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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________ to __________
COMMISSION FILE NUMBER: 1-2987
NIAGARA MOHAWK POWER CORPORATION
(Exact name of registrant as specified in its charter)
STATE OF NEW YORK 15-0265555
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
300 ERIE BOULEVARD WEST SYRACUSE, NEW YORK 13202
(Address of principal executive offices) (Zip Code)
(315) 474-1511
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
(Each class is registered on the New York Stock Exchange)
Title of each class
Common Stock ($1 par value)
---------------------------
Preferred Stock ($100 par Preferred Stock ($25 par
value-cumulative): value-cumulative):
- ------------------------- ------------------------
3.40% Series 4.10% Series 6.10% Series 9.50% Series
3.60% Series 4.85% Series 7.72% Series Adjustable Rate Series A &
3.90% Series 5.25% Series Series C
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. YES [ X ] NO [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K [ X ]
State the aggregate market value of the voting stock held by non-affiliates of
the registrant.
APPROXIMATELY $2,800,000,000 AT MARCH 1, 1999.
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 1, 1999 - 187,364,863
NIAGARA MOHAWK POWER CORPORATION
INFORMATION REQUIRED IN FORM 10-K
INDEX
- -----
PART I
------
Glossary of Terms
Item 1. Business
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Submission of Matters to a Vote of Security Holders
Executive Officers of the Registrant
PART II
-------
Item 5. Market for the Registrant's Common Equity and Related
Stockholders Matters
Item 6. Selected Consolidated Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
PART III
--------
Item 10. Directors and Executive Officers of the Registrant
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners
and Management
Item 13. Certain Relationships and Related Transactions
PART IV
-------
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
Signatures
NIAGARA MOHAWK POWER CORPORATION
GLOSSARY OF TERMS
-----------------
TERM DEFINITION
- ---- ----------
AFC Allowance for Funds Used During Construction
CNG CNG Transmission Corporation, an interstate natural gas pipeline
regulated by FERC
CNP Canadian Niagara Power Company, Limited
COPS Competitive Opportunities Proceeding
CTC Competitive transition charges: a mechanism established in the
POWERCHOICE agreement to recover stranded costs from customers
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, Amortization of Nuclear Fuel,
Allowance for Funds Used During Construction, MRA Regulatory
Asset amortization, non-cash regulatory deferrals and other
amortizations and extraordinary items (a non-GAAP measure of
cash flow)
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 Independent Power Producers that were a party to the MRA
Party
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
MRA Master Restructuring Agreement - an agreement, including amendments
thereto, which terminated, restated or amended certain IPP Party
power purchase agreements effective June 30, 1998
MRA Recoverable costs to terminate, restate or amend IPP Party
regulatory contracts, which have been deferred and are being amortized and
asset recovered under the POWERCHOICE agreement
MW Megawatt: one million watts
MWh Megawatt-hour: one thousand kilowatt-hours
Net Cash Reflects interest charges plus allowance for funds used during
Interest construction less the non-cash impact of the net amortization of
discount on long-term debt and interest accrued on the Nuclear
Waste Policy Act disposal liability less interest income
NRC U. S. Nuclear Regulatory Commission
NYISO New York Independent System Operator
NYPA New York Power Authority
NYPP New York Power Pool
NYPP Eight Member Systems are: the seven New York
Member State investor-owned electric utilities and NYPA
Systems
NYSERDA New York State Energy Research and Development Authority
POWERCHOICE Company's five-year electric rate agreement, which incorporates
Agreement the MRA, approved by the PSC in an order dated March 20, 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 Stockholders 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"
Stranded Utility costs that may become unrecoverable due to a change in
Costs 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 1
------
ITEM 1. BUSINESS
Niagara Mohawk Power Corporation (the "Company"), organized in 1937 under the
laws of New York State, is engaged principally in the regulated 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. Segment
Information."
The regulated business described above is the Company's primary business
segment. All other businesses of the Company are non-regulated and at this time
are not considered to be material to the Company's results of operations and
financial condition. For purposes of this report, all discussion relates to the
regulated electric and gas business unless otherwise noted.
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 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 past electricity and gas prices reflected
traditional utility regulation. As such, the Company's electricity prices have
included both state-mandated purchased power costs from IPPs, at costs far
exceeding the Company's actual avoided costs, and 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 prices, rapid technological advances
have significantly reduced the price of new generation and significantly
improved the performance of smaller scale generating units. 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.
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.
In 1998, the Company finalized these agreements and believes they will
significantly improve its financial outlook. Pursuant to the Company's
POWERCHOICE agreement, approved by the PSC, which regulates utilities in the
state of New York, the Company agreed to a five year rate plan and agreed to
divest its fossil and hydro generating assets, representing 4,217 MW of capacity
and approximately $1.1 billion of net book value. The Company has entered into
contract to sell its 72 hydro generating stations and its two coal-fired
generating stations (Huntley and Dunkirk). The Company is continuing its
efforts to pursue the sale of its two oil and gas fired plants in Albany and
Oswego. In January 1999, the Company announced plans to pursue the sale of its
nuclear assets.
As part of the MRA, the Company terminated 18 PPAs for 1,092 MW, restated 8 PPAs
for 535 MW and amended one PPA for 42 MW in exchange for cash and shares of
Company common stock. Management believes that the MRA and the POWERCHOICE
agreement provide the Company with financial stability and create an improved
platform from which to build value. The primary objective of the MRA was to
convert a large and growing off-balance sheet payment obligation that threatened
the financial viability of the Company into a fixed and manageable capital
obligation. Accordingly, the Company believes that the lower contractual
obligations resulting from the MRA will significantly improve cash flow which
can be dedicated to reduce indebtedness incurred to fund the MRA. With the
POWERCHOICE agreement, the Company has lowered prices for its industrial,
commercial and residential electric customers for a period of three years and
provides reasonable certainty of prices for the years thereafter. The
POWERCHOICE agreement and the MRA also facilitate the creation of a
competitive electricity supply market in the Company's service territory.
In the near term, the Company believes the greatest opportunity for improving
the cash flow and financial condition of the Company will come from paying down
debt. The Company will continue to emphasize operational excellence and seek to
improve margins through cost reductions. In addition, the Company intends to
pursue low risk unregulated business opportunities through its unregulated
subsidiaries. Pursuant to the POWERCHOICE agreement, the Company was authorized
to form a holding company that would enhance the Company's ability to explore
unregulated business opportunities to foster longer term strategic growth.
The Company has obtained approval from its shareholders and several regulatory
agencies for the formation of a holding company. The implementation of a
holding company will occur following the receipt of one final regulatory
approval. See Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters - "Formation of Holding Company".
For a discussion of events that occurred during 1998 in the competitive
environment, federal and state regulatory initiatives and the Company's efforts
to address its competitive disadvantages and financial condition, see Part II,
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
The following topics are discussed under the general heading of "Business."
Where applicable, the discussions make reference to the various other items of
this Form 10-K.
TOPIC
- -----
Regulation and Rates
IPPs
New York Power Authority
Other Purchased Power
Fuel for Electric Generation
Nuclear Operations
Electric Supply Planning
Electric Delivery Planning
Gas Delivery
Gas Supply
Financial Information About Segments
Environmental Matters
Research and Development
Construction Program
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 shape 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," "Future of the Natural Gas Industry," "NRC Policy
Statement and Amended Decommissioning Funding Regulations," "PSC Staff's
Tentative Conclusions on the Future of Nuclear Generation," and "NRC and Nuclear
Operating Matters" for a discussion of these 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 FUTURE OF THE NATURAL GAS BUSINESS.
For a discussion of the three-year gas rate settlement agreement that was
conditionally approved by the PSC in December 1996 and the PSC's efforts to
restructure the gas industry, 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 "-
"Future of the Natural Gas Business."
PRICE DISCOUNTS. For a discussion of price discounts offered to customers, 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."
IPPS
----
In 1998, the Company purchased 9,668,000 MWh or about 25% of its total power
supply from IPPs, which is a 29% reduction from 1997. 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" and Note 10. "Fair Value
of Financial and Derivative Financial Instruments."
NEW YORK POWER AUTHORITY
------------------------
The Company presently has contracts to purchase electricity from a number of
generating facilities owned by the NYPA. In 1998, these purchases amounted to
7,483,000 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
hydropower 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,
1999.
OTHER PURCHASED POWER
---------------------
Power purchased in 1998 from sources other than IPPs and NYPA amounted to
1,155,000 MWh, representing approximately 3% of the Company's total power
supply requirements. Power purchases from other sources should increase in
future years as a result of the MRA and the Company's sale of its generation
facilities. 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 has eliminated the Company's FAC, which in the past
has provided for partial pass-through to customers of fuel and purchased power
cost fluctuations from amounts forecast. The Company expects to complete the
sale of its coal-fired and hydro generating assets in 1999. The Company
continues to pursue the sale of its two oil and gas fired generating 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."
COAL. The C. R. Huntley and Dunkirk Steam Stations, the Company's only
coal-fired generating stations purchased their 1998 coal requirements under
short-term contracts. Similar supply arrangements are in place for 1999. The
average level of coal supply was 30 days, which is managed for supply risk.
The annual average cost of coal burned was as follows:
Cost 1998 1997 1996
- --------------- ------ ------ ------
per million BTU $ 1.46 $ 1.41 $ 1.39
per ton . . . . 38.16 36.68 36.00
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 1996, 1997 and 1998, natural gas was the predominant fuel
used. Generation at this station has been curtailed significantly during this
period because of the requirement to purchase IPP power and excess capacity in
the region. However, since the completion of the MRA, there has been a
significant increase in the use of Albany Steam Station. The Oswego Steam
Station, primarily fueled by residual oil, has limited capability for using
natural gas for electric generation.
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 1998, approximately 1.0
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, was as follows:
Cost 1998 1997 1996
- --------------- ----- ----- -----
per million BTU $2.35 $2.50 $1.96
per Dth . . . . 2.35 2.50 1.96
RESIDUAL OIL. The Company's total requirements for residual oil in 1999 for
its Albany and Oswego Steam Stations are estimated at approximately 2.0 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 returned to service in June 1998 after being placed on
long-term cold standby in March 1994. All oil requirements are met on the spot
market. At December 31, 1998, there were approximately 1.3 million barrels of
oil, or more than a 54-day supply, at the Oswego Steam Station and approximately
0.49 million barrels of oil, or a 45-day supply, at the Albany Steam Station,
based on recent burn projections.
The average price of oil for Oswego at December 31, 1998 was $19.00 per barrel
and $18.25 per barrel for 0.7% sulfur residual oil and 1.5% sulfur residual oil,
respectively. The price of 1.5% sulfur residual oil for Albany at December 1,
1998 was $14.25 per barrel. The fuel oil prices quoted include the $3.05 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. All oil requirements are met on the spot
market.
The annual average cost of residual oil burned at the Albany, Oswego and
Roseton Steam Stations was as follows:
Cost 1998 1997 1996
- --------------- ------ ------ ------
per million BTU $ 3.09 $ 4.05 $ 3.81
per barrel. . . 19.45 25.58 24.15
NUCLEAR. The supply of fuel for the Company's Nine Mile Point nuclear
generating plants involves: (1) the procurement of uranium concentrates, (2) the
conversion of uranium concentrates to uranium hexafluoride, (3) the enrichment
of the uranium hexafluoride, (4) the fabrication of fuel assemblies and (5) the
disposal of spent fuel and radioactive wastes. Agreements for nuclear fuel
materials and services for Unit 1 and Unit 2 (in which the Company has a 41%
interest) have been made through the following years:
Unit No. 1 Unit No. 2
---------- ----------
Uranium Concentrates 2002 2002
Conversion . . . . . 2002 2002
Enrichment . . . . . 2003 2003
Fabrication. . . . . 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 90% and 85% 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 and Unit 2 was as follows:
Cost per million BTU 1998 1997 1996
- -------------------- ----- ----- -----
Unit 1 . . . . . . . $0.51 $0.54 $0.60
Unit 2 . . . . . . . 0.45 0.49 0.50
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 treatment of its nuclear
assets under POWERCHOICE, see Item 7. - Management's Discussion and Analysis of
Financial Condition and Results of Operations - "Master Restructuring Agreement
and the POWERCHOICE Agreement."
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."
ELECTRIC SUPPLY PLANNING
------------------------
Under the POWERCHOICE agreement, the PSC approved the Company's plan to divest
its hydro and fossil generating plants, which is a key component in the
Company's POWERCHOICE agreement to lower average electricity prices and provide
customer choice. In addition, the Company is pursuing the sale of its nuclear
generating assets. As a result, the Company will now purchase power through
various contracts or when necessary from the spot market. For a discussion of
the results of the sale and discussion of power contracts, see Part II, Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations - "Master Restructuring Agreement and the POWERCHOICE Agreement,"
"FERC Rulemaking on Open Access and Stranded Cost Recovery," and Item 8.
Financial Statements and Supplementary Data - Note 9. "Commitments and
Contingencies" and Note 10. "Fair Value of Financial and Derivative Financial
Instruments."
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 to how the Company's transmission system will be
managed under the ISO.
As of January 1, 1999, 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 maintain the reliability of electric service while
minimizing 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
7. Management's Discussion and Analysis of Financial Condition and Results of
Operation - "1998 Storms." The Company continually reviews the adequacy of its
electric delivery facilities and establishes capital requirements to support new
load growth.
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 is for residential and commercial space
and water heating. Consequently, the demand for natural gas by the Company's
customers is seasonal and influenced by weather factors. The Company purchases
its natural gas for sale to its customers under firm and spot contracts, which
is transported on both firm and interruptible transportation contracts. During
1998, about 93% and 7% of the Company's natural gas supply was purchased under
firm contracts and spot contracts, respectively. The spot contracts are
generally for commitments less 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 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. Segment Information."
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 1998 totaled
approximately $35.1 million, of which approximately $2.1 million was capitalized
as pollution control or plant environmental surveillance equipment and
approximately $33.0 million was charged to operating expense for remediation,
operation of environmental monitoring and waste disposal programs. Expenditures
for 1999 are estimated to total $39.9 million, of which $6.1 million is expected
to be capitalized and $33.8 million charged to operating expense. Anticipated
expenditures for 2000 are estimated to total $31.4 million, of which $1.0
million is expected to be capitalized and $30.4 million charged to operating
expense. The expenditures for 1999 and 2000 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, but
exclude costs for the fossil and hydro generating plants. Costs for site
investigation and remediation are included in operating expense to the extent
actual costs exceed the amount provided for in rates, in which case, the excess
costs are deferred for future recovery through cost-of-service based rates.
The Company believes 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."
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 were 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.
As part of the POWERCHOICE agreement, the Company is selling its fossil and
hydro generating assets. Sales have been announced for the hydro and coal-fired
assets (Huntley and Dunkirk Steam Stations), and the Company is pursuing the
sale of its oil and gas fired assets as well as its nuclear assets. With the
sale of these assets, the Company will no longer be responsible for meeting the
related environmental requirements. The following discussion of air, water and
solid waste matters presents the Company's plans for addressing environmental
requirements in the unlikely event the Company were to retain ownership of the
assets.
AIR. The Company is required to comply with applicable federal and state air
quality requirements pertaining to emissions into the atmosphere from its
fossil-fired 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 by reducing the 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 owners of the fossil plants to
further reduce SO2 emissions at all of the 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. Appropriate deployment of these options will be
determined by the new owners.
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 has proposed
regulations governing the Phase II NOx reduction program in New York State,
which will be implemented beginning May 1, 1999. The need for and extent of any
further reductions needed in Phase III is the focus of Phase III working group
meetings currently being conducted by the DEC. However, this should not have an
impact on the Company as a result of the pending sale of its fossil generation
stations.
The Company spent approximately $0.1 million in capital expenditures in each of
the years 1996 and 1997, on projects at the fossil generation plants associated
with Phase I compliance. The Company has included $0.6 million in its 1999
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 pursue compliance with such requirements. In
general, 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 conducting a program to investigate and remediate, as
necessary to meet current environmental standards, certain properties associated
with former gas manufacturing and other properties which the Company has learned
may be contaminated with industrial waste. The Company is also 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 136 sites with which it has been or may be
associated, including 82 which are Company-owned. 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. The Company has denied any responsibility at
certain of the PRP sites and is contesting liability accordingly.
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 past-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 cleanup
obligations are joint and several.
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 for these owned sites, representing its best current estimate for
its share of the costs for investigation and remediation. The potential high
end of the range is presently estimated at approximately $710 million, including
approximately $340 million in the unlikely event the Company is required to
assume 100 percent responsibility at non-owned sites. The amount accrued at
December 31, 1998, incorporates a method to estimate the liability for 22 of the
Company's largest sites, which relies upon a decision analysis approach. This
method includes developing several remediation approaches for each of the 22
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 share of a PRP
allocation or, where no better estimate is available, the low end of a range of
possible outcomes is used. 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 $21 million and a high end of $360
million, with an expected value calculation of $56 million, which is included in
the total amounts accrued at December 31, 1998. The range represents the total
costs to remediate the properties and does not consider contributions from other
PRPs, the amount of which the Company is unable to estimate. The Company has
received comments from the DEC on the draft feasibility study, which will
facilitate completion of the feasibility study phase in 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 the DEC 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. The New York State Attorney General moved to dismiss the
Company's claims against the state of New York, the New York State Department of
Transportation and the Thruway Authority and Canal Corporation under the
Comprehensive Environmental Response, Compensation and Liability Act. The
Company opposed this motion. On April 3, 1998, the Court denied the New York
State Attorney General's motion as it pertains to the Thruway Authority and
Canal Corporation, and granted the motion relative to the state of New York and
the Department of Transportation. On January 12, 1999, a pre-trial status
conference was convened by the Court. The Court will be issuing an amended case
management order that is expected to call for the close of discovery by the end
of June 1999 and to establish December 1, 1999 as the trial ready date. As a
result, the Company cannot predict the outcome of the pending litigation against
the defendants 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 $75
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 $340 million, but
it is unlikely that the Company will be 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. Ten of the
PRP sites are included on the National Priorities List ("NPL"). The Company
estimates that 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 cleanup and then applying a
Company contribution factor to that estimate where appropriate. Estimates of
the total cleanup 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 cleanup obligations are joint and several.
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), and which
provides 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 during 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
manufactured gas plant, industrial waste sites and sites for which the Company
has been identified as a PRP. The Company has reached settlements with a number
of insurance carriers, resulting in payments to the Company of approximately $39
million, net of costs incurred in pursuing recoveries. This amount is being
amortized in rates generally over a 10-year period.
For a discussion of 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 the
Company's customers with new electric and gas technologies. R&D expenditures
in 1996 through 1998 were not material to the Company's results of operations
or financial condition.
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."
INSURANCE
---------
As of January 31, 1999, the Company's directors and officers liability insurance
was renewed. This coverage includes nuclear operations and insures the
directors and officers against obligations incurred as a result of their
indemnification by the Company. The coverage also insures the directors and
officers against liabilities for which they may not be indemnified by the
Company, except for a dishonest act or breach of trust. In addition, the policy
covers all of the Company's subsidiaries. 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, 1998 numbered approximately 8,400, of
whom approximately 69% were union members. It is estimated that approximately
80% of the Company's total labor costs is applicable to operation and
maintenance and approximately 20% is 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.
The Company has reached agreements to sell its 72 hydro generation stations and
its two coal-fired generating stations, which employ approximately 550
individuals. In addition, the Company is pursuing the sale of its two oil and
gas-fired stations, which employ approximately 150 individuals. The Company
has also announced its intent to pursue a sale of its nuclear assets, which
employ approximately 1,300 individuals.
SEASONALITY
-----------
See Item 2. Properties - "Electric Service" and Part II, Item 8. Financial
Statements and Supplementary Data - "Note 13. Quarterly Financial Data
(Unaudited)."
ITEM 2. PROPERTIES
ELECTRIC SERVICE
----------------
As of December 31, 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, and 72 hydroelectric plants, and had a
majority interest in Beebee Island and Feeder Dam hydro plants and their output.
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 ongoing sale of the Company's
generation assets. 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 Niagara Mohawk
Energy, 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. Several of these licenses have been
involved in re-licensing since the early 1990's and are expected to take
several more years to conclude. As of December 31, 1998, the Company has
renewed 3 hydro licenses and has 12 license renewals pending. The hydro
licenses and the pending license applications will be transferred to the new
owner of the hydro assets, who will be required to comply with current
conditions and negotiated agreements in place at the time of closing.
The following is a list of the Company's major operating generating stations at
December 31, 1998, all of which are for sale:
Company's
Share of
Nominal Net
Percent Capability
Station Location Ownership Energy Source in MW
- -------------------------- ------------- --------- ---------------- -----------
Huntley. . . . . . . . . Niagara River 100% Coal 760
Dunkirk. . . . . . . . . Lake Erie 100% Coal 600
Albany . . . . . . . . . Hudson River 100% Oil/Natural Gas 400
* Oswego (Unit 5) . . . . Lake Ontario 100% Oil 850
Oswego (Unit 6). . . . . Lake Ontario 76% Oil/Natural Gas 646
Roseton. . . . . . . . . Hudson River 25% Oil/Natural Gas 300
Nine Mile Point (Unit 1) Lake Ontario 100% Nuclear 613
Nine Mile Point (Unit 2) Lake Ontario 41% Nuclear 469
* Oswego Unit 5 was returned to service in June 1998 after being put into
long-term cold standby in 1994.
On November 30, 1998, the Company filed an application with the New York State
Board on Electric Generation Siting and the Environment 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 to
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 14 months and be
transferable to a new owner of the facility under the fossil asset sale.
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, 1998, 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 1998, the Company's
maximum hourly demand occurred in the summer. Historically, the Company's
maximum hourly demand has 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, 1998
occurred on July 16, 1998 and was 5,928 KWh. For a summary of the Company's
electric supply capability at December 31, 1998, see Part II, Item 8. Financial
Statements and Supplementary Data -"Electric and Gas Statistics."
LAND CLAIMS
-----------
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 opened discussions
alleging the invalidity of the right-of-way agreements for these transmission
lines. While discussions between the Nation and the Company were suspended in
mid-1992, in 1997, the Nation asked the Company to reopen the discussions. On
September 30, 1998, the Nation filed, in the U.S. District Court for the Western
District of New York, a civil action to eject the Company from the Nation's land
and is also seeking financial relief from the Company. The Company is unable to
predict the outcome of this matter.
The Company has also held discussions with other Native American nations and was
involved in legal proceedings regarding the PSC's jurisdiction over their
territories, the Company's right to provide service to individuals located
within these territories, the validity of franchise agreements within their
territories, and the Company's right to collect stranded costs. The potential
outcome of these discussions could lead to, but is not limited to, more
formalized litigation proceedings. The Company intends to continue these
discussions and defend its position, but is unable to predict the timing or
outcome of these matters.
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 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, 1998, the Company's natural gas system was comprised
of approximately 9,100 miles of pipelines and mains, only a part of which is
located on property owned by the Company.
SUBSIDIARIES
------------
The Company's subsidiaries are as follows:
1. Opinac North America, Inc. - owns:
a. Opinac Energy Corporation - a Canadian corporation which has portfolio
investments and owns a 50 percent interest in CNP. CNP is an electric
company, 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
through subsidiary companies, owns and operates a wind power facility
in the province of Alberta, Canada.
b. Niagara Mohawk Energy, Inc. - was incorporated in the state of Delaware
and is an unregulated company that offers energy-related services.
2. 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.
3. NM Properties, Inc. (formerly NM Holdings, Inc.) - engages in real estate
development of property formally owned by the Company.
4. NM Receivables - facilitates the sale of an undivided interest in a
designated pool of customer receivables, including accrued unbilled
revenues. NM Receivables LLC is owned by the Company (over 99.99%)
and by NM Receivables Corp. II, which is a wholly owned subsidiary
of the Company.
5. Moreau Manufacturing Corporation - the Company owns a 66.67% interest in
a New York State subsidiary that owns and operates a hydroelectric
generating station. The Company has included its interest in Moreau
in its hydro generating asset sale.
6. Beebee Island Corporation - the Company owns 82.84% interest in a New
York State subsidiary that owns and operates a hydroelectric generating
station. The Company has included its interest in Beebee Island in its
hydro generating asset sale.
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 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," Item 2.
Properties - "Land Claims," 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
addition, consistent with POWERCHOICE and its gas settlement agreement, 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 property damage
and/or physical injury. The plaintiffs seek compensatory and punitive
damages so far totaling 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 remedial cost 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 February 4, 1994, the Company notified NorCon Partners, LP (NorCon) of
the Company's demand for adequate assurance that NorCon would perform all of
their future repayment obligations as required by agreement.
On March 7, 1994, 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 26, 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 New York 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 New York
Court of Appeals. A motion to stay further proceedings was made since this
contract was included in the MRA.
NorCon subsequently dropped out of the MRA and arguments were held on
October 22, 1998 in the New York Court of Appeals at the request of the
Company. On December 1, 1998, the New York Court of Appeals ruled in favor
of the Company's right to demand adequate assurance of future performance
on an electric contract. Resolution of the remaining issues will be
determined in the U.S. District Court for the Southern District of New York.
The Company is unable to predict the timing and outcome of this matter.
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
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.
During July 1998, Fourth Branch commenced a condemnation proceeding in
Federal District Court to obtain title to the project property and also has
made a unilateral offer of settlement before FERC. The Company has served
an answer with various affirmative defenses. On July 30, 1998, Fourth
Branch moved for Summary Judgment. The Company opposed Fourth Branch's
motion and cross-moved for summary judgment in favor of the Company.
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 and perfected the appeal in
October 1998. The appeal was argued before the Appellate Division, Third
Department, on January 15, 1999. The Company is unable to predict the
outcome of this matter.
5. The DEC, in response to an EPA audit of their enforcement policies,
which found enforcement of air regulation violations to be insufficient,
began an initiative to address this issue in 1997. As a result, the DEC
began to pursue consent orders from all New York utilities for past opacity
variances for the years 1994, 1995 and 1996. The consent order also
includes various opacity reduction measures and stipulated penalties for
future excursions after execution of a consent order. The Company is in
the process of negotiating a mutually agreeable consent order. Based upon
current negotiations of the consent order, the Company believes that the
penalties for past opacity variances would be immaterial to the Company's
results of operations. In addition, the stipulated penalties for future
excursions will be reduced subject to the Company's sale of its fossil
generation assets. The outcome of this matter is uncertain at this time.
6. In July 1998, the Public Utility Law Project of New York, Inc. (PULP)
and others sought a declaratory judgment, declaring the Company's
POWERCHOICE agreement unlawful, null and void and injunctive relief in the
Supreme Court of the state of New York, Albany County against the PSC and
the Company to enjoin the defendants to halt all their actions and
expenditures to implement the rules for the provision of retail energy
services contained in the POWERCHOICE agreement. The PSC and the Company
have filed a motion seeking to dismiss this action. The motion is pending
in Albany County Supreme Court. The Company is unable to predict the
outcome of this matter.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth
quarter of 1998.
EXECUTIVE OFFCERS OF REGISTRANT
-------------------------------
All executive officers of the Company are elected on an annual basis at the
Organizational 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 12-31-1998 Current and Prior Positions Date Commenced
- --------- ---------- --------------------------- --------------
William E. Davis . . . . .56 Chairman of the Board and Chief Executive Officer May 1993
Albert J. Budney Jr.. . 51 President April 1995
Corporate Managing Vice President - UtiliCorp Power Prior to joining
Services Group (a Unit of UtiliCorp United, Inc.) the Company
President-Missouri Public Service (Operating January 1993
Division of UtiliCorp United, Inc.)
Darlene D. Kerr. .. . . 47 Executive Vice President - Energy Delivery September 1998
Senior Vice President - Energy Distribution December 1995
Senior Vice President - Electric Customer Service January 1994
Vice President - Electric Customer Service July 1993
B. Ralph Sylvia. . .. .. 58 Retired July 1998
Executive Vice President January 1998
Executive Vice President - Electric Generation December 1995
and Chief Nuclear Officer
Executive Vice President - Nuclear November 1990
David J. Arrington . . 47 Senior Vice President - Human Resources December 1990
Thomas H. Baron. . .. . 54 Senior Vice President - Field Operations October 1998
Vice President - Fossil/Hydro Generation and April 1998
and Environmental Affairs
Vice President - Fossil & Hydro Generation May 1991
Edward J. Dienst . .. . 43 Senior Vice President - Customer Delivery & Asset Management October 1998
Vice President Electric Delivery May 1996
Vice President Regional Operations April 1994
General Manager - Northeast Region April 1991
William F. Edwards . . . 41 Senior Vice President and Chief Financial Officer September 1997
Vice President of Financial Planning December 1995
Executive Assistant of the Chief Executive Officer July 1993
and President
Gary J. Lavine . . . .. 48 Senior Vice President - Legal & Corporate Relations October 1990
John H. Mueller. . .. . 52 Senior Vice President and Chief Nuclear Officer January 1998
Site Vice President of Commonwealth Edison's August 1996
Zion Plant
Vice President of Nuclear Energy (for Nebraska July 1994
Public Power District, owner and operator of the
Cooper nuclear plant)
Plant Manager - Unit 2 August 1993
Theresa A. Flaim . .. . 49 Vice President - Corporate Strategic Planning May 1994
Vice President - Corporate Planning April 1993
Kapua A. Rice. . . .. . 47 Corporate Secretary September 1994
Assistant Secretary October 1992
Steven W. Tasker . . . 41 Vice President - Controller December 1993
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. During the second quarter of 1998, the Company consummated the MRA
agreement. As part of the MRA agreement, the Company made a significant payment
to the IPP Parties that resulted in a substantial tax net operating loss. (See
Part II, Item 7. Management's Discussion and Analysis of Financial Condition
and Results on Operations - "Master Restructuring Agreement and the POWERCHOICE
Agreement," and "Financial Position, Liquidity and Capital Resources"). As a
result of this tax net operating loss, dividends paid in the second, third and
fourth quarters of 1998 will constitute a return of capital and only the first
quarter dividends are taxable as ordinary income.
The table below shows quoted market prices (NYSE) for the Company's common
stock:
1998 1997
-------- ---------
HIGH LOW High Low
--------- -------- --------- --------
1st Quarter $13 9/16 $ 10 1/8 $ 11 1/8 $ 8 1/8
2nd Quarter 15 1/4 11 9 7 7/8
3rd Quarter 16 3/8 14 3/4 10 1/16 8 1/4
4th Quarter 16 1/2 13 15/16 10 9/16 9 1/16
For a discussion regarding the common stock dividend, see Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations -
"Financial Position, Liquidity and Capital Resources - Common Stock Dividend"
below.
OTHER COMPANY 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.
At the Company's annual meeting on June 29, 1998, the shareholders approved an
amendment to the Company's certificate of incorporation to increase the number
of authorized shares of common stock to 250 million from 185 million.
After the closing of 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"), IPP Parties and their
designees owned approximately 20.5 million shares of the Company's common stock,
representing approximately 11% of the Company's voting securities. Pursuant to
the MRA, any IPP Party that received 2% or more of the outstanding common stock
and any designee of IPP Parties that received more than 4.9% of the outstanding
common stock upon the consummation of the MRA, together with certain but not all
affiliates (collectively, "2% Shareholders"), entered into certain shareholder
agreements (the "Shareholders Agreements"). Pursuant to each Shareholder
Agreement, the 2% Shareholders agree that for five years from the consummation
of the MRA, 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 generally vote their shares on a "pass-through" basis, in the same
proportion as all shares held by other shareholders are voted, except that they
may vote in their discretion (i) for extraordinary transactions and (ii) for
directors when there is a pending proposal to acquire the Company.
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. This provision will continue to apply to the
regulated company under the holding company structure. See "Formation of
Holding Company" as discussed below.
As of January 1, 1999, there were approximately 60,000 holders of record of
common stock of the Company and about 4,300 holders of record of preferred
stock. The chart below summarizes common stockholder ownership by size of
holding:
Size of Holding Total Total
(Shares) Stockholders Shares Held
- ---------------- ------------ -----------
1 to 99. . . . . 29,576 761,377
100 to 999 . . . 27,862 6,701,542
1,000 or more. . 2,601 179,901,944
------ -----------
60,039 187,364,863
====== ===========
FORMATION OF HOLDING COMPANY. The POWERCHOICE agreement allows the Company to
form a holding company, which the Company's shareholders approved at its 1998
annual meeting. The Company also received approval from the FERC, PSC and NRC,
and is awaiting further approval from the Securities and Exchange Commission.
Once all approvals are received, a share exchange will occur whereby holders of
shares of the Company's common stock will automatically become holders of common
stock of Niagara Mohawk Holdings, Inc. ("Holdings") on the basis of one share of
common stock for one share of Holdings common stock. The Company's preferred
stock will not be exchanged as part of the share exchange but will continue as
shares of the Company's preferred stock. Holdings is authorized to issue
50,000,000 shares of its own preferred stock. The share exchange and the
holding company structure will not change the rights of holders of the
outstanding shares of the Company's preferred stock. The Company's preferred
stock will continue to rank senior to the Company's common stock (which will be
held by Holdings) as to dividends and as to distribution of the Company's assets
upon any liquidation.
As a result of the share exchange:
- - Holdings will become a holding company owned by the former common
shareholders of the Company
- - Holdings will become the sole owner of the Company's common stock
- - The Company's obligations with respect to its long-term debt, First
Mortgage Bonds and preferred stock will remain with the Company and not
be transferred to Holdings
- - The Company will continue to carry on its regulated utility business as a
subsidiary of Holdings and the Company's non-regulated subsidiaries will
be owned as a separate subsidiary of Holdings. The Company will retain
all other subsidiaries.
