SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1993
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OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
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Commission file number 1-672-2
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Rochester Gas and Electric Corporation
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(Exact name of registrant as specified in its charter)
New York 16-0612110
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) identification No.)
89 East Avenue, Rochester, NY 14649
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (716) 546-2700
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Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
First Mortgage 8 3/8% Bonds due
September 15, 2007, Series CC New York Stock Exchange
Common Stock, $5 par value New York Stock Exchange
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock, $100 par value
4% Series F 4.95% Series K
4.10% Series H 4.55% Series M
4 3/4% Series I 7.50% Series N
4.10% Series J
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
On January 1, 1994 the aggregate market value of the voting stock held by
nonaffiliates of the Registrant was $971,722,264.
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
YES X NO
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Indicate the number of shares outstanding of each of the registrant's
classes of common stock as of the latest practicable date.
Common Stock, $5 par value, at January 1, 1994, 37,051,592.
Documents Incorporated by Reference Part of Form 10-K
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Definitive proxy statement in III
connection with annual meeting of
shareholders to be held April 20,
1994.
Rochester Gas and Electric Corporation
Information required on Form 10-K
Item Number Description Page
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Part I
Item 1 Business 1
Item 2 Properties 20
Item 3 Legal Proceedings 21
Item 4 Submission of Matters to a Vote of
Security Holders 22
Item 4-A Executive Officers of the Registrant 22
Part II
Item 5 Market for the Registrant's Common Equity
and Related Stockholder Matters 24
Item 6 Selected Financial Data 25
Item 7 Management's Discussion and Analysis of
Financial Condition and Results of Operations 28
Item 8 Financial Statements and Supplementary Data 53
Item 9 Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 84
Part III
Item 10 Directors and Executive Officers of the
Registrant 85
Item 11 Executive Compensation 85
Item 12 Security Ownership of Certain Beneficial Owners
and Management 85
Item 13 Certain Relationships and Related Transactions 85
Part IV
Item 14 Exhibits, Financial Statement Schedules and
Reports on Form 8-K 86
Signatures 98
PART I
ITEM 1. BUSINESS
The following are discussed under the general heading of
"Business". Reference is made to the various other Items as
applicable.
CAPTION PAGE
General 1
Financing and Capital Requirements Program 2
Regulatory Matters 4
Competition 8
Electric Operations 9
Gas Operations 12
Fuel Supply
Nuclear 13
Coal 15
Oil 15
Environmental Quality Control 16
Research and Development 17
Operating Statistics 18
GENERAL
Incorporated in 1904 in the State of New York, the Company
supplies electric and gas service wholly within that State. It
produces and distributes electricity and distributes gas in parts of
nine counties centering about the City of Rochester. At December 31,
1993 the Company had 2,536 employees.
The Company's service area has a population of approximately one
million and is well diversified among residential, commercial and
industrial consumers. In addition to the City of Rochester, which is
the third largest city and a major industrial center in New York
State, it includes a substantial suburban area with commercial growth
and a large and prosperous farming area. A majority of the industrial
firms in the Company's service area manufacture consumer goods. Many
of the Company's industrial customers are nationally known, such as
Xerox Corporation, Eastman Kodak Company, General Motors Corporation,
Mobil Corporation and Bausch & Lomb Incorporated.
Energyline Corporation, a wholly owned subsidiary, was formed by
the Company as a gas pipeline corporation to fund the Company's
investment in the Empire State Pipeline. The Company has invested a
net amount of approximately $10 million in Energyline as of December
31, 1993.
The business of the Company is seasonal. With respect to
electricity, winter peak loads are attained due to spaceheating sales
and shorter daylight hours and summer peak loads are reached due to
the use of air-conditioning and other cooling equipment. With respect
to gas, the greatest sales occur in the winter months due to
spaceheating usage.
In each of the communities in which it renders service, the
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Company, with minor exceptions, holds the necessary municipal
franchises, none of which contains burdensome restrictions. The
franchises are non-exclusive, and are either unlimited as to time or
run for terms of years. The Company anticipates renewing franchises
as they expire on a basis substantially the same as at present.
Information concerning revenues, operating profits and
identifiable assets for significant industry segments is set forth in
Note 4 of the Notes to the Company's financial statements under Item
8. Information relating to the principal classes of service from
which electric and gas revenues are derived and other operating data
are included herein under "Operating Statistics". A discussion of the
causes of significant changes in revenues is presented in Item 7 -
Management's Discussion and Analysis of Financial Condition and
Results of Operations. Percentages of the Company's operating
revenues derived from electric and gas operations for each of the last
three years are as follows:
1993 1992 1991
----- ----- -----
Electric 69.1% 70.8% 72.4%
Gas 30.9% 29.2% 27.6%
----- ----- -----
100.0% 100.0% 100.0%
FINANCING AND CAPITAL REQUIREMENTS PROGRAM
A discussion of the Company's capital requirements and the
resources available to meet such requirements may be found in Item 7 -
Management's Discussion and Analysis of Financial Condition and
Results of Operations. In addition to those issues discussed in Item
7, the sale of additional securities depends on regulatory approval
and the Company's ability to meet certain requirements contained in
its mortgage and Restated Certificate of Incorporation.
Under the New York State Public Service Law, the Company is
required to secure authorization from the Public Service Commission of
the State of New York (PSC) prior to issuance of any stock or any debt
having a maturity of more than one year.
The Company's First Mortgage Bonds are issued under a General
Mortgage dated September 1, 1918, between the Company and Bankers
Trust Company, as Trustee, which has been amended and supplemented by
thirty-nine supplemental indentures. Before additional First Mortgage
Bonds are issued, the following financial requirements must be
satisfied:
(a) The First Mortgage prohibits the issuance of additional First
Mortgage Bonds unless earnings (as defined) for a period of
twelve months ending not earlier than sixty days prior to the
issue date of the additional bonds are at least 2.00 times
the annual interest charges on First Mortgage Bonds, both
those outstanding and those proposed to be outstanding. The
ratio under this test for the twelve months ended December
31, 1993 was 4.52.
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(b) The First Mortgage also provides that, if additional First
Mortgage Bonds are being issued on the basis of property
additions (as defined), the principal amount of the bonds may
not exceed 60% of available property additions. As of
December 31, 1993 the amount of additional First Mortgage
Bonds which could be issued on that basis was approximately
$332,408,000. In addition to issuance on the basis of
property additions, First Mortgage Bonds may be issued on the
basis of 100% of the principal amount of other First Mortgage
Bonds which have been redeemed, paid at maturity, or
otherwise reacquired by the Company. As of December 31,
1993, the Company could issue $160,584,000 of Bonds against
Bonds that have matured or been redeemed.
The Company's Restated Certificate of Incorporation (Charter)
provides that, without consent by two-thirds of the votes entitled to
be cast by the preferred stockholders, the Company may not issue
additional preferred stock unless in a 12-month period within the
preceding 15 months: (a) net earnings applicable to payment of
dividends on preferred stock, after taxes, have been at least 2.00
times the annual dividend requirements on preferred stock, including
the shares both outstanding and proposed to be issued, and (b) net
earnings available for interest on indebtedness, after taxes, have
been at least 1.50 times the annual interest requirements on
indebtedness and annual dividend requirements on preferred stock,
including the shares both outstanding and proposed to be issued. For
the twelve months ended December 31, 1993, the coverage ratio under
(b) above (the more restrictive provision) was 2.23.
The Company's Charter also provides that, without consent by a
majority of the votes entitled to be cast by the preferred
stockholders, the Company may not issue or assume any unsecured
indebtedness in excess of 15% of the total of its outstanding bonds
and any other secured indebtedness plus its capital and surplus. At
December 31, 1993, including the $51.3 million of unsecured
indebtedness already outstanding, the Company was able to issue $70.5
million of unsecured debt under this provision. The Company also has
unsecured short-term credit facilities totaling $70 million. Interim
financing is available through short-term borrowings under a $90
million revolving credit agreement which expires December 31, 1996.
In order to be able to use its revolving credit agreement, the Company
created a subordinate mortgage which secures borrowings under its
revolving credit agreement that might otherwise be restricted by this
provision of the Company's Charter. The subordinate mortgage provides
that the aggregate principal amount of bonds outstanding under the
First Mortgage together with all borrowings under the revolving credit
agreement will not exceed 70% of available property additions. At
December 31, 1993, this provision would not restrict borrowings under
the revolving credit agreement. In addition, the Company has a loan
and security agreement with a domestic bank providing for up to $20
million of short-term debt. Borrowings under this agreement, which
extends to December 31, 1994, are secured by the Company's accounts
receivable. At December 31, 1993, the Company had $68 million of
short-term debt outstanding consisting of $51 million unsecured short-
term debt and $17 million of secured short-term debt.
The Company's Charter does not contain any financial tests for
the
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issuance of preference or common stock.
REGULATORY MATTERS
The Company is subject to regulation by the PSC under New York
statutes, by the Federal Energy Regulatory Commission (FERC) as a
licensee and public utility under the Federal Power Act and by the
Nuclear Regulatory Commission (NRC) as a licensee of nuclear
facilities.
The National Energy Policy Act (Energy Act), signed into law in
1992 is the most comprehensive energy bill in more than a decade and
impacts virtually every sector of the U.S. energy industry. Major
provisions of the Energy Act, as they relate to the Company, include
energy efficiency, promoting competition in the electric power
industry at the wholesale level, streamlining of federal licensing of
nuclear power plants, encouraging development and production of coal
resources and ensuring that a new class of independent power producers
established under the bill as well as qualified facilities and other
electric utilities can achieve access to utility-owned transmission
lines upon payment of appropriate prices. Under the Energy Act, FERC
may order utilities to provide wholesale transmission services for
others only if, among other things, the order meets certain
requirements as to cost recovery and fairness of rates. This law
prohibits FERC from ordering retail wheeling, which is power to be
transmitted directly to a customer from a supplier other than the
customer's local utility. The law, however, does not prevent state
regulatory commissions from allowing or ordering intrastate retail
wheeling; and, New York State is currently considering the issue of
retail wheeling through various studies and hearings. The Company
believes this Act could lead to enhanced competition among the Company
and other service providers in the electric industry.
In April 1992 FERC issued Order No. 636 with the intention of
fostering competition in the gas supply industry and improving access
of customers to gas supply sources. In essence, FERC Order No. 636
requires interstate natural gas companies to offer customers
"unbundled", or separate, sales and transportation services. FERC
Order 636 offers an opportunity for the Company and other gas
utilities to negotiate directly with gas producers for supplies of
natural gas. With the unbundling of services, primary responsibility
for reliable natural gas supply has shifted from interstate pipeline
companies to local distribution companies, such as the Company. Since
1988 the Company has endeavored to diversify both its natural gas
supply sources and the pipelines on which that supply is delivered to
the Company's distribution system. With the unbundling of services as
required under FERC Order 636 and the commencement of Empire State
Pipeline operation, the Company has successfully achieved those goals,
which should enhance its competitive position.
In 1988 the PSC ordered New York utilities to submit proposals to
implement a competitive bidding procedure for new electric generation.
In response to this requirement, the Company filed with the PSC (and
thereafter amended such filings as required by the PSC) its proposed
request for proposals (RFP) for the bidding of capacity additions and
certain demand side management (DSM) measures. On September 11, 1990,
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the Company issued an RFP to purchase 70,000 kilowatts (Kw) of
capacity or capacity savings. Of this total resource block, 20,000 Kw
was set aside for DSM projects implemented within the Company's
service territory while the remaining 50,000 Kw could be filled either
by some form of generation directly interconnected to the electric
system within or outside the Company's service territory or by
additional DSM projects. The Company expressed a strong preference
for peaking capacity in the RFP. The Company announced the successful
bids in October 1991. Contract negotiations have been completed with
three successful bidders of DSM projects resulting in contracts to
supply 20.6 MW of capacity savings to be phased-in over the 1993-1996
period. Contract negotiations continue with one successful bidder for
.125 MW of capacity savings. One successful bidder decided not to go
forward with a proposal for 3 MW of capacity savings. A joint New
York State utility analysis completed in late August 1991 concluded
that capacity reserves on a statewide basis would exceed required
levels until after the long-range planning period, or through and
beyond the year 2007. Based on this analysis, the Company determined
that its remaining needs could be more economically met through spot
market purchases of capacity more closely tailored to its year-to-year
requirements than by a long-term supply commitment. As a result, no
contracts were offered to sponsors of supply-side proposals. On
September 1, 1993 the Company issued an RFP for 3 MW of summer peak
capacity savings at one of its facilities. Four proposals were
received on October 20, 1993. A contract was executed on December 1,
1993. This project is expected to be completed in 1996.
In June 1992, the Company filed with the PSC an Integrated
Resource Plan (IRP), which is a long-range plan used to examine future
options with regard to generating resources and alternative methods of
meeting electric capacity requirements. The plan covers a 15-year
period, beginning in 1992, and provides current strategies and
alternatives for meeting the Company's customers' energy requirements
in a changing business and technological environment. The IRP takes
into account anticipated capacity requirements and available resource
options, as well as factors such as reliability, price of product,
public acceptance, financial integrity, environmental issues, the
competitive marketplace, demand side management and potential new
technologies.
One result of the IRP was the decision made by the Company in
December 1992 to replace the two steam generators at the Ginna nuclear
plant in 1996. Like similar plants, the Ginna nuclear plant has
experienced degradation in some of the tubes that make up each steam
generator. About 30 percent of these tubes have required repair. In
addition, a chemical buildup in some of the tubes has reduced their
heat transfer capability. Both conditions would continue to erode the
plant's performance if the existing steam generators were left in
place. Installation of new steam generators was determined by the
Company to be the most cost-effective, reliable and environmentally
compatible option for the plant. The new steam generators should
result in reduced maintenance costs and help sustain a high level of
plant availability. Cost of replacement is estimated at $115 million,
and preparation to replace these generators began during the plant's
routine 1993 fuel outage.
As a part of the on-going IRP process, the Company in mid-1993
made
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a decision to place Unit 1 at Russell Station (47 MW) on cold standby,
while modifying Units 2, 3 and 4 to meet Federal Environmental
Protection Agency standards. Unit 1 is expected to be in cold standby
in early 1994. Modification of Units 3 and 4 is expected to be
completed by March 1995 at a cost of approximately $4.6 million. In
addition, Unit 12 at Beebee Station and Unit 2 at Russell Station will
be adjusted to produce fewer nitrogen oxides (NOx) by converting a
third of the burners in each to achieve overfire air capability at a
cost of approximately $1.2 million. These actions will allow the
Company to comply with Phase I -Title I, NOx controls requirements of
the Federal Clean Air Act, to meet projected load demands in its
service territory, and to maintain a mix of fuel generation while
remaining competitive and retaining wholesale opportunities.
Outlined below are other results of the IRP process to date:
- The plan calls for evaluating the possibility of using either
alternative generation or current generating equipment in
partnership with certain large industrial customers.
- The Company will continue to use demand side management
programs to reduce the need for generating capacity.
- The Company will consider phasing out the coal-fired Beebee
Station by the year 2000, unless it is converted to natural gas
and operated under a partnership arrangement with a large
customer.
The Company is subject to regulation of rates, service, and sale
of securities, among other matters, by the PSC. On August 24, 1993
the PSC issued an order approving a settlement agreement (1993 Rate
Agreement) among the Company, PSC Staff and other interested parties.
This agreement resolves the Company's rate case proceedings initiated
in July 1992. Retroactive application of new rates to July 1, 1993
was authorized by the PSC. The 1993 Rate Agreement will determine the
Company's rates through June 30, 1996 and includes certain incentive
arrangements providing for both rewards and penalties. The 1993 Rate
Agreement is discussed below.
A summary of recent PSC rate decisions is presented in the table
below. The 1993 Rate Agreement amounts are based on an allowed return
on common equity of 11.50% through June 30, 1996. Earnings between
8.50% and 14.50% will be absorbed/retained by the Company. Earnings
above 14.50% will be refunded to the customers. If, but not unless,
earnings fall below 8.50%, or if cash interest coverage falls below
2.2 times, the Company can seek relief by petitioning the PSC for a
review of the 1993 Rate Agreement terms.
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Amount of
Increase Rate of Rate of
(Decrease) Percent Return on Return on
Class of (Annual Basis) Increase Rate Base Equity
Service Date of Increase (000's) (Decrease) Authorized Authorized
-------- ----------------- -------------- ---------- ----------- -----------
Electric July 12, 1990 $36,059 6.6% 9.91% 12.10%
July 1, 1991 33,133 5.5 9.66 11.70
July 1, 1992 32,220 5.1 9.31 11.00
July 1, 1993* 18,500 2.8 9.46 11.50
July 1, 1994* 20,900 2.9 9.39 11.50
July 1, 1995* 21,800 2.9 9.41 11.50
Gas July 12, 1990 4,250 1.7 9.91 12.10
July 1, 1991 1,148 0.4 9.66 11.70
July 1, 1992 12,316 4.1 9.31 11.00
July 1, 1993* 2,600 1.1 9.46 11.50
July 1, 1994* 4,400 1.8 9.39 11.50
July 1, 1995* 4,300 1.7 9.41 11.50
* See below for additional details.
The following measures were incorporated into the 1993 Rate
Agreement:
- Incentive mechanisms that have the potential to either increase
or reduce earnings from 5 to 70 basis points each, depending on
the Company's ability to meet a variety of prescribed targets
in the areas of electric fuel costs, demand side management,
service quality and integrated resource management (relative
electric production efficiency). During the rate year ending
July 30, 1994, these incentives have the potential to affect
earnings by approximately $12 million.
- Mechanisms for sharing costs between customers and shareholders
for operation and maintenance expenses. In general, non-fuel
operation and maintenance expense variations are treated in
three different ways depending upon the amount of control the
Company can exert over them. Those costs that are directly
manageable (approximately $172 million in the first rate year)
have no sharing and are absorbed by the Company, those costs
that are not significantly affected by management action in the
short run (approximately $34 million in the first rate year)
are trued up 100% and variances resulting from all other such
costs (approximately $110 million in the first rate year) are
shared 50% by customers and 50% by the Company.
- Mechanisms for sharing 50% of overspending variances between
forecasted and actual electric capital expenditures related to
production and transmission facilities. The Company will
retain the savings for cost of money and depreciation on
underspending variances. The settlement also provides for a
sharing mechanism regarding the replacement of the Ginna
nuclear station steam generators. A graduated sharing
percentage is applied for up to $15 million of variances, plus
or minus, from the forecasted cost of $115 million. Variances
above $130 million or below $100 million are absorbed by the
Company.
- An Electric Revenue Adjustment Mechanism designed to stabilize
electric revenues by eliminating the impact of variations in
electric sales. A gas weather normalization clause previously
in place was retained.
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To the extent incentive and sharing mechanisms apply, the
negotiated revenue increase shown in the table above may be adjusted
up or down in the second and third year of the agreement. As shown in
the table below negotiated electric rate increases could be reduced to
zero or increased up to an additional 1.5% in year two, 1.6% in year
three and 1.8% in the following year. Negotiated gas rate increases
could also be reduced to zero or increased up to an additional 0.8% in
year two, 0.9% in year three and 1.1% in the following year, exclusive
of the impact of the Empire State Pipeline going into service.
Electric Gas
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Per After Adjustments Per After Adjustments
----------------- -----------------
Settlement Minimum Maximum Settlement Minimum Maximum
---------- ------- ------- ---------- ------- -------
7/93 - 6/94 2.8% - - 1.1% - -
7/94 - 6/95 2.9% 0% 4.4% 1.8% 0% 2.6%
7/95 - 6/95 2.9% 0% 4.5% 1.7% 0% 2.6%
7/96 - 6/97 Forecast 0% Forecast Forecast 0% Forecast
+1.8% +1.1%
In July 1993 the Company requested approval from the PSC for a
new flexible pricing tariff for major industrial and commercial
electric customers. A settlement in this matter was filed with the
PSC on November 19, 1993 and a decision on whether or not to approve
the settlement is expected early in 1994. Such a tariff would allow
the Company to negotiate competitive electric rates at discount prices
to compete with alternative power sources, such as customer-owned
generation facilities. Under the terms of the settlement, the Company
would absorb 30 percent of any net revenues lost as a result of such
discounts through June 1996, while the remainder would be recovered
from other customers. The portion recoverable after June 1996 is
expected to be determined in a generic proceeding currently being
conducted by the PSC.
In September 1993 the PSC instituted a formal proceeding to
investigate what the Company believes are undercharges to gas
customers for certain gas purchases for the period August 1990 to
August 1992. The Company's estimate of these undercharges is
approximately $7.5 million, of which $2.3 million had been previously
expensed and $5.2 million had been deferred on the Company's balance
sheet. The Company wrote off the $2.0 million balance of the
undercharges as of December 31, 1993. See Item 7 - Management's
Discussion and Analysis of Financial Condition and Results of
operations under the subheading "New York State Public Service
Commission" and Item 8, Note 10 - Commitments and Other Matters under
the subheading "Gas Purchase Undercharges" for a further discussion.
COMPETITION
The Company is operating in an increasingly competitive
environment. In its electric business, this environment includes a
federal trend toward deregulation and a state trend toward incentive
regulation. In addition, excess capacity in the region, new
technology and cost pressures on major customers have created
incentives for major
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customers to investigate different electric supply options.
Initially, those options will include various forms of self
generation, but may eventually include customer access to the
transmission system in order to purchase electricity from suppliers
other than the Company. As discussed under the Regulatory Matters
section, the passage of the National Energy Policy Act of 1992 has
accelerated these competitive challenges.
The Company accepts these challenges and is working to anticipate
the impact of the increased competition. Its Business Plan, both in
detail for one year and in summary for five years, focuses on
improving service while reducing expenses. The Company is engaged in
a continuous process improvement program to find opportunities for
improved service and efficiency and has implemented an early
retirement program in which 173 people, representing approximately
seven percent of its workforce, have retired early and will not be
replaced. In addition, the Company has agreed to a three-year rate
settlement which includes caps on rate increases that approximate or
are less than projected inflation, contains incentive programs that
tie performance to earnings and stabilizes revenue through revenue
adjustment mechanisms. An agreement has been reached with the PSC
Staff and others on the terms of a competitive rate tariff that would
allow negotiated rates with larger industrial and commercial customers
that have competitive electric supply options. These regulatory
changes are discussed in more detail in the Regulatory Matters
section.
Competition in the Company's gas business has existed for some
time, as the larger customers have had the option of obtaining their
own gas supply and transporting it through the Company's distribution
system. This process has been accelerated with FERC Order 636,
discussed in more detail in the Regulatory Matters section above. In
addition, the Company has responded to the changes in the gas business
by positioning itself to obtain greater access to both US and Canadian
natural gas supplies and storage, so that it can take advantage of the
unbundling of services that results from FERC Order 636. A major
element of this strategy went into place in 1993 with the start-up of
the Empire State Pipeline. The Company is engaged in various aspects
of capacity release and is investigating other options available to it
to mitigate its cost and increase its revenue in the new gas
regulatory environment.
Beyond the Company's efforts to remain competitive in its core
business, it is conducting a broad review of its general business
strategy to identify opportunities that will exist in this changed
environment. This may result in expansion of various elements of the
core business or engaging in new, but related, business activity.
ELECTRIC OPERATIONS
The total net generating capacity of the Company's electric
system is 1,237,000 Kw. In addition the Company purchases 120,000 Kw
of firm power under contract and 35,000 Kw of non-contractual peaking
power from the Power Authority, 150,000 Kw of a 1,000,000 Kw pumped
storage plant owned by the Power Authority in Schoharie County, New
York, 22,000 Kw of firm power from the Power Authority's 821,000 Kw
FitzPatrick Nuclear Power Plant near Oswego, New York and 20,000 Kw of
firm power from Hydro-
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Quebec purchased through the Power Authority. The Company's net peak
load of 1,333,000 Kw occurred on July 8, 1993.
The percentages of electricity generated and purchased for the
years 1989-1993 are as follows:
1993 1992 1991 1990 1989
Sources of Generated Energy: ----- ----- ----- ----- -----
Nuclear 57.6% 52.1% 53.8% 48.5% 44.5%
Fossil-Coal 18.2 24.4 23.0 23.8 25.7
-Oil 1.3 2.9 3.3 6.4 5.8
Hydro and Other 2.6 3.5 2.1 3.2 2.6
----- ----- ----- ----- -----
Total Generated Net 79.7 82.9 82.2 81.9 78.6
Purchased 20.3 17.1 17.8 18.1 21.4
----- ----- ----- ----- -----
Total Electric Energy 100.0% 100.0% 100.0% 100.0% 100.0%
===== ===== ===== ===== =====
The Company, six other New York utilities and the Power Authority
are members of the New York Power Pool. The primary purposes of the
Power Pool are to coordinate inter-utility sales of bulk power, long
range planning of generation and transmission facilities, and inter-
utility operating and emergency procedures in order to better assure
reliable, adequate and economic electric service throughout the State.
By agreement with the other members of the New York Power Pool, the
Company is required to maintain a reserve generating capacity equal to
at least 18% of its forecasted peak load. The Company expects to have
reserve margins, which include purchased energy under long term firm
contractual arrangements, of 25%, 26% and 30%, for the years 1994,
1995 and 1996, respectively.
The Company's five major generating facilities are two nuclear
units, the Ginna Nuclear Plant and the Company's 14% share of Nine
Mile Point Nuclear Plant Unit No. 2 (Nine Mile Two), and three fossil
fuel generating stations, the Russell and Beebee Stations and the
Company's 24% share of Oswego Unit Six. These comprise 38%, 12%, 21%,
6% and 16%, respectively, of the Company's current electric system
generating capacity.
Nine Mile Two, a nuclear generating unit in Oswego County, New
York with a capability of 1,080 megawatts (Mw), was completed and
entered commercial service in Spring 1988. Niagara Mohawk Power
Corporation (Niagara) is operating the Unit on behalf of all owners
pursuant to a full power operating license which the NRC issued on
July 2, 1987 for a 40-year term beginning October 31, 1986. Under
arrangements dating from September 1975, ownership, output and cost of
the project are shared by the Company (14%), Niagara (41%) Long Island
Lighting Company (18%), New York State Electric & Gas Corporation
(18%) and Central Hudson Gas & Electric Corporation (9%). Under the
operating Agreement, Niagara serves as operator of Nine Mile Two, but
all five cotenant owners shared certain policy, budget and managerial
oversight functions. The base term of the Operating Agreement is 24
months from its effective date, with automatic extension, unless
terminated by written notice of one or more of the cotenant owners to
the other cotenant owners; such termination becomes effective six
months from the receipt of any such notice of termination by all the
cotenant owners receiving such notice. The owners petitioned the PSC
in March 1993 for approval of the Operating Agreement and
- 11 -
understand that action by the PSC will be taken thereon early in 1994.
