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 - FEBRUARY 15, 1995
NIAGARA MOHAWK POWER CORPORATION
--------------------------------
(Exact name of registrant as specified in its charter)
State of New York 15-0265555
----------------- ----------
(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
NIAGARA MOHAWK POWER CORPORATION
--------------------------------
Item 5. Other Events.
Registrant hereby files the following items which will constitute
a portion of its 1994 Annual Report to Stockholders:
Page
- Highlights 3
- Market for the Registrant's Common Equity and Related
Stockholder Matters 4
- Selected Financial Data for the five years ended
December 31, 1994 6
- Management's Discussion and Analysis of Financial
Condition and Results of Operations 7
- Report of Management 50
- Report of Independent Accountants 52
- Consolidated Statements of Income and Retained
Earnings for each year in the three-year period
ended December 31, 1994 53
- Consolidated Balance Sheets at December 31, 1994
and 1993 54
- Consolidated Statements of Cash Flows for each
year in the three-year period ended
December 31, 1994 56
- Notes to Consolidated Financial Statements 57
- Electric and Gas Statistics 105
Item 7. Financial Statement, Proforma Financial Information and Exhibits.
Exhibit 11 - Computation of Average Number of
Shares of Common Stock Outstanding 108
Exhibit 12 - Statements Showing Computations
of Certain Financial Ratios 109
Exhibit 23 - Accountant's Consent
Signature 110
%
HIGHLIGHTS 1994 1993 Change
Total operating revenues. . . . . . . . $ 4,152,178,000 $ 3,933,431,000 5.6
Income available for common
stockholders . . . . . . . . . . . . . $ 143,311,000 $ 239,974,000 (40.3)
Earnings per common share . . . . . . . $1.00 $1.71 (41.5)
Dividends per common share. . . . . . . $1.09 $0.95 14.7
Common shares outstanding (average) . . 143,261,000 140,417,000 2.0
Utility plant (gross) . . . . . . . . . $10,485,339,000 $10,108,529,000 3.7
Construction work in progress . . . . . $ 481,335,000 $ 569,404,000 (15.5)
Gross additions to utility plant. . . . $ 490,124,000 $ 519,612,000 (5.7)
Public kilowatt-hour sales. . . . . . . 34,006,000,000 33,750,000,000 0.8
Total kilowatt-hour sales . . . . . . . 41,599,000,000 37,724,000,000 10.3
Electric customers at
end of year. . . . . . . . . . . . . . 1,559,000 1,552,000 0.5
Electric peak load (kilowatts). . . . . 6,458,000 6,191,000 4.3
Natural gas sales to ultimate customers
(dekatherms) . . . . . . . . . . . . . 85,615,000 83,201,000 2.9
Natural gas transported
(dekatherms) . . . . . . . . . . . . . 85,910,000 67,741,000 26.8
Gas customers at end of year. . . . . . 512,000 501,000 2.2
995,801 929,285 7.2
Maximum day gas deliveries
(dekatherms) . . . . . . . . . . . . .
MARKET FOR THE REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The Company's common stock and certain of its preferred
series are listed on the New York Stock Exchange. The common
stock is also traded on the Boston, Cincinnati, Midwest, Pacific
and Philadelphia stock exchanges. Common stock options are
traded on the American Stock Exchange. The ticker symbol is
"NMK".
Preferred dividends were paid on March 31, June 30,
September 30 and December 31. Common stock dividends were paid
on February 28, May 31, August 31 and November 30. The Company
presently estimates that none of the 1994 common or preferred
stock dividends will constitute a return of capital and therefore
all of such dividends are subject to Federal tax as ordinary
income.
The table below shows quoted market prices and dividends per
share for the Company's common stock:
Dividends Price Range
Paid
1994 Per Share High Low
1st Quarter $.25 $20 5/8 $17 3/4
2nd Quarter .28 19 14 5/8
3rd Quarter .28 17 1/2 12
4th Quarter .28 14 3/8 12 7/8
1993
1st Quarter $.20 $22 3/8 $18 7/8
2nd Quarter .25 24 1/4 21 5/8
3rd Quarter .25 25 1/4 23 3/4
4th Quarter .25 23 7/8 19 1/4
OTHER STOCKHOLDER MATTERS: The holders of Common Stock are
entitled to one vote per share and may not cumulate their votes
for the election of Directors. Whenever dividends on Preferred
Stock are in default in an amount equivalent to four full
quarterly dividends and thereafter until all dividends thereon
are paid or declared and set aside for payment, the holders of
such stock can elect a majority of the Board of Directors.
Whenever dividends on any Preference Stock are in default in an
amount equivalent to six full quarterly dividends and thereafter
until all dividends thereon are paid or declared and set aside
for payment, the holders of such stock can elect two members to
the Board of Directors. No dividends on Preferred Stock are now
in arrears and no Preference Stock is now outstanding. Upon any
dissolution, liquidation or winding up of the Company's business,
the holders of Common Stock are entitled to receive a pro rata
share of all of the Company's assets remaining and available for
distribution after the full amounts to which holders of Preferred
and Preference Stock are entitled have been satisfied.
The indenture securing the Company's mortgage debt provides
that retained earnings shall be reserved and held unavailable for
the payment of dividends on Common Stock to the extent that
expenditures for maintenance and repairs plus provisions for
depreciation do not exceed 2.25% of depreciable property as
defined therein. Such provisions have never resulted in a
restriction of the Company's retained earnings.
At year end, about 92,000 stockholders owned common shares
of the Company and about 6,000 held preferred stock. The chart
below summarizes common stockholder ownership by size of holding:
Size of holding
(Shares) Total stockholders Total shares held
1 to 99 35,919 1,045,670
100 to 999 50,539 12,596,578
1,000 or more 5,247 130,669,218
91,705 144,311,466
Selected Financial Data
As discussed in Management's Discussion and Analysis of Financial Condition and Results of
Operations and Notes to Consolidated Financial Statements, certain of the following
selected financial data may not be indicative of the Company's future financial condition
or results of operations.
1994 1993 1992 1991 1990
Operations: (000's)
Operating revenues . . . . . . . . . $4,152,178 $3,933,431 $3,701,527 $3,382,518 $3,154,719
Net income . . . . . . . . . . . . . 176,984 271,831 256,432 243,369 82,878
Common stock data:
Book value per share at year end . . $17.06 $17.25 $16.33 $15.54 $14.37
Market price at year end . . . . . . 14 1/4 20 1/4 19 1/8 17 7/8 13 1/8
Ratio of market price to book value 83.5% 117.4% 117.1% 115.0% 91.4%
at year end. . . . . . . . . . . . .
Dividend yield at year end . . . . . 7.9% 4.9% 4.2% 3.6% 0.0%
Earnings per average common share. . $ 1.00 $ 1.71 $ 1.61 $ 1.49 $ .30
Rate of return on common equity . . 5.8% 10.2% 10.1% 10.0% 2.1%
Dividends paid per common share. . . $ 1.09 $ .95 $ .76 $ .32 $ .00
Dividend payout ratio. . . . . . . . 109.0% 55.6% 47.2% 21.5% 0.0%
Capitalization: (000's)
Common equity. . . . . . . . . . . . $2,462,398 $2,456,465 $2,240,441 $2,115,542 $1,955,118
Non-redeemable preferred stock . . . 290,000 290,000 290,000 290,000 290,000
Redeemable preferred stock . . . . . 256,000 123,200 170,400 212,600 241,550
Long-term debt . . . . . . . . . . . 3,297,874 3,258,612 3,491,059 3,325,028 3,313,286
Total. . . . . . . . . . . . . . . 6,306,272 6,128,277 6,191,900 5,943,170 5,799,954
First mortgage bonds maturing within
one year . . . . . . . . . . . . . . - 190,000 - 100,000 40,000
Total. . . . . . . . . . . . . . . $6,306,272 $6,138,277 $6,191,900 $6,043,170 $5,839,954
Capitalization ratios: (including first mortgage bonds maturing within one year):
Common stock equity. . . . . . . . . 39.0% 38.9% 36.2% 35.0% 33.5%
Preferred stock. . . . . . . . . . . 8.7 6.5 7.4 8.3 9.1
Long-term debt . . . . . . . . . . . 52.3 54.6 56.4 56.7 57.4
Financial ratios:
Ratio of earnings to fixed charges . 1.91 2.31 2.24 2.09 1.41
Ratio of earnings to fixed charges
without AFC. . . . . . . . . . . . . 1.89 2.26 2.17 2.03 1.35
Ratio of AFC to balance available for 6.3% 6.7% 9.7% 9.3% 52.8%
common stock . . . . . . . . . . . .
Ratio of earnings to fixed charges
and preferred stock dividends. . . . 1.63 2.00 1.90 1.77 1.17
Other ratios-% of operating revenues:
Fuel, purchased power and purchased gas.. 39.6% 36.1% 34.1% 32.1% 36.9%
Other operation expenses. . . . . 18.2 20.9 19.7 20.0 19.9
Maintenance, depreciation and
amortization . . . . . . . . . . 12.3 13.0 13.5 14.4 14.4
Total taxes . . . . . . . . . . . 14.7 16.2 17.3 16.4 14.4
Operating income. . . . . . . . . 10.4 13.3 14.2 15.5 14.3
Balance available for common
stock. . . . . . . . . . . . . . 3.5 6.1 5.9 6.0 1.3
Miscellaneous: (000's)
Gross additions to utility plant . . $ 490,124 $ 519,612 $ 502,244 $ 522,474 $ 431,579
Total utility plant. . . . . . . . . 10,485,339 10,108,529 9,642,262 9,180,212 8,702,741
Accumulated depreciation and
amortization . . . . . . . . . . . . 3,449,696 3,231,237 2,975,977 2,741,004 2,484,124
Total assets . . . . . . . . . . . . 9,649,439 9,471,327 8,590,535 8,241,476 7,765,406
/TABLE
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
---------------------------------------------------------------
RESULTS OF OPERATIONS
---------------------
OVERVIEW OF 1994 RESULTS
------------------------
Earnings declined to $143.3 million or $1.00 per share as
compared to $240.0 million or $1.71 per share in 1993, reflecting
management's decision to charge earnings for nearly all of the
cost of the Voluntary Employee Reduction Program (VERP),
described below, rather than seek rate recovery, based on the
impact on future rates of deferring and recovering these costs.
The VERP had been initiated to bring the Company's staffing
levels and work practices more into line with peer utilities and
to enable the Company to become more competitive in its cost
structure. Without the VERP charge of approximately $197 million
($.89 per share), earnings would have improved, reflecting
continued cost control efforts and improved gas sales. Also,
because of the Company's NERAM (described below), shortfalls in
all classes of sales, equivalent to $.46 per share in 1994, were
deferred for future recovery in rates. The Company's 1995 and
multi-year rate proceedings do not seek to extend the NERAM in
view of the pricing flexibility sought, although, the separation of
the 1995 phase of the case may present some opportunity to extend
this mechanism. The Company's earned return on equity was 5.8%,
but without the VERP charge would have been 10.7%, somewhat
below the PSC authorized return on equity on electric utility
operations of 11.4%. Earnings for 1995 depend substantially on
the outcome of the 1995 rate case discussed below and the level
of rate discounts necessary to minimize loss of industrial
customers. An Administrative Law Judge's Recommended Decision,
discussed below, if adopted by the PSC, could result in 1995
earnings being considerably lower than 1994 earnings exclusive of
VERP costs. Beyond 1995, earnings will depend on the outcome
of the multi-year rate case, also discussed below, and the
extent to which competition may erode the Company's revenues
without relief from the burden of regulatory and
legislatively mandated costs.
The Company increased the common stock dividend 12% in 1994
to an annual rate of $1.12. Exclusive of the VERP charge, the
common dividend payout ratio was relatively low, 57.7%, as
compared to the rest of the electric and gas industry in 1994.
However, several utilities reduced common dividend levels and
resulting payout ratios in 1994, stating publicly that such
actions were to better position these companies for a more
competitive future. In making future dividend decisions, the
Company must likewise evaluate the results of the 1995 and multi-
year phases of its pending rate case and the degree of
competitive pressure on its prices and, therefore, on its future
earnings.
The outcome of these rate proceedings will have a
significant effect on the Company's liquidity and financing
requirements and its ability to obtain financing on customary
terms. Short-term debt exceeded $400 million at December 31,
1994. A substantial portion of this short-term debt was repaid
in January 1995 with the proceeds from the sale of HYDRA-CO
(discussed later). The Company must renew a significant
portion of its bank credit arrangements in 1995, and while it
expects to be able to secure new arrangements, the cost may be
significantly higher. The Company also faces a possible downgrade
in the ratings of its senior securities to below investment grade.
While management believes long-term debt financing can still be
secured by issuing First Mortgage Bonds, the cost of such securities
will likely be higher. The Company is precluded from issuing
preferred stock in 1995 due to insufficient dividend coverage, as a
result of the VERP writeoff.
The Company is increasingly challenged to maintain its
financial condition in the face of expanding competition and
probable erosion of traditional regulation. While utilities
across the nation must address these concerns to varying degrees,
the Company believes that it is more vulnerable than others to
competitive threats. The factors contributing to this
vulnerability include a large industrial customer base, an
oversupply of high cost mandated power purchases from unregulated
generators, an excess supply of wholesale power at relatively low
prices and a high tax burden. Recent changes in state leadership
may change the energy policies of New York State. The Company will
be pursuing actions to redress inequities and reform regulatory
policies that have contributed to the Company's increasing prices.
The following sections present an assessment of competitive
conditions and steps being taken to improve the Company's
strategic and financial position.
CHANGING COMPETITIVE ENVIRONMENT
--------------------------------
The potential intensity and accelerating pace of competition
may be the most significant factor driving fundamental changes in
the way utilities, including the Company, are being managed. The
Company believes that the price of electricity may be the most
important element of future success in the industry and has
intensified its efforts to reduce various costs that
significantly influence the price of electricity. The ability to
control or reduce costs may be significantly limited in a number
of ways, particularly in the areas of state mandated unregulated
generator contracts and excessive taxes such as the gross
receipts tax and property taxes. These costs are among the most
prominent causes of the Company's recent increases in prices, but
may be the most controversial problems to solve as judicial,
regulatory and/or legislative action will almost certainly be
needed to achieve desired results. The dismissal of the Inter-
Power lawsuit and certain developments in the Sithe/Alcan
proceeding described below demonstrate some progress, but much
more needs to be accomplished. The failure to secure favorable
judicial, regulatory and/or legislative actions in the near
future could have, depending on the pace of competition, severe
financial consequences to the Company and would require dramatic
steps to protect stockholder interests.
The Company has made significant progress in managing the
costs under its direct control. As described below, the Company,
as part of its downsizing efforts, completed the VERP program, in
which approximately 1,400 active employees elected to
participate. Since December 1992, the employee level will have
been reduced by over 3,100, or 27%. Capital spending has also
been reduced sharply in recent years, with electric construction
spending in future years expected to be limited to the level of
depreciation expense, thereby resulting in little growth in
traditional rate base. The Company remains focused on materially
reducing its total costs.
The increasing movement towards a competitive environment
has required regulators on both the state and federal levels to
begin to address the many substantial issues confronting electric
utilities. During 1994, the Federal Energy Regulatory Commission
(FERC) and the New York State Public Service Commission (PSC)
each provided or proposed guidelines to address different aspects
of competition. The FERC issued guidelines for pricing electric
transmission service and proposed guidelines for the recovery of
stranded costs, which are unrecoverable due to a change in the
regulatory environment. Meanwhile, the PSC, in Phase I of its
generic competitive proceeding, adopted guidelines to govern
flexible rates which could be offered by utilities to retain
qualified customers. Phase II of this proceeding will examine
issues relating to the establishment of a wholesale and retail
competitive markets (see "Defining Competitive Challenges"
below).
DEFINING COMPETITIVE CHALLENGES
-------------------------------
COMPANY COMPETITIVENESS STUDY. Under the terms of its 1994
Rate Agreement with the PSC, the Company filed a
"competitiveness" study on April 7, 1994, entitled "The Impacts
of Emerging Competition in the Electric Utility Industry." The
assessment of competition contained in the report describes the
initial results of the Company's CIRCA 2000 (Comprehensive
Industry Restructuring and Competitive Assessment for the 2000s)
studies. Although there is considerable debate about what
changes should occur in the electric industry and even more
uncertainty about what will actually happen, the study explores
the Company's best estimate of how impacts would vary depending
on the extent of changes in the industry and the pace at which
those changes are allowed to unfold.
The Company generates electricity from diverse sources to
reduce sensitivity to changes in the economics of any single fuel
source. However, the average cost of these diverse fuel sources
may be greater than any single fuel source. While the Company's
average generation costs are competitive with costs of new
suppliers of electricity, the current excess supply of capacity
in the Northeast and Canada has significantly depressed wholesale
prices, which may be indicative of retail prices in the near term
if retail customers are allowed direct access to the wholesale
generation market. Under these circumstances, by-pass (i.e.,
sale directly to existing customers by others) of the Company's
generation system is a growing threat, although no regulatory
structure for by-pass currently exists in New York State. A
growing number of municipalities within the Company's service
territory are investigating the possibility of achieving by-pass
through formation of their own utility operations. As wholesale
entities these new utilities would have open access to
transmission and thus would be able to acquire alternative
sources of supply. While the municipalities exploring this
possibility are mostly in the earliest stages of inquiry and
currently represent an extremely small percentage of Company
sales, municipalization has the potential to adversely affect the
Company's customer base and profitability.
From a broader industry perspective, the Company's
assessment concludes that selective discounting to avoid
uneconomic by-pass is likely to be effective in the current
regulatory and competitive regime. Full retail competition, if
not managed appropriately and consistently, could create
significantly higher prices for core customers, jeopardize the
financial viability of the Company and devastate the social
programs delivered by the Company. While aggressive cost
management must be part of any response to competition, it alone
cannot address the financial consequences that may arise from any
sudden and dramatic policy change. As mentioned above, a
significant portion of the Company's costs are outside its direct
control. The Company believes that regulators, legislators, and
utilities must collaborate to deal with overpaid unregulated
generation and other issues to create a fair and equitable
transition to increased competition that addresses the obligation
to serve, including addressing regulatory obligations for social
programs, (i.e.; low-income programs), and provide for proper
recovery of shareholder's investment.
Certain adversaries of the Company in New York State and
certain governmental officials have stated that the best way for
the Company to address competitive issues would be to take
substantial, but unspecified in amount, writedowns of its assets,
particularly its nuclear and fossil generating plants. The
Company's position is that any proper solution to the problems
posed by increasing competition and deregulation must be
substantially more evenhanded, and will necessarily be more
complicated, than any such proposal. The Company will vigorously
contest inequitable solutions to competitive conditions.
FERC NOPR ON STRANDED INVESTMENT. The FERC issued a Notice
of Proposed Rulemaking (NOPR) on June 29, 1994 proposing rules
governing the ability of utilities to recover wholesale and
retail stranded investments (or costs). The NOPR defines
wholesale stranded costs as "any legitimate, prudent and
verifiable costs incurred by a public utility or a transmitting
utility to provide service to a wholesale customer that
subsequently becomes, in whole
or in part, an unbundled transmission service customer of that
public utility or transmitting utility." The same definition
applies to "retail stranded investment" for "retail franchise
customers."
For existing contracts, the NOPR proposes that a three-year
period be set during which the contracts can be negotiated to
permit recovery of stranded costs. FERC would bar recovery where
contracts already have exit fees or address stranded costs in
some other way. If the parties fail to reach agreement, the
utility may unilaterally file a stranded cost provision.
The FERC believes it to be generally inappropriate to permit
recovery of stranded costs via transmission rates and instead
prefers renegotiation of bulk (generally wholesale) power
contracts. Further, FERC has indicated a strong preference for
the costs of the transition to competition at the retail level to
be addressed by the states. The NOPR seeks comments as to
whether the FERC should allow recovery of retail stranded costs
in transmission rates under certain circumstances. The Company
has responded, with other New York State utilities, that it is
generally supportive of the FERC's findings, but believes that
the FERC must play a more active role in addressing retail
stranded cost recovery, particularly in the context of increased
municipalization activity discussed above.