- - The par value per share of Holdings common stock will be $0.01
No income tax gain or loss will be recognized by a holder of the Company's
common stock as a result of share exchange solely for Holdings common stock
under IRS Code Section 351. The tax basis of the Holdings common stock received
in the share exchange will be the same as the exchanging shareholder's basis in
the Company's common stock. In addition, no income tax gain or loss will be
recognized by the Company or Holdings.
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, 1998, 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.
1998 1997 1996* 1995 1994
------------ ----------- ----------- ----------- -----------
OPERATIONS: (000'S)
Operating revenues. . . . . . . . $ 3,826,373 $3,966,404 $3,990,653 $3,917,338 $4,152,178
Net income (loss) . . . . . . . . (120,825) 183,335 110,390 248,036 176,984
- --------------------------------- ------------ ----------- ----------- ----------- -----------
COMMON STOCK DATA:
Book value per share at year end. $ 16.92 $ 18.89 $ 17.91 $ 17.42 $ 17.06
Market price at year end . . . . 16 1/8 10 1/2 9 7/8 9 1/2 14 1/4
Ratio of market price to
book value at year end . . . . 95.3% 55.6% 55.1% 54.5% 83.5%
Dividend yield at year end. . . . - - - 11.8% 7.9%
Basic and diluted earnings per
average common share . . . . . ($0.95) $ 1.01 $ 0.50 $ 1.44 $ 1.00
Rate of return on common equity . (5.3)% 5.5% 2.8% 8.4% 5.8%
Dividends paid per common share . - - - $ 1.12 $ 1.09
Dividend payout ratio . . . . . . - - - 77.8% 109.0%
- --------------------------------- ------------ ----------- ----------- ----------- -----------
CAPITALIZATION: (000'S)
Common equity . . . . . . . . . . $ 3,170,142 $2,727,527 $2,585,572 $2,513,952 $2,462,398
Non-redeemable preferred stock. . 440,000 440,000 440,000 440,000 440,000
Mandatorily redeemable
preferred stock. . . . . . . . 68,990 76,610 86,730 96,850 106,000
Long-term debt. . . . . . . . . . 6,417,225 3,417,381 3,477,879 3,582,414 3,297,874
- --------------------------------- ------------ ----------- ----------- ----------- -----------
Total. . . . . . . . . . . . 10,096,357 6,661,518 6,590,181 6,633,216 6,306,272
Long-term debt maturing
within one year. . . . . . . . 312,240 67,095 48,084 65,064 77,971
- --------------------------------- ------------ ----------- ----------- ----------- -----------
Total. . . . . . . . . . . . $10,408,597 $6,728,613 $6,638,265 $6,698,280 $6,384,243
- --------------------------------- ------------ ----------- ----------- ----------- -----------
Capitalization ratios: (including long-term debt maturing within one year)
Common stock equity . . . . . . . 30.5% 40.5% 39.0% 37.5% 38.6%
Preferred stock . . . . . . . . . 4.9 7.7 7.9 8.0 8.5
Long-term debt. . . . . . . . . . 64.6 51.8 53.1 54.5 52.9
*Amounts include extraordinary item, see Note 2. Rate and Regulatory Issues and
Contingencies
1998 1997 1996* 1995 1994
------------ ------------ ------------ ------------ ------------
FINANCIAL RATIOS:
EBITDA (000's)). . . . . . . . . . . . $ 990.5 $ 961.5 $ 957.5 $ 929.1 $ 1,029.9
Net cash interest (000's). . . . . . . $ 345.5 $ 226.9 $ 244.5 $ 260.5 $ 261.7
Ratio of EBITDA to net cash
interest. . . . . . . . . . . . . . 2.9 4.2 3.9 3.6 3.9
Ratio of earnings to fixed charges . . . 0.57 2.02 1.57 2.29 1.91
Ratio of earnings to fixed charges
and preferred stock dividends . . . . 0.52 1.67 1.31 1.90 1.63
Other ratios (% of operating revenues):
Fuel, electricity purchased and
and gas purchased. . . . . . . . . 39.6% 44.4% 43.5% 40.3% 39.6%
Other operation and maintenance
expenses . . . . . . . . . . . . . 24.5 21.1 23.3 20.9 23.1
Depreciation and amortization . . . . 9.3 8.6 8.3 8.1 7.4
Amortization of the MRA
regulatory asset . . . . . . . . . 3.4 - - - -
Federal and foreign income taxes,
and other taxes. . . . . . . . . . 10.3 15.1 13.6 17.3 14.7
Operating income. . . . . . . . . . . 4.4 14.1 13.1 17.5 13.3
Balance available for common
stock. . . . . . . . . . . . . . . (4.1) 3.7 1.8 5.3 3.5
MISCELLANEOUS: (000'S)
Gross additions to utility plant . . . . $ 392,200 $ 290,757 $ 352,049 $ 345,804 $ 490,124
Total utility plant. . . . . . . . . . . 11,431,447 11,075,874 10,839,341 10,649,301 10,485,339
Accumulated depreciation
and amortization. . . . . . . . . . . 4,553,448 4,207,830 3,881,726 3,641,448 3,449,696
Total assets . . . . . . . . . . . . . . 13,861,187 9,584,141 9,427,635 9,477,869 9,649,816
*Amounts include extraordinary item, see Note 2. Rate and Regulatory Issues and
Contingencies
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 that involve risk and uncertainty, including the
improvement in the Company's cash flow upon the implementation of the MRA and
POWERCHOICE, the timing and outcome of the future sale of the Company's fossil,
hydro and nuclear generation assets, and the costs and potential recoveries
associated with the January 1998 ice storm and September 1998 windstorm.
In addition, certain statements made related to the Company's year 2000 program
are also forward-looking (see "Year 2000 Readiness Disclosure").
These forward-looking statements are based upon a number of assumptions,
including assumptions regarding the POWERCHOICE agreement and regulatory
actions to continue to support such an agreement, internal assessment of damage
related to the 1998 storms and related government and insurance company's
actions with respect to providing recovery for such damage. Actual future
results and developments may differ materially depending on a number of
factors, including regulatory changes either by the federal government or the
PSC, uncertainties regarding the ultimate impact on the Company as the
regulated electric and gas industries are further deregulated and electricity
and gas suppliers gain open access to the Company's retail customers, challenges
to the POWERCHOICE agreement under New York laws, the timing and extent of
changes in commodity prices and interest rates, the effects of weather, the
length and frequency of outages at the Company's two nuclear plants, the
results from the Company's ongoing sale of its generation assets, and the
economic conditions of the Company's service territory.
The Company's main business segment is its regulated operations. See Part II,
Item 8. Financial Statements and Supplementary Data - "Note 12. Segment
Information." This discussion and analysis will concentrate on this business
segment unless otherwise noted.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
EVENTS AFFECTING 1998 AND THE FUTURE
------------------------------------
- - In early January 1998, a major ice storm caused extensive damage to the
Company's facilities in northern New York. The cost to repair damaged
facilities was approximately $140 million.
- - On March 20, 1998, the PSC approved the POWERCHOICE settlement agreement,
which incorporated the terms of the MRA. POWERCHOICE was implemented
September 1, 1998 upon PSC approval of rate tariffs.
- - At the June 29, 1998 annual meeting, the shareholders gave the Company
approval to form a holding company, the implementation of which will
occur following the receipt of one final regulatory approval.
- - On June 30, 1998, the Company completed $3.8 billion in public financing
and used the net proceeds along with shares of the Company's common stock
and additional cash to consummate the MRA, which terminated, restated or
amended certain IPP power purchase contracts.
- - In September 1998, a severe windstorm passed through a portion of the
Company's service territory interrupting electric service to more than
250,000 customers. The cost to repair and replace damaged facilities was
approximately $22.5 million.
- - In December 1998, the Company announced agreements to sell its 72
hydroelectric generating plants for $425 million and its coal-fired electric
generating stations for $355 million, which have a combined net book value
of $639 million as of December 31, 1998. The Company continues to pursue the
sale of its two oil and gas-fired plants and its interest in a third plant.
- - In January 1999, the Company announced plans to pursue the sale of its
nuclear assets, the Unit 1 nuclear plant and a 41% co-ownership of the Unit
2 plant.
MASTER RESTRUCTURING AGREEMENT AND THE POWERCHOICE AGREEMENT
------------------------------------------------------------
BACKGROUND. The Company entered into the PPAs that were subject to the MRA
because it was required to do so under PURPA and New York State law, which
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 was
delegated certain 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 statutory minimum price
for utility purchases of electric power from IPP 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 adjusted by the PSC during this period. PURPA
and the Six-Cent Law, in combination with other factors, including the area's
existing energy infrastructure and availability of cogeneration hosts, attracted
large numbers of IPPs to New York State, and, in particular, to the Company's
service territory. 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 was obligated to
purchase electricity offered from IPPs in quantities in excess of its own demand
and at prices in excess of those 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 deteriorated and the price of electricity
paid per KWh by its customers rose 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 resulted in reducing 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 in respect of 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 estimated that absent the MRA, payments made
to the IPPs pursuant to PPAs would have continued 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. The MRA was consummated on June 30, 1998 with
14 IPPs. The MRA allowed the Company to terminate, restate or amend 27 PPAs
which represented approximately three-quarters of the Company's over-market
purchase power obligations. The Company terminated 18 PPAs for 1,092 MW of
electric generating capacity, restated eight PPAs representing 535 MW of
capacity and amended one PPA representing 42 MW of capacity. The Company paid
the IPP Parties an aggregate of $3.934 billion in cash, of which $3.212 billion
was obtained through a public market offering of senior unsecured debt, $303.7
million from the public sale of 22.4 million shares of common stock, and the
remainder from cash on hand. In addition, the Company issued 20.5 million
shares of common stock to the IPP Parties.
Under the PSC approved POWERCHOICE agreement, a regulatory asset was established
for the costs of the MRA and will be amortized over a period generally not to
exceed ten years. The Company's rates under POWERCHOICE have been designed to
permit recovery of the MRA regulatory asset. In approving POWERCHOICE, the PSC
limited the estimated value of the MRA regulatory asset that could be recovered,
which resulted in a charge to the second quarter of 1998 earnings of $263.2
million upon the closing the MRA. The POWERCHOICE agreement, while having the
effect of substantially depressing earnings during its five-year term, will
substantially improve operating cash flows.
The MRA is estimated to reduce the Company's IPP payments by more than $500
million annually, net of purchases of power at market price. The improved cash
flow will allow the Company to reduce electricity prices and repay the debt
required to finance the MRA. In addition, the Company is actively pursuing
other opportunities to reduce its payments to IPPs that were not party to the
MRA.
Under the terms of the MRA, the Company has no continuing obligation to
purchase energy from the terminated IPP Parties. The restated contracts with
eight PPAs reflect economic terms and conditions that are more favorable to the
Company than the previous PPAs. The restated contracts have a term of ten years
and are structured as indexed 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 average 4,100 GWh per year and are fixed for the full
ten-year term of the contracts. The indexed pricing structure in combination
with the Company's procurement policies ensures that the net 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. The put energy is to be priced at a market proxy based upon short run
marginal cost. Additionally, one PPA representing 42 MW of capacity was amended
to reflect a shortened term and a lower stream of fixed unit prices. The
Company projects, based upon current projections of future market prices, that
it will make the following payments to the IPP Parties under the indexed swap
contracts for the years 1999 to 2003 as follows:
Projected
Payment
Year (in thousands)
- ---- ---------------
1999 $ 97,354
2000 97,688
2001 102,073
2002 103,552
2003 105,531
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 contains terms
that are believed to be more responsive to competitive market price changes.
See Item 8. Financial Statements and Supplementary Data, and Note 9.
"Commitments and Contingencies - Long-term Contracts for the Purchase of
Electric Power."
POWERCHOICE AGREEMENT. The POWERCHOICE proposal was originally filed by the
Company in October 1995 and subsequent negotiations with PSC Staff and
intervenors resulted in the POWERCHOICE settlement agreement which was filed
by the Company in October 1997. The POWERCHOICE agreement, which was approved
in the PSC's written order dated March 20, 1998, establishes a five-year rate
plan that will reduce class average residential and commercial prices by an
aggregate of 3.2% over the first three years, beginning September 1, 1998.
The reduction in prices includes certain savings that will result from approved
reductions of the New York State GRT. Industrial customers will see average
reductions of 25% relative to 1995 tariffs; these decreases will include
discounts currently offered to some industrial customers through optional
and flexible rate programs. Additionally, in approving POWERCHOICE, which
incorporated the terms of the MRA, the PSC made various changes to the
settlement agreement. These changes included, among others, exempting certain
customers from paying the CTC and requiring the Company to defer savings from
the reduction in the interest rate associated with the debt issued in connection
with the MRA financing, which have accumulated to $10.7 million through
December 31,1 998. 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 12-month
period. The rates used in the POWERCHOICE implementation on September 1, 1998
are based on the 12-month period ended December 31, 1997 for residential and
commercial customers and 1995 prices for all others.
During the term of the POWERCHOICE agreement, the Company would be permitted to
defer certain incremental costs associated primarily with environmental
remediation, nuclear decommissioning and related costs, and changes in laws,
regulations, rules and orders. To date, the Company has not deferred any
additional costs other than those stipulated in the POWERCHOICE agreement. 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, beginning in year four, recover cost
variations in the indexed swap 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. Currently, some customers are able to choose their electricity
supplier, and the Company expects to offer retail choice to all customers by
August 1, 1999. The Company will continue to distribute electricity through its
transmission and distribution systems and will be obligated to be the 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 are 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. 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.
Between the MRA closing date (June 30, 1998) and the POWERCHOICE implementation
date (September 1, 1998), the Company experienced a reduction in power purchase
costs of $80 million as well as increased financing costs of $40.4 million as a
result of the MRA and the MRA financing. The net effect of these items was
deferred for future disposition because the time lag between these events was
not contemplated in the POWERCHOICE agreement.
In July 1998, the Public Utility Law Project of New York, Inc. ("PULP") and
others sought a declaratory judgment, declaring the Company's POWERCHOICE
agreement unlawful, null and void and seeking injunctive relief in the Supreme
Court of the state of New York, Albany County against the PSC and the Company to
enjoin the defendants to halt all their actions and expenditures to implement
the rules for the provision of retail energy services contained in the
POWERCHOICE agreement. The PSC and the Company filed a motion seeking to
dismiss this action. The motion is pending in the Albany County Supreme Court.
The Company is unable to predict the outcome of this matter.
In early October 1998, the Alliance for Municipal Power, a group of 21 towns
and villages in St. Lawrence and Franklin Counties pursuing municipalization
that has also called themselves the Retail Service Communities, and Alfred P.
Coppola, a Councilman from the City of Buffalo, commenced an Article 78
Proceeding in Albany County Supreme Court that challenged the PSC's decision to
approve POWERCHOICE and the PSC's decision that denied the petitions of Alliance
for Municipal Power and Coppola for rehearing before the Commission. The
Article 78 Petition seeks to vacate the decision of the PSC approving
POWERCHOICE provisions relating to the determination and recovery of strandable
costs through the application of a competitive transition charge and exit fees.
The PSC has made a motion to dismiss the Article 78 Petition in this matter and
the motion is pending in the Albany County Supreme Court. The Company is unable
to predict the outcome of this matter at this time. Suspension of POWERCHOICE
or renegotiation of its material terms could have a material adverse effect on
the Company's results of operations, financial condition, and future cash flows.
In its written Order dated May 6, 1998, the PSC approved the Company's plan to
divest all of its fossil and hydro generation assets, which is a key component
in the Company's POWERCHOICE agreement to lower average electricity prices and
provide customer choice. On December 3, 1998, the Company announced it had
reached an agreement with an affiliate of Orion Power Holding, Inc. ("Orion") to
sell its 72 hydroelectric generating plants with a combined capacity of 661 MW
for $425 million, representing 1.7 times their book value of approximately
$258.2 million at December 31, 1998. As part of the agreement, the Company will
purchase electricity from Orion under a transition power agreement ("TPA")
through September 2001. On December 23, 1998, the Company announced an
agreement with NRG Energy, Inc. ("NRG") to sell its Huntley and Dunkirk
coal-fired electric generating stations for $355 million. The coal stations
have a book value of approximately $380.6 million and a combined capacity of
1,360 megawatts at December 31, 1998. The Company has also signed, as part of
this agreement, a TPA to purchase electricity from NRG through June 2003 at
prices consistent with those negotiated in POWERCHOICE for those assets. The
TPAs for the hydro and coal-fired facilities are designed to help the Company
meet the objectives of rate reduction and price cap commitments as well as meet
expected demand as the "provider of last resort" as outlined in the POWERCHOICE
agreement. The TPAs acts as hedges against rising power costs. The terms of
the TPAs provide for both fixed and variable payments, encompassing both
capacity and energy. These TPAs are one part of the integrated transactions
for the sale of the generating facilities. It is anticipated that transaction
closings will occur in mid-1999 after receipt of the necessary regulatory
approvals. The Company continues to pursue the sale of its two oil and
gas-fired plants in Albany and Oswego, which have net book values of $39.3
million and $332.4 million, respectively at December 31, 1998. The Company is
unable to predict the outcome or timing of the divestiture of these plants.
The Company will also be selling its interest in the Roseton plant with a net
book value of $39.8 million as of December 31, 1998, through an auction by the
operator of the plant, Central Hudson Gas and Electric Corporation. Central
Hudson Gas and Electric Corporation has indicated that the sale is expected to
conclude in 2000. 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 is obligated to use 85% of the proceeds
of the sale of the fossil and hydro generation assets to reduce outstanding
debt.
The POWERCHOICE agreement contemplated that the Company's nuclear plants would
remain part of the Company's regulated business. The POWERCHOICE agreement
stipulates that absent 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. On January 28, 1999, the Company
announced plans to pursue the sale of its nuclear assets. The Company is unable
to predict if a sale will occur and the timing of such sale. See "PSC Staff's
Tentative Conclusions on the Future of Nuclear Generation."
The POWERCHOICE agreement also allows the Company to form a holding company,
which the Company's shareholders approved at its 1998 annual meeting. The
Company received approval from the FERC, PSC and NRC to form the holding
company. The Company is awaiting further approval from the Securities and
Exchange Commission, prior to implementation of the holding company.
The holding company structure is intended to provide the Company and its
subsidiaries with the financial and regulatory flexibility to compete more
effectively in an increasingly competitive energy industry by providing a
structure that can accommodate both regulated and unregulated lines of business.
The holding company structure would largely eliminate many regulatory
constraints that would limit the Company's ability to participate in unregulated
business opportunities as the industry evolves.
All of the foregoing discussion of the POWERCHOICE agreement is qualified in its
entirety by the text of the agreement and PSC Order.
For a discussion of the Company's ability to continue to apply SFAS No. 71 to
its remaining electric business (nuclear generation and electric transmission
and distribution business), under POWERCHOICE, see Note 2. Rate and Regulatory
Issues and Contingencies.
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, and the introduction
of a competitive wholesale power market and retail access for all electric
customers. The goals include 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 provisions of the Company's
POWERCHOICE agreement are consistent with COPS objectives.
The PSC continues to assess other functions in the regulated electric and gas
business to lower consumer rates and increase customer choice. The PSC is
considering to open competition to such functions as metering, billing,
collections and customer service. In addition, on January 13, 1999, the PSC
adopted a set of Uniform Business Rules for Retail Access designed to streamline
and make more uniform the manner in which the local utilities interact with
natural gas and electricity marketers, energy services companies and customers
who purchase energy in New York State's evolving competitive market. This was a
collaborative effort among all parties involved. The Company will continue to
participate with the PSC and other parties as New York State moves forward with
a competitive utility industry, but the Company cannot predict the outcome of
the results and the impact on its POWERCHOICE agreement.
FERC RULEMAKING ON OPEN ACCESS AND STRANDED COST RECOVERY
---------------------------------------------------------
RULEMAKING ON OPEN ACCESS. In April 1996, the FERC issued 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 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 ("ALJ")
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 a NYISO, 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 NYISO
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 NYISO tariff. Through the NYISO, 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 NYISO operates the bulk power system. The NYISO would
also administer the daily electric energy market and the NYPE would facilitate
the electric energy market on a day-ahead basis.
On June 24, 1998, FERC gave the Member Systems conditional approval to form the
NYISO. However, FERC deferred action on the rates, terms and conditions of the
NYISO's open access transmission tariff, and directed the Member Systems and
interested parties to negotiate a modified voting structure for the NYISO
committees. In compliance with this directive, a settlement agreement supported
by the Member Systems and a number of parties was submitted to FERC on October
23, 1998. Other steps have also been taken to prepare for the establishment of
the NYISO, including selection of members of the Board of Directors.
Subsequently, on January 27, 1999, FERC conditionally approved the tariffs,
market rules and market based rates proposed by the NYISO. While the Company is
unable to predict when FERC will rule on the remaining details of the Member
Systems' NYISO proposal, it does believe that progress is being made in New York
State toward more competitive wholesale electricity markets, consistent with the
POWERCHOICE restructuring agreement.
STRANDED COST RECOVERY IN THE CASE OF MUNICIPALIZATION. 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.
In November 1997, FERC issued Order 888-B. This Order clarified 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 approving POWERCHOICE, the PSC authorized changes to the Company's Retail
Tariff providing for the recovery of stranded costs in the case of
municipalization regardless of whether the new municipal utility requires
transmission service from the Company. The calculation of stranded costs is
governed by this Retail Tariff, which became effective on April 6, 1998. A
number of communities are considering municipalization and have requested an
estimate of their stranded cost obligation.
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 withdrew from the Company's system to create
municipal electric utilities. The stranded cost calculations were based on the
methodology prescribed by the FERC in Order 888. The preliminary estimate of
the combined potential stranded cost liability for the communities ranged from a
low of $225 million to a high of $452 million, depending upon the forecast of
electricity market prices that was used. These amounts did not include the
costs of creating and operating a municipal utility. At this time, it appears
that 21 of the original 26 communities are still pursing municipalization. If
these 21 communities withdrew from the Company's system, the Company would
experience a potential revenue loss of approximately 2% per year.
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 state 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, those communities will be subject both to the exit fee
provisions of the Company's Retail Tariff and the possibility that a state court
may permit the Company to recover some or all of the stranded costs in a
condemnation proceeding. The 21 communities have filed suit in state court
challenging the PSC's approval of the exit fee provisions in the Company's
Retail Tariff. The PSC has moved to dismiss the case. The Company is unable to
predict the outcome of this matter. See "Master Restructuring Agreement and
the POWERCHOICE Agreement."
In August 1997, the Company provided the Village of Lakewood with an estimate of
its stranded cost obligation in response to a formal request under FERC Order
888. In June 1998, the Village of Lakewood filed a petition with FERC seeking a
determination that it would not be responsible for any of the Company's stranded
costs if it created a new municipal electric system. The Company responded in
opposition to this petition. On October 1, 1998, FERC set a hearing with a FERC
Administrative Law Judge in the matter of Lakewood's stranded cost obligation to
the Company under Order 888.
The PSC and the Company requested rehearing of the FERC's Order of October 1,
1998. Both parties pointed out that the PSC has a process in place to
adjudicate Lakewood's liability for stranded costs under the Company's Retail
Tariff in the event of municipalization, and suggested that it would be
inefficient and contrary to Order No. 888-B for the FERC to hold hearings on
Lakewood's stranded cost obligation under Order 888 until Lakewood's stranded
cost obligation under the Retail Tariff has been established by the PSC. The
Company also sought clarification that Order 888 does not preempt the PSC's
jurisdiction to authorize the recovery of stranded costs under the exit fee
provisions of the Company's Retail Tariff.
On December 11, 1998 the FERC issued an order granting the Company's request for
clarification that Order 888 does not preempt the exit fee provision of the
Retail Tariff and directing that the Lakewood case be held in abeyance pending
the resolution of Lakewood's stranded cost obligation under the Company's Retail
Tariff. Lakewood and the Company are required to file a joint status report
with FERC six months from the issuance of the Order. On January 7, 1999, the
PSC directed the Company to provide Lakewood, within 45 days, an estimate of
Lakewood's stranded cost obligation under the exit fee provisions of the
Company's Retail Tariff. On February 18, 1999, the Company provided Lakewood
with an estimate of these exit fees of $14.98 million. The Company is unable to
predict the outcome of this matter.
On December 7, 1998, the Company provided the City of Buffalo with both a PSC
exit fee estimate and FERC Order 888 estimate of its stranded cost obligation.
The PSC exit fee estimate is $899 million and the FERC Order 888 estimate is
$1.5 billion. If the City of Buffalo withdrew from the Company's system, the
Company would experience a potential revenue loss of approximately 8% per year.
The Company has also prepared exit fee stranded cost estimates for annexations
in the Village of Wellsville and Madison County. The Company is unable to
predict whether the City of Buffalo or these other municipalities will pursue
withdrawal from the Company's system or the amount of stranded costs the Company
may receive as a result of any withdrawals.
OTHER FEDERAL AND STATE REGULATORY INITIATIVES
----------------------------------------------
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 settlement rate
has the effect of a $10 million annual reduction in base rates or a $30 million
total reduction over the three-year term of the settlement. This reflected 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 estimated that the combination of in-hand supplier refunds and
further reductions in upstream pipeline costs would 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. As of
December 31, 1998, the Company has credited $30 million to the CRA. With
respect to the second year of the gas rate settlement agreement (November 1,
1997 to October 31, 1998), the Company did not experience any margin (revenues
less fuel costs) or peak shaving losses, since the terminating and restructuring
IPPs ran longer than originally anticipated. However, the Company may
experience margin or peak shaving losses in the last year of the settlement, a
result of the termination or restructuring of IPP contracts. 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, such that the Company is allowed
to recover more of its costs through the customer basic service charge and less
on the customer usage charge, which fluctuates based on volume. The Company
obtained an ROE cap of 13.5% with 50/50 sharing between ratepayers and
shareholders in excess of the cap. The Company has not achieved an ROE
exceeding the cap in the rate years ending October 31, 1997 or 1998. 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.
FUTURE OF THE NATURAL GAS INDUSTRY. In November 1998, the PSC issued its
Policy Statement concerning the Future of the Natural Gas Industry in New York
State and Order Terminating Capacity Assignment (PSC Policy Statement). The PSC
Policy Statement noted the following:
- - The PSC envisions a transitional time frame of three to seven years for
local gas distribution companies (LDC) to exit the business of purchasing
natural gas (the "merchant" function).
- - The PSC envisions a process comprising three basic elements, which should
be pursued in parallel in the exiting of the merchant function:
1. Addressing the issues involved in the exiting of the merchant
function on a utility-by-utility basis as part of the LDCs individual
rate plans;
2. Collaboration among staff, LDCs, marketers, pipelines and other
stakeholders of generic issues such as operational and reliability
issues, protocols and information systems requiring a status report
by April 1, 1999; and
3. Coordination of issues faced by electric utilities, including provider
of last resort issues and a plan to allow competition in other areas,
such as metering, billing and information services.
- - LDCs may no longer require capacity assignment or inclusion of capacity
costs in transportation rates beyond April 1, 1999 to customers migrating to
marketers except where specific operational and reliability requirements
warrant.
In November 1998, the PSC approved the Company's proposed pilot program that
would, effective December 1, 1998, no longer require assigning pipeline capacity
and related costs upstream of the CNG Transmission System to customers migrating
to transportation. However, the Company's proposed pilot program sought to
continue to assign capacity on the CNG system until October 31, 1999, the
expiration date of its current gas rate settlement agreement. A stranded cost
recovery mechanism, in the form of a surcharge, was established to provide for
the recovery of the unassigned pipeline capacity costs until October 31, 1999.
In December 1998, the Company notified the PSC that the Company's specific
operational and reliability requirements continue to warrant certain mandatory
capacity assignment and inclusion of capacity costs in transportation rates
after April 1, 1999. The PSC noted in its PSC Policy Statement that it will
provide LDCs with a reasonable opportunity to recover these strandable costs if
they can demonstrate compliance with the PSC's directives to minimize such
costs. The Company believes that it has taken numerous actions to reduce its
capacity obligations and its potential stranded costs, but is unable to predict
the outcome of this matter. The Company anticipates that this issue will be
addressed in the individual negotiations with the PSC anticipated to begin
during the second quarter of 1999. For a discussion of the Company's long term
supply, transportation and storage commitments, see Part II, Item 8. Financial
Statements and Supplementary Data - Note 9." Commitments and Contingencies."
NRC POLICY STATEMENT AND AMENDED DECOMMISSIONING FUNDING REGULATIONS. The NRC
issued a policy statement on the Restructuring and Economic Deregulation of the
Electric Utility Industry (NRC Policy Statement) in 1997. The NRC Policy
Statement addresses the NRC's concerns about the adequacy of decommissioning
funds and about the potential impact on operational safety. In addition to the
NRC Policy Statement, the NRC amended its regulations on decommissioning funding
to reflect conditions expected from deregulation of the electric power industry.
The NRC's new decommissioning funding rule, which addresses concerns about the
adequacy of decommissioning funds, took effect on November 23, 1998. The NRC's
new rule and its accompanying standard review plan, which is still pending NRC
review, could raise compliance issues. Licensees that are no longer subject to
traditional cost-of-service regulation for 80% or less of their electricity
sales will need to assure that they have a source of revenue for decommissioning
funds through a non-bypassable charge which qualifies a licensee to use a
sinking fund. See Part II, Item 8. Financial Statements and Supplementary
Data, Note 3 - "Nuclear Operations" for a discussion of the Company's
decommissioning estimates for Unit 1 and Unit 2.
NRC AND NUCLEAR OPERATING MATTERS. In January 1998, the NRC issued its
Systematic Assessment of Licensee Performance ("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 has taken several actions
to make those needed improvements.
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. Subsequently, 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, and currently has NRC
approval to operate Unit 1 until the Unit's scheduled refueling and maintenance
outage in spring 1999, at which time the core shroud will be reinspected. The
Company has developed a repair that would be accomplished during the spring 1999
outage if inspections indicate that repairs are needed.
On May 2, 1998, Unit 2 was taken out of service for a planned refueling and
maintenance outage. During the outage the Company performed scheduled
inspections of the plant's reactor core shroud and identified cracking in the
welds of the shroud. The scope of the inspection was expanded once the cracking
was found, which extended the length of outage. The NRC staff agreed that
continued operation without repair or intermediate inspection of the core shroud
is acceptable for at least one operating cycle after completion of the May 1998
refueling outage. Unit 2 returned to service on July 5, 1998 after completing
the 64-day refueling and maintenance outage.
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 should be treated after decisions are made on the
individual electric restructuring agreements. 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 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, and the utilities recommended that a more formal process be
developed to address issues relating to competition, sale of nuclear plants,
responsibility for decommissioning, disposal of spent fuel, safety, and
environmental benefits of fuel diversity.
On March 20, 1998, the PSC issued an opinion and order instituting a further
inquiry into the matters addressed in the PSC Staff's tentative conclusions
regarding the treatment of nuclear generation in the future. The order
concluded that the proposals contained in the Staff Report required more
extensive examination, and directed that the examination begin with a
collaborative process and move to litigation on particular issues if necessary.
A collaborative proceeding commenced on January 20, 1999.
The matters addressed in the inquiry include:
- - Market treatment for nuclear power
- - The feasibility of mandated divestiture and its likely consequences
- - Decommissioning issues
- - Effects of PSC Staff's proposal on municipalities
The tentative time line established by PSC Staff for this inquiry calls for
completion of the process by the end of 1999.
In January 1999, the Company announced plans to pursue the sale of its nuclear
assets, which will require approval from the PSC. The Company is unable to
predict if a sale will occur and the timing of such sale.
At December 31, 1998, the net book value of the Company's nuclear generating
assets was approximately $1.6 billion, excluding the reserve for
decommissioning. In addition, the Company has other assets of approximately
$0.5 billion. These assets include the decommissioning trusts and regulatory
assets, primarily due to the deferral of income taxes.
OTHER COMPANY EFFORTS TO ADDRESS COMPETITIVE CHALLENGES
-------------------------------------------------------
TAX INITIATIVES. The Company is working with utility, customer and state
representatives to solve 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 was 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 1997's level of 4.25%. As
contemplated in POWERCHOICE, 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 1996 through
1998:
In millions of dollars
1998 1997 1996
----------- ------- -------
Property tax expense. . . . . . . . . $ 251.1 $250.7 $249.4
Sales tax . . . . . . . . . . . . . . 17.6 13.4 14.1
Payroll tax . . . . . . . . . . . . . 37.4 34.1 36.4
Gross Receipts Tax. . . . . . . . . . 167.0 184.6 184.1
Other taxes . . . . . . . . . . . . . 0.3 0.1 0.5
------------- ------- -------
Total tax expense . . . . . . . 473.4 482.9 484.5
Charged to construction, subsidiaries
and regulatory recognition . . . . (13.4) (11.4) (8.7)
------------- ------- -------
Total other taxes . . . . . . . $ 460.0 $471.5 $475.8
============= ======= =======
CUSTOMER DISCOUNTS. In recent years, as energy prices have risen, customers
have found alternatives to electric service from their host utility, including
the Company. To address that competitive challenge, the Company filed for a
service tariff in 1994 called SC-11. The SC-11 tariff provided the Company with
flexibility to individually negotiate service agreements within the Company's
service franchise territory in response to a number of competitive alternatives
such as on-site generation, fuel switching, and facility relocation.
