SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10K/A
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1995
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)
Preferred Stock ($100 par, cumulative):
Series B, 5.00% Series E, 4.35%
Series CC, 7.66% Series I, 5 3/5%, Convertible
Preferred Stock ($25 par, cumulative):
Series AA, 7.95% Series GG, $1.67
Series NN, $1.95 Series QQ, 7.05%
General and Refunding Bonds:
8 3/4% Series Due 1996 7.85% Series Due 1999 7.90% Series Due 2008
8 3/4% Series Due 1997 8 5/8% Series Due 2004 9 3/4% Series Due 2021
7 5/8% Series Due 1998 8.50% Series Due 2006 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
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 each of the other securities listed above is 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 January 31, 1996 ws $2,038,959,770. The aggregate market value of
Preferred Stock held by non-affiliates of the Company at January 31, 1996,
established by Lehman Brothers based on the average bid and asked price, was
$642,932,411.
Common Stock ($5 par) - Shares outstanding at January 31, 1996: 119,938,810
The Company's proxy statement for its Annual Meeting of Shareowners to be
held on May 9, 1996 has been incorporated by reference into Part III of this
Form 10-K to provide information required in Item 10 (Directors and Executive
Officers of the Company) as to Directors, Item 11 (Executive Compensation), Item
12 (Security Ownership of Certain Beneficial Owners and Management) and Item 13
(Certain Relationships and Related Transactions).
<PAGE>
This Form 10-K/A amends Part II, Item 7 of Form 10-K for the Fiscal Year ended
December 31, 1995.
ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
This discussion and analysis addresses matters of significance with regard to
the Company and its financial condition, liquidity, capital requirements and
results of operations for the last three years.
Overview
As the utility industry continues the transition to a more competitive
marketplace, the pressure from customers and regulators to reduce rates on Long
Island has intensified. This pressure to reduce rates has resulted in an attempt
by the Long Island Power Authority (LIPA), an agency of the State of New York,
to develop a plan to replace the Company as the primary electric and gas utility
on Long Island. The Company's response to these challenges has been to continue
a strategic plan designed to avoid future rate increases through an aggressive
cost containment program, while maintaining a reliable electric and gas system.
The Company believes that these efforts will allow it to improve its financial
health and better position itself for the transition to a more competitive
environment.
Significant achievements during 1995 included:
o Cash generated from operations exceeded the Company's operating,
construction and refunding requirements;
o The extinguishment of the First Mortgage debt with cash on
hand, resulting in an improvement in the Company's debt ratio;
o Earnings per common share of $2.10, despite a lower allowed return on
common equity and the modification of certain performance-based
incentives related to the electric business;
o The continuation of the Company's quarterly common stock dividend
rate at 44 1/2 cents per share;
o Continuation of the electric rate freeze for the second consecutive
year;
o A reduction in the Rate Moderation Component balance from $463 million
at December 31, 1994 to $383 million at December 31, 1995;
o The establishment of a record peak electric energy demand of 4,077
megawatts on August 4, 1995, surpassing the old record of 3,967
megawatts on July 9, 1993;
o Receipt of a 3.2% gas rate increase effective December 1, 1995, which
is the final of three gas rate increases under a three-year settlement
between the Company and the Public Service Commission of the State of
New York;
<PAGE>
o The addition of over 6,500 new gas space heating customers, resulting
from the continuation of the Company's gas expansion program;
o A reduction in the level of construction expenditures and operations
and maintenance expenses;
o A reduction in staff levels through attrition while reducing
overtime payments;
o Receipt of final regulatory approval of the decommissioning of the
Shoreham Nuclear Power Station.
As part of its strategic effort to improve its competitive position, the
Company, for the rate years ended November 30, 1995 and 1996, froze electric
rates by focusing on cost reduction. The Company's cost reduction programs,
which seek to maximize operating efficiencies as a means to reduce operating
costs, resulted in reducing non-fuel operations and maintenance expenses by
approximately $29 million from the 1994 amount.
During 1995, the Company continued its policy of not replacing employees who
decided to either retire or terminate employment with the Company. The benefits
derived from internal process review programs and the Company's commitment to
reallocate existing resources have allowed the Company to operate with increased
efficiencies despite the loss, through attrition, of 857 employees or about 13%
of it's workforce since 1990. In 1995, the Company's workforce was reduced by
259 employees or about 5%.
In addition to reducing its operations and maintenance expense, the Company also
reduced its capital expenditures by approximately $130 million in 1995, due
primarily to the completion, in 1994, of the decommissioning of the Shoreham
Nuclear Power Station (Shoreham). However, the Company's commitment to increase
penetration in the gas home heating market on Long Island remains strong. In
1995, the Company invested approximately $50 million into its gas infrastructure
to increase safety, reliability and availability of gas in order to attract new
gas space heating customers.
As a result of the above, the Company, for the second consecutive year,
generated sufficient cash flow to meet all of its operating and construction
requirements. This enhanced cash flow also allowed the Company to redeem all
amounts outstanding under the First Mortgage with cash on hand.
<PAGE>
Long Island Power Authority Proposed Plan
During 1995, the Governor of the State of New York requested that the Long
Island Power Authority (LIPA) develop a plan that, in addition to replacing the
Company as the primary electric and gas utility on Long Island, would among
other things, produce an electric rate reduction of at least 10%, provide a
framework for long-term competition in power production and protect property
taxpayers on Long Island. In response to this request, the Board of Trustees of
LIPA established a committee (Evaluation Committee) to analyze various plans
involving the Company's business operations and assets.
In December 1995, after soliciting information and indications of interest from
various parties in connection with a LIPA-facilitated financial
restructuring/acquisition of the Company, the members of the Evaluation
Committee and their advisors announced a proposed plan to restructure the
Company and reduce electric rates on Long Island by 12% (Proposed Plan). The
Proposed Plan, which has not been adopted by the LIPA Board or formally
presented to the Company's Board of Directors for consideration, generally
provides that: (i) the Company sell, subject to LIPA's approval, its gas
business and electric generation assets; (ii) LIPA purchase the Company's
transmission, distribution and Shoreham-related assets; (iii) LIPA enter into
long-term power purchase agreements with the purchasers of the generation
assets; (iv) LIPA enter into agreements with contractors to manage the
transmission and distribution system; and (v) LIPA exercise its power of eminent
domain over all or a portion of the Company's assets or securities in order to
achieve its objectives if a negotiated agreement cannot be reached with the
Company.