The Company has four licensed hydroelectric generating stations
with an aggregate capability of 49 megawatts. Although applications
for renewal of those licenses were timely made in 1991, the FERC was
unable to complete processing of many such applications by the
December 31, 1993 license expiration. The Company and many other
hydro project owners are thus operating under FERC annual licenses
that essentially extend the terms of the old licenses year-to year
until processing of new ones can be completed. The Company
understands that renewal licenses for three of its four stations are
scheduled to be issued by the second quarter of 1994, but a license
for the fourth -- the smallest -- may be delayed or even denied
depending on what environmental conditions are determined to apply to
its continued operation. That determination, as well as decisions on
what environmental conditions FERC will impose in new licenses for the
other three stations, depends in part on the content of state water
quality certifications issued by the New York State Department of
Environmental Conservation (NYSDEC). Certifications NYSDEC issued for
the Company's projects in late 1992 are in the process of revisions,
owing to a November 1993 decision by the State of New York's highest
court which, in a case brought by another utility licensee, held in
effect that NYSDEC certifications exceeded the authority of the agency
under applicable law. Draft revisions purporting to comply with that
decision are currently under review in a NYSDEC administrative
proceeding initially brought by the Company to challenge the 1992
certifications. Overly stringent environmental conditions or other
governmental requirements could nullify or greatly impair the economic
viability of one or more of the Company's hydro stations and could
even compel it to abandon efforts to relicense the affected station or
stations. If, however, conditions in the renewal licenses for these
stations can be limited to those proposed by FERC Staff in its
evaluation, the Company believes that it can continue to operate them
economically.
The Company's Ginna Nuclear Plant, which has been in commercial
operation since July 1, 1970, provides 470 Mw of the Company's
electric generating capacity. In August 1991 the NRC approved the
Company's application for amendment to extend the Ginna Nuclear Plant
facility operating license expiration date from April 25, 2006 to
September 18, 2009.
In December 1992, the Company announced that it will replace the
two steam generators in the Ginna Nuclear Plant in 1996. Cost of the
replacement is estimated at $115 million. The units themselves cost
about $40 million, and installation will cost about $60 million. The
remainder of the cost is for engineering, radiation protection, site
support, interest charges and other services.
During 1993, fixed price contracts were issued for both the steam
generators and for the installation. Preparation for the replacement
began in 1993 and will continue until the replacement in 1996. Steam
generator fabrication is well underway and detailed engineering will
begin in 1994. The existing steam generators, once removed, will
become low-level radioactive waste. They will be placed in a
protective structure which will be built on site, pending as yet
undetermined permanent disposal.
- 12 -
Like similar plants, Ginna has experienced degradation in some
of the 3,260 tubes that make up each steam generator. About 30
percent of the tubes have required repair. In addition, a chemical
buildup on some of the tubes has reduced their ability to transfer
heat, causing a loss in plant output of about 3 percent, or 15
megawatts. Both conditions would continue to erode the plant's
performance if the existing steam generators were left in place. A
number of design improvements have been incorporated into the new
steam generators. These improvements combined with continued
aggressive maintenance should result in a higher level of plant
availability.
The decision regarding Ginna is one part of the Integrated
Resource Plan (IRP) previously discussed. Installation of new steam
generators was determined to be the most cost-effective, reliable and
environmentally compatible option for the plant.
The gross and net book cost of the Ginna Plant as of December 31,
1993 are $470 million and $263 million, respectively. From time to
time the NRC issues directives requiring all or a certain group of
reactor licensees to perform analyses as to their ability to meet
specified criteria, guidelines or operating objectives and where
necessary to modify facilities, systems or procedures to conform
thereto. Typically, these directives are premised on the NRC's
obligation to protect the public health and safety. The Company is
reviewing several such directives and is in the process of
implementing a variety of modifications based on these directives and
resulting analyses. Additional analyses and modifications can be
expected. Expenditures, including AFUDC, at the Ginna Plant
(including the cost of these modifications and $17.1 million in 1994,
$30.6 million in 1995, and $51.4 million in 1996 for steam generator
replacement as discussed above) are estimated to be $43.2 million,
$57.0 million and $71.9 million for the years 1994, 1995 and 1996,
respectively, and are included in the capital expenditure amounts
presented under Item 7 - Management's Discussion and Analysis of
Financial Condition and Results of Operations.
See Item 8, Note 10 - Commitments and Other Matters, "Nuclear-
Related Matters", for a discussion relating to nuclear insurance
including information on coverages and maximum assessments.
GAS OPERATIONS
The total daily capacity of the Company's gas system, reflecting
the maximum demand which the transmission system can accept without a
deficiency, is 4,485,000 Therms (one Therm is equivalent to 1,000,000
British Thermal Units). On January 19, 1994, the Company experienced
its maximum daily send out of approximately 4,740,000 Therms. If a
deficiency exists, the Company is able to manually bypass the
regulators in the system to meet a demand of up to 10% in excess of
capacity.
As a result of the implementation of FERC Order 636, and the
commencement of operation of the Empire State Pipeline (Empire), the
Company now purchases all of its required gas supply from numerous
producers and marketers under contracts containing varying terms and
conditions. The Company anticipates no problem with obtaining
reliable,
- 13 -
competitively priced natural gas in the future. See Item 7 -
Management's Discussion and Analysis of Financial Condition and
Results of Operations under the captions "Energy Costs and Supply -
Gas" and "FERC Order 636" for a discussion of those topics and
"Capital Requirements and Gas Operations" for a discussion of Empire.
The Company continues to provide new and additional gas service.
Of 231,937 residential gas spaceheating customers at December 31,
1993, 3,841 were added during 1993, and 37% of those were conversions
from other fuels.
Approximately 23% of the gas delivered to customers by the
Company during 1993 was purchased directly by commercial, industrial
and municipal customers from brokers, producers and pipelines. The
Company provided the transportation of gas on its system to these
customers' premises.
FUEL SUPPLY
NUCLEAR
Generally, the nuclear fuel cycle consists of the following: (1)
the procurement of uranium concentrate (yellowcake), (2) the
conversion of uranium concentrate to uranium hexaflouride, (3) the
enrichment of the uranium hexaflouride, (4) the fabrication of fuel
assemblies, (5) the utilization of the nuclear fuel in generating
station reactors and (6) the appropriate storage or disposition of
spent fuel and radioactive wastes. Arrangements for nuclear fuel
materials and services for the Ginna Plant and Nine Mile Two have been
made to permit operation of the units through the years indicated:
Ginna Plant Nine Mile Two/(1)/
------------ -------------------
Uranium Concentrate 1995 2000/(2)/
Conversion 1997/(3)/ 2000/(2)/
Enrichment (4) (4)
Fabrication 1995 2003
--------------
(1) Information was supplied by Niagara Mohawk Power Corporation.
(2) Arrangements have been made for procuring the majority of the
uranium and conversion requirements through 2000, leaving the
remaining portion of the requirements uncommitted.
(3) Seventy percent of the conversion requirements have been procured
through 1997.
(4) Thirty years from 1984 or life of reactor, whichever is less.
See the following discussion.
The Company has a contract with United States Enrichment
Corporation (USEC) formerly with the federal Department of Energy
(DOE)
- 14 -
for nuclear fuel enrichment services which assures provision of 70% of
the Ginna Plant's requirements throughout its service life or 30
years, whichever is less. No payment obligation accrues unless such
enrichment services are needed. Annually, the Company is permitted to
decline USEC-furnished enrichment for a future year upon giving ten
years' notice. Consistent with that provision, the Company has
terminated its commitment to USEC for the years 2000, 2001 and 2002.
The USEC waived, for an interim period, the obligation to give ten
years notice for 2003. The Company has secured the remaining 30% of
its Ginna requirements for the reload years 1994 through 1995 under
different arrangements with USEC. The Company plans to meet its
enrichment requirements for years beyond those already committed by
making further arrangements with USEC or by contracting with third
parties. The cost of USEC enrichment services utilized for the next
seven reload years (priced at the most current rate) range from $4
million to $7 million per year.
The Company is pursuing arrangements for the supply of uranium
requirements and related services beyond those years for which
arrangements have been made as shown above. The prices and terms of
any such arrangements cannot be predicted at this time.
The average annual cost of nuclear fuel per million BTU used for
electric generation for the last five years is as follows:
1993 1992 1991 1990 1989
----- ----- ----- ----- -----
Ginna $.400 $.359 $.442 $.485 $.498
Nine Mile Two $.515 $.558 $.714 $.990 $.998
There are presently no facilities in operation in the United
States available for the reprocessing of spent nuclear fuel from
utility companies. In the Company's determination of nuclear fuel
costs it has taken into account that nuclear fuel would not be
reprocessed and has provided for disposal costs in accordance with the
Nuclear Waste Policy Act discussed below. The Company currently has
adequate interim storage capability at the Ginna Plant, including full
core discharge capability through the year 1999 based on anticipated
fuel usage.
The cost of nuclear fuel and estimated permanent storage costs of
spent nuclear fuel are charged to operating expense on the basis of
the thermal output of the reactor. These costs are charged to
customers through the fuel cost adjustment clause and base rates.
The Nuclear Waste Policy Act (Act) of 1982, as amended, requires
the DOE to establish a nuclear waste disposal site and to take title
to nuclear waste. A permanent DOE high level nuclear waste repository
is not expected to be operational before the year 2010. The DOE is
pursuing efforts to establish a monitored retrievable interim storage
facility which may allow it to take title to and possession of nuclear
waste prior to the establishment of a permanent repository. The Act
provides for a determination of the fees collectible by the DOE for
the disposal of nuclear fuel irradiated prior to April 7, 1983 and for
three payment options. The option of a single payment to be made at
any time prior to the first delivery of fuel to the DOE was selected
in June 1985. The Company estimates the fees, including accrued
interest, owed to the DOE
- 15 -
to be $68.1 million at December 31, 1993. The Company is allowed by
the PSC to recover in rates these costs. The estimated fees are
classified as a long term liability and interest is accrued at the
three-month Treasury bill rate, adjusted quarterly. The Act also
requires the DOE to provide for the disposal of nuclear fuel
irradiated after April 6, 1983, for a charge of one mill ($.001) per
Kwh of nuclear energy generated and sold. This charge is currently
being collected from customers and paid to the DOE pursuant to PSC
authorization. The Company expects to utilize on-site storage for all
spent or retired fuel assemblies until an interim or permanent nuclear
disposal facility is operational.
Decommissioning costs (costs to take the plant out of service in
the future) for the Ginna Plant are estimated to be approximately
$150.7 million, and those for the Company's 14% share of Nine Mile Two
are estimated to be approximately $34.3 million (January 1993
dollars). Through December 31, 1993, the Company has accrued and
recovered in rates $61.2 million for this purpose and is currently
accruing for decommissioning costs at a rate of approximately $8.9
million per year based on the use of a combination of internal and
external sinking funds.
See Notes 1 and 10 of the Notes to Financial Statements under
Item 8 for additional information regarding nuclear plant
decommissioning and DOE uranium enrichment facility decontamination
and decommissioning.
COAL
The Company's present annual coal requirement is approximately
570,000 tons. In 1993 approximately 5% of its requirements were
purchased under contract and the balance on the open market. The
Company is meeting its requirements during early 1994 through contract
purchases. Normally, the Company maintains a reserve supply of coal
ranging from a 30 to a 60 day supply at maximum burn rates.
The sulfur content of the coal utilized in the Company's existing
coal-fired facilities ranges from 1.4 to 1.9 pounds per million BTU.
Under existing New York State regulations, the Company's coal-fired
facilities may not burn coal which exceeds 2.5 pounds per million BTU,
which averages more than 1.9 pounds per million BTU over a three-month
period or which averages more than 1.7 pounds per million BTU over a
12-month period.
The average annual delivered cost of coal used for electric
generation was as follows:
1993 1992 1991 1990 1989
------ ------ ------ ------ ------
Per Ton $37.27 $39.28 $41.95 $42.27 $41.11
Per Million BTU $1.42 $1.48 $1.61 $1.60 $1.56
OIL
The Company's present annual requirement at Company-operated
facilities is estimated at 800,000 gallons of #2 fuel oil. The
Company currently intends to meet this requirement through
competitively bid
- 16 -
contracts.
ENVIRONMENTAL QUALITY CONTROL
Operations at the Company's facilities are subject to various
Federal, state and local environmental standards. To assure the
Company's compliance with these requirements, the Company expended
approximately $1.0 million on a variety of projects and facility
additions during 1993.
The most significant environmental control measures affecting
Company operations involve the regulation of the quality of fuel
burned in utility boilers, the evaluation to determine ambient air
quality standards, the imposition of emission limitations on
discharges into the air and effluent limitations and pretreatment
standards on liquid discharges, the evaluation to determine water
quality objectives for water bodies into which Company facilities
discharge, the regulation of toxic substances and the disposal of
solid wastes.
The Company is monitoring a public concern tending to associate
health effects with electromagnetic fields from power lines. Together
with other New York utilities, the Company funded some of the earliest
governmentally-directed research on the question and it continues,
with other electric utilities nationwide, to underwrite a broad
program of industry-sponsored research in this area. The Company also
participated with other New York utilities in compiling information on
the state's existing high voltage lines in an initiative which served
as a basis for PSC adoption of field limits applicable to the
construction of new high voltage lines. The Company has no definitive
plans to construct new high voltage lines for its system, but, in
connection with Clean Air Act compliance and planning of generation
resources, it is considering possible transmission reinforcements; at
least one option could require such construction. On request, the
Company performs surveys of electromagnetic fields on customer
premises. None of its lines have been found to exceed the State field
limits applicable to new construction.
The Federal Low Level Radioactive Waste Policy Act (Act), as
amended in 1985, provides for states to join compacts or individually
develop their own low level radioactive waste disposal sites. The
portion of the Act that requires a state which fails to provide access
to a licensed disposal site by 1996 to take title to such waste was
declared unconstitutional by the United States Supreme Court on June
19, 1992, but the court upheld other provisions of the Act enabling
sited states to increase charges on shipments from non-sited states
and ultimately to refuse such shipments altogether. New York has
entered into a contract with the State of South Carolina for the
disposal of all low level radioactive waste through June 1994. The
Company can provide no assurance as to what disposal arrangements, if
any, New York will have in place after that date. The State has not
passed legislation that would designate a site for the disposal of low
level radioactive waste. In 1990, Governor Cuomo certified a plan
that requires all nuclear power plants in New York State to store
their low level radioactive waste on site from January 1, 1993, until
the end of 1995. The Company has interim storage capacity at the
Ginna Plant through December 31, 1995 and
- 17 -
efforts are being pursued to extend storage capacity to mid-1999, if
necessary, at this plant. A low level radioactive waste management
and contingency plan is currently ongoing to provide assurance that
Nine Mile Two will be properly prepared to handle interim storage of
low level radioactive waste for the next ten years.
The Company has wastewater discharge permits from NYSDEC for its
Beebee, Russell and Ginna Stations. The Russell Station permit is
currently in the renewal process. The Beebee and Ginna Station
permits were renewed in December 1993 and July 1992, respectively.
While no significant changes are anticipated, modifications to the
wastewater treatment systems may be necessary. The Company believes
that any costs associated with such modifications would be fully
recoverable in rates.
The Company believes that additional expenditures and costs made
necessary by environmental regulations will be fully allowable for
ratemaking purposes. Expenditures for meeting various Federal, State
and local environmental standards are estimated to be $6.7 million for
the year 1994, $4.8 million for the year 1995 and $3.9 million for the
year 1996. These expenditures are included under Item 7 -
Management's Discussion and Analysis of Financial Condition and
Results of Operations, in the table entitled "Capital Requirements".
See Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations and Item 8, Note 10 - Commitments
and Other Matters, with respect to other environmental matters.
RESEARCH AND DEVELOPMENT
The Company's research activities are designed to improve existing
energy technologies and to develop new technologies for the
production, distribution, utilization and conservation of energy while
preserving environmental quality. Research and development
expenditures in 1993, 1992 and 1991 were $8,329,278, $7,416,945, and
$6,404,766, respectively. These expenditures represent the Company's
contribution to research administered by Electric Power Research
Institute and Empire State Electric Energy Research Corporation, the
Company's share of research related to Nine Mile Two, an assessment
for state government sponsored research by the New York State Energy
Research and Development Authority, as well as internal research
projects.
- 18 -
Electric Department Statistics
Year Ended December 31 1993 1992 1991 1990 1989 1988
---- ---- ---- ---- ---- ----
Electric Revenue (000's)
Residential $235,286 $220,866 $212,327 $197,612 $191,732 $188,451
Commercial 196,456 184,815 181,561 165,445 155,076 149,663
Industrial 147,396 142,392 141,001 130,012 124,634 120,490
Other (Includes Unbilled Revenue) 59,817 60,194 54,041 58,861 71,654 56,033
--------- --------- --------- --------- --------- ---------
Electric revenue from our customers 638,955 608,267 588,930 551,930 543,096 514,637
Other electric utilities 16,361 25,541 28,612 42,465 38,028 29,966
--------- --------- --------- --------- --------- ---------
Total electric revenue 655,316 633,808 617,542 594,395 581,124 544,603
--------- --------- --------- --------- --------- ---------
Electric Expense (000's)
Fuel used in electric generation 45,871 48,376 65,105 76,420 75,873 65,787
Purchased electricity 31,563 29,706 27,683 34,264 39,645 30,299
Other operation 188,684 183,118 168,610 155,289 137,458 124,871
Maintenance 52,464 53,714 57,032 53,880 55,915 44,060
Depreciation and Amortization 72,326 73,213 72,746 67,302 65,287 60,444
Taxes - local, state and other 96,043 94,841 86,925 77,323 71,361 66,426
--------- --------- --------- --------- --------- ---------
Total electric expense 486,951 482,968 478,101 464,478 445,539 391,887
--------- --------- --------- --------- --------- ---------
Operating Income before
Federal Income Tax 168,365 150,840 139,441 129,917 135,585 152,716
Federal income tax 43,845 38,046 31,390 30,670 29,887 34,093
--------- --------- --------- --------- --------- ---------
Operating Income from
Electric Operations (000's) $124,520 $112,794 $108,051 $ 99,247 $105,698 $118,623
--------- --------- --------- --------- --------- ---------
Electric Operating Ratio % 48.6 49.7 51.6 53.8 53.2 48.7
Electric Sales - KWH (000's)
Residential 2,124,763 2,084,466 2,085,429 2,075,072 2,072,047 2,051,808
Commercial 1,987,490 1,937,950 1,928,730 1,897,583 1,832,521 1,792,162
Industrial 1,894,026 1,929,498 1,917,796 1,931,633 1,906,429 1,869,417
Other 505,341 503,330 507,765 490,077 491,905 483,730
--------- --------- --------- --------- --------- ---------
Total billed 6,511,620 6,455,244 6,439,720 6,394,365 6,302,902 6,197,117
Unbilled sales (4,556) 742 7,657 (25,421) 33,406 -
--------- --------- --------- --------- --------- ---------
Total customer sales 6,507,064 6,455,986 6,447,377 6,368,944 6,336,308 6,197,117
Other electric utilities 743,588 1,062,738 1,034,370 1,316,379 1,255,282 1,149,900
--------- --------- --------- --------- --------- ---------
Total electric sales 7,250,652 7,518,724 7,481,747 7,685,323 7,591,590 7,347,017
--------- --------- --------- --------- --------- ---------
Electric Customers at December 31
Residential 302,219 300,344 298,440 296,110 293,418 290,037
Commercial 29,635 29,339 28,856 28,804 28,386 27,888
Industrial 1,382 1,386 1,388 1,428 1,422 1,392
Other 2,638 2,605 2,558 2,553 2,512 2,326
--------- --------- --------- --------- --------- ---------
Total electric customers 335,874 333,674 331,242 328,895 325,738 321,643
--------- --------- --------- --------- --------- ---------
Electricity Generated and
Purchased - KWH (000's)
Fossil 1,520,936 2,197,757 2,146,664 2,505,110 2,578,006 2,214,588
Nuclear 4,495,457 4,191,035 4,391,480 4,016,721 3,659,185 3,884,884
Hydro 199,239 278,318 174,239 244,539 175,085 169,002
Pumped storage 233,477 226,391 240,206 269,966 290,582 292,305
Less energy for pumping (355,725) (344,245) (364,520) (405,966) (429,895) (430,401)
Other 2,559 811 1,269 20,408 54,893 2,195
--------- --------- --------- --------- --------- ---------
Total generated - Net 6,095,943 6,550,067 6,589,338 6,650,778 6,327,856 6,132,573
Purchased 1,583,582 1,389,875 1,451,208 1,498,089 1,757,413 1,705,755
--------- --------- --------- --------- --------- ---------
Total electric energy 7,679,525 7,939,942 8,040,546 8,148,867 8,085,269 7,838,328
--------- --------- --------- --------- --------- ---------
System Net Capability -
KW at December 31
Fossil 541,000 541,000 541,000 541,000 541,000 541,000
Nuclear 620,000 617,000 622,000 621,000 621,000 621,000
Hydro 47,000 47,000 47,000 47,000 47,000 47,000
Other 29,000 29,000 29,000 29,000 29,000 29,000
Purchased 347,000 348,000 354,000 356,000 369,000 360,000
--------- --------- --------- --------- --------- ---------
Total system net capability 1,584,000 1,582,000 1,593,000 1,594,000 1,607,000 1,598,000
--------- --------- --------- --------- --------- ---------
Net Peak Load - KW 1,333,000 1,252,000 1,297,000 1,208,000 1,249,000 1,275,000
Annual Load Factor - Net % 59.1 62.5 61.7 64.6 62.4 59.7
- 19 -
Gas Department Statistics
Year Ended December 31 1993 1992 1991 1990 1989 1988
---- ---- ---- ---- ---- ----
Gas Revenue (000's)
Residential $ 5,526 $ 6,456 $ 6,354 $ 6,508 $ 6,770 $ 6,439
Residential spaceheating 196,411 183,405 157,458 159,501 165,832 150,383
Commercial 45,620 44,274 40,196 43,534 46,897 44,781
Industrial 6,346 6,418 6,761 9,674 9,371 9,859
Municipal and other
(Includes Unbilled Revenue) 39,805 21,171 24,959 17,279 35,703 19,755
--------- --------- --------- --------- --------- ---------
Total gas revenue 293,708 261,724 235,728 236,496 264,573 231,217
--------- --------- --------- --------- --------- ---------
Gas Expense (000's)
Gas purchased for resale 166,884 141,291 129,779 132,512 152,623 129,596
Other operation 46,697 43,506 39,830 39,307 36,306 34,818
Maintenance 9,229 9,006 8,383 8,510 8,401 8,515
Depreciation 11,851 11,815 11,435 10,465 9,776 9,259
Taxes - local, state and other 30,849 29,411 26,724 23,711 23,980 22,209
--------- --------- --------- --------- --------- ---------
Total gas expense 265,510 235,029 216,151 214,505 231,086 204,397
--------- --------- --------- --------- --------- ---------
Operating Income before
Federal Income Tax 28,198 26,695 19,577 21,991 33,487 26,820
Federal income tax 5,485 5,545 2,869 3,820 7,952 6,569
--------- --------- --------- --------- --------- ---------
Operating Income from
Gas Operations (000's) $ 22,713 $ 21,150 $ 16,708 $ 18,171 $ 25,535 $ 20,251
--------- --------- --------- --------- --------- ---------
Gas Operating Ratio % 75.9 74.1 75.5 76.3 74.6 74.8
Gas Sales - Therms (000's)
Residential 6,735 8,780 9,068 9,644 10,321 10,374
Residential spaceheating 289,252 287,614 253,655 262,458 277,267 267,697
Commerical 77,326 78,993 71,509 77,617 84,152 86,413
Industrial 11,792 12,437 13,000 18,536 17,873 20,174
Municipal 11,947 11,410 10,580 13,350 12,319 15,514
--------- --------- --------- --------- --------- ---------
Total billed 397,052 399,234 357,812 381,605 401,932 400,172
Unbilled sales 8,017 13 3,291 (22,840) 20,320 -
--------- --------- --------- --------- --------- ---------
Total gas sales 405,069 399,247 361,103 358,765 422,252 400,172
Transportation of customer-owned gas 124,436 126,140 109,835 101,98 105,303 83,594
--------- --------- --------- --------- --------- ---------
Total gas sold and transported 529,505 525,387 470,938 460,750 527,555 483,766
--------- --------- --------- --------- --------- ---------
Gas Customers at December 31
Residential 18,389 19,114 21,448 22,410 23,321 24,139
Residential spaceheating 231,937 228,096 222,918 219,242 215,120 210,710
Commercial 18,636 18,378 18,151 17,920 17,677 17,213
Industrial 924 932 921 960 1,095 1,042
Municipal 1,001 1,010 983 984 1,067 1,039
Transportation 466 424 423 401 367 270
--------- --------- --------- --------- --------- ---------
Total gas customers 271,353 267,954 264,844 261,917 258,647 254,413
--------- --------- --------- --------- --------- ---------
Gas - Therms (000's)
Purchased for resale 347,778 360,493 384,643 366,684 426,941 408,044
Gas from storage 76,378 53,757 16,755 - - -
Other 1,039 1,061 1,617 2,525 1,764 1,967
--------- --------- --------- --------- --------- ---------
Total gas available 425,195 415,311 403,015 369,209 428,705 410,011
--------- --------- --------- --------- --------- ---------
Cost of gas per therm (cents) 36.79c 35.35c 32.96c 36.03c 35.74c 31.76c
Total Daily Capacity -
Therms at December 31* 4,485,000 4,485,000 4,485,000 4,485,000 4,485,000 4,485,000
--------- --------- --------- --------- --------- ---------
Maximum daily throughput - Therms 3,864,850 3,768,470 3,539,260 3,539,820 3,719,050 3,744,500
Degree Days (Calendar Month)
For the period 7,044 6,981 6,146 5,924 7,109 6,862
Percent colder (warmer) than normal 4.4 3.4 (8.4) (11.8) 5.9 1.6
*Method for determining daily capacity, based on current network analysis,
reflects the maximum demand which the transmission systems can accept without
a deficiency.
- 20 -
ITEM 2. PROPERTIES
ELECTRIC PROPERTIES
The net capability of the Company's electric generating
plants in operation as of December 31, 1993, the net generation of
each plant for the year ended December 31, 1993, and the year each
plant was placed in service are as set forth below:
Electric Generating Plants
Year Units Net Generation
Placed Net Capability (thousands
Type of Fuel in Service (Mw) kwh)
------------ ---------- -------------- --------------
Beebee Station
(Steam) Coal 1959 80 338,436
Beebee Station
(Gas Turbine) Oil 1969 14 340
Russell Station
(Steam) Coal 1949-1957 257 1,083,523
Ginna Station
(Steam) Nuclear 1970 470 3,491,727
Oswego Unit 6/(1)/
(Steam) Oil 1980 204 98,977
Nine Mile Point
Unit No. 2/(2)/
(Steam) Nuclear 1988 150 1,003,730
Station No. 9
(Gas Turbine) Gas 1969 15 2,217
Station 5
(Hydro) Water 1917 39 152,007
5 Other Stations
(Hydro) Water 1906-1960 8 47,232
----------
6,218,189
Pumped Storage/(3)/ 233,477
Less energy for
pumping (355,725)
----- ----------
1,237 6,095,941
===== ==========
(1) Represents 24% share of jointly-owned facility.
