FORM 10-K/A
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(Mark One)
/X/ Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the fiscal year ended December 31, 1997
OR
/ / Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 for the transition
period from ______ to ______
Commission file number 1-2987
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NIAGARA MOHAWK POWER CORPORATION
(Exact name of registrant as specified in its charter)
State of New York 15-0265555
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(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
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
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Securities registered pursuant to Section 12(b) of the
Act:
(Each class is registered on the New York Stock Exchange)
Title of each class
Common Stock ($1 par value)
Preferred Stock ($100 par Preferred Stock ($25 par
value-cumulative): value-cumulative):
3.40% Series 4.10% Series 6.10% Series 9.50% Series
3.60% Series 4.85% Series 7.72% Series Adjustable Rate
3.90% Series 5.25% Series Series A & Series C
Securities registered pursuant to Section 12(g) of the Act: None
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Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements
for the past 90 days. Yes /X/ No / /
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not
be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part
III of this Form 10-K or any amendment to this Form 10-K /X/
State the aggregate market value of the voting stock held by non-
affiliates of the registrant.
Approximately $1,800,000,000 at March 26, 1998.
Indicate the number of shares outstanding of each of the
registrant's classes of common stock, as of the latest practicable
date.
Common stock, $1 par value, outstanding at March 26, 1998:
144,419,351.
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NIAGARA MOHAWK POWER CORPORATION
INFORMATION REQUIRED IN FORM 10-K/A
Item Number
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Glossary of Terms
PART II
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Item 6. Selected Consolidated Financial Data.
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.
Item 8. Financial Statements and Supplementary Data.
PART IV
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Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K.
Signatures
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NIAGARA MOHAWK POWER CORPORATION
GLOSSARY OF TERMS
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TERM DEFINITION
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AFC Allowance for Funds Used During Construction
CNP Canadian Niagara Power Company, Limited
COPS Competitive Opportunities Proceeding
CTC Competitive Transition Charges
DEC New York State Department of Environmental
Conservation
DOE U. S. Department of Energy
Dth Dekatherm: one thousand cubic feet of gas with a
heat content of 1,000 British Thermal Units per
cubic foot
EBITDA Earnings before Interest Charges, Interest
Income, Income Taxes, Depreciation and
Amortization, Amortization of Nuclear Fuel,
Allowance for Funds Used During Construction,
MRA Regulatory Asset amortization, non-cash
regulatory deferrals and other amortizations and
extraordinary items (a non-GAAP measure of cash
flow)
FAC Fuel Adjustment Clause: a clause in a rate
schedule that provides for an adjustment to the
customer's bill if the cost of fuel varies from
a specified unit cost
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
GAAP Generally Accepted Accounting Principles
GRT Gross Receipts Tax
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GWh Gigawatt-hour: one gigawatt-hour equals one
billion watt-hours
IPP Independent Power Producer: any person that owns
or operates, in whole or in part, one or more
Independent Power Facilities
IPP Party Independent Power Producers that are a party to
the MRA
ISO Independent System Operator
KW Kilowatt: one thousand watts
KWh Kilowatt-hour: a unit of electrical energy equal
to one kilowatt of power supplied or taken from
an electric circuit steadily for one hour
MERIT Measured Equity Return Incentive Term
MRA Master Restructuring Agreement - an agreement to
terminate, restate or amend IPP Party power
purchase agreements
MRA Recoverable costs to terminate, restate or amend
regulatory IPP Party contracts, which are deferred
asset and amortized under PowerChoice
MW Megawatt: one million watts
MWh Megawatt-hour: one thousand kilowatt-hours
NRC U. S. Nuclear Regulatory Commission
NYPA New York Power Authority
NYPP New York Power Pool
NYPP Member Eight Member Systems are: the seven New York
Systems State investor-owned electric utilities and NYPA
NYSERDA New York State Energy Research and Development
Authority
PowerChoice Company's five-year electric rate agreement,
agreement which incorporates the MRA, approved in February
1998
PPA Power Purchase Agreement: long-term contracts
under which a utility is obligated to purchase
electricity from an IPP at specified rates
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PRP Potentially Responsible Party
PSC New York State Public Service Commission
PURPA Public Utility Regulatory Policies Act of 1978,
as amended. One of five bills signed into law on
November 8, 1978, as the National Energy Act. It
sets forth procedures and requirements applicable
to state utility commissions, electric and
natural gas utilities and certain federal
regulatory agencies. A major aspect of this law
is the mandatory purchase obligation from
qualifying facilities.
QF Qualifying Facility: an individual (or
corporation) that owns and/or operates a
generating facility but is not primarily engaged
in the generation or sale of electric power. QFs
are either power production or cogeneration
facilities that qualify under Section 201 of
PURPA.
ROE Return on Common Stock Equity
SFAS Statement of Financial Accounting Standards No.
No. 71 71 "Accounting for the Effects of Certain
Types of Regulation"
SFAS Statement of Financial Accounting Standards No.
No. 101 101 "Regulated Enterprises - Accounting for the
Discontinuance of Application of FASB Statement
No. 71"
SFAS Statement of Financial Accounting Standards No.
No. 106 106 "Employers' Accounting for Postretirement
Benefits Other Than Pensions"
SFAS Statement of Financial Accounting Standards No.
No. 109 109 "Accounting for Income Taxes"
SFAS Statement of Financial Accounting Standards No.
No. 121 121 "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to Be Disposed
Of"
SFAS Statement of Financial Accounting Standards No.
No. 130 130 "Reporting Comprehensive Income"
SFAS Statement of Financial Accounting Standards No.
No. 131 131 "Disclosures about Segments of an Enterprise
and Related Information"
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SFAS Statement of Financial Accounting Standards No.
No. 132 132 "Employers' Disclosure about Pensions and
Other Postretirement Benefits"
stranded Utility costs that may become unrecoverable due
costs to a change in the regulatory environment
Unit 1 Nine Mile Point Nuclear Station Unit No. 1
Unit 2 Nine Mile Point Nuclear Station Unit No. 2
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NIAGARA MOHAWK POWER CORPORATION
ITEM 6. 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, 1997, which has been derived from the audited
financial statements of the Company, and should be read in connection therewith. As
discussed in Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations and Item 8. Financial Statements and Supplementary Data - "Notes to
Consolidated Financial Statements," the following selected financial data is not likely to
be indicative of the Company's future financial condition or results of operations.
1997 1996* 1995 1994 1993
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Operations: (000's)
Operating revenues $ 3,966,404 $ 3,990,653 $ 3,917,338 $ 4,152,178 $ 3,933,431
Net income 183,335 110,390 248,036 176,984 271,831
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Common stock data:
Book value per share
at year end $18.89 $17.91 $17.42 $17.06 $17.25
Market price at
year end 10 1/2 9 7/8 9 1/2 14 1/4 20 1/4
Ratio of market price to
book value at year end 55.6% 55.1% 54.5% 83.5% 117.4%
Dividend yield at year end - - 11.8% 7.9% 4.9%
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Basic and diluted earnings
per average common
share $1.01 $ .50 $1.44 $1.00 $1.71
Rate of return on common
equity 5.5% 2.8% 8.4% 5.8% 10.2%
Dividends paid per
common share - - $1.12 $1.09 $ .95
Dividend payout ratio - - 77.8% 109.0% 55.6%
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Capitalization: (000's)
Common equity $ 2,727,527 $ 2,585,572 $ 2,513,952 $ 2,462,398 $ 2,456,465
Non-redeemable
preferred stock 440,000 440,000 440,000 440,000 290,000
Mandatorily redeemable
preferred stock 76,610 86,730 96,850 106,000 123,200
Long-term debt 3,417,381 3,477,879 3,582,414 3,297,874 3,258,612
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TOTAL 6,661,518 6,590,181 6,633,216 6,306,272 6,128,277
Long-term debt maturing
within one year 67,095 48,084 65,064 77,971 216,185
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TOTAL $ 6,728,613 $ 6,638,265 $ 6,698,280 $ 6,384,243 $ 6,344,462
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Capitalization ratios: (including long-term debt maturing within one year)
Common stock equity 40.5% 39.0% 37.5% 38.6% 38.7%
Preferred stock 7.7 7.9 8.0 8.5 6.5
Long-term debt 51.8 53.1 54.5 52.9 54.8
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Financial ratios:
Ratio of earnings to
fixed charges 2.02 1.57 2.29 1.91 2.31
Ratio of earnings to
fixed charges and
preferred stock
dividends 1.67 1.31 1.90 1.63 2.00
Other ratios - % of
operating revenues:
Fuel, electricity purchased
and gas purchased 44.4% 43.5% 40.3% 39.6% 36.1%
Other operation and
maintenance expenses 21.1 23.3 20.9 23.1 26.9
Depreciation and
amortization 8.6 8.3 8.1 7.4 7.0
Federal and foreign
income taxes, and
other taxes 15.1 13.6 17.3 14.7 16.2
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Operating income 14.1 13.1 17.5 13.3 17.5
Balance available for
common stock 3.7 1.8 5.3 3.5 6.1
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Miscellaneous: (000's)
Gross additions to
utility plant $ 290,757 $ 352,049 $ 345,804 $ 490,124 $ 519,612
Total utility plant 11,075,874 10,839,341 10,649,301 10,485,339 10,108,529
Accumulated depreciation
and amortization 4,207,830 3,881,726 3,641,448 3,449,696 3,231,237
Total assets 9,584,141 9,427,635 9,477,869 9,649,816 9,471,327
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* Amounts include extraordinary item, see Note 2. Rate and Regulatory Issues and
Contingencies.
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NIAGARA MOHAWK POWER CORPORATION
Certain statements included in this Annual Report on Form
10-K are forward-looking statements as defined in Section 21E of
the Securities Exchange Act of 1934, including the hedge against
upward movement in market prices provided by the restructured and
amended PPAs, the improvement in operating cash flows as a result
of the MRA and PowerChoice, the recoverability of the MRA
regulatory asset through the prices charged for electric service,
the effect of a PSC natural gas proposal on the Company's results
of operations, expected earnings over the five-year term of the
PowerChoice agreement, the effect of the elimination of the FAC
under PowerChoice on the Company's financial condition, the
reduction in net income resulting from the non-cash amortization of
the MRA regulatory asset, the effect of the January 1998 ice storm
damage restoration costs on the Company's capital requirements,
recoverability of environmental compliance costs and nuclear
decommissioning costs through rates, and the improvement in the
Company's financial condition expected as a result of the MRA and
the implementation of PowerChoice. The Company's actual results
and developments may differ materially from the results discussed
in or implied by such forward-looking statements, due to risks and
uncertainties that exist in the Company's operations and business
environment, including, but not limited to, matters described in
the context of such forward-looking statements, as well as such
other factors as set forth in the Notes to Consolidated Financial
Statements contained herein.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
EVENTS AFFECTING 1997 AND THE FUTURE
- - On July 9, 1997, the Company announced the MRA to terminate,
restate or amend IPP power purchase contracts in exchange for
cash, shares of the Company's common stock and certain
financial contracts. The terms of the MRA have been and may
continue to be modified.
- - In February 1998, the PSC approved the PowerChoice settlement
agreement, which incorporates the terms of the MRA. Under
PowerChoice, a regulatory asset will be established for the
costs of the MRA and it will be amortized over a period
generally not to exceed ten years. The Company's rates under
PowerChoice are designed to permit recovery of the MRA
regulatory asset. In approving PowerChoice, the PSC limited
the estimated value of the MRA regulatory asset that can be
recovered to approximately $4,000 million, which is expected
to result in a charge to the second quarter of 1998 earnings
of $190.0 million or 85 cents per share upon the closing of
the MRA.
The PowerChoice agreement, while having the effect of
substantially depressing earnings during its five-year term,
will substantially improve operating cash flows.
- - In December 1997, the preferred shareholders gave the Company
approval to increase the amount of unsecured debt that the
Company may issue by $5 billion. This authorization enables
the issuance of unsecured debt to consummate the MRA.
- - The PowerChoice agreement calls for the Company to conduct an
auction to sell all of its fossil and hydro generation
assets.
- - In early January 1998, a major ice storm caused extensive and
costly damage to the Company's facilities in northern New
York.
MASTER RESTRUCTURING AGREEMENT AND THE POWERCHOICE AGREEMENT
The Company entered into the PPAs that are subject to the MRA
because it was required to do so under PURPA, which was intended to
provide incentives for businesses to create alternative energy
sources. Under PURPA, the Company was required to purchase
electricity generated by qualifying facilities of IPPs at prices
that were not expected to exceed the cost that otherwise would have
been incurred by the Company in generating its own electricity, or
in purchasing it from other sources (known as "avoided costs").
While PURPA was a federal initiative, each state retained certain
delegated authority over how PURPA would be implemented within its
borders. In its implementation of PURPA, the State of New York
passed the "Six-Cent Law," establishing 6 cents per KWh as the
floor on avoided costs for projects less than 80 MW in size. The
Six-Cent Law remained in place until it was amended in 1992 to deny
the benefit of the statute to any future PPAs. The avoided cost
determinations under PURPA were periodically increased by the PSC
during this period. PURPA and the Six-Cent Law, in combination
with other factors, attracted large numbers of IPPs to New York
State, and, in particular, to the Company's service territory, due
to the area's existing energy infrastructure and availability of
cogeneration hosts. The pricing terms of substantially all of the
PPAs that the Company entered into in compliance with PURPA and the
Six-Cent Law or other New York laws were based, at the option of
the IPP, either on administratively determined avoided costs or
minimum prices, both of which have consistently been materially
higher than the wholesale market prices for electricity.
Since PURPA and the Six-Cent Law were passed, the Company has
been required to purchase electricity from IPPs in quantities in
excess of its own demand and at prices in excess of that available
to the Company by internal generation or for purchase in the
wholesale market. In fact, by 1991, the Company was facing a
potential obligation to purchase power from IPPs substantially in
excess of its peak demand of 6,093 MW. As a result, the Company's
competitive position and financial performance have deteriorated
and the price of electricity paid per KWh by its customers has
risen significantly above the national average. Accordingly, in
1991 the Company initiated a parallel strategy of negotiating
individual PPA buyouts, cancellations and renegotiations, and of
pursuing regulatory and legislative support and litigation to
mitigate the Company's obligation under the PPAs. By mid-1996,
this strategy had resulted in reducing the capacity of the
Company's obligations to purchase power under its PPA portfolio to
approximately 2,700 MW. Notwithstanding this reduction in
capacity, over the same period the payments made to the IPPs under
their PPAs rose from approximately $200 million in 1990 to
approximately $1.1 billion in 1997 as independent power facilities
from which the Company was obligated to purchase electricity
commenced operations. The Company estimates that absent the MRA,
payments made to the IPPs pursuant to PPAs would continue to
escalate by approximately $50 million per year until 2002.
Recognizing the competitive trends in the electric utility
industry and the impracticability of remedying the situation
through a series of customer rate increases, in mid-1996 the
Company began comprehensive negotiations to terminate, amend or
restate a substantial portion of above-market PPAs in an effort to
mitigate the escalating cost of these PPAs as well as to prepare
the Company for a more competitive environment. These negotiations
led to the MRA and the PowerChoice agreement.
MASTER RESTRUCTURING AGREEMENT. On July 9, 1997, the Company
entered into the MRA with 16 IPP Parties who sell electricity to
the Company under 29 PPAs. The MRA specifically contemplated that
two IPPs, Oxbow Power of North Tonawanda, New York, Inc. ("Oxbow")
and NorCon would enter into further negotiations concerning their
treatment under the MRA. Following such negotiations, Oxbow has
withdrawn from the MRA, but, based on the value of its allocation
under the MRA and the terms of its existing PPA, Oxbow's withdrawal
does not materially impact the cost reductions associated with the
MRA. The Company and NorCon have agreed to replace NorCon's
initial allocation under the MRA with an all cash allocation which
has, in the Company's estimation, a value approximately $60 million
higher than NorCon's initial allocation. A third IPP Party has
agreed to take cash in exchange for the shares of common stock
allocated to it in the MRA. As a result of these cash allocations,
there are 3,054,000 fewer shares of common stock allocated to the
IPPs under the MRA. The MRA has been amended to expire on July 15,
1998.
The MRA currently provides for the termination, restatement
or amendment of 28 PPAs with 15 IPPs, which represent approximately
80% of the Company's over-market purchased power obligations, in
exchange for an aggregate of $3,616 million in cash and 42.9
million shares of the Company's common stock and certain financial
contracts. The closing of the MRA is subject to a number of
conditions, including the Company and the IPP Parties negotiating
individual restated and amended contracts, the receipt of all
regulatory approvals, the receipt of all consents by third parties
necessary for the transactions contemplated by the MRA (including
the termination of the existing PPAs and the termination or
amendment of all related third party agreements), the IPP Parties
entering into new third party arrangements which will enable each
IPP Party to restructure its projects on a reasonably satisfactory
economic basis, the Company having completed all necessary
financing arrangements and the Company and the IPP Parties having
received all necessary approvals from their respective boards of
directors, shareholders and partners. While one or more of the IPP
Parties may under certain circumstances terminate the MRA with
respect to itself, the Company's obligation to close the MRA is
subject to its determination that as a result of any such
terminations the benefits anticipated to be received by the Company
pursuant to the MRA have not been materially and adversely
affected. The Company expects that prior to the consummation of
the MRA, the mix of consideration to be received by the IPP Parties
may be renegotiated. The foregoing is qualified in its entirety by
the text of the MRA (see Exhibit 10-11). As the Conditions
Determination Date (the date by which all IPP Parties must satisfy
or waive their third party conditions or withdraw from the MRA) has
not occurred, the Company cannot predict whether such conditions
will be satisfied, whether some IPP Parties may withdraw, whether
the terms of the MRA might be renegotiated, or whether the MRA will
be consummated. In the event the Company is unable to successfully
complete the MRA and therefore implement PowerChoice, it would
pursue all alternatives including a traditional rate request.
The principal effects of the MRA are to reduce significantly
the Company's existing payment obligations under the PPAs, which
currently consist of approximately 2,700 MW of capacity at December
31, 1997. While earnings will be depressed during the five-year
term, the savings in annual energy payments, coupled with the rates
established in PowerChoice, will yield free cash flow that can be
dedicated to the new debt service obligations associated with the
payment of cash to the IPP Parties.
Under the terms of the MRA, the Company's significant long
term and escalating IPP payment obligations will be restructured
into a defined and more manageable obligation and a portfolio of
restated and amended PPAs with price and duration terms that the
Company believes are more favorable than the existing PPAs. Under
the MRA, 19 PPAs representing approximately 1,180 MW of capacity
will be terminated completely thus allowing this capacity to be
replaced through the competitive market at market based prices.
The Company has no continuing obligation to purchase energy from
the terminating IPP Parties.
Also under the MRA, 8 PPAs representing approximately 541 MW
of capacity will be restated on economic terms and conditions that
are more favorable to the Company than the existing PPAs. The
restated contracts have a term of 10 years and are structured as
financial swap contracts where the Company receives or makes
payments to the IPP Parties based upon the differential between the
contract price and a market reference price for electricity. The
contract prices are fixed for the first two years changing to an
indexed pricing formula thereafter. Contract quantities are fixed
for the full 10 year term of the contracts. The indexed pricing
structure ensures that the price paid for energy and capacity will
fluctuate relative to the underlying market cost of gas and general
indices of inflation. Until such time as a competitive energy
market structure becomes operational in the State of New York, the
restated contracts provide the IPP Parties with a put option for
the physical delivery of energy. Additionally, one PPA
representing 42 MW of capacity will be amended to reflect a
shortened term and a lower stream of fixed unit prices. Finally,
the MRA requires the Company to provide the IPP Parties with a
number of fixed price swap contracts with a term of seven years
beginning in 2003. The fixed price swap contracts will be cash
settled monthly based upon a stream of defined quantities and
prices.
Although against the Company's forecast of market energy
prices the restructured and amended PPAs represent an expected
above-market payment obligation, the Company's portfolio of these
PPAs provides it and its customers with a hedge against significant
upward movement in market prices that may be caused by a change in
energy supply or demand. This portfolio and market purchases
contain terms that are believed to be more responsive to
competitive market price changes. (See Item 8. Financial
Statements and Supplementary Data - "Note 9. Commitments and
Contingencies - Long-term Contracts for the Purchase of Electric
Power").
POWERCHOICE AGREEMENT. The PowerChoice agreement establishes
a five-year rate plan that will reduce average residential and
commercial rates by an aggregate of 3.2% over the first three
years. This reduction will include certain savings that will
result from partial reductions of the New York State GRT.
Industrial customers will see average reductions of 25% relative to
1995 price levels; these decreases will include discounts currently
offered to some industrial customers through optional and flexible
rate programs. The cumulative rate reductions, net of GRT savings,
are estimated to be approximately $112 million, to be experienced
on a generally ratable basis over the first three years of the
agreement. During the term of the PowerChoice agreement, the
Company will be permitted to defer certain costs, associated
primarily with environmental remediation, nuclear decommissioning
and related costs, and changes in laws, regulations, rules and
orders. In years four and five of its rate plan, the Company can
request an annual increase in prices subject to a cap of 1% of the
all-in price, excluding commodity costs (e.g., transmission,
distribution, nuclear, and forecasted CTC). In addition to the
price cap, the PowerChoice agreement provides for the recovery of
deferrals established in years one through four and cost variations
in the MRA financial contracts resulting from indexing provisions
of these contracts. The aggregate of the price cap increase and
recovery of deferrals is subject to an overall limitation of
inflation.
Under the terms of the PowerChoice agreement, all of the
Company's customers will be able to choose their electricity
supplier in a competitive market by December 1999. The Company will
continue to distribute electricity through its distribution and
transmission facilities and would be obligated to be the so-called
provider of last resort for those customers who do not exercise
their right to choose a new electricity supplier.
The PowerChoice agreement provides that the MRA and the
contracts executed pursuant thereto shall be found to be prudent.
The PowerChoice agreement further provides that the Company shall
have a reasonable opportunity to recover its stranded costs,
including those associated with the MRA and the contracts executed
thereto, through a CTC and, under certain circumstances, through
exit fees or in rates for back up service.
Under the PowerChoice agreement, an MRA regulatory asset,
aggregating approximately $4,000 million, will be established. In
this way, the costs of the MRA would be deferred and amortized over
a period generally not to exceed ten years. The Company's rates
under PowerChoice are designed to permit recovery of the MRA
regulatory asset and to permit recovery of, and a return on, the
remainder of its assets, as appropriate. The PowerChoice
agreement, while having the effect of substantially depressing
earnings during its five-year term, will substantially improve
operating cash flows.
The PowerChoice agreement calls for the Company to divest all
of its fossil and hydro generation assets. Divestiture is intended
to be accomplished through an auction. Winning bids would be
selected within 11 months of PSC approval of the auction plan,
which was filed with the PSC separately from the PowerChoice
agreement. The Company will receive a portion of the auction sale
proceeds as an incentive to obtain maximum value in the sale. This
incentive would be recovered from sale proceeds. The Company
agreed that if it does not receive an acceptable bid for an asset,
the Company will form a subsidiary to hold any such assets and then
legally separate this subsidiary from the Company through a spin-
off to shareholders or otherwise. If a bid of zero or below is
received for an asset, the Company may keep the asset as part of
its regulated business. The auction process will serve to quantify
any stranded costs associated with the Company's fossil and hydro
generating assets. The Company will have a reasonable opportunity
to recover these costs through the CTC and otherwise as described
above. After the auction process is complete, the Company has
agreed not to own any non-nuclear generating assets in the State of
New York, subject to certain exceptions provided in the PowerChoice
agreement. Under the terms of the note indenture prepared in
connection with the financing of the MRA, the Company will be
required to use a majority of the cash portion of net proceeds from
the sale of its fossil and hydro generating assets to reduce
indebtedness. Such restrictions would not apply in the event that
the Company was unable to successfully conclude the consummation of
the MRA and therefore of PowerChoice but nonetheless sold such
assets.
The PowerChoice agreement contemplates that the Company's
nuclear plants will remain part of the Company's regulated
business. The Company has been supportive of the creation of a
statewide New York Nuclear Operating Company that it expects would
improve the efficiency of nuclear units throughout the state. The
PowerChoice agreement stipulates that absent such a statewide
solution, the Company will file a detailed plan for analyzing other
proposals regarding its nuclear assets, including the feasibility
of an auction, transfer and/or divestiture of such facilities,
within 24 months of PowerChoice approval.
The PowerChoice agreement also allows the Company to form a
holding company at its election. The Company plans to seek its
shareholders' approval at its 1998 annual meeting to the formation
of a holding company, the implementation of which would only occur
following various regulatory approvals.
At its public session on February 24, 1998, the PSC voted to
approve the PowerChoice agreement, which incorporates the terms of
the MRA. Subject to the satisfaction of the conditions to the MRA,
the PSC's approval of PowerChoice should allow the Company to
consummate the MRA in the first half of 1998. The PowerChoice
agreement will only become effective upon the closing of the MRA.
In approving PowerChoice, the PSC made the following changes, among
others, to the agreement: i) customers who had made a substantial
investment in on-site generation as of October 10, 1997 will be
grandfathered and not have to pay the CTC; ii) savings from any
reduction in the interest rate associated with the debt issued in
connection with the MRA financing as compared to assumptions
underlying the Company's PowerChoice filing will be deferred for
future disposition; and iii) change the generation auction
incentive to 15% of proceeds in excess of net book value for non-
Oswego assets and 5% of proceeds in excess of $100 million for
Oswego assets.