The Company has indicated to LIPA that certain elements of the Proposed Plan
raise significant concerns. Specifically, the Proposed Plan contains no
information regarding the values or prices contemplated to be paid for the
Company's assets, no financing commitments for any portion of the proposed
transaction were disclosed and no indications that endorsements by certain State
officials required to approve any transaction undertaken by LIPA have been
obtained. In addition, based on the limited information currently available, the
Company is unable to determine how the anticipated rate reduction would be
achieved and how the reliability of the electric system, including storm
restoration capabilities, would be maintained given the multiple entities that
would be responsible for providing such service.
Notwithstanding these concerns, the Company remains willing to cooperate with
LIPA in developing a plan that is beneficial to the Company's investors,
customers and employees. The Company is continuously assessing various other
strategies in an effort to provide the greatest possible value to its
constituents in light of the changing economic, regulatory and political
challenges affecting the Company. Such strategies may include a review and
modification of its operations to best meet the challenges of a competitive
environment, a possible reorganization of the Company, potential joint ventures
and/or possible business combinations with other entities.
<PAGE>
The implementation of certain plans involving the Company's business operations
and assets would be subject to, among other things, shareholder and regulatory
approvals and could impact the Company's future financial results and
operations. Accordingly, the Company is unable to determine what plan, if any,
will be pursued by it and/or LIPA or whether any related transaction will be
consummated.
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 1995, both the Public Service Commission of the State of
New York (PSC) and the Federal Energy Regulatory Commission (FERC) continued
their separate initiatives with respect to developing a framework for a
competitive electric marketplace.
New York State Competitive Opportunities Proceedings
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.
During 1995, the proceedings continued with the PSC adopting a series of
principles which it will use to guide the transition of the electric utility
industry in New York State from a rate-regulated cost of service model to a
competitive market-driven model. The principles state, among other things, that:
(i) consumers should have a reasonable opportunity to realize savings from
competition; (ii) a basic level of reasonably priced service must be maintained;
(iii) the integrity, safety and reliability of the system should not be
jeopardized; and (iv) the current industry structure, in which most power plants
are vertically integrated with natural monopoly transmission and distribution
systems, should be thoroughly examined to ensure that it does not impede or
obstruct the development of effective wholesale or retail competition. In
addition, the principles state that utilities should have a reasonable
opportunity to recover prudent and verifiable expenditures and commitments made
pursuant to their legal obligations, consistent with these principles.
In October 1995, the Energy Association, which is comprised of the Company and
the six other investor-owned New York State utilities, filed a proposal designed
to achieve the principles outlined by the PSC. The proposal, which is referred
to as the "Wholesale Poolco Model", establishes a framework that will allow
competition at the wholesale level. The plan would, among other things: (i)
allow utilities, non-regulated generators
<PAGE>
and other market participants to create a wholesale exchange that allows market
forces to determine the price of wholesale electricity; (ii) establish an
Independent System Operator (ISO) to coordinate the safe and reliable operation
of the bulk power transmission system; (iii) increase customer choice by
providing clear market price signals so customers can make informed decisions on
the use of electricity; and (iv) separate the generation portion of a utility's
business from its regulated transmission and distribution business.
In this model, competing generating suppliers would bid energy sales into the
market. The market clearing price for energy would be determined by the bid of
the highest price unit needed to serve the load in a particular location.
Regulated utility companies could purchase energy from the market, which would
establish a half-hour locational spot market price for electricity, or the
utility could seek to enter into bilateral energy agreements with other parties.
Bilateral agreements would be administered independently of the wholesale
exchange, but would be scheduled through the ISO. These bilateral agreements
would be permitted among utility companies, generating companies and power
marketers. In the Wholesale Poolco Model, the purchase of electricity by end use
customers would still be bundled with transmission, distribution and customer
service, all of which would be provided by regulated utilities.
The support of the New York State utilities for the Wholesale Poolco Model is
predicated on a number of factors, including: (i) a reasonable opportunity to
fully recover all investments and expenditures made to provide reliable service
under the existing regulatory compact; (ii) PSC support for the option of each
utility to continue in the generation business; (iii) special treatment of
nuclear plants based on their unique characteristics; and (iv) the adoption of a
clearly defined transition plan to ensure that the interests of the customer and
the investor are adequately protected.
In December 1995, an Administrative Law Judge (ALJ) of the PSC issued a
Recommended Decision (RD) to the PSC with respect to this Competitive
Opportunities Proceedings. The ALJ recommended a competitive model which seeks
to transition the electric utility industry in New York State to full retail
competition through two stages. The first stage of this recommendation seeks to
transition the industry from its current cost of service rate regulation to a
competitive wholesale model similar to the Wholesale Poolco Model. This first
stage would allow participants to become familiar with the operation of a
deregulated, competitive generation market prior to the eventual movement to
full retail competition in the second stage, through a model known as the
Flexible Retail Poolco Model.
The Flexible Retail Poolco Model contains many of the same attributes associated
with the Wholesale Poolco Model, including: (i) an ISO to coordinate the safe
and reliable operation of generation and transmission; (ii) open access to the
transmission system, which would be regulated by FERC; and (iii) the
continuation of a regulated distribution company to operate and maintain the
distribution system. The principal difference between the models is that
customers would have a choice among suppliers of
<PAGE>
electricity in the Flexible Retail Poolco Model whereas in the Wholesale Poolco
Model, the regulated entity would acquire electric energy from the spot energy
sales exchange to sell to the customer.
The Flexible Retail Poolco Model would also: (i) deregulate energy/customer
services such as meter reading and customer billing; (ii) unbundle electricity
into four components: generation, transmission, distribution, and
energy/customer services; and (iii) provide customers with a choice among
suppliers of electricity, and allow customers to acquire electricity either by
long-term contracts or purchases on the spot market or a combination of the two.
One of the most contentious issues of the Competitive Opportunities Proceedings
has been the position taken by the various parties to the proceedings on the
amount of recovery utilities should be permitted to collect from customers for
so-called stranded investments. Stranded investments represent costs that
utilities would have otherwise recovered through rates under traditional cost of
service regulation that, under competition, utilities may not be able to recover
since the market price for their product may be inadequate to recover these
costs. The Staff of the PSC, for example, has indicated that utilities should
not expect full recovery of stranded costs. The Energy Association has commented
that utilities have a sound legal precedent confirmed by long-standing PSC
policy to fully recover all prudently incurred costs, including stranded costs.