(2) Represents 14% share of jointly-owned facility.
(3) Owned and operated by the Power Authority.
The Company owns 146 distribution substations having an
aggregate rated transformer capacity of approximately 2,058,579 Kva,
of which 137, having an aggregate rated capacity of 1,879,413 Kva,
were
- 21 -
located on lands owned in fee, and 9 of which, having an aggregate
rated capacity of 179,166 Kva, were located on land under easements,
leases or license agreements. The Company also has 73,950 line
transformers with a capacity of 2,894,753 Kva. The Company also owns
24 transmission substations having an aggregate rated capacity of
approximately 2,996,017 Kva of which 23, having an aggregate rated
capacity of approximately 2,921,350 Kva, were located on land owned in
fee and 1, having a rated capacity of 74,667 Kva, was located on land
under easements. The Company's transmission system consists of
approximately 702 wire miles of overhead lines and 396 wire miles of
underground lines. The distribution system consists of approximately
15,987 wire miles of overhead lines, approximately 3,427 wire miles of
underground lines and 340,546 installed meters. The electric
transmission and distribution system is entirely interconnected and,
in the central portion of the City of Rochester, is underground. The
electric system of the Company is directly interconnected with other
electric utility systems in New York and indirectly interconnected
with most of the electric utility systems in the United States and
Canada. (See Item 1 - Business, "Electric Operations".)
GAS PROPERTIES
The gas distribution systems consists of 4,175 miles of gas
mains and 278,850 installed meters. (See Item 1 - Business, "Gas
Operations".)
OTHER PROPERTIES
The Company owns a ten-story office building centrally
located in Rochester, an Operations Center south of Rochester, and
other structures and property.
The Company has good title in fee, with minor exceptions,
to its principal plants and important units, except rights of way and
flowage rights, subject to restrictions, reservations, rights of way,
leases, easements, covenants, contracts, similar encumbrances and
minor defects of a character common to properties of the size and
nature of those of the Company. The electric and gas transmission and
distribution lines and mains are located in part in or upon public
streets and highways and in part on private property, either pursuant
to easements granted by the apparent owner containing in some
instances removal and relocation provisions and time limitations, or
without easements but without objection of the owners. The First
Mortgage securing the Company's outstanding bonds is a first lien on
substantially all the property owned by the Company (except cash and
accounts receivable). A mortgage securing the Company's revolving
credit agreement is also a lien on substantially all the property
owned by the Company (except cash and accounts receivable) subject and
subordinate to the lien of the First Mortgage. The Company has a
credit agreement with a domestic bank under which short term
borrowings are secured by the Company's accounts receivable.
ITEM 3. LEGAL PROCEEDINGS
See Item 8, Note 10 - Commitments and Other Matters.
- 22 -
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders
during the fourth quarter of the fiscal year ended December 31, 1993.
ITEM 4-A. EXECUTIVE OFFICERS OF THE REGISTRANT
Age Positions, Offices and Business
Name 12/31/93 Experience 1989 to Date
---- -------- -----------------------------------------
Roger W. Kober 60 Chairman of the Board, President and
Chief Executive Officer - 1992 to Date
President and Chief Executive Officer -
1991
President and Chief Operating Officer -
1989
David K. Laniak 58 Senior Vice President, Gas, Electric
Distribution and Customer Services -
1990 to Date
Senior Vice President, Gas, Electric
Distribution and Corporate Planning -
1989
Thomas S. Richards 50 Senior Vice President, Finance and
General Counsel - October, 1993 to date
General Counsel - October, 1991 to
October, 1993
Partner at the law firm of Nixon,
Hargrave, Devans & Doyle
Clinton Square, P.O. Box 1051
Rochester, NY 14603 prior to joining
the Company in 1991
Robert E. Smith 56 Senior Vice President, Production and
Engineering - 1989 to Date
David C. Heiligman 53 Vice President, Secretary and Treasurer -
1989 to Date
Robert C. Mecredy 48 Vice President, Ginna Nuclear Production
- 1990 to Date
Division Manager, Nuclear Production -
1990
General Manager, Nuclear Production -
1989
Wilfred J. Schrouder, Jr. 52 Vice President, Employee Relations,
Public Affairs and Materials Management
- 1990 to Date
Vice President, Employee Relations and
Public Affairs - 1989
- 23 -
The term of office of each officer extends to the meeting of
the Board of Directors following the next annual meeting of
shareholders and until his or her successor is elected and qualifies.
- 24 -
PART II
ITEM 5 MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
COMMON STOCK AND DIVIDENDS
- -------------------------------------------------
Earnings/Dividends 1993 1992 1991
- -------------------------------------------------
Earnings per weighted
average share $2.00 $1.86 $1.60
Dividends paid
per share $1.72 $1.68 $1.62
- -------------------------------------------------
- -------------------------------------------------------
Shares/Shareholders 1993 1992 1991
- -------------------------------------------------------
Number of shares (000's)
Weighted average 35,599 33,258 31,794
Actual number at
December 31 36,911 34,797 32,101
Number of shareholders
at December 31 38,102 39,017 39,157
- -------------------------------------------------------
Tax Status of Cash Dividends
Cash dividends paid in 1993, 1992 and 1991 were 100 percent taxable for
Federal income tax purposes.
Dividend Policy
The Company has paid cash dividends quarterly on its Common Stock without
interruption since it became publicly held in 1949. The level of future cash
dividend payments will be dependent upon the Company's future earnings, its
financial requirements and other factors. The Company's Certificate of
Incorporation provides for the payment of dividends on Common Stock out of the
surplus net profits (retained earnings) of the Company.
Quarterly dividends on Common Stock are generally paid on the twenty-fifth day
of January, April, July and October. In January 1994, the Company paid a cash
dividend of $.44 per share on its Common Stock, up $.01 from the prior quarterly
dividend payment of $.43. The January 1994 dividend payment is equivalent to
$1.76 on an annual basis.
Common Stock Trading
Shares of the Company's Common Stock are traded on the New York Stock Exchange
under the symbol "RGS".
- -------------------------------------------------------------
1993 1992 1991
- -------------------------------------------------------------
Common Stock--Price Range
High
1st quarter 28 3/8 23 1/4 20 3/4
2nd quarter 28 24 20 1/2
3rd quarter 29 3/4 24 3/4 20 7/8
4th quarter 29 1/4 25 1/4 23 7/8
Low
1st quarter 24 1/8 20 7/8 17 3/4
2nd quarter 25 1/2 21 1/4 19
3rd quarter 27 3/8 22 3/4 19
4th quarter 24 3/4 23 1/8 20 1/8
At December 31 26 1/4 24 1/2 23 1/4
- -------------------------------------------------------------
- 25-
Item 6. Selected Financial Data
Consolidated Summary of Operations Year Ended December 31
(Thousands of Dollars) 1993 1992 1991 1990 1989 1988
- ------------------------------------------------------------------------------------------------------------------------
Operating Revenues
Electric $ 638,955 $ 608,267 $ 588,930 $ 551,930 $ 543,096 $ 514,637
Gas 293,708 261,724 235,728 236,496 264,573 231,217
----------------------------------------------------------------------------------------------------------------------
932,663 869,991 824,658 788,426 807,669 745,854
Electric sales to other utilities 16,361 25,541 28,612 42,465 38,028 29,966
----------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 949,024 895,532 853,270 830,891 845,697 775,820
----------------------------------------------------------------------------------------------------------------------
Operating Expenses
Fuel Expenses
Electric fuels 45,871 48,376 65,105 76,420 75,873 65,787
Purchased electricity 31,563 29,706 27,683 34,264 39,645 30,299
Gas purchased for resale 166,884 141,291 129,779 132,512 152,623 129,596
----------------------------------------------------------------------------------------------------------------------
Total Fuel Expenses 244,318 219,373 222,567 243,196 268,141 225,682
----------------------------------------------------------------------------------------------------------------------
Operating Revenues Less Fuel Expenses 704,706 676,159 630,703 587,695 577,556 550,138
Other Operating Expenses
Operations excluding fuel expenses 235,381 226,624 208,440 194,594 173,764 159,689
Maintenance 61,693 62,720 65,415 62,391 64,316 52,575
Depreciation and Amortization 84,177 85,028 84,181 77,767 75,063 69,703
Taxes - local, state and other 126,892 124,252 113,649 101,035 95,341 88,635
Federal income tax - current 33,453 36,101 28,766 20,661 20,509 20,363
- deferred 15,877 7,490 5,493 13,829 17,330 20,299
----------------------------------------------------------------------------------------------------------------------
Total Other Operating Expenses 557,473 542,215 505,944 470,277 446,323 411,264
----------------------------------------------------------------------------------------------------------------------
Operating Income 147,233 133,944 124,759 117,418 131,233 138,874
-----------------------------------------------------------------------------------------------------------------------
Other Income and Deductions
Allowance for other funds used during
construction 153 164 675 2,689 2,261 2,047
Federal income tax 9,827 4,195 4,580 2,459 1,439 1,683
Pension plan curtailment (8,179) - - - - -
Regulatory disallowances (1,953) (8,215) (10,000) - (2,100) -
Other, net (7,074) 6,155 6,078 4,062 8,328 6,901
----------------------------------------------------------------------------------------------------------------------
Total Other Income and (Deductions) (7,226) 2,299 1,333 9,210 9,928 10,631
----------------------------------------------------------------------------------------------------------------------
Income before Interest Charges 140,007 136,243 126,092 126,628 141,161 149,505
----------------------------------------------------------------------------------------------------------------------
Interest Charges
Long term debt 56,451 60,810 63,918 64,873 68,628 72,270
Short term debt 1,487 1,950 2,623 1,070 - -
Other, net 5,220 5,228 4,459 3,523 3,115 2,898
Allowance for borrowed funds used during
construction (1,714) (2,184) (2,905) (2,719) (2,026) (1,777)
----------------------------------------------------------------------------------------------------------------------
Total Interest Charges 61,444 65,804 68,095 66,747 69,717 73,391
----------------------------------------------------------------------------------------------------------------------
Net Income 78,563 70,439 57,997 59,881 71,444 76,114
Dividends on Preferred Stock
at required rates 7,300 8,290 6,963 6,025 6,025 7,348
----------------------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 71,263 $ 62,149 $ 51,034 $ 53,856 $ 65,419 $ 68,766
----------------------------------------------------------------------------------------------------------------------
Weighted average number of shares
outstanding in each period (000's) 35,599 33,258 31,794 31,293 31,090 30,513
Earnings per Common Share $ 2.00 $ 1.86 $ 1.60 $ 1.72 $ 2.10 $ 2.25
----------------------------------------------------------------------------------------------------------------------
Cash Dividends Paid per Common Share $ 1.72 $ 1.68 $ 1.62 $ 1.56 $ 1.50 $ 1.50
----------------------------------------------------------------------------------------------------------------------
- 26 -
Condensed Consolidated Balance Sheet ----------------------------------------------------------------------
(Thousands of Dollars) At December 31 1993 1992 1991 1990 1989 1988
- --------------------------------------------------------------------------------------------------------------------
Assets
Utility Plant $2,890,799 $2,798,581 $2,706,554 $2,310,294 $2,208,158 $2,122,922
Less: Accumulated depreciation and
amortization 1,335,083 1,253,117 1,178,649 812,994 730,621 653,876
---------- ---------- ---------- ---------- ---------- ----------
1,555,716 1,545,464 1,527,905 1,497,300 1,477,537 1,469,046
Construction work in progress 112,750 83,834 76,848 82,663 68,784 41,044
---------- ---------- ---------- ---------- ---------- ----------
Net utility plant 1,668,466 1,629,298 1,604,753 1,579,963 1,546,321 1,510,090
Current Assets 248,589 209,621 189,009 176,045 190,321 213,626
Investment in Empire 38,560 9,846 - - - -
Deferred Debits 502,015 200,676 160,034 108,451 102,729 102,015
---------- ---------- ---------- ---------- ---------- ----------
Total Assets $2,457,630 $2,049,441 $1,953,796 $1,864,459 $1,839,371 $1,825,731
- ------------------------------------------- ========== ========== ========== ========== ========== ==========
CAPITALIZATION AND LIABILITIES
Capitalization
Long term debt $747,631 $658,880 $672,322 $721,612 $764,627 $792,976
Preferred stock redeemable at option
of Company 67,000 67,000 67,000 67,000 67,000 67,000
Preferred stock subject to mandatory
redemption 42,000 54,000 60,000 30,000 30,000 30,000
Common shareholders' equity
Common stock 652,172 591,532 529,339 516,388 513,560 504,907
Retained earnings 75,126 66,968 61,515 62,542 57,983 39,710
---------- ---------- ---------- ---------- ---------- ----------
Total common shareholders' equity 727,298 658,500 590,854 578,930 571,543 544,617
---------- ---------- ---------- ---------- ---------- ----------
Total Capitalization 1,583,929 1,438,380 1,390,176 1,397,542 1,433,170 1,434,593
---------- ---------- ---------- ---------- ---------- ----------
Long Term Liabilities (Department
of Energy) 89,804 94,602 63,626 59,989 55,502 51,016
Current Liabilities 234,530 267,276 267,601 183,720 137,899 126,661
Deferred Credits and Other Liabilities 549,367 249,183 232,393 223,208 212,800 213,461
---------- ---------- ---------- ---------- ---------- ----------
Total Capitalization and Liabilities $2,457,630 $2,049,441 $1,953,796 $1,864,459 $1,839,371 $1,825,731
- ------------------------------------------- ========== ========== ========== ========== ========== ==========
- 27 -
Financial Data
At December 31 1993 1992 1991 1990 1989 1988
---- ---- ---- ---- ---- ----
Capitalization Ratios(a)(percent)
Long term debt 49.4 48.2 50.6 53.6 55.1 56.8
Preferred stock 6.6 8.0 8.7 6.7 6.5 6.5
Common shareholders' equity 44.0 43.8 40.7 39.7 38.4 36.7
------ ------ ------ ------ ------ ------
Total 100.0 100.0 100.0 100.0 100.0 100.0
------ ------ ------ ------ ------ ------
Book Value per Common Share--Year End $19.70 $18.92 $18.41 $18.42 $18.28 $17.69
Rate of Return on Average Common Equity
(percent) 10.25 9.98 8.60 9.29 11.56(b) 12.68
Embedded Cost of Senior Capital (percent)
Long term debt 7.36 7.91 8.32 8.59 8.74 8.71
Preferred stock 6.69 6.98 6.97 6.72 6.72 6.72
Effective Federal Income Tax Rate (percent) 33.5 35.9 33.9 34.8 33.8 33.9
Depreciation Rate (percent) - Electric 2.62 2.69 3.05 3.33 3.25 3.56
- Gas 2.60 2.78 2.94 2.94 2.96 2.96
Interest Coverages(b)(c)
Before federal income taxes (incld. AFUDC) 3.03 2.74 2.38 2.32 2.53 2.53
(excld. AFUDC) 3.00 2.70 2.33 2.25 2.47 2.48
After federal income taxes (incld. AFUDC) 2.35 2.12 1.91 1.86 2.02 2.01
(excld. AFUDC) 2.32 2.08 1.86 1.78 1.96 1.96
(a) Includes Company's long term liability to the Department of Energy (DOE)
for nuclear waste disposal. Excludes DOE long term liability for uranium
enrichment decommissioning and amounts due or redeemable within one year.
(b) Excludes disallowed Nine Mile Two plant costs written off in 1989.
(c) The recognition by the Company in 1991 of a fuel procurement audit approved
by the New York State Public Service Commission (PSC) has been excluded
from 1991 coverages. Likewise, recognition by the Company in 1992 of
disallowed ice storm costs as approved by the PSC has been excluded from
1992 coverages. Coverages for 1993 exclude the effects of retirement
enhancement programs recognized by the Company during the year and certain
gas purchase undercharges written off in December 1993.
- 28 -
ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following is Management's assessment of significant factors which
affect the Company's financial condition and operating results.
Liquidity and Capital Resources
During 1993 cash flow from operations, together with proceeds from
external financing activity (see Consolidated Statement of Cash Flows), provided
the funds for construction expenditures and the retirement and refinancing of
long-term debt and preferred stock. Capital requirements during 1994, including
debt maturity and sinking fund obligations, are anticipated to be satisfied
primarily from the use of internally generated funds. Some external financing,
mainly in the form of short-term debt, is expected to be incurred. Any
refinancing activity would require additional external financing.
Projected Capital and Other Requirements
The Company's capital requirements relate primarily to expenditures
for electric generation, transmission and distribution facilities and gas mains
and services as well as the repayment of existing debt. Construction programs
of the Company focus on the need to serve new customers, to provide for the
replacement of obsolete or inefficient utility property and to modify facilities
consistent with the most current environmental and safety regulations.
The Company has no current plans to install additional baseload
generation. The Company either has contracts or is continuing negotiations for
the realization of approximately 24 megawatts of capacity savings being phased-
in over the 1993-1996 period under its demand side management program and,
beginning in late 1994 or early 1995, expects approximately 55 megawatts of
capacity to be supplied by a cogenerator under contract with the Company. The
Company has no other obligations with non-utility generating companies at this
time.
In June 1992 the Company filed with the New York State Public Service
Commission (PSC) an Integrated Resource Plan (IRP)
- 29 -
which is a long-range plan examining options for the future with regard to
generating resources and alternative methods of meeting electric capacity
requirements. The plan covers a 15-year period, beginning in 1992, and provides
current strategies and alternatives for meeting customer energy requirements in
a changing business and technological environment. The IRP takes into account
anticipated capacity requirements and available resource options, as well as
factors such as reliability, price of product, public acceptance, financial
integrity, environmental issues, the competitive marketplace, demand side
management and potential new technologies.
One result of the IRP was the decision made by the Company in December
1992 to replace the two steam generators at the Ginna nuclear plant in 1996.
Like similar plants, the Ginna nuclear plant has experienced degradation in some
of the tubes that make up each steam generator. About 30 percent of these tubes
have required repair. In addition, a chemical buildup in some of the tubes has
reduced their heat transfer capability. Both conditions would continue to erode
the plant's performance if the existing steam generators were left in place.
Installation of new steam generators was determined by the Company to be the
most cost-effective, reliable and environmentally compatible option for the
plant. The new steam generators should result in reduced maintenance costs and
help sustain a high level of plant availability. Cost of replacement is
estimated at $115 million, and preparation to replace these generators began
during the plant's routine 1993 fuel outage.
As a part of the on-going IRP process, the Company in mid-1993 made a
decision to place Unit 1 at Russell Station (47 MW) on cold standby, while
modifying Units 2, 3 and 4 with new burners to meet Federal Environmental
Protection Agency standards. Unit 1 is expected to be in cold standby by early
1994. Modification of Units 3 and 4 is expected to be completed by March 1995
at a cost of approximately $4.6 million. In addition, Unit 12 at Beebee Station
and Unit 2 at Russell Station will be adjusted to produce fewer nitrogen oxides
(NOx) by converting a third of the burners in each to achieve overfire air
capability at a cost of approximately $1.2 million. These actions will allow
the Company to comply with Phase I - Title I, NOx controls requirements of the
Federal Clean Air Act, to meet projected load demands in its service territory,
and to maintain a mix of fuel generation while remaining competitive and
retaining wholesale sales opportunities.
Outlined below are other results of the IRP process to date:
- The plan calls for evaluating the possibility of using either
alternative generation or current generating equipment in
partnership with certain large industrial customers.
- 30 -
- The Company will continue to use demand side management programs to
reduce the need for generating capacity.
- The Company will consider phasing out its coal-fired Beebee Station
by the year 2000, unless it is converted to natural gas and
operated under a partnership arrangement with a large customer.
The Company's capital expenditures program is under continuous review
and will be revised depending upon the progress of construction projects,
customer demand for energy, rate relief, government mandates and other factors.
In addition to its projected construction requirements, the Company may
consider, as conditions warrant, the redemption or refinancing of certain long-
term securities.
Capital Requirements and Electric Operations
Electric production plant expenditures in 1993 included $42 million of
expenditures made at the Company's Ginna nuclear plant, of which $15 million was
incurred for preparation to replace the steam generators. In addition, nuclear
fuel expenditures of $11 million were incurred at Ginna during 1993. A
refueling outage at Ginna normally occurs annually for a period of approximately
40 to 50 days.
Exclusive of fuel costs, the Company's 14 percent share of electric
production plant expenditures at the Nine Mile Two nuclear facility totaled $6
million in 1993. Expenditures of $5 million during 1993 were made for the
Company's share of nuclear fuel at Nine Mile Two. On October 2, 1993 Nine Mile
Two was taken out of service for a scheduled refueling outage. Refueling was
completed and Nine Mile Two resumed full operation on December 3, 1993. The
prior refueling outage occurred in 1992 from early March to early July. The
next refueling outage for Nine Mile Two is anticipated to begin in May 1995.
Electric transmission and distribution expenditures, as presented in
the Capital Requirements table, totaled $29 million in 1993, of which $24
million was for the upgrading of electric distribution facilities to meet the
energy requirements of new and existing customers.
Capital Requirements and Gas Operations
Construction began in June 1993 on the Empire State Pipeline (Empire),
an intrastate natural gas pipeline subject to PSC regulation between Grand
Island and Syracuse, New York. The Company received its first gas deliveries
through the pipeline in early November 1993. This pipeline will provide
capacity for up to 50 percent of the Company's gas requirements by its second
- 31 -
year of operation. The Company is participating as an equity owner of Empire,
along with subsidiaries of Coastal Corporation and Westcoast Energy Inc. In
June 1991 the PSC authorized the Company to invest up to $20 million in Empire
subject to certain conditions, notably that the investment not be included in
rate base. In 1992 the Company formed a wholly owned subsidiary, Energyline
Corporation, to acquire its ownership interest in Empire. The Company's share
of ownership in Empire will be dependent upon final project costs and the timing
and method of financing selected by the Company. In June 1993 Empire secured a
$150 million credit agreement, the proceeds of which are to finance
approximately 75 percent of the total construction cost. At December 31, 1993
the Company had invested a net amount of $10.2 million in Energyline ($9.9
million in 1992 and $0.3 million in 1993) and was committed for $9.7 million of
the borrowings under the credit agreement. In December 1993 the Company's
investment in Energyline was consolidated for accounting and reporting purposes
into the accounts of the Company. Such consolidation resulted in a $0.5 million
charge to Other Income during 1993.
In addition to the Empire project discussed above, construction
expenditures in the Gas Department totaled $20 million and were principally for
the replacement of older cast iron mains with longer-lasting and less expensive
plastic and coated steel pipe, the relocation of gas mains for highway
improvement, and the installation of gas services for new load.
Environmental Issues
The production and delivery of energy are necessarily accompanied by
the release of by-products subject to environmental controls. In recognition of
the Company's responsibility to preserve the quality of the air, water, and land
it shares with the community it serves, the Company has taken a variety of
measures (e.g., self-auditing, recycling and waste minimization, training of
employees in hazardous waste management) to reduce the potential for adverse
environmental effects from its energy operations and, specifically, to manage
and appropriately dispose of wastes currently being generated. The Company,
nevertheless, has been contacted, along with numerous others, concerning wastes
shipped off-site to licensed treatment, storage and disposal sites where
authorities have later questioned the handling of such wastes. In such
instances, the Company typically seeks to cooperate with those authorities and
with other site users to develop cleanup programs and to fairly allocate the
associated costs.
As a part of its commitment to environmental excellence, the Company
is conducting proactive Site Investigation and Remediation (SIR) efforts at
Company-owned sites where past waste handling and disposal may have occurred.
- 32 -
The Company currently estimates the total costs it could incur for SIR
activities at Company-owned sites to be about $20 million. This estimate will
vary as better site information is available. The Company anticipates spending
$10 million over the next 5 years on SIR initiatives. Approximately $4.5
million has been provided for in rates through June 1996 for recovery of SIR
costs. To the extent actual expenditures differ from this amount, they will be
deferred for future disposition and recovery as authorized by the PSC.
Additional environmental issues are discussed in Note 10 of the Notes to
Financial Statements.
The Company is developing strategies responsive to the Federal Clean
Air Act Amendments of 1990 (Amendments). The Amendments primarily affect air
emissions from the Company's fossil-fueled electric generating facilities (see
Note 10 of the Notes to Financial Statements). The Company is in the process of
identifying the optimum mix of control measures that will allow the fossil fuel
based portion of the generation system to fully comply with applicable
regulatory requirements. Although work is continuing, not all compliance
control measures have been determined. The Company has adopted control measures
for NOx emissions which must be in effect by the federally mandated compliance
date of May 31, 1995. These control measures are discussed under Projected
Capital and Other Requirements. Capital costs for NOx controls and the
installation of continuous emission monitoring systems are not expected to
exceed $6.8 million and will be incurred during 1994 and 1995. A range of
capital costs between $20 million and $30 million (1993 dollars) has been
estimated for the implementation of several potential scenarios which would
enable the Company to meet the foreseeable future NOx and sulphur dioxide
requirements of the Amendments. These capital costs would be incurred between
1996 and 2000. The Company currently estimates that it could also incur up to
$2 million (1993 dollars) of additional annual operating expenses, excluding
fuel, to comply with the Amendments. The use of scrubbing equipment is not
presently being considered. Likewise, the purchase or sale of "emission
allowances", as allowed by the Amendments, is not currently being considered.
The Company anticipates that the costs incurred to comply with the Amendments
will be recoverable through rates based on previous rate recovery of
environmental costs required by governmental authorities.
Competition
The Company is operating in an increasingly competitive environment.
In its electric business, this environment includes a federal trend toward
deregulation and a state trend toward incentive regulation. In addition, excess
capacity in the region, new technology and cost pressures on major customers
have created incentives for major customers to investigate different electric
supply options. Initially, those options will include various forms of self
generation, but may eventually include
- 33 -
customer access to the transmission system in order to purchase electricity from
suppliers other than the Company. As discussed under the Regulatory Matters
section, the passage of the National Energy Policy Act of 1992 has accelerated
these competitive challenges.
The Company accepts these challenges and is working to anticipate the
impact of the increased competition. Its Business Plan, both in detail for one
year and in summary for five years, focuses on improving service while reducing
expenses. The Company is engaged in a continuous process improvement program to
find opportunities for improved service and efficiency and has implemented an
early retirement program in which 173 people, representing approximately seven
percent of its workforce, have retired early and will not be replaced. In
addition, the Company has agreed to a three-year rate settlement which includes
caps on rate increases that approximate or are less than projected inflation,
contains incentive programs that tie performance to earnings and stabilizes
revenue through revenue adjustment mechanisms. An agreement has been reached
with the PSC Staff and others on the terms of a competitive rate tariff that
would allow negotiated rates with larger industrial and commercial customers
that have competitive electric supply options. These regulatory changes are
discussed in more detail in the Regulatory Matters section.