In its written order dated March 20, 1998, the PSC made
several other changes to the PowerChoice agreement, in addition to
those discussed at the February 24 session. The PSC determined to
limit the estimated value of the MRA regulatory asset that can be
recovered from customers, to approximately $4,000 million. The
estimated value of the MRA regulatory asset includes the issuance
of 42.9 million shares of common stock, which the PSC, in
determining the recoverable amount of such asset valued at $8 per
share. The Company's common stock closed at $12 7/16 per share on
March 26, 1998. The accounting implications of the limitation in
value are discussed under "Accounting Implications of the
PowerChoice Agreement and Master Restructuring Agreement." The PSC
also modified the reduction in average residential and commercial
rates. The PowerChoice agreement measured the 3.2% reduction
against 1995 prices. The PSC determined that the percentage
reduction should be applied against the lower of 1995 prices or the
most current twelve-month period. To the extent prices for the
most current twelve-month period are lower than 1995 prices, the
amount of cumulative rate reductions described below will increase.
Lastly, the PSC ordered the Company not to proceed to consummate
the MRA with respect to one contract held by one developer until a
satisfactory resolution of a cogeneration steam host contract is
reached.
New York law provides parties the right to appeal the
Commission's decision approving the PowerChoice agreement within
four months of the date of that decision. In addition, parties
have the right to petition the Commission for rehearing of the
decision within 30 days of the date of the decision. If a petition
for rehearing is filed and the Commission issues a decision on
rehearing, parties may appeal the decision on rehearing within four
months of the date of the decision on rehearing. Such an appeal or
petition for rehearing may be based on the failure of the record to
show a reasonable basis for the terms of the PowerChoice agreement
and may result in an amendment of the record to correct such
failure, in renegotiation of such terms or in renegotiation of the
PowerChoice agreement as a whole. There can be no assurance that,
on appeal or on rehearing, the approval of the PowerChoice
agreement will be upheld or that such appeal or rehearing will not
result in terms substantially less favorable to the Company than
those described herein.
All of the foregoing discussion of the PowerChoice agreement
is qualified in its entirety by the text of the agreement and PSC
Order (see Exhibits 10-12 and 10-13).
ACCOUNTING IMPLICATIONS OF THE POWERCHOICE AGREEMENT
AND MASTER RESTRUCTURING AGREEMENT
The Company concluded as of December 31, 1996, that the
termination, restatement or amendment of IPP contracts and
implementation of PowerChoice was the probable outcome of
negotiations that had taken place since the PowerChoice
announcement. Under PowerChoice, the separated non-nuclear
generation business would no longer be rate-regulated on a cost-of-
service basis and, accordingly, regulatory assets related to the
non-nuclear power generation business, amounting to approximately
$103.6 million ($67.4 million after tax or 47 cents per share) were
charged against 1996 income as an extraordinary non-cash charge.
As described under "Master Restructuring Agreement and the
PowerChoice Agreement," the PSC in its written order issued March
20, 1998 limited the estimated value of the MRA regulatory asset
that can be recovered from customers to approximately $4,000
million. The ultimate amount of the regulatory asset to be
established may vary based on certain events related to the
closing of the MRA. The estimated value of the MRA regulatory
asset includes the issuance of 42.9 million shares of common stock,
which the PSC, in determining the recoverable amount of such asset
valued at $8 per share. Because the value of the consideration to
be paid to the IPP Parties can only be determined at the MRA
closing, the value of the limitation on the recoverability of the
MRA regulatory asset is expected to be recorded as a charge to
expense in the second quarter of 1998 upon the closing of the MRA.
The charge to expense will be determined as the difference between
$8 per share and the Company's closing common stock price on the
date the MRA closes, multiplied by 42.9 million shares. Using the
Company's common stock price on March 26, 1998 of 12 7/16 per
share, the charge to expense would be approximately $190 million
(85 cents per share).
Under PowerChoice, the Company's remaining electric business
(nuclear generation and electric transmission and distribution
business) will continue to be rate-regulated on a cost-of-service
basis and, accordingly, the Company continues to apply SFAS No. 71
to these businesses. Also, the Company's IPP contracts, including
those restructured under the MRA and those not so restructured will
continue to be the obligations of the regulated business. As
described under "Master Restructuring Agreement and the PowerChoice
Agreement," the consummation of the MRA, as well as implementation
of PowerChoice, is subject to a number of contingencies.
The Emerging Issues Task Force ("EITF") of the FASB reached
a consensus on Issue No. 97-4 "Deregulation of the Pricing of
Electricity - Issues Related to the Application of SFAS No. 71 and
SFAS No. 101" in July 1997. The Company discontinued the
application of SFAS No. 71 and applied SFAS No. 101 with respect
to the fossil and hydro generation business at December 31, 1996,
in a manner consistent with the EITF consensus.
In addition, EITF 97-4 does not require the Company to earn
a return on regulatory assets that arise from a deregulating
transition plan in assessing the applicability of SFAS No. 71. In
the event the MRA and PowerChoice are implemented, the Company
believes that the regulated cash flows to be derived from prices it
would charge for electric service over 10 years, including the
CTC, assuming no unforeseen reduction in demand or bypass of the
CTC or exit fees, will be sufficient to recover the MRA regulatory
asset and provide recovery of and a return on the remainder of its
assets, as appropriate. In the event the Company could no longer
apply SFAS No. 71 in the future, it would be required to record an
after-tax non-cash charge against income for any remaining
unamortized regulatory assets and liabilities. Depending on when
SFAS No. 71 was required to be discontinued, such charge would
likely be material to the Company's reported financial condition
and results of operations and the Company's ability to pay common
and preferred dividends. The PowerChoice agreement while having
the effect of substantially depressing earnings during its five-
year term, will substantially improve operating cash flows.
In the event the Company is unable to successfully complete
the MRA and therefore implement PowerChoice, it would pursue all
alternatives including a traditional rate request. However,
notwithstanding such a rate request, it is likely that application
of SFAS No. 71 would be discontinued for the remaining electric
business, since the Company's current rate structure would no
longer be sufficient to recover its costs. The resulting non-cash
after-tax charges against income, based on regulatory assets and
liabilities associated with the nuclear generation and electric
transmission and distribution businesses as of December 31, 1997,
would be approximately $526.5 million or $3.65 per share. In
addition, the Company would be required to reassess the carrying
amounts of its long-lived assets in accordance with SFAS No. 121.
SFAS No. 121 requires long-lived assets and certain identifiable
intangibles 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 or when assets
are to be disposed of. 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/or its disposition. The Company would also be required
to determine the extent to which adverse purchase commitments, if
any, are required to be recorded as obligations. Various
requirements under applicable law and regulations and under
corporate instruments, including those with respect to issuance of
debt and equity securities, payment of common and preferred
dividends, and certain types of transfers of assets could be
adversely impacted by any such write-downs.
With the implementation of PowerChoice, specifically the
separation of non-nuclear generation as an entity that would no
longer be cost-of-service regulated, the Company is required to
assess the carrying amounts of its long-lived assets in accordance
with SFAS No. 121. The Company has determined that there is no
impairment of its fossil and hydro generating assets. To the extent
the proceeds resulting from the sale of the fossil and hydro assets
are not sufficient to avoid a loss, the Company would be able to
recover such loss through the CTC. The PowerChoice agreement
provides for deferral and future recovery of losses, if any,
resulting from the sale of the non-nuclear generating assets.
The Company believe that it will be permitted to record a
regulatory asset for any such loss in accordance with EITF 97-4.
The Company's fossil and hydro generation plant assets had a net
book value of approximately $1.1 billion at December 31, 1997.
PSC COMPETITIVE OPPORTUNITIES PROCEEDING - ELECTRIC
On May 16, 1996, the PSC issued its Order in the COPS case,
which called for a major restructuring of New York State's electric
industry. The COPS order called for a competitive wholesale power
market and the introduction of retail access for all electric
customers. The goals cited in its decision included lowering
consumer rates, increasing choice, continuing reliability of
service, continuing environmental and public policy programs,
mitigating concerns about market power and continuing customer
protection and the obligation to serve.
The PSC decision in the COPS proceeding states that recovery
of utility stranded costs may be accomplished by a non-bypassable
"wires charge" to be imposed by distribution companies. The PSC
decision also states that a careful balancing of customer and
utility interests and expectations is necessary, and that the level
of stranded cost recovery will ultimately depend upon the
particular circumstances of each utility.
On June 10, 1997, the PSC ordered a multi-utility, retail
access pilot program that would allow qualified farmers and food
processors to shop for electricity and other energy services. The
PSC required utilities to adjust the current delivery rates for
farmers and food processors, which resulted in rate reductions of
about 10 percent for farmers and 3 percent to 6 percent for food
processors. Delivery under this program began in late 1997. The
Company does not believe that this order will have a material
adverse effect on its financial position or results of operations.
On August 27, 1997, the PSC requested comments on its staff's
tentative conclusions about how nuclear generation and fossil
generation should be treated after decisions are made on the
individual electric restructuring agreements currently pending
before the PSC. The PSC staff concluded that beyond the transition
period (the period covered by the individual restructuring
agreements including PowerChoice), nuclear generation should
operate on a competitive basis. In addition, the PSC staff
concluded that a sale of generation plants to third parties is the
preferred means of determining the fair market value of generation
plants and offers the greatest potential for the mitigation of
stranded costs. The PSC staff also concluded that recovery of sunk
costs, including post shutdown costs, would be subject to review by
the PSC and this process should take into account mitigation
measures taken by the utility, including the steps it has taken to
encourage competition in its service area. The Company's nuclear
generation assets had a net book value of $1.5 billion (excluding
the reserve for decommissioning) at December 31, 1997.
In October 1997, the majority of utilities with interests in
nuclear power plants, including the Company, requested that the PSC
reconsider its staff's nuclear proposal. In addition, the
utilities raised the following issues: impediments to nuclear
plants operating in a competitive mode; impediments to the sale of
plants; responsibility for decommissioning and disposal of spent
fuel; safety and health concerns; and environmental and fuel
diversity benefits. In light of all of these issues, the utilities
recommended that a more formal process be developed to address
those issues.
The three investor-owned utilities, Rochester Gas and
Electric Corporation, Consolidated Edison Company of New York, Inc.
and the Company, which are currently pursuing formation of a
nuclear operating company in New York State, also filed a response
with the PSC in October 1997. The response stated that a forced
divestiture of the nuclear plants would add uncertainty to
developing a statewide approach to operating the plants and
requested that such a forced divestiture proposal be rescinded.
The response also stated that implementation of a consolidated
six-unit operation would contribute to the mitigation of
unrecovered nuclear costs. The NYPA, which is also pursuing
formation of the nuclear operating company, submitted its own
comments which were similar to the comments of the three utilities.
In February 1998, the PSC established a formal proceeding to
further examine issues related to nuclear plants and the
feasibility of applying market-based pricing to these facilities.
See "Master Restructuring Agreement and PowerChoice
Agreement" above for a discussion of the treatment of nuclear
operations during the term of PowerChoice.
FERC RULEMAKING ON OPEN ACCESS AND STRANDED COST RECOVERY
In April 1996, the FERC issued FERC Order 888. Order 888
promotes competition by requiring that public utilities owning,
operating, or controlling interstate transmission facilities file
tariffs which offer others the same transmission services they
provide for themselves, under comparable terms and conditions. The
Company has complied with this requirement by filing its open
access transmission tariff with FERC on July 7, 1996. Based upon
settlement discussions with various parties, a proposed settlement
was submitted to the FERC in the first quarter of 1997. The
settlement has not been approved by the FERC at this time.
Hearings were conducted in September 1997 with non-settling
parties. A March 1998 Administrative Law Judge's recommended
decision in this proceeding recommended lower tariffs than those
filed by the Company. The Company is unable to determine the
ultimate resolution of this issue or when a decision will be issued
by FERC.
Under FERC Order 888, the NYPP was required to file reformed
power pooling agreements that establish open, non-discriminatory
membership provisions and modify any provisions that are unduly
discriminatory or preferential. On January 31, 1997, the NYPP
Member Systems (the "Member Systems") submitted a comprehensive
proposal to establish an ISO, a New York State Reliability Council
("NYSRC") and a New York Power Exchange ("NYPE") that will foster
a fully competitive wholesale electricity market in New York State.
The ISO would provide for the reliable operation of the
transmission system in New York State and provide nondiscriminatory
open access to transmission services under a single ISO tariff.
Through the ISO, the transmission owners, including the Company,
would be compensated for the use of their transmission systems on
a cost-of-service basis. The NYSRC would establish the reliability
rules and standards by which the ISO operates the bulk power
system. The ISO would also administer the daily electric energy
market and the NYPE would facilitate the electric energy market on
a day-ahead basis. On May 2, 1997, the Member Systems made a
supplemental filing related to the proposed NYSRC and on August 15,
1997, six of the Member Systems filed an application for market-
based rate authority in the new wholesale market structure. On
December 19, 1997, the Member Systems submitted a revised filing
which reflected the fundamental components of the initial January
31, 1997 filing. However, the December 19, 1997 filing provides
for additional explanatory materials, incorporates FERC's guidance
set forth in FERC orders involving other power pools and ISOs, and
sets forth a revised governance structure of the ISO. The Company
is unable to predict when FERC will act on these submittals, or
whether it will approve the filings with or without modifications.
However, the Company's PowerChoice agreement does not condition
retail access on the presence of an ISO.
In Order 888, the FERC also stated that it would provide for
the recovery of prudent and verifiable wholesale stranded costs
where the wholesale customer was able to obtain alternative power
supplies as a result of Order 888's open access mandate. Order 888
left to the states the issue of retail stranded cost recovery.
Where newly created municipal electric utilities required
transmission service from the displaced utility, the FERC stated
that it would entertain requests for stranded cost recovery since
such municipalization is made possible by open access. The FERC
also reserved the right to consider stranded costs on a case-by-
case basis if it appeared that open access was being used to
circumvent stranded cost review by any regulatory agency.
Numerous parties, including the Company, filed requests for
rehearing of Order 888. In March 1997, the FERC issued Order 888-
A, which generally affirmed Order 888 and granted rehearing on only
a handful of issues. One of those issues was whether the FERC
would review stranded costs in annexation cases as it committed to
do in municipalization cases. In Order 888-A the FERC stated that
it would review stranded costs resulting from territorial
annexation by an existing municipal electric system, provided that
system relied on transmission from the displaced utility. The FERC
denied the Company's request for rehearing on how stranded costs
would be calculated and other issues. In November 1997, FERC
issued Order 888-B. This Order largely affirmed the positions set
forth in Order 888-A while clarifying that the FERC recognizes the
existence of concurrent state jurisdiction over stranded costs
arising from municipalization. The FERC acknowledged in Order 888-
B that the states may be first to address the issue of retail-
turned-wholesale stranded costs, and stated that it will give the
states substantial deference where they have done so.
In late January 1997, the Company provided 26 communities in
St. Lawrence and Franklin counties with estimates they requested of
the stranded costs they might be expected to pay if they withdraw
from the Company's system to create government-controlled
utilities. The preliminary estimate of the combined potential
stranded cost liability for the communities ranges from a low of
$225 million to a high of $452 million, depending upon the forecast
of electricity market prices that is used. These amounts do not
include the costs of creating and operating a municipal utility.
At this time, 21 of the original 26 communities are still pursuing
the matter. If these 21 communities withdrew from the Company's
system, the Company would experience a potential revenue loss of
approximately $60 million to $65 million per year. In addition,
the Company is aware of other communities that are considering
municipalization. However, the Company is unable to predict
whether those communities would pursue municipalization.
The stranded cost calculations were based on a methodology
prescribed by the FERC. Because no municipality has moved forward
with condemnation, the value of the Company's facilities has not
been deducted from the stranded cost estimates. The stranded costs
included in these estimates are the communities' share of
obligations that were incurred on behalf of all customers to
fulfill the Company's legal obligations to ensure adequate,
reliable electricity service. Such legitimate and prudent costs
are currently included in electricity rates. Government-mandated
payments to IPPs represent the largest single component of these
costs. These 21 communities seeking to withdraw from the Company's
system also propose to disconnect entirely from the Company's
system and to take transmission service from another utility. They
believe that, given the provisions of Order 888, FERC would not
approve the Company's request for stranded cost recovery under
these circumstances. The Company has responded that, regardless of
the result at the FERC, opportunities for stranded cost recovery in
this matter could also be pursued before the PSC and in a state
condemnation proceeding. (See "Master Restructuring Agreement and
the PowerChoice Agreement.") The Company is unable to predict the
outcome of this matter.
OTHER FEDERAL AND STATE REGULATORY INITIATIVES
PSC PROPOSAL OF NEW IPP OPERATING AND PPA MANAGEMENT
PROCEDURES. In August 1996, the PSC proposed to examine the
circumstances under which a utility, including the Company, may
legally curtail purchases from IPPs; whether utilities should be
permitted to collect data that will assist in monitoring IPPs'
compliance with federal QF requirements, upon which the mandated
purchases are predicated; and if utilities should be allowed to
demand security from IPPs to ensure the repayment of amounts
accumulated in tracking accounts made under their purchased power
contracts.
The PSC noted that some of the current IPP contracts are far
above market prices and are causing utilities to seek rate
increases. In addition, the PSC stated that its proposal was
initiated to protect ratepayers, since it would ensure just and
reasonable rates in the event ongoing negotiations between
utilities and IPPs fail.
MONITORING. In December 1996, the PSC gave the New York
State utilities, including the Company, the authority to collect
data to assist them in monitoring IPPs' compliance with both
federal QF standards and state requirements. The PSC stated that
if QFs are not meeting requirements, the obligation to pay the full
contract rate, which is funded by utility ratepayers, is generally
excused or mitigated. Furthermore, if the data collected through
a QF monitoring program indicates a facility is not meeting federal
standards, the utility could petition the FERC to decertify the QF,
which could result in penalties that could include cancellation of
the contract. A similar penalty could be imposed if it is
determined a QF has failed to maintain compliance with state law.
Under the monitoring program, QFs are required to submit data as of
March 1 each year for the previous calendar year. In accordance
with the terms of the MRA, the Company will not implement any QF
monitoring program for the IPP Parties. However, the Company
continues to monitor those IPPs that are not IPP Parties for
continued QF compliance under PSC regulation.
CURTAILMENT. On May 20, 1997, the PSC addressed the
procedures under which a utility, including the Company, may
legally curtail purchases from IPPs that are QFs, unless
curtailment is specifically prohibited by contract. Curtailment is
allowed by a FERC rule, under certain operational circumstances
when purchases from the QFs will exceed the costs the utility would
incur if it generated the power itself. Advance notice must be
provided to the QF along with the reasons for such curtailment,
which are subject to verification by the PSC either before or after
curtailment. The PSC stated that PURPA, which encouraged
generation by IPPs, was supposed to be revenue-neutral. However,
they noted that this has not been the situation in New York State
and ratepayers have been unduly burdened because of their lack of
specific curtailment procedures.
The decision to permit curtailment is not likely to affect
the PPAs covered by the MRA, which represents approximately 80% of
the Company's over-market purchased power obligations, as described
previously. However, the decision could affect most of the
remaining IPP contracts. The Company is unable to determine the
effect of these statements until such a time as there is a final
order.
The Company cannot predict whether the PSC will take any
action on the firm security issue. However, the firm security
issue with respect to the IPP Parties covered under the MRA would
be settled upon the closing of the MRA.
MULTI-YEAR GAS RATE SETTLEMENT AGREEMENT. The Company,
Multiple Intervenors (an unincorporated association of
approximately 60 large commercial and industrial energy users with
manufacturing and other facilities located throughout New York
State) and PSC staff reached a three-year settlement that was
conditionally approved by the PSC on December 19, 1996. The PSC
ordered conditional approval on the three-year settlement agreement
until a final, redrafted agreement, which reflects the Commission's
order, is submitted for final approval. The settlement results in
a $10 million annual reduction in base rates or a $30 million total
reduction over the three-year term of the settlement. This
reflects a $19 million reduction in the amount of fixed non-
commodity costs to be recoverable in base rates, offset by a $9
million increase in annual base rates. The Company estimates that
the combination of in-hand supplier refunds and further reductions
in upstream pipeline costs will be sufficient to fund the $19
million annual reduction in non-commodity cost recovery.
If the non-commodity cost reductions exceed $57 million ($19
million annually) during the three-year settlement period, the
excess, up to $40 million will be credited to a Contingency Reserve
Account ("CRA") to be utilized for ratepayer benefit in the rate
year ending October 31, 2000 or beyond. To the extent the actual
non-commodity cost reductions exceed $57 million by more than $40
million, the Company may retain any excess subject to a return on
equity sharing provision. In the event the non-commodity
reductions fall short of the $57 million estimate, the Company will
bear the risk of any shortfall. In the event that the termination
or restructuring of IPP contracts results in margin (revenues less
fuel costs) or peak shaving losses, the margin losses would be
collected currently subject to 80%/20% (ratepayer/shareholder)
sharing and the peak shaving losses will be deferred to the CRA,
subject to limits specified in the settlement.
In return for taking on this risk, the Company has achieved
a portion of the revised rate structure that had been proposed to
reduce its throughput risk. The Company obtained an ROE cap of
13.5% with 50/50 sharing between ratepayers and shareholders in
excess of the cap. The Company also has an opportunity to earn up
to $2.25 million annually if its gas commodity costs are lower than
a market based target without being subject to the ROE cap. The
Company has an equal $2.25 million risk if gas commodity costs
exceed the target. An additional major benefit of the revised rate
design is that the margin made on each additional new customer will
significantly increase to the extent additional throughput does not
require additional upstream pipeline capacity for service. This,
along with the approval of the Company's Progress Fund, which
allows the Company to use utility revenues in an amount not to
exceed $11 million in total for the purpose of providing financing
for large customers to convert or increase their gas use, will
provide new opportunities for growth.
GENERIC GAS RATE PROCEEDING. As a result of the generic rate
proceeding, in which the PSC ordered all New York utilities to
implement a service unbundling beginning in May 1996, nearly 3,000
customers have chosen to buy natural gas from other sources, with
the Company continuing to provide transportation service for a
separate fee. These changes have not had a material impact on the
Company's margins since the margin is traditionally derived from
the delivery service and not from the commodity sale. The margin
for delivery for residential and commercial aggregation services
equals the margin on the traditional sales service classes. To
date this migration has not resulted in any stranded costs since
the PSC has allowed the utilities to assign the pipeline capacity
to the customers converting from sales to transportation. This
assignment is allowed during a three-year period ending March 1999,
at which time the PSC will decide on methods for dealing with the
remaining unassigned or excess capacity. As a part of the generic
rate proceeding, all utilities are required to file a report with
the PSC in April 1998, describing actions that have been taken to
mitigate potential stranded costs as customers migrate to
transportation service. In a clarifying order in this proceeding,
issued September 4, 1997, the PSC has indicated that it is unlikely
that utilities will be allowed to continue to assign pipeline
capacity to departing customers after March 1999.
On a separate but parallel path, in September 1997, the PSC
issued for comment its staff's position paper on the future of the
natural gas industry, including recommendations for increasing
competition and expanding customer choice in the natural gas
marketplace. The staff proposed, among other things, that all
regulated natural gas utilities exit the business of purchasing
natural gas for customers over the next five years. This would
complete the transition of customers from sales to transportation
service only. The regulated utilities would only deliver natural
gas purchased by customers from competitive suppliers. If this
proposal is adopted by the PSC, then it would eliminate the need to
regulate natural gas purchasing practices since market forces would
establish natural gas prices.
The position paper identified a number of issues that would
need to be resolved in order for this proposal to be successful.
The primary issues are the pipeline capacity and gas supply
contracts that the local utilities have with interstate pipelines
that extend beyond the proposed five-year transition period, the
obligation of the utility to serve as supplier of last resort, and
the issue of system reliability.
The Company and other parties submitted comments and reply
comments to the PSC in late November and December of 1997,
respectively. With the exception of the issues to be resolved by
the PSC, as mentioned above, the Company does not believe that this
proposal will have a material adverse effect on its results of
operations or financial condition, since the Company's natural gas
margin is derived from the delivery service and not from the
commodity sale. The resolution of the issues identified by the PSC
could result in unrecovered stranded costs for the Company. The
Company is unable to predict how the PSC will resolve those issues.
For a discussion of the Company's gas supply, storage and pipeline
commitments, see Item 8. Financial Statements and Supplementary
Data - "Note 9. Commitments and Contingencies - Gas Supply, Storage
and Pipeline Commitments.")
NRC AND NUCLEAR OPERATING MATTERS. In October 1996, the NRC
required companies with nuclear plants to provide the NRC with
added confidence and assurance that their plants are operated and
maintained within the design basis, and any deviations are
reconciled in a timely manner. Such information, which was filed
within the required 120 days, will be used by the NRC to verify
that companies are in compliance with the terms and conditions of
their license(s) and NRC regulations. In addition, it will allow
the NRC to determine if other inspection activities or enforcement
actions should be taken on a particular company.
In the letter transmitting the requested information to the
NRC, the Company concluded that it has reasonable assurance that
(i) design basis requirements are being translated into operating,
maintenance, and testing procedures; and (ii) system, structure and
component configuration and performance are consistent with the
design basis. Also, the Company has an effective administrative
tool for the identification, documentation, notification,
evaluation, correction, and reporting of conditions, events,
activities, and concerns that have the potential for adversely
affecting the safe and reliable operation of Unit 1 and Unit 2.
In April 1997 and December 1997, the Company received notices
from the NRC of a $200,000 fine and $50,000 fine, respectively, for
violations at Unit 1 and Unit 2. The penalties were for violations
related to corrective actions and design control. The Company paid
the fines and is implementing corrective action. On January 23,
1998, the Company received notice of a proposed $55,000 fine from
the NRC for violations of NRC requirements related to radioactive
waste issues. The Company does not plan to contest the proposed
NRC fine.
In January 1998, the NRC issued its Systematic Assessment of
Licensee Performance (the "SALP") report on Unit 1 and Unit 2,
which covers the period June 1996 to November 1997. The SALP
report, which is an extensive assessment of the plants' performance
in the areas of operations, maintenance, engineering and support,
stated that the performance of Unit 1 and Unit 2 was generally
good, although ratings were lower than the previous assessment.
