c) Exhibits.
See Exhibit Index.
(d) Financial Statement Schedule.
See (a)(2) above.
REPORT OF INDEPENDENT ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULE
- -----------------------------------------------------------------
To the Board of Directors of
Niagara Mohawk Power Corporation
Our audits of the consolidated financial statements of Niagara
Mohawk Power Corporation referred to in our report dated January
25, 1996 appearing in this Form 10-K also included an audit of the
Financial Statement Schedule listed in Item 14(a) of this Form 10-
K. In our opinion, this Financial Statement Schedule presents
fairly, in all material respects, the information set forth therein
when read in conjunction with the related consolidated financial
statements.
/s/ PRICE WATERHOUSE LLP
Syracuse, New York
January 25, 1996
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- ------------------------------------------------------------
(In Thousands of Dollars)
Column A Column B Column C Column D Column E
- ------------------------ ---------- ---------------------- ---------- ---------
Additions
----------------------
Balance at Charged to Charged to Balance
Beginning Costs and Other at End
Description of Period Expenses Accounts Deductions of Period
- ------------------------ ---------- ---------- ---------- ---------- ---------
Allowance for Doubtful
Accounts - deducted from
Accounts Receivable in
the Consolidated Balance
Sheets
1995 $3,600 $31,284 $16,400 (a) $31,284 (b) $20,000
1994 3,600 39,599 - 39,599 (b) 3,600
1993 3,600 37,200 - 37,200 (b) 3,600
(a) The Company increased its allowance for doubtful accounts in 1995 and recorded a
regulatory asset of $16.4 million, which reflects the amount that the Company expects
to recover in rates.
(b) Uncollectible accounts written off net of recoveries of $10,830, $7,969 and $9,704 in
1995, 1994 and 1993, respectively.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- ------------------------------------------------------------
(In Thousands of Dollars)
Column A Column B Column C Column D Column E
- ------------------------ ---------- ---------------------- ---------- ---------
Additions
----------------------
Balance at Charged to Charged to Balance
Beginning Costs and Other at End
Description of Period Expenses Accounts Deductions of Period
- ------------------------ ---------- ---------- ---------- ---------- ---------
Reserve for Loss on
Investment -
NM Uranium, Inc. -
deducted from Utility
Plant, Nuclear Fuel
in the Consolidated Balance
Sheets
1995 $58,200 $3,805 $ - $52,642 (c) $ 9,363
1994 56,300 1,900 - - 58,200
1993 53,000 3,300 - - 56,300
(c) Represents the portion of the investment charged to the reserve.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- ------------------------------------------------------------
(In Thousands of Dollars)
Column A Column B Column C Column D Column E
- ------------------------ ---------- ---------------------- ---------- ---------
Additions
----------------------
Balance at Charged to Charged to Balance
Beginning Costs and Other at End
Description of Period Expenses Accounts Deductions of Period
- ------------------------ ---------- ---------- ---------- ---------- ---------
Reserve for Loss on
oil and gas operations -
Opinac Energy Corp. -
deducted from
Other Property and
Investments in
the Consolidated Balance
Sheets
1995 $ - $ - $ - $ - $ -
1994 - - - - -
1993 65,837 - - 65,837 (d) -
(d) Represents the reversal of the total reserve upon sale of the oil and gas operations in
June 1993.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- ------------------------------------------------------------
(In Thousands of Dollars)
Column A Column B Column C Column D Column E
- ------------------------ ---------- ---------------------- ---------- ---------
Additions
----------------------
Balance at Charged to Charged to Balance
Beginning Costs and Other at End
Description of Period Expenses Accounts Deductions of Period (e)
- ------------------------ ---------- ---------- ---------- ---------- ---------
Miscellaneous
Valuation Reserves
1995 $29,197 $18,719 $ - $8,490 $39,426
1994 9,167 20,030 - - 29,197
1993 1,407 7,760 - - 9,167
(e) The reserve relates primarily to certain inventory and non-rate base properties.
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;
V--NMPC Registration Statement No. 2-10501;
X--NMPC Registration Statement No. 2-12443;
Z--NMPC Registration Statement No. 2-13285;
CC--NMPC Registration Statement No. 2-16193;
DD--NMPC Registration Statement No. 2-18995;
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;
OO--NMPC Registration Statement No. 2-49570;
QQ--NMPC Registration Statement No. 2-51934;
SS--NMPC Registration Statement No. 2-52852;
TT--NMPC Registration Statement No. 2-54017;
VV--NMPC Registration Statement No. 2-59500;
CCC--NMPC Registration Statement No. 2-70860;
III--NMPC Registration Statement No. 2-90568;
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;
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; and
d--NMPC Annual Report on Form 10-K for year ended December 31,
1993; and
e--NMPC Annual Report on Form 10-K for year ended December 31,
1994.
f--NMPC Quarterly Report on Form 10-Q for quarter ended March 31,
1993; and
g--NMPC Quarterly Report on Form 10-Q for quarter ended September
30, 1993; and
h--NMPC Quarterly Report on Form 10-Q for quarter ended June 30,
1995.
INCORPORATION BY REFERENCE
----------------------------------
PREVIOUS PREVIOUS EXHIBIT
EXHIBIT NO. DESCRIPTION OF INSTRUMENT FILING 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. e 3(a)(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. e 3(a)(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. e 3(a)(3)
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. e 3(a)(4)
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. e 3(a)(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. e 3(a)(6)
3(a)(7) --Certificate of NMPC pursuant to Section
11 of the Stock Corporation Law of New
York, filed February 18, 1958 in the office
of the New York Secretary of State. e 3(a)(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. e 3(a)(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. e 3(a)(9)
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. e 3(a)(10)
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. e 3(a)(11)
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. e 3(a)(12)
3(a)(13) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York, filed August 18, 1972 in the
office of the New York Secretary of State. e 3(a)(13)
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. e 3(a)(14)
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. e 3(a)(15)
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. e 3(a)(16)
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. e 3(a)(17)
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. e 3(a)(18)
3(a)(19) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York, filed May 7, 1976 in the
office of the New York Secretary of State. e 3(a)(19)
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. e 3(a)(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. e 3(a)(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. e 3(a)(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. e 3(a)(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. e 3(a)(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 March 3, 1980 in the
office of the New York Secretary of State. e 3(a)(25)
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. e 3(a)(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. e 3(a)(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. e 3(a)(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. e 3(a)(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. e 3(a)(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. e 3(a)(31)
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. e 3(a)(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. e 3(a)(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. e 3(a)(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. e 3(a)(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. e 3(a)(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. e 3(a)(37)
3(a)(38) --Certificate of Amendment of Certificate
of Incorporation of NMPC 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. e 3(a)(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. e 3(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. e 3(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. e 3(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. e 3(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. e 3(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 October 18, 1991 in the
office of the New York Secretary of State. e 3(a)(44)
3(a)(45) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed May 5, 1994 in the
office of the New York Secretary of State. e 3(a)(45)
3(a)(46) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed August 5, 1994 in the
office of the New York Secretary of State. e 3(a)(46)
3(b) --By-Laws of NMPC. e 3(b)
4(a) --Agreement to furnish certain debt
instruments. e 4(b)