Effective September 1, 1998, the Company's POWERCHOICE agreement was
implemented. As part of that agreement, the PSC approved several key pricing
initiatives to address the Company's price levels and the resulting need to
provide discounted service. Those initiatives include:
- - Service class specific pricing goals were agreed upon (see "Master
Restructuring Agreement and the POWERCHOICE Agreement"). The targeted rate
redesigns contained in POWERCHOICE are intended to deliver the greatest price
reductions to those customers who have exhibited the greatest competitive
challenges to the Company under SC-11. The rate design provides the most
competitive prices to customers who provide economic value to the state
because they use the greater amounts of electricity and have the greater
demand on the Company's system, thereby minimizing the need (and amount)
of future discounts, while maximizing the incentive to remain in New York
State. In addition, the pricing goals include those discounts forecasted
under SC-11.
- - The PSC agreed to close SC-11 to new subscriptions provided that the
Company agrees to honor all existing contracts through their natural
expiration date, provide a provision for limited renewal of expiring SC-11
agreements and develop a suitable replacement tariff. Therefore, as
contracts expire, customers will either migrate back to the redesigned
standard tariff rate classification or continue on the SC-11 agreement.
- - A new service tariff, SC-12, has been approved as a replacement tariff to
SC-11 and will address future competitive challenges for the Company. SC-12
is differentiated from SC-11 in that predetermined minimum criteria are
specified within the tariff along with standardized discounted pricing which
varies according to the underlying competitive challenge which the Company
is facing. The Company has also retained flexibility to address specific
competitive challenges for energy intensive and job intensive challenges
through individual negotiations.
- - Revisions were made to the Company's back up, supplemental, and maintenance
pricing tariff for customers installing on-site generation. The Company has
been trying to establish compensatory rates for these services for a
number of years. A tariff provision resulting from POWERCHOICE ensures that
the Company can charge compensatory rates for these services and thereby
reduce the discounts that would otherwise be necessary in its absence.
Together, these initiatives will provide lower overall prices to customers,
strengthen the Company's competitive position and minimize the amount of future
discounts during the term of POWERCHOICE.
YEAR 2000 READINESS DISCLOSURE
------------------------------
As the year 2000 approaches, the Company, along with other companies, could
experience potentially serious operational problems, since many computer
programs that were developed in the past may not properly recognize calendar
dates beginning with year 2000. Further, there are embedded chips contained
within generation, transmission, distribution, gas, and other equipment that may
be date sensitive. In circumstances where an embedded chip fails to recognize
the correct date, electric, gas and business operations could be adversely
affected.
PLAN: A Company-wide year 2000 project management office has been formed and
year 2000 project managers have been appointed within each business group. A
year 2000 program vice-president and an executive level steering committee have
been put in place to oversee all aspects of the program. In addition to Company
personnel, the Company has retained the services of leading computer service and
consulting firms specializing in computer systems and embedded components, which
are involved in various phases of the project. Also, the Company is working
closely with industry groups such as the Electric Power Research Institute
("EPRI"), North American Electric Reliability Council ("NERC"), Nuclear Energy
Institute, and other utilities. In addition, the PSC is requiring that New York
utilities have mission critical year 2000 work, including a contingency plan,
completed by July 1, 1999, and the NRC is requiring the Company to certify that
the Company's two nuclear plants will be year 2000 ready by July 1, 1999. A
plan was developed that established phases of the work to be done. The phases
are:
- - an inventory of all systems and equipment, (including a physical
walk-down of all of the Company's substations),
- - an assessment of all systems and equipment and definition of next steps,
- - remediation,
- - testing and validation,
- - acceptance and deployment,
- - independent validation, and
- - contingency planning.
As part of the inventory phase, all the systems and equipment have been
prioritized into four categories based upon their functional need and
importance. The priorities are:
- - Priority 1 - Any failure or regulatory breach that can cause an
interruption to the generation or delivery of electric or gas energy to
customers, or can jeopardize the safety of any employee, customer, or the
general public (e.g. the Energy Management System that controls the flow of
electricity and communicates information between the control center and
sub-stations).
- - Priority 2 - Any failure that can cause an interruption to customer
service or breach of significant contractual or financial commitment (e.g.
Meter reading equipment).
- - Priority 3 - Any failure that can inconvenience a business partner or
significantly impact a Company business group productivity (e.g. electronic
payments to vendors).
- - Priority 4 - Any failure that can adversely impact a Company work group or
personal productivity, or other business processes (e.g. applications used
on a desktop computer used to accomplish day-to-day productivity activities).
Although the Company has identified seven different phases of the project, in
some cases the phases are done concurrently. For example, individual computers
may be completely tested and redeployed while others are still being remediated.
Information obtained within the phases is reviewed by a panel consisting of
employees and consultants. Additional testing may be performed based on the
importance of the component and a recommendation of the panel. Complete
integration and interface testing will be performed on components and systems
whenever possible.
The Company's primary focus is on priorities 1 and 2 because of the direct
impact on customers. Although the Company's plan addresses completion of all
priority items prior to July 1, 1999, some exceptions may not be addressed
completely. These are scheduled, however, to be completed by January 1, 2000.
The Company's progress with its year 2000 issues for priority items 1 and 2 are
as follows:
PHASE STATUS ESTIMATED COMPLETION DATE
- ------------------------ --------------- -------------------------
- - Inventory Complete
- - Assessment Complete
- - Remediation In-progress December 1998 - May 1999
- - Testing & Validation In-progress March 1999 - May 1999
- - Acceptance In-progress March 1999 - June 1999
- - Independent Validation In-progress October 1999
- - Contingency Planning In-progress December 1998 - June 1999
Note: Each business group within the Company has its own schedule. The
estimated completion dates above may show a range due to different
schedules within each business group.
The Company has expanded the scope of its Independent Validation phase and has
added an additional Quality Assurance Audit scheduled for September 1999.
Therefore, the Company has extended its estimated completion date for that phase
to October 1999.
RISKS: The failure to correct for year 2000 problems, either by the Company or
third parties, could result in significant disruptions of the Company's
operations. At this point in time based on the Company's progress to date and
the information received from third parties, the Company is unable to determine
its most reasonably likely worst case scenario.
Like any organization, the Company is dependent upon many third parties,
including suppliers of energy and materials (e.g. independent power producers),
service providers, transporters, and the government. These third parties
provide services vital to the Company and year 2000 problems at these companies
could adversely affect electric and gas operations. One such example is that
the Company expects that by the year 2000, it will be purchasing the majority of
its electric generation needs. If any of these suppliers has a year 2000
failure, it could interrupt energy supply to the Company's customers. Another
example of such a vital third party is telephone companies. If the telephone
companies have year 2000 failures, this could in turn affect the Company's
customer response capabilities and the Company's ability to operate and maintain
the transmission and distribution system that carries electricity to businesses
and customer homes. To address these third party issues, the Company has
requested certificates of compliance from third parties. To date, the Company
has received some responses, but disclosure has been limited. The Company will
continue to follow up with third parties to verify the accuracy of responses
when the Company's relationship with such third parties is material for its
operations. However, the Company may not be able to verify accuracy in all
cases. The inability of suppliers to complete their year 2000 readiness process
could materially impact the Company.
The Company is connected to an electric grid that links utilities throughout
the United States and Canada. This interconnection is essential to the
reliability and operational integrity of the connected utilities. If one of the
electric utilities in the grid has a failure, it could cause power fluctuations
and possible interruption of others in the grid. As a result, even when the
Company does an effective job of becoming compliant, it could still have
customer interruptions. The Company is working closely with NYPP, NERC, other
utilities, EPRI, and other industry groups to address the issue of grid
reliability.
The Company's gas distribution system also has the potential to be adversely
impacted by year 2000 noncompliance either by third parties or if the Company's
program fails to identify and remediate all problem areas. From the third party
natural gas production and transmission facilities, to the Company's
distribution pipeline system, and ultimately, to the customer, there are
computer systems and equipment with date sensitive processing. If, despite the
Company and third party's best efforts, a year 2000 failure occurs, the flow of
gas to the customer could be jeopardized.
As an example, the Company is connected directly to three major transmission
pipelines, and has an indirect connection with a fourth. If these pipelines are
unable to provide full gas delivery to the Company, the Company would implement
standing emergency procedures that could interrupt customers. To avoid such an
event, the Company is working with the pipelines, and state agencies to reduce
the probability of any customer interruptions due to year 2000 problems.
CONTINGENCY PLANS: The Company's year 2000 schedules also include the
development and implementation of contingency plans in the event of year 2000
failures, both within the Company and by third parties. The Company expects to
have these plans completed during 1999 for all priority categories. The Company
has established a year 2000 Contingency Planning department to oversee and
assist the business groups in the creation of their contingency plans. The
contingency plans will vary by business group and by the various priority levels
for different systems and equipment. A schedule has been created to track
progress, which includes participation in the NERC drills scheduled for April
1999 and September 1999.
COSTS: The Company estimates that total program costs will approximate $33.3
million of which approximately $23.3 million will be expensed and $10 million
will be capitalized. Total program costs incurred through December 31, 1998 are
$11.6 million of which $8.0 million was expensed and $3.6 million was
capitalized. The Company expects to fund the total program costs through
operating cash flows.
Over the last several years as the Company implemented various large computer
projects, the Company was conscious of year 2000 exposures and therefore made
sure the projects were year 2000 compliant. However, these computer projects
were implemented for business reasons rather than to solely comply with year
2000 issues. These projects included replacing the customer
service/billing/revenue system, as well as implementing a project accounting
system, a computer aided dispatch system, and desktop computers for employees,
among others. Through December 31, 1998, the Company has spent approximately $70
million on these projects in addition to specific year 2000 compliance spending.
The Company has not deferred any significant computer projects as a result of
the year 2000 project.
Certain statements included in this discussion regarding year 2000 compliance
are forward-looking statements as defined in Section 21E of the Securities
Exchange Act of 1934. These statements include management's best estimates for
completion dates for the various phases and priorities, testing to be performed,
costs to be spent for compliance, and the risks associated with non-compliance
either by the Company or third parties. These forward-looking statements are
subject to various factors, which may materially affect the Company's efforts
with year 2000 compliance. Specific factors that might cause such material
differences include, but are not limited to, the availability and cost of
personnel trained in this area, which could cause a change in the estimated
completion date of a particular phase, the ability to locate and correct all
relevant software and embedded components, the compliance of critical vendors,
as well as neighboring utilities, and similar uncertainties. The Company's
assessments of the effects of year 2000 on the Company are based, in part, upon
information received from third parties and other utilities, and the Company's
reasonable reliance on that information. Therefore, the risk that inaccurate
information is supplied by third parties and other utilities upon which the
Company reasonably relied must be considered as a risk factor that might affect
the Company's year 2000 efforts. The Company is attempting to reduce the risks
by utilizing an organized approach, extensive testing, and allowance of ample
contingency time to address issues identified by tests.
1998 STORMS
-----------
In early January 1998, a major ice storm and flooding caused extensive damage in
a large area of northern New York. The Company's regulated 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.
The total estimated cost of the restoration and rebuild efforts is approximately
$140.5 million. As of December 31, 1998, the Company expensed $72.9 million
associated with the January 1998 ice storm (of which $62.1 million was
considered incremental) and capitalized $67.6 million of costs as utility plant.
The Company continues to pursue federal disaster relief assistance. The Company
has submitted claims to its insurance carriers for hydroelectric stations and
substations damages, and for electric transmission and distribution damages.
In December 1998, the Company received a $2 million advance payment from one of
its insurance carriers. The Company is unable to determine the total amount of
recoveries it may receive from these sources.
On September 7, 1998 a severe windstorm passed through a portion of the
Company's service territory interrupting electric service to more than 250,000
customers from Niagara Falls to Albany. Power was restored to the majority of
the customers within one week. The total preliminary estimated cost of
restoration from the September storm is approximately $22.5 million. However,
final costs of the storm will not be known until all costs and charges are
analyzed and charges from other utilities and contractors have been received.
As of December 31, 1998, the Company recorded $19.2 million in expense (of which
$15.7 million was considered incremental). The remaining $3.3 million has been
capitalized. The Company is continuing to inspect and survey the work
completed. The Company will pursue federal disaster relief assistance for the
September storm.
RESULTS OF OPERATIONS
---------------------
The Company experienced a loss in 1998 of $157.4 million or 95 cents per share,
as compared to earnings of $145.9 million, or $1.01 per share, in 1997 and
earnings of $72.1 million, or 50 cents per share, in 1996.
Results for 1998 were negatively impacted by a non-cash write-off of $263.2
million or $1.03 per share associated with the portion of the MRA regulatory
asset disallowed in rates by the PSC and by the regulatory treatment of the MRA
regulatory asset. (see Master Restructuring Agreement and the POWERCHOICE
Agreement). With the consummation of the MRA and implementation of POWERCHOICE
effective September 1, 1998, the Company expects reported earnings for the next
five years to be substantially depressed as a result of the regulatory treatment
of the MRA regulatory asset. (See Item 8. Financial Statements and
Supplementary Data - Note 2. Rate and Regulatory Issues and Contingencies). The
January 1998 ice storm and the September 1998 windstorm also negatively impacted
1998 earnings by $77.8 million, or 30 cents per share, which reflects the
Company's estimate of incremental, non-capitalized costs to restore power and
rebuild its electric system. In addition, per share results for the year ended
December 31, 1998 were diluted by the issuance of 42.9 million shares of common
stock in connection with the MRA.
Earnings in 1996 were reduced by an after-tax write-off of $67.4 million, or 47
cents per share, associated with the discontinued application of regulatory
accounting principles to the Company's fossil and hydro generation business.
Largely as a result of the Company's 1996 assessment of the increased risk of
collecting significantly higher levels of past-due customer bills, bad debt
expense in 1996 was higher than in 1997 by $81.1 million, reducing earnings in
1996, compared to 1997, by 37 cents per share. However, earnings in 1996 were
aided by a $15 million after-tax gain on the sale of a 50 percent interest in
CNP which added 10 cents per share to 1996 earnings. Industrial customer
discounts not recovered in rates in 1997 exceeded 1996 levels by $25.2 million,
reducing 1997 earnings by 11 cents per share. In addition, 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),
as well as, industrial sales increased. As a result, 1997 total public sales
were essentially the same as sales in 1996.
The Company's 1998 earned ROE was -5.3% as compared to 5.5% in 1997 and 2.8%
(5.4% before extraordinary loss) in 1996. 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 regulated gas business. No specific ROE percentage was established
under POWERCHOICE.
The following discussion and analysis highlights items that significantly
affected primarily the regulated operations during the three-year period ended
December 31, 1998. This discussion and analysis is not likely to be indicative
of future operations or earnings, particularly in view of the consummation of
the MRA 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.
REGULATED SEGMENT REVENUES AND SALES
------------------------------------
REGULATED ELECTRIC REVENUES for 1998 were $3,261 million and were $3,309 million
in both 1997 and 1996. Revenues in 1997 and 1996 were the same in aggregate
with variances between customer groups.
The $48.3 million or 1.5% decrease in 1998 regulated electric revenues was
primarily due to a decrease in volume and mix of sales of $44.4 million along
with rate reductions under POWERCHOICE. The decrease was partially offset by
increases in sales of energy to other electric systems. Under POWERCHOICE,
revenues may decline further as customers choose alternative suppliers.
However, the Company will recover stranded costs through the CTC. See "Master
Restructuring Agreement and the POWERCHOICE Agreement."
During 1997, FAC revenues increased $42.8 million, 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.
Increase (decrease) from prior year
(In millions of dollars)
REGULATED ELECTRIC REVENUES 1998 1997 Total
- --------------------------------- ---- ---- -----
Fuel adjustment clause revenues . $ (4.7) $ 42.8 $ 38.1
Changes in volume and mix of
sales to ultimate consumers (44.4) (12.7) (57.1)
Sales to other electric systems . 11.0 (29.6) (18.6)
POWERCHOICE rates . . . . . . . . (10.2) - (10.2)
---------- ------- -------
$ (48.3) $ 0.5 $(47.8)
========== ======= =======
The FAC has been eliminated under the POWERCHOICE agreement. Changes in FAC
revenues generally were 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
resulted in low margin contributions to the Company. Thus, fluctuations in
these revenue components generally did not have a significant impact on net
operating income. With POWERCHOICE, the Company is no longer subject to
regulatory sharing mechanisms for sales to other utilities and transmission
revenues.
REGULATED ELECTRIC KILOWATT-HOUR SALES were 36.4 billion in 1998, 37.1 billion
in 1997 and 39.1 billion in 1996. The 1998 decrease of 0.7 billion KWh, or 1.9%
as compared to 1997, is related primarily to a 4.5% decrease in sales to other
electric systems. See Item 8. Financial Statements and Supplementary Data
- -"Regulated Electric and Gas Statistics - Regulated Electric Statistics."
Sales to ultimate consumers also decreased in 1998 primarily due to warmer
weather during the winter months. After adjusting for the effects of weather
and the farm and food processor retail access pilot program (which the pilot
program has the effect of reducing sales to ultimate consumers), sales to
ultimate consumers would have expected to increase 0.4%. The 1997 decrease of
2.0 billion KWh, or 5.1% as compared to 1996, primarily reflects a 31.0%
decrease in sales to other electric systems.
Details of the changes in regulated electric revenues and KWh sales by customer
group are highlighted in the table below:
1998
% OF % Increase (decrease) from prior year
-------------------------------------
ELECTRIC 1998 1997
CLASS OF SERVICE REVENUES REVENUES SALES Revenues Sales
- ------------------------------ -------- -------- ----- -------- -----
Residential 36.9 (2.1) (2.6) (2.0) (2.0)
Commercial 37.4 (1.1) 0.1 (0.3) (0.1)
Industrial 14.7 (9.5) (4.8) 1.2 0.6
Industrial - Special 2.0 3.3 1.4 5.8 4.2
Other 1.7 1.1 2.6 1.4 (4.5)
----- ----- ----- ------ -------
Total to ultimate consumers 92.7 (2.8) (1.6) (0.6) -
Other electric systems 2.9 13.1 (4.5) (26.1) (31.0)
Miscellaneous 4.4 23.2 - 70.4 (100.0)
----- ----- ----- ------ -------
Total 100.0 (1.5) (1.9) - (5.1)
As indicated in the table below, REGULATED ELECTRIC FUEL AND PURCHASE POWER
COSTS decreased in 1998 by 12.3% or $173.6 million. The decrease is mainly the
result of decreased purchases from the IPPs of $321.9 million. Of this amount,
$80 million relates to net reductions in purchases from IPP Parties for the
period between the closing of the MRA to the POWERCHOICE implementation date,
which were deferred for future rate making disposition because the time lag
between these events was not contemplated in the POWERCHOICE agreement. The
decrease in IPP purchases is primarily the result of the MRA agreement, which
resulted in the termination of 18 PPAs for 1,092 MW, restatement of eight PPAs
for 535 MW and the amendment of one PPA for 42 MW. Other purchased power costs
decreased $8.2 million. As a result, the Company's load requirements were met
to a greater extent from internal sources, which resulted in an increase in fuel
costs of $58.9 million as compared to 1997.
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. 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%.
REGULATED ELECTRIC FUEL AND PURCHASED POWER COSTS
-------------------------------------------------
% Change from prior year
----------------------------
1998 1997 1996 1998 TO 1997 1997 to 1996
---- ---- ---- ------------ ------------
GWH COST GWh Cost GWh Cost GWH COST GWh Cost
---------------------------------------------------------------------------------------
FUEL FOR ELECTRIC GENERATION:
Coal . . . . . . . . . . . 7,988 $ 118.7 7,459 $ 106.4 7,095 $ 100.6 7.1 11.6 5.1 5.8
Oil. . . . . . . . . . . . 1,669 57.1 701 32.2 462 21.1 138.1 77.3 51.7 52.6
Natural gas. . . . . . . . 843 23.3 394 8.6 319 9.2 114.0 170.9 23.5 (6.5)
Nuclear. . . . . . . . . . 7,842 40.0 6,339 33.0 8,243 47.7 23.7 21.2 (23.1) (30.8)
Hydro. . . . . . . . . . . 2,694 - 2,905 - 3,679 - (7.3) - (21.0) -
------ -------- ------ --------- ------ -------- ------ ------ ------ ------
21,036 239.1 17,798 180.2 19,798 178.6 18.2 32.7 (10.1) 0.9
------ -------- ------ --------- ------ -------- ------ ------ ------ ------
ELECTRICITY PURCHASED:
IPP's:
Capacity . . . . . . . . . - 127.9 - 220.8 - 212.8 - (42.1) - 3.8
Energy and taxes . . . . . 9,668 656.7 13,520 885.7 13,797 875.7 (28.5) (25.9) (2.0) 1.1
------ -------- ------ --------- ------ --------- ------ ------ ------ ------
Total IPP purchases . . 9,668 784.6 13,520 1,106.5 13,797 1,088.5 (28.5) (29.1) (2.0) 1.7
Other . . . . . . . . . . . . 8,638 122.0 9,421 130.2 9,569 130.6 (8.3) (6.3) (1.5) (0.3)
------ -------- ------ --------- ------ -------- ------ ------ ------ ------
18,306 906.6 22,941 1,236.7 23,366 1,219.1 (20.2) (26.7) (1.8) 1.4
------ -------- ------ --------- ------ -------- ------ ------ ------ ------
TOTAL GENERATED AND
PURCHASED . . . . . . . 39,342 1,145.7 40,739 1,416.9 43,164 1,397.7 (3.4) (19.1) (5.6) 1.4
Fuel adjustment clause. . . . - 96.3 - (1.3) - (33.3) - -
Losses/Company use. . . . . . 2,910 - 3,603 - 4,037 - (19.2) - (10.8) -
------ -------- ------ --------- ------ -------- ------ ------ ------- ------
36,432 $1,242.0 37,136 $ 1,415.6 39,127 $1,364.4 (1.9) (12.3) (5.1) 3.8
====== ======== ====== ========= ====== ======== ====== ====== ====== ======
The above table presents the total costs for purchased electricity, while
reflecting only fuel costs for Company generation. Other costs of power
production, 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.
There was lower snowfall during the winter months resulting in lower than normal
1998 spring run off. In addition, the January 1998 ice storm damaged several
hydro generation stations. As a result, hydroelectric IPP projects delivered 56
GWh or 3.7% less under PPAs than they did for the same period last year,
representing decreased payments to those IPPs of $1.7 million.
A substantial portion of the Company's portfolio of IPP projects has
historically operated on a "must run" basis. This means that they would 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 2,720
GWh or 33.7% lower than produced last year, mainly due to the closing of the MRA
agreement, which terminated or restructured 13 of the largest contracts of this
type. Separate from the MRA, the Company also bought out two IPP contracts with
intermediate sized cogeneration facilities. See "Master Restructuring
Agreement and the POWERCHOICE Agreement."
Quantities purchased from schedulable cogeneration IPPs also decreased 1,076 GWh
or 27.5% and payments decreased $119.3 million. The decrease in payments is
also mainly due to the closing of the MRA Agreement, which either terminated or
amended all but one of these contract types. See "Master Restructuring
Agreement and the POWERCHOICE Agreement."
REGULATED GAS REVENUES decreased by $91.7 million, or 14.0% in 1998, and
decreased by $24.7 million, or 3.6%, in 1997. As shown in the table below,
regulated gas revenues decreased in 1998 primarily due to decreased sales to
ultimate customers as a result of the migration of commercial sales customers to
the transportation class and due to warmer weather in the winter months.
Regulated gas revenues were also negatively impacted by the regulated gas
commodity cost adjustment clause ("CCAC"). See "Other Federal and State
Regulatory Initiatives - Future of the Natural Gas Industry."
Regulated 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 regulated CCAC recoveries and an increase in revenues
from the transportation of customer-owned gas.
Rates for transported gas (excluding aggregation services) yield lower margins
than gas sold directly by the Company. Therefore, sales 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 CCAC revenues are generally
margin- neutral.
Increase (decrease) from prior year
(In millions of dollars)
REGULATED GAS REVENUES 1998 1997 Total
- ---------------------- ---- ---- -----
Base rates . . . . . . . . . . . . . $ - $ (5.9) $ (5.9)
Transportation of customer-owned gas (1.6) 5.3 3.7
CCAC revenues. . . . . . . . . . . . (38.5) 45.3 6.8
Spot market sales. . . . . . . . . . 2.4 (30.8) (28.4)
Changes in volume and mix of sales
to ultimate consumers. . . . . (54.0) (38.6) (92.6)
-------- ------- --------
$ (91.7) $(24.7) $(116.4)
======== ======= ========
REGULATED GAS SALES, excluding transportation of customer-owned gas and spot
market sales, were 65.0 million Dth in 1998, a 17.3% decrease from 1997.
Regulated gas sales for 1997 decreased 7.3% from 1996. See Item 8. Financial
Statements and Supplementary Data - "Regulated Electric and Gas Statistics -
Regulated Gas Statistics." The decrease in 1998 was in all ultimate consumer
classes, primarily due to the warmer weather. Regulated gas revenues were also
negatively impacted by a decrease in transportation volumes of 24.9 million Dth
or 16.3% to customers purchasing gas directly from producers mainly as a result
of the termination and restatement of the PPAs as part of the MRA. The
decreases were partially offset by increased spot market sales (sales for
resale), which are generally from higher priced gas available to the Company
and, therefore, yield margins that are substantially lower than traditional
sales to ultimate customers.
Changes in regulated gas revenues and Dth sales by customer group are detailed
in the table below:
1998
% OF % Increase (decrease) from prior year
-------------------------------------
GAS 1998 1997
CLASS OF SERVICE REVENUES REVENUES SALES Revenues Sales
- ------------------------------------ -------- -------- ----- -------- -----
Residential 66.9 (13.3) (14.4) 4.5 (2.7)
Commercial 19.6 (25.4) (22.9) (8.7) (13.0)
Industrial 0.6 (44.8) (45.5) (50.9) (50.1)
----- ------ ------ ------ ------
Total to ultimate consumers 87.1 (16.7) (17.3) (0.3) (7.3)
Other gas systems - (46.9) (39.3) (5.8) (6.7)
Transportation of customer-owned gas 9.6 (2.8) (16.3) 10.5 13.5
Spot market sales 1.5 37.9 83.6 (82.9) (76.6)
Miscellaneous 1.8 155.7 - 263.1 -
----- ------ ------ ------ ------
Total 100.0 (14.0) (15.6) (3.6) 1.7
The total cost of GAS PURCHASED decreased 21.3% in 1998 and decreased 6.6% in
1997. The cost fluctuations generally correspond to sales volume changes, as
well as a decrease in gas prices. The Company sold 4.5, 2.5 and 10.5 million
Dth on the spot market in 1998, 1997 and 1996, respectively. The total cost of
gas decreased $73.5 million in 1998. This was the result of a 19.3 million
decrease in Dth purchased and withdrawn from storage for ultimate consumer sales
($71.7 million), a 1.3% decrease in the average cost per Dth purchased ($3.5
million) and a $1.0 million decrease in purchased gas costs and certain other
items recognized and recovered through the CCAC. These decreases were partially
offset by a $2.7 million increase in Dth purchased for spot market sales.
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 CCAC.
Through the electric FAC and gas CCAC, costs of fuel, purchased power and gas
purchased, above or below the levels allowed in approved rate schedules, are
billed or credited to customers. In the past, the Company's electric FAC
provided 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 $1.4
million and $13.1 million in 1996 and 1997, and $11.0 million for the first
eight months in 1998, respectively. Effective September 1, 1998, under
POWERCHOICE, the electric FAC has been eliminated. The Company does not believe
that the elimination of the electric 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 auction of the fossil and hydro assets;
(ii) fixed price and quantity 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 increased in 1998 by $102.5 million, or
12.3%, as compared to a decrease of $92.9 million or 10% in 1997. The increase
in 1998 is primarily the result of costs associated in the 1998 storms (see
"1998 Storms") and increased nuclear costs of $8 million mostly due to the
extended Unit 2 refueling outage. Other operation and maintenance expense
decreased in 1997 mainly due to lower bad debt expense. During 1996, the
Company changed its method of assessing uncollectible customer accounts to give
greater recognition to the increased risk of collecting past due customer bills,
which resulted in significantly higher bad debt expense recognition in 1996 as
compared to 1997. Bad debt expense was $127.6 million, $46.5 million and $31.7
million in 1996, 1997 and 1998, respectively. 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 increased by $17.6 million in 1998 and decreased by $10.9 million
in 1997. Other income increased in 1998 mainly due to the deferral of MRA
financing costs, which are reflected in interest charges, due to the delay in
the implementation of POWERCHOICE. The increase was partially offset by lower
interest income, which reflects the use of cash and also by lower subsidiary
earnings.
Despite higher interest income ($12.0 million) related to increasing cash
balances, OTHER INCOME was lower in 1997, since 1996 reflected a gain on the
sale of a 50% interest in CNP ($15.0 million).
INTEREST CHARGES increased in 1998 by $123.3 million after having remained
fairly constant for the years 1996 and 1997. The increase in 1998 is mainly due
to the interest charges incurred on the debt issued in connection with the MRA.
Dividends on preferred stock decreased by $0.8 million and $0.9 million in 1998
and 1997, respectively, primarily due to a reduction in preferred stock
outstanding through sinking fund redemptions. The weighted average long-term
debt interest rate and preferred dividend rate paid, reflecting the actual cost
of variable rate issues, changed to 7.46% and 7.00%, respectively, in 1998 from
7.81% and 7.04%, respectively, in 1997.
FEDERAL AND FOREIGN INCOME TAXES decreased by $193.3 million in 1998 primarily
due to a decrease in pre-tax income and increased by $24.1 million in 1997
primarily due to an increase in pre-tax income. Other taxes decreased by $11.5
million in 1998 and decreased by $4.4 million in 1997. The 1998 decrease is
mainly due to a reduction in GRT taxes of $17.6 million primarily due to the
lower sales revenue for the year and due to the GRT credits received for
customers in the Company's service territory that participate in New York
State's Power for Jobs program. The 1997 decrease was primarily due to lower
payroll taxes ($2.3 million) and lower sales taxes ($0.7 million).
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 utility assets 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 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, 1998 and
1997 was as follows:
% 1998 1997
- ---------------- ---- ----
Long-term debt . 64.6 51.8
Preferred stock. 4.9 7.7
Common equity. . 30.5 40.5
The closing of the MRA has significantly increased the leverage of the Company.
Under the MRA, the Company paid an aggregate of $3.934 billion in cash, of which
$3.212 billion was obtained through a public market offering of senior unsecured
debt, $303.7 million from the public sale of 22.4 million shares of common
stock, and the remainder from cash on hand. In addition, the Company issued
20.5 million shares of common stock to the IPP Parties. Through the anticipated
increased operating cash flow resulting from the MRA and POWERCHOICE agreement
and the sale of the generation assets, the planned rapid repayment of debt
should deleverage the Company over time. Book value of the common stock was
$16.92 per share at December 31, 1998, as compared to $18.89 per share at
December 31, 1997. With the issuance of common stock at below book value to
the IPP Parties as part of the MRA and the one-time non-cash write-off
associated with the portion of the MRA regulatory asset disallowed in rates by
the PSC, book value per share and earnings per share have been diluted.
The 1998 ratio of earnings to fixed charges was 0.57 times. The ratios of
earnings to fixed charges for 1997 and 1996 were 2.02 times and 1.57 times,
respectively. The change in the ratio is primarily due to the consummation of
the MRA, since the MRA and POWERCHOICE agreements 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 result of the
MRA was to convert a large and growing off-balance sheet payment obligation that
threatened the financial viability of the Company into a fixed and more
manageable capital obligation.
The Company's EBITDA for 1998 was approximately $990.5 million. After the
changes from POWERCHOICE and the MRA are fully reflected in a consecutive
12-month period, EBITDA is expected to increase to approximately $1.2 billion to
$1.3 billion per year. EBITDA represents earnings before interest charges,
interest income, income taxes, depreciation and amortization, amortization of
nuclear fuel, allowance for funds used during construction, non-cash regulatory
deferrals and other amortizations and extraordinary items. The ratio of EBITDA
to net cash interest for 1998 was 2.9 times. Net cash interest is defined as
interest charges plus allowance for funds used during construction less the
non-cash impact of the net amortization of discount on long-term debt and
interest accrued on the Nuclear Waste Policy Act liability less interest income.
The ratio of EBITDA to net cash interest is also expected to improve as the
results of the MRA and POWERCHOICE are fully reflected in a consecutive 12-month
period and the Company reduces its debt. 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. 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.
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
addressed 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, limitations on
dividend payments under the POWERCHOICE agreement, limitations on common stock
dividends in indenture agreements, 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 stock dividends that can be
paid by the regulated business. The POWERCHOICE agreement limits the amount of
common stock dividends that can be paid by the regulated company to the holding
company, but does not limit the dividends the holding company may pay to its
shareholders. The limit under POWERCHOICE is based upon the amount of net
income each year of the regulated company, plus a specified amount ranging from
$50 million in 1998 to $100 million in 2000 and declining thereafter through
2007. The limitation excludes one-time dividends associated with asset sales.
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 " Master Restructuring Agreement and the
POWERCHOICE 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,"), nuclear decommissioning funding
requirements (See Item 8. Financial Statements and Supplementary Data - "Note 3.
