MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
SOURCES OF LIQUIDITY Cash and temporary cash investments were
$342.3 million at December 31, 1995 compared with $245.2 million
at December 31, 1994 and $36.8 million at December 31, 1993. The
Company's cash balances reflect, among other things, the timing
and amounts of external financing. The Company's cash
requirements are subject to substantial fluctuations during the
year due to seasonal variations in cash flow and peak in January
and July of each year when the semi-annual payments of New York
City property taxes are due. In July 1995 the Company issued $100
million of 6 5/8% 10-year debentures. The cash balance at
December 31, 1995 was used on January 2, 1996 for redemption at
maturity of the $100 million 5% Series CC mortgage bonds and for
a $224 million semi-annual New York City property tax payment.
In the first quarter of 1994 pursuant to its amended
dividend reinvestment plan, the Company issued 478,016 shares of
common stock for $14.7 million. The Company amended the plan in
1993 to permit, at the option of the Company, the use of new
shares or outstanding shares purchased in the market.
In February 1994 the Company issued $150 million of 35-year
debentures. In July 1994 the Company issued $150 million of
five-year floating-rate debentures, the interest rate on which is
reset quarterly. In December 1994 the Company issued $100 million
of 35-year tax-exempt debt through the New York State Energy
Research and Development Authority (NYSERDA).
In April 1993 the Company issued $101 million of 35-year
tax-exempt debt through NYSERDA. The Company issued 373,227
shares of common stock in December 1993 for $11.9 million
pursuant to the Company's amended dividend reinvestment plan.
In June 1993 the Company issued $380 million of 30-year
debentures of which approximately $80 million was used to meet
1993 capital requirements and the balance was used to retire
higher cost debt securities.
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Advance Refundings. Since 1992 the Company has taken the
opportunity of generally declining interest rates to reduce costs
by redeeming outstanding securities in advance of maturity dates
and replacing them with new securities bearing lower interest or
dividend rates. In August 1995 the Company issued $128.3 million
of 25-year 6.10% tax-exempt debt through NYSERDA, the proceeds of
which were used to redeem a like amount of outstanding 9%
tax-exempt debt. In December 1995 the Company redeemed, in
advance of maturity, $27.4 million of 9.70% Series 1990A
debentures representing the balance of this issue outstanding.
Excluding the preferred stock transactions discussed below,
approximately $1.9 billion of securities have been refunded,
producing aggregate first-year savings in interest and preferred
dividends of about $25 million, with continued savings in
subsequent years.
Tender Offer. In January 1996 the Company commenced a tender
offer for certain series of its preferred stock. Shareholders
tendered approximately $227 million of such preferred stock
pursuant to the offer, which expired on February 27, 1996. The
Company expects to call $90 million of its other preferred stock
for redemption and to issue subordinated debentures (interest
payments on which, unlike preferred stock dividends, are tax
deductible) to fund the purchase of the tendered stock and the
redemptions. The Company's current expectation is that these
transactions will produce revenue-equivalent present value
savings of approximately $42 million. Under generally accepted
accounting principles, the net gain realized from these
transactions as a result of acquiring preferred stock below its
book value will be included in the calculation of period earnings
per share, but not in net income. In accordance with an order of
the New York State Public Service Commission (PSC), the Company,
consistent with its objective of reducing potentially strandable
costs (discussed below), will apply the net gain, which is
presently estimated to be approximately $14 million, to reduce
net utility plant by an additional provision for depreciation.
While 1996 net income will be reduced by the amount of the
additional provision for depreciation, due to the treatment of
the net gain, earnings per share will be unaffected.
In 1994 and 1993 the Company borrowed from banks for short
periods; in 1995 there were no short-term borrowings. For 1996
the Company has arranged for bank credit lines amounting to $150
million. Borrowings thereunder would bear interest at prevailing
market rates.
Customer accounts receivable, less allowance for
uncollectible accounts, amounted to $497.2 million, $440.5
million and $459.3 million at December 31, 1995, 1994 and 1993,
respectively. In terms of equivalent days of revenue outstanding,
these amounts represented 27.6, 27.1 and 27.6 days, respectively.
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Regulatory accounts receivable at December 31, 1995 amounted
to a net credit to be refunded to customers of $6.5 million. Net
regulatory accounts receivable recoverable from customers
amounted to $26.3 million and $97.1 million at December 31, 1994
and 1993, respectively. See Note A to the financial statements.