Competition in the Company's gas business has existed for some time,
as the larger customers have had the option of obtaining their own gas supply
and transporting it through the Company's distribution system. This process has
been accelerated with FERC Order 636, discussed in more detail in the Regulatory
Matters section. In addition to the matters discussed above, the Company has
responded to the changes in the gas business by positioning itself to obtain
greater access to both U.S. and Canadian natural gas supplies and storage, so
that it can take advantage of the unbundling of services that results from FERC
Order 636. A major element of this strategy went into place in 1993 with the
start-up of the Empire State Pipeline. The Company is engaged in various
aspects of capacity release and is investigating other options available to it
to mitigate its cost and increase its revenue in the new gas regulatory
environment.
Beyond the Company's efforts to remain competitive in its core
business, it is conducting a broad review of its general business strategy to
identify opportunities that will exist in this changed environment. This may
result in expansion of various elements of the core business or engaging in new,
but related, business activity.
- 34 -
Redemption of Securities
Discretionary first mortgage bond redemptions totaled $120 million
during 1993. A $75 million first mortgage bond maturity and $17 million of
sinking fund obligations were also a part of the Company's capital requirements
in 1993.
Capital requirements in 1992 included a $75 million first mortgage
bond maturity, and discretionary first mortgage bond redemptions of $79.5
million.
Capital Requirements - Summary
The Company's capital program is designed to maintain reliable and
safe electric and natural gas service, to improve the Company's competitive
position, and to meet future customer service requirements. Capital
requirements for the three-year period 1991 to 1993 and the current estimate of
capital requirements through 1996 are summarized in the Capital Requirements
table.
Capital Requirements
- --------------------------------------------------------------------------------
Actual Projected
-------------------- --------------------
1991 1992 1993 1994 1995 1996
Type of Facilities: (Millions of Dollars)
- --------------------------------------------------------------------------------
Electric Property:
Production $ 44 $ 47 $ 54 $ 55 $ 66 $ 76
Transmission and Distribution 29 35 29 26 36 40
Street Lighting and Other 2 2 2 1 2 2
----- ----- ----- ----- ----- -----
Subtotal 75 84 85 82 104 118
Nuclear Fuel 12 11 16 20 20 22
----- ----- ----- ----- ----- -----
Total Electric 87 95 101 102 124 140
Gas Property 22 19 20 19 28 25
Common Property 13 15 21 15 16 16
----- ----- ----- ----- ----- -----
Total 122 129 142 136 168 181
Carrying Costs:
Allowance for Funds Used
During
Construction (AFUDC) 4 2 2 2 3 3
Deferred Financing Charges
Included in Other Income 5 3 1 - - -
----- ----- ----- ----- ----- -----
Total Construction
Requirements 131 134 145 138 171 184
Securities Redemptions,
Maturities
and Sinking Fund Obligations* 92 160 212 39 3 21
----- ----- ----- ----- ----- -----
Total Capital
Requirements $ 223 $ 294 $ 357 $ 177 $ 174 $ 205
----- ----- ----- ----- ----- -----
*Excludes prospective refinancings.
- 35 -
For the period 1994 through 1996, the Company anticipates construction
requirements to total approximately $493 million. Replacement of the steam
generators at the Ginna nuclear plant is scheduled to be completed in 1996.
Electric production plant expenditures over the period include $16 million in
1994, $29 million in 1995, and $50 million in 1996 for that replacement. In
addition to its construction expenditures, the Company has security maturities
and sinking fund obligations totaling $63 million over the three-year period
1994 through 1996. Excluded from the Capital Requirements table are
expenditures associated with the Company's obligations to the United States
Department of Energy for nuclear waste disposal and the Department of Energy's
uranium enrichment facility decommissioning (see Notes 1 and 10 of the Notes to
Financial Statements).
Financing and Capital Structure
Capital requirements in 1993 were satisfied by a combination of long-
term debt and equity issues, internally generated funds, and short-term
borrowings. Common shareholders equity increased during 1993 as the result of a
public issue of one and one-half million shares of Common Stock in September.
Favorable market conditions allowed the Company to refinance $120 million of its
higher-cost long-term debt in 1993. In addition, the Company was able to
refinance at a lower interest rate $75 million of its First Mortgage, 8.60%
Bonds, Series LL, which matured on August 1. Such refinancing activity over the
past three years has helped to reduce the annual cost of long-term debt by
approximately $8.8 million and contributed to a drop in the Company's embedded
cost of long-term debt from 8.6% at year-end 1990 to 7.4% at the end of 1993.
The Company believes that an average of approximately 85 percent to 90
percent of the funds required per year for its 1994 through 1996 construction
program will be generated internally and the balance will be obtained through
the issue of securities and short-term borrowings. The Company is utilizing its
credit agreements to meet any interim external financing needs prior to issuing
any long-term securities. As financial market conditions warrant, the Company
may, from time to time, issue securities to permit the early redemption of
higher-cost senior securities. The Company's financing program is under
continuous review and may be revised depending upon the level of construction,
financial market conditions, rate relief, cost of capital and other factors.
- Financing
Interim financing is available from certain domestic banks in the form
of short-term borrowings under a $90 million revolving credit agreement which
continues until December 31,
- 36 -
1996 and may be extended annually. Borrowings under this agreement are secured
by a subordinate mortgage on substantially all of the Company's property except
cash and accounts receivable. In addition, the Company entered into a Loan and
Security Agreement with a domestic bank until December 31, 1994 providing for up
to $20 million of short-term debt. Borrowings under this agreement, which can
be renewed annually, are secured by the Company's accounts receivable. The
Company also has unsecured short-term credit facilities totaling $70 million.
At December 31, 1993 the Company had short-term borrowings outstanding of $68.1
million, consisting of $51.3 million of unsecured short-term debt and $16.8
million of secured short-term debt.
Under provisions of the Company's Certificate of Incorporation
(Charter), the Company may not issue unsecured debt if immediately after such
issuance the total amount of unsecured debt outstanding would exceed 15 percent
of the Company's total secured indebtedness, capital, and surplus without the
approval of at least a majority of the holders of outstanding Preferred Stock.
Under this restriction, the Company as of December 31, 1993 was able to issue
$19.2 million of additional unsecured debt. Additional interim financing
capability remains available with secured borrowings under the Company's credit
agreements, as discussed above.
During 1993 the Company sold several issues of First Mortgage Bonds,
Designated Secured Medium-Term Notes, Series A aggregating $200 million
principal amount. Proceeds from the sale of the medium-term notes were used to
redeem prior to maturity, at lower interest rates, $120 million principal amount
of first mortgage bonds, to pay at maturity $75 million principal amount of
first mortgage bonds and to repay short-term debt of $5 million.
In July 1993 the Company filed a shelf registration on Form S-3
providing for the offering of $250 million of new securities. The Company may
use the shelf registration to offer, from time to time, its first mortgage bonds
in one or more series, its Preferred Stock in one or more series and/or its
Common Stock depending on market conditions and Company requirements. This
Registration Statement became effective August 1993 and allows the Company
financing flexibility regarding the timing of new issues. The net proceeds from
the sale of the securities will be used to finance a portion of the Company's
capital requirements, to discharge or refund certain outstanding indebtedness or
preferred stock of the Company, to satisfy certain sinking fund obligations, or
for general corporate purposes.
In September 1993 the Company sold 1,500,000 shares of new Common
Stock in a public offering under the shelf
- 37 -
registration discussed above. The offering raised $43.1 million in net
proceeds, which were used to retire short-term debt incurred in the Company's
construction program.
During 1993 approximately 515,000 new shares of Common Stock were sold
through the Company's Automatic Dividend Reinvestment and Stock Purchase Plan
(ADR Plan), providing approximately $14.1 million to help finance its capital
expenditures program. New shares issued in 1992 and 1993 through the ADR Plan
were purchased from the Company at a market price above the book value per share
at the time of purchase.
- Capital Structure
The public sale of Common Stock in 1992 and 1993 strengthened the
Company's common equity. The Company's retained earnings at December 31, 1993
were $75.1 million, an increase of approximately $8.1 million compared with a
year earlier. Common equity (including retained earnings) comprised 44.0
percent of the Company's capitalization at December 31, 1993, with the balance
being comprised of 6.6 percent preferred equity and 49.4 percent long-term debt.
At December 31, 1993 the Company had $21.3 million of long-term debt due within
one year and $6.0 million of preferred stock redeemable within one year which,
if included in capitalization, would increase the long-term debt component of
capitalization at 1993 year-end to 49.8 percent, raise the preferred equity to
6.9 percent and reduce common equity to 43.3 percent of capitalization. As
presented, these percentages are based on the Company's capitalization inclusive
of its long-term liability to the United States Department of Energy (DOE) for
nuclear waste disposal as explained in Note 1 of the Notes to Financial
Statements. It is the Company's long-term objective to move to a less leveraged
capital structure and to increase the common equity percentage of capitalization
toward the 45 percent range. To improve its capital structure, the Company
anticipates the issuance of new shares of common stock, primarily through the
Company's ADR Plan, and will consider the redemption of higher-cost senior
securities.
Regulatory Matters
- New York State Public Service Commission (PSC)
The Company is subject to regulation of rates, service, and sale of
securities, among other matters, by the PSC. On August 24, 1993 the PSC issued
an order approving a settlement agreement (1993 Rate Agreement) among the
Company, PSC Staff and other interested parties. This agreement resolves the
Company's rate case proceedings initiated in July 1992. Retroactive application
of new rates to July 1, 1993 was authorized by the PSC. The 1993 Rate Agreement
will determine the Company's rates through June 30, 1996 and includes certain
incentive arrangements
- 38 -
providing for both rewards and penalties. A summary of recent PSC rate
decisions is presented in the table titled "Rate Increases". The 1993 Rate
Agreement amounts are based on an allowed return on common equity of 11.50%
through June 30, 1996. Earnings between 8.50% and 14.50% will be
absorbed/retained by the Company. Earnings above 14.50% will be refunded to the
customers. If, but not unless, earnings fall below 8.50%, or cash interest
coverage falls below 2.2 times, the Company can seek relief by petitioning the
PSC for a review of the 1993 Rate Agreement terms.
Rate Increases
- -------------------------------------------------------------------------------
Granted
Authorized
Amount of Increase Rate of Return on
Class of Effective (Annual Basis) Percent ---------------------
Service Date of Increase (000's) Increase Rate Base Equity
- -------------------------------------------------------------------------------
Electric July 12, 1990 $36,059 6.6% 9.91% 12.10%
July 1, 1991 33,133 5.5 9.66 11.70
July 1, 1992 32,220 5.2 9.31 11.00
July 1, 1993* 18,500 2.8 9.46 11.50
July 1, 1994* 20,900 2.9 9.39 11.50
July 1, 1995* 21,800 2.9 9.41 11.50
Gas July 12, 1990 4,250 1.7 9.91 12.10
July 1, 1991 1,148 0.4 9.66 11.70
July 1, 1992 12,316 4.1 9.31 11.00
July 1, 1993* 2,600 1.1 9.46 11.50
July 1, 1994* 4,400 1.8 9.39 11.50
July 1, 1995* 4,300 1.7 9.41 11.50
*See under heading Regulatory Matters for additional details
The following measures were incorporated into the 1993 Rate Agreement:
- Incentive mechanisms that have the potential to either increase or
reduce earnings from 5 to 70 basis points each, depending on the
Company's ability to meet a variety of prescribed targets in the
areas of electric fuel costs, demand side management, service
quality, and integrated resource management (relative electric
production efficiency). During the rate year ending June 30, 1994,
these incentives have the potential to affect earnings by
approximately $12 million.
- Mechanisms for sharing costs between customers and shareholders for
operation and maintenance expenses. In general, non-fuel operation
and maintenance
- 39 -
expense variations are treated in three different ways depending
upon the amount of control the Company can exert over them. Those
costs that are directly manageable (approximately $172 million in
the first rate year) have no sharing and are absorbed by the
Company, those costs that are not significantly affected by
management action in the short run (approximately $34 million in
the first rate year) are trued up 100% and variances resulting from
all other such costs (approximately $110 million in the first rate
year) are shared 50% by customers and 50% by the Company.
- Mechanisms for sharing 50% of overspending variances between
forecasted and actual electric capital expenditures related to
production and transmission facilities. The Company will retain
the savings for cost of money and depreciation on underspending
variances. The settlement also provides for a sharing mechanism
regarding the replacement of the Ginna nuclear station steam
generators. A graduated sharing percentage is applied for up to
$15 million of variances, plus or minus, from the forecasted cost
of $115 million. Variances above $130 million or below $100
million are absorbed by the Company.
- An Electric Revenue Adjustment Mechanism (ERAM) designed to
stabilize electric revenues by eliminating the impact of variations
in electric sales. A gas weather normalization clause previously
in place was retained.
To the extent incentive and sharing mechanisms apply, the negotiated
rate increases shown in the table titled "Rate Increases" may be adjusted up or
down in the second and third year of the agreement. Negotiated electric rate
increases could be reduced to zero or increased up to an additional 1.5% in year
two, 1.6% in year three and 1.8% in the subsequent year. Negotiated gas rate
increases could also be reduced to zero or increased up to an additional 0.8% in
year two, 0.9% in year three, and 1.1% in the subsequent year, exclusive of the
impact of the Empire State Pipeline going into service.
In July 1993 the Company requested approval from the PSC for a new
flexible pricing tariff for major industrial and commercial electric customers.
A settlement in this matter was filed with the PSC on November 19, 1993 and a
decision on whether or not to approve the settlement is expected early in 1994.
Such a tariff would allow the Company to negotiate competitive electric rates at
discount prices to compete with alternative power sources, such as customer-
owned generation facilities. Under the terms of the settlement, the Company
would absorb 30
- 40 -
percent of any net revenues lost as a result of such discounts through June
1996, while the remainder would be recovered from other customers. The portion
recoverable after June 1996 is expected to be determined in a generic proceeding
currently being conducted by the PSC.
In September 1993 the PSC instituted a formal proceeding to
investigate what the Company believes are under-charges to gas customers for
certain gas purchases for the period August 1990 to August 1992. The Company's
estimate of these undercharges is approximately $7.5 million, of which $2.3
million had been previously expensed and $5.2 million had been deferred on the
Company's balance sheet. The PSC has made the Company's current gas rates under
the 1993 Rate Agreement temporary solely to consider the impact of these
undercharges. On December 30, 1993, a proposed settlement among the Company,
PSC Staff and another party was filed with the PSC. It provides for the
recovery in rates of $3.2 million over three years, subject to audit and to
limitations on rate adjustments established in the August 24 Order. The Company
wrote off the $2.0 million balance of the undercharges as of December 31, 1993.
That write-off amounts to a reduction in 1993 earnings of approximately $.04 per
share, net of tax. Although no party, to the Company's knowledge, opposes the
proposed settlement, the Company is unable to predict whether the PSC will
approve it. A PSC decision on whether to approve this settlement is not
expected before March 1994.
In its June 1992 rate decision, the PSC allowed the Company to defer
and recover through rates over a period of ten years approximately $21.3 million
of non-capital incremental storm-damage repair costs which the Company had
incurred as a result of a March 1991 ice storm. The PSC has permitted the
unamortized balance of these allowed costs to be included in rate base. Rate
recovery of an additional $8.2 million of non-capital storm-damage costs
incurred by the Company was denied by the PSC and the Company accordingly
recorded in the second quarter of 1992 a charge to earnings in the amount of
$8.2 million, equivalent to approximately $.15 per share, net of tax, after
issuance of the two million shares of stock in August 1992.
Pursuant to a November 1991 Order approving a settlement agreement
between the PSC Staff and the Company relating to the Staff's audit of the
Company's fuel procurement practices, the Company refunded $10 million to its
electric customers through adjustments to their energy bills over a twelve-month
period beginning in January 1992. The Company recorded a $6.6 million net-of-
tax reduction to net income, thereby reducing earnings per share by
approximately $.21 for the fourth quarter of 1991.
- 41 -
- National Energy Policy Act of 1992
The National Energy Policy Act (Energy Act) was signed into law in
1992. Major provisions of the Energy Act, as they relate to the Company,
include energy efficiency, promoting competition in the electric power industry
at the wholesale level, streamlining of federal licensing of nuclear power
plants, encouraging development and production of coal resources, and ensuring
that a new class of independent power producers established under the bill, as
well as qualified facilities and other electric utilities, can achieve access to
utility-owned transmission facilities upon payment of appropriate prices. Under
the Energy Act, FERC may order utilities to provide wholesale transmission
services for others only if, among other things, the order meets certain
requirements as to cost recovery and fairness of rates. FERC is prohibited,
however, from ordering retail wheeling, i.e. transmitting power directly to a
customer from a supplier other than the customer's local utility. The law,
however, does not prevent state regulatory commissions from allowing or ordering
intrastate retail wheeling; and, New York State is currently considering the
issue of retail wheeling through various studies and hearings. The Company
believes this Act could lead to enhanced competition among the Company and other
service providers in the electric industry.
- FERC Order 636
In April 1992 FERC issued Order No. 636 with the intention of
fostering competition and improving access of customers to gas supply sources.
In essence, FERC Order No. 636 requires interstate natural gas companies to
offer customers "unbundled", or separate, sales and transportation services.
FERC Order 636 enables the Company and other gas utilities to contract directly
with gas producers for supplies of natural gas. With the unbundling of
services, primary responsibility for reliable natural gas supply has shifted
from interstate pipeline companies to local distribution companies, such as the
Company. Since 1988 the Company has endeavored to diversify both its natural
gas supply sources and the pipelines on which that supply is delivered to the
Company's distribution system. The unbundling of services as required under
FERC Order 636 and the commencement of Empire State Pipeline operation have
enabled the Company to achieve those goals, which should enhance its competitive
position. As a result of FERC Order 636, the Company does face certain
restructuring transition costs as explained under the heading Energy Costs and
Supply-Gas.
Results of Operations
The following financial review identifies the causes of
- 42 -
significant changes in the amounts of revenues and expenses, comparing 1993 to
1992 and 1992 to 1991. The Notes to Financial Statements contain additional
information.
Operating Revenues and Sales
Compared with a year earlier, operating revenues rose six percent in
1993 following a five percent increase in 1992. Gains in retail customer
electric and gas revenues offset a decline in electric revenues from the sale of
electric energy to other utilities. Customer revenue increases in 1993 resulted
primarily from rate relief and the impact of warmer weather on air conditioning
usage. Details of the revenue changes are presented in the Operating Revenues
table. As presented in this table, the base cost of fuel has been excluded from
customer consumption and is included under fuel costs, revenue taxes are
included as a part of other revenues, and unbilled revenues are included in each
caption as appropriate.
Operating Revenues
- --------------------------------------------------------------------------------
Increase or (Decrease) from
Prior Year
Electric Department Gas Department
---------------------------------------
(Thousands of Dollars) 1993 1992 1993 1992
- --------------------------------------------------------------------------------
Customer Revenues
(Estimated) from:
Rate Increases $21,827 $28,138 $ 8,087 $ 3,644
Fuel Costs 9,093 (9,633) 25,593 11,512
Weather Effects (Heating) 200 1,236 700 5,722
Customer Consumption 4,374 (2,826) 1,381 1,098
Other (4,806) 2,422 (3,777) 4,020
------- ------- ------- -------
Total Change in Customer
Revenues 30,688 19,337 31,984 25,996
Electric Sales to Other
Utilities (9,180) (3,071) - -
------- ------- ------- -------
Total Change in Operating
Revenues $21,508 $16,266 $31,984 $25,996
Unbilled revenues are the estimated revenues attributable to energy
which has been delivered to customers but for which the metered amount has not
been read and recorded on the Company's books. Such revenues do not enhance the
Company's cash position. The Company records monthly accruals for unbilled
revenues. The Company's Statement of Income reflects net unbilled revenues of
$18.7 million in 1993, $(0.8) million in 1992, and $2.6 million in 1991.
Primarily as a result of the seasonal nature of gas revenues, unbilled revenues
can fluctuate from month to month and will normally be near their maximum around
January and at their minimum near the end of June.
Under the ERAM provisions of the 1993 Rate Agreement, as discussed
under Regulatory Matters, the Company is comparing, on a monthly basis, actual
results to forecast electric gross
- 43 -
margins as defined (basically, revenues less incremental cost of fuel) and
utilized in establishing rates. Variations between these target margins and the
Company's actual margins may be deferred and either recovered from or returned
to customers. As discussed earlier, the 1993 Rate Agreement "caps", that is
limits, the amount of revenue increases that can be obtained each rate year. At
the end of each rate year (i.e. June 30) any balance for ERAM will be taken into
consideration along with other balances eligible for passback or surcharge to
customers (primarily incentive and expense sharing provisions) to determine the
final disposition of the balance. As of December 31, 1993 no provisions to
accrue or defer revenues associated with any of the ERAM incentive or sharing
provisions under the 1993 Rate Agreement had been made, except for fuel
adjustment clause revenues.
Changes in fuel and purchased power cost revenues are normally
earnings neutral. The Company, however, does have fuel clause provisions which
currently provide that customers and shareholders will share, generally on a
50%/50% basis subject to certain incentive limits, the benefits and detriments
realized from actual electric fuel costs, generation mix, sales of gas to dual-
fuel customers and sales of electricity to other utilities compared with PSC-
approved forecast, or base rate, amounts. As a result of these sharing
arrangements, discussed further in Note 1 of the Notes to Financial Statements,
pretax earnings were increased by $4.4 million in 1992 and in 1993, primarily
reflecting actual experience in both electric fuel costs and generation mix
compared with rate assumptions. Fuel clause revenues also include the recovery
of incremental margins that vary from those provided for in base rates for the
implementation of the Company's energy efficiency programs (discussed below in
this section). Beginning in October 1993, the Company also began the recovery
through its fuel adjustment clause of deferred costs associated with the DOE's
assessment for future uranium enrichment decontamination. For the 1992
comparison period, fuel clause revenues were reduced due to a refund to electric
customers resulting from a PSC fuel audit settlement as described in the last
paragraph under the heading New York State Public Service Commission.
The effect of weather variations on operating revenues is most
measurable in the Gas Department, where revenues from space heating customers
comprise about 85 to 90 percent of total gas operating revenues. Variation in
weather conditions can also have a meaningful impact on the volume of gas
delivered and the revenues derived from the transportation of customer-owned gas
since a substantial portion of these gas deliveries is ultimately used for space
heating. After experiencing unseasonably mild weather during the 1991 heating
season, weather in the Company's service area during 1992 and 1993 was colder
than normal. Gas sales were enhanced as a result of this cooler weather, while
- 44 -
unseasonably warm summer weather during 1993 boosted electric energy sales to
meet the demand for air conditioning usage, compared with the cool, wet 1992
summer weather conditions. The decoupling, or separation, of sales level
fluctuations from revenue through the ERAM provisions, discussed under
Regulatory Matters, and a gas normalization weather clause (see following
paragraph) may mitigate the effect of abnormal weather conditions on earnings.
As part of the June 1992 rate decision, retail customers who use gas
for spaceheating became subject to a weather normalization adjustment to
reflect the impact of variations from normal weather on a billing cycle month
basis for the months of October through May, inclusive. The weather
normalization adjustment for a billing cycle will apply only if the actual
heating degree days are lower than 97.5 percent or higher than 102.5 percent
of the normal heating degree days. Weather normalization adjustments lowered
gas revenues in 1993 by approximately $1.2 million and in 1992 by
approximately $1.8 million. The potential for such adjustments continues
through June 1996 under the terms of the 1993 Rate Agreement.
Compared with the prior year, kilowatt-hour sales of energy to retail
customers in 1993 climbed about one percent after being nearly flat in 1992.
Electric demand for air conditioning usage had a significant impact on such
sales in 1993 and 1992. During 1993, an increase in sales to both residential
and commercial customers more than offset a decline in sales to industrial
customers. Kilowatt-hour sales of energy in 1993 reflect the impact of
approximately 2,200 new electric customers, which follows the addition of nearly
2,400 customers a year earlier.
Like many other electric utilities, the Company is encouraging energy
efficiency through demand side management (DSM) programs. Objectives of the DSM
programs include increasing the efficiency with which electricity is used and
shifting electric load from peak to non-peak times, thus helping to save energy
and delay the need to add new generating capacity. DSM programs include rebates
for energy-efficient equipment, audits which focus on potential techniques for
saving energy, consumer information and outreach, and design assistance to
encourage energy-efficient new construction. In general, the Company is being
allowed to amortize major DSM program expenditures over a five-year period. An
incentive allowance (award) of approximately $0.6 million was provided for in
the Company's rates based on the Company's DSM performance during 1992. Lost
margins resulting from DSM activities are estimated and recovered in base rates.
Variances between actual results and such estimates are recovered through fuel
clause revenue adjustments, subject to certain incentive limitations.
- 45 -
Fluctuations in revenues from electric sales to other utilities are
generally related to the Company's customer energy requirements, New York Power
Pool energy market and transmission conditions and the availability of electric
generation from Company facilities. Such revenues in 1992 and 1993 reflect the
sale of energy at a lower average rate per megawatt hour, a result, in part, of
competition and greater availability of energy. With more open access to
transmission services as provided for under the Energy Act, the Company is
examining alternative markets and procedures to meet what it believes will be
increased competition for the sale of electric energy to other utilities.
The transportation of gas for large-volume customers who are able to
purchase natural gas from sources other than the Company remains an important
component of the Company's marketing mix. Company facilities are used to
transport this gas, which amounted to 12.4 million dekatherms in 1993 and 12.6
million dekatherms in 1992. These purchases have caused decreases in customer
revenues, with offsetting decreases in purchased gas expenses, but do not
adversely affect earnings because transportation customers are billed at rates
which, except for the cost of gas, approximate the rates charged the Company's
other gas service customers. Gas supplies transported in this manner are not
included in Company therm sales, depressing reported gas sales to non-
residential customers.
Therms of gas sold and transported, including unbilled sales, were
nearly flat in 1993, following an 11.8 percent increase in 1992. These changes
reflect, primarily, the effect of weather variations on therm sales to customers
with space heating. If adjusted for normal weather conditions, residential gas
sales would have decreased about 0.3 percent in 1993 over 1992, while
nonresidential sales, including gas transported, would have decreased
approximately 2.1 percent in 1993. The average use per residential gas
customer, when adjusted for normal weather conditions was slightly down in 1993,
following a modest increase in 1992. Total therms of gas transported increased
in 1992 primarily as a result of higher sales to certain large industrial and
municipal transportation customers. Sales to these customers in 1993 were down
compared with 1992 sales.
Fluctuations in "Other" customer revenues shown in the Operating
Revenues table for both comparison periods are largely the result of revenue
taxes, deferred fuel costs, and miscellaneous revenues.