Nuclear Operations - Nuclear Plant Decommissioning"), working capital needs,
maturing debt issues and sinking fund provisions on preferred stock. Annual
expenditures for the years 1996 to 1998 for construction and nuclear fuel,
including related AFC and overheads capitalized, were $352.1 million, $290.8
million and $351.2 million, respectively, and are budgeted to be approximately
$300 million for 1999 and to range from $266 - $312 million for each of the
subsequent three years. Capital expenditures for 1998 increased primarily due
to the costs incurred to rebuild a portion of the Company's regulated electric
transmission and distribution facilities as a result of several storms in 1998
(see "1998 Storms"). The estimate for 1999 and beyond excludes construction
expenditures relating to the fossil and hydro generation assets.
Mandatory debt and preferred stock retirements are expected to add approximately
another $320 million to the 1999 estimate of capital requirements. In addition,
the Company is obligated to reduce the Senior Debt outstanding by using 85% of
the net proceeds of the sale of the generation assets within 180 days after the
receipt of such proceeds. As of December 31, 1998, the Company has entered
into agreements for the sale of its hydroelectric and coal-fired generation
assets for $780 million. It is anticipated that transaction closings will
occur in mid-1999 after receipt of the necessary regulatory approvals. The
Company is also pursuing the sale of its oil and gas-fired, and nuclear
generation assets. The Company may also use the positive cash flow generated
as a result of the MRA and the cash tax benefits received as a result of the tax
net operating loss generated from the MRA to further reduce debt. The estimate
of construction additions included in capital requirements for the period 1999
to 2003 will be reviewed by management to give effect to 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 the five-year period, 1999 to 2003.
LIQUIDITY AND CAPITAL RESOURCES. External financing plans are subject to
periodic revision as underlying assumptions are changed to reflect developments
and market conditions. The ultimate level of financing during the period 1999
through 2003 will be affected by, among other things: the cash tax benefits
anticipated because the MRA generated a net tax operating loss carryforward in
1998; the implementation of the POWERCHOICE agreement, levels of common dividend
payments, if any, and preferred dividend payments; the results of the sale of
the Company's generation assets; the Company's competitive position and
the extent to which competition penetrates the Company's markets; potential
future actions with respect to IPPs not covered under the MRA; and uncertain
energy demand due to the weather and economic conditions. The proceeds of the
sale of the generation assets will be subject to the terms of the Company's
mortgage indenture and the note indenture that was 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 "NRC Policy Statement
and Amended Decommissioning Funding Regulations"). The Company does not
anticipate the need to incur any additional financing in 1999 and expects that
all capital needs can be met internally. However, the Company may refinance
existing debt to take advantage of lower interest rates.
The Company has an $804 million senior bank financing 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 bank
financing is variable based on certain rate options available under the
agreement and currently approximates 6.5% (but is capped at 15%). As of
December 31, 1998, the amount outstanding under the senior bank financing was
$529 million, consisting of $105 million under the term loan facility and $424
million of letters of credit, leaving the Company with $275 million of borrowing
capability under the financing. The Company amended the financing as of June
30, 1998. The amendment, which included an extension of the term from June 30,
1999 to June 1, 2000, also accommodates the holding company structure and
permits the auction of fossil and hydro generating assets.
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"). The Company has the ability
to issue First Mortgage Bonds to the extent that there have been redemptions
since June 30, 1998. The Company redeemed $60 million First Mortgage Bonds in
August 1998.
During November 1998, the Company refinanced its 8-7/8 percent series of
tax-exempt bonds issued through NYSERDA. The $75 million bonds were refinanced
at 5.15 percent. The refinancing will reduce interest expense by approximately
$2.8 million per year, not including the costs of issuance.
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 that
credit ratings could decline or not increase if the current expectation of
stranded cost recovery is endangered.
In December 1998, the Company received a ruling from the IRS to the effect that
the amount of cash and the value of common stock that was paid to the terminated
IPP Parties will be currently deductible and generate a substantial net
operating loss ("NOL") for federal income tax purposes, such that the Company
will not pay taxes for 1998. Further, the Company has carried back unused NOL
to the years ended 1996 and 1997, and also for the years 1988 through 1990,
which has resulted in tax refunds of $130 million and $5 million, respectively,
received in January 1999. In addition, the Company anticipates that it will be
able to utilize the remaining $3.3 billion NOL deductions carried over to future
years before the expiration date in 2019. The Company's ability to utilize the
NOL generated as a result of the MRA could be limited under the rules of section
382 of the Internal Revenue Code if certain changes in the Company's common
stock ownership were to occur in the future. In general, the limitation is
triggered by a more than 50% change in stock ownership during a three-year
testing period by shareholders that own, directly or indirectly, 5% or more of
the common stock. For purposes of making the change in ownership computation,
the IPP Parties who were issued common stock pursuant to the MRA are likely to
be considered a separate 5% shareholder group, as will the purchasers of common
stock in the public offering completed immediately prior to consummation of the
MRA. Under the computational rules prescribed by applicable Treasury
regulations, the aggregate increase in stock ownership experienced by these
shareholder groups as a result of their participation in the public offering and
the MRA was likely no greater than 17%. Thus, if the IPP Parties, the
purchasers in the public offering, and any other 5% shareholders collectively
experience ownership increases totaling more than 33% during any three year
testing period that includes the consummation dates of the public offering and
the MRA, the statutory threshold could be breached and the NOL limitation would
in that event apply. The rules for determining change in stock ownership for
purposes of Code Section 382 are extremely complicated and in many respects
uncertain. A stock ownership change could occur as a result of circumstances
that are not within the control of the Company. If a more than 50% change in
ownership were to occur, the Company's remaining usable NOL likely would be
significantly lower in the future than the NOL amount which otherwise would be
usable absent the limitation. Consequently, the Company's net cash position
could be significantly lower as a result of tax liabilities, which otherwise
would be eliminated or reduced through unrestricted use of the NOL.
During 1995, past due accounts receivable increased significantly. A number of
factors 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.
In 1996, the Company increased its allowance for doubtful accounts because of
its reassessment of the collection risk associated with residential accounts
receivable and arrears. Over the last several years, the Company has
implemented a number of collection initiatives that have resulted in lower
arrears levels, and in 1998, the Company lowered its allowance for doubtful
accounts.
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 in 1996 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 wrote-off a substantial
number of these accounts as well as increased its allowance for doubtful
accounts in 1996 and 1997. In 1998, 1997 and 1996, the Company charged $31.7
million, $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 improvement in collection
efforts, future results are necessarily dependent upon the following factors,
including, among other things, the effectiveness of the strategies implemented
to date, 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 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 to customers but not increase collection
risk to the Company. The Company is actively pursuing these issues before the
PSC.
NET CASH USED IN OPERATING ACTIVITIES increased $3,778.0 million in 1998
primarily due to the consummation of the MRA.
NET CASH USED IN INVESTING ACTIVITIES increased $53.1 million in 1998 primarily
as a result of an increase in the acquisition of utility plant of $98.1 million,
mainly due to the January 1998 ice storm and the September 1998 windstorm.
NET CASH PROVIDED BY FINANCING ACTIVITIES increased $3,573.1 million, primarily
due to the issuance of the senior notes and public sale of common stock used to
consummate the MRA.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The financial instruments held or issued by the regulated business are for
purposes other than trading. The Company's energy marketing subsidiary engages
in both trading and non-trading activities.
Quantitative and qualitative disclosures are discussed by market risk exposure
category:
- - Interest Rate Risk
- - Commodity Price Risk
- - Equity Price Risk
- - Foreign Currency Exchange Risk
The Company has a foreign currency exchange risk as a result of its
investments in Canada through its subsidiary Opinac Energy Corporation.
Translation adjustments due to exchange rate movement across the value of
the subsidiary is reported in Capitalization as a Foreign Currency
Translation Adjustment (see "Note 5. - Capitalization") and is a component
of Comprehensive Income. See " Consolidated Statements of Comprehensive
Income." In aggregate, the risk of loss does not pose a material threat
to the Company's consolidated results of operations or total
capitalization.
The Company maintains a Financial Risk Management Policy Manual (the "Policy")
applicable to the regulated company that outlines the parameters within which
corporate managers are to engage in, manage, and report on various areas of risk
exposure. At the core of the Policy is a condition that the Company will engage
in activities at risk, only to the extent that those activities fall within
commodities and financial markets to which it has a physical market exposure, in
terms and in volumes consistent with its core business. That core business is
to supply energy, in the form of electricity and natural gas to customers within
the Company's service territory. The policies of the Company may be revised as
its primary markets continue to change, principally as increased competition is
introduced and the role of the Company in these markets evolves.
The Company's energy marketing subsidiary maintains a separate Risk Management
and Trading Policy Manual that allows for transactions such as marketing and
trading in retail and wholesale, physically and financially settled, energy
based instruments. These actions expose this subsidiary to a number of risks
such as forward price, deliverability, market liquidity and credit risk. Like
the Company's Policy, the energy trading policy seeks to assure that risks are
identified, evaluated and actively managed.
INTEREST RATE RISK. The Company's exposure to changes in interest rates is due
to its financing through a senior debt facility, several series of adjustable
rate promissory notes and adjustable rate preferred stock. See "Note 5.
Capitalization" and "Note 6. Bank Credit Arrangements." Under the senior debt
facility, the Company currently has an outstanding term loan of $105 million.
The adjustable rate promissory notes are currently valued at $413.8 million, and
the Company has $122.5 million outstanding in adjustable rate preferred stock.
There is no interest rate cap on the promissory notes. The interest on the term
loan is variable but capped at 15%.
Dividend rates for the preferred stock are indexed to U.S. government interest
bearing securities plus or minus an amount stipulated in each series and have
floors of 6.5% to 7.0% and caps of between 13.5% and 16.5%. As of December 31,
1998, the rate calculated on the index for each series is below the floor;
therefore, the current rate is equal to the floor. Future changes in the
indexed rate will not result in an exposure to higher dividend rates until the
floor is exceeded. However, for the purposes of the following sensitivity
analysis, a hypothetical one percent increase from the floor dividend rate is
assumed.
The Company also maintains long term debt at fixed interest rates. A
controlling factor on the exposure to interest rate variations is the mix of
fixed to variable rate instruments maintained by the Company. All adjustable
rate instruments comprise 6.4% of total capitalization. The term loan and
promissory notes are 7.7% of total long-term debt, thus limiting Company
exposure to interest rate fluctuations.
If interest rates averaged one percent more in 1999 versus 1998, the Company's
interest expense would increase and income before taxes decrease by
approximately $5.2 million. This figure was derived by applying the
hypothetical one percent variance across the variable rate debt of $518.8
million at December 31, 1998 (the sum of the term loan and promissory notes).
The same one percent increase in the preferred dividend rate applied against the
outstanding balance of $122.5 million would result in an increase to dividend
payments of $1.2 million, assuming that the indexed rate was between the floor
and cap. Under POWERCHOICE, prices to customers are fixed for three years, with
limited increases available in years four and five, if justified by the Company.
Changes in the actual cost of capital from levels assumed in POWERCHOICE would
create either exposure or opportunity for the Company until reflected in future
prices.
COMMODITY PRICE RISK. The Company is exposed to market fluctuations in the
prices for electricity, natural gas, coal, and oil. The Company, exclusive of
its energy marketing subsidiary, does not, generally, speculate on movements in
the underlying prices for these commodities. Purchases are based on analyses
performed in relation to fuel needs for power generation and customer delivery
for electricity and natural gas. Where possible, the Company takes positions in
order to mitigate expected price increases but only to the extent that
quantities are based on expectations of delivery. The Company attempts to
mitigate exposure through a program that hedges risks as appropriate.
Niagara Mohawk Energy, Inc., a wholly owned subsidiary of the Company, does
engage in both trading and non-trading activities.
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 change. At December 31, 1998, there were no open trading
positions.
Activities for non-trading purposes generally consist of transactions entered
into to hedge the market fluctuations of contractual and anticipated
commitments. Gas futures are used for hedging purposes. Changes in market
value of futures contracts relating to hedged items are deferred until the
physical transaction occurs, at which time, income or loss is recognized. The
fair value of open positions for non-trading purposes at December 31, 1998, as
well as the effect of these activities on the Company's results of operations
for the same period ending, was not material.
The fair values of futures and forward contracts are determined using quoted
market prices or broker's quotes.
The commodity risk exposure of Niagara Mohawk Energy, Inc. does not constitute a
material risk of loss to the Company.
The regulated company, as part of the MRA, entered into restated indexed swap
contracts with eight IPPs. See Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations - Master Restructuring Agreement
and the POWERCHOICE Agreement for a more detailed discussion of the indexed swap
contracts.
The fair value of the liability under the indexed swap contracts, based upon the
difference between projected future market prices and projected indexed contract
prices applied to the notional quantities and discounted at 8.5% is
approximately $693 million and is recorded on the balance sheet as a liability
for indexed swap contracts. The discount rate is based upon comparable debt
instruments of the Company. Based upon the PSC's approval of the restated
contracts, including the indexed swap contracts, as part of the MRA and being
provided a reasonable opportunity to recover the estimated indexed swap
liability from customers, the Company has recorded a corresponding regulatory
asset. The amount of the recorded liability and regulatory asset is sensitive
to changes in discount rate, anticipated future market prices and changes in the
indices upon which the indexed swap contracts are based. However, changes in
anticipated future market prices and discount rates will not impact the future
cash flow of the Company when considering the all-in price of the notional
quantities of energy. Specifically, as market prices rise or fall, payments
under the indexed swap contracts move inversely. Similarly, changes in discount
rates will not impact the all-in price. If the indexed contract price were to
increase or decrease by one percent, the Company would see a $15.5 million
increase or decrease in the present value of the projected over-market exposure.
If the market prices were to increase or fall by one percent, the Company would
see a $7.5 million decrease or increase in the projected over-market exposure.
If the discount rate were to increase or decrease to 9.0% or 8.0%, the net
present value of the projected over market exposure would decrease or increase
by approximately $10.5 million.
Under POWERCHOICE, the Company agreed to divest of its fossil generation assets
through an auction process. As of December 31, 1998, the Company has reached an
agreement to sell its coal-fired generation plants with an anticipated close in
mid-1999. The Company continues to pursue the sale of its two oil and gas-fired
generation plants. Central Hudson Gas and Electric Corporation has indicated
that the sale of the Company's share of the Roseton Steam Station is not
expected to close until mid-2000. The terms of these sales call for the new
owners to take possession of the existing fuel inventory at book value.
Because of these anticipated sales and the level of coal and oil inventory on
hand at December 31, 1998, the Company will not be exposed to any significant
commodity price risks for fuel used in generation in 1999 and beyond.
The Company has an exposure to market price fluctuations for the cost of the
natural gas sold to customers. The gas prices are most volatile in the winter
months. The Company has adopted a policy to reduce the variability in gas
costs, primarily over the winter months. The Company has accomplished this by
limiting or eliminating gas price volatility on four contracts and through the
use of stored gas supplies where the price is already fixed. These two factors,
as compared to the winter gas needs, allow the Company to reduce or eliminate
volatility on approximately 49% of anticipated demand.
The remaining gas needs of the Company are met through spot market purchases and
are subject to market price fluctuations. However, the Company has a gas
commodity cost adjustment clause (CCAC) built into its approved rate structure
that limits this risk. This pricing mechanism calls for a 50/50 sharing,
between customers and stockholders, of the variability between a target price
for gas and actual purchases up to $2.25 million annually. Variability greater
than $2.25 million accrues to or is borne by the customers.
EQUITY PRICE RISK. The NRC requires nuclear plant owners to place funds in an
external trust to provide for the cost of decommissioning of the contaminated
portions of nuclear facilities. See "Note 3. - Nuclear Operations." The
Company has established qualified and non-qualified trust funds for Unit 1 and
Unit 2. As of December 31, 1998, these funds were invested in fixed income
securities, domestic equity securities, and cash equivalents. The fixed income
securities are subject to interest rate fluctuations and the equity securities
to price change in the equity markets. The funds asset allocation is designed
to maximize returns commensurate with the Company's risk tolerance.
The Company's investment policy for managing the nuclear decommissioning trust
funds conforms to NRC guidelines. The policy's main objective is to assure that
the growth in the decommissioning funds, together with Company contributions,
will ultimately provide sufficient funds to decommission Units 1 and 2. This
objective is met by optimizing the return; maintaining a diversified portfolio;
and seeking a return competitive with like institutions employing similar
strategies.
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 31,1998
- - Consolidated Statements of Comprehensive Income for each of the three
years in the period ended December 31, 1998
- - Consolidated Balance Sheets at December 31, 1998 and 1997
- - Consolidated Statements of Cash Flows for each of the three years in the
period ended December 31, 1998
- - 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 PricewaterhouseCoopers LLP, the
Company's independent accountants, in accordance with GAAP. In planning and
performing its audit, PricewaterhouseCoopers 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 PricewaterhouseCoopers LLP to review and
discuss internal accounting controls, audit examinations and financial reporting
matters. PricewaterhouseCoopers 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, of cash flows and of
comprehensive income present fairly, in all material respects, the financial
position of Niagara Mohawk Power Corporation and its subsidiaries at December
31, 1998 and 1997, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1998, 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.
/s/PricewaterhouseCoopers LLP
- -----------------------------
PricewaterhouseCoopers LLP
Syracuse, New York
January 28, 1999
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For the year ended December 31,
1998 1997 1996
---- ---- ----
(In thousands of dollars)
OPERATING REVENUES:
Electric . . . . . . . . . . . . . . . . . . . . $ 3,261,144 $3,309,441 $3,308,979
Gas. . . . . . . . . . . . . . . . . . . . . . . 565,229 656,963 681,674
-------------------- ---------- -----------
3,826,373 3,966,404 3,990,653
-------------------- ---------- -----------
OPERATING EXPENSES:
Fuel for electric generation . . . . . . . . . . 239,982 179,455 181,486
Electricity purchased. . . . . . . . . . . . . . 1,001,991 1,236,108 1,182,892
Gas purchased. . . . . . . . . . . . . . . . . . 272,141 345,610 370,040
Other operation and maintenance expenses . . . . 937,798 835,282 928,224
POWERCHOICE charge (Note 2). . . . . . . . . . . 263,227 - -
Amortization of the MRA regulatory asset . . . . 128,833 - -
Depreciation and amortization (Note 1) . . . . . 355,417 339,641 329,827
Other taxes. . . . . . . . . . . . . . . . . . . 459,961 471,469 475,846
-------------------- ---------- -----------
3,659,350 3,407,565 3,468,315
------------------- ---------- -----------
OPERATING INCOME . . . . . . . . . . . . . . . . . . 167,023 558,839 522,338
Other income (deductions) (Note 1) . . . . . . . . . 42,602 24,997 35,943
-------------------- ---------- -----------
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . 209,625 583,836 558,281
Interest charges (Note 1). . . . . . . . . . . . . . 397,178 273,906 278,033
-------------------- ---------- -----------
INCOME (LOSS) BEFORE FEDERAL AND FOREIGN
INCOME TAXES . . . . . . . . . . . . . . . . . . (187,553) 309,930 280,248
Federal and foreign income taxes (Note 7). . . . . . (66,728) 126,595 102,494
-------------------- ---------- -----------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM. . . . . . . (120,825) 183,335 177,754
Extraordinary item for the discontinuance of
regulatory accounting principles, net of income
taxes of $36,273 (Note 2) . . . . . . . . . . . . - - (67,364)
-------------------- ---------- -----------
NET INCOME (LOSS). . . . . . . . . . . . . . . . . . (120,825) 183,335 110,390
Dividends on preferred stock . . . . . . . . . . . . 36,555 37,397 38,281
-------------------- ---------- -----------
BALANCE AVAILABLE FOR COMMON STOCK . . . . . . . . . (157,380) 145,938 72,109
Retained earnings at beginning of year . . . . . . . 803,420 657,482 585,373
-------------------- ---------- -----------
Retained earnings at end of year . . . . . . . . . . $ 646,040 $ 803,420 $ 657,482
==================== ========== ===========
AVERAGE NUMBER OF SHARES OF COMMON STOCK
OUTSTANDING (IN THOUSANDS) . . . . . . . . . . . 166,186 144,404 144,350
BASIC AND DILUTED EARNINGS (LOSS) PER AVERAGE SHARE
OF COMMON STOCK BEFORE EXTRAORDINARY ITEM. . . . $ (0.95) $ 1.01 $ 0.97
EXTRAORDINARY ITEM . . . . . . . . . . . . . . . . . - - (0.47)
-------------------- ---------- -----------
BASIC AND DILUTED EARNINGS PER AVERAGE SHARE
OF COMMON STOCK . . . . . . . . . . . . . . . . . $ (0.95) $ 1.01 $ 0.50
==================== ========== ===========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the year ended December 31,
1998 1997 1996
----------------- --------- ---------
(In thousands of dollars)
NET INCOME (LOSS) . . . . . . . . . . . . . . . . . . . $ (120,825) $183,335 $110,390
---------------- --------- ---------
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gains (losses) on securities, net of tax. 304 6 (231)
Foreign currency translation adjustment. . . . . . . (6,896) (4,567) (708)
---------------- --------- ---------
OTHER COMPREHENSIVE INCOME (LOSS) . . . . . . . . . . . (6,592) (4,561) (939)
---------------- --------- ---------
COMPREHENSIVE INCOME (LOSS) . . . . . . . . . . . . . . $ (127,417) $178,774 $109,451
================ ========= =========
( ) Denotes deduction
The accompanying notes are an integral part of these financial statements.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
December 31,
1998 1997
---------------- ------------
ASSETS (In thousands of dollars)
UTILITY PLANT (NOTE 1):
Electric plant. . . . . . . . . . . . . . . . . . . . . . . $ 8,826,650 $ 8,752,865
Nuclear fuel. . . . . . . . . . . . . . . . . . . . . . . . 604,213 577,409
Gas plant . . . . . . . . . . . . . . . . . . . . . . . . . 1,179,716 1,131,541
Common plant. . . . . . . . . . . . . . . . . . . . . . . . 349,066 319,409
Construction work in progress . . . . . . . . . . . . . . . 471,802 294,650
---------------- -----------
TOTAL UTILITY PLANT. . . . . . . . 11,431,447 11,075,874
Less - Accumulated depreciation and amortization. . . . . . 4,553,488 4,207,830
---------------- -----------
NET UTILITY PLANT. . . . . . . . . 6,877,959 6,868,044
---------------- -----------
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . . . . . . . . 411,106 371,709
---------------- -----------
CURRENT ASSETS:
Cash, including temporary cash investments
of $122,837 and $315,708, respectively. . . . . . . . 172,998 378,232
Accounts receivable (less allowance for doubtful accounts
of $47,900 and $62,500, respectively) (Notes 1 and 9) 427,588 492,244
Materials and supplies, at average cost:
Coal and oil for production of electricity. . . . . . 42,299 27,642
Gas storage . . . . . . . . . . . . . . . . . . . . . 38,803 39,447
Other . . . . . . . . . . . . . . . . . . . . . . . . 118,855 118,308
Refundable Federal income taxes . . . . . . . . . . . . . . 130,411 -
Prepaid taxes . . . . . . . . . . . . . . . . . . . . . . . 17,282 15,518
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,208 20,309
---------------- -----------
970,444 1,091,700
---------------- -----------
REGULATORY ASSETS (NOTE 2):
MRA regulatory asset . . . . . . . . . . . . . . . . . . . 4,045,647 7,516
Indexed swap contracts regulatory asset. . . . . . . . . . 535,000 -
Regulatory tax asset . . . . . . . . . . . . . . . . . . . 425,898 399,119
Deferred finance charges . . . . . . . . . . . . . . . . . - 239,880
Deferred environmental restoration costs (Note 9). . . . . 220,000 220,000
Unamortized debt expense . . . . . . . . . . . . . . . . . 51,922 57,312
Postretirement benefits other than pensions. . . . . . . . 52,701 56,464
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 137,061 196,533
---------------- -----------
5,468,229 1,176,824
---------------- -----------
OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133,449 75,864
---------------- -----------
$ 13,861,187 $ 9,584,141
================ ===========
The accompanying notes are an integral part of these financial statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
December 31,
1998 1997
---- ----
CAPITALIZATION AND LIABILITIES (In thousands of dollars)
CAPITALIZATION (NOTE 5):
COMMON STOCKHOLDERS' EQUITY:
Common stock, issued 187,364,863 and 144,419,351, respectively. $ 187,365 $ 144,419
Capital stock premium and expense . . . . . . . . . . . . . . . 2,358,380 1,794,739
Accumulated other comprehensive income. . . . . . . . . . . . . (21,643) (15,051)
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . 646,040 803,420
---------------- -----------
3,170,142 2,727,527
Non-redeemable preferred stock . . . . . . . . . . . . . . . . . . . 440,000 440,000
Mandatorily redeemable preferred stock . . . . . . . . . . . . . . . 68,990 76,610
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,417,225 3,417,381
---------------- -----------
TOTAL CAPITALIZATION. . . . . . . . . . . . . . . . . . . . . . 10,096,357 6,661,518
---------------- -----------
CURRENT LIABILITIES:
Long-term debt due within one year (Note 5) . . . . . . . . . . . . 312,240 67,095
Sinking fund requirements on redeemable preferred stock (Note 5). . 7,620 10,120
Accounts payable. . . . . . . . . . . . . . . . . . . . . . . . . . 197,124 263,095
Payable on outstanding bank checks. . . . . . . . . . . . . . . . . 39,306 23,720
Customers' deposits . . . . . . . . . . . . . . . . . . . . . . . . 17,148 18,372
Accrued taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,254 9,005
Accrued interest. . . . . . . . . . . . . . . . . . . . . . . . . . 132,236 62,643
Accrued vacation pay. . . . . . . . . . . . . . . . . . . . . . . . 38,727 36,532
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91,877 64,756
---------------- -----------
842,532 555,338
---------------- -----------
REGULATORY AND OTHER LIABILITIES (NOTE 2):
Deferred finance charges. . . . . . . . . . . . . . . . . . . . . . - 239,880
Accumulated deferred income taxes (Notes 1 and 7) . . . . . . . . . 1,511,417 1,387,032
Employee pension and other benefits (Note 8). . . . . . . . . . . . 235,376 240,211
Unbilled revenues (Note 1). . . . . . . . . . . . . . . . . . . . . 30,652 43,281
Liability for indexed swap contracts (Note 10). . . . . . . . . . . 693,363 -
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 231,490 236,881
---------------- -----------
2,702,298 2,147,285
---------------- -----------
COMMITMENTS AND CONTINGENCIES (NOTES 2 AND 9):
Liability for environmental restoration. . . . . . . . . . . . . . 220,000 220,000
---------------- -----------
$ 13,861,187 $9,584,141
================ ===========
The accompanying notes are an integral part of these financial statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
INCREASE (DECREASE) IN CASH
FOR THE YEAR ENDED DECEMBER 31,
1998 1997 1996
---- ---- ----
(In thousands of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . $ (120,825) $ 183,335 $ 110,390
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
POWERCHOICE charge. . . . . . . . . . . . . . . . . . . . . . 263,227 - -
Extraordinary item for the discontinuance of regulatory
accounting principles, net of income taxes . . . . . . . . - - 67,364
Depreciation and amortization . . . . . . . . . . . . . . . . 355,417 339,641 329,827
Amortization of MRA regulatory asset. . . . . . . . . . . . . 128,833 - -
Amortization of nuclear fuel. . . . . . . . . . . . . . . . . 30,798 25,241 38,077
Provision for deferred income taxes . . . . . . . . . . . . . 97,606 46,994 (6,870)
Gain on sale of subsidiary. . . . . . . . . . . . . . . . . . - - (15,025)
Unbilled revenues . . . . . . . . . . . . . . . . . . . . . . (12,629) (6,600) 21,471
Net accounts receivable . . . . . . . . . . . . . . . . . . . 64,656 (118,939) 121,198
Materials and supplies. . . . . . . . . . . . . . . . . . . . (14,341) (1,306) 2,265
Accounts payable and accrued expenses . . . . . . . . . . . . (38,712) (11,175) 8,224
Accrued interest and taxes. . . . . . . . . . . . . . . . . . 66,842 4,180 (11,750)
MRA regulatory asset. . . . . . . . . . . . . . . . . . . . . (3,959,508) (7,516) -
Refundable Federal income taxes . . . . . . . . . . . . . . . (130,411) - -
Changes in other assets and liabilities . . . . . . . . . . . 28,592 83,720 35,231
---------------- ---------- ---------
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES. (3,240,455) 537,575 700,402
---------------- ---------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction additions. . . . . . . . . . . . . . . . . . . . . (365,396) (286,389) (296,689)
Nuclear fuel. . . . . . . . . . . . . . . . . . . . . . . . . . (26,804) (4,368) (55,360)
Less: Allowance for other funds used during construction. . . . 8,626 5,310 3,665
---------------- ---------- ----------
Acquisition of utility plant. . . . . . . . . . . . . . . . . . (383,574) (285,447) (348,384)
Materials and supplies related to construction. . . . . . . . . (219) 1,042 8,362
Accounts payable and accrued expenses related to construction . (9,678) (2,794) 2,056
Other investments . . . . . . . . . . . . . . . . . . . . . . . (35,069) (115,533) 541
Proceeds from sale of subsidiary (net of cash sold) . . . . . . - - -
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (18,551) 8,761 (8,786)
---------------- ---------- ----------
NET CASH USED IN INVESTING ACTIVITIES. . . . . . . . (447,091) (393,971) (331,611)
---------------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock. . . . . . . . . . . . . . . . . . . . 316,389 - -
Proceeds from long-term debt. . . . . . . . . . . . . . . . . . 3,361,178 - 105,000
Reductions of preferred stock . . . . . . . . . . . . . . . . . (10,120) (8,870) (10,400)
Reductions in long-term debt. . . . . . . . . . . . . . . . . . (135,000) (44,600) (244,341)
Dividends paid. . . . . . . . . . . . . . . . . . . . . . . . . (36,555) (37,397) (38,281)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (13,580) 97 (8,846)
---------------- ---------- ----------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES. 3,482,312 (90,770) (196,868)
---------------- ---------- ----------
NET INCREASE (DECREASE) IN CASH . . . . . . . . . . . . . . . . (205,234) 52,834 171,923
Cash at beginning of period . . . . . . . . . . . . . . . . . . 378,232 325,398 153,475
---------------- ---------- ----------
CASH AT END OF PERIOD . . . . . . . . . . . . . . . . . . . . $ 172,998 $ 378,232 $ 325,398
================ ========== ==========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid . . . . . . . . . . . . . . . . . . . . . . . . .$ 315,541 $ 279,957 $ 286,497
Income taxes paid (refunded). . . . . . . . . . . . . . . . . .$ (12,127) $ 82,331 $ 95,632
SUPPLEMENTAL SCHEDULE OF NONCASH FINANCING ACTIVITIES:
Issued 20,546,264 shares of common stock, valued at $14.75 per
share to the IPP Parties on June 30, 1998 or $303.1 million
The accompanying notes are an integral part of these financial statements
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. Inter-company 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 are 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 to the fossil and hydro operations 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 1998 was 9.19%. AFC is
segregated into its two components, borrowed funds and other funds, and is
reflected in the "Interest charges" and "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:
1998 1997 1996
------- ------ ------
Other income . . $ 8,626 $5,310 $3,665
Interest charges 10,228 4,396 3,690
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 and 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 3.4% to 3.5% for the years 1996 through
1998. 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 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 is in the
process of selling its fossil and hydro generating assets through an auction
process. In addition, the Company has announced plans to pursue the sale of its
nuclear assets (see Note 3).
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.
REVENUES: Revenues are based on cycle billings rendered to certain customers
monthly and others bi-monthly. The Company accrues the estimated revenue
associated with energy consumed and not billed at the end of the fiscal period.
The unbilled revenues included in accounts receivable at December 31, 1998 and
1997 were $205.6 million and $211.9 million, respectively.
In accordance with regulatory practice, accrued unbilled revenues are not
recognized in results of operations until authorized and may be used to reduce
future revenue requirements. Such amounts are included in "Other Liabilities"
pending regulatory disposition. Under the POWERCHOICE agreement, $8.6 million
of unrecognized unbilled electric revenues as of the implementation date of
POWERCHOICE were netted with certain other regulatory assets and liabilities and
subsequent changes in the estimated unbilled electric revenues are recognized
currently in results of operations. At December 31, 1998 and 1997, $30.7
million and $34.7 million, respectively, of unbilled gas revenues remain
unrecognized in results of operations.
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
variances in the period of recovery. The PSC has periodically authorized the
Company to make changes in the level of allowed purchased gas costs included in
approved rate schedules. As a result of such periodic changes, a portion of
purchased gas costs deferred at the time of change would not be recovered or may
be overrecovered under the normal operation of the gas adjustment clause.
However, the Company has been permitted to defer and bill or credit such
portions to customers, through the gas adjustment clause, over a specified
period of time from the effective date of each change. Under the POWERCHOICE
agreement, the electric fuel adjustment clause was discontinued as of September
1, 1998.
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 pass back 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 or excess costs beyond that amount flow to
ratepayers.
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, 1998, 1997 and 1996 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.