The following is a summary of the balances and activity in
regulatory accounts receivable in 1995:
1995
Balance Recoveries Balance
Dec. 31, 1995 from Dec. 31,
(Millions of Dollars) 1994* Accruals* Customers** 1995*
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ERAM/Modified ERAM $(56.4) $(35.3) $ 54.0 $(37.7)
Electric Incentives
Enlightened Energy
program 70.1 32.7 (83.1) 19.7
Customer service 6.7 5.7 (8.4) 4.0
Fuel and purchased power 5.9 19.2 (23.2) 1.9
Gas Incentives
System improvement -- 6.1 (1.5) 4.6
Customer service -- 1.3 (0.3) 1.0
----------------------------------------------------
Total $ 26.3 $ 29.7 $(62.5) $ (6.5)
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* Negative amounts are refundable; positive amounts
recoverable.
** Negative amounts were recovered; positive amounts refunded.
The components of the balance in regulatory accounts
receivable at December 31, 1995 will be refunded to or recovered
from customers during 1996 and 1997 as discussed in Note A to the
financial statements. The incentives are discussed below under
"1992 Electric Rate Agreement," "1995 Electric Rate Agreement"
and "Gas and Steam Rate Agreements."
Deferred charges for Enlightened Energy (demand side
management) program costs amounted to $144.3 million, $170.2
million and $140.1 million at December 31, 1995, 1994 and 1993,
respectively. These costs are being recovered in rates, as
discussed below under the "1992 Electric Rate Agreement" and
"1995 Electric Rate Agreement."
The Company's earnings include an allowance for funds used
during construction which, as a percent of net income for common
stock, was 0.8 percent in 1995 and 1.7 percent in 1994 and 1993.
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Interest coverage on the SEC book basis was 4.20, 4.58 and
4.19 times for 1995, 1994 and 1993, respectively. The decline in
interest coverage in 1995 was due to lower earnings and higher
interest charges. The improvement in interest coverage in 1994
was due to debt refundings and increased earnings. The Company's
interest coverage continues to be high compared with the electric
utility industry generally.
The Company's senior debt (first mortgage bonds) is rated
Aa3, A+ and AA- by Moody's Investors Service (Moody's), Standard
& Poor's (S&P) and Duff and Phelps, Inc., respectively. Moody's
and S&P revised their ratings during 1995 from Aa2 and AA-,
respectively. Major factors for the revision were the uncertain
implications of New York's transition towards a more
market-oriented energy industry and the Company's obligations
under contracts with independent power producers (IPPs) (see
"Electric Capacity Resources" below and Note G to the financial
statements). The Company has not issued first mortgage bonds
since 1974; as of December 31, 1995 $175 million of first
mortgage bonds were outstanding, all of which mature in 1996. The
Company's unsecured debt securities (debentures and tax-exempt
debt) are rated A1, A+ and A+ by Moody's, S&P and Duff and
Phelps, Inc., respectively.
Cash flows from operating activities for years 1993 through
1995 were as follows:
(Millions of Dollars) 1995 1994 1993
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Net cash flows from operating activities $1,276 $1,250 $1,025
Less: Dividends on common and preferred stock 515 505 490
----------------------
Net after dividends $ 761 $ 745 $ 535
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Net cash flows in 1995 were favorably affected by incentive
billings of $116.5 million, offset by the refund to customers of
$54.0 million of revenues under the ERAM. Net cash flows in 1994
were favorably affected by incentive billings of $92.3 million,
ERAM billings of $28.9 million and labor productivity
improvements resulting in costs estimated to be approximately $51
million less than reflected in rates. See the table above for
balances in regulatory accounts receivable at December 31, 1995
to be refunded to or recovered from customers in future periods.
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CAPITAL REQUIREMENTS The following table compares the Company's
capital requirements for the years 1993 through 1995 and
estimated amounts for 1996 and 1997:
(Millions of Dollars) 1997 1996 1995 1994 1993
- ----------------------------------------------- ----------------------
Construction expenditures $ 671 $ 678 $ 693 $ 758 $ 789
Enlightened Energy program
costs less recoveries/(a)/ (33) (15) (26) 30 59
Power contract termination
costs - net/(a)/ (39) (31) (55) 62 68
Nuclear decommissioning
trust/(a)//(b)/ 21 21 19 15 19
Nuclear fuel 44 24 13 47 14
Investment in gas marketing
subsidiary 10 10 2 7 1
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Subtotal 674 687 646 919 950
Retirement of long-term debt
and preferred stock/(c)/ 106 184 11 134 178
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Total $ 780 $ 871 $ 657 $1,053 $1,128
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/(a)/ See discussion below of electric rate agreements.
/(b)/ See Note A to the financial statements for discussion of nuclear
decommissioning costs.
/(c)/ Does not include refundings in advance of maturity, nor the preferred
stock refunding in 1996 discussed above. For details of securities
maturing after 1997, see Note B to the financial statements.
Capital requirements shown above for 1995 were met from
internally generated funds. The Company expects to meet these
capital requirements for 1996 and 1997, including $290 million of
maturing securities, from cash balances, internally generated
funds and external financings of about $150 million, which would
likely be debt issues. In 1996 and 1997 the Company may, from
time to time, make short-term borrowings.
