SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8 - K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
DATE OF REPORT - MARCH 5, 1996
NIAGARA MOHAWK POWER CORPORATION
- --------------------------------
(Exact name of registrant as specified in its charter)
State of New York 15-0265555
- ----------------- ----------
(State or other jurisdiction (I.R.S. Employer
of incorporation) Identification No.)
Commission file Number 1-2987
300 Erie Boulevard West, Syracuse, New York 13202
(Address of principal executive offices) (zip code)
(315) 474-1511
Registrant's telephone number, including area code
NIAGARA MOHAWK POWER CORPORATION
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Item 5. Other Events.
Registrant hereby files the following items which will constitute
a portion of its 1995 Annual Report to Stockholders:
- - Highlights
- - Market for the Registrant's Common Equity and Related
Stockholder Matters
- - Selected Consolidated Financial Data for the five years ended
December 31, 1995
- - Management's Discussion and Analysis of Financial Condition
and Results of Operations
- - Report of Management
- - Report of Independent Accountants
- - Consolidated Statements of Income and Retained Earnings for
each year in the three-year period ended December 31,
1995
- - Consolidated Balance Sheets at December 31, 1995 and 1994
- - Consolidated Statements of Cash Flows for each year in the
three-year period ended December 31, 1995
- - Notes to Consolidated Financial Statements
- - Electric and Gas Statistics
Item 7. Financial Statement, Proforma Financial Information and
Exhibits.
Exhibit 11 - Computation of Average Number of Shares of Common
Stock Outstanding
Exhibit 12 - Statements Showing Computations of Certain Financial
Ratios
Exhibit 23 - Accountant's Consent
Exhibit 27 - Financial Data Schedule
Signature
%
HIGHLIGHTS 1995 1994 CHANGE
- ----------------------------------------------------------------
Total operating revenues $ 3,917,338,000 $ 4,152,178,000 (5.7)
Income available for
common stockholders $ 208,440,000 $ 143,311,000 45.4
Earnings per common share $ 1.44 $ 1.00 44.0
Dividends per common share $ 1.12 $ 1.09 2.8
Common shares outstanding
(average) 144,329,000 143,261,000 0.7
Utility plant (gross) $10,649,301,000 $10,485,339,000 1.6
Construction work in
progress $ 289,604,000 $ 481,335,000 (39.8)
Gross additions to
utility plant $ 345,804,000 $ 490,124,000 (29.4)
Public kilowatt-hour
sales 33,228,000,000 34,006,000,000 (2.3)
Total kilowatt-hour
sales 37,684,000,000 41,599,000,000 (9.4)
Electric customers at
end of year 1,568,000 1,559,000 0.6
Electric peak load
(kilowatts) 6,211,000 6,458,000 (3.8)
Natural gas sales to
ultimate customers
(dekatherms) 78,481,000 85,615,000 (8.3)
Natural gas transported
(dekatherms) 144,613,000 85,910,000 68.3
Gas customers at
end of year 518,000 512,000 1.2
Maximum day gas
deliveries
(dekatherms) 1,211,252 995,801 21.6
/TABLE
MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The Company's common stock and certain of its preferred
series are listed on the New York Stock Exchange (NYSE). The
common stock is also traded on the Boston, Cincinnati, Midwest,
Pacific and Philadelphia stock exchanges. Common stock options
are traded on the American Stock Exchange. The ticker symbol is
"NMK."
Preferred dividends were paid on March 31, June 30,
September 30 and December 31. Common stock dividends were paid
on February 28, May 31, August 31 and November 30. The Company
estimates that none of the 1995 common or preferred stock
dividends will constitute a return of capital and therefore all
of such dividends are subject to Federal tax as ordinary income.
The table below shows quoted market prices (NYSE) and
dividends per share for the Company's common stock:
DIVIDENDS PAID PRICE RANGE
1995 PER SHARE HIGH LOW
- --------------------------------------------------------------
1st Quarter $.28 $15 5/8 $13 3/8
2nd Quarter .28 15 1/8 13 5/8
3rd Quarter .28 14 3/4 11 1/4
4th Quarter .28 13 3/8 9 1/2
1994
- --------------------------------------------------------------
1st Quarter $.25 $20 5/8 $17 3/4
2nd Quarter .28 19 14 5/8
3rd Quarter .28 17 1/2 12
4th Quarter .28 14 3/8 12 7/8
On January 25, 1996, the board of directors omitted the
common stock dividend for the first quarter of 1996. This action
was taken to help stabilize the Company's financial condition and
provide flexibility as the Company addresses growing pressure
from mandated power purchases and weaker sales. See
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" below. In making future dividend
decisions, the board will evaluate, along with standard business
considerations, the level and timing of future rate relief, the
progress of renegotiating contracts with unregulated generators
(UGs) within the context of its PowerChoice proposal, the degree
of competitive pressure on its prices, and other strategic
considerations.
OTHER STOCKHOLDER MATTERS: The holders of common stock are
entitled to one vote per share and may not cumulate their votes
for the election of Directors. Whenever dividends on preferred
stock are in default in an amount equivalent to four full
quarterly dividends and thereafter until all dividends thereon
are paid or declared and set aside for payment, the holders of
such stock can elect a majority of the board of directors.
Whenever dividends on any preference stock are in default in an
amount equivalent to six full quarterly dividends and thereafter
until all dividends thereon are paid or declared and set aside
for payment, the holders of such stock can elect two members to
the board of directors. No dividends on preferred stock are now
in arrears and no preference stock is now outstanding. Upon any
dissolution, liquidation or winding up of the Company's business,
the holders of common stock are entitled to receive a pro rata
share of all of the Company's assets remaining and available for
distribution after the full amounts to which holders of preferred
and preference stock are entitled have been satisfied.
The indenture securing the Company's mortgage debt provides
that retained earnings shall be reserved and held unavailable for
the payment of dividends on common stock to the extent that
expenditures for maintenance and repairs plus provisions for
depreciation do not exceed 2.25% of depreciable property as
defined therein. Such provisions have never resulted in a
restriction of the Company's retained earnings.
At year end, there were approximately 84,600 holders of
record of common stock of the Company and about 5,700 holders of
record of preferred stock. The chart below summarizes common
stockholder ownership by size of holding:
SIZE OF HOLDING TOTAL STOCKHOLDERS TOTAL SHARES HELD
(SHARES)
- -----------------------------------------------------------------
1 to 99 34,975 977,436
100 to 999 44,871 11,155,890
1,000 or more 4,780 132,198,797
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84,626 144,332,123
====== ===========
/TABLE
SELECTED CONSOLIDATED FINANCIAL DATA
The following table sets forth selected financial information of the Company for each of
the five years during the period ended December 31, 1995, which has been derived from the
audited financial statements of the Company, and should be read in connection therewith.
As discussed in "Management's Discussion and Analysis of Financial Condition and Results
of Operations" and "Notes to Consolidated Financial Statements," the following selected
financial data may not be indicative of the Company's future financial condition or
results of operations:
1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------------------
Operations: (000's)
Operating revenues $ 3,917,338 $ 4,152,178 $ 3,933,431 $ 3,701,527 $ 3,382,518
Net income 248,036 176,984 271,831 256,432 243,369
- ------------------------------------------------------------------------------------------
Common stock data:
Book value per share
at year end $17.42 $17.06 $17.25 $16.33 $15.54
Market price at
year end 9 1/2 14 1/4 20 1/4 19 1/8 17 7/8
Ratio of market price to
book value at year end 54.5% 83.5% 117.4% 117.1% 115.0%
Dividend yield at year end 11.8%* 7.9% 4.9% 4.2% 3.6%
Earnings per average
common share $1.44 $1.00 $1.71 $1.61 $1.49
Rate of return on common
equity 8.4% 5.8% 10.2% 10.1% 10.0%
Dividends paid per
common share $1.12* $1.09 $ .95 $ .76 $ .32
Dividend payout ratio 77.8%* 109.0% 55.6% 47.2% 21.5%
- ------------------------------------------------------------------------------------------
Capitalization: (000's)
Common equity $ 2,513,952 $ 2,462,398 $ 2,456,465 $ 2,240,441 $ 2,115,542
Non-redeemable
preferred stock 440,000 440,000 290,000 290,000 290,000
Mandatorily redeemable
preferred stock 96,850 106,000 123,200 170,400 212,600
Long-term debt 3,582,414 3,297,874 3,258,612 3,491,059 3,325,028
- ------------------------------------------------------------------------------------------
TOTAL 6,633,216 6,306,272 6,128,277 6,191,900 5,943,170
Long-term debt maturing
within one year 65,064 77,971 216,185 57,722 175,501
- ------------------------------------------------------------------------------------------
TOTAL $ 6,698,280 $ 6,384,243 $ 6,344,462 $ 6,249,622 $ 6,118,671
- ------------------------------------------------------------------------------------------
Capitalization ratios: (including long-term debt maturing within one year)
Common stock equity 37.5% 38.6% 38.7% 35.8% 34.6%
Preferred stock 8.0 8.5 6.5 7.4 8.2
Long-term debt 54.5 52.9 54.8 56.8 57.2
- ------------------------------------------------------------------------------------------
Financial ratios:
Ratio of earnings to
fixed charges 2.29 1.91 2.31 2.24 2.09
Ratio of earnings to
fixed charges
without AFC 2.26 1.89 2.26 2.17 2.03
Ratio of AFC to balance
available for
common stock 4.3% 6.3% 6.8% 9.7% 9.3%
Ratio of earnings to
fixed charges and
preferred stock
dividends 1.90 1.63 2.00 1.90 1.77
Other ratios - % of
operating revenues:
Fuel, purchased
power and purchased
gas 40.3% 39.6% 36.1% 34.1% 32.1%
Other operation
expenses and maintenance 20.9 23.1 26.9 26.3 27.6
Depreciation and
amortization 8.1 7.4 7.0 7.4 7.7
Total taxes, including
real property, income
and revenue taxes 17.3 14.7 16.2 17.3 16.4
Operating income 13.5 10.4 13.3 14.2 15.5
Balance available for
common stock 5.3 3.5 6.1 5.9 6.0
- ------------------------------------------------------------------------------------------
Miscellaneous: (000's)
Gross additions to
utility plant $ 345,804 $ 490,124 $ 519,612 $ 502,244 $ 522,474
Total utility plant 10,649,301 10,485,339 10,108,529 9,642,262 9,180,212
Accumulated depreciation
and amortization 3,641,448 3,449,696 3,231,237 2,975,977 2,741,004
Total assets 9,477,869 9,649,816 9,471,327 8,590,535 8,241,476
==========================================================================================
* On January 25, 1996, the Board of Directors omitted the common stock dividend.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
- ---------------------
OVERVIEW
Earnings in 1995 were $208.4 million or $1.44 per share.
Earnings in 1994 were $143.3 million or $1.00 per share and
included $101.2 million or 46 cents per share of electric margin
recorded under the Niagara Mohawk Electric Revenue Adjustment
Mechanism (NERAM), as well as a charge of about $197 million (89
cents per share) for nearly all of the cost of the Voluntary
Employee Reduction Program (VERP). NERAM was a surcharge which
assured that the Company's margin on electric sales would equal
the margin assumed in establishing rates. In January 1995 NERAM
was discontinued. 1995 earnings were negatively impacted by
lower sales of electricity and natural gas, compared to amounts
used to establish 1995 prices, due primarily to continuing weak
economic conditions in upstate New York, loss of industrial load
to New York Power Authority (NYPA) and discounts. However, cost
reduction efforts begun in 1994 through the VERP helped 1995
earnings. The Company's 1995 earned return on common equity was
8.4%, which was below the 11.0% that the New York State Public
Service Commission (PSC) authorized on electric utility
operations due to, among other things: sales below those forecast
in determining rates; about $20 million of negotiated customer
discounts in excess of the approximately $42 million reflected in
rates; the inability to achieve stringent wholesale margin
targets set by the PSC; and fuel target penalties caused by low
hydro production due to dry weather. The Company expects the
trend of weak sales to continue, given the poor economic
condition of the Company's service territory.
In the long term, the Company's earnings will depend
substantially on the outcome of the Company's PowerChoice
proposal discussed below, which was filed with the PSC in October
1995. The Company filed for price increases of 4.1% for 1996 and
4.2% for 1997 and earnings for these years will depend on the
outcome of the rate requests. The 1996 rate filing is for
temporary rate relief for which the Company has asked for
immediate action. On February 16, 1996, the PSC issued an order
that, among other things, established a schedule with respect to
temporary rates that would have the case certified directly to
the PSC within 60 days of the order. The 1997 filing will
preserve the Company's right to traditional cost-based rates in
the event that an acceptable regulatory solution cannot be
achieved through negotiation of the PowerChoice proposal. While
negotiations are continuing on PowerChoice, in view of increasing
UG payments, discounts and continued weak sales expectations, the
Company has found it necessary to seek these price increases.
Without any form of rate relief in 1996 and 1997, the Company
would expect to earn a return on equity substantially below that
earned in 1995. The Company is implementing additional
reductions in non-essential programs (not related to safety and
reliability) to reduce costs.
On January 25, 1996, the board of directors omitted the
common stock dividend for the first quarter of 1996. This action
was taken to help stabilize the Company's financial condition and
provide flexibility as the Company addresses growing pressure
from mandated power purchases and weaker sales. In making future
dividend decisions, the board will evaluate, along with standard
business considerations, the level and timing of future rate
relief, the progress of renegotiating contracts with UGs within
the context of its PowerChoice proposal, the degree of
competitive pressure on its prices, and other strategic
considerations.
Following the announcement of the PowerChoice proposal,
Standard & Poor's (S&P) and Moody's Investors Service (Moody's)
downgraded all of the Company's credit ratings to "below
investment grade," and placed the Company's securities on "Credit
Watch" with negative implications. The downgrade of the
Company's security ratings reflects concerns regarding the
uncertainty and potential negative impact of the PowerChoice
proposal on the Company, as well as the potential for bankruptcy.
The Company is committed to pursuing PowerChoice as a positive
response to competitive threats and to stabilize and improve the
financial condition of the Company. The Company will also
consider pursuing other actions, such as requesting rate relief
or evaluating solutions other than PowerChoice, to maintain the
financial viability of the Company.
Due, in part, to the negative response to the PowerChoice
proposal from rating agencies, the prices of the Company's common
stock, preferred stock and bonds declined sharply. The
downgrading of the Company's bonds can be expected to make it
more difficult and expensive for the Company to finance in the
manner it has used in the past. Consequently, the Company is
borrowing under its bank revolving credit agreement. In order to
further satisfy anticipated financing needs, including those
which may be necessary as a result of potential changes to the
structure of New York State electricity markets, the Company is
currently renegotiating its bank credit facilities and filed a
petition with the PSC in December 1995 for authority to enter
into a senior debt facility. The proposed senior debt facility
totals $815 million and would consolidate and replace certain of
the Company's existing working capital lines of credit and letter
of credit facilities, as well as provide additional reserves of
bank credit. There can be no assurance that the Company will be
successful in putting this facility in place; in the event the
facility is not completed, the Company believes that the
elimination of the common dividend, the implementation of
reductions in non-essential programs and the year-end 1995 cash
position, in combination with alternative sources of credit the
Company believes are available if necessary, will be sufficient
to fund cash requirements for 1996. Current market conditions
preclude the Company from issuing stock in 1996 due to the
downgrading of the Company's security ratings. (See "FINANCIAL
POSITION, LIQUIDITY AND CAPITAL RESOURCES").
The Company faces significant challenges in its efforts to
maintain its financial condition in the face of expanding
competition and weak sales. While utilities across the nation
must address these concerns to varying degrees, the Company
believes that it is more financially vulnerable than others to
competitive threats. The factors contributing to this
vulnerability include a large industrial customer base,
accounting for about 21% of total electric Kwh sales, an
oversupply of high cost mandated power purchases from UGs, an
excess supply of wholesale power at relatively low prices, a high
tax burden, a stagnant economy in the Company's service territory
and significant investments in nuclear plants. Moreover, solving
the problems the Company faces, including the implementation of
PowerChoice, requires the cooperation and agreement of third
parties. Accordingly, the outcome cannot be assured and the
possibility of restructuring under Chapter 11 of the U.S.
Bankruptcy Code cannot be ruled out.
The following sections present an assessment of competitive
conditions and steps being taken to improve the Company's
strategic and financial condition.
CHANGING COMPETITIVE ENVIRONMENT
The accelerating pace of competition is driving dramatic
changes throughout the utility industry. In addition, the
Company is challenged by state-imposed burdens, especially state-
mandated contracts that require the Company to buy electricity
from UGs in amounts that exceed customer needs and at prices that
are above the Company's own cost of providing electricity. In
addition, the Company and other New York utilities bear an
excessive tax burden that is more than twice the average for
utilities nationwide.
The Company has pursued a number of actions to mitigate the
impact of these factors on prices. These actions have included
renegotiating and buying out some UG contracts and canceling
others when contract terms were not being adhered to. The
Company has also been actively seeking reductions in its state
and local tax obligations. Nevertheless, mandated UG purchases
and high taxes have combined to create an irrational energy
market in the Company's service territory - despite an oversupply
of generating capacity, prices are rising. Further price
increases would make it more difficult for the Company to retain
its customers in the longer term and an increasing number of
customers are pursuing other supply options including self-
generation, alternate supply sources, and municipalization. As a
result, electric margins are narrowing and sales are eroding,
damaging the Company's financial condition and putting further
pressure on the Company to seek even more rate increases under
traditional cost-of-service ratemaking.
The Company has responded to these factors by, among other
actions, sharply reducing internal costs. The Company has
reduced the size of its work force by about 3,200 employees, or
27%, in the past three years, and has eliminated, consolidated or
modernized many of its operations. The Company has also sharply
reduced capital spending. Electric construction spending in
future years is expected to be limited to the level of
depreciation expense, thereby resulting in little growth in rate
base.
These cost control efforts have produced significant
savings. However, the savings are being outpaced by continuing
escalation in the externally imposed costs discussed above.
Recognizing that major changes in the electricity marketplace in
New York State were needed, the Company undertook an exhaustive
analytical process with the goal of creating a rational energy
market that would link supply, demand and price, provide
customers with better and broader services, and provide greater
opportunities for building shareholder value. That process
resulted in the filing of the Company's PowerChoice proposal on
October 6, 1995.
PowerChoice is the Company's proposal for stable retail
prices, customer choice and an open, competitive electric
generation market. The proposal includes, among other things, a
five-year price freeze for residential and commercial customers,
a price cut for industrial customers to help create jobs and spur
economic activity, and restructuring of the Company's businesses.
The Company would separate its electrical generation operations,
along with the UG contracts not restructured, into a different
company that would compete in a deregulated power market. The
remaining company would have regulated and unregulated
subsidiaries that would transmit and distribute power and engage
in new business opportunities with growth potential.
The Company believes that PowerChoice is the best course of
action to deal with emerging competition and address the factors
that have been pushing up prices. However, the success of
PowerChoice and its associated price freeze depends upon the
willingness of UGs and the Company to make substantial reductions
in embedded costs (i.e., sunk generation costs, regulatory assets
and future obligations under UG contracts). In addition, the
Company believes that the state must play a role in reducing
costs, particularly by reducing or eliminating the state gross
receipts tax, which taxes revenue rather than income. State
involvement with the Company's nuclear plants would also be
needed for all aspects of the plan to succeed and achieve a price
freeze. Addressing these issues will be difficult and will
almost certainly require judicial, regulatory and/or legislative
action. However, the Company believes that the implementation of
PowerChoice is achievable.
When PowerChoice was announced, the Company said that
failure to approve the plan would mean continued price escalation
under traditional regulation, or failing that, further
deterioration in the Company's financial condition. The Company
filed for price increases of 4.1% for 1996 and 4.2% for 1997 and
earnings for these years depend on the outcome of the rate
requests. The 1996 rate filing is for temporary rate relief for
which the Company has asked for immediate action. On February
16, 1996, the PSC issued an order that, among other things,
established a schedule with respect to temporary rates that would
have the case certified directly to the PSC within 60 days of the
order. The 1997 filing will preserve the Company's right to
traditional cost-based rates in the event that an acceptable
regulatory solution cannot be achieved through negotiation of the
PowerChoice proposal. While negotiations are continuing on
PowerChoice, in view of increasing UG payments, discounts and
continued weak sales expectations, the Company has found it
necessary to seek these price increases. The Company expects
that the PSC will approve cost-of-service based rate increases
until such time as implementation of a new competitive market
model becomes probable.
The Company's current electricity and gas prices reflect
traditional utility regulation. As such, the Company's
electricity prices include state-mandated purchased power costs
from UGs, at costs far exceeding the Company's actual avoided
costs, as well as the costs of high taxes in New York. Without
legislative or regulatory action, the Company is severely limited
in its ability to control or reduce these purchased power costs
and taxes, which are major causes of the Company's recent
increases in prices.
While the Company is experiencing rising prices, rapid
technological advances are significantly reducing the price of
new generation and significantly improving the performance of
smaller scale generating unit technology. In addition, the
current excess supply of generating capacity has driven down the
prices a competitive market would support. Actions taken by
other utilities throughout the country to lower their prices,
including those in areas with already relatively low prices,
increase the threat of industrial relocation and the need to
offer discounts to industrial customers.
The Company continues to take aggressive action to both
prevent the loss of certain industrial customers, and to attract
new business. In 1995, the Company granted approximately $62
million of discounts. Discounts are expected to increase in 1996
and 1997, but will depend on energy price levels in the
marketplace and other competitive activity. (See "Customer
Discounts").
The Company also faces the continued threat of
municipalization. A growing number of municipalities within the
Company's service territory are investigating the possibility of
acquiring less expensive sources of electricity by forming their
own utility operations. If successfully established as
legitimate wholesale entities, these new utilities would have
open access to transmission and would be able to by-pass the
Company's generation system. The municipalities exploring this
possibility are generally in the early stages of inquiry and
represent a small percentage of Company sales. Municipalization
has the potential to adversely affect the Company's customer base
and profitability, although rules proposed by the Federal Energy
Regulatory Commission (FERC), as discussed below, would greatly
mitigate any negative economic effects on the Company.
POWERCHOICE PROPOSAL
The PSC's 1995 rate order directed the Company and other
interested parties to address several key issues regarding long-
range rate proposals. These issues were to include: improving
the Company's competitive position by addressing uneconomic
utility generation and the high price of many UG contracts;
eliminating, if possible, the fuel adjustment clause and other
billing mechanisms; addressing property tax issues with local
authorities; improving operating efficiency; and identifying
governmental mandates that are no longer warranted in a
competitive environment. No proposal under this directive could
create anti-competitive effects or lead to a deterioration in
safe and adequate service. The PSC also said any multi-year plan
should ensure that the Company has an investment-grade bond
rating (although the Company is currently below investment
grade), and include protection for low-income customers.
Finally, the PSC directed that the plan should propose changes in
the regulatory approach for the Company that support fair
competition in the electric generation market consistent with the
PSC's determination in its generic competitive opportunities
proceeding (COPS), discussed below.
Following the PSC's directives, the parties engaged in a
collaborative process in which the Company has made a series of
presentations describing its views of the transition to
competition and the options it presents the Company.
On October 6, 1995, the Company filed its PowerChoice
proposal with the PSC. The proposal was offered as an integrated
package (although certain details are subject to modification)
and included these key elements:
* CREATION OF A COMPETITIVE WHOLESALE ELECTRICITY MARKET AND
DIRECT ACCESS BY RETAIL CUSTOMERS. To give customers their
choice of power suppliers and pricing terms, the Company
will open its system to competing electricity generators as
early as 1997. The timing of full implementation depends on
resolution of technical, administrative and regulatory
issues. Envisioned is the formation of a competitive
wholesale spot market in the Company's service area under
the supervision of the FERC that is consistent with
proposals announced October 5, 1995 by the Energy
Association of New York. Beginning in 1997 with its largest
customers, the Company would allow full direct access to
alternative suppliers of electricity. The Company would
deliver that power over its transmission and distribution
system. Access for the remaining customers would be phased
in over the years 1997-2000.
