S E C U R I T I E S A N D E X C H A N G E C O M M I S S I O N
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
FOR THE FISCAL YEAR ENDED MARCH 31, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
COMMISSION FILE NUMBER 1-3571
LONG ISLAND LIGHTING COMPANY
INCORPORATED PURSUANT TO THE LAWS OF NEW YORK STATE
INTERNAL REVENUE SERVICE - EMPLOYER IDENTIFICATION NUMBER 11-1019782
175 EAST OLD COUNTRY ROAD, HICKSVILLE, NEW YORK 11801
516-755-6650
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
Title of each class so registered:
Common Stock ($5 par)
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Preferred Stock ($100 par, cumulative):
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Series B, 5.00% Series E, 4.35% Series I, 5 3/4%, Convertible
Series D, 4.25% Series CC, 7.66%
Preferred Stock ($25 par, cumulative):
Series AA, 7.95% Series GG, $1.67 Series QQ, 7.05%
Series NN, $1.95
General and Refunding Bonds:
7.85% Series Due 1999 8.50% Series Due 2006 9 3/4% Series Due 2021
8 5/8% Series Due 2004 7.90% Series Due 2008 9 5/8% Series Due 2024
Debentures:
7.30% Series Due 1999 7.05% Series Due 2003 8.90% Series Due 2019
7.30% Series Due 2000 7.00% Series Due 2004 9.00% Series Due 2022
6.25% Series Due 2001 7.125% Series Due 2005 8.20% Series Due 2023
7.50% Series Due 2007
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NAME OF EACH EXCHANGE ON WHICH EACH CLASS IS REGISTERED: The New York
Stock Exchange and the Pacific Stock Exchange are the only exchanges on which
the Common Stock is registered. The New York Stock Exchange is the only exchange
on which certain of the other securities listed above are registered.
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]
The aggregate market value of the Common Stock held by non-affiliates
of the Company at March 31,1998 was $3,832,943,909. The aggregate market value
of Preferred Stock held by non-affiliates of the Company at March 31, 1998,
established by Lehman Brothers based on the average bid and asked price, was
$735,033,360.
COMMON STOCK ($5 PAR) - SHARES OUTSTANDING AT MARCH 31, 1998: 121,680,759
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TABLE OF CONTENTS
ABBREVIATIONS.....................................................................................................iii
PART I
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ITEM 1. BUSINESS...............................................................................................1
The Company............................................................................................1
Territory..............................................................................................1
Business Segments......................................................................................1
Employees..............................................................................................1
Regulation and Accounting Controls.....................................................................2
Long Island Power Authority Transaction................................................................2
KeySpan Energy Corporation Transaction.................................................................4
Competitive Environment................................................................................6
Electric Operations....................................................................................6
General.......................................................................................6
System Requirements, Energy Available and Reliability.........................................7
Energy Sources................................................................................7
Oil...................................................................................7
Natural Gas...........................................................................8
Purchased Power.......................................................................8
Nuclear...............................................................................9
Interconnections......................................................................9
Conservation Services.........................................................................9
The 1989 Settlement...........................................................................9
Electric Rates................................................................................9
Gas Operations........................................................................................10
General......................................................................................10
Gas System Requirements......................................................................10
Peak Day Capability..................................................................11
Transportation ......................................................................11
Storage..............................................................................11
Cogen/IPP Deliveries.................................................................11
Peak Shaving.........................................................................11
Firm Gas Supply......................................................................12
Gas Rates....................................................................................12
Recovery of Transition Costs.................................................................12
Natural Gas Vehicles.........................................................................12
Environmental Matters.................................................................................12
General......................................................................................12
Air..........................................................................................13
Water........................................................................................15
Land.........................................................................................16
Nuclear Waste................................................................................19
The Company's Securities..............................................................................20
General......................................................................................20
The G&R Mortgage.............................................................................20
Unsecured Debt...............................................................................21
Equity Securities............................................................................21
Common Stock.........................................................................21
Preferred Stock......................................................................22
Preference Stock.....................................................................22
Executive Officers of the Company.....................................................................23
Capital Requirements, Liquidity and Capital Provided..................................................28
ITEM 2. PROPERTIES............................................................................................28
ITEM 3. LEGAL PROCEEDINGS.....................................................................................28
Shoreham..............................................................................................28
Environmental.........................................................................................29
Human Resources.......................................................................................30
Other Matters.........................................................................................30
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS...................................................30
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PART II
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ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTER...................................31
ITEM 6. SELECTED FINANCIAL DATA....................................................................................32
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS......................33
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................................................................55
Balance Sheet..............................................................................................55
Statement of Income........................................................................................57
Statement of Cash Flows....................................................................................58
Statement of Retained Earnings.............................................................................59
Statement of Capitalization................................................................................59
Notes to Financial Statements..............................................................................61
Report of Independent Auditors.............................................................................96
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURES..................................................................................97
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY............................................................98
ITEM 11. EXECUTIVE COMPENSATION....................................................................................101
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT............................................113
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS............................................................116
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K..................................................................................................117
List of Financial Statements.....................................................................117
List of Financial Statement Schedules............................................................117
List of Exhibits.................................................................................118
Reports on Form 8-K...........................................................................129
SCHEDULE II .....................................................................................130
SIGNATURES.............................................................................................................131
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ABBREVIATIONS
The following abbreviations are sometimes used in this Annual Report.
ACO.................. Administrative Consent Order
AFC.................. Allowance For Funds Used During Construction
ALJ.................. Administrative Law Judge
BFC.................. Base Financial Component
BVPA................. Bondable Value of Property Additions
DEC.................. New York State Department of Environmental Conservation
DOE.................. United States Department of Energy
DOL.................. New York State Department of Law
DSM.................. Demand Side Management
Dth.................. Dekatherms (Approx. One Thousand Cubic Feet of Gas)
EFRBs................ Electric Facilities Revenue Bonds
EMF.................. Electromagnetic Fields
EPA.................. United States Environmental Protection Agency
ERISA................ Employee Retirement Income Security Act of 1974
FCA.................. Fuel Cost Adjustment
FERC................. Federal Energy Regulatory Commission
FMC.................. Fuel Moderation Component
FRA.................. Financial Resource Asset
G&R Bonds............ General and Refunding Bonds
G&R Mortgage......... General and Refunding Indenture dated as of June 1, 1975
GAAP................. Generally Accepted Accounting Principles
GWh.................. Gigawatt Hour (One Million kWh)
IC................... Internal Combustion
IDRBs................ Industrial Development Revenue Bonds
IERP................. Integrated Electric Resource Plan
IPP.................. Independent Power Producers
ISO.................. Independent System Operator
kWh.................. Kilowatt hour
LIPA................. Long Island Power Authority
LRAC................. Long-Range Avoided Costs
LRPP................. LILCO Ratemaking and Performance Plan
MDA.................. Municipal Distribution Agency
MGP.................. Manufactured Gas Plant
MW................... Megawatts (One Million Watts)
MWh.................. Megawatt Hour
NEPA................. National Energy Policy Act of 1992
NGV.................. Natural Gas Vehicle
NMP2................. Nine Mile Point Nuclear Power Station, Unit 2
NMPC................. Niagara Mohawk Power Corporation
NOPR................. Notice of Proposed Rulemaking
NRC.................. Nuclear Regulatory Commission
NUG.................. Non-Utility Generator
NUSCO................ Northeast Utilities Service Company
NYPA................. New York Power Authority
NYPP................. New York Power Pool
NYSERDA.............. New York State Energy Research and Development Authority
PACB................. Public Authorities Control Board
PCB.................. Polychlorinated Biphenyls
PCRBs................ Pollution Control Revenue Bonds
PILOTs............... Payments-in-lieu-of-taxes
PRP.................. Potentially Responsible Party
PSC.................. Public Service Commission of the State of New York
PURPA................ Public Utility Regulatory Policies Act of 1978
QF................... Qualified Facilities
RI/FS................ Remedial Investigation and Feasibility Study
RMA.................. Rate Moderation Agreement
RMC.................. Rate Moderation Component
Shoreham............. Shoreham Nuclear Power Station
SFAS................. Statement of Financial Accounting Standards
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PART I
ITEM 1. BUSINESS
THE COMPANY
Long Island Lighting Company (Company or LILCO) was incorporated in 1910 under
the Transportation Corporations Law of the State of New York and supplies
electric and gas service in Nassau and Suffolk Counties and to the Rockaway
Peninsula in Queens County, all on Long Island, New York. The mailing address of
the Company is 175 East Old Country Road, Hicksville, New York 11801 and the
general telephone number is (516) 755-6650.
On April 11, 1997, the Company changed its year end from December 31 to March
31. Accordingly, unless otherwise indicated, references to 1998 and 1997
represent the twelve month periods ended March 31, 1998 and March 31, 1997,
respectively, while references to all other periods refer to the respective
calendar years ended December 31.
TERRITORY
The Company's service territory covers an area of approximately 1,230 square
miles. The population of the service area, according to the Company's 1998 Long
Island Population Survey, is 2.75 million persons, including approximately
98,500 persons who reside in Queens County within the City of New York. The 1998
population survey reflects a 1.6% increase since the 1990 census.
Approximately 80% of all workers residing in Nassau and Suffolk Counties are
employed within the two counties. During the year ended December 31, 1997 total
non-agricultural employment in Nassau and Suffolk Counties increased by
approximately 18,600 positions, an employment increase of 1.7%.
The Company serves approximately 1.04 million electric customers of which
approximately 931,000 are residential. The Company receives approximately 49% of
its electric revenues from residential customers, 48% from commercial/industrial
customers and the balance from sales to other utilities and public authorities.
The Company also serves approximately 467,000 gas customers, 417,000 of which
are residential, accounting for about 61% of its gas revenues, 17,000 of which
are commercial/industrial, accounting for 23% of its gas revenues, 3,600 of
which are firm transportation customers, accounting for 3% of its gas revenues,
with the balance of the gas revenues derived from off-system sales.
BUSINESS SEGMENTS
For information concerning the Company's electric and gas financial and
operating results, see Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and Note 13 of Notes to Financial
Statements.
EMPLOYEES
As of March 31, 1998, the Company had 5,187 full-time employees, of which 2,149
belong to Local 1049 and 1,220 belong to Local 1381 of the International
Brotherhood of Electrical Workers. Effective February 14, 1996, the Company and
these unions agreed upon contracts which will expire on February 13, 2001. The
contracts provide, among other things, for wage increases totaling 15.5% over
the term of the agreements.
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REGULATION AND ACCOUNTING CONTROLS
The Company is subject to regulation by the Public Service Commission of the
State of New York (PSC) with respect to rates, issuances and sales of
securities, adequacy and continuance of service, safety and siting of certain
facilities, accounting, conservation of energy, management effectiveness and
other matters. To ensure that its accounting controls and procedures are
consistently maintained, the Company actively monitors these controls and
procedures. The Audit Committee of the Company's Board of Directors, as part of
its responsibilities, periodically reviews this monitoring program.
The Company is also subject, in certain of its activities, to the jurisdiction
of the United States Department of Energy (DOE) and the Federal Energy
Regulatory Commission (FERC). In addition to accounting jurisdiction, the FERC
has jurisdiction over rates that the Company may charge for the sale of electric
energy for resale in interstate commerce, including rates the Company charges
for electricity sold to municipal electric systems within the Company's
territory, and for the transmission, through the Company's system, of electric
energy to other utilities or certain industrial customers. It is in the exercise
of this jurisdiction over transmission that the FERC has issued two orders
relating to the development of competitive wholesale electric markets. For a
discussion of these FERC Orders, see Note 12 of Notes to Financial Statements.
The FERC also has some jurisdiction over a portion of the Company's gas supplies
and substantial jurisdiction over transportation to the Company of its gas
supplies.
Operation of Nine Mile Point Nuclear Power Station, Unit 2 (NMP2), a nuclear
facility in which the Company has an 18% interest, is subject to regulation by
the Nuclear Regulatory Commission (NRC).
LONG ISLAND POWER AUTHORITY TRANSACTION
On June 26, 1997, the Company and Long Island Power Authority (LIPA) entered
into definitive agreements pursuant to which, after the transfer of the
Company's gas business unit assets, non-nuclear electric generating facility
assets and certain other assets and liabilities to one or more newly-formed
subsidiaries of a new holding company (HoldCo), formed in connection with the
LIPA Transaction and KeySpan Transaction discussed below, the Company's common
stock will be sold to LIPA for $2.4975 billion in cash.
In connection with this transaction, the principal assets to be acquired by LIPA
through its stock acquisition of LILCO include: (i) the net book value of
LILCO's electric transmission and distribution system, which amounted to
approximately $1.3 billion at March 31, 1998; (ii) LILCO's net investment in
NMP2, which amounted to approximately $0.7 billion at March 31, 1998; (iii)
certain of LILCO's regulatory assets associated with its electric business; and
(iv) allocated accounts receivable and other assets. The regulatory assets to be
acquired by LIPA amounted to approximately $6.6 billion at March 31, 1998, and
primarily consist of the Base Financial Component (BFC), Rate Moderation
Component (RMC), Shoreham post-settlement costs, Shoreham nuclear fuel, and the
electric portion of the regulatory tax asset. For a further discussion of these
regulatory assets, see Note 1 of Notes to Financial Statements.
LIPA is contractually responsible for reimbursing HoldCo for postretirement
benefits other than pension costs related to employees of LILCO's electric
business. Accordingly, upon consummation of the transaction, HoldCo will
reclassify the associated regulatory asset for postretirement benefits other
than pensions to a contractual receivable.
The principal liabilities to be assumed by LIPA through its stock acquisition of
LILCO include:
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(i) LILCO's regulatory liabilities associated with its electric business; (ii)
allocated accounts payable, customer deposits, other deferred credits and claims
and damages; and (iii) certain series of long-term debt, a portion of which will
be refinanced. The regulatory liabilities to be assumed by LIPA amounted to
approximately $365 million at March 31, 1998, and primarily consist of the
regulatory liability component, 1989 Settlement credits and the electric portion
of the regulatory tax liability. For a further discussion of these regulatory
liabilities, see Note 1 of Notes to Financial Statements.
The long-term debt to be assumed by LIPA will consist of: (i) all amounts then
outstanding under the General and Refunding (G&R) Indentures; (ii) all amounts
then outstanding under the Debenture Indentures, except as noted below; and
(iii) substantially all of the tax-exempt authority financing notes. HoldCo is
required to assume the financial obligation associated with the 7.30% Debentures
due July 15, 1999, with an aggregate principal amount currently outstanding of
$397 million and 8.20% Debentures due March 15, 2023, with an aggregate
principal amount currently outstanding of $270 million. HoldCo will seek to
exchange its Debentures, with identical terms, for these two series of
Debentures and will issue a promissory note to LIPA in an amount equal to the
unexchanged amount of such Debentures. HoldCo will also issue a promissory note
to LIPA for a portion of the tax-exempt debt borrowed to support LILCO's current
gas operations, with terms identical to those currently outstanding. The Company
currently estimates the amount of this promissory note to be approximately $250
million.
In July 1997, in accordance with the provisions of the LIPA Transaction, the
Company and The Brooklyn Union Gas Company (Brooklyn Union) formed a limited
partnership and each Company invested $30 million in order to purchase an
interest rate swap option instrument to protect LIPA against market risk
associated with the municipal bonds expected to be issued by LIPA to finance the
transaction. Upon the closing of the LIPA Transaction, each limited partner will
receive from LIPA $30 million plus interest thereon, based on each partners'
average weighted cost of capital. In the event that the LIPA Transaction is not
consummated, the maximum potential loss to the Company is the amount originally
invested. In such event, the Company plans to defer any loss and petition the
PSC to allow recovery from its customers.
As part of the LIPA Transaction, the definitive agreements contemplate that one
or more subsidiaries of HoldCo will enter into agreements with LIPA, pursuant to
which such subsidiaries will provide management and operations services to LIPA
with respect to the electric transmission and distribution system, deliver power
generated by its power plants to LIPA, and manage LIPA's fuel and electric
purchases and any off-system electric sales. In addition, three years after the
LIPA Transaction is consummated, LIPA will have the right for a one-year period
to acquire all of HoldCo's generating assets at the fair market value at the
time of the exercise of the right, which value will be determined by independent
appraisers.
In July 1997, the New York State Public Authorities Control Board (PACB),
created pursuant to the New York State Public Authorities Law and consisting of
five members appointed by the governor, unanimously approved the definitive
agreements related to the LIPA Transaction subject to the following conditions:
(i) within one year of the effective date of the transaction, LIPA must
establish a plan for open access to the electric distribution system; (ii) if
LIPA exercises its option to acquire the generation assets of HoldCo's
generation subsidiary, LIPA may not purchase the generating facilities, as
contemplated in the generation purchase right agreement, at a price greater than
book value; (iii) HoldCo must agree to invest, over a ten-year period, at least
$1.3 billion in energy-related and economic development projects, and natural
gas infrastructure projects on Long Island; (iv) LIPA will guarantee that, over
a ten-year period, average electric rates will be reduced
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by no less than 14% when measured against the Company's rates today and no less
than a 2% cost savings to LIPA customers must result from the savings
attributable to the merger of LILCO and KeySpan; and (v) LIPA will not increase
average electric customer rates by more than 2.5% over a twelve-month period
without approval from the PSC. LIPA has adopted the conditions set forth by the
PACB. The holders of common and certain series of preferred stock of the Company
eligible to vote approved the LIPA Transaction in August 1997.
In December 1997, the United States Nuclear Regulatory Commission (NRC) issued
an order approving the indirect transfer of control of the Company's 18%
ownership interest in NMP2 to LIPA.
In December 1997, the Company filed with the FERC a settlement agreement reached
with LIPA in connection with a previous filing of the Company's proposed rates
for the sale of capacity and energy to LIPA, as contemplated in the LIPA
transaction agreements. The Company also had previously filed an application
with the FERC seeking approval of the transfer of the Company's electric
transmission and distribution system to LIPA in connection with LIPA's purchase
of the common stock of the Company.
In February 1998, the FERC issued orders on both of the Company filings.
Specifically, the FERC approved the Company's application to transfer assets to
LIPA in connection with LIPA's acquisition of the Company's common stock. In
addition, the FERC accepted the Company's proposed rates for sale of capacity
and energy to LIPA. Those rates may go into effect on the date the service to
LIPA begins, subject to refund, and final rates will be set after the FERC has
completed its investigation of such rates, the timing of which cannot be
determined at this time.
In January 1998, the Company filed an application with the PSC in connection
with the proposed transfer of its gas business unit assets, non-nuclear
generating facility assets and certain other assets and related liabilities to
one or more subsidiaries of HoldCo to be formed as contemplated in the LIPA
Transaction agreements. On April 29, 1998, the PSC approved the transfer of the
above-mentioned assets.
In July 1997, the Company, Brooklyn Union and LIPA filed requests for private
letter rulings with the Internal Revenue Service (IRS) regarding certain federal
income tax issues which require favorable rulings in order for the LIPA
Transaction to be consummated. On March 4, 1998, the IRS issued a private letter
ruling confirming that the sale of the Company's common stock to LIPA would not
result in a corporate tax liability to the Company. In addition, the IRS ruled
that, after the stock sale, the income of LIPA's electric utility business will
not be subject to federal income tax. In a separate ruling on February 27, 1998,
the IRS also ruled that the bonds to be issued by LIPA to finance the
acquisition would be tax-exempt.
In January 1998, the Company filed an application with the SEC seeking an
exception for most of the provisions of the Public Utilities Holding Company Act
of 1935. In May 1998, the SEC issued an order approving the Company's
application.
The Company currently anticipates that the LIPA transaction will be consummated
on or about May 28, 1998.
KEYSPAN ENERGY CORPORATION TRANSACTION
On December 29, 1996, The Brooklyn Union Gas Company (Brooklyn Union) and the
Company entered into an Agreement and Plan of Exchange and Merger (Share
Exchange Agreement),
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pursuant to which the companies will be merged in a transaction (KeySpan
Transaction) that will result in the formation of HoldCo.
The Share Exchange Agreement was amended and restated to reflect certain
technical changes as of February 7, 1997 and June 26, 1997. Effective September
29, 1997, Brooklyn Union reorganized into a holding company structure, with
KeySpan Energy Corporation (KeySpan) becoming its parent holding company.
Accordingly, the parties entered into an Amendment, Assignment and Assumption
Agreement, dated as of September 29, 1997, which among other things, amended the
Share Exchange Agreement and related stock option agreements to reflect the
assignment by Brooklyn Union to KeySpan and the assumption by KeySpan of all
Brooklyn Union's rights and obligations under such agreements.
The KeySpan Transaction, which has been approved by both companies' boards of
directors and shareholders, would unite the resources of the Company with the
resources of KeySpan. KeySpan, with approximately 3,300 employees, distributes
natural gas at retail, primarily in a territory of approximately 187 square
miles which includes the boroughs of Brooklyn and Staten Island and two-thirds
of the borough of Queens, all in New York City. KeySpan has energy-related
investments in gas exploration, production and marketing in the United States
and Northern Ireland, as well as energy services in the United States, including
cogeneration projects, pipeline transportation and gas storage.
Under the terms of the KeySpan Transaction, the Company's common shareowners
will receive 0.803 shares (the Ratio) of HoldCo's common stock for each share of
the Company's common stock that they hold at the time of closing. KeySpan common
shareowners will receive one share of common stock of HoldCo for each common
share of KeySpan they hold at the time of closing. Shareowners of the Company
will own approximately 66% of the common stock of HoldCo while KeySpan
shareowners will own approximately 34%. In the event that the LIPA Transaction
is consummated, the Ratio will be 0.880 with Company shareowners owning
approximately 68% of the HoldCo common stock. Consummation of the Share Exchange
Agreement is not conditioned upon the consummation of the LIPA Transaction and
consummation of the LIPA Transaction is not conditioned upon consummation of the
Share Exchange Agreement. Based on current facts and circumstances, it is
probable that the purchase method of accounting will apply to the KeySpan
Transaction, with the Company being the acquiring company for accounting
purposes.
In March 1997, the Company filed an application with the FERC seeking approval
of the transfer of the Company's common equity and certain FERC-jurisdictional
assets to HoldCo. In July 1997, the FERC granted such approval.
The Share Exchange Agreement contains certain covenants of the parties pending
the consummation of the transaction. Generally, the parties must carry on their
businesses in the ordinary course consistent with past practice, may not
increase dividends on common stock beyond specified levels and may not issue
capital stock beyond certain limits. The Share Exchange Agreement also contains
restrictions on, among other things, charter and by-law amendments, capital
expenditures, acquisitions, dispositions, incurrence of indebtedness, certain
increases in employee compensation and benefits, and affiliate transactions.
The Company and KeySpan expect to continue their respective current dividend
policies until completion of the KeySpan Transaction. It is anticipated that
HoldCo will set an initial annual dividend rate of $1.78 per share for its
common stock.
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Upon completion of the merger, Dr. William J. Catacosinos will become chairman
and chief executive officer of HoldCo; Mr. Robert B. Catell, currently chairman
and chief executive officer of KeySpan, will become president and chief
operating officer of HoldCo. One year after the closing, Mr. Catell will succeed
Dr. Catacosinos as chief executive officer, with Dr. Catacosinos continuing as
chairman. The board of directors of HoldCo will be comprised of 15 members, six
from the Company, six from KeySpan and three additional persons previously
unaffiliated with either company.
Effects of LIPA and KeySpan Transactions on Future Operations
The future operations and financial position of the Company will be
significantly affected by each of the proposed transactions with LIPA and
KeySpan described above. The discussion contained in this report and any
analysis of financial condition and results of operations does not reflect,
unless otherwise indicated, the potential effects of the transactions with LIPA
and KeySpan.
COMPETITIVE ENVIRONMENT
A discussion of the competitive issues the Company faces appears in Note 12 of
Notes to Financial Statements.
ELECTRIC OPERATIONS
General
The Company's system energy requirements are supplied from sources
located both on and off Long Island.
The following table indicates the 1997 summer capacity of the Company's steam
generation facilities, Internal Combustion (IC) Units and other generation
facilities as reported to the New York Power Pool (NYPP):
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Location of Units Description Fuel Units MW
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Company Owned:
Northport, L.I. Steam Turbine Dual* 2 778
Oil 2 754
Port Jefferson, L.I. Steam Turbine Dual* 2 382
Glenwood, L.I. Steam Turbine Gas 2 218
Island Park, L.I. Steam Turbine Dual* 2 386
Far Rockaway, L.I. Steam Turbine Dual* 1 109
Throughout L.I. IC Units Dual* 12 279
Oil 30 1,072
Jointly Owned:
NMP2 (18% Share) Oswego, New York Steam Turbine Nuclear 1 205
Owned by the New York Power Authority:
Holtsville, L.I. Combined Cycle Dual* 1 142
- -------------------------------------------------- ---------------------- ----------- ----------- ---------
Total 55 4,325
- -------------------------------------------------- ---------------------- ----------- ----------- ---------
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*Dual - Oil or natural gas.
Additional generating facilities owned by others, such as independent power
producers (IPPs) and cogenerators located on Long Island and investor-owned and
public electric systems located off Long Island provide the balance of the
Company's energy supplies.
The maximum demand on the Company's system was 4,140 Megawatts (MW) on July 15,
1997, representing 84% of the total available capacity of 4,953 MW on that day,
which included 766 MW of firm capacity purchased from other sources. By
agreement with the NYPP, the Company is required to maintain, on a monthly
basis, an installed and contracted firm power reserve
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generating capacity equal to at least 18% of its actual peak load. The Company
continues to meet this NYPP requirement.
System Requirements, Energy Available and Reliability
For the year ended March 31, 1998, system kilowatt hours (kWh) energy
requirements on the Company's system were 1.0% higher than the corresponding
1997 period. The Company forecasts increases of 2.3% and 3.2%, for the years
ending March 1999 and 2000, respectively compared to that experienced for the
year ended March 31, 1998. For the years ending March 31, 2001-2010, the Company
forecasts an average annual growth rate in system energy requirements of 1.1%.
Due to the effects of price elasticity, the projected peak demand for electric
power is expected to increase if the LIPA transaction is consummated. Based on
projections of peak demand for electric power in the absence of the LIPA
Transaction, the Company believes it will need to acquire additional generating
or demand-side resources starting in 1998 in order to maintain electric supply
reliability. In accordance with the Company's Integrated Electric Resource Plan
(IERP), issued in 1996, the Company intends to institute a combination of a peak
load reduction demand-side management program and a capacity purchase to meet
this need. Current projections are that new electric generating capacity will
not need to be installed on Long Island to meet peak demand until after 2002. It
is anticipated that such new capacity would be acquired through a competitive
bidding process.
Fuel Mix
The megawatt hours (MWh) and percentages of total energy available by type of
fuel for electric operations for the years ended March 31, 1998 and 1997, and
the years ended December 31, 1996 and 1995 were as follows:
<TABLE>
<CAPTION>
(In thousands of MWh)
Year Ended Year Ended
March 31, December 31,
--------- ------------
1998 1997 1996 1995
- ---------------------------------------------------------------------------------------------------------------
MWh % MWh % MWh % MWh %
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Oil 3,434 20% 3,278 19% 4,219 24% 3,099 17%
Gas 6,212 35% 5,469 31% 4,542 25% 6,344 36%
Nuclear 1,545 9% 1,553 9% 1,558 9% 1,301 7%
Purchased power 6,412 36% 7,261 41% 7,388 42% 7,143 40%
- ---------------------------------------------------------------------------------------------------------------
Total 17,603 100% 17,561 100% 17,707 100% 17,887 100%
===============================================================================================================
</TABLE>
Energy Sources
The total energy provided by oil and natural gas is generated by the Company's
units located on Long Island, while the nuclear generation is provided through
NMP2, the Company's 18% owned nuclear power plant which is located near Oswego,
New York.
Oil
The availability and cost of oil used by the Company is affected by factors such
as the international oil market, environmental regulations, conservation
measures and the availability of alternative fuels. In order to reduce the
impact of the above factors on the Company's operations, the Company, over the
past several years, has refitted the majority of its steam generation units
enabling them to burn oil or natural gas, whichever is more economical and
consistent with seasonal environmental requirements. The Company's fuel oil is
supplied principally by three suppliers.
7
<PAGE>
Oil consumption in barrels was as follows:
- -----------------------------------------------------------------------------
Years Ended Consumption (in barrels)
- -----------------------------------------------------------------------------
- -----------------------------------------------------------------------------
March 31, 1998 5.6 million
- -----------------------------------------------------------------------------
- -----------------------------------------------------------------------------
March 31, 1997 5.5 million
- -----------------------------------------------------------------------------
- -----------------------------------------------------------------------------
December 31, 1996 7.1 million
- -----------------------------------------------------------------------------
- -----------------------------------------------------------------------------
December 31, 1995 5.2 million
- -----------------------------------------------------------------------------
Natural Gas
Nine of the Company's eleven steam generating units have the capability of
burning natural gas. Seven of these units are capable of burning either oil or
natural gas. This enables the Company to burn the most cost-efficient fuel,
consistent with seasonal environmental requirements, thereby reducing the
Company's generation costs. In April 1996 and May 1997, the Company completed
two planned conversions of oil-fired steam generating units at its Port
Jefferson Power Station to dual-firing units.
Gas consumption for electric generation was as follows:
- ----------------------------------------------------------------------------
Years Ended Consumption (in million Dth)
- ----------------------------------------------------------------------------
- ----------------------------------------------------------------------------
March 31, 1998 69.4
- ----------------------------------------------------------------------------
- ----------------------------------------------------------------------------
March 31, 1997 63.6
- ----------------------------------------------------------------------------
- ----------------------------------------------------------------------------
December 31, 1996 50.2
- ----------------------------------------------------------------------------
- ----------------------------------------------------------------------------
December 31, 1995 69.8
- ----------------------------------------------------------------------------
The percentage of energy generated by burning natural gas at the Company's steam
and internal combustion units was as follows:
- ----------------------------------- --------------------------------
Years Ended Percent Generated
- ----------------------------------- --------------------------------
- ----------------------------------- --------------------------------
March 31, 1998 64%
- ----------------------------------- --------------------------------
- ----------------------------------- --------------------------------
March 31, 1997 63%
- ----------------------------------- --------------------------------
- ----------------------------------- --------------------------------
December 31, 1996 52%
- ----------------------------------- --------------------------------
- ----------------------------------- --------------------------------
December 31, 1995 67%
- ----------------------------------- --------------------------------
Purchased Power
The Company strives to provide its customers with the most economical energy
available to keep electric rates as low as possible. Often, this energy is
generated more economically at power plants within other electric systems and
transmitted to the Company through its interconnections. In addition, the
Company is required to purchase energy from sources located within its service
territory including the New York Power Authority (NYPA) Holtsville facility,
IPPs and cogenerators. IPPs and cogenerators located within the Company's
service territory provided approximately 206 MW of capacity to the Company
during the year ended March 31, 1998.
The percentage of the total energy made available to the Company by IPPs,
cogenerators and the NYPA Holtsville facility was follows:
- ----------------------------------- ---------------------------------------
Years Ended Percent of Energy Available
- ----------------------------------- ---------------------------------------
- ----------------------------------- ---------------------------------------
March 31, 1998 17.2%
- ----------------------------------- ---------------------------------------
- ----------------------------------- ---------------------------------------
March 31, 1997 16.1%
- ----------------------------------- ---------------------------------------
- ----------------------------------- ---------------------------------------
December 31, 1996 16.1%
- ----------------------------------- ---------------------------------------
- ----------------------------------- ---------------------------------------
December 31, 1995 16.3%
- ----------------------------------- ---------------------------------------
8
<PAGE>
The Company does not expect any new major IPPs or cogenerators to be built on
Long Island in the near future. Among the reasons supporting this conclusion is
the Company's belief that the market for IPPs and cogenerators to provide power
to the Company's remaining commercial and industrial customers is small.
Furthermore, under federal law, the Company is required to buy energy from
qualified producers at the Company's long-range avoided costs. Current
long-range avoided cost estimates for the Company have significantly reduced the
economic advantage to entrepreneurs seeking to compete with the Company and with
existing IPPs. For additional information with respect to competitive issues
facing the Company, see Note 12 of Notes to Financial Statements.
Nuclear
The Company holds an 18% interest in NMP2, an 1,137 MW nuclear generating unit
near Oswego, New York, which is operated by Niagara Mohawk Power Corporation
(NMPC). The cotenants of NMP2, in addition to the Company, are NMPC (41%), New
York State Electric & Gas Corporation (18%), Rochester Gas and Electric
Corporation (14%) and Central Hudson Gas & Electric Corporation (9%). For the
year ended March 31, 1998, NMP2 operated at 86.63% of its capacity. For a
further discussion of NMP2, see Note 5 of Notes to Financial Statements.
Interconnections
Five interconnections allow for the transfer of electricity between the Company
and members of the NYPP and the New England Power Pool. Energy from these
sources is transmitted pursuant to transmission agreements with NMPC, NYPA,
Northeast Utilities Service Company (NUSCO), a co-owner of one of these
interconnections, and Consolidated Edison Company of New York, Inc. (Con Edison)
and displaces energy that would otherwise be generated on the Company's system
at a higher cost. The capacity of these interconnections is utilized for Company
requirements including the transmission of the Company's share of power from
NMP2, the requirements of Con Edison, a co-owner with the Company of three of
these interconnections, and the requirements on Long Island of NYPA, the owner
of one of these interconnections.
Conservation Services
A discussion of conservation services appears in Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
The 1989 Settlement
In February 1989, the Company and the State of New York entered into the 1989
Settlement resolving certain issues relating to the Company and providing, among
other matters, for the financial recovery of the Company and for the transfer of
the Shoreham Nuclear Power Station (Shoreham) to LIPA for its subsequent
decommissioning.
A discussion of the 1989 Settlement and Shoreham decommissioning appears in Note
10 of Notes to Financial Statements.
Electric Rates
A discussion of electric rates appears in Note 4 of Notes to Financial
Statements.
9
<PAGE>
GAS OPERATIONS
General
The Company's gas supplies are transported by interstate pipelines from Canadian
and domestic sources. On-system peak shaving and IPP/Cogen peaking supplies are
available to meet system requirements during winter periods.
During the past several years, the Company actively participated in proceedings
before the FERC in an effort to mitigate any adverse impact that filings by
interstate pipeline companies might have on the Company's gas customers as well
as to decrease upstream transportation costs and improve operational tariffs.
The Company also actively participated in the proceedings before the PSC which
established the framework for a new competitive natural gas marketplace within
the State of New York.
In response to changes in federal and state regulations that have "unbundled"
traditional pipeline services in order to promote competition in the gas supply
and gas services market, the Company implemented its NaturalChoice(sm) firm
transportation program in April 1996. Under NaturalChoice(sm), customers may
purchase natural gas from qualified suppliers other than the Company. The
Company continues to provide NaturalChoice(sm) customers with all gas services
provided to traditional customers except for the procurement and sale of gas.
These services include the local transportation of gas, meter reading and
billing, equipment maintenance and emergency response. The Company's profit
margins have not been impacted by this new program as the Company collects from
these customers all costs associated with providing its service, including
operating the gas system.
As of March 31, 1998, there were approximately 3,600 NaturalChoice(sm) customers
with annual requirements of approximately 4,213,000 Dth or 7 percent of the
Company's annual gas system requirements.
Gas System Requirements
The Company has 467,000 firm gas customers at March 31, 1998, including 295,000
gas space heating customers, an increase of more than 15,000 gas space heating
customers over the past three years. The Company's penetration in the gas space
heating market within its service territory is approximately 29%.
Total firm sales for the year ended March 31, 1998, when normalized for weather,
decreased approximately 3.6% over the comparable period in 1997 primarily due to
customers switching to the NaturalChoice(sm) Program. The maximum daily sendout
experienced on the Company's gas system was 585,227 Dth on January 19, 1994,
representing 83% of the Company's per day capability at that time. The
forecasted maximum daily sendout for the 1998-1999 winter season (November 1 -
March 31) is approximately 652,000 Dth, or 88% of the Company's peak-day
capability.
10
<PAGE>
Peak Day Capability
The Company has firm gas peak day capability in excess of its projected
requirements for firm gas customers for the 1998-1999 winter season (November
1-March 31). Firm capability is summarized in the following table:
- ---------------------------------------------------- --------------------
Dth per day % of Total
- ---------------------------------------------------- --------------------
Transportation 263,000 35
Storage 294,000 40
Cogen/IPP Deliveries 85,000 11
Peak Shaving 103,000 14
==================================================== ====================
Total 745,000 100%
==================================================== ====================
Transportation
The Company has available under firm contract 263,000 Dth per day of year-round
and seasonal pipeline transportation capacity which is provided by four
interstate pipeline companies including the Iroquois Gas Transmission System.
The Company, through its majority interest in a subsidiary, LILCO Energy
Systems, Inc., is a general partner in the Iroquois pipeline with an equity
share of 1%.
Storage
In order to meet higher winter demand, the Company also has long-term firm
market area storage services in Pennsylvania and New York which provide a total
maximum supply of 294,000 Dth per day, with a total capacity of 22,534,000 Dth
for the winter period.
In order to provide the Company with greater security of supply and enhanced
operational flexibility in meeting peak-day requirements, the Company also
contracts for production area storage capacity in Louisiana and Mississippi.
However, the Company has no incremental firm pipeline transportation capacity
for these supplies.
Cogen/IPP Deliveries
The Company has contract rights with the Brooklyn Navy Yard Cogen facility to
receive approximately 576,000 Dth of peaking supplies during the winter period
at a rate of approximately 30,000 Dth per day. Also, the Company has contract
rights with the Nassau District Energy Corporation to receive 250,000 Dth of
peaking supplies during the winter period at a rate of 12,500 Dth per day.
The Company has contract rights with the NYPA IPP facility to receive 900,000
Dth of storage service during any continuous 100-day period during each winter
season at a daily rate not to exceed 31,000 Dth per day. In addition, the
Company has contract rights with Nissequogue Cogen facility to receive up to
330,000 Dth of storage service for 30 days during each winter season at a daily
rate not to exceed 11,000 Dth per day. The Company has the obligation to return
these quantities in kind during the following summer period. In addition, the
Company has the right to request 812,000 Dth in the winter season from the TBG
Cogen facility with the obligation to return the quantities in kind during the
following summer period. The daily quantity of 12,500 Dth is only available on
warmer winter days.
Peak Shaving
The Company has its own peak shaving supplies to meet its firm requirements on
excessively cold winter days. They include a liquefied natural gas plant with a
storage capacity of approximately 600,000 Dth and vaporization facilities which
provide approximately 103,000 Dth per day to the
11
<PAGE>
peak-day capability of the Company's system.
Firm Gas Supply
The Company has approximately 161,000 Dth per day of firm gas supplies that are
transported under its firm pipeline transportation capacity. About 83,000 Dth
per day is obtained from Canadian sources and 78,000 Dth per day is obtained
from domestic sources. Included in the long-term firm Canadian gas is about
3,000 Dth per day of gas contracted with Boundary Gas, Inc. (Boundary). The
Company owns 2.7% of the common stock of Boundary, a corporation formed with 14
other gas utility companies to act as a purchasing agent for the importation of
natural gas from Canada.
The Company's 161,000 Dth per day of long-term supply contracts have commodity
rates that are market-based. The Company has no fixed price supply contracts.
Certain of these contracts have minimum annual take or pay arrangements and/or
associated demand charges.
The Company also purchases various quantities of market-priced gas in both the
seasonal and monthly spot markets that is transported under firm and
interruptible transportation agreements.
Gas Rates
A discussion of gas rates appears in Note 4 of Notes to Financial Statements.
Recovery of Transition Costs
Transition costs are the costs associated with unbundling the pipeline
companies' merchant services in compliance with FERC Order No. 636. They include
pipeline companies' unrecovered gas costs and the costs that pipelines incur as
a result of modifying or terminating their gas supply contracts. In order to
recover transition costs, pipeline companies must demonstrate to the FERC that
such costs were attributable to Order No. 636 and that they were prudently
incurred. While the Company has challenged, on both eligibility and prudence
grounds, its supplier pipelines' efforts to recover their claimed transition
costs, the Company estimates that it will be responsible for total transition
costs of approximately $10 million. As of March 31, 1998, the Company has
collected $8.7 million of these transition costs from its gas customers.
Natural Gas Vehicles
The Company continues to maintain a focus on promoting Natural Gas Vehicles
(NGVs) and infrastructure development. Additional resources have been dedicated
to the NGV program in 1997 and 1998 and an arrangement with a company named
Fuelmaker has provided customers with a low risk, low cost approach to refueling
their NGVs. In addition, consistent with a Clean Cities designation, the Company
has aggressively assisted customers in obtaining Congestion Mitigation Air
Quality (CMAQ) grants and other Department of Energy funds to help offset their
incremental NGV and refueling equipment costs. As a result of these efforts,
NGVs consumed approximately 130,000 Dth and resulted in $260,000 in revenue net
of fuel for the year ended March 31, 1998.
ENVIRONMENTAL MATTERS
General
The Company's ordinary business operations necessarily involve materials and
activities which subject the Company to federal, state and local laws, rules and
regulations dealing with the environment, including air, water and land quality.
These environmental requirements may entail significant expenditures for capital
improvements or modifications and may expose the Company
12
<PAGE>
to potential liabilities which, in certain instances, may be imposed without
regard to fault or for historical activities which were lawful at the time they
occurred.
Laws which may impose such potential liabilities include (but are not limited
to) the federal Comprehensive Environmental Response, Compensation and Liability
Act (CERCLA, commonly known as Superfund), the federal Resource Conservation and
Recovery Act, the federal Toxic Substances Control Act (TSCA), the federal Clean
Water Act (CWA), and the federal Clean Air Act (CAA).
Capital expenditures for environmental improvements and related studies amounted
to approximately $9.2 million for the year ended March 31, 1998 and, based on
existing information, are expected to be $4.0 million for the year ended March
31, 1999. The expenditures in fiscal year 1998 and expected spending in fiscal
year 1999 include a total of $10.6 million for the completion of a gas-firing
capability project at Northport Unit 1 and Port Jefferson Unit 4.
It is not possible to ascertain with certainty if or when the various required
governmental approvals for which applications have been made will be issued, or
whether, except as noted below, additional facilities or modifications of
existing or planned facilities will be required or, generally, what effect
existing or future controls may have upon Company operations. Except as set
forth below and in Item 3 - "Legal Proceedings," no material proceedings have
been commenced or, to the knowledge of the Company, are contemplated by any
federal, state or local agency against the Company, nor is the Company a
defendant in any material litigation with respect to any matter relating to the
protection of the environment.
Recoverability of Environmental Costs
The Company believes that none of the environmental matters, discussed below,
will have a material adverse impact on the Company's financial position, cash
flows or results of operations. In addition, the Company believes that all
significant costs incurred with respect to environmental investigation and
remediation activities, not recoverable from insurance carriers, will be
recoverable from its customers.
Air
Federal, state and local regulations affecting new and existing electric
generating plants govern emissions of sulfur dioxide (SO2), nitrogen oxides
(NOX), particulate matter, and, potentially in the future, fine particulate
matter (aerosols of SO2), hazardous air pollutants and carbon dioxide (CO2).
Sulfur Dioxide Requirements
The laws governing the sulfur content of the fuel oil being burned by the
Company in compliance with the United States Environmental Protection Agency
(EPA) approved Air Quality State Implementation Plan (SIP) are administered by
the New York State Department of Environmental Conservation (DEC). The Company
does not expect to incur any costs to satisfy the 1990 amendments to the federal
CAA with respect to the reduction of SO2 emissions, as the Company already uses
natural gas and oil with acceptably low levels of sulfur as boiler fuels. These
fuels also result in reduced vulnerability to any future fine particulate
standards implemented in the form of stringent sulfur dioxide emission limits.
The Company's use of low sulfur fuels has resulted, and will continue to result,
in approximately 70,000 excess SO2 allowances per year through the year 1999.
The Company presently applies the proceeds resulting from any sales of excess
SO2 allowances as a reduction to the RMC balance.
The Company entered into a voluntary Memorandum of Understanding with the DEC
which
13
<PAGE>
provides that the Company will not sell SO2 allowances for use in 15 states in
an effort to mitigate the transport of acid rain precursors into New York State
from upwind states.
Nitrogen Oxides Requirements
Due to the Company's program of cost-effective emission reductions, including
the optimization of natural gas firing ability at almost all the steam electric
generating stations, the Company had the lowest NOX emissions rate of all the
utilities in New York State for the years ended December 31, 1997, 1996 and
1995. Since the Company's generating facilities are located within a CAA
Amendment-designated ozone non-attainment area, they are subject to NOx
reduction requirements which are being implemented in three phases. Phase I was
completed in 1995; Phase II and Phase III will be completed in 1999 and 2003,
respectively.
The Company is currently in compliance with Phase I NOx reduction requirements.
It is estimated that additional expenditures of approximately $1 million will be
required to meet Phase II NOx reduction requirements. Subject to requirements
that are expected to be promulgated in forthcoming regulations, the Company
estimates that it may be required to spend an additional $10 million to $34
million, excluding the Northport Unit 1 conversion, by the year 2003 to meet
Phase III NOx reduction requirements. The completion of the project to add
gas-firing capability at Northport Unit 1 (completed in May 1998 at a total cost
of approximately $8.4 million) will also facilitate the Company's compliance
with the anticipated Phase III Nox reduction requirements.
Continuous Emission Monitoring
Additional software and equipment upgrades for Continuous Emissions Monitors of
approximately $2 million may be required through 1999 at all generating
facilities in order to meet EPA requirements under development for the NOx
allowance tracking/trading program.
Hazardous Air Pollutants
Utility boilers are presently exempt from regulation as sources of hazardous air
pollutants until the EPA completes a study of the risks, if any, to public
health reasonably anticipated to occur as a result of emissions by electric
generating units. The EPA is expected to make a determination concerning the
need for control of hazardous air pollutants from utility facilities in 1998.
Until such determination is made by the EPA, the Company cannot fully ascertain
what, if any, costs will be incurred for the control of hazardous air
pollutants.
However, after the expenditure of approximately $1.5 million in fiscal 1998 and
the planned spending of $0.5 million through March 31, 1999, for electrostatic
precipitator upgrades and, with the maximization of clean burning natural gas as
the primary fuel, hazardous air pollutant regulations, if enacted, should not
impose any additional control requirements for the Company's facilities.
Carbon Dioxide Requirements
CO2 emissions from the Company's plants have been reduced by approximately 23%
since 1990, largely through greater reliance on the use of natural gas and
through conservation programs. This makes the Company less vulnerable to future
CO2 reduction requirements.
Opacity Issues
The DEC has proposed commencing enforcement actions against all New York
utilities for alleged opacity exceedences from steam electric generating
facilities. Opacity is a measure of the relative level of light that is obscured
from passing through a power plant stack emission plume. An exceedence occurs
when the level of light passing through the plume is reduced by more than 20%
14
<PAGE>
for six minutes or more. The Company has entered into an Administrative Consent
Order (ACO) with the DEC which resolves all historical opacity exceedences,
establishes an opacity reduction program to be undertaken by the Company, and
sets a stipulated penalty schedule for future exceedences. The number of
exceedences experienced by the Company is relatively low, placing the Company
among the best performers in New York State.
Electromagnetic Fields
Electromagnetic fields (EMF) occur naturally and also are produced wherever
there is electricity. These fields exist around power lines and other utility
equipment. The Company is in compliance with all applicable regulatory standards
and requirements concerning EMF. The Company also monitors scientific
developments in the study of EMF, has contributed to funding for research
efforts, and is actively involved in customer and employee outreach programs to
inform the community of EMF developments as they occur. Although an extensive
body of scientific literature has not shown an unsafe exposure level or a causal
relationship between EMF exposure and adverse health effects, concern over the
potential for adverse health effects will likely continue without final
resolution for some time. To date, four residential property owners have
initiated separate lawsuits against the Company alleging that the existence of
EMF has diminished the value of their homes. These actions are in the
preliminary stages of discovery and are similar to actions brought against
another New York State utility, which were dismissed by the New York State Court
of Appeals. The Company is not involved in any active litigation that alleges a
causal relationship between exposure to EMF and adverse health effects.