The Company agrees with the NRC's determination that there are
areas of its performance that need improvement and is taking
several actions to make those needed improvements.
The Company believes that NRC safety enforcement is becoming
more stringent as indicated by the NRC's request for information,
fines that the Company has been assessed and lower SALP ratings and
that there may be a direct cost impact on companies with nuclear
plants as a result. The Company is unable to predict how such a
changed operating environment may affect its results of operations
or financial condition.
Some owners of older General Electric Company boiling water
reactors, including the Company, have experienced cracking in
horizontal welds in the plants' core shrouds. In response to
industry findings, the Company installed pre-emptive modifications
to the Unit 1 core shroud during a 1995 refueling and maintenance
outage. The core shroud, a stainless steel cylinder inside the
reactor vessel, surrounds the fuel and directs the flow of reactor
water through the fuel assemblies.
Inspections conducted as part of the March 1997 refueling and
maintenance outage detected cracking in vertical welds not
reinforced by the 1995 repairs. On April 8, 1997, the Company
filed a comprehensive inspection and analysis report with the NRC
that concluded that the condition of the Unit 1 core shroud
supports the safe operation of the plant.
On May 8, 1997, the NRC approved the Company's request to
operate Unit 1 until the next scheduled mid-cycle outage, late
1998. The Company agreed to propose an inspection plan for the
outage and submit the plan to the NRC at least three months before
the outage is scheduled to begin. The Company believes it has a
strong technical basis to operate Unit 1 without a mid-cycle outage
and is seeking the necessary approval from the NRC to postpone the
inspections until the unit's refueling and maintenance outage in
spring 1999, but there can be no assurance that such approval will
be granted.
The Unit 1 refueling and maintenance outage, originally
planned to be completed in early April 1997, was completed on May
10, 1997 due to the core shroud issue. On September 15, 1997, Unit
1 was taken out of service due to leaking in one of four back-up
condensers. The standby condensers serve as a back-up system for
the removal of reactor steam. The condensers are maintained in a
ready state during normal plant operations. Tests and inspections
were conducted on the remaining condensers and similar conditions
were found. On December 10, 1997, Unit 1 was returned to service
after the replacement of all four condensers, which cost
approximately $6.7 million.
OTHER COMPANY EFFORTS TO ADDRESS COMPETITIVE CHALLENGES
TAX INITIATIVES. The Company is working with utility,
customer and state representatives to explain the negative impact
that all utility taxes, including the GRT, are having on rates and
the state of the economy. At the same time, the Company is also
contesting the high real estate taxes it is assessed by many taxing
authorities, particularly those imposed upon generating facilities.
The New York State Legislature passed a state budget in
August 1997 which includes a reduction of the GRT over three years.
For gas and electric utilities, the tax imposed on gross income
will be reduced from 3.5% to 3.25% on October 1, 1998, and from
3.25% to 2.5% on January 1, 2000. The state tax imposed on gross
earnings will remain unchanged at .75%, bringing the total GRT to
3.25% -- a full percentage point lower than today's level of 4.25%.
The savings from the reduction of the GRT will be passed on to the
Company's customers. The Company believes that further tax relief
is needed to relieve the Company's customers of high energy costs
and to improve New York State's competitive position as the
industry moves toward a competitive marketplace.
The following table sets forth a summary of the components of
other taxes (exclusive of income taxes) incurred by the Company in
the years 1995 through 1997:
<TABLE>
<CAPTION>
In millions of dollars
1997 1996 1995
- ---------------------------------------------------------------
<S> <C> <C> <C>
Property tax expense $250.7 $249.4 $264.8
Sales tax 13.4 14.1 13.9
Payroll tax 34.1 36.4 37.3
Gross Receipts Tax 184.6 184.1 190.2
Other taxes 0.1 0.5 5.2
- ---------------------------------------------------------------
Total tax expense 482.9 484.5 511.4
Charged to construction,
subsidiaries and regulatory
recognition (11.4) (8.7) 6.1
- ---------------------------------------------------------------
Total other taxes $471.5 $475.8 $517.5
===============================================================
</TABLE>
CUSTOMER DISCOUNTS. In recent years, some industrial
customers have found alternative suppliers or are generating their
own power. In addition, a weakened economy or attractive energy
prices elsewhere have contributed to other industrial 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 (SC-11), under which all new contract rates are
administered based on demonstrated industrial and commercial
competitive pricing alternatives 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. In addition, the Company has
economic development programs which provide tariff based incentives
to retain and grow load.
As of January 1998, the Company has 152 executed contracts
under its flexible tariff offerings. These contracts have been
signed to mitigate the lost margin impacts associated with
customers executing the competitive alternatives mentioned above.
In addition, many of these contracts include an increase in
production levels and/or attract new customers to the Company's
service territory.
In 1997 and 1996, the total amount of customer discounts
(economic development programs and flexible pricing) was $90.6
million and $75.5 million, respectively. The Company recovered
$46.6 million and $56.7 million in rates, respectively. Pending
implementation of PowerChoice, the Company budgeted its discounts
to increase to approximately $95.4 million in 1998 as some
discounts granted in 1997 are in effect for an entire year and
further discounts are granted. The Company is aggressively using
SC-11 to increase sales to existing customers and to attract new
customers to its service territory. With the reduction in
industrial prices provided in PowerChoice, the level of discounts
that have been necessary should decline in the future.
REGULATORY AGREEMENTS/PROPOSALS
(See "Master Restructuring Agreement and the PowerChoice
Agreement.")
1995 RATE ORDER. 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.
YEAR 2000 COMPUTER ISSUE
As the year 2000 approaches, the Company, along with many
other companies, could experience potentially serious operational
problems, since many computer programs that were developed will not
properly recognize calendar dates beginning with the year 2000.
Further, there are embedded chips contained within generation,
transmission, distribution and gas equipment that may be date-
sensitive. In these circumstances where an embedded chip fails to
recognize the correct date, electric or gas operations could be
adversely affected. The Company is addressing these issues so that
its computer systems and, where necessary, its embedded chips will
process dates greater than 1999, thereby preventing any adverse
operational or financial impacts. The Company has been addressing
the year 2000 information technology issue through the remediation
and replacement of existing business applications and parts of its
technical infrastructure. In late 1997, the services of a leading
computer services and consulting firm were retained to conduct an
assessment of the Company's entire year 2000 program. As a result
of the assessment, a Company-wide year 2000 project management
office has been formed and year 2000 project managers have been
appointed within each business group and efforts are underway to
evaluate the scope of the problem for embedded technologies/process
control systems in all business groups within the Company. A
Company-wide program director and an executive level steering
committee have been put in place to oversee all aspects of the
program. The Company is also evaluating the exposure to year 2000
problems of third parties with whom the Company conducts business.
The Company expects to complete an inventory of exposures,
including an assessment of priorities, costs and resources, by the
third quarter of 1998. Failures of the Company and/or third party
computer systems and embedded chips could have a material impact on
the Company's ability to conduct its business. Until further
progress is made on these efforts, management is unable to estimate
the total year 2000 compliance expense, but it is in the process of
assessing this expense.
RESULTS OF OPERATIONS
Earnings for 1997 were $145.9 million, or $1.01 per share,
as compared to $72.1 million, or 50 cents per share, in 1996 and
$208.4 million, or $1.44 per share, in 1995. In comparing
year-to-year results, earnings in 1996 reflect certain significant
events that were not repeated in 1997. Earnings in 1996 were
reduced by an after-tax write-off of $67.4 million, or 47 cents per
share, associated with the discontinued application of regulatory
accounting principles to the Company's fossil and hydro generation
business. Largely as a result of the Company's 1996 assessment of
the increased risk of collecting significantly higher levels of
past-due customer bills, bad debt expense in 1996 was higher than
in 1997 by $81.1 million, reducing earnings in 1996, compared to
1997, by 37 cents per share. However, earnings in 1996 were aided
by a $15 million after-tax gain on the sale of a 50 percent
interest in CNP which added 10 cents per share to 1996 earnings.
Industrial customer discounts not recovered in rates in 1997
exceeded 1996 levels by $25.2 million, reducing 1997 earnings by 11
cents per share (see Other Company Efforts to Address Competitive
Challenges - "Customer Discounts.") In addition, a decline in
higher-margin residential sales also adversely impacted 1997
earnings. The lower-margin industrial-special sales (sales by the
Company on behalf of NYPA) and industrial sales increased. As a
result, total public sales were essentially the same as sales in
1996.
Earnings for 1995 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. These
factors similarly impacted 1996 and 1997 results. In addition,
1995 earnings included the recording of a one-time, non-cash
adjustment of prior years' demand-side management ("DSM") incentive
revenues, revenues earned under the Unit 1 operating incentive
sharing mechanism and a gain on the sale of HYDRA-CO that
collectively increased 1995 earnings by 17 cents per share.
The Company's 1997 earned ROE was 5.5% as compared to 2.8%
(5.4% before extraordinary loss) in 1996 and 8.4% in 1995. The
Company's ROE authorized in the 1995 or last rate setting process
is 11.0% for the electric business and 11.4% for the gas business.
Factors contributing to earnings below authorized levels in 1997
included, among other things, sales below those forecasted in
determining rates, contractual increases in capacity payments to
IPPs and increasing discounts to customers. As discussed under
"Master Restructuring Agreement and the PowerChoice Agreement" and
"Accounting Implications of the PowerChoice Agreement and Master
Restructuring Agreement," the Company forecasts that earnings for
the five-year term of the PowerChoice agreement will be
substantially depressed. The level of earnings for 1998 will also
be impacted, in part, by the date of implementation of PowerChoice,
the PowerChoice charge of $190 million expected to be taken in the
second quarter of 1998 and may also be negatively impacted by the
financial effects of the January 1998 ice storm (see Item 8.
Financial Statements and Supplementary Data - "Note 13. Subsequent
Event").
The following discussion and analysis highlights items that
significantly affected operations during the three-year period
ended December 31, 1997. This discussion and analysis is not
likely to be indicative of future operations or earnings,
particularly in view of the probable termination, restatement or
amendment of IPP contracts and implementation of PowerChoice. It
also should be read in conjunction with Item 8. Financial
Statements and Supplementary Data and other financial and
statistical information appearing elsewhere in this report.
ELECTRIC REVENUES were $3,309 million in both 1997 and 1996,
a decrease of $26.1 million, or 0.8% from 1995. As shown in the
following table, FAC revenues increased $42.8 million in 1997,
primarily as a result of the Company's ability in 1997 to recover
increased payments to the IPPs through the FAC. However, this
increase was offset by a decrease in revenues from sales to other
electric systems and lower electric sales due to warmer weather.
Under PowerChoice, revenues may decline as customers choose
alternative suppliers. However, the Company will recover stranded
costs through the CTC. See "Master Restructuring Agreement and the
PowerChoice Agreement."
Electric operating revenues decreased in 1996, primarily due
to a decrease in miscellaneous electric revenues. Miscellaneous
electric revenues were lower in 1996 primarily because 1995
electric revenues included the recording of $71.5 million of
unbilled, non-cash revenues in accordance with the 1995 rate order,
$13.0 million of revenues earned under MERIT (an incentive
mechanism related to improvement in key performance areas which
ended in 1996) and a one-time, non-cash adjustment of prior year's
DSM incentive revenues and a reduction in the DSM rebate cost
program. However, higher electric sales due to colder weather, an
increase in sales to other electric systems, an increase in FAC
revenues and higher electric rates (effective April 26, 1995)
partly offset those factors that contributed to lower electric
revenues. FAC revenues increased $28.3 million in 1996, which
primarily reflects the Company's increased payments to the IPPs
recovered through the FAC.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
INCREASE (DECREASE) FROM PRIOR YEAR
(In millions of dollars)
- -----------------------------------------------------------------
ELECTRIC REVENUES 1997 1996 TOTAL
- -----------------------------------------------------------------
<S> <C> <C> <C>
Amortization of unbilled
revenues $ - $ (77.1) $ (77.1)
Base rates - 65.3 65.3
Fuel adjustment clause
revenues 42.8 28.3 71.1
Changes in volume and mix
of sales to ultimate
consumers (12.7) (28.1) (40.8)
Sales to other electric
systems (29.6) 24.5 (5.1)
MERIT revenue - (13.0) (13.0)
DSM revenue - (26.5) (26.5)
------- ------ -----
$ 0.5 $ (26.6) $ (26.1)
======== ====== ======
</TABLE>
<PAGE>
<PAGE>
The FAC is eliminated under the PowerChoice agreement.
Changes in FAC revenues are generally margin-neutral (subject to an
incentive mechanism discussed in Item 8. Financial Statements and
Supplementary Data - "Note 1. Summary of Significant Accounting
Policies"), 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 provided for the recovery
of program related rebate costs.
ELECTRIC KILOWATT-HOUR SALES were 37.1 billion in 1997, 39.1
billion in 1996 and 37.7 billion in 1995. The 1997 decrease of 2.0
billion KWh, or 5.1% as compared to 1996, is related primarily to
a 31.0% decrease in sales to other electric systems. (See Item 8.
Financial Statements and Supplementary Data -"Electric and Gas
Statistics - Electric Statistics"). The 1996 increase of 1.4
billion KWh, or 3.8% as compared to 1995, reflects a 26.2% increase
in sales to other electric systems and a 1.2% increase in sales to
ultimate customers due to the colder weather. Sales to other
electric systems were lower primarily due to a reduction in the
availability of nuclear generation as a result of the outages at
Unit 1. The Company is anticipating little or no growth in 1998 in
sales to ultimate consumers, which will be sensitive to the
business climate in its service territory.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
Details of the changes in electric revenues and KWh sales by customer group are
highlighted in the table below:
% INCREASE (DECREASE) FROM PRIOR YEAR
1997 % OF -------------------------------------
ELECTRIC 1997 1996
CLASS OF SERVICE REVENUES REVENUES SALES REVENUES SALES
- ----------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Residential 37.1% (2.0)% (2.0)% 3.1% 0.5%
Commercial 37.3 (0.3) (0.1) - (0.4)
Industrial 16.1 1.2 0.6 0.2 1.2
Industrial-Special 1.9 5.8 4.2 3.9 6.7
Municipal service 1.6 1.4 (4.5) 5.8 7.4
- ----------------------------------------------------------------------
Total to ultimate
consumers 94.0 (0.6) - 1.4 1.2
Other electric
systems 2.5 (26.1) (31.0) 27.5 26.2
Miscellaneous 3.5 70.4 (100.0) (57.8) (17.7)
- ----------------------------------------------------------------------
TOTAL 100.0% -% (5.1)% (0.8)% 3.8%
</TABLE>
<PAGE>
<PAGE>
As indicated in the table below, internal generation
decreased 10.1% in 1997, principally due to the outage at Unit 1
and a reduction in hydroelectric power as a result of lower than
normal precipitation in the summer months. In 1997, Unit 1 was out
of service for 153 days, due to a planned refueling and
maintenance outage (which took 68 days) and for the emergency
condenser replacement (which took approximately 85 days) while in
1996, Unit 2 was out of service for a 36 day planned refueling and
maintenance outage. (See "Other Federal and State Regulatory
Initiatives - NRC and Nuclear Operating Matters.") The amount of
electricity delivered to the Company by the IPPs decreased by
approximately 277 GWh or 2.0%. However, total IPP costs increased
by approximately $18.0 million or 1.7%, as discussed below. (See
"Master Restructuring Agreement and the PowerChoice Agreement").
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
1997 1996 1995
--------------- ---------------- ----------------
(In millions of dollars)
GWh Cost GWh Cost GWh Cost
------ ------ ------ ------- ------ --------
<S> <C> <C> <C> <C> <C> <C>
Fuel for electric
generation:
Coal 7,459 $ 106.4 7,095 $ 100.6 6,841 $ 97.9
Oil 701 32.2 462 21.1 537 21.3
Natural gas 394 8.6 319 9.2 996 20.2
Nuclear 6,339 33.0 8,243 47.7 7,272 43.3
Hydro 2,905 - 3,679 - 2,971 -
------- ------ ------ ------- ------ --------
17,798 180.2 19,798 178.6 18,617 182.7
------- ------ ------ ------- ------ --------
Electricity
purchased:
IPPs:
Capacity - 220.8 - 212.8 - 181.2
Energy and taxes 13,520 885.7 13,797 875.7 14,023 798.7
------ ----- ------ ------- ------ -------
Total IPP purchases 13,520 1,106.5 13,797 1,088.5 14,023 979.9
Other 9,421 130.2 9,569 130.6 9,463 126.5
------ ------- ------ ------- ------ -------
22,941 1,236.7 23,366 1,219.1 23,486 1,106.4
------ ------- ------ ------- ------ -------
<PAGE>
<PAGE>
Total generated
and purchased 40,739 1,416.9 43,164 1,397.7 42,103 1,289.1
Fuel adjustment
clause - (1.3) - (33.3) - 14.8
Losses/Company use 3,603 - 4,037 - 4,419 -
------ ------- ------ -------- ------ --------
37,136 $1,415.6 39,127 $1,364.4 37,684 $1,303.9
====== ======= ====== ======== ====== ========
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
% Change from Prior Year
---------------------------------
1997 to 1996 1996 to 1995
------------ ------------
(In millions of dollars)
GWh Cost GWh Cost
------ ---- ------ ----
<S> <C> <C> <C> <C>
Fuel for electric
generation:
Coal 5.1% 5.8% 3.7% 2.8%
Oil 51.7 52.6 (14.0) (0.9)
Natural gas 23.5 (6.5) (68.0) (54.5)
Nuclear (23.1) (30.8) 13.4 10.2
Hydro (21.0) - 23.8 -
------ ------ ------ ------
(10.1) 0.9 6.3 (2.2)
------ ------ ------ ------
Electricity
purchased:
IPPs:
Capacity - 3.8 - 17.4
Energy and taxes (2.0) 1.1 (1.6) 9.6
----- ----- ----- -----
Total IPP purchases (2.0) 1.7 (1.6) 11.1
Other (1.5) (0.3) 1.1 3.2
----- ----- ----- -----
(1.8) 1.4 (0.5) 10.2
----- ------ ----- -----
<PAGE>
<PAGE>
Total generated
and purchased (5.6) 1.4 2.5 8.4
Fuel adjustment
clause - (96.1) - (325.0)
Losses/Company use (10.8) - (8.6) -
------- ------- ------ -------
(5.1)% 3.8% 3.8% 4.6%
======= ======= ====== =======
</TABLE>
<PAGE>
<PAGE>
The above table presents the total costs for purchased
electricity, while reflecting only fuel costs for Company
generation. Other costs of generation, such as taxes, other
operating expenses and depreciation are included within other
income statement line items.
The Company's management of its IPP power supply generally
divides the projects into three categories: hydroelectric, "must
run" cogeneration and schedulable cogeneration projects.
Following a higher than normal spring run off, the
precipitation in the summer months was lower than usual. As a
result, hydroelectric IPP projects delivered 242 GWh or 13.7% less
under PPAs than they did for the same period last year,
representing decreased payments to those IPPs of $15.7 million.
A substantial portion of the Company's portfolio of IPP
projects operate on a "must run" basis. This means that they tend
to run at maximum production levels regardless of the need for or
economic value of the electricity produced. Output from "must run"
cogeneration IPPs was 230 GWh or 2.6% lower than produced last
year, in part due to lower energy purchases from the Sithe
Independence plant. However, payments to those IPPs were $12.8
million higher. This was due to a combination of output turndown
arrangements with individual projects and escalating contract
rates. A turndown arrangement is an agreement where the Company
compensates an IPP to reduce the output from their facility.
Although output is reduced, the net economic impact is favorable to
the Company and its customers since the electricity is replaced
from the market or other lower cost sources.
Quantities purchased from schedulable cogeneration IPPs
increased 195 GWh or 6.3% and payments increased $20.9 million.
The increased payments are largely due to escalating contract rates
for capacity (fixed) and increased volumes of energy. The terms of
these PPAs allow the Company to schedule (with certain constraints)
energy deliveries and pay for the energy supplied. In addition,
the Company is required to make fixed payments if the IPP plants
remain available for service. (See Item 8. Financial Statements
and Supplementary Data - "Note 9. Commitments and Contingencies -
Long-term Contracts for the Purchase of Electric Power").
GAS REVENUES decreased by $24.7 million, or 3.6% in 1997, and
increased by $99.9 million, or 17.2%, in 1996. As shown in the
table below, gas revenues decreased in 1997 primarily due to
decreased sales to ultimate customers as a result of the migration
of commercial sales customers to the transportation class,
decreased spot market sales and a decrease in base rates of $5.9
million in accordance with the 1996 rate order. This was partially
offset by higher gas adjustment clause recoveries and an increase
in revenues from the transportation of customer-owned gas (see
"Other Federal and State Regulatory Initiatives -Generic Gas Rate
Proceeding").
Gas revenues increased in 1996 primarily due to increased
sales to ultimate customers due to colder weather, increased spot
market sales, higher gas adjustment clause recoveries, an increase
in revenues from the transportation of customer-owned gas and an
increase in base rates of $3.1 million in accordance with the 1995
rate order.
Rates for transported gas (excluding aggregation services)
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, particularly in
instances where customers that took direct service from the Company
move to a transportation-only class. In addition, changes in
purchased gas adjustment clause revenues are generally margin-
neutral.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
INCREASE (DECREASE) FROM PRIOR YEAR
(In millions of dollars)
GAS REVENUES 1997 1996 TOTAL
- ---------------------------------------------------------------
<S> <C> <C> <C>
Base rates $ (5.9) $ 3.1 $ (2.8)
Transportation of
customer-owned gas 5.3 2.1 7.4
Purchased gas adjustment
clause revenues 45.3 30.8 76.1
Spot market sales (30.8) 34.0 3.3
Changes in volume and
mix of sales to ultimate
consumers (38.6) 29.9 (8.8)
------- ------ ------
$(24.7) $ 99.9 $ 75.2
======= ====== =======
</TABLE>
GAS SALES, excluding transportation of customer-owned gas and
spot market sales, were 78.7 million Dth in 1997, a 7.3% decrease
from 1996, and a 0.3% increase from 1995. (See Item 8. Financial
Statements and Supplementary Data - "Electric and Gas Statistics -
Gas Statistics"). The decrease in 1997 was in all ultimate
consumer classes, in part due to the warmer weather. In addition,
spot market sales (sales for resale), which are generally from the
higher priced gas available to the Company and therefore yield
margins that are substantially lower than traditional sales to
ultimate customers, decreased 8.0 million Dth. This was partially
offset by an increase in transportation volumes of 18.1 million Dth
or 13.5% to customers purchasing gas directly from producers. The
Company has experienced an increase in customers of approximately
17,800 since 1995, primarily in the residential class, an increase
of 3.5%.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
Changes in gas revenues and Dth sales by customer group are
detailed in the table below:
% INCREASE (DECREASE) FROM PRIOR YEAR
1997 % OF -------------------------------------
GAS 1997 1996
CLASS OF SERVICE REVENUES REVENUES SALES REVENUES SALES
- ---------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Residential 66.4% 4.5% (2.7)% 13.3% 9.4%
Commercial 22.6 (8.7) (13.0) 13.0 6.4
Industrial 1.0 (50.9) (50.1) 15.6 4.1
- ---------------------------------------------------------------------
Total to ultimate
consumers 90.0 (0.3) (7.3) 13.3 8.3
Other gas
systems - (5.8) (6.7) (81.9) (81.4)
Transportation of
customer-owned
gas 8.5 10.5 13.5 4.3 (6.9)
Spot market sales 1.0 (82.9) (76.6) 1,099.1 507.0
Miscellaneous 0.5 263.1 - (82.2) -
- ---------------------------------------------------------------------
TOTAL 100.0% (3.6)% 1.7% 17.2% 2.3%
</TABLE>
<PAGE>
<PAGE>
The total cost of gas purchased decreased 6.6% in 1997 and
increased 34.0% in 1996. The cost fluctuations generally
correspond to sales volume changes, as spot market sales activity
decreased, as well as changes in gas prices. The Company sold 2.5,
10.5 and 1.7 million Dth on the spot market in 1997, 1996 and 1995,
respectively. The total cost of gas decreased $24.4 million in
1997. This was the result of a 5.3 million decrease in Dth
purchased and withdrawn from storage for ultimate consumer sales
($18.8 million) and a $22.5 million decrease in Dth purchased for
spot market sales, partially offset by a 3.3% increase in the
average cost per Dth purchased ($10.7 million) and a $6.3 million
increase in purchased gas costs and certain other items recognized
and recovered through the purchased gas adjustment clause.
The total cost of gas purchased increased $93.8 million in
1996. This was the result of a 9.3 million increase in Dth
purchased and withdrawn from storage for ultimate consumer sales
($29.6 million), a $25.6 million increase in Dth purchased for spot
market sales and a 12.9% increase in the average cost per Dth
purchased ($38.7 million). Gas purchased for spot market sales
decreased $22.5 million in 1997 and increased $25.6 million in
1996. The Company's net cost per Dth sold, as charged to expense
and excluding spot market purchases, increased to $3.82 in 1997
from $3.62 in 1996 and was $3.17 in 1995.
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. The Company absorbed losses
of approximately $11.8 million, $1.4 million and $13.1 million in
1995, 1996 and 1997, respectively. Under PowerChoice, the FAC will
be terminated. The Company does not believe that the elimination
of the FAC will have a material adverse effect on its financial
condition, as a result of its management of (1) power supplies
provided through: (i) the operation of its own power plants, and
future power purchase arrangements as part of the planned auction
of its fossil and hydro assets, (ii) fixed power purchases from
NYPA and remaining IPPs and (iii) fixed and indexed swap
arrangements with IPP Parties and (2) the transfer of the risk
associated with electricity commodity prices to the customer
through implementation of retail access included in the PowerChoice
agreement.
