SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A
AMENDMENT NO. 2
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996
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 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:
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
7.85% Series Due 1999 7.90% Series Due 2008
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 December 31, 1996 was $2,672,275,023. The aggregate market value
of Preferred Stock held by non-affiliates of the Company at December 31, 1996,
established by Lehman Brothers based on the average bid and asked price, was
$675,542,820.
COMMON STOCK ($5 PAR) - SHARES OUTSTANDING AT DECEMBER 31, 1996: 120,780,792
<PAGE>
This Form 10-K/A amends Part II, Items 7 and 8 of Form 10-K for the Fiscal Year
ended December 31, 1996.
PART II
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
EARNINGS
Earnings for the years 1996, 1995 and 1994 were as follows:
(In millions of dollars and shares except earnings per share)
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
Net income $ 316.5 $ 303.3 $ 301.8
Preferred stock dividend
requirements 52.2 52.6 53.0
- --------------------------------------------------------------------------------
Earnings for Common Stock $ 264.3 $ 250.7 $ 248.8
- --------------------------------------------------------------------------------
Average common shares
outstanding 120.4 119.2 115.9
- --------------------------------------------------------------------------------
Earnings per Common Share $ 2.20 $ 2.10 $ 2.15
================================================================================
The Company's 1996 earnings are higher for both the 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 are a result of the
Company's increased investment in electric plant in 1996, as compared to 1995.
Factors contributing to the increase in electric business earnings include 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 sales.
The Company's 1995 earnings per common share were lower than 1994 earnings per
common share as a result of the New York State Public Service Commission's (PSC)
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. Partially offsetting the effects on earnings of the electric rate
order was higher gas business earnings in 1995 when compared to 1994.
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REVENUES
ELECTRIC REVENUES
Revenues from the Company's electric operations totaled $2.5 billion in each of
the years ended December 31, 1996, 1995 and 1994.
The Company experienced a growth in electric system sales in 1996 on a weather
normalized basis compared to 1995 and in 1995 compared to 1994. This growth is
primarily attributable to the addition of new electric customers. The Company's
electric revenues fluctuate 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 which
eliminates the impact on earnings caused by sales volumes that are above or
below adjudicated levels. Total electric sales volumes were 16,414 million
kilowatt hour (kWh) in 1996, compared to 16,572 million kWh in 1995 and 16,382
million kWh in 1994.
For a further discussion on electric rates, see Notes 1 and 3 of Notes to
Financial Statements.
GAS REVENUES
Revenues from the Company's gas operations for the years 1996, 1995 and 1994
were $684 million, $591 million and $586 million, respectively.
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, an increase
in sales volumes, an increase in gas fuel expense recoveries and revenues
generated through the Company's continuing efforts to provide non-traditional
services, including off-system sales. The increase in 1995 revenues when
compared to 1994 is attributable to a 3.8% gas rate increase, effective December
1, 1994, offset by a decrease in fuel expense recoveries.
The Company experienced a 6.3% increase in firm sales volumes in 1996 compared
to 1995, due to the addition of approximately 5,100 gas space heating customers
and colder weather during the 1996 heating season when compared to the prior
year. The increase in sales volumes caused by variations in weather has a
limited impact on revenues as the Company's current gas rate structure includes
a weather normalization clause which mitigates the impact on revenues of
experiencing weather that is warmer or colder than normal.
The Company continues to increase its space heating penetration through various
marketing programs, and as a result of these efforts has added approximately
20,000 gas space heating customers over the past three years.
The recovery of gas fuel expenses in 1996 when compared to 1995 increased
approximately $31 million as a result of higher average gas
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prices and increased per customer usage due to colder weather than experienced
in the prior year. In 1995, the Company experienced a decrease of $24 million in
the recoveries of gas fuel expenses when compared to the same period of 1994,
primarily due to lower average gas prices.
In 1996, non-traditional revenues totaled $46 million, including $37 million for
off-system sales. In 1995 and 1994, revenues from off-system sales totaled $24
million and $26 million, respectively. Profits generated from off-system sales
are allocated 85% to the firm gas ratepayer and 15% to the shareowners, in
accordance with PSC mandates.
OPERATING EXPENSES
FUEL AND PURCHASED POWER
Fuel and purchased power expenses for the years 1996, 1995 and 1994 were as
follows:
(In millions of dollars)
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
Fuel for Electric Operations
Oil $ 158 $ 98 $ 145
Gas 138 149 101
Nuclear 15 14 15
Purchased power 329 310 308
- --------------------------------------------------------------------------------
Total 640 571 569
================================================================================
Gas fuel 323 264 279
- --------------------------------------------------------------------------------
Total $ 963 $ 835 $ 848
================================================================================
Electric fuel and purchased power mix for the years 1996, 1995 and 1994 were as
follows:
(In thousands of MWh)
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
MWh % MWh % MWh %
- --------------------------------------------------------------------------------
Oil 4,219 24% 3,099 17% 4,480 25%
Gas 4,542 25 6,344 36 4,056 23
Nuclear 1,558 9 1,301 7 1,498 9
Purchased power 7,388 42 7,143 40 7,640 43
- --------------------------------------------------------------------------------
Total 17,707 100% 17,887 100% 17,674 100%
================================================================================
During 1996, the Company completed the first of two planned conversions of oil
fired steam generating units at its Port Jefferson Power Station to
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dual firing units, bringing the total number of steam units capable of burning
natural gas to eight. Of the Company's eight steam generation units capable of
burning natural gas, six are dual-fired, providing the Company with the ability
to burn the most cost efficient fuel available, consistent with seasonal
environmental requirements, thereby providing customers with the lowest possible
cost energy. The conversion of the second unit at Port Jefferson has a projected
completion date of May 1997.
As a result of a sharp increase in the cost of natural gas during the year,
generation with oil became more economical than generation with gas. The total
barrels of oil consumed for electric operations were 7.1 million, 5.2 million,
and 7.5 million for the years 1996, 1995 and 1994, respectively.
Cogenerators, Independent Power Producers (IPPs) and energy supplied from a
facility in Holtsville, New York, owned by the New York Power Authority (NYPA),
and constructed for the benefit of the Company, provided approximately 16% of
the total energy made available by the Company in 1996 and 1995, compared to
approximately 14% in 1994. Increases in purchase power expenses in 1996 compared
to 1995 is due to increases in the average unit price and in the quantity
purchased. The increase in purchased power expenses in 1995 compared to 1994 is
primarily attributable to increased purchases from the NYPA Holtsville facility
which began commercial operations in 1994.
Gas system fuel expense increased in 1996 by $58 million when compared with
1995, due to higher firm sales volumes and a 26% increase in the Company's
average price of gas. In 1995, this expense decreased by $15 million when
compared with 1994, as a result of a decline in the average price of gas,
despite higher sales volumes.
Variations in fuel costs have no impact on operating results as the Company's
current rate structures include fuel adjustment clauses whereby variations
between actual fuel costs and fuel costs included in base rates are deferred and
subsequently returned to or collected from customers. However, in a period when
base electric fuel costs are in excess of actual electric fuel costs, such
amounts are credited to the RMC.
OPERATIONS AND MAINTENANCE EXPENSES
Operations and maintenance (O&M) expenses, excluding fuel and purchased power,
were $499 million, $511 million and $541 million, for the years 1996, 1995 and
1994, respectively. The decrease in O&M for 1996 compared to 1995 and 1995
compared to 1994 was primarily due to the Company's continuing 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. The RMC is adjusted monthly for the
operation of the Company's Fuel Moderation Component (FMC)
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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.
In 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, as discussed above. The
adjustments to the accretion of the RMC totaled $26 million, of which $24
million was derived from the operation of the FMC mechanism.
In 1995 and 1994, the Company recorded non-cash charges to income of
approximately $22 million and $198 million, respectively, after giving effect to
the credits generated principally by the operation of the FMC mechanism. FMC
credits for 1995 and 1994 totaled $87 million and $83 million, respectively.
Based on the Company's current long-range projections for energy sales,
operations and maintenance costs, property taxes, construction and other
expenditures, the RMC balance will be fully amortized by year-end 2001. The
assumptions used in the forecast are as follows: (i) the Company's base electric
rates remain at current levels through the year 2001; (ii) the Company receives
PSC permission to credit the Phase I Shoreham property tax litigation proceeds
that the Company received in January 1996 to the RMC balance in 1997, at which
time the proceeds plus interest are expected to be $83 million; and (iii) $360
million of the total judgment awarded the Company in Phase II of the Shoreham
property tax case is received by the Company during the 1999 to 2001 time frame
and will be applied to reduce the RMC balance. Based upon the assumptions used
in this forecast, RMC non-cash charges to income will be approximately $52
million in 1997, $89 million in 1998, $143 million in 1999, $57 million in 2000
and $57 million in 2001. These estimates are based on the multi-year rate plan
(Plan) submitted to the PSC in September 1996.
If the assumptions outlined immediately above are not adopted by the PSC, the
Company proposed as an alternative in the September 1996 filing that, in order
to insure the timely and certain recovery of any remaining RMC balance at
November 30, 1999, that the Company recover any such balance through rates over
a two year period using its Fuel Adjustment Clause. By using the Fuel Adjustment
Clause, which it has used in the past to recover other regulatory assets,
customer bills would be automatically adjusted in order to amortize on a
straight-line-basis any remaining RMC balance over a two year period ending
November 30, 2001.
Based upon the above, and the fact that actions of the PSC continue to support
the full recovery of the Shoreham related regulatory assets, as provided in the
Rate Moderation Agreement (RMA), the Company believes that future revenues will
be provided specifically for the recovery of the RMC balance. For a further
discussion of the plan, see Rate Matters, under the heading "Electric."
For a further discussion of the RMC, see Note 3 of Notes to Financial
Statements.
OTHER REGULATORY AMORTIZATION
In 1996, the net total of other regulatory amortization was a non-cash charge to
income of $127 million, compared to $162 million in 1995 and $4 million in 1994.
The change from 1996 to 1995 is primarily attributable to the operation of the
revenue reconciliation mechanism included in the Company's electric rate
structure, partially offset by a non-cash charge to income recorded to reduce
the Company's earnings to the levels provided for in rates for both the electric
and gas businesses.
The electric revenue reconciliation mechanism, as established under the
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LILCO Ratemaking and Performance Plan (LRPP), 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. The Company recorded a non-cash charge to income of
approximately $3 million and $64 million for the years 1996 and 1995,
respectively, representing a net margin level in excess of that provided for in
rates. The decrease between 1996 and 1995 was the result of an increase in the
adjudicated net margin sales levels and cooler summer weather in 1996 when
compared to 1995.
Earnings in excess of the Company's allowed return on common equity generated by
the electric business was approximately $9 million for the 1996 rate year
compared to approximately $6 million for the 1995 rate year. In accordance with
the Company's electric rate structure, earnings above the allowed return on
common equity are applied against the RMC balance. The ratepayers' portion of
gas earnings in excess of a 10.6% allowed return on common equity totaled $10
million for the 1996 rate year compared to $1 million in 1995.
In 1995, other regulatory amortization was higher than 1994 as a result of the
operation of the revenue reconciliation mechanism and an increase in the
amortization of prior period LRPP deferrals, as more fully discussed in Note 3
of Notes to Financial Statements.
OPERATING TAXES
Operating taxes were $472 million, $448 million and $407 million for the years
1996, 1995 and 1994, respectively. The increase in 1996 compared to 1995 is
primarily attributable to increased property taxes, as well as higher gross
receipts taxes due to increased revenues. The increase in 1995 when compared to
1994 is primarily attributable to higher property taxes.