Water
Under the federal CWA and the New York State Environmental Conservation Law, the
Company is required to obtain a State Pollutant Discharge Elimination System
permit to make any discharge into the waters of the United States or New York
State. The DEC has the jurisdiction to issue these permits and their renewals
and has issued permits for the Company's generating units. The permits allow the
continued use of the circulating water systems which have been determined to be
in compliance with state water quality standards. The permits also allow for the
continued use of the chemical treatment systems and for the continued discharge
of water in accordance with applicable permit limits.
In fiscal year 1998, the Company spent approximately $300,000 to upgrade its
waste water treatment facilities and for other measures designed to protect
surface and ground water quality and expects to spend an additional $100,000 in
the years 1998-2000.
Long Island Sound Transmission Cables
During 1996, the Connecticut Department of Environmental Protection (DEP) issued
a modification to an Administrative Consent Order (ACO) previously issued in
connection with an investigation of an electric transmission cable system
located under the Long Island Sound (Sound Cable) that is jointly owned by the
Company and the Connecticut Light and Power Company (Owners). The modified ACO
requires the Owners to submit to the DEP and DEC a series of reports and studies
describing cable system condition, operation and repair practices, alternatives
for cable improvements or replacement and environmental impacts associated with
leaks of fluid into the Long Island Sound which have occurred from time to time.
The Company continues to compile required information and coordinate the
activities necessary to perform these studies and, at the present time, is
unable to determine the costs it will incur to complete the requirements of the
modified ACO or to comply with any additional requirements.
15
<PAGE>
The Owners have also entered into an ACO with the DEC as a result of leaks of
dielectric fluid from the Sound Cable. The ACO formalizes the DEC's authority to
participate in and separately approve the reports and studies being prepared
pursuant to the ACO issued by the DEP. In addition, the ACO settles any DEC
claim for natural resource damages in connection with historical releases of
dielectric fluid from the Sound Cable.
In October 1995, the U.S. Attorney for the District of Connecticut had commenced
an investigation regarding occasional releases of fluid from the Sound Cable, as
well as associated operating and maintenance practices. The Owners have provided
the U.S. Attorney with all requested documentation. The Company believes that
all activities associated with the response to occasional releases from the
Sound Cable were consistent with legal and regulatory requirements.
In December 1996, a barge, owned and operated by a third party, dropped anchor
which then dragged over and damaged the Sound Cable, resulting in the release of
dielectric fluid into Long Island Sound. Temporary clamps and leak abaters were
installed on the cables to stop the leaks. Permanent repairs were completed in
June 1997. The cost to repair the Sound Cable was approximately $17.8 million,
for which there was $15 million of insurance coverage. The Owners filed a claim
and answer in response to the maritime limitation proceeding instituted by the
barge owner in the United States District Court, Eastern District of New York.
The claim seeks recovery of the amounts paid by insurance carriers and recovery
of the costs incurred for which there was no insurance coverage. Any costs to
repair the Sound Cable which are not reimbursed by a third party or covered by
insurance will be shared equally by the Owners.
Land
Superfund imposes joint and several liability, regardless of fault, upon
generators of hazardous substances for costs associated with environmental
cleanup activities. Superfund also imposes liability for remediation of
pollution caused by historical acts which were lawful at the time they occurred.
In the course of the Company's ordinary business operations, the Company is
involved in the handling of materials that are deemed to be hazardous substances
under Superfund. These materials include asbestos, metals, certain flammable and
organic compounds and dielectric fluids containing polychlorinated biphenyls
(PCBs). Other hazardous substances may be handled in the Company's operations or
may be present at Company locations as a result of historical practices by the
Company or its predecessors in interest. The Company has received notice
concerning possible claims under Superfund or analogous state laws relating to a
number of sites at which it is alleged that hazardous substances generated by
the Company and other potentially responsible parties (PRPs) were deposited. A
discussion of these sites is set forth below.
Estimates of the Company's allocated share of costs for investigative, removal
and remedial activities at these sites range from preliminary to refined and are
updated as new information becomes available. In December 1996, the Company
filed a complaint in the United States District Court for the Southern District
of New York against 14 of the Company's insurers which issued general
comprehensive liability (GCL) policies to the Company. In January 1998, the
Company commenced a similar action against the same and certain additional
insurer defendants in New York State Supreme Court, First Department; the
federal court action was subsequently dismissed in March 1998. The Company is
seeking recovery under the GCL policies for the costs incurred to date and
future costs associated with the clean-up of the Company's former manufactured
gas plant (MGP) sites and Superfund sites for which the Company has been named a
PRP. The Company is seeking a declaratory judgment that the defendant insurers
are bound by the
16
<PAGE>
terms of the GCL policies, subject to the stated coverage limits, to reimburse
the Company for the clean up costs. The outcome of this proceeding cannot yet be
determined.
Superfund Sites
Metal Bank
The EPA has notified the Company that it is one of many PRPs that may be liable
for the remediation of a licensed disposal site located in Philadelphia,
Pennsylvania, and operated by Metal Bank of America. The Company and nine other
PRPs, all of which are public utilities, completed performance of a Remedial
Investigation and Feasibility Study (RI/FS), which was conducted under an ACO
with the EPA. In December 1997, the EPA issued its Record of Decision (ROD),
setting forth the final remedial action selected for the site. In the ROD, the
EPA estimated that the present cost of the selected remedy for the site is $17.3
million. At this time, the Company cannot predict with reasonable certainty the
actual cost of the selected remedy, who will implement the remedy, or the cost,
if any, to the Company. Under a PRP participation agreement, the Company
previously was responsible for 8.2% of the costs associated with the RI/FS. The
Company's allocable share of liability for the remediation activities has not
yet been determined.
The Company has recorded a liability of approximately $1 million representing
its estimated share of the additional cost to remediate this site based upon its
8.2% responsibility under the RI/FS.
Syosset
The Company and nine other PRPs have been named in a lawsuit where the Town of
Oyster Bay (Town) is seeking indemnification for remediation and investigation
costs that have been or will be incurred for a federal Superfund site in
Syosset, New York. For a further discussion on this matter, see Item 3, Legal
Proceedings - Environmental.
PCB Treatment, Inc.
The Company has also been named a PRP for disposal sites in Kansas City, Kansas,
and Kansas City, Missouri. The two sites were used by a company named PCB
Treatment, Inc. from 1982 until 1987 for the storage, processing, and treatment
of electric equipment, dielectric oils and materials containing PCBs. According
to the EPA, the buildings and certain soil areas outside the buildings are
contaminated with PCBs.
Certain of the PRPs, including the Company and several other utilities, formed a
PRP group, signed an ACO, and have developed a workplan for investigating
environmental conditions at the sites. Documentation connecting the Company to
the sites indicates that the Company was responsible for less than 1% of the
materials that were shipped to the Missouri site. The EPA has not yet completed
compiling the documents for the Kansas site.
Osage
The EPA has notified the Company that it is a PRP at the Osage Metals Site, a
former scrap metal recycling facility located in Kansas City, Kansas. Under
Section 107(a) of CERCLA, parties who arranged for disposal of hazardous
substances are liable for costs incurred by the EPA in responding to a release
or threat of release of the hazardous substances. Osage had purchased capacitor
scrap metal from PCB Treatment, Inc. Through the arrangements that the Company
made with PCB Treatment, Inc. to dispose of capacitors, the Company is alleged
to have arranged for disposal within the meaning of the federal Superfund law. A
similar letter was sent to 861 parties who sent capacitors to PCB Treatment,
Inc. The EPA is seeking to recover approximately $1.1 million dollars it
expended to conduct a removal action at the site. The Company is currently
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unable to determine its share of the $1.1 million expenditure.
Port Refinery
The Company has been notified that it is a PRP at the Port Refinery Superfund
site located in Westchester County, New York. Port Refinery was engaged in the
business of purchasing, selling, refining and processing mercury and the Company
may have shipped a small amount of waste products containing mercury to this
site. Tests conducted by the EPA indicated that the site and certain adjacent
properties were contaminated with mercury. As a result, the EPA has performed a
response action at the site and seeks to recover its costs, currently totaling
approximately $4.4 million, plus interest, from the PRPs. The Company does not
believe its portion of these costs, if any, will be material.
Port Washington
In 1989, the EPA notified the Company that it was a PRP for a landfill in Port
Washington, New York. The Company does not believe that it sent any materials to
the site that contributed to the contamination which requires remediation and
has therefore declined the EPA's requests to participate in funding the
investigation and remediation activities at the property. The Company has not
received further communications regarding this site.
Liberty
The EPA has notified the Company that it is a PRP in a Superfund site located in
Farmingdale, New York. Industrial operations took place at this site for at
least fifty years. The PRP group has claimed that the Company should absorb
remediation expenses in the amount of approximately $100,000 associated with
removing PCB-contaminated soils from a portion of the site which formerly
contained electric transformers. The Company is currently unable to determine
its share of costs of remediation at this site.
Huntington/East Northport
The DEC has notified the Company, pursuant to the State Superfund program, that
its records indicate the Company may be responsible for the disposal of waste at
this municipal landfill property. The Company conducted a search of its
corporate records and did not locate any documents concerning waste disposal
practices associated with this landfill. The Company is currently unable to
determine its share, if any, of the costs to investigate and remediate this
site.
Blydenburgh
The New York State Office of the Attorney General has notified the Company that
it may be responsible for the disposal of wastes and/or for the generation of
hazardous substances which may have been disposed of at the Blydenburgh
Superfund site, a municipal sanitary landfill located in the Town of Islip,
Suffolk County. The State has incurred approximately $15 million in costs for
the investigation and remediation of environmental conditions at the landfill.
In connection with this notification, the Company conducted a review of its
corporate records and did not locate any documents concerning waste disposal
practices associated with this landfill. The Company is currently unable to
determine its share, if any, of the costs to investigate and remediate this
site.
Other Sites
Manufactured Gas Plant Sites
The DEC has required the Company and other New York State utilities to
investigate and, where necessary, remediate their former MGP sites. Currently,
the Company is the owner of six pieces of property on which the Company or
certain of its predecessor companies produced manufactured gas. Operations at
these facilities in the late 1800's and early 1900's may have resulted in the
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disposal of certain waste products located at these sites.
The Company has entered into discussions with the DEC which are expected to lead
to the issuance of one or more ACOs regarding the management of environmental
activities at these six properties. Although the exact amount of the Company's
cleanup costs cannot yet be determined, based on the findings of preliminary
investigations conducted at each of these six sites, current estimates indicate
that it may cost approximately $54 to $92 million to investigate and remediate
all of these sites. Considering the range of possible remediation estimates, the
Company felt it appropriate to record a $54 million liability reflecting the
present value of the future stream of payments amounting to $70 million to
investigate and remediate these sites. The Company used a risk-free rate of 6.0%
to discount this obligation. The Company believes that the PSC will provide for
future recovery of these costs and has recorded a $54 million regulatory asset.
The Company's rate settlement which the PSC approved February 4, 1998 as
discussed in Note 3 of Notes to Financial Statements, allows for the recovery of
MGP expenditures from gas customers.
The Company is also evaluating its responsibilities with respect to several
other former MGP sites that existed in its territory which it does not presently
own. Research is underway to determine the existence and nature of operations
and relationship, if any, to the Company or its predecessor companies.
North Hills Leak
The Company has undertaken remediation of certain soil locations in North Hills,
New York that were impacted by a release of insulating fluid from an electrical
cable in August 1994. The Company estimates that any additional cleanup costs
will not exceed $0.5 million. The Company has initiated cost recovery actions
against the third parties it believes are responsible for causing the cable
leak, the outcome of which are uncertain.
Storage Facilities
As a result of petroleum leaks from underground storage facilities and other
historical occurrences, the Company is required to investigate and, in certain
cases, remediate affected soil and groundwater conditions at several facilities
within its service territory. The aggregate costs of such remediation work could
be between $3 million and $5 million. To the extent that these costs are not
recoverable through insurance carriers, the Company believes such costs will be
recoverable from its customers.
Nuclear Waste
Low Level Radioactive Waste
The federal Low Level Radioactive Waste Policy Amendment Act of 1985, requires
states to arrange for the disposal of all low level radioactive waste generated
within the state or, in the alternative, to contract for their disposal at an
operating facility outside the state. As a result, New York State has stated its
intentions of developing an in-state disposal facility due to the large volume
of low level radioactive waste generated within the state and has committed to
develop a plan for the management of such waste during the interim period until
a disposal facility is available. New York State is still developing a disposal
methodology and acceptance criteria for a disposal facility. The latest New York
State low level radioactive waste site development schedule now assumes two
possible siting scenarios, a volunteer approach and a non-volunteer approach,
either of which would not begin operation until at least 2001. Low level
radioactive waste generated at NMP2 is currently being disposed of at the
Barnwell, South Carolina waste disposal facility which reopened in July 1995 to
out-of-state low level waste generators.
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In the event that off-site storage becomes unavailable prior to 2001, NMPC has
implemented a low level radioactive waste management program that will properly
handle interim on-site storage of low level radioactive waste for NMP2 for at
least ten years. The Company's share of the costs associated with temporary
storage and ultimate disposal are currently recovered in rates.
Spent Nuclear Fuel
NMPC, on behalf of the NMP2 cotenants, has entered into a contract with the DOE
for the permanent storage of NMP2 spent nuclear fuel. The Company reimburses
NMPC for its 18% share of the cost under the contract at a rate of $1.00 per
megawatt hour of net generation less a factor to account for transmission line
losses. The Company is collecting its portion of this fee from its electric
customers. It is anticipated that the DOE facility may not be available for
permanent storage until at least 2010. Currently, all spent nuclear fuel from
NMP2 is stored at the NMPC site, and existing facilities are sufficient to
handle all spent nuclear fuel generated at NMP2 through the year 2012.
For information concerning environmental litigation, see Item 3 "Legal
Proceedings" under the heading Environmental.
THE COMPANY'S SECURITIES
General
The Company's securities are rated by Moody's Investors Service, Inc., Standard
and Poor's, Fitch IBCA, Inc. and Duff & Phelps Credit Rating Co. For information
relating to the ratings of the Company's securities, see Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
The G&R Mortgage
The Company's General and Refunding Indenture dated June 1, 1975 (G&R Mortgage)
is a lien upon substantially all of the Company's properties. Outstanding at
March 31, 1998 and 1997 were approximately $1.3 billion of G&R Bonds.
Under the G&R Mortgage, the Company may issue G&R Bonds on the basis of either
matured or redeemed G&R Bonds or on the basis of the Bondable Value of Property
Additions (BVPA). Generally, when issuing G&R Bonds, the Company must satisfy a
mortgage interest coverage requirement, known as the G&R Mortgage Interest
Coverage. The G&R Mortgage Interest Coverage requires that the net earnings as
defined in the G&R Indenture, available for interest for any 12 consecutive
calendar months within the 15 consecutive calendar months preceding the issuance
of any G&R Bonds must be equal to at least two times the stated annual interest
payable on outstanding G&R Bonds, including any new G&R Bonds. Under the G&R
Mortgage Interest Coverage, the Company would currently be able to issue
approximately $5.2 billion of additional G&R Bonds based upon net earnings for
the year ended March 31, 1998 and an assumed interest rate of 7.75% for such
additional G&R Bonds. A change of 1/8 of 1% in the assumed interest rate of such
G&R Bonds would result in a change of approximately $82 million in the amount of
such G&R Bonds that the Company could issue. The maximum amount of additional
G&R Bonds which the Company is currently able to issue on the basis of either
matured or retired G&R Bonds and on the basis of the BVPA is approximately $1.5
billion.
Under the provisions of the G&R Mortgage, the Company must also satisfy by June
30 of each year a Sinking Fund requirement, which for the year ended December
31, 1997 is $25 million. The Company believes that, based upon currently
scheduled redemptions and maturities, it will
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have sufficient retired G&R Bonds for the foreseeable future to satisfy the
requirements of the G&R Sinking Fund.
The G&R Mortgage also contains a Maintenance Fund covenant which requires that
the aggregate amount of property additions added subsequent to December 31, 1974
must be, as of the end of each calendar year subsequent to 1974, at least equal
to the cumulative provision for depreciation (as defined in the G&R Mortgage)
from December 31, 1974. The G&R Mortgage requires cash (or retired G&R Bonds) to
be deposited to satisfy the Maintenance Fund requirement only when such
cumulative provision for depreciation exceeds such aggregate amount of property
additions. As of December 31, 1997, the amount of such cumulative property
additions calculated pursuant to the G&R Mortgage was approximately $10.4
billion, including approximately $5.5 billion of property additions attributable
to Shoreham. Also, as of December 31, 1997, the amount of the cumulative
provision for depreciation, similarly calculated, was approximately $2.0
billion. The Company anticipates that the aggregate amount of property additions
will continue to exceed the cumulative provision for depreciation.
For a discussion of the effect the LIPA Transaction will have on Company debt
outstanding, see Long Island Power Authority Transaction, above.
Unsecured Debt
The Company's G&R Mortgage and its Restated Certificate of Incorporation do not
contain any limitations upon the issuance of unsecured debt. The Company's
unsecured debt consists of debentures and certain tax-exempt securities.
The Company's Debenture Indenture, dated as of November 1, 1986, as
supplemented, and its Debenture Indenture, dated as of November 1, 1992, as
supplemented, each provide for the issuance of an unlimited amount of Debentures
to be issued in amounts that may be authorized from time to time in one or more
series. The debentures are unsecured and rank pari passu with all other
unsecured indebtedness of the Company subordinate to the obligations secured by
the Company's G&R Mortgage. At March 31, 1998 and 1997, there were approximately
$2.3 billion of debentures outstanding. For a discussion of the effect that the
LIPA Transaction will have on the Company's G&R Bonds and Debentures, see "Long
Island Power Authority Transaction," above.
As of March 31, 1998, the Company had outstanding approximately $941 million
principal amount of promissory notes, comprised of: (i) $2 million of tax-exempt
Industrial Development Revenue Bonds (IDRBs); (ii) approximately $214 million of
tax-exempt Pollution Control Revenue Bonds (PCRBs); and (iii) $725 million of
tax-exempt Electric Facilities Revenue Bonds (EFRBs). Of these amounts, certain
series are subject to periodic tenders. For a discussion of the effect that the
LIPA Transaction will have on the Company's tax exempt authority financing
notes, see "Long Island Power Authority Transaction," above.
For additional information respecting tender provisions and other information on
the Company's outstanding debt, see Note 7 of Notes to Financial Statements.
Equity Securities
Common Stock
The Company's common stock is listed on the New York and Pacific Stock
Exchanges, and is traded under the symbol "LIL." The Board of Directors' current
policy is to pay cash dividends on the common stock on a quarterly basis.
However, before declaring any dividends, the Company's Board of Directors
considers, among other factors, the Company's financial condition, its ability
to
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comply with provisions of the Company's Restated Certificate of Incorporation
and the availability of retained earnings, future earnings and cash. For
additional information with respect to the Company's common stock, see Note 6 of
Notes to Financial Statements.
Preferred Stock
The Company's Restated Certificate of Incorporation provides that the Company
may not issue additional preferred stock unless, for any 12 consecutive calendar
months within the 15 calendar months immediately preceding the calendar month
within which such additional shares shall be issued, the net earnings of the
Company available for the payment of interest charges on the Company's
interest-bearing indebtedness, determined after provision for depreciation and
all taxes, and in accordance with sound accounting practice, shall have been at
least one and one-half times the aggregate of the annual interest charges on the
interest-bearing indebtedness of the Company and annual dividend requirements on
all shares of preferred stock to be outstanding immediately after the proposed
issue of such shares of the preferred stock (Earnings Ratio). At March 31, 1998,
the Company satisfied the Earnings Ratio and could issue up to approximately
$1,076 million of preferred stock at an assumed dividend rate of 8.25%. When the
proceeds from the sale of the preferred stock to be issued are used to redeem
outstanding preferred stock, the requirement to satisfy the Earnings Ratio is
not applicable if the dividend requirement and the requirements for redemption
in a voluntary liquidation of the preferred stock to be issued do not exceed the
respective amounts for the preferred stock which is to be retired. Additional
preferred stock may also be issued beyond amounts permitted under the Earnings
Ratio with the approval of at least two-thirds of the votes entitled to be cast
by the holders of the total number of shares of outstanding preferred stock. For
additional information with respect to the Company's preferred stock, see Note 6
of Notes to Financial Statements.
Preference Stock
Issuance of preference stock, which is subordinate to the Company's preferred
stock but senior to its common stock, with respect to declaration and payment of
dividends and the right to receive amounts payable on any dissolution, does not
require satisfaction of a net earnings test or any other coverage requirement,
unless established by the Board of Directors for one or more series of
preference stock, prior to the issuance of such series. No preference stock has
been issued by the Company, nor does the Company currently plan to issue any.
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EXECUTIVE OFFICERS OF THE COMPANY
Current information regarding the Company's Executive Officers, all of whom
serve at the will of the Board of Directors, follows:
William J. Catacosinos: Dr. Catacosinos has served as Chairman of the Board of
Directors and Chief Executive Officer of the Company since January 1984, and as
a Director since December 1978. He currently chairs the Executive Committee of
the Company's Board of Directors. Dr. Catacosinos also served as President of
the Company from March 1984 to January 1987 and from March 1994 to December
1996. Dr. Catacosinos, 68, a resident of Mill Neck, Long Island, earned a
bachelor of science degree, a masters degree in business administration and a
doctoral degree in economics from New York University. Dr. Catacosinos is a
member of the Boards of Atlantic Bank of New York, the Long Island Association
and the Empire State Business Alliance, and is a member of the Advisory
Committee of the Huntington Township Chamber Foundation. He is the former
Chairman and Chief Executive Officer of Applied Digital Data Systems, Inc.,
Hauppauge, New York; served as Chairman of the Board and Treasurer of Corometric
Systems, Inc. of Wallingford, Connecticut; and served as Assistant Director at
Brookhaven National Laboratory, Upton, New York.
Theodore A. Babcock: Vice President since January 1997, Treasurer since February
1994 and Assistant Corporate Secretary since January 1996, Mr. Babcock joined
the Company in July 1992 as Assistant Treasurer. He previously spent five years
with the AMBASE Corporation as an Assistant Vice President and was promoted in
1988 to Vice President and Treasurer. Prior to AMBASE, Mr. Babcock spent 11
years with the Associated Dry Goods Corporation where he was promoted to
Assistant Treasurer and Director of Corporate Treasury Operations in 1984. Mr.
Babcock, 43, received a bachelor of science degree in accounting from Manhattan
College and a masters degree in finance from Iona College. Mr. Babcock is a
member of the board of the Huntington Township Chamber Foundation.
Michael E. Bray: Senior Vice President of the Electric Business Unit since
joining the Company in March 1997. Prior to joining the Company Mr. Bray was
President and CEO of DB Riley Consolidated in Worcester, Massachusetts. From
1987-1994 Mr. Bray was with ABB Power Generation, Inc. in Windsor, Connecticut
holding the positions of Senior Vice President Sales & Marketing for ABB Power
Generation and President of ABB's Resource Recovery Systems organization. Prior
to that, he spent 17 years with General Electric Company beginning as a field
engineer in the power equipment service organization and ultimately managing
General Electric's cogeneration development, construction and operating
organization. Mr. Bray, 50, holds a bachelor of science degree in mechanical
engineering from the University of Missouri at Rolla and a masters degree in
Business Administration from Washington University. Mr. Bray is a member of the
American Academy of Mechanical Engineers, past Board of Director/member of
American Boiler Manufacturer's Association and the Greater Hartford Chamber of
Commerce. He is also a charter member of the Academy of Mechanical Engineers at
the University of Missouri at Rolla.
Charles A. Daverio: Vice President of The Energy Exchange Group since December
1996, Mr. Daverio, 48, holds a bachelor of engineering degree in mechanical
engineering from Manhattan College, a master of science degree in industrial
engineering from New York University and a master of business administration
from New York Institute of Technology. He joined the Company in 1976 as an
Associate Engineer. He held various supervisory and managerial positions in the
Nuclear Engineering Department from 1979 through 1989. In 1990, he was assigned
Manager of Gas Supply and Planning and was given the additional responsibility
for Gas Operations in 1993. Mr. Daverio is the Company's representative on the
Iroquois Gas
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Transmission System's Management Committee and is on the Board of the Iroquois
Pipeline Operating Company. Mr. Daverio is a member of the board of the
Huntington Arts Council.
Jane A. Fernandez: Vice President of Human Resources since May 1997, Ms.
Fernandez joined the Company in 1973 and has held various positions in the
Employee Relations/Human Resources organization since that time. She was
Director of Human Resource Planning from 1988 to 1990, Director of Human
Resource Services from 1990 to 1994, Director of Corporate Training and Human
Resources in 1994, and Assistant Vice President of Human Resources from 1994 to
1997. Ms. Fernandez, 48, is a graduate of C. W. Post College and holds an MBA in
Management from Hofstra University.
James T. Flynn: President and member of the Company's Board of Directors since
December 1996 and Chief Operating Officer since March 1994, Mr. Flynn joined the
Company in October 1986 as Vice President of Fossil Production. He also held the
positions of Group Vice President, Engineering and Operations and Executive Vice
President. Before joining the Company, Mr. Flynn, 64, was General
Manager-Eastern Service Department for General Electric. His career began as a
member of General Electric's Technical Marketing Program in 1957. He holds a
bachelor of science degree in mechanical engineering from Bucknell University
and is a Licensed Professional Engineer in the State of Pennsylvania.
Joseph E. Fontana: Vice President since January 1997 and Controller since
October 1994, Mr. Fontana joined the Company in December 1992 as Director of
Accounting Services. He held the position of Assistant Controller from February
1994 through September 1994. In his capacity as Controller, Mr. Fontana serves
as the Company's Chief Accounting Officer. Mr. Fontana is a member of the
American Institute of Certified Public Accountants and the New York State
Society of CPAs. Before joining the Company, Mr. Fontana was a Senior Manager at
the international accounting firm of Ernst & Young, LLP. Mr. Fontana, 40, holds
a bachelor of science degree in accounting from Westchester State College and is
a Certified Public Accountant.
George B. Jongeling: Vice President of Special Projects since April 1998. Prior
to joining the Company, Mr. Jongeling was President and Chief Operating Officer
of Smith Cogeneration Company, an Independent Power Development Company with
active independent power development in Asia and operating plants in the U.S.
Previous assignments included Vice President of Operations and Member of the
Board of Directors of DB Riley, President of PACE Construction Company, Vice
President of Service and Spare Parts for ABB Gas Turbine Business and Vice
President of Business Development for ABB waste to energy business. He started
his career in 1966 as a field engineer for the General Electric Company and
spent 24 years working in the power generation business in domestic and foreign
management positions. His last General Electric assignment was as Manager of the
Eastern Region of the U.S. for the Systems Marketing Group supporting the
cogeneration, construction, development and O&M businesses for General Electric.
Mr. Jongeling, 54, received a Bachelor of Science degree in Mechanical
Engineering from the South Dakota School of Mines and Technology and is a
licensed professional engineer in Illinois and Missouri.
Robert X. Kelleher: Senior Vice President of Human Resources since May 1997, Mr.
Kelleher joined the Company in 1959 and has held various managerial positions in
the Finance, Accounting, Purchasing, Stores, and Employee Relations
organizations. He was Industrial Relations Manager from 1975 to 1979, Manager of
the Employee Relations Department from 1979 to 1985, Assistant Vice President of
the Employee Relations Department from 1985 to 1986, and Vice President of Human
Resources from 1986 to 1997. Mr. Kelleher, 61, is a graduate of St.
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Francis College and the Human Resources Management and Executive Management
Programs of Pennsylvania State University. Mr. Kelleher is a member of the
American Compensation Association, Personnel Directors Council, Industrial
Relations Research Institute and The Edison Electric Institute's Labor Relations
Committee.
John D. Leonard, Jr.: Vice President of Special Projects since April 1997, Mr.
Leonard joined the Company in 1984 as Vice President of Nuclear Operations. He
continues to be responsible for nuclear issues. Mr. Leonard served as Vice
President of Engineering and Construction from March 1994 through March 1997,
and previously served as Vice President of Corporate Services from July 1989
through March 1994. From 1980 to 1984, Mr. Leonard was the Vice President and
Assistant Chief Engineer for Design and Analysis at the New York Power
Authority. Prior to this position, he served as a Resident Manager of the
Fitzpatrick Nuclear Power Plant for approximately five years. Before accepting a
position at the New York Power Authority, Mr. Leonard served as Corporate
Supervisor of Operational Quality Assurance of the Virginia Electric Power
Company from 1974 to 1976. In 1974, Mr. Leonard retired with the rank of
Commander from the United States Navy, having commanded two nuclear-powered
submarines in a career that spanned 20 years. He holds a bachelor of science
degree from Duke University and a master of science degree from the Naval Post
Graduate School. He is 65 and a Licensed Professional Engineer in the State of
New York.
Adam M. Madsen: Senior Vice President of Corporate and Strategic Planning since
1984, Mr. Madsen, 61, holds a bachelors degree in electrical engineering from
Manhattan College and a master of science degree in nuclear engineering from
Long Island University. He has been with the Company since 1961, serving in
various engineering positions including Manager of Engineering from 1978 to
1984. Prior to that time, he held the position of Manager of the Planning
Department. Since 1978, Mr. Madsen has been the Company's representative to the
Planning Committee of the New York Power Pool. He is a member of the Northeast
Power Coordinating Council's Executive Committee and the Council's Reliability
Coordinating Committee. He also serves on the Board of Directors of the Empire
State Electric Energy Research Company. Mr. Madsen is a Licensed Professional
Engineer in the State of New York.
Kathleen A. Marion: Vice President of Corporate Services since April 1994 and
Corporate Secretary since April 1992, Ms. Marion has served as Assistant to the
Chairman since April 1987. She was Assistant Corporate Secretary from April 1990
to April 1992. Ms. Marion, 43, has a bachelor of science degree in business and
finance from the State University of New York at Old Westbury.
Brian R. McCaffrey: Vice President of Communications since February 1997, Mr.
McCaffrey joined the Company in 1973. Mr. McCaffrey, 52, holds a bachelor of
science degree in aerospace engineering from the University of Notre Dame. He
also received a master of science degree in aerospace engineering from
Pennsylvania State University and a master of science degree in nuclear
engineering from Polytechnic University. He is a Licensed Professional Engineer
in the State of New York. Prior to his present assignment, Mr. McCaffrey was
Vice President of Administration since 1987. Previously, Mr. McCaffrey served in
many positions in the nuclear organizations of the Company and positions in
engineering capacities associated with gas turbine and fossil power station
projects. Mr. McCaffrey is a member of the Executive Board of the Suffolk County
Council Boy Scouts of America.
Joseph W. McDonnell: Senior Vice President of Marketing and External Affairs
since December 1996, Dr. McDonnell joined the Company in 1984. Dr. McDonnell was
Assistant to the Chairman
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from 1984 through 1987 when he was named Vice President of Communications. In
July 1992 he was named Vice President of External Affairs. Prior to joining the
Company, he was the Director of Strategic Planning and Business Administration
for Applied Digital Data Systems, Inc. and Associate Director of the University
Hospital at the State University of New York at Stony Brook. Dr. McDonnell, 46,
holds bachelor of arts and master of arts degrees in philosophy from the State
University of New York at Stony Brook and a doctoral degree in communications
from the University of Southern California.
Leonard P. Novello: Senior Vice President since December 1996, and General
Counsel since he joined the Company in April 1995. Before joining the Company,
Mr. Novello was General Counsel at the international accounting firm of KPMG
Peat Marwick, where he advised senior management on a variety of litigation and
corporate issues and was responsible for all legal matters arising out of the
firm's operations and its audit, tax and management consulting engagements.
Prior to joining Peat Marwick in 1975 as an Associate General Counsel, Mr.
Novello was associated with the New York law firm of Cravath, Swaine and Moore.
Mr. Novello is active in professional associations and is a member of the
Executive Committee of the Litigation Commercial and Federal Section of the New
York State Bar Association and the Association of the Bar of the City of New
York. He is also a member of the Executive Committee of the CPR Institute for
Dispute Resolution. Mr. Novello, 57, has a bachelors degree from the College of
the Holy Cross and a juris doctorate from Fordham University.
Anthony Nozzolillo: Senior Vice President of Finance and Chief Financial Officer
of the Company since February 1994, Mr. Nozzolillo served as the Company's
Treasurer from July 1992 to February 1994. He has been with the Company since
1972 serving in various positions including Manager of Financial Planning and
Manager of Systems Planning. Mr. Nozzolillo, 49, holds a bachelor of science
degree in electrical engineering from the Polytechnic Institute of Brooklyn and
a master of business administration degree from Long Island University, C.W.
Post Campus. Mr. Nozzolillo is chairman of the Community Advisory Board of
Lawrence Public Schools' "School to Career Initiative."
Richard Reichler: Deputy General Counsel and Vice President of Tax Planning and
Services since January 1997. Mr. Reichler held the positions of Deputy General
Counsel and Vice President of Financial Planning and Taxation from January 1995
through December 1996 and Assistant Vice President for Tax and Benefits Planning
from October 1992 through December 1994. Prior to joining the Company, he was a
partner in the international accounting firm of Ernst & Young LLP for 23 years.
Mr. Reichler, 63, holds a bachelor of arts degree from Columbia College and a
bachelor of law degree from Columbia University School of Law. Since 1989, he
has taught various courses at Baruch College, including state and local
taxation, corporate taxation and real estate taxation. He has authored several
publications on tax and employee benefit topics and has served as a member of
the Executive Committee of the Tax Section of the New York State Bar Association
and as an Advisor to the Urban Development Corporation High Technology Advisory
Council.
William G. Schiffmacher: Senior Vice President of Customer Relations and
Information Systems and Technology since December 1996, Mr. Schiffmacher held
the positions of Vice President of Customer Relations from April 1994 through
November 1996 and Vice President of Electric Operations from July 1990 through
March 1994. He joined the Company in 1965 after receiving a bachelor of
electrical engineering degree from Manhattan College. Mr. Schiffmacher, 54, also
holds a master of science degree in management engineering from Long Island
University. He has held a variety of positions in the Company, including Manager
of Electric System Operations,
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Manager of Electrical Engineering and Vice President of Engineering and
Construction.
Werner J. Schweiger: Vice President of Electric Operations since December 1996,
Mr. Schweiger joined the Company in 1981 and has held a number of positions in
Electric Operations, as well as in Engineering. Most recently, he was Manager of
Electric Systems Engineering from October 1995 through November 1996. Mr.
Schweiger, 38, received his bachelors degree in electrical engineering from
Manhattan College and also holds a masters degree in Energy Management from the
New York Institute of Technology.
Richard M. Siegel: Vice President of Information Systems and Technology since
December 1996, Mr. Siegel held the position of Director of Information Systems
and Technology from June 1995 to December 1996. Mr. Siegel, 51, joined the
Company in 1969 as an Associate Engineer and has held progressive management
positions in Electric Operations and Engineering, including Manager of Electric
System Engineering and Manager of Electric System Operations. Mr. Siegel holds a
bachelor of electrical engineering degree from the City College of New York and
a master of science degree in Industrial Management from the State University of
New York at Stony Brook. Mr. Siegel is a Licensed Professional Engineer in the
State of New York.
Robert B. Steger: Senior Vice President of Gas Business Unit since December
1996, Mr. Steger held the positions of Vice President of Electric Operations
from April 1994 through November 1996 and Vice President of Fossil Production
from February 1990 through March 1994. He joined the Company in 1963 and held
progressive operating and engineering positions including Manager of Electric
Production-Fossil from 1985 through 1989. Mr. Steger, 61, holds a bachelor of
mechanical engineering degree from Pratt Institute and is a Licensed
Professional Engineer in the State of New York.
William E. Steiger, Jr.: Vice President of Facilities and Real Estate since
February 1997, Mr. Steiger, 54, held the positions of Vice President of Fossil
Production from April 1994 through February 1997 and Vice President of
Engineering and Construction from July 1990 through March 1994. During his
career with the Company, which began in 1968, he has served, among other
positions, as Lead Nuclear Engineer for Shoreham, Chief Operations Engineer for
Shoreham, Plant Manager for Shoreham as well as Assistant Vice President of
Nuclear Operations. Mr. Steiger, received a bachelor of science degree in marine
engineering from the United States Merchant Marine Academy and a master of
science degree in nuclear engineering from Long Island University.
Edward J. Youngling: Senior Vice President of Engineering & Construction since
February 1997, Mr. Youngling joined the Company in 1968 and has held various
positions in the offices of Fossil Production, Engineering and Nuclear
Operations including service as Department Manager of Nuclear Engineering. In
1988, Mr. Youngling was named Vice President of Conservation and Load
Management. In 1990, he became Vice President of Customer Relations, and from
March 1993 through March 1994, he was Vice President of Customer Relations and
Conservation. In April 1994 he was named Senior Vice President of the Electric
Business Unit. Mr. Youngling, 53, holds a bachelor of science degree in
mechanical engineering from Lehigh University. Mr. Youngling serves on the board
of the Empire State Electric Energy Research Company and is a member of the
Executive Committee of the New York Power Pool. Mr. Youngling also serves on the
Eastern Advisory Board of the Protection Mutual Insurance Company.
27
<PAGE>
CAPITAL REQUIREMENTS, LIQUIDITY AND CAPITAL PROVIDED
Information as to "Capital Requirements," "Liquidity" and "Capital Provided"
appears in Item 7, "Management's Discussion and Analysis of Financial Condition
and Results of Operations."
ITEM 2. PROPERTIES
The location and general character of the principal properties of the Company
are described in Item 1, "Business" under the headings "Electric Operations" and
"Gas Operations."
ITEM 3. LEGAL PROCEEDINGS
SHOREHAM
Pursuant to the LIPA Act, LIPA is required to make payments-in-lieu-of-taxes
(PILOTs) to the municipalities that impose real property taxes on Shoreham.
Pursuant to the 1989 Settlement, the Company agreed to fund LIPA's obligation to
make Shoreham PILOTs. The timing and duration of PILOTs under the LIPA Act were
the subject of litigation entitled LIPA, et al. v. Shoreham-Wading River Central
School District, et al., brought in Nassau County Supreme Court by LIPA against,
among others, Suffolk County, the Town of Brookhaven and the Shoreham-Wading
River Central School District. The Company was permitted to intervene in the
lawsuit. In June 1996, the New York State Court of Appeals rendered its opinion
on the cross-appeals filed by the parties regarding the timing, duration and
refundability of PILOTs under the LIPA Act. The Court affirmed portions of a
prior ruling by the Appellate Division, Second Department by holding that (a)
LIPA's PILOT obligation is perpetual, (b) PILOTs, like taxes, are subject to
refund if the assessment upon which the PILOTs were based is determined to be
excessive, and (c) PILOTs phase down by ten percent of the prior year's amount,
rather than ten percent of the first PILOT year amount, until PILOTs reach a
level that equals the taxes that would have been levied on the plant in a
non-operative state. Additionally, the Court modified the Appellate Division's
ruling by finding that PILOTs commence, not at the time the Company transferred
Shoreham to LIPA in February 1992, but rather on December 1, 1992, the beginning
of the next tax year.
Unless otherwise agreed by the parties, the proper assessment of Shoreham for
purposes of determining the proper amount of PILOTs is to be determined in a
proceeding challenging the Shoreham assessment for the 1992-93 tax year. If that
determination results in PILOTs that are less than the amount of PILOTs that
have already been paid, LIPA, and therefore the Company, should be entitled to
refunds of excessive PILOTs already made.
The costs of Shoreham included real property taxes imposed by, among others, the
Town of Brookhaven, and were capitalized by the Company during construction. The
Company sought judicial review in New York Supreme Court, Suffolk County (Long
Island Lighting Company v. The Assessor of the Town of Brookhaven, et al.) of
the assessments upon which those taxes were based for the years 1976 through
1992 (excluding 1979 which had been settled). The Supreme Court consolidated the
review of the tax years at issue into two phases: 1976 through 1983 (Phase I);
and 1984 through 1992 (Phase II). In January 1996, the Company received
approximately $81 million, including interest, from Suffolk County pursuant to
ruling by the Supreme Court, upheld on appeal, that found that Shoreham had been
overvalued for real property tax purposes in Phase I.
28
<PAGE>
In November 1996, the Supreme Court ruled that Shoreham had also been
over-assessed for real property tax purposes for Phase II. A judgment was
entered on March 26, 1997 in the amount of $868,478,912 which includes interest
to November 4, 1996. Suffolk County, the Town of Brookhaven and the Shoreham
Wading-River Central School District have appealed the judgment to the Appellate
Division, Second Department. All briefs have been filed and oral argument
occurred on May 6, 1998. The Court reserved decision. If the assessment for the
1991-92 tax year is used to determine the proper amount of PILOTs this ruling
should also result in a refund of approximately $260 million plus interest for
PILOTs for the years 1992-1996.
The refund of any real property taxes, PILOTs, and interest thereon, net of
litigation costs, will be used to reduce electric rates in the future. However,
the court's ruling is subject to appeal and, as a result, the Company is unable
to determine the amount and timing of any additional real property tax and PILOT
refunds.
ENVIRONMENTAL
In February 1994, a lawsuit was filed in the United States District Court for
the Eastern District of New York by the Town of Oyster Bay (Town), against the
Company and nine other PRPs. The Town is seeking indemnification for remediation
and investigation costs that have been or will be incurred for a federal
Superfund site in Syosset, New York, which served as a Town-owned and operated
landfill between 1933 and 1975. In a Record of Decision issued in September
1990, the EPA set forth a remedial design plan, the cost of which was estimated
at $27 million and is reflected in the Town's lawsuit. In an Administrative
Consent Decree entered into between the EPA and the Town in December 1990, the
Town agreed to undertake remediation at the site. The Company is participating
in a joint PRP defense effort with several other defendants. Liability, if
imposed, would be joint and several. An agreement in principal has been reached
between the Company, certain other defendants, the State of New York and the
Town; any settlement is subject to court approval and if approved would not have
a material adverse effect on its financial position, cash flows or results of
operations.
In March 1996, the Village of Asharoken filed a lawsuit against the Company in
the New York Supreme Court, Suffolk County (Incorporated Village of Asharoken,
New York, et al. v. Long Island Lighting Company). The Village is seeking
monetary damages and injunctive relief based upon theories of negligence, gross
negligence and nuisance in connection with the Company's design and construction
of the Northport Power Plant which the Village alleges upset the littoral drift,
thereby causing beach erosion. In November 1996, the Court decided the Company's
motion to dismiss the lawsuit, dismissing two of the three causes of action. The
Court limited monetary damages on the surviving continuous nuisance claim to
three years prior to the commencement of the action. The Company's liability, if
any, resulting from this proceeding cannot yet be determined. However, the
Company does not believe that this proceeding will have a material adverse
effect on its financial position, cash flows or results of operations.
In June 1996, a lawsuit was commenced against the Company in the New York
Supreme Court, Suffolk County (Town of Riverhead, et al. v. Long Island Lighting
Company), in which the plaintiffs seek monetary damages and injunctive relief
based upon theories of nuisance, breach of contract, and breach of the Public
Trust in connection with the Company's construction of the Shoreham Nuclear
Power Station and the Company's diversion and maintenance of the Wading River
Creek. The plaintiffs allege that the diversion of the Wading River Creek and
the construction of the Shoreham Nuclear Power Station have caused negative
environmental impacts on surrounding areas. The plaintiffs also allege that the
Company has contractual obligations to
29
<PAGE>
perform annual maintenance dredging of the Wading River Creek and beach
replenishment of certain beach front property. In September 1996, the Company
filed a motion to dismiss the complaint on numerous grounds. In January 1997,
the plaintiffs cross-moved for an order seeking partial summary judgment. The
Court issued an Order dated August 26, 1997 which denied both motions except
that it dismissed Plaintiffs' cause of action alleging violation of the Public
Trust Doctrine and prohibited the Town of Riverhead from suing in its sovereign
capacity. The parties have filed notices of intent to appeal this order and
discovery has commenced. The Company's liability, if any, resulting from this
proceeding cannot yet be determined. However, the Company does not believe that
this proceeding will have a material adverse effect on its financial position,
cash flows or results of operations.
HUMAN RESOURCES
Pending before federal and state courts, the federal Equal Employment
Opportunity Commission and the New York State Division of Human Rights are
charges by several individuals alleging, in separate actions, that the Company
discriminated against them, or that they were the subject of harassment, on
various grounds. The Company has estimated that any costs to the Company
resulting from these matters will not have a material adverse effect on its
financial position, cash flows or results of operations.
In May 1995, eight participants of the Company's Retirement Income Plan (RIP)
filed a lawsuit against the Company, the RIP and Robert X. Kelleher, the Plan
Administrator, in the United States District Court for the Eastern District of
New York (Becher, et al. v. Long Island Lighting Company, et al.). In January
1996, the Court ordered that this action be maintained as a class action. This
proceeding arose in connection with the plaintiffs' withdrawal, approximately 25
years ago, of contributions made to the RIP, thereby resulting in a reduction of
their pension benefits. The plaintiffs are now seeking, among other things, to
have these reduced benefits restored to their pension accounts. The Company's
liability, if any, resulting from this proceeding cannot yet be determined. In
November 1997, the Company filed a motion for partial summary judgment with the
District Court. On April 28, 1998, the Court denied the Company's motion and
permitted the Company to file a further motion for partial summary judgement on
additional grounds. The Company maintains that the plaintiff's claims
are without merit and intends to defend against said claims.
OTHER MATTERS
A discussion of legal proceedings related to competitive issues facing the
Company appears in Note 12 of Notes to Financial Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
30
<PAGE>
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters At March 31, 1998, the Company had 78,314 registered holders of record
of common stock.
The common stock of the Company is traded on the New York Stock Exchange and the
Pacific Stock Exchange. Certain of the Company's preferred stock series are
traded on the New York Stock Exchange.
The high and low market prices of the Company's common stock and dividends per
common share for 1996, 1997 and the first quarter of calendar 1998 are set forth
on the table below.