4(b)(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 **
_________________________
** Filed October 15, 1937 after effective date of Registration Statement No. 2-3414.
4(b)(2) --Supplemental Indenture dated as of
December 1, 1938, supplemental to
Exhibit 4(1). VV 2-3
4(b)(3) --Supplemental Indenture dated as of
April 15, 1939, supplemental to
Exhibit 4(1). VV 2-4
4(b)(4) --Supplemental Indenture dated as of
July 1, 1940, supplemental to
Exhibit 4(1). VV 2-5
4(b)(5) --Supplemental Indenture dated as of
October 1, 1944, supplemental to
Exhibit 4(1). G 7-6
4(b)(6) --Supplemental Indenture dated as of
June 1, 1945, supplemental to
Exhibit 4(1). VV 2-8
4(b)(7) --Supplemental Indenture dated as of
August 17, 1948, supplemental to
Exhibit 4(1). VV 2-9
4(b)(8) --Supplemental Indenture dated as of
December 31, 1949, supplemental to
Exhibit 4(1). A 7-9
4(b)(9) --Supplemental Indenture dated as of
January 1, 1950, supplemental to
Exhibit 4(1). A 7-10
4(b)(10) --Supplemental Indenture dated as of
October 1, 1950, supplemental to
Exhibit 4(1). C 7-11
4(b)(11) --Supplemental Indenture dated as of
October 19, 1950, supplemental to
Exhibit 4(1). C 7-12
4(b)(12) --Supplemental Indenture dated as of
February 20, 1953, supplemental to
Exhibit 4(1). V 4-16
4(b)(13) --Supplemental Indenture dated as of
April 25, 1956, supplemental to
Exhibit 4(1). X 4-19
4(b)(14) --Supplemental Indenture dated as of
March 15, 1960, supplemental to
Exhibit 4(1). CC 2-23
4(b)(15) --Supplemental Indenture dated as of
October 1, 1966, supplemental to
Exhibit 4(1). GG 2-27
4(b)(16) --Supplemental Indenture dated as of
July 15, 1967, supplemental to
Exhibit 4(1). HH 4-29
4(b)(17) --Supplemental Indenture dated as of
August 1, 1967, supplemental to
Exhibit 4(1). HH 4-30
4(b)(18) --Supplemental Indenture dated as of
August 1, 1968, supplemental to
Exhibit 4(1). II 2-30
4(b)(19) --Supplemental Indenture dated as of
March 15, 1977, supplemental to
Exhibit 4(1). VV 2-39
4(b)(20) --Supplemental Indenture dated as of
August 1, 1977, supplemental to
Exhibit 4(1). CCC 4(b)(40)
4(b)(21) --Supplemental Indenture dated as of
March 1, 1978, supplemental to
Exhibit 4(1). CCC 4(b)(42)
4(b)(22) --Supplemental Indenture dated as of
June 15, 1980, supplemental to
Exhibit 4(1). CCC 4(b)(46)
4(b)(23) --Supplemental Indenture dated as of
November 1, 1985, supplemental to
Exhibit 4(1). III 4(b)(64)
4(b)(24) --Supplemental Indenture dated as of
October 1, 1989, supplemental to
Exhibit 4(1). OOO 4(b)(73)
4(b)(25) --Supplemental Indenture dated as of
June 1, 1990, supplemental to
Exhibit 4(1). PPP 4(b)(74)
4(b)(26) --Supplemental Indenture dated as of
November 1, 1990, supplemental to
Exhibit 4(1). PPP 4(b)(75)
4(b)(27) --Supplemental Indenture dated as of
March 1, 1991, supplemental to
Exhibit 4(1). QQQ 4(b)(76)
4(b)(28) --Supplemental Indenture dated as of
October 1, 1991, supplemental to
Exhibit 4(1). QQQ 4(b)(77)
4(b)(29) --Supplemental Indenture dated as of
April 1, 1992, supplemental to
Exhibit 4(1). QQQ 4(b)(78)
4(b)(30) --Supplemental Indenture dated as of
June 1, 1992, supplemental to
Exhibit 4(1). RRR 4(b)(79)
4(b)(31) --Supplemental Indenture dated as of
July 1, 1992, supplemental to
Exhibit 4(1). RRR 4(b)(80)
4(b)(32) --Supplemental Indenture dated as of
August 1, 1992, supplemental to
Exhibit 4(1). RRR 4(b)(81)
4(b)(33) --Supplemental Indenture dated as of
April 1, 1993, supplemental to
Exhibit 4(1). f 4(b)(82)
4(b)(34) --Supplemental Indenture dated as of
July 1, 1993, supplemental to
Exhibit 4(1). g 4(b)(83)
4(b)(35) --Supplemental Indenture dated as of
September 1, 1993, supplemental to
Exhibit 4(1). g 4(b)(84)
4(b)(36) --Supplemental Indenture dated as of
March 1, 1994, supplemental to
Exhibit 4(1). d 4(b)(85)
4(b)(37) --Supplemental Indenture dated as of
July 1, 1994, supplemental to
Exhibit 4(1). e 4(86)
4(b)(38) --Supplemental Indenture dated as of
May 1, 1995, supplemental to
Exhibit 4(1). h 4(87)
4(b)(39) --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. DD 13-6
10-3 --Agreement dated July 26, 1961
between the Power Authority of the
State of New York and NMPC
supplemental to Exhibit 10-2. DD 13-7
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. KK 5-8
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
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. SS 5-13
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. SS 5-13
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 utilities
with respect to Nine Mile Point Nuclear
Station Unit No. 2. SS 5-14
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. VV 5-14b
10-9c --Nine Mile Point Nuclear Station Unit
No. 2 Operating Agreement. c 10-19
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. SS 5-15
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
(A)10-11 --NMPC Officers' Incentive Compensation Plan -
Plan Document. b 10-16
(A)10-12 --NMPC Management Incentive Compensation Plan -
Plan Document. b 10-17
(A)10-13 --NMPC 1990 Stock Award Plan. b 10-18
(A)10-14 --NMPC Deferred Compensation Plan. d 10-16
(A)10-15 --NMPC Performance Share Unit Plan. d 10-17
(A)10-16 --NMPC 1992 Stock Option Plan. d 10-18
(A)10-17 --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. d 10-19
(A)10-18 --Employment Agreement between NMPC and
John M. Endries, President, dated
January 1, 1993, including letter
dated January 24, 1994. d 10-20
(A)10-19 --Employment Agreement between NMPC and
B. Ralph Sylvia, Executive Vice
President, Nuclear, dated January 1,
1993, including letter dated
January 24, 1994. d 10-21
(A)10-20 --Employment Agreement between NMPC and
David J. Arrington, Sr. Vice President,
Human Resources, dated January 1, 1993,
including letter dated January 24, 1994. d 10-22
(A)10-21 --Employment Agreement between NMPC and
Darlene D. Kerr, Sr. Vice President,
Electric Customer Service, dated
January 1, 1994. d 10-23
(A)10-22 --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. d 10-24
(A)10-23 --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. d 10-26
(A)10-23(a) --Amendment to employment agreement between
NMPC and John W. Powers, Sr. Vice
President, Finance and Corporate Services,
dated November 8, 1994. e 10-23(a)
(A)10-24 --Employment Agreement between NMPC and
Michael P. Ranalli, Sr. Vice President,
Electric Supply & Delivery, dated
January 1, 1993, including letter dated
January 24, 1994. d 10-27
(A)10-25 --Agreement for Consulting Services between
NMPC and William J. Donlon, effective
July 15, 1993. d 10-28
*(A)10-26 --Employment Agreement between NMPC and
Albert J. Budney, Jr., President and
Chief Operating Officer, dated April 1, 1995.
*(A)10-27 --Amendment to employment agreement between
NMPC and David J. Arrington, Sr. Vice
President, Human Resources, dated October 10,
1995.
*(A)10-28 --Amendment to employment agreement between
NMPC and William E. Davis, Chairman of the
Board and Chief Executive Officer, dated
October 10, 1995.
*(A)10-29 --Amendment to employment agreement between
NMPC and Gary J. Lavine, Sr. Vice President -
Legal and Corporate Relations, dated October 10,
1995.
*(A)10-30 --Amendment to employment agreement between
NMPC and B. Ralph Sylvia, Executive Vice
President - Electric Generation and Chief
Nuclear Officer, dated October 10, 1995.
*(A)10-31 --NMPC 1995 Stock Incentive Plan.
*11 --Statement setting forth the computation of
average number of shares of common stock
outstanding.
*12 --Statements Showing Computations of Certain
Financial Ratios.
*21 --Subsidiaries of the Registrant.
*23 --Consent of Price Waterhouse LLP,
independent accountants.
99(1) --Form 11-K Annual Report of the Employee
Savings Fund Plan for Represented Employees
of Niagara Mohawk Power Corporation for To be filed at
Fiscal Year Ended December 31, 1995. 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, 1995. a later date.
- -------------------------
(A) Management contract or compensatory plan or arrangement required to be filed as an
exhibit pursuant to Item 601 of Regulation S-K.
EXHIBIT 10-26
- -------------
EMPLOYMENT AGREEMENT
- --------------------
Agreement made as of the 1st day of April, 1995, between
Niagara Mohawk Power Corporation (the "Company"), and Albert J.
Budney, Jr. (the "Executive").
WHEREAS, the Company desires to employ the Executive, and the
Executive desires to accept/continue employment with the Company,
on the terms and conditions hereinafter set forth.
NOW, THEREFORE, in consideration of the mutual covenants and
agreements hereinafter set forth, the Company and the Executive
hereby agree as follows:
1. The Company shall employ the Executive, and the Executive
shall serve the Company, for the period beginning April 1, 1995 and
expiring on March 31, 1998. The term of this Agreement will be
extended by one year at the completion of each full year of
employment, unless either party notifies the other to the contrary
not later than sixty (60) days prior to the completion of the full
year of employment.
2. The Executive shall serve the Company as its President and
Chief Operating Officer. During the term of this Agreement, the
Executive shall, except during vacation or sick leave, devote the
whole of the Executive's time, attention and skill during usual
business hours (and outside those hours when reasonably necessary
to the Executive's duties hereunder); faithfully and diligently
perform such duties and exercise such powers as may be from time to
time assigned to or vested in the Executive by the Company's Board
of Directors (the "Board") or by any officer of the Company
superior to the Executive; obey the directions of the Board and of
any officer of the Company superior to the Executive; and use the
Executive's best efforts to promote the interests of the Company.
The Executive may be required in pursuance of the Executive's
duties hereunder to perform services for any company controlling,
controlled by or under common control with the Company (such
companies hereinafter collectively called "Affiliates") and to
accept such offices in any Affiliates as the Board may require.
The Executive shall obey all policies of the Company and applicable
policies of its Affiliates.
3. a. During the term of this Agreement, the Company shall
pay the Executive a salary at an annual rate of $315,000, which
shall be payable periodically in accordance with the Company's then
prevailing payroll practices, or such greater amount as the Company
may from time to time determine.
b. The Executive shall be entitled to participate in the
Company's Supplemental Executive Retirement Plan ("SERP") according
to its terms, as modified by Schedule A hereto.
c. The Executive shall be entitled to participate in the
Company's Officers Incentive Compensation Plan, Stock Option Plan
and Performance Share Unit Plan, and any successors thereto, in
accordance with the terms thereof.
d. The Executive shall be entitled to such expense
accounts, vacation time, sick leave, perquisites of office, fringe
benefits, insurance coverage, and other terms and conditions of
employment as the Company generally provides to its employees
having rank and seniority at the Company comparable to the
Executive.