FEDERAL INCOME TAX
Federal income tax was $209 million, $206 million and $177 million for the years
1996, 1995 and 1994, respectively. The increase in federal income tax in 1996
when compared to 1995 was primarily attributable to higher earnings, partially
offset by the utilization of investment tax credits. The increase in 1995 when
compared to 1994 was primarily attributable to higher earnings and the
amortization of previously deferred taxes resulting from a change in corporate
tax rates.
OTHER INCOME AND DEDUCTIONS, NET
Other income and deductions, totaled $19 million for 1996, compared to $34
million and $35 million for 1995 and 1994, respectively. The decrease in 1996
when compared to 1995 is primarily attributable to the recognition of
nonrecurring 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
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certain litigation proceeds related to the construction of the Shoreham Nuclear
Power Station. The change from 1995 when compared to 1994, in addition to the
effects of the litigation proceeds, resulted from lower non-cash carrying
charges and lower incentive income as a result of the PSC rate order for the
rate year ended November 30, 1995, which eliminated certain performance-based
incentives.
INTEREST EXPENSE
Lower interest expense in 1996 compared to 1995, and in 1995 compared to 1994 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. For a further discussion of the Company's
investment ratings, see the discussion below under the heading "Investment
Rating". The Company's strategy continues to be the application of available
cash balances toward the satisfaction of maturing debt whenever practicable.
Accordingly, in 1996, the Company used cash on hand and cash previously
deposited with the Trustee of the General & Refunding (G&R) Mortgage to satisfy
the mandatory redemption of $415 million of the Company's G&R Bonds. During
1995, the Company used approximately $75 million of cash on hand to redeem,
prior to maturity, the remaining outstanding First Mortgage Bonds.
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LIQUIDITY
During 1996, 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 reduce both O&M
expenses and construction expenditures; (ii) lower interest payments resulting
from lower debt levels; and (iii) increased revenues from off-system gas sales.
At December 31, 1996, the Company's cash and cash equivalents amounted to
approximately $280 million, compared to $351 million at December 31, 1995. In
addition, the Company has available for its use a revolving line of credit
through October 1, 1997, provided by its 1989 Revolving Credit Agreement (1989
RCA). In July 1996, at the Company's request, the amount committed by the banks
participating in the facility was reduced from $300 million to $250 million. The
Company believes this action is appropriate given the levels of cash on hand,
projected future cash generated from operations and modest debt and preferred
stock maturities through 1998. This line of credit is secured by a first 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 RMC balance by
the amount received, net of litigation costs incurred by the Company. The PSC
has not yet acted on the Company's petition and, therefore, such amounts
continue to be deferred on the Company's balance sheet as other regulatory
liabilities.
In November 1996, the New York State Supreme Court ruled that Shoreham had also
been over-assessed for real property tax purposes for the years 1984 through
1992. Based on this over-assessment, the Company has preliminarily estimated
that it is entitled to a tax refund of approximately $500 million plus interest.
If the assessment for the 1991-92 tax year is used to determine the proper
amount of payments-in-lieu-of-taxes (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 real property tax and PILOT refunds.
The Company does not intend to access the financial markets during 1997 to meet
any of its operating, construction or refunding requirements, including the
retirement of its $250 million of maturing debt on February 15, 1997. However,
if necessary, the Company will avail itself of interim financing via the 1989
RCA to satisfy a portion of the debt maturing in February 1997. The Company will
avail itself of any tax-exempt financing
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made available to it by the New York State Energy Research and Development
Authority (NYSERDA). With respect to the repayment of $101 million of maturing
debt in 1998 and the repayment of $454 million of maturing debt and $22 million
of mandatory redemption requirements of preferred stock in 1999, 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 Company has protested some of the proposed adjustments
which are presently under review by the Regional Appeals Office of the Internal
Revenue Service. The Company believes that cash balances at the time of
settlement will be sufficient to satisfy any settlement reached. However, if
necessary, the Company will avail itself of interim financing via the 1989 RCA
to meet this obligation. The Company currently believes that a settlement of the
1981 through 1989 years should be reached with the Regional Appeals Office
sometime in 1997.
CAPITALIZATION
The Company's capitalization, including current maturities of long-term debt and
current redemption requirements of preferred stock, at December 31, 1996 and
1995, was $7.9 billion and $8.3 billion, respectively. At December 31, 1996 and
1995, the Company's capitalization ratios were as follows:
1996 1995
- --------------------------------------------------------------------------------
Long-term debt 59.3% 61.8%
Preferred stock 8.9 8.6
Common shareowners' equity 31.8 29.6
- --------------------------------------------------------------------------------
100.0% 100.0%
================================================================================
In support of the Company's continuing goal to reduce its debt ratio, the
Company, in 1996, retired at maturity $415 million of G&R Bonds, with cash on
hand and cash previously deposited with the Trustee of the G&R Mortgage. The
Company expects to use cash on hand to satisfy the $250 million of G&R Bonds
scheduled to mature in February 1997. However, if necessary, the Company will
avail itself of interim financing via the 1989 RCA to satisfy a portion of this
obligation.
INVESTMENT RATING
The Company's securities are rated by Standard and Poor's (S&P), Moody's
Investors Service, Inc. (Moody's), Fitch Investors Service, L.P. (Fitch) and
Duff & Phelps Credit Rating Co. (D&P). The rating agencies have been
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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 June 1996, Moody's downgraded its rating of the Company's G&R Bonds from
minimum investment grade to one notch below minimum investment grade. Moody's
also downgraded its ratings of the Company's debentures and preferred stock,
which were already below minimum investment grade.
In November 1996, Moody's revised its outlook on the Company's G&R Bonds,
debentures and preferred stock from negative to stable, as a result of a New
York State Supreme Court ruling that found that Shoreham had been overvalued for
real property taxes for the years 1984 through 1992. For a further discussion of
this ruling, see Item 3, Legal Proceedings.
As a result of the announcement of the merger agreement on December 29, 1996
between the Company and The Brooklyn Union Gas Company, the Company's bond
ratings "outlook"/"Credit Watch" was raised to "positive" by Moody's, S & P and
Fitch. D&P has reaffirmed the Company's ratings but maintains a rating watch
with uncertain implications.
At December 31, 1996 the ratings for each of the Company's principal securities
were as follows:
S&P Moody's Fitch D&P
- --------------------------------------------------------------------------------
G&R Bonds BBB- Ba1 BBB- BBB
Debentures BB+ Ba3 BB+ BB+
Preferred Stock BB+ ba3 BB-* BB
- --------------------------------------------------------------------------------
MINIMUM INVESTMENT
GRADE BBB- Baa3 BBB- BBB-
================================================================================
Bold face indicates securities that meet or exceed minimum investment grade.
* In December 1996, Fitch announced that it will begin rating preferred stock on
the same scale as investment grade and speculative bonds and, as a result, the
Company's preferred stock is now rated BB-.
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CAPITAL REQUIREMENTS AND CAPITAL PROVIDED
Capital requirements and capital provided for 1996 and 1995 were as follows:
(In millions of dollars)
- --------------------------------------------------------------------------------
1996 1995
- --------------------------------------------------------------------------------
CAPITAL REQUIREMENTS
Construction*
Electric $ 142 $ 144
Gas 71 79
Common 27 21
- --------------------------------------------------------------------------------
Total Construction 240 244
- --------------------------------------------------------------------------------
Refundings and Dividends
Long-term debt 415 100
Preferred stock 5 5
Common stock dividends 214 211
Preferred stock dividends 52 53
- --------------------------------------------------------------------------------
Total Refundings and Dividends 686 369
- --------------------------------------------------------------------------------
Shoreham post-settlement costs 52 71
- --------------------------------------------------------------------------------
TOTAL CAPITAL REQUIREMENTS $ 978 $ 684
================================================================================
CAPITAL PROVIDED
Cash generated from operations $ 892 $ 772
Long-term debt issued - 49
Common stock issued 19 20
Other investing activities (4) 9
Increase(decrease) in cash 71 (166)
- --------------------------------------------------------------------------------
Total Capital Provided $ 978 $ 684
================================================================================
* Excludes non-cash allowance for other funds used during construction. For
further information, see the Statement of Cash Flows.
For 1997, total capital requirements (excluding common stock dividends) are
estimated to be $629 million, of which maturing debt is $251 million,
construction requirements are $282 million, preferred stock dividends are $52
million, preferred stock sinking funds are $1 million and Shoreham
post-settlement costs are $43 million (including $41 million for payments-
in-lieu-of-taxes). The Company believes that cash generated from operations
coupled with beginning cash balances will be sufficient to meet all capital
requirements in 1997.
Based upon the projections of peak demand for electric power, the Company
believes it will need to acquire additional generating or demand-side resources
starting in 1998 in order to maintain satisfactory electric supply. The
Company's Integrated Electric Resource Plan (IERP), recommends a combination of
a peak load reduction demand-side management program and a capacity purchase as
the most economical method of meeting this need. The
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IERP projects that new electric generating capacity will need to be installed on
Long Island to meet peak demand in the summer of 2001. It is anticipated that
such new capacity would be acquired through a competitive bidding process.
MERGER AGREEMENT WITH THE BROOKLYN UNION GAS COMPANY
On December 29, 1996, the Company and The Brooklyn Union Gas Company (Brooklyn
Union) entered into an Agreement and Plan of Exchange (Share Exchange
Agreement), pursuant to which the companies will be merged in a transaction that
will result in the formation of a new holding company. The new holding company,
which has not yet been named, will serve approximately 2.2 million customers and
have annual revenues of more than $4.5 billion. The merger is expected to be
accomplished through a tax-free exchange of shares.
The description of the Share Exchange Agreement set forth herein does not
purport to be complete and is qualified in its entirety by the provisions of the
Share Exchange Agreement, filed as an exhibit to the Company's Current Report on
Form 8-K dated December 30, 1996.
The proposed transaction, which has been approved by both companies' boards of
directors, would unite the resources of the Company with the resources of
Brooklyn Union. Brooklyn Union, 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
approximately two-thirds of the borough of Queens, all in New York City.
Brooklyn Union has energy-related investments in gas exploration, production and
marketing in the United States and Canada, as well as energy services in the
United States, including cogeneration products, pipeline transportation and gas
storage.
Under the terms of the proposed transaction, the Company's common shareowners
will receive .803 shares (the Ratio) of the new holding company's common stock
for each share of the Company's common stock that they currently hold. Brooklyn
Union common shareowners will receive one share of common stock of the new
holding company for each common share of Brooklyn Union they currently hold.
Shareowners of the Company will own approximately 66% of the common stock of the
new holding company while Brooklyn Union shareowners will own approximately 34%.
The proposed transaction will have no effect on either company's debt issues or
outstanding preferred stock.
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.
Accordingly, the Company's ability to engage in certain activity described
herein may be limited or prohibited by the Share Exchange Agreement.
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Upon completion of the merger, Dr. William J. Catacosinos will become chairman
and chief executive officer of the new holding company; Mr. Robert B. Catell,
currently chairman and chief executive officer of Brooklyn Union, will become
president and chief operating officer of the new holding company. 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 the new
company will be composed of 15 members, six from the Company, six from Brooklyn
Union and three additional persons previously unaffiliated with either company
and jointly selected by them.
The companies will continue their respective current dividend policies until the
closing, consistent with the provisions of the Share Exchange Agreement. It is
expected that the new holding company's dividend policy will be determined prior
to closing.
The merger is conditioned upon, among other things, the approval of the merger
by the holders of two-thirds of the outstanding shares of common stock of each
of the Company and Brooklyn Union and the receipt of all required regulatory
approvals. The Company is unable to determine when or if all required approvals
will be obtained.
In 1995, the Long Island Power Authority (LIPA), an agency of the State of New
York (NYS), was requested by the Governor of NYS to develop a plan, pursuant to
its authority under NYS law, to provide 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.
