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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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(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, 1997
OR
/ / Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 for the transition
period from ______ to ______
Commission file number 1-2987
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NIAGARA MOHAWK POWER CORPORATION
(Exact name of registrant as specified in its charter)
State of New York 15-0265555
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(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
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Securities registered pursuant to Section 12(b) of the
Act:
(Each class is registered on the New York Stock Exchange)
Title of each class
Common Stock ($1 par value)
Preferred Stock ($100 par Preferred Stock ($25 par
value-cumulative): value-cumulative):
3.40% Series 4.10% Series 6.10% Series 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
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Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements
for the past 90 days. Yes /X/ No / /
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not
be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part
III of this Form 10-K or any amendment to this Form 10-K /X/
State the aggregate market value of the voting stock held by non-
affiliates of the registrant.
Approximately $1,800,000,000 at March 26, 1998.
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 value, outstanding at March 26, 1998:
144,419,351.
NIAGARA MOHAWK POWER CORPORATION
INFORMATION REQUIRED IN FORM 10-K
PART I
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Item Number
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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
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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
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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
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Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K.
Signatures
NIAGARA MOHAWK POWER CORPORATION
GLOSSARY OF TERMS
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TERM DEFINITION
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AFC Allowance for Funds Used During Construction
BTU British Thermal Units
Clean Air
Act Clean Air Act Amendments of 1990
CNG CNG Transmission Corporation
CNP Canadian Niagara Power Company, Limited
COPS Competitive Opportunities Proceeding
CTC Competitive Transition Charges
CWIP Construction Work in Progress
DEC New York State Department of Environmental
Conservation
DOE U. S. Department of Energy
Dth Dekatherm: one thousand cubic feet of gas with a
heat content of 1,000 British Thermal Units per
cubic foot
EBITDA Earnings before Interest Charges, Interest Income,
Income Taxes, Depreciation and Amortization (a non-
GAAP measure of cash flow)
EPA U. S. Environmental Protection Agency
FAC Fuel Adjustment Clause: a clause in a rate schedule
that provides for an adjustment to the customer's
bill if the cost of fuel varies from a specified
unit cost
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
GAAP Generally Accepted Accounting Principles
GRT Gross Receipts Tax
GWh Gigawatt-hour: one gigawatt-hour equals one billion
watt-hours
IPP Independent Power Producer: any person that owns or
operates, in whole or in part, one or more
Independent Power Facilities
IPP Party Independent Power Producers that are a party to the
MRA
ISO Independent System Operator
KW Kilowatt: one thousand watts
KWh Kilowatt-hour: a unit of electrical energy equal to
one kilowatt of power supplied or taken from an
electric circuit steadily for one hour
MERIT Measured Equity Return Incentive Term
MGP Manufactured Gas Plant
MRA Master Restructuring Agreement - an agreement to
terminate, restate or amend IPP Party power
purchase agreements
MRA Recoverable costs to terminate, restate or amend IPP
regulatory Party contracts, which are deferred and amortized
asset under PowerChoice
MW Megawatt: one million watts
MWh Megawatt-hour: one thousand kilowatt-hours
NOx Nitrogen Oxide: gases formed in great part from
atmospheric nitrogen and oxygen when combustion
takes place under conditions of high temperature
and high pressure; considered a major air pollutant
NPL Federal National Priorities List for Uncontrolled
Hazardous Waste Sites
NYS Supreme Supreme Court of the State of New York, Albany
Court County
NRC U. S. Nuclear Regulatory Commission
NYPA New York Power Authority
NYPP New York Power Pool
NYPP Member Eight Member Systems are: the seven New York State
Systems investor-owned electric utilities and NYPA
NYSERDA New York State Energy Research and Development
Authority
PowerChoice Company's five-year electric rate agreement, which
agreement incorporates the MRA, approved in February 1998
PPA Power Purchase Agreement: long-term contracts under
which a utility is obligated to purchase
electricity from an IPP at specified rates
PRP Potentially Responsible Party
PSC New York State Public Service Commission
PURPA Public Utility Regulatory Policies Act of 1978, as
amended. One of five bills signed into law on
November 8, 1978, as the National Energy Act. It
sets forth procedures and requirements applicable
to state utility commissions, electric and natural
gas utilities and certain federal regulatory
agencies. A major aspect of this law is the
mandatory purchase obligation from qualifying
facilities.
QF Qualifying Facility: an individual (or corporation)
that owns and/or operates a generating facility but
is not primarily engaged in the generation or sale
of electric power. QFs are either power production
or cogeneration facilities that qualify under
Section 201 of PURPA.
ROE Return on Common Stock Equity
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. 101
No. 101 "Regulated Enterprises - Accounting for the
Discontinuance of Application of FASB Statement No.
71"
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. 121
No. 121 "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of"
SFAS Statement of Financial Accounting Standards No. 130
No. 130 "Reporting Comprehensive Income"
SFAS Statement of Financial Accounting Standards No. 131
No. 131 "Disclosures about Segments of an Enterprise and
Related Information"
SFAS Statement of Financial Accounting Standards No. 132
No. 132 "Employers' Disclosure about Pensions and Other
Postretirement Benefits"
SO2 Sulfur Dioxide: a colorless gas of compounds of
sulfur and oxygen which is produced primarily by
the combustion of fossil fuel
stranded Utility costs that may become unrecoverable due to
costs a change in the regulatory environment
Unit 1 Nine Mile Point Nuclear Station Unit No. 1
Unit 2 Nine Mile Point Nuclear Station Unit No. 2
NIAGARA MOHAWK POWER CORPORATION
PART I
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ITEM 1. BUSINESS.
Niagara Mohawk Power Corporation (the "Company"), organized 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 Part II, Item 8.
Financial Statements and Supplementary Data - "Note 12. Information
Regarding the Electric and Gas Businesses."
GENERAL
Until recent years, 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 upheld the utility's
exclusive right to provide service in its franchise areas in
exchange for the utility company's obligation to provide universal
service to customers in its service territory, subject to cost-of-
service regulation. Such regulation often encouraged regulators
and other governmental bodies to use utilities as vehicles to
advance social programs and collect taxes. In general, prices were
established based on cost-of-service, including a fair rate of
return and utilities were allowed to fully recover all prudently
incurred costs. Cash flows were relatively predictable, as was the
industry's ability to sustain 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 have included state-mandated purchased power
costs from IPPs, at costs far exceeding the Company's actual
avoided costs, as well as the costs of high taxes in the State of
New York. Avoided costs are the costs the Company would otherwise
incur to generate power if it did not purchase electricity from
another source.
While the Company was experiencing rising costs, rapid
technological advances have significantly reduced the price of new
generation and significantly improved the performance of smaller
scale generating units. 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.
In 1997, the Company entered into two related agreements that
it believes will significantly improve its financial outlook.
Pursuant to the Company's PowerChoice agreement, entered into with
the PSC, which regulates utilities in the State of New York, the
Company has agreed to a five year rate plan and has agreed to
divest its fossil and hydro generating assets, representing 4,217
MW of capacity and approximately $1,100 million of net book value.
Pursuant to the MRA, the Company and 15 IPPs have agreed to
terminate, restate or amend 28 PPAs in exchange for cash, shares of
Company common stock and certain financial contracts.
For a discussion of events that occurred during 1997 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
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Regulation and Rates
IPPs
New York Power Authority
Other Purchased Power
Fuel for Electric Generation
Gas Delivery
Gas Supply
Financial Information About Industry Segments
Environmental Matters
Research and Development
Nuclear Operations
Construction Program
Electric Supply Planning
Electric Delivery Planning
Insurance
Employee Relations
Seasonality
In addition, for a discussion of the Company's properties, 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
Several critical initiatives have been undertaken by various
regulatory bodies and the Company that have had, and are likely to
continue to have, a significant impact on the reshaping of the
Company and the utility industry. See Part II, Item 7.
Management's Discussion and Analysis of Financial Condition and
Results of Operations - "PSC Competitive Opportunities Proceeding -
Electric," "FERC Rulemaking on Open Access and Stranded Cost
Recovery," and "Other Federal and State Regulatory Initiatives -
PSC Proposal of New IPP Operating and PPA Management Procedures,"
" - Generic Gas Rate Proceeding" and " - NRC and Nuclear Operating
Matters" for a discussion of these other initiatives.
POWERCHOICE AGREEMENT AND THE MRA. For a discussion of the
PowerChoice agreement and the MRA, see Part II, Item 7.
Management's Discussion and Analysis of Financial Condition and
Results of Operations - "Master Restructuring Agreement and the
PowerChoice Agreement".
MULTI-YEAR GAS RATE SETTLEMENT AGREEMENT AND GENERIC GAS RATE
PROCEEDING. For a discussion of the three-year gas rate settlement
agreement that was conditionally approved by the PSC in December
1996, see Part II, Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations - Other Federal and
State Regulatory Initiatives - "Multi-Year Gas Rate Settlement
Agreement" and "- Generic Gas Rate Proceeding."
PRICE DISCOUNTS. For a discussion of price 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."
PSC AUDIT. In September 1996 as a result of the Company's
investigation of a contract with a scrap dealer, Joseph Barsuk,
Inc. ("Barsuk"), the PSC directed its staff to investigate the
prudence of several long term contracts involving scrap metal and
the circumstances surrounding the letting and administration of
those contracts. In February 1997, the PSC concluded that a more
comprehensive investigation was required to ensure that the
Company's ethics and internal control procedures are being
effectively implemented. The final report on the prudence review
was issued on January 21, 1998 and contained various
recommendations to strengthen the Company's scrap handling
procedures, its ethics program and its internal control processes.
Actions are currently underway to address recommendations in the
report. Further, the Company will refund to customers between $2.9
million and $3.7 million related to losses from actions by a scrap
metal dealer to defraud the Company between 1970 and 1990 and has
also committed to continue to strengthen its ethics program and
internal controls. The Company is engaged in litigation against
Barsuk and a former inside director of the Company who retired in
1988 to recover damages from such dealings, but is unable to
determine the outcome of this matter.
IPPs
In 1997, the Company purchased 13,520,000 MWh or about 33% of
its total power supply from IPPs. For a discussion of Company
efforts to reduce its IPP costs, see Item 3. Legal Proceedings,
Part II, Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - "Master Restructuring
Agreement and the PowerChoice Agreement" and "Other Federal and
State Regulatory Initiatives - PSC Proposal of New IPP Operating
and PPA Management Procedures" and Part II, Item 8. Financial
Statements and Supplementary Data - "Note 9. Commitments and
Contingencies - Long-Term Contracts for the Purchase of Electric
Power."
NEW YORK POWER AUTHORITY
The Company presently has contractual rights to purchase
electricity from a number of generating facilities owned by the
NYPA. In 1997, these purchases amounted to 7,578,000 MWh, or about
19% of the Company's total power supply requirements. The Company
credits to its residential customers, pursuant to the terms of the
agreements with NYPA, a portion of the low cost power purchased
from NYPA hydro power sources. Refer to Part II, Item 8.
Financial Statements and Supplementary Data - "Note 9. Commitments
and Contingencies - Long-Term Contracts for the Purchase of
Electric Power" for a table that summarizes the NYPA generating
source, amounts of power, and the contract expiration dates for
NYPA electricity which the Company was entitled to purchase as of
January 1, 1998.
On May 23, 1997, the Company signed an agreement with NYPA and
the PSC that allows NYPA's current industrial customers to continue
to receive their power allocations from NYPA's James A. FitzPatrick
nuclear plant. The agreement also protects the Company's remaining
customers by generally requiring the reimbursement by NYPA of
stranded costs which may result from any NYPA sales above current
levels. The agreement enables the State of New York to continue to
use NYPA's electricity to keep and create jobs and investment in
New York State while protecting the financial interests of the
Company. This agreement terminated litigation pending before the
PSC and the FERC regarding NYPA's power sales to industrial
customers.
OTHER PURCHASED POWER
Power purchased in 1997 from sources other than IPPs and NYPA
amounted to 1,844,000 MWh, representing approximately 4% 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, based on market prices.
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
and the price the Company pays or receives for that power.
FUEL FOR ELECTRIC GENERATION
The PowerChoice agreement will eliminate the Company's FAC,
which provided for partial pass-through to customers of fuel and
purchased power cost fluctuations from amounts forecast. Also, the
Company will auction its fossil and hydro generating assets in
accordance with the restructuring under PowerChoice. (See Part II,
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - "Master Restructuring
Agreement and the PowerChoice Agreement.")
COAL. The C. R. Huntley and Dunkirk Steam Stations, the
Company's only coal fired generating stations, are expected to burn
about 1.8 million and 1.4 million tons of coal, respectively, in
1998. The Company purchased its 1997 coal requirements under
short-term contracts and anticipates obtaining its total 1998 coal
requirements under short-term contracts as well. The average level
of coal supply was 25 days, which is managed for supply risk.
The annual average cost of coal burned in 1995, 1996 and 1997
was $1.42, $1.39, and $1.41 respectively, per million BTU, or
$36.81, $36.00 and $36.68, respectively, per ton.
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 the lower
cost fuel depending on fuel market conditions. During 1995, 1996
and 1997, natural gas was the predominant fuel used. However,
generation at this station was curtailed significantly during this
period because of the requirement to purchase IPP power and excess
capacity in the region. In early 1995, modifications were
completed at the Oswego Steam Station that provided a limited
capability for using natural gas for electric generation. The
Oswego Steam Station's primary fuel is residual oil.
The Company currently purchases all natural gas for the Albany
and Oswego Steam Stations from the spot market. 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.
The Company has a 25% ownership interest in Roseton Steam
Station Units No. 1 and 2 (the "Roseton Units"). Both Roseton
Units have dual fuel capability with residual oil as the primary
fuel and natural gas as the alternate fuel. Central Hudson Gas and
Electric Corporation, a co-owner and the operator of the Roseton
Steam Station, has one contract for the supply of up to
approximately 100,000 Dths per day of natural gas for use at the
Roseton Units. The natural gas supply is used primarily during off
peak months (April through October of each year), minimizing the
exposure to interruption. In 1997, approximately 0.7 million Dth
(the Company's share) of gas were used at the Roseton Units.
The annual average cost of natural gas burned by the Company,
including the Roseton Steam Station, from 1995 through 1997 was
$1.65, $1.96, and $2.50 respectively, per million BTU, or $1.65,
$1.96 and $2.50, respectively, per Dth.
RESIDUAL OIL. The Company's total requirements for residual
oil in 1998 for its Albany and Oswego Steam Stations are estimated
at approximately 1.0 million barrels. Fuel sulfur content
standards instituted by New York State require 1.5% sulfur content
fuel oil to be burned at the Albany Steam Station. 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, 1997, there were approximately 386,000
barrels of oil, or more than a 16-day supply, at the Oswego Steam
Station and approximately 350,000 barrels of oil, or a 30-day
supply, at the Albany Steam Station, based on recent burn
projections.
The average price of Oswego Unit No. 6 oil at January 1, 1998
was approximately $22.00 per barrel for 0.7% sulfur oil. For 1.5%
sulfur oil, the average price was approximately $17.50 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.
The supply of residual oil for the Roseton Units has been
arranged by Central Hudson Gas and Electric Corporation. A
requirements contract is currently in place with options to extend
the contract period.
The annual average cost of residual oil burned at the Albany,
Oswego and Roseton Steam Stations from 1995 through 1997 was $3.41,
$3.81 and $4.05, respectively, per million BTU, or $21.66, $24.15
and $25.58, 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
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Uranium Concentrates 2002 2002
Conversion 2002 2002
Enrichment 2003 2003
Fabrication 2007 2006
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. 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, 1996 and 1997
was $0.61, $0.60 and $0.54 per million BTU, respectively. The cost
of fuel utilized at Unit 2 for 1995 through 1997 was $0.51, $0.50
and $0.49 per million BTU, respectively.
For a discussion of nuclear fuel disposal costs and the
disposal of nuclear wastes, 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.
Summary of Significant Accounting Policies - Depreciation,
Amortization and Nuclear Generating Plant Decommissioning Costs"
and "Note 3. Nuclear Operations." For a discussion of the
Company's plans to form a New York Nuclear Operating Company, see
Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations - "Master Restructuring
Agreement and the PowerChoice Agreement."
GAS DELIVERY
The Company sells, 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 connection with Iroquois Gas
Transmission and one with Empire State Pipeline.
GAS SUPPLY
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 primarily seasonal
and influenced by weather factors. The Company purchases its
natural gas for sale to its customers under firm and short-term
spot contracts, which is transported on both firm and interruptible
transportation contracts. During 1997, about 92% and 8% of the
Company's natural gas supply was purchased under firm contracts and
short-term spot contracts, respectively (generally longer than 30
days) (See Part II. Item 8 - Financial Statements and
Supplementary Data - "Note 9. Commitments and Contingencies - Gas
Supply, Storage and Pipeline Commitments"). In addition, the
Company has a commitment with CNG to provide gas storage capability
until March 2002. For a discussion of the PSC staff's proposal
that natural gas utilities exit the business of purchasing natural
gas for customers over the next five years, See Part II. Item 7 -
Management's Discussion and Analysis of Financial Condition and
Results of Operations - "Generic Gas Rate Proceeding."
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
See Part II, Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations and Item 8. Financial
Statements and Supplementary Data - "Note 12. Information
Regarding the Electric and Gas Businesses."
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 health and safety 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
1997 totaled approximately $37.1 million, of which approximately
$5.6 million was capitalized as pollution control equipment or
plant environmental surveillance and approximately $31.5 million
was charged to operating expense for remediation, operation of
environmental monitoring and waste disposal programs. Expenditures
for 1998 are estimated to total $41.6 million, of which $9.0
million is expected to be capitalized and $32.6 million charged to
operating expense. Anticipated expenditures for 1999 are estimated
to total $42.5 million, of which $5.1 million is expected to be
capitalized and $37.4 million charged to operating expense. The
expenditures for 1998 and 1999 include the estimated costs for the
Company's expected proportionate share of the costs for site
investigation and remediation of waste sites discussed under
"Solid/Hazardous Waste" below. Costs for site investigation and
remediation are included in operating expense to the extent actual
costs do not exceed the amount provided for in rates, in which
case, the excess costs are deferred for future recovery through
cost-of-service based rates.
ISO 14001. During 1997, the Company had all of its fossil and
nuclear generating assets (the Oswego, Albany, Huntley and Dunkirk
Steam Stations and Nine Mile Point) certified to the ISO 14001
environmental management system standard. The registration audits
of these facilities was conducted by Advanced Waste Management
Systems. The Company's position has been and continues to be that
an effective environmental management system is necessary to
prudently manage environmental issues and minimize environmental
liabilities.
The Company believes that it is probable that costs associated
with environmental compliance will continue to be recovered through
the ratemaking process. For a discussion of the circumstances
regarding the Company's continued ability to recover these types of
expenditures in rates, see Part II, Item 8. Financial Statements
and Supplementary Data - "Note 2. Rates and Regulatory Issues and
Contingencies."
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 (the Albany, Huntley, Oswego and Dunkirk Steam
Stations) have 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
will continue to have a substantial and increasing impact upon the
operation of fossil-fired electric power plants in future years.
The acid rain provisions of the Clean Air Act (Title IV)
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 were to be achieved in two phases - Phase I was
to be completed by January 1, 1995 and Phase II will be completed
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 reasonably available
control technology ("RACT") on all of the Company's coal, oil and
gas-fired units by May 31, 1995. Compliance with Title I RACT
requirements at the Company's units was achieved by installing low
NOx burners or other combustion control technology.
Phase II requirements associated with Title IV of the Clean
Air Act (targeted for the year 2000 and beyond) will require the
Company to further reduce its SO2 emissions at all of its fossil
generating units. Possible options for Phase II SO2 compliance
beyond those considered for Phase I compliance include 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, air emission sources located in upstate New York (which
includes all of the Company's air emission sources) will have to
reduce NOx emissions by May, 1999 by 55 percent relative to 1990
levels. In Phase III, these air emission sources will have to
reduce NOx emissions in May 2003 by 75 percent relative to 1990
levels. The Memorandum of Understanding provides that the
specified reductions in Phase III may be modified if evidence shows
that alternative NOx reductions, together with other emission
reductions, will satisfy the air quality standard across the
region. The DEC will be developing its Phase II NOx regulations in
1998. The need for and extent of any further reductions needed in
Phase III will not be determined until 1999 or later. 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, although such costs could be
significant.
Potential air regulatory developments may impact the Company
in the future including: (1) a proposed "long range ozone
transport" rulemaking for utilities and other NOx sources in the
Northeast and Midwest to substantially reduce their NOx emissions;
and (2) a revised National Ambient Air Quality Standard for
Particulate Matter that includes fine particulates.
The Company spent approximately $5 million, $0.1 million, and
$0.1 million in capital expenditures in 1995, 1996 and 1997,
respectively, on projects at the fossil generation plants
associated with Phase I compliance. The Company has included $1.0
million in its 1998 through 2000 construction forecast for Phase II
compliance which will become effective January 1, 2000. For a
discussion on the Company's plans to sell its fossil and hydro
assets, see Part II, Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations - "Master
Restructuring Agreement and the PowerChoice Agreement." For a
discussion of the Company's negotiations with DEC of a Consent
Decree addressing past opacity excursions and future opacity
compliance issues, see Item 3. Legal Proceedings.
WATER. The Company is required to comply with applicable
Federal and State water quality requirements, including the 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. In
addition, hydroelectric facilities are required to obtain Clean
Water Act certifications as part of the FERC licensing/relicensing
process. Such certifications have been issued or are pending for
a substantial portion of the Company's hydroelectric facilities.
Conditions of the permits typically 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.
LOW LEVEL RADIOACTIVE WASTE. See Part II, Item 8. Financial
Statements and Supplementary Data - "Note 3. Nuclear Operations -
Low Level Radioactive Waste."
SOLID/HAZARDOUS WASTE. The public utility industry typically
utilizes and/or generates in its operations a broad range of
hazardous and 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
potential areas of concern and aid in compliance with such
requirements. Environmental laws can impose liability for the
entire cost of site remediation upon each of the parties that have
sent waste to a contaminated site regardless of fault or the
lawfulness of the original disposal activity. The Company is also
currently investigating and remediating, as necessary to meet
current environmental standards, certain properties associated with
its former gas manufacturing operations and other properties which
the Company has learned may be impacted by industrial waste, as
well as investigating identified industrial waste sites where
Company waste materials may have been sent. 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 124 such sites with which it
has been or may be associated, including 76 which are Company-
owned. The Company-owned sites include 21 former MGP sites, 10
industrial waste sites and 45 operating property sites where
corrective actions may be deemed necessary to prevent, contain
and/or remediate impacts to soil and/or water in the vicinity. Of
these Company-owned sites, Saratoga Springs is on the NPL published
by the EPA. The number of owned sites has increased as the Company
has established a program to actively identify and manage potential
areas of concern at its electric substations. This effort resulted
in identifying an additional 32 sites in 1997. The 48 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 fund some share of
the remedial costs. Although one party can, as a matter of law, be
held liable for all of the remedial costs at a site, regardless of
fault, in practice costs are usually allocated among PRPs.
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 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 investigations are ongoing at most
sites, the estimated cost of any remedial action is subject to
change.
Estimates of the Company's potential liability for Company-
owned sites 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 and costs at similarly
situated sites. Additionally, as further described below, the
Company's estimating approach now includes a process for certain
sites where these factors are developed and reviewed using direct
input and support obtained from the DEC. 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 at certain of these sites where other PRPs are
identified and is contesting liability accordingly.
As a consequence of site characterizations and assessments
completed to date, the Company has accrued a liability of $155
million for these owned sites, representing its best current
estimate for its share of the costs for investigation and
remediation. The high end of the range is presently estimated at
approximately $365 million. The amount accrued at December 31,
1997, incorporates the additional electric substations, previously
mentioned, and a change in the method used to estimate the
liability for 27 of its largest sites, to rely upon a decision
analysis approach. This method includes developing several
remediation approaches for each of the 27 sites, using the factors
previously described, and then assigning a probability to each
approach. The probability represents the Company's best estimate
of the likelihood of the approach occurring using input received
directly from the DEC. The probable costs for each approach are
then calculated to arrive at an expected value. While this
approach calculates a range of outcomes, the Company has accrued
the sum of the expected values for these sites. The amount accrued
for the Company's remaining owned sites represents either costs
resulting from feasibility studies or engineering estimates, the
Company's share of a PRP allocation or, where no better estimate is
available, the low end of a range of possible outcomes.
The majority of cost estimates for currently owned properties
relate to the MGP sites, particularly the Harbor Point site (Utica,
New York), which includes five surrounding non-owned sites. In
October 1997, the Company submitted a draft feasibility study to
the DEC for the Harbor Point and surrounding sites. The study
indicates a range of viable remedial approaches. However, a final
determination has not been made concerning the remedial approach to
be taken. This range consists of a low end of $22 million and a
high end of $230 million with an expected value calculation of $51
million, which is included in the total amounts accrued at December
31, 1997. The range represents the total costs to remediate Harbor
Point and the surrounding sites and does not consider contributions
from other PRPs. The Company anticipates receiving comments from
the DEC on the draft feasibility study by the spring of 1999. At
this time, the Company cannot definitively predict the nature of
the DEC proposed remedial action plan or the range of remediation
costs it will require. While the Company does not expect to be
responsible for the entire cost to remediate these properties, it
is not possible at this time to determine its share of the cost of
remediation. In May 1995, the Company filed a complaint, pursuant
to applicable Federal and New York State law, in the U.S. District
Court for the Northern District of New York against several
defendants seeking recovery of past and future costs associated
with the investigation and remediation of the Harbor Point and
surrounding sites. In a motion currently pending before the Court,
the New York State Attorney General has moved to dismiss the
Company's claims against the State of New York, the New York State
Department of Transportation, the Thruway Authority and Canal
Corporation. The Company has opposed this motion. The case
management order presently calls for the close of discovery on
December 31, 1998. As a result, the Company cannot predict the
outcome of the pending litigation against other PRPs or the
allocation of the Company's share of the costs to remediate the
Harbor Point and surrounding sites.
With respect to sites not owned by the Company, but for which
the Company has been or may be associated as a PRP, the Company has
recorded a liability of $65 million, representing its best current
estimate of its share of the total cost to investigate and
remediate these sites. Total costs to investigate and remediate
all non-owned sites is estimated to be approximately $285 million
in the unlikely event the Company is required to assume 100% of the
responsibility for these sites. The Company has denied any
responsibility for certain of these PRP sites and is contesting
liability accordingly. Eight of the PRP sites are included on the
NPL. The Company estimates its share of the liability for these
eight sites is not material and has included the amount in the
determination of the amounts accrued.
Estimates of the Company's potential liability for sites not
owned by the Company, but for which the Company has been identified
as an alleged PRP, have been derived by estimating the total cost
of site clean-up and then applying a Company contribution factor to
that estimate where appropriate. 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 Fed. Reg. 119). A contribution
factor is calculated, when there is a reasonable basis for it, that
uses either a pro rata share based upon the total number of PRPs
named or otherwise identified, or the percentage agreed upon with
other PRPs through steering committee negotiations or by other
means. In some instances, the Company has been unable to determine
a contribution factor and has included in the amount accrued the
total estimated costs to remediate the sites. 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. While the Company has accrued an obligation of
$220 million for its owned and non-owned sites, the high end of the
range of remedial obligations is currently estimated to be
approximately $650 million.
In May 1997, the DEC executed an Order on Consent (the "1997
Order") which serves to keep the annual cash requirement for
certain site investigation and remediation ("SIR") level (at
approximately $15 million per year), as well as provide for an
annual site prioritization mechanism. As executed, the 1997 Order
expands the scope of the original 1992 Order, which covered 21
former MGP sites, to encompass 52 sites with which the Company has
been associated. The agreement is supported by the decision
analysis approach, which the Company and the DEC will continue to
revise on an annual basis to address SIR progress and site
priorities relative to establishing the annual cost cap, as well as
determining the Company's liability for these sites. The Saratoga
Springs and Harbor Point MGP sites are being investigated and
remediated pursuant to separate regulatory Consent Orders with the
EPA and the DEC, respectively. However, the annual costs
associated with the remediation of these sites are included in the
cash requirements under the amended 1997 Order.
PowerChoice and the Company's gas settlement provide for the
recovery of SIR costs over the settlement periods. The Company
believes future costs, beyond the settlement periods, will continue
to be recovered in rates. Based upon this assessment, a regulatory
asset has been recorded in the amount of $220 million, representing
the future recovery of remediation obligations accrued to date. As
a result, the Company does not believe SIR costs will have a
material adverse effect on its results of operations or financial
condition. See also Part II, Item 8. Financial Statements and
Supplementary Data - "Note 2. Rate and Regulatory Issues and
Contingencies."
Where appropriate, the Company has provided notices of
insurance claims to carriers with respect to the investigation and
remediation costs for MGP, industrial waste sites and sites for
which the Company has been identified as a PRP. To date, the
Company has reached settlements with a number of insurance
carriers, resulting in payments to the Company of approximately $36
million, net of costs incurred in pursuing recoveries. The Company
has agreed, in its PowerChoice settlement, to amortize the portion
allocated to the electric business, or approximately $32 million,
over a ten-year period. The remaining portion relates to the gas
business and is being amortized over the three-year settlement
period.
For a discussion of additional environmental legal
proceedings, see Item 3. Legal Proceedings.
RESEARCH AND DEVELOPMENT
The Company maintains a research and development ("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; (5) promoting economic development and (6) improving the
quality of life for our customers with new electric technologies.
R&D expenditures in 1995 through 1997 were not material to the
Company's results of operations or financial condition.
NUCLEAR OPERATIONS
See Part II, Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations - "Other Federal and
State Regulatory Initiatives - NRC and Nuclear Operating Matters"
and Part II, Item 8. Financial Statements and Supplementary Data -
"Note 3. Nuclear Operations."
CONSTRUCTION PROGRAM
See Part II, Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations - "Financial
Position, Liquidity and Capital Resources - Construction and Other
Capital Requirements" and Part II, Item 8. Financial Statements
and Supplementary Data - "Note 9. Commitments and Contingencies -
Construction Program."
ELECTRIC SUPPLY PLANNING
Under the PowerChoice agreement, the Company has agreed to
put all of its fossil and hydro generation assets up for auction.
Winning bids would be selected within 11 months of PSC approval of
the auction plan, which was filed with the PSC on December 1, 1997
separately from the PowerChoice agreement. If the Company does not
receive an acceptable positive bid for an asset, the Company agreed
to form a subsidiary to hold any such assets and then to legally
separate this subsidiary from the Company through a spin-off to
shareholders or otherwise. After the foregoing process is
complete, the Company agreed not to own any non-nuclear generating
assets in the State of New York, subject to certain limited
exceptions provided in the PowerChoice agreement.
ELECTRIC DELIVERY PLANNING
(See Part II. Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations - "FERC Rulemaking on
Open Access and Stranded Cost Recovery.")
As of January 1, 1998, the Company had approximately 130,000
miles of transmission and distribution lines for electric delivery.
Evaluation of these facilities relative to NYPP and Northeast Power
Coordinating Council planning criteria and anticipated Company
internal and external demands is an ongoing process intended to
minimize the capital requirements for expansion of these
facilities. (For a discussion of major restoration of the
Company's electric delivery facilities in northern New York as a
result of an ice storm in January 1998, see Part II, Item 8.
Financial Statements and Supplementary Data - "Note 13. Subsequent
Event)."
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.
Transmission planning studies are presently in progress to
investigate the system impact of two proposed generation projects,
U.S. Generating Company's 1080 MW plant located in Athens, New York
and the Company's 723 MW repowering of the Albany Steam Station in
Bethlehem, New York. (See Item 2. Properties -"Electric Service").
Both of these projects are filing for Article X certification with
a projected in service date of 2001.
INSURANCE
As of January 31, 1998, the Company's directors and officers
liability insurance was renewed. This coverage includes nuclear
operations and insures the Company against obligations incurred as
a result of its indemnification of directors and officers. 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. In addition, for a
discussion of nuclear insurance, see Part II, Item 8. Financial
Statements and Supplementary Data - "Note 3. Nuclear Operations -
Nuclear Liability Insurance" and - "Nuclear Property Insurance."
EMPLOYEE RELATIONS
The Company's work force at December 31, 1997 numbered
approximately 8,500 of whom approximately 71% were union members.
It is estimated that approximately 78% of the Company's total labor
costs are applicable to operation and maintenance and approximately
22% are applicable to construction and other accounts.
All of the Company's non-supervisory production and clerical
workers subject to collective bargaining are represented by the
International Brotherhood of Electrical Workers ("IBEW"). In April
1996, the Company and the IBEW agreed on a five-year, three month
labor agreement, which provides for wage increases of approximately
2% to 3% in each of the subsequent four years.
SEASONALITY
See Item 2. Properties - "Electric Service" and Part II, Item
8. Financial Statements and Supplementary Data - "Note 14.
Quarterly Financial Data (Unaudited)."
ITEM 2. PROPERTIES.
ELECTRIC SERVICE
As of January 1, 1998, 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 72 hydroelectric
plants, and had a majority interest in Beebee Island and Feeder Dam
hydro plants and their output. The Company also purchases
substantially all of the output of 93 other hydroelectric
facilities. The Company's wholly-owned subsidiary, Opinac North
America, Inc., owns Opinac Energy Corporation and Plum Street
Enterprises, Inc. Opinac Energy Corporation has a 50 percent
interest in CNP (owner and operator of the 76.8 MW Rankine
hydroelectric plant) which distributes electric power within the
Province of Ontario and owns 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
- - "IPPs," - "New York Power Authority" and - "Other Purchased
Power" and Part II, Item 8. Financial Statements and Supplementary
Data - "Note 9. Commitments and Contingencies - Long-term
Contracts for the Purchase of Electric Power" and - "Electric
and Gas Statistics." The Company holds the FERC license for 65
hydroelectric plants. A significant number of these licenses are
subject to renewal over the next 4 years. As of December 31, 1997,
the Company has renewed 2 hydro licenses and has 7 license renewals
pending. In the event the Company is unable to renew a hydro
license, it is entitled to compensation for the facility. (See
Part II, Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - "Master Restructuring
Agreement and the PowerChoice Agreement - PowerChoice Agreement"
for a discussion of the Company's plans to sell its fossil and
hydro assets).
The following is a list of the Company's major operating
generating stations at February 1, 1998:
Company's Share of
Station, Location Nominal Net
and Percent Ownership Energy Source Capability in MW
- ------------------------------------------------------------------
Huntley, Niagara River (100%) Coal 760
Dunkirk, Lake Erie (100%) Coal 600
Albany, Hudson River (100%) Oil/Natural Gas 400
Oswego, Lake Ontario (76%)
(Unit 6) Oil/Natural Gas 646
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
In 1994, Oswego Unit No. 5 (an oil-fired unit with a net book
value of $160 million and a capability of 850 MW) was put into
long-term cold standby, but can be returned to service in three
months.
The Company is pursuing the necessary permits to install
state-of-the-art technology at the Albany Steam Station to
redevelop the facility to increase the capacity from the current
400 MW to 723 MW and rename the station the Bethlehem Energy
Center. The new facility would use natural gas fueled combined
cycle units which would reduce air emissions and significantly
improve the facility's operating efficiency. The licensing effort
and permitting process is expected to take up to 18 months and be
transferable to a new owner of the facility under the fossil and
hydro generating facility auction.
The electric system of the Company and CNP 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
through the Eastern Interconnection of the United States. As of
December 31, 1997, the Company's electric transmission and
distribution systems were composed of 952 substations with a rated
transformer capacity of approximately 28,500,000 kilovoltamperes,
approximately 8,000 circuit miles of overhead transmission lines,
approximately 1,100 cable miles of underground transmission lines,
approximately 113,100 conductor miles of overhead distribution
lines and about 5,800 cable miles of underground distribution
cables, only a part of such transmission and distribution lines
being located on property owned by the Company.
There is seasonal variation in electric customer load. In
1997, the Company's maximum hourly demand occurred in the summer.
Historically, the Company's maximum hourly demand occurred in the
winter. 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, 1997 occurred
on July 15, 1997 and was 6,348,000 KWh. For a summary of the
Company's electric supply capability at December 31, 1997, see Part
II, Item 8. Financial Statements and Supplementary Data -
"Electric and Gas Statistics."
The Company owns and operates several electric transmission
lines crossing the Seneca Nation Cattaraugus and Allegany
Reservations which range from 230 kilovolts to 34.5 kilovolts. In
1991, the Seneca Nation challenged the validity of the right-of-way
agreements for these transmission lines. While discussions between
the Nation and the Company were suspended in mid-1992, the Nation
has recently asked the Company to reopen the discussions. The
Company is unable to estimate any potential costs associated with
this issue, if any.
NEW YORK POWER POOL
The Company, six other New York utilities and NYPA constitute
the NYPP, 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 - "Master
Restructuring Agreement and the PowerChoice Agreement" and - "FERC
Rulemaking on Open Access and Stranded Cost Recovery."
GAS SERVICE
The Company distributes gas purchased from suppliers and
transports gas owned by others. As of December 31, 1997, the
Company's natural gas system was comprised of approximately 8,000
miles of pipelines and mains, only a part of which is located on
property owned by the Company.
SUBSIDIARIES
One of the Company's wholly-owned subsidiaries, Opinac North
America, Inc. owns Opinac Energy Corporation (a Canadian
corporation) and Plum Street Enterprises, Inc. Opinac Energy
Corporation has a 50 percent interest in an electric company, CNP,
which has operations in the Province of Ontario, Canada. CNP
generates electricity at its Rankine hydro plant for the wholesale
market and for its distribution system in Fort Erie, Ontario. CNP
owns a 99.99% interest in Canadian Niagara Wind Power Company, Inc.
and Cowley Ridge Partnership, respectively, which together operate
a wind power joint venture in the Province of Alberta, Canada. Plum
Street Enterprises, Inc., incorporated in the State of Delaware, is
an unregulated company that offers energy related services. A
wholly-owned Texas subsidiary of the Company, 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 wholly-owned New York State subsidiary of the Company, NM
Holdings, Inc., engages in real estate development of property
formerly owned by the utility company. In addition, the Company
has established a single-purpose wholly-owned subsidiary, NM
Receivables Corporation, to facilitate its sale of an undivided
interest in a designated pool of customer receivables, including
accrued unbilled revenues. The Company also owns a 66.67 percent
and 82.84 percent interest in Moreau Manufacturing Corporation and
Beebee Island Corporation, respectively, which are New York State
subsidiaries that own and operate hydro-electric generating
stations.
MORTGAGE LIENS
Substantially all of the Company's operating properties are
subject to a mortgage lien securing its mortgage debt. (See Part
II, Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - "Master Restructuring
Agreement and the Revised PowerChoice Agreement").
ITEM 3. LEGAL PROCEEDINGS.
For a detailed discussion of additional legal proceedings, see
Part II, Item 8. Financial Statements and Supplementary Data -
"Note 9. Commitments and Contingencies - Tax Assessments" 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 - "Master Restructuring Agreement and the
PowerChoice Agreement." The Company is unable to predict the
ultimate disposition of the matters referred to below in (1), (2),
(3), (4) and (5). However, the Company has previously been allowed
to recover these types of expenditures in rates. In addition,
consistent with PowerChoice, the Company believes that it is
probable that the Company will continue to recover these types of
expenditures in cost-of-service based rates. See also Part II,
Item 8. Financial Statements and Supplementary Data - "Note 2.
Rate and Regulatory Issues and Contingencies."
1. On June 22, 1993, the Company and twenty other industrial
entities, as well as the owner/operator of the Pfohl
Brothers Landfill near Buffalo, New York, were sued in NYS
Supreme Court, Erie County, by a group of residents living
in the area surrounding the landfill. The plaintiffs seek
compensation for alleged economic loss and property damage
claimed to have resulted from exposure to contamination
associated with the landfill. In addition, since January
18, 1995, the Company has been named as a defendant or
third-party defendant in a series of toxic tort actions
filed in federal or state courts in the Buffalo area.
These actions allege exposure on the part of plaintiffs or
plaintiffs' decedents to toxic chemicals emanated from the
landfill, resulting in the alleged causation of cancer.
The plaintiffs seek compensatory and punitive damages so
far totalling approximately $60 million. The Company has
filed answers responding to the claims put forth in these
suits, denying liability as to any of the claimed
conditions or damages, and intends to continue to
vigorously defend against each claim.
The Company is unable to predict at this time the probable
outcome of these proceedings, which at present remain in
the discovery stage. The Company, through membership in
the Pfohl Brothers landfill Site Committee, is
participating in the design and implementation of a
remedial program for the landfill. In the context of
liability allocation procedures conducted on behalf of the
Committee, it has been determined that the Company's
contribution of industrial wastes to the landfill was
minor. Further, it is the Company's position that
materials present at the landfill attributable to the
Company are not causally related to any condition alleged
by plaintiffs in the various lawsuits associated with the
landfill. The Company does not believe that the outcome of
these proceedings will have a material adverse effect on
its results of operations or financial condition.
2. On October 23, 1992, the Company petitioned the PSC to
order IPPs 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. However, in August
1996, the PSC proposed to examine the circumstances under
which a utility, including the Company, should be allowed
to demand security from IPPs to ensure the repayment of
advance payments made under their purchased power
contracts. See Part II, Item 7. Management's Discussion
and Analysis of Financial Condition and Results of
Operations - "Other Federal and State Regulatory
Initiatives - PSC Proposal of New IPP Operating and PPA
Management Procedures."
On February 4, 1994, the Company notified the owners of
nine projects with contracts that provide for front-end
loaded payments of the Company's demand for adequate
assurance that the owners will perform all of their future
repayment obligations, including the obligation to deliver
electricity in the future at prices below the Company's
avoided cost 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. Litigation ensued with six of the
projects as a result of these notifications, as follows:
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 (the "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 has appealed this
decision. A motion to stay further proceedings has been
made since this contract is included in the MRA.
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
NYS Supreme Court 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 NYS 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 has appealed
this decision. A motion to stay further proceedings has
been made since this contract is included in the MRA.
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 PPA 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 PPA.
NorCon sought a temporary restraining order against the
Company to prevent the Company from taking any action on
its February 4, 1994 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. On March 25, 1997, the
U.S. Court of Appeals for the Second Circuit ordered that
the question of whether there exists under New York
commercial law the right to demand firm security on an
electric contract should be certified to the N.Y. Court of
Appeals, the highest New York court, for final resolution.
The Second Circuit order effectively stayed the U.S.
District Court's order against the Company, pending final
disposition by the N.Y. Court of Appeals. A motion to stay
further proceedings has been made since this contract is
included in the MRA.
The Company can neither provide any judgement regarding the
likely outcome nor any estimate or range of possible loss
or reduction of exposure in the cases above. Accordingly,
no provision for liability, if any, that may result from
any of these suits has been made in the Company's financial
statements. If the MRA closes with respect to the IPP
Parties mentioned above, then these litigations would be
dismissed with respect to such IPP Parties (see Part II,
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - "Master Restructuring
Agreement and the PowerChoice Agreement").
3. 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 filed an appeal from the Court's order. On
January 30, 1997, the Appellate Division modified the
November 7, 1995 court decision by reversing the dismissal
of the fourth and fifth causes of action set forth in
Fourth Branch's complaint.
The Company and Fourth Branch had also entered into
negotiations under a FERC mediation process. As a result
of these negotiations, the Company had proposed to sell the
hydroelectric plant to Fourth Branch for an amount which
would not be material. In addition, the proposal included
a provision that would require the discontinuance of all
litigation between the parties.
Attempts to implement this proposal have been unsuccessful
and the Company has informed FERC that its participation in
the mediation efforts has been concluded. On January 14,
1997, the FERC Administrative Law Judge issued a report to
FERC recommending that the mediation proceeding be
terminated, leaving outstanding a Fourth Branch complaint
to FERC that alleges anti-competitive conduct by the
Company. The Company has made a motion to dismiss Fourth
Branch's antitrust complaint before the FERC, which motion
was opposed by Fourth Branch. A decision from FERC on this
matter is pending.
The Company is unable to predict the ultimate disposition
of the lawsuit referred to above. However, the Company
believes it has meritorious defenses and intends to defend
this lawsuit vigorously. No provision for liability, if
any, that may result from this lawsuit has been made in the
Company's financial statements.
4. 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 PPA 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 PPA 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. This one breach of contract claim was remanded to
the NYS Supreme Court for further consideration. In
January 1998, the NYS Supreme Court granted the Company's
motion for summary judgment on all remaining claims in this
lawsuit and dismissed this lawsuit in its entirety. In
January 1998, Inter-Power filed a notice of appeal.
5. The DEC, in response to an EPA audit of their enforcement
policies, which found enforcement of air regulation
violations to be insufficient, has begun an initiative to
address this issue. As a result, the DEC is seeking
penalties from all New York utilities for past opacity
variances for the years 1994, 1995 and 1996. Furthermore,
the DEC is requiring various opacity reduction measures and
stipulated penalties for future excursions after execution
of a consent order. All New York State utilities,
including the Company, which was notified in September
1997, are in the process of negotiating the various terms
and conditions of the draft consent order with the DEC. The
outcome of this matter is uncertain at this time and it is
not possible to predict what the financial impact to the
Company will be in terms of penalty payment and
implementation of an opacity reduction program.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
On October 23, 1997, the Board of Directors authorized the
solicitation of consents from its preferred shareholders, as
required by the Company's Certificate of Incorporation, to increase
the amount of unsecured debt the Company may issue from the level
prior to the consent of approximately $700 million by up to an
additional $5 billion. On December 3, 1997, the preferred
shareholders approved the proposal to increase the level of
unsecured debt by a vote of 3,562,645 for, 479,124 against and
140,107 abstentions.
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 12/31/97 Current and Prior Positions Date Commenced
--------- -------- --------------------------- --------------
William E. Davis 55 Chairman of the Board and Chief Executive Officer May 1993
Vice Chairman of the Board of Directors November 1992
Albert J. Budney, 50 President 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
B. Ralph Sylvia 57 Executive Vice President January 1998*
Executive Vice President - Electric Generation and
Chief Nuclear Officer December 1995
Executive Vice President - Nuclear November 1990
David J. Arrington 46 Senior Vice President - Human Resources December 1990
William F. Edwards 40 Senior Vice President and Chief Financial Officer September 1997
Vice President - Financial Planning December 1995
Executive Assistant to the Chief Executive Officer
and President July 1993
Director of Budget and Financial Management June 1989
Darlene D. Kerr 46 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 47 Senior Vice President - Legal & Corporate Relations May 1993
Senior Vice President - Legal & Corporate Relations
and General Counsel October 1992
John H. Mueller 51 Senior Vice President and Chief Nuclear Officer January 1998*
Site Vice President of Commonwealth Edison's Zion
Plant August 1996
Vice President of Nuclear Energy (for the Nebraska
Public Power District, owner and operator of the
Cooper nuclear plant) July 1994
Plant Manager - Unit 2 August 1993
Operations Manager - Unit 2 October 1992
John W. Powers 59 Retired December 1997
Senior Vice President September 1997
Senior Vice President and Chief Financial Officer January 1996
Senior Vice President - Finance & Corporate Services October 1990
Theresa A. Flaim 48 Vice President - Corporate Strategic Planning May 1994
Vice President - Corporate Planning April 1993
Manager - Gas Rates & Integrated Resource Planning June 1991
Kapua A. Rice 46 Corporate Secretary September 1994
Assistant Secretary October 1992
Manager - Legal & Corporate Relations July 1991
Steven W. Tasker 40 Vice President - Controller December 1993
Controller May 1991
* On January 13, 1998, John H. Mueller was elected as Senior Vice President and Chief
Nuclear Officer, which became effective January 19, 1998. He will succeed B. Ralph
Sylvia, who will remain with the Company as an Executive Vice President until his planned
mid-year retirement.
/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. The Company estimates that none of the 1997
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) for the
Company's common stock:
1997 1996
---------------- -----------------
HIGH LOW HIGH LOW
- -----------------------------------------------------
1st Quarter $11 1/8 $8 1/8 $10 1/8 $6 1/2
2nd Quarter 9 7 7/8 8 5/8 6 1/2
3rd Quarter 10 1/16 8 1/4 8 7/8 6 3/4
4th Quarter 10 9/16 9 1/16 10 7 5/8
For a discussion regarding the common stock dividend, see Item 7.
Management's Discussion and Analysis of Financial Condition and
Results of Operations - "Accounting Implications of the PowerChoice
Agreement and Master Restructuring Agreement" and "Financial
Position, Liquidity and Capital Resources - Common Stock Dividend"
below.
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 preferred
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.
Upon consummation of the MRA (see Item 7. Management's
Discussion and Analysis of Financial Condition and Results of
Operations - "Master Restructuring Agreement and the PowerChoice
Agreement" for a listing of conditions that must be met in order to
close the MRA), which is expected to occur later this year, the IPP
Parties are expected to own 42.9 million shares of the Company's
common stock, representing 23% of the Company's voting securities
following the issuance of such shares. In the MRA, the parties
agree that any IPP Party that receives 2% or more of the
outstanding Common Stock and any designees of IPP Parties that
receives more than 4.9% of the outstanding Common Stock upon the
consummation of the MRA will, together with certain but not all
affiliates (collectively, "2% Shareholders"), enter into certain
shareholder agreements (the "Shareholders Agreements"). Pursuant
to each Shareholder Agreement, the 2% Shareholders agree that for
five years they will not acquire more than an additional 5% of the
outstanding Common Stock (resulting in ownership in all cases of no
more than 9.9%) or take any actions to attempt to acquire control
of the Company, other than certain permitted actions in response to
unsolicited actions by third parties. The 2% shareholders will
generally vote their shares on a "pass-through" basis, that is in
the same proportion as all shares held by other shareholders are
voted, except that they may vote in their discretion for
extraordinary transactions and, when there is a pending proposal to
acquire the Company, for directors.
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.
As of March 26, 1998, there were approximately 66,300 holders
of record of common stock of the Company and about 4,700 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 31,056 812,652
100 to 999 31,930 7,775,973
1,000 or more 3,325 135,830,726
------ -----------
66,311 144,419,351
====== ===========
/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, 1997, which has been derived from the audited
financial statements of the Company, and should be read in connection therewith. As
discussed in Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations and Item 8. Financial Statements and Supplementary Data - "Notes to
Consolidated Financial Statements," the following selected financial data is not likely to
be indicative of the Company's future financial condition or results of operations.
1997 1996* 1995 1994 1993
- ------------------------------------------------------------------------------------------
Operations: (000's)
Operating revenues $ 3,966,404 $ 3,990,653 $ 3,917,338 $ 4,152,178 $ 3,933,431
Net income 59,835 110,390 248,036 176,984 271,831
- ------------------------------------------------------------------------------------------
Common stock data:
Book value per share
at year end $18.03 $17.91 $17.42 $17.06 $17.25
Market price at
year end 10 1/2 9 7/8 9 1/2 14 1/4 20 1/4
Ratio of market price to
book value at year end 58.2% 55.1% 54.5% 83.5% 117.4%
Dividend yield at year end - - 11.8% 7.9% 4.9%
Basic and diluted earnings
(loss) per average common
share $.16 $ .50 $1.44 $1.00 $1.71
Rate of return on common
equity 0.9% 2.8% 8.4% 5.8% 10.2%
Dividends paid per
common share - - $1.12 $1.09 $ .95
Dividend payout ratio - - 77.8% 109.0% 55.6%
- ------------------------------------------------------------------------------------------
Capitalization: (000's)
Common equity $ 2,604,027 $ 2,585,572 $ 2,513,952 $ 2,462,398 $ 2,456,465
Non-redeemable
preferred stock 440,000 440,000 440,000 440,000 290,000
Mandatorily redeemable
preferred stock 76,610 86,730 96,850 106,000 123,200
Long-term debt 3,417,381 3,477,879 3,582,414 3,297,874 3,258,612
- ------------------------------------------------------------------------------------------
TOTAL 6,538,018 6,590,181 6,633,216 6,306,272 6,128,277
Long-term debt maturing
within one year 67,095 48,084 65,064 77,971 216,185
- ------------------------------------------------------------------------------------------
TOTAL $ 6,605,113 $ 6,638,265 $ 6,698,280 $ 6,384,243 $ 6,344,462
- ------------------------------------------------------------------------------------------
Capitalization ratios: (including long-term debt maturing within one year)
Common stock equity 39.4% 39.0% 37.5% 38.6% 38.7%
Preferred stock 7.8 7.9 8.0 8.5 6.5
Long-term debt 52.8 53.1 54.5 52.9 54.8
- ------------------------------------------------------------------------------------------
Financial ratios:
Ratio of earnings to
fixed charges 1.39 1.57 2.29 1.91 2.31
Ratio of earnings to
fixed charges and
preferred stock
dividends 1.12 1.31 1.90 1.63 2.00
Other ratios - % of
operating revenues:
Fuel, electricity purchased
and gas purchased 44.4% 43.5% 40.3% 39.6% 36.1%
Other operation and
maintenance expenses 21.1 23.3 20.9 23.1 26.9
Depreciation and
amortization 8.6 8.3 8.1 7.4 7.0
Federal and foreign
income taxes, and
other taxes 13.4 13.6 17.3 14.7 16.2
Operating income 14.1 13.1 17.5 13.3 17.5
Balance available for
common stock 0.6 1.8 5.3 3.5 6.1
- ------------------------------------------------------------------------------------------
Miscellaneous: (000's)
Gross additions to
utility plant $ 290,757 $ 352,049 $ 345,804 $ 490,124 $ 519,612
Total utility plant 11,075,874 10,839,341 10,649,301 10,485,339 10,108,529
Accumulated depreciation
and amortization 4,207,830 3,881,726 3,641,448 3,449,696 3,231,237
Total assets 9,584,141 9,427,635 9,477,869 9,649,816 9,471,327
==========================================================================================
* Amounts include extraordinary item, see Note 2. Rate and Regulatory Issues and
Contingencies.
/TABLE
NIAGARA MOHAWK POWER CORPORATION
Certain statements included in this Annual Report on Form 10-K
are forward-looking statements as defined in Section 21E of the
Securities Exchange Act of 1934, including the hedge against upward
movement in market prices provided by the restructured and amended
PPAs, the improvement in operating cash flows as a result of the
MRA and PowerChoice, the recoverability of the MRA regulatory asset
through the prices charged for electric service, the effect of a
PSC natural gas proposal on the Company's results of operations,
expected earnings over the five-year term of the PowerChoice
agreement, the effect of the elimination of the FAC under
PowerChoice on the Company's financial condition, the reduction in
net income resulting from the non-cash amortization of the MRA
regulatory asset, the effect of the January 1998 ice storm damage
restoration costs on the Company's capital requirements,
recoverability of environmental compliance costs and nuclear
decommissioning costs through rates, and the improvement in the
Company's financial condition expected as a result of the MRA and
the implementation of PowerChoice. The Company's actual results
and developments may differ materially from the results discussed
in or implied by such forward-looking statements, due to risks and
uncertainties that exist in the Company's operations and business
environment, including, but not limited to, matters described in
the context of such forward-looking statements, as well as such
other factors as set forth in the Notes to Consolidated Financial
Statements contained herein.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
EVENTS AFFECTING 1997 AND THE FUTURE
- - On July 9, 1997, the Company announced the MRA to terminate,
restate or amend IPP power purchase contracts in exchange for
cash, shares of the Company's common stock and certain
financial contracts. The terms of the MRA have been and may
continue to be modified.
- - In February 1998, the PSC approved the PowerChoice settlement
agreement, which incorporates the terms of the MRA. Under
PowerChoice, a regulatory asset will be established for the
costs of the MRA and it will be amortized over a period not to
exceed ten years. The Company's rates under PowerChoice are
designed to permit recovery of the MRA regulatory asset. In
approving PowerChoice, the PSC limited the estimated value of
the MRA regulatory asset that can be recovered to
approximately $4,000 million, resulting in a charge to 1997
earnings of $190.0 million or 85 cents per share. The
PowerChoice agreement, while having the effect of
substantially depressing earnings during its five-year term,
will substantially improve operating cash flows.
- - In December 1997, the preferred shareholders gave the Company
approval to increase the amount of unsecured debt that the
Company may issue by $5 billion. This authorization enables
the issuance of unsecured debt to consummate the MRA.
- - The PowerChoice agreement calls for the Company to conduct an
auction to sell all of its fossil and hydro generation assets.
- - In early January 1998, a major ice storm caused extensive and
costly damage to the Company's facilities in northern New
York.
MASTER RESTRUCTURING AGREEMENT AND THE POWERCHOICE AGREEMENT
The Company entered into the PPAs that are subject to the MRA
because it was required to do so under PURPA, which was intended to
provide incentives for businesses to create alternative energy
sources. Under PURPA, the Company was required to purchase
electricity generated by qualifying facilities of IPPs at prices
that were not expected to exceed the cost that otherwise would have
been incurred by the Company in generating its own electricity, or
in purchasing it from other sources (known as "avoided costs").
While PURPA was a federal initiative, each state retained certain
delegated authority over how PURPA would be implemented within its
borders. In its implementation of PURPA, the State of New York
passed the "Six-Cent Law," establishing 6 cents per KWh as the
floor on avoided costs for projects less than 80 MW in size. The
Six-Cent Law remained in place until it was amended in 1992 to deny
the benefit of the statute to any future PPAs. The avoided cost
determinations under PURPA were periodically increased by the PSC
during this period. PURPA and the Six-Cent Law, in combination
with other factors, attracted large numbers of IPPs to New York
State, and, in particular, to the Company's service territory, due
to the area's existing energy infrastructure and availability of
cogeneration hosts. The pricing terms of substantially all of the
PPAs that the Company entered into in compliance with PURPA and the
Six-Cent Law or other New York laws were based, at the option of
the IPP, either on administratively determined avoided costs or
minimum prices, both of which have consistently been materially
higher than the wholesale market prices for electricity.
Since PURPA and the Six-Cent Law were passed, the Company has
been required to purchase electricity from IPPs in quantities in
excess of its own demand and at prices in excess of that available
to the Company by internal generation or for purchase in the
wholesale market. In fact, by 1991, the Company was facing a
potential obligation to purchase power from IPPs substantially in
excess of its peak demand of 6,093 MW. As a result, the Company's
competitive position and financial performance have deteriorated
and the price of electricity paid per KWh by its customers has
risen significantly above the national average. Accordingly, in
1991 the Company initiated a parallel strategy of negotiating
individual PPA buyouts, cancellations and renegotiations, and of
pursuing regulatory and legislative support and litigation to
mitigate the Company's obligation under the PPAs. By mid-1996,
this strategy had resulted in reducing the capacity of the
Company's obligations to purchase power under its PPA portfolio to
approximately 2,700 MW. Notwithstanding this reduction in
capacity, over the same period the payments made to the IPPs under
their PPAs rose from approximately $200 million in 1990 to
approximately $1.1 billion in 1997 as independent power facilities
from which the Company was obligated to purchase electricity
commenced operations. The Company estimates that absent the MRA,
payments made to the IPPs pursuant to PPAs would continue to
escalate by approximately $50 million per year until 2002.
Recognizing the competitive trends in the electric utility
industry and the impracticability of remedying the situation
through a series of customer rate increases, in mid-1996 the
Company began comprehensive negotiations to terminate, amend or
restate a substantial portion of above-market PPAs in an effort to
mitigate the escalating cost of these PPAs as well as to prepare
the Company for a more competitive environment. These negotiations
led to the MRA and the PowerChoice agreement.
MASTER RESTRUCTURING AGREEMENT. On July 9, 1997, the Company
entered into the MRA with 16 IPP Parties who sell electricity to
the Company under 29 PPAs. The MRA specifically contemplated that
two IPPs, Oxbow Power of North Tonawanda, New York, Inc. ("Oxbow")
and NorCon would enter into further negotiations concerning their
treatment under the MRA. Following such negotiations, Oxbow has
withdrawn from the MRA, but, based on the value of its allocation
under the MRA and the terms of its existing PPA, Oxbow's withdrawal
does not materially impact the cost reductions associated with the
MRA. The Company and NorCon have agreed to replace NorCon's
initial allocation under the MRA with an all cash allocation which
has, in the Company's estimation, a value approximately $60 million
higher than NorCon's initial allocation. A third IPP Party has
agreed to take cash in exchange for the shares of common stock
allocated to it in the MRA. As a result of these cash allocations,
there are 3,054,000 fewer shares of common stock allocated to the
IPPs under the MRA. The MRA has been amended to expire on July 15,
1998.
The MRA currently provides for the termination, restatement or
amendment of 28 PPAs with 15 IPPs, which represent approximately
80% of the Company's over-market purchased power obligations, in
exchange for an aggregate of $3,616 million in cash and 42.9
million shares of the Company's common stock and certain financial
contracts. The closing of the MRA is subject to a number of
conditions, including the Company and the IPP Parties negotiating
individual restated and amended contracts, the receipt of all
regulatory approvals, the receipt of all consents by third parties
necessary for the transactions contemplated by the MRA (including
the termination of the existing PPAs and the termination or
amendment of all related third party agreements), the IPP Parties
entering into new third party arrangements which will enable each
IPP Party to restructure its projects on a reasonably satisfactory
economic basis, the Company having completed all necessary
financing arrangements and the Company and the IPP Parties having
received all necessary approvals from their respective boards of
directors, shareholders and partners. While one or more of the IPP
Parties may under certain circumstances terminate the MRA with
respect to itself, the Company's obligation to close the MRA is
subject to its determination that as a result of any such
terminations the benefits anticipated to be received by the Company
pursuant to the MRA have not been materially and adversely
affected. The Company expects that prior to the consummation of
the MRA, the mix of consideration to be received by the IPP Parties
may be renegotiated. The foregoing is qualified in its entirety by
the text of the MRA (see Exhibit 10-11). As the Conditions
Determination Date (the date by which all IPP Parties must satisfy
or waive their third party conditions or withdraw from the MRA) has
not occurred, the Company cannot predict whether such conditions
will be satisfied, whether some IPP Parties may withdraw, whether
the terms of the MRA might be renegotiated, or whether the MRA will
be consummated. In the event the Company is unable to successfully
complete the MRA and therefore implement PowerChoice, it would
pursue all alternatives including a traditional rate request.
The principal effects of the MRA are to reduce significantly
the Company's existing payment obligations under the PPAs, which
currently consist of approximately 2,700 MW of capacity at December
31, 1997. While earnings will be depressed during the five-year
term, the savings in annual energy payments, coupled with the rates
established in PowerChoice, will yield free cash flow that can be
dedicated to the new debt service obligations associated with the
payment of cash to the IPP Parties.
Under the terms of the MRA, the Company's significant long
term and escalating IPP payment obligations will be restructured
into a defined and more manageable obligation and a portfolio of
restated and amended PPAs with price and duration terms that the
Company believes are more favorable than the existing PPAs. Under
the MRA, 19 PPAs representing approximately 1,180 MW of capacity
will be terminated completely thus allowing this capacity to be
replaced through the competitive market at market based prices.
The Company has no continuing obligation to purchase energy from
the terminating IPP Parties.
Also under the MRA, 8 PPAs representing approximately 541 MW
of capacity will be restated on economic terms and conditions that
are more favorable to the Company than the existing PPAs. The
restated contracts have a term of 10 years and are structured as
financial swap contracts where the Company receives or makes
payments to the IPP Parties based upon the differential between the
contract price and a market reference price for electricity. The
contract prices are fixed for the first two years changing to an
indexed pricing formula thereafter. Contract quantities are fixed
for the full 10 year term of the contracts. The indexed pricing
structure ensures that the price paid for energy and capacity will
fluctuate relative to the underlying market cost of gas and general
indices of inflation. Until such time as a competitive energy
market structure becomes operational in the State of New York, the
restated contracts provide the IPP Parties with a put option for
the physical delivery of energy. Additionally, one PPA
representing 42 MW of capacity will be amended to reflect a
shortened term and a lower stream of fixed unit prices. Finally,
the MRA requires the Company to provide the IPP Parties with a
number of fixed price swap contracts with a term of seven years
beginning in 2003. The fixed price swap contracts will be cash
settled monthly based upon a stream of defined quantities and
prices.
Although against the Company's forecast of market energy
prices the restructured and amended PPAs represent an expected
above-market payment obligation, the Company's portfolio of these
PPAs provides it and its customers with a hedge against significant
upward movement in market prices that may be caused by a change in
energy supply or demand. This portfolio and market purchases
contain terms that are believed to be more responsive to
competitive market price changes. (See Item 8. Financial
Statements and Supplementary Data - "Note 9. Commitments and
Contingencies - Long-term Contracts for the Purchase of Electric
Power").
POWERCHOICE AGREEMENT. The PowerChoice agreement establishes
a five-year rate plan that will reduce average residential and
commercial rates by an aggregate of 3.2% over the first three
years. This reduction will include certain savings that will
result from partial reductions of the New York State GRT.
Industrial customers will see average reductions of 25% relative to
1995 price levels; these decreases will include discounts currently
offered to some industrial customers through optional and flexible
rate programs. The cumulative rate reductions, net of GRT savings,
are estimated to be approximately $112 million, to be experienced
on a generally ratable basis over the first three years of the
agreement. During the term of the PowerChoice agreement, the
Company will be permitted to defer certain costs, associated
primarily with environmental remediation, nuclear decommissioning
and related costs, and changes in laws, regulations, rules and
orders. In years four and five of its rate plan, the Company can
request an annual increase in prices subject to a cap of 1% of the
all-in price, excluding commodity costs (e.g., transmission,
distribution, nuclear, and forecasted CTC). In addition to the
price cap, the PowerChoice agreement provides for the recovery of
deferrals established in years one through four and cost variations
in the MRA financial contracts resulting from indexing provisions
of these contracts. The aggregate of the price cap increase and
recovery of deferrals is subject to an overall limitation of
inflation.
Under the terms of the PowerChoice agreement, all of the
Company's customers will be able to choose their electricity
supplier in a competitive market by December 1999. The Company will
continue to distribute electricity through its distribution and
transmission facilities and would be obligated to be the so-called
provider of last resort for those customers who do not exercise
their right to choose a new electricity supplier.
The PowerChoice agreement provides that the MRA and the
contracts executed pursuant thereto shall be found to be prudent.
The PowerChoice agreement further provides that the Company shall
have a reasonable opportunity to recover its stranded costs,
including those associated with the MRA and the contracts executed
thereto, through a CTC and, under certain circumstances, through
exit fees or in rates for back up service.
Under the PowerChoice agreement, an MRA regulatory asset,
aggregating approximately $4,000 million, will be established. In
this way, the costs of the MRA would be deferred and amortized over
a period not to exceed ten years. The Company's rates under
PowerChoice are designed to permit recovery of the MRA regulatory
asset and to permit recovery of, and a return on, the remainder of
its assets, as appropriate. The PowerChoice agreement, while
having the effect of substantially depressing earnings during its
five-year term, will substantially improve operating cash flows.
The PowerChoice agreement calls for the Company to divest all
of its fossil and hydro generation assets. Divestiture is intended
to be accomplished through an auction. Winning bids would be
selected within 11 months of PSC approval of the auction plan,
which was filed with the PSC separately from the PowerChoice
agreement. The Company will receive a portion of the auction sale
proceeds as an incentive to obtain maximum value in the sale. This
incentive would be recovered from sale proceeds. The Company
agreed that if it does not receive an acceptable bid for an asset,
the Company will form a subsidiary to hold any such assets and then
legally separate this subsidiary from the Company through a spin-
off to shareholders or otherwise. If a bid of zero or below is
received for an asset, the Company may keep the asset as part of
its regulated business. The auction process will serve to quantify
any stranded costs associated with the Company's fossil and hydro
generating assets. The Company will have a reasonable opportunity
to recover these costs through the CTC and otherwise as described
above. After the auction process is complete, the Company has
agreed not to own any non-nuclear generating assets in the State of
New York, subject to certain exceptions provided in the PowerChoice
agreement. Under the terms of the note indenture prepared in
connection with the financing of the MRA, the Company will be
required to use a majority of the cash portion of net proceeds from
the sale of its fossil and hydro generating assets to reduce
indebtedness. Such restrictions would not apply in the event that
the Company was unable to successfully conclude the consummation of
the MRA and therefore of PowerChoice but nonetheless sold such
assets.
The PowerChoice agreement contemplates that the Company's
nuclear plants will remain part of the Company's regulated
business. The Company has been supportive of the creation of a
statewide New York Nuclear Operating Company that it expects would
improve the efficiency of nuclear units throughout the state. The
PowerChoice agreement stipulates that absent such a statewide
solution, the Company will file a detailed plan for analyzing other
proposals regarding its nuclear assets, including the feasibility
of an auction, transfer and/or divestiture of such facilities,
within 24 months of PowerChoice approval.
The PowerChoice agreement also allows the Company to form a
holding company at its election. The Company plans to seek its
shareholders' approval at its 1998 annual meeting to the formation
of a holding company, the implementation of which would only occur
following various regulatory approvals.