ELECTRIC CAPACITY RESOURCES Electric peak load in the Company's
service area, adjusted for historical design weather conditions,
grew by 150 MW (1.4 percent) in 1995. The growth was due
primarily to unusually high use of existing and new air
conditioners by customers during the exceptionally humid summer.
The growth in peak load has been moderated by the Company's
Enlightened Energy program, introduced in 1990, which helps the
Company's customers purchase and install energy-efficient
equipment and encourages the efficient use of energy resources.
This program continues to be modified for future years, based on
the Company's experience to date, so as to obtain energy
efficiency benefits at lower program costs.
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In response to federal and state regulatory policies and
requirements for utilities to contract with IPPs, the Company by
December 1992 had entered into contracts for the supply of
substantial capacity from facilities of IPPs. Plants with 1,798
MW of such capacity are in commercial operation, and the related
charges are reflected in the Company's rates. Approximately 186
MW of additional capacity is expected to be in operation and in
rates in 1996. Thereafter, additional capacity totalling about 70
MW is expected.
After 1992 estimates of future market prices for power
decreased significantly as excess generating capacity developed
in the Northeast. During 1993 and 1994, the Company entered into
agreements to terminate IPP contracts involving approximately 720
MW at a cost of $211 million (exclusive of interest) to be paid
over a period of several years. These costs (including interest)
are already reflected in rates. See "1995 Electric Rate
Agreement" below.
The Company's current resource plans, which reflect the
uncertainty as to the future industry structure in New York, do
not include the addition of long-term capacity resources to its
electric system during the next 20 years, other than the IPPs
discussed above.
COMPETITION No federal or New York State law presently requires
the Company to permit other sellers of electricity to use the
Company's facilities to make sales to the Company's retail
customers in New York City and Westchester County. However, in
recent years, federal and New York State legislation have
promoted the development of non-utility electric generating
capacity and competition at the wholesale level for electric
capacity and energy sales. A number of states, including New
York, are now considering whether to require electric utilities
to deliver electricity from other sellers directly to electricity
consumers, referred to as "retail wheeling."
Retail Wheeling. The most likely targets for retail wheeling are
large industrial customers and, to a lesser extent, governmental
customers. Almost all of the Company's customers are residential
or commercial, with sales to industrial customers comprising
about 2 percent of the Company's 1995 electric sales. Most
governmental customers in the Company's service area are, and for
many years have been, served by the New York Power Authority
(NYPA). However, if retail wheeling were permitted, the Company's
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large-usage commercial customers would also be targets. In any
case, competition would be mitigated by the limited capacity of
the existing transmission facilities for importing power and
energy into the Company's service area. Nevertheless, in a
competitive environment, the Company could be disadvantaged by
the relatively high costs of its generating facilities and the
Company's substantial commitments under its IPP contracts
relative to electric prices in a competitive market. Assuming
performance by the IPPs, the Company is obligated over the terms
of these contracts (which extend for various periods, up to 2034)
to make payments that currently are, and are projected to be,
uneconomic. See Note G to the financial statements.
Competitive Strategy. The Company's strategy for dealing with
competition includes ongoing cost reductions, increased
productivity, pursuit of growth opportunities and strengthening
of customer relations by providing value-added services. Another
major element of the strategy which the Company is promoting with
government and regulators is a "level playing field" on which the
Company could compete without unfair burdens of regulation or
taxation. For example, taxes other than federal income tax
represent 21 cents of every dollar the Company bills customers.
PSC Proceeding. The PSC is conducting a generic "competitive
opportunities" proceeding to investigate whether and how to
introduce increased competition into the electric utility
industry in the State.
In June 1995 the PSC adopted principles in this proceeding,
which among other things, state that "The current industry
structure, in which most power plants are vertically integrated
with natural monopoly transmission and distribution, must be
thoroughly examined to ensure that it does not impede or obstruct
development of effective wholesale or retail competition." With
respect to so-called "strandable costs", another principle states
"Utilities should have a reasonable opportunity to recover
prudent and verifiable expenditures and commitments made pursuant
to their legal obligations, consistent with these principles."
The principles also indicate that utilities should take all
practicable measures to mitigate transition costs.
In October 1995 the investor-owned utility companies of New
York State (including the Company) filed a proposal in this
proceeding that would restructure the State's electric industry
in a carefully planned transition to competition in the wholesale
market where bulk electricity would be bought and sold. Numerous
other parties, including the PSC staff, have submitted proposals
in this proceeding, some of which, if adopted by the PSC, could
adversely affect the Company.