Operating Expenses
Compared with the prior year, operating expenses were up $40.2 million
in 1993 after increasing $33.1 million in 1992. Approximately two-thirds of the
increase in 1993 operating
- 46 -
expenses resulted from higher gas purchased for resale costs. The increase in
operating expenses for the 1993 comparison period was mitigated by the Company's
continuing efforts to curtail increases in other operation expenses. Operating
expenses are summarized in the table titled "Operating Expenses".
Operating Expenses
- --------------------------------------------------------------------------------
Increase or (Decrease) from Prior Year
(Thousands of Dollars) 1993 1992
- --------------------------------------------------------------------------------
Fuel for Electric Generation $ (2,505) $ (16,729)
Purchased Electricity 1,857 2,023
Gas Purchased for Resale 25,593 11,512
Other Operation 8,757 18,184
Maintenance (1,027) (2,695)
Depreciation (176) 478
Amortization of Other Plant (675) 369
Taxes Charged to Operating Expenses
Local, State and Other Taxes 2,640 10,603
Federal Income Tax 5,739 9,332
-------- ---------
Total Change in Operating Expenses $ 40,203 $ 33,077
======== =========
- Energy Costs - Electric
An electric generation mix favoring less expensive nuclear fuel,
compared with the cost of coal or oil, resulted in fuel expenses not increasing
at the same rate as electric generation for the 1993 comparison period. For the
1992 comparison period, fuel expense for electric generation was lower by $16.7
million due, in part, to a refund to electric customers as described in the last
paragraph under the heading New York State Public Service Commission. For both
comparison periods, the average cost of coal declined.
Average rates for purchased electricity declined in 1993, after
increasing in 1992. Such average rates partially offset an increase in
kilowatt-hours purchased in 1993. For the 1992 comparison period, the increase
in purchased electricity expense was caused by higher average rates during the
year.
- Energy Costs and Supply - Gas
As a result of the implementation of FERC Order 636, and the
commencement of operation of the Empire State Pipeline, the Company now
purchases all of its required gas supply directly
- 47 -
from numerous producers and marketers under contracts containing varying terms
and conditions. The Company holds firm transportation capacity on nine major
pipelines, giving the Company access to the major gas-producing regions of North
America. In addition to firm pipeline capacity, the Company also has obtained
contracts for firm storage capacity on the CNG Transmission Corporation (CNG)
system (10.4 billion cubic feet) and on the ANR Pipeline system (6.4 billion
cubic feet) which are used to help satisfy its customers' winter demand
requirements. With the commencement of operation of the Empire State Pipeline,
the Company placed into operation its new Mendon gate station which is capable
of supplying up to one-half of the Company's gas supply needs while also
maintaining the various gate station interconnections with the CNG system that,
prior to Empire, had supplied all of the Company's needs.
The transportation service to be provided by Empire was scheduled to
phase in over 12 months, at which point the combined CNG and Empire
transportation capacity would have exceeded the Company's current requirements.
Therefore, the Company recently entered into a marketing agreement with CNG,
pursuant to which CNG will assist the Company in obtaining permanent replacement
customers for the transportation capacity the Company will not require. It may
renegotiate its arrangements with CNG and/or Empire or it may negotiate
assignment, on a permanent or temporary basis, of the transportation capacity
that exceeds the requirements of its customers. In addition, under FERC rules,
the Company may sell its excess transportation capacity in the market. While
CNG has already secured letters of intent for a substantial portion of such
capacity, whether and to what extent CNG and/or the Company can successfully
negotiate the assignment or sale of the excess capacity, or at what price,
cannot be determined at the present time. The retention of some or all of this
excess transportation capacity may cause an increase in the Company's gas supply
costs. This would be in addition to any increase caused by other aspects of the
gas transportation restructuring.
As a result of the restructuring of the gas transportation industry by
the FERC, there will be a number of changes in this aspect of the Company's
business over the next several years. These changes, which will apply
throughout the industry, will affect different companies differently and may
result, at least initially, in increases in the gas transportation costs of the
Company. The Company will also be required to pay a share of certain transition
costs incurred by the pipelines as a result of the FERC restructuring. These
include costs related to restructuring existing gas supply contracts,
unrecovered gas costs that would otherwise have been billable to pipeline
customers under previous regulation and other related costs deemed reasonable
by the FERC. Although the final amounts of such transition costs are subject to
continuing
- 48 -
negotiations with several pipelines and ongoing pipeline filings requiring FERC
approval, the Company expects such costs to range between $43.5 and $52.0
million. A substantial portion of such costs will be on the CNG system of which
approximately $27 million was billed to the Company on December 3, 1993 payable
over the following three years. The Company recorded a regulatory asset on its
Balance Sheet and concurrently recognized a liability totaling approximately
$43.5 million for estimated restructuring transition costs under FERC Order 636.
The Company expects these transition costs to be recoverable in its rates.
The volume of gas purchased increased in both comparison periods
primarily due to higher combined residential and commercial space heating sales,
reflecting colder weather. The effect of higher-volume purchases was partially
offset by lower average rates in 1992. In contrast to 1992, however, it was
primarily an increase in these rates that pushed up the cost of gas purchased
for resale in 1993. These higher rates reflect, in part, increased demand
charges and, to a lesser extent, newly assessable gas service restructuring
charges as a result of FERC Order 636.
- Operating Expenses, Excluding Fuel
Other operation expenses rose over both comparison periods as shown by
the table titled "Operating Expenses". The recording of certain postretirement
benefits other than pensions, as required by Statement of Financial Accounting
Standards No. 106 (SFAS-106) and discussed in the following paragraph, increased
other operation expenses in 1992 by $4.9 million. Compared with a year earlier,
other operation expenses in 1992 also reflect an increase of $3.0 million for
transmission wheeling charges, $1.9 million due to increased amortization of
costs associated with the Company's demand side management programs, and
additional expenses of about $1.6 million associated with the Company's share of
Nine Mile Two operation expenses. As stated earlier, the growth in other
operation expenses was significantly less over the 1993 comparison period, a
direct result, in part, of enhanced cost control efforts by the Company's
employees. Compared with 1992, operating expenses associated with fire and
liability insurance, transportation, materials and supplies, legal expenses, and
the Company's share of Nine Mile Two operation expenses declined in 1993. The
change in other operation expenses for the 1993 comparison period reflects
primarily increased payroll costs and demand side management expenses.
During the first quarter of 1992, the Company adopted the Financial
Accounting Standards Board's (FASB) SFAS-106 for financial accounting purposes.
Among other things, SFAS-106 requires accrual accounting for postretirement
benefits other than pensions. Based on accrual accounting required by SFAS-106,
- 49 -
the Company's net periodic cost for postretirement benefits other than pension
was $7.5 million in 1993 and $7.8 million in 1992. The PSC has allowed the
Company revenues in rates based on SFAS-106. In September 1993, the PSC issued
a "Statement of Policy Concerning the Accounting and Ratemaking Treatment for
Pensions and Postretirement Benefits Other Than Pensions." The Statement's
provisions require, among other things, ten-year amortization of actuarial gains
and losses and deferral of differences between actual costs and rate allowances.
The Company adopted the Statement in 1993 for regulatory accounting purposes.
In November 1992, the FASB issued SFAS-112 entitled "Employees'
Accounting for Postemployment Benefits" which is effective for fiscal years
beginning after December 15, 1993. This Statement requires the Company to
recognize the obligation to provide postemployment benefits to former or
inactive employees after employment but before retirement. Employers must
accrue an obligation if the benefits are attributable to service already
rendered, the benefits accumulate or vest, payment is probable, and the amounts
can be reasonably estimated. The Company must adopt SFAS-112 not later than the
first quarter of 1994. The Company is currently evaluating the impact of SFAS-
112; however, based on studies the Company has performed to date, the adoption
of SFAS-112 is not expected to have a material effect on the Company's financial
condition or results of operations.
Reduced maintenance expense in both comparison periods was largely due
to lower maintenance expenses incurred at nuclear production facilities and the
effect of increased activity in 1991 associated with electric distribution
facilities.
Despite an increase in depreciable plant in both comparison periods,
depreciation and amortization of other plant fluctuated only moderately due
mainly to a decrease in the depreciation and accrued decommissioning expenses
related to the Ginna nuclear plant because of a three-year extension of its
operating license and the completion in July 1992 of amortization of the
Sterling property previously abandoned.
- Taxes Charged to Operating Expenses
The increase in local, state and other taxes in both comparison
periods resulted primarily from an increase in revenues combined with an
increase in the revenue tax rate, and increased property tax rates and higher
property assessments. The 1993 increase in local, state and other taxes was
mitigated by the effect of the relative magnitude of these factors compared with
1992. The increase in these taxes for the 1992 comparison period reflects an
adjustment for a one-half percent increase in the New York State gross revenue
tax rate accounted for beginning
- 50 -
in October 1991 retroactive to January 1, 1991.
During the first quarter of 1993, the Company adopted SFAS-109
entitled "Accounting for Income Taxes" issued by the FASB in February 1992.
Among other things, SFAS-109 requires that a deferred tax liability be
recognized on the balance sheet for tax differences previously flowed through to
customers. The Company's adoption of SFAS-109 in the first quarter of 1993 did
not have a material effect on the Company's results of operations although since
then, reflection of a deferred tax liability, together with a corresponding
regulatory asset, caused total assets and liabilities to increase significantly.
See Note 2 of the Notes to Financial Statements for further discussion of SFAS-
109 and an analysis of Federal income taxes.
In August 1993, the Revenue Reconciliation Act of 1993 (1993 Tax Act)
was signed into law. Among other provisions, the 1993 Tax Act provides for a
Federal corporate income tax rate of 35% (previously 34%) retroactive to January
1, 1993. The Company has adjusted its tax reserve balances to reflect this new
rate. There was no earnings impact since the effects of the tax change have
been deferred. The Company petitioned the PSC in late 1993 for recognition and
recovery of this incremental tax liability which was not reflected in the
provisions of its 1993 Rate Agreement. The Company's ability to recover this
cost is dependent upon the PSC issuing a generic ruling on the treatment of the
1993 Tax Act.
Other Statement of Income Items
AFUDC variances are generally related to the amount of utility plant
under construction and not included in rate base. AFUDC levels also reflect
decreases in the gross rate to 3.90 percent effective September 1, 1993 from
earlier rates of 4.50 percent, 5.50 percent, and 7.10 percent.
Variations in non-operating Federal income tax reflect mainly
accounting adjustments related to retirement enhancement programs (see following
paragraph), regulatory disallowances, and an employee performance incentive
program (discussed below in this section).
Recorded under the caption Other Income and Deductions is the
recognition of retirement enhancement programs designed to reduce overall labor
costs which were implemented by the Company during the third and fourth quarters
of 1993. A total of 173 employees elected to participate under these programs.
The Company does not plan to replace any of those employees. Total estimated
pretax costs of $8.2 million associated with these programs were recognized by
the Company in its 1993 Statement of Income, thereby reducing after-tax earnings
by approximately $.15
- 51 -
per share for the year. The Company estimates that the net pre-tax savings
through 1997 resulting from these programs will amount to about $8.9 million.
Recorded under the caption Regulatory Disallowances is the recognition
of the 1991 PSC order associated with the Company's fuel procurement practices,
the 1992 PSC order related to the March 1991 ice storm, and the 1993 settlement
with the PSC regarding certain alleged gas purchase undercharges, each discussed
under the heading New York State Public Service Commission.
Other Income in 1992 includes $3.5 million of proceeds received in
settlement of lawsuits filed against certain contractors involved in the
construction of the Nine Mile Two nuclear plant. Non-cash earnings associated
with the amortization of customer prepaid Nine Mile Two financing costs of $4.8
million in 1991, $2.5 million in 1992, and $1.2 million in 1993 are also
included in Other Income. The decline in Other-Net Income and Deductions for
the 1993 comparison period results mainly from the recognition of an employee
performance incentive program for 1993. This program recognizes employees'
achievements in meeting corporate goals and reducing expenses. Compared with a
year earlier, Other-Net Income and Deductions also reflects lower miscellaneous
interest revenues in 1993 and the recognition of Energyline earnings (losses)
upon consolidation with the accounts of the Company as discussed under Capital
Requirements and Gas Operations.
Both mandatory and optional redemptions of certain higher-cost first
mortgage bonds have helped to reduce long-term debt interest expense over the
three-year period 1991-1993, despite the issuance of additional long-term debt
in 1991 and 1992. In 1992, the effect of lower interest rates on debt expense
was partially offset by increased short-term borrowings. The level of short-
term debt borrowings decreased in 1993.
EARNINGS/SUMMARY
Presented below is a table which summarizes the Company's Common Stock
earnings on a per-share basis. Certain non-recurring items and their effect on
earnings per share have been identified in this table. Compared with a year
earlier, earnings per share were up in 1993 and 1992 despite the effect of a
public issuance of Common Stock in each year. Future earnings will be affected,
in part, by the Company's success in achieving demand side management and other
incentive goals, as well as controlling operating and capital costs, within
levels provided for in rates under the terms of the 1993 Rate Agreement.
In December 1992 the Company announced a quarterly
- 52 -
dividend increase from $.42 to $.43 per share of Common Stock payable in January
1993. Subsequently, in December 1993 the Company announced a new quarterly
dividend rate of $.44 per share payable in January 1994. The Company's Charter
provides for the payment of dividends on Common Stock out of the surplus net
profits (retained earnings) of the Company. Accordingly, dividend payments are
dependent on future earnings, in addition to financial requirements and other
factors.
Earnings Per Share - Summary
- -------------------------------------------------------------------------
(Dollars per Share) 1993 1992 1991
- -------------------------------------------------------------------------
Earnings per Share Before Non-recurring Items $2.19 $1.91 $1.81
Non-recurring Items
Gas Under-recovery Writeoff (.04)
Retirement Enhancement Programs (.15)
Nine Mile Two Litigation Proceeds .10
Ice Storm Disallowance (.15)
Fuel Procurement Audit (.21)
----- ----- -----
Total Non-recurring Items $(.19) $(.05) $(.21)
----- ----- -----
Reported Earnings per Share $2.00 $1.86 $1.60
===== ===== =====
- 53 -
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
A. Financial Statements
Report of Independent Accountants
Consolidated Statements of Income and Retained Earnings for each of
the three years ended December 31, 1993.
Consolidated Balance sheets at December 31, 1993 and 1992.
Consolidated Statement of Cash Flows for each of the three years
ended December 31, 1993.
Notes to Consolidated Financial Statements.
Financial Statement Schedules -
The following Financial Statement Schedules are submitted as part
of Item 14, Exhibits, Financial Statement Schedules and Reports on
Form 8-K, of this Report. (All other Financial Statement Schedules
are omitted because they are not applicable, or the required
information appears in the Financial Statements or the Notes
thereto.)
Schedule V - Property, Plant and Equipment (Utility Plant)
Schedule VI - Accumulated Depreciation and Amortization (Utility
Plant)
Schedule VIII - Valuation and Qualifying Accounts
Schedule IX - Short-term Borrowings
Schedule X - Supplementary Income Statement Information
B. Supplementary Data
Interim Financial Data.
- 54 -
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders and
Board of Directors of
Rochester Gas and Electric Corporation
In our opinion, the consolidated financial statements listed under Item 8A in
the index appearing on the preceding page present fairly, in all material
respects, the financial position of Rochester Gas and Electric Corporation and
its subsidiaries at December 31, 1993 and 1992, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1993, 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 1 to the financial statements, the Company adopted the
provisions of Statement of Financial Accounting Standards No. 109, "Accounting
for Income Taxes" in 1993.
PRICE WATERHOUSE
Rochester, New York
January 14, 1994
- 55 -
Consolidated Statement of Income
--------------------------------------------
(Thousands of Dollars) Year Ended December 31 1993 1992 1991
- ----------------------------------------------------------------------------------------------------
Operating Revenues
Electric $638,955 $608,267 $588,930
Gas 293,708 261,724 235,728
-------- -------- --------
932,663 869,991 824,658
Electric sales to other utilities 16,361 25,541 28,612
-------- -------- --------
Total Operating Revenues 949,024 895,532 853,270
Operating Expenses -------- -------- --------
Fuel Expenses
Fuel for electric generation 45,871 48,376 65,105
Purchased electricity 31,563 29,706 27,683
Gas purchased for resale 166,884 141,291 129,779
-------- -------- --------
Total Fuel Expenses 244,318 219,373 222,567
-------- -------- --------
Operating Revenues Less Fuel Expenses 704,706 676,159 630,703
Other Operating Expenses -------- -------- --------
Operations excluding fuel expenses 235,381 226,624 208,440
Maintenance 61,693 62,720 65,415
Depreciation and amortization 84,177 85,028 84,181
Taxes - local, state and other 126,892 124,252 113,649
Federal income tax 49,330 43,591 34,259
-------- -------- --------
Total Other Operating Expenses 557,473 542,215 505,944
-------- -------- --------
Operating Income 147,233 133,944 124,759
Other Income and Deductions -------- -------- --------
Allowance for other funds used during construction 153 164 675
Federal income tax 9,827 4,195 4,580
Pension Plan Curtailment (8,179) - -
Regulatory disallowances (1,953) (8,215) (10,000)
Other, net (7,074) 6,155 6,078
-------- -------- --------
Total Other Income and (Deductions) (7,226) 2,299 1,333
-------- -------- --------
Income Before Interest Charges 140,007 136,243 126,092
Interest Charges -------- -------- --------
Long term debt 56,451 60,810 63,918
Other, net 6,707 7,178 7,082
Allowance for borrowed funds used during construction (1,714) (2,184) (2,905)
-------- -------- --------
Total Interest Charges 61,444 65,804 68,095
-------- -------- --------
Net Income 78,563 70,439 57,997
Dividends on Preferred Stock 7,300 8,290 6,963
-------- -------- --------
Earnings Applicable to Common Stock $ 71,263 $ 62,149 $ 51,034
-------- -------- --------
Weighted Average Number of Shares for Period (000's) 35,599 33,258 31,794
-------- -------- --------
Earnings per Common Share $ 2.00 $ 1.86 $ 1.60
- ------------------------------------------------------- -------- -------- --------
Consolidated Statement of Retained Earnings
--------------------------------------------
(Thousands of Dollars) Year Ended December 31 1993 1992 1991
- ----------------------------------------------------------------------------------------------------
Balance at Beginning of Period $ 66,968 $ 61,515 $ 62,542
Add
Net Income 78,563 70,439 57,997
Adjustment Associated With Stock Redemption (933) - -
-------- -------- --------
Total 144,598 131,954 120,539
-------- -------- --------
Deduct
Dividends declared on capital stock
Cumulative preferred stock 7,300 8,290 6,963
Common Stock 62,172 56,696 52,061
-------- -------- --------
Total 69,472 64,986 59,024
-------- -------- --------
Balance at End of Period $ 75,126 $ 66,968 $ 61,515
- ------------------------------------------------------- -------- -------- --------
The accompanying notes are an integral part of the financial statements.
- 56 -
Consolidated Balance Sheet
----------------------
(Thousands of Dollars) At December 31 1993 1992
- --------------------------------------------------------------------------------
Assets
Utility Plant
Electric $2,234,530 $2,175,255
Gas 356,484 341,466
Common 125,428 123,034
Nuclear fuel 174,357 158,826
---------- ----------
2,890,799 2,798,581
Less: Accumulated depreciation 1,190,801 1,125,502
Nuclear fuel amortization 144,282 127,615
---------- ----------
1,555,716 1,545,464
Construction work in progress 112,750 83,834
---------- ----------
Net Utility Plant 1,668,466 1,629,298
---------- ----------
Current Assets
Cash and cash equivalents 2,327 1,759
Accounts receivable, net of allowance for
doubtful accounts:
1993 - $ 600; 1992 - $ 500 104,753 92,292
Unbilled revenue receivable 61,330 60,184
Materials and supplies, at average cost
Fossil fuel 5,983 12,273
Construction and other supplies 13,644 13,130
Gas stored underground 38,989 9,998
Prepayments 21,563 19,985
---------- ----------
Total Current Assets 248,589 209,621
---------- ----------
Investment in Empire 38,560 9,846
Deferred Debits
Regulatory Asset - Income Taxes 241,741 -
Deferred finance charges - Nine Mile Two 19,242 20,492
Deferred ice storm charges 21,621 24,197
Uranium enrichment decommissioning deferral 23,421 28,613
Nuclear generating plant decommissioning fund 38,930 29,549
Nine Mile Two deferred costs 34,513 34,300
FERC 636 Transition Costs 41,265 -
Unamortized debt expense 19,326 13,553
Other 61,956 49,972
---------- ----------
Total Deferred Debits 502,015 200,676
---------- ----------
Total Assets $2,457,630 $2,049,441
- ------------------------------------------------ ========== ==========
Capitalization and
Liabilities
Capitalization
Long term debt - mortgage bonds $ 655,731 $ 566,980
- promissory notes 91,900 91,900
Preferred stock redeemable at option of Company 67,000 67,000
Preferred stock subject to mandatory redemption 42,000 54,000
Common shareholders' equity
Common stock 652,172 591,532
Retained earnings 75,126 66,968
---------- ----------
Total Common Shareholders' Equity 727,298 658,500
---------- ----------
Total Capitalization 1,583,929 1,438,380
---------- ----------
Long Term Liabilities
(Department of Energy):
Nuclear waste disposal 68,055 65,989
Uranium enrichment decommissioning 21,749 28,613
Total Long Term Liabilities 89,804 94,602
Current Liabilities
Long term debt due within one year 21,250 110,250
Preferred stock redeemable within one year 6,000 6,000
Note Payable - Empire 29,600 -
Short term debt 68,100 50,800
Accounts payable 52,596 40,578
Dividends payable 18,066 17,035
Taxes accrued 6,472 13,743
Interest accrued 12,955 15,461
Other 19,491 13,409
---------- ----------
Total Current Liabilities 234,530 267,276
---------- ----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 425,648 171,673
Deferred finance charges - Nine Mile Two 19,242 20,492
Pension costs accrued 31,919 20,278
Other 72,558 36,740
---------- ----------
Total Deferred Credits and Other
Liabilities 549,367 249,183
---------- ----------
Commitments and Other Matters (Note 10) - -
---------- ----------
Total Capitalization and Liabilities $2,457,630 $2,049,441
- ------------------------------------------------ ========== ==========
The accompanying notes are an integral part of the financial statements.
-57-
Consolidated Statement of Cash Flows --------------------------------------
(Thousands of Dollars) Year Ended December 31 1993 1992 1991
-------------------------------------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATIONS
Net income $ 78,563 $ 70,439 $ 57,997
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation and amortization 84,177 85,028 84,181
Amortization of nuclear fuel 18,861 18,803 23,606
Deferred fuel - electric (2,072) 2,543 4,122
Deferred fuel - gas (11,500) 4,896 2,166
Deferred income taxes 15,232 10,466 9,124
Allowance for funds used during construction (1,867) (2,348) (3,580)
Unbilled revenue, net (5,107) (6,631) (8,931)
Ice storm costs 2,576 12,234 (36,431)
Nuclear generating plant decommissioning (9,381) (10,328) (15,581)
Changes in certain current assets and liabilities:
Accounts receivable (12,461) (8,239) (4,773)
Materials and supplies - fossil fuel 6,290 (1,507) 7,506
- construction and other supplies (514) (591) (315)
Gas stored underground (28,991) (2,942) (7,057)
Taxes accrued (7,271) 1,693 1,444
Accounts payable 12,018 (13,404) 6,914
Interest accrued (2,506) (852) 1,722
Other current assets and liabilities, net 6,113 (2,528) (592)
Other, net 10,966 (5,832) (2,075)
----------- ----------- -----------
Total Operating $ 153,126 $ 150,900 $ 119,447
-------------------------------------------------------- =========== =========== ===========
CASH FLOW FROM INVESTING ACTIVITIES
Utility Plant
Plant additions $ (125,744) $ (115,792) $ (114,579)
Nuclear fuel additions (15,530) (11,763) (13,058)
Less: Allowance for funds used during construction 1,867 2,348 3,580
----------- ----------- -----------
Additions to Utility Plant (139,407) (125,207) (124,057)
Investment in Empire - net 884 (9,846) -
Other, net (1,907) 490 (685)
----------- ----------- -----------
Total Investing $ (140,430) $ (134,563) $ (124,742)
-------------------------------------------------------- =========== =========== ===========
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/Issue of common stock $ 61,254 $ 63,928 $ 13,446
Sale of preferred stock - - 30,000
Sale of long term debt, mortgage bonds 200,000 160,500 100,000
Short term borrowings 17,300 (8,700) 17,100
Retirement of long term debt (200,249) (160,000) (92,334)
Retirement of preferred stock (12,000) - -
Capital stock expense (615) (1,735) (495)
Discount and expense of issuing long term debt (7,909) (6,368) (3,310)
Dividends paid on preferred stock (7,548) (8,290) (6,396)
Dividends paid on common stock (60,893) (55,216) (51,308)
Other, net (1,468) (185) (464)
----------- ----------- -----------
Total Financing $ (12,128) $ (16,066) $ 6,239
Increase (decrease) in cash and cash equivalents $ 568 $ 271 $ 944
Cash and cash equivalents at beginning of year $ 1,759 $ 1,488 $ 544
----------- ----------- -----------
Cash and cash equivalents at end of year $ 2,327 $ 1,759 $ 1,488
-------------------------------------------------------- =========== =========== ===========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
---------------------------------------
(Thousands of Dollars) Year Ended December 31 1993 1992 1991
------------------------------------------------------------------------------------------------------------------------
Cash Paid During the Year
Interest paid (net of capitalized amount) $ 60,852 $ 64,431 $ 63,848
Income taxes paid $ 32,779 $ 22,911 $ 20,399
-------------------------------------------------------- =========== =========== ===========
The accompanying notes are an integral part of the financial
statements.
- 58 -
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF ACCOUNTING PRINCIPLES
General. The Company is subject to regulation by the Public Service Commission
of the State of New York (PSC) under New York statutes and by the Federal Energy
Regulatory Commission (FERC) as a licensee and public utility under the Federal
Power Act. The Company's accounting policies conform to generally accepted
accounting principles as applied to New York State public utilities giving
effect to the rate-making and accounting practices and policies of the PSC.
In June 1988, the Board of Directors authorized the creation of
Utilicom, Inc. as a wholly owned subsidiary. Utilicom develops and markets
computer software to assist customers in complying with state and federal
environmental and safety regulations. On August 31, 1993, the Company sold the
assets of Utilicom and liquidated the subsidiary. The subsidiary activity prior
to and including disposition was insignificant to the Company's financial
position and results of operation.
In April 1990, the Board of Directors authorized the creation of
Energyline Corporation, a wholly owned subsidiary, which was incorporated in
July 1992. Energyline was formed as a gas pipeline corporation to fund the
Company's investment in the Empire State Pipeline project. On November 1, 1993
Empire commenced service to the Company's gas distribution facilities. The
Company has authority to invest up to $20 million in Empire. In June 1993
Empire secured a $150 million credit agreement, the proceeds of which are to
finance approximately 75 percent of the total construction cost and initial
operating expenses. Energyline is obligated to pay up to 20% of the balance
outstanding subject to a commitment of $9.7 million under the credit agreement.