At its public session on February 24, 1998, the PSC voted to
approve the PowerChoice agreement, which incorporates the terms of
the MRA. Subject to the satisfaction of the conditions to the MRA,
the PSC's approval of PowerChoice should allow the Company to
consummate the MRA in the first half of 1998. The PowerChoice
agreement will only become effective upon the closing of the MRA.
In approving PowerChoice, the PSC made the following changes, among
others, to the agreement: i) customers who had made a substantial
investment in on-site generation as of October 10, 1997 will be
grandfathered and not have to pay the CTC; ii) savings from any
reduction in the interest rate associated with the debt issued in
connection with the MRA financing as compared to assumptions
underlying the Company's PowerChoice filing will be deferred for
future disposition; and iii) change the generation auction
incentive to 15% of proceeds in excess of net book value for non-
Oswego assets and 5% of proceeds in excess of $100 million for
Oswego assets.
In its written order dated March 20, 1998, the PSC made
several other changes to the PowerChoice agreement, in addition to
those discussed at the February 24 session. The PSC determined to
limit the estimated value of the MRA regulatory asset that can be
recovered from customers, to approximately $4,000 million. The
estimated value of the MRA regulatory asset includes the issuance
of 42.9 million shares of common stock, which the PSC, in
determining the recoverable amount of such asset valued at $8 per
share. The Company's common stock closed at $12 7/16 per share on
March 26, 1998. The accounting implications of the limitation in
value are discussed under "Accounting Implications of the
PowerChoice Agreement and Master Restructuring Agreement." The PSC
also modified the reduction in average residential and commercial
rates. The PowerChoice agreement measured the 3.2% reduction
against 1995 prices. The PSC determined that the percentage
reduction should be applied against the lower of 1995 prices or the
most current twelve-month period. To the extent prices for the
most current twelve-month period are lower than 1995 prices, the
amount of cumulative rate reductions described below will increase.
Lastly, the PSC ordered the Company not to proceed to consummate
the MRA with respect to one contract held by one developer until a
satisfactory resolution of a cogeneration steam host contract is
reached.
New York law provides parties the right to appeal the
Commission's decision approving the PowerChoice agreement within
four months of the date of that decision. In addition, parties
have the right to petition the Commission for rehearing of the
decision within 30 days of the date of the decision. If a petition
for rehearing is filed and the Commission issues a decision on
rehearing, parties may appeal the decision on rehearing within four
months of the date of the decision on rehearing. Such an appeal or
petition for rehearing may be based on the failure of the record to
show a reasonable basis for the terms of the PowerChoice agreement
and may result in an amendment of the record to correct such
failure, in renegotiation of such terms or in renegotiation of the
PowerChoice agreement as a whole. There can be no assurance that,
on appeal or on rehearing, the approval of the PowerChoice
agreement will be upheld or that such appeal or rehearing will not
result in terms substantially less favorable to the Company than
those described herein.
All of the foregoing discussion of the PowerChoice agreement
is qualified in its entirety by the text of the agreement and PSC
Order (see Exhibits 10-12 and 10-13).
ACCOUNTING IMPLICATIONS OF THE POWERCHOICE AGREEMENT
AND MASTER RESTRUCTURING AGREEMENT
The Company concluded as of December 31, 1996, that the
termination, restatement or amendment of IPP contracts and
implementation of PowerChoice was the probable outcome of
negotiations that had taken place since the PowerChoice
announcement. Under PowerChoice, the separated non-nuclear
generation business would no longer be rate-regulated on a cost-of-
service basis and, accordingly, regulatory assets related to the
non-nuclear power generation business, amounting to approximately
$103.6 million ($67.4 million after tax or 47 cents per share) were
charged against 1996 income as an extraordinary non-cash charge.
As described under "Master Restructuring Agreement and the
PowerChoice Agreement," the PSC in its written order issued March
20, 1998 limited the estimated value of the MRA regulatory asset
that can be recovered from customers to approximately $4,000
million. The ultimate amount of the regulatory asset to be
established may vary based on certain events related to the closing
of the MRA. The estimated value of the MRA regulatory asset
includes the issuance of 42.9 million shares of common stock, which
the PSC, in determining the recoverable amount of such asset valued
at $8 per share. Because the value of the consideration to be paid
to the IPP Parties can only be determined at the MRA closing, the
value of the limitation on the recoverability of the MRA regulatory
asset has been estimated at $190 million (85 cents per share) which
has been charged to 1997 earnings. The charge to expense was
determined as the difference between $8 per share and the Company's
closing common stock price on March 26, 1998 of $12 7/16 per share,
multiplied by 42.9 million shares. Any variance from the estimate
used in determining the charge to expense in 1997, including
changes in the common stock price at closing, will be reflected in
results of operations in 1998.
Under PowerChoice, the Company's remaining electric business
(nuclear generation and electric transmission and distribution
business) will continue to be rate-regulated on a cost-of-service
basis and, accordingly, the Company continues to apply SFAS No. 71
to these businesses. Also, the Company's IPP contracts, including
those restructured under the MRA and those not so restructured will
continue to be the obligations of the regulated business. As
described under "Master Restructuring Agreement and the PowerChoice
Agreement," the consummation of the MRA, as well as implementation
of PowerChoice, is subject to a number of contingencies.
In the event the Company is unable to successfully complete
the MRA and therefore implement PowerChoice, it would pursue all
alternatives including a traditional rate request. However,
notwithstanding such a rate request, it is likely that application
of SFAS No. 71 would be discontinued for the remaining electric
business, since the Company's current rate structure would no
longer be sufficient to recover its costs. The resulting non-cash
after-tax charges against income, based on regulatory assets and
liabilities associated with the nuclear generation and electric
transmission and distribution businesses as of December 31, 1997,
would be approximately $526.5 million or $3.65 per share. In
addition, the Company would be required to reassess the carrying
amounts of its long-lived assets in accordance with SFAS No. 121.
SFAS No. 121 requires long-lived assets and certain identifiable
intangibles 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 or when assets
are to be disposed of. 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/or its disposition. The Company would also be required
to determine the extent to which adverse purchase commitments, if
any, are required to be recorded as obligations. Various
requirements under applicable law and regulations and under
corporate instruments, including those with respect to issuance of
debt and equity securities, payment of common and preferred
dividends, and certain types of transfers of assets could be
adversely impacted by any such write-downs.
SFAS No. 71 does not require the Company to earn a return on
the regulatory assets in assessing its applicability. In the event
the MRA and PowerChoice are implemented, the Company believes that
the prices it would charge for electric service over 10 years,
including the CTC, assuming no unforeseen reduction in demand or
bypass of the CTC or exit fees, will be sufficient to recover the
MRA regulatory asset (currently estimated to be $4,000 million as
adjusted for the stock price cap) and provide recovery of and a
return on the remainder of its assets, as appropriate. In the
event the Company could no longer apply SFAS No. 71 in the future,
it would be required to record an after-tax non-cash charge against
income for any remaining unamortized regulatory assets and
liabilities. Depending on when SFAS No. 71 was required to be
discontinued, such charge would likely be material to the Company's
reported financial condition and results of operations and the
Company's ability to pay common and preferred dividends.
The Emerging Issues Task Force ("EITF") of the FASB reached a
consensus on Issue No. 97-4 "Deregulation of the Pricing of
Electricity - Issues Related to the Application of SFAS No. 71 and
SFAS No. 101" in July 1997. The Company discontinued the
application of SFAS No. 71 and applied SFAS No. 101 with respect to
the fossil and hydro generation business at December 31, 1996, in
a manner consistent with the EITF consensus.
With the implementation of PowerChoice, specifically the
separation of non-nuclear generation as an entity that would no
longer be cost-of-service regulated, the Company is required to
assess the carrying amounts of its long-lived assets in accordance
with SFAS No. 121. The Company has determined that there is no
impairment of its fossil and hydro generating assets. To the extent
the proceeds resulting from the sale of the fossil and hydro assets
are not sufficient to avoid a loss, the Company would be able to
recover such loss through the CTC. The PowerChoice agreement
provides for deferral and future recovery of losses, if any,
resulting from the sale of the non-nuclear generating assets. The
Company's fossil and hydro generation plant assets had a net book
value of approximately $1.1 billion at December 31, 1997.
PSC COMPETITIVE OPPORTUNITIES PROCEEDING - ELECTRIC
On May 16, 1996, the PSC issued its Order in the COPS case,
which called for a major restructuring of New York State's electric
industry. The COPS order called for a competitive wholesale power
market and the introduction of retail access for all electric
customers. The goals cited in its decision included lowering
consumer rates, increasing choice, continuing reliability of
service, continuing environmental and public policy programs,
mitigating concerns about market power and continuing customer
protection and the obligation to serve.
The PSC decision in the COPS proceeding states that recovery
of utility stranded costs may be accomplished by a non-bypassable
"wires charge" to be imposed by distribution companies. The PSC
decision also states that a careful balancing of customer and
utility interests and expectations is necessary, and that the level
of stranded cost recovery will ultimately depend upon the
particular circumstances of each utility.
On June 10, 1997, the PSC ordered a multi-utility, retail
access pilot program that would allow qualified farmers and food
processors to shop for electricity and other energy services. The
PSC required utilities to adjust the current delivery rates for
farmers and food processors, which resulted in rate reductions of
about 10 percent for farmers and 3 percent to 6 percent for food
processors. Delivery under this program began in late 1997. The
Company does not believe that this order will have a material
adverse effect on its financial position or results of operations.
On August 27, 1997, the PSC requested comments on its staff's
tentative conclusions about how nuclear generation and fossil
generation should be treated after decisions are made on the
individual electric restructuring agreements currently pending
before the PSC. The PSC staff concluded that beyond the transition
period (the period covered by the individual restructuring
agreements including PowerChoice), nuclear generation should
operate on a competitive basis. In addition, the PSC staff
concluded that a sale of generation plants to third parties is the
preferred means of determining the fair market value of generation
plants and offers the greatest potential for the mitigation of
stranded costs. The PSC staff also concluded that recovery of sunk
costs, including post shutdown costs, would be subject to review by
the PSC and this process should take into account mitigation
measures taken by the utility, including the steps it has taken to
encourage competition in its service area. The Company's nuclear
generation assets had a net book value of $1.5 billion (excluding
the reserve for decommissioning) at December 31, 1997.
In October 1997, the majority of utilities with interests in
nuclear power plants, including the Company, requested that the PSC
reconsider its staff's nuclear proposal. In addition, the
utilities raised the following issues: impediments to nuclear
plants operating in a competitive mode; impediments to the sale of
plants; responsibility for decommissioning and disposal of spent
fuel; safety and health concerns; and environmental and fuel
diversity benefits. In light of all of these issues, the utilities
recommended that a more formal process be developed to address
those issues.
The three investor-owned utilities, Rochester Gas and Electric
Corporation, Consolidated Edison Company of New York, Inc. and the
Company, which are currently pursuing formation of a nuclear
operating company in New York State, also filed a response with the
PSC in October 1997. The response stated that a forced divestiture
of the nuclear plants would add uncertainty to developing a
statewide approach to operating the plants and requested that such
a forced divestiture proposal be rescinded. The response also
stated that implementation of a consolidated six-unit operation
would contribute to the mitigation of unrecovered nuclear costs.
The NYPA, which is also pursuing formation of the nuclear operating
company, submitted its own comments which were similar to the
comments of the three utilities.
In February 1998, the PSC established a formal proceeding to
further examine issues related to nuclear plants and the
feasibility of applying market-based pricing to these facilities.
See "Master Restructuring Agreement and PowerChoice Agreement"
above for a discussion of the treatment of nuclear operations
during the term of PowerChoice.
FERC RULEMAKING ON OPEN ACCESS AND STRANDED COST RECOVERY
In April 1996, the FERC issued FERC Order 888. Order 888
promotes competition by requiring that public utilities owning,
operating, or controlling interstate transmission facilities file
tariffs which offer others the same transmission services they
provide for themselves, under comparable terms and conditions. The
Company has complied with this requirement by filing its open
access transmission tariff with FERC on July 7, 1996. Based upon
settlement discussions with various parties, a proposed settlement
was submitted to the FERC in the first quarter of 1997. The
settlement has not been approved by the FERC at this time.
Hearings were conducted in September 1997 with non-settling
parties. A March 1998 Administrative Law Judge's recommended
decision in this proceeding recommended lower tariffs than those
filed by the Company. The Company is unable to determine the
ultimate resolution of this issue or when a decision will be issued
by FERC.
Under FERC Order 888, the NYPP was required to file reformed
power pooling agreements that establish open, non-discriminatory
membership provisions and modify any provisions that are unduly
discriminatory or preferential. On January 31, 1997, the NYPP
Member Systems (the "Member Systems") submitted a comprehensive
proposal to establish an ISO, a New York State Reliability Council
("NYSRC") and a New York Power Exchange ("NYPE") that will foster
a fully competitive wholesale electricity market in New York State.
The ISO would provide for the reliable operation of the
transmission system in New York State and provide nondiscriminatory
open access to transmission services under a single ISO tariff.
Through the ISO, the transmission owners, including the Company,
would be compensated for the use of their transmission systems on
a cost-of-service basis. The NYSRC would establish the reliability
rules and standards by which the ISO operates the bulk power
system. The ISO would also administer the daily electric energy
market and the NYPE would facilitate the electric energy market on
a day-ahead basis. On May 2, 1997, the Member Systems made a
supplemental filing related to the proposed NYSRC and on August 15,
1997, six of the Member Systems filed an application for market-
based rate authority in the new wholesale market structure. On
December 19, 1997, the Member Systems submitted a revised filing
which reflected the fundamental components of the initial January
31, 1997 filing. However, the December 19, 1997 filing provides
for additional explanatory materials, incorporates FERC's guidance
set forth in FERC orders involving other power pools and ISOs, and
sets forth a revised governance structure of the ISO. The Company
is unable to predict when FERC will act on these submittals, or
whether it will approve the filings with or without modifications.
However, the Company's PowerChoice agreement does not condition
retail access on the presence of an ISO.
In Order 888, the FERC also stated that it would provide for
the recovery of prudent and verifiable wholesale stranded costs
where the wholesale customer was able to obtain alternative power
supplies as a result of Order 888's open access mandate. Order 888
left to the states the issue of retail stranded cost recovery.
Where newly created municipal electric utilities required
transmission service from the displaced utility, the FERC stated
that it would entertain requests for stranded cost recovery since
such municipalization is made possible by open access. The FERC
also reserved the right to consider stranded costs on a case-by-
case basis if it appeared that open access was being used to
circumvent stranded cost review by any regulatory agency.
Numerous parties, including the Company, filed requests for
rehearing of Order 888. In March 1997, the FERC issued Order 888-
A, which generally affirmed Order 888 and granted rehearing on only
a handful of issues. One of those issues was whether the FERC
would review stranded costs in annexation cases as it committed to
do in municipalization cases. In Order 888-A the FERC stated that
it would review stranded costs resulting from territorial
annexation by an existing municipal electric system, provided that
system relied on transmission from the displaced utility. The FERC
denied the Company's request for rehearing on how stranded costs
would be calculated and other issues. In November 1997, FERC
issued Order 888-B. This Order largely affirmed the positions set
forth in Order 888-A while clarifying that the FERC recognizes the
existence of concurrent state jurisdiction over stranded costs
arising from municipalization. The FERC acknowledged in Order 888-
B that the states may be first to address the issue of retail-
turned-wholesale stranded costs, and stated that it will give the
states substantial deference where they have done so.
In late January 1997, the Company provided 26 communities in
St. Lawrence and Franklin counties with estimates they requested of
the stranded costs they might be expected to pay if they withdraw
from the Company's system to create government-controlled
utilities. The preliminary estimate of the combined potential
stranded cost liability for the communities ranges from a low of
$225 million to a high of $452 million, depending upon the forecast
of electricity market prices that is used. These amounts do not
include the costs of creating and operating a municipal utility.
At this time, 21 of the original 26 communities are still pursuing
the matter. If these 21 communities withdrew from the Company's
system, the Company would experience a potential revenue loss of
approximately $60 million to $65 million per year. In addition,
the Company is aware of other communities that are considering
municipalization. However, the Company is unable to predict
whether those communities would pursue municipalization.
The stranded cost calculations were based on a methodology
prescribed by the FERC. Because no municipality has moved forward
with condemnation, the value of the Company's facilities has not
been deducted from the stranded cost estimates. The stranded costs
included in these estimates are the communities' share of
obligations that were incurred on behalf of all customers to
fulfill the Company's legal obligations to ensure adequate,
reliable electricity service. Such legitimate and prudent costs
are currently included in electricity rates. Government-mandated
payments to IPPs represent the largest single component of these
costs. These 21 communities seeking to withdraw from the Company's
system also propose to disconnect entirely from the Company's
system and to take transmission service from another utility. They
believe that, given the provisions of Order 888, FERC would not
approve the Company's request for stranded cost recovery under
these circumstances. The Company has responded that, regardless of
the result at the FERC, opportunities for stranded cost recovery in
this matter could also be pursued before the PSC and in a state
condemnation proceeding. (See "Master Restructuring Agreement and
the PowerChoice Agreement.") The Company is unable to predict the
outcome of this matter.
OTHER FEDERAL AND STATE REGULATORY INITIATIVES
PSC PROPOSAL OF NEW IPP OPERATING AND PPA MANAGEMENT
PROCEDURES. In August 1996, the PSC proposed to examine the
circumstances under which a utility, including the Company, may
legally curtail purchases from IPPs; whether utilities should be
permitted to collect data that will assist in monitoring IPPs'
compliance with federal QF requirements, upon which the mandated
purchases are predicated; and if utilities should be allowed to
demand security from IPPs to ensure the repayment of amounts
accumulated in tracking accounts made under their purchased power
contracts.
The PSC noted that some of the current IPP contracts are far
above market prices and are causing utilities to seek rate
increases. In addition, the PSC stated that its proposal was
initiated to protect ratepayers, since it would ensure just and
reasonable rates in the event ongoing negotiations between
utilities and IPPs fail.
MONITORING. In December 1996, the PSC gave the New York State
utilities, including the Company, the authority to collect data to
assist them in monitoring IPPs' compliance with both federal QF
standards and state requirements. The PSC stated that if QFs are
not meeting requirements, the obligation to pay the full contract
rate, which is funded by utility ratepayers, is generally excused
or mitigated. Furthermore, if the data collected through a QF
monitoring program indicates a facility is not meeting federal
standards, the utility could petition the FERC to decertify the QF,
which could result in penalties that could include cancellation of
the contract. A similar penalty could be imposed if it is
determined a QF has failed to maintain compliance with state law.
Under the monitoring program, QFs are required to submit data as of
March 1 each year for the previous calendar year. In accordance
with the terms of the MRA, the Company will not implement any QF
monitoring program for the IPP Parties. However, the Company
continues to monitor those IPPs that are not IPP Parties for
continued QF compliance under PSC regulation.
CURTAILMENT. On May 20, 1997, the PSC addressed the
procedures under which a utility, including the Company, may
legally curtail purchases from IPPs that are QFs, unless
curtailment is specifically prohibited by contract. Curtailment is
allowed by a FERC rule, under certain operational circumstances
when purchases from the QFs will exceed the costs the utility would
incur if it generated the power itself. Advance notice must be
provided to the QF along with the reasons for such curtailment,
which are subject to verification by the PSC either before or after
curtailment. The PSC stated that PURPA, which encouraged
generation by IPPs, was supposed to be revenue-neutral. However,
they noted that this has not been the situation in New York State
and ratepayers have been unduly burdened because of their lack of
specific curtailment procedures.
The decision to permit curtailment is not likely to affect the
PPAs covered by the MRA, which represents approximately 80% of the
Company's over-market purchased power obligations, as described
previously. However, the decision could affect most of the
remaining IPP contracts. The Company is unable to determine the
effect of these statements until such a time as there is a final
order.
The Company cannot predict whether the PSC will take any
action on the firm security issue. However, the firm security
issue with respect to the IPP Parties covered under the MRA would
be settled upon the closing of the MRA.
MULTI-YEAR GAS RATE SETTLEMENT AGREEMENT. The Company,
Multiple Intervenors (an unincorporated association of
approximately 60 large commercial and industrial energy users with
manufacturing and other facilities located throughout New York
State) and PSC staff reached a three-year settlement that was
conditionally approved by the PSC on December 19, 1996. The PSC
ordered conditional approval on the three-year settlement agreement
until a final, redrafted agreement, which reflects the Commission's
order, is submitted for final approval. The settlement results in
a $10 million annual reduction in base rates or a $30 million total
reduction over the three-year term of the settlement. This
reflects a $19 million reduction in the amount of fixed non-
commodity costs to be recoverable in base rates, offset by a $9
million increase in annual base rates. The Company estimates that
the combination of in-hand supplier refunds and further reductions
in upstream pipeline costs will be sufficient to fund the $19
million annual reduction in non-commodity cost recovery.
If the non-commodity cost reductions exceed $57 million ($19
million annually) during the three-year settlement period, the
excess, up to $40 million will be credited to a Contingency Reserve
Account ("CRA") to be utilized for ratepayer benefit in the rate
year ending October 31, 2000 or beyond. To the extent the actual
non-commodity cost reductions exceed $57 million by more than $40
million, the Company may retain any excess subject to a return on
equity sharing provision. In the event the non-commodity
reductions fall short of the $57 million estimate, the Company will
bear the risk of any shortfall. In the event that the termination
or restructuring of IPP contracts results in margin (revenues less
fuel costs) or peak shaving losses, the margin losses would be
collected currently subject to 80%/20% (ratepayer/shareholder)
sharing and the peak shaving losses will be deferred to the CRA,
subject to limits specified in the settlement.
In return for taking on this risk, the Company has achieved a
portion of the revised rate structure that had been proposed to
reduce its throughput risk. The Company obtained an ROE cap of
13.5% with 50/50 sharing between ratepayers and shareholders in
excess of the cap. The Company also has an opportunity to earn up
to $2.25 million annually if its gas commodity costs are lower than
a market based target without being subject to the ROE cap. The
Company has an equal $2.25 million risk if gas commodity costs
exceed the target. An additional major benefit of the revised rate
design is that the margin made on each additional new customer will
significantly increase to the extent additional throughput does not
require additional upstream pipeline capacity for service. This,
along with the approval of the Company's Progress Fund, which
allows the Company to use utility revenues in an amount not to
exceed $11 million in total for the purpose of providing financing
for large customers to convert or increase their gas use, will
provide new opportunities for growth.
GENERIC GAS RATE PROCEEDING. As a result of the generic rate
proceeding, in which the PSC ordered all New York utilities to
implement a service unbundling beginning in May 1996, nearly 3,000
customers have chosen to buy natural gas from other sources, with
the Company continuing to provide transportation service for a
separate fee. These changes have not had a material impact on the
Company's margins since the margin is traditionally derived from
the delivery service and not from the commodity sale. The margin
for delivery for residential and commercial aggregation services
equals the margin on the traditional sales service classes. To
date this migration has not resulted in any stranded costs since
the PSC has allowed the utilities to assign the pipeline capacity
to the customers converting from sales to transportation. This
assignment is allowed during a three-year period ending March 1999,
at which time the PSC will decide on methods for dealing with the
remaining unassigned or excess capacity. As a part of the generic
rate proceeding, all utilities are required to file a report with
the PSC in April 1998, describing actions that have been taken to
mitigate potential stranded costs as customers migrate to
transportation service. In a clarifying order in this proceeding,
issued September 4, 1997, the PSC has indicated that it is unlikely
that utilities will be allowed to continue to assign pipeline
capacity to departing customers after March 1999.
On a separate but parallel path, in September 1997, the PSC
issued for comment its staff's position paper on the future of the
natural gas industry, including recommendations for increasing
competition and expanding customer choice in the natural gas
marketplace. The staff proposed, among other things, that all
regulated natural gas utilities exit the business of purchasing
natural gas for customers over the next five years. This would
complete the transition of customers from sales to transportation
service only. The regulated utilities would only deliver natural
gas purchased by customers from competitive suppliers. If this
proposal is adopted by the PSC, then it would eliminate the need to
regulate natural gas purchasing practices since market forces would
establish natural gas prices.
The position paper identified a number of issues that would
need to be resolved in order for this proposal to be successful.
The primary issues are the pipeline capacity and gas supply
contracts that the local utilities have with interstate pipelines
that extend beyond the proposed five-year transition period, the
obligation of the utility to serve as supplier of last resort, and
the issue of system reliability.
The Company and other parties submitted comments and reply
comments to the PSC in late November and December of 1997,
respectively. With the exception of the issues to be resolved by
the PSC, as mentioned above, the Company does not believe that this
proposal will have a material adverse effect on its results of
operations or financial condition, since the Company's natural gas
margin is derived from the delivery service and not from the
commodity sale. The resolution of the issues identified by the PSC
could result in unrecovered stranded costs for the Company. The
Company is unable to predict how the PSC will resolve those issues.
For a discussion of the Company's gas supply, storage and pipeline
commitments, see Item 8. Financial Statements and Supplementary
Data - "Note 9. Commitments and Contingencies - Gas Supply, Storage
and Pipeline Commitments.")
NRC AND NUCLEAR OPERATING MATTERS. In October 1996, the NRC
required companies with nuclear plants to provide the NRC with
added confidence and assurance that their plants are operated and
maintained within the design basis, and any deviations are
reconciled in a timely manner. Such information, which was filed
within the required 120 days, will be used by the NRC to verify
that companies are in compliance with the terms and conditions of
their license(s) and NRC regulations. In addition, it will allow
the NRC to determine if other inspection activities or enforcement
actions should be taken on a particular company.
In the letter transmitting the requested information to the
NRC, the Company concluded that it has reasonable assurance that
(i) design basis requirements are being translated into operating,
maintenance, and testing procedures; and (ii) system, structure and
component configuration and performance are consistent with the
design basis. Also, the Company has an effective administrative
tool for the identification, documentation, notification,
evaluation, correction, and reporting of conditions, events,
activities, and concerns that have the potential for adversely
affecting the safe and reliable operation of Unit 1 and Unit 2.
In April 1997 and December 1997, the Company received notices
from the NRC of a $200,000 fine and $50,000 fine, respectively, for
violations at Unit 1 and Unit 2. The penalties were for violations
related to corrective actions and design control. The Company paid
the fines and is implementing corrective action. On January 23,
1998, the Company received notice of a proposed $55,000 fine from
the NRC for violations of NRC requirements related to radioactive
waste issues. The Company does not plan to contest the proposed
NRC fine.
In January 1998, the NRC issued its Systematic Assessment of
Licensee Performance (the "SALP") report on Unit 1 and Unit 2,
which covers the period June 1996 to November 1997. The SALP
report, which is an extensive assessment of the plants' performance
in the areas of operations, maintenance, engineering and support,
stated that the performance of Unit 1 and Unit 2 was generally
good, although ratings were lower than the previous assessment.
The Company agrees with the NRC's determination that there are
areas of its performance that need improvement and is taking
several actions to make those needed improvements.
The Company believes that NRC safety enforcement is becoming
more stringent as indicated by the NRC's request for information,
fines that the Company has been assessed and lower SALP ratings and
that there may be a direct cost impact on companies with nuclear
plants as a result. The Company is unable to predict how such a
changed operating environment may affect its results of operations
or financial condition.
Some owners of older General Electric Company boiling water
reactors, including the Company, have experienced cracking in
horizontal welds in the plants' core shrouds. In response to
industry findings, the Company installed pre-emptive modifications
to the Unit 1 core shroud during a 1995 refueling and maintenance
outage. The core shroud, a stainless steel cylinder inside the
reactor vessel, surrounds the fuel and directs the flow of reactor
water through the fuel assemblies.
Inspections conducted as part of the March 1997 refueling and
maintenance outage detected cracking in vertical welds not
reinforced by the 1995 repairs. On April 8, 1997, the Company
filed a comprehensive inspection and analysis report with the NRC
that concluded that the condition of the Unit 1 core shroud
supports the safe operation of the plant.
On May 8, 1997, the NRC approved the Company's request to
operate Unit 1 until the next scheduled mid-cycle outage, late
1998. The Company agreed to propose an inspection plan for the
outage and submit the plan to the NRC at least three months before
the outage is scheduled to begin. The Company believes it has a
strong technical basis to operate Unit 1 without a mid-cycle outage
and is seeking the necessary approval from the NRC to postpone the
inspections until the unit's refueling and maintenance outage in
spring 1999, but there can be no assurance that such approval will
be granted.
The Unit 1 refueling and maintenance outage, originally
planned to be completed in early April 1997, was completed on May
10, 1997 due to the core shroud issue. On September 15, 1997, Unit
1 was taken out of service due to leaking in one of four back-up
condensers. The standby condensers serve as a back-up system for
the removal of reactor steam. The condensers are maintained in a
ready state during normal plant operations. Tests and inspections
were conducted on the remaining condensers and similar conditions
were found. On December 10, 1997, Unit 1 was returned to service
after the replacement of all four condensers, which cost
approximately $6.7 million.
OTHER COMPANY EFFORTS TO ADDRESS COMPETITIVE CHALLENGES
TAX INITIATIVES. The Company is working with utility,
customer and state representatives to explain the negative impact
that all utility taxes, including the GRT, are having on rates and
the state of the economy. At the same time, the Company is also
contesting the high real estate taxes it is assessed by many taxing
authorities, particularly those imposed upon generating facilities.
The New York State Legislature passed a state budget in August
1997 which includes a reduction of the GRT over three years. For
gas and electric utilities, the tax imposed on gross income will be
reduced from 3.5% to 3.25% on October 1, 1998, and from 3.25% to
2.5% on January 1, 2000. The state tax imposed on gross earnings
will remain unchanged at .75%, bringing the total GRT to 3.25% --
a full percentage point lower than today's level of 4.25%. The
savings from the reduction of the GRT will be passed on to the
Company's customers. The Company believes that further tax relief
is needed to relieve the Company's customers of high energy costs
and to improve New York State's competitive position as the
industry moves toward a competitive marketplace.
The following table sets forth a summary of the components of
other taxes (exclusive of income taxes) incurred by the Company in
the years 1995 through 1997:
In millions of dollars
1997 1996 1995
- ---------------------------------------------------------------
Property tax expense $250.7 $249.4 $264.8
Sales tax 13.4 14.1 13.9
Payroll tax 34.1 36.4 37.3
Gross Receipts Tax 184.6 184.1 190.2
Other taxes 0.1 0.5 5.2
- ---------------------------------------------------------------
Total tax expense 482.9 484.5 511.4
Charged to construction,
subsidiaries and regulatory
recognition (11.4) (8.7) 6.1
- ---------------------------------------------------------------
Total other taxes $471.5 $475.8 $517.5
===============================================================
CUSTOMER DISCOUNTS. In recent years, some industrial
customers have found alternative suppliers or are generating their
own power. In addition, a weakened economy or attractive energy
prices elsewhere have contributed to other industrial 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 (SC-11), under which all new contract rates are
administered based on demonstrated industrial and commercial
competitive pricing alternatives 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. In addition, the Company has
economic development programs which provide tariff based incentives
to retain and grow load.
As of January 1998, the Company has 152 executed contracts
under its flexible tariff offerings. These contracts have been
signed to mitigate the lost margin impacts associated with
customers executing the competitive alternatives mentioned above.
In addition, many of these contracts include an increase in
production levels and/or attract new customers to the Company's
service territory.
In 1997 and 1996, the total amount of customer discounts
(economic development programs and flexible pricing) was $90.6
million and $75.5 million, respectively. The Company recovered
$46.6 million and $56.7 million in rates, respectively. Pending
implementation of PowerChoice, the Company budgeted its discounts
to increase to approximately $95.4 million in 1998 as some
discounts granted in 1997 are in effect for an entire year and
further discounts are granted. The Company is aggressively using
SC-11 to increase sales to existing customers and to attract new
customers to its service territory. With the reduction in
industrial prices provided in PowerChoice, the level of discounts
that have been necessary should decline in the future.
REGULATORY AGREEMENTS/PROPOSALS
(See "Master Restructuring Agreement and the PowerChoice
Agreement.")
1995 RATE ORDER. 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.
YEAR 2000 COMPUTER ISSUE
As the year 2000 approaches, the Company, along with many
other companies, could experience potentially serious operational
problems, since many computer programs that were developed will not
properly recognize calendar dates beginning with the year 2000.
Further, there are embedded chips contained within generation,
transmission, distribution and gas equipment that may be date-
sensitive. In these circumstances where an embedded chip fails to
recognize the correct date, electric or gas operations could be
adversely affected. The Company is addressing these issues so that
its computer systems and, where necessary, its embedded chips will
process dates greater than 1999, thereby preventing any adverse
operational or financial impacts. The Company has been addressing
the year 2000 information technology issue through the remediation
and replacement of existing business applications and parts of its
technical infrastructure. In late 1997, the services of a leading
computer services and consulting firm were retained to conduct an
assessment of the Company's entire year 2000 program. As a result
of the assessment, a Company-wide year 2000 project management
office has been formed and year 2000 project managers have been
appointed within each business group and efforts are underway to
evaluate the scope of the problem for embedded technologies/process
control systems in all business groups within the Company. A
Company-wide program director and an executive level steering
committee have been put in place to oversee all aspects of the
program. The Company is also evaluating the exposure to year 2000
problems of third parties with whom the Company conducts business.
The Company expects to complete an inventory of exposures,
including an assessment of priorities, costs and resources, by the
third quarter of 1998. Failures of the Company and/or third party
computer systems and embedded chips could have a material impact on
the Company's ability to conduct its business. Until further
progress is made on these efforts, management is unable to estimate
the total year 2000 compliance expense, but it is in the process of
assessing this expense.
RESULTS OF OPERATIONS
Earnings for 1997 were $22.4 million, or 16 cents per share,
as compared to $72.1 million, or 50 cents per share, in 1996 and
$208.4 million, or $1.44 per share, in 1995. 1997 earnings were
negatively impacted by a write-off of $190.0 million or 85 cents
per share associated with the portion of the MRA regulatory asset
disallowed in rates by the PSC, which was included in other income
and deductions in the income statement (see "Master Restructuring
Agreement and the PowerChoice Agreement" and "Accounting
Implications of the PowerChoice Agreement and Master Restructuring
Agreement.") In addition, an increase in industrial customer
discounts of $25.2 million not recovered in rates (see Other
Company Efforts to Address Competitive Challenges - "Customer
Discounts"), and a decline in higher-margin residential sales also
adversely impacted 1997 earnings. The lower-margin industrial-
special sales (sales by the Company on behalf of NYPA) and
industrial sales increased. As a result, total public sales were
essentially the same as sales in 1996. This was partially offset
by a decline in bad debt expense of $81.1 million in 1997 as
compared to 1996 but is $15.3 million over 1995.
Earnings for 1996 include the discontinued application of
regulatory accounting principles to the Company's fossil and hydro
generation business. The Company reached this conclusion because
the March 10, 1997 agreement-in-principle to terminate or
restructure power contracts with certain IPPs made probable the
implementation of PowerChoice in which the Company proposed to have
its non-nuclear generation sell power at competitive prices in the
wholesale market. The discontinuance resulted in the write-off of
$103.6 million of regulatory assets associated with the fossil and
hydro business which was included in the income statement as an
extraordinary loss after tax of $67.4 million, or 47 cents per
share. Earnings before the extraordinary loss were $139.5 million
or 97 cents per share. Excluding the extraordinary loss, earnings
for 1996 were lower because of an increase in bad debt expense of
$96.4 million or 43 cents per share (see "Financial Position,
Liquidity and Capital Resources - Liquidity and Capital
Resources"). This was partially offset by a $15.0 million gain on
the sale of a 50% interest in CNP that contributed 10 cents per
share to 1996 earnings. The Company's request for a temporary rate
increase in 1996 was denied by the PSC.
Earnings for 1995 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. These
factors similarly impacted 1996 and 1997 results. In addition,
1995 earnings included the recording of a one-time, non-cash
adjustment of prior years' demand-side management ("DSM") incentive
revenues, revenues earned under the Unit 1 operating incentive
sharing mechanism and a gain on the sale of HYDRA-CO that
collectively increased 1995 earnings by 17 cents per share.
The Company's 1997 earned ROE was 0.9% as compared to 2.8%
(5.4% before extraordinary loss) in 1996 and 8.4% in 1995. The
Company's ROE authorized in the 1995 or last rate setting process
is 11.0% for the electric business and 11.4% for the gas business.
Factors contributing to earnings below authorized levels in 1997
included, among other things, the PowerChoice charge described
above, sales below those forecasted in determining rates,
contractual increases in capacity payments to IPPs and increasing
discounts to customers. As discussed under "Master Restructuring
Agreement and the PowerChoice Agreement" and "Accounting
Implications of the PowerChoice Agreement and Master Restructuring
Agreement," the Company forecasts that earnings for the five-year
term of the PowerChoice agreement will be substantially depressed.
The level of earnings for 1998 will also be impacted, in part, by
the date of implementation of PowerChoice and may also be
negatively impacted by the financial effects of the January 1998
ice storm (see Item 8. Financial Statements and Supplementary Data
- - "Note 13. Subsequent Event").
The following discussion and analysis highlights items that
significantly affected operations during the three-year period
ended December 31, 1997. This discussion and analysis is not
likely to be indicative of future operations or earnings,
particularly in view of the probable termination, restatement or
amendment of IPP contracts and implementation of PowerChoice. It
also should be read in conjunction with Item 8. Financial
Statements and Supplementary Data and other financial and
statistical information appearing elsewhere in this report.
ELECTRIC REVENUES were $3,309 million in both 1997 and 1996,
a decrease of $26.1 million, or 0.8% from 1995. As shown in the
following table, FAC revenues increased $42.8 million in 1997,
primarily as a result of the Company's ability in 1997 to recover
increased payments to the IPPs through the FAC. However, this
increase was offset by a decrease in revenues from sales to other
electric systems and lower electric sales due to warmer weather.
Under PowerChoice, revenues may decline as customers choose
alternative suppliers. However, the Company will recover stranded
costs through the CTC. See "Master Restructuring Agreement and the
PowerChoice Agreement."
Electric operating revenues decreased in 1996, primarily due
to a decrease in miscellaneous electric revenues. Miscellaneous
electric revenues were lower in 1996 primarily because 1995
electric revenues included the recording of $71.5 million of
unbilled, non-cash revenues in accordance with the 1995 rate order,
$13.0 million of revenues earned under MERIT (an incentive
mechanism related to improvement in key performance areas which
ended in 1996) and a one-time, non-cash adjustment of prior year's
DSM incentive revenues and a reduction in the DSM rebate cost
program. However, higher electric sales due to colder weather, an
increase in sales to other electric systems, an increase in FAC
revenues and higher electric rates (effective April 26, 1995)
partly offset those factors that contributed to lower electric
revenues. FAC revenues increased $28.3 million in 1996, which
primarily reflects the Company's increased payments to the IPPs
recovered through the FAC.
INCREASE (DECREASE) FROM PRIOR YEAR
(In millions of dollars)
- -----------------------------------------------------------------
ELECTRIC REVENUES 1997 1996 TOTAL
- -----------------------------------------------------------------
Amortization of unbilled
revenues $ - $ (77.1) $ (77.1)
Base rates - 65.3 65.3
Fuel adjustment clause
revenues 42.8 28.3 71.1
Changes in volume and mix
of sales to ultimate
consumers (12.7) (28.1) (40.8)
Sales to other electric
systems (29.6) 24.5 (5.1)
MERIT revenue - (13.0) (13.0)
DSM revenue - (26.5) (26.5)
------- ------ -----
$ 0.5 $ (26.6) $ (26.1)
======== ====== ======
The FAC is eliminated under the PowerChoice agreement.
Changes in FAC revenues are generally margin-neutral (subject to an
incentive mechanism discussed in Item 8. Financial Statements and
Supplementary Data - "Note 1. Summary of Significant Accounting
Policies"), 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 provided for the recovery
of program related rebate costs.
ELECTRIC KILOWATT-HOUR SALES were 37.1 billion in 1997, 39.1
billion in 1996 and 37.7 billion in 1995. The 1997 decrease of 2.0
billion KWh, or 5.1% as compared to 1996, is related primarily to
a 31.0% decrease in sales to other electric systems. (See Item 8.
Financial Statements and Supplementary Data -"Electric and Gas
Statistics - Electric Statistics"). The 1996 increase of 1.4
billion KWh, or 3.8% as compared to 1995, reflects a 26.2% increase
in sales to other electric systems and a 1.2% increase in sales to
ultimate customers due to the colder weather. Sales to other
electric systems were lower primarily due to a reduction in the
availability of nuclear generation as a result of the outages at
Unit 1. The Company is anticipating little or no growth in 1998 in
sales to ultimate consumers, which will be sensitive to the
business climate in its service territory.
Details of the changes in electric revenues and KWh sales by customer group are
highlighted in the table below:
% INCREASE (DECREASE) FROM PRIOR YEAR
1997 % OF -------------------------------------
ELECTRIC 1997 1996
CLASS OF SERVICE REVENUES REVENUES SALES REVENUES SALES
- ----------------------------------------------------------------------
Residential 37.1% (2.0)% (2.0)% 3.1% 0.5%
Commercial 37.3 (0.3) (0.1) - (0.4)
Industrial 16.1 1.2 0.6 0.2 1.2
Industrial-Special 1.9 5.8 4.2 3.9 6.7
Municipal service 1.6 1.4 (4.5) 5.8 7.4
- ----------------------------------------------------------------------
Total to ultimate
consumers 94.0 (0.6) - 1.4 1.2
Other electric
systems 2.5 (26.1) (31.0) 27.5 26.2
Miscellaneous 3.5 70.4 (100.0) (57.8) (17.7)
- ----------------------------------------------------------------------
TOTAL 100.0% -% (5.1)% (0.8)% 3.8%
As indicated in the table below, internal generation decreased
10.1% in 1997, principally due to the outage at Unit 1 and a
reduction in hydroelectric power as a result of lower than normal
precipitation in the summer months. In 1997, Unit 1 was out of
service for 153 days, due to a planned refueling and maintenance
outage (which took 68 days) and for the emergency condenser
replacement (which took approximately 85 days) while in 1996, Unit
2 was out of service for a 36 day planned refueling and maintenance
outage. (See "Other Federal and State Regulatory Initiatives - NRC
and Nuclear Operating Matters.") The amount of electricity
delivered to the Company by the IPPs decreased by approximately 277
GWh or 2.0%. However, total IPP costs increased by approximately
$18.0 million or 1.7%, as discussed below. (See "Master
Restructuring Agreement and the PowerChoice Agreement").
1997 1996 1995
--------------- ---------------- ----------------
(In millions of dollars)
GWh Cost GWh Cost GWh Cost
------ ------ ------ ------- ------ --------
Fuel for electric
generation:
Coal 7,459 $ 106.4 7,095 $ 100.6 6,841 $ 97.9
Oil 701 32.2 462 21.1 537 21.3
Natural gas 394 8.6 319 9.2 996 20.2
Nuclear 6,339 33.0 8,243 47.7 7,272 43.3
Hydro 2,905 - 3,679 - 2,971 -
------- ------ ------ ------- ------ --------
17,798 180.2 19,798 178.6 18,617 182.7
------- ------ ------ ------- ------ --------
Electricity
purchased:
IPPs:
Capacity - 220.8 - 212.8 - 181.2
Energy and taxes 13,520 885.7 13,797 875.7 14,023 798.7
------ ----- ------ ------- ------ -------
Total IPP purchases 13,520 1,106.5 13,797 1,088.5 14,023 979.9
Other 9,421 130.2 9,569 130.6 9,463 126.5
------ ------- ------ ------- ------ -------
22,941 1,236.7 23,366 1,219.1 23,486 1,106.4
------ ------- ------ ------- ------ -------
Total generated
and purchased 40,739 1,416.9 43,164 1,397.7 42,103 1,289.1
Fuel adjustment
clause - (1.3) - (33.3) - 14.8
Losses/Company use 3,603 - 4,037 - 4,419 -
------ ------- ------ -------- ------ --------
37,136 $1,415.6 39,127 $1,364.4 37,684 $1,303.9
====== ======= ====== ======== ====== ========
% Change from Prior Year
---------------------------------
1997 to 1996 1996 to 1995
------------ ------------
(In millions of dollars)
GWh Cost GWh Cost
------ ---- ------ ----
Fuel for electric
generation:
Coal 5.1% 5.8% 3.7% 2.8%
Oil 51.7 52.6 (14.0) (0.9)
Natural gas 23.5 (6.5) (68.0) (54.5)
Nuclear (23.1) (30.8) 13.4 10.2
Hydro (21.0) - 23.8 -
------ ------ ------ ------
(10.1) 0.9 6.3 (2.2)
------ ------ ------ ------
Electricity
purchased:
IPPs:
Capacity - 3.8 - 17.4
Energy and taxes (2.0) 1.1 (1.6) 9.6
----- ----- ----- -----
Total IPP purchases (2.0) 1.7 (1.6) 11.1
Other (1.5) (0.3) 1.1 3.2
----- ----- ----- -----
(1.8) 1.4 (0.5) 10.2
----- ------ ----- -----
Total generated
and purchased (5.6) 1.4 2.5 8.4
Fuel adjustment
clause - (96.1) - (325.0)
Losses/Company use (10.8) - (8.6) -
------- ------- ------ -------
(5.1)% 3.8% 3.8% 4.6%
======= ======= ====== =======
The above table presents the total costs for purchased
electricity, while reflecting only fuel costs for Company
generation. Other costs of generation, such as taxes, other
operating expenses and depreciation are included within other
income statement line items.
The Company's management of its IPP power supply generally
divides the projects into three categories: hydroelectric, "must
run" cogeneration and schedulable cogeneration projects.
Following a higher than normal spring run off, the
precipitation in the summer months was lower than usual. As a
result, hydroelectric IPP projects delivered 242 GWh or 13.7% less
under PPAs than they did for the same period last year,
representing decreased payments to those IPPs of $15.7 million.
A substantial portion of the Company's portfolio of IPP
projects operate on a "must run" basis. This means that they tend
to run at maximum production levels regardless of the need for or
economic value of the electricity produced. Output from "must run"
cogeneration IPPs was 230 GWh or 2.6% lower than produced last
year, in part due to lower energy purchases from the Sithe
Independence plant. However, payments to those IPPs were $12.8
million higher. This was due to a combination of output turndown
arrangements with individual projects and escalating contract
rates. A turndown arrangement is an agreement where the Company
compensates an IPP to reduce the output from their facility.
Although output is reduced, the net economic impact is favorable to
the Company and its customers since the electricity is replaced
from the market or other lower cost sources.
Quantities purchased from schedulable cogeneration IPPs
increased 195 GWh or 6.3% and payments increased $20.9 million.
The increased payments are largely due to escalating contract rates
for capacity (fixed) and increased volumes of energy. The terms of
these PPAs allow the Company to schedule (with certain constraints)
energy deliveries and pay for the energy supplied. In addition,
the Company is required to make fixed payments if the IPP plants
remain available for service. (See Item 8. Financial Statements
and Supplementary Data - "Note 9. Commitments and Contingencies -
Long-term Contracts for the Purchase of Electric Power").
GAS REVENUES decreased by $24.7 million, or 3.6% in 1997, and
increased by $99.9 million, or 17.2%, in 1996. As shown in the
table below, gas revenues decreased in 1997 primarily due to
decreased sales to ultimate customers as a result of the migration
of commercial sales customers to the transportation class,
decreased spot market sales and a decrease in base rates of $5.9
million in accordance with the 1996 rate order. This was partially
offset by higher gas adjustment clause recoveries and an increase
in revenues from the transportation of customer-owned gas (see
"Other Federal and State Regulatory Initiatives -Generic Gas Rate
Proceeding").
Gas revenues increased in 1996 primarily due to increased
sales to ultimate customers due to colder weather, increased spot
market sales, higher gas adjustment clause recoveries, an increase
in revenues from the transportation of customer-owned gas and an
increase in base rates of $3.1 million in accordance with the 1995
rate order.
Rates for transported gas (excluding aggregation services)
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, particularly in
instances where customers that took direct service from the Company
move to a transportation-only class. In addition, changes in
purchased gas adjustment clause revenues are generally margin-
neutral.
INCREASE (DECREASE) FROM PRIOR YEAR
(In millions of dollars)
GAS REVENUES 1997 1996 TOTAL
- ---------------------------------------------------------------
Base rates $ (5.9) $ 3.1 $ (2.8)
Transportation of
customer-owned gas 5.3 2.1 7.4
Purchased gas adjustment
clause revenues 45.3 30.8 76.1
Spot market sales (30.8) 34.0 3.3
Changes in volume and
mix of sales to ultimate
consumers (38.6) 29.9 (8.8)
------- ------ ------
$(24.7) $ 99.9 $ 75.2
======= ====== =======
GAS SALES, excluding transportation of customer-owned gas and
spot market sales, were 78.7 million Dth in 1997, a 7.3% decrease
from 1996, and a 0.3% increase from 1995. (See Item 8. Financial
Statements and Supplementary Data - "Electric and Gas Statistics -
Gas Statistics"). The decrease in 1997 was in all ultimate
consumer classes, in part due to the warmer weather. In addition,
spot market sales (sales for resale), which are generally from the
higher priced gas available to the Company and therefore yield
margins that are substantially lower than traditional sales to
ultimate customers, decreased 8.0 million Dth. This was partially
offset by an increase in transportation volumes of 18.1 million Dth
or 13.5% to customers purchasing gas directly from producers. The
Company has experienced an increase in customers of approximately
17,800 since 1995, primarily in the residential class, an increase
of 3.5%.
Changes in gas revenues and Dth sales by customer group are
detailed in the table below:
% INCREASE (DECREASE) FROM PRIOR YEAR
1997 % OF -------------------------------------
GAS 1997 1996
CLASS OF SERVICE REVENUES REVENUES SALES REVENUES SALES
- ---------------------------------------------------------------------
Residential 66.4% 4.5% (2.7)% 13.3% 9.4%
Commercial 22.6 (8.7) (13.0) 13.0 6.4
Industrial 1.0 (50.9) (50.1) 15.6 4.1
- ---------------------------------------------------------------------
Total to ultimate
consumers 90.0 (0.3) (7.3) 13.3 8.3
Other gas
systems - (5.8) (6.7) (81.9) (81.4)
Transportation of
customer-owned
gas 8.5 10.5 13.5 4.3 (6.9)
Spot market sales 1.0 (82.9) (76.6) 1,099.1 507.0
Miscellaneous 0.5 263.1 - (82.2) -
- ---------------------------------------------------------------------
TOTAL 100.0% (3.6)% 1.7% 17.2% 2.3%
The total cost of gas purchased decreased 6.6% in 1997 and
increased 34.0% in 1996. The cost fluctuations generally
correspond to sales volume changes, as spot market sales activity
decreased, as well as changes in gas prices. The Company sold 2.5,
10.5 and 1.7 million Dth on the spot market in 1997, 1996 and 1995,
respectively. The total cost of gas decreased $24.4 million in
1997. This was the result of a 5.3 million decrease in Dth
purchased and withdrawn from storage for ultimate consumer sales
($18.8 million) and a $22.5 million decrease in Dth purchased for
spot market sales, partially offset by a 3.3% increase in the
average cost per Dth purchased ($10.7 million) and a $6.3 million
increase in purchased gas costs and certain other items recognized
and recovered through the purchased gas adjustment clause.
The total cost of gas purchased increased $93.8 million in
1996. This was the result of a 9.3 million increase in Dth
purchased and withdrawn from storage for ultimate consumer sales
($29.6 million), a $25.6 million increase in Dth purchased for spot
market sales and a 12.9% increase in the average cost per Dth
purchased ($38.7 million). Gas purchased for spot market sales
decreased $22.5 million in 1997 and increased $25.6 million in
1996. The Company's net cost per Dth sold, as charged to expense
and excluding spot market purchases, increased to $3.82 in 1997
from $3.62 in 1996 and was $3.17 in 1995.
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. The Company absorbed losses
of approximately $11.8 million, $1.4 million and $13.1 million in
1995, 1996 and 1997, respectively. Under PowerChoice, the FAC will
be terminated. The Company does not believe that the elimination
of the FAC will have a material adverse effect on its financial
condition, as a result of its management of (1) power supplies
provided through: (i) the operation of its own power plants, and
future power purchase arrangements as part of the planned auction
of its fossil and hydro assets, (ii) fixed power purchases from
NYPA and remaining IPPs and (iii) fixed and indexed swap
arrangements with IPP Parties and (2) the transfer of the risk
associated with electricity commodity prices to the customer
through implementation of retail access included in the PowerChoice
agreement.
OTHER OPERATION AND MAINTENANCE EXPENSE decreased in 1997 by
$92.9 million, or 10.0%, as compared to an increase of $110.3
million or 13.5% in 1996. These changes in 1996 and 1997 each
result primarily from a change in 1996 in the Company's assessment
of uncollectible customer accounts, which gives greater recognition
to the increased risk of collecting past due customer bills,
resulting in increases in the Company's allowance for doubtful
accounts and a significantly higher expense recognition in 1996.
Bad debt expense was $31.2 million, $127.6 million and $46.5
million in 1995, 1996 and 1997, respectively. In 1997, write-offs
were $39.0 million and the Company incurred a $10.5 million
increase in allowance for doubtful accounts. The increase in the
allowance for doubtful accounts was attributable to increases in
the collection risk associated with residential accounts receivable
and arrears. The Company has implemented a number of collection
initiatives that are expected to result in lower arrears levels and
potentially lower the allowance for doubtful accounts. Other
operation and maintenance expense also decreased in 1997 as a
result of a reduction in administrative and general expenses of
$15.8 million, primarily due to a reduction in legal costs.
OTHER INCOME AND DEDUCTIONS decreased by $200.9 million in
1997 and increased by $32.9 million in 1996. Despite higher
interest income ($12.0 million) related to increasing cash
balances, "other income and deductions" decreased in 1997 due to
the write-off of $190.0 million associated with the estimated
portion of the MRA regulatory asset disallowed in rates and lower
subsidiary earnings. In addition, "other income and deductions"
was lower in 1997, since 1996 reflected a gain on the sale of a 50%
interest in CNP ($15.0 million). The 1996 increase also reflected
higher interest income ($10.9 million) as a result of an increase
in temporary cash investments. In addition, "other income and
deductions" was higher in 1996 since there were customer service
penalties and certain other items written off because they were
disallowed in rates in 1995.
FEDERAL AND FOREIGN INCOME TAXES decreased by $42.4 million in
1997 and $56.9 million in 1996 primarily due to a decrease in pre-
tax income. Other taxes decreased by $4.4 million in 1997 and
decreased by $41.6 million in 1996. The 1997 decrease was
primarily due to lower payroll taxes ($2.3 million) and lower sales
taxes ($0.7 million). The 1996 decrease was primarily as a result
of lower real estate taxes ($15.4 million), lower GRTs ($6.1
million) primarily due to a reduction in the GRT surcharge during
1996, lower New York State excess dividend tax accrual due to a
suspension of the common stock dividend ($4.6 million) and year-to-
year differences in the accounting for regulatory deferrals ($15.2
million) associated primarily with a settlement of tax issues with
respect to the Company's Dunkirk facility.
INTEREST CHARGES remained fairly constant for the years 1995
through 1997. However, dividends on preferred stock decreased by
$0.9 million and $1.3 million in 1997 and 1996, respectively.
Dividends on preferred stock decreased in 1997 primarily due to a
reduction in preferred stock outstanding through sinking fund
redemptions and decreased in 1996 primarily due to a decrease in
the cost of variable rate issues. The weighted average long-term
debt interest rate and preferred dividend rate paid, reflecting the
actual cost of variable rate issues, changed to 7.81% and 7.04%,
respectively, in 1997 from 7.71% and 7.09%, respectively, in 1996
and from 7.77% and 7.19%, respectively, in 1995.
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, 1997 was 52.8% long-term debt, 7.8% preferred stock
and 39.4% common equity, as compared to 53.1%, 7.9% and 39.0%
respectively, at December 31, 1996. The culmination of the
termination, restatement or amendment of IPP contracts will
significantly increase the leverage of the Company to nearly 65% at
the time of closing. Through the anticipated increased operating
cash flow resulting from the MRA and PowerChoice agreement, the
planned rapid repayment of debt should deleverage the Company over
time. Book value of the common stock was $18.03 per share at
December 31, 1997, as compared to $17.91 per share at December 31,
1996. With the issuance of equity at below book value to the IPP
Parties as part of the MRA, book value per share will be diluted.
In addition, earnings per share will be diluted by the effect of
the issuance to the IPP Parties of approximately 42.9 million
shares of the Company's common stock.
The Company's EBITDA for 1997 was approximately $897 million,
and upon implementation of the MRA and PowerChoice is expected to
increase to approximately $1,300 million to $1,500 million per
year. EBITDA represents earnings before interest charges, interest
income, income taxes, depreciation and amortization, and
extraordinary items. EBITDA is a non-GAAP measure of cash flows
and is presented to provide additional information about the
Company's ability to meet its future requirements for debt service
which would increase significantly upon consummation of the MRA.
EBITDA should not be considered an alternative to net income as an
indicator of operating performance or as an alternative to cash
flows, as presented on the Consolidated Statement of Cash Flows, as
a measure of liquidity.
The 1997 ratio of earnings to fixed charges was 1.39 times.
The ratios of earnings to fixed charges for 1996 and 1995 were 1.57
times and 2.29 times, respectively. The change in the ratio was
primarily due to changes in earnings during the period. Assuming
the MRA is implemented, the ratio of earnings to fixed charges will
substantially decrease in the future, since the MRA and PowerChoice
agreement will have the effect of substantially depressing earnings
during its five-year term, while at the same time substantially
improving operating cash flows. The primary objective of the MRA
is to convert a large and growing off-balance sheet payment
obligation that threatens the financial viability of the Company
into a fixed and manageable capital obligation.
COMMON STOCK DIVIDEND. The Board of Directors omitted the
common stock dividend beginning 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 and is the
primary reason for the increase in the cash balance. In making
future dividend decisions, the Board of Directors will evaluate,
along with standard business considerations, the financial
condition of the Company, the closing of the MRA and implementation
of PowerChoice, or the failure to implement such actions,
contractual restrictions that might be entered into in conjunction
with financing the MRA, the degree of competitive pressure on its
prices, the level of available cash flow and retained earnings and
other strategic considerations. The Company expects to dedicate a
substantial portion of its future expected positive cash flow to
reduce the leverage created in connection with the implementation
of the MRA. The PowerChoice agreement establishes limits to the
annual amount of common and preferred stock dividends that can be
paid by the regulated business. The limit is based upon the amount
of net income each year, plus a specified amount ranging from $50
million in 1998 to $100 million in 2000. The dividend limitation is
subject to review after the term of the PowerChoice agreement.
Furthermore, the Company forecasts that earnings for the five-year
term of the PowerChoice agreement will be substantially depressed,
as non-cash amortization of the MRA regulatory asset is occurring
and the interest costs on the IPP debt is the greatest. See
"Accounting Implications of the PowerChoice Agreement and Master
Restructuring Agreement."
CONSTRUCTION AND OTHER CAPITAL REQUIREMENTS. The Company's
total capital requirements consist of amounts for the Company's
construction program (see Item 8. Financial Statements and
Supplementary Data - "Note 9. Commitments and Contingencies -
Construction Program,"). The January 1998 ice storm damage
restoration costs may further add to these requirements (see Item
8. Financial Statements and Supplementary Data - "Note 13.
Subsequent Event"), nuclear decommissioning funding requirements
(See Item 8. Financial Statements and Supplementary Data - "Note 3.
Nuclear Operations - Nuclear Plant Decommissioning" and - "NRC
Policy Statement and Proposal"), working capital needs, maturing
debt issues and sinking fund provisions on preferred stock, as well
as requirements to complete the MRA and accomplish the
restructuring contemplated by the PowerChoice agreement. Annual
expenditures for the years 1995 to 1997 for construction and
nuclear fuel, including related AFC and overheads capitalized, were
$345.8 million, $352.1 million and $290.8 million, respectively,
and are budgeted to be approximately $358 million for 1998 and to
range from $279 - $352 million for each of the subsequent four
years. These estimates include construction expenditures for non-
nuclear generation of $20 million to $38 million per year.
In addition to the assumed cost of the MRA requirements, as
described below, mandatory debt and preferred stock retirements are
expected to add approximately another $77 million to the 1998
estimate of capital requirements. The estimate of construction
additions included in capital requirements for the period 1998 to
2002 will be reviewed by management to give effect to the storm
restoration costs and the overall objective of further reducing
construction spending 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.
Under the MRA, the Company will pay an aggregate of $3,616
million in cash. The Company expects to issue senior unsecured debt
to fund this requirement, which is expected to consist of both debt
issued through a public market offering and debt issues to banks
which would serve to replace its existing $804 million senior debt
facility, discussed below. The Company's preferred shareholders
gave the Company approval to increase the amount of unsecured debt
the Company may issue by $5 billion. Previously, the Company was
able to issue $700 million under the restrictions of its amended
Certificate of Incorporation. This authorization will enable the
issuance of unsecured debt to consummate the MRA. In addition, the
Company believes that the ability to use unsecured indebtedness
will increase its flexibility in planning and financing its
business activities.
LIQUIDITY AND CAPITAL RESOURCES. External financing plans
are subject to periodic revision as underlying assumptions are
changed to reflect developments, market conditions and, most
importantly, conclusion of the MRA and implementation of
PowerChoice. The ultimate level of financing during the period
1998 through 2002 will be affected by, among other things: the
timing and outcome of the MRA and the cash tax benefits anticipated
because the MRA is expected to result in a net operating loss for
1998 income tax purposes; the implementation of the PowerChoice
agreement, levels of common dividend payments, if any, and
preferred dividend payments; the results of the auction of the
Company's fossil and hydro assets; 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 effects of the ice storm that struck
a portion of the Company's service territory in early 1998. The
proceeds of the sale of the fossil and hydro assets will be subject
to the terms of the Company's mortgage indenture and the note
indenture that will be entered into in connection with the MRA debt
financing. The Company could also be affected by the outcome of
the NRC's consideration of new rules for adequate financial
assurance of nuclear decommissioning obligations. (See Item 8.
Notes to Consolidated Financial Statements - "Note 3. Nuclear
Operations - NRC Policy Statement and Proposal" and "Note 13.
Subsequent Event").
The Company has an $804 million senior debt facility with a
bank group, consisting of a $255 million term loan facility, a $125
million revolving credit facility and $424 million for letters of
credit. The letter of credit facility provides credit support for
the adjustable rate pollution control revenue bonds issued through
the NYSERDA. The interest rate applicable to the senior debt
facility is variable based on certain rate options available under
the agreement and currently approximates 7.7% (but is capped at
15%). As of December 31, 1997, the amount outstanding under the
senior debt facility was $529 million, consisting of $105 million
under the term loan facility and a $424 million letter of credit,
leaving the Company with $275 million of borrowing capability under
the facility. The facility expires on June 30, 1999 (subject to
earlier termination if the Company separates its fossil/hydro
generation business from its transmission and distribution
business, or any other significant restructuring plan). The
Company is currently negotiating with the lenders to replace the
senior debt facility with a larger facility to finance a portion of
the MRA.
This facility is collateralized by first mortgage bonds which
were issued on the basis of additional property under the earnings
test required under the mortgage trust indenture ("First Mortgage
Bonds"). As of December 31, 1997, the Company could issue an
additional $1,396 million aggregate principal amount of First
Mortgage Bonds under the Company's mortgage trust indenture. This
amount is based upon retired bonds without regard to an interest
coverage test. The Company is presently precluded from issuing
First Mortgage Bonds based on additional property.
Although no assurance can be provided, the Company believes
that the closing of the MRA and implementation of PowerChoice will
result in substantially depressed earnings during its five-year
term, but will substantially improve operating cash flows. There
is risk throughout the electric industry that credit ratings could
decline if the issue of stranded cost recovery is not
satisfactorily resolved. In the event the MRA is not closed, and
comparable solutions are not available, the Company will undertake
other actions necessary to act in the best interests of
stockholders and other constituencies.
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. This has not been the case in the last two years as the
Company's cash balance has increased, reflecting suspension of the
common stock dividend in 1996. 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. The
Company believes it has sufficient borrowing capacity to fund
deficits as necessary in the near term. However, the Company's
borrowing capacity to fund such deficits may be affected by the
factors discussed above relating to the Company's external
financial plans.
Since 1995, past-due accounts receivable have increased
significantly. A number of factors have contributed to the
increase, including rising prices (particularly to residential
customers). Rising prices have been driven by increased payments
to IPPs and high taxes and have been passed on in customers' bills.
The stagnant economy in the Company's service territory since the
early 1990's has adversely affected collection of past-due
accounts. Also, laws, regulations and regulatory policies impose
more stringent collection limitations on the Company than those
imposed on business in general; for example, the Company faces more
stringent requirements to terminate service during the winter
heating season. The increase in the allowance for doubtful
accounts was attributable to the reassessment of the collection
risk associated with residential accounts receivable and arrears.
The Company has implemented a number of collection initiatives that
are expected to result in lower arrears levels and potentially
lower the allowance for doubtful accounts. The Company has and
will continue to implement a variety of strategies to improve its
collection of past due accounts and reduce its bad debt expense.
The information gathered in developing these strategies
enabled management to update its risk assessment of the accounts
receivable portfolio. Based on this assessment, management
determined that the level of risk associated primarily with the
older accounts had increased and the historical loss experience no
longer applied. Accordingly, the Company determined that a
significant portion of the past-due accounts receivable
(principally of residential customers) might be uncollectible, and
had written-off a substantial number of these accounts as well as
increased its allowance for doubtful accounts in 1996. In 1997 and
1996, the Company charged $46.5 million and $127.6 million,
respectively to bad debt expense. The allowance for doubtful
accounts is based on assumptions and judgments as to the
effectiveness of collection efforts. Future results with respect
to collecting the past-due receivables may prove to be different
from those anticipated. Although the Company has experienced a
level of improvement in collection efforts, future results are
necessarily dependent upon the following factors, including, among
other things, the effectiveness of the strategies discussed above,
the support of regulators and legislators to allow utilities to
move towards commercial collection practices and improvement in the
condition of the economy in the Company's service territory. The
Company has been pursuing PowerChoice to address high prices that
are the result of traditional price regulation, but the
introduction of competition requires that policies and practices
that were central to traditional regulation, including those
involving collections, be changed so as not to jeopardize the
benefits of competition.
NET CASH PROVIDED BY OPERATING ACTIVITIES decreased $162.8
million in 1997 primarily due to a decrease of $105.9 million in
the amount of accounts receivable sold under the accounts
receivable sales program (which the Company has budgeted to restore
in 1998) partially offset by an increase in deferred taxes of $53.9
million.
NET CASH USED IN INVESTING ACTIVITIES increased $62.4 million
in 1997 primarily as a result of an increase in other cash
investments of $116.1 million offset by a decrease in the
acquisition of utility plant of $62.9 million.
NET CASH USED IN FINANCING ACTIVITIES decreased $106.1
million, primarily due to a net reduction of $94.7 million in the
payments on long-term debt.
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,
1997.
Consolidated Balance Sheets at December 31, 1997 and 1996.
Consolidated Statements of Cash Flows for each of the three
years in the period ended December 31, 1997.
Notes to Consolidated Financial Statements.
REPORT OF MANAGEMENT
The consolidated financial statements of the Company 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 (the "Code") that supply
employees with a framework describing and defining the Company's
overall approach to business and require 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
GAAP. In planning and performing its audit, Price Waterhouse LLP
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 LLP to review
and discuss internal accounting controls, audit examinations and
financial reporting matters. Price Waterhouse LLP and the
Company's internal auditors have free access to meet individually
with the Audit Committee at any time, without management being
present.
/s/ William E. Davis
William E. Davis
Chairman of the Board and
Chief Executive Officer
Niagara Mohawk Power Corporation
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, 1997 and 1996, and the results of
their operations and their cash flows for each of the three years
in the period ended December 31, 1997, 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") for its nuclear generation,
electric transmission and distribution and gas businesses. In the
event that the Company is unable to complete the termination,
restatement or amendment of independent power producer contracts
and implement PowerChoice, this conclusion could change in 1998 and
beyond, resulting in material adverse effects on the Company's
financial condition and results of operations.
As discussed in Note 2, the Company discontinued application of
SFAS No. 71 for its non-nuclear generation business in 1996.
