SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
DATE OF REPORT - SEPTEMBER 26, 1994
NIAGARA MOHAWK POWER CORPORATION
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(Exact name of registrant as specified in its charter)
State of New York 15-0265555
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
Commission file Number 1-2987
300 Erie Boulevard West Syracuse, New York 13202
(Address of principal executive offices) (zip code)
(315) 474-1511
Registrant's telephone number, including area code
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Item 5. Other Events
1. Sithe/Alcan Update
In April 1994, the New York State Public Service Commission
(PSC) ruled that, in the event Sithe Independence Power
Partners Inc. (Sithe) ultimately obtained authority to sell
electric power at retail, those retail sales would be
subject to a lower level of regulation than the PSC
presently imposes on the Company. Sithe, which will sell
electricity to Consolidated Edison of New York, Inc. (Con
Ed) and the Company on a wholesale basis from its 1,040
megawatt natural gas cogeneration plant, plans to provide
steam to Alcan Rolled Products (Alcan). Sithe also proposes
to sell a portion of its electricity output on a retail
basis to Alcan, currently a customer of the Company.
The PSC has previously ruled that under the Public Service
Law Sithe must obtain a PSC certificate before it may use
its electricity generating facilities to serve any retail
customers. Although Sithe continues to contend that these
retail sales are not subject to regulation by the PSC, Sithe
has filed an application for authority to provide such
services subject to PSC regulation.
In briefs filed with the PSC on July 26, 1994, the Company
stated that retail sales by Sithe's Independence Plant
should be prohibited because such transactions would result
in higher electricity bills for the Company's other
customers, would not further economic efficiency and would
not provide economic development benefits.
The Company maintained that if the PSC nevertheless granted
the certificate, the PSC must require that Sithe compensate
the Company for any lost revenue so that the Company's
remaining customers are not harmed.
On September 8, 1994, the PSC authorized sales by Sithe of
electricity directly to Alcan and to Liberty Paperboard
(Liberty), a potential new industrial customer. The Company
had opposed such authorizations. In its September 8, 1994
order, the PSC requested comments by September 16, 1994, as
to the amount of compensatory payments due the Company with
the intention of rendering a decision at its September 22,
1994 session. At the September 22, 1994 session, the
decision was postponed for one week. The Company proposed
that Sithe should compensate it at the rate of approximately
$10 million annually. In his report to the PSC, the
Administrative Law Judge (ALJ) recommended that Sithe pay
the Company a fee based upon the prices at which Sithe would
sell to Alcan. The ALJ recommended a fee structured to
produce a net present value of approximately $19.6 million
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based on annual payments tied to long-run avoided costs
(LRACs). For 1995, the ALJ's recommended fee would be
approximately $3.9 million. He recommended against a fee in
connection with Sithe's sale to Liberty. On September 2,
1994, the PSC Staff and Sithe submitted a settlement
proposal based on the payment by Sithe to the Company of a
fee of $3 million per year for a maximum of 7 1/2 years.
The Company cannot predict the outcome of this proceeding,
but will continue to press its position aggressively.
2. Rate Case Proceedings
On February 4, 1994, the Company made a combined electric
and gas rate filing for rates to be effective January 1,
1995 seeking a $133.7 million (4.3%) increase in electric
revenues and a $24.8 million (4.1%) increase in gas
revenues. The electric filing includes a proposal to
institute a methodology to establish rates beginning in 1996
and running through 1999. The proposal would provide for
rate indexing to a quarterly forecast of the consumer price
index as adjusted for a productivity factor. The
methodology sets a price cap, but the Company could elect
not to raise its rates up to the cap. Such a decision would
be based on the Company's assessment of the market. The
Niagara Mohawk Electric Revenue Adjustment Mechanism (NERAM)
and certain expense deferral mechanisms would be eliminated,
while the fuel adjustment clause would be modified to cap
the Company's exposure to fuel and purchased power cost
variances from forecast at $20 million annually. However,
certain items (so-called "Z factors") which are not within
the Company's control would be outside of the indexing.