The Share Exchange Agreement contemplates that discussions, which are currently
in progress, will continue with LIPA to arrive at an agreement mutually
acceptable to the Company, Brooklyn Union and LIPA, pursuant to which LIPA would
acquire certain assets or securities of the Company, the consideration for which
would inure to the benefit of the new holding company. In the event that such a
transaction is completed, the Ratio would become .880. In connection with
discussions with LIPA, LIPA has indicated that it may exercise its power of
eminent domain over all or a portion of the Company's assets or securities, in
order to achieve its objective of reducing current electric rates, if a
negotiated agreement cannot be reached. The Company is unable to determine when
or if an agreement with LIPA will be reached, or what action, if any, LIPA will
take if such an agreement is not reached.
RATE MATTERS
ELECTRIC
In 1995, the Company submitted a compliance filing requesting that the PSC
extend the provisions of its 1995 electric rate order, discussed below, through
November 30, 1996. This filing was updated by the Company in August 1996 and
approved by the PSC in January 1997.
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During 1996, the PSC instituted numerous initiatives intended to lower electric
rates on Long Island. The Company shares the PSC's concern regarding electric
rate levels and is prepared to assist the PSC in pursuing any reasonable
opportunity to reduce electric rates. The initiatives instituted were as
follows:
An Order to Show Cause, issued in February 1996, to examine various
opportunities to reduce the Company's electric rates;
An Order, issued in April 1996, expanding the scope of the Order to Show
Cause proceeding in an effort to provide "immediate and substantial rate
relief." This order directed the Company to file financial and other
information sufficient to provide a legal basis for setting new rates for
both the single rate year (1997) and the three-year period 1997 through 1999;
and
An Order, issued in July 1996, to institute an expedited temporary rate phase
in the Order to Show Cause proceeding to be conducted in parallel with the
ongoing phase concerning permanent rates.
The Order issued in July requested that interested parties file testimony and
exhibits sufficient to provide a basis for the PSC to decide whether the
Company's electric rates should be made temporary and, if so, the proper level
of such temporary rates. The Staff of the PSC (Staff), in response to this
Order, recommended that the Company's rates be reduced on a temporary basis by
4.2% effective October 1, 1996, until the permanent rate case is decided. In its
filing, the Company sought to demonstrate that current electric rate levels were
appropriate and that there was no justification for reducing them. Although
evidentiary hearings on the Company's, Staff's and other interested parties'
submissions were subsequently held on an expedited basis to enable the PSC to
render a decision on the Company's rates, as of the date of this report, the PSC
has yet to take any action.
In September 1996, the Company completed the filing of a multi-year rate plan
(Plan) in compliance with the April 1996 Order. 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 Fuel Cost Adjustment (FCA), over a two-year
period.
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 Rate Moderation Agreement's (RMA) objective
of restoring the Company to financial health. The 1995 Order, which became
effective December 1, 1994, froze base
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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. 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 is subject to a
maximum penalty of 38 basis points of the allowed return on common equity and
can earn up to 4 basis points under the customer service program. This 4 basis
point incentive can only be used to offset a penalty under the transmission and
distribution reliability program. Under the original LRPP, the Company was
allowed to earn up to 40 basis points or forfeit up to 18 basis points under
these incentive programs.
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, 1996, the Company earned 20 basis points,
or approximately $4.3 million, net of tax effects, as a result of its
performance under all incentive programs. For the rate years ended November 30,
1995 and 1994, the Company earned 19 and 50 basis points, respectively, or
approximately $4.0 million and $9.2 million, respectively, net of tax effects,
under the incentive programs in effect at those times.
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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, 1996, the amount to be returned to
customers resulting from the revenue and expense reconciliations,
performance-based incentive programs and associated carrying charges totaled
$14.5 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 January 1997. For the rate year ended November 30, 1995, the
Company recorded a net deferred LRPP 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. For the rate year ended
November 30, 1994, the Company recorded a net deferred charge of approximately
$79 million. The first $15 million of the deferral was applied as an increase to
the RMC while the remaining deferral of $64 million was recovered from
customers.
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, 1996 and 1995, the Company earned $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 1994, the Company did not
earn in excess of its allowed return on common equity.
The Company is currently unable to predict the outcome of any of the rate
proceedings currently before the PSC and their effect, if any, on the Company's
financial position, cash flows or results of operations.
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 provided annual gas
rate increases of 4.7%, 3.8% and 3.2% for each of the three rate years beginning
December 1, 1993, 1994, and 1995, 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 settlement also 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, 1995 and 1994, the
firm gas customers' portion of gas earnings in excess of the allowed return on
common equity totaled approximately $10 million, $1 million and $7 million,
respectively. In 1996, the Company was granted
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permission by the PSC to apply the customers' portion of the gas excess earnings
and associated carrying charges for the 1995 and 1994 rate years to the recovery
of deferred costs associated with postretirement benefits other than pensions
and costs incurred for investigation and remediation of manufactured gas plant
(MGP) sites. The Company has requested that the same treatment be granted for
the disposition of the customers' portion of the 1996 rate year gas excess
earnings.
The Company currently has no gas rate filings before the PSC and does not intend
to file a gas rate case during the current rate year, unless required to do so
in connection with the proposed merger with Brooklyn Union.
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 1996, both the PSC and the Federal Energy Regulatory
Commission (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
calls for a competitive wholesale power market to be in place by early 1997
which will 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 file a
rate/restructuring plan which is consistent with the PSC's policy and
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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. Since October 1, 1996,
proceedings have commenced for the five electric utilities which filed
restructuring plans in accordance with track one and the Company has intervened
in each of these proceedings.
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 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. While these discussions are
continuing in an attempt to narrow the differences among the parties, on
December 31, 1996, the NYPP 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.
The PSC envisions 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
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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, 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. Oral argument
in the Appellate Division has not yet been scheduled, but a decision is expected
by the end of 1997.
THE ELECTRIC INDUSTRY - FEDERAL REGULATORY ISSUES
In April 1996, in response to its Notice of Proposed Rulemaking issued in March
1995, the FERC issued two orders 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 themselves
and to third parties on a non-discriminatory basis. Additionally, utilities must
use these same tariffs for their own wholesale sales. The Company filed its open
access tariff in July 1996.
In September 1996, the FERC ordered Rate Hearings on 28 utility
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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. The
procedural schedule was suspended pending filing of the settlement agreement,
which is anticipated during the first quarter of 1997. Non-rate issues
associated with the Company's open access tariff have not yet been addressed by
the FERC.
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.
With other members of the industry, the Company has participated in several
joint petitions for rehearing and/or clarification of the FERC's Orders 888 and
889. Among other issues, these petitions address the FERC's obligation to
exercise its jurisdiction to provide for the recovery of strandable investments
in any retail wheeling situations. The outcome and timing of the FERC Orders on
rehearing are uncertain.
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
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," could then
require a significant write-down of all or a portion of the Company's net
regulatory assets. If the Company were unable to continue to apply the
provisions of SFAS No. 71 at December 31, 1996, the Company estimates that
approximately $4.6 billion would have been written off at such time.
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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. These competitors are
non-utility generators (NUGS), NYPA and Municipal Distribution Agencies (MDAs).
The Public Utility Regulatory Policies Act of 1978 (PURPA), the goal of which is
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. 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
PURPA to purchase the output of certain of these generators, which are known as
qualified facilities (QFs).
In 1996, the Company lost sales to NUGs totaling 422 gigawatt-hours (GWh)
representing a loss in electric revenues net of fuel (net revenues) of
approximately $34 million, or 1.9% of the Company's net revenues. In 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 1997, sales losses to NUGs will be 429
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 in 1996 approximated 218 megawatts (MW) and in early
1995 approximated 205 MW. The increase was the result of the SUNY Stony Brook
facility going on line in mid 1995. The Company estimates that purchases from
QFs required by federal and state law cost the Company $63 million and $53
million in 1996 and 1995, respectively, more than it would have cost had the
Company generated this power.
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
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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 NYPA power for economic development. The
Company estimates that in 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. Currently, the potential loss of additional load is limited by
conditions in the Company's transmission agreements with NYPA.
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.
In December 1996, the FERC ordered the Company to provide transmission services
to Suffolk County to the extent necessary to accommodate proposed
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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 their decision once
that decision becomes final, which is not expected for several months. 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. Research is
underway to determine the existence
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and nature of operations and their relationship, if any, to the Company or
its predecessor companies.
The Company has entered into discussions with the DEC which may lead to the
issuance of one or more Administrative Consent Orders (ACO) regarding the
management of environmental activities at these properties. Although the exact
amount of the Company's remediation costs cannot yet be determined, based on the
findings of investigations at two of these six sites, estimates indicate that it
will cost approximately $51 million to remediate all of these sites through the
year 2005. Accordingly, the Company has 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 $35 million liability reflects the present value of
the future stream of payments to investigate and remediate these sites. The
Company used a risk-free rate of 7.25% to discount this obligation.
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. 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 MGP
sites and Superfund sites for which the Company has been named a potentially
responsible party (PRP). The Company is seeking a declaratory judgement 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 remediation 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,
have entered into an ACO with the EPA to conduct a Remedial Investigation and
Feasibility Study (RI/FS), which has been completed and is currently being
reviewed by the EPA. Under a PRP participation agreement, the Company is
responsible for 8.2% of the costs associated with this RI/FS. The level of
remediation required will be determined when the EPA issues its decision, but
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 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.
24
<PAGE>
In 1994, the EPA requested certain of the large PRPs, which include several
other utilities, to form a group, sign an ACO, and conduct a remediation program
for the sites under the Toxic Substances Control Act, or in the alternative, to
perform a Superfund cleanup for the sites. The EPA has provided the Company with
documents indicating 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. The Company intends to join a PRP
Group which includes other utilities, which has been organized for the purpose
of developing and implementing acceptable remediation programs for the sites.
The Company is currently unable to determine its share of the cost to remediate
these sites.
In addition, the Company was notified that it is a PRP at a Superfund site
located 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 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 unable to determine its share of costs of remediation at this site.
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.
Previously, 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 addition, during 1996 the Long Island Soundkeeper Fund, a non-profit
organization, filed a suit against the Owners of the Sound Cable in Federal
District Court in Connecticut alleging that the Sound Cable fluid leaks
constitute unpermitted discharges of pollutants in violation of the Clean Water
Act (CWA) and that such pollutants present a threat to the environment and
public health. The suit seeks, among other things, injunctive relief prohibiting
the Owners from continuing to operate the Sound Cable in alleged violation of
the CWA and civil penalties of $25,000 per day for each violation from each of
the Owners.
25
<PAGE>
In December 1996, a barge, owned and operated by a third party, dropped anchor,
causing extensive damage to the Sound Cable and a release of dielectric fluid
into the Long Island Sound. Temporary clamps and leak abaters have been placed
on the cables which have stopped the leaks. Permanent repairs are expected to be
undertaken in the late spring of 1997. The preliminary estimate of the cost of
these repairs is $15 million. The Company intends to seek recovery from third
parties for all costs incurred by the Company as a result of this incident. The
timing and amount of recovery, if any, cannot yet be determined. In addition,
the Owners maintain insurance coverage for the Sound Cable which the Company
believes will be sufficient to cover any repair costs. In any event, costs not
reimbursed by a third party or not 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.
CONSERVATION SERVICES
The Company's 1996 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, improved the efficiency of the Company's facilities, induced market
transformation and provided financing for energy efficiency. The Company was
successful in meeting the PSC energy penalty threshold of 26.7 GWh (80% of 33.3
GWh goal) at a cost less than that provided for in electric rates.