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In December 1995 the administrative law judge (ALJ)
submitted her recommended decision to the PSC. She called for
competition to be implemented at the wholesale level with the
goal of introducing retail access as quickly as possible, but
with caution. The ALJ recommended that utilities be entitled to
present a case showing why it would be reasonable for recovery of
strandable costs to be allowed. She also advocated a "reasonable
opportunity" for consumers to realize savings and pay lower
prices.
A PSC order in this proceeding is expected in 1996. The
order is not expected to conclude the PSC's review of competition
and related issues. It is not possible to predict the outcome of
the proceeding or its impact upon the Company. See Note A to the
financial statements.
Federal Proceeding. In March 1995 the Federal Energy Regulatory
Commission (FERC) proposed new rules under which the Company and
other electric utilities would be required to file
non-discriminatory open access transmission tariffs that would be
available to wholesale sellers and buyers of electric energy, and
that would also apply to the Company's and other electric
utilities' own wholesale sales of electric energy. As proposed,
the new rules would allow utilities to recover legitimate and
verifiable wholesale stranded costs. FERC would follow this
policy with regard to costs subject to its jurisdiction and urged
the states to follow the same policy with regard to costs subject
to their jurisdictions.
It is not possible to predict the outcome of this
proceeding. The Company participates in the wholesale electric
market primarily as a buyer, and in this regard should benefit if
rules are adopted which result in lower wholesale prices for its
purchases of electricity for its retail customers.
1992 ELECTRIC RATE AGREEMENT In April 1992 the PSC approved an
electric rate agreement covering the three-year period April 1,
1992 through March 31, 1995. Under the agreement annual electric
rates were increased by $250.5 million (5.0 percent) in April
1992, by $251.2 million (5.0 percent) in April 1993 and by $55.2
million (1.1 percent) in April 1994. The agreement provided for a
rate of return on common equity of 11.50 percent for the first
rate year and 11.60 percent for the second and third rate years,
based on a common equity ratio of 52 percent. In order to settle
disputed items, including alleged excess earnings in prior years,
the Company's revenue allowance was reduced in each of the three
years by $35 million. For calendar years 1994, 1993 and 1992, the
Company accrued incentives for attaining certain objectives for
the Company's Enlightened Energy program, customer service and
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fuel costs of $116.4 million, $69.6 million and $58.1 million,
respectively, before federal income tax. For each of the three
rate years, the Company's rate of return on electric common
equity, excluding incentives and labor productivity, was below
the thresholds set in the agreement for sharing with customers.
The agreement introduced a rate-making concept known as the
Electric Revenue Adjustment Mechanism (ERAM). The purpose of the
ERAM was to eliminate the linkage between customers' energy
consumption and Company profits. Under the ERAM rates were based
on annual forecasts of electric sales and sales revenues with
refund to or recovery from customers of any overages or
deficiencies from the forecast in the prior rate year.
Implementation of the ERAM removes from Company earnings all
variations in electric sales from forecasts, including the
effects of year-to-year weather variations, the results of
changes in economic conditions, and the impact of the Enlightened
Energy program. In 1994 the Company set aside $63.7 million to be
refunded to customers for revenue overcollections under the ERAM.
In 1993 and 1992 the Company accrued $10.9 million and $130.1
million, respectively, of additional revenues to be recovered
from customers under the ERAM.
1995 ELECTRIC RATE AGREEMENT In April 1995 the PSC approved a
three-year electric rate agreement effective April 1, 1995. The
principal features of the agreement are as follows:
Limited Increases in Base Revenues. There was no increase in
base electric revenues for the first rate year of the agreement
(the twelve months ending March 31, 1996). However, differences
between actual and projected amounts for certain expense items
for each rate year will be reconciled and deferred for refund to
or recovery from customers in subsequent years. These items
include pension and retiree health and life insurance expenses,
costs incurred under IPP contracts, and certain Enlightened
Energy and renewable energy expenses. Property tax differences
will be similarly reconciled and refunded to or recovered from
customers, except that the Company will absorb (or retain) 14
percent of any property tax increase or decrease from the
forecast amounts.
For the second and third rate years, rates will also be
changed to provide for projected costs in each year of pensions
and retiree health and life insurance, IPP contracts, and the
Enlightened Energy program. Pension and postretirement benefit
costs will increase substantially in 1996, reflecting the
discount rate and health cost trend rates assumed. See Notes D
and E to the financial statements.
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Unlike previous multi-year rate agreements, there will be no
increases in rates in the second and third rate years to cover
general escalation, wage and salary increases or carrying costs
on increased utility plant investment. See "Modified ERAM" below
for revenue adjustments to reflect changes in numbers of
customers.
Return on Equity and Equity Ratio. The allowed rate of return on
common equity is 11.1 percent in the first rate year and is to be
adjusted for the second and third rate years by adding or
subtracting one-half of the change in 30-year Treasury bond rates
from a January/February 1995 base, to or from 11.1 percent. The
maximum change in the rate of return from the previous rate year
is 100 basis points (one percent). A preliminary estimate of the
indicated rate of return on equity for the second rate year is
between 10.2 and 10.4 percent. A 52 percent common equity ratio
is assumed throughout the term of the agreement.