4. Unless terminated in accordance with the following
provisions of this paragraph 4, the Company shall continue to
employ the Executive and the Executive shall continue to work for
the Company, during the term of this Agreement.
a. This Agreement shall terminate automatically upon the
death of the Executive. Any right or benefit accrued on behalf of
the Executive or to which the Executive became entitled under the
terms of this Agreement prior to death (other than payment of
salary in respect of the period following the Executive's death),
and any obligation of the Company to the Executive in respect of
any such right or benefit, shall not be extinguished by reason of
the Executive's death. Any salary earned and unpaid as of the date
of the Executive's death shall be paid to the Executive's estate in
accordance with paragraph 4f below.
b. Upon the Executive's "Disability" (as defined below)
the payment of benefits under the Company's short-term and long-
term disability plans shall satisfy the Company's obligations under
paragraph 3a hereof. The Executive shall be deemed to be under a
Disability if (i) a physician selected by the Company advises the
Company that the Executive's physical or mental condition will
render the Executive unable to perform the Executive's duties for
a period exceeding 12 consecutive months, or (ii) due to a physical
or mental condition, the Executive has not substantially performed
the Executive's duties hereunder for a period of 12 consecutive
months.
c. The Company may terminate the Executive's employment
at any time for "Cause"; Cause shall mean (i) a material default or
other material breach by the Executive of his obligations under
this Agreement, (ii) failure by the Executive diligently and
competently to perform the Executive's duties under this Agreement,
or (iii) misconduct, dishonesty, insubordination or other act by
the Executive detrimental to the good will of the Company or
damaging to the Company's relationships with its customers,
suppliers or employees.
d. If any of the following events, any of which shall
constitute "Good Reason", occurs within twenty-four full calendar
months after a Change in Control (as that term is defined in
Schedule B hereto), the Executive may voluntarily terminate the
Executive's employment for Good Reason within 90 days after the
occurrence of such event and be entitled to the severance benefits
set forth in subparagraph e below.
(i) The Company assigns any duties to the Executive which are
materially inconsistent with the Executive's position, duties,
offices, responsibilities or reporting requirements immediately
prior to a Change in Control; or
(ii) the Company reduces the Executive's base salary,
including deferrals, as in effect immediately prior to a Change in
Control; or
(iii) the Company discontinues any bonus or other compensation
plan or any other benefit, stock ownership plan, stock purchase
plan, stock option plan, life insurance plan, health plan,
disability plan or similar plan (as the same existed immediately
prior to the Change in Control) in which the Executive participated
or was eligible to participate in immediately prior to the Change
in Control and in lieu thereof does not make available plans
providing at least comparable benefits; or
(iv) the Company takes action which adversely affects the
Executive's participation in, or eligibility for, or materially
reduces the Executive's benefits under, any of the plans described
in (iii) above, or deprives the Executive of any material fringe
benefit enjoyed by the Executive immediately prior to the Change in
Control, or fails to provide the Executive with the number of paid
vacation days to which the Executive was entitled in accordance
with normal vacation policy immediately prior to the Change in
Control; or
(v) the Company requires the Executive to be based at any
office or location other than one within a 50-mile radius of the
office or location at which the Executive was based immediately
prior to the Change in Control; or
(vi) the Company purports to terminate the Executive's
employment otherwise than as expressly permitted by this Agreement;
or
(vii) the Company fails to comply with and satisfy paragraph
5 hereof, provided that such successor has received prior written
notice from the Company or from the Executive of the requirements
of paragraph 5 hereof.
The Executive shall have the sole right to determine, in good
faith, whether any of the above events has occurred.
e. The Company may terminate the Executive's employment
at any time without Cause. In the event that the Executive's
employment is terminated by the Company without Cause or by the
Executive for Good Reason following a Change in Control as set
forth above, the Company shall pay the Executive a severance
benefit, payable in twenty-four equal monthly installments, equal
to two years' base salary, plus the greater of (i) two times the
most recent annual bonus or (ii) two times the average annual bonus
for the three prior years. In addition, the Executive will be
entitled to continue participation in the Company's benefit plans
for a two-year period, provided, however, that such benefit
continuation will terminate upon the Executive's coverage under
comparable plans. The payments and benefits continuation provided
to the Executive by the Company pursuant to this subsection will be
in full and complete satisfaction (except as provided in
subparagraphs f and i below and Schedule A hereto) of any and all
obligations owing to the Executive pursuant to this Agreement.
f. Upon termination pursuant to a, b, c, d, or e above,
the Company shall pay the Executive or the Executive's estate any
salary earned and unpaid to the date of termination, and any
outstanding funds advanced by the Company to or on behalf of the
Executive shall become immediately due and payable.
g. It is the intention of the parties to this Agreement
that no severance benefits hereunder will be paid to the extent
that such benefits (either alone or when aggregated with other
benefits contingent on a Change in Control) and paid to or for
benefit of the Executive) constitute "excess parachute payments"
within the meaning of Section 280G of the Internal Revenue Code of
1986, as amended (the "Code"). Accordingly, under the
circumstances set forth below, severance benefits payable under
this Agreement shall be subject to the following ceiling
notwithstanding anything in this Agreement to the contrary: The
"aggregate present value" of severance benefits payable under this
Agreement which, together with all other payments to the Executive
or for the Executive's benefit, would be "parachute payments" if
their "aggregate present value" equalled or exceeded 300% of the
Executive's "base amount" shall in no event exceed 295% of the
Executive's "base amount" (within those terms' meaning under
Section 280G of the Code).
h. The determination of any reduction in the payments
under this Agreement, or in payments made other than pursuant to
this Agreement, pursuant to the foregoing proviso, including
apportionment among specific payments and benefits, shall be made
by the Executive in good faith, and such determination shall be
conclusive and binding on the Company. The Company shall make the
calculations referred to above within thirty days following the
termination of the Executive's employment and shall provide such
calculations and the basis therefor to the Executive within such
period. In the event the foregoing limit is exceeded, the
Executive shall give notice to the Company within 20 days of the
Executive's receipt of such calculations and related information of
the Executive's determination of the reduction of benefits.
i. Subject to and contingent upon the occurrence of a
Change in Control the Company agrees to pay promptly as incurred,
to the full extent permitted by law, all legal fees and expenses
which the Executive may reasonably thereafter incur as a result of
any contest, litigation or arbitration (regardless of the outcome
thereof) by the Company, by the Executive or by any third party of
the validity of, or liability under, this Agreement or the SERP
(including any contest by the Executive about the amount of any
payment pursuant to this Agreement or pursuant to the SERP), plus
in each case interest on any delayed payment at the rate of 150% of
the Prime Rate posted by the Chase Manhattan Bank, N.A., provided,
however, that the Company shall not be liable for the Executive's
legal fees and expenses if the Executive's position in such
contest, litigation or arbitration is found by the neutral
decision-maker to be frivolous.
5. The Company shall require any successor (whether direct or
indirect, by purchase, merger, consolidation or otherwise) to all
or substantially all of the business and/or assets of the Company
to assume expressly and agree to perform this Agreement in the same
manner and to the same extent that the Company would be required to
perform. As used in this Agreement, "Company" shall mean the
company as hereinbefore defined and any successor to its business
and/or assets as aforesaid which assumes and agrees to perform this
Agreement by operation of law, or otherwise.
6. The Executive shall not divulge or communicate to any
person (except in performing the Executive's duties under this
Agreement) or use for the Executive's own purposes trade secrets,
confidential commercial information, or any other information,
knowledge or data of the Company or of any of its Affiliates which
is not generally known to the public and shall use the Executive's
best efforts to prevent the publication or disclosure by any other
person of any such secret, information, knowledge or data. All
documents and objects made, compiled, received, held or used by the
Executive while employed by the Company in connection with the
business of the Company shall be and remain the Company's property
and shall be delivered by the Executive to the Company upon the
termination of the Executive's employment or at any earlier time
requested by the Company. It is understood that the Executive
shall retain ownership of the Executive's personal property,
including the Executive's private working papers not containing
proprietary information of or about the Company.
7. The Executive agrees that during the Executive's
employment at the Company and for a period of one year after the
termination of the Executive's employment, the Executive will not
directly or indirectly, whether or not for compensation and whether
or not as an employee, be engaged in or have any financial interest
in any business competing with or which may compete with the
business of the Company (or with any business of any Affiliate for
which the Executive performed services hereunder) within any state,
region or locality in which the Company or such Affiliate is then
doing business or marketing its products, as the business of the
Company or such Affiliates may then be constituted. For purposes
of this Agreement, the Executive shall be deemed to be engaged in
or to have a financial interest in such a business if the Executive
is an employee, officer, director, or partner, of any person,
partnership, corporation, trust or other entity which is engaged in
such a business, or if the Executive directly or indirectly
performs services for such entity or if the Executive or any member
of the Executive's immediate family beneficially owns an equity
interest, or interest convertible into equity, in any such entity;
provided, however, that the foregoing shall not prohibit the
Executive or a member of the Executive's immediate family from
owning, for the purpose of passive investment, less than 5% of any
class of securities of a publicly held corporation. The Executive
recognizes that a breach or threatened breach by the Executive of
the Executive's obligations under this paragraph 7 would cause
irreparable injury to the Company, and the Company shall be
entitled to preliminary and permanent injunctions enjoining the
Executive from violating this paragraph 7 in addition to any other
remedies which may be available.
8. The Executive agrees that the Executive shall not, for a
period of one year after the termination of this Agreement, employ
any person who was employed by the Company or any of its Affiliates
or induce such person to accept employment other than with the
Company and its Affiliates.
9. The Executive hereby agrees that any and all improvements,
inventions, discoveries, formulae, processes, methods, know-how,
confidential data, trade secrets and other proprietary information
(collectively, "Work Products") within the scope of any business of
the Company or any Affiliate which the Executive may conceive or
make or have conceived or made during the Executive's employment
with the Company shall be and are the sole and exclusive property
of the Company, and that the Executive shall, whenever requested to
do so by the Company, at its expense, execute and sign any and all
applications, assignments or other instruments and do all other
things which the Company may deem necessary or appropriate (i) in
order to apply for, obtain, maintain, enforce, or defend letters
patent of the United States or any foreign country for any Work
Product, or (ii) in order to assign, transfer, convey or otherwise
make available to the Company the sole and exclusive right, title
and interest in and to any Work Product.