OTHER OPERATION AND MAINTENANCE EXPENSE decreased in 1997 by
$92.9 million, or 10.0%, as compared to an increase of $110.3
million or 13.5% in 1996. These changes in 1996 and 1997 each
result primarily from a change in 1996 in the Company's assessment
of uncollectible customer accounts, which gives greater recognition
to the increased risk of collecting past due customer bills,
resulting in increases in the Company's allowance for doubtful
accounts and a significantly higher expense recognition in 1996.
Bad debt expense was $31.2 million, $127.6 million and $46.5
million in 1995, 1996 and 1997, respectively. In 1997, write-offs
were $39.0 million and the Company incurred a $10.5 million
increase in allowance for doubtful accounts. The increase in the
allowance for doubtful accounts was attributable to increases in
the collection risk associated with residential accounts receivable
and arrears. The Company has implemented a number of collection
initiatives that are expected to result in lower arrears levels and
potentially lower the allowance for doubtful accounts. Other
operation and maintenance expense also decreased in 1997 as a
result of a reduction in administrative and general expenses of
$15.8 million, primarily due to a reduction in legal costs.
OTHER INCOME decreased by $10.9 million in 1997 and increased
by $32.9 million in 1996. Despite higher interest income ($12.0
million) related to increasing cash balances, "other income" was
lower in 1997, since 1996 reflected a gain on the sale of a 50%
interest in CNP ($15.0 million). The 1996 increase also reflected
higher interest income ($10.9 million) as a result of an increase
in temporary cash investments. In addition, "other income" was
higher in 1996 since there were customer service penalties and
certain other items written off because they were disallowed in
rates in 1995.
FEDERAL AND FOREIGN INCOME TAXES increased by $24.1 million
in 1997 primarily due to an increase in pre-tax income and
decreased by $56.9 million in 1996 primarily due to a decrease in
pre-tax income. Other taxes decreased by $4.4 million in 1997 and
decreased by $41.6 million in 1996. The 1997 decrease was
primarily due to lower payroll taxes ($2.3 million) and lower sales
taxes ($0.7 million). The 1996 decrease was primarily as a result
of lower real estate taxes ($15.4 million), lower GRTs ($6.1
million) primarily due to a reduction in the GRT surcharge during
1996, lower New York State excess dividend tax accrual due to a
suspension of the common stock dividend ($4.6 million) and year-to-
year differences in the accounting for regulatory deferrals ($15.2
million) associated primarily with a settlement of tax issues with
respect to the Company's Dunkirk facility.
INTEREST CHARGES remained fairly constant for the years 1995
through 1997. However, dividends on preferred stock decreased by
$0.9 million and $1.3 million in 1997 and 1996, respectively.
Dividends on preferred stock decreased in 1997 primarily due to a
reduction in preferred stock outstanding through sinking fund
redemptions and decreased in 1996 primarily due to a decrease in
the cost of variable rate issues. The weighted average long-term
debt interest rate and preferred dividend rate paid, reflecting the
actual cost of variable rate issues, changed to 7.81% and 7.04%,
respectively, in 1997 from 7.71% and 7.09%, respectively, in 1996
and from 7.77% and 7.19%, respectively, in 1995.
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, 1997 was 51.8% long-term debt, 7.7% preferred stock
and 40.5% common equity, as compared to 53.1%, 7.9% and 39.0%
respectively, at December 31, 1996. The culmination of the
termination, restatement or amendment of IPP contracts will
significantly increase the leverage of the Company to nearly 65% at
the time of closing. Through the anticipated increased operating
cash flow resulting from the MRA and PowerChoice agreement, the
planned rapid repayment of debt should deleverage the Company over
time. Book value of the common stock was $18.89 per share at
December 31, 1997, as compared to $17.91 per share at December 31,
1996. With the issuance of equity at below book value to the IPP
Parties as part of the MRA, book value per share will be diluted.
In addition, earnings per share will be diluted by the effect of
the issuance to the IPP Parties of approximately 42.9 million
shares of the Company's common stock.
The Company's EBITDA for 1997 was approximately $962 million,
and upon implementation of the MRA and PowerChoice is expected to
increase to approximately $1,200 million to $1,300 million per
year. EBITDA represents earnings before interest charges, interest
income, income taxes, depreciation and amortization, amortization
of nuclear fuel, allowance for funds used during construction,
non-cash regulatory deferrals and other amortizations and
extraordinary items. EBITDA is a non-GAAP measure of cash flows
and is presented to provide additional information about the
Company's ability to meet its future requirements for debt service
which would increase significantly upon consummation of the MRA.
EBITDA should not be considered an alternative to net income as an
indicator of operating performance or as an alternative to cash
flows, as presented on the Consolidated Statement of Cash Flows, as
a measure of liquidity.
The 1997 ratio of earnings to fixed charges was 2.02 times.
The ratios of earnings to fixed charges for 1996 and 1995 were 1.57
times and 2.29 times, respectively. The change in the ratio was
primarily due to changes in earnings during the period. Assuming
the MRA is implemented, the ratio of earnings to fixed charges will
substantially decrease in the future, since the MRA and PowerChoice
agreement will have the effect of substantially depressing earnings
during its five-year term, while at the same time substantially
improving operating cash flows. The primary objective of the MRA
is to convert a large and growing off-balance sheet payment
obligation that threatens the financial viability of the Company
into a fixed and manageable capital obligation.
COMMON STOCK DIVIDEND. The Board of Directors omitted the
common stock dividend beginning 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 and is the
primary reason for the increase in the cash balance. In making
future dividend decisions, the Board of Directors will evaluate,
along with standard business considerations, the financial
condition of the Company, the closing of the MRA and implementation
of PowerChoice, or the failure to implement such actions,
contractual restrictions that might be entered into in conjunction
with financing the MRA, the degree of competitive pressure on its
prices, the level of available cash flow and retained earnings and
other strategic considerations. The Company expects to dedicate a
substantial portion of its future expected positive cash flow to
reduce the leverage created in connection with the implementation
of the MRA. The PowerChoice agreement establishes limits to the
annual amount of common and preferred stock dividends that can be
paid by the regulated business. The limit is based upon the amount
of net income each year, plus a specified amount ranging from $50
million in 1998 to $100 million in 2000. The dividend limitation is
subject to review after the term of the PowerChoice agreement.
Furthermore, the Company forecasts that earnings for the five-year
term of the PowerChoice agreement will be substantially depressed,
as non-cash amortization of the MRA regulatory asset is occurring
and the interest costs on the IPP debt is the greatest. See
"Accounting Implications of the PowerChoice Agreement and Master
Restructuring Agreement."
CONSTRUCTION AND OTHER CAPITAL REQUIREMENTS. The Company's
total capital requirements consist of amounts for the Company's
construction program (see Item 8. Financial Statements and
Supplementary Data - "Note 9. Commitments and Contingencies -
Construction Program,"). The January 1998 ice storm damage
restoration costs may further add to these requirements (see Item
8. Financial Statements and Supplementary Data - "Note 13.
Subsequent Event"), nuclear decommissioning funding requirements
(See Item 8. Financial Statements and Supplementary Data - "Note 3.
Nuclear Operations - Nuclear Plant Decommissioning" and - "NRC
Policy Statement and Proposal"), working capital needs, maturing
debt issues and sinking fund provisions on preferred stock, as well
as requirements to complete the MRA and accomplish the
restructuring contemplated by the PowerChoice agreement. Annual
expenditures for the years 1995 to 1997 for construction and
nuclear fuel, including related AFC and overheads capitalized, were
$345.8 million, $352.1 million and $290.8 million, respectively,
and are budgeted to be approximately $358 million for 1998 and to
range from $279 - $352 million for each of the subsequent four
years. These estimates include construction expenditures for non-
nuclear generation of $20 million to $38 million per year.
In addition to the assumed cost of the MRA requirements, as
described below, mandatory debt and preferred stock retirements are
expected to add approximately another $77 million to the 1998
estimate of capital requirements. The estimate of construction
additions included in capital requirements for the period 1998 to
2002 will be reviewed by management to give effect to the storm
restoration costs and the overall objective of further reducing
construction spending 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.
Under the MRA, the Company will pay an aggregate of $3,616
million in cash. The Company expects to issue senior unsecured debt
to fund this requirement, which is expected to consist of both debt
issued through a public market offering and debt issues to banks
which would serve to replace its existing $804 million senior debt
facility, discussed below. The Company's preferred shareholders
gave the Company approval to increase the amount of unsecured debt
the Company may issue by $5 billion. Previously, the Company was
able to issue $700 million under the restrictions of its amended
Certificate of Incorporation. This authorization will enable the
issuance of unsecured debt to consummate the MRA. In addition, the
Company believes that the ability to use unsecured indebtedness
will increase its flexibility in planning and financing its
business activities.
LIQUIDITY AND CAPITAL RESOURCES. External financing plans
are subject to periodic revision as underlying assumptions are
changed to reflect developments, market conditions and, most
importantly, conclusion of the MRA and implementation of
PowerChoice. The ultimate level of financing during the period
1998 through 2002 will be affected by, among other things: the
timing and outcome of the MRA and the cash tax benefits anticipated
because the MRA is expected to result in a net operating loss for
1998 income tax purposes; the implementation of the PowerChoice
agreement, levels of common dividend payments, if any, and
preferred dividend payments; the results of the auction of the
Company's fossil and hydro assets; 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 effects of the ice storm that struck
a portion of the Company's service territory in early 1998. The
proceeds of the sale of the fossil and hydro assets will be subject
to the terms of the Company's mortgage indenture and the note
indenture that will be entered into in connection with the MRA debt
financing. The Company could also be affected by the outcome of
the NRC's consideration of new rules for adequate financial
assurance of nuclear decommissioning obligations. (See Item 8.
Notes to Consolidated Financial Statements - "Note 3. Nuclear
Operations - NRC Policy Statement and Proposal" and "Note 13.
Subsequent Event").
The Company has an $804 million senior debt facility with a
bank group, consisting of a $255 million term loan facility, a $125
million revolving credit facility and $424 million for letters of
credit. The letter of credit facility provides credit support for
the adjustable rate pollution control revenue bonds issued through
the NYSERDA. The interest rate applicable to the senior debt
facility is variable based on certain rate options available under
the agreement and currently approximates 7.7% (but is capped at
15%). As of December 31, 1997, the amount outstanding under the
senior debt facility was $529 million, consisting of $105 million
under the term loan facility and a $424 million letter of credit,
leaving the Company with $275 million of borrowing capability under
the facility. The facility expires on June 30, 1999 (subject to
earlier termination if the Company separates its fossil/hydro
generation business from its transmission and distribution
business, or any other significant restructuring plan). The
Company is currently negotiating with the lenders to replace the
senior debt facility with a larger facility to finance a portion of
the MRA.
This facility is collateralized by first mortgage bonds which
were issued on the basis of additional property under the earnings
test required under the mortgage trust indenture ("First Mortgage
Bonds"). As of December 31, 1997, the Company could issue an
additional $1,396 million aggregate principal amount of First
Mortgage Bonds under the Company's mortgage trust indenture. This
amount is based upon retired bonds without regard to an interest
coverage test. The Company is presently precluded from issuing
First Mortgage Bonds based on additional property.
Although no assurance can be provided, the Company believes
that the closing of the MRA and implementation of PowerChoice will
result in substantially depressed earnings during its five-year
term, but will substantially improve operating cash flows. There
is risk throughout the electric industry that credit ratings could
decline if the issue of stranded cost recovery is not
satisfactorily resolved. In the event the MRA is not closed, and
comparable solutions are not available, the Company will undertake
other actions necessary to act in the best interests of
stockholders and other constituencies.
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. This has not been the case in the last two years as the
Company's cash balance has increased, reflecting suspension of the
common stock dividend in 1996. 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. The
Company believes it has sufficient borrowing capacity to fund
deficits as necessary in the near term. However, the Company's
borrowing capacity to fund such deficits may be affected by the
factors discussed above relating to the Company's external
financial plans.
Since 1995, past-due accounts receivable have increased
significantly. A number of factors have contributed to the
increase, including rising prices (particularly to residential
customers). Rising prices have been driven by increased payments
to IPPs and high taxes and have been passed on in customers' bills.
The stagnant economy in the Company's service territory since the
early 1990's has adversely affected collection of past-due
accounts. Also, laws, regulations and regulatory policies impose
more stringent collection limitations on the Company than those
imposed on business in general; for example, the Company faces more
stringent requirements to terminate service during the winter
heating season. The increase in the allowance for doubtful
accounts was attributable to the reassessment of the collection
risk associated with residential accounts receivable and arrears.
The Company has implemented a number of collection initiatives that
are expected to result in lower arrears levels and potentially
lower the allowance for doubtful accounts. The Company has and
will continue to implement a variety of strategies to improve its
collection of past due accounts and reduce its bad debt expense.
The information gathered in developing these strategies
enabled management to update its risk assessment of the accounts
receivable portfolio. Based on this assessment, management
determined that the level of risk associated primarily with the
older accounts had increased and the historical loss experience no
longer applied. Accordingly, the Company determined that a
significant portion of the past-due accounts receivable
(principally of residential customers) might be uncollectible, and
had written-off a substantial number of these accounts as well as
increased its allowance for doubtful accounts in 1996. In 1997 and
1996, the Company charged $46.5 million and $127.6 million,
respectively to bad debt expense. The allowance for doubtful
accounts is based on assumptions and judgments as to the
effectiveness of collection efforts. Future results with respect
to collecting the past-due receivables may prove to be different
from those anticipated. Although the Company has experienced a
level of improvement in collection efforts, future results are
necessarily dependent upon the following factors, including, among
other things, the effectiveness of the strategies discussed above,
the support of regulators and legislators to allow utilities to
move towards commercial collection practices and improvement in the
condition of the economy in the Company's service territory. The
Company has been pursuing PowerChoice to address high prices that
are the result of traditional price regulation, but the
introduction of competition requires that policies and practices
that were central to traditional regulation, including those
involving collections, be changed so as not to jeopardize the
benefits of competition.
NET CASH PROVIDED BY OPERATING ACTIVITIES decreased $162.8
million in 1997 primarily due to a decrease of $105.9 million in
the amount of accounts receivable sold under the accounts
receivable sales program (which the Company has budgeted to restore
in 1998) partially offset by an increase in deferred taxes of $53.9
million.
NET CASH USED IN INVESTING ACTIVITIES increased $62.4 million
in 1997 primarily as a result of an increase in other cash
investments of $116.1 million offset by a decrease in the
acquisition of utility plant of $62.9 million.
NET CASH USED IN FINANCING ACTIVITIES decreased $106.1
million, primarily due to a net reduction of $94.7 million in the
payments on long-term debt.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
A. FINANCIAL STATEMENTS
Report of Management
Report of Independent Accountants
Consolidated Statements of Income and Retained Earnings for
each of the three years in the period ended December 31,
1997.
Consolidated Balance Sheets at December 31, 1997 and 1996.
Consolidated Statements of Cash Flows for each of the three
years in the period ended December 31, 1997.
Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
REPORT OF MANAGEMENT
The consolidated financial statements of the Company 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 (the "Code") that supply
employees with a framework describing and defining the Company's
overall approach to business and require 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 GAAP. In planning and performing its audit, Price
Waterhouse LLP 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 LLP to review and discuss internal accounting
controls, audit examinations and financial reporting matters.
Price Waterhouse LLP and the Company's internal auditors have free
access to meet individually with the Audit Committee at any time,
without management being present.
/s/ William E. Davis
William E. Davis
Chairman of the Board and
Chief Executive Officer
Niagara Mohawk Power Corporation
<PAGE>
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, 1997 and 1996, and the results of
their operations and their cash flows for each of the three years
in the period ended December 31, 1997, 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 15 to the accompanying financial statements,
the Company has restated its 1997 financial statements to eliminate
the $190 million charge related to the limitation on the
recoverability of the regulatory asset described in Note 2.
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") for its nuclear generation,
electric transmission and distribution and gas businesses. In the
event that the Company is unable to complete the termination,
restatement or amendment of independent power producer contracts
and implement PowerChoice, this conclusion could change in 1998 and
beyond, resulting in material adverse effects on the Company's
financial condition and results of operations.
As discussed in Note 2, the Company discontinued application of
SFAS No. 71 for its non-nuclear generation business in 1996.
/s/ Price Waterhouse LLP
Price Waterhouse LLP
Syracuse, New York
March 26, 1998, except Note 2 (third paragraph) and Note 15, as to
which the date is May 29, 1998
<PAGE>
<TABLE>
<CAPTION>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
In thousands of dollars
For the year ended
December 31, 1997 1996 1995
- -----------------------------------------------------------------
Operating revenues:
<S> <C> <C> <C>
Electric $3,309,441 $3,308,979 $3,335,548
Gas 656,963 681,674 581,790
- -----------------------------------------------------------------
3,966,404 3,990,653 3,917,338
- -----------------------------------------------------------------
Operating expenses:
Fuel for electric
generation 179,455 181,486 165,929
Electricity purchased 1,236,108 1,182,892 1,137,937
Gas purchased 345,610 370,040 276,232
Other operation and
maintenance expenses 835,282 928,224 817,897
Depreciation and
amortization (Note 1) 339,641 329,827 317,831
Other taxes 471,469 475,846 517,478
- -----------------------------------------------------------------
3,407,565 3,468,315 3,233,304
- -----------------------------------------------------------------
<PAGE>
<PAGE>
Operating income 558,839 522,338 684,034
- -----------------------------------------------------------------
Other income (Note 1) 24,997 35,943 3,069
- -----------------------------------------------------------------
Income before interest
charges 583,836 558,281 687,103
- -----------------------------------------------------------------
Interest charges (Note 1) 273,906 278,033 279,674
- -----------------------------------------------------------------
Income before federal and
foreign income taxes 309,930 280,248 407,429
Federal and foreign income
taxes (Note 7) 126,595 102,494 159,393
- -----------------------------------------------------------------
Income before extraordinary
item 183,335 177,754 248,036
Extraordinary item for the
discontinuance of regulatory
accounting principles, net of
income taxes of $36,273 in
1996 (Note 2) - (67,364) -
- -----------------------------------------------------------------
Net income (Note 15) 183,335 110,390 248,036
Dividends on preferred stock 37,397 38,281 39,596
- -----------------------------------------------------------------
Balance available for
common stock 145,938 72,109 208,440
Dividends on common stock - - 161,650
- -----------------------------------------------------------------
145,938 72,109 46,790
Retained earnings at
beginning of year 657,482 585,373 538,583
- -----------------------------------------------------------------
Retained earnings at
end of year $ 803,420 $ 657,482 $ 585,373
=================================================================
<PAGE>
<PAGE>
Average number of shares
of common stock outstanding
(in thousands) 144,404 144,350 144,329
Basic and diluted earnings
per average share of common
stock before extraordinary
item $ 1.01 $ 0.97 $ 1.44
Extraordinary item $ - $ (0.47) $ -
- -----------------------------------------------------------------
Basic and diluted earnings
per average share of
common stock $ 1.01 $ 0.50 $ 1.44
Dividends on common stock
paid per share $ - $ - $ 1.12
=================================================================
() Denotes deduction
The accompanying notes are an integral part of these financial
statements
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
CONSOLIDATED BALANCE SHEETS
In thousands of dollars
At December 31, 1997 1996
- ---------------------------------------------------------
ASSETS
Utility plant (Note 1):
<S> <C> <C>
Electric plant $ 8,752,865 $ 8,611,419
Nuclear Fuel 577,409 573,041
Gas plant 1,131,541 1,082,298
Common plant 319,409 292,591
Construction work in progress 294,650 279,992
- ---------------------------------------------------------
Total utility plant 11,075,874 10,839,341
Less: Accumulated
depreciation and
amortization 4,207,830 3,881,726
- ---------------------------------------------------------
Net utility plant 6,868,044 6,957,615
- ---------------------------------------------------------
Other property and
investments 371,709 257,145
- ---------------------------------------------------------
Current assets:
Cash, including temporary
cash investments of $315,708
and $223,829, respectively 378,232 325,398
Accounts receivable (less
allowance for doubtful accounts
of $62,500 and $52,100,
respectively) (Notes 1 and 9) 492,244 373,305
<PAGE>
<PAGE>
Materials and supplies, at
average cost:
Coal and oil for production
of electricity 27,642 20,788
Gas storage 39,447 43,431
Other 118,308 120,914
Prepaid taxes 15,518 11,976
Other 20,309 25,329
- ---------------------------------------------------------
1,091,700 921,141
- ---------------------------------------------------------
Regulatory assets (Note 2):
Regulatory tax asset 399,119 416,599
Deferred finance charges 239,880 239,880
Deferred environmental
restoration costs (Note 9) 220,000 225,000
Unamortized debt expense 57,312 65,993
Postretirement benefits other
than pensions 56,464 60,482
Other 204,049 206,352
- ---------------------------------------------------------
1,176,824 1,214,306
- ---------------------------------------------------------
Other assets 75,864 77,428
- ---------------------------------------------------------
$9,584,141 $9,427,635
=========================================================
The accompanying notes are an integral part of these financial
statements
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
CONSOLIDATED BALANCE SHEETS
In thousands of dollars
At December 31, 1997 1996
- ---------------------------------------------------------
CAPITALIZATION AND LIABILITIES
Capitalization (Note 5):
Common stockholders' equity:
<S> <C> <C>
Common stock, issued
144,419,351 and 144,365,214
shares, respectively $ 144,419 $ 144,365
Capital stock premium
and expense 1,779,688 1,783,725
Retained earnings 803,420 657,482
- ---------------------------------------------------------
2,727,527 2,585,572
Non-redeemable preferred stock 440,000 440,000
Mandatorily redeemable
preferred stock 76,610 86,730
Long-term debt 3,417,381 3,477,879
- ---------------------------------------------------------
Total capitalization 6,661,518 6,590,181
- ---------------------------------------------------------
<PAGE>
<PAGE>
Current liabilities:
Long-term debt due within
one year (Note 5) 67,095 48,084
Sinking fund requirements on
redeemable preferred stock
(Note 5) 10,120 8,870
Accounts payable 263,095 271,830
Payable on outstanding bank
checks 23,720 32,008
Customers' deposits 18,372 15,505
Accrued taxes 9,005 4,216
Accrued interest 62,643 63,252
Accrued vacation pay 36,532 36,436
Other 64,756 52,455
- ---------------------------------------------------------
555,338 532,656
- ---------------------------------------------------------
<PAGE>
<PAGE>
Regulatory liabilities (Note 2):
Deferred finance charges 239,880 239,880
- ---------------------------------------------------------
Other liabilities:
Accumulated deferred income
taxes (Notes 1 and 7) 1,387,032 1,357,518
Employee pension and other
benefits (Note 8) 240,211 238,688
Deferred pension settlement
gain 12,438 19,269
Unbilled revenues (Note 1) 43,281 49,881
Other 224,443 174,562
- ---------------------------------------------------------
1,907,405 1,839,918
- ---------------------------------------------------------
Commitments and contingencies (Notes 2 and 9):
Liability for environmental
restoration 220,000 225,000
- ---------------------------------------------------------
$9,584,141 $9,427,635
=========================================================
The accompanying notes are an integral part of these financial
statements
</TABLE>
<PAGE>
<PAGE>
<TABLE>
(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, 1997 1996 1995
- -----------------------------------------------------------------
Cash flows from operating activities:
<S> <C> <C> <C>
Net income $ 183,335 $ 110,390 $ 248,036
Adjustments to reconcile
net income to net cash
provided by operating
activities:
Extraordinary item for the
discontinuance of regulatory
accounting principles, net of
income taxes - 67,364 -
Depreciation and amortization 339,641 329,827 317,831
Electric margin recoverable - - 58,588
Amortization of nuclear fuel 25,241 38,077 34,295
Provision for deferred income
taxes 46,994 (6,870) 114,917
Gain on sale of subsidiary - (15,025) (11,257)
Unbilled revenues (6,600) 21,471 (71,258)
Net accounts receivable (118,939) 121,198 56,748
Materials and supplies (1,306) 2,265 13,663
Accounts payable and accrued
expenses (11,175) 8,224 (47,048)
Accrued interest and taxes 4,180 (11,750) (35,440)
Changes in other assets and
liabilities 76,204 35,231 20,930
- -----------------------------------------------------------------
Net cash provided by
operating activities 537,575 700,402 700,005
- -----------------------------------------------------------------
<PAGE>
<PAGE>
Cash flows from investing activities:
Construction additions (286,389) (296,689) (332,443)
Nuclear fuel (4,368) (55,360) (13,361)
Less: Allowance for other
funds used during construction 5,310 3,665 1,063
- -----------------------------------------------------------------
Acquisition of utility plant (285,447) (348,384) (344,741)
Decrease in materials and
Materials and supplies related
ton construction 1,042 8,362 3,346
Accounts payable and accrued
expenses related to
construction (2,794) 2,056 (7,112)
Other investments (115,533) 541 (115,818)
Proceeds from sale of sub-
sidiary (net of cash sold) - 14,600 161,087
Other 8,761 (8,786) 26,234
- -----------------------------------------------------------------
Net cash used in investing
activities (393,971) (331,611) (277,004)
- -----------------------------------------------------------------
Cash flows from financing activities:
Proceeds from long-term debt - 105,000 346,000
Redemption of preferred stock (8,870) (10,400) (10,950)
Reductions of long-term debt (44,600) (244,341) (73,415)
Net change in short-term debt - - (416,750)
Dividends paid (37,397) (38,281) (201,246)
Other 97 (8,846) (7,495)
- -----------------------------------------------------------------
Net cash used in financing
activities (90,770) (196,868) (363,856)
- -----------------------------------------------------------------
Net increase in cash 52,834 171,923 59,145
Cash at beginning of year 325,398 153,475 94,330
- -----------------------------------------------------------------
Cash at end of year $ 378,232 $ 325,398 $ 153,475
=================================================================
<PAGE>
<PAGE>
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest $ 279,957 $ 286,497 $ 290,352
Income taxes $ 82,331 $ 95,632 $ 47,378
=================================================================
The accompanying notes are an integral part of these financial
statements
</TABLE>
<PAGE>
<PAGE>
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 GAAP, including the accounting
principles for rate-regulated entities with respect to the
Company's nuclear, transmission, distribution and gas operations
(regulated business), and are in accordance with the accounting
requirements and ratemaking practices of the regulatory
authorities. The Company discontinued the application of
regulatory accounting principles to its fossil and hydro generation
operations in 1996 (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
replacements of retirement units of property are 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. The
discontinuation of SFAS No. 71 did not affect the carrying value of
the Company's utility plant.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION: The Company
capitalizes AFC in amounts equivalent to the cost of funds devoted
to plant under construction for its regulated business. AFC rates
are determined in accordance with FERC and PSC regulations. The
AFC rate in effect during 1997 was 9.28%. AFC is segregated into
its two components, borrowed funds and other funds, and is
reflected in the "Interest charges" and the "Other income"
sections, respectively, of the Consolidated Statements of Income.