In 1997, the Company plans to continue this strategy with an increased emphasis
on programs which facilitate the retention, attraction and expansion of major
commercial/industrial customers. Specifically these programs will provide
incentives to encourage companies to invest in energy-efficiency as a means to
remain, expand or relocate to Long Island. Overall, they will help to improve
the economic climate on Long Island as well as the Company's competitiveness as
an energy provider. The 1997 Plan targets an annualized energy savings of 28.7
GWh. The Company believes that it will meet the target and avoid any earnings
penalty.
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
26
<PAGE>
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
merger with Brooklyn Union and a possible transaction with LIPA as discussed
under the heading "Merger Agreement with The Brooklyn Union Gas Company", state
and federal regulatory rate proceedings, competition, and certain environmental
matters each as discussed herein.
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 Item 6: Selected Financial Data.
Information with regard to the Company's business segments for the last three
years is provided in Note 12 of Notes to Financial Statements.
27
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
BALANCE SHEET
- ---------------------------------------------------------------------------------
ASSETS (In thousands of dollars)
- ---------------------------------------------------------------------------------
at December 31 1996 1995
- ---------------------------------------------------------------------------------
<S> <C> <C>
UTILITY PLANT
Electric $ 3,882,297 $ 3,786,540
Gas 1,154,543 1,086,145
Common 260,268 244,828
Construction work in progress 112,184 100,521
Nuclear fuel in process and in reactor 15,454 16,456
- ---------------------------------------------------------------------------------
5,424,746 5,234,490
Less - Accumulated depreciation
and amortization 1,729,576 1,639,492
- ---------------------------------------------------------------------------------
Total Net Utility Plant 3,695,170 3,594,998
- ---------------------------------------------------------------------------------
REGULATORY ASSETS
Base financial component
(less accumulated amortization
of $757,282 and $656,311) 3,281,548 3,382,519
Rate moderation component 402,213 383,086
Shoreham post-settlement costs 991,795 968,999
Shoreham nuclear fuel 69,113 71,244
Unamortized cost of issuing securities 194,151 222,567
Postretirement benefits other than pensions 360,842 383,642
Regulatory tax asset 1,772,778 1,802,383
Other 199,879 229,809
- ---------------------------------------------------------------------------------
Total Regulatory Assets 7,272,319 7,444,249
- ---------------------------------------------------------------------------------
NONUTILITY PROPERTY AND OTHER INVESTMENTS 18,597 16,030
- ---------------------------------------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents 279,993 351,453
Special deposits 38,266 63,412
Customer accounts receivable
(less allowance for doubtful
accounts of $25,000 and $24,676) 255,801 282,218
LRPP receivable - 74,281
Other accounts receivable 65,764 107,387
Accrued unbilled revenues 169,712 184,440
Materials and supplies at average cost 55,789 63,595
Fuel oil at average cost 53,941 32,090
Gas in storage at average cost 73,562 53,076
Deferred tax asset 145,205 191,000
Prepayments and other current assets 8,569 8,986
- ---------------------------------------------------------------------------------
Total Current Assets 1,146,602 1,411,938
- ---------------------------------------------------------------------------------
DEFERRED CHARGES 76,991 60,382
- ---------------------------------------------------------------------------------
TOTAL ASSETS $ 12,209,679 $ 12,527,597
================================================================================
</TABLE>
SEE NOTES TO FINANCIAL STATEMENTS.
28
<PAGE>
<TABLE>
<CAPTION>
CAPITALIZATION AND LIABILITIES (In thousands of dollars)
- ---------------------------------------------------------------------------------
at December 31 1996 1995
- ---------------------------------------------------------------------------------
<S> <C> <C>
CAPITALIZATION
Long-term debt $ 4,471,675 $ 4,722,675
Unamortized discount on debt (14,903) (16,075)
- ---------------------------------------------------------------------------------
4,456,772 4,706,600
- ---------------------------------------------------------------------------------
Preferred stock - redemption required 638,500 639,550
Preferred stock - no redemption required 63,664 63,934
- ---------------------------------------------------------------------------------
Total Preferred Stock 702,164 703,484
- ---------------------------------------------------------------------------------
Common stock 603,921 598,277
Premium on capital stock 1,127,971 1,114,508
Capital stock expense (49,330) (50,751)
Retained earnings 840,867 790,919
Treasury stock, at cost (60) -
- ---------------------------------------------------------------------------------
Total Common Shareowners' Equity 2,523,369 2,452,953
- ---------------------------------------------------------------------------------
Total Capitalization 7,682,305 7,863,037
- ---------------------------------------------------------------------------------
REGULATORY LIABILITIES
Regulatory liability component 198,398 277,757
1989 Settlement credits 127,442 136,655
Regulatory tax liability 102,887 116,060
Other 146,852 132,891
- ---------------------------------------------------------------------------------
Total Regulatory Liabilities 575,579 663,363
- ---------------------------------------------------------------------------------
CURRENT LIABILITIES
Current maturities of long-term debt 251,000 415,000
Current redemption requirements of preferred stock 1,050 4,800
Accounts payable and accrued expenses 289,141 260,879
LRPP payable 40,499 17,240
Accrued taxes (including federal income
tax of $25,884 and $28,736) 63,640 60,498
Accrued interest 160,615 158,325
Dividends payable 58,378 57,899
Class Settlement 55,833 45,833
Customer deposits 29,471 29,547
- ---------------------------------------------------------------------------------
Total Current Liabilities 949,627 1,050,021
- ---------------------------------------------------------------------------------
DEFERRED CREDITS
Deferred federal income tax 2,442,606 2,337,732
Class Settlement 98,497 129,809
Other 32,105 34,499
- ---------------------------------------------------------------------------------
Total Deferred Credits 2,573,208 2,502,040
- ---------------------------------------------------------------------------------
OPERATING RESERVES
Pensions and other postretirement benefits 381,996 396,490
Claims and damages 46,964 52,646
- ---------------------------------------------------------------------------------
Total Operating Reserves 428,960 449,136
- ---------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES - -
- ---------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES $ 12,209,679 $ 12,527,597
=================================================================================
</TABLE>
SEE NOTES TO FINANCIAL STATEMENTS.
29
<PAGE>
<TABLE>
<CAPTION>
STATEMENT OF INCOME (In thousands of dollars except per share amounts)
- ----------------------------------------------------------------------------------------------------
For year ended December 31 1996 1995 1994
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
REVENUES
Electric $ 2,466,435 $ 2,484,014 $ 2,481,637
Gas 684,260 591,114 585,670
- ----------------------------------------------------------------------------------------------------
Total Revenues 3,150,695 3,075,128 3,067,307
- ----------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operations - fuel and purchased power 963,251 834,979 847,986
Operations - other 381,076 383,238 406,014
Maintenance 118,135 128,155 134,640
Depreciation and amortization 153,925 145,357 130,664
Base financial component amortization 100,971 100,971 100,971
Rate moderation component amortization (24,232) 21,933 197,656
Regulatory liability component amortization (79,359) (79,359) (79,359)
1989 Settlement credits amortization (9,214) (9,214) (9,214)
Other regulatory amortization 127,288 161,605 4,328
Operating taxes 472,076 447,507 406,895
Federal income tax - current 42,197 14,596 10,784
Federal income tax - deferred and other 168,000 193,742 170,997
- ----------------------------------------------------------------------------------------------------
Total Operating Expenses 2,414,114 2,343,510 2,322,362
- ----------------------------------------------------------------------------------------------------
Operating Income 736,581 731,618 744,945
- ----------------------------------------------------------------------------------------------------
OTHER INCOME AND (DEDUCTIONS)
Rate moderation component carrying charges 25,259 25,274 32,321
Other income and deductions, net 19,197 34,400 35,343
Class Settlement (20,772) (21,669) (22,730)
Allowance for other funds used during construction 2,888 2,898 2,716
Federal income tax - deferred and other 940 2,800 5,069
- ----------------------------------------------------------------------------------------------------
Total Other Income and (Deductions) 27,512 43,703 52,719
- ----------------------------------------------------------------------------------------------------
Income Before Interest Charges 764,093 775,321 797,664
- ----------------------------------------------------------------------------------------------------
INTEREST CHARGES
Interest on long-term debt 384,198 412,512 437,751
Other interest 67,130 63,461 62,345
Allowance for borrowed funds used during construction (3,699) (3,938) (4,284)
- ----------------------------------------------------------------------------------------------------
Total Interest Charges 447,629 472,035 495,812
- ----------------------------------------------------------------------------------------------------
NET INCOME 316,464 303,286 301,852
Preferred stock dividend requirements 52,216 52,620 53,020
- ----------------------------------------------------------------------------------------------------
EARNINGS FOR COMMON STOCK $ 264,248 $ 250,666 $ 248,832
====================================================================================================
AVERAGE COMMON SHARES OUTSTANDING (000) 120,361 119,195 115,880
- ----------------------------------------------------------------------------------------------------
EARNINGS PER COMMON SHARE $ 2.20 $ 2.10 $ 2.15
====================================================================================================
DIVIDENDS DECLARED PER COMMON SHARE $ 1.78 $ 1.78 $ 1.78
- ----------------------------------------------------------------------------------------------------
</TABLE>
SEE NOTES TO FINANCIAL STATEMENTS.
30
<PAGE>
<TABLE>
<CAPTION>
STATEMENT OF CASH FLOWS (In thousands of dollars)
- -------------------------------------------------------------------------------------------------
For year ended December 31 1996 1995 1994
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net Income $ 316,464 $ 303,286 $ 301,852
cash provided by operating activities
Depreciation and amortization 153,925 145,357 130,664
Base financial component amortization 100,971 100,971 100,971
Rate moderation component amortization (24,232) 21,933 197,656
Regulatory liability component amortization (79,359) (79,359) (79,359)
1989 Settlement credits amortization (9,214) (9,214) (9,214)
Other regulatory amortization 127,288 161,605 4,328
Rate moderation component carrying charges (25,259) (25,274) (32,321)
Amortization of cost of issuing and redeeming securities 34,611 39,589 46,237
Class Settlement 20,772 21,669 22,730
Provision for doubtful accounts 23,119 17,751 19,542
Federal income tax - deferred and other 167,060 190,942 165,928
Other 66,624 61,576 46,531
Changes in operating assets and liabilities
Accounts receivable 69,215 (67,213) (17,353)
Class Settlement (42,084) (33,464) (30,235)
Accrued unbilled revenues 14,728 (20,061) 5,663
Accounts payable and accrued expenses 28,258 19,100 (44,598)
Other (50,574) (77,194) 6,727
- -------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 892,313 772,000 835,749
- -------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Construction and nuclear fuel expenditures (239,896) (243,586) (276,954)
Shoreham post-settlement costs (51,722) (70,589) (167,367)
Other investing activities (4,806) 8,019 (1,349)
- -------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (296,424) (306,156) (445,670)
- -------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Proceeds from issuance of securities 18,837 68,726 449,434
Redemption of securities (419,800) (104,800) (639,858)
Common stock dividends paid (213,753) (211,630) (205,086)
Preferred stock dividends paid (52,264) (52,667) (52,927)
Other financing activities (369) 529 (4,723)
- -------------------------------------------------------------------------------------------------
Net Cash Used in Financing Activities (667,349) (299,842) (453,160)
- -------------------------------------------------------------------------------------------------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS $ (71,460) $ 166,002 $ (63,081)
=================================================================================================
Cash and cash equivalents at January 1 $ 351,453 $ 185,451 $ 248,532
Net (decrease) increase in cash and cash equivalents (71,460) 166,002 (63,081)
- -------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT DECEMBER 31 $ 279,993 $ 351,453 $ 185,451
=================================================================================================
Interest paid, before reduction for the allowance
for borrowed funds used during constuction $ 404,663 $ 427,988 $ 446,340
Federal income tax - paid $ 45,050 $ 14,200 $ 10,780
- -------------------------------------------------------------------------------------------------
</TABLE>
SEE NOTES TO FINANCIAL STATEMENTS.