<TABLE>
<CAPTION>
- ----------------------------------------------------- ------------------------------------------------------------------
Fiscal Year Ended March 31, 1998
------------------------------------------------------------------
3 Months Ended 3/31/97 6/30/97 9/30/97 12/31/97 3/31/98
- ------------------------------------- --------------- ----------------- --------------- --------------- ----------------
<S> <C> <C> <C> <C> <C>
Market price of common stock
High 24 1/2 24 1/8 26 30 1/2 31 5/8
Low 21 3/4 22 22 3/4 24 1/8 27 15/16
Dividends per common share .445 .445 .445 .445 .445
- -------------------------------------- -------------- ----------------- -------------- ----------------- --------------
- ----------------------------------------------------- ----------------------------------------------------------------
Calendar Year Ended December 31, 1996
----------------------------------------------------------------
3 Months Ended 3/31/96 6/30/96 9/30/96 12/31/96
- ------------------------------------- --------------- --------------- ---------------- --------------- ---------------
Market price of common stock
High 18 1/8 17 7/8 17 3/4 22 3/8
Low 15 7/8 16 1/8 16 5/8 17 1/8
Dividends per common share .445 .445 .445 .445
- -------------------------------------- -------------- --------------- ---------------- --------------- ---------------
</TABLE>
31
<PAGE>
<TABLE>
<CAPTION>
ITEM 6. SELECTED FINANCIAL DATA (In thousands of dollars except per share amounts)
- ------------------------------------------------------------------------------------------------------------------------------------
March 31 March 31 December 31 December 31
For the year ended 1998 1997 1996 1995
- ------------------------------------------------------------------------------------------------------------------------------------
REVENUES
<S> <C> <C> <C> <C>
Electric $ 2,478,435 $ 2,464,957 2,466,435 $ 2,484,014
Gas 645,659 672,705 684,260 591,114
- ------------------------------------------------------------------------------------------------------------------------------------
Total Revenues 3,124,094 3,137,662 3,150,695 3,075,128
- ------------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operations - fuel and purchased power 957,807 954,848 963,251 834,979
Operations - other 400,045 372,880 381,076 383,238
Maintenance 111,120 116,988 118,135 128,155
Depreciation and amortization 158,537 154,921 153,925 145,357
Base financial component amortization 100,971 100,971 100,971 100,971
Rate moderation component amortization (35,079) (2,999) (24,232) 21,933
Regulatory liability component amortization (79,359) (79,359) (79,359) (79,359)
1989 Settlement credits amortization (9,213) (9,213) (9,214) (9,214)
Other regulatory amortization 47,272 112,294 127,288 161,605
Operating taxes 466,326 469,561 472,076 447,507
Federal income tax - current 86,388 52,737 42,197 14,596
Federal income tax - deferred and other 150,983 157,873 168,000 193,742
- ------------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 2,355,798 2,401,502 2,414,114 2,343,510
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Income 768,296 736,160 736,581 731,618
- ------------------------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND (DEDUCTIONS)
Rate moderation component carrying charges 23,632 25,279 25,259 25,274
Other income and deductions, net (18,156) 13,921 19,197 34,400
Class Settlement (15,623) (19,895) (20,772) (21,669)
Allowance for other funds used during construction 3,846 2,886 2,888 2,898
Federal income tax - current 594 -- -- --
Federal income tax - deferred and other 4,124 (723) 940 2,800
- ------------------------------------------------------------------------------------------------------------------------------------
Total Other Income and (Deductions) (1,583) 21,468 27,512 43,703
- ------------------------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges 766,713 757,628 764,093 775,321
- ------------------------------------------------------------------------------------------------------------------------------------
INTEREST CHARGES
Interest on long-term debt 351,261 372,108 384,198 412,512
Other interest 57,805 66,818 67,130 63,461
Allowance for borrowed funds used during construction (4,593) (3,707) (3,699) (3,938)
- ------------------------------------------------------------------------------------------------------------------------------------
Total Interest Charges 404,473 435,219 447,629 472,035
- ------------------------------------------------------------------------------------------------------------------------------------
NET INCOME 362,240 322,409 316,464 303,286
Preferred stock dividend requirements 51,813 52,113 52,216 52,620
- ------------------------------------------------------------------------------------------------------------------------------------
EARNINGS FOR COMMON STOCK $ 310,427 $ 270,296 264,248 $ 250,666
====================================================================================================================================
AVERAGE COMMON SHARES OUTSTANDING (000) 121,415 $ 120,620 120,360 119,195
- ------------------------------------------------------------------------------------------------------------------------------------
BASIC AND DILUTED EARNINGS PER COMMON SHARE $ 2.56 2.24 2.20 $ 2.10
====================================================================================================================================
Common stock dividends declared per share $ 1.78 1.78 1.78 $ 1.78
Common stock dividends paid per share $ 1.78 1.78 1.78 $ 1.78
Book value per common share at $ 21.88 21.07 20.89 $ 20.50
Common shares outstanding at (000) 121,681 120,987 120,781 119,655
Common shareowners of record at 78,314 77,691 86,607 93,088
====================================================================================================================================
TOTAL ASSETS $ 11,900,725 $ 11,849,574 12,209,679 $ 12,527,597
LONG-TERM DEBT $ 4,381,949 $ 4,457,047 4,456,772 $ 4,706,600
PREFERRED STOCK - REDEMPTION REQUIRED $ 562,600 $ 638,500 638,500 $ 639,550
PREFERRED STOCK - NO REDEMPTION REQUIRED $ -- $ 63,598 63,664 $ 63,934
COMMON SHAREOWNERS' EQUITY $ 2,662,447 $ 2,549,049 2,523,369 $ 2,452,953
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA (In thousands of dollars except per share amounts)
- -------------------------------------------------------------------------------------------------
December 31 December 31
For the year ended 1994 1993
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
REVENUES
Electric $ 2,481,637 $ 2,352,109
Gas 585,670 528,886
- ------------------------------------------------------------------------------------------------
Total Revenues 3,067,307 2,880,995
- ------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operations - fuel and purchased power 847,986 827,591
Operations - other 406,014 387,808
Maintenance 134,640 133,852
Depreciation and amortization 130,664 122,471
Base financial component amortization 100,971 100,971
Rate moderation component amortization 197,656 88,667
Regulatory liability component amortization (79,359) (79,359)
1989 Settlement credits amortization (9,214) (9,214)
Other regulatory amortization 4,328 (18,044)
Operating taxes 406,895 385,847
Federal income tax - current 10,784 6,324
Federal income tax - deferred and other 170,997 178,530
- ------------------------------------------------------------------------------------------------
Total Operating Expenses 2,322,362 2,125,444
- ------------------------------------------------------------------------------------------------
Operating Income 744,945 755,551
- ------------------------------------------------------------------------------------------------
OTHER INCOME AND (DEDUCTIONS)
Rate moderation component carrying charges 32,321 40,004
Other income and deductions, net 35,343 38,997
Class Settlement (22,730) (23,178)
Allowance for other funds used during construction 2,716 2,473
Federal income tax - current -- --
Federal income tax - deferred and other 5,069 12,578
- ------------------------------------------------------------------------------------------------
Total Other Income and (Deductions) 52,719 70,874
- ------------------------------------------------------------------------------------------------
Income Before Interest Charges 797,664 826,425
- ------------------------------------------------------------------------------------------------
INTEREST CHARGES
Interest on long-term debt 437,751 466,538
Other interest 62,345 67,534
Allowance for borrowed funds used during construction (4,284) (4,210)
- ------------------------------------------------------------------------------------------------
Total Interest Charges 495,812 529,862
- ------------------------------------------------------------------------------------------------
NET INCOME 301,852 296,563
Preferred stock dividend requirements 53,020 56,108
- ------------------------------------------------------------------------------------------------
EARNINGS FOR COMMON STOCK $ 248,832 $ 240,455
================================================================================================
AVERAGE COMMON SHARES OUTSTANDING (000) 115,880 112,057
- ------------------------------------------------------------------------------------------------
BASIC AND DILUTED EARNINGS PER COMMON SHARE $ 2.15 $ 2.15
================================================================================================
Common stock dividends declared per share $ 1.78 $ 1.76
Common stock dividends paid per share $ 1.78 $ 1.75
Book value per common share at $ 20.21 $ 19.88
Common shares outstanding at (000) 118,417 112,332
Common shareowners of record at 96,491 94,877
=================================================================================================
TOTAL ASSETS $ 12,479,289 $ 12,453,771
LONG-TERM DEBT $ 5,145,397 $ 4,870,340
PREFERRED STOCK - REDEMPTION REQUIRED $ 644,350 $ 649,150
PREFERRED STOCK - NO REDEMPTION REQUIRED $ 63,957 $ 64,038
COMMON SHAREOWNERS' EQUITY $ 2,393,628 $ 2,232,950
</TABLE>
32
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
On April 11, 1997, the Company changed its year end from December 31 to March
31. Accordingly, unless otherwise indicated, references to 1998 and 1997
represent the twelve month periods ended March 31, 1998 and March 31, 1997,
respectively, while references to all other periods refer to the respective
calendar years ended December 31.
Effects of LIPA and KeySpan Transactions on Future Operations
The future operations and financial position of the Company will be
significantly affected by each of the proposed transactions with LIPA and
KeySpan described below. The discussion contained in this management's
discussion and analysis of financial condition and results of operations does
not reflect, unless otherwise indicated, the potential effects of the
transactions with LIPA and KeySpan.
RESULTS OF OPERATIONS
EARNINGS
Earnings for the years ended March 31, 1998 and March 31, 1997 were as follows:
(In millions of dollars and shares except earnings per share)
- --------------------------------------------------------------- -------------
1998 1997
- --------------------------------------------------------------- -------------
Net income $362.2 $322.4
Preferred stock dividend requirements 51.8 52.1
=============================================================== =============
Earnings for common stock $310.4 $270.3
=============================================================== =============
Average common shares outstanding 121.4 120.6
=============================================================== =============
Basic and diluted earnings per common share $ 2.56 $ 2.24
=============================================================== =============
For the year ended March 31, 1998 the Company had higher earnings in the
electric business partially offset by lower earnings in the gas business
compared to the year ended March 31, 1997.
In the electric business, the increase in earnings for the year ended March 31,
1998, was primarily due to a change in the method of amortizing the Rate
Moderation Component (RMC) to eliminate the effects of seasonality on monthly
operating income, as more fully discussed in the section titled "Rate Moderation
Component." This positive contributor to earnings more than offset the effects
of lower short-term interest income and the accruals for certain obligations for
key employees , as more fully discussed in Note 8 of Notes to Financial
Statements.
The decrease in earnings in the gas business for the year ended March 31, 1998
resulted from lower short-term interest income and the accruals, noted above,
partially offset by lower operations and maintenance expenses.
Earnings for the years ended December 31, 1996 and December 31, 1995 were as
follows: (In millions of dollars and shares except earnings per share)
- --------------------------------------------- -------------- ---------------
1996 1995
- --------------------------------------------- -------------- ---------------
Net income $316.5 $303.3
Preferred stock dividend requirements 52.2 52.6
============================================= ============== ===============
Earnings for common stock $264.3 $250.7
============================================= ============== ===============
Average common shares outstanding 120.4 119.2
============================================= ============== ===============
Basic and diluted earnings per common share $ 2.20 $ 2.10
============================================= ============== ===============
33
<PAGE>
The Company's 1996 earnings were higher for both its electric and gas businesses
as compared to 1995. While the Company's allowed rate of return in 1996 was the
same as 1995, the higher earnings for the electric business were the result of
the Company's increased investment in electric plant in 1996, as compared to
1995. Also contributing to the increase in electric business earnings were the
Company's continued efforts to reduce operations and maintenance expenses and
the efficient use of cash generated by operations to retire maturing debt.
The increase in earnings in the gas business was the result of additional
revenues due to the continued growth in the number of gas space heating
customers. Also contributing to the increase in gas business earnings was a 3.2%
rate increase which became effective December 1, 1995, and an increase in
off-system gas sales.
REVENUES
Electric Revenues
The table below provides a summary of the Company's electric revenues, sales and
customers.
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
Years Ended March 31, Years Ended December 31,
- -------------------------------------------------------------------------------------------------------------------
REVENUES (000) 1998 1997 1996 1995
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Residential $1,206,640 $1,199,976 $1,205,133 $1,204,987
Commercial and industrial 1,194,725 1,178,471 1,174,499 1,194,014
Other system revenues 47,832 50,499 50,513 52,472
- -------------------------------------------------------------------------------------------------------------------
Total system revenues 2,449,197 2,428,946 2,430,145 2,451,473
Other revenues 29,238 36,011 36,290 32,541
================================================================================================-------------------
Total Revenues $2,478,435 $2,464,957 $2,466,435 $2,484,014
================================================================================================-------------------
SALES - MILLIONS OF KWH
Residential 7,170 7,121 7,203 7,156
Commercial and industrial 8,375 8,209 8,242 8,336
Other system sales 415 437 441 460
================================================================================================-------------------
Total system sales 15,960 15,767 15,886 15,952
================================================================================================-------------------
CUSTOMERS - MONTHLY AVERAGE
Residential 928,580 922,330 920,930 915,162
Commercial and industrial 105,795 104,703 104,488 103,669
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
Years Ended March 31, 1998 and 1997
The Company's electric revenues fluctuate mainly as a result of system growth,
variations in weather and fuel costs, as electric base rates have remained
unchanged since December 1993. However, these variations have no impact on
earnings due to the current electric rate structure which includes a revenue
reconciliation mechanism to eliminate the impact on earnings caused by sales
volumes that are above or below adjudicated levels. The slight increase in
revenues for the year ended March 31, 1998, when compared to the year ended
March 31, 1997, was primarily due to higher system sales volumes resulting in
part from the addition of approximately 8,000 new electric customers and higher
fuel expense recoveries, partially offset by lower sales to other utilities.
Years Ended December 31, 1996 and 1995
The Company experienced a growth in electric system sales in 1996 on a
weather-normalized basis compared to 1995. This growth is primarily attributable
to the addition of new electric customers.
34
<PAGE>
For a further discussion on electric rates, see Note 4 of Notes to Financial
Statements.
Gas Revenues
The table below provides a summary of the Company's gas revenues, sales and
customers.
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------------------
Years Ended March 31, Years Ended December 31,
- ---------------------------------------------------------------------------------------------------------------------------
REVENUES (000) 1998 1997 1996 1995
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Residential $390,990 $396,143 $414,749 $365,775
Commercial and industrial 145,861 163,824 181,356 165,257
- ---------------------------------------------------------------------------------------------------------------------------
Total firm revenues 536,851 559,967 596,105 531,032
Interruptible revenues 37,565 42,584 37,927 32,837
- ---------------------------------------------------------------------------------------------------------------------------
Total system revenues 574,416 602,551 634,032 563,869
Other revenues 71,243 70,154 50,228 27,245
===========================================================================================================================
Total Revenues $645,659 $672,705 $684,260 $591,114
===========================================================================================================================
SALES - THOUSANDS OF DTH
Residential 37,417 39,286 40,850 38,265
Commercial and industrial 17,168 19,341 21,054 20,439
- ---------------------------------------------------------------------------------------------------------------------------
Total firm sales 54,585 58,627 61,904 58,704
Interruptible sales 9,130 8,399 7,869 9,176
Off-system sales 10,372 10,036 7,457 7,743
- ---------------------------------------------------------------------------------------------------------------------------
Total Sales 74,087 77,062 77,230 75,623
========================================================================================================-------------------
CUSTOMERS - MONTHLY AVERAGE
Residential 415,369 411,734 410,922 407,566
Commercial and industrial 44,917 45,684 45,887 45,340
- ---------------------------------------------------------------------------------------------------------------------------
Total firm customers 460,286 457,418 456,809 452,906
Interruptible customers 688 659 651 623
Firm transportation customers 3,589 833 349 -
- ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
Years Ended March 31, 1998 and 1997
Despite an increase of approximately 5,600 gas space heating customers, gas
revenues decreased primarily as a result of lower sales volumes due to warmer
weather experienced during the year ended March 31, 1998 when compared to the
year ended March 31, 1997.
In 1998 and 1997, other gas revenues totaled $71 million and $70 million,
respectively. Included in other gas revenues is off-system gas sales which
totaled $34 million and $43 million, for 1998 and 1997, respectively. Profits
generated from off-system gas sales are allocated 85% to firm gas customers and
15% to the shareowners, in accordance with PSC mandates. Off-system gas sales
decreased as the demand for natural gas declined as a direct result of the
warmer weather experienced in this region during this period.
Years Ended December 31, 1996 and 1995
The increase in 1996 gas revenues when compared to 1995 is attributable to a
3.2% gas rate increase which became effective on December 1, 1995, higher sales
volumes, an increase in gas fuel expense recoveries driven by higher sales
volumes, and revenues generated through non-traditional services, including
off-system gas sales. The recovery of gas fuel expenses in 1996 when compared to
1995 increased approximately $31 million as a result of higher average gas
prices and increased per customer usage due to colder weather than experienced
in the prior year. In 1996 and 1995, other gas
35
<PAGE>
revenues totaled $50 million and $27 million, respectively. Included in other
gas revenues is off-system gas sales which totaled $37 million and $24 million
for 1996 and 1995, respectively.
OPERATING EXPENSES
Fuel and Purchased Power
Electric System
Fuel and purchased power expenses for the years ended March 31, 1998 and 1997,
and for the years ended December 31, 1996 and 1995 were as follows:
<TABLE>
<CAPTION>
(In millions of dollars)
- -------------------------------------------------- ------------------------------- -----------------------------------
Years Ended Years Ended
March 31, December 31,
--------- ------------
1998 1997 1996 1995
- -------------------------------------------------- --------------- --------------- --------------- -------------------
Fuel for Electric Operations
<S> <C> <C> <C> <C>
Oil $123 $128 $158 $ 98
Gas 197 170 138 149
Nuclear 15 15 15 14
Purchased power 324 333 329 310
================================================== =============== =============== =============== ===================
Total $659 $646 $640 $571
================================================== =============== =============== =============== ===================
</TABLE>
Variations in fuel and purchased power costs have no impact on operating results
as the Company's current electric rate structure includes a mechanism that
provides for the recovery of fuel costs which are greater than the costs
collected in base rates. If the actual fuel costs are less than the amounts
included in base rates, the difference is credited to the RMC balance.
Electric fuel and purchased power mix for the years ended March 31, 1998 and
1997, and years ended December 31, 1996 and 1995 were as follows:
<TABLE>
<CAPTION>
(In thousands of MWh)
- ---------------------------------------------------------------------------------------------------------------
Years Ended Years Ended
March 31, December 31,
--------- ------------
1998 1997 1996 1995
- ---------------------------------------------------------------------------------------------------------------
MWh % MWh % MWh % MWh %
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Oil 3,434 20% 3,278 19% 4,219 24% 3,099 17%
Gas 6,212 35% 5,469 31% 4,542 25% 6,344 36%
Nuclear 1,545 9% 1,553 9% 1,558 9% 1,301 7%
Purchased power 6,412 36% 7,261 41% 7,388 42% 7,143 40%
- ---------------------------------------------------------------------------------------------------------------
Total 17,603 100% 17,561 100% 17,707 100% 17,887 100%
===============================================================================================================
</TABLE>
In May 1997, the Company completed the second of two planned conversions of
oil-fired steam generating units at its Port Jefferson Power Station to dual
firing units, bringing the total number of steam units capable of burning
natural gas to nine. As a result, seven of the Company's nine steam generating
units are currently dual-fired, providing the Company with the ability to burn
the most cost-efficient fuel available, consistent with seasonal environmental
requirements.
Years Ended March 31, 1998 and 1997
Electric fuel costs increased as a result of higher system sales volumes. During
1998, the price per kWh of power purchased increased over 1997. As a result, the
Company changed the mix of generation and purchased power in 1998 when compared
to 1997 by generating more electricity using gas and oil rather than purchasing
the equivalent energy from off-system.
36
<PAGE>
Years Ended December 31, 1996 and 1995
As a result of a sharp increase in the cost of natural gas in 1996, generation
with oil became more economical than generation with gas. The total barrels of
oil consumed for electric operations were 7.1 million and 5.2 million for the
years 1996 and 1995, respectively.
Gas System
Variations in gas fuel costs have no impact on operating results as the
Company's current gas rate structure includes a fuel adjustment clause whereby
variations between actual fuel costs and fuel costs included in base rates are
deferred and subsequently returned to or collected from customers. Effective
February 5, 1998, in accordance with the Stipulation, discussed in Note 3 of
Notes to Financial Statements, total gas fuel costs are recovered through the
gas fuel adjustment clause.
Years Ended March 31, 1998 and 1997
Gas system fuel expense totaled $299 million and $309 million for the years
ended March 31, 1998 and 1997, respectively. The decrease is due to lower firm
sales volumes and lower off-system gas sales resulting from warmer weather
experienced in this region during this period.
Years Ended December 31, 1996 and 1995
For the years ended December 31, 1996 and 1995, gas system fuel expense totaled
$323 million and $264 million, respectively. The increase of $59 million was due
to higher firm sales volumes, an increase in the Company's average price of gas
and higher off-system gas sales.
Operations and Maintenance Expenses
Years Ended March 31, 1998 and 1997
Operations and Maintenance (O&M) expenses, excluding fuel and purchased power,
were $511 million and $490 million, for the years ended March 31, 1998 and 1997,
respectively. This increase in O&M was primarily due to the recognition of
higher performance-based employee incentives and certain other charges for
empoloyee benefits related to the KeySpan/LILCO merger.
Years Ended December 31, 1996 and 1995
O&M expenses, excluding fuel and purchased power, were $499 million and $511
million, for the years ended December 31, 1996 and 1995, respectively. This
decrease in O&M was primarily due to the Company's cost containment program
which resulted in lower plant maintenance expenses, lower distribution expenses
and lower administrative and general expenses.
Rate Moderation Component
The Rate Moderation Component (RMC) represents the difference between the
Company's revenue requirements under conventional ratemaking and the revenues
provided by its electric rate structure. In addition, the RMC is also adjusted
for the operation of the Company's Fuel Moderation Component (FMC) mechanism and
the difference between the Company's share of actual operating costs at Nine
Mile Point Nuclear Power Station, Unit 2 (NMP2) and amounts provided for in
electric rates.
37
<PAGE>
In April 1998, the PSC authorized a revision to the Company's method for
recording its monthly RMC amortization. Prior to this revision, the amortization
of the annual level of RMC was recorded monthly on a straight-line, levelized
basis over the Company's rate year which runs from December 1 to November 30.
However, revenue requirements fluctuate from month to month based upon
consumption, which is greatly impacted by the effects of weather. Under this
revised method, effective December 1, 1997, the monthly amortization of the
annual RMC level varies based upon each month's forecasted revenue requirements,
which more closely aligns such amortization with the Company's cost of service.
As a result of this change, for the fiscal year ended March 31, 1998, the
Company recorded approximately $65.1 million more of non-cash RMC credits to
income (representing accretion of the RMC balance), or $42.5 million net of tax,
representing $.35 per share than it would have under the previous method.
However, the total RMC amortization for the rate year ended November 30, 1998,
will be equal to the amount that would have been provided for under the previous
method.
The Company continues to believe that the full amortization and recovery of the
RMC balance, which at March 31, 1998, was approximately $434 million, will take
place within the time frame established by the Rate Moderation Agreement (RMA),
in accordance with the rate plans submitted to the Public Service Commission of
the State of New York (PSC) for the single rate year 1997 and the three year
rate period 1997 through 1999. In December 1997, the Company received PSC
approval to continue the RMC mechanism and the LILCO Ratemaking and Performance
Plan (LRPP) ratemaking mechanisms and incentives for the electric rate year
ending November 30, 1997. In the event that the LIPA Transaction is not
consummated, the Company expects that the PSC will issue an order providing for,
among other things, the continuing recovery, through rates, of the RMC balance,
one of the Shoreham-related regulatory assets. If such an electric rate order is
not obtained or does not provide for the continuing recovery of the RMC balance,
the Company may be required to write-off the amount not expected to be provided
for in rates. For a further discussion of the LIPA Transaction, see Note 2 of
Notes to Financial Statements.
Years Ended March 31, 1998 and 1997
For the years ended March 31, 1998 and March 31, 1997, the Company recorded
non-cash credits to income of approximately $52 million and $30 million,
respectively, representing the amount by which revenue requirements exceeded
revenues provided for under the current electric rate structure. Partially
offsetting these accretions were the effects of the FMC mechanism and the
differences between actual and adjudicated operating costs for NMP2, as
discussed above. The adjustments to the accretion of the RMC totaled $17 million
and $27 million, respectively, of which $12 million and $23 million,
respectively, were derived from the operation of the FMC mechanism.
Years Ended December 31, 1996 and 1995
For the year ended December 31, 1996, the Company recorded a non-cash credit to
income of approximately $50 million, representing the amount by which revenue
requirements exceeded revenues provided for under the current electric rate
structure. Partially offsetting this accretion were the effects of the FMC
mechanism and the differences between actual and adjudicated operating costs for
NMP2. The adjustments to the accretion of the RMC totaled $26 million, of which
$24 million was derived from the operation of the FMC mechanism.
38
<PAGE>
For the year ended December 31, 1995, the Company recorded a non-cash charge to
income of approximately $22 million, after giving effect to the credits
generated principally by the operation of the FMC mechanism. FMC credits for
1995 totaled approximately $87 million.
For a further discussion of the RMC, see Note 4 of Notes to Financial
Statements.
Other Regulatory Amortization
The significant components of other regulatory amortization are the following:
<TABLE>
<CAPTION>
(In millions of dollars)
- ----------------------------------------- -------------------------------------------------------------------------
(Income)Expense
- ----------------------------------------- -------------------------------------------------------------------------
Years Ended Years Ended
March 31 December 31
- ----------------------------------------- ------------- --------------- ------------ --------------- --------------
1998 1997 1996 1995
- ----------------------------------------- ------------- --------------- ------------ --------------- --------------
<S> <C> <C> <C> <C>
Net Margin $ 2 $ (5) $ 3 $ 64
LRPP Amortization - 42 59 53
Excess Earnings - Electric (3) 21 10 3
Excess Earnings - Gas 10 10 10 1
Shoreham Post Settlement Costs 31 30 29 27
Other 7 14 16 14
========================================= ============= =============== ============ =============== ==============
$47 $112 $127 $162
========================================= ============= =============== ============ =============== ==============
</TABLE>
Net Margin- An electric business unit revenue reconciliation mechanism,
established under the LRPP, which eliminates the impact on earnings of
experiencing sales that are above or below adjudicated levels by providing a
fixed annual net margin level (defined as sales revenue, net of fuel and gross
receipts taxes). Variations in electric revenue resulting from differences
between actual and adjudicated net margin sales levels are deferred on a monthly
basis during the rate year through a charge or credit to other regulatory
amortization. These deferrals are then refunded to or recovered from ratepayers
as explained below under "LRPP Amortization."
LRPP Amortization- As established under the LRPP, deferred balances resulting
from the net margin, electric property tax expense reconciliation, earned
performance incentives, and associated carrying charges are accumulated during
each rate year. The first $15 million of the total deferral is recovered from or
credited to electric ratepayers by increasing or decreasing the RMC balance.
Amounts deferred in excess of $15 million, upon approval by the PSC, are
refunded to or recovered from ratepayers through the Fuel Cost Adjustment (FCA)
mechanism over a subsequent 12-month period, with the offset being recorded in
other regulatory amortization.
For the rate years ended November 30, 1997 and 1996, the total amount deferred
under the LRPP was $4.0 and $15.0 million, respectively. Such amounts were
credited against the RMC balance.
Years Ended March 31, 1998 and 1997
For the year ended March 31, 1998, there was no LRPP amortization, as the
Company has not yet received approval from the PSC to begin refunding $26
million of the remaining deferred LRPP balance in excess of $15 million for the
rate year ended November 30, 1995. For the year ended March 31, 1997, the
Company recognized $42.4 million of non-cash charges to income representing the
amortization of the deferred LRPP balance related to the rate year ended
November 30, 1994.
39
<PAGE>
Years Ended December 31, 1996 and 1995
For the year ended December 31, 1996, the Company recognized $58.7 million of
non-cash charges to income representing the amortization of the deferred LRPP
balance related to the rate year ended November 30, 1994.
For the year ended December 31, 1995, the Company recognized $52.9 million of
non-cash charges to income representing the amortization of the deferred LRPP
balance related to the rate year ended November 30, 1993.
For a further discussion of the LRPP, see Note 4 of Notes to Financial
Statements.
Excess Earnings - Also recorded in other regulatory amortization, if applicable,
are non-cash charges representing: (a) 100% of electric earnings generated by
the Company in excess of amounts provided for in electric rates, which is
returned to the electric customer through a reduction to the RMC balance; and
(b) 50% of the gas earnings generated by the Company in excess of amounts
provided for in gas rates, which will be returned to the firm gas customer.
Effective February 5, 1998, the Company, in accordance with the Stipulation
discussed in Note 3 of Notes to Financial Statements, established a gas
balancing account in order to defer excess gas earnings for future disposition.
For the rate year ended November 30, 1997, the electric business earned $4.8
million in excess of its allowed return on common equity and the firm gas
customers' portion of the gas business earnings was $6.3 million.
Shoreham Post Settlement Costs - Represents the amortization of Shoreham
decommissioning costs, fuel disposal costs, payments-in-lieu-of-taxes, carrying
charges and other costs over a forty-year period on a straight line remaining
life basis.
Years Ended March 31, 1998 and 1997
Other regulatory amortization was a non-cash charge to income of $47 million and
$112 million for the years ended March 31, 1998 and 1997, respectively. For the
year ended March 31, 1997, the Company recognized approximately $42 million of
charges representing the amortization of the deferred LRPP balance associated
with the rate year ended November 30, 1994. For the year ended March 31, 1998,
there was no LRPP amortization, as the Company has not yet received approval
from the PSC to begin refunding $26 million of the remaining deferred LRPP
balance in excess of $15 million for the rate year ended November 30, 1995. Also
contributing to the decrease in other regulatory amortization was the timing of
the recognition of electric excess earnings for the rate years ended November
30, 1997 and 1996.
Years Ended December 31, 1996 and 1995
Other regulatory amortization was a non-cash charge to income of $127 and $162
for the years ended December 31, 1996 and 1995, respectively. This decrease is
primarily attributable to the operation of the net margin, discussed above. For
the year ended December 31, 1995, the amount deferred related to the net margin
amounted to $64 million compared to $3 million for the year ended December 31,
1996.
40
<PAGE>
Operating Taxes
Operating taxes were $466 million and $470 million for the years ended March 31,
1998 and 1997, respectively. The decrease in 1998 is primarily attributable to
the expiration of the Corporate Tax Surcharge and lower gross receipts taxes
related to lower gas revenues. For the years ended December 31, 1996 and 1995,
operating taxes were $472 million and $448 million, respectively. The increase
in 1996 compared to 1995 is primarily related to higher property taxes and
higher gross receipts taxes, due to increased revenues.
Federal Income Tax
Federal income tax was $233 million and $211 million for the years ended March
31, 1998 and 1997, respectively. For the years ended December 31, 1996 and
December 31, 1995, federal income tax was $209 million and $206 million,
respectively. The increase in federal income tax for both periods was primarily
attributable to higher pre-tax earnings partially offset by the utilization of
investment tax credits.
Other Income and Deductions, Net
Years Ended March 31, 1998 and 1997
Other income and deductions was a $22 million charge to income for the year
ended March 31, 1998, compared to a $14 million credit to income for the same
period in 1997. The difference, which amounts to approximately $36 million,
relates primarily to a charge of approximately $31 million with respect to
certain benefits earned by its officers recorded in 1998. For a further
discussion of this matter, see Note 8 of Notes to Financial Statements.
Years Ended December 31, 1996 and 1995
Other income and deductions totaled $19 million for the year ended December 31,
1996, compared to $34 million for the same period in 1995. The decrease in 1996
when compared to 1995 is primarily attributable to the recognition of
non-recurring expenditures associated with one of the Company's wholly-owned
subsidiaries, a decrease in non-cash carrying charge income associated with
regulatory assets not currently in rate base and the recognition in 1995 of
certain litigation proceeds related to the construction of the Shoreham Nuclear
Power Station.
INTEREST EXPENSE
Years Ended March 31, 1998 and 1997
Interest expense for the year ended March 31, 1998 totaled $409 million compared
to $439 million for the year ended March 31, 1997. This decrease is primarily
attributable to lower outstanding debt levels as the Company retired $250
million of G&R Bonds in February 1997.
Years Ended December 31, 1996 and 1995
Interest expense for the year ended December 31, 1996 totaled $451 million
compared to $476 million for the year ended December 31, 1995. This decrease is
primarily attributable to lower outstanding debt levels, partially offset by
higher letter of credit and commitment fees associated with the change in the
Company's credit rating in 1996.
41
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
LIQUIDITY
For the year ended March 31, 1998, cash generated from operations exceeded the
Company's operating, construction and dividend requirements. This positive cash
flow is the result of, among other things: (i) the Company's continuing efforts
to control both O&M expenses and construction expenditures; (ii) lower interest
payments resulting from lower debt levels; and (iii) lower fuel expenditures.
At March 31, 1998, the Company's cash and cash equivalents amounted to
approximately $181 million, compared to $65 million at March 31, 1997. In
addition, the Company has available for its use a revolving line of credit
through October 1, 1998, provided by its 1989 Revolving Credit Agreement (1989
RCA). This line of credit is secured by a first lien upon the Company's accounts
receivable and fuel oil inventories. In July 1997, the Company utilized $40
million in interim financing under the RCA, which was repaid in August 1997. The
Company will, in order to satisfy short-term cash requirements, continue to
avail itself of interim financing through the RCA, as necessary. For a further
discussion of the 1989 RCA, see Note 7 of Notes to Financial Statements.
The Company does not intend to access the financial markets during 1998 to meet
any of its ongoing operating, construction or refunding requirements. However,
the Company will avail itself of any tax-exempt financing made available to it
by the New York State Energy Research and Development Authority (NYSERDA). The
Company used cash on hand to satisfy the retirement of $100 million of G&R Bonds
which matured on April 15, 1998.
In December 1997, the Company received $24.5 million in net proceeds from the
sale of Electric Facilities Revenue Bonds (EFRBs) issued by NYSERDA. The
proceeds from this offering were used to reimburse the Company's treasury for
amounts previously expended on electric non-nuclear generation projects.
With respect to the repayment of $454 million of maturing debt and $22 million
of maturing preferred stock in 1999 and the repayment of $37 million of maturing
debt and $363 million of maturing preferred stock in 2000, should the LIPA
Transaction not close, the Company intends to use cash generated from operations
to the maximum extent practicable.
Pursuant to the terms of the LIPA Transaction, each issued and outstanding share
of the Company's preferred stock that is subject to optional redemption will be
called for redemption at or before closing of the LIPA Transaction. The LIPA
Transaction provides for repayment to the Company, at closing, for the principal
amount of the preferred stock to be redeemed. Accordingly, on April 17, 1998,
the Company exercised its option and called for redemption on May 19, 1998, all
the outstanding shares of its Preferred Stock Series B, D, E, F, H, I, L, and
NN. The redemption of these Preferred Stock Series amounted to $122 million
which included approximately $5 million of redemption premiums. The Company used
cash generated from operations and the utilization of interim financing through
its 1989 RCA to finance the redemption. In the event the LIPA Transaction is not
consummated, the Company may elect to access the capital markets for permanent
financing to replace the Preferred Stock redeemed.
In 1990 and 1992, the Company received Revenue Agents' Reports disallowing
certain deductions and credits claimed by the Company on its federal income tax
returns for the years 1981 through 1989. A settlement resolving all audit issues
was reached between the Company and the Internal Revenue
42
<PAGE>
Service in May 1998. The settlement provided for the payment of taxes and
interest of approximately $9 million and $35 million, respectively, which the
Company made in May 1998.
In May 1998, the Company funded certain of its obligations for postretirement
benefits other than pensions in order to take a current tax deduction. The
Company secured a bridge loan of $250 million to fund Voluntary Employee's
Beneficiary Association trusts. The Company intends to repay this bridge loan
upon the closing of the LIPA Transaction.
CAPITALIZATION
The Company's capitalization, including current maturities of long-term debt and
current redemption requirements of preferred stock, at March 31, 1998 and 1997
and December 31, 1996 and 1995, was $7.8 billion, $7.7 billion, $7.9 billion and
$8.3 billion, respectively.
At March 31, 1998 and 1997 and at, December 31, 1996 and 1995, the Company's
capitalization ratios were as follows:
<TABLE>
<CAPTION>
- --------------------------------------- --------------------------------- ----------------------------------
March 31 December 31
- --------------------------------------- --------------------------------- ----------------------------------
1998 1997 1996 1995
- --------------------------------------- ---------------- ----------------- ---------------- ----------------
<S> <C> <C> <C> <C>
Long term debt 57.3% 57.8% 59.3% 61.8%
Preferred stock 9.0 9.1 8.9 8.6
Common shareowners' equity 33.7 33.1 31.8 29.6
======================================= ================ ================= ================ ================
100.0% 100.0% 100.0% 100.0%
======================================= ================ ================= ================ ================
</TABLE>
In support of the Company's continuing goal to reduce its debt ratio, the
Company, in February 1997, retired at maturity $250 million of G&R Bonds with
cash on hand and by utilizing interim financing of $30 million, which was repaid
in March 1997. The Company used cash on hand to satisfy the $100 million of G&R
Bonds which matured in April 1998.
INVESTMENT RATING
The Company's securities are rated by Standard and Poor's (S&P), Moody's
Investors Service, Inc. (Moody's), Fitch IBCA, Inc. (Fitch) and Duff & Phelps
Credit Rating Co. (D&P).
At March 31, 1998, the ratings for each of the Company's principal securities
were as follows:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------
S&P Moody's Fitch D&P
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
G&R Bonds BBB* Baa3* BBB-* BBB*
Debentures BB+ Ba1 BB+ BB+
Preferred Stock BB+ ba1 BB- BB
- ------------------------------------------------------------------------------------------------------------------
Minimum Investment Grade BBB-* Baa3* BBB-* BBB-*
==================================================================================================================
*Bold face indicates securities that meet or exceed minimum investment grade.
</TABLE>
During March 1998, following the announcement that the Company received
favorable tax rulings from the IRS with respect to the LIPA Transaction, Moody's
raised the ratings of the Company's G&R Bonds to Baa3 from Ba1; its debentures
to Ba1 from Ba3 and its preferred stock to ba1 from ba3.
During October 1997, S&P announced that it raised the Company's G&R Bonds
ratings one notch to BBB from BBB-. The upgrade resulted from S&P incorporating
into its ratings of corporate issues a more vigorous analysis of ultimate
recovery potential to supplement the analysis of default risk. The
43
<PAGE>
incorporation of ultimate recovery risk is particularly important for ratings of
electric, gas, and water utility senior secured debt. If, in S&P's analytical
conclusion, full recovery of principal can be anticipated in a post-default
scenario, an issue's rating may be enhanced above the corporate credit rating or
default rating.
CAPITAL REQUIREMENTS AND CAPITAL PROVIDED
Capital requirements and capital provided for the year ended March 31, 1998, the
three months ended March 31, 1997 and the year ended December 31, 1996, were as
follows:
<TABLE>
<CAPTION>
(In Millions of Dollars)
- ------------------------------------------------ -------------------------- ------------------------ ---------------------------
Year Ended Three Months Ended Year Ended
March 31, 1998 March 31, 1997 December 31, 1996
- ------------------------------------------------ -------------------------- ------------------------ ---------------------------
- ------------------------------------------------ -------------------------- ------------------------ ---------------------------
CAPITAL REQUIREMENTS
Construction * $257 $ 50 $240
- ------------------------------------------------ -------------------------- ------------------------ ---------------------------
<S> <C> <C> <C>
Redemptions and Dividends
Long-term debt 1 250 415
Preferred stock 1 - 5
Preferred stock dividends 52 13 52
Common stock dividends 216 54 214
- ------------------------------------------------ -------------------------- ------------------------ ---------------------------
Total Redemption and Dividends 270 317 686
- ------------------------------------------------ -------------------------- ------------------------ ---------------------------
Shoreham post-settlement costs 40 12 52
Investment in interest rate hedge 30 - -
================================================ ========================== ======================== ===========================
Total Capital Requirements $597 $379 $978
================================================ ========================== ======================== ===========================
CAPITAL PROVIDED
Cash from operations $674 $160 $892
(Increase) Decrease in cash balances (116) 215 71
Long term debt issued 25 - -
Common stock issued 18 5 19
Other investing and financing activities ( 4) (1) ( 4)
================================================ ========================== ======================== ===========================
Total Capital Provided $597 $379 $978
================================================ ========================== ======================== ===========================
</TABLE>
* Excludes non-cash allowance for other funds used during construction.
For further information, see the Statement of Cash Flows.
For the year ended March 31, 1999, total capital requirements (excluding common
stock dividends) are estimated to be $589 million, of which maturing debt is
$101 million, construction requirements are $266 million, preferred stock
dividends are $45 million, redemptions of preferred stock are $144 million and
Shoreham post-settlement costs are $33 million (including $31 million for
payments-in-lieu-of-taxes). The Company believes that cash generated from
operations coupled with cash balances will be sufficient to meet all capital
requirements during this period.
OTHER MATTERS
LONG ISLAND POWER AUTHORITY TRANSACTION
For a discussion of the Long Island Power Authority Transaction, see Note 2 of
Notes to Financial Statements.
KEYSPAN ENERGY CORPORATION TRANSACTION
For a discussion of the KeySpan Energy Corporation Transaction, see Note 3 of
Notes to Financial Statements.
44
<PAGE>
RATE MATTERS
For a discussion of Rate Matters, see Note 4 of Notes to Financial Statements.
COMPETITIVE ENVIRONMENT
For a discussion of competitive issues facing the Company, see Note 12 of Notes
to Financial Statements.
ENVIRONMENTAL MATTERS
General
The Company's ordinary business operations necessarily involve materials and
activities which subject the Company to federal, state and local laws, rules and
regulations dealing with the environment, including air, water and land quality.
These environmental requirements may entail significant expenditures for capital
improvements or modifications and may expose the Company to potential
liabilities which, in certain instances, may be imposed without regard to fault
or for historical activities which were lawful at the time they occurred.
Laws which may impose such potential liabilities include (but are not limited
to) the federal Comprehensive Environmental Response, Compensation and Liability
Act (CERCLA, commonly known as Superfund), the federal Resource Conservation and
Recovery Act, the federal Toxic Substances Control Act (TSCA), the federal Clean
Water Act (CWA), and the federal Clean Air Act (CAA).
Capital expenditures for environmental improvements and related studies amounted
to approximately $9.2 million for the year ended March 31, 1998 and, based on
existing information, are expected to be $4.0 million for the year ended March
31, 1999. The expenditures in fiscal year 1998 and expected spending in fiscal
year 1999 include a total of $10.6 million for the completion of a gas-firing
capability project at Northport Unit 1 and Port Jefferson Unit 4.
It is not possible to ascertain with certainty if or when the various required
governmental approvals for which applications have been made will be issued, or
whether, except as noted below, additional facilities or modifications of
existing or planned facilities will be required or, generally, what effect
existing or future controls may have upon Company operations. Except as set
forth below and in Item 3 - "Legal Proceedings," no material proceedings have
been commenced or, to the knowledge of the Company, are contemplated by any
federal, state or local agency against the Company, nor is the Company a
defendant in any material litigation with respect to any matter relating to the
protection of the environment.
Recoverability of Environmental Costs
The Company believes that none of the environmental matters, discussed below,
will have a material adverse impact on the Company's financial position, cash
flows or results of operations. In addition, the Company believes that all
significant costs incurred with respect to environmental investigation and
remediation activities, not recoverable from insurance carriers, will be
recoverable from its customers.
Air
Federal, state and local regulations affecting new and existing electric
generating plants govern emissions of sulfur dioxide (SO2), nitrogen oxides
(NOX), particulate matter, and, potentially in the future, fine particulate
matter (aerosols of SO2), hazardous air pollutants and carbon dioxide (CO2).
45
<PAGE>
Sulfur Dioxide Requirements
The laws governing the sulfur content of the fuel oil being burned by the
Company in compliance with the United States Environmental Protection Agency
(EPA) approved Air Quality State Implementation Plan (SIP) are administered by
the New York State Department of Environmental Conservation (DEC). The Company
does not expect to incur any costs to satisfy the 1990 amendments to the federal
CAA with respect to the reduction of SO2 emissions, as the Company already uses
natural gas and oil with acceptably low levels of sulfur as boiler fuels. These
fuels also result in reduced vulnerability to any future fine particulate
standards implemented in the form of stringent sulfur dioxide emission limits.
The Company's use of low sulfur fuels has resulted, and will continue to result,
in approximately 70,000 excess SO2 allowances per year through the year 1999.
The Company presently applies the proceeds resulting from any sales of excess
SO2 allowances as a reduction to the RMC balance.
The Company entered into a voluntary Memorandum of Understanding with the DEC
which provides that the Company will not sell SO2 allowances for use in 15
states in an effort to mitigate the transport of acid rain precursors into New
York State from upwind states.
Nitrogen Oxides Requirements
Due to the Company's program of cost-effective emission reductions, including
the optimization of natural gas firing ability at almost all the steam electric
generating stations, the Company had the lowest NOX emissions rate of all the
utilities in New York State for the years ended December 31, 1997, 1996 and
1995. Since the Company's generating facilities are located within a CAA
Amendment-designated ozone non-attainment area, they are subject to NOx
reduction requirements which are being implemented in three phases. Phase I was
completed in 1995; Phase II and Phase III will be completed in 1999 and 2003,
respectively.
The Company is currently in compliance with Phase I NOx reduction requirements.
It is estimated that additional expenditures of approximately $1 million will be
required to meet Phase II NOx reduction requirements. Subject to requirements
that are expected to be promulgated in forthcoming regulations, the Company
estimates that it may be required to spend an additional $10 million to $34
million, excluding the Northport Unit 1 conversion, by the year 2003 to meet
Phase III NOx reduction requirements. The completion of the project to add
gas-firing capability at Northport Unit 1 (completed in May 1998 at a total cost
of approximately $8.4 million) will also facilitate the Company's compliance
with the anticipated Phase III Nox reduction requirements.
Continuous Emission Monitoring
Additional software and equipment upgrades for Continuous Emissions Monitors of
approximately $2 million may be required through 1999 at all generating
facilities in order to meet EPA requirements under development for the NOx
allowance tracking/trading program.
Hazardous Air Pollutants
Utility boilers are presently exempt from regulation as sources of hazardous air
pollutants until the EPA completes a study of the risks, if any, to public
health reasonably anticipated to occur as a result of emissions by electric
generating units. The EPA is expected to make a determination concerning the
need for control of hazardous air pollutants from utility facilities in 1998.
Until such determination
46
<PAGE>
is made by the EPA, the Company cannot fully ascertain what, if any, costs will
be incurred for the control of hazardous air pollutants.
However, after the expenditure of approximately $1.5 million in fiscal 1998 and
the planned spending of $0.5 million through March 31, 1999, for electrostatic
precipitator upgrades and, with the maximization of clean burning natural gas as
the primary fuel, hazardous air pollutant regulations, if enacted, should not
impose any additional control requirements for the Company's facilities.
Carbon Dioxide Requirements
CO2 emissions from the Company's plants have been reduced by approximately 23%
since 1990, largely through greater reliance on the use of natural gas and
through conservation programs. This makes the Company less vulnerable to future
CO2 reduction requirements.
Opacity Issues
The DEC has proposed commencing enforcement actions against all New York
utilities for alleged opacity exceedences from steam electric generating
facilities. Opacity is a measure of the relative level of light that is obscured
from passing through a power plant stack emission plume. An exceedence occurs
when the level of light passing through the plume is reduced by more than 20%
for six minutes or more. The Company has entered into an Administrative Consent
Order (ACO) with the DEC which resolves all historical opacity exceedences,
establishes an opacity reduction program to be undertaken by the Company, and
sets a stipulated penalty schedule for future exceedences. The number of
exceedences experienced by the Company is relatively low, placing the Company
among the best performers in New York State.
Electromagnetic Fields
Electromagnetic fields (EMF) occur naturally and also are produced wherever
there is electricity. These fields exist around power lines and other utility
equipment. The Company is in compliance with all applicable regulatory standards
and requirements concerning EMF. The Company also monitors scientific
developments in the study of EMF, has contributed to funding for research
efforts, and is actively involved in customer and employee outreach programs to
inform the community of EMF developments as they occur. Although an extensive
body of scientific literature has not shown an unsafe exposure level or a causal
relationship between EMF exposure and adverse health effects, concern over the
potential for adverse health effects will likely continue without final
resolution for some time. To date, four residential property owners have
initiated separate lawsuits against the Company alleging that the existence of
EMF has diminished the value of their homes. These actions are in the
preliminary stages of discovery and are similar to actions brought against
another New York State utility, which were dismissed by the New York State Court
of Appeals. The Company is not involved in any active litigation that alleges a
causal relationship between exposure to EMF and adverse health effects.
Water
Under the federal CWA and the New York State Environmental Conservation Law, the
Company is required to obtain a State Pollutant Discharge Elimination System
permit to make any discharge into the waters of the United States or New York
State. The DEC has the jurisdiction to issue these permits and their renewals
and has issued permits for the Company's generating units. The permits allow the
continued use of the circulating water systems which have been determined to be
in compliance with
47
<PAGE>
state water quality standards. The permits also allow for the continued use of
the chemical treatment systems and for the continued discharge of water in
accordance with applicable permit limits.
In fiscal year 1998, the Company spent approximately $300,000 to upgrade its
waste water treatment facilities and for other measures designed to protect
surface and ground water quality and expects to spend an additional $100,000 in
the years 1998-2000.