/s/ Price Waterhouse LLP
Price Waterhouse LLP
Syracuse, New York
March 26, 1998
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
In thousands of dollars
For the year ended
December 31, 1997 1996 1995
- -----------------------------------------------------------------
Operating revenues:
Electric $3,309,441 $3,308,979 $3,335,548
Gas 656,963 681,674 581,790
- -----------------------------------------------------------------
3,966,404 3,990,653 3,917,338
- -----------------------------------------------------------------
Operating expenses:
Fuel for electric
generation 179,455 181,486 165,929
Electricity purchased 1,236,108 1,182,892 1,137,937
Gas purchased 345,610 370,040 276,232
Other operation and
maintenance expenses 835,282 928,224 817,897
Depreciation and
amortization (Note 1) 339,641 329,827 317,831
Other taxes 471,469 475,846 517,478
- -----------------------------------------------------------------
3,407,565 3,468,315 3,233,304
- -----------------------------------------------------------------
Operating income 558,839 522,338 684,034
- -----------------------------------------------------------------
Other Income and
(Deductions):
PowerChoice charge (Note 2) (190,000) - -
Other income (Note 1) 24,997 35,943 3,069
- -----------------------------------------------------------------
(165,003) 35,943 3,069
- -----------------------------------------------------------------
Income before interest
charges 393,836 558,281 687,103
- -----------------------------------------------------------------
Interest charges (Note 1) 273,906 278,033 279,674
- -----------------------------------------------------------------
Income before federal and
foreign income taxes 119,930 280,248 407,429
Federal and foreign income
taxes (Note 7) 60,095 102,494 159,393
- -----------------------------------------------------------------
Income before extraordinary
item 59,835 177,754 248,036
Extraordinary item for the
discontinuance of regulatory
accounting principles, net of
income taxes of $36,273 in
1996 (Note 2) - (67,364) -
- -----------------------------------------------------------------
Net income 59,835 110,390 248,036
Dividends on preferred stock 37,397 38,281 39,596
- -----------------------------------------------------------------
Balance available for
common stock 22,438 72,109 208,440
Dividends on common stock - - 161,650
- -----------------------------------------------------------------
22,438 72,109 46,790
Retained earnings at
beginning of year 657,482 585,373 538,583
- -----------------------------------------------------------------
Retained earnings at
end of year $ 679,920 $ 657,482 $ 585,373
=================================================================
Average number of shares
of common stock outstanding
(in thousands) 144,404 144,350 144,329
Basic and diluted earnings
per average share of common
stock before extraordinary
item $ 0.16 $ 0.97 $ 1.44
Extraordinary item $ - $ (0.47) $ -
- -----------------------------------------------------------------
Basic and diluted earnings
per average share of
common stock $ 0.16 $ 0.50 $ 1.44
Dividends on common stock
paid per share $ - $ - $ 1.12
=================================================================
() Denotes deduction
The accompanying notes are an integral part of these financial
statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
CONSOLIDATED BALANCE SHEETS
In thousands of dollars
At December 31, 1997 1996
- ---------------------------------------------------------
ASSETS
Utility plant (Note 1):
Electric plant $ 8,752,865 $ 8,611,419
Nuclear Fuel 577,409 573,041
Gas plant 1,131,541 1,082,298
Common plant 319,409 292,591
Construction work in progress 294,650 279,992
- ---------------------------------------------------------
Total utility plant 11,075,874 10,839,341
Less: Accumulated
depreciation and
amortization 4,207,830 3,881,726
- ---------------------------------------------------------
Net utility plant 6,868,044 6,957,615
- ---------------------------------------------------------
Other property and
investments 371,709 257,145
- ---------------------------------------------------------
Current assets:
Cash, including temporary
cash investments of $315,708
and $223,829, respectively 378,232 325,398
Accounts receivable (less
allowance for doubtful accounts
of $62,500 and $52,100,
respectively) (Notes 1 and 9) 492,244 373,305
Materials and supplies, at
average cost:
Coal and oil for production
of electricity 27,642 20,788
Gas storage 39,447 43,431
Other 118,308 120,914
Prepaid taxes 15,518 11,976
Other 20,309 25,329
- ---------------------------------------------------------
1,091,700 921,141
- ---------------------------------------------------------
Regulatory assets (Note 2):
Regulatory tax asset 399,119 416,599
Deferred finance charges 239,880 239,880
Deferred environmental
restoration costs (Note 9) 220,000 225,000
Unamortized debt expense 57,312 65,993
Postretirement benefits other
than pensions 56,464 60,482
Other 204,049 206,352
- ---------------------------------------------------------
1,176,824 1,214,306
- ---------------------------------------------------------
Other assets 75,864 77,428
- ---------------------------------------------------------
$9,584,141 $9,427,635
=========================================================
The accompanying notes are an integral part of these financial
statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
CONSOLIDATED BALANCE SHEETS
In thousands of dollars
At December 31, 1997 1996
- ---------------------------------------------------------
CAPITALIZATION AND LIABILITIES
Capitalization (Note 5):
Common stockholders' equity:
Common stock, issued
144,419,351 and 144,365,214
shares, respectively $ 144,419 $ 144,365
Capital stock premium
and expense 1,779,688 1,783,725
Retained earnings 679,920 657,482
- ---------------------------------------------------------
2,604,027 2,585,572
Non-redeemable preferred stock 440,000 440,000
Mandatorily redeemable
preferred stock 76,610 86,730
Long-term debt 3,417,381 3,477,879
- ---------------------------------------------------------
Total capitalization 6,538,018 6,590,181
- ---------------------------------------------------------
Current liabilities:
Long-term debt due within
one year (Note 5) 67,095 48,084
Sinking fund requirements on
redeemable preferred stock
(Note 5) 10,120 8,870
Accounts payable 263,095 271,830
Payable on outstanding bank
checks 23,720 32,008
Customers' deposits 18,372 15,505
Accrued taxes 9,005 4,216
Accrued interest 62,643 63,252
Accrued vacation pay 36,532 36,436
Other 64,756 52,455
- ---------------------------------------------------------
555,338 532,656
- ---------------------------------------------------------
Regulatory liabilities (Note 2):
Deferred finance charges 239,880 239,880
- ---------------------------------------------------------
Other liabilities:
Accumulated deferred income
taxes (Notes 1 and 7) 1,320,532 1,357,518
Employee pension and other
benefits (Note 8) 240,211 238,688
Deferred pension settlement
gain 12,438 19,269
Unbilled revenues (Note 1) 43,281 49,881
Other 414,443 174,562
- ---------------------------------------------------------
2,030,905 1,839,918
- ---------------------------------------------------------
Commitments and contingencies (Notes 2 and 9):
Liability for environmental
restoration 220,000 225,000
- ---------------------------------------------------------
$9,584,141 $9,427,635
=========================================================
The accompanying notes are an integral part of these financial
statements
(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, 1997 1996 1995
- -----------------------------------------------------------------
Cash flows from operating activities:
Net income $ 59,835 $ 110,390 $ 248,036
Adjustments to reconcile
net income to net cash
provided by operating
activities:
Extraordinary item for the
discontinuance of regulatory
accounting principles, net of
income taxes - 67,364 -
PowerChoice charge 190,000 - -
Depreciation and amortization 339,641 329,827 317,831
Electric margin recoverable - - 58,588
Amortization of nuclear fuel 25,241 38,077 34,295
Provision for deferred income
taxes (19,506) (6,870) 114,917
Gain on sale of subsidiary - (15,025) (11,257)
Unbilled revenues (6,600) 21,471 (71,258)
Net accounts receivable (118,939) 121,198 56,748
Materials and supplies (1,306) 2,265 13,663
Accounts payable and accrued
expenses (11,175) 8,224 (47,048)
Accrued interest and taxes 4,180 (11,750) (35,440)
Changes in other assets and
liabilities 76,204 35,231 20,930
- -----------------------------------------------------------------
Net cash provided by
operating activities 537,575 700,402 700,005
- -----------------------------------------------------------------
Cash flows from investing activities:
Construction additions (286,389) (296,689) (332,443)
Nuclear fuel (4,368) (55,360) (13,361)
Less: Allowance for other
funds used during construction 5,310 3,665 1,063
- -----------------------------------------------------------------
Acquisition of utility plant (285,447) (348,384) (344,741)
Decrease in materials and
Materials and supplies related
ton construction 1,042 8,362 3,346
Accounts payable and accrued
expenses related to
construction (2,794) 2,056 (7,112)
Other investments (115,533) 541 (115,818)
Proceeds from sale of sub-
sidiary (net of cash sold) - 14,600 161,087
Other 8,761 (8,786) 26,234
- -----------------------------------------------------------------
Net cash used in investing
activities (393,971) (331,611) (277,004)
- -----------------------------------------------------------------
Cash flows from financing activities:
Proceeds from long-term debt - 105,000 346,000
Redemption of preferred stock (8,870) (10,400) (10,950)
Reductions of long-term debt (44,600) (244,341) (73,415)
Net change in short-term debt - - (416,750)
Dividends paid (37,397) (38,281) (201,246)
Other 97 (8,846) (7,495)
- -----------------------------------------------------------------
Net cash used in financing
activities (90,770) (196,868) (363,856)
- -----------------------------------------------------------------
Net increase in cash 52,834 171,923 59,145
Cash at beginning of year 325,398 153,475 94,330
- -----------------------------------------------------------------
Cash at end of year $ 378,232 $ 325,398 $ 153,475
=================================================================
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest $ 279,957 $ 286,497 $ 290,352
Income taxes $ 82,331 $ 95,632 $ 47,378
=================================================================
The accompanying notes are an integral part of these financial
statements
/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, including the accounting
principles for rate-regulated entities with respect to the
Company's nuclear, transmission, distribution and gas operations
(regulated business), and are in accordance with the accounting
requirements and ratemaking practices of the regulatory
authorities. The Company discontinued the application of
regulatory accounting principles to its fossil and hydro generation
operations in 1996 (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
replacements of retirement units of property are 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. The
discontinuation of SFAS No. 71 did not affect the carrying value of
the Company's utility plant.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION: The Company
capitalizes AFC in amounts equivalent to the cost of funds devoted
to plant under construction for its regulated business. AFC rates
are determined in accordance with FERC and PSC regulations. The
AFC rate in effect during 1997 was 9.28%. AFC is segregated into
its two components, borrowed funds and other funds, and is
reflected in the "Interest charges" and the "Other income"
sections, respectively, of the Consolidated Statements of Income.
The amount of AFC credits recorded in each of the three years ended
December 31, in thousands of dollars, was as follows:
1997 1996 1995
---- ---- ----
Other income $5,310 $3,665 $1,063
Interest charges 4,396 3,690 7,987
As a result of the discontinued application of SFAS No. 71 to
the fossil and hydro operations, the Company capitalizes interest
cost associated with the construction of fossil/hydro assets.
DEPRECIATION, AMORTIZATION AND NUCLEAR GENERATING PLANT
DECOMMISSIONING COSTS: For accounting and regulatory purposes,
depreciation is computed on the straight-line basis using the
license 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 approximately 3%
for the years 1995 through 1997. The Company performs depreciation
studies to determine service lives of classes of property and
adjusts the depreciation 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 the Units components promptly at
that time. See Note 3 - "Nuclear Plant Decommissioning."
The FASB issued an exposure draft in February 1996 entitled
"Accounting for Certain Liabilities Related to Closure or Removal
Costs of Long-Lived Assets." The scope of the project includes
certain plant decommissioning costs, including those for fossil,
hydro and nuclear plants. If approved, a liability would be
recognized, with a corresponding plant asset, whenever a legal or
constructive obligation exists to perform dismantlement or removal
activities. The Company currently recognizes the liability for
nuclear decommissioning over the service life of the plant as an
increase to accumulated depreciation and does not recognize the
closure or removal obligation associated with its fossil and hydro
plants. The Company's PowerChoice agreement provides for the
recovery of nuclear decommissioning costs. As discussed in Note 2,
the Company intends to sell its fossil and hydro generating assets
through an auction process. To the extent the assets are sold, the
effect of this exposure draft on the Company should be mitigated.
However, the Company cannot predict the results of the auction.
The adoption of the proposed standard is not expected to impact the
cash flow from these assets. The FASB continues to discuss the
issues addressed in the exposure draft, as well as the timing of
its implementation.
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 KWh of net generation available for sale, is
based upon a contract with the DOE. 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 for energy consumed
and not billed at the end of the fiscal year. At December 31, 1997
and 1996, approximately $8.6 million and $11.1 million,
respectively, of unbilled electric revenues remained unrecognized
in results of operations, are included in "Other liabilities."
Under the Company's PowerChoice agreement, the amount of
unrecognized electric unbilled revenue as of the PowerChoice
implementation date will be netted against certain other regulatory
assets and liabilities. Thereafter, changes in electric unbilled
revenues will no longer be deferred. In 1995, the Company used
$71.5 million of electric unbilled revenues to reduce the 1995
revenue requirement. At December 31, 1997 and 1996, $34.7 million
and $38.8 million, respectively, of unbilled gas revenues remain
unrecognized in results of operations and may be used to reduce
future gas revenue requirements. The unbilled revenues included in
accounts receivable at December 31, 1997 and 1996, were $211.9
million and $218.5 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 1995
through 1997 were not material. Under the PowerChoice agreement,
the FAC will be discontinued.
In December 1996, the Company, Multiple Intervenors and the
PSC staff reached a three year gas settlement that was
conditionally approved by the PSC. The agreement eliminated the
gas adjustment clause and established a gas commodity cost
adjustment clause ("CCAC"). The Company's gas CCAC provides for
the collection or passback of certain increases or decreases from
the base commodity cost of gas. The maximum annual risk or benefit
to the Company is $2.25 million. All savings and excess costs
beyond that amount will flow to ratepayers. For a discussion of
the ratemaking associated with non-commodity gas costs, see Item 7.
Management's Discussion and Analysis of Financial Condition and
Results of Operations - "Other Federal and State Regulatory
Initiatives - Multi-Year Gas Rate Settlement Agreement."
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 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.
EARNINGS PER SHARE: Basic earnings per share ("EPS") is
computed based on the weighted average number of common shares
outstanding for the period. The number of options outstanding at
December 31, 1997, 1996 and 1995 that could potentially dilute
basic EPS, (but are considered antidilutive for each period because
the options exercise price was greater than the average market
price of common shares), is immaterial. Therefore, the calculation
of both basic and dilutive EPS are the same for each period.
RECLASSIFICATIONS: Certain amounts from prior years have been
reclassified on the accompanying Consolidated Financial Statements
to conform with the 1997 presentation.
COMPREHENSIVE INCOME: In June 1997, FASB issued SFAS No. 130.
SFAS No. 130 establishes standards for reporting comprehensive
income. Comprehensive income is the change in the equity of a
company, not including those changes that result from shareholder
transactions. All components of comprehensive income are required
to be reported in a new financial statement that is displayed with
equal prominence as existing financial statements. The Company
will be required to adopt SFAS No. 130 on January 1, 1998. The
Company does not expect that adoption of SFAS No. 130 will have a
significant impact on its reporting and disclosure requirements.
SEGMENT DISCLOSURES: Also in June 1997, FASB issued SFAS No.
131. SFAS No. 131 establishes standards for additional disclosure
about operating segments for interim and annual financial
statements. More specifically, it requires financial information
to be disclosed for segments whose operating results are reviewed
by the chief operating officer for decisions on resource
allocation. It also requires related disclosures about product and
services, geographic areas and major customers. The Company will
be required to adopt SFAS No. 131 for the fiscal year ending
December 31, 1998. The Company does not expect that the adoption
of SFAS No. 131 will have a significant impact on its reporting and
disclosure requirements.
PENSION AND OTHER POSTRETIREMENT BENEFITS: In February 1998,
FASB issued SFAS No. 132. SFAS No. 132 revises employers'
disclosures about pension and other postretirement benefit plans.
It does not change the measurement or recognition of those plans.
It standardizes the disclosure requirements for pensions and other
postretirement benefits to the extent practicable and requires
additional information on changes in the benefit obligations and
fair values of plan assets. The Company will be required to adopt
SFAS No. 132 for the fiscal year ending December 31, 1998. The
Company does not expect the adoption of SFAS No. 132 will have a
significant impact on its reporting and disclosure requirements.
NOTE 2. RATE AND REGULATORY ISSUES AND CONTINGENCIES
The Company's financial statements conform to GAAP, including
the accounting principles for rate-regulated entities with respect
to its regulated operations. Substantively, these principles
permit a public utility, regulated on a cost-of-service basis, to
defer certain costs which would otherwise be charged to expense,
when authorized to do so by the regulator. These deferred costs
are known as regulatory assets, which in the case of the Company
are approximately $937 million, net of approximately $240 million
of regulatory liabilities at December 31, 1997. These regulatory
assets are probable of recovery. The portion of the $937 million
which has been allocated to the nuclear generation and electric
transmission and distribution business is approximately $810
million, which is net of approximately $240 million of regulatory
liabilities. Regulatory assets allocated to the rate-regulated gas
distribution business are $127 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 are consistent
with those used in prior regulatory proceedings.
The Company concluded as of December 31, 1996 that the
termination, restatement or amendment of IPP contracts and
implementation of PowerChoice was the probable outcome of
negotiations that had taken place since the PowerChoice
announcement. Under PowerChoice, the separated non-nuclear
generation business would no longer be rate-regulated on a cost-of-
service basis and, accordingly, regulatory assets related to the
non-nuclear power generation business, amounting to approximately
$103.6 million ($67.4 million after tax or 47 cents per share) was
charged against 1996 income as an extraordinary non-cash charge.
The PSC in its written order issued March 20, 1998 approving
PowerChoice, determined to limit the estimated value of the MRA
regulatory asset that can be recovered from customers to
approximately $4,000 million. The ultimate amount of the
regulatory asset to be established may vary based on certain events
related to the closing of the MRA. The estimated value of the MRA
regulatory asset includes the issuance of 42.9 million shares of
common stock, which the PSC in determining the recoverable amount
of such asset, valued at $8 per share. Because the value of the
consideration to be paid to the IPP Parties can only be determined
at the MRA closing, the value of the limitation on the
recoverability of the MRA regulatory asset has been estimated at
$190 million (85 cents per share) which has been charged to 1997
earnings. The charge to expense was determined as the difference
between $8 per share and the Company's closing common stock price
on March 26, 1998 of $12 7/16 per share, multiplied by 42.9 million
shares. Any variance from the estimate used in determining the
charge to expense in 1997, including changes to the common stock
price at closing, will be reflected in results of operations in
1998.
Under PowerChoice, the Company's remaining electric business
(nuclear generation and electric transmission and distribution
business) will continue to be rate-regulated on a cost-of-service
basis and, accordingly, the Company continues to apply SFAS No. 71
to these businesses. Also, the Company's IPP contracts, including
those restructured under the MRA and those not so restructured will
continue to be the obligations of the regulated business.
SFAS No. 71 does not require the Company to earn a return on
the regulatory assets in assessing its applicability. The Company
believes that the prices it will charge for electric service over
10 years, including the CTC, assuming no reduction in demand or
bypass of the CTC or exit fees, will be sufficient to recover the
MRA regulatory asset and to provide recovery of and a return on the
remainder of its assets, as appropriate. In the event the Company
could no longer apply SFAS No. 71 in the future, it would be
required to record an after-tax non-cash charge against income for
any remaining unamortized regulatory assets and liabilities.
Depending on when SFAS No. 71 was required to be discontinued, such
charge would likely be material to the Company's reported financial
condition and results of operations and the Company's ability to
pay dividends. The PowerChoice agreement, while having the effect
of substantially depressing earnings during its five-year term,
will substantially improve operating cash flows.
The EITF of the FASB reached a consensus on Issue No. 97-4
"Deregulation of the Pricing of Electricity - Issues Related to the
Application of SFAS No. 71 and SFAS No. 101" in July 1997. As
discussed previously, the Company discontinued the application of
SFAS No. 71 and applied SFAS No. 101 with respect to the fossil and
hydro generation business at December 31, 1996, in a manner
consistent with the EITF consensus.
With the implementation of PowerChoice, specifically the
separation of non-nuclear generation as an entity that would no
longer be cost-of-service regulated, the Company is required to
assess the carrying amounts of its long-lived assets in accordance
with SFAS No. 121. SFAS No. 121 requires long-lived assets and
certain identifiable intangibles held and used by an entity to be
reviewed for impairment whenever events or changes in circumstances
indicate that the carrying amount of an asset may not be
recoverable or when assets are to be disposed of. 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/or its disposition. The Company has determined that
there is no impairment of its fossil and hydro generating assets.
To the extent the proceeds resulting from the sale of the fossil
and hydro assets are not sufficient to avoid a loss, the Company
would be able to recover such loss through the CTC. The
PowerChoice agreement provides for deferral and future recovery of
losses, if any, resulting from the sale of the non-nuclear
generating assets. The Company's fossil and hydro generation plant
assets had a net book value of approximately $1.1 billion at
December 31, 1997.
As described in Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations - "Master
Restructuring Agreement and the PowerChoice Agreement," the
conclusion of the termination, restatement or amendment of IPP
contracts, and closing of the financing necessary to implement such
termination, restatement or amendment, as well as implementation of
PowerChoice, is subject to a number of contingencies. In the event
the Company is unable to successfully bring these events to
conclusion, it is likely that application of SFAS No. 71 would be
discontinued. The resulting non-cash after-tax charges against
income, based on regulatory assets and liabilities associated with
the nuclear generation and electric transmission and distribution
businesses as of December 31, 1997, would be approximately $526.5
million or $3.65 per share. Various requirements under applicable
law and regulations and under corporate instruments, including
those with respect to issuance of debt and equity securities,
payment of common and preferred dividends and certain types of
transfers of assets could be adversely impacted by any such write-
downs.
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. PowerChoice provides for netting,
and thereby elimination of the debit and credit balances of
deferred finance charges.
DEFERRED ENVIRONMENTAL RESTORATION COSTS represent the
Company's share of the estimated costs to investigate and perform
certain remediation activities at both Company-owned sites and non-
owned sites with which it may be associated. The Company has
recorded a regulatory asset representing the remediation
obligations to be recovered from ratepayers. PowerChoice and the
Company's gas settlement provide for the recovery of these costs
over the settlement periods. The Company believes future costs,
beyond the settlement periods, will continue to be recovered in
rates. 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.
Substantially all of the Company's regulatory assets described
above are being amortized to expense and recovered in rates over
periods approved in the Company's electric and gas rate cases,
respectively.
NOTE 3. NUCLEAR OPERATIONS
NUCLEAR PLANT DECOMMISSIONING: The Company's site specific
cost estimates for decommissioning Unit 1 and its ownership
interest in Unit 2 at December 31, 1997 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 January 1998 dollars) In millions of dollars
Radioactive Components $481 $201
Non-radioactive Components 117 48
Fuel Dry Storage/Continuing
Care 78 43
---- ----
$676 $292
==== ====
The Company estimates that by the time decommissioning is
completed, the above costs will ultimately amount to $1.7 billion
and $.9 billion for Unit 1 and Unit 2, respectively, using
approximately 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 1998 dollars, these costs are expected to
amount to $119 million and $63 million for Unit 1 and the Company's
share of Unit 2, respectively. The amounts will escalate to $210
million and $190 million for Unit 1 and the Company's share of Unit
2, respectively, by the time decommissioning is completed. In
1997, the Company made adjustments to the cash flow assumptions at
Unit 1 for fuel dry storage, radioactive cost components, property
tax and insurance, to more accurately reflect the estimated cost of
each cost component. The revisions reduced the total cost estimate
by approximately $10 million (in 1998 dollars).
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 was approximately $23.7 million, for
each of the three years ended December 31, 1997. The amount was
based upon the 1993 NRC minimum decommissioning cost requirements
of $437 million and $198 million (in 1998 dollars) for Unit 1 and
the Company's share of Unit 2, respectively. In Opinion No. 95-21,
the Company was authorized, until the PSC orders otherwise, to
continue to fund to the NRC minimum requirements. PowerChoice
permits rate recovery for all radioactive and non-radioactive cost
components for both units, including post-shutdown costs, based
upon the amounts estimated in the 1995 site specific studies
described above, which are higher than the NRC minimum. 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.
Decommissioning costs recovered in rates are reflected in
"Accumulated depreciation and amortization" on the balance sheet
and amount to $266.8 million and $217.7 million at December 31,
1997 and 1996, respectively for both units. Additionally at
December 31, 1997, the fair value of funds accumulated in the
Company's external trusts were $164.7 million for Unit 1 and $51.0
million for its share of Unit 2. The trusts are included in "Other
property and investments." Earnings on the external trust
aggregated $40.3 million through December 31, 1997 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 $45.2
million at December 31, 1997.
NRC POLICY STATEMENT AND PROPOSAL. The NRC issued a policy
statement on the Restructuring and Economic Deregulation of the
Electric Utility Industry (the "Policy Statement") in 1997. The
Policy Statement addresses the NRC's concerns about the adequacy of
decommissioning funds and about the potential impact on operational
safety. Current NRC regulations allow a utility to set aside
decommissioning funds annually over the estimated life of a plant.
The Policy Statement declares the NRC will:
- - Continue to conduct reviews of financial qualifications,
decommissioning funding and antitrust requirements of nuclear
power plants;
- - Establish and maintain working relationships with state and
federal rate regulators;
- - Identify all nuclear power plant owners, indirect as well as
direct; and
- - Re-evaluate the adequacy of current regulations in light of
economic and other changes resulting from rate deregulation.
In addition to the above Policy Statement, the NRC is proposing to
amend its regulations on decommissioning funding to reflect
conditions expected from deregulation of the electric power
industry. The amended rule would:
- - Revise the definition of an "electric utility" to reflect
changes caused by restructuring within the industry.
- - Define a "Federal licensee" as any licensee which has the full
faith and credit backing of the United States government.
Only such licensees could use statements of intent to meet
decommissioning financial assurance requirements for power
reactors.
- - Require nuclear power plant licensees to report to the NRC on
the status of their decommissioning funds at least once every
three years and annually within five years of the planned end
of operation. NRC's present rule contains no such requirement
because State and Federal rate-regulating bodies actively
monitor these funds. A deregulated nuclear utility would have
no such monitoring.
- - Permit nuclear licensees to take credit on earnings for
prepaid decommissioning trust funds and external sinking funds
from the time the funds are set aside through the end of the
decommissioning period. The present rule does not permit such
credit because it assumed that inflation and taxes would erode
any investment return. NRC has decided, however, that this
position is not borne out by historical performance of
inflation-adjusted funds invested in U.S. Treasury
instruments.
The Company is unable to predict the outcome of this matter.
PSC STAFF'S TENTATIVE CONCLUSIONS ON THE FUTURE OF NUCLEAR
GENERATION: On August 27, 1997, the PSC requested comments on its
staff's tentative conclusions about how nuclear generation and
fossil generation should be treated after decisions are made on the
individual electric restructuring agreements currently pending
before the PSC. The PSC staff concluded that beyond the transition
period (the period covered by the various New York utility
restructuring agreements, including PowerChoice), nuclear
generation should operate on a competitive basis. In addition, the
PSC staff concluded that a sale of generation plants to third
parties is the preferred means of determining the fair market value
of generation plants and offers the greatest potential for the
mitigation of stranded costs. The PSC staff also concluded that
recovery of sunk costs, including post shutdown costs, would be
subject to review by the PSC and this process should take into
account mitigation measures taken by the utility, including the
steps it has taken to encourage competition in its service area.
In October 1997, the majority of utilities with interests in
nuclear power plants, including the Company, requested that the PSC
reconsider its staff's nuclear proposal. In addition, the utilities
raised the following issues: impediments to nuclear plants
operating in a competitive mode; impediments to the sale of plants;
responsibility for decommissioning and disposal of spent fuel;
safety and health concerns; and environmental and fuel diversity
benefits. In light of all of these issues, the utilities
recommended that a more formal process be developed to address
those issues.
The three investor-owned utilities, Rochester Gas and Electric
Corporation, Consolidated Edison Company of New York, Inc. and the
Company, which are currently pursuing formation of a nuclear
operating company in New York State, also filed a response with the
PSC in October 1997. The response stated that a forced divestiture
of the nuclear plants would add uncertainty to developing a
statewide approach to operating the plants and requested that such
a forced divestiture proposal be rescinded. The response also
stated that implementation of a consolidated six-unit operation
would contribute to the mitigation of unrecovered nuclear costs.
NYPA, which is also pursuing formation of the nuclear operating
company, submitted its own comments which were similar to the
comments of the three utilities.
PowerChoice contemplates that the Company's nuclear plants
will remain part of the Company's regulated business and that the
Company will continue efforts to pursue a statewide solution such
as the New York Nuclear Operating Company. The settlement
stipulates that absent a statewide solution, the Company will file
a detailed plan for analyzing proposed solutions for its nuclear
assets, including the feasibility of an auction, transfer and/or
divestiture within 24 months of PowerChoice approval. At December
31, 1997, the net book value of the Company's nuclear assets was
approximately $1.5 billion, excluding the reserve for
decommissioning.
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.
With respect to a nuclear incident at a licensed reactor, the
statutory limit for the protection of the public under the Price-
Anderson Amendments Act of 1988 which is in excess of the $200
million of nuclear liability insurance, is currently $8.2 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. With the 5%
surcharge included, the statutory limit is $8.6 billion.
The Company's interest in Units 1 and 2 could expose it to a
maximum potential loss, for each accident, of $111.8 million (with
5% assessment) 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 $2.25
billion 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 also provides
insurance coverage against the extra expense incurred in purchasing
replacement power during prolonged accidental outages. The
insurance provides coverage for outages for 156 weeks, after a 21-
week waiting period. NEIL insurance is subject to retrospective
premium adjustment under which the Company could be assessed up to
approximately $11.3 million per loss.
LOW LEVEL RADIOACTIVE WASTE: The Company currently uses the
Barnwell, South Carolina waste disposal facility for low level
radioactive waste; however, continued access to Barnwell is not
assured and the Company 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.
Under the Federal Low Level Waste Policy Amendment Act of
1985, New York State was required by January 1, 1993 to have
arranged for the disposal of all low level radioactive waste within
the state or in the alternative, contracted for the disposal at a
facility outside the state. To date, New York State has made no
funding available to support siting for a disposal facility.
NUCLEAR FUEL DISPOSAL COST: In January 1983, the Nuclear
Waste Policy Act of 1982 (the "Nuclear Waste Act") established a
cost of $.001 per KWh of net generation for current disposal of
nuclear fuel and provides for a determination of the Company's
liability to the 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. As of December 31, 1997, the Company has
recorded a liability of $114.3 million for the disposal of nuclear
fuel irradiated prior to 1983. 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.
However, in July 1996, the United States Circuit Court of Appeals
for the District of Columbia ruled that the DOE must begin
accepting spent fuel from the nuclear industry by January 31, 1998
even though a permanent storage site will not be ready by then. The
DOE did not appeal this decision. On January 31, 1997, the Company
joined a number of other utilities, states, state agencies and
regulatory commissions in filing a suit in the U.S. Court of
Appeals for the District of Columbia against the DOE. The suit
requested the court to suspend the utilities payments into the
Nuclear Waste Fund and to place future payments into an escrow
account until the DOE fulfills its obligation to accept spent fuel.
On June 3, 1997, the DOE notified utilities that it likely will not
meet its January 31, 1998 deadline and that the delay was
unavoidable pursuant to the terms of the standard contract with DOE
for fuel disposal. DOE also indicated it was not obligated to
provide a financial remedy for such unavoidable delay. On November
14, 1997 the United States Court of Appeals for the District of
Columbia Circuit issued a writ of mandamus precluding DOE from
excusing its own delay on the grounds that it has not yet prepared
a permanent repository or interim storage facility. On December
11, 1997, 27 utilities, including the Company, petitioned the DOE
to suspend their future payments to the Nuclear Waste Fund until
the DOE begins moving fuel from their plant sites. The petition
further sought permission to escrow payments to the waste fund
beginning in February 1998. On January 12, 1998, the DOE denied
the petition. The Company is unable to determine the final outcome
of this matter.
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, 1997. 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.
Under PowerChoice, the Company will divest all of its fossil and hydro generation assets with
a net book value of $1.1 billion, including its interests in jointly-owned facilities.
In thousands of dollars
-----------------------------------------------
Percent Utility Accumulated Construction
Ownership Plant Depreciation Work in Progress
- ------------------------------------------------------------------------------------------
Roseton Steam Station
Units No. 1 and 2 (a) 25 $ 96,110 $ 54,130 $ 432
Oswego Steam Station
Unit No. 6 (b) 76 $ 270,316 $125,089 $ 39
Nine Mile Point Nuclear
Station Unit No. 2 (c) 41 $1,507,721 $327,006 $6,748
- ------------------------------------------------------------------------------------------
(a) The remaining ownership interests are Central Hudson Gas and Electric Corporation
("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 Rochester Gas and
Electric ("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 Long Island Lighting
Company ("LILCO") (18%), New York State Electric & Gas Corporation ("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.
In June 1997, LILCO and Long Island Power Authority ("LIPA") entered into an agreement,
whereby, upon completion of certain transactions, LILCO's stock would be sold to LIPA.
It is anticipated that LIPA would own LILCO's 18% ownership interest in Unit 2. In July
1997, the New York State Public Authorities Control Board unanimously approved the
agreements related to the LIPA transaction, subject to certain conditions, and LILCO's
stockholders subsequently approved this transaction.
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 1995, 1996 and
1997:
COMMON STOCK
$1 PAR VALUE
--------------------------
SHARES AMOUNT*
- --------------------------------------------------------
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
Issued 33,091 33
Redemptions
Foreign currency
translation adjustment
- --------------------------------------------------------
December 31, 1996: 144,365,214 144,365
Issued 54,137 54
Redemptions
Foreign currency
translation adjustment
- --------------------------------------------------------
December 31, 1997: 144,419,351 $144,419
========================================================
* In thousands of dollars
/TABLE
PREFERRED STOCK
$100 PAR VALUE
---------------------------------------
SHARES NON-REDEEMABLE* REDEEMABLE*
- --------------------------------------------------------------
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)
Issued - - -
Redemptions (18,000) - (1,800)
Foreign currency
translation adjustment
- --------------------------------------------------------------
December 31, 1996: 2,340,000 $210,000 $24,000 (a)
Issued - - -
Redemptions (18,000) - (1,800)
Foreign currency
translation adjustment
- --------------------------------------------------------------
December 31, 1997: 2,322,000 $210,000 $22,200 (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, 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
Issued - - - 214
Redemptions (344,000) - (8,600) (28)
Foreign currency
translation adjustment (708)
- ----------------------------------------------------------------------------
December 31, 1996: 12,064,005 $230,000 $71,600 (a) $1,783,725
Issued - - - 426
Redemptions (282,801) - (7,070) 104
Foreign currency
translation adjustment (4,567)
- ----------------------------------------------------------------------------
December 31, 1997: 11,781,204 $230,000 $64,530 (a) $1,779,688
============================================================================
* In thousands of dollars
(a) Includes sinking fund requirements due within one year.
The cumulative amount of foreign currency translation adjustment at December 31, 1997 was
$(15,448).
NON-REDEEMABLE PREFERRED STOCK (Optionally Redeemable)
The Company had 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 1997 1996 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:
9.50% 6,000,000 150,000 150,000 25.00 (a)
Adjustable Rate -
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 had 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 1998
through 2002 are as follows: $10,120; $7,620; $7,620; $7,620 and $3,050, respectively. The
aggregate preference of preferred shares upon involuntary liquidation of the Company is the
aggregate par value of such shares, plus an amount equal to the dividends accumulated and
unpaid on such shares to the date of payment whether or not earned or declared.
- ---------------------------------------------------------------------------------
Redemption price per
share (Before adding
Shares In thousands of dollars accumulated dividends)
Eventual
Series 1997 1996 1997 1996 1997 Minimum
- ---------------------------------------------------------------------------------
Preferred $100 par value:
7.45% 222,000 240,000 $ 22,200 $ 24,000 $101.69 $100.00
Preferred $25 par value:
7.85% 731,204 914,005 18,280 22,850 25.28 25.00
8.375% 100,000 200,000 2,500 5,000 25.00 25.00
Adjustable Rate-
Series B 1,750,000 1,750,000 43,750 43,750 25.00 25.00
- ---------------------------------------------------------------------------------
86,730 95,600
Less sinking fund requirements 10,120 8,870
- ---------------------------------------------------------------------------------
$ 76,610 $ 86,730
=================================================================================
LONG-TERM DEBT
Long-term debt at December 31 consisted of the following:
- -------------------------------------------------------------
In thousands of dollars
-----------------------
SERIES DUE 1997 1996
- -------------------------------------------------------------
First mortgage bonds:
6 1/4% 1997 $ - $ 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 275,000 275,000
*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 2,801,305 2,841,305
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
Term Loan Agreement 105,000 105,000
Unsecured notes payable:
Medium Term Notes, Various rates,
due 2000-2004 20,000 20,000
Other 154,295 156,606
Unamortized premium (discount) (9,884) (10,708)
- --------------------------------------------------------------
TOTAL LONG-TERM DEBT 3,484,476 3,525,963
Less long-term debt due
within one year 67,095 48,084
- --------------------------------------------------------------
$3,417,381 $3,477,879
==============================================================
*Tax-exempt pollution control related issues
Several series of First Mortgage Bonds and Promissory 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 3.63% for 1997 and 3.46% for 1996
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 1997 consists of obligations under
capital leases of approximately $29.7 million, a liability to the
DOE for nuclear fuel disposal of approximately $114.3 million and
a liability for IPP contract terminations of approximately $10.3
million. The aggregate maturities of long-term debt for the five
years subsequent to December 31, 1997, excluding capital leases, in
millions, are approximately $64, $108, $158, $310 and $230
respectively. The Company's aggregate maturities will increase
significantly upon closing of the MRA. See Item 7. Management's
Discussion and Analysis of Financial Condition and Results of
Operations - "Master Restructuring Agreement and the PowerChoice
Agreement."
NOTE 6. BANK CREDIT ARRANGEMENTS
The Company has an $804 million senior debt facility with a
bank group consisting of a $255 million term loan facility, a $125
million revolving credit facility and $424 million for letters of
credit. The letter of credit facility provides credit support for
the adjustable rate pollution control revenue bonds issued through
the NYSERDA discussed in Note 5. As of December 31, 1997, the
amount outstanding under the senior debt facility was $529 million,
consisting of $105 million under the term loan facility and a $424
million letter of credit, leaving the Company with $275 million of
borrowing capability under the facility. The facility expires on
June 30, 1999 (subject to earlier termination if the Company
separates its fossil/hydro generation business from its
transmission and distribution business, or any other significant
restructuring plan). The interest rate applicable to the facility
is variable based on certain rate options available under the
agreement and currently approximates 7.7% (but capped at 15%). The
Company is currently negotiating with the lenders to replace the
senior debt facility with a larger facility to finance part of the
MRA. The Company did not have any short-term debt outstanding at
December 31, 1997 and 1996.
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
1997 1996 1995
- ---------------------------------------------------------------
United States $125,027 $269,128 $400,087
Foreign (1,621) 28,522 17,609
Consolidating eliminations (3,476) (17,402) (10,267)
- ---------------------------------------------------------------
Income before extraordinary
item and income taxes $119,930 $280,248 $407,429
===============================================================
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:
In thousands of dollars
1997 1996* 1995
- --------------------------------------------------------------
Components of Federal and foreign income taxes:
Current tax expense:
Federal $ 77,565 $ 96,011 $ 67,366
Foreign - 3,708 3,900
- ---------------------------------------------------------------
77,565 99,719 71,266
- ---------------------------------------------------------------
Deferred tax expense:
Federal (18,664) 382 84,002
Foreign 1,194 2,393 4,125
- ---------------------------------------------------------------
(17,470) 2,775 88,127
- ---------------------------------------------------------------
Total $ 60,095 $102,494 $159,393
===============================================================
Reconciliation between Federal and foreign income taxes and the tax
computed at prevailing U.S. statutory rate on income before income
taxes:
Computed tax $ 41,975 $ 98,087 $142,601
- ---------------------------------------------------------------
Increase (reduction) attributable to flow-through of certain tax
adjustments:
Depreciation 36,411 28,103 31,033
Cost of removal (8,168) (8,849) (9,247)
Deferred investment tax
credit amortization (7,454) (8,018) (8,589)
Other (2,669) (6,829) 3,595
- ---------------------------------------------------------------
18,120 4,407 16,792
- ---------------------------------------------------------------
Federal and foreign
income taxes $ 60,095 $102,494 $159,393
===============================================================
* Does not include the deferred tax benefit of $36,273 in 1996
associated with the extraordinary item for the discontinuance of
regulatory accounting principles.
At December 31, the deferred tax liabilities (assets) were
comprised of the following:
In thousands of dollars
1997 1996
---- ----
PowerChoice charge $ (66,500) $ -
Alternative minimum tax (17,448) (64,313)
Unbilled revenue (88,859) (83,577)
Other (247,438) (237,850)
---------- ----------
Total deferred tax assets (420,245) (385,740)
---------- ----------
Depreciation related 1,358,827 1,421,550
Investment tax credit related 79,858 84,294
Other 302,092 237,414
---------- ----------
Total deferred tax
liabilities 1,740,777 1,743,258
---------- ----------
Accumulated deferred income
taxes $1,320,532 $1,357,518
=========== ===========
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.
Net pension cost for 1997, 1996 and 1995 included the
following components:
- -----------------------------------------------------------------
In thousands of dollars
-----------------------
1997 1996 1995
- -----------------------------------------------------------------
Service cost - benefits
earned during the period $ 27,100 $ 25,000 $ 22,500
Interest cost on projected
benefit obligation 75,200 71,700 73,000
Actual return on plan assets (188,200) (134,100) (215,600)
Net amortization and deferral 100,400 55,700 140,300
- -----------------------------------------------------------------
Total pension cost (1) $ 14,500 $ 18,300 $ 20,200
=================================================================
(1) $3.2 million for 1997, $3.8 million for 1996, and $4.1 million
for 1995 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, 1997 1996
- --------------------------------------------------------------
Actuarial present value of
accumulated benefit obligations:
Vested benefits $ 990,415 $803,202
Non-vested benefits 73,430 83,107
- --------------------------------------------------------------
Accumulated benefit obligations 1,063,845 886,309
Additional amounts related to
projected pay increases 108,583 141,472
- --------------------------------------------------------------
Projected benefits obligation for
service rendered to date 1,172,428 1,027,781
Plan assets at fair value, consisting
primarily of listed stocks, bonds,
other fixed income obligations
and insurance contracts (1,304,338) (1,159,822)
- --------------------------------------------------------------
Plan assets in excess of
projected benefit obligations (131,910) (132,041)
Unrecognized net obligation at
January 1, 1987 being recognized
over approximately 19 years (19,446) (22,005)
Unrecognized net gain from actual
return on plan assets different
from that assumed 265,100 219,680
Unrecognized net gain from past
experience different from that
assumed and effects of changes
in assumptions amortized over 10
years 19,920 66,129
Prior service cost not yet recognized
in net periodic pension cost (50,473) (49,651)
- ---------------------------------------------------------------
Pension liability included
in the consolidated balance sheets $ 83,191 $ 82,112
===============================================================
Principle Actuarial Assumptions (%):
Discount Rate 7.00 7.50
Rate of increase in future
compensation levels (plus
merit increases) 2.50 2.50
Long-term rate of return on
plan assets 9.25 9.25
===============================================================
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 comply with SFAS No.
106. The Company has established various trusts to fund its future
postretirement benefit obligation. In 1997, 1996 and 1995, the
Company made contributions to such trusts of approximately $13.5
million, $28.5 million and $53.1 million, respectively, which
represent the amount received in rates and from cotenants.
Net postretirement benefit cost for 1997, 1996 and 1995
included the following components:
- -----------------------------------------------------------------
In thousands of dollars
----------------------------
1997 1996 1995
- -----------------------------------------------------------------
Service cost - benefits attributed
to service during the period $12,300 $12,900 $12,600
Interest cost on accumulated
benefit obligation 34,800 37,500 45,400
Actual return on plan assets (24,500) (12,900) (11,200)
Amortization of the transition
obligation over 20 years 10,900 13,500 18,800
Net amortization 9,500 6,000 14,600
- -----------------------------------------------------------------
Total postretirement benefit cost $43,000 $57,000 $80,200
=================================================================
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, 1997 1996
- -----------------------------------------------------------
Actuarial present value of accumulated benefit obligations:
Retired and surviving spouses $392,832 $370,259
Active eligible 43,299 31,030
Active ineligible 83,720 69,441
- ------------------------------------------------------------
Accumulated benefit obligation 519,851 470,730
Plan assets at fair value,
consisting primarily of
listed stocks, bonds and
other fixed obligations (181,101) (143,071)
- -----------------------------------------------------------
Accumulated postretirement
benefit obligation in excess
of plan assets 338,750 327,659
Unrecognized net loss from
past experience different from
that assumed and effects of
changes in assumptions (48,466) (36,048)
Prior service cost not yet
recognized in postretirement
benefit cost 30,086 39,205
Unrecognized transition obligation
being amortized over 20 years (163,350) (174,240)
- -----------------------------------------------------------
Accrued postretirement benefit
liability included in the
consolidated balance sheet $157,020 $156,576
===========================================================
===========================================================
Principal actuarial assumptions (%):
Discount rate 7.00 7.50
Long-term rate of return
on plan assets 9.25 8.00
Health care cost trend rate:
Pre-65 7.00 8.00
Post-65 6.00 6.50
===========================================================
During 1996, the Company changed the eligibility requirements
for plan benefits for employees who retire after May 1, 1996.
Generally, plan benefits are now accrued for eligible participants
beginning after age 45. Previous to this change, the Company
accrued these benefits over the employees' service life. The
effect of this change resulted in a decrease in the accumulated
benefit obligation for active ineligible employees.
At December 31, 1997, the assumed health cost trend rates
gradually decline to 5.0% in 2001. If the health care cost trend
rate was increased by one percent, the accumulated postretirement
benefit obligation as of December 31, 1997 would increase by
approximately 6.7% and the aggregate of the service and interest
cost component of net periodic postretirement benefit cost for the
year would increase by approximately 5.8%.
The Company recognizes 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, 1997 and 1996, the Company's
postemployment benefit obligation is approximately $13.3 million
and $13 million, respectively.
NOTE 9. COMMITMENTS AND CONTINGENCIES
See Note 2.
LONG-TERM CONTRACTS FOR THE PURCHASE OF ELECTRIC POWER: At
January 1, 1998, 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 MW capacity cost
- -----------------------------------------------------------------
Niagara - hydroelectric
project 2007 951 $27,369,000
St. Lawrence - hydroelectric
project 2007 104 1,300,000
Blenheim-Gilboa - pumped
storage generating station 2002 270 7,500,000
- -----------------------------------------------------------------
1,325 $36,169,000
=================================================================
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 and the
recently cancelled contract with Fitzpatrick nuclear plant was
approximately, in millions, $91.0, $93.3 and $92.5 for the years
1997, 1996 and 1995, respectively. In May 1997, the Company
cancelled its commitment to purchase 110 MW of capacity from the
Fitzpatrick facility. The Company continues to have a contract
with Fitzpatrick to purchase for resale up to 46 MW of power for
NYPA's economic development customers.
Under the requirements of PURPA, the Company is required to
purchase power generated by IPPs, as defined therein. The Company
has 141 PPAs with 148 facilities, of which 143 are on line,
amounting to approximately 2,695 MW of capacity at December 31,
1997. Of this amount 2,382 MW is considered firm. The following
table shows the payments for fixed and other capacity costs, and
energy and related taxes the Company estimates it will be obligated
to make under these contracts without giving effect to the MRA.
The payments are subject to the tested capacity and availability of
the facilities, scheduling and price escalation.
- ---------------------------------------------------------
(In thousands of dollars)
SCHEDULABLE
FIXED COSTS VARIABLE COSTS
------------------ --------------
YEAR CAPACITY OTHER ENERGY AND TAXES TOTAL
- ---------------------------------------------------------------
1998 $247,740 $41,420 $ 906,590 $1,195,750
1999 252,130 42,450 943,720 1,238,300
2000 242,030 44,080 974,080 1,260,190
2001 244,620 45,650 1,042,380 1,332,650
2002 248,940 47,330 1,063,830 1,360,100
- ----------------------------------------------------------------
The capacity and other fixed costs relate to contracts with
11 facilities, where the Company is required to make capacity and
other fixed payments, including payments when a facility is not
operating but available for service. These 11 facilities account
for approximately 774 MW of capacity, with contract lengths ranging
from 20 to 35 years. The terms of these existing 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 $8
billion over their terms, using escalated contract rates.
Contracts relating to the remaining facilities in service at
December 31, 1997, require the Company to pay only when energy is
delivered, except when the Company decides that it would be better
to pay a particular project a reduced energy payment to have the
project reduce its high priced energy deliveries as described
below. 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 $1,106
million, $1,088 million and $980 million in 1997, 1996 and 1995 for
13,500,000 MWh, 13,800,000 MWh and 14,000,000 MWh, respectively, of
electric power under all IPP contracts.
On July 9, 1997, the Company announced the MRA to terminate,
restate or amend certain IPP power purchase contracts. As a result
of negotiations, the MRA currently provides for the termination,
restatement or amendment of 28 PPAs with 15 IPPs, in exchange for
an aggregate of approximately $3,616 million in cash and 42.9
million shares of the Company's common stock and certain fixed
price swap contracts. Under the terms of the MRA, the Company
would terminate PPAs representing approximately 1,180 MW of
capacity and restate contracts representing 583 MW of capacity.
The restated contracts are structured to be in the form of
financial swaps with fixed prices for the first two years changing
to an indexed pricing formula thereafter. The contract quantities
are fixed for the full ten year term of the contracts. The MRA
also requires the Company to provide the IPP Parties with a number
of fixed price swap contracts with a term of seven years beginning
in 2003. The terms of the MRA have been and continue to be
modified.
Since 1996, the Company has negotiated 2 long term and several
limited term contract amendments whereby the Company can reduce the
energy deliveries from the facilities. These reduced energy
agreements resulted in a reduction of IPP deliveries of
approximately 1,010,000 MWh and 984,000 MWh during 1997 and 1996,
respectively.
SALE OF CUSTOMER RECEIVABLES: The Company has established a
single-purpose, wholly-owned financing subsidiary, NM Receivables
Corp., whose business consists of the purchase and resale of an
undivided interest in a designated pool of customer receivables,
including accrued unbilled revenues. 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. NM
Receivables Corp. has its own separate creditors which, upon
liquidation of NM Receivables Corp., will be entitled to be
satisfied out of its assets prior to any value becoming available
to the Company. The sale of receivables are in fee simple for a
reasonably equivalent value and are not secured loans. Some
receivables have been contributed in the form of a capital
contribution to NM Receivables Corp. in fee simple for reasonably
equivalent value, and all receivables transferred to NM Receivables
Corp. are assets owned by NM Receivables Corp. in fee simple and
are not available to pay the parent Company's creditors.
At December 31, 1997 and 1996, $144.1 and $250 million,
respectively, of receivables had been sold by NM Receivables, Corp.
to a third party. The undivided interest in the designated pool of
receivables was sold with limited recourse. The agreement provides
for a formula based loss reserve pursuant to which additional
customer receivables are assigned to the purchaser to protect
against bad debts. At December 31, 1997, the amount of additional
receivables assigned to the purchaser, as a loss reserve, was
approximately $64.4 million. Although this represents the formula-
based amount of credit exposure at December 31, 1997 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 Internal Revenue Service ("IRS") has
conducted an examination of the Company's federal income tax
returns for the years 1989 and 1990 and issued a Revenue Agents'
Report. The IRS has raised an issue concerning the deductibility
of payments made to IPPs in accordance with certain contracts that
include a provision for a tracking account. A tracking account
represents amounts that these mandated contracts required the
Company to pay IPPs in excess of the Company's avoided costs,
including a carrying charge. The IRS proposes to disallow a
current deduction for amounts paid in excess of the avoided costs
of the Company. Although the Company believes that any such
disallowances 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. To the extent that contracts involving tracking
accounts are terminated or restated or amended under the MRA with
IPP Parties as described in Note 2, the effects of any proposed
disallowance would be mitigated with respect to the IPP Parties
covered under the MRA. The Company is vigorously defending its
position on this issue. The IRS is currently conducting its
examination of the Company's federal income tax returns for the
years 1991 through 1993.
ENVIRONMENTAL CONTINGENCIES: The public utility industry
typically utilizes and/or generates in its operations a broad range
of hazardous and 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 aid in 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 124 sites with which it has
been or may be associated, including 76 which are Company-owned.
The number of owned sites increased as the Company has established
a program to identify and actively manage potential areas of
concern at its electric substations. This effort resulted in
identifying an additional 32 sites. With respect to non-owned
sites, the Company may be required to contribute some proportionate
share of remedial costs. Although one party can, as a matter of
law, be held liable for all of the remedial costs at a site,
regardless of fault, in practice costs are usually allocated among
PRPs.
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 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 investigations are ongoing for
most sites, the estimated cost of remedial action is subject to
change.
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 and costs at similarly
situated sites. Additionally, the Company's estimating process
includes an initiative where these factors are developed and
reviewed using direct input and support obtained from the DEC.
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 at certain of these PRP sites and is contesting
liability accordingly.
As a consequence of site characterizations and assessments
completed to date and negotiations with PRPs, the Company has
accrued a liability in the amount of $220 million, which is
reflected in the Company's Consolidated Balance Sheets at December
31, 1997. The potential high end of the range is presently
estimated at approximately $650 million, including approximately
$285 million in the unlikely event the Company is required to
assume 100% responsibility at non-owned sites. The amount accrued
at December 31, 1997, incorporates the additional electric
substations, previously mentioned, and a change in the method used
to estimate the liability for 27 of the Company's largest sites to
rely upon a decision analysis approach. This method includes
developing several remediation approaches for each of the 27 sites,
using the factors previously described, and then assigning a
probability to each approach. The probability represents the
Company's best estimate of the likelihood of the approach occurring
using input received directly from the DEC. The probable costs for
each approach are then calculated to arrive at an expected value.
While this approach calculates a range of outcomes for each site,
the Company has accrued the sum of the expected values for these
sites. The amount accrued for the Company's remaining sites is
determined through feasibility studies or engineering estimates,
the Company's estimated share of a PRP allocation or where no
better estimate is available, the low end of a range of possible
outcomes. In addition, the Company has recorded a regulatory asset
representing the remediation obligations to be recovered from
ratepayers. PowerChoice provides for the continued application of
deferral accounting for cost differences resulting from this
effort.
In October 1997, the Company submitted a draft feasibility
study to the DEC, which included the Company's Harbor Point site
and five surrounding non-owned sites. The study indicates a range
of viable remedial approaches, however, a final determination has
not been made concerning the remedial approach to be taken. This
range consists of a low end of $22 million and a high end of $230
million, with an expected value calculation of $51 million, which
is included in the amounts accrued at December 31, 1997. The range
represents the total costs to remediate the properties and does not
consider contributions from other PRPs. The Company anticipates
receiving comments from the DEC on the draft feasibility study by
the spring of 1999. At this time, the Company cannot definitively
predict the nature of the DEC proposed remedial action plan or the
range of remediation costs it will require. While the Company does
not expect to be responsible for the entire cost to remediate these
properties, it is not possible at this time to determine its share
of the cost of remediation. In May 1995, the Company filed a
complaint pursuant to applicable Federal and New York State law, in
the U.S. District Court for the Northern District of New York
against several defendants seeking recovery of past and future
costs associated with the investigation and remediation of the
Harbor Point and surrounding sites. In a motion currently pending
before the court, the New York State Attorney General has moved to
dismiss the Company's claims against the State of New York, the New
York State Department of Transportation, the Thruway Authority and
Canal Corporation. The Company has opposed this motion. The case
management order presently calls for the close of discovery on
December 31, 1998. As a result, the Company cannot predict the
outcome of the pending litigation against other PRPs or the
allocation of the Company's share of the costs to remediate the
Harbor Point and surrounding sites.
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.
To date, the Company has reached settlements with a number of
insurance carriers, resulting in payments to the Company of
approximately $36 million, net of costs incurred in pursuing
recoveries. Under PowerChoice the electric portion or
approximately $32 million will be amortized over 10 years. The
remaining portion relates to the gas business and is being
amortized over the three year settlement period.
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 1998 through 2002 will require approximately
$1.4 billion, excluding AFC and nuclear fuel. For the years 1998
through 2002, the estimates, in millions, are $328, $269, $264,
$275 and $300, respectively, which includes $26, $25, $22, $20 and
$38, respectively, related to non-nuclear generation. The impact
of the ice storm (see Note 13) on the construction program will not
be known until restoration efforts have been completed. These
amounts are reviewed by management as circumstances dictate.
Under PowerChoice, the Company will separate, through sale or
spin-off, the Company's non-nuclear power generation business from
the remainder of the business.
GAS SUPPLY, STORAGE AND PIPELINE COMMITMENTS: In connection
with its gas business, the Company has long-term commitments with
a variety of suppliers and pipelines to purchase gas commodity,
provide gas storage capability and transport gas commodity on
interstate gas pipelines. The table below sets forth the Company's
estimated commitments at December 31, 1997, for the next five
years, and thereafter.
(In thousands of dollars)
YEAR GAS SUPPLY GAS STORAGE/PIPELINE
- ---- ---------- --------------------
1998 $103,990 $95,720
1999 78,380 99,490
2000 56,110 81,550
2001 53,140 60,170
2002 39,860 26,610
Thereafter 155,560 71,130
With respect to firm gas supply commitments, the amounts are
based upon volumes specified in the contracts giving consideration
for the minimum take provisions. Commodity prices are based on New
York Mercantile Exchange quotes and reservation charges, when
applicable. For storage and pipeline capacity commitments, amounts
are based upon volumes specified in the contracts, and represent
demand charges priced at current filed tariffs.
At December 31, 1997, the Company's firm gas supply
commitments extend through October 2006, while the gas storage and
transportation commitments extend through October 2012. Beginning
in May 1996, as a result of a generic rate proceeding, the Company
was required to implement service unbundling, where customers could
choose to buy natural gas from sources other than the Company. To
date the migration has not resulted in any stranded costs since the
PSC has allowed utilities to assign the pipeline capacity to the
customers choosing another supplier. This assignment is allowed
during a three-year period ending March 1999, at which time the PSC
will decide on methods for dealing with the remaining unassigned or
excess capacity. In September 1997, the PSC indicated that it is
unlikely utilities will be allowed to continue to assign pipeline
capacity to departing customers after March 1999. The Company is
unable to predict how the PSC will resolve these issues.
NOTE 10. FAIR VALUE OF FINANCIAL AND DERIVATIVE FINANCIAL
INSTRUMENTS
The following methods and assumptions were used to estimate
the fair value of each class of financial instruments:
CASH AND SHORT-TERM INVESTMENTS: The carrying amount
approximates fair value because of the short maturity of the
financial instruments.
LONG-TERM 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.
DERIVATIVE FINANCIAL INSTRUMENTS: The fair value of futures
and forward contracts are determined using quoted market prices and
broker quotes.
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, 1997 1996
- ------------------------------------ --------------------- ----------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- ------------------------------------ --------------------- ----------------------
Cash and short-term
investments $ 378,232 $ 378,232 $ 325,398 $ 325,398
Mandatorily redeemable
preferred stock 86,730 87,328 95,600 86,516
Long-term debt: First Mortgage bonds 2,801,305 2,878,368 2,841,305 2,690,707
Medium-term notes 20,000 22,944 20,000 21,994
Promissory notes 413,760 413,760 413,760 413,760
Other 229,634 229,634 228,461 228,461
In 1997, the Company's energy marketing subsidiary began to
engage in both trading and non-trading activities generally using
gas futures and electric and gas forward contracts. At December
31, 1997, for both trading and non-trading activities, the fair
value of long and short positions was approximately $59.9 million
and $57.6 million, respectively. These fair values exceed the
weighted average fair value of open positions for the period ending
December 31, 1997. The positions above extend for a period of less
than one year. With respect to these activities the Company does
not have any material counterparty credit risk at December 31,
1997.
Transactions entered into for trading purposes are accounted
for on a mark-to-market basis with changes in fair value recognized
as a gain or loss in the period of the change. At December 31,
1997, the open trading positions consisted of off-balance sheet
electric and gas forward contracts. These positions consisted of
long and short electric forward contracts with fair values of $45.3
million (1,878,000 MWh) and $44.3 million (1,778,000 MWh),
respectively, and long and short gas forward contracts with fair
values of $9.4 million (7.1 million Dth) and $10.2 million (7.3
million Dth), respectively. The quantities above represent
notional contract quantities. The effects of trading activities on
the Company's 1997 results of operations were not material.
Activities for non-trading purposes generally consist of
transactions entered into to hedge the market fluctuations of
contractual and anticipated commitments. Gas futures contracts are
primarily used for hedging purposes. The change in fair value of
these transactions are deferred until the gain or loss on the
hedged item is recognized. The fair value of open positions for
non-trading purposes at December 31, 1997, as well as the effect of
these activities on the Company's results of operations for the
same period ending, was not material.
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 Energy Corporation (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, 1997. The proceeds from the sale of investments were
$159.7 million, $99.4 million and $70.3 million in 1997, 1996 and
1995, 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 Energy Corporation and the pension trust are
included, net of tax, in "Common stockholders' equity" on the
Consolidated Balance Sheets, while the realized gains and losses
are included in "Other income and deductions" 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, 1997 1996
- --------------- ---------------------------------- -----------------------------------
Gross Gross
Unrealized Fair Unrealized Fair
Security Type Cost Gain (Loss) Value Cost Gain (Loss) Value
- --------------- ---------------------------------- -----------------------------------
U.S. Government
Obligations $ 14,136 $ 1,864 $ (4) $ 15,996 $ 24,782 $1,530 $ (33) $26,279
Commercial Paper 106,035 1,542 - 107,577 90,495 739 - 91,234
Tax Exempt
Obligations 80,115 5,884 (55) 85,944 75,590 3,209 (147) 78,652
Corporate
Obligations 92,949 17,368 (830) 109,487 62,723 8,524 (422) 70,825
Other 3,025 - - 3,025 2,586 - - 2,586
-------- -------- ------ -------- -------- ------- -------- --------
$296,260 $26,658 $(889) $322,029 $256,176 $14,002 $ (602) $269,576
======== ======= ====== ======== ======== ======= ======== ========
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, 1997 1996 1995
- ----------------------- ---- ---- ----
Realized gains $3,487 $2,121 $2,523
Realized losses 686 806 328
The contractual maturities of the Company's investments in
debt securities is as follows:
- ---------------------------------------------------------
In thousands of dollars
-----------------------------
At December 31, 1997 Fair Value Cost
- ---------------------------------------------------------
Less than 1 year $106,677 $105,135
1 year to 5 years 10,845 10,654
5 years to 10 years 52,526 50,351
Due after 10 years 113,946 104,353
NOTE 11. STOCK BASED COMPENSATION
Under the Company's stock compensation plans, stock units and
stock appreciation rights ("SARs") may be granted to officers, key
employees and directors. In addition, the Company's plans allow
for the grant of stock options to officers. In 1997, 1996 and 1995
the Company granted 209,918 units and 296,300 SARs, 291,228 units
and 376,600 SARs and 169,500 units and 414,000 SARs, respectively.
Also, in 1995 the Company granted 85,375 stock options. At
December 31, 1997, there were 668,132 units, 1,086,900 SARs and
298,583 options outstanding. Stock units are payable in cash at
the end of a defined vesting period, determined at the date of the
grant, based upon the Company's stock price for a defined period.
SARs become exercisable, as determined at the grant date, and are
payable in cash based upon the increase in the Company's stock
price from a specified level. As such, for these awards,
compensation expense is recognized over the vesting period of the
award based upon changes in the Company's stock price for that
period. Options were granted over the period 1992 to 1995 and
become exercisable three years and expire ten years from the grant
date. These options are all considered to be antidilutive for EPS
calculations. Included in the results of operations for the years
ending 1997 and 1996, is approximately $3.2 and $2.6 million,
respectively, related to these plans.
As permitted by SFAS No. 123 - "Accounting for Stock-Based
Compensation" ("SFAS No. 123") the Company has elected to follow
Accounting Principles Board Opinion No. 25-"Accounting for Stock
Issued to Employees" (APB No. 25) and related interpretations in
accounting for its employee stock options. Under APB No. 25, no
compensation expense is recognized for stock options because the
exercise price of the Company's employee stock options equals the
market price of the underlying stock on the grant date. Since
stock units and SARs are payable in cash, the accounting under APB
No. 25 and SFAS No. 123 is the same. Therefore, the pro-forma
disclosure of information regarding net income, as required by SFAS
No. 123, relates only to the Company's outstanding stock options,
the effect of which is immaterial to the financial statements for
the years ended 1997, 1996 and 1995. There is no effect on
earnings per share for these years resulting from the pro-forma
adjustments to net income.
NOTE 12. 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, 1997, total plant
assets consisted of approximately 24% Nuclear, 20% Fossil/Hydro,
42% Transmission and Distribution, 11% Gas and 3% Common.
In thousands of dollars
-----------------------
1997 1996 1995
---- ---- ----
Operating revenues:
Electric $3,309,441 $3,308,979 $3,335,548
Gas 656,963 681,674 581,790
- -----------------------------------------------------------------
Total $3,966,404 $3,990,653 $3,917,338
=================================================================
Operating income:
Electric $ 462,240 $ 438,590 $ 587,282
Gas 96,599 83,748 96,752
- -----------------------------------------------------------------
Total $ 558,839 $ 522,338 $ 684,034
=================================================================
Other income and (deductions):
Electric $(190,000) $ - $ -
- -----------------------------------------------------------------
Sub-total $ 368,839 $ 522,338 $ 684,034
Other income 24,997 35,943 3,069
Interest charges (273,906) (278,033) (279,674)
- -----------------------------------------------------------------
Income before federal and
foreign income taxes $ 119,930 $ 280,248 $ 407,429
=================================================================
Federal and foreign income taxes:
Electric 30,090 79,574 133,246
Gas 30,005 22,920 26,147
- -----------------------------------------------------------------
Total 60,095 102,494 159,393
=================================================================
Income before
extraordinary item $ 59,835 $ 177,754 $ 248,036
=================================================================
Depreciation and amortization:
Electric $ 311,683 $ 302,825 $ 292,995
Gas 27,958 27,002 24,836
- -----------------------------------------------------------------
Total $ 339,641 $ 329,827 $ 317,831
=================================================================
Construction expenditures (including nuclear fuel):
Electric $ 221,915 $ 277,505 $ 285,722
Gas 68,842 74,544 60,082
- -----------------------------------------------------------------
Total $ 290,757 $ 352,049 $ 345,804
=================================================================
Identifiable assets:
Electric $7,257,163 $7,372,370 $7,592,287
Gas 1,185,001 1,203,184 1,123,045
- -----------------------------------------------------------------
Total 8,442,164 8,575,554 8,715,332
Corporate assets 1,141,977 852,081 762,537
- -----------------------------------------------------------------
Total assets $9,584,141 $9,427,635 $9,477,869
=================================================================
NOTE 13. SUBSEQUENT EVENT
In early January 1998, a major ice storm and flooding caused
extensive damage in a large area of northern New York. The
Company's electric transmission and distribution facilities in an
area of approximately 7,000 square miles were damaged, interrupting
service to approximately 120,000 of the Company's customers, or
approximately 300,000 people. The Company had to rebuild much of
its transmission and distribution system to restore power in this
area. By the end of January 1998, service to all customers was
restored; however, the final costs of the storm will not be known
as crews continue to make final repairs to temporary measures to
restore service and salvage operations cannot be completed until
spring.
The preliminary estimate of the total cost of the restoration
and rebuild efforts could exceed $125 million. A portion of the
cost will be capitalized; however, at this time, the Company is
unable to determine the capital portion until rebuild efforts have
been completed and all labor, material and other costs, including
charges from other utilities and contractors, have been received
and analyzed.
The Company is pursuing federal disaster relief assistance and
is working with its insurance carriers to assess what portion of
the rebuild costs are covered by insurance policies. The Company
is also analyzing potential available options for state financial
aid. The Company is unable to determine what recoveries, if any,
it may receive from these sources.
Absent recovery, the Company would face a charge to earnings
in the first quarter of 1998 to reflect its estimate of
unrecoverable, non-capitalized costs.
NOTE 14. QUARTERLY FINANCIAL DATA (UNAUDITED
Operating revenues, operating income, net income (loss) and
earnings (loss) per common share by quarters from 1997, 1996 and
1995, 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
-----------------------
BASIC AND
BASIC AND DILUTED
DILUTED NET EARNINGS
OPERATING OPERATING INCOME (LOSS) PER
QUARTER ENDED REVENUES INCOME (LOSS) COMMON SHARE
- ----------------------------------------------------------------
December 31, 1997 $ 960,304 $ 86,024 $(115,619) $ (.86)
1996 971,106 117,832 (25,808) (.24)
1995 966,478 132,228 27,874 .13
- ----------------------------------------------------------------
September 30, 1997 $ 896,570 $110,174 $ 31,683 $ .15
1996 895,713 47,119 (12,916) (.16)
1995 887,231 142,732 46,941 .26
- ----------------------------------------------------------------
June 30, 1997 $ 945,698 $130,704 $ 40,749 $ .22
1996 960,771 142,755 52,992 .30
1995 938,816 152,297 54,485 .31
- ----------------------------------------------------------------
March 31, 1997 $1,163,832 $231,937 $103,022 $ .65
1996 1,163,063 214,632 96,122 .60
1995 1,124,813 256,777 118,736 .75
- ----------------------------------------------------------------
In the fourth quarter of 1997 the Company wrote-off $190.0
million (85 cents per share) for the estimated amount of the MRA
regulatory asset disallowed in rates by the PSC. In the fourth
quarter of 1996 the Company recorded an extraordinary item for the
discontinuance of regulatory accounting principles of $103.6
million (47 cents per common share). In the third quarter of 1996
the Company increased the allowance for doubtful accounts by $68.5
million (31 cents per common share). In the fourth quarter of
1995, the Company recorded $16.9 million (8 cents per common share)
for MERIT earned in accordance with the 1991 Agreement.