SEGMENT DISCLOSURE: For the fiscal year ending December 31, 1998, the Company
adopted Statement of Financial Accounting Standards No. 131 "Disclosures about
Segments of an Enterprise and Related Information." SFAS No. 131 supersedes
Statement of Financial Accounting Standards No. 14 "Financial Reporting for
Segments of a Business Enterprise," replacing the "industry segment" approach
with the "management" approach. The management approach 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 products and service, geographic areas and
major customers. The adoption of SFAS No. 131 did not affect results of
operations or financial position, but did affect the disclosure of segment
information.
DERIVATIVES: In June 1998, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standards No. 133 "Accounting for
Derivative Instruments and Hedging Activities." The new standard requires
companies to record derivatives on the balance sheet as assets or liabilities,
measured at fair value. Gains or losses resulting from the changes in the
values of the derivatives will be accounted for depending on the use of the
derivative and whether it qualifies for hedge accounting. The Company will be
required to adopt this standard by fiscal year beginning January 1, 2000. The
Company has identified the indexed swap contracts (see Note 10. - "Fair Value of
Financial and Derivative Financial Instruments") as derivative instruments and
has recorded a liability at fair value under SFAS No. 80, "Accounting for
Futures Contracts." These indexed swap contracts qualify as hedges of future
purchase commitments and will continue to under SFAS No. 133. The Company
continues to assess the applicability of this new standard to other contractual
obligations.
ENERGY TRADING: The Emerging Issues Task Force of the FASB recently reached a
consensus on Issue 98-10, "Accounting for Energy Trading and Risk Management
Activities." The Company does not believe that the accounting requirements of
Issue 98-10 will have a significant impact on its financial position or results
of operations. Niagara Mohawk Energy, Inc., a wholly owned subsidiary of the
Company, engages in trading activities, and such transactions are accounted for
on a mark-to-market basis with changes in fair value recognized as a gain or
loss in the period of change. The effects of these trading activities on the
Company's 1998 and 1997 results of operations were not material.
COMPREHENSIVE INCOME: While the primary component of comprehensive income is
the Company's reported net income or loss, the other components of comprehensive
income relate to foreign currency translation adjustments and unrealized gains
and losses associated with certain investments held as available for sale.
RECLASSIFICATIONS: Certain amounts from prior years have been reclassified on
the accompanying Consolidated Financial Statements to conform with the 1998
presentation.
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.
The Company discontinued application of regulatory accounting principles to the
Company's fossil and hydro generation business as of December 31, 1996, which
resulted in a $103.6 million charge against 1996 income as an extraordinary
non-cash charge. Substantively, SFAS No. 71 permits 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 $5.5 billion at December 31, 1998. These regulatory assets are
probable of recovery.
Under POWERCHOICE, a regulatory asset was established for the costs of the MRA
and will be amortized over a period generally not to exceed ten years. The
Company's rates under POWERCHOICE have been designed to permit recovery of the
MRA regulatory asset. In approving POWERCHOICE, the PSC limited the estimated
value of the MRA regulatory asset that could be recovered, which resulted in a
charge to the second quarter of 1998 earnings of $263.2 million upon the closing
of the MRA.
The Company, as part of the MRA, entered into restated contracts with eight
IPPs. The contracts have a term of ten years and are structured as indexed 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 Company has recorded the liability for these contractual
obligations and recorded a corresponding regulatory asset since payments under
these restated contracts are authorized under POWERCHOICE. See Note 10. - "Fair
Value of Financial and Derivative Financial Instruments."
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, will continue to be the
obligations of the regulated business. Under POWERCHOICE, the Company was
required to net certain regulatory assets and liabilities for future ratemaking
consideration and has reflected these changes in its December 31, 1998 balance
sheet.
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. EITF 97-4 does not require the Company to earn a
return on regulatory assets that arise from a deregulating transition plan in
assessing the applicability of SFAS No. 71. The Company believes that the
regulated cash flows to be derived from prices it will charge for electric
service over the next 10 years, including the Competitive Transition Charge
("CTC") assuming no unforeseen 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 determines, as a result of lower than expected revenues and/or
higher than expected costs, that its net regulatory assets are not probable of
recovery, it can no longer apply the principles of SFAS No. 71 and would be
required to record an after-tax non-cash charge against income for any remaining
unamortized regulatory assets and liabilities. If the Company could no longer
apply SFAS No. 71, the resulting charge would be material to the Company's
reported financial condition and results of operations and adversely effect the
Company's ability to pay dividends.
POWERCHOICE requires the Company to divest its portfolio of fossil and hydro
generating assets. As of December 31, 1998, the Company has agreed to sell its
hydroelectric generating plants and coal-fired stations for $780 million. These
assets have a total book value of approximately $639 million. The remaining oil
and gas-fired plants in Albany and Oswego and the Company's 25% ownership in the
Roseton Steam Station have a book value of approximately $411 million. The
POWERCHOICE agreement provides for deferral and future recovery of net losses,
if any, resulting from the sale of the portfolio. The Company believes that it
will be permitted to record a regulatory asset for any such losses in accordance
with EITF 97-4. The Company has determined that there is no impairment of this
portfolio of assets.
The Company has recorded the following regulatory assets on its Consolidated
Balance Sheets reflecting the rate actions of its regulators:
MRA REGULATORY ASSET represents the recoverable costs to terminate, restate or
amend IPP Party contracts, which have been deferred and are being amortized and
recovered under the POWERCHOICE agreement. The MRA Regulatory Asset is being
amortized generally over ten years, beginning September 1, 1998.
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.
INDEXED SWAP CONTRACT REGULATORY ASSET represents the fair value of the
difference between estimated future market prices and the indexed contract
prices for the notional quantities of power in the restated PPA contracts. In
accordance with the MRA, this asset will be amortized over ten years ending in
June 2008, as notional quantities are settled. The amount of this regulatory
asset will fluctuate as estimates of future market and contract prices change
over the term of the contracts.
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 were phased into rates generally over a five-year period and
amounts deferred are being amortized and recovered over a period of
approximately 15 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
The Company is the owner and operator of the 613 MW Unit 1 and the operator and
a 41% co-owner of the 1,143 MW Unit 2. The remaining ownership interests are
Long Island Power Authority (LIPA) - 18%; New York State Electric and Gas
Corporation (NYSEG) - 18%; Rochester Gas and Electric Corporation (RG&E) - 14%;
and Central Hudson Gas and Electric Corporation (Central Hudson) - 9%. Unit 1
was placed in commercial operation in 1969 and Unit 2 in 1988.
In January 1999, the Company announced plans to pursue the sale of its nuclear
assets, which will require approval from the PSC. The Company is unable to
predict if a sale will occur and the timing of such sale.
At December 31, 1998, the net book value of the Company's nuclear generating
assets was approximately $1.6 billion, excluding the reserve for
decommissioning. In addition, the Company has other assets of approximately
$0.5 billion. These assets include the decommissioning trusts and regulatory
assets, primarily due to the deferral of income taxes.
NUCLEAR PLANT DECOMMISSIONING: The Company's site specific cost estimates for
decommissioning Unit 1 and its ownership interest in Unit 2 at December 31, 1998
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 1999 dollars). . In millions of dollars
Radioactive Components . . . $498 $207
Non-radioactive Components . 121 50
Fuel Dry Storage/Continuing
Care. . . . . . . . . . . 80 45
----------------- ----------------
$699 $302
================= ================
The Company estimates that by the time decommissioning is completed, the above
costs will ultimately amount to $1.7 billion and $0.9 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 ramp down, insurance and property taxes. In 1999
dollars, these costs are expected to amount to $123 million and $65 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 expected to be completed.
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 allowance for Unit 1 and the
Company's share of Unit 2 was approximately $25.2 million, for the year ended
December 31, 1998. This is $1.5 million higher than 1997 when the NRC minimum
cost requirements were authorized in rates by the PSC. POWERCHOICE, which was
implemented September 1, 1998, 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. For 1999, the annual
decommissioning allowance will increase to $42 million of which $28 million is
for radioactive components and $14 million is for non-radioactive components.
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 $315.5 million
and $266.8 million at December 31, 1998 and 1997, respectively for both units.
Additionally at December 31, 1998, the fair value of funds accumulated in the
Company's external trusts were $192.4 million for Unit 1 and $64.9 million for
its share of Unit 2. The trusts are included in "Other Property and
Investments." Earnings on the external trust aggregated $81.1 million through
December 31, 1998, including $27.9 million of unrealized market gains, 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 $51.2 million at December 31, 1998.
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 $9.15 billion without the 5% surcharge discussed below. This limit
would be funded by assessments of up to $83.9 million for each of the 109
presently licensed nuclear reactors in the United States, payable at a rate not
to exceed $10 million per reactor, per year, per incident. 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 $9.6 billion.
The Company's interest in Units 1 and 2 could expose it to a maximum potential
loss, for each accident, of $124.2 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 American Nuclear Insurers (ANI). 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 $9.9 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 ten-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. 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. In July
1996, the United States Circuit Court of Appeals for the District of Columbia
ruled that the DOE has an obligation to accept spent fuel from the nuclear
industry by January 31, 1998 even though a permanent storage site would 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. The DOE did not meet its January 31, 1998 deadline and indicated it was
not obligated to provide a financial remedy for 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. In 1998, both the House and the U.S. Senate
passed legislation to reform the federal government's spent nuclear fuel
disposal policy. This legislation authorized DOE to construct an interim spent
fuel storage facility to accommodate acceptance of spent fuel beginning no later
than June 2003. Additionally, this legislation required the payment of one-time
fees by electric utilities for the disposal of fuel irradiated prior to 1983 to
be paid to the Nuclear Waste Fund no later than September 30, 2001. However,
this legislation was never sent to the President for approval. It is expected
that similar legislation will be introduced in 1999. As of December 31, 1998,
the Company has recorded a liability of $120.2 million for the disposal of
nuclear fuel irradiated prior to 1983. The Company is unable to predict the
outcome of this matter.
The Company has several alternatives under consideration to provide additional
spent fuel 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. In May 1998,
the Company requested approval from the NRC to add additional racks in the spent
fuel pool at Unit 1 that will allow almost 50% more spent fuel to be stored in
the pool. The NRC is expected to make a decision during March 1999. If
approved, the additional racks will provide Unit 1 with enough spent fuel
storage through the end of Unit 1's licensing period. 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, 1998. 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 fossil 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 $ 96,192 $ 57,639 $ 740
OSWEGO STEAM STATION
Unit No. 6 (b) . . . . 76 $ 270,316 $ 133,678 $ 140
NINE MILE POINT NUCLEAR
Station Unit No. 2 (c) 41 $1,505,319 $ 362,003 $ 8,239
(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.
Central Hudson intends to sell its generation assets and will include the
Company's share of Roseton in its sale, which Central Hudson expects to
conclude in 2000.
(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. The Company will sell RG&E'
share in its auction of fossil generation assets.
(c) The Company is the operator. The remaining ownership interests are
Long Island Power Authority ("LIPA") (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.
NOTE 5. CAPITALIZATION
CAPITAL STOCK
The Company is authorized to issue 250,000,000 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 1996, 1997 and 1998:
Preferred Stock
---------------------------------
Common Stock $100 par value
$1 Par Value Non-
Shares Amount* Shares Redeemable* Redeemable*
- ---------------------------------------------------------------------------------------------
DECEMBER 31, 1995. . . . . 144,332,123 $ 144,332 2,358,000 $ 210,000 $ 25,800 (a)
Issued . . . . . . . . . . 33,091 33 - - -
Redemptions. . . . . . . . (18,000) - (1,800)
Unrealized gain (loss) on
securities (net of tax)
Foreign currency
translation adjustment
----------- --------- --------- --------- ----------
DECEMBER 31, 1996. . . . 144,365,214 $ 144,365 2,340,000 $ 210,000 $ 24,000 (a)
Issued . . . . . . . . 54,137 54 - - -
Redemptions. . . . . . . . (18,000) - (1,800)
Unrealized gain (loss) on
securities (net of tax)
Foreign currency
translation adjustment
----------- --------- --------- --------- ----------
DECEMBER 31, 1997. . . . 144,419,351 $ 144,419 2,322,000 $ 210,000 $ 22,200 (a)
Issued . . . . . . . . . 42,945,512 42,946 - - -
Redemptions. . . . . . . . (18,000) - (1,800)
Unrealized gain (loss) on
securities (net of tax)
Foreign currency
translation adjustment
----------- --------- --------- --------- ----------
DECEMBER 31, 1998. . . . . 187,364,863 $ 187,365 2,304,000 $ 210,000 $ 20,400 (a)
=========== ========= ========= ========= ==========
Preferred Stock
--------------------------------- Capital Stock Accumulated
$25 par value Premium and Other
Non- Expense Comprehensive
Shares Redeemable* Redeemable* (Net)* Income*
- -----------------------------------------------------------------------------------------------
DECEMBER 31, 1995. . . . . 12,408,005 $ 230,000 80,200 (a) $1,793,798 $ (9,551)
Issued . . . . . . . . . . - - - 214
Redemptions. . . . . . . . (344,000) - (8,600) 203
Unrealized gain (loss) on (231)
securities (net of tax)
Foreign currency
translation adjustment (708)
---------- --------- ---------- ---------- ---------
DECEMBER 31, 1996. . . . 12,064,005 $ 230,000 $ 71,600 (a) $1,794,215 $(10,490)
Issued . . . . . . . . - - - 426
Redemptions. . . . . . . . (282,801) - (7,070) 98
Unrealized gain (loss) on
securities (net of tax) 6
Foreign currency
translation adjustment (4,567)
---------- --------- ---------- ---------- ---------
DECEMBER 31, 1997. . . . 11,781,204 $ 230,000 $ 64,530 (a) $1,794,739 $(15,051)
Issued . . . . . . . . . - - - 563,540
Redemptions. . . . . . . . (332,801) - (8,320) 101 -
Unrealized gain (loss) on
securities (net of tax) 304
Foreign currency
translation adjustment (6,896)
---------- --------- ---------- --------- ---------
DECEMBER 31, 1998. . . . . 11,448,403 $ 230,000 $ 56,210 (a) $2,358,380 $(21,643)
========== ========= ========== ========== =========
* In thousands of dollars
(a) Includes sinking fund requirements due within one year.
The cumulative amount of foreign currency translation adjustment at
December 31, 1998 was $ (22,344).
The cumulative amount of unrealized gain on securities at December 31, 1998 was
$ 701.
NON-REDEEMABLE PREFERRED STOCK (Optionally Redeemable)
The Company had certain issues of preferred stock, which provide for optional
redemption at December 31, as follows:
Redemption price
per share
In thousands of dollars (Before adding
Series Shares 1998 1997 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
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
======== ========
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 are as
follows:
Redemption
Requirements
(in thousands)
---------------
1999 $ 7,620
2000 7,620
2001 7,620
2002 3,050
2003 3,050
Redemption price
per share
(Before adding
accumulated dividends)
Shares In thousands of dollars Eventual
Series 1998 1997 1998 1997 1998 Minimum
- --------------------------------------------------------------------------------------------------------
PREFERRED $100 PAR VALUE:
7.45% 204,000 222,000 $20,400 $22,200 $101.45 $100.00
PREFERRED $25 PAR VALUE:
7.85% 548,403 731,204 13,710 18,280 25.00 25.00
8.375% - 100,000 - 2,500 -
Adjustable Rate-
Series B . . . . . . . . 1,700,000 1,750,000 42,500 43,750 25.00 25.00
------- -------
76,610 86,730
Less sinking fund requirements 7,620 10,120
------- -------
$68,990 $76,610
======= =======
LONG-TERM DEBT
Long-term debt at December 31 consisted of the following:
In thousands of dollars
Series Due 1998 1997
- ---------------------------------------------------------
FIRST MORTGAGE BONDS:
6 1/2% 1998 $ - $ 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
*5.15% 2025 75,000 -
* 7.2% 2029 115,705 115,705
---------- ----------
Total First Mortgage Bonds 2,741,305 2,801,305
---------- ----------
SENIOR NOTES:
6 1/2% 1999 300,000 -
7% 2000 450,000 -
7 1/8% 2001 400,000 -
7 1/4% 2002 400,000 -
7 3/8% 2003 400,000 -
7 5/8% 2005 400,000 -
7 3/4% 2008 600,000 -
8 1/2% 2010 500,000 -
Unamortized discount
on 8 1/2% Senior Note (156,216)
---------- ----------
Total Senior Notes 3,293,784 -
---------- ----------
PROMISSORY NOTES:
*Adjustable Rate Series due
2015 100,000 100,000
2023 69,800 69,800
2025 75,000 75,000
2026 50,000 50,000
2027 25,760 25,760
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 174,462 154,295
Unamortized premium (discount) (18,846) (9,884)
---------- -----------
TOTAL LONG-TERM DEBT 6,729,465 3,484,476
Less long-term debt due
within one year 312,240 67,095
---------- ----------
$6,417,225 $3,417,381
========== ==========
*Tax-exempt pollution control related issues
The Company's long-term debt increased significantly upon the closing of the MRA
on June 30, 1998. The MRA was largely financed through the Senior Notes. The
Senior Notes are unsecured obligations of the Company and rank pari passu in
right of payment to its First Mortgage Bonds, the senior bank financing and
unsecured medium term notes. The Company's ability to make common stock
dividend payments may be restricted under certain covenants of the Senior Notes
relating to fixed charge coverages and operating cash flow as defined in the
indenture. These restrictions are no longer applicable once the Senior Notes
become rated as investment grade.
In addition, the Company is obligated to use 85% of the net proceeds of the sale
of the generation assets to reduce its senior debt outstanding
within 180 days after the receipt of such proceeds. As of December 31,1998, the
Company has entered into agreements for the sale of its two largest components
of its fossil and hydroelectric generating portfolio for $780 million. It is
anticipated that transaction closings will occur in mid-1999 after receipt of
the necessary regulatory approvals.
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 3.39 % for 1998 and 3.63% for
1997 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). In November 1998, the Company
refinanced its 8-7/8% series of tax exempt bonds issued through NYSERDA at a
rate of 5.15%.
Other long-term debt in 1998 consists of obligations under capital leases of
approximately $26.3 million, a liability to the DOE for nuclear fuel disposal of
approximately $120.2 million and a liability for IPP contract terminations not
related to the MRA of approximately $28.0 million. The aggregate maturities of
long-term debt for the five years subsequent to December 31, 1998, excluding
capital leases, in millions, are approximately $309, $719, $715, $635 and $705,
respectively and exclude acceleration of debt repayment associated with the sale
of fossil and hydro assets.
NOTE 6. BANK CREDIT ARRANGEMENTS
The Company has an $804 million senior bank financing 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, 1998, the
amount outstanding under the senior bank financing was $529 million, consisting
of $105 million under the term loan facility and $424 million of letters of
credit, leaving the Company with $275 million of borrowing capability under the
financing. The senior bank financing was amended as of June 30, 1998. The
amendment, which included an extension of the term from June 30, 1999 to June 1,
2000, also accommodates the holding company structure and permits the auction of
the fossil and hydro generating assets. In addition, the amendment limits the
annual amount of common stock dividend payments 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 interest rate applicable to the facility is variable based on certain
rate options available under the agreement and currently approximates 6.5% (but
capped at 15%). In addition, the Company's unregulated subsidiaries have an
agreement with banks for letters of credit totaling up to $25 million. The
Company did not have any short-term debt outstanding at December 31, 1998 and
1997.
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
1998 1997 1996
----------------------------
United States . . . . . . . $ (206,372) $315,027 $269,128
Foreign . . . . . . . . . . 8,227 (1,621) 28,522
Consolidating eliminations. 10,592 (3,476) (17,402)
------------- --------- ---------
Income before extraordinary
item and income taxes. . $ (187,553) $309,930 $280,248
============= ======== =========
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
1998 1997 1996
---------------------------------
COMPONENTS OF FEDERAL AND FOREIGN INCOME TAXES:
Current tax expense:
Federal. . . . . . . . .. $ (155,320) $ 77,565 $ 96,011
Foreign. . . . . . . . . - - 3,708
------------- -------- --------
(155,320) 77,565 99,719
------------- -------- --------
Deferred tax expense:
Federal. . . . . . . . 84,466 47,836 382 *
Foreign. . . . . . . . . . 4,126 1,194 2,393
------------- -------- --------
88,592 49,030 2,775
------------- -------- --------
Total . . . . . . . . . . . $ (66,728) $126,595 $102,494
============= ======== ========
* Does not include the deferred tax benefit of $36,273 in 1996 associated
with the extraordinary item for the discontinuance of regulatory
accounting principles.
RECONCILIATION BETWEEN FEDERAL AND FOREIGN INCOME TAXES AND THE TAX COMPUTED AT
PREVAILING U.S. STATUTORY RATE ON INCOME BEFORE INCOME TAXES:
Computed tax $(65,644) $108,475 $98,087
- --------------------------------------------------- --------- --------- ---------
INCREASE (REDUCTION) ATTIBUTABLE TO FLOW-THROUGH OF
CERTAIN TAX ADJUSTMENTS:
Depreciation. . . . . . . . . . . . . . . . . . . . 20,808 34,926 26,216
Cost of removal . . . . . . . . . . . . . . . . . . (7,859) (8,168) (8,849)
Allowance for funds used
during construction . . . . . . . . . . . . . (4,207) (2,952) (1,431)
Expiring foreign tax credits. . . . . . . . . . . . 10,053 - -
Pension settlement amortization . . . . . . . . . . (3,317) (2,391) (4,721)
Debt premium & mortgage
recording tax . . . . . . . . . . . . . . . . (9,408) 23 1,252
Deferred investment tax credit
amortization . . . . . . . . . . . . . . . . . . (7,454) (7,454) (8,018)
Other . . . . . . . . . . . . . . . . . . . . . . . 300 4,136 (42)
--------- --------- ---------
(1,084) 18,120 4,407
--------- --------- ---------
Federal and foreign income
taxes. . . . . . . . . . . . . . . . . . . . . . $(66,728) $126,595 $102,494
========= ========= =========
At December 31, the deferred tax liabilities (assets) were comprised of the
following:
In thousands of dollars
1998 1997
-----------------------------
Alternative minimum tax . . . . . $ (82,621) $ (17,448)
Unbilled revenue. . . . . . . . . (81,685) (88,859)
Non-utilized NOL carryforward . . (1,161,898) -
Other . . . . . . . . . . . . . . (290,035) (247,438)
------------- -----------
Total deferred tax assets. . . (1,616,239) (353,745)
------------- -----------
Depreciation related. . . . . . . 1,292,582 1,358,827
Investment tax credit related . . 76,418 79,858
MRA terminated IPP contracts. . . 1,415,977 -
Other . . . . . . . . . . . . . . 342,679 302,092
------------- ----------
Total deferred tax liabilities 3,127,656 1,740,777
------------ ----------
Accumulated deferred income
taxes. . . . . . . . . . . . . $ 1,511,417 $1,387,032
============ ==========
In December 1998, the Company received a ruling from the IRS to the effect that
the amount of cash and the value of common stock that was paid to the terminated
IPP Parties will be currently deductible and generate a substantial net
operating loss for federal income tax purposes, such that the Company will not
pay federal income taxes for 1998. Further, the Company has carried back unused
NOL to the years 1996 and 1997, and also for the years 1988 through 1990, which
has resulted in a refund of $130 million and $5 million, respectively, that were
received in January 1999. In addition, the Company anticipates that it will be
able to utilize the remaining $3.3 billion NOL carryforward prior to its
expiration date in 2019. The Company's ability to utilize the NOL generated as
a result of the MRA could be limited under the rules of section 382 of the
Internal Revenue Code if certain changes in the Company's common stock ownership
were to occur in the future.
NOTE 8. PENSION AND OTHER RETIREMENT PLANS
During 1998, the Company's non-contributory defined benefit pension plan
covering substantially all employees was amended to include a cash balance
benefit in which the participant has an account to which amounts are credited
based on qualifying compensation and with interest determined annually based on
average annual 30-year Treasury bond yield. Supplemental non-qualified,
non-contributory executive retirement programs provide additional defined
pension benefits for certain officers. In addition, the Company provides
certain contributory health care and life insurance benefits for active and
retired employees and dependents.
The changes in benefit obligations, plan assets and plan funded status for these
pension and other retirement plans as of, and for the year ended December 31,
are summarized as follows:
(In thousands of dollars)
Pension Benefits Other Retirement Benefits
------------------- -------------------------
CHANGE IN BENEFIT OBLIGATION:. . . . . . 1998 1997 1998 1997
---- ---- ---- ----
Benefit obligation at January 1. . . . . $ 1,172,428 $ 1,027,781 $ 519,851 $ 470,730
Service cost. . . . . . . . . . . . . . 30,430 27,106 14,338 12,255
Interest cost . . . . . . . . . . . . . 79,748 74,984 35,338 34,829
Benefits paid to participants . . . . . (75,650) (57,100) (32,917) (28,602)
Plan amendments . . . . . . . . . . . . 33,694 4,602 (6,579) -
Actuarial (gain) loss . . . . . . . . . 61,547 95,055 17,589 30,639
--------------- -------------- ---------- ----------
Benefit obligation at December 31. . . . 1,302,197 1,172,428 547,620 519,851
--------------- -------------- ---------- ----------
CHANGE IN PLAN ASSETS:
Fair Value of plan assets at January 1 . 1,304,338 1,159,822 181,101 143,071
Contributions. . . . . . . . . . . . . 12,446 12,446 9,466 13,542
Net return on plan assets. . . . . . . 198,943 188,239 19,479 24,488
Benefits paid to participants. . . . . (69,215) (56,169) - -
--------------- -------------- ---------- ----------
Fair value of plan assets at December 31 1,446,512 1,304,338 210,046 181,101
--------------- -------------- ---------- ----------
Funded status. . . . . . . . . . . . . . 144,315 131,910 (337,574) (338,750)
Unrecognized initial obligation. . . . . 16,887 19,446 152,460 163,350
Unrecognized net gain from actual return
on plan assets . . . . . . . . . . . . (360,450) (265,100) - -
Unrecognized net loss (gain) from past
experience different from that assumed 41,914 (19,920) 55,335 48,840
Unrecognized prior service cost. . . . . 79,269 50,473 (27,532) (30,460)
--------------- -------------- ---------- ----------
Benefits liability on the consolidated
balance sheet. . . . . . . . . . . . . $ (78,065) $ (83,191) $(157,311) $(157,020)
=============== ============== ========== ==========
The non-qualified executive pension plan has no plan assets due to the nature of
the plan, and therefore, has an accumulated benefit obligation in excess of plan
assets of $8,816 and $6,243 at December 31, 1998 and 1997, respectively.
The following table summarizes the components of the net annual benefit costs.
(In thousands of dollars)
Pension Benefits Other Retirement Benefits
------------------------------------- ---------------------------
1998 1997 1996 1998 1997 1996
-------------------------------------------------------------------
Service Cost . . . . . $ 30,430 $ 27,106 $ 24,951 $ 14,338 $ 12,255 $12,935
Interest Cost. . . . . 79,748 74,984 71,729 35,338 34,829 37,495
Expected return
on plan assets . . . (95,472) (84,859) (78,083) (16,752) (13,234) (8,138)
Amortization of the
initial obligation . 2,559 2,559 2,559 10,890 10,890 13,507
Amortization of
gains and losses . . (8,408) (9,226) (6,540) 8,367 6,967 6,987
Amortization of prior
service costs. . . . 4,899 3,892 3,638 (9,508) (8,745) (5,830)
----------- ---------- --------- --------- --------- --------
Net benefit cost (1). $ 13,756 $ 14,456 $ 18,254 $ 42,673 $ 42,962 $56,956
=========== ========== ======== ======== ======== ========
(1) A portion of the benefit costs relates to construction labor, and
accordingly, is allocated to construction projects.
Pension Benefits Other Retirement Benefits
---------------- -------------------------
1998 1997 1998 1997
---- ---- ---- ----
Weighted-average assumptions
as of December 31:
Discount rate . . . . . . . . . 6.75% 7.00% 6.75% 7.00%
Expected return on plan assets. 9.25 9.25 9.25 9.25
Rate of compensation increase
(plus merit increases) . . 2.50 2.50 N/A N/A
Health care cost trend rate:
Under age 65 . . . . . . . N/A N/A 7.00 7.00
Over age 65. . . . . . . . N/A N/A 6.00 6.00
The assumed health cost trend rates decline to 5% in 2000 and remain at that
level thereafter. The assumed health cost trend rates can have a significant
effect on the amounts reported for the health care plans. A
one-percentage-point change in assumed health care cost trend rates would have
the following effects:
1% Increase 1% Decrease
----------- -----------
Effect on total of service and interest
cost components of net periodic
postretirement health care benefit cost $ 2,076 $ (1,799)
Effect on the health care component of
the accumulated postretirement
benefit obligation. . . . . . . . . . . 32,906 (28,465)
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, 1998 and 1997, the Company's postemployment benefit
obligation is approximately $15.3 million and $13.3 million, respectively.
NOTE 9. COMMITMENTS AND CONTINGENCIES
LONG-TERM CONTRACTS FOR THE PURCHASE OF ELECTRIC POWER: At January 1, 1999, 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 $27,667,000
St. Lawrence - hydroelectric
project. . . . . . . . . . 2007 104 1,248,000
Blenheim-Gilboa - pumped
storage generating station 2002 270 7,452,000
----- -----------
1,325 $36,367,000
===== ===========
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 was approximately, in millions, $93.1, $91.0 and $93.3 for the
years 1998, 1997 and 1996, respectively. The Company continues to have a
contract with NYPA's Fitzpatrick nuclear facility 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 118 PPAs with 125
facilities, amounting to approximately 1,125 MW of capacity at December 31,
1998. All of this amount is considered firm, but excludes PPAs that provide
energy only. The following table shows the estimated payments for fixed costs
(capacity) and variable costs (capacity, energy and related taxes) the Company
estimates it will be obligated to make under these contracts, excluding the over
market obligation under the indexed swap contracts. See Note 10. Fair Value of
Financial and Derivative Financial Instruments. These payments have been
significantly reduced by the consummation of the MRA. The MRA was consummated
on June 30, 1998 with 14 IPPs. The MRA allowed the Company to terminate,
restate or amend 27 PPAs which represented approximately three quarters of the
Company's over-market purchase power obligations. Under the terms of the MRA,
the Company terminated 18 PPAs representing 1,092 MW of electric generating
capacity, restated eight PPAs representing 535 MW of capacity and amended one
PPA representing 42 MW of capacity. In addition, the Company is continuing to
actively pursue other opportunities to reduce payments to IPPs that were not a
party to the MRA.
The payments are subject to the tested capacity and availability of the
facilities, scheduling and price escalation.
(In thousands of dollars)
Fixed Costs Variable Costs
Capacity,
Year Capacity Energy and Taxes Total
- ------------------------------------------------------
1999 $ 13,456 $ 392,029 $405,485
2000 13,793 412,177 425,970
2001 13,989 413,482 427,471
2002 14,288 425,357 439,645
2003 14,635 437,731 452,366
Fixed capacity costs (in the table above) relate to one 56 MW contract, where
the Company is required to make capacity payments, including payments when the
facility is not operating but available for service. The terms of this contract
allows the Company to schedule energy deliveries and then pay for the energy
delivered. Contracts relating to the remaining facilities in service at December
31, 1998, 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. The Company paid approximately $785 million, $1,106 million and
$1,088 million in 1998, 1997 and 1996 for 9,700,000 MWh, 13,500,000 MWh and
13,800,000 MWh, respectively, of electric power under all IPP contracts.
SALE OF CUSTOMER RECEIVABLES: The Company has established a single-purpose,
financing subsidiary, NM Receivables LLC, 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 LLC has its own separate
creditors which, upon liquidation of NM Receivables LLC, 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 LLC in fee simple for
reasonably equivalent value, and all receivables transferred to NM Receivables
LLC are assets owned by NM Receivables LLC in fee simple and are not available
to pay the parent Company's creditors.
At December 31, 1998 and 1997, $150 million and $144.1 million, respectively, of
receivables had been sold by NM Receivables LLC 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, 1998, the amount of additional receivables assigned
to the purchaser, as a loss reserve, was approximately $40.0 million.
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") conducted an examination
of the Company's federal income tax returns for the years 1989 and 1990 and
issued a Revenue Agents' Report (RAR). The IRS raised an issue concerning the
deductibility of payments made to IPPs in accordance with certain contracts that
include a provision for a tracking account. In late November 1998, the Company
received a final settlement letter from the IRS allowing the deduction of these
IPP payments. The IRS also conducted an examination of the Company's federal
income tax returns for the years 1991 through 1993 and issued an RAR in the
second quarter of 1998. Based upon the Company's review of the report, the
Company does not believe that the findings will have a material impact on its
financial position or results of operation.
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 remediate, as necessary to meet current environmental standards, certain
properties associated with former gas manufacturing 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 136 sites with which it has been or may be
associated, including 82 which are Company-owned. 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. The Company has denied any responsibility at
certain of these PRP sites and is contesting liability accordingly.
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 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.