Costs for debt and preferred stock will not be updated from
the levels projected for the first rate year.
Earnings Sharing. Following each rate year the Company's actual
return on equity will be calculated, using actual capitalization
ratios and debt and preferred stock costs, but excluding any
earnings from the incentives discussed below. The Company will
retain 100 percent of any earnings up to 50 basis points above
the allowed rate of return for that rate year. The Company will
retain 50 percent of earnings exceeding the allowed rate of
return by more than 50 basis points but not more than 150 basis
points and the balance will be deferred for customer benefit. The
Company will retain 25 percent of earnings that exceed the
allowed rate of return by more than 150 basis points; one-third
of the balance will be deferred for customer benefit and
two-thirds will be applied to reduce rate base balances in a
manner to be determined by the Company.
Due principally to increased productivity, the Company
estimates the actual rate of return on electric common equity,
excluding incentives, for the first rate year will exceed the
sharing threshold of 11.6 percent. As a result, in the fourth
quarter of 1995 the Company recorded a provision for the future
benefit of electric customers of $10.0 million, before federal
income tax.
IPP Termination Costs. The rate agreement also provides for full
recovery by the Company of all IPP contract termination costs
incurred to date, and permits the Company to petition the PSC to
defer the costs of new IPP contract terminations or
modifications, if any, during the term of the agreement.
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Incentive Provisions. The rate agreement permits the Company to
earn additional incentive amounts, not subject to the earnings
sharing provisions, by attaining certain objectives for the
Company's Enlightened Energy program, fuel costs, and customer
service. While these incentive mechanisms are similar to those
provided under the 1992 electric rate agreement, opportunities
for earning incentives are generally less than under the earlier
agreement. There would also be penalties for failing to achieve
minimum objectives, and there is a penalty-only incentive
mechanism designed to encourage the Company to maintain its high
level of service reliability.
For calendar year 1995 the Company accrued benefits of $32.7
million (including $17.1 million related to the prior year) and
$5.7 million, before federal income tax, for the Enlightened
Energy incentive and for electric customer service performance,
respectively.
Partial Pass-Through Fuel Adjustment Clause. The PPFAC incentive
is continued with certain modifications from the 1992 electric
rate agreement. For each rate year of the new agreement there
will be a $35 million cap (previously $30 million) on the maximum
incentive or penalty, with a "sub-cap" (within the $35 million
cap) of $10 million (as previously) for costs associated with
generation from the Company's Indian Point 2 nuclear unit. While
the cap is higher, the targets established for incentive earnings
are generally more difficult than under the prior agreement. For
calendar year 1995 the Company earned $19.2 million, before
federal income tax, under the PPFAC, $6.5 million of which was
earned in the first calendar quarter, under the 1992 agreement.
Modified ERAM. The agreement continues, in modified form, the
ERAM introduced in the 1992 electric rate agreement. The new
agreement adds to the ERAM a revenue per customer (RPC) mechanism
which excludes from adjustment those variances in the Company's
electric revenues which result from changes in the number of
customers in each electric service classification. In effect, the
Company will retain additional revenues attributable to added
customers, but will bear the revenue shortfall resulting from
lost customers, while other variances from forecast revenues will
be deferred for subsequent recovery from or refund to customers,
and will not affect the Company's earnings. The ERAM and the RPC
mechanism will not apply to delivery service for NYPA.
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At the end of each rate year, the forecast average annual
amount of revenue per customer in each service classification
(the RPC Factor) for that rate year is multiplied by the actual
average number of customers in that classification. The net
difference between that amount and the actual revenues from all
service classifications is deferred for refund to or recovery
from customers in the subsequent rate year; the RPC Factor for
the following rate year will be adjusted to reflect such net
difference. The RPC Factors will also be adjusted in the second
and third rate years to reflect any increase or decrease in
allowed base revenues for reconciliations and projections
discussed above in "Limited Increases in Base Revenues."
For calendar year 1995 the Company set aside $35.3 million,
before federal income tax, to be refunded to customers for
revenue overcollections under the ERAM, net of $13.3 million
earned under the RPC.
Nuclear Decommissioning Expense. See Note A to the financial
statements for changes in nuclear decommissioning expense.
Second Rate Year. In February 1996 the Company filed revisions
to its electric rates to become effective April 1, 1996 for the
second rate year, as required in the agreement. The Company
estimated that there would be no material change in rates. The
matter is pending before the PSC.