ELECTRIC AND GAS STATISTICS
ELECTRIC CAPABILITY
Thousands of KW
----------------
December 31, 1997 % 1996 1995
- ------------------------------------------------------------
Owned:
Coal 1,360 16.7 1,333 1,316
Oil* 646 7.9 636 636
Dual Fuel - Oil/Gas 700 8.6 700 700
Nuclear 1,082 13.3 1,082 1,082
Hydro 661 8.1 617 665
----- ---- ----- -----
4,449 54.6 4,368 4,399
----- ---- ----- -----
Purchased:
New York Power Authority
- Hydro 1,325 16.2 1,310 1,325
- Nuclear - - 110 110
IPPs 2,382 29.2 2,406 2,390
----- ---- ----- -----
3,707 45.4 3,826 3,825
----- ---- ----- -----
Total capability** 8,156 100.0 8,194 8,224
===== ===== ===== =====
Electric peak load 6,348 6,021 6,211
===== ===== =====
* In 1994, Oswego Unit No. 5 (an oil-fired unit with a
capability of 850,000 KW) was put into long-term cold standby,
but could be returned to service in three months.
** 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
1997 1996 1995
- ----------------------------------------------------------------
Electric sales (Millions of KWh):
Residential 9,905 10,109 10,055
Commercial 11,552 11,564 11,613
Industrial 7,191 7,148 7,061
Industrial-Special 4,507 4,326 4,053
Municipal service 235 246 229
Other electric systems 3,746 5,431 4,305
Subsidiary - 303 368
- -----------------------------------------------------------------
37,136 39,127 37,684
Electric revenues (Thousands of dollars):
Residential $1,227,245 $1,252,165 $1,214,848
Commercial 1,233,417 1,237,385 1,237,502
Industrial 531,164 524,858 523,996
Industrial-Special 61,820 58,444 56,250
Municipal service 54,545 53,795 50,860
Other electric systems 83,794 113,391 88,936
Miscellaneous 117,456 53,698 143,625
Subsidiary - 15,243 19,531
- -----------------------------------------------------------------
$3,309,441 $3,308,979 $3,335,548
Electric customers (Average):
Residential 1,404,345 1,405,083 1,399,725
Commercial 146,039 145,149 144,731
Industrial 1,970 2,045 2,122
Industrial-Special 85 99 83
Other 1,519 1,302 1,488
Subsidiary - 13,557 13,508
- -----------------------------------------------------------------
1,553,958 1,567,235 1,561,657
Residential (Average):
Annual KWh use per customer 7,053 7,195 7,184
Cost to customer per KWh
(in cents) 12.39 12.39 12.08
Annual revenue per customer $873.89 $891.17 $867.92
GAS STATISTICS
1997 1996 1995
- -----------------------------------------------------------------
Gas Sales (Thousands of Dth):
Residential 55,203 56,728 51,842
Commercial 22,069 25,353 23,818
Industrial 1,381 2,770 2,660
Other gas systems 28 30 161
- -----------------------------------------------------------------
Total sales 78,681 84,881 78,481
Spot market 2,451 10,459 1,723
Transportation of customer-
owned gas 152,813 134,671 144,613
- -----------------------------------------------------------------
Total gas delivered 233,945 230,011 224,817
Gas Revenues (Thousands of dollars):
Residential $ 436,136 $ 417,348 $ 368,391
Commercial 148,213 162,275 143,643
Industrial 6,549 13,325 11,530
Other gas systems 130 138 762
Spot market 6,346 37,124 3,096
Transportation of customer-
owned gas 55,657 50,381 48,290
Miscellaneous 3,932 1,083 6,078
- -----------------------------------------------------------------
$ 656,963 $ 681,674 $ 581,790
Gas Customers (Average):
Residential 484,862 477,786 471,948
Commercial 40,955 41,266 40,945
Industrial 186 206 225
Other 6 6 1
Transportation 843 713 652
- -----------------------------------------------------------------
526,852 519,977 513,771
Residential (Average):
Annual dekatherm use
per customer 113.9 118.7 109.8
Cost to customer per Dth $ 7.90 $ 7.36 $ 7.11
Annual revenue per customer $899.51 $873.50 $780.58
Maximum day gas sendout (Dth) 1,133,370 1,152,996 1,211,252
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.
BUSINESS BACKGROUND OF DIRECTORS
CLASS I DIRECTORS - TERMS EXPIRING IN 1998
ALBERT J. BUDNEY, JR.
- - President, Niagara Mohawk Power Corporation
- - Director since 1995
Mr. Budney, age 50, was elected President of the Company in 1995.
Mr. Budney was previously employed by UtiliCorp United, Inc., an
energy services company, as Managing Vice President of the
UtiliCorp Power Services Group and as President of the Missouri
Public Service Division. Mr. Budney joined UtiliCorp United,
Inc. in 1993. Prior to that, he was Vice President of Stone &
Webster Engineering Corp., where he managed the engineering
firm's Boston Business Development Department. Director of Plum
Street Enterprises, Inc. ("Plum Street"); Canadian Niagara Power
Company, Limited ("CNP"); and Utilities Mutual Insurance Company.
President of Opinac North America, Inc. ("Opinac NA"), a wholly-owned
subsidiary of the Company. Opinac NA holds 100% of Plum Street and, through
its subsidiary, Opinac Energy Corporation ("Opinac"), a 50
percent interest in CNP.
EDMUND M. DAVIS
- - Attorney
- - Director since 1970
- - Member of Compensation & Succession, Corporate Public Policy
& Environmental Affairs, and Finance Committees of the Board
Mr. Davis, age 68, retired in 1995 as of counsel to Hiscock &
Barclay, LLP, Syracuse, NY, Attorneys-at-Law. Mr. Davis was a
partner and had been associated with the law firm since 1957.
DR. BONNIE GUITON HILL
- - President and Chief Executive Officer of The Times Mirror
Foundation and Vice President of The Times Mirror Company
- - Director since 1991
- - Member of Audit, Corporate Public Policy & Environmental
Affairs, and Finance Committees of the Board
Dr. Hill, age 56, President and Chief Executive Officer of The
Times Mirror Foundation, a non-profit institution, and Vice
President of The Times Mirror Company, a news and information
company, located in Los Angeles, CA. Dr. Hill served as Dean and
Professor of Commerce of the McIntire School of Commerce at the
University of Virginia from 1992-1996. Prior to that, she served
as the Secretary of State and Consumer Services Agency for the
State of California. Director of AK Steel Corporation; Crestar
Financial Corporation; Hershey Foods Corporation; and
Louisiana-Pacific Corporation.
HENRY A. PANASCI, JR.
- - Chairman, Cygnus Management Group, LLC
- - Director since 1988
- - Member of Compensation & Succession, Corporate Public Policy
and Environmental Affairs, and Finance Committees of the
Board
Mr. Panasci, age 69, Chairman of Cygnus Management Group, LLC, a
consulting firm specializing in venture capital and private
investments located in Syracuse, NY. Mr. Panasci retired in 1996
as Chairman of the Board and Chief Executive Officer of Fay's
Incorporated, a drug store chain. Mr. Panasci co-founded Fay's
Drug Co., Inc., with his father, in 1958. Director of National
Association of Chain Drug Stores.
CLASS II DIRECTORS - TERMS EXPIRING IN 1999
WILLIAM F. ALLYN
- - President and Chief Executive Officer of Welch Allyn, Inc.
- - Director since 1988
- - Member of Audit, Compensation & Succession, and Nuclear
Oversight Committees of the Board
Mr. Allyn, age 62, President and Chief Executive Officer of Welch
Allyn, Inc., Skaneateles Falls, NY, a manufacturer of medical
diagnostic instrumentation, bar code readers and optical scanning
devices. Mr. Allyn joined Welch Allyn, Inc. in 1962 and was
elected to his present position in 1980. Director of ONBANCorp.,
Inc.; OnBank & Trust Company; Oneida Limited; and Perfex
Corporation.
WILLIAM E. DAVIS
- - Chairman of the Board and Chief Executive Officer
of the Company
- - Director since 1992
- - Chairperson of Executive Committee of the Board
Mr. Davis, age 55, was elected Chairman of the Board and Chief
Executive Officer of the Company in 1993. Mr. Davis joined the
Company in 1990 and was elected Senior Vice President in April
1992, serving in that capacity until elected Vice-Chairman of the
Board of the Company in November 1992. Director of Opinac NA;
Plum Street; Opinac; CNP; and Utilities Mutual Insurance Company.
Mr. Davis is also the Chairman of the Board of Plum Street and
holds the position of Secretary, Utilities Mutual Insurance
Company.
WILLIAM J. DONLON
- - Former Chairman of the Board and Chief Executive Officer of
the Company
- - Director since 1980
Mr. Donlon, age 68, retired in 1993 as Chairman of the Board and
Chief Executive Officer of the Company with 45 years service as
an active employee. Director of Opinac; ONBANCorp., Inc.; and
OnBank & Trust Company.
ANTHONY H. GIOIA
- - Chairman and Chief Executive Officer of Gioia Management,
Inc.
- - Director since 1996
- - Member of Executive, Compensation & Succession, and Nuclear
Oversight Committees of the Board
Mr. Gioia, age 56, Chairman and Chief Executive Officer of Gioia
Management, Inc., a holding company for several companies,
including three packaging companies located in Buffalo and
Lockport, NY. Mr. Gioia has held his present position since
1987.
DR. PATTI McGILL PETERSON
- - Executive Director of the Council for International Exchange
of Scholars
- - Director since 1988
- - Member of Executive, Audit (Chairperson), and Corporate
Public Policy & Environmental Affairs Committees of the
Board
Dr. Peterson, age 54, Executive Director of the Council for
International Exchange of Scholars, a non-profit organization
located in Washington, DC. From 1996 to 1997, Dr. Peterson was a
Senior Fellow of the Cornell Institute for Public Affairs,
Cornell University, Ithaca, NY. Dr. Peterson also served as
President of St. Lawrence University from 1987-1996. Prior to
that, she was President of Wells College. She holds the title
President Emerita at both institutions. Independent Trustee of
John Hancock Mutual Funds.
CLASS III DIRECTORS - TERMS EXPIRING IN 2000
LAWRENCE BURKHARDT, III
- - Nuclear Consultant
- - Director since 1988
- - Chairperson of Nuclear Oversight Committee of the Board
Mr. Burkhardt, age 65, independent consultant to the nuclear
industry since 1990. Prior to his retirement in 1990,
Mr. Burkhardt was employed by the Company and served as Executive
Vice President of Nuclear Operations. Director of MACTEC, Inc.,
formerly Management Analysis Company.
DOUGLAS M. COSTLE
- - Distinguished Senior Fellow and Chairman of the Board of the
Institute for Sustainable Communities
- - Director since 1991
Member of Executive, Audit, Corporate Public Policy &
Environmental Affairs (Chairperson), and Nuclear Oversight
Committees of the Board
Mr. Costle, age 58, Distinguished Senior Fellow and Chairman of
the Board of the Institute for Sustainable Communities, a
non-profit organization located in Montpelier, VT. Mr. Costle
has held his present position since 1991. Former Dean of the
Vermont Law School in South Royalton, Vermont, and Administrator
of the U.S. Environmental Protection Agency. Independent Trustee
of John Hancock Mutual Funds.
DONALD B. RIEFLER
- - Financial Market Consultant
- - Director since 1978
- - Member of Executive, Audit, Finance (Chairperson), and
Nuclear Oversight Committees of the Board
Mr. Riefler, age 70, financial market consultant and advisor to
J. P. Morgan, Florida FSB, Palm Beach, FL, a private banking
concern affiliated with J. P. Morgan & Co., Inc. Prior to his
retirement in 1991, Mr. Riefler was Chairman of the Market Risk
Committee for J. P. Morgan & Co. Incorporated and Morgan Guaranty
Trust Company of New York.
STEPHEN B. SCHWARTZ
- - Retired Senior Vice President, International Business
Machines Corporation
- - Director since 1992
- - Member of Executive, Compensation & Succession
(Chairperson), and Finance Committees of the Board
Mr. Schwartz, age 63, retired as Senior Vice President of
International Business Machines Corporation in 1992.
Mr. Schwartz joined IBM in 1957 and was elected Senior Vice
President in 1990. Director of MFRI, Inc.
The information regarding executive officers appears at the end
of Part I of this Form 10-K Annual Report.
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities and Exchange Act of 1934
requires the Company's directors, executive officers, and
beneficial owners of more than 10 percent of any class of equity
securities or any other person subject to Section 16 ("reporting
persons") to file initial reports of ownership and reports of
changes in ownership of the Company's equity securities with the
Securities and Exchange Commission and the New York Stock
Exchange. Based solely on a review of the copies of such forms
and written representations from the Company's directors and
executive officers, the Company believes that during the
preceding year the reporting persons have complied with all
Section 16(a) filing requirements.
ITEM 11. EXECUTIVE COMPENSATION
BOARD OF DIRECTORS' COMPENSATION AND SUCCESSION COMMITTEE REPORT
ON EXECUTIVE COMPENSATION
The Compensation and Succession Committee of the Board of
Directors (the "Committee") is composed entirely of non-employee
directors. The Committee has responsibility for recommending
officer salaries and for the administration of the Company's
officer incentive compensation plans as described in this report.
The Committee makes recommendations to the Board of Directors
which makes final officer compensation determinations.
This Committee report describes the Company's executive officer
compensation policies, the components of the compensation
program, and the manner in which 1997 compensation determinations
were made for the Company's Chairman of the Board and Chief
Executive Officer, Mr. William E. Davis.
The 1997 Executive Officer Compensation Program was composed
entirely of base salary, frozen at 1995 levels, and 1997 grants
of stock units and stock appreciation rights ("SARs") made
pursuant to the Long-Term Incentive Plan adopted by the Board of
Directors on September 25, 1996 (the "LTIP"), as described later
in this report.
BASE SALARY
The Committee seeks to ensure that salaries of the Company's
officers, including executive officers, remain competitive with
levels paid to comparable positions among other U.S. electric and
gas utilities with comparable revenues (collectively referred to
as the "Comparator Utilities"). The Committee believes that
competitive salaries provide the foundation of the Company's
officer compensation program and are essential for the Company to
attract and retain qualified officers, especially in light of the
increasing competition within the industry. Each officer
position has been assigned to a competitive salary range. The
Committee intends to administer salaries within the 25th to 75th
percentiles of practice with respect to those Comparator
Utilities. The 1997 average salary of the five named executive
officers falls below 25th percentile competitive levels. Since
executive officer salaries were frozen at 1995 levels, as a
condition for receipt of 1995 stock incentive grants, the
competitiveness of annual executive officer compensation is
heavily dependent on stock-related incentives in the form of
stock units and stock appreciation rights granted under the 1995
Stock Incentive Plan ("SIP") and the LTIP.
1995 STOCK INCENTIVE PLAN
On December 14, 1995, the Board of Directors approved the SIP to
promote the success and enhance the value of the Company through
the retention and continued motivation of the Company's officers
and to focus their efforts toward the execution of business
strategies directed toward improving financial returns to
shareholders. Awards under the SIP consisted of stock units and
SARs. These stock unit grants will be paid in cash in 1998
based on the fair market value of the Company's common stock
during the last 12 consecutive trading days in 1997 ($9.922).
Under the SIP, dividends are credited (in an amount equivalent to
dividends paid, if any, on the Company's common stock) with
respect to all stock units granted. These credits are reinvested
at the prevailing stock price, thereby increasing the number of
stock units payable at the end of the period. No dividends were
credited to SIP stock units. The SARs first became exercisable
on January 2, 1998, and may be exercised until they expire on
December 31, 2002.
The SIP was structured so that any compensation earned by
officers during the two-year period 1996 and 1997, other than
base salary, will be based on the Company's year-end 1997 stock
price and total returns realized by shareholders during this
period. Accordingly, participants (including the executive
officers listed in the Summary Compensation Table) did not
receive any salary increases (except to reflect promotions),
annual incentive compensation payments or stock option grants
during 1996 and 1997. Generally speaking, SIP grants were
structured so that the Company's stock price would have to more
than double during this two-year period in order for the total
compensation of the participants to approximate median
competitive levels.
The Committee does not intend to make further SIP grants other
than the 1995 stock unit grants which became payable on December 31,
1997 and the 1995 stock appreciation rights grants which became
exercisable on January 2, 1998 and expire on December 31, 2002.
Long-term incentive grants were made in 1996, 1997, and 1998
under the LTIP described below.
LONG-TERM INCENTIVE PLAN
Because the Committee seeks to provide a continuous program of
long-term stock incentives, on September 25, 1996 the Board of
Directors adopted the LTIP and approved stock unit and SAR grants
for the 1996-1998 period. These stock unit grants will be paid
in cash in early 1999. Dividends are credited (in an amount
equivalent to dividends paid, if any, on the Company's common
stock) with respect to the 1996-1998 stock unit grants, which are
reinvested at the prevailing stock price, thereby increasing the
number of stock units payable in early 1999. The payment value
of the stock units will be based on the average fair market value
of the Company's common stock during the last 12 consecutive
trading days in 1998. The 1996 LTIP SAR grants first become
exercisable on January 2, 1999, and may be exercised until they
expire on December 31, 2005.
On January 29, 1997, the Board of Directors approved the grant of
LTIP stock units and SARs for the 1997-1999 performance period.
These stock units, and accumulated dividend stock units, will be
paid in early 2000 based on the average fair market value of the
Company's common stock during the last twelve consecutive trading
days in 1999. The SARs first become exercisable on January 2,
2000, and can be exercised until they expire on December 31,
2006.
The size of both the 1996-1998 and 1997-1999 LTIP stock unit and
SAR grants were determined, based on the price of the Company's
common stock at the time these grants were made, so that the
combination of the officers' current salaries plus the grant date
present value of SIP, and LTIP grants for the 1996-1998 and
1997-1999 performance periods, would approximate the 50th
percentile of comparator utility total compensation practice for
the three-year period 1995 through 1997. The competitiveness of
the actual compensation realized from SIP and the 1996-1998 and
1997-1999 LTIP grants is dependent on the market value of the
Company's common stock at the end of 1997, 1998, and 1999.
The Board of Directors also approved a January 19, 1998 grant of
LTIP stock units and SARs for the period 1998-2000. These stock
units, and any accumulated dividend stock units, will be paid in
early 2001 based on the average fair market value of the
Company's common stock during the last 12 consecutive trading
days in 2000. The SARs will first become exercisable on January
2, 2001, and can be exercised until they expire on December 31,
2007. The 1998 stock unit and SAR grants were determined so that
the average current salary and the average grant date present
value of the 1998 LTIP grants for the five named executive
officers would approximate the 50th percentile of 1997 comparator
utility total compensation practice.
Through the combination of base salary, and, during 1996, 1997
and 1998, stock unit and SAR grants, the Committee seeks to focus
the efforts of officers toward improving, annually and over the
longer-term, the financial returns for the Company's
shareholders.
COMPENSATION OF WILLIAM E. DAVIS, CHAIRMAN OF THE
BOARD AND CHIEF EXECUTIVE OFFICER
Mr. Davis became Chief Executive Officer on May 1, 1993. In April
1996, Mr. Davis voluntarily reduced his annual salary from a
level of $490,000 to the current level of $450,500. The
Committee has been advised by its consultant that Mr. Davis' 1997
salary falls well below the 25th percentile relative to the Chief
Executive Officers of the Comparator Utilities. On December 13,
1995, the Board granted Mr. Davis 25,000 stock units and 142,500
SARs, with an exercise price of $10.75, under the 1995 Stock
Incentive Plan. As set forth above, SIP stock units will be paid to Mr.
Davis and the other named executive officers in 1998. Mr. Davis'
SIP stock unit and SAR grants were intended to provide competitive total
compensation opportunities during the 1996 and 1997 period, depending
on the Company's stock price, considering that his salary would not be
increased and that he would receive no annual incentive compensation payments
and no stock options during this two-year period.
As previously indicated, the Committee and the Board of Directors
seek to provide a continuous program of long-term stock
incentives beyond 1997 when SIP stock unit grants became payable
and SIP SAR grants became exercisable. Accordingly, on September
25, 1996 the Board of Directors approved a grant of 45,000 stock
units and 90,000 SARs, with an exercise price of $8.00, for Mr.
Davis for the 1996-1998 performance period. On January 29, 1997
the Board of Directors approved a grant of 35,000 stock units and
70,000 SARs, with an exercise price of $10.30, for the 1997-1999
performance period. Both the 1996-1998 and 1997-1999 grants were
made under the terms of the LTIP. The size of the 1996-1998 and
1997-1999 LTIP grants for Mr. Davis was determined so that the
grant date present value of both grants, in combination with his
current salary and his SIP grants, would approximate the 50th
percentile for Comparator Utility chief executive officers during
the 1995-1997 period. The competitiveness of the compensation
Mr. Davis actually realizes from the SIP and LTIP grants is
dependent on the market value of the Company's common stock at
the end of 1997, 1998, and 1999.
As previously indicated, the Board of Directors approved a
January 19, 1998 grant of LTIP stock units and SARs for Mr. Davis
for the period 1998-2000. The size of these grants was
determined so that the sum of his current salary plus the grant
date present value of the 1998 stock unit and SAR grants would
fall approximately midway between the 25th and 50th percentiles
of 1997 total compensation practice for electric/gas utilities of
comparable size.
The Committee is aware of the limitations that tax legislation
has placed on the tax deductibility of compensation in excess of
$1 million which is paid in any year to an executive officer.
Currently none of the executive officers has received
compensation subject to such limitations. The Committee will
continue to monitor developments in this area and take
appropriate actions to preserve the tax deductibility of
compensation paid to executive officers, should this become
necessary.
Submitted by the Compensation and Succession Committee of the
Board of Directors:
Stephen B. Schwartz, Chairperson
William F. Allyn
Edmund M. Davis
Anthony H. Gioia
Henry A. Panasci, Jr.
EXECUTIVE COMPENSATION
The table below sets forth all compensation paid by the Company for services rendered in
all capacities during the fiscal years ended December 31, 1997, December 31, 1996 and
December 31, 1995, to the Chairman of the Board and Chief Executive Officer and to each of
the other four most highly compensated executive officers of the Company for the fiscal
year ended December 31, 1997.
SUMMARY COMPENSATION TABLE
Fiscal Years 1997, 1996 and 1995
ANNUAL COMPENSATION
OTHER
ANNUAL
NAME POSITION YEAR SALARY ($)(A) BONUS($) COMPENSATION($)(C)
W. E. Davis Chairman of the 1997 450,501 0 110
Board and Chief 1996 462,351 0 0
Executive Officer 1995 473,542 0 0
A. J. Budney, Jr.
President and 1997 315,002 0 110
Chief Operating 1996 315,002 0 2,956
Officer 1995 236,251 50,000(B) 32,727
B. R. Sylvia Executive Vice 1997 295,001 0 110
President 1996 295,001 0 0
1995 295,001 0 0
J. W. Powers Senior Vice 1997 210,190 0 110
President 1996 211,002 0 0
1995 209,251 0 0
D. D. Kerr Senior Vice 1997 210,001 0 110
President 1996 210,001 0 0
1995 191,085 0 0
LONG-TERM COMPENSATION
AWARDS
RESTRICTED SECURITIES ALL OTHER
STOCK UNDERLYING COMPENSATION($)
NAME POSITION YEAR AWARDS ($)(D) OPTIONS/SARS(#) (E)
W. E. Davis Chairman of the 1997 371,875 70,000 42,358
Board and Chief 1996 360,000 90,000 43,365
Executive Officer 1995 246,875 152,500 35,729
A. J. Budney, Jr.
President and 1997 185,938 35,000 16,436
Chief Operating 1996 180,000 45,000 24,975
Officer 1995 148,125 76,000 48,541
B. R. Sylvia Executive Vice 1997 117,938 22,200 11,153
President 1996 114,000 28,500 10,174
1995 98,750 49,000 24,832
J. W. Powers Senior Vice 1997 85,000 16,000 187,878
President 1996 142,000 30,000 30,541
1995 0 22,000 58,466
D. D. Kerr Senior Vice 1997 85,000 16,000 7,953
President 1996 82,000 20,500 9,415
1995 74,063 31,500 7,338
__________________
(A) Includes all employee contributions to the Employees'
Savings Fund Plan.
(B) 1995 bonus for Mr. Budney represents a bonus for 1995
guaranteed at the time he was hired if earnings per share
thresholds were not met under the Officer Incentive
Compensation Plan (an annual incentive compensation plan
adopted by the Board of Directors on December 13, 1990, and
suspended for 1996 and 1997 as a condition of participation
in the SIP).
(C) 1996 and 1995 Other Annual Compensation for Mr. Budney
represents amounts reimbursed for payment of taxes
associated with relocation expenses. 1997 Other Annual
Compensation for Messrs. Davis, Budney, Sylvia and Powers
and Ms. Kerr represents amounts reimbursed for payment of
taxes associated with non-cash compensation.
(D) In 1995, 57,500 stock units were granted to the above named
executive officers pursuant to the SIP adopted by the Board
of Directors on December 14, 1995. These stock units vested
and became payable on December 31, 1997. No dividend
equivalents were credited on these stock units. The 1995
values listed in the table were calculated by multiplying
the stock units granted by the closing market price of the
company's stock ($9.875) on the date of the grant (December
31, 1995).
In 1996, 109,750 stock units were granted to the above
named executive officers pursuant to the LTIP adopted by
the Board of Directors on September 25, 1996. These grants
were made for the three-year period January 1, 1996,
through December 31, 1998, and vest and become payable on
December 31, 1998. The 1996 values listed in the table
were calculated by multiplying the stock units granted by
$8.00, the price at the time these stock unit grants were
determined. Dividend equivalents, if any, will be credited
on these grants and will be paid when the related stock
units are paid. For Mr. Powers, the value also includes
the value of stock units granted in 1996 under the 1995
SIP.
In 1997, 79,600 stock units were granted to the above named
executive officers pursuant to the LTIP adopted by the
Board of Directors on September 25, 1996. These grants
were made for the three-year period January 1, 1997,
through December 31, 1999, and vest and become payable on
December 31, 1999. The 1997 values listed in the table
were calculated by multiplying the stock units granted by
$10.625, the price at the time these stock unit grants were
determined. Dividend equivalents, if any, will be credited
on these grants and will be paid when the related stock
units are paid.
As of the end of the 1997 fiscal year, based on a closing
market price of $10.50, Mr. Davis held 105,000 stock units
having a market value of $1,102,500; Mr. Budney held 55,000
stock units having a market value of $577,500; Mr. Sylvia
held 35,350 stock units having a market value of $371,175;
Mr. Powers held 25,750 stock units having a market value of
$270,375; and Ms. Kerr held 25,750 stock units having a
market value of $270,375.
(E) All Other Compensation for 1997 includes: employer
contributions to the Company's Employees' Savings Fund
Plan: Mr. Davis ($4,800), Mr. Sylvia ($4,800), Mr. Powers
($4,800), and Ms. Kerr ($4,800); taxable portion of life
insurance premiums: Mr. Davis ($13,743), Mr. Budney
($2,436), Mr. Sylvia ($3,537), Mr. Powers ($3,528), and Ms.
Kerr ($1,653); employer contributions to the Company's
Excess Benefit Plan: Mr. Davis ($8,715), Mr. Sylvia
($1,837), Mr. Powers ($560), and Ms. Kerr ($1,500);
director fees received from Opinac Energy Corporation:
Mr. Davis ($15,000), Mr. Budney ($14,000), and Mr. Powers
($11,000); lump sum payment for accrued, unused vacation
upon retirement: Mr. Powers ($62,490); severance allowance
paid pursuant to Employment Agreement: Mr. Powers
($105,500); personal travel allowance: Mr. Sylvia ($979).
The following table discloses, for the Chairman of the Board and
Chief Executive Officer, Mr. William E. Davis and the other named
executive officers, the number and terms of SARs granted during
the fiscal year ended December 31, 1997.
OPTION/SAR GRANTS IN LAST FISCAL YEAR
INDIVIDUAL GRANTS
_________________________________________________________________
NUMBER OF % OF TOTAL
SECURITIES OPTIONS/SARS
UNDERLYING GRANTED TO
OPTIONS/SARS EMPLOYEES EXERCISE OR
GRANTED IN FISCAL BASE PRICE
NAME (#) YEAR ($/SH)
W. E. Davis 70,000 23.62% 10.30
A. J. Budney, Jr. 35,000 11.81% 10.30
B. R. Sylvia 22,200 7.49% 10.30
J. W. Powers 16,000 5.40% 10.30
D. D. Kerr 16,000 5.40% 10.30
EXPIRATION GRANT DATE
NAME DATE (A) PRESENT VALUE($) (B)
W. E. Davis 12/31/2006 249,200
A. J. Budney, Jr. 12/31/2006 124,600
B. R. Sylvia 12/31/2006 79,032
J. W. Powers 12/31/2006 56,960
D. D. Kerr 12/31/2006 56,960
_______________
(A) SARs granted in 1997 under the LTIP become exercisable
January 2, 2000. All SARs become exercisable upon a change
in control.
(B) The grant date present value of SARs is calculated using
the Black-Scholes Option Pricing Model with the following
assumptions: market price of the stock at the September 29,
1997 grant date ($10.30); exercise price of rights that
expire on December 31, 2006 ($10.30); stock volatility
(0.2957); dividend yield (2.86%); risk free rate (6.00%);
exercise term (10 years); Black-Scholes ratio (0.3454); and
Black-Scholes value ($3.56) for rights that expire on
December 31, 2006. Stock volatility and dividend yield
assumptions are based on 36 months of results for the
period ending December 31, 1997.
The following table summarizes exercises of options by the Chairman of the Board and Chief
Executive Officer, Mr. William E. Davis, and the other named executive officers, the
number of unexercised options held by them and the spread (the difference between the
current market price of the stock and the exercise price of the option, to the extent that
market price at the end of the year exceeds exercise price) on those unexercised options
for fiscal year ended December 31, 1997.
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION VALUES
NUMBER OF
SECURITIES UNDERLYING
UNEXERCISED OPTIONS/SARS
AT FISCAL YEAR END (#)
SHARES
ACQUIRED ON VALUE
NAME EXERCISE (#) REALIZED ($) EXERCISABLE UNEXERCISABLE
W. E. Davis 0 0 32,625 312,500
A. J. Budney, Jr. 0 0 0 156,000
B. R. Sylvia 0 0 13,000 99,700
J. W. Powers 0 0 9,000 68,000
D. D. Kerr 0 0 6,000 68,000
/TABLE
VALUE OF UNEXERCISED
OPTIONS/SARS AT
FISCAL YEAR-END ($) (A)
NAME EXERCISABLE UNEXERCISABLE
W. E. Davis 0 239,000
A. J. Budney, Jr. 0 119,500
B. R. Sylvia 0 75,690
J. W. Powers 0 78,200
D. D. Kerr 0 54,450
_________________
(A) Calculated based on the closing market price of the Company's common stock on
December 31, 1997 ($10.50).
/TABLE
NIAGARA MOHAWK POWER CORPORATION
Comparison of Five-Year Cumulative Total Return(1)
vs. S&P 500, EEI and Peer Group of Eastern Region Utilities
[ILLUSTRATION OF PERFORMANCE GRAPH--ATTACHED]
1992 1993 1994 1995 1996 1997
NMPC 100.00 110.46 83.26 60.67 63.07 67.06
S&P 500 Index 100.00 110.08 111.53 153.45 188.68 251.63
EEI Index 100.00 111.66 97.28 123.91 123.13 159.17
Peer Group 100.00 109.15 93.87 124.16 122.02 158.83
Assumes $100 invested on December 31, 1992 in Niagara Mohawk's
stock, S&P 500, EEI and Eastern Region utilities. All dividends
assumed to be reinvested over the five-year period.
In prior years, the Company has compared its five-year total
shareholder returns to a peer group comprised of the 23 eastern
region utilities listed below. In future years, the Company
intends to compare its total shareholder returns to the Edison
Electric Institute Combination Gas and Electric Investor-Owned
Utilities Index ("EEI Index"), which is a published industry
index. In view of the nationwide deregulation of the electric
and gas utility industry, the Company believes that a national
peer group, such as the EEI Index, is more appropriate than the
regional utility peer group used in prior years. Furthermore,
the EEI Index is more appropriate since it is composed entirely
of combination electric and gas utilites, like Niagara Mohawk.
PEER GROUP OF EASTERN REGION UTILITIES:
Allegheny Energy Inc. Delmarva Power & Light Co.
Atlantic Energy, Inc. Eastern Utilities Associates
Baltimore Gas & Electric Company General Public Utilities Corp.
Boston Edison Company Keyspan Energy Corp.
Central Hudson Gas & Electric Corp. Long Island Lighting Co.
Central Maine Power Co. National Fuel Gas Company
Consolidated Edison Co. of New York, Inc. New England Electric System
DQE, Inc. New York State Electric & Gas Corp.
Northeast Utilities
Orange & Rockland Utilities Inc.
PECO Energy Company
PP&L Resources Inc
Public Service Enterprise Group Inc.
Rochester Gas & Electric Corp.
The United Illuminating Company
______________
(1) Total returns for each Eastern Region Utility were determined in accordance with the
Securities and Exchange Commission's regulations, i.e., weighted according to each
issuer's stock market capitalization.
RETIREMENT BENEFITS
The following table illustrates the maximum aggregate pension
benefit, with certain deductions for Social Security, payable by
the Company under both the Niagara Mohawk Pension Plan ("Basic
Plan") and the Company's Supplemental Executive Retirement Plan
("SERP") to an officer in specified average salary and
years-of-service classifications. Such benefit amounts have been
calculated as though each officer selected a straight life
annuity and retired on December 31, 1997 at age 65. The amount of
compensation taken into account under a tax-qualified plan is
subject to certain annual limits (adjusted for increases in the
cost of living, $150,000 in 1996 and $160,000 in 1997). This
limitation may reduce benefits payable to highly compensated
individuals.
ANNUAL RETIREMENT ALLOWANCE
3-Year Average 10 Years 20 Years 30 Years
Annual Salary Service* Service Service
$150,000 $21,090 $ 81,948 $ 81,948
225,000 23,555 126,948 126,948
300,000 23,869 171,948 171,948
375,000 23,869 216,948 216,948
450,000 23,869 261,948 261,948
525,000 23,869 306,948 306,948
3-Year Average 40 Years
Annual Salary Service
$150,000 $ 81,948
225,000 126,948
300,000 171,948
375,000 216,948
450,000 261,948
525,000 306,948
_____________
*Subject to five-year average annual salary.
The credited years of service under the Basic Plan and the SERP
for the individuals listed in the Summary Compensation Table are
Mr. Davis, 8 years; Mr. Budney, 3 years; Mr. Sylvia, 7 years; Mr.
Powers, 34 years; Ms. Kerr, 24 years.
The Basic Plan, a noncontributory, tax-qualified defined benefit
plan, provides all employees of the Company with a minimum
retirement benefit related to the highest consecutive five-year
average compensation. Compensation covered by the Basic Plan
includes only the participant's base salary or pay, subject to
the maximum annual limit noted above. Directors who are not
employees are not eligible to participate.
The SERP is a nonqualified, noncontributory defined benefit plan
providing additional benefits to certain officers of the Company
upon retirement after age 55 who have 20 or more years of
employment. The Committee may grant exceptions to these
requirements. The SERP provides for payment monthly of an amount
equal to the greater of (i) 60% of monthly base salary averaged
over the final 36 months of employment, less benefits payable
under the Basic Plan, retirement benefits accrued during previous
employment and one-half of the maximum Social Security benefit to
which the participant may be entitled at the time of retirement,
or (ii) benefits payable under the Basic Plan without regard to
the annual benefit limitations imposed by the Internal Revenue
Code. Participants in the SERP may elect to receive their
benefit in a lump sum payment provided certain established
criteria are met.
EMPLOYEE AGREEMENTS
The Company entered into employment agreements with Messrs.
Davis, Budney, Sylvia and Powers and Ms. Kerr, effective as of
December 20, 1996, which superseded their prior agreements with
the Company. The agreements have a three-year term, and, unless
either party gives 60 days prior notice to the contrary, the
agreements are extended at the end of each year for an additional
year. In the event of a change in control (as defined in the
agreement), the agreement will remain in effect for a period of
at least 36 months thereafter unless a notice not to extend the
term of the agreement was given at least 18 months prior to the
change in control. The agreements provide that the executive
will receive a base salary at the executive's current annual
salary or such greater amount determined by the Company and that
the executive will be able to participate in the Company's
incentive compensation plans according to their terms. In
addition, the executive is entitled to business expense
reimbursement, vacation, sick leave, perquisites, fringe
benefits, insurance coverage and other terms and conditions of
the agreement as are provided to employees of the Company with
comparable rank and seniority. Under an amendment to the agreements
effective as of June 9, 1997, if an executive has completed eight
years of service and attained age 55 at the time of the executive's
termination of employment, the executive (and eligible dependents)
will be entitled to coverage for medical, prescription drug, dental
and hospitalization benefits equal to those provided by the Company
on March 26, 1997 for the remainder of the executive's life with all
premiums therefore paid by the Company. If an executive has completed
eight years of service but has not attained age 55 upon terminating
employment, such benefits will be provided when the executive attains
age 55.
The employment agreements also provide that the executive's
benefits under the SERP will be based on the executive's salary,
annual incentive awards and SIP awards, as applicable. Further,
if the executive's employment is terminated by the Company
without cause (whether prior to or after a change in control), or
by the executive for good reason after a change in control, or
after completing eight years of service, the agreements provide
that the executive will be deemed fully vested under such plan
without reduction for early commencement. If the executive is
under age 55 at the time of such termination, the executive will
be entitled to a fully vested benefit under the SERP upon
attaining age 55, without reduction for early commencement.
The agreements restrict under certain circumstances prior to a
change in control the executive's ability to compete with the
Company and to use confidential information concerning the
Company. In the event of a dispute over an executive's rights
under the executive's agreement following a change in control of
the Company, the Company will pay the executive's reasonable
legal fees with respect to the dispute unless the executive's
claims are found to be frivolous.
If the executive's employment is terminated by the Company
without cause prior to a change in control (as defined in the
agreement), the executive will be entitled to a lump sum
severance benefit in an amount equal to two times the executive's
base salary plus an amount equal to two times the greater of the
executive's (i) most recent annual incentive award or (ii)
average annual incentive award paid over the previous three years
(a portion of the value of the SIP awards to the executive will
be treated as incentive awards for 1996 and 1997 for this
purpose). In addition, the executive will receive a pro rata
portion of the incentive award which would have been payable to
the executive for the fiscal year in which termination of
employment occurs provided that the executive has been employed
for 180 days in such fiscal year. In the event of such
termination of employment, the executive will also be entitled to
continued participation in the Company's employee benefit plans
for two years, coverage for the balance of the executive's life
under a life insurance policy providing a death benefit equal to
2.5 times the executive's base salary at termination and payment
by the Company of fees and expenses or any executive recruiting
or placement firm in seeking new employment.
If, following a change in control, the executive's employment is
terminated by the Company without cause or by the executive for
good reason (as defined in the agreement), the executive will be
entitled to a lump sum severance benefit equal to four times the
executive's base salary. The executive will also be entitled to
the additional benefits referred to in the last sentence of the
preceding paragraph, except that employee benefit plan coverage
for medical, prescription drug, dental and hospitalization
benefits will continue for the remainder of the executive's life
with all premiums therefor paid by the Company and coverage under
other employee benefit plans will continue for four years. In
the event that the payments to the executive upon termination of
employment following a change in control would subject the
executive to the excise tax on excess parachute payments under
the Internal Revenue Code, the Company will reimburse the
executive for such excise tax (and the income tax and excise tax
on such reimbursement).
In November 1994, the Company entered into a supplemental
agreement with Mr. Powers in exchange for his foregoing
retirement under the Company's Voluntary Employee Reduction
Program and continuing employment with the Company until December
31, 1996. This agreement was modified by an agreement between
Mr. Powers and the Company entered into in October 1996 in
exchange for his foregoing retirement on December 31, 1996, and
continuing employment with the Company for up to 12 additional
months. Mr. Powers retired from the Company effective December
31, 1997. Under the agreements, Mr. Powers became entitled to a
lump sum payment following the successful closing of the sale of
HYDRA-CO Enterprises, Inc., and to a severance allowance equal to
one-half of his annual salary in effect on December 31, 1996,
which was paid to him in January 1997. The agreements also
provide that Mr. Powers would be entitled to (i) a SIP award of
7,500 stock units and 9,500 SARs, which would be fully vested
(assuming retirement during 1997) and payable (in the case of
stock units) or exercisable (in the case of SARs) on December 31,
1997, (ii) long-term incentive grants equivalent to those
provided to other senior vice presidents for the 1996-1998 and
1997-1999 cycles (prorated for his period of service during those
cycles), (iii) a lump sum payment for unused vacation for 1995,
1996 and 1997 upon retirement and (iv) "grandfathered" retiree
medical coverages in effect on December 31, 1996. Under the
agreements Mr. Powers also is entitled to a benefit under the
Company's SERP no less than his benefit calculated as of November
1994, and to have the fees he received as a member of the board
of directors of Opinac Energy Corporation (or would have received
in the event that such fees are eliminated) taken into account in
calculating his benefit under this plan period. In January 1997,
the Committee agreed that if Mr. Powers elected to receive a lump
sum payment of his benefit under the SERP (which he did), it
would be based on a discount rate no higher than the applicable
discount rate in effect under the plan on December 31, 1996.
COMPENSATION OF DIRECTORS
Directors who are not employees of the Company receive an annual
retainer of $20,000 and $1,000 per Board meeting attended.
Directors who are not employees and who chair any of the standing
Board Committees receive an additional annual fee of $3,000 and
those who serve on any of the standing Board Committees,
including the chair, receive $850 per Committee meeting attended.
The Company also reimburses its directors for travel, lodging and
related expenses they incur in attending Board and Committee
meetings.
The Board of Directors terminated the Outside Director Retirement
Plan effective December 31, 1995. The plan paid annual
retirement benefits equal to the annual retainer in effect at the
time of retirement to outside directors who retired on or after
age 65 with 10 years of service. Directors under age 60 had the
present value of their accrued benefits as of December 31, 1995
converted into deferred stock units of equivalent value which
become payable upon the director's termination from the Board.
Directors age 60 or older were given an election to (1) continue
to receive grandfathered retirement benefits based on the annual
retainer in 1995, (2) convert the present value of their accrued
benefits into deferred stock units, or (3) receive half the
grandfathered retirement benefit and convert half the present
value of their accrued benefit into deferred stock units. Four
directors elected to continue to receive the grandfathered
Retirement Plan benefits.
Deferred Stock Units ("DSUs"), administered in accordance with
the terms of the Outside Director Deferred Stock Unit Plan
adopted by the Board of Directors on December 2, 1996, are paid
when a person ceases to be an outside director, either in a lump
sum or in five equal annual installments. The first DSU
installment payment would be made shortly after the director's
service ends and the other installments would be paid on the
first through fourth anniversaries of such date, based on the
prevailing stock price at that time.
DSUs are credited with respect to any dividends paid during the
term of their deferral. Such dividend credits are reinvested
into DSUs of equivalent current value based on the prevailing
price of the Company's common stock at that time.
Commencing in 1996, and annually thereafter, each outside
director is credited with DSUs equal in value to 50% of the
prevailing year's annual retainer (60% for Committee Chairs).
Accordingly, all outside directors were credited with 1,168 DSUs
(1,402 for Committee Chairs) based on a closing stock price of
$8.5625 on May 7, 1997. The beneficial stock ownership table in
Item 12, shows the DSUs which have been credited to each of the
outside directors under this plan as of March 10, 1998.
The Company provides certain health and life insurance benefits
to directors who are not employees of the Company. Each outside
director covered under the Company's health care plans
contributes approximately 20 percent of the monthly costs
associated with these plans. During 1997, the following
directors received the indicated benefits under the foregoing
arrangements: Mr. Burkhardt ($3,689), Mr. Costle ($3,178), Mr.
Edmund Davis ($6,602), Mr. Donlon ($204), Mr. Gioia ($4,077), Dr.
Hill ($3,306), Mr. Panasci ($212), Dr. Peterson ($2,361), Mr.
Riefler ($4,856) and Mr. Schwartz ($384). Mr. Burkhardt received
a consulting fee of $18,000 during 1997.
COMPENSATION AND SUCCESSION COMMITTEE INTERLOCKS AND INSIDER
PARTICIPATION
Directors Allyn, Edmund Davis, Gioia, Panasci and Schwartz, all
of whom are non-employee directors, are the members of the
Compensation and Succession Committee.
No person serving during 1997 as a member of the Compensation and
Succession Committee of the Board served as an officer or
employee of the Company or any of its subsidiaries during or
prior to 1997.
No person serving during 1997 as an executive officer of the
Company serves or has served as a director or a member of the
compensation committee of any other entity that has an executive
officer who serves or has served either as a member of the
Compensation and Succession Committee or as a member of the Board
of Directors of Niagara Mohawk Power Corporation.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The following table shows the persons (as the term is used in Section 13(d)(3)
of the Securities Exchange Act of 1934) known to the Company to own more than
five percent (5%) of the Company's common stock as of December 31, 1997.
AMOUNT AND NATURE
TITLE OF NAME AND ADDRESS OF OF BENEFICIAL PERCENT
CLASS BENEFICIAL OWNER OWNERSHIP OF CLASS
Common Stock FMR Corp. 14,441,831(1) 10.00%
82 Devonshire Street
Boston, Massachusetts 02109
Common Stock Fidelity Management Trust Co. 11,829,786(2) 8.19%
82 Devonshire Street
Boston, Massachusetts 02109
Common Stock The Prudential Insurance Company
of America 8,404,245(3) 5.82%
751 Broad Street
Newark, New Jersey 07102-3777
(1) Includes 1,873,631 shares with respect to which FMR Corp. has sole voting
power and 14,441,831 with sole power to dispose or to direct disposition
as reported on Schedule 13G, dated February 14, 1998, filed with the SEC.
(2) The above represents shares in the Company's Non-Represented and
Represented Employees' Savings Fund Plans. Fidelity Management Trust
Company serves as Trustee. The Trustee will vote all shares of common
stock held in the Trusts established for the Plans in accordance with
the directions received from the employees participating in the Plans.
The Trustee will vote shares for which it receives no instructions in
the same proportion as it votes shares for which it receives instructions.
(3) Includes 789,900 shares with respect to which Prudential Insurance
Company of America has sole voting power; 7,575,445 shares with shared
power to vote; 789,900 shares with sole power to dispose or to direct
disposition; and 7,614,345 shares with shared power to dispose, as
reported on Schedule 13G, dated February 10, 1998, filed with the SEC.
The Company believes that holders of approximately 88.2% of the
Company's Common Stock outstanding as of December 31, 1997,
elected to hold their shares, not in their own names, but in the
names of banking or financial intermediaries. Accordingly, as of
that date, 127,431,405 shares were registered in the nominee name
of The Depository Trust Company, Cede & Co.
SECURITY OWNERSHIP OF DIRECTORS AND EXECUTIVE OFFICERS
The following table reflects shares of the Company's common stock
beneficially owned (or deemed to be beneficially owned pursuant
to the rules of the Securities and Exchange Commission) as of
March 10, 1998, by each director of the Company, each of the
named executive officers in the Summary Compensation Table below
and the current directors and executive officers of the Company
as a group. The table also lists the number of stock units
credited to directors, named executive officers and the directors
and executive officers of the Company as a group as of March 10,
1998, pursuant to the Company's compensation and benefit
programs. No voting rights are associated with stock units.
TITLE OF NAME AND ADDRESS OF AMOUNT AND NATURE OF PERCENT
CLASS BENEFICIAL OWNER BENEFICIAL OWNERSHIP* OF CLASS
Common Stock Directors:
William F. Allyn 1,000 **
Albert J. Budney, Jr. 10,500(1) **
Lawrence Burkhardt, III 452 **
Douglas M. Costle 500 **
Edmund M. Davis 2,274 **
William E. Davis 45,238(2) **
William J. Donlon 15,343(3) **
Anthony H. Gioia 500 **
Bonnie Guiton Hill 1,000 **
Henry A. Panasci, Jr. 2,500 **
Patti McGill Peterson 500 **
Donald B. Riefler 1,000 **
Stephen B. Schwartz 500 **
Named Executives:
B. Ralph Sylvia 22,787(4) **
John W. Powers 26,659(5) **
Darlene D. Kerr 15,726(6) **
All Directors and Executive
Officers (23) as a group 197,260(7) **
TITLE OF NAME AND ADDRESS OF NUMBER OF
CLASS BENEFICIAL OWNER STOCK UNITS HELD
Common Stock Directors:
William F. Allyn 9,158(8)
Albert J. Budney, Jr. 72,500(9)
Lawrence Burkhardt, III 2,773(8)
Douglas M. Costle 9,551(8)
Edmund M. Davis 26,386(8)
William E. Davis 140,000(9)
William J. Donlon 0
Anthony H. Gioia 2,311(8)
Bonnie Guiton Hill 8,077(8)
Henry A. Panasci, Jr. 2,311(8)
Patti McGill Peterson 11,199(8)
Donald B. Riefler 25,877(8)
Stephen B. Schwartz 11,204(8)
Named Executives:
B. Ralph Sylvia 46,450(9)
John W. Powers 25,750(9)
Darlene D. Kerr 36,850(9)
All Directors and Executive
Officers (23) as a group 569,297
_______________
* Based on information furnished to the Company by the Directors
and Executive Officers. Includes shares of common stock
credited under the Employees' Savings Fund Plan as of March
10, 1998.
** Less than one percent.
(1) Includes options for 10,000 shares of common stock
exercisable within 60 days.
(2) Includes presently exercisable options for 42,625 shares of
common stock.
(3) Includes presently exercisable options for 13,333 shares of
common stock.
(4) Includes presently exercisable options for 18,000 shares of
common stock.
(5) Includes presently exercisable options for 12,000 shares of
common stock.
(6) Includes presently exercisable options for 9,000 shares of
common stock.
(7) Includes presently exercisable options for 141,083 shares of
common stock.
(8) Represents deferred stock units granted pursuant to the
Outside Director Deferred Stock Unit Plan. No voting rights
are associated with deferred stock units. For additional
information regarding deferred stock units, refer to Item
11. Executive Compensation - "Compensation of Directors".
(9) Represents stock units granted in 1995 pursuant to the SIP and in
1996, 1997 and 1998 pursuant to the LTIP. No voting rights are
associated with stock units. For additional information regarding
stock units granted to named executives, refer to Item 11.
Executive Compensation - "Long-Term Incentive Plan").
In addition to the shares of the Company's common stock, Albert
J. Budney, Jr. indirectly owns 100 shares of the Company's
Preferred Stock, 9 1/2% Series.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The Company has nothing to report for this item.
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, 1997
Consolidated Balance Sheets at December 31, 1997 and 1996
Consolidated Statements of Cash Flows for each of the
three years in the period ended December 31, 1997
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, 1997, 1996 and 1995 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 - October 10, 1997
Item reported - Item 5. Other Events.
Registrant filed information concerning the PowerChoice
settlement.
Form 8-K Reporting Date - February 11, 1998
Item reported - Item 5. Other Events.
Registrant filed information concerning the January 1998 ice
storm.
(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 March 26,
1998 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
March 26, 1998
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 Deductions at End
Description of Period Expenses Accounts (a) of Period
- ------------------------ ---------- ---------- ---------- ---------- ---------
Allowance for Doubtful
Accounts - deducted from
Accounts Receivable in
the Consolidated Balance
Sheets
1997 $52,096 $ 46,549 $ 3,000 (b) $39,097 $62,548
1996 20,000 127,648 800 (b) 96,352 52,096
1995 3,600 31,284 16,400 (b) 31,284 20,000
(a) Uncollectible accounts written off net of recoveries of $14,416, $12,842, and $10,830
in 1997, 1996 and 1995, respectively.
(b) The Company increased its allowance for doubtful accounts in 1995 and recorded a
regulatory asset of $16,400, which reflects the amount that the Company expects to
recover in rates. In 1996, regulatory asset increased by $800 to $17,200 and in 1997,
regulatory asset increased $3,000 to $20,200.
/TABLE
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 (c)
- ------------------------ ---------- ---------- ---------- ---------- ---------
Miscellaneous
Valuation Reserves
1997 $37,740 $ 2,207 $ - $ 4,049 $35,898
1996 39,426 10,261 - 11,947 37,740
1995 29,197 18,719 - 8,490 39,426
(c) The reserves relate primarily to certain inventory and non-rate base properties.
/TABLE
NIAGARA MOHAWK POWER CORPORATION
EXHIBIT INDEX
- -------------
In the following exhibit list, NMPC refers to the Company and
CNYP refers to Central New York Power Corporation, a predecessor
company. 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; and
f--NMPC Annual Report on Form 10-K for year ended December 31,
1995; and
g--NMPC Annual Report on Form 10-K for year ended December 31,
1996.
h--NMPC Quarterly Report on Form 10-Q for quarter ended March 31,
1993; and
i--NMPC Quarterly Report on Form 10-Q for quarter ended September
30, 1993; and
j--NMPC Quarterly Report on Form 10-Q for quarter ended June 30,
1995; and
k--NMPC Quarterly Report on Form 10-Q for quarter ended September
30, 1996;
l--NMPC Quarterly Report on Form 10-Q for quarter ended June 30,
1997; and
m--NMPC Quarterly Report on Form 10-Q for quarter ended September
30, 1997.
n--NMPC Report on Form 8-K dated July 9, 1997; and
o--NMPC Report on Form 8-K dated October 10, 1997.
In accordance with Paragraph 4(iii) of Item 601 (b) of Regulation
S-K, the Company agrees to furnish to the Securities and Exchange
Commission, upon request, a copy of the agreements comprising the
$804 million senior debt facility that the Company completed with
a bank group during March 1996. The total amount of long-term debt
authorized under such agreement does not exceed 10 percent of the
total consolidated assets of the Company and its subsidiaries.
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, as amended February 26,
1998.
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). h 4(b)(82)
4(b)(34) --Supplemental Indenture dated as of
July 1, 1993, supplemental to
Exhibit 4(1). i 4(b)(83)
4(b)(35) --Supplemental Indenture dated as of
September 1, 1993, supplemental to
Exhibit 4(1). i 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). j 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
10-11 --Master Restructuring Agreement, dated as
of July 9, 1997, between the Company and
the sixteen independent power producers
signatory thereto. n 10.28
10-12 --PowerChoice settlement filed with the PSC
on October 10, 1997 o 99-9
*10-13 --PSC Opinion and Order regarding approval of
the PowerChoice settlement agreement with
PSC, issued and effective March 20, 1998.
*10-14 --Preferred Consent, December, 1997
(A)10-15 --NMPC Officers' Incentive Compensation Plan -
Plan Document. b 10-16
(A)10-16 --NMPC Long Term Incentive Plan - Plan
Document. l 10-1
(A)10-17 --NMPC Management Incentive Compensation Plan -
Plan Document. b 10-17
(A)10-18 --CEO Special Award Plan. l 10-2
(A)10-19 --NMPC Deferred Compensation Plan. d 10-16
*(A)10-20 --Amendment to NMPC Deferred Compensation Plan
(A)10-21 --NMPC Performance Share Unit Plan. d 10-17
(A)10-22 --NMPC 1992 Stock Option Plan. d 10-18
(A)10-23 --NMPC 1995 Stock Incentive Plan f 10-31
(A)10-24 --Employment Agreement between NMPC and
David J. Arrington, Sr. Vice President,
Human Resources, dated December 20, 1996. g 10-17
(A)10-25 --Employment Agreement between NMPC and
Albert J. Budney, Jr., President and
Chief Operating Officer, December 20, 1996. g 10-18
(A)10-26 --Employment Agreement between NMPC and William
E. Davis, Chairman of the Board and Chief
Executive Officer, dated December 20, 1996. g 10-19
(A)10-27 --Employment Agreement between NMPC and
Darlene D. Kerr, Sr. Vice President,
Energy Distribution, dated
December 20, 1996. g 10-20
(A)10-28 --Employment Agreement between NMPC and
Gary J. Lavine, Sr. Vice President,
Legal and Corporate Relations, dated
December 20, 1996. g 10-21
(A)10-29 --Employment Agreement between NMPC and
John W. Powers, Sr. Vice President,
and Chief Executive Officer, dated
December 20, 1996. g 10-22
(A)10-30 --Employment Agreement between NMPC and
B. Ralph Sylvia, Executive Vice
President, Electric Generation and
Chief Nuclear Officer, dated
December 20, 1996. g 10-23
(A)10-31 --Employment Agreement between NMPC and
Theresa A. Flaim, Vice President -
Corporate Strategic Planning, dated
December 20, 1996. g 10-24
(A)10-32 --Employment Agreement between NMPC and
Steven W. Tasker, Vice President -
Controller, dated December 20, 1996. g 10-25
(A)10-33 --Employment Agreement between NMPC and
Kapua A. Rice, Corporate Secretary,
dated December 20, 1996. g 10-26
(A)10-34 --Amendment to Employment Agreement between
NMPC and David J. Arrington, Albert J.
Budney, Jr., William E. Davis, Darlene D.
Kerr, Gary J. Lavine, John W. Powers and
B. Ralph Sylvia, dated June 9, 1997. l 10-3
(A)10-35 --Employment Agreement between NMPC and
William F. Edwards, dated September 25, 1997. m 10-4
*(A)10-36 --Employment Agreement between NMPC and
John H. Mueller, dated January 19, 1998.
(A)10-37 --Deferred Stock Unit Plan for Outside Directors g 10-27
*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.
*27 -- Financial Data Schedule.
- -------------------------
(A) Management contract or compensatory plan or arrangement required to be filed as an
exhibit pursuant to Item 601 of Regulation S-K.
/TABLE
1 Exhibit 3(b)
BY-LAWS
NIAGARA MOHAWK POWER CORPORATION
ADOPTED JANUARY 5, 1950
(As Amended February 26, 1998)
2
BY-LAWS
NIAGARA MOHAWK POWER CORPORATION
ADOPTED JANUARY 5, 1950
(As Amended February 26, 1998)
Index*
Page Page
Additional Officers 14 Officers 11
Adjournments 4 Place of Meeting 3
Amendments 20 President 12
Annual Meeting 2 Procedure 4,9,11,20
Assistant Officers 13,14 Proxies 6
Audit Committee 10 Quorum 4,9
Bonds 15 Record Date 18
Certificate of Stock 17 Registrar 17
Chairman of the Board 12 Resignation 7
Committees 9 Scrip 19
Compensation 8,15 Secretary 13
Controller 13 Special Meetings 3
Corporate Charter 1 Stock 17
Corporate Seal 20 Stockholders' Meetings 2
Directors 6 Term of Office 6,12
Directors' Meetings 8 Transfer Agent 17
Election 2,6,12,20 Transfers of Shares 18
Executive Committee 10 Treasurer 14
Finance Committee 10 Unanimous Written Consent 11
Finances 19 Vacancies 7
Fiscal Year 20 Vice Presidents 13
General Provisions 19 Voting 5
Indemnification; Insurance 15,17
Inspectors of Election 5
Lost Stock Certificates 19
Notices of Meetings 3,8,11
/TABLE
*This Index does not constitute part of the By-Laws or have any
bearing upon the interpretation of their terms and provisions.
3
BY-LAWS OF NIAGARA MOHAWK POWER CORPORATION
ARTICLE I
BY-LAWS SUPPLEMENT CORPORATE CHARTER
Section 1. Corporate Charter: The provisions of these by-laws
supplement the corporate charter. The provisions of the latter
shall govern over the provisions of these by-laws in the event of
any conflict. Elections of directors and meetings of stockholders
in addition to those provided by these by-laws may be held in
accordance with the provisions of the corporate charter. The term
"corporate charter" as used in these by-laws includes the
Certificate of Consolidation of Antwerp Light and Power Company,
Baldwinsville Light and Heat Company of Baldwinsville, N.Y., Fulton
Fuel and Light Company, Fulton Light, Heat and Power Company,
Malone Light and Power Company, Northern New York Utilities, Inc.,
The Norwood Electric Light and Power Company, Peoples Gas and
Electric Company of Oswego, St. Lawrence County Utilities, Inc.,
St. Lawrence Valley Power Corporation, The Syracuse Lighting
Company, Inc., and Utica Gas and Electric Company forming Niagara
Hudson Public Service Corporation, filed in the Department of State
of the State of New York on July 31, 1937, all certificates
supplemental thereto or amendatory thereof or in restatement
thereof filed in the Department of State of the State of New York
(including specifically but without limitation among all such
supplemental or amendatory certificates heretofore filed or
hereafter to be filed, the Certificate of Change of Name of Niagara
Hudson Public Service Corporation to Central New York Power
Corporation, filed in the Department of State of the State of New
York on September 15, 1937, the Certificate of Consolidation of New
York Power and Light Corporation and Buffalo Niagara Electric
Corporation and Central New York Power Corporation which is to
survive the consolidation and be named Niagara Mohawk Power
Corporation Pursuant to Sections 26-a and 86 of the Stock
Corporation Law and to Subdivision 4 of Section 11 of the
Transportation Corporations Law, filed in the Department of State
of the State of New York on January 5, 1950, and the Certificate of
Amendment of Certificate of Incorporation of Niagara Mohawk Power
Corporation Pursuant to Sections 26-a and 36 of the Stock
4
Corporation Law, filed in the Department of State of the State of New York
on January 5, 1950), and includes also all resolutions of the board of
directors fixing the designations, preferences, privileges and voting powers
of any series of stock of the corporation, and all other instruments which
are binding upon, and define or set forth the rights of, the stockholders
of the corporation.
ARTICLE II
MEETINGS OF STOCKHOLDERS
Section 1. Annual Meeting: The annual meeting of the stockholders
of the corporation for the election of directors and the
transaction of such other business as may properly come before it
shall be held at such date and time as may be designated by the Board of
Directors.
Business properly brought before any such annual meeting shall
include matters specifically set forth in the corporation's proxy
statement with respect to such meeting, matters which the Chairman
of the Board of Directors in his sole discretion causes to be
placed on the agenda of any such annual meeting and (i) any
proposal of a stockholder of this corporation and (ii) any
nomination by a stockholder of a person or persons for election as
director or directors, if such stockholder has made a written
request to this corporation to have such proposal or nomination
considered at such annual meeting, as provided herein, and further
provided that such proposal or nomination is otherwise proper for
consideration under applicable law and the certificate of
incorporation and by-laws of the corporation.
Notice of any proposal to be presented by any stockholder or of the
name of any person to be nominated by any stockholder for election
as a director of the corporation must be received by the secretary
of the corporation at its principal executive office not less than
60 nor more than 90 days prior to the date of the annual meeting;
provided, however, that if the date of the annual meeting is first
publicly announced or disclosed (in a public filing or otherwise)
less than 70 days prior to the date of the meeting, such notice
shall be given not more than ten days after such date is first so
announced or disclosed. Public notice shall be deemed to have been
5
given more than 70 days in advance of the annual meeting if the
corporation shall have previously disclosed, in these by-laws or
otherwise, that the annual meeting in each year is to be held on a
determinable date, unless and until the Board of Directors determines to
hold the meeting on a different date.
Any stockholder who gives notice of any such proposal shall deliver
therewith the text of the proposal to be presented and a brief
written statement of the reasons why such stockholder favors the
proposal and setting forth such stockholder's name and address, the
number and class of all shares of each class of stock of the
corporation beneficially owned by such stockholder and any material
interest of such stockholder in the proposal (other than as a
stockholder).
Any stockholder desiring to nominate any person for election as a
director of the corporation shall deliver with such notice a
statement in writing setting forth the name of the person to be
nominated, the number and class of all shares of each class of
stock of the corporation beneficially owned by such person, the
information regarding such person required by paragraphs (a), (e)
and (f) of Item 401 of Regulation S-K adopted by the Securities and
Exchange Commission (or the corresponding provisions of any
regulation subsequently adopted by the Securities and Exchange
Commission applicable to the corporation), such person's signed
consent to serve as a director of the corporation if elected, such
stockholder's name and address and the number and class of all
shares of each class of stock of the corporation beneficially owned
by such stockholder. As used herein, shares "beneficially owned"
shall mean all shares as to which such person, together with such
person's affiliates and associates (as defined in Rule 12b-2 under
the Securities Exchange Act of 1934), may be deemed to beneficially
own pursuant to Rules 13d-3 and 13d-5 under the Securities Exchange
Act of 1934, as well as all shares as to which such person,
together with such person's affiliates and associates, has the
right to become the beneficial owner pursuant to any agreement or
understanding, or upon the exercise of warrants, option or rights
to convert or exchange (whether such rights are exercisable
immediately or only after the passage of time or the occurrence of
conditions).
The person presiding at the meeting, in addition to making any
other determinations that may be appropriate to the conduct of the
meeting, shall determine whether such notice has been duly given
6
and shall direct that proposals and nominees not be considered if
such notice has not been so given.
Section 2. Special Meetings: Special meetings of the stockholders
of the corporation may be called at any time by a majority of the
entire board of directors or by the Chairman of the Board or the
President. Such request shall state the purpose or purposes of the
proposed meeting.
Special meetings of stockholders for the election of directors in
accordance with the provisions of the corporate charter providing
for a special election of directors in the event of default in the
payment of dividends on the preferred stock or preference stock for
a specified period and on the termination of such default may be
called as provided in the corporate charter.
Section 3. Place and Notice of Stockholders' Meetings: Meetings of
Stockholders shall be held at the principal office of the
corporation in the City of Syracuse, New York, or at such other
place or places in the State of New York as may be determined from
time to time by the board of directors. For meetings other than annual
meetings, the notice shall also state by and at whose direction and for
what purpose or purposes the meeting is called. If the manner of giving
notice of the meeting is not specified by law or the corporate
charter, notice shall be given by mailing, postage prepaid, not
less than ten (10) nor more than sixty (60) days before such
meeting, a copy of the notice of such meeting, stating the purpose
or purposes for which the meeting is called and the time when and
the place where it is to be held, to each stockholder of record on the
record date established pursuant to Article VII, Section 4 entitled to
vote at the meeting at his address as it appears on the stock book
of the corporation, unless he shall have filed with the Secretary
of the corporation a written request that notices intended for him
be mailed to some other address, in which case it shall be mailed
to the address designated in such request. If, at any meeting,
action is proposed to be taken which would, if taken, entitle shareholders
fulfilling the requirements of Section 623 of the New York Business
Corporation Law to receive payment for their shares, the notice of
such meeting shall also include a statement to that effect.
7
Section 4. Business at Stockholders' Meetings: Business transacted
at all meetings of stockholders shall be confined to the objects
stated in the notice of the meeting and matters germane thereto.
In the absence of fraud, the determination of the holders of a
majority of the stock present in person or by proxy and entitled to
vote at the meeting shall be conclusive as to whether any proposed
action or proceeding at such meeting is within the scope of the notice of
such meeting.
Section 5. Procedure: The order of business and all other matters
of procedure at every meeting of stockholders may be determined by
the presiding officer.
Section 6. Quorum: Except as otherwise provided by law or in the
corporate charter, the presence of a majority of the holders of
shares, in person or by proxy, entitled to vote thereat shall
constitute a quorum at any shareholders' meeting.
Section 7. Adjournments: Except as otherwise provided by the
corporate charter, the stockholders entitled to vote who are
present in person or by proxy at any meeting of stockholders,
whether or not a quorum shall be present or represented at the
meeting, shall have power by a majority vote to adjourn the meeting
from time to time without further notice other than announcement at
the meeting, unless the board of directors shall fix a new record
date in respect of such adjourned meeting, in which case the
provisions of Section 3 of this Article shall apply. At any
adjourned meeting at which the requisite amount of voting stock shall be
present in person or by proxy any business may be transacted which might
have been transacted at the meeting as originally called, and the
stockholders entitled to vote at the meeting as originally called, and no
others, unless the board of directors shall have fixed a new record date
in respect thereof, shall be entitled to vote at such adjourned meeting.
Section 8. Voting: Whenever an action shall require the vote of
stockholders, the tabulations that identify the particular vote of
a stockholder on all proxies, consents, authorizations and ballots
shall be kept confidential, except as disclosure may be required
8
(i) by applicable law, (ii) in pursuit or defense of legal
proceedings, (iii) to resolve a bona fide dispute as to the
authenticity of one or more proxies, consents, authorizations or
ballots or as to the accuracy of any tabulation of such proxies,
consents, authorizations or ballots, (iv) if an individual
stockholder requests that his or her vote and identity be forwarded
to the corporation, or (v) in the event of a proxy or consent
solicitation in opposition to the solicitation of the Board of
Directors of the corporation; and the receipt and tabulation of such votes
will be by an independent third party not affiliated with the corporation.