PSC COMPETITIVE OPPORTUNITIES PROCEEDING - ELECTRIC. In
June 1994, the PSC instituted Phase II of its competitiveness
opportunities proceeding, the overall objective of which is "to
identify regulatory and ratemaking practices that will assist in
the transition to a more competitive electric industry designed
to increase efficiency in the provision of electricity while
maintaining safety, environmental affordability, and service
quality goals." In an order issued December 22, 1994, the PSC
released for comment a series of principles to guide the
transition to competition. The principles emphasize the
importance of the economic and environmental well-being of New
York State, which "cannot be compromised to accommodate other
principles." Other proposed principles recognize that
competition, at least at the wholesale level, will further the
economic and environmental well-being of New York State, that
"bill shock" for any class of customers should be minimized, that
the integrity, safety and reliability of the bulk (transmission
and distribution) electric system should not be jeopardized, that
the current industry structure of a vertically integrated utility
(ownership of generation, transmission and distribution
activities) is incompatible with effective wholesale or retail
competition and that utilities should have a reasonable
opportunity to recover "prudent and verifiable expenditures and
commitments made pursuant to their legal obligations, as long as
the utilities are cooperating in furthering all of the
principles." According to the order, similar cooperation by
independent power producers (IPP) should result in "respect for
the reasonable expectations of IPP investors." The PSC has
said it believes the transition to competition should balance
order, deliberation and speed. Although the focus of the
original order was on the wholesale market, the PSC concluded
that the proceeding should examine issues related to retail
competition as well. The PSC notes, in its order, that it can
only implement these principles within the context of its own
authority and that coordination across government is necessary
to avoid major dislocation among suppliers of electricity.
The Company cannot predict the timing or the results of the
proceeding.
FERC ORDER 636 AND PSC COMPETITIVE OPPORTUNITIES
PROCEEDING - GAS. Portions of the natural gas industry have
undergone significant structural changes. A major milestone in
this process occurred in November 1993 with the implementation of
FERC Order 636. FERC Order 636 requires interstate pipelines to
unbundle pipeline sales services from pipeline transportation
service. These changes enable the Company to arrange for its gas
supply directly with producers, gas marketers or pipelines, at
its discretion, as well as to arrange for transportation and gas
storage services. The flexibility provided to the Company by
these changes should enable it to protect its existing market and
still expand its core and non-core market offerings. With these
expanded opportunities come increased competition from gas
marketers and other utilities.
Similar rate initiatives on competitively priced natural gas
were addressed in a generic investigation completed by the PSC in
December 1994. The PSC order in the proceeding significantly
expands customer access to competitive gas suppliers using a
framework designed to "assure that (1) local distribution
companies (LDCs) and new entrants can compete; (2) customers
benefit from increased choices and improved performance resulting
from a more competitive industry; and (3) core customers continue
to receive quality services at affordable rates." The Company
intends to respond by proposing a comprehensive restructuring of
rates and services designed to take advantage of the
opportunities presented by this new "open" environment.
STATE ENERGY PLANNING BOARD INITIATIVES. In October 1994,
the State Energy Planning Board issued an updated New York State
Energy Plan, which called for significant reductions in state
energy taxes, called upon the New York Power Authority (NYPA) and
the state's investor-owned utilities to study the feasibility of
creating a joint entity to operate and maintain the nuclear
generating stations in the state and endorsed greater competition
in utility purchases of electricity. The report also called for
the development of a fully competitive wholesale generation
market in the state within five years and observed that if
utility generation is separated from transmission, the PSC
"should consider carefully the valuation and allocation of
utility assets in the regulated and competitive sectors." It
recommended that retail competition should occur when fair
treatment of all customer classes, competitors, energy
efficiency and renewables and capital committed in prudent response
to past government mandates is reasonably assured. The Company is
unable to predict whether or how this plan will influence regulatory
policy.
NYPA RESTRUCTURING STUDY. Also during 1994, the NYPA issued
a report to its trustees concerning a proposed restructuring
effort for the 21st century. This report stated that a major
step toward a competitive electric industry would be to separate
transmission from generation. It also stated that another
significant advance toward cutting the price of electricity would
be the creation of a single operating company for all six of New
York State's nuclear power plants. In addition, the report
recommends creation of a "New York State Electrical Thruway" that
would combine all of the State's transmission lines into one
independent entity.
The effect on the Company's financial position or results of
operations based on any or all of the above events cannot be
determined at this time.
In summary, the electric and gas utility industry is
undergoing large changes and faces an uncertain future. To
succeed, utilities must be prepared to respond quickly to change.
The Company must be successful in, among other things, helping
to bring about favorable regulatory reform to deal with such
change, managing the economic operation of its nuclear units
and addressing growing electric competition, expanded gas supply
competition, and various cost impacts, especially excess high-cost
unregulated generator power contracts and taxes. While the Company
will seek full recovery of its investment through the rate setting
process with respect to the issues described herein, a review
of political and regulatory actions during the past 15 years with
respect to industry issues and the experiences of virtually every
other industry that has gone through deregulation, indicate that
utility shareholders may ultimately bear a significant portion of
the burden of solving these problems.
COMPANY EFFORTS TO ADDRESS COMPETITIVE CHALLENGES
-------------------------------------------------
In response to these issues being faced by the Company, the
Company has considered, and is continuing to consider, various
strategies designed to enhance its competitive position and to
increase its ability to adapt to and anticipate changes in its
utility business. These strategies may include business
combinations with other companies, acquisitions of related or
unrelated businesses, and additions to or disposition of portions
of its franchised service territories. Additionally, a number of
electric utilities have recently announced consideration of plans
to organize their operations so that generation and power supply
activities are conducted by an entity within the corporate group
separate from the entity which provides transmission and
distribution services to the utility's customers. The Company is
also studying such a division of its operations, in part because
of suggestions by New York governmental officials that power
supply should be separated from transmission and distribution
functions and in part as a means of dealing with issues related
to unregulated generator contracts.
VOLUNTARY EMPLOYEE REDUCTION PROGRAM (VERP). In July 1994,
the Company announced a voluntary early retirement program and a
voluntary separation program (together the VERP) to achieve
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. Later, union employees approved
amendments to the current labor agreement which offered union
employees the VERP, in exchange for a negotiated package of work
rule changes.
Approximately 1,400 active employees elected to participate
in the VERP and most terminated their employment as of October
31, 1994. The number of employees electing the VERP did not meet
management's expectations, and some layoffs have and will
continue to occur in an effort to reach a level of approximately
8,750 regular employees during 1995. At December 31, 1994, the
Company had approximately 9,200 employees. The accrued cost of
the VERP is estimated at approximately $212 million. The Company
decided to reduce 1994 earnings by the cost of the VERP that is
allocable to electric customers, net of allocation to cotenant
and other ventures, or approximately $197 million ($.89 per share).
The Company deferred, for proposed recovery over a five year period
beginning in 1995, the $11 million of VERP costs allocable to
gas customers. In reaching these decisions, the Company
considered, among other things, the impact on future rates of
deferring and recovering these costs.
Most of the VERP cash cost will be provided by pension fund
assets over time, thereby limiting the immediate cash impact
to the Company. The 1995 cash impact will be approximately $20
million, primarily in the first quarter.
In a filing with the PSC on December 23, 1994, the Company
updated its rate request for 1995 to reflect the labor and labor-
related savings in operating costs as a result of the VERP. The
savings are expected to amount to nearly $100 million annually,
of which $60 million in 1995 is the labor and related savings
allocable to electric and gas expense (the remaining savings,
generally allocable to construction, should enable the Company to
achieve its construction spending plans for 1995, which have been
reduced from prior forecasts).
UNREGULATED GENERATOR INITIATIVES are discussed in a
separate section below.
TAX INITIATIVES. The Company has launched a media
initiative to inform customers of how much (approximately 16%) of
their utility bill directly pays various forms of taxes. The
Company is also working with utility and state representatives to
explain the negative impact that all taxes, including the gross
receipts tax, are having on rates and the state of the economy.
At the same time, the Company is contesting with many taxing
authorities the high real estate taxes it is assessed,
particularly compared to the taxes assessed unregulated
generators.
CUSTOMER DISCOUNTS. The Company is experiencing a loss of
industrial load across its system for a variety of reasons. In
some cases, customers have found alternative suppliers or are
generating their own power. In other cases a weakened economy
has forced customers to relocate or shut down.
As a first step in addressing the threat of further loss of
industrial load, the PSC approved a rate (referred to as SC-10)
under which the Company was allowed to negotiate individual
contracts with some of its largest industrial and commercial
customers to provide them with electricity at lower prices.
Under this rate, customers had to demonstrate that they could
generate power more economically than the Company's service.
While the SC-10 tariff has now been superseded by the SC-11
tariff described below, seventeen contracts are still in effect
and expire by early 1997. The total SC-10 discounts amounted to
$12.4 million in 1994.
In June 1994, the PSC announced the adoption of guidelines
to govern flexible electric rates offered by utilities to retain
qualified industrial customers in the face of growing competition
from unregulated generators, and requiring the Company (and other
New York utilities with flexible tariffs) to file amendments to
SC-10. On August 10, 1994, the Company filed for a new service
tariff, SC-11, for "Individually Negotiated Contract Rates." All
new contract rates will be administered under the new SC-11
service classification based on demonstrated industrial and
commercial competitive pricing situations including, but not
limited to, on-site generation, fuel switching, facility
relocation and partial plant production shifting. Contracts will
be for a term not to exceed seven years without PSC approval.
The Company expects a significant number of industrial
customers to negotiate contracts. Many of these contracts may
result in increased load which may be revenue enhancing. As of
December 31, 1994, approximately 20 customers, representing
approximately 80 MW of load, had made requests to the Company for
an SC-11 contract. The Company also offers economic development
rates, which can result in discounts for existing, as well as
new, load. In total, the Company granted $39 million in
discounts against 1994 revenues, of which it absorbed 20%
pursuant to the 1994 Settlement. Under its 1995 and multi-year
rate proposal, the Company anticipates offering approximately $30
million of discounts in excess of the approximately $42 million
expected to be reflected in rates in 1995, although no assurance
can be given as to the actual amount of discounts. The amount of
discounts given will also depend on the level of rates authorized
in the 1995 rate proceeding, and the allocation between customer
classes. The level of discounts beyond 1995 and the attendant
financial consequences will depend on a variety of factors.
The increase in the Company's rates over the past four
years, due in large part to required purchases from unregulated
generators, has made cogeneration and self-generation by many
industrial and large commercial customers more economically
feasible. The Company believes its SC-11 tariff pricing
flexibility will help prevent erosion of its customer base.
Price pressure, however, may limit the recovery of such costs
from the remainder of its customer base.
SITHE/ALCAN. In April 1994, the PSC ruled that, in the
event Sithe Independence Power Partners Inc. (Sithe) ultimately
obtained authority to sell electric power at retail, those retail
sales would be subject to a lower level of regulation than the
PSC presently imposes on the Company. Sithe, which sells
electricity to Consolidated Edison Company of New York, Inc.
and the Company on a wholesale basis from its 1,040
megawatt natural gas cogeneration plant, also provides steam to
Alcan Rolled Products (Alcan). As authorized by the PSC in
September 1994, Sithe also sells a portion of its electricity
output on a retail basis to Alcan, previously a customer of the
Company, and is authorized to sell to Liberty Paperboard
(Liberty), a potential new industrial customer. The PSC ordered
that Sithe pay the Company a fee over a period of ten years,
based upon the prices at which Sithe would sell to Alcan,
structured to produce a net present value of approximately $19.6
million. For 1995, the fee would be approximately $3.05 million.
The Company had argued for compensation, which assures discounted
rates to Alcan, with a net present value of $39 million. The PSC
did not authorize a fee in connection with Sithe's sale to Liberty.
On October 12, 1994, the Company filed an appeal in State
Supreme Court, Albany County, which states that the April 1994
PSC Order is a violation of legal procedure and precedent and
should be reversed. The Company cannot predict the outcome of
this proceeding, but will continue to press its position
vigorously. Notwithstanding the Company's strong opposition to
Sithe's ability to sell to a retail customer, and the level of
compensation involved, the decision to require compensation to
utilities for costs that would otherwise be stranded has
established a precedent in by-pass situations for some level of
recovery of the Company's investment.
ASSET MANAGEMENT STUDIES - FOSSIL. The Company continually
examines its competitive situation and future strategic
direction. Among other things, it has, and continues to, study
the economics of continued operation of its fossil-fueled
generating plants, given current forecasts of excess capacity.
Growth in unregulated generator supply sources, compliance
requirements of the Clean Air Act and low wholesale market prices
are key considerations in evaluating the Company's internal
generation needs. While the Company's coal-burning plants continue
to be cost advantageous, certain older units and certain
gas/oil-burning units are continually assessed to evaluate
their economic value and estimated remaining useful lives.
Due to projected excess capacity, the Company plans to retire
or put certain units in long-term cold standby. A total of 340 MW's
of aging coal fired capacity is to be retired by the end of 1999
and 850 MW's of oil fired capacity was placed in long-term cold
standby in 1994. The Company is also continuing to evaluate under
what circumstances the standby plant would be returned to service,
but barring unforeseen circumstances it is not likely that a
return would occur before the end of 1999. This action will
permit the reduction of operating costs and capital expenditures for
retired and standby plants. The remaining investment in these plants
of approximately $250 million at December 31, 1994 (of which
approximately $180 million relates to the facility in cold
standby) is currently being recovered in rates through
depreciation. See Note 1 of Notes to Consolidated Financial
Statements - "Exposure Draft on Impairment of Assets".
ASSET MANAGEMENT STUDIES - NINE MILE POINT NUCLEAR STATION
UNIT NO. 1 (UNIT 1). Under the terms of a previous regulatory
agreement, the Company agreed to prepare and update studies of
the advantages and disadvantages of continued operation of Unit 1
prior to the start of the then next two refueling outages. The
first report, which recommended continued operation of Unit 1
over the then next fuel cycle, was filed with the PSC in March
1990 and a second study in November 1992 indicated that the Unit
could continue to provide benefits for the term of its license if
operating costs could be reduced and generating output improved
above its then historical average.
Operating experience at Unit 1 has improved substantially since
the 1992 study. Unit 1's capacity factor has been about 94% since
its last refueling outage.
The third study was filed with the PSC on November 1, 1994.
This study agreed with the November 1992 study, confirming
continued operation over the remaining term of its license. No
further economic studies are currently required for this Unit,
although the Company continues as a matter of course to examine
the economic and strategic issues related to operation of all its
generating units.
In connection with these asset management studies, the
Company also updated its estimated costs to decommission Unit 1.
The estimate includes amounts for both radioactive and non-
radioactive dismantlement costs, as well as spent fuel storage
cost estimates until the fuel can be transferred to a permanent
federal repository. The current estimate of radioactive ($344
million) and non-radioactive ($51 million) dismantlement in 1994
dollars is approximately $395 million. Fuel storage and plant
maintenance estimates will increase the total estimated
costs to approximately $527 million (in 1994 dollars), and this
amount escalates to $1.4 billion by the time decommissioning is
completed. While these estimates have increased from previous
estimates, the delayed dismantlement approach is believed to
be the most economic. The new estimates along with increased
estimates for the decommissioning of Nine Mile Point Nuclear
Station Unit No. 2 (Unit 2), will be required to be reflected
in rates in the future. See also Notes 1 and 3 of Notes to
the Consolidated Financial Statements.
REGULATORY AGREEMENTS/PROPOSALS
-------------------------------
1995 FIVE-YEAR RATE PLAN. In February 1994, the Company
made an electric and gas rate filing, for rates to be effective
January 4, 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 included a proposal to institute a
methodology to establish rates beginning in 1996 and running
through 1999. The proposal would provide for rate indexing to an
applicable 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. NERAM (see "Prior Regulatory Agreements" below)
and certain other expense deferrals 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 which are not
within the Company's control would be included in billing
adjustment factors 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 MERIT (see "Prior Regulatory Agreements" below),
NERAM 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 which, if not achieved,
would permit the Company to refile and reset base rates subject
to indexing or to seek some other form of rate relief.
Conversely, in the event earnings exceeded an established maximum
allowed return on equity, such excess earnings would be used to
accelerate recovery of regulatory or other assets. The proposal
would provide the Company with greater flexibility to adjust
prices within customer classes to meet competitive pressures from
alternative electric suppliers, but would also substantially
increase the risk that the Company will not earn its allowed rate
of return and that earnings would be much more volatile than in
the past. The Company believes that its proposed rate plan meets
the criteria for continued application of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation" (SFAS No. 71). Gas rate adjustments
beyond 1995 would follow traditional regulatory methodology.
In 1994, the Company agreed 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 will absorb one-half of the costs
(the lost margin) arising because of the extension from January
4, 1995. The remainder of the costs will 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
recent updated filing described below, the Company would absorb
approximately $41 million.
On August 31, 1994, the PSC Staff, in response to the
Company's proposal, proposed an overall decrease in electric
revenues from 1994 levels of approximately $146 million,
excluding anticipated sales growth. This contrasts with the
Company's original proposed total revenue increase, excluding
sales growth, of $146 million for 1995. Because the Company's
proposed 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 approximately $90 million in
purchased power payments made principally to unregulated
generators; additional adjustments to the 1995 unregulated
generator forecast 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 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 a national average
electricity price, elimination of all of the Company-proposed
adjustment factors outside of indexing, 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 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 certain plant and unregulated generator
costs) that could be charged to customers. The reference price
each year would be based initially upon the Company's marginal
cost of generation (which is significantly below its embedded
cost) until a reliable market price becomes available. After a
10 year phase-down, 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.
Rates with respect to the Company's costs of transmission,
distribution and customer service would continue to be based on
cost of service for 1995, but would be indexed in 1996-1999 by
the national average electricity index.
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. While the PSC Staff identified a number of general
cost reduction measures intended to mitigate the financial
consequences of its proposal, the Company believes the value of
the measures is greatly overstated. 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 ratemaking principles. 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
discontinue the application of SFAS No. 71 and incur substantial
additional writeoffs. Such writeoffs, which would include a
substantial portion of the $1.4 billion of regulatory assets on
the Company's balance sheet as well as the disallowed plant costs
and purchased power costs described above, would arise because of
the departure from cost-based ratemaking and because they would
no longer meet the accounting criteria regarding probability of
recovery. The Company believes the financial consequences to be
of an order of magnitude that would adversely affect the
Company's financial position and results of operations, its
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 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 stated 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 is continuing to
aggressively advocate its own position.
With the December 1994 filing in which the Company proposed
to absorb certain VERP costs and reflect labor and related
savings, the Company updated its rate request and resultant total
bill impact for 1995. The Company is now requesting an increase
in 1995 electric revenues of approximately $89 million (2.8%),
which reflects the delay in implementing new rates, and an
increase in 1995 gas revenues of $20.6 million (3.4%). This
compares with the electric bill impact of approximately 4.3% and
gas revenue increase of 4.1% requested in its original filing.
The difference between the Company's most recent filing and the
PSC Staff's proposal still exceeds $300 million on an annualized
basis.
The current rate proceeding has been separated into two
distinct phases. A final PSC decision on 1995 rates is not
expected until the end of April 1995 and new electric rates would
be implemented about that time along with any final adjustments
to gas rates. A schedule for the multi-year phase of the
proceeding has not been established, but is expected to extend at
least into the summer of 1995.
On January 27, 1995, the Administrative Law Judges (ALJ)
issued a Recommended Decision with respect to the 1995 phase of
the rate proceeding. The Recommended Decision would allow the
Company to increase its electric base rates $253.8 million (7.3%)
for the 1995 rate year and $10.3 million (1.7%) for gas base
rates. The ALJ disallowed from recovery approximately $18
million of unregulated generator costs, but rejected $68 million
of disallowances associated with contracts the PSC Staff believed
should have been bought out. The existing fuel adjustment clause
mechanism would be retained, including full recovery of prudent
unregulated generator payments, until addressed in the multi-year
phase of the proceeding. A number of other adjustments to
unregulated generator purchases relate to timing of in-service
dates, generation levels and pricing, which the Company expects
will be fully considered in the fuel adjustment clause. Finally,
the ALJ stated that sufficient evidence had been produced by the
PSC Staff to warrant a prudence investigation of the Company's
unregulated generator contract practices absent a multi-year rate
plan.
The Recommended Decision reduced the level of departmental
expenses by over $50 million based on the ALJ's assessment of
lack of adequate support for the Company's rate request. The ALJ
also recommended a 1% gross margin penalty to ensure that all of
the benefits that might otherwise inure to the shareholders due
to the ALJ's perceived lack of support are captured for ratepayers.
In addition, the Recommended Decision does not reflect any of
the VERP cost savings, which could be used to further reduce the
annualized electric base rate increase by as much as $55 million,
and the gas base rate increase by $5 million, depending on whether
the Company could demonstrate that several of the ALJs'
recommendations would be duplicated by the VERP cost savings. An
11% return on equity was recommended.
If the Recommended Decision were to be adopted in its
entirety by the PSC, excluding the further reduction in base rate
relief granted for VERP cost savings, the Company expects that
1995 electric revenues would decrease by at least 1% or
approximately $28 million as compared to 1994, although on a
twelve month basis, electric revenues would increase
approximately $57 million or 1.9%. The impact on the Company's
earnings, if the Recommended Decision were to be fully adopted by
the PSC, will depend substantially on the Company's ability to
further reduce costs since little growth in sales is forecast.