* SEPARATION OF THE COMPANY'S POWER GENERATION BUSINESS. The
Company has initially proposed that one company would own
and operate its present power plants and any unregulated
generator contracts that are not restructured. All the
Company's assets and businesses other than generation would
be held by a holding company that would provide cost-based
rate regulated transmission, distribution and gas services
through a regulated subsidiary and through a second
subsidiary would provide competitive unregulated services,
such as energy marketing and other services. Both companies
would be financially restructured so that stockholders and
other constituencies would be treated in a fair and
equitable fashion. Any release of assets under the
Company's mortgage indenture would involve the substitution
of other collateral of equivalent value. The Company
believes NYPA or New York state can be helpful in this
restructuring process, through the purchasing or refinancing
of the Company's nuclear plants or through the use of other
risk-mitigation strategies associated with those facilities.
* RELIEF FROM OVERPRICED UNREGULATED GENERATOR CONTRACTS THAT
WERE MANDATED BY PUBLIC POLICY, ALONG WITH EQUITABLE WRITE-
DOWNS OF ABOVE-MARKET COMPANY ASSETS. As a result of state
and federal policy, the Company entered into over 220
contracts, of which there are over 150 remaining, to buy
power from UGs at above-market prices, even when the power
is not needed. The Company's payments to UGs have increased
from less than $200 million in 1990 to nearly $1 billion in
1995, and will continue to grow by an average of
approximately $60 million per year over the next five years
as contract prices increase. To create an open and
competitive market and achieve a price freeze, the Company
has offered to negotiate new contracts with UGs.
If negotiations fail, the Company has proposed to take
possession of these projects and compensate their owners
through the Company's power of eminent domain. The Company
would then resell the projects, allowing the projects to
sell electricity into the competitive pool at market prices.
Some of the costs related to the Company and UGs that would
be "stranded" or unrecoverable in a competitive market would
be written off (see discussion below). The remaining
stranded costs would be recovered through a contract with
the distribution company which, in turn, would recover these
costs through a generally non-bypassable fee tied to
distribution services.
* A PRICE FREEZE OR CUT FOR ALL CUSTOMER CLASSES. If the
proposal is agreed to by all necessary parties, the average
prices paid by residential and commercial class customers
could be frozen for five years. Prices for industrial
customers, who now subsidize other customers, would be
reduced.
The price freeze and restructuring of the Company's markets
and business envisioned in the PowerChoice proposal are
contingent on substantial cost reductions, which depend in turn
on the willingness of the UGs and the Company to absorb the
losses required to make substantial reductions in the Company's
embedded cost structure. The Company's PowerChoice proposal
would reduce its embedded cost structure through substantial
write-downs if, and only if, the UGs agree to cost reductions
that are proportional to their relative responsibility for
strandable costs. The Company proposes that reduction in its
fixed costs of service be made by mutual contribution of the
Company's shareholders and UGs that are in the same proportion as
the contribution of each to the problem of strandable costs,
which the Company calculates to be $4 of UG strandable cost for
every $1 of Company strandable cost. Achieving a five-year price
freeze, as the Company proposes, would require financial
concessions of approximately $2 billion (in nominal dollars) over
five years, consisting of approximately $400 million by the
Company and $1.6 billion by the UGs. The Company has proposed
that the remaining strandable costs be recoverable by the Company
and the UGs through surcharges on rates for remaining
distribution and transmission services. To ensure full recovery
of these costs, the Company has proposed that the remaining
strandable costs be recovered in rates in a manner which
minimizes the Company's exposure due to sales volume variations.
Recovery of remaining strandable costs by the new owner of the
Company's generation facilities is intended to be structured so
as not to impede each unit from being an efficient participant in
the competitive generation market.
The Company is also pursuing other courses of action to
support the objectives of restructuring. The Company filed a
petition with the PSC in December 1995 seeking an order that
certain projects post firm security to ensure performance of
their obligations (see "Demand for Adequate Assurance"). The
Company is also actively pursuing various forms of tax relief
(see "Tax Initiatives"). The timely and successful
implementation of PowerChoice, including, most importantly, the
restructuring of the energy market and of UG contracts, will most
likely occur only through negotiations and with the full and
active support of the state. The Company is actively negotiating
the PowerChoice proposal with a broad range of interested
parties. Separate negotiations are also under way with the UGs
and involve state representatives. Alternatives to PowerChoice
may be proposed during negotiations that could, in the Company's
view, be in the best interests of shareholders, customers and
bondholders. The outcome of PowerChoice and the Company's other
initiatives cannot be assured and the possibility of
restructuring under Chapter 11 of the U.S. Bankruptcy Code cannot
be ruled out.
Under PowerChoice, the successor to all the Company's assets
and businesses other than generation would be an unregulated
holding company that would provide cost-based rate regulated
transmission, distribution and gas services through one
subsidiary and would provide through a second subsidiary
competitive unregulated services, such as energy marketing and
other services. The Company believes the regulated subsidiary
would continue to account for its assets and costs, based on
ratemaking conventions as approved by the PSC and FERC, and in
accordance with Statement of Financial Accounting Standards No.
71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS No. 71).
Effective for the year commencing January 1, 1996, this
accounting standard, under which the Company reports its
financial condition and results of operations, is amended by
Statement of Financial Accounting Standards No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of" (SFAS No. 121). As discussed in Note 2 of
Notes to Consolidated Financial Statements, the Company believes
there is no impairment of its investment in generating plant
assets under the provisions of SFAS No. 121 under either the
PowerChoice proposal or traditional cost-based ratemaking.
As further discussed in Note 2 of Notes to Consolidated
Financial Statements, the Company believes that it continues to
meet the requirements for application of SFAS No. 71 and that its
regulatory assets are currently probable of recovery in future
rates charged to customers. However, the Company's PowerChoice
proposal described above (or a similar proposal) may require a
write off of the approximately $400 million of regulatory assets
related to generation. There are a number of events that could
change these conclusions in 1996 and beyond, which could result
in material adverse effects on the Company's financial condition
and results of operations.
MULTI-YEAR GAS RATE PROPOSAL. The Company also filed a
proposal to adopt a "performance-based regulation" mechanism,
including a gas cost incentive mechanism, for its gas operations.
The proposal provides for a complete unbundling of the Company's
sales service, allowing customers to choose alternative gas
suppliers. Increases for gas distribution services would be
subject to a price index through the year 2000. The price index,
which is based on inflation associated with gas service-related
costs, would be applied to existing 1995 prices after
consideration of the service restructuring. A gas cost incentive
mechanism is also being proposed, along with discontinuation of
the weather normalization clause. Flexibility in pursuing
unregulated opportunities related to the gas business is also
being sought. In November 1995, the Company filed for a 5.8% gas
rate increase, under traditional cost-based regulation, in the
event negotiations on the multi-year gas rate proposal are
unsuccessful. If approved, such rates would become effective on
October 1, 1996. In either case, the Company believes its gas
operations will continue to be cost-of-service rate regulated.
FEDERAL AND STATE REGULATORY INITIATIVES
FERC NOPR on Stranded Investment. In March 1995, the FERC
issued two notices of proposed rulemaking (NOPR) to facilitate
the development of competitive wholesale electric markets by
opening up transmission services and to address the transition
costs, or "stranded costs," associated with open transmission
access. Stranded costs are utility costs that may become
unrecoverable due to a change in the regulatory environment.
In a supplemental NOPR on stranded costs, the FERC has
established the principle that utilities are entitled to the full
recovery of "legitimate, prudent, and verifiable" stranded costs
at both the state and federal level. The NOPR also concludes
that the FERC should be the principal forum for addressing the
recovery of stranded costs due to potential municipalization or
similar situations where former retail customers become wholesale
customers, as well as for wholesale stranded costs. For stranded
costs that result from retail wheeling, the FERC proposes that
state regulatory authorities assume responsibility, except in the
narrow circumstance where state regulatory authorities lack the
authority to address the recovery of such costs.
The FERC continues to seek comments with respect to the
complex issues raised by power pools. The New York Power Pool
(NYPP), of which the Company is a member, is actively evaluating
the effect of wholesale competition and the NOPR on NYPP
operations and pricing policies. While changes to existing NYPP
arrangements are expected, the extent and nature of these changes
and their possible effects on the Company are uncertain.
The Company responded to the NOPR, both individually and as
a member of several utility groups, in support of the FERC's
position with respect to the recovery of stranded costs caused by
wholesale and retail wheeling, but has urged the FERC not to
abdicate its responsibility for retail stranded costs. It is
anticipated that a final rule will be issued in 1996. The
Company cannot predict the outcome of this matter or its effects
on the Company's results of operations or financial condition.
PSC COMPETITIVE OPPORTUNITIES PROCEEDING - ELECTRIC. In
June 1994, the PSC instituted Phase II of COPS with the overall
objective "to identify regulatory and ratemaking practices that
will assist in the transition to a more competitive electric
industry designed to increase efficiency in the provision of
electricity while maintaining safety, environmental
affordability, and service quality goals." In a June 1995 order,
the PSC adopted principles to guide the transition to
competition. The first principle states that competition in the
electric power industry will further the economic and
environmental well-being of New York state. Other adopted
principles address various issues, including: safety and
reliability, customer service, economic efficiency, economic
development and stranded costs. The June 1995 order stated that
utilities should have a reasonable opportunity to recover prudent
and verifiable expenditures and commitments made pursuant to
their legal obligations, consistent with all of the principles.
In addition, the June 1995 order encourages "respect" for the
reasonable expectations of UGs and confirms the need for
utilities and UGs to share responsibility for mitigating the
costs of transition to a more competitive market. Issues related
to both wholesale and retail competition are being examined in
this proceeding.
On October 25, 1995, the PSC staff filed a proposal in COPS
to restructure New York State's electric industry. Under the
PSC staff's proposal, which is similar in many respects to the
Company's PowerChoice proposal, utilities and UGs would share the
responsibility for reducing the current high electric system
costs. The PSC staff proposed that electric utilities would
absorb a portion of their current generation investments that
might become "stranded" or unrecoverable in a competitive market
and that the UGs would need to cooperatively restructure their
high-cost power contracts with utilities. In addition, the PSC
staff's proposal would allow customers to choose among competing
energy suppliers, beginning the transition to a competitive
retail market by early 1998. A key element of the model for
wholesale and retail competition in the proposal is the
separation of most generating operations from transmission and
distribution services. However, it recommended that the electric
delivery system, which includes substations, power lines and a
central power pool, continue to be operated by regulated
entities. The Company's PowerChoice proposal includes the
separation of generation from transmission and distribution into
distinct entities.
In December 1995, the New York PSC Administrative Law Judge
(ALJ) issued a recommended decision in COPS (ALJ plan), which is
similar in many respects to the Company's PowerChoice proposal.
The ALJ plan includes a competitive model in which an Independent
System Operator (ISO) would oversee a spot market of electricity
supplied by generators competing in an open market which would be
functionally separated from other utility functions. The ISO
would dispatch generators selling into the spot market and
acquire services needed to maintain reliability.
The ALJ plan recommends that competition initially be
limited to the wholesale level, largely because of concerns about
the reliability of electricity supply. If wholesale competition
works, the state would extend competition to the retail level.
As with the PowerChoice proposal, transmission and
distribution would remain regulated. Consideration would be
given, during the wholesale phase, to the development of
effective competition among energy service companies.
In addition, the ALJ plan calls for a non-bypassable "wire
charge" to be imposed by distribution companies to help utilities
recover "strandable" costs. It advocates generic rules for
defining and measuring such costs, requirements for possible
reductions, a preferable recovery mechanism, and a standard for
recovery. The actual amount of stranded costs to be recovered by
each utility, and the timing of recovery, would be left to
individual rate cases, to begin in 1996 if the ALJ plan is given
final approval. The ALJ plan requires that strandable costs be
determined to be prudent, verifiable and incapable of being
reduced before recovery is allowed. The ALJ further suggests
that a careful balancing of customer and utility interests and
expectations is necessary, and the level of strandable cost
recovery may vary utility by utility.
The Company responded to the ALJ plan, as a member of the
Energy Association of New York State (Energy Association). The
Energy Association includes the Company and seven other investor
owned utilities as members. The Energy Association expressed
concern that the ALJ's plan might not allow utilities a
reasonable opportunity to fully recover strandable costs and
noted the failure of the plan to address and recommend lawful
changes which would make possible reductions in electric prices,
both in the short and long term.
After a comment period, the Commissioners will review the
ALJ plan and other plans submitted by interested parties, and
ultimately accept, modify or reject it. A decision is expected
by mid-1996.
ASSEMBLYMAN SILVER'S PROPOSED PLANS. New York State
Assembly Speaker Sheldon Silver introduced a plan on January 2,
1996, that would freeze electric rates immediately and set a goal
of cutting them 25% through the introduction of competition among
utilities. Key components of the proposal include assurances
that reliability, quality and safety levels are maintained, the
dislocation of utility workers is minimized, no guarantee of
stranded cost recovery, a reduction in the costs of UGs and the
continued encouragement of environmental protection efforts.
Utilities would be required to divest generation by 2002. The
Company is unable to predict whether legislation will be
introduced in support of this plan, and if introduced and
enacted, the effect, if any, on the Company's financial condition
and results of operations.
FERC ORDER 636 AND PSC COMPETITIVE OPPORTUNITIES PROCEEDING
- - GAS. Portions of the natural gas industry have undergone
significant structural changes in recent years. A major
milestone in this process occurred in November 1993 with the
implementation of FERC Order 636. FERC Order 636 requires
interstate pipelines to unbundle pipeline sales service from
pipeline transportation service. This has enabled the Company to
arrange for its gas supply directly with producers, gas marketers
or pipelines, at its discretion, as well as to arrange for
transportation and gas storage services. Such flexibility should
allow the Company to protect its existing market and to expand
its core and non-core market offerings. With these expanded
opportunities come increased competition from gas marketers and
other utilities.
OTHER COMPANY EFFORTS TO ADDRESS COMPETITIVE CHALLENGES
UNREGULATED GENERATOR INITIATIVES are discussed in a
separate section below.
TAX INITIATIVES. The Company is working with utility and
state representatives to explain the negative impact that all
taxes, including the Gross Receipts Tax (GRT), are having on
rates and the state of the economy. Governor Pataki and other
state officials have identified changes in the GRT as an element
in improving the business climate in New York. At the same time,
the Company is contesting the high real estate taxes it is
assessed by many taxing authorities, particularly compared to the
taxes assessed on UGs.
As noted above, the Company has reduced its work force over
the past three years, resulting in a decrease in the amount of
payroll taxes incurred over that period. Meanwhile, the
reduction in revenues experienced by the Company resulting from
reduced sales and an increase in customer discounts, combined
with a phase out of the GRT surcharge, has caused the amount of
GRT paid by the Company to be reduced. The following table sets
forth a summary of the components of other taxes (exclusive of
income taxes) incurred by the Company in the years 1993 through
1995:
In millions of dollars
1995 1994 1993
- ------------------------------------------------------------
Property tax paid $264.8 $262.6 $246.7
Sales tax 20.1 17.5 19.7
Payroll tax 37.3 42.5 44.3
Gross Receipts tax 190.2 198.1 200.7
Other taxes 5.2 4.3 4.2
- ------------------------------------------------------------
Total tax payments 517.6 525.0 515.6
Charged to construction,
subsidiaries and regulatory
recognition (.1) (28.1) (24.2)
- ------------------------------------------------------------
Total Other Taxes $517.5 $496.9 $491.4
CUSTOMER DISCOUNTS. The Company is experiencing a loss of
industrial load across its system for a variety of reasons. In
some cases, customers have found alternative suppliers or are
generating their own power. In other cases a weakened economy or
attractive energy prices elsewhere have contributed to customer
decisions to relocate or close.
In addressing the threat of further loss of industrial load,
the PSC established guidelines to govern flexible electric rates
offered by utilities to retain qualified industrial customers.
Under these guidelines, the Company filed for a new service
tariff in August 1994, under which all new contract rates are
administered based on demonstrated industrial and commercial
competitive pricing situations including, but not limited to, on-
site generation, fuel switching, facility relocation and partial
plant production shifting. Contracts are for terms not to
exceed seven years without PSC approval.
The Company has granted discounts to a number of industrial
customers and expects others to seek discounts through
negotiating long-term contracts. Many of these contracts may
result in increased load that could be revenue enhancing. The
Company also offers economic development rates, which can result
in discounts for existing, as well as, new load. In 1995, the
Company granted approximately $62 million of discounts which
exceeded by $20 million the approximately $42 million that were
anticipated in setting rates for 1995. As of January 3, 1996,
electric commercial and industrial customers have signed 67
discount agreements with an average term of four years. In
addition, the average discount negotiated in 1995 was 21% below
tariff prices. The Company expects discounts to increase in 1996
to approximately $87 million, 80% of which the Company seeks to
recover in its February 1996 rate filing. As was the case in
1995, the Company would absorb the impact of any discounts in
excess of amounts reflected in rates.
The increase in the Company's prices over the past four
years, which is largely due to mandated purchases from UGs, has
made cogeneration and self-generation by many industrial and
large commercial customers more attractive. The Company believes
the pricing flexibility mentioned above was a necessary first
step to prevent erosion of its customer base. Price pressure in
the longer term, however, may limit the recovery of such costs
from the remainder of its customer base.
SITHE/ALCAN. In April 1994, the PSC ruled that, in the
event Sithe Independence Power Partners Inc. (Sithe) ultimately
obtained authority to sell electric power at retail, those retail
sales would be subject to a lower level of regulation than the
PSC presently imposes on the Company. Sithe, which sells
electricity to Consolidated Edison Company of New York, Inc. and
to the Company at wholesale from its 1,040 megawatt (MW) natural
gas cogeneration plant, also provides steam to Alcan Rolled
Products (Alcan). As authorized by the PSC in September 1994,
Sithe also sells a portion of its electricity output on a retail
basis to Alcan, previously a customer of the Company, and is
authorized to sell to Liberty Paperboard (Liberty), a potential
new industrial customer. The PSC ordered that Sithe pay the
Company a fee over a period of ten years, based upon the prices
at which Sithe would sell to Alcan, structured to produce a net
present value of approximately $19.6 million. Beginning in 1995,
the fee was approximately $3.05 million. The Company had argued
for compensation, which would have assured discounted rates to
Alcan, with a net present value of $39 million. The PSC did not
authorize a fee in connection with Sithe's sale to Liberty.
A Company appeal in State Supreme Court, Albany County,
contending that the April 1994 PSC Order is a violation of legal
procedure and precedent and should be reversed, was dismissed in
February 1996. Although the Company's appeal of Sithe's ability
to sell to a retail customer and the level of compensation
involved was denied, the PSC's decision to require compensation
to utilities for costs that would otherwise be stranded has
established a precedent in by-pass situations for some level of
recovery of the Company's investment.
GENERATING ASSET MANAGEMENT STUDIES - The Company continues
as a matter of course to examine the economic and strategic
issues related to operation of all its generating units. As a
result of economic studies that the Company has performed (most
recently in 1994), it has presently determined that it is
economically advantageous to continue operation of Nine Mile
Point Nuclear Station Unit No. 1 (Unit 1) over the remaining term
of its license.
The Company also has, and continues to, study the economics
of continued operation of its fossil-fueled generating plants,
given current forecasts of excess capacity. Growth in UG supply
sources, compliance requirements of the Clean Air Act Amendment
of 1990 (Clean Air Act) and low wholesale market prices are key
considerations in evaluating the Company's internal generation
needs. Due to projected excess capacity and Clean Air Act
requirements, a total of 340 MW's of aging coal fired capacity is
expected to be retired by the end of 1999 and 850 MW's of oil
fired capacity was placed in long-term cold standby in 1994.
These decisions will be revisited as facts and circumstances
change. These actions permit the reduction of operating costs
and capital expenditures for retired and standby plants. The
remaining investment in these plants of approximately $250
million at December 31, 1995 (of which approximately $180 million
relates to the facility in cold standby) is currently being
recovered in rates through depreciation under traditional
ratemaking; recovery would also be provided under PowerChoice.
(See Note 2 of Notes to Consolidated Financial Statements).
These asset management studies have enabled the Company to
make significant reductions in capital spending, and with
increased output and lower operating costs, to improve the cost-
efficiency of the units which is important as the Company
continues to examine its competitive situation and future
strategic direction.
REGULATORY AGREEMENTS/PROPOSALS
1995 RATE ORDER. (See Note 2 of Notes to the Consolidated
Financial Statements).
Through its Brief Opposing Exceptions dated March 2, 1995,
the Company requested an increase in 1995 electric revenues of
approximately $110 million (3.5%) and an increase in 1995 gas
revenues of $16.4 million (2.7%).
On April 21, 1995, the Company received a rate decision
(1995 rate order) from the PSC which approved an approximately
$47 million increase in electric revenues and a $4.9 million
increase in gas revenues, an expected bill increase of 1.1% for
electric customers (a 3.4% increase for residential and a 1.6%
decrease for large industrial) and an 0.8% increase for gas
customers.
The 1995 rate order allows the Company to retain its fuel
adjustment clause (FAC) mechanism, but NERAM, which permitted the
Company to recover revenue shortfalls during future periods, was
discontinued (See "RESULTS OF OPERATIONS").
The 1995 rate order includes performance-based penalties
related to customer service quality and demand-side management
programs. In December 1995, the Company estimated and recorded a
customer service penalty for 1995 of $4.8 million, or 2 cents per
share, since it did not maintain certain customer service goals
at 1994 levels. The final amount of the penalty will be subject
to audit by the PSC.
PRIOR REGULATORY AGREEMENTS. The Company's results during
the past several years have been strongly influenced by several
agreements with the PSC. A brief discussion of the key terms of
certain of these agreements is provided below.
The 1991 Financial Recovery Agreement implemented NERAM and
the Measured Equity Return Incentive Term (MERIT). See Note 1 of
Notes to the Consolidated Financial Statements.
NERAM required the Company to reconcile actual results to
the forecasted electric public sales gross margin used in
establishing rates. NERAM was discontinued in 1995.
Approximately $101.2 million of NERAM revenues were recorded in
1994 and $65.7 million in 1993. Substantially all of the
remaining balance of NERAM revenues recorded of approximately
$48.8 million will be collected in 1996.
The MERIT program is an incentive mechanism. Overall goal
targets and criteria for the 1993-1995 MERIT periods were
results-oriented and intended to measure improvement in key
performance areas. The total possible awards are $34 million and
$41 million for 1994 and 1995, respectively. The Company has
recognized approximately $20.3 million, $20.8 million and $16.9
million of MERIT revenues in 1993, 1994 and 1995, respectively.
The recorded 1995 award represents the objectively determinable
portion of the anticipated earned award, with the balance to be
recorded in 1996 when approved.
UNREGULATED GENERATORS
In recent years, the leading cause of higher customer bills
and the deterioration of the Company's competitive position has
been the requirement to buy power from UGs in excessive
quantities at an average price which is more than twice as high
as the cost of power that could be purchased in the wholesale
market.
By the end of 1994, the Company had virtually all UG
capacity scheduled to come into service on line and selling
power, which at December 31, 1995, consisted of 151 facilities
with a combined capacity of 2,708 MW. Of these, 2,390 MW are
considered firm capacity. UG purchases were approximately $736
million in 1993, $960 million in 1994 and $980 million in 1995.
In the absence of UG contract restructuring under PowerChoice or
any similar proposal, the Company estimates that purchase power
payments to UGs will continue to escalate at an average annual
rate of about 6% through the year 2000.
The Company has initiated a series of actions to deal with
the growth of supply and to realign its supply with demand, but
cannot predict the outcomes. These actions include mothballing
and retiring Company-owned generating facilities (See "Generating
Asset Management Studies") and buyouts of UG projects, as well as
the implementation of an aggressive wholesale marketing effort.