Comments written on proxies, consents, authorizations and ballots, will be
transcribed and provided to the secretary of the corporation
without reference to the vote of the stockholder, except where such
stockholder has requested that the nature of their vote be forwarded to
the corporation.
Stockholders shall have such voting rights as may be granted by law
and the provisions of the corporate charter. All questions
presented to stockholders for decision shall be decided by a vote
of shares. Voting may be viva voce unless a stockholder present in
person or by proxy and entitled to vote at the meeting shall demand
a vote by ballot in which event a vote by ballot shall be taken.
Except where otherwise provided by law, the corporate charter or
these by-laws, elections shall be determined by a plurality vote
and all other questions that shall be submitted to stockholders for
decision shall be decided by a majority of the votes cast.
Section 9. Inspectors of Election: Two inspectors of election who
are not employees or directors of the corporation, shall be
appointed by the directors to serve at each meeting of
stockholders, or of a class of stockholders, such inspectors to
serve at such meeting and any adjournments thereof; and such
inspectors shall have authority to count and report upon the votes
cast at such meeting upon the election of directors and such other
questions as may be voted upon by ballot. In the event that any
such inspector of election shall not have been appointed by the
directors to serve at such meeting, or, having been appointed,
shall be absent from such meeting or adjournment or unable to serve
thereat, such inspector shall be appointed by the presiding officer
at such meeting or adjournment.
The inspectors appointed to act at any meeting of stockholders,
before entering upon the discharge of their duties, shall be sworn
9
faithfully to execute the duties of inspectors at such meeting with
strict impartiality and according to the best of their ability, and
the oath so taken shall be subscribed by them and shall be filed in
the records of such meeting.
The inspectors shall be responsible for determining the number of
shares outstanding, the voting power of each, the shares
represented at the meeting, the existence of a quorum, and the
validity and effect of any proxies. They shall also receive and
tabulate all votes, ballots or consents and determine the result of
any election, hear and determine all challenges and questions arising in
connection with any election and do such acts to conduct the election
according to the applicable provisions of law of the State of New York.
Section 10. Proxies: Each stockholder entitled to vote at any
meeting of stockholders may be represented and vote at such meeting
by his proxy, authorized and acting in manner as provided by the
applicable laws of the State of New York. No proxy shall be valid
after the expiration of eleven (11) months from the date of its execution
unless otherwise provided in the proxy in accordance with law.
ARTICLE III
DIRECTORS
Section 1. Number and Qualifications: Except as otherwise required
by the provisions of the corporate charter relating to the rights
of the holders of any class or series of preferred or preference
stock having a preference over the common stock as to dividends or
to elect directors under specified circumstances, the board of directors
shall consist of not less than nine (9) nor more than twenty-one
(21) persons, the exact number initially to be fifteen (15)
persons, subject to change from time to time to any number not less
than nine (9) nor more than twenty-one (21) persons by the board of
directors pursuant to a resolution adopted by a majority of the
total number of authorized directors (whether or not there exist
10
any vacancies in previously authorized directorships at the time
any such resolution is presented to the board for adoption). Directors
need not be stockholders. No person, other than those serving on
November 11, 1976, who has reached age 70 shall stand for election as a
director.
Section 2. Election and Tenure of Office: Except as otherwise
provided by law, the corporate charter or these by-laws, the
directors of the corporation shall be elected at the annual meeting
of the stockholders or at any meeting of the stockholders held in
lieu of such annual meeting, which meeting, for the purposes of
these by-laws, shall be deemed the annual meeting. The directors
shall be classified, with respect to the time for which they
severally hold office into three classes, as nearly equal in number
as possible, one class to hold office initially for a term expiring at
the annual meeting of stockholders to be held in 1989, another class to
hold office initially for a term expiring at the annual meeting of
stockholders to be held in 1990, and another class to hold office
initially for a term expiring at the annual meeting of stockholders
to be held in 1991, with the members of each class to hold office
until their successors are elected and qualified. At each annual
meeting of the stockholders of the corporation, the successors to
the class of directors whose terms expire at that meeting shall be
elected, to hold office until the annual meeting of stockholders
held in the third year following the year of their election.
Except as otherwise provided in the corporate charter, the directors
shall hold office until the annual meeting at which their respective
terms expire and until their successors are elected and have
qualified. The election of directors shall be conducted by two
inspectors of election appointed as hereinbefore provided. The
election need not be by ballot and shall be decided by a plurality
vote.
Section 3. Resignation; Removal: Any director of the corporation
may resign at any time by giving his resignation to the chief
executive officer of the corporation, or to the Secretary. Such
resignation shall take effect at the time specified therein; and,
unless otherwise specified therein, the acceptance of such resignation
11
shall not be necessary to make it effective. Subject to the rights
of the holders of any class or series of preferred or preference
stock having preference over the holders of common stock as to
dividends or to elect directors under specified circumstances, any
director, or the entire board of directors, may be removed from office
at any time, but only for cause.
Section 4. Vacancies: Except as otherwise provided by the corporate
charter, if the office of any director becomes vacant for any
reason, a majority of the directors then in office, whether or not
such majority shall constitute a quorum, may choose a successor
who, to the extent required by New York law, shall hold office until
the next annual meeting of stockholders at which the election of directors
is in the regular order of business and until his successor has been
elected and qualified; provided that if New York law does not so require,
such director shall hold office for the full unexpired term of the
director whose seat he is filling, or any such vacancy in the board of
directors may be filled by the stockholders entitled to vote at any
meeting of stockholders, notice of which shall have referred to the
proposed election.
Except as otherwise provided by the corporate charter, in the event
of an increase in the number of directors pursuant to Section 1 of
this Article III, a majority of the directors then in office,
whether or not such majority shall constitute a quorum, may elect
the additional director or directors who to the extent required by
New York law, shall hold office until the next annual meeting of
stockholders at which the election of directors is in the regular
order of business and until his successor has been elected and
qualified; provided that if New York law does not so require, such
director or directors shall hold office for the full unexpired term
of the class of directors to which such director or directors is
elected, or any such director or directors may be elected by the
12
stockholders entitled to vote at any meeting of stockholders,
notice of which shall have referred to the proposed election. No
decrease in the number of authorized directors constituting the
entire board of directors shall shorten the term of any incumbent
director.
Section 5. Compensation: Members of the board of directors shall be
entitled to compensation for service and the board of directors may
assign duties to any member or members of the board and may fix the
amount of compensation therefor, which shall be a charge to be paid
by the corporation. The board of directors may elect or appoint
members of the board as officers, members of committees, or agents
of the corporation, may assign duties to be performed and may fix
the amount of the respective salaries, fees or other compensation
therefor, and the amount so fixed shall be a charge to be paid by
the corporation. In addition to any other compensation provided
pursuant to these by-laws, each director shall be entitled to
receive a fee, in amount as fixed from time to time by resolution
of the board of directors, for attendance at any meeting of the
board, or of any committee of the board, together with his expenses of
attendance, if any.
Section 6. Meetings of Directors: Regular meetings of the board of
directors shall be held at such times and at such places as may be
determined by the board of directors, or by the Chairman of the Board or
by the President. Special meetings of the board may be called from time
to time by any three directors, or by the Chairman of the Board or by the
President.
Any action required or permitted to be taken by the board or any
committee thereof may be taken without a meeting if all board or
committee members file one or more written consents to a resolution
authorizing the action with the respective minutes of the board or
committee as the case may be.
Any one or more members of the board or of any of its committees
may participate in a meeting of the board or committee by
conference telephone or similar communications equipment allowing
13
all participants in the meeting to hear each other at the same time.
Participation by such means shall constitute presence at a meeting.
Section 7. Notice of Meetings of Board of Directors: Notice of each
meeting of the board of directors, stating the time and place
thereof, shall be given to each member of the board by the Secretary, or an
Assistant Secretary, by mailing the same, postage prepaid, addressed to
each member of the board at his residence to usual place of business not
less than three (3) days before the meeting, or by delivering the same to
each member of the board personally or to his residence or usual place of
business, or by sending the same by telegraph or facsimile transmission
to his residence or usual place of business, not less than one (1) day
before the meeting. Meetings of the board of directors may also be held
at any time and place without notice provided all the members are present at
such meeting without protest or, at any time before or after the meeting,
shall sign a written waiver of notice. The notice of any meeting of the
board of directors need not specify the purpose or purposes for which the
meeting is called, except as otherwise expressly provided in these
by-laws.
Section 8. Quorum: At all meetings of the board of directors, except
where otherwise provided by law, the corporate charter, or these by-laws, a
quorum shall be required for the transaction of business and shall consist
of not less than one-third of the entire board, if the number of members
be more than nine (9), but not less than a majority, if the number of
directors be less than nine (9); and the vote of a majority of the
directors present shall decide any questions that may come before the
meeting. A majority of the directors present at any meeting, although
less than a quorum, may adjourn the same from time to time, without
notice other than announcement at the meeting, until a quorum is present.
Section 9. Procedure: The order of business and all other matters
of procedure at every meeting of directors may be determined by the
presiding member.
14
ARTICLE IV
COMMITTEES OF DIRECTORS
Section 1. Designation: The board of directors, by resolution or
resolutions adopted by a majority of the entire board, shall
designate an Executive Committee, an Audit Committee and a Finance
Committee, and may designate one or more other committees, each
committee to consist of three (3) or more directors of the
corporation. In the interim between meetings of the board, the
Executive Committee shall have and may exercise the powers of the
board of directors granted by the corporate charter and these
by-laws and by resolution of the board, and such other committees
shall have only such powers as shall be granted by these by-laws
and by resolution of the board; provided, however, that no committee shall
have authority as to the following matters:
(a) The submission to shareholders of any action that needs
shareholders' approval by law;
(b) The filling of vacancies in the board of directors or in any
committee;
(c) The fixing of compensation of the directors for serving on the
board or on any committee;
(d) The amendment or repeal of the by-laws, or the adoption of new
by-laws; or
(e) The amendment or repeal of any resolution of the board which,
by its terms, shall not be so amendable or repealable.
Each committee shall serve at the pleasure of the board of
directors and shall have such name or names as may be determined
from time to time by the by-laws or by resolution or resolutions
adopted by the board of directors. Except as otherwise required by
law, the existence of any such committee may be terminated, or its
powers and authority modified, at any time by resolution of the
board of directors.
15
Section 2. Executive Committee: When the board of directors is not
in session, the Executive Committee shall have all of the authority
of the board of directors, except it shall have no authority as to
the matters specified in Section 1 of this Article IV. The
Chairman of the Board shall be Chairman of the Executive Committee. The
members of the Executive Committee shall serve at the pleasure of
the board of directors.
Section 3. Audit Committee: The Audit Committee shall recommend to
the board of directors the accounting firm to be selected by the
board or to be recommended by it for shareholder approval, as
independent auditor of the corporation and its subsidiaries; act on
behalf of the board in meeting and reviewing with the independent
auditors, the chief internal auditor and the appropriate corporate
officers matters relating to corporate financial reporting and
accounting procedures and policies, adequacy of internal controls
and the scope of the respective audits of the independent auditors
and the internal auditor; review the results of such audits with
the respective auditing agency and reporting thereon to the board;
review and make recommendations to the board concerning the
independent auditor's fees and services; review interim and annual
financial reports and disclosures and submit to the board any
recommendations it may have from time to time with respect to
financial reporting and accounting practices and policies; be
consulted, and its consent obtained, prior to the selection or
termination of the chief internal auditor; oversee matters
involving compliance with Corporate business ethics policies
including the work of the Business Ethics Council; review
management's assessment of financial risks; authorize special
investigations and studies, as appropriate, in fulfillment of its
function as specified herein or by resolution of the board of
directors; and perform any other duties or functions deemed
appropriate by the board of directors. The Committee will conduct
a self-assessment at least every three years of its performance in
relation to its powers and responsibilities. The membership of
such committee shall consist only of directors of the corporation who
are not, and have not been, officers of the company.
Section 4. Finance Committee: The Finance Committee shall exercise
such powers of the board of directors as shall be provided in one
16
or more resolutions of the board of directors with respect to the
issuance by the corporation of securities and evidences of
indebtedness and the participation by the corporation in other
financing transactions and with respect to the authorization of the
making, modification, alteration, termination or abrogation of
notes, bills, mortgages, sales, deeds, financing leases, liens and
contracts of the corporation and shall further be empowered to take
any action in connection with the determination of the terms of any
securities, evidences of indebtedness or other financing transactions of
the corporation the issuance of which by the corporation or the
participation in which by the corporation shall have theretofore been
approved by the board of directors, and shall further perform any other
duties or functions deemed appropriate by the board of directors.
Section 5. Records and Procedure: Said committees shall keep
regular minutes of their proceedings and report the same to the
board when required. Unless otherwise determined by the board of
directors each committee may appoint a chairman and a secretary and
such other officers of the committee as it may deem advisable, may
determine the time and place of holding each meeting of the
committee, the notice of meetings to be given to members, and all
other procedural questions which may arise in connection with the
work of the committee.
Section 6. Unanimous Written Consent: Any action authorized in writing,
by all of the members of a committee, and filed with the minutes of the
corporation shall be the act of that committee with the same force and
effect as if the same had been passed by unanimous vote at a duly called
meeting of such committee.
Section 7. Notice: Unless otherwise provided by resolution of the board
of directors or by a vote of a majority of the members of the relevant
committee, notice of committee meetings shall be given in the same manner
as notice of special meetings of the board of directors is to be given
under Article III, Section 7 of the By-Laws.
ARTICLE V
OFFICERS
Section 1. Officers: The officers of the corporation shall consist
of a Chairman of the Board, a President, one or more Vice-Presidents, a
Secretary, a Controller, a Treasurer, and such Assistant Secretaries,
Assistant Controllers and Assistant Treasurers and other officers as
shall be elected or appointed by the board of directors. The board
of directors may elect or appoint a General Counsel upon such terms
and with such powers and duties as it may prescribe and may also
designate the General Counsel an officer of the corporation.
Section 2. Election: The officers of the corporation shall be
17
elected or appointed by the board of directors at the meeting of
the board held after each annual meeting of the stockholders. The
Chairman of the Board and the President shall be elected or
appointed by the board of directors from among their number. Any
number of Vice-Presidents, the Secretary, the Controller, the Treasurer
and other officers established pursuant to resolution of the board of
directors shall also be elected or appointed by the board of directors.
Section 3. Term of Office: The officers of the corporation shall
hold office until the meeting of the board of directors held after
the next annual meeting of the stockholders and until their
successors are elected and have qualified, unless a shorter term is
fixed or unless removed, subject to the provisions of law, by the
board of directors. The Chairman of the Board, the President, any
Vice President, the Secretary, the Controller or the Treasurer may
be removed at any time, with or without cause, by the board of
directors provided that notice of the meeting at which such action
shall have been taken shall set forth such action as one of the
purposes of such meeting. Any other officer of the corporation may
be removed at any time, with or without cause, by the board of
directors. If the office of any officer becomes vacant for any
reason, the vacancy may be filled by the board of directors at any
time to serve the remaining current term of that office.
Section 4. Chairman of the Board: There shall be a chairman of the
Board of Directors, with the official title "Chairman of the
Board", who shall be the chief executive officer of the
corporation. The Chairman of the Board shall preside at meetings
of the stockholders, the board of directors and the Executive Committee.
He shall recommend to the board policies to be followed by the corporation,
and, subject to the board, shall have general charge of the
policies and business of the corporation and general supervision of
the details thereof, and shall supervise the operation, maintenance
and preservation of the properties of the corporation. He shall
keep the board of directors informed respecting thebusiness of the
corporation. He shall have authority to sign on behalf of the
corporation all contracts and other documents or instruments to be
signed or executed by the corporation, and, in all cases where the
18
duties and powers of subordinate officers and agents of the
corporation are not specifically prescribed by the by-laws or by
resolutions of the board of directors, the Chairman of the Board
may prescribe such duties and powers. He shall perform such other
duties as may from time to time be assigned to him by the board of
directors.
Section 5. The President: The President shall have the direction of
and responsibility for the operations of the corporation and such
other powers and duties as the board of directors or the Chairman
of the Board shall designate from time to time and, in the absence
or inability to act of the Chairman of the Board, shall have the
powers and duties of the Chairman of the Board. The President,
unless some other person is thereunto specifically authorized by
vote of the board of directors, shall have authority to sign all
contracts and other documents and instruments of the corporation.
Section 6. The Vice-Presidents: The Vice-Presidents may be
designated by such title or titles and in such order of seniority
as the board of directors may determine. The Vice-Presidents shall
perform such of the duties and exercise such of the powers of the
President on behalf of the corporation as may be assigned to them
respectively from time to time by the board of directors or by the
Chairman of the Board or the President, and, subject to the control
of the board, shall have authority to sign on behalf of the
corporation all contracts and other documents or instruments
necessary for the conduct of the business of the corporation. The
Vice-Presidents shall perform such other duties as may from time to
time be assigned to them respectively by the board of directors or the
Chairman of the Board or the President.
Section 7. The Secretary and Assistant Secretaries: The Secretary
shall cause notices of all meetings of stockholders and directors
to be given as required by law, the corporate charter, and these
by-laws. He shall attend all meetings of stockholders and of the
board of directors and keep the minutes thereof. He shall affix
the corporate seal to and sign such instruments as require the seal
and his signature and shall perform such other duties as usually
pertain to his office or as are required of him by the board of directors
or the Chairman of the Board or the President.
19
Any Assistant Secretary may, in the absence or disability of the
Secretary, or at his request, perform the duties and exercise the
powers of the Secretary, and shall perform such other duties as the
board of directors, the Chairman of the Board, the President or the
Secretary shall prescribe.
The Secretary or any Assistant Secretary may certify under the
corporate seal as to the corporate charter or these by-laws or any
provision thereof, the acts of the board of directors or any
committee thereof, the tenure, signatures, identity and acts of
officers of the corporation or other corporate facts, and any such
certificate may be relied upon by any person or corporation to whom
the same shall be given until receipt of written notice to the
contrary.
In the absence of the Secretary and of an Assistant Secretary, the
stockholders or the board of directors may appoint a secretary pro
tem to record the proceedings of their respective meetings and to
perform such other acts pertaining to said office as they may
direct.
Section 8. The Controller and Assistant Controllers: The Controller
shall be the chief accounting officer of the corporation. He shall
have general supervision of the accounting and financial reporting
policies of the corporation, and shall recommend policies and
procedures and shall render current and periodic reports of
financial status to the Chairman of the Board, the President and
the board of directors. He shall perform such other duties as
usually pertain to his office or as are required of him by the
board of directors or the Chairman of the Board or the President.
Any Assistant Controller may, in the absence or disability of the
Controller, or at his request, perform the duties and exercise the
powers of the Controller and shall perform such other duties as the
board of directors, the Chairman of the Board, the President or the
Controller shall prescribe.
Section 9. The Treasurer and Assistant Treasurers: The Treasurer is
authorized and empowered to receive and collect all moneys due the
corporation and to receipt for the same. He shall be empowered to
execute on behalf of the corporation all instruments, agreements
20
and certificates necessary or appropriate to effect the issuance by
the corporation of securities or evidences of indebtedness or to permit
the corporation to enter into and perform any other financing
transactions to the extent the foregoing are within the ordinary
course of business of the corporation or have been authorized by
the board of directors or a committee thereof. He shall cause to
be entered in books of the corporation to be kept for that purpose
full and accurate accounts of all moneys received by and paid on
account of the corporation. He shall make and sign such reports,
statements, and instruments as may be required of him by the board
of directors or by laws of the United States or the State of New
York, or by commission, bureau, department or agency created under
any such laws, and shall perform such other duties as usually
pertain to his office or as are required of him by the board of
directors or the Chairman of the Board or the President.
Any Assistant Treasurer may, in the absence or disability of the
Treasurer, or at his request, perform the duties and exercise the
powers of the Treasurer and shall perform such other duties as the
board of directors, the Chairman of the Board, or the President,
or the Treasurer shall prescribe.
Section 10. Additional Officers: In addition to the officers
provided for by these by-laws, the board of directors may, from
time to time, designate and appoint such other officers as may be
necessary or convenient for the transaction of the business and
affairs of the corporation. Such other officers shall have such powers
and duties as may be assigned to them by resolution of the board of
directors.
Section 11. Officers Holding Two or More Offices: Any two or more
of the above-mentioned offices may be held by the same person,
except that the President shall not also be the Secretary, but no officer
shall execute or verify any instrument in more than one capacity if
such instrument be required by law or otherwise to be executed or
verified by any two or more officers.
Section 12. Duties of Officers May be Delegated: In case of the
absence of any officer of the corporation, or for any other reason
21
that the board of directors may deem sufficient, the board of
directors may delegate, for the time and to the extent specified,
the powers or duties of any officer to any other officer, or to any
director.
Section 13. Compensation: The compensation of all officers with an
assigned salary level above the scale of Salary Level 20 as
prescribed in the Salary Administration Program, as adopted by the
board of directors, shall be fixed by the board of directors. The
compensation of all other officers and employees shall be fixed by
the Chairman of the Board or by the President in accordance with
the Salary Administration Program.
Section 14. Bonds: The board of directors may require any officer,
agent or employee of the corporation to give a bond to the
corporation, conditional upon the faithful performance of his
duties, with one or more sureties and in such amount as may be
satisfactory to the board of directors. The premium payable to any
surety company for such bond shall be paid by the corporation.
ARTICLE VI
INDEMNIFICATION OF DIRECTORS AND OFFICERS; INSURANCE
Section 1. Indemnification: The corporation shall fully indemnify,
to the extent not expressly prohibited by law, each person involved
in, or made or threatened to be made a party to, any action, claim
or proceeding, whether civil or criminal, including any
investigative, administrative, legislative, or other proceeding,
and including an action by or in the right of the corporation or
any other corporation, or any partnership, joint venture, trust,
employee benefit plan, or other enterprise, and including appeals
therein (any such action or proceeding being hereinafter referred to as
a "Matter"), by reason of the fact that such person, such person's
testator or intestate (i) is or was a director or officer of the
corporation, or (ii) is or was serving, at the request of the
corporation, as a director, officer, or in any other capacity, any
other corporation, or any partnership, joint venture, trust,
employee benefit plan, or other enterprise, against any and all
22
judgments, fines, penalties, amounts paid in settlement, and expenses,
including attorneys' fees, actually and reasonably incurred as a
result of or in connection with any Matter, except as provided in
the next paragraph.
No indemnification shall be made to or on behalf of any such person
if a judgment or other final adjudication adverse to such person
establishes that such person's acts were committed in bad faith or
were the result of active and deliberate dishonesty and were
material to the cause of action so adjudicated, or that such person
personally gained in fact a financial profit or other advantage to
which such person was not legally entitled. In addition, no
indemnification shall be made with respect to any Matter initiated
by any such person against the corporation, or a director or officer of
the corporation, other than to enforce the terms of this article,
unless such Matter was authorized by the board of directors.
Further, no indemnification shall be made with respect to any
settlement or compromise of any Matter unless and until the corporation has
consented to such settlement or compromise.
In making any determination regarding any person's entitlement to
indemnification hereunder, it shall be presumed that such person is
entitled to indemnification, and the corporation shall have the
burden of proving the contrary.
Written notice of any Matter for which indemnity may be sought by
any person shall be given to the corporation as soon as practicable
and the corporation shall be permitted to participate therein.
Such person shall cooperate in good faith with any request that
common counsel be utilized by the parties to any Matter who are
similarly situated, unless to do so would be inappropriate due to
actual or potential differing interests between or among such
parties.
Section 2. Advancement of Expenses: Except in the case of a Matter
against a director, officer, or other person specifically approved
by the board of directors, the corporation shall, subject to
Section 1 above, pay expenses actually and reasonably incurred by
23
or on behalf of such a person in connection with any Matter in advance
of the final disposition of such Matter. Such payments shall be made
promptly upon receipt by the corporation, from time to time, of a
written demand of such person for such advancement, together with
an undertaking by or on behalf of such person to repay any expenses
so advanced to the extent that the person receiving the advancement
is ultimately found not to be entitled to indemnification for part
or all of such expenses.
Section 3. Rights Not Exclusive: The rights to indemnification and
advancement of expenses granted by or pursuant to this article (i)
shall not limit or exclude, but shall be in addition to, any other
rights which may be granted by or pursuant to any statute,
corporate charter, by-law, resolution, or agreement, (ii) shall be deemed
to constitute contractual obligations of the corporation to any
director, officer, or other person who serves in a capacity
referred to herein at any time while this article is in effect,
(iii) are intended to be retroactive and shall be available with respect
to events occurring prior to the adoption of this article, and (iv)
shall continue to exist after the repeal or modification hereof
with respect to events occurring prior thereto. It is the intent
of this article to require the corporation to indemnify the persons
referred to herein for the aforementioned judgments, fines,
penalties, amounts paid in settlement, and expenses, including
attorneys' fees, in each and every circumstance in which such
indemnification could lawfully be permitted by express provisions
of by-laws, and the indemnification required by this article shall
not be limited by the absence of an express recital of such
circumstances.
Section 4. Authorization of Contracts: The corporation may, with
the approval of the board of directors, enter into an agreement
with any person who is, or is about to become, a director or
officer of the corporation, or who is serving, or is about to
serve, at the request of the corporation, as a director, officer, or
in any other capacity, any other corporation, or any partnership, joint
venture, trust, employee benefit plan, or other enterprise, which agreement
may provide for indemnification of such person and advancement of
24
expenses to such person upon terms, and to the extent, not
prohibited by law. The failure to enter into any such agreement
shall not affect or limit the rights of any such person under this
article.
Section 5. Insurance: The corporation may purchase and maintain
insurance to indemnify the corporation and the directors and
officers within the limits permitted by law.
Section 6. Severability: If any provision of this article is
determined at any time to be unenforceable in any respect, the
other provisions shall not in any way be affected or impaired
thereby.
ARTICLE VII
STOCK
Section 1. Transfer Agent and Registrar: The board of directors may
appoint one or more individuals, banks, firms of bankers, or trust
companies the agent or agents of the corporation for the transfer
of shares of its stock, and may also appoint one or more
individuals, bank, firms of bankers, or trust companies registrar
or registrars for the registering of shares of its stock.
Section 2. Certificate of Stock: The certificates of stock of the
corporation shall be numbered and shall be recorded in the books of
the corporation as they are issued. They shall contain the
holder's name and number of shares and shall be signed by the
Chairman of the Board, the President or a Vice-President and the
Secretary or an Assistant Secretary or the Treasurer or an
Assistant Treasurer, and shall be sealed with the corporate seal,
25
which may be a facsimile. Where any such certificate is signed by
a registrar, the signatures of any such Chairman of the Board,
President, Vice-President, Secretary, Assistant Secretary,
Treasurer or Assistant Treasurer upon such certificate may be
facsimiles. In case any such officer who has signed or whose
facsimile signature has been placed upon such certificate shall
have ceased to be such before such certificate is issued, it may be
issued by the corporation with the same effect as if such officer
had not ceased to be such at the date of its issue. No certificate
of stock shall be valid until countersigned by a transfer agent if
the corporation have a transfer agent for the class or series of
stock represented by such certificate whose signature may be a
facsimile and until registered by a registrar if the corporation
have a registrar for such class or series.
Section 3. Transfers of Shares: Subject to applicable law, shares
of stock shall be transferable on the books of the corporation by
the holder thereof, in person or by duly authorized attorney, upon
the surrender to the corporation or any transfer agent of the
corporation of the certificate representing the shares to be
transferred, duly endorsed or accompanied by proper evidence of
succession, assignment or authority to transfer. The corporation
shall be entitled to treat the holder of record of any share or
shares of stock as the owner thereof and accordingly shall not be
bound to recognize any equitable or other claim to or interest in such
share or shares on the part of any other person whether or not it shall
have express or other notice thereof, save as expressly provided by the
laws of the State of New York. The board of directors, to the extent
permitted by law, shall have power and authority to make all such rules and
regulations as it may deem expedient concerning the issue, transfer, and
registration of certificates of stock.
Section 4. Fixing of Record Date or Closing Transfer Books: The
board of directors may fix a day and hour, not more than sixty (60)
days prior to the day on which any meeting of stockholders is to be
held, as the time as of which stockholders entitled to notice of or
to vote at such meeting and at all adjournments thereof shall be
determined; and in the event such record date is fixed by the board
of directors no one other than the holders of record on such date
of stock entitled to notice of or to vote at such meeting shall be
entitled to notice of or to vote at such meeting, or unless a new
26
record date be fixed as provided in Article II, Section 7 of these by-laws,
any adjournment thereof. The board of directors may at its option, in
lieu of fixing a record date as aforesaid, prescribe a period, not
exceeding sixty (60) days prior to any meeting of stockholders,
during which no transfer of shares on the books of the corporation
may be made.
The board of directors may fix a day and hour, not exceeding sixty
(60) days preceding the date fixed for the payment of a dividend or
the making of any distribution, or for the delivery of evidences or
rights or evidences of interests arising out of any change,
conversion or exchange of stock, as a record time for the
determination of the stockholders, or stockholders of any class or
series, entitled to receive any such dividend, distribution,
rights, or interests, and in such case only stockholders of record
at the time so fixed shall be entitled to receive such dividend,
distribution, rights, or interests, or the board of directors may
at its option prescribe a period, not exceeding sixty (60) days prior
to the date for such payment, distribution or delivery, during
which no transfer of stock on the books of the corporation may be
made.
Section 5. Lost Stock Certificates: The holder of any certificate
representing shares of stock of the corporation shall immediately
notify the corporation of any mutilation, loss, or destruction
thereof, and the board of directors or an officer or officers duly
authorized thereunto by the board of directors may in its or his
discretion authorize one or more new certificates for the same
number of shares in the aggregate to be issued to such holder upon
the surrender of the mutilated certificate, or, in case of loss or
destruction of the certificate, upon satisfactory proof of such
loss or destruction and the deposit of indemnity by way of bond or
otherwise in such form and amount and with such surety or sureties
or security as the board of directors or such officer or officers may
require to protect the corporation against loss or liability by
reason of the issuance of such new certificates; but the board of
directors may in its discretion refuse to issue new certificates
save upon the order of the court having jurisdiction in such
matters.
27
Section 6. Scrip: The board of directors may from time to time
authorize the issuance by the corporation of scrip certificates
representing interests in fractions of a full share of any class or
series of stock of the corporation, and, subject to the provisions
of the corporate charter and applicable provisions of law, shall
have power to prescribe the rights, and the conditions and
limitations thereof, to which the holders of such scrip
certificates shall be entitled in respect of such scrip certificates and
of the interests in shares of stock of the corporation represented thereby,
which rights and the conditions and limitations thereon shall be set
forth therein to the extent required by law. Such scrip
certificates may be issued in registered or bearer form, as the
board of directors may determine.
ARTICLE VIII
GENERAL PROVISIONS
Section 1. Finances: The funds of the corporation shall be
deposited in its name with such bank or banks, firm or firms of
bankers, trust company or trust companies as the board of directors
may from time to time designate. All checks, notes, drafts and
other negotiable instruments of the corporation shall be signed by such
officer or officers, agent or agents, employee or employees or such
other person or persons as may be designated by the board of directors
from time to time by resolution, or by the Chairman of the Board or
the President or the Treasurer in the exercise of authority conferred
by resolution of the board of directors. No officers, agents,
employees of the corporation, or other person, alone or with
others, shall have power to make any checks, notes, drafts or other
negotiable instruments in the name of the corporation or to bind
the corporation thereby, except as in this article provided.
Section 2. Fiscal Year: The fiscal year of the corporation shall be
the calendar year unless otherwise provided by the board of directors.
28
ARTICLE IX
CORPORATE SEAL
Section 1. Form of Seal: The seal of the corporation shall bear the
name of the corporation, the year of its incorporation, and such
appropriate design as the board of directors may approve. The seal
on stock certificates or on any corporate obligation for the
payment of money may be facsimile.
ARTICLE X
AMENDMENTS
Section 1. Procedure: These by-laws may be added to, amended,
altered, or repealed at any meeting of stockholders, notice of
which shall have referred to the proposed action, by the vote of
the holders of record of a majority of the outstanding shares of
the corporation entitled to vote, or, to the extent permitted by
law, at any meeting of the board of directors, notice of which
shall have referred to the proposed action, by the affirmative vote
of a majority of the board of directors.
Section 2. Amendment of By-Law Regulating Election of Directors: If
any by-law regulating an impending election of directors is adopted
or amended or repealed by the board of directors, there shall be
set forth in the notice of the next meeting of stockholders for the
election of directors the by-law so adopted or amended or repealed,
together with a concise statement of the changes made.
EXHIBIT 10-13
- -------------
STATE OF NEW YORK
PUBLIC SERVICE COMMISSION
OPINION NO. 98-8
CASE 94-E-0098 -Proceeding on Motion of the Commission as to the
Rates, Charges, Rules and Regulations of Niagara
Mohawk Power Corporation for Electric Service.
CASE 94-E-0099 -Proceeding on Motion of the Commission as to the
Rates, Charges, Rules and Regulations of Niagara
Mohawk Power Corporation for Electric Street
Lighting Service.
OPINION AND ORDER ADOPTING TERMS
OF SETTLEMENT AGREEMENT SUBJECT
TO MODIFICATIONS AND CONDITIONS
Issued and Effective: March 20, 1998
TABLE OF CONTENTS
- -----------------
INTRODUCTION
General Background
Procedural History
SUMMARY OF THE MRA AND THE SETTLEMENT
EXCEPTIONS
Master Restructuring Agreement
1. Prudence
2. Escrow Account
3. Steam Host and Power
Producer Dealings
4. Third-Party Releases and
Ratemaking Presumptions
5. Discussion and Conclusion
PowerChoice Settlement Provisions
1. The General Public Interest Standard
2. The Settlement's Revenue Decreases
a. Exceptions
b. Replies
c. Discussion
3. The Settlement's Duration
4. Customer Charges
5. Stranded Cost Recovery
a. Exceptions
b. Replies
c. Discussion
TABLE OF CONTENTS
- -----------------
6. Enron/Wepco Rate Proposals
a. Energy Backout Rate
b. Niagara Mohawk Energy Sales to ESCOs
c. Alternative Residential Rate Design
7. Generation Auction Incentives
8. Nuclear Generation Facilities
9. Niagara Mohawk's Identity
and Royalty Payments
a. Use of the Corporate Name
b. Royalty Payments
10. Generic and Case-Specific
Determinations
11. State Environmental Quality
Review Act Findings
12. Other Matters
a. Cost Allocation Manual
Review Procedures
b. Disclosure of Social Security Numbers
c. Future Tax Refunds
d. Residential Hydroelectric Allotments
e. PULP's Legal Arguments
f. Standard Performance Contracts
g. Local Taxes and the CTC
h. Additional Public Comments
i. Recently Settled and Corrected Matters
j. Finch's Exceptions
TABLE OF CONTENTS
- -----------------
k. Recovery of Costs Associated With
Termination of Gas Transportation
and Peak Shaving Agreements
l. Service Quality Incentive
CONCLUSION
ORDER
APPENDICES
STATE OF NEW YORK
PUBLIC SERVICE COMMISSION
COMMISSIONERS:
John F. O'Mara, Chairman
Maureen O. Helmer
Thomas J. Dunleavy
CASE 94-E-0098 -Proceeding on Motion of the Commission as to the
Rates, Charges, Rules and Regulations of Niagara
Mohawk Power Corporation for Electric Service.
CASE 94-E-0099 -Proceeding on Motion of the Commission as to the
Rates, Charges, Rules and Regulations of Niagara
Mohawk Power Corporation for Electric Street
Lighting Service.
OPINION NO. 98-8
OPINION AND ORDER ADOPTING TERMS
OF SETTLEMENT AGREEMENT SUBJECT
TO MODIFICATIONS AND CONDITIONS
(Issued and Effective March 20, 1998)
BY THE COMMISSION:
INTRODUCTION
- ------------
On October 10, 1997, Niagara Mohawk Power Corporation
(Niagara Mohawk or the company) filed a Settlement Agreement
(Settlement) addressing electric rate, corporate structure, and
competitive market matters. In addition to the company, the
Settlement was executed by Department of Public Service Staff
(Staff); the Settling Independent Power Producers (SIPPs); the
Independent Power Producers of New York, Inc. (IPPNY);
Sithe/Independence Power Partners, L.P.; Multiple Intervenors (MI);
the Steam Host Action Group (SHAG); Pace Energy Project; Natural
Resources Defense Council; Adirondack Council; Association for
Energy Affordability; New York Rivers United; New York State
Community Action Association; Joint Supporters by The E Cubed
Company; National Association of Energy Services Companies; IBEW
Local 97; State Department of Economic Development, Empire State
Development Corporation, and the Job Development Authority (jointly
DED); and, the New York Power Authority (NYPA).
The Settlement includes the Master Restructuring
Agreement (MRA) that Niagara Mohawk entered into with 16
independent power producers to ameliorate the above-market prices
the company pays for electricity. Both the Settlement and the MRA
are considered in this opinion and order.
GENERAL BACKGROUND
In 1990, Niagara Mohawk charged among the lowest
electricity prices of the investor-owned utilities operating in New
York, even taking into account its costs for two nuclear generation
plants. However, between 1990 and 1995, the company's average
retail prices rose by 25% and some customers experienced 35%
increases in their total bills. Several factors contributed to
this dramatic change. For one thing, the company's external costs
grew rapidly during the early 1990's. By 1995, they had become
nearly half of Niagara Mohawk's total costs. In addition, gross
receipts and real property taxes increased the company's costs.
By far, the single largest factor contributing to the
company's higher electric prices was increased payments to
independent power producers (IPPs) pursuant to power purchase
agreements (PPAs) containing prices exceeding the market value of
electricity. In 1995, for example, Niagara Mohawk's total payments
to IPPs exceeded $1 billion. These payments were expected to
increase over the next 20 years at a rate faster than the forecast
rate of inflation.
Niagara Mohawk's financial difficulties have been
compounded by economic recession in its service territory. From
1990 to 1995, electric sales did not grow appreciably. Even today,
growth lags in comparison with the downstate region. While
economic growth, and other factors, have helped to moderate
electricity prices elsewhere, Niagara Mohawk's electric rates
remain relatively high.
In 1993, the company began to reduce its internal costs
by implementing a substantial work force reduction. Over five
years, it managed to decrease its departmental expenses by almost
ten percent and capital spending by a third. With respect to
external costs, Niagara Mohawk sought to monitor the IPPs'
qualifying facility status, to curtail purchases from IPPs, and it
requested assurances from the IPPs that ratepayers will ultimately
receive the anticipated benefits of front-loaded contracts that
were supported in rates. It also sought to limit the amount paid
for IPP generation in excess of contract quantities and to
eliminate statutory requirements mandating IPP purchases. The
company also challenged various property tax assessments and
lobbied for legislative tax reforms. While some of its efforts
were successful, Niagara Mohawk did not manage to reduce its
external costs appreciably.
Finally, during the 1990's, Niagara Mohawk was under
constant pressure to reduce electric prices from customers with
access to competitive alternatives. It was also strongly
encouraged to stop increasing electric rates.
PROCEDURAL HISTORY
These cases began in February 1994 when Niagara Mohawk
filed a proposal for a traditionally-derived electric rate increase
for 1995 and proposed electric price caps for the succeeding four
years. The company's 1995 rate proposal was fully litigated; Staff
and other parties responded to the company's multi-year rate
proposal with alternatives of their own. Following the first round
of hearings, new rates were set for 1995 and these proceedings were
bifurcated. We directed Niagara Mohawk to continue to devise
an acceptable multi-year plan addressing its rate levels, the
company's financial security, customer service quality, and certain
regulatory changes needed to stimulate competition in the
marketplace.
During the summer of 1995, the parties met regularly to
address these matters. Administrative Law Judge Jeffrey E.
Stockholm served as a Settlement Judge and he aided the parties in
their efforts to achieve a negotiated resolution of the issues.
Initially, the company provided the parties pertinent information
about its financial condition and stated its position on electric
restructuring issues.
In October 1995, Niagara Mohawk submitted, only for
settlement discussion purposes, a comprehensive, multi-year rate
and restructuring proposal commonly referred to as
"PowerChoice". For the next nine months, the parties continued
negotiations and we developed our approach to restructuring New
York's electric utilities. In May 1996, the electric service
competitive opportunities decision was issued. Niagara Mohawk
was explicitly excepted from the filing requirements of that
decision as it had already submitted its PowerChoice proposal.
In June 1996, progress in the PowerChoice settlement
discussions stalled while Niagara Mohawk focused its efforts on
separate negotiations with the IPPs. Completion of these efforts
was necessary for Niagara Mohawk to be able to draft a revised
PowerChoice proposal for the parties to consider. On July 9, 1997,
the company executed the MRA with 16 SIPPs whose 29 PPAs represent
more than 80% of Niagara Mohawk's above-market costs.
Thereafter, on July 23, 1997, the PowerChoice settlement
discussions resumed and the company presented a new settlement
offer taking into account the MRA. Negotiations facilitated by the
Settlement Judge culminated on October 10, 1997 when the Settlement
was filed.
In accordance with the October 17, 1997 ruling that set
the schedule for these proceedings, the parties prefiled testimony
supporting and opposing the Settlement. Evidentiary hearings
began on November 18, 1997 and ran for three days. Between November
25 and December 4, 1997 public statement hearings were held at ten
locations throughout the company's service territory. Oral
statements and written comments were received from residential,
commercial, and industrial customers and their representatives.
Statements and comments were also received from local government
officials and participants in the emerging competitive electric
market.
On December 29, 1997, Administrative Law Judge William
Bouteiller's recommended decision was issued. The Judge
recommended that the MRA be accepted and the financing needed to
implement it be approved. He also recommended that the Settlement
be adopted subject to three modifications that would shorten it
from five to three years, eliminate those customer charge increases
that would increase customers' bills, and permit some customers to
use on-site generation and to form municipal systems without having
to pay some or all of their share of the company's stranded
costs.
Briefs on exceptions to the recommended decision were
filed on January 9, 1998 by Niagara Mohawk; Staff; the State
Consumer Protection Board (CPB); the State Department of Law (DOL);
the SIPPs; the National Power Lenders Forum (NPLF); MI; SHAG;
Norcen Energy Resources Limited (Norcen); DED; IPPNY; the Federal
Executive Agencies and the Department of Defense (USEA); Retail
Council of New York and the Buffalo Commercial Building Association
(Retail Council); the City of Oswego; Public Utility Law
Project of New York, Inc. (PULP); Enron Capital & Trade Resources
Corp. and Wheeled Electric Power Company (Enron/Wepco); Finch,
Pruyn & Company, Inc. (Finch); New York State Electric & Gas
Corporation (NYSEG); Novus Engineering, P.C.; The Wing Group for
the Retail Service Communities; and, the City of Buffalo.
Briefs opposing exceptions were filed on January 16, 1997
by all but nine of the parties filing exceptions and by
Central Hudson Gas & Electric Corporation, Long Island Lighting
Company, and Rochester Gas and Electric Corporation (jointly
Central Hudson/LILCO/RG&E); New York Coalition for On-Site Power
Generation (Coalition); ENtrust, LLC; and, ANR Pipeline and Empire
State Pipeline.
SUMMARY OF THE MRA AND THE SETTLEMENT
- -------------------------------------
The MRA will terminate, restate, or amend 29 PPAs and
provide the SIPPs about $3.6 billion in cash, 46 million
shares of Niagara Mohawk common stock, and a portfolio of financial
and physical delivery contracts. Currently, the 29 PPAs affect
1800 MW of capacity and, on average, 11,500 gWh of energy per year
for the next five years. They require Niagara Mohawk to pay
substantially more than it would cost the company either to
generate the same amount of electricity or to purchase it from
others.
Initially, the MRA reduces by about 5,000 gWh Niagara
Mohawk's annual purchases from the SIPPs and makes this electricity
available for purchase in the competitive energy market. Most of
the electricity remaining under contract to Niagara Mohawk will be
subject to financial instruments that allow generators to
participate fully in the competitive market. New contracts for
5,000-8,000 gWh annually will be executed and indexed to the cost
of competitive natural gas supplies.
Various conditions and requirements must be satisfied
before Niagara Mohawk and the SIPPs will close the MRA, including
the negotiation of restated and amended contracts and their
obtaining third-party consents to terminate the existing PPAs and
other agreements. The SIPPs expect to enter into new arrangements
to restructure their projects economically. Niagara Mohawk must
complete its financing arrangements. Both sides must obtain
approvals from their boards of directors, shareholders, and
partners. While one or more of the SIPPs may, under certain
circumstances, drop out of the MRA, Niagara Mohawk remains obliged
to close it as long as the company's benefits are not adversely
affected by the loss of a particular SIPP.
The Settlement itself runs for five years. It would
reduce average residential and commercial prices by 3.2% during its
first three years relative to 1995 levels, including anticipated
reductions in the New York State gross receipts tax. Tariff rates
for the industrial class would be reduced to below 6/kWh which is
a reduction of 25% by 2000. Because some industrial customers are
already receiving discounts, not all customers will experience the
25% reduction.
During the settlement term, Niagara Mohawk could defer
certain unanticipated costs (above the forecasted amounts) for
environmental remediation, nuclear decommissioning, and changes in
governmental requirements. But it would eliminate the existing
fuel adjustment clause (FAC) and various other bill surcharge
mechanisms.
In the fourth and fifth years of the settlement period,
Niagara Mohawk could file for rate increases, but they would be
capped at one percent annually for increases in transmission,
distribution, nuclear, customer service costs, and changes in the
competitive transition charge (CTC). Beyond this amount, the
company's recovery of deferred costs, certain surcharges, and any
auction incentive it earns is limited by the rate of inflation.
The Settlement allows Niagara Mohawk to recover its
MRA-related costs. A MRA-related regulatory asset would be
established and this liability would be paid off over the next ten
years, if not sooner. The Settlement also provides the company a
reasonable opportunity to recover its strandable costs; however,
Niagara Mohawk has agreed to forgo most of the earnings it would
otherwise receive, and the proposed rate plan is premised on the
limited recovery of the company's carrying charges for the
MRA-related regulatory asset. Thus, the company would absorb over
the next five years approximately $2 billion of its stranded costs
due to electric industry restructuring by accepting a very low
equity return during the Settlement's term. Otherwise, stranded
costs are recoverable from all customers through the CTC, other
fees, and access charges.
The Settlement provides for the divestiture of Niagara
Mohawk's fossil and hydro generation assets either at auction or by
being spun off to a separate entity. If the auction produces
viable results, winning bids would be selected within eleven months
of Commission approval of an auction plan. The Settlement allows
the company to retain for shareholders a percentage of the auction
sale proceeds as an incentive to obtain the maximum amount. Niagara
Mohawk may keep its generation assets that receive no positive bids
at auction.
The Settlement allows Niagara Mohawk's nuclear facilities
to remain with the regulated business while the Commission and the
company explore statewide resolutions to nuclear power issues. If
this matter is not resolved this way, the company would have to
file, no later than 24 months, a plan that analyzes all available
solutions for the nuclear facilities, including the feasibility of
an auction, transfer, or divestiture. Niagara Mohawk would be
allowed to pass through to customers its replacement power costs if
a nuclear plant is prudently retired.
This year, large industrial and commercial customers
would have full retail access and, by the end of 1999, all
customers would be able to choose their own electricity suppliers.
Niagara Mohawk would continue to deliver electricity over its
transmission and distribution facilities, and it would continue to
be the provider of last resort for customers who do not choose
another supplier.
The Settlement proposes to decrease electric energy
charges and to increase the customer charges that residential and
small commercial customers pay. While the classes would, on the
whole, experience an overall 3.2% revenue decrease, about 44% of
residential and 55% of small commercial customers' bills would
increase slightly if this Settlement provision were approved.
Under the Settlement, electric rates would be unbundled
into separate charges for transmission, distribution, customer
service, electric commodities, and the CTC. Customers will have
bundled and unbundled service options, and the ability to choose a
fixed or floating CTC. Niagara Mohawk would charge its customers
the actual market price for the electricity it provides. Customers
who purchase electricity from a competing supplier would see
Niagara Mohawk's energy charge "backed out" of their utility bills.
Certain customer service costs would also be backed out of
customers' bills.
To ensure that customers obtain quality service from
Niagara Mohawk, the Settlement includes an incentive mechanism that
exposes the company to up to a $6.6 million loss annually if its
performance does not measure up to specified standards. To assist
low-income customers, the Settlement requires Niagara Mohawk to
expand its Low Income Customer Assistance Program (LICAP) and make
it available to all qualified customers.
The Settlement provides for a third-party administrator
for the system benefits charge and $15 million during each of its
first three years for demand-side management, research and
development, and low-income energy efficiency programs. The
Settlement also contains a number of other environmental and public
policy provisions, including those concerning the development of an
environmental disclosure mechanism, wind and photovoltaic
generation, the donation and sale of land holdings of significance
to the environment, and the retirement of sulfur dioxide
allowances. It also allows the company to operate as a holding
company and contains rules for affiliate transactions and standards
for competitive conduct. No additional royalty payments for
affiliated companies would be required other than those subsumed by
the proposed rate plan. The Settlement also addresses tax refunds
Niagara Mohawk may receive, and the disposal of certain real estate
interests the company no longer needs pursuant to an Occupancy Cost
Reduction Initiative.
EXCEPTIONS
- ----------
MASTER RESTRUCTURING AGREEMENT
Two parties, PULP and the City of Oswego, except to the
Judge's recommendation to accept the MRA and approve the financing
needed to execute it. Five other parties--the SIPPs, NPLF, Niagara
Mohawk, SHAG, and DED--except to the recommendations about the need
for an escrow account to control the payment of the MRA proceeds,
and whether we should oversee negotiations between the steam hosts
and power producers. Finally, Norcen seeks certain ratemaking
presumptions for any costs Niagara Mohawk incurs to obtain
third-party releases from the existing PPAs. The parties'
arguments are summarized first, followed by a discussion and our
conclusions on these matters.
1. PRUDENCE
PULP claims the Settlement's proponents did not
demonstrate that the MRA is prudent and that ratepayers should bear
its costs. PULP says they failed to meet their burden of proof and
that the Judge skirted the issue by limiting his finding. It
insists that the MRA's prudence must be addressed directly but, it
says, the record is deficient and precludes an affirmative finding.
PULP believes the proponents should have compared the MRA
to other alternatives, including a continuation of the status quo.
Because Niagara Mohawk did not provide a quantitative, present
value analysis of competing alternatives, PULP claims there is no
way of knowing whether it is prudent for the company to incur debt
to finance the MRA.
PULP also objects to the SIPPs acquiring almost 25% of
Niagara Mohawk's common stock. It claims such an ownership
interest guarantees the SIPPs two seats on the company's board of
directors that they could use to influence company decisions.
Rather than support corporate policies that benefit ratepayers,
shareholders, and competition, PULP says these directors would
favor the SIPPs' interests.
Instead of obtaining cash and common stock, PULP
considers it preferable that the SIPPs receive utility debt, such
as notes and bonds. Alternatively, it contends Niagara Mohawk
should have followed through with its plan to acquire the SIPPs'
facilities through eminent domain proceedings. PULP fears that the
SIPPs will use their MRA proceeds to purchase Niagara Mohawk
generating plants at auction and thereby control the price of
electricity in the upstate region. If this were to occur, PULP
says, it would defeat our efforts to establish a competitive
electricity market.
Finally, PULP challenges any suggestion that Niagara
Mohawk must take steps to avoid bankruptcy now. It insists that
the company has cash resources to sustain it to the year 2000 and
there is ample time for Niagara Mohawk to strike a better deal than
the one presented here. If need be, PULP says, the company could
obtain temporary rate relief were a true emergency to arise. Thus,
PULP urges that other alternatives be explored, including a merger
and consolidation of Niagara Mohawk with another electric
distribution company, before the MRA is accepted.
The City of Oswego also criticizes the MRA, saying it is
neither the only alternative nor the best one available. Rather
than worry about bankruptcy, the City says an approach should be
established to provide sufficient rate reductions for residential
customers, to avoid adverse consequences for local municipalities,
and to better serve the public interest.
In response to PULP and Oswego, Niagara Mohawk insists
the MRA is prudent, that bankruptcy is the likely alternative, and
that corporate insolvency would not serve the public interest.
As to PULP's call for a net present value analysis, the company
says the MRA payments are less than those required by the existing
contracts and it denies that the MRA's benefits can be determined
by this measure alone. In addition to providing financial savings,
Niagara Mohawk points out that the MRA permits it to restructure
long-term IPP payments and its debt obligations. It also notes
that the MRA provides a basis for rate reductions and a quick
transition to competition in the generation market. Also, by
forgoing a return on the MRA-related regulatory asset, the company
says, it will bear a large portion of the costs of the financing
without obtaining recovery from ratepayers.
Niagara Mohawk urges us to reject PULP's alternatives,
noting that the MRA was produced through years of litigation and
arms length bargaining. The company denies that the SIPPs could
gain corporate control with their equity interest since they cannot
act in concert in a competitive market, and because any SIPP with
more than a two percent equity interest must execute a written
agreement to remain independent of the other power producers.
The SIPPs add that they have neither the intent nor the
ability to control Niagara Mohawk's transmission and distribution
system, nor can they influence unduly its board of directors. They
point to the large number of producers, their diverse ownership and
geographical locations, and to the competition among them. Rather
than keep their Niagara Mohawk common stock, the SIPPs say it is
more likely they will use it to settle creditors' claims.
2. ESCROW ACCOUNT
The SIPPs, NPLF, and PULP except to the Judge's
recommendation that the SIPPs provide steam hosts, and others,
reasonable assurances of their ability to pay claims and judgments
with the MRA-related proceeds and other assets. Absent such
assurances, the Judge recommended that we carefully consider the
need for an escrow account to serve this purpose.
The SIPPs agree with the Judge's recommendations
concerning other SHAG proposals; however, with respect to the need
for any "reasonable assurances," they insist that nothing in the
record suggests that they would breach contracts, deplete assets,
or attempt to avoid their responsibilities.
The SIPPs note that detailed contracts control their
relationships with the steam hosts and that the contracts were
executed by knowledgeable executives. The SIPPs also claim there
are ample assets available to meet their obligations, and that
they are required by state and federal law to deal fairly with
suppliers, contractors, and creditors. Given the prevailing
contracts and applicable law, the SIPPs insist that no further
assurances are needed. They urge us not to provide the steam hosts
any new or better rights than those bargained for in the respective
contracts.
NPLF also considers it unwise to require the SIPPs to
provide any assurances to steam hosts beyond those in their
contracts. It objects to the use of regulatory authority either to
obtain additional assurances or to review the adequacy of any
assurances due the steam hosts. NPLF says it is better to refrain
from overseeing power producer/steam host transactions. According
to NPLF, an escrow mechanism, or any similar process, could
adversely affect the SIPPs' secured creditors and prevent the MRA's
consummation.
As to any potential Niagara Mohawk liability to the
SIPPs' contractors and suppliers related to the PPAs, the SIPPs say
that the MRA provides the company adequate protection because it
can insist on adequate releases (or indemnification) or Niagara
Mohawk can refuse to close the deal. Niagara Mohawk insists that
it is not a party to the SIPPs' dealings with the steam hosts and
it has no liability to them. It prefers to remain out of these
matters.
In response to the parties who oppose an escrow account,
SHAG insists one is needed to address concerns about the power
producers' contract performances, and to protect thousands of jobs
in the upstate region it asserts are otherwise at risk. SHAG fears
the power producers will pursue a strategy of protracted litigation
and force them to incur significant costs that they may not be able
to recover without an escrow account. In SHAG's opinion, the
assurances the SIPPs have provided to date are inadequate.
SHAG adds that the applicable state and federal statutes
do not preclude limited partnerships from making wrongful
distributions--they merely provide an injured party a cause of
action against a partner who receives a fraudulent conveyance.
SHAG insists that an escrow account is needed to preserve the MRA
proceeds before they can be conveyed to others.
As to the possibility of protracted litigation between
IPPs and steam hosts, SHAG says its members cannot afford to incur
the operational problems and service interruptions that lawsuits
may engender. It also suggests Niagara Mohawk may have to be
involved if the disputes go to court. If litigation ensues, SHAG
also says there could be job losses and damage to the upstate
economy.
Given that the MRA is, in part, attributable to
governmental urgings that the SIPPs modify the existing PPAs, SHAG
considers it proper for us to require an escrow account for the
benefit of contractors, suppliers, and creditors which would serve
the public interest by forestalling economic harm to them. SHAG
also doubts that the MRA would unravel if an escrow account were
established. It insists that the steam hosts are not seeking to
improve their positions or take unfair advantage of the power
producers. SHAG concludes, saying the steam hosts have provided
reasonable estimates of their costs and damages if the SIPPs cease
to perform their contractual duties.
3. STEAM HOST AND POWER PRODUCER DEALINGS
Contrary to the Judge's recommendation, SHAG urges us to
oversee the negotiations between SIPPs and steam hosts. It claims
only we are in a position to assist the parties and address their
concerns. According to SHAG, performance delays, interruptions,
and uncertain thermal supplies would adversely affect the steam
hosts' competitive positions and their capital investments. It
asks us to promote good faith negotiations and determine when SIPPs
may terminate service to steam hosts. It also proposes that we
address regulatory issues that may arise between the parties and
ameliorate the steam hosts' economic losses by exempting them from
the CTC, other fees, and access charges, when necessary.
DED agrees with SHAG that steam hosts should be relieved
of the CTC and other charges and fees. It urges that such relief
not be limited to SHAG members but also be made available to other
similarly situated firms. DED believes Niagara Mohawk should be
kept whole by ratepayers for any revenues it loses. DED also
argues that steam host relief is important to the State's economy.
The SIPPs respond that there is little need for us to
oversee negotiations with steam hosts. They say there is no
strategy to protract negotiations or to assume a litigation stance.
The SIPPs point to instances where steam hosts and power producers
have reached agreements, and cases where power producers have
offered to continue to provide thermal energy under existing
contracts. Thus, the SIPPs surmise that only a few steam hosts are
threatening the MRA by seeking our involvement in their
negotiations.
In its reply, Niagara Mohawk opposes SHAG's and DED's
request that steam hosts be relieved of the CTC and other
transition charges. The company highlights its poor financial
condition, emphasizes its substantial contribution to the
Settlement, and complains that relieving steam hosts of the CTC
would unfairly burden the company further. In response to DED's
proposal that lost revenues be collected from other customers,
Niagara Mohawk points out that residential, commercial, and other
industrial customers' rates are already too high and should not be
increased further to pick up stranded costs that should properly be
allocated to the steam hosts.
4. THIRD-PARTY RELEASES AND RATEMAKING PRESUMPTIONS
Norcen, a natural gas supplier to three SIPPs which has
"backstop agreements" with Niagara Mohawk, considers the MRA
imprudent to the extent it does not avoid potential negative
effects on third parties such as it. To mitigate the MRA's adverse
consequences, Norcen proposed that any costs Niagara Mohawk incurs
to obtain third-party consents and releases be presumed to be
recoverable in rates. It also proposed that any costs the company
incurs to unsuccessfully block third-party rights be presumed to be
unrecoverable. The Judge recommended against these presumptions,
and Norcen excepts.
Norcen says its approach does not require any final
determinations now and it only provides the company the benefit of
rebuttable presumptions. It claims such presumptions are the
regulatory norm for circumstances like these and they should be
made explicit.
Next, Norcen says Niagara Mohawk can afford to make
payments to third parties even taking its MRA financing costs into
account. It suggests that any additional costs be recovered from
ratepayers through the CTC.
Finally, Norcen criticizes the Judge for observing that
third parties should look primarily to the SIPPs, and not Niagara
Mohawk, for their compensation. In response, it points to the
backstop agreements Niagara Mohawk executed and says the company
has a direct contractual relationship with Norcen for which it is
responsible. If the SIPPs do not cover the full enterprise value
created by the PPAs, then Norcen believes Niagara Mohawk should
remain liable to third parties that have valid claims against
it.
In response, Niagara Mohawk urges us not to establish any
ratemaking presumptions at this time. The company says they are
unnecessary and premature until a court determines that Niagara
Mohawk is liable to Norcen. The SIPPs also ask us not to prejudge
Norcen's claims against the company. They say the way the MRA
works, ratepayers do not have any financial risks or liabilities
running to Norcen. Finally, ANR Pipeline and Empire State Pipeline
urge that no third-party entities affected by the MRA or the
Settlement be given preferential treatment. It says none of the
third-party interests should receive any precedence over the
others.
5. DISCUSSION AND CONCLUSION
Several parties correctly suggest that the MRA's prudence
is the first matter that must be decided in these proceedings
because much depends upon this determination. To the MRA's credit,
few parties have challenged it even though all recognize this issue
as one of the most important in these cases. Only PULP and Oswego
present alternatives to the MRA and urge us either to postpone a
decision or to explore a different avenue. The other parties who
raise issues about the MRA do not challenge it; rather, they either
assume it will be implemented and seek to assure that their own
interests are protected, or they simply seek our assistance to
avoid commercial disputes.
Beginning with the procedural issues, we find that the
record in these cases is sufficiently developed to evaluate the
MRA's prudence. The Settlement's proponents executed their
responsibilities and fulfilled their burden of going forward by
providing direct testimony supporting the reasonableness of the MRA
and the Settlement. Such testimony was provided by the
Settlement's primary sponsors, including the company, the SIPPs,
Staff, and DED. We also find that the Settlement's opponents
were afforded ample opportunity to challenge the MRA's merits and
to provide us all the information they consider relevant to the
MRA's prudence, including alternatives.
Turning to the substantive issues, we find that the MRA
is a reasonable method to restructure the company's finances and
provide Niagara Mohawk the means to provide safe and adequate
service, at just and reasonable rates, in New York's emerging
competitive electric market. Among other things, the MRA is
projected to result in new contracts with IPPs that will afford
Niagara Mohawk greater operating flexibility, allowing it to make
fewer purchases on a "must take" basis. The new contracts will
also give Niagara Mohawk greater flexibility to make purchases from
IPPs when needed, at lower per kWh rates. The anticipated
cumulative effect of these changes is that Niagara Mohawk, and
ultimately ratepayers, will avoid future rate increases previously
forecast to total 20% or more over the next few years.
Indeed, our analysis suggests these new arrangements will yield
ratepayer benefits on a net present value basis of approximately
$0.5 billion if the future payment streams are discounted at 10%,
and more if a lower discount rate were assumed. Additionally,
the MRA permanently resolves many of the most difficult issues
recently faced by Niagara Mohawk, short of a utility bankruptcy,
which no party advocates.
Nor are we troubled by Niagara Mohawk using a portion of
its common stock to pay the SIPPs. The proponents have
convincingly demonstrated that the SIPPs cannot use their combined
interests in the company to improperly influence its operations.
Were they to attempt to do so, we would investigate any such
circumstances and take proper steps to preclude improper
manipulations of the competitive market.
The opponents of the MRA have also failed to establish
that there is any serious alternative that would produce the same
or greater benefits than the MRA. PULP, for example, suggests a
continuation of the status quo, including the prospects for rate
increases, is preferable to the MRA because the company might be
able to avoid making payments to the SIPPs by moving closer towards
bankruptcy. However, we consider PULP's proposal inferior because
of its greater risk of rate increases and for courting the
uncertain and adverse effects of a Niagara Mohawk bankruptcy on the
rates and service of this and other New York utilities. If efforts
were made to put off the restructuring of the company's finances,
such action would create pressure for higher rates as more
uneconomic purchase power obligations came due. It would also
leave the steam hosts and other third parties far more vulnerable
than they are under the MRA. In any event, we would continue to
face the same issues that are before us now as they would not
disappear. We could not put off these matters for long and there
is no reason to believe any better solution than the MRA would be
presented.
PULP suggests that the SIPPs would accept lower payments
if the company were closer to insolvency. However, there is no
evidence that the proximity of bankruptcy proceedings would lead to
the results PULP envisions. The reorganization of the company in
a bankruptcy proceeding would entail great uncertainty, and we are
not convinced that the public interest is best served by pursuing
any such course.
However, we are concerned about the effect of the MRA on
steam hosts. We agree that it is an important public interest
consideration bearing on whether we should approve and find prudent
the MRA, because the potential effects on steam hosts could have a
substantial impact on the economy in Niagara Mohawk's service
territory. If satisfactory arrangements between the SIPPs and
steam hosts had not been reached, the public interest would not
have been served. Consequently, to the extent such arrangements
had not been reached we would not have approved the MRA.
When we first considered these proceedings in early
February 1998, we expressed a strong interest in obtaining prompt
resolutions of the issues remaining between the SIPPs and the SHAG
members in order to serve the public interest, protect the State's
economy, and minimize the risk that the MRA might not close. Such
results benefit ratepayers by making clear and certain the
company's obligations during the rate plan. Consequently, our
Staff assisted these parties and they managed to resolve their
private disputes in all cases except one pertaining to Encogen Four
Partners, Ltd. (Encogen) and Outokumpu American Brass, Inc.
(American Brass). Thus, we are satisfied that acceptable steam
host/SIPP arrangements have been reached in all cases except one.
We hereby find the MRA to be in the public interest and
Niagara Mohawk's conduct to be prudent to the extent that
satisfactory SIPP/steam host arrangements are reached.
Consequently, if the one outstanding dispute cannot be resolved to
the mutual satisfaction of the parties or the Commission, Niagara
Mohawk should not proceed to consummate the MRA as concerns
Encogen.
With respect to the parties' exceptions urging us to
place the MRA-related proceeds in an escrow account to ensure their
availability for steam hosts, the treatment described above
adequately addresses these interests. And as to third party
claims, we are satisfied that no liabilities will flow to Niagara
Mohawk from the SIPPs' dealings.
Finally, there is no need for us to adopt any of the
ratemaking presumptions that Norcen proposes. We accept Niagara
Mohawk's and the SIPP's representations that their resolution of
the matters pertaining to Norcen are not expected to result in any
additional costs for ratepayers.
POWERCHOICE SETTLEMENT PROVISIONS
1. THE GENERAL PUBLIC INTEREST STANDARD
Our Settlement Guidelines establish the following
standards for assessing a proposed settlement and determining
whether it should be approved:
A desirable settlement should strive for a
balance among (1) protection of the
ratepayers, (2) fairness to investors, and
(3) the long term viability of the utility;
should be consistent with sound
environmental, social, and economic policies
of the Agency and the State; and should
produce results that were within the range of
reasonable results that would likely have
arisen from a Commission decision in a
litigated proceeding.
In judging a settlement, the Commission shall
give weight to the fact that a settlement
reflects the agreement by normally
adversarial parties.
The PowerChoice Settlement proponents maintain, and the
Judge generally found, that these criteria are satisfied. However,
the opponents, principally PULP and the City of Oswego, claim that
the Settlement is generally not in the public interest.
PULP argues that the changes to the rate plan recommended
by the Judge demonstrate that the Settlement is not in the public
interest. Moreover, PULP contends the Settlement is contrary to
law and inconsistent with desirable public policy objectives even
if all of the Judge's recommended changes were adopted. Only to
the extent PULP's position is accepted in its entirety would this
party conclude that the Settlement is in the public interest.
In general, PULP prefers that restructuring of the
electric industry proceed pursuant to legislation. Also, rather
than rely on the company's historical operating data and
information provided in other proceedings, PULP would prefer that
Niagara Mohawk provide more recent financial data and forecasts to
set electric rates for 1998 and subsequent years.
The City of Oswego meanwhile contends a better analysis
of the Settlement's impacts on local municipal units is needed
before its reasonableness can be determined. Until the
Settlement's effects on local business, employment, and municipal
revenues are fully known and detailed, the City maintains, the
requirements of the State Environmental Quality Review Act (SEQRA)
cannot be completed and action on the Settlement should wait.
Niagara Mohawk responds to PULP's general arguments.
Comparing the Settlement with the vision and goals provided by our
Competitive Opportunities decision, the company observes that
the Settlement reduces electric prices, aids the State's economy,
creates a competitive market, and provides customers retail access.
It also points out that the Settlement was negotiated in full
compliance with our rules and guidelines and describes it as
properly balanced, protecting ratepayers and investors and helping
ensure the company's long-term viability. All of this is
demonstrated, according to the company, in the Settlement's
specific provisions. And, as a wide range of interests--20 parties
in all--have endorsed the Settlement, Niagara Mohawk says, this is
strong proof that the public interest and the State's
environmental, social, and economic policies are well served by the
Settlement.
Niagara Mohawk also points to the Settlement's specific
benefits to refute PULP. The company points, for example, to the
rate reductions for all customer classes, lower energy charges
approaching marginal costs, and cost-based customer charges. It
highlights as well the Settlement's few cost deferrals and
surcharges, and the elimination of the fuel adjustment clause.