Without further cost reductions, which must be judged relative to
costs under the Company's direct control, earnings for 1995 will
be considerably lower than 1994 earnings adjusted for VERP. If
the unregulated generator disallowances were adopted by the PSC,
the Company would be required to assess whether a loss associated
with these contracts, measured by the net present value of
unrecoverable costs over the remaining term of the contracts,
would be recorded in 1995. Using projections of long-run avoided
costs, the recordable loss could exceed $100 million.
While the adoption of the PSC Staff's proposals or the
Recommended Decision by the PSC would have a material adverse
impact on the Company's 1995 results of operations, 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 any transition plan to a more
competitive environment must provide for an equitable allocation
of transition costs across customer classes. In addition, the
Company believes that any transition to a more competitive rate
structure should be addressed in a generic proceeding rather than
the Company's current multi-year rate filing. The ultimate
impact on the Company's financial condition will depend on the
pace of change in the marketplace, the actions of regulators and
government 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 effects of the interaction of
these factors.
PRIOR REGULATORY AGREEMENTS. The Company's results during
the past several years have been strongly influenced by several
agreements with the PSC. A brief discussion of the key terms of
certain of these agreements is provided below.
The 1991 Financial Recovery Agreement implemented the
Niagara Mohawk Electric Revenue Adjustment Mechanism (NERAM) and
the Measured Equity Return Incentive Term (MERIT).
The NERAM requires the Company to reconcile actual results
to forecast electric public sales gross margin used in
establishing rates. The NERAM produces certainty in the amount
of electric gross margin the Company will receive in a given
period to fund its operations. While reducing risk during
periods of economic uncertainty and mitigating the variable
effects of weather, the NERAM does not allow the Company to
benefit from unforeseen growth in sales. The Company's 1995 and
multi-year rate proceedings do not seek to extend the NERAM in
view of the pricing flexibility sought, although, the separation
of the 1995 phase of the case may present some opportunity to
extend this mechanism. The lack of a NERAM will inevitably
increase earnings volatility due to variations in weather and
economic conditions. In 1994, the Company deferred for recovery
$101.2 million of revenue under the NERAM mechanism for
collection in 1995 and 1996.
The MERIT program is the incentive mechanism which
originally allowed the Company to earn up to $180 million of
additional return on equity through May 31, 1994. The program
was later amended to extend the performance period through 1995
and add $10 million to the total available award. Overall goal
targets and criteria for the 1993-1995 MERIT periods are
results-oriented and are intended to measure change in key
overall performance areas. The total available award for 1994
is $34 million and $41 million in 1995. Through the 1993 MERIT
period, the Company has earned approximately $85.5 million of
the $115 million of MERIT available and presently assesses that it
earned approximately $28 million of the $34 million available for
1994.
On January 27, 1993, the PSC approved a 1993 Rate Agreement
authorizing a 3.1% increase in the Company's electric and gas
rates providing for additional annual revenues of $108.5 million
(electric $98.4 million or 3.4%; gas $10.1 million or 1.8%).
Retroactive application of the new rates to January 1, 1993 was
authorized by the PSC.
The increase reflected an allowed return on equity of 11.4%,
as compared to the 12.3% authorized for 1992. The agreement also
included extension of the NERAM through December 1993 and
provisions to defer expenses related to mitigation of unregulated
generator costs, (aggregating $50.7 million at December 31, 1993)
including contract buyout costs and certain other items.
The Company and the local unions of the International
Brotherhood of Electrical Workers, agreed on a two-year nine-
month labor contract effective June 1, 1993. The new labor
contract includes general wage increases of 4% on each June 1st
through 1995 and changes to employee benefit plans including
certain contributions by employees. Agreement was also
reached concerning several work practices which should result in
improved productivity and enhanced customer service. The PSC
approved a filing resulting from the union settlement and
authorized $8.1 million in additional revenues ($6.8 million
electric and $1.3 million gas) for 1993.
On February 2, 1994, the PSC approved an increase in gas
rates of $10.4 million or 1.7%. The gas rates became effective
as of January 1, 1994 and include for the first time a weather
normalization clause.
The PSC also approved the Company's electric supplement
agreement with the PSC Staff and other parties to extend certain
cost recovery mechanisms in the 1993 Rate Agreement without
increasing electric base rates for calendar year 1994. The goal
of the supplement was to keep total electric bill impacts for
1994 at or below the rate of inflation. Modifications were made
to the NERAM and MERIT provisions which determine how these
amounts are to be distributed to various customer classes and
also provided for the Company to absorb 20% of margin variances
(within certain limits) originating from SC-10 rate discounts (as
described above) and certain other discount programs for
industrial customers as well as 20% of the gross margin variance
from NERAM targets for industrial customers not subject to
discounts. The supplement also allows the Company to begin
recovery over three years of approximately $15 million of
unregulated generator buyout costs, subject to final PSC
determination with respect to the reasonableness of such costs.
UNREGULATED GENERATORS
----------------------
In recent years, a leading factor in the increases in
customer bills and the deterioration of the Company's competitive
position has been the requirement to purchase power from
unregulated generators at prices in excess of the Company's
internal cost of production and in volumes greater than the
Company's needs.
The Company is being forced to make excess payments to
unregulated generators, in comparison with its own costs of
production, for energy and capacity it does not currently need.
The Company estimates that it made excess payments of
approximately $205 million in 1993 and approximately $330 million
in 1994 and expects to make excess payments of approximately $400
million in 1995. The Company has initiated a series of actions
to address this situation, but cannot predict the outcome.
Recent changes in state leadership may change the energy policies
of New York State. The Company will be pursuing actions to
redress inequities and reform regulatory policies that have
contributed to the Company's increasing prices.
As of December 31, 1994, 148 of these unregulated generators
with a combined capacity of 2,592 MW were on line and selling
power to the Company. Of these, 2,273 MW are considered firm
capacity (including 207 MW of unregulated generator projects on
standby). The following table illustrates the actual and
estimated growth in capacity, payments and relative magnitude of
unregulated generator purchases compared to Company requirements:
Actual Estimated
1991 1992 1993 1994 1995 1996 1997 1998 1999
Capacity MW's 1,027 1,549 2,253 2,273 2,403 2,403 2,403 2,413 2,413
Payments
(millions) $ 268 $ 543 $ 736 $ 960 $1,041 $1,091 $1,152 $1,213 $1,262
Percent of Total
Fuel and
Purchased Power
Costs 32% 56% 67% 73%
/TABLE
By the end of 1994, the Company had virtually all
unregulated generator capacity scheduled to come into service on
line.
In order to deal with the growth of excess supply, the
Company has taken numerous actions to attempt to realign its
supply with demand. These actions include mothballing and
retirement of Company owned generating facilities (see "Asset
Management Studies - Fossil") and buyouts of unregulated
generator projects, as well as the implementation of an
aggressive wholesale marketing effort. Such actions have been
successful in bringing installed capacity reserve margins down to
levels in line with normal planning criteria. The Company is
actively pursuing other initiatives to reduce its unregulated
generator costs.
FERC PROCEEDING. On January 11, 1995, the FERC issued an
order in a case involving Connecticut Light & Power (CL&P) that the
Public Utility Regulatory Policy Act (PURPA) forbids the states
from requiring utilities to pay more than avoided cost to qualifying
facilities (QFs) for electric power. FERC, however, also ruled that
it would not invalidate any pre-existing contracts, but only would
apply its ruling prospectively or to contracts that are subject to
a pending challenge (instituted at the time of signing) by a
utility. On the same day, FERC issued an order that an ongoing
challenge by the Company to the New York law requiring utilities to
pay QFs a minimum of six cents for electric power (the "Six Cent
Law") was moot in light of amendment of that law in 1992 to prohibit
future power purchase contracts requiring the utility to pay more
than its avoided cost. This latter proceeding had been filed in
1987. In April 1988, FERC had ruled in the Company's favor, finding
that the states could not impose rates exceeding avoided cost for
purchases from QFs, but then stayed that decision in light of a
rulemaking it was instituting to address the issue. That rulemaking
was never completed.
On February 10, 1995, the Company filed a petition for rehearing
of both orders. The Company argues, among other things, that Federal
law requires that FERC apply the ruling in CL&P in all pending cases,
including its case involving the Six Cent Law, and that it is entitled
to the opportunity, either at FERC or in the courts, to demonstrate
that pre-existing power purchase contracts resulting from the Six Cent
Law should be invalidated. The Company argues further that amendment
of the Six Cent Law did not render the proceeding addressing that law
moot because the amendment has perpetuated and, in some instances,
expanded the Company's obligation to purchase power from QFs at rates
above avoided cost. The Company intends to press its rights
vigorously, but cannot predict the outcome of these proceedings.
CURTAILMENT PROCEDURES. On August 18, 1992, the Company
filed a petition with the PSC which calls for the implementation
of "curtailment procedures." Under existing FERC and PSC policy,
this petition would allow the Company to limit its purchases from
unregulated generators when demand is low. Also, the Company has
commenced settlement discussions with certain unregulated
generators regarding curtailments. On April 5, 1994, after
informing the PSC of its progress in settlement, the Company
requested the PSC to expedite the consideration of its petition.
The Company cannot predict the outcome of this action.
DEMAND FOR ADEQUATE ASSURANCE. On February 4, 1994, the
Company notified the owners of nine projects with contracts that
provide for front-end loaded payments of the Company's demand for
adequate assurance that the owners will perform all of their
future repayment obligations, including the obligation to deliver
electricity in the future at prices below the Company's avoided
cost and the repayment of any advance payment balance which
remains outstanding at the end of the contract.
The projects at issue total 426 MW. The Company's demand is
based on its assessment of the amount of advance payment to be
accumulated under the terms of the contracts, future avoided
costs, and future operating costs of the projects. The Company
has been sued by the owners of three unregulated generator
projects who challenge the Company's right to demand adequate
assurance.
The Company cannot predict the outcome of these federal and
state court actions or the response otherwise to its February 4,
1994 notifications, but will continue to press for adequate
assurance that the owners of these projects will honor their
repayment obligations.
RESULTS OF OPERATIONS
---------------------
Earnings for 1994 were $143.3 million or $1.00 per share
compared with $240.0 million or $1.71 per share in 1993 and
$219.9 million or $1.61 per share in 1992. The decline in 1994
earnings was principally due to the charge to earnings of the
cost of the VERP of $197 million ($.89 per share). NERAM
equivalent to $101.2 million ($.46 per share) was recorded in
1994 and deferred for future recovery in rates as compared to NERAM
of $65.7 million ($.31 per share) recorded in 1993. The primary
factor contributing to the increase in earnings in 1993 as
compared to 1992 was the impact of electric and gas rate
increases effective January 1, 1993 and July 1, 1992.
In 1994, the Company's earned return on common equity was
5.8%, but without the VERP charge would have been 10.7%, compared
to 10.2% in 1993 and 10.1% in 1992. The Company's return on
common equity authorized in the rate setting process for the year
ended December 31, 1994, provided an electric return on equity
cap of 11.4% and a return on equity cap for gas of 10.4%.
Factors contributing to the earnings being below authorized
levels in 1993 included lower than anticipated results from the
Company's subsidiaries, certain operating expenses which were not
included in rates and exclusion of approximately $23 million from
the Company's rate base (upon which the Company would otherwise earn
a return) as a consequence of prior year write-offs of disallowed
Unit 2 costs.
The following discussion and analysis highlights items
having a significant effect on operations during the three-year
period ended December 31, 1994. It may not be indicative of
future operations or earnings. It also should be read in
conjunction with the Notes to Consolidated Financial Statements
and other financial and statistical information appearing
elsewhere in this report.
ELECTRIC REVENUES increased $621.7 million or 21.4% over the
three-year period. This increase results primarily from rate
increases, NERAM revenues, higher recoveries through the
operation of the fuel adjustment clause mechanism, increased
sales to other electric systems and other factors as indicated in
the table below. An increase in the base cost of fuel, (which is
included in base rates), would typically result in a
corresponding decrease in fuel and purchased power cost revenues,
thus having a revenue neutral impact. Purchased power costs,
largely from unregulated generators, have increased significantly
during this period, offsetting much of the decrease in Fuel
Adjustment Clause (FAC) revenues which would have occurred
otherwise.
Increase (decrease) from prior year
(In millions of dollars)
Electric revenues 1994 1993 1992 Total
Increase in base rates. . . . . . . . . . . . $ 36.0 $193.1 $250.6 $479.7
Fuel and purchased power cost revenues. . . . 108.3 (42.6) (6.4) 59.3
Sales to ultimate consumers . . . . . . . . . (13.6) 11.0 39.7 37.1
Sales to other electric systems . . . . . . . 62.1 11.7 (12.8) 61.0
DSM revenue . . . . . . . . . . . . . . . . . (27.7) (30.3) (24.3) (82.3)
Miscellaneous operating revenues. . . . . . . (4.6) 23.9 (11.3) 8.0
NERAM revenues. . . . . . . . . . . . . . . . 35.5 24.0 7.8 67.3
MERIT revenues. . . . . . . . . . . . . . . . 0.5 (6.0) (2.9) (8.4)
$196.5 $184.8 $240.4 $621.7
/TABLE
Although sales to ultimate customers increased slightly in
1994, this level of sales was substantially below the forecast
used in establishing rates for the year. As a result, the
Company accrued NERAM revenues of $101.2 million ($.46 per share)
during 1994 as compared to $65.7 million ($.31 per share) of
NERAM revenues in 1993. NERAM would no longer be available under
the new rate plan as originally proposed by the Company, thus
creating exposure for lost margin if sales forecasts are not met.
The sales forecast underlying the Company's 1995 rate request
reflects an increase in kwh sales of .5% over 1994 actual
results. The Company recorded $12.3 million of the 1994 MERIT
available based on management's assessment of the achievement of
objectively measured criteria.
Changes in fuel and purchased power cost revenues are
generally margin-neutral (subject to an incentive mechanism
discussed in Note 1 of Notes to Consolidated Financial
Statements), while sales to other utilities, because of
regulatory sharing mechanisms and relatively low prices due to
excess supply, generally result in low margin contribution to the
Company. Thus, fluctuations in these revenue components do not
generally have a significant impact on net operating income. The
Company has proposed certain changes in the fuel adjustment
clause in its 1995 and multi-year rate proposal (discussed above
under "1995 Five-Year Rate Plan"). Electric revenues reflect the
billing of a separate factor for DSM programs, which provide for
the recovery of program related rebate costs and a Company
incentive based on 10% of total net resource savings.
ELECTRIC KILOWATT-HOUR SALES were 41.6 billion in 1994, an
increase of 10.3% from 1993 and an increase of 13.6% over 1992.
The 1994 increase reflects increased sales to other electric
systems, while sales to ultimate consumers were generally flat.
The increase in wholesale sales reflects the increase in
purchases from unregulated generators and the increase in nuclear
production, both of which enabled the Company to make its fossil
generation available for sale. The 1993 increase reflected
increased sales to other electric systems, while sales to
ultimate customers increased slightly (See Electric and Gas
Statistics - Electric Sales). The electric margin effect of
sales in 1994 was adjusted by the NERAM except for the large
industrial customer class, within which the Company absorbed 20%
of the variance from the NERAM sales forecast. Industrial-
Special sales are New York State Power Authority allocations of
low-cost power to specified customers, from which the Company
earns a transportation charge.
Details of the changes in electric revenues and kilowatt-
hour sales by customer group are highlighted in the table below:
1994 % Increase (decrease) from prior years
% of
Electric 1994 1993 1992
Class of service Revenues Revenues Sales Revenues Sales Revenues Sales
Residential 34.9% 5.2% (0.6)% 6.9% 0.8% 11.3% 0.7%
Commercial 36.1 2.5 (2.2) 7.0 3.9 11.1 (0.5)
Industrial 16.4 4.3 5.0 (6.0) (5.2) 13.0 (1.3)
Industrial-Special 1.4 14.5 5.9 9.1 .8 11.8 1.9
Municipal service 1.4 (1.3) (2.3) .6 (3.1) 5.8 (0.4)
Total to ultimate consumers 90.2 3.9 0.8 4.3 0.5 11.4 0.0
Other electric systems 4.7 59.1 91.1 12.6 31.2 (12.1) (3.5)
Miscellaneous 5.1 8.2 - 40.6 - (29.0) -
Total 100.0% 5.9% 10.3% 5.9% 3.0% 8.3% (0.3)%
/TABLE
As indicated in the table below, internal generation from
fossil fuel sources continued to decline in 1994, principally at
the Oswego oil-fired facility and Albany gas-fired station,
corresponding to the increase in required unregulated generator
purchases. There were no nuclear refueling outages in 1994,
while both Units were refueled in 1993. Unit 1 operated at a
capacity factor of approximately 92% for 1994, while Unit 2
operated at approximately 90%. The next nuclear refueling
outages at each unit are scheduled for 1995 (See Note 3 - Nuclear
Operations).
% Change from prior year
1994 1993 1992 1994 to 1993 1993 to 1992
Fuel for electric
generation:
(in millions of dollars)
GwHrs. Cost GwHrs. Cost GwHrs. Cost GwHrs. Cost GwHrs. Cost
Coal 6,783 $ 107.3 7,088 $ 113.0 8,340 $128.8 (4.3)% (5.0)% (15.0)% (12.3)%
Oil 1,245 40.9 2,177 74.2 3,372 106.6 (42.8) (44.9) (35.4) (30.4)
Natural gas 700 16.1 548 12.5 1,769 44.6 27.7 28.8 (69.0) (72.0)
Nuclear 8,327 49.5 7,303 43.3 5,031 28.9 14.0 14.3 45.2 49.8
Hydro 3,485 - 3,530 - 3,818 - (1.3) - (7.5) -
20,540 213.8 20,646 243.0 22,330 308.9 (0.5) (12.0) (7.5) (21.3)
Electricity
purchased:
Unregulated
generators 14,794 960.1 11,720 735.7 8,632 543.0 26.2 30.5 35.8 35.5
Other 10,382 140.3 9,046 118.1 8,917 115.7 14.8 18.8 1.5 2.1
25,176 1,100.4 20,766 853.8 17,549 658.7 21.2 28.9 18.3 29.6
Total generated and
purchased 45,716 1,314.2 41,412 1,096.8 39,879 967.6 10.4 19.8 3.8 13.4
Fuel adjustment
clause - 12.7 - (2.2) - 6.0 - (677.3) - (136.7)
Losses/Company use 4,117 - 3,688 - 3,268 - 11.6 - 12.9 -
41,599 $1,326.9 37,724 $1,094.6 36,611 $973.6 10.3% 21.2% 3.0% 12.4%
/TABLE
Gas revenues increased $148.0 million, or 31.1%, over the
three-year period. As shown by the table below, this increase is
primarily attributable to increased sales to ultimate customers
and increased base rates and gas adjustment clause recoveries.
In 1994, spot market sales declined because the abundance and
price of spot gas made it more difficult to earn sufficient
margin on these sales. Spot market sales are generally the
higher priced gas available and sold in the wholesale market and
yield margins substantially lower than traditional sales to
ultimate customers. Rates for transported gas also yield lower
margins than gas sold directly by the Company and, therefore,
increases in the volume of gas transportation services have not
had a proportionate impact on earnings. Changes in purchased gas
adjustment clause revenues are generally margin-neutral.
Increase (decrease) from prior
year
(In millions of dollars)
Gas revenues 1994 1993 1992 Total
Increase in base rates. . . . . . . . . . . $ 7.1 $ 7.3 $ 4.7 $ 19.1
Transportation of customer-owned gas. . . . 3.5 (9.7) 6.3 0.1
Purchased gas adjustment clause revenues. . 7.7 12.2 12.5 32.4
Spot market sales . . . . . . . . . . . . . (25.4) 27.2 2.6 4.4
MERIT revenues. . . . . . . . . . . . . . . (1.3) (0.4) (0.3) (2.0)
Miscellaneous operating revenues. . . . . . 7.6 (4.6) - 3.0
Sales to ultimate consumers and other sales 23.0 15.1 52.9 91.0
$ 22.2 $ 47.1 $ 78.7 $148.0
/TABLE
GAS SALES, excluding transportation of customer-owned gas
and spot market sales, were 85.6 million dekatherms in 1994, a
2.9% increase from 1993 and an 8.1% increase from 1992 (See
Electric and Gas Statistics - Gas Sales). The increase in 1994
includes a 2.9% increase in residential sales, a 8.6% increase in
commercial sales, both of which were strongly influenced by
weather, and a 28.2% decrease in industrial sales. The gas
weather normalization clause had an effective date of February
12, 1994, was not ordered to be implemented on a retroactive
basis and, therefore, did not have a significant impact on gas
revenues. The Company has added approximately 30,000 new
customers since 1991, primarily in the residential class, an
increase of 6.2%, and expects a continued increase in new
customers in 1995. During 1993, there also was a shift from the
transportation sales class to the industrial sales class,
corresponding with the implementation of a stand-by industrial
rate.