The amount of AFC credits recorded in each of the three years ended
December 31, in thousands of dollars, was as follows:
1997 1996 1995
---- ---- ----
Other income $5,310 $3,665 $1,063
Interest charges 4,396 3,690 7,987
As a result of the discontinued application of SFAS No. 71 to
the fossil and hydro operations, the Company capitalizes interest
cost associated with the construction of fossil/hydro assets.
DEPRECIATION, AMORTIZATION AND NUCLEAR GENERATING PLANT
DECOMMISSIONING COSTS: For accounting and regulatory purposes,
depreciation is computed on the straight-line basis using the
license 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 approximately 3%
for the years 1995 through 1997. The Company performs depreciation
studies to determine service lives of classes of property and
adjusts the depreciation 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 the Units components promptly at
that time. See Note 3 - "Nuclear Plant Decommissioning."
The FASB issued an exposure draft in February 1996 entitled
"Accounting for Certain Liabilities Related to Closure or Removal
Costs of Long-Lived Assets." The scope of the project includes
certain plant decommissioning costs, including those for fossil,
hydro and nuclear plants. If approved, a liability would be
recognized, with a corresponding plant asset, whenever a legal or
constructive obligation exists to perform dismantlement or removal
activities. The Company currently recognizes the liability for
nuclear decommissioning over the service life of the plant as an
increase to accumulated depreciation and does not recognize the
closure or removal obligation associated with its fossil and hydro
plants. The Company's PowerChoice agreement provides for the
recovery of nuclear decommissioning costs. As discussed in Note 2,
the Company intends to sell its fossil and hydro generating assets
through an auction process. To the extent the assets are sold, the
effect of this exposure draft on the Company should be mitigated.
However, the Company cannot predict the results of the auction.
The adoption of the proposed standard is not expected to impact the
cash flow from these assets. The FASB continues to discuss the
issues addressed in the exposure draft, as well as the timing of
its implementation.
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 KWh of net generation available for sale, is
based upon a contract with the DOE. 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 for energy consumed
and not billed at the end of the fiscal year. At December 31, 1997
and 1996, approximately $8.6 million and $11.1 million,
respectively, of unbilled electric revenues remained unrecognized
in results of operations, are included in "Other liabilities."
Under the Company's PowerChoice agreement, the amount of
unrecognized electric unbilled revenue as of the PowerChoice
implementation date will be netted against certain other regulatory
assets and liabilities. Thereafter, changes in electric unbilled
revenues will no longer be deferred. In 1995, the Company used
$71.5 million of electric unbilled revenues to reduce the 1995
revenue requirement. At December 31, 1997 and 1996, $34.7 million
and $38.8 million, respectively, of unbilled gas revenues remain
unrecognized in results of operations and may be used to reduce
future gas revenue requirements. The unbilled revenues included in
accounts receivable at December 31, 1997 and 1996, were $211.9
million and $218.5 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 1995
through 1997 were not material. Under the PowerChoice agreement,
the FAC will be discontinued.
In December 1996, the Company, Multiple Intervenors and the
PSC staff reached a three year gas settlement that was
conditionally approved by the PSC. The agreement eliminated the
gas adjustment clause and established a gas commodity cost
adjustment clause ("CCAC"). The Company's gas CCAC provides for
the collection or passback of certain increases or decreases from
the base commodity cost of gas. The maximum annual risk or benefit
to the Company is $2.25 million. All savings and excess costs
beyond that amount will flow to ratepayers. For a discussion of
the ratemaking associated with non-commodity gas costs, see Item 7.
Management's Discussion and Analysis of Financial Condition and
Results of Operations - "Other Federal and State Regulatory
Initiatives - Multi-Year Gas Rate Settlement Agreement."
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 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.
EARNINGS PER SHARE: Basic earnings per share ("EPS") is
computed based on the weighted average number of common shares
outstanding for the period. The number of options outstanding at
December 31, 1997, 1996 and 1995 that could potentially dilute
basic EPS, (but are considered antidilutive for each period because
the options exercise price was greater than the average market
price of common shares), is immaterial. Therefore, the calculation
of both basic and dilutive EPS are the same for each period.
RECLASSIFICATIONS: Certain amounts from prior years have
been reclassified on the accompanying Consolidated Financial
Statements to conform with the 1997 presentation.
COMPREHENSIVE INCOME: In June 1997, FASB issued SFAS No.
130. SFAS No. 130 establishes standards for reporting comprehensive
income. Comprehensive income is the change in the equity of a
company, not including those changes that result from shareholder
transactions. All components of comprehensive income are required
to be reported in a new financial statement that is displayed with
equal prominence as existing financial statements. The Company
will be required to adopt SFAS No. 130 on January 1, 1998. The
Company does not expect that adoption of SFAS No. 130 will have a
significant impact on its reporting and disclosure requirements.
SEGMENT DISCLOSURES: Also in June 1997, FASB issued SFAS No.
131. SFAS No. 131 establishes standards for additional disclosure
about operating segments for interim and annual financial
statements. More specifically, it requires financial information
to be disclosed for segments whose operating results are reviewed
by the chief operating officer for decisions on resource
allocation. It also requires related disclosures about product and
services, geographic areas and major customers. The Company will
be required to adopt SFAS No. 131 for the fiscal year ending
December 31, 1998. The Company does not expect that the adoption
of SFAS No. 131 will have a significant impact on its reporting and
disclosure requirements.
PENSION AND OTHER POSTRETIREMENT BENEFITS: In February 1998,
FASB issued SFAS No. 132. SFAS No. 132 revises employers'
disclosures about pension and other postretirement benefit plans.
It does not change the measurement or recognition of those plans.
It standardizes the disclosure requirements for pensions and other
postretirement benefits to the extent practicable and requires
additional information on changes in the benefit obligations and
fair values of plan assets. The Company will be required to adopt
SFAS No. 132 for the fiscal year ending December 31, 1998. The
Company does not expect the adoption of SFAS No. 132 will have a
significant impact on its reporting and disclosure requirements.
NOTE 2. RATE AND REGULATORY ISSUES AND CONTINGENCIES
The Company's financial statements conform to GAAP, including
the accounting principles for rate-regulated entities with respect
to its regulated operations. Substantively, these principles
permit a public utility, regulated on a cost-of-service basis, to
defer certain costs which would otherwise be charged to expense,
when authorized to do so by the regulator. These deferred costs
are known as regulatory assets, which in the case of the Company
are approximately $937 million, net of approximately $240 million
of regulatory liabilities at December 31, 1997. These regulatory
assets are probable of recovery. The portion of the $937 million
which has been allocated to the nuclear generation and electric
transmission and distribution business is approximately $810
million, which is net of approximately $240 million of regulatory
liabilities. Regulatory assets allocated to the rate-regulated gas
distribution business are $127 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 are consistent
with those used in prior regulatory proceedings.
The Company concluded as of December 31, 1996 that the
termination, restatement or amendment of IPP contracts and
implementation of PowerChoice was the probable outcome of
negotiations that had taken place since the PowerChoice
announcement. Under PowerChoice, the separated non-nuclear
generation business would no longer be rate-regulated on a cost-of-
service basis and, accordingly, regulatory assets related to the
non-nuclear power generation business, amounting to approximately
$103.6 million ($67.4 million after tax or 47 cents per share) was
charged against 1996 income as an extraordinary non-cash charge.
The PSC in its written order issued March 20, 1998 approving
PowerChoice, determined to limit the estimated value of the MRA
regulatory asset that can be recovered from customers to
approximately $4,000 million. The ultimate amount of the
regulatory asset to be established may vary based on certain events
related to the closing of the MRA. The estimated value of the MRA
regulatory asset includes the issuance of 42.9 million shares of
common stock, which the PSC in determining the recoverable amount
of such asset, valued at $8 per share. Because the value of the
consideration to be paid to the IPP Parties can only be determined
at the MRA closing, the value of the limitation on the
recoverability of the MRA regulatory asset is expected to be
recorded as a charge to expense in the second quarter of 1998 upon
the closing of the MRA. The charge to expense will be determined
as the difference between $8 per share and the Company's closing
common stock price on the date the MRA closes, multiplied by 42.9
million shares. Using the Company's common stock price on March
26, 1998 of $12 7/16 per share, the charge to expense would be
approximately $190 million (85 cents per share).
Under PowerChoice, the Company's remaining electric business
(nuclear generation and electric transmission and distribution
business) will continue to be rate-regulated on a cost-of-service
basis and, accordingly, the Company continues to apply SFAS No. 71
to these businesses. Also, the Company's IPP contracts, including
those restructured under the MRA and those not so restructured will
continue to be the obligations of the regulated business.
The EITF of the FASB reached a consensus on Issue No. 97-4
"Deregulation of the Pricing of Electricity - Issues Related to the
Application of SFAS No. 71 and SFAS No. 101" in July 1997. As
discussed previously, the Company discontinued the application of
SFAS No. 71 and applied SFAS No. 101 with respect to the fossil and
hydro generation business at December 31, 1996, in a manner
consistent with the EITF consensus.
In addition, EITF 97-4 does not require the Company to earn
a return on regulatory assets that arise from a deregulating
transition plan in assessing the applicability of SFAS No. 71. In
the event the MRA and PowerChoice are implemented, the Company
believes that the regulated cash flows to be derived from prices it
will charge for electric service over 10 years, including the CTC,
assuming no unforeseen reduction in demand or bypass of the CTC or
exit fees, will be sufficient to recover the MRA regulatory asset
and to provide recovery of and a return on the remainder of its
assets, as appropriate. In the event the Company could no longer
apply SFAS No. 71 in the future, it would be required to record an
after-tax non-cash charge against income for any remaining
unamortized regulatory assets and liabilities. Depending on when
SFAS No. 71 was required to be discontinued, such charge would
likely be material to the Company's reported financial condition
and results of operations and the Company's ability to pay
dividends. The PowerChoice agreement, while having the effect of
substantially depressing earnings during its five-year term, will
substantially improve operating cash flows.
With the implementation of PowerChoice, specifically the
separation of non-nuclear generation as an entity that would no
longer be cost-of-service regulated, the Company is required to
assess the carrying amounts of its long-lived assets in accordance
with SFAS No. 121. SFAS No. 121 requires long-lived assets and
certain identifiable intangibles held and used by an entity to be
reviewed for impairment whenever events or changes in circumstances
indicate that the carrying amount of an asset may not be
recoverable or when assets are to be disposed of. 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/or its disposition. The Company has determined that
there is no impairment of its fossil and hydro generating assets.
To the extent the proceeds resulting from the sale of the fossil
and hydro assets are not sufficient to avoid a loss, the Company
would be able to recover such loss through the CTC. The
PowerChoice agreement provides for deferral and future recovery of
losses, if any, resulting from the sale of the non-nuclear
generating assets. The Company believes that it will be permitted
to record a regulatory asset for any such loss in accordance with
EITF 97-4. The Company's fossil and hydro generation plant assets
had a net book value of approximately $1.1 billion at December 31,
1997.
As described in Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations - "Master
Restructuring Agreement and the PowerChoice Agreement," the
conclusion of the termination, restatement or amendment of IPP
contracts, and closing of the financing necessary to implement such
termination, restatement or amendment, as well as implementation of
PowerChoice, is subject to a number of contingencies. In the event
the Company is unable to successfully bring these events to
conclusion, it is likely that application of SFAS No. 71 would be
discontinued. The resulting non-cash after-tax charges against
income, based on regulatory assets and liabilities associated with
the nuclear generation and electric transmission and distribution
businesses as of December 31, 1997, would be approximately $526.5
million or $3.65 per share. Various requirements under applicable
law and regulations and under corporate instruments, including
those with respect to issuance of debt and equity securities,
payment of common and preferred dividends and certain types of
transfers of assets could be adversely impacted by any such write-
downs.
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 SFAS No. 109 on a revenue-
neutral basis.
DEFERRED FINANCE CHARGES represent the deferral of the
discontinued portion of AFC related to 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. PowerChoice provides for netting,
and thereby elimination of the debit and credit balances of
deferred finance charges.
DEFERRED ENVIRONMENTAL RESTORATION COSTS represent the
Company's share of the estimated costs to investigate and perform
certain remediation activities at both Company-owned sites and non-
owned sites with which it may be associated. The Company has
recorded a regulatory asset representing the remediation
obligations to be recovered from ratepayers. PowerChoice and the
Company's gas settlement provide for the recovery of these costs
over the settlement periods. The Company believes future costs,
beyond the settlement periods, will continue to be recovered in
rates. 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 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.
Substantially all of the Company's regulatory assets
described above are being amortized to expense and recovered in
rates over periods approved in the Company's electric and gas rate
cases, respectively.
<PAGE>
<PAGE>
NOTE 3. NUCLEAR OPERATIONS
NUCLEAR PLANT DECOMMISSIONING: The Company's site specific
cost estimates for decommissioning Unit 1 and its ownership
interest in Unit 2 at December 31, 1997 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 January 1998 dollars) In millions of dollars
Radioactive Components $481 $201
Non-radioactive Components 117 48
Fuel Dry Storage/Continuing
Care 78 43
---- ----
$676 $292
==== ====
The Company estimates that by the time decommissioning is
completed, the above costs will ultimately amount to $1.7 billion
and $.9 billion for Unit 1 and Unit 2, respectively, using
approximately 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 1998 dollars, these costs are expected to
amount to $119 million and $63 million for Unit 1 and the Company's
share of Unit 2, respectively. The amounts will escalate to $210
million and $190 million for Unit 1 and the Company's share of Unit
2, respectively, by the time decommissioning is completed. In
1997, the Company made adjustments to the cash flow assumptions at
Unit 1 for fuel dry storage, radioactive cost components, property
tax and insurance, to more accurately reflect the estimated cost of
each cost component. The revisions reduced the total cost estimate
by approximately $10 million (in 1998 dollars).
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 was approximately $23.7 million, for
each of the three years ended December 31, 1997. The amount was
based upon the 1993 NRC minimum decommissioning cost requirements
of $437 million and $198 million (in 1998 dollars) for Unit 1 and
the Company's share of Unit 2, respectively. In Opinion No. 95-21,
the Company was authorized, until the PSC orders otherwise, to
continue to fund to the NRC minimum requirements. PowerChoice
permits rate recovery for all radioactive and non-radioactive cost
components for both units, including post-shutdown costs, based
upon the amounts estimated in the 1995 site specific studies
described above, which are higher than the NRC minimum. 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.
Decommissioning costs recovered in rates are reflected in
"Accumulated depreciation and amortization" on the balance sheet
and amount to $266.8 million and $217.7 million at December 31,
1997 and 1996, respectively for both units. Additionally at
December 31, 1997, the fair value of funds accumulated in the
Company's external trusts were $164.7 million for Unit 1 and $51.0
million for its share of Unit 2. The trusts are included in "Other
property and investments." Earnings on the external trust
aggregated $40.3 million through December 31, 1997 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 $45.2
million at December 31, 1997.
NRC POLICY STATEMENT AND PROPOSAL. The NRC issued a policy
statement on the Restructuring and Economic Deregulation of the
Electric Utility Industry (the "Policy Statement") in 1997. The
Policy Statement addresses the NRC's concerns about the adequacy of
decommissioning funds and about the potential impact on operational
safety. Current NRC regulations allow a utility to set aside
decommissioning funds annually over the estimated life of a plant.
The Policy Statement declares the NRC will:
- - Continue to conduct reviews of financial qualifications,
decommissioning funding and antitrust requirements of nuclear
power plants;
- - Establish and maintain working relationships with state and
federal rate regulators;
- - Identify all nuclear power plant owners, indirect as well as
direct; and
- - Re-evaluate the adequacy of current regulations in light of
economic and other changes resulting from rate deregulation.
In addition to the above Policy Statement, the NRC is proposing to
amend its regulations on decommissioning funding to reflect
conditions expected from deregulation of the electric power
industry. The amended rule would:
- - Revise the definition of an "electric utility" to reflect
changes caused by restructuring within the industry.
- - Define a "Federal licensee" as any licensee which has the
full faith and credit backing of the United States
government. Only such licensees could use statements of
intent to meet decommissioning financial assurance
requirements for power reactors.
- - Require nuclear power plant licensees to report to the NRC on
the status of their decommissioning funds at least once every
three years and annually within five years of the planned end
of operation. NRC's present rule contains no such
requirement because State and Federal rate-regulating bodies
actively monitor these funds. A deregulated nuclear utility
would have no such monitoring.
- - Permit nuclear licensees to take credit on earnings for
prepaid decommissioning trust funds and external sinking
funds from the time the funds are set aside through the end
of the decommissioning period. The present rule does not
permit such credit because it assumed that inflation and
taxes would erode any investment return. NRC has decided,
however, that this position is not borne out by historical
performance of inflation-adjusted funds invested in U.S.
Treasury instruments.
The Company is unable to predict the outcome of this matter.
PSC STAFF'S TENTATIVE CONCLUSIONS ON THE FUTURE OF NUCLEAR
GENERATION: On August 27, 1997, the PSC requested comments on its
staff's tentative conclusions about how nuclear generation and
fossil generation should be treated after decisions are made on the
individual electric restructuring agreements currently pending
before the PSC. The PSC staff concluded that beyond the transition
period (the period covered by the various New York utility
restructuring agreements, including PowerChoice), nuclear
generation should operate on a competitive basis. In addition, the
PSC staff concluded that a sale of generation plants to third
parties is the preferred means of determining the fair market value
of generation plants and offers the greatest potential for the
mitigation of stranded costs. The PSC staff also concluded that
recovery of sunk costs, including post shutdown costs, would be
subject to review by the PSC and this process should take into
account mitigation measures taken by the utility, including the
steps it has taken to encourage competition in its service area.
In October 1997, the majority of utilities with interests in
nuclear power plants, including the Company, requested that the PSC
reconsider its staff's nuclear proposal. In addition, the utilities
raised the following issues: impediments to nuclear plants
operating in a competitive mode; impediments to the sale of plants;
responsibility for decommissioning and disposal of spent fuel;
safety and health concerns; and environmental and fuel diversity
benefits. In light of all of these issues, the utilities
recommended that a more formal process be developed to address
those issues.
The three investor-owned utilities, Rochester Gas and
Electric Corporation, Consolidated Edison Company of New York, Inc.
and the Company, which are currently pursuing formation of a
nuclear operating company in New York State, also filed a response
with the PSC in October 1997. The response stated that a forced
divestiture of the nuclear plants would add uncertainty to
developing a statewide approach to operating the plants and
requested that such a forced divestiture proposal be rescinded.
The response also stated that implementation of a consolidated
six-unit operation would contribute to the mitigation of
unrecovered nuclear costs. NYPA, which is also pursuing formation
of the nuclear operating company, submitted its own comments which
were similar to the comments of the three utilities.
PowerChoice contemplates that the Company's nuclear plants
will remain part of the Company's regulated business and that the
Company will continue efforts to pursue a statewide solution such
as the New York Nuclear Operating Company. The settlement
stipulates that absent a statewide solution, the Company will file
a detailed plan for analyzing proposed solutions for its nuclear
assets, including the feasibility of an auction, transfer and/or
divestiture within 24 months of PowerChoice approval. At December
31, 1997, the net book value of the Company's nuclear assets was
approximately $1.5 billion, excluding the reserve for
decommissioning.
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.
With respect to a nuclear incident at a licensed reactor, the
statutory limit for the protection of the public under the Price-
Anderson Amendments Act of 1988 which is in excess of the $200
million of nuclear liability insurance, is currently $8.2 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. With the 5%
surcharge included, the statutory limit is $8.6 billion.
The Company's interest in Units 1 and 2 could expose it to a
maximum potential loss, for each accident, of $111.8 million (with
5% assessment) 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 $2.25
billion 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 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 $11.3 million per loss.
LOW LEVEL RADIOACTIVE WASTE: The Company currently uses the
Barnwell, South Carolina waste disposal facility for low level
radioactive waste; however, continued access to Barnwell is not
assured and the Company 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.
Under the Federal Low Level Waste Policy Amendment Act of
1985, New York State was required by January 1, 1993 to have
arranged for the disposal of all low level radioactive waste within
the state or in the alternative, contracted for the disposal at a
facility outside the state. To date, New York State has made no
funding available to support siting for a disposal facility.
NUCLEAR FUEL DISPOSAL COST: In January 1983, the Nuclear
Waste Policy Act of 1982 (the "Nuclear Waste Act") established a
cost of $.001 per KWh of net generation for current disposal of
nuclear fuel and provides for a determination of the Company's
liability to the 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. As of December 31, 1997, the Company has
recorded a liability of $114.3 million for the disposal of nuclear
fuel irradiated prior to 1983. 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.
However, in July 1996, the United States Circuit Court of Appeals
for the District of Columbia ruled that the DOE must begin
accepting spent fuel from the nuclear industry by January 31, 1998
even though a permanent storage site will not be ready by then. The
DOE did not appeal this decision. On January 31, 1997, the Company
joined a number of other utilities, states, state agencies and
regulatory commissions in filing a suit in the U.S. Court of
Appeals for the District of Columbia against the DOE. The suit
requested the court to suspend the utilities payments into the
Nuclear Waste Fund and to place future payments into an escrow
account until the DOE fulfills its obligation to accept spent fuel.
On June 3, 1997, the DOE notified utilities that it likely will not
meet its January 31, 1998 deadline and that the delay was
unavoidable pursuant to the terms of the standard contract with DOE
for fuel disposal. DOE also indicated it was not obligated to
provide a financial remedy for such unavoidable delay. On November
14, 1997 the United States Court of Appeals for the District of
Columbia Circuit issued a writ of mandamus precluding DOE from
excusing its own delay on the grounds that it has not yet prepared
a permanent repository or interim storage facility. On December
11, 1997, 27 utilities, including the Company, petitioned the DOE
to suspend their future payments to the Nuclear Waste Fund until
the DOE begins moving fuel from their plant sites. The petition
further sought permission to escrow payments to the waste fund
beginning in February 1998. On January 12, 1998, the DOE denied
the petition. The Company is unable to determine the final outcome
of this matter.
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.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
NOTE 4. JOINTLY-OWNED GENERATING FACILITIES
The following table reflects the Company's share of jointly-owned generating facilities
at December 31, 1997. 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.
Under PowerChoice, the Company will divest all of its fossil and hydro generation assets with
a net book value of $1.1 billion, including its interests in jointly-owned facilities.
In thousands of dollars
-----------------------------------------------
Percent Utility Accumulated Construction
Ownership Plant Depreciation Work in Progress
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Roseton Steam Station
Units No. 1 and 2 (a) 25 $ 96,110 $ 54,130 $ 432
Oswego Steam Station
Unit No. 6 (b) 76 $ 270,316 $125,089 $ 39
Nine Mile Point Nuclear
Station Unit No. 2 (c) 41 $1,507,721 $327,006 $6,748
- ------------------------------------------------------------------------------------------
(a) The remaining ownership interests are Central Hudson Gas and Electric Corporation
("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 Rochester Gas and
Electric ("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 Long Island
Lighting Company ("LILCO") (18%), New York State Electric & Gas Corporation ("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. In June 1997, LILCO and Long Island Power Authority ("LIPA")
entered into an agreement, whereby, upon completion of certain transactions, LILCO's
stock would be sold to LIPA. It is anticipated that LIPA would own LILCO's 18%
ownership interest in Unit 2. In July 1997, the New York State Public Authorities
Control Board unanimously approved the agreements related to the LIPA transaction,
subject to certain conditions, and LILCO's stockholders subsequently approved this
transaction.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
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 1995, 1996 and
1997:
COMMON STOCK
$1 PAR VALUE
--------------------------
SHARES AMOUNT*
- --------------------------------------------------------
<S> <C> <C>
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
Issued 33,091 33
Redemptions
Foreign currency
translation adjustment
- --------------------------------------------------------
<PAGE>
December 31, 1996: 144,365,214 144,365
Issued 54,137 54
Redemptions
Foreign currency
translation adjustment
- --------------------------------------------------------
December 31, 1997: 144,419,351 $144,419
========================================================
* In thousands of dollars
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
PREFERRED STOCK
$100 PAR VALUE
---------------------------------------
SHARES NON-REDEEMABLE* REDEEMABLE*
- --------------------------------------------------------------
<S> <C> <C> <C>
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)
Issued - - -
Redemptions (18,000) - (1,800)
Foreign currency
translation adjustment
- --------------------------------------------------------------
December 31, 1996: 2,340,000 $210,000 $24,000 (a)
Issued - - -
Redemptions (18,000) - (1,800)
Foreign currency
translation adjustment
- --------------------------------------------------------------
December 31, 1997: 2,322,000 $210,000 $22,200 (a)
==============================================================
* In thousands of dollars
(a) Includes sinking fund requirements due within one year.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
PREFERRED STOCK
$25 PAR VALUE
---------------------------------------
CAPITAL STOCK
PREMIUM AND
EXPENSE
SHARES NON-REDEEMABLE* REDEEMABLE* (NET)*
- ----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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
Issued - - - 214
Redemptions (344,000) - (8,600) (28)
Foreign currency
translation adjustment (708)
- ----------------------------------------------------------------------------
<PAGE>
<PAGE>
December 31, 1996: 12,064,005 $230,000 $71,600 (a) $1,783,725
Issued - - - 426
Redemptions (282,801) - (7,070) 104
Foreign currency
translation adjustment (4,567)
- ----------------------------------------------------------------------------
December 31, 1997: 11,781,204 $230,000 $64,530 (a) $1,779,688
============================================================================
* In thousands of dollars
(a) Includes sinking fund requirements due within one year.