The RD states that for recovery, stranded costs must be prudent, verifiable and
unable to be reduced through mitigation measures. The RD states that recovery of
stranded costs be predicated on the prudency of the costs incurred. The costs
must be verifiable and the Company must show that it was unable to avoid
incurring these costs.
The RD states that a generic decision should address the definition, the method
of measurement, the requirements for mitigation, a preferable recovery mechanism
and a standard for the recovery of stranded investments. The calculation of the
amount to be recovered from customers, however, should be left to individual
rate cases or special proceedings that should begin during 1996. The RD further
directs New York State investor-owned utilities to individually file, within six
months of the PSC's order, a comprehensive long-term proposal addressing the
significant components of the RD.
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 these proceedings could
adversely affect the Company's ability to apply Statement of Financial
Accounting Standards (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" and SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," could then
require a significant write-down of assets, the amount of which cannot presently
be determined. For a further discussion of SFAS No. 71 and SFAS No. 121, see
Note 1 of Notes to Financial Statements.
<PAGE>
The Electric Industry - Federal Regulatory Issues
As a result of Congress' passage of the Public Utility Regulatory Policies Act
of 1978 (PURPA), and the National Energy Policy Act of 1992 (NEPA), the once
monopolistic electric utility industry now faces competition.
PURPA's goal is to reduce the United States' dependence on foreign oil,
encourage energy conservation and promote diversification of fuel supply.
Accordingly, PURPA provided for the development of a new class of electric
generators which rely on either cogeneration technology or alternate fuels. The
utilities are obligated under PURPA to purchase the output of certain of these
new generators, which are known as qualified facilities (QFs).
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 (i.e., sales to an entity for resale to the ultimate
consumer). NEPA does so by creating exempt wholesale generators that can sell
power in wholesale markets without the regulatory constraints placed on utility
generators such as the Company. NEPA also expanded FERC's authority to grant
access to utility transmission systems to all parties who seek wholesale
wheeling for wholesale competition. Significant issues associated with the
removal of restrictions on wholesale transmission system access have yet to be
resolved and the potential impact on the Company's financial position cannot yet
be determined.
FERC is in the process of setting policy which will largely determine how
wholesale competition will be implemented. FERC has declared that utilities must
provide wholesale wheeling to others that is comparable to the service utilities
provide themselves. FERC has issued policy statements concerning regional
transmission groups, transmission information requirements and "good faith"
requests for service and transmission pricing. In March 1995, FERC issued a
Notice of Proposed Rulemaking (NOPR) which combined the issues of open
transmission access and stranded cost recovery. The NOPR contained a strong
endorsement of the right of the utilities to full recovery of stranded costs due
to wholesale wheeling and retail-turned-wholesale wheeling arrangements. During
the year, FERC has followed up on these issues through an extensive comment
period, holding public hearings on pro-forma transmission tariffs, ancillary
services, real-time information systems and power pooling issues. FERC recently
announced its interest in exploring the role of an ISO in providing comparable
transmission access. It is expected that FERC will issue a final order on open
access in 1996. Utilities, including the Company, and numerous other interested
parties are actively involved in these proceedings.
It is not possible to predict the outcome of these proceedings or the effect, if
any, on the financial condition of the Company. The Company participates in the
wholesale electricity market primarily as a buyer, and in this regard should
benefit if rules are adopted which result in lower wholesale prices for its
retail customers.
<PAGE>
The Company's Service Territory
The changing utility regulatory environment has affected the Company in a number
of ways. For example, PURPA's encouragement of the non-utility generator (NUG)
industry has negatively impacted the Company. In 1995, the Company lost sales to
NUGs totaling 366 gigawatt-hours (Gwh) representing a loss in electric revenues
net of fuel (net revenues) of approximately $28 million, or 1.5% of the
Company's net revenues. In 1994, the Company lost sales to NUGs totaling 237 Gwh
or approximately $24 million of net revenues. The increase in lost net revenues
resulted principally from the completion, in April 1995, of a QF located at the
State University of New York at Stony Brook, New York (Stony Brook Project). The
annual load loss due to this QF is estimated to be 188 Gwh. The Company
estimates that in 1996, sales losses to NUGs will be 414 Gwh, or approximately
1.7% of projected net revenues, an increase reflecting 12 months of operation
for the Stony Brook Project. 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 in 1995 and 1994 approximated 205 megawatts (MW). 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 now only applies 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. The Company
estimates that purchases from QFs required by federal and state law cost the
Company $53 million more than it would have cost had the Company generated this
power in both 1995 and 1994.
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 in 1995 and 1994 NYPA power
displaced approximately 429 Gwh and 400 Gwh of annual energy sales,
respectively. The net revenue loss associated with this amount of sales is
approximately $30 million or 1.6% of the Company's 1995 net revenues and $28
million or 1.5% of the Company's 1994 net revenues. Currently, the potential
loss of additional load is limited by conditions in the Company's transmission
agreements with NYPA.
Aside from NUGs, 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
<PAGE>
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
likely to increase as a result of NEPA. The Town of Southampton and several
other towns in the Company's service territory are considering the formation of
a municipally owned and operated electric authority to replace the services
currently provided by the Company. Suffolk County issued a request for proposal
from suppliers for up to 200 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.
The Company has responded that it does not believe the County is eligible under
present laws and regulations to purchase wholesale power and resell it to retail
customers, and has declined to offer the requested retail wheeling service. 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.
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 FERC may take regarding any of these matters, or the impact on
the Company's financial condition if some or all of these matters are approved
or implemented by the appropriate regulatory authority.
Notwithstanding the outcome of the federal or state regulatory rate 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.
Liquidity
During 1995, cash generated from operations exceeded the Company's operating,
construction and refunding requirements in addition to allowing for the early
redemption of the Company's remaining First Mortgage Bonds. This positive cash
flow is the result of: (i) the Company's continuing efforts to control both
operations and maintenance (O&M) costs and construction expenditures; (ii) lower
fuel costs; (iii) significantly lower costs incurred at Shoreham as a result of
the completion of the plant's decommissioning in 1994; (iv) lower interest
payments resulting from lower debt levels; and (v) the collection of previously
deferred revenues.