In 1994, the Company transported 85.9 million dekatherms (a
significant increase from 1993) for customers purchasing gas
directly from producers, and expects a continued increase in such
transportation volumes in 1995, leading to a forecast increase in
total gas deliveries in 1995 of approximately 18% above 1994.
Public sales are expected to increase approximately 2%. Factors
affecting these forecasts include the economy, the relative price
differences between oil and gas in combination with the relative
availability of each fuel, the expanded number of cogeneration
projects served by the Company and increased marketing efforts.
Changes in gas revenues and dekatherm sales by customer group are
detailed in the table below:
1994 % Increase (decrease) from prior years
% of
Gas 1994 1993 1992
Class of service Revenues Revenues Sales Revenues Sales Revenues Sales
Residential 63.9% 7.5% 2.9% 4.6% 1.8% 17.0% 12.0%
Commercial 25.5 9.9 8.6 9.2 6.5 16.6 10.2
Industrial 2.4 (21.0) (28.2) 84.8 143.6 18.6 (2.2)
Total to ultimate consumers 91.8 7.1 2.9 7.4 6.4 16.9 11.1
Other gas systems 0.2 8.7 4.3 (77.5) (80.3) (32.0) (21.7)
Transportation of
customer-owned gas 6.1 10.1 26.8 (18.5) 2.9 17.2 30.0
Spot market sales 0.7 (85.3) (88.1) 1,056.1 1,053.8 - -
Miscellaneous 1.2 423.3 - (79.4) - 0.4 -
Total 100.0% 3.7% 5.4% 8.5% 12.3% 16.5% 19.5%
/TABLE
The total cost of gas purchased decreased 3.2% in 1994,
while increasing 13.6% in 1993 and 16.1% in 1992. The cost
fluctuations generally correspond to sales volume changes,
particularly in 1993, as spot market sales activity increased.
The Company sold 1.6 and 13.2 million dekatherms on the spot
market in 1994 and 1993, respectively. In 1993, this activity
accounted for two-thirds of the 1993 purchased gas expense
increase. The purchased gas cost increase associated with
purchases for ultimate consumers in 1994 resulted from a 1.5%
increase in dekatherms purchased, coupled with a .9% increase in
rates charged by suppliers and an increase of $6.4 million in
purchased gas costs and certain other items recognized and
recovered through the purchased gas adjustment clause. Gas
purchased for spot market sales decreased $24.4 million in 1994
and increased $25.8 million in 1993. The purchased gas cost
increase associated with purchases for ultimate consumers in 1993
resulted from a 8.7% increase in dekatherms purchased, combined
with a 2.1% increase in rates charged by suppliers, offset by a
$17.8 million decrease in purchased gas costs and certain other
items recognized and recovered through the purchased gas
adjustment clause. The Company's net cost per dekatherm
purchased for sales to ultimate consumers increased to $3.44 in
1994 from $3.34 in 1993 and was $3.47 in 1992.
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 fuel adjustment
clause provides for partial pass-through of fuel and purchased
power cost fluctuations from those forecast in rate proceedings,
with the Company absorbing a portion of increases or retaining a
portion of decreases to a maximum of $15 million per rate year.
While the amounts absorbed in 1992 and 1993 were not material,
the Company retained the maximum benefit of $15 million in 1994.
OTHER OPERATION EXPENSE decreased in 1994 by 8.1%, as
compared to increases of 9.8% in 1993 and 5.9% in 1992. The 1994
decrease relates primarily to decreases in nuclear costs
associated with the Unit 1 and Unit 2 refueling outages in 1993
($27 million) and the decrease in amortization of regulatory
deferrals ($49 million) which expired in 1993. The 1993 increase
is due to an increase in DSM program expenses, nuclear expenses
related to increased production along with refueling outages at
Unit 1 and Unit 2, amortization of regulatory assets deferred in
prior years, increased recognition of other post-retirement
benefit costs and inflation.
MAINTENANCE EXPENSE decreased 14.2% in 1994 as compared to
an increase of 4.5% in 1993, principally due to nuclear expenses
incurred during the 1993 refueling outages at Unit 1 and Unit 2
($19 million).
DEPRECIATION AND AMORTIZATION expense for 1994 and 1993
increased 11.5% and 0.9%, respectively. The increase is
attributable to the completion of required improvements to plant
into service during late 1993 and early 1994.
NET FEDERAL AND FOREIGN INCOME TAXES for 1994 decreased due
to lower pre-tax income. In 1993 the decrease was due to the tax
benefit derived from the Company's Canadian subsidiary upon the
sale of its oil and gas investments. The increase in OTHER TAXES
in the three-year period is due principally to higher revenue-
based taxes ($36 million) combined with higher property taxes
($28 million).
OTHER ITEMS, NET, excluding Federal income taxes and
allowance for funds used during construction (AFC), increased
$8.0 million in 1994 and increased $23.4 million in 1993. The
1994 increase primarily related to increased earnings of
subsidiaries which included a nonrecurring gain on
the sale of an investment for $9 million. The 1993 increase was
the effect of the recording in 1992 of a $45 million reserve
against the carrying value of Canadian subsidiary oil and gas
reserves. The sale of the Company's subsidiary, HYDRA-CO
Enterprises, Inc. (HYDRA-CO), will be recorded in the first
quarter of 1995 as the sale was completed in January 1995 and did
not affect 1994 earnings. HYDRA-CO's earnings for the three
years ended December 31, 1994 were not material.
Net INTEREST CHARGES decreased $5.5 million in 1994 and $9.3
million in 1993, as the result of the first mortgage bond
refinancing program that began in 1992 and based on existing
market conditions is now complete. Dividends on preferred stock
increased $1.8 million in 1994 due to the issuance of $150 million
of preferred stock in August 1994, while decreasing $4.7 million
and $3.9 million in 1993 and 1992, respectively, because of
reductions in the average amounts of stock outstanding. The
weighted average long-term debt interest rate and preferred
dividend rate paid, reflecting the actual cost of variable rate
issues, changed to 7.79% and 6.84%, respectively, in 1994, from
7.97% and 6.70%, respectively, in 1993, and from 8.29% and 7.04%,
respectively, in 1992.
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 from the present. 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 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 assets with identical ones 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 current cost of providing
service. 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, 1994 was
52.3% long-term debt, 8.7% preferred stock and 39.0% common
equity, as compared to 54.6%, 6.5% and 38.9%, respectively, at
December 31, 1993. Book value of the common stock was $17.06 per
share at December 31, 1994, as compared to $17.25 per share at
December 31, 1993, reflecting the charge to earnings of the VERP
and the payment of dividends in 1994. Market analysts have
observed that the Company's low market to book ratio, 83.5% at
December 31, 1994, stems from the adverse effects of New York
State's economy and regulatory attitudes, as well as
uncertainties about the pace of regulatory change, which could
result in increased competition and reduced prices. These
adverse effects and uncertainties, coupled with high embedded
costs of the Company due principally to unregulated generators
and taxes, may make the Company more vulnerable than some other
traditional utilities.
The 1994 ratio of earnings to fixed charges was 1.91.
Without the VERP charge, the ratio would have been 2.54. The
ratios of earnings to fixed charges for 1993 and 1992 were 2.31
and 2.24, respectively.
Firms which publish securities ratings have begun to impute
certain items into the Company's interest coverage calculations
and capital structure, the most significant of which is the
inclusion of a "leverage" factor for unregulated generator
contracts. These firms believe that the financial structure of
the unregulated generators (which typically have very high debt-
to-equity ratios) and the character of their power purchase
agreements increase the financial risk of utilities. The
Company's reported interest coverage and debt-to-equity ratios
have recently been discounted by varying amounts for purposes of
establishing credit ratings. Because of existing commitments for
unregulated generator purchases, the imputation has had and will
continue to have a materially negative impact on the Company's
financial ratings.
At present, sales of preferred stock are not possible and
sales of common stock, which would cause substantial dilution to
current shareholders, are financially inadvisable.
CONSTRUCTION AND OTHER CAPITAL REQUIREMENTS
-------------------------------------------
The Company's total capital requirements consist of amounts
for the Company's construction program, working capital needs,
maturing debt issues and sinking fund provisions on preferred
stock. Annual expenditures for the years 1992 to 1994 for
construction and nuclear fuel, including related AFC and
overheads capitalized, were $502.2 million, $519.6 million and
$490.1 million, respectively.
The 1995 estimate for construction additions, including
overheads capitalized, nuclear fuel and AFC, is approximately
$380 million, and is expected to be funded by cash provided from
operations. Mandatory debt and preferred stock retirements and
other requirements are expected to add approximately another $77
million (expected to be refinanced from external sources) to the
Company's capital requirements, for a total of $ 457 million.
Current estimates of total capital requirements for the years
1996 to 1999 are $475, $408, $480 and $566 million, respectively,
of which $406, $358, $410 and $358 million relates to expected
construction additions. The estimate of construction additions
included in capital requirements for the period 1996 to 1999 will
be reviewed by management during 1995 with the objective of
further reducing these amounts where possible.
The provisions of the Clean Air Act Amendments of 1990
(Clean Air Act) are expected to have an impact on the Company's
fossil generation plants during the period through 2000 and
beyond. The Company has evaluated options for compliance with
Phase I of the Clean Air Act, which becomes effective on May 31,
1995 and continues through 1999. The Company spent approximately
$32 and $19 million in 1994 and 1993, respectively, and has
included $6 million for Phase I in its construction forecast for
1995 through 1999 to make combustion modifications at its fossil
fired plants, including the installation of low NOx burners at
the Dunkirk and Huntley plants. With respect to Phase II,
preliminary estimates for compliance anticipate approximately $17
million in capital costs. The Company anticipates that
additional expenditures of approximately $70 million may be
necessary for Phase III to be incurred beyond 2000. The asset
management studies, described above, include Phase I, II and III
estimates for Clean Air Act compliance.
LIQUIDITY AND CAPITAL RESOURCES
-------------------------------
Cash flows to meet the Company's requirements for operating,
investing and financing activities during the past three years
are reported in the Consolidated Statements of Cash Flows.
During 1994, the Company raised approximately $553.9 million
from external sources, consisting of $325.7 million of First
Mortgage Bonds, $150 million of Preferred Stock, $29.5 million of
common stock and a net increase of $48.7 million of short and
intermediate term debt. The proceeds of the $325.7 million of
First Mortgage Bonds were used to provide for the early
redemption of approximately $315.7 million of higher coupon First
Mortgage Bonds. The Company also retired $190 million of First
Mortgage Bonds that matured during 1994.
During January 1995, the Company completed the sale of its
wholly-owned subsidiary, HYDRA-CO. Enterprises, Inc. Net cash
proceeds of approximately $200 million were used to reduce short-
term debt which aggregated over $400 million at December 31,
1994.
External financing for 1995 is projected to consist of $400
to $600 million of First Mortgage Bonds depending upon the final
outcome of the current rate proceeding discussed above. The
Company's ability to issue more common stock to improve its
capital structure is limited by the uncertainties that have
depressed the stock's price. The Company would not likely pursue
a new issue offering unless the common stock price was closer to
book value.
Depending on the outcome of the multi-year rate case
discussed above, cash provided by operations is generally
expected to provide sufficient funds for the Company's
anticipated construction program for 1996 to 1999. External
financing plans are subject to periodic revision as underlying
assumptions are changed to reflect developments, most importantly
in its rate proceedings. The ultimate level of financing during
this four year period will reflect, among other things, the
extent and timing of rate relief, the Company's competitive
positioning and the extent to which competition penetrates the
Company's markets, uncertain energy demand due to economic
conditions and capital expenditures relating to distribution and
transmission load reliability projects, as well as continued
expansion of the gas business. Environmental standards compliance
costs, the effects of rate regulation and various regulatory
initiatives, the level of internally generated funds and
dividend payments, the availability and cost of capital and
the ability of the Company to meet its interest and preferred
stock dividend coverage requirements, to satisfy legal
requirements and restrictions in governing instruments and to
maintain an adequate credit rating, also will impact the amount
and type of future external financing.
The Company has initiated a ten to fifteen year site
investigation and remediation program that seeks a) to identify
and remedy environmental contamination hazards in a proactive and
cost-effective manner and b) to ensure financial participation by
other responsible parties. The Company is currently aware of 89
sites with which it has been or may be associated, including 47
which are Company-owned. With respect to non-owned sites, the
Company may be required to contribute some proportionate share of
remedial costs.
The Company has accrued a minimum liability of $240 million
at December 31, 1994 for its estimated liability for
investigation and remediation of certain Company-owned and
Company-associated hazardous waste sites, which represents the low
end of a range of estimates developed from the Company's ongoing
site investigation and remediation program. The potential high
end of the range is presently estimated at approximately
$1 billion, including approximately $500 million in the unlikely
event the Company were required to assume 100% responsibility at
non-owned sites.
The Company believes that costs incurred in the
investigation and remediation process are recoverable in the
ratesetting process as currently in effect. (See Note 9 of Notes
to Consolidated Financial Statements under "Environmental
Contingencies"). Rate agreements since 1991 have included a
recovery mechanism and an annual allowance for costs expected to
be incurred for waste site investigation and remediation. The
recovery mechanism provides that expenditures over or under the
allowance be deferred for future rate consideration. The Company
does not expect these costs to impact external financing,
although any such impact is dependent upon the timing of
expenditures and associated recovery.
The Nuclear Regulatory Commission (NRC) requires owners of
nuclear power plants to place funds associated with
decommissioning activities for contaminated portions of nuclear
facilities into an external trust. Further, the NRC established
guidelines for determining minimum amounts that must be available
in the trust for these specified decommissioning activities at
the time of decommissioning. Applying the NRC guidelines, the
Company has estimated that the minimum requirements for Unit 1
and its share of Unit 2, respectively, will be $381 million and
$173 million in 1994 dollars. The Company is seeking an increase
in its rate allowance for Unit 1 and Unit 2 decommissioning in
its rate case for 1995 to reflect new NRC minimum requirements.
Amounts collected for the NRC minimum are being placed in an
external trust. (See Note 3 of Notes to Consolidated Financial
Statements under "Nuclear Plant Decommissioning").
The Company believes that traditionally available sources of
financing should be sufficient to satisfy the Company's external
financing needs during the period 1995 through 1999. As of
December 31, 1994, the Company could issue an additional $2,351
million aggregate principal amount of First Mortgage Bonds. This
includes approximately $1,311 million from retired bonds without
regard to an interest coverage test and approximately $1,040
million supported by additional property currently certified and
available, assuming a 10% interest rate, under the applicable
tests set forth in the Company's mortgage trust indenture. The
Company also has $200 million of Preference Stock authorized for
sale. The Company will continue to explore and use, as
appropriate, other methods of raising funds.
Ordinarily, construction related short-term borrowings are
refunded with long-term securities on a regular basis. This
approach generally results in the Company showing a working
capital deficit. Working capital deficits also may be
temporarily created because 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's accounts receivable increased 23% over 1993,
due primarily to the effects of economic conditions in the Company's
service territory. A focus on the Company's new centralized
collections function will be to improve receivable collections
in 1995.
The Company has had sufficient borrowing capacity to fund
such a working capital deficit as necessary. Bank credit
arrangements which, at December 31, 1994, totaled $580 million
are used by the Company to enhance flexibility as to the
type and timing of its long-term security sales. Of the $580
million total available, $200 million is represented by a
Revolving Credit Agreement which expires in 1997. The remainder
of the arrangements are subject to review by the lenders on an
ongoing basis with interest rates negotiated at the time of use.
In 1994, the Company also obtained $161 million in bank loans,
which will expire in 1995 and which the Company expects to renew.
The Company's charter restricts the amount of unsecured
indebtedness that may be incurred by the Company to 10% of
consolidated capitalization plus $50 million. The Company has
not reached this restrictive limit.
The Company's securities ratings at December 31, 1994, were:
Secured Preferred Commercial
Debt Stock Paper
Standard & Poors Corporation *BBB- BB+ A-3
Moody's Investors Service Baa2 *baa3 P-2
Duff & Phelps BBB *BBB- Not applicable
Fitch Investors Service BBB *BBB- Not applicable
* Lowest investment grade rating
As described further below, the security ratings set forth
above are subject to revision and/or withdrawal at any time by
the respective rating organizations and should not be considered
a recommendation to buy, sell or hold securities of the Company.
The Company's costs of financing and access to markets have
been and could be further negatively affected by events outside
its control. The Company's securities ratings could be
negatively affected by, among other things, the Company's
obligations to purchase power from unregulated generators.
Rating agencies have expressed concern about the impact on
Company financial indicators and risk that unregulated generator
financial leveraging may have. The Company's securities ratings
and the terms of its access to capital markets could also be
negatively impacted by adverse outcomes in the 1995 and multi-
year rate proceedings or rapid penetration of competition in the
Company's service territory.
In September 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
1994 decision on Sithe/Alcan and the August 1994 proposal from
the PSC Staff to reduce the Company's electric and gas rates
over the next five years.
Also in September 1994, Standard and Poor's (S&P) placed its
ratings on the Company, Con Edison and Long Island Lighting
Company on credit watch with negative implications. This action
by S&P reflected 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. If any
rating agency lowers the Company's securities rating,
particularly to below investment grade, such action could
increase the cost to issue new securities, and/or limit the
Company's flexibility.
REPORT OF MANAGEMENT
--------------------
The consolidated financial statements of Niagara Mohawk Power
Corporation and its subsidiaries were prepared by and are the
responsibility of management. Financial information contained
elsewhere in this Annual Report is consistent with that in the
financial statements.
To meet its responsibilities with respect to financial
information, management maintains and enforces a system of
internal accounting controls, which is designed to provide
reasonable assurance, on a cost effective basis, as to the
integrity, objectivity and reliability of the financial records
and protection of assets. This system includes communication
through written policies and procedures, an organizational
structure that provides for appropriate division of
responsibility and the training of personnel. This system is
also tested by a comprehensive internal audit program. In
addition, the Company has a Corporate Policy Register and a Code
of Business Conduct which supply employees with a framework
describing and defining the Company's overall approach to
business and requires all employees to maintain the highest level
of ethical standards as well as requiring all management
employees to formally affirm their compliance with the Code.
The financial statements have been audited by Price
Waterhouse LLP, the Company's independent accountants, in
accordance with generally accepted auditing standards. In
planning and performing their audit, Price Waterhouse considered
the Company's internal control structure in order to determine
auditing procedures for the purpose of expressing an opinion on
the financial statements, and not to provide assurance on the
internal control structure. The independent accountants' audit
does not limit in any way management's responsibility for the
fair presentation of the financial statements and all other
information, whether audited or unaudited, in this Annual Report.
The Audit Committee of the Board of Directors, consisting of five
outside directors who are not employees, meets regularly with
management, internal auditors and Price Waterhouse to review and
discuss internal accounting controls, audit examinations and
financial reporting matters. Price Waterhouse and the Company's
internal auditors have free access to meet individually with the
Audit Committee at any time, without management being present.
REPORT OF INDEPENDENT ACCOUNTANTS
---------------------------------
To the Stockholders and
Board of Directors of
Niagara Mohawk Power Corporation
In our opinion, the accompanying consolidated balance sheets and
the related consolidated statements of income and retained
earnings and of cash flows present fairly, in all material
respects, the financial position of Niagara Mohawk Power
Corporation and its subsidiaries at December 31, 1994 and 1993,
and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1994, 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 9, the Company is a defendant in lawsuits
relating to its actions with respect to certain purchased power
contracts. Management is unable to predict whether the
resolution of these matters will have a material effect on its
financial position or results of operations. Accordingly, no
provision for any liability that may result upon resolution of
this uncertainty has been made in the accompanying 1994 and 1993
financial statements.
As discussed in Note 2, certain representatives of the New York
Public Service Commission have proposed: i) a plan to establish
the Company's rates for its electric business based on a
transition plan to market-based prices rather than based on the
Company's costs and ii) disallowance of certain costs with
respect to unregulated generator contracts. If these proposals
or certain provisions thereof are implemented as proposed, the
Company would be required to writedown certain assets, recognize
a loss on uneconomic unregulated generator contracts and/or
discontinue the application of Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS No. 71), with respect to portions of the
Company's business. Such writedowns or losses could have a
material adverse effect on the Company's financial position and
results of operations. Because the outcome of these matters
cannot be predicted, the accompanying financial statements do not
include any adjustments that might result from the resolution of
these proceedings.