Extension of Agreement. The agreement stipulates that if the
Company abstains from filing for a general electric rate increase
to take effect at the end of the three-year period, the operation
of the rate agreement may be extended beyond March 31, 1998. Any
party to the agreement may file a petition to compel the Company
to justify continuation of the mechanisms, provisions and
formulas beyond March 31, 1998. If the agreement is extended, the
provisions for limited rate changes, adjustment of equity return,
earnings sharing, incentives, and Modified ERAM will continue in
effect until changed by the PSC.
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GAS AND STEAM RATE AGREEMENTS In October 1992 the PSC approved
two-year gas and steam rate agreements which included annual
increases for the first rate year in firm gas and steam rates of
$12.3 million (1.9 percent) and $11.8 million (3.6 percent),
respectively. In September 1993 the PSC granted the Company
permission to increase its firm gas rates for the second rate
year by $21.6 million (2.8 percent). In lieu of a steam rate
increase of $2.1 million for the second rate year, the PSC
authorized the Company to retain certain tax refunds being held
by the Company for refund to steam customers. The gas and steam
rate agreements were premised upon an allowed equity return of
11.6 percent and a common equity ratio of 52 percent of total
capitalization. Earnings above an 11.95 percent return were to be
shared equally with customers. For both rate years, the twelve
months ended September 30, 1993 and 1994, the Company's rate of
return on gas common equity was below the sharing threshold. The
Company's rate of return on steam common equity for the first and
second rate years was above the sharing threshold, and as a
result, the Company recorded a provision for refund to steam
customers of $1.7 million in 1993 and $3.6 million in 1994.
In October 1994 the PSC approved three-year rate agreements
for gas and steam services. The agreements provide for gas and
steam rate increases in the first rate year, the twelve months
ended September 30, 1995, of $7.7 million (0.9 percent) and $9.9
million (3.0 percent), respectively, and a methodology for rate
changes in the second and third rate years. For both services,
the October 1994 increases reflect a 10.9 percent rate of return
on common equity and a 52 percent common equity ratio. The
agreements contain "excess earnings" provisions giving
stockholders the benefit of 100 percent retention of any earnings
between 10.9 percent and 11.65 percent, and 50 percent sharing
with customers above 11.65 percent. The steam earnings
calculation also excludes the effects of net sales increases
related to abnormal weather, up to a maximum exclusion for
abnormal weather which is the equivalent of 25 basis points in
common equity return per year. The gas agreement contains two
incentive (or penalty) mechanisms (not subject to the "excess
earnings" provisions). In 1995 the Company accrued benefits of
$6.1 million and $1.3 million, before federal income tax, for the
gas system improvement and customer service incentives,
respectively. For the first rate year, the twelve months ended
September 30, 1995, the Company's rates of return on common
equity for gas and steam were below the threshold for sharing.
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Effective October 1, 1995 (the beginning of the second year
of the October 1994 three-year gas and steam rate agreements),
gas and steam rates were increased by $20.9 million (2.5 percent)
and $4.6 million (1.3 percent), respectively. The primary reasons
for the gas rate increase were escalation in certain operation
and maintenance expenses, return and depreciation on higher plant
balances, and recovery of earnings under the incentive provisions
of the agreement. The steam rate increase was primarily to cover
escalation in operation and maintenance expenses, and return and
depreciation on higher plant balances.
CLEAN AIR ACT AMENDMENTS The Clean Air Act amendments of 1990
impose limits on sulfur dioxide emissions from electric
generating units. Because the Company uses very low sulfur fuel
oil and natural gas as boiler fuels, the sulfur dioxide emissions
limits should not affect the Company's operations. The Company
will incur increased capital and operating costs to meet the
nitrogen oxide emissions limits set by the New York State
Department of Environmental Conservation (DEC) under the
"Reasonably Available Control Technology" (RACT) provisions of
the Clean Air Act. The Company has spent approximately $23
million to comply with the Phase I limitations. The State may
further reduce the nitrogen oxide emissions limits under Phase II
of the RACT program which is expected to take effect in 1999. New
York and nine other member states of the Northeast Ozone
Transport Commission have entered into a Memorandum of
Understanding which calls for the states to adopt more stringent
nitrogen oxide emissions limits for RACT Phases II and III,
effective in 1999 and 2003, respectively. The Company estimates
that the cost of compliance with these phases could approximate
$150 million.