At December 31, 1995, the Company's cash and cash equivalents amounted to
approximately $351 million, compared to $185 million at December 31, 1994. In
addition, the Company has available for its use a $300 million revolving line of
credit through October 1, 1996, provided by its 1989 Revolving Credit Agreement
(1989 RCA). This line of credit is secured by a first
<PAGE>
lien upon the Company's accounts receivable and fuel oil inventories. For a
further discussion of the 1989 RCA, see Note 7 of Notes to Financial Statements.
In January 1996, the Company received approximately $81 million, including
interest, from Suffolk County pursuant to a judgment in the Company's favor that
found that the Shoreham property was overvalued for property tax purposes
between 1976 and 1983 (excluding 1979 which had previously been settled). The
Company has petitioned the PSC to allow the Company to reduce the Rate
Moderation Component (RMC) by the amount received, net of litigation costs
incurred by the Company. The Company is also seeking recovery from Suffolk
County for the overpayment of taxes on the Shoreham property for the years 1984
through 1992 in a separate proceeding which is currently pending before the New
York Supreme Court. For a further discussion of this proceeding, see "Shoreham
Related Litigation" below.
The Company currently believes that it will not need to access the financial
markets to retire its $415 million of maturing debt in 1996 as cash balances on
hand at that time will be sufficient to support all Company requirements for
1996. 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). With respect to the repayment of $251 million and $101 million of
debt maturing in 1997 and 1998, respectively, the Company intends to use cash
generated from operations to the maximum extent practicable.
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. The Revenue Agents' Reports reflect
proposed adjustments to the Company's federal income tax returns for this period
which, if sustained, would give rise to tax deficiencies totaling approximately
$227 million. The Company believes that any such deficiencies as finally
determined would be significantly less than the amounts proposed in the Revenue
Agents' Reports. The Revenue Agents have also proposed investment tax credit
(ITC) adjustments which, if sustained, would reduce the ITC carryforwards by
approximately $96 million. The Company has protested some of the proposed
adjustments which are presently under review by the Regional Appeals Office of
the Internal Revenue Service. If this review does not result in a settlement
that is satisfactory to the Company, the Company intends to seek a judicial
review. The Company believes that its reserves are adequate to cover any tax
deficiency that may ultimately be determined and that cash from operations will
be sufficient to satisfy any settlement reached.
The Company will exhaust its net operating loss carryforwards for alternative
minimum tax purposes in 1996. As a result, it is anticipated that the Company
will be required to pay approximately $80 million of alternative minimum tax in
1996. In addition, during 1996, the Company anticipates utilization of net
operating loss carryforwards amounting to approximately $547 million and to
fully utilize its remaining NOL for regular income tax purposes in 1997.
<PAGE>
Capitalization
The Company's capitalization, including current maturities of long-term debt and
current redemption requirements of preferred stock, at December 31, 1995 and
1994, was $8.3 billion. At December 31, 1995 and 1994, the Company's
capitalization ratios were as follows:
<TABLE>
<CAPTION>
1995 1994
---- ----
<S> <C> <C>
Long-term debt 61.8% 62.5%
Preferred stock 8.6 8.6
Common shareowners' equity 29.6 28.9
==== ====
100.0% 100.0%
</TABLE>
In support of the Company's continuing goal to reduce its debt ratio, the
Company, in 1995, retired at maturity, with cash on hand, $25 million of First
Mortgage Bonds and voluntarily redeemed prior to maturity, the remaining $75
million of First Mortgage Bonds. With the retirement/ redemption of the First
Mortgage Bonds, the lien of the First Mortgage was discharged leaving the
Company's General and Refunding Bonds (G&R Bonds) as its only outstanding
secured indebtedness. The Company currently anticipates that it will use cash on
hand to satisfy the $415 million of G&R Bonds scheduled to mature in 1996. At
such time, assuming a level of earnings consistent with 1995, the Company's debt
ratio will be below 60%.
During 1995, the Company received proceeds from the sale of $50 million of
Electric Facilities Revenue Bonds (EFRBs) issued by NYSERDA. The proceeds from
this offering were used to reimburse the Company's treasury for electric
projects previously completed or under construction.
Investment Rating
The Company's securities are rated by Standard and Poor's Corporation (S&P),
Moody's Investors Service (Moody's), Fitch Investors Service, L.P. (Fitch) and
Duff and Phelps, Inc. (D&P). The rating agencies have been watching the electric
utility industry closely and have expressed concern regarding the ability of
high cost utilities, such as the Company, to recover all of their fixed costs in
a competitive, deregulated marketplace.
In 1995, Fitch lowered its credit ratings of the Company's securities one level.
Both Fitch and S&P have placed the Company's securities on "Credit Watch" with
"evolving or developing" implications. Credit Watch indicates a rating change is
likely, and the evolving or developing status indicates ratings may be raised or
lowered. In December 1995, Moody's stated that it will continue to review the
Company's credit ratings and also changed the direction of the ratings review to
uncertain from negative.
<PAGE>
Currently, only the Company's G&R Bonds meet or exceed minimum investment grade.
At December 31, 1995, 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-
=============================================================================
</TABLE>
Capital Requirements and Capital Provided
Capital requirements and capital provided for 1995 and 1994 were as follows:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------
(In millions of dollars)
1995 1994
- -------------------------------------------------------------------------------------
<S> <C> <C>
Capital Requirements
Construction*
Electric $ 144 $ 135
Gas 79 119
Common 21 23
- ------------------------------------------------------------------------------------
Total Construction 244 277
- ------------------------------------------------------------------------------------
Refundings and Dividends
Long-term debt 100 635
Preferred stock 5 5
Common stock dividends 211 205
Preferred stock dividends 53 53
Redemption costs - 2
- ------------------------------------------------------------------------------------
Total Refundings and Dividends 369 900
- ------------------------------------------------------------------------------------
Shoreham post-settlement costs 71 167
- ------------------------------------------------------------------------------------
Total Capital Requirements $ 684 $ 1,344
====================================================================================
Capital Provided
Cash generated from operations $ 772 $ 836
Long-term debt issued 49 331
Common stock issued 20 118
Financing costs - (4)
- ------------------------------------------------------------------------------------
Other investing activities 9 -
- ------------------------------------------------------------------------------------
(Increase) decrease in cash (166) 63
====================================================================================
Total Capital Provided $ 684 $ 1,344
</TABLE>
* Excludes non-cash allowance for other funds used during
construction.