/s/ Price Waterhouse LLP
------------------------
Syracuse, New York
February 1, 1995
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
---------------------------------------------------------
Consolidated Statements of Income and Retained Earnings
-------------------------------------------------------
In thousands of dollars
For the year ended December 31, 1994 1993 1992
Operating revenues:
Electric $3,528,987 $3,332,464 $3,147,676
Gas 623,191 600,967 553,851
4,152,178 3,933,431 3,701,527
Operating expenses:
Operation:
Fuel for electric generation 219,849 231,064 323,200
Electricity purchased 1,107,133 863,513 650,379
Gas purchased 315,714 326,273 287,316
Other operation expenses 754,695 821,247 748,023
Employee reduction program 196,625 - -
Maintenance 202,682 236,333 226,127
Depreciation and amortization 308,351 276,623 274,090
(Note 1)
Federal and foreign income 117,834 162,515 183,233
taxes (Note 7)
Other taxes 496,922 491,363 484,833
3,719,805 3,408,931 3,177,201
Operating income 432,373 524,500 524,326
Other income and deductions:
Allowance for other funds used
during construction 2,159 7,119 9,648
(Note 1)
Federal and foreign income 27,729
taxes (Note 7) 6,365 15,440
Other items (net) 15,045 7,035 (16,338)
23,569 29,594 21,039
Income before interest charges 455,942 554,094 545,365
Interest charges:
Interest on long-term debt 264,891 279,902 290,734
Other interest 20,987 11,474 9,982
Allowance for borrowed funds
used during construction
(6,920) (9,113) (11,783)
278,958 282,263 288,933
Net income 176,984 271,831 256,432
Dividends on preferred stock 33,673 31,857 36,312
Balance available for common 143,311 239,974 219,920
stock
Dividends on common stock 156,060 133,908 103,784
(12,749) 106,066 116,136
Retained earnings at beginning $ 551,332 $ 445,266 $ 329,130
of year
Retained earnings at end of 538,583 551,332 445,266
year
Average number of shares of
common stock 143,261 140,417 136,570
outstanding (in thousands)
Balance available per average $ 1.00 $ 1.71 $ 1.61
share of common stock
Dividends paid per share $ 1.09 $ .95 $ .76
() Denotes deduction
/TABLE
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
---------------------------------------------------------
CONSOLIDATED BALANCE SHEETS
--------------------------- In thousands of dollars
1994 1993
At December 31,
ASSETS
Utility plant (Note 1):
Electric plant $ 8,285,263 $ 7,991,346
Nuclear fuel 504,320 458,186
Gas plant 922,459 845,299
Common plant 291,962 244,294
Construction work in progress 481,335 569,404
Total utility plant 10,485,339 10,108,529
Less: Accumulated depreciation and 3,449,696 3,231,237
amortization
Net utility plant 7,035,643 6,877,292
Other property and investments 224,039 209,051
Current assets:
Cash, including temporary cash
investments of $50,052 and $100,182, 124,351
respectively 94,330
Accounts receivable (less allowance
for doubtful accounts of $3,600) 317,282 258,137
(Note 9)
Unbilled revenues (Note 1) 196,700 197,200
Electric margin recoverable 66,796 21,368
Materials and supplies, at average
cost:
Coal and oil for production of 31,652 29,469
electricity
Gas storage 30,931 31,689
Other 150,186 163,044
Prepayments:
Taxes 43,249 23,879
Pension expense (Note 8) - 37,238
Other 45,189 34,382
976,315 920,757
Regulatory and other assets (Note 2):
Unamortized debt expense 153,047 154,210
Deferred recoverable energy costs 62,884 67,632
Deferred finance charges 239,880 239,880
Income taxes recoverable 465,109 558,771
Recoverable environmental restoration 240,000 240,000
costs (Note 9)
Other 252,522 203,734
1,413,442 1,464,227
$ 9,649,439 $9,471,327
/TABLE
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
---------------------------------------------------------
CONSOLIDATED BALANCE SHEETS In thousandsof dollars
---------------------------
1994 1993
At December 31,
CAPITALIZATION AND LIABILITIES
Capitalization (Note 5):
Common stockholders' equity:
Common stock, issued 144,311,466
and 142,427,057 shares,
respectively $ 144,311 $ 142,427
Capital stock premium and expense 1,779,504 1,762,706
Retained earnings 538,583 551,332
2,462,398 2,456,465
Non-redeemable preferred stock 290,000 290,000
Mandatorily redeemable preferred stock 256,000 123,200
Long-term debt 3,297,874 3,258,612
Total capitalization 6,306,272 6,128,277
Current liabilities:
Short-term debt (Note 6) 416,750 368,016
77,971 216,185
Long-term debt due within one year (Note 5)
Sinking fund requirements on redeemable preferred 10,950 27,200
stock (Note 5)
Accounts payable 277,782 299,209
Payable on outstanding bank checks 64,133 5,284
Customers' deposits 14,562 14,072
Accrued taxes 43,358 56,382
Accrued interest 63,639 70,529
Accrued vacation pay 36,550 40,178
Other 77,818 39,565
1,083,513 1,166,620
Regulatory and other liabilities:
Accumulated deferred income taxes (Notes 1 and 7). 1,258,463 1,344,259
Deferred finance charges (Note 2) 239,880 239,880
Employee pension and other benefits (Note 8) 235,741 35,507
Unbilled revenues (Note 1) 93,668 94,968
Deferred pension settlement gain 50,261 62,282
Other 141,641 159,534
2,019,654 1,936,430
Commitments and contingencies (Notes 2 and 9):
Liability for environmental restoration 240,000 240,000
$9,649,439 $9,471,327
/TABLE
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, 1994 1993 1992
Cash flows from operating activities:
Net income $176,984 $271,831 $256,432
Adjustments to reconcile net income to net cash provided by operating
activities:
Amortization of nuclear replacement (23,081)
power cost disallowance. 308,351 (23,720) (39,547)
Depreciation and amortization 37,887 276,623 274,090
Amortization of nuclear fuel 7,866 35,971 26,159
Provision for deferred income taxes (45,428) 30,067 55,929
Electric margin recoverable 196,625 (9,773) 3,670
Employee reduction program - -
Allowance for other funds used during (2,159)
construction (7,119) (9,648)
Deferred recoverable energy costs 4,748 (5,688) (14,329)
(Gain)\loss on investments - net - (5,490) 44,296
Deferred operating expenses - 15,746 20,257
Increase in net accounts receivable (59,145) (36,972) (44,969)
(Increase) decrease in materials and supplies 6,290 43,581 (28,293)
Increase (decrease) in accounts payable and
accrued expenses (5,991) 15,716 31,025
Increase (decrease) in accrued interest and
taxes (19,914) 3,996 10,133
Changes in other assets and liabilities 14,188 10,624 39,565
Net cash provided by operating activities 597,221 615,393 624,770
Cash flows from investing activities:
Construction additions (439,289) (506,267) (452,497)
Nuclear fuel (46,134) (12,296) (37,247)
Less: Allowance for other funds used
during construction 2,159 7,119 9,648
Acquisition of utility plant (483,264) (511,444) (480,096)
(Increase) decrease in materials and
supplies related to construction 5,143 3,837 (7,359)
Increase (decrease) in accounts payable
and accrued expenses related to
construction (1,498) 3,929 7,756
Increase in other investments (23,375) (26,774) (11,615)
Proceeds from sale of subsidiary - 95,408 -
Other (17,979) (15,260) (31,588)
Net cash used in investing activities (520,973) (450,304) (522,902)
Cash flows from financing activities:
Proceeds from sale of common stock 29,514 116,764 13,340
Proceeds from long-term debt 424,705 635,000 835,000
Issuance of preferred stock 150,000 - -
Redemption of preferred stock (33,450) (47,200) (41,950)
Reductions of long-term debt (526,584) (641,990) (796,795)
Net change in short-term debt 48,734 50,318 90,130
Dividends paid (189,733) (165,765) (140,296)
Other (9,455) (31,759) (44,781)
Net cash used in financing activities (106,269) (84,632) (85,352)
Net increase (decrease) in cash (30,021) 80,457 16,516
Cash at beginning of year 124,351 43,894 27,378
Cash at end of year $94,330 $ 124,351 $43,894
Supplemental disclosures of cash flow
information:
Cash paid during the year for:
Interest $ 300,242 $ 300,791 $323,972
Income taxes 136,876 106,202 76,519
Supplemental schedule of noncash investing and
financing activities:
Liability for environmental restoration - 25,000 15,000
/TABLE
Notes to Consolidated Financial Statements
NOTE 1. Summary of Significant Accounting Policies
The Company is subject to regulation by the PSC and FERC
with respect to its rates for service under a methodology which
establishes prices based on the Company's cost. The Company's
accounting policies conform to generally accepted accounting
principles, as applied to regulated public utilities, and are in
accordance with the accounting requirements and ratemaking
practices of the regulatory authorities (See "Exposure Draft on
Impairment of Assets" below and Note 2. "Rate and Regulatory
Issues and Contingencies").
PRINCIPLES OF CONSOLIDATION: The consolidated financial
statements include the Company and its wholly-owned subsidiaries.
Intercompany balances and transactions have been eliminated.
UTILITY PLANT: The cost of additions to utility plant and of
replacements of retirement units of property is capitalized.
Cost includes direct material, labor, overhead and allowance for
funds used during construction (AFC). Replacement of minor items
of utility plant and the cost of current repairs and maintenance
is charged to expense. Whenever utility plant is retired, its
original cost, together with the cost of removal, less salvage,
is charged to accumulated depreciation.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION: The Company
capitalizes AFC in amounts equivalent to the cost of funds
devoted to plant under construction. AFC rates are determined in
accordance with FERC and PSC regulations. The AFC rate in effect
at December 31, 1994 was 5.75%. AFC is segregated into its two
components, borrowed funds and other funds, and is reflected in
the Interest charges and the Other income and deductions
sections, respectively, of the Consolidated Statements of Income.
DEPRECIATION, AMORTIZATION AND NUCLEAR GENERATING PLANT
DECOMMISSIONING COSTS: For accounting and regulatory purposes,
depreciation is computed on the straight-line basis using the
remaining service lives for nuclear and hydro classes of
depreciable property and the average service lives for all other
classes. The percentage relationship between the total provision
for depreciation and average depreciable property was 3.3% for
1994, 3.2% for 1993 and 3.3% for 1992. The Company performs
depreciation studies to determine service lives of classes of
property and adjusts the depreciation rates periodically.
Estimated decommissioning costs (costs to remove a nuclear
plant from service in the future) for the Company's Unit 1 and
its share of Unit 2 are being accrued over the service lives of
the units, recovered in rates through an annual allowance and
currently charged to operations through depreciation. The
Company expects to commence decommissioning of both units shortly
after cessation of operations at Unit 2 (currently planned for
2026), using a method which removes or decontaminates Unit
components promptly at that time. (See Note 3. "Nuclear Plant
Decommissioning".)
The Financial Accounting Standards Board (FASB) has added to
its agenda a project on accounting for obligations for
decommissioning of nuclear power plants. The objective of the
FASB's project is to determine when a liability for nuclear
decommissioning should be recognized, how any such liability
should be measured, and whether a corresponding asset is created.
If current electric utility industry accounting practices for
such decommissioning are changed, the Company may be required to
record the estimated cost for decommissioning as a liability
rather than as accumulated depreciation, establish a regulatory
asset for the difference between the amount accrued to date and
the total estimated decommissioning liability and report income
from the external decommissioning trusts as investment income
rather than as a reduction to decommissioning expense. The
annual provisions for decommissioning could increase. The
Company does not believe that such changes, if required, would
have an adverse effect on results of operations due to the
Company's belief that decommissioning costs will continue to be
recovered in rates (see "Exposure Draft on Impairment of Assets",
below).
Amortization of the cost of nuclear fuel is determined on
the basis of the quantity of heat produced for the generation of
electric energy. The cost of disposal of nuclear fuel, which
presently is $.001 per kilowatt-hour of net generation available
for sale, is based upon a contract with the U.S. Department of
Energy. These costs are charged to operating expense and
recovered from customers through base rates or through the fuel
adjustment clause.
REVENUES: Revenues are based on cycle billings rendered to
certain customers monthly and others bi-monthly. Although the
Company commenced the practice in 1988 of accruing electric
revenues for energy consumed and not billed at the end of the
fiscal year, the impact of such accruals has not yet been fully
recognized in the Company's results of operations because of
regulatory requirements. At December 31, 1994 and 1993,
approximately $71.8 million and $74.1 million, respectively, of
unbilled electric revenues remained unrecognized in results of
operations, are included in Deferred Credits and may be used to
reduce future revenue requirements. At December 31, 1994 and
1993, the Company accrued $21.9 and $20.9 million, respectively,
of unbilled gas revenues which remained unrecognized in results
of operations and will similarly be used to reduce future gas
revenue requirements.
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 fuel adjustment clause (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 1992 through 1994 were not
material.
In the Company's current rate proceeding the Company has
proposed to eliminate the FAC and replace it with the fuel
adjustment mechanism (FAM). If this is implemented, the portion
of fuel and purchase power cost fluctuations, from amounts
forecast, that the Company would retain or absorb could reach a
maximum of $20 million per rate year. For the additional years
of the rate proceeding's five-year plan (1996-1999), the 1995
monthly fuel cost would form the basis for the forecast.
Beginning in 1991, the Company's rate agreements provided
for NERAM, which permits the Company to reconcile actual results
to forecast electric public sales gross margin as defined and
utilized in establishing rates. Depending on the level of actual
sales, a liability to customers was created if sales exceed the
forecast and an asset recorded for a sales shortfall, thereby
generally preserving recorded electric gross margin at the level
forecast in established rates. The 1994 rate settlement provided
for the operation of the NERAM through December 31, 1994.
Recovery or refund of accruals pursuant to the NERAM is
accomplished by a surcharge (either plus or minus) to customers
over a twelve-month period, to begin when cumulative amounts
reach certain specified levels. While the NERAM may be
terminated in 1995, the recovery period of the outstanding
balance as of December 31, 1994 will not be affected.
In February 1994, the Company implemented a weather
normalization clause for retail customers who use gas for heating
to reflect the impact of variations from normal weather on a
billing month basis for the months of October through May,
inclusive. Normal weather is defined as the 30 year average
daily high and low temperatures for the Company's main gas
service territory. The weather normalization clause will only be
activated if the actual weather deviates 2.2% or more from the
normal weather. Weather normalization clause adjustments were
not significant to 1994 gas revenues.
Rate agreements since 1991 also include MERIT, under which
the Company has the opportunity to achieve earnings above its
allowed return on equity based on attainment of specified goals
associated with its self-assessment process. The MERIT program
provides for specific measurement periods and reporting for PSC
approval of MERIT earnings. Approved MERIT awards are billed to
customers over a period not greater than twelve months. The
Company records MERIT earnings when attainment of goals is
approved by the PSC or when objectively measured criteria are
achieved. MERIT expires at the end of 1995.
FEDERAL INCOME TAXES: As directed by the PSC, the Company defers
any amounts payable pursuant to the alternative minimum tax
rules. Deferred investment tax credits are amortized to Other
Income and Deductions over the useful life of the underlying
property.
STATEMENT OF CASH FLOWS: The Company considers all highly liquid
investments, purchased with a remaining maturity of three months
or less, to be cash equivalents.
RECLASSIFICATIONS: Certain amounts from prior years have been
reclassified on the accompanying Consolidated Financial
Statements to conform with the 1994 presentation.
EXPOSURE DRAFT ON IMPAIRMENT OF ASSETS: In November 1993, the
FASB issued an Exposure Draft on ACCOUNTING FOR THE IMPAIRMENT OF
LONG-LIVED ASSETS. The Exposure Draft would require companies,
including utilities, to assess the need to recognize a loss
whenever events or circumstances occur which indicate that the
carrying amount of an asset may not be fully recoverable. An
impairment loss would be recognized if the sum of the future
undiscounted net cash flows expected to be generated by an asset
is less than its book value. The amount of the loss would be
based on a comparison of book value to fair value. The Exposure
Draft would also amend Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation," (SFAS No. 71) to require writeoff of a regulatory
asset if it is no longer probable that future revenues will
recover the cost of the asset.
The Exposure Draft, which is expected to become applicable
in 1996, may have consequences to a number of utilities,
including the Company, which are facing growing competitive
threats that may erode future prices, and which have relatively
high-cost nuclear generating assets and unregulated generator
contracts. The Company is also faced with ratemaking proposals
by the PSC Staff in the current 1995 and multi-year rate cases,
and by the Administrative Law Judges (ALJ's) Recommended Decision
in the 1995 case, that would likely result in asset impairment
issues under the Exposure Draft provisions if the PSC Staff's
proposals or the Recommended Decision are adopted by the PSC.
See Management's Discussion and Analysis - "Regulatory
Agreements/Proposals" for a more extensive discussion of the
competitive threats facing the Company and of the PSC Staff's
proposals and the ALJ's Recommended Decision.
While the Company is unable to determine the financial
consequences of applying the provisions of the Exposure Draft, if
the PSC Staff's proposals and/or the ALJ's Recommended Decision
are adopted, they would have a material adverse effect on the
Company's financial position and results of operations.
NOTE 2. Rate and Regulatory Issues and Contingencies
-----------------------------------------------------
In accordance with SFAS No. 71, the Company's financial
statements reflect assets and costs based on ratemaking
conventions, as approved by the PSC and the FERC. Certain
expenses and credits, normally reflected in income as incurred,
are only recognized when included in rates and recovered from or
refunded to customers. Historically, all costs of this nature
which are determined by the regulators to have been prudently
incurred have been recoverable through rates in the course of
normal ratemaking procedures and the Company believes that the
items detailed below will be afforded similar treatment.
Continued accounting under SFAS No. 71 requires, among other
things, that rates be designed to recover specific costs of
providing regulated services and products and that it be
reasonable to assume that rates are set at levels that will
recover a utility's costs and can be charged to and collected
from customers. When a utility determines it can no longer apply
the provisions of SFAS No. 71 to all or a part of its operation,
it must eliminate from its balance sheet, the effects of actions
of regulators that had been recorded previously as assets and
liabilities pursuant to SFAS No. 71 but which would have not been
so accounted for by enterprises in general.
The Company's proposed multi-year rate plan for 1995-1999
contemplates no change in this approach to such reporting, even
though the plan recognizes that in a more competitive environment
an effective response to the general pressure to manage costs and
preserve or expand markets is vital to maintaining profitability.
The Company's proposed plan includes the establishment of rates
for 1995 on a cost of service basis, followed by an index-based
approach to rates for 1996 through 1999. The index is based on
inflation factors believed to be indicative of cost increases to
be experienced by the Company. The proposal for 1996-1999 also
includes adjustment factors related to events outside the
Company's control and a mechanism for resetting rates if the
expected return on equity falls below a minimum threshold.
Therefore, the Company believes that it can continue to apply
SFAS No. 71 under its multi-year rate proposal.
The PSC Staff has proposed a multi-year ratesetting plan
which the Company believes would require write-down of certain
assets, would not permit the continued application of SFAS No. 71
to its generation operations and may similarly jeopardize
application of SFAS No. 71 to its transmission and distribution
operations under certain circumstances. The ALJ's Recommended
Decision proposes to disallow from recovery approximately $18
million of unregulated generator costs, recommends a prudence
investigation of the Company's unregulated generator contract
practices absent a multi-year rate plan, proposes to reduce the
level of departmental expenses and gross margin because of "lack
of support" and states that the VERP savings could be used to
further reduce the rate increase recommended. See Management's
Discussion and Analysis of Financial Condition and Results of
Operations - "Regulatory Agreements/Proposals" for a discussion
of the PSC Staff's and ALJ's proposals and potential financial
consequences. In the event that the Company is required to
write-down its assets, recognize a loss on uneconomic unregulated
generator contracts and/or could no longer apply SFAS No. 71 to
either its generation operations or to its entire electric
business, a material adverse effect on its financial condition
and results of operations would result.
The Company believes the financial consequences to be of an
order of magnitude that would adversely affect the Company's
financial position and results of operations, its 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 its ability to maintain
current levels of service to its customers.
The Company has recorded the following regulatory assets.
(In thousands)
At December 31, 1994 1993
Income taxes recoverable $ 465,109 $ 558,771
Recoverable environmental
restoration costs 240,000 240,000
Deferred finance charges 239,880 239,880
Unamortized debt expense 153,047 154,210
Deferred postretirement benefit 67,486 30,741
costs
Deferred recoverable energy costs 62,884 67,632
Deferred unregulated generator
contract termination costs 38,286 50,680
Deferred gas pipeline costs 17,000 31,000
Other 129,750 91,313
Total $1,413,442 $1,464,227
INCOME TAXES RECOVERABLE 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. These amounts are amortized and recovered as the
related temporary differences reverse. In January 1993, the PSC
issued a Statement of Interim Policy on Accounting and Ratemaking
Procedures that required adoption of Statement of Financial
Accounting Standards No. 109 - "Accounting for Income Taxes"
(SFAS No. 109) on a revenue-neutral basis.
RECOVERABLE 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. Current rates
provide an annual allowance to recover anticipated annual
expenditures.
DEFERRED FINANCE CHARGES represent the deferral of the
discontinued portion of AFC related to construction work in
progress (CWIP) at Unit 2 which was included in rate base. In
1985, pursuant to PSC authorization, the Company discontinued
accruing AFC on CWIP for which a cash return was being allowed.