Excluding the loan commitment, at December 31, 1993 the Company had invested a
net amount of $10.2 million in Energyline.
A description of the Company's principal accounting policies follows.
Rates and Revenue. Revenue is recorded on the basis of meters read. In
addition, the Company records an estimate of unbilled revenue for service
rendered subsequent to the meter-read date through the end of the accounting
period.
Tariffs for electric and gas service include fuel cost adjustment
clauses which adjust the rates monthly to reflect changes in the actual average
cost of fuels. The electric fuel adjustment provides that ratepayers and the
Company will share the effects of any variation from forecast monthly unit fuel
costs on a 50%/50% basis up to a $5.6 million cumulative annual gain or loss to
the Company. Thereafter, 100 percent of additional fuel clause adjustment
amounts are assigned to customers. The electric fuel cost adjustment also
provides that any variation from forecast margins below $7.1 million or above
$8.5 million on sales to electric utilities be shared with retail customers on a
50%/50% basis.
- 59 -
In addition, there is a similar 50%/50% sharing process of variances
from forecasted margins derived from sales and the transportation of privately
owned gas to large customers that can use alternate fuels.
Under the Company's Electric Revenue Assurance Mechanism (ERAM), which
was established in the 1993 multi-year rate settlement, any variations between
actual margins and the established targets may be recovered from or returned to
customers. Other performance incentives or penalties were established in the
settlement and under some circumstances could be recognized periodically.
However, through December 31, 1993, no amount was recognized as recoverable or
payable to customers.
Retail customers who use gas for spaceheating are subject to a weather
normalization adjustment to reflect the impact of variations from normal weather
on a billing month basis for the months of October through May, inclusive. The
weather normalization adjustment for a billing cycle will apply only if the
actual heating degree days are lower than 97.5 percent or higher than 102.5
percent of the normal heating degree days. Weather normalization adjustments
lowered gas revenues in 1993 and 1992 by approximately $1.2 million and $1.8
million respectively. These adjustments will continue through June 1996 in
accordance with the 1993 multi-year rate settlement agreement.
Deferred Fuel Costs. The Company practices fuel cost deferral accounting as
described above. A reconciliation of recoverable gas costs with gas revenues is
done annually as of August 31, and the excess or deficiency is refunded to or
recovered from the customers during a subsequent twelve-month period beginning
in December. These deferred fuel costs are included as a component of unbilled
revenues.
Utility Plant, Depreciation and Amortization. The cost of additions to utility
plant and replacement of retirement units of property is capitalized. Cost
includes labor, material, and similar items, as well as indirect charges such
as engineering and supervision, and is recorded at original cost. The Company
capitalizes an allowance for funds used during construction approximately
equivalent to the cost of capital devoted to plant under construction that is
not included in its rate base. Replacement of minor items of property is
included in maintenance expenses. Costs of depreciable units of plant retired
are eliminated from utility plant accounts, and such costs, plus removal
expenses, less salvage, are charged to the accumulated depreciation reserve.
Depreciation in the financial statements is provided on a straight-
line basis at rates based on the estimated useful lives of property, which have
resulted in provisions of 2.9%, 2.9% and 3.3% per annum of average depreciable
property in 1993, 1992 and 1991, respectively. The decrease in depreciation
provision percentages from 1991 to 1992 is principally the result of a 3 1/2
year extension of the Ginna Nuclear Plant license term and lengthening estimated
useful lives at other property.
Nuclear Fuel Disposal Costs. The Nuclear Waste Policy Act (Act) of 1982, as
amended, requires the United States Department of Energy (DOE)
- 60 -
to establish a nuclear waste disposal site and to take title to nuclear waste.
A permanent DOE high-level nuclear waste repository is not expected to be
operational before the year 2010. The DOE is pursuing efforts to establish a
monitored retrievable interim storage facility which may allow it to take title
to and possession of nuclear waste prior to the establishment of a permanent
repository. The Act provides for a determination of the fees collectible by the
DOE for the disposal of nuclear fuel irradiated prior to April 7, 1983 and for
three payment options. The option of a single payment to be made at any time
prior to the first delivery of fuel to the DOE was selected by the Company in
June 1985. The Company estimates the fees, including accrued interest, owed to
the DOE to be $68.1 million at December 31, 1993. The Company is allowed by the
PSC to recover these costs in rates. The estimated fees are classified as a
long-term liability and interest is accrued at the current three-month Treasury
bill rate, adjusted quarterly. The Act also requires the DOE to provide for the
disposal of nuclear fuel irradiated after April 6, 1983, for a charge of one
mill ($.001) per KWH of nuclear energy generated and sold. This charge is
currently being collected from customers and paid to the DOE pursuant to PSC
authorization. The Company expects to utilize on-site storage for all spent or
retired nuclear fuel assemblies until an interim or permanent nuclear disposal
facility is operational.
Nuclear Decommissioning Costs. Decommissioning costs (costs to take the plant
out of service in the future) for the Company's Ginna Nuclear Plant are
estimated to be approximately $150.7 million, and those for the Company's 14%
share of Nine Mile Two's decommissioning costs are estimated to be approximately
$34.3 million (January 1993 dollars). Through December 31, 1993, the Company
has accrued and recovered in rates $61.2 million for this purpose and is
currently accruing and recovering decommissioning costs at a rate of
approximately $8.9 million per year based on the use of a combination of
internal and external sinking funds. (See Note 10.)
The decommissioning costs, which form the basis for current accruals,
were derived from the record of the Company's prior rate proceeding (PSC Opinion
93-19, issued August 1993) and were estimated principally by reference to a
formula prescribed by the NRC for the purpose of providing for adequate funding
at the time of the decommissioning.
Uranium Enrichment Decontamination and Decommissioning Fund. As part of the
National Energy Act (Act) issued in October 1992, utilities with nuclear
generating facilities are assessed an annual fee payable over 15 years to pay
for the decommissioning of Federally owned uranium enrichment facilities. The
assessments for Ginna and Nine Mile Two are estimated to total $24.1 million,
excluding inflation and interest. The first installment of $1.6 million was
paid in 1993 and recovered through the fuel adjustment clause. A liability has
been recognized on the financial statements along with a corresponding
regulatory asset. The Company believes that the full amount of the assessment
will be recoverable in rates as described in the Act.
FERC Order 636. Under this order, gas supply and pipeline companies are allowed
to pass restructuring and transition costs associated with the
- 61 -
implementation of the order on to their customers. The Company, as a customer,
has estimated a total of $43.5 million which will be paid to its suppliers. A
regulatory asset and related deferred credit have been established on the
balance sheet to account for these estimated costs. Approximately $2.2 million
of these costs were paid during 1993 to various suppliers, and have been
included in purchased gas costs (see Note 10).
Allowance for Funds Used During Construction. The Company capitalizes an
Allowance for Funds Used During Construction (AFUDC) based upon the cost of
borrowed funds for construction purposes, and a reasonable rate upon the
Company's other funds when so used. AFUDC is segregated into two components and
classified in the Statement of Income as Allowance for Borrowed Funds Used
During Construction, an offset to Interest Charges, and Allowance for Other
Funds used During Construction, a part of Other Income.
The rates approved by the PSC for purposes of computing AFUDC were:
3.9% from September 1, 1993 through December 31, 1993; 4.5% from September 1,
1992 through August 31, 1993; 5.5% from April 1, 1992 through August 31, 1992;
7.1% from July 1, 1991 through March 31, 1992; 8.6% from February 1, 1991
through June 30, 1991; 9.6% from January 1, 1991 through January 31, 1991.
In 1984, the Company discontinued accruing AFUDC on a portion of its
investment in Nine Mile Two for which a cash return was allowed. Amounts were
accumulated in deferred debit and credit accounts equal to the amount of AFUDC
which was no longer accrued. The balance in the deferred credit account was
intended to reduce future cash revenue requirements over a period substantially
shorter than the life of Nine Mile Two, and the balance in the deferred debit
account would then be collected from customers over a longer period of time.
The current balances of $19.2 million are expected to remain on the Company's
books for future application by the PSC as a rate moderator.
Federal Income Tax. For income tax purposes, depreciation is generally computed
using the most liberal methods permitted. The resulting tax reductions are
offset by provisions for deferred income taxes only to the extent ordered or
permitted by regulatory authorities.
Statement of Financial Accounting Standards (SFAS) 109, Accounting for
Income Taxes, was adopted by the Company during the first quarter of 1993.
SFAS-109 requires that a deferred tax liability must be recognized on the
balance sheet for tax differences previously flowed through to customers.
Substantially all of these flow-through adjustments relate to property plant and
equipment and related investment tax credits and will be amortized consistent
with the depreciation of these accounts. The net amount of the additional
liability at December 31, 1993 was $241 million. In conjunction with the
recognition of this liability, a corresponding regulatory asset was also
recognized.
SFAS-109 also requires that a deferred tax liability or asset be
adjusted in the period of enactment for the effect of changes in tax laws or
rates. During the year the statutory income tax rate was
- 62 -
increased one percent to 35%. This resulted in increases of $.6 million and
$1.3 million for current and deferred tax liabilities, respectively. There was
no earnings impact since the effects of the tax change have been deferred for
future recovery.
The Company uses the separate-period approach in calculating the
interim quarterly tax provision.
Retirement Health Care and Life Insurance Benefits. The Company provides
certain health care and life insurance benefits for retired employees and health
care coverage for surviving spouses of retirees. Substantially all of the
Company's employees may become eligible for these benefits if they reach
retirement age while working for the Company. These and similar benefits for
active employees are provided through insurance policies whose premiums are
based upon the experience of benefits actually paid.
In December 1990, the FASB issued SFAS-106 entitled "Accounting for
Postretirement Benefits Other than Pensions" effective for fiscal years
beginning after December 15, 1992. Among other things, SFAS-106 requires
accrual accounting by employers for postretirement benefits other than pensions
reflecting currently earned benefits. The Company adopted this accounting
practice in 1992.
In September 1993, the PSC issued a "Statement of Policy Concerning the
Accounting and Ratemaking Treatment for Pensions and Postretirement Benefits
Other Than Pensions". The Statement's provisions require, among other things,
ten-year amortization of actuarial gains and losses and deferral of differences
between actual costs and rate allowances. The effects of applying the ten year
amortization of actuarial gains were deferred.
Postemployment Benefits. In November 1992, the FASB issued SFAS-112 entitled
"Employees' Accounting for Postemployment Benefits" which is effective for
fiscal years beginning after December 15, 1993. This Statement requires the
Company to recognize the obligation to provide post-employment benefits to
former or inactive employees after employment but before retirement. The
Company must adopt SFAS-112 not later than the first quarter of 1994. The
Company is currently evaluating the impact of SFAS-112; however, based on
studies the Company has performed to date, the adoption of SFAS-112 is not
expected to have a material effect on the Company's financial condition or
results of operations.
Earnings Per Share. Earnings applicable to each share of common stock are based
on the weighted average number of shares outstanding during the respective
years.
- 63 -
Note 2. Federal Income Taxes
The provision for Federal income taxes is distributed between operating
expense and other income based upon the treatment of the various components of
the provision in the rate-making process. The following is a summary of income
tax expense for the three most recent years.
(Thousands of Dollars) 1993 1992 1991
-------- -------- --------
Charged to operating expense:
Current $ 33,453 $ 36,101 $ 28,766
Deferred 15,877 7,490 5,493
-------- -------- --------
Total 49,330 43,591 34,259
-------- -------- --------
Charged (Credited) to other income:
Current (9,182) (7,171) (8,211)
Deferred (645) 2,976 3,631
-------- -------- --------
Total (9,827) (4,195) (4,580)
-------- -------- --------
Total Federal income tax expense $ 39,503 $ 39,396 $ 29,679
-------- -------- --------
The following is a reconciliation of the difference between the amount of
Federal income tax expense reported in the Statement of Income and the amount
computed by multiplying the income by the statutory tax rate.
(Thousands of Dollars) 1993 1992 1991
% of % of % of
Pretax Pretax Pretax
Amount Income Amount Income Amount Income
------ ------ ------ ------ ------ ------
Net Income $ 78,563 $ 70,439 $ 57,997
Add: Federal income tax expense 39,503 39,396 29,679
-------- -------- --------
Income before Federal income tax $118,066 $109,835 $ 87,676
-------- -------- --------
Computed tax expense $ 41,323 35.0 $ 37,344 34.0 $ 29,810 34.0
Increases (decreases) in tax resulting
from: Difference between tax
depreciation and amount deferred 6,337 5.4 6,775 6.2 5,606 6.4
Investment tax credit (2,432) (2.1) (2,426) (2.2) (2,432) (2.8)
Miscellaneous items, net (5,725) (4.8) (2,297) (2.1) (3,305) (3.7)
-------- -------- --------
Total Federal income tax expense $ 39,503 33.5 $ 39,396 35.9 $ 29,679 33.9
A summary of the components of the net deferred tax liability is as follows:
(Thousands of Dollars) 1993 1992
------ ------
Nuclear decommissioning ($11,518) ($13,087)
Nine Mile disallowance (15,200) (19,569)
Alternate minimum tax (27,908) (27,611)
Accelerated depreciation 164,821 174,237
Investment tax credit 34,305 55,206
Ice storm 5,642 6,519
Depreciation and ITC previously flowed through 246,127 -
Other 29,379 (4,022)
-------- --------
Total $425,648 $171,673
In 1993, the regulatory asset recognized by the Company as a result of
adopting SFAS No. 109 is attributed to $222 million in depreciation, $18 million
to property taxes, $18 million of deferred finance charges - Nine Mile Two and
$4 million of Miscellaneous items offset by $21 million attributed to investment
tax credits.
- 64 -
Note 3. Pension Plan and Other Retirement Benefits
The Company has a defined benefit pension plan covering substantially all of
its employees. The benefits are based on years of service and the employee's
compensation during the last three years of employment. The Company's funding
policy is to contribute annually an amount consistent with the requirements of
the Employee Retirement Income Security Act and the Internal Revenue Code.
These contributions are intended to provide for benefits attributed to service
to date and for those expected to be earned in the future.
The plan's funded status and amounts recognized on the Company's balance
sheet are as follows:
(Millions)
------------------------
1993 1992
Accumulated benefit obligation, including
vested benefits of $286.1 in 1993 and
$249.6 in 1992 $ (309.3)* $(268.1)*
========= =======
Projected benefit obligation for service
rendered to date $ (429.5)* $(378.0)*
Less - Plan assets at fair value, primarily
listed stocks and bonds 490.3 449.9
--------- -------
Plan assets in excess of projected benefits 60.8 71.9
Unrecognized net loss (gain) from past
experience different from that assumed
and effects of changes in assumptions (110.6) (102.4)
Prior service cost not yet recognized in
net periodic pension cost 13.7 5.4
Unrecognized net obligation at December 31 4.2 4.8
--------- -------
Pension costs accrued $(31.9)** $ (20.3)
========= =======
* Actuarial present value
** Includes $9.2 million pension plan curtailment charge.
(Millions)
-------------------------------
1993 1992 1991
Net pension cost included the following
components:
Service cost - benefits earned during
the period $ 8.7 $ 8.8 $ 7.1
Interest cost on projected benefit
obligation 30.0 27.9 26.4
Actual return on plan assets (60.2) (35.1) (58.6)
Net amortization and deferral 24.3 5.5 33.1
------ ------ ------
Net periodic pension cost $ 2.8 $ 7.1 $ 8.0
====== ====== ======
- 65 -
The projected benefit obligation at December 31, 1993 and 1992 assumed
discount rates of 7 1/4 percent and 7 3/4 percent, respectively and long-term
rate of increase in future compensation levels of 6 percent and 6 1/2 percent,
respectively. The assumed long-term rate of return on plan assets for 1993 and
1992 was 8 1/2 percent. The unrecognized net obligation is being amortized over
15 years beginning January 1986.
In September 1993, the PSC issued a "Statement of Policy Concerning the
Accounting and Ratemaking Treatment for Pensions and Postretirement Benefits
Other than Pensions" (Statement). The 1993 pension cost reflects adoption of
the Statement's provisions which, among other things, requires ten-year
amortization of actuarial gains and losses and deferral of differences between
actual costs and rate allowances.
In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits to retired employees and health care
coverage for surviving spouses of retirees. Substantially all of the Company's
employees are eligible provided that they retire as employees of the Company.
In 1993, the health care benefit consisted of a contribution of up to $175 per
month towards the cost of a group health policy provided by the Company. The
life insurance benefit consists of a Basic Group Life benefit, covering
substantially all employees, providing a death benefit equal to one-half of the
retiree's final pay. In addition, certain employees and retirees, employed by
the Company at December 31, 1982, are entitled to a Special Group Life benefit
providing a death benefit equal to the employee's December 31, 1982 pay.
The Company adopted SFAS-106, "Accounting for Postretirement Benefits Other
than Pensions" as of January 1, 1992 for financial accounting purposes.
Subsequently, with the issuance of the Statement referenced above, the Company's
application of SFAS-106 will extend to ratemaking purposes as well. The Company
has elected to amortize the unrecognized, unfunded Accumulated Postretirement
Benefit Obligation at January 1, 1992 over twenty years as provided by SFAS-106.
The Company intends to continue funding these benefits on a pay-as-you-go basis.
- 66 -
The plans' funded status reconciled with the Company's balance sheet is as
follows:
(Millions)
------------------
1993 1992
Accumulated postretirement benefit
obligation:
Retired employees $(39.9) $(35.3)
Active employees (24.9) (23.6)
------ ------
$(64.8) $(58.9)
Less - Plan assets at fair value 0.0 0.0
------ ------
Accumulated postretirement benefit
obligation (in excess of) less than
fair value of assets (64.8) (58.9)
Unrecognized net loss (gain) from past experience
different from that assumed and effects
of changes in assumptions 2.9 0.0
Prior service cost not yet recognized in
net periodic pension cost 1.7 0.0
Unrecognized net obligation at December 31 50.7 53.6
------ ------
Accrued postretirement benefit cost $ (9.5) $ (5.3)
====== ======
Net periodic postretirement benefit
cost included the following components:
(Millions)
------------------
1993 1992
Service cost - benefits attributed to
the period $ 0.7 $ 0.7
Interest cost on accumulated postretirement
benefit obligation 4.6 4.3
Actual return on plan assets 0.0 0.0
Net amortization and deferral 2.2 2.8
------ ------
Net periodic postretirement benefit cost $ 7.5 $ 7.8
====== ======
The Accumulated Postretirement Benefit Obligation at December 31, 1993 and
1992 assumed discount rates of 7 1/4 percent and 7 3/4 percent, respectively and
long-term rate of increase in future compensation levels of 6 percent and 6 1/2
percent, respectively.
- 67 -
Note 4. Departmental Financial Information
The Company's records are maintained by operating departments, in
accordance with PSC accounting policies, giving effect to the rate-
making process. The following is the operating data for each of the
Company's departments, and no interdepartmental adjustments are
required to arrive at the operating data included in the Statement of
Income.
(Thousands of Dollars)
1993 1992 1991
---- ---- ----
Electric
Operating Information
Operating revenues $ 655,316 $ 633,808 $ 617,542
Operating expenses, excluding
provision for income taxes 486,951 482,968 478,101
--------- --------- ---------
Pretax operating income 168,365 150,840 139,441
Provision for income taxes 43,845 38,046 31,390
--------- --------- ---------
Net operating income $ 124,520 $ 112,794 $ 108,051
--------- --------- ---------
Other Information
Depreciation and amortization $ 72,326 $ 73,213 $ 72,746
Nuclear fuel amortization $ 18,861 $ 18,803 $ 23,606
Capital expenditures $ 112,022 $ 100,974 $ 97,294
Investment Information
Identifiable assets (a) $1,978,009 $1,671,492 $1,607,210
Gas
Operating Information
Operating revenues $ 293,708 $ 261,724 $ 235,728
Operating expenses, excluding
provision for income taxes 265,510 235,029 216,151
--------- --------- ---------
Pretax operating income 28,198 26,695 19,577
Provision for income taxes 5,485 5,545 2,869
--------- --------- ---------
Net operating income $ 22,713 $ 21,150 $ 16,708
--------- --------- ---------
Other Information
Depreciation and amortization $ 11,851 $ 11,815 $ 11,435
Capital expenditures $ 27,385 $ 24,231 $ 26,763
Investment Information
Identifiable assets (a) $ 491,563 $ 354,528 $ 325,451
(a) Excludes cash, unamortized debt expense and other common items.
- 68 -
NOTE 5. JOINTLY-OWNED FACILITIES
The following table sets forth the jointly-owned electric generating
facilities in which the Company is participating. Both Oswego Unit No. 6 and
Nine Mile Point Nuclear Plant Unit No. 2 have been constructed and are
operated by Niagara Mohawk Power Corporation. Each participant must provide
its own financing for any additions to the facilities. The Company's share of
direct expenses associated with these two units is included in the appropriate
operating expenses in the Statement of Income. Various modifications will be
made throughout the lives of these plants to increase operating efficiency or
reliability, and to satisfy changing environmental and safety regulations.
================================================================================
Oswego Nine Mile
Unit No. 6 Point Nuclear
Unit No. 2
- --------------------------------------------------------------------------------
Net megawatt capacity 850 1,080
RG&E's share-megawatts 204 151
-percent 24 14
Year of completion 1980 1988
Millions of Dollars at December 31, 1993
---------------------------
Plant In Service Balance $97.7 $869.8
Accumulated Provision For Depreciation $32.0 $441.1
Plant Under Construction $ 0.5 $ 12.4
================================================================================
The Plant in Service and Accumulated Provision for Depreciation balances for
Nine Mile Point Nuclear Unit No. 2 shown above have been increased by the
disallowed costs of $374.3 million. Such costs, net of income tax effects, were
previously written off in 1987 and 1989.
- 69 -
Note 6. Long Term Debt
First Mortgage Bonds
- -------------------------------------------------------------------------------------
(Thousands)
Principal Amount
-----------------------
December 31
% Series Due 1993 1992
- -------------------------------------------------------------------------------------
4 5/8 U Sept. 15, 1994 $ 16,000 $ 16,000
5.30 V May 1, 1996 18,000 18,000
6 1/4 W Sept. 15, 1997 20,000 20,000
6.7 X July 1, 1998 30,000 30,000
8.00 Y Aug. 15, 1999 30,000 30,000
9 1/8 Z Sept. 1, 2000 - 30,000
9 1/4 BB June 15, 2006 - 50,000
8 3/8 CC Sept. 15, 2007 50,000 50,000
9 1/2 DD Dec. 1, 2003 - 40,000
6 1/2 EE/(a)/ Aug. 1, 2009 10,000 10,000
10.95 FF Feb. 15, 2005 2,750 5,500
13 7/8 JJ June 15, 1999 15,000 17,500
8.60 LL Aug. 1, 1993 - 75,000
8 3/8 OO/(a)/ Dec. 1, 2028 25,500 25,500
9 3/8 PP Apr. 1, 2021 100,000 100,000
8 1/4 QQ/(b)/ Mar. 15, 2002 100,000 100,000
6.35 RR/(a)/ May 15, 2032 10,500 10,500
6.50 SS/(a)/ May 15, 2032 50,000 50,000
7.00 (b)(c) Jan. 14, 2000 30,000 -
7.15 (b)(c) Feb. 10, 2003 39,000 -
7.13 (b)(c) Mar. 3, 2003 1,000 -
7.64 (c) Mar. 15, 2023 33,000 -
7.66 (c) Mar. 15, 2023 5,000 -
7.67 (c) Mar. 15, 2023 12,000 -
6.375 (b)(c) July 30, 2003 40,000 -
7.45 (c) July 30, 2023 40,000 -
-------- --------
677,750 678,000
Net bond discount (769) (770)
Less: Due within one year 21,250 110,250
-------- --------
Total $655,731 $566,980
======== ========
(a) The Series EE, Series OO, Series RR and Series SS First Mortgage Bonds equal
the principal amount of and provide for all payments of principal, premium
and interest corresponding to the Pollution Control Revenue Bonds, Series A,
Series C, and Pollution Control Refunding Revenue Bonds, Series 1992 A,
Series 1992 B (Rochester Gas and Electric Corporation Projects),
respectively, issued by the New York State Energy Research and Development
Authority through a participation agreement with the Company. Payment of
the principal of, and interest on the Series 1992 A and Series 1992 B Bonds
are guaranteed under a Bond Insurance Policy by Municipal Bond Investors
Assurance Corporation. The Series EE Bonds are subject to a mandatory
sinking fund beginning August 1, 2000 and each August 1 thereafter. Nine
annual deposits aggregating $3.2 million will be made to the sinking fund,
with the balance of $6.8 million principal amount of the bonds becoming due
August 1, 2009.
(b) The Series QQ First Mortgage Bonds and 7%, 7.15%, 7.13% and 6.375% medium-
term notes described below are generally not redeemable prior to maturity.
(c) In 1993 the Company issued $200 million under a medium-term note program
- 70 -
entitled "First Mortgage Bonds, Designated Secured Medium-Term Notes, Series
A" with maturities that range from seven years to thirty years.
The First Mortgage provides security for the bonds through a first lien on
substantially all the property owned by the Company (except cash and accounts
receivable).
Sinking and improvement fund requirements aggregate $333,540 per annum under the
First Mortgage, excluding mandatory sinking funds of individual series. Such
requirements may be met by certification of additional property or by depositing
cash with the Trustee. The 1992 and 1993 requirements were met by certification
of additional property.
Sinking fund requirements and bond maturities for the next five years are:
(Thousands)
-----------------------------------------------------------
1994 1995 1996 1997 1998
-----------------------------------------------------------
Series FF/(d)/ $ 2,750
Series JJ/(e)/ 2,500 $ 2,500 $ 2,500 $ 2,500 $ 2,500
Series U 16,000
Series V 18,000
Series W 20,000
Series X 30,000
-----------------------------------------------------------
$21,250 $ 2,500 $20,500 $22,500 $32,500
(d) The Series FF First Mortgage Bonds are subject to a mandatory sinking fund
of $2.75 million annually each February 15.
(e) The Series JJ First Mortgage Bonds are subject to a mandatory sinking fund
of $2.5 million annually each June 15.
Promissory Notes
- ---------------------------------------------------------------
(Thousands)
December 31
Issued Due 1993 1992
- ---------------------------------------------------------------
November 15, 1984/(f)/ October 1, 2014 $51,700 $51,700
December 5, 1985/(g)/ November 15, 2015 40,200 40,200
------- -------
Total $91,900 $91,900
======= =======
(f) The $51.7 million Promissory Note was issued in connection with NYSERDA's
Floating Rate Monthly Demand Pollution Control Revenue Bonds (Rochester Gas
and Electric Corporation Project), Series 1984. This obligation is supported
by an irrevocable Letter of Credit expiring October 15, 1994. The interest
rate on this note for each monthly interest payment period will be based on
the evaluation of the yields of short term tax-exempt securities at par
having the same credit rating as said Series 1984 Bonds. The average
interest rate was 2.19% for 1993, 2.74% for 1992 and 4.32% for 1991. The
interest rate will be adjusted monthly unless converted to a fixed rate.