Such actions have succeeded in reducing installed capacity
reserve margins to normal planning levels. The Company is
actively pursuing other initiatives to reduce its UG costs. The
Company also filed its PowerChoice proposal with the PSC as part
of its multi-year electric rate proceeding (see "POWERCHOICE
PROPOSAL") in an attempt to address this problem.
FERC PROCEEDING. On January 11, 1995, in a case involving
Connecticut Light & Power (CL&P), FERC ruled that the Public
Utility Regulatory Policy Act (PURPA) forbids states from
requiring utilities to pay more than avoided cost to qualifying
facilities (QFs) for electric power. However, FERC also said it
would not invalidate any prior contracts, but would apply its
ruling prospectively or to contracts that were subject to a
pending challenge (instituted at the time of signing) by a
utility. On the same day, FERC ordered that an ongoing challenge
by the Company to the New York law requiring utilities to pay QFs
a minimum of six cents per Kwh for electric power ("Six Cent
Law") was moot in light of a 1992 amendment to that law
prohibiting future contracts that require utilities to pay more
than avoided costs. The latter proceeding began in 1987. In
April 1988, FERC had ruled in the Company's favor, finding that
states could not impose rates exceeding avoided cost for
purchases from QFs. FERC then stayed its decision in light of a
rulemaking it was instituting to address the issue. That
rulemaking was never completed.
On February 10, 1995, the Company filed a petition for
rehearing of both orders. The petition was denied. The Company
then asked U.S. Court of Appeals for the District of Columbia to
review FERC's denial. FERC and other parties moved to dismiss
for lack of jurisdiction. These motions remain pending. On May
11, 1995, the Company filed complaints in the U.S. District Court
for the Northern District of New York against the FERC and the
PSC, contending the FERC unlawfully ruled that its decision in
CL&P does not apply to purchases of power under existing
agreements. The PSC was named in this complaint on the basis
that its policies required the Company to enter into the above-
market-value agreements. In July 1995, various parties to these
actions, including the FERC and the PSC, moved to dismiss the
case. The motions remain pending.
CURTAILMENT PROCEDURES. On August 18, 1992, the Company
filed a petition with the PSC calling for the implementation of
"curtailment procedures." Under existing FERC and PSC policy,
this petition would allow the Company to limit its purchases from
UGs during light load periods as contemplated in FERC
regulations. Also, the Company has negotiated settlements with
certain UGs regarding curtailment provisions of power purchase
agreements. On April 5, 1994, after informing the PSC of its
progress, or lack thereof, in settlement discussions, the Company
asked the PSC to expedite its review of the petition. The
Company cannot predict the outcome of this action.
DEMAND FOR ADEQUATE ASSURANCE. On February 4, 1994, the
Company notified the owners of nine projects of the Company's
demand for adequate assurance that the owners will fulfill all
future obligations, including the obligation to deliver
electricity at prices below the Company's avoided cost. These
nine projects have contracts that provide for initial purchase of
power by the Company at rates above avoided cost.
The projects at issue total 429 MW. The Company's demand is
based on its assessment of the amount of payments above avoided
cost to be accumulated under the terms of the contracts. The
Company believes it needs adequate assurance because the
projects' future obligations to deliver electricity at prices
below avoided costs to offset these accumulated account balances
would involve operating losses that would cause the owners to
abandon the projects. The Company has been sued in three
separate actions by the owners of six UG projects which challenge
the Company's right to demand adequate assurance. Court
decisions in February 1996 in two of these actions found that the
Company does not have the legal right to demand adequate
assurance. The Company intends to appeal these decisions.
In December 1995, the Company filed a petition with the PSC
seeking an order that eight UGs post firm security to ensure
performance of their obligations and thereby, protect customers'
interests under UG contracts. Alternatively, the Company asked
that the PSC should cancel these contracts if such security is
not provided. The Company estimates that the above-market
payments to these eight UGs, which will amount to more than $100
million in 1996, will grow to approximately $3.3 billion on a
cumulative basis in a little more than a decade.
The Company cannot predict the outcome of its petition or of
the legal actions regarding adequate assurance but because the
Company and its customers continue to bear the substantial burden
these contracts impose, the Company will continue to press for
adequate assurance that the owners of these projects will honor
their obligations.
RESULTS OF OPERATIONS
Earnings for 1995 were $208.4 million, or $1.44 per share,
as compared to $143.3 million, or $1.00 per share, in 1994, and
$240.0 million, or $1.71 per share, in 1993. 1994 earnings
included $101.2 million, or 46 cents per share, of electric
margin recorded under NERAM, but were adversely affected by the
charge to earnings of approximately $197 million (89 cents per
share) for nearly all of the cost of the VERP. The VERP was
initiated in 1994 to bring the Company's staff levels and work
practices into line with peer utilities and to create a more
competitive cost structure. Since January 1, 1993, the Company
has reduced its employment by approximately 3,200, or 27%, as of
December 31, 1995. About 70% of the Company's work force is
subject to a collective bargaining agreement with the
International Brotherhood of Electrical Workers. This thirty-
three month agreement expired February 29, 1996, and is currently
in negotiation.
1995 earnings were hurt by lower sales quantities of
electricity and natural gas, as compared with amounts used to
establish 1995 prices. Sales were primarily affected by the
continuing weak economic conditions in upstate New York, loss of
industrial customers' load to NYPA and discounts granted. In
January 1995 NERAM was discontinued. The Company's 1995 earned
return on common equity was 8.4%, compared to 5.8% (10.7% without
the VERP charge) in 1994 and 10.2% in 1993. The Company's return
on common equity authorized in the rate setting process for the
year ended December 31, 1995, provided an electric return on
equity of 11.0% and a return on equity for gas of 11.4%. Factors
contributing to earnings below authorized levels in 1995
included, among other things: sales below those forecasted in
determining rates; about $20 million more in customer discounts
than those reflected in rates; the inability to achieve stringent
wholesale margin targets set by the PSC; and fuel target
penalties for low hydro production caused by dry weather. The
Company expects the trend of weak sales to continue, given weak
economic conditions in the Company's service territory.
The following discussion and analysis highlights items that
significantly affected operations during the three-year period
ended December 31, 1995. This discussion and analysis may not be
indicative of future operations or earnings. It also should be
read in conjunction with the Notes to Consolidated Financial
Statements and other financial and statistical information
appearing elsewhere in this report.
ELECTRIC REVENUES decreased by $193.4 million, or 5.5%, in
1995, and increased by $196.5 million, or 5.9%, in 1994.
As shown in the following table, electric operating revenues
decreased in 1995 primarily due to the elimination of NERAM after
1994, and the decrease in sales to other electric systems and in
sales to ultimate consumers. In addition, FAC revenues decreased
$86.4 million, in part due to a decrease in fuel and purchased
power costs that are recoverable through the FAC as compared to
1994. Despite a decrease in fuel costs, the Company absorbed a
loss of approximately $11.8 million in 1995, since its actual
costs in 1995 were higher than the amounts forecasted in rates.
In 1994, the Company retained a maximum benefit of $15 million,
since its actual costs were lower than the amounts forecasted in
rates. The amount forecasted in rates in 1995 reflected a lower
fuel cost than 1994. The decrease in FAC revenues also reflects
a higher amount of transmission revenues ($21.6 million) passed
on to customers. These decreases were partially offset by higher
electric rates that took effect April 26, 1995, and by the
recording of $71.5 million unbilled, non-cash revenues in 1995 in
accordance with the 1995 rate order. The increase in demand side
management (DSM) revenues relates to a one-time, non-cash
adjustment of prior years' DSM incentives, partially offset by a
reduction in the DSM rebate cost program.
The $196.5 million, or 5.9%, increase in electric operating
revenues in 1994 was primarily due to higher recoveries through
the operation of the FAC mechanism, increased sales to other
electric systems, NERAM revenues and rate increases (mainly
reflecting the pass through of increases in mandated purchases of
UG power and rising taxes).
INCREASE (DECREASE) FROM PRIOR YEAR
(In millions of dollars)
ELECTRIC REVENUES 1995 1994 1993 TOTAL
- -----------------------------------------------------------------
Amortization of unbilled
revenues $ 71.5 $ - $ - $ 71.5
Increase in base rates 68.2 36.0 193.1 297.3
Fuel adjustment clause
revenues (86.4) 108.3 (42.6) (20.7)
Changes in volume and mix
of sales to ultimate
consumers (57.5) (13.6) 11.0 (60.1)
Sales to other electric
systems (71.3) 62.1 11.7 2.5
DSM revenue 1.4 (27.7) (30.3) (56.6)
Miscellaneous operating
revenues (18.1) (4.1) 17.9 (4.3)
NERAM revenues (101.2) 35.5 24.0 (41.7)
------- ------ ------ ------
$(193.4) $196.5 $184.8 $187.9
======== ====== ====== ======
Changes in FAC revenues are generally margin-neutral
(subject to an incentive mechanism discussed in Note 1 of Notes
to Consolidated Financial Statements), while sales to other
utilities, because of regulatory sharing mechanisms and
relatively low prices, generally result in low margin
contributions to the Company. Thus, fluctuations in these
revenue components do not generally have a significant impact on
net operating income. Electric revenues reflect the billing of a
separate factor for DSM programs, which provide for the recovery
of program related rebate costs.
ELECTRIC KILOWATT-HOUR SALES were 37.7 billion in both years
1995 and 1993, and 41.6 billion in 1994. The 1995 decrease of
3.9 billion kilowatt-hours (Kwh), or 9.4% as compared to 1994,
reflects a 41.3% decrease in sales to other electric systems and
a 2.3% decrease in sales to ultimate consumers. The decline
reflects reduced demand due to the continued stagnant economy,
loss of several large industrial customers due primarily to
relocations and closings, loss of Alcan to Sithe, loss of sales
to NYPA, and more competitive pricing caused by excess supply.
The 1994 increase reflected increased sales to other electric
systems, while sales to ultimate consumers were generally flat.
(See Electric and Gas Statistics - Electric Sales). The lost
electric margin effect of sales in 1994 was adjusted by NERAM
except for the large industrial customer class, within which the
Company absorbed 20% of the variance from the NERAM sales
forecast. This adjustment was not made in 1995, since NERAM was
discontinued. Industrial-Special sales are NYPA allocations of
low-cost power to specified customers, from which the Company
earns a transportation charge. While these sales decreased
slightly in 1995 as compared to 1994, usage as a percentage of
capacity increased resulting in an increase in revenues.
Details of the changes in electric revenues and kilowatt-hour sales by customer group
are highlighted in the table below:
% INCREASE (DECREASE) FROM PRIOR YEARS
1995 % OF ------------------------------------------------------------
ELECTRIC 1995 1994 1993
CLASS OF SERVICE REVENUES REVENUES SALES REVENUES SALES REVENUES SALES
- ------------------------------------------------------------------------------------------
Residential 36.6% (1.0)% (2.5)% 5.2% (0.6)% 6.9% 0.8%
Commercial 37.2 (2.4) (1.1) 2.5 (2.2) 7.0 3.9
Industrial 15.8 (8.7) (4.3) 4.3 5.0 (6.0) (5.2)
Industrial-Special 1.7 14.3 (1.6) 14.5 5.9 9.1 0.8
Municipal service 1.5 (0.9) - (1.3) (2.3) 0.6 (3.1)
- ------------------------------------------------------------------------------------------
Total to ultimate
consumers 92.8 (2.7) (2.3) 3.9 0.8 4.3 0.5
Other electric
systems 2.9 (42.7) (41.3) 59.1 91.1 12.6 31.2
Miscellaneous 4.3 (19.9) - 8.2 - 40.6 -
- ------------------------------------------------------------------------------------------
TOTAL 100.0% (5.5)% (9.4)% 5.9% 10.3% 5.9% 3.0%
As indicated in the table below, internal generation from
fossil-fuel sources declined in 1995, principally at the Oswego
oil-fired facility. The decrease in fuel costs reflects a
decrease in Company generation due to reduced demand, which
reduced the need to operate the fossil plants, even after taking
into account the 1995 Nine Mile Point Nuclear Station Units No. 1
(Unit 1) and No. 2 (Unit 2) scheduled refueling and maintenance
outages. Quantities purchased from UGs decreased in 1995, due in
part to the low water supply which limited the amount of power
the hydroelectric UGs could produce. Although gigawatt-hours
(GwHrs) decreased, total costs escalated due to renegotiated
contracts that required payments to be made to the UGs for
schedulable capacity. See Note 9 of Notes to the Consolidated
Financial Statements - "Contracts for the Purchase of Electric
Power."
1995 1994 1993
--------------- ---------------- ----------------
(In millions of dollars)
Fuel for electric
generation: GwHrs. Cost GwHrs. Cost GwHrs. Cost
------ ---- ------ ---- ------ ----
Coal 6,841 $ 97.9 6,783 $ 107.3 7,088 $ 113.0
Oil 537 21.3 1,245 40.9 2,177 74.2
Natural gas 996 20.2 700 16.1 548 12.5
Nuclear 7,272 43.3 8,327 49.5 7,303 43.3
Hydro 2,971 - 3,485 - 3,530 -
------- ------ ------ ------- ------ --------
18,617 182.7 20,540 213.8 20,646 243.0
------- ------ ------ ------- ------ --------
Electricity
purchased:
Unregulated
generators:
Capacity - 181.2 - 84.6 - 20.3
Energy and taxes 14,023 798.7 14,794 875.5 11,720 715.4
------ ----- ------ ----- ------ -------
Total UG purchases 14,023 979.9 14,794 960.1 11,720 735.7
Other 9,463 126.5 10,382 140.3 9,046 118.1
------ ------- ------ ------- ------ -------
23,486 1,106.4 25,176 1,100.4 20,766 853.8
------ ------- ------ ------- ------ -------
Total generated
and purchased 42,103 1,289.1 45,716 1,314.2 41,412 1,096.8
Fuel adjustment
clause - 14.8 - 12.7 - (2.2)
Losses/Company use 4,419 - 4,117 - 3,688 -
------ ------- ------ -------- ------ ---------
37,684 $1,303.9 41,599 $1,326.9 37,724 $1,094.6
====== ======= ====== ======== ====== =========
% Change from Prior Year
-------------------------------------
1995 to 1994 1994 to 1993
------------- -------------
(In millions of dollars)
Fuel for electric
generation: GwHrs. Cost GwHrs. Cost
------ ---- ------ ----
Coal 0.9% (8.8)% (4.3)% (5.0)%
Oil (56.9) (47.9) (42.8) (44.9)
Natural gas 42.3 25.5 27.7 28.8
Nuclear (12.7) (12.5) 14.0 14.3
Hydro (14.7) - (1.3) -
------ ------ ------ ------
(9.4) (14.5) (0.5) (12.0)
------ ------ ------ ------
Electricity
purchased:
Unregulated
generators:
Capacity - 114.2 - 316.7
Energy and taxes (5.2) (8.8) 26.2 22.4
----- ----- ---- -----
Total UG purchases (5.2) 2.1 26.2 30.5
Other (8.9) (9.8) 14.8 18.8
----- ----- ---- -----
(6.7) 0.5 21.2 28.9
------ ------ ---- -----
Total generated
and purchased (7.9) (1.9) 10.4 19.8
Fuel adjustment
clause - 16.5 - (677.3)
Losses/Company use 7.3 - 11.6 -
---- ---- ----- -------
(9.4)% (1.7)% 10.3% 21.2%
====== ====== ====== =======
GAS REVENUES decreased by $41.4 million, or 6.6%, in 1995,
and increased by $22.2 million, or 3.7%, in 1994. As shown by
the table below, gas revenues decreased in 1995 primarily due to
decreased sales to ultimate customers, which reflects reduced
demand due to the weak economy and warmer weather, and lower gas
adjustment clause recoveries. This decrease was partially offset
by an increase in revenues from the transportation of customer-
owned gas of approximately $9.9 million which was primarily
caused by the Sithe gas-fired generating project coming on-line
in the Company's service territory and an increase in base rates
of $4.7 million in accordance with the 1995 rate order. Rates
for transported gas yield lower margins than gas sold directly by
the Company. Therefore, increases in the volume of gas
transportation services have not had a proportionate impact on
earnings. In addition, changes in purchased gas adjustment
clause revenues are generally margin-neutral.
In 1994, the revenue increase was primarily attributable to
increased sales to ultimate customers, increased base rates, and
gas adjustment clause recoveries. This increase was partially
offset by a decline in spot market sales, because the abundance
and price of spot gas made it more difficult to earn sufficient
margins on these sales. Spot market sales are generally the
higher priced gas available and sold in the wholesale market and
yield margins substantially lower than traditional sales to
ultimate customers.
INCREASE (DECREASE) FROM PRIOR YEAR
(In millions of dollars)
GAS REVENUES 1995 1994 1993 TOTAL
- -----------------------------------------------------------------
Increase in base rates $ 4.7 $ 7.1 $ 7.3 $ 19.1
Transportation of
customer-owned gas 9.9 3.5 (9.7) 3.7
Purchased gas adjustment
clause revenues (10.7) 7.7 12.2 9.2
Spot market sales (1.3) (25.4) 27.2 0.5
Miscellaneous operating
revenues (3.5) 6.3 (5.0) (2.2)
Changes in volume and
mix of sales to ultimate
consumers (40.5) 23.0 15.1 (2.4)
------- ------ ------ ------
$(41.4) $ 22.2 $ 47.1 $ 27.9
======= ====== ====== =======
GAS SALES, excluding transportation of customer-owned gas
and spot market sales, were 78.5 million dekatherms (dth) in
1995, an 8.3% decrease from 1994 and a 5.7% decrease from 1993
(See Electric and Gas Statistics - Gas Sales). The decrease in
1995 was in all ultimate consumer classes, which reflects the
continuing weak economic conditions in upstate New York. The
Company has added approximately 25,000 new customers since 1992,
primarily in the residential class, an increase of 5.1%, and
expects a continued increase in new customers in 1996 at levels
slightly lower than previous levels. During 1995, there was also
a shift from the industrial sales class to the transportation
sales class.
Even though gas sales and revenues decreased in 1995,
corresponding reductions in purchased gas expense enabled a
slight improvement in margin on gas sales.
In 1995, the Company transported 144.6 million dth, or 68.3%
increase, for customers purchasing gas directly from producers.
A continued increase in transportation volumes is expected in
1996, leading to a forecast increase in total gas transported in
1996 of approximately 8% above 1995. Factors affecting this
forecast include the economy, the relative price differences
between oil and gas in combination with the relative availability
of each fuel, the expanded number of cogeneration projects served
by the Company and increased marketing efforts. Changes in gas
revenues and dth sales by customer group are detailed in the
table below:
% INCREASE (DECREASE) FROM PRIOR YEARS
1995 % OF -----------------------------------------------------------
GAS 1995 1994 1993
CLASS OF SERVICE REVENUES REVENUES SALES REVENUES SALES REVENUES SALES
- ------------------------------------------------------------------------------------------
Residential 63.3% (7.5)% (8.2)% 7.5% 2.9% 4.6% 1.8%
Commercial 24.7 (9.7) (7.6) 9.9 8.6 9.2 6.5
Industrial 2.0 (21.0) (14.1) (21.0) (28.2) 84.8 143.6
- ------------------------------------------------------------------------------------------
Total to ultimate
consumers 90.0 (8.5) (8.3) 7.1 2.9 7.4 6.4
Other gas
systems 0.1 (34.3) (34.0) 8.7 4.3 (77.5) (80.3)
Transportation of
customer-owned
gas 8.3 25.9 68.3 10.1 26.8 (18.5) 2.9
Spot market sales 0.5 (29.2) 9.6 (85.3) (88.1) 1,056.1 1,053.8
Miscellaneous 1.1 (16.7) - 423.3 - (79.4) -
- ------------------------------------------------------------------------------------------
TOTAL 100.0% (6.6)% 29.9% 3.7% 5.4% 8.5% 12.3%
==========================================================================================
The total cost of gas purchased decreased 12.5% in 1995 and
3.2% in 1994, and increased 13.6% in 1993. The cost fluctuations
generally correspond to sales volume changes, particularly in
1993, as spot market sales activity increased. The Company sold
1.7, 1.6 and 13.2 million dth on the spot market in 1995, 1994
and 1993, respectively. In 1993, this activity accounted for
two-thirds of the 1993 purchased gas expense increase. The
purchased gas cost decrease associated with purchases for
ultimate consumers in 1995 resulted from a 4.3 million decrease
in dth purchased and withdrawn from storage for ultimate consumer
sales ($15.1 million) and a 10.8% decrease in the average cost
per dth purchased ($32.8 million). This was partially offset by
an increase of $10.1 million in purchased gas costs and certain
other items recognized and recovered through the purchased gas
adjustment clause (GAC). Gas purchased for spot market sales
decreased $1.4 million and $24.4 million in 1995 and 1994,
respectively. The purchased gas cost increase associated with
purchases for ultimate consumers in 1994 resulted from a 1.5%
increase in dth purchased, coupled with a .9% increase in rates
charged by suppliers and an increase of $6.4 million in purchased
gas costs and certain other items recognized and recovered
through the purchased GAC. The Company's net cost per dth sold,
as charged to expense and excluding spot market purchases,
decreased to $3.17 in 1995 from $3.44 in 1994 and was $3.34 in
1993.
Through the electric and purchased gas adjustment clauses,
costs of fuel, purchased power and gas purchased, above or below
the levels allowed in approved rate schedules, are billed or
credited to customers. The Company's electric FAC provides for a
partial pass-through of fuel and purchased power cost
fluctuations from those forecast in rate proceedings, with the
Company absorbing a portion of increases or retaining a portion
of decreases to a maximum of $15 million per rate year. While
the amount absorbed in 1993 was not material, the Company
retained the maximum benefit of $15 million in 1994 and absorbed
a loss of approximately $11.8 million in 1995.
Other operation expense decreased in 1995 by $139.8 million,
or 18.5%, as compared to a decrease of $66.6 million, or 8.1% in
1994. Despite the costs related to the 1995 scheduled nuclear
refueling outages of Units 1 and 2 of approximately $36 million,
other operation expense decreased in 1995 primarily as a result
of the Company's cost reduction program. In addition to lower
labor costs, the Company also reduced 1995 non-labor costs, such
as research and development expenditures ($21 million), general
office expenses ($8 million), and DSM rebate costs ($19 million).
The 1994 decrease relates primarily to decreases in nuclear costs
associated with the Unit 1 and Unit 2 refueling and maintenance
outages in 1993 ($27 million) and the decrease in amortization of
regulatory deferrals ($49 million) which expired in 1993.
Other items, net decreased by $13.0 million in 1995 and
increased by $8.0 million in 1994. The 1995 decrease was
primarily due to the recognition of customer service penalties,
certain other items disallowed in rates and lower subsidiary
earnings, offset in part by the gain recognized on the sale of
HYDRA-CO Enterprises, Inc. (HYDRA-CO). The 1994 increase
primarily related to increased earnings of subsidiaries which
included a nonrecurring gain on the sale of an investment for $9
million.
Net Federal and foreign income taxes increased in 1995 by
approximately $47.9 million due to an increase in pre-tax income,
which included the increase related to the sale of HYDRA-CO. In
1994, the decrease of approximately $35.6 million was due to
lower pre-tax income, which included a charge to earnings of
approximately $197 million in 1994 for nearly all of the costs of
VERP. The increase in other taxes increased in 1995 primarily as
a result of an increase in the amortization of amounts deferred
in prior years ($19.7 million) related to real estate taxes.
This increase was partially offset by a reduction of
approximately $7.9 million in gross receipts taxes as a result of
lower revenues in 1995 as compared to 1994, and a reduction in
the gross receipts tax surcharge during 1995, as well as, a
reduction in payroll taxes ($5.2 million) due to a decrease in
employees. In 1994, the increase was principally due to an
increase in real estate taxes ($15.9 million).