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, 1998. The potential high end of the range is presently estimated
at approximately $710 million, including approximately $340 million in the
unlikely event the Company is required to assume 100% responsibility at
non-owned sites. The amount accrued at December 31, 1998, incorporates a method
to estimate the liability for 22 of the Company's largest sites, which relies
upon a decision analysis approach. This method includes developing several
remediation approaches for each of the 22 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 is used. 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 $21 million and a high end of $360
million, with an expected value calculation of $56 million, which is included in
the amounts accrued at December 31, 1998. The range represents the total costs
to remediate the properties and does not consider contributions from other PRPs,
the amount of which the Company is unable to estimate. The Company has received
comments from the DEC on the draft feasibility study, which will facilitate
completion of the feasibility study phase in 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 the DEC 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. The New York State Attorney General moved to dismiss the
Company's claims against the state of New York, the New York State Department of
Transportation and the Thruway Authority and Canal Corporation under the
Comprehensive Environmental Response, Compensation and Liability Act. The
Company opposed this motion. On April 3, 1998, the Court denied the New York
State Attorney General's motion as it pertains to the Thruway Authority and
Canal Corporation, and granted the motion relative to the state of New York and
the Department of Transportation. On January 12, 1999, a pre-trial status
conference was convened by the Court. The Court will be issuing an amended case
management order that is expected to call for the close of discovery by the end
of June 1999 and to establish December 1, 1999 as the trial ready date. As a
result, the Company cannot predict the outcome of the pending litigation against
the defendants 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. The Company has reached settlements with a number
of insurance carriers, resulting in payments to the Company of approximately $39
million, net of costs incurred in pursuing recoveries. This amount is being
amortized in rates generally over a 10-year 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 1999 through
2002, the period covered under the POWERCHOICE agreement, will require
approximately $981 million, excluding AFC and nuclear fuel. For the years 1999
through 2002, the estimates, in millions, are $254, $240, $243, and $244,
respectively, which excludes amounts relating to the Company's fossil and hydro
generation assets. On December 3, 1998, the Company announced it had reached an
agreement with an affiliate of Orion Power Holding, Inc. to sell its 72
hydroelectric generating plants and on December 23, 1998, the Company announced
an agreement with NRG Energy, Inc. to sell its Huntley and Dunkirk coal-fired
electric generating stations. It is anticipated that transaction closings will
occur in mid-1999 after receipt of the necessary regulatory approvals. The
Company continues to pursue the sale of its two oil and gas-fired plants in
Albany and Oswego. The Company is unable to predict the outcome or timing of the
divestiture of its two oil and gas-fired plants.
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, 1998, for the next five
years, and thereafter.
(In thousands of dollars)
Gas Storage/
Year Gas Supply Pipeline
- ---------------------------------------------------
1999 . . . $ 83,785 $ 96,772
2000 . . . 48,939 80,052
2001 . . . 46,565 65,942
2002 . . . 35,272 33,894
2003 . . . 35,272 11,926
Thereafter 99,921 58,474
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, 1998, 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.
The PSC issued its Policy Statement in November 1998 concerning the future of
the Natural Gas Industry in New York State and Order Terminating Capacity
Assignment. The PSC Policy Statement states that utilities may no longer
require capacity assignment or inclusion of capacity costs in transportation
rates beyond April 1, 1999 to customers migrating to marketers except where
specific operational and reliability requirements warrant.
In November 1998, the PSC approved the Company's proposed pilot program that
would, effective December 1, 1998, no longer require assigning pipeline capacity
and related costs upstream of the CNG Transmission System to customers migrating
to transportation. However, the Company's proposed pilot program sought to
continue to assign capacity on the CNG system until October 31, 1999, the
expiration date of its current gas rate settlement agreement. A stranded cost
recovery mechanism, in the form of a surcharge, was established to provide for
the recovery of the unassigned pipeline capacity costs until October 31, 1999.
In December 1998, the Company notified the PSC that the Company's specific
operational and reliability requirements continue to warrant certain mandatory
capacity assignment and inclusion of capacity costs in transportation rates
after April 1, 1999. The PSC noted in its PSC Policy Statement that it will
provide LDCs with a reasonable opportunity to recover these strandable costs if
they can demonstrate compliance with the PSC's directives to minimize such
costs. The Company believes that it has taken numerous actions to reduce its
capacity obligations and its potential stranded costs, but is unable to predict
the outcome of this matter. The Company anticipates that this issue will be
addressed in the individual negotiations with the PSC anticipated to begin
during the second quarter of 1999.
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.
INDEXED SWAP CONTRACTS: Indexed swap contracts are ten-year financial contracts
where the Company receives or makes payments to certain 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 primarily related to gas prices, thereafter.
Contract quantities are fixed for each year of the full ten-year term of the
contracts and average 4.1 million MWh. 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. At December 31,
1998, the Company projects that it will make the following payments to the IPP
Parties for the years 1999 to 2003:
Projected
Payment
Year (in thousands)
- ---- --------------
1999 $ 97,354
2000 97,688
2001 102,073
2002 103,552
2003 105,531
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)
1998 1997
---- ----
CARRYING FAIR Carrying Fair
At December 31, AMOUNT VALUE Amount Value
- ----------------------------------------------------------------------------------
Cash and short-term
investments $ 172,998 $ 172,998 $ 378,232 $ 378,232
Mandatorily redeemable
preferred stock 76,610 86,444 86,730 87,328
Long-term debt:
First Mortgage bonds 2,741,305 2,905,141 2,801,305 2,878,368
Senior Notes 3,293,784 3,324,777 - -
Medium-term notes 20,000 23,290 20,000 22,944
Promissory notes 413,760 413,760 413,760 413,760
Other 253,195 253,195 229,634 229,634
Indexed swap contracts
regulatory asset 693,363 693,363 - -
At December 31, 1998, the Company's energy marketing subsidiary had no open
trading positions. At December 31, 1997, the fair value of its long and short
trading positions was approximately $54.7 million and $54.5 million,
respectively. These fair values were less than the weighted average fair value
of open positions for the year ending December 31, 1998 and greater than the
weighted average fair value of open positions for the year ending December 31,
1997.
Transactions entered into for trading purposes are accounted for on a
market-to-market basis with changes in fair value recognized as a gain or loss
in the period of change. At December 31, 1998, there were no open trading
positions. 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 MWhrs) and $44.3 million (1,778,000 MWhrs),
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 effects of these trading activities on the Company's
1998 and 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 are used for hedging purposes. Changes in market
value of futures contracts relating to hedged items are deferred until the
physical transaction occurs, at which time, income or loss is recognized. At
December 31, 1998, the open non-trading positions consisted of long and short
gas futures contracts with fair values of $4.8 million (2.5 million Dth) and
$1.2 million (.7 million Dth), respectively. At December 31, 1997, the open
non-trading positions consisted of long and short gas futures contracts with
fair values of $5.2 million (2.3 million Dth) and $3.1 million (1.3 million
Dth), respectively. The fair value of open positions for non-trading purposes
at December 31, 1998, as well as the effect of these activities on the Company's
results of operations for the same period ending, was not material.
The fair value of futures and forward contracts are determined using quoted
market prices or broker's quotes.
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"), investments held by
Opinac North America, Inc. 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, 1998. The proceeds from the sale of
investments were $202.1 million, $159.7 million, and $99.4 million in 1998,
1997, and 1996, 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 the pension trust and Opinac Energy for the
period ending December 31, 1998 are not material to the results of operations of
the Company. 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, 1998 1997
GROSS UNREALIZED FAIR Gross Unrealized Fair
Security Type COST GAIN (LOSS) VALUE Cost Gain (Loss) Value
- ------------------------------------------------------------------------------------------------------------
U.S. Government
Obligations . $ 19,291 $ 2,621 $ (117) $ 21,795 $ 14,136 $ 1,864 $ (4) $ 15,996
Commercial Paper 82,930 1,269 - 84,199 106,035 1,542 - 107,577
Tax Exempt
Obligations . 104,538 6,786 (164) 111,160 80,115 5,884 (55) 85,944
Corporate
Obligations . 100,736 22,684 (2,856) 120,564 92,949 17,368 (830) 109,487
Other. . . . . . 6,666 - - 6,666 3,025 - - 3,025
--------- ------- -------- -------- -------- ------- ------- --------
$ 314,161 $33,360 $(3,137) $344,384 $296,260 $26,658 $ (889) $322,029
========= ======= ======== ======== ======== ======= ======= ========
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, 1998 1997 1996
- ---------------------- ---- ---- ----
Realized gains. . . . . $ 5,350 $3,487 $2,121
Realized losses . . . 2,221 686 806
The contractual maturities of the Company's investments in debt securities is
as follows:
At December 31, 1998 Fair Value Cost
- -------------------- ----------- --------
Less than 1 year . . $ 78,438 $ 77,135
1 year to 5 years. . 18,289 17,617
5 years to 10 years. 63,504 61,122
Due after 10 years . 126,363 120,838
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.
The table below sets forth the activity under the Company's stock compensation
plans for the years 1996 through 1998:
SARS UNITS OPTIONS
---------- --------- --------
OUTSTANDING AT DECEMBER 31, 1995 414,000 169,500 300,583
Granted. . . . . . . . . . . . . 376,600 291,228 -
Exercised. . . . . . . . . . . . - - -
Forfeited. . . . . . . . . . . . - - (2,000)
---------- --------- --------
OUTSTANDING AT DECEMBER 31, 1996 790,600 460,728 298,583
Granted. . . . . . . . . . . . . 296,300 208,750 -
Exercised. . . . . . . . . . . . - (2,514) -
Forfeited. . . . . . . . . . . . - - -
---------- --------- --------
OUTSTANDING AT DECEMBER 31, 1997 1,086,900 666,964 298,583
Granted. . . . . . . . . . . . . 1,723,500 488,428 -
Exercised. . . . . . . . . . . . (42,700) (211,403) -
Forfeited. . . . . . . . . . . . (28,000) (10,550) (12,000)
---------- --------- --------
OUTSTANDING AT DECEMBER 31, 1998 2,739,700 933,439 286,583
========== ========= ========
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 in 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 1998, 1997 and 1996,
is approximately $9.8 million, $3.2 million 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
1998, 1997 and 1996. There is no effect on earnings per share for these years
resulting from the pro-forma adjustments to net income.
NOTE 12. SEGMENT INFORMATION
In 1998, the Company adopted SFAS No. 131, "Disclosures About Segments of an
Enterprise and Related Information." SFAS No. 131 supersedes SFAS No. 14,
"Financial Reporting for Segments of a Business Enterprise." Prior years'
information has been restated to conform to SFAS No. 131.
The Company is organized between regulated and unregulated activities. The
Company is pursuing formation of a holding company in 1999 that would further
separate these activities. Within the regulated business, which has 99% of
total assets and 96% of total revenues, there are three principal business
units: Energy Delivery, Nuclear and Fossil/Hydro. The Company has announced
plans to, and expects to, consummate sale of the fossil and hydro assets in
1999. Although there are three identified business units, financial performance
and resource allocation are measured and managed at the regulated business
level.
The Company's unregulated activities do not meet the reporting thresholds of
SFAS No. 131, but comprise a substantial portion of "other" in the accompany
table.
Depreciation Federal &
Total & Foreign Economic Construction Identifiable
(In thousands of dollars) Revenues Amortization* Income Taxes Value Added Expenditures Assets
- ------------------------- -------------- --------------- -------------- ------------- ------------- -------------
1998
REGULATED COMPANY . . . . $ 3,826,373 $ 484,250 $ (63,131) $ (697,948) $ 392,200 $ 13,733,055
OTHER . . . . . . . . . . 141,931 493 (3,597) (31,471) - 128,132
RECLASSIFICATION IN
CONSOLIDATION. . . . . (141,931) (493) - - - -
-------------- --------------- -------------- ------------- ------------- -------------
TOTAL CONSOLIDATED. $ 3,826,373 $ 484,250 $ (66,728) $ (729,419) $ 392,200 $ 13,861,187
========================= ============== =============== ============== ============= ============= =============
1997
Regulated Company . . . . $ 3,966,404 $ 339,641 $ 125,401 $ (650,188) $ 290,757 $ 9,431,763
Other . . . . . . . . . . 116,258 551 1,194 (32,009) - 152,378
Reclassification in
Consolidation. . . . . (116,258) (551) - - - -
-------------- --------------- -------------- ------------- ------------- -------------
Total Consolidated. $ 3,966,404 $ 339,641 $ 126,595 $ (682,197) $ 290,757 $ 9,584,141
========================= ============== =============== ============== ============= ============= =============
1996
Regulated Company . . . . $ 3,975,410 $ 329,253 $ 99,795 $ (637,444) $ 352,049 $ 9,290,711
Other . . . . . . . . . . 37,595 688 2,699 (21,523) - 136,924
Reclassification in
Consolidation. . . . . (22,352) (114) - - - -
-------------- --------------- -------------- ------------- ------------- -------------
Total Consolidated. $ 3,990,653 $ 329,827 $ 102,494 $ (658,967) $ 352,049 $ 9,427,635
========================= ============== =============== ============== ============= ============= =============
*-Includes amortization of the MRA regulatory asset in 1998.
A reconciliation of total segment Economic Value Added to total consolidated net
income for the years ended December 31, 1998, 1997 and 1996 is as follows:
(In thousands of dollars) 1998 1997 1996
- ------------------------------------- ----------- ----------- -----------
Economic Value Added:
Operations. . . . . . . . . . . . $ (248,624) $ (266,459) $ (230,613)
IPP-Related . . . . . . . . . . . (480,795) (415,738) (428,354)
----------- ----------- -----------
Total Economic Value Added. . . . . . (729,419) (682,197) (658,967)
Charge for Use of Investor's Capital. 1,225,437 1,237,499 1,244,579
Adjustments for Significant Items . . (351,388) (189,938) (224,756)
Interest Charges (net of taxes) . . . (265,455) (182,029) (183,102)
Extraordinary Item. . . . . . . . . . - - (67,364)
----------- ----------- -----------
Consolidated Net Income (loss) . . $ (120,825) $ 183,335 $ 110,390
=========== =========== ===========
The Company implemented a shareholder value based management system. The metric
used to measure shareholder value creation is Economic Value Added (EVA). EVA
is the financial measure used to evaluate projects, allocate resources and
report and incent performance.
EVA is calculated as Net Operating Profit after Taxes less a charge for the use
of capital employed. The capital charge is determined by applying a rate
representing an estimate of investors' expected return given the risk of the
business and a targeted capital structure. The rate is not the same as the
embedded cost of capital, including the return of equity that may be established
in a rate proceeding. Certain adjustments to accounting data are made to more
closely reflect operating or economic results. In each of the three years, an
adjustment is made to include the recognition of the off-balance sheet liability
for remaining future over-market contracts with IPPs and the corresponding
recognition of imputed interest on that liability. In addition, there was a
significant adjustment in 1998 to reflect the re-capitalization for EVA purposes
of the POWERCHOICE charge and the incremental operating expense associated with
the January 1998 ice storm and the September 1998 windstorm.
EVA is further segmented between EVA from Operations and EVA due to the MRA and
the remaining over-market IPP contracts. This distinction is used to allow
management to focus on operating performance versus shareholder value created as
the MRA is amortized, the corresponding debt is retired and remaining contracts
are restructured or otherwise expire.
NOTE 13. QUARTERLY FINANCIAL DATA (UNAUDITED)
Operating revenues, operating income, net income (loss) and earnings (loss) per
common share by quarters from 1998, 1997 and 1996, 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
Diluted
Net Earnings
Operating Operating Income (Loss) per
Quarter Ended Revenues Income (Loss) (Loss) Common Share
- ---------------------------------------------------------------------------------------
December 31,. 1998 $ 886,432 $ 103,263 $ (17,433) ($0.14)
1997 960,304 86,024 7,881 (0.01)
1996 971,106 117,832 (25,808) (0.24)
- -------------------------------------------------------------------------------------
September 30, 1998 $ 930,631 $ 110,287 $ 17,653 $ 0.05
1997 896,570 110,174 31,683 0.15
1996 895,713 47,119 (12,916) (0.16)
- -------------------------------------------------------------------------------------
June 30, 1998 $ 910,906 $(180,824) $(141,408) ($1.04)
1997 945,698 130,704 40,749 0.22
1996 960,771 142,755 52,992 0.30
- -------------------------------------------------------------------------------------
March 31, 1998 $1,098,404 $ 134,297 $ 20,363 $ 0.08
1997 1,163,832 231,937 103,022 0.65
1996 1,163,063 214,632 96,122 0.60
- -------------------------------------------------------------------------------------
In the first quarter of 1998, the Company expensed $70.2 million associated
with the January 1998 ice storm (of which $62.9 million was considered
incremental) or 28 cents per common share. In the second quarter of 1998, the
Company recorded a non-cash write-off of $263.2 million ($1.18 per common share)
associated with the portion of the MRA 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).
REGULATED ELECTRIC AND GAS STATISTICS
ELECTRIC CAPABILITY
Thousands of KW
DECEMBER 31, 1998 % 1997 1996
- -----------------------------------------------------------------
OWNED:
Coal . . . . . . . . . . 1,360 17.5 1,360 1,333
Oil* . . . . . . . . . . 850 11.0 - -
Dual Fuel- Oil/Gas . . . 1,346 17.4 1,346 1,336
Nuclear. . . . . . . . . 1,082 14.0 1,082 1,082
Hydro. . . . . . . . . . 661 8.5 661 617
----- ----- ----- ------
5,299 68.4 4,449 4,368
----- ----- ----- ------
PURCHASED:
New York Power Authority
-Hydro. . . . . . . . 1,325 17.1 1,325 1,310
-Nuclear. . . . . . . - - - 110
IPPs** . . . . . . . . . 1,125 14.5 2,382 2,406
----- ----- ----- -----
2,450 31.6 3,707 3,826
----- ----- ----- -----
Total capability*** . . . . 7,749 100.0 8,156 8,194
===== ===== ====== ======
Electric peak load. . . . . 5,928 6,348 6,021
===== ===== =====
* In 1994, Oswego Unit No. 5 (an oil-fired unit with a capability of
potentially up to 850,000 KW) was put into long-term cold standby.
In June 1998, the unit was returned to service.
** On June 30, 1998, the MRA was consummated with 14 IPPs. The MRA allowed
the Company to terminate, restate or amend 27 PPAs. The Company terminated
18 PPAs for 1,092 MW of electric generating capacity, restated eight PPAs
representing 535 MW of capacity and amended one PPA representing 42 MW of
capacity.
***Available capability can be increased during heavy load periods by
purchases from neighboring interconnected systems.
REGULATED ELECTRIC STATISTICS
1998 1997 1996
---------- ---------- ----------
REGULATED ELECTRIC SALES (MILLIONS OF KWH):
Residential . . . . . . . . . . . . . . . . . . . 9,643 9,905 10,109
Commercial. . . . . . . . . . . . . . . . . . . . 11,560 11,552 11,564
Industrial. . . . . . . . . . . . . . . . . . . . 6,843 7,191 7,148
Industrial-Special. . . . . . . . . . . . . . . . 4,568 4,507 4,326
Other . . . . . . . . . . . . . . . . . . . . . . 241 235 246
Other electric systems. . . . . . . . . . . . . . 3,577 3,746 5,431
Subsidiary. . . . . . . . . . . . . . . . . . . . - - 303
---------- ---------- ----------
36,432 37,136 39,127
========== ========== ==========
REGULATED ELECTRIC REVENUES (THOUSANDS OF DOLLARS):
Residential . . . . . . . . . . . . . . . . . . . $1,201,697 $1,227,245 $1,252,165
Commercial. . . . . . . . . . . . . . . . . . . . 1,220,067 1,233,417 1,237,385
Industrial. . . . . . . . . . . . . . . . . . . . 480,942 531,164 524,858
Industrial-Special. . . . . . . . . . . . . . . . 63,870 61,820 58,444
Other . . . . . . . . . . . . . . . . . . . . . . 55,119 54,545 53,795
Other electric systems. . . . . . . . . . . . . . 94,756 83,794 113,391
Miscellaneous . . . . . . . . . . . . . . . . . . 144,693 117,456 53,698
Subsidiary. . . . . . . . . . . . . . . . . . . . - - 15,243
---------- ---------- ----------
$3,261,144 $3,309,441 $3,308,979
========== ========== ==========
REGULATED ELECTRIC CUSTOMERS (AVERAGE):
Residential . . . . . . . . . . . . . . . . . . . 1,401,178 1,404,345 1,405,083
Commercial. . . . . . . . . . . . . . . . . . . . 146,034 146,039 145,149
Industrial. . . . . . . . . . . . . . . . . . . . 1,905 1,970 2,045
Industrial-Special. . . . . . . . . . . . . . . . 109 85 99
Other . . . . . . . . . . . . . . . . . . . . . . 1,544 1,519 1,302
Subsidiary. . . . . . . . . . . . . . . . . . . . - - 13,557
---------- ----------- ---------
1,550,770 1,553,958 1,567,235
========== ========== ==========
RESIDENTIAL (AVERAGE):
Annual KWh use per customer . . . . . . . . . . . 6,882 7,053 7,195
Cost to customer per KWh
(in cents) . . . . . . . . . . . . . . . . . . 12.46 12.39 12.39
Annual revenue per customer . . . . . . . . . . . $ 857.63 $ 873.89 $ 891.17
REGULATED GAS STATISTICS
1998 1997 1996
---------- ---------- ----------
REGULATED GAS SALES (THOUSANDS OF DTH):
Residential. . . . . . . . . . . . . . . . . 47,250 55,203 56,728
Commercial . . . . . . . . . . . . . . . . . 17,023 22,069 25,353
Industrial . . . . . . . . . . . . . . . . . 752 1,381 2,770
---------- ---------- ----------
Total sales . . . . . . . . . . . . . . . 65,025 78,653 84,851
---------- ---------- ----------
Other gas systems. . . . . . . . . . . . . . 17 28 30
Spot market. . . . . . . . . . . . . . . . . 4,501 2,451 10,459
Transportation of customer -
owned gas . . . . . . . . . . . . . . . . 127,850 152,813 134,671
---------- ---------- ----------
Total gas delivered . . . . . . . . . . . 197,393 233,945 230,011
========== ========== ==========
REGULATED GAS REVENUES (THOUSANDS OF DOLLARS):
Residential. . . . . . . . . . . . . . . . . $ 378,150 $ 436,136 $ 417,348
Commercial . . . . . . . . . . . . . . . . . 110,499 148,213 162,275
Industrial . . . . . . . . . . . . . . . . . 3,618 6,549 13,325
Other gas systems. . . . . . . . . . . . . . 69 130 138
Spot market. . . . . . . . . . . . . . . . . 8,749 6,346 37,124
Transportation of customer -
owned gas . . . . . . . . . . . . . . . . 54,091 55,657 50,381
Miscellaneous. . . . . . . . . . . . . . . . 10,053 3,932 1,083
---------- ---------- ----------
$ 565,229 $ 656,963 $ 681,674
========== ========== ==========
REGULATED GAS CUSTOMERS (AVERAGE):
Residential. . . . . . . . . . . . . . . . . 487,325 484,862 477,786
Commercial . . . . . . . . . . . . . . . . . 39,779 40,955 41,266
Industrial . . . . . . . . . . . . . . . . . 168 186 206
Other. . . . . . . . . . . . . . . . . . . . 6 6 6
Transportation . . . . . . . . . . . . . . . 3,355 2,557 713
---------- ---------- ----------
530,633 528,566 519,977
========== ========== ==========
RESIDENTIAL (AVERAGE):
Annual dekatherm use
per customer. . . . . . . . . . . . . . . 97.0 113.9 118.7
Cost to customer per Dth . . . . . . . . . . $ 8.00 $ 7.90 $ 7.36
Annual revenue per customer. . . . . . . . . $ 775.97 $ 899.51 $ 873.50
Maximum day gas sendout (Dth). . . . . . . . 1,083,802 1,133,370 1,152,996
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
The Company has nothing to report for this item.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Business Background of Directors
SALVATORE H. ALFIERO
- - Chairman and Chief Executive Officer, Mark IV Industries, Inc.
- - Director since 1998
- - Member of Corporate Public Policy & Environmental Affairs and Finance
Committees of the Board
Mr. Alfiero, age 61, Chairman and Chief Executive Officer, Mark IV Industries,
Inc., a manufacturer of engineered systems and components for power
transmission, fluid power and transfer, and filtration applications, located in
Amherst, New York. Mr. Alfiero founded Mark IV Industries, Inc. in 1969 and has
been Chairman and Chief Executive Officer since its inception. Director of
Marine Midland Bank; Phoenix Home Life Mutual Insurance Company; and Southwire
Company.
WILLIAM F. ALLYN
- - President and Chief Executive Officer of Welch Allyn, Inc.
- - Director since 1988
- - Member of Audit, Compensation and Succession, and Nuclear Oversight
Committees of the Board
Mr. Allyn, age 63, President and Chief Executive Officer of Welch Allyn, Inc.,
Skaneateles Falls, New York, 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 M&T Bank; Oneida Limited; and Perfex Corporation.
ALBERT J. BUDNEY JR.
- - President of the Company
- - Director since 1995
Mr. Budney, age 51, 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 Opinac NA; Niagara Mohawk Energy, Inc.; CNP
and Utilities Mutual Insurance Company. President of Opinac NA and Opinac.
LAWRENCE BURKHARDT III
- - Retired Rear Admiral, United States Navy
- - Director since 1988
- - Chair of Nuclear Oversight Committee of the Board
Mr. Burkhardt, age 66, independent consultant to the nuclear industry since
1990. Prior to his retirement in 1990, Mr. Burkhardt was employed by NMPC and
served as Executive Vice President of Nuclear Operations. Director of MACTEC,
Inc.
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 (Chair), and Nuclear Oversight Committees of the Board
Mr. Costle, age 59, Distinguished Senior Fellow and Chairman of the Board of the
Institute for Sustainable Communities, a non-profit organization located in
Montpelier, Vermont. 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.
WILLIAM E. DAVIS
- - Chairman of the Board and Chief Executive Officer of the Company
- - Director since 1992
- - Chair of Executive Committee of the Board
Mr. Davis, age 56, was elected Chairman of the Board and Chief Executive 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 NMPC in November 1992. Director of Opinac North
America, Inc. ("Opinac NA"); Niagara Mohawk Energy, Inc. ("NM Energy"); Canadian
Niagara Power Company, Limited ("CNP"); and Utilities Mutual Insurance Company.
Mr. Davis is also the Chairman of the Board of NM Energy and holds the position
of Secretary, Utilities Mutual Insurance Company. Opinac NA, a wholly-owned
subsidiary of the Company, holds 100 percent of Niagara Mohawk Energy and,
through its subsidiary, Opinac Energy Corporation ("Opinac"), a 50 percent
interest in CNP.
WILLIAM J. DONLON
- - Former Chairman of the Board and Chief Executive Officer of NMPC
- - Director since 1980
Mr. Donlon, age 68, retired in 1993 as Chairman of the Board and Chief Executive
Officer of NMPC with 45 years service as an active employee. Director of the
Directors' Advisory Council--Syracuse Division for M&T Bank.
ANTHONY H. GIOIA
- - Chairman and Chief Executive Officer of Gioia Management, Inc.
- - Director since 1996
- - Member of Executive, Compensation and Succession and Nuclear Oversight
Committess of the Board
Mr. Gioia, age 57, Chairman and Chief Executive Officer of Gioia Management,
Inc., a holding company for several companies, including three packaging
companies located in Buffalo and Lockport, New York. Mr. Gioia has held his
present position since 1987. Director of Greater Buffalo Savings Bank.
DR. BONNIE G. HILL
- - President and Chief Executive Officer of The Times Mirror Foundation; Vice
President of The Times Mirror Company and Sr. Vice President-Communications
and Public Affairs of The Los Angeles Times
- - Director since 1991
- - Member of Audit, Corporate Public Policy & Environmental Affairs and
Finance Committees of the Board
Dr. Hill, age 57, President and Chief Executive Officer of The Times Mirror
Foundation, a non-profit institution; Vice President of The Times Mirror
Company, a news and information company, and Sr. Vice President-Communications
and Public Affairs of The Los Angeles Times, located in Los Angeles, California.
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; Hershey Foods Corporation; and
Louisiana-Pacific Corporation.
CLARK A. JOHNSON
- - Chairman, Pier 1 Imports, Inc.
- - Director since 1998
- - Member of Compensation and Succession and Finance Committees of the Board
Mr. Johnson, age 68, Chairman of Pier 1 Imports, Inc., a specialty retailer of
imported home furnishings, gifts and related items, located in Forth Worth,
Texas. Mr. Johnson joined Pier 1 Imports, Inc. in 1985 and was elected Chairman
and Chief Executive Officer in 1987, serving in that capacity until elected
Chairman in 1998. Director of Pier 1 Imports, Inc.; Albertson's, Inc.;
InterTAN Inc.; Metro Media International Group; and Land Care, Inc.
HENRY A. PANASCI JR.
- - Chairman of Cygnus Management Group, LLC
- - Director since 1988
- - Member of Compensation and Succession, Corporate Public Policy &
Environmental Affairs and Finance Committees of the Board
Mr. Panasci, age 70, Chairman of Cygnus Management Group, LLC, a consulting firm
specializing in venture capital and private investments headquartered in
Syracuse, New York. 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.
DR. PATTI MCGILL PETERSON
- - Executive Director of the Council for International Exchange of Scholars
and Vice President of the Institute for International Education
- - Director since 1988
- - Member of Executive, Audit (Chair) and Corporate Public Policy &
Environmental Affairs Committees of the Board
Dr. Peterson, age 55, Executive Director of the Council for International
Exchange of Scholars, Washington, D.C., and Vice President of the Institute for
International Education, New York, New York, affiliated non-profit institutions.
From 1996 to 1997, Dr. Peterson was a Senior Fellow of the Cornell Institute for
Public Affairs, Cornell University, Ithaca, New York. 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.
DONALD B. RIEFLER
- - Financial Market Consultant
- - Director since 1978
- - Member of Executive, Audit, Finance (Chair) and Nuclear Oversight
Committees of the Board
Mr. Riefler, age 71, financial market consultant and advisor to J. P. Morgan,
Florida FSB, Palm Beach, Florida, 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., Inc. 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 and Succession (Chair) and Finance
Committees of the Board
Mr. Schwartz, age 64, retired as Senior Vice President of International Business
Machines Corporation in 1992. Mr. Schwartz joined IBM in 1957. In 1984 he
served as President and Chief Executive Officer of Satellite Business Systems.
He returned to IBM in 1985 and was elected Senior Vice President in 1990.
Director of MFRI, Inc.
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
The rules of the SEC require that the Company disclose late filings of reports
of ownership and changes in ownership of the Company's equity securities by its
directors, executive officers and any other person subject to Section 16 of the
Securities and Exchange Act of 1934. To the best of the Company's knowledge,
there were no late filings during 1998.
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
1998 compensation determinations were made for the Company's Chairman of the
Board and Chief Executive Officer, Mr. William E. Davis.
The 1998 Executive Officer Compensation Program was composed of base salary,
annual incentive compensation, and grants of stock units and stock appreciation
rights ("SARs") made pursuant to the Long-Term Incentive Plan ("LTIP") adopted
by the Board of Directors on September 25, 1996, 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
1998 average salary of the five named executive officers fell between the 25th
and 50th percentile competitive levels.
ANNUAL OFFICER INCENTIVE COMPENSATION PLAN ("OICP")
On December 13, 1990, the Board of Directors adopted the Company's OICP for
officers and the Management Incentive Compensation Plan for management
employees. The OICP is structured and administered so that a significant
component of each officer's annual cash compensation must be earned on the basis
of the Company's and the officer's annual performance. Maximum incentive award
opportunities for 1998 were set by the Committee at 40% of salary for Mr. Davis
and at 25% to 40% for all other officers. OICP award opportunities are intended
to position officer annual compensation (salary + OICP awards) within the 25th
to 75th percentile of Comparator Utility practice depending on company
financial, business and support unit performance. In connection with a freeze
on award cash compensation instituted in late 1995, no awards were made to
officers under the OICP for plan years 1996 and 1997. The OICP was reinstated
for the 1998 plan year.
For the 1998 plan year, awards were based on the degree to which certain
pre-established financial and operating objectives were met or exceeded. The
objectives for the 1998 plan year included economic value added (EVA), business
unit financial objectives and business/support group operating objectives.
These objectives were weighted differently for each business/support unit, based
on the applicability of such objectives to the business or support unit.
Awards for the named executive officers averaged 30.6% of their 1998 salaries.
Their average annual compensation (salary + OICP awards) fell between the 25th
and 50th percentiles of comparator utility practice. Refer to the Summary
Compensation Table for specific amounts which will be paid in early 1999 to
named executive officers under the 1998 OICP.
LONG-TERM INCENTIVE PLAN
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. Under the LTIP, dividends are credited (in an
amount equivalent to dividends paid, if any, on the Company's common stock) with
respect to stock unit grants, which would be reinvested at the prevailing stock
price, thereby increasing the number of stock units payable. These stock unit
grants will be paid in cash in early 1999 based on the average fair market value
of the Company's common stock during the last 12 consecutive trading days in
1998 ($16.138). The 1996 LTIP SAR grants became 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 12
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 December 14, 1995 stock unit and SAR grants made
under the 1995 Stock Incentive Plan ("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
these 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.
On August 25, 1998, the Board of Directors approved the accelerated granting of
LTIP stock units and SARs that would have normally been granted at the start of
1999 (for the 3-year period 1999-2001) and at the start of 2000 (for the 3-year
period 2000-2002). These LTIP grants were accelerated so as to provide
additional motivation and incentive to officers and to increase the retention
value of LTIP grants. The LTIP stock units granted with respect to the
1999-2001 period will not vest until the end of 2001, and the LTIP stock units
granted with respect to the 2000-2002 period will not vest until the end of
2002. Similarly, accelerated 1999 SAR grants do not vest and become exercisable
until January 2, 2002 and expire on December 31, 2008. Accelerated 2000 SAR
grants do not vest and become exercisable until January 2, 2003, and expire
December 31, 2009. Thus, despite the acceleration of these two stock unit and
SAR grants, the accelerated LTIP stock units would not vest and be paid, and the
accelerated SAR grants would not vest, become exercisable or expire, any sooner
than would have been the case had they been made at the start of 1999 and 2000.