Long Island Sound Transmission Cables
During 1996, the Connecticut Department of Environmental Protection (DEP) issued
a modification to an Administrative Consent Order (ACO) previously issued in
connection with an investigation of an electric transmission cable system
located under the Long Island Sound (Sound Cable) that is jointly owned by the
Company and the Connecticut Light and Power Company (Owners). The modified ACO
requires the Owners to submit to the DEP and DEC a series of reports and studies
describing cable system condition, operation and repair practices, alternatives
for cable improvements or replacement and environmental impacts associated with
leaks of fluid into the Long Island Sound which have occurred from time to time.
The Company continues to compile required information and coordinate the
activities necessary to perform these studies and, at the present time, is
unable to determine the costs it will incur to complete the requirements of the
modified ACO or to comply with any additional requirements.
The Owners have also entered into an ACO with the DEC as a result of leaks of
dielectric fluid from the Sound Cable. The ACO formalizes the DEC's authority to
participate in and separately approve the reports and studies being prepared
pursuant to the ACO issued by the DEP. In addition, the ACO settles any DEC
claim for natural resource damages in connection with historical releases of
dielectric fluid from the Sound Cable.
In October 1995, the U.S. Attorney for the District of Connecticut had commenced
an investigation regarding occasional releases of fluid from the Sound Cable, as
well as associated operating and maintenance practices. The Owners have provided
the U.S. Attorney with all requested documentation. The Company believes that
all activities associated with the response to occasional releases from the
Sound Cable were consistent with legal and regulatory requirements.
In December 1996, a barge, owned and operated by a third party, dropped anchor
which then dragged over and damaged the Sound Cable, resulting in the release of
dielectric fluid into Long Island Sound. Temporary clamps and leak abaters were
installed on the cables to stop the leaks. Permanent repairs were completed in
June 1997. The cost to repair the Sound Cable was approximately $17.8 million,
for which there was $15 million of insurance coverage. The Owners filed a claim
and answer in response to the maritime limitation proceeding instituted by the
barge owner in the United States District Court, Eastern District of New York.
The claim seeks recovery of the amounts paid by insurance carriers and recovery
of the costs incurred for which there was no insurance coverage. Any costs to
repair the Sound Cable which are not reimbursed by a third party or covered by
insurance will be shared equally by the Owners.
Land
Superfund imposes joint and several liability, regardless of fault, upon
generators of hazardous substances for costs associated with environmental
cleanup activities. Superfund also imposes liability for remediation of
pollution caused by historical acts which were lawful at the time they occurred.
48
<PAGE>
In the course of the Company's ordinary business operations, the Company is
involved in the handling of materials that are deemed to be hazardous substances
under Superfund. These materials include asbestos, metals, certain flammable and
organic compounds and dielectric fluids containing polychlorinated biphenyls
(PCBs). Other hazardous substances may be handled in the Company's operations or
may be present at Company locations as a result of historical practices by the
Company or its predecessors in interest. The Company has received notice
concerning possible claims under Superfund or analogous state laws relating to a
number of sites at which it is alleged that hazardous substances generated by
the Company and other potentially responsible parties (PRPs) were deposited. A
discussion of these sites is set forth below.
Estimates of the Company's allocated share of costs for investigative, removal
and remedial activities at these sites range from preliminary to refined and are
updated as new information becomes available. In December 1996, the Company
filed a complaint in the United States District Court for the Southern District
of New York against 14 of the Company's insurers which issued general
comprehensive liability (GCL) policies to the Company. In January 1998, the
Company commenced a similar action against the same and certain additional
insurer defendants in New York State Supreme Court, First Department; the
federal court action was subsequently dismissed in March 1998. The Company is
seeking recovery under the GCL policies for the costs incurred to date and
future costs associated with the clean-up of the Company's former manufactured
gas plant (MGP) sites and Superfund sites for which the Company has been named a
PRP. The Company is seeking a declaratory judgment that the defendant insurers
are bound by the terms of the GCL policies, subject to the stated coverage
limits, to reimburse the Company for the clean up costs. The outcome of this
proceeding cannot yet be determined.
Superfund Sites
Metal Bank
The EPA has notified the Company that it is one of many PRPs that may be liable
for the remediation of a licensed disposal site located in Philadelphia,
Pennsylvania, and operated by Metal Bank of America. The Company and nine other
PRPs, all of which are public utilities, completed performance of a Remedial
Investigation and Feasibility Study (RI/FS), which was conducted under an ACO
with the EPA. In December 1997, the EPA issued its Record of Decision (ROD),
setting forth the final remedial action selected for the site. In the ROD, the
EPA estimated that the present cost of the selected remedy for the site is $17.3
million. At this time, the Company cannot predict with reasonable certainty the
actual cost of the selected remedy, who will implement the remedy, or the cost,
if any, to the Company. Under a PRP participation agreement, the Company
previously was responsible for 8.2% of the costs associated with the RI/FS. The
Company's allocable share of liability for the remediation activities has not
yet been determined.
The Company has recorded a liability of approximately $1 million representing
its estimated share of the additional cost to remediate this site based upon its
8.2% responsibility under the RI/FS.
Syosset
The Company and nine other PRPs have been named in a lawsuit where the Town of
Oyster Bay (Town) is seeking indemnification for remediation and investigation
costs that have been or will be
49
<PAGE>
incurred for a federal Superfund site in Syosset, New York. For a further
discussion on this matter, see Item 3, Legal Proceedings - Environmental.
PCB Treatment, Inc.
The Company has also been named a PRP for disposal sites in Kansas City, Kansas,
and Kansas City, Missouri. The two sites were used by a company named PCB
Treatment, Inc. from 1982 until 1987 for the storage, processing, and treatment
of electric equipment, dielectric oils and materials containing PCBs. According
to the EPA, the buildings and certain soil areas outside the buildings are
contaminated with PCBs.
Certain of the PRPs, including the Company and several other utilities, formed a
PRP group, signed an ACO, and have developed a workplan for investigating
environmental conditions at the sites. Documentation connecting the Company to
the sites indicates that the Company was responsible for less than 1% of the
materials that were shipped to the Missouri site. The EPA has not yet completed
compiling the documents for the Kansas site.
Osage
The EPA has notified the Company that it is a PRP at the Osage Metals Site, a
former scrap metal recycling facility located in Kansas City, Kansas. Under
Section 107(a) of CERCLA, parties who arranged for disposal of hazardous
substances are liable for costs incurred by the EPA in responding to a release
or threat of release of the hazardous substances. Osage had purchased capacitor
scrap metal from PCB Treatment, Inc. Through the arrangements that the Company
made with PCB Treatment, Inc. to dispose of capacitors, the Company is alleged
to have arranged for disposal within the meaning of the federal Superfund law. A
similar letter was sent to 861 parties who sent capacitors to PCB Treatment,
Inc. The EPA is seeking to recover approximately $1.1 million dollars it
expended to conduct a removal action at the site. The Company is currently
unable to determine its share of the $1.1 million expenditure.
Port Refinery
The Company has been notified that it is a PRP at the Port Refinery Superfund
site located in Westchester County, New York. Port Refinery was engaged in the
business of purchasing, selling, refining and processing mercury and the Company
may have shipped a small amount of waste products containing mercury to this
site. Tests conducted by the EPA indicated that the site and certain adjacent
properties were contaminated with mercury. As a result, the EPA has performed a
response action at the site and seeks to recover its costs, currently totaling
approximately $4.4 million, plus interest, from the PRPs. The Company does not
believe its portion of these costs, if any, will be material.
Port Washington
In 1989, the EPA notified the Company that it was a PRP for a landfill in Port
Washington, New York. The Company does not believe that it sent any materials to
the site that contributed to the contamination which requires remediation and
has therefore declined the EPA's requests to participate in funding the
investigation and remediation activities at the property. The Company has not
received further communications regarding this site.
50
<PAGE>
Liberty
The EPA has notified the Company that it is a PRP in a Superfund site located in
Farmingdale, New York. Industrial operations took place at this site for at
least fifty years. The PRP group has claimed that the Company should absorb
remediation expenses in the amount of approximately $100,000 associated with
removing PCB-contaminated soils from a portion of the site which formerly
contained electric transformers. The Company is currently unable to determine
its share of costs of remediation at this site.
Huntington/East Northport
The DEC has notified the Company, pursuant to the State Superfund program, that
its records indicate the Company may be responsible for the disposal of waste at
this municipal landfill property. The Company conducted a search of its
corporate records and did not locate any documents concerning waste disposal
practices associated with this landfill. The Company is currently unable to
determine its share, if any, of the costs to investigate and remediate this
site.
Blydenburgh
The New York State Office of the Attorney General has notified the Company that
it may be responsible for the disposal of wastes and/or for the generation of
hazardous substances which may have been disposed of at the Blydenburgh
Superfund site, a municipal sanitary landfill located in the Town of Islip,
Suffolk County. The State has incurred approximately $15 million in costs for
the investigation and remediation of environmental conditions at the landfill.
In connection with this notification, the Company conducted a review of its
corporate records and did not locate any documents concerning waste disposal
practices associated with this landfill. The Company is currently unable to
determine its share, if any, of the costs to investigate and remediate this
site.
Other Sites
Manufactured Gas Plant Sites
The DEC has required the Company and other New York State utilities to
investigate and, where necessary, remediate their former MGP sites. Currently,
the Company is the owner of six pieces of property on which the Company or
certain of its predecessor companies produced manufactured gas. Operations at
these facilities in the late 1800's and early 1900's may have resulted in the
disposal of certain waste products located at these sites.
The Company has entered into discussions with the DEC which is expected to lead
to the issuance of one or more ACOs regarding the management of environmental
activities at these six properties. Although the exact amount of the Company's
cleanup costs cannot yet be determined, based on the findings of preliminary
investigations conducted at each of these six sites, current estimates indicate
that it may cost approximately $54 to $92 million to investigate and remediate
all of these sites. Considering the range of possible remediation estimates, the
Company felt it appropriate to record a $54 million liability reflecting the
present value of the future stream of payments amounting to $70 million to
investigate and remediate these sites. The Company used a risk-free rate of 6.0%
to discount this obligation. The Company believes that the PSC will provide for
future recovery of these costs and has recorded a $54 million regulatory asset.
The Company's rate settlement which the PSC approved February 4, 1998 as
discussed in Note 3 of Notes to Financial Statements, allows for the recovery of
MGP expenditures from gas customers.
51
<PAGE>
The Company is also evaluating its responsibilities with respect to several
other former MGP sites that existed in its territory which it does not presently
own. Research is underway to determine the existence and nature of operations
and relationship, if any, to the Company or its predecessor companies.
North Hills Leak
The Company has undertaken remediation of certain soil locations in North Hills,
New York that were impacted by a release of insulating fluid from an electrical
cable in August 1994. The Company estimates that any additional cleanup costs
will not exceed $0.5 million. The Company has initiated cost recovery actions
against the third parties it believes are responsible for causing the cable
leak, the outcome of which are uncertain.
Storage Facilities
As a result of petroleum leaks from underground storage facilities and other
historical occurrences, the Company is required to investigate and, in certain
cases, remediate affected soil and groundwater conditions at several facilities
within its service territory. The aggregate costs of such remediation work could
be between $3 million and $5 million. To the extent that these costs are not
recoverable through insurance carriers, the Company believes such costs will be
recoverable from its customers.
Nuclear Waste
Low Level Radioactive Waste
The federal Low Level Radioactive Waste Policy Amendment Act of 1985, requires
states to arrange for the disposal of all low level radioactive waste generated
within the state or, in the alternative, to contract for their disposal at an
operating facility outside the state. As a result, New York State has stated its
intentions of developing an in-state disposal facility due to the large volume
of low level radioactive waste generated within the state and has committed to
develop a plan for the management of such waste during the interim period until
a disposal facility is available. New York State is still developing a disposal
methodology and acceptance criteria for a disposal facility. The latest New York
State low level radioactive waste site development schedule now assumes two
possible siting scenarios, a volunteer approach and a non-volunteer approach,
either of which would not begin operation until at least 2001. Low level
radioactive waste generated at NMP2 is currently being disposed of at the
Barnwell, South Carolina waste disposal facility which reopened in July 1995 to
out-of-state low level waste generators.
In the event that off-site storage becomes unavailable prior to 2001, NMPC has
implemented a low level radioactive waste management program that will properly
handle interim on-site storage of low level radioactive waste for NMP2 for at
least ten years. The Company's share of the costs associated with temporary
storage and ultimate disposal are currently recovered in rates.
Spent Nuclear Fuel
NMPC, on behalf of the NMP2 cotenants, has entered into a contract with the DOE
for the permanent storage of NMP2 spent nuclear fuel. The Company reimburses
NMPC for its 18% share of the cost under the contract at a rate of $1.00 per
megawatt hour of net generation less a factor to account for transmission line
losses. The Company is collecting its portion of this fee from its electric
customers. It is anticipated that the DOE facility may not be available for
permanent
52
<PAGE>
storage until at least 2010. Currently, all spent nuclear fuel from NMP2 is
stored at the NMPC site, and existing facilities are sufficient to handle all
spent nuclear fuel generated at NMP2 through the year 2012.
For information concerning environmental litigation, see Item 3 "Legal
Proceedings" under the heading Environmental.
IMPACT OF YEAR 2000
Some of the Company's older computer programs were written using two digits
rather than four to define the applicable year. As a result, those computer
programs have time-sensitive software that recognizes a date using "00" as the
year 1900 rather than the year 2000. This could cause a system failure or
miscalculations causing disruptions of operations, including, among other
things, a temporary inability to process transactions, or engage in normal
business activities.
The Company embarked on a program in 1996 to complete Year 2000 compliance by
December 31, 1998. A corporate-wide program has been established to review all
software, hardware and associated compliance plans. The readiness of suppliers
and vendor systems is also under review. Contingency and business continuation
plans are being prepared and will be reviewed periodically.
The Company expects to spend approximately $10 million to address the Year 2000
issue over a three-year period (1997-1999) consisting of $7 million to test and
modify application systems and $3 million to test and modify non-information
technology systems. All costs will be expensed as incurred. As of March 31,
1998, $4.53 million has been expended in investigating and modifying software.
This effort is scheduled to be completed in 1998 and testing will continue into
early 1999.
The Company believes that, with modifications to existing software and
conversions to new software, the Year 2000 Issue will not pose significant
operational problems for its computer systems. However, if such modifications
and conversions are not made, or are not completed on time, the Year 2000 Issue
could have a material adverse impact on the operations of the Company.
The costs of the project and the date on which the Company believes it will
complete the Year 2000 modifications are based on management's best estimates,
which were derived utilizing numerous assumptions of future events, including
the continued availability of certain resources and other factors. However,
actual results could differ materially from those anticipated. Specific factors
that might cause such material differences include, but are not limited to, the
availability and cost of personnel trained in this area, the ability to locate
and correct all relevant computer codes and similar uncertainties.
RECENT ACCOUNTING PRONOUNCEMENTS
Comprehensive Income
In June 1997, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards (SFAS) No. 130. SFAS No. 130 establishes
standards for reporting comprehensive income. Comprehensive income is the change
in the equity of a company, not including those changes that result from
shareholder transactions. All components of comprehensive income are required to
be reported in a new financial statement that is displayed with equal
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prominence as existing financial statements. The Company will be required to
adopt SFAS No. 130 for the year ending March 31, 1999. The Company does not
expect that the adoption of SFAS NO. 130 will have a significant impact on its
reporting and disclosure requirements.
Segment Disclosures
Also in June 1997, FASB issued SFAS No. 131. SFAS No. 131 establishes standards
for additional disclosure about operating segments for interim and annual
financial statements. More specifically, it requires financial information to be
disclosed for segments whose operating results are reviewed by the chief
decision maker for decisions on resource allocation. It also requires related
disclosures about products and services, geographic areas and major customers.
The Company will be required to adopt SFAS No. 131 for the year ending March 31,
1999. The Company does not expect that the adoption of SFAS No. 131 will have a
significant impact on its reporting and disclosure requirements.
CONSERVATION SERVICES
The Company's 1997 Demand Side Management (DSM) Plan focused on the pursuit of
energy efficiency and peak load reduction in a way that had minimal impact on
electric rate increases. To assure the success of this strategy, the Company
implemented a balanced and cost-effective mix of DSM programs that continued to
represent a limited reliance on broad-based rebates and a concentrated emphasis
on programs that provided education and information, targeted business
development, provided financing for energy efficiency, induced market
transformation and improved the efficiency of LILCO facilities. The Company was
successful in meeting the PSC Energy Penalty Threshold by obtaining energy
savings of approximately 24.4 GWh at a cost less than that provided for in
electric rates.
In 1998, the Company plans to continue to follow the aforementioned strategy
while introducing several new initiatives. These include a program targeted at
increasing the energy efficiency of residences of low income customers, the
introduction of a peak load curtailment program constructed to help the Company
meet its peak supply side requirements and an increased emphasis on programs
that induce market transformation. Overall, the 1998 Plan targets an annualized
energy savings of 18.6 GWh at a budget of $10.7 million.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This report contains statements which, to the extent they are not recitations of
historical fact, constitute "forward-looking statements" within the meaning of
the Securities Litigation Reform Act of 1995 (Reform Act). In this respect, the
words "estimate," "project," "anticipate," "expect," "intend," "believe" and
similar expressions are intended to identify forward-looking statements. All
such forward-looking statements are intended to be subject to the safe harbor
protection provided by the Reform Act. A number of important factors affecting
the Company's business and financial results could cause actual results to
differ materially from those stated in the forward-looking statements. Those
factors include the proposed transactions with The KeySpan Energy Corporation
and LIPA as discussed under the heading "KeySpan Energy Corporation Transaction"
and "Long Island Power Authority Transaction" state and federal regulatory rate
proceedings, competition, and certain environmental matters each as discussed
herein, in the Joint Proxy Statement/Prospectus filed June 30, 1997, or in other
reports filed by the Company with the Securities and Exchange Commission.
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<PAGE>
FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Balance Sheet (In thousands of dollars)
- ---------------------------------------------------------------------------------------------------------------------------
Assets at March 31, 1998 March 31, 1997 December 31, 1996
- ---------------------------------------------------------------------------------------------------------------------------
UTILITY PLANT
<S> <C> <C> <C>
Electric $ 4,031,510 $ 3,900,264 $ 3,882,297
Gas 1,233,281 1,171,183 1,154,543
Common 290,221 263,267 260,268
Construction work in progress 118,808 108,850 112,184
Nuclear fuel in process and in reactor 18,119 15,503 15,454
- --------------------------------------------------------------------------------------------------------------------------
5,691,939 5,459,067 5,424,746
Less - Accumulated depreciation and amortization 1,877,858 1,759,110 1,729,576
- --------------------------------------------------------------------------------------------------------------------------
Total Net Utility Plant 3,814,081 3,699,957 3,695,170
- --------------------------------------------------------------------------------------------------------------------------
REGULATORY ASSETS
Base financial component (less accumulated
amortization of $883,496, $782,525 and $757,282) 3,155,334 3,256,305 3,281,548
Rate moderation component 434,004 409,512 402,213
Shoreham post-settlement costs 1,005,316 996,270 991,795
Shoreham nuclear fuel 66,455 68,581 69,113
Unamortized cost of issuing securities 159,941 187,309 194,151
Postretirement benefits other than pensions 340,109 357,668 360,842
Regulatory tax asset 1,737,932 1,767,164 1,772,778
Other 192,763 200,137 199,879
- --------------------------------------------------------------------------------------------------------------------------
Total Regulatory Assets 7,091,854 7,242,946 7,272,319
- --------------------------------------------------------------------------------------------------------------------------
NONUTILITY PROPERTY AND OTHER INVESTMENTS 50,816 18,870 18,597
- --------------------------------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents 180,919 64,539 279,993
Special deposits 95,790 37,631 38,266
Customer accounts receivable (less allowance
for doubtful accounts of $23,483, $23,675 and $25,000) 297,889 305,436 255,801
Other accounts receivable 43,744 42,946 65,764
Accrued unbilled revenues 124,464 141,389 169,712
Materials and supplies at average cost 54,883 55,454 55,789
Fuel oil at average cost 32,142 49,703 53,941
Gas in storage at average cost 14,634 10,893 73,562
Deferred tax asset - net operating loss -- 93,349 145,205
Prepayments and other current assets 13,807 8,805 8,569
- --------------------------------------------------------------------------------------------------------------------------
Total Current Assets 858,272 810,145 1,146,602
- --------------------------------------------------------------------------------------------------------------------------
DEFERRED CHARGES 85,702 77,656 76,991
- --------------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $11,900,725 $11,849,574 $12,209,679
==========================================================================================================================
See Notes to Financial Statements.
55
<PAGE>
(In thousands of dollars)
- ---------------------------------------------------------------------------------------------------------------------------
Capitalization and Liabilities at March 31, 1998 March 31, 1997 December 31, 1996
- ---------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION
Long-term debt $ 4,395,555 $ 4,471,675 $ 4,471,675
Unamortized discount on debt (13,606) (14,628) (14,903)
- --------------------------------------------------------------------------------------------------------------------------
4,381,949 4,457,047 4,456,772
- --------------------------------------------------------------------------------------------------------------------------
Preferred stock - redemption required 562,600 638,500 638,500
Preferred stock - no redemption required -- 63,598 63,664
- --------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock 562,600 702,098 702,164
- --------------------------------------------------------------------------------------------------------------------------
Common stock 608,635 605,022 603,921
Premium on capital stock 1,146,425 1,131,576 1,127,971
Capital stock expense (47,501) (48,915) (49,330)
Retained earnings 956,092 861,751 840,867
Treasury stock, at cost (1,204) (385) (60)
- --------------------------------------------------------------------------------------------------------------------------
Total Common Shareowners' Equity 2,662,447 2,549,049 2,523,369
- --------------------------------------------------------------------------------------------------------------------------
Total Capitalization 7,606,996 7,708,194 7,682,305
- --------------------------------------------------------------------------------------------------------------------------
REGULATORY LIABILITIES
Regulatory liability component 99,199 178,558 198,398
1989 Settlement credits 59,397 125,138 127,442
Regulatory tax liability 78,913 100,377 102,887
Other 151,922 158,660 139,510
- --------------------------------------------------------------------------------------------------------------------------
Total Regulatory Liabilities 389,431 562,733 568,237
- --------------------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Current maturities of long-term debt 101,000 1,000 251,000
Current redemption requirements of preferred stock 139,374 1,050 1,050
Accounts payable and accrued expenses 228,583 230,189 289,141
LRPP payable 30,118 40,499 40,499
Accrued taxes (including federal income
tax of $28,308, $49,262 and $25,884) 34,753 51,157 63,640
Accrued interest 146,607 143,983 160,615
Dividends payable 58,748 58,474 58,378
Class Settlement 60,000 58,333 55,833
Customer deposits 28,627 29,173 29,471
- --------------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 827,810 613,858 949,627
- --------------------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS
Deferred federal income tax - net 2,539,364 2,420,443 2,442,606
Class Settlement 46,940 89,487 98,497
Other 22,529 20,889 39,447
- --------------------------------------------------------------------------------------------------------------------------
Total Deferred Credits 2,608,833 2,530,819 2,580,550
- --------------------------------------------------------------------------------------------------------------------------
OPERATING RESERVES
Pensions and other postretirement benefits 401,401 387,048 381,996
Claims and damages 66,254 46,922 46,964
- --------------------------------------------------------------------------------------------------------------------------
Total Operating Reserves 467,655 433,970 428,960
- --------------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES -- -- --
- --------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES $ 11,900,725 $ 11,849,574 $ 12,209,679
=========================================================================================================================
</TABLE>
See Notes to Financial Statements.
56
<PAGE>
<TABLE>
<CAPTION>
STATEMENT OF INCOME (In thousands of dollars except per share amounts)
- -------------------------------------------------------------------------------------------------------------------------------
Three Months
Year Ended Ended Year Ended Year Ended
March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995
- -------------------------------------------------------------------------------------------------------------------------------
REVENUES
<S> <C> <C> <C> <C>
Electric $ 2,478,435 $ 557,791 $ 2,466,435 $ 2,484,014
Gas 645,659 293,391 684,260 591,114
- -------------------------------------------------------------------------------------------------------------------------------
Total Revenues 3,124,094 851,182 3,150,695 3,075,128
- -------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operations - fuel and purchased power 957,807 301,867 963,251 834,979
Operations - other 400,045 95,673 381,076 383,238
Maintenance 111,120 29,340 118,135 128,155
Depreciation and amortization 158,537 38,561 153,925 145,357
Base financial component amortization 100,971 25,243 100,971 100,971
Rate moderation component amortization (35,079) 5,907 (24,232) 21,933
Regulatory liability component amortization (79,359) (19,840) (79,359) (79,359)
1989 Settlement credits amortization (9,213) (2,303) (9,214) (9,214)
Other regulatory amortization 47,272 12,218 127,288 161,605
Operating taxes 466,326 117,513 472,076 447,507
Federal income tax - current 86,388 23,378 42,197 14,596
Federal income tax - deferred and other 150,983 33,624 168,000 193,742
- -------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 2,355,798 661,181 2,414,114 2,343,510
- -------------------------------------------------------------------------------------------------------------------------------
Operating Income 768,296 190,001 736,581 731,618
- -------------------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND (DEDUCTIONS)
Rate moderation component carrying charges 23,632 5,919 25,259 25,274
Other income and deductions, net (18,156) 645 19,197 34,400
Class Settlement (15,623) (4,496) (20,772) (21,669)
Allowance for other funds used during construction 3,846 717 2,888 2,898
Federal income tax - current 594 - - -
Federal income tax - deferred and other 4,124 789 940 2,800
- -------------------------------------------------------------------------------------------------------------------------------
Total Other Income and (Deductions) (1,583) 3,574 27,512 43,703
- -------------------------------------------------------------------------------------------------------------------------------
Income Before Interest Charges 766,713 193,575 764,093 775,321
- -------------------------------------------------------------------------------------------------------------------------------
INTEREST CHARGES
Interest on long-term debt 351,261 90,168 384,198 412,512
Other interest 57,805 16,659 67,130 63,461
Allowance for borrowed funds used during construction (4,593) (949) (3,699) (3,938)
- -------------------------------------------------------------------------------------------------------------------------------
Total Interest Charges 404,473 105,878 447,629 472,035
- -------------------------------------------------------------------------------------------------------------------------------
NET INCOME 362,240 87,697 316,464 303,286
Preferred stock dividend requirements 51,813 12,969 52,216 52,620
- -------------------------------------------------------------------------------------------------------------------------------
EARNINGS FOR COMMON STOCK $ 310,427 $ 74,728 $ 264,248 $ 250,666
===============================================================================================================================
AVERAGE COMMON SHARES OUTSTANDING (000) 121,415 120,995 120,360 119,195
- -------------------------------------------------------------------------------------------------------------------------------
BASIC AND DILUTED EARNINGS PER COMMON SHARE $ 2.56 $ 0.62 $ 2.20 $ 2.10
==================================================================================================================================
DIVIDENDS DECLARED PER COMMON SHARE $ 1.78 $ 0.45 $ 1.78 $ 1.78
- ----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
See Notes to Financial Statements.
57
<PAGE>
<TABLE>
<CAPTION>
STATEMENT OF CASH FLOWS
(In thousands of dollars)
- ------------------------------------------------------------------------------------------------------------------------
Year Three Year Year
Ended Months Ended Ended Ended
March 31 March 31 December 31 December 31
1998 1997 1996 1995
- ------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
<S> <C> <C> <C> <C>
Net Income $362,240 $87,697 $316,464 $303,286
Adjustments to reconcile net income to net
cash provided by operating activities
Provision for doubtful accounts 23,239 4,821 23,119 17,751
Depreciation and amortization 158,537 38,561 153,925 145,357
Base financial component amortization 100,971 25,243 100,971 100,971
Rate moderation component amortization (35,079) 5,907 (24,232) 21,933
Regulatory liability component amortization (79,359) (19,840) (79,359) (79,359)
1989 Settlement credits amortization (9,213) (2,303) (9,214) (9,214)
Other regulatory amortization 47,272 12,218 127,288 161,605
Rate moderation component carrying charges (23,632) (5,919) (25,259) (25,274)
Class Settlement 15,623 4,496 20,772 21,669
Amortization of cost of issuing and redeeming securities 30,823 8,087 34,611 39,589
Federal income tax - deferred and other 146,859 32,835 167,060 190,942
Pensions and Other Post Retirement Benefits 48,512 13,496 14,952 4,900
Other 87,618 2,381 51,671 56,675
Changes in operating assets and liabilities
Accounts receivable (14,905) (31,638) 69,215 (67,213)
Materials and supplies, fuel oil and gas in storage 14,391 67,242 (34,531) 21,986
Accounts payable and accrued expenses 1,668 (58,952) 28,258 19,100
Class Settlement (56,503) (11,006) (42,084) (33,464)
Special deposits (58,159) 635 25,146 (35,798)
Other (86,819) (14,394) (26,460) (83,442)
- ------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 674,084 159,567 892,313 772,000
- ------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Construction and nuclear fuel expenditures (257,402) (50,375) (239,896) (243,586)
Shoreham post-settlement costs (39,828) (12,104) (51,722) (70,589)
Investment in interest rate hedge (30,000) --- --- ---
Other (1,987) 160 (4,806) 8,019
- ------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (329,217) (62,319) (296,424) (306,156)
- ------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Proceeds from issuance of securities 43,218 4,640 18,837 68,726
Redemption of securities (2,050) (250,000) (419,800) (104,800)
Common stock dividends paid (215,790) (53,749) (213,753) (211,630)
Preferred stock dividends paid (51,833) (12,969) (52,264) (52,667)
Other (2,032) (624) (369) 529
- ------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Financing Activities (228,487) (312,702) (667,349) (299,842)
- ------------------------------------------------------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS $116,380 ($215,454) ($71,460) $166,002
- ------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of period $64,539 $279,993 $351,453 $185,451
Net increase (decrease) in cash and cash equivalents 116,380 (215,454) (71,460) 166,002
- ------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $180,919 $64,539 $279,993 $351,453
- ------------------------------------------------------------------------------------------------------------------------
Interest paid, before reduction for the allowance
for borrowed funds used during construction $364,864 $112,981 $404,663 $427,988
Federal income tax paid $108,980 --- $45,050 $14,200
- ------------------------------------------------------------------------------------------------------------------------
</TABLE>
See Notes to Financial Statements.
58
<PAGE>
STATEMENT OF RETAINED EARNINGS
<TABLE>
<CAPTION>
(In thousands of dollars)
- --------------------------------------------------------------------------------------------------------------------------------
March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Balance at beginning of period $ 861,751 $ 840,867 $ 790,919 $ 752,480
Net income for the period 362,240 87,697 316,464 303,286
- ------------------------------------------------------------------------------------------------------------------------------
1,223,991 928,564 1,107,383 1,055,766
Deductions
Cash dividends declared on common stock 216,086 53,844 214,255 212,181
Cash dividends declared on preferred stock 51,812 12,969 52,240 52,647
Other 1 - 21 19
- ------------------------------------------------------------------------------------------------------------------------------
BALANCE AT END OF PERIOD $ 956,092 $ 861,751 $ 840,867 $ 790,919
==============================================================================================================================
</TABLE>
See Notes to Financial Statements.
<TABLE>
<CAPTION>
STATEMENT OF CAPITALIZATION Shares Issued (In thousands of dollars)
- -----------------------------------------------------------------------------------------------------------------------------------
March 31, 1998 March 31, 1997 December 31, 1996 March 31, 1998 March 31, 1997
- -----------------------------------------------------------------------------------------------------------------------------------
COMMON SHAREOWNERS' EQUITY
<S> <C> <C> <C> <C> <C>
Common stock, $5.00 par value 121,727,040 121,004,315 120,784,277 $ 608,635 $ 605,022
Premium on capital stock 1,146,425 1,131,576
Capital stock expense (47,501) (48,915)
Retained earnings 956,092 861,751
Treasury stock, at cost 46,281 16,985 3,485 (1,204) (385)
- -----------------------------------------------------------------------------------------------------------------------------
TOTAL COMMON SHAREOWNERS' EQUITY 2,662,447 2,549,049
- -----------------------------------------------------------------------------------------------------------------------------
PREFERRED STOCK - REDEMPTION REQUIRED
Par value $100 per share
7.40% Series L 150,500 161,000 161,000 15,050 16,100
7.66% Series CC 570,000 570,000 570,000 57,000 57,000
Less - Series called for redemption 15,050 1,050
- -----------------------------------------------------------------------------------------------------------------------------
57,000 72,050
- -----------------------------------------------------------------------------------------------------------------------------
Par value $25 per share
7.95% Series AA 14,520,000 14,520,000 14,520,000 363,000 363,000
$1.67 Series GG 880,000 880,000 880,000 22,000 22,000
$1.95 Series NN 1,554,000 1,554,000 1,554,000 38,850 38,850
7.05% Series QQ 3,464,000 3,464,000 3,464,000 86,600 86,600
6.875% Series UU 2,240,000 2,240,000 2,240,000 56,000 56,000
Less - Series called for redemption 38,850 -
Less - Mandatory redemption of preferred stock 22,000 -
- -----------------------------------------------------------------------------------------------------------------------------
505,600 566,450
- -----------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - Redemption Required 562,600 638,500
- -----------------------------------------------------------------------------------------------------------------------------
PREFERRED STOCK - NO REDEMPTION REQUIRED
Par value $100 per share
5.00% Series B 100,000 100,000 100,000 10,000 10,000
4.25% Series D 70,000 70,000 70,000 7,000 7,000
4.35% Series E 200,000 200,000 200,000 20,000 20,000
4.35% Series F 50,000 50,000 50,000 5,000 5,000
5 1/8% Series H 200,000 200,000 200,000 20,000 20,000
5 3/4% Series I - Convertible 14,743 15,978 16,637 1,474 1,598
Less - Series called for redemption 63,474 -
- -----------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - No Redemption Required - 63,598
- -----------------------------------------------------------------------------------------------------------------------------
TOTAL PREFERRED STOCK $ 562,600 $ 702,098
- -----------------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
STATEMENT OF CAPITALIZATION (In thousands of dollars)
- -----------------------------------------------------------------------------
December 31, 1996
- -----------------------------------------------------------------------------
COMMON SHAREOWNERS' EQUITY
Common stock, $5.00 par value $ 603,921
Premium on capital stock 1,127,971
Capital stock expense (49,330)
Retained earnings 840,867
Treasury stock, at cost (60)
- -----------------------------------------------------------------------------
TOTAL COMMON SHAREOWNERS' EQUITY 2,523,369
- -----------------------------------------------------------------------------
PREFERRED STOCK - REDEMPTION REQUIRED
Par value $100 per share
7.40% Series L 16,100
7.66% Series CC 57,000
Less - Series called for redemption 1,050
- -----------------------------------------------------------------------------
72,050
- -----------------------------------------------------------------------------
Par value $25 per share
7.95% Series AA 363,000
$1.67 Series GG 22,000
$1.95 Series NN 38,850
7.05% Series QQ 86,600
6.875% Series UU 56,000
Less - Series called for redemption -
Less - Mandatory redemption of preferred stock -
- -----------------------------------------------------------------------------
566,450
- -----------------------------------------------------------------------------
Total Preferred Stock - Redemption Required 638,500
- -----------------------------------------------------------------------------
PREFERRED STOCK - NO REDEMPTION REQUIRED
Par value $100 per share
5.00% Series B 10,000
4.25% Series D 7,000
4.35% Series E 20,000
4.35% Series F 5,000
5 1/8% Series H 20,000
5 3/4% Series I - Convertible 1,664
Less - Series called for redemption -
- -----------------------------------------------------------------------------
Total Preferred Stock - No Redemption Required 63,664
- -----------------------------------------------------------------------------
TOTAL PREFERRED STOCK $ 702,164
- -----------------------------------------------------------------------------
59
<PAGE>
<TABLE>
<CAPTION>
(In thousands of dollars)
- -----------------------------------------------------------------------------------------------------------------------------------
Maturity Interest Rate Series March 31, 1998 March 31, 1997
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
GENERAL AND REFUNDING BONDS
February 15, 1997 8 3/4% $ - $ -
April 15, 1998 7 5/8% 100,000 100,000
May 15, 1999 7.85% 56,000 56,000
April 15, 2004 8 5/8% 185,000 185,000
May 15, 2006 8.50% 75,000 75,000
July 15, 2008 7.90% 80,000 80,000
May 1, 2021 9 3/4% 415,000 415,000
July 1, 2024 9 5/8% 375,000 375,000
- ----------------------------------------------------------------------------------------------------------------------------------
Total General and Refunding Bonds 1,286,000 1,286,000
- ----------------------------------------------------------------------------------------------------------------------------------
DEBENTURES
July 15, 1999 7.30% 397,000 397,000
January 15, 2000 7.30% 36,000 36,000
July 15, 2001 6.25% 145,000 145,000
March 15, 2003 7.05% 150,000 150,000
March 1, 2004 7.00% 59,000 59,000
June 1, 2005 7.125% 200,000 200,000
March 1, 2007 7.50% 142,000 142,000
July 15, 2019 8.90% 420,000 420,000
November 1, 2022 9.00% 451,000 451,000
March 15, 2023 8.20% 270,000 270,000
- ----------------------------------------------------------------------------------------------------------------------------------
Total Debentures 2,270,000 2,270,000
- ----------------------------------------------------------------------------------------------------------------------------------
AUTHORITY FINANCING NOTES
Industrial Development Revenue Bonds
December 1, 2006 7.50% 1976 A,B 2,000 2,000
Pollution Control Revenue Bonds
December 1, 2006 7.50% 1976 A 27,375 28,375
December 1, 2009 7.80% 1979 B 19,100 19,100
October 1, 2012 8 1/4% 1982 17,200 17,200
March 1, 2016 3.58% 1985 A,B 150,000 150,000
Electric Facilities Revenue Bonds
September 1, 2019 7.15% 1989 A,B 100,000 100,000
June 1, 2020 7.15% 1990 A 100,000 100,000
December 1, 2020 7.15% 1991 A 100,000 100,000
February 1, 2022 7.15% 1992 A,B 100,000 100,000
August 1, 2022 6.90% 1992 C,D 100,000 100,000
November 1, 2023 3.70% 1993 A 50,000 50,000
November 1, 2023 3.70% 1993 B 50,000 50,000
October 1, 2024 3.70% 1994 A 50,000 50,000
August 1, 2025 3.70% 1995 A 50,000 50,000
December 1, 2027 3.55% 1997 A 24,880 -
- ----------------------------------------------------------------------------------------------------------------------------------
Total Authority Financing Notes 940,555 916,675
- ----------------------------------------------------------------------------------------------------------------------------------
Unamortized Discount on Debt (13,606) (14,628)
- ----------------------------------------------------------------------------------------------------------------------------------
Total 4,482,949 4,458,047
Less Current Maturities 101,000 1,000
- ----------------------------------------------------------------------------------------------------------------------------------
TOTAL LONG-TERM DEBT 4,381,949 4,457,047
- ----------------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION $ 7,606,996 $ 7,708,194
==================================================================================================================================
</TABLE>
<PAGE>
(In thousands of dollars)
December 31, 1996
- -----------------------------------------------------------
GENERAL AND REFUNDING BONDS
$ 250,000
100,000
56,000
185,000
75,000
80,000
415,000
375,000
- -----------------------------------------------------------
Total General and Refunding Bonds 1,536,000
- -----------------------------------------------------------
DEBENTURES
397,000
36,000
145,000
150,000
59,000
200,000
142,000
420,000
451,000
270,000
- -----------------------------------------------------------
Total Debentures 2,270,000
- -----------------------------------------------------------
AUTHORITY FINANCING NOTES
Industrial Development Revenue Bonds
2,000
Pollution Control Revenue Bonds
28,375
19,100
17,200
150,000
Electric Facilities Revenue Bonds 100,000
100,000
100,000
100,000
100,000
50,000
50,000
50,000
50,000
-
- -----------------------------------------------------------
Total Authority Financing Notes 916,675
- -----------------------------------------------------------
Unamortized Discount on Debt (14,903)
- -----------------------------------------------------------
Total 4,707,772
Less Current Maturities 251,000
- -----------------------------------------------------------
TOTAL LONG-TERM DEBT 4,456,772
- -----------------------------------------------------------
TOTAL CAPITALIZATION $ 7,682,305
===========================================================
See Notes to Financial Statements.
60
<PAGE>
NOTES TO FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies
Basis of Presentation
On April 11, 1997, the Company changed its year end from December 31 to March
31. Accordingly, unless otherwise indicated, references to 1998 and 1997
represent the twelve month period ended March 31, 1998 and March 31, 1997, while
references to all other periods refer to the respective calendar years ended
December 31.
As further discussed in Note 2, on June 26, 1997, the Company and the Long
Island Power Authority (LIPA) entered into definitive agreements pursuant to
which, after the transfer of the Company's gas business unit assets, non-nuclear
electric generating facility assets and certain other assets and liabilities to
one or more newly-formed subsidiaries of a new holding company, the Company's
common stock will be sold to LIPA for approximately $2.4975 billion in cash. No
adjustments have been made to the Company's financial statements to reflect this
proposed transaction.
Nature of Operations
The Company was incorporated in 1910 under the Transportation Corporations Law
of the State of New York and supplies electric and gas service in Nassau and
Suffolk Counties and to the Rockaway Peninsula in Queens County, all on Long
Island, New York. The Company's service territory covers an area of
approximately 1,230 square miles. The population of the service area, according
to the Company's 1998 Long Island Population Survey estimate, is about 2.75
million persons, including approximately 98,500 persons who reside in Queens
County within the City of New York.
The Company serves approximately 1.04 million electric customers of which
approximately 931,000 are residential. The Company receives approximately 49% of
its electric revenues from residential customers, 48% from commercial/industrial
customers and the balance from sales to other utilities and public authorities.
The Company also serves approximately 467,000 gas customers, 417,000 of which
are residential, accounting for about 61% of its gas revenues, 17,000 of which
are commercial/industrial, accounting for 23% of its gas revenues, 3,600 of
which are firm transportation customers, accounting for 3% of its gas revenues,
with the balance of the gas revenues made up by off-system sales.
The Company's geographic location and the limited electrical interconnections to
Long Island serve to limit the accessibility of the transmission grid to
potential competitors from off the system. In addition, the Company does not
expect any new major independent power producers (IPPs) or cogenerators to be
built on Long Island in the foreseeable future. One of the reasons supporting
this conclusion is based on the Company's belief that the composition and
distribution of the Company's remaining commercial and industrial customers
would make it difficult for large electric projects to operate economically.
Furthermore, under federal law, the Company is required to buy energy from
qualified producers at the Company's avoided cost. Current long-range avoided
cost estimates for the Company have significantly reduced the economic advantage
to entrepreneurs seeking to compete with the Company and with existing IPPs. For
a further discussion of the competitive issues facing the Company, see Note 12.
Regulation
The Company's accounting records are maintained in accordance with the Uniform
Systems of Accounts prescribed by the Public Service Commission of the State of
New York (PSC) and the Federal Energy Regulatory Commission (FERC). Its
financial statements reflect the ratemaking policies and actions of
61
<PAGE>
these commissions in conformity with generally accepted accounting principles
for rate-regulated enterprises.
Accounting for the Effects of Rate Regulation
General
The Company is subject to the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation". This statement recognizes the economic ability of regulators,
through the ratemaking process, to create future economic benefits and
obligations affecting rate-regulated companies. Accordingly, the Company records
these future economic benefits and obligations as regulatory assets and
regulatory liabilities, respectively.
Regulatory assets represent probable future revenues associated with previously
incurred costs that are expected to be recovered from customers. Regulatory
liabilities represent probable future reductions in revenues associated with
amounts that are expected to be refunded to customers through the ratemaking
process. Regulatory assets net of regulatory liabilities amounted to
approximately $6.7 billion at March 31, 1998, March 31, 1997 and December 31,
1996.
In order for a rate-regulated entity to continue to apply the provisions of SFAS
No. 71, it must continue to meet the following three criteria: (i) the
enterprise's rates for regulated services provided to its customers must be
established by an independent third-party regulator; (ii) the regulated rates
must be designed to recover the specific enterprise's costs of providing the
regulated services; and (iii) in view of the demand for the regulated services
and the level of competition, it is reasonable to assume that rates set at
levels that will recover the enterprise's costs can be charged to and collected
from customers.
Based upon the Company's evaluation of the three criteria discussed above in
relation to its operations, the effect of competition on its ability to recover
its costs, including its allowed return on common equity and the regulatory
environment in which the Company operates, the Company believes that SFAS No. 71
continues to apply to the Company's electric and gas operations. The Company
formed its conclusion based upon several factors including: (i) the Company's
continuing ability to earn its allowed return on common equity for both its
electric and gas operations; and (ii) the PSC's continued commitment to the
Company's full recovery of the Shoreham Nuclear Power Station (Shoreham) related
assets and all other prudently incurred costs.
Notwithstanding the above, rate regulation is undergoing significant change as
regulators and customers seek lower prices for electric and gas service. In the
event that regulation significantly changes the opportunity for the Company to
recover its costs in the future, all or a portion of the Company's operations
may no longer meet the criteria discussed above. In that event, a significant
write-down of all or a portion of the Company's existing regulatory assets and
liabilities could result. If the Company had been unable to continue to apply
the provisions of SFAS 71 at March 31, 1998, the Company would apply the
provisions of SFAS 101 "Regulated Enterprises - Accounting for the
Discontinuation of Application of FASB Statement No. 71". If SFAS 101 were
implemented, the charge to earnings could be as high as $4.5 billion, net of
tax. For additional information respecting the Company's Shoreham-related
assets, see below and Notes 4 and 10.
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of" requires that costs which were capitalized
in accordance with regulatory practices, because it was probable that future
recovery would be allowed by the regulator, must be charged against current
period earnings if it appears that the criterion for capitalization no longer
applies. The carrying amount of such assets would be reduced by amounts for
which recovery is unlikely. SFAS No. 121 also provides for
62
<PAGE>
the restoration of previously disallowed costs that are subsequently allowed by
a regulator. No impairment losses have been recognized by the Company with
respect to regulatory or other long-lived assets.
Discussed below are the Company's significant regulatory assets and regulatory
liabilities.
Base Financial Component and Rate Moderation Component
Pursuant to the 1989 Settlement, the Company recorded a regulatory asset known
as the Financial Resource Asset (FRA). The FRA is designed to provide the
Company with sufficient cash flows to assure its financial recovery. The FRA has
two components, the Base Financial Component (BFC) and the Rate Moderation
Component (RMC).
The BFC represents the present value of the future net-after-tax cash flows
which the Rate Moderation Agreement (RMA), one of the constituent documents of
the 1989 Settlement, provided the Company for its financial recovery. The BFC
was granted rate base treatment under the terms of the RMA and is included in
the Company's revenue requirements through an amortization included in rates
over a forty-year period on a straight-line basis which began July 1, 1989.
The RMC reflects the difference between the Company's revenue requirements under
conventional ratemaking and the revenues resulting from the implementation of
the rate moderation plan provided for in the RMA. The RMC is currently adjusted,
on a monthly basis, for the Company's share of certain NMP2 operations and
maintenance expenses, fuel credits resulting from the Company's electric fuel
cost adjustment clause and gross receipts tax adjustments related to the FRA.
In April 1998, the PSC authorized a revision to the Company's method for
recording its monthly RMC amortization. Prior to this revision, the amortization
of the annual level of RMC was recorded monthly on a straight-line, levelized
basis over the Company's rate year which runs from December 1 to November 30.
However, revenue requirements fluctuate from month to month based upon
consumption, which is greatly impacted by the effects of weather. Under this
revised method, effective December 1, 1997, the monthly amortization of the
annual RMC level varies based upon each month's forecasted revenue requirements,
which more closely aligns such amortization with the Company's cost of service.
As a result of this change, for the fiscal year ended March 31, 1998, the
Company recorded approximately $65.1 million more of non-cash RMC credits to
income (representing accretion of the RMC balance), or $42.5 million net of tax,
representing $.35 per share than it would have under the previous method.