Net interest charges remained fairly constant for the years
1993 through 1995. However, dividends on preferred stock
increased during this time by $1.8 million and $5.9 million in
1994 and 1995, respectively. Dividends on preferred stock
increased $5.9 million in 1995 primarily as a result of an
increase in the cost of variable rate issues and increased $1.8
million in 1994 due to the issuance of $150 million of preferred
stock issued in August 1994. The weighted average long-term debt
interest rate and preferred dividend rate paid, reflecting the
actual cost of variable rate issues, changed to 7.77% and 7.19%,
respectively, in 1995 from 7.79% and 6.84%, respectively, in
1994, and from 7.97% and 6.70%, respectively, in 1993.
EFFECTS OF CHANGING PRICES
The Company is especially sensitive to inflation because of
the amount of capital it typically needs and because its prices
are regulated using a rate base methodology that reflects the
historical cost of utility plant.
The Company's consolidated financial statements are based on
historical events and transactions when the purchasing power of
the dollar was substantially different than now. The effects of
inflation on most utilities, including the Company, are most
significant in the areas of depreciation and utility plant. The
Company could not replace its non-nuclear utility plant and
equipment for the historical cost value at which they are
recorded on the Company's books. In addition, the Company would
not replace these with identical assets due to technological
advances and competitive and regulatory changes that have
occurred. In light of these considerations, the depreciation
charges in operating expenses do not reflect the cost of
providing service if new generating facilities were installed.
The Company will seek additional revenue or reallocate resources,
if possible, to cover the costs of maintaining service as assets
are replaced or retired.
FINANCIAL POSITION, LIQUIDITY AND CAPITAL RESOURCES
- ---------------------------------------------------
FINANCIAL POSITION
The Company's capital structure at December 31, 1995 was
54.5% long-term debt, 8.0% preferred stock and 37.5% common
equity, as compared to 52.9%, 8.5% and 38.6%, respectively, at
December 31, 1994. Book value of the common stock was $17.42 per
share at December 31, 1995, as compared to $17.06 per share at
December 31, 1994. Market analysts have observed that the
Company's low market to book ratio, 54.5% at December 31, 1995,
results from a weak New York State economy and regulatory
attitudes, and from uncertainty about the pace of regulatory
change, which could increase competition and reduce prices,
rendering the Company particularly vulnerable. In addition,
market analysts have expressed concern about the uncertainty and
potential negative impact of the PowerChoice proposal on the
Company, as well as the possibility of bankruptcy. As indicated
elsewhere, the Company believes the PowerChoice proposal is in
the best interests of shareholders, bondholders and customers.
However, the Company is committed to taking necessary courses of
action to improve its financial profile, including consideration
of other alternatives to PowerChoice that may represent better
value to these constituencies.
The 1995 ratio of earnings to fixed charges was 2.29 times.
The ratios of earnings to fixed charges for 1994 and 1993 were
1.91 times and 2.31 times, respectively. Security rating firms
have begun to impute certain items into the Company's interest
coverage calculations and capital structure, the most significant
of which is the inclusion of a "leverage" factor for UG
contracts. The rating firms believe the financial structure of
the UGs (which typically have very high debt-to-equity ratios)
and the character of their power-purchase agreements increase the
financial risk to utilities. The Company's reported interest
coverage and debt-to-equity ratios have recently been discounted
by varying amounts for purposes of establishing credit ratings.
Because of existing commitments for UG purchases, the imputation
has had, and will continue to have, a materially negative impact
on the Company's financial ratings. Management expects that the
reduced commitments for UG purchases, as proposed in PowerChoice,
would reduce the inclusion of the "coverage factor" for UG
contracts and reduce the financial risk of the Company.
COMMON STOCK DIVIDEND
On January 25, 1996, the board of directors omitted the
common stock dividend for the first quarter of 1996. This action
was taken to help stabilize the Company's financial condition and
provide flexibility as the Company addresses growing pressure
from mandated power purchases and weaker sales. In making future
dividend decisions, the board will evaluate, along with standard
business considerations, the level and timing of future rate
relief, the progress of renegotiating contracts with UGs within
the context of its PowerChoice proposal, the degree of
competitive pressure on its prices, and other strategic
considerations.
CONSTRUCTION AND OTHER CAPITAL REQUIREMENTS
The Company's total capital requirements consist of amounts
for the Company's construction program, compliance with the Clean
Air Act and other environmental requirements (as discussed below
and in Note 9 of Notes to the Consolidated Financial Statements -
"Environmental Contingencies"), nuclear decommissioning funding
requirements (See Note 3 of Notes to the Consolidated Financial
Statements - "Nuclear Plant Decommissioning"), working capital
needs, maturing debt issues and sinking fund provisions on
preferred stock, as well as requirements to accomplish
restructuring contemplated by the PowerChoice proposal. Annual
expenditures for the years 1993 to 1995 for construction and
nuclear fuel, including related allowance for funds used during
construction (AFC) and overheads capitalized, were $519.6
million, $490.1 million and $345.8 million, respectively, and are
expected to be approximately $347 million for 1996 and to range
between $307 million - $372 million for each of the subsequent
four years.
Mandatory debt and preferred stock retirements and other
requirements are expected to add approximately another $70
million to the 1996 estimate of capital requirements and
significant additional capital may be required if the New York
State Energy and Development Authority (NYSERDA) bonds discussed
below need to be refinanced. The estimate of construction
additions included in capital requirements for the period 1996 to
2000 will be reviewed by management during 1996 with the
objective of further reducing these amounts where possible. See
discussion in "LIQUIDITY AND CAPITAL RESOURCES" section below,
which describes how management intends to meet its financing
needs for this five-year period.
The provisions of the Clean Air Act are expected to have an
impact on the Company's fossil generation plants during the
period through 2000 and beyond. The Company has complied with
Phase I of the Clean Air Act, which includes reductions of
nitrogen oxides and sulfur dioxide. Phase I became effective on
January 1, 1995 and will continue through 1999. The Company
spent approximately $5 million and $32 million in 1995 and 1994,
respectively, on projects at the fossil generation plants
associated with Phase I compliance. The Company has included $15
million in its 1996 through 1999 construction forecast for Phase
II compliance which will become effective January 1, 2000. The
Company anticipates that additional expenditures of approximately
$74 million may be necessary for Phase III to be incurred beyond
2000. The asset management studies, described above, consider
spending estimates for Clean Air Act compliance.
LIQUIDITY AND CAPITAL RESOURCES
Following the PowerChoice proposal, Standard & Poor's (S&P)
lowered its ratings on the Company's senior secured debt to BB
from BBB-, senior unsecured debt to B+ from BB+, preferred stock
to B from BB+, and commercial paper to B from A-3. The present
ratings are "below investment grade." In addition, S&P's ratings
of the Company's securities are on "CreditWatch" with negative
implications. The downgrade of the Company's security ratings
reflects S&P's stated concern regarding the uncertainty and
potential negative impact of the PowerChoice proposal on the
Company. Further, S&P stated that the ultimate possibility of
restructuring under Chapter 11 of the U.S. Bankruptcy Code cannot
be ruled out, based on the Company's statements in that regard.
In December 1995, S&P assigned a private placement rating of "2-
plus" to the Company's first mortgage bonds. Private placement
ratings evaluate the extent of potential loss to an investor
following default, whereas S&P's traditional debt ratings measure
the risk of default in timely payment. S&P stated the rating
(based on a scale of one to six, with "1-plus" the most
favorable) "reflects the strong asset protection and recovery
value and low likelihood that first mortgage bondholders would
suffer any ultimate loss, even in the event of a default by the
issuer."
Moody's Investors Service (Moody's) lowered its ratings
below investment grade for the Company's senior secured debt, to
Ba1 from Baa3; senior unsecured debt to Ba2 from Ba1; its
preferred stock to ba3 from ba1; and its short-term rating for
commercial paper to Not Prime from Prime -3. Moody's is also
maintaining these ratings under review for possible further
downgrade. Moody's cited the necessity for agreement by third
parties significantly diminishes the likelihood that the
PowerChoice proposal will survive intact and increases
uncertainty about the Company's future over the interim period,
as related negotiations proceed. Moody's further stated that the
Company's apparent willingness to consider restructuring under
Chapter 11 of the U.S. Bankruptcy Code raises serious doubts as
to the Company's financial stability. Moody's stated that its
continued review will consider responses to the PowerChoice
proposal, the likelihood of the proposal being adopted and the
effect any interim or final agreement may have on bondholders.
Fitch Investors Services, Inc. (Fitch) also downgraded below
investment grade the Company's first mortgage bonds and secured
pollution control bonds rating from BBB to BB and its preferred
stock rating from BBB- to B+ and noted a declining credit trend.
Fitch's stated concerns are similar to those expressed by S&P and
Moody's.
A summary of the Company's securities ratings at December
31, 1995, was:
- ----------------------------------------------------------------
SECURED PREFERRED COMMERCIAL UNSECURED
DEBT STOCK PAPER DEBT
- ----------------------------------------------------------------
Standard & Poor's
Corporation BB B B B+
Moody's Investors
Service Ba1 ba3 Not Prime Ba2
Fitch Investors
Service BB B+ Not Not
applicable applicable
- ----------------------------------------------------------------
These rating agencies have cited the increased risk and
uncertainty and the potential for bankruptcy as reasons for
downgrade. The Company believes these reasons likewise increase
the risk to third party UGs and their security ratings. The
Company believes its PowerChoice proposal is in the best
interests of its stockholders, customers and bondholders. In the
event PowerChoice is not adopted, and comparable solutions are
not available, the Company will undertake any other actions
necessary to act in the best interests of stockholders and other
constituencies. To that end, on February 12, 1996, the Company
filed for rate relief for 1996 and 1997 and the Company has
implemented a reduction of non-essential programs to reduce its
costs. (See "CHANGING COMPETITIVE ENVIRONMENT," "POWERCHOICE
PROPOSAL" and "COMMON STOCK DIVIDEND").
Cash flows to meet the Company's requirements for operating,
investing and financing activities during the past three years
are reported in the Consolidated Statements of Cash Flows.
During 1995, the Company raised approximately $346 million
from external sources, consisting of $275 million of 7-3/4% First
Mortgage Bonds due May 2006 issued during May 1995 and an
increase of $71 million issued under the Company's Revolving
Credit Agreement.
The Company received approximately $207 million in January
1995, related to the sale of the Company's subsidiary, HYDRA-CO,
the proceeds of which were used to repay short-term debt. The
after-tax gain on the sale of HYDRA-CO was approximately $11.3
million. In addition, the Company received $50 million from the
sale of customer receivables in the fourth quarter of 1995. (See
Note 9 of Notes to the Consolidated Financial Statements - "Sale
of Customer Receivables").
Ordinarily, construction related short-term borrowings are
refunded with long-term securities on a periodic basis. This
approach generally results in the Company showing a working
capital deficit. Working capital deficits may also be a result
of the seasonal nature of the Company's operations as well as
timing differences between the collection of customer receivables
and the payment of fuel and purchased power costs. Recently the
Company has experienced a deterioration in its collections as
compared to prior years' experience and is taking steps to
improve collection. The Company believes it has sufficient
borrowing capacity to fund such deficits as necessary in the near
term. The Company's existing revolving credit facility, which
the Company is in the process of renegotiating as described
below, expires in April 1997.
The Company's capital structure continues to be weak, and
the Company's ability to issue more common stock to improve its
capital structure is essentially precluded by the uncertainties
that have depressed its stock price. The Company is unlikely to
pursue a new issue offering unless the common stock price is
closer to book value and these uncertainties are mitigated. The
reduction to below investment grade ratings on the Company's
bonds and preferred stock can be expected to make it more
difficult and expensive for the Company to finance in the manner
it has used in the past.
External financing plans are subject to periodic revision as
underlying assumptions are changed to reflect developments,
market conditions and, most importantly, the Company's rate
proceedings. The ultimate level of financing during the period
1996 through 1999 will reflect, among other things: the outcome
of the 1996 and 1997 rate requests; the outcome of the
restructuring envisioned in the PowerChoice proposal, including
whether the Company proceeds with exercising its right of eminent
domain with respect to UG contracts; levels of common dividend
payments, if any, and preferred dividend payments; the Company's
competitive position and the extent to which competition
penetrates the Company's markets; uncertain energy demand due to
the weather and economic conditions; and the extent to which the
Company reduces non-essential programs and manages its cash flow
during this period. In the longer term, in the absence of
PowerChoice or some reasonably equivalent solution, financing
will depend on the amount of rate relief that may be granted.
The Company is renegotiating its bank credit facilities to
insure, to the extent possible, adequate financial resources to
satisfy its financing needs over the period 1996 through June
1999. These facilities by their terms would terminate upon
adoption of PowerChoice.
As a result of the Company's ongoing negotiations with its
banks, the Company entered into a commitment letter with
Citibank, N.A., Morgan Guaranty Trust Company of New York and
Toronto Dominion Bank, as co-syndication agents (the Agent
Banks), for the provision of a senior debt facility totaling $815
million for the purpose of consolidating and refinancing certain
of the Company's existing credit agreements and letter of credit
facilities and providing additional reserves of bank credit. The
proposed senior debt facility will consist of a $380 million term
loan and revolving credit facility and a $435 million letter of
credit facility. The letter of credit facility will provide
credit support for $414 million of outstanding pollution control
revenue bonds issued through NYSERDA whose current letter of
credit support expires between April 1996 and January 1997. In
the absence of this support the Company would seek to remarket
these NYSERDA bonds collateralized by its first mortgage bonds.
The interest rate applicable to the senior debt facility
will be variable based on certain rate options available under
the agreement and is currently expected to approximate 8% (but
capped at 13 1/4%). The commitment by the Agent Banks to proceed
with the senior debt financing will expire on the earlier of (i)
fifteen days after the senior debt financing is approved by the
PSC or (ii) March 31, 1996. As contemplated by the commitment,
the term loan and revolving credit facility and the letter of
credit facility will be collateralized by the Company's first
mortgage bonds and will expire on the earlier of June 30, 1999 or
the implementation of the Company's PowerChoice restructuring
proposal or any other significant restructuring plan. The
Company expects that the first mortgage bonds to be issued as
security will be based on additional property under the earnings
test required under the mortgage trust indenture; the bonds could
also be issued on the basis of previously retired bonds without
regard to an earnings test.
This commitment for the senior debt facility is subject to
the preparation and execution of loan documentation agreeable to
the parties and the approval of the PSC.
The Company believes that this commitment on behalf of the
Agent Banks to provide this senior debt facility is an important
step in establishing a firm financial basis for negotiating the
Company's PowerChoice restructuring proposal. The Company is
seeking PSC approval on its petition in March, 1996. In the
event the petition is not approved, the Company believes the
elimination of the common dividend, the implementation of
reductions in non-essential programs and the year-end 1995 cash
position, in combination with alternative sources of credit the
Company believes are available if necessary, will be sufficient
to fund cash requirements for 1996. Sufficient rate relief, if
granted, would provide adequate funds for 1997. The Company can
provide no assurances beyond 1997 as cash flow will depend on
sales, the implementation of PowerChoice, including UG contract
renegotiation, levels of cash rate relief, approval of the senior
debt bank facility agreement, levels of common and preferred
dividends and the ability to further reduce costs, among other
things. As of December 31, 1995, the Company could issue an
additional $2,272 million aggregate principal amount of first
mortgage bonds under the applicable tests set forth in the
Company's mortgage trust indenture. This includes approximately
$1,311 million from retired bonds without regard to an interest
coverage test and approximately $961 million supported by
additional property currently certified and available, assuming a
10% interest rate. In the event of a significant write-down in
the future, the Company will likely be precluded from issuing
first mortgage bonds based on additional property and the
earnings test, for at least the twelve months subsequent to such
write-down.
The Company also has $200 million of Preference Stock
authorized for sale. Current market conditions preclude the
Company from issuing preferred or preference stock in 1996 due to
the downgrading of the Company's security ratings. The Company's
charter also limits the amount of unsecured indebtedness that may
be incurred by the Company to 10% of consolidated capitalization
plus $50 million. At December 31, 1995, this charter restriction
is approximately $683 million and the Company's unsecured debt
outstanding is $200 million.
REPORT OF MANAGEMENT
- --------------------
The consolidated financial statements of Niagara Mohawk
Power Corporation and its subsidiaries were prepared by and are
the responsibility of management. Financial information
contained elsewhere in this Annual Report is consistent with that
in the financial statements.
To meet its responsibilities with respect to financial
information, management maintains and enforces a system of
internal accounting controls, which is designed to provide
reasonable assurance, on a cost effective basis, as to the
integrity, objectivity and reliability of the financial records
and protection of assets. This system includes communication
through written policies and procedures, an organizational
structure that provides for appropriate division of
responsibility and the training of personnel. This system is
also tested by a comprehensive internal audit program. In
addition, the Company has a Corporate Policy Register and a Code
of Business Conduct that supply employees with a framework
describing and defining the Company's overall approach to
business and requires all employees to maintain the highest level
of ethical standards as well as requiring all management
employees to formally affirm their compliance with the Code.
The financial statements have been audited by Price
Waterhouse LLP, the Company's independent accountants, in
accordance with generally accepted auditing standards. In
planning and performing its audit, Price Waterhouse considered
the Company's internal control structure in order to determine
auditing procedures for the purpose of expressing an opinion on
the financial statements, and not to provide assurance on the
internal control structure. The independent accountants' audit
does not limit in any way management's responsibility for the
fair presentation of the financial statements and all other
information, whether audited or unaudited, in this Annual Report.
The Audit Committee of the Board of Directors, consisting of five
outside directors who are not employees, meets regularly with
management, internal auditors and Price Waterhouse to review and
discuss internal accounting controls, audit examinations and
financial reporting matters. Price Waterhouse and the Company's
internal auditors have free access to meet individually with the
Audit Committee at any time, without management being present.
REPORT OF INDEPENDENT ACCOUNTANTS
- ---------------------------------
To the Stockholders and
Board of Directors of
Niagara Mohawk Power Corporation
In our opinion, the accompanying consolidated balance sheets and
the related consolidated statements of income and retained
earnings and of cash flows present fairly, in all material
respects, the financial position of Niagara Mohawk Power
Corporation and its subsidiaries at December 31, 1995 and 1994,
and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1995, in
conformity with generally accepted accounting principles. These
financial statements are the responsibility of the Company's
management; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted
auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the
opinion expressed above.
As discussed in Note 2, the Company believes that it continues to
meet the requirements for application of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation" (SFAS No. 71) and that its
regulatory assets are currently probable of recovery in future
rates charged to customers. There are a number of events that
could change these conclusions in 1996 and beyond, resulting in
material adverse effects on the Company's financial condition and
results of operations. As also discussed in Note 2, the Company
has filed its PowerChoice proposal with the Public Service
Commission for restructuring the Company to facilitate a
transition to a competitive electric generation market. If it
becomes probable that the proposal (or a similar proposal) will
be implemented and certain other conditions are met by third
parties, the Company would discontinue application of (SFAS No.
71) with respect to the electric generation business and write
off the related regulatory assets, currently approximately $392
million. Such an outcome would have a material adverse effect on
the Company's results of operations and financial condition.