10. Any dispute or controversy between the parties relating
to this Agreement (except any dispute relating to paragraph 6, 7 or
8 hereof) or relating to or arising out of the Executive's
employment with the Company, shall be settled by binding
arbitration in the City of Syracuse, State of New York, pursuant to
the governing rules of the American Arbitration Association and
shall be subject to the provisions of Article 75 of the New York
Civil Practice Law and Rules. Judgment upon the award may be
entered in any court of competent jurisdiction. Notwithstanding
anything herein to the contrary, if any dispute arises between the
parties under paragraph 6, 7, or 8 hereof, or if the Company makes
any claim under paragraph 6, 7, or 8, the Company shall not be
required to arbitrate such dispute or claim but shall have the
right to institute judicial proceedings in any court of competent
jurisdiction with respect to such dispute or claim. If such
judicial proceedings are instituted, the parties agree that such
proceedings shall not be stayed or delayed pending the outcome of
any arbitration proceedings hereunder.
11. Any notice or other communication required or permitted
under this Agreement shall be effective only if it is in writing
and delivered personally or sent by registered or certified mail,
postage prepaid, addressed as follows:
If to the Company:
Niagara Mohawk Power Corporation
300 Erie Boulevard West
Syracuse, New York 13202
ATTN: Corporate Secretary
If to the Executive:
1241 West 58th Street
Kansas City, Missouri 64113
or to such other address as either party may designate by notice to
the other, and shall be deemed to have been given upon receipt.
12. This Agreement constitutes the entire agreement between
the parties hereto with respect to the Executive's employment by
the Company, and supersedes and is in full substitution for any and
all prior understandings or agreements with respect to the
Executive's employment.
13. This Agreement may be amended only by an instrument in
writing signed by the parties hereto, and any provision hereof may
be waived only by an instrument in writing signed by the party or
parties against whom or which enforcement of such waiver is sought.
The failure of either party hereto at any time to require the
performance by the other party hereto of any provision hereof shall
in no way affect the full right to require such performance at any
time thereafter, nor shall the waiver by either party hereto of a
breach of any provision hereof be taken or held to be a waiver of
any succeeding breach of such provision or a waiver of the
provision itself or a waiver of any other provision of this
Agreement.
14. This Agreement is binding on and is for the benefit of
the parties hereto and their respective successors, heirs,
executors, administrators and other legal representatives. Neither
this Agreement nor any right or obligation hereunder may be
assigned by the Company (except to an Affiliate) or by the
Executive.
15. If any provision of this Agreement, or portion thereof,
is so broad, in scope or duration, so as to be unenforceable, such
provision or portion thereof shall be interpreted to be only so
broad as is enforceable.
16. This Agreement shall be governed by and construed in
accordance with the laws of the State of New York.
17. This Agreement may be executed in several counterparts,
each of which shall be deemed an original, but all of which shall
constitute one and the same instrument.
18. The Executive represents and warrants that the Executive
is not party to any agreement which would prohibit the Executive
from entering into this Agreement or performing fully the
Executive's obligations hereunder.
19. The obligations of the Executive set forth in paragraphs
6, 7, 8, 9 and 10 represent independent covenants by which the
Executive is and will remain bound notwithstanding any breach by
the Company, and shall survive the termination of this Agreement.
IN WITNESS WHEREOF, the Company and the Executive have
executed this Agreement as of the date first written above.
/s/ Albert J. Budney, Jr. NIAGARA MOHAWK POWER CORPORATION
- -------------------------
Albert J. Budney, Jr. By: /s/ David J. Arrington
----------------------
DAVID J. ARRINGTON
Senior Vice President -
Human Resources
SCHEDULE A
- ----------
Modifications in Respect of Albert J. Budney, Jr. ("Executive") to
the Supplemental Executive Retirement Plan ("SERP") of the Niagara
Mohawk Power Corporation ("Company")
- ------------------------------------
I. Subsection 1.8 of Section I of the SERP is hereby modified to
provide that the term "Earnings" shall mean the sum of the (i)
Executive's base annual salary, whether or not deferred,
averaged over the final 36 months of the Executive's
employment with the Company and (ii) average of the annual
bonus earned by the Executive under the Corporation's Annual
Officers Incentive Compensation Plan, whether or not deferred,
in respect of the final 36 months of the Executive's
employment with the Company.
II. Subsection 2.1 of Section II of the SERP is hereby modified to
provide that full SERP benefits are vested following eight (8)
years of continuous service with the Company.
III. Subsection 4.3 of Section IV of the SERP is hereby modified to
provide that in the event of (x) the Executive's involuntary
termination of employment by the Company, at any time, other
than for Cause, (y) the Executive's Disability (as defined in
paragraph 4b of this Agreement) or (z) the Executive's
termination of employment for Good Reason within the 24 full
calendar month period following a Change in Control (as
defined in Schedule B of this Agreement), the Executive shall
be 100% vested in his full SERP benefit (i.e., 60% of Earnings
(as modified above)) regardless of the Executive's years of
continuous service with the Company. If the Executive is less
than age 55 at the date of such termination of employment, the
Executive shall be entitled to receive benefits commencing no
earlier than age 55, calculated pursuant to Section III of the
SERP.
IV. Except as provided above, the provisions of the SERP shall
apply and control participation therein and the payment of
benefits thereunder.
/s/ Albert J. Budney, Jr. NIAGARA MOHAWK POWER CORPORATION
- -------------------------
Albert J. Budney, Jr. By: /s/ David J. Arrington
----------------------
DAVID J. ARRINGTON
Senior Vice President -
Human Resources
SCHEDULE B
- ----------
For purposes of this Agreement, the term "Change in Control"
shall mean:
(1) The acquisition by any individual, entity or group
(within the meaning of Section 13(d)(3) or 14(d)(2) of the
Securities Exchange Act of 1934, as amended (the "Exchange Act"))
(a "Person") of beneficial ownership (within the meaning of Rule
13d-3 promulgated under the Exchange Act) of 20% or more of either
(i) the then outstanding shares of common stock of the Company (the
"Outstanding Company Common Stock") or (ii) the combined voting
power of the then outstanding voting securities of the Company
entitled to vote generally in the election of directors (the
"Outstanding Company Voting Securities"); provided, however, that
the following acquisitions shall not constitute a Change of
Control: (i) any acquisition directly from the Company (excluding
an acquisition by virtue of the exercise of a conversion
privilege), (ii) any acquisition by the Company, (iii) any
acquisition by any employee benefit plan (or related trust)
sponsored or maintained by the Company or any corporation
controlled by the Company or (iv) any acquisition by any
corporation pursuant to a reorganization, merger or consolidation,
if, following such reorganization, merger or consolidation, the
conditions described in clauses (i), (ii) and (iii) of subparagraph
(3) of this Schedule B are satisfied; or
(2) Individuals who, as of the date hereof, constitute the
Company's Board of Directors (the "Incumbent Board") cease for any
reason to constitute at least a majority of the Board; provided,
however, that any individual becoming a director subsequent to the
date hereof whose election, or nomination for election by the
Company's shareholders, was approved by a vote of at least a
majority of the directors then comprising the Incumbent Board shall
be considered as though such individual were a member of the
Incumbent Board, but excluding, for this purpose, any such
individual whose initial assumption of office occurs as a result of
either an actual or threatened election contest (as such terms are
used in Rule 14a-11 of Regulation 14A promulgated under the
Exchange Act) or other actual or threatened solicitation of proxies
or consents by or on behalf of a Person other than the Board; or
(3) Approval by the shareholders of the Company of a
reorganization, merger or consolidation, in each case, unless,
following such reorganization, merger or consolidation, (i) more
than 75% of, respectively, the then outstanding shares of common
stock of the corporation resulting from such reorganization, merger
or consolidation and the combined voting power of the then
outstanding voting securities of such corporation entitled to vote
generally in the election of directors is then beneficially owned,
directly or indirectly, by all or substantially all of the
individuals and entities who were the beneficial owners,
respectively, of the Outstanding Company Common Stock and
Outstanding Company Voting Securities immediately prior to such
reorganization, merger or consolidation in substantially the same
proportions as their ownership, immediately prior to such
reorganization, merger or consolidation, of the Outstanding Company
Common Stock and Outstanding Company Voting Securities, as the case
may be, (ii) no Person (excluding the Company, any employee benefit
plan (or related trust) of the Company or such corporation
resulting from such reorganization, merger or consolidation and any
Person beneficially owning, immediately prior to such
reorganization, merger or consolidation, directly or indirectly,
20% or more of the Outstanding Company Common stock or Outstanding
Voting Securities, as the case may be) beneficially owns, directly
or indirectly, 20% or more of, respectively, the then outstanding
shares of common stock of the corporation resulting from such
reorganization, merger or consolidation or the combined voting
power of the then outstanding voting securities of such corporation
entitled to vote generally in the election of directors and (iii)
at least a majority of the members of the board of directors of the
corporation resulting from such reorganization, merger or
consolidation were members of the Incumbent Board at the time of
the execution of the initial agreement providing for such
reorganization, merger or consolidation; or
(4) Approval by the shareholders of the Company of (i) a
complete liquidation or dissolution of the Company or (ii) the sale
or other disposition of all or substantially all of the assets of
the Company, other than to a corporation, with respect to which
following such sale or other disposition, (A) more than 75% of,
respectively, the then outstanding shares of common stock of such
corporation and the combined voting power of the then outstanding
voting securities of such corporation entitled to vote generally in
the election of directors is then beneficially owned, directly or
indirectly, by all or substantially all of the individuals and
entities who were the beneficial owners, respectively, of the
Outstanding Company Common Stock and Outstanding Company Voting
Securities immediately prior to such sale or other disposition in
substantially the same proportion as their ownership, immediately
prior to such sale or other disposition, of the Outstanding Company
Common Stock and Outstanding Company Voting Securities, as the case
may be, (B) no Person (excluding the Company and any employee
benefit plan (or related trust) of the Company or such corporation
and any Person beneficially owning, immediately prior to such sale
or other disposition, directly or indirectly, 20% or more of the
Outstanding Company Common Stock or Outstanding Company Voting
Securities, as the case may be) beneficially owns, directly or
indirectly, 20% or more of, respectively, the then outstanding
shares of common stock of such corporation and the combined voting
power of the then outstanding voting securities of such corporation
entitled to vote generally in the election of directors and (C) at
least a majority of the members of the board of directors of such
corporation were members of the Incumbent Board at the time of the
execution of the initial agreement or action of the Board providing
for such sale or other disposition of assets of the Company.