However, the total RMC amortization for the rate year ending November 30, 1998,
will be equal to the amount that would have been provided for under the previous
method. As discussed in Note 2, the RMC will be acquired by LIPA as part of the
LIPA Transaction.
For a further discussion of the 1989 Settlement and FRA, see Notes 4 and 10.
Shoreham Post-Settlement Costs
Shoreham post-settlement costs consist of Shoreham decommissioning costs, fuel
disposal costs, payments-in-lieu-of-taxes, carrying charges and other costs.
These costs are being capitalized and amortized and recovered through rates over
a forty-year period on a straight-line remaining life basis which began July 1,
1989. For a further discussion of Shoreham post-settlement costs, see Note 10.
Shoreham Nuclear Fuel
Shoreham nuclear fuel principally reflects the unamortized portion of Shoreham
nuclear fuel which was reclassified from Nuclear Fuel in Process and in Reactor
at the time of the 1989 Settlement. This amount is being amortized and recovered
through rates over a forty-year period on a straight-line remaining life basis
which began July 1, 1989.
63
<PAGE>
Unamortized Cost of Issuing Securities
Unamortized cost of issuing securities represents the unamortized premiums or
discounts and expenses related to the issues of long-term debt that have been
retired prior to maturity and the costs associated with the early redemption of
those issues. In addition, this balance includes the unamortized capital stock
expense and redemption costs related to certain series of preferred stock that
have been refinanced. These costs are amortized and recovered through rates, as
provided by the PSC, over the shorter of the life of the redeemed issue or the
new issue.
Postretirement Benefits Other Than Pensions
The Company defers as a regulatory asset the difference between postretirement
benefit expense recorded in accordance with SFAS No. 106, "Employers' Accounting
for Postretirement Benefits Other Than Pensions", and postretirement benefit
expense reflected in current rates. Pursuant to a PSC order, the ongoing annual
SFAS No. 106 benefit expense was phased into and fully reflected in rates by
November 30, 1997, with the accumulated deferred asset to be recovered in rates
over the fifteen-year period which began December 1, 1997. For a further
discussion of SFAS No. 106, see Note 8.
Regulatory Tax Asset and Regulatory Tax Liability
The Company has recorded a regulatory tax asset for amounts that it will collect
in future rates for the portion of its deferred tax liability that has not yet
been recognized for ratemaking purposes. The regulatory tax asset is comprised
principally of the tax effect of the difference in the cost basis of the BFC for
financial and tax reporting purposes, depreciation differences not normalized
and the allowance for equity funds used during construction.
The regulatory tax liability is primarily attributable to deferred taxes
previously recognized at rates higher than current enacted tax law, unamortized
investment tax credits and tax credit carryforwards.
Regulatory Liability Component
Pursuant to the 1989 Settlement, certain tax benefits attributable to the
Shoreham abandonment are to be shared between electric customers and
shareowners. A regulatory liability of approximately $794 million was recorded
in June 1989 to preserve an amount equivalent to the customer tax benefits
attributable to the Shoreham abandonment. This amount is being amortized over a
ten-year period on a straight-line basis which began July 1, 1989.
1989 Settlement Credits
Represents the unamortized portion of an adjustment of the book write-off to the
negotiated 1989 Settlement amount. A portion of this amount is being amortized
over a ten-year period which began on July 1, 1989. The remaining portion is not
currently being recognized for ratemaking purposes.
Utility Plant
Additions to and replacements of utility plant are capitalized at original cost,
which includes material, labor, indirect costs associated with an addition or
replacement and an allowance for the cost of funds used during construction. The
cost of renewals and betterments relating to units of property is added to
utility plant. The cost of property replaced, retired or otherwise disposed of
is deducted from utility plant and, generally, together with dismantling costs
less any salvage, is charged to accumulated depreciation. The cost of repairs
and minor renewals is charged to maintenance expense. Mass properties (such as
poles, wire and meters) are accounted for on an average unit cost basis by year
of installation.
64
<PAGE>
Allowance for Funds Used During Construction
The Uniform Systems of Accounts as prescribed by the PSC, defines the Allowance
For Funds Used During Construction (AFC) as the net cost of borrowed funds used
for construction purposes and a reasonable rate of return upon the utility's
equity when so used. AFC is not an item of current cash income. AFC is computed
monthly using a rate permitted by the FERC on a portion of construction work in
progress. The average AFC rate, without giving effect to compounding, was as
follows:
Periods AFC Rate
------------------------ --------
12 Months Ended 3/31/98 9.29%
3 Months Ended 3/31/97 2.26%
12 Months Ended 12/31/96 9.02%
12 Months Ended 12/31/95 9.36%
Depreciation
The provisions for depreciation result from the application of straight-line
rates to the original cost, by groups, of depreciable properties in service. The
rates are determined by age-life studies performed annually on depreciable
properties. The average depreciation rate as a percentage of respective average
depreciable plant costs was as follows:
Periods Electric Gas
------- -------- ---
12 Months Ended 3/31/98 3.07% 2.04%
3 Months Ended 3/31/97 .78% .51%
12 Months Ended 12/31/96 3.00% 2.00%
12 Months Ended 12/31/95 3.00% 2.00%
Cash and Cash Equivalents
Cash equivalents are highly liquid investments with maturities of three months
or less when purchased. The carrying amount approximates fair value because of
the short maturity of these investments.
LRPP Payable
Represents the current portion of amounts due to ratepayers that result from the
revenue and expense reconciliations, performance-based incentives and associated
carrying charges as established under the LILCO Ratemaking and Performance Plan
(LRPP). For further discussion of the LRPP, see Note 4.
Fair Values of Financial Instruments
The fair values for the Company's long-term debt and redeemable preferred stock
are based on quoted market prices, where available. The fair values for all
other long-term debt and redeemable preferred stock are estimated using
discounted cash flow analyses based upon the Company's current incremental
borrowing rate for similar types of securities.
Revenues
Revenues are comprised of cycle billings rendered to customers and the accrual
of electric and gas revenues for services rendered to customers not billed at
month-end.
The Company's electric rate structure provides for a revenue reconciliation
mechanism which eliminates the impact on earnings of experiencing electric sales
that are above or below the levels reflected in rates.
The Company's gas rate structure provides for a weather normalization clause
which reduces the impact on revenues of experiencing weather which is warmer or
colder than normal.
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Fuel Cost Adjustments
The Company's electric and gas tariffs include fuel cost adjustment (FCA)
clauses which provide for the disposition of the difference between actual fuel
costs and the fuel costs allowed in the Company's base tariff rates (base fuel
costs). The Company defers these differences to future periods in which they
will be billed or credited to customers, except for base electric fuel costs in
excess of actual electric fuel costs, which are currently credited to the RMC as
incurred. Pursuant to the Stipulation, as described in Note 3, gas fuel costs
are excluded from base fuel costs and recovered through the gas fuel adjustment
clause.
Federal Income Tax
The Company provides deferred federal income tax with respect to certain items
of income and expense that are reported in different periods for federal income
tax purposes than for financial statement purposes. Additionally, the Company
provides deferred federal income tax with respect to items with different bases
for financial and tax reporting purposes, as discussed in Note 9.
The Company defers the benefit of 60% of pre-1982 gas and pre-1983 electric and
100% of all other investment tax credits, with respect to regulated properties,
when realized on its tax returns. Accumulated deferred investment tax credits
are amortized ratably over the lives of the related properties.
For ratemaking purposes, the Company provides deferred federal income tax with
respect to certain differences between income before income tax for financial
reporting purposes and taxable income for federal income tax purposes. Also,
certain accumulated deferred federal income tax is deducted from rate base and
amortized or otherwise applied as a reduction in federal income tax expense in
future years.
Reserves for Claims and Damages
Losses arising from claims against the Company, including workers' compensation
claims, property damage, extraordinary storm costs and general liability claims,
are partially self-insured. Reserves for these claims and damages are based on,
among other things, experience, risk of loss and the ratemaking practices of the
PSC. Extraordinary storm losses incurred by the Company are partially insured by
various commercial insurance carriers. These insurance carriers provide partial
insurance coverage for individual storm losses to the Company's transmission and
distribution system between $15 million and $25 million. Storm losses which are
outside of this range are self-insured by the Company.
Recent Accounting Pronouncements
Earnings Per Share
At December 31, 1997, the Company adopted SFAS No. 128, "Earnings Per Share."
This statement replaced the calculation of primary and fully diluted earnings
per share with basic and diluted earnings per share. Unlike primary earnings per
share, basic earnings per share excludes any dilutive effects of options,
warrants and convertible securities. Diluted earnings per share are very similar
to the previously reported fully diluted earnings per share. None of the
earnings per share amounts for periods presented were effected by the adoption
of SFAS No. 128.
Comprehensive Income
In June 1997, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards (SFAS) No. 130. SFAS No. 130 establishes
standards for reporting comprehensive income. Comprehensive income is the change
in the equity of a company, not including those changes that result from
shareholder transactions. All components of comprehensive income are required to
be reported in a new financial statement that is displayed with equal prominence
as existing financial statements. The Company will be required to adopt SFAS No.
130 for the year ending March 31, 1999.
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The Company does not expect that the adoption of SFAS No. 130 will have a
significant impact on its reporting and disclosure requirements.
Segment Disclosures
In June 1997, FASB issued SFAS No. 131 "Disclosures about Segments of an
Enterprise and Related Information." SFAS No. 131 establishes standards for
additional disclosure about operating segments for interim and annual financial
statements. More specifically, it requires financial information to be disclosed
for segments whose operating results are reviewed by the chief operating
decision maker for decisions on resource allocation. It also requires related
disclosures about products and services, geographic areas and major customers.
The Company will be required to adopt SFAS No. 131 for the fiscal year ending
March 31, 1999. The Company does not expect that the adoption of SFAS No. 131
will have a significant impact on its reporting and disclosure requirements.
Use of Estimates
The preparation of the financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the amounts reported in the financial statements and
accompanying notes.
Actual results could differ from those estimates.
Reclassifications
Certain prior year amounts have been reclassified in the financial statements to
conform with the current year presentation.
Note 2. Long Island Power Authority Transaction
On June 26, 1997, the Company and Long Island Power Authority (LIPA) entered
into definitive agreements pursuant to which, after the transfer of the
Company's gas business unit assets, non-nuclear electric generating facility
assets and certain other assets and liabilities to one or more newly-formed
subsidiaries of a new holding company (HoldCo), formed in connection with the
LIPA Transaction and KeySpan Transaction discussed below, the Company's common
stock will be sold to LIPA for $2.4975 billion in cash.
In connection with this transaction, the principal assets to be acquired by LIPA
through its stock acquisition of LILCO include: (i) the net book value of
LILCO's electric transmission and distribution system, which amounted to
approximately $1.3 billion at March 31, 1998; (ii) LILCO's net investment in
NMP2, which amounted to approximately $0.7 billion at March 31, 1998 (as more
fully discussed in Note 5); (iii) certain of LILCO's regulatory assets
associated with its electric business; and (iv) allocated accounts receivable
and other assets. The regulatory assets to be acquired by LIPA amounted to
approximately $6.6 billion at March 31, 1998, and primarily consist of the Base
Financial Component (BFC), Rate Moderation Component (RMC), Shoreham
post-settlement costs, Shoreham nuclear fuel, and the electric portion of the
regulatory tax asset. For a further discussion of these regulatory assets, see
Note 1.
LIPA is contractually responsible for reimbursing HoldCo for postretirement
benefits other than pension costs related to employees of LILCO's electric
business. Accordingly, upon consummation of the transaction, HoldCo will
reclassify the associated regulatory asset for postretirement benefits other
than pensions to a contractual receivable.
The principal liabilities to be assumed by LIPA through its stock acquisition of
LILCO include: (i) LILCO's regulatory liabilities associated with its electric
business; (ii) allocated accounts payable, customer deposits, other deferred
credits and claims and damages; and (iii) certain series of long-term
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debt. The regulatory liabilities to be assumed by LIPA amounted to approximately
$365 million at March 31, 1998, and primarily consist of the regulatory
liability component, 1989 Settlement credits and the electric portion of the
regulatory tax liability. For a further discussion of these regulatory
liabilities, see Note 1 of Notes to Financial Statements.
The long-term debt to be assumed by LIPA will consist of: (i) all amounts then
outstanding under the General and Refunding (G&R) Indentures; (ii) all amounts
then outstanding under the Debenture Indentures, except as noted below; and
(iii) substantially all of the tax-exempt authority financing notes. HoldCo is
required to assume the financial obligation associated with the 7.30% Debentures
due July 15, 1999, with an aggregate principal amount currently outstanding of
$397 million and 8.20% Debentures due March 15, 2023, with an aggregate
principal amount currently outstanding of $270 million. HoldCo will seek to
exchange its Debentures, with identical terms, for these two series of
Debentures and will issue a promissory note to LIPA in an amount equal to the
unexchanged amount of such Debentures. HoldCo will also issue a promissory note
to LIPA for a portion of the tax-exempt debt borrowed to support LILCO's current
gas operations, with terms identical to those currently outstanding. The Company
currently estimates the amount of this promissory note to be approximately $250
million.
In July 1997, in accordance with the provisions of the LIPA Transaction, the
Company and The Brooklyn Union Gas Company (Brooklyn Union) formed a limited
partnership and each Company invested $30 million in order to purchase an
interest rate swap option instrument to protect LIPA against market risk
associated with the municipal bonds expected to be issued by LIPA to finance the
transaction. Upon the closing of the LIPA Transaction, each limited partner will
receive from LIPA $30 million plus interest thereon, based on each partners'
average weighted cost of capital. In the event that the LIPA Transaction is not
consummated, the maximum potential loss to the Company is the amount originally
invested. In such event, the Company plans to defer any loss and petition the
PSC to allow recovery from its customers.
As part of the LIPA Transaction, the definitive agreements contemplate that one
or more subsidiaries of HoldCo will enter into agreements with LIPA, pursuant to
which such subsidiaries will provide management and operations services to LIPA
with respect to the electric transmission and distribution system, deliver power
generated by its power plants to LIPA, and manage LIPA's fuel and electric
purchases and any off-system electric sales. In addition, three years after the
LIPA Transaction is consummated, LIPA will have the right for a one-year period
to acquire all of HoldCo's generating assets at the fair market value at the
time of the exercise of the right, which value will be determined by independent
appraisers.
In July 1997, the New York State Public Authorities Control Board (PACB),
created pursuant to the New York State Public Authorities Law and consisting of
five members appointed by the governor, unanimously approved the definitive
agreements related to the LIPA Transaction subject to the following conditions:
(i) within one year of the effective date of the transaction, LIPA must
establish a plan for open access to the electric distribution system; (ii) if
LIPA exercises its option to acquire the generation assets of HoldCo's
generation subsidiary, LIPA may not purchase the generating facilities, as
contemplated in the generation purchase right agreement, at a price greater than
book value; (iii) HoldCo must agree to invest, over a ten-year period, at least
$1.3 billion in energy-related and economic development projects, and natural
gas infrastructure projects on Long Island; (iv) LIPA will guarantee that, over
a ten-year period, average electric rates will be reduced by no less than 14%
when measured against the Company's rates today and no less than a 2% cost
savings to LIPA customers must result from the savings attributable to the
merger of LILCO and KeySpan; and (v) LIPA will not increase average electric
customer rates by more than
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2.5% over a twelve-month period without approval from the PSC. LIPA has adopted
the conditions set forth by the PACB.
The holders of common and certain series of preferred stock of the Company
eligible to vote approved the LIPA Transaction in August 1997.
In December 1997, the United States Nuclear Regulatory Commission (NRC) issued
an order approving the indirect transfer of control of the Company's 18%
ownership interest in NMP2 to LIPA.
In December 1997, the Company filed with the FERC a settlement agreement reached
with LIPA in connection with a previous filing of the Company's proposed rates
for the sale of capacity and energy to LIPA, as contemplated in the LIPA
transaction agreements. The Company also had previously filed an application
with the FERC seeking approval of the transfer of the Company's electric
transmission and distribution system to LIPA in connection with LIPA's purchase
of the common stock of the Company.
In February 1998, the FERC issued orders on both of the Company filings.
Specifically, the FERC approved the Company's application to transfer assets to
LIPA in connection with LIPA's acquisition of the Company's common stock. In
addition, the FERC accepted the Company's proposed rates for sale of capacity
and energy to LIPA. Those rates may go into effect on the date the service to
LIPA begins, subject to refund, and final rates will be set after the FERC has
completed its investigation of such rates, the timing of which cannot be
determined at this time.
In January 1998, the Company filed an application with the PSC in connection
with the proposed transfer of its gas business unit assets, non-nuclear
generating facility assets and certain other assets and related liabilities to
one or more subsidiaries of HoldCo to be formed as contemplated in the LIPA
Transaction agreements. On April 29, 1998, the PSC approved the transfer of the
above-mentioned assets.
In July 1997, the Company, Brooklyn Union and LIPA filed requests for private
letter rulings with the Internal Revenue Service (IRS) regarding certain federal
income tax issues which require favorable rulings in order for the LIPA
Transaction to be consummated. On March 4, 1998, the IRS issued a private letter
ruling confirming that the sale of the Company's common stock to LIPA would not
result in a corporate tax liability to the Company. In addition, the IRS ruled
that, after the stock sale, the income of LIPA's electric utility business will
not be subject to federal income tax. In a separate ruling on February 27, 1998,
the IRS also ruled that the bonds to be issued by LIPA to finance the
acquisition would be tax-exempt.
In January 1998, the Company filed an application with the SEC seeking an
exception for most of the provisions of the Public Utilities Holding Company Act
of 1935. In May 1998, the SEC issued an order approving the Company's
application.
The Company currently anticipates that the LIPA transaction will be consummated
by June 30, 1998.
Note 3. KeySpan Energy Corporation Transaction
On December 29, 1996, The Brooklyn Union Gas Company (Brooklyn Union) and the
Company entered into an Agreement and Plan of Exchange and Merger (Share
Exchange Agreement), pursuant to which the companies will be merged in a
transaction (KeySpan Transaction) that will result in the formation of HoldCo.
The Share Exchange Agreement was amended and restated to reflect certain
technical changes as of February 7, 1997 and June 26, 1997. Effective September
29, 1997, Brooklyn Union reorganized into a
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holding company structure, with KeySpan Energy Corporation (KeySpan) becoming
its parent holding company. Accordingly, the parties entered into an Amendment,
Assignment and Assumption Agreement, dated as of September 29, 1997, which among
other things, amended the Share Exchange Agreement and related stock option
agreements to reflect the assignment by Brooklyn Union to KeySpan and the
assumption by KeySpan of all Brooklyn Union's rights and obligations under such
agreements.
The KeySpan Transaction, which has been approved by both companies' boards of
directors and shareholders, would unite the resources of the Company with the
resources of KeySpan. KeySpan, with approximately 3,300 employees, distributes
natural gas at retail, primarily in a territory of approximately 187 square
miles which includes the boroughs of Brooklyn and Staten Island and two-thirds
of the borough of Queens, all in New York City. KeySpan has energy-related
investments in gas exploration, production and marketing in the United States
and Northern Ireland, as well as energy services in the United States, including
cogeneration projects, pipeline transportation and gas storage.
Under the terms of the KeySpan Transaction, the Company's common shareowners
will receive .803 shares (the Ratio) of HoldCo's common stock for each share of
the Company's common stock that they currently hold. KeySpan common shareowners
will receive one share of common stock of HoldCo for each common share of
KeySpan they currently hold. Shareowners of the Company will own approximately
66% of the common stock of HoldCo while KeySpan shareowners will own
approximately 34%. In the event that the LIPA Transaction is consummated, the
Ratio will be 0.880 with Company shareowners owning approximately 68% of the
HoldCo common stock. Based on current facts and circumstances, it is probable
that the purchase method of accounting will apply to the KeySpan Transaction,
with the Company being the acquiring company for accounting purposes.
Consummation of the Share Exchange Agreement is not conditioned upon the
consummation of the LIPA Transaction and consummation of the LIPA Transaction is
not conditioned upon consummation of the Share Exchange Agreement.
In March 1997, the Company filed an application with the FERC seeking approval
of the transfer of the Company's common equity and certain FERC-jurisdictional
assets to HoldCo. On July 17, 1997, the FERC granted such approval.
The Share Exchange Agreement contains certain covenants of the parties pending
the consummation of the transaction. Generally, the parties must carry on their
businesses in the ordinary course consistent with past practice, may not
increase dividends on common stock beyond specified levels and may not issue
capital stock beyond certain limits. The Share Exchange Agreement also contains
restrictions on, among other things, charter and by-law amendments, capital
expenditures, acquisitions, dispositions, incurrence of indebtedness, certain
increases in employee compensation and benefits, and affiliate transactions.
Upon completion of the merger, Dr. William J. Catacosinos will become chairman
and chief executive officer of HoldCo; Mr. Robert B. Catell, currently chairman
and chief executive officer of KeySpan, will become president and chief
operating officer of HoldCo. One year after the closing, Mr. Catell will succeed
Dr. Catacosinos as chief executive officer, with Dr. Catacosinos continuing as
chairman. The board of directors of HoldCo will be comprised of 15 members, six
from the Company, six from KeySpan and three additional persons previously
unaffiliated with either company.
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In March 1997, the Company and the Brooklyn Union Gas Company (Brooklyn Union)
filed a joint petition with the PSC seeking approval, under section 70 of the
New York Public Service Law, of the KeySpan Agreement by which the Company and
KeySpan each would become subsidiaries of HoldCo through an exchange of shares
of common stock with HoldCo. In addition, the petition called for approximately
$1.0 billion of savings attributable to operating synergies that are expected to
be realized over the 10-year period following the combination to be allocated to
customers, net of transaction costs for the combination. On December 10, 1997,
Brooklyn Union, the Company, the Staff of the PSC and three other parties
entered into a Settlement Agreement (Stipulation) resolving all issues among
them in the proceeding. Hearings on the Stipulation were held in early January
1998 and, on February 4, 1998, the PSC approved, effective February 5, 1998, the
Stipulation, modified only to reduce Brooklyn Union's earnings cap for the
remaining years of its rate plan.
Under the Stipulation, a three-year gas rate plan covering the period December
1, 1997 through November 30, 2000 will be implemented by the Company which
provides for, among other things, an estimated reduction in customers' bills of
approximately 3.9%, including fuel savings, through at least November 30, 2000.
This gas rate reduction will occur in three phases as follows: (i) a reduction
in base rates of approximately $12.2 million to reflect decreases in the
Company's gas cost of service effective on February 5, 1998; (ii) a base rate
reduction of approximately $6.2 million associated with non-fuel savings related
to the KeySpan Transaction to become effective on the closing date of the
transaction; and (iii) an expected reduction in the Gas Adjustment Clause (GAC)
to reflect annual fuel savings associated with the transaction estimated at
approximately $4.0 million, the actual level of which will be reflected in rates
if and when they actually materialize. The Company will be subject to an
earnings sharing provision pursuant to which it will be required to credit to
core/firm customers 60% of any utility earnings up to 100 basis points above
11.10% and 50% of any utility earnings in excess of 12.10% of the allowed return
on common equity. Both a customer service and a safety and reliability incentive
performance program will be implemented effective December 1, 1997, with maximum
pre-tax return on equity penalties of 40 and 12 basis points, respectively, if
the Company fails to achieve certain performance standards in these areas.
The Stipulation, which obligates the Company to reduce electric customers' bills
by approximately 2.5% resulting from the savings in operating and fuel costs,
related to synergy savings, also defers the time within which the PSC must act
on the Company's pending electric rate plan until July 1, 1998. However, any
reduction in customers' bills would not become effective until the PSC sets the
Company's electric rates.
For Brooklyn Union, effective on the date of the consummation of the KeySpan
Transaction, Brooklyn Union's base rates to core/firm customers will be reduced
by $23.9 million annually. In addition, effective in the fiscal year in which
the KeySpan Transaction is consummated, Brooklyn Union will be subject to an
earnings sharing provision pursuant to which it will be required to credit to
core/firm customers 60% of any utility earnings up to 100 basis points above
certain threshold equity return levels over the term of the rate plan (other
than any earnings associated with discrete incentives) and 50% of any utility
earnings in excess of 100 basis points above such threshold levels. The
threshold levels, as modified by the February 5, 1998 Order, are 13.75% for
fiscal year 1998, 13.50% for fiscal years 1999,
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2000, and 2001; and 13.25% for fiscal year 2002. A safety and reliability
incentive mechanism will be implemented effective on the consummation date of
the KeySpan Transaction, with a maximum 12 basis point pre-tax penalty return on
common equity if Brooklyn Union fails to achieve certain safety and reliability
performance standards. With the exception of the simplification of the customer
service performance standards, the current Brooklyn Union rate plan approved by
the PSC in 1996 remains unchanged. Any gas cost savings allocable to Brooklyn
Union resulting from the KeySpan Transaction will be reflected in rates to
utility customers through the GAC as those savings are realized.
The Stipulation adopts certain affiliate transaction restrictions, cost
allocation and financial integrity conditions, and a competitive code of
conduct. These restrictions and conditions eliminate or relax many restrictions
currently applicable to Brooklyn Union in such areas as affiliate transactions,
use of the name and reputation of Brooklyn Union by unregulated affiliates,
common officers of HoldCo, the utility subsidiaries and unregulated
subsidiaries, dividend payment restrictions, and the composition of the Board of
Directors of Brooklyn Union.
The Stipulation also enables the utilities to form one or more shared services
subsidiaries to perform functions common to both utilities and their affiliates
such as accounting, finance, human resources, legal and information systems and
technology to realize synergy savings.
Note 4. Rate Matters
Electric
In April 1996, the PSC issued an order directing the Company to file financial
and other information sufficient to provide a legal basis for setting new rates
for the three-year period 1997 through 1999. In compliance with the order, the
Company submitted a multi-year rate plan (Plan) in September 1996. Major
elements of the Plan include: (i) a base rate freeze for the three-year period
December 1, 1996 through November 30, 1999; (ii) an allowed return on common
equity of 11.0% through the term of the Plan with the Company fully retaining
all earnings up to 12.66%, and sharing with the customer any earnings above
12.66%; (iii) the continuation of existing LRPP revenue and expense
reconciliation mechanisms and performance incentive programs; (iv) crediting all
net proceeds from the Shoreham property tax litigation to the RMC to reduce its
balance; and (v) a mechanism to fully recover any outstanding RMC balance at the
end of the 1999 rate year through inclusion in the FCA, over a two-year period.
Pursuant to the provisions of the Stipulation discussed above, under the heading
KeySpan Energy Corporation Transaction, the PSC has until July 1, 1998 to render
a decision on this filing.
As an interim measure, pending the consummation of the LIPA Transaction or the
adjudication of its electric rate filing, the Company submitted petitions in May
1997 and December 1997 requesting PSC approval to extend, through the rate years
ending November 30, 1996 and 1997, respectively, the provisions of its 1995
electric rate order (1995 Order). These petitions were approved by the PSC in
December 1997 and April 1998, respectively.
1995 Electric Rate Order
The basis of the 1995 Order included minimizing future electric rate increases
while continuing to provide for the recovery of the Company's regulatory assets
and retaining consistency with the RMA's objective of restoring the Company to
financial health. The 1995 Order, which became effective December 1, 1994, froze
base electric rates, reduced the Company's allowed return on common equity from
11.6% to 11.0% and modified or eliminated certain performance based incentives,
as discussed below.
The LRPP, originally approved by the PSC in November 1991, contained three major
components: (i) revenue reconciliation; (ii) expense attrition and
reconciliation; and, (iii) performance-based incentives.
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In the 1995 Order, the PSC continued the three major components of the LRPP with
modifications to the expense attrition and reconciliation mechanism and the
performance-based incentives. The revenue reconciliation mechanism remains
unchanged.
Revenue reconciliation provides a mechanism that eliminates the impact of
experiencing sales that are above or below adjudicated levels by providing a
fixed annual net margin level (defined as sales revenues, net of fuel expenses
and gross receipts taxes). The difference between actual and adjudicated net
margin levels are deferred on a monthly basis during the rate year.
The expense attrition and reconciliation component permits the Company to make
adjustments for certain expenses recognizing that these cost increases are
unavoidable due to inflation and changes outside the control of the Company.
Pursuant to the 1995 Order, the Company is permitted to reconcile expenses for
property taxes only, whereas under the original LRPP the Company was able to
reconcile expenses for wage rates, property taxes, interest costs and demand
side management (DSM) costs.
The original LRPP had also provided for the deferral and amortization of certain
cost variances for enhanced reliability, production operations and maintenance
expenses and the application of an inflation index to other expenses. Under the
1995 Order, these deferrals have been eliminated and any unamortized balances
were credited to the RMC during 1995.
The modified performance-based incentive programs include the DSM program, the
customer service performance program and the transmission and distribution
reliability program. Under these revised programs, the Company was subject to a
maximum penalty of 38 basis points of the allowed return on common equity and
could earn up to 4 basis points under the customer service program. Pursuant to
the Stipulation, the Company's customer service incentive program was further
modified to eliminate the 4 basis point reward and increased the maximum penalty
which can be incurred under the these programs from 38 to 62 basis points.
The partial pass-through fuel incentive program remains unchanged. Under this
incentive, the Company can earn or forfeit up to 20 basis points of the allowed
return on common equity.
For the rate year ended November 30, 1997, the Company earned 12.7 basis points,
or approximately $2.9 million, net of tax effects, as a result of its
performance under all incentive programs. For the rate years ended November 30,
1996 and 1995, the Company earned 20 and 19 basis points, respectively, or
approximately $4.3 million and $4.0 million, respectively, net of tax effects,
under the incentive programs in effect at those times.
The deferred balances resulting from the net margin and expense reconciliations,
and earned performance-based incentives are netted at the end of each rate year,
as established under the LRPP and continued under the 1995 Order. The first $15
million of the total deferral is recovered from or credited to ratepayers by
increasing or decreasing the RMC balance. Deferrals in excess of the $15
million, upon approval of the PSC, are refunded to or recovered from the
customers through the FCA mechanism over a 12-month period.
For the rate year ended November 30, 1997, the amount to be returned to
customers resulting from the revenue and expense reconciliations,
performance-based incentive programs and associated carrying charges totaled
$4.1 million. Consistent with the mechanics of the LRPP, it is anticipated that
the entire balance of the deferral will be used to reduce the RMC balance upon
approval by the PSC of the Company's reconciliation filing which was submitted
to the PSC in March 1998. For the rate year ended November 30, 1996, the Company
recorded a net deferred LRPP credit of approximately $14.5 million
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which was subsequently applied as a reduction to the RMC upon the PSC's approval
of the Company's reconciliation filing in December 1996. For the rate year ended
November 30, 1995, the Company recorded a net deferred credit of approximately
$41 million. The first $15 million of the deferral was applied as a reduction to
the RMC while the remaining portion of the deferral of $26 million will be
returned to customers through the FCA when approved by the PSC.
Another mechanism of the LRPP provides that earnings in excess of the allowed
return on common equity, excluding the impacts of the various incentive and/or
penalty programs, are used to reduce the RMC. For the rate years ended November
30, 1997, 1996 and 1995, the Company earned $4.8 million, $9.1 million, and $6.2
million, respectively, in excess of its allowed return on common equity. These
excess earnings were applied as reductions to the RMC.
In the event that the LIPA Transaction is not consummated, the Company is
currently unable to predict the outcome of the electric rate proceeding
currently before the PSC and its effect, if any, on the Company's financial
position, cash flows or results of operations.
Gas
In May 1997, the Company submitted a petition requesting PSC approval to extend
through the rate year ending November 30, 1997, the gas excess earnings sharing
mechanism established in its prior three-year gas rate settlement agreement
which expired on November 30, 1996. Pursuant to this request, earnings in excess
of a return on common equity of 11.0% are to be allocated equally between
customers and shareowners with the customers' share of excess earnings credited
to the regulatory asset created as a result of costs associated with
manufactured gas plant (MGP) site investigation and remediation costs. This
request was approved by the PSC in December 1997. As a result of this mechanism,
the customer's allocation of excess earnings amounted to $6.3 million for the
rate year ended November 30, 1997, and will be applied to offset costs incurred
to investigate and remediate MGP sites. The prior gas rate settlement provided
that earnings in excess of a 10.6% return on common equity be shared equally
between the Company's firm gas customers and its shareowners. For the rate years
ended November 30, 1996 and 1995, the firm gas customers' portion of gas excess
earnings totaled approximately $10 million and $1 million, respectively. In
1997, the Company was granted permission by the PSC to apply the customers'
portion of the gas excess earnings and associated carrying charges for the 1996
and 1995 rate years to the recovery of deferred costs associated with
post-retirement benefits other than pensions and costs incurred for
investigation and remediation of MGP sites.
Note 5. Nine Mile Point Nuclear Power Station, Unit 2
The Company has an undivided 18% interest in NMP2, located near Oswego, New York
which is operated by Niagara Mohawk Power Corporation (NMPC). The owners of NMP2
and their respective percentage ownership are as follows: the Company (18%),
NMPC (41%), New York State Electric & Gas Corporation (18%), Rochester Gas and
Electric Corporation (14%) and Central Hudson Gas & Electric Corporation (9%).
The Company's share of the rated capability is approximately 205 MW. The
Company's net utility plant investment, excluding nuclear fuel, was
approximately $689 million at March 31, 1998, $710 million at March 31, 1997 and
$715 million at December 31, 1996. The accumulated provision for depreciation,
excluding decommissioning costs, was approximately $196 million and $175 million
at March 31, 1998 and 1997, respectively, and $169 million at December 31, 1996.
Generation from NMP2 and operating expenses incurred by NMP2 are shared in the
same proportions as the cotenants' respective ownership interests. The Company
is required to provide its respective share of financing for any capital
additions to NMP2. Nuclear fuel costs associated with NMP2 are being amortized
on the basis of the quantity of heat produced for the generation of electricity.
74
<PAGE>
NMPC has contracted with the United States Department of Energy for the disposal
of spent nuclear fuel. The Company reimburses NMPC for its 18% share of the cost
under the contract at a rate of $1.00 per megawatt hour of net generation less a
factor to account for transmission line losses. For the year ended March 31,
1998 and for the three months ended March 31, 1997, this totaled $1.4 million
and $0.4 million, respectively. For the years ended December 31, 1996 and 1995,
this totaled $1.4 million and $1.2 million, respectively. As discussed in Note
2, the LIPA Transaction contemplates that LIPA will acquire the Company's 18%
interest in NMP2.
Nuclear Plant Decommissioning
NMPC expects to commence the decommissioning of NMP2 in 2026, shortly after the
cessation of plant operations, using a method which provides for the removal of
all equipment and structures and the release of the property for unrestricted
use. The Company's share of decommissioning costs, based upon a "Site-Specific"
1995 study (1995 study), is estimated to be $309 million in 2026 dollars ($155
million in 1998 dollars). The Company's share of the estimated decommissioning
costs is currently being provided for in electric rates and is being charged to
operations as depreciation expense over the service life of NMP2. The amount of
decommissioning costs recorded as depreciation expense for the year ended March
31, 1998 and the three months ended March 31, 1997, totaled $2.2 million and
$0.5 million, respectively, and $3.9 million and $2.3 million for the years
ended December 31, 1996 and 1995, respectively. The accumulated decommissioning
costs collected in rates through March 31, 1998 and 1997 and December 31, 1996
amounted to $17.7 million, $15.5 million and $14.9 million, respectively.
The Company has established trust funds for the decommissioning of the
contaminated portion of the NMP2 plant. It is currently estimated that the cost
to decommission the contaminated portion of the plant will be approximately 76%
of the total decommissioning costs. These funds comply with regulations issued
by the NRC and the FERC governing the funding of nuclear plant decommissioning
costs. The Company's policy is to make quarterly contributions to the funds
based upon the amount of decommissioning costs reflected in rates. As of March
31, 1998, the balance in these funds, including reinvested net earnings, was
approximately $17.9 million. These amounts are included on the Company's Balance
Sheet in Nonutility Property and Other Investments. The trust funds investment
consists of U.S. Treasury debt securities and cash equivalents. The carrying
amounts of these instruments approximate fair market value.
The FASB issued an exposure draft in 1996 entitled "Accounting for Certain
Liabilities Related to Closure or Removal of Long-Lived Assets." Under the
provisions of the exposure draft, the Company would be required to change its
current accounting practices for decommissioning costs as follows: (i) the
Company's share of the total estimated decommissioning costs would be accounted
for as a liability, based on discounted future cash flows; (ii) the recognition
of the liability for decommissioning costs would result in a corresponding
increase to the cost of the nuclear plant rather than as depreciation expense;
and (iii) investment earnings on the assets dedicated to the external
decommissioning trust fund would be recorded as investment income rather than as
an increase to accumulated depreciation. Discussions of the issues expressed in
the exposure draft are ongoing. If the Company was required to record the
present value of its share of NMP2 decommissioning costs on its Balance Sheet as
of March 31, 1998, the Company would have to recognize a liability and
corresponding increase to nuclear plant of approximately $62 million. Upon
consummation of the LIPA Transaction, LIPA will acquire the Company's interest
in NMP2 as well as the trusts referred to above.
Nuclear Plant Insurance
NMPC procures public liability and property insurance for NMP2, and the Company
reimburses NMPC for its 18% share of those costs.
75
<PAGE>
The Price-Anderson Amendments Act mandates that nuclear power plants secure
financial protection in the event of a nuclear accident. This protection must
consist of two levels. The primary level provides liability insurance coverage
of $200 million (the maximum amount available) in the event of a nuclear
accident. If claims exceed that amount, a second level of protection is provided
through a retrospective assessment of all licensed operating reactors.
Currently, this "secondary financial protection" subjects each of the 110
presently licensed nuclear reactors in the United States to a retrospective
assessment of up to $76 million for each nuclear incident, payable at a rate not
to exceed $10 million per year. The Company's interest in NMP2 could expose it
to a maximum potential loss of $13.6 million, per incident, through assessments
of $1.8 million per year in the event of a serious nuclear accident at NMP2 or
another licensed U.S. commercial nuclear reactor. These assessments are subject
to periodic inflation indexing and to a 5% surcharge if funds prove insufficient
to pay claims.
NMPC has also procured $500 million primary nuclear property insurance with the
Nuclear Insurance Pools and approximately $2.3 billion of additional protection
(including decontamination costs) in excess of the primary layer through Nuclear
Electric Insurance Limited (NEIL). Each member of NEIL, including the Company,
is also subject to retrospective premium adjustments in the event losses exceed
accumulated reserves. For its share of NMP2, the Company could be assessed up to
approximately $1.6 million per loss. This level of insurance is in excess of the
NRC required $1.06 billion of coverage.
The Company has obtained insurance coverage from NEIL for the extra expense
incurred in purchasing replacement power during prolonged accidental outages.
Under this program, should losses exceed the accumulated reserves of NEIL, each
member, including the Company, would be liable for its share of deficiency. The
Company's maximum liability per incident under the replacement power coverage,
in the event of a deficiency, is approximately $0.7 million.
Note 6. Capital Stock
Common Stock
Currently the Company has 150,000,000 shares of authorized common stock, of
which 121,727,040 were issued and 46,281 shares were held in Treasury at March
31, 1998. The Company has 1,644,865 shares reserved for sale through its
Employee Stock Purchase Plan, 2,829,968 shares committed to the Investor Common
Stock Plan and 86,099 shares reserved for conversion of the Series I Convertible
Preferred Stock at a rate of $17.15 per share. In addition, in connection with
the Share Exchange Agreement, as discussed in Note 3, the Company has granted
KeySpan the option to purchase, under certain circumstances, 23,981,964 shares
of common stock at a price of $19.725 per share. In connection with such option,
the Company has received shareowner approval to increase the authorized shares
of common stock to 160,000,000.
Preferred Stock
The Company has 7,000,000 authorized shares, cumulative preferred stock, par
value $100 per share and 30,000,000 authorized shares, cumulative preferred
stock, par value $25 per share. Dividends on preferred stock are paid in
preference to dividends on common stock or any other stock ranking junior to
preferred stock.
Preferred Stock Subject to Mandatory Redemption
The aggregate fair value of redeemable preferred stock with mandatory
redemptions at March 31, 1998 and 1997 and December 31, 1996 amounted to
approximately $675, $643 and $637 million, respectively, compared to their
carrying amounts of $639, $640 and $640 million, respectively. For a further
discussion on the basis of the fair value of the securities discussed above, see
Note 1.
76
<PAGE>
Each year the Company is required to redeem certain series of preferred stock
through the operation of sinking fund provisions as follows:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
Series Redemption Provision Number of Shares Redemption Amounts
Beginning Ending
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
6.875% Series UU 10/15/99 10/15/19 112,000 $2,800,000
=============================================================================================================
</TABLE>
The aggregate par value of preferred stock required to be redeemed through
sinking funds during the fiscal year ended March 31, is $2.8 million in each of
the years 2000, 2001, 2002 and 2003. The Company also has the non-cumulative
option to double the number of shares to be redeemed pursuant to the sinking
fund provisions in any year for the preferred stock series UU.
The Company is also required to redeem all shares of certain series of preferred
stock which are not subject to sinking fund requirements. The mandatory
redemption requirements for these series are as follows:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------
Series Redemption Date Number of Shares Redemption Amounts
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
$1.67 Series GG 3/1/99 880,000 $ 22,000,000
7.95% Series AA 6/1/00 14,520,000 363,000,000
7.05% Series QQ 5/1/01 3,464,000 86,600,000
7.66% Series CC 8/1/02 570,000 57,000,000
============================================================================================================
</TABLE>
Preferred Stock Subject to Optional Redemption
The Company has the option to redeem certain series of its preferred stock. For
the series subject to optional redemption at March 31, 1998, the call prices
were as follows:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------
Series Call Price Redemption Amounts
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C>
5.00% Series B $101.00 $10,100,000
4.25% Series D 102.00 7,140,000
4.35% Series E 102.00 20,400,000
4.35% Series F 102.00 5,100,000
5 1/8% Series H 102.00 20,400,000
5 3/4% Series I - Convertible 100.00 1,474,300
7.40% Series L 102.07 15,361,535
$1.95 Series NN 26.95 41,880,300
===========================================================================================================
</TABLE>
On April 17, 1998, the Company exercised its option to redeem its callable
preferred stock and called for redemption on May 19, 1998 all of the outstanding
shares of the preferred stock series noted above for a total of $122 million
including approximately $5 million of call premiums.
Preference Stock
At March 31, 1998, none of the authorized 7,500,000 shares of nonparticipating
preference stock, par value $1 per share, which ranks junior to preferred stock,
were outstanding.
Note 7. Long-Term Debt
G&R Mortgage
The General and Refunding (G&R) Bonds are the Company's only outstanding secured
indebtedness. The G&R Mortgage is a lien on substantially all of the Company's
properties.
The annual G&R Mortgage sinking fund requirement for 1997, due not later than
June 30, 1998, is estimated at $25 million. It is anticipated that this
requirement will be satisfied with retired G&R Bonds, property additions, or any
combination thereof.
77
<PAGE>
Upon consummation of the LIPA Transaction, all of the Company's series of G&R
Bonds will be assumed by LIPA. LIPA has indicated that it intends to redeem all
such G&R Bonds as soon as practicable after the closing of the LIPA Transaction.
1989 Revolving Credit Agreement
The Company has available through October 1, 1998, $250 million under its 1989
Revolving Credit Agreement (1989 RCA). This line of credit is secured by a first
lien upon the Company's accounts receivable and fuel oil inventories. In
February 1997, the Company utilized $30 million in interim financing under the
1989 RCA, which was repaid in March 1997, and $40 million in July 1997, which
was repaid in August 1997. At March 31, 1998, no amounts were outstanding under
the 1989 RCA. The Company has filed, with the lending institutions, the
documentation necessary to terminate the 1989 RCA effective upon the closing of
the LIPA and KeySpan Transactions.
Authority Financing Notes
Authority Financing Notes are issued by the Company to the New York State Energy
Research and Development Authority (NYSERDA) to secure certain tax-exempt
Industrial Development Revenue Bonds, Pollution Control Revenue Bonds (PCRBs)
and Electric Facilities Revenue Bonds (EFRBs) issued by NYSERDA. Certain of
these bonds are subject to periodic tender, at which time their interest rates
may be subject to redetermination.
Tender requirements of Authority Financing Notes at March 31, 1998 were as
follows:
<TABLE>
<CAPTION>
(In thousands of dollars)
- --------------------------------------------------------------------------------------------------------------
Interest Rate Series Principal Tendered
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
PCRBs 8 1/4% 1982 $ 17,200 Tendered every three years, next tender October 2000
3.58% 1985 A,B 150,000 Tendered annually on March 1
EFRBs 3.70% 1993 A 50,000 Tendered weekly
3.70% 1993 B 50,000 Tendered weekly
3.70% 1994 A 50,000 Tendered weekly
3.70% 1995 A 50,000 Tendered weekly
3.55% 1997 A 24,880 Tendered weekly
==============================================================================================================
</TABLE>
The 1997, 1995, 1994 and 1993 EFRBs and the 1985 PCRBs are supported by letters
of credit pursuant to which the letter of credit banks have agreed to pay the
principal, interest and premium, if applicable, in the aggregate, up to
approximately $408 million in the event of default. The obligation of the
Company to reimburse the letter of credit banks is unsecured.
The expiration dates for these letters of credit are as follows:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
Series Expiration Date
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C>
PCRBs 1985 A,B 3/16/99
EFRBs 1993 A,B 11/17/99
1994 A 10/26/00
1995 A 8/24/98
1997 A 12/30/98
=================================================================================================================
</TABLE>
Prior to expiration, the Company is required to obtain either an extension of
the letters of credit or a substitute credit facility. If neither can be
obtained, the authority financing notes supported by letters of credit must be
redeemed.
In accordance with the LIPA Agreement, LIPA will assume substantially all of the
tax-exempt authority financing notes. HoldCo will issue a promissory note to
LIPA for a portion of the tax-exempt debt borrowed to support LILCO's current
gas operations, with terms identical to those currently outstanding. The Company
currently estimates the amount of this promissory note to be approximately $250
million.
78
<PAGE>
Fair Values of Long-Term Debt
The carrying amounts and fair values of the Company's long-term debt at March
31, 1998 and 1997 and December 31, 1996 were as follows:
<TABLE>
<CAPTION>
Fair Value (In thousands of dollars)
- -----------------------------------------------------------------------------------------------------------------
March 31, 1998 March 31, 1997 December 31, 1996
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
General and Refunding Bonds $1,288,470 $1,314,273 $1,571,745
Debentures 2,407,178 2,256,573 2,271,095
Authority Financing Notes 987,646 959,092 950,758
=================================================================================================================
Total $4,683,294 $4,529,938 $4,793,598
=================================================================================================================
Carrying Amount (In thousands of dollars)
- -----------------------------------------------------------------------------------------------------------------
March 31, 1998 March 31, 1997 December 31, 1996
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
General and Refunding Bonds $1,286,000 $1,286,000 $1,536,000
Debentures 2,270,000 2,270,000 2,270,000
Authority Financing Notes 940,555 916,675 916,675
=================================================================================================================
Total $4,496,555 $4,472,675 $4,722,675
=================================================================================================================
</TABLE>
For a further discussion on the basis of the fair value of t securities listed
above, see Note 1.
Debt Maturity Schedule
The total long-term debt maturing in each of the next five years ending March 31
is as follows: 1999, $101 million; 2000, $490 million; 2001, $1 million; 2002,
$146 million; and 2003, $154 million.
Note 8. Retirement Benefit Plans
Pension Plans
The Company maintains a defined benefit pension plan which covers substantially
all employees (Primary Plan), a supplemental plan which covers officers and
certain key executives (Supplemental Plan) and a retirement plan which covers
the Board of Directors (Directors' Plan). The Company also maintains ss.401(k)
plans for its union and non-union employees to which it does not contribute.
Primary Plan
The Company's funding policy is to contribute annually to the Primary Plan a
minimum amount consistent with the requirements of the Employee Retirement
Income Security Act of 1974, plus such additional amounts, if any, as the
Company may determine to be appropriate from time to time. Pension benefits are
based upon years of participation in the Primary Plan and compensation.