Such items would include legislative, accounting, regulatory
and tax law changes as well as environmental and nuclear
decommissioning costs. These items and the existing
balances of certain other deferral items, such as Measured
Equity Return Incentive Term (MERIT) and demand-side
management (DSM), would be recovered or returned using a
temporary rate surcharge. The proposal would also establish
a minimum return on equity that, if not achieved, would
permit the Company to refile for new base rates subject to
indexing or to seek some other form of rate relief, although
there would be no assurance as to the form or amount of such
rate relief, if any. Conversely, in the event earnings
exceeded an established maximum allowed return on equity,
such excess earnings would be used to accelerate recovery of
regulatory assets. The proposal would provide the Company
with greater flexibility to adjust prices within customer
classes to meet competitive pressures from alternative
electric suppliers while increasing the risk that the
Company will earn less than its allowed rate of return. Gas
rate adjustments beyond 1995 would follow traditional
regulatory methodology.
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The Company settled a motion filed by the PSC Staff to
reject the filing as being deficient in support by agreeing
to extend the date by which the PSC must rule on the
Company's rate request by twelve weeks, to March 29, 1995.
The Company would absorb one-half of the costs (the lost
margin) arising because of the extension. The remainder of
the costs would be recovered through a noncash credit to
income, and is dependent upon the amount of rate relief
ultimately granted by the PSC for 1995. Based on its
filing, the Company would absorb approximately $28 million.
Temporary gas rates would be instituted for the full twelve
weeks. This settlement of the PSC Staff's motion must
ultimately be approved by the PSC.
On August 31, 1994, the PSC Staff proposed an overall
decrease in electric revenues from 1994 levels of
approximately $146 million, excluding anticipated sales
growth. This contrasts with the Company's total revenue
increase, excluding sales growth, of $146 million for 1995.
Because the Company's total revenue increase reflects an
effective date of March 29, 1995, while the PSC Staff's
proposal is an annualized amount, the difference between the
two positions is approximately $366 million. The more
significant adjustments proposed by the PSC Staff include
disallowance of $90 million in purchased power payments,
made principally to unregulated generators, additional
adjustments to the unregulated generator forecast for 1995
for prices, capacity levels and in-service dates of certain
projects, reductions in operating and maintenance expenses
stemming largely from the PSC Staff's contention that the
Company's forecast was unsupported, and assumed increases in
revenues from sales to other utilities and transmission
revenues. The PSC Staff also proposes to disallow certain
unregulated generator buyout costs equal to approximately
$12 million in 1995 and to set the electric return on equity
at 10.5%, as compared to the Company's request of 11%. The
PSC Staff recommends that gas revenues be reduced by $5
million in 1995, while also recommending a return on equity
of 10.5% (as opposed to the Company's request of 11.59%).
The reduction from the Company's gas proposal relates
principally to lower departmental expenses, lower return on
equity and higher expected sales in 1995.
In response to the Company's electric indexing proposal for
1996 through 1999, the PSC Staff proposed the use of a
different index, based on the annual change in the national
average electricity price, elimination of all of the
Company-proposed Z-factors, including those for fuel and
purchased power costs, environmental costs, nuclear
decommissioning and accounting and tax law changes, and
elimination of the minimum and maximum Return on Equity
limit. The PSC Staff went well beyond the Company's
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proposal by recommending a "regulatory regime that accepts
market based prices for utility generation." The PSC
Staff's plan would limit, in increasing amounts, the amount
of embedded generation costs (including unregulated
generator costs) that could be charged to customers. The
reference price each year would be based upon either a
reliable market price or the Company's marginal cost of
generation. After such a 10 year phase-in, the Company
would only be able to charge a market-related price for
generation. The Company would be forced to absorb the
difference between its embedded costs and what it could
charge customers, regardless of whether its past practices
were prudent or even mandated by government action.
While the PSC Staff's case contains no financial modelling
of the potential consequences of its proposal on the
Company, such consequences, if the plan is adopted as
proposed could be substantial. The PSC Staff's plan is
based on a price ceiling rather than a cost of service
theory of ratemaking--a departure from the Company's case
and all prior New York State rate-making principles in the
modern era. It in effect also proposes a substantial but
unquantified disallowance with respect to the Company's
generating plants and a similar but undifferentiated
disallowance with respect to the difference between
estimated market costs of power and the amount the Company
is required by law and PSC mandate to pay for unregulated
generator power. If those elements of the PSC Staff's case
were to be implemented as proposed, the Company would also
be required to change one of its basic accounting principles
(the application of Standard of Financial Accounting
Standards (SFAS) No. 71) and incur substantial writeoffs.