The cumulative amount of foreign currency translation adjustment at December 31, 1997 was
$(15,448).
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
NON-REDEEMABLE PREFERRED STOCK (Optionally Redeemable)
The Company had 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 1997 1996 accumulated dividends)
- --------------------------------------------------------------
Preferred $100 par value:
<S> <C> <C> <C> <C>
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:
9.50% 6,000,000 150,000 150,000 25.00 (a)
<PAGE>
<PAGE>
Adjustable Rate -
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>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
MANDATORILY REDEEMABLE PREFERRED STOCK
At December 31, the Company had 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 1998
through 2002 are as follows: $10,120; $7,620; $7,620; $7,620 and $3,050, respectively. The
aggregate preference of preferred shares upon involuntary liquidation of the Company is the
aggregate par value of such shares, plus an amount equal to the dividends accumulated and
unpaid on such shares to the date of payment whether or not earned or declared.
- ---------------------------------------------------------------------------------
Redemption price per
share (Before adding
Shares In thousands of dollars accumulated dividends)
Eventual
Series 1997 1996 1997 1996 1997 Minimum
- ---------------------------------------------------------------------------------
Preferred $100 par value:
<S> <C> <C> <C> <C> <C> <C>
7.45% 222,000 240,000 $ 22,200 $ 24,000 $101.69 $100.00
Preferred $25 par value:
7.85% 731,204 914,005 18,280 22,850 25.28 25.00
8.375% 100,000 200,000 2,500 5,000 25.00 25.00
<PAGE>
<PAGE>
Adjustable Rate-
Series B 1,750,000 1,750,000 43,750 43,750 25.00 25.00
- ---------------------------------------------------------------------------------
86,730 95,600
Less sinking fund requirements 10,120 8,870
- ---------------------------------------------------------------------------------
$ 76,610 $ 86,730
=================================================================================
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
LONG-TERM DEBT
Long-term debt at December 31 consisted of the following:
- -------------------------------------------------------------
In thousands of dollars
-----------------------
SERIES DUE 1997 1996
- -------------------------------------------------------------
First mortgage bonds:
<S> <C> <C> <C>
6 1/4% 1997 $ - $ 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 275,000 275,000
*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 2,801,305 2,841,305
<PAGE>
<PAGE>
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
Term Loan Agreement 105,000 105,000
Unsecured notes payable:
Medium Term Notes, Various rates,
due 2000-2004 20,000 20,000
Other 154,295 156,606
Unamortized premium (discount) (9,884) (10,708)
- --------------------------------------------------------------
TOTAL LONG-TERM DEBT 3,484,476 3,525,963
Less long-term debt due
within one year 67,095 48,084
- --------------------------------------------------------------
$3,417,381 $3,477,879
==============================================================
*Tax-exempt pollution control related issues
</TABLE>
<PAGE>
<PAGE>
Several series of First Mortgage Bonds and Promissory 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 3.63% for 1997 and 3.46% for 1996
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 1997 consists of obligations under
capital leases of approximately $29.7 million, a liability to the
DOE for nuclear fuel disposal of approximately $114.3 million and
a liability for IPP contract terminations of approximately $10.3
million. The aggregate maturities of long-term debt for the five
years subsequent to December 31, 1997, excluding capital leases, in
millions, are approximately $64, $108, $158, $310 and $230
respectively. The Company's aggregate maturities will increase
significantly upon closing of the MRA. See Item 7. Management's
Discussion and Analysis of Financial Condition and Results of
Operations - "Master Restructuring Agreement and the PowerChoice
Agreement."
NOTE 6. BANK CREDIT ARRANGEMENTS
The Company has an $804 million senior debt facility with a
bank group consisting of a $255 million term loan facility, a $125
million revolving credit facility and $424 million for letters of
credit. The letter of credit facility provides credit support for
the adjustable rate pollution control revenue bonds issued through
the NYSERDA discussed in Note 5. As of December 31, 1997, the
amount outstanding under the senior debt facility was $529 million,
consisting of $105 million under the term loan facility and a $424
million letter of credit, leaving the Company with $275 million of
borrowing capability under the facility. The facility expires on
June 30, 1999 (subject to earlier termination if the Company
separates its fossil/hydro generation business from its
transmission and distribution business, or any other significant
restructuring plan). The interest rate applicable to the facility
is variable based on certain rate options available under the
agreement and currently approximates 7.7% (but capped at 15%). The
Company is currently negotiating with the lenders to replace the
senior debt facility with a larger facility to finance part of the
MRA. The Company did not have any short-term debt outstanding at
December 31, 1997 and 1996.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
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
1997 1996 1995
- ---------------------------------------------------------------
<S> <C> <C> <C>
United States $315,027 $269,128 $400,087
Foreign (1,621) 28,522 17,609
Consolidating eliminations (3,476) (17,402) (10,267)
- ---------------------------------------------------------------
Income before extraordinary
item and income taxes $309,930 $280,248 $407,429
===============================================================
/TABLE
<PAGE>
<PAGE>
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:
In thousands of dollars
1997 1996* 1995
- --------------------------------------------------------------
Components of Federal and foreign income taxes:
Current tax expense:
Federal $ 77,565 $ 96,011 $ 67,366
Foreign - 3,708 3,900
- ---------------------------------------------------------------
77,565 99,719 71,266
- ---------------------------------------------------------------
Deferred tax expense:
Federal 47,836 382 84,002
Foreign 1,194 2,393 4,125
- ---------------------------------------------------------------
49,030 2,775 88,127
- ---------------------------------------------------------------
Total $126,595 $102,494 $159,393
===============================================================
Reconciliation between Federal and foreign income taxes and the tax
computed at prevailing U.S. statutory rate on income before income
taxes:
Computed tax $108,475 $ 98,087 $142,601
- ---------------------------------------------------------------
Increase (reduction) attributable to flow-through of certain tax
adjustments:
Depreciation 36,411 28,103 31,033
Cost of removal (8,168) (8,849) (9,247)
Deferred investment tax
credit amortization (7,454) (8,018) (8,589)
Other (2,669) (6,829) 3,595
- ---------------------------------------------------------------
18,120 4,407 16,792
- ---------------------------------------------------------------
Federal and foreign
income taxes $126,595 $102,494 $159,393
===============================================================
* Does not include the deferred tax benefit of $36,273 in 1996
associated with the extraordinary item for the discontinuance of
regulatory accounting principles.
<PAGE>
<TABLE>
<CAPTION>
At December 31, the deferred tax liabilities (assets) were
comprised of the following:
In thousands of dollars
1997 1996
---- ----
<S> <C> <C>
Alternative minimum tax (17,448) (64,313)
Unbilled revenue (88,859) (83,577)
Other (247,438) (237,850)
---------- ----------
Total deferred tax assets (353,745) (385,740)
---------- ----------
Depreciation related 1,358,827 1,421,550
Investment tax credit related 79,858 84,294
Other 302,092 237,414
---------- ----------
Total deferred tax
liabilities 1,740,777 1,743,258
---------- ----------
Accumulated deferred income
taxes $1,387,032 $1,357,518
=========== ===========
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
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.
Net pension cost for 1997, 1996 and 1995 included the
following components:
- -----------------------------------------------------------------
In thousands of dollars
-----------------------
1997 1996 1995
- -----------------------------------------------------------------
<S> <C> <C> <C>
Service cost - benefits
earned during the period $ 27,100 $ 25,000 $ 22,500
Interest cost on projected
benefit obligation 75,200 71,700 73,000
Actual return on plan assets (188,200) (134,100) (215,600)
Net amortization and deferral 100,400 55,700 140,300
- -----------------------------------------------------------------
Total pension cost (1) $ 14,500 $ 18,300 $ 20,200
=================================================================
(1) $3.2 million for 1997, $3.8 million for 1996, and $4.1
million
for 1995 was related to construction labor and, accordingly,
was charged to construction projects.
</TABLE>
<PAGE>
<PAGE>
The following table sets forth the plan's funded status and
amounts recognized in the Company's Consolidated Balance Sheets:
<TABLE>
<CAPTION>
- --------------------------------------------------------------
In thousands of dollars
-----------------------
At December 31, 1997 1996
- --------------------------------------------------------------
<S> <C> <C>
Actuarial present value of
accumulated benefit obligations:
Vested benefits $ 990,415 $803,202
Non-vested benefits 73,430 83,107
- --------------------------------------------------------------
Accumulated benefit obligations 1,063,845 886,309
Additional amounts related to
projected pay increases 108,583 141,472
- --------------------------------------------------------------
Projected benefits obligation for
service rendered to date 1,172,428 1,027,781
Plan assets at fair value, consisting
primarily of listed stocks, bonds,
other fixed income obligations
and insurance contracts (1,304,338) (1,159,822)
- --------------------------------------------------------------
Plan assets in excess of
projected benefit obligations (131,910) (132,041)
Unrecognized net obligation at
January 1, 1987 being recognized
over approximately 19 years (19,446) (22,005)
Unrecognized net gain from actual
return on plan assets different
from that assumed 265,100 219,680
Unrecognized net gain from past
experience different from that
assumed and effects of changes
in assumptions amortized over 10
years 19,920 66,129
Prior service cost not yet recognized
in net periodic pension cost (50,473) (49,651)
- ---------------------------------------------------------------
Pension liability included
in the consolidated balance sheets $ 83,191 $ 82,112
===============================================================
<PAGE>
<PAGE>
Principle Actuarial Assumptions (%):
Discount Rate 7.00 7.50
Rate of increase in future
compensation levels (plus
merit increases) 2.50 2.50
Long-term rate of return on
plan assets 9.25 9.25
===============================================================
</TABLE>
<PAGE>
<PAGE>
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 comply with SFAS No.
106. The Company has established various trusts to fund its future
postretirement benefit obligation. In 1997, 1996 and 1995, the
Company made contributions to such trusts of approximately $13.5
million, $28.5 million and $53.1 million, respectively, which
represent the amount received in rates and from cotenants.
Net postretirement benefit cost for 1997, 1996 and 1995
included the following components:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------
In thousands of dollars
----------------------------
1997 1996 1995
- -----------------------------------------------------------------
<S> <C> <C> <C>
Service cost - benefits attributed
to service during the period $12,300 $12,900 $12,600
Interest cost on accumulated
benefit obligation 34,800 37,500 45,400
Actual return on plan assets (24,500) (12,900) (11,200)
Amortization of the transition
obligation over 20 years 10,900 13,500 18,800
Net amortization 9,500 6,000 14,600
- -----------------------------------------------------------------
Total postretirement benefit cost $43,000 $57,000 $80,200
=================================================================
<PAGE>
<PAGE>
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, 1997 1996
- -----------------------------------------------------------
Actuarial present value of accumulated benefit obligations:
Retired and surviving spouses $392,832 $370,259
Active eligible 43,299 31,030
Active ineligible 83,720 69,441
- ------------------------------------------------------------
Accumulated benefit obligation 519,851 470,730
Plan assets at fair value,
consisting primarily of
listed stocks, bonds and
other fixed obligations (181,101) (143,071)
- -----------------------------------------------------------
Accumulated postretirement
benefit obligation in excess
of plan assets 338,750 327,659
Unrecognized net loss from
past experience different from
that assumed and effects of
changes in assumptions (48,466) (36,048)
Prior service cost not yet
recognized in postretirement
benefit cost 30,086 39,205
Unrecognized transition obligation
being amortized over 20 years (163,350) (174,240)
- -----------------------------------------------------------
Accrued postretirement benefit
liability included in the
consolidated balance sheet $157,020 $156,576
===========================================================
<PAGE>
<PAGE>
===========================================================
Principal actuarial assumptions (%):
Discount rate 7.00 7.50
Long-term rate of return
on plan assets 9.25 8.00
Health care cost trend rate:
Pre-65 7.00 8.00
Post-65 6.00 6.50
===========================================================
</TABLE>
During 1996, the Company changed the eligibility requirements
for plan benefits for employees who retire after May 1, 1996.
Generally, plan benefits are now accrued for eligible participants
beginning after age 45. Previous to this change, the Company
accrued these benefits over the employees' service life. The
effect of this change resulted in a decrease in the accumulated
benefit obligation for active ineligible employees.
At December 31, 1997, the assumed health cost trend rates
gradually decline to 5.0% in 2001. If the health care cost trend
rate was increased by one percent, the accumulated postretirement
benefit obligation as of December 31, 1997 would increase by
approximately 6.7% and the aggregate of the service and interest
cost component of net periodic postretirement benefit cost for the
year would increase by approximately 5.8%.
The Company recognizes 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, 1997 and 1996, the Company's
postemployment benefit obligation is approximately $13.3 million
and $13 million, respectively.
<PAGE>
<PAGE>
NOTE 9. COMMITMENTS AND CONTINGENCIES
See Note 2.
LONG-TERM CONTRACTS FOR THE PURCHASE OF ELECTRIC POWER: At
January 1, 1998, the Company had long-term contracts to purchase
electric power from the following generating facilities owned by
NYPA:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------
Expiration Purchased Estimated
date of capacity annual
Facility contract in MW capacity cost
- -----------------------------------------------------------------
<S> <C> <C> <C>
Niagara - hydroelectric
project 2007 951 $27,369,000
St. Lawrence - hydroelectric
project 2007 104 1,300,000
Blenheim-Gilboa - pumped
storage generating station 2002 270 7,500,000
- -----------------------------------------------------------------
1,325 $36,169,000
=================================================================
</TABLE>
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
and the recently cancelled contract with Fitzpatrick nuclear plant
was approximately, in millions, $91.0, $93.3 and $92.5 for the
years 1997, 1996 and 1995, respectively. In May 1997, the Company
cancelled its commitment to purchase 110 MW of capacity from the
Fitzpatrick facility. The Company continues to have a contract
with Fitzpatrick to purchase for resale up to 46 MW of power for
NYPA's economic development customers.
Under the requirements of PURPA, the Company is required to
purchase power generated by IPPs, as defined therein. The Company
has 141 PPAs with 148 facilities, of which 143 are on line,
amounting to approximately 2,695 MW of capacity at December 31,
1997. Of this amount 2,382 MW is considered firm. The following
table shows the payments for fixed and other capacity costs, and
energy and related taxes the Company estimates it will be obligated
to make under these contracts without giving effect to the MRA.
<PAGE>
The payments are subject to the tested capacity and availability of
the facilities, scheduling and price escalation.
<TABLE>
<CAPTION>
- ---------------------------------------------------------
(In thousands of dollars)
SCHEDULABLE
FIXED COSTS VARIABLE COSTS
------------------ --------------
YEAR CAPACITY OTHER ENERGY AND TAXES TOTAL
- ---------------------------------------------------------------
<S> <C> <C> <C> <C>
1998 $247,740 $41,420 $ 906,590 $1,195,750
1999 252,130 42,450 943,720 1,238,300
2000 242,030 44,080 974,080 1,260,190
2001 244,620 45,650 1,042,380 1,332,650
2002 248,940 47,330 1,063,830 1,360,100
- ----------------------------------------------------------------
</TABLE>
The capacity and other fixed costs relate to contracts with
11 facilities, where the Company is required to make capacity and
other fixed payments, including payments when a facility is not
operating but available for service. These 11 facilities account
for approximately 774 MW of capacity, with contract lengths ranging
from 20 to 35 years. The terms of these existing 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 $8
billion over their terms, using escalated contract rates.
Contracts relating to the remaining facilities in service at
December 31, 1997, require the Company to pay only when energy is
delivered, except when the Company decides that it would be better
to pay a particular project a reduced energy payment to have the
project reduce its high priced energy deliveries as described
below. 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 $1,106
million, $1,088 million and $980 million in 1997, 1996 and 1995 for
13,500,000 MWh, 13,800,000 MWh and 14,000,000 MWh, respectively, of
electric power under all IPP contracts.
On July 9, 1997, the Company announced the MRA to terminate,
restate or amend certain IPP power purchase contracts. As a result
of negotiations, the MRA currently provides for the termination,
restatement or amendment of 28 PPAs with 15 IPPs, in exchange for
an aggregate of approximately $3,616 million in cash and 42.9
million shares of the Company's common stock and certain fixed
price swap contracts. Under the terms of the MRA, the Company
would terminate PPAs representing approximately 1,180 MW of
capacity and restate contracts representing 583 MW of capacity.
The restated contracts are structured to be in the form of
financial swaps with fixed prices for the first two years changing
to an indexed pricing formula thereafter. The contract quantities
are fixed for the full ten year term of the contracts. The MRA
also requires the Company to provide the IPP Parties with a number
of fixed price swap contracts with a term of seven years beginning
in 2003. The terms of the MRA have been and continue to be
modified.
Since 1996, the Company has negotiated 2 long term and
several limited term contract amendments whereby the Company can
reduce the energy deliveries from the facilities. These reduced
energy agreements resulted in a reduction of IPP deliveries of
approximately 1,010,000 MWh and 984,000 MWh during 1997 and 1996,
respectively.
SALE OF CUSTOMER RECEIVABLES: The Company has established a
single-purpose, wholly-owned financing subsidiary, NM Receivables
Corp., whose business consists of the purchase and resale of an
undivided interest in a designated pool of customer receivables,
including accrued unbilled revenues. 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. NM
Receivables Corp. has its own separate creditors which, upon
liquidation of NM Receivables Corp., will be entitled to be
satisfied out of its assets prior to any value becoming available
to the Company. The sale of receivables are in fee simple for a
reasonably equivalent value and are not secured loans. Some
receivables have been contributed in the form of a capital
contribution to NM Receivables Corp. in fee simple for reasonably
equivalent value, and all receivables transferred to NM Receivables
Corp. are assets owned by NM Receivables Corp. in fee simple and
are not available to pay the parent Company's creditors.
At December 31, 1997 and 1996, $144.1 and $250 million,
respectively, of receivables had been sold by NM Receivables, Corp.
to a third party. The undivided interest in the designated pool of
receivables was sold with limited recourse. The agreement provides
for a formula based loss reserve pursuant to which additional
customer receivables are assigned to the purchaser to protect
against bad debts. At December 31, 1997, the amount of additional
receivables assigned to the purchaser, as a loss reserve, was
approximately $64.4 million. Although this represents the formula-
based amount of credit exposure at December 31, 1997 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 1989 and 1990 and issued a Revenue Agents'
Report. The IRS has raised an issue concerning the deductibility
of payments made to IPPs in accordance with certain contracts that
include a provision for a tracking account. A tracking account
represents amounts that these mandated contracts required the
Company to pay IPPs in excess of the Company's avoided costs,
including a carrying charge. The IRS proposes to disallow a
current deduction for amounts paid in excess of the avoided costs
of the Company. Although the Company believes that any such
disallowances 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. To the extent that contracts involving tracking
accounts are terminated or restated or amended under the MRA with
IPP Parties as described in Note 2, the effects of any proposed
disallowance would be mitigated with respect to the IPP Parties
covered under the MRA. The Company is vigorously defending its
position on this issue. The IRS is currently conducting its
examination of the Company's federal income tax returns for the
years 1991 through 1993.
ENVIRONMENTAL CONTINGENCIES: The public utility industry
typically utilizes and/or generates in its operations a broad range
of hazardous and 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 aid in 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 124 sites with which it has
been or may be associated, including 76 which are Company-owned.
The number of owned sites increased as the Company has established
a program to identify and actively manage potential areas of
concern at its electric substations. This effort resulted in
identifying an additional 32 sites. With respect to non-owned
sites, the Company may be required to contribute some proportionate
share of remedial costs. Although one party can, as a matter of
law, be held liable for all of the remedial costs at a site,
regardless of fault, in practice costs are usually allocated among
PRPs.
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
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 investigations are ongoing for
most sites, the estimated cost of remedial action is subject to
change.
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 and costs at similarly
situated sites. Additionally, the Company's estimating process
includes an initiative where these factors are developed and
reviewed using direct input and support obtained from the DEC.
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 at certain of these PRP sites and is contesting
liability accordingly.
As a consequence of site characterizations and assessments
completed to date and negotiations with PRPs, the Company has
accrued a liability in the amount of $220 million, which is
reflected in the Company's Consolidated Balance Sheets at December
31, 1997. The potential high end of the range is presently
estimated at approximately $650 million, including approximately
$285 million in the unlikely event the Company is required to
assume 100% responsibility at non-owned sites. The amount accrued
at December 31, 1997, incorporates the additional electric
substations, previously mentioned, and a change in the method used
to estimate the liability for 27 of the Company's largest sites to
rely upon a decision analysis approach. This method includes
developing several remediation approaches for each of the 27 sites,
using the factors previously described, and then assigning a
probability to each approach. The probability represents the
Company's best estimate of the likelihood of the approach occurring
using input received directly from the DEC. The probable costs for
each approach are then calculated to arrive at an expected value.
While this approach calculates a range of outcomes for each site,
the Company has accrued the sum of the expected values for these
sites. The amount accrued for the Company's remaining sites is
determined through feasibility studies or engineering estimates,
the Company's estimated share of a PRP allocation or where no
better estimate is available, the low end of a range of possible
outcomes. In addition, the Company has recorded a regulatory asset
representing the remediation obligations to be recovered from
ratepayers. PowerChoice provides for the continued application of
deferral accounting for cost differences resulting from this
effort.
In October 1997, the Company submitted a draft feasibility
study to the DEC, which included the Company's Harbor Point site
and five surrounding non-owned sites. The study indicates a range
of viable remedial approaches, however, a final determination has
not been made concerning the remedial approach to be taken. This
range consists of a low end of $22 million and a high end of $230
million, with an expected value calculation of $51 million, which
is included in the amounts accrued at December 31, 1997. The range
represents the total costs to remediate the properties and does not
consider contributions from other PRPs. The Company anticipates
receiving comments from the DEC on the draft feasibility study by
the spring of 1999. At this time, the Company cannot definitively
predict the nature of the DEC proposed remedial action plan or the
range of remediation costs it will require. While the Company does
not expect to be responsible for the entire cost to remediate these
properties, it is not possible at this time to determine its share
of the cost of remediation. In May 1995, the Company filed a
complaint pursuant to applicable Federal and New York State law, in
the U.S. District Court for the Northern District of New York
against several defendants seeking recovery of past and future
costs associated with the investigation and remediation of the
Harbor Point and surrounding sites. In a motion currently pending
before the court, the New York State Attorney General has moved to
dismiss the Company's claims against the State of New York, the New
York State Department of Transportation, the Thruway Authority and
Canal Corporation. The Company has opposed this motion. The case
management order presently calls for the close of discovery on
December 31, 1998. As a result, the Company cannot predict the
outcome of the pending litigation against other PRPs or the
allocation of the Company's share of the costs to remediate the
Harbor Point and surrounding sites.
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.
To date, the Company has reached settlements with a number of
insurance carriers, resulting in payments to the Company of
approximately $36 million, net of costs incurred in pursuing
recoveries. Under PowerChoice the electric portion or
approximately $32 million will be amortized over 10 years. The
remaining portion relates to the gas business and is being
amortized over the three year settlement period.
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 1998 through 2002 will require approximately
$1.4 billion, excluding AFC and nuclear fuel. For the years 1998
through 2002, the estimates, in millions, are $328, $269, $264,
$275 and $300, respectively, which includes $26, $25, $22, $20 and
$38, respectively, related to non-nuclear generation. The impact
of the ice storm (see Note 13) on the construction program will not
be known until restoration efforts have been completed. These
amounts are reviewed by management as circumstances dictate.
Under PowerChoice, the Company will separate, through sale or
spin-off, the Company's non-nuclear power generation business from
the remainder of the business.
GAS SUPPLY, STORAGE AND PIPELINE COMMITMENTS: In connection
with its gas business, the Company has long-term commitments with
a variety of suppliers and pipelines to purchase gas commodity,
provide gas storage capability and transport gas commodity on
interstate gas pipelines. The table below sets forth the Company's
estimated commitments at December 31, 1997, for the next five
years, and thereafter.
<PAGE>
<PAGE>
(In thousands of dollars)
YEAR GAS SUPPLY GAS STORAGE/PIPELINE
- ---- ---------- --------------------
1998 $103,990 $95,720
1999 78,380 99,490
2000 56,110 81,550
2001 53,140 60,170
2002 39,860 26,610
Thereafter 155,560 71,130
With respect to firm gas supply commitments, the amounts are
based upon volumes specified in the contracts giving consideration
for the minimum take provisions. Commodity prices are based on New
York Mercantile Exchange quotes and reservation charges, when
applicable. For storage and pipeline capacity commitments, amounts
are based upon volumes specified in the contracts, and represent
demand charges priced at current filed tariffs.