The Primary Plan's funded status and amounts recognized on the Balance Sheet at
March 31, 1998 and March 31, 1997 and December 31, 1996 were as follows:
<TABLE>
<CAPTION>
(In thousands of dollars)
- ---------------------------------------------------------------------------------------------------------------------
March 31, 1998 March 31, 1997 December 31, 1996
- ---------------------------------------------------------------------------------------------------------------------
Actuarial present value of benefit obligation
<S> <C> <C> <C>
Vested benefits $661,075 $642,392 $547,002
Nonvested benefits 59,268 57,960 55,157
=====================================================================================================================
Accumulated Benefit Obligation $720,343 $700,352 $602,159
=====================================================================================================================
Plan assets at fair value $919,100 $744,400 $746,400
Actuarial present value of projected benefit
obligation 825,159 807,703 689,661
- ---------------------------------------------------------------------------------------------------------------------
Projected benefit obligation less (greater) than
plan assets 93,941 (63,303) 56,739
Unrecognized net obligation 62,652 69,399 71,085
Unrecognized net (gain) (163,034) ( 1,605) (123,759)
=====================================================================================================================
Net (Accrued) Prepaid Pension Cost $( 6,441) $ 4,491 $ 4,065
====================================================================================================================
</TABLE>
79
<PAGE>
The increase in the present value of the accrued benefit at March 31, 1997
compared to December 31, 1996, is due primarily to the change in the discount
rate from 7.25% to 7.00% and the use of updated actuarial assumptions, relating
to mortality.
Periodic pension cost for the Primary Plan and the significant assumptions
consisted of the following:
<TABLE>
<CAPTION>
(In thousands of dollars)
- --------------------------------------------------------------------------------------------------------------------------
Year Ended Three Months Ended Year Ended Year Ended
March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Service cost - benefits
earned during the period $ 21,114 $ 4,645 $ 17,384 $ 15,385
Interest cost on projected benefits
obligation and service cost 56,379 12,494 47,927 45,987
Actual return on plan assets (200,025) (3,694) (81,165) (102,099)
Net amortization and deferral 151,438 (9,446) 33,541 57,665
- --------------------------------------------------------------------------------------------------------------------------
Net Periodic Pension Cost $ 28,906 $ 3,999 $ 17,687 $ 16,938
==========================================================================================================================
- --------------------------------------------------------------------------------------------------------------------------
March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995
- --------------------------------------------------------------------------------------------------------------------------
Discount rate for obligation 7.00% 7.00% 7.25% 7.25%
Discount rate for expense 7.00% 7.25% 7.25% 7.25%
Rate of future compensation increases 4.50% 5.00% 5.00% 5.00%
Long-term rate of return on assets 8.50% 7.50% 7.50% 7.50%
==========================================================================================================================
</TABLE>
The Primary Plan assets at fair value include cash, cash equivalents, group
annuity contracts, bonds and equity securities.
In 1993, the PSC issued an Order which addressed the accounting and ratemaking
treatment of pension costs in accordance with SFAS No. 87, "Employers'
Accounting for Pensions." Under the Order, the Company is required to recognize
any deferred net gains or losses over a ten-year period rather than using the
corridor approach method. The Company believes that this method of accounting
for financial reporting purposes results in a better matching of revenues and
the Company's pension cost. The Company defers differences between pension rate
allowance and pension expense under the Order. In addition, the PSC requires the
Company to measure and pay a carrying charge on amounts in excess of the pension
rate allowance and the annual pension contributions contributed into the pension
fund.
In addition, effective December 1, 1997, in accordance with the Stipulation, the
Company defers the difference between the sum of gas pension and gas
postretirement benefit costs other than pension and the amounts provided for in
rates, to the extent that such differences are in excess of or below three
percent of the Company's pretax net income from its gas operations. Such excess
will be transferred to a gas balancing account. For a further discussion of the
Stipulation, see Note 3.
Supplemental Plan
The Supplemental Plan provides supplemental death and retirement benefits for
officers and other key executives without contribution from such employees. The
Supplemental Plan is a non-qualified plan under the Internal Revenue Code. The
provision for plan benefits totaled approximately $0.7 million for the three
months ended March 31, 1997 and $2.7 million and $2.3 million for the years
ended December 31, 1996 and 1995, respectively. For the year ended March 31,
1998, the Company recorded a charge of approximately $31 million relating to
certain benefits earned by its officers relating to the termination of their
annuity benefits earned through the supplemental retirement plan and other
executive retirement benefits. These charges, the cost of which are borne by the
Company's shareowners, result from provisions of the officers' employment
contracts, including the Chairman's employment contract, and the pending
transactions with LIPA and KeySpan which affect the timing of when these costs
are recorded.
80
<PAGE>
Directors' Plan
The Directors' Plan provides benefits to directors who are not officers of the
Company. Directors who have served in that capacity for more than five years
qualify as participants under the plan. The Directors' Plan is a non-qualified
plan under the Internal Revenue Code. The provision for retirement benefits,
which are unfunded, totaled approximately $132,000 for the year ended March 31,
1998, $34,000 for the three months ended March 31, 1997 and $127,000 and
$114,000 for the years ended December 31, 1996 and 1995, respectively.
Postretirement Benefits Other Than Pensions
In addition to providing pension benefits, the Company provides certain medical
and life insurance benefits to retired employees. Substantially all of the
Company's employees may become eligible for these benefits if they reach
retirement age after working for the Company for a minimum of five years. These
and similar benefits for active employees are provided by the Company or by
insurance companies whose premiums are based on the benefits paid during the
year. Effective January 1, 1993, the Company adopted the provisions of SFAS No.
106, "Employers' Accounting for Postretirement Benefits Other Than Pensions,"
which requires the Company to recognize the expected cost of providing
postretirement benefits when employee services are rendered rather than when
paid. As a result, the Company, in 1993, recorded an accumulated postretirement
benefit obligation and a corresponding regulatory asset of approximately $376
million.
The PSC requires the Company to defer as a regulatory asset the difference
between postretirement benefit expense recorded for accounting purposes in
accordance with SFAS No. 106 and the postretirement benefit expense reflected in
rates. The ongoing annual postretirement benefit expense was phased into and
fully reflected in rates beginning December 1, 1996 with the accumulated
regulatory asset to be recovered in rates over a 15-year period, beginning
December 1, 1997. In addition, the Company is required to recognize any deferred
net gains or losses over a ten-year period.
In addition, effective December 1, 1997, in accordance with the Stipulation, the
Company defers the difference between the sum of gas pension and gas
postretirement benefit costs other than pension and the amounts provided for in
rates, to the extent that such differences are in excess of or below three
percent of the Company's pretax net income from its gas operations. Such excess
will be transferred to a gas balancing account. For a further discussion of the
Stipulation, see Note 3.
In 1994, the Company established Voluntary Employee's Beneficiary Association
trusts for union and non-union employees for the funding of incremental costs
collected in rates for postretirement benefits. The Company funded the trusts
with approximately $21 million for the year ended March 31, 1998, $5 million for
the three months ended March 31, 1997 and $18 million and $50 million for the
years ended December 31, 1996 and 1995, respectively. In May 1998, the Company
funded an additional $250 million into the trusts, representing obligations
related to the electric business unit employees. The Company secured a bridge
loan to fund these trusts.
81
<PAGE>
Accumulated postretirement benefit obligation other than pensions at March 31,
1998, March 31, 1997 and December 31, 1996 was as follows:
<TABLE>
<CAPTION>
(In thousands of dollars)
- --------------------------------------------------------------------------------------------------------------------------
March 31, 1998 March 31, 1997 December 31, 1996
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Retirees $157,380 $169,655 $156,181
Fully eligible plan participants 60,711 62,491 56,950
Other active plan participants 140,850 183,526 152,627
- --------------------------------------------------------------------------------------------------------------------------
Accumulated postretirement benefit obligation $358,941 $415,672 $365,758
Plan assets 108,165 80,533 74,692
- --------------------------------------------------------------------------------------------------------------------------
Accumulated postretirement benefit
obligation in excess of plan assets 250,776 335,139 291,066
Unrecognized prior service costs (175) (185) (188)
Unrecognized net gain 102,346 28,563 75,309
===========================================================================================================================
Accrued Postretirement Benefit Cost $352,947 $363,517 $366,187
===========================================================================================================================
</TABLE>
The increase in the present value of the accrued benefit at March 31, 1997
compared to December 31, 1996 is due to the change in the discount rate from
7.25% to 7.00% and the use of updated actuarial assumptions relating to
mortality.
The change in the accumulated postretirement benefit obligation from March 31,
1997 to March 31, 1998 reflects a decrease in the healthcare cost trend rate
based on the company's review of the medical plan cost experience and also
revised assumptions with respect to future compensation increases, mortality and
the percentage of employees who are assumed to be married at the time of
retirement.
At March 31, 1998, March 31, 1997 and December 31, 1996 the Plan assets, which
are recorded at fair value, include cash and cash equivalents, fixed income
investments and approximately $100,000 of listed equity securities of the
Company.
Periodic postretirement benefit cost other than pensions and the significant
assumptions consisted of the following:
<TABLE>
<CAPTION>
(In thousands of dollars)
- --------------------------------------------------------------------------------------------------------------------------
Year Ended Three Months Ended Year Ended Year Ended
March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Service cost - benefits
earned during the period $ 12,204 $ 2,821 $ 10,690 $ 9,082
Interest cost on projected benefits
obligation and service cost 27,328 6,642 25,030 22,412
Actual return on plan assets (6,632) (591) (3,046) (1,034)
Net amortization and deferral (10,000) (3,446) (12,175) (14,699)
- --------------------------------------------------------------------------------------------------------------------------
Net Periodic Pension Cost $ 22,900 $ 5,426 $ 20,499 $ 15,761
==========================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------
March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Discount rate for obligation 7.00% 7.00% 7.25% 7.25%
Discount rate for expense 7.00% 7.25% 7.25% 7.25%
Rate of future compensation increases 4.50% 5.00% 5.00% 5.00%
Long-term rate of return on assets 8.50% 7.50% 7.50% 7.50%
==========================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
The actuarial assumptions used for postretirement benefit plans are:
- --------------------------------------------------------------------------------------------------------------------------
(In thousands of dollars) March 31, 1998 March 31, 1997 December 31, 1996
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Health care cost trend 5.00%(a) 8.00%(b) 8.00%(b)
Effect of one percent increase in health care cost trend rate:
On cost components $ 7 $ 1 $ 5
On accumulated benefit obligation $42 $59 $43
==========================================================================================================================
</TABLE>
(a) Per year indefinitely
(b) Gradually declining to 6.0% in 2001 and thereafter.
82
<PAGE>
Note 9. Federal Income Tax
The significant components of the Company's deferred tax assets and liabilities
calculated under the provisions of SFAS No. 109, "Accounting for Income Taxes,"
were as follows:
<TABLE>
<CAPTION>
(In thousands of dollars)
- --------------------------------------------------------------------------------------------------------------------------
3/31/98 3/31/97 12/31/96
- --------------------------------------------------------------------------------------------------------------------------
Deferred Tax Assets
<S> <C> <C> <C>
Net operating loss carryforwards $ - $ 93,349 $ 145,205
Reserves not currently deductible 39,667 56,749 58,981
Tax depreciable basis in excess of 10,559 33,848 34,314
book
Nondiscretionary excess credits 24,858 27,037 27,700
Credit carryforwards 40,318 128,469 135,902
Other 261,729 225,885 186,907
- --------------------------------------------------------------------------------------------------------------------------
Total Deferred Tax Assets $ 377,131 $ 565,337 $ 589,009
- --------------------------------------------------------------------------------------------------------------------------
Deferred Tax Liabilities
1989 Settlement $2,169,909 $2,165,462 $2,163,239
Accelerated depreciation 650,562 642,656 642,702
Call premiums 38,698 43,617 44,846
Rate case deferrals 564 2,579 2,127
Other 56,762 38,117 33,496
- --------------------------------------------------------------------------------------------------------------------------
Total Deferred Tax Liabilities 2,916,495 2,892,431 2,886,410
==========================================================================================================================
Net Deferred Tax Liability $2,539,364 $2,327,094 $2,297,401
==========================================================================================================================
SFAS No. 109 requires utilities to establish regulatory assets and liabilities
for the portion of its deferred tax assets and liabilities that have not yet
been recognized for ratemaking purposes. The major components of these
regulatory assets and liabilities are as follows:
(In thousands of dollars)
- --------------------------------------------------------------------------------------------------------------------------
3/31/98 3/31/97 12/31/96
- --------------------------------------------------------------------------------------------------------------------------
Regulatory Assets
1989 Settlement $1,652,412 $1,659,065 $1,660,871
Plant items 100,661 120,460 125,976
Other (15,141) (12,361) (14,069)
==========================================================================================================================
Total Regulatory Assets $1,737,932 $1,767,164 $1,772,778
==========================================================================================================================
Regulatory Liabilities
Carryforward credits $ 38,720 $ 64,548 $ 68,421
Other 40,193 35,829 34,466
========================================= =============================== ========================= ======================
Total Regulatory Liabilities $ 78,913 $ 100,377 $ 102,887
========================================= =============================== ========================= ======================
</TABLE>
The federal income tax amounts included in the Statement of Income differ from
the amounts which result from applying the statutory federal income tax rate to
income before income tax.
The table below sets forth the reasons for such differences.
<TABLE>
<CAPTION>
(In thousands of dollars)
- -------------------------------------------------------------------------------------------------------------------------
Year Ended Three Months Ended Year Ended Year Ended
March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Income before federal income tax $594,893 $143,910 $525,721 $508,824
Statutory federal income tax rate 35% 35% 35% 35%
- -------------------------------------------------------------------------------------------------------------------------
Statutory federal income tax $208,213 $ 50,369 $184,002 $178,088
Additions (reductions) in federal income
tax
Excess of book over tax depreciation 17,912 4,356 18,339 18,588
1989 Settlement 4,212 1,053 4,212 4,213
Interest capitalized 2,962 588 2,270 2,218
Tax credits (2,464) (940) (4,383) (1,025)
Tax rate change amortization 2,223 815 3,686 3,752
Allowance for funds used during (2,953) (583) (2,305) (2,392)
construction
Other items 2,549 555 3,436 2,096
- -------------------------------------------------------------------------------------------------------------------------
Total Federal Income Tax Expense $232,654 $56,213 $209,257 $205,538
=========================================================================================================================
Effective Federal Income Tax Rate 39.1% 39.1% 39.8% 40.4%
=========================================================================================================================
</TABLE>
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<PAGE>
The Company currently has tax credit carryforwards of approximately $40 million.
This balance is composed of investment tax credit (ITC) carryforwards, net of
the 35% reduction required by the Tax Reform Act of 1986, totaling approximately
$31 million and research and development credits totaling approximately $9
million.
In 1990 and 1992, the Company received Revenue Agents' Reports disallowing
certain deductions and credits claimed by the Company on its federal income tax
returns for the years 1981 through 1989. A settlement resolving all audit issues
was reached between the Company and the Internal Revenue Service in May 1998.
The settlement provided for the payment of taxes and interest of approximately
$9 million and $35 million, respectively, which the Company made in May 1998.
The Company had previously provided reserves adequate to cover such taxes and
interest.
Note 10. The 1989 Settlement
In February 1989, the Company and the State of New York entered into the 1989
Settlement resolving certain issues relating to the Company and providing, among
other matters, for the financial recovery of the Company and for the transfer of
Shoreham to LIPA, an agency of the State of New York, for its subsequent
decommissioning. In February 1992, the Company transferred ownership of Shoreham
to LIPA. In May 1995, the NRC terminated LIPA's possession-only license for
Shoreham which signified the NRC's approval that decommissioning was complete
and that the site is suitable for unrestricted use.
Upon the effectiveness of the 1989 Settlement, in June 1989, the Company
recorded the FRA on its Balance Sheet and the retirement of its investment of
approximately $4.2 billion, principally in Shoreham. For a further discussion of
the FRA, see Note 1.
Pursuant to the 1989 Settlement, the Company was required to reimburse LIPA for
all of its costs associated with the decommissioning of Shoreham. The PSC has
determined that all costs associated with Shoreham which are prudently incurred
by the Company subsequent to the effectiveness of the 1989 Settlement are
decommissioning costs. The RMA provides for the recovery of such costs through
electric rates over the balance of a forty-year period ending 2029. At March 31,
1998, Shoreham post-settlement costs totaled approximately $1.2 billion,
consisting of $587 million of property taxes and payments-in-lieu-of-taxes, and
$568 million of decommissioning costs, fuel disposal costs and all other costs
incurred at Shoreham after June 30, 1989.
Note 11. The Class Settlement
The Class Settlement, which became effective in June 1989, resolved a civil
lawsuit against the Company brought under the federal Racketeer Influenced and
Corrupt Organizations Act. The lawsuit, which the Class Settlement resolved, had
alleged that the Company made inadequate disclosures before the PSC concerning
the construction and completion of nuclear generating facilities.
The Class Settlement provides the Company's electric customers with rate
reductions aggregating $390 million that are being reflected as adjustments to
their monthly electric bills over a ten-year period which began on June 1, 1990.
Upon its effectiveness, the Company recorded its liability for the Class
Settlement on a present value basis at $170 million. The Class Settlement
obligation at March 31, 1998 reflects the present value of the remaining
reductions to be refunded to customers. The remaining reductions to customers
bills, amounting to approximately $130 million as of March 31, 1998, consists of
approximately $10 million for the two-month period beginning April 1, 1998, and
$60 million for each of the 12-month periods beginning June 1, 1998 and 1999.
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<PAGE>
Note 12. Commitments and Contingencies
Electric
The Company has entered into contracts with numerous Independent Power Producers
(IPPs) and the New York Power Authority (NYPA) for electric generating capacity.
Under the terms of the agreement with NYPA, which is set to expire in May 2014,
the Company may purchase up to 100% of the electric energy produced at the NYPA
facility located within the Company's service territory at Holtsville, NY. The
Company is required to reimburse NYPA for the minimum debt service payments, and
to make fixed non-energy payments and expenses associated with operating and
maintaining the plant.
With respect to contracts entered into with the IPPs, the Company is obligated
to purchase all the energy they make available to the Company at prices that
often exceed current market prices. However, the Company has no obligation to
the IPPs if they fail to deliver energy. For purposes of the table below, the
Company has assumed full performance by the IPPs, as no event has occurred to
suggest anything less than full performance by these parties.
The Company also has contracted with NYPA for firm transmission (wheeling)
capacity in connection with a transmission cable which was constructed, in part,
for the benefit of the Company. In accordance with the provisions of this
agreement, which expires in 2020, the Company is required to reimburse NYPA for
debt service payments and the cost of operating and maintaining the cables. The
cost of such contracts is included in electric fuel expense and is recoverable
through rates.
The following table represents the Company's commitments under purchased power
contracts.
<TABLE>
<CAPTION>
Electric Operations (In millions of dollars)
- -------------------------------------------------------------------------------------------------------------------------
NYPA Holtsville
-------------------------------------------
Other Fixed Firm Total
For the fiscal years ended Debt Service Charges Energy* Transmission IPPs* Business*
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
1999 $ 21.7 $ 14.7 $ 6.7 $ 25.7 $ 127.6 $ 196.4
2000 21.7 13.7 6.7 26.0 132.7 200.8
2001 21.8 14.6 7.2 27.8 135.8 207.2
2002 21.9 16.3 8.7 27.8 139.5 214.2
2003 22.0 16.7 9.0 27.9 137.9 213.5
Subsequent Years 232.4 217.1 119.8 474.0 957.5 2,000.8
- -------------------------------------------------------------------------------------------------------------------------
Total $341.5 $293.1 $158.1 $609.2 $1,631.0 $3,032.9
- -------------------------------------------------------------------------------------------------------------------------
Less: Imputed Interest $166.8 $154.1 $ 85.3 $381.9 $ 805.2 $1,593.3
- -------------------------------------------------------------------------------------------------------------------------
Present Value of Payments $174.7 $139.0 $ 72.8 $227.3 $ 825.8 $1,439.6
- -------------------------------------------------------------------------------------------------------------------------
</TABLE>
*Assumes full performance by the IPPs and NYPA.
Gas
In order to provide for sufficient supplies of gas for the Company's gas
customers, the Company has entered into long-term firm gas transportation,
storage and supply contracts which contain provisions that require the Company
to make fixed payments (demand charges) even if the services are not fully
utilized. The cost of such contracts is included in gas fuel expense and is
recoverable through rates. The table below sets forth the Company's aggregate
obligation under these commitments which extend through 2014.
Gas Operations (In millions of dollars)
---------------------------------------------------------------------
For the fiscal years ended
1999 $111.73
2000 110.37
2001 101.33
2002 97.81
2003 91.69
Subsequent Years 371.20
---------------------------------------------------------------------
Total $884.13
Less: Imputed Interest 258.45
=====================================================================
Present Value of Payments $625.68
=====================================================================
85
<PAGE>
Competitive Environment
The electric industry continues to undergo fundamental changes as regulators,
elected officials and customers seek lower energy prices. These changes, which
may have a significant impact on future financial performance of electric
utilities, are being driven by a number of factors including a regulatory
environment in which traditional cost-based regulation is seen as a barrier to
lower energy prices. In 1997 and 1998, both the PSC and the FERC continued their
separate, but in some cases parallel, initiatives with respect to developing a
framework for a competitive electric marketplace.
The Electric Industry - State Regulatory Issues
In 1994, the PSC began the second phase of its Competitive Opportunities
Proceedings to investigate issues related to the future of the regulatory
process in an industry which is moving toward competition. The PSC's overall
objective was to identify regulatory and ratemaking practices that would assist
New York State utilities in the transition to a more competitive environment
designed to increase efficiency in providing electricity while maintaining safe,
affordable and reliable service.
As a result of the Competitive Opportunities Proceedings, in May 1996, the PSC
issued an order (Order) which stated its belief that introducing competition to
the electric industry in New York has the potential to reduce electric rates
over time, increase customer choice and encourage economic growth. The Order
called for a competitive wholesale power market to be in place by early 1997 to
be followed by the introduction of retail access for all customers by early
1998.
The PSC stated that competition should be transitioned on an individual company
basis, due to differences in individual service territories, the level and type
of strandable investments (i.e., costs that utilities would have otherwise
recovered through rates under traditional cost of service regulation that, under
market competition, would not be recoverable) and utility specific financial
conditions.
The Order contemplates that implementation of competition will proceed on two
tracks. The Order requires that each major electric utility (except the Company
and Niagara Mohawk Power Corporation) file a rate/restructuring plan which is
consistent with the PSC's policy and vision for increased competition. Those
plans were submitted by October 1, 1996, in compliance with the Order. However,
the Company was exempted from this requirement due to the PSC's separate
investigation of the Company's rates and LIPA's examination of the Company's
structure. The PSC has now approved settlement agreements with each of the five
New York utilities that were required to file restructuring plans in the
Competitive Opportunities Proceeding. LILCO and Niagara Mohawk were exempt
however, on February 18,1998 the PSC also approved a settlement agreement on the
Niagara Mohawk PowerChoice restructuring proposal that had been filed in October
1995.
In general, the terms of the agreements vary from three to five years with all
agreements calling for some rate reductions, structural separation of the
generation and power delivery function, divestiture of fossil generation, full
retail access in two to four years, and the imposition of a system benefits
charge to cover the costs of research and development (R&D), conservation,
low-income and environmental programs. In each case, the PSC is giving the
utility a reasonable opportunity to recover all prudently-incurred stranded
costs.
The PSC Order also anticipated that certain other filings would be made on
October 1, 1996, by all New York State utilities, to both the PSC and the FERC.
The filings were to address the delineation of transmission and distribution
facilities jurisdiction between the FERC or the PSC, a pricing of each company's
transmission services, and a joint filing by all the utilities to address the
formation of an Independent System Operator (ISO) and the creation of a market
exchange that will establish spot market
86
<PAGE>
prices. Although there were extensive collaborative meetings among the parties,
it was not possible for the additional filings to be completed by October 1,
1996. On December 31, 1996, the New York Power Pool members submitted a
compliance filing to the FERC which provides open membership and comparable
services to eligible entities in accordance with FERC Order 888, discussed
below. The New York State utilities submitted the full ISO/Power Exchange filing
to the FERC in January 1997, which proposes to establish a competitive wholesale
marketplace in New York State for electric energy and transmission pricing at
market-based rates. Subsequent to the FERC filing in January 1997, the New York
State utilities made three relating filings with the FERC: (i) a supplemental
filing, providing additional details regarding the creation of a New York State
Reliability Council, in May 1997; (ii) a request for market-based rate
authority, by six of the New York utilities, in August 1997; and (iii) a
supplemental filing with the FERC on December 19, 1997 which expands upon and
provides additional details with respect to the January 1997 filing.
The PSC has taken the position that a fully operational wholesale competitive
structure will foster the expeditious movement to full retail competition. The
PSC's vision of the retail competitive structure, known as the Flexible Retail
Poolco Model, consists of: (i) the creation of an ISO to coordinate the safe and
reliable operation of electric generation and transmission; (ii) open access to
the transmission system, which would be regulated by the FERC; (iii) the
continuation of a regulated distribution company to operate and maintain the
distribution system; (iv) the deregulation of energy/customer services such as
meter reading and customer billing; (v) the ability of customers to choose among
suppliers of electricity; and (vi) the allowance of customers to acquire
electricity either by long-term contracts, purchases on the spot market, or a
combination of the two.
One issue discussed in the Order that could affect the Company is strandable
investments. The PSC stated in its Order that it is not required to allow
recovery of all prudently-incurred investments, that it has considerable
discretion to set rates that balance ratepayer and shareholder interests, and
that the amount of strandable investments that a utility will be permitted to
recover will depend on the particular circumstances of each utility.
Additionally, the Order provided that every effort should be made by utilities
to mitigate these costs prior to seeking recovery.
Certain aspects of the restructuring envisioned by the PSC --particularly the
PSC's apparent determinations that it may deny the utilities recovery of prudent
investments made on behalf of the public, order retail wheeling, require
divestiture of generation assets, and deregulate certain sectors of the energy
market -- could, if implemented, have a negative impact on the operations and
financial conditions of New York's investor-owned electric utilities, including
the Company.
The Company is party to a lawsuit commenced in September 1996 by the Energy
Association of New York State and the state's other investor-owned electric
utilities (collectively, Petitioners) against the PSC in New York Supreme Court,
Albany County (The Energy Association of New York State, et al. v. Public
Service Commission of the State of New York, et al.). The Petitioners have
requested that the Court declare that the Order is unlawful or, in the
alternative, that the Court clarify that the PSC's statements in the Order
constitute simply a policy statement with no binding legal effect. In November
1996, the Court issued a Decision and Order denying the Petitioners' request to
invalidate the Order. Although the Court stated that most of the Order is a
non-binding statement of policy, the Court rejected the Petitioners' substantive
challenges to the Order. In December 1996, the Petitioners filed a notice of
appeal with the Third Department of the Appellate Division of the New York State
Supreme Court. The litigation is ongoing and the Company is unable at this time
to predict the likelihood of success or the impact of the litigation on the
Company's financial position, cash flows or results of operations. At the
request of the
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<PAGE>
Energy Association and Public Utility Law Project of New York (PULP), the Court
has extended the time in which the Energy Association and PULP must perfect
their appeals until July 6, 1998.
The Electric Industry - Federal Regulatory Issues
In April 1996, in response to its Notice of Proposed Rulemaking issued in March
1995, the FERC issued Orders 888 and 889 relating to the development of
competitive wholesale electric markets.
Order 888 is a final rule on open transmission access and stranded cost recovery
and provides that the FERC has exclusive jurisdiction over interstate wholesale
wheeling and that utility transmission systems must now be open to qualifying
sellers and purchasers of power on a non-discriminatory basis.
Order 888 allows utilities to recover legitimate, prudent and verifiable
stranded costs associated with wholesale transmission, including the
circumstances where full requirements customers become wholesale transmission
customers, such as where a municipality establishes its own electric system.
With respect to retail wheeling, the FERC concluded that it has jurisdiction
over rates, terms and conditions of service, but would leave the issue of
recovery of the costs stranded by retail wheeling to the states.
Order 888 required utilities to file open access tariffs under which they would
provide transmission services, comparable to those which they provide to
themselves and to third parties on a non-discriminatory basis. Additionally,
utilities must use these same tariffs for their own wholesale sales. Order
888-A, issued in March 1997, generally reaffirmed the FERC's basic determination
in Order 888. One pertinent change made in 888-A, however, was that the FERC, as
opposed to the states, will be the primary forum for determining stranded costs
in cases involving municipal annexation. Order 888-B, issued November 1997,
reaffirmed 888-A's findings.
The Company filed its open access tariff in July 1996. In September 1996, the
FERC ordered Rate Hearings on 28 utility transmission tariffs, including the
Company's. On the basis of a preliminary review, the FERC was not satisfied that
the tariff rates were just and reasonable. Settlement discussions have been held
between the Company and various intervenors concerning the Company's
transmission rates. In December 1996, the parties reached a tentative settlement
on the rate issues.
On May 14, 1997, the FERC approved the settlement agreement that the Company
filed (with five other entities) concerning the rates for the Company's open
access electric tariff. The effective date for those rates was July 9, 1996. The
Company and four other New York utilities are seeking review of certain non-rate
aspects of the FERC's open access transmission tariff orders in the U.S. Court
of Appeals for the D.C. Circuit.
Order 889, which is a final rule on a transmission pricing bulletin board,
addresses the rules and technical standards for operation of an electronic
bulletin board that will make available, on a real-time basis, the price,
availability and other pertinent information concerning each transmission
utility's services. It also addresses standards of conduct to ensure that
transmission utilities functionally separate their transmission and wholesale
power merchant functions to prevent discriminatory self-dealing. In December
1996, the Company filed its standards of conduct in accordance with the Order.
Order 889-A and 889-B, issued in March and November 1997, respectively,
generally reaffirmed and clarified the original Order 889. Order 889-A
implemented new discounting policies and required that all negotiations between
a transmission provider and a potential customer take place on the transmission
pricing bulletin board and be visible to all.
88
<PAGE>
It is not possible to predict the ultimate outcome of these proceedings, the
timing thereof, or the amount, if any, of stranded costs that the Company would
recover in a competitive environment. The outcome of the state and federal
regulatory proceedings could adversely affect the Company's ability to apply
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," which,
pursuant to SFAS No. 101, "Accounting for Discontinuation of Application of SFAS
No. 71," could then require a significant write-down of all or a portion of the
Company's net regulatory assets.
The Company's Service Territory
The Company's geographic location and the limited electrical interconnections to
Long Island serve to limit the accessibility of its transmission grid to
potential competitors from off the system. However, the changing utility
regulatory environment has affected the Company by requiring the Company to
co-exist with state and federally mandated competitors, non-utility generators
(NUGs).
The Public Utility Regulatory Policies Act of 1978 (PURPA), the goals of which
are to reduce the United States' dependency on foreign oil, to encourage energy
conservation and to promote diversification of the fuel supply, has negatively
impacted the Company through the encouragement of the NUG industry. The PURPA
provides for the development of a new class of electric generators which rely on
either cogeneration technology or alternate fuels. Utilities are obligated under
the PURPA to purchase the output of certain of these generators, which are known
as qualified facilities (QFs).
For the years ended March 31, 1998 and 1997, the Company lost sales to NUGs
totaling 447 and 422 gigawatt hours (GWh) representing a loss in electric
revenues net of fuel (net revenues) of approximately $36 million and $34
million, respectively or 2.0% and 1.9% of the Company's net revenues,
respectively.
For the year ended December 31, 1996, the Company lost sales to NUGs totaling
422 GWh representing a loss in electric net revenues of approximately $34
million, or 1.9% of the Company's net revenues. For the year ended December 31,
1995, the Company lost sales to NUGs totaling 366 GWh or approximately $28
million or 1.5% of the Company's net revenues.
The increase in lost net revenues resulted principally from the completion of
seven facilities that became commercially operational during 1996 and the full
year operation of the IPP located at the State University of New York at Stony
Brook, NY. The Company estimates that in 1999 sales losses to NUGs will be 447
GWh, or approximately 1.8% of projected net revenues.
The Company believes that load losses due to NUGs have stabilized. This belief
is based on the fact that the Company's customer load characteristics, which
lack a significant industrial base and related large thermal load, will mitigate
load loss and thereby make cogeneration economically unattractive.
Additionally, as mentioned above, the Company is required to purchase all the
power offered by QFs, which for the years ended March 31, 1998 and 1997,
approximated 220 megawatts (MW) and 226 MW, respectively. The Company estimates
that purchases from QFs required by federal and state law cost the Company $71
million and $64 million in 1998 and 1997, respectively, more than it would have
cost had the Company purchased the power in the open market or generated it.
For the years ended December 31, 1996 and 1995, QFs offered approximately 218 MW
and 205 MW, respectively. The Company estimates that purchases from QFs required
by federal and state law cost the Company $63 million and $53 million for the
years ended December 31, 1996 and 1995, respectively, more than it would have
cost had the Company purchased the power in the open market or generated it.
89
<PAGE>
QFs have the choice of pricing sales to the Company at either the PSC's
published estimates of the Company's long-range avoided costs (LRAC) or the
Company's tariff rates, which are modified from time to time, reflecting the
Company's actual avoided costs. Additionally, until repealed in 1992, New York
State law set a minimum price of six cents per kilowatt-hour (kWh) for utility
purchases of power from certain categories of QFs, considerably above the
Company's avoided cost. The six cent minimum continues to apply to contracts
entered into before June 1992. The Company believes that the repeal of the six
cent minimum, coupled with recent PSC updates which resulted in lower LRAC
estimates, has significantly reduced the economic benefits of constructing new
QFs within its service territory.
The Company has also experienced a revenue loss as a result of its policy of
voluntarily providing wheeling of New York Power Authority (NYPA) power for
economic development. The Company estimates that for the years ended March 31,
1998 and 1997, NYPA power displaced approximately 373 GWh and 424 GWh of annual
energy sales, respectively. Net revenue loss associated with these volumes of
sales is approximately $23 million, or 1.2% of the Company's 1998 net revenues,
and $27 million, or 1.5% of the Company's 1997 net revenues. Currently, the
potential loss of additional load is limited by conditions in the Company's
transmission agreements with NYPA.
The Company estimates that for the years ended December 31, 1996 and 1995, NYPA
power displaced approximately 417 GWh and 429 GWh of annual energy sales,
respectively. Net revenue loss associated with these volumes of sales is
approximately $26 million, or 1.4% of the Company's 1996 net revenues, and $30
million, or 1.6% of the Company's 1995 net revenues.
A number of customer groups are seeking to hasten consideration and
implementation of full retail competition. For example, an energy consultant has
petitioned the PSC, seeking alternate sources of power for Long Island school
districts. The County of Nassau has also petitioned the PSC to authorize retail
wheeling for all classes of electric customers in the county.
In addition, several towns and villages on Long Island are investigating
municipalization, in which customers form a government-sponsored electric supply
company. This is one form of competition that is likely to increase as a result
of the National Energy Policy Act of 1992 (NEPA). NEPA sought to increase
economic efficiency in the creation and distribution of power by relaxing
restrictions on the entry of new competitors to the wholesale electric power
market. NEPA does so by creating exempt wholesale generators that can sell power
in wholesale markets without the regulatory constraint placed on utility
generators such as on the Company. NEPA also expanded the FERC's authority to
grant access to utility transmission systems to all parties who seek wholesale
wheeling for wholesale competition. While it should be noted that the FERC's
position favoring stranded cost recovery from retail turned wholesale customers
will reduce utility risk from municipalization, significant issues associated
with the removal of restrictions on wholesale transmission system access have
yet to be resolved.
There are numerous towns and villages in the Company's service territory that
are considering the formation of a municipally-owned and operated electric
authority to replace the services currently provided by the Company.
In 1995, Suffolk County issued a request for proposal from suppliers for up to
300 MW of power which the County would then sell to its residential and
commercial customers. The County has awarded the bid to two off-Long Island
suppliers and has requested the Company to deliver the power. After the Company
challenged Suffolk County's eligibility for such service, the County petitioned
the FERC to order the Company to provide the requested transmission service.
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<PAGE>
In December 1996, the FERC ordered the Company to provide transmission services
to Suffolk County to the extent necessary to accommodate proposed sales to
customers to which it was providing service on the date of enactment of NEPA
(this Order could provide Suffolk County with the ability to import up to 200 MW
of power on a daily basis). The FERC reserved decision on the remaining 100 MW
of Suffolk County's request until the County identifies the ownership or control
of distribution facilities that it alleges qualifies it for a wheeling order to
Suffolk County customers who were not receiving service on the date of NEPA's
enactment. The Company may ask the FERC to reconsider its decision once that
decision becomes final, which is not expected for several months. The Company
and Suffolk County submitted briefs in July 1997 addressing the pricing for the
200 MW of power. The FERC has yet to determine the pricing of that service. As
previously noted, FERC Order 888 allows utilities to recover legitimate, prudent
and verifiable stranded costs associated with wholesale transmission, including
the circumstances where full requirements customers become wholesale
transmission customers, such as where a municipality establishes its own
electric system.
The matters discussed above involve substantial social, economic, legal,
environmental and financial issues. The Company is opposed to any proposal that
merely shifts costs from one group of customers to another, that fails to
enhance the provision of least-cost, efficiently-generated electricity or that
fails to provide the Company's shareowners with an adequate return on and
recovery of their investment. The Company is unable to predict what action, if
any, the PSC or the FERC may take regarding any of these matters, or the impact
on the Company's financial position, cash flows or results of operations if some
or all of these matters are approved or implemented by the appropriate
regulatory authority.
Notwithstanding the outcome of the state or federal regulatory proceedings, or
any other state action, the Company believes that, among other obligations, the
State has a contractual obligation to allow the Company to recover its
Shoreham-related assets.
Environmental Matters
The Company is subject to federal, state and local laws and regulations dealing
with air and water quality and other environmental matters. Environmental
matters may expose the Company to potential liabilities which, in certain
instances, may be imposed without regard to fault or for historical activities
which were lawful at the time they occurred. The Company continually monitors
its activities in order to determine the impact of its activities on the
environment and to ensure compliance with various environmental laws. Except as
set forth below, no material proceedings have been commenced or, to the
knowledge of the Company, are contemplated against the Company with respect to
any matter relating to the protection of the environment.
The New York State Department of Environmental Conservation (DEC) has required
the Company and other New York State utilities to investigate and, where
necessary, remediate their former manufactured gas plant (MGP) sites. Currently,
the Company is the owner of six pieces of property on which the Company or
certain of its predecessor companies are believed to have produced manufactured
gas. Operations at these facilities in the late 1800's and early 1900's may have
resulted in the disposal of certain waste products on these sites.
The Company has entered into discussions with the DEC which is expected to lead
to the issuance of one or more ACOs regarding the management of environmental
activities at these six properties. Although the exact amount of the Company's
cleanup costs cannot yet be determined, based on the findings of preliminary
investigations conducted at each of these six sites, current estimates indicate
that it may cost approximately $54 to $92 million to investigate and remediate
all of these sites. In considering the range of possible remediation estimates,
the Company felt it appropriate to record a $54 million liability
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<PAGE>
reflecting the present value of the future stream of payments amounting to $70
million to investigate and remediate these sites. The Company used a risk-free
rate of 6.0% to discount this obligation. The Company believes that the PSC will
provide for future recovery of these costs and has recorded a $54 million
regulatory asset. The Company's rate settlement which the PSC approved February
4, 1998 as discussed in Note 3 of Notes to Financial Statements, allows for the
recovery of MGP expenditures from gas customers.
In December 1996, the Company filed a complaint in the United States District
Court for the Southern District of New York against 14 of the Company's insurers
which issued general comprehensive liability (GCL) policies to the Company. In
January 1998, the Company commenced a similar action against the same and
certain additional insurer defendants in New York State Supreme Court, First
Department; the federal court action was subsequently dismissed in March 1998.
The Company is seeking recovery under the GCL policies for the costs incurred to
date and future costs associated with the clean-up of the Company's former
manufactured gas plant (MGP) sites and Superfund sites for which the Company has
been named a PRP. The Company is seeking a declaratory judgment that the
defendant insurers are bound by the terms of the GCL policies, subject to the
stated coverage limits, to reimburse the Company for the clean up costs. The
outcome of this proceeding cannot yet be determined.
The Company has been notified by the United States Environmental Protection
Agency (EPA) that it is one of many PRPs that may be liable for the remediation
of three licensed treatment, storage and disposal sites to which the Company may
have shipped waste products and which have subsequently become environmentally
contaminated.
At one site, located in Philadelphia, Pennsylvania, and operated by Metal Bank
of America, the Company and nine other PRPs, all of which are public utilities,
completed performance of a Remedial Investigation and Feasibility Study (RI/FS),
which was conducted under an ACO with the EPA. In December 1997, the EPA issued
its Record of Decision (ROD), setting forth the final remedial action selected
for this site. In the ROD, the EPA estimated that the present cost of the
selected remedy for the site is $17.3 million. At this time, the Company cannot
predict with reasonable certainty the actual cost of the selected remedy, who
will implement the remedy, or the cost, if any, to the Company. Under a PRP
participation agreement, the Company previously was responsible for 8.2% of the
costs associated with the RI/FS. The Company's allocable share of liability for
the remediation activities has not yet been determined. The Company has recorded
a liability of approximately $1 million representing its estimated share of the
cost to remediate this site based upon its 8.2% responsibility under the RI/FS.
The Company has also been named a PRP for disposal sites in Kansas City, Kansas,
and Kansas City, Missouri. The two sites were used by a company named PCB, Inc.
from 1982 until 1987 for the storage, processing, and treatment of electric
equipment, dielectric oils and materials containing PCBs. According to the EPA,
the buildings and certain soil areas outside the buildings are contaminated with
PCBs. Certain of the PRPs, including the Company and several other utilities
formed a PRP group, signed an ACO, and have developed a workplan for
investigating environmental conditions at the sites. Documentation connecting
the Company to the sites indicates that the Company was responsible for less
than 1% of the materials that were shipped to the Missouri site. The EPA has not
yet completed compiling the documents for the Kansas site.
In addition, the Company was notified that it is a PRP at a Superfund site
located in Farmingdale, New York. Industrial operations took place at this site
for at least fifty years. The PRP group has claimed that the Company should
absorb remediation expenses in the amount of approximately $100,000 associated
with removing PCB-contaminated soils from a portion of the site which formerly
contained electric transformers. The Company is currently unable to determine
its share of costs of remediation at this site.
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During 1996, the Connecticut Department of Environmental Protection (DEP) issued
a modification to an ACO previously issued in connection with an investigation
of an electric transmission cable located under the Long Island Sound (Sound
Cable) that is jointly owned by the Company and the Connecticut Light and Power
Company (Owners). The modified ACO requires the Owners to submit to the DEP and
DEC a series of reports and studies describing cable system condition, operation
and repair practices, alternatives for cable improvements or replacement and
environmental impacts associated with leaks of fluid into the Long Island Sound,
which have occurred from time to time. The Company continues to compile required
information and coordinate the activities necessary to perform these studies
and, at the present time, is unable to determine the costs it will incur to
complete the requirements of the modified ACO or to comply with any additional
requirements.
The Owners have also entered into an ACO with the DEC as a result of leaks of
dielectric fluid from the Sound Cable. The ACO formalizes the DEC's authority to
participate in and separately approve the reports and studies being prepared
pursuant to the ACO issued by the DEP. In addition, the ACO settles any DEC
claim for natural resource damages in connection with historical releases of
dielectric fluid from the Sound Cable.
In October 1995, the U.S. Attorney for the District of Connecticut had commenced
an investigation regarding occasional releases of fluid from the Sound Cable, as
well as associated operating and maintenance practices. The Owners have provided
the U.S. Attorney with all requested documentation. The Company believes that
all activities associated with the response to occasional releases from the
Sound Cable were consistent with legal and regulatory requirements.
In December 1996, a barge, owned and operated by a third party, dropped anchor
which then dragged over and damaged the Sound Cable, resulting in the release of
dielectric fluid into Long Island Sound. Temporary clamps and leak abaters were
installed on the cables to stop the leaks. Permanent repairs were completed in
June 1997. The cost to repair the Sound Cable was approximately $17.8 million,
for which there was $15 million of insurance coverage. The Owners filed a claim
and answer in response to the maritime limitation proceeding instituted by the
barge owner in the United States District Court, Eastern District of New York.
The claim seeks recovery of the amounts paid by insurance carriers and recovery
of the costs incurred for which there was no insurance coverage. Any costs to
repair the Sound Cable which are not reimbursed by a third party or covered by
insurance will be shared equally by the Owners.
The Company believes that none of the environmental matters, discussed above,
will have a material adverse impact on the Company's financial position, cash
flows or results of operations. In addition, the Company believes that all
significant costs incurred with respect to environmental investigation and
remediation activities, not recoverable from insurance carriers, will be
recoverable through rates.
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Note 13. Business Segments
Identifiable assets by segment include net utility plant, regulatory assets,
materials and supplies, accrued unbilled revenues, gas in storage, fuel and
deferred charges. Assets utilized for overall Company operations consist
primarily of cash and cash equivalents, accounts receivable, common net utility
plant and unamortized cost of issuing securities.
<TABLE>
<CAPTION>
(In millions of dollars)
- --------------------------------------------------------------------------------------------------------------------------
Year Ended Three Months Ended Year Ended Year Ended
March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995
- --------------------------------------------------------------------------------------------------------------------------
Operating revenues
<S> <C> <C> <C> <C>
Electric $ 2,478 $ 558 $ 2,467 $ 2,484
Gas 646 293 684 591
==========================================================================================================================
Total $ 3,124 $ 851 $ 3,151 $ 3,075
==========================================================================================================================
Operating expenses
(excludes federal income tax)
Electric $ 1,595 $ 400 $ 1,644 $ 1,657
Gas 523 204 560 478
==========================================================================================================================
Total $ 2,118 $ 604 $ 2,204 $ 2,135
==========================================================================================================================
Operating income
(before federal income tax)
Electric $ 883 $ 158 $ 823 $ 827
Gas 123 89 124 113
==========================================================================================================================
Total operating income $ 1,006 $ 247 $ 947 $ 940
==========================================================================================================================
AFC $ (8) $ (2) $ (6) $ (7)
Other income and deductions 10 (2) (23) (38)
Interest charges 409 107 451 476
Federal income tax 233 56 209 206
==========================================================================================================================
Net Income $ 362 $ 88 $ 316 $ 303
==========================================================================================================================
Depreciation and Amortization
Electric $ 131 $ 32 $ 129 $ 122
Gas 28 7 25 23
==========================================================================================================================
Total $ 159 $ 39 $ 154 $ 145
==========================================================================================================================
Construction and nuclear fuel
expenditures*
Electric $ 181 $ 35 $ 165 $ 162
Gas 80 16 78 84
==========================================================================================================================
Total $ 261 $ 51 $ 243 $ 246
==========================================================================================================================
</TABLE>
* Includes non-cash allowance for other funds used during construction and
excludes Shoreham post-settlement costs.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------
March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995
- --------------------------------------------------------------------------------------------------------------------------
Identifiable Assets
<S> <C> <C> <C> <C>
Electric $ 9,553 $10,048 $9,835 $10,020
Gas 1,219 1,134 1,232 1,181
- --------------------------------------------------------------------------------------------------------------------------
Total Identifiable Assets 10,772 11,182 11,067 11,201
Assets Utilized for Overall
Company Operations 1,129 668 1,143 1,326
==========================================================================================================================
Total Assets $11,901 $11,850 $12,210 $12,527
==========================================================================================================================
</TABLE>
94
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Note 14. Disaggregated Condensed Balance Sheet (Unaudited)
Set forth below is the Company's condensed balance sheet at March 31, 1998 which
has been disaggregated pursuant to the terms of the LIPA Agreement to give
effect to the proposed LIPA transaction as if it had occurred on March 31, 1998.