/s/ Price Waterhouse LLP
Syracuse, New York
January 25, 1996
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
In thousands of dollars
For the year ended
December 31, 1995 1994 1993
- -----------------------------------------------------------------
Operating revenues:
Electric $3,335,548 $3,528,987 $3,332,464
Gas 581,790 623,191 600,967
- -----------------------------------------------------------------
3,917,338 4,152,178 3,933,431
- -----------------------------------------------------------------
Operating expenses:
Operation:
Fuel for electric
generation 165,929 219,849 231,064
Electricity purchased 1,137,937 1,107,133 863,513
Gas purchased 276,232 315,714 326,273
Other operation expenses 614,930 754,695 821,247
Employee reduction program - 196,625 -
Maintenance 202,967 202,682 236,333
Depreciation and
amortization (Note 1) 317,831 308,351 276,623
Federal and foreign income
taxes (Note 7) 156,008 117,834 162,515
Other taxes 517,478 496,922 491,363
- -----------------------------------------------------------------
3,389,312 3,719,805 3,408,931
- -----------------------------------------------------------------
Operating income 528,026 432,373 524,500
- -----------------------------------------------------------------
Other income and deductions:
Allowance for other funds
used during construction
(Note 1) 1,063 2,159 7,119
Federal and foreign income
taxes (Note 7) (3,385) 6,365 15,440
Other items (net) 2,006 15,045 7,035
- -----------------------------------------------------------------
(316) 23,569 29,594
- -----------------------------------------------------------------
Income before interest
charges 527,710 455,942 554,094
- -----------------------------------------------------------------
Interest charges:
Interest on long-term debt 267,019 264,891 279,902
Other interest 20,642 20,987 11,474
Allowance for borrowed funds
used during construction (7,987) (6,920) (9,113)
- -----------------------------------------------------------------
279,674 278,958 282,263
- -----------------------------------------------------------------
Net income 248,036 176,984 271,831
Dividends on preferred stock 39,596 33,673 31,857
- -----------------------------------------------------------------
Balance available for
common stock 208,440 143,311 239,974
Dividends on common stock 161,650 156,060 133,908
- -----------------------------------------------------------------
46,790 (12,749) 106,066
Retained earnings at
beginning of year 538,583 551,332 445,266
- -----------------------------------------------------------------
Retained earnings at
end of year $ 585,373 $ 538,583 $ 551,332
=================================================================
Average number of shares
of common stock outstanding
(in thousands) 144,329 143,261 140,417
Balance available per average
share of common stock $ 1.44 $ 1.00 $ 1.71
Dividends paid per share $ 1.12 $ 1.09 $ .95
- -----------------------------------------------------------------
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
CONSOLIDATED BALANCE SHEETS
In thousands of dollars
At December 31, 1995 1994
- ---------------------------------------------------------
ASSETS
Utility plant (Note 1):
Electric plant $ 8,543,429 $ 8,285,263
Nuclear Fuel 517,681 504,320
Gas plant 1,017,062 922,459
Common plant 281,525 291,962
Construction work in progress 289,604 481,335
- ---------------------------------------------------------
Total utility plant 10,649,301 10,485,339
Less: Accumulated
depreciation and
amortization 3,641,448 3,449,696
- ---------------------------------------------------------
Net utility plant 7,007,853 7,035,643
- ---------------------------------------------------------
Other property and
investments 218,417 224,039
- ---------------------------------------------------------
Current assets:
Cash, including temporary
cash investments of $114,415
and $50,052, respectively 153,475 94,330
Accounts receivable (less
allowance for doubtful accounts
of $20,000 and $3,600,
respectively) (Notes 1 and 9) 463,234 513,982
Electric margin recoverable 8,208 66,796
Materials and supplies, at
average cost:
Coal and oil for production
of electricity 27,509 31,652
Gas storage 26,431 30,931
Other 141,820 150,186
Prepaid taxes 17,239 43,249
Other 45,834 45,189
- ---------------------------------------------------------
883,750 976,315
- ---------------------------------------------------------
Regulatory assets (Note 2):
Regulatory tax asset 470,198 465,109
Deferred finance charges 239,880 239,880
Deferred environmental
restoration costs (Note 9) 225,000 240,000
Unamortized debt expense 92,548 105,457
Postretirement benefits other
than pensions 68,933 67,486
Other 204,253 227,542
- ---------------------------------------------------------
1,300,812 1,345,474
- ---------------------------------------------------------
Other assets 67,037 68,345
- ---------------------------------------------------------
$9,477,869 $9,649,816
=========================================================
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
CONSOLIDATED BALANCE SHEETS
In thousands of dollars
At December 31, 1995 1994
- ---------------------------------------------------------
CAPITALIZATION AND LIABILITIES
Capitalization (Note 5):
Common stockholders' equity:
Common stock, issued
144,332,123 and 144,311,466
shares, respectively $ 144,332 $ 144,311
Capital stock premium
and expense 1,784,247 1,779,504
Retained earnings 585,373 538,583
- ---------------------------------------------------------
2,513,952 2,462,398
Non-redeemable preferred stock 440,000 440,000
Mandatorily redeemable
preferred stock 96,850 106,000
Long-term debt 3,582,414 3,297,874
- ---------------------------------------------------------
Total capitalization 6,633,216 6,306,272
- ---------------------------------------------------------
Current liabilities:
Short-term debt (Note 6) - 416,750
Long-term debt due within
one year (Note 5) 65,064 77,971
Sinking fund requirements on
redeemable preferred stock
(Note 5) 9,150 10,950
Accounts payable 268,603 277,782
Payable on outstanding bank
checks 36,371 64,133
Customers' deposits 14,376 14,562
Accrued taxes 14,770 43,358
Accrued interest 64,448 63,639
Accrued vacation pay 35,214 36,550
Other 57,748 64,687
- ---------------------------------------------------------
565,744 1,070,382
- ---------------------------------------------------------
Regulatory liabilities (Note 2):
Deferred finance charges 239,880 239,880
Other 2,712 16,580
- ---------------------------------------------------------
242,592 256,460
- ---------------------------------------------------------
Other liabilities:
Accumulated deferred income
taxes (Notes 1 and 7) 1,388,799 1,258,463
Employee pension and other
benefits (Note 8) 245,047 248,872
Deferred pension settlement
gain 32,756 50,261
Unbilled revenues (Note 1) 28,410 93,668
Other 116,305 125,438
- ---------------------------------------------------------
1,811,317 1,776,702
- ---------------------------------------------------------
Commitments and contingencies (Notes 2 and 9):
Liability for environmental
restoration 225,000 240,000
- ---------------------------------------------------------
$9,477,869 $9,649,816
=========================================================
(CAPTION>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
INCREASE (DECREASE) IN CASH
In thousands of dollars
For the year ended December 31, 1995 1994 1993
- -----------------------------------------------------------------
Cash flows from operating activities:
Net income $ 248,036 $ 176,984 $ 271,831
Adjustments to reconcile
net income to net cash
provided by operating
activities:
Amortization of nuclear
replacement power cost
disallowance - (23,081) (23,720)
Depreciation and amortization 317,831 308,351 276,623
Amortization of nuclear fuel 34,295 37,887 35,971
Provision for deferred income
taxes 114,917 7,866 30,067
Electric margin recoverable 58,588 (45,428) (9,773)
Employee reduction program - 196,625 -
Deferred recoverable energy
costs 46,489 4,748 (5,688)
Gain on sale of subsidiary (11,257) - (5,490)
Unbilled revenues (71,258) - -
Sale of accounts receivable 50,000 - -
(Increase) decrease in net
accounts receivable 6,748 (59,145) (36,972)
Decrease in materials
and supplies 13,663 6,290 43,581
Increase (decrease) in accounts
payable and accrued expenses (47,048) (5,991) 15,716
Increase (decrease) in accrued
interest and taxes (35,440) (19,914) 3,996
Changes in other assets and
liabilities (33,974) 12,029 19,251
- -----------------------------------------------------------------
Net cash provided by
operating activities 691,590 597,221 615,393
- -----------------------------------------------------------------
Cash flows from investing activities:
Construction additions (332,443) (439,289) (506,267)
Nuclear fuel (13,361) (46,134) (12,296)
Less: Allowance for other
funds used during construction 1,063 2,159 7,119
- -----------------------------------------------------------------
Acquisition of utility plant (344,741) (483,264) (511,444)
Decrease in materials and
supplies related to con-
struction 3,346 5,143 3,837
Increase (decrease) in accounts
payable and accrued expenses
related to construction (7,112) (1,498) 3,929
Increase in other investments (115,818) (23,375) (26,774)
Proceeds from sale of sub-
sidiary (net of cash sold) 161,087 - 95,408
Other 26,234 (17,979) (15,260)
- -----------------------------------------------------------------
Net cash used in investing
activities (277,004) (520,973) (450,304)
- -----------------------------------------------------------------
Cash flows from financing activities:
Proceeds from sale of common
stock 304 29,514 116,764
Proceeds from long-term debt 346,000 424,705 635,000
Issuance of preferred stock - 150,000 -
Redemption of preferred stock (10,950) (33,450) (47,200)
Reductions of long-term debt (65,000) (526,584) (641,990)
Net change in short-term debt (416,750) 48,734 50,318
Dividends paid (201,246) (189,733) (165,765)
Other (7,799) (9,455) (31,759)
- -----------------------------------------------------------------
Net cash used in financing
activities (355,441) (106,269) (84,632)
- -----------------------------------------------------------------
Net increase (decrease) in cash 59,145 (30,021) 80,457
Cash at beginning of year 94,330 124,351 43,894
- -----------------------------------------------------------------
Cash at end of year $ 153,475 $ 94,330 $ 124,351
=================================================================
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest $ 290,352 $ 300,242 $ 300,791
Income taxes $ 47,378 $ 136,876 $ 106,202
/TABLE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ------------------------------------------
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Company is subject to regulation by the PSC and FERC
with respect to its rates for service under a methodology which
establishes prices based on the Company's cost. The Company's
accounting policies conform to generally accepted accounting
principles (GAAP), as applied to regulated public utilities, and
are in accordance with the accounting requirements and ratemaking
practices of the regulatory authorities (see Note 2). In order
to be in conformity with GAAP, management is required to use
estimates in the preparation of the Company's financial
statements.
PRINCIPLES OF CONSOLIDATION: The consolidated financial
statements include the Company and its wholly-owned subsidiaries.
Intercompany balances and transactions have been eliminated.
UTILITY PLANT: The cost of additions to utility plant and
of replacements of retirement units of property is capitalized.
Cost includes direct material, labor, overhead and AFC.
Replacement of minor items of utility plant and the cost of
current repairs and maintenance is charged to expense. Whenever
utility plant is retired, its original cost, together with the
cost of removal, less salvage, is charged to accumulated
depreciation.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION: The Company
capitalizes AFC in amounts equivalent to the cost of funds
devoted to plant under construction. AFC rates are determined in
accordance with FERC and PSC regulations. The AFC rate in effect
at December 31, 1995 was 7.47%. AFC is segregated into its two
components, borrowed funds and other funds, and is reflected in
the Interest charges and the Other income and deductions
sections, respectively, of the Consolidated Statements of Income.
DEPRECIATION, AMORTIZATION AND NUCLEAR GENERATING PLANT
DECOMMISSIONING COSTS: For accounting and regulatory purposes,
depreciation is computed on the straight-line basis using the
remaining service lives for nuclear and hydro classes of
depreciable property and the average service lives for all other
classes. The percentage relationship between the total provision
for depreciation and average depreciable property was 3.3% for
both years 1995 and 1994, and 3.2% for 1993. The Company
performs depreciation studies to determine service lives of
classes of property and adjusts the depreciation reserves and
rates when necessary.
Estimated decommissioning costs (costs to remove a nuclear
plant from service in the future) for the Company's Unit 1 and
its share of Unit 2 are being accrued over the service lives of
the units, recovered in rates through an annual allowance and
currently charged to operations through depreciation. The
Company expects to commence decommissioning of both units shortly
after cessation of operations at Unit 2 (currently planned for
2026), using a method which removes or decontaminates Unit
components promptly at that time. See Note 3 - "Nuclear Plant
Decommissioning."
The Financial Accounting Standards Board (FASB) is expected
to issue an exposure draft in February 1996 entitled "Accounting
for Certain Liabilities Related to Closure or Removal of Long-
Lived Assets." The scope of the original project has broadened
and will now include the Company's fossil and hydro plants, as
well as nuclear plants. If approved as drafted, the exposure
draft would require the cost of closure and removal obligations
to be accounted for as a liability and accrued as the obligation
is incurred. The recognition of the liability would result in an
increase to the cost of the related asset and would be reported
based upon discounted future cash flows as opposed to current
cost. The Company would not be allowed to net the balance of
funds accumulated in the nuclear decommissioning trust funds
against the nuclear plant closure and removal obligation.
Additionally, the exposure draft would allow the Company to
establish a regulatory asset for the difference between costs of
closure and removal obligations recognized and the costs
allowable for rate-making purposes, subject to the provisions of
SFAS No. 71. As noted above, the Company currently recognizes
the liability for nuclear decommissioning over the service life
of the plant and as an increase to accumulated depreciation based
on amounts allowed in rates. The Company currently does not
reflect the closure and removal obligation associated with its
fossil and hydro plants in the financial statements. As such,
the annual provisions for depreciation could increase. Under
traditional cost based regulation such accounting changes would
not have an adverse effect on the results of operations of the
Company. However, with the filing of the Company's PowerChoice
proposal and the expectation the generating assets associated
with this obligation will face competition in the future and the
issuance of SFAS No. 121 (discussed in Note 2), the Company
cannot currently predict the impact this exposure draft may have
on the Company's future results of operations.
Amortization of the cost of nuclear fuel is determined on
the basis of the quantity of heat produced for the generation of
electric energy. The cost of disposal of nuclear fuel, which
presently is $.001 per kilowatt-hour of net generation available
for sale, is based upon a contract with the U.S. Department of
Energy. These costs are charged to operating expense and
recovered from customers through base rates or through the fuel
adjustment clause.
REVENUES: Revenues are based on cycle billings rendered to
certain customers monthly and others bi-monthly. Although the
Company commenced the practice in 1988 of accruing electric
revenues for energy consumed and not billed at the end of the
fiscal year, the impact of such accruals has not yet been fully
recognized in the Company's results of operations because of
regulatory requirements. At December 31, 1995 and 1994,
approximately $5.2 million and $71.8 million, respectively, of
unbilled electric revenues remained unrecognized in results of
operations, are included in Other liabilities and may be used to
reduce future revenue requirements. In 1995, the Company used
$71.5 million of electric unbilled revenues to reduce the 1995
revenue requirement. At December 31, 1995 and 1994, $23.2
million and $21.9 million, respectively, of unbilled gas revenues
remain unrecognized in results of operations and may similarly be
used to reduce future gas revenue requirements. The unbilled
revenues included in accounts receivable at December 31, 1995 and
1994, were $202.7 million and $196.7 million, respectively.
The Company's tariffs include electric and gas adjustment
clauses under which energy and purchased gas costs, respectively,
above or below the levels allowed in approved rate schedules, are
billed or credited to customers. The Company, as authorized by
the PSC, charges operations for energy and purchased gas cost
increases in the period of recovery. The PSC has periodically
authorized the Company to make changes in the level of allowed
energy and purchased gas costs included in approved rate
schedules. As a result of such periodic changes, a portion of
energy costs deferred at the time of change would not be
recovered or may be overrecovered under the normal operation of
the electric and gas adjustment clauses. However, the Company
has to date been permitted to defer and bill or credit such
portions to customers, through the electric and gas adjustment
clauses, over a specified period of time from the effective date
of each change.
The Company's electric FAC provides for partial pass-through
of fuel and purchased power cost fluctuations from amounts
forecast, with the Company absorbing a portion of increases or
retaining a portion of decreases up to a maximum of $15 million
per rate year. Thereafter, 100% of the fluctuation is passed on
to ratepayers. The Company also shares with ratepayers
fluctuations from amounts forecast for net resale margin and
transmission benefits, with the Company retaining/absorbing 40%
and passing 60% through to ratepayers. The amounts retained or
absorbed in 1993 through 1995 were not material.
From 1991 through 1994, the Company's rate agreements
provided for NERAM, which permitted the Company to reconcile
actual results to forecast electric public sales gross margin as
defined and utilized in establishing rates. Depending on the
level of actual sales, a liability to customers was created if
sales exceed the forecast and an asset recorded for a sales
shortfall, thereby generally preserving recorded electric gross
margin at the level forecast in established rates. Recovery or
refund of accruals pursuant to the NERAM is accomplished by a
surcharge (either plus or minus) to customers over a twelve-month
period, to begin when cumulative amounts reach certain specified
levels.
Rate agreements since 1991 also included MERIT, under which
the Company had the opportunity to achieve earnings above its
allowed return on equity based on attainment of specified goals
associated with its self-assessment process. The MERIT program
provided for specific measurement periods and reporting for PSC
approval of MERIT earnings. Approved MERIT awards are billed to
customers over a period not greater than twelve months. The
Company records MERIT earnings when attainment of goals is
approved by the PSC or when objectively measured criteria are
achieved. MERIT expired at the end of 1995, but collections of
allowed awards will continue into 1997.
The Company's PowerChoice proposal, which the Company filed
in October 1995 as part of its multi-year electric rate
proceeding, proposed to eliminate all surcharges, including the
FAC, NERAM and MERIT surcharges.
In February 1994, the Company implemented a weather
normalization clause for retail customers who use gas for heating
to reflect the impact of variations from normal weather on a
billing month basis for the months of October through May,
inclusive. Normal weather is defined as the 30 year average
daily high and low temperatures for the Company's main gas
service territory. The weather normalization clause will only be
activated if the actual weather deviates 2.2% or more from the
normal weather. Weather normalization clause adjustments were
not significant to 1995 gas revenues. As part of the Company's
PowerChoice proposal, as well as the formal gas rate filing made
in November 1995 (See "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Multi-Year Gas
Rate Proposal"), the Company proposed elimination of the weather
normalization clause. These surcharges would be reflected in
base rates as part of the Company's proposal to freeze overall
prices.
ALLOWANCE FOR DOUBTFUL ACCOUNTS: The allowance for doubtful
accounts receivable on the consolidated balance sheets amounted
to $20.0 million and $3.6 million at December 31, 1995 and 1994,
respectively. The Company increased its allowance for doubtful
accounts in 1995 and recorded a regulatory asset of $16.4
million, which reflects the amount that the Company expects to
recover in rates. Previously, the Company netted expected rate
recoveries for bad debt expense from expected uncollectible
accounts in determining its allowance for doubtful accounts,
which was consistent with the manner in which this item is
treated in its ratemaking.
FEDERAL INCOME TAXES: As directed by the PSC, the Company
defers any amounts payable pursuant to the alternative minimum
tax rules. Deferred investment tax credits are amortized to
Other Income and Deductions over the useful life of the
underlying property.
STATEMENT OF CASH FLOWS: The Company considers all highly
liquid investments, purchased with a remaining maturity of three
months or less, to be cash equivalents.
RECLASSIFICATIONS: Certain amounts from prior years have
been reclassified on the accompanying Consolidated Financial
Statements to conform with the 1995 presentation.
NOTE 2. RATE AND REGULATORY ISSUES AND CONTINGENCIES
The Company's financial statements conform to GAAP, as
applied to regulated public utilities and reflect the application
of SFAS No. 71. Substantively, SFAS No. 71 permits a public
utility regulated on a cost-of-service basis to defer certain
costs when authorized to do so by the regulator which would
otherwise be charged to expense. These deferred costs are known
as regulatory assets, which in the case of the Company are
approximately $1,058 million, net of approximately $242 million
of regulatory liabilities at December 31, 1995. The portion of
the $1,058 million which has been allocated to the electric
business is approximately $890 million. Generally, regulatory
assets and liabilities were allocated to the portion of the
business that incurred the underlying transaction that resulted
in the recognition of the regulatory asset or liability. The
allocation methods used between electric and gas were consistent
with those used in prior regulatory proceedings.
While the allocation of regulatory assets and liabilities at
December 31, 1995 is based on management's assessment, a final
determination can only be made at the time the Company, or a
portion thereof, discontinues the application of SFAS No. 71.
Currently, substantially all of the Company's regulatory assets
have been approved by the PSC and are being amortized to expense
as they are being recovered in rates as last established in April
1995.
RATE FILING. The Company filed in February 1996 a request
to increase electric rates. This rate increase request of 4.1%
for 1996 and 4.2% for 1997 was based on the Company's cost of
providing services. The Company requested that its 4.1% increase
for 1996 be implemented immediately with a provision that rates
charged will be subject to refund if later it is determined that
some portion of the request is not allowed by the PSC. These
rate increases are predicated on a requested rate of return on
common stock equity of approximately 11% on an annual basis and
recover the Company's cost of providing electric service. On
February 16, 1996, the PSC issued an Order that, among other
things, established a schedule with respect to temporary rates
that would have the case certified directly to the PSC within 60
days of the order. The Company believes that the PSC will
approve rate increases on a timely basis in levels sufficient to
enable it to earn a reasonable return on equity in 1996 and 1997.
As a result the Company believes that it will continue to be
regulated on a cost-of-service basis which will enable it to
continue to apply SFAS No. 71. Accordingly, the Company believes
its regulatory assets are currently probable of recovery. While
various proposals have been made to develop a new regulatory
model, including the Company's PowerChoice proposal, none of
these proposals are currently probable of implementation since a
number of parties are required to act on the change in the
regulatory model. The Company expects that the PSC will approve
cost-of-service based rate increases that will result in the
Company earning a reasonable return on common equity until such
time as implementation of a new competitive market model becomes
probable.
While the Company believes that it continues to meet the
requirements for the application of SFAS No. 71 to the electric
business, there are a number of events that could change that
conclusion during 1996 and beyond. Those future events include:
inaction or inadequate action on the Company's rate request by
the PSC; a decision by the Company in the future not to pursue
the rate requests filed; unanticipated reduction in electricity
usage by customers; unanticipated customer discounts; adverse
results of litigation; and a change in the regulatory model
becoming probable.
As discussed in Management's Discussion and Analysis of
Financial Condition and Results of Operations, the Company has
been unable to earn its allowed rate of return in 1995 and 1994.
Additionally, if the Company's rate increase proposals with
respect to 1996 and 1997 are not approved, then the Company will,
more likely than not, be unable to earn a reasonable return on
its common equity for such years. The inability of the Company
to earn a reasonable rate of return on common equity over a
sustained period would indicate that its rates are not based on
its cost of service. In such a case, application of SFAS No. 71
would be discontinued. The resulting charges against income
would reduce or possibly eliminate retained earnings, the balance
of which is currently approximately $585 million. Various tests
under applicable law and corporate instruments, including those
with respect to issuance of debt and equity securities, payment
of preferred and common dividends and certain types of transfers
of assets could be adversely impacted by any such write-downs.
In addition, such write-downs could preclude it from borrowing
additional amounts under its current revolving credit facility,
which is planned to be replaced by the proposed senior debt
facility (see Note 6) whose terms are intended to accommodate the
discontinuance of SFAS No. 71 as it applies to the Company's
electric business.
COMPETITION. The public utility industry in general, and
the Company in particular, is facing increasing competitive
threats. As competition penetrates the marketplace, it is
possible that the Company may no longer be able to continue to
apply the fundamental accounting principles of SFAS No. 71. The
Company believes that in the future some form of market-based
pricing may replace cost-based pricing in certain aspects of its
business. In that regard, in October 1995, the Company filed its
PowerChoice proposal with the PSC. PowerChoice, further
described in the Management Discussion and Analysis -
"PowerChoice Proposal", would:
* Create a competitive wholesale electricity market and allow
direct access by retail customers.
* Separate the Company's power generation business from the
remainder of the business.
* Provide relief from overpriced unregulated generator
contracts that were mandated by public policy, along with
equitable write-downs of above-market company assets.
* Freeze or cut prices for all Company electric customers for
a period of 5 years.
The separated generation business proposed in PowerChoice
would no longer be rate-regulated and, accordingly, existing
regulatory assets related to the generation business, amounting
to $392 million, net of approximately $242 million of regulatory
liabilities at December 31, 1995 (management's assessment), would
be charged against income if and when PowerChoice (or a similar
proposal) is probable of implementation. Under PowerChoice, the
Company's electric transmission and distribution business is
proposed to continue to be rate regulated on a cost-of-service
basis and, accordingly, continue to apply SFAS No. 71. The
PowerChoice proposal also includes provisions for recovery of
"stranded costs" by the generation business and unregulated
generators through surcharges on rates for transmission and
distribution customers. Stranded costs are those costs of
utilities that may become unrecoverable due to a change in the
regulatory environment and include costs related to the Company's
generating plants, regulatory assets and overpriced unregulated
generator contracts.
Critical to the price freeze and restructuring of the
Company's markets and business envisioned in the PowerChoice
proposal are substantial reductions in the Company's embedded
cost structure. Such cost reductions depend in turn on the
willingness of the UGs and the Company to absorb substantial
write-offs. The Company's proposal expresses its willingness if,
and only if, the UGs agree to cost reductions that are
proportional to their relative responsibility for strandable
cost. The Company proposes a reduction in its fixed costs of
service be made by mutual contribution of the Company's
shareholders and UGs that are in the same proportion as the
contribution of each to the problem of strandable costs, which
the Company calculates to be $4 of UG strandable cost for every
$1 of Company strandable cost. Under the Company's proposal, the
aggregate contribution would be approximately $2 billion,
consisting of $400 million by the Company and $1.6 billion by the
UGs. The Company's PowerChoice proposal faces opposition,
principally from unregulated generators. The Company does not
presently expect that its PowerChoice proposal or any other
alternative proposal could be fully effective before sometime in
1997, at the earliest.
There are also other proposals to introduce competition into
the utility marketplace presently before the PSC. In addition,
the FERC has pending proposals before it relating to open access
to the nation's transmission system and the recovery of stranded
costs.
IMPAIRMENT OF LONG-LIVED ASSETS: In March 1995, the FASB
issued SFAS No. 121. This Statement, which the Company will
adopt in 1996, requires that long-lived assets and certain
identifiable intangibles to be held and used by an entity, be
reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may
not be recoverable. In performing the review for recoverability,
the Company is required to estimate future undiscounted cash
flows expected to result from the use of the asset and its
eventual disposition. Furthermore, this Statement amends SFAS
No. 71 to clarify that regulatory assets should be charged
against earnings if the assets are no longer considered probable
of recovery rather than probable of loss. While the Company is
unable to predict the outcome of its PowerChoice proposal, or
various FERC and PSC initiatives, it has analyzed the provisions
of SFAS No. 121, as it relates to the impairment of its
investment in generating plant, under two scenarios: traditional
cost-based rate-making and its PowerChoice proposal, as filed.
As a result of these analyses, the Company does not believe the
effects of adopting SFAS No. 121, as it relates to the impairment
of its investment in generating plant, will currently have an
effect on its results of operations and financial condition. In
addition, the Company expects that the PSC will approve cost-of-
service based rate increases until such time as a new competitive
regulatory model is developed. As a result, the Company believes
currently that its regulatory assets are probable of recovery.
However, if in the future management can no longer conclude that
existing regulatory assets are probable of recovery, then all or
a portion of such regulatory assets would have to be charged to
income, which could have a material adverse effect on the
Company's financial position and results of operations.
The Company has recorded the following regulatory assets on
its Consolidated Balance Sheets reflecting the rate actions of
its regulators:
REGULATORY TAX ASSET represents the expected future recovery
from ratepayers of the tax consequences of temporary differences
between the recorded book bases and the tax bases of assets and
liabilities. This amount is primarily timing differences related
to depreciation. These amounts are amortized and recovered as
the related temporary differences reverse. In January 1993, the
PSC issued a Statement of Interim Policy on Accounting and
Ratemaking Procedures that required adoption of Statement of
Financial Accounting Standards No. 109 - "Accounting for Income
Taxes" (SFAS No. 109) on a revenue-neutral basis.
DEFERRED FINANCE CHARGES represent the deferral of the
discontinued portion of AFC related to construction work in
progress (CWIP) at Unit 2 which was included in rate base. In
1985, pursuant to PSC authorization, the Company discontinued
accruing AFC on CWIP for which a cash return was being allowed.
This amount, which was accumulated in deferred debit and credit
accounts up to the commercial operation date of Unit 2, awaits
future disposition by the PSC. A portion of the deferred credit
could be utilized to reduce future revenue requirements over a
period shorter than the life of Unit 2, with a like amount of
deferred debit amortized and recovered in rates over the
remaining life of Unit 2.