At December 31, 1997, the Company's firm gas supply
commitments extend through October 2006, while the gas storage and
transportation commitments extend through October 2012. Beginning
in May 1996, as a result of a generic rate proceeding, the Company
was required to implement service unbundling, where customers could
choose to buy natural gas from sources other than the Company. To
date the migration has not resulted in any stranded costs since the
PSC has allowed utilities to assign the pipeline capacity to the
customers choosing another supplier. This assignment is allowed
during a three-year period ending March 1999, at which time the PSC
will decide on methods for dealing with the remaining unassigned or
excess capacity. In September 1997, the PSC indicated that it is
unlikely utilities will be allowed to continue to assign pipeline
capacity to departing customers after March 1999. The Company is
unable to predict how the PSC will resolve these issues.
<PAGE>
<PAGE>
NOTE 10. FAIR VALUE OF FINANCIAL AND DERIVATIVE 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.
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.
DERIVATIVE FINANCIAL INSTRUMENTS: The fair value of futures
and forward contracts are determined using quoted market prices and
broker quotes.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
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, 1997 1996
- ------------------------------------ --------------------- ----------------------
Carrying Fair Carrying
Fair
Amount Value Amount
Value
- ------------------------------------ --------------------- ----------------------
<S> <C> <C> <C> <C>
Cash and short-term
investments $ 378,232 $ 378,232 $ 325,398 $ 325,398
Mandatorily redeemable
preferred stock 86,730 87,328 95,600 86,516
Long-term debt: First Mortgage bonds 2,801,305 2,878,368 2,841,305 2,690,707
Medium-term notes 20,000 22,944 20,000 21,994
Promissory notes 413,760 413,760 413,760 413,760
Other 229,634 229,634 228,461 228,461
</TABLE>
<PAGE>
<PAGE>
In 1997, the Company's energy marketing subsidiary began to
engage in both trading and non-trading activities generally using
gas futures and electric and gas forward contracts. At December
31, 1997, for both trading and non-trading activities, the fair
value of long and short positions was approximately $59.9 million
and $57.6 million, respectively. These fair values exceed the
weighted average fair value of open positions for the period ending
December 31, 1997. The positions above extend for a period of less
than one year. With respect to these activities the Company does
not have any material counterparty credit risk at December 31,
1997.
Transactions entered into for trading purposes are accounted
for on a mark-to-market basis with changes in fair value recognized
as a gain or loss in the period of the change. At December 31,
1997, the open trading positions consisted of off-balance sheet
electric and gas forward contracts. These positions consisted of
long and short electric forward contracts with fair values of $45.3
million (1,878,000 MWh) and $44.3 million (1,778,000 MWh),
respectively, and long and short gas forward contracts with fair
values of $9.4 million (7.1 million Dth) and $10.2 million (7.3
million Dth), respectively. The quantities above represent
notional contract quantities. The effects of trading activities on
the Company's 1997 results of operations were not material.
Activities for non-trading purposes generally consist of
transactions entered into to hedge the market fluctuations of
contractual and anticipated commitments. Gas futures contracts are
primarily used for hedging purposes. The change in fair value of
these transactions are deferred until the gain or loss on the
hedged item is recognized. The fair value of open positions for
non-trading purposes at December 31, 1997, as well as the effect of
these activities on the Company's results of operations for the
same period ending, was not material.
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 Energy Corporation (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, 1997. The proceeds from the sale of investments were
$159.7 million, $99.4 million and $70.3 million in 1997, 1996 and
1995, respectively. Net realized and unrealized gains and losses
related to the nuclear decommissioning trust are reflected in
"Accumulated depreciation and amortization" on the Consolidated
Balance Sheets, 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 Energy Corporation and the pension trust are
included, net of tax, in "Common stockholders' equity" on the
Consolidated Balance Sheets, while the realized gains and losses
are included in "Other income and deductions" on the Consolidated
Income Statements. The recorded fair values and cost basis of the
Company's investments in debt and equity securities is as follows:
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------
In thousands of dollars
-------------------------------------------------------------------------
At December 31, 1997 1996
- --------------- ---------------------------------- -----------------------------------
Gross Gross
Unrealized Fair Unrealized Fair
Security Type Cost Gain (Loss) Value Cost Gain (Loss) Value
- --------------- ---------------------------------- -----------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
U.S. Government
Obligations $ 14,136 $ 1,864 $ (4) $ 15,996 $ 24,782 $1,530 $ (33) $26,279
Commercial Paper 106,035 1,542 - 107,577 90,495 739 - 91,234
Tax Exempt
Obligations 80,115 5,884 (55) 85,944 75,590 3,209 (147) 78,652
Corporate
Obligations 92,949 17,368 (830) 109,487 62,723 8,524 (422) 70,825
Other 3,025 - - 3,025 2,586 - - 2,586
-------- -------- ------ -------- -------- ------- -------- --------
$296,260 $26,658 $(889) $322,029 $256,176 $14,002 $ (602) $269,576
======== ======= ====== ======== ======== ======= ======== ========
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
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, 1997 1996 1995
- ----------------------- ---- ---- ----
<S> <C> <C> <C>
Realized gains $3,487 $2,121 $2,523
Realized losses 686 806 328
</TABLE>
<TABLE>
<CAPTION>
The contractual maturities of the Company's investments in
debt securities is as follows:
- ---------------------------------------------------------
In thousands of dollars
-----------------------------
At December 31, 1997 Fair Value Cost
- ---------------------------------------------------------
<S> <C> <C>
Less than 1 year $106,677 $105,135
1 year to 5 years 10,845 10,654
5 years to 10 years 52,526 50,351
Due after 10 years 113,946 104,353
</TABLE>
<PAGE>
<PAGE>
NOTE 11. STOCK BASED COMPENSATION
Under the Company's stock compensation plans, stock units and
stock appreciation rights ("SARs") may be granted to officers, key
employees and directors. In addition, the Company's plans allow
for the grant of stock options to officers. In 1997, 1996 and 1995
the Company granted 209,918 units and 296,300 SARs, 291,228 units
and 376,600 SARs and 169,500 units and 414,000 SARs, respectively.
Also, in 1995 the Company granted 85,375 stock options. At
December 31, 1997, there were 668,132 units, 1,086,900 SARs and
298,583 options outstanding. Stock units are payable in cash at
the end of a defined vesting period, determined at the date of the
grant, based upon the Company's stock price for a defined period.
SARs become exercisable, as determined at the grant date, and are
payable in cash based upon the increase in the Company's stock
price from a specified level. As such, for these awards,
compensation expense is recognized over the vesting period of the
award based upon changes in the Company's stock price for that
period. Options were granted over the period 1992 to 1995 and
become exercisable three years and expire ten years from the grant
date. These options are all considered to be antidilutive for EPS
calculations. Included in the results of operations for the years
ending 1997 and 1996, is approximately $3.2 and $2.6 million,
respectively, related to these plans.
As permitted by SFAS No. 123 - "Accounting for Stock-Based
Compensation" ("SFAS No. 123") the Company has elected to follow
Accounting Principles Board Opinion No. 25-"Accounting for Stock
Issued to Employees" (APB No. 25) and related interpretations in
accounting for its employee stock options. Under APB No. 25, no
compensation expense is recognized for stock options because the
exercise price of the Company's employee stock options equals the
market price of the underlying stock on the grant date. Since
stock units and SARs are payable in cash, the accounting under APB
No. 25 and SFAS No. 123 is the same. Therefore, the pro-forma
disclosure of information regarding net income, as required by SFAS
No. 123, relates only to the Company's outstanding stock options,
the effect of which is immaterial to the financial statements for
the years ended 1997, 1996 and 1995. There is no effect on
earnings per share for these years resulting from the pro-forma
adjustments to net income.
<PAGE>
<PAGE>
NOTE 12. 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, 1997, total plant
assets consisted of approximately 24% Nuclear, 20% Fossil/Hydro,
42% Transmission and Distribution, 11% Gas and 3% Common.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
In thousands of dollars
-----------------------
1997 1996 1995
---- ---- ----
<S> <C> <C> <C>
Operating revenues:
Electric $3,309,441 $3,308,979 $3,335,548
Gas 656,963 681,674 581,790
- -----------------------------------------------------------------
Total $3,966,404 $3,990,653 $3,917,338
=================================================================
Operating income:
Electric $ 462,240 $ 438,590 $ 587,282
Gas 96,599 83,748 96,752
- -----------------------------------------------------------------
Total $ 558,839 $ 522,338 $ 684,034
=================================================================
Federal and foreign income taxes:
Electric 96,590 79,574 133,246
Gas 30,005 22,920 26,147
- -----------------------------------------------------------------
Total 126,595 102,494 159,393
=================================================================
Income before
extraordinary item $ 183,335 $ 177,754 $ 248,036
=================================================================
Depreciation and amortization:
Electric $ 311,683 $ 302,825 $ 292,995
Gas 27,958 27,002 24,836
- -----------------------------------------------------------------
Total $ 339,641 $ 329,827 $ 317,831
=================================================================
Construction expenditures (including nuclear fuel):
Electric $ 221,915 $ 277,505 $ 285,722
Gas 68,842 74,544 60,082
- -----------------------------------------------------------------
Total $ 290,757 $ 352,049 $ 345,804
=================================================================
<PAGE>
<PAGE>
Identifiable assets:
Electric $7,257,163 $7,372,370 $7,592,287
Gas 1,185,001 1,203,184 1,123,045
- -----------------------------------------------------------------
Total 8,442,164 8,575,554 8,715,332
Corporate assets 1,141,977 852,081 762,537
- -----------------------------------------------------------------
Total assets $9,584,141 $9,427,635 $9,477,869
=================================================================
</TABLE>
<PAGE>
<PAGE>
NOTE 13. SUBSEQUENT EVENT
In early January 1998, a major ice storm and flooding caused
extensive damage in a large area of northern New York. The
Company's electric transmission and distribution facilities in an
area of approximately 7,000 square miles were damaged, interrupting
service to approximately 120,000 of the Company's customers, or
approximately 300,000 people. The Company had to rebuild much of
its transmission and distribution system to restore power in this
area. By the end of January 1998, service to all customers was
restored; however, the final costs of the storm will not be known
as crews continue to make final repairs to temporary measures to
restore service and salvage operations cannot be completed until
spring.
The preliminary estimate of the total cost of the restoration
and rebuild efforts could exceed $125 million. A portion of the
cost will be capitalized; however, at this time, the Company is
unable to determine the capital portion until rebuild efforts have
been completed and all labor, material and other costs, including
charges from other utilities and contractors, have been received
and analyzed.
The Company is pursuing federal disaster relief assistance
and is working with its insurance carriers to assess what portion
of the rebuild costs are covered by insurance policies. The
Company is also analyzing potential available options for state
financial aid. The Company is unable to determine what recoveries,
if any, it may receive from these sources.
Absent recovery, the Company would face a charge to earnings
in the first quarter of 1998 to reflect its estimate of
unrecoverable, non-capitalized costs.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
NOTE 14. QUARTERLY FINANCIAL DATA (UNAUDITED
Operating revenues, operating income, net income (loss) and
earnings (loss) per common share by quarters from 1997, 1996 and
1995, 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
-----------------------
BASIC AND
BASIC AND DILUTED
DILUTED NET EARNINGS
OPERATING OPERATING INCOME (LOSS) PER
QUARTER ENDED REVENUES INCOME (LOSS) COMMON SHARE
- ----------------------------------------------------------------
<S> <C> <C> <C> <C>
December 31, 1997 $ 960,304 $ 86,024 $ 7,881 $ (.01)
1996 971,106 117,832 (25,808) (.24)
1995 966,478 132,228 27,874 .13
- ----------------------------------------------------------------
September 30, 1997 $ 896,570 $110,174 $ 31,683 $ .15
1996 895,713 47,119 (12,916) (.16)
1995 887,231 142,732 46,941 .26
- ----------------------------------------------------------------
June 30, 1997 $ 945,698 $130,704 $ 40,749 $ .22
1996 960,771 142,755 52,992 .30
1995 938,816 152,297 54,485 .31
- ----------------------------------------------------------------
March 31, 1997 $1,163,832 $231,937 $103,022 $ .65
1996 1,163,063 214,632 96,122 .60
1995 1,124,813 256,777 118,736 .75
- ----------------------------------------------------------------
</TABLE>
In the fourth quarter of 1996 the Company recorded an
extraordinary item for the discontinuance of regulatory accounting
principles of $103.6 million (47 cents per common share). In the
third quarter of 1996 the Company increased the allowance for
doubtful accounts by $68.5 million (31 cents per common share).
In the fourth quarter of 1995, the Company recorded $16.9 million
(8 cents per common share) for MERIT earned in accordance with the
1991 Agreement.
NOTE 15. ADJUSTMENT OF 1997 FINANCIAL STATEMENTS
On May 29, 1998, after discussion with the Staff of the
Securities and Exchange Commission, the Company determined that the
$190 million limitation on the recoverability of the MRA regulatory
asset, as discussed in Note 2 - "Rate and Regulatory Issues and
Contingencies," should be charged to expense in the quarter in
which the MRA closes. Accordingly, the 1997 financial statements,
as presented herein, have been restated to eliminate this charge
and the Company expects that the second quarter 1998 financial
statements will reflect such $190 million charge.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
ELECTRIC AND GAS STATISTICS
ELECTRIC CAPABILITY
Thousands of KW
----------------
December 31, 1997 % 1996 1995
- ------------------------------------------------------------
Owned:
<S> <C> <C> <C> <C>
Coal 1,360 16.7 1,333 1,316
Oil* 646 7.9 636 636
Dual Fuel - Oil/Gas 700 8.6 700 700
Nuclear 1,082 13.3 1,082 1,082
Hydro 661 8.1 617 665
----- ---- ----- -----
4,449 54.6 4,368 4,399
----- ---- ----- -----
Purchased:
New York Power Authority
- Hydro 1,325 16.2 1,310 1,325
- Nuclear - - 110 110
IPPs 2,382 29.2 2,406 2,390
----- ---- ----- -----
3,707 45.4 3,826 3,825
----- ---- ----- -----
Total capability** 8,156 100.0 8,194 8,224
===== ===== ===== =====
Electric peak load 6,348 6,021 6,211
===== ===== =====
* In 1994, Oswego Unit No. 5 (an oil-fired unit with a
capability of 850,000 KW) was put into long-term cold
standby, but could be returned to service in three months.
** 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.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
ELECTRIC STATISTICS
1997 1996 1995
- ----------------------------------------------------------------
<S> <C> <C> <C>
Electric sales (Millions of KWh):
Residential 9,905 10,109 10,055
Commercial 11,552 11,564 11,613
Industrial 7,191 7,148 7,061
Industrial-Special 4,507 4,326 4,053
Municipal service 235 246 229
Other electric systems 3,746 5,431 4,305
Subsidiary - 303 368
- -----------------------------------------------------------------
37,136 39,127 37,684
Electric revenues (Thousands of dollars):
Residential $1,227,245 $1,252,165 $1,214,848
Commercial 1,233,417 1,237,385 1,237,502
Industrial 531,164 524,858 523,996
Industrial-Special 61,820 58,444 56,250
Municipal service 54,545 53,795 50,860
Other electric systems 83,794 113,391 88,936
Miscellaneous 117,456 53,698 143,625
Subsidiary - 15,243 19,531
- -----------------------------------------------------------------
$3,309,441 $3,308,979 $3,335,548
Electric customers (Average):
Residential 1,404,345 1,405,083 1,399,725
Commercial 146,039 145,149 144,731
Industrial 1,970 2,045 2,122
Industrial-Special 85 99 83
Other 1,519 1,302 1,488
Subsidiary - 13,557 13,508
- -----------------------------------------------------------------
1,553,958 1,567,235 1,561,657
Residential (Average):
Annual KWh use per customer 7,053 7,195 7,184
Cost to customer per KWh
(in cents) 12.39 12.39 12.08
Annual revenue per customer $873.89 $891.17 $867.92
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
GAS STATISTICS
1997 1996 1995
- -----------------------------------------------------------------
<S> <C> <C> <C>
Gas Sales (Thousands of Dth):
Residential 55,203 56,728 51,842
Commercial 22,069 25,353 23,818
Industrial 1,381 2,770 2,660
Other gas systems 28 30 161
- -----------------------------------------------------------------
Total sales 78,681 84,881 78,481
Spot market 2,451 10,459 1,723
Transportation of customer-
owned gas 152,813 134,671 144,613
- -----------------------------------------------------------------
Total gas delivered 233,945 230,011 224,817
Gas Revenues (Thousands of dollars):
Residential $ 436,136 $ 417,348 $ 368,391
Commercial 148,213 162,275 143,643
Industrial 6,549 13,325 11,530
Other gas systems 130 138 762
Spot market 6,346 37,124 3,096
Transportation of customer-
owned gas 55,657 50,381 48,290
Miscellaneous 3,932 1,083 6,078
- -----------------------------------------------------------------
$ 656,963 $ 681,674 $ 581,790
Gas Customers (Average):
Residential 484,862 477,786 471,948
Commercial 40,955 41,266 40,945
Industrial 186 206 225
Other 6 6 1
Transportation 843 713 652
- -----------------------------------------------------------------
526,852 519,977 513,771
<PAGE>
<PAGE>
Residential (Average):
Annual dekatherm use
per customer 113.9 118.7 109.8
Cost to customer per Dth $ 7.90 $ 7.36 $ 7.11
Annual revenue per customer $899.51 $873.50 $780.58
Maximum day gas sendout (Dth) 1,133,370 1,152,996 1,211,252
</TABLE>
<PAGE>
<PAGE>
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K.
(a) Certain documents filed as part of the Form 10-K.
(1) INDEX OF FINANCIAL STATEMENTS
Report of Independent Accountants
Consolidated Statements of Income and Retained Earnings
for each of the three years in the period ended December
31, 1997
Consolidated Balance Sheets at December 31, 1997 and 1996
Consolidated Statements of Cash Flows for each of the
three years in the period ended December 31, 1997
Notes to Consolidated Financial Statements
Separate financial statements of the Company have been
omitted since it is primarily an operating company and all
consolidated subsidiaries are wholly-owned directly or by
subsidiaries.
(2) The following financial statement schedules of the Company
for the years ended December 31, 1997, 1996 and 1995 are
included:
Report of Independent Accountants on Financial Statement
Schedule
Consolidated Financial Statement Schedule:
II--Valuation and Qualifying Accounts and Reserves
The Financial Statement Schedule above should be read in
conjunction with the Consolidated Financial Statements in
Part II, Item 8 (Financial Statements and Supplementary
Data).
Schedules other than those mentioned above are omitted
because the conditions requiring their filing do not exist or
because the required information is given in the financial
statements, including the notes thereto.
(3) List of Exhibits:
See Exhibit Index.
<PAGE>
<PAGE>
(b) Reports on Form 8-K:
Form 8-K Reporting Date - October 10, 1997
Item reported - Item 5. Other Events.
Registrant filed information concerning the PowerChoice
settlement.
Form 8-K Reporting Date - February 11, 1998
Item reported - Item 5. Other Events.
Registrant filed information concerning the January 1998 ice
storm.
(c) Exhibits.
See Exhibit Index.
(d) Financial Statement Schedule.
See (a)(2) above.
<PAGE>
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULE
- -----------------------------------------------------------------
To the Board of Directors of
Niagara Mohawk Power Corporation
Our audits of the consolidated financial statements of Niagara
Mohawk Power Corporation referred to in our report dated March 26,
1998 appearing in this Form 10-K also included an audit of the
Financial Statement Schedule listed in Item 14(a) of this Form 10-
K. In our opinion, this Financial Statement Schedule presents
fairly, in all material respects, the information set forth therein
when read in conjunction with the related consolidated financial
statements.
/s/ PRICE WATERHOUSE LLP
Syracuse, New York
March 26, 1998
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- ------------------------------------------------------------
(In Thousands of Dollars)
Column A Column B Column C Column D Column E
- ------------------------ ---------- ---------------------- ---------- ---------
Additions
----------------------
Balance at Charged to Charged to Balance
Beginning Costs and Other Deductions at End
Description of Period Expenses Accounts (a) of Period
- ------------------------ ---------- ---------- ---------- ---------- ---------
<S> <C> <C> <C> <C> <C>
Allowance for Doubtful
Accounts - deducted from
Accounts Receivable in
the Consolidated Balance
Sheets
1997 $52,096 $ 46,549 $ 3,000 (b) $39,097 $62,548
1996 20,000 127,648 800 (b) 96,352 52,096
1995 3,600 31,284 16,400 (b) 31,284 20,000
(a) Uncollectible accounts written off net of recoveries of $14,416, $12,842, and $10,830
in 1997, 1996 and 1995, respectively.
<PAGE>
<PAGE>
(b) The Company increased its allowance for doubtful accounts in 1995 and recorded a
regulatory asset of $16,400, which reflects the amount that the Company expects to
recover in rates. In 1996, regulatory asset increased by $800 to $17,200 and in 1997,
regulatory asset increased $3,000 to $20,200.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
- ---------------------------------------------------------
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- ------------------------------------------------------------
(In Thousands of Dollars)
Column A Column B Column C Column D Column E
- ------------------------ ---------- ---------------------- ---------- ---------
Additions
----------------------
Balance at Charged to Charged to Balance
Beginning Costs and Other at End
Description of Period Expenses Accounts Deductions of Period (c)
- ------------------------ ---------- ---------- ---------- ---------- ---------
<S> <C> <C> <C> <C> <C>
Miscellaneous
Valuation Reserves
1997 $37,740 $ 2,207 $ - $ 4,049 $35,898
1996 39,426 10,261 - 11,947 37,740
1995 29,197 18,719 - 8,490 39,426
(c) The reserves relate primarily to certain inventory and non-rate base properties.
</TABLE>
<PAGE>
<PAGE>
NIAGARA MOHAWK POWER CORPORATION
EXHIBIT INDEX
- -------------
In the following exhibit list, NMPC refers to the Company and
CNYP refers to Central New York Power Corporation, a predecessor
company. Each document referred to below is incorporated by
reference to the files of the Commission, unless the reference to
the document in the list is preceded by an asterisk. Previous
filings with the Commission are indicated as follows:
A--NMPC Registration Statement No. 2-8214;
C--NMPC Registration Statement No. 2-8634;
F--CNYP Registration Statement No. 2-3414;
G--CNYP Registration Statement No. 2-5490;
V--NMPC Registration Statement No. 2-10501;
X--NMPC Registration Statement No. 2-12443;
Z--NMPC Registration Statement No. 2-13285;
CC--NMPC Registration Statement No. 2-16193;
DD--NMPC Registration Statement No. 2-18995;
GG--NMPC Registration Statement No. 2-25526;
HH--NMPC Registration Statement No. 2-26918;
II--NMPC Registration Statement No. 2-29575;
JJ--NMPC Registration Statement No. 2-35112;
KK--NMPC Registration Statement No. 2-38083;
OO--NMPC Registration Statement No. 2-49570;
QQ--NMPC Registration Statement No. 2-51934;
SS--NMPC Registration Statement No. 2-52852;
TT--NMPC Registration Statement No. 2-54017;
VV--NMPC Registration Statement No. 2-59500;
CCC--NMPC Registration Statement No. 2-70860;
III--NMPC Registration Statement No. 2-90568;
OOO--NMPC Registration Statement No. 33-32475;
PPP--NMPC Registration Statement No. 33-38093;
QQQ--NMPC Registration Statement No. 33-47241;
RRR--NMPC Registration Statement No. 33-59594;
<PAGE>
b--NMPC Annual Report on Form 10-K for year ended December 31,
1990; and
c--NMPC Annual Report on Form 10-K for year ended December 31,
1992; and
d--NMPC Annual Report on Form 10-K for year ended December 31,
1993; and
e--NMPC Annual Report on Form 10-K for year ended December 31,
1994; and
f--NMPC Annual Report on Form 10-K for year ended December 31,
1995; and
g--NMPC Annual Report on Form 10-K for year ended December 31,
1996.
h--NMPC Quarterly Report on Form 10-Q for quarter ended March 31,
1993; and
i--NMPC Quarterly Report on Form 10-Q for quarter ended September
30, 1993; and
j--NMPC Quarterly Report on Form 10-Q for quarter ended June 30,
1995; and
k--NMPC Quarterly Report on Form 10-Q for quarter ended September
30, 1996;
l--NMPC Quarterly Report on Form 10-Q for quarter ended June 30,
1997; and
m--NMPC Quarterly Report on Form 10-Q for quarter ended September
30, 1997.
n--NMPC Report on Form 8-K dated July 9, 1997; and
o--NMPC Report on Form 8-K dated October 10, 1997.