These writeoffs would arise not only from disallowed plant
costs and purchased power costs, but also because the
departure from cost-based ratemaking would require that a
substantial portion of the $1.4 billion of regulatory assets
on the Company's balance sheet would no longer be regarded
as recoverable. The Company has not quantified the amounts
which might be involved, but they appear to be of an order
of magnitude that would adversely affect the Company's
ability to access the capital markets on reasonable and
customary terms, its dividend paying capacity, its ability
to continue to make payments to unregulated generators and
even its ability to maintain current levels of service to
its customers. Senior members of the PSC Staff and other
senior public officials in Albany have made it clear that
the PSC trial Staff's proposal was developed independent of
consultation with Commissioners, that the trial staff
functions independently of those individuals and that the
process in this proceeding is far from complete. In the
meantime, the Company will continue to aggressively advocate
its own position.
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The continued application of SFAS 71, "Accounting for the
Effects of Certain Types of Regulation" to the financial
reports and financial statements of electric utilities,
including the Company, as competition continues to expand in
the industry will be an issue during this transition period.
The Company is unable to predict the outcome of these
proceedings, or the possible attendant financial
consequences. However, the Company strongly believes that
its unregulated generator administrative practices were
prudent and should not be disallowed, that the Company's
unregulated generator purchases are in large part the result
of government policy and should be recovered at no penalty
to the shareholders and that a transition plan to a more
competitive environment must provide for an equitable
allocation of transition costs. The ultimate impact on the
Company's financial condition will depend on the pace of
change in the marketplace, the actions of regulators in
response to that change and the actions of the Company in
controlling costs and competing effectively while remaining
in substantial part a regulated enterprise. The Company is
unable to predict the results of the interaction of these
factors.
3. Early Retirement and Voluntary Separation Program
On July 29, 1994, the Company announced a plan to achieve
further substantial reductions in its staffing levels in an
effort to bring the Company's staffing levels and work
practices more into line with other peer group utilities and
become more competitive in its cost structure. The plan
includes an early retirement program and a voluntary
separation program for management employees not eligible for
early retirement. On August 30, 1994, union employees,
representing approximately 70% of the Company's workforce,
approved amendments to the current labor agreement with the
Company which offers union employees the early retirement
and voluntary separation plans, in exchange for a negotiated
package of work rule changes. Passage came with approval of
55.6% of those voting. Employees now have until October 17,
1994 to choose to participate in these programs. The
Company is unable to predict the size of the reduction of
staff and associated cost reductions or the cost of the
early retirement and voluntary separation programs. While
the Company generally intends to pass the savings from the
program back to customers in 1995, it has not determined the
method by which the passback would be accomplished. Based
on current Company estimates, 1994 cash outlays in
connection with the program are not expected to be material.
Although the staffing reductions are expected to produce
long term savings, the Company may be required to record a
charge against earnings in the fourth quarter of 1994. In
the event a charge against income would otherwise be
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required, the Company may decide to seek recovery from
customers of all or a portion of the cost of the program,
but can provide no assurance that the PSC would approve such
recovery.
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4. Credit Ratings
On September 8, 1994, Moody's Investors Service placed the
credit ratings of the Company under review for possible
downgrade. The review was prompted by both the PSC's
September 8 decision on Sithe/Alcan and the August 31
proposal from the PSC Staff to reduce the Company's electric
and gas rates over the next five years. Moody's current
rating for the Company's senior secured debt is Baa2.
On September 9, 1994, Standard and Poor's (S&P) placed its
ratings on the Company, Con Ed and Long Island Lighting
Company on credit watch with negative implications. This
action by S&P reflects continued concern about a shift in
the regulatory environment in New York State that would be
even more hostile to the financial health of the state's
utilities. S&P's current rating for the Company's senior
secured debt is BBB-, the lowest investment grade rating.
Duff and Phelps is also monitoring New York State utilities
following recent negative ratemaking recommendations by the
PSC Staff.
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NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of
1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
NIAGARA MOHAWK POWER CORPORATION
(Registrant)
Date: September 26, 1994 By /s/ Steven W. Tasker
Steven W. Tasker
Vice President-Controller and
Principal Accounting Officer,
in his respective capacities
as such
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