EXHIBIT 10-27
- -------------
October 10, 1995
Mr. David J. Arrington
4302 Hepatica Hill Road
Manlius, NY 13104
Re: Employment Agreement
Dear Dave,
Reference is made to the Employment Agreement between Niagara
Mohawk Power Corporation (the "Company") and you, dated as of
January 1, 1993 (the "Agreement").
Unless otherwise indicated, defined terms of the Agreement
shall have the same meaning herein. In consideration of the mutual
covenants and agreements hereinafter set forth, the Company hereby
offers to amend the Agreement as follows:
Paragraph II of Schedule A to the Agreement is hereby amended
to read as follows:
"Subsection 2.1 of Section II of the SERP is hereby modified
to provide that full SERP benefits are vested following eight
(8) years of continuous service with the Company."
If you agree to the amendment of the Agreement as set forth
above, kindly sign and date the attached copy of this letter and
return it to me.
If you have any questions or comments, please feel free to
contact me.
Very truly yours,
/s/ William E. Davis
Agreed: /s/ D. J. Arrington
-------------------
Date: 10/10/95
-------------------
EXHIBIT 10-28
- -------------
October 10, 1995
Mr. William E. Davis
88 West Lake Road
Skaneateles, NY 13152
Re: Employment Agreement
Dear Bill,
Reference is made to the Employment Agreement between Niagara
Mohawk Power Corporation (the "Company") and you, dated as of
January 1, 1993 (the "Agreement").
Unless otherwise indicated, defined terms of the Agreement
shall have the same meaning herein. In consideration of the mutual
covenants and agreements hereinafter set forth, the Company hereby
offers to amend the Agreement as follows:
Paragraph II of Schedule A to the Agreement is hereby amended
to read as follows:
"Subsection 2.1 of Section II of the SERP is hereby modified
to provide that full SERP benefits are vested following eight
(8) years of continuous service with the Company."
If you agree to the amendment of the Agreement as set forth
above, kindly sign and date the attached copy of this letter and
return it to me.
If you have any questions or comments, please feel free to
contact me.
Very truly yours,
/s/ David J. Arrington
Agreed: /s/ William E. Davis
--------------------
Date: 10/10/95
-------------------
EXHIBIT 10-29
- -------------
October 10, 1995
Mr. Gary J. Lavine
11 Holliston Circle
Fayetteville, NY 13066
Re: Employment Agreement
Dear Gary,
Reference is made to the Employment Agreement between Niagara
Mohawk Power Corporation (the "Company") and you, dated as of
January 1, 1993 (the "Agreement").
Unless otherwise indicated, defined terms of the Agreement
shall have the same meaning herein. In consideration of the mutual
covenants and agreements hereinafter set forth, the Company hereby
offers to amend the Agreement as follows:
Paragraph II of Schedule A to the Agreement is hereby amended
to read as follows:
"Subsection 2.1 of Section II of the SERP is hereby modified
to provide that full SERP benefits are vested following eight
(8) years of continuous service with the Company."
If you agree to the amendment of the Agreement as set forth
above, kindly sign and date the attached copy of this letter and
return it to me.
If you have any questions or comments, please feel free to
contact me.
Very truly yours,
/s/ David J. Arrington
Agreed: /s/ Gary J. Lavine
-------------------
Date: 10/18/95
-------------------
EXHIBIT 10-30
- -------------
October 10, 1995
Mr. B. Ralph Sylvia
124 Coachmans Whip
Baldwinsville, NY 13027
Re: Employment Agreement
Dear Ralph,
Reference is made to the Employment Agreement between Niagara
Mohawk Power Corporation (the "Company") and you, dated as of
January 1, 1993 (the "Agreement").
Unless otherwise indicated, defined terms of the Agreement
shall have the same meaning herein. In consideration of the mutual
covenants and agreements hereinafter set forth, the Company hereby
offers to amend the Agreement as follows:
Paragraph II of Schedule A to the Agreement is hereby amended
to read as follows:
"Subsection 2.1 of Section II of the SERP is hereby modified
to provide that full SERP benefits are vested following eight
(8) years of continuous service with the Company."
If you agree to the amendment of the Agreement as set forth
above, kindly sign and date the attached copy of this letter and
return it to me.
If you have any questions or comments, please feel free to
contact me.
Very truly yours,
/s/ David J. Arrington
Agreed: /s/ B. Ralph Sylvia
-------------------
Date: October 17, 1995
-------------------
EXHIBIT 10-31
- -------------
NIAGARA MOHAWK POWER CORPORATION
- --------------------------------
1995 STOCK INCENTIVE PLAN
- -------------------------
ARTICLE 1. ESTABLISHMENT, PURPOSE AND DURATION
1.1 ESTABLISHMENT OF THE PLAN. Niagara Mohawk Power
Corporation, a New York corporation (hereinafter referred to as the
"Company"), hereby establishes an incentive compensation plan to be
known as the "Niagara Mohawk Power Corporation 1995 Stock
Incentive Plan" (hereinafter referred to as the "Plan"), as set
forth in this document. The Plan permits the grant of Stock
Appreciation Rights, Stock Units and Dividend Equivalents, as
defined herein.
The Plan shall become effective as of December 13, 1995 (the
"Effective Date") and shall remain in effect as provided in Section
1.3 herein.
1.2 PURPOSE OF THE PLAN. The purpose of the Plan is to
promote the success and enhance the value of the Company through
the retention and continued motivation of Participants, focusing
their efforts toward the execution of business strategies directed
toward improving financial returns to shareholders.
1.3 DURATION OF THE PLAN. The Plan shall commence on the
Effective Date, as described in Section 1.1 herein, and shall
remain in effect, subject to the right of the Board of Directors to
terminate the Plan at any time pursuant to Article 14 herein, until
the earlier of (i) December 31, 2002 and (ii) all SARs and Stock
Units subject to the Plan shall have been granted according to the
Plan's provisions. The applicable terms of the Plan and any terms
and conditions applicable to SARs or Stock Units, including any
deferral elections, granted prior to such date shall survive the
termination of the Plan.
ARTICLE 2. DEFINITIONS
Whenever used in the Plan, the following terms shall have the
meanings set forth below and, when such meaning is intended, the
initial letter of the word is capitalized:
2.1 "Award" means, individually or collectively, a grant
under the Plan of SARs or Stock Units.
2.2 "Award Agreement" means an agreement entered into by each
Participant and the Company, setting forth the terms and provisions
applicable to an Award granted to a Participant under the Plan.
2.3 "Base Value" of an SAR shall have the meaning set forth
in Section 6.2 herein.
2.4 "Board" or "Board of Directors" means the Board of
Directors of the Company.
2.5 "Cause" means: (i) a material default or other material
breach by a Participant of his obligations under any Employment
Agreement he may have with the Company, (ii) failure by a
Participant diligently and competently to perform his duties under
any Employment Agreement he may have with the Company, or
otherwise, or (iii) misconduct, dishonesty, insubordination or
other act by a Participant detrimental to the good will of the
Company or damaging the Company's relationships with its customers,
suppliers or employees. "Cause" shall be determined in good faith
by the Committee.