Niagara Mohawk also contends the Settlement will achieve
electric generation competition because the divestiture of its
non-nuclear facilities will end its vertical integration and
control over the generation market. In the next two years, the
company goes on, energy suppliers will move into the industrial,
commercial, and residential sectors and, by the end of 1999, all
customers will be able to choose their own unbundled energy
services.
Niagara Mohawk contends, as well, that the public
interest is served by its corporate and financial structure changes
ending the current arrangements with the SIPPs, allowing
competitive markets to form, and segregating monopoly services from
competitive ventures. The company says it expects to halt its
financial deterioration, avoid bankruptcy, and recover uneconomic
stranded costs without disturbing the operation of the competitive
marketplace. And it will abide by the rules governing affiliate
relationships and protecting competitive
conduct.
In sum, according to the company, no other alternative
provides as much benefit and serves the public interest as well as
the Settlement. No other party, it says, has laid out an
alternative approach that accomplishes as much as the Settlement.
Any continuation of the status quo, the company warns, will require
rate increases to cover its rising costs. Finally, Niagara Mohawk
points to the low earnings it will experience for the next three to
five years as convincing proof that it is making every effort to
serve the public interest through this Settlement.
Responding to the City of Oswego, Niagara Mohawk
contends its electric rates in a competitive market should not be
made to cover the cost of government services for localities that
may lose tax revenues due to electric industry restructuring.
The company also maintains that, on the whole, the Settlement
will provide substantial economic and social benefits for the
entire service territory by creating new business opportunities,
generating jobs, and promoting economic development. In this
context, Niagara Mohawk believes the local impacts of concern to
Oswego do not provide good reason to forgo the sale of the
company's generation facilities, which is essential to electric
generation competition.
Many of PULP's and Oswego's public interest criticisms
and concerns are discussed below in the context of our issue-
specific findings and in the overall discussion and conclusion at
the end of this opinion and order. These include, for example,
those about the Settlement's proposed rate design, the adequacy
and fairness of the proposed rate reductions, and compliance with
SEQRA. At this point, however, we observe that legislative
action, while possible, is not necessary for us to evaluate the
Settlement's reasonableness or to implement its terms.
Furthermore, legislation proposed to date does not provide the
level of benefits created by the Settlement. Also, it is not
necessary for us to have more recent financial results and
forecasts in order to evaluate the Settlement's reasonableness.
Staff conducted an examination of the company's financial
condition over the Settlement term which provides us an ample
basis for evaluating the Settlement's rate plan. In sum, we
conclude that the Settlement, as modified and conditioned by this
opinion and order, is in the public interest.
2. THE SETTLEMENT'S REVENUE DECREASES
a. EXCEPTIONS
CPB, PULP, and Retail Council consider the 3.2% revenue
decreases proposed for the residential and small commercial
customer classes to be too small and urge that the classes
receive greater decreases.
CPB excepts to the Judge's recommendation against the
ratemaking adjustments it proposed. At a minimum, CPB believes a
5.2% revenue decrease should apply to these classes and it can be
achieved by reducing the company's bad debt expense, increasing
the forecast of electric sales, and increasing the amortization
period for the MRA-related regulatory asset. Several other
parties also propose changes in the amortization of the MRA-
related regulatory asset or in the term of the MRA debt
financing.
CPB says residential and commercial customers expect to
see lower rates from the changes in the electric industry. CPB
notes that these customers experienced substantial rate increases
in recent years and it remains unpersuaded that a valid cost basis
exists to raise customer charges now. Lower prices for
residential and small commercial customers, CPB says, would help to
improve the economic condition of the service territory. It also
believes that Niagara Mohawk's long-term financial viability would
improve were lower electric prices implemented for all customers.
Retail Council and PULP complain about the disparity in
the revenue decreases the Settlement would provide to large
industrial and commercial customers, on the one hand, and to small
commercial and residential customers, on the other. PULP believes
there are sufficient programs currently available to provide
electric rate relief to large industrial customers and the
Settlement's provisions are not needed.
Retail Council argues that the Settlement's industrial
rate provisions are flawed and the record does not support
disparate rate reductions for the various classes. According to
it, economic development and business growth are more apt to come
from the commercial and service sectors than from industry.
Assuming there are insufficient funds to provide large decreases
for the commercial and service sectors, Retail Council contends
that all classes should receive comparable revenue reductions.
If any customers are to receive disparate rate
reductions, PULP urges that low-income customers' rates be reduced
by 25%. It says these customers are the neediest and least able to
afford even modest bill increases.
b. REPLIES
In response to CPB's proposal for larger revenue
decreases, Staff and the company say there are no funds available
to finance such reductions. They also say any extension of the
payment period for the MRA-related debt or the amortization period
of the regulatory asset is undesirable. According to Staff, an
extension would only shift these costs to future ratepayers and
increase the total amount (and the interest payments) ratepayers
would have to pay. Staff urges that the company's cash flow not be
adversely affected, and the company agrees that its cash flow is
needed to sustain its operations.
Niagara Mohawk says an extension of the MRA financing is
contrary to strandable cost minimization and would unnecessarily
extend the transition to competition. The company also contends an
extension of the financing period would be unfair to it to the
extent it agreed to give up some earnings for the next few years on
the condition it can repay the MRA-related debt promptly and thus
improve its financial condition. The company concludes by saying
an extension of the MRA financing could endanger its ability to
obtain this financing and thereby upset the Settlement.
Niagara Mohawk and Staff fail to see any merit in CPB's
proposed adjustments to bad debt expense and electric sales. They
are unaware of any support for CPB's position on bad debt, and they
are concerned about increasing the company's financial risk
exposure. As to the projected sales, Staff observes that CPB did
not provide its own sales forecast but compared the company's
projections with actual sales.
Niagara Mohawk also challenges CPB's policy arguments for
an additional two percent rate decrease for residential customers.
It insists that the proposed industrial rate reductions are needed
to produce competitive, electric rates, particularly if NYPA sales
are ignored. The company also disputes the extent to which small
businesses can reasonably be expected to drive the upstate economy
and provide economic growth. Given that the upstate area remains
vulnerable to loss of load and usage reductions from industrial and
large commercial accounts, the company insists that the
Settlement's industrial rate reductions are of paramount
importance.
MI also disputes CPB's claim about the economic
advantages of expanding large industry versus smaller businesses.
Like Niagara Mohawk, MI contends that existing industrial rates
remain unattractive, even taking into account low-cost hydropower
that is available in limited quantities to specified customers. MI
insists that small businesses, by themselves, cannot rehabilitate
the upstate region or provide sufficient amounts of sustained
economic growth. It says industrial growth is needed to cure the
lag in the State's economy dating back to 1989.
Staff questions the wisdom of PULP's proposal to use the
limited amount of rate reductions available to reduce only
low-income customers' rates. Staff contends it would be better to
use the amount available to improve the local economy and thereby
provide assistance to more customers. Staff also notes that the
Settlement's LICAP program, its provider of last resort provisions,
the service quality standards, and the revenue reduction for the
residential class, all enure to the benefit of low-income
customers.
c. DISCUSSION
We agree that the largest possible rate decrease overall,
and the decreases for the residential and commercial classes, are
important objectives. In recent cases involving other electric
companies, we did not approve the parties' proposed settlements
until we were satisfied that all reasonable means for obtaining the
greatest amount of rate decreases were exhausted. In this case, we
are satisfied that a full examination of the company's ability to
provide rate decreases was made and it suggests decreases larger
than anticipated in the Settlement cannot reasonably be granted at
this time. However, to implement the Settlement in a manner that
ensures that S.C. 1 (residential) and S.C. 2 (commercial) customers
experience the tariff rate reductions projected from the Settlement
relative to current rate levels, we shall require the company to
reduce its energy charges using as the base year the most current
twelve-month period or the 1995 base year levels as set forth in
the agreement, whichever base year results in the lowest first year
rate level.
With respect to CPB's proposals to further reduce the
company's total revenue requirements based on a forecast of the
company's bad debt expense and an increase in the company's
projection of future electric sales, we find these projections are
too speculative to support any further rate decreases at this time.
As to various parties' proposals to adjust the term of
the MRA financing or extend the amortization of the MRA-related
asset on the company's books, we find the Settlement reasonable and
adopt it without any change. In reaching this decision, we have
balanced the need for reductions in Niagara Mohawk's bundled
electric rates with the company's need to be able to finance the
MRA and we conclude that the Settlement, as proposed, is fairly
balanced.
Concerning various parties' suggestions that more
economic development can be obtained by shifting more of the
overall revenue reduction from the industrial customers to the
commercial and residential customer classes, we are not persuaded
that any such substantial changes should be made. To begin,
industrial load is more contestable to the extent industrial
customers have a greater ability to shift production. Lower
industrial rates help maintain total load and ensure contribution
to total costs, benefiting all ratepayers. While it may be true
that some economic growth could be stimulated by reducing electric
rates for commercial and retail customers more than the amount the
Settlement provides, and by reducing the cost of electricity for
residential customers, we are not willing to sacrifice the
improvements that the Settlement provides in the electric rates for
large industrial customers, which provide substantial net
employment opportunities in the upstate region. Moreover, if the
amount available to reduce rates were used to provide all classes
of customers the same percentage reductions, residential and small
commercial customers would only see slightly greater
reductions--4.3% instead of the Settlement's 3.2% reductions.
In sum, the larger reductions for the industrial class provide a
significant opportunity for economic development as well as a
contribution to total fixed costs to the benefit of all customers.
Finally, as to PULP's proposal for a 25% rate decrease
for low-income customers, the Settlement's LICAP provisions provide
substantial benefits designed to assist needy customers. Before we
would entertain a proposal like PULP's, the expanded LICAP program
should be fully implemented and its results evaluated. Finally, we
conclude implementation of PULP's proposal, with the limited
resources available, would provide less benefit to the economy
overall in comparison with the Settlement.
3. THE SETTLEMENT'S DURATION
Rather than commit to a five-year settlement term, the
Judge recommended that we adopt the Settlement only for three
years. He expressed concern about the possibility of electric rate
increases in 2001 and 2002, and recommended that the company file
in the normal course for any rate increases in either of these
years. Niagara Mohawk, Staff, NPLF, MI, and DED except.
Niagara Mohawk says the period need not be shortened
because the Settlement does not assure it any rate relief for 2001
and 2002. The company points out that the Settlement requires it
to fully justify any request it makes for these years and it caps
the request at one percent for each year. If this limit is not
adopted, Niagara Mohawk says ratepayers may otherwise be exposed to
greater rate increases.
Niagara Mohawk also says it negotiated for a reasonably
assured revenue stream in the Settlement's fourth and fifth years.
Without an assurance of adequate revenues in these years, the
company says it would be exposed to higher financial risks than it
can stand. It also expresses concern that other important
Settlement provisions, including the collection of any generation
sale auction incentive and recovery of certain deferred and nuclear
generation costs, would be undermined if the Settlement's term were
shortened.
NPLF is also concerned about Niagara Mohawk's financial
risks absent the five-year Settlement. It says a shorter period
would threaten the viability of the financing needed for the MRA.
Staff explains that the Settlement does not provide the
company automatic rate increases in 2001 or 2002, and it emphasizes
the amount Niagara Mohawk may seek in these years is limited.
Staff also contends it is desirable to preserve advantageous
Settlement features that apply in the fourth and fifth year,
including the service quality incentives, the LICAP enrollment
targets, and the affiliate transaction rules and competitive
conduct standards.
MI points out that the Settlement places a "hard cap" on
the amount by which rates can increase. While it would have
preferred an absolute prohibition on rate increases, MI considers
this aspect of the Settlement to be a reasonable compromise. MI
also sees benefits in various Settlement provisions for 2001 and
2002, including those concerning optional five-year contracts for
large industrial and commercial customers and those allowing
certain customers to extend their current contracts for the full
Settlement term.
DED also supports a five-year Settlement for reasons
similar to those already discussed. The provisions for 2001 and
2002 of primary interest to DED are those governing S.C. 11
contracts and the transition plan for the Economic Development Zone
Rider.
In response to these exceptions, various parties continue
to state concerns about customers being exposed to higher rates in
2001 and 2002. CPB, Oswego, and PULP, for example, generally favor
a three-year rate plan.
CPB says that even if the rate increases for 2001 and
2002 are not automatic, they remain a real possibility due to the
Settlement's provisions. Similarly, PULP says electricity prices
for residential customers could escalate significantly under the
Settlement due to market changes in energy rates, higher customer
charges, company cost increases, deferrals, and surcharges.
The parties' exceptions are granted and the Settlement
will be approved for five years. As many proponents point out, the
Settlement offers substantial benefits in the fourth and fifth
years. While the Judge is properly concerned about rate stability
in the fourth and fifth years, we are satisfied such stability will
be afforded by the Settlement. This is because, as some parties
point out, any rate increase requests in those years is not
automatic and they will be subject to full review. The company's
possible rate increases for non-commodity costs are capped at one
percent and those increases, together with surcharges and deferral
recoveries, are subject to an overall inflation cap. Moreover, our
current forecasts suggest the need for increases in these years
will not be great and they can be ameliorated by anticipated
savings related to recent interest rate reductions. Finally,
we are concerned that shortening the Settlement's term to three
years could adversely affect the terms and maturity of the
MRA-related debt issues, if not their feasibility overall. In sum,
the risks of significant rate increases are sufficiently minimized
that the Settlement should be approved for its full term.
4. CUSTOMER CHARGES
The Settlement proposes to increase the customer charges
for residential and small commercial customers over the next three
years as energy rates decline. For low-use customers, the higher
customer charges would increase their electric bills by modest
dollar amounts.
The Judge recommended against any customers experiencing
bill increases due to of the Settlement, seeing such results as
contrary to the objective of decreasing customers' electricity
costs. The company and Staff except, while CPB, DOL, PULP and
Oswego oppose the Settlement's proposed customer charge increases
and the exceptions.
The excepting parties insist there are good reasons for
the Settlement's rate design provisions. The company, for example,
contends it is proper to align energy rates with marginal energy
costs. Staff agrees, noting the benefits of economically efficient
pricing that customers should see in a competitive energy market.
The company and Staff points out the customer charge
proposal also will help to eliminate the inherent unfairness of
large-use customers paying for costs that small-use customers
should bear. Niagara Mohawk also emphasizes that it prefers to
recover its fixed costs through customer charges so any decline in
sales will not affect the recovery of these costs. Given its
generally poor financial condition, the resulting revenue stability
will help minimize the company's risks.
Anticipating arguments that customer charges should not
be increased for low-income, low-use residential customers who may
not be able to afford modestly higher bills, Niagara Mohawk and
Staff say LICAP provides them sufficient assistance. Staff also
notes that many low-income customers who use large amounts of
electricity stand to benefit substantially from the proposed
changes.
Finally, highlighting the Settlement's substantial
advantages for average and high-use residential customers, Staff
points out that under the Settlement energy charges would decrease
by about 17%. It notes that small commercial customers would also
see significant energy rate savings. Staff believes that such
reductions would improve economic development in the service
territory, making it more attractive for small businesses to expand
their operations.
In response, CPB denies that low-use customer rates and
costs are out of line. According to CPB, there is conflicting cost
of service evidence on this point and, in a competitive
environment, a new study may be needed to adequately address its
differences with Staff. On the basis of the cost data CPB would
credit, it says that non-heat (low-use) customers are not being
subsidized by high-use, electric heating customers. CPB also
believes that many low-income, low-use residential customers would
experience unacceptable bill increases were the Settlement
approved. And it remains concerned that higher minimum bills will
lead to lower sales, greater uncollectibles, and customer
disconnections.
Retail Council characterizes the Judge's rate design
recommendations as regressive and counterproductive. It urges that
the electric bill components be realigned, as the Settlement
provides, to more accurately reflect marginal customer and energy
costs. In this regard, it says the Settlement's rate design
provisions are better than the Judge's status quo recommendations.
If we adopt any customer charge increases, PULP says we
should also adopt its low-income rate proposal. DOL urges us not
to allow any bill increases pursuant to the Settlement. Oswego
responds to Staff by claiming that many residential customers may
be worse off by the Settlement's effects on local employment,
disposable income, and municipalities with utility generation
facilities.
The Settlement's proponents have offered valid reasons
why it would be beneficial to increase the customer charges
applicable to the residential and small commercial customer
classes. In previous rate proceedings, we have permitted these
charges to increase for many of the reasons that the proponents
have advanced here. But this portion of the Settlement has
generated substantial public reaction. At a time when we are
fostering a transition to competition and economic development, the
Settlement's proposed customer charges would have the undesirable
effect of increasing the bills for many of the company's
residential and small commercial customers. This holds the
potential for customer confusion and skepticism about the benefits
of competition. In these circumstances, we shall exercise our
discretion on this rate design matter and defer a final decision on
this aspect of the Settlement until unbundled rates are filed for
residential and small commercial customers. No changes from base
period levels will be made in these charges for now.
5. STRANDED COST RECOVERY
a. EXCEPTIONS
The Judge generally recommends the use of a competitive
transition charge (CTC) and a system of access charges and other
fees to provide Niagara Mohawk the revenues it needs to pay the
stranded costs associated with restructuring its above-market
purchase power agreements and divestiture of its fossil generation
facilities. However, he also recommends that some amount of
stranded cost bypass be allowed for on-site generation and
municipalities. Numerous exceptions to these recommendations have
been filed by Niagara Mohawk, Staff, MI, PULP, CPB, Enron, Novus,
and The Wing Group.
Niagara Mohawk contends that stranded cost bypass for
self-generators and municipalities would be unfair to the remaining
ratepayers and would constitute poor public policy. It maintains
as well that uneconomic on-site generation should be discouraged
and that all customers should pay stranded costs, other than the $2
billion the company will absorb during the term of the Settlement.
The company observes that the debt needed to finance the
MRA can only be obtained if it has sufficient revenues. If any
customers are allowed to bypass the CTC, access charges, and other
fees, the company contends, the debt market may not be sufficiently
assured of Niagara Mohawk's ability to repay the MRA-related debt.
This could prevent the financing or result in higher debt costs.
The company also doubts that any amount of stranded cost bypass can
reasonably be controlled and limited.
Staff agrees that stranded cost bypass must be prevented
in order to finance the MRA. Given the company's already poor
financial condition, Staff is concerned about any loopholes for
customers to bypass the CTC. Staff also supports access charges
and other fees to recover embedded investments and discharge
commitments before customers can be allowed to bypass the system.
Staff distinguishes between economic and uneconomic on-site
generation and notes that only uneconomic alternatives to the
company's services are discouraged under the Settlement.
While MI supports the Settlement, it also believes that
customers who have determined that on-site generation is a viable
alternative should be allowed to obtain backup service from Niagara
Mohawk without paying a CTC, access charges, or other fees. If the
Judge's recommendations on this matter were to be adopted, it
proposes that the parties devise suitable criteria for an on-site
generation program. PULP opposes stranded cost bypass by any
customers other than perhaps large industrial and commercial
customers who have competitive alternatives.
CPB opposes the CTC mechanism altogether, claiming it is
anti-competitive. According to CPB, Niagara Mohawk should simply
reduce its rates, achieve greater efficiencies, and absorb any
stranded costs it cannot recover within these constraints. It fears
the company will use the CTC to engage in predatory pricing and
thereby harm the competitive market. It is also concerned about
the CTC being used to reverse the modest rate decreases that
residential and small commercial customers obtain from the
Settlement.
Enron/Wepco oppose the CTC to the extent the level of
this charge can vary over time, or "float" pursuant to the
Settlement's terms. Like CPB, they say the charge is incompatible
with the operation of a competitive market. They contend the
floating CTC will be a significant barrier to entry by competitors,
precluding them from offering consumers a fixed-price product in
competition with Niagara Mohawk's. These parties urge that a fixed
CTC be established from the start. They claim customers can be
assured of rate decreases without Niagara Mohawk's floating CTC and
they point to other settlements that contain fixed CTCs and provide
specified rate decreases for bundled service.
Novus, meanwhile, urges establishment of an on-site
generation program that does not have the Settlement's
"suppressing" effects. Specifically, it proposes that up to 8 MW
of load currently served by Niagara Mohawk be allowed to convert to
on-site generation without having to pay access charges. It says
this amount of self-generation would have virtually no impact on
the company but would allow some beneficial self-generation to
develop in the service territory.
Finally, The Wing Group on behalf of various local
communities interested in municipalization, points to substantial
amounts of customer dissatisfaction with the rates Niagara Mohawk
charges. It urges that all types of on-site generation be exempt
from stranded cost recovery.
b. REPLIES
Niagara Mohawk insists that no substantial amount of CTC
bypass can be tolerated. Responding to MI, the company says it is
inappropriate for this party, as a signatory to the agreement, to
support any Settlement modifications, even those proposed by the
Judge.
In response to CPB, Niagara Mohawk reiterates that it
will absorb $2 billion of stranded costs and that it should not be
asked to absorb any more. Staff says CPB has misconceptions about
the proposed CTC and explains that the CTC is included in the
company's bundled rates, which will be unbundled and reduced during
the Settlement term. According to Staff, the overall Settlement
approach enhances competition and does not allow the company to use
the CTC to abuse the marketplace.
The company opposes PULP's proposal for ratepayers and
shareholders to share stranded costs as this too would increase the
amount of stranded costs for it to absorb. Staff responds to
PULP's criticism of the rates applicable to large industrial and
commercial customers by stating that the CTC applies to these
customers despite any energy discounts they may receive to remain
on the electric system.
Responding to Enron/Wepco, Niagara Mohawk and Staff say
a floating CTC guarantees that customers experience fixed and
stable prices, which are important to several parties who executed
the Settlement and to ratepayers generally during the transition
period. The company also says it cannot afford to undercollect
stranded costs, and a fixed CTC applicable to all customers would
expose it to this risk. Finally, Niagara Mohawk says Enron/Wepco
can only speculate that a floating CTC will hinder competition
since no one knows how retail marketers will offer their services
and products. If it interferes with competition, the company says
we can modify the transition process accordingly.
Staff says that Enron/Wepco only present theoretical
arguments against a floating CTC that do not pertain here. Staff
insists it is not possible to implement a fixed CTC for all
customers immediately without exposing the company to an
unacceptable amount of financial risk. Further, Staff argues that
Enron ignores the relationship between the wholesale market and
retail rates. According to it, the mixture of fixed and floating
CTCs provided in the Settlement carefully balances the hedged and
unhedged power facing Niagara Mohawk in the wholesale market.
Staff concludes that the Settlement's mix of fixed and floating CTC
options represents the best retail package that could be fashioned
given the existing and restructured IPP contracts.
Responding to The Wing Group, Niagara Mohawk says this
party cannot credibly oppose the company's recovery of stranded
costs given that it is affiliated to a firm that wants full
recovery of its strandable costs.
Various other parties oppose the company's and Staff's
positions and urge that a limited amount of stranded cost bypass be
allowed for on-site generation and municipal interests. These
parties include Oswego, ENtrust, Coalition, Finch, and Novus. They
doubt that a limited amount of CTC bypass for these interests would
expose the company to any large risks, and they urge that
competition from on-site generation not be precluded. They note
that this alternative has been historically available to customers
and they claim it should not be forestalled now.
c. DISCUSSION
We previously determined that it is prudent for Niagara
Mohawk to execute the MRA in order to reduce the financial burdens
due to its uneconomic purchase power contracts with the IPPs. This
significant transaction benefits all the company's customers by
mitigating a long-standing problem and by making the transition to
a competitive generation market possible. A non-avoidable CTC is
both an important element to Niagara Mohawk's ability to issue over
$3 billion of debt to fund the IPP buyout and a reasonable means to
recover the costs of the MRA from all who benefit from it. Were
any customers who currently use the company's generation resources
able to bypass the CTC, aside from grandfathering self-generation
investments already made, this would unfairly require the remaining
customers on the system to pay costs which are fairly and properly
attributable to departing or bypassing customers. To ensure that
the CTC remains manageable, and does not become too large a burden
for any group of customers, we will approve the Settlement's terms
imposing certain fees in limited circumstances and structuring
backup rates to recover stranded costs from on-site generators. We
note that the Settlement states that the access fees related to on-
site generators taking back-up service are designed to discourage
uneconomic bypass. Consistent with this goal, we will require that
the company's implementing tariff be designed to avoid any harsh
results for customers who can demonstrate that, as of October 10,
1997, they had made a decision to proceed with and had made a
substantial investment in on-site generation, effectively
grandfathering them from the effects of the new rates.
Any municipality that forms its own electric system will
be required to pay for the generation facility costs that are
attributable to the customers who transfer to municipal service.
Consequently, we are granting the Settlement proponents' exceptions
concerning stranded cost recovery.
With respect to CPB's and Enron/Wepco's concerns about
the CTC being anti-competitive, their arguments are unpersuasive.
The application of this charge to all customers helps to ensure
that all generation will compete on an equal footing, thus
furthering development of a competitive market. Through our
continuing oversight of the company, and by enforcing applicable
Settlement provisions, we shall ensure that Niagara Mohawk does not
engage in predatory pricing, or any other anti-competitive behavior
during the transition to a competitive market or after a fully
competitive market is established. Also, the CTC cannot be rigidly
fixed for all customers initially without sacrificing the rate
decreases that customers are expecting to see in the company's
bundled rates pursuant to the Settlement.
6. ENRON/WEPCO RATE PROPOSALS
a. ENERGY BACKOUT RATE
The Judge recommends that we reject Enron/Wepco's
proposal to increase the amount to be backed out of Niagara
Mohawk's bundled rates when customers obtain commodity services
from other marketers. He considered the Settlement's provisions
covering this matter adequate for the limited period before the
independent system operator (ISO) begins to operate. He saw no
need to expend any substantial resources to devise a better
administrative method for setting this credit before a fully
competitive market emerges. Enron/Wepco except.
These parties say the Settlement's backout rate is too
low and anti-competitive because it does not reflect all the costs
that they claim an equally efficient rival would bear. At a
minimum, Enron/Wepco urge that the backout rate be adjusted for
property taxes, and that the New York Power Pool's (NYPP's) 18%
reserve requirement be substituted for the 14% figure the company
estimates assumed. They say there is no reason not to use the
NYPP's reserve requirements for 1998.
With respect to property taxes that were excluded from
Niagara Mohawk's original estimates, Enron/Wepco attempt to
demonstrate how this item could affect the calculation of
generation costs. Enron/Wepco say that Niagara Mohawk forecasted
$15/kW for capacity without accounting for property taxes. In
1997, the average real estate taxes the company paid on its steam
stations was $22.50/kW. Thus, they maintain that an equally
efficient competitor should receive a $37.50/kW capacity credit.
In addition to this, Enron/Wepco point to other costs
(administrative and general costs, depreciation, and allowances for
funds used during construction) excluded from the Settlement's
backout rate. In sum, they say the Settlement's backout rate
provisions are so low as to preclude rivals from entering the
market.
Enron/Wepco insist that a properly designed backout rate
should cover up to three to five years worth of generation costs.
But, they say, the Settlement's provisions neither cover the costs
for this period nor do they otherwise reflect long-run incremental
costs that are more properly used to set backout rates.
Finally, as a check on Niagara Mohawk's backout rate,
Enron/Wepco compared it to the then available backout rate proposal
in the NYSEG case. They say that the Judge's recommendations here
are inconsistent with those made by a different Judge in the NYSEG
case, which they prefer.
In response, Niagara Mohawk insists that the parties
negotiated a proper backout rate, and the forecasts of market
prices they relied upon are reliable. It says the long-run
incremental cost (LRIC) method Enron/Wepco favor should not be used
to administratively set the backout rate because past attempts to
do this resulted in much too high prices for independent power
production. According to Niagara Mohawk, competition currently
exists in the generation market and it requires no stimulation
before the ISO operates and the company divests its generation
facilities.
Niagara Mohawk admits that the Settlement's backout rate
is low but says it is not because the rate omits costs. It insists
that the low backout rate reflects low market prices and a surplus
of electricity that is driving energy prices down.
Addressing property taxes specifically, Niagara Mohawk
says the Settlement's backout rate need not be adjusted for this
cost because an equally efficient ESCO can purchase electric
commodities in the open market and need not build or operate any
generation facilities. Thus, an ESCO may never incur any property
taxes and, the company says, it would be incorrect to adjust the
backout rate for this.
With respect to NYPP reserve requirements, Niagara Mohawk
insists a 14% requirement is reasonable for 1998. It says the
current 18% standard is not pertinent because the New York State
Reliability Council is expected to only require a 14% reserve when
the ISO begins to operate later this year. In any event, Niagara
Mohawk says this item has only a small effect on the backout rate.
Finally, the company says whatever the settlement in the
NYSEG case is, it is not good precedent here and its circumstances
are distinguishable in any event due to different financial
circumstances between the two utility companies.
Staff criticizes Enron/Wepco's backout rate proposal for
not reflecting the current market price of power and as posing a
serious risk to the proper development of a competitive market.
Like Niagara Mohawk, it observes that marketers purchase power in
the open market from competing suppliers at market prices. Because
rivals need only incur these market prices, Staff suggests no
specific allowance is needed to cover Niagara Mohawk's property
taxes or any of its other costs. Staff concludes that it is market
prices, not Enron/Wepco's LRIC approach, that provide the proper
backout rate.
The company and Staff are correct that the backout rate
proposed here requires no change and this Settlement provision is
approved. As the company notes, competition has begun and
market-based transactions are occurring. The backout rate is
properly pegged to a market price and the forecast of such prices
negotiated by the proponents is both reasonable and the only such
forecast presented here. Finally, we concur that the financial
risks faced by Niagara Mohawk and NYSEG are different--among them
being Niagara Mohawk's agreement to accept poor earnings--and, in
any event, the NYSEG settlement is not precedental.
b. NIAGARA MOHAWK ENERGY SALES TO ESCOS
Enron/Wepco proposed that Niagara Mohawk be required to
sell energy to them and other marketers at the same price backed
out of the company's bundled rates. The company responded, saying
it would sell to them but only if it had hedged power left from
meeting its retail customers' needs. The Judge accepted Niagara
Mohawk's response; however, Enron/Wepco continue to urge that the
company be unconditionally required to provide them energy at the
Settlement back-out rate. They point to the Dairylea pilot program
and other utility companies' retail access programs where this
approach was used. They say a similar stop-gap measure is needed
here so competition can begin without ESCOs incurring losses.
Niagara Mohawk responds that it may not have sufficient
amounts of hedged power to provide electric commodities to ESCOs.
And, it says, the company should not be required to bear the
financial risk of providing unhedged commodities to marketers.
Requiring Niagara Mohawk to sell at its backout rate is
reasonable only to the extent the company has a sufficiently hedged
wholesale supply. And the company is willing to sell to ESCOs up
to that point. Beyond it, however, the effect of any such
requirement would be to expose the company to an unknown,
potentially significant risk, at a time when it is already in a
weak position. For this reason, Enron/Wepco's approach is not
reasonable here and its exception on this point is denied.
c. ALTERNATIVE RESIDENTIAL RATE DESIGN
The Judge found that the record did not demonstrate
sufficiently the merits of Enron/Wepco's alternative rate design
for the residential class. He recommended that the proposal be
examined further and addressed when the company presents its
unbundled tariffs for this class. This approach is similar to the
one we adopted in the Orange & Rockland rate restructuring case.
Enron/Wepco and Niagara Mohawk except.
Enron/Wepco urge that their alternative rate design be
adopted now since, they believe, they have shown its clear
advantages, including additional revenues for Niagara Mohawk. They
also say there would be no adverse customer impacts under their
proposal as residential customers' total bills would remain the
same as those produced by the current rate design. But, they say,
customers would benefit from the new design's lower usage-sensitive
energy prices.
On the other hand, Niagara Mohawk excepts to further
consideration for the Enron/Wepco proposal when it files unbundled
rates. It says the proposal has never been tried or fully
analyzed. It also contends that the proposal presents unacceptable
financial risks and it fears that no additional revenues would
materialize. According to Niagara Mohawk, Enron/Wepco overestimate
the price elasticity for the proposed price change. And, the
company is not sure that customers would like the alternative
design which it considers to be impractical and too costly to
administer.
Enron/Wepco respond by denying their proposal creates any
financial risk for the company and they stand by their price
elasticity estimates. According to them, there is no good reason
to delay a move to lower energy rates, given that customer charges
can be adjusted to maintain overall bill levels. They say that a
similar approach has worked well in the telecommunications industry
and suggest this could also work in the electric industry.
Staff responds to Enron/Wepco, saying the Judge properly
put off their alternative to when the unbundled tariffs are filed.
It says this is the best way to deal with the controversy and
uncertainty surrounding the proposal.
We shall adopt the Judge's recommendation to handle this
matter just as we did in the Orange & Rockland case. This
rate design proposal is basically the same as the one we previously
considered in the Orange and Rockland case, and it has not been
adequately developed for us to consider adopting it. The proposal
may therefore be raised again by Enron/Wepco and be explored
further when unbundled rates for the residential and small
commercial customers are filed.
7. GENERATION AUCTION INCENTIVES
The Judge recommends we adopt CPB's proposal to limit the
financial incentive payments to Niagara Mohawk when it divests its
fossil and hydro-generation facilities to 10% of any gain.
However, contrary to the CPB proposal that the ratepayer share of
the sale proceeds be used to fund rate reductions, the Judge
recommends instead that it be used to pay off stranded costs.
Niagara Mohawk, Staff, IPPNY, CPB, PULP, and Oswego except.
The company and Staff support the Settlement's auction
incentive provisions. Concerning the proposed incentive payments
for any sales made below book cost, they insist that the plants'
remaining original costs are irrelevant because the auction seeks
bids based on future expectations of electric generation costs and
revenues, not the plants' historic value. The company also
contends that ratepayers are fully responsible for its stranded
costs; therefore, they benefit from any proceeds obtained at
auction even if the plants are sold at a loss.
In further support of the Settlement's incentive
provisions, the company and Staff claim they properly align
ratepayer and shareholder interests and the graduated payment
feature reflects the fact that higher bids and sales prices are
harder to obtain. Nonetheless, if higher than expected prices are
achieved, they say, the Settlement precludes the company from
enjoying a windfall. These proponents claim the Judge's proposal
lacks these attributes.
Niagara Mohawk, Staff, and IPPNY also maintain that
incentives greater than the Judge proposes are needed to maximize
the sale price of the generation facilities. IPPNY notes that the
Settlement's auction incentive provisions are designed to
discourage the company from rejecting bids and to promote an
auction over a spin-off of the generation facilities to another
entity.
These three parties assert that the auction incentive
provisions are integral to the Settlement and shareholders expect
higher equity earnings, if the auction proves to be successful, in
exchange for otherwise accepting lower earnings. Niagara Mohawk
also argues it is entitled to the full incentive contained in the
Settlement, given its willingness to divest its non-nuclear
generation facilities. Similarly, Staff points to the benefits of
the company's withdrawal from the State's electric generation
market and argues such action warrants a strong incentive.
CPB excepts to the recommendation that the auction
proceeds be used to pay stranded costs. It urges that they be used
instead to provide residential and small commercial customers
greater rate decreases. Only after larger rate reductions are
achieved for these customers would CPB use any auction proceeds to
reduce stranded costs. CPB argues that public acceptance of the
Settlement can only be gained with larger rate decreases and the
auction proceeds provide a painless way to obtain them. It
suggests that a similar issue in the Orange & Rockland rate
restructuring case was resolved as it proposes.
PULP is opposed to divestiture by Niagara Mohawk until
comprehensive legislation is passed. Alternatively, it urges that
additional hearings or proceedings be held concerning the company's
generation divestiture plan filed on December 1, 1997.
Oswego urges that comments on the company's December 1997
divestiture plan not be considered until after we act on the
Settlement (a decision already made). However, until the economic
and other effects of divestiture of generation facilities are fully
evaluated and the impacts on local communities are known, Oswego
says we should not find the Settlement to be in the public
interest. According to Oswego, Niagara Mohawk has not provided
sufficient concessions to warrant as large a financial incentive as
the Settlement provides.
In response to PULP and Oswego, Niagara Mohawk sees no
need for further hearings or legislative action. The company also
suggests we fully addressed the merits of utility generation
divestiture in our Competitive Opportunities decision and argues
our prior conclusions are not undermined by the record here.
In response to Staff and the company, CPB insists that
Niagara Mohawk should not receive an incentive for sales made below
book value because ratepayers will have to pay for more stranded
costs as a result. It argues the company should only be rewarded
for obtaining a gain. As to the amount of an incentive the company
should be allowed to earn, CPB says a 10% incentive is ample and
anything more, in its view, would be excessive.
We find with respect to Niagara Mohawk's non-nuclear
generation units, except for the Oswego facilities, 15% of any
gain the company achieves above net book value is a sufficient and
proper incentive for it to obtain the best possible prices for
these facilities at auction. As to Oswego's and PULP's procedural
proposals, having decided to approve the Settlement with the
modifications presented herein, we will next consider Niagara
Mohawk's divestiture plan and the parties' comments concerning it.
Given the ample record in these proceedings, there is no need for
any additional hearings concerning the divestiture of the company's
non-nuclear generation facilities.
8. NUCLEAR GENERATION FACILITIES
The Settlement provides that:
[t]he nuclear assets held by Niagara Mohawk
will remain part of [the transmission and
distribution company] as a separate business
unit until they are either transferred or
divested.
Niagara Mohawk will continue to pursue
statewide solutions for its nuclear assets
through discussions in formation of NYNOC and
in any generic proceedings established by the
Commission. Statewide solutions for nuclear
plants will be explored before other
potential solutions.
Absent a statewide solution, Niagara Mohawk
commits to file a detailed plan, analyzing
the proposed solutions for its nuclear
assets, within 24 months of this Settlement
Agreement. The plan will consider the
feasibility of auction, transfer, and/or
divestiture of Niagara Mohawk's nuclear
assets. The detailed plan will undergo an
appropriate level of Commission review and
approval to be concluded on an expedited
basis.
The Judge recommends approval of this Settlement
provision, and NYSEG excepts. Rather than pursue a statewide
solution or consider a Niagara Mohawk plan thereafter, NYSEG urges
that the company be required to auction its nuclear assets now to
resolve this issue expeditiously. It considers the Settlement too
open ended and insists that a continuation of the status quo is
intolerable and contrary to our goal of obtaining complete
divestiture of all utility generation facilities. NYSEG takes no
solace in the fact that nuclear generation matters are currently
being considered in Case 94-E-0952.
Niagara Mohawk, Central Hudson/LILCO/RG&E, and Staff
respond to NYSEG. The company says the Settlement approach is best
because it neither delays the resolution of nuclear matters nor
forestalls their proper consideration. It considers Case 94-E-0952
a better place to determine whether a nuclear auction should be
pursued.
The other utility companies agree with Niagara Mohawk on
the latter point and dispute NYSEG's assertion that an auction
would provide certainty. They say there are regulatory approval
problems inherent with an auction that may not be easily resolved.
Staff responds that the Settlement is neither adverse to
nor inconsistent with NYSEG's preference for a nuclear auction
because that result is not precluded. Staff insists that all
worthy alternatives should be examined in Case 94-E-0952 before a
decision is reached.
It is clear that the disposition of Nine Mile 2 directly
involves the other utilities and any resolution would affect each
of them. Rather than seek to resolve such matters here, the
Settlement properly acknowledges the currently ongoing statewide
efforts and provides a reasonable period for Niagara Mohawk to
submit its own proposal if the ongoing efforts fail. Moreover, we
are considering divestiture of nuclear generation in Case 94-E-0952
and we have no plans to delay that proceeding.
NYSEG's exception is therefore denied.
9. NIAGARA MOHAWK'S IDENTITY AND ROYALTY PAYMENTS
a. USE OF THE CORPORATE NAME
Enron/Wepco proposed that Niagara Mohawk's affiliates be
precluded from using the corporate name and logo in their
marketing, particularly in the company's service territory. The
Judge did not recommend their proposal and these parties except.
Enron/Wepco say the Niagara Mohawk affiliates will obtain
a competitive advantage from using the company name but it does not
provide them with any greater efficiency, which should be the
primary determinant of whether a competitor succeeds. In contrast,
they say, new market entrants will have to expend substantial sums
to establish their own brand names. Alternatively, if the
affiliates are allowed to use the utility name, Enron/Wepco urge
that a royalty be imposed to capture the name's value. These
parties say one or the other approach is needed to ensure that
affiliates do not dominate the energy services market simply by
virtue of their association with the incumbent utility.
Niagara Mohawk replies that its affiliates should be
allowed to use its name. It says the name's value is uncertain
but, in any event, its use should not be restricted nor should its
affiliates be handicapped from the start. Other potential
competitors, according to Niagara Mohawk, are large, well-funded,
and fast becoming known to the consuming public. In this context,
the company says there is no reason to place it at a competitive
disadvantage.
We are not persuaded that a utility must be denied the
use of its name and identity in its own service territory for
competitors to be able to enter the market and compete
successfully. Whether or not a utility affiliate is known to
operate in the same market, competitors will, in any event, have to
establish themselves and advertise. The exception is denied.
b. ROYALTY PAYMENTS
The Settlement provides that the rate plan:
. . .shall be in lieu of any and all
"royalty" payments that could or might be
asserted to be payable by any affiliate or
imputed to [Niagara Mohawk] or credited to
[Niagara Mohawk] customers at any time,
including after the expiration of this
Settlement.
The Judge recommends that royalty payments not be
required during the term of the Settlement because the company's
low earnings during this period could reasonably be considered to
subsume a royalty. However, he recommends that we not accept this
provision to the extent it would exempt the company and its
affiliates from making royalty payments indefinitely, even beyond
the term of the agreement. The company, Staff, and PULP except.
Niagara Mohawk says its low earnings under the Settlement
and the $2 billion of stranded costs it is absorbing warrants
permanent elimination of any royalty. As elsewhere, it insists
that this provision is integral to the deal it struck. And it
insists that the company's affiliates should not be hindered in
their future competitive efforts by having to make any such
payments.
The company believes that changes in the electric
industry since the Commission first adopted its royalty policy
support the Settlement's approach. It also points to our approval
of a recent settlement involving Consolidated Edison Company of New
York, Inc. as precedent supporting approval of this Settlement
provision.
For its part, Staff points to the Settlement's affiliate
transaction rules and its code of competitive conduct as reasons
for eliminating royalty payments. It observes that, once the
royalty requirement is dropped and affiliates begin to use the
corporate name, it will become more difficult to apply the royalty
concept fairly thereafter. Staff therefore argues against any
reexamination of this matter at the Settlement's end.
If Niagara Mohawk forms a holding company, PULP contends
unregulated affiliates that use the corporate name and advertise
their affiliation should be required to pay royalties to compensate
the regulated utility company for the competitive value of this
use. The company's current financial condition, according to PULP,
is no excuse for not requiring a royalty, especially given that a
royalty would be a beneficial source of new revenues. Further,
PULP contends Niagara Mohawk should receive substantial royalty
payments given that the Settlement allows the company to pay up to
$625 million of dividends to a new parent company.
In response to PULP, Niagara Mohawk argues that the
Settlement's corporate structure and dividend payment provisions
are reasonable and supported by the record. The company maintains
that the rate plan subsumes an unquantified but certain sum to
compensate for the use of the corporate name and argues that
royalty requirements are fast becoming obsolete in any event.
Staff replies that PULP is also incorrect to suggest there will be
any additional money available to pay a royalty.
For its part, CPB urges us not to rule out the
possibility of an explicit royalty payment at a later date. It
says it is best to reserve the right to examine this issue after
the company's current circumstances are resolved and when it can be
considered as a matter of long-term policy.
It is permissible for the proponents of rate settlements
to address the issue of royalty charges in any rate plan they
submit, as the parties have done here. And, if a rate plan is
otherwise acceptable, we would not necessarily reject it if it
contained no explicit amount earmarked as such. Instead, we
examine a proposed settlement as a whole to determine whether it is
reasonable. In this instance, we are satisfied with the rate plan
being proposed for the next five years and we see no need to impute
or ascribe any additional royalty amounts to the company, either as
a matter of general policy or on the basis of arguments presented
here. We therefore reject PULP's and Enron/Wepco's exceptions.
As to whether the company should be subject to any
royalty payments subsequent to the rate plan's five-year term, we
are adopting the Settlement subject to the condition we will not
preclude parties from raising and having the issue considered
again, with any royalty to be effective, if ever, after this
Settlement ends.
10. GENERIC AND CASE-SPECIFIC DETERMINATIONS
The Judge accepted the Settlement's dividing line between
those issues which would be fully resolved here on a
company-specific basis and those which would be resolved in generic
cases. Enron/Wepco except to this recommendation to the extent the
Settlement's affiliate transaction rules and competitive code of
conduct would remain in place for the Settlement's term even if
intervening generic decisions are different. Similarly, they
except to the extent the Settlement would establish specific
creditworthiness requirements for ESCOs that operate in Niagara
Mohawk's service territory.
Enron/Wepco contend the negotiations that produced the
Settlement should not dictate our policies to foster competition.
They complain the Settlement's provisions restrict our flexibility
to address competitive market developments, and claim the
Settlement's rules are too inflexible, impairing competition and
barring us from taking remedial action when necessary. These
parties ask that we reserve the right to apply different rules and
codes produced on a generic basis.
As to the Settlement's creditworthiness requirements for
ESCOs, Enron/Wepco again claim the provisions will impede
competition. They say the company does not require as much
security as it seeks to obtain from ESCOs. Accordingly, they
contend these requirements amount to an unfair barrier to entry
that should be rejected. The details of implementing retail
access, they say, should be the subject of further proceedings
rather than be codified by the Settlement.
Niagara Mohawk responds that the Settlement is intended
to protect the company, during its term, from adverse financial
impacts that could occur were changes made to our regulatory
approach to affiliate relations. Staff observes that the
Settlement's standards for competitive conduct do not provide the
company any license to act improperly. Staff adds that the
Settlement contains procedures for resolving competitor complaints
and violations of its standards. Thus, Staff sees no reason why
such matters should be referred to a generic proceeding.
As to the Settlement's ESCO creditworthiness
requirements, the company says they are needed to protect against
the risk of an ESCO's default, in which case Niagara Mohawk would
be obligated to pay for power needed to serve affected customers
until they switch to another provider. Staff responds that the
Settlement's creditworthiness requirement is commensurate with the
company's financial exposure inasmuch as defaulting ESCOs may owe
the company for three months or more of service.
We find no need or reason to disturb the Judge's
recommendations on these matters. We find that the Settlement's
affiliate relationship rules and its code of competitive conduct
are reasonable in the context of the overall agreement. Also, the
Settlement's ESCO creditworthiness provisions are justified given
the extent of the company's financial exposure. Accordingly,
Enron/Wepco's exceptions are denied.
As a final matter in this category, we note that the
Settlement requires all customers in S.C. 3 and above to have an
hourly interval meter whether or not they select an alternative
energy supplier. Under the Settlement, such customers would
bear the incremental cost of a new meter unless we decided
otherwise as a matter of general policy. S.C. 3A and 4 customers
already have such meters but S.C. 3 customers may have to obtain
them by May 1999.
We plan to consider, as a generic matter, whether
customers should be required to bear the cost of new meters and we
may adopt new metering standards for use in 1999. Therefore,
Niagara Mohawk customers will not be required to purchase any
replacement meters until the standards for 1999 are known.
11. STATE ENVIRONMENTAL QUALITY REVIEW ACT FINDINGS
On May 3, 1996, in conformance with the State
Environmental Quality Review Act (SEQRA), we issued a Final Generic
Environmental Impact Statement (FGEIS) which evaluated the action
adopted in Case 94-E-0952, the generic Competitive Opportunities
Proceeding. The individual electric utility companies were
subsequently required to provide individual environmental
assessments of their restructuring proposals. Niagara Mohawk
provided its Environmental Assessment Form (EAF) and SEQRA
recommendation on August 26, 1997. The company supplemented its
EAF on November 4, 1997 and addressed the environmental
implications of Settlement provisions that differed from the
company's original proposal. Parties to these proceedings were
requested to provide their comments on the supplemented EAF either
by December 3, 1997 or with their trial briefs. Comments on this
matter were received from various parties, including SHAG, MI, and
Oswego.
The information provided by Niagara Mohawk in its EAF,
the parties' comments and responses, and other information were
evaluated in order to determine whether the potential impacts
resulting from adopting the Settlement's terms would be within the
bounds and thresholds of the FGEIS adopted in 1996. Arguably, all
of the potential impacts need not be considered given that some
result from Type II exempt rate actions. Nonetheless, the analysis
examined all areas in which impacts would reasonably be expected.
No impacts were found to be associated with the
Settlement's treatment of the competitive transition charge (CTC).
Localized community economic impacts may occur (e.g., due
to reduced tax receipts or employment at existing generating
stations), but these would be balanced by positive effects in other
localities.
Another potential concern is the possible increase in air
pollution that could accompany increased demand for electric
energy. It is possible that increases in energy demand will result
from the Settlement's decrease in rates and in DSM expenditures:
0.50% average annual increased demand over the 1997-2012 period
from the former and 0.13% increased demand from the latter. Each
of these incremental growth rates is an upper bound. For example,
it is not clear that all of the rate reductions from the Settlement
should be attributed to restructuring; and the lower DSM
expenditures do not consider ESCO DSM spending. Staff's view is
that the actual growth rates will be substantially less than the
corresponding rates in the FGEIS (1% annual incremental growth from
the "high sales" scenario, and 0.29% from the "no incremental
utility DSM" scenario).
Because of the inherent uncertainty in forecasting future
impacts, as a matter of discretion, monitoring of the restructuring
and environmental impacts is being implemented and a system
benefits charge is being established.
Based on these analyses, the potential environmental
impacts of the Settlement are found to be within the range of
thresholds and conditions set forth in the FGEIS. Therefore, no
further SEQRA action is necessary. We note, however, that we will
act in the future on the company's plan for auctioning its
generation assets. Additional SEQRA analysis may be required at
that time.
12. OTHER MATTERS
a. COST ALLOCATION MANUAL REVIEW PROCEDURES
The Settlement requires Niagara Mohawk to file a cost
allocation manual with the Director of the Office of Accounting and
Finance that will become effective 30 days after it is submitted if
the Director accepts the company's filing. The Judge
recommended that the National Electrical Contractors Association
(NECA) and other interested parties be allowed to examine the
company's proposed manual and submit comments to the Director for
his consideration.
On exceptions, Niagara Mohawk says acceptance of the
Judge's recommendation would change the Settlement which did not
contemplate an opportunity for anyone to submit comments concerning
the manual. The company also says it did not expect the Director
to approve the manual but merely to accept it for filing purposes.
While Niagara Mohawk does not object to NECA inspecting its
proposed manual, it is opposed to NECA, or any other party, slowing
the process the Settlement envisions.
We adopt the Judge's recommendation allowing anyone
interested in the company's cost allocation manual to submit timely
comments to the Director of the Office of Accounting and Finance
before he accepts the proposed manual. If need be, the Director
can postpone the effective date of the manual, or any subsequently
proposed amendments and supplements, beyond the 30-day period
stated in the Settlement if additional time is required to consider
any comments he receives. If the company submits a proposed manual
which the Director considers to be unacceptable, our understanding
of the Settlement is that he has the authority to refuse to accept
the company's filing. In any event, by allowing parties to file
comments we do not intend that there be any delay in this process.
b. DISCLOSURE OF SOCIAL SECURITY NUMBERS
DOL proposed that Niagara Mohawk be required to inform
customers in all instances that provision of social security
numbers to an ESCO is not necessary to obtain electric service.
The Judge recommended against the proposal.
On exceptions, DOL urges that customers be notified of
their right to decline to provide their social security information
and that such action will not adversely affect service. DOL says
customers should know that they can keep this information private
to avoid its misuse.
Niagara Mohawk responds that it complies with laws that
apply to social security numbers and it knows of no customer who
has been injured by having been asked to provide the company this
form of identification. It urges us to refrain from imposing new
disclosure requirements that neither Congress nor the Legislature
has seen fit to impose.
DOL also presented its concerns about the use of social
security numbers in a recent rulemaking proceeding, Case 96-M-0706,
in which we changed some of our consumer protection rules to
streamline their operation, remove burdens on utility companies,
and maintain adequate customer protections. In that case, we said:
In its comments on the Revised Rulemaking,
[DOL] again argues for a prohibition on
social security numbers, or that potential
customers should at least be informed that
disclosure is voluntary and no harmful
consequences will come to those who refuse to
supply it. [DOL] does not offer any new
reasons why the use of social security
numbers should be prohibited; we will not
revise the proposal on this matter. However,
we do agree that potential customers should
not be coerced into revealing social security
numbers or left with the impression that
refusal to reveal a social security number
will result in harmful consequences. If
customers are asked for a social security
number, they should also be made aware that
they are not required to give it, and that
other identification will be accepted.
The rule we adopted applies to this situation and all
ESCOs; this statement addresses adequately the concerns DOL raised
in these cases.
c. FUTURE TAX REFUNDS
The Settlement seeks to streamline the handling of future
tax refunds and deficiency assessments. The company would keep any
refunds of up to $500,000 each and it would not be able to recover
any liabilities up to this amount. Refunds and liabilities
exceeding this amount would be deferred for disposition after the
Settlement term. According to the Settlement, the company
would not file a formal notice of the tax refunds it receives nor
would additional hearings be convened.
In response to DOL's objection to this proposed
procedure, the Judge recommended that the company continue to
provide formal notice of its refunds and that a decision on whether
to hold a hearing be made after such notice is provided. The Judge
supported the Settlement's substantive treatment of future refunds
and recommended that the company have the benefit of a rebuttable
presumption that the Settlement results should apply.
On exceptions, Niagara Mohawk urges that the Settlement's
approach to future refunds be adopted in its entirety. It insists
that notice and hearings should not be needed for any refunds under
$500,000.
In response, CPB urges us to preserve the option to hold
a hearing in any instance that may warrant one. It agrees with
Niagara Mohawk that hearings are not needed for trivial matters
but, it says, that should be decided after notice is provided.
The notice requirements implementing PSL 113(2), set
forth at 16 NYCRR 89.3, will be followed since they are not
burdensome and we reserve the right to schedule a hearing upon the
filing of such notice. However, we will establish a rebuttable
presumption that all refunds received during the Settlement's term
should be accounted for and applied as the Settlement provides.
The Settlement provision is adopted subject to this change or
condition.
d. RESIDENTIAL HYDROELECTRIC ALLOTMENTS
PULP objects to the Settlement's method for providing
residential customers the benefit of certain low-cost hydroelectric
power to which they are entitled. Rather than include this cost in
the company's base rates, it would prefer to see hydropower
separately stated on customers' bills without any markups. PULP
says its approach is consistent with the move to unbundled charges,
and it asserts its proposal should be adopted to ensure residential
customers receive their full allocation of this low-cost
electricity. Essentially, PULP is concerned customers may end up
paying more for NYPA hydropower based on its market value.
The Judge recommended against this proposal because PULP
did not show the Settlement would deprive residential customers of
any of the benefits of their allocation of this power. PULP
excepts, requesting that further proceedings be established at
which Niagara Mohawk would prove the Settlement approach is the
best means to provide hydropower benefits to residential customers.
Niagara Mohawk responds, pointing to testimony and other
information establishing that residential customers will continue
to receive all their hydropower benefits of approximately $45
million per year. Similarly, Staff affirms that unbundling
electricity charges will have no impact on the customers'
hydropower benefits and they will receive them no matter who is
their chosen supplier. Staff notes also that NYPA, the authority
charged with the responsibility of administering this power,
supports the Settlement, among other reasons, because it ensures
residential customers will continue to receive their full
hydropower benefits.
Having considered PULP's points, we find that the Judge's
recommendation properly resolves this matter. For the reasons
offered by the Judge and the parties, PULP's exception is denied.
e. PULP'S LEGAL ARGUMENTS
PULP excepts to the Settlement's approach for
implementing competition in the electric industry and claims we
lack authority to implement its provisions. First, it objects to
an expansion of LICAP through 2002 because it generally does not
include customers who receive public assistance. It claims that
these customers should have the same opportunity to obtain
favorable credit terms as non-recipients of public assistance and
that LICAP violates the Equal Credit Opportunity Act (ECOA).
PULP insists that LICAP coverage of public assistance customers in
the Child Assistance Program and the company's willingness to test
a pilot program for public assistance customers is not enough to
satisfy the ECOA's requirements.
Next, PULP claims the Settlement's utility generation
divestiture provisions would adversely affect the company's ability
to provide adequate service, as the company would no longer own and
operate facilities needed to supply customers. At most, it
believes that the Settlement's proponents should have developed a
proposal for comprehensive restructuring legislation rather than
pursue generation divestiture through the Settlement.
Similarly, PULP objects to the Settlement provisions
contemplating that ESCOs will sell electricity to the public. PULP
insists that they cannot do so without satisfying statutory
requirements applicable to electric utility companies. It says all
market entrants should be required to provide the customer service
and rate protections that public utilities are currently required
to provide.
PULP also says the Settlement's retail access plan is
impermissible. Rather than allow the market to set electricity
prices, PULP says administrative action must set just and
reasonable prices for adequate service. PULP doubts that adequate
competition will emerge to protect customers' interests and it
would prefer to see legislation establish competition in the
electric industry. At a minimum, PULP urges us to condition the
Settlement's approval on the formation of an adequate competitive
electric market in which no sellers can exercise market power. It
objects to any relaxation of the service rules applicable to
electric utilities for the benefit of the ESCOs.
Finally, PULP claims that, before we can establish any
competitive opportunities policies, legislation should address the
impacts of such changes on municipalities. As tax bases and local
employment may suffer, PULP urges legislation be passed to address
these matters.
In response, Niagara Mohawk and Staff insist that PULP is
viewing the applicable legal requirements too restrictively and it
is ignoring recent case law that supports the approach being used
here. Staff also says PULP's legal arguments have already been
presented, considered, and rejected.
With the exception of PULP's challenge to Niagara
Mohawk's LICAP, this party has not presented any new legal
arguments or theories that we have not already considered and
rejected. They deserve no further consideration here and PULP's
exceptions on them are denied for reasons explained elsewhere.
As to LICAP, we are satisfied it does not violate the
Equal Credit Opportunity Act. To begin, LICAP is not primarily
intended to be a mechanism for providing credit to customers.
Instead, it is a means for the company to control its
uncollectibles and the amount of bad debt it incurs, benefiting all
customers. Moreover, even if the ECOA applies, a creditor does not
violate the law if a refusal to extend credit to a public
assistance recipient is made pursuant to a program otherwise
expressly authorized for a class of disadvantaged persons.
The LICAP proposal targets such a group, while taking into account
the limited resources available for such a program in the
circumstances presented. Finally, to the company's credit, it has
agreed to substantially enlarge the scope of this program and make
it applicable to more public assistance recipients. The company
has also not ruled out the possibility that a suitable program to
decrease arrears and uncollectibles might be developed for other
public assistance customers. For all of these reasons, PULP's
exceptions to the LICAP recommendations are denied.
f. STANDARD PERFORMANCE CONTRACTS
With respect to system benefits charges (SBC), the
Settlement says:
[n]othing in this agreement will prohibit the
Statewide administrator from allocating a
significant portion of the total SBC revenues
derived from Niagara Mohawk's customers to be
disbursed within Niagara Mohawk's service
territory through competitive standard
performance contracts which provide for
stipulated pricing for energy efficiency,
consistent with any generic guidelines for
SBC expenditures separately developed from
this proceeding by the PSC.
In its initial trial brief in these cases, NAESCO
supported the Settlement's SBC provisions. Pointing to this
provision, NAESCO said it supported the competitive distribution of
energy efficiency funds through a standard performance contract
mechanism with stipulated pricing. The Judge recited NAESCO's
position in the recommended decision and MI, another Settlement
supporter, excepts.
MI disputes NAESCO's characterization of the provision
and says its clear language does not provide support for standard
performance contracts. According to MI, this provision merely
preserves the matter for a future generic proceeding and the
Settlement would permit such contracts to be used in the Niagara
Mohawk service territory if they are allowed as a matter of general
policy. NAESCO does not respond to MI's description of this
section.
MI is correct that the Settlement only establishes that
the use of standard performance contracts is not barred by the
agreement. Whether such contracts should be employed remains open
for further consideration.
g. LOCAL TAXES AND THE CTC
The City of Oswego claimed that the Settlement would
adversely affect its tax structure and eliminate a significant
source of its tax revenues. It proposed that lost tax revenues,
due to reductions in the value of utility generation assets, be
included in the CTC as part of the transition to a competitive,
electric generation market. The Judge recommended that this
proposal be rejected and Oswego excepts.
Oswego says the Commission has the authority, and the
public interest would be well served, to require that local taxing
jurisdictions recover lost tax revenue through the CTC. However,
Niagara Mohawk urges that local municipalities not be allowed to
recover the cost of governmental and local services in utility
charges applicable to all customers. The company says it is unfair
to burden customers elsewhere with the costs for local services,
which do not benefit and cannot be controlled by them.
Staff responds that Oswego's tax problems are not due to
the Settlement. It observes that the Settlement neither changes
the City's tax base nor alters Oswego's assessment of the company's
property. If anything, Staff says, the Settlement serves Oswego's
interests by providing for three-year energy purchase contracts for
the generation units that are sold. The allowance made for such
contracts presumes that property taxes will continue to apply.
The City of Oswego's proposal to include "stranded taxes"
in the CTC is denied. We agree with the company that there are
inequities in including any such amounts in the CTC that applies to
all customers. Staff is also correct that the Settlement provides
the City, and other municipalities that host utility generation
facilities, a transition period with the energy purchase contracts
Niagara Mohawk expects to execute with the firms that buy its
plants.
h. ADDITIONAL PUBLIC COMMENTS
The recommended decision considered the comments made by
customers and their representatives at the public statement
hearings and in correspondence. Written comments from persons
interested in the Settlement continued to be submitted after the
recommended decision was issued. For example, substantial comments
about numerous Settlement provisions have been received from The
Wing Group, a City of Buffalo Council Member, and a Washington,
D.C. public utility consultant. Comments have also been received
from the Sierra Club in the Niagara region, and the Statewide
Senior Action Council, which reinforce the statements made by their
respective members at the public statement hearings. Various firms
interested in self-generation and customers interested in municipal
power have also continued to submit comments on the Settlement's
provisions, all of which have been considered.
i. RECENTLY SETTLED AND CORRECTED MATTERS
By letter dated January 22, 1998, Niagara Mohawk notified
us that, as contemplated by the Settlement, various parties had
considered the details of an implementation mechanism for the
expanded LICAP program and had reached an agreement. These parties
arrived at a performance incentive mechanism that contains annual
enrollment, service, and workshop goals for the company to meet.
Niagara Mohawk's failure to achieve these goals would subject the
company to financial penalties of up to $1.1 million per year. The
company will also provide quarterly and annual reports concerning
its progress and performance.
By letter dated January 23, 1998, the company also
notified us that various parties have agreed on provisions for the
customer service backout credit, as provided by the Settlement.
Niagara Mohawk's revenue exposure for these credits is limited to
$30 million during the first three years covered by the Settlement.
This amount is allocated among the company's service classes and,
if the class allocations are reached, access to the credits will be
restricted. Staff will review the company's subscription levels,
historical data, and its calculations when the available amounts
may be exhausted. ESCOs will also be informed of the amounts that
remain available to them.
While we received these agreements after briefs opposing
exceptions were filed, the parties to these proceedings were on
notice that these matters would be considered and that the details
of the LICAP performance incentive mechanism and a customer service
backout credit would be submitted to us for consideration with the
Settlement. This approach drew no objections when it was presented
nor has any party criticized the specific provisions that have been
reached. Accordingly, we will adopt the agreed-upon terms for
these two additional issues.
Finally, by letter dated February 13, 1998, Niagara
Mohawk notified us that a provision the parties had intended to
include in the Settlement was inadvertently omitted. The
Settlement eliminates Niagara Mohawk's fuel adjustment clause
(FAC). However, when the FAC ends, the company will have either a
positive or negative deferred fuel balance that must either be paid
back to customers or collected from them. The settling parties
intended to include in the Settlement a provision to flow through
the deferred fuel balance to customers over two monthly billing
cycles. To accomplish this, the company has provided a revision
for Settlement 4.3.1. We accept this revision to the Settlement to
the extent it allocates to customers deferred costs or benefits
properly allocable to them.
j. FINCH'S EXCEPTIONS
Finch urges us to adopt and apply four general principles
to on-site generation:
(1) Supplemental service rates for on-site
generators should be the same as the rates
that apply to full service customers in the
same service category;
(2) Backup and maintenance service rates for
on-site generators should be set using the
same cost method that is used to develop
rates for similar full requirements
customers;
(3) On-site generators should be given the
option to obtain firm service at the same
rates that apply to similar customers without
on-site generation; and,
(4) Customers with existing on-site
generation facilities should not be
transferred to a new service class that would
substantially increase the rates applicable
to them.
Finch complains that the Settlement proponents have not
provided a proposed tariff for the on-site generation parties to
examine and see how the Settlement would actually apply to them.
It insists that only a smattering of general concepts has been
offered for consideration. Finch is concerned about such things as
the amount of the proposed access charges, the applicable energy
rates, surcharges, and reconciliations. It also claims that the
proponents do not share a common understanding of the Settlement's
on-site generation rate, tariff, and stranded cost provisions.
Given such uncertainties as these, Finch says, it is impossible for
on-site generation customers to determine how the Settlement
specifically affects them. It believes this portion of the
Settlement should be rejected and Niagara Mohawk should be required
to provide a specific proposal for consideration now.
Also with respect to the Settlement's on-site generation
provisions, Finch claims they are unduly discriminatory, unjust and
unreasonable, and not in the public interest. It says they are
contrary to the Public Service Law, the Public Utility Regulatory
Policies Act (PURPA), and the Federal Energy Regulatory Commission
(FERC) regulations implementing PURPA. Further, it maintains they
are anti-competitive and preclude on-site generators from using
economically competitive alternatives.
In response to Finch, the company points out that this
party entered the proceedings after the close of the record, did
not contribute to the record, and did not participate in the
settlement process. Nonetheless, the company responds to Finch's
policy and legal arguments.
As to Finch's concerns about rate discrimination, Niagara
Mohawk says the existing and proposed service classes for on-site
generators are based on their common characteristics and cost of
service. It points out that such customers require continuous
connections to the company's system for backup power and, as a
group, they have distinguishable load and cost characteristics.
The company contends that the Settlement's provisions for these
customers are designed to recover the fixed costs associated with
each customer's historic level of usage and to recover a proper
share of stranded costs. Thus, the company says Finch errs in
claiming that the Settlement's S.C. 7 provisions are not cost
based.
With respect to whether the intended revisions for S.C.
7 should have been submitted with the Settlement, Niagara Mohawk
says the Settlement contains the complete proposal for revising the
service classification and nothing more is needed for it to be
approved. Given the complexity of these proceedings and large
amount of activity they require, the company claims it is
reasonable for action on the S.C. 7 tariff revisions to follow the
Settlement's approval.
Concerning the claim that the on-site generation rate
proposal violates state and federal statutes and regulations,
Niagara Mohawk denies Finch's assertion. The company insists that
the Settlement's provisions are consistent with PURPA and FERC
regulations requiring that accurate data and consistent systemwide
costing principles be used to set all customers' rates. Finch
objects to the rate reductions for customers other than on-site
generators; but, the company says this aspect of the Settlement is
not discriminatory. Niagara Mohawk points out that the parties
vigorously negotiated allocation of the rate decreases and applying
the rate decreases to full service customers is fully justified.
Next, Niagara Mohawk says on-site generators must pay
stranded costs because the company stands ready to serve their load
requirements at any time. According to the company, the valid
reasons for not treating on-site generators the same as full
requirement customers include the need to discourage uneconomic
bypass and to avoid shifting costs to other ratepayers.
Finally, the company says the Settlement's on-site
generation provisions are clear and it will not have any
difficulties submitting a revised S.C. 7 that complies with the
Settlement. To the extent any party's view of the Settlement's
requirements differs from the company's, it says any such matters
can be resolved when the revised tariffs are filed.
MI says Finch's claims of disparate treatment should not
be credited because the Settlement does not produce or require any
such results. MI suggests that Finch wait and see the new, on-site
generation tariffs the company proposes, and the results of Niagara
Mohawk's generation auction, before it launches any such charges.
MI is correct that Finch's concerns about the actual
rates and charges Niagara Mohawk will file to implement the
Settlement's provisions applicable to on-site generation are
premature and should await the company's tariff filing. When the
tariff is submitted, Finch and other parties will have an
opportunity to examine it and provide their comments.
In any event, Finch's broad criticisms and legal
challenge of the Settlement's on-site generation provisions are
rejected. Like all other classes of customers, the on-site
generators that subscribe to Niagara Mohawk's backup and
supplemental services must bear a portion of the company's stranded
costs in fairness to all other customers who must also pay these
costs. Moreover, it is reasonable to revise the S.C. 7 tariff due
to the company's restructuring and the transition being made to a
competitive market. During the transition period, uneconomic
alternatives should not be encouraged as the company must be
assured of a reasonable opportunity to pay its MRA-related costs.