For further information, see the Statement of Cash Flows.
<PAGE>
Based upon the availability of electricity provided by the Company's existing
generating facilities, including its portion of energy generated at Nine Mile
Nuclear Power Station, Unit 2 (NMP2), and by its ability to purchase power under
firm contracts from other electric systems and certain non-Company owned
facilities located within the Company's service territory, the Company believes
it has adequate generating resources to meet its energy demands for the next
several years.
For 1996, total capital requirements (excluding common stock dividends) are
estimated at $792 million, of which maturing debt is $415 million, construction
requirements is $270 million, preferred stock dividends are $52 million,
preferred stock sinking funds are $5 million and Shoreham post-settlement costs
are $50 million (including $49 million for payments- in-lieu-of-taxes). The
Company believes that cash generated from operations and cash on hand will be
sufficient to meet all capital requirements in 1996.
Rate Matters
Electric
In 1993, the Company filed an Electric Rate Plan (Plan) with the PSC for the
three-year period which began December 1, 1994. The goals of this Plan included
minimizing future electric rate increases in addition to providing for the
continued recovery of the Company's regulatory assets while retaining
consistency with the Rate Moderation Agreement's (RMA) objective of restoring
the Company to financial health. As a result of the rate proceeding initiated by
the filing of the Company's Plan, the PSC issued an Order for the rate year
beginning December 1, 1994. The Order, which among other things, froze overall
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.
In addition, the PSC ordered that the rate proceeding be continued to allow the
parties to develop a plan for achieving long-term rate stability at the
prevailing rate levels, while, among other things, providing for the continuing
recovery of the Shoreham-related assets. In its rate decision, the PSC
reaffirmed its commitment to allow the Company to recover its Shoreham-related
assets, noting that it is a crucial factor in the Company's ability to maintain
its investment grade bond rating and to secure reasonably priced capital. The
continuation of the rate proceeding will also enable the PSC to consider the
Company's operations and its opportunities to achieve greater efficiency over
the next several years.
The Company filed a compliance filing under the terms of the Order to extend the
overall rate freeze through the rate year which began December 1, 1995. The PSC
has yet to issue an electric rate order in response to this filing.
In February 1996, the PSC issued an order to show cause and instituted a
proceeding to examine various opportunities to reduce the Company's current
electric rates. Specifically, the Company has been directed to address the
<PAGE>
following: (i) should all or a part of the $81 million Suffolk County property
tax refund, as more fully discussed under the captions "Liquidity" and "Shoreham
Related Litigation", be used to reduce current rates; (ii) should the return of
the $26 million 1995 rate year net reconciliation credit to customers, as more
fully discussed in Note 3 of Notes to Financial Statements, be accelerated;
(iii) determine, upon review of the forecasts reflected in the September 1995
compliance filing for the rate year commencing December 1, 1995, whether
adjustments to the forecasts can be reflected in rate reductions currently; and
(iv) revisit the current mechanics of the Fuel Cost Adjustment (FCA) clause, as
more fully discussed in Notes 1 and 3 of Notes to Financial Statements, to
determine whether all or a portion of any fuel cost savings can be reflected in
current customer bills.
The Company has been directed to submit a response to the order to show cause
addressing these items. Interested parties will have an opportunity to submit
comments on the Company's filing, after which a hearing before an ALJ will be
convened and the ALJ will determine further procedures. The Company is unable to
predict the outcome of this proceeding and the impact, if any, that it may have
on the Company's cash flow, financial condition or results of its operations.
While no assurance can be given, the Company's objective is to continue the
current rate freeze through the rate year ending November 30, 1997.
For a further discussion respecting electric rates see Note 3 of Notes to
Financial Statements.
Gas
In December 1993, the PSC approved a three-year gas rate settlement between the
Company and the Staff of the PSC. The gas rate settlement provides that the
Company receive, for each of the rate years beginning December 1, 1993, 1994 and
1995, annual gas rate increases of 4.7%, 3.8% and 3.2%, respectively. In the
determination of the revenue requirements for the gas rate settlement, an
allowed return on common equity of 10.1% was used. The gas rate decision also
provides 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 a
further discussion respecting gas rates see Note 3 of Notes to Financial
Statements.
Environment
The Company is subject to federal, state and local laws and regulations dealing
with air and water quality and other environmental matters. The Company
continually monitors its activities in order to determine the impact of such
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.
<PAGE>
The New York State Department of Environmental Conservation (NYSDEC) 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 is believed to have produced
manufactured gas. The Company expects to enter into an Administrative Consent
Order (ACO) with the NYDEC in 1996 regarding the management of environmental
activities at these properties. Although the exact amount of the Company's
clean-up costs cannot yet be determined, based on the findings of investigations
at two of these six sites, preliminary estimates indicate that it will cost
approximately $35 million to clean up all of these sites over the next five to
ten years. Accordingly, the Company had recorded a $35 million liability and a
corresponding regulatory asset to reflect its belief that the PSC will provide
for the future recovery of these costs through rates as it has for other New
York State utilities. The Company has notified its former and current insurance
carriers that it seeks to recover from them certain of these investigation and
clean-up costs. However, the Company is unable to predict the amount of
insurance recovery, if any, that it may obtain. In addition, there are several
other sites within the Company's service territory that were former MGP sites.
Research is underway to determine their relationship, if any, to the Company or
its predecessor companies. 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 been notified by the Environmental Protection Agency (EPA) that
it is one of many potentially responsible parties (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, have entered into an ACO with the EPA
to conduct a Remedial Investigation and Feasibility Study (RI/FS). Under a PRP
participant agreement, the Company is responsible for 8.2% of the costs
associated with this RI/FS which has been completed and is currently being
reviewed by the EPA. The Company's total share of costs to date is approximately
$0.5 million. The level of remediation required will be determined when the EPA
issues its decision. Based on information available to date, the Company
currently anticipates that the total cost to remediate this site will be between
$14 million and $30 million. The Company has recorded a liability of $1.1
million representing its estimated share of the additional cost to remediate
this site.