The assets, capitalization and liabilities attributable to HoldCo Subsidiary
represent the Company's transfer of its gas and generation business to such
subsidiary. The assets, capitalization and liabilities attributable to LIPA
represent those items that will be aqcquired or assumed by LIPA through its
acquisition of the Company's common stock. All such amounts exclude the proceeds
from the sale of common stock to LIPA. The disaggregated condensed balance sheet
was prepared by management of the Company, and is subject to adjustment. For a
further discussion of the LIPA Transaction, see Note 2.
<TABLE>
<CAPTION>
(In millions of dollars)
- -------------------------------------------------------------------------------------------------------------------------
ASSETS LILCO HoldCo Subsidiary LIPA
<S> <C> <C> <C>
- -------------------------------------------------------------------------------------------------------------------------
Total Net Utility Plant $3,814.1 $1,777.8 $2,036.3
- -------------------------------------------------------------------------------------------------------------------------
Regulatory Assets
Shoreham related 4,661.1 4,661.1
Regulatory tax asset 1,737.9 21.0 1,716.9
Other 692.8 430.1 262.7
- -------------------------------------------------------------------------------------------------------------------------
Total Regulatory Assets 7,091.8 451.1 6,640.7
- ------------------------------------------------------------------------------------------------------------------------
Nonutility Property and Other Investments 50.8 32.9 17.9
Total Current Assets 858.3 494.2 364.1
Deferred Charges 85.7 38.0 47.7
- -------------------------------------------------------------------------------------------------------------------------
Total Assets $11,900.7 $2,794.0 $9,106.7
=========================================================================================================================
- -------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
- -------------------------------------------------------------------------------------------------------------------------
Long term debt, including current maturities $4,482.9 $1,130.5 $3,352.4
Preferred stock, including current maturities 702.0 363.0 339.0
Common Shareowner's Equity 2,662.5 161.7 2,500.8
- -------------------------------------------------------------------------------------------------------------------------
Total Capitalization $7,847.4 $1,655.2 $6,192.2
Regulatory Liabilities 389.4 1.6 365.2
Current Liabilities 587.4 433.0 154.4
Deferred Credits 2,608.8 211.2 2,397.6
Operating Reserves 467.7 470.4 (2.7)
Commitments and Contingencies - - -
- -------------------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $11,900.7 $2,794.0 $9,106.7
=========================================================================================================================
</TABLE>
95
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Note 15. Quarterly Financial Information (Unaudited)
Summarized quarterly financial data for 1998, 1997 and 1996 is as follows:
<TABLE>
<CAPTION>
(In thousands of dollars except earnings per common share)
- ----------------------------------------------------------------------------------------------------------------------------
Fiscal Year Ended March 31, 1998
-----------------------------------------------------------------------------
3 Months Ended 3/31/97 6/30/97 9/30/97 12/31/97 3/31/98
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating Revenues $851,182 $664,488 $852,408 $779,622 $827,576
Operating Income 190,001 144,079 242,611 171,969 209,637
Net Income 87,697 45,161 144,384 56,756 115,939
Earnings for common stock 74,728 32,193 131,435 43,807 102,992
Basic and diluted earnings per common share .62 .26 1.09 .36 .85
- ----------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------------
Calendar Year Ended December 31, 1996
------------------------------------------------------------------
3 Months Ended 3/31/96 6/30/96 9/30/96 12/31/96
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating Revenues $864,214 $694,602 $849,775 $742,104
Operating Income 190,421 141,065 235,402 169,693
Net Income 81,753 40,524 130,023 64,164
Earnings for common stock 68,682 27,453 116,972 51,141
Basic and diluted earnings per common share .57 .23 .97 .43
- ----------------------------------------------------------------------------------------------------------------------------
</TABLE>
Report of Ernst & Young LLP, Independent Auditors
To the Shareowners and Board of Directors of Long Island Lighting Company
We have audited the accompanying balance sheet of Long Island Lighting Company
and the related statement of capitalization as of March 31, 1998 and 1997, and
December 31, 1996 and the related statements of income, retained earnings and
cash flows for the year ended March 31, 1998, the transition period from January
1, 1997 to March 31, 1997 and each of the two years in the period ended December
31, 1996. Our audits also included the financial statement schedule listed in
the index at Item 14(a). These financial statements and schedule are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards 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. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Long Island Lighting Company at
March 31, 1998 and 1997, and December 31, 1996, and the results of its
operations and its cash flows for the year ended March 31, 1998, the transition
period from January 1, 1997 to March 31, 1997 and each of the two years in the
period ended December 31, 1996, in conformity with generally accepted accounting
principles. Also, in our opinion, the related finacial statement schedule, whe
considered in relation to the basic financial statements taken as a whole,
presents fairly in all material respects the information set forth therein.
As dicussed in Note 1 to the financial statements, during the year ended March
31, 1998 the Company changed its method of accounting for revenues provided for
under the Rate Moderation Component.
Melville, New York
May 22, 1998
96
<PAGE>
Item 9. Changes In And Disagreements With Accountants On Accounting And
Financial Disclosures
Not applicable.
97
<PAGE>
PART III
Item 10. Directors and Executive Officers of the Company
Directors of the Company
All Directors are elected annually. Current information regarding the Company's
Directors follows:
William J. Catacosinos: Chairman of the Board of Directors and Chief Executive
Officer ("CEO") of LILCO since January 1984 and a Director since 1978; President
of LILCO from March 1984 to January 1987 and from March 1994 to December 1996.
Dr. Catacosinos, 68, is a resident of Mill Neck, Long Island. Received bachelor
of science degree, masters degree in business administration and a doctoral
degree in economics from New York University. Member, boards of Atlantic Bank of
New York; Long Island Association; Empire State Business Alliance; and a member
of the Advisory Committee of the Huntington Township Chamber Foundation. Former
chairman and chief executive officer of Applied Digital Data Systems, Inc.,
Hauppauge, New York; chairman of the board and treasurer of Corometric Systems,
Inc. of Wallingford, Connecticut; and assistant director at Brookhaven National
Laboratory, Upton, New York.
John H. Talmage: Director of LILCO since 1982. Graduate of the College of
Agriculture and Life Sciences, Cornell University, Mr. Talmage is 68. President
since 1992 and director since 1960, Friar's Head Farm, Inc.; Chairman, board of
directors, H.P. Hood, Inc. of Boston, Massachusetts, 1980 to 1995; partner, HR
Talmage & Son Farm 1954 to present; director, Agway, Inc., 1967 to 1995; Curtice
Burns Foods, Inc., 1969 to 1984; and Suffolk County Federal Savings and Loan
Association, 1975 to 1982.
Basil A. Paterson: Director of LILCO since 1983. Received juris doctorate from
St. John's University School of Law. Served as Secretary of State of New York
from 1979 to 1982, as Deputy Mayor of New York City, as a New York State Senator
and as a commissioner of the Port Authority of New York and New Jersey. Mr.
Paterson, 72, is a partner in the law firm of Meyer, Suozzi, English and Klein,
P.C., Mineola, New York. Served as a professor at a number of universities, as a
member of the board of editors of the New York Law Journal and as a member of
the State of New York Commission on Judicial Nomination.
George Bugliarello: Director of LILCO since 1990. Received doctor of science
degree in engineering from Massachusetts Institute of Technology and several
honorary degrees from other institutions. Dr. Bugliarello, 71, served as
President of Polytechnic University from 1973 to July 1994, and presently holds
the position of Chancellor. Member, board of directors of the Lord Corporation,
Symbol Technologies, Comtech Telecommunications Corp., the Teagle Foundation,
the Jura Corp., the Greenwall Foundation and Spectrum Information Technologies,
Inc., and the ANSER Corporation. Member of the Council on Foreign Relations and
National Academy of Engineering. Fellow, the American Society of Civil
Engineers, the American Association for the Advancement of Science and the New
York Academy of Medicine; Founding Fellow, the American Institute of Medical and
Biological Engineering. Previously held a NATO Senior Faculty Fellowship at the
Technical University of Berlin and the chairmanship on the
98
<PAGE>
Committee on Science, Engineering and Public Policy of the American Association
for the Advancement of Science and of the Board on Infrastructure and
Constructed Environment, National Research Council. Former member of the
Scientific Committee of the Summer School on Environmental Dynamics in Venice.
George J. Sideris: Director of LILCO since 1991. Received bachelors degree in
economics from New York University. Mr. Sideris, 71, joined LILCO in 1984 as
Vice President of Finance and Chief Financial Officer. Became Senior Vice
President of Finance in 1987 and retired in January 1992. Member, board of
directors of Utilities Mutual Insurance Company through December 1994.
Self-employed as a management and financial consultant, 1981-1984. Previously
served as a vice president of Qualpeco Services, Inc., and as a vice president
and chairman of the Northeast Operations Group of U.S. Industries, Inc.
A. James Barnes: Director of LILCO since 1992. Received undergraduate degree
from Michigan State University and juris doctorate from Harvard Law School. Mr.
Barnes, 56, served as General Counsel of the U.S. Department of Agriculture from
1981 to 1983, as General Counsel of the U.S. Environmental Protection Agency
from 1983 to 1984 and as Deputy Administrator of the Agency from 1985 to 1988.
Previously was a partner in the law firm of Beveridge, Fairbanks and Diamond,
Washington, D.C. and also served with the U.S. Department of Justice. Joined the
Indiana University School of Public and Environmental Affairs as its Dean in
1988. Currently serving as a member of the Board of Trustees of the National
Institute for Global Environmental Change.
Richard L. Schmalensee: Director of LILCO since 1992. Received doctoral degree
in economics and bachelor of science degree in economics, politics and science
from the Massachusetts Institute of Technology ("MIT"). Gordon Y. Billard
Professor of Economics and Management at MIT's Sloan School since 1988. Served
as member of the President's Council of Economic Advisors from 1989 to 1991.
Currently, Deputy Dean of the MIT Sloan School of Management and Director of the
MIT Center for Energy and Environmental Policy Research. Dr. Schmalensee, 54, is
a consultant to a variety of government agencies and private firms through the
National Economic Research Associates Inc. on a range of issues including
aspects of utility regulation.
Renso L. Caporali: Director of LILCO since 1992. Received doctorate and two
masters degrees in Aeronautical Engineering from Princeton University and a
masters of mechanical engineering degree and bachelor of civil engineering
degree from Clarkson College of Technology. Dr. Caporali, 65, served as
President of Grumman Corporation's Aircraft Systems Division since 1985, Vice
Chairman of Corporate Technology 1988 to 1990 and Chairman and CEO from 1990 to
June 1994. Consultant to and member of the board of directors of
Northrop-Grumman from June 1994 to March 1995. Serves on a Princeton University
Advisory Council. Former Chairman of the Aerospace Industries Association's
Board of Governors and Executive Committee. Presently corporate Senior Vice
President of Engineering and Business Development for the Raytheon Company.
Member of the National Academy of Engineering.
Katherine D. Ortega: Director of LILCO since 1993. Received bachelor of arts
degree in business and economics from Eastern New Mexico University and three
honorary doctor of law
99
<PAGE>
degrees and an honorary doctor of social science degree. Ms. Ortega, 63, served
as Treasurer of the United States from 1983 to 1989. Served as a commissioner of
the Copyright Royalty Tribunal, a member of the President's Advisory Committee
on Small and Minority Business and an alternate representative to the United
Nations General Assembly. Member of the board of directors of Ultramar Diamond
Shamrock Corporation, The Kroger Company, Ralston Purina Company, Rayonier Inc.
and Catalyst. Member of the Comptroller General's Consultant Panel. Advisory
Board Member of Washington Mutual Investors Fund.
Vicki L. Fuller: Director of LILCO since 1994. Received bachelors degree at
Roosevelt University and masters degree in business administration at the
University of Chicago and is a Certified Public Accountant. Ms. Fuller, 41,
served as an associate in Morgan Stanley and Co.'s corporate finance department
from 1981 to 1983. Served as a rating officer at Standard & Poor's Corporation
from 1984 to 1985. Joined Equitable Capital Management Corporation ("ECM") in
1985 as a senior investment manager, holding various positions including
Managing Director from 1989 to 1993. Vice President of Alliance Capital
Management Corporation ("Alliance"), which acquired ECM, from 1993 to 1994;
currently holds the position of Senior Vice President of Alliance. In compliance
with Section 305(b) of the Federal Power Act, Ms. Fuller has authorization to
hold the position of an officer or director of a public utility and at the same
time the position of an officer or director of a firm that is authorized to
underwrite or participate in the marketing of the securities of a public
utility.
James T. Flynn: Appointed by the Board of Directors, Mr. Flynn became a Director
in December 1996. Holds a bachelor of science degree in mechanical engineering
from Bucknell University and is a Licensed Professional Engineer. Joined LILCO
in October 1986 as Vice President of Fossil Production and was promoted to Group
Vice President, Engineering and Operations in April 1992. Appointed Executive
Vice President and Chief Operating Officer in March 1994. Mr. Flynn, 64, has
served as President and Chief Operating Officer since December 1996.
Executive Officers of the Company
Information required by Item 10 as to the Company's Executive Officers is set
forth in Item 1, "Business" under the heading "Executive Officers of the
Company" above.
Compliance with Section 16(a) of the Exchange Act
LILCO is required to identify any Director, Officer, or person who owns more
than ten percent of a class of equity securities who failed to timely file with
the Securities and Exchange Commission (the "SEC") a required report relating to
ownership and changes in ownership of LILCO's equity securities. Based on
information provided to LILCO by such persons, all LILCO Officers and Directors
made all required filings during the fiscal year ended March 31, 1998. LILCO
does not know of any person beneficially owning more than 10% of a class of
equity securities.
100
<PAGE>
Item 11. Executive Compensation
Compensation Paid to Directors
The annual retainer fee paid to each Director during the prior fiscal year was
$12,500 in cash and $12,500 applied to a deferred stock unit account, except for
Dr. Catacosinos and Mr. Flynn who, as Officers of LILCO, do not receive
compensation for serving as Directors. The fee paid to each Director who is not
also an Officer of LILCO for attending each meeting of the Board of Directors or
of one of its committees was $500.
Under the terms of the Directors' Stock Unit Retainer Plan (the "Retainer
Plan"), each non-employee director of LILCO is required to apply at least 50% of
his or her annual retainer to the purchase of Common Stock units ("Stock
Units"). Allocation of Stock Units under the Retainer Plan are made
automatically on the date during each fiscal quarter on which the quarterly
installment of the annual retainer is paid.
Under the Retainer Plan, the value of the units which will be credited to each
non-employee Director's account on a quarterly basis will be determined by
dividing the aggregate amount of cash credited to such account by the closing
price per share of LILCO Common Stock, as reported on a New York Stock Exchange
listing of composite transactions, on the first trading day of the calendar
month in which the Participant's retainer is paid. The amounts accumulated
pursuant to the Retainer Plan will be held until such time as (i) a participant
ceases to serve as a Director or Consulting Director; (ii) a participant's
death; or (iii) a "Change in Control" (as defined in the Retainer Plan).
If the Director so elects, the aggregate value of the Stock Units accumulated
pursuant to the Retainer Plan may be received in certificated shares of LILCO
Common Stock at the time of distribution. The Director may elect to receive a
distribution of Retainer Plan benefits in a lump sum or in ten annual
installments. Any such shares shall be purchased by LILCO on the open market or
shall be taken from shares of Common Stock previously acquired by LILCO and held
in its treasury. Prior to distribution, a Director shall have no voting or other
rights of a shareholder with respect to such Stock Units. However, each
Director's account will be credited with an amount equal to the amount of any
dividends paid on shares of LILCO Common Stock proportionate to the number of
Stock Units accumulated pursuant to the Retainer Plan prior to such dividend
payment date. Amounts so credited shall be applied toward the purchase of an
additional number of Stock Units. The transactions contemplated with KeySpan
and/or LIPA will result in a Change in Control for purposes of the Retainer
Plan.
LILCO has entered into a consulting agreement with Eben W. Pyne, a former
Director of LILCO, naming him Consulting Director. This agreement provides that
the Consulting Director will advise and counsel the Board and any of its
committees on various matters and will receive an annual retainer of $25,000
(half of which was credited to a deferred stock unit account pursuant to the
Retainer Plan as discussed above) plus an additional $500 for each Board or
committee meeting attended. A Consulting Director does not have the right to
vote at meetings of the Board or at meetings of committees of the Board.
Directors may elect to defer the receipt of any portion of their compensation
under the Deferred Compensation Plan for Directors. Amounts deferred may be
allocated to a deferred
101
<PAGE>
compensation account. Each participating Director's account accrues interest,
compounded quarterly, at the prime rates plus 1/2%. The Deferred Compensation
Plan for Directors is unfunded and any accounts under the plan will be general
obligations of LILCO. Distributions from a deferred compensation account
commence upon termination of membership on the Board of Directors, death or
disability, or at a date previously designed by the participating Director.
Distributions from the deferred compensation account may be made by lump-sum
payment or annually over either a five or ten-year period. Currently none of the
Directors are participating in the Deferred Compensation Plan for Directors. The
Deferred Compensation will be terminated immediately prior to the completion of
the transactions contemplated with KeySpan and/or LIPA.
LILCO has a Retirement Plan for Directors (the "Retirement Plan"), providing
benefits to Directors who are not or who have not been Officers of LILCO.
Directors who have served in that capacity for more than five years qualify as
participants under the plan. The plan provides for a monthly benefit equal to
one-twelfth of the highest annual retainer paid to each participant. A full
benefit is available for participants who serve for ten years with a reduction
of one-sixtieth for each month of service less than ten years. Under the plan,
payment of benefits is to begin when the Director ceases to serve as a Director
or Consulting Director or reaches age 65, whichever is later. The plan also
provides that in the event of a "change in control" (as defined in the
Retirement Plan), including by virtue of an acquisition of LILCO's assets or
stock, the value of vested benefits could be payable immediately. In addition to
Directors Barnes, Bugliarello, Caporali, Ortega and Schmalensee who would be
entitled to be paid a reduced benefit, Directors Paterson, Talmage and Pyne
would be entitled to be paid full benefits were they to cease to serve as a
Consulting Director or Director at this time. Benefits are provided on a
straight-life annuity basis except that if the Director is married at the time
benefits begin, a joint and 50% survivor benefit may be paid on an actuarially
equivalent basis. The benefits are unfunded and are general obligations of
LILCO. The transactions contemplated with KeySpan and/or LIPA will result in a
Change in Control for purposes of the Retirement Plan and such Retirement Plan
will be terminated immediately prior to the close of these transactions.
LILCO entered into an agreement in 1987 with Mr. Sideris, while he was an
Officer of LILCO, which provides retirement benefits supplementing the benefits
to which he is entitled under LILCO's Retirement Income Plan and Supplemental
Death and Retirement Benefits Plan, both discussed below. LILCO has established
a trust, which is currently making payment of the retirement benefits.
Notwithstanding the creation of the trust, LILCO continues to be primarily
liable.
Pursuant to the New York Business Corporation Law and LILCO By-laws, LILCO has
entered into agreements with its Directors and Officers providing for
indemnification and advancement of expenses in defending certain actions or
proceedings in advance of their final disposition subject to refund if they are
found not to be entitled to indemnification. LILCO has established a trust, the
Long Island Lighting Company Officers' and Directors' Protective Trust, to fund
LILCO's obligations under these agreements.
102
<PAGE>
Report of the Compensation and Management
Appraisal Committee on Executive Compensation
The disclosure contained in this section of the Form 10-K shall not be deemed
incorporated by reference into any prior filing by LILCO pursuant to the
Securities Act of 1933 or the Securities Exchange Act of 1934 that incorporate
future filings or portions thereof (including this Form 10-K or any amendment or
any part thereof).
The Compensation and Management Appraisal Committee (the "Committee"), which
establishes the procedures by which management compensation is determined,
reviews and recommends to the Board of Directors the compensation levels of
LILCO's officers and administers the Annual Stock Incentive Compensation Plan
(the "Annual Stock Incentive Plan") and the Long-Term Incentive Plan (the
"Long-Term Incentive Plan") discussed below. The Committee is made up entirely
of outside Directors. Its members are George Bugliarello, A. James Barnes,
Richard L. Schmalensee and John H. Talmage.
During 1997, the Committee used two outside consultants, the Hay Group ("Hay")
and William M. Mercer, Inc. ("Mercer"), to review the compensation levels of
LILCO's officers, including the named executive officers, and to provide advice
with respect to incentive compensation arrangements. LILCO's Human Resources
office also supplied industry compensation comparisons.
Executive Compensation Philosophy
It is the Board's philosophy to use incentives and other variable
performance-based pay programs to link executive pay with enhancements to LILCO
performance and customer service and to ensure the attraction, retention and
motivation of key executives. In order to keep pace with industry practice and
accomplish these objectives, the Board adopted the Annual Stock Incentive
Program in 1995 and adopted the Long-Term Incentive Program in 1996. Both
incentive programs have been approved by common stock shareholders. This
performance-based compensation philosophy places a significant emphasis on the
achievement of strategic goals related to financial and customer service
performance. However, even after the adoption of the Annual and Long-Term
Incentive Plans, data provided to the Committee by Hay and Mercer indicate that
LILCO's officer total compensation opportunities remains significantly below all
competitive market segments, including other comparable electric utilities, as
described below.
Determination of Base Salary Levels
In 1997, the Committee considered adjustments to base salary ranges using the
external comparisons to other utility and non-utility companies as described
below. Specifically, the Committee studied the average compensation levels of
comparable executives of three databases provided by Hay for general industry,
metropolitan New York companies and 15 electric and gas stock-issuing utilities.
For CEO compensation, Hay also provided comparisons to 37 Standard & Poor's
Utilities. In addition to compensation levels among the Hay databases, the
Committee also reviewed the results of the Edison Electric Institute's Annual
Compensation Survey of 85 utilities (the "EEI Utilities") as well as the
compensation paid to the officers of ten other regional utilities. Based on
these comparisons and the recommendation of Hay, the Board adopted a
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philosophy to target base salary ranges at the median of general industry in the
metropolitan New York area.
Individual base salary increases within those ranges are then subjectively
determined based on several factors. These factors include the competitiveness
of the executive's current base salary and potential incentive compensation, the
executive's individual accomplishments during the year and the executive's
length of time in his or her position. However, based on data provided by Hay in
December 1997, LILCO base salaries were 4.2 percent below general industry, 11.7
percent below metropolitan New York companies and 9.7 percent below the Hay
utility group.
The Annual Stock Incentive Compensation Plan
Annual incentive compensation is earned under LILCO's Annual Stock Incentive
Plan. This Plan was adopted in 1995 and approved by shareholders at the 1997
Annual Meeting. Awards earned under the Plan, less applicable tax withholding,
are paid in common stock. By making the awards payable in LILCO common stock,
officers' performance is more closely aligned with shareholder interest. At the
end of 1997, the Board altered its policy of paying awards in the calendar year
following the year in which they were earned to a policy of paying awards at the
end of the year in which they were earned. Therefore, officers received payment
in stock for the performance achieved in 1997 at the end of December 1997. In
addition, officers received payment at that time of awards for performance
earned in 1996.
The Annual Stock Incentive Plan is based on the achievement of two quantifiable
objectives: reducing expenditures and maintaining or improving critical service
goals. If threshold levels are not achieved for either objective, no incentive
is earned. As threshold levels are exceeded, the officers become eligible to
receive awards from the Annual Stock Incentive Plan.
For 1998, target incentive awards - the amounts earned if goal performance
levels are attained for all program objectives - are 60% for the CEO, 50% for
the COO, 35% for senior officers and 20% for other officers, of the greater of
their base salary or the midpoint of the base salary range for each participant.
For 1997, target incentive awards were 45% for the CEO, 30% for the COO, 20% for
senior officers and 15% for other officers. For 1996, target incentive awards
were 45% for the CEO, 25% for the COO, 15% for senior officers and 10% for other
officers. The midpoint for the base salary range is dependent upon the
executive's level in the organization. Seventy-five percent of each individual's
earned incentive award is based on the level of achievement of the two corporate
objectives. The balance of each award, which can range from zero to 50 percent
of the earned incentive award, is then subjectively determined by the Committee
based on each individual's contribution toward helping LILCO achieve its
objectives. Based on the level of achievement for the increase in net cash flow
and service goals, and individual contributions to LILCO, awards under the
Annual Stock Incentive Plan paid in 1997 for plan year 1997 and 1996 ranged from
75 to 112 percent and from 75 to 124 percent, respectively, of each individual's
earned incentive award. As a result of the closing of the KeySpan Transaction at
the end of May 1998, both KeySpan and LILCO terminated their Annual Incentive
Plans. LILCO pro-rated its target goals so that 5/12ths of the earned incentive
was made based on the results achieved to date. For 1998, all participants were
paid 100 percent of their pro-rated individual earned incentive.
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The Officer Long-term Incentive Plan
In December 1995, LILCO's Board of Directors adopted, and at the 1996 Annual
Meeting the shareholders approved, the Long-Term Incentive Plan. The purpose of
the Long-Term Incentive Plan is to motivate the Officers to meet or exceed
LILCO's business goals, with a particular focus on the long-term effects of
their actions, and to provide incentives for continued service to LILCO.
Awards made under the Long-Term Incentive Plan are paid only upon the attainment
of financial performance goals or goals set by the Committee. The first
Performance Period was for two years (1996-1997) and the goals included freezing
rates, improving earnings and reducing operating and maintenance expenditures.
Subsequent Performance Periods were to include goals to be attained over the
period of three calendar years, with a new cycle beginning every two years (the
"Performance Period"). Awards are paid for the attainment of specified
threshold, target and maximum results over the Performance Period and are a
specified percentage per year of the greater of the participant's base salary or
midpoint of that individual participant's salary range. For the 1996-1997
Performance Period, the maximum award of 125% of each participants target
incentive award was earned.
Originally, the Plan was designed so that the awards would be paid in two
installments, each of which could be paid in shares of Common Stock. However,
following the completion of the first cycle at the end of 1997 and due to the
anticipated closing of the KeySpan Transaction during 1998, the Board determined
to award the full amounts for the 1996-97 cycle to all officers. In addition,
similar to the Annual Stock Incentive Plan and as a result of the closing of the
KeySpan Transaction at the end of May 1998, both KeySpan and LILCO terminated
their Long-Term Incentive Plans. LILCO pro-rated its target goals so that
17/36ths of the earned incentive award for the 1997-99 Performance Period was
made. All goals for this period achieved their maximum levels and, thus, 125% of
each participant's target incentive award was earned.
Special Performance Incentives
During 1997, the Board authorized special performance incentives to seven
officers, including four of the named officers in the Compensation table, in
recognition of the efforts of these individuals in connection with the KeySpan
Transaction and the LIPA Transaction. The amount of the awards were paid in
shares of common stock, net of appropriate employment tax withholdings, and were
based on a percentage of the greater of base salary or the midpoint of the base
salary range for each participant. Awards related to the LIPA Transaction ranged
from 5 percent to 20 percent, and for the KeySpan Transaction ranged from 5
percent to 25 percent, based on each individual's contribution and involvement
in one or both of the transactions.
Transaction-Related Actions
In order to reduce the risk of loosing key executives during the critical period
of planning for the consummation of the KeySpan Transaction and LIPA
Transactions, the Company entered into Retention Agreements with eligible
officers, except the CEO and COO, for a one-year period commencing July 1997.
These Agreements provided an incentive of 20 percent of the greater of
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each participant's base salary or the midpoint of the base salary range for
continued employment throughout the period of the Agreement.
In addition, payments were made of benefits previously accrued by executives
under plans and programs which are not to be continued by the new combined
entity.
Finally, because the payments of the pro-rated 1998 Annual Incentive and the
1997-1999 Long-term Incentive were made immediately prior to the closing of the
two transactions, these awards were authorized to be paid in cash rather than
stock for administrative simplicity prior to the share exchange and delisting of
LILCO's Common Stock.
CEO Compensation
Coming into 1997, Dr. Catacosinos' base salary had been held at its March 1995
level in order to transition to incentive-based compensation through the
introduction of the Annual Stock and Long-Term Incentive Plans. Therefore,
during 1997, the Board twice, in January and in December, considered Dr.
Catacosinos' base salary level. Each time the Board considered the competitive
market, Dr. Catacosinos's tenure as CEO and the performance factors described
below. Based on these factors, Dr. Catacosinos' base salary was increased by 14
percent in February 1997 and by 5.7 percent in December 1997.
In authorizing the February increase in base salary for Dr. Catacosinos, the
Board considered the Company's performance during 1996. Throughout 1996, the
Company continued to pursue its aggressive program to contain operating and
maintenance expenses as well as capital expenses. As a result, budget targets
were underrun by 5.6 percent and earnings increased by 4 cents per share. In
addition, positive net cash flow of $241 million was achieved and the Company
was able to use $415 million of cash to satisfy its obligation regarding G&R
bonds that matured. The debt to equity ratio continued to improve, dropping from
61.8 to 59.3 percent. In addition, at the end of 1996 the Company had
successfully negotiated a merger agreement with Brooklyn Union that is expected
to result in significant synergy savings to the combined entity and enhance such
entity's competitive position.
In authorizing the December increase in base salary for Dr. Catacosinos, the
Board considered the Company's performance and achievements during 1997. Notably
in 1997, the Company negotiated the LIPA Transaction that would enable electric
rates to be reduced by approximately 20 percent and included the purchase by
LIPA, in a stock transaction, of the electric transmission and distribution
system, the Company's 18 percent interest in the Nine Mile Point 2 nuclear plant
and the Company's electric regulatory assets. In addition during 1997, while
planning for the consummation of the KeySpan Transaction and LIPA Transaction,
the Company was also able to achieve significant financial results.
Specifically, earnings per share increased by 13 cents per share. Net cash flow
of $187 million was achieved. The Company was able to use cash to redeem $252
million of maturing debt, reducing the debt to equity ratio to 57.5 percent.
In making its determination with respect to Dr. Catacosinos' Annual Stock
Incentive Plan award for plan year 1996, the Board considered, among other
things, the level of achievement of the budget and service goals in accordance
with the Annual Stock Incentive Plan and the period of
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time from the earning of the incentive to the granting of the award. Based on
these achievements, the Board approved an incentive award for Dr. Catacosinos of
10,535 shares of LILCO common stock. For 1997, based on the level of goal
achievement, Dr. Catacosinos was awarded 8,351 shares of common stock. Awards of
shares of common stock for 1996 and 1997 were net of the appropriate income and
employment taxes. For the 1998 pro-rated incentive, Dr.
Catacosinos was granted an award of $218,750.
With respect to Dr. Catacosinos' 1996-97 Long-term Incentive, based on the
results achieved, the Board granted an award of 17,164 shares of Common Stock,
net of appropriate income and employment taxes. For the 1997-99 pro-rated
Performance Period, an award of $743,750 was granted based on the results
achieved.
Hay's market comparisons in 1997 showed that Dr. Catacosinos' total direct
compensation was 21.5 percent below general industry, 25.3 percent below
metropolitan New York companies and 27.4 below the Hay utility group. However,
by establishing direct links between performance and both direct and long-term
compensation, the Committee believes that LILCO's compensation programs properly
align management's interests with the long-term interests of ratepayers and
shareholders.
Certain Tax Matters
Generally, Section 162(m) of the Internal Revenue Code of 1986, as amended
limits tax deductions for executive compensation to $1 million. However, since
LILCO will have no publicly traded equity securities at the end of its 1998 tax
year, Section 162(m) does not apply.
George Bugliarello -- Chairman
John H. Talmage
A. James Barnes
Richard L. Schmalensee
Stock Performance Graph
Set forth below is a graph comparing the cumulative return of LILCO, the
Standard & Poor's 500 Composite Stock Index ("S&P 500") and the S&P Electric
Utilities Index ("S&P ELEC") over the preceding five fiscal years commencing
with fiscal year ended March 31, 1993. The graph assumes a $100 initial
investment on March 31, 1993, and a reinvestment of dividends in LILCO and each
of the companies reported in the indices.
LILCO S&P 500 S&P ELEC
1993 $ 100 $ 100 $ 100
1994 84 101 90
1995 63 117 93
1996 85 155 113
1997 127 186 112
1998 177 275 155
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PRIVILEGED AND CONFIDENTIAL
ATTORNEY-CLIENT COMMUNICATION
Compensation Paid to Executive Officers
Summary Compensation Table: In March 1997, the Board of Directors voted to
change the Company's fiscal year end from December 31 to March 31 effective with
the three month period ended March 31, 1997 (the "Transition Period").
Accordingly, the following table illustrates the compensation paid by LILCO to
each of its most highly compensated Executive Officers for the fiscal year ended
March 31, 1998 and for the fiscal years ended December 31, 1996 and 1995. Also
included is certain compensation earned during fiscal 1998.
<TABLE>
<CAPTION>
Annual Compensation Long Term Compensation
- -----------------------------------------------------------------------------------------------------------------------------------
Other Restricted Payouts-
Annual Stock Options/ LTIP All Other
Name and Principal Salary Bonus Compensation Award(s)($) SARs (#) Payouts Compensation
Position Year ($)(1)(2) ($)(3) ($) ($)(4) ($)(5)
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
William J. Catacosinos - 1997/98 673,333(6) 1,202,972 n/a n/a n/a 742,500 23,241
CEO 1996 580,413(6) 153,203 n/a n/a n/a n/a 18,653
1995 587,976(6) 0 n/a n/a n/a n/a 15,184
- -----------------------------------------------------------------------------------------------------------------------------------
James T. Flynn - COO and 1997/98 310,000 408,956 n/a n/a n/a 294,362 8,300
President 1996 263,364 90,554 n/a n/a n/a n/a 5,800
1995 255,500 0 n/a n/a n/a n/a 3,725
- -----------------------------------------------------------------------------------------------------------------------------------
Leonard P. Novello - 1997/98 258,335 211,458 n/a n/a n/a 125,000 1,753
Senior Vice President 1996 236,186 33,693 n/a n/a n/a n/a 1,410
and General Counsel 1995 176,250(7) 0 n/a n/a n/a n/a 883
- -----------------------------------------------------------------------------------------------------------------------------------
Michael E. Bray - 1997/98 254,334(8) 62,500 n/a n/a n/a 0 738
Senior Vice President - 1996 0 0 n/a n/a n/a n/a n/a
Electric Business Unit 1995 0 0 n/a n/a n/a n/a n/a
- -----------------------------------------------------------------------------------------------------------------------------------
Adam M. Madsen - 1997/98 198,666 133,945 n/a n/a n/a 96,196 833
Senior Vice President - 1996 172,166 15,826 n/a n/a n/a n/a 1,392
Corporate and Strategic 1995 162,000 0 n/a n/a n/a n/a 1,205
Planning
=================================================================================================================================
</TABLE>
* n/a - Not Applicable.
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Notes to Summary Compensation Table:
(1) During the Transition Period, Dr. Catacosinos, Mr. Flynn, Mr. Novello, and
Mr. Madsen received salary payments of $133,234, $75,000, $62,083, $43,000,
respectively. As discussed below, Mr. Bray was not an employee of the
Company during the Transition Period.
(2) LILCO has in place a 401(k) Capital Accumulation Plan, which qualifies for
favorable tax treatment under the Internal Revenue Code of 1986, as
amended. This plan is designed to provide for salary reduction
contributions by participants under Section 401(k) of the Internal Revenue
Code of 1986, as amended that permit employees to defer a portion of their
current compensation and therefore a portion of their current federal and,
in most instances, state and local income taxes. Although this plan allows
LILCO to make matching contributions to these deferred amounts, no such
matching contributions have been made to date. The amounts shown for annual
salary in the Summary Compensation Table for each individual officer
include amounts deferred by those individuals into this plan.
(3) Represents (i) the dollar value of LILCO Common Stock awards under the
Annual Stock Incentive Plan for plan years 1996 (other than for Mr. Bray)
and 1997, including applicable tax withholdings and (ii) awards in
connection with the LIPA and KeySpan transactions (other than for Mr.
Bray). The net amount of these awards were primarily paid in shares of
LILCO Common Stock as follows: Dr. Catacosinos - 27,081 shares, Mr. Flynn -
8,976 shares, Mr. Novello - 4,533 shares, Mr. Bray - 1,406 shares, and Mr.
Madsen - 3,013 shares. For the 1998 plan year, pro rata amounts will be
paid in cash immediately prior to completion of the transactions
contemplated with KeySpan and LIPA as follows: Dr. Catacosinos - $218,750,
Mr. Flynn - $109,354, Mr. Novello - $50,130, Mr. Bray - $48,998, and Mr.
Madsen - $38,646.
(4) Represents the dollar value of LILCO Common Stock awards under the Long
Term Incentive Plan for plan years 1996-1997, including applicable tax
withholdings. The net amount of the awards were paid in shares of LILCO
Common Stock as follows: Dr. Catacosinos - 16,703, Mr. Flynn - 6,621, Mr.
Novello - 2,812, Mr. Madsen - 2,164. For the 1998 plan year, pro rata
amounts will be paid in cash immediately prior to completion of the
transactions contemplated with KeySpan and LIPA as follows: Dr. Catacosinos
- $743,150, Mr. Flynn - $371,803, Mr. Novello - $170,442, Mr. Bray -
$166,593, and Mr. Madsen - $131,395.
(5) LILCO has a noncontributory Supplemental Death and Retirement Benefits Plan
for its Officers and certain other senior management employees. Currently,
death benefits for the Chairman, CEO, President and Chief Operating Officer
("COO") are five times their plan compensation and, for each other Officer,
three times their plan compensation. Compensation under this plan is
defined as the highest salary including any incentive earned pursuant to
the Annual Stock Incentive Plan. The cost of life insurance, paid by LILCO
for coverage under this plan, is included in All Other Compensation for
each of the individuals listed. For each year reflected in the Compensation
Table, insurance coverage for these death benefits was provided by
split-dollar life insurance policies on the life of each plan participant.
The amount shown for each participant represents the amount allocated to
such participant for income tax purposes.
(6) A portion of Dr. Catacosinos' salary in each of these years has been
deferred at his request and is reflected in the amounts shown.
(7) Leonard P. Novello assumed duties as General Counsel effective April 1,
1995. Prior to that date, Mr. Novello was General Counsel for the public
accounting firm of KPMG Peat Marwick.
(8) Michael E. Bray assumed the duties of Senior Vice President - Electric
Business Unit effective March 1, 1997. Prior to that date, Mr. Bray was
President and CEO of DB Riley Consolidated.
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Supplemental Death and Retirement Benefits Plan: Officers and certain other
senior management employees eligible to participate in LILCO's Supplemental
Death and Retirement Benefits Plan are provided with death benefits, generally
funded by life insurance, equal to five times the plan compensation for the
Chairman, CEO, President and COO and three times the plan compensation for each
other Officer. "Plan compensation" is defined in this plan as the highest annual
rate of pay consisting of (i) the highest rate of base pay in effect at any time
and (ii) a single incentive benefit payment pursuant to the annual stock
incentive plan. Prior to retirement, participants elect either to receive
continued death benefit coverage or to receive monthly retirement benefits, a
partial lump-sum distribution, or a combination of each. For a participant who
retires on or after age 65 and elects the death benefit, the death benefit
coverage will be continued up to five times plan compensation for the Chairman,
CEO, President and COO and up to three times plan compensation for each Officer.
For a participant who retires on or after age 65 and elects the monthly
retirement income benefit, the annual retirement benefits payable under the
15-year certain option will be, for the Chairman, CEO, President and COO, 25% of
plan compensation and, for each other Officer, 15% of such Officer's plan
compensation, with other options available to make payment on an actuarially
equivalent basis through a lifetime annuity, a joint and survivor annuity or an
increasing income annuity. Retirement benefits under this plan are not available
to participants who retire prior to age 60. A participant will vest upon the
earlier of attainment of age 60 with ten years of service or upon attainment of
his or her normal retirement date (i.e., age 65). If a vested participant
retires prior to age 65, reduced benefits are payable. The terms of Dr.
Catacosinos' employment agreement, discussed below, provide for his continued
employment beyond normal retirement age.
In contemplation of the consummation of the KeySpan transaction, the Board of
Directors determined, for various reasons, to discontinue future participation
in the plan and to make payments of the accrued retirement benefits under it.
The projected annual pension assuming payment on May 28, 1998, pursuant to the
Supplemental Death and Retirement Benefits Plan considering the Change of
Control provisions in the Executive Employment Agreements with each officer, are
as follows: Mr. Flynn, $125,444; Mr. Novello, $16,099; Mr. Bray, $2,658; and Mr.
Madsen, $38,069. Accordingly, each officer received, pursuant to Board actions,
a benefit representing the present value of the projected annual amounts earned.
Pursuant to the terms of the plan, Dr. Catacosinos would be entitled to an
annual retirement benefit, however, because Dr. Catacosinos has made an
assignment of his rights to death benefits, he did not receive any retirement
income benefits under this plan.
LILCO recognized the cost of all benefits provided under the Plan, which were
borne by LILCO's shareholders, as an expense on its income statement. LILCO has
also established a trust to provide for payments of its obligations to retired
participants in the Supplemental Death and Retirement Benefits Plan.
Notwithstanding the creation of the trust, LILCO continues to be primarily
liable for both the death and retirement benefits payable to the participants
and is currently making payments to retired participants.
Retirement Income Plan: Generally, all LILCO employees (except certain leased
and part-time employees) are eligible for inclusion in the Retirement Income
Plan upon completion of one year
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of employment with LILCO. A participant will vest upon completion of five years
of service. This plan is currently noncontributory and provides fixed-dollar
pension benefits.
The Retirement Income Plan uses a career average pay formula which provides a
credit for each year of participation in the retirement plan. For service before
January 1, 1992, pension benefits are determined based on the greater of the
accrued benefit as of December 31, 1991, or by multiplying a moving five-year
average of plan compensation, not to exceed the January 1, 1992 salary, by a
certain percentage determined by years of participation in the retirement plan
at December 31, 1991. For service after January 1, 1992, pension benefits are
equal to 2% of "plan compensation" through age 49 and 2 1/2% thereafter. "Plan
compensation" is defined in this plan as the base rate of pay in effect on
January 1 of each year and may differ from the amounts reported under the
heading "Salary" in the Summary Compensation Table. Any difference is primarily
attributable to the timing of annual salary increases for the named executive
officers which impacts the amount paid to such officer and reported for a given
year.
The following table shows the projected annual retirement benefit payable on a
straight-life annuity basis pursuant to LILCO's Retirement Income Plan to each
of the individuals listed in the Summary Compensation Table at normal retirement
age (which is the later of age 65 or five years of service), assuming
continuation of employment to normal retirement date at the rate of plan
compensation during fiscal 1998:
<TABLE>
<CAPTION>
Annual Credited Normal
Retirement Service as Retirement
Benefit(1) of 3/31/97 Date
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
William J. Catacosinos $196,452 14 years, 2 months April 1, 1995(2)
James T. Flynn $ 68,353 11 years, 6 months January 1, 1999
Leonard P. Novello $ 24,333 3 years, 0 months December 1, 2005
Michael E. Bray $ 10,080 1 year, 1 month June 1, 2012
Adam M. Madsen $ 82,935 30 years, 3 months August 1, 2001
</TABLE>
(1) These Retirement Income Plan benefits may be limited at retirement by the
maximum benefit limitation under Section 415 or the maximum compensation
limitation under Section 401(a)(17) of the Internal Revenue Code. The benefits
shown have been calculated without the limitations. LILCO has established the
Retirement Income Restoration Plan of Long Island Lighting Company to restore
qualified plan benefits which have been reduced pursuant to the Code or which
may not be includible in the calculation of benefits pursuant to LILCO's
Retirement Income Plan. "Plan compensation" is defined in the Retirement Income
Restoration Plan, as the highest annual rate of pay consisting of (i) the
highest rate of base pay in effect at any time and (ii) a single incentive
benefit payment pursuant to the annual stock incentive plan. In the event that
the retirement benefits are reduced by operation of either Section 415 or
401(a)(17) of the Internal Revenue Code, LILCO's Retirement Income Restoration
Plan would provide payment of plan formula pension benefits which exceed those
payable under the Code's maximum limitations. For 1997, the maximum benefit
limit set by Section 415 and applicable to the amounts shown above was $125,000.
For 1997, the maximum compensation limit set by Section 401(a)(17) and
applicable to the amounts shown above was $160,000. For 1998, the maximum
benefit limit set by Section 415 is $130,000 and the maximum compensation limit
set by Section 401(a)(17) and to be utilized for benefits accrued in 1998 is
$160,000. Because the Supplemental Plan retirement benefits were paid through
March 31, 1998, any retirement benefit adjustments payable to the officers are
to be
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made from the Retirement Income Restoration Plan immediately prior to the
completion of the transactions contemplated with KeySpan and/or LIPA.
(2) Dr. Catacosinos' employment agreement, discussed below, provides for his
continued employment beyond his normal retirement date.
Agreements with Executives: LILCO has entered into individual employment
agreements with each of its Officers to provide them with employment security
and to minimize distractions resulting from personal uncertainties and risks of
a change in control of LILCO. Currently, the principal benefits under these
agreements, payable if the Officer's employment is terminated for any reason
(including voluntary resignation) within three years of a change in control (as
defined in these agreements), including by virtue of an acquisition of LILCO's
assets or stock, prior to December 31, 1999, are: (i) severance pay equal to
three years' salary; (ii) accelerated vesting and payment of the value of
supplemental retirement benefits at the time of a change in control, which are
enhanced by three years of service; (iii) continuation of life, medical and
dental insurance for a period of three years; (iv) gross up of any tax payable
pursuant to the Internal Revenue Code amended. The costs associated with these
arrangements will be borne by LILCO's shareholders. Notwithstanding the creation
of a trust to support payment of its obligations, LILCO is primarily liable for
the compensation and retirement benefits payable to the Officers and the trust
will make such payments only to the extent that LILCO does not. The transactions
contemplated with KeySpan and/or LIPA will result in a change in control (as
defined in these agreements) and entitle each Officer to the benefits payable
under the terms of the employment agreements if such Officer's employment is
terminated for any reason.
LILCO has also entered into individual employment agreements with certain of its
officers (not including Dr. Catacosinos and Mr. Flynn), effective July 1, 1997,
pursuant to which such officers are employed for a one year term and are
entitled to receive a retention bonus equal to 20% of the greater of job value
or salary, if they are still employed by LILCO or its affiliates at the end of
such term or are terminated without cause (as determined by the Chief Executive
Officer) prior to the expiration of such term. These agreements have been
entered into to induce such officers to continue their employment during the
period prior to the consummation of the LIPA and KeySpan Transactions.
Under the terms of an employment contract dated as of January 30, 1984, as
amended (the "Contract"), Dr. Catacosinos has agreed to serve as CEO of LILCO
until January 31, 2002. The Contract provides for a five-year consulting period
following the termination of his employment (other than, except after a change
in control, for cause). His consulting compensation will be 90% of his base
annual salary at his retirement during the first two years, 75% of such salary
during the third and fourth years and 50% of such salary during the fifth year.
The Contract also provides for supplemental disability benefits. Dr.
Catacosinos' employment under the Contract may be terminated by LILCO for cause
or for such other reason as the Board of Directors may, in good faith, determine
to be in the best interests of LILCO and by Dr. Catacosinos if he determines it
to be in the best interests of LILCO or for any reason after a change in
control. The transactions contemplated with KeySpan and/or LIPA will result in a
change in control under the Contract. The Contract also provides for vested
Contract Retirement Benefits commencing at the
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earlier of Dr. Catacosinos' retirement or death, payable monthly to Dr.
Catacosinos and his wife as a joint and survivor annuity with a minimum
guaranteed period of ten years or the present value thereof as a lum sum on a
change-in-control. The Contract Retirement Benefits in any year will be reduced
by monthly benefits payable under LILCO's other retirement plans payable under
their normal retirement forms. The benefit will be based upon a formula that
considers his age at retirement, his highest annual salary, the highest bonus he
has received and the length of his service to LILCO including service as a
Director, employee or consultant. The benefit is also subject to certain annual
cost of living adjustments. Assuming, for illustrative purposes, his retirement
at May 31, 1998 the amount of the estimated retirement benefit payable under the
Contract to Dr. Catacosinos as of May 31, 1998 (assuming continuation of his
current salary) would be approximately $2,094,000. LILCO has established trusts
to provide for payments of its obligations under the Contract, the costs of
which are borne by LILCO's shareholders. Notwithstanding the creation of the
trusts, LILCO continues to be primarily liable for all amounts payable to Dr.