2.6 "Change in Control" of the Company shall be deemed to
have occurred as of the first day that any one or more of the
following conditions shall have been satisfied:
(1) The acquisition by any Person of beneficial ownership
(within the meaning of Rule 13d-3 promulgated under the
Exchange Act) of 20% or more of either (i) the then
outstanding Shares of the Company or (ii) the combined
voting power of the then outstanding voting securities of
the Company entitled to vote generally in the election of
directors (the "Outstanding Company Voting Securities");
provided, however, that the following acquisitions shall
not constitute a Change of Control: (i) any acquisition
directly from the Company (excluding an acquisition by
virtue of the exercise of a conversion privilege), (ii)
any acquisition by the Company, (iii) any acquisition by
any employee benefit plan (or related trust) sponsored or
maintained by the Company or any corporation controlled
by the Company or (iv) any acquisition by any corporation
pursuant to a reorganization, merger or consolidation,
if, following such reorganization, merger or
consolidation, the conditions described in clauses (i),
(ii) and (iii) of subparagraph (3) below are satisfied;
or
(2) Individuals who, as of the date hereof, constitute the
Board of Directors (the "Incumbent Board") cease for any
reason to constitute at least a majority of the Board;
provided, however, that any individual becoming a
director subsequent to the date hereof whose election, or
nomination for election by the Company's shareholders,
was approved by a vote of at least a majority of the
directors then comprising the Incumbent Board shall be
considered as though such individual were a member of the
Incumbent Board, but excluding, for this purpose, any
such individual whose initial assumption of office occurs
as a result of either an actual or threatened election
contest (as such terms are used in Rule 14a-11 of
Regulation 14A promulgated under the Exchange Act) or
other actual or threatened solicitation of proxies or
consents by or on behalf of a Person other than the
Board; or
(3) Approval by the shareholders of the Company of a
reorganization, merger or consolidation, in each case,
unless, following such reorganization, merger or
consolidation, (i) more than 75% of, respectively, the
then outstanding shares of common stock of the
corporation resulting from such reorganization, merger or
consolidation and the combined voting power of the then
outstanding voting securities of such corporation
entitled to vote generally in the election of directors
are then beneficially owned, directly or indirectly, by
all or substantially all of the individuals and entities
who were the beneficial owners, respectively, of the
Outstanding Shares and Outstanding Company Voting
Securities immediately prior to such reorganization,
merger or consolidation, in substantially the same
proportions as their ownership immediately prior to such
reorganization, merger or consolidation, of the
Outstanding Shares and Outstanding Company Voting
Securities, as the case may be, (ii) no Person (excluding
the Company, any employee benefit plan (or related trust)
of the Company or such corporation resulting from such
reorganization, merger or consolidation and any Person
beneficially owning, immediately prior to such
reorganization, merger or consolidation, directly or
indirectly, 20% or more of the Outstanding Shares or
Outstanding Voting Securities, as the case may be)
beneficially owns, directly or indirectly, 20% or more
of, respectively, the then outstanding shares of common
stock of the corporation resulting from such
reorganization, merger or consolidation or the combined
voting power of the then outstanding voting securities of
such corporation entitled to vote generally in the
election of directors and (iii) at least a majority of
the members of the board of directors of the corporation
resulting from such reorganization, merger or
consolidation were members of the Incumbent Board at the
time of the execution of the initial agreement providing
for such reorganization, merger or consolidation; or
(4) Approval by the shareholders of the Company of (i) a
complete liquidation or dissolution of the Company or
(ii) the sale or other disposition of all or
substantially all of the assets of the Company, other
than to a corporation, with respect to which following
such sale or other disposition, (A) more than 75% of,
respectively, the then outstanding shares of common stock
of such corporation and the combined voting power of the
then outstanding voting securities of such corporation
entitled to vote generally in the election of directors
is then beneficially owned, directly or indirectly, by
all or substantially all of the individuals and entities
who were the beneficial owners, respectively, of the
Outstanding Shares and Outstanding Company Voting
Securities immediately prior to such sale or other
disposition in substantially the same proportion as their
ownership immediately prior to such sale or other
disposition of the Outstanding Shares and Outstanding
Company Voting Securities, as the case may be, (B) no
Person (excluding the Company and any employee benefit
plan (or related trust) of the Company or such
corporation and any Person beneficially owning,
immediately prior to such sale or other disposition,
directly or indirectly, 20% or more of the Outstanding
Shares or Outstanding Company Voting Securities, as the
case may be) beneficially owns, directly or indirectly,
20% or more of, respectively, the then outstanding shares
of common stock of such corporation and the combined
voting power of the then outstanding voting securities of
such corporation entitled to vote generally in the
election of directors and (C) at least a majority of the
members of the board of directors of such corporation
were members of the Incumbent Board at the time of the
execution of the initial agreement or action of the Board
providing for such sale or other disposition of assets of
the Company;
provided, however, that the implementation of the corporate
restructuring contemplated by the Company's PowerChoice proposal
filed with the New York Public Service Commission on October 6,
1995, or any substantially similar corporate restructuring (as
determined by the Committee) shall not be deemed to be a "Change in
Control".
2.7 "Code" means the Internal Revenue Code of 1986, as
amended from time to time.
2.8 "Committee" means the committee, as specified in Article
3, appointed by the Board to administer the Plan with respect to
grants of Awards.
2.9 "Company" means Niagara Mohawk Power Corporation, a New
York corporation, or any successor thereto as provided in Article
16 herein.
2.10 "Director" means any individual who is a member of the
Board of Directors of the Company.
2.11 "Disability" shall have the meaning ascribed to such term
under Section 22(e)(3) of the Code.
2.12 "Dividend Equivalent" means, with respect to Shares
underlying a Stock Unit, an amount equal to all cash and stock
dividends declared on an equal number of outstanding Shares on all
common stock dividend payment dates occurring during the Vesting
Period.
2.13 "Eligible Employee" means an Employee who is eligible to
participate in the Plan, as set forth in Section 5.1 herein.
2.14 "Employee" means any full-time employee of the Company,
who is not covered by any collective bargaining agreement to which
the Company is a party. Directors who are not otherwise employed
by the Company shall not be considered Employees under the Plan.
For purposes of the Plan, transfer of employment of a Participant
from the Company to any one of its Subsidiaries shall not be deemed
a termination of employment.
2.15 "Exchange Act" means the Securities Exchange Act of 1934,
as amended from time to time, or any successor act thereto.
2.16 "Exercise Period" means the period during which an SAR is
exercisable, as set forth in the related Award Agreement.
2.17 "Fair Market Value" means the average of the daily
opening and closing sale prices as reported in the consolidated
transaction reporting system.
2.18 "Participant" means an Employee of the Company who has
outstanding an Award granted under the Plan.
2.19 "Person" shall have the meaning ascribed to such term in
Section 3(a)(9) of the Exchange Act, as used in Sections 13(d) and
14(d) thereof, including usage in the definition of a "group" in
Section 13(d) thereof.
2.20 "Retirement" shall have the meaning ascribed to such term
in the tax-qualified defined benefit pension plan maintained by the
Company for the benefit of some or all of its non-represented
employees.
2.21 "Shares" means the shares of common stock of the Company,
par value $1.
2.22 "Stock Appreciation Right" or "SAR" means a right,
designated as an SAR, to receive a payment on the day the right is
exercised, pursuant to the terms of Article 6 herein. Each SAR
shall be denominated in terms of one Share.
2.23 "Stock Unit" means a right, designated as a Stock Unit,
to receive a payment on or about the last day of a Vesting Period,
pursuant to the terms of Article 7 herein. Each Stock Unit shall
be denominated in terms of one Share.
2.24 "Subsidiary" means any corporation that is a "subsidiary
corporation" of the Company as that term is defined in Section
424(f) of the Code.
2.25 "Valuation Period" means the 12 trading day period ending
on and including the relevant date.
2.26 "Vesting Period" means the period during which Stock
Units are not yet payable, as set forth in the related Award
Agreement.
ARTICLE 3. ADMINISTRATION
3.1 THE COMMITTEE. The Plan shall be administered by the
Compensation and Succession Committee of the Board, or by any other
Committee appointed by the Board consisting of not less than two
(2) non-employee Directors. The members of the Committee shall be
appointed from time to time by, and shall serve at the discretion
of, the Board of Directors. The Committee, to the extent
necessary, shall be comprised solely of Directors who are eligible
to administer the Plan pursuant to Rule 16b-3(c)(2) under the
Exchange Act.
3.2 AUTHORITY OF THE COMMITTEE. The Committee shall have
full power except as limited by law, the Articles of Incorporation
and the Bylaws of the Company, subject to such other restricting
limitations or directions as may be imposed by the Board and
subject to the provisions herein, to determine the size and types
of Awards; to determine the terms and conditions of such Awards in
a manner consistent with the Plan; to construe and interpret the
Plan and any agreement or instrument entered into under the Plan;
to establish, amend or waive rules and regulations for the Plan's
administration; and (subject to the provisions of Article 14
herein) to amend the terms and conditions of any outstanding Award.
Further, the Committee shall make all other determinations that may
be necessary or advisable for the administration of the Plan. As
permitted by law, the Committee may delegate its authorities as
identified hereunder.
3.3 DECISIONS BINDING. All determinations and decisions made
by the Committee pursuant to the provisions of the Plan and all
related orders or resolutions of the Board shall be final,
conclusive and binding on all persons, including the Company, its
shareholders, Employees, Participants and their estates and
beneficiaries.
3.4 COSTS. The Company shall pay all costs of administration
of the Plan.
ARTICLE 4. SARs AND STOCK UNITS SUBJECT TO THE PLAN
4.1 NUMBER. Subject to Section 4.2 herein, the maximum
number of SARs and Stock Units available for grant under the Plan
shall be 700,000.
4.2 ADJUSTMENTS IN AUTHORIZED SHARES. In the event of any
merger, reorganization consolidation, recapitalization, separation,
liquidation, stock dividend, split-up, share combination or other
change in the corporate structure of the Company affecting the
Shares, such adjustment shall be made in the number of SARs and
Stock Units that may be granted under the Plan, and in the number
and/or price of outstanding Awards granted under the Plan, as may
be determined to be appropriate and equitable by the Committee, in
its sole discretion, to prevent dilution or enlargement of rights;
provided, however, that the number of SARs and Stock Units subject
to an Award shall always be a whole number.
ARTICLE 5. ELIGIBILITY AND PARTICIPATION
5.1 ELIGIBILITY. Persons eligible to participate in the Plan
include all Employees who are officers of the Company, as
determined by the Committee, including Employees who are members of
the Board, but excluding Directors who are not Employees.
5.2 ACTUAL PARTICIPATION. Subject to the provisions of the
Plan, the Committee may, from time to time, select from all
eligible Employees those to whom Awards shall be granted and shall
determine the nature and amount of each Award.
ARTICLE 6. STOCK APPRECIATION RIGHTS
6.1 GRANT OF SARs. Subject to the terms and conditions of
the Plan, SARs may be granted to Eligible Employees at any time and
from time to time, as shall be determined by the Committee.
The Committee shall have complete discretion in determining
the number of SARs granted to each Participant (subject to Article
4 herein) and, consistent with the provisions of the Plan, in
determining the terms and conditions pertaining to such SARs.
6.2 BASE VALUE. The Base Value of an SAR shall equal the
Fair Market Value of a Share determined for the 12 trading day
period commencing October 16, 1995 to and including October 31,
1995, or for such other period as the Compensation Committee, in
its sole discretion, shall determine at the time of grant.
6.3 EXERCISE AND PAYMENT OF SARs. A Participant may exercise
an SAR at any time during the Exercise Period. SARs shall be
exercised by the delivery of a written notice of exercise to the
Company, setting forth the number of SARs being exercised. Upon
exercise of an SAR, a Participant shall be entitled to receive
payment in cash from the Company in an amount equal to the product
of:
(a) the excess of (i) the Fair Market Value of a Share on the
date of exercise over (ii) the Base Value of the SAR,
multiplied by
(b) the number of Shares with respect to which the SAR is
exercised.
6.4 SAR AWARD AGREEMENT. Each SAR grant shall be evidenced
by an Award Agreement that shall specify the number of SARs
granted, the Base Value, the Exercise Period, the expiration date
and such other provisions as the Committee shall determine.