With respect to the other two sites, located in Kansas City, Kansas and Kansas
City, Missouri, the Company is investigating allegations that it had made
agreements for disposal of polychlorinated biphenyls (PCBs) or items containing
PCBs at these sites. The EPA has provided the Company with documents indicating
that the Company was responsible for less than 1% of the total weight of the
PCB-containing equipment, oil and materials that were shipped to the Missouri
site. The EPA has not yet completed compiling documents for the Kansas site. The
Company is currently unable to determine its share, if any, of the cost to
remediate these two sites or the impact, if any, on the Company's financial
position.
<PAGE>
In addition, the Company was notified that it is a PRP at a Superfund Site in
Farmingdale, New York. Portions of the site are allegedly contaminated with
PCBs, solvents and metals. The Company was also notified by other PRPs that it
should be responsible for expenses in the amount of approximately $0.1 million
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 the cost to remediate this site or the impact, if any, on
the Company's financial position.
The Connecticut Department of Environmental Protection (DEP) and the Company
have signed an ACO which will require the Company to address leaks from an
electric transmission cable located under the Long Island Sound (Sound Cable).
The Sound Cable is jointly owned by the Company and the Connecticut Light and
Power Company, a subsidiary of Northeast Utilities. Specifically, the order
requires the Company to evaluate existing procedures and practices for cable
maintenance, operations and fluid spill response procedures and to propose
alternatives to minimize fluid spill occurrences and their impact on the
environment. Alternatives to be evaluated range from improving existing
monitoring and maintenance practices to removal and replacement of the Sound
Cable. The Company is currently unable to determine the costs it will incur to
complete the requirements of the ACO or to comply with any additional DEP
requirements.
In addition, the Company has been served with a subpoena from the U.S. Attorney
for the District of Connecticut to supply certain written information regarding
releases of fluid from the Sound Cable, as well as associated operating and
maintenance practices. Since the investigation is in its preliminary stages, the
Company is unable to determine the likelihood of a criminal proceeding being
initiated at this time. However, the Company believes all activities associated
with the response to releases from the Sound Cable were consistent with legal
and regulatory requirements.
The Company believes that all significant costs incurred with respect to
environmental investigations and remediation activities will be recoverable
through rates.
Conservation Services
The Company's 1995 Demand Side Management (DSM) Plan (1995 DSM Plan) focused on
promoting energy efficient load growth while minimizing the impact that
conservation programs have on increasing the Company's electric rates. The 1995
DSM Plan reflected the Company's goal to educate its customers on the benefits
of energy efficiency while reducing the reliance on cash subsidies. The PSC
approved funding for the Company's 1995 DSM Plan at $12 million, as compared to
$19 million and $33 million in 1994 and 1993, respectively. In addition, the PSC
established an incremental annualized energy savings goal of 70 Gwh, including a
monetary penalty to the Company if 80% of the threshold was not achieved. The
Company was successful in exceeding the penalty threshold identified by the PSC.
In 1996, the Company plans to continue its pursuit of energy efficiency and peak
load reduction while maintaining the strategy of controlling electric
<PAGE>
rates. Through careful management of DSM expenditures and the delivery of
targeted DSM programs, the Company plans to offer cost-effective DSM programs
that will appeal to a variety of customers. The 1996 DSM Plan will continue to
focus on customer education and information and to promote efficient load growth
in both the residential and commercial sectors. In addition, the Company will
place an increased emphasis on programs which facilitate the attraction,
expansion and retention of major commercial/industrial customers. These programs
will act to position the Company as a business partner, helping to improve the
economic climate on Long Island. At the same time, these programs will help to
improve the Company's competitiveness as an energy provider.
Shoreham Related Litigation
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 are
the subject of litigation 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. On January 10, 1994, the Appellate Division, Second
Department, affirmed a lower court's March 29, 1993 decision holding, in major
part, that the Company is not obligated for any real property taxes that accrued
after February 28, 1992, attributable to property that it conveyed to LIPA, that
PILOTs commenced on March 1, 1992, that PILOTs are subject to refunds and that
the LIPA act does not provide for the termination of PILOTs. Generally, these
holdings are favorable to the Company. In October 1995, the Court of Appeals
granted the parties motion for leave to appeal the lower court decision
following an agreement between the parties to voluntarily dismiss outstanding
causes of action. The proper amount of PILOTs is to be determined in pending
litigation described below.
The costs of Shoreham included real property taxes imposed by, among others, the
Town of Brookhaven on Shoreham and capitalized by the Company during
construction. The Company had sought judicial review in New York Supreme Court,
Suffolk County of the assessments upon which those taxes were based for the
years 1976 through 1992 (excluding 1979). The Supreme Court consolidated the
review of the tax years at issue into two phases: 1976 through 1983, excluding
1979, which had been settled (Phase I); and 1984 through 1992 (Phase II). In
October 1992, the Supreme Court ruled that Shoreham had been overvalued for real
property tax purposes for Phase I. In May 1995, the New York Court of Appeals
denied the request of the Town of Brookhaven and other respondents for leave to
appeal this decision, which had been previously affirmed in an unanimous
decision by the New York State Appellate Division, Second Department.
Thereafter, in January 1996, the Company received approximately $81 million,
including interest, from Suffolk County pursuant to this Phase I judgment.
In the Phase II proceeding, the Company is seeking to recover over $500
million, plus interest, in property taxes paid on Shoreham for the years
1984-1992. In this proceeding, the taking of evidence has been completed and
final briefs have been filed by the parties. The amount of the Company's
recovery, if any, in the Phase II proceeding and the timing of all refunds
cannot yet be determined. LIPA has been permitted to intervene in the proceeding
for the 1991-92 tax year which under the Appellate Division's decision discussed
above, will partially establish LIPA's PILOT obligation. Pursuant to the
Appellate Division's decision, LIPA's PILOT obligations will be determined
either by agreement or in a separate proceeding challenging the Shoreham
assessment for the 1992-93 tax year.