- 71 -
(g) The $40.2 million Promissory Note was issued in connection with NYSERDA's
Adjustable Rate Pollution Control Revenue Bonds (Rochester Gas and Electric
Corporation Project), Series 1985. This obligation is supported by an
irrevocable Letter of Credit expiring November 30, 1996. The annual interest
rate was adjusted to 4.50% effective November 15, 1991, to 3.10% effective
November 15, 1992 and to 2.75% effective November 15, 1993. The interest
rate will be adjusted annually unless converted to a fixed rate.
The Company is obligated to make payments of principal, premium and interest on
each Promissory Note which correspond to the payments of principal, premium, if
any, and interest on certain Pollution Control Revenue Bonds issued by the New
York State Energy Research and Development Authority (NYSERDA) as described
above. These obligations are supported by certain Bank Letters of Credit
discussed above. Any amounts advanced under such Letters of Credit must be
repaid, with interest, by the Company.
Based on an estimated borrowing rate at year-end 1993 of 6.68% for long term
debt with similar terms and average maturities (14 years), the fair value of the
Company's long term debt outstanding (including Promissory Notes as described
above) is approximately $816 million at December 31, 1993.
- 72 -
Note 7. Preferred and Preference Stock
Type, by Order Par Shares Shares
of Seniority Value Authorized Outstanding
- -------------- ----- ---------- ------------
Preferred Stock (cumulative) $100 2,000,000 1,150,000*
Preferred Stock (cumulative) 25 4,000,000
Preference Stock 1 5,000,000
*See below for mandatory redemption requirements
No shares of preferred or preference stock are reserved for employees, or for
options, warrants, conversions, or other rights.
A. Preferred Stock, not subject to mandatory redemption:
(Thousands)
Shares ----------- Optional
Outstanding December 31 Redemption
% Series December 31, 1993 1993 1992 (per share) #
- ----- ------ ----------------- ------- ------- -------------
4 F 120,000 $12,000 $12,000 $105
4.10 H 80,000 8,000 8,000 101
4 3/4 I 60,000 6,000 6,000 101
4.10 J 50,000 5,000 5,000 102.5
4.95 K 60,000 6,000 6,000 102
4.55 M 100,000 10,000 10,000 101
7.50 N 200,000 20,000 20,000 102
------- ------- -------
Total 670,000 $67,000 $67,000
------- ------- -------
#May be redeemed at any time at the option of the Company on 30 days minimum
notice, plus accrued dividends in all cases
B. Preferred Stock, subject to mandatory redemption:
(Thousands)
Shares ----------- Optional
Outstanding December 31 Redemption
% Series December 31, 1993 1993 1992 (per share)
- ---- ------ ----------------- ------- --------- ---------------------
8.25 R 180,000 $18,000 $30,000 $102.00 Before 3/1/94+
7.45 S 100,000 10,000 10,000 Not applicable
7.55 T 100,000 10,000 10,000 Not applicable
7.65 U 100,000 10,000 10,000 Not applicable
------- ------- -------
480,000 48,000 60,000
Less: Due within one year 60,000 6,000 6,000 **
------- ------- -------
420,000 $42,000 $54,000
------- -------
+Thereafter at $100.00
**Excludes $ six million optional redemption effective March 1, 1993
Mandatory Redemption Provisions.
- -------------------------------
In the event the Company should be in arrears in the sinking fund requirement,
the Company may not redeem or pay dividends on any stock subordinate to the
Preferred Stock.
Series R. Mandatory redemption of 60,000 shares per year at $100 per share
- --------
commenced on March 1, 1993 for Series R and on each March 1 thereafter, so long
as any shares remain outstanding. In addition, the Company has the non-
cumulative right to redeem up to an additional 60,000 shares on the same terms
and dates applicable to the mandatory sinking fund redemptions. The Company
redeemed 120,000 shares on March 1, 1993 and the Company has the right to redeem
up to the remaining 180,000 shares on March 1, 1994.
- 73 -
Series S, Series T, Series U. All of the shares are subject to redemption
- ----------------------------
pursuant to mandatory sinking funds on September 1, 1997 in the case of Series
S, September 1, 1998 in the case of Series T and September 1, 1999 in the case
of Series U; in each case at $100 per share.
Based on an estimated dividend rate at year-end 1993 of 5.25% for Preferred
Stock, subject to mandatory redemption, with similar terms and average
maturities (3.25 years), the fair value of the Company's Preferred Stock,
subject to mandatory redemption, is approximately $53 million at December 31,
1993.
- 74 -
Note 8. Common Stock
At December 31, 1993, there were 50,000,000 shares of $5 par value Common Stock
authorized, of which 36,911,265 were outstanding. No shares of Common Stock are
reserved for options, warrants, conversions, or other rights. There were
1,193,613 shares of Common Stock reserved and unissued for shareholders under
the Automatic Dividend Reinvestment and Stock Purchase Plan and 253,090 shares
reserved and unissued for employees under the RG&E Savings Plus Plan.
Common Stock
Per Shares Amount
Share Outstanding (Thousands)
----- ----------- -----------
Balance, January 1, 1991 31,421,268 $516,388
Automatic Dividend Reinvestment 18.750-
and Stock Purchase Plan 23.163 571,669 11,252
Savings Plus Plan 19.375-
23.563 108,202 2,194
Capital Stock Expense (495)
----------- ---------
Balance, December 31, 1991 32,101,139 $529,339
Sale of Stock 24.000 2,000,000 48,000
Automatic Dividend Reinvestment 21.325-
and Stock Purchase Plan 24.850 584,854 13,338
Savings Plus Plan 22.063-
25.188 110,666 2,590
Capital Stock Expense (1,735)
----------- ---------
Balance, December 31, 1992 34,796,659 $591,532
Sale of Stock 29.625 1,500,000 44,438
Automatic Dividend Reinvestment 25.475-
and Stock Purchase Plan 29.413 515,036 14,076
Savings Plus Plan 25.813-
29.250 99,570 2,741
Capital Stock Expense (615)
----------- ---------
Balance, December 31, 1993 36,911,265 $652,172
- 75 -
Note 9. Short Term Debt
At December 31, 1993 and December 31, 1992, the Company had short term debt
outstanding of $68.1 million and $50.8 million, respectively. The weighted
average interest rate on short term debt outstanding at year end 1993 was
3.46% and was 3.48% for borrowings during the year. For 1992, the weighted
average interest rate on short term debt outstanding at year end was 3.99% and
was 4.28% for borrowings during the year.
On December 1, 1988 the Company renewed its $90 million revolving credit
facility for a period of three years and this agreement has been regularly
extended. In November of 1993 the Company was granted a one-year extension of
the commitment termination date to December 31, 1996. Commitment fees related
to this facility amounted to $169,000 in 1993, $169,000 in 1992 and $149,000 in
1991.
The Company's Charter provides that unsecured debt may not exceed 15 percent of
the Company's total capitalization (excluding unsecured debt). As of December
31, 1993, the Company would be able to incur $19.2 million of additional
unsecured debt under this provision. In order to be able to use its revolving
credit agreement, the Company has created a subordinate mortgage which secures
borrowings under its revolving credit agreement that might otherwise be
restricted by this provision of the Company's Charter.
Since June 1990 the Company has had a credit agreement with a domestic bank
providing for up to $20 million of short term debt. Borrowings under this
agreement, which has been extended to December 31, 1994, are secured by the
Company's accounts receivable.
Also, additional unsecured short term borrowing capacity of up to $70 million is
available from domestic banks, at their discretion.
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Note 10. Commitments and Other Matters
CAPITAL EXPENDITURES.
The Company's 1994 construction expenditures program is currently
estimated at $138 million, including $16 million related to replacement of the
steam generators at the Ginna Nuclear Plant and $2 million of Allowance for
Funds Used During Construction. The Company has entered into certain
commitments for purchase of materials and equipment in connection with that
program.
NUCLEAR-RELATED MATTERS.
DECOMMISSIONING TRUST. Under accounting procedures approved by the
PSC, the Company has been collecting in its electric rates amounts for the
eventual decommissioning of its Ginna Plant and for its 14% share of the
decommissioning of Nine Mile Two. The operating licenses for these plants
expire in 2009 and 2026 respectively. The Company has collected approximately
$61.2 million through December 31, 1993.
The Nuclear Regulatory Commission (NRC) requires reactor licensees to
submit funding plans that establish minimum external funding levels for reactor
decommissioning. The Company's plan consists principally of an external
decommissioning trust fund covering both its Ginna Plant and its Nine Mile Two
share. Since 1990, the Company has contributed some $36.9 million to this fund.
In addition, the Company maintains an internal reserve to fund the removal of
non-radioactive structures, a feature not covered by the NRC minimum funding.
In connection with the Company's rate settlement completed in August
1993, the PSC approved the collection during the rate year ending June 30, 1994
of an aggregate $8.9 million for decommissioning, covering both nuclear units.
The amount allowed in rates is based on estimated ultimate decommissioning costs
of $150.7 million for Ginna and $34.3 million for the Company's 14% share of
Nine Mile Two (January 1993 dollars). This estimate is based principally on the
application of a NRC formula to determine minimum funding. Site specific
studies of the anticipated costs of actual decommissioning are required to be
submitted to the NRC at least five years prior to the expiration of the license.
The Company intends to fund the external decommissioning trust in the amount of
the NRC minimum funding requirement. The difference between the amount to be
collected and the NRC minimum will be held in an internal reserve.
The Company is aware of recent NRC activities related to upward
revisions to the required minimum funding levels. These activities, primarily
focused on disposition of low level radioactive waste, may require the Company
to increase funding. The Company continues to monitor these activities but
cannot predict what regulatory actions the NRC may ultimately take.
URANIUM ENRICHMENT DECONTAMINATION AND DECOMMISSIONING FUND. Nuclear
reactor licensees in the U.S. are assessed annually for the decontamination and
decommissioning of Department of Energy (DOE) enrichment facilities. The
Company made the first of 15 annual payments for this purpose in September 1993,
remitting approximately $1.6 million ($1.5 million for the Ginna Plant and $0.1
million for its share of the Nine Mile Two plant). For the two facilities the
Company recognized liabilities at December 31, 1993 of $23.4 million ($21.7
million as a
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long-term liability and $1.7 million as a current liability). In October 1993,
the Company began recovery of this deferral through its fuel adjustment clause.
INSURANCE PROGRAM. The Price-Anderson Act establishes a federal
program, providing indemnification and insurance against public liability,
applicable in the event of a nuclear accident at a licensed U.S. reactor. As a
result of amendments to the Act in 1988, the limit of liability has increased to
approximately $9.4 billion. Also in 1988 coverage was expanded to include
precautionary evacuations and the Act was extended until the year 2002. Under
the program, claims would first be met by insurance which licensees are required
to carry in the maximum amount available (currently $200 million). If claims
exceed that amount, licensees are subject to a retrospective assessment up to
$75.5 million per licensed facility for each nuclear incident, payable at a rate
not to exceed $10 million per year. Those assessments are subject to periodic
inflation-indexing and to a 5% surcharge if funds prove insufficient to pay
claims. In addition, the retrospective assessments would be subject to a three
percent charge for premium tax. The Company's interests in two nuclear units
could thus expose it to a potential liability for each accident of $86.1 million
through retrospective assessments of $11.4 million per year in the event of a
sufficiently serious nuclear accident at its own or another U.S. commercial
nuclear reactor.
Beginning in 1988, coverage for claims alleging radiation-induced
injuries to some workers at nuclear reactor sites was removed from the nuclear
liability insurance policies purchased by the Company. Coverage for workers
first engaged in nuclear-related employment at a nuclear site prior to 1988
continues to be provided under then-existing nuclear liability insurance
policies. Those workers first employed at a nuclear facility in 1988 or later
are covered under a separate, industry-wide insurance program. That program
contains a retrospective premium assessment feature whereby participants in the
program can be assessed to pay incurred losses that exceed the program's
reserves. Under the plan as currently established, the Company could be
assessed a maximum of $3.1 million over the life of the insurance coverage.
The Company is a member of Nuclear Electric Insurance Limited, which
provides insurance coverage for the cost of replacement power during certain
prolonged accidental outages of nuclear generating units and coverage for
property losses in excess of $500 million at nuclear generating units. As of
December 31, 1993, the Company is purchasing a weekly indemnity limit of $3.5
million in the NEIL I replacement power expense program and full policy limits
of $1.4 billion in the NEIL II Property Insurance Program for the Ginna Nuclear
Power Plant. Coverage under the Property Insurance Program includes the
shortfall in the NRC required external trust fund resulting from the premature
decommissioning of a nuclear power plant following an accident with property
damage in excess of $500 million. The Company currently has designated $166
million as a sublimit for this coverage at the Ginna Nuclear Power Plant. For
its share in the generation of Nine Mile Two the Company purchases a weekly
indemnity limit of $.5 million in the NEIL I replacement power expense program.
The owners at Nine Mile Two purchase the full policy limit of $1.4 billion in
the NEIL II Property Insurance Program and the Company pays its proportionate
share of those premiums. The owners at Nine Mile Two have selected the maximum
available sublimit of $250 million for premature decommissioning. If an
insuring program's losses exceeded its other resources available to pay
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claims, the Company could be subject to maximum assessments in any one policy
year of approximately $4.9 million and $14.9 million in the event of losses
under the replacement power and property damage coverages, respectively.
ENVIRONMENTAL MATTERS.
The production and delivery of energy are necessarily accompanied by
the release of by-products subject to environmental controls. In recognition of
the Company's responsibility to preserve the quality of the air, water, and land
it shares with the community it serves, the Company has taken a variety of
measures (e.g., self-auditing, recycling and waste minimization, training of
employees in hazardous waste management) to reduce the potential for adverse
environmental effects from its energy operations and, specifically, to manage
and appropriately dispose of wastes currently being generated. The Company,
nevertheless, has been contacted, along with numerous others, concerning wastes
shipped off-site to licensed treatment, storage and disposal sites where
authorities have later questioned the handling of such wastes. In such
instances, the Company typically seeks to cooperate with those authorities and
with other site users to develop cleanup programs and to fairly allocate the
associated costs.
As part of its commitment to environmental excellence, the Company is
conducting proactive Site Investigation and Remediation (SIR) efforts at
Company-owned sites where past waste handling and disposal may have occurred.
The Company currently estimates the total costs it could incur for SIR
activities at Company-owned sites to be about $20 million. This estimate will
vary as better site information is available. The Company anticipates spending
$10 million over the next 5 years on SIR initiatives. Approximately $4.5
million has been provided for in rates through June 1996 for recovery of SIR
costs. To the extent actual expenditures differ from this amount, they will be
deferred for future disposition and recovery as authorized by the PSC.
In 1985, the New York State Department of Environmental Conservation
(NYSDEC) identified property in the vicinity of the Lower Falls of the Genesee
River (the Lower Falls) in Rochester as an inactive hazardous waste disposal
site. The Company owns, and was the prior owner or operator of, a number of
locations within the Lower Falls. In mid-1991, NYSDEC advised the Company that
it had delisted the Lower Falls site, i.e., removed it from its Registry of
Inactive Hazardous Waste Disposal Sites. The effect of delisting is to
terminate the Company's status as a potentially responsible party for the Lower
Falls site, to discontinue the pending NYSDEC review of a joint Company/City of
Rochester proposal for a limited further investigation of the Lower Falls, to
defer the prospect of remedial action and perhaps to end any Company sharing of
the cost thereof. However, NYSDEC also stated its intention to consider listing
individual coal gasification sites within the larger, original site once the
State of New York adopts new federal hazardous waste criteria. There is at
least some material at one of the individual coal gasification sites that could
trigger relisting. The Company is unable to predict what further listing action
NYSDEC may take, but regards the delisting as a positive development.
The Company and its predecessors formerly owned and operated coal
gasification facilities within the Lower Falls. In September 1991 the Company
initiated a study of subsurface conditions in the vicinity of retired facilities
at its West Station property and has since commenced the removal of soils
containing hazardous substances in order
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to minimize any potential long-term exposure risks. Cleanup efforts have been
temporarily suspended while the Company investigates more cost effective
remedial technologies. Activities are expected to resume within a year.
On a portion of the Company's property in the Lower Falls, and
elsewhere in the general area, the County of Monroe has installed and operates
sewer lines. During sewer installation, the County constructed over Company
property, pursuant to an easement which the Company granted the County, certain
retention ponds which reportedly received from the sewer construction area
certain fossil-fuel-based materials ("the materials") found there. In July 1989
the Company received a letter from the County asserting that activities of the
Company left the County unable to effect a regulatorily-approved closure of the
retention pond area. The County's letter takes the position that it intends to
seek reimbursement for its additional costs incurred with respect to the
materials once the NYSDEC identifies the generator thereof and that any further
cleanup action which the NYSDEC may require at the retention pond site is the
Company's responsibility. In the course of discussions over this matter, the
County has claimed, without offering any evidence, that the Company was the
original generator of the materials. It asserts that it will hold the Company
liable for all County costs --presently estimated at $1.5 million -- associated
both with the materials' excavation, treatment and disposal and with effecting a
regulatorily-approved closure of the retention pond area. The Company could
incur costs as yet undetermined if it were to be found liable for such closure
and materials handling, although provisions of the easement afford the Company
rights which may serve to offset all or a portion of any such County claim. To
date, the Company has agreed to pay a 20% share of the County's investigation of
this area, which commenced in September 1993 and which is estimated to cost no
more than $150,000, but no commitment has been made toward any remedial measures
which may be recommended by the investigation.
In the letter announcing the delisting of the Lower Falls site, NYSDEC
indicated an intention to pursue appropriate closure of the County's former
retention pond area, suggesting that it will be evaluated separately to
determine whether it meets the criteria of a hazardous waste site. The Company
is unable to assess what implications the NYSDEC letter may have for the
County's claim against it.
At another location along the River where the Company owns property, a
boring taken in Fall 1988 for a sewer system project showed a layer containing a
black viscous material. The Company undertook an investigation to determine the
extent of the layer. The study found that some of the soil and ground water on-
site had been adversely impacted by the hazardous substance constituents of the
black viscous material, but evidence was inadequate to determine whether the
material or its constituents had migrated off-site. The matter was reported to
the NYSDEC and, in September 1990, the Company also provided the agency with a
risk assessment for its review. That assessment concluded that the findings
warranted no agency action and that site conditions posed no significant threat
to the environment. Although NYSDEC could require the Company to undertake
further investigation and/or remediation, the agency has taken no action in the
nearly three and one-half years since the report's submittal.
In August 1990 the Company was notified of the existence of a federal
Superfund site located in Syracuse, NY, known as the Quanta Resources Site. The
federal Environmental Protection Agency (EPA) has included the Company in its
list of approximately 25 potentially
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responsible parties (PRPs) at the site, but no data has been produced showing
that any of its wastes were delivered to the site. In return for its release
from liability for that phase, the Company has joined other PRPs in agreeing to
divide among them, utilizing a two-tier structure, EPA's cost of a contractor-
performed removal action intended to stabilize the site. The Company, in the
lower tier of PRPs, paid its $27,500 share of such cost. The NYSDEC has not yet
made an assessment for certain response and investigation costs it has incurred
at the site, nor is there as yet any information on which to base an estimate of
the cost to design and conduct at the site any remedial measures which federal
or state authorities may require.
On May 21, 1993, the Company was notified by NYSDEC that it was
considered a potentially responsible party (PRP) for the Frontier Chemical
Pendleton Superfund Site located in Pendleton, NY. The Company has signed a PRP
Agreement with approximately 15 parties and is participating in negotiations for
an Administrative Order on Consent with NYSDEC. The PRPs have negotiated a
workplan for site remediation and have retained a consulting firm to implement
the workplan. Preliminary estimates indicate site remediation will be between
$6 and $8 million. The Company is participating with the group to allocate
costs among the PRPs. An allocation scheme has yet to be developed.
Monitoring wells installed at another Company facility in 1989
revealed that an undetermined amount of leaded gasoline had reached the
groundwater. The Company has continued to monitor free product levels in the
wells, and has begun a modest free product recovery project, reports on both of
which are routinely furnished to the NYSDEC. Free product levels in the wells
have declined, but authorities may require further remediation once most of the
free product has been recovered.
The Company is developing strategies responsive to the Federal Clean
Air Act Amendments of 1990 (Amendments). The Amendments will primarily affect
air emissions from the Company's fossil-fueled electric generating facilities.
The Company is in the process of identifying the optimum mix of control measures
that will allow the fossil fuel based portion of the generation system to fully
comply with applicable regulatory requirements. Although work is continuing,
not all compliance control measures have been determined. The Company has
adopted control measures for nitrogen oxides (NOx) emissions which must be in
effect by the federally mandated compliance date of May 31, 1995. The chosen
NOx control measures consist of the installation of low NOx burners on some
units, the derating of unit generation by taking burners out of service on other
units and placing one unit on cold standby with the redistribution of load to
the remaining more efficient units. Capital costs for NOx controls and the
installation of continuous emission monitoring systems are not expected to
exceed $6.8 million and will be incurred during 1994 and 1995. A range of
capital costs between $20 million and $30 million (1993 dollars) has been
estimated for the implementation of several potential scenarios which would
enable the Company to meet the foreseeable future NOx and sulphur dioxide
requirements of the Amendments. These capital costs would be incurred between
1996 and 2000. The Company currently estimates that it could also incur up to
$2 million (1993 dollars) of additional annual operating expenses, excluding
fuel, to comply with the Amendments. The use of scrubbing equipment is not
presently being considered. Likewise, the purchase or sale of "emission
allowances," as allowed by the Amendments, is not currently being considered.
The Company anticipates that the costs incurred to comply with the Amendments
will be recoverable through rates based on previous rate recovery of
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environmental costs required by governmental authorities.
GAS COST RECOVERY.
Many interstate gas pipeline companies entered into contracts with gas
producers which required the pipeline companies to pay for a minimum amount of
gas whether or not the gas is actually taken from the producer (take-or-pay
costs). Pursuant to FERC authorization, the Company's gas suppliers have
included certain amounts of their take-or-pay costs in the rates charged to the
Company.
The PSC instituted a proceeding in October 1988 to determine the
extent to which the gas distribution companies in New York State would be
permitted to recover in rates the take-or-pay costs imposed upon them. Through
a series of subsequent settlements between the Staff of the PSC and the Company,
the Company was permitted to recover in rates 87.5% of the first $12 million of
the pipeline take-or-pay costs imposed upon it and all such costs in excess
thereof except for a maximum of $562,500.
As of December 31, 1993 the Company had been billed for $17.6 million
of take-or-pay costs and has thus far recovered $16.4 million from its
customers. The Company expects only insignificant amounts of take-or-pay costs
remain to be billed to the Company.
As a result of the restructuring of the gas transportation industry by
the FERC, there will be a number of changes in this aspect of the Company's
business over the next several years. These changes, which will apply
throughout the industry, will affect different companies differently and may
result, at least initially, in increases in the gas transportation costs of the
Company. The Company will also be required to pay a share of certain transition
costs incurred by the pipelines as a result of the FERC restructuring. Although
the final amounts of such transition costs are subject to continuing
negotiations with several pipelines and ongoing pipeline filings requiring FERC
approval, the Company expects such costs to range between $43.5 and $52.0
million. A substantial portion of such costs will be on the CNG Transmission
Corporation (CNG) system of which approximately $27 million was billed to the
Company on December 3, 1993 payable over the following three years. The Company
expects these transition costs to be recoverable in its rates.
In a related matter, in connection with the development of the Empire
State Pipeline ("Empire"), the Company is committed as of November 1993, to
transportation capacity from Empire, to upstream pipeline transportation and
storage service and to the purchase of natural gas in quantities corresponding
to these transportation and storage arrangements. The Company also has certain
contractual obligations with CNG whereby the Company is subject to demand
charges for transportation capacity for a period of eight years. In October
1993, the effective date of implementation of pipeline restructuring pursuant to
FERC Order No. 636 and CNG's individual restructuring in Docket No. RS92-14,
CNG's transportation rights on upstream pipelines were assigned to its
customers, including the Company. The Company has concluded the corresponding
contracts with those upstream pipelines.
The transportation service to be provided by Empire was scheduled to
phase in over 12 months, at which point the combined CNG and Empire
transportation capacity would have exceeded the Company's current requirements.
Therefore, the Company recently entered into a marketing agreement with CNG,
pursuant to which CNG will assist the Company in obtaining permanent replacement
customers for the
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transportation capacity the Company will not require. It may renegotiate its
arrangements with CNG and/or Empire or it may negotiate assignment, on a
permanent or temporary basis, of the transportation capacity that exceeds the
requirements of its customers. In addition, under FERC rules, the Company may
sell its excess transportation capacity in the market. While CNG has already
secured letters of intent for a substantial portion of such capacity, whether
and to what extent CNG and/or the Company can successfully negotiate the
assignment or sale of the excess capacity, or at what price, cannot be
determined at the present time. The retention of some or all of this excess
transportation capacity may cause an increase in the Company's gas supply costs.
This would be in addition to any increase caused by other aspects of the gas
transportation restructuring.
GAS PURCHASE UNDERCHARGES.
The Company became aware during 1993 that it did not account properly
for certain gas purchases for the period August 1990 - August 1992 resulting in
undercharges to gas customers of approximately $7.5 million. The Company had
previously estimated the effect to approximate as much as $10 million; however,
further review determined that the magnitude of the error on previously reported
operations was substantially less.
The undercharges arose from the increased complexity arising from the
federal deregulation of the gas industry and the Company's transition from a
full requirements customer of one gas supplier to the purchase of gas
transportation service and natural gas on the open market. Problems of this
type are routinely corrected through the Gas Adjustment Clause process and
appropriate amounts are collected from or refunded to customers. Of the total
undercharges, $2.3 million has previously been expensed and $5.2 million had
been deferred on the Company's balance sheet.
The Company advised the PSC and all parties to the Company's most
recent rate proceeding of the undercharges. In its August 24, 1993 Order
approving the Company's three-year rate settlement the PSC made the Company's
current gas rates temporary solely to consider the impacts of the erroneous gas
accounting, and in a September 13, 1993 Order the PSC instituted a proceeding to
investigate the resulting undercollections and the recoverability of such
amounts from customers. In its September 13 Order the PSC directed the Company
to demonstrate fully the existence and amount of the undercharges, to explain
the reasons for the errors, and to address possible general and specific legal
limitations on the Company's right to recover portions of the undercharges. The
Company filed evidence and analysis responsive to that Order on October 27,
1993.