This amount, which was accumulated in deferred debit and credit
accounts up to the commercial operation date of Unit 2, awaits
future disposition by the PSC. A portion of the deferred credit
could be utilized to reduce future revenue requirements over a
period shorter than the life of Unit 2, with a like amount of
deferred debit amortized and recovered in rates over the
remaining life of Unit 2.
UNAMORTIZED DEBT EXPENSE represents the costs to issue long-term
debt securities including premiums on certain debt retirements
prior to maturity. These amounts are amortized as interest
expense ratably over the lives of the related issues in
accordance with PSC directives.
DEFERRED POSTRETIREMENT BENEFIT COSTS represent the excess of
such costs recognized in accordance with Statement of Financial
Accounting Standards No. 106 - "Employers' Accounting for
Postretirement Benefits Other Than Pensions" (SFAS No. 106) over
the amount received in rates. In accordance with the PSC policy
statement, postretirement benefit costs other than pensions are
being phased-in to rates over a five-year period and amounts
deferred will be amortized and recovered over a period not to
exceed 20 years.
DEFERRED RECOVERABLE ENERGY COSTS includes the difference between
actual fuel costs and the fuel revenues received through the
Company's fuel adjustment clause. The balance also includes the
unamortized portion of the Company's mandated contribution to
decommission the Department of Energy's (DOE) uranium enrichment
facilities. The costs to decommission DOE facilities result from
the Energy Policy Act of 1992, which requires domestic utilities
to contribute amounts, escalated for inflation, based upon the
amount of uranium enriched by DOE for each utility. The fuel
costs are amortized as they are collected from customers while
the costs to decommission the DOE facilities are being amortized
and recovered, as a fuel cost, over a period ending in 2006.
DEFERRED UNREGULATED GENERATORS CONTRACT TERMINATION COSTS
represent the Company's cost to buy out certain unregulated
generator projects. Approximately $15 million of these costs are
currently being recovered over a three-year period beginning in
1994. The remaining costs are being addressed in the Company's
current rate filing.
DEFERRED GAS PIPELINE COSTS represent the estimated restructuring
costs the Company anticipates incurring as a result of FERC Order
No. 636. These costs are treated as a cost of purchased gas and
are recoverable through the operation of the gas adjustment
clause mechanism, or direct surcharge to transportation customers
over a period of approximately 7 years beginning in 1994, with
recovery more heavily weighted in the first 3 years.
All other regulatory assets are generally being amortized
over various periods or addressed in the Company's current rate
filing under a provision which proposes recovery using a one-year
rate surcharge.
The above regulatory assets are generally not included in
rate base (and therefore do not earn a return) either because an
outlay of funds has not yet occurred or as a result of regulatory
policy.
NOTE 3. Nuclear Operations
---------------------------
The Company is the owner and operator of the 613 MW Unit 1
and the operator and a 41% co-owner of the 1,062 MW Unit 2. Unit
1 was placed in commercial operation in 1969 and Unit 2 in 1988.
UNIT 1 ECONOMIC STUDY: Under the terms of a previous regulatory
agreement, the Company agreed to prepare and update studies of
the advantages and disadvantages of continued operation of Unit
1. The 1990 study recommended continued operation of Unit 1 over
the next fuel cycle, and the 1992 study indicated that the Unit
could continue to provide benefits for the term of its license
(2009) if operating costs could be reduced and generating output
improved above its then historical average.
The 1994 study again confirmed that continued operation over
the remaining term of its license is warranted. The Company will
continue as a matter of course to examine the economic and
strategic issues related to operation of all its generating
units.
The operating experience at Unit 1 has improved
substantially since the prior study. At December 31, 1994, Unit
1's capacity factor has been about 94% since the 1993 refueling
outage.
The Company's net investment in Unit 1 is approximately $575
million, exclusive of decommissioning costs.
UNIT 1 STATUS: A scheduled refueling outage began on February 8,
1995. Using the net design electric rating as a basis, Unit 1's
capacity factor for 1994 was approximately 92%. Using NRC
guidelines, which reflect net maximum dependable capacity during
the most restrictive seasonal conditions, Unit 1's capacity
factor was approximately 99%.
UNIT 2 STATUS: The next refueling outage is scheduled to begin
in April 1995. Using the net design electric rating as a basis,
Unit 2's capacity factor for 1994 was approximately 90%. Using
NRC guidelines as described above, Unit 2's capacity factor was
approximately 96%.
NUCLEAR PLANT DECOMMISSIONING: The Company estimates the cost of
decommissioning Unit 1 and its ownership interest in Unit 2 at
December 31, 1994 as follows:
Unit 1 Unit 2
Site Study (year) 1994 1989 (a)
End of Plant Life (year) 2009 2026
Radioactive Dismantlement
to Begin (year) 2026 2029
Method of Decommissioning Delayed Immediate
Dismantlement Dismantlement
Cost of Decommissioning (in 1994 dollars) (in millions)
Radioactive Components $344 $207
Non-radioactive Components 51 33
Fuel Dry Storage/Continuing Care 132 50
$527 $290
(a) The estimate of Unit 2's decommissioning costs was
updated by extrapolating data from the updated Unit 1
decommissioning estimate. The Unit 2 estimate should be
considered preliminary, as the Company expects to perform a more
detailed study in 1995.
The Company estimates by the time decommissioning is
completed, the above costs will ultimately amount to $1.4 billion
and $1.0 billion for Unit 1 and Unit 2, respectively, using 2.3%
as an initial inflation factor. This factor increases gradually,
reaching a maximum of 3.4% in the year 2004 and for the years
thereafter.
In addition to the costs mentioned above, the Company
expects to incur post-shutdown costs for plant rampdown,
insurance and property taxes. In 1994 dollars, these costs are
expected to amount to $110 million and $80 million for Unit 1 and
the Company's share of Unit 2, respectively. The amounts will
escalate to $235 million and $405 million for Unit 1 and the
Company's share of Unit 2, respectively.
Based upon a 1989 study the Company had previously estimated
the cost to decommission Unit 1 to be approximately $416 million
in 2009 ($263 million in 1994 dollars). In addition, non-
radioactive dismantlement costs were estimated to be $25 million
in 1994 dollars. The 1989 estimate was based upon a
dismantlement of Unit 1 at the end of its useful life in 2009.
The $527 million estimate assumes a delayed dismantlement to
coincide with Unit 2 and was prepared in connection with the
Economic Study discussed above. The estimate differs from the
1989 estimate primarily due to an increase in burial costs and
the inclusion of nuclear fuel storage charges and costs for
continuing care. The delayed dismantlement approach should be
the most economic after applying the Company's current weighted
average cost of capital.
The Company, in a 1989 study, estimated its 41% share of the
cost to decommission Unit 2 to be $316 million in 2026 dollars
($112 million in 1994 dollars). In addition, the Company's share
of non-radioactive dismantlement cost were estimated to be $18
million (in 1994 dollars). The $290 million estimate differs
from the 1989 study primarily due to an increase in burial costs
and the inclusion of nuclear fuel storage charges and costs for
continuing care.
Decommissioning costs recovered in rates are reflected in
Accumulated Depreciation and Amortization on the Balance Sheet
and amount to $134.1 million and $113.9 million at December 31,
1994 and 1993, respectively for both Units. The annual allowance
for Unit 1 and the Company's share of Unit 2 for the years ended
December 31, 1994, 1993 and 1992 was approximately $18.7, $18.7
and $23.1 million, respectively. These amounts were based on the
1989 study. The FASB has added to its agenda a project on
accounting for obligations for decommissioning of nuclear power
plants (See Note 1. "Depreciation, Amortization and Nuclear
Generating Plant Decommissioning Costs").
NRC regulations require owners of nuclear power plants to
place funds into an external trust to provide for the cost of
decommissioning contaminated portions of nuclear facilities and
establish minimum amounts that must be available in such a trust
at the time of decommissioning. As of December 31, 1994, the
fair value of funds accumulated in the Company's external trusts
were $74.0 million for Unit 1 and $18.7 million for its share of
Unit 2. The investments are included in Other property and
investments. Earnings on the external trust aggregated $13.1
million through December 31, 1994 and, because they are available
to fund decommissioning, have also been included in Accumulated
Depreciation and Amortization (See Note 10. "Disclosures about
Fair Value of Financial Instruments"). Amounts recovered for
non-radioactive dismantlement are accumulated in an internal
reserve fund which has an accumulated balance of $37.1 million at
December 31, 1994.
The NRC minimum decommissioning cost calculation is based
upon a 1986 cost estimate escalated by increases in labor,
energy, and burial cost factors. A substantial increase in
burial costs, partly offset by reduced estimates in the volumes
of waste to be disposed, increased the NRC minimum requirement
for Unit 1 to $381 million in 1994 dollars and the Company's
share of Unit 2 to $173 million in 1994 dollars. The Company's
1995 rate filing includes an aggregate increase of $8 million in
decommissioning allowances to reflect funding to the increased
NRC minimum requirements. In its next rate filing the Company
intends to seek decommissioning allowances necessary to fund to
the Company's 1994 decommissioning estimates discussed above.
There is no assurance that the decommissioning allowance
recovered in rates will ultimately aggregate a sufficient amount
to decommission the units. The Company believes that if
decommissioning costs are higher than currently estimated, the
costs would ultimately be included in the rate process.
NUCLEAR LIABILITY INSURANCE: The Atomic Energy Act of 1954, as
amended, requires the purchase of nuclear liability insurance
from the Nuclear Insurance Pools in amounts as determined by the
NRC. At the present time, the Company maintains the required
$200 million of nuclear liability insurance.
In 1993, the statutory liability limits for the protection
of the public under the Price-Anderson Amendments Act of 1988
(the Act) were further increased. With respect to a nuclear
incident at a licensed reactor, the statutory limit, which is in
excess of the $200 million of nuclear liability insurance, is
currently $8.3 billion without the 5% surcharge discussed below.
This limit would be funded by assessments of up to $75.5 million
against each of the 110 presently licensed nuclear reactors in
the United States, payable at a rate not to exceed $10 million
per reactor per year. Such assessments are subject to periodic
inflation indexing and to a 5% surcharge if funds prove
insufficient to pay claims.
The Company's interest in Units 1 and 2 could expose it to a
potential loss, for each accident, of $111.8 million through
assessments of $14.1 million per year in the event of a serious
nuclear accident at its own or another licensed U.S. commercial
nuclear reactor. The amendments also provide, among other
things, that insurance and indemnity will cover precautionary
evacuations, whether or not a nuclear incident actually occurs.
NUCLEAR PROPERTY INSURANCE: The Nine Mile Point Nuclear Site has
$500 million primary nuclear property insurance with the Nuclear
Insurance Pools (ANI/MRP). In addition, there is $1.4 billion,
in excess of the $500 million primary nuclear insurance, with
Nuclear Electric Insurance Limited (NEIL) and $850 million, which
is also in excess of the $500 million primary and the $1.4
billion excess nuclear insurance, also with NEIL. The total
nuclear property insurance is $2.75 billion. NEIL is a utility
industry-owned mutual insurance company chartered in Bermuda.
NEIL also provides insurance coverage against the extra expense
incurred in purchasing replacement power during prolonged
accidental outages. The insurance provides coverage for outages
for 156 weeks, after a 21-week waiting period.
NEIL insurance is subject to retrospective premium
adjustment under which the Company could be assessed up to
approximately $15.8 million per loss.
LOW LEVEL RADIOACTIVE WASTE: The Federal Low Level Radioactive
Waste Policy Act as amended in 1985 requires states to join
compacts or to individually develop their own low level
radioactive waste disposal site. In response to the Federal law,
New York State decided to develop its own site because of the
large volume of low level radioactive waste it generates, and
committed to develop a plan for the management of low level
radioactive waste in New York State during the interim period
until a disposal facility is available.
New York State is still developing disposal methodology and
acceptance criteria for a disposal facility. The latest New York
State low level radioactive waste site development schedule now
assumes two possible siting scenarios, a volunteer approach and a
non-volunteer approach, either of which would begin operation in
2001. Effective July 1, 1994, access to the Barnwell, South
Carolina waste disposal facility was denied, by the state of
South Carolina to out-of-region low level radioactive waste
generators, including New York State. 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.
NUCLEAR FUEL DISPOSAL COST: In January 1983, the Nuclear Waste
Policy Act of 1982 (the Nuclear Waste Act) established a cost of
$.001 per kilowatt-hour of net generation for current disposal of
nuclear fuel and provides for a determination of the Company's
liability to the Department of Energy (DOE) for the disposal of
nuclear fuel irradiated prior to 1983. The Nuclear Waste Act
also provides three payment options for liquidating such
liability and the Company has elected to delay payment, with
interest, until 1998, the year in which the Company had initially
planned to ship irradiated fuel to an approved DOE disposal
facility (See Note 5 of Notes to the Consolidated Financial
Statements - "Capitalization"). Progress in developing the DOE
facility has been slow and it is anticipated that the DOE
facility will not be ready to accept deliveries until at least
2010. The Company does not anticipate that the DOE will accept
all of its spent fuel immediately upon opening of the facility,
but rather expects a transfer period of as long as 20 years. 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 the incurrance of additional
costs. The Company does not believe that the possible
unavailability of the DOE disposal facility until 2010 will
inhibit operation of either Unit.
NOTE 4. Jointly-Owned Generating Facilities
--------------------------------------------
The following table reflects the Company's share of jointly-
owned generating facilities at December 31, 1994. The Company is
required to provide its respective share of financing for any
additions to the facilities. Power output and related expenses
are shared based on proportionate ownership. The Company's share
of expenses associated with these facilities is included in the
appropriate operating expenses in the Consolidated Statements of
Income.
In thousands of dollars
Percentage Accumulated Construction
Ownership Utility Plant depreciation work in
progress
Roseton Steam Station
Units No. 1 and 2 (a) 25 $ 93,090 $ 46,625 $ 2,679
Oswego Steam Station
Unit No. 6 (b) 76 $ 270,498 $106,343 $ 5,143
Nine Mile Point Nuclear
Station Unit No. 2 (c) 41 $1,504,185 $252,747 $12,029
(a) The remaining ownership interests are Central Hudson Gas and Electric Corporation, the operator of the plant
(35%), and Consolidated Edison Company of New York, Inc. (40%). On March 30, 1994, the Company and Central
Hudson Gas and Electric Corporation (CHG&E) terminated and cancelled the 1987 agreement where CHG&E had agreed
to acquire the Company's 25% interest in the plant in ten equal installments of 2.5% (30 mw.) starting on
December 31, 1994 and on each December 31 thereafter. The cancellation agreement is subject to PSC approval.
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 Corporation (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 (18%), New
York State Electric and Gas Corporation (18%), Rochester Gas and Electric Corporation (14%), and Central Hudson
Gas and Electric Corporation (9%). Output of Unit 2, which has a capability of 1,062,000 kw., is shared in the
same proportions as the cotenants' respective ownership interests.
/TABLE
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 1992,
1993 and 1994:
Common Stock $1 par value Preferred Stock $100 par value
Non-
Shares Amount* Shares Redeemable* Redeemable*
December 31, 1991 136,099,654 $136,100 2,490,000 $210,000 $39,000 (a)
Issued 1,059,953 1,060 - - -
Redemptions (78,000) - (7,800)
Foreign currency
translation adjustment
---------------------------------------------------------------------------------------------------------
December 31, 1992: 137,159,607 137,160 2,412,000 210,000 31,200 (a)
Issued 5,267,450 5,267 - - -
Redemptions (18,000) - (1,800)
Foreign currency
translation adjustment
---------------------------------------------------------------------------------------------------------
December 31, 1993: 142,427,057 142,427 2,394,000 210,000 29,400 (a)
Issued 1,884,409 1,884 - - -
Redemptions (18,000) - (1,800)
Foreign currency
translation adjustment
---------------------------------------------------------------------------------------------------------
December 31, 1994: 144,311,466 $144,311 2,376,000 210,000 $27,600 (a)
---------------------------------------------------------------------------------------------------------
* In thousands of dollars
(a) Includes sinking fund requirements due within one year.
/TABLE
Preferred Stock $25 par value
Non- Capital Stock Premium
Shares Redeemable* Redeemable* and Expense (Net)*
December 31, 1991 11,222,005 $ 80,000 $200,550 (a) $1,650,312
Issued - - - 18,401
Redemptions (1,366,000) - (34,150) 796
Foreign currency
translation adjustment (11,494)
---------------------------------------------------------------------------------------------------------
December 31, 1992: 9,856,005 80,000 166,400 (a) 1,658,015
Issued - - - 111,497
Redemptions (1,816,000) - (45,400) (2,471)
Foreign currency
translation adjustment (4,335)
---------------------------------------------------------------------------------------------------------
December 31, 1993: 8,040,005 80,000 121,000 (a) 1,762,706
Issued 6,000,000 - 150,000 27,630
Redemptions (1,266,000) (31,650) (4,619)
Foreign currency
translation adjustment (6,213)
---------------------------------------------------------------------------------------------------------
December 31, 1994: 12,774,005 $ 80,000 $239,350 (a) $1,779,504
---------------------------------------------------------------------------------------------------------
* In thousands of dollars
(a) Includes sinking fund requirements due within one year.
The cumulative amount of foreign currency translation adjustment at December 31, 1994 was $(13,313).
/TABLE
NON-REDEEMABLE PREFERRED STOCK (Optionally Redeemable)
------------------------------------------------------
The Company has certain issues of preferred stock which provide for optional redemption at December 31, as follows:
Redemption price per share
In thousands of (Before adding accumulated dividends)
dollars
Series Shares 1994 1993
Preferred $100 par value:
3.40% 200,000 $20,000 $20,000 $103.50
3.60% 350,000 35,000 35,000 104.85
3.90% 240,000 24,000 24,000 106.00
4.10% 210,000 21,000 21,000 102.00
4.85% 250,000 25,000 25,000 102.00
5.25% 200,000 20,000 20,000 102.00
6.10% 250,000 25,000 25,000 101.00
7.72% 400,000 40,000 40,000 102.36
Preferred $25 par
value:
Adjustable Rate
Series A 1,200,000 30,000 30,000 25.00
Series C 2,000,000 50,000 50,000 25.75
(1)
$290,000 $290,000
(1) Eventual minimum $25.00.
/TABLE
MANDATORILY REDEEMABLE PREFERRED STOCK
--------------------------------------
The Company has certain issues of preferred stock which provide for
mandatory and optional redemption at December 31, as follows:
Redemption price per
Shares In thousands of share
dollars (Before adding
accumulated dividends)
Eventual
Series 1994 1993 1994 1993 1994 minimum
Preferred $100 par value:
7.45% (c) 276,000 294,000 $ 27,600 $ 29,400 $102.41 $100.00
Preferred $25 par
value:
7.85% (c) 914,005 914,005 22,850 22,850 (a) 25.00
8.375% (c) 400,000 500,000 10,000 12,500 25.33 25.00
8.70% (c) 200,000 600,000 5,000 15,000 25.25 25.00
8.75% - 600,000 - 15,000 25.25 25.00
9.50% 6,000,000 - 150,000 - (b) 25.00
9.75% (c) 210,000 276,000 5,250 6,900 25.13 25.00
Adjustable
Rate 1,850,000 1,950,000 46,250 48,750 25.00 25.00
Series B (c)
266,950 150,400
27,200
Less sinking fund 10,950
requirements
$256,000 $123,200
(a) Not redeemable until 1996.
(b) Not redeemable until 1999.
(c) 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 1995 through 1999 are as follows: $10,950;
$9,150; $10,120; $10,120; and $7,620, respectively.
LONG-TERM DEBT
--------------
Long-term debt at December 31, consisted of the following:
In thousands of dollars
Series Due 1994 1993
First mortgage bonds:
8 7/8% 1994 $ - $150,000
4 5/8% 1994 - 40,000
5 7/8% 1996 45,000 45,000
6 1/4% 1997 40,000 40,000
6 1/2% 1998 60,000 60,000
10 1/4% 1999** - 100,000
10 3/8% 1999** - 100,000
9 1/2% 2000 150,000 150,000
6 7/8% 2001 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
*6 5/8% 2013 45,600 45,600
*11 1/4% 2014** - 75,690
*11 3/8% 2014** - 40,015
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 -
Total First Mortgage Bonds 2,611,305 2,791,305
Promissory notes:
*Adjustable Rate Series due
July 1, 2015 100,000 100,000
December 1, 2023 69,800 69,800
December 1, 2025 75,000 75,000
December 1, 2026 50,000 50,000
March 1, 2027 25,760 25,760
July 1, 2027 93,200 93,200
Unsecured notes payable:
Medium Term Notes, Various 45,000 55,500
rates, due 1993-2004
Swiss Franc Bonds due December 50,000 50,000
15, 1995
Revolving Credit Agreement 99,000 -
Other 169,421 176,888
Unamortized premium (discount) (12,641) (12,656)
TOTAL LONG-TERM DEBT 3,375,845 3,474,797
Less long-term debt due within 77,971 216,185
one year
$3,297,874 $3,258,612
*Tax-exempt pollution control related
issues
**Retired prior to maturity
/TABLE
Several series of First Mortgage Bonds and Notes were issued
to secure a like amount of tax-exempt revenue bonds issued by the
New York State Energy Research and Development Authority
(NYSERDA). Approximately $414 million of such bonds 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 2.76% for 1994 and 2.14% for 1993
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.