NUCLEAR FUEL DISPOSAL The Company has a contract with the United
States Department of Energy (DOE) which provides that, in return
for payments being made by the Company to the DOE pursuant to the
contract, the DOE, starting in 1998, will take title to the
Company's spent nuclear fuel, transport it to a federal
repository and store it permanently. Notwithstanding the
contract, the DOE has announced that it is not likely to have an
operating permanent repository before 2015. The DOE has also
taken the position that it is not obligated to begin accepting
the spent fuel until it has an appropriate facility for such
purpose. In June 1994 the Company and a number of other utilities
petitioned the United States Court of Appeals for the District of
Columbia for a declaratory judgment that the DOE is
unconditionally obligated to begin accepting the spent fuel by
1998, an order directing the DOE to implement a program enabling
it to begin acceptance of spent fuel by 1998, and, if warranted,
- 15 -
appropriate relief for the financial burden to the utilities
resulting from the DOE's delay. The Company estimates that it now
has adequate on-site capacity until 2005 for interim storage of
its spent fuel. Absent regulatory or technological developments
by 2005, the Company expects that it will require additional
on-site or other spent fuel storage facilities. Such additional
facilities would require regulatory approvals. In the event that
the Company is unable to make appropriate arrangements for the
storage of its spent fuel, the Company would be required to
curtail the operation of its Indian Point 2 nuclear unit. See
discussion of decommissioning in Note A to the financial
statements.
SUPERFUND AND ASBESTOS CLAIMS AND OTHER CONTINGENCIES Reference
is made to Note F to the financial statements for information
concerning potential liabilities of the Company arising from the
Federal Comprehensive Environmental Response, Compensation and
Liability Act of 1980 ("Superfund"), from claims relating to
alleged exposure to asbestos, and from certain other
contingencies to which the Company is subject.
COLLECTIVE BARGAINING CONTRACT The Company's four-year
collective bargaining contract with Local No. 1-2, Utility
Workers' Union of America, which represents 66% of the Company's
employees, expires in June 1996.
IMPACT OF INFLATION The Company is affected by the decline in
the purchasing power of the dollar caused by inflation.
Regulation permits the Company to recover through depreciation
only the historical cost of its plant assets even though in an
inflationary economy the cost to replace the assets upon their
retirement will substantially exceed historical cost. However,
this is partially offset by the repayment of the Company's
long-term debt in dollars of lesser value than the dollars
originally borrowed.
- 16 -
RESULTS OF OPERATIONS
Earnings per share were $2.93 in 1995, $2.98 in 1994 and
$2.66 in 1993. The average number of common shares outstanding
for 1995, 1994 and 1993 was 234.9 million, 234.8 million and
234.0 million, respectively.
Earnings for 1995, 1994 and 1993 reflect electric, gas and steam
rate increases, and other provisions of the electric, gas and
steam rate agreements discussed above.
OPERATING REVENUES AND FUEL COSTS Operating revenues in 1995 and
1994 increased from the prior year by $163.8 million and by
$107.7 million, respectively. The principal increases and
decreases in revenue were:
Increase (Decrease)
--------------------
1995 1994
(Millions of Dollars) Over 1994 Over 1993
- -----------------------------------------------------
Electric, gas and steam
rate changes $ 29.3 $ 115.8
Fuel rider billings* 22.4 (143.3)
Sales volume changes
Electric** 41.4 56.3
Gas (11.7) 26.1
Steam (13.9) 14.4
Gas weather normalization 5.9 (5.6)
Electric:
ERAM/Modified ERAM
accruals 28.4 (74.7)
Recoveries of prior rate
year ERAM accruals 83.1 75.9
Rate refund provision (10.0) --
Off-system sales 12.5 19.8
Other (23.6) 23.0
--------------------
Total $163.8 $ 107.7
- -----------------------------------------------------
* Excludes costs of fuel, purchased power and gas purchased
for resale reflected in base rates.
** Includes Con Edison direct customers and delivery service
for NYPA and municipal agencies.
- 17 -
The increase in fuel billings in 1995 reflects higher unit
costs of purchased power, offset by lower cost of gas per therm.
The decrease in fuel billings in 1994 reflects decreases in the
unit costs of both purchased power and fuel used to produce
electricity. The cost of gas per therm was 20.2 percent lower in
1995 than in 1994 and was 10.4 percent lower in 1994 than in
1993.
Electric fuel costs decreased $56.1 million in 1995 largely
because of the Company's increased power purchases and consequent
lower generation; steam fuel costs decreased $7.6 million in 1995
due to lower sendout and lower unit cost of fuel. Electric fuel
costs in 1995 and 1994 were affected by the greater availability
in 1994 than in 1995 of lower-cost nuclear generation from the
Company's Indian Point 2 unit. During 1995 Indian Point 2
underwent a scheduled refueling and maintenance outage and the
unit's low cost generation was, therefore, unavailable for part
of the year. During 1995 the Company purchased 59 percent of its
total electric energy requirements, compared with 51 percent in
1994. Reflecting this increase, including increased purchases of
the relatively high cost power that the Company is required to
pay for under its IPP contracts, purchased power costs increased
by $319.8 million over the 1994 period. Gas purchased for resale
decreased $81.4 million in 1995, reflecting the lower unit cost
of purchased gas, offset by higher sendout.