Since the 1999 and 2000 LTIP stock unit and SAR grants were accelerated,
additional LTIP grants for these periods are not anticipated. The two
accelerated LTIP stock unit and SAR grants were determined so that the sum of
the average grant date value of the January 19, 1998 and the two accelerated
August 25, 1998 grants, in combination with the average salaries and incentive
award payments (at half maximum levels) of the proxy executive officers, would
approximate the 50th percentile of Comparator Utility total compensation
practice over the 3-year period, 1998-2000.
Through the combination of base salary, annual incentive compensation, 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 its
shareholders.
COMPENSATION OF WILLIAM E. DAVIS, CHAIRMAN OF THE
BOARD AND CHIEF EXECUTIVE OFFICER
Mr. Davis became Chief Executive Officer on May 1, 1993. During 1998, Mr.
Davis's salary was increased to its current annual rate of $570,000. The
increase in Mr. Davis's salary reflected an evaluation of his performance and
the fact that his salary was well below the 25th percentile relative to salaries
paid to CEOs at electric and gas utilities with comparable revenues. The
Committee has been advised by its consultant that Mr. Davis's current annual
salary approximates the 25th percentile of this comparison group. With respect
to 1998, Mr. Davis earned an annual incentive compensation award in the amount
of $180,937, which represented 34.139% of the salary he received in 1998. This
award will be paid in early 1999 pursuant to the terms of the OCIP and financial
and operating objectives approved by the Committee for 1998. These objectives
related to economic value added (EVA), business unit financial performance, and
business/support group operating performance. Mr. Davis's 1998 annual
compensation (salary + OICP award) fell between the 25th and 50th percentiles of
comparator utility practice.
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 will depend on the market value of the Corporation'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. This
grant consisted of 35,000 stock units and 125,000 SARs with an exercise price of
$10.90. 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.
On August 25, 1998, the Board of Directors approved an accelerated grant of LTIP
stock units and SARs to Mr. Davis that would have normally been granted at the
start of 1999 (for the 3-year period 1999-2001) and at the start of 2000 (for
the 3-year period 2000-2002). Each of these grants consisted of 28,000 stock
units and 100,000 SARs, with an exercise price of $15.36. These grants were
accelerated in order to increase the incentive and retention value of these LTIP
grants. Despite the acceleration of these grants, the stock units will not vest
and be paid, and the SARs will not vest, become exercisable or expire any sooner
than would have been the case had they been granted at the start of 1999 and
2000. Additional LTIP grants to Mr. Davis for these periods are not
anticipated. The two accelerated LTIP stock unit and SAR grants were determined
so that the sum of the average grant date value of the January 19, 1998 and the
two August 25, 1998 LTIP grants, in combination with Mr. Davis's salary and
incentive award payment (at half maximum level) would approximate the 50th
percentile of Comparator Utility total compensation practice over the three-year
period 1998-2000.
Under Section 162(m) of the Internal Revenue Code, the Company may not deduct
certain forms of compensation in excess of $1,000,000 paid to a named executive
officer. The Committee continually reviews executive compensation plans and
programs for changes to comply with the limit, where appropriate. The
Committee believes it is important to maintain flexibility in its executive
compensation plans in order to attract and retain high quality executives,
which may result in compensation being paid in a particular year in excess of
the limit. In 1998, a substantial increase in the value of a share of common
stock resulted in a corresponding increase in the value of stock-based
compensation. As a result, the compensation of Mr. Davis exceeded the limit.
_______________
Submitted by the Compensation and Succession Committee of the Board of
Directors:
Stephen B. Schwartz, Chair
William F. Allyn
Anthony H. Gioia
Clark A. Johnson
Henry A. Panasci Jr.
EXECUTIVE COMPENSATION
The following table shows, for the last three fiscal years, cash and other
compensation paid to the Chairman of the Board and Chief Executive Officer and
to each of the other four most highly compensated executive officers of the
Company for fiscal year ended December 31, 1998.
SUMMARY COMPENSATION TABLE
FISCAL YEARS 1998, 1997 AND 1996
Annual Compensation Long-Term Compensation
Awards
------------------------ --------------------------
Other Securities All
Annual Restricted Underlying Other
Compen- Stock Options/ Compen-
Name and Principal Salary Bonus sation Awards SARs sation
Position Year ($)(A) ($) ($)(B) ($)(C) (#) ($)(E)
- ----------------------------------------------------------------------------------------------
1998 530,001 180,937 218 1,256,500(D) 325,000(D) 44,539
W. E. Davis 1997 450,501 0 110 371,875 70,000 42,358
Chairman and CEO 1996 462,351 0 0 360,000 90,000 43,365
- ------------------------ ---- ------- ------- ------ --------- ------- ------
1998 366,001 124,949 218 503,750(D) 170,000(D) 18,051
A. J. Budney Jr. 1997 315,002 0 110 185,938 35,000 16,436
President 1996 315,002 0 2,956 180,000 45,000 24,975
- ------------------------ ---- ------- ------- ------ --------- ------- ------
1998 256,334 79,942 218 371,100(D) 119,000(D) 9,583
D. D. Kerr 1997 210,001 0 110 85,000 16,000 7,953
Executive Vice President 1996 210,001 0 0 82,000 20,500 9,415
- ------------------------ ---- ------- ------- ------ --------- ------- ------
1998 255,835 48,519 11,585 324,413(D) 104,000(D) 30,529
J. H. Mueller 1997 - - - - - -
Senior Vice President 1996 - - - - - -
- ------------------------ ---- ------- ------- ------ --------- ------- ------
1998 222,001 63,936 16,370 290,313(D) 89,000(D) 29,283
G. J. Lavine 1997 191,502 0 110 85,000 16,000 8,565
Senior Vice President 1996 191,502 0 0 82,000 20,500 8,571
- ------------------------ ---- ------- ------- ------ --------- ------- ------
<
(A) Includes all employee contributions to the Employees' Savings Fund Plan.
(B) Other Annual Compensation for Mr. Budney in 1996 and for Mr. Mueller in
1998 represents or includes amounts reimbursed for payment of taxes
associated with relocation expenses. 1997 and 1998 Other Annual
Compensation for Messrs. Davis, Budney, Kerr, Mueller and Lavine represents
or includes amounts reimbursed for payment of taxes associated with
non-cash compensation. 1998 Other Annual Compensation for Mr. Lavine
includes amounts reimbursed for payment of taxes associated with
Company-paid legal expenses.
(C) In 1996, 88,000 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 stock units vested and became payable on
December 31, 1998. No dividend equivalents were credited on these stock
units. 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.
In 1997, 68,500 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.
In 1998, 82,700 stock units were granted in January and 118,000 in August
(consisting of two grants of 59,000 each) to the above named executive
officers pursuant to the LTIP adopted by the Board of Directors on
September 25, 1996. The first grant was made for a three-year period
January 1, 1998 through December 31, 2000, and vest and become payable
on December 31, 2000; the second grant was made for a three-year period
January 1, 1999 through December 31, 2001, and vest and become payable
on December 31, 2001; and the third grant was made for a three-year period
January 1, 2000 through December 31, 2002, and vest and become payable on
December 31, 2002. The 1998 values listed in the table were calculated by
multiplying the stock units granted in January by $12.00 and those granted
in August by $15.5625, the prices 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 1998 fiscal year, based on a closing market price of
$16.125, Mr. Davis held 171,000 stock units having a market value of
$2,757,375; Mr. Budney held 77,500 stock units having a market value of
$1,249,688; Ms. Kerr held 45,350 stock units having a market value of
$731,269; Mr. Mueller held 24,100 stock units having a market value of
$388,613; and Mr. Lavine held 39,250 stock units having a market value of
$632,906.
(D) This amount represents three distinct grants from the LTIP. The first
grant will vest and become payable (in the case of stock units) and
exercisable (in the case of SARs) after December 31, 2000; the second
after December 31, 2001; and the third after December 31, 2002. No
additional grants for these periods are anticipated.
(E) All Other Compensation for 1998 includes: employer contributions to the
Company's Employees' Savings Fund Plan: Mr. Davis ($4,793), Mr. Budney
($1,955), Ms. Kerr ($4,758), Mr. Mueller ($5,044), and Mr. Lavine ($4,797);
taxable portion of life insurance premiums: Mr. Davis ($15,935), Mr.
Budney ($2,821), Ms. Kerr ($2,020), Mr. Mueller ($3,565), and Mr. Lavine
($3,243); payments under the Company's Relocation Policy: Mr. Mueller
($21,673); employer contributions to the Company's Excess Benefit Plan:
Mr. Davis ($10,811), Ms. Kerr ($2,805), and Mr. Lavine ($1,747);
directors' fees received from Canadian Niagara Power Corporation: Mr.
Davis ($13,000) and Mr. Budney ($13,000); personal travel allowance:
Mr. Budney ($275) and Mr. Mueller ($247); Company-paid legal expenses:
Mr. Lavine ($19,496).
The following table discloses, for the Chairman of the Board and Chief Executive
Officer, Mr. William E. Davis, and the other named executive officers, the
number and terms of SARs granted during the fiscal year ended December 31, 1998.
OPTION/SAR GRANTS IN LAST FISCAL YEAR
Individual Grants
--------------------------------------------------
Number of % of Total Grant
Securities Options/SARs Exercise Date
Underlying Granted to or Present
Options/SARs Employees in Base Price Expiration Value
Name Granted (#) Fiscal Year ($/Sh) Date (A) ($)(B)
- ---------------------------------------------------------------------------------
W.E. Davis 125,000 7.37 10.90 12/31/2007 478,750
100,000 6.00 15.36 12/31/2008 773,000
100,000 6.00 15.36 12/31/2009 802,000
A.J. Budney Jr. 70,000 4.13 10.90 12/31/2007 268,100
50,000 2.95 15.36 12/31/2008 386,500
50,000 2.95 15.36 12/31/2009 401,000
D.D. Kerr 39,000 2.30 10.90 12/31/2007 149,370
40,000 2.36 15.36 12/31/2008 309,200
40,000 2.36 15.36 12/31/2009 320,800
J.H. Mueller 39,000 2.30 10.90 12/31/2007 149,370
32,500 1.92 15.36 12/31/2008 251,225
32,500 1.92 15.36 12/31/2009 260,650
G.J. Lavine 24,000 1.42 10.90 12/31/2007 91,920
32,500 1.92 15.36 12/31/2008 251,225
32,500 1.92 15.36 12/31/2009 260,650
(A) In 1998, the Board of Directors made three grants of SARs under the
LTIP. The first grant of SARs that expire on December 31, 2007 become
exercisable January 2, 2001; the second grant of SARs that expire on
December 31, 2008 become exercisable January 2, 2002; and the third grant
of SARs that expire on December 31, 2009 become exercisable January 2,
2003. 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:
(1) exercise price of rights that expire on December 31, 2007 ($10.90);
stock volatility (29.57%); dividend yield (2.86%); risk free rate
(6.25%); exercise term (10 years); Black-Scholes ratio (.3512);
and Black-Scholes value ($3.83) for rights that expire on December
31, 2007. Stock volatility and dividend yield assumptions are based
on 36 months of results for the period ending December 31, 1998.
(2) exercise price of rights that expire on December 31, 2008 ($15.36);
stock volatility (31.10%); dividend yield (0.86%); risk free rate
(6.25%); exercise term (10 1/3 years); Black-Scholes ratio (.5031);
and Black-Scholes value ($7.73) for rights that expire on
December 31, 2008. Stock volatility and dividend yield assumptions
are based on 36 months of results for the period ending December 31,
1998.
(3) exercise price of rights that expire on December 31, 2009 ($15.36);
stock volatility (31.10%); dividend yield (0.86%); risk free rate
(6.25%); exercise term (11 1/3 years); Black-Scholes ratio (.5224);
and Black-Scholes value ($8.02) for rights that expire on December 31,
2009. Stock volatility and dividend yield assumptions are based on 36
months of results for the period ending December 31, 1998.
The following table summarizes exercises of options by the Chairman of the
Board and Chief Executive Officer, Mr. William E. Davis, and the other named
executive officers, the number of unexercised options held by them and the
spread (the difference between the current market price of the stock and the
exercise price of the option, to the extent that market price at the end of the
year exceeds exercise price) on those unexercised options for fiscal year ended
December 31, 1998.
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION/SAR VALUES
Number of Securities
Shares Underlying Unexercised Value of Unexercised
Acquired Value Options/SARs at Fiscal Year Options/SARs at Fiscal Year
on Exercise Realized End (#) End ($)(A)
--------------------------- ---------------------------
Name (#) ($) Exercisable Unexercisable Exercisable Unexercisable
- ----------------------------------------------------------------------------------------------
W.E. Davis 0 0 185,125 485,000 787,188 1,945,125
A.J. Budney Jr. 0 0 76,000 250,000 376,000 1,011,750
D.D. Kerr 6,000 28,320 31,500 155,500 125,063 524,738
J.H. Mueller 0 0 0 104,000 0 253,501
G.J. Lavine 0 0 37,500 125,500 157,313 434,889
_______________
(A) Calculated based on the closing market price of the Company's Common
Stock on December 31, 1998 ($16.125).
PERFORMANCE GRAPH
NIAGARA MOHAWK POWER CORPORATION
COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN
VS. S&P 500 INDEX AND EEI INDEX
[ILLUSTRATION OF PERFORMANCE GRAPH ]
Data Points
1993 1994 1995 1996 1997 1998
---- ---- ---- ---- ---- ----
NMPC 100.00 75.38 54.93 57.10 60.71 93.23
S&P 500 Index 100.00 101.32 139.40 171.40 228.59 293.91
EEI Index 100.00 87.12 110.96 110.27 142.54 165.62
Assumes $100 invested on December 31, 1993 in Niagara Mohawk stock, S&P 500 and
the Edison Electric Institute Combination Gas and Electric Investor-Owned
Utilities Index ("EEI Index"). All dividends assumed to be reinvested over the
five-year period.
RETIREMENT BENEFITS
NIAGARA MOHAWK PENSION PLAN
The Niagara Mohawk Pension Plan ("Basic Plan") is a noncontributory,
tax-qualified defined benefit plan and provides all employees of the Company
with a minimum retirement benefit. This retirement benefit is related to
compensation--that is, base salary or pay--subject to the maximum annual limits
noted in the Retirement Benefits Table.
The participant's Basic Plan retirement benefit is based on one of two formulas
depending on age and years of service on July 1, 1998:
- - the cash balance formula; or
- - the highest five-year average compensation.
Effective July 1, 1998, the Basic Plan was amended to include a cash balance
formula. Under a cash balance formula, a participant's retirement benefit grows
with pay credits (4% - 8% x salary) plus interest credits on a monthly basis. A
non-represented (management) employee who was at least 45 years of age and has
10 years of service on July 1, 1998 will receive the higher of the two
formulas--the cash balance formula or the highest consecutive five-year
compensation. All other non-represented employees' Basic Plan benefit will be
based on the cash balance formula only. Directors who are not employees are not
eligible to participate in the Basic Plan.
SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN
The Supplemental Executive Retirement Plan ("SERP") is a noncontributory,
nonqualified defined benefit plan that provides additional retirement benefits
to officers of the Company who have obtained age 55 and who have 20 or more
years of employment. The Committee may grant exceptions to the age and service
requirements.
The SERP provides a benefit equal to the greater of:
(i) 60% of base salary averaged over
the final 36 months of employment, reduced by benefits payable under the
Basic Plan; retirement benefits accrued during previous employment and
one-half of the maximum 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.
Provided certain established criteria are met, participants in the SERP may
elect to receive their benefit in a lump sum payment.
The following table shows the maximum retirement benefit (adjusted for Social
Security) an officer can earn in aggregate under both the Basic Plan and the
SERP.
ANNUAL RETIREMENT ALLOWANCE
3-Year
Average Year of Service
Annual -------------------------------------------------------------------
Salary 10* 15* 20 25 30 35
- -------------------------------------------------------------------------------
150,000 $21,090 $33,885 $ 81,762 $ 81,762 $ 81,762 $ 81,762
225,000 21,670 34,815 126,762 126,762 126,762 126,762
300,000 21,670 34,815 171,762 171,762 171,762 171,762
375,000 21,670 34,815 216,762 216,762 216,762 216,762
450,000 21,670 34,815 261,762 261,762 261,762 261,762
525,000 21,670 34,815 306,762 306,762 306,762 306,762
*Subject to the Basic Plan benefit.
The benefit calculations assume the officer has selected a straight life annuity
and retired on December 31, 1998 at age 65. Annual compensation limits
($150,000 in 1996; $160,000 for 1997 and 1998) under a tax-qualified plan will
reduce the benefit amount collectible under the Basic Plan for some highly
compensated officers.
As of December 31, 1998, the persons named in the Summary Compensation Table had
the following estimated credited years of benefit service for purposes of the
pension program: Mr. Davis, 9 years; Mr. Budney, 4 years; Ms. Kerr, 26 years;
Mr. Mueller, 3 years; and Mr. Lavine, 12 years.
EMPLOYEE AGREEMENTS
The Company entered into employment agreements with Messrs. Davis, Budney,
Lavine, Mueller and Ms. Kerr, which have a rolling three-year term. 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 equal to the executive's annual salary at the effective date of the
agreements or such greater amount determined by the Company, that the executive
will be able to participate in the Company's incentive compensation plans and
that the executive is entitled to vacation, 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. If the 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 for the remainder of the executive's life with all premiums therefor
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 at any time, or by the executive for good reason after
a change in control (as such terms are defined in the agreement), or after
completing eight years of service, the agreements provide that the executive
will be deemed fully vested under the SERP without reduction for early
commencement. If the executive is under age 55, the executive will be entitled
to a fully vested SERP benefit upon attaining age 55, without reduction for
early commencement.
If the executive's employment is terminated by the Company without cause prior
to a change in control, 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. 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. 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, 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 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.
DIRECTOR COMPENSATION
ANNUAL CASH RETAINER FEES
Directors who are not employees of the Company receive an annual retainer of
$20,000. Non-employee directors who chair any of the Board Committees receive
an additional annual fee of $3,000.
MEETING FEES
Directors who are not employees of the Company receive a fee of $1,000 for
attending each Board meeting and $850 for each Committee meeting. Directors are
reimbursed for their travel, lodging and related expenses.
OUTSIDE DIRECTOR DEFERRED STOCK UNIT PLAN
In 1996, the Board of Directors adopted an Outside Director Deferred Stock Unit
Plan.
Each outside director is credited with deferred stock units ("DSUs") on an
annual basis equal in value to $15,000 ($17,000 for Committee Chairs).
Accordingly, all outside directors were credited with 1,011 DSUs (1,145 for
Committee Chairs) based on the average of the opening and closing price of a
share of common stock on June 30, 1998 ($14.84375). The beneficial stock
ownership table in Item 12, shows the total number of DSUs credited to each of
the outside directors under this plan as of March 12, 1999.
When a director ceases to be an outside director, the amount of DSUs credited to
him or her is paid 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.
HEALTH AND LIFE INSURANCE BENEFITS
The Company provides certain health and life insurance benefits to directors
who are not employees of the Company. Each outside director who elected
coverage under the Company's health care plans contributes a portion of the
monthly costs associated with these plans. During 1998, the following health
and life insurance benefits were received by the following directors: Mr.
Alfiero ($138), Mr. Burkhardt ($5,448), Mr. Costle ($3,980), Mr. Donlon ($288),
Mr. Gioia ($7,665), Dr. Hill ($4,040), Mr. Panasci ($187), Dr. Peterson
($3,114), Mr. Riefler ($6,163) and Mr. Schwartz ($552).
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The following table indicates the number of shares of Common Stock owned by
persons known to the Company to own beneficially more than 5% of the outstanding
Common Stock as of December 31, 1998.
Name and Address of Beneficial Amount and Nature of Percent
Title of Class Owner Beneficial Ownership of Class
- -------------------------- ----------------------------- -------------------- --------
Common Stock. . . . . . . . . . . Tiger Management LLC 12,714,700(a) 6.8%
101 Park Avenue
New York, NY 10178
Common Stock. . . . . . . . . . . FMR Corp. 10,877,491(b) 5.805%
82 Devonshire Street
Boston, Massachusetts 02109
Common Stock. . . . . . . . . . . Fidelity Management Trust Co. 10,074,275(c) 5.377%
82 Devonshire Street
Boston, Massachusetts 02109
(a) Tiger Management L.L.C. has shared voting power pursuant to Schedule
13G, dated February 12, 1999, filed with the SEC.
(b) Includes 1,271,991 shares with respect to which FMR Corp. has sole
voting power and 10,877,491 with sole power to dispose or to direct
disposition as reported on Schedule 13G, dated February 1, 1999, filed
with the Securities and Exchange Commission.
(c) 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.
Approximately 83.8% or 156,937,575 shares of the Company's common stock
outstanding as of December 31, 1998, are held by shareholders who elected to
hold their shares, not in their own names, but in the names of banking or
financial intermediaries. These shares are registered in the nominee name of
The Depository Trust Company, Cede & Co.
SECURITY OWNERSHIP OF DIRECTORS AND EXECUTIVE OFFICERS
The following table indicates the number of shares of the Company's Common
Stock beneficially owned as of December 31, 1998, by each director of the
Company, each of the executive officers named 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 pursuant to the Company's compensation and benefit programs as of
December 31, 1998. No voting rights are associated with stock units.
TITLE OF AMOUNT AND NATURE OF PERCENT STOCK UNITS
CLASS NAME OF BENEFICIAL OWNER BENEFICIAL OWNERSHIP* OF CLASS HELD
- ------------------------------------------------------------------------------------------
Common Stock
DIRECTORS:
Salvatore H. Alfiero. . . . 5,000 ** 1,011(6)
William F. Allyn. . . . . . 1,000 ** 10,169(6)
Albert J. Budney Jr.. . . . 10,625(1) ** 77,500(7)
Lawrence Burkhardt III. . . 452 ** 3,918(6)
Douglas M. Costle . . . . . 500 ** 10,696(6)
William E. Davis. . . . . . 45,431(2) ** 171,000(7)
William J. Donlon . . . . . 2,010 ** 337(6)
Anthony H. Gioia. . . . . . 500 ** 3,322(6)
Bonnie G. Hill. . . . . . . 1,000 ** 9,088(6)
Clark A. Johnson. . . . . . 0 ** 1,011(6)
Henry A. Panasci Jr.. . . . 2,500 ** 3,322(6)
Patti McGill Peterson . . . 500 ** 12,344(6)
Donald B. Riefler . . . . . 1,000 ** 27,022(6)
Stephen B. Schwartz . . . . 500 ** 12,349(6)
NAMED EXECUTIVES:
Darlene D. Kerr . . . . . . 15,972(3) ** 45,350(7)
John H. Mueller . . . . . . 342 ** 24,100(7)
Gary J. Lavine. . . . . . . 17,555(4) ** 39,250(7)
All Directors and Executive
Officers (24) as a group. . 157,967(5) ** 506,850
* 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 December 31, 1998.
** Less than one percent.
(1) Includes presently exercisable options for 10,000 shares of Common Stock.
(2) Includes presently exercisable options for 42,625 shares of Common Stock.
(3) Includes presently exercisable options for 9,000 shares of Common Stock.
(4) Includes presently exercisable options for 12,000 shares of Common Stock.
(5) Includes presently exercisable options for 106,375 shares of Common Stock.
(6) Represents deferred stock units granted pursuant to the Outside Director
Deferred Stock Unit Plan. For additional information regarding deferred
stock units, refer to Item 11, Director Compensation.
(7) Represents stock units granted in 1997, 1998 and 1999 pursuant to the
Long-Term Incentive Plan. For additional information regarding stock units
granted to named executives, refer to Item 11, Long-Term Incentive Plan.
In addition to the shares of the Company's common stock, Albert J. Budney Jr.
indirectly owns 100 shares of preferred stock, 9 % Series.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
COMPENSATION AND SUCCESSION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
No person serving during 1998 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 1998.
No person serving during 1998 as an executive officer of the Company is or was
a director or a member of the compensation committee of any other entity that
has an executive officer who is or was a member of the Compensation and
Succession Committee or a member of the Board of Directors of Niagara Mohawk
Holdings, Inc.
RELATED TRANSACTIONS
Lawrence Burkhardt III received a consulting fee of $18,000 during 1998.
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 Management
- - Report of Independent Accountants
- - Consolidated Statements of Income and Retained Earnings for each of the
three years in the period ended December 31, 1998
- - Consolidated Statements of Comprehensive Income for each of the three years
in the period ended December 1998
- - Consolidated Balance Sheets at December 31, 1998 and 1997
- - Consolidated Statements of Cash Flows for each of the three years in the
period ended December 31, 1998
- - 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, 1998, 1997 and 1996 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 - December 3, 1998
Items reported:
(1) Item 5. Other Events.
Registrant filed press release regarding the Company's agreement
to sell its hydroelectric generating plants.
(2) Item 7. Financial Statement and Exhibits.
Exhibits required to be filed by Item 601 of Regulation S-K.
Form 8-K Reporting Date - December 23, 1998
Items reported:
(1) Item 5. Other Events.
(a) Registrant filed press release regarding a favorable ruling
from the Internal Revenue Service regarding current
deductibility of consideration paid to certain IPPs to
terminate power contracts under the MRA.
(b) Registrant filed press release regarding the Company's
agreement to sell its two coal-fired electric generating
plants.
(2) Item 7. Financial Statements and Exhibits.
Exhibits required to be filed by Item 601 of Regulation S-K.
Form 8-K Reporting Date - January 28, 1999
Items reported:
(1) Item 5. Other Events
(a) Registrant filed press release announcing plans to pursue
the sale of the Company's Unit 1 nuclear and plant and its
41% ownership in the Unit 2 nuclear plant.
(b) Registrant filed a press release regarding annual and fourth
quarter earnings for 1998.
(2) Item 7. Financial Statements and Exhibits.
Exhibits required to be filed by Item 601 of Regulation S-K.
(c) Exhibits.
See Exhibit Index.
(d) Financial Statement Schedule
See (a)(2) above.
REPORT OF INDEPENDENT ACCOUNTANTS ON
FINANCIAL STATEMENT SCHEDULE
To the Board of Directors of
Niagara Mohawk Power Corporation
Our audits of the consolidated financial statements of Niagara Mohawk Power
Corporation referred to in our report dated January 28, 1999 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/PricewaterhouseCoopers LLP
- -----------------------------
PricewaterhouseCoopers LLP
Syracuse, New York
January 28, 1999
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
1998. . . . . . . . . . . $ 62,548 $ 31,727 $ 5,000 (b) $ 51,412 $ 47,863
1997. . . . . . . . . . . 52,096 46,549 3,000 (b) 39,097 62,548
1996. . . . . . . . . . . 20,000 127,648 800 (b) 96,352 52,096
(a) Uncollectible accounts written off net of recoveries of $14,734,
$14,416, and $12,842 in 1998, 1997 and 1996, respectively.
(b) The Company has recorded a regulatory asset, which reflects the amount
of doubtful accounts reserved for what the Company expects to recover in
rates. In 1996, regulatory asset increased by $800 to $17,200; in 1997,
the regulatory asset was increased by $3,000 to $20,200; and in 1998, the
regulatory asset was increased by $5,000 to $25,200.
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
1998. . . . . . . . . . . $ 45,261 $ 769 $ - $ 12,967 $ 33,063
1997. . . . . . . . . . . 47,103 2,207 - 4,049 45,261
1996. . . . . . . . . . . 48,789 10,261 - 11,947 47,103
(c) The reserves relate primarily to certain inventory and non-rate base
properties.
NOTE: The 1996 and 1997 balances have been restated to reflect the inclusion
of the reserve for loss on the Company's investment in NM Uranium, Inc.
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:
Reference Report Name
- --------- -----------
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
SSS NMPC Registration Statement No. 33-49541
b NMPC Annual Report on Form 10-K for year ended December 31, 1990
c NMPC Annual Report on Form 10-K for year ended December 31, 1992
d NMPC Annual Report on Form 10-K for year ended December 31, 1993
e NMPC Annual Report on Form 10-K for year ended December 31, 1994
f NMPC Annual Report on Form 10-K for year ended December 31, 1995
g NMPC Annual Report on Form 10-K for year ended December 31, 1996
h NMPC Annual Report on Form 10-K for year ended December 31, 1997
i NMPC Quarterly Report on Form 10-Q for quarter ended March 31, 1993
j NMPC Quarterly Report on Form 10-Q for quarter ended September 30,
1993
k NMPC Quarterly Report on Form 10-Q for quarter ended June 30, 1995
l NMPC Quarterly Report on Form 10-Q for quarter ended June 30, 1997
m NMPC Quarterly Report on Form 10-Q for quarter ended September
30, 1997
n NMPC Quarterly Report on Form 10-Q for quarter ended March 31, 1998
o NMPC Quarterly Report on Form 10-Q for quarter ended June 30, 1998
p NMPC Quarterly Report on Form 10-Q for quarter ended September
30, 1998
q NMPC Report on Form 8-K dated July 9, 1997
r 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 bank
financing that the Company completed with a bank group during March 1996 and
subsequently amended (effective June 30, 1998). 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(a)(47) Certificate of Amendment of Certificate
of Incorporation of NMPC under Section 805
of the Business Corporation Law of New
York filed June 29, 1998 in the office of
the New York Secretary of State o 3
3(b)(1) By-Laws of NMPC, as amended April 23, 1998 n 3(i)
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 **
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) i 4(b)(82)
4(b)(34) Supplemental Indenture dated as of
July 1, 1993, supplemental to
Exhibit 4(1) j 4(b)(83)
4(b)(35) Supplemental Indenture dated as of
September 1, 1993, supplemental to
Exhibit 4(1) j 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) k 4(87)
4(b)(39) Supplemental Indenture dated
as of March 20, 1996, supplemental
to Exhibit 4(1) SSS 4(a)(39)
4(b)(40) 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
4(c) Form of Indenture relating to the Senior
Notes dated June 30, 1998 SSS 4(a)(41)
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
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
10-10 Master Restructuring Agreement, dated as
of July 9, 1997, between the Company and
the sixteen independent power producers
signatory thereto q 10.28
10-11 POWERCHOICE settlement filed with the PSC
on October 10, 1997 r 99-9
10-12 PSC Opinion and Order regarding approval h 10-13
of the POWERCHOICE settlement agreement
with PSC, issued and effective
March 20, 1998
10-13 Preferred Consent, December, 1997 h 10-14
10-14 Amendments to the Master Restructuring
Agreement n 10(c)
(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 h 10-20
(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
B. Ralph Sylvia, Executive Vice
President, Electric Generation and
Chief Nuclear Officer, dated
December 20, 1996 g 10-23
(A)10-30 Employment Agreement between NMPC and
Theresa A. Flaim, Vice President -
Corporate Strategic Planning, dated
December 20, 1996 g 10-24
(A)10-31 Employment Agreement between NMPC and
Steven W. Tasker, Vice President -
Controller, dated December 20, 1996 g 10-25
(A)10-32 Employment Agreement between NMPC and
Kapua A. Rice, Corporate Secretary,
dated December 20, 1996 g 10-26
(A)10-33 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)10-34 Employment Agreement between NMPC and
William F. Edwards, dated September
25, 1997 m 10-4
(A)10-35 Employment Agreement between NMPC and
John H. Mueller, dated January 19, 1998 h 10-36
(A)10-36 Deferred Stock Unit Plan for Outside
Directors g 10-27
(A)10-37 Amendment to the Deferred Stock Unit o 10
Plan for Outside Directors
(A)10-38 Amendment to the Deferred Stock Unit p 10
Plan for Outside Directors
*(A)10-39 Employment Agreement between NMPC
and Thomas H. Baron, dated October 22, 1998
*(A)10-40 Employment Agreement between NMPC
and Edward J. Dienst, dated October 22, 1998
*(A)10-41 Amendment to the NMPC Officers
Incentive Compensation Plan
*11 Statement setting forth the computation of
average number of shares of common stock
outstanding
*12 Statements Showing Computations of
Certain Financial Ratios
*21 Subsidiaries of the Registrant
*23 Consent of PricewaterhouseCoopers LLP,
independent accountants
*27 Financial Data Schedule
- -------------------------
**Filed October 15, 1937 after effective date of Registration Statement No.
2-3414.
(A) Management contract or compensatory plan or arrangement required to be
filed as an exhibit pursuant to Item 601 of Regulation S-K.
EXHIBIT (A) 10-39
EMPLOYMENT AGREEMENT
Agreement made as of the 22nd day of October, 1998, between NIAGARA
MOHAWK POWER CORPORATION (the "Company"), and Thomas H. Baron (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 October 22,
1998 and expiring on December 31, 2001, subject to earlier termination as
provided under paragraph 4 hereof. This Agreement shall be extended
automatically by one year commencing on January 1, 2000 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 - Field Operations. 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
$215,000, 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, 1995 Stock Incentive 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 ACause@ 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 AOICP@) 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). For purposes of the first sentence of this
paragraph 4f, there shall be taken into account as bonus paid to the Executive
for each of the years 1996 and 1997 under the OICP one-half of the sum of (x)
cash payments with respect to Restricted Stock Units (and related Dividend
Equivalents) granted to the Executive under the Corporation's 1995 Stock
Incentive Plan and (y) the result of multiplying the number of Stock
Appreciation Rights granted to the Executive under the Corporation's 1995
Stock Incentive Plan by the difference between (1) the value of one share of
the Corporation's common stock on December 31, 1997 and (2) the Base
Value ($10.75).