The $115.7 million of tax-exempt bonds due 2014 were
refinanced at 7.2% during 1994 pursuant to a forward refunding
agreement entered into in 1992.
Notes payable include a Swiss franc bond issue maturing in
1995 equivalent to $50 million in U.S. funds. Simultaneously
with the sale of these bonds, the Company entered into a currency
exchange agreement to fully hedge against currency exchange rate
fluctuations.
Other long-term debt in 1994 consists of obligations under
capital leases of approximately $44.3 million, a liability to the
U.S. Department of Energy for nuclear fuel disposal of
approximately $97.4 million (See Note 3. "Nuclear Fuel Disposal
Costs") and liabilities for unregulated generator contract
terminations of approximately $27.7 million (See Note 9. "Long-
term Contracts for the Purchase of Electric Power").
Certain of the Company's debt securities provide for a
mandatory sinking fund for annual redemption. The aggregate
maturities of long-term debt for the five years subsequent to
December 31, 1994, excluding capital leases, are approximately
$73 million, $61 million, $145 million, $164 million and $0
million, respectively.
NOTE 6. Bank Credit Arrangements
---------------------------------
At December 31, 1994, (excluding HYDRA-Co Enterprises, Inc.
which was sold January 9, 1995), the Company had $580 million of
bank credit arrangements with 16 banks. These credit
arrangements consisted of $200 million in commitments under a
Revolving Credit Agreement, $199 million in one-year commitments
under Credit Agreements, $111 million in lines of credit and $70
million under a Bankers Acceptance Facility Agreement. The
Revolving Credit Agreement extends into 1997 and the interest
rate applicable to borrowing is based on certain rate options
available under the Agreement. All of the other bank credit
arrangements are subject to review on an ongoing basis with
interest rates negotiated at the time of use. The Company also
issues commercial paper. Unused bank credit facilities are held
available to support the amount of commercial paper outstanding.
In addition to these credit arrangements, the Company had
outstanding at December 31, 1994, $161 million in bank loans
which expire in 1995 and which the Company expects to renew.
The Company pays fees for substantially all of its bank
credit arrangements. The Bankers Acceptance Facility Agreement,
which is used to finance the fuel inventory for the Company's
generating stations, provides for the payment of fees only at the
time of issuance of each acceptance.
The following table summarizes additional information applicable to short-term debt:
In thousands of dollars
At December 31: 1994 1993
Short-term debt:
Commercial paper . . . . $ 84,750 $210,016
Notes payable . . . . . . 321,000 153,000
Bankers acceptances . . . 11,000 5,000
$416,750 $368,016
Weighted average interest
rate (a) . . 6.21% 3.60%
----------------------------------------------------------------------------------
For Year Ended December 31:
Daily average outstanding . $342,801 $165,458
Monthly weighted average interest
rate (a) . . . . . 4.71% 3.72%
Monthly amount outstanding $497,700 $368,016
----------------------------------------------------------------------------------
(a) Excluding fees.
/TABLE
NOTE 7. Federal and Foreign Income Taxes
-----------------------------------------
Components of United States and foreign income before income taxes:
In thousands of dollars
1994 1993 1992
United States . . . . . . . . . . $291,501 $438,914 $410,283
Foreign . . . . . . . . . . . . . 15,475 (24,845) 18,394
Consolidating eliminations . . . (18,523) 4,837 (16,741)
Income before income taxes . . . $288,453 $418,906 $411,936
Following is a summary of the components of Federal and foreign income
tax and a reconciliation between the amount of Federal income tax expense
reported in the Consolidated Statements of Income and the computed amount
at the statutory tax rate:
Summary Analysis: In thousands of dollars
1994 1993 1992
Components of Federal and foreign income taxes:
Current tax expense: Federal . . $117,314 $118,918 $119,929
Foreign . . . . . 4,423 8,445 915
121,737 127,363 120,844
Deferred tax expense:Federal . . (6,931) 35,152 54,858
Foreign . . . . . . . . . 3,028 - 7,531
(3,903) 35,152 62,389
Income taxes included in
Operating Expenses . . . . . . . 117,834 162,515 183,233
Current Federal and foreign income
tax credits included in
Other Income and Deductions . . (11,507) (16,061) (31,787)
Deferred Federal and foreign income
tax expense included in Other
Income and Deductions . . . . . 5,142 621 4,058
Total $111,469 $147,075 $155,504
Reconciliation between Federal and foreign income taxes and the tax computed at prevailing U.S. statutory
rate on income before income taxes:
Computed tax 100,959 $146,617 $140,058
Reduction (increase) attributable to flow-through of certain tax adjustments:
Depreciation . . . . . . . . . (33,328) (35,153) (37,543)
Allowance for funds used during
construction . . . . . . . . 3,291 2,951 11,205
Cost of removal . . . . . . . . 8,908 7,822 6,845
Deferred investment tax credit
amortization . . . . . . . . 8,018 8,018 8,024
Other . . . . . . . . . . . . . 2,601 15,904 (3,977)
(10,510) (458) (15,446)
Federal and foreign income taxes $111,469 $147,075 $155,504
/TABLE
At December 31, the deferred tax liabilities (assets) were comprised of the following:
(In thousands)
1994 1993
Alternative minimum tax $ (93,893) $ (95,071)
Unbilled revenue (98,201) (82,829)
Other (258,621) (163,256)
Total deferred tax assets (450,715) (341,156)
Depreciation related 1,398,695 1,387,244
Investment tax credit related 95,325 108,140
Other 215,158 190,031
Total deferred tax 1,709,178 1,685,415
liabilities
Accumulated deferred income $1,258,463 $1,344,259
taxes
/TABLE
NOTE 8. Pension and Other Retirement Plans
-------------------------------------------
The Company and certain of its subsidiaries have non-
contributory, defined-benefit pension plans covering
substantially all their employees. Benefits are based on the
employee's years of service and compensation level. The
Company's general policy is to fund the pension costs accrued
with consideration given to the maximum amount that can be
deducted for Federal income tax purposes.
During 1994, the Company offered an early retirement program
and a voluntary separation program (together the VERP) to reduce
the Company's staffing levels and streamline operations. The
VERP, which included both represented and non represented
employees, was accepted by approximately 1,400 employees. The
following table sets forth the components and allocation of the
costs of the programs.
(In thousands of dollars)
Plan Electric Gas Total
Pension benefits $107,800 $ 6,200 $114,000
Other Postretirement benefits 75,900 4,300 80,200
Other Postemployment benefits 16,800 900 17,700
200,500 11,400 211,900
Less: allocation to
cotenant and other ventures 3,900 - 3,900
Cost $196,600 $11,400 $208,000
Included in 1994 operating expenses is a one-time charge of
$196.6 million, representing the cost of the VERP allocable to
electric customers. The Company has recorded a regulatory asset
for the portion of the VERP cost allocable to gas customers of
approximately $11.4 million, which it has proposed to recover
over a five-year period beginning in 1995.
Net pension cost for 1994, 1993 and 1992 included the following components:
In thousands of dollars
1994 1993 1992
Service cost - benefits $ 30,400 $ 30,100 $ 27,100
earned during the period
Interest cost on 62,700 54,200 48,800
projected benefit
obligation
Actual return on Plan 7,700 (106,100) (59,600)
assets
Net amortization and (63,600) 38,700 6,900
deferral
Net pension cost 37,200 16,900 23,200
VERP costs 114,000 - -
Regulatory asset (6,200) - -
Total pension cost (1) $145,000 $ 16,900 $ 23,200
(1)$5.9 million for 1994, $5.6 million for 1993 and $6.2 million for 1992 was related to construction labor and,
accordingly, was charged to construction projects.
/TABLE
The following table sets forth the plan's funded status and amounts recognized in the Company's Consolidated
Balance Sheets:
In thousands of
dollars
At December 31, 1994 1993
Actuarial present value of accumulated
benefit obligations:
Vested benefits $640,689 $ 501,900
Non-vested benefits 69,642 64,973
Accumulated benefit obligations 710,331 566,873
Additional amounts related to projected pay 222,667 236,906
increases
Projected benefits obligation for service 932,998 803,779
rendered to date
Plan assets at fair value, consisting
primarily of listed stocks, bonds, other 893,313 913,200
fixed income obligations and insurance
contracts
Plan assets in excess of/(less than)
projected benefit obligations (39,685) 109,421
Unrecognized net obligation at January 1,
1987 being recognized over approximately 19 27,122 32,392
years
Unrecognized net gain from actual return on
plan assets different from that assumed
(58,379) (114,536)
Unrecognized net gain from past experience
different from that assumed and effects of
changes in assumptions amortized over 10 (67,857) (39,652)
years
Prior service cost not yet recognized in net 44,421 49,613
periodic pension cost
Pension asset/(liability) included in the ($94,378) $ 37,238
consolidated balance sheets
Principle Actuarial Assumptions (%):
Discount Rate 8.00 7.30
Rate of increase in future compensation
levels (plus merit increases) 3.25 3.25
Long-term rate of return on
plan assets 8.75 9.00
/TABLE
In addition to providing pension benefits, the Company and
its subsidiaries provide certain health care and life insurance
benefits for active and retired employees and dependents. Under
current policies, substantially all of the Company's employees
may be eligible for continuation of some of these benefits upon
normal or early retirement.
The Company accounts for the cost of these benefits in
accordance with PSC policy requirements which generally comply
with SFAS No. 106. This Statement, which was implemented
beginning in 1993, requires accrual accounting by employers for
postretirement benefits other than pensions reflecting currently
earned benefits. The 1992 cost of these benefits was
approximately $16.7 million. The Company has various trusts to
fund its future OPEB obligation. The Company made contributions
to such trusts, equal to the amount received in rates, of
approximately $24 million and $12 million in 1994 and 1993,
respectively.
Net postretirement benefit cost for 1994 and 1993 included the following components:
In thousands of dollars
1994 1993
Service cost - benefits $ 15,000 $12,300
attributed to service during the period
Interest cost on accumulated benefit 40,200 32,800
obligation
Actual return on plan assets (900) -
Amortization of the transition obligation 20,200 20,400
over 20 years
Net amortization 8,900 -
Net postretirement benefit cost 83,400 65,500
VERP costs 80,200 -
Regulatory asset (4,300) -
Total postretirement benefit cost $159,300 $65,500
/TABLE
The following table sets forth the plan's funded status and amounts recognized in the Company's Consolidated
Balance Sheet:
In thousands of dollars
1994 1993
At December 31,
Actuarial present value of accumulated benefit
obligation:
Retired and surviving spouses $371,223 $224,936
Active eligible 20,400 73,474
Active ineligible 208,900 220,420
Accumulated benefit obligation 600,523 518,830
Plan assets at fair value, consisting primarily
of listed stocks, bonds and other fixed 36,754 11,967
obligations
Accumulated postretirement benefit obligation 563,769 506,863
in excess of plan assets
Unrecognized net loss from past experience 71,939 82,756
different from that assumed and effects of
changes in assumptions 337,336 388,600
Unrecognized transition obligation to be
amortized over 20 years
Accrued postretirement benefit liability
included in the consolidated balance sheet $154,494 $ 35,507
Principal actuarial assumptions (%):
Discount rate 8.00 7.30
Long-term rate of return on plan assets 8.75 -
Health care cost trend rate:
Pre-65 12.00 10.05
Post-65 9.00 7.05
/TABLE
At December 31, 1994, the assumed health cost trend rates
gradually decline to 5.75% in 1999. If the health care cost
trend rate was increased by one percent, the accumulated
postretirement benefit obligation as of December 31, 1994 would
increase by approximately 11.2% and the aggregate of the service
and interest cost component of net periodic postretirement
benefit cost for the year would increase by approximately 12.7%.
On January 1, 1994, the Company adopted Statement of
Financial Accounting Standards No. 112, "Employers' Accounting
for Postemployment Benefits" (SFAS No. 112). This Statement
requires employers to recognize the obligation to provide
postemployment benefits if the obligation is attributable to
employees' past services, rights to those benefits are vested,
payment is probable and the amount of the benefits can be
reasonably estimated. The Company previously accounted for such
costs on a cash basis. At December 31, 1994, the Company's
postemployment benefit obligation is approximately $26.3 million,
including the portion of the obligation related to the VERP. The
Company has absorbed in 1994 earnings, $16.8 million related to
the postemployment benefit portion of VERP costs allocated to the
electric business and has recorded a regulatory asset of
approximately $9.5 million, the majority of which is expected to
be recovered equally over three years beginning in 1995.
NOTE 9. Commitments and Contingencies
--------------------------------------
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 1995 through 1999 will require
approximately $1.7 billion, excluding AFC and nuclear fuel. For
the years 1995 through 1999, the estimates are $364 million, $344
million, $338 million, $358 million and $339 million,
respectively. These amounts are reviewed by management as
circumstances dictate.
LONG-TERM CONTRACTS FOR THE PURCHASE OF ELECTRIC POWER: At
January 1, 1995, the Company had long-term contracts to purchase
electric power from the following generating facilities owned by
the New York Power Authority (NYPA):
Purchased Estimated
Facility Expiration date of capacity annual
contract in kw. capacity cost
Niagara - hydroelectric 2007 926,000(a) $23,200,000
project
St. Lawrence - 2007 104,000 1,300,000
hydroelectric project
Blenheim-Gilboa - pumped 2002
storage generating 270,000 7,500,000
station
Fitzpatrick - nuclear year-to-year
plant basis 74,000(b) 7,900,000
1,374,000 $39,900,000
(a) 926,000 kw for summer of 1995; 951,000 kw for winter of 1995-96.
(b) 74,000 kw for summer of 1995; 110,000 kw for winter of 1995-96.
/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 was approximately $85.1 million, $72.2 million
and $64.4 million for the years 1994, 1993 and 1992,
respectively.
Under the requirements of the Federal Public Utility
Regulatory Policies Act of 1978, the Company is required to
purchase power generated by unregulated generators, as defined
therein. At December 31, 1994, the Company had virtually all
unregulated generator capacity scheduled to come into service on
line, totaling approximately 2,592 MW of capacity of which 2,273
MW is considered firm. The following table shows the payments
for fixed capacity costs and energy the Company estimates it will
be obligated to make under these contracts. The payments are
subject to the tested capacity and availability of the
facilities, scheduling and price escalation.
(in thousands)
Fixed
Year Costs Energy Total
1995 $ 201,000 $ 840,000 $ 1,041,000
1996 232,000 859,000 1,091,000
1997 246,000 906,000 1,152,000
1998 269,000 944,000 1,213,000
1999 271,000 991,000 1,262,000
/TABLE
The fixed costs relate to contracts with 10 facilities where
the Company is required to make fixed payments, including
payments when a facility is not operating but available for
service. These 10 facilities account for approximately 708 MW of
capacity, with contract lengths ranging from 20 to 35 years. The
terms of these contracts allow the Company to schedule energy
deliveries from the facilities and then pay for the energy
delivered. The Company estimates the fixed payments under these
contracts will aggregate to approximately $7.5 billion over their
terms. Contracts relating to the remaining facilities in service
at December 31, 1994, require the Company to pay only when energy
is delivered. The Company currently recovers both capacity and
energy payments to unregulated generators through base rates
and/or through the FAC. The Company has proposed to recover such
costs through the FAM beginning in 1995.
The Company paid approximately $960 million, $736 million
and $543 million in 1994, 1993 and 1992 for 14,800,000 mwhrs,
11,720,000 mwhrs and 8,632,000 mwhrs, respectively, of electric
power under all unregulated generator contracts.
In an effort to reduce the costs associated with unregulated
generators, at December 31, 1994, the Company had agreed to buy
out 15 projects consisting of 453 MW of capacity (See Note 2.
"Rate and Regulatory Issues and Contingencies" and Note 5.
"Capitalization"). Additionally, the Company has entered into
agreements with 41 projects, comprising 1,153 MW of capacity,
which allow the Company to curtail purchases from these
unregulated generators when demand is low. The Company expects
to continue efforts of these types into the future, to control
its power supply and related costs, but at this time cannot
predict the outcome of such efforts.
SALE OF CUSTOMER RECEIVABLES: The Company has an agreement
whereby it can sell an undivided interest in a designated pool of
customer receivables, including accrued unbilled electric
revenues, up to a maximum of $200 million. At December 31, 1994
and 1993, respectively, $200 million of receivables had been sold
under this agreement. The undivided interest in the designated
pool of receivables was sold with limited recourse. The
agreement provides for a loss reserve pursuant to which
additional customer receivables are assigned to the purchaser to
protect against bad debts. To the extent actual loss experience
of the pool receivables exceeds the loss reserve, the purchaser
absorbs the excess. 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.
TAX ASSESSMENTS: The Internal Revenue Service (IRS) has
conducted an examination of the Company's Federal income tax
returns for the years 1987 and 1988 and has submitted a Revenue
Agents' Report to the Company. The IRS has proposed various
adjustments to the Company's federal income tax liability for
these years which could increase Federal income tax liability by
approximately $80 million, before assessment of penalties and
interest. Included in these proposed adjustments are several
significant issues involving Unit 2. The Company is vigorously
defending its position on each of the issues, and submitted a
protest to the IRS in 1993. Pursuant to the Unit 2 settlement
entered into with the PSC in 1990, to the extent the IRS is able
to sustain adjustments, the Company will be required to absorb a
portion of any assessment. The Company believes any such
disallowance will not have a material impact on its financial
position or results of operations.
LITIGATION: In March 1993, a complaint was filed in the Supreme
Court of the State of New York, Albany County, against the
Company and certain of its officers and employees. The
plaintiff, Inter-Power of New York, Inc. (Inter-Power), alleges,
among other matters, fraud, negligent misrepresentation and
breach of contract in connection with the Company's alleged
termination of a power purchase agreement in January 1993. The
plaintiff sought enforcement of the original contract or
compensatory and punitive damages in an aggregate amount that
would not exceed $1 billion, excluding pre-judgment interest.
In July 1994, the New York Supreme Court dismissed Inter-
Power's complaint for lack of merit and denied Inter-Power's
cross-motion to compel disclosure. In August 1994, Inter-Power
filed a notice of appeal of this decision which was rejected.
The Company cannot predict whether Inter-Power will pursue
further appeals of this decision. The Company believes it has
meritorious defenses and will continue to defend the lawsuit
vigorously.
In November 1993, Fourth Branch Associates Mechanicville
(Fourth Branch) filed suit against the Company and several of its
officers and employees in the New York Supreme Court, Albany
County, seeking compensatory damages of $50 million, punitive
damages of $100 million and injunctive and other related relief.
The suit grows out of the Company's termination of a contract for
Fourth Branch to operate and maintain a hydroelectric plant the
Company owns in the Town of Halfmoon, New York. Fourth Branch's
complaint also alleges claims based on the inability of Fourth
Branch and the Company to agree on terms for the purchase of
power from a new facility that Fourth Branch hoped to construct
at the Mechanicville site. In January 1994, the defendants filed
a joint motion to dismiss Fourth Branch's complaint. This motion
has yet to be decided. The Company understands that Fourth
Branch has filed for bankruptcy.
In October 1994, Fourth Branch petitioned the PSC to direct
the Company to sell the Mechanicville facility to Fourth Branch
for fair value and to relinquish its FERC license, or in the
alternative, to require the Company to turn over to Fourth Branch
its rate base investment in the plant. The Company has opposed
this petition.
The Medina Power Company is an independent power project
with a contract requiring it to be a qualifying facility (QF)
under federal law or face a contractual penalty. Having come on-
line without a steam host, Medina did not meet this QF
requirement, subjecting it to a 15% rate reduction. The Company
advised Medina that it had exercised its contract right and
reduced the rate accordingly. Medina is seeking $40 million in
compensatory damages, a trebling of this amount to $120 million
under the New York State antitrust laws, and $100 million in
punitive damages. The Company believes Medina's case is without
merit, but cannot predict the outcome of this action.
The Company is involved in a number of court cases regarding
the price of energy it is required to purchase in excess of
contract levels from certain unregulated generators
("overgeneration"). The Company has paid the unregulated
generators based on its long-run avoided cost for all such
overgeneration rather than the price which the unregulated
generators contend is applicable under the contracts. The
Company cannot predict the outcome of these actions, but will
continue to aggressively press its position.
The Company believes it has meritorious defenses and intends
to defend these lawsuits vigorously, but can neither provide any
judgment regarding the likely outcome nor provide any estimate or
range of possible loss.