6.5 LAPSE OF SARs. Subject to the provisions of Article 9,
an SAR will lapse upon the earlier of (i) ten (10) years from the
date of grant and (ii) the expiration of the Exercise Period as set
forth in the grant.
ARTICLE 7. STOCK UNITS
7. 1 GRANT OF STOCK UNITS. Subject to the terms and
conditions of the Plan, Stock Units may be granted to Eligible
Employees at any time and from time to time, as shall be determined
by the Committee.
The Committee shall have complete discretion in determining
the number of Stock Units granted to each Participant (subject to
Article 4 herein) and, consistent with the provisions of the Plan,
in determining the terms and conditions pertaining to such Stock
Units.
7.2 VESTING OF STOCK UNITS. The Vesting Period of Stock
Units granted under the Plan shall be determined by the Committee,
in its sole discretion, as set forth in the related Award
Agreement.
7.3 PAYMENT OF STOCK UNITS. After the applicable Vesting
Period has ended, the holder of Stock Units shall be entitled to
receive, for each Stock Unit held, payment in cash from the Company
in an amount equal to the Fair Market Value of one Share determined
as of the Valuation Period ending on the last day of the Vesting
Period. Payment shall be made on or about the last day of the
Vesting Period.
7.4 STOCK UNIT AWARD AGREEMENT. Each Stock Unit grant shall
be evidenced by an Award Agreement that shall specify the number of
Stock Units granted, the Vesting Period and such other provisions
as the Committee shall determine.
ARTICLE 8. DIVIDEND EQUIVALENTS
Simultaneously with the grant of Stock Units, the Participant
shall be granted Dividend Equivalents, to be credited to a
bookkeeping entry account, on each common stock dividend payment
date with respect to the Shares subject to such Award. In the case
of cash dividends, the number of Dividend Equivalents credited on
each common stock dividend payment date shall equal the number of
Shares (including fractional Shares) that could be purchased on the
dividend payment date, based on the average of the opening and
closing sale price, as reported in the consolidated transaction
reporting system on that date, with cash dividends that would have
been paid on Awards of Stock Units and on Dividend Equivalents
previously credited to such bookkeeping entry account, if such
Stock Units or Dividend Equivalents were Shares. In the case of
stock dividends, the number of Dividend Equivalents credited on
each stock dividend payment date shall be equal to the number of
Shares (including fractional Shares) that would have been issued as
a stock dividend in respect of the Participant's Stock Units and on
Dividend Equivalents previously credited to such bookkeeping entry
account, if such Stock Units or Dividend Equivalents were Shares.
Participants shall receive cash payment from the Company of
the Fair Market Value of the Dividend Equivalents, if and when they
receive payment of the related Stock Units, the Fair Market Value
of such Dividend Equivalents to be determined in the same manner as
for the related Stock Units.
The Committee may, in its discretion, establish such rules and
procedures governing the crediting of Dividend Equivalents,
including timing and payment contingencies that apply to the
Dividend Equivalents, as the Committee deems necessary or
appropriate in order to comply with Rule 16b-3 under the Exchange
Act and other applicable law.
ARTICLE 9. TERMINATION OF EMPLOYMENT; TRANSFERABILITY
9.1 DISABILITY; INVOLUNTARY TERMINATION. In the event the
employment of a Participant is terminated by reason of Disability
or involuntarily by the Company (other than for Cause):
(i) during a Vesting Period for Stock Units, the Participant
shall receive a full payout of the Stock Units and
related Dividend Equivalents, as and when provided in
Section 7.3 herein;
(ii) before the Exercise Period commences for SARs subject to
an Award, such SARs may be exercised in full at any time
during the one year period commencing on the day the
Exercise Period begins; and
(iii) during the Exercise Period for SARs, but before
exercise, such SARs may be exercised in full at any
time during the one year period after such
termination, but in no event after the Exercise
Period for such SARs has expired.
9.2 DEATH. In the event the employment of a Participant is
terminated by reason of death:
(i) during the Vesting Period for Stock Units, the
Participant's beneficiary or estate shall receive a full
payout of the Stock Units and related Dividend
Equivalents. The payout shall be made promptly based on
the Fair Market Value of a Share on the date of death;
and
(ii) before the Exercise Period commences for SARs subject to
an Award or during the Exercise Period, but before
exercise, the Participant's beneficiary or estate shall
receive a full payout of all SARs subject to an Award, to
the extent the Fair Market Value of a Share exceeds the
Base Value of the SAR on the date of death.
9.3 CORPORATE RESTRUCTURING. In the event (i) the corporate
restructuring as contemplated by the Company's PowerChoice proposal
filed with the New York Public Service Commission on October 6,
1995, or any substantially similar corporate restructuring
(determined by the Committee), is implemented and (ii) the
employment of a Participant with the Company is terminated (other
than for Cause),
(i) during a Vesting Period for Stock Units, the Participant
shall receive a full payout of Stock Units and related
Dividend Equivalents, as and when provided in Section 7.3
herein;
(ii) before the Exercise Period commences for SARs subject to
an Award, such SARs may be exercised in full at any time
during the one year period commencing on the day the
Exercise Period begins; and
(iii) during the Exercise Period for SARs, but before
exercise, such SARs may be exercised in full at
any time during the one year period after such
termination, but in no event after the Exercise
Period for such SARs has expired.
9.4 RETIREMENT. In the event the employment of a Participant
is terminated by reason of Retirement:
(i) during a Vesting Period for Stock Units, the Participant
shall receive a prorated payout of the Stock Units and
related Dividend Equivalents. The prorated payout shall
be determined by the Committee, shall be based upon the
length of time that the Participant held the Stock Units
during the Vesting Period and shall be made as and when
provided in Section 7.3 herein;
(ii) before the Exercise Period commences for SARs subject to
an Award, the number of SARs subject to an Award shall be
prorated by the Committee, based upon the length of time
that the Participant held the SARs before Retirement;
after the Exercise Period commences, the prorated SARs
may be exercised at any time in full or in part from time
to time during the Exercise Period, and
(iii) during the Exercise Period for SARs, but before
exercise, such SARs may be exercised at any time
in full or in part from time to time during the
Exercise Period.
Other than as set forth in Article 13, in the event that a
Participant's employment terminates for any reason other than as
set forth in Sections 9.l, 9.2, 9.3 and 9.4, above, all Stock
Units, SARs and Dividend Equivalents shall be forfeited by the
Participant to the Company.
9.5 NONTRANSFERABILITY OF AWARDS. No Award granted under the
Plan may be sold, transferred, pledged, assigned, or otherwise
alienated or hypothecated, other than by will or by the laws of
descent and distribution or pursuant to a domestic relations order.
Further, all Awards granted to a Participant under the Plan shall
be exercisable/payable during his or her lifetime only by or to
such Participant or his or her legal representative.
9.6 RIGHT OF COMMITTEE. Subject to the provisions of Section
14.2 herein, all provisions in this Article 9 are subject to the
Committee's right, at any time, to make such other determinations
as it may choose, in its sole discretion. Furthermore, should more
than one section of Article 9 and/or Article 13 apply to a
situation, the Committee shall have the right, in its sole
discretion, to determine which section and/or article to apply.
ARTICLE 10. BENEFICIARY DESIGNATION
Each Participant under the Plan may, from time to time, name
any beneficiary or beneficiaries (who may be named contingently or
successively) to whom any benefit under the Plan is to be paid in
case of his death before he receives any or all of such benefit.
Each such designation shall revoke all prior designations by the
same Participant, shall be in a form prescribed by the Committee,
and will be effective only when filed by the Participant in writing
with the Committee during the Participant's lifetime. In the
absence of any such designation, benefits remaining unpaid at the
Participant's death shall be paid to the Participant's estate.
The spouse of a married Participant domiciled in a community
property jurisdiction shall join in any designation of beneficiary
or beneficiaries other than the spouse.
ARTICLE 11. DEFERRALS
The Committee may permit a Participant to defer such
Participant's receipt of the payment of cash that would otherwise
be due to such Participant. If any such deferral election is
permitted, the Committee shall, in its sole discretion, establish
such rules and procedures as it deems necessary or desirable for
such payment deferrals.
ARTICLE 12. RIGHTS OF EMPLOYEES
12.1 EMPLOYMENT. Nothing in the Plan shall interfere with or
limit in any way the right of the Company to terminate any
Participant's employment at any time, for any reason or no reason,
in the Company's sole discretion, nor confer upon any Participant
any right to continue in the employ of the Company.
12.2 PARTICIPATION. No Employee shall have the right to be
selected to receive an Award under the Plan, or, having been so
selected, to be selected to receive a future Award.
ARTICLE 13. CHANGE IN CONTROL
Upon the occurrence of a Change in Control, as defined herein,
unless otherwise specifically prohibited by the terms of Article 17
herein:
(a) Any and all SARs granted hereunder shall be deemed to
have been exercised on the date such Change in Control occurs;
(b) Any Vesting Period with respect to Stock Units shall be
deemed to have expired, and there shall be paid out in cash to
Participants within thirty (30) days following the effective
date of the Change in Control the cash payment due with
respect to such Stock Units and related Dividend Equivalents,
with a Valuation Period ending on the effective date of the
Change in Control;
provided, however, that with respect to the payment of SARs and
Stock Units as set forth in (a) and (b) above, in no case shall
payment be made in an amount (i) with respect to SARs, exceeding
three times the Base Value of an SAR and (ii) with respect to Stock
Units, exceeding three times the Fair Market Value of Company
common stock on the date of grant.
ARTICLE 14. AMENDMENT, MODIFICATION AND TERMINATION
14.1 AMENDMENT, MODIFICATION AND TERMINATION. The Board may,
at any time and from time to time, alter, amend, suspend or
terminate the Plan in whole or in part.