DEFERRED ENVIRONMENTAL RESTORATION COSTS represent the
Company's share of the estimated minimum costs to investigate and
perform certain remediation activities at both Company-owned
sites and non-owned sites with which it may be associated. Prior
to 1995, the Company recovered 100% of its costs associated with
site investigation and restoration. In the Company's 1995 rate
order, costs incurred during 1995 for the investigation and
restoration of Company-owned sites and sites with which it is
associated were subject to 80%/20% (ratepayer/Company) sharing.
In 1995, the Company incurred $11.5 million of such costs,
resulting in a disallowance of $2.3 million (before tax), which
the Company has recorded as a loss in Other items (net) on the
Consolidated Statements of Income. The PSC stated in its full
opinion, dated December 1995, its decision to require sharing was
"on a one-time, short-term basis only, pending its further
evaluation of the issue in future proceedings." The Company has
recorded a regulatory asset representing the remediation
obligations to be recovered from ratepayers. See Note 9 -
"Environmental Contingencies".
UNAMORTIZED DEBT EXPENSE represents the costs to issue and
redeem certain long-term debt securities which were retired prior
to maturity. These amounts are amortized as interest expense
ratably over the lives of the related issues in accordance with
PSC directives.
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS represent the
excess of such costs recognized in accordance with Statement of
Financial Accounting Standards No. 106 - "Employers' Accounting
for Postretirement Benefits Other Than Pensions" (SFAS No. 106)
over the amount received in rates. In accordance with the PSC
policy statement, postretirement benefit costs other than
pensions are being phased-in to rates over a five-year period and
amounts deferred will be amortized and recovered over a period
not to exceed 20 years.
NOTE 3. NUCLEAR OPERATIONS
The Company is the owner and operator of the 613 MW Unit 1
and the operator and a 41% co-owner of the 1,143 MW Unit 2. The
remaining ownership interests are Long Island Lighting Company
(LILCO) - 18%, New York State Electric and Gas Corporation
(NYSEG) - 18%, Rochester Gas and Electric Corporation (RG&E) -
14%, and Central Hudson Gas and Electric Corporation (Central
Hudson) - 9%. Unit 1 was placed in commercial operation in 1969
and Unit 2 in 1988.
In December 1995, a state utility board appointed by
Governor George E. Pataki developed a plan to dismantle LILCO.
The plan delayed making any recommendation as to LILCO's
ownership interest in Unit 2, but otherwise recommends the
creation of a competitive generation market on Long Island,
through the sale of existing generating capacity by LILCO. The
Company is unable to predict what effects, if any, this proposal
may have on its results of operations or financial condition,
since there are many uncertainties related to this proposal. It
is estimated that the earliest time such a plan could be
completed is one to two years.
UNIT 1 STATUS: On February 8, 1995, Unit 1 was taken out of
service for a planned refueling and maintenance outage and
returned to service on April 4, 1995. Its next refueling and
maintenance outage is scheduled to begin in February 1997. Using
the net design electric rating as a basis, Unit 1's capacity
factor for 1995 was approximately 80%. Using Nuclear Regulatory
Commission (NRC) guidelines, which reflect net maximum dependable
capacity during the most restrictive seasonal conditions, Unit
1's capacity factor was approximately 87%.
UNIT 2 STATUS: On April 8, 1995, Unit 2 was taken out of
service for a planned refueling and maintenance outage and
returned to service on June 2, 1995. Its next refueling and
maintenance outage is scheduled for Fall 1996. During the 1995
refueling outage the Company completed its power uprate project,
installed new turbine rotors and made other operational
improvements enabling the plant to increase its capacity from
1,062 MW to 1,143 MW. Using the net design electric rating as a
basis, Unit 2's capacity factor for 1995 was approximately 75%.
Using NRC guidelines as described above, Unit 2's capacity factor
was approximately 78%.
NUCLEAR PLANT DECOMMISSIONING: The Company's site specific
cost estimates for decommissioning Unit 1 and its ownership
interest in Unit 2 at December 31, 1995 are as follows:
Unit 1 Unit 2
------ ------
Site Study (year) 1995 1995
End of Plant Life (year) 2009 2026
Radioactive Dismantlement
to Begin (year) 2026 2028
Method of Decommissioning Delayed Immediate
Dismantlement Dismantlement
Cost of Decommissioning
(in 1996 dollars) (In millions)
Radioactive Components $409 $187
Non-radioactive Components 111 45
Fuel Dry Storage/Continuing Care 113 40
---- ----
$633 $272
==== ====
The Company estimates that by the time decommissioning is
completed, the above costs will ultimately amount to $1.7 billion
and $1.1 billion for Unit 1 and Unit 2, respectively, using 3.5%
as an annual inflation factor.
In addition to the costs mentioned above, the Company
expects to incur post-shutdown costs for plant rampdown,
insurance and property taxes. In 1996 dollars, these costs are
expected to amount to $99 million and $59 million for Unit 1 and
the Company's share of Unit 2, respectively. The amounts will
escalate to $182 million and $190 million for Unit 1 and the
Company's share of Unit 2, respectively.
Based upon a 1994 study, the Company had previously
estimated the cost to decommission Unit 1 to be approximately
$565 million in 1996 dollars. In addition, post-shutdown costs
were estimated to be $118 million, also in 1996 dollars. While
both estimates assume a delayed dismantlement to coincide with
Unit 2, the 1995 estimate of $633 million differs from the 1994
estimate primarily due to an increase in burial costs and the
labor associated with the non-radioactive dismantlement,
partially offset by lower waste volumes. The delayed
dismantlement approach should be the most economic after applying
the Company's weighted average cost of capital.
The Company had previously estimated the cost to
decommission its share of Unit 2 by extrapolating data from the
1994 Unit 1 decommissioning cost estimate. The extrapolated
estimate of $311 million, in 1996 dollars, differs from the 1995
study of $272 million primarily due to the estimate being based
upon plant specifics rather than extrapolated values.
NRC regulations require owners of nuclear power plants to
place funds into an external trust to provide for the cost of
decommissioning radioactive portions of nuclear facilities and
establish minimum amounts that must be available in such a trust
at the time of decommissioning. The annual allowance for Unit 1
and the Company's share of Unit 2 for the years ended December
31, 1995, 1994 and 1993 was approximately $23.7 million, $18.7
million and $18.7 million, respectively. The amount for 1995 was
based upon the NRC minimum decommissioning cost requirements of
$408 million and $185 million (in 1996 dollars) for Unit 1 and
the Company's share of Unit 2, respectively. The amounts for 1994
and 1993 were based upon site studies performed in 1989. In the
1995 rate order, the Company was authorized, until the PSC orders
otherwise, to continue to fund to the NRC minimum requirements.
In the 1997 rate filing, the Company has requested, for both
units, rate recovery for all radioactive and non-radioactive
components (including post-shutdown costs) based upon the amounts
estimated in the 1995 site specific studies described above.
There is no assurance that the decommissioning allowance
recovered in rates will ultimately aggregate a sufficient amount
to decommission the units. The Company believes that if
decommissioning costs are higher than currently estimated, the
costs would ultimately be included in the rate process under
traditional ratemaking and PowerChoice.
Decommissioning costs recovered in rates are reflected in
Accumulated depreciation and amortization on the balance sheet
and amount to $183.4 million and $134.1 million at December 31,
1995 and 1994, respectively for both Units. Additionally at
December 31, 1995, the fair value of funds accumulated in the
Company's external trusts were $108.8 million for Unit 1 and
$28.8 million for its share of Unit 2. The trusts are included
in Other property and investments. Earnings on the external
trust aggregated $20.9 million through December 31, 1995 and,
because the earnings are available to fund decommissioning, have
also been included in Accumulated depreciation and amortization.
Amounts recovered for non-radioactive dismantlement are
accumulated in an internal reserve fund which has an accumulated
balance of $39.8 million at December 31, 1995.
The FASB is expected to issue an exposure draft in February
1996 on accounting for closure and removal of long-lived assets.
See Note 1 - "Depreciation, Amortization and Nuclear Generating
Plant Decommissioning Costs."
NUCLEAR LIABILITY INSURANCE: The Atomic Energy Act of 1954,
as amended, requires the purchase of nuclear liability insurance
from the Nuclear Insurance Pools in amounts as determined by the
NRC. At the present time, the Company maintains the required
$200 million of nuclear liability insurance.
In 1993, the statutory limit for the protection of the
public under the Price-Anderson Amendments Act of 1988 (the Act)
were further increased. With respect to a nuclear incident at a
licensed reactor, the statutory limit, which is in excess of the
$200 million of nuclear liability insurance, is currently $8.3
billion without the 5% surcharge discussed below. This limit
would be funded by assessments of up to $75.5 million for each of
the 110 presently licensed nuclear reactors in the United States,
payable at a rate not to exceed $10 million per reactor per year.
Such assessments are subject to periodic inflation indexing and
to a 5% surcharge if funds prove insufficient to pay claims.
The Company's interest in Units 1 and 2 could expose it to a
maximum potential loss, for each accident, of $111.8 million
through assessments of $14.1 million per year in the event of a
serious nuclear accident at its own or another licensed U.S.
commercial nuclear reactor. The amendments also provide, among
other things, that insurance and indemnity will cover
precautionary evacuations, whether or not a nuclear incident
actually occurs.
NUCLEAR PROPERTY INSURANCE: The Nine Mile Point Nuclear
Site has $500 million primary nuclear property insurance with the
Nuclear Insurance Pools (ANI/MRP). In addition, there is $2,250
million in excess of the $500 million primary nuclear insurance
with Nuclear Electric Insurance Limited (NEIL). The total
nuclear property insurance is $2.75 billion. NEIL is a utility
industry-owned mutual insurance company chartered in Bermuda.
NEIL also provides insurance coverage against the extra expense
incurred in purchasing replacement power during prolonged
accidental outages. The insurance provides coverage for outages
for 156 weeks, after a 21-week waiting period.
NEIL insurance is subject to retrospective premium
adjustment under which the Company could be assessed up to
approximately $17.7 million per loss.
LOW LEVEL RADIOACTIVE WASTE: The Federal Low Level
Radioactive Waste Policy Act as amended in 1985 requires states
to join compacts or to individually develop their own low level
radioactive waste disposal site. In response to the Federal law,
New York State decided to develop its own site because of the
large volume of low level radioactive waste it generates, and
committed to develop a plan for the management of low level
radioactive waste in New York State during the interim period
until a disposal facility is available.
New York State is still developing a disposal methodology
and acceptance criteria for a disposal facility. The latest New
York State low level radioactive waste site development schedule
now assumes two possible siting scenarios, a volunteer approach
and a non-volunteer approach, either of which would begin
operation in 2001. The Company currently uses the Barnwell,
South Carolina waste disposal facility for low level radioactive
waste, however access to Barnwell was denied by the State of
South Carolina to out of region low level waste generators,
including New York State from July 1, 1994 to July 1, 1995. The
Company also has implemented a low level radioactive waste
management program so that Unit 1 and Unit 2 are prepared to
properly handle interim on-site storage of low level radioactive
waste for at least a 10 year period.
NUCLEAR FUEL DISPOSAL COST: In January 1983, the Nuclear
Waste Policy Act of 1982 (the Nuclear Waste Act) established a
cost of $.001 per kilowatt-hour of net generation for current
disposal of nuclear fuel and provides for a determination of the
Company's liability to the Department of Energy (DOE) for the
disposal of nuclear fuel irradiated prior to 1983. The Nuclear
Waste Act also provides three payment options for liquidating
such liability and the Company has elected to delay payment, with
interest, until the year in which the Company initially plans to
ship irradiated fuel to an approved DOE disposal facility.
Progress in developing the DOE facility has been slow and it is
anticipated that the DOE facility will not be ready to accept
deliveries until at least 2010. The Company does not anticipate
that the DOE will accept all of its spent fuel immediately upon
opening of the facility, but rather expects a transfer period
that will extend to the year 2044. The Company has several
alternatives under consideration to provide additional storage
facilities, as necessary. Each alternative will likely require
NRC approval, may require other regulatory approvals and would
likely require incurring additional costs, which the Company has
included in its decommissioning estimates for both Unit 1 and its
share of Unit 2. The Company does not believe that the possible
unavailability of the DOE disposal facility until 2010 will
inhibit operation of either Unit.
NOTE 4. JOINTLY-OWNED GENERATING FACILITIES
The following table reflects the Company's share of jointly-
owned generating facilities at December 31, 1995. The Company is
required to provide its respective share of financing for any
additions to the facilities. Power output and related expenses
are shared based on proportionate ownership. The Company's share
of expenses associated with these facilities is included in the
appropriate operating expenses in the Consolidated Statements of
Income.
In thousands of dollars
-----------------------------------------------
Percent Utility Accumulated Construction
Ownership Plant Depreciation Work in Progress
- ------------------------------------------------------------------------------------------
Roseton Steam Station
Units No. 1 and 2 (a) 25 $ 95,540 $ 48,385 $ 1,345
Oswego Steam Station
Unit No. 6 (b) 76 $ 271,472 $ 111,631 $ 782
Nine Mile Point Nuclear
Station Unit No. 2 (c) 41 $1,519,351 $ 272,888 $ 5,105
- ------------------------------------------------------------------------------------------
(a) The remaining ownership interests are Central Hudson, the operator of the plant
(35%), and Consolidated Edison Company of New York, Inc. (40%). Output of Roseton
Units No. 1 and 2, which have a capability of 1,200,000 kw., is shared in the same
proportions as the cotenants' respective ownership interests.
(b) The Company is the operator. The remaining ownership interest is RG&E (24%). Output
of Oswego Unit No. 6, which has a capability of 850,000 kw., is shared in the same
proportions as the cotenants' respective ownership interests.
(c) The Company is the operator. The remaining ownership interests are LILCO (18%),
NYSEG (18%), RG&E (14%), and Central Hudson (9%). Output of Unit 2, which has a
capability of 1,143,000 kw., is shared in the same proportions as the cotenants'
respective ownership interests.
NOTE 5. CAPITALIZATION
- ----------------------
CAPITAL STOCK
The Company is authorized to issue 185,000,000 shares of
common stock, $1 par value; 3,400,000 shares of preferred stock,
$100 par value; 19,600,000 shares of preferred stock, $25 par
value; and 8,000,000 shares of preference stock; $25 par value.
The table below summarizes changes in the capital stock issued
and outstanding and the related capital accounts for 1993, 1994
and 1995:
COMMON STOCK
$1 PAR VALUE
--------------------------
SHARES AMOUNT*
- --------------------------------------------------------
December 31, 1992: 137,159,607 $137,160
Issued 5,267,450 5,267
Redemptions
Foreign currency
translation adjustment
- --------------------------------------------------------
December 31, 1993: 142,427,057 142,427
Issued 1,884,409 1,884
Redemptions
Foreign currency
translation adjustment
- --------------------------------------------------------
December 31, 1994: 144,311,466 144,311
Issued 20,657 21
Redemptions
Foreign currency
translation adjustment
- --------------------------------------------------------
December 31, 1995: 144,332,123 $144,332
========================================================
* In thousands of dollars
/TABLE
PREFERRED STOCK
$100 PAR VALUE
---------------------------------------
SHARES NON-REDEEMABLE* REDEEMABLE*
- --------------------------------------------------------------
December 31, 1992: 2,412,000 $210,000 $31,200 (a)
Issued - - -
Redemptions (18,000) - (1,800)
Foreign currency
translation adjustment
- --------------------------------------------------------------
December 31, 1993: 2,394,000 210,000 29,400 (a)
Issued - - -
Redemptions (18,000) - (1,800)
Foreign currency
translation adjustment
- --------------------------------------------------------------
December 31, 1994: 2,376,000 210,000 27,600 (a)
Issued - - -
Redemptions (18,000) - (1,800)
Foreign currency
translation adjustment
- --------------------------------------------------------------
December 31, 1995: 2,358,000 $210,000 $25,800 (a)
==============================================================
* In thousands of dollars
(a) Includes sinking fund requirements due within one year.
PREFERRED STOCK
$25 PAR VALUE
---------------------------------------
CAPITAL STOCK
PREMIUM AND
EXPENSE
SHARES NON-REDEEMABLE* REDEEMABLE* (NET)*
- ----------------------------------------------------------------------------
December 31, 1992: 9,856,005 $80,000 $166,400 (a) $1,658,015
Issued - - - 111,497
Redemptions (1,816,000) - (45,400) (2,471)
Foreign currency
translation adjustment (4,335)
- ----------------------------------------------------------------------------
December 31, 1993: 8,040,005 80,000 121,000 (a) 1,762,706
Issued 6,000,000 150,000 - 27,630
Redemptions (1,266,000) - (31,650) (4,619)
Foreign currency
translation adjustment (6,213)
- ----------------------------------------------------------------------------
December 31, 1994: 12,774,005 230,000 89,350 (a) 1,779,504
Issued - - - 283
Redemptions (366,000) - (9,150) 1,319
Foreign currency
translation adjustment 3,141
- ----------------------------------------------------------------------------
December 31, 1995: 12,408,005 $230,000 $ 80,200 (a) $1,784,247
============================================================================
* In thousands of dollars
(a) Includes sinking fund requirements due within one year.
The cumulative amount of foreign currency translation adjustment at December 31, 1995 was
$(10,172).
NON-REDEEMABLE PREFERRED STOCK (Optionally Redeemable)
The Company has certain issues of preferred stock which provide
for optional redemption at December 31, as follows:
- --------------------------------------------------------------
In thousands Redemption price per
of dollars share (before adding
Series Shares 1995 1994 accumulated dividends)
- --------------------------------------------------------------
Preferred $100 par value:
3.40% 200,000 $20,000 $20,000 $103.50
3.60% 350,000 35,000 35,000 104.85
3.90% 240,000 24,000 24,000 106.00
4.10% 210,000 21,000 21,000 102.00
4.85% 250,000 25,000 25,000 102.00
5.25% 200,000 20,000 20,000 102.00
6.10% 250,000 25,000 25,000 101.00
7.72% 400,000 40,000 40,000 102.36
Preferred $25 par value:
Adjustable Rate
9.50% 6,000,000 150,000 150,000 25.00 (a)
Series A 1,200,000 30,000 30,000 25.00
Series C 2,000,000 50,000 50,000 25.00
- --------------------------------------------------------------
$440,000 $440,000
==============================================================
(a) Not redeemable until 1999.
/TABLE
MANDATORILY REDEEMABLE PREFERRED STOCK
At December 31, the Company has certain issues of preferred stock, as detailed below,
which provide for mandatory and optional redemption. These series require mandatory
sinking funds for annual redemption and provide optional sinking funds through which the
Company may redeem, at par, a like amount of additional shares (limited to 120,000 shares
of the 7.45% series). The option to redeem additional amounts is not cumulative. The
Company's five year mandatory sinking fund redemption requirements for preferred stock, in
thousands, for 1996 through 2000 are as follows: $9,150; $10,120; $10,120; $7,620; and
$7,620, respectively.
- ---------------------------------------------------------------------------------
Redemption price per
share (before adding
Shares In thousands of dollars accumulated dividends)
Eventual
Series 1995 1994 1995 1994 1995 Minimum
- ---------------------------------------------------------------------------------
Preferred $100 par value:
7.45% 258,000 276,000 $ 25,800 $ 27,600 $102.17 $100.00
Preferred $25 par value:
7.85% 914,005 914,005 22,850 22,850 (a) 25.00
8.375% 300,000 400,000 7,500 10,000 25.22 25.00
8.70% - 200,000 - 5,000 - -
9.75% 144,000 210,000 3,600 5,250 25.00 25.00
Adjustable Rate
Series B 1,850,000 1,850,000 46,250 46,250 25.00 25.00
- ---------------------------------------------------------------------------------
106,000 116,950
Less sinking fund requirements 9,150 10,950
- ---------------------------------------------------------------------------------
$ 96,850 $106,000
=================================================================================
(a) Not redeemable until 1997.
LONG-TERM DEBT
Long-term debt at December 31, consisted of the following:
- -------------------------------------------------------------
In thousands of dollars
-----------------------
SERIES DUE 1995 1994
- -------------------------------------------------------------
First mortgage bonds:
5 7/8% 1996 $ 45,000 $ 45,000
6 1/4% 1997 40,000 40,000
6 1/2% 1998 60,000 60,000
9 1/2% 2000 150,000 150,000
6 7/8% 2001 210,000 210,000
9 1/4% 2001 100,000 100,000
5 7/8% 2002 230,000 230,000
6 7/8% 2003 85,000 85,000
7 3/8% 2003 220,000 220,000
8% 2004 300,000 300,000
6 5/8% 2005 110,000 110,000
9 3/4% 2005 150,000 150,000
7 3/4% 2006 275,000 -
*6 5/8% 2013 45,600 45,600
9 1/2% 2021 150,000 150,000
8 3/4% 2022 150,000 150,000
8 1/2% 2023 165,000 165,000
7 7/8% 2024 210,000 210,000
*8 7/8% 2025 75,000 75,000
* 7.2% 2029 115,705 115,705
- -------------------------------------------------------------
Total First Mortgage Bonds 2,886,305 2,611,305
Promissory notes:
*Adjustable Rate Series due
July 1, 2015 100,000 100,000
December 1, 2023 69,800 69,800
December 1, 2025 75,000 75,000
December 1, 2026 50,000 50,000
March 1, 2027 25,760 25,760
July 1, 2027 93,200 93,200
Unsecured notes payable:
Medium Term Notes, Various rates,
due 1995-2004 30,000 45,000
Swiss Franc Bonds due
December 15, 1995 - 50,000
Revolving Credit Agreement 170,000 99,000
Other 159,198 169,421
Unamortized premium (discount) (11,785) (12,641)
- --------------------------------------------------------------
TOTAL LONG-TERM DEBT 3,647,478 3,375,845
Less long-term debt due
within one year 65,064 77,971
- --------------------------------------------------------------
$3,582,414 $3,297,874
==============================================================
*Tax-exempt pollution control related issues
==============================================================
Several series of First Mortgage Bonds and Notes were issued
to secure a like amount of tax-exempt revenue bonds issued by
NYSERDA. Approximately $414 million of such securities bear
interest at a daily adjustable interest rate (with a Company
option to convert to other rates, including a fixed interest rate
which would require the Company to issue First Mortgage Bonds to
secure the debt) which averaged 3.81% for 1995 and 2.76% for 1994
and are supported by bank direct pay letters of credit. Pursuant
to agreements between NYSERDA and the Company, proceeds from such
issues were used for the purpose of financing the construction of
certain pollution control facilities at the Company's generating
facilities or to refund outstanding tax-exempt bonds and notes
(see Note 6).
Other long-term debt in 1995 consists of obligations under
capital leases of approximately $36.8 million, a liability to the
U.S. Department of Energy for nuclear fuel disposal of
approximately $103.1 million and liabilities for unregulated
generator contract terminations of approximately $19.3 million.
The aggregate maturities of long-term debt for the five
years subsequent to December 31, 1995, excluding capital leases,
are approximately $61 million, $216 million, $66 million, $0 and
$155 million, respectively.
NOTE 6. BANK CREDIT ARRANGEMENTS
At December 31, 1995, the Company had $310 million of bank
credit arrangements with 14 banks. These credit arrangements
consisted of $200 million in commitments under a Revolving Credit
Agreement, $99 million in one-year commitments under Credit
Agreements and $11 million in lines of credit. The Revolving
Credit Agreement extends into 1997 and the interest rate
applicable to borrowing is based on certain rate options
available under the Agreement. All of the other bank credit
arrangements are subject to review on an ongoing basis with
interest rates negotiated at the time of use.