ENVIRONMENTAL CONTINGENCIES: The public utility industry
typically utilizes and/or generates in its operations a broad
range of potentially hazardous wastes and by-products. The
Company believes it is handling identified wastes and by-products
in a manner consistent with Federal, state and local requirements
and has implemented an environmental audit program to identify
any potential areas of concern and assure compliance with such
requirements. The Company is also currently conducting a program
to investigate and restore, as necessary to meet current
environmental standards, certain properties associated with its
former gas manufacturing process and other properties which the
Company has learned may be contaminated with industrial waste, as
well as investigating identified industrial waste sites as to
which it may be determined that the Company contributed. The
Company has been advised that various Federal, state or local
agencies believe certain properties require investigation and has
prioritized the sites to enhance the management of investigation
and remediation, if necessary.
The Company is currently aware of 89 sites with which it has
been or may be associated, including 47 which are Company-owned.
With respect to non-owned sites, the Company may be required to
contribute some proportionate share of remedial costs.
Investigations at each of the Company-owned sites are
designed to (1) determine if environmental contamination problems
exist, (2) determine the extent, rate of movement and
concentration of pollutants, (3) if necessary, determine the
appropriate remedial actions required for site restoration and
(4) where appropriate, identify other parties who should bear
some or all of the cost of remediation. Legal action against
such other parties, if necessary, will be initiated. After site
investigations are completed, the Company expects to determine
site-specific remedial actions and to estimate the attendant
costs for restoration. However, since technologies are still
developing and the Company has not yet undertaken any full-scale
remedial actions at any identified sites, nor have any detailed
remedial designs been prepared or submitted to appropriate
regulatory agencies, the ultimate cost of remedial actions may
change substantially.
Estimates of the cost of remediation and post-remedial
monitoring are based upon a variety of factors, including
identified or potential contaminants, location, size and use of
the site, proximity to sensitive resources, status of regulatory
investigation and knowledge of activities at similarly situated
sites and the Environmental Protection Agency (EPA) figure for
average cost to remediate a site. Actual Company expenditures
are dependent upon the total cost of investigation and
remediation and the ultimate determination of the Company's share
of responsibility for such costs, as well as the financial
viability of other identified responsible parties since clean-up
obligations are joint and several. The Company has denied any
responsibility in certain of these Potentially Responsible Party
(PRP) sites and is contesting liability accordingly.
As a consequence of site characterizations and assessments
completed to date and negotiations with PRPs, the Company has
accrued a liability of $240 million, representing the low end of
the range of its share of the estimated cost for investigation
and remediation. The potential high end of the range is
presently estimated at approximately $1 billion, including
approximately $500 million in the unlikely event the Company was
required to assume 100% responsibility at non-owned sites.
The Company believes that costs incurred in the
investigation and restoration process for both Company-owned
sites and sites with which it is associated will be recoverable
in the ratesetting process (See Note 2. "Rate and Regulatory
Issues and Contingencies"). Rate agreements in effect since 1991
provide for recovery of anticipated investigation and remediation
expenditures. The Company has proposed in its multi-year rate
case net recovery of $13.5 million for 1995 for site
investigation and remediation. The PSC Staff reserves the right
to review the appropriateness of the costs incurred. While the
PSC Staff has not challenged any remediation costs to date, the
PSC Staff asserted in the current gas rate proceeding that the
Company must, in future rate proceedings, justify why it is
appropriate that remediation costs associated with non-utility
property owned by the Company be recovered from ratepayers.
Based upon management's assessment that remediation costs will be
recovered from ratepayers, a regulatory asset has been recorded
representing the future recovery of remediation obligations
accrued to date.
The Company is currently providing notices of insurance
claims to carriers with respect to the investigation and
remediation costs for manufactured gas plant, industrial waste
sites and sites for which the Company has been identified as a
PRP. The Company is unable to predict whether such insurance
claims will be successful.
NOTE 10. Disclosures about Fair Value of Financial Instruments
---------------------------------------------------------------
The following methods and assumptions were used to estimate
the fair value of each class of financial instruments:
CASH AND SHORT-TERM INVESTMENTS: The carrying amount
approximates fair value because of the short maturity of the
financial instruments.
LONG-TERM INVESTMENTS: The carrying value and market value are
not material to the financial statements.
SHORT-TERM DEBT: The carrying amount approximates fair value
because of the short-term nature of the borrowings.
MANDATORILY REDEEMABLE PREFERRED STOCK: Fair value of the
mandatorily redeemable preferred stock has been determined by one
of the Company's brokers.
LONG-TERM DEBT: The fair value of the Company's long-term debt
has been estimated by one of the Company's brokers. The carrying
value of NYSERDA bonds and other long-term debt are considered to
approximate fair value.
The financial instruments held or issued by the Company are
for purposes other than trading. The estimated fair values of
the Company's financial instruments are as follows:
(In thousands of dollars)
At December 31, 1994 1993
Carrying Carrying
Amount Fair Value Amount Fair Value
Cash and short-term investments $ 94,330 $ 94,330 $ 124,351 $ 124,351
Short-term debt 416,750 416,750 368,016 386,016
Mandatorily redeemable preferred 266,950 277,072 150,400 155,326
stock
Long-Term debt: First Mortgage Bonds 2,611,305 2,367,755 2,791,305 2,969,228
Medium Term Notes 45,000 45,783 55,500 62,458
NYSERDA bonds 413,760 413,760 413,760 413,760
Swiss franc bond 50,000 83,682 50,000 73,794
Other 224,107 224,107 131,587 131,587
/TABLE
In addition, off balance sheet financial instruments,
consisting of a currency exchange agreement used to fully hedge
against currency exchange rate fluctuations related to the Swiss
Franc bond, had a fair value of $31.7 and $20.1 million at
December 31, 1994 and 1993, respectively. As a result of this
agreement, at December 31, 1994, the Company's net obligation due
at maturity on December 15, 1995, of the Swiss Franc bond is
estimated to be approximately $50 million.
On January 1, 1994, the Company adopted Statement of
Financial Accounting Standards No. 115, "Accounting for Certain
Investments in Debt and Equity Securities." This statement
addresses the accounting and reporting for investments in equity
securities that have readily determinable fair values and for all
investments in debt securities. The Company's investments in
debt and equity securities are held in 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").
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, 1994. The
proceeds from the sale of investments were $104.6 million in
1994. Using the specific identification method to determine
cost, the gross realized gains and gross realized losses on those
sales were $1.1 and $1.6 million, respectively. Net realized and
unrealized gains and losses are reflected in Accumulated
Depreciation and Amortization on the Balance Sheet, which is
consistent with the method used by the Company to account for the
decommissioning costs recovered in rates. The recorded fair
values and cost basis of the Company's investments in debt and
equity securities is as follows:
At December 31, 1994
(In thousands of dollars)
Security Gross Unrealized
Type Cost Gain Loss Fair Value
U.S.
Government $15,165 $ 19 $ (325) $14,859
Obligations
Tax Exempt
Obligations 45,029 659 (1,778) 43,910
Corporate 27,407 9 (1,253) 26,163
Obligations
Other 8,121 28 (348) 7,801
$95,722 $715 $(3,704) $92,733
/TABLE
The contractual maturities of the Company's investments in
debt securities is as follows:
At December 31, 1994
(In thousands of dollars)
Fair Value Cost
1 year to 5 years $11,197 $11,429
5 years to 10 years 20,111 20,778
Due after 10 years 57,689 59,591
/TABLE
NOTE 11. Information Regarding the Electric and Gas Businesses
---------------------------------------------------------------
The Company is engaged in the electric and natural gas
utility businesses. Certain information regarding these 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.
In thousands of dollars
1994 1993 1992
Operating revenues:
Electric . . . . . . . . $3,528,987 $3,332,464 $3,147,676
Gas . . . . . . . . . . . 623,191 600,967 553,851
Total . . . . . . . . . $4,152,178 $3,933,431 $3,701,527
Operating income before taxes:
Electric . . . . . . . . $ 466,978* $ 625,852 $ 645,696
Gas . . . . . . . . . . . 83,229 61,163 61,863
Total . . . . . . . . . $ 550,207 $ 687,015 $ 707,559
Pretax operating income, including AFC:
Electric . . . . . . . . $ 475,694 $ 641,435 $ 666,269
Gas . . . . . . . . . . . 83,592 61,812 62,721
Total . . . . . . . . . 559,286 703,247 728,990
Income taxes, included in operating expenses:
Electric . . . . . . . . 97,417 148,695 176,901
Gas . . . . . . . . . . . 20,417 13,820 6,332
Total . . . . . . . . . 117,834 162,515 183,233
Other (income) and deductions (21,410) (22,475) (11,391)
Interest charges . . . . . . 285,878 291,376 300,716
Net income . . . . . . . . . $ 176,984 $ 271,831 $ 256,432
Depreciation and amortization:
Electric . . . . . . . . $ 283,694 $ 255,718 $ 255,256
Gas . . . . . . . . . . . 24,657 20,905 18,834
Total . . .. . . . . . $ 308,351 $ 276,623 $ 274,090
Construction expenditures
(including nuclear fuel):
Electric . . . . . . . . $ 376,159 $ 429,265 $ 442,741
Gas . . . . . . . . . . . 113,965 90,347 59,503
Total . . . . . . . . . $ 490,124 $ 519,612 $ 502,244
Identifiable assets:
Electric . . . . . . . . $7,162,118 $7,042,762 $7,000,659
Gas . . . . . . . . . . . 1,009,566 926,648 783,766
Total . . . . . . . . . 8,171,684 7,969,410 7,784,425
Corporate assets . . . . 1,477,755 1,501,917 806,110
Total assets . . . . . $9,649,439 $9,471,327 $8,590,535
* Includes $196,625 of VERP expenses.
/TABLE
NOTE 12. Quarterly Financial Data (Unaudited)
----------------------------------------------
Operating revenues, operating income, net income and earnings
per common share by quarters from 1994, 1993 and 1992, 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
Operating Net
Quarter Operating income income Earnings
Ended revenues (loss) (loss) (loss)
per
common
share
December 31, 1994 $1,018,110 $(10,536) $ (77,422) $ (.61)
1993 988,195 95,623 30,955 .16
1992 963,629 119,181 41,835 .24
September 30, 1994 $ 918,810 $108,937 $ 48,383 $ .27
1993 879,952 108,539 48,595 .29
1992 822,530 89,658 40,401 .23
June 30, 1994 $ 979,700 $130,624 $ 67,559 $ .42
1993 929,245 132,669 65,325
1992 881,427 137,515 71,734 .41
.46
March 31, 1994 $1,235,558 $203,348 $ 138,464 $ .92
1993 1,136,039 187,669 126,956 .86
1992 1,033,941 177,972 102,462 .68
In the fourth quarter of 1994 the Company recorded $196.6 million
($.89 per common share) for the electric expense allocation of the
VERP. In the second quarter of 1992, the third quarter of 1993,
and the fourth quarter of 1994 the Company recorded $22.8 million
($.11 per common share), $10.3 million ($.05 per common share) and
$12.3 million ($.06 per common share), respectively, for MERIT
earned in accordance with the 1991 Agreement. In the first and
fourth quarters of 1992 the Company recorded $21 million ($.09 per
common share) and $24 million ($.09 per common share), respectively,
to write-down its subsidiary investment in oil and gas properties.
ELECTRIC AND GAS STATISTICS
---------------------------
ELECTRIC CAPABILITY
Thousands of kilowatts
December 31, 1994 % 1993 1992
Owned:
Coal 1,285 16.0 1,285 1,285
Oil 646 8.1 1,496 1,496
Dual Fuel - Oil/Gas 700 8.7 700 700
Nuclear 1,048 13.1 1,048 1,059
Hydro 700 8.7 700 706
Natural Gas - - 74 108
4,379 54.6 5,303 5,354
Purchased:
New York Power Authority (NYPA)
- Hydro 1,300 16.2 1,302 1,302
- Nuclear 74 0.9 65 67
Unregulated generators 2,273 28.3 2,253 1,549
3,647 45.4 3,620 2,918
Total capability * 8,026 100.0 8,923 8,272
Electric peak load 6,458 6,191 6,205
* 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
ELECTRIC STATISTICS
-------------------
1994 1993 1992
Electric sales (Millions of kw-hrs.):
Residential . . . . . . . . . . . . . . . 10,415 10,475 10,392
Commercial . . . . . . . . . . . . . . . 11,813 12,079 11,628
Industrial . . . . . . . . . . . . . . . 7,445 7,088 7,477
Industrial-Special. . . . . . . . . . . . 4,118 3,888 3,857
Municipal service . . . . . . . . . . . . 215 220 227
Other electric systems. . . . . . . . . . 7,593 3,974 3,030
41,599 37,724 36,611
Electric revenues (Thousands of dollars):
Residential . . . . . . . . . . . . . . . $1,233,007 $1,171,787 $1,096,418
Commercial . . . . . . . . . . . . . . . 1,272,234 1,241,743 1,160,643
Industrial . . . . . . . . . . . . . . . 577,473 553,921 589,258
Industrial-Special. . . . . . . . . . . . 49,217 42,988 39,409
Municipal service . . . . . . . . . . . . 50,007 50,642 50,327
Other electric systems . . . . . . . . . 167,131 105,044 93,283
Miscellaneous . . . . . . . . . . . . . . 179,918 166,339 118,338
$3,528,987 $3,332,464 $3,147,676
Electric customers (Average):
Residential . . . . . . . . . . . . . . . 1,405,343 1,398,756 1,389,470
Commercial. . . . . . . . . . . . . . . . 144,249 143,078 142,345
Industrial. . . . . . . . . . . . . . . . 2,105 2,132 2,197
Industrial-Special. . . . . . . . . . . . 82 76 72
Other . . . . . . . . . . . . . . . . . . 2,318 3,438 3,262
1,554,097 1,547,480 1,537,346
Residential (Average):
Annual kw-hr. use per customer. . . . . . 7,411 7,489 7,479
Cost to customer per kw-hr (in cents) . . 11.84 11.19 10.55
Annual revenue per customer . . . . . . . $877.37 $837.74 $789.09
/TABLE
GAS STATISTICS
1994 1993 1992
Gas Sales (Thousands of dekatherms):
Residential . . . . . . . . . . . . . . 56,491 54,908 53,945
Commercial . . . . . . . . . . . . . . 25,783 23,743 22,289
Industrial . . . . . . . . . . . . . . 3,097 4,316 1,772
Other gas systems . . . . . . . . . . . 244 234 1,190
Total sales . . . . . . . . . . . 85,615 83,201 79,196
Spot market . . . . . . . . . . . . . . 1,572 13,223 1,146
Transportation of customer-owned gas . 85,910 67,741 65,845
Total gas delivered . . . . . . . 173,097 164,165 146,187
Gas Revenues (Thousands of dollars):
Residential . . . . . . . . . . . . . . $398,257 $370,565 $354,429
Commercial . . . . . . . . . . . . . . 159,157 144,834 132,609
Industrial . . . . . . . . . . . . . . 14,602 18,482 10,001
Other gas systems . . . . . . . . . . . 1,159 1,066 4,737
Spot market . . . . . . . . . . . . . . 4,370 29,782 2,576
Transportation of customer-owned gas . 38,346 34,843 42,726
Miscellaneous . . . . . . . . . . . . . 7,300 1,395 6,773
$623,191 $600,967 $553,851
Gas Customers (Average):
Residential . . . . . . . . . . . . . . 463,933 455,629 446,571
Commercial . . . . . . . . . . . . . . 40,256 39,662 38,675
Industrial . . . . . . . . . . . . . . 256 233 234
Other . . . . . . . . . . . . . . . . . 1 1 1
Transportation . . . . . . . . . . . . 661 673 673
505,107 496,198 486,154
Residential (Average):
Annual dekatherm use per customer . . . 121.8 120.5 120.8
Cost to customer per dekatherm . . . . $7.05 $6.75 $6.57
Annual revenue per customer . . . . . . $858.44 $813.30 $793.67
Maximum day gas sendout (dekatherms) . 995,801 929,285 905,872
/TABLE
Exhibit 11
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARIES
COMPUTATION OF AVERAGE NUMBER OF SHARES OF COMMON STOCK OUTSTANDING
Average Number
of Shares
(1) (2) Outstanding as
Shares of Number (3) Shown on Consolidated
Common of Days Share Days Statement of Income
Year Ended December 31, Stock Outstanding (2 x 1) (3/Number of days in year)
1994
January 1 - December 31 142,427,057 365 51,985,875,805
Shares sold at various times
during the year -
Employee Savings Fund Plan 857,700 * 152,153,100
Dividend Reinvestment Plan 1,026,709 * 152,123,611
144,311,466 52,290,152,516 143,260,692
1993
January 1 - May 4 137,159,607 124 17,007,791,268
Shares sold May 5 4,494,000
May 5 - December 31 141,653,607 241 34,138,519,287
Shares sold at various times
during the year -
Employee Savings Fund Plan 140,000 22 3,080,000
Dividend Reinvestment Plan 632,341 * 102,395,031
Acquisition - Syracuse
Suburban Gas Company, Inc. 1,109 * 350,374
142,427,057 51,252,135,960 140,416,811
1992
January 1 - December 31 136,099,654 366 49,812,473,364
Shares sold at various times
during the year -
Employee Savings Fund Plan 240,866 * 45,435,347
Dividend Reinvestment Plan 463,736 * 59,130,626
Acquisition - Syracuse
Suburban Gas Company, Inc. 355,351 * 67,443,538
137,159,607 49,984,482,875 136,569,625
* Number of days outstanding not shown as shares represent an accumulation of weekly, monthly
and quarterly sales throughout the year. Share days for shares sold are based on
the total number of days each share was outstanding during the year.
Note: Earnings per share calculated on both a primary and fully diluted basis are the same due to the effects of
rounding.
/TABLE
Exhibit 12
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Statement Showing Computations of Ratio of Earnings to Fixed Charges,
Ratio of Earnings to Fixed Charges without AFC and Ratio of Earnings to Fixed Charges and Preferred Stock Dividends
Year Ended December 31,
1994 1993 1992 1991 1990
A. Net Income per Statements of Income (a) $176,984 $271,831 $256,432 $243,369 $ 82,878
B. Taxes Based on Income or Profits 111,469 147,075 155,504 133,895 61,119
C. Earnings, Before Income Taxes 288,453 418,906 411,936 377,264 143,997
D. Fixed Charges (b) 315,274 319,197 332,413 346,255 347,957
E. Earnings Before Income Taxes and Fixed
Charges 603,727 738,103 744,349 723,519 491,954
F. Allowance for Funds Used During
Construction 9,079 16,232 21,431 18,931 21,414
G. Earnings Before Income Taxes and Fixed
Charges without AFC $594,648 $721,871 $722,918 $704,588 $470,540
Preferred Dividend Factor:
H. Preferred Dividend Requirements $ 33,673 $ 31,857 $ 36,512 $ 40,411 $ 42,300
I. Ratio of Pre-Tax Income to Net Income
(C / A) 1.63 1.54 1.61 1.55 1.74
J. Preferred Dividend Factor (H x I) $ 54,887 $ 49,060 $ 58,784 $ 62,637 $ 73,602
K. Fixed Charges as above (D) 315,274 319,197 332,413 346,255 347,957
L. Fixed Charges and Preferred Dividends
Combined $370,161 $368,257 $391,197 $408,892 $421,559
M. Ratio of Earnings to Fixed Charges
(E / D) 1.91 2.31 2.24 2.09 1.41
N. Ratio of Earnings to Fixed Charges
without AFC (G / D) 1.89 2.26 2.17 2.03 1.35
O. Ratio of Earnings to Fixed Charges and
Preferred Dividends Combined (E / L) 1.63 2.00 1.90 1.77 1.17
(a) Includes the effects of amortization of amounts deferred, under the 1989 Agreement,$15,746 for 1993, $20,257 for
1992 and $31,176 for 1991.
(b) Includes a portion of rentals deemed representative of the interest factor $29,396 for 1994, $27,821 for 1993,
$31,697 for 1992, $34,616 for 1991, and $29,088 for 1990.
/TABLE
EXHIBIT 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the
Registration Statements on Form S-8 (Nos. 33-36189, 33-42720, 33-
42721, 33-42771 and 33-54829) and in the Prospectus constituting
part of the Registration Statements on Form S-3 (Nos. 33-45898,
33-50703, 33-51073, 33-54827, 33-55546 and 33-59594) of Niagara
Mohawk Power Corporation of our report dated February 1, 1995
appearing on page of the financial statements included in the
Company's Form 8-K dated February 15, 1995.
PRICE WATERHOUSE LLP
Syracuse, New York
February 15, 1995
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act
of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned thereunto duly authorized.
Date: February 15, 1995
NIAGARA MOHAWK POWER CORPORATION
By /s/ Steven W. Tasker
Steven W. Tasker
Vice President-Controller
and Principal Accounting Officer