14.2 AWARDS PREVIOUSLY GRANTED. No termination, amendment or
modification of the Plan shall adversely affect in any material way
any Award previously granted under the Plan, without the written
consent of the Participant holding such Award, unless such
termination, modification or amendment is required by applicable
law.
ARTICLE 15. TAX WITHHOLDING
The Company shall have the power and the right to deduct or
withhold, or require a Participant to remit to the Company, an
amount sufficient to satisfy Federal, state and local taxes
(including the Participant's FICA obligation) required by law to be
withheld with respect to any taxable event arising out of or as a
result of an Award made under the Plan.
ARTICLE 16. SUCCESSORS
All obligations of the Company under the Plan, with respect to
Awards granted hereunder shall be binding on any successor to the
Company, whether the existence of such successor is the result of
a direct or indirect purchase, merger, consolidation or otherwise,
of all or substantially all of the business and/or assets of the
Company.
ARTICLE 17. LEGAL CONSTRUCTION
17.1 GENDER AND NUMBER. Except where otherwise indicated by
the context, any masculine term used herein also shall include the
feminine, the plural shall include the singular and the singular
shall include the plural.
17.2 SEVERABILITY. In the event any provision of the Plan
shall be held illegal or invalid for any reason, the illegality or
invalidity shall not affect the remaining parts of the Plan, and
the Plan shall be construed and enforced as if the illegal or
invalid provision had not been included.
17.3 REQUIREMENTS OF LAW. The granting of Awards under the
Plan shall be subject to all applicable laws, rules and
regulations, and to such approvals by any governmental agencies or
national securities exchanges as may be required.
17.4 GOVERNING LAW. To the extent not preempted by Federal
law, the Plan, and all agreements hereunder, shall be construed in
accordance with, and governed by, the laws of the State of New
York, without regard to conflicts of law provisions.
EXHIBIT 11
- ----------
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARIES
COMPUTATION OF AVERAGE NUMBER OF SHARES OF COMMON STOCK OUTSTANDING
Average Number
of Shares Out-
standing as Shown
on Consolidated
(1) (2) Statements of In-
Shares of Number (3) come (3 Divided
Common of Days Share Days by Number of Days
Year Ended December 31, Stock Outstanding (2 x 1) in Year)
- ----------------------- --------- ----------- ---------- -----------------
1995
----
January 1 - December 31 144,311,466 365 52,673,685,090
Shares sold -
Dividend Reinvestment
Plan - January 31 19,016 335 6,370,360
Acquisition - Syracuse
Suburban Gas Company,
Inc. - October 4 1,641 89 146,049
------------ ---------------
144,332,123 52,680,201,499 144,329,319
============ ============== ===========
1994
----
January 1 - December 31 142,427,057 365 51,985,875,805
Shares sold at various
times during the year -
Dividend Reinvestment
Plan 1,026,709 * 152,123,611
Employee Savings
Fund Plan 857,700 * 152,153,100
----------- --------------
144,311,466 52,290,152,516 143,260,692
=========== ============== ===========
1993
----
January 1 - May 4 137,159,607 124 17,007,791,268
Shares sold May 5 4,494,000
-----------
May 5 - December 31 141,653,607 241 34,138,519,287
Shares sold at various
times during the year -
Dividend Reinvestment
Plan 632,341 * 102,395,031
Employee Savings
Fund Plan 140,000 22 3,080,000
Acquisition - Syracuse
Suburban Gas Company,
Inc. 1,109 * 350,374
----------- --------------
142,427,057 51,252,135,960 140,416,811
=========== ============== ===========
* Number of days outstanding not shown as shares represent an accumulation of weekly,
monthly and quarterly sales throughout the year. Share days for shares sold are based
on the total number of days each share was outstanding during the year.
Note: Earnings per share calculated on both a primary and fully diluted basis are the
same due to the effects of rounding.
/TABLE
EXHIBIT 12
- ----------
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
STATEMENT SHOWING COMPUTATIONS OF RATIO OF EARNINGS TO FIXED CHARGES, RATIO OF EARNINGS TO
FIXED CHARGES WITHOUT AFC AND RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED STOCK
DIVIDENDS
Year Ended December 31,
------------------------------------------------------------
1995 1994 1993 1992 1991
---- ---- ---- ---- ----
A. Net Income per Statements
of Income (a) $248,036 $176,984 $271,831 $256,432 $243,369
B. Taxes Based on Income or
Profits 159,393 111,469 147,075 155,504 133,895
-------- -------- -------- -------- --------
C. Earnings, Before Income
Taxes 407,429 288,453 418,906 411,936 377,264
D. Fixed Charges (b) 314,973 315,274 319,197 332,413 346,255
-------- -------- -------- -------- --------
E. Earnings Before Income
Taxes and Fixed Charges 722,402 603,727 738,103 744,349 723,519
F. Allowance for Funds Used
During Construction 9,050 9,079 16,232 21,431 18,931
-------- -------- -------- ------- -------
G. Earnings Before Income
Taxes and Fixed Charges
without AFC $713,352 $594,648 $721,871 $722,918 $704,588
======== ======== ======== ======== ========
Preferred Dividend Factor:
H. Preferred Dividend
Requirements $ 39,596 $ 33,673 $ 31,857 $ 36,512 $ 40,411
-------- -------- -------- --------- --------
I. Ratio of Pre-Tax Income
to Net Income (C / A) 1.64 1.63 1.54 1.61 1.55
-------- --------- --------- --------- ---------
J. Preferred Dividend Factor
(H x I) $ 64,937 $ 54,887 $ 49,060 $ 58,784 $ 62,637
K. Fixed Charges as above (D) 314,973 315,274 319,197 332,413 346,255
-------- -------- -------- -------- --------
L. Fixed Charges and Preferred
Dividends Combined $379,910 $370,161 $368,257 $391,197 $408,892
======== ======== ======== ======== ========
M. Ratio of Earnings to
Fixed Charges (E / D) 2.29 1.91 2.31 2.24 2.09
-------- -------- -------- -------- --------
N. Ratio of Earnings to Fixed
Charges without AFC (G / D) 2.26 1.89 2.26 2.17 2.03
-------- -------- -------- -------- --------
O. Ratio of Earnings to Fixed
Charges and Preferred
Dividends Combined (E / L) 1.90 1.63 2.00 1.90 1.77
-------- ------- -------- -------- --------
(a) Includes the effects of amortization of amounts deferred, under the 1989 Agreement,
$15,746 for 1993, $20,257 for 1992 and $31,176 for 1991.
(b) Includes a portion of rentals deemed representative of the interest factor $27,312 for
1995, $29,396 for 1994, $27,821 for 1993, $31,697 for 1992 and $34,616 for 1991.
/TABLE
EXHIBIT 21
- ----------
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SUBSIDIARIES OF THE REGISTRANT
Name of Company State of Organization
- --------------- ---------------------
Opinac Energy Corporation Province of Ontario, Canada
(Note 1)
NM Uranium, Inc. Texas
EMCO-TECH, Inc. (Note 2) New York
NM Suburban Gas, Inc. New York
NM Holdings, Inc. New York
Moreau Manufacturing Corporation New York
Beebee Island Corporation New York
Note 1: At December 31, 1995, Opinac Energy Corporation owns
Canadian Niagara Power Company, Limited, which is
incorporated in the Province of Ontario, Canada and Plum
Street Enterprises, Inc., which is incorporated in the
State of Delaware. Canadian Niagara Power Company,
Limited, owns Cowley Ridge Partnership (an Alberta,
Canada general partnership) and Cowley Ridge Wind Power
Company, Inc. (incorporated in the Province of Alberta,
Canada).
Note 2: EMCO-TECH, Inc. is inactive at December 31, 1995.
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, 33-42771 and 33-54829) 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, 33-54827 and 33-
55546) of Niagara Mohawk Power Corporation of our report dated
January 25, 1996 appearing in the Company's Form 10-K dated March
28, 1996. We also consent to the incorporation by reference of our
report on the financial statement schedules, which appears in this
Form 10-K.
/s/ Price Waterhouse LLP
Syracuse, New York
March 28, 1996
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 28, 1996 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 28, 1996
- --------------------
William F. Allyn
/s/ Albert J. Budney, Jr. Director,
- ------------------------- President and Chief
Albert J. Budney, Jr. Operating Officer March 28, 1996
/s/ Lawrence Burkhardt, III Director March 28, 1996
- ---------------------------
Lawrence Burkhardt, III
/s/ Douglas M. Costle Director March 28, 1996
- ---------------------
Douglas M. Costle
Signature Title Date
- --------- ----- ----
/s/ Edmund M. Davis Director March 28, 1996
- -------------------
Edmund M. Davis
Chairman of the
Board of Directors
and Chief Executive
/s/ William E. Davis Officer March 28, 1996
- --------------------
William E. Davis
/s/ William J. Donlon Director March 28, 1996
- ---------------------
William J. Donlon
/s/ Edward W. Duffy Director March 28, 1996
- -------------------
Edward W. Duffy
/s/ Bonnie Guiton Hill Director March 28, 1996
- ----------------------
Bonnie Guiton Hill
/s/ Henry A. Panasci, Jr. Director March 28, 1996
- -------------------------
Henry A. Panasci, Jr.
/s/ Patti McGill Peterson Director March 28, 1996
- -------------------------
Patti McGill Peterson
/s/ Donald B. Riefler Director March 28, 1996
- ---------------------
Donald B. Riefler
Director March 28, 1996
- -----------------------
Stephen B. Schwartz
Signature Title Date
- --------- ----- ----
Senior Vice President
and Principal Financial
/s/ John W. Powers Officer March 28, 1996
- ------------------
John W. Powers
Vice President-Controller
and Principal Accounting
/s/ Steven W. Tasker Officer March 28, 1996
- --------------------
Steven W. Tasker