<PAGE>
Results of Operations
Earnings
Earnings for the years 1995, 1994 and 1993 were as follows:
<TABLE>
<CAPTION>
(In millions of dollars and shares except earnings per share)
- -----------------------------------------------------------------------------------------
1995 1994 1993
- -----------------------------------------------------------------------------------------
<S> <C> <C> <C>
Net income $ 303.3 $ 301.8 $ 296.6
Preferred stock dividend
requirements 52.6 53.0 56.1
- ----------------------------------------------------------------------------------------
Earnings for Common Stock $ 250.7 $ 248.8 $ 240.5
========================================================================================
Average common shares
outstanding 119.2 115.9 112.1
- ----------------------------------------------------------------------------------------
Earnings per Common Share $ 2.10 $ 2.15 $ 2.15
========================================================================================
</TABLE>
The Company's 1995 earnings per common share were lower than 1994 earnings per
common share as a result of the PSC's current electric rate order, effective
December 1, 1994, that lowered the allowed return on common equity from 11.6% to
11.0% and modified certain performance-based incentives. These two actions had
the effect of reducing the Company's earnings by 15 cents per common share
compared to the previous year. The effects of the electric rate order were
mitigated by a significant reduction in operating costs which were achieved by a
comprehensive cost containment program.
Earnings per common share for the gas business were higher in 1995 when compared
to 1994 due to cost containment measures and a write-off in 1994 of previously
deferred storm costs. The higher level of earnings in the gas business also
helped to mitigate the adverse effects of the electric rate order.
Earnings per common share for 1994 equaled that of 1993. The electric business
achieved a higher level of earnings which were offset by a decrease in the gas
business earnings.
Revenues
Total revenues, including revenues from the recovery of fuel costs, were $3.1
billion for each of the years ended December 31, 1995 and 1994, and $2.9 billion
for the year ended December 31, 1993.
Electric Revenues
Revenues from the Company's electric operations totaled $2.5 billion for the
years ended December 31, 1995 and 1994, compared to $2.4 billion in 1993.
The Company's electric rates have not increased since December 1, 1993, when the
Company received an electric rate increase of 4.0%. Given the absence of any
electric rate increases combined with operating in a mature
<PAGE>
market, electric revenues have remained relatively flat over the last two years.
The December 1993 rate increase provided $69 million of additional electric
revenues in 1994 when compared to 1993.
For a further discussion on electric rates, see Notes 1 and 3 of Notes to
Financial Statements.
Total electric sales volumes were 16,572 million kilowatt hour (kWh) in 1995,
16,382 million kWh in 1994 and 16,128 million kWh in 1993. The increase in 1995
sales when compared to 1994 is attributable primarily to higher sales for
resale. System sales for 1995, when compared to 1994, were negatively impacted
by a 174 million kWh reduction in customer usage due to the effects of weather.
Partially offsetting this reduction was a 116 million kWh increase in system
load over 1994. The 116 million kWh growth occurred despite the loss of the
Stony Brook Project. The increase in system sales for 1994, when compared to
1993, was primarily the result of warmer weather experienced in the comparable
summer months. In each of the years 1995, 1994 and 1993, residential sales
accounted for 45% of total system sales, while commercial and industrial sales
accounted for 52% of the total, with sales to public authorities representing
3%.
Gas Revenues
Revenues from the Company's gas operations for the years 1995, 1994 and 1993
were $591 million, $586 million and $529 million, respectively.
In December 1993, the PSC approved a three-year gas rate settlement between the
Company and the Staff of the PSC. The gas rate settlement provided the Company
with annual gas rate increases of 4.7%, 3.8% and 3.2% for the rate years
beginning December 1, 1993, 1994 and 1995, respectively. These rate increases
provided $21 million in additional revenues for 1995 as compared to 1994, and
$25 million in additional revenues for 1994 as compared to 1993.
A decrease of $24 million in the recoveries of gas fuel expenses more than
offset the additional revenues provided by the annual gas rate increase in 1995.
The decrease in the recovery of gas fuel expenses in 1995 was primarily due to
lower average gas prices when compared to 1994. The recoveries of gas fuel
expenses in 1994 when compared to 1993, increased by $33 million primarily due
to increased billed sales volumes and higher average gas prices. The Company has
a weather normalization clause to mitigate the impact on revenues of
experiencing weather that is warmer or colder than normal.
In 1993, the Company began selling gas to businesses off the Company's system.
These off-system gas sales revenues totaled $24 million, $26 million and $8
million for the years 1995, 1994 and 1993, respectively. Profits realized from
off-system sales are allocated 85% to firm gas customers and 15% to shareowners.
For 1995, firm gas sales volumes decreased by less than 1% when compared to
1994 even though the 1995 heating season was much warmer than the 1994 heating
season. The impact of the warmer weather was ameliorated by the addition of over
6,500 new gas space heating customers during 1995, resulting from the
continuation of the Company's gas expansion program. In 1994, the Company added
over 7,000 gas space heating customers.
<PAGE>
Operating Expenses
Fuel and Purchased Power
Fuel and purchased power expenses for the years 1995, 1994 and 1993 were as
follows:
<TABLE>
<CAPTION>
(In millions of dollars)
- -------------------------------------------------------------------------------------------
1995 1994 1993
- -------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Fuel for Electric Operations
Oil $ 98 $ 145 $ 180
Gas 149 101 93
Nuclear 14 15 13
Purchased power 310 308 293
- -------------------------------------------------------------------------------------------
Total 571 569 579
- -------------------------------------------------------------------------------------------
Gas fuel 264 279 249
- -------------------------------------------------------------------------------------------
Total $ 835 $ 848 $ 828
===========================================================================================
</TABLE>
During 1995, the Company refitted an additional steam generating unit to enable
it to burn either oil or natural gas, bringing the total number of steam units
capable of burning natural gas to seven. Of these seven, five are dual-fired,
having the capability of burning either natural gas or oil. As a result, the
Company, over the past three years, has increased the amount of energy generated
with natural gas, thereby displacing more costly energy generated with oil or
purchased from others. Electric fuel expense for 1995 increased slightly from
1994 as a result of increased electric sales volumes. For 1994, fuel expense for
electric generation decreased relative to 1993 as a result of an increase in the
amount of energy generated with more economical natural gas.