Electricity sales volume in the Company's service territory
increased 0.7 percent in 1995 and 2.0 percent in 1994. Gas sales
volume to firm customers decreased 2.8 percent in 1995 and
increased 3.9 percent in 1994. Transportation of customer-owned
gas increased 65.3 percent in 1995 and decreased 12.1 percent in
1994, primarily due to variations in the volume of gas
transported for NYPA's use as boiler fuel at its Poletti unit.
Steam sales volume decreased 4.1 percent in 1995 and increased
4.4 percent in 1994.
The Company's electricity, gas and steam sales vary
seasonally in response to weather. Electric peak load occurs in
the summer, while gas and steam sales peak in the winter. After
adjusting for variations, principally weather and billing days,
in each period, electricity sales volume increased 1.2 percent in
1995 and 1.5 percent in 1994. Similarly adjusted, gas sales
volume to firm customers increased 0.1 percent in 1995 and 1.6
percent in 1994, and steam sales volume decreased 1.9 percent in
1995 and increased 0.6 percent in 1994. Weather-adjusted sales
represent the Company's estimate of the sales that would have
been made if historical average weather conditions had prevailed.
- 18 -
Off-system electricity sales increased to 5,035 millions of
kilowatthours (kWhrs) in 1995 compared with 1,785 millions of
kWhrs in 1994. The increase in 1995 in such sales was due largely
to arrangements in which the Company produces electricity for
others using gas they provide as fuel. The Company has purchased
a substantial portion of this electricity for sale to its own
customers.
OTHER OPERATIONS AND MAINTENANCE EXPENSES Other operations and
maintenance expenses were unchanged in 1995 and decreased 1.5
percent in 1994. For 1995 lower administrative and general
expenses and production expenses at fossil generating stations
were offset in part by higher amortization of previously deferred
Enlightened Energy program costs and higher production expenses
related to the refueling and maintenance outage of the Indian
Point 2 nuclear unit in 1995. For 1994 the decrease reflects
lower production expenses, principally due to the refueling and
maintenance outage of the Indian Point 2 nuclear unit in 1993;
there was no outage in 1994. The decrease was offset in part by
costs in connection with the settlement of an environmental
proceeding (discussed below) and higher health insurance costs.
During 1995 the Company accrued $10 million for additional
environmental investigation and site remediation costs pursuant
to a 1994 settlement of a DEC civil administrative proceeding
against the Company and $5 million for two Superfund sites. In
1994, pursuant to the DEC settlement, the Company paid a $9
million penalty and contributed $5 million to an environmental
projects fund. The penalty was charged to miscellaneous income
deductions ($2 million in 1994 and $7 million in prior years).
The payment to the environmental projects fund was charged to
operations and maintenance expenses in 1994. In addition the
Company accrued $11.5 million during 1994 for environmental
investigation and site remediation costs. See Note F to the
financial statements for additional information about the
settlement.
- 19 -
TAXES, OTHER THAN FEDERAL INCOME TAX At $1.1 billion, taxes
other than federal income tax remain one of the Company's largest
operating expenses. The principal components and variations in
operating taxes were:
Increase (Decrease)
---------------------
1995 1994
(Millions of Dollars) 1995 Over 1994 Over 1993
- --------------------------------------------------------------
Property taxes $ 534.0 $ (5.4) $(36.8)
State and local taxes
on revenues 460.3 (2.2) (6.3)
Payroll taxes 58.2 .4 (.2)
Other taxes 67.7 (.3) 11.7
---------------------------------
Total $1,120.2* $(7.5) $(31.6)
- --------------------------------------------------------------
* Including sales taxes on customers' bills, total taxes other
than federal income tax billed to customers in 1995 were
$1,413.8 million.
The reductions in property taxes in 1995 and 1994 reflect
decreases in the share of total New York City property taxes
borne by the Company. Under the terms of the current electric,
gas and steam rate agreements most of the difference between
property taxes included in rates and actual property taxes is
being deferred for future recovery from or refund to customers.
OTHER INCOME Other income increased $8.2 million in 1995 and
decreased $2.3 million in 1994. For 1995 the increase reflects
higher interest on temporary cash investments and for 1994 the
decrease reflects lower interest income accrued on ERAM revenue
deferrals under the 1992 electric rate agreement.
NET INTEREST CHARGES Interest on long-term debt increased $12.9
million in 1995 and $7.3 million in 1994 principally as a result
of new debt issues, offset to a large extent in 1994 by the
effect of debt refundings. Other interest increased $9.1 million
in 1995 principally as a result of a higher customer deposit rate
and interest associated with certain tax settlements.
FEDERAL INCOME TAX Federal income tax decreased $41.0 million in
1995 and increased $73.6 million in 1994 reflecting the changes
each year in income before tax and in tax credits. See Note H to
the financial statements.
February 27, 1996