31
<PAGE>
<TABLE>
<CAPTION>
STATEMENT OF RETAINED EARNINGS (In thousands of dollars)
- ---------------------------------------------------------------------------------------
1996 1995 1994
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Balance at January 1 $ 790,919 $ 752,480 $ 711,432
Net income for the year 316,464 303,286 301,852
- ---------------------------------------------------------------------------------------
1,107,383 1,055,766 1,013,284
Deductions
Cash dividends declared on common stock 214,255 212,181 207,794
Cash dividends declared on preferred stock 52,240 52,647 53,046
Other 21 19 (36)
- ---------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31 $ 840,867 $ 790,919 $ 752,480
=======================================================================================
</TABLE>
SEE NOTES TO FINANCIAL STATEMENTS.
<TABLE>
<CAPTION>
STATEMENT OF CAPITALIZATION Shares Issued (In thousands of dollars)
- -------------------------------------------------------------------------------------------------------------------------------
At December 31 1996 1995 1996 1995
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
COMMON SHAREOWNERS' EQUITY
Common stock, $5.00 par value 120,784,277 119,655,441 $ 603,921 $ 598,277
Premium on capital stock 1,127,971 1,114,508
Capital stock expense (49,330) (50,751)
Retained earnings 840,867 790,919
Treasury stock, at cost 3,485 - (60) -
- ------------------------------------------------------------------------------------------------------------------------------
TOTAL COMMON SHAREOWNERS' EQUITY 2,523,369 2,452,953
- ------------------------------------------------------------------------------------------------------------------------------
PREFERRED STOCK - REDEMPTION REQUIRED
Par value $100 per share
7.40% Series L 161,000 171,500 16,100 17,150
8.50% Series R - 37,500 - 3,750
7.66% Series CC 570,000 570,000 57,000 57,000
Less - Sinking fund requirement 1,050 4,800
- ------------------------------------------------------------------------------------------------------------------------------
72,050 73,100
- ------------------------------------------------------------------------------------------------------------------------------
Par value $25 per share
7.95% Series AA 14,520,000 14,520,000 363,000 363,000
$1.67 Series GG 880,000 880,000 22,000 22,000
$1.95 Series NN 1,554,000 1,554,000 38,850 38,850
7.05% Series QQ 3,464,000 3,464,000 86,600 86,600
6.875% Series UU 2,240,000 2,240,000 56,000 56,000
- ------------------------------------------------------------------------------------------------------------------------------
566,450 566,450
- ------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - Redemption Required 638,500 639,550
- ------------------------------------------------------------------------------------------------------------------------------
PREFERRED STOCK - NO REDEMPTION REQUIRED
Par value $100 per share
5.00% Series B 100,000 100,000 10,000 10,000
4.25% Series D 70,000 70,000 7,000 7,000
4.35% Series E 200,000 200,000 20,000 20,000
4.35% Series F 50,000 50,000 5,000 5,000
5 1/8% Series H 200,000 200,000 20,000 20,000
5 3/4% Series I - Convertible 16,637 19,336 1,664 1,934
- ------------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - No Redemption Required 63,664 63,934
- ------------------------------------------------------------------------------------------------------------------------------
TOTAL PREFERRED STOCK $ 702,164 $ 703,484
- ------------------------------------------------------------------------------------------------------------------------------
</TABLE>
32
<PAGE>
<TABLE>
<CAPTION>
(In thousands of dollars)
- ------------------------------------------------------------------------------------------------------------------------------
At December 31 Maturity Interest Rate Series 1996 1995
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
GENERAL AND REFUNDING BONDS
May 1, 1996 8 3/4% - 415,000
February 15, 1997 8 3/4% 250,000 250,000
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 1,536,000 1,951,000
- ------------------------------------------------------------------------------------------------------------------------------
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 28,375 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 3.25% 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 4.05% 1993 A 50,000 50,000
November 1, 2023 4.00% 1993 B 50,000 50,000
October 1, 2024 4.00% 1994 A 50,000 50,000
August 1, 2025 4.00% 1995 A 50,000 50,000
- ------------------------------------------------------------------------------------------------------------------------------
Total Authority Financing Notes 916,675 916,675
- ------------------------------------------------------------------------------------------------------------------------------
Unamortized Discount on Debt (14,903) (16,075)
- ------------------------------------------------------------------------------------------------------------------------------
Total 4,707,772 5,121,600
Less Current Maturities 251,000 415,000
- ------------------------------------------------------------------------------------------------------------------------------
TOTAL LONG-TERM DEBT 4,456,772 4,706,600
- ------------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION $ 7,682,305 $ 7,863,037
==============================================================================================================================
</TABLE>
SEE NOTES TO FINANCIAL STATEMENTS.
33
<PAGE>
Note 1. Summary of Significant Accounting Policies
NATURE OF OPERATIONS
Long Island Lighting Company (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 1996 estimate, is about 2.7 million
persons, including approximately 98,000 persons who reside in Queens County
within the City of New York.
The Company serves approximately 1.03 million electric customers of which
approximately 921,000 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 460,000 gas customers, 412,000 of which
are residential, accounting for 61% of the gas revenues, with the balance of the
gas revenues made up by the commercial/industrial customers and 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 11.
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 these
commissions in conformity with generally accepted accounting principles for
rate-regulated enterprises.
34
<PAGE>
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.
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 and $6.8 billion at December 31, 1996 and 1995,
respectively.
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. As
discussed more fully in Note 11, the PSC has made a decision in the Competitive
Opportunities Proceedings to transition the electric industry to a wholesale
power market in early 1997 followed by the introduction of retail access for all
customers by early 1998. 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. For additional
information respecting the Company's Shoreham-related assets, see below and
Notes 2, 3 and 11.
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In 1996, the Company adopted SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of" which amends SFAS
No. 71. Under SFAS No. 121, 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 the restoration of previously
disallowed costs that are subsequently allowed by a regulator. With respect to
assets recognized under SFAS No. 71 and all other long-lived assets, the
adoption of SFAS No. 121 did not have an effect on the Company's financial
position, cash flows or results of operations. However, if the Company had been
unable to continue to apply the provisions of SFAS No. 71 at December 31, 1996,
the Company estimates that approximately $4.6 billion would have been written
off at such time.
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 Nine Mile Point Nuclear
Power Station, Unit 2 (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. For a further discussion of the
1989 Settlement and FRA, see Notes 2 and 3.
SHOREHAM POST-SETTLEMENT COSTS
Consists 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
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period on a straight-line remaining life basis which began July 1, 1989. For a
further discussion of Shoreham post-settlement costs, see Note 2.
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.
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 over the shorter of the life of the
redeemed issue or the new issue as provided by the PSC.
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 must be phased into and fully reflected in rates by
November 30, 1997, with the accumulated deferred asset being recovered in rates
over the next fifteen-year period. 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 ratepayers and
shareowners. A regulatory liability of approximately $794 million was recorded
in June 1989 to preserve an amount equivalent to the customer tax
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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.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The Uniform Systems of Accounts 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
annual AFC rate, without giving effect to compounding, was 9.02%, 9.36% and
9.18% for the years 1996, 1995 and 1994, respectively.
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. Depreciation for electric properties was equivalent to approximately
3.0% of respective average depreciable plant costs for each of the years 1996,
1995 and 1994. Depreciation for gas properties was equivalent to approximately
2.0% of respective average depreciable plant costs for each of the years 1996,
1995 and 1994.
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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 RECEIVABLE/PAYABLE
Represents the current portion of amounts recoverable from or 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 3.
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 which is based upon the Company's current
incremental borrowing rate for similar types of securities.
REVENUES
Revenues are based on cycle billings rendered to certain customers monthly and
others bi-monthly. The Company also accrues electric and gas revenues for
services rendered to customers but not billed at month-end.
The Company's electric rate structure, as discussed in Note 3, 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.
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.
FEDERAL INCOME TAX
The Company provides deferred federal income tax with respect to certain items
of income and expense that are reported in different years for federal income
tax purposes and financial statement purposes and with
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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.
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. 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 the Long Island Power Authority (LIPA), an agency of the State of
New York, for its subsequent decommissioning.
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. The FRA has two components,
the BFC and the RMC. For a further discussion of the FRA, see
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Note 1.
In February 1992, the Company transferred ownership of Shoreham to LIPA.
Pursuant to the 1989 Settlement, the Company was required to reimburse LIPA for
all of its costs associated with the decommissioning of Shoreham. Effective May
1, 1995, the Nuclear Regulatory Commission (NRC) terminated LIPA's
possession-only license for Shoreham. The termination signified the NRC's
approval that decommissioning was complete and that the site is suitable for
unrestricted use. At December 31, 1996, Shoreham post- settlement costs totaled
approximately $1.103 billion, consisting of $536 million of property taxes and
payments-in-lieu-of-taxes, and $567 million of decommissioning costs, fuel
disposal costs and all other costs incurred at Shoreham after June 30, 1989.
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.
NOTE 3. RATE MATTERS
ELECTRIC
In 1995, the Company submitted a compliance filing requesting that the PSC
extend the provisions of its 1995 electric rate order, discussed below, through
November 30, 1996. This filing was updated by the Company in August 1996 and
approved by the PSC in January 1997.
During 1996, the PSC instituted numerous initiatives intended to lower electric
rates on Long Island. The Company shares the PSC's concern regarding electric
rate levels and is prepared to assist the PSC in pursuing any reasonable
opportunity to reduce electric rates. The initiatives instituted were as
follows:
An Order to Show Cause, issued in February 1996, to examine various
opportunities to reduce the Company's electric rates;
An Order, issued in April 1996, expanding the scope of the Order to Show
Cause proceeding in an effort to provide "immediate and substantial rate
relief." This order directed the Company to file financial and other
information sufficient to provide a legal basis for setting new rates for
both the single rate year (1997) and the three-year period 1997 through
1999; and
An Order, issued in July 1996, to institute an expedited temporary rate
phase in the Order to Show Cause proceeding to be conducted in parallel
with the ongoing phase concerning permanent rates.
The Order issued in July requested that interested parties file testimony and
exhibits sufficient to provide a basis for the PSC to decide whether
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the Company's electric rates should be made temporary and, if so, the proper
level of such temporary rates. The Staff of the PSC (Staff), in response to this
Order, recommended that the Company's rates be reduced on a temporary basis by
4.2% effective October 1, 1996, until the permanent rate case is decided. In its
filing, the Company sought to demonstrate that current electric rate levels were
appropriate and that there was no justification for reducing them. Although
evidentiary hearings on the Company's, Staff's and other interested parties'
submissions were subsequently held on an expedited basis to enable the PSC to
render a decision on the Company's rates, as of the date of this report, the PSC
has yet to take any action.
In September 1996, the Company completed the filing of a multi-year rate plan
(Plan) in compliance with the April 1996 Order. 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 Fuel Cost Adjustment (FCA), over a two-year
period.
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. 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
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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 is subject to a
maximum penalty of 38 basis points of the allowed return on common equity and
can earn up to 4 basis points under the customer service program. This 4 basis
point incentive can only be used to offset a penalty under the transmission and
distribution reliability program. Under the original LRPP, the Company was
allowed to earn up to 40 basis points or forfeit up to 18 basis points under
these incentive programs.
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, 1996, the Company earned 20 basis points,
or approximately $4.3 million, net of tax effects, as a result of its
performance under all incentive programs. For the rate years ended November 30,
1995 and 1994, the Company earned 19 and 50 basis points, respectively, or
approximately $4.0 million and $9.2 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, 1996, the amount to be returned to
customers resulting from the revenue and expense reconciliations,
performance-based incentive programs and associated carrying charges totaled
$14.5 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 January 1997. For the rate year ended November 30, 1995, the
Company recorded a net deferred LRPP 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. For the rate year ended
November 30, 1994, the Company recorded a net deferred charge of approximately
$79 million. The first $15 million of the deferral was applied as an increase to
the RMC
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while the remaining deferral of $64 million was recovered from customers.