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
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
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 ten
(10) 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 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:
4953 Bryn Mawr Drive
Syracuse, NY 13215
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
Thomas H. Baron
By:______________________________
DAVID J. ARRINGTON
Senior Vice President -
Human Resources
SCHEDULE A
Modifications in Respect of Thomas H. Baron ("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. If the Executive is an employee of
the Company on December 31, 1997, there shall be taken into account for
purposes of the preceding sentence as an annual bonus under the OICP, the sum
of (x) cash payments made with respect to Stock Units (and related Dividend
Equivalents) granted to the Executive under the SIP and (y) the result of
multiplying the number of Stock Appreciation Rights granted to the Executive
under the SIP, prorated if applicable to Article 9 of the SIP, by the
difference between (1) the value of one share of the Corporation's common
stock on December 31, 1997 and (2) the Base Value ($10.75).
II. Subsection 2.1 of Section II of the SERP is hereby modified to provide that
full SERP benefits are vested following ten (10) 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 (A) 10-40
EMPLOYMENT AGREEMENT
Agreement made as of the 22nd day of October, 1998, between NIAGARA MOHAWK
POWER CORPORATION (the "Company"), and Edward J. Dienst (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 October 22, 1998
and expiring on December 31, 200l, subject to earlier termination as provided
under paragraph 4 hereof. This Agreement shall be extended automatically
by one year commencing on January 1, 2000 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
- - Customer Delivery & Asset Management. 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
$215,000, 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, 1995 Stock Incentive 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). For purposes of the first sentence
of this paragraph 4f, there shall be taken into account as bonus paid to the
Executive for each of the years 1996 and 1997 under the OICP one-half of
the sum of (x) cash payments with respect to Restricted Stock Units (and
related Dividend Equivalents) granted to the Executive under the Corporation's
1995 Stock Incentive Plan and (y) the result of multiplying the number of
Stock Appreciation Rights granted to the Executive under the Corporation's
1995 Stock Incentive Plan by the difference between (1) the value of
one share of the Corporation's common stock on December 31, 1997 and (2) the
Base Value ($10.75).
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 hightest 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 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 ten (10)
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 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:
1053 The Lane
Skaneateles, NY 13152
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
Edward J. Dienst
By:______________________________
DAVID J. ARRINGTON
Senior Vice President -
Human Resources
SCHEDULE A
Modifications in Respect of Edward J. Dienst ("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. If the Executive
is an employee of the Company on December 31, 1997 there shall be taken
into account for purposes of the preceding sentence as an annual bonus under
the OICP, the sum of (x) cash payments made with respect to Stock Units (and
related Dividend Equivalents) granted to the Executive under the SIP and (y)
the result of multiplying the number of Stock Appreciation Rights granted to the
Executive under the SIP, prorated if applicable to Article 9 of the SIP, by
the difference between (1) the value of one share of the Corporation's common
stock on December 31, 1997 and (2) the Base Value ($10.75).
II. Subsection 2.1 of Section II of the SERP is hereby modified to provide that
full SERP benefits are vested following ten (10) 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.
NIAGARA MOHAWK EXHIBIT 10-41
OFFICERS ANNUAL INCENTIVE COMPENSATION PLAN
Article 1. Establishment, Purpose and Duration
1.1 Establishment of the Plan. Niagara Mohawk Power Corporation, a New York
corporation hereinafter referred to as the "Company"), hereby amends and
restates the Niagara Mohawk Officers Annual Incentive Compensation Plan
(hereinafter referred to as the "Plan"), as set forth in this document. The
Plan permits the grant of cash awards, Contingent Stock Units and Dividend
Equivalents, as defined herein.
The Plan became effective as of December 31, 1990 (the "Effective Date"). This
amendment and reinstatement of the Plan is effective as of December 10,
1998 and shall remain in effect as provided in Section 1.3 herein.
1.2 Purpose of the Plan. The purpose of the Plan is to encourage the
achievement of the Company's financial and operating objectives; to assist
the Company in attracting and retaining highly qualified executives; and to
enhance the mutual interest of customers, shareholders and employees.
Article 2. Definitions
Whenever used in the Plan, the following terms shall have the meanings set forth
below and, when such meaning is intended, the initial letter of the
word is capitalized:
2.1 "Award" means, individually or collectively, a grant under the Plan of
Contingent Stock Units.
2.2 "Award Agreement" means an agreement entered into by each Participant and
the Company, setting forth the terms and provisions applicable to an
Award granted to a Participant under the Plan.
2.3 "Board" or "Board of Directors" means the Board of Directors of the Company.
2.4 "Cause" means: (i) a material default or other material breach by a
Participant of his obligations under any Employment Agreement he may have
with the Company, (ii) failure by a Participant diligently and competently to
perform his duties under any Employment Agreement he may have with the
Company, or otherwise, or (iii) misconduct, dishonesty, insubordination or other
act by a Participant detrimental to the good will of the Company or damaging the
Company's relationships with its customers, suppliers or employees. "Cause"
shall be determined in good faith by the Committee.
2.5 "Change in Control" of the Company shall be deemed to have occurred as of
the first day that any one or more of the following conditions shall have been
satisfied:
(1) The acquisition by any Person of beneficial ownership (within the meaning
of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either (i)
the then outstanding Shares of the Company or (ii) the combined voting power of
the then outstanding voting securities of the Company entitled to vote generally
in the election of directors (the "Outstanding Company Voting Securities");
provided, however, that the following acquisitions shall not constitute a
Change of Control: (i) any acquisition directly from the Company (excluding
an acquisition by virtue of the exercise of a conversion privilege), (ii) any
acquisition by the Company, (iii) any acquisition by any employee benefit plan
(or related trust) sponsored or maintained by the Company or any corporation
controlled by the Company or (iv) any acquisition by any corporation pursuant
to a reorganization, merger or consolidation, if, following such
reorganization, merger or consolidation, the conditions described in clauses
(i), (ii) and (iii) of subparagraph (3) below are satisfied; or
(2) Individuals who, as of the date hereof, constitute the Board of Directors
(the "Incumbent Board") cease for any reason to constitute at least a majority
of the Board; provided, however, that any individual becoming a director
subsequent to the date hereof whose election, or nomination for election by the
Company's shareholders, was approved by a vote of at least a majority of the
directors then comprising the Incumbent Board shall be considered as though such
individual were a member of the Incumbent Board, but excluding, for this
purpose, any such individual whose initial assumption of office occurs as a
result of either an actual or threatened election contest (as such terms are
used in Rule 14a-11 of Regulation 14A promulgated under the Exchange Act) or
other actual or threatened solicitation of proxies or consents by or on
behalf of a Person other than the Board; or
(3) Approval by the shareholders of the Company of a reorganization, merger
or consolidation, in each case, unless, following such reorganization, merger
or consolidation, (i) more than 75 % of, respectively, the then outstanding
shares of common stock of the corporation resulting from such reorganization,
merger or consolidation and the combined voting power of the then outstanding
voting securities of such corporation entitled to vote generally in the
election of directors are then beneficially owned, directly or indirectly, by
all or substantially all of the individuals and entities who were the
beneficial owners, respectively, of the Outstanding Shares and Outstanding
Company Voting Securities immediately prior to such reorganization, merger or
consolidation, in substantially the same proportions as their ownership
immediately prior to such reorganization, merger or consolidation, of the
Outstanding Shares and Outstanding Company Voting Securities, as the case may
be, (ii) no Person (excluding the Company, any employee benefit plan (or
related trust) of the Company or such corporation resulting from such
reorganization, merger or consolidation and any Person beneficially owning,
immediately prior to such reorganization, merger or consolidation, directly
or indirectly, 20% or more of the Outstanding Shares or Outstanding Voting
Securities, as the case may be) beneficially owns, directly or indirectly,
20% or more of, respectively, the then outstanding shares of common stock of
the corporation resulting from such reorganization, merger or consolidation
or the combined voting power of the then outstanding voting securities of such
corporation entitled to vote generally in the election of directors and (iii) at
least a majority of the members of the board of directors of the corporation
resulting from such reorganization, merger or consolidation were members of
the Incumbent Board at the time of the execution of the initial agreement
providing for such reorganization, merger or consolidation; or
(4) Approval by the shareholders of the Company of (i) a complete liquidation or
dissolution of the Company or (ii) the sale or other disposition of all or
substantially all of the assets of the Company, other than to a corporation,
with respect to which following such sale or other disposition, (A) more than
75% of, respectively, the then outstanding shares of common stock of such
corporation and the combined voting power of the then outstanding voting
securities of such corporation entitled to vote generally in the
election of directors is then beneficially owned, directly or indirectly, by all
or substantially all of the individuals and entities who were the beneficial
owners, respectively, of the Outstanding Shares and Outstanding Company Voting
Securities immediately prior to such sale or other disposition in substantially
the same proportion as their ownership immediately prior to such sale or other
disposition of the Outstanding Shares and Outstanding Company Voting Securities,
as the case may be, (B) no Person (excluding the Company and any employee
benefit plan (or related trust) of the Company or such corporation and any
Person beneficially owning, immediately prior to such sale or other disposition,
directly or indirectly, 20% or more of the Outstanding Shares or Outstanding
Company Voting Securities, as the case may be) beneficially owns, directly or
indirectly, 20% or more of, respectively, the then outstanding shares of
common stock of such corporation and the combined voting power of the then
outstanding voting securities of such corporation entitled to vote generally
in the election of directors and (C) at least a majority of the members of
the board of directors of such corporation were members of the Incumbent Board
at the time of the execution of the initial agreement or action of the Board
providing for such sale or other disposition of assets of the Company;
provided, however, that the implementation of the corporate restructuring
contemplated by the Company's PowerChoice proposal filed with the New
York Public Service Commission on October 6, 1995, or any substantially
similar corporate restructuring (as determined by the Committee) shall
not be deemed to be a "Change in Control".
2.6 "Code" means the Internal Revenue Code of 1986, as amended from time to
time.
2.7 "Committee" means the committee, as specified in Article 3, appointed by
theBoard to administer the Plan with respect to grants of Awards.
2.8 "Company" means Niagara Mohawk Power Corporation, a New York corporation,
or any successor thereto as provided in Article 17 herein.
2.9 "Compensation" means the base salary earned by a Participant during any
Performance Period, excluding overtime, premium, bonus or other special
payments.
2.10 "Contingent Stock Unit" means a right, designated as a Contingent Stock
Unit, to receive a payment as soon as practicable following the last day of
a Vesting Period, pursuant to the terms of Articles 7 and 8 herein. Each
Contingent Stock Unit shall be denominated in terms of one Share.
2.11 "Director" means any individual who is a member of the Board of
Directors of the Company.
2.12 "Disability" shall have the meaning ascribed to such term under Section
22(e)(3) of the Code.
2.13 "Dividend Equivalent" means, with respect to Shares underlying a Contingent
Stock Unit, an amount equal to all cash and stock dividends declared on an
equal number of outstanding Shares on all common stock dividend payment dates
occurring during the Vesting Period.
2.14 "Exchange Act" means the Securities Exchange Act of 1934, as amended from
time to time, or any successor act thereto.
2.15 "Fair Market Value" means the average of the daily opening and closing
sale prices as reported in the consolidated transaction reporting system.
2.16 "Incentive Award" means a Participant's award for a Performance Period
under this Plan, expressed as a percentage of the Participant's Compensation.
2.17 "Participant" means an officer of the Company whose salary is fixed by
the Board of Directors of the Company.
2.18 "Performance Period" means a period of a calendar year during which
Incentive Awards may be earned by Participants in the Plan.
2.19 "Person" shall have the meaning ascribed to such term in Section 3(a)
(9) of the Exchange Act, as used in Sections 13(d) and 14(d) thereof,
including usage in the definition of a "group" in Section 13(d) thereof.
2.20 "Plan" means this Officers Annual Incentive Compensation Plan.
2.21 "Program" means the identified performance criteria goals and
associated incentive award opportunities, together with the other
terms and conditions, approved for a particular Performance Period.
2.22 "Retirement" means (i) ascribed to such term in the tax-qualified
defined benefit pension plan maintained by the Company for the
benefit of some or all of its non-represented employees and (ii) retirement
from the Company or its subsidiaries with the approval of the
Committee.
2.23 "Shares" means the shares of common stock of the Company, par value $1.
2.24 "Subsidiary" means any corporation that is a "subsidiary corporation"
of the Company as that term is defined in Section 424(f) of the Code.
2.25 "Valuation Period" means the 12 trading day period ending on and
including the relevant date.
2.26 "Vesting Period" means the period during which Stock Units are not yet
payable, as set forth in the related Award Agreement.
Article 3. Administration
3.1 The Committee. The Plan shall be administered by the Compensation and
Succession Committee of the Board, or by any other Committee appointed by the
Board consisting of not less than two (2) non-employee Directors. The
members of the Committee shall be appointed from time to time by, and shall
serve at the discretion of, the Board of Directors.
3.2 Authority of the Committee. The Committee shall have full power except
as limited by law, the Articles of Incorporation and the Bylaws of the
Company, subject to such other restricting limitations or directions as may
be imposed by the Board and subject to the provisions herein, to determine
the size and types of Awards; to determine the terms and conditions of such
Awards in a manner consistent with the Plan; to construe and interpret the
Plan and any agreement or instrument entered into under the Plan; to
establish, amend or waive rules and regulations for the Plan's
administration; and (subject to the provisions of Article 14 herein) to amend
the terms and conditions of any outstanding Award. Further, the Committee
shall make all other determinations that may be necessary or advisable for
the administration of the Plan. As permitted by law, the Committee may
delegate its authorities as identified hereunder.
3.3 Decisions Binding. All determinations and decisions made by the Committee
pursuant to the provisions of the Plan and all related orders or resolutions of
the Board shall be final, conclusive and binding on all persons, including
the Company, its shareholders, Employees, Participants and their estates and
beneficiaries .
3.4 Costs. The Company shall pay all costs of administration of the Plan.
Article 4. Adjustments in Authorized Shares
In the event of any merger, reorganization consolidation, recapitalization,
separation, liquidation, stock dividend, split-up, share combination or other
change in the corporate structure of the Company affecting the Shares, such
adjustment shall be made in the number of Contingent Stock Units that may be
granted under the Plan, and in the number and/or price of outstanding Awards
granted under the Plan, as may be determined to be appropriate and equitable
by the Committee, in its sole discretion, to prevent dilution or enlargement of
rights; provided, however, that the number of Contingent Stock Units subject
to an Award shall always be a whole number.
Article 5. Eligibility and Participation
5.1 Eligibility. Any person who is a Participant for the entire length of a
Performance Period shall be eligible for consideration for an Incentive Award
with respect to that Performance Period. The Committee may provide a
prorated Incentive Award for a person who becomes a Participant during the
Performance Period and meets such other requirements as the Committee deems
appropriate. However, any Participant whose performance is evaluated as
unacceptable during a Performance Period shall be ineligible for any Incentive
Award with respect to that Performance Period.
5.2 Termination. Any Participant who resigns or is terminated for any reason
during a Performance Period will not be eligible for any Incentive Award with
respect to that Performance Period.
5.3 Retirement or Death of a Participant. In the event of the death or
retirement of a Participant during a Performance Period such Participant may,
in the discretion of the Committee, be considered for a prorated Incentive
Award with respect to that Performance Period to the extent the Committee
deems appropriate.
Article 6. Performance Criteria and Award Opportunities
6.1 Before the beginning of a Performance Period, the Committee shall approve
the terms of the Program for that particular Performance Period. The Program
shall include identified performance criteria and related award opportunities.
6.2 The Program may include designations of contingent events whose
occurrence during the Performance Period is a required prerequisite to or
would preclude the approval and payment of any Incentive Award.
6.3 The Program may define maximum award opportunities for identified groups of
Participants by officer levels or other appropriate groupings.
6.4 The Program may include various combinations of goals applicable to all
Participants, goals applicable to Participants in separate business units,
and goals applicable to Participants in specific departments, as may be
appropriate. Each goal shall be matched with a corresponding award
opportunity for successful accomplishment.
Article 7. Determination of Participant Incentive Awards
7.1 Following the completion of a Performance Period, the Committee shall
undertake or direct an evaluation of performance as compared to the
appropriate performance criteria established for the Performance Period, and
compute Participants tentative Incentive Awards.
7.2 The Committee may adjust or prorate the Incentive Award of any Participant
to the extent it deems appropriate to reflect changes in responsibilities
during a Performance Period.
7.3 The Committee shall review all tentative Incentive Awards and may, in its
discretion, reduce or eliminate any Participant's tentative Incentive Award
as it deems warranted by extraordinary circumstance.
7.4 The Committee may, for reasons it deems appropriate, in its discretion,
determine to delay, disapprove, or eliminate all tentative Incentive Awards
for any Performance Period.
7.5 No Incentive Award may be paid without the prior approval of the Committee.
7.6 Incentive Awards will be paid by check as soon as practicable following
the end of the Performance Period to which they relate. The Company shall
deduct from any payment any sums required to be withheld by applicable
federal, state, or local tax laws. Incentive Award payments will not be
considered as earnings for purposes of the Niagara Mohawk Pension Plan, the
Employee Savings Fund Plan, or any other employee benefit or insurance programs.
Article 8. Contingent Stock Units
8.1 Subject to the terms and conditions of the Plan, the Committee may, in its
discretion, convert Incentive Award opportunities into Contingent Stock
Units, which may be granted to Participants at the beginning of a Period.
8.2 The number of Contingent Stock Units to be granted will be determined by
multiplying Compensation or Projected Compensation (as determined by the
Committee) as of the end of the Performance Period by the Incentive Award
opportunity, and dividing that amount by the Fair Market Value of a Share
determined for the 12 trading day period immediately preceding the date of
the grant, or for such other period as the Committee, in its sole discretion,
shall determine at the time of the grant.
8.3 The vesting of Contingent Stock Units granted under the Plan shall be
determined by the Committee, in its sole discretion, as set forth in the
related Award Agreement.
8.4 After the conclusion of the applicable Performance Period, the number of
Contingent Stock Units which vest will be determined by multiplying the
number of Contingent Stock Units granted by a percentage representing the degree
to which goals in the Plan (the Program) were accomplished during the
Performance Period. The number of Contingent Stock Units which vest may also be
adjusted at the conclusion of the Performance Period to reflect actual
earnings during the Performance Period.
8.5 After determining the number of Contingent Stock Units which vest and become
payable, the payment value will be determined by multiplying the number of
vested Contingent Stock Units by the Fair Market Value of a share.
8.6 Payment of Contingent Stock Units. After the applicable Vesting Period has
ended, the holder of Contingent Stock Units shall be entitled to receive, for
each vested Contingent Stock Unit held, payment in cash from the Company in an
amount equal to the Fair Market Value of one Share determined as of the
Valuation Period ending on the last day of the Vesting Period. Payment shall be
made as soon as practicable following the last day of the Vesting Period.
8.7 Contingent Stock Unit Award Agreement. Each Contingent Stock Unit grant
shall be evidenced by an Award Agreement that shall specify the number of
Contingent Stock Units granted, the Vesting Period and such other provisions as
the Committee shall determine.
Article 9. Dividend Equivalents
Simultaneously with the grant of Contingent Stock Units, the Participant may be
granted Dividend Equivalents, to be credited to a bookkeeping entry account,
on each common stock dividend payment date with respect to the Shares subject to
such Award. In the case of cash dividends, the number of Dividend
Equivalents credited on each common stock dividend payment date shall equal the
number of Shares (including fractional Shares) that could be purchased on the
dividend payment date, based on the average of the opening and closing sale
price, as reported in the consolidated transaction reporting system on that
date, with cash dividends that would have been paid on Awards of Contingent
Stock Units and on Dividend Equivalents previously credited to such
bookkeeping entry account, if such Contingent Stock Units or Dividend
Equivalents were Shares. In the case of stock dividends, the number of
Dividend Equivalents credited on each stock dividend payment date shall be equal
to the number of Shares (including fractional Shares) that would have been
issued as a stock dividend in respect of the Participant's Contingent Stock
Units and on Dividend Equivalents previously credited to such bookkeeping
entry account, if such Contingent Stock Units or Dividend Equivalents
were Shares.
Participants shall receive cash payment from the Company of the Fair Market
Value of the Dividend Equivalents, if and when they receive payment of the
related Contingent Stock Units, the Fair Market Value of such Dividend
Equivalents to be determined in the same manner as for the
related Contingent Stock Units.
The Committee may, in its discretion, establish such rules and procedures
governing the crediting of Dividend Equivalents, including timing and
payment contingencies that apply to the Dividend Equivalents, as the
Committee deems necessary or appropriate in order to comply with
applicable law.
Article 10. Termination of Employment
10.1 Disability; Involuntary Termination. In the event the employment of a
Participant is terminated by reason of Disability or involuntarily by the
Company (other than for Cause) during a Vesting Period for Contingent Stock
Units, the Participant shall receive a full payout of the Contingent Stock
Units and related Dividend Equivalents, as and when provided in Section 8
herein.
10.2 Death. In the event the employment of a Participant is terminated by
reason of death during the Vesting Period for Contingent Stock Units, the
Participant's beneficiary or estate shall receive a full payout of the
Contingent Stock Units and related Dividend Equivalents. The payout shall be
made promptly based on the Fair Market Value of a Share on the date
of death.
10.3 Retirement. In the event the employment of a Participant is terminated by
reason of Retirement during a Vesting Period for Contingent Stock Units, the
Participant shall receive a prorated payout of the Contingent Stock Units
and related Dividend Equivalents. The prorated payout shall be determined by
the Committee, shall be based upon the length of time that the Participant
held the Contingent Stock Units during the Vesting Period and shall be made as
and when provided in Section 8.
10.4 Other than as set forth in Article 13, in the event that a Participant's
employment terminates for any reason other than as set forth in Sections
10.1, 10.2 and 10.3, above, all Contingent Stock Units and Dividend
Equivalents shall be forfeited by the Participant to the Company .
10.5 Right of Committee. Subject to the provisions of Section 14.2 herein, all
provisions in this Article 10 are subject to the Committee's right, at any
time, to make such other determinations as it may choose, in its sole
discretion. Furthermore, should more than one section of Article 10 and/or
Article 14 apply to a situation, the Committee shall have the right, in its sole
discretion, to determine which section and/or article to apply.
Article 11. Beneficiary Designation
Each Participant under the Plan may, from time to time, name any beneficiary or
beneficiaries (who may be named contingently or successively) to whom any
benefit under the Plan is to be paid in case of his death before he receives any
or all of such benefit. Each such designation shall revoke all prior
designations by the same Participant, shall be in a form prescribed by the
Committee, and will be effective only when filed by the Participant in
writing with the Committee during the Participant's lifetime. In the absence of
any such designation, benefits remaining unpaid at the Participant's death
shall be paid to the Participant's estate.
The spouse of a married Participant domiciled in a community property
jurisdiction shall join in any designation of beneficiary or beneficiaries
other than the spouse.
Article 12. Rights of Participants
12.1 Employment. Nothing in the Plan shall interfere with or limit in any way
the right of the Company to terminate any Participant's employment at any
time, for any reason or no reason, in the Company's sole discretion, nor confer
upon any Participant any right to continue in the employ of the Company.
12.2 Participation. No Participant shall have the right to be selected to
receive an Award or Incentive Award under the Plan, or, having been so
selected, to be selected to receive a future Award or Incentive Award.
Article 13. Change in Control
Any Vesting Period with respect to Contingent Stock Units shall be deemed to
have expired, and there shall be paid out in cash to Participants within
thirty (30) days following the effective date of the Change in Control the cash
payment due with respect to such Contingent Stock Units and related Dividend
Equivalents, with a Valuation Period ending on the effective date of the Change
in Control.
Article 14. Amendment, Modification and Termination
14.1 Amendment. Modification and Termination. The Board may, at any time and
from time to time, alter, amend, suspend or terminate the Plan in whole or in
part.
14.2 Awards Previously Granted. No termination, amendment or modification of
the Plan shall adversely affect in any material way any Award or Incentive
Award previously granted under the Plan, without the written consent of the
Participant holding such Award, unless such termination, modification or
amendment is required by applicable law.
Article 15. Tax Withholding
The Company shall have the power and the right to deduct or withhold, or require
a Participant to remit to the Company, an amount sufficient to satisfy
Federal, state and local taxes (including the Participant's FICA obligation)
required by law to be withheld with respect to any taxable event arising out
of or as a result of an Award or Incentive Award made under the Plan.
Article 16. Successors
All obligations of the Company under the Plan, with respect to Awards or
Incentive Awards granted hereunder shall be binding on any successor to the
Company, whether the existence of such successor is the result of a direct or
indirect purchase, merger, consolidation or otherwise, of all or
substantially all of the business and/or assets of the Company.
Article 17. Legal Construction
17.1 Gender and Number. Except where otherwise indicated by the context, any
masculine term used herein also shall include the feminine, the plural shall
include the singular and the singular shall include the plural.
17.2 Severability. In the event any provision of the Plan shall be held
illegal or invalid for any reason, the illegality or invalidity
shall not affect the remaining parts of the Plan, and the Plan shall be
construed and enforced as if the illegal or invalid provision had not
been included.
17.3 Requirements of Law. The granting of Awards or Incentive Awards under the
Plan shall be subject to all applicable laws, rules and regulations, and to
such approvals by any governmental agencies or national securities exchanges
as may be required.
17.4 Governing Law. To the extent not preempted by Federal law, the Plan,
and all agreements hereunder, shall be construed in accordance with, and
governed by, the laws of the State of New York, without regard to conflicts
of law provisions.
17.5 Notices. Any notice to a Participant may be given either by personal
delivery or by depositing it in the United States mail, postage prepaid,
addressed to his last-known address. Any notice to the Company or the
Committee shall be given either by delivering it or depositing it in the
United States mail, postage prepaid, to the Secretary, Niagara Mohawk, 300 Erie
Boulevard West, Syracuse, New York 13202.
17.6 No Waiver. Failure by the Company or the Committee to insist upon strict
compliance with any of the terms or conditions of this Plan shall not be
deemed a waiver of any such term or condition, nor shall any waiver or
relinquishment of any right or power at any one or more times be deemed a
waiver or relinquishment of any such right or power at any other time or times.
17.7 Partial Invalidity. The invalidity or unenforceability of any provision of
this Plan shall not affect the validity or enforceability of any other
provision.
17.8 Venue of any suit involving the Plan or Plan benefits shall lie in Onondaga
County, New York, if a state court action, and in the United States District
Court, Northern District of New York, if a federal court action.
EXHIBIT 11
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
COMPUTATION OF AVERAGE NUMBER OF SHARES OF COMMON STOCK OUTSTANDING
Average Number
of Shares Out-
standing as shown
on Consolidated
(1) (2) Statements of Income
Shares of Number (3) (3 divided
Common of Days Share Days by number of days
Year Ended December 31, Stock Outstanding (2 x 1) in year)
- ----------------------------- ----------------- ------------ ------------------ --------------------
1998
----
JANUARY 1 - DECEMBER 31 144,419,351 365 52,713,063,115
SHARES ISSUED IN ACCORDANCE
WITH THE MRA AGREEMENT
JUNE 30 42,945,512 185 7,944,919,720
----------- -------------
187,364,863 60,657,982,835 166,186,254
=========== ============== ===========
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 period -
Acquisition - Syracuse
Suburban Gas Company, Inc. 33,091 * 6,397,653
----------- --------------
144,365,214 52,831,954,671 144,349,603
=========== ============== ===========
* 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.
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,
----------------------------------------------
1998 1997 1996 1995 1994
--------------------------------------------------
A..Net Income (Loss) per
Statements of Income . . $(120,825) $183,335 $110,390 $248,036 $176,984
B. Taxes Based on Income or
Profits. . . . . . . . . (66,728) 126,595 66,221 159,393 111,469
---------- -------- -------- -------- --------
C. Earnings, Before Income
Taxes. . . . . . . . . . (187,553) 309,930 176,611 407,429 288,453
D. Fixed Charges (a) 433,313 304,451 308,323 314,973 315,274
---------- -------- -------- -------- --------
E. Earnings Before Income
Taxes and Fixed Charges. 245,760 614,381 484,934 722,402 603,727
F. Allowance for Funds Used
During Construction. . . 18,854 9,706 7,355 9,050 9,079
---------- -------- -------- -------- --------
G. Earnings Before Income
Taxes and Fixed Charges
without AFC. . . . . . . $ 226,906 $604,675 $477,579 $713,352 $594,648
========== ======== ======== ======== ========
PREFERRED DIVIDEND FACTOR:
H. Preferred Dividend
Requirements . . . . . . $ 36,555 $ 37,397 $ 38,281 $ 39,596 $ 33,673
========== ======== ======== ======== ========
I. Ratio of Pre-Tax Income
to Net Income (C/A). . . N/A 1.69 1.60 1.64 1.63
J. Preferred Dividend Factor
(H x I). . . . . . . . . $ 36,555 $ 63,201 $ 61,250 $ 64,937 $ 54,887
K. Fixed Charges as above (D) 433,313 304,451 308,323 314,973 315,274
---------- -------- -------- -------- --------
L. Fixed Charges and Preferred
Dividends Combined . . . $ 469,868 $367,652 $369,573 $379,910 $370,161
========= ======== ======== ======== ========
M. Ratio of Earnings to
Fixed Charges (E/D). . . 0.57 2.02 1.57 2.29 1.91
========= ======== ======== ======== ========
N. Ratio of Earnings to Fixed
Charges and Preferred
Dividends Combined (E/L) 0.52 1.67 1.31 1.90 1.63
=========== ======== ======== ======== ========
(a) Includes a portion of rentals deemed representative of the interest
factor: $25,907 for 1998, $26,149 for 1997, $26,600 for 1996, $27,312
for 1995 and $29,396 for 1994.
N/A - Not applicable due to net loss displayed in line A.
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 Properties, Inc. (Note 3) New York
Moreau Manufacturing Corporation (Note 4) New York
Beebee Island Corporation (Note 4) New York
NM Receivables Corp. II New York
NM Receivables. LLC New York
Note 1: At December 31, 1998, Opinac North America, Inc. owns Opinac Energy
Corporation and Niagara Mohawk Energy, Inc. (formerly Plum Street Enterprises,
Inc.). Opinac Energy Corporation has portfolio investments and has a 50 percent
interest in CNP, which is incorporated in the Province of Ontario, Canada. CNP
owns, through subsidiary companies, a wind power facility in Alberta, Canada.
Niagara Mohawk Energy, Inc., an unregulated company, is incorporated in the
State of Delaware. Niagara Mohawk Energy, Inc., among other investments, owns
Niagara Mohawk 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).
Note 2: EMCO-TECH, Inc. is inactive at December 31, 1998 and was dissolved on
January 15, 1999.
Note 3: At December 31, 1998, NM Properties, Inc. (formerly 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.
Note 4: The Company has included its interest in the subsidiary in its sale of
its hydroelectric generating plants.
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) and in the Prospectus/Proxy Statement constituting part of the
Registration Statement on Form S-4 (No. 333-49769) of Niagara Mohawk Power
Corporation of our report dated January 28, 1999 appearing in the Company's Form
10-K dated March 9, 1999. We also consent to the incorporation by reference
of our report on the Financial Statement Schedule, which appears in this Form
10-K.
/s/PricewaterhouseCoopers LLP
- -----------------------------
PricewaterhouseCoopers LLP
Syracuse, New York
January 28, 1999
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 9,1999 /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/Salvatore H. Alfiero Director February 25, 1999
- -----------------------
Salvatore H. Alfiero
/s/William F. Allyn Director February 25, 1999
- -------------------
William F. Allyn
Director,
/s/Albert J. Budney Jr. President February 25, 1999
- -----------------------
Albert J. Budney Jr.
/s/Lawrence Burkhardt III Director February 25, 1999
- -------------------------
Lawrence Burkhardt III
Chairman of the
Board of Directors
and Chief Executive
/s/William E. Davis Officer February 25, 1999
- -------------------
William E. Davis
/s/William J. Donlon Director February 25, 1999
- --------------------
William J. Donlon
/s/Anthony H. Gioia Director February 25, 1999
- -------------------
Anthony H. Gioia
/s/Bonnie G. Hill Director February 25, 1999
- -----------------
Bonnie G. Hill
/s/Clark A. Johnson Director February 25, 1999
- -------------------
Clark A. Johnson
/s/Henry A. Panasci Jr. Director February 25, 1999
- -----------------------
Henry A. Panasci Jr.
/s/Patti McGill Peterson Director February 25, 1999
- ------------------------
Patti McGill Peterson
/s/Donald B. Riefler Director February 25, 1999
- --------------------
Donald B. Riefler
/s/Stephen B. Schwartz Director February 25, 1999
- ----------------------
Stephen B. Schwartz
Executive Vice President
/s/Darlene D. Kerr Energy Delivery February 25, 1999
- ------------------
Darlene D. Kerr
Senior Vice President
and Chief Financial
/s/William F. Edwards Officer February 25, 1999
- ---------------------
William F. Edwards
Vice President-Controller
and Principal Accounting
/s/Steven W. Tasker Officer February 25, 1999
- -------------------
Steven W. Tasker