We have examined Finch's claims of discrimination and
anti-competitive rates and find that the Settlement's on-site
generation provisions do not violate any state or federal
requirements that preclude undue discrimination and anti-
competitive behavior. The Settlement proponents have detailed and
supported the Settlement's acceptable approach to this class of
customers. Clear differences exist between these customers and the
company's full requirements customers supporting the separate
classifications and the differing treatment they receive under the
Settlement. There is, therefore, no need to adopt Finch's four
general principles for on-site generators. The principles we
normally adhere to design rates and to allocate revenue
requirements will continue to apply except to the extent the
Settlement requires any departures for its proper implementation.
Finally, as discussed above, in making the transition
from the existing S.C. 7 tariff to the revised tariff required by
the Settlement, we are concerned that there not be any harsh impact
for customers who, as of October 10, 1997, decided to implement
on-site generation and have made a substantial investment. Niagara
Mohawk will be required to present a proposal addressing this
concern, and the parties may comment on it, before we consider the
company's revised tariffs for S.C. 7. To the extent any other
matters require our attention, there will be ample opportunity for
the parties to state specific concerns in their comments on the
company's on-site generation tariff revisions.
k. RECOVERY OF COSTS ASSOCIATED WITH TERMINATION OF GAS
TRANSPORTATION AND PEAK SHAVING AGREEMENTS
Appendix B of the Settlement provides that the company
would continue to recover, solely from gas customers, lost revenues
or additional costs incurred in connection with new peak shaving
and gas transportation contracts, in effect extending the terms and
duration of the Stipulation and Agreement among the parties in
Cases 95-G-1095 and 95-G-0091. We approve the gas-customer-only
recovery mechanism to the extent it is limited to lost revenues and
replacement costs incurred between now and October 31, 1999, as
provided in the Gas Stipulation and Agreement. However, without
fuller explanation of the relative benefits of restructuring the
peak shaving and transportation contracts, we are unwilling at this
time to extend this gas-customers-only recovery mechanism beyond
October 31, 1999. We shall review the appropriate allocation
between the gas and electric departments at the time the company
files its proposed recovery mechanism of such lost revenues and
replacement costs beyond October 31, 1999.
l. SERVICE QUALITY INCENTIVE
Section 6 of the Settlement describes a service quality
incentive whose total value is $6.6 million (30 basis points) per
year. The total would be allocated one half to a customer service
performance inventive and the balance would be for a service
reliability incentive. The company is not now providing high
levels of service and it will continue to face serious financial
pressures. In these circumstances, a strong incentive is
appropriate. To ensure that the company remains focused on its
service obligations during the Settlement term, this provision is
adopted subject to the modification that the $6.6 million is
doubled and all the maximum dollar penalties associated with
various scored intervals are doubled accordingly.
CONCLUSION
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The terms of the Settlement and the Master Restructuring
Agreement, summarized and discussed above, will offer a generally
sound regulatory framework for Niagara Mohawk, its competitors, and
its customers in the transition to fully competitive generation and
energy services markets. Among other things, the Settlement and
MRA reverse the upward spiral of rate increases experienced by
ratepayers in the past and replace it with significant rate
decreases. These rate reductions, brought about primarily by the
company's absorption of up to $2 billion in revenue losses, savings
from the MRA, and reduced taxes, avoid the need to consider the
company's alternative pending request for a $3.25 million (10.5%)
rate increase and the prospect of further rate increases driven by
uneconomic power purchase contracts. The majority of the
nominal revenue reductions will be enjoyed by the residential and
commercial classes. At the same time, significant rate reductions
will be implemented for large industrial and commercial customers,
reductions which are essential to attract and retain jobs and boost
the economy of upstate New York. Other important benefits include
the company's prompt divestiture of its fossil and hydro generation
and the restructuring of a substantial amount of IPP generation
capacity to market pricing. In 1999, all customers will have the
ability to choose their energy supplier. These benefits, in our
view, would not be achieved by any of the alternatives that have
been presented or that we are otherwise aware of, including the
bankruptcy alternative and the various legislative proposals now
pending.
Having reviewed the Settlement's terms, the recommended
decision, the parties' exceptions, the public's comments, and the
Environmental Assessment Form prepared for us by our Staff, we find
that there are several terms that are not satisfactory under the
circumstances presented. They are discussed in detail above. Such
items include the terms for the proposed cost recovery shift from
energy to customer charges for the residential and small commercial
classes, the base period for implementing the S.C. 1 and S.C. 2
rate reductions, the prejudgment of a royalty treatment beyond the
Settlement's term, the incentive for divestiture of non-Oswego
fossil and hydro generation, service quality penalties, recovery of
certain lost gas revenues and new gas costs, and the disposition of
certain tax refunds.
These and other terms of concern to us are adopted
subject to the conditions or modifications described above or, in
the case of the proposed customer charge increases, are not adopted
at this time. With the modifications and conditions, the
Settlement and Master Restructuring Agreement satisfy the
objectives enumerated in Opinion No. 96-12 and meet the criteria
states in our Settlement Guidelines.
Accordingly, the terms of the Settlement and the Master
Restructuring Agreement are adopted with all the modifications and
changes discussed in this opinion and order. Inasmuch as those
terms and our modifications and conditions are interrelated, if any
term, modification, or condition is modified, vacated, or otherwise
materially affected on judicial review, we may re-examine our
entire decision.
THE COMMISSION ORDERS:
1. The terms of the Niagara Mohawk Power Corporation
PowerChoice Settlement Agreement, Exhibit 97-1 in these
proceedings, including the revisions submitted by letters dated
December 9, 1997 and February 13, 1998, and the supplements
submitted by letters dated January 22 and 23, 1998, subject to the
modifications and conditions described in this opinion and order,
are adopted and incorporated as part of this opinion and order.
2. Niagara Mohawk Power Corporation is directed to
cancel the suspended tariff amendments and supplements listed in
Appendix B concurrent with the effective date of tariffs filed in
conjunction with the implementation of the PowerChoice Settlement
Agreement, the PowerChoice Implementation Date.
3. The company is directed to file as soon as is
reasonably possible, but not later than May 19, 1998, tariff
amendments implementing the Settlement. The amendments shall
become effective on not less than sixty (60) day's notice. The
company shall serve copies of its compliance filing upon all
parties to this proceeding. Any comments on the filing must be
received at the Commission's offices within 45 days of service of
the company's proposed amendments. The amendments shall not become
effective on a permanent basis until approved by the Commission.
The requirement of the Public Service Law that newspaper
publication be completed prior to the effective date of the
amendments is waived, but the company is directed to file with the
Commission, not later than six weeks following the effective date
of the amendments, proof that a notice of the changes set forth in
the amendments and their effective date has been published for four
consecutive weeks in a newspaper having general circulation in the
service territory of the company.
4. Sections 4.5.1.2, 4.6.1.2 and 4.6.2.1 of the
agreement addressing the rebalancing of customer and energy charges
shall be modified as follows:
Monthly customer charges for residential,
small commercial non-demand and demand
metered customers shall be fixed at $9.67,
$14.65, and $27.22, respectively, at this
time.
The parties may address the customer charge/energy charge
rebalancing issues presented in these proceedings commensurate with
the review period preceding Commission approval of unbundled
tariffs for these customers.
5. The primary tariff filings directed in Clause 3 above
required to effectuate initial implementation of the PowerChoice
Settlement Agreement shall include unbundled retail access tariffs
for Customer Groups I and II, as defined in 8.2 of the agreement,
bundled (standard) tariffs for all remaining customers not included
in the above, and shall reflect the price reductions specified in
4.0 of the agreement and otherwise described herein. Subsequent
unbundled tariff filings for customers in Groups III, IV and V
should be made at least ninety (90) days prior to each group's
scheduled date for obtaining retail access.
6. Niagara Mohawk Power Corporation is directed to file
by no later than April 3, 1998 a tariff amendment, to become
effective on one day's notice on a temporary basis, to grandfather
the electric rates applicable to on-site generators who can
demonstrate that as of October 10, 1997 they had made a decision to
proceed with and had a substantial investment in self-generation.
The company shall serve copies of its proposal upon all parties to
this proceeding. Any comments on the proposal must be received at
the Commission's offices within 10 days of service of the company's
proposal. The amendments shall not become effective on a permanent
basis until approved by the Commission. The requirement of the
Public Service Law that newspaper publication be completed prior to
the effective date of the amendments is waived, but the company is
directed to file with the Commission, not later than six weeks
following the effective date of the amendments, proof that a notice
of the changes set forth in the amendments and their effective date
has been published for four consecutive weeks in a newspaper having
general circulation in the service territory of the company.
7. Niagara Mohawk is authorized to file tariff
amendments, to become effective on not less than one day's notice
on a temporary basis, to implement the open access charges for
municipalizations. Any comments on the proposal must be received
at the Commission's office within 10 days of service of the
company's proposal. The amendments shall not become effective on
a permanent basis until approved by the Commission. The
requirement of the Public Service Law that newspaper publication be
completed prior to the effective date of the amendments is waived,
but the company is directed to file with the Commission, not later
than six weeks following the effective date of the amendments,
proof that a notice of the changes set forth in the amendments and
their effective date has been published for four consecutive weeks
in a newspaper having general circulation in the service territory
of the company.
8. To the extent exceptions to the recommended decision
issued in these proceedings on December 29, 1997 are not moot, or
are otherwise granted, they are denied.
9. The potential environmental impacts of these terms
are within the bounds and thresholds evaluated in the 1996 FGEIS,
and, therefore, no further SEQRA action is necessary in these cases
at this time.
10. Niagara Mohawk, in cooperation with Staff, shall
monitor the environmental impacts of electric restructuring
resulting from this order.
11. Niagara Mohawk is authorized to include the
following decommissioning related activities in its cost of service
for Nine Mile 1: rampdown, wet fuel storage, dry fuel storage, and
radioactive dismantlement costs in the amount of $23,227,000 in
each year commencing on April 1, 1998 through 2009, unless and
until the Commission orders otherwise. The company is authorized
to deposit $18,494,000 of its Nine Mile 1 decommissioning
authorization in a tax qualified nuclear decommissioning fund and
$4,733,000 in a non-qualified nuclear decommissioning fund. The
company is also authorized to include in its cost of service, the
following decommissioning related activities for its 41% share of
Nine Mile 2: rampdown, wet fuel storage, dry fuel storage, and
radioactive dismantlement costs in the amount of $4,776,000 which
it is authorized to deposit in each year commencing on April 1,
1998 through 2026 in a tax qualified nuclear decommissioning fund,
unless and until the Commission orders otherwise. These plant
decommissioning authorizations are based on plant specific studies
escalated using the estimated escalation factors described below.
The estimated decommission related activities of Nine Mile 1 and
the company's 41% share of Nine Mile 2, in 1998 dollars, are $518
million and $262 million, respectively. Using an escalation factor
of 3.5%, the Nine Mile Unit 1 radioactive decommissioning costs are
estimated to be approximately $901 million in 2009, and the
company's share of the Nine Mile 2 radioactive decommissioning cost
is estimated to be about $802 million in 2026. The funding
assumptions are based upon the DECON method of decommissioning and
are assumed to be incurred between 2009 and 2041 for Nine Mile 1
and between 2026 and 2045 for Nine Mile 2. These time periods
presently represent the respective years over which each plant is
assumed to be decommissioned. An after-tax trust fund earning rate
of 6.3% was used for the Nine Mile 1 trust fund and a 6.9% rate for
the Nine Mile 2 trust fund. All applicable costs collected from
ratepayers shall be deposited by the company in external trust
funds on a quarterly basis.
12. For each of the five years of the Settlement period,
Niagara Mohawk Power Corporation is directed to defer any interest
rate savings related to the senior subordinated notes or other debt
instruments used to finance the MRA buyout. The savings will be
calculated by comparing the actual interest rate(s) to the 8.5%
interest rate forecasted for such debt as included in Appendix C of
the Settlement. The savings will be included in Account 253, Other
Deferred Credits, until such time the Commission utilizes the
deferred savings.
13. Niagara Mohawk Power Corporation shall submit a
written statement of unconditional acceptance of the modifications
and conditions contained in this opinion and order, signed and
acknowledged by a duly authorized officer of the company by April
3, 1998. The company's statement should be filed with the
Secretary of the Commission and served on the parties to these
proceedings.
14. Cases 94-E-0098 and 94-E-0099 are continued.
By the Commission,
(SIGNED) JOHN C. CRARY
Secretary
APPEARANCES
- -----------
FOR DEPARTMENT OF PUBLIC SERVICE STAFF:
Elizabeth H. Liebschutz, Esq. and Jane C. Assaf, Esq.
Staff Counsel, Three Empire State Plaza, Albany,
New York 12223-1350.
FOR NIAGARA MOHAWK POWER CORPORATION:
M. Margaret Fabic, Esq., Chief Counsel, 300 Erie
Boulevard West, Syracuse, New York 13202.
Swidler & Berlin (by J. Phillip Jordan, Esq. and
William B. Glew, Jr., Esq.), 3000 K Street, N.W.,
Suite 300, Washington DC 20007.
Adams, Dayter & Sheehan, LLP., (by Timothy P.
Sheehan, Esq.), 39 North Pearl Street,
Albany, New York 12207.
FOR SETTLING INDEPENDENT POWER PRODUCERS:
Read and Laniado (by Howard J. Read, Esq. and
Sam M. Laniado, Esq.), 25 Eagle Street,
Albany, New York 12207.
FOR NEW YORK STATE CONSUMER PROTECTION BOARD:
James F. Warden, Jr., Esq., Five Empire State Plaza,
Albany, New York 12223.
FOR CITY OF COHOES:
Peter Henner, Esq., P. O. Box 326,
Clarksville, New York 12041.
FOR CITIES OF FULTON AND OSWEGO:
Paul V. Nolan, Esq., 5515 North 17th Street,
Arlington, Virginia 22205.
FOR PUBLIC UTILITY LAW PROJECT:
Gerald Norlander, Esq., 90 State Street,
Albany, New York 12207.
FOR NEW YORK STATE ELECTRIC & GAS CORPORATION:
Huber, Lawrence & Abell (by Amy A. Davis, Esq.),
605 Third Avenue, New York, New York 10158.
APPEARANCES
- -----------
FOR RETAIL COUNCIL OF NEW YORK:
Cohen, Dax & Koenig, P.C. (by Paul Rapp, Esq.),
90 State Street, Albany, New York 12207.
FOR MULTIPLE INTERVENORS AND STEAM HOST ACTION GROUP:
Couch, White, Brenner, Howard & Feigenbaum (by Algird
White, Esq., Leonard Singer, Esq., and Doreen
Saia, Esq.), 540 Broadway, P.O. Box 22222,
Albany, New York 12201-2222.
FOR ENRON CAPITAL & TRADE RESOURCE CORP.:
Bracewell & Patterson, L.L.P. (by Randall S.
Rich, Esq.), 2000 K Street N.W., Suite 500,
Washington, DC 20006.
FOR NORCEN ENERGY RESOURCES LIMITED:
Brady & Berliner (by Peter G. Hirst, Esq.),
1225 19th Street N.W., Washington DC 20036.
FOR CONSOLIDATED NATURAL GAS TRANSMISSION CORPORATION:
Whiteman, Osterman & Hanna (by Thomas O'Donnell, Esq.
and Michael Whiteman, Esq.), One Commerce Plaza,
Albany, New York 12260.
FOR FINGER LAKES CHAPTER, NECA, INC.:
McMahon, Kublick, McGinty & Smith P.C. (by Jan
Kublick, Esq.), 500 South Salina Street,
Syracuse, New York 13202.
FOR EMPIRE STATE DEVELOPMENT AND NEW YORK STATE DEPARTMENT OF
ECONOMIC DEVELOPMENT:
Gloria Kavanah, Esq., One Commerce Plaza, Room 931,
Albany, New York 12245.
FOR CITIZENS UTILITY BOARD:
Robert Ceisler, 146 Washington Avenue,
Albany, New York 12210.
FOR ANR PIPELINE:
William Malcolm, Esq., 500 Renaissance Center,
Detroit, Michigan 48243.
APPEARANCES
- -----------
FOR SITHE ENERGIES USA, INC.:
Read and Laniado (by Craig M. Indyke, Esq.),
25 Eagle Street, Albany, New York 12207.
FOR LOCAL 97, IBEW:
Thomas P. Primero, Jr., Agent, 890 Third Street,
Albany, New York 12206.
Blitman & King (by Donald D. Oliver, Esq.), The
500 Building, 500 South Salina Street,
Syracuse, New York 13202.
FOR COASTAL GAS MARKETING COMPANY:
Cullen & Dykman (by Gerard A. Maher, Esq.),
177 Montague Street, Brooklyn, New York 11201-3611.
FOR NEW YORK STATE DEPARTMENT OF LAW:
Richard W. Golden, Esq., 120 Broadway, New York,
New York 10271.
FOR U.S. EXECUTIVE AGENCIES:
Robert A. Ganton, Esq., U.S. Department of Army,
901 North Stuart Street, Suite 713,
Arlington, Virginia 22203-1837.
FOR JOINT SUPPORTERS, CNG ENERGY SERVICES CORPORATION, AND
NATIONAL ASSOCIATION OF ENERGY SERVICE COMPANIES:
Ruben S. Brown, The E Cubed Company,
201 West 70th Street, Suite 41E, New York,
New York 10023.
FOR ENTRUST,LLC:
David A. Schilling, President, 100 Clinton Square,
Suite 450, 126 North Salina Street, Syracuse, New York
13202.
FOR ROCHESTER GAS AND ELECTRIC CORPORATION, CENTRAL HUDSON GAS &
ELECTRIC CORPORATION, AND LONG ISLAND LIGHTING COMPANY:
Nixon, Hargrave, Devans & Doyle (by Richard N.
George, Esq.), P. O. Box 1051, Clinton Square,
Rochester, New York 14603.
APPEARANCES
- -----------
FOR NEW YORK POWER AUTHORITY:
Eric J. Schmaler, 1633 Broadway, New York,
New York 10019.
FOR WHEELED ENERGY POWER COMPANY OF NEW YORK:
Joel Blau, 32 Windsor Court, Delmar, New York 12054.
FOR NEW YORK POWER FORUM:
Cohen, Dax & Koenig, P.C. (by John W. Dax), 90 State
Street, Suite 1030, Albany, New York 12207.
C. 94-E-0098, C. 94-E-0099 Appendix B
Page 1 of 2
Amendments to Schedule P.S.C. No. 207 - Electricity
Original Leaves Nos. 71-U, 101-B, 101-C, 101-D, 101-E,
101-F, 101-G, 101-H
First Revised Leaves Nos. 79-N, 83-A7, 87-A4, 87-A5
Second Revised Leaves Nos. 70-C2, 70-H, 71-C, 79-0, 87-F2,
106-B, 165
Third Revised Leaves Nos. 97-A, 100, 151
Fourth Revised Leaves Nos. 57-A, 70-E, 106-A
Fifth Revised Leaves Nos. 57-B1, 70-I
Sixth Revised Leaves Nos. 57-B, 105
Seventh Revised Leaves Nos. 57-C, 106
Eighth Revised Leaf No. 79-I
Ninth Revised Leaf No. 79-F
Eleventh Revised Leaf No. 83-A3
Twelfth Revised Leaf No. 83-A4
Thirteenth Revised Leaves Nos. 67, 79
Fifteenth Revised Leaf No. 55-B
Seventeenth Revised Leaf No. 70-D
Eighteenth Revised Leaf No. 2
Nineteenth Revised Leaf No. 55-A
Twentieth Revised Leaf No. 101-A
Twenty-First Revised Leaf No. 56
Twenty-Second Revised Leaves Nos. 58, 99, 102
Twenty-Third Revised Leaves Nos. 57, 98
Twenty-Sixth Revised Leaf No. 95
Twenty-Ninth Revised Leaf No. 85
Thirtieth Revised Leaf No. 103
Thirty-First Revised Leaves Nos. 87-C, 97, 101
Thirty-Fifth Revised Leaves Nos. 55, 104
Forty-First Revised Leaves Nos. 3, 89
Forty-Third Revised Leaf No. 81
Forty-Ninth Revised Leaf No. 83
Fifty-Fourth Revised Leaf No. 94
Fifty-Fifth Revised Leaf No. 80
Fifty-Sixth Revised Leaf No. 88
Fifty-Seventh Revised Leaf No. 84
Fifty-Eighth Revised Leaf No. 78
Supplements Nos. 207, 215, 217 and 223 to Schedule P.S.C. No. 207
- Electricity
C. 94-E-0098, C. 94-E-0099 Appendix B
Page 2 of 2
Amendments to Schedule P.S.C. 213 - Electricity (Street Lighting)
First Revised Leaf No. 80
Second Revised Leaf No. 78
Third Revised Leaves Nos. 44, 79, 81, 84
Twelfth Revised Leaves Nos. 9, 47
Sixteenth Revised Leaf No. 55
Seventeenth Revised Leaf No. 20
Eighteenth Revised Leaf No. 49
Twenty-Fifth Revised Leaf No. 43
Twenty-Seventh Revised Leaf No. 46
Thirtieth Revised Leaf No. 45
Thirty-Fourth Revised Leaves Nos. 30, 33, 34, 36, 40, 41
Thirty-Fifth Revised Leaves Nos. 28-A, 31, 37
Thirty-Sixth Revised Leaves Nos. 5, 6, 26, 28
Thirty-Seventh Revised Leaves Nos. 27, 38, 39
Thirty-Eighth Revised Leaves Nos. 16, 32, 35
Thirty-Ninth Revised Leaves Nos. 15, 29
Fortieth Revised Leaf No. 13
Forty-Second Revised Leaf 14
Forty-Third Revised Leaf 25
Supplements Nos. 67, 68 69 and 70 to Schedule P.S.C. No. 207
- Electricity
CASES 94-E-0098 and 94-E-0099
APPENDIX C
617.20
State Environmental Quality Review
ENVIRONMENTAL ASSESSMENT FORM
PROJECT INFORMATION
1. APPLICANT/SPONSOR: Niagara Mohawk Power Corporation
(NMPC)
2. PROJECT NAME: Elect. Rate/Restructuring - Case 94-E-0098,
94-E-0099
3. PROJECT LOCATION: NMPC Service Territory
Municipality NA County NA
4. PRECISE LOCATION: (Street address and road intersections,
prominent landmarks, etc., or provide map) NA
5. PROPOSED ACTION IS:
New Expansion X Modification/alteration
6. DESCRIBE PROJECT BRIEFLY: Cases 94-E-0952, 94-E-0098 and
94-E-0099 - In the matter of competitive opportunities regarding
electric service, filed in Case 93-M-0229; Plans for electric
rate/restructuring pursuant to Opinion No. 96-12; and the
formation of a holding company pursuant to PSL, Sections 70, 108
and 110, and certain related transactions -- Environmental
Assessment Form.
7. AMOUNT OF LAND AFFECTED: NA
Initially _______ acres Ultimately _________ acres
8. WILL PROPOSED ACTION COMPLY WITH EXISTING ZONING OR OTHER
EXISTING LAND USE RESTRICTIONS? NA
____ Yes ____ No If No, describe briefly
9. WHAT IS PRESENT LAND USE IN VICINITY OF PROJECT? NA
_____ Residential _____ Industrial _____ Commercial
_____ Agricultural ____ Park/Forest/Open space ____ Other
Describe:
10. DOES ACTION INVOLVE A PERMIT APPROVAL, OR FUNDING, NOW OR
ULTIMATELY FROM ANY OTHER GOVERNMENTAL AGENCY (FEDERAL, STATE
OR LOCAL)?
X Yes No If yes, list agency(s) name and permit/
approvals: NYS Public Service Commission
11. DOES ANY ASPECT OF THE ACTION HAVE A CURRENTLY VALID PERMIT OR
APPROVAL?
X Yes No If yes, list agency(s) name and permit/
approval: Stationary sources owned and
operated by NMPC have valid, approved
certificates to operate.
12. AS A RESULT OF PROPOSED ACTION WILL EXISTING PERMIT/APPROVAL
REQUIRE MODIFICATION? NA
____ Yes ____ No
I CERTIFY THAT THE INFORMATION PROVIDED ABOVE IS TRUE TO THE BEST
OF MY KNOWLEDGE
Agency: NYS Department of Public Service
--------------------------------
Date: February 13, 1998
-----------------
Signature: -------------------------------
PART II-ENVIRONMENTAL ASSESSMENT
A. DOES ACTION EXCEED ANY TYPE 1 THRESHOLD IN 6 NYCRR, PART 617.4?
If yes, coordinate the review process and use the FULL EAF.
Yes X No
B. WILL ACTION RECEIVE COORDINATED REVIEW AS PROVIDED FOR UNLISTED
ACTIONS IN 6 NYCRR, PART 617.6? If No, a negative declaration
may be superseded by another involved agency. NA
____ Yes ____ No
C. COULD ACTION RESULT IN ANY ADVERSE EFFECTS ASSOCIATED WITH THE
FOLLOWING: (Answers may be handwritten, if legible.)
C1. Existing air quality, surface or groundwater quality or
quantity, noise levels, existing traffic patterns, solid waste
production or disposal, potential for erosion, drainage or
flooding problems? Explain briefly:
Expected impacts are within the range of thresholds and
conditions set forth in the FGEIS.
C2. Aesthetic, agricultural, archaeological, historic, or other
natural or cultural resources; or community or neighborhood
character? Explain briefly:
Expected impacts are within the range of thresholds and
conditions set forth in the FGEIS.
C3. Vegetation or fauna, fish, shellfish or wildlife species,
significant habitats, or threatened or endangered species?
Explain briefly:
Expected impacts are within the range of thresholds and
conditions set forth in the FGEIS.
C4. A community's existing plans or goals as officially adopted, or
a change in use or intensity of use of land or other natural
resources? Explain briefly:
Expected impacts are within the range of thresholds and
conditions set forth in the FGEIS.
C5. Growth, subsequent development, or related activities likely to
be induced by the proposed action? Explain briefly:
Expected impacts are within the range of thresholds and
conditions set forth in the FGEIS.
C6. Long term, short term, cumulative, or other effects not
identified in C1-C5? Explain briefly:
Expected impacts are within the range of thresholds and
conditions set forth in the FGEIS.
C7. Other impacts (including changes in use of either quantity or
type of energy)? Explain briefly:
Expected impacts are within the range of thresholds and
conditions set forth in the FGEIS.
D. WILL THE PROJECT HAVE AN IMPACT ON THE ENVIRONMENTAL
CHARACTERISTICS THAT CAUSED THE ESTABLISHMENT OF A CRITICAL
ENVIRONMENTAL AREA (CEA)? Yes X No If Yes, explain
briefly:
E. IS THERE, OR IS THERE LIKELY TO BE, CONTROVERSY RELATED TO
POTENTIAL ADVERSE ENVIRONMENTAL IMPACTS? Yes X No If Yes,
explain briefly:
Part III - DETERMINATION OF SIGNIFICANCE (To be completed by
Agency)
See the attached Environmental Assessment Form Narrative.
Staff recommends that the Final Generic Environmental Impact
Statement (FGEIS) issued on May 3, 1996 (Case 94-E-0952), with
respect to the proposed action of adopting a policy supporting
increased competition in electric markets be extended in
applicability, without modification or supplementation, to the
approval of New Niagara Mohawk Power Corporation (The Corporation)
Agreement and Settlement on the grounds that the significance of
the proposal's anticipated environmental impacts will not exceed
the threshold values examined in the FGEIS. Consequently, no
further State Environmental Quality Review Act (SEQRA) action is
necessary in approving the Proposal.
Staff further recommends that a monitoring program be instituted to
provide a record of changes resulting from the restructuring plan's
implementation to enable confirmation and/or exposition of
unexpected outcomes and their significance, and to assure that
specific mitigation measures are implemented as needed.
NYS Department of Public Service
- --------------------------------
Name of Lead Agency
February 13, 1998
- -----------------
Date
John H. Smolinsky
- -----------------
Print or Type Name of Responsible Officer in Lead Agency
Chief, Environmental Compliance and Operations
- ----------------------------------------------
Title of Responsible Officer
____________________________________
Signature of Responsible Officer in Lead Agency
____________________________________
Signature of Preparer (If different from responsible officer)
APPENDIX C
ENVIRONMENTAL ASSESSMENT FORM
I. BACKGROUND
On May 3, 1996, the Commission issued a Final Generic
Environmental Impact Statement (FGEIS) in the Competitive
Opportunities proceeding which addressed the environmental impacts
of a policy supporting increased competition in electric markets.
Alternative approaches to achieving electric competition, including
a no-action alternative, were studied.
In Opinion No. 96-12 issued May 20, 1996, the
Commission set forth its findings with respect to the FGEIS
(p.76-81). The Commission determined that the likely environmental
effects of a shift to a more competitive market for electricity are
not fully predictable but that:
In general, the proposed action will have environmental
impacts that are modest or not distinguishable from
those of alternative actions, including the no-action
alternative... Apart from the areas of substantial
concern noted below, the FGEIS did not identify
reasonably likely significant adverse impacts.
With respect to air quality impacts related to oxides
of nitrogen and sulfur, it appears likely that the
retail or wholesale electric market structures would
have greater impacts than the no action alternative.
It appears likely that, in the absence of mitigation
measures, research and development in environmental and
renewables areas would lose funding if competitive
restructuring moves forward. In addition, there would
likely be a decrease in the amount of cost-effective
energy efficiency during any transition to wholesale or
retail competition...
In order to address the adverse environmental effects
identified above on air quality, energy efficiency, and
research and development, several mitigation measures
will be employed as necessary. First, a system
benefits charge will be used as appropriate to fund DSM
and research and development in environmental and
renewable resource areas during the transition to
competition. Second, the competitive restructuring
will be monitored closely to ensure that specific
mitigation measures are implemented if needed.
Finally, the Commission will support and assist efforts
by New York State and federal agencies to ensure that
adverse environmental impacts to the state's air
quality from upwind sources of air contamination do not
occur as a result of the movement toward competition.
Notwithstanding the mitigation measures identified, the
proposed action to restructure the electric industry
may result in an unavoidable adverse environmental
impact on air quality related to oxides of nitrogen and
sulfur, loss of some DSM activity, loss of some
research and development funding in the environmental
and renewables areas, and displacement of workers and
local economic loss where plants are closed.
Nevertheless, weighing and balancing these likely
environmental effects of the shift to competition in
the electric industry in New York with social,
economic, and other essential considerations, leads to
the conclusion that implementing the proposed action
toward greater competition is desirable.
The Commission also recognized that individual utility
proposals might bring to light new concerns. In Opinion No.
96-12, and as further clarified in Opinion No. 96-17, it
required each utility to file with its restructuring plans an
Environmental Assessment Form and a recommendation on further
environmental review. The information to be provided was expected
to assist the Commission in determining the need for additional
mitigation measures with respect to company restructuring.
On August 26, 1997, Niagara Mohawk submitted its
Environmental Assessment Form (EAF) and SEQRA recommendation in
connection with its initially proposed PowerChoice restructuring
plan in Case 94-E-0098 and Case 94-E-0099. This proposal served as
the basis for negotiations between the company, Staff and
interested parties. On October 10, 1997, the company, Staff and
many of the interested parties signed a restructuring settlement.
On November 4, 1997, the company filed a supplement to
its EAF which addressed the environmental implications of areas
where the negotiated settlement differed from the original
proposal. On November 12, 1997, Administrative Law Judge
Bouteiller issued a procedural ruling which requested parties in
Case 94-E-0098 to file initial comments on the supplemented EAF by
December 3, 1997. Comments were received from the Steam Host
Action Group (SHAG) and Multiple Intervenors (MI) on that date. No
other parties submitted formal comments at that time. However, a
number of parties, including the City of Oswego, commented on the
EAF or on environmental issues in their briefs.
SEQRA and Commission Approval of the Niagara Mohawk Restructuring
Plan - Options Before the Commission
The FGEIS issued by the Commission in conformance with
SEQRA in Case 94-E-0952, et. al., addressed the following proposed
action:
"adoption of a policy supporting increased
competition in electric markets, including a
preferred method to achieve electric competition;
and regulatory and ratemaking practices that will
assist in the transition to a more competitive and
efficient electric industry, while maintaining
safety, environmental, affordability, and service
quality goals."
Commission approval of Niagara Mohawk's proposed
restructuring plan constitutes a "subsequent proposed action."
SEQRA requirements with respect to this "subsequent proposed
action" allow the Commission to pursue one of the four following
options:
1. No further State Environmental Quality Review
(SEQRA) compliance is required if a subsequent
proposed action will be carried out in conformance
with the conditions and thresholds established for
such actions in the generic Environmental Impact
Statement (EIS) or its findings statement.
2. An amended findings statement must be prepared if
the subsequent proposed action was adequately
addressed in the generic EIS but was not addressed
or was not adequately addressed in the findings
statement for the generic EIS.
3. A negative declaration must be prepared if a
subsequent proposed action was not addressed or
was not adequately addressed in the generic EIS
and the subsequent action will not result in any
significant environmental impacts.
4. A supplement to the final generic EIS must be
prepared if the subsequent proposed action was not
addressed or was not adequately addressed in the
generic EIS and the subsequent action may have one
or more significant adverse environmental
impacts.
The following environmental assessment will assist in
choosing the appropriate option. The assessment is based on
Niagara Mohawk's EAF, party comments submitted in response to the
company's EAF, and on additional analysis by Department Staff. In
addition, the EAF will consider certain generic comments raised by
Public Interest Intervenors in its May 13, 1997 petition requesting
that the Commission order the filing of supplemental environmental
impact statements in all restructuring cases. The Assessment
consists of:
Section II - summarizes the proposed settlement
agreement.
Section III - summarizes the Environmental Assessment
Form submitted by the company.
Section IV - summarizes party comments on the company's
EAF.
Section V - Staff's analysis of the environmental
impacts of the proposed settlement.
Section VI - recommends mitigation and monitoring plan.
Section VII - Staff's overall conclusions and
recommendations.
II. NMPC PROPOSED RESTRUCTURING SETTLEMENT
Under the proposal, residential and smaller commercial
customers would receive rate reductions phased in over the first
three years of the settlement which would amount to an average
reduction of 3.2% by the year 2000. Large industrial customers
would receive reductions in their NMPC rates which would average
13% by the year 2000.
The agreement requires the company to auction virtually
all of its non-nuclear generation and prohibits the company and its
subsidiaries from owning generation in New York in the future. The
company's nuclear generation will be placed in a separate business
unit but retained pending a statewide solution to the nuclear
issue.
The plan also provides for phase-in of retail access for
all customers by December of 1999. A competitive transition charge
(CTC) will be charged all customers in order to collect stranded
costs.
The plan establishes a $10 million fund which will be
used for programs such a retraining, outplacement and early
retirement of its employees to mitigate any employment impacts
caused by the auction or retirement of its generating plants. Under
the plan, the company would continue its current program to
remediate pollution at coal gas production sites. The plan also
provides for the continuation of low income programs and for the
institution of a $15 million per year System Benefits Charge to be
used for RD&D energy conservation and other public benefit
programs. The company has also agreed to retire 5000 SO2
allowances and to transfer ownership or conservation easements for
a number of land parcels in the Adirondacks to New York State.
In a separate but related action, the company negotiated
an agreement (the Master Restructuring Agreement or MRA) with
certain Independent Power Producers (IPPs) which are currently
selling power to NMPC under "must run" contracts which are
unfavorable to the company. This agreement will modify or
terminate the contracts of the settling IPPs. A number of these
IPPs also provide steam under contract to industrial customers
(Steam Hosts).
III. THE NMPC ENVIRONMENTAL ASSESSMENT FORM (EAF)
On August 26, 1997, Niagara Mohawk filed an EAF covering
the environmental impacts of NMPC's July 23 PowerChoice Proposal.
Subsequently, the company's proposal was modified as a result of
settlement negotiations, culminating in an Agreement filed October
10, 1997. On November 4, 1997, the company filed a supplement to
the EAF which addressed additional areas of environmental concern
raised by details of the final settlement. In comprehensiveness
and analytic depth, the NMPC EAF exceeds those submitted by other
utilities in their restructuring cases.
As the basis for much of its EAF, NMPC ran a series of
PROMOD computer analyses which simulated plant dispatching under
various scenarios associated with the PowerChoice Proposal. The
scenarios differed from one another in terms of assumed demand
levels, IPP operations, Demand Side Management levels, and the
early retirement of nuclear and certain fossil units, but
encompassed the likely range of outcomes from PowerChoice. The
company compared these scenarios to an NMPC-generated "no-action"
base case and to the PROMOD runs contained in the FGEIS. The
company reports that the potential air quality impacts associated
with the scenarios fell well within the limits projected in the
FGEIS scenarios.
The company argues that since existing generating
facilities in New York have received permits which allow operation
up to design capacity, and since operation at full design capacity
was considered in the permitting process, changes in plant
operation due to PowerChoice will not have significant aquatic or
water quality effects beyond those already considered and found
acceptable.
The company notes that while PowerChoice will have
overall beneficial effects on the State's economy, a more
competitive environment could result in localized socio-economic
impacts, including loss of employment and tax revenues, if some
existing NMPC or IPP plants are retired earlier than they otherwise
would have been. Other communities might benefit from the
construction of new competitive plants. Statewide employment
levels should rise as an indirect effect of lower electricity
prices.
The company's supplemented EAF also addressed the
question of the indirect effect of the MRA on IPP steam hosts. The
company estimates that, at most, only 14 million mmBtu per year of
steam production, or about 15% of the total IPP steam production,
will be retired or mothballed as a result of the MRA. Only about
5% of that 14 million mmBtu is currently being used by steam hosts.
Since this is only 0.07% of the over 1 billion mmBtu annual steam
production in the NMPC system, the incremental air quality impacts
of any changes in emissions resulting from steam hosts running less
efficient boilers to replace IPP steam are immaterial and fall
within the limits considered in the FGEIS.
The company notes in its supplemented EAF that the
donation of SO2 allowances, the $15 million per year SBC fund and
the negotiated transfer of environmentally significant land parcels
will result in environmental benefits not considered in the July 23
PowerChoice proposal.
The company also states that the PowerChoice proposal
will not affect the company's existing Site Investigation and
Remediation (SIR) program--which is designed to identify and
mitigate polluted sites owned by the company.
IV. COMMENTS ON THE NIAGARA MOHAWK EAF
On November 4, 1997, NMPC submitted a supplemented EAF
which addresses issues arising from the negotiated agreement.
Comments on the EAF were received from the Steam Host Action Group
(SHAG) and Multiple Intervenors (MI) on December 3, 1997. Other
parties, including the City of Oswego, addressed environmental
issues in their briefs.
COMMENTS SUBMITTED ON THE SUPPLEMENTED EAF
SHAG's comments addressed only one issue--the potential
socio-economic effects of changes in contracts between NMPC and
certain IPPs on some industrial customers who purchase cogenerated
steam from the IPPs. For a number of years, NMPC has had "must
run" contracts to purchase power at above market prices from a
number of IPPs. Many of those IPPs have had "steam host" customers
who purchased steam or hot water which was produced as a byproduct
of electric generation. Part of the negotiated settlement is a
Master Restructuring Agreement (MRA) which sets the ground rules
whereby NMPC and certain of these IPPs will modify or terminate
their contracts.
SHAG states in its comments on the EAF that the
termination of contracts between IPPs and NMPC may lead some IPPs
to breach their contracts with the steam hosts. This might
increase the costs of the steam hosts or disrupt their operations.
In either event, layoffs and economic harm to communities
containing the steam hosts might follow. SHAG states that these
issues are not adequately addressed in the company's supplemented
EAF and urges the Commission to take steps to mitigate the impacts
of the MRA on its members.
In its comments, MI states that the EAF adequately
addresses all potential environmental impacts and that no further
action under SEQRA is required. MI does support, however, SHAG's
request that the Commission adopt measures to mitigate the
potential effects of the MRA on steam hosts.
RELATED COMMENTS IN INITIAL BRIEFS
Several parties also addressed the EAF, or environmental
issues arising from the proposed settlement, in their initial
briefs on the proposed settlement.
PULP's position was that environmental matters had not
been adequately considered in the proceeding to comply with the
provisions of the State Environmental Quality Review Act (SEQRA),
but did not specify in what ways the proceeding had failed.
The initial briefs of SHAG referred to its comments
(summarized above) on the EAF.
The City of Oswego challenged both the SBC and renewable
energy projects proposed in the settlement as wasteful and the
company's proposed conservation land donations as illegal, and
faulted the EAF for not dealing adequately with potential
socio-economic impacts of power plant closures which might result
from the sale of NMPC generating units.
The Cities of Fulton and Cohoes and the NYS Assessors
Association adopted Oswego's comments on the EAF by reference in
its initial brief.
Empire State Development, while supporting the
settlement, suggested that the Commission monitor the compliance of
parties with provisions of the settlement which require good faith
efforts to mitigate the effects of the MRA on steam hosts.
The National Association of Energy Services Companies
(NAESCO) endorsed the settlement in general and specifically
singled out and supported the proposed level of system benefit
spending and provisions in the settlement by which NMPC commits to
investigating the use of DSM and distributed generation to mitigate
T&D related problems.
The Consumer Protection Board, while taking no position
on the effects of divestiture on local community taxes and
employment, did note that recent sale prices of generation assets
in California indicated communities might see tax increases
resulting from divestiture. In addition, it endorsed the
establishment of an SBC at the level specified in the settlement
and declined to take a position on the adequacy of the EAF.
Multiple Intervenors recapitulated in the brief the
environmental positions it took in its comments on the supplemented
EAF.
The Settling Independent Power Producers endorsed the
settlement agreement and the MRA and opposed the positions of the
City of Oswego and SHAG with regards to impacts of the settlement
and the MRA. SIPP stated that they believed that the potential
costs and disruption to industrial operations claimed by SHAG were
exaggerated and could be mitigated by negotiations between SIPP and
SHAG members without Commission involvement.
Niagara Mohawk stated in its brief that the supplemented
EAF it had submitted had fully satisfied the requirements of SEQRA.
GENERIC COMMENTS ON UTILITY EAFS
On May 13, 1997, the Public Interest Intervenors (PII)
moved for the Department of Public Service Staff to prepare
supplemental environmental impact statements (SEISs) in several
restructuring cases. At the time the petition was filed, Niagara
Mohawk had not yet submitted an Environmental Assessment Form. In
its petition, PII identified a number of claimed deficiencies in
the EAFs which had been filed at that date. Some of PII's comments
were generic in nature and, in our understanding, were intended to
apply to all utilities; some were specific to particular utilities.
Even though NMPC had not submitted an EAF at the time of the PII
petition and even though PII did not comment on the NMPC EAF
subsequently, Staff summarizes below generic points raised by PII
in May which are generally relevant to the NMPC EAF.
PII noted that the FGEIS considered using a
system benefits charge (SBC)--which would pay
for certain energy efficiency, low income and
R&D activities not likely to be undertaken by
a deregulated utility--as a means of
mitigating some environmental impacts. It
asserted that the Commission made a decision
in Opinion No. 96-12 that the SBC should be
funded at approximately the current levels of
activity and that the SBC charge proposed in
several of the plans it reviewed were below
this threshold.
While the system benefits charge is intended
to provide for energy efficiency services
(beyond those arising from market forces), it
is anticipated that utilities will continue
to offer some DSM services. PII asserts that
some utilities' proposed DSM budgets will be
lower than in previous years as a result of
the restructuring plan and that will have
negative environmental impacts.
PII noted that although the proposed
agreements provided for transition to market
pricing of generation, T&D services would
remain under a traditional form of
regulation. PII argued that traditional
regulation contains inherent incentives for a
utility to increase sales and inflate rate
base and that the Commission is therefore
required to order an SEIS.
Several settlements reviewed by PII include
provision for a Competitive Transition Charge
(CTC) which would allow the company to
recover certain non-marginal costs of
utility electric plants. PII argued that, by
providing a mechanism for the recovery of
these costs, the agreement would subsidize
the operation of utility plants, giving the
companies an unfair price advantage when
bidding energy sales to an ISO and result in
those plants operating more than is
economically efficient. Environmental
impacts would ensue if the utility plants
were run in lieu of other plants which are
both more economically efficient and more
environmentally benign.
PII noted that load pockets have been
identified in several utilities' service
territories and that construction of new
transmission facilities may be required to
mitigate these load pockets. PII asserted
that these facilities will have environmental
impacts which should be evaluated in an
SEIS.
Chief Administrative Law Judge Lynch considered the PII
petition and reply comments by Staff and several other parties and
recommended that "the final EAFs prepared for Commission use in the
Con Edison and O&R cases consider the potential environmental
effects of T&D price cap regulation for Con Edison and the recovery
of non-variable generation costs in T&D rates for Con Edison and
O&R" but that "in all other respects, there is no reason to
commence preparation of SEISs." Nonetheless staff's analysis
in Section V will address the issues raised by PII which are
broadly relevant to NMPC.
We note that several of the environmental groups
represented by PII are signatories to the NMPC settlement
agreement and that neither PII nor any of its member
environmental groups have commented on the NMPC EAF or raised
environmental impact issues.
V. STAFF ANALYSIS
The FGEIS covered the significant generic issues
connected with restructuring at considerable length. The following
analysis will not recapitulate the material in the FGEIS. Instead,
this analysis will deal with issues identified by Staff, by
comments on the Niagara Mohawk EAF and with general comments
offered by parties on other utility restructuring EAFs. The issues
to be examined are primarily those for which it is reasonable to
believe that unique features of the company's service territory or
restructuring plan might result in environmental impacts not
considered in the FGEIS or in excess of thresholds identified in
the FGEIS.
A. EFFECTS OF RESTRUCTURING ON OVERALL LEVEL OF
ELECTRIC SALES IN NIAGARA MOHAWK'S SERVICE TERRITORY
A key determinant of the incremental environmental
impacts of restructuring the electric industry in New York is the
effect of restructuring on the overall level of electric sales.
This section of the EAF will address the question of whether any
likely effect of the Niagara Mohawk restructuring plan would cause
sales growth in excess of the levels contemplated in the Final
Generic Environmental Impact Statement (FGEIS).
There appear to be three realistic ways in which
restructuring could have significant impacts on electric sales:
reduced rates and price elasticity; effects of rate of return
regulation; and reduced use of energy efficiency. The following
paragraphs examine each of these effects.
1. PRICE ELASTICITY EFFECTS
If electric prices drop as a result of utility rate
reductions incorporated in restructuring agreements and/or as a
result of competition among the utility and alternative suppliers,
customers may make the economic decision to consume more
electricity. This is a price elasticity effect. The FGEIS
analysis included the preparation of a statewide "high sales"
scenario based on estimated sales increases that could result from
decreases in electric prices, given the best information then
available to staff economists. The high sales scenario assumed
that the compounding statewide electric sales growth would be about
2.2% per year.
This scenario was compared to a FGEIS base case
"evolving regulatory model" scenario. The base case assumed
incremental sales growth of 1.2%. Thus, the additional incremental
statewide sales growth likely to result from the high sales
scenario compared to the no action base case was estimated as about
1.0% per year.
PROMOD simulation of comparative plant dispatching
under these scenarios showed that, compared to the evolving
regulatory model, the high sales model would result in a 2.9%
increase in SO2 emissions, a 5.5% increase in NOx and a 12%
increase in CO2 by 2012. The Commission determined that, although
the FGEIS showed the possibility of detrimental incremental air
quality impacts "consistent with the social, economic and other
considerations, from among the reasonable alternatives available,"
the Commission's restructuring policy "avoids or minimizes adverse
environmental impacts to the maximum extent possible."
Niagara Mohawk accounted for roughly 26% of NYPP
sales in 1996. In analyzing the significance of any potential
incremental sales growth attributable to the Niagara Mohawk
restructuring plan, it is reasonable to focus on Niagara Mohawk's
pro rata share of the sales growth and impacts considered in the
FGEIS and ask whether Niagara Mohawk's incremental sales growth due
to price elasticity effects resulting from restructuring would be
likely to be significantly greater than the average statewide
incremental sales growth due to restructuring.
Recently, Staff of the Office of Energy Efficiency
and Environment (OEEE), with the assistance of the Office of
Regulatory Economics (ORE) of the DPS, performed an elasticity
analysis using the rate reductions in the Niagara Mohawk
settlement. The results (see Attachment A, Table B) show that the
settlement rate reductions are likely to produce a 0.50%
incremental annual increase in demand compared to the FGEIS base
case over the same 15 year modeling period used in the FGEIS. This
is only half the incremental sales increase modeled in the FGEIS
high sales scenario.
It is important to note that this elasticity
analysis estimates only the additional sales growth which would
result from the rate reductions in the settlement agreement. It
does not consider other important factors, such as population
growth, general economic growth and the prices of competitive
energy sources, which also help to determine overall sales growth,
and so should not be interpreted as a sales forecast.
2. REGULATION OF THE T&D UTILITY
While the proposed settlement provides for a
transition to a more competitive market for generation, the T&D
portion of Niagara Mohawk would remain a regulated utility with
rate of return regulation. In its May 13, 1997 petition, PII
argued that rate of return regulation gives the T&D utility
incentives to promote sales and to build uneconomic rate base.
According to PII, these incentives could result in environmental
impacts which should be considered in a separate SEIS.
For several years, a revenue decoupling mechanism
(NERAM) was in effect for NMPC which was intended to remove the
linkage between increased sales and increased company profits.
However, in 1995 the Commission approved the discontinuation of the
general NERAM revenue reconciliation mechanism, but allowed
continuation of a limited mechanism for recovery of lost revenues
due to DSM. As discussed below, the company's expenditures on DSM
declined sharply after 1995. It did not request recovery of
DSM lost revenues after that date.
The Agreement proposes discontinuation of this DSM
lost revenue recovery mechanism. Its discontinuation is unlikely
to have a material effect on the company's already much reduced DSM
programs or to act as an incentive to promote sales and to build an
uneconomic rate base.
3. LOWER ENERGY EFFICIENCY EFFECT
For a number of years, the New York Commission has
encouraged utilities to promote end use energy efficiency (DSM).
This encouragement has included review and approval of utility DSM
plans and budgets and various incentive and cost recovery
mechanisms. For all New York utilities, including Niagara Mohawk,
the levels of DSM expenditures and energy savings have declined
drastically in recent years. Niagara Mohawk's DSM expenditures
peaked at $65.9 million in 1992 and its incremental annual DSM
energy savings peaked at 324.6 GWH, also in 1992. By 1996, its DSM
expenditures had declined to only $0.8 million and its DSM
incremental energy savings goal had declined to only 29.9 GWH.
While the company had budgeted $2.7 million for DSM in 1997, by
mid-year it had only spent about $0.1 million. We estimate 1997
incremental DSM savings at about 6 GWH based on mid-year
achievements. The company plans to continue to offer limited DSM
programs to customers, but no specific sum is included in the
settlement for these activities. As discussed below, money is
allocated for a System Benefits Charge (SBC) which will include
energy efficiency programs.
Staff examined the possibility that DSM budget
reductions could reduce the energy conservation measures taken by
NMPC customers and result in incremental increases in electric
sales beyond the base case.
In the FGEIS, the base case "evolving regulatory
model" scenario and the "high sales" scenario included annual
incremental Niagara Mohawk DSM energy savings of 112 GWH for
the years 1997 and beyond. Another scenario in the FGEIS estimated
the sales and environmental impacts of halting all DSM activities;
the sales and environmental impacts of this "No incremental utility
DSM" scenario were shown to be much smaller than those of the
"high sales scenario."
The FGEIS did not consider a scenario that assumed
both high sales and no incremental DSM, so Staff evaluated the
plausibility that a realistic combination of low Niagara Mohawk DSM
and high Niagara Mohawk sales growth could result in sales greater
than those postulated in the FGEIS "high sales scenario." Staff
has re-analyzed the impact of energy efficiency programs on NMPC
sales growth using a value of 29.9 GWH for 1996, 6.0 GWH for 1997
and 0 GWH for the years 1998 through 2012 and compared that to the
DSM impact analysis underlying the FGEIS high sales scenario. We
calculate that, averaged over the FGEIS modeling period (1997
through 2012), the elimination of all energy efficiency sales
reductions after 1997 would increase sales by only 0.13% a year.
This analysis probably overstates the effects of
reductions in utility DSM programs on the availability of energy
efficiency services for two reasons. First, as discussed below,
the Agreement provides substantial funding for an SBC, much of
which will be used to provide energy efficiency programs or
information. Secondly, (as observed in the FGEIS) retail
competition will result in the development of a competitive ESCO
market in which some ESCO's will probably offer energy efficiency
services as a way of distinguishing themselves from competitors.
As discussed above, the price elasticity effects of
the settlement rate reductions would increase sales by an average
rate of 0.50% a year over the 15 year period compared to the FGEIS
base case. If the effects of no DSM are added, the likely
incremental sales increases due to the settlement are about 0.63%.
This is well below the 1.0% incremental growth considered in the
FGEIS high sales scenario.
B. SYSTEM BENEFITS CHARGE
The settlement provides for an SBC funded at a level
of $15 million a year. The City of Oswego has objected to the
establishment of an SBC as wasteful. However, in adopting the
FGEIS, the Commission found that an SBC is necessary to mitigate
the environmental effects of the reduction in utility DSM programs
and provide for the continuation of other important public benefit
programs.
In its May 13, 1997 comments, PII argued that
restructuring agreements should provide for SBCs funded at the
levels of utility DSM expenditures current when the Commission
adopted the FGEIS. Staff believes that the proposed level of
funding is compatible with the FGEIS and that no further analysis
is required.
C. EFFECT OF RESTRUCTURING ON RETIREMENT OR CONSTRUCTION
OF NEW GENERATION, PLANT DISPATCH OR FUEL PURCHASE
Another potential factor that could, in concept,
affect New York's environment is the direct or indirect effect of
the Niagara Mohawk restructuring plan on the mix of fuels burned or
plants run to meet electric sales in Niagara Mohawk's territory.
The following section will analyze whether there is any reason to
believe that the Niagara Mohawk plan would result in impacts that
are greater than or different in nature or causation from those
already addressed in the FGEIS.
1. CONSTRUCTION OF NEW GENERATING PLANTS
Projections in the FGEIS suggest that new
capacity will be required on the New York State system within
several years. This capacity might be provided by constructing new
facilities, repowering existing plants, additional firm power
imports or a combination of the above. It is also possible that
some investors will find it attractive to construct new power
plants (or refurbish existing less efficient plants) to compete as
merchant plants in the new open power market being established by
the Commission.
If new or repowered plants in excess of 80 MW,
or significant transmission construction is required, those
projects will be subject to full environmental review under
Articles X and VII of the Public Service Law. In any event, under
current air quality regulations (particularly the emissions offset
policies for NOx) construction of new facilities tends to improve
air quality for critical emissions.
2. TRANSFER OF OWNERSHIP OF NMPC NON-
NUCLEAR GENERATION
Under the Agreement, the company is required to
auction its non-nuclear generation. The company has prepared an
auction plan which will be the subject of a separate Commission
proceeding. The potential environmental consequences of the
auction are beyond the scope of this EAF. Staff will examine the
auction plan and advise the Commission about whether a separate
SEQRA analysis of the auction is required.
However, the City of Oswego and other parties
have raised concerns about the possible effects of the settlement
agreement on existing NMPC plants. It is possible to make some
general observations about the possible environmental impacts of
the divestiture of the company's generation assets.
It is likely that the company's lowest cost
generating facilities will be acquired by another owner. These
plants may be operated in much the same fashion by the new owners
as they have been by NMPC. In general, the permitting and
licensing restrictions and environmental standards which apply to
these plants under Niagara Mohawk's ownership will continue to
apply. However, it is possible that competitive pressures will
cause the new owners to seek to cut environmental expenditures in
non-mandated areas. Such problems could be mitigated through
specific agreements between NMPC and bidders if required by
the auction plan.
The company estimates that most plant staff
will be retained by new owners, but it is possible that transfer of
these low operating cost plants would result in replacement of some
existing NMPC employees or a reduction in work force.
The effect of divestiture on higher cost plants
is more speculative. It is possible that new owners will acquire
some or all of these less efficient plants and invest money to make
them more competitive. Even plants with high operating costs may
have significant advantages over "green field" sites in terms of
existing transmission links and fuel access, as well as community
acceptance and relative ease of environmental licensing. We note
that Niagara Mohawk is currently in the early stages of an Article
X licensing proceeding for the repowering of its Albany Steam
Station. This application is intended expressly to increase the
value of that facility to prospective bidders.
The combination of incentives for prompt
auctioning of these sites and the opportunity for NMPC to recover
much of its stranded costs may mean that currently inefficient
plants will be available at reasonable prices to developers. The
result could be a willingness to invest in plant refurbishment to
make them competitive in the market. The transfer of ownership
from a regulated utility to an unregulated owner may also provide
an opportunity for the new owner to negotiate lower property tax
payments--further improving the plant's competitiveness.
3. RETIREMENT OF NMPC GENERATING FACILITIES
If no market for a given facility is revealed
by the auction, retirement of that facility is a likely outcome.
However, retirement of a major NMPC generating facility could have
a variety of local fiscal, economic, employment and other
environmental impacts. The City of Oswego cited concerns about the
potential local impacts of retirement of the Oswego Steam Station.
The potential impact of early plant retirements
was considered by the Commission in the FGEIS. The FGEIS concluded
that accelerated retirement of less efficient plants is an
unavoidable potential consequence of a more competitive electric
industry. It further concluded that such changes could have
significant adverse impacts on individuals and communities.
Impacts discussed in the EAF included local economic impacts,
decreased employment and reduced local tax revenues. While the EAF
predicted that competition would lead to lower electric rates and
an enhanced economy which would more than offset these impacts
on a statewide basis, it stated that permanent displacement of some
workers might result and that not all communities would share
equally in the benefits of competition.
In Opinion No. 96-12, the Commission determined
that "adverse environmental impacts will be avoided or minimized to
the maximum extent practicable by incorporating as conditions to
the decision those mitigative measures that were identified as
practicable." One measure adopted by the Commission was a charge
to Staff to monitor and, if indicated, mitigate specific impacts
that may occur. The Settlement includes a commitment from the
company to establish a $10 million fund which will be used for
programs such as retraining, outplacement and early retirement of
its employees to mitigate any employment impacts caused by the
auction or retirement of its generating plants.
The potential impacts on the City of Oswego,
and other communities potentially affected, fall within the range
considered in the FGEIS and no further analysis is required in this
proceeding.
4. EFFECT OF COMPETITIVE TRANSITION CHARGE
(CTC) ON PLANT DISPATCH
The proposed Settlement includes a provision
which will allow the company to partially recover its above-market
generation costs through a non-avoidable CTC charge. In its motion
filed on May 13, 1997 in Case 96-E-0952, PII contended that since
potential competitors will not receive a similar income stream,
companies receiving a CTC would offer generation to the ISO at a
subsidized and uneconomic price. This, PII asserted, could result
in a company operating less efficient and dirtier plants than the
competitive plants which would have operated in the absence of the
CTC.
However, under the provisions of the proposed
settlement, collection of NMPC's stranded costs is not dependent on
operating a Niagara Mohawk plant (i.e., is not marginal revenue).
Both Niagara Mohawk and any competitors would face the same short
term decision criterion. They would maximize profits (or minimize
losses) on existing facilities by selling on the market whenever
the clearing price equals or exceeds their marginal operating
costs--as they themselves calculate marginal costs given their best
information.
While not addressed in any filed comments, some
parties in public hearings have objected to the collection of the
CTC from customers who choose to install solar panels or other
renewable technologies to supply their power but remain connected
with the company for back-up. They contend that, by increasing
their costs, the CTC slows the development of renewable energy and
increases environmental impacts. It appears to Staff that
even-handed application of the CTC merely puts all power sources on
an even footing. Since the CTC costs avoided by installers of
renewable equipment would be ultimately born by other ratepayers or
company stockholders, special exemptions from the CTC would
constitute an indirect and uneconomic subsidy. If subsidies for
renewables are in the public interest, they can be provided
directly through the SBC or through legislative action.
4. FUEL BURNED BY NIAGARA MOHAWK
Various Niagara Mohawk units have the capacity
to burn either coal, oil or gas within existing air quality limits.
Decisions about which fuel to burn at these facilities will
continue to be based on economic considerations and unrelated to
restructuring regardless of ownership.
D. EFFECTS OF THE MRA
For a number of years the company has been locked
into "must run" contracts requiring it to purchase power, whenever
offered, at above-market prices. Most of these plants are either
small hydro-electric facilities or modern gas-fired cogenerators.
In July of 1997, the company reached a Master Restructuring
Agreement with 29 IPPs representing 80% of the company's
above-market costs. Under the MRA, the settling IPPs agreed to
"restructure, amend or replace" their current contracts in return
for payments from NMPC, purchase by NMPC or other contract
modifications.
1. POTENTIAL AIR QUALITY IMPACTS OF CHANGES IN
IPP CONTRACTS
It is not feasible to predict how the operation
of each of these plants will be changed by the MRA. However, in
general, the MRA could impact the operation of the settling IPP
plants through changes in the dispatch of the IPPs and changes in
steam sales to steam hosts. According to NMPC estimates, at most
about 15% of the total IPP steam production would be retired or
moth balled due to the MRA. The remainder will continue operating
but will either enter into bi-lateral contracts or bid into the
market on a basis that reflects true marginal costs.
The FGEIS examined the possibility that all the
"must run" IPP contracts in New York State would be renegotiated so
that these plants would be economically dispatched. The model used
for the FGEIS showed that economic dispatch of IPPs would result in
increased SO2 emissions and decreased NOx and CO2 emissions,
relative to the base case, during most of the study period.
However, during the later years of the period, economic dispatch of
IPPs would result in lower SO2 emissions.
In Opinion No. 96-12, which adopted the FGEIS,
the Commission observed that the analysis of retail market
structures (which included consideration of economic dispatch of
IPPs) forecast that competition would result in greater air quality
impacts then the no action alternative, but that moving towards
competition was still desirable when these effects were balanced
against the likely economic benefits of the policy.
The proposed MRA would have smaller effects
than those reported in the FGEIS since the FGEIS assumed that all
the IPPs in the state with "must run" contracts would be
economically dispatched, while the MRA affects only some of the
IPPs having contracts with NMPC. It should be noted that, although
there is likely to be a temporary increase in SO2 emissions
resulting from the MRA, NMPC has agreed to permanently donate 5,000
SO2 allowances to the Adirondack Council for retirement.
Many of the IPP units affected by the MRA have
steam hosts which currently purchase byproduct steam or hot water
from generating activities. To the extent that IPPs are retired or
mothballed, the steam hosts may have to build new auxiliary boilers
or refurbish retired boilers. Niagara Mohawk, in its EAF,
estimates that the steam host steam requirements directly affected
by retirement of settling IPPs would represent only about 0.8% of
total IPP steam production. In addition, it is possible that
changes in the operation of an IPP due to renegotiation of
contracts with NMPC could result in a higher steam price or limited
steam availability and thus cause increased operation of auxiliary
boilers. These single purpose boilers could be less efficient and
somewhat more polluting than the cogeneration units they replace.
In general, we would assume that the indirect
air quality impacts of increased operation of new or existing
auxiliary steam host boilers would have only marginal air quality
impacts since most steam hosts currently served by an adjacent gas
fired IPP would probably have relatively easy physical access to
clean burning natural gas to feed their own boilers and since
the amount of steam involved is relatively low in the context of
this assessment.
2. POTENTIAL SOCIO-ECONOMIC IMPACTS OF
INTERRUPTION OF STEAM SUPPLY TO STEAM HOSTS
As noted above, it is possible that the MRA,
which modifies or terminates contracts between NMPC and a number of
IPPs, may affect the price or availability of steam or hot water
currently provided by these IPPs to industrial steam hosts. This
could have a variety of impacts on the costs or operations of the
steam hosts. For example:
- steam prices charged to the steam hosts could
rise because of changes in the cogenerators'
revenue structure;
- steam hosts may have to change production
schedules because cogenerators operate less
frequently or less regularly;
- steam may no longer be available from
cogenerators who cease operation;
- the installation or refurbishment of
auxiliary boilers to replace cogenerated
steam may result in higher capital and
operating costs or in disruption of steam
host operations during the period of
permitting and construction.
Such changes could have short term effects on
profits, worker incomes, employment and local economies if, for
example, production curtailments and layoffs or reduced shifts were
required during a transition period. Long term local socio-
economic impacts might result if the steam host saw a major
permanent change in its capital or operating costs which made it
less competitive in the market.
These adverse local socio-economic impacts
would be balanced by positive socio-economic impacts on a larger
scale. In many cases, IPPs sought out steam hosts primarily to
become "qualifying facilities" (QFs) under the Public Utilities
Regulatory Policy Act of 1978 (PURPA) and thus eligible for
legislatively mandated above-market price must-run contracts with
Niagara Mohawk. As a result of the MRA, these plants will be
dispatched economically based on their marginal costs. The
resulting improvement in economic efficiency will lower costs and
benefit ratepayers and the state's economy.
This is not to say that the local economic
disruption which might be caused by the MRA is inconsequential.
However, it is likely that such impacts can be adequately
mitigated. We note that the parties to the settlement have
committed (section 13.8) to "pursue diligently ways to minimize any
economic or operational difficulties due to changes in IPP steam
production which could occur as a result of the MRA..."
E. EFFECT OF RESTRUCTURING PLAN ON CONSTRUCTION
OF NEW TRANSMISSION FACILITIES
In its EAF, Niagara Mohawk states that no new
transmission facilities are required to implement the October 10
agreement. It is possible, however, that load pockets could occur
within the franchise in certain combinations of load and weather.
Load pockets are of potential concern in a
competitive environment because the owner of facilities in the load
pocket could exercise market power during load pocket conditions
unless there were sufficient competing generation sources within
the load pocket. In many areas of the NMPC franchise there is a
mix of generating facilities owned by NMPC and IPPs. Where this
diversity of ownership occurs, the exercise of market power is less
likely to occur. However, ownership of NMPC facilities is likely
to change within the next few years because NMPC has committed to
auctioning its non-nuclear generation. Conceivably the ownership
of generation could become more dispersed in some areas (lessening
market power concerns) and more concentrated in other regions
(increasing the potential market power of owners).
Additional transmission could be constructed by the
regulated T&D utility to prevent the exercise of market power. The
construction of new transmission facilities can be anticipated to
have a variety of environmental impacts. These were discussed
generically in the FGEIS. However, any construction of significant
new transmission would require environmental review and approval by
the Public Service Commission under Article VII of the Public
Service Law. Under this law the Commission is obligated to weigh
the costs and benefits of the transmission addition and to consider
alternatives.
In many situations, the Commission could take other
steps to relieve or prevent market power which would not have
incremental environmental impacts. For example, it could impose
requirements on Niagara Mohawk's auction process which would limit
the amount of generation any one bidder could buy in a potential
load pocket, or could require purchasers to enter into special
contracts with the T&D utility which would limit or index prices
which could be charged during load pocket conditions. In some
situations the Commission might encourage T&D utilities to offer
targeted DSM programs to prevent the exercise of market power. In
Section 7.2(1) of the settlement, the company committed itself to
evaluate and implement cost effective alternatives to major T&D
projects including DSM and distributed generation.
F. MISCELLANEOUS ENVIRONMENTAL ISSUES
1. REMEDIATION OF COAL GAS SITES
For several years the company has been
conducting a site remediation program designed primarily to clean
up environmental damage at old coal gas sites which the company had
acquired during its consolidation. Section 2.6.5.2 of the
settlement commits the company to continue this effort. No
incremental environmental impacts are anticipated.
2. ENVIRONMENTALLY SIGNIFICANT LANDS OWNED
BY NIAGARA MOHAWK
The company currently owns extensive
undeveloped land associated primarily with its hydro facilities.
Some portions of this land have considerable ecological or scenic
value. Divestiture of these hydro facilities could result in the
development of these lands and the loss of their ecological values.
However, in sections 7.2 (iv through x) the company commits to
donate or sell conservation and development right easements to the
State of New York for these critical parcels. No incremental
negative environmental impacts are anticipated.
3. ENVIRONMENTAL DISCLOSURE
Various parties suggested that some customers
in a competitive power market may wish to consider environmental
values in their power purchase decisions. In the absence of
reliable and consistently presented information on the generation
sources used by suppliers, customers may be unable to make informed
decisions based on environmental as well as economic
considerations. A well defined environmental disclosure program
would encourage the use of environmentally responsible generation
sources.
Section 7.2 (xvi) of the settlement states that
the company and Staff have agreed to " ... work with load serving
entities and others to develop and implement, where feasible,
meaningful and cost effective, an approach to providing customers
with fuel mix and emission characteristics of the generation
sources relied upon by the load serving entity."
VI. MITIGATION OF IMPACTS -- MONITORING
It is important to note that the FGEIS explicitly
recognized that "the likely environmental effects of a shift to a
more competitive market for electricity are not fully
predictable due to the absence of precedence, complexity of
the New York electric industry, future regulatory activities,
including those of other states and the federal government, and the
nature and degree of market response. The same uncertainty
persists with respect to Niagara Mohawk's restructuring plan.