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, 1996 and 1995, the Company earned $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 1994, the Company did not
earn in excess of its allowed return on common equity.
The Company is currently unable to predict the outcome of any of the rate
proceedings currently before the PSC and their effect, if any, on the Company's
financial position, cash flows or results of operations.
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 provided annual gas
rate increases of 4.7%, 3.8% and 3.2% for each of the three rate years beginning
December 1, 1993, 1994 and 1995, 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 settlement also 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, 1995 and 1994, the
firm gas customers' portion of gas earnings in excess of the allowed return on
common equity totaled approximately $10 million, $1 million and $7 million,
respectively. In 1996, the Company was granted permission by the PSC to apply
the customers' portion of the gas excess earnings and associated carrying
charges for the 1995 and 1994 rate years to the recovery of deferred costs
associated with postretirement benefits other than pensions and costs incurred
for investigation and remediation of manufactured gas plant (MGP) sites. The
Company has requested that the same treatment be granted for the disposition of
the customers' portion of the 1996 rate year gas excess earnings.
The Company currently has no gas rate filings before the PSC and does not intend
to file a gas rate case during the current rate year, unless required to do so
in connection with the proposed merger with Brooklyn Union.
NOTE 4. THE CLASS SETTLEMENT
The Class Settlement, which became effective on June 28, 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
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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 December 31, 1996 reflects the present value of the remaining
reductions to be refunded to customers. The remaining reductions to customers
bills, amounting to approximately $201 million as of December 31, 1996, consists
of approximately $21 million for the five-month period beginning January 1,
1997, and $60 million for each of the 12- month periods beginning June 1, 1997,
1998 and 1999.
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). Ownership of NMP2
is shared by five cotenants: 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 206 MW. The Company's net utility plant
investment, excluding nuclear fuel, was approximately $715 million and $740
million at December 31, 1996 and 1995, respectively. The accumulated provision
for depreciation, excluding decommissioning costs, was approximately $169
million and $153 million at December 31, 1996 and 1995, respectively. Generation
from NMP2 and operating expenses incurred by NMP2 are shared in the same
proportions as the cotenants' respective ownership interests. The Company's
share of operating expenses is included in the corresponding operating expenses
on its Statement of Income. 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.
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 1996, 1995 and 1994, this
totaled $1.4 million, $1.2 million, and $1.4 million, respectively.
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 $368 million in 2026 dollars ($148
million in 1996 dollars). The Company's estimate for decommissioning costs
decreased in 1996 as compared to 1995 principally as a result of a reduction in
the estimated annual inflation factor. 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 in
1996, 1995 and
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1994 was $3.9 million, $2.3 million and $1.6 million, respectively. The
accumulated decommissioning costs collected in rates through December 31, 1996,
1995 and 1994 amounted to $14.9 million, $11.0 million and $8.7 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
December 31, 1996, the balance in these funds, including reinvested net
earnings, was approximately $15.3 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 Financial Accounting Standards Board 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. If the Company
was required to record the present value of its share of NMP2 decommissioning
costs on its Balance Sheet as of December 31, 1996, the Company would have to
recognize a liability and corresponding increase to nuclear plant of
approximately $54 million.
NUCLEAR PLANT INSURANCE
NMPC procures public liability and property insurance for NMP2, and the Company
reimburses NMPC for its 18% share of those costs.
The Price-Anderson 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 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
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$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 million 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 $1.9 million per loss. This level of insurance is in excess of the
NRC's 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 $842,000.
RECENT ACTIONS OF THE NRC
In October 1996, NMPC, along with other companies, received a letter from the
NRC requiring them to provide the NRC with information on the "adequacy and
availability" of design basis documentation on their nuclear plants within 120
days. Such information will be used by the NRC to verify that companies are in
compliance with the terms and conditions of their license(s) and NRC
regulations. In addition, it will allow the NRC to determine if other inspection
activities or enforcement actions should be taken on a particular company. NMPC
plans to respond to the NRC by the February 9, 1997 due date.
NMPC believes that the NRC is becoming more stringent as indicated by this
request and that a direct cost impact on companies with nuclear plants may
result. The Company is unable to predict how such a higher risk operating
environment may affect its financial position, cash flows or results of
operations.
47
<PAGE>
NOTE 6. CAPITAL STOCK
COMMON STOCK
The Company has 150,000,000 shares of authorized common stock, of which
120,784,277 were issued and 3,485 shares were held in Treasury at December 31,
1996. The Company has 1,678,208 shares reserved for sale through its Employee
Stock Purchase Plan, 2,728,486 shares committed to the Automatic Dividend
Reinvestment Plan and 97,093 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 10, the
Company has granted Brooklyn Union the right, under certain circumstances, to
purchase 23,981,964 shares of common stock at a price of $19.725 per share.
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 December 31, 1996 and 1995 amounted to approximately $637 million
and $598 million, respectively, compared to their carrying amounts of $640
million and $644 million, respectively. For a further discussion on the basis of
the fair value of the securities discussed above, see Note 1.
Each year the Company is required to redeem certain series of preferred stock
through the operation of sinking fund provisions as follows:
- --------------------------------------------------------------------------------
Redemption Provision Number Redemption
Series Beginning Ending of Shares Price
- --------------------------------------------------------------------------------
L 7/31/79 7/31/11 10,500 $100
NN 3/1/99 3/1/19 77,700 25
UU 10/15/99 10/15/19 112,000 25
================================================================================
The Company 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 NN and UU. The aggregate par value of preferred stock required to
be redeemed through sinking funds is $1.1 million in 1997 and 1998 and $5.8
million in each of the years 1999, 2000 and 2001.
48
<PAGE>
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:
- --------------------------------------------------------------------------------
Redemption Redemption Number of
Series Date Shares Amounts
- --------------------------------------------------------------------------------
$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
================================================================================
PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
The Company has the option to redeem certain series of its preferred stock. For
the series subject to optional redemption at December 31, 1996, the call prices
were as follows:
- --------------------------------------------------------------------------------
Series Call Price
- --------------------------------------------------------------------------------
5.00% Series B $101
4.25% Series D 102
4.35% Series E 102
4.35% Series F 102
5 1/8% Series H 102
5 3/4% Series I - Convertible 100
================================================================================
PREFERENCE STOCK
At December 31, 1996, 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.
49
<PAGE>
The annual G&R Mortgage sinking fund requirement for 1996, due not later than
June 30, 1997, is estimated at $25 million. The Company expects to satisfy this
requirement with retired G&R Bonds, property additions, or any combination
thereof.
1989 REVOLVING CREDIT AGREEMENT
The Company has available through October 1, 1997, $250 million under its 1989
Revolving Credit Agreement (1989 RCA). In July 1996, at the Company's request,
the amount committed by the banks participating in the facility was reduced from
$300 million to $250 million. This line of credit is secured by a first lien
upon the Company's accounts receivable and fuel oil inventories. At December 31,
1996, no amounts were outstanding under the 1989 RCA. The 1989 RCA may be
extended for one-year periods upon the acceptance by the lending banks of a
request by the Company, which must be delivered to the lending banks prior to
April 1 of each year. It is the Company's intent to request an extension prior
to April 1, 1997.
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 December 31, 1996 were as
follows:
(In thousands of dollars)
- --------------------------------------------------------------------------------
Interest
Rate Series Principal Tendered
- --------------------------------------------------------------------------------
PCRBs 8 1/4% 1982 $ 17,200 Tendered every three
years, next tender
October 1997
3.25% 1985 A,B 150,000 Tendered annually on
March 1
EFRBs 4.05% 1993 A 50,000 Tendered weekly
4.00% 1993 B 50,000 Tendered weekly
4.00% 1994 A 50,000 Tendered weekly
4.00% 1995 A 50,000 Tendered weekly
================================================================================
The 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 $381 million in the event of default. The obligation of the
Company to reimburse the letter of credit banks is unsecured.
50
<PAGE>
The expiration dates for these letters of credit are as follows:
- --------------------------------------------------------------------------------
Series Expiration Date
- --------------------------------------------------------------------------------
PCRBs 1985 A,B 3/16/99
EFRBs 1993 A,B 11/17/99
1994 A 10/26/97
1995 A 8/24/98
================================================================================
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.
FAIR VALUES OF LONG-TERM DEBT
The carrying amounts and fair values of the Company's long-term debt at December
31 were as follows:
(In thousands of dollars)
- --------------------------------------------------------------------------------
1996
- --------------------------------------------------------------------------------
Fair Carrying
Value Amount
- --------------------------------------------------------------------------------
General and Refunding Bonds $1,571,745 $1,536,000
Debentures 2,271,095 2,270,000
Authority Financing Notes 950,758 916,675
- --------------------------------------------------------------------------------
Total $4,793,598 $4,722,675
================================================================================
1995
- --------------------------------------------------------------------------------
General and Refunding Bonds $1,968,173 1,951,000
Debentures 2,245,138 2,270,000
Authority Financing Notes 928,967 916,675
- --------------------------------------------------------------------------------
Total $5,142,278 $5,137,675
================================================================================
For a further discussion on the basis of the fair value of the securities listed
above, see Note 1.
DEBT MATURITY SCHEDULE
The total long-term debt maturing in each of the next five years is as follows:
1997, $251 million; 1998, $101 million; 1999, $454 million; 2000, $37 million;
and 2001, $146 million.
51
<PAGE>
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 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 December 31,
1996 and 1995 were as follows:
(In thousands of dollars)
- --------------------------------------------------------------------------------
1996 1995
- --------------------------------------------------------------------------------
Actuarial present value of benefit obligation
Vested benefits $ 547,002 $ 518,487
Nonvested benefits 55,157 54,305
- --------------------------------------------------------------------------------
Accumulated Benefit Obligation $ 602,159 $ 572,792
================================================================================
Plan assets at fair value $ 746,400 $ 685,300
Actuarial present value of projected
benefit obligation 689,661 662,360
- --------------------------------------------------------------------------------
Projected benefit obligation less
than plan assets 56,739 22,940
Unrecognized net obligation 71,085 77,831
Unrecognized net gain (123,759) (97,285)
- --------------------------------------------------------------------------------
Net Prepaid (Accrued) Pension Cost $ 4,065 $ 3,486
================================================================================
Periodic pension cost for the Primary Plan included the following components:
(In thousands of dollars)
- --------------------------------------------------------------------------------
1996 1995 1994
================================================================================
Service cost - benefits
earned during the period $ 17,384 $ 15,385 $ 16,465
Interest cost on projected benefit
obligation and service cost 47,927 45,987 43,782
Actual return on plan assets (81,165) (102,099) (12,431)
Net amortization and deferral 33,541 57,665 (31,633)
- --------------------------------------------------------------------------------
Net Periodic Pension Cost $ 17,687 $ 16,938 $ 16,183
================================================================================
52
<PAGE>
Assumptions used in accounting for the Primary Plan were as follows:
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
Discount rate 7.25% 7.25% 7.75%
Rate of future compensation increases 5.00% 5.00% 5.00%
Long-term rate of return on assets 7.50% 7.50% 7.50%
- --------------------------------------------------------------------------------
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 the difference between the pension rate allowance and the
annual pension contributions contributed into the pension fund.
SUPPLEMENTAL PLAN
The Supplemental Plan, the cost of which is borne by the Company's shareowners,
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. Death benefits are currently
provided by insurance. The provision for plan benefits, which are unfunded,
totaled approximately $2.7 million in 1996 and $2.3 million in both 1995 and
1994.