In accordance with Paragraph 4(iii) of Item 601 (b) of Regulation
S-K, the Company agrees to furnish to the Securities and Exchange
Commission, upon request, a copy of the agreements comprising the
$804 million senior debt facility that the Company completed with
a bank group during March 1996. The total amount of long-term debt
authorized under such agreement does not exceed 10 percent of the
total consolidated assets of the Company and its subsidiaries.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
INCORPORATION BY REFERENCE
----------------------------------
PREVIOUS PREVIOUS EXHIBIT
EXHIBIT NO. DESCRIPTION OF INSTRUMENT FILING DESIGNATION
- ---------- ------------------------- -------- ----------------
<S> <C> <C> <C>
3(a)(1) --Certificate of Consolidation of New
York Power and Light Corporation,
Buffalo Niagara Electric Corporation
and Central New York Power Corporation,
filed in the office of the New York
Secretary of State, January 5, 1950. e 3(a)(1)
3(a)(2) --Certificate of Amendment of Certificate
of Incorporation of NMPC, filed in the
office of the New York Secretary of
State, January 5, 1950. e 3(a)(2)
3(a)(3) --Certificate of Amendment of Certificate
of Incorporation of NMPC, pursuant to
Section 36 of the Stock Corporation Law of
New York, filed August 22, 1952, in the
office of the New York Secretary of State. e 3(a)(3)
3(a)(4) --Certificate of NMPC pursuant to Section
11 of the Stock Corporation Law of New
York filed May 5, 1954 in the office of
the New York Secretary of State. e 3(a)(4)
3(a)(5) --Certificate of Amendment of Certificate of
Incorporation of NMPC, pursuant to Section
36 of the Stock Corporation Law of New
York, filed January 9, 1957 in the office
of the New York Secretary of State. e 3(a)(5)
<PAGE>
3(a)(6) --Certificate of NMPC pursuant to Section
11 of the Stock Corporation Law of New
York, filed May 22, 1957 in the office of
the New York Secretary of State. e 3(a)(6)
3(a)(7) --Certificate of NMPC pursuant to Section
11 of the Stock Corporation Law of New
York, filed February 18, 1958 in the office
of the New York Secretary of State. e 3(a)(7)
3(a)(8) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York, filed May 5, 1965 in the office
of the New York Secretary of State. e 3(a)(8)
3(a)(9) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of New
York, filed August 24, 1967 in the office
of the New York Secretary of State. e 3(a)(9)
3(a)(10) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of New
York, filed August 19, 1968 in the office
of the New York Secretary of State. e 3(a)(10)
3(a)(11) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of New
York, filed September 22, 1969 in the office
of the New York Secretary of State. e 3(a)(11)
<PAGE>
<PAGE>
3(a)(12) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of New
York, filed May 12, 1971 in the office of
the New York Secretary of State. e 3(a)(12)
3(a)(13) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York, filed August 18, 1972 in the
office of the New York Secretary of State. e 3(a)(13)
3(a)(14) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York, filed June 26, 1973 in the
office of the New York Secretary of State. e 3(a)(14)
3(a)(15) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York, filed May 9, 1974 in the
office of the New York Secretary of State. e 3(a)(15)
3(a)(16) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York, filed March 12, 1975 in the
office of the New York Secretary of State. e 3(a)(16)
3(a)(17) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York, filed May 7, 1975 in the
office of the New York Secretary of State. e 3(a)(17)
<PAGE>
<PAGE>
3(a)(18) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York, filed August 27, 1975 in the
office of the New York Secretary of State. e 3(a)(18)
3(a)(19) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York, filed May 7, 1976 in the
office of the New York Secretary of State. e 3(a)(19)
3(a)(20) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed September 28, 1976 in the
office of the New York Secretary of State. e 3(a)(20)
3(a)(21) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed January 27, 1978 in the
office of the New York Secretary of State. e 3(a)(21)
3(a)(22) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed May 8, 1978 in the
office of the New York Secretary of State. e 3(a)(22)
3(a)(23) --Certificate of Correction of the
Certificate of Amendment filed May 7,
1976 of the Certificate of Incorporation
under Section 105 of the Business
Corporation Law of New York filed
July 13, 1978 in the office of the
New York Secretary of State. e 3(a)(23)
<PAGE>
3(a)(24) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed July 17, 1978 in the
office of the New York Secretary of State. e 3(a)(24)
3(a)(25) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed March 3, 1980 in the
office of the New York Secretary of State. e 3(a)(25)
3(a)(26) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed March 31, 1981 in the
office of the New York Secretary of State. e 3(a)(26)
3(a)(27) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed March 31, 1981 in the
office of the New York Secretary of State. e 3(a)(27)
3(a)(28) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed April 22, 1981 in the
office of the New York Secretary of State. e 3(a)(28)
3(a)(29) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed May 8, 1981 in the office
of the New York Secretary of State. e 3(a)(29)
<PAGE>
<PAGE>
3(a)(30) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed April 26, 1982 in the
office of the New York Secretary of State. e 3(a)(30)
3(a)(31) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed January 24, 1983 in the
office of the New York Secretary of State. e 3(a)(31)
3(a)(32) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed August 3, 1983 in the
office of the New York Secretary of State. e 3(a)(32)
3(a)(33) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed December 27, 1983 in the
office of the New York Secretary of State. e 3(a)(33)
3(a)(34) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed December 27, 1983 in the
office of the New York Secretary of State. e 3(a)(34)
3(a)(35) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed June 4, 1984 in the
office of the New York Secretary of State. e 3(a)(35)
<PAGE>
3(a)(36) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed August 29, 1984 in the
office of the New York Secretary of State. e 3(a)(36)
3(a)(37) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed April 17, 1985, in the
office of the New York Secretary of State. e 3(a)(37)
3(a)(38) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed May 3, 1985, in the
office of the New York Secretary of State. e 3(a)(38)
3(a)(39) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed December 24, 1986 in the
office of the New York Secretary of State. e 3(a)(39)
3(a)(40) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed June 1, 1987 in the
office of the New York Secretary of State. e 3(a)(40)
3(a)(41) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed July 16, 1987 in the
office of the New York Secretary of State. e 3(a)(41)
<PAGE>
<PAGE>
3(a)(42) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed May 27, 1988 in the
office of the New York Secretary of State. e 3(a)(42)
3(a)(43) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed September 27, 1990 in the
office of the New York Secretary of State. e 3(a)(43)
3(a)(44) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed October 18, 1991 in the
office of the New York Secretary of State. e 3(a)(44)
3(a)(45) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed May 5, 1994 in the
office of the New York Secretary of State. e 3(a)(45)
3(a)(46) --Certificate of Amendment of Certificate
of Incorporation of NMPC under Section
805 of the Business Corporation Law of
New York filed August 5, 1994 in the
office of the New York Secretary of State. e 3(a)(46)
*3(b) --By-Laws of NMPC, as amended February 26,
1998.
4(a) --Agreement to furnish certain debt
instruments. e 4(b)
<PAGE>
<PAGE>
4(b)(1) --Mortgage Trust Indenture dated as of
October 1, 1937 between NMPC (formerly
CNYP) and Marine Midland Bank, N.A.
(formerly named The Marine Midland Trust
Company of New York), as Trustee. F **
_________________________
** Filed October 15, 1937 after effective date of Registration Statement No. 2-3414.
4(b)(2) --Supplemental Indenture dated as of
December 1, 1938, supplemental to
Exhibit 4(1). VV 2-3
4(b)(3) --Supplemental Indenture dated as of
April 15, 1939, supplemental to
Exhibit 4(1). VV 2-4
4(b)(4) --Supplemental Indenture dated as of
July 1, 1940, supplemental to
Exhibit 4(1). VV 2-5
4(b)(5) --Supplemental Indenture dated as of
October 1, 1944, supplemental to
Exhibit 4(1). G 7-6
4(b)(6) --Supplemental Indenture dated as of
June 1, 1945, supplemental to
Exhibit 4(1). VV 2-8
4(b)(7) --Supplemental Indenture dated as of
August 17, 1948, supplemental to
Exhibit 4(1). VV 2-9
4(b)(8) --Supplemental Indenture dated as of
December 31, 1949, supplemental to
Exhibit 4(1). A 7-9
<PAGE>
4(b)(9) --Supplemental Indenture dated as of
January 1, 1950, supplemental to
Exhibit 4(1). A 7-10
4(b)(10) --Supplemental Indenture dated as of
October 1, 1950, supplemental to
Exhibit 4(1). C 7-11
4(b)(11) --Supplemental Indenture dated as of
October 19, 1950, supplemental to
Exhibit 4(1). C 7-12
4(b)(12) --Supplemental Indenture dated as of
February 20, 1953, supplemental to
Exhibit 4(1). V 4-16
4(b)(13) --Supplemental Indenture dated as of
April 25, 1956, supplemental to
Exhibit 4(1). X 4-19
4(b)(14) --Supplemental Indenture dated as of
March 15, 1960, supplemental to
Exhibit 4(1). CC 2-23
4(b)(15) --Supplemental Indenture dated as of
October 1, 1966, supplemental to
Exhibit 4(1). GG 2-27
4(b)(16) --Supplemental Indenture dated as of
July 15, 1967, supplemental to
Exhibit 4(1). HH 4-29
4(b)(17) --Supplemental Indenture dated as of
August 1, 1967, supplemental to
Exhibit 4(1). HH 4-30
<PAGE>
4(b)(18) --Supplemental Indenture dated as of
August 1, 1968, supplemental to
Exhibit 4(1). II 2-30
4(b)(19) --Supplemental Indenture dated as of
March 15, 1977, supplemental to
Exhibit 4(1). VV 2-39
4(b)(20) --Supplemental Indenture dated as of
August 1, 1977, supplemental to
Exhibit 4(1). CCC 4(b)(40)
4(b)(21) --Supplemental Indenture dated as of
March 1, 1978, supplemental to
Exhibit 4(1). CCC 4(b)(42)
4(b)(22) --Supplemental Indenture dated as of
June 15, 1980, supplemental to
Exhibit 4(1). CCC 4(b)(46)
4(b)(23) --Supplemental Indenture dated as of
November 1, 1985, supplemental to
Exhibit 4(1). III 4(b)(64)
4(b)(24) --Supplemental Indenture dated as of
October 1, 1989, supplemental to
Exhibit 4(1). OOO 4(b)(73)
4(b)(25) --Supplemental Indenture dated as of
June 1, 1990, supplemental to
Exhibit 4(1). PPP 4(b)(74)
4(b)(26) --Supplemental Indenture dated as of
November 1, 1990, supplemental to
Exhibit 4(1). PPP 4(b)(75)
<PAGE>
4(b)(27) --Supplemental Indenture dated as of
March 1, 1991, supplemental to
Exhibit 4(1). QQQ 4(b)(76)
4(b)(28) --Supplemental Indenture dated as of
October 1, 1991, supplemental to
Exhibit 4(1). QQQ 4(b)(77)
4(b)(29) --Supplemental Indenture dated as of
April 1, 1992, supplemental to
Exhibit 4(1). QQQ 4(b)(78)
4(b)(30) --Supplemental Indenture dated as of
June 1, 1992, supplemental to
Exhibit 4(1). RRR 4(b)(79)
4(b)(31) --Supplemental Indenture dated as of
July 1, 1992, supplemental to
Exhibit 4(1). RRR 4(b)(80)
4(b)(32) --Supplemental Indenture dated as of
August 1, 1992, supplemental to
Exhibit 4(1). RRR 4(b)(81)
4(b)(33) --Supplemental Indenture dated as of
April 1, 1993, supplemental to
Exhibit 4(1). h 4(b)(82)
4(b)(34) --Supplemental Indenture dated as of
July 1, 1993, supplemental to
Exhibit 4(1). i 4(b)(83)
4(b)(35) --Supplemental Indenture dated as of
September 1, 1993, supplemental to
Exhibit 4(1). i 4(b)(84)
<PAGE>
4(b)(36) --Supplemental Indenture dated as of
March 1, 1994, supplemental to
Exhibit 4(1). d 4(b)(85)
4(b)(37) --Supplemental Indenture dated as of
July 1, 1994, supplemental to
Exhibit 4(1). e 4(86)
4(b)(38) --Supplemental Indenture dated as of
May 1, 1995, supplemental to
Exhibit 4(1). j 4(87)
4(b)(39) --Agreement dated as of August 16, 1940,
between CNYP, The Chase National Bank
of the City of New York, as Successor
Trustee, and The Marine Midland Trust
Company of New York, as Trustee. G 7-23
10-1 --Agreement dated March 1, 1957 between
the Power Authority of the State of
New York and NMPC as to sale,
transmission and disposition of St.
Lawrence power. Z 13-11
10-2 --Agreement dated February 10, 1961
between the Power Authority of the
State of New York and NMPC as to sale,
transmission and disposition of
Niagara redevelopment power. DD 13-6
10-3 --Agreement dated July 26, 1961
between the Power Authority of the
State of New York and NMPC
supplemental to Exhibit 10-2. DD 13-7
<PAGE>
10-4 --Agreement dated as of March 23, 1973
between the Power Authority of the
State of New York and NMPC as to
the sale, transmission and disposition
of Blenheim-Gilboa power. OO 5-8
10-5 --Agreement dated January 23, 1970
between Consolidated Gas Supply
Corporation (formerly named New York
State Natural Gas Corporation) and NMPC. KK 5-8
10-6a --New York Power Pool Agreement
dated as of February 1, 1974
between NMPC and six other New York
utilities and the Power Authority
of the State of New York. QQ 5-10
10-6b --New York Power Pool Agreement
dated as of April 27, 1975 between
NMPC and six other New York electric
utilities and the Power Authority of
the State of New York (the parties
to the Agreement have petitioned
the Federal Power Commission for an
order permitting such Agreement,
which increases the reserve factor
of all parties from .14 to .18,
to supersede the New York Power
Pool Agreement dated as of
February 1, 1974). TT 5-10b
10-7 --Agreement dated as of October 31, 1968
between NMPC, Central Hudson Gas &
Electric Corporation and Consolidated
Edison Company of New York, Inc. as
to Joint Electric Generating Plant
(the Roseton Station). JJ 5-10
<PAGE>
10-8a --Memorandum of Understanding dated as
of May 30, 1975 between NMPC and
Rochester Gas & Electric Corporation
with respect to Oswego Unit No. 6. SS 5-13
10-8b --Memorandum of Understanding dated as
of May 30, 1975 between NMPC and
Rochester Gas and Electric Corporation
with respect to Oswego Unit No. 6. SS 5-13
10-8c --Basic Agreement dated as of September 22,
1975 between NMPC and Rochester Gas and
Electric Corporation with respect to
Oswego Unit No. 6. VV 5-13b
10-9a --Memorandum of Understanding dated
as of May 30, 1975 between NMPC and
four other New York electric utilities
with respect to Nine Mile Point Nuclear
Station Unit No. 2. SS 5-14
10-9b --Basic Agreement dated as of
September 22, 1975 between NMPC and
four other New York electric utilities
with respect to Nine Mile Point
Nuclear Station Unit No. 2. VV 5-14b
10-9c --Nine Mile Point Nuclear Station Unit
No. 2 Operating Agreement. c 10-19
10-10a --Memorandum of Understanding dated as
of May 16, 1974, as amended May 30,
1975, between NMPC and three other
New York electric utilities with respect
to the Sterling Nuclear Station. SS 5-15
<PAGE>
<PAGE>
10-10b --Basic Agreement dated as of
September 22, 1975 between NMPC and
three other New York electric utilities
with respect to the Sterling Nuclear
Stations. VV 5-15b
10-11 --Master Restructuring Agreement, dated as
of July 9, 1997, between the Company and
the sixteen independent power producers
signatory thereto. n 10.28
10-12 --PowerChoice settlement filed with the PSC
on October 10, 1997 o 99-9
*10-13 --PSC Opinion and Order regarding approval of
the PowerChoice settlement agreement with
PSC, issued and effective March 20, 1998.
*10-14 --Preferred Consent, December, 1997
(A)10-15 --NMPC Officers' Incentive Compensation Plan -
Plan Document. b 10-16
(A)10-16 --NMPC Long Term Incentive Plan - Plan
Document. l 10-1
(A)10-17 --NMPC Management Incentive Compensation Plan -
Plan Document. b 10-17
(A)10-18 --CEO Special Award Plan. l 10-2
(A)10-19 --NMPC Deferred Compensation Plan. d 10-16
*(A)10-20 --Amendment to NMPC Deferred Compensation Plan
(A)10-21 --NMPC Performance Share Unit Plan. d 10-17
(A)10-22 --NMPC 1992 Stock Option Plan. d 10-18
<PAGE>
(A)10-23 --NMPC 1995 Stock Incentive Plan f 10-31
(A)10-24 --Employment Agreement between NMPC and
David J. Arrington, Sr. Vice President,
Human Resources, dated December 20, 1996. g 10-17
(A)10-25 --Employment Agreement between NMPC and
Albert J. Budney, Jr., President and
Chief Operating Officer, December 20, 1996. g 10-18
(A)10-26 --Employment Agreement between NMPC and William
E. Davis, Chairman of the Board and Chief
Executive Officer, dated December 20, 1996. g 10-19
(A)10-27 --Employment Agreement between NMPC and
Darlene D. Kerr, Sr. Vice President,
Energy Distribution, dated
December 20, 1996. g 10-20
(A)10-28 --Employment Agreement between NMPC and
Gary J. Lavine, Sr. Vice President,
Legal and Corporate Relations, dated
December 20, 1996. g 10-21
(A)10-29 --Employment Agreement between NMPC and
John W. Powers, Sr. Vice President,
and Chief Executive Officer, dated
December 20, 1996. g 10-22
(A)10-30 --Employment Agreement between NMPC and
B. Ralph Sylvia, Executive Vice
President, Electric Generation and
Chief Nuclear Officer, dated
December 20, 1996. g 10-23
<PAGE>
(A)10-31 --Employment Agreement between NMPC and
Theresa A. Flaim, Vice President -
Corporate Strategic Planning, dated
December 20, 1996. g 10-24
(A)10-32 --Employment Agreement between NMPC and
Steven W. Tasker, Vice President -
Controller, dated December 20, 1996. g 10-25
(A)10-33 --Employment Agreement between NMPC and
Kapua A. Rice, Corporate Secretary,
dated December 20, 1996. g 10-26
(A)10-34 --Amendment to Employment Agreement between
NMPC and David J. Arrington, Albert J.
Budney, Jr., William E. Davis, Darlene D.
Kerr, Gary J. Lavine, John W. Powers and
B. Ralph Sylvia, dated June 9, 1997. l 10-3
(A)10-35 --Employment Agreement between NMPC and
William F. Edwards, dated September 25, 1997. m 10-4
*(A)10-36 --Employment Agreement between NMPC and
John H. Mueller, dated January 19, 1998.
(A)10-37 --Deferred Stock Unit Plan for Outside Directors g 10-27
*11 --Statement setting forth the computation of
average number of shares of common stock
outstanding.
*12 --Statements Showing Computations of Certain
Financial Ratios.
*21 --Subsidiaries of the Registrant.
<PAGE>
<PAGE>
*23 --Consent of Price Waterhouse LLP,
independent accountants.
*27 -- Financial Data Schedule.
- -------------------------
(A) Management contract or compensatory plan or arrangement required to be filed as an
exhibit pursuant to Item 601 of Regulation S-K.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
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)
- ----------------------- --------- ----------- ---------- -----------------
1997
----
<S> <C> <C> <C> <C>
January 1 - December 31 144,365,214 365 52,693,303,110
Shares issued at various
times during the period -
Acquisition - Syracuse
Suburban Gas Company,
Inc. 54,137 * 14,260,096
----------- --------------
144,419,351 52,707,563,206 144,404,283
=========== ============== ===========
<PAGE>
<PAGE>
1996
----
January 1 - December 31 144,332,123 366 52,825,557,018
Shares issued at various
times during the year -
Acquisition - Syracuse
Suburban Gas Company,
Inc. 33,091 * 6,397,653
----------- --------------
144,365,214 52,831,954,671 144,349,603
=========== ============== ===========
1995
----
January 1 - December 31 144,311,466 365 52,673,685,090
Shares issued -
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
=========== ============== ===========
* Number of days outstanding not shown as shares represent an accumulation of weekly,
monthly and quarterly issues throughout the year. Share days for shares issued are
based on the total number of days each share was outstanding during the year.
<PAGE>
Note: Earnings per share calculated on both a basic and diluted basis are the same due to
the effects of rounding.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
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,
------------------------------------------------------------
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
A. Net Income per Statements
of Income $183,335 $110,390 $248,036 $176,984 $271,831
B. Taxes Based on Income or
Profits 126,595 66,221 159,393 111,469 147,075
-------- -------- -------- -------- --------
C. Earnings, Before Income
Taxes 309,930 176,611 407,429 288,453 418,906
D. Fixed Charges (a) 304,451 308,323 314,973 315,274 319,197
-------- -------- -------- -------- --------
E. Earnings Before Income
Taxes and Fixed Charges 614,381 484,934 722,402 603,727 738,103
F. Allowance for Funds Used
During Construction 9,706 7,355 9,050 9,079 16,232
-------- -------- -------- ------- -------
<PAGE>
<PAGE>
G. Earnings Before Income
Taxes and Fixed Charges
without AFC $604,675 $477,579 $713,352 $594,648 $721,871
======== ======== ======== ======== ========
Preferred Dividend Factor:
H. Preferred Dividend
Requirements $ 37,397 $ 38,281 $ 39,596 $ 33,673 $ 31,857
-------- -------- -------- --------- --------
I. Ratio of Pre-Tax Income
to Net Income (C / A) 1.69 1.60 1.64 1.63 1.54
-------- --------- --------- --------- ---------
J. Preferred Dividend Factor
(H x I) $ 63,201 $ 61,250 $ 64,937 $ 54,887 $ 49,060
K. Fixed Charges as above (D) 304,451 308,323 314,973 315,274 319,197
-------- -------- -------- -------- --------
L. Fixed Charges and Preferred
Dividends Combined $367,652 $369,573 $379,910 $370,161 $368,257
======== ======== ======== ======== ========
M. Ratio of Earnings to
Fixed Charges (E / D) 2.02 1.57 2.29 1.91 2.31
-------- -------- -------- -------- --------
N. Ratio of Earnings to Fixed
Charges without AFC (G / D) 1.99 1.55 2.26 1.89 2.26
-------- -------- -------- -------- --------
O. Ratio of Earnings to Fixed
Charges and Preferred
Dividends Combined (E / L) 1.67 1.31 1.90 1.63 2.00
-------- ------- -------- -------- --------
<PAGE>
<PAGE>
(a) Includes a portion of rentals deemed representative of the interest factor: $26,149
for
1997, $26,600 for 1996, $27,312 for 1995, $29,396 for 1994 and $27,821 for 1993.
</TABLE>
<PAGE>
<PAGE>
EXHIBIT 21
- ----------
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SUBSIDIARIES OF THE REGISTRANT
Name of Company State of Organization
--------------- ---------------------
Opinac North America, Inc. Delaware
(Note 1)
NM Uranium, Inc. Texas
EMCO-TECH, Inc. (Note 2) New York
NM Holdings, Inc. (Note 3) New York
Moreau Manufacturing Corporation New York
Beebee Island Corporation New York
NM Receivables Corp. New York
NOTE 1: At December 31, 1997, Opinac North America, Inc. owns
Opinac Energy Corporation and Plum Street Enterprises,
Inc. Opinac Energy Corporation has a 50 percent interest
in CNP, which is incorporated in the Province of Ontario,
Canada. CNP owns Cowley Ridge Partnership (an Alberta,
Canada general partnership) and Canadian Niagara Wind
Power Company, Inc. (incorporated in the Province of
Alberta, Canada). Plum Street Enterprises, Inc., ("Plum
Street") an unregulated company, is incorporated in the
State of Delaware. Plum Street owns Plum Street Energy
Marketing, Inc. (incorporated in the State of Delaware),
Global Energy Enterprises India Private Limited, 90% of
Dolphin Investments International, Inc. (a corporation
organized and existing under the laws of Nevis, West
Indies, which owns 45% of Atlantis Energie Systems AG (a
corporation organized and existing under the laws of the
Federal Republic of Germany)), 25% of Telergy Joint
Venture and 26% of Direct Global Power, Inc.
NOTE 2: EMCO-TECH, Inc. is inactive at December 31, 1997.
NOTE 3: At December 31, 1997, NM Holdings, Inc. owns Salmon
Shores, Inc., Moreau Park, Inc., Riverview, Inc., Hudson
Pointe, Inc., Upper Hudson Development, Inc., Land
Management & Development, Inc., OPropco, Inc. and
LandWest, Inc.
<PAGE>
<PAGE>
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, 33-42771 and
333-13781) and to the incorporation by reference in the Prospectus
constituting part of the Registration Statement on Form S-3 (Nos.
33-50703, 33-51073, 33-54827 and 33-55546 and 333-49541) and in the
Prospectus/Proxy Statement constituting part of the Registration
Statement on Form S-4 (No. 333-49769) of Niagara Mohawk Power
Corporation of our report dated March 26, 1998, except Note 2
(third paragraph) and Note 15, as to which the date is May 29, 1998
appearing in the Company's Form 10-K/A dated May 29, 1998. We also
consent to the incorporation by reference of our report on the
financial statement schedules, which appears in the Form 10-K.
/s/ Price Waterhouse LLP
Syracuse, New York
May 29, 1998
<PAGE>
<PAGE>
SIGNATURES
- ----------
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
NIAGARA MOHAWK POWER CORPORATION
(Registrant)
Date: May 29, 1998 By /s/ Steven W. Tasker
--------------------
Steven W. Tasker
Vice President-Controller
and Principal Accounting
Officer
<TABLE> <S> <C>
<ARTICLE> OPUR1
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET, CONSOLIDATED STATEMENT OF INCOME AND CONSOLIDATED
STATEMENT OF CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 6868044
<OTHER-PROPERTY-AND-INVEST> 371709
<TOTAL-CURRENT-ASSETS> 1091700
<TOTAL-DEFERRED-CHARGES> 1176824
<OTHER-ASSETS> 75864
<TOTAL-ASSETS> 9584141
<COMMON> 144419
<CAPITAL-SURPLUS-PAID-IN> 1779688
<RETAINED-EARNINGS> 803420
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2727527
76610
440000
<LONG-TERM-DEBT-NET> 3417381
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 67095
10120
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2968908
<TOT-CAPITALIZATION-AND-LIAB> 9584141
<GROSS-OPERATING-REVENUE> 3966404
<INCOME-TAX-EXPENSE> 126595
<OTHER-OPERATING-EXPENSES> 3407565
<TOTAL-OPERATING-EXPENSES> 3407565
<OPERATING-INCOME-LOSS> 558839
<OTHER-INCOME-NET> 24997
<INCOME-BEFORE-INTEREST-EXPEN> 583836
<TOTAL-INTEREST-EXPENSE> 273906
<NET-INCOME> 183335
37397
<EARNINGS-AVAILABLE-FOR-COMM> 145938
<COMMON-STOCK-DIVIDENDS> 0
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 537575
<EPS-PRIMARY> 1.01
<EPS-DILUTED> 0
</TABLE>