Catacosinos and the trusts will make such payments to the extent that LILCO does
not.
The Officers have also entered into indemnification agreements that are
described below under the heading "Transactions with Management and Others."
No Director or Officer or associate of any Director or Officer has any
arrangement with any person with respect to any future employment by LILCO or
its affiliates other than those described herein.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Current Ownership of LILCO Common Stock. The following table shows the number of
shares* of Common Stock beneficially owned, as of March 31, 1998, by each
Director, certain Officers, and by all Directors and Officers as a group. The
percentage of shares held by any one person, or all Directors and Officers as a
group, does not exceed 1% of all outstanding shares of Common Stock. The address
of each of the Directors and Officers is: c/o Long Island Lighting Company, 175
East Old Country Road, Hicksville, New York 11801.
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Name Number of Shares*
A. James Barnes.....................................................1,893
Michael E. Bray.....................................................1,406
George Bugliarello..................................................2,393
Renso L. Caporali...................................................2,625
William J. Catacosinos.............................................25,442
James T. Flynn.....................................................21,327
Vicki L. Fuller.....................................................1,693
Adam M. Madsen......................................................7,283
Leonard P. Novello..................................................8,534
Katherine D. Ortega.................................................2,264
Basil A. Paterson...................................................2,499
Richard L. Schmalensee..............................................1,493
George J. Sideris...................................................5,271
John H. Talmage.....................................................1,925
Edward J. Youngling.................................................6,269
All Directors and Officers as a group, including
those named above, a total of 32 persons......................... 157,958
*The number of shares includes whole shares held under LILCO's Investor
Common Stock Plan. The number also includes shares held or beneficially
owned by a spouse, parent or child for which beneficial ownership is
disclaimed for John H. Talmage - 287 shares, and for George Bugliarello
- 500 shares. In addition, the number of shares shown for each
Director, other than Dr. Catacosinos and Mr. Flynn, includes 1,393
LILCO Common Stock units, which do not confer any voting rights,
credited pursuant to the Retainer Plan.
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The following table sets forth certain information with respect to the shares of
Preferred Stock and Common Stock owned by each person known by LILCO to be the
beneficial owner of more than 5% of such Preferred Stock and Common Stock as of
December 31, 1997.
<TABLE>
<CAPTION>
Title of Percentage
Class Names and Address Owned of Class
<S> <C> <C>
Common Stock KeySpan Energy Corporation 23,981,964* 16.6%
One MetroTech Center
Brooklyn, NY 11201-3850
Common Stock The Capital Group Companies, Inc. 11,696,700 9.6%
and
Capital Research and Management Company
333 South Hope Street
Los Angeles, CA 90071
Common Stock John A. Levin & Co., Inc. 6,861,988 5.7%
One Rockefeller Plaza
New York, NY 10020
and
Baker Fentress & Company
200 West Madison Street
Chicago, IL 60606
</TABLE>
*Represents the number of shares that may be purchased pursuant to the
Amended and Restated LILCO Stock Option Agreement filed on June 30,
1997 as Exhibit B to Registration Statement on Form S-4, No. 333-30353.
LILCO has not been advised, nor is it aware, of any additional shares
to which anyone has the right to acquire beneficial ownership.
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Item 13. Certain Relationships and Related Transactions
Transactions with Management and Others
Indemnification of Directors and Officers: For many years prior to 1986,
statutory provisions of the New York Business Corporation Law permitted
corporations, including LILCO, under certain circumstances in connection with
litigation in which its Directors and Officers were defendants, to indemnify
them for, among other things, judgments, amounts paid in settlement and
reasonable expenses. To reimburse it when it has indemnified its Directors and
Officers, LILCO began in 1970, pursuant to statutory authorization, to purchase
Director and Officer ("D&O") liability insurance in each year. D&O liability
insurance also provides direct payment to LILCO's Directors and Officers under
certain circumstances when LILCO has not previously provided indemnification.
LILCO has D&O liability insurance which it has purchased from Associated
Electric & Gas Insurance Services Ltd. ("AEGIS"), Energy Insurance Mutual
("EIM"), Steadfast Insurance Company, A.C.E. Insurance Company and XL Insurance
Company, all with the effective date of August 26, 1997. LILCO also has
liability insurance effective August 26, 1997 purchased from AEGIS and EIM,
which provides fiduciary liability coverage for LILCO, its Directors, Officers
and employees for any alleged breach of fiduciary duty under ERISA. The total
annual premium for all these coverages was approximately $1.5 million in fiscal
1998.
The LILCO By-laws provide for the mandatory indemnification of Directors and
Officers to the extent not expressly prohibited by the New York Business
Corporation Law. In addition, the Bylaws authorize the Board of Directors to
grant indemnity rights to employees and other agents of LILCO. Such provisions
are effective as to all claims for indemnification, whether the acts or
omissions giving rise to a claim for such indemnification occurred or the
expenses for which indemnity is sought were incurred, before or after the
provisions of the By-laws were adopted. One of the provisions of the By-laws
authorized the Board of Directors to enter into indemnification agreements with
any of LILCO's Directors or Officers extending rights to indemnification and
advancement of expenses to such person to the fullest extent permitted by
applicable law. LILCO has entered into such agreements, which are described
under the heading "Compensation Paid to Directors," with each of its Directors
and Officers. Pursuant to the terms of those agreements and the provisions of
the By-laws, LILCO has also established a trust to fund LILCO's obligations
under the agreements.
The LILCO Restated Certificate of Incorporation (the "LILCO Certificate") limits
the personal liability of Directors for certain breaches of duty in such
capacity pursuant to provisions of the New York Business Corporation Law. The
LILCO Certificate does not bar litigation against Directors but provides that
Directors are still required to defend themselves in litigation in which acts or
omissions to act are alleged for which they might be held liable. Furthermore,
the LILCO Certificate provides protection to Directors only and does not affect
the liability of Officers of LILCO for breaches of the fiduciary duties of care
and loyalty.
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PART IV
Item 14. Exhibits, Financial Statement Schedules, And Reports On Form 8-K
(a)(1) List of Financial Statements
Statement of Income for the year ended March 31, 1998, the three
months ended March 31, 1997 and the years ended December 31, 1996
and 1995.
Balance Sheet at March 31, 1998 and 1997 and December 31, 1996.
Statement of Retained Earnings at March 31, 1998 and 1997 and December
31, 1996 and 1995.
Statement of Capitalization at March 31, 1998 and 1997 and December
31, 1996.
Statement of Cash Flows for the year ended March 31, 1998, the three
months ended March 31, 1997 and the years ended December 31, 1996
and 1995.
Notes to Financial Statements.
(2) List of Financial Statement Schedules
Valuation and Qualifying Accounts (Schedule II)
(3) List of Exhibits
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(3) LIST OF EXHIBITS
Exhibits listed below which have been filed with the Securities and Exchange
Commission pursuant to the Securities Act of 1933 or the Securities Exchange Act
of 1934, and which were filed as noted below, are hereby incorporated by
reference and made a part of this report with the same effect as if filed
herewith.
2(a) Amended and Restated Agreement and Plan of Exchange and Merger dated
June 26, 1997 between The Brooklyn Union Gas Company and Long Island
Lighting Company dated as of June 26, 1997 (filed as Annex A to
Registration Statement on Form S-4, No. 333-30353, on June 30, 1997).
2(b) Amendment, Assignment and Assumption Agreement dated as of September
29, 1997 by and among The Brooklyn Union Gas Company, Long Island
Lighting Company and KeySpan Energy Corporation (filed as Exhibit 2.5
to Schedule 13D by Long Island Lighting Company on October 24, 1997).
2(c) Agreement and Plan of Merger dated as of June 26, 1997 by and among BL
Holding Corp., Long Island Lighting Company, Long Island Power
Authority and LIPA Acquisition Corp. (filed as Annex D to Registration
Statement on Form S-4 No. 333-30353 on June 30, 1997).
2(d) Amended and Restated LILCO Stock Option Agreement between The Brooklyn
Union Gas Company and Long Island Lighting Company dated as of June
26, 1997 (filed as Annex B to Registration Statement on Form S-4, No.
333-30353, on June 30, 1997).
2(e) Amended and Restated Brooklyn Union Stock Option Agreement between
Long Island Lighting Company and The Brooklyn Union Gas Company dated
as of June 26, 1997 (filed as Annex C to Registration Statement on
Form S-4, No. 333-30353, on June 30, 1997).
3(a) Restated Certificate of Incorporation of the Company dated November
11, 1993 (filed as an Exhibit to the Company's Form 10-K for the Year
Ended December 31, 1993.)
3(b) By-laws of the Company as amended on December 18, 1996 (filed as an
Exhibit to the Company's Form 10-K for the Year Ended December 31,
1996.)
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4(a) General and Refunding Indenture dated as of June 1, 1975 (filed as an
Exhibit to the Company's Form 10-K for the Year Ended December 31,
1991.)
Twenty-seven Supplemental Indentures to the General and Refunding
Indenture dated as of June 1, 1975, as follows:
Previously Filed As An
Supplemental Indenture Exhibit To The Company's
NUMBER DATE FORM DATE
------ ---- ---- ----
First 06/1/75 10-K 12/31/87
Second 09/1/75 10-K 12/31/87
Third 06/1/76 10-K 12/31/87
Fourth 12/1/76 10-K 12/31/87
Fifth 05/1/77 10-K 12/31/87
Sixth 04/1/78 10-K 12/31/87
Seventh 03/1/79 10-K 12/31/87
Eighth 02/1/80 10-K 12/31/87
Ninth 03/1/81 10-K 12/31/87
Tenth 07/1/81 10-K 12/31/87
Eleventh 07/1/81 10-K 12/31/87
Twelfth 12/1/81 10-K 12/31/87
Thirteenth 12/1/81 10-K 12/31/87
Fourteenth 06/1/82 10-K 12/31/87
Fifteenth 10/1/82 10-K 12/31/87
Sixteenth 04/1/83 10-K 12/31/87
Seventeenth 05/1/83 10-K 12/31/87
Eighteenth 09/1/84 10-K 12/31/87
Nineteenth 10/1/84 10-K 12/31/87
Twentieth 06/1/85 10-K 12/31/87
Twenty-first 04/1/86 10-K 12/31/87
Twenty-second 02/1/91 10-K 12/31/90
Twenty-third 05/1/91 10-K 12/31/91
Twenty-fourth 07/1/91 10-K 12/31/91
Twenty-fifth 05/1/92 10-K 12/31/92
Twenty-sixth 07/1/92 10-K 12/31/92
Twenty-seventh 06/1/94 10-K 12/31/94
4(b) Debenture Indenture dated as of November 1, 1986 from the Company to
The Connecticut Bank and Trust Company, National Association, as
Trustee (filed as an Exhibit to the Company's Form 10-K for the Year
Ended December 31, 1986).
Seven Supplemental Indentures to the Debenture Indenture dated as of
November 1, 1986, filed as follows:
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<PAGE>
Previously Filed As An
Supplemental Indenture Exhibit To The Company's
NUMBER DATE FORM DATE
------ ---- ---- ----
First 11/1/86 10-K 12/31/86
Second 04/1/86 10-K 12/31/89
Third 07/1/86 10-K 12/31/89
Fourth 07/1/92 10-K 12/31/92
Fifth 11/1/92 10-K 12/31/92
Sixth 06/1/93 10-K 12/31/92
Seventh 07/1/93 10-K 12/31/92
4(c) Debenture Indenture dated as of November 1, 1992 from the Company to
Chemical Bank, as Trustee (filed as an Exhibit to the Company's Form
10-K for the Year Ended December 31, 1992).
Four Supplemental Indentures to the Debenture Indenture dated as of
November 1, 1992, filed as follows:
Previously Filed As An
Supplemental Indenture Exhibit to the Company's
NUMBER DATE FORM DATE
------ ---- ---- ----
First 01/1/93 10-K 12/31/92
Second 03/1/93 10-K 12/31/92
Third 03/1/93 10-K 12/31/92
Fourth 03/1/93 10-K 12/31/92
10(a)Sound Cable Project Facilities and Marketing Agreement dated as of
August 26, 1987 between the Company and the Power Authority of the
State of New York (filed as an Exhibit to the Company's Form 10-K for
the Year Ended December 31, 1987).
10(b)Transmission Agreement by and between the Company and Consolidated
Edison Company of New York, Inc. dated as of March 31, 1989 (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1989).
10(c)Contract for the sale of Firm Power and Energy by and between the
Company and the State of New York dated as of April 26, 1989 (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1989).
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<PAGE>
10(d)Capacity Supply Agreement dated as of December 13, 1991 between the
Company and the Power Authority of the State of New York (filed as an
Exhibit to the Company's Form 10-K for the Year Ended December 31,
1991).
10(e)Nine Mile Point Nuclear Station Unit 2 Operating Agreement dated as of
January 1, 1993 by and between the Company, New York State Electric &
Gas Corporation, Rochester Gas and Electric Corporation and Central
Hudson Gas and Electric Corporation (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1993).
10(f)Settlement Agreement on Issues Related to Nine Mile Two Nuclear Plant
dated as of June 6, 1990 by and between the Company, the Staff of the
Department of Public Service and others (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1990).
10(g)Settlement Agreement -- LILCO Issues dated as of February 28, 1989 by
and between the Company and the State of New York (filed as an Exhibit
to the Company's Form 10-K for the Year Ended December 31, 1988).
10(h)Amended and Restated Asset Transfer Agreement by and between the
Company and the Long Island Power Authority dated as of June 16, 1988
as amended and restated on April 14, 1989 (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1989).
10(i)Memorandum of Understanding concerning proposed agreements on power
supply for Long Island dated as of June 16, 1988 by and between the
Company and New York Power Authority as amended May 24, 1989 (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1989).
10(j)Rate Moderation Agreement submitted by the staff of the New York State
Public Service Commission on March 16, 1989 and supported by the
Company (filed as an Exhibit to the Company's Form 10-K for the Year
Ended December 31, 1989).
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10(k)Site Cooperation and Reimbursement Agreement dated as of January 24,
1990 by and between the Company and Long Island Power Authority (filed
as an Exhibit to the Company's Form 10-K for the Year Ended December
31, 1989).
10(l)Stipulation of settlement of federal Racketeer Influenced and Corrupt
Organizations Act Class Action and False Claims Action dated as of
February 27, 1989 among the attorneys for the Company, the ratepayer
class, the United States of America and the individual defendants
named therein (filed as an Exhibit to the Company's Form 10-K for the
Year Ended December 31, 1988).
10(m)Revolving Credit Agreement dated as of June 27, 1989, between the
Company and the banks and co-agents listed therein, with the Exhibits
thereto (filed as an Exhibit to the Company's Form 10-K for the Year
Ended December 31, 1989) and as amended by the First Amendment dated
as of October 13, 1989 (filed as an Exhibit to the Company's Form 10-K
for the Year Ended December 31, 1990) and as amended by the Second
Amendment dated as of March 5, 1992 and as modified by a Waiver dated
November 5, 1992 (filed as an Exhibit to the Company's Form 10-K for
the Year Ended December 31, 1992).
10(n)Indenture of Trust dated as of December 1, 1989 by and between New
York State Energy Research and Development Authority ("NYSERDA") and
The Connecticut National Bank, as Trustee, relating to the 1989 EFRBs
(filed as an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1989).
Participation Agreement dated as of December 1, 1989 by and between
NYSERDA and the Company relating to the 1989 EFRBs (filed as an
Exhibit to the Company's Form 10-K for the Year Ended December 31,
1989).
10(o)Indenture of Trust dated as of May 1, 1990 by and between NYSERDA and
The Connecticut National Bank, as Trustee, relating to the 1990 EFRBs
(filed as an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1990).
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<PAGE>
Participation Agreement dated as of May 1, 1990 by and between NYSERDA
and the Company relating to the 1990 EFRBs (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1990).
10(p)Indenture of Trust dated as of January 1, 1991 by and between NYSERDA
and The Connecticut National Bank, as Trustee, relating to the 1991
EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year
Ended December 31, 1990).
Participation Agreement dated as of January 1, 1991 by and between
NYSERDA and the Company relating to the 1991 EFRBs (filed as an
Exhibit to the Company's Form 10-K for the Year Ended December 31,
1990).
10(q)Indenture of Trust dated as of February 1, 1992 by and between NYSERDA
and IBJ Schroder Bank and Trust Company, as Trustee, relating to the
1992 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K
for the Year Ended December 31, 1991).
Participation Agreement dated as of February 1, 1992 by and between
NYSERDA and the Company relating to the 1992 EFRBs, Series A (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1991).
10(r)Indenture of Trust dated as of February 1, 1992 by and between NYSERDA
and IBJ Schroder Bank and Trust Company, as Trustee, relating to the
1992 EFRBs, Series B (filed as an Exhibit to the Company's Form 10-K
for the Year Ended December 31, 1991).
Participation Agreement dated as of February 1, 1992 by and between
NYSERDA and the Company relating to the 1992 EFRBs, Series B (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1991).
10(s)Indenture of Trust dated as of August 1, 1992 by and between NYSERDA
and IBJ Schroder Bank and Trust Company, as Trustee, relating to the
1992 EFRBs, Series C (filed as an Exhibit to the Company's Form 10-K
for the Year Ended December 31, 1992).
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<PAGE>
Participation Agreement dated as of August 1, 1992 by and between
NYSERDA and the Company relating to the 1992 EFRBs, Series C (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1992).
10(t)Indenture of Trust dated as of August 1, 1992 by and between NYSERDA
and IBJ Schroder Bank and Trust Company, as Trustee, relating to the
1992 EFRBs, Series D (filed as an Exhibit to the Company's Form 10-K
for the Year Ended December 31, 1992).
Participation Agreement dated as of August 1, 1992 by and between
NYSERDA and the Company relating to the 1992 EFRBs, Series D (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1992).
10(u)Indenture of Trust dated as of November 1, 1993 by and between NYSERDA
and Chemical Bank, as Trustee, relating to the 1993 EFRBs, Series A
(filed as an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1993).
Participation Agreement dated as of November 1, 1993 by and between
NYSERDA and the Company relating to the 1993 EFRBs, Series A (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1993).
10(v)Indenture of Trust dated as of November 1, 1993 by and between NYSERDA
and Chemical Bank, as Trustee, relating to the 1993 EFRBs, Series B
(filed as an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1993).
Participation Agreement dated as of November 1, 1993 by and between
NYSERDA and the Company relating to the 1993 EFRBs, Series B (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1993).
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10(w)Indenture of Trust dated as of October 1, 1994 by and between NYSERDA
and Chemical Bank, as Trustee, relating to the 1994 EFRBs, Series A
(filed as an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1994).
Participation Agreement dated as of October 1, 1994 by and between
NYSERDA and the Company relating to the 1994 EFRBs, Series A (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December
31,1994).
10(x)Indenture of Trust dated as of August 1, 1995 by and between NYSERDA
and Chemical Bank, as Trustee, relating to the 1995 EFRBs, Series A
(filed as an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1995).
Participation Agreement dated as of August 1, 1995 by and between
NYSERDA and the Company relating to the 1995 EFRBs, Series A (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1995).
10(y)Indenture of Trust dated as of December 1, 1997 by and between
NYSERDA and The Chase Manhattan Bank, as Trustee, relating to the 1997
EFRBs, Series A (filed as an Exhibit to the Company's Form 10-Q for
the period ended December 31, 1997).
Participation Agreement dated as of December 1, 1997 by and between
NYSERDA and the Company relating to the 1997 EFRBs, Series A (filed as
an Exhibit to the Company's Form 10-Q for the period ended December
31, 1997).
10(z)Supplemental Death and Retirement Benefits Plan as amended and
restated effective January 1, 1993 (filed as an Exhibit to the
Company's Form 10-Q for the Quarterly Period Ended September 30, 1995)
and related Trust Agreement, which Trust Agreement was filed as
Exhibit 10(q) to the Company's Form 10-K for the Year Ended December
31, 1990.
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10(aa) Executive Agreements and Management Contracts
(1) Executive Employment Agreement dated as of January 30, 1984 by and
between William J. Catacosinos and the Company, as amended by
amendments dated March 20, 1987 (filed as an Exhibit to the Company's
Form 10-K for the Year Ended December 31, 1986), December 22, 1989
(filed as an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1989), and December 2, 1991 (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1991), which
amendment was restated by an amendment dated as of December 2, 1991,
and amendments dated as of May 31, 1995 and August 4, 1995 (filed as
Exhibits to the Company's Form 10-Q for the Quarterly Period Ended
September 30, 1995); an Executive Employment Agreement dated as of
August 4, 1995 (filed as an Exhibit to the Company's Form 10-Q for the
Quarterly Period ended September 30, 1995; an amendment dated as of
December 29, 1996 (filed as an Exhibit to the Company's Form 10-Q for
the Quarterly Period Ended June 30, 1997).
(2) Executive Employment Agreement dated as of November 21, 1994 by and
between the Company and Theodore A. Babcock (filed as an Exhibit to
the Company's Form 10-K for the Year Ended December 31, 1994), which
agreement is substantially the same as Executive Employment Agreement
by and between the Company and (1) Charles A. Daverio dated as of
December 1, 1996, (2) Jane A. Fernandez, (3) James T. Flynn, (4)
Joseph E. Fontana, (5) Robert X. Kelleher, (6) Howard A. Kosel dated
as of April 1, 1997, (7) John D. Leonard, Jr., (8) Adam M. Madsen, (9)
Kathleen A. Marion, (10) Brian R. McCaffrey, (11) Joseph W. McDonnell,
(12) Leonard P. Novello dated as of April 1, 1995, (13) Anthony
Nozzolillo, (14) Richard Reichler, (15) William G. Schiffmacher, (16)
Werner J. Schweiger dated as of December 1, 1996, (17) Richard M.
Siegel dated as of December 1, 1996, (18) Robert B. Steger, (19)
William E. Steiger, and (20) Edward J. Youngling.
(3) Executive Employment Agreement by and between the Company and Michael
E. Bray dated as of March 1, 1997 (filed as an Exhibit to the
Company's Form 10- Q for the transition period from 1/1/97 to
3/31/97.)
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<PAGE>
(4) Executive Retention Agreement dated as of July 1, 1997 by and between
the Company and Theodore A. Babcock, Vice President and Treasurer
(filed as an Exhibit to the Company's Form 10-Q for the period ended
December 31, 1997), which agreement is substantially the same as
Executive Retention Agreement by and between the Company and (1)
Michael E. Bray, Senior Vice President; (2) Charles A. Daverio, Vice
President; (3) Jane A. Fernandez, Vice President; (4) Joseph E.
Fontana, Vice President and Controller; (5) Robert X. Kelleher, Senior
Vice President; (6) Howard A. Kosel, Vice President; (7) John D.
Leonard, Jr., Vice President; (8) Adam M. Madsen, Senior Vice
President; (9) Kathleen A. Marion, Vice President; (10) Brian R.
McCaffrey, Vice President; (11) Joseph W. McDonnell, Senior Vice
President; (12) Leonard P. Novello, Senior Vice President and General
Counsel; (13) Anthony Nozzolillo, Senior Vice President and Chief
Financial Officer; (14) Richard Reichler, Vice President; (15) William
G. Schiffmacher, Senior Vice President; (16) Werner J. Schweiger, Vice
President; (17) Richard M. Siegel, Vice President; (18) Robert B.
Steger, Senior Vice President; (19) William E. Steiger, Jr, Vice
President, and (20) Edward J. Youngling,, Senior Vice President.
(5) Indemnification Agreement by and between the Company and Theodore A.
Babcock dated as of February 23, 1994 (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1994), which
agreement is substantially the same as Indemnification Agreement by
and between the Company and (1) Michael E. Bray dated as of March 1,
1997, (2) Charles A. Daverio dated as of December 1, 1996, (3) Jane A.
Fernandez dated as of September 19, 1994, (4) James T. Flynn dated as
of November 25, 1987, (5) Joseph E. Fontana dated as of October 20,
1994, (6) George B. Jongeling dated as of April 1, 1998, (7) Robert X.
Kelleher dated as of November 25, 1987, (8) Howard A. Kosel dated as
of April 1, 1997, (9) John D. Leonard, Jr. dated as of November 25,
1987, (10) Adam M. Madsen dated as of November 25, 1987, (11) Kathleen
A. Marion dated as of May 30, 1990, (12) Brian R. McCaffrey dated as
of November 25, 1987, (13) Joseph W. McDonnell dated as of March 18,
1988, (14) Leonard P. Novello dated as of April 1, 1995, (15) Anthony
Nozzolillo dated as of July 29, 1992, (16) Richard Reichler dated as
of September 30, 1993,
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(17) William G. Schiffmacher dated as of November 25, 1987, (18)
Werner J. Schweiger dated as of December 1, 1996, (19) Richard M.
Siegel dated as of December 1, 1996, (20) Robert B. Steger dated as of
February 20, 1990, (21) William E. Steiger, Jr. dated as of March 1,
1989, and (22) Edward J. Youngling dated as of November 4, 1988.
(6) Indemnification Agreement by and between the Company and Vicki L.
Fuller dated as of January 3, 1994, (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1994) which
agreement is substantially the same as Indemnification Agreement by
and between the Company and (1) A. James Barnes dated as of January
31, 1992, (2) George Bugliarello dated as of May 30, 1990, (3) Renso
L. Caporali dated as of April 17, 1992, (4) William J. Catacosinos
dated as of November 19, 1987, (5) Katherine D. Ortega dated as of
April 20, 1993, (6) Basil A. Paterson dated as of November 19, 1987,
(7) Richard L. Schmalensee dated as of February 8, 1992, (8) George J.
Sideris dated as of November 30, 1987, and (9) John H. Talmage dated
as of November 19, 1987.
(7) Indemnification Agreement by and between the Company and Eben W. Pyne
dated as of April 20, 1993, (filed as an Exhibit to the Company's Form
10-K for the Year Ended December 31, 1993.)
(8) Long Island Lighting Company Officers' and Directors' Protective Trust
dated as of April 18, 1988 as Amended and Restated as of September 1,
1994 by and between the Company and Clarence Goldberg, as Trustee
(filed as an Exhibit to the Company's Form 10-Q for the Quarterly
period Ended September 30, 1994).
(9) Long Island Lighting Company's Retirement Plan for Directors dated as
of February 2, 1990 (filed as an Exhibit to the Company's Form 10-K
for the Year Ended December 31, 1989).
(10) Trust Agreement for Officers dated March 20, 1987 by and between the
Company and Clarence Goldberg as Trustee (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1988).
128
<PAGE>
*(11) Consulting Agreement dated as of August 9, 1997 by and between the
Company and Eben W. Pyne.
*18 Letter re change in accounting principles.
*23 Consent of Ernst & Young LLP, Independent Auditors.
*24(a) Powers of Attorney executed by the Directors and
Officers of the Company.
*24(b) Certificate as to Corporate Power of Attorney.
*24(c) Certified copy of Resolution of Board of Directors authorizing
signature pursuant to Power of Attorney.
*27 Financial Data Schedule UT for the twelve-month
period ended March 31, 1998.
Financial Statements of subsidiary companies accounted for by
the equity method have been omitted because such subsidiaries do not constitute
significant subsidiaries.
(b) REPORTS ON FORM 8-K
None.
- --------
*Filed herewith.
129
<PAGE>
<PAGE>
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)
<TABLE>
<CAPTION>
- --------------------------------------- -------------- ------------------------------- --------------- ---------------
Column A Column B Column C Column D Column E
- --------------------------------------- -------------- ------------------------------- --------------- ---------------
Additions
---------------- --------------
Balance at Charged to Charged to Balance at
Description beginning of costs and other Deductions- end of period
period expenses accounts- describe
describe
- --------------------------------------- -------------- ---------------- -------------- --------------- ---------------
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Year ended March 31, 1998
Deducted from asset accounts:
Allowance for doubtful accounts $23,675 $23,239 -- $23,431(1) $23,483
Three Months Ended March 31, 1997
Deducted from asset accounts:
Allowance for doubtful accounts $25,000 $ 4,821 -- $6,146(1) $23,675
Year ended December 31, 1996
Deducted from asset accounts:
Allowance for doubtful accounts $24,676 $23,119 -- $22,795(1) $25,000
Year ended December 31, 1995
Deducted from asset accounts:
Allowance for doubtful accounts $23,365 $17,751 -- $16,440(1) $24,676
</TABLE>
(1) Uncollectible accounts written off, net of recoveries.
130
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, this
amendment has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Date
May 28, 1998
Signature and Title
--------------------------------------------
WILLIAM J. CATACOSINOS*
William J. Catacosinos, Principal
Executive Officer, President and
Chairman of the Board of Directors
JAMES T. FLYNN*
James T. Flynn, President,
Chief Operating Officer and Director
/s/ JOSEPH E. FONTANA
--------------------------------------------
Joseph E. Fontana, Controller,
Principal Accounting Officer
--------------------------------------------
A. JAMES BARNES*
A. James Barnes, Director
--------------------------------------------
GEORGE BUGLIARELLO*
George Bugliarello, Director
--------------------------------------------
RENSO L. CAPORALI*
Renso L. Caporali, Director
--------------------------------------------
VICKI L. FULLER*
Vicki L. Fuller, Director
--------------------------------------------
KATHERINE D. ORTEGA*
Katherine D. Ortega, Director
--------------------------------------------
BASIL A. PATERSON*
Basil A. Paterson, Director
--------------------------------------------
RICHARD L. SCHMALENSEE*
Richard L. Schmalensee, Director
--------------------------------------------
GEORGE J. SIDERIS*
George J. Sideris, Director
--------------------------------------------
JOHN H. TALMAGE*
John H. Talmage, Director
/s/ ANTHONY NOZZOLILLO
--------------------------------------------
*Anthony Nozzolillo (Individually,
as Senior Vice President and Principal Financial Officer and as
attorney-in-fact for each of
the persons indicated)
131
<PAGE>
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this amendment to be signed
on its behalf by the undersigned, thereunto duly authorized.
LONG ISLAND LIGHTING COMPANY
Date: May 28, 1998 By: /s/ ANTHONY NOZZOLILLO
-----------------------
Anthony Nozzolillo
Principal Financial Officer
Original powers of attorney, authorizing Kathleen A. Marion and Anthony
Nozzolillo, and each of them, to sign this report and any amendments thereto, as
attorney-in-fact for each of the Directors and Officers of the Company, and a
certified copy of the resolution of the Board of Directors of the Company
authorizing said persons and each of them to sign this report and amendments
thereto as attorney-in-fact for any Officers signing on behalf of the Company,
are being filed with the Securities and Exchange Commission.
132
Exhibit 10(aa)(11)
CONSULTING AGREEMENT
AGREEMENT made as of August 7, 1997 between LONG ISLAND LIGHTING COMPANY, a
New York corporation, having its principal offices at 175 East Old Country Road,
Hicksville, New York 11801 (hereinafter the "Company") and EBEN W. PYNE,
residing in Old Westbury, New York (hereinafter the "Consultant");
WHEREAS, the Company has requested that the Consultant perform services for
it; and WHEREAS, the Consultant is willing to perform consulting services for
the Company;
NOW THEREFORE, it is agreed that:
1. Effective August 7, 1997, the Consultant will be engaged as a Consulting
Director for a period ending on the day of the 1998 Annual Meeting of
Shareholders. The Consultant will advise and counsel the Board of Directors
and any of its committees on various business and financial matters and any
other areas requested by or on behalf of the Board of Directors of the
Company.
2. For such services, the Consultant will receive an annual retainer equal to
the annual retainer paid to a duly elected Director, an additional $500.00
for each Board or Committee meeting attended and the same pension and
health benefits provided to a duly elected director. Consultant
acknowledges that he will participate in the Company's Directors' Stock
Unit Retainer Plan, which was effective January 1, 1996, and that at least
50% of Consultant's retainer will be applied to the purchase of stock
units.
3. The Consultant shall have the right to participate as a Consulting Director
in the Company's Deferred Compensation Plan for Directors and the Company's
Retirement Income Plan for Directors.
4. This agreement shall be governed by the laws of the State of New York.
IN WITNESS WHEREOF, this agreement has been executed this 7th day of
August, 1997.
CONSULTANT LONG ISLAND LIGHTING COMPANY
/s/ EBEN W. PYNE By: /s/ KATHLEEN A. MARION
- ------------------ -----------------------------
EBEN W. PYNE CORPORATE SECRETARY
Exhibit 18
May 22, 1998
Anthony Nozzolillo
Senior Vice President and Principal Financial Officer
Long Island Lighting Company
175 E Old Country Road
Hicksville, NY 11801
Dear Mr. Nozzolillo:
Note 1 of Notes to the Financial Statements of Long Island Lighting Company
included in its Annual Report on Form 10-K for the year ended March 31, 1998
describes a change in the method of accounting for the annual amortization of
the Rate Moderation Component (RMC) of a regulatory asset from a straight line
method to a method which is computed based upon monthly forecasted revenue
requirements. You have advised us that you believe that the change is to a
preferable method in your circumstances because the monthly amortization of the
RMC, which varies based upon each month's forecasted revenue requirements, more
closely aligns such amortization with the Company's cost of service producing a
better matching of revenue with the related expense for reporting within a rate
year.
There are no authoritative criteria for determining a "preferable" method of
accounting for the annual amortization of the RMC, however we conclude that the
change in the method of accounting for the annual amortization of the RMC is to
an acceptable alternative method which, based on your business judgment to make
this change for the reason cited above, is preferable in your circumstances.
Very truly yours,
/s/ Ernst & Young LLP
- ---------------------
Consent of Independent Auditors
We consent to the incorporation by reference in the Post-Effective
Amendment No. 3 to Registration Statement (No. 33-16238) on Form S-8 relating to
Long Island Lighting Company's Employee Stock Purchase Plan, Post-Effective
Amendment No. 1 to Registration Statement (No. 2-87427) on Form S-3 relating to
Long Island Lighting Company's Automatic Dividend Reinvestment Plan and in the
related Prospectus, Registration Statement (No. 2-88578) on Form S-3 relating to
the issuance of Common Stock and in the related Prospectus and Registration
Statement (No. 33-52963) on Form S-3 relating to the issuance of General and
Refunding Bonds, Debentures, Preferred Stock or Common Stock and in the related
Prospectus, of our report dated May 22, 1998, with respect to the financial
statements and schedule of Long Island Lighting Company included in this Annual
Report on Form 10-K for the year ended March 31, 1998.
/s/ Ernst & Young LLP
- ---------------------
Melville, New York
May 26, 1998
Exhibit 24(a)
Annual Report on Form
10-K for the period
ending March 31, 1998
LONG ISLAND LIGHTING COMPANY
POWER OF ATTORNEY
WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the
"Company"), intends to file with the Securities and Exchange Commission under
the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K
as prescribed by said Commission pursuant to said Act and the rules and
regulations promulgated thereunder.
NOW, THEREFORE, in my capacity either as a director or officer, or
both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION
and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with
power to execute in my name and place, and in my capacity as a director,
officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said
Report, any amendment to said Report and any other documents required in
connection therewith, and to file the same with the Securities and Exchange
Commission.
IN WITNESS WHEREOF, I have executed this power of attorney this 7th
day of May 1998.
/S/ WILLIAM J. CATACOSINOS
--------------------------
WILLIAM J. CATACOSINOS
PRINCIPAL EXECUTIVE OFFICER,
and CHAIRMAN OF THE
BOARD OF DIRECTORS
<PAGE>
Exhibit 24(a)
Annual Report on Form
10-K for the period
ending March 31, 1998
LONG ISLAND LIGHTING COMPANY
POWER OF ATTORNEY
WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the
"Company"), intends to file with the Securities and Exchange Commission under
the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K
as prescribed by said Commission pursuant to said Act and the rules and
regulations promulgated thereunder.
NOW, THEREFORE, in my capacity either as a director or officer, or
both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION
and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with
power to execute in my name and place, and in my capacity as a director,
officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said
Report, any amendment to said Report and any other documents required in
connection therewith, and to file the same with the Securities and Exchange
Commission.
IN WITNESS WHEREOF, I have executed this power of attorney this 27
day of May 1998.
/S/ A. JAMES BARNES
-------------------
A. JAMES BARNES, DIRECTOR
<PAGE>
Exhibit 24(a)
Annual Report on Form
10-K for the period
ending March 31, 1998
LONG ISLAND LIGHTING COMPANY
POWER OF ATTORNEY
WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the
"Company"), intends to file with the Securities and Exchange Commission under
the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K
as prescribed by said Commission pursuant to said Act and the rules and
regulations promulgated thereunder.
NOW, THEREFORE, in my capacity either as a director or officer, or
both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION
and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with
power to execute in my name and place, and in my capacity as a director,
officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said
Report, any amendment to said Report and any other documents required in
connection therewith, and to file the same with the Securities and Exchange
Commission.
IN WITNESS WHEREOF, I have executed this power of attorney this 27
day of May 1998.
/S/ GEORGE BUGLIARELLO
----------------------
GEORGE BUGLIARELLO, DIRECTOR
<PAGE>
Exhibit 24(a)
Annual Report on Form
10-K for the period
ending March 31, 1998
LONG ISLAND LIGHTING COMPANY
POWER OF ATTORNEY
WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the
"Company"), intends to file with the Securities and Exchange Commission under
the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K
as prescribed by said Commission pursuant to said Act and the rules and
regulations promulgated thereunder.
NOW, THEREFORE, in my capacity either as a director or officer, or
both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION
and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with
power to execute in my name and place, and in my capacity as a director,
officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said
Report, any amendment to said Report and any other documents required in
connection therewith, and to file the same with the Securities and Exchange
Commission.
IN WITNESS WHEREOF, I have executed this power of attorney this 27
day of May 1998.
/S/ RENSO L. CAPORALI
---------------------
RENSO L. CAPORALI, DIRECTOR
<PAGE>
Exhibit 24(a)
Annual Report on Form
10-K for the period
ending March 31, 1998
LONG ISLAND LIGHTING COMPANY
POWER OF ATTORNEY
WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the
"Company"), intends to file with the Securities and Exchange Commission under
the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K
as prescribed by said Commission pursuant to said Act and the rules and
regulations promulgated thereunder.
NOW, THEREFORE, in my capacity either as a director or officer, or
both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION
and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with
power to execute in my name and place, and in my capacity as a director,
officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said
Report, any amendment to said Report and any other documents required in
connection therewith, and to file the same with the Securities and Exchange
Commission.
IN WITNESS WHEREOF, I have executed this power of attorney this 7th
day of May 1998.
/S/ JAMES T. FLYNN
------------------
JAMES T. FLYNN,
PRESIDENT, CHIEF OPERATING
OFFICER AND DIRECTOR
<PAGE>
Exhibit 24(a)
Annual Report on Form
10-K for the period
ending March 31, 1998
LONG ISLAND LIGHTING COMPANY
POWER OF ATTORNEY
WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the
"Company"), intends to file with the Securities and Exchange Commission under
the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K
as prescribed by said Commission pursuant to said Act and the rules and
regulations promulgated thereunder.
NOW, THEREFORE, in my capacity either as a director or officer, or
both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION
and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with
power to execute in my name and place, and in my capacity as a director,
officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said
Report, any amendment to said Report and any other documents required in
connection therewith, and to file the same with the Securities and Exchange
Commission.
IN WITNESS WHEREOF, I have executed this power of attorney this 27
day of May 1998.
/S/ VICKI L. FULLER
-------------------
VICKI L. FULLER, DIRECTOR
<PAGE>
Exhibit 24(a)
Annual Report on Form
10-K for the period
ending March 31, 1998
LONG ISLAND LIGHTING COMPANY
POWER OF ATTORNEY
WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the
"Company"), intends to file with the Securities and Exchange Commission under
the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K
as prescribed by said Commission pursuant to said Act and the rules and
regulations promulgated thereunder.
NOW, THEREFORE, in my capacity either as a director or officer, or
both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION
and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with
power to execute in my name and place, and in my capacity as a director,
officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said
Report, any amendment to said Report and any other documents required in
connection therewith, and to file the same with the Securities and Exchange
Commission.
IN WITNESS WHEREOF, I have executed this power of attorney this 27
day of May 1998.
/S/ KATHERINE D. ORTEGA
-----------------------
KATHERINE D. ORTEGA, DIRECTOR
<PAGE>
Exhibit 24(a)
Annual Report on Form
10-K for the period
ending March 31, 1998
LONG ISLAND LIGHTING COMPANY
POWER OF ATTORNEY
WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the
"Company"), intends to file with the Securities and Exchange Commission under
the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K
as prescribed by said Commission pursuant to said Act and the rules and
regulations promulgated thereunder.
NOW, THEREFORE, in my capacity either as a director or officer, or
both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION
and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with
power to execute in my name and place, and in my capacity as a director,
officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said
Report, any amendment to said Report and any other documents required in
connection therewith, and to file the same with the Securities and Exchange
Commission.
IN WITNESS WHEREOF, I have executed this power of attorney this 27
day of May 1998.
/S/ BASIL A. PATERSON
---------------------
BASIL A. PATERSON, DIRECTOR
<PAGE>
Exhibit 24(a)
Annual Report on Form
10-K for the period
ending March 31, 1998
LONG ISLAND LIGHTING COMPANY
POWER OF ATTORNEY
WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the
"Company"), intends to file with the Securities and Exchange Commission under
the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K
as prescribed by said Commission pursuant to said Act and the rules and
regulations promulgated thereunder.
NOW, THEREFORE, in my capacity either as a director or officer, or
both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION
and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with
power to execute in my name and place, and in my capacity as a director,
officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said
Report, any amendment to said Report and any other documents required in
connection therewith, and to file the same with the Securities and Exchange
Commission.
IN WITNESS WHEREOF, I have executed this power of attorney this 27
day of May 1998.
/S/ RICHARD L. SCHMALENSEE
--------------------------
RICHARD L. SCHMALENSEE, DIRECTOR
<PAGE>
Exhibit 24(a)
Annual Report on Form
10-K for the period
ending March 31, 1998
LONG ISLAND LIGHTING COMPANY
POWER OF ATTORNEY
WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the
"Company"), intends to file with the Securities and Exchange Commission under
the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K
as prescribed by said Commission pursuant to said Act and the rules and
regulations promulgated thereunder.
NOW, THEREFORE, in my capacity either as a director or officer, or
both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION
and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with
power to execute in my name and place, and in my capacity as a director,
officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said
Report, any amendment to said Report and any other documents required in
connection therewith, and to file the same with the Securities and Exchange
Commission.
IN WITNESS WHEREOF, I have executed this power of attorney this 7th
day of May 1998.
/S/ GEORGE J.. SIDERIS
----------------------
GEORGE J. SIDERIS, DIRECTOR
<PAGE>
Exhibit 24(a)
Annual Report on Form
10-K for the period
ending March 31, 1998
LONG ISLAND LIGHTING COMPANY
POWER OF ATTORNEY
WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the
"Company"), intends to file with the Securities and Exchange Commission under
the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K
as prescribed by said Commission pursuant to said Act and the rules and
regulations promulgated thereunder.
NOW, THEREFORE, in my capacity either as a director or officer, or
both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION
and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with
power to execute in my name and place, and in my capacity as a director,
officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said
Report, any amendment to said Report and any other documents required in
connection therewith, and to file the same with the Securities and Exchange
Commission.
IN WITNESS WHEREOF, I have executed this power of attorney this 11
day of May 1998.
/S/ JOHN H. TALMAGE
-------------------
JOHN H. TALMAGE, DIRECTOR
<PAGE>
EXHIBIT 24(b)
Form 10-K for year
ended March 31, 1998
LONG ISLAND LIGHTING COMPANY
CERTIFICATE AS TO POWER OF ATTORNEY
WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation,
intends to file with the Securities and Exchange Commission under the Securities
Exchange Act of 1934, as amended, an Annual Report for the year ended March 31,
1998, on Form 10-K as prescribed by said Commission pursuant to said Act and the
rules and regulations promulgated thereunder.
NOW, THEREFORE, in my capacity as Assistant Corporate Secretary of
Long Island Lighting Company, I do hereby certify that Anthony Nozzolillo has
been appointed by the Board of Directors of Long Island Lighting Company with
power to execute, among other documents, said Report, any amendment to said
Report and any other documents required in connection therewith, and to file the
same with the Securities and Exchange Commission.
WITNESS my hand and the seal of the Company this 27 day of May, 1998
/S/ THEODORE A. BABCOCK
-----------------------
THEODORE A. BABCOCK
Assistant Corporate Secretary
(Corporate Seal)
<PAGE>
LONG ISLAND LIGHTING COMPANY
(Resolution adopted on May 27, 1998)
"RESOLVED, that the proper officers of the Corporation be, and hereby are,
and each of them with the full authority without the others hereby is,
authorized, empowered and directed, in the name and on behalf of the
Corporation, to execute the corporation's Form 10-K for the year ended March 31,
1998, substantially in the form previously circulated to the Directors of the
Corporation, with such changes as such proper officers, with the advice of
counsel deem necessary or desirable, the execution by such proper officers to be
conclusive evidence that they or he/she deemed such changes to be necessary or
desirable, and to execute any amendment to such Form 10-K, to procure all
necessary signatures thereon, and to file such Form 10-K and any amendment when
so executed (together with appropriate exhibits thereto) with the Securities
Exchange Commission."
<PAGE>
Exhibit 24(c)
Form 10-K for year
ending March 31, 1998
LONG ISLAND LIGHTING COMPANY
I, KATHLEEN A. MARION, Corporate Secretary of LONG ISLAND LIGHTING COMPANY
(the "Company"), a New York corporation, DO HEREBY CERTIFY that annexed hereto
is a true, correct and complete copy of the resolution adopted at a meeting of
the Board of Directors of the Company duly called and held on May 27, 1998, at
which meeting a quorum was present and acting throughout.
AND I DO FURTHER CERTIFY that the foregoing resolution has not been in any
way amended, annulled, rescinded or revoked and that the same is still in full
force and effect.
WITNESS my hand and the seal of the Company this 27 day of May, 1998.
/S/ KATHLEEN A. MARION
----------------------
KATHLEEN A. MARION
Corporate Secretary
(Corporate Seal)
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted fom the
Statement of Income, Balance Sheet and Statement of Cash Flows, and is
qualified in its entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> MAR-31-1998
<PERIOD-END> MAR-31-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,814,081
<OTHER-PROPERTY-AND-INVEST> 50,816
<TOTAL-CURRENT-ASSETS> 854,272
<TOTAL-DEFERRED-CHARGES> 85,702
<OTHER-ASSETS> 7,091,854
<TOTAL-ASSETS> 11,896,725
<COMMON> 608,635
<CAPITAL-SURPLUS-PAID-IN> 1,097,720
<RETAINED-EARNINGS> 953,492
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,659,847
562,600
0
<LONG-TERM-DEBT-NET> 4,395,555
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 101,000
139,374
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 4,038,349
<TOT-CAPITALIZATION-AND-LIAB> 11,896,725
<GROSS-OPERATING-REVENUE> 3,124,094
<INCOME-TAX-EXPENSE> 237,371
<OTHER-OPERATING-EXPENSES> 2,118,427
<TOTAL-OPERATING-EXPENSES> 2,355,798
<OPERATING-INCOME-LOSS> 768,296
<OTHER-INCOME-NET> (4,183)
<INCOME-BEFORE-INTEREST-EXPEN> 764,113
<TOTAL-INTEREST-EXPENSE> 404,473
<NET-INCOME> 359,640
51,813
<EARNINGS-AVAILABLE-FOR-COMM> 307,827
<COMMON-STOCK-DIVIDENDS> 215,790
<TOTAL-INTEREST-ON-BONDS> 351,261
<CASH-FLOW-OPERATIONS> 674,084
<EPS-PRIMARY> 2.54
<EPS-DILUTED> 2.54
</TABLE>