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 $127,000, $114,000 and $148,000 in
1996, 1995 and 1994, respectively.
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
In addition to providing pension benefits, the Company provides certain medical
and life insurance benefits for 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
53
<PAGE>
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 will be phased into and
fully reflected in rates within a five-year period from the year of adoption,
which began December 1, 1993, with the accumulated regulatory asset being
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 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. For the years ended December 31,
1996 and 1995, the Company funded the trusts with approximately $18 million and
$50 million, respectively.
Accumulated postretirement benefit obligation other than pensions at December 31
was as follows:
(In thousands of dollars)
- --------------------------------------------------------------------------------
1996 1995
- --------------------------------------------------------------------------------
Retirees $ 156,181 $ 135,497
Fully eligible plan participants 56,950 52,028
Other active plan participants 152,627 142,035
- --------------------------------------------------------------------------------
Accumulated postretirement
benefit obligation $ 365,758 $ 329,560
Plan assets 74,692 53,646
- --------------------------------------------------------------------------------
Accumulated postretirement benefit
obligation in excess of plan assets 291,066 275,914
Unrecognized prior service cost (188) -
Unrecognized net gain 75,309 100,335
- --------------------------------------------------------------------------------
Accrued Postretirement Benefit Cost $ 366,187 $ 376,249
================================================================================
54
<PAGE>
At December 31, 1996, and 1995, 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 for the years were as
follows:
(In thousands of dollars)
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
Service cost-benefits
earned during the period $ 10,690 $ 9,082 $ 11,275
Interest cost on projected
benefit obligation and
service cost 25,030 22,412 25,713
Actual return on plan assets (3,046) (1,034) -
Net Amortization
and deferral (12,175) (14,699) (5,213)
- --------------------------------------------------------------------------------
Periodic Postretirement
Benefit Cost $ 20,499 $ 15,761 $ 31,775
================================================================================
Assumptions used to determine the postretirement benefit obligation were as
follows:
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
Discount rate 7.25% 7.25% 7.75%
Rate of future compensation increases 5.00% 5.00% 5.00%
Long-term rate of return on assets 7.50% 7.50% -
- --------------------------------------------------------------------------------
The assumed health care cost trend rates used in measuring the accumulated
postretirement benefit obligation at December 31, 1996 and 1995 were 8.0% and
8.5%, respectively, gradually declining to 6.0% in 2001 and thereafter. A one
percentage point increase in the health care cost trend rate would increase the
accumulated postretirement benefit obligation as of December 31, 1996 and 1995
by approximately $43 million and $36 million, respectively, and the sum of the
service and interest costs in 1996 and 1995 by $5 million and $4 million,
respectively.
55
<PAGE>
NOTE 9. FEDERAL INCOME TAX
At December 31, 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:
(In thousands of dollars)
- --------------------------------------------------------------------------------
1996 1995
- --------------------------------------------------------------------------------
DEFERRED TAX ASSETS
Net operating loss carryforwards $ 145,205 $ 338,921
Reserves not currently deductible 58,981 66,825
Tax depreciable basis in excess
of book 34,314 41,428
Nondiscretionary excess credits 27,700 29,826
Credit carryforwards 135,902 149,545
Other 186,907 125,246
- --------------------------------------------------------------------------------
Total Deferred Tax Assets $ 589,009 $ 751,791
- --------------------------------------------------------------------------------
DEFERRED TAX LIABILITIES
1989 Settlement $ 2,163,239 $ 2,155,418
Accelerated depreciation 642,702 628,475
Call premiums 44,846 50,062
Rate case deferrals 2,127 28,971
Other 33,496 35,597
- --------------------------------------------------------------------------------
Total Deferred Tax Liabilities 2,886,410 2,898,523
- --------------------------------------------------------------------------------
Net Deferred Tax Liability $ 2,297,401 $ 2,146,732
================================================================================
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)
- --------------------------------------------------------------------------------
1996 1995
- --------------------------------------------------------------------------------
Regulatory Assets
1989 Settlement $ 1,660,871 $ 1,666,744
Plant items 125,976 149,520
Other (14,069) (13,881)
- --------------------------------------------------------------------------------
Total Regulatory Assets $ 1,772,778 $ 1,802,383
================================================================================
Regulatory Liabilities
Carryforward credits $ 68,421 $ 82,330
Other 34,466 33,730
- --------------------------------------------------------------------------------
Total Regulatory Liabilities $ 102,887 $ 116,060
================================================================================
56
<PAGE>
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.
(In thousands of dollars)
- --------------------------------------------------------------------------------
1996 1995 1994
Income before federal income tax $ 525,721 $ 508,824 $ 478,564
Statutory federal income tax rate 35% 35% 35%
- --------------------------------------------------------------------------------
Statutory federal income tax $ 184,002 $ 178,088 $ 167,497
ADDITIONS (REDUCTIONS) IN FEDERAL
INCOME TAX
Excess of book depreciation over
tax depreciation 18,339 18,588 14,745
1989 Settlement 4,212 4,213 4,213
Interest capitalized 2,270 2,218 2,449
Tax credits (4,383) (1,025) (2,058)
Tax rate change amortization 3,686 3,752 (4,779)
Allowance for funds used during
construction (2,305) (2,392) (2,450)
Other items 3,436 2,096 (2,905)
- --------------------------------------------------------------------------------
Total Federal Income Tax Expense $ 209,257 $ 205,538 $ 176,712
================================================================================
Effective Federal Income Tax Rate 39.8% 40.4% 36.9%
================================================================================
The Company's net operating loss (NOL) carryforwards for federal income tax
purposes are estimated to be approximately $415 million at December 31, 1996.
These NOL carryforwards are scheduled to expire in the years 2004 through 2007.
The Company currently has tax credit carryforwards of approximately $136
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 $128 million and research and development credits totaling
approximately $8 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. The Revenue Agents'
Reports proposed ITC adjustments which if sustained, would reduce the ITC
carryforwards to approximately $63 million.
Additionally, the Revenue Agents' Reports reflect proposed adjustments to the
Company's federal income tax returns for the years 1981 through 1989 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 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
57
<PAGE>
sufficient to satisfy any settlement reached. However, if necessary, the Company
will avail itself of interim financing via the 1989 RCA to meet this obligation.
The Company currently believes that a settlement of the 1981 through 1989 years
should be reached with the Regional Appeals Office sometime in 1997.
NOTE 10. MERGER AGREEMENT WITH THE BROOKLYN UNION GAS COMPANY
On December 29, 1996, the Company and The Brooklyn Union Gas Company (Brooklyn
Union) entered into an Agreement and Plan of Exchange (Share Exchange
Agreement), pursuant to which the companies will be merged in a transaction that
will result in the formation of a new holding company. The new holding company,
which has not yet been named, will serve approximately 2.2 million customers and
have annual revenues of more than $4.5 billion. The merger is expected to be
accomplished through a tax-free exchange of shares.
The proposed transaction, which has been approved by both companies' boards of
directors, would unite the resources of the Company with the resources of
Brooklyn Union. Brooklyn Union, 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
approximately two-thirds of the borough of Queens, all in New York City.
Brooklyn Union has energy-related investments in gas exploration, production and
marketing in the United States and Canada, as well as energy services in the
United States, including cogeneration products, pipeline transportation and gas
storage.
Under the terms of the proposed transaction, the Company's common shareowners
will receive .803 shares (the Ratio) of the new holding company's common stock
for each share of the Company's common stock that they currently hold. Brooklyn
Union common shareowners will receive one share of common stock of the new
holding company for each share of Brooklyn Union common stock that they
currently hold. Shareowners of the Company will own approximately 66% of the
common stock of the new holding company while Brooklyn Union shareowners will
own approximately 34%. The proposed transaction will have no effect on either
company's debt issues or outstanding preferred stock.
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.
Accordingly, the Company's ability to engage in certain activity described
herein may be limited or prohibited by the Share Exchange Agreement.
Upon completion of the merger, Dr. William J. Catacosinos will become
58
<PAGE>
chairman and chief executive officer of the new holding company; Mr. Robert B.
Catell, currently chairman and chief executive officer of Brooklyn Union, will
become president and chief operating officer of the new holding company. 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 the new company will be composed of 15 members, six from the
Company, six from Brooklyn Union and three additional persons previously
unaffiliated with either company and jointly selected by them.
The companies will continue their respective current dividend policies until the
closing, consistent with the provisions of the Share Exchange Agreement. It is
expected that the new holding company's dividend policy will be determined prior
to closing.
The merger is conditioned upon, among other things, the approval of the merger
by the holders of two-thirds of the outstanding shares of common stock of each
of the Company and Brooklyn Union and the receipt of all required regulatory
approvals. The Company is unable to determine when or if all required approvals
will be obtained.
In 1995, the Long Island Power Authority (LIPA), an agency of the State of New
York (NYS), was requested by the Governor of NYS to develop a plan, pursuant to
its authority under NYS law, to provide 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.
The Share Exchange Agreement contemplates that discussions, which are currently
in progress, will continue with LIPA to arrive at an agreement mutually
acceptable to the Company, Brooklyn Union and LIPA, pursuant to which LIPA would
acquire certain assets or securities of the Company, the consideration for which
would inure to the benefit of the new holding company. In the event that such a
transaction is completed, the Ratio would become .880. In connection with
discussions with LIPA, LIPA has indicated that it may exercise its power of
eminent domain over all or a portion of the Company's assets or securities, in
order to achieve its objective of reducing current electric rates, if a
negotiated agreement cannot be reached. The Company is unable to determine when
or if an agreement with LIPA will be reached, or what action, if any, LIPA will
take if such an agreement is not reached.
NOTE 11. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
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.
59
<PAGE>
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 expire 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 purchase power
contracts.
<TABLE>
<CAPTION>
Electric Operations (In millions of dollars)
- ----------------------------------------------------------------------------------------------
NYPA Holtsville
---------------
Other
Debt Fixed Firm Total
Service Charges Energy* Transmission IPP's* Business*
------- ------- ------- ------------ ------ ---------
<S> <C> <C> <C> <C> <C> <C>
1997 $ 20.3 $ 15.0 $ 7.7 $ 27.8 $ 110.7 $ 181.5
1998 21.6 15.2 9.0 27.8 115.3 188.9
1999 21.7 16.3 7.2 27.2 118.3 190.7
2000 21.8 16.4 8.0 27.0 123.3 196.5
2001 21.9 16.6 11.3 29.0 126.7 205.5
Subsequent Years 259.9 254.9 137.0 557.4 1,161.6 2,370.8
- ----------------------------------------------------------------------------------------------
Total $ 367.2 $ 334.4 $ 180.2 $ 696.2 $1,755.9 $3,333.9
Less: Imputed Interest 188.0 183.7 96.9 426.4 841.8 1,736.8
- ----------------------------------------------------------------------------------------------
Present Value of Payments $ 179.2 $ 150.7 $ 83.3 $ 269.8 $ 914.1 $1,597.1
==============================================================================================
</TABLE>
*Assumes full performance by the IPPs and NYPA.
GAS
In order to provide 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
payments even if the services are not provided (take-or-pay.) 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 2012.
Gas Operations (In millions of dollars)
- --------------------------------------------------------------------------------
1997 $ 38.7
1998 37.6
1999 37.6
2000 37.6
2001 34.7
Subsequent Years 232.5
- --------------------------------------------------------------------------------
Total $ 418.7
Less: Imputed Interest 182.1
- --------------------------------------------------------------------------------
Present Value of Payments $ 236.6
================================================================================
60
<PAGE>
CONTINUOUS EMISSION MONITORING
The Company expended approximately $1 million in 1996 to meet continuous
emission monitoring requirements, to meet Phase II nitrogen oxide (NOx)
reduction requirements under the federal Clean Air Act (CAA). Subject to
requirements that are expected to be promulgated in forthcoming regulations, the
Company estimates that it may be required to expend approximately $44 million by
2003 to meet Phase II and Phase III NOx reduction requirements and approximately
$2 million by 1999 to meet potential requirements for the control of hazardous
air pollutants from power plants. The Company believes that all of the above
costs will be recoverable through rates.