In order to enhance the Company's financial flexibility
during the period 1996 through 1999, the Company entered into a
commitment letter with Citibank, N.A., Morgan Guaranty Trust
Company of New York and Toronto Dominion Bank, as co-syndication
agents (Agent Banks), for the provision of a senior debt facility
totaling $815 million for the purpose of consolidating and
refinancing certain of the Company's existing working capital
lines of credit and letter of credit facilities and providing
additional reserves of bank credit. The proposed senior debt
facility will consist of a $380 million term loan and revolving
credit facility and a $435 million letter of credit facility,
with such letter of credit facility to provide credit support for
the pollution control revenue bonds issued through NYSERDA,
discussed in Note 5. The interest rate applicable to the
facility will be variable based on certain rate options available
under the agreement and is currently expected to approximate 8%
(but capped at 13 1/4%). The commitment by the Agent Banks to
proceed with the senior debt financing will expire on the earlier
of (i) fifteen days after the senior debt financing is approved
by the PSC or (ii) March 31, 1996. As contemplated by the
commitment, the term loan and revolving credit facility and the
letter of credit facility will be collateralized by the Company's
first mortgage bonds and will expire on the earlier of June 30,
1999 or the implementation of the Company's PowerChoice
restructuring proposal or any other significant restructuring
plan.
This commitment for the senior debt facility will be subject
to the preparation and execution of loan documentation agreeable
to the parties, as well as the approval of the PSC.
The Company is seeking PSC approval on its petition in
March, 1996. In the event the petition is not approved, the
Company believes that the elimination of the common dividend, the
implementation of reductions in non-essential programs and the
year end 1995 cash position, in combination with alternative
sources of credit the Company believes are available if
necessary, will be sufficient to fund cash requirements for 1996.
Sufficient rate relief, if granted, would provide adequate funds
for 1997. The Company can provide no assurances beyond 1997 as
cash flow will depend on sales, the implementation of
PowerChoice, including UG contract renegotiations, levels of cash
rate relief, approval of the bank facility agreement, levels of
common and preferred dividends and the ability to further reduce
costs.
The Company pays fees for substantially all of its bank
credit arrangements. The following table summarizes additional
information applicable to short-term debt:
- --------------------------------------------------------
In thousands of dollars
At December 31, 1995 1994
- --------------------------------------------------------
Short-term debt:
Commercial paper $ - $ 84,750
Notes payable - 321,000
Bankers acceptances - 11,000
- ---------------------------------------------------------
$ - $416,750
Weighted average interest
rate (a) - 6.21%
- ---------------------------------------------------------
For Year Ended December 31:
- ---------------------------------------------------------
Daily average outstanding $179,505 $342,801
Monthly weighted average
interest rate (a) 6.43% 4.71%
Maximum amount outstanding $459,700 $497,700
- ---------------------------------------------------------
(a) Excluding fees.
- ---------------------------------------------------------
/TABLE
NOTE 7. FEDERAL AND FOREIGN INCOME TAXES
- -----------------------------------------
See Note 9 - "Tax Assessments."
Components of United States and foreign income before income
taxes:
In thousands of dollars
1995 1994 1993
- ---------------------------------------------------------------
United States $400,087 $291,501 $438,914
Foreign 17,609 15,475 (24,845)
Consolidating eliminations (10,267) (18,523) 4,837
- ---------------------------------------------------------------
Income before income taxes $407,429 $288,453 $418,906
===============================================================
Following is a summary of the components of Federal and
foreign income tax and a reconciliation between the amount of
Federal income tax expense reported in the Consolidated
Statements of Income and the computed amount at the statutory tax
rate:
SUMMARY ANALYSIS:
In thousands of dollars
1995 1994 1993
- --------------------------------------------------------------
Components of Federal and foreign income taxes:
Current tax expense:
Federal $ 67,563 $117,314 $118,918
Foreign 3,900 4,423 8,445
- ---------------------------------------------------------------
71,463 121,737 127,363
- ---------------------------------------------------------------
Deferred tax expense:
Federal 82,323 (6,931) 35,152
Foreign 2,222 3,028 -
- ---------------------------------------------------------------
84,545 (3,903) 35,152
- ---------------------------------------------------------------
Income taxes included in
Operating Expenses 156,008 117,834 162,515
Current Federal and
foreign income tax
credits included in
Other Income and
Deductions (197) (11,507) (16,061)
Deferred Federal and
foreign income tax
expense included in
Other Income and
Deductions 3,582 5,142 621
- ---------------------------------------------------------------
Total $159,393 $111,469 $147,075
===============================================================
Reconciliation between Federal and foreign income taxes and the
tax computed at prevailing U.S. statutory rate on income before
income taxes:
Computed tax $142,601 $100,959 $146,617
- ---------------------------------------------------------------
Reduction (increase) attributable to flow-through of certain tax
adjustments:
Depreciation (31,033) (33,328) (35,153)
Cost of removal 9,247 8,908 7,822
Deferred investment tax
credit amortization 8,589 8,018 8,018
Other (3,595) 5,892 18,855
- ---------------------------------------------------------------
(16,792) (10,510) (458)
- ---------------------------------------------------------------
Federal and foreign
income taxes $159,393 $111,469 $147,075
===============================================================
At December 31, the deferred tax liabilities (assets) were
comprised of the following:
(In thousands)
1995 1994
---- ----
Alternative minimum tax $ (82,869) $ (93,893)
Unbilled revenue (77,675) (98,201)
Other (248,275) (258,621)
---------- ----------
Total deferred tax assets (408,819) (450,715)
---------- ----------
Depreciation related 1,456,949 1,398,695
Investment tax credit related 91,458 95,325
Other 249,211 215,158
---------- ----------
Total deferred tax
liabilities 1,797,618 1,709,178
---------- ----------
Accumulated deferred income
taxes $1,388,799 $1,258,463
========== ===========
NOTE 8. PENSION AND OTHER RETIREMENT PLANS
The Company and certain of its subsidiaries have non-
contributory, defined-benefit pension plans covering
substantially all their employees. Benefits are based on the
employee's years of service and compensation level. The
Company's general policy is to fund the pension costs accrued
with consideration given to the maximum amount that can be
deducted for Federal income tax purposes.
During 1994, the Company offered an early retirement program
and a voluntary separation program (together the VERP) to reduce
the Company's staffing levels and streamline operations. The
VERP, which included both represented and non-represented
employees, was accepted by approximately 1,400 employees. The
program cost the Company approximately $208 million of which
$11.4 million, related to the gas business, was deferred with
recovery anticipated to occur over a five year period, beginning
in 1995.
Net pension cost for 1995, 1994 and 1993 included the
following components:
- -----------------------------------------------------------------
In thousands of dollars
-----------------------
1995 1994 1993
- -----------------------------------------------------------------
Service cost - benefits
earned during the period $ 22,500 $ 30,400 $ 30,100
Interest cost on projected
benefit obligation 73,000 62,700 54,200
Actual return on Plan assets (215,600) 7,700 (106,100)
Net amortization and deferral 140,300 (63,600) 38,700
- -----------------------------------------------------------------
Net pension cost 20,200 37,200 16,900
VERP costs - 114,000 -
Regulatory asset - (6,200) -
- -----------------------------------------------------------------
Total pension cost (1) $ 20,200 $145,000 $ 16,900
=================================================================
(1) $4.1 million for 1995, $5.9 million for 1994, and $5.6
million for 1993 was related to construction labor and,
accordingly, was charged to construction projects.
/TABLE
The following table sets forth the plan's funded status and
amounts recognized in the Company's Consolidated Balance Sheets:
- --------------------------------------------------------------
In thousands of dollars
-----------------------
At December 31, 1995 1994
- --------------------------------------------------------------
Actuarial present value of
accumulated benefit obligations:
Vested benefits $ 777,584 $640,689
Non-vested benefits 64,383 69,642
- --------------------------------------------------------------
Accumulated benefit obligations 841,967 710,331
Additional amounts related to
projected pay increases 135,115 222,667
- --------------------------------------------------------------
Projected benefits obligation for
service rendered to date 977,082 932,998
Plan assets at fair value, consisting
primarily of listed stocks, bonds,
other fixed income obligations
and insurance contracts (1,074,333) (893,313)
- --------------------------------------------------------------
Plan assets (in excess of) less than
projected benefit obligations (97,251) 39,685
Unrecognized net obligation at
January 1, 1987 being recognized
over approximately 19 years (21,500) (27,122)
Unrecognized net gain from actual
return on plan assets different
from that assumed 198,035 58,379
Unrecognized net gain from past
experience different from that
assumed and effects of changes
in assumptions amortized over 10
years 46,982 67,857
Prior service cost not yet recognized
in net periodic pension cost (41,291) (44,421)
- ---------------------------------------------------------------
Pension liability included
in the consolidated balance sheets $ 84,975 $ 94,378
===============================================================
Principle Actuarial Assumptions (%):
Discount Rate 7.50 8.00
Rate of increase in future
compensation levels (plus
merit increases) 2.50 3.25
Long-term rate of return on
plan assets 9.25 8.75
===============================================================
In addition to providing pension benefits, the Company and
its subsidiaries provide certain health care and life insurance
benefits for active and retired employees and dependents. Under
current policies, substantially all of the Company's employees
may be eligible for continuation of some of these benefits upon
normal or early retirement.
The Company accounts for the cost of these benefits in
accordance with PSC policy requirements which generally comply
with SFAS No. 106. The Company has established various trusts to
fund its future postretirement benefit obligation. In 1995, the
Company made contributions to such trusts of approximately $53.1
million, which represented the amount received in rates, certain
capital portions of the postretirement benefit obligation and
amounts received from co-tenants. In 1994 and 1993, the Company
contributed $24 million and $12 million, respectively, which
represented the amount received in rates.
Net postretirement benefit cost for 1995, 1994 and 1993
included the following components:
- -----------------------------------------------------------------
In thousands of dollars
----------------------------
1995 1994 1993
- -----------------------------------------------------------------
Service cost - benefits attributed
to service during the period $12,600 $ 15,000 $12,300
Interest cost on accumulated
benefit obligation 45,400 40,200 32,800
Actual return on plan assets (11,200) (900) -
Amortization of the transition
obligation over 20 years 18,800 20,200 20,400
Net amortization 14,600 8,900 -
- -----------------------------------------------------------------
Net postretirement benefit cost 80,200 83,400 65,500
VERP costs - 80,200 -
Regulatory asset - (4,300) -
- -----------------------------------------------------------------
Total postretirement benefit
cost $80,200 $159,300 $65,500
=================================================================
The following table sets forth the plan's funded status and
amounts recognized in the Company's Consolidated Balance Sheet:
- -----------------------------------------------------------
In thousands of dollars
-----------------------
At December 31, 1995 1994
- -----------------------------------------------------------
Actuarial present value of accumulated benefit obligation:
Retired and surviving spouses $214,367 $371,223
Active eligible 24,374 20,400
Active ineligible 397,547 208,900
- ------------------------------------------------------------
Accumulated benefit obligation 636,288 600,523
Plan assets at fair value,
consisting primarily of
listed stocks, bonds and
other fixed obligations (101,721) (36,754)
- -----------------------------------------------------------
Accumulated postretirement
benefit obligation in excess
of plan assets 534,567 563,769
Unrecognized net gain from
actual return on plan assets
different from that assumed 8,713 -
Unrecognized net loss from
past experience different from
that assumed and effects of
changes in assumptions (64,612) (71,939)
Unrecognized transition obligation
being amortized over 20 years (318,596) (337,336)
- -----------------------------------------------------------
Accrued postretirement benefit
liability included in the
consolidated balance sheet $160,072 $154,494
===========================================================
===========================================================
Principal actuarial assumptions (%):
Discount rate 7.50 8.00
Long-term rate of return
on plan assets 9.25 8.75
Health care cost trend rate:
Pre-65 8.25 9.75
Post-65 5.25 6.75
===========================================================
At December 31, 1995, the assumed health cost trend rates
gradually decline to 5.0% in 1999. If the health care cost trend
rate was increased by one percent, the accumulated postretirement
benefit obligation as of December 31, 1995 would increase by
approximately 10.9% and the aggregate of the service and interest
cost component of net periodic postretirement benefit cost for
the year would increase by approximately 13.6%.
On January 1, 1994, the Company adopted Statement of
Financial Accounting Standards No. 112, "Employers' Accounting
for Postemployment Benefits" (SFAS No. 112). This Statement
requires employers to recognize the obligation to provide
postemployment benefits if the obligation is attributable to
employees' past services, rights to those benefits are vested,
payment is probable and the amount of the benefits can be
reasonably estimated. At December 31, 1995 and 1994, the
Company's postemployment benefit obligation is approximately
$12.5 million and $26.3 million, respectively, including the
portion of the obligation related to the VERP. At December 31,
1995, the Company has recorded a regulatory asset of
approximately $10.4 million, the majority of which will be
recovered over three years beginning in 1995.
NOTE 9. COMMITMENTS AND CONTINGENCIES
See Note 2 and Note 6.
LONG-TERM CONTRACTS FOR THE PURCHASE OF ELECTRIC POWER: At
January 1, 1996, the Company had long-term contracts to purchase
electric power from the following generating facilities owned by
NYPA:
- -----------------------------------------------------------------
Expiration Purchased Estimated
Date of Capacity Annual
Facility Contract in kw. Capacity Cost
- -----------------------------------------------------------------
Niagara - hydroelectric
project 2007 951,000(a) $25,200,000
St. Lawrence - hydroelectric
project 2007 104,000 1,300,000
Blenheim-Gilboa - pumped
storage generating station 2002 270,000 7,500,000
Fitzpatrick - nuclear plant year-
to-
year
basis(b) 110,000(c) 7,900,000
- -----------------------------------------------------------------
1,435,000 $41,900,000
=================================================================
(a) 943,000 kw for summer of 1996; 951,000 kw for winter of
1996-97.
(b) The Company has agreed to not terminate or reduce purchases
before May 1, 1997 if NYPA does not increase rates.
(c) 72,000 kw for summer of 1996; 110,000 kw for winter of 1996-
97.
The purchase capacities shown above are based on the
contracts currently in effect. The estimated annual capacity
costs are subject to price escalation and are exclusive of
applicable energy charges. The total cost of purchases under
these contracts was approximately $92.5 million, $85.1 million,
and $72.2 million for the years 1995, 1994 and 1993,
respectively.
Under the requirements of the Federal Public Utility
Regulatory Policies Act of 1978, the Company is required to
purchase power generated by unregulated generators, as defined
therein. The Company has virtually all unregulated generator
capacity on line, amounting to approximately 2,708 MW of capacity
at December 31, 1995. Of this amount 2,390 MW is considered
firm.
The following table shows the payments for fixed capacity
costs and energy and related taxes the Company estimates it will
be obligated to make under these contracts. The payments are
subject to the tested capacity and availability of the
facilities, scheduling and price escalation.
- ---------------------------------------------------------
(In thousands of dollars)
SCHEDULABLE
FIXED COSTS
------------------
YEAR CAPACITY OTHER ENERGY TOTAL
- ---------------------------------------------------------
1996 $201,000 $40,000 $ 863,000 $1,104,000
1997 213,000 41,000 921,000 1,175,000
1998 237,000 42,000 947,000 1,226,000
1999 241,000 43,000 981,000 1,265,000
2000 229,000 44,000 1,020,000 1,293,000
- ---------------------------------------------------------
The fixed costs relate to contracts with 10 facilities where
the Company is required to make fixed payments, including
payments when a facility is not operating but available for
service. These 10 facilities account for approximately 708 MW of
capacity, with contract lengths ranging from 20 to 35 years. The
terms of these contracts allow the Company to schedule energy
deliveries from the facilities and then pay for the energy
delivered. The Company estimates the fixed payments under these
contracts will aggregate to approximately $7.7 billion over their
terms, using escalated contract rates. Contracts relating to the
remaining facilities in service at December 31, 1995, require the
Company to pay only when energy is delivered. The Company
currently recovers schedulable capacity through base rates and
energy payments, taxes and other schedulable fixed costs through
the FAC.
The Company paid approximately $980 million, $960 million
and $736 million in 1995, 1994 and 1993 for 14,000,000 MWh,
14,800,000 MWh and 11,720,000 MWh, respectively, of electric
power under all unregulated generator contracts.
In an effort to reduce the costs associated with unregulated
generators, at December 31, 1995, the Company had agreed to buy
out 17 projects consisting of 457 MW of capacity. Additionally,
the Company has entered into agreements with 41 projects,
comprising 1,153 MW of capacity, which allow the Company to
curtail purchases from these UGs when demand is low or otherwise
provide cost reductions or operational benefits. The Company
expects to continue efforts of these types into the future, to
control its power supply and related costs, but at this time
cannot predict the outcome of such efforts. (See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations - Unregulated Generators").
SALE OF CUSTOMER RECEIVABLES: The Company has an agreement
whereby it can sell an undivided interest in a designated pool of
customer receivables, including accrued unbilled electric
revenues. The agreement was amended in September 1995 to allow
for sale of an additional $50 million of customer receivables.
The Company sold this additional $50 million in the fourth
quarter of 1995, thereby bringing the total amount of receivables
sold under the agreement to $250 million. For receivables sold,
the Company has retained collection and administrative
responsibilities as agent for the purchaser. As collections
reduce previously sold undivided interests, new receivables are
customarily sold.
At December 31, 1995 and 1994, $250 million and $200
million, respectively, of receivables had been sold under this
agreement. The undivided interest in the designated pool of
receivables was sold with limited recourse. The agreement
provides for a loss reserve pursuant to which additional customer
receivables are assigned to the purchaser to protect against bad
debts. Under the terms of the agreement, a formula determines
the amount of the loss reserve. At December 31, 1995, the amount
of additional receivables assigned to the purchaser, as a loss
reserve, was approximately $78.3 million. Although this
represents the formula-based amount of credit exposure at
December 31, 1995 under the agreement, historical losses have
been substantially less.
To the extent actual loss experience of the pool receivables
exceeds the loss reserve, the purchaser absorbs the excess.
Concentrations of credit risk to the purchaser with respect to
accounts receivable are limited due to the Company's large,
diverse customer base within its service territory. The Company
generally does not require collateral, i.e., customer deposits.
TAX ASSESSMENTS: The Internal Revenue Service (IRS) has
conducted an examination of the Company's Federal income tax
returns for the years 1987 and 1988 and has submitted a Revenue
Agents' Report to the Company. The IRS has proposed various
adjustments to the Company's federal income tax liability for
these years which could increase Federal income tax liability by
approximately $80 million, before assessment of penalties and
interest. Included in these proposed adjustments are several
significant issues involving Unit 2. The Company is vigorously
defending its position on each of the issues, and submitted a
protest to the IRS in 1993. Pursuant to the Unit 2 settlement
entered into with the PSC in 1990, to the extent the IRS is able
to sustain adjustments, the Company will be required to absorb a
portion of any assessment. The Company believes any such
disallowance will not have a material impact on its financial
position or results of operations under traditional ratemaking.
The Company is currently attempting to negotiate a settlement of
these issues with the Appeals Division of the IRS.
In addition, the IRS is currently examining the years 1989
and 1990. The Company received a Revenue Agents' Report in late
January 1996. The IRS has raised the issue concerning the
deductibility of advance payments made to UGs in accordance with
certain contracts that include a provision for an Advance Payment
Account. The IRS proposes to disallow a current deduction for
amounts paid in excess of the avoided costs by the Company.
Although the Company believes that any such disallowance for the
years 1989 and 1990 will not have a material impact on its
financial position or results of operations, it believes that a
disallowance for these above-market payments for the years
subsequent to 1990 could have a material adverse affect on its
cash flows. The Company is vigorously defending its position on
this issue.
LITIGATION: The Company is unable to predict the ultimate
disposition of the lawsuits referred to below. However, the
Company believes it has meritorious defenses and intends to
defend these lawsuits vigorously, but can neither provide any
judgment regarding the likely outcome nor provide any estimate or
range of possible loss. Accordingly, no provision for liability,
if any, that may result from these lawsuits has been made in the
Company's financial statements.
(a) In March 1993, Inter-Power of New York, Inc. (Inter-
Power), filed a complaint against the Company and
certain of its officers and employees in the Supreme
Court of the State of New York, Albany County (NYS
Supreme Court). Inter-Power alleged, among other
matters, fraud, negligent misrepresentation and breach
of contract in connection with the Company's alleged
termination of a power purchase agreement in January
1993. The plaintiff sought enforcement of the original
contract or compensatory and punitive damages in an
aggregate amount that would not exceed $1 billion,
excluding pre-judgment interest.
In early 1994, the NYS Supreme Court dismissed two of
the plaintiff's claims; this dismissal was upheld by
the Appellate Division, Third Department of the NYS
Supreme Court. Subsequently, the NYS Supreme Court
granted the Company's motion for summary judgment on
the remaining causes of action in Inter-Power's
complaint. In August 1994, Inter-Power appealed this
decision and on July 27, 1995, the Appellate Division,
Third Department affirmed the granting of summary
judgment as to all counts, except for one dealing with
an alleged breach of the power purchase agreement
relating to the Company's having declared the agreement
null and void on the grounds that Inter-Power had
failed to provide it with information regarding its
fuel supply in a timely fashion. In August 1995, the
Company filed a motion to reargue or for leave to
appeal to the Court of Appeals. The Company's motion
was denied on October 25, 1995.
(b) In November 1993, Fourth Branch Associates
Mechanicville (Fourth Branch) filed an action against
the Company and several of its officers and employees
in the NYS Supreme Court, seeking compensatory damages
of $50 million, punitive damages of $100 million and
injunctive and other related relief. The lawsuit grows
out of the Company's termination of a contract for
Fourth Branch to operate and maintain a hydroelectric
plant the Company owns in the Town of Halfmoon, New
York. Fourth Branch's complaint also alleges claims
based on the inability of Fourth Branch and the Company
to agree on terms for the purchase of power from a new
facility that Fourth Branch hoped to construct at the
Mechanicville site. In January 1994, the Company filed
a motion to dismiss Fourth Branch's complaint. By
order dated November 7, 1995, the court granted the
Company's motion to dismiss the complaint in its
entirety. Fourth Branch has filed an appeal from the
Court's order. Fourth Branch has filed for protection
under Chapter 11 of the Bankruptcy Code in the
Bankruptcy Court for the Northern District of New York.
On January 5, 1996, Fourth Branch vacated the
Mechanicville site.
(c) On June 8, 1994, Medina Power Company (Medina) filed a
lawsuit against the Company in the New York State
Supreme Court, Erie County. Medina alleges, among
other claims, that the Company violated various New
York State antitrust laws in connection with a contract
that the Company has with Medina. On July 11, 1995
Medina amended its complaint and removed the allegation
of antitrust violations, and is now seeking unspecified
damages.
The Company had previously entered into a contract with
Medina, an unregulated generator, for the purchase of
electricity. The original contract required Medina to
be a qualifying facility (QF) under federal law or face
a contractual penalty. Having come on-line without a
thermal host, Medina did not meet this QF requirement,
subjecting it to a 15% rate reduction. The Company
advised Medina that it had exercised its contract right
and reduced the rate accordingly. The Company believes
Medina's lawsuit is without merit, but cannot predict
the outcome of this action.
(d) The Company is involved in a number of court cases
regarding the price of energy it is required to
purchase in excess of contract levels from certain
unregulated generators ("overgeneration"). The Company
has paid the unregulated generators based on its short-
run avoided cost (under Service Class No. 6) for all
such overgeneration rather than the price which the
unregulated generators contend is applicable under the
contracts. At December 31, 1995, this amount of
overgeneration adjustments in dispute that the Company
estimates it has not paid or accrued is approximately
$32 million, exclusive of interest. The Company cannot
predict the outcome of these actions, but will continue
to aggressively press its position.