In Opinion 96-12 (Opinion and Order Regarding Competitive
Opportunities for Electric Service), the Commission made certain
"findings" pursuant to the State Environmental Quality Review Act.
The Commission determined that "...adverse environmental impacts
will be avoided or minimized to the maximum extent practicable by
incorporating as conditions to the decision those mitigative
measures that were identified as practicable;... These mitigation
measures are: (1) monitoring environmental impacts; (2) system
benefits charge; and (3) assisting efforts undertaken by other
agencies to address interstate pollution transport."
Staff analysis of the Niagara Mohawk restructuring plan
shows that its implementation would result in environmental effects
which would most likely be less than the impact values assessed in
the FGEIS. To address any uncertainty and to evaluate unknown
outcomes, a monitoring program, as envisioned in the FGEIS should
be developed.
Environmental impacts which could be monitored are
described in Section 6.2.3 of the Final Generic Environmental
Impact Statement (FGEIS) issued May 3, 1996 in Case 94-E-0952
(Competitive Opportunities Regarding Electric Service). In
addition, this EAF discuss a number of activities and environmental
changes that would be important to monitor during the transition to
competition. Examples of environmental issues that could require
monitoring include:
- imported electricity from the midwest,
- SO2 and NOx emissions,
- retirement of Niagara Mohawk power plants,
- in-state and out-of-state purchased generation,
- fuel mixture of generation,
- reduction in environmental RD&D,
- loss of environmentally significant land,
- new electric and gas transmission line construction,
- acid precipitation in the Adirondacks and Catskills, and
- mitigation of load pockets.
The proposed environmental monitoring plan currently
being developed by Staff will be organized around the major
environmental impacts considered in the FGEIS and this EAF,
including information necessary for analysis of any restructuring
environmental impacts, confirmation of expected impacts and
exposition of unexpected outcomes and their significance. Staff
anticipates Niagara Mohawk's cooperation in the development and
implementation of this monitoring plan.
VII. CONCLUSIONS
We have considered the proposed October 10 settlement
agreement and have analyzed the potential impacts of that agreement
on the environment. We have compared these likely impacts to those
addressed in the FGEIS. Our analysis has been broadly framed and
has looked at limiting cases in order to encompass any
modifications to that agreement likely to be adopted by the
Commission. In our analysis we have also considered issues raised
by other parties commenting on the Niagara Mohawk EAF.
We conclude that the Niagara Mohawk restructuring plan
would not result in significant new environmental impacts not
considered in the FGEIS, nor would it result in impacts likely to
be greater than those considered in the FGEIS. Therefore no SEIS is
required under the provisions of SEQRA. Staff recommends that the
Commission determine that no further SEQRA compliance is required
with regard to the transitional restructuring plan for this
company.
Although no further SEQRA compliance is required before
Commission action on the NMPC restructuring agreement, the
Commission should institute mechanisms for monitoring and, if
indicated, mitigating some of the potential impacts of
restructuring. Staff is developing a proposed monitoring plan for
the Commission's consideration.
In the future, the Commission will be asked to act on
NMPC's detailed auction plan. Staff is considering the potential
impacts of the auction plan and will advise the Commission on the
possible need for an EAF on that action.
APPENDIX
IMPACT OF POSSIBLE RATE DECREASES ON SALES GROWTH
Several of the potential impacts of deregulation examined
in the Final Generic Environmental Impact Statement (FGEIS) are a
result of the increased sales that are expected to accompany
deregulation. Rate reductions, which are a primary driver of the
increased sales, are not considered explicitly in the FGEIS; rather
it was assumed that, beginning in 1997, sales would increase by an
additional 1% per year for 15 years. That is, if statewide growth
without deregulation is 1.2% per year (as was assumed in the FGEIS
evolving regulatory model), growth with deregulation would be 2.2%.
In each of the restructuring cases, specific rate
reductions are now being considered. Using price elasticity of
demand, these proposed rate reductions now permit the calculation
of an estimate of increased sales to be expected from
restructuring.
The following tables (developed by the Office of Energy
Efficiency and Environment with the assistance of the Office of
Regulatory Economics) consider both short-run elasticity (the
increase in sales which occurs immediately after the rate
reduction) and long-run elasticity (increases which occur in
subsequent years). No other growth inducing factors are included,
so the analysis only reflects the incremental impact of rate
changes. The first step in the calculation (Table F) is to
determine the weighted average elasticities based on the
elasticities for each sector (industrial, commercial and
residential) and the fraction of the utility' load in each sector
(sales weight). Also, the average price reduction per year is
calculated based on the expected rate decrease for each sector and
the sales weight.
Five price reduction scenarios (A through E) are
considered. Scenario B is based on the price reductions from the
Agreement and is the scenario used in the EAF. Other scenarios
explore alternative hypothetical rate reductions.
Tables A through E then calculate the year by year
increase in sales due to competition (short-run, long-run and
total), the cumulative change in sales, and the annual average rate
of sales growth. Residential Delta (Res Delta) is the possible
residential rate reduction considered in the table; Percent Total
Impact per Year (%TI/Yr) is the average price reduction per year
from Table F. The end of the five year settlement period and the
end of the 15 year modeling period are highlighted.
NIAGARA MOHAWK PRICE ELASTICITY IMPACT
- --------------------------------------
Sales ch = (price elasticity * % price ch) + lambda * (sales ch lag
1)
A. %Res
Delta %Tl/Yr Lambda SR Elas LR Elas
1.0 1.35 0.71 0.33 1.14
Cumu- Annual
Year SR Sales LR Sales Total lative Rate
---- -------- -------- ----- ------ ------
1998 0.439 0.000 0.439 0.439 0.44
1999 0.439 0.313 0.752 1.191 0.59
2000 0.439 0.537 0.976 2.167 0.72
2001 0.000 0.697 0.697 2.865 0.71
2002 0.000 0.498 0.498 3.363 0.66
2003 0.000 0.356 0.356 3.718 0.61
2004 0.000 0.254 0.254 3.973 0.56
2005 0.000 0.182 0.182 4.154 0.51
2006 0.000 0.130 0.130 4.284 0.47
2007 0.000 0.093 0.093 4.376 0.43
2008 0.000 0.066 0.066 4.442 0.40
2009 0.000 0.047 0.047 4.490 0.37
2010 0.000 0.034 0.034 4.523 0.34
2011 0.000 0.024 0.024 4.548 0.32
2012 0.000 0.017 0.017 4.565 0.30
B. %Res
Delta %Tl/Yr Lambda SR Elas LR Elas
3.2 2.31 0.71 0.33 1.14
Cumu- Annual
Year SR Sales LR Sales Total lative Rate
---- -------- -------- ----- ------ ------
1998 0.751 0.000 0.751 0.751 0.75
1999 0.751 0.536 1.287 2.037 1.01
2000 0.751 0.919 1.670 3.707 1.22
2001 0.000 1.193 1.193 4.899 1.20
2002 0.000 0.852 0.852 5.751 1.12
2003 0.000 0.608 0.608 6.360 1.03
2004 0.000 0.435 0.435 6.794 0.94
2005 0.000 0.310 0.310 7.105 0.86
2006 0.000 0.222 0.222 7.326 0.79
2007 0.000 0.158 0.158 7.485 0.72
2008 0.000 0.113 0.113 7.598 0.67
2009 0.000 0.081 0.081 7.679 0.62
2010 0.000 0.058 0.058 7.736 0.57
2011 0.000 0.041 0.041 7.778 0.54
2012 0.000 0.029 0.029 7.807 0.50
NIAGARA MOHAWK
Sales ch = (price elasticity * % price ch) + lambda * (sales ch lag
1)
C. %Res
Delta %Tl/Yr Lambda SR Elas LR Elas
5.0 2.73 0.71 0.33 1.14
Cumu-
Year SR Sales LR Sales Total lative Rate
---- -------- -------- ----- ------ ----
1998 0.887 0.000 0.887 0.887 0.89
1999 0.887 0.633 1.520 2.407 1.20
2000 0.887 1.086 1.973 4.380 1.44
2001 0.000 1.409 1.409 5.789 1.42
2002 0.000 1.006 1.006 6.795 1.32
2003 0.000 0.719 0.719 7.514 1.21
2004 0.000 0.514 0.514 8.028 1.11
2005 0.000 0.367 0.367 8.394 1.01
2006 0.000 0.262 0.262 8.656 0.93
2007 0.000 0.187 0.187 8.844 0.85
2008 0.000 0.134 0.134 8.977 0.78
2009 0.000 0.095 0.095 9.073 0.73
2010 0.000 0.068 0.068 9.141 0.68
2011 0.000 0.049 0.049 9.190 0.63
2012 0.000 0.035 0.035 9.224 0.59
D. %Res
Delta %Tl/Yr Lambda SR Elas LR Elas
7.0 3.64 0.71 0.33 1.14
Cumu- Annual
Year SR Sales LR Sales Total lative Rate
---- -------- -------- ----- ------ ------
1998 1.185 0.000 1.185 1.185 1.18
1999 1.185 0.846 2.031 3.215 1.59
2000 1.185 1.451 2.635 5.850 1.91
2001 0.000 1.882 1.882 7.733 1.88
2002 0.000 1.344 1.344 9.077 1.75
2003 0.000 0.960 0.960 10.037 1.61
2004 0.000 0.686 0.686 10.723 1.47
2005 0.000 0.490 0.490 11.213 1.34
2006 0.000 0.350 0.350 11.563 1.22
2007 0.000 0.250 0.250 11.813 1.12
2008 0.000 0.179 0.179 11.992 1.03
2009 0.000 0.128 0.128 12.119 0.96
2010 0.000 0.091 0.091 12.210 0.89
2011 0.000 0.065 0.065 12.275 0.83
2012 0.000 0.046 0.046 12.322 0.78
NIAGARA MOHAWK
Sales ch = (price elasticity * % price ch) + lambda * (sales ch lag
1)
E. %Res Delta %Tl/Yr Lambda SR Elas LR Elas
9.0 4.55 0.71 0.33 1.14
Cumu- Annual
Year SR Sales LR Sales Total lative Rate
---- -------- -------- ----- ------ ------
1998 1.477 0.000 1.477 1.477 1.48
1999 1.477 1.055 2.532 4.010 1.99
2000 1.477 1.809 3.286 7.296 2.37
2001 0.000 2.347 2.347 9.643 2.33
2002 0.000 1.677 1.677 11.319 2.17
2003 0.000 1.198 1.198 12.517 1.98
2004 0.000 0.855 0.855 13.372 1.81
2005 0.000 0.611 0.611 13.983 1.65
2006 0.000 0.436 0.436 14.419 1.51
2007 0.000 0.312 0.312 14.731 1.38
2008 0.000 0.223 0.223 14.954 1.27
2009 0.000 0.159 0.159 15.113 1.18
2010 0.000 0.114 0.114 15.226 1.10
2011 0.000 0.081 0.081 15.308 1.02
2012 0.000 0.058 0.058 15.366 0.96
F. LARGE SMALL RES/ WGTED PRICE
IND IND/COM OTHER AVG PER YR
----- ------- ----- ----- ------
Sales Weight 0.31 0.32 0.37
SR Price Elas. 0.43 0.31 0.25 0.33
LR Price Elas. 1.28 1.17 0.99 1.14
Price Red. A 10.00 2.00 1.00 4.11 1.35
Price Red. B 13.31 5.56 3.22 7.10 2.31
Price Red. C 15.00 6.00 5.00 8.42 2.73
Price Red. D 20.00 8.00 7.00 11.35 3.64
Price Red. E 25.00 10.00 9.00 14.28 4.55
Lambda (1- SR Elas/LR Elas): 0.71
Cases 94-E-0098 et al., Order Setting Electric, Electric
Street Lighting, and Gas Rates (issued April 21, 1995); Opinion No.
95-21 (issued December 21, 1995).
Later on, Administrative Law Judges Jaclyn A. Brilling and
Judith A. Lee also provided the parties assistance in their
settlement efforts.
Niagara Mohawk decided to make the PowerChoice proposal public
to promote a better understanding of the changes under
consideration.
Cases 94-E-0952 et al., Competitive Opportunities Proceeding,
Opinion No. 96-12 (issued May 20, 1996).
Ibid., pp. 74-75.
Cases 94-E-0098 and 94-E-0099, Ruling Setting Case Schedule,
(issued October 17, 1997.)
The Judge presented various other recommendations that are
discussed below in the context of the parties' exceptions.
USEA generally supports the recommended decision and takes no
specific exceptions to it.
The Cities of Fulton and Cohoes, the New York State Conference
of Mayors, and the New York State Assessors' Association join in
the brief filed by the City of Oswego.
The City of Buffalo's brief was filed by Council Member
Alfred T. Coppola.
DOL, NPLF, IPPNY, USEA, Retail Council, NYSEG, PULP, The Wing
Group, and the City of Buffalo did not file briefs opposing
exceptions.
Written comments continued to be submitted after the
recommended decision was issued, including those from the Niagara
Chapter of the Sierra Club, State Senator James W. Wright, the New
York State Wide Senior Action Council, Inc., and the Genesee
Memorial Hospital.
This section summarizing the MRA and the Settlement is
provided for the convenience of the reader. It does not take
precedence over the MRA's or the Settlement's terms.
$50 million of this amount may either be paid in short term
notes or cash at the company's option.
The SIPPs deny that the MRA provides them any seats on the
board of directors. They say it only requires Niagara Mohawk to
select two directors from a list of ten candidates who are not
affiliated with the SIPPs but who are acceptable to them.
As to when the company would become bankrupt, Niagara Mohawk
concedes that its insolvency is not imminent; however, it says,
steps must be taken to arrest its financial demise. Since it sees
no better approach emerging in the future, the company urges that
the MRA be approved.
In addition to MRA-related proceeds, the SIPPs claim they
have physical assets and contractual rights with substantial value.
The SIPPs observe that the New York Debtor and Creditor Law
and the Federal Bankruptcy Code protect creditors against
fraudulent conveyances and the improper depletion of assets. They
also note that the Delaware, New York, and Illinois Revised Uniform
Limited Partnership Acts protect creditors by prohibiting limited
partnerships from making distributions that result in liabilities
exceeding assets.
PULP and the Retail Council are also opposed to the
establishment of an escrow account to benefit the steam hosts.
They believe the steam hosts' contracts should determine their
rights.
According to Norcen, these agreements are separate contracts
in which Niagara Mohawk has undertaken independent obligations
otherwise undertaken by the IPPs.
In its reply brief, Norcen addresses the reasonable
assurances the SIPPs provided in response to the Judge's request
and says they are inadequate. Like the steam hosts, Norcen urges
that an escrow account be established to protect its interests.
See, for example, Tr. 12,565-12,568; 12,779-12,795; 13,039-
13,042; 13,066-13,073; 13,288-13,292.
See, Tr. 13,040.
The analysis values the transfer of Niagara Mohawk's stock to
the SIPPs based on the company's valuation of the regulatory asset
as presented in Appendix C to the Settlement. Our prudence
determination is premised on that value.
As Niagara Mohawk has agreed in the Settlement Agreement,
this finding of prudence carries with it no entitlement to recovery
by Niagara Mohawk of any return on the regulatory asset associated
with the MRA, either during the term of the Settlement or
thereafter.
The parties' exceptions concerning the CTC are discussed
elsewhere in this opinion and order.
Cases 90-M-0225 et al., Settlement Procedures, Opinion No.
92-2 (issued March 24, 1992) Appendix B, p. 8.
The company, Staff, and MI also respond to the specific
points supporting PULP's and Oswego's general opposition to the
Settlement. Such points are addressed below.
Cases 94-E-0952 et al., supra, Opinion No. 96-12.
CPB specifically proposes that the amortization period for
the MRA-related asset be extended by a year. Enron/Wepco consider
a one to three year extension of the MRA debt financing proper
while PULP does not quantify the extension it recommends.
Customer charges are addressed below.
Tr. 13,048.
While MI seeks to preserve a five-year rate option for
industrial customers that would lock in their Niagara Mohawk
electric commodity and CTC charges, Enron/Wepco is concerned that
the company will use this option to provide large customers below
market rates and preclude marketers from competing for their
business.
The financial forecasts supporting the Settlement (Appendix
C to the agreement) are premised in part on an assumed average
interest rate of 8.5% for the senior subordinated notes needed to
finance the MRA. Since the time those forecasts were made,
interest rates have declined. While the actual interest rates on
the senior subordinated notes will not be known until the company
issues the notes in the near future, we are requiring the company
to defer the interest rate savings between the forecasted 8.5% and
the actual rate for each of the five years of the settlement
period. To the extent the Commission reduces rates beyond the
levels in PowerChoice or the company applies for a rate increase in
the fourth or fifth year, as allowed by the Settlement's terms, the
deferred interest rate savings may be used to fund such reductions
or offset any such increase that may be authorized. To the extent
a deferred interest rate savings balance remains at the end of the
fifth year, we will decide at that time how best to use the
deferred savings.
Staff observes that the Retail Council supports the
Settlement's rate design approach for small commercial customers.
With respect to these customers, PULP believes we should
reconsider whether they should be able to avoid making CTC
payments. In general, PULP considers it inequitable for stranded
cost recovery to shift from some customers to others. It suggests
that the existing exemption for customers with flexible negotiated
rates cease when their contracts end. Only in those cases where
the CTC would force a customer off the system would PULP support a
waiver.
This point refers to The Wing Group's affiliation to Western
Resources, Inc.
Such customers shall be considered the same as existing S.C.
7 customers under Settlement Section 4.11.4.1. To implement this
requirement, we are directing Niagara Mohawk to file a proposal
within two weeks and interested parties will have ten days to
comment on it.
MI proposed that the parties meet to consider ways to
implement the Judge's recommendations but no such meetings are
necessary.
Case 96-E-0900, Orange and Rockland Utilities, Inc. -
Electric Rates/Restructuring, Opinion No. 97-20 (issued December
31, 1997), mimeo pp. 16-18.
We are approving the Settlement's incentive provisions for
the auction of the Oswego Steam Station.
Settlement Section 3.3.1.
Settlement Section 9.3.1.
Enron/Wepco specifically object to the requirement that ESCOs
provide security equal to their customers' two highest monthly
usage levels multiplied by the company's highest monthly on-peak
energy buyback rate.
Settlement Section 8.3.2.
The final Environmental Assessment Form is Appendix C. The
substantive comments received are considered here and in the EAF.
As a procedural matter, Oswego excepts, contending we have failed
to comply with the requirements of SEQRA to date. However, as
detailed above, the process we have used complies fully with the
applicable requirements. Moreover, the attached EAF addresses the
substantive and environmental concerns that were raised by Oswego
and other parties.
Settlement Section 9.2.1.3.
Case 96-M-0706, Consumer Protection Rule Amendments,
Memorandum and Resolution Adopting Amendments To 16 NYCRR Part 11
(issued February 17, 1998), P. 6.
Settlement Section 11.1.2.
Id.
Specifically, 15 U.S.C. Section 1691(a)(2).
See, for example, Case 94-E-0952, Competitive Opportunities,
Opinion and Order Deciding Petitions for Clarification and
Rehearing, Opinion No. 97-17 (issued November 18, 1997), mimeo pp.
29-35.
15 U.S.C. Section 1691(c)(1).
Settlement Section 7.1.2.
We are aware that Niagara Mohawk is participating in ongoing
negotiations with the City of Oswego, County, and School District
representatives on the future tax status of the company's
facilities in Oswego. We consider such negotiations between
municipalities and utility companies to be a beneficial means for
resolving such issues, absent legislation.
Niagara Mohawk's contractual commitments to the IPPs alone
have been rising by $50 million per year. Tr. 13,040.
Cases 94-E-0952, et al., In the Matter of Competitive
Opportunities Proceeding Regarding Electric Service, Opinion No.
96-12 (issued May 20, 1996).
Ibid, p. 78, n. 1.
Cases 94-E-0952, et al., Competitive Opportunities Proceeding
Rehearing Petitions, Opinion No. 96-17 (issued October 24, 1996).
Cases 94-E-0952, et al., Competitive Opportunities
Proceeding, Opinion No. 96-12 (issued May 20, 1996), p. 76.
6 NYCRR Part 617.10(d).
These are primarily sites where coal gas was produced for
illumination during the 19th century which were acquired by NMPC
during the period of consolidation of smaller utilities which
resulted in the creation of NMPC.
Cases 94-E-0952, et al., Ruling on the Motion for
Supplemental Environmental Impact Statements, (issued June 19,
1997), p. 17.
The following PII members are signatories to the settlement:
NRDC, PACE, the Adirondack Council, New York Rivers United and the
Association for Energy Affordability.
To provide a sense of scale, estimated NYPP sales for 1996
were about 144,500 GWH and NMPC sales were 37,355 GWH. Under the
FGEIS comparative scenarios, a 1.0% per year incremental growth
rate would result in additional statewide sales of about 1.445 GWH
in 1997 due to price elasticity and additional NMPC sales of about
374 GWH.
Cases 94-E-0952, et al., In the Matter of Competitive
Opportunities Regarding Electric Service, Opinion and Order 96-12
(issued May 20, 1996), pg. 81.
The assumed level of DSM was equivalent to the company's 1996
DSM goal. No provision was made in the base case for energy
efficiency sales reductions resulting from programs funded by a
system benefits charge.
For example, if a cogenerator which formerly ran around the
clock under a "must run" contract, moved to a more limited or
irregular operating regime under economic dispatch.
The possible economic and employment impacts of changes or
discontinuation of IPP steam sales to steam hosts will be discussed
in another section of this EAF.
FGEIS, p. 77.
EXHIBIT 10-14
- -------------
NIAGARA MOHAWK POWER CORPORATION
CONSENT SOLICITED BY NIAGARA MOHAWK POWER CORPORATION
TO ACTION OF PREFERRED SHAREHOLDERS WITHOUT A MEETING
The undersigned, a holder of record of shares of preferred stock of
Niagara Mohawk Power Corporation (the "Corporation") on the record
date, October 23, 1997, for this consent solicitation, hereby
acknowledges receipt of the Consent Statement dated October 28,
1997 (the "Consent Statement"), and consents pursuant to the
Corporation's Certificate of Incorporation, with respect to all of
the shares of preferred stock held by the undersigned, to the
adoption of the following proposal (the "Proposal") without a
meeting of the shareholders of the Corporation (except as otherwise
specified below).
THE CORPORATION URGES YOU TO CONSENT TO THE PROPOSAL. Proposal:
Consent to the incurrance of $5 billion in unsecured debt in excess
of the Present Limitation applicable to the Corporation as set
forth in the Consent Statement.*
- ----------------
*The Present Limitation is so defined as (i) 10% of the sum of the
secured indebtedness of the Corporation and its wholly-owned
subsidiaries, the capital of the Corporation and the consolidated
surplus of the Corporation plus (ii) $50,000,000.
EXHIBIT 10-20
NIAGARA MOHAWK POWER CORPORATION
DEFERRED COMPENSATION PLAN
As Established Effective January 1, 1994
Amended October 23, 1997
1. PURPOSE
The purpose of the Niagara Mohawk Power Corporation Deferred
Compensation Plan is to provide a select group of management or highly
compensated employees of the Company with the opportunity to defer the
current receipt of cash compensation otherwise due them. The Plan is
intended to constitute a "top hat" plan within the meaning of Sections
201(2), 301(a)(3), and 401(a)(1) of the Employee Retirement Income
Security Act of 1974, as amended.
2. DEFINITIONS
"Administrator" means the Board or its designee, the Compensation and
Succession Committee of the Board, which shall be responsible for the
administration of this Plan.
"Board" means the Board of Directors of the Company.
"Company" means Niagara Mohawk Power Corporation, its successors and
assigns.
"Change in Control" shall have the meaning set forth in Appendix A
hereto.
"Constructive Termination" means the Participant's deemed
termination of employment with the Company by reason of any of the following
events which occurs within 24 full calendar months after a Change in Control:
(i) the Company assigns any duties to the Participant which
are materially inconsistent with the Participant's position, duties,
offices, responsibilities, or reporting requirements immediately prior
to a Change in Control; or
(ii) the Company reduces the Participant's 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) and in lieu thereof does not make available plans
providing at least comparable benefits; or
(iv) the Company takes action which adversely affects the
Participant's participation in, or eligibility for, or materially
reduces the Participant's benefits under, any of the plans described
in (iii) above, or deprives the Participant of any material fringe
benefit enjoyed by the Participant immediately prior to the Change in
Control, or fails to provide the Participant with the number of paid
vacation days to which the Participant was entitled in accordance with
normal vacation policy immediately prior to the Change in Control; or
(v) the Company requires the Participant to be based at any
office or location other than one within a 50-mile radius of the
office or location at which the Participant was based immediately
prior to the Change in Control; or
(vi) the Company purports to terminate the Participant's
employment otherwise than as expressly permitted by his or her
employment agreement, if any; or
(vii) the Company fails to comply with and satisfy Section 12.2
of the Plan.
"Deferral Account" means the Participant's individual account
established on his or her behalf pursuant to the Plan.
"Eligible Employee" means a highly paid Employee or a management
Employee whose position of authority may influence policy decisions of
the Company (including design and operation of the Plan) and who in
either case has been selected by the Administrator as eligible to
participate in the Plan.
"Employee" means an employee of the Company.
"ERISA" means the Employee Retirement Income Security Act of 1974, as
amended.
"Incentive Award" means an award, if any, provided to an Eligible
Employee under the Company's Annual Officer Incentive Compensation Plan,
Stock Incentive Plan, or Long-Term Incentive Plan, excluding any awards
of Stock Appreciation Rights under such Plans.
"Participant" means an Eligible Employee who has elected under the
terms and conditions of the Plan to defer payment of a portion of Salary or
all or a portion of an Incentive Award, or both, which would have
otherwise been paid to such Employee for services rendered to the
Company.
"Payment Date" means the date as of which payments are due to commence
under the Plan.
"Plan" means the Niagara Mohawk Power Corporation Deferred Compensation
Plan (including any Appendices), as set forth herein and as amended from
time to time.
"Plan Year" means the calendar year.
"Salary" means the annualized rate of an Employee's normal base cash
compensation, prior to any deferrals and exclusive of overtime, bonuses,
special or incentive pay or any fringe benefits determined as of
December 31 of each year prior to the beginning of the next Plan Year.
"Total Disability" means the Participant's physical or mental inability
to perform substantially the Participant's duties of employment with the
Company for a period exceeding 12 consecutive months, as determined by a
licensed physician selected by the Administrator.
3. DEFERRAL ELIGIBILITY AND PARTICIPATION
3.1 An Eligible Employee shall be eligible to participate in the Plan
as of the first day of the Plan Year after completion and submission to the
Administrator of an election form, pursuant to Section 4 of the Plan.
3.2 No later than the November 1 preceding a Plan Year, the
Administrator shall notify each Eligible Employee of eligibility to
participate in the Plan for that Plan Year.
4. ELECTION TO DEFER
4.1 By November 30 prior to the beginning of a Plan Year, an Eligible
Employee may elect, irrevocably, by written notice to the Administrator on an
election form, to defer payment of a percentage of Salary or an Incentive
Award, or both, otherwise payable during such Plan Year. The deferral
percentage applicable to Salary shall be in 5% increments, not to exceed 25%
of Salary. The deferral percentage applicable to an Incentive Award shall be
in 10% increments, not to exceed 100% of an Award.
4.2 Notwithstanding any provisions in the Plan to the contrary, an
Employee or other individual who becomes an Eligible Employee during a Plan
Year may elect, in the manner described in Section 4.1 of the Plan, to defer a
percentage of Salary otherwise payable during the remainder of the Plan Year
or an Incentive Award, or both, provided such election is made, irrevocably,
within thirty (30) days after being notified that such individual is an
Eligible Employee.
4.3 Salary deferred under the Plan will be ratably deducted in each
pay period in the Plan Year. An expressed percentage shall apply to any
Salary changes during the Plan Year.
4.4 The Deferral Period shall be, irrevocably, a period beginning as
of the first day of the Plan Year to which the deferral election applies and
ending on the earliest of:
(a) the date the Participant retires at early or normal retirement age under
the tax-qualified defined benefit pension plan maintained by the Company, in
which the Participant participates, or
(b) the date the Participant terminates employment with the Company for
any other reason, including death or Total Disability; or
(c) the date the Participant's employment with the Company is deemed
terminated by reason of Constructive Termination.
4.5 Although an election to defer under the Plan is irrevocable,
the Administrator may authorize a Participant to reduce or waive such election
for the remainder of the Plan Year upon a finding that the Participant has
suffered a financial hardship, within the meaning of Section 7.2 of the Plan.
4.6 The company shall deduct from any deferred Salary and
Incentive Award, any FICA, FUTA or medicare taxes required to be withheld.
5. DEFERRAL ACCOUNT
5.1 As of the last day of each month, the Company shall credit to
a Participant's Deferral Account the amount deferred for that month in
accordance with the Participant's deferral election pursuant to Section 4.1 of
the Plan.
5.2 The Company shall credit earnings to each Participant's
Deferral Account until the entire Deferral Account has been distributed. For
any calendar year, the rate of credited earnings shall be the equivalent of
the rate of return on the investment fund or funds selected by the Participant
on an appropriate election form provided to the Administrator at the time of
the Participant's deferral election pursuant to Section 4.1 of the Plan. A
Participant may select from the investment funds designated from time to time
by the Administrator, and shall elect, in 50% increments, the portion of his
or her Deferral Account considered invested in such fund or funds
for the purpose of credited earnings. Earnings shall be credited to a
Participant's Deferral Account as of the last day of each month. A
Participant may change his or her investment fund selection annually at the
time of any subsequent deferral election pursuant to Section 4.1 of the Plan;
any such investment fund change shall be effective as of the first day of the
Plan Year following such deferral election. Notwithstanding the foregoing
provisions of this Section 5.2, neither the Company nor the Administrator, nor
any agent thereof, shall be under any obligation whatsoever to have any assets
or other funds actually invested on behalf of the Participant in the
investment fund or funds selected by the Participant for the purpose of
credited earnings.
5.3 (a) Funds held for a Participant shall be held as a general asset
of the Company subject to the Company's general creditors. No Participant or
beneficiary shall have any security interest whatsoever in any assets of the
Company. To the extent that any person acquires a right to receive payments
under the Plan, such right shall not be secured or represented by any assets
of the Company.
(b) Participants have the status of general unsecured creditors of
the Company with respect to their Deferral Accounts, and the Plan
constitutes a mere promise by the Company to make payments of deferred Salary
or Incentive Award(s) in the future. It is the intention of the Participants
and the Company that the Plan be unfunded for tax purposes and for purposes of
Title I of ERISA.
5.4 Each Participant's Deferral Account shall be maintained on the
books of the Company until full payment has been made to the Participant or
beneficiary. The Company may, but shall not be required to, set funds aside
for the Deferral Account. Any funds that are so set aside shall be subject to
claims of the Company's general creditors, as provided in the document
governing the funds.
5.5 Upon the request of a Participant, but no more frequently than
quarterly, the Administrator shall provide a statement of any amounts credited
to such Participant's Deferral Account.
6. TIME AND MANNER OF PAYMENT
6.1 Subject to Section 7, a Participant's Payment Date shall be the
first of the month after the earliest of the following:
(a) the date the Participant retires at normal or early retirement
age under the tax-qualified defined benefit pension plan maintained by the
Company, in which the Participant participates; or
(b) the date the Participant terminates employment with the Company
for any other reason, including death or Total Disability; or
(c) the date the Participant's employment with the Company is
deemed terminated by reason of Constructive Termination.
6.2 The value of a Participant's Deferral Account shall be determined
as of the last day of the month immediately preceding the Payment Date.
6.3 The distribution of a Participant's Deferral Account shall be in
cash, in one of the following methods as the Participant selects in writing to
the Administrator at the time of his or her last deferral election under
Section 4.1 of the Plan:
(a) a single sum paid within thirty (30) days after the Payment
Date; or
(b) substantially equal annual installments starting on the Payment
Date and paid over a specified period, not to exceed ten (10) years.
In the event the Participant shall for any reason fail to timely
select a method of distribution pursuant to the foregoing provision of this
Section 6.3, such Participant's Deferral Account shall be paid in accordance
with method (b) above over ten (10) years.
6.4 The Company may withhold from any payment under the Plan any taxes
or other amounts as required by law. Any taxes imposed on Plan benefits
shall be the sole responsibility of the Participant or beneficiary.
7. WITHDRAWALS
7.1 A Participant or surviving spouse may withdraw amounts before those
amounts would otherwise have been paid because of financial hardship, as
determined by the Administrator. The withdrawal shall be limited to the
amount reasonably necessary to meet the financial hardship.
7.2 "Financial hardship" means a severe financial hardship resulting
from a sudden and unexpected illness or accident of the Participant or a
dependent (as defined in Code Section 152(a)) of the Participant, loss of the
Participant's property due to casualty, or other similar extraordinary and
unforeseeable circumstances arising as a result of events beyond the control
of the Participant. The circumstances that will constitute a financial
hardship will depend upon the facts of each case, but, in any case, payment
may not be made to the extent that such hardship is or may be relieved (i)
through reimbursement or compensation by insurance or otherwise, (ii) by
liquidation of the Participant's assets, to the extent the liquidation of such
assets would not itself cause severe financial hardship, or (iii) by cessation
of the Participant's election to defer under the Plan.
7.3 The Administrator shall establish guidelines and procedures for
implementing withdrawals. An application shall be in writing, signed by the
Participant or surviving spouse and include a statement of facts causing the
financial hardship and any other facts required by the Administrator.
7.4 The withdrawal date shall be determined by the Administrator. The
Administrator may require a minimum advance notice and may limit the amount,
time and frequency of withdrawals.
8. DEATH OR DISABILITY
8.1 Upon death of a Participant, the value of the Deferral Account
shall be paid within thirty (30) days after receipt of satisfactory proof of
death, in the following order of priority:
(a) to the beneficiary designated by the Participant in writing to
the Administrator; or if none
(b) to the Participant's surviving spouse; or if none
(c) to the Participant's descendants, per stirpes; or if none
(d) to the Participant's estate.
8.2 All beneficiary designations shall be in writing and signed by the
Participant, and shall be effective only if and when delivered to the
Administrator during the lifetime of the Participant. A Participant may,
during his or her lifetime, change the beneficiary or beneficiaries by a
signed, written instrument delivered to the Administrator. The payment of
amounts shall be in accordance with the last unrevoked written designation of
the beneficiary that has been signed and so delivered.
8.3 If the recipient is the surviving spouse and the Participant had
selected an installment payout, distribution of the Deferral Account balance
will be by installments in accordance with the election, subject to Section 7.
In all other cases, distribution will be by a single sum payment.
8.4 A Participant who terminates employment by reason of Total
Disability shall be entitled to payment of his or her Deferral Account in
accordance with Section 6.3.
9. PLAN TERMINATION AND AMENDMENT
9.1 The Board may terminate or suspend the Plan at any time for any
reason, without prior notice to any Participant or beneficiary. On
termination or suspension of the Plan the following shall apply:
(a) amounts deferred through the last month before the effective
date of termination or suspension shall remain deferred and shall be credited
to the Participants' Deferral Accounts in accordance with the Plan.
(b) deferral elections shall terminate as of the effective date of
the Plan termination or suspension, and no further deferrals shall be allowed.
(c) amounts credited to a Deferral Account shall remain to the
credit of the Account. In the event of Plan termination, the Account shall
continue to be credited with earnings, in accordance with Section 5.2 of the
Plan, until the effective date of Plan termination, and any amounts credited
to the Account shall be paid out in a single sum payment as soon as
practicable after Plan termination. In the event of Plan suspension, the
Account shall continue to be credited with earnings, in accordance with
Section 5.2 of the Plan, and shall be paid out in accordance with the
provisions of the Plan.
9.2 The Board may amend this Plan; an amendment may be retroactive
within a Plan Year except that the right of Participants to defer Salary and
Incentive Awards may not be reduced for the portion of the Plan Year through
the month in which the amendment was adopted and no amendment may reduce a
Participant's Deferral Account balance as of the effective date of such
amendment.
If the Internal Revenue Service determines that any amount deferred
under this Plan will be subject to current income taxation, all amounts to
which the determination is applicable will be paid to the Participants within
thirty (30) days of such determination.
10. ADMINISTRATION
10.1 The Plan shall be administered by the Administrator. The
Administrator, in its sole discretion, shall interpret the Plan, determine
eligibility, see that the records are maintained, and assume responsibility
for ensuring that the Plan is operated in accordance with its purpose. The
Administrator may delegate any of its responsibilities to such person or
persons or committees, and may appoint such agents, as it shall deem necessary
or advisable.
10.2 The Company shall be solely responsible for providing Plan
benefits, and the Administrator, any officer, employee or agent of the Company
shall not be liable for such benefits. The Administrator, its delegate, any
officer, employee or agent of the Company shall not be liable for any action
or failure to act with respect to the Plan, except where such act or omission
was willful, intentional, or fraudulent. The Company shall indemnify and hold
harmless the Administrator and any officer or employee of the Company against
any claims, loss, damage, expense or liability arising from any action or
failure to act with respect to the Plan except where such act or omission was
willful, intentional or fraudulent.
11. CLAIMS PROCEDURE
11.1 Original Claim
Any person claiming a benefit, requesting an interpretation or ruling
under the Plan, or requesting information under the Plan shall present the
request in writing to the Administrator which shall respond in writing as soon
as practicable, but within sixty (60) days.
11.2 Denial
If the claim or request is denied, the written notice of denial shall
state:
(a) the reasons for denial, with specific reference to the Plan
provisions on which the denial is based;
(b) a description of any additional material or information
required and an explanation of which it is necessary; and
(c) an explanation of the Plan's claim review procedure.
11.3 Request for Review
Any person whose claim or request is denied or who has not received a
response within sixty (60) days may request review by notice given in writing
to the Administrator. The claim or request shall be reviewed by the
Administrator or a designated committee of the Administrator which may, but
shall not be required to, have the claimant appear before it. On review, the
claimant may have representation, examine pertinent documents, and submit
issues and comments in writing. The Administrator shall be the named
fiduciary for the review of denied claims under ERISA.
11.4 Final Decision
The decision of review shall normally be made within ninety (90) days.
If an extension is required for a hearing or other special circumstances, the
claimant shall be so notified and the time limit shall be one hundred twenty
(120) days. The decision shall be in writing and shall state the reasons and
the relevant Plan provisions. All decisions on review shall be final and bind
all parties concerned.
12. MISCELLANEOUS PROVISIONS
12.1 The rights of a Participant under this Plan are personal and,
prior to a Payment Date, are not subject in any manner to anticipation,
alienation, sale, transfer, assignment, pledge, encumbrance, attachment, or
garnishment by creditors of the Participant or the Participant's beneficiary.
In the event the Company elects to invest any funds deferred hereunder, such
funds and the earnings thereon shall remain the exclusive property of the
Company.
12.2 If the Company merges, consolidates, or otherwise
reorganizes, or its assets or business are acquired by another company, this
Plan shall continue with respect to those Participants who continue in the
employ of the successor company. In such an event, however, a successor
corporation may terminate or suspend the Plan as to its employees on the
effective date of the succession or thereafter in accordance with Section 9 of
the Plan. In any such event, Participants will be notified promptly.
12.3 All Participants understand they are employees at will.
Therefore, nothing in the Plan shall interfere with or limit in any way the
right of the Company to terminate, for any reason, any Participant's
employment at any time, nor confer upon a Participant any right to continue in
the employ of the Company or continue as an Eligible Employee.
12.4 If any Plan provision, or its application to any Participant
or beneficiary, is held to be invalid or illegal, neither the remainder of the
Plan nor its application to any other Participant or beneficiary shall be
affected.
12.5 Participation in the Plan shall not reduce any Company
welfare benefit based upon Salary, but neither the Salary nor Incentive Award
deferred under the Plan nor any Plan benefits shall be counted as compensation
for purposes of the Company's tax-qualified retirement plans.
12.6 If a Plan benefit is payable to a person incapable of
handling the disposition of property, the Administrator or its delegate may
direct payment of such benefit to the person taking care of the Participant.
Such distribution shall completely discharge the Administrator and the Company
from all liability with respect to such payments.
12.7 The Plan, and all forms or agreements hereunder, shall be
construed in accordance with and governed by the laws of the State of New York
(other than the conflict of laws provisions) except to the extent that such
laws may be preempted by federal law.
APPENDIX A
For purposes of the Plan, 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 ( ) 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 in Control: ( ) 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 ( ), (ii) and (iii) of subparagraph (3) of this Schedule
A 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, ( ) 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, 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 ( ) 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 10-36
EMPLOYMENT AGREEMENT
Agreement made as of the 19th day of January, 1998, between
NIAGARA MOHAWK POWER CORPORATION (the "Company"), and John H.
Mueller(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. Term of Agreement. The Company shall employ the Executive,
and the Executive shall serve the Company, for the period
beginning January 19, 1998 and expiring on December 31,
2000, subject to earlier termination as provided under paragraph
4 hereof. This Agreement shall be extended automatically by one
year commencing on January 1, 1999 and on January 1st of each
year thereafter, unless either party notifies the other to the
contrary not later than sixty (60) days prior to such date.
Notwithstanding any such notice by the Company, this Agreement
shall remain in effect for a period of thirty-six months from the
date of a "Change in Control" (as that term is defined in
Schedule B hereto, unless such notice was given at least 18
months prior to the date of the Change in Control).
2. Duties. The Executive shall serve the Company as its Senior
Vice President and Chief Nuclear 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 to the business of the Company 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. Compensation. During the term of this Agreement:
a. The Company shall pay the Executive a base salary at an
annual rate of $260,000, 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 and Long Term
Incentive Plan, and any successors thereto, in accordance with
the terms thereof; and
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. Termination. The Company shall continue to employ the
Executive, and the Executive shall continue to work for the
Company, during the term of this Agreement, unless the Agreement
is terminated in accordance with the following provisions:
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
base 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 base 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 4g below.
b. By notice to the Executive, the Company may terminate
this Agreement upon the "Disability" of the Executive. The
Executive shall be deemed to incur a Disability when (i) a
physician selected by the Company advises the Company that the
Executive's physical or mental condition has rendered the
Executive unable to perform the essential functions of the
Executive's position in a reasonable manner, with or without
reasonable accommodation and will continue to render him unable
to perform the essential functions of the Executive's position in
such manner, for a period exceeding 12 consecutive months, or
(ii) due to a physical or mental condition, the Executive has not
performed the essential functions of the Executive's position in
a reasonable manner, with or without reasonable accommodation,
for a period of 12 consecutive months. Following termination of
this Agreement pursuant to clause (i) of the preceding sentence
of this paragraph, the Executive shall continue to receive his
base salary under paragraph 3a hereof for a period of 12 months
from the date of his Disability, reduced by any benefits payable
during such period under the Company's short-term disability plan
and long-term disability plan. Thereafter, or in the event of
termination of this Agreement pursuant to clause (ii) of the
preceding sentence, the Executive shall receive benefits under
the Company's long-term disability plan in lieu of any further
base salary under paragraph 3a hereof.
c. By notice to the Executive, the Company may terminate
the Executive's employment at any time for "Cause". The Company
must deliver such notice within ninety (90) days after the Board
both (i) has or should have had knowledge of conduct or an event
allegedly constituting Cause, and (ii) has reason to believe that
such conduct or event could be grounds for Cause. For purposes
of this Agreement "Cause" shall mean (i) the Executive is
convicted of, or has plead guilty or nolo contendere to, a
felony; (ii) the willful and continued failure by the Executive
to perform substantially his duties with the Company (other than
any such failure resulting from incapacity due to physical or
mental illness) after a demand for substantial performance is
delivered to the Executive by the Company which specifically
identifies the manner in which the Company believes the Executive
has not substantially performed his duties; (iii) the Executive
engages in conduct that constitutes gross neglect or willful
misconduct in carrying out his duties under this Agreement
involving material economic harm to the Company or any of its
subsidiaries; or (iv) the Executive has engaged in a material
breach of Sections 6 or 7 of this Agreement. In the event the
termination notice is based on clause (ii) of the preceding
sentence, the Executive shall have ten (10) business days
following receipt of the notice of termination to cure his
conduct, to the extent such cure is possible, and if the
Executive does not cure within the ten (10) business day period,
his termination of employment in accordance with such termination
notice shall be deemed to be for Cause. The determination of
Cause shall be made by the Board upon the recommendation of the
Compensation and Succession Committee of the Board. Following a
Change in Control, such determination shall be made in a
resolution duly adopted by the affirmative vote of not less than
three-fourths (3/4) of the membership of the Board, excluding
members who are employees of the Company, at a meeting called for
the purpose of determining that Executive has engaged in conduct
which constitutes Cause (and at which Executive had a reasonable
opportunity, together with his counsel, to be heard before the
Board prior to such vote). The Executive shall not be entitled
to the payment of any additional compensation from the Company,
except to the extent provided in paragraph 4h hereof, in the
event of the termination of his employment for Cause.
d. If any of the following events, any of which shall
constitute "Good Reason", occurs within thirty-six months after a
Change in Control, the Executive, by notice of the Company, may
voluntarily terminate the Executive's employment for Good Reason
within ninety (90) days after the Executive both (i) has or
should have had knowledge of conduct or an event allegedly
constituting Good Reason, and (ii) has reason to believe that
such conduct or event could be grounds for Good Reason. In such
event, the Executive shall be entitled to the severance benefits
set forth in paragraph 4g below.
(i) the Company assigns any duties to the Executive which
are materially inconsistent in any adverse respect with the
Executive's position, duties, offices, responsibilities or
reporting requirements immediately prior to a Change in Control,
including any diminution of such duties or responsibilities; or
(ii) the Company reduces the Executive's base salary,
including salary 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, retirement plan
(including the SERP), 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 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 Section
5 hereof, provided that such successor has received prior written
notice from the Company or from the Executive of the requirements
of Section 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.
f. In the event that the Executive's employment is
terminated by the Company without Cause prior to a Change in
Control, the Company shall pay the Executive a lump sum severance
benefit, equal to two years' base salary at the rate in effect as
of the date of termination, plus the greater of (i) two times the
most recent annual bonus paid to the Executive under the
Corporation's Annual Officers Incentive Compensation Plan (the
"OICP") or any similar annual bonus plan (excluding the pro rata
bonus referred to in the next sentence) or (ii) two times the
average annual bonus paid to the Executive for the three prior
years under the OICP or such similar plan (excluding the pro rata
annual bonus referred to in the next sentence). If one hundred
eighty (180) days or more have elapsed in the Company's fiscal
year in which such termination occurs, the Company shall also pay
the Executive in a lump sum, within ninety (90) days after the
end of such fiscal year, a pro rata portion of Executive's annual
bonus in an amount equal to (A) the bonus which would have been
payable to Executive under OICP or any similar plan for the
fiscal year in which Executive's termination occurs, multiplied
by (B) a fraction, the numerator of which is the number of days
in the fiscal year in which the termination occurs through the
termination date and the denominator of which is three hundred
sixty-five (365).
In addition, in the event that the Executive's employment is
terminated by the Company without cause prior to a Change in
Control, the Executive (and his eligible dependents) shall be
entitled to continue participation in the Company's employee
benefit plans for a two-year period from the date of termination,
provided, however, that if Executive cannot continue to
participate in any of the benefit plans, the Company shall
otherwise provide equivalent benefits to the Executive and his
dependents on the same after-tax basis as if continued
participated had been permitted. Notwithstanding the foregoing,
in the event Executive becomes employed by another employer and
becomes eligible to participate in an employee benefit plan of
such employer, the benefits described herein shall be secondary
to such benefits during the period of Executive's eligibility,
but only to the extent that the Company reimburses Executive for
any increased cost and provides any additional benefits necessary
to give Executive the benefits provided hereunder.
Furthermore, in the event that the Executive's employment is
terminated by the Company without Cause prior to a Change in
Control, the Executive shall be entitled to (i) be covered by a
life insurance policy providing a death benefit, equal to 2.5
times the Executive's base salary at the rate in effect as of the
time of termination, payable to a beneficiary or beneficiaries
designated by the Executive, the premiums for which will be paid
by the Company for the balance of the Executive's life and (ii)
payment by the Company of all fees and expenses of any executive
recruiting, counseling or placement firm selected by the
Executive for the purposes of seeking new employment following
his termination of employment.
g. In the event that the Executive's employment is
terminated following a Change in Control, either by the Company
without Cause or by the Executive for Good Reason, the Company
shall pay the Executive a lump sum severance benefit, equal to
four years' base salary at the rate in effect as of the date of
termination.
In addition, 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, the (i) Executive (and
his eligible dependents) shall be entitled to continue
participation (the premiums for which will be paid by the
Company) in the Company's employee benefit plans providing
medical, prescription drug, dental, and hospitalization benefits
for the remainder of the Executive's life (ii) the Executive
shall be entitled to continue participation (the premiums for
which will be paid by the Company) in the Company's other
employee benefit plans for a four year period from the date of
termination; provided, however, that if Executive cannot continue
to participate in any of the benefit plans, the Company shall
otherwise provide equivalent benefits to the Executive and his
dependents on the same after-tax basis as if continued
participation had been permitted. Notwithstanding the foregoing,
in the event Executive becomes employed by another employer and
becomes eligible to participate in an employee benefit plan of
such employer, the benefits described herein shall be secondary
to such benefits during the period of Executive's eligibility,
but only to the extent that the Company reimburses Executive for
any increased cost and provides any additional benefits necessary
to give Executive the benefits provided hereunder.
Furthermore, in the event that the Executive's employment is
terminated following a Change in Control, either by the Company
without Cause or by the Executive for Good Reason, the Executive
shall be entitled to (i) be covered by a life insurance policy
providing a death benefit, equal to 2.5 times the Executive's
base salary at the rate in effect as of the time of termination,
payable to a beneficiary or beneficiaries designated by the
Executive, the premiums for which will be paid by the Company for
the balance of the Executive's life and (ii) payment by the
Company of all fees and expenses of any executive recruiting,
counseling or placement firm selected by the Executive for the
purposes of seeking new employment following his termination of
employment.
h. Upon termination pursuant to paragraphs 4a, b, c, d, or
e above, the Company shall pay the Executive or the Executive's
estate any base salary earned and unpaid to the date of
termination.
i. Anything in this Agreement to the contrary
notwithstanding, in the event it shall be determined that any
payment, award, benefit or distribution (or any acceleration of
any payment, award, benefit or distribution) by the Company or
any entity which effectuates a Change in Control (or any of its
affiliated entities) to or for the benefit of the Executive
(whether pursuant to the terms of this Agreement or otherwise,
but determined without regard to any additional payments required
under this paragraph 4i)(the "Payments") would be subject to the
excise tax imposed by Section 4999 of the Internal Revenue Code
of 1986, as amended (the "Code"), or any interest or penalties
are incurred by the Executive with respect to such excise tax
(such excise tax, together with any such interest and penalties,
are hereinafter collectively referred to as the "Excise Tax"),
then the Company shall pay to the Executive (or to the Internal
Revenue Service on behalf of the Executive) an additional payment
(a "Gross-Up Payment") in an amount such that after payment by
the Executive of all taxes (including any Excise Tax) imposed
upon the Gross-Up Payment, the Executive retains (or has had paid
to the Internal Revenue Service on his behalf) an amount of the
Gross-Up Payment equal to the sum of (x) the Excise Tax imposed
upon the Payments and (y) the product of any deductions
disallowed because of the inclusion of the Gross-Up Payment in
the Executive's adjusted gross income and the highest applicable
marginal rate of federal income taxation for the calendar year in
which the Gross-up Payment is to be made. For purposes of
determining the amount of the Gross-up Payment, the Executive
shall be deemed (i) pay federal income taxes at the highest
marginal rates of federal income taxation for the calendar year
in which the Gross-up Payment is to be made, (ii) pay applicable
state and local income taxes at the highest marginal rate of
taxation for the calendar year in which the Gross-up Payment is
to be made, net of the maximum reduction in federal income taxes
which could be obtained from deduction of such state and local
taxes and (iii) have otherwise allowable deductions for federal
income tax purposes at least equal to the Gross-up Payment.
j. All determinations required to be made under such
paragraph 4i, including whether and when a Gross-up Payment is
required, the amount of such Gross-up Payment and the assumptions
to be utilized in arriving at such determinations, shall be made
by the public accounting firm that is retained by the Company as
of the date immediately prior to the Change in Control (the
"Accounting Firm") which shall provide detailed supporting
calculations both to the Company and the Executive within fifteen
(15) business days of the receipt of notice from the Company or
the Executive that there has been a Payment, or such earlier time
as is requested by the Company (collectively, the
"Determination"). In the event that the Accounting Firm is
serving as accountant or auditor for the individual, entity or
group effecting the Change in Control, the Executive may appoint
another nationally recognized public accounting firm to make the
determinations required hereunder (which accounting firm shall
then be referred to as the Accounting Firm hereunder). All fees
and expenses of the Accounting Firm shall be borne solely by the
Company and the Company shall enter into any agreement requested
by the Accounting Firm in connection with the performance of the
services hereunder. The Gross-up Payment under subparagraph 4i
with respect to any Payments shall be made no later than thirty
(30) days following such Payment. If the Accounting Firm
determines that no Excise Tax is payable by the Executive, it
shall furnish the Executive with a written opinion to such
effect, and to the effect that failure to report the Excise Tax,
if any, on the Executive's applicable federal income tax return
will not result in the imposition of a negligence or similar
penalty. The Determination by the Accounting Firm shall be
binding upon the Company and the Executive.
As a result of the uncertainty in the application of Section
4999 of the Code at the time of the Determination, it is possible
that Gross-up Payment which will not have been made by the
Company should have been made ("Underpayment") or Gross-up
Payments are made by the Company which should not have been made
("Overpayment"), consistent with the calculations required to be
made hereunder. In the event that the Executive thereafter is
required to make payment of any Excise Tax or additional Excise
Tax, the Accounting Firm shall determine the amount of the
Underpayment that has occurred and any such Underpayment
(together with interest at the rate provided in Section 1274(b)
(2) (B) of the Code) shall be promptly paid by the Company to or
for the benefit of the Executive. In the event the amount of
Gross-up Payment exceeds the amount necessary to reimburse the
Executive for his Excise Tax, the Accounting Firm shall determine
the amount of the Overpayment that has been made and any such
Overpayment (together with interest at the rate provided in
Section 1274(b) (2) of the Code) shall be promptly paid by
Executive (to the extent he has received a refund if the
applicable Excise Tax has been paid to the Internal Revenue
Service) to or for the benefit of the Company. The Executive
shall cooperate, to the extent his expenses are reimbursed by the
Company, with any reasonable requests by the Company in
connection with any contests or disputes with the Internal
Revenue Service in connection with the Excise Tax.
k. Upon the occurrence of a Change in Control the Company
shall 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, or by the Executive 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. or its successor, 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.
l. Notwithstanding anything contained in this Section 4 to
the contrary, upon termination of the Executive's employment
after completion of eight (8) years of continuous service with
the Company (as determined pursuant to the SERP), the Executive
and his eligible dependents shall be entitled to receive medical,
prescription drug, dental and hospitalization benefits equal to
those provided by the Company to Executives on March 26, 1997 for
the remainder of the Executive's life, the cost of which shall be
paid in full by the Company (if applicable, on the same after-tax
basis to the executive as if the Executive had continued
participation in the Company's employee benefit plans providing
such benefits). If the Executive is less than age 55 at the date
of such termination of employment, the Executive shall be
entitled to receive such benefits upon attaining age 55 and prior
thereto the Executive, if applicable, shall be entitled to the
medical, prescription drug, dental and hospitalization benefits
provided by paragraphs 4f or g above.
5. Successor Liability. 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 to
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. Confidential Information. The Executive agrees to keep
secret and retain in the strictest confidence all confidential
matters which relate to the Company, its subsidiaries and
affiliates, including, without limitation, customer lists, client
lists, trade secrets, pricing policies and other business affairs
of the Company, its subsidiaries and affiliates learned by him
from the Company or any such subsidiary or affiliate or otherwise
before or after the date of this Agreement, and not to disclose
any such confidential matter to anyone outside the Company or any
of its subsidiaries or affiliates, whether during or after his
period of service with the Company, except (i) as such disclosure
may be required or appropriate in connection with his work as an
employee of the Company or (ii) when required to do so by a court
of law, by any governmental agency having supervisory authority
over the business of the Company or by any administrative or
legislative body (including a committee thereof) with apparent
jurisdiction to order him to divulge, disclose or make accessible
such information. The Executive agrees to give the Company
advance written notice of any disclosure pursuant to clause (ii)
of the preceding sentence and to cooperate with any efforts by
the Company to limit the extent of such disclosure. Upon request
by the Company, the Executive agrees to deliver promptly to the
Company upon termination of his services for the Company, or at
any time thereafter as the Company may request, all Company
subsidiary or affiliate memoranda, notes, records, reports,
manuals, drawings, designs, computer file in any media and other
documents (and all copies thereof) relating to the Company's or
any subsidiary's or affiliate's business and all property of the
Company or any subsidiary or affiliate associated therewith,
which he may then possess or have under his direct control, other
than personal notes, diaries, Rolodexes and correspondence.
7. Non-Compete and Non-Solicitation. During the
Executive's employment by the Company and for a period of
one year following the termination thereof for any reason (other
than following a Change in Control), the Executive covenants and
agrees that he will not for himself or on behalf of any other
person, partnership, company or corporation, directly or
indirectly, acquire any financial or beneficial interest in
(except as provided in the next sentence), provide consulting
services to, be employed by, or own, manage, operate or control
any business which is in competition with a business engaged in
by the Company or any of its subsidiaries or affiliates in any
state of the United States in which any of them are engaged in
business at the time of such termination of employment for as
long as they carry on a business therein. Notwithstanding the
preceding sentence, the Executive shall not be prohibited from
owning less than five (5%) percent of any publicly traded
corporation, whether or not such corporation is in competition
with the Company.
The Executive hereby covenants and agrees that, at all times
during the period of his employment and for a period of one year
immediately following the termination thereof for any reason
(other than following a Change in Control), the Executive shall
not employ or seek to employ any person employed at that time by
the Company or any of its subsidiaries, or otherwise encourage or
entice such person or entity to leave such employment.
It is the intention of the parties hereto that the
restrictions contained in this Section be enforceable to the
fullest extent permitted by applicable law. Therefore, to the
extent any court of competent jurisdiction shall determine that
any portion of the foregoing restrictions is excessive, such
provision shall not be entirely void, but rather shall be limited
or revised only to the extent necessary to make it enforceable.
Specifically, if any court of competent jurisdiction should hold
that any portion of the foregoing description is overly broad as
to one or more states of the United States, then that state or
states shall be eliminated from the territory to which the
restrictions of paragraph (a) of this Section applies and the
restrictions shall remain applicable in all other states of the
United States.
8. No Mitigation. The Executive shall not be required to
mitigate the amount of any payments or benefits provided for in
paragraph 4f or 4g hereof by seeking other employment or
otherwise and no amounts earned by the Executive shall be used to
reduce or offset the amounts payable hereunder, except as
otherwise provided in paragraph 4f or 4g.
9. Ownership of Work Product. 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,
whenever requested to do so by the Company, at its expense, shall
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) to apply for, obtain, maintain,
enforce, or defend letters patent of the United States or any
foreign country for any Work Product, or (ii) 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. Arbitration. Any dispute or controversy between the
parties relating to this Agreement (except any dispute relating
to Sections 6 or 7 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 Employment Dispute Resolution 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
Sections 6 or 7 hereof, or if the Company makes any claim under
Sections 6 or 7, 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. Notices. 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 certified mail,
postage prepaid, or overnight delivery 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:
Mr. John H. Mueller
2389 Sourwood Drive
Phoenix, NY 13135
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. Entire Agreement. This Agreement constitutes the
entire agreement between the parties hereto, and supersedes, and
is in full substitution for any and all prior understandings or
agreements, oral or written, with respect to the Executive's
employment.
13. Amendment. 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. Obligation to Provide Benefits. The company may
utilize certain financing vehicles, including a trust, to provide
a source of funding for the Company's obligations under this
Agreement. Any such financing vehicles will be subject to the
claims of the general creditors of the Company. No such
financing vehicles shall relieve the Company, or its successors,
of its obligation to provide benefits under this Agreement,
except to the extent the Executive receives payments directly
from such financing vehicle.
15. Miscellaneous. 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 without the prior written consent
of the other party. This Agreement shall be binding upon any
successor to the Company, whether by merger, consolidation,
reorganization, purchase of all or substantially all of the stock
or assets of the Company, or by operation of law.
16. Severability. 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.
17. Governing Law. This Agreement shall be governed by and
construed in accordance with the laws of the State of New York
without reference to principles of conflicts of law.
18. Counterparts. 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.
19. Performance Covenant. The Executive represents and
warrants to the Company 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.
20. Survival of Covenants. The obligations of the
Executive set forth in Sections 6, 7, 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.
_____________________________ NIAGARA MOHAWK POWER CORPORATION
John H. Mueller
By:______________________________
DAVID J. ARRINGTON
Senior Vice President -
Human Resources
SCHEDULE A
Modifications in Respect of John H. Mueller ("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 and
including any elective before-tax contributions made by the
Executive to a plan qualified under Section 401(k) of the
Internal Revenue Code, averaged over the final 36 months of the
Executive's employment with the Company and (ii) the average of
the annual bonus earned by the Executive under the Corporation's
Annual Officers Incentive Compensation Plan ("OICP"), 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 (i.e., 60% of
Earnings (as modified above) without reduction for an Early
Commencement Factor) 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 without reduction for an Early Commencement Factor.
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 termination of this Agreement on account of
the Executive's Disability or (z) the Executive's termination of
employment for Good Reason within the 36 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) without
reduction for an Early Commencement Factor) 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 without reduction for an Early Commencement
Factor.
IV. Except as provided above, the provisions of the SERP shall
apply and control participation therein and the payment of
benefits thereunder.
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 Sections 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 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)
- ----------------------- --------- ----------- ---------- -----------------
1997
----
January 1 - December 31 144,365,214 365 52,693,303,110
Shares issued at various
times during the period -
Acquisition - Syracuse
Suburban Gas Company,
Inc. 54,137 * 14,260,096
----------- --------------
144,419,351 52,707,563,206 144,404,283
=========== ============== ===========
1996
----
January 1 - December 31 144,332,123 366 52,825,557,018
Shares issued at various
times during the year -
Acquisition - Syracuse
Suburban Gas Company,
Inc. 33,091 * 6,397,653
----------- --------------
144,365,214 52,831,954,671 144,349,603
=========== ============== ===========
1995
----
January 1 - December 31 144,311,466 365 52,673,685,090
Shares issued -
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
=========== ============== ===========
* Number of days outstanding not shown as shares represent an accumulation of weekly,
monthly and quarterly issues throughout the year. Share days for shares issued are
based on the total number of days each share was outstanding during the year.
Note: Earnings per share calculated on both a basic and 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,
------------------------------------------------------------
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
A. Net Income per Statements
of Income $ 59,835 $110,390 $248,036 $176,984 $271,831
B. Taxes Based on Income or
Profits 60,095 66,221 159,393 111,469 147,075
-------- -------- -------- -------- --------
C. Earnings, Before Income
Taxes 119,930 176,611 407,429 288,453 418,906
D. Fixed Charges (a) 304,451 308,323 314,973 315,274 319,197
-------- -------- -------- -------- --------
E. Earnings Before Income
Taxes and Fixed Charges 424,381 484,934 722,402 603,727 738,103
F. Allowance for Funds Used
During Construction 9,706 7,355 9,050 9,079 16,232
-------- -------- -------- ------- -------
G. Earnings Before Income
Taxes and Fixed Charges
without AFC $414,675 $477,579 $713,352 $594,648 $721,871
======== ======== ======== ======== ========
Preferred Dividend Factor:
H. Preferred Dividend
Requirements $ 37,397 $ 38,281 $ 39,596 $ 33,673 $ 31,857
-------- -------- -------- --------- --------
I. Ratio of Pre-Tax Income
to Net Income (C / A) 2.00 1.60 1.64 1.63 1.54
-------- --------- --------- --------- ---------
J. Preferred Dividend Factor
(H x I) $ 74,794 $ 61,250 $ 64,937 $ 54,887 $ 49,060
K. Fixed Charges as above (D) 304,451 308,323 314,973 315,274 319,197
-------- -------- -------- -------- --------
L. Fixed Charges and Preferred
Dividends Combined $379,245 $369,573 $379,910 $370,161 $368,257
======== ======== ======== ======== ========
M. Ratio of Earnings to
Fixed Charges (E / D) 1.39 1.57 2.29 1.91 2.31
-------- -------- -------- -------- --------
N. Ratio of Earnings to Fixed
Charges without AFC (G / D) 1.36 1.55 2.26 1.89 2.26
-------- -------- -------- -------- --------
O. Ratio of Earnings to Fixed
Charges and Preferred
Dividends Combined (E / L) 1.12 1.31 1.90 1.63 2.00
-------- ------- -------- -------- --------
(a) Includes a portion of rentals deemed representative of the interest factor: $26,149 for
1997, $26,600 for 1996, $27,312 for 1995, $29,396 for 1994 and $27,821 for 1993.
/TABLE
EXHIBIT 21
- ----------
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SUBSIDIARIES OF THE REGISTRANT
Name of Company State of Organization
--------------- ---------------------
Opinac North America, Inc. Delaware
(Note 1)
NM Uranium, Inc. Texas
EMCO-TECH, Inc. (Note 2) New York
NM Holdings, Inc. (Note 3) New York
Moreau Manufacturing Corporation New York
Beebee Island Corporation New York
NM Receivables Corp. New York
NOTE 1: At December 31, 1997, Opinac North America, Inc. owns
Opinac Energy Corporation and Plum Street Enterprises,
Inc. Opinac Energy Corporation has a 50 percent interest
in CNP, which is incorporated in the Province of Ontario,
Canada. CNP owns Cowley Ridge Partnership (an Alberta,
Canada general partnership) and Canadian Niagara Wind
Power Company, Inc. (incorporated in the Province of
Alberta, Canada). Plum Street Enterprises, Inc., ("Plum
Street") an unregulated company, is incorporated in the
State of Delaware. Plum Street owns Plum Street Energy
Marketing, Inc. (incorporated in the State of Delaware),
Global Energy Enterprises India Private Limited, 90% of
Dolphin Investments International, Inc. (a corporation
organized and existing under the laws of Nevis, West
Indies, which owns 45% of Atlantis Energie Systems AG (a
corporation organized and existing under the laws of the
Federal Republic of Germany)), 25% of Telergy Joint
Venture and 26% of Direct Global Power, Inc.
NOTE 2: EMCO-TECH, Inc. is inactive at December 31, 1997.
NOTE 3: At December 31, 1997, NM Holdings, Inc. owns Salmon
Shores, Inc., Moreau Park, Inc., Riverview, Inc., Hudson
Pointe, Inc., Upper Hudson Development, Inc., Land
Management & Development, Inc., OPropco, Inc. and
LandWest, Inc.
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, 33-42771 and
333-13781) and to the incorporation by reference in the Prospectus
constituting part of the Registration Statement on Form S-3 (Nos.
33-50703, 33-51073, 33-54827 and 33-55546) of Niagara Mohawk Power
Corporation of our report dated March 26, 1998 appearing in the
Company's Form 10-K dated March 26, 1998. 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 26, 1998
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 26, 1998 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 26, 1998
- --------------------
William F. Allyn
/s/ Albert J. Budney, Jr. Director,
- ------------------------- President
Albert J. Budney, Jr. March 26, 1998
/s/ Lawrence Burkhardt, III Director March 26, 1998
- ---------------------------
Lawrence Burkhardt, III
/s/ Douglas M. Costle Director March 26, 1998
- ---------------------
Douglas M. Costle
Signature Title Date
- --------- ----- ----
/s/ Edmund M. Davis Director March 26, 1998
- -------------------
Edmund M. Davis
Chairman of the
Board of Directors
and Chief Executive
/s/ William E. Davis Officer March 26, 1998
- --------------------
William E. Davis
/s/ William J. Donlon Director March 26, 1998
- ---------------------
William J. Donlon
/s/ Anthony H. Gioia Director March 26, 1998
- --------------------
Anthony H. Gioia
/s/ Bonnie Guiton Hill Director March 26, 1998
- ----------------------
Bonnie Guiton Hill
/s/ Henry A. Panasci, Jr. Director March 26, 1998
- -------------------------
Henry A. Panasci, Jr.
/s/ Patti McGill Peterson Director March 26, 1998
- -------------------------
Patti McGill Peterson
/s/ Donald B. Riefler Director March 26, 1998
- ---------------------
Donald B. Riefler
/s/ Stephen B. Schwartz Director March 26, 1998
- -----------------------
Stephen B. Schwartz
Signature Title Date
- --------- ----- ----
Senior Vice President
and Chief Financial
/s/ William F. Edwards Officer March 26, 1998
- ----------------------
William F. Edwards
Vice President-Controller
and Principal Account-
/s/ Steven W. Tasker ing Officer March 26, 1998
- --------------------
Steven W. Tasker