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 1996, 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
calls for a competitive wholesale power market to be in place by early 1997
which will 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.
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The Order contemplates that implementation of competition will proceed on two
tracks. The Order requires that each major electric utility 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. Since October 1, 1996,
proceedings have commenced for the five electric utilities which filed
restructuring plans in accordance with track one and the Company has intervened
in each of these proceedings.
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 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. While these discussions are
continuing in an attempt to narrow the differences among the parties, on
December 31, 1996, the New York Power Pool (NYPP) 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. It is
anticipated that the New York State utilities will submit the full ISO/Power
Exchange filing to the FERC during the first quarter of 1997.
The PSC envisions 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
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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, 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. Oral argument
in the Appellate Division has not yet been scheduled, but a decision is expected
by the end of 1997.
THE ELECTRIC INDUSTRY - FEDERAL REGULATORY ISSUES
In April 1996, in response to its Notice of Proposed Rulemaking issued in March
1995, the FERC issued two orders 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
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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 themselves
and to third parties on a non-discriminatory basis. Additionally, utilities must
use these same tariffs for their own wholesale sales. 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. The
procedural schedule was suspended pending filing of the settlement agreement,
which is anticipated during the first quarter of 1997. Non-rate issues
associated with the Company's open access tariff have not yet been addressed by
the FERC.
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.
With other members of the industry, the Company has participated in several
joint petitions for rehearing and/or clarification of the FERC's Orders 888 and
889. Among other issues, these petitions address the FERC's obligation to
exercise its jurisdiction to provide for the recovery of strandable investments
in any retail wheeling situations. The outcome and timing of the FERC Orders on
rehearing are uncertain.
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
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," could then
require a significant write-down of all or a portion of the Company's net
regulatory assets.
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If the Company were unable to continue to apply the provisions of SFAS No. 71,
at December 31, 1996, the Company estimates that approximately $4.6 billion
would have been written off at such time.
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. These competitors are
non-utility generators (NUGS), NYPA and Municipal Distribution Agencies (MDAs).
The Public Utility Regulatory Policies Act of 1978 (PURPA), the goal of which is
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. 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
PURPA to purchase the output of certain of these generators, which are known as
qualified facilities (QFs).
In 1996, the Company lost sales to NUGs totaling 422 gigawatt- hours (GWh)
representing a loss in electric revenues net of fuel (net revenues) of
approximately $34 million, or 1.9% of the Company's net revenues. In 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 1997, sales losses to NUGs will be 429
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 in 1996 approximated
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218 megawatts (MW) and in early 1995 approximated 205 MW. The increase was the
result of the SUNY Stony Brook facility going on line in mid 1995. The Company
estimates that purchases from QFs required by federal and state law cost the
Company $63 million and $53 million in 1996 and 1995, respectively, more than it
would have cost had the Company generated this power.
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 NYPA power for economic development. The
Company estimates that in 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. Currently, the potential loss of additional load is limited by
conditions in the Company's transmission agreements with NYPA.
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
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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.
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 their decision once that
decision becomes final, which is not expected for several months. 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.
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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. Research is
underway to determine the existence and nature of operations and their
relationship, if any, to the Company or its predecessor companies.
The Company has entered into discussions with the DEC which may lead to the
issuance of one or more Administrative Consent Orders (ACO) regarding the
management of environmental activities at these properties. Although the exact
amount of the Company's remediation costs cannot yet be determined, based on the
findings of investigations at two of these six sites, estimates indicate that it
will cost approximately $51 million to remediate all of these sites through the
year 2005. Accordingly, the Company has 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 $35 million liability reflects the present value of
the future stream of payments to investigate and remediate these sites. The
Company used a risk-free rate of 7.25% to discount this obligation.
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. The
Company is seeking recovery under the GCL policies for the costs
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incurred to date and future costs associated with the clean-up of the Company's
former MGP sites and Superfund sites for which the Company has been named a
potentially responsible party (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
remediation 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,
have entered into an ACO with the EPA to conduct a Remedial Investigation and
Feasibility Study (RI/FS), which has been completed and is currently being
reviewed by the EPA. Under a PRP participation agreement, the Company is
responsible for 8.2% of the costs associated with this RI/FS. The level of
remediation required will be determined when the EPA issues its decision, but
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 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.
In 1994, the EPA requested certain of the large PRPs, which include several
other utilities, to form a group, sign an ACO, and conduct a remediation program
for the sites under the Toxic Substances Control Act, or in the alternative, to
perform a Superfund cleanup for the sites. The EPA has provided the Company with
documents indicating 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. The Company intends to join a PRP
Group which includes other utilities, which has been organized for the purpose
of developing and implementing acceptable remediation programs for the sites.
The Company is currently unable to determine its share of the cost to remediate
these sites.
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In addition, the Company was notified that it is a PRP at a Superfund site
located 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 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.
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.
Previously, 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 addition, during 1996 the Long Island Soundkeeper Fund, a non-profit
organization, filed a suit against the Owners of the Sound Cable in Federal
District Court in Connecticut alleging that the Sound Cable fluid leaks
constitute unpermitted discharges of pollutants in violation of the Clean Water
Act (CWA) and that such pollutants present a threat to the environment and
public health. The suit seeks, among other things, injunctive relief prohibiting
the Owners from continuing to operate the Sound Cable in alleged violation of
the CWA and civil penalties of $25,000 per day for each violation from each of
the Owners.
In December 1996, a barge, owned and operated by a third party, dropped anchor,
causing extensive damage to the Sound Cable and a release of dielectric fluid
into the Long Island Sound. Temporary clamps and leak abaters have been placed
on the cables and have stopped the leaks. Permanent repairs are expected to be
undertaken in the late spring of 1997. The preliminary estimate of the cost of
these repairs is $15 million. The Company intends
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to seek recovery from third parties for costs incurred by the Company as a
result of this incident. The timing and amount of recovery, if any, cannot yet
be determined. In addition, the Owners maintain insurance coverage for the Sound
Cable which the Company believes will be sufficient to cover any repair costs.
In any event, costs not reimbursed by a third party or not 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 12. SEGMENTS OF BUSINESS
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.
(In millions of dollars)
- --------------------------------------------------------------------------------
For year ended December 31 1996 1995 1994
- --------------------------------------------------------------------------------
OPERATING REVENUES
Electric $ 2,467 $ 2,484 $ 2,481
Gas 684 591 586
- --------------------------------------------------------------------------------
Total $ 3,151 $ 3,075 $ 3,067
================================================================================
OPERATING EXPENSES
(excludes federal income tax)
Electric $ 1,644 $ 1,657 $ 1,640
Gas 560 478 500
- --------------------------------------------------------------------------------
Total $ 2,204 $ 2,135 $ 2,140
================================================================================
OPERATING INCOME
(before federal income tax)
Electric $ 823 $ 827 $ 842
Gas 124 113 85
- --------------------------------------------------------------------------------
Total operating income 947 940 927
AFC (6) (7) (7)
Other income and deductions (23) (38) (45)
Interest charges 451 476 500
Federal income tax 209 206 177
- --------------------------------------------------------------------------------
Net Income $ 316 $ 303 $ 302
================================================================================
DEPRECIATION AND AMORTIZATION
Electric $ 129 $ 122 $ 112
Gas 25 23 19
- --------------------------------------------------------------------------------
Total $ 154 $ 145 $ 131
================================================================================
CONSTRUCTION AND NUCLEAR FUEL EXPENDITURES*
Electric $ 165 $ 162 $ 155
Gas 78 84 125
- --------------------------------------------------------------------------------
Total $ 243 $ 246 $ 280
================================================================================
* Includes non-cash allowance for other funds used during construction
and excludes Shoreham post-settlement costs.
(In millions of dollars)
- --------------------------------------------------------------------------------
At December 31 1996 1995 1994
- --------------------------------------------------------------------------------
IDENTIFIABLE ASSETS
Electric $ 9,835 $ 10,020 $ 10,285
Gas 1,232 1,181 1,181
- --------------------------------------------------------------------------------
Total identifiable assets 11,067 11,201 11,466
Assets utilized for overall
Company operations 1,143 1,326 1,013
- --------------------------------------------------------------------------------
Total Assets $ 12,210 $ 12,527 $ 12,479
================================================================================
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NOTE 13. QUARTERLY FINANCIAL INFORMATION
(Unaudited)
(In thousands of dollars except earnings per common share)
- --------------------------------------------------------------------------------
1996 1995
- --------------------------------------------------------------------------------
OPERATING REVENUES
For the quarter ended March 31 $ 864,214 $ 791,188
June 30 694,602 653,824
September 30 849,775 875,794
December 31 742,104 754,322
================================================================================
OPERATING INCOME
For the quarter ended March 31 $ 190,421 $ 180,875
June 30 141,065 143,246
September 30 235,402 239,561
December 31 169,693 167,936
================================================================================
NET INCOME
For the quarter ended March 31 $ 81,753 $ 70,299
June 30 40,524 41,392
September 30 130,023 131,221
December 31 64,164 60,374
================================================================================
EARNINGS FOR COMMON STOCK
For the quarter ended March 31 $ 68,682 $ 57,127
June 30 27,453 28,220
September 30 116,972 118,069
December 31 51,141 47,250
================================================================================
EARNINGS PER COMMON SHARE
For the quarter ended March 31 $ .57 $ .48
June 30 .23 .24
September 30 .97 .99
December 31 .43 .39
================================================================================
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NOTE 14. EVENT SUBSEQUENT TO THE DATE OF THE REPORT OF INDEPENDENT AUDITORS
(UNAUDITED)
LONG ISLAND POWER AUTHORITY PROPOSED TRANSACTION
On April 30, 1997, the Long Island Power Authority (LIPA) submitted to the New
York State Public Authorities Control Board for approval, unexecuted copies of
agreements related to LIPA's proposed acquisition (via the purchase of the
Company's common stock) of the Company's transmission and distribution system
and certain other assets and liabilities (LIPA Transaction). Prior to LIPA's
acquisition of the common stock, the Company's gas assets, electric generating
facility assets and certain other assets and liabilities will be transferred to
affiliates of the holding company to be formed in connection with the Share
Exchange Agreement with Brooklyn Union.
While the specific allocation of assets and liabilities has not yet been finally
determined, it is currently contemplated that the holding company would, subject
to obtaining all required consents, assume the Company's (i) 7.30% Debentures
due July 15, 1999; (ii) 8.20% Debentures due March 15, 2023; and (iii) Preferred
Stock, 7.95%, Series AA.
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.
The Company is unable to determine when or if the agreements related to the LIPA
Transaction will be executed by the parties or when or if all consents and
approvals required to consummate the LIPA Transaction will be obtained.
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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 December 31, 1996 and 1995 and
the related statements of income, retained earnings and cash flows for each of
the three 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
December 31, 1996 and 1995, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1996, in conformity
with generally accepted accounting principles. Also, in our opinion, the related
financial statement schedule, when considered in relation to the basic financial
statements taken as a whole, presents fairly in all material respects the
information set forth therein.
Melville, New York
January 31, 1997
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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
- ----
June , 1997
Signature and Title
WILLIAM J. CATACOSINOS*
-----------------------
William J. Catacosinos,
Principal Executive Officer 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, Vice President,
Controller and 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)
74
<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: June , 1997
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, 1996.
75