ENVIRONMENTAL CONTINGENCIES: The public utility industry
typically utilizes and/or generates in its operations a broad
range of potentially hazardous wastes and by-products. The
Company believes it is handling identified wastes and by-products
in a manner consistent with Federal, state and local requirements
and has implemented an environmental audit program to identify
any potential areas of concern and assure compliance with such
requirements. The Company is also currently conducting a program
to investigate and restore, as necessary to meet current
environmental standards, certain properties associated with its
former gas manufacturing process and other properties which the
Company has learned may be contaminated with industrial waste, as
well as investigating identified industrial waste sites as to
which it may be determined that the Company contributed. The
Company has also been advised that various Federal, state or
local agencies believe certain properties require investigation
and has prioritized the sites based on available information in
order to enhance the management of investigation and remediation,
if necessary.
The Company is currently aware of 88 sites with which it has
been or may be associated, including 46 which are Company-owned.
With respect to non-owned sites, the Company may be required to
contribute some proportionate share of remedial costs.
Investigations at each of the Company-owned sites are
designed to (1) determine if environmental contamination problems
exist, (2) if necessary, determine the appropriate remedial
actions required for site restoration and (3) where appropriate,
identify other parties who should bear some or all of the cost of
remediation. Legal action against such other parties will be
initiated where appropriate. After site investigations are
completed, the Company expects to determine site-specific
remedial actions and to estimate the attendant costs for
restoration. However, since technologies are still developing,
the ultimate cost of remedial actions may change substantially.
Estimates of the cost of remediation and post-remedial
monitoring are based upon a variety of factors, including
identified or potential contaminants, location, size and use of
the site, proximity to sensitive resources, status of regulatory
investigation and knowledge of activities at similarly situated
sites, and the United States Environmental Protection Agency
(EPA) figure for average cost to remediate a site. Actual
Company expenditures are dependent upon the total cost of
investigation and remediation and the ultimate determination of
the Company's share of responsibility for such costs, as well as
the financial viability of other identified responsible parties
since clean-up obligations are joint and several. The Company
has denied any responsibility in certain of these Potentially
Responsible Party (PRP) sites and is contesting liability
accordingly.
As a consequence of site characterizations and assessments
completed to date and negotiations with PRP's, the Company has
accrued a liability in the amount of $225 million and $240
million, which is reflected in the Company's balance sheets at
December 31, 1995 and 1994, respectively. The liability was
reduced in 1995 to reflect the Company's current estimate, which
incorporates the recent availability of better information
regarding the cost to remediate one of its major sites, the
Saratoga Springs manufactured gas plant site, since a Record of
Decision was issued by the EPA at that site. The Saratoga
Springs site is included on the National Priority's List. This
liability represents the low end of the range of its share of the
estimated cost for investigation and remediation. The potential
high end of the range is presently estimated at approximately
$930 million, including approximately $430 million in the
unlikely event the Company is required to assume 100%
responsibility at non-owned sites.
Prior to 1995, the Company recovered 100% of its costs
associated with site investigation and restoration. In the
Company's 1995 rate order, costs incurred during 1995 for the
investigation and restoration of Company-owned sites and sites
with which it is associated were subject to 80%/20% (ratepayer/
Company) sharing. In 1995, the Company incurred $11.5 million of
such costs, resulting in a disallowance of $2.3 million (before
tax), which the Company has recognized as a loss in Other items
(net) on the Consolidated Statements of Income. The PSC stated
in its opinion, dated December 1995, its decision to require
sharing was "on a one-time, short-term basis only, pending its
further evaluation of the issue in future proceedings." The
Company has recorded a regulatory asset representing the
remediation obligations to be recovered from ratepayers.
Where appropriate, the Company has provided notices of
insurance claims to carriers with respect to the investigation
and remediation costs for manufactured gas plant, industrial
waste sites and sites for which the Company has been identified
as a PRP. The Company is unable to predict whether such
insurance claims will be successful.
CONSTRUCTION PROGRAM: The Company is committed to an
ongoing construction program to assure delivery of its electric
and gas services. The Company presently estimates that the
construction program for the years 1996 through 2000 will require
approximately $1.5 billion, excluding AFC and nuclear fuel. For
the years 1996 through 2000, the estimates are $290 million, $295
million, $307 million, $306 million and $290 million,
respectively, which includes $42 million, $46 million, $58
million, $49 million and $40 million, respectively, related to
generation. These amounts are reviewed by management as
circumstances dictate.
NOTE 10. DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate
the fair value of each class of financial instruments:
CASH AND SHORT-TERM INVESTMENTS: The carrying amount
approximates fair value because of the short maturity of the
financial instruments.
SHORT-TERM DEBT: The carrying amount approximates fair
value because of the short-term nature of the borrowings.
LONG-TERM INVESTMENTS: The carrying value and market value
are not material to the financial statements.
LONG-TERM DEBT AND MANDATORILY REDEEMABLE PREFERRED STOCK:
The fair value of fixed rate long-term debt and redeemable
preferred stock is estimated using quoted market prices where
available or discounting remaining cash flows at the Company's
incremental borrowing rate. The carrying value of NYSERDA bonds
and other long-term debt are considered to approximate fair
value.
The financial instruments held or issued by the Company are for purposes other than
trading. The estimated fair values of the Company's financial instruments are as follows:
- ------------------------------------------------------------------------------------------
(In thousands of dollars)
-------------------------------------------------
At December 31, 1995 1994
- ------------------------------------ --------------------- ----------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- ------------------------------------ --------------------- ----------------------
Cash and short-term
investments $ 153,475 $ 153,475 $ 94,330 $ 94,330
Short-term debt - - 416,750 416,750
Mandatorily redeemable
preferred stock 106,000 92,676 116,950 134,692
Long-term debt: First Mortgage bonds 2,866,305 2,815,206 2,611,305 2,367,755
Medium Term notes 30,000 31,826 45,000 45,783
NYSERDA bonds 413,760 413,760 413,760 413,760
Swiss franc bond - - 50,000 83,682
Other 292,436 292,436 224,107 224,107
On January 1, 1994, the Company adopted Statement of
Financial Accounting Standards No. 115, "Accounting for Certain
Investments in Debt and Equity Securities." This statement
addresses the accounting and reporting for investments in equity
securities that have readily determinable fair values and for all
investments in debt securities. The Company's investments in
debt and equity securities consist of trust funds for the purpose
of funding the nuclear decommissioning of Unit 1 and its share of
Unit 2 (See Note 3 - "Nuclear Plant Decommissioning"), short-term
investments held by Opinac (a subsidiary) and a trust fund for
certain pension benefits. The Company has classified all
investments in debt and equity securities as available for sale
and has recorded all such investments at their fair market value
at December 31, 1995. The proceeds from the sale of investments
were $70.3 million and $104.6 million in 1995 and 1994,
respectively. Net realized and unrealized gains and losses
related to the nuclear decommissioning trust are reflected in
Accumulated depreciation and amortization on the balance sheet,
which is consistent with the method used by the Company to
account for the decommissioning costs recovered in rates. The
unrealized gains and losses related to the investments held by
Opinac and the pension trust are included, net of tax, in
stockholders' equity on the balance sheet, while the realized
gains and losses are included in Other items (net) on the income
statement. The recorded fair values and cost basis of the
Company's investments in debt and equity securities is as
follows:
- ------------------------------------------------------------------------------------------
(In thousands of dollars)
-----------------------------------------------------------------------
At December 31, 1995 1994
- --------------- ---------------------------------- ---------------------------------
Gross Gross
Unrealized Fair Unrealized Fair
Security Type Cost Gain (Loss) Value Cost Gain (Loss) Value
- --------------- ---------------------------------- ---------------------------------
U.S. Government
Obligations $ 16,271 $ 3,009 $ - $ 19,280 $15,165 $ 19 $ (325) $14,859
Commercial Paper 47,105 1,019 - 48,124 - - - -
Tax Exempt
Obligations 66,155 3,830 (72) 69,913 45,029 659 (1,778) 43,910
Corporate
Obligations 45,279 5,399 (344) 50,334 27,407 9 (1,253) 26,163
Other 10,022 945 - 10,967 8,121 28 (348) 7,801
-------- -------- ----- -------- ------- ---- ------- -----
$184,832 $14,202 $(416) $198,618 $95,722 $715 $(3,704) $92,733
======== ======= ====== ======== ======== ===== ======= =======
Using the specific identification method to determine cost,
the gross realized gains and gross realized losses were:
In thousands of dollars
-----------------------
Year Ended December 31, 1995 1994
- ----------------------- ---- ----
Realized gains $2,523 $1,123
Realized losses $ 328 $1,637
The contractual maturities of the Company's investments in
debt securities is as follows:
- ---------------------------------------------------------
At December 31, 1995
-----------------------------
(In thousands of dollars)
-----------------------------
Fair Value Cost
- ---------------------------------------------------------
Less than 1 year $48,124 $47,105
1 year to 5 years 10,308 9,689
5 years to 10 years 31,759 30,066
Due after 10 years 83,112 75,348
NOTE 11. INFORMATION REGARDING THE ELECTRIC AND GAS BUSINESSES
The Company is engaged principally in the business of
production, purchase, transmission, distribution and sale of
electricity and the purchase, distribution, sale and
transportation of gas in New York State. The Company provides
electric service to the public in an area of New York State
having a total population of about 3,500,000, including among
others, the cities of Buffalo, Syracuse, Albany, Utica,
Schenectady, Niagara Falls, Watertown and Troy. The Company
distributes or transports natural gas in areas of central,
northern and eastern New York having a total population of about
1,700,000 nearly all within the Company's electric service area.
Certain information regarding the Company's electric and natural
gas segments is set forth in the following table. General
corporate expenses, property common to both segments and
depreciation of such common property have been allocated to the
segments in accordance with the practice established for
regulatory purposes. Identifiable assets include net utility
plant, materials and supplies, deferred finance charges, deferred
recoverable energy costs and certain other regulatory and other
assets. Corporate assets consist of other property and
investments, cash, accounts receivable, prepayments, unamortized
debt expense and certain other regulatory and other assets. At
December 31, 1995, total plant assets consisted of 24.1% Nuclear,
16.7% Generation, 41.5% Transmission and Distribution, 4.5% Hydro
and 10.3% Gas and 2.9% Common.
In thousands of dollars
-----------------------
1995 1994 1993
---- ---- ----
Operating revenues:
Electric $3,335,548 $3,528,987 $3,332,464
Gas 581,790 623,191 600,967
- -----------------------------------------------------------------
Total $3,917,338 $4,152,178 $3,933,431
=================================================================
Operating income before taxes:
Electric $ 587,282 $ 466,978* $ 625,852
Gas 96,752 83,229 61,163
- -----------------------------------------------------------------
Total $ 684,034 $ 550,207 $ 687,015
=================================================================
Pretax operating income, including AFC:
Electric $ 595,970 $ 475,694 $ 641,435
Gas 97,114 83,592 61,812
- -----------------------------------------------------------------
Total 693,084 559,286 703,247
- -----------------------------------------------------------------
Income taxes, included in operating expenses:
Electric 129,861 97,417 148,695
Gas 26,147 20,417 13,820
- -----------------------------------------------------------------
Total 156,008 117,834 162,515
- -----------------------------------------------------------------
Other (income) and
deductions 1,379 (21,410) (22,475)
Interest charges 287,661 285,878 291,376
- -----------------------------------------------------------------
Net income $ 248,036 $ 176,984 $ 271,831
=================================================================
Depreciation and amortization:
Electric $ 292,995 $ 283,694 $ 255,718
Gas 24,836 24,657 20,905
- -----------------------------------------------------------------
Total $ 317,831 $ 308,351 $ 276,623
=================================================================
Construction expenditures (including nuclear fuel):
Electric $ 285,722 $ 376,159 $ 429,265
Gas 60,082 113,965 90,347
- -----------------------------------------------------------------
Total $ 345,804 $ 490,124 $ 519,612
=================================================================
Identifiable assets:
Electric $7,592,287 $7,759,549 $7,700,888
Gas 1,123,045 1,093,812 1,008,272
- -----------------------------------------------------------------
Total 8,715,332 8,853,361 8,709,160
Corporate assets 762,537 796,455 762,167
- -----------------------------------------------------------------
Total assets $9,477,869 $9,649,816 $9,471,327
=================================================================
* Includes $196,625 of VERP expenses.
NOTE 12. QUARTERLY FINANCIAL DATA (UNAUDITED)
Operating revenues, operating income, net income and
earnings per common share by quarters from 1995, 1994 and 1993,
respectively, are shown in the following table. The Company, in
its opinion, has included all adjustments necessary for a fair
presentation of the results of operations for the quarters. Due
to the seasonal nature of the utility business, the annual
amounts are not generated evenly by quarter during the year. The
Company's quarterly results of operations reflect the seasonal
nature of its business, with peak electric loads in summer and
winter periods. Gas sales peak in the winter.
In thousands of dollars
-----------------------
EARNINGS
OPERATING NET (LOSS)
OPERATING INCOME INCOME PER COMMON
QUARTER ENDED REVENUES (LOSS) (LOSS) SHARE
- ----------------------------------------------------------------
December 31, 1995 $ 966,478 $113,510 $ 27,874 $ .13
1994 1,018,110 (10,536) (77,422) (.61)
1993 988,195 95,623 30,955 .16
- ----------------------------------------------------------------
September 30, 1995 $ 887,231 $114,126 $ 46,941 $ .26
1994 918,810 108,937 48,383 .27
1993 879,952 108,539 48,595 .29
- ----------------------------------------------------------------
June 30, 1995 $ 938,816 $121,985 $ 54,485 $ .31
1994 979,700 130,624 67,559 .42
1993 929,245 132,669 65,325 .41
- ----------------------------------------------------------------
March 31, 1995 $1,124,813 $178,405 $118,736 $ .75
1994 1,235,558 203,348 138,464 .92
1993 1,136,039 187,669 126,956 .86
- ----------------------------------------------------------------
In the fourth quarter of 1994 the Company recorded $196.6
million (89 cents per common share) for the electric expense
allocation of the VERP. In the third quarter of 1993 and the
fourth quarters of 1994 and 1995, the Company recorded $10.3
million (5 cents per common share), $12.3 million (6 cents per
common share), and $16.9 million (8 cents per common share),
respectively, for MERIT earned in accordance with the 1991
Agreement.
ELECTRIC AND GAS STATISTICS
ELECTRIC CAPABILITY
Thousands of kilowatts
----------------------
December 31, 1995 % 1994 1993
- ------------------------------------------------------------
Owned:
Coal 1,316 16.0 1,285 1,285
Oil 636 7.7 646 1,496
Dual Fuel - Oil/Gas 700 8.5 700 700
Nuclear 1,082 13.2 1,048 1,048
Hydro 665 8.1 700 700
Natural Gas - - - 74
----- ---- ----- -----
4,399 53.5 4,379 5,303
----- ---- ----- -----
Purchased:
New York Power Authority
- Hydro 1,325 16.1 1,300 1,302
- Nuclear 110 1.3 74 65
Unregulated
generators 2,390 29.1 2,273 2,253
----- ---- ----- -----
3,825 46.5 3,647 3,620
----- ---- ----- -----
Total capability* 8,224 100.0 8,026 8,923
===== ===== ===== =====
Electric peak load 6,211 6,458 6,191
===== ===== =====
* Available capability can be increased during heavy load
periods by purchases from neighboring interconnected
systems. Hydro station capability is based on average
December stream-flow conditions.
ELECTRIC STATISTICS
1995 1994 1993
- ----------------------------------------------------------------
Electric sales (Millions of kw-hrs.):
Residential 10,150 10,415 10,475
Commercial 11,684 11,813 12,079
Industrial 7,126 7,445 7,088
Industrial-Special 4,053 4,118 3,888
Municipal service 215 215 220
Other electric systems 4,456 7,593 3,974
- -----------------------------------------------------------------
37,684 41,599 37,724
Electric revenues (Thousands of dollars):
Residential $1,221,105 $1,233,007 $1,171,787
Commercial 1,241,479 1,272,234 1,241,743
Industrial 527,244 577,473 553,921
Industrial-Special 56,250 49,217 42,988
Municipal service 49,543 50,007 50,642
Other electric systems 95,812 167,131 105,044
Miscellaneous 144,115 179,918 166,339
- -----------------------------------------------------------------
$3,335,548 $3,528,987 $3,332,464
Electric customers (Average):
Residential 1,411,953 1,405,343 1,398,756
Commercial 145,965 144,249 143,078
Industrial 2,159 2,105 2,132
Industrial-Special 83 82 76
Other 1,497 2,318 3,438
- -----------------------------------------------------------------
1,561,657 1,554,097 1,547,480
Residential (Average):
Annual kw-hr. use per customer 7,189 7,411 7,489
Cost to customer per kw-hr.
(in cents) 12.03 11.84 11.19
Annual revenue per customer $864.83 $877.37 $837.74
GAS STATISTICS
1995 1994 1993
- -----------------------------------------------------------------
Gas Sales (Thousands of dekatherms):
Residential 51,842 56,491 54,908
Commercial 23,818 25,783 23,743
Industrial 2,660 3,097 4,316
Other gas systems 161 244 234
- -----------------------------------------------------------------
Total sales 78,481 85,615 83,201
Spot market 1,723 1,572 13,223
Transportation of customer-
owned gas 144,613 85,910 67,741
- -----------------------------------------------------------------
Total gas delivered 224,817 173,097 164,165
Gas Revenues (Thousands of dollars):
Residential $ 368,391 $ 398,257 $ 370,565
Commercial 143,643 159,157 144,834
Industrial 11,530 14,602 18,482
Other gas systems 762 1,159 1,066
Spot market 3,096 4,370 29,782
Transportation of customer-
owned gas 48,290 38,346 34,843
Miscellaneous 6,078 7,300 1,395
- -----------------------------------------------------------------
$ 581,790 $ 623,191 $ 600,967
Gas Customers (Average):
Residential 471,948 463,933 455,629
Commercial 40,945 40,256 39,662
Industrial 225 256 233
Other 1 1 1
Transportation 652 661 673
- -----------------------------------------------------------------
513,771 505,107 496,198
Residential (Average):
Annual dekatherm use
per customer 109.8 121.8 120.5
Cost to customer per dekatherm $ 7.11 $ 7.05 $ 6.75
Annual revenue per customer $780.58 $858.44 $813.30
Maximum day gas sendout
(dekatherms) 1,211,252 995,801 929,285
EXHIBIT 11
- ----------
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARIES
COMPUTATION OF AVERAGE NUMBER OF SHARES OF COMMON STOCK OUTSTANDING
Average Number
of Shares Out-
standing as Shown
on Consolidated
(1) (2) Statements of In-
Shares of Number (3) come (3 Divided
Common of Days Share Days by Number of Days
Year Ended December 31, Stock Outstanding (2 x 1) in Year)
- ----------------------- --------- ----------- ---------- -----------------
1995
----
January 1 - December 31 144,311,466 365 52,673,685,090
Shares sold -
Dividend Reinvestment
Plan - January 31 19,016 335 6,370,360
Acquisition - Syracuse
Suburban Gas Company,
Inc. - October 4 1,641 89 146,049
------------ ---------------
144,332,123 52,680,201,499 144,329,319
============ ============== ===========
1994
----
January 1 - December 31 142,427,057 365 51,985,875,805
Shares sold at various
times during the year -
Dividend Reinvestment
Plan 1,026,709 * 152,123,611
Employee Savings
Fund Plan 857,700 * 152,153,100
----------- --------------
144,311,466 52,290,152,516 143,260,692
=========== ============== ===========
1993
----
January 1 - May 4 137,159,607 124 17,007,791,268
Shares sold May 5 4,494,000
-----------
May 5 - December 31 141,653,607 241 34,138,519,287
Shares sold at various
times during the year -
Dividend Reinvestment
Plan 632,341 * 102,395,031
Employee Savings
Fund Plan 140,000 22 3,080,000
Acquisition - Syracuse
Suburban Gas Company,
Inc. 1,109 * 350,374
----------- --------------
142,427,057 51,252,135,960 140,416,811
=========== ============== ===========
* Number of days outstanding not shown as shares represent an accumulation of weekly,
monthly and quarterly sales throughout the year. Share days for shares sold are
based on the total number of days each share was outstanding during the year.
Note: Earnings per share calculated on both a primary and fully diluted basis are the
same due to the effects of rounding.
/TABLE
EXHIBIT 12
- ----------
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
STATEMENT SHOWING COMPUTATIONS OF RATIO OF EARNINGS TO FIXED CHARGES, RATIO OF EARNINGS TO
FIXED CHARGES WITHOUT AFC AND RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED STOCK
DIVIDENDS
Year Ended December 31,
------------------------------------------------------------
1995 1994 1993 1992 1991
---- ---- ---- ---- ----
A. Net Income per Statements
of Income (a) $248,036 $176,984 $271,831 $256,432 $243,369
B. Taxes Based on Income or
Profits 159,393 111,469 147,075 155,504 133,895
-------- -------- -------- -------- --------
C. Earnings, Before Income
Taxes 407,429 288,453 418,906 411,936 377,264
D. Fixed Charges (b) 314,973 315,274 319,197 332,413 346,255
-------- -------- -------- -------- --------
E. Earnings Before Income
Taxes and Fixed Charges 722,402 603,727 738,103 744,349 723,519
F. Allowance for Funds Used
During Construction 9,050 9,079 16,232 21,431 18,931
-------- -------- -------- ------- -------
G. Earnings Before Income
Taxes and Fixed Charges
without AFC $713,352 $594,648 $721,871 $722,918 $704,588
======== ======== ======== ======== ========
Preferred Dividend Factor:
H. Preferred Dividend
Requirements $ 39,596 $ 33,673 $ 31,857 $ 36,512 $ 40,411
-------- -------- -------- --------- --------
I. Ratio of Pre-Tax Income
to Net Income (C / A) 1.64 1.63 1.54 1.61 1.55
-------- --------- --------- --------- ---------
J. Preferred Dividend Factor
(H x I) $ 64,937 $ 54,887 $ 49,060 $ 58,784 $ 62,637
K. Fixed Charges as above (D) 314,973 315,274 319,197 332,413 346,255
-------- -------- -------- -------- --------
L. Fixed Charges and Preferred
Dividends Combined $379,910 $370,161 $368,257 $391,197 $408,892
======== ======== ======== ======== ========
M. Ratio of Earnings to
Fixed Charges (E / D) 2.29 1.91 2.31 2.24 2.09
-------- -------- -------- -------- --------
N. Ratio of Earnings to Fixed
Charges without AFC (G / D) 2.26 1.89 2.26 2.17 2.03
-------- -------- -------- -------- --------
O. Ratio of Earnings to Fixed
Charges and Preferred
Dividends Combined (E / L) 1.90 1.63 2.00 1.90 1.77
-------- ------- -------- -------- --------
(a) Includes the effects of amortization of amounts deferred, under the 1989 Agreement,
$15,746 for 1993, $20,257 for 1992 and $31,176 for 1991.
(b) Includes a portion of rentals deemed representative of the interest factor $27,312
for 1995, $29,396 for 1994, $27,821 for 1993, $31,697 for 1992 and $34,616 for 1991.
/TABLE
EXHIBIT 23
- ----------
CONSENT OF INDEPENDENT ACCOUNTANTS
- ----------------------------------
We hereby consent to the incorporation by reference in the
Registration Statement on Form S-8 (Nos. 33-36189, 33-42720, 33-
42721, 33-42771 and 33-54829) and to the incorporation by
reference in the Prospectus constituting part of the Registration
Statement on Form S-3 (Nos. 33-45898, 33-50703, 33-51073, 33-
54827 and 33-55546) of Niagara Mohawk Power Corporation of our
report dated January 25, 1996 appearing on a page in the
financial statements included in the Company's Form 8-K dated
March 1, 1996.
/s/ Price Waterhouse LLP
Syracuse, New York
March 1, 1996
SIGNATURE
- ---------
Pursuant to the requirements of the Securities Exchange Act
of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned thereunto duly authorized.
Date: March 5, 1996
NIAGARA MOHAWK POWER CORPORATION
By /s/ Steven W. Tasker
--------------------
Steven W. Tasker
Vice President-Controller
and Principal
Accounting Officer