On December 30, 1993, a proposed settlement among the Company, PSC
Staff and another party was filed with the PSC. It provides for the recovery in
rates of $3.2 million over three years, subject to audit and to limitations on
rate adjustments established in the August 24 Order. The Company wrote off the
$2.0 million balance of the undercharges as of December 31, 1993. That write-
off amounts to a reduction in 1993 earnings of four cents per share, net of tax.
Although no party, to the Company's knowledge, opposes the proposed settlement,
the Company is unable to predict whether the PSC will approve it.
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OTHER MATTERS.
REGULATORY DISALLOWANCES. In June 1992 the Company recorded a charge
to earnings of $8.2 million in connection with ice storm restoration costs
disallowed by the PSC. In December 1991, the Company recorded a non-cash charge
against earnings of $10 million for refunds to be made to customers in
connection with a PSC fuel procurement audit.
NUCLEAR FUEL ENRICHMENT SERVICES. The Company has a contract with the
United States Enrichment Corporation (USEC), formerly with the DOE, for nuclear
fuel enrichment services which assures provision of 70% of the Ginna Nuclear
Plant's requirements throughout its service life or 30 years, whichever is less.
No payment obligation accrues unless such enrichment services are needed.
Annually, the Company is permitted to decline USEC-furnished enrichment for a
future year upon giving ten years' notice. Consistent with that provision, the
Company has terminated its commitment to USEC for the years 2000, 2001 and 2002.
The USEC waived, for an interim period, the obligation to give ten years' notice
for 2003. The Company has secured the remaining 30% of its Ginna requirements
for the reload years 1994 through 1995 under different arrangements with USEC.
The Company plans to meet its enrichment requirements for years beyond those
already committed by making further arrangements with USEC or by contracting
with third parties. The cost of USEC enrichment services utilized for the next
seven reload years (priced at the most current rate) ranges from $4 million to
$7 million per year.
ASSERTION OF TAX LIABILITY. The Company's federal income tax returns
for 1987 and 1988 have been examined by the Internal Revenue Service (IRS) which
has proposed adjustments of approximately $29 million.
The adjustments at issue generally pertain to the characterization and
treatment of events and relationships at the Nine Mile Two project and to the
appropriate tax treatment of investments made and expenses incurred at the
project by the Company and the other co-tenants. A principal issue appears to
be the year in which the plant was placed in service.
The Company has filed a protest of the IRS adjustments to its 1987-88
tax liability and has had an initial hearing before the appeals officers. The
Company believes it has sound bases for its protest, but cannot predict the
outcome thereof. Generally, the Company would expect to receive rate relief to
the extent it was unsuccessful in its protest except for that part of the IRS
assessment stemming from the Nine Mile Two disallowed costs, although no such
assurance can be given.
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Interim Financial Data
In the opinion of the Company, the following quarterly information includes
all adjustments, consisting of normal recurring adjustments, necessary for a
fair statement of the results of operations for such periods. The variations
in operations reported on a quarterly basis are a result of the seasonal
nature of the Company's business and the availability of surplus electricity.
(Thousands of Dollars)
--------------------------------------------------
Earnings per
Operating Operating Net Earnings on Common Share
Quarter Ended Revenues Income Income Common Stock (in dollars)
December 31, 1993 * 256,219 43,756 22,366 20,541 $ .55
September 30, 1993 ** 217,278 38,058 20,204 18,379 .51
June 30, 1993 203,252 21,295 6,909 5,084 .15
March 31, 1993 272,275 44,124 29,084 27,259 .78
December 31, 1992 $244,290 $41,744 $29,146 $27,073 $ .77
September 30, 1992 198,341 33,006 17,507 15,435 .45
June 30, 1992 *** 195,154 16,460 (4,579) (6,651) (.20)
March 31, 1992 257,747 42,735 28,365 26,293 .81
December 31, 1991 **** $229,331 $38,578 $14,911 $12,467 $ .38
September 30, 1991 195,629 31,752 17,262 15,756 .49
June 30, 1991 182,637 17,230 1,538 32 -
March 31, 1991 245,673 37,198 24,286 22,780 .72
* Includes recognition of $1.9 million net-of-tax pension plan curtailment
** Includes recognition of $3.4 million net-of-tax pension plan curtailment
*** Includes recognition of $5.4 million net-of-tax ice storm disallowance
**** Includes recognition of $6.6 million net-of-tax fuels audit disallowance
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
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PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by Item 10 of Form 10-K relating to
directors who are nominees for election as directors at the Company's
Annual Meeting of Shareholders to be held on April 20, 1994, will be
set forth under the heading "Election of Directors" in the Company's
Definitive Proxy Statement for such Annual Meeting of Shareholders.
The information required by Item 10 of Form 10-K with respect
to executive officers is, pursuant to instruction 3 of paragraph (b)
of Item 401 of Regulation S-K, set forth in Part I as Item 4-A of this
Form 10-K under the heading "Executive Officers of the Registrant".
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 of Form 10-K will be set
forth under the headings "Report of the Committee on Management on
Executive Compensation", "Executive Compensation" and "Pension Plan
Table" in the Company's Definitive Proxy Statement for the Annual
Meeting of Shareholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 of Form 10-K will be set
forth under the headings "General" and "Security Ownership of
Management" in the Company's Definitive Proxy Statement for the Annual
Meeting of Shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by Item 13 of Form 10-K will be set
forth under the heading "Election of Directors" in the Company's
Definitive Proxy Statement for the Annual Meeting of Shareholders.
Pursuant to General Instruction G(3) to Form 10-K, Items 10 through 13
have not been answered because, within 120 days after the close of its fiscal
year, the Registrant will file with the Commission a definitive proxy statement
pursuant to Regulation 14A which involves the election of directors. Regis-
trant's definitive proxy statement dated March 7, 1994 will be filed with the
Securities and Exchange Commission prior to April 30, 1994. The information
required in Items 10 through 13 under the headings set forth above is incorpo-
rated by reference herein by this reference thereto. Except as specifically
referenced herein the proxy statement in connection with the annual meeting of
shareholders to be held April 20, 1994 is not deemed to be filed as part of this
Report.
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Part IV
-------
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) 1. The financial statements listed below are shown under Item 8 of
this Report.
Report of Independent Accountants
Consolidated Statements of Income and Retained Earnings for each
of the three years ended December 31, 1993
Consolidated Balance Sheets at December 31, 1993 and 1992
Consolidated Statement of Cash Flows for each of the three years
ended December 31, 1993
Notes to Consolidated Financial Statements
(a) 2. Financial Statement Schedules - Included in Item 14 herein:
For each of the three years ended December 31, 1993
Schedule V - Property, Plant and Equipment (Utility Plant)
Schedule VI - Accumulated Depreciation and Amortization (Utility
Plant)
Schedule VIII - Valuation and Qualifying Accounts
Schedule IX - Short-term Borrowings
Schedule X - Supplementary Income Statement Information
(a) 3. Exhibits
Exhibit 3-1* - Restated Certificate of Incorporation of
Rochester Gas and Electric Corporation
under Section 807 of the Business
Corporation Law filed with the Secretary
of State of the State of New York on June
23, 1992. (Filed in Registration No.
33-49805 as Exhibit 4-5 in July 1993)
Exhibit 3-2 - By-Laws of the Company, as amended to date.
Exhibit 4-1* - Restated Certificate of Incorporation of
Rochester Gas and Electric Corporation
under Section 807 of the Business
Corporation Law filed with the Secretary
of State of the State of New York on June
23, 1992. (Filed in Registration No.
33-49805 as Exhibit 4-5 in July 1993)
- 87 -
Exhibit 4-2* - By-Laws of the Company, as amended to date.
(Filed as Exhibit 3-2 herein)
Exhibit 4-3* - General Mortgage to Bankers Trust Company,
as Trustee, dated September 1, 1918, and
supplements thereto, dated March 1, 1921,
October 23, 1928, August 1, 1932 and May
1, 1940. (Filed as Exhibit 4-2 in February
1991 on Form 10-K for the year ended
December 31, 1990, SEC File No. 1-672-2)
Exhibit 4-4* - Supplemental Indenture, dated as of March
1, 1983 between the Company and Bankers
Trust Company, as Trustee (Filed as
Exhibit 4-1 on Form 8-K dated July 15,
1993, SEC File No. 1-672)
Exhibit 10-1* - Basic Agreement dated as of September 22,
1975 among the Company, Niagara Mohawk
Power Corporation, Long Island Lighting
Company, New York State Electric & Gas
Corporation and Central Hudson Gas &
Electric Corporation.(Filed in
Registration No. 2-54547, as Exhibit 5-P
in October 1975.)
Exhibit 10-2* - Letter amendment modifying Basic Agreement
dated September 22, 1975 among the
Company, Central Hudson Gas & Electric
Corporation, Orange and Rockland
Utilities, Inc. and Niagara Mohawk Power
Corporation. (Filed in Registration No.
2-56351, as Exhibit 5-R in June 1976.)
Exhibit 10-3* - Agreement dated September 25, 1984 between
the Company and the United States
Department of Energy. (Filed as Exhibit
10-8 in November 1984 on Form 10-Q for the
quarter ended September 30, 1984, SEC File
No. 1-672)
Exhibit 10-4* - Contract modification Nos. 1, 2 and 3 to
Agreement dated September 25, 1984 between
the Company and the United States
Department of Energy. (Filed as Exhibit
10-8 in November 1986 on Form 10-Q for the
quarter ended September 30, 1986, SEC File
No. 1-672)
Exhibit 10-5* - Specification of Terms and Conditions of
Offer of Settlement dated as of September
3, 1985 between cotenants and PSC with
respect to Case 29124 and the Nine Mile
Point Nuclear Plant Unit No. 2. (Filed as
Exhibit 10-8 in February 1988 on Form 10-K
for the year ended December 31, 1987, SEC
File No. 1-672-2)
Exhibit 10-6* - Offer to Induce Settlement, dated July 15,
1986, among cotenants of Nine Mile Point
Nuclear Plant Unit No. 2. (Filed as Exhibit
10-9 in February 1988 on Form 10-K for the
year ended December 31, 1987, SEC File No.
1-672-2)
- 88 -
Exhibit 10-7* - Agreement dated February 5, 1980 between
the Company and the Power Authority of the
State of New York. (Filed as Exhibit 10-10
in February 1990 on Form 10-K for the year
ended December 31, 1989, SEC File No.
1-672-2)
Exhibit 10-8* - Agreement dated March 9, 1990 between the
Company and Mellon Bank, N.A. (Filed as
Exhibit 10-1 in May 1990 on Form 10-Q for
the quarter ended March 31, 1990, SEC File
No. 1-672)
Exhibit 10-9* - Rochester Gas and Electric Corporation
Executive Incentive Plan dated January 29,
1992. (Filed as Exhibit 10-13 in February
1992 on Form 10-K for the year ended
December 31, 1991, SEC File No. 1-672-2)
Exhibit 10-10* - Basic Agreement dated September 22, 1975 as
amended and supplemented between the
Company and Niagara Mohawk Power
Corporation. (Filed as Exhibit 10-11 in
February 1993 on Form 10-K for the year
ended December 31, 1992, SEC File No.
1-672-2)
Exhibit 10-11* - Operating Agreement effective January 1,
1993 among the owners of the Nine Mile
Point Nuclear Plant Unit No. 2. (Filed as
Exhibit 10-12 in February 1993 on Form
10-K for the year ended December 31, 1992,
SEC File No. 1-672-2)
Exhibit 10-12 - Rochester Gas and Electric Corporation
Executive Incentive Plan, Restatement of
January 1, 1993.
Exhibit 10-13 - Rochester Gas and Electric Corporation Long
Term Incentive Plan
Exhibit 10-14 - Rochester Gas and Electric Corporation
Deferred Compensation Plan
Exhibit 23 - Consent of Price Waterhouse, independent
accountants
* Incorporated by reference.
The Company agrees to furnish to the Commission, upon request, a copy of all
agreements or instruments defining the rights of holders of debt which do not
exceed 10% of the total assets with respect to each issue, including the
Supplemental Indentures under the General Mortgage and credit agreements in
connection with promissory notes as set forth in Note 6 of the Notes to
Financial Statements.
(b) Reports on Form 8-K - None
- 89 -
Rochester Gas and Electric Corporation
SCHEDULE V - UTILITY PLANT
For the Year Ended December 31, 1991
(Thousands of Dollars)
Column A Column B Column C Column D Column E Column F
-------- ------------ ----------- ----------- ------------- ----------
Balance at Other Changes Balance at
Beginning of Additions -Debit and/or End of
Classification Period at Cost (a) Retirements (Credit) (a) Period
-------------- ------------ ----------- ----------- -------------- ----------
Electric
In Service
Production $1,090,551 $ 424,409 $ 8,272 ($942) $1,505,746
Transmission and Distribution 566,535 35,169 5,386 (345) 595,973
General 13,364 3,294 42 134 16,750
Nuclear Fuel Assemblies 227,219 13,058 93,214 147,063
Electric Plant held for future use 1,978 1,978
Plant Acquisition Adjustments 1,879 (78) 1,801
---------- -------- ----------
1,901,526 475,930 106,914 (1,231) 2,269,311
---------- --------- -------- -------- ----------
Gas
In Service
Production and Storage 110 110
Transportation and Distribution 301,855 19,266 3,157 (48) 317,916
General 2,343 101 91 6 2,359
---------- --------- -------- -------- ----------
304,308 19,367 3,248 (42) 320,385
---------- --------- -------- -------- ----------
Common
In Service, General 104,460 13,818 2,240 820 116,858
---------- --------- -------- -------- ----------
Construction Work in Progress
Electric 68,865 (387,316) 379,769 61,318
Gas 7,129 2,347 1 9,477
Common 6,669 (617) 1 6,053
---------- --------- -------- ----------
82,663 (385,586) 0 379,771 76,848
---------- --------- -------- -------- ----------
Total Utility Plant $2,392,957 $ 123,529 $112,402 $379,318 $2,783,402
========== ========= ======== ======== ==========
Parentheses denote negative amounts
(a) Includes $375,929 addition to nuclear plant due to Nine Mile Two Settlement
recognized in March, 1991.
-90-
Rochester Gas and Electric Corporation
SCHEDULE V - UTILITY PLANT
For the Year Ended December 31, 1992
(Thousands of Dollars)
Column A Column B Column C Column D Column E Column F
----------- ------------- ------------- ------------- ------------- -------------
Balance at Other Changes Balance at
Beginning of Additions -Debit and/or End of
Classification Period at Cost Retirements (Credit) Period
--------------- ------------- ------------- ------------- ------------- -------------
Electric
In Service
Production $1,505,746 $39,702 $8,739 ($244) $1,536,465
Transmission and Distribution 595,973 26,569 6,767 (238) 615,537
General 16,750 3,759 932 (25) 19,552
Nuclear Fuel Assemblies 147,063 11,763 158,826
Electric Plant held for future use 1,978 1,978
Plant Acquisition Adjustments 1,801 (78) 1,723
------------- ------------- ------------- ------------- -------------
2,269,311 81,793 16,438 (585) 2,334,081
------------- ------------- ------------- ------------- -------------
Gas
In Service
Production and Storage 110 3 107
Transportation and Distribution 317,916 23,217 1,922 339,211
General 2,359 127 338 2,148
------------- ------------- ------------- ------------- -------------
320,385 23,344 2,263 0 341,466
------------- ------------- ------------- ------------- -------------
Common
In Service, General 116,858 12,111 6,152 217 123,034
------------- ------------- ------------- ------------- -------------
Construction Work in Progress
Electric 61,318 9,102 96 70,516
Gas 9,477 (4,396) 180 5,261
Common 6,053 2,005 (1) 8,057
------------- ------------- ------------- ------------- -------------
76,848 6,711 0 275 83,834
------------- ------------- ------------- ------------- -------------
Total Utility Plant $2,783,402 $123,959 $24,853 ($93) $2,882,415
============= ============= ============= ============= =============
Parentheses denote negative amounts
-91-
Rochester Gas and Electric Corporation
SCHEDULE V - UTILITY PLANT
For the Year Ended December 31, 1993
(Thousands of Dollars)
Column A Column B Column C Column D Column E Column F
---------- ------------- --------- ----------- ------------ ----------
Balance at Other Changes Balance at
Beginning of Additions -Debit and/or End of
Classification Period at Cost Retirements (Credit) Period
-------------- ------------- --------- ----------- ----------- ----------
Electric
In Service
Production $1,536,465 $37,394 $3,250 ($134) $1,570,475
Transmission and Distribution 615,537 25,519 4,734 58 636,380
General 19,552 4,008 131 633 24,062
Nuclear Fuel Assemblies 158,826 15,530 174,356
Electric Plant held for future use 1,978 (9) 1,969
Plant Acquisition Adjustments 1,723 (78) 1,645
---------- --------- ---------- ---------- ----------
2,334,081 82,451 8,115 470 2,408,887
---------- --------- ---------- ---------- ----------
Gas
In Service
Production and Storage 107 23 84
Transportation and Distribution 339,211 16,342 1,420 354,133
General 2,148 186 69 2 2,267
---------- --------- ---------- ---------- ----------
341,466 16,528 1,512 2 356,484
---------- --------- ---------- ---------- ----------
Common
In Service, General 123,034 12,455 9,805 (256) 125,428
---------- --------- ---------- ---------- ----------
Construction Work in Progress
Electric 70,516 17,188 26 87,730
Gas 5,261 2,995 (1) 8,255
Common 8,057 8,701 7 16,765
---------- --------- ---------- ---------- ----------
83,834 28,884 0 32 112,750
---------- --------- ---------- ---------- ----------
Total Utility Plant $2,882,415 $140,318 $19,432 $ 248 $3,003,549
========== ========= ========== ========== ==========
Parentheses denote negative amounts
- 92 -
Rochester Gas and Electric Corporation
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF UTILITY PLANT
For the Year Ended December 31, 1991
(Thousands of Dollars)
Column A Column B Column C Column D Column E Column F
----------- ------------ ------------ ------------ ------------ ------------
Additions
Charged
Balance at to Costs Balance at
Beginning of and Other End of
Period Expenses Retirements Changes Period
------------ ------------ ------------ ------------ ------------
Electric $484,817 $67,501 $16,386 $376,045 a $911,977
Provision for amortization
of nuclear fuel assemblies 184,423 23,606 93,214 (3,637)b 111,178
------------ ------------ ------------ ------------ ------------
669,240 91,107 109,600 372,408 1,023,155
------------ ------------ ------------ ------------ ------------
Gas 99,784 9,058 3,903 104,939
Common 43,970 8,348 2,335 572 50,555
------------ ------------ ------------ ------------ ------------
Totals $812,994 $108,513 $115,838 $372,980 $1,178,649
============ ============ ============ ============ ============
Parentheses denote negative amounts
NOTES:
a. Represents mainly adjustments to accumulated depreciation due to Nine
Mile Two Plant Settlement
Agreement recognized in March 1991.
b. Represents reclassification as a long term liability for disposal of
nuclear fuel.
- 93 -
Rochester Gas and Electric Corporation
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF UTILITY PLANT
For the Year Ended December 31, 1992
(Thousands of Dollars)
Column A Column B Column C Column D Column E Column F
---------- ------------ ------------ ------------- ------------ ------------
Additions
Charged
Balance at to Costs Balance at
Beginning of and Other End of
Period Expenses Retirements Changes Period
------------ ------------ ------------- ------------ ------------
Electric $911,977 $66,671 $19,421 $988 a $960,215
Provision for amortization
of nuclear fuel assemblies 111,178 18,804 5 (2,362)b 127,615
------------ ------------ ------------ ------------ ------------
1,023,155 85,475 19,426 (1,374) 1,087,830
------------ ------------ ------------ ------------ ------------
Gas 104,939 9,084 2,488 111,535
Common 50,555 9,443 6,261 15 c 53,752
------------ ------------ ------------ ------------ ------------
Totals $1,178,649 $104,002 $28,175 ($1,359) $1,253,117
============ ============ ============ ============ ============
Parentheses denote negative amounts
NOTES:
a. Represents miscellaneous adjustments of $1,003 and interdepartmental
transfers of $(15).
b. Represents reclassification as a long term liability for disposal of nuclear
fuel.
c. Represents interdepartmental transfers.
- 94 -
Rochester Gas and Electric Corporation
SCHEDULE VI - ACCUMULATED DEPRECIATION AND AMORTIZATION OF UTILITY PLANT
For the Year Ended December 31, 1993
(Thousands of Dollars)
Column A Column B Column C Column D Column E Column F
---------- ------------- ------------- ------------- ------------- -------------
Additions
Charged
Balance at to Costs Balance at
Beginning of and Other End of
Period Expenses Retirements Changes Period
------------- ------------- ------------- ------------- -------------
Electric $960,215 $66,049 $8,619 $567 a $1,018,212
Provision for amortization
of nuclear fuel assemblies 127,615 18,862 128 (2,067)b 144,282
------------- ------------- ------------- ------------- -------------
1,087,830 84,911 8,747 (1,500) 1,162,494
------------- ------------- ------------- ------------- -------------
Gas 111,535 8,963 2,148 (1)c 118,349
Common 53,752 9,970 9,460 (22)c 54,240
------------- ------------- ------------- ------------- -------------
Totals $1,253,117 $103,844 $20,355 ($1,523) $1,335,083
============= ============= ============= ============= =============
Parentheses denote negative amounts
NOTES:
a. Represents miscellaneous adjustments of $544 and interdepartmental
transfers of $23.
b. Represents reclassification as a long term liability for disposal of
nuclear fuel.
c. Represents interdepartmental transfers.
- 95 -
ROCHESTER GAS AND ELECTRIC CORPORATION
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)
FOR THE YEAR ENDED DECEMBER 31, 1991
Additions
--------------------
Charged
Balance at to Costs Charged Balance at
Beginning and to Other End of
Descriptions of Period Expenses Accounts Deductions Period
------------ --------- -------- -------- ---------- ----------
Reserves for:
Uncollectible
accounts $ 591 $4,353 $4,533/(a)/ $ 411
FOR THE YEAR ENDED DECEMBER 31, 1992/(b)/
Additions
--------------------
Charged
Balance at to Costs Charged Balance at
Beginning and to Other End of
Descriptions of Period Expenses Accounts Deductions Period
------------ --------- -------- -------- ---------- ----------
Reserves for:
Uncollectible
accounts $ 411 $ 89 $ 500
FOR THE YEAR ENDED DECEMBER 31, 1993/(b)/
Additions
--------------------
Charged
Balance at to Costs Charged Balance at
Beginning and to Other End of
Descriptions of Period Expenses Accounts Deductions Period
------------ --------- -------- -------- ---------- ----------
Reserves for:
Uncollectible
accounts $ 500 $ 100 $ 600
/(a)/ Accounts written off, less recoveries.
/(b)/ Beginning in 1992 the Company no longer charges uncollectible expenses
through the uncollectible reserve. The total amount written off
directly to expense in 1992 was $5,116 and in 1993 was $6,241.
- 96 -
ROCHESTER GAS AND ELECTRIC CORPORATION
SCHEDULE IX - SHORT TERM BORROWINGS(1)
(Thousands of Dollars)
Weighted
Average Weighted
Interest Maximum Average Average
Category of Balance Rate at Amount Amount Interest Rate
Aggregate Short-Term at end of End of Outstanding Outstanding During
Borrowings Period Period During Period During Period(2) Period(3)
- -------------------- --------- -------- ------------- ------------- -------------
For the year ended
December 31, 1991
Notes Payable $59,500 5.09% $68,800 $40,757 6.43%
Commercial Paper - - - - -
For the year ended
December 31, 1992
Notes Payable $50,800 3.99% $89,900 $45,645 4.28%
Commercial Paper - - - - -
For the year ended
December 31, 1993
Notes Payable $68,100 3.46% $73,200 $42,762 3.48%
Commercial Paper - - - - -
NOTES:
1. Borrowings under a Revolving Credit Loan Agreement are at Prime, C.D. or
Libor rates plus a fraction thereof. Notes issued have various terms of
maturity but do not exceed six months. The Company also issues commercial
paper at various discount rates, usually maturing within 30-45 days.
2. Average amount outstanding is the simple average of the daily amount
outstanding during the period.
3. Weighted average interest rate is computed by dividing the total interest
accrued during the period by the daily average amount outstanding.
- 97 -
ROCHESTER GAS AND ELECTRIC CORPORATION
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
(Thousands of Dollars)
The amounts of maintenance and provisions for depreciation and
amortization are as set forth in the Statements of Income and of Cash Flows.
During the years 1991, 1992, and 1993 and the amounts for royalties or
advertising costs did not exceed 1% of total revenues as reported in the
Statement of Income. Taxes, other than Federal income tax, which exceed 1% of
total revenues were classified as follows:
Years Ended December 31,
------------------------
1993 1992 1991
---- ---- ----
Real Estate (including
special franchise) $ 58,015 $ 54,623 $ 51,459
Gross Income 46,033 46,889 40,852
Other Taxes 22,844 22,740 21,338
-------- -------- --------
Total $126,892 $124,252 $113,649
======== ======== ========
- 98 -
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
ROCHESTER GAS AND ELECTRIC CORPORATION
By ROGER W. KOBER
-------------------------------------
(Roger W. Kober)
(Chairman of the Board, President
and Chief Executive Officer)
Date: February 15, 1994
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant in the capacities and on the dates indicated.
Signature Title Date
Principal Executive Officer:
ROGER W. KOBER Chairman of the Board, February 15, 1994
- ------------------------------
(Roger W. Kober) President and Chief
Executive Officer
Principal Financial Officer and Principal Accounting Officer:
THOMAS S. RICHARDS Senior Vice President, February 15, 1994
- ------------------------------
(Thomas S. Richards) Finance and General
Counsel
- 99 -
Signature Title Date
Directors:
WILLIAM BALDERSTON III Director February 15, 1994
- ----------------------------------
(William Balderston III)
ANGELO J. CHIARELLA Director February 15, 1994
- ----------------------------------
(Angelo J. Chiarella)
ALLAN E. DUGAN Director February 15, 1994
- ----------------------------------
(Allan E. Dugan)
WILLIAM F. FOWBLE Director February 15, 1994
- ----------------------------------
(William F. Fowble)
JAY T. HOLMES Director February 15, 1994
- ----------------------------------
(Jay T. Holmes)
ROGER W. KOBER Director February 15, 1994
- ----------------------------------
(Roger W. Kober)
THEODORE L. LEVINSON Director February 15, 1994
- ----------------------------------
(Theodore L. Levinson)
CONSTANCE M. MITCHELL Director February 15, 1994
- ----------------------------------
(Constance M. Mitchell)
CORNELIUS J. MURPHY Director February 15, 1994
- ----------------------------------
(Cornelius J. Murphy)
ARTHUR M. RICHARDSON Director February 15, 1994
- ----------------------------------
(Arthur M. Richardson)
M. RICHARD ROSE Director February 15, 1994
- ----------------------------------
(M. Richard Rose)
Director February , 1994
- ----------------------------------
(Harry G. Saddock)