Electric fuel and purchased power mix for the years 1995, 1994 and 1993 were as
follows:
<TABLE>
<CAPTION>
(In thousands of MWH)
- ------------------------------------------------------------------------------------------
1995 1994 1993
- ------------------------------------------------------------------------------------------
MWH % MWH % MWH %
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Oil 3,099 17% 4,480 25% 5,894 34%
Gas 6,344 36 4,056 23 3,329 19
Nuclear 1,301 7 1,498 9 1,291 7
Purchased power 7,143 40 7,640 43 7,023 40
- ------------------------------------------------------------------------------------------
Total 17,887 100% 17,674 100% 17,537 100%
==========================================================================================
</TABLE>
<PAGE>
The Company has reduced oil consumption by purchasing more economical power
from other systems, by increased generation with natural gas, by using energy
generated at NMP2 and by purchasing energy supplied by cogenerators and
independent power producers (IPPs) as required by New York State law. The total
barrels of oil consumed for electric operations were 5.2 million, 7.5 million,
and 9.7 million for the years 1995, 1994 and 1993, respectively.
Cogenerators and IPPs provided approximately 10% of the total energy made
available by the Company in 1995 and approximately 9% in both 1994 and 1993. The
increase in purchased power expenses in 1995 and 1994 is primarily attributable
to purchases from the 136 MW facility in Holtsville, New York, owned by NYPA,
and constructed for the benefit of the Company.
Gas system fuel expenses decreased in 1995 by $15 million when compared with
1994, despite higher sales volumes, because of a decline in the average price of
gas. In 1994, these expenses increased by $30 million when compared with 1993,
primarily due to the costs associated with the Company's off-system gas sales
which began in 1993.
Operations and Maintenance Expenses
Operations and maintenance (O&M) expenses, excluding fuel and purchased power,
were $511 million, $541 million and $522 million, for the years 1995, 1994 and
1993, respectively. The decrease in O&M for 1995 was primarily due to the
continuation of the Company's cost containment efforts which resulted in lower
production costs, lower transmission and distribution costs and lower
administrative and general expenses.
O&M expenses increased in 1994 when compared to 1993 due to the write-off of
previously deferred storm costs associated with gas operations, an increase in
costs associated with the Company's gas expansion program, the recognition of
certain costs which exceeded the Company's insurance recoveries, and an increase
in employee benefit costs.
Rate Moderation Component Amortization
The rate moderation component amortization reflects the difference between the
Company's revenue requirements under conventional ratemaking and the revenues
provided by its electric rate structure. In 1995, 1994 and 1993, the Company
recorded non-cash charges to income of approximately $22 million, $198 million
and $89 million, respectively, representing the amortization of the RMC. In
1995, the operation of the Fuel Moderation Component (FMC) as discussed in Note
3 of Notes to Financial Statements, resulted in credits to the RMC of $87
million which more than offset the accretion of the RMC resulting from revenues
under the current electric rate structure being less than revenue requirements
under conventional ratemaking. For the years 1994 and 1993, revenues under the
rate structure in effect in those years, were greater than that required by
conventional ratemaking resulting in the amortization of the RMC. In addition,
the RMC amortization for the years 1994 and 1993 increased as a result of the
FMC, which totaled $83 million and $45 million for 1994 and 1993, respectively.
For a further discussion on the RMC, see Note 3 of Notes to Financial
Statements.
<PAGE>
Other Regulatory Amortization
In 1995, the net total of other regulatory amortization was a non-cash charge to
income of $161.6 million, compared to $4.3 million in 1994. This change is
primarily attributable to the operation of the revenue reconciliation mechanism
and increased amortization of the LRPP deferrals, as more fully discussed in
Note 3 of Notes to Financial Statements. The revenue reconciliation mechanism,
as established under the LRPP, eliminates the impact on earnings of experiencing
electric 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). The difference between the actual and adjudicated net margin
sales level is deferred on a monthly basis during the year. During 1995, the
Company recorded a non-cash charge to income of approximately $64 million
representing a net margin level in excess of that provided for in rates. In
1994, the Company recorded non-cash income of approximately $51 million as the
actual net margin level was below that which was provided for in rates. The
increase in the amortization of the LRPP deferrals in 1995 totaled $34 million.
In 1994, other regulatory amortization was higher than 1993 as a result of the
amortization of the 1992 rate year LRPP deferrals which began in August 1993,
the operation of the interest deferral mechanism and an increase in amortization
expense related to Shoreham post-settlement costs. These items were partially
offset by higher net margin revenues.
Operating Taxes
Operating taxes were $448 million, $407 million and $386 million for the years
1995, 1994 and 1993, respectively. The increase in operating tax of
approximately $41 million in 1995 when compared to 1994 is primarily
attributable to increased property taxes. The increase of $21 million in 1994
when compared to 1993 is primarily attributable to higher gross receipts taxes
resulting from increased revenues, higher property taxes, additional payroll
taxes and higher dividend taxes.
Federal Income Tax
Federal income tax was $206 million, $177 million and $172 million for the years
1995, 1994 and 1993, respectively. The increase in federal income tax in 1995
when compared to 1994 is primarily attributable to higher earnings and the
amortization of a tax rate increase which had previously been deferred.
Interest Expense
The reductions in interest expense in 1995 when compared to 1994 and in 1994
when compared to 1993 are primarily attributable to lower outstanding debt
levels. The Company's strategy is to apply available cash balances toward the
satisfaction of debt whenever practicable. Accordingly, in 1995, the Company
used approximately $75 million of cash on hand to redeem, prior to maturity, the
remaining outstanding First Mortgage Bonds. During 1994, the Company used
approximately $200 million of cash on hand and the proceeds from the issuance of
5.1 million shares of common stock to reduce debt
<PAGE>
levels by approximately $300 million. The lower interest expense in 1994 also
reflects the satisfaction of $175 million of debt which matured in November 1993
with the use of cash on hand.
Selected Financial Data
Additional information respecting revenues, expenses, electric and gas operating
income and operations data and balance sheet information for the last five years
is provided in Tables 1 through 11 of Selected Financial Data. Information with
regard to the Company's business segments for the last three years is provided
in Note 11 of Notes to Financial Statements.
<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:
April , 1996
Signature and Title
WILLIAM J. CATACOSINOS*
William J. Catacosinos, Principal
Executive Officer, President and
Chairman of the Board of Directors
/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
PETER O. CRISP*
Peter O. Crisp, 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)
<PAGE>
SIGNATURES
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: April , 1996 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, have been filed with the Securities and Exchange Commission as Exhibit
24 to the Company's Form 10-K for the Year Ended December